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Home My WebLink About207-084Alaska 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 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1a. Well Status: Oil ❑ Gas❑ SPLUG ❑ Other ❑ Abandoned 0 Suspended❑ 20AAC 25.105 - 20AAC 25.110 GINJ ❑ WINJ ❑ WAG[] WDSPL ❑ No. of Completions: lb. Well Class: Development Exploratory ❑ Service ❑ Stratigraphic Test ❑ 2. Operator Name: Plugging Inlet, LLC 6. Date Comp., Susp., or Ab na d ' 10/8/2019 14. Permit to Drill Number / Sundry: 207-0847318 - 3g, 3. Address: 6733 South Yale Ave., Tulsa, OK 74138 7. Date Spudded: 9/25/2008 15. API Number: 50-283-20120-00 4a. Location of Well (Governmental Section): Surface: 1160'FNL, 1415' FEL, SEC 1, T11 N, R12W, SM Top of Productive Interval: SAME Total Depth: SAME 8. Date TD Reached: 10/24/2008 16. Well Name and Number: Moquawkie #4 9. Ref Elevations: KB: 314' GL: 299' 17. Field / Pool(s): Moquawkie Undefined Gas Field 10. Plug Back Depth MD/TVD: Surf (Pad - 35) 18. Property Designation: C-061390 4b. Location of Well (State Base Plane Coordinates, NAD 27): Surface: x- 266767 y- 2587949 Zone- 4 TPI: x- SAME y- Zone- Total Depth: x- SAME y- Zone- 11. Total Depth MD/TVD: wo., wK 3f -V ,3'60 19. DNR Approval Number: N/A 12. SSSV Depth K4D/TVD: N/A 20. Thickness of Permafrost MD/TVD: N/A 5. Directional or Inclination Survey: Yes ❑ (attached) No 0 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 logs were obtained during P&A operations except short CCL inside tubing to correlate and set CIBP. 23. CASING, LINER AND CEMENTING RECORD WT. PER GRADE SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CASING FT TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD PULLED 13-3/8" 68# H-40 Surface 80' Surface 80' Driven Driven 0 9-5/8" 36# J-55 Surface 855' Surface 855' 12-1/4" 360 sx 13.3/14.5 ppg GasBlok 0 5-1/2" 15.5# J-55 Surface 3427' Surface 3427' 7-7/8" 3 stages: 125 sx 13.5ppg+ 0 500 sx 15.8 ppg "G" 24. Open to production or injection? Yes ❑ No 7 If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perld): / j�(��q l ( 25. TUBING RECORD SIZE DEPTH SET (MD) PACKER SET (MD/TVD) 2-7/8" 2878' 1711, 2064', 2540', 2676' 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. Was hydraulic fracturing used during completion? Yes ❑ No 2] Per 20 AAC 25.283 (i)(2) attach electronic and printed information DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED Surf -1711' Circ 37.3 bbl Class "G" cement at 15.8 ppg 27. PRODUCTION TEST Date First Production: Method of Operation (Flowing, gas lift, etc.): No production tests during P&A operations 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 _ / CONTINUED ON PAGE 2 DSR -3/25/202C 3BDMS16� (arc ' ti JQ1q;ubmit ORIGINIAL only DLB 03/25/20 xG 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 during P&A 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 de the 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, paleontological re ort rod cti n or well test results er 20 AAC 25.070. 32. 1 hereby certify that the foregoinq is true and correct to the best of my knowledqe. Authorized Name: Ed Jones Contact Name: Ed Jones Authorized Title: O tions Consultant Contact Email: AuthorizedContact Phone: 713-8998103 Signature: -�-� Date: /✓ INSTRUCTIONS General: Tm T'form and the;egwred 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 MOQUAWKIE #4 r- (AOGCC PERMIT No. 207-084) (API No. 50-283-20120-00 PLUG AND ABANDONMENT DAILY OPERATIONS SUMMARY FORM 10-407 7/10/2017—Aurora Gas operation. RU Pollard slickline (SL). RIH wit wire brush to 1715'. RIH with gauge ring to 1706'. PU PX plug, RIH and set in X profile in sliding sleeve (SS) at 1706'. RIH with prong and set in PX plug. Bled tubing to 0 and monitor for 30 minutes—no build up. 10/24/2018—RU SL. RIH, fill tubing, and pull PX plug and prong at 1706'. RIH with 2" bailer, tag at 2330', cleanout to 2368'. Fill tubing and pressure to 1100 psi. SD for night. 10/25/2018—TP-770 psi, IA -500 psi. RU SL. RIH w/ 2" bailer, tag at 2396'. Pump 5 bbl water. Tag at 2398'. Pressure test to 1500 psi. RIH with XO shifting tool and close SS's at 2259', 2101', 1937', and 1810'. Run XA shifting tool and close SS at 1706'. PT—good. RIH and verify that SS at 1706' is closed, RD SL. RU AEL. PU 2-7/8" CIBP, RIH, correlate, and set at_1714 . PT tubing to 1660 psi—good. Fill IA with 24 bbl water. Test tubingto. l 60 nsi . for 30 minutes—good. Test IA to 1650 psi for 30 minutes—good. RD AEL. 10/28/2018—prepare to pressure test, but AOGCC inspector on weather hold. 10/30/2018—RU HO truck for PT. AOGCC inspector, Guy Cook, on location to witness. Test IA to 1725 psi and tubing to 1725 psi for 30 minutes. OAS. —both good. Bled off. RU SL, RIH and open SS at 1706'—ready to cement. 11/4/2018—MI and RU Schlumberger (SLB). Heat 70 bbl water to 80°. Pump 10 bbl water down tubing, up IA. Test lines to 2500 psi. Mix chemical in water and batch mix 37.3 bbl (176 sx) Class G cement at 15.8 ppg and 1.19 cf/sk. Pump at 500 psi with good returns. Wash out lines and RD SLB. 11/8/2018—RU HO truck. PT tbg to 1450 psi -1350 in 15 minutes. IA -2150 psi -2000 psi in 15 minutes. 7/12-14/2019—Checked well. Can hear some gas bubbles. Check OOA and OA valves for pressure -0. Monitored for 2 days—no pressure buildup. 8/5/2019—Cut window in 13-3/8" conductor—small amount of gas bubbles in water at top, but no pressure. 8/6/2019—Mixed 1 sk G cement with CaC12 and dumped into 9-5/8" X 7" OA—filled 8'. SI. OOA still bubbling. 8/7/2019—Some bubbles in both OOA and OA. 8/15/2019—Add 1 sk cement to 9-5/8" X 7" OA. SI. 8/16/2019—Cut window in casings—still bubbling. 8/17/2019—Cut off wellhead, tree, and casings. 8/20/2019—Added cement to top of casing stubs. 8/21/2019—Added 4 sx Quikcrete to casing stubs morning and evening. 8/26/2019—Jackhammered cement out of IA. 9/25/2019—Suck water out of cellar—still venting small amount of gas. 9/26/2019—Leveled casing cut-off tops. Cut hole in plate for 13-3/8" and welded on 2" collar. Install plate over 13-3/8" conductor and welded in place. 9/27/2019—Finished welding on plate to cover all casings. Add 3/4" collar and valve to plate for vent. Install 10 -gal pressure vessel made from 9-5/8" casing. Pressure test to 600 psi. Filled vessel with 10 gal 16.5 ppg G cement wit CaC12 and pressure to 600 psi—took about 1 gal. Pumped to 600 psi when pressure leaked off to 500—repeat several times in an hour—pump about 2.5 gal cement. Attempt to bleed off—gas bubbling. Valve in vessel leaking. Remove vessel and wash out. 9/28/2019—Open valve on plate—gas venting. Changed 2" valve. 9/29/2019—SIP on plate -50 psi. 9/30/2019—Suck water from cellar. RU vessel on plate. Mix 16 ppg cement with CaC12 and filled vessel. Connect to pump. Pressure to 700 psi. Open to well, pressure bled to 500 psi. Repressure to 700. Repeat for 30 minutes and SI. Pumped 1 gal cement. Disconnect vessel and wash out. 10/2/2019-2" valve on plate cemented shut. Installed gauge on 3/4" valve -50 psi. Cut off plate and found 2 small channels on top of cement under plate. 10/3/2019—Jackhammered cement from all annuli as deep as possible -8-10". Blew out cement chips and dust. Found small hole in IA—drilled down, filled with JB Weld, and pushed down with wooden dowel. Add 5' piece of 2-7/8" tubing onto plate and rewelded plate to conductor. Filled 5' tubing section with 1.25 gal of cement and pumped 1 gal to 700 psi. SI. 10/4/2019—Opened 3/4" needle valve—no gas. Remove tubing pup, cut off plate. Flame tested—no gas. 10/8/2019—AOGCC insector Lou Laubenstein inspected cut off casing—OK (below original GL as well is in a "cut." Welded ID marker plate onto 13-3/8" conductor. 10/10/2019—Pump water out of cellar, removed debris, and backfilled. 10/14/2019—Added gravel to backfill to mound up 15" for settlement. 11/16-17/2019AOGCC inspector Guy Cook unable to fly from Anchorage due to weather. Cancelled site clearance inspection. Ed Jones 12/9/2019 PLUGGING INLET, LLC Moquawkie #4 ACTUAL PLUG & ABNADONNIENT API# 50-283-20120-00 PTD #207-084 KB — 15.2ft October 2019 Drill 12-1/4" Hole to 850' Beluga –not completed Tyonek Tops Carya 2-1 – 1,734' Carya 2-2 – 1942' Carya 2-3 – 2230' Carya 2-4.2 – 2,700' Carya 2-6 – 3303' Carya 2-1.1 1745-85' 2 7/8 6.5# 8rd EUE J-55 Tubing Carya 2-2.1 XO Sliding Sleeve @ 1,9371(open) 1948-58' 1972-76' :.. Hydraulic -set Packer Ca3 2,064' 1980-88' ' y, Carya 2-23 2106-11' 2116-21' 13-3/8" 68# Structural 2140-50' 2166-76' Conductor driven to 80' 12/4/15 ---tag hard fill at 2273' Carya 2-3.1 9-5/8" 36# Surface Casing set at 850' 2254-74' Cement w/ 14.5 ppg Gas -Block Arrowset Mechanical -set Packer enhanced Carya 2-4.1 v Sliding Sleeve @ 2642'(open) 2600-15' 2637-47' �` ~' '�' 'r• �' '� COMBINATION PLUG (PERFS, Carya 24.2 2-7/8 x 3-1/2" NU XO @ 2,787' 2702-22' SURF CSG SHOE, AND 2732-52'XO 1 jt 3-1/2" tubing and Bull Plug at ~_ -•SURFACE}-373 bbl (176 Sx) Class Carya 2-5 Jan 2015—tag at 2835'. 2874-79' G Cement (15.8 ppg, 1.19 cf/sk) Carya 2-6 Cement Retainer @ 3,259' 3306-26' Drill 7-7/8" Hole to 3,450' Y `t .... Set CHIP at 1714' and open sliding sleeve at 1706' ` XA Sliding sleeve @ 1,706' HRP Packer @ 1,711' Carya 2-1.1 1745-85' XO Sliding Sleeve @ 1,810'(open) Carya 2-2.1 XO Sliding Sleeve @ 1,9371(open) 1948-58' 1972-76' :.. Hydraulic -set Packer Ca3 2,064' 1980-88' ' XO Sliding Sleeve @ 2,101 '(open) Carya 2-23 2106-11' 2116-21' 2140-50' 2166-76' XO Sliding Sleeve @ 2,259' (open) 12/4/15 ---tag hard fill at 2273' Carya 2-3.1 2254-74' On/Off tool @ 2,540' Arrowset Mechanical -set Packer @ –2,546' Carya 2-4.1 v Sliding Sleeve @ 2642'(open) 2600-15' 2637-47' �` ~' Hydraulic -set Packer @ 2,676' XN Ninnle no 2-692' Carya 24.2 2-7/8 x 3-1/2" NU XO @ 2,787' 2702-22' 60ft of 3.5" screen 30/50 mesh 2732-52'XO 1 jt 3-1/2" tubing and Bull Plug at 2,878' Carya 2-5 Jan 2015—tag at 2835'. 2874-79' Carya 2-6 Cement Retainer @ 3,259' 3306-26' Drill 7-7/8" Hole to 3,450' Estimated PBTD @ 3,396' 3322-37' 5'/:" 15.5# J-55 Casing to 3,427 MD (TVD) /� UgGu? �,�i e 7 �eiylerl �d h�� .� /lea ✓,fie.' I �q �- /��a U� wk%P � UVB /l � �� r; � � /v/G+✓�r / ��ii� X14(4 /1/1 ��a U✓J[�c q Pam 6733 South Yale Avenue Tulsa, OK 74136 Contact: Ed Jones, Consultant Plu• •• Inlet, LLC 713-899-8103 (C) email: jejones(a)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. Thank you. 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 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 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim ReggDATE: P. I. Supervisor FROM: Lou Laubenstein SUBJECT: Petroleum Inspector 10/13/19 Surface Abandonment Moquawkie #4 ' Plugging Inlet LLC PTD 2070840; Sundry 318-336 10/8/19: 1 arrived on location for the surface abandonment inspection on Moquawkie #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. I departed location and communicated the deficiencies to AOGCC Inspection Supervisor Jim Regg. Inspection Supervisor Addendum: On 10/10/2019 Plugging Inlet was given approval by AOGCC to proceed with abandonment, leaving the well cut-off depth as is. Attachments: Photos (3) Email— Plugging Inlet Casing Cutoff Proposals 10/10/2019 2019-1008_Surface_Abandon_Moquawkie-4_11. docx Page 1 of 3 - r�. �TY ! .l.. � / f ! � x U r rj�•n♦ � 1;c r�" f.' wry a s � ` l(k old"tc/i��L! t__ 44Regg, James B (CED) (M ?V`70W From: Regg, James B (CED) Sent: Thursday, October 10, 2019 9:39 AM To: Schwartz, Guy L (CED) Subject: RE: Plugging Inlet Abandonments I agree with what they have proposed. 48 hr notice after cutoffs for inspections. Jim Regg Supervisor, Inspections AOGCC 333 W.7th 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.reee@alaska.¢ov. From: Schwartz, Guy L (CED) <guy.schwartz@alaska.gov> Sent: Thursday, October 10, 2019 9:07 AM To: Regg, James B (CED) <jim.regg@alaska.gov> Subject: FW: Plugging Inlet Abandonments fyi Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793-1226 ) or (Guv Schwartz®alaska gov). From: J. Edward Jones <jeiones@auroraoower.com> Sent: Thursday, October 10, 2019 8:44 AM To: Schwartz, Guy L (CED) <guy.schwartz@alaska.gov> Cc: Regg, James B (CED) <iim.reae@alaska.gov>; David Wallingford <david996@vahoo.com> Subject: RE: Plugging Inlet Abandonments Guy, Please see what we propose for cutoff depths of the wells and reason below (I have also attached a Word document of the same info and proposal). Please let me know if these proposals are acceptable, in particular Moquawkie 4 and Simpco Moquawkie 2. Lone Creek 1 needs more excavation for specific proposal. Please feel free to call if you need to discuss (713-899-8103). Thanks, Ed PLUGGING INLET CASING CUTOFF PROPOSALS (10/10/19) Aspen 1 WDW (PTD 205-111): Cutoff is now 4'2" below gravel pad; Typar is 2'2" above cutoff. Plan: Dig down 1' below cut-off and recut --will be 5' 2" from top of pad. Kaloa 2 (PTD 204-096): Now 3'9" to cut off from top of gravel pad. Typar is 2' above cutoff. Plan: Dig down 1' below cut-off and recut. Will be 4'9" from top of pad. Lone Creek 1 (PTD 198-084). Cutoff is 4'3" below top of gravel pad. Gravel to bottom of excavation. Plan: Dig down to see if can find bottom of gravel. Lone Creek 3 (PTD 205-097): Cutoff is now 4'5" below top of gravel pad. Typar is 2'1" above cutoff. Plan: Dig down 1' below cut-off. Will be 5' 5" from top of pad (now in water). Lone Creek 4 (PTD 207-091): Cutoff is now 3'2" below top of gravel pad. Typar is 1'8" above cutoff. Plan: Dig down 1'6" below cut-off and recut. Will be 4' 7" from top of pad (now in water). Moquawkie 1 (203-069): Cutoff is now 4'8" below gravel pad. Debris (cement and drilling mud residue) around cellar excavation from drilling issues (blowout and fire) makes it impossible to see change in gravel/soil. However, Moquawkie #3 is on same pad at same level about 100' away, based on change in soil composition there, original GL appears to be about 3'10" below top of gravel pad—see #3 below. Plan: Dig down 2' 2" below cut-off. Should give new cut-off 6' 10" from top of pad. Moquawkie 3 (PTD 205-080): Cutoff is 3'10" from top of gravel pad. Soil composition changes from gravel to clay even with cutoff. Plan: Dig down so new cut off is 6' 10" from top of pad, which is 3' down below current cut-off (now in water). Moquawkie 4 (PTD 207-084): Cutoff is now 3"5" below top of gravel pad and is 6" below Typar with clay layer under it. Plan: If necessary, dig down 2' 6" below cut-off and recut, will be 6' from top of pad. However, note that this pad was built in a cut—the original GL was 19' above top of current gravel pad (as staked plat elevation vs. as built elevation). Would the current cutoff depth be acceptable for that reason? Simpco Moquawkie 1 (PTD 178-047): Cutoff is 57" below top of pad and 3'2" below change in composition of gravel/dirt. Plan: Cap and bury. Simpco Moquawkie 2 (PTD 178-088): Cutoff is 7'3" below top of old gravel pad. Debris (cement and drilling mud residue) around cellar excavation from drilling issues makes it impossible to see change in gravel/soil. However, the pad is about the same level as the trees just off the pad closest to the well, so cutoff is believed to be at least 3' below original GL. Plan: Cap and bury if this assessment is acceptable. From: Schwartz, Guy L (CED)[mailtoa;uy.sch�ska.govj Sent: Wednesday, October 09, 2019 1:31 PM To: J. Edward Jones <jejpnesLaurgrapo ei.com> Cc: Regg, James B (CED) <jin ierg,,,)aIaska.gov>; David Wallingford <davirl9��6.i>yah��o.corip Subject: RE: Plugging Inlet Abandonments z Zo7-Z4 Megan S From: Schwartz, Guy L (DOA) Sent: Thursday, March 7, 2019 8:13 AM To: Mcphee, Megan S (DOA) Subject: FW: CIRI P & A well status Could you place this email letter in all of the well files listed below. There should be 8 wells listed. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended reciptent(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793-1226) or (Guv.schwartz@oIaska.Qov). From: Ed Jones <jejones@aurorapower.com> Sent: Wednesday, March 6, 2019 1:53 PM To: Schwartz, Guy L (DOA) <guy.schwartz@alaska.gov> Cc: George Pollock <gpollock@aurorapower.com>; Tom Redman <TomR@kfoc.net>; Mark Carr <MarkC@kfoc.net>; David Wallingford (david996@yahoo.com) <david996@yahoo.com> Subject: RE: CIRI P & A well status Guy, Following is an update on the status of each of the CIRI wells, formerly operated by Aurora Gas: Aspen 1(WDSPL)—PTD 205-111: An MIT was performed on the well on 10/14/18, the temporary tubing plug was pulled, and the well was cleaned out with slickline bailer. Produced water disposal was commenced soon thereafter, and 473 bbl of produced water was injected into the well for disposal in 3 days October. Another 2486 bbl of produced water, returned packer fluid (while cementing or testing), and cement rinsate were injected in 13 days in November. The well and injection facility was then winterized and shut-in pending commencement of plugging operations in the spring of 2019. Kaloa 2—PTD-204-096: A CIBP was set in the tubing at 2331' on 10/26/18. The tubing and IA were pressure tested to 1775 and 1700 psi, respectively on 10/31/18 (witnessed). On 11/7 35 bbl of cement were pumped of planned 49 bbl— ran out of cement. Shut down and tested in AM—tubing to 1650 psi and IA to 1700 psi. Submitted request for remedial procedure, which was approved. Barge delivered additional cement. On 11/10/18, cement was tagged in tubing at 373', perforated tubing at 370-373', and cemented down tubing with 11.7 bbl of cement, with cement to surface after 8.5 bbl. On 11/15/18, pressure tested tubing to 2175 psi and IA to 2300 psi. No further activity was performed pending cutting off casing this spring. Simpco Moquawkie 1—PTD 178-047: the pretest of the tubing and IA in late October indicated a casing leak. A temperature survey was performed while pumping down the IA, and a casing leak was indicated at 2122-46' (old squeeze perfs). A revised cementing procedure was submitted to the AOGCC and approved. On 11/3/18, the well was cemented by pumping 1 bbl down heater string, 112 bbl of cement down the tubing until cement returns at surface, then IA was shut in and 1 bbl of cement was squeezed into old squeeze perfs resulting in a squeeze pressure of 1700 psi. On 11/8/18, the tubing and IA were tested to 1800 and 2550 psi, respectively. No further activity was performed pending cutting off casing this spring. Simpco Moquawkie 2—PTD 178-088: Tubing and casing were pressure tested (witnessed) to 1600 and 1550 psi, respectively on 10/24/18, and the tubing was perforated at 5209' on 11/5, as sliding sleeve could not be opened. On 11/6, the well was cemented: 10 bbl were pumped down OA, then 193.6 bbl of cement were pumped down IA and up tubing to surface. The tubing, IA, and OA were pressure tested on 11/8 with final pressures of 2900, 3050, and 3050 psi. respectively. No further activity was performed pending cutting off casing this spring. Mobil Moquawkie 1—PTD 203-069: Pressure tests of tubing and IA were performed and witnessed on 10/15/18. The sliding sleeve at 2513' was opened and on 11/2/18 the well was cemented with 195.5 bbl of cement slurry pumped down the tubing with cement to surface out the IA. On 11/9, the tubing and IA were tested to 2450 and 4060 psi, respectively. No further activity was performed pending cutting off casing this spring. Moquawkie 3—PTD 205-080: The well was cleaned out with slickline between 10/17 and 10/22, and a CIBP was set in tubing at 1410'. On 10/27, the tubing and IA were pressured tested (witnessed) to 2000 and 1650 psi, respectively, and the tubing was perforated at 1380'. On 11/1, the well was cemented with 36 bbl of cement pumped down the tubing, with the IA shut in after 30 bbl pumped and 6 bbl was squeezed into open Beluga perfs at 1402-69'. On 11/8, the tubing and casing were pressure tested to 2225 and 1500 psi, respectively. No further activity was performed pending cutting off casing this spring. Moquawkie 4—PTD 207-084: Pressure tests of the tubing and IA were performed and witnessed on 10/30/18—the tubing to 1725 psi and the IA to 1750 psi. On 11/4/18 the well was cemented with 37.3 bbl of cement down tubing and out IA. On 11/8/18 the tubing and IA were pressure tested to 1450 psi and 2000 psi, respectively. No further activity was performed pending cutting off casing this spring. Lone Creek 1—PTD-198-084: Closed sleeves on 11/3/18 and set CIBP in tubing at 1780'. On 11/16/18, pretested tubing an IA, and pumped 15 bbl down OA at 1 BPM. On 11/18/18, tested tubing to 1780 psi and IA to 1700 psi (witnessed). Opened sleeve at 1745'. Prepared to cement as per approved procedure in Sundry, except will likely use light -weight cement to fill IA instead of viscous spacer. Lone Creek 3—PTD 205-097: 11/2-11/5/18 closed all sliding sleeves in the well (PX plug in bottom packer at 2841' from previous operations, so tubing is closed to all perforations). On 11/17/18, tubing and IA were pressure tested (witnessed), tubing tested to 2080 psi and IA to 1500 but dropped to 1225 in 30 minutes—packer leak is suspected. Revised procedure was submitted to AOGCC to add a second plug below top packer on 11/26/18, which was approved on 12/11/18. Lone Creek 4—PTD-207-084: All sleeves are closed and there is a PX plug from earlier operations at 2057'. On 11/17, the tubing and IA were tested (witnessed) to 2200 and 2100 psi, respectively. The tubing was perforated above and below the top packer at 1078-81' and 978-81' in preparation to cement as per procedure. The plan forward is to mobilize in late April or early May depending upon the Schlumberger cementers availability, barging access, and road conditions. At that time, the 3 Lone Creek wells will be submitted as per procedures (approved revised procedure of #3 and an additional 35 bbl of light -weight cement will be pumped in the Lone Creek 1 instead of viscous spacer), which should take 7-10 days, including West Side mobilization and set up. The Wach saw will be mobilized at about that time, the well heads removed and the casing cut off, any top -off of cement will be done, steel plates welded on, and the cellars backfilled. Please let me know if you need additional information. Thanks, Ed J. Edward Jones Petroleum Consultant 4645 Sweetwater Blvd., Suite 200 Sugar Land, TX 77479 713-899-8103(C) 281-495-9957, ext 201 (0) 832-999-4382(F) From: Schwartz, Guy L (DOA) [mailto:guv.schwartz@alaska eov) Sent: Monday, March 04, 20191:30 PM To: Ed Jones <> Cc: George Pollock <gpollock@aurorapower com> Subject: CIRI P & A well status Ed/George, I never received a final update on the work that was done on these CIRI wells.. last update was in first week of November. I recall you requested a temporary shutdown of operations until spring to finish the wellhead cutoffs. don't have an email or any documentation that I can find for this request. You are requested to Provide an update on each of the wells current status and detail Your plan to return and finish the P & A wellwork. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to You, contact Guy Schwartz at (907-7931226) or (Goy schwartz@alasko aov). MEMORANDUM 0 State of Alaska Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Alaska Oil and Gas Conservation Commission '-7) TO: Jim Regg 11t P.I. Supervisor 'C C� r t $ DATE: Tuesday, November 13, 2018 SUBJECT: Mechanical Integrity Tests AURORA GAS LLC BBL Returned: t.� - OA 1 �.. — - -- 4 FROM: Guy Cook MOQUAWKIE 4 Petroleum Inspector Notes: MIT -IA. __j_7 Tested pre P&A as per Sundry 31$ 33_6. Src: Inspector Reviewed By:��pp��,, P.I. Supry V -- NON -CONFIDENTIAL Comm Well Name MOQUAWKIE 4 API Well Number 50-283-20120-00-00 Inspector Name: Guy Cook Permit Number: 207-084-0 Inspection Date: 10/30/2018 Insp Num: mitGDC181106071747 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well 4Type 1. In� N TVD tztl Tubing PTD 2070840 'Type Test SPT Test psi 1500 IA o 0 0 0 0 ins 1725 - lns — BBL Pumped: p BBL Returned: t.� - OA 1 �.. — - -- 0� 0 0 0 _ _ Interval OTHERP PAF �- Notes: MIT -IA. __j_7 Tested pre P&A as per Sundry 31$ 33_6. Tuesday, November 13, 2018 Page 1 of 1 MEMORANDUM • TO: Jim Re � P.I. Super isor e�rl 1(11tj, FROM: Guy Cook Petroleum Inspector NON -CONFIDENTIAL • State of Alaska Alaska Oil and Gas Conservation Commission DATE: Tuesday, November 13, 2018 SUBJECT: Mechanical Integrity Tests AURORA GAS LLC 4 MOQUAWKIE 4 Src: Inspector Reviewed By: P.I. Supry Yg2-- Comm Well Name MOQUAWKIE 4 r API Well Number 50-283-20120-00-00 Inspector Name: Guy Cook Permit Number: 207-084-0 Inspection Date: 10/30/2018 Insp Num: mitGDC181106072053 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well4 PTD 2070840 Type Inj - Type Test N SPT TVD Test psi 1711 1500 Tubing IA 0 0 1725 30 1725 30 1725 50 BBL Pumped: 1 0.7 'BBL Returned: 0,7 OA 0 0 0 0 Interval - OT R - P/F P VI Notes: MIT -T. Tested pre P&A as per Sundry 318-336. $CANNrO J 11 Tuesday, November 13, 2018 Page I of 1 THEOATE 01ALASK-A GOVERNOR BILL WALKER George Pollock Consultant Plugging Inlet, LLC 6733 South Yale Avenue Tulsa, OK 74136 Alaska Oil and Gas Conservation f.o SCANKV Auf s o 7o1$ Re: Moquawkie Field, Undefined Gas Pool, Moquawkie 4 Permit to Drill Number: 207-084 Sundry Number: 318-336 Dear Mr. Pollock: 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.cogcc.alaska.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. 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. Sincerely, Hollis S. French Chair -4 DATED this Z� day of August, 2018. RBDMS`21UG 2 9 2018 0 STATE OF ALASKA ALASKA OtL AND GAS CONSERVAT40N COMMISS40N APPLICATION FOR SUNDRY APPROVALS 20 AAC 2528'0 F14 EE C E ivy * E D AUG 0 8 2018 '2- AOGCC 1. Type of Request: Abandon ❑ Plug Perforations Fracture StilmulateEl Repair Well F] Operations shutdown ❑ Suspend ❑ Perforate Q Other StimulaleEl Pull Tubing ❑ Change Approved Program Plug for Redhil ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ After Casing ❑ Other. Temporary Plug ❑ 2. Operator Name: 4- Current WeftClass: 5. Permit to Drill Number: Plugging Inlet, LLC Exploratory El Development Stratigraphic E] Service Fi 207-0B4 . 3. Address: 6733 South Yale Avenue 6, API Number' Tulsa, OK 74136 50-283-20120-00 7. If perforating- a. Well Name and Number., What Regulation or Conservation Order governs well spacing. in this pool? Moquawkie #4 Will planned perforations require a spacing exception? Yes El No E] 9: Property Designation (Lease Number): 170- Fieid/PooRs): C-061390 * Moguawkie Undefined Gas 11. PRESENT WELL CONDMOK SLUMARY Total Depth MD (11): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 3450' - 3450' 3396' 3396' 950 psi None None Casing Length size `1111113 TV13 Burst Collapse Structural Conductor W 13 3/8* 68# K55 W W 3450 psi 1950 psi Surface 8511' 9 51W 40# L20 850' &W 5120 psi 2370 psi Intermediate Production 3450' 7"23# NW 3450' 3450' 4(140 psi 4910 psi Liner 11 1 11 Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Ttitkq Grade. Tubing MD (ft): 1745'- 2879' 1745'- 2879' 2 7/8" 1 6.5# J55 2887' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (fty. HRP, Hydraulic set and mechanical set Packers HRP @ 1706', Ffydraubc @ 2064', Mechanical 2546' and Hydraulic @ 2676' 12. Attachments: Proposal Summary E Wellbore schematic [A 13. Well Class after proposed work: Detailed Operations Program [Z BOP Sketch [] Exploratory D Strafigraphic ❑ Development P1 Service ❑ 14. Estimated Date for TBD 15. Well Status after proposed work: Commencing Operations: OIL El WINJ El WDSPL F1 Suspended ❑ 'GAS f—I WAG R GSTOR El SPLUG F-1 16. Verbal Approval: Date: Commission Representative: GtNj El Op Shutdown E] Abandoned 2 - 17. 1 hereby certify that the foregoing is true and the procedure approved 7;;i;n will not be deviated from without prior written approval. Authorized Name: George Pollock Contact Name: George Pollock Authorized Title: Consultant Contact Email: gpol look eaurora power. Com ContactPhone: 907-351-8286 Authorized Signature: Date: 6 -Aug -18 COMMULSM USE ONLY ,*ooNofify Commission so that a representative may witnessry Number Conditions of approv ;� � L Plug Integrity BOP Test E] Mechanicallr4egrityTe-st ❑ Location Clearance A -t-o -r -s -ro r-• P Other: cc- wyr-om is r , sbc ps., '5 *0 �1'16r +0 C0-w-WLe%A-+.-. +b -;Mce At -So W 17-Aj,--- '5S C_ 6M IEW r rd' Stj r ;tsc e - Post WtiallnjectionMIT 'Reqd? Yes 7 No F] Spacing Exception 'Required? Yes E] NO Subsequent Form Required: b - APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: RBDMSarWub Z 9 201&bmk Form and Form 1"03 Revised4/2017 Approved aWQ4j4G+ "Lfrtatnhe daft of M oval - t'r tg Is Duplicate • CURRENT CONDITONS: • =AUFGRA SAS, -LLC WELL ABANDONMENT MOQUAWK/E #4 \ Atiniscf 7n47 Version 1:0 (8/23/1.7) Max SITP-720 psi. KB= 15.2 feet CASING: 5-1/2", 17# J-55 set at 3427'MD/TVD. Cement Retainer set at 3259'. PBTD=3396' TUBING: 2-7/8", 6.5# J-55 8 rd EUE, w/ 11.1 ppg NaBr-NaCl brine as packer fluid in tbg-csg annulus -above top_packer and -with: Sliding Sleeves at: WXA at 1-711' (closed—opens upward—now closed with PX plug set in profile); WXO at 1810' (now open); WXO at 1937' (open); WXO at 2101' (now open); WXO at 2259' (now open); and WXO at 2642'; and 2.31" X nipple at 2692' (now open). Packers: PHRP's at 1711', 2064', and 2676' and with Arrowset IX at 2546' (between last two HRP's) with On -Off tool at 2546'. 3=U2" -Screens at: 2787' to 2847'-w/`bull-plug at 2818' Last -known sand fill at 2273'. (See attached well bore and completion diagrams) CAPACITIES: 2-7/8" 6.5# Tubing: 0.00579 bbl/ft; Tubing -Casing Annulus: 0.0152 BPF; 5-1/2", 17# Casing: 0.0232 bbl/ft. Tubing volume to Bull Plug below bottom packer= 16.7 bbl, Annular Volume to tap Packer= 26.0 bbl; -to deepest -packer= 65.3 bbl -(bottoms -up); Casing Volume to Arrowset Packer at -3083'= -71.5 -bbl. PERFS: Carya 2-1.1 at 1745-85' and Carya 2-2.1 at 1948-58', 1972-76', 1980-85' behind sleeves at 1810' and 1937' Carya 2-2.3 at 2106-11'; 2116-21'; 2140-50', & 2166-76' and Carya 2-3.1at 2254-74' behind sleeves at 2101' & 2259' C:arya 2-4.1 at 260 0-1-51 & 2637-47' behind slee p at 2642' Carya-2-4.2 at 2702--22" &/732 32' and 1* 0 g" Carya 2-5 at 2874-79' behind screens at278.7-2847' ' Below cement retainer at 3259' Carya 2-6 at 3306-26' and 3322-37' NOTES: 1) Well is a straight hole. ZUMN1A-RY-UF=P1A-N:-RU_slickline. _RIH-and ,_ pull, prong _and_plug_atA706'. Opensleeve_at 1706' and clump 11.1 ppg NaBr-NaCl brine into tubing to kill well—add additional clean produced water (or 3% KCl) 'to tubing and annulus to fill if needed to kill (not likely). Run gauge ring on slick line and tag-tluid-level and bottom. -Close all sliding sleeves.'(Eill-is-known to be -above at least one sleeve and the,packer at -2676'). Fill tubing and casing with clean field paroduced water or XCI water. Run CIBP for 2-7/8" tubing and set in top of top packer at 1711'. Test CIBP to 1500 psi. Run tubing perforating gun and perforate tubing at 1700' with 4 SPF. RU cementers on tree (thru wing valve). Establish circulation pressure with 5-10 bbl KCl water at 3 BPM. Pump 190 sx (219 cf-38.9 bbl) Class G cement (15.8 ppg, 1.15 cf/sk yield) with pump time of 4 hr at 70 degrees -3% excess and displace to surface—this one balanced plug is to meet the requirements of: 1) plug for perforated -intervals, 2-) surtace casing shoe, and 3') surtace;plug. Monitor for flow or tall -back. Waste out tubing casing annulus to 34' below GL. WOC 8-hrs, pressure test to 1-500 psi. Bleed off pressure. MI crane. Remove tree. Cutoff casing strings and tubing 34' below GL. Mix any cement needed to fill any casing sting or tubing to cut-off. Weldon 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. i1h el"40JIM 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), slickline/electric line 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 slick -line 4 lubricator on tree. RIH and _pull prong from uPXplug at 1706' KB. Allow=pressure to equalize (expect maximum of 720 psi). Check lubricator and tree for leaks. If none, pule PX plug body. 4) Kill well by opening sleeve at 1,706' and dumping I L1 ppg NaBr-NaCl packer fluid, from annulus into tubing. Allow tubing to stabilize, bleed off pressure. Add clean produced water or 3% KCl water to fill tubing and casing if needed to kill well. (Volume to deepest open perfs is about 18 hhl—however fill is oxnPr.ted nt nhmit ?27(1' volume to that depth is 13 hhll_ -5) °Run2.25" -gauge -ring (GR)=tozheck-for-fluid_level-and-tag°bottom (expected °to° e-above2273, where hard fill was found in Dec. 2015, the lass time .fill was tagged). 1f restrictions are found, run bailer, brushes, etc. to -cleanout to about 2270' to close -sleeve at 2259'—if feasible. 6) 8114 with shifting tool. Close sliding sleeves at 2642' (if not below fill), 2259' (if not below fill), 2101', 1937', and 1810'. If tubing is open to 2692', which is not expected, set PX plug in profile at 2692'. Fill tubing and casing—close sleeve at 1706'. Pressure up on tubing to 1500 psi to confirm +-[,-+ ,11 11<.,,,>A- . -1,..,,..1 DAIA.,-A ,, DTl -lll,LLL_all-.lk4aJ.vh.o-ui-\. �lV JLu. AAA,1-,LL FLi-4A.JJu1-'.-1.\lJ-Jllirltllli\.-�u VtYLtultJ�. -7) _RU electric=line lubricator -(see Notes below for -possible -alternative methods -of accomplishing this same result). PU CIBP for 2-7/8" CIBP, RIH and set inside top packer at about 1711`'. POOH. Pressure test CIBP to 1500,p . Release pressure. PU 1-1/2" gun with 4 SPF for large holes, RIH, tag CfBP, pull up to 1700' and perforate 4 shot in I' at 1700'. POOH. 8) COMBINATION PLUG: RU cement pumper on wing valve of tree. Open casing valve (tubing - casing annulus) and pump 10 bbl into perfs with KCl water down tubing and establish circulation and pressure ai 3 -BrM— NOTE: annular Fluid is _1-1: i ppg nor-twaCi nr>ne—catch and use subsequent wells.Mix and pump 190 sx-ClassG cement (accelerated for 4 hours pump -time at 70 degress,15.8 ppg, 1.15 cf/sk yield) down tubing, circulating cement to surface (3% excess). Catch t (i W t -r N 0,57's 36 IM-% W �, t} VL: -v -rtar E.SAi"Lt annular urine tor -use -in subsequent -wells, divert -to open tank as soon as -returns are cementcolored. This -is to be a balanced plug—monitor for flow or fallback. 9) When cement top is stable, disconnect cementer. Washout tubing, and tubing -casing a ulus to 3- 4' below GL. WOC 8 hours. Pressure test both sides (tubing and annulus) to 1500 pst. Release pressure. MI crane. Remove tree. Cutoff conductor, surface, and production casing strings and tubing 34' below GL. Mix any cement needed to fill any casing sting or tubing to cut-off. Release cementers and slickline units to next location. 44 , o6c-f, -m &#J+TxhzS I )Tabricate'%a steel -marker -.plate captor -9-5/8" conductor casing,-not'to extend -beyond casing OL), and -bead -weld the following information onto marker plate; Aurora Gas, LLC - -- PTD # 207-084 Moquawkie No. 4 API # 50-283-20120-00 –evP z' f" -s' if 11) Following any necessary inspections, remove cellar and bury marker. Dispose of any waste. Haul -KCI-water, tanks, and any support equipment to -next location. -1 -2) -Remove tree and casing/tubing cut-offs, surface production equipment, trash, and any other materials from the location. Clean up grade and level location. Take soil samples and send to lab to confirm no contamination. NOTES: 1) Will check with slickline company about setting CIBP on slickline. If so, we will use slickline Kinley punch (or similar) to perforate tubing at 1300', eliminating the need for an electric line unit. -2) Also, looking at the possibility of cementing through the ports of the upper sliding sleeves, which are very close to proposed tubing perfs, instead of adding perforations to tubing. 3) Another possibility is to reset the PX plug in the X profile in the uppermost sliding sleeve instead of using CIBP's. However, because the profiles are above the ports, if this is done, it rules out Note 2 above, so the tubing would be perforated just above the PX plug. 4) The feasibility and cost of these options will be reviewed. However, whatever method is -used, the bottom of the;plugs-will tie -very close to the depths -in the -text -above. Ed Jones (8/23/2017) • Aurora Gas, LLC Moquawkie #4 CURRENT COMPLETION since August 18, 2010 AFI# 50-283-20120-00-4V PTD #207-084 KB—15.2ft Updated Dec, 2016 Drill 12-1/4" Hole to 850' 2-7/8" x 5-V:" annulus displaced with inhibited packer fluid 11.1 ppg NaBr/NaCl to 1,711' Beluga —not completed • 2 7/8 6.5#8rd EUE J-55 Tubing KB 15.2' 13-3/S" 68# Structural Conductor driven to 80' 9-518" 36# Surface Casing set at 850' Cement w/-14.5-ppg Gas -Block enhanced XASliding sleeve @1,706' Tyonek Tops Carya 2.1-1,734' , HRP Packer @°1,711' Carya 2-2 — 1942' Carya 2-1.1 Carya 2-3 — 2230' 1745-85' Carya 24.2 -- 2,790' XO Sliding Sleeve @ 1,810'(open) Carva 2-6 — 3303' Cary* ,Z 21 1948.58' XO Sliding Sleeve @ 1,937'(open) 1972-76' 1980-98, Hydraulic -set Packer @ 2,064' Carya 2-2.3, 2106-11' . t XO Sliding Sleeve @ 2,101'(open) 2116-21' 2140-50' 2166-76' XO Sliding Sleeve @ 2,259' (open) 12/4/15-4ag hardJill at 2273' Carya 2-3.1 2254-74' On/Off too[ @ 2,540' Arrowset Mechanical -set Packer Carya 24.1 (d -2—UW 2600-15' Sliding Sleeve @2642'(open) 2637-47' x, F -` Hydraulic -set Packer 2,676' XN Nipple (g 2,692' Carya 2-41 2702-22' 2-7/8 x 3-1/2" NU XO @ 2,787' 2732-52' 69111 of 3.5" screen 30/50 mesh Q XO 1 it 3-112" tubing and Bull Plug at rel. 2,878' Jan 2015—tag at 28W. Carya 2-5 2874-79' Cement Retainer @ 3,259" Carya 2-6 3306-26' 5 K" 15.5# J-55 Casing to 3,427' MD (TVD) 3322-37' Drill 7-7/8" Hole to 3,450' Estimated PBTD @ 3,396' 4; Aurora Gas, LLCM 2 7/8 6:5# 8rd EUE J-55 Tubing ;KB 75.2' Moquawkie #4 PROPOSED PLUG & 13-3/8" 68# Structural ABNADONMENT Conductor driven to 80' AP1# 50-283-20120-00-1— ) PTD #207-084 $7' f 9-518" 36# Surface Casing set at 850' enhanced KB-15.2ft $,l �i' /� / 14.5 ppg Gas -Block August 2017 Drill 12-1/4" Hole to 850' 2-7/8" a 5 -Ss" annulus displaced COMBINATION PLUG (PERFS, with inhibited packerfluid llcl SURFCSG SHOE, AND ppg NaBr/NaC1 to 1,711' whieh SURFACE) -190 Sx Class G Cement will be used to kits well and wi11 (15.8 ppg, 1.15 cf/sk) remain -in tubing and across perfs when P&A'd. Beluga -not conWleied Tyonek Tops Carya 2-1 -=1,734' Carya 2-2 - 1942' Carya 2-3 - 2230' Carya 24.2 - 2,700' Carva 2-6 -- 3303' Carya 241 1745-&4' Cary& 2-2.1 1948-58' 1972-76' 1980-88' Carya 2-2.3 2106=11' 2116-21' 2140-50' 2166-76' Wow Carya 2-3.1 2254-74' Carya 2-4.1 no 2600-15' 2637-47' Carya 24.2 2702-22' 2732-52' Carya 2-5 2874-79' Carya 2-6 330626' Estimated PBTD @ 3,396' 3322-37' Set CHIP at 1711' and Perf Tubing at 17fl1W XA Sliding sleeve aA 1,706' 1 HRP Packer @ 1,711' XOSWxgSteeve.@ 1,810'(open) XO Sliding Sleeve @ 1,937(open) Hydranfic-set Packer (a) 2064' XO Sliding Sleeve @ 2, 1 01'(open) XO Sliding Sleeve @ 2,259' (open) 1247 1417 5 --flag hard frll at 2273' On/Off tool @ 2,540' Arrowset Mechanical -set Packer @-2,546' Sliming Sleeve @ 2642'(open) Hydraulic -set Packer @ 2,676' XN Ninnte (a7 7-692' 2-7/8 x 3-1/2" NU. XO *2;787' -60ft of 35" screen 30/50 mesh XO I jt 34/2" tubing and Buil Plug at 2,878' Jan 2015 --tag at 2835'. Genettetainer{)a 3,259" Drill 7-7/8" Hole to 3,450' 5-h" 14.5# J-55 Casing to 3,427' MD (TVD) 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 backdated 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, Dick Rowland Land & Natural Resources Manager Tyonek Native Corporation (907) 646-3121 Direct (907) 272-0707 Main rrowland@tyonek.com www.tyonek.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 AIJOA OIL AND GAS CONSERVATION COM ION REP'ORTDF SUNDRY WELL OPERATIONS JAN 2 3 2018 1.Operations Abandon U PlugPerforations U FractureStirmAate M Pawl Tubing vown Perfrnned: Suspend Q Perforate ❑ Cather S*mAate El Alter Caswg Q Changie Approved Program Q Plug for Redng Q Perforate New Pool ❑ Repair Wen Q Re-enter Susi.well Q Temporary Plug Q 2."Operator Aurora Gas, LLC 4 Well Class Before Work: 5: Permit to DAW Nuradaer Name: Dever Q Expilwatory [ S'1 atigraphic Q Service Q 207-084: 3. Address: 3705 Arctic Blvd. #2114 Ar age, AK 99503 6- API Numbw: 283-20120-00 7. Property Designation (Lease Number): 8. Well Name and Number: C-061390 Moquawkie #4 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): NA Moquawkie Undefined Gas 11. Present Well Condition Summary: otai pth : roeasurecf:3iE5D "feet Rugs rneasurecl ; S7 : feet true vertical 3450 feet Junk measured None feet Effective Depth rrreasured 3396 feet Packer measured 1706 - 2676 feet )rue vertical 3396 'fest true vertical 1706 - 2676 feet Casing Length Size MD TVD Burst Collapse Structural Conductor ;80 .13718 fib# K65 � 80 -80 3450 W, ,196ttk psi' Surface 850 a x/8'40# L80 850 850 5120 psi 2370 psi Intermediate Production 3450 7 23# N80 3450 3450 4040 psi' 4910 psi Liner Perforation depth Measured depth 1745 - 2879 feet -17wei.Vettic al tleoth i`t745 --,2M "feet Tubing -(size; grade, measured and true vertical,depth) 27/8 6.,5# J55 2887 2887 Packers and SSSV(type, measured and true vertical d4pth.) 12. Stimulation or cement squeeze summary: Intervals treated (measured): .NA � pNU�I�t+ C ra t!. a sul Treatment descriptions including volumes used and frnatpressune: NA 13: Representative Daily.Average Production or Injection Data Oil lt#�i Gas-Mcf = Water,-BbI Casiog, Pressure i Twbiti%Pressur Prior to well operation: 0 10 1690 Subsequent to operation: 0 10 10 14. Attachments (required per 20 AAC 25.070, 25.072, & 25.283) 15. Well Class after work: Daily Report of Well Operations P] Exploratory Q Development Q Service Q Stratigrawc Q Copies of Logs and Surveys Run Q 16. Weil Status after work: Oil ElGas [Z WDSPL [� Printed and Electronic Stimulation •Data Q GSTOR `E]WNJ -E] WAG L] Gnu ❑ 3USP O SPLUG Q 17. 1 hereby certify that the fon3going -is true and, correct to the best of my knowkKige. Sundry Number or N/A if C.O. Exempt: 317-274 Authorized, Naive: George Pollock Contact Name: Authorized Tittle: M - Prod Ops 8 EM Com! mail: gpoilock0auroraoower.c� Authorized Signature: -- �?—a Dat: 1/23/2018 Contact Phone: 907.351.8286 Form 10-404 Revised 4/2017 )� t-/4 /), ,& YZ4// $' R Q D M S �/ — J F`,` "? 1, 2-J18 Suburd Onginat Only Auror--wG"-,(;LLC Operations Summary — Set Temporary Plug, Moquawkie #4 Well -ju!y--7A,--2017 1100 hours Move to location from M1 1115 hours R/U WL, PT lubricator w/wellbore -1 -13=0;hours ;RIH --w-12.4" -brusk-to-brush--profile in -ale -eve, iP-QOH y - 1200 hours RIH w/2.33' gauge ring to, 23151 KB, tag profile in sleeve,. POOH 1230 hours RIH w/2-7/91' X -line w/ PX Plug to 1715', WT, set plug, POOH 1330 hours RIH w/2" SB w/Prong to 1715', WT, set Prong, POOH 4400 hows Meedoltwell,-,snowtor Pressure- 3Wminutes, Pass 1430 hours RD WL, Mob to SM1 i 0 :Aurora Gas, LLC Mogaawkie #4 Workover Completion August 123, 201,0 API# 50-2233-20120-00 PTD #207-084 KB —15.211 Updated July 2017 Drill 12-1/4" Hole to 850' 2-7/8" x 5-%" aaanlns displaced with inhibited packer fluid 11.1 ppg NaBr/NaC! to 1,711' Beluga -not completed Tyonek Tops Carya 2-1 - 1,734' Carya 2-2 -1942' Carya 2-3 - 2230' Carya 24.2 - 2,7W Carva 2-6 - 3303' Estimated PBTD @ 3,3%' Carya 2-1.1 17454$5' Carya 2.2.1 1948.58' 1972-76' 1980,88' Carya 2-2.3 2106-11` 21161 2i' 2140-50' 2166-76' Carya 2-3.1 2254-74' Carya 24:1 2606-15' 2637-47' Carya 21.2 27e2-22' 2732-52' Carya 2-5 2874-79' Carya 2-6 3306-26' 3322-37' 2 718 6.5418rd EUE J-55 Tubing K8 15.2' 13-3/8" 68# Structural. Conductor driven to 80' 9-5/8" 36# Surface Casing set at 850' Centel w/ 14:5 ppg Gas, -.Block enhanced p 1-71 XA MAW sleeve e* 1706' HRP Packer C 1,721' PX Plug @`1715' XO Sledging Sleeve 1,81'(open) XO SHAng Sleeve @ 1,937'(open) 4lydrauise-set Packer @ 2,%4' XO MAW Meeve a*? 2,1e1'(open) X0 Sliding Slees+e!a 2,239' (open) 1214115—tag kard fr/l at 2273' OR/Off tool a�. 2,540' Arrowset Mechanical -set Packer tea, _2,595' Sliding Sleeve @ 2642' {open) HydranGc-set Packer 2,676' XN Nipple (a 2,692' 2-7/8 x 3-1/2" NU XO 02,787' 60ft o13.5" screen 3W-'% mesh XO I it 3-1/2" tubing and Bull Plug at 2,878' Jan 2815 --tag at 2835'. Cemem Retainer@ 3,259- 5 %-15.5# J-55 Casio to 3,427' MD (TVD) DrIB 7-718" Mic to 3,450' THE STATE 9410 1 WIE GOVERNOR BILL WALKER George Pollock Alaska Oil and Gas Conservation Commissio~: Manager SCANNED F!' ! n Aurora Gas, LLC 1400 W Benson Blvd., Suite 410 Anchorage, AK 99510 Re: Moquawkie Field, Undefined Gas Pool, Moquawkie 4 Permit to Drill Number: 207-084 Sundry Number: 317-411 Dear Mr. Pollock.: 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Enclosed is the approved application for 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, /-u 10�� Cath P. Foerster Commissioner DATED this 6 day of September, 2017. RDDMS V- SFP - 7 2017 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25 28 RECEIVED AIJG 2�5�01 075 U17 AOGCO 1. Type of Request: Abandon Plug Perforatiom Fracture Stimulate Repa r 'Ne Operations Vhutdowm Suspend Perforate Other Stimwale Plug for Redrill ?erforate New Pool --j: Re-enter Suw Well Alter Casa i; iDl-rer, I einccrary P�ug 2. Operator Name- 4, Current Viet, Ciass e-, Aurora Gas. LLC Exploratory Development Stratigraphic Sev-ce 3. Address- 1400 W. Benson Blvd, Suite 4'i 0 Anchorage. AK 99503 7, If perforafirtg: 8 Avell %awe and N!Urnne' What Regulation or Conservation, Order governs wL-,i spacing in th4s -Moquawkie #4 Will, planned perforations require a spacing exception? Yes No 9. Property Designation (Lease Number): 10 Feid/PooNs) C-061390 - I aii Undefrp-< Gas 11 PRESENT WELL 00NOITICiN SUMMARY Total Depth MID (11). Total Depth TVD Effective Depth MD: Effective Depth TVD MPSP fpsi)] 17 -gs Vl-� -UnR WC�' 3451,)' 3396 33%-' 9500s, I Nor"e casing Length size No TV0 Bust Collapse Sfructural Conductor W, 13 ZIB' 68* K55 801 341 1K S; 1.950 psi Surface 850' 9 5JB' 40* J30 850' 653, r;is• -j37G Ds Intermediate Productiop, 3450' 7' 23* N80 C Liner — Perforation Depth MID (ft): Perforation Depth TVD (ft) F;70-1—al [TubSize I Tubftpg - Grade! 1 -U0 i --g 1745'- 2879' 745' - 2879' 2 7/8' 6 5 -- Packers and SSSV Type. Packers and SSSV MID (ft) and TVD t HRP. Hydraubc set ano -,^echartical set pacxers HRP @ 17ydr a4UijC C 2064!, Tv ecr ar :a 2:5�' ane 2676 12, Attachments: Proposal Summary Wellbore schematic 113. Well Class after proposed work Detailed Operations Program BOR Sket& lExploratory Stratigraw, C se, z ce 14. Estimated Date for TBD 115. Well Status after proposed work Cornmenang, Operations 104Lv W -IN - #GASWAG Gs --CR 5. 16. Verbal Approval: Dale, Commission Representative. l&N, 17. 1 hereby certify that the foregoing is true anc the procedure approved herein wilt not be deviated from without Prior written approval I Authorized Name George Pollock Contac,r a^ e Gecrige Authorized Title: Manager - PYSOPOPS 4 Contact;E-I'a.` Comact P-cre 351 'BE Authorized Signature: Date: 24 -Aug-'* 7 COMMISSION USE 014LY Conditions of approval: Notify Commission so that a representative may w.triess Plug Integrity BOP 7est Mechanical mlegnry Test Ciewarioe Other Post }nitiai fnject*n ViT Req'c? Yes INC .7 Spacing Exception Required? Yes No Subsequent Form Required. RBDMS L SEP 7 2017 APPROVED BY COMMISSIONER THE COMMISSION Date Approved by: mo Ja -a q /3 //# AOfl'10r11' stli Torr IC -403 Rev;SW 4;2017 &Rf &L" ftfar 112 .1tt, from the daW of aW.0val. I" Submit Farm and 4t�4,e-s n'D�Okcate 5� AURORA GAS, LLC • WELL ABANDONMENT MOQUAWKIE #4 August 2017 Version LO (8/23/17) IwURRE.N7 COJN.JD!1TONS: Max SITP-720 psi. KB=15.2 feet CASING: 5-1/2", 17# J-55 set at 3427'MD/TVD. Cement Retainer set at 3259'. PBTD=3396' TUBING: 2-7/8", 6.5# J-55 8 rd EUE, w/ 11.1 ppg NaBr-NaCl brine as packer fluid in tbg-csg annulus above top packer and with: Sliding Sleeves, at: WXA at 1711' (closed—opens upward—now closed with; TAX plug set in profrle); WXO at 1810' (now open) WXO at 1937' (open); WXO at 2101' (now open); WXO at 2259' (now opera and WXO,,at 2642; and 2.31" X nipple at 2692' (now open). Packers: PHRP's at 1711', 2064', and 2676' and with Arrowset IX at 2546' (between last two HRP's) with On -Off tool at 2546'. 3-1/2" Screens at:.2787' to 2847'w/ bull plug at 2878'. Last known sand f ll at 2273'. (See attached we9;l.bom and completion diagrams) CAPACITIES: 2-7/8" 6.5# Tubing: 0.00579 bbl/ft; Tubing -Casing Annulus: 0.0152 BPF; 5-1/2", 17# Casing: 0.0232 bbl/ft. Tubing volume to Bull Plug below bottom packer= 16.7 bbl, Annular Volume to top Packer= 26.0 bbl; to deepest packer= 653 bbl (bottoms up); Casing Volume to Arrowset Packer at 3083'- 71.5 bbl. PERFS: Carya 2-1.1 at 1745-85' and Carya 2-2.1 at 1948-58', I972-76', 1980-85' behind sleeves at 1810' and 1937' Carya 2-2.3 at 2106-11', 2116-21', 2140-50', & 2166-76' and Carya 2-3.1at 2254-74' behind sleeves at 2101' & 2259' Carya 24.1 at_2600-15' &.2637-47' behind sleeve at 2642' Carya 2-4.2 ;at 27,02-22' & 3732-52':and Carya 2-5 at 2874-79' behind screens at 2787-2847' Below cement retainer at 3259' Carya 2-6 at 3306-26' and 3322-37' NOTES: 1) Well is a straight hole. SUMMARY OF PIAN: RU slickline. RIH and pull prong and plug at 1706'. Open sleeve at 1706' aril. dump 1, l,. I ppg NaBr,-N,aCt brim into tubing to kill well,—add additional clean pcodu€edr water (or 3% KCI) to ting and} ammlVs to fill`, if riceded to k%1f (mixt hkel ). Run gauge ring omsfick, line and tag fluid level and bottom. Close all sliding -sleeves. (fill is.known to beabove at least>one sleeve.and,the packer at 2676'). Fill ubing and casing with clean field produced watererr 3% KC1 water. Run CIBP for 2-7/8" tubing and set in trap of top packer at 1711'. Test CIBP to 1500 psi. Run tubing.perforating gun,antl perforate tu'bing::at 1700' with 4 SPF. RU cement owtr$er(hru wing valve). Establish circulation pressure with 5-10 bbl KCl water at 3 BPM. Pump 190 sx (219 cf=38.9 bbl) Class G cement (15.8 ppg, 1.15 of/sk yield) with pump time of 4 hr at 70 degrees -3% excess and displace to surface—this one balanced plug is to meet the requirements of: 1) plug for perforated intervals,, 2) surface casing shoe, and 3) surface plu=g. Monitor for flow or fall back. Wash out tubing casing annulus to 3-4' below GL. WOC & hrs, pressure test to 1500 psi. Bleed off pressure. MI crane. Remove tree. Cut off casing; strings and tubing 3-4' below GL. Mix any cement needed to fall any casing sting or tubing to crit -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: I) Pick and move wellhouse. Notary AOGCC inspector:tofpL-m for plugging operations 2) 'Move in cerner ter }(pump +buddmixer), bulk went (200 sx Class % slic ine/electric dine 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 slickline lubricator on tree. RIH and pull prang from PX plug at 1706' KB. Allow pressure to equalize (expect rnaximum of 720: psi): Cheek lubricator and tree for leaks. If none, pull PX plug body. Kill well by opening sleeve at 17W anddwnaing 11.1 ppg NaBr-NaCl packer fluid from annulus into tubing. Allow tubing to stabilize, bleed off pressure. Add clean produced water or 3% KCl water to fill tubing and casing if needed to kill well. (Volume to deepest open perfs is about 18 bbl—however, fill is expected at about 2270', volume to that depth is 13 bbl). 5) Run 2.25" gauge ring (GR) to check for fluid level and tag bottom (expected to he above 2273, where hard fill was found in Dec. 2015, the last time "fill was tagged). If restrictions are found, run bailer, brushes, etc. to cleanout to about 2270' to close sleeve at 2259'—if feasible. 6) RIH with shift g tool. Close .sliding sleeves at 2,642' if not below fill), 2259' (if not below fill), 2101', 1937', and 1810'. If tubing is open to 2692', which is not expected, set PX plug in profile at 2692'. Fill tubing and casing --close sleeve at 1706'. Pressure up on tubing to 1500 psi to confirm that all sleeves are closed. Release pressure. RD slickline lubricator. 7) RU electric line lubricator (see Notes below for possible alternative methods of accomplishing this same result). PU CIBP for 2-7/8" CIBP, RIH and set inside tap packer at about 1711'. POOH. Pressure test CIBP to 1500 psi. Release pressure. PU 1-1/2" gun with, 4 SPF for large holes, RIH, tag CIBP, puff up to r700,' andperforate; 44'shot in f' at 1700'. POOH: 8) COMBINATION PLUG: RU cement pumper on wing valve of tree. Open casing valve (tubing - casing annulus) and pump 10 bbl into perfs with KCl water down tubing and establish circulation and pressure at 3 BPM— NOTE: annular fluid is 11.1 ppg KCl -NaCl brine—catch and use subsequent wells. Mix and pump 190 sx Class G cement (accelerated for 4..hours pump time at 70 degmss,15.S ppg, 1.15 cf/sk yield)down tubing, circulating cement to surface (3% excess). Catch • 0 annular brine for use in subsequent wells, divert to open tank as soon as. -returns -are cement colored; This is to be a balanced plug—monitor for flow or fall back. 9) 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)` tto1500 vsi. Release 3 pressure. MI crane. Remove tree. Cut off conductor, surface, and production casing strings and o tubing 34' below GL. Mix any cement needed to fill any casing sting or tubing to cut-off. Release cementers and slickline units to next location. 10) Fabricate'/" steel marker -plate cap for 9-5/8" conductor casing, not to<extend .beyond casing OD, ,and bead -well the following information onto marker plate; Aurora Gas, LLC n•.>e.ur.�e-i., c ,. �c, �.� t-� PTD # 207-084 r e�� ct i �-� �•�S t i t'� - %NDC -LO -N Moquawkie No. 4 �r�-t \t� Li`l API # 50-283-20120-00 ��-0 11) Following any necessary inspections, remove cellar and bury marker. Dispose of any waste. Haul KCl water, tanks, and any support equipment to next location. 12) Remove tree and easing/tubing cut-offs, surface production equipment, trash;, and any other materials from the location. Clean up, grade and level location. Take soil samples and send to lab to confirm no contaminatiom NOTES: 1) Will check with slickline company about setting CIBP on slickline. If so, we will use slickline Kinley punch (or similar) to perforate tubing at 1300', eliminating the need for an electric line unit. 2) Also, 4looking at the possibility of cementing through the ports of the upper sliding sleeves, Which are very blose;to tproposed Ytubing ,perfs, instead of adding perforations to tubing. 3) Another possibifity is to reset the PX plug in the Xprofile in the uppermost sliding sleeve instead of using CIBP's. However, because the profiles are above the ports, if this is done, it rules out Note 2 above, so the tubing would be perforated just above the PX plug. 4) The feasibility and cost of these options will be reviewed. However, whatever method is used, the bottom of the plugs will be very close to the depths in the text above. Ed .Tones (8/23/2017) Co., Gvr T w� ll f*&'e''a(Alof 6.0 fity`f qN.� jiff hu f Piodv� .�e /vv /1 cop a-- /Lots 'Q/fry,gre ,00 AO._ ; Aurora GAS, LLQ t J- . MoquavAde #4 CURRENT COMPLETION since August 18, 2010 AP1# 50-283-20120-00 PTD #207-084 KE-15.21it Updated Dec. 2016 Drill 12-1/4" Hale to 8611' VO SYdi" S1eww,i ; 2.259' (open) 2-7/8" x 5'h" annulus displaced 1214115—tag herd jiff at 2273' with ioMbited packer fluid I1.1 On/Off tool 2,540' ppg NaBr/NaCl to 1,711' * ' Beluga -not completed n 2,546 7'youck Tops Sliding Sleeve @ 2642'(open) Carya 2-1 - 1,734' Hydraulic -set Packer @ 2,676' Carys 2-2 -19#2' Carya 2-1-1 X'\ Nipple,.a_1 2,692' Carya 2.3 - 2236' 1745-8:5' 2-7/8 x 3-1/2" NU XO @ 2,787' Cary& 2.4.2 - 2,700' 66tt of 3.5" screen 3M nsesb Carva 2-6 - 3303' Carta 2-2.1 XO 1 it 3-112" tubing and'Ball Plug at 1'448 -Sr 2,878' 1972-7V Jim 21115—tag at 28351. 1986418' Cement Retainer {ai; 3,259' Carya 2-2.3 2106-11' 21116-21' 2140-50' 2166-76' - Carya 2-3.1 2254-74' Carys 24.1 2600-15' 2637-47' 77 Carya 2- 27 2702-222' 2732-52' 1 Cary& 2-5 297479' Carya 2-6 3306-26' 3322-37' Estimated PBTD ^a, 3.396' 0 -` 2 7111 6M 3rd EUC J-55 Tubing KB 15.2' 13-3/8" 68# Structural Conductor driven to 80' I 5 9-5/8" 36# Surface Casing set at 850' ?' Cement wt 14.5 ppg Gas -Block enhanced X3 Slidin sleeve @ I,7w tMP P.M)" @ 1,711' XO Siftding Sleeve @ 1,810'(open) XO SkeOng Skrw @ 1,9371("v.) Hydraulic -so Packer @ 2,*64' , XO Sliding Sleeve * 2,1#1 '(open) ` VO SYdi" S1eww,i ; 2.259' (open) 1214115—tag herd jiff at 2273' On/Off tool 2,540' Arrovrset Mechanical-stt Packer n 2,546 Sliding Sleeve @ 2642'(open) Hydraulic -set Packer @ 2,676' X'\ Nipple,.a_1 2,692' 2-7/8 x 3-1/2" NU XO @ 2,787' 66tt of 3.5" screen 3M nsesb Kt XO 1 it 3-112" tubing and'Ball Plug at 2,878' Jim 21115—tag at 28351. , Cement Retainer {ai; 3,259' 5 'h" 15.4# 3-55 Casing to 3,427' 111) (TVD) L Drill 7-7/8" Hole to 3,450' • 0 $ 2 7/8 6.5# Srd ELBE 3-55 Tab' Aurora Gas, LCC a * ng KB / .,, Moquawkie #4 PROPOSED PLUG & ABNADONMENT API# 50-283-20120-00 PTD #207-084 KB —15.2ft August 2017 Drill 12-114" Hole to SSW 2-7/8" x 5-'/2" annulus displaced with inhibited packer fluid 11.1 ppg NaBr/,NaC1 to 1,711' which will be used to kill well and will remain in tubing and across perfs when P&A'+d. Beluga -not completed Tyonek Tops Carya 2-1 - 1,734' Carya 2-2 - 1942' Carya 2-3 - 2230' Carya 24.2 - 2,700' Carva 2-6 -3303' 13-31r 68# Structural 4 Conductor driven to 89' i } 9-5/8" 36# Surface Casing set at 850' ' Cement w/ 14.5 ppg Cas -dock enhanced coM6lrrATlari PLUG (PE11Fs, SURF CSG SHOE, 4vND t SURFACE) -190 Sx Cla; G Cement (15.8 ppg, 1.15 rusk) 4 { Set CHIP at 1711'=A Perf Tobin at - 1700' XA SVAv slerre (a), 1,766' 1181" Paeiur (n} 1,71 it, Carya 2-1.1 174545' XO Sliding Skew @ 1,810'(open) Carya 2-2.1 1948-58' XOS6d w Sleevr * 1,99377(opeu) 1972-76' Hydrautic-set Packer W 2^4' 1980-88' Carya 2-23 XO SNJ g Sk re * 2, 101'(.p.) 2106-11' 2116-21' 214&50' 2166-76' Carva 23.1 2254-74' Carva 24.1 2600-15' 263747' Carya 24.2 2702-22' 2732-52' Cary& 2-5 2874-79' Carya 2-6 330E-26' D fe3 Estimated PBT3,3%' 3322-37' XO Sliding Sleeves @ 2,259' (open) . - 121411S - -ft haridjW at 2273' ` On/Off tool 2,50' Arrowset Mechanical -set Packer Sk&ng Sleeve* 2642'(apen) Hydraulic -set Packer (a? 2,676' XN '1linmle ,rW 2 692' 2-7/8 x 3-1/2" PIU+ XO @ 2,787' 60ft of 3.5" screen 30/50 mesh XO 1 jt 3-1/2" tubing and Bull Ping at 2,878, Jan 2015—tag at 2835'. Cment Retainer a 3,259' Drill 7-7/8" Hole to 3,450' 5 %" 15.5# J-55 Casing to 3,427 MD (TVD) THE STATE OfALASKA GOVERNOR BILL WALKER George Pollock Manager Aurora Gas, LLC 1400 W. Benson Blvd., Suite 410 Anchorage, AK 99503 Alaska Oil and Gas Conservation Commission scate ,jig 2 6 2.014", Re: Moquawkie Field, Undefined Gas Pool, Moquawkie 4 Permit to Drill Number: 207-084 Sundry Number: 317-275 Dear Mr. Pollock: 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Enclosed is the approved application for 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 kL Chair DATED this day of July, 2017. RBDMS L--- JUL 1 1 2017 1 I • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 JUN 16 91017 , 0GO"' 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair W61 ❑ Operations shutdown ❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ After Casing ❑ Other, Temporary Plug ❑ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number Aurora Gas, LLC Exploratory ❑ Development ❑ Stratigraphic ❑ Service ❑ 207-084 3. Address: 1400 W. Benson Blvd. Suite 410 6. API Number Anchorage, AK 99503 60-283-20120-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? INQ- Moquawkie #4' Will planned perforations require a spacing exception? Yes ❑ No 9. Property Designation (Lease Number): 10. Field/Pool(s): C-061390 Mo uawkie 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): 3450' • 3450' 3396' 3396' 950 psi None None Casing Length Size MD TVD Burst Collapse Structural Conductor 80' 13 3/8" 68# K55 W. 80' 3450 psi 1950 psi Surface 850' 9 5/8' 40# L80 850' 850' 5120 psi 2370 psi Intermediate Production 3450' 7" 23# N80 3450' 3450' 4040 psi 4910 psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 1745'- 2879' 1745'- 2879' 2 7/8" 6.5# J55 2887' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (fty: HRP, Hydraulic set and mechanical set packers HRP @ 1706', Hydraulic @ 2064', Mechanical @ 2546' and Hydraulic @ 2676' 12. Attachments: Proposal Summary ❑ Wellbore schematic ✓ 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development 0 , 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 240e± Eng Contact Email: goollock aaurora power. com Contact Phone: 907-277-1003 Authorized Signature: r Date: 16 -Jun -17 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number 3 (,7 — 2 7 S Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test F1 Location Clearance ❑ Other: 1/�i.W/� LAS Z u�S:'c SWVJ DR, �4A Post Initial Injection MIT Req'd? Yes ❑ No ❑ RBDMS L�- JUL 1 1 2017 Spacing Exception Required? Yes ❑ No Subsequent Form Required: W-404 APPROVED BY 73 Approved by:LL09a==:= COMMISSIONER THE COMMISSION Date: 'C ?#q� WgI /�- �� sv In Form 10403 Revised 412017 irlvlid for 12 months from the date of approval. Submit Form and Attachments in Duplicate Aurora Gas, LLC June 16, 2017 Ms. Cathy Foerster, Chair ECE1 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 "116 2011 Anchorage, AK 99501 AQGQC Re: Application for Sundry Approval — Set Temporary Plug Moquawkie #4 Well PTD #: 207-084 API #: 50-283-20120-00 Dear Ms. Foerster: Aurora Gas, LLC hereby requests approval to set a temporary plug to secure this onshore development well in the Moquawkie Undefined Gas Field on the west side of Cook Inlet, southwest of the Village of Tyonek. This well is currently producing gas from multiple zones in the 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 1,706' 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. The master valve 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. Sincerel 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''` Moquawkie #4 Workover Completion ' August 18, 2010 API# 50-283-20120-00 PTD #207-084 KB — 15.2ft Updated Dec. 2016 , Drill 12-1/4" Hole to 850' 2-7/8" x 5 'h" annulus displaced with inhibited packer fluid 11.1 ppg NaBr/NaCI to 1,711' gy Beluga –not completed Tyonek Tops Carya 2-1 – 1,734'+ Carya 2-2 – 1942' Carya 2-1.1_ 1 = Carya 2-3 – 2230' 1745-85' ' 13-3/8" 68# Structural Carya 2-4.2 – 2,700' Conductor driven to 80' Carya 2-6 – 3303' Cement w/ 14.5 ppg Gas -Block Carya 2-2.1 1948-58' 1972-76' „ 1980-88' XA Sliding sleeve @ 1,706' , a` Carya 2-2.3 HRP Packer @ 1,711' 2106-11' 2116-21' 2140-50' 2166-76'� Hydraulic -set Packer @ 2,064' , XO Slieitng Sleeve @ 2,101'(open) Carya 2-3.1 '+ 12/4/15-4ag hard fill at 2273' 2254-74' Carya 24.1 Arrowset Mechanical -set Packer 2600-15' (a) 2,546' 2637-47' Hydraulic -set Packer /,& 2,676' i s Carya 24.2 60ft of 3.5" screen 30/50 mesh 2702-22' XO 1 jt 3-1/2" tubing and Bull Plug at 2732-52' } Jan 2015 ---tag at 28351. Cement Retainer @ 3,259" Carya 2-5 OR 2874-79' Carya 2-6 3306-26' 3322-37' Estimated PBTD @ 3,396' • 5'/a" 15.5# J-55 Casing to 3,427' MD (TVD) Drill 7-7/8' Hole to 3,450' 2 7B 65# 8rd EUE J-55 Tubing 1 = KB /5.2' t� ' 13-3/8" 68# Structural Conductor driven to 80' 9-5/8" 36# Surface Casing set at 850' Cement w/ 14.5 ppg Gas -Block enhanced �F y A XA Sliding sleeve @ 1,706' , a` HRP Packer @ 1,711' s; *4 XO Sliding Sleeve @ 1,810'(open) XO Sliding Sleeve @ 1,937'(open) Hydraulic -set Packer @ 2,064' , XO Slieitng Sleeve @ 2,101'(open) XO Sliding Sleeve @ 2,259' (open) '+ 12/4/15-4ag hard fill at 2273' On/Off tool @ 2,540' Arrowset Mechanical -set Packer `« (a) 2,546' Sliding Sleeve @ 2642'(open) Hydraulic -set Packer /,& 2,676' XN Nipple @ 2,692' s 2-7/8 x 3-1/2" NU XO @ 2,787' 60ft of 3.5" screen 30/50 mesh y XO 1 jt 3-1/2" tubing and Bull Plug at 2,878' }' Jan 2015 ---tag at 28351. Cement Retainer @ 3,259" 5'/a" 15.5# J-55 Casing to 3,427' MD (TVD) Drill 7-7/8' Hole to 3,450' • 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 %2" tubing with 2.812" X landing nipple profile. Set PXX 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. Z* Saaage (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. <� 0 7 - 03 4 Well History File Identifier Organizing (done) ❑ Two-sided III II�III II III II III ❑ Rescan Needed III IIII(III II III III RESCAN DIGITAL DATA OVERSIZED (Scannable) Color Items: ❑ Diskettes, No. ❑ Maps: yscale Items: ElOther, No/Type: ❑ Other Items Scannable by XreEy a Large Scanner ❑ Poor Quality Originals: r-1 Other: OVERSIZED (Non -Scannable) ❑ Logs of various kinds: NOTES: ❑ Other:: BY: Maria Date: /s/ Project Proofing II I II II II I I III I I III BY: Maria Date: /s/ Scanning Preparation �5 x 30 = + _ n = TOTAL PAGES I 0 Mf (Count does not include cover sheet) BY: Maria Date: /s/ Production Scanning II I I I (I II I I III (III I Stage 1 Page Count from Scanned File: (Count does in::Zsheet) Page Count Matches Number in Scanning Pre aration:ES NO BY: Maria Date: D I ` /s/ M P Stage 1 If NO in stage 1, page(s) discrepancies were found: YES NO BY: Maria Date: /s/ Scanning is complete at this point unless rescanning is required. II I II IIII I II II I I III ReScanned III IIIIII IIIA II III BY: Maria Date: /s/ Comments about this file: Quality Checked III II'lII III II'I III 10/6/2005 Well History File Cover Page.doc DATA SUBMITTAL COMPLIANCE REPORT 3/2/2011 Permit to Drill 2070840 Well Name/No. MOQUAWKIE 4 Operator AURORA GAS LLC API No. 50-283-20120-00-00 MD 3450 TVD 3450 Completion Date 11/9/2008 Completion Status 1 -GAS Current Status 1 -GAS UIC N REQUIRED INFORMATION Mud Log No Samples No Directional Survey No DATA INFORMATION Types Electric or Other Logs Run: Data too large for this data block (data taken from Logs Portion of Master Well Data Maint Well Log Information: Log/ Electr Data Digital Dataset Log Log Run Interval OH/ Log Med/Frmt Number Name Scale Media No Start Stop GH Received comments Report: Final Well R 0 0 Open 12/9/2008 End of Well Report neG Info, Daily Summ, Daily Ops, Morning Reports, Bit Rec, Mud Rec, Days vrs Depth C 17262 Report: Final Well R 0 0 Open 12/9/2008 End of Well Report, Gen Info, Daily Summ, Daily Ops, Morning Reports, Bit Rec, Mud Rec, Days vrs Depth w/PDS and PDF Mud Logs Mud Log 5 Col 80 3450 Open 12/9/2008 MD Surface Data MudLog 25 -Oct -2008 Sonic 5 Col 523 3400 Open 12/9/2008 best DT, DSI Processing 10 -Nov -2008 Temperature 5 Col 0 843 Case 2/3/2009 Temp, GR, CCL 4 -Oct - 2008 Perforation Col 288 512 Case 2/3/2009 Perf 2.5' PF HSD, 4SPF. 60Deg, GR CCL 7 -Oct - 2008 Cement Evaluation 5 Col 48 800 Case 2/3/2009 CBL, USIT, CCL 5 -Oct - 2008 Cement Evaluation 5 Col 48 819 Case 2/3/2009 CBL, 3-3/8" Dig Sonic Log, GR, CCL 5 -Oct -2008 • Is DATA SUBMITTAL COMPLIANCE REPORT 3/2/2011 Permit to Drill 2070840 Well Name/No. MOQUAWKIE 4 Operator AURORA GAS LLC API No. 50-283-20120-00-00 Mn 3450 TVD 3450 Completion Date 11/9/2008 Completion Status 1 -GAS Current Status 1 -GAS UIC N og Sonic 5 Col 856 3420 Open 2/3/2009 Dipole, GR, Monopole P&S, Lower Dip 26 -Oct - 2008 Log Sample 5 Col 1064 3330 Open 2/3/2009 Chono Sample Taker 26 - Oct -2008 Log Pressure OTH Col 1082 3340 Case 2/3/2009 Espress Pres, XPT, GR Log Induction/Resistivity 5 Col 855 3407 Open 2/3/2009 26 -Oct -2008 Plat Express, Array Induct 26 -Oct -2008 t C Las l 17582&4nduction/Resistivity 523 3415 Open 2/13/2009 PEX and DSI logs 523'- 3415' Log Cement Evaluation 5 Col 100 3400 Case 5/3/2010 SCMT, GR, CCL Co�: ' Gamma Ray 5 Blu 1500 2500 Case 9/30/2010 GR, CCL EXPRO kog Perforation 5 Blu 1500 2500 Case 9/30/2010 Perf EXPRO Well Cores/Samples Information: Name ADDITIONAL INFORMATION Well Cored? y/; Chips Received?_ --'t�1'NN Analysis-.4�4� Received? Comments: Compliance Reviewed By: Sample Interval Set Start Stop Sent Received Number Comments SY, Daily History Received? N Formation Tops N Date: • ALASKA STATE OF ALASKA AND GAS CONSERVATION COMMISSO REPORT OF SUNDRY WELL OPERATIONS �J(.A- N/Tu 1201" 1. Operations Abandon Li Repair Well ✓ Plug Perforations Lj Stimulate Li Other ✓ Test Well Performed: Alter Casing ❑ Pull Tubing ❑✓ Perforate New Pool ❑ Waiver ❑ Time Extension ❑ Change Approved Program ❑ Operat. Shutdown ❑ Perforate ❑✓ Re-enter Suspended Well ❑ 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Aurora Gas, LLC Development Q Exploratory ❑ Stratigraphic❑ Service ❑ , 207-084-0 3. Address: 1400 W. Benson Blvd., Suite 410 6. API Number: Anchorage, AK 99503 .. 50-283-20120-00-00 7. Property Designation (Lease Number):8. `` Well Name and Number: _ C-061390 iE.F_ C: 1 ( 11 Mo uawkie No. 4 9. Field/Pool(s): r Mo uawkie Undefined Gas Pool 10. Present Well Condition Summary: Total Depth measured 3,450 feet Plugs (measured) 3,259 feet true vertical 3,450 feet Junk (measured) none feet Effective Depth measured 3,396 feet Packer (measured) 1,726', 2,078', 2,557', 2,690' feet true vertical 3,396 feet (true vertical) 1,726', 2,078', 2,557', 2,690' feet Casing Length Size MD TVD Burst Collapse Structural Conductor 80' 13-3/8" 68# K-55 80' 80' Surface 850' 9-518" 36# L-80 850' 850' 3,520 psi 2,020 psi Intermediate Production 3,450' 5-1/2" 15.5# J-55 3,427' 3,427' 5,320 psi 4,910 psi Liner 1,745'-1,786', 1,948'-1,958', 1,972'-1,976', 1,980'-1,988', 2,106'-2,111', 2,116'-2,121', 2,140' - Perforation depth: Measured depth: 2,150', 2,166'- 2,176', 2,554'- 2,574', 2,600'-2,615', 2,637'-2,647', 2,702'-2,722', 2,732'-2,752, 2,874' - 2,879', (3,306'-3,326' and 3,322'-3,337' below retainer, not open) True Vertical depth: same as Measured depth above Tubing (size, grade, measured and true vertical depth): 2-718" 6.5# J-55 2,887' 2,887' Packers and SSSV (type, measured and true vertical depth): HRP Packer Hydraulic Packer Mech. Packer Hydraulic Packer / 1,726' MD/TVD 2,078' MDITVD 0' MDITVD 11. Stimulation or cement squeeze summary: Intervals treated (measured): 0'/ 2, 9 2010i iN none Treatment descriptions including volumes used and final pressure: "M firma Goss. U'6Ij 43101 i none 12. Representative Daily Average Production or Injecti , 9#1 ago Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 0 30 Subsequent to operation: 0 1,500 2 0 330 13. Attachments: Perf, Gamma, CCL Corr. 14. Well Class after work: Copies of Logs and Surveys Run submitted 9/29/2010 Exploratory E] Development ❑✓ ° Service ❑ Stratigraphic ❑ Daily Report of Well Operations dated 11-16-10 15. Well Status after work: Oil Gas ✓ ',it WDSPL IGSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP❑ SPLUG ❑ 16. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 310-168 Contact J. Edward Jones, 281-495-9957 Printed Name Bruce D. Webb Title Manager, Land and Regulatory Affairs Signature Phone Phone 907-277-1003 Date 11/18/2010 RBDMS Nov z a 2a � „ Form 10-404 Revised 1A/2Q10 Submit Original Only Aurora Gas, LLC Moquawkie #4 Workover Completion September 2, 2010 API# 50-283-20120-00 PTD #207-084 KB—15.2ft Drill 12-1/4" Hole to 850' 2-7/8" x 5-'/:" annulus displaced with inhibited packer fluid 11.1 ppg NaBr/NaCI to 1,711' Beluga —not completed Tyonek Tops Carya 2-1 —1,734' Carya 2-2 — 1942' Carya 2-3 — 2230' Carya 24.2 — 2,700' Carva 2-6 — 3303' Estimated PBTD @ 3,396' Carya 2-1.1 1745-8.5' Carya 2-2.1 1948-58' 1972-76' 1980-88' Carya 2-2.3 2106-11' 2116-21' 2140-50' 2166-76' Carya 2-3.1 2254-74' Carya 2-4.1 2600-15' 2637-47' Carya 24.2 2702-22' 2732-52' Carya 2-5 2874-79' Carya 2-6 3306-26' 3322-37' 2 7/8 6.5# 8rd EUE J-55 Tubing KB 15.2' 13-3/8" 68# Structural Conductor driven to 80' 9-5/81136# Surface Casing set at 850' Cement w/ 14.5 ppg Gas -Block enhanced XA Sliding sleeve @ 1,717' HRP Packer @ 1,726' XO Sliding Sleeve @ 1,822' XO Sliding Sleeve @ 1,948' Hydraulic -set Packer @ 2,078' XO Sliding Sleeve @ 2,113' XO Sliding Sleeve @ 2,270' On/Off tool @ 2,550' Arrowset Mechanical -set Packer (a, —2,557' Sliding Sleeve @ 2653' Hydraulic -set Packer @ 2,690' XN Nipple @ 2,702' 2-7/8 x 3-1/2" NU XO @ 2,795' 60ft of 3.5" screen 30/50 mesh XO 1 jt 3-1/2" tubing and Bull Plug at 2,887' Cement Retainer @ 3,259" 5%11 15.5# J-55 Casing to 3,427' MD (TVD) Drill 7-7/8" Hole to 3,450' LJ AURORA GAS, LLC MOQUAWKIE NO. 4 (AOGCC DRLG PERMIT No. 207-0840) (API No. 50-283-20120-00) WORKOVER: CLEANOUT & RECOMPLETION OPERATIONS SUMMARY 7/26-29/10—MI & RU AWS #1 rig. 7/30/10—Fin RU. Test choke manifold. Displace 9.0 ppg KCl -NaCl brine in annulus. . Set 2 - way check in hanger. ND tree. 7/31/10— NU BOP. Test BOP to 250/3000 psi. (Witness waived by Jim Regg). 8/1/10—Fin BOP test—good. Pull 2 -way check. PU to remove tbg hanger. Pull 45K to release hydraulic packers. Release mechanical packer. Circ out. Inc brine wt to 9.5 ppg. Start POH. 8/2/10—Fin POH w/ 2-7/8" tubing and packers. LD packers. TIH w/ mule shoe (MS) to 2565'— tag sand. Wash to 2734', losing fluid. Mix & circ 20 bbl Baraplug (salt) lost circ pill. Start POH. Total losses=139 bbl. 8/3/10—Mix 2nd Baraplug pill. TIH. Spot pill & reduce brine wt to 8.8 ppg. POH. RIH w/ Inflatable Bridge Plug (IBP) retrieving tool to 2670'. Inc brine wt to 9.0 ppg. POH to clean retrieve tool. RIH OE to spot Baraplug pill. Mix pill. Total losses to date=286 bbl. 8/4/10—Fin mix pill. Spot pill at 1 BPM. Monitor losses—decreasing. Spot 17 bbl Baraplug pill at 2515'. POH. RIH w/ retrieving tool. Tag IBP, attempt to engage—no wt increase when PU. C & C brine to 8.8 ppg. Total Losses=392 bbl. 8/5/10— POH slowly. IBP retrieve tool (overshot) full of sand. RIH w/ wash -over shoe to 2734' Circulate, Mix & pump high vis Barazon pill to clean hole. POH, LD WO shoe. Monitor losses & W.O. different WF retrieving tool. RIH w/ retrieving tool w/ circ ports to 2734'. Attempt to engage IBP—push down to 2746'. POH w/ IBP—LD. PU mill & casing scraper and RIH. 8/6/10—Finish RIH w/ scraper & mill. Tag fill at 2714'. Attempt to wash down w/o success. POH & LD scraper. RIH w/ 4-3/4" mill to 2714'. Wash & rotate down to 3293'. Total losses= 490 bbl. 8/7/10—Wash down to 3396'. CBU w/ high vis pill. POH w/ SLM. Test BOP (witness waived --� by Bob Noble). PU test packer & TIH to set at 3232' (to test Carya 2-6 perfs at 3306-37'. Total Losses=513.5 bbl 0 • 8/8/10—Set pkr at 3332'. Test flow back lines incl sand filter to 1500 psi. Repair valves on test choke skid. RU to swab. Make 10 runs 1000-2600', rec 36.5 bbbl (19.6 bbl tubing & below packer). SIFBU. 8/9/10-1-1/4 hr SITP-225 psi. Blow down thru test unit—rec 2.75 bbl (tested as produced water by Cl and wt). Fill tubing & open unloader. CBU. Release packer, POH, LD packer. MU cement retainer, run on tubing to 3253', & set. Test retainer to 2000 psi for 15 min—good. Rel packer, pull up to 2860', & reset. RU to swab test Carya 2-5.1 perfs at 2874-79'. Swabbed well, FL 1000-2300' & well started flowing—flow thru test separator to flare. Total Losses= 541 bbl. 8/10/10—SI for 1/2 hr -240 psi. Flow and SI several times. Blow down. Open unloader & circulate out. Release packer. POH. PU RBP & packer, RIH. Set RBP at 2860', pull up and set packer at 2767' test to 2000 psi. Release pkr and reset at 2673' w/ EOT at 2742'. Mix and filter 500 bbl 8.5 ppg 3% KCl water to 5 microns. Fill casing with 39.8 bbl. Spot 15 bbl KCl brine w/ 0.2% Kleen Rinse, close unloader. Pump 25 bbl KCl w/ Kleen Rinse followed by 256 bbl KCI brine w/ 5% Weatherford Sand Aid. Displace to EOT w/ 15 bbl KCl brine w/ 0.2% Kleen Rinse. Pump at +/-1.5 BPM at +/-500 psi. SI. Losses-to-date=549 bbl + pumped 296 bbl treatment into formation. 8/11/10—Release pkr. Rev 17.7 bbl. SI -70 psi in 1/2 hr. Open well and flow back treatment— rec. reatmentrec. 86.5 bbl at 6.5 BPH. Open unloader. Release pkr. RIH to 2860', release RBP. Pull up and reset RBP at 2679'. PU and reset pkr at 2548'. Spot 15 bbl KCl brine w/ 0.2% Kleen Rinse. Close unloader. Attempt to pump into perfs at 2600-2649' 3X (for Sand Aid treatment)—pressure to 860 psi w/o taking fluid. RU and swab back 11.5 bbI brine before well started blowing— flowed back 2.2 bbl in 1 hr. SIFBU--630 psi in 2 hrs. Open well to test separator. Flow 4 hrs— final rate --460 mcfpd at 200 psi w/ no water. SIFBU-695 psi in 30 minutes. Prep to open unloader to kill well—replace leaking wing valve. Lost 6 bbl for total losses of 555 bbl, recovered 86.5 bbl treatment brine leaving 209.5 BUR. 8/12/10—Open unloader & circ out gas. Release pkr, retrieve RBP and reset at 2760'. PU and reset pkr at 2673'. RU to swab perfs at 2702-59'. Swab down to 2400' ---couldn't get below 250' on 4th run due to sludge (Sand Aid and/or new swab line grease/tar). Mix and spot 15 bbl KCl brine w/ 2% Kleen Rinse and 8% methanol down tubing. SI and let soak for an hour. Swab 2-1/2 hr., then could not get below 480'. Make up wireline brush and run to 2200'. Continue swabbing—recover a total of 94 bbl (2 tubing volumes + 62 bbl load water from treatment). SI for buildup. Total losses: 555 bbl + 148 BUR. 8/13/10-3-1/2 Hr SITP-17 psi. Mix 1 bbl methanol in 17 bbl KCl brine. Attempt to release pkr--could not. Pumped down tubing, released packer. Spot 16 bbl methanol pill. Reset pkr. RU to swab. Swabbed & flowed 16 hrs—recovered 228 bbl. Flow thru test separator at rates up to 400 mcfpd at 165 psi—recover 60.7 bbl. Total recovery= 148 BLW + 141 bbl losses: net losses to recover = 414 bbl. 8/14/10 ---Continue to flow well for 2 hr—rate dropped to 67 mcfpd at 50 psi, rec 36 bbl. Sl for 1/2 hr -95 psi. RD swab lubricator. Kill well. Release pkr. Pump 45 bbl to get returns. Wash down from 2740' to RBP at 2760', recover lots of sand. Release RBP. CBU, recover lots of Sand Aid semi-solids over shaker. RD power swivel and clean pits. Total Losses today: 153 bbl, Total Unrecovered Losses = 567 bbl. 2 e 0 0 8/15/10—Mix Baraplug LCM pill and displace down tubing, POOH w/ packer and RBP. Test BOPS. Clean pits for heavier completion fluid. WO tools. Mix 11.1 ppg NaCl -KCl -Naar brine. Losses today -57.5 bbl. Unrecovered losses = 624.5 bbl. 8/16/10—PU Lower Completion and RIH: 1 jt 3-1/2" tbg w/ bull plug, 60' 3-1/2" 30/50 mesh WF Stratapack screens (top at 2787'0, X -O, 2-7/8" tbg, XN nipple (2692'), pup jt, HRP hydraulic pkr (2676'), 1 jt 2-7/8" tbg, XO sliding sleeve (2642'), 3 jts 2-7/8" tbg, Arrowset mech pkr (2546'), On -Off tool (2540') on 2-7/8" tbg. Set mech pkr. Test casing to 2000 psi. RU Pollard. Run & set PX plug in X profile at 2692'. RD Pollard. Test tbg to 3000 psi & attempt to set HRP—failed. Bleed off and repressure to 3800 psi—pkr set. Release from On -Off tool. Displace hole w/ 52 bbl 11.1 ppg NaBr brine. PHH, LD On -Off tool. LD 9 stds 2-7/8" tbg. ND riser & NU shooting head. RU Expro. Test lubricator to 1500 psi. Run GR/CCL log from 2538'. PU & run WL -set RBP, set at 2500'. Losses today = 0. 8/17/10—Rerun GR/CCL for better correlation. PU Expro 3-3/8" perf guns w/ 6 SPF deep - penetrating charges w/ 60 -deg phasing and perforate Upper Tyonek Carya 2-3, 2-2, and 2-1 sands: Run #1-2254--74', #2--2166-76', #3-2140-50', #4-2006-11' & 2016-21', #5-1972-76' & 1980-88', #6-1948-58', and #7 & #8-1745-85'. RD Expro. RD shooting head and NU riser. PU casing scraper & RBP retrieving tool and RIH. Reverse circ debris off RBP, engage, release, and POH. Losses today = 0. 8/18/10—LD RBP, ret tool, & scraper. PU Upper Completion assembly and RIH on 2-7/8" tubing: On-off skirt, tbg, XO sliding sleeve (2259'), tbg, XO sliding sleeve (2101'), tbg, HRP hydraulic packer (2064'), tbg, XO sliding sleeve (1937'), tbg, XO sliding sleeve (1810'), tbg, HRP (1711'), 1 jt tbg, XA sliding sleeve (1706'), and 2-7/8" tubing to surface. Tag On -Off tool at 2540'. Circ inhibited brine pkr fluid. Space out and land in ead w/ 16,500# compression. Test tubing to 2000 psi, increase to 4000 psi to set HRP's. BOP'§. NU tree and test to 3200 psi. Release rig and startRD. RU Pollard. Open sleeves at ' =&f 2101'. Start swabbing to test well. Losses today = 0. 8/19/10— Swab well in w/ Pollard. SIFBU-750 psi in 3-1/2 hr. RIH w/ shifting too on slickline and close sleeves at 2101' and 2259'. Open sleeve at 1810'. POH—lost tool string 30' from surface. MU imp blk and RIH tag fish at 2101'. POH. Order fishing tools & personnel. MU tools and RIH. Tag and engage fish—POOH, recover fish. RIH w/ shifting tool & confirm sleeve at 2101' is closed. Flow test Upper Completion for 2 hr: 416 mcfpd at 358 psig and no water from perfs at 1745-1988'. 8/20/10 --Continue testing well—SITP-854 psia in 2 hrs. Continue RD AWS #1. Set PX plug in profile in XA sliding sleeve at 1706'. Start MO rig. 8/24/10 – 9/7/2010—Continued flow testing well. Testing Summary next page: 3 PERF INTERVAL FLOW RATE SITP Top Bottom TEST DATE FTP psig WATER mcf d psig Calc BHP bbl psia Carya 2-6 3322 3338 8/8/2010 0 235 38.5 3306 3316 LOWER COMPLETION Packer at 2676' 45 min SI 2874 2884 8/9/2010 165 25 240+ 1 Carya 2.4.2 8/14/2010 315 200 96 2732 2755 8/20/2010 not sustained 580 2702 2720 9/6/2010 not sustained 610 FL -2180' 897 LOWER MIDDLE COMPLETION Packer at 2546' 8/11/2010 460 200 695 0 Carya 2-4.1 8/26/2010 566 284 645 0 2636 2648 8/27/2010 539 371 628 2600 2615 9/6/2010 1317 125 Sliding Sleeve at 2642' 9/7/2010 1096 300 840 1.5 906 UPPER MIDDLE COMPLETION Packer at 2064' Carya 2-3 2254 2274 8/18/2010 no flow 8/24/2010 blew down 782 Sliding sleeves at 2101' & 2259' 8/29/2010 170 130 1050 0 Carya 2-2 9/6/2010 140 30 1030 0 2106 2176 1120 (30' net perfs) ,-UPPER COMPLETION Packer at 1711' 1947 1988 8/19/2010 416 358 841 0 (22' net perfs) 8/25/2010 598 294 856 0.5 Carya 2. 1.1 909 1745 1785 commingled with the above during both tests Sliding sleeves at 1810'& 1937' Ed Jones 11/16/10 C! 0 0 September 29, 2010 Mr. Howard Oakland Alaska Oil and Gas Conservation Commission 333 W. 7t' Avenue, Suite 100 Anchorage, AK 99501 RE: Moquawkie #4 Dear Mr. Oakland: 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 Undefined Gas Field, Cook Inlet, Alaska. The enclosed data consists of the following: EXPRO LOGS Perforating Record, 1:240 scale Gamma Ray / CCL Correlation, 1:240 scale 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 either myself or Ed Jones at the Houston number below. Sincerely, Bruce D. Webb Manager, Land and Regulatory Affairs RECEIVED AND ACCEPTED ABOVE DATA This _day of , i 2009. 1400 West Benson Blvd., Smite 410 a Anchorage, AK 99503 9 (907) 277-1003 a Fax. (907) 277-1,006 5031 North Coarse Drive Suite 200 o Houston, TX 77072 o (713) 977-3799 1 Fax. (733) 97.7-1347 0 0 D ALASKA SEAN PARNELL, GOVERNOR ALASKA OIL AND GAS333 W. 7th AVENUE, SUITE 100 CONSERVATION COMHSSION ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907)276-7542 Bruce D. Webb Manager, Land and Regulatory Affairs �y Aurora Gas, LLC 1400 W. Benson Blvd., Suite 410 Anchorage, AK 99503 Re: Moquawkie Field, Undefined Gas Pool, Moquawkie No. 4 Sundry Number: 310-168 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. 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, zx—g!<� Daniel T. Seamount, Jr. Chair DATED this f day of June, 2010. Encl. VIVI10 ! RECEIVED " O'Lo (p STATE OF ALASKA �U� p 2O1Q ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVAL§Bska Oil glfes Cons. Commission 20 AAC 25.280 A_..l._.nnn 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well Q Change Approved Program ❑ Suspend ❑ Plug Perforations ❑ Perforate ❑✓ Pull Tubing ❑✓ Time Extension [] Operations Shutdown ❑ Re-enter Susp. Well ❑ Stimulate ❑ Alter Casing ❑ Other: Zt t W-tj ( 53' 1 2. Operator Name: Aurora Gas, LLC 4. Current Well Class: 5. Permit to Drill Number. 7 �u>c �� Development Q, Exploratory [:]-084 Stratigraphic ❑ Service 3. Address: 6. API Number' 1400 W. Benson Blvd., Suite 410, Anchorage, AK 99503 50-283-20120-00 ` 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 MO uawkie No. 4 ' 9. Property Designation (Lease Number): 10. Field/Pool(s): rl&�'I C-061390 M uawkie Undefined Gas F' d 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 3,450' 3,450' 3,380' 3,380' 3,380' 3,324' Casing Length Size MD TVD Burst Collapse Structural Conductor 80' 13-3/8" 68# K-55 80' 80' Surface 850' 9-5/8" 36# L-80 850' 850' 3,520 psi 2,020 psi Intermediate Production 3,427' 5-1/2" 15.5# J-55 3,427' 3,427' 5,320 psi 4,910 psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size:Tubing Grade: Tubing MD (ft): 2,600 - 2,615', 2,637' -2,647', 2,701' - 2,722', 2,732' - 2,752', 2-7/8" 6.5# J-56 2,606' 2,874' - 2,879', 3,306' - 3,326', 3,322' - 3,337' Packers and SSSV Type: Packers Packers and SSSV MD (ft) and TVD (ft): � 2,267', 2,409', and 2,586' Weathford Hydraulic 12. Attachments: Description Summary of Proposal Q 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Development Q Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: June 15, 2010 Oil ❑ Gas Q W1NJ ❑ GINJ ❑ WDSPL ❑ Suspended ❑ WAG ❑ Abandoned ❑ 16. Verbal Approval: Date: Commission Representative: GSTOR ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Chad Helgeson 907.277-1003 Printed Name Bruce D. Webb Title Manager, Land and Regulatory Affairs Signature Phone Date 907-277-1003 May 21, 2010 COMMISSION USE ONLY rr� Sundry Number: '51 C) Conditions of approval: Notify Commission so that a representative may witness Plug Integrity❑BOP Test Tr/Mechanical Integrity Test ❑ Location Clearance ❑ Other: -".G St3 0 L f -D 3 D o b , Subsequent Form Required: L0 — 4-0 4- APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: 6$ WA to DI IIS JUN 15 2010 Form 10-403 Revised 1/W R ' N Submit in Dupli c�ic� �J Drill 12-1/4" Hole to 850' 2-7/8" x 5-1/z" annulus displaced with inhibited packer fluid 9.5 ppg KCl to 2,223' Beluga -not completed initially Tyonek Tops Carya 2-1 - 1,734' Carya 2-2 - 1942' Carya 2-3--2230 Carya 2-4.2 - 2,700' Carva 2-6 - 3303' Carya 24.1 2600-15' 263747' Carya 24.2 2702-22' 2732-52' Carya 2-5 2874-79' Catya 2-6 3306-26' 3322-37' Estimated PBTD @ 3,380 rs� ►1i 9 2 7/8 6.5# 8rd EUE J-55 Tubing kB 14.5' 13-3/8" 684 Structural Conductor driven to 80' 9-5/8" 369 Surface Casing set at 850' Cement w/ 14.5 ppg Cas -Block enhanced Sliding sleeve @ 2,223' Hydraulic -Set Packer @ 2,267' Sliding Sleeve @ 2,368' Hydraulic -set Packer @ 2,409' Sliding Sleeve @ 2,537' On -Off Tool above Arrowset Mechanical Packer @ 2,586' End of tail pipe, 2,606', 2.25" no go nipple broached to a 2.30" ID Weatherford 2.125" Inflatable Bridge Plug @ 2,728' (Center of element) with I " fuhneck End of Tail Pipe 2AW' 5 %- 15.5# J-55 Casing to 3,427' MD (TVD) Dry 7-7/8" Hole to 3,450' • Aurora Gas, LLC Moquawkie #4 Workover Option 1 Well Configuration Summer 2010 API# 50-283-20120-00 PTD #207-084 KB—14.5ft Drill 12-1/4" Hole to 850' 2-7/8" x 5-%" annulus displaced with inhibited packer fluid 9.5 ppg KCl to 1,700' Beluga —not completed Tyonek Tops Carya 2-1 — 1,734' Carya 2-2 — 1942' Carya 2-3--2230 Carya 24.2 — 2,700' Carva 2-6 — 3303' Estimated PBTD @ 3,380 Carys 17• Caryl 19 Carya 21( Carya 7 2254 Carya 2 2600- 2637• Carya2 2702. 2732- Carya 2 2874-7 Carya 2- 3306-26 3322-37 0 2 7/8 6.5# 8rd EUE J-55 Tubing KB 14.5' 13-3/8" 68# Structural Conductor driven to 80' 0-5/8" 36# Surface Casing set at 850' �cment w/ 14.5 ppg Gas -Block !nhanced Sliding sleeve @ 1,694' draulic-Set Packer @ 1,700' ng Sleeve @ 1,802' Pig Sleeve @ 1,926' raulic-set Packer @ 2,050' sg Sleeve @ —2,080' ling Sleeve @ —2240' Wtool Mechanical -set cer (& —2.550' ding Sleeve @ —2580' Iraulie-set Packer @ —2,670' iding Sleeve @ —2760' lydraulic Packer @ —2,825' Nipple below packer .5" screen w/ bullplug Option 1(A) If 2-6 is not Productive 15.5# J-55 Casing to 3,427' MD (TVD) )rill 7-7/8" Hole to 3,450' • Aurora Gas, LLC MOQUAWKIE #4 2009 REMEDIAL RIG WORKO VER / RECOMPLETION PROCEDURE Version 1.3 CAPACITIES: 2-7/8" Tubing: 0.00579 bbl/ft and 5-1/2" 15.5# J Casing: 0.0238 bbl/ft 5-1/2" Casing X 2-7/8" Annular Volume: 0.0158 bbl/ft. Casing ID is 4.950", Drift ID is 4.825". Tubing Volume to Sliding Sleeve above Top Packer is 12.9 bbl. Annular volume to sliding sleeve is 35.1 bbl for total circulation volume of 48.0 bbl. Casing vol. to deepest per£ 79.4 bbl. 9.5 ppg KCl brine left in tbg-csg annulus. KB= 14.5' above GL (all depths from KB). PBTD=3380' MD/TVD; TD=3427'MD/TVD TUBING/COMPLETION: Tubing ID=2.441". Drift ID=2.347" Weatherford XA Sliding Sleeve at 2223'-2.313" X profile Weatherford Hydraulic -set Packer at 2267' Weatherford XO Sliding Sleeve at 2368' w/ 2.313" X profile Weatherford Hydraulic -set Packer at 2409' Weatherford XO Sliding Sleeve at 2537' w/ 2.313" X profile Weatherford On/Off Tool—at 2582' –2.441" ID Weatherford Arrowset Mechanical Packer at 2586'-2.440" min ID Bottom of Tubing w/Bull Plug -2606'—w/ 2.30" broached No -Go. Thru-tbg Weatherford Inflatable Bridge -Plug set at 2728' EXISTING PERFS: 2600-15' (15'); 2637-47' (10'); 2702-22' (20'); 2732-52' (20'); 2874-79' (5'); 3306-26' (20'); 3322-37' (15')– 105' net/ 737' gross interval. J NOTE: Pollard Wireline work in March 2010 indicated sand fill in tubing at 2495', and earlier Pollard work indicated fill at 2756' below inflatable Bridge Plug, when setting it. May 2010 slickline work tried to bail sand below tubing, but was unsuccessful and bailed sand to 2528'. 1) Prior to moving in rig, fill tubing with produced water using electrical glycol pump and blow -down tank. Bleed off any gas pressure and pump more produced water. Repeat until pressure no longer builds up and water is at surface. Disconnect flow line downstream of SSV. Disconnect controls and put in safe place—use care to avoid damaging. Disconnect and remove SSV. 2) Move in, rig up Pollard w/ lubricator. Run 2.0" gauge ring, confirm fluid is at surface and tag sand. PU bailer (have several types on hand) and bailer sand to 2607' KB (just out bottom of tubing). Open XA sliding sleeve (upward pull) at 2265' and leave open. RD and release Pollard. 3) Move in, rig up AWS #1 rig w/ single workover pit for mud system (not AG mud system) and support equipment only as needed for workover (one gen set, 1 mud pump, etc.). Also, move in and spot Aurora Gas test unit, flare and sand filter. 4) Starting with clean mud pit, mix 150 bbl (usable volume pg 6% KCl -NaCl brine (6% KCl-22#/bbl+ weight up with oilfield salt, 26bl), using clean produced water from tanks on AG locations. 5) RU to pump down annulus thru casing valve on tree. RU to take returns from flowline (2-1/8" 5000# API flanged connection). Reverse circulate out 35 bbl of 9.5 ppg packer fluid out of annulus, back into mud system—should increase weight to 9.0 ppg all around. Circ until clean and gas free. Set Vetco 2 -way check in hanger. ND tree, NU 3000 -psi BOPE. Test to 3000 psi (or as required by AOGCC Sundry approval). Pull 2 -way check—release Vetco. 6) Screw into tubing hanger, release hold downs, and pull to release hydraulic packers (approx 43,000# overpull). Release mechanical packer at 2584' (if packer will not release or is not free when released, release from On -Off tool at 2580'. When packer is released, circ until gas free, then POH, standing back tubing and laying down packers and sliding sleeves. (If tubing is stuck or has drag, may want to have Pollard close sliding sleeve at 2265' and circulate around bottom packer). Strap out of hole and keep good records. Monitor hole and keep full. Bring additional 25 joints of 2-7/8" new or inspected tubing to location. 7) A. If losses are minimal, PU WF inflatable bridge plug (113P) retrieving tool and TIH—expect to tag fill at 2650', but RIH slowly from 2580'. Wash down to IBP at 2729'. Circ clean. Latch onto IBP, release and POH. LD IBP, PU 4-3/4" bit (no jets), and RIH on 2-7/8" tubing and clean out to 3380' (PBTD), noting depths any fill is encountered. Catch samples of fill. Circulate hole clean w/ clean 9.0 ppg 61/0 KCl/NaCl brine, using 20 bbl high -vis (Barazan-D) pills for sweeps as needed. Monitor fluid level—determine rate of loss, if any. POOH with tubing. LD bit. B. ALTERNATIVE (not expected to need): If hole will not stay full or if circulation cannot be established, PU Weatherford tubing Sand Pump and run on tubing to clean out fill, as needed. Retrieve IBP, as above. RIH w/ 4-3/4" bit and follow Weatherford's procedure (may need to pick up 1000' of tubing between bit and sand pump.) Keep hole full. Fill tubing until you get to PDTD of 3380'. Attempt to circulate. --If losses are not serious, circulate hole clean w/ clean 9.0 ppg 6% KCl/NaCI brine. Monitor fluid level --determine rate of loss, if any. POOH with tubing. --If losses are high, mix 20 bbl saturated brine in very clean water, then use this to make 12 bbl pill of Baraplug (see notes at end of Procedure) and balance for spacer. Spot Baraplug pill across perfs at 2600-47', precede w/ 5 bbl saturated brine spacer and followed by 3 bbl saturated -brine spacer. (Displace Baraplug to 3100' w/ 3 bbl saturated brine + 15 bbl 6% KCl -NaCl brine.) POH, very slowly until bit is above 2000'. 8) PU casing scraper and bit and run to 3300'. Circ clean (if losses are significant, circulate a minimum). POH, LD scraper and bit. 9) PU test/treat packer (with unloader). Run in hole to 3250' and set. RU Aurora Gas test unit and flare while running in hole. 2 • 0 10) Swab in Carya 2-6 perfs at 3306-37' and test as in Test Procedure (Steps 24, 25, & 27) below—flow until stabilized—get water and gas rates and stable pressure. See RU and Test Procedure Below. Report results. If test is good, go to #12. 11) If water rate is high, sand production is observed, or gas rate is low, kill well (open unloader valve and circulate 9.0 ppg KCl brine around). POH, LD packer. RIH with CIBP and set at 3275' 12) Pull up and set packer at 2800'. Swab in (combined zones if deeper zone had good test) and test. Compare results. A. If this Carya 2-5.1 interval at 2874-79' is wet or produces sand, f kill well and POH. i) If previous test was bad, RIH open ended and spot 20 sx G cement plug onto of CIBP at 3275'. Rev circ tubing clean. POH. PU cement retainer, RIH and set at 2850'. Mix 30 sx G cement, pump 25 sx below retainer, pull out of retainer and spot remaining 5-6 sx (50') on top of retainer. Pull up to +/-2790' and circ out excess cement. POH. (More detailed Procedure will be provided for cementing). Go to Step # 13. ii) If this zone is wet and/or produces sand but deeper Carya J 2-6 zone was productive, will isolate with hydraulic - set packers in Step 16.A. ii) below, w/ hydraulic packers at 3200' and 2825'. Go to Step #13. B. If this Carya 2-5.1 interval is productive, kill well, and POH. 13) PU retrievable BP, 12' pup jt, and test/treat packer. RIH and set RBP at 2800'. Pull 1 jt, set packer, and test to 1500 psi. Release pkr and reset at 2675'. Swab in and test Carya 2-4.2 perfs at 2702'-2752'. . 14) Kill well. Release packer, Circ down to RBP, retrieve, pull up to 2675' and reset RBP. Pull 1 joint and test RBP to 1500 psi. Pull up to 2550' and reset packer. 15) Swab in and test Carya 2-4.1 perfs at 2600-47'.' Kill well and release packer. 16) Depending upon test results of both of the last zones, A. If both zones (Carya 2-4.1 and 2-4.2) were productive and did not produce sand or significant water (not expected—we believe that one of these two intervals is the water and sand producer), circ down to RBP, retrieve, and POH. i) If both deeper zones (Carya 2-5 and 2-6) are non-productive and have been cemented, PU hydraulic packer with 10' pup, X - profile nipple w/ PX plug in place, and WLEG below (may add 1 jt of StrataPack screen w/ 4' pup, and bull plug instead of WLEG), 3 jts 2-7/8" tubing, XO sliding sleeve (@ 2763'), 1 jt tubing, mechanical -set packer with On -Off tool. RIH and set mechanical packer at 2550', pressure tubing to 3000 psi to set hydraulic packer at 2675'. Release from On -Off tool. Go to Step #17. ii) If the Carya 2-5 is productive, PU hydraulic packer with 10' pup, X -profile nipple w/ PX plug in place, and WLEG below (may 3 add 1 jt of StrataPack screen w/ 4' pup, and bull plug instead of WLEG) , 2 jts 2-7/8" tubing, XO sliding sleeve (to be at 2760'), 3 jts tubing, hydraulic -set packer, 3 jts tubing, XO sliding sleeve (at 2580'), 1 jt tubing, mechanical -set packer w/ On -Off tool to set at 2550'. RIH to set mechanical packer at 2550' w/ hydraulic packers at 2825' and 2670'. Pressure up to 3000 psi and set hydraulic packers. Release from On -Off tool at 2545'. Go to Step 17. iii) If Carya 2-5 is not productive but Carya 2-6 is, add an additional hydraulic packer to isolate the 2-5 perfs: run deepest packer as above in ii) but set it at 3200', but then 12 joints of tubing, hydraulic packer at 2825', then as above with hydraulic packer at 2670' and mechanical packer at 2550'. B. If one zone was productive but other produced water and/or sand (Carya 2-4.1 or 2-4.2), proceed as in A. i) or ii) to isolate with packers, but do not install sliding sleeve to access water/sand producing zone. C. If neither Carya 2-4.1 nor 2-4.2 are productive, i) If both deeper zones (Carya 2-5 and 2-6) were also non-productive, permanently abandon the well below 2600'—Procedure to be provided at that time. ii) If either deeper zone (Carya 2-5 or 2-6) are productive, proceed as in A.ii) or iii) above, except leave out hydraulic packer between the 2-4.1 and 2-4.2 perfs (and run no sliding sleeves between packers}—i.e., set mechanical -set packer with On -Off tool and set packer at – 2550'. Go to Step 17. 17) With all sleeves closed and PX plug in place below deepest packer, Pull up and displace 9.0 ppg brine with 11.1 ppg KCl-NaCl--NaBr brine (see formula at end of Procedure) and filter brine until it is 11.1 ppg and clean throughout (thru 5 or 10 micron sock filters). POH, LD 18) Move in Schlumberger electric -line unit, and lubricator. Run GR/CCL to onoff tool above packer at 2545, tie in to open -hole logs, and log up to surface casing (850'). 19) PU wireline -set RBP and set at +/-2500'. 20) PU Schlumberger 3-1/2" HSD guns with Powerjet Omega charges (6 SPF w/ 60 deg phasing—OR EQUAL) and test lubricator to 2000 psi. RIH and perforate as follows: a) 2254-74' (20')—XPT failed • C -., Y,a-- 2 – b) 2166-76' (10')—no test--- .' c) 2140-50' (10'}- no test d) 2106-11' & 2116-21' (one 20' gun, 10' net) --no test Czg e) 1972-76' & 1980-88' (one 20' gun, 12' net) -10.2 ppg 'Z ' f) 1948-58' (10')—XPT pressure -1038 psi (10.2 ppg) " g) 1745-85' (40'-2 X 20' guns}--XPT pressure -1017 psi (11.1 ppg) and 970 c4�'z psi (10.5 ppg). 112' of perfs, 8 guns (3 X 10' and 5 X 20') over 529' gross interval. RD & release SLB. 4 21) Run bit and scraper to 2500'. Circ and condition brine. RIH and POH slowly. POH, lay down bit and scraper. 22) PU retrieving tool, RIH and retrieve RBP at 2500'. POH and LD RBP. 23) PU shallow completion string consisting of 2 hydraulic packers +/-350' apart (to be set at +/-2050' and +/-1700' with 2 XO sliding sleeves between at 1926' and 1802' and XA sliding sleeve 1 jt above top packer—i.e., packer, 4 jts tubing, sliding sleeve, 4 jts of tubing, sliding sleeve, 3jts tubing, packer, 1 jt tubing, XA sliding sleeve, then tubing to surface). What is run below deepest packer, depending upon results of testing deeper sands: a) if well was plugged below 2600' (nothing productive below new perfs), run mechanical -set packer w/ 10' pup w/ 2.313" X nipple and pump -out ball catcher /wire -line entry guide to set packer at +/-2205', 4 jts of tubing, XO sliding sleeve (closed) w/ X profile nipple (sleeve at +/-2080'), then 1 jt tubing spacer to 2047', then 2 hydraulic packers and sleeves as above. RIH to 2205'. Add inhibitor to 35 bbl 11.0 ppg brine and circ into annulus as packer fluid. Set mechanical packer at 2205'. Space out and land tubing. Drop ball and test tubing to 2000 psi, then pressure up to 3000+ psi to set hydraulic packers and then sheer ball catcher. b) if a mechanical set packer has been set at +/-2550', run On -Off Tool skirt, 10 jts tubing, XO sliding sleeve (to be @ +/-2240'), 5 jts tubing, XO sliding sleeve (to be @ +/-2080'), 1 jt tubing, then 2 hydraulic packers and sleeve as above. RIH, tag On -Off Tool at 2250', circ clean. Add inhibitor to 40 bbl 1.0 -ppg brine and circ into annulus as packer fluid. Latch onto mechanical packer at 0'. Space out and land tubing. Pressure up to 2000 psi for 15 minutes to test tubing. Pressure to 3000+ psi to set hydraulic packers. NOTE: Rabbit all tubing before going in hole and watch torque DO NOT OVER TORQUE. 24) Test annulus to 1000 psi. Set 2 -way check in tubing hanger. ND BOP, NU and test tree. TEST PROCEDURE 25) RU Aurora Gas Test Unit as follows: a) Set sand filter pot next to choke skid, upstream of AG choke manifold with a bypass, set up an open top tank to blow the sand filter into. b) set test choke manifold close to rig choke skid and connect to w/ 1502 hard line; c) install 24/64" positive choke in manifold (left side)-- use 2" 1502 target tees upstream of choke skid; d) run AG 2" 1502 hard line from choke manifold to test separator; e) set flare stack 100' or more from the rig and from trees and raise stack; and f) lay AG 3" 1502 hard line from separator skid to flare stack, and connect propane bottle to flare stack. 5 26) Prepare for test: a) Take and record initial measurements of brine levels in all tanks to which swabbed/flowed back brine will go—know exact volume of brine is in all tanks; b) Record test separator water level in tank; c) install new chart on Barton recorder; d) install fresh nitrogen bottle onto skid for instrumentation; e) install new 2000 psi pressure gauge near test head or surface pressure data recorder, isolated with needle valve (upstream from valve that will shut in well for buildup—will want it to record and show SI pressures), f) confirm electric clock on chart recorder is on and set to 12 hrs and chart is appropriate for clock time, and g) install sand monitor on the line from well to choke skid, (Jim Schultz, Troy G. or Chad Helgeson to set this up.) 27) Test deepest completion of new perfs. ( RU Pollard if necessary to open sliding sleeve). RD Pollard. RU to flow back. 28) Flow test well as follows until clean and stable, as follows: a) swab in as necessary to top sliding sleeve (or X profile nipple), unloading fluid to shaker/possum belly until well is gassing and/or kicks off to flow; b) when significant gas is at surface (whether swabbing or flowing) or the well is flowing, divert flow to test separator: i) shut down momentarily to light flare stack, then bring back on, adjusting choke size until well is flowing strongly to cleanup, but holding some back pressure on it (probably start at 14/64's and adjust accordingly, target flow at 75% of SIP. ii) Flow until rate and pressure have stabilized for 15 minutes, increasing slightly is OK, but dropping is not—wait until fluctuations tend to be up, not down) and water has dried up (all of tubing volume + casing volume to perfs has been recovered) or rate has stabilized . Flow for a minimum of 1 hour. Probably more (2-3 hours), depending upon water production and cleanup. Watch for sand production in water. If producing any sand or much water, shut in and call. iii) Start w/ 1" orifice in test meter. Flow rate in mcf/day= static reading (blue) X differential reading (red) X 31, If red chart reading is below 3, change to 0.75" orifice; if it is above 8 change to 1.5", then 2.0" orifice. Meter factors change to 17.4, 70, or 130, respectively. Orifices may be changed by experienced operator while flowing w/the Daniel Sr. orifice fitting. iv) Catch water samples thru out (downstream of test separator)—have tested with mud kit for weight—record with time of sample. Produced water should have weight is less than 8.4 ppg—if water is trending in that direction, continue to flow until these properties have stabilized. Keep last sample of produced water to send to lab in Anchorage—label thoroughly. v) Shut in well for buildup twice as long as flow period (maximum surface pressure for any test is expected to be less than 1200 psi, but will likely be less - 1000 psi max for new shallower zones). Report test results to me (Ed)— including email report of flow and buildup tests. If well is making significant water, well will be killed, the packer pulled, a test packer run, and the water production will be isolated—a Supplementary Procedure will be provided for this operation. n 29) Without killing well, RU Pollard slick -line unit, test lubricator to 1500 psi, and RIH to close sliding sleeve (or set PX plug) to isolate just tested interval). Open next shallower interval. RD Pollard. 30) Prep for test. Swab well in if necessary and test as in Step 28) above. 31) Repeat Steps 29 and 30, if necessary, to test final interval. When test is completed, RU slick -line and RIH to close all sliding sleeves POH w/ tool. and retrieve X plug. May have to baile perforating debris off of it—have hydrostatic bailer available. RD Pollard. Set BPV. RD and release rig. Ed Jones 4/23/10 (Rev 6/1/10) (Chad Helgeson Rev 6/1/10) NOTES: 9.0 ppg 6% KCI- NaCl Brine 0.95 bbls Water 22 ppb KCI 23 ppb NaCl 2) BARAPLUG Perf Pill (Note: Barazan can be substituted for N -Vis, but it is dirtier). Product Concentration Saturated NaCl Brine 0.83 bbl BARADEFOAM HP 0.1 ppb or as needed Citric Acid 0.5 ppb N -VIS 2 ppb or as needed for 35 YP DEXTRID 4 ppb KOH As needed pH 9.0 BARAPLUG 50 50 ppb NaCl (Salt) 10 ppb ALDACIDE G 0.25 ppb 3% KCI Saturated NaCl brine 0.888 bbls Water 11 ppb KCI 98 ppb NaCl Saturation will be a 9.9+ ppg MW 10.5 ppg 6% KCI/NaCl/NaBr 0.856 bbls Water 21.8 ppb KCI 65.8 ppb NaCl 46.4 ppb NaBr 11.0 ppg 6% KCI/NaCl/NaBr 0.871 bbls Water 21.8 ppb KCI 45.5 ppb NaCl 92.8 ppb NaBr 7 Itv59 2009 2010 Potassium Chloride 50 Ib sack 45.36 $46.36 Sodium Chloride 50 Ib sack 15.98 $15.82 SODIUM BROMIDE" 55 Ib sack 5140-64 $140-64 0 • Aurora Gas, LLC www.aurorapower.com June 2, 2010 Mr. Dan Seamount Chairman Alaska Oil and Gas Conservation Commission 333 West 7t' Ave., Suite 100 Anchorage, Alaska 99501 Re: Application for Sundry Approval Moquawkie #4 Development Gas Well Dear Mr. Seamount: RECENED FAUN 0 2 ?010 Alaska Oil & 681 Cens• Commission AnahOMP Attached, please find Aurora Gas, LLC's application for workover operations on the Moquawkie #4 gas well. The plan calls for pulling the tubing, cleaning out the well bore, testing existing perforations, perforating new intervals, and installing tubing and packers. For more detailed information, please refer to the Workover / Recompletion Procedures. Thank you for your consideration and assistance. Should questions arise in connection with this request, please contact Mr. Ed Jones in the Anchorage office at (907) 277-1003. Respectfully Submitted By, 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 • (281) 495-9957 • Fax: (281) 495-1473 South 2050800 2070840 1780470 North 502832011100 502832012000 502832006000 1063 ft 0 1592 ft AURORA AURORA AURORA MOQUAWKIE 3 MOQUAWKIE 4 SIMPCO MOQUAWKIE 1 2159 FNL 1728 FEL 1259 FEL 1211 FNL 424 FSL 1261 FEL TWP: 11 N - Range: 12 W - Sec. 1 TWP: 11 N - Range: 12 W - Sec. 1 TWP: 12 N - Range: 12 W - Sec. 36 0 ]66 Fn Boo eo -500 900 mD } m low luo 7 TSUGA 2-7-1. TSUGA 2-7_2� -1000 in — - - TSUGA 2.8-1y o l 1500 Irsv 1r t.."' 1760 J c`• CAR 2.1 ICARYA21_I ® S 1 , X11 19o0 20 ARYA 2-27- CARYA -2 CARYA 2-2 1 a o a—r-- _ 2CARYA42_ 2 e CARYA 2-2_3. 1 2mo uu %� 23CARYA 2-3 -2000 2460 � `., CARYA 2J 31L TD=2560 f -2500 � 7 !,IMP 0 �1N+SA'fuKiE I I ix.ePr000sea !.1(101 {crt -3500 .MO 1 100 101 4 ?X 200 30 30o m "I m 500 ID 600 � 3x r ]00 m i u i} 900 9AyY' Z 'i- - 1000 me 7b mt -_ ITSUGA 2-7 1 ITSUGA 2-72 i 13w nc .10x �. ITSUGA 2-874 - 15w 1. 1dS la= lsoe ,mo I- s_ - 1]w ,xP t m t CARYA 2-1 Ifio6 a I x 1900 .. CARYA 2-2` 2oou o9L C S- w CARYA 2.2 3 ■ ■ 2200 CARYA 2.3 : kF 2300 — an[ 4-- moo b _2n6o 2+10 .na 2500 m. t CARYA 2-4_1 0 av?' CARYA 2422 2800 `CARYA 2-6_111 j 3000 mo rv. 3100 T60 dIX ` 9200 3 1nL i 6 rrc CARYA 2-6 Moo 1887 TD=3500 2010 Proposed Perfs (Sundry 310-168) <610 Too Im 200 3 /C\,J 300 a IOL '• a00 m .1 c T s 500 � a Im A, a ]o0 3n B00 � J� m wo sn g_J low in -500 O 5 tmo um 1200 rA6 ' ITSUGA 2-7 1 I TSUGA 2-7 2 L `t -1000 ,500 In ITSUGA2-8 1 t� " I600 CARY -1 CARYA 2-1_2x ) - --- -1500 2000 i CARYA 2-2f - - - 2CARYA 2-21 I T ,.,.. 2CARYA 2-2_3 NX CARYA 2-3_ 2500 3i0 2CARYA 2.3 3 3 — 2,66 26w IDJO }• 2CARYA 2.4_2 ffi 2 30w 30 _ ffiLT 9100 31w 1y] 32w 300 a-� moo ffi ` 3x00 Seo s CARYA 2-67 - - '3000 3500 IDp iIQ � r 3600 T 3]w 0'po 38w Ev 33w xm 1. 4_ oe- TD=6166 S D—es AOGCC June 4. 2010 0 # Davies, Stephen F (DOA) From: Bruce D Webb [bwebb@aurorapower.com] Sent: Friday, June 04, 2010 1:23 PM To: Davies, Stephen F (DOA) Cc: Aubert, Winton G (DOA); 'Ed Jones'; Chad Helgeson; 'David Boelens' Subject: RE: Moquawkie 4 Workover Questions Steve, That is an excellent question Presently, we do not have funding approval for the Moquawkie #5. This could be why we are going to perforate those sands I the Moquawkie #4. Chad and Ed are both on the west side today and will be in the office on Monday. I suspect we will want to amend the #5 permit, as opposed to cancelling it all together. Then in the future, if we have funding to drill the #5, we can do so, and if we believe there is a justifiable reason to perforate other sands that may be at the same depths as the #4 we will apply for a spacing exception at that time. I will talk it over with Ed on Monday and get his take, then let you know. Thanks for catching that Have a wonderful weekend. Bruce D. 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 From: Davies, Stephen F (DOA) [mailto:steve.davies@alaska.gov] Sent: Friday, June 04, 2010 1:09 PM To: Bruce D Webb Cc: Aubert, Winton G (DOA) Subject: Moquawkie 4 Workover Questions Bruce I'm reviewing Aurora's sundry application for working -over inactive producer Moquawkie 4, and I have a question. Aurora plans to perforate the Carya2-1, Carya 2-2, Carya 2-2.3 and Carya 2-3 intervals in Moquawkie 4, four intervals that were previously not perforated. Last year, Aurora permitted and received a spacing exception for the planned Moquawkie 5 well, anew well located about 150' east of Moquawkie 4. Justification presented for Moquawkie 5 in the permit to drill application stated that this new well "...will target Beluga Tsuga 2-7 to Upper Tyonek Carya 2-3 sands ...". Aurora's application for spacing exception dated June 1, 2009 states "The Moquawkie #5 well will not be producing from the same geologic horizons as the Moquawkie #4." The Carya2-1, Carya 2-2, Carya 2-2.3 and Carya 2-3 intervals can't be open to both Moquawkie 4 and Moquawkie 5, since the wells will be so closely spaced (to prevent waste). So, is Aurora still planning to drill Moquawkie 5, or is Aurora planning to alter the approved drilling and completion program for Moquawkie 5? Thanks, 0 Steve Davies AOGCC 907-793-1224 9 urora Gast C 2 www.aurorapower.com ' June 9, 2010 Mr. Steve Davies Alaska Oil and Gas Conservation Commission 333 West 7th Ave., Suite 100 Anchorage, Alaska 99501 RE: Cancellation of Permit to Drill No. 209-065: Moquawkie No. 5 Dear Mr. Davies: Aurora Gas, LLC ("Aurora") received a Permit to Drill on June 30, 2009 for an onshore gas exploration well in the Moquawkie Gas Field northwest of the village of Tyonek. The well was planned as a vertical well targeting the Upper Tyonek Formation to test for gas. Aurora has re-evaluated the drilling and development plans for this area of the Moquawkie Undefined Gas Field and has determined that the targeted reserves, specifically the Carya 2-1 through 2-1 sands, can be accessed by work -over operations on the Moquawkie No. 4 well. The concept of the Moquawkie No. 5 well was that of an acceleration well for production of the Upper Tyonek sands that are producible in the Moquawkie #3 well but appear to be fault separated, as indicated by seismic and confirmed by initial pressures in the No. 4. While a re - completion of the No. 4 will not accelerate the shallower reserves, it will access the reserves at a much lower cost, especially since remedial work must be performed on the No. 4 well anyway. Therefore, Aurora respectfully cancels its Permit to Drill for the Moquawkie No. 5 well. If you have any questions or require additional information, please contact me or Mr. Ed Jones at (907) 277-1003. Sincerely, AURORA GAS, LLC Bruce D. Webb Manager, Land and Regulatory Affairs 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 ® (281) 495-9957 • Fax. (281) 495-1473 Auwra LLC www.aurorapower.com May 3, 2010 Mr. Winton Aubert Alaska Oil and Gas Conservation Commission 333 W. 7t' Avenue, Suite 100 Anchorage, AK 99501 RE: Moquawkie #4 Dear Mr. Aubert: 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 Moquawkie #4 Slim Cement Mapping Tool SCMT — GR - CCL 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 '9�q -cty RECEIVED AND ACCEPTED ABOVE DATA This _day of 2009. E'. W TITLE: 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 . (281) 495-9957 • Fax: (281) 495-1473 STATE OF ALASKA ALASKA AND GAS CONSERVATION COMMIS* GAS WELL OPEN FLOW POTENTIAL TEST REPORT 1a. Test: Initial Annual Special 1b. Type Test: Stabilized Non Stabilized Multipoint ❑ Constant Time ❑ Isochronal ❑ Other: 2. Operator Name: 5. Date Completed: 11. Permit to Drill Number: Aurora Gas, LLC 20 -Dec -08 207-084 3. Address: 6. Date TD Reached: 12. API Number: 1400 West Benson Blvd., Suite 410, Anchorage AK 99503 T 50- 283-20120-00 4a. Location of Well (Governmental Section): 7. KB Elevation above MSL (feet): 13. Well Name and Number: Surface: T 11 N., R. 12W., S.M. Sec. 1, 1415'FEL and 1,160'FNL 299' MLLW, 14.5' (GL) Moquawkie #4 Top of Productive Horizon: 8. Plug Back Depth(MD+TVD): 14. Field/Pool(s): Same 3,380' MD 3,380' TVD Moquawkie Gas Field Total Depth: 0.562 9. Total Depth (MD + TVD): Same 3,450' MD, 3,450' TVD 0.9981 4b. Location of Well (State Base Plane Coordinates NAD 27): 10. Land Use Permit: 15. Property Designation: Surface: x- 266767.784 - 2587949.272 Zone- 4 N/A C-061390 TPI: x- Same - Same Zone- 4 16. Type of Completion (Describe): Total Depth: x- Same - Same Zone- 4 Multi -packer Selective w/ Sliding sleeves 17. Casing Size Weight per foot, Ib I.D. in inches Set at ft. 19. Perforations: From To 5-1/2" 15.5# 4.89" 3,427' 2,600-2,615', 2,637-2,647', 2,702'-2,722', 2,732'-2,752', 18. Tubing Size Weight per foot, Ib I.D. in inches Set at ft. 2-7/8" 6.5# 2.44^ 2,606' 2,874-2,879', 3,306-3,326', 3,322'-3.3<37' 20. Packer set at ft: 21: GOR cf/bbl: 22. API Liquid Hydrocarbons: 23. Specific Gravity Flowing Fluid (G): 2,267', 2,409', & 2,586' N/A N/A 0.56 24a. Producing through: 24b. Reservoir Temp: 24c. Reservoir Pressure: 24d. Barometric Pressure (Pa): Q Tubing ❑ Casing 92 F° 1,381 psia @ Datum 3,320' TVDSS 14.65 psia 25. Length of Flow Channel (L): Vertical Depth (H): Gg: % CO2: % N2: % H2S: Prover: Meter Run: Taps: 2,606 2,606 0.56 0 1 0 Daniel Sr. 4.026 Flange 26. FLOW C ATA TUBING DATA CASING DATA No. Prover Orifice Line X Pres ure Diff. Temp. Pressure Temp. Pressure Temp. Duration of Flow Size (in.) psi Hw F° psig F° psig F° Hr. Size (in.) 1 • 4 X 2 658.15 7.84 27.735 1128.35 61 1 hr 2. 4 X 2 635.15 16 31.74 1057.15 61 1 hr 3. 4 X 2 658.15 26.5225 36.015 968.22 63 1 hr 4. 4 X 2 658.15 34.81 37.5 893.85 67 1 hr 5. X Basic Coefficient Pressure Flow Temp. Gravity Factor Super Comp. Rate of Flow No. (24 -Hour) hw m Pm Factor F 9 Factor Q, Mcfd Fb or Fp Ft Fpv 1. 20.32 72.62 672.8 1.033 1.333 1.001 2,034 2. 20.32 101.96 649.8 1.028 1.333 1.001 2,842 3. 20.32 133.58 672.8 1.024 1.333 1.001 3,709 4. 20.32 153.03 672.8 1.022 1.333 1.001 4,240 5. Form 10-421 Rev. 7/2009 CONTINUED ON REVER915UMS UFTL251 2 3 2010 7 Submit 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 0.562 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 REVER915UMS UFTL251 2 3 2010 7 Submit in Duplicate Pc 1275 pot 1625625 • Pf 1381 p{2 1907161 No. Pt Pte Pc2-Pt2 PW Pvvz Pc2-Pv2 Ps Pse pe -P 2 1. 1129.7 1276222.09 349402.91 84.3 7106.49 1618518.51 1214 1473796 433.365 2. 1071.8 1148755.24 476869.76 71.2 5069.44 1620555.56 1143 1306449 600.712 3. 982.8 965895.84 659729.16 84.2 7089.64 1618535.36 1067 1138489 768.672 4. 908.50 825372.25 800252.75 78.50 6162.25 1619462.75 987 974169 932.992 5. 25. AOF (Mcfd) Remarks: 8760 hereby certify that the foregoing is true and correct to the best of my knowledge. Signed Title Mgr. Production Ops & Eng DEFINITIONS OF SYMBOLS n 0.938 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= T11Z 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 is 0 These results were prepared using Reservoir Solutions Software. This is not Ryder Scott work product. YG A SEAN PARNELL, GOVERNOR ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMUSSIOI�T ANCHORAGE, ALASKA 99501-3539 m PHONE (907) 279-1433 FAX (907) 276-7542 Mr. Bruce D, Webb Manager, Land and Regulatory Affairs Aurora Gas LLC 1400 West Benson Blvd., Suite 410 Anchorage, Alaska 99503 ..�( Re: Moquawkie, Undefined Gas, Moquawkie No. 4 Sundry Number: 309-367 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, -6--- Daniel T. Seamount, Jr. Chair DATED this ,3�day of November, 2009 Encl. p { "f , `*ATE OF ALASKA 1113/2,001 �j ALAOOIL AND GAS CONSERVATION COMMIS NOV Q 4 K0 APPLICATION FOR SUNDRY APPROVAL %,,, , -)n e err of �rzn Idi 11 �t GSS 1�'r01i5. UiY1Tf11SS' +i 1. Type of Request: Abandon ❑ Suspend ❑ Operational shutdown ❑ Perforate ❑ Re-enter SusrAltdoMP,� ❑ Alter casing ❑ Repair well ❑ Plug Perforations Q Stimulate ❑ Other Specify: Change approved program ❑ Pull Tubing ❑ Perforate New Pool ❑ Time Extension ❑ f Install removeable Bridge Plug_ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: AURORA GAS LLC Development ❑ Exploratory 13207-084 Stratigraphic ❑ Service ❑ 3. Address: 6. API Number 1400 West Benson Blvd., Suite 410 50-283-20120-00 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or Iandownership changes: Spacing Exception Required? Yes ❑ No 9 MO uawkie No. 4 ' 9. Property Designation (Lease Number): 10. Field/Pool(s): C-061390 oquawe Gas-Fild" eC C_tZr��ry Mki�� ' '� `/' f-(°67 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 3,450' - 3,450' 3,380' 3,380' 3,380' 3,324' Casing Length Size MD / TVD Burst Collapse Structural Conductor 80' 13-3/&'68# K55 80' 80' Surface 850' 9-5/8" 36# L-80 850' 850' 3520 2020 Intermediate Production 3,427' 5-1/2" 15.5# J-55 3,427' 3,427' 5,320 4,910 Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 2600-2615, 2637-2647, 2702-2722, 2732-2752, 287479, 2-7/8" 6.5# J-55 2,606' 3306-3326, & 3322-3337 ft Packers and SSSV Type: Weatherford Hydraulic Packers Packers and SSSV MD (ft) and TVD (ft): Packers 2,26 ', 2,409' &2,586' 12. Attachments: Description Summary of Proposal Q 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Development Q Service ❑ 14. Estimated Date for November 4th, 2009 15. Well Status after proposed work: Commencing Operations: _7 Oil ❑ Gas ❑✓ WINJ ❑ GINJ ❑ WDSPL ❑ Plugged WAG ❑ Abandoned ❑ ❑ 16. Verbal Approval: Date: Commission Representative: GSTOR ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Printed Name Bruce D. Webb Title Manager, Land and Regulatory Affairs Signatur Phone J 907-277-1003 Date 3 -Nov -09 COMMISSION USE ONLY [Sundry Number: 7 Conditions of approval: Notify Commission so that a representative may witness Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: Subsequent Form Required: APPROVED BY Date: Approved by: COMMISSIONER THE COMMISSION Form 10-403 Revised 7/2009 ORIGINAL 40m, () t III I "<'In' / / - -" - (�"? Submit in Duplicate 0 Moquawkie #4 AURORA GAS, LLC E -LINE PROCEDURE Moquawkie #4 November 4, 2009 CURRENT CONDITONS: • SI pressure – 935 psi TUBING: 2-7/8". 6.5 # with Sliding Sleeves at: 2,223' (packer fluid --closed) Opens up, Weatherford VXA 2,368' Closed (WFT XO Sleeve, opens down), no perfs 2,537' Closed (WFT XO Sleeve, opens down), no perfs (all w/ X profiles above the ports), KB of well is 14.5'. Packer depths 2,267', 2,409', and 2,586'. SUMMARY OF PLAN: Install Weatherford 2.125" Inflatable Bridge Plug in well at 2,850'. PROCEDURE: 1) RU Pollard E -Line on M#4 (no well house in place). RU lubricator on tree cap. i Open well to pressure test lubricator—have pressure gauge on lubricator. 2) AG Operators blow down well to zero or until water starts to flow from well (this is to get water into the formation where the plug will be set.) 3) RIH with CCL/Gamma Ray tool and make correlating run with Ex -Pro. 4) POH and rig up Weatherford setting tool, inflatable bridge plug and assembly. 5) RIH and set make pass with CCL/Gamma Ray and from 2,900' to 2,600' to ensure on depth. 6) Run back in hole and pullup tQ stop depth, 2,850'. 7) Set inflatable bridge plug. 8) POH and ensure equipment set properly and pull into lubricator. 9) AG Operators to blow down well and try to flow and see if improvement is made. 10) Once flow is stabilized, release Pollard and crew and RD equipment. 11) AG operators flow well to Moquawkie production facility for extended test. Monitor well closely for 24 hrs to determine water flow rate and sand production. / 12) Shutdown flow and reinstall wellhouse and equipment for winter operation. Chad Helgeson (11/3/09) .Aurora Gas, LLC Moquawkie #4 Well Configuration Revised 11/2/09 Drill 12-1/4" Hole to 850' 2-7/8" x 5-Y2" annulus displaced with inhibited packer fluid 9.5 ppg KCI to 2,223' Beluga —not completed initially Tyonek Tops Carya 2-1 — 1,734' Carya 2-2 — 1942' Carya 2-3-2230 Carya 24.2 — 2,700' Carva 2-6 — 3303' Carya2 2600• 2637 Carya2 2702 2732 Carya 2- 2874-79 Carya 2- 3306-26 3322-37 Estimated PBTD @ 3,380 • 2 7/8 6.5# 8rd EUE J-55 Tubing KB 14.5' 13-3/8" 68# Structural Conductor driven to 80' 1-5/8" 36# Surface Casing set at 850' 'ement w/ 14.5 ppg Gas -Block !nhanced ling sleeve @ 2,223' draulic-Set Packer @ 2,267' ng Sleeve @ 2,368' raulic-set Packer @ 2,409' ag Sleeve @ 2,537' If Tool above Arrowset anical Packer @ 2,586' f tail pipe, 2,6061, 2.25" no go broached to a 230" ID ad of Tail Pipe 2,856" 15.5# J-55 Casing to 3,427' MD (TVD) Drill 7-7/8" Hole to 3,450' 0 Aurora Gas, LLC Moquawkie #4 Well Configuration Proposed 11/4/09 Drill 12-1/4" Hole to 850' 2-7/8" x 5-%" annulus displaced with inhibited packer fluid 9.5 ppg KCl to 2,223' Beluga —not completed initially Tyonek Tops Carya 2-1 — 1,734' Carya 2-2 — 1942' Carya 2-3--2230 Carya 2.4.2 — 2,700' Carva 2-6 — 3303' Carya 2. 2600- 2637- Carya 2 2702. 2732- Carya 2 2874-79 Carya 2-i 3306-26 3322-37 Estimated PBTD @ 3,380 • 2 7/8 6S# 8rd EUE J-55 Tubing KB 14.5' 13-3/8" 68# Structural Conductor driven to 80' 1-5/8" 36# Surface Casing set at 850' �cment w/ 14.5 ppg Gas -Block enhanced Jing sleeve @ 2,223' draulic-Set Packer @ 2,267' ng Sleeve @ 2,368' raulic-set Packer @ 2,409' ng Sleeve @ 2,537' ff Tool above Arrowset anical Packer @ 2,586' f tail pipe, 2,606'9 2.25" no go broached to a 2.30" H) ?atherfo . 725" Inflatable Bridge ,,g @ ,850' ad of Tail Pipe 2,856" 15.5# J-55 Casing to 3,427' MD (TVD) Drill 7-7/8" Hole to 3,450' --= -Aurora Gas LLC www.aurorapower.com November 3, 2009 RECEIVED NOV 11 4 %1109 Winton Aubert, Petroleum Engineer 418sk8 Oil & Gas Cons. Commission State of Alaska Anchorage Oil and Gas Conservation Commission 333 West 7"' Avenue, Suite 100 Anchorage, AK 99501 RE: Sundry Approval Request for inflatable bridge plug installation procedure for Moquawkie #4 Development Gas Well, Permit to Drill No. 207-084 Dear Mr. Aubert: Pursuant to 20 AAC 25.280, Aurora Gas LLC ("Aurora") request sundry approval to install a 2.125" Weatherford Inflatable Bridge Plug in the 5-1/2" casing in the Moquawkie #4 development gas well at 2,850'. This well has been on production and started making more water and sand than the surface facilities can handle. We conducted a flowing survey on this well and think we can cut off a bunch of the water and sand production with this operation. We will use the Weatherford tool and setting equipment with Pollard Wireline's a -line equipment and Ex -Pro E -line engineer for this work. Attached, please find the 10-403 Application for Sundry Approval, the proposed e -line procedure and a well schematic showing the current well configuration. Thank you for your review and consideration of this request. We just received the data on the production survey (10-30-09) to make this job possible and with the weather getting colder and barge season shortening we have the opportunity to get this job completed this week if we get the approvals for the work. Should questions arise in connection with this request, please contact Mr. Chad Helgeson at the Anchorage 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 Ll 0 Mr. Steve Davies Alaska Oil and Gas Conservation Commission February 11, 2009 333 W. 7`i' 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: SCHLUMBERGER DATA CD's Moquawkie #4 Field PDS Graphics and LAS of: DSI/PEX/AIT Main Log Lone Creek #4 Field PDS Graphics and LAS of: 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. Bruce D. Webb Manager, Land and Regulatory Affairs RECEIVED AND CICEPTED ABOV This _day of ��' , 2009. 1400 West Benson Bien!., Suite 410 *Anchorage, AK 99503 ® (907) 277-1003 a Fax., (907) 277-1006 6051 North Course Drive, Suite 200 a Houston, TX 77072 ® (713) 977-5799 9 Fax: (713) 977-1347 P_ .�, f t x, f STATE OF ALAS, ALA OIL AND GAS CONSERV� i66I9SION WELL COMPLETION OR RECONIft raTIQ,, SORT AND LOG 1a. Well Status: Oil Gas ✓ Plugged Abandoned 20AAC 25.105 Suspe4 pWAG 20AAC 25.110 ell Class: Development Exploratory ❑ GINJ ❑ WINJ ❑ WDSPL ❑ No. of Completions Other Service ❑ Stratigraphic Test ❑ 2. Operator Name: 5. Date CoSusp.,r .1 -fie.° t to 2. PermiDrill Number: Aurora Gas, LLC Aband.: it Nov. , 2008 207-084 3. Address: 6. Date Spudded: 13. API Number: 1400 West Benson Blvd, Suite 410 Anchorage, AK. 99503 Sept. 25, 2008 50-283-20120-00 - 4a. Location of Well (Governmental Section): 7. Date TD Reached: 14. Well Name and Number: Surface: 1160' FNL, 1415' FEL, Sec 1, T11N, R12W, SM 24 -Oct -08 • Moquawkie #4 Top of Productive Horizon: 8. KB Elevation (ft): 15. Field/Pool(s): 1160' FML, 1415- FEL, Sec 1, T11N, RI 2W, SM 314' KB - Total Depth: Mgquawkie Undefined Gas Pool 9. Plug Back Depth(MD+TVD): 1160' FNL, 1415' FEL, Sec 1, T11N, R12W, SM • MD 3399' TVD 3399' - 4b. Location of Well (State Base Plane Coordinates): NAD 27 10. Total Depth (MD + •fVD): 16. Property Designation: Surface: x- 266767 • y- 2587949 • Zone- 4 MD 3450' TVD 3450' C-61390 - TPI: x- 266767 y- 2587949 Zone- 4 11. Depth Where SSSV Set: 17. Land Use Permit: Total Depth: x 266767 y- 2587949 Zone- 4 NIA CIRI Lease 18. Directional Survey: Yes ✓ No El 19. Water Depth, if Offshore: 20. Thickness of Permafrost: N/A feet MSL NIA 21. Logs Run: Schlumberger Hole Logs: BestDT, DSI Processing; Haliburton end of well log and mud logs 22. CASING, LINER AND CEMENTING RECORD WT. PER GRADE SETTING DEPTH MD SETTING DEPTH TVD HOLE SIZE CASING FT TOP BOTTOM TOP BOTTOM CEMENTING RECORD AMOUNT PULLED 13-3/8 68.0# H40 Surface 80' RKB Surface 80' RKB driven Drilled and Driven 9-518 36.0# J-65 Surface 855' Surface 856' 12.25" 360 sks,13.3 and 14.5 ppg gas -block enhanced curt 6-1/2 15.5# J-65 Surface 3,427' Surface 3,427' 7.875" 3 stage, 1126 sks,13.6 ppg +500 sks,16.8 ppg "G" curt 23. Perforations open to Production (MD + TVD of Top and Bottom 24. TUBING RECORD Interval, Size and Number; if none, state "none'): SIZE DEPTH SET (MD) I PACKER SET (MD) 2-718", 6.5# 2,856' 2,549, 2,691', 2,837' 2,60W.2,615', 2,637'-2,647', 2,702'.2,722', 2,732'-2,752', 2,874' - 8rd EWE, J-55 2,879', 3,306' - 3,326', 3,322' - 3,337- MD/TVD. 3.5" HST Poweryet Omega, 6 spf, 60 deg phasing 25. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 520' - 525' 21 bbis @ 14.7 ppg Class G cement w/ 2% CaCI 520' - 52V 2.2 bbis @ 15.8 -16.0 ppg Class G cement w/ 11% CaCI 26, PRODUCTION TEST Date First Production: Method of Operation (Flowing, gas lift, etc.): December 31, 2008 Flowing, 4 hm. at 1.9 MMcfpd 1080 psi. ' Date of Test: Hours Tested: Production for Oil -Bbl: Gas -MCF: Water -Bbl: Choke Size: Gas -Oil Ratio: 1 12/20/2008 10 hm Test Period 0 5,582 mcf 9 bbis 16164" to 26164" na Flow Tubing Casing Press: Calculated Oil -Bbl: Gas -MCF: Water -Bbl: Oil Gravity - API (corr): Press. 24 -Hour Rate —.0. 27, CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water (attach separate sheet, if necessary). Submit core chips; if none, state "none". No cores taken. ✓ - '"..CN )irT�: .... R Form 10-407 Revised 12/2003 ! r ONTINUED ON REVERSE /3�� 28. GEOLOGIC MARKEW 29. FORMATION TESTS NAME MD TVD Include and briefly summarize test results. List intervals tested, and attach detailed supporting data as necessary. If no tests were conducted, state "None". d-1p y ot, "See Attachment" ( ryQ 2-a ear�4L L --3 Z. ZZ 30 2-V.2— 2, Z X40 From, At OaW4,w- 7 30. List of Attachments: Formation Tops 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: Title: Manager, Land and Regulatory Affairs Signature: �Jr tfr, Phone: 907 277-1003 Date: 2/3/2009 INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. Item 1 a: Classification of Service wells: Gas Injection, Water Injection, Water -Alternating -Gas Injection, Salt Water Disposal, Water Supply for injection, Observation, or Other. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 4b: TPI (Top of Producing Interval). Item 8: The Kelly Bushing elevation in feet above mean low low water. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 20: True vertical thickness. Item 22: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 23: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 26: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 27: If no cores taken, indicate "none". Item 29: List all test information. If none, state "None". Form 10-407 Revised 12/2003 0 • Aurora Gas, LLC Moquawkie #4 Actual Configuration Drill 12-1/4" Hole to 868' Tyonek Tops Carya 2-1 — 1,734' Carya 2-2 — 1942' Carya 2-1 Carya 2-3--2230 Carya 24.2 — 2,700' Carva 2-6 — 3303' Carya 2-: Carya2 2600• 2637 Carya2 2702 2732 Carya 2874• Carya: 3306-: 3322 PBTD @ 3,399' 2 7/8 6.5# 8rd EUE J-55 Drill 7-718" Hole to 31450' 13-3/8" 68# Structural Conductor to be driven to 80' S/8" 36# Surface Casing set at 855' ement w/ 14.5 ppg Gas -Block enbanced Sliding sleeve 1 joint above packer at 2507' Hydraulic Set Packer @ 2549' Sliding Sleeve @ 2650' Hydraulic -set Packer @ 2,691' Sliding Sleeve @ 2,791' M Toot at 2833' above Arrowset hanical Packer (w)M7' w/ 2.31 Je XN nipple w/ 2.205 NoGo 15.5# J-55 Casing to 3,427' MD (TVD) cut w/ 125 sx 13.5 ppg+500 sx 15.8 ppg ti..."s `G' • 0 AURORA GAS, LLC MOQUAWKIE 4 (AOGCC PERMIT No. 207-084) (API No. 50-283-20120-00) DRILLING AND COMPLETION OPERATION SUMMARY 8/15/08 -9/14/08 ---Construct new well pad. 9/16/08—Start moving equipment from Three Mile Creek 2 to Moquawkie 4 location. 9/17/08 --Move in rig and related equipment. 9/18/09 --Continue move in and rig up. 9/19/08 --Continue move in and rig up. 9/20/08—Continue move in and rig up. 9/21/08—Continue move in and rig up. Cut conductor and install slip-on head. 9/22/08 ---RU diverter system, bell nipple, flow line, diverter lines, 9/23/08 --Function test diverter, knife valve, gas detectors, flow -line sensors. Start drilling mousehole. 9/24/08 ---Continue drilling mousehole, encountering large rocks and washing out cellar base. Start driving and drilling mousehole sheath. 9/25/08—Finish installing mousehole. Fill in around cellar. PU mill and clean out conductor. PU 12-1/4" bit, 6" DC's, and RIH to 95' KB (80' from GL). PU Power Swivel. Fill hole and check for leaks. SPUD at 1700 hrs. Drill to 124'. MW -9.0 ppg. 9/26/08—Drill 12-1/4" hole to 178' w/ 6" DC's. POOH, LD 6" collars. PU 8" BHA, RIH to 140', wash and ream to 178'. MW -9.0 ppg. 9/27/08—Drill 12-1/4" hole from 178' to 460'. MW -9.2 ppg. 9/28/08—Drill 12-1/4" hole to 495'. Repair power swivel hydraulic power unit. Drill to 524'. Survey -0 deg Drill to 868'. Survey -0.75 deg. RU to run 9-5/8" casing while circ and cond hole. Start short trip --well kicked after 2 stands at 2230 hrs. Stab safety 0 i valve, close annular/open diverter. PU to pump dynamic kill. Evacuate non-essential personnel from location and block road. Weight up mud. MW -9.7 ppg. 9/29/08—Continue building mud weight to 10.3 ppg. Pump around at 14 BPM— unsuccessful, did not kill well. Build mud weight to 13 ppg and volume to 370 bbl. Pump dynamic kill with 13 ppg mud at 14 BPM. No returns until about 122 F5Tpuniped, then open annular and take returns until MW 13 ppg all around at a ppg- .5 ppg mua. circ out gas ana cuttings Wash an ream to bottom. MW -12.8 9/30/08—Wash & ream to bottom. Clean up pad. POOH slowly to 186', RIH to 868'. Circ and condition hole. POOH, LD 8" BHA. RU and run 855'9-5/8" 36# K-55 BTC casing. RD casing crew. Prep to cement. 10/01/08—Pump 13 bbl spacer, Pump 130 bbl cement (360 sx mixed at 13.3 and 14.5 ppg), displace w/ mud. Did not bump plug., Circ 5 bbl cement to surface, W.O. C. ND diverter system. Make rough cut on 9-5/8". Make final cut. Preheat casing to weld on head. 10/2/08—Weld on starting head. Test to 1600 psi. NU BOP. 10/3�-�Fin NU BOP. Test BOP—witnessed by Chuck Scheve w/ AOGCC. Install wear ring. LD 2 6-3/4" DC's. PU/MU 4-3/4" BHA. RIH, tag cement at 792'. PU PS. Circ and condition mud, reducing weight from 12.8 ppg to 10.5 ppg. 10/4/08—Drill cement to 805'. Drill float collar and cement to 827'. POOH and change jets. RIH to 827'. Test casing to 1600 psi. Weld derrick board. Drill cement to 845'. CBU. POOH. RU Schlumberger and run temperature and bond logs. 10/5/08 --Continue running temp and bond logs. W.O. USIT tool. Run USIT log. POH w/ tool, lost bow spring. W.O. weather for packer and BP. RIH. Wash and ream to 825'. 10/6/08—Mill cement to 845'. POH and clean junk basket. RIH and mill/reverse circulate to 8461. POH. LD junk basket—no fish. PU EZ -Drill BP, run to 530', and set. POH, LD running tool. W.O. cementers, delayed by weather. MW -12.8 ppg. 10/7/08 --Continue W.O. cementers. RU Schlumberger. Run 5' 2-1/2" HSD gun w/ 4 SPF and perforate for squeeze at 520-525'. POH & RD SLB. Pump 2 bbl mud into perfs art 1.3 BPM at 385 psi—ISIP-325 psi. PU and run RTTS packer to 470' and set. RU BJ. 10/8/08—BJ pumped 10 bbl mud at 1, 1.5, then 2 BPM at 415 psi last 3 bbl. Mix and pump,squeeze of 82 sx (21 bbl)14.7 ppg Class G cement w/ 2% CaCI & additives at 2 BPM and 300 psi. Open ports on RTTS and rev out. Pull 1 jt, reset RTTS at 440'. Pressure to 125 psi—held at 90 psi. RD BJ. WOC 12 hrs. Release RTTS, POH—found 0 soft cement in 2nd stand. Run back in, circ clean, POH, LD RTTS. RU SLB. Run 3 passes of temp. log w/ 2.5 and 3 hrs between runs -logs inconclusive. 10/9/08 -Fin temp' surveys, RD SLB. PU 7-7/8" bit, RIH. Tag cement at 452'. Drill soft cement to 510'. WOC 15 hrs. Drill soft cement to 520'. 10/10/08 -Drilled soft cement to top of EZSV at 528'. Test perfs-break down at 260 psi, dropped to 180 psi. Est. injection rate: took mud at 450 psi, fell to 350 psi after 4 bbl pompe at /4 BPM. ISIP-180 psi. Circ out. POH. Test BOP-AOGCC waived witnessing. PU mule shoe and RIH on DP to tag EZSV. Pull up V to 527', C & C to prep to spot balanced plug. 10/11/08 -Pump 5 BW. Mix and spot 75 sx (15.2 bbl) Class G w/ 1% CaCI + additives at 15.8 -16.0 ppg, follow w/ 1.4 BW. Pull and LD 8 jts of DP to 287'. (Calc TOC -3 1'). Squeeze 2.2 bbl at 0.2 BPM at 480 psi -locked up at 550 psi. 30 -min SIP -495 psi. Repressure to 536 psi. SI. WOC. 480 psi after 3-1/2 hr., 345 psi after 7 hrs. Bleed off. Rev out 2X BU. Pressure to 482 psi. WOC 3 hrs--416 psi. Bleed off. POH w/ DP. PU bit and BHA. RIH and tag cement at 358'. C & C. Drill out good firm cement to 420'. MW -12.4 ppg. r 10/12/08 -Continue drilling cement to 495' -last 45' soft. WOC 8 hrs. Drill 5' hard cement --circ BU. Drill out hard cement to top of EZSV at 528'. Circ clean. Pressure test to 500 psi in stages -bled off 12 psi in 45 min. POH. MU junk mill and boot basket, IUFF- 10/13/08-Cont, RIH. Ream cement skin from 358' to 528', top of EZSV. Circ BU. Re -test casing to 500 psi for 15 min. -held OK. Mill EZSV from 528-530'. MW -11.1 ppg_ 10/14/08 -Continue milling on EZSV broke thru and push down hole to 837. Mill on junk and cement 837' to 850'. Circ and condtion hole and inc MW to 11.5 ppg. Test casing to 498 psi -lost 15 psi in 30 min --OK Continue milling to 854, broke thru shoe. Wash and ream 12-1/4" rat hole to 869'. Circ clean. MW -11.5 ppg. 10/15/08 -Drill 5' new hole to 874'. Circ and cond. Dump cement contaminated mud. Build mud volume. Displace hole w/ new 11.5 ppg mud., circ and condition. POH, LD DP, mill, and boot basket. PU 7-7/8" bit and RIH. Drill to 8891. Perform FIT/LOT: leaked off at 14.2 ppg EMW (137 psi w/ 11.5 ppg mud). Drill 20' to 909'. Repeat FIT to 210 psi (16.2 ppg EMW) --slow leak off to 185 psi in 25 min -OK. Drill to 920'. MW -11.5 ppg. 10/16/08 -Drill to 13869, circulating out gas at 1047', 1091', 1124, 1190', and 1231'. Circ and condition for survey. MW -11.5 ppg. 0 • 10/17/08 -Survey at 1350'-1-1/4 deg. Short trip into surface casing to 795'. Drill to 1604'w/ circ out gas at 1534', 1541', and 1604'. Survey at 1571'-1 deg. CBU 2X. POH slowly to 824'. Circ and cond. POH. MW -11.5 ppg. 10/18/08 -Test BOP'S-AOGCC waived witnessing. RIH. Wash and ream to bottom. Drill to 17001. MW ---11.6 ppg. 10/19/08 --Drill to 2074' w/ max gas at 1758'. CBU 2X. Survey at 2074'--2 deg. CBU. Start POH. 10/20/08-POH slowly to 1575. RIH (ST). Wash and ream to bottom. CBU. Drill to 2397' w/ max gas at 2268'. MW -11.4 ppg. 10/21/08 -Drill to 2574'. CBU. Survey -2 deg at 2574'. CBU. Drill to 2605' w/ drlg break 2576-2605'. CBU. Short trip to 2050'. Drill to 26761. MW -11.4+ ppg. 10/22/08 -Drill to 2916'. CBU. Survey -4-1/4 deg at 2885'. POH. PU new bit and 3- 4-3/4" DC's. Prep to RIH. MW -11.4 ppg. 10/23/08-RIH w/ new bit. Tag at 2730'. Circ out gas. Ream to 2916'. Repeat survey -2-1/2 deg at 2885'. Pump out 6 jts, run back in hole. Drill to 3102'. MW - 11.4+ ppg. 10/24/08 -Drill to 3401'. Circ up samples and review mud log. Drill to 3450', circ up samples and review mud log -TD.. MW -11.4+ ppg. 10/25/08 -Short trip w/ some tight spots -work thru. RIH. Mix and pump high -vis sweeps. CBU. Survey -2 deg at 3400'. POH to shoe, working thru tight spots at 2040' and 1900'. Continue POH. Start BOP test. RU SLB for open -hole logs. MW -11.4+ ppg- 1026/08-Fin BOP test --all OK. Witnessing waived by Jim Regg. Fin RU Schlumberger. Run PEX (Array Induction/Density/Neutron) to 3416'. Log up to 700'. RU and run DSI (di -pole sonic) from 3420' w/ GR to surface. RU and run CST (sidewall core gun) to 3400'. Pull up to 3300' -one shot and tool failed. POOH. PU 2nd CST gun, run. MW -11.4+ ppg. 10/27/08 -Attempt 21 SWC's from 3330-1063'. POOH. Recover 18 core samples. RU and run XPT (Express Pressure test tool). Attempt 21 formation pressures between 3335' and 1082'-l0 good tests. POOH. RD SLB. RIH w/ bit to surface casing shoe. MW - 11.4+ ppg. 10/28/08 --Circ bottoms up. RIH to 3330'. Wash & ream to bottom. Short trip to 2627', back to bottom. CBU 3X. POH, LD DP. MW -11.4 ppg. 0 • 10/29/08—LD BHA. Clean pit and mix 50 bbl KCI brine. Change rams to 5-1/2". RU GBR to run casing. Run 80 jts of 5-1/2",15.5#, J-55, BTC casing to 3427. RU BJ to cement. 10/30/08—Fin RU BJ. Mix and pump 20 bbl spacer at 11.0 ppg , then 41 bbl (125 sx) Class G lead blend cement at 13.5 ppg, then 105 bbl (500 sx) Class G tail blend cement at 15.8 ppg, displace w/ 80.3 bbl 9.3 ppg KCI water (overdisplace by 1 bbl as plug did not bump). Floats held. Full returns while cementing, including 40 bbI lead blend to surface. WOC 12 hrs---chance rams to 2-7/8" and clean mud pits. MW ---9.3 ppg brine. 10/31/08—ND BOP. Set slips. Cut off 5-1/2". Install and test tubing spool. NU BOP. Test BOP. MW -9.3 ppg. 11/i/08 Fin test BOP. (Witness by AOGCC was waived by Jim Regg). PU, strap, and drift 2-7/8" 6.5#, J-55, 8rd EUE tubing, running hole (42 jts). MW -9.3 ppg. 11/2/08 ---Continue PU and run 2-7/8" tubing—tag float collar at 33371, with 110 jt. Mix 9.4 ppg KCl -NaCl brine. Thaw lines, Drill float collar and cement to 3399'. 11/3/08—Strap out of hole. PU casing scraper. RIH to tag at 3399'. RU to filter brine. Test casing to 2000 psi—lost 75 psi in 20 min—held at 1925 psi—OK. POH. RU Schlumberger and run CMT CBL from 3398' to surface. RD SLB. RIH w/ bit and scraper. 11/4/08 --Continue RIH to 3399'. Circ and condition brine, filtering to 5 micron and building volume and weight to 9.4 ppg. POH, strapping 2-7/8" tubing. RU SLB to perf. 11/5/08 --RU lubricator and test to 1500 psi. RIH w/ 10' gun and GR/CCL correlation tool. Correlate to PEX. Perforate 3322-37' (Carya 2-6). Make 6 more runs and perf 3706-16' (Carya 2-6), 2874-79' (Carya 2-5), 2737-52' & 2702-22' (Carya 2-4.2), and 2637-47' & 2600-15' (Carya 2-4.1) w/ 6 SPF w/ 3-1/2" Power Jet Omega guns. Lost 3.5 bbl when perforating Carys 2-4.2 and 2-4.1). POH. RD SLB. Prep to run bit and scraper. 11/6/08—RIH w/ bit and scraper to 3392'. Circ and filter brine, POH, LD I I jts tbg, scraper, and bit. PU and run completion on 2-7/8" tubing, including Weatherford AS -1 mechanical packer (set at 2837') 2 -- PHR hydraulic packers (at 2691' and 2549'), 2 XO sliding sleeves (at 2791' and 2650'), and an XA sliding sleeve at 2507'. Space out. Land tubing. Set mechanical packer. Release On -Off tool. Pull up 4' and circulate 55 bbl inhibited brine. Re-engage On -Off tool. Land tubing. Drop ball and pressure up 3500 psi to set hydraulic packers and shear out ball. 11/7/08—NU BOP. NU and test tree to 2500 psi. I/RU test equipment. RU Pollard Wireline. 0 • 11/8/08—Fin RU Pollard lubricator and BOP—test to 1500 psi. Packing failed. Repair and retest --OK. Test tree to 3000 psi --OK. Swab 70', well kicked off—flow 28 bbl thru gas buster. Turn to test unit. Light flare and flow for 3 hours, FFP -1111 psi. Sl well. ISIP-1271 psi. 30 -min. SIP --1320 psi. RU Pollard and ran XV plug to set at 2854', but stopped and released at 2595'. POH, get retrieving tool, RIH, and retrieve plug. Ran 2.25' gauge ring—stopped at 26051. Ran 1.75" GR to btm. Ran 2.0" Gr, hung up a bit but went to btm. Ran 2.25" GR, stopped at 2605'. RD and release Pollard. Release rig and start rig down. 11/9/08 --Continue rig down and start move to Lone Creek 4. Set BPV in tree. 11/10-1 1/08—Continue rig down and move out. 12/20/08—Four-point tested thru Aurora Gas test unit: SITP-1181 psi. Open well and flowed 10 hours, made 9 bbl water: 4483 mcfpd at 985 psi on 26/64" choke 3799 mcfpd at 981 psi on 23/64" choke 2987 mcfpd at 1052 psi on 20/64" choke 2127 mcfpd at 1126 psi on 16/64" choke 1 -hour SITP-1200 psi. 12/31/08—after constructing flowline to Moquawkie Facility and installing satellite facility on well site, started production to sales (4 hours) at about 1.9 MMcfpd at 1080 psi. Ed Jones (2/3/09) 9 0 =Aurrora Gas, LLC www.aurorapower.com February 3, 2009 Tom Maunder, Senior Petroleum Engineer State of Alaska Oil and Gas Conservation Commission At , Anchorage, 333 W. AAK 99 Olte 100 ��' � �' g Re: Permit to Drill No. 207-084 Moquawkie #4 Development Gas Well Well Completion Report Dear Mr. Maunder: Aurora Gas, LLC (Aurora) hereby submits the Well Completion Report for the Moquawkie #4 development gas well in the Moquawkie Unit on the west side of the Cook Inlet. Attached, Please find the AOGCC Form 10-407, a well schematic showing the current well completion configuration, and the Drilling and Completion Operation Summary. 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 -,,�-Auwra Gas, Mr. Steve Davies February 3, 2009 Alaska Oil and Gas Conservation Commission rw 333 W. 7"' Avenue, Suite 100 Anchorage, AK 99501 RE: Moquawkie #4 Dear Mr. Davies: k' 3t 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 Moquawkie #4 Platform Express, Array Induction Express Pressure Tool, XPT — GR Chronological Sampler Taker, CST — GR Dipole Sonic — GR, Monoplole P&S / Lower Dipole Cement Bond Log, 3-3/8" Digital Sonic Logging Tool, GR/CCL Cement Bond Log, Ultrasonic Imaging Tool, CCL Temperature Log, GR/CCL Perforating Record, 2.5" PF HSD, 4SPF, 60Deg, GR/CCL 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 RECEIVED AND ACCEPTED ABOVE DATA This _day of , 2009. 1400 West .Benson Blvd., Suite 410 a Anchorage, AK 99503 a (907) 277-1003 a Fax: (907) 277-1006 6051 North Course give, Suite 200 a Houston, TX 77072 a (713) 977-5799 a Fax: (713) 977-1347 m " Gasy LLC Alaska Oil and Gas Conservation Commission December 9, 2008 333 W. th Avenue, Suite 100 Anchorage, AK 99501 Attn: Mr. Jim Regg RE: Moquawkie #4 Dear Mr. Regg: 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 SCHLUMBERGER LOG RECORD Moquawkie #4 - One paper copy BestDT* DSI Processing HALLIBURTON - SPERRY DRILLING SERVICES Moquawkie #4 - One bound report w/ 3 paper log and CD End of Well Report Mud Logs 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 RECEIVED AND ACCEPTED ABOVE DATA This / -day of 52008. BY: TITLE: a West Benson Blvd., Suite 410 ®Anchorage, AK 995 17. , -'907) 277-1093 o Fax.a (907) 277-I D06 3C.-71" North Course Drive, Suite 200 ® Houston, TX 77072 , 47.23,", y7713) 977-1347 0 • MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Reggi z(17 DATE: November 24, 2008 P. I. Supervisor P 1 Nk FROM: John Crisp, SUBJECT: Temporary Drilling Waste Petroleum Inspector Storage Areas * �y4a,�°� 4- D , 70-7- Obq- 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 I inspect temporary drilling waste storage areas for Lone Creek #4 & Moquawkie #4. Lone Creek #4 — The storage pit was being prepared for cuttings when I 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. V/M0000quawkie #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 Temporary Drilling Waste Storage Areas Photos by AOGCC Inspector J. Crisp November 24, 2008 Lone Creek — temporary waste storage area construction 0 i Moquawkie — temporary waste storage area construction 11 0 MEMORANDUM TO: Jim Regg P. I. SupervisorCe' FROM: John Crisp, Petroleum Inspector State of Alaska Alaska Oil and Gas Conservation Commission DATE: SUBJECT: November 24, 2008 Aurora Gas, LLC Moquawkie #4 PTD 207-084 Well Inspection 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 I also inspect Moquawkie #4's wellhead & Pad after the Lone Creek #4 Diverter Inspection. Moquawkie #4's OA -IA, Master, Swab & Wing valves were found to be shut in with no pressure monitoring at the time of my Inspection. No valves were opened to observe pressures. Conductor by Surface casing annulus was found to have been packed with cement to a depth of approximately 3' to prevent gas release to cellar. The conductor was supposed to have been vented to prevent gas from building pressure & releasing from the top of conductor. This vent line was either not there or covered with snow in the cellar. Small but steady amount of gas was venting from conductor by surface casing annulus. Audible gas release from conductor by surface casing was witnessed. Small amount of red substance was noticed on top of snow in the cellar. With the gas release between conductor by surface casing suspicion of this red substance being pre -cement red dye spacer from surface casing cement job could be in question. The red sheen could be explained as coming from a different source. After the Surface hole diverting event AOGCC required cement to surface on the surface casing was most probably a priority. Moquawkie #4's location was not cleared of snow & had well testing equipment attached to the well. I do not know if well testing had been completed. It was difficult if not impossible to inspect location with snow & equipment on & around location. Summary: I inspected Aurora Gas LLC Moquawkie #4 well for surface casing to conductor gas migration & release. Attachments: Photos Moquawkie-4 well_2008-1124jc.doc Moquawkie #4 Wellhead and Pad Inspection Photos by AOGCC Inspector J. Crisp November 24, 2008 Moquawkie #4 production tree Moquawkie #4 flowline, surface production equipment Moquawkie #4 conductor by surface annulus; red dye on snow released from annulus Moquawkie-4_well_2008-1124_ic. doc ,Aurora Gas, LLC wwwaurorapower.com November 12, 2008 Thomas E. Maunder Senior Petroleum Engineer State of Alaska Alaska Oil and Gas Conservation Commission 333 W. 7t' Avenue, Suite 100 Anchorage, AK 99501 Re: Notification of Uncontrolled Release of Gas 30 Day Report Moquawkie #4 Development Gas Well Dear Mr. Maunder: REIE N'U'' 1 1 2 2008 Alaska Oil & Gas tons. Commission ARcI'sorage Pursuant to 20 AAC 25.205 (b), Aurora Gas, LLC (Aurora) hereby submits the following factual information regarding the gas diverter event at the Moquawkie No. 4 drilling operations for a development gas well on the west side of the Cook Inlet.. 1. The incident occurred at 10:30 PM on September 28, 2008. The event lasted approximately 22.5 hours, ending by 9:00 PM on September 29, 2008. 2. The event occurred at the Moquawkie No. 4 well site, Permit to Drill #207-084, located within Section 1, Township 11 North, Range 12 West, Seward Meridian. 3. The rate of gas released was estimated to be as high as 1 to 2 MMcf/day for most of the 22.5 hours that the well flowed through the diverter. The pressure and volume fluctuated during the event, and these rates were estimated by the rig supervisors based on visual observation of the gas plume coming from the diverter line. It was reported that, at times, the gas projected approximately eight to twelve feet from the end of the 12" diverter line. Thus, if the flow rated averaged 1.5 MMcf/day, the total volume vented is approximately 1.406 MMcf, 4. The cause of the event is attributed to an over -pressured coal sear close to the surface in combination with a too -near -balances -d–r1 ing mud weight (at.2-9.4 ppg). The well had been drilled to 868' at this mud weight, without incident. On 9/28/08 at 8:30 PM, the surface casing point was reached, and the well was circulated to clean out the hole and was determined to be dead—essentially no gas on the mud log for over an hour. 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 The short trip was started about 10:00 PM. At 10:30 PM, two stands of drill pipe had been pulled out of the hole, placing the bit at approximately 750' below the surface; the same depth as a coal seam with a gas show as indicated by the mud log. As the drill bit passed this coal seam, it apparently had a swabbing effect on the coal seam, reducing the hydrostatic pressure and allowing the gas influx. 5. Control of the well was lost at approximately 10:30 PM on the 28`h. The drilling crew immediately took responsive actions by installing a safety valve on the drill pipe, shutting the annular blow out preventer, and opening the actuated diverter valve. The location was cleared of all non-essential personnel. The drilling mud in the pits was weighted up to 10.6 ppg and an attempt to pump and kill the well was made. This mud was blown out of the hole as it was pumped in. A total of approximately 250 bbls of mud was lost through the diverter. Additional mud had to be mixed to a weight of 13 ppg and pumped at 14 bblslmin. to kill the well—full returns were obtained after pumping 122 bbl. The well was back to normal circulation by 9:00 PM on the 29`h 6. In the future, Aurora Gas will use 11-11.5 ppg mud during surface drilling operations in this area. A basin will also be constructed at the end of the diverter line to minimize the impact to the environment if the event did happen again, where a supersucker or vac truck could recover any lost fluids. Keeping the mud weight overbalanced until the surface casing is set will minimize the possibility of future occurrences. Aurora Gas, LLC commends the drilling crew of the Aurora Well Service rig for their immediate and by -the -book response to this incident. Further, Aurora appreciates the assistance and oversight provided by the AOGCC during this drilling program. Should questions arise in connection with this request, please contact me at the Anchorage office, or Mr. Ed Jones in the Houston office at (713) 977-5799. Respectfully Submitted By, Bruce D. Webb Manager, Land and Regulatory Affairs 0 0 Page 1 of 3 Maunder, Thomas E (DOA) From: David Boelens [dboelens@aurorapower.com] Sent: Monday, September 29, 2008 3:28 PM To: Maunder, Thomas E (DOA) Cc: 'Ed Jones' Subject: FW: Some Recommendations from Wild Well Control Tom Here is the kill procedure from Wild Well Control. We have 250 bbls mixed and 50 bbl more to go. Kill fluid will be 13.0 ppg Estimate on flowing gas at daylight was a million a day and 40 bbls of water per hour be dropping over time. Estimate a 5 foot plume out the 12 inch divert. David Boelens VP Alaska Operations Aurora Power/Gas/Well Service/Shirleyville Ent Phone 907-277-1003 Fax 907-277-1006 Cell 907-223-0713 From: aurorapower@gci.net [mailto:aurorapower@gci.net] On Behalf Of Ed Jones Sent. Monday, September 29, 2008 12:24 PM To: 'Ag Company Man'; sirromeyo@yahoo.com Cc: 'Chad Helgeson'; 'David Boelens'; 'Scott Pfoff (E-mail)' Subject: Some Recommendations from Wild Well Control Gas volume appears to Gentlemen, Please review the attached and call me. It appears that the proposal of 13.0 ppg mud pumped at 13.4 BPM (560 GPM/200 SPM combined pump rate) is the best plan. What volume did the nut plug sweep give us? Assuming a 12-1/2" hole, I get an annular volume of about 97 bbl --what are you thinking it is? Please call and let me know the status and plans --obviously it would be good to get this done during daylight, with some time to spare. Thanks, Ed From: David Barnett [mailto:dbarnett@wildwell.com] Sent: Monday, September 29, 2008 3:07 PM To: Ed Jones Subject: RE: MSA (WWCI) Ed: I've been trying to put some of the kill modeling information into a more presentable format but probably just as well that I pass it on to you in this email. 9/29/2008 0 Page 2 of 3 I have modeled the flow as very dry gas. Water production will theoretically reduce the required kill rate with a given mud density since the flowing density if slightly higher that pure gas. However, the .67 bpm won't have a significant impact. I have modeled kill weight mud as follows: 10.0 ppg 26.2 bpm 10.5 ppf 22.0 bpm 11.0 ppg 18.7 bpm 11.5 ppg 17.1 bpm 12.0 ppg 15.7 bpm 12.5 ppg 14.4 bpm 13.0 ppg 13.4 bpm 13.5 ppg 12.0 bpm 14.0 ppg 11.3 bpm 14.5 ppg 10.8 bpm 15.0 ppg 10.3 bpm All simulations were done with PV = 9 & YP = 21. Varying the rheology did not have a large impact on the kill rate - only the friction pressure through the drill string. This is not too surprising since the annular friction at 13.5 bpm is only 1.4 psi. The kill is purely by building hydrostatic pressure at a sufficient rate and does not rely on annular friction to any large degree. The decrease in pump rate per ppg increase in mud weight is highest from 10.0 ppg up to 12.5 ppg where it decreases the necessary rate by 11.8 bpm (26.2 bpm down to 14.4 bpm). The next 2.5 ppg increase in mud density from 12.5 ppg up to 15.0 ppg only reduces the required kill rate by 4.1 bpm (14.4 bpm down to 10.3 bpm). Since you have the capability to pump around 13.0 bpm to 14.0 bpm it makes sense to go with mud density in the 12.5 ppg to 13.0 ppg range. Further increase in density does not yield a corresponding decrease in pump rate required to kill. 1 believe that circulating s sufficient amount of fluid is key to getting the well dead and keeping it dead. We not only need to re-establish hydrostatic equilibrium at the coal seam(s) but we also need to clear the gas cut mud from the annulus else migration might cause enough mud to be expelled that it will cause the entire well to unload and we'll be back in a flowing situation. The heavier mud will assist with this since it will increase the margin we have for fluid to be expelled while maintaining adequate BHP at the flowing zone. Other tidbits: (mostly goes without saying, but good reminders) • Make sure all fluid and equipment is ready so it is not necessary to shut down in the middle of the kill operation. Unloading mud places significant stresses on the surface equipment and the conductor shoe and should be avoided as much as possible. • Try to reduce pump pressure with large ID pump lines to the extent possible • Be prepared to top off the well in case it will not remain full after kill operations • If possible, start the operation early in the day so that you have a full day to accomplish the well kill 1 will be around for the remainder of the day and part of tomorrow before I have to fly out of the country. I will have to tum this over to someone else if more work is required. If you need to contact me please use the cell number from this morning. Regards, David Barnett 9/29/2008 0 0 Page 3 of 3 Wild Well Control, Inc. Vice President, Engineering Services dbarnett@wildwell.com • www.wildwell.com 281.784.4700 Phone 0 281.784.4750 Fax "Experience Makes The Difference" The contents of this message are provided for informational purposes only. Wild Well Control, Inc. does not guarantee the accuracy or completeness of the contents and assumes no liability whatsoever for loss or damage arising out of recipient's reliance on or use of the information provided herein. This message contains confidential information and is intended solely for the named recipient(s). If you are not the intended recipient, please immediately contact the sender by return e-mail and destroy all copies of the original message. Thank you. From: aurorapower@gci.net [mailto:aurorapower@gci.net] On Behalf Of Ed Jones Sent: Monday, September 29, 2008 9:31 PM To: David Barnett Subject: RE: MSA (WWCI) David, Thanks --I'll start processing this. Any more insight into our dynamic kill situation? We did get lots of barite and are now mixing mud --planning to mix about 400 bbl total (unfortunately, our 500 bbl tiger tanks are full of other fluids). According to the model, 13 ppg mud at 560 gpm ought to give us a dynamic kill? It now appears that we are making about 40 bbl of water per hour, so I assume we should bump the mud wt up a bit to compensate for that? Thanks, Ed Jones Ed Jones Vice President Engineering & Operations Aurora Gas, LLC 713-977-5799 (Houston) 907-277-1003 (Anchorage) From: David Barnett [mailto:dbarnett@wildwell.com] Sent: Monday, September 29, 2008 2:08 PM To: jejones@aurorapower.com Cc: Bill Mahler Subject: MSA (WWCI) Ed: Per our earlier conversation, see attached Master Service Agreement currently in use by WWCI. Please contact Mr. Bill Mahler at 281.784.4700 to discuss any of the contents and to finalize an agreement. Regards, David Barnett Wild Well Control, Inc. Vice President, Engineering Services dbarnett@wildwell.com • www.wildwell.com 281.784.4700 Phone 0 281.784.4750 Fax "Experience Makes The Difference" The contents of this message are provided for informational purposes only. Wild Well Control, Inc. does not guarantee the accuracy or completeness of the contents and assumes no liability whatsoever for loss or damage arising out of recipient's reliance on or use of the information provided herein. This message contains confidential information and is intended solely for the named recipient(s). If you are not the intended recipient, please immediately contact the sender by return e-mail and destroy all copies of the original message. Thank you. 9/29/2008 Customer: Aurora Gas, LLC Report #: 4 Well: Moquawkie4 Date: 9/29/2008 sap®rry Oe -filling Area: Tyonek 06:00 Depth: 867' Lease: Moquawkie Progress 24 hrs: 339' Rig: AWS -1 Rig Activity: Well Control Mudlogger's Morning Report Job No.: AK -AM -0006174381 Report For: Coine/Newton Daily Cost: $3,725 Cumulative Cost: $45,075 ROP&Gas: Current 24 hr Avg 24 hr Max Max @ ft Pump & Flow Data: R.O.P. ft/hr 29.7 285.0 750 Flow in m SPP(psi) Gas (units) 40 423 751 Fow in (s m) Gallons/stroke 2.8 Mud Data: Density (ppg) Viscosity filtrate PV YP Chlorides FC 1(1/32") PH Solids Depth in out (sedgt) (cc/30 min) cP (lb/100ff) ( ) % 867 9.7 9.7 56 7 13 20 42,000 1 8.0 1.1 BIT DATA: Type Size TFA Hours Depth in / out Footage WOB RPM Condition Bit # Sec XCL1 N 12.25 0.75 43.1 82 867 785 1-8 80 Last Bit # Lithology Sd Sst Silt Siltst Cly Clyst I Sh Lst Coal Tuff 10 10 j 50 30 Connection Gas and Mud Cut Trip gas see note ft units ppg ft units ppg ft units ppg 24 hour Gas Breakdown Gas (units) Chromatograph (ppm) Depth Max Average C1 C2 C3 C4 Tot C5 Tot Type 570 to 575 252 32 32737 0 0 0 0 GP 590 to 596 168 36 19210 0 0 0 0 GP 624 to 627 135 36 15571 0 0 0 0 GP 640 to 642 116 29 11813 0 0 0 0 GP 653 to 656 115 20 14574 0 0 0 0 GP 676 to 679 147 22 19371 0 0 0 0 GP 683 to 685 109 39 13240 0 0 0 0 GP 722 to 734 119 22 12789 0 0 0 0 GP 747 to 758 423 64 56942 0 0 0 0 GP 760 to 771 179 73 23950 0 0 0 0 GP 777 to 783 162 40 22589 0 0 0 0 GP 791 to 810 255 56 29650 0 0 0 0 GP 844 to 848 188 43 23546 0 0 0 0 GP 854 to 862 246 50 33756 0 0 0 0 GP 864 to 867 214 62 29070 0 0 0 0 WTG 867 to 867 9492 9437 502024 0 0 0 0 Blowout Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas: POG - pumps off gas 24 hr Recap: Drilled f/528' to surface hole TD of 867'. Ran slickline survey. Start short trip. Took a kick. Shut in well and venting through diverter. Maximum gas of 9492 units Attempted to kill twice with 9.2+ ppg mud and 10.2 ppg mud. Building kill mud and awaiting kill sheet from Wild Well Control. Note: connection gas ranged from 30 to 205 units over BG of 10-30 units - 432 units at 803' occurred with incr BG - Various gas peaks associated with coal ranging from 100-425 units over a background of 30-60 units. Gas peaks of 170 U at 845', 240 U at 855', and 190 U at 866' were associated with coal stringers verified by ^-50-70% coal coming across the shakers at those lag depths. Well most likely kicked from potential coal seam at 750' that had a GP of 423 U over BG of 64 U. Logging Engineer: Wayne Hermanson/Danny Kane 10000 units= 100% Gas In Air • • :�Ia� a OLand Cas Consen-ation Comms isiio 33 7" Aebnu®, Suit-- !X -.7sh®l-a- e, AK 99501-3339 Phi y. ( 907) 27901433 Fax: (9 37) 276-7542 Fax Transmission rfte infbnaration captained in this fax is confidential and/or privileged. This fax is intended to be reviewed initially by only the individual named below. If the reader of this transmittal ,sage is not the intended recipient or a representative of the intended recipient; you are hereby notified that any review, disseminatrorr or copying of this fax or the information contained herein is prohibited if you have received this fax i,, error, please immediately notify the sander by t_lephorre and return this fax to the sander at the above address. Thank you. From. Phone #: subject: message ax Oats: �- Pages (inciuding cover street): y7L, 1J ^O` r?cei"(9 all tea ragas Or 6-3`!3 3'1% PrObivR^S :,`iis tax. aleasa :aii for assistarca 3_ (307) 793-9223. 0 0 Maunder, Thomas E (DOA) From: David Boelens [dboelens@aurorapower.com] Sent: Monday, September 29, 2008 3:31 PM To: Maunder, Thomas E (DOA) Cc: 'Ed Jones' Subject: FW: Mud Loggers AM -report for Mowquawkie #4 for Sept 29 Attachments: Moquawkie 4 Mudlog Report 4.pdf Moquawkie 4 9udlog Report 4. pd., Tom Here is the mud loggers morning report. David Boelens VP Alaska Operations Aurora Power/Gas/Well Service/Shirleyville Ent Phone 907-277-1003 Fax 907-277-1006 Cell 907-223-0713 -----Original Message ----- From: aurorapower@gci.net [mailto:aurorapower@gci.net] On Behalf Of Ed Jones Sent: Monday, September 29, 2008 9:42 AM To: 'David Boelens'; 'Scott Pfoff (E-mail)' Subject: FW: Mud Loggers AM -report for Mowquawkie #4 for Sept 29 -----Original Message ----- From: Wayne Hermanson [mailto:Wayne.Hermanson@Halliburton.com] Sent: Monday, September 29, 2008 10:57 AM To: jejones@aurorapower.com; wellsitesuper@aurorapower.com Subject: Mud Loggers AM -report for Mowquawkie #4 for Sept 29 Please see attached Mud Loggers AM -report for Mowquawkie #4 for Sept 29. Thanks Wayne Hermanson ---------------------------------------------------------------------- This e-mail, including any attached files, may contain confidential and privileged information for the sole use of the intended recipient. Any review, use, distribution, or disclosure by others is strictly prohibited. If you are not the intended recipient (or authorized to receive information for the intended recipient), please contact the sender by reply e-mail and delete all copies of this message. 1 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMAUN APPLICATION FOR SUNDRY APPROVALS On A A/` Or 04n RECEIVED �%OfCT 2 2 2008 1. Type of Request: Abandon❑ Suspend El Operational shutdown El Perforate El Waiver her _ i�"Si , After casing❑ Repair well ❑ Plug Perforations ❑ Stimulate ❑ Time Extension Change approved programEl . 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 p] . Exploratory ❑ Stratigraphic ❑ Service ❑ 207-084 3. Address: 6. API Number: 1400 West Benson, Suite 410, Anchorage, AK 99503 50-283-20120-00 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 ❑ MOQUAWKIE NO. 4 9. Property Designation: 10. KB Elevation (ft): 1314' 11. Field/Pool(s): o4F tcQ L! U a-' C-061390 IMOQUAWKIE GAS FIELD 12. PRESENT WELL CONDITION SUMMARY i••23 Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 1 2600'& drilling 2600'& drilling Casing Length Size MD TVD Burst Collapse Structural Conductor 80 13-3/8", 68# 95 95 3450 1950 Surface 840 9-5/8", 36# 855.6 855.6 3520 2020 Intermediate Production Liner Perforation Depth MD (ft): ration Depth TVD (ft): 7 Tubing Size: Tubing Grade: Tubing MD (ft): Packers and SSSV Type: Packers and SSSV MD (ft): 13. Attachments: Description Summary of Proposal P 14. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Development (] Service ❑ 15. Estimated Date for drilling in progress, completion to start 10/26/08 16. Well Status after proposed work: Commencing Operations: Oil ❑ Gas R 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 Printed Name J. Edward Jones Title Exec. Vice President, Engineemg & Operations Signature Phone 907-277-1003 Date 10/22/2008 ltA COMMISSION USE ONLY t Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity El BOP Test K Mechanical Integrity Test ❑ Location Clearance ❑ Other: Subsequent Form Required: nt, APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: /19 R OCT 2 3 2008 Form 10-403 Revised 06/2006 3 JJc Iro r `o. )PI Submit in Duplicate Aueora Gas, Moquawkie #4 Drilling Program Moquawkie #4 PROCEDURE (Revised 10/21/08) Moquawkie #4 is a grass-roots well targeting Beluga & Tyonek Gas Production. It is located in the Moquawkie Gas Field V4 mile NE of the Moquawkie #1 & #3 wells. Moquawkie #4 will target Beluga Tsuga 2-8 sands plus Upper Tyonek Carya 2-1 thru 2-3 sands in a separate thrust slice from the downdip Moquawkie #3 well. Moquawkie #4 will also penetrate the Upper Tyonek Carya 2-4 in an updip attic location relative to the Moquawkie #I well and will access gas reserves that have been undrained by that well and may remain undrained due to excess water production resulting from suspected casing damage and poor cement quality. Pre Rig work 1. Stake & survey the Moquawkie #4 drillsite. 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 Vetco 13-5/8" VG LOK head. 3. Rig up diverter & Sperry 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 (next time use 11-11.5 ppg). Load, strap & drift 850' of 9-5/8" surface casing. 6. PU Security 12-1/4" XCL1N mill tooth bit & drill to —850', using stabilized BHA, as per the Sperry plan. 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 #, K-55 BTC casing @ 850', 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. Prepared by Jack McDade Page 1 of 12 Rev. 1.0 Aurbra Gas, Moquawkie #4 Drilling Program Cementing (BJ) 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 Vetco i 1" 3M wellhead. 10. Notify AOGCC of pending BOP test. 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. 11. PU Security QHC IS 7-7/8" bit, stabilizers as per Sperry recommendation & RIH . Drill out shoetrack. Condition / treat mud as needed for cement contamination, drill 20' new formation. Pull back into shoe & perform FIT (we hope not to break down) to 16.0 ppg EMW with low volume test pump (287 psi at surface with 9.5 ppg mud). Record results. REVISED BELOW ON .10121/08 -revisions are highlighted in Bold f 12. Drill 7-7/8" hole to TD @ 3,500' (depending upon the mud log, we may TD well as shallow as 3350'—depending upon mud log shows—we want to see the Carya 2-6, which was at 3315' in the Mobil Moquawkie 1, and we may go as deep as 3550' if mud log shows persist thru the 2-6 sand, to took at poor quality sands in the MM 1 at 3480-3540', which should be 50' shallower in #4). Monitor well & pit volumes carefully. Be prepared to shut in the well & weight up if well begins to flow. Monitor drilling trends for signs of poor hole cleaning & pump sweeps / short trip accordingly. 13. Condition hole, short trip and prepare for running wireline logs. 14. 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 (PEX, possibly DSI, f SWC's, and MDT/EPT). RD wireline. 15. RIH w/ 7-7/8" drilling assembly to TD & condition hole for running 5-%2" casing. Ensure cementing head has proper connections or proper cross-over and is available for quick rig up. 16. POOH while laying down drillpipe & BHA, RU to run casing. Verify cementer's equipment is ready. 17. Install 5-Y2' pipe rams. 18. Run 5-112" 15.5# BTC J-55 casing installing 1 centralizer per joint centered on 1" 4 joints above shoe, 1 centralizer every 2nd joint in open hole & every Yd joint inside surface casing (Turbolizer centralizers will be run just below and thru potential pay sections). Shoe joint connection at float shoe, float collar & stage tool landing collar must be Baker -Locked (80'shoetrack). While running casing, fill every Yd joint. Be prepared to wash to bottom. 19. RU BJ cementers, cement per attached cementing program from TD to sur€ace. A sufficient amount of 13.5 ppg Class G lead cement will be pumped to cover 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 the 9-5/8" shoe. Excess will be calculated using caliper log data. Plug will be bumped with clean brine (exact weight will depend Prepared by Jack McDade Page 2 of 12 Rev. 1.0 0 Aurora Gas, Moquawkie #4 Drilling Program upon MDT pressures, but likely will be about 9.5 ppg KCl -NaCl brine). If possible reciprocate pipe while displacing cement. Land casing & WOC. 20. RD cementers, nipple down stack, land casing in slips & cut casing. Remove usable mud to storage (AWS pit w/ agitators and tiger tank, to be used in Lone Creek 4). Clean mud pits for brine. 21. Notify AOGCC of pending BOP test. Install I1" X 7-1/16" tubing spool, 7-1/16" X 11" DSA (from Vetco), 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. 22. Install 2-7/8" pipe rams. 23. RIH w/ bit & casing scraper on 2-7/8" tubing to float collar. Displace well w/ filtered KCi/NaCI brine (wt. to be determined from MDT data --run thru centrifuge, then filter to 10 microns, then to 5 microns). Continue to clean brine for perforating by running through centrifuge & filtering. POOH. Strap tubing on TOH to validate tally. MORE DETAILED COMPLETION PROCEDURE WILL BE PROVIDED AT THIS POINT. 24. PU wireline GOP's & lubricator, pressure test to 1500 psi against casing. 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 --expect to perforate 150-175' of Tyonek Carya 2-1 thru 2-6 sands. Watch for pressures in casing after shooting. POOH, LD perf gun, RD wireline. 25. 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. 26. 27. 28. Delete this step 1 Delete this step Delete this step S d 29. Pick up & assemble completion assembly which will consist of mechanical packer w/ on-off tool 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. RIH with 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 up tubing to 3000 psi to test and to set packers. Install BPV. ND BOP. NU and test tree. 30. Pull BPV and RIH w/ slick line and pull blanking plug. 31. RU & swab in deepest zone. After well cleans up, perform flow test --get stabilized rate (1 hour). 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. 32. Add needed KCl water cushion to tubing (10001). Open deepest sliding sleeve. Test well as per Step 31. DO NOT IO LL, but close sliding sleeve. Prepared by Jack McDade Page 3 of 12 Rev. 1.0 Aurora Gas, Moquawkie #4 Drilling Program 33. Repeat Step 32 for remaining shallower intervals (1 or 2). 34. Open zones for initial production (depending upon pressures and test results --likely the 24.2 and deeper)—flow to clean up. Shut in. Set BPV in tree. Release rig, RD, and move rig to Lone Creek 4 location. 35. Pull BPV. Run 4 -point test of initial production zone as per Procedure provided at that time. RD test unit. 36. Clear & clean location. Hand well over to production. 37. File completion reports with proper agencies. NO CHANGES BELOW EXCEPT TO WELL BORE DLAGRAM Prepared by Jack McDade Page 4 of 12 Rev. 1.0 Aurora Gas, Survey Program 0 Moquawkie #4 Drilling Program The Moquawkie #4 well will be drilled as a vertical well. Wellbore surveys will be obtained @ 500' intervals in accordance with rules laid out in 20 AAC 25.050 (a) (1) & (2). Logging Program Mud loggers will be on site for the duration of drilling activities. Schlumberger will provide wireline logging services as proposed below: Moquawkie #4 Proposed Logging Program Well Section Depths OH CH LoType I2-1/4" 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' 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 —`ID O'— 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: 12-1/4" Surface Hole 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 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 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. Prepared by Jack McDade Page 5 of 12 Rev. 1.0 Aurora Gas, Drilling Fluids Moquawkie #4 Drilling Program The drilling fluids will be furnished by Baroid Drilling Fluids who has extensive experience with drilling activities in this area. An experienced (consulting) 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 850' 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 3,500' Beluga and Tyonek Formations Base Fluid 6% KCL Density 9.3 —10 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 mixed with Portland cement and made into slabs or blocks for use as foundations, pipeline weights, etc. 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 6 of 12 Rev. 1.0 s • Aurbra Gas, Moquawkie #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 Moquawkie #4 will be installed by drilling/driving the 13-3/8" 68# (12.259" drift may be tight) 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. 9-5/8" 36# K-55 BTC Surface Casing Analysis and Cementing Program The 9-5/8" surface casing will be cemented from the proposed setting depth of 850' to surface with a 14.5 ppg Type I, gas block enhanced cement system. Capacities: 9-5/8" Csg. Capacity =.1458 bbl/ft 9 -5/8" Csg. x 12-1/4" OH Capacity= .0558 bbl/ft System Volume: 12-1/4"OH x 9-5/8"Csg: 850' x .0558 bbi/ft x 2 (100 % excess) = 94.9 bbls Shoe Jt: 40' x .0773 bbl/ft = 3 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 System Weight (ppg) bbl cf sx Gas -Block enhanced Type I 14.5 94.9 532.8 362 Yield 1.47 cf/sx Please see attached 9-5/8" surface casing analysis and specifications. 5-1/2" 15.5# J-55 BTC 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: 5-1/z" 15.5# csg capacity = .0238 bbl/ft 5-1/2" 15.5# csg X 7-7/8" OH capacity =.0309 bbl/ft Prepared by Jack McDade Page 7 of 12 Rev. 1.0 U Aurora Gas, 5-1/2' 15.5# csg X 9-5/8" 36# annular capacity =.0479 bbl/ft Lead System: 9-5/8" CH x 5-1/2'Csg: 850 ft 850' x.0479 bbls/ft x 1 (0% excess) = 40.7 bbls Lead Cement Volume = 40.7 bbl Tail System: 7-7/8" OH x 5-1/2 Csg: 3,500'-850'=2,650' 2,650' x .0309 bbl/ft x 1.25(25% excess) =102.4 bbls Shoe Joint: 40' x .0238 bbl/ft = l Total Tail Cement Volume = 103.4 bbls • Moquawkie #4 Drilling Program Actual volumes will be calculated at time of running casing due to potential variation in depth from planned. Cement Svstem Type Cement Weight (ppg) bbl cf sx Lead @ 1.83 cf/sx G 13.5 40.7 229 125 Tail @ 1.17 cf/sx G 15.8 103.4 581 497 Please see attached 5 M" 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 Moquawkie #3, maximum anticipated bottom -hole pressures should not exceed 1,785 psi at 3,500 ft. Pressures measured at the Moquawkie #3 well indicated a gradient of —.51 psi/ft with a bottom -hole pressure of 1,270 psi recorded at 2,473'. Maximum anticipated surface pressures "MASP" can be calculated by subtracting the gas gradient of .l psi/ft from pore pressure gradient of .51 psi / ft and multiplying by the total TVD depth. Maximum Anticipated Surface Pressure= (.51 - .1) * 3,500'=1,435psi A formation integrity test to 16.0 ppg EMW @ 620' was conducted while drilling Moquawkie #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)*850'=673 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 112S 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 S of 12 Rev. 1.0 Aurora Gas, Moquawkie #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 coats 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 Moquawkie #4. The nearest well activity lies 1/ mile SW on the Moquawkie #1 drUlsite. Other Risks Sticky bentonitie clays, boulders, lost returns & differential sticking with overbalanced muds and gas influx while cementing or swabbing while tripping pipe. Prepared by Jack McDade Page 9 of 12 Rev. 1.0 Aurora Gas, Moquawkie #4 Drilling Program 2 7/8 6.5# 8rd EUE J-55 Tubing Beluga —not likely completed initially Sliding sleeve 1 joint above packer Est. Tyonek Tops Hydraulic Set Packer @ 1650' Carya 2-1 — 1,710' Carya 2-2 — 1920' Carya 2-1 Carya 2-3--2230 Carya 24.2 — 2,580' Carva 2-6 — 3265' Tyonek Perforation Intervals to be determined by open -hole logging. Sliding Sleeve @ 1950' Carya 2-2 Carya 2-3 Carya24 Hydraulic Set Packer @ 2130' Sliding Sleeve @ 2250' Hydraulic -set Packer @ 2,550' Sliding Sleeve @ —2,700' Carya 2-5 I tOn -Off Tool above Arrowset Mechanical Packer @2740' w/ 2.31 Drill 7 5/8" Hole to 3,500' prol'de XN nipple Carya 2-6 5 %:" 15.5# J-55 Casing to 3,500' MD (TVD) Estimated PBTD @ 3,420 Drill 7-7/8" Hole to 3,500' Prepared by Jack McDade Page 10 of 12 Rev. 1.0 Aurora Gas, 0 0 500 1,000 1,500 m 2,000 m 2,500 3,000 3,500 4,000 Moquawkie #4 Days vs Depth 5 10 15 20 Moquawkie #4 Drilling Program 25 30 Days Prepared by Jack McDade Page 11 of 12 Rev. 1.0 Drill 12-1/4 Rm 9-5/8 Ca mg Drill 8-1/2 Interval Log Well, Run Run Completion 5-1/2 Casing, erforate, Test Days Prepared by Jack McDade Page 11 of 12 Rev. 1.0 Aurora Gas, 0 Moguawkie #4 0 Moquawkie #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 trams as dictated b drilling rilling trends. � There is no 112S 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 MOQUAWKIE #4 WELL PLAN FOR ADDITIONAL INFORMATION Prepared by Jack McDade Page 12 of 12 Rev. 1.0 SARAH PALIN, GOVERNOR �T ALASKA ®uI AND r�rGAS T 333 W. 7th AVENUE, SUITE 100 CONSEDVAois COMUSSIOQANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 J. Edwards Jones Executive Vice President, Engineering 8v Operations Aurora Gas, LLC 1400 West Benson Blvd., Suite 410 Anchorage, Alaska 99503 Re: Moquawkie Gas Field, Moquawkie Undefined Gas Pool Moquawkie No. 4 Sundry Number: 308-385 Dear Mr. Jones: 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, 1-2 Cathy P. Foerster Commissioner DATED this fd day of October, 2008 Encl. Page 1 of Maunder, Thomas E (DOA) From: aurorapower@gci.net on behalf of Ed Jones Dejones@aurorapower.com] Sent: Tuesday, October 21, 2008 10:52 AM To: Maunder, Thomas E (DOA); 'Ag Company Man'; 'JON ROBERTA WEST'; sirromeyo@yahoo.com Cc: 'Chad Helgeson'; 'Bruce D Webb; Regg, James B (DOA) Subject: RE: Revised Drilling /Completion Procedure for Moquawkie 4 Tom, I'll get a Sundry Notice in soon. Regarding the other questions: 1) The well is drilling at about 2500' this AM with 11.4 ppg mud. 2) The bubbling is about the same --sometimes very little, sometimes the "slow boil." 3) Vetco got back to us with their design measurements for fabrication of the pack -off, but some (the OD of the 9-5/8") looked funny (slightly out of round), so we plan to reconfirm today before local fabrication. Ed Jones From: Maunder, Thomas E (DOA) [maiito:tom.maunder@alaska.gov] Sent: Tuesday, October 21, 2008 1:37 PM To: Ed Jones; Ag Company Man; JON ROBERTA WEST; sirromeyo@yahoo.com Cc: Chad Helgeson; Bruce D Webb; Regg, James B (DOA) Subject: RE: Revised Drilling /Completion Procedure for Moquawkie 4 Ed, I have just done a quick review of the revision. It is probably appropriate to submit a sundry notice for the revision. Sorry for any additional paperwork. Also, what is the current status of the well (depth, MW, bubbling, any issues)? Any news on the packoff? Call or message with any questions. Tom Maunder, PE AOGCC From: aurorapower@gci.net [mailto:aurorapower@gci.net] On Behalf Of Ed Jones Sent: Tuesday, October 21, 2008 10:30 AM To: 'Ag Company Man'; 'JON ROBERTA WEST; sirromeyo@yahoo.com Cc: 'Chad Helgeson'; 'Bruce D Webb'; Maunder, Thomas E (DOA) Subject: Revised Drilling /Completion Procedure for Moquawkie 4 Gentlemen, Attached is a revised Procedure for the Moquawkie 4 --most of the changes have to do with the end of drilling and the completion. A more detailed Completion and Test Procedure will be provided after logging. Please let me know if you questions, suggestions, or concerns. Thanks, Ed Ed Jones Vice President Engineering & Operations Aurora Gas, LLC 713-977-5799 (Houston) 907-277-1003 (Anchorage) 10/23/2008 0 • Page 1 of 1 Regg, James B (DOA) From: Grimaldi, Louis R (DOA) Sent: Monday, September 29, 2008 4:53 AM To: DOA AOGCC Prudhoe Bay; Maunder, Thomas E (DOA) Subject: Moqauwkie #4 Surface Kick All, Bob Noble fielded a call on 659-2714 from Oneil Coyne at approximately 02:20 09/29/08 who reported that they had taken a kick while drilling surface hole on Aurora's well, Moqaukwie #4 (PTD 207-0840) at approximately 22:30 the previous evening (09/28/08). 1 returned the call to Mr Coyne at 02:40 and discussed the following with him; • Aurora well Moqaukwie #4, PTD 208-0840. Spudded 09/26/08. • Drilled 12 1/4" hole to 865'. • 16" Conductor shoe @ 80' • Hole Vol. 120 bbl's • Pit Vol. 270 bbl's • Had been getting background gas (? units) during drilling. • While POOH, two stands off bottom, well started flowing. Closed Diverter/Opened Vent line. Pumped 9.2 mud and raised MW to 10.4 on the fly. Opened bag and pumped pits dry. Somewhere during this time mud was 2-3 feet above table. • Gas alarms in pits sounded and well was put back to Divert during remainder of mud pumped. The following are estimations I asked Mr. Coyne to make from memory. • At height of mud flow from 12" vent line, mud exited tip of line 30' horizontal. • At height of gas flow from 12" vent line, gas exited tip of line 6' horizontal. • At present gas is "Breathing" from tip of vent line (no horizontal flow). Plan forward; • Build new 13# mud, they have seven pallets on location, are getting some more from Nab 129 @ Beluga and will get a barge in if needed. • Pump new mud taking returns out vent line to ? • If and when mud returns to surface and cleans up, open diverter and attempt circulation. • I informed Oneil to call us on slope before pump job began. Contacts; Co. Rep. 907-472-7794 Toolpusher 907-472-7793 Oneil's pers cell 907-355-2054 9/29/2008 0 Maunder, Thomas E (DOA) From: Grimaldi, Louis R (DOA) Sent: Monday, September 29, 2008 4:53 AM To: DOA AOGCC Prudhoe Bay; Maunder, Thomas E (DOA) Subject: Moqauwkie #4 Surface Kick 0 Page 1 of 1 All, Bob Noble fielded a call on 659-2714 from Oneil Coyne at approximately 02:20 09/29/08 who reported that they had taken a kick while drilling surface hole on Aurora's well,;< at approximately 22:30 the previous evening (09/28/08). I returned the call to Mr Coyne at 02:40 and discussed the following with him; • Aurora well Moqaukwie #4, PTD 208-0840. Spudded 09/26/08. • Drilled 12 114" hole to 865'. • 16" Conductor shoe @ 80' • Hole Vol. 120 bbl's • Pit Vol. 270 bbl's • Had been getting background gas (? units) during drilling. • While POOH, two stands off bottom, well started flowing. Closed Diverter/Opened Vent line. Pumped 9.2 mud and raised MW to 10.4 on the fly. Opened bag and pumped pits dry. Somewhere during this time mud was 2-3 feet above table. • Gas alarms in pits sounded and well was put back to Divert during remainder of mud pumped. The following are estimations I asked Mr. Coyne to make from memory. • At height of mud flow from 12" vent line, mud exited tip of line 30' horizontal. • At height of gas flow from 12" vent line, gas exited tip of line 6' horizontal. • At present gas is "Breathing" from tip of vent line (no horizontal flow). Pian forward; • Build new 13# mud, they have seven pallets on location, are getting some more from Nab 129 @ Beluga and will get a barge in if needed. • Pump new mud taking returns out vent line to ? • If and when mud returns to surface and cleans up, open diverter and attempt circulation. • I informed Oneil to call us on slope before pump job began. Contacts; Co. Rep. 907-472-7794 Toolpusher 907-472-7793 Oneil's pers cell 907-355-2054 9/29/2008 • • Page 1 of 2 Maunder, Thomas E (DOA) From: Bruce D Webb [bwebb@aurorapower.com] Sent: Monday, September 22, 2008 9:30 AM To: Maunder, Thomas E (DOA) Subject: RE: Moquawkie 42�9y�Questions Thanks Tom, 1 am on the phone with DEC right now. Sorry to bother you, I didn't realize how easy it was to find the BOP requirements. I will pass the 7 -day on to Ed. Bruce D. 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 From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Monday, September 22, 2008 9:27 AM To: Bruce D Webb Subject: RE: Moquawkie 4 (207-091) Questions Morning Bruce, Sorry I missed the BOP test interval on the review. At least to start, please plan on a 7 day interval. Regarding the impermeable well cellar, that is a requirement of ADEC and not administered by AOGCC. Call or message with any questions. Tom Maunder, PE AOGCC From: Bruce D Webb [mailto:bwebb@aurorapower.com] Sent: Monday, September 22, 2008 9:06 AM To: Maunder, Thomas E (DOA) Subject: FW: Moquawkie 4 Questions Good morning Tom, Ed has asked a couple of questions, that I honestly do not know the answer to. Can you help me out? Permit to Drill 207-091 Thanks, -Bruce From: aurorapower@gci.net [mailto:aurorapower@gci.net] On Behalf Of Ed Jones Sent: Monday, September 22, 2008 6:59 AM 9/29/2008 0 0 Page 2 of 2 To: 'Bruce D Webb' Cc: 'Chad Helgeson' Subject: Moquawkie 4 Questions Bruce, There are a couple of things we need you to check into for the M 4 well ASAP: 1) BOP test interval / frequency --none was mentioned on the approved 10-401. It is a development well, does this mean that we are on a two-week test interval since a shorter interval was not prescribed on the approved 10- 401? 2) Some new rules were / are being implemented requiring impermeable floors in well cellars. Does this apply to M 4? At what point in time is this required? Is is possible to place when we are cementing the surface casing (using cement from that job)? Please let me know what you find out. Thanks, Ed Ed Jones Vice President Engineering & Operations Aurora Gas, LLC 713-977-5799 (Houston) 907-277-1003 (Anchorage) 9/29/2008 ALASKA OIL AND GAS CONSERVATION COMMISSION Bruce Webb Aurora Gas, LLC Address 1400 West Benson Blvd, Suite 410 Anchorage, Alaska 99503 i SARAH PALIN, GOVERNOR 333 W. 7th AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Re: Moquawkie #4 Aurora Gas, LLC Permit No: 207-084 (revised) Surface Location: 1415' FEL, 1160' FNL, SEC. 1, TI IN, R12W, SM Bottomhole Location: 1415' FEL, 1160' FNL, SEC. 1, TI 1N, R12W, SM Dear Mr. Webb: Enclosed is the 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 August 2, 2007 all requirements contained in that approval still apply. 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). Sincerely, Daniel T. Seamount Chair DATED this day of September, 2008 cc: Department of Fish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. STATE OF ALASKA AA OIL AND GAS CONSERVATION CON&SION 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 Q Multiple Zone ❑ Single Zone ❑ 1 1c. Specify if well is proposed for: Coalbed Methane ❑ Gas Hydrates ❑ Shale Gas ❑ 2. Operator Name: Aurora Gas LLC 5. Bond: Blanket Q Single Well ❑ Bond No. NZS 429815 11. Well Name and Number: Mo uawkie No.4 3. Address: 1400 W. Benson Blvd Suite 410 Anchorage AK 99503 6. Proposed Depth: MD: 3 500' TVD: 3,500' 12. Field/Pool(s): Moquawkie Gas Field 4a. Location of Well (Governmental Section): Surface: T.11 N., R.12 W., S.M., Section 1 1,415" FEL and 1,160' FNL Top of Productive Horizon: Total Depth: 7. Property Designation: C-061390 8. Land Use Permit: T onek Native Corp.,# AR -101765 13. Approximate Spud Date: 9/19/2008 9. Acres in Property: 640 14. Dist. to Nearest Property: 1,415' FEL and 1,160' FNL 4b. Surface Location of Well (State Base Plane Coordinates): x- 266767.784 y- 2587949.272 zone: 4 10. KB Elevation 299' MLLW (Height above GL): 16' feet 15. Distance to Nearest Well Within Pool: 1,030' 16. Deviated wells: Kickoff depth: feet Maximum Hole Angle: degrees 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Downhole: 1,785psi Surface: 1,435 psi 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, 0. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) Driven 13-3/8" 72# K-55 BW 80' 16' 16' 96' 96' N/A 12-1/4" 9-5/8" 36# L-80 BTC 834' 16' 16' 850' 850' 362 sx 7-7/8" 5-1/2" 15.5# J-55 BTC 3§484' 16' 16' 3 500' 3.600' 622 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 ^`, '" ii 1, - (20n'„ , �- Perforation Depth MD (ft): Perforation Depth TVD (ft): r, , s as 20. Attachments: Filing Fee ❑ BOP Sketch ❑ Drilling Program ❑ Time v. Depth Plot❑ Shallow Hazard Analysis ❑ Revised Property Plat ❑✓ Diverter Sketch ❑ Seabed Report ❑ 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 , CIDr,a�; Phone (907).277-1003 Date September 15 2008 Commission Use Only Permit to Drill Number: 207-084 API Number: 50 - 283 - 20120 - 00 Permit Approval Date: 8/22/2007 ISee cover letter for other Irequirements. Conditions of approval: If box checked, well may not to explore for, test, or produce coalbed methane, g hydrates, or gas contained in shales: Other: �w0 �'' �� Nc!S� Samples req'd: Yes❑ Nd� Mud log req'd: Yes❑ No `� 112Smeasures: Yes❑ No Directional stvyy re 'd: Yes ❑ N c`vci��rcacc�,��E�QAAC�S.®�S1Cr7 3_ APPROVED BY THE COMMISSION l DATE: COMMISSIONER Form 10-401 Revised 12/2005 ORIGINAL Submit in Duplicate t ti 4urora i Gas, LLC www.aurorapower.com September 15, 2008 Tom Maunder, Senior Petroleum Engineer State of Alaska Oil and Gas Conservation Commission 333 W. 7d' Avenue, Suite 100 Anchorage, AK 99501 Re: Revised Permit to Drill No. 207-084 Moquawkie #4 Development Gas Well Dear Mr. Maunder: i f J SEP 1 5 2008 Alaska Oil & Gas Cons. Commission Archy raga 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 Moquawkie #4 development gas well at a location approximately 160 feet west-southwest of the originally permitted location in the Moquawkie Unit on the west side of the Cook Inlet. Attached is a revised plat depicting the location of this proposed well. The Moquawkie #4 development gas well was originally approved by the AOGCC on August 22, 2007, Permit to Drill No. 207-084 (PTD). Subsequent to that date Aurora had been in contact with the U.S. Corps of Engineers (COE) concerning the location of the proposed Moquawkie #4 gravel pad. According to the COE, the originally permitted location of the pad would have required a COE 404 development permit, as a small portion of the pad was in wetlands. The COE advised that moving the pad location a short distance to the northwest would result in the pad being completely in the uplands area, and would not require any additional COE permits. Aurora notified the COE as to the change in the pad's location on September 12, 2008. The relocation of the pad has resulted in the surface location of the well being relocated approximately 160 feet. The original PTD included a spacing exception, which would still be valid for the new location of this development gas well. Attached to this revised PTD is the previously approved PTD, a revised plat, and the notification letter to the COE. Should questions arise in connection with this request, please contact me at the Anchorage telephone number below. Sincerely,, , ) 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 ORIGINAL Aurora Gas, LLC www.aurorapowercom September 12, 2008 Mr. Jack Hewitt, Project Manager Department of the Army U.S. Army Engineer District, Alaska Regulatory Division P.O. Box 6898 Elmendorf AFB, Alaska 99506-0898 RE: Lone Creek No. 4 Gas Development Well POA -2008-969 Dear Mr. Hewitt, Aurora Gas, LLC (Aurora) hereby withdraws the Corps of Engineer's permit for the placement of fill material into waters of the United States. Upon further investigation at the project location, Aurora has determined that a reduction of approximately seventy-five (75) feet from the eastern portion of the proposed drill pad, as well as relocating the drill pad slightly north to the uplands area, will result in avoiding the small wetlands area in the vicinity. Because the reduction in pad size and slight relocation will not impact any waters of the United States, it is Aurora's understanding that no permit of further regulatory action is required. Thank you for your review and assistance in this project. Should you have any questions, please contact me at the Anchorage telephone number below. Sincerely, O-. 6—Jto< Bruce D. Webb Manager, Land and Regulatory Affairs CC: Jodi Delgado-Plikat Oil and Gas Project Review Coordinator 550 West 7th Avenue, Suite 705 Anchorage, AK 99501-3568 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 STATE OF ALASKA �,, ALAS OIL AND GAS CONSERVATION COMMILl6tCON PERMIT TO DRILL 20 AAC 25 005 P E EIVED )IJIN 1 2 2007 & ;'as Cons. Commission Fa. Type of Work: 1b. Current Well Class: Exploratory ❑ Development Oil ❑ 1c. Specify if well is proposed for: Anche age Drill E] Redrill ❑ Stratigraphic Test ❑ Service [} Development Gas Q Coalbed Methane ❑ Gas Hydrates ❑ Re-entry ❑ Multiple Zone ❑ Single Zone ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket / Single Well 11. Well Name and Number: Aurora Gas, LLC Bond No. 14.6 4 ,0 Moquawkie No.4 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 1400 West Benson Blvd, Suite 410, Anchorage AK, 99503 MD: 3,500' TVD: 3,500' Moquawkie Gas Field 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: i,7 -5T FEL, ,I Zi FNL, Sec. 1, T11N, R12W, SM C-061390 Top of Productive Horizon: 8. Land Use Permit: 13. Approximate Spud Date: Same NIA 8/1/2007 Total Depth: 9. Acres in Propertv: 14. Distance to Nearest Same 640 Property: J,(Z,( FNL. 4b. Location of Well (State Base Plane Coordinates): 10. KB Elevation 32 GL): 16' feet G #- Distance to Nearest Well iithin Pool: 1,127' Surface: x-266913 y- 2588012.3 Zoi 4 (Height above 16. Deviated wells: Kickoff depth: feet 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: degrees Downhole: 1,785 psi Surface: 1,435 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) Driven 13-3/8" 72# K-55 BW 80' 16' 16' 96' 96' NIA 12.25" 9-5/8" 36# L-80 LTC 834' 16' 16' 850' 850' 362 sx 5-1/2" 15.5# J-55 BTC 3484 16' 16' 31500' 3,500' 622 sx *t 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: Date 22. 1 hereby certify that the foregoing is true and correct. Contact Printed Name J. Edward Jones Title Execurive Vice President --Engineering and Operations Signature Phone 713-977-5799 Date June 11, 2007 Commission Use Only Permit to Drill Number:'- � API NurYiber.7a Permit prova( See cover letter for other 50-(�.•�l�l� - Date: or •v 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:51 Other:-�r„ev� S�` Samples req'd: Yes[] Noce Mud log req'd: Yes❑ NoW ❑ No[T S measures: Yes z [�j' Dire 'nal svy req'd: Yes[] No A ��•�(�il�cc\t..� c.u�p�c,�,� ab AAL a5 •o3SCL �►cl�h4�ie►•,, s�.t.r-wc �,; ,6�'j� •zr• PROVED BY THE COMMISSION DATE:e• ,a r� COMMISSIONER Form 10-401 Revised 12/2005 DUPLICATE Submit in Duplicate ,7 TtMAMXAMNVf A*4mGasWfoi Anothe TML TrAP MTOATi o -&don testh% 20 AA 25.053(a) toal 6, ww',: lifi* 0' --eq ents spamiq r, u 404 t4wai prod of the Woo 4pme ,�kvclo nt wets vNithi I - same gov sdeftbu" din' bff," *#* vw Page 1 of 2 Saltmarsh, Arthur C (DOA) From: Pirtle Bates [PBates@ciri.com] Sent: Wednesday, September 17, 2008 9:50 AM To: Bruce D Webb; Charles Akers; Geri Simon Cc: Saltmarsh, Arthur C (DOA); Maunder, Thomas E (DOA) Subject: RE: Amended location of Moquawkie No. 4 Development Gas Well I have reviewed the revised Permit to Drill and other information attached to the below e-mail. CIRI has no objection to the location or spacing of the proposed Moquawkie No. 4 Development Gas Well, or the location of the pad from which it will be drilled. Should you have any questions, please feel free to contact me at the number below. Pirtle Bates, Jr., CPL Manager, Resources CIRI 907-263-5517 From: Bruce D Webb [mailto:bwebb@aurorapower.com] Sent: Tuesday, September 16, 2008 10:56 AM To: Pirtle Bates; 'Charles Akers'; 'Geri Simon' Cc: 'Art Satmarsh'; 'Maunder, Thomas E (DOA)' Subject: Amended location of Moquawkie No. 4 Development Gas Well Pirtle and Chuck or Geri, Aurora Gas, LLC has submitted a revised Permit to Drill application to the Alaska Oil and Gas Conservation Commission (AOGCC), which moves the surface location of the Moquawkie No. 4 Development Gas Well approximately 160 feet to the west (west-southwest). The original permit to drill included a Spacing Exception, for which there were no objections or comments of any kind by CIRI, TNC or the public. Before the AOGCC can approve the revised application, they need to receive concurrence from you that you have no objections. Attached is a copy of the Permit to Drill, cover letter, plat and related documents. Please review this request as soon as possible, Aurora plans on beginning drilling of the Moquawkie No. 4 by this weekend. Your response should go to Mr. Art Saltmarsh of the AOGCC and myself. An e-mail response is sufficient, please respond by "Reply to All" to this e-mail. Thank you for your time and consideration. Sincerely, Bruce D. Webb Manager, Land and Regulatory Affairs Aurora Gas, LLC 1400 W. Benson Blvd., Suite 410 Anchorage, AK 99503 9/17/2008 Page 2 of 2 (907) 277-1003 office (907) 229-8398 cell (970)277-1006 fax 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. 9/17/2008 0 Maunder, Thomas E (DOA) From: Bruce D Webb [bwebb@aurorapower.com] Page 1 of/, Sent~ Tuesday, September 16, 2008 2:16 PM To: 'Geri Simon'; 'Pirtle Bates'; 'Charles Akers'; 'Tom Harris'; 'Donita Slawson'; 'Donald Standifer.tnd Cc: Saltmarsh, Arthur C (DOA); Maunder, Thomas E (DOA) Subject: RE: Amended location of Moquawkie No. 4 Development Gas Well Hi Geri, The well is included in the report that I sent over, the location has only moved 160 feet from the originally permitted location to avoid wetlands. Don Standifer has already completed the pad construction. It is really a non -issue and the AOGCC is simply wanting something for their records. In the original application, there were no comments received by the AOGCC. Is there any chance Don can be reached by cell phone, or perhaps you could run it by Tom Harris or make the determination yourself? The rig is on its way to the drill site right now and will be be rigged up and could be drilling by this weekend, if the AOGCC gets the non -objection from CIRI and TNC. Otherwise, we will be shut down and on stand-by until AOGCC gets what they need and can issue the permit... this includes the drilling rig and support contractors, some of which are TNC shareholders. Your time consideration is appreciated. Thank you. -Bruce From: Geri Simon [mailto:gsimon@tyonek.com] Sent: Tuesday, September 16, 2008 2:04 PM To: Bruce D Webb; Pirtle Bates; Charles Akers; Tom Harris; Donita Slawson; Donald Standifer.tnc Cc: Art Satmarsh; Maunder, Thomas E (DOA) Subject: RE: Amended location of Moquawkie No. 4 Development Gas Well Good afternoon Bruce, Sorry but we will not be able to respond by Friday, September 19th as Chuck Akers and Don Standifer are both out of the office/State. Chuck is out moose hunting so unavailable via email or cell phone. Both return to the office on Monday, September 22"d. Thanks. Geri Simon General Counsel and Chief Administrative Officer Tyonek Native Corporation (907) 272-0707, Main telephone (907) 646-3113, Direct line (907) 274-7125, Fax VYerAL.Bruce D Webb [mailto:bwebb@aurorapower.com] Sent: Tues tember 16, 2008 10:56 AM To: 'Pirtle Bates; Char!EGeri Simon Cc: 'Art Satmarsh'; 'Maunder, Thoma ' Subject: Amended location of Moquawkie No. 4 nt Gas Well Pirtle and Chuck or Geri, 9/16/2008 Page 1 of 1 Saltmarsh, Arthur C (DOA) From: Bruce D Webb [bwebb@aurorapower.com] Sent: Tuesday, September 16, 2008 10:56 AM To: 'Pirtle Bates'; 'Charles Akers'; 'Geri Simon' Cc: Saltmarsh, Arthur C (DOA); Maunder, Thomas E (DOA) Subject: Amended location of Moquawkie No. 4 Development Gas Well Attachments: Moquawkie #4 APD10-401.xls; AOGCC MOQ 4 Rev. PTD.doc; Moquawkie No.4 As- Builtrevised location.pdf; Corps of Engineers - MOQ #4.doc Pirtle and Chuck or Geri, Aurora Gas, LLC has submitted a revised Permit to Drill application to the Alaska Oil and Gas Conservation Commission (AOGCC), which moves the surface location of the Moquawkie No. 4 Development Gas Well approximately 160 feet to the west (west-southwest). The original permit to drill included a Spacing Exception, for which there were no objections or comments of any kind by CIRI, TNC or the public. Before the AOGCC can approve the revised application, they need to receive concurrence from you that you have no objections. Attached is a copy of the Permit to Drill, cover letter, plat and related documents. Please review this request as soon as possible, Aurora plans on beginning drilling of the Moquawkie No. 4 by this weekend. Your response should go to Mr. Art Saltmarsh of the AOGCC and myself. An e-mail response is sufficient, please respond by "Reply to All" to this e-mail. Thank you for your time and consideration. Sincerely, Bruce D. 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 9/16/2008 0 September 12, 2008 Mr. Jack Hewitt, Project Manager Department of the Army U.S. Army Engineer District, Alaska Regulatory Division P.O. Box 6898 Elmendorf AFB, Alaska 99506-0898 RE: Moquawkie No. 4 Gas Development Well POA -2008-969 Dear Mr. Hewitt, Aurora Gas, LLC (Aurora) hereby withdraws the Corps of Engineer's permit for the placement of fill material into waters of the United States. Upon further investigation at the project location, Aurora has determined that a reduction of approximately seventy-five (75) feet from the eastern portion of the proposed drill pad, as well as relocating the drill pad slightly north to the uplands area, will result in avoiding the small wetlands area in the vicinity. Because the reduction in pad size and slight relocation will not impact any waters of the United States, it is Aurora's understanding that no permit of further regulatory action is required. Thank you for your review and assistance in this project. Should you have any questions, please contact me at the Anchorage telephone number below. Sincerely, Bruce D. Webb Manager, Land and Regulatory Affairs CC: Jodi Delgado-Plikat Oil and Gas Project Review Coordinator 550 West 7th Avenue, Suite 705 Anchorage, AK 99501-3568 0 TRANSMITTAL LETTER CHECKLIST WELL NAME O JGIV.)1t--1 PTD# Development, Service Exploratory Stradgraphic Test Non -Conventional Well FIELD. StJG,v3 POOL: Circle Appropriate Letter 1 Paragraphs to be Included in Transmittal Letter CHECK ADD-ONS WHAT (OPTIONS) TEXT FOR APPROVAL LETTER APPLIES MULTILATERAL The permit is for a new wellbore segment of existing well (If last two digits in permit No. AP[ No. 50- API number are between 60-69) _, Production should continue to be reported as a function of the original API number stated above. PILOT HOLE In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name ( PH) and API number (50- _) from records, data and logs acquired for well SPACING The permit is approved subject to full compliance with 20 AAC EXCEPTION 25.055. Approval to perforate and produce !inject is contingent upon issuance of a conservation order approving a spacing exception. assumes the liability of any protest to the spacing exception that may occur. DRY DITCH All dry ditch sample sets submitted to the Commission must be in SAMPLE no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Non -Conventional Please note the following special condition of this permit. Well production or production testing of coal bed methane is not allowed for (name of well) until after (Comaaav Name) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. (Cgmoanv Name) must contact the Commission to obtain advance approval of such water well testing program. Rev: 1/1 W008 WELL PERMIT CHECKLISTField & Pool MOQUAWKIE, UNDEFINED GAS - 528500 Well Name: MOQUAWKIE 4 Program DEV Well bore seg ❑ PTD#: 2070840 Company AURORA GAS LLC Initial Class/Type DEV / 1 -GAS GeoArea 820 Unit On/Off Shore On Annular Disposal ❑ Administration1 Perm it fee attached---------------------------------------------NA---------------------------------------------------------------------------- 2 Leasenumberappropriate----------------------------------------- Yes------- CIRllease_C-061390------------------------------------------------------- 3 Uniqueweil-name and number ------------------------------------- Yes--------------------------------------------------------------------------- 4 Welllocatedin-a-defined-pool---------------------------------------No -------- Moquawkiegas_poolis undefined ------------------------------------------------ 5 Well located proper distance from drilling unittmndary------------------------ Yes _ _ _ _ _ _ _ Will be located over 1 mile from nearest property boundary._ - _ - _ - - _ _ - - _ - _ - - - - _ - - - - - - - - - - - - - - 6 Well -located proper distance from other wells -- No _ - _ _ - _ _ SPACING EXCEPTION NEEDED: _located closer than 3000' to nearest producer- - - - - - - - - - - - - - - - - - - - 7 Sufficient acreage available in -drilling unit_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ No- - - _ _ _ - _ SPACING EXCEPTION NEEDED:- 30 -gas producer in Section 1.- - - - - - - - - - - - - - - - - - - - - - - - - - _ - - 8 Ifdeviated,isweliboreplat-included-----------------------------------NA -------- Vertical well ------------------------------------------------------------- 9 Operator only affected party ----------------------------------------- es--------------------------------------------------------------------------- �10 Operator has-appropriatebondinfQrce--------------------------------- Yes ------- NZS429815--------_----_----------------------------------------------- 11 Permit can be issued without conservation order_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ No_ _ _ _ _ _ _ _ Draft text of conservation order completed August 16, 2007 _ SFD - - _ - - - _ - _ _ _ _ _ _ _ _ - - - _ - - - - - - - - - Appr Date 12 Permit can be issued without administrative approval _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes - - - _ _ - _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ - - - _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ - _ _ _ - - ACS 9/16/2008 13 -Can permit -be approved before l5-day_wait------------------------------- No----------------------------------------------------------_----------------- 14 Welllwated within area and -strata authorized by- Injection Order# (put 10# in -comments) (For NA_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 15 All wells_ within1/4-mile_area_ofreview identified (For sery_icewellonly) --------------- NA____--_____----__-_-_---____-_-_-___________________________-_-_---_---_--_ 16 Pre -produced injector. durabon_ofpre-production less than3months- (Forservicewell ody)--- NA--------------------------------------------------------------------------- 17 Nonconven.gasconfor_rrstoA$31.05:030(j.1.A),(L2.A-D)----------------------- A- --------------------------------------------------------- ------------------ Engineering 18 Conductor string- provided ----------------------------------------- Kes ------------------------------------------------------------------------- 19 Surface casingprotects all -known- USDWs _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ - _ _ _ _ _ Surface and -production casing will_protect any -FW sands._ Based on area drilling, -gas cQube be present at _ - - _ _ 20 CMT vol adequate to circulate -on conductor & surf csg _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ _ _ _ _ _ _ or near the _surface casing shoe. _ _ - - - - - - - - - - - - - - _ - - _ - _ _ _ _ _ _ - - - - - - - - _ _ - _ - _ _ - _ - - - 21 CMTv_oladequatetotie-inlQngstringtosurfcsg---------------------------- Yes ---------------------------------------------------- 22 CMTwillcover all known -productive horizons ------------------------------ Yes --------------------------------------------------------------------------- 23 Casing designs adequate for CJ, B&- permafrost --------------------------- Yes--------------------------------------------------------------------------- 24 Adequate -tankage or reserve pit _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ - - - - Rig is_equipped with steei_pits. _Although relatively small, Aurora has successfully drilled similar wells _ _ _ _ _ _ - _ 25 If_a re -drill, has_a 10-403 for abandonment been approved _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA__ _ _ _ _ _ _ _ _using this rig. Drilling waste likely handled via Envirotech._ - _ _ - - - - - _ - _ _ _ _ _ _ - - - _ - - - _ - - _ - - _ _ 26 Adequatewellboreseparationproposed--------------------------- - - - - -- Yes--------------------------------------------------------------------------- 27 If diverter-required, does it meet regulations_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ No_ _ _ _ _ _ _ _ Plan is for 12-1/4" hole with -12" line._ This arrangement has been approved previously ._ _ - _ - _ - - - _ - - - - - - - Appr Date 28 �29 Drilling fluid program schematic-& equip list -adequate -_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ _ _ _ _ Maximum expected formation pressure up to 9.8 EMW. Planned MW -up tQ 10.0 ppg• - - - - - - - - - - - - - - - - - TEM 9/16/2008 BOPEs,_dothey-meet regulation------------------------------------- Yes------------------------------------------- ------------------------------- �'r" 1 30 BOPE_press rating appropriate; test to -(put prig in comments)_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes - _ _ _ _ _ _ MASP calculated at 1435 psi. 3000_psi-BOP test -planned - _ - _ - _ - _ _ _ _ - _ _ _ _ _ - - - - - - - - - - - - - - - - - 31 Choke_ manifold compliesWAPI_RP-53GMay64_)---------------------------- Yes --------------------------------------------------------------------------- 32 Work will occur withoutoperaionshutdown------------------------------- Yes-----------------------------------------------------------_--------------- 33 Is presence ofH2Sgas. probable -------------------------------------- o---------------------------------------------------------------------------- 34 Mechanical -condition ofveilswithinAORverifiied(Forservicewellonly)______________ NA-------_-_--_---__--____--_-_-- -_--_----__--_---_______--_---_----_-_______ Geology 35 Permit can be issued wto hydrogen sulfide measures _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ _ _ _ _ No record of H2S_in shallow sands within this area. _112S monitoring equipment will be --------------- 36 36- Data -presented on potential overpressure zones _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ _ _ _ _ Well will be mudlogged. _ Moquawkie 3 encountered gradient of 0,51-psilft (9 6-ppg EMW)._ Moquawkie 4 will be _ _ Appr Date 37 Seismic analysis of shallow gas -zones ----------------------------------- A_ - _ _ - _ _ _ drilled using 9,3 to 10.0 ppg mud. _ _ _ _ _ _ - _ _ --------------------------------------- ACS 9/16/2008 38 Seabed condition survey -(if off -shore) _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA_ _ _ _ 39 Contact name/phone for weekly -progress reports [exploratory only] _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ _ _ _ _ Ed Jones -713-977-5799 or Bruce Webb 277-1003 or_229-8398_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - _ _ _ _ _ - Geologic Engineering Public Date: Date Date SPACING EXCEPTION REQUIRED. Hearing scheduled for July 26, 2007 was vacated on July. 23, 2007. CO 589 for Commissioner: Comm' sioner: Commissioner spacing Exception. MUDLOGGERS AND GAS DETECTION EQUIPMENT REQUIRED due to shallow gas hazards in the c� area. Moquawkie 1 had a blowout and fire caused by shallow gas. Moquawkie 3 flowed at 1020' where 2900 units of gas were recorded. Well flowed again at 1258'& 1539'. 5000 units of gas were recorded at 1539 & at 2471'. Page 1 of r 0 is 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 Tom, I miss -spoke when we discussed the production casing bit size by phone earlier today, talking off the top of my head instead of reviewing the files. In reviewing the plans for the Moquawkie #4 well and what we have been doing in recently drilled wells and confirming this in a conversation with Jack McDade, the plan is indeed to run 7- 7/8" bits with either 9-5/8" or 8-5/8" surface casing. Thus, please change any reference to 8-1/2" bits in the APD documents to 7-7/8" (apparently left over from the Nicolai Creek 10 well documents being used as a template). Therefore, the cement volumes, calculated on the basis of 7-7/8" hole will remain the same. Sorry for the inconvenience 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 least 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 OF AIASKA SARAH PAUN, GOVERNOR ALALSKAL OIL, AND`AS333 W. 7th AVENUE, SUITE 100 CON MRVA IONT COMMSSIO 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 Address 1400 West Benson Blvd, Suite 410 Anchorage, Alaska 99503 Re: Moquawkie #4 Aurora Gas, LLC Permit No: 207-084 Surface Location: 1259' FEL, 1121' FNL, SEC. 1, T1 IN, R12W, SM Bottomhole Location: 1259' FEL, 1121' FNL, SEC. 1, T1 IN, R12W, 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). DATED this l ay of August, 2007 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 RECEIVEO 2 Zoo? 1 a. Type of Work: Drill i] Redrill ❑ Re-entry E]Multiple 1 b. Current Well Class: Exploratory ❑ Development Oil ❑ Stratigraphic Test ❑ Service ❑ Development Gas I] Zone E]Single Zone ElShale 1c. Specify if well is proposed o . I Gas Co Coalbed Methane E] Gas HyAr"OrZ. Can n Gas E] 2. Operator Name: Aurora Gas, LLC 5. Bond: Blanket 0 Single Welln Bond No. A/ r yl.b 11. ell Name and Number: qua No.4 3. Address: 1400 West Benson Blvd, Suite 410, Anchorage AK, 99503 6. Proposed Depth: 0112. MD: 3,500' TVD: 3,500' Field/Pool(s): Moquawkie Gas Field 4a. Location of Well (Governmental Section): Surface: 11Z51"FEL, t'IZf FNL, Sec. 1, T11N, R12W, SM Top of Productive Horizon: Same Total Depth: Same 7. Property Designation: C-061390 8. Land Use Permit: N/A 13. Approximate Spud Date: 8/1/2007 9. Acres in Propertv: 640 14. Distance to Nearest Property: j,IZ,i FNI, 4b. Location of Well (State Base Plane Coordinates): Surface: x-266913 y- 2588012.3 Zoi 4 10, KB Elevation 3 O"W D (Height above GL): 77 feet 4.1414.0 15. Distance to Nearest Well ithin Pool: 1,127' 16. Deviated wells: Kickoff depth: feet Maximum Hole Angle: degrees 17. Maximum Antici ted Pressures in psig (see 20 AAC 25.035) Downhole: 1,785 si Surface: 1,435 psi 18. Casing Program: Specifications Top -,getting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) Driven 13-3/8" 72# K-55 BW 80' 16' 16' 96' 96' N/A 12.25" 9-5/8" 36# L-80 LTC 834' 16' A 16' 850' 850' 362 sx 5-1/2" 15.5# J-55 BTC 3484 1 16' 3,500' 3,500' 622 sx 19. PRESENT WELL CONDITION SUMMARY (To b c p d f Redrill and Re -Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): E Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): 'r 19 Casing Length Size Cement Volume MD TVD Conductor/Structural r Surface Intermediate Production xv Liner ILY Perforation Depth MD (ft): Perforation Depth TVD (ft): 20. Attachments: Filing Fee B Ph E]Drilling Program FZ] Time v. Depth Plot i] Shallow Hazard Analysis ElProperty Plat i] Div r tch ❑ Seabed Report ❑ Drilling Fluid Program I] 20 AAC 25.050 requirements ❑ 21. Verbal Approval: Commission Represent ve. Date - 22. 1 hereby certify that the foregoing is true d co ct. Contact Printed Name J. Edward Jones Title Execurive Vice President—Engineering and Operations Signature Phone 713-977-5799 Date June 11, 2007 Commission Use Only Permit to Dri Number:? API u ber:.�Q2 �/� Permit Approval ! 50- " Zd l �t�-l� Date: a •Q See cover letter for other Irequirements. Conditions of approval : If box ' checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Other: 3p00 QS% 6 Q �e�,�r Samples req'd: Yes[]NoG�' Mud log req'd: Yes[] Nope Directional svy req'd: Yes❑ NoLv1 `aN VZV@t'tQC" G��1 aOA�� O�S`,...kI2S measures: Yes❑ No[r Ib ` \JVJ cI�N�►rh®�'► 3tkMtL%1iCLd- ,.2[.m7 APBY THE COMMISSION DATE: g" Z Z4 PROV , COMMISSIONER Form 10-401 Revised 12/2005 ORIGINALSubmit in Duplicate tissi �Aurora Gas, LLC www.aurorapower.com June 7, 2007 Mr. John Norman, Chair Alaska Oil and Gas Conservation Commission 333 West 7a' Ave., Suite 100 Anchorage, Alaska 99501 RE: Application for Permit to Drill: Moquawkie No. 4 Dear Mr. Norman: RECEIVED JUN 1 2 2007 Alaska Oil & Gas Cons. Cammission Anchorage Aurora Gas, LLC hereby applies for a Permit to Drill an onshore gas development well in the Moquawkie Field about 6 miles west of the Native Village of Tyonek. The well is planned as a vertical well targeting the Upper Tyonek Formation to test for gas. A secondary target is the shallower Beluga 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 Edward Jones Executive Vice President Engineering and Operations enclosures cc: Bruce Webb — Aurora Gas 0 Aurora Gas, Moquawkie #4 floquawkie #4 Drilling Program Moquawkie #4 is a grass-roots well targeting Beluga & Tyonek Gas Production. It is located in the Moquawkie Gas Field '/4 mile NE of the Moquawkie #1 & #3 wells. Moquawkie #4 will target Beluga Tsuga 2-8 sands plus Upper Tyonek Carya 2-1 thru 2-3 sands in a separate thrust slice from the downdip Moquawkie #3 well. Moquawkie #4 will also penetrate the Upper Tyonek Carya 2-4 in an updip attic location relative - to the Moquawkie #1 well and will access gas reserves that have been undrained by that well and may remain undrained due to excess water production resulting from suspected casing damage and poor cement quality. Pre Rig work 1. Stake & survey the Moquawkie #4 drillsite. 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. Cutoff 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 850' of 9-5/8" surface casing. i 6. PU 12-1/4" mill tooth bit & drill to —850', 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 9-5/8" surface casing, POOH, LD 12-1/4" BHA. 8. Run & cement new 9-5/8" 36 #, K-55 LTC casing @ 850', installing 1 centralizer /joint centered on the 1" 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. Prepared by Jack McDade Page I of 11 Rev. 1.0 Aurora Gas, 0 foquawkie #4 Drilling Program 9. RD cementers, nipple down diverter, cut casing and install i 1" 3M wellhead. 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 requir C on approved Permit to Drill. 11. PU `insert bit, stabilizers & RIH w/ 6-1/4" 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. 12. Drill y718" hole to TD @ 3,500'. Monitor well & pit volumes carefully. Be prepared to shut in the well & weight up if well begins to flow. Monitor drilling trends for signs of poor hole cleaning & pump sweeps / short trip accordingly. C ©\ESi`ZC 13. Condition hole, short trip and prepare for running wireline logs. .� 14. POOH, rack back drillstring and RU wireline BOP's and lubricator and logging tools. r 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. 15. RIH w/,3,W8" drilling assembly to TD & condition hole for running 5-'/2' casing. Ensure cementing head has proper connections or proper cross-over and is available for quick rig up. 16. POOH while laying down drillpipe & BHA, RU to run casing. Verify cementer's equipment is ready. 17. Install 5-t/2' pipe rams. 18. Run 5-1/2' 15.5# BTC J-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. 19. 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 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 the 9-5/8" 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. 20. RD cementers, nipple down stack, land casing in slips & cut casing. 21. 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. 22. Install 2-7/8" pipe rams. 23. RIH w/ bit & casing scraper on 2-7/8" tubing to float collar. Displace well w/ filtered KCl/NaCl brine (wt. to be determined from MDT data). Continue to clean brine for Prepared by Jack McDade Page 2 of 11 Rev. 1.0 Aurora Gas, 11 Moquawkie #4 Drilling Program perforating by running through centrifuge & filtering. POOH. Strap tubing on TOH to validate tally. 24. 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. 25. 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. 26. 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. 27. Repeat step 26 until all zones of interest have been evaluated for production. 28. POOH. Pull slowly to avoid swabbing in well with packer. 29. 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. 30. RIH with new 2-7/8" 6.5# EUE 8rd production tubing, hydraulic -set retrievable packers, sliding sleeves & 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. 31. 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. 32. Install BPV, nipple down & remove BOP stack. Install production tree. Tear down & remove all rig equipment. 33. Clear & clean location. Hand well over to production. 34. File completion reports with proper agencies. Site Access Moquawkie #4 will be accessible via existing gravel roads currently in use to support production operations at the Moquawkie #1 drillsite. Rig Aurora Well Service, Rig No. 1 (AWS 1) will be used to drill the Moquawkie 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. Prepared by Jack McDade Page 3 of 11 Rev. 1.0 Aurora Gas, 0 Survey Program floquawkie #4 Drilling Program The Moquawkie #4 well will be drilled as a vertical well. Wellbore surveys will be obtained @ 500' intervals in accordance with rules laid out in 20 AAC 25.050 (a) (1) & (2). Logging Program Mud loggers will be on site for the duration of drilling activities. Schlumberger will provide wireline logging services as proposed below: Moquawkie #4 Proposed Logging Program Well Section Depths OH CH Log Type 12-1/4" Surface 0'— 850' N/A: No open -hole logs planned for surface at this time. GR only in cased hole. ,kVT" Production Hole 8501— 3,500' 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: 12-1/4" Surface Hole 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. sll?. X7/'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 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. Prepared by Jack McDade Page 4 of 11 Rev. 1.0 Aurora Gas, 0 Drilling Fluids Ilquawkie #4 Drilling Program 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 12-1/4" interval to 850' 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,75-70rinterval to 3,500' Beluga and Tyonek Formations Base Fluid 6% KCL Density 9.3 —10 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 Aurora Gas, Casing / Cementing Program floquawkie #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" 72# K-55 Conductor Analysis and Cementing Program The conductor for Moquawkie #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. 9-5/8" 36# K-55 BTC Surface Casing Analysis and Cementing Program The 9-5/8" surface casing will be cemented from the proposed setting depth of 850' to surface with a 14.5 ppg Type I, gas block enhanced cement system. Capacities: 9-5/8" Csg. Capacity =.1458 bbl/ft 9 -5/8" Csg. x 12-1/4" OH Capacity --.0558 bbl/ft System Volume: 12-1/4"OH x 9-5/8"Csg: 850'x.0558 bbl/ft x 2 (100 % excess) = 94.9 bbls Shoe Jt: 40' x .0773 bbl/ft = 3 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 System Weight (ppg) bbl cf sx Gas -Block enhanced Type I 14.5 94.9 532.8 Yield 1.47 cf/sx Please see attached 9-5/8" surface casing analysis and specifications. 5-1/2" 15.5# J-55 BTC 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: 5-1/2' 15.5# csg capacity = .0238 bbl/ft 5-1/2" 15.5# csg X 7-7/8" OH capacity =.0309 bbl/ft Prepared by Jack McDade Page 6 of i i Rev. 1.0 Aurora Gas, • floquawkie #4 Drilling Program 5-1/z" 15.5# csg X 9-5/8" 36# annular capacity = .0479 bbl/ft Lead System: 9-5/8" CH x 5-'/2"Csg: 850 ft 850' x .0479 bbls/ft x 1 (0% excess) = 40.7 bbls Lead Cement Volume = 40.7 bbl Tail System: 7-7/8" OH x 5-1/2 Csg: 3,500'-850'=2,650' 2,650' x .0309 bbl/ft x 1.25(25% excess) = 102.4 bbls Shoe Joint: 40'x.0238 bbl/ft = 1 Total Tail Cement Volume =103.4 bbls Actual volumes will be calculated at time of running casing due to potential variation in depth from planned. Cement System Type Cement Weight (ppg) bbl cf sx Lead @ 1.83 cf/sx G 13.5 40.7 229 ?mow Tail @ 1.17 cf/sx G 15.8 103.4 581 499 ` a 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 Moquawkie #3, maximum anticipated bottom -hole pressures should not exceed 1,785 psi at 3,500 ft. Pressures measured at the Moquawkie #3 well indicated a gradient of —.51 psi/ft with a bottom -hole pressure of 1,270 psi recorded at 2,473'. Maximum anticipated surface pressures "MASP" can be calculated by subtracting the gas gradient of .1 psi/ft from pore pressure gradient of .51 psi / ft and multiplying by the total TVD depth. Maximum Anticipated Surface Pressure= (.51 -.1) * 3,500'= 1,435psi A formation integrity test to 16.0 ppg EMW @ 620' was conducted while drilling Moquawkie #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)*850'=673 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. I/ responsible personnel will be made aware and a notice of such hazards will be posted in the rig doghouse. There is no record of 1-12S in the region, however; a gas detection system capable of detecting 1-12S 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 Aurora Gas, 0 Voquawkie #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 Moquawkie #4. The nearest well activity lies'/4 mile SW on the Moquawkie #1 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 Aurora Gas, 0 a14!/m d Gas,, LLC IMoquawkie #4 Proposed Configuration Drill 12-1/4" Hole to 850' 2-7/8" x 5-%" annulus to be displaced over to inhibited packer fluid through sleeve @ 845' Beluga Tops Tsuga 2-8— 954' Tyonek Tops Carya 2-1 — 1,582' Carya 2-23 — 2,200' Carya 2-4 — 2,361' Tyonek Perforation Intervals to be determined by open -hole logging. Carya 2 Carya 2-2 Carya2 Carya: Drill 7 5/8" Hole to 3,500' Estimated PBTD @ 3,460 floquawkic #4 Drilling Program 2 7/8 6S# 8rd EUE J-55 Tubing 12-1/4" 68# Structural Conductor to be driven to 80' or refusal -5/8" 36# Surface Casing set at 850' :cment w/ 14.5 ppg Gas -Block nhanced Aiding sleeve 1 joint above packer tydraulic Set Packer @ — 875' Aiding Sleeve @ — 950' ,draulic Set Packer @ 1,500' ling Sleeve @ —1,582' 6.5# EUE 8rd Tubing w/ Seal ibly to Retrievable Seal Bore Packer 50' Sliding Sleeve @ 2,200' Hydraulic Set Packer @ 2,300'w/ 131 profile XN nipple Drill 7-7/8" Hole to 3,500' 15.5# J-55 Casing to 3,500' MD (TVD) Prepared by Jack McDade Page 9 of 11 Rev. 1.0 Sli27/81 Asw 3 C 12-1/4" 68# Structural Conductor to be driven to 80' or refusal -5/8" 36# Surface Casing set at 850' :cment w/ 14.5 ppg Gas -Block nhanced Aiding sleeve 1 joint above packer tydraulic Set Packer @ — 875' Aiding Sleeve @ — 950' ,draulic Set Packer @ 1,500' ling Sleeve @ —1,582' 6.5# EUE 8rd Tubing w/ Seal ibly to Retrievable Seal Bore Packer 50' Sliding Sleeve @ 2,200' Hydraulic Set Packer @ 2,300'w/ 131 profile XN nipple Drill 7-7/8" Hole to 3,500' 15.5# J-55 Casing to 3,500' MD (TVD) Prepared by Jack McDade Page 9 of 11 Rev. 1.0 Aurora Gas, 0 0 500 1,000 1,500 s a m m 2,000 m 2 2,500 3,000 3,500 4,000 • Moquawkie #4 Days vs Depth 5 10 15 foquawkie #4 Drilling Program 20 25 30 Days Prepared by Jack McDade Page 10 of 11 Rev. 1.0 Drill 121/4 I i R in 9-5/8 Ca ing I I I i I I Drill 8-1/2 Interval I i i j I I I Log Well, Run 5-1/2 Casing, I Perforate, Testi I Run Completion i I I Days Prepared by Jack McDade Page 10 of 11 Rev. 1.0 Aurora Gas, folquawkie #4 Drilling Program Moquawkie #4 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. 4 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 MOQUAWKIE #4 WELL PLAN FOR ADDITIONAL INFORMATION Prepared by Jack McDade Page 11 of 11 Rev. 1.0 Aurora Gas, LLC Moquawkie No.4 Casing Properties and Design Verification Casing Performance Properties Internal Collapse Tensile Strength Size Weight Yield Resistance Joint Body TVD MD in.1� b/ft) Grade Cnxn kRsji si (1,000 lbs (ft RKB) (ft RKB) 9-5/8 36 K-55 LTC 3,520 2,020 489 564 850 850 5-1/2 15.5 J-55 BTC 4,810 4,040 300 248 3,500 3,500 * Tensile design safety factors are calculated using pipe weight less buoyancy. Design Safety Factor* T B C 18.8 5.2 5.0 5.4 3.5 2.4 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 9-5/8" 850'MD / 820'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" 3,500'MD / 3,500'TVD Production casing to stabilize and isolate producing interval for production operations. Is • 6 0 TRANSMITTAL LETTER/ CHECKLIST WELLNAME /�l/o ZC2 �Kfd PTD# �7—ogc/_ /Development Service Exploratory Stratigraphic Test Non -Conventional Well Circle Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK , ADD-ONS TEXT FOR APPROVAL LETTER WHAT 1 (OPTIONS) APPLIES I � I MliLTI LATERAL The permit is for a new wellbore segment of existing 1 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 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 ( PI -1) and API number ' (50- --) from records, data and logs acquired for well SPACING The permit is approved subject to full compliance ith 20 AAC I EXCEPTION 25.055. Approval to perforate and Rroduce is contingent ` upon issuance of a conseUation L !proving a spacing j exception. y✓CsyG�.. �- assumes the 1 liability of any protest to the spacing exception that may occur. I 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 Ifrom where samples are first caught and 10' sample intervals ii through target zones. Please note the following special condition of this permit. j Non -Conventional production or production testing of coal bed methane is not allowed j Well for (name of well) until after (Company Name) has designed and implemented a water well testing program to provide baseline data j on water quality and quantity. (Comoa Name) must contact the Commission to obtain advance approval of such water well testing program. _ Rev: P25i06 C :`jody\tmnsmitta1_chcck1 ist . 't y Fi&MOQUAWKIE, UNDEFINED GAS - 528500 �5"" eld Pool SPACING EXCEPTION REQUIRED. Hearing scheduled for July 26, 2007 was vacated on July 23, 2007. MUDLOGGERS AND Well Name: MOQUAWKIE 4 Program DEV Well bore seg ❑ PTD#:2070840 Company AURORA GAS LLC Initial Class/Type DEV / PEND GeoArea 820 Unit On/Off Shore On Annular Disposal ❑ Administration 1 Permit fee attached - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 2 Lease number appropriate_ _ Yes - ease_C-0613903 - - - - - _ CI_RI lease-C-061390- 3 Unique well -name and number - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 4 Welllocatedin-a_defined-pool ----------------- _-------------------- No ----- Moquawkiegas_poolisundefined --- __________________ 5 Well located proper distance from drilling unit_boundary_ _ - - _ - - - - Yes Will be located over 1 mile from nearest property boundary-- - - - - - - - - - - - - - - - - - - - - - - - 6 Well located proper distance_ from other wells- - - - - - - - - - - - - - - - - - - - - - - - - - - - - NO - - - - - - - - SPACING EXCEPTION -NEEDED:- _located closer than 3000' to nearest -------------------- - - 17 17- Sufficient acreage available in. drilling unit_ - _ _ _ _ N_o_ SPACING EXCEPTION -NEEDED: 3rd _gas producer_in Section 1 -- _ _ _ - - _ _ _ _ 8 If -deviated, is -wellbore plat -included - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - NA_ - _ _ _ - - - Vertical well_ _ _ _ _ _ _ _ - - - _ _ 9 Operator onlyaff_ectedparty---- - - - - -- - - - -. --- --- ---------- - - - - -- Yes- ----------------------------------------- - - - - ----- ---- -- -..------------- 10 Operator has_appropriate_bondinforce-- ------------------------- - - - - -- Yes_______ NZS429815___________ -------------------------------------------------- 11 Permit_can be issued without conservation order- - - - - - - - - - - - - - - - - - - - - - - - - - - N_o_ - - - - - - - Draft text of conservation order_c_ompleted August 1.6, 2007._SFD _ - _ _ _ - - _ - - - _ _ - _ _ _ _ _ _ _ _ _ - _ - - - - 12 Permit _canbeissuedwithoutadministrativ_e_approval _________________________ Yes______---__-----_______--_- --_-___-_.--____-------------------------___-_ Appr Date 13 Canpermitbeapprovedbefore 15-daywait-------------------------------NO SFD 8/16/2007 14 Well located within area and strata authorized b Injection Ord # Y lectOrder (put 10# in_comments)_(For_ NA- - - - - - - - - - - - 15 All wells -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 Nonconven, gas conforms to AS31,05.030�.1_.A),(j 2.A -D) NA_ - _ - - _ Engineering 118 Conductor string_provided - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - - - - - - - - - - - - - - - - - - - - 119 Surface casing_ protects all -known USDWs - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes Surface and -production casing _w_ill_protect any FW sands._ Based on area drilling, -gas coube be present at- - - - - 120 CMT -vol_ adequate to circulate on conductor & su_rf_csg - - - _ - _ - - - - _ _ Yes or near the surface casing- shoe . - - - - - (21 -CMT vol- adequate- to tie-in long string to surf csg- - - - - - - - - - - - - - - - - - - - - - - - - - - Yes _ - _ _ _ . 22 CMT -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. _Although relatively small, Aurora has successfully drilled similar wells 25 If_a_re-drill, has_a 1.0-403 for abandonment been approved - - - - - - - - - - - - - - - - - - - - NA_ - - - - - - - - - using this rig. Drilling waste likely handled via Envirotech-_ - - - - - - - - - - - - _ - - - - - - - - _ - - - - - - - - - 26 Adequate wellbore separation_proposed Yes 27 If_diverter required, does it meet regulations- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - No_ - - - - - - - Plan is for 12-1/4" hole with 12" line._ This arrangement has-been approved previously._ - - _ - . 28 _D_rilling fluid program schematic_& equip list adequate- - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - _ Maximum expected formation pressure up to 9.8 EMW. Planned MW_up to 10.0 ppg, -- - - -- - - -- - - - -- Appr Date 29 B O P E s , - d o they meet regulation - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - TEM 7/26/2007 30 BOPE_press rating appropriate; test to -(put psig in comments)_ _ - - - - - - - - - - - - - - - Yes - - - - - - - MASP calculated at 1435 psi. 3000_psi_BOP test planned, - - - - - - _ - - - - - - - - - - - - - - - - - - - - - - - - - - 31 Choke_manifold complies WAPI_RP-53 (May 84)- - - - - - - - - - - - - - - - Yes - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 32 Work will occur without operation shutdown- - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - _ - - - _ - _ _ - - - _ - _ _ _ _ _ - _ _ _ _- -------- --- ----- - -- - -- - -- -- -------------------- 33 -is presence_ofH2$ gas probable _____________________________________ N_o____________________________ ------------------------------------------------ 34 Mechanical_ condition of wells within AOR verified (For service well only_) - - - - - - - - - - - - - NA_ - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Geology 35 Permit -can be issued w/o hydrogen_ sulfide measures - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - - - - - No record of H2S_in shallow sands within -this area. _H2S-monitoring equipment will be used. 36 Data_presented on potential overpressure zones _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ _ _ _ _ Well will be mudlogged. _ Moquawkie 3 encountered gradient of 0,51 -psi/ft (9.8ppg EMW)._ Moquawkie 4 will be _ _ 37 Seismic analysis of shallow gas_zones- - - - - - - - - - - - - - - - - NA_ drilled using 9.3 to 10.0 ppg mud - - - - - - - - - - - - _ _ _ _ Appr Date 38 Seabed condition survey_(ifoff_-shore)--------------------------------- NA_________--------------_____ ____-------- - -_ _ - -_ SFD 6/21/2007 39 Contact name/phone for weekly- progress repo -rt -s [exploratory only] ----------------- Yes -- Ed Jones 713-977-5799 _ Geologic Engineering SPACING EXCEPTION REQUIRED. Hearing scheduled for July 26, 2007 was vacated on July 23, 2007. MUDLOGGERS AND Commissioner: Date: Co missioner• Date COO Date over �� GAS DETECTION EQUIPMENT REQUIRED due to shallow gas hazards in the area. Moquawkie 1 had a blowout and fire caused by shallow gas. Moquawkie 3 flowed at 1020' where 2900 units of gas were recorded. Well flowed again at 1258' & 1539'. 5000 units of gas were recorded at 1539 & at 2471'. • 0 Well History File APPENDIX Information of detailed nature that is not particularly germane to the Well Permitting Process but is part of the history file. To improve the readability of the Well History file and to simplify finding information, information of this nature is accumulated at the end of the file under APPENDIX. No special effort has been made to chronologically organize this category of information. 0 1 HALLIBURT N 1 Sperry Drilling Services � Aurora Gas,, LLC L C Ci J C L Moquawkie #4 End of Well Report �o� -0b't I--�96,) Aurora Gas, LLC TABLE OF CONTENTS 1. General Information 2. Daily Summary 3. Daily Operations (I.A.D.C.) 4. Morning Reports 5. Bit Record 6. Mud Record 7. Days vs Depth 8. Data CD 9. Formation Evaluation Logs 10. Engineering Log HALLIBURTON Sperry Drilling Services Aurora Gas, LLC GENERAL WELL INFORMATION Company: Rig: Well: Field: Borough: State: Country: API Number: Sperry -Sun Job Number: Spud Date: Total Depth Date: Rig Release Date: Total Depth: Aurora Gas, LLC. AWS -1 Moquawkie 4 Moquawkie Tyonek Borough Alaska United States 50-283-20120-00 AK -AM -0006174381 25 Sep, 2008 17:00 hrs 24 Oct, 2008 23:00 hrs 8 Nov, 2008 3450' M D Location: 1415' FEL, 1160' FNL, SEC. 1, T11N, R1 2W, SM Cartesian Coordinates: X=266767.784', Y=2587949.272' Longitude: 1510 4'37.26" N Latitude: 610 19' 1.87" W Drill Floor Elevation: 299.00' above MSL Ground Elevation: 284.50' above MSL SDL Engineers: Wayne Hermanson, Danny Kane, Colby Marks, Daniel Sherwood ISSDS Unit Number: l i J 110 HALLIBURTON Sperry Drilling Services DAILY SUMMARY Aurora Gas, LLC MOQUAWKIE #4 ' 2_ DAILY SUMMARY 23 Sep 2008 Rig up and test gas sensors. Make up bit and equipment to drill mousehole. Cut 10 3/4" joint to T for mousehole sleeve. Spot vac truck at cellar and drill mouse hole. 24 Sep 2008 Drill mousehole. Note: large rocks and sluffing pea gravel. Used vac Truck to suck fluids from cellar and super sucker to remove gravels. Run fluid back over shakers. Note: Pulled several rocks out 2' in diameter and backside of cellar box eroding. Made 19' below ground level. Pick up mousehole and drive down with 6" drill collar. Use rig pump to wash down mousehole and vac truck to return fluids to pits. 25 Sep 2008 Continue to pump and drive mousehole down. Rig down equipment for mousehole project. Rig up for milling conductor. Fill in cellar box and around outside of cellar and compact. Load pipe rack with drill pipe and strap pipe. Make up milling assembly and clean out conductor to bottom — 80'. Make up 12 1/4" bit and 6" DC's. Drill 12 1/4" hole from 80' to 124'. 26 Sep 2008 Drill 12 1/4" hole from 114' to 178' with 6" DC's. Pull out of hole and lay down 6" DC's. Set mud pump 42 and diesel tank. Fabricate new suction line for #2 mud pump. Pick up 8" BHA while fabricating new suction line. Run in hole to 140'- tag fill. Pick up and work on #2 mud pump. Wash back to bottom from 140' to 178'. 27 Sep 2008 Wash fill from hole and circulate hole clean. Drill 12 1/4" hole from 178'to 460'. Note: Highest gas peak 3250/18 units at 344' possibly in a coal. 28 Sep 2008 Drill 12 1/4" hole from 460' to 495'. Hydraulic power swivel unit down - replace actuator. Drill 12 1/4" hole from 495' to 868' —total depth surface hole. Note: connection gas ranged from 30 to 205 units over a background of 10-30 units - 432 units at 803' occurred with an increase in background gas making interpretation of connection gas amount difficult. Circulate hole clean. Drop survey 0.750. Rig up floor and stand back power swivel in preparation for wiper trip. Start short trip, pull 2 stands and well kicked at 22:30 hrs — maximum gas observed at the shaker 9492 units. Stab safety valve, closed bag and opened diverter. Rig up to pump down drill pipe. Clear all nonessential personnel from location, block entrance and weight up mud system. 29 Sep 2008 Continue to weight up mud to 10.3 ppg. Pump on well at 14 bpm in attempt to kill, but unsuccessful. Build volume and weight up pits to 13.0 ppg use Vac trucks to store 100 bbls mud and build 270 bbls mud in pits. Clean up location. Hold pre job safety meeting and discuss responsibilities and duties during kill operations. Fill trip tank with 13.Oppg mud, bring pumps up slowly and fill pipe. Bring rate up to 14 bpm and pump 70 bbls. Note: had trouble with #1 pump, therefore pumped through bleeder and continued kill operations. Bubbles were observed in cellar - no returns or losses in cellar. Got 10.5 ppg mud at vent line, therefore opened bag and took returns back to pits. Note: Maximum gas while killing well 3931 units. Circulate out gas and cuttings until 13.0 ppg mud weight was achieved. Break down 2 stands to singles and pickup power swivel. Ream back to bottom and circulate gas out between connections (450-510 units). 30 Sep 2008 Ream and circulate to bottom. Wipe tight spots. Circulate on bottom and clean up pad. Note: had 2 gas peaks of 466 and 511 units and gas tapered off to 20-30 units while reaming back to bottom. Pull out of hole (wiper run) from 868' to 186'- pull slow and watch for swab. Run in hole and circulate hole clean — maximum wiper trip gas 45 units.Trip out of hole to run casing. Rig up and run 855' of 9 5/8" 36 # casing. Circulate with rig pumps and clear equipment. Hold pre job safety meeting with BJ Cements and crew - wait on Tyonek water truck for 1.5 hrs. 11 DAILY SUMMARY Aurora Gas, LLC MOQUAWKIE #4 01 Oct 2008 Take on water from Tyonek Vac truck. Pump 13.0 ppg spacer swap hose to BJ. Pressure test lines - hose leaked. Changed hose and pressure test to 3000 psi. Pump cement and displace with mud - 5 bbls cement to surf. Note: plug did not bump but floats held. Work on mud pumps, clear pad of 8" tools and GBR equip. Nipple down diverter system and clean same. Make rough cut on 9 5/8" casing. Make final cut on casing and preheat for weld procedure. 02 Oct 2008 Continue to preheat wellhead and weld same. Insulate wellhead and cool weld. Gather BOP equipment. Test wellhead to 1,600 psi for 15 minutes and change HCR's. Change rams to 3 1/2" and nipple up BOP'S. 03 Oct 2008 Nipple up and test BOP'S. Lay down test plug, test joint and install wear ring. Repair gas detector on rig floor. Lay down two 6-3/4" DC's. Make up 4-3/4" BHA and run in hole with 3-1/2" drill pipe. Lay down 5 joints from derrick. Tagged cement at 792'. Circulate and cut mud weight from 12.8 to 10.5 ppg. 04 Oct 2008 Continue to circulate to lower mud weight to 10.5 ppg. Drill cement from 792' to 805', drill float collar and cement to 827'. Having electrical problems with breaker for mud pumps. Pull out of hole and change jets from 18's to 15's. Trip in hole to 827'. Rig up and test casing to 1,500 psi for 15 minutes - lost 60 psi. Weld derrick board. Drill cement from 827' to 845'. Circulate bottoms up. Lay down one single and pull out of hole. Rig up Schlumberger and run temperature and bond logs. 05 Oct 2008 Rig up and re -run temperature logs. Rig up and run bond log tools. Rig up and run MAPS and temp log. Wait on USIT log tools from Kenai (weather hold). Rig up and run USIT logs. Rig down Schlumberger (lost bow spring to hole). Wait on junk basket, RTTS packer and bridge plug (weather hold). Lay down bit, bit sub and float sub. Run in hole and wash and ream from 792' to 825'. 06 Oct 2008 Mill cement from 825' to 845'. Set back power swivel and reverse circulate. Pull out of hole SLM. Lay down junk basket and clean rubber from ports. Run in hole. Reverse circulate to 846'. Pull out of hole. Lay down junk basket - no fish. Make up EZ Drill packer and run in hole to 530' and set packer. Wait on orders for mud weight up (winterize rig). Weight up 80 bbls from 10.5 to 12.8 ppg and displace 350' casing. Pull out of hole. Lay down running tool. Wait on weather to get Cementers to do squeeze. 07 Oct 2008 Hang tarps winterize rig while waiting on weather to get Cementers to do squeeze. Finish rigging up Schlumberger and run run guns to perforate from 520' to 525'. Pull out of hole - 20 shots fired. Inject 2.0 bbls mud to verify perfs open - 1.3 bbls/min, 385 psi max, 325 psi at shutdown. Run RTTS packer and set at 470'. Finish rigging up BJ for cement job. 08 Oct 2008 Pressure test lines to 2,500 psi with BJ - OK. Establish injection at 1, 1.5, 2 and 3 bbls/min--415 psi for a total of 10 bbls pumped - no change on annulus. Mix and pump 82 sx, 21 bbl, 14.7 ppg Class G with 2% CaCI + additives, inject at —1.2 bbls/min avg and 300 psi. Cement thick, mix water very hot, switch to displacement. Open reversing valve, reverse out above RTTS at 470'. Reset RTTS at 440', pressure up to 125 psi, held 90 psi for 2 minutes. Rig down BJ. Continue to winterize rig while waiting on cement. Release RTTS packer. Pull out of hole, soft cement in 2nd DC, break circulation, run 2 DC back in, circulate to clear cement from pipe. Pull out of hole and lay down RTTS. Rig up Schlumberger. Log 3 passes with Temp Log - wait 2.5 hr and 3.0 hr between passes. Logs inconclusive. 09 Oct 2008 Finish running 3rd pass with Temp Log - logs inconclusive. Rig down Schlumberger wireline. Run in hole with 7-7/8" bit and tag cement at 452'. Drill soft cement to 510'. Will not wash down, but drills with little to no weight with rotation. Circulate hole clean and wait on cement. Continue winterizing rig. Resume drilling soft cement from 510' to 520'. Shut down to clean fine cement cuttings out of returns ditch in pits. 2 IDAILY SUMMARY Aurora Gas, LLC MOQUAWKIE #4 10 Oct 2008 Drill soft cement from 520' to top of EZSV at 528'. Circulate hole clean. Stage up to test squeeze perfs. Perfs broke down in test to 260 psi, fell to 180 psi in 10 minutes. Stage up to establish injection rate. Perfs broke down and started taking more mud at 425 psi and 450 psi. Initial pressure 450 psi fell to 350 psi after injecting 4 bbls at 0.75 bbls/min. Initial shut in pres 180 psi. Circulate hole clean, 50 unit gas spike at bottoms up. Pull out of hole. Test BOP'S and equipment. Make up mill shoe and run in hole. Break circulation and tag EZSV at 528'. Pick up one foot and circulate mud in preparation for squeeze. 11 Oct 2008 Condition mud to 12.7 ppg in nd out. With mill shoe at 527', line up to BJ Cementers and perform squeeze of 2.2 bbls and hold back pressure of approximately 500 psi. Note: at 09:30 pressure had bled off to 345 psi at. Bleed off pressure to zero. Reverse circulate two bottoms up. Re -pressure to 482 psi and wait on cement with pressure bleeding off to 416 psi by 13:15 hrs. Bleed off pressure. Pull out of hole and lay down drill pipe. Run in hole and tag cement at 358'. Circulate and condition mud to 12.4 ppg. Drill out cement from 358' to 420'. Good, firm cement. 12 Oct 2008 Continue drilling cement from 420' to 495'. Last 45' drilled faster, more ratty, with soft spots, had —28 units gas from cuttings. Stop drilling and wait on cement. Continue winterizing rig and rig maintenance. Dump and rebuild some volume for cement contamination. Drill from 495' to 500' with hard cement. Circulate bottoms up and verify hard cuttings. Continue drilling hard cement from 500' to 528'- top of EZSV. Circulate hole clean. Test casing perfs to 500 psi. Note: Lost 12 psi to 488 psi, in 45 minutes - good test. Pull out of hole and make up 8-1/2" Junk Mill and boot basket. Set wear ring and run in hole with milling assembly. 13 Oct 2008 Run in hole with 8-1/2" Mill. Ream out cement skin from 358' to 458'. Circulate bottoms up. Change out wash pipe packing on power swivel. Continue reaming out cement from 458' to EZSV at 528'. Circulate bottoms up. Re -test squeeze perfs to 500 psi for 15 min - OK Mill on EZSV from 528' to 529'+. Circulate while Derrick Hand on crown changing out communications antenna. Continue milling on EZSV at 529'+ to 530'. 14 Oct 2008 Continue milling on EZSV at 530' and moving down hole. Circulate and weight up mud to 11.5 ppg. Test casing to 498 psi and lost 15 psi — OK. Continue milling on EZSV parts, junk, and cement to 869'. Circulate rat hole clean with 66 units of max gas. 15 Oct 2008 Drill 5' of new hole with mill. Shut down and monitor well — static. Dump contaminated mud while conditioning new mud up to 11.5 ppg. Pull out of hole and monitor well — static. Make up of 7-7/8" bit, run in hole. Drill to 889' and condition mud for FIT/LOT. Appeared to have leak off at 14.4 ppg EMW, 137 psi on 11.5 ppg mud. Drill to 909' for repeat FIT/LOT. Restest formation to 210 psi, no leak -off, 16.2 ppg EMW FIT. Monitor shut in for 25 minutes, slow decline to 185'. Circulate bottoms up and record SPR's. Drilling ahead. 16 Oct 2008 Drill ahead to 1386' while circulating out gas spikes and bottoms up gas on connections. At 1047', had 10' fast drilling break with 702 units max gas. Circulate hole clean. Rig up for survey and short trip. 17 Oct 2008 Circulate and survey, 1-1/4° at 1350'. Circulate bottoms up for short trip. Pull out of hole. Make up power swivel and run in hole. Circulate bottoms up with 220 units of max gas. Drill from 1386' to 1510' with 318 units of gas at 1510'. Drill from 1510' to 1604' with 700 units of gas at 1541'. Survey 1° at 1572'. Pull out of hole and rig up equipement to test choke manifold. No swabbing. 18 Oct 2008 Test choke manifold. Test BOP's, all good except lower Kelly valve. Run in hole with bit and BHA to shoe. Re -test lower Kelly valve — OK. Wash and ream to bottom, circulate up 250 units of max gas. Drill to 1700'. IDAILY SUMMARY Aurora Gas, LLC MOQUAWKIE #4 19 Oct 2008 Drill from 1700' to 2074' with 473 units of max gas at 1758'. Survey 2° at 2074'. Begin to pull out of hole for short trip. 20 Oct 2008 Short trip to 1575' and run in hole with no hole problems. Circulate bottoms up with minimal gas. Drill from 2074' to 2397'. Note: 1069 units of max gas at 2268'. 21 Oct 2008 Drill to 2574'. Run survey, 2° at 2544'. Had drill break at 2576' in a sand for rest of joint to 2605'.Short trip to 2050'. Trip volumes — OK. Circulate bottoms up with 165 units of gas. Drill ahead to 2676'. r22 Oct 2008 Drill to 2916'. ROP's slowed to about 10 feet per hour from 2865' to 2875'. Run wireline survey, 4-1/4° at 2885'. Pull r out of hole with proper fill. Replace worn bit, '/2 worn and 1/16" under gauge. Prepare to run in hole. 23 Oct 2008 Run in hole and circulated up 4875 units of trip gas, circulated clear. Ream out under gauge hole from 2730' to 2916'. Repeat wireline survey, 2-1/2° at 2885'. Drill from 2916' to 3102'. 24 Oct 2008 Drill from 3102' to 3401' and send mud logs to town for evaluation. Drill to 3450' as TD. 25 Oct 2008 Short trip 12 stands, tight spots on stands 10 and 11 (2450') with 3 klbs over pull, worked through. Run in hole with no tight spots and pump high viscosity sweep. Survey, 2° at 3400'. Pull out to shoe, tight spots at 2040' and 1900' with 4 klbs over pull, worked through. Pull out of hole.Test BOP'S. Rig up Schlumberger wireline service for logs. 26 Oct 2008 Complete rig up of Schlumberger wireline equipement. Run in hole with PEX, DSI, and CSI tools. CSI tool failed, pull out of hole to evaluate. 27 Oct 2008 Run in hole with CST run 42. Pull out of hole with tools. Run in hole with XPT tools. Lay down XPT tools rig down Schlumberger wireline equipement. Run in hole with BHA #3 to casing shoe. ' 28 Oct 2008 Attempt to circulate but line found frozen in pump room, repaired and circulate bottoms up at the shoe. Run in hole to 3390'. Circulate 4 bottoms up with lots of cuttings coming back. Short trip 13 stands to 2636' with minor tight spots. Run in hole to bottom. Flow check well. Pull out of hole. 29 Oct 2008 Lay down BHA. Function test 5-1/2" casing. Rams not closing properly, door opened and repositioned. Ready GBR tools and run casing to 3427'(no tight hole). Rig up stand pipe and rig up service lines to BJ. 30 Oct 2008 Pump cement, plug did not bump - bleed press, floats held. Full returns throughout job. Wait on cement to cure. 31 Oct 2008 Pick up stack and cut 5-1/2" casing, dress, make up and test BOP'S. 01 Nov 2008 Strap and drift 2-7/8" tubing and then run in hole tubing from pipe skate. 4 1 DAILY SUMMARY Aurora Gas, LLC MOQUAWKIE #4 1 02 Nov 2008 Finish running 2 7/8" tubing. Break circulation and drill cement from 3338' to 3399'. 03 Nov 2008 I Casing test failed due to equipement failure. Run in hole with 5-1/2" casing scrapper. Test 5-1/2" casing and pull out of hole. Logging run with Schlumberger tools from 3398' to surface. Run in hole with clean out assembly. 04 Nov 2008 Circulate and condition mixing KCL and oil field salt as needed to maintain weight of 9.4+ ppg. Pull out of hole, strap 2- 7/8" tubing on trip. 05 Nov 2008 Begin 7 runs with Schlumberger perf guns. Pull out of hole. Run in hole with bit and scrapper for clean out run. � I I I I I I I I I IL I I t 5 ' ' DAILY ACTIVITY Aurora Gas, LLC MOQ UAWKIE #4 3_ DAILY ACTIVITY �I_A_D_C_� Time Elapsed Operations Breakdown (hrs) Time 09/23/2008 00:00-24:00 24.00 Mix cement for cellar floor. Weld 4" nipple & install valve. Rig up weight indicator & remote choke. Set up mud dock & mud mans shack. Test koomey bottles. Pick up 1 joint DP & function test ' diverter, knife valve, flowline, pit sensors, H2S & LEL sensors. Note: test witness waived by Jim Regg with AOGCC. Make up bit, bit sub, power swivel & IBOP to drill mousehole. Cut 10 3/4" joint to 8' for mousehole sleeve. Spot vac truck at cellar & drill mouse hole. ' 09/24/2008 00:00-15:30 15.5 Drill mousehole. Note: large rocks & sluffing pea gravel. Used vac Truck to suck fluids from cellar & super sucker to remove gravels. Run fluid back over shakers. Pulled several rocks out 2' in diameter. Back side of cellar box eroding. Made 19' below ground level. 15:30-24:00 8.50 Pick up mousehole & drive down with 6" DC. Use rig pump to wash down mousehole & vac truck to ' return fluids to pits. 09/25/08 00:00-04:00 4.00 Continue Ito pump & drive mousehole down. 04:00-06:00 2.00 Rig down equipment for mousehole project. Rig up for milling conductor. Move & tighten burning line. Transfer fluid from cellar to pits. Lay down used 12 1/4" bit. 06:00-12:00 6.00 Fill in cellar box & around outside of cellar & compact. Load pipe rack with DP & strap DP. 12:00-15:00 3.00 Make up milling assembly & clean out conductor to bottom - 80'. 15:00-17:00 2.00 Make up BHA with 6" DC's. RIH to 80'. Make up power swivel & fill hole & check for leaks. ' 17:00-24:00 7.00 Drill 12 1/4" hole from 80' to 124'. Note: running lightweight on bit to maintain straight hole. 09/26/2008 00:00-05:00 5.00 Drill 12 1/4" hole from 114' to 178' with 6" DC's. ' 05:00-07:30 2.50 Stand back power swivel & POOH. Lay down 6" DC's. 07:30-21:00 13.50 Set mud pump #2 & diesel tank. Fabricate new suction line for #2 mud pump. Pick up 8" BHA while fabricating new suction line. RIH to 140'. Tag fill. Pick up & work on #2 mud pump. 21:00-24:00 3.00 Wash back to bottom from 140' to 178'. ' 09/27/2008 00:00-01:00 1.00 Wash fill from hole & circ hole clean. 01:00-24:00 23.00 Drill 12 1/4" hole from 178' to 460'. Spot wireline unit hang sheaves load rack with 9 5/8" casing & drift ' 09/28/2008 same. 00:00-02:00 2.00 Drill 12 1/4" hole from 460' to 495'. 02:00-04:00 2.00 Hydraulic power swivel unit down - replace actuator. 04:00-05:00 1.00 Drill 12 1/4" hole from 495' to 524'. ' 05:00-05:30 0.50 Deviation survey 0°. 05:30-20:30 15.00 Drill 12 1/4" hole from 524' to 868'. Drift & strap 9 5/8" casing. Rig up casing power unit. 20:30-21:00 0.50 Circ hole clean. 21:00-21:30 0.50 Drop survey 0.75°. 21:30-22:00 0.50 Rig up floor & stand back power swivel. 22:00-24:00 2.00 Start short trip, pull 2 stands & well kicked at 22:30 hrs stab safety valve, closed bag & opened diverter. Rig up to pump down DP. Clear all nonessential personnel from location, block entrance & weight up mud system. ' 09/29/2008 00:00-01:30 1.50 Continue to weight up mud to 10.3 ppg. 01:30-02:00 0.50 Pump on well at 14 bpm in attempt to kill. 02:00-18:00 16.00 Build volume & weight up pits to 13.0 ppg use vac trucks to store 100 bbls mud & build 270 bbls mud in pits. Clean up location. ' 18:00-18:30 0.50 Hold PJSM & discuss responsibilities & duties during kill operations. 18:30-21:00 2.50 Fill trip tank with 13.0 ppg mud, bring pumps up slowly & fill pipe. Bring rate up to 14 bpm & pump 70 bbls. Note: had trouble with #1 pump, therefore pumped through bleeder & continued kill operations. Bubbles were observed in cellar - no returns or losses in cellar. Got 10.5 ppg mud at vent line, ' therefore opened bag & took returns back to pits. Circ out gas & cuttings until 13.0 ppg mud weight was achieved - pit volume of 179 bbls. 21:00-24:00 3.50 Break down 2 stands to singles & pick up power swivel. Ream back to bottom & circ gas out between connections. ' 09/30/2008 00:00-02:00 2.00 Continue to ream & circ to bottom. Wipe tight spots. 02:00-03:30 1.50 Circ on bottom & clean up pad. 03:30-04:00 0.50 Stand back power swivel & rig up floor. 04:00-06:30 2.50 POOH (wiper run) from 868' to 186'- pull slow & watch for swab. ' DAILY ACTIVITYI.A.D.C. i ) Aurora Gas, LLC MOQUAWxIE #4 Time Elapsed Operations Breakdown (hrs) Time 06:30-07:30 1.00 RIH. 07:30-09:00 1.50 Pick up power swivel & circ hole clean. ' 09:00-14:00 5.00 POOH. Lay down BHA & clear floor. 14:00-15:30 1.50 Rig up GBR. Hold PJSM. 15:30-19:30 4.00 Run 855' of 9 5/8" 36 # casing & rig down GBR. 19:30-22:30 22:30-24:00 3.00 1.50 Circ with rig pumps & clear equip. Hold PJSM with BJ & crew - wait on Tyonek water truck for 1.5 hrs. 10/01/2008 00:00-00:30 0.50 Take on water from Tyonek Vac truck. ' 00:30-01:00 0.50 Pump 13.0 ppg spacer swap hose to BJ. Pres test lines - hose leaked. Changed hose & pres test to 3000 psi. 01:00-03:00 2.00 Pump cement & displace with mud - 5 bbls cement to surf. Note: plug did not bump but floats held. 03:00-05:00 2.00 Clean up rig floor lay down hoses, drain & rinse diverter. 05:00-12:00 12:00-13:00 7.00 1.00 Work on mud pumps, clear pad of 8" tools & GBR equip. All hands on pad take drug test. 13:00-21:30 8.50 Nipple down diverter system & clean same. Make rough cut on 9 5/8" casing. 21:30-24:00 2.50 Make final cut on casing & preheat for weld procedure. 10/02/2008 00:00-04:00 4.00 Continue to preheat wellhead & weld same. 04:00-10:00 6.00 Insulate & let weld cool. Gather BOP equipment. 10:00-12:00 2.00 Test wellhead to 1,600 psi for 15 min & change HCR's. ' 12:00-24:00 10/03/2008 12.00 Change rams to 3 1/2" & nipple up BOP'S - clean pumps out. 00:00-09:00 9.00 Nipple up BOP's. 09:00-13:00 4.00 Test GOP's. 13:00-15:00 2.00 Rig down power swivel. Lay down test plug & test joint. Install wear ring & fix gas detector on rig floor. 15:00-21:00 6.00 Lay down 2 6-3/4" DC's. Make up 4-3/4" BHA & RIH with 3-1/2" DP. Lay down 5 joints from derrick. Tagged cement at 792'. 21:00-21:30 0.50 Pick up power swivel. 21:30-24:00 2.50 Circ & cut mud weight from 12.8 to 10.5 ppg. 10/04/2008 00:00-03:00 3.00 Continue to circ to lower mud weight tol0.5 ppg. 03:00-08:00 5.00 Drill cement from 792' to 805', drill float collar & cement to 827'. 08:00-11:00 3.00 Having electrical problems with breaker for mud pumps - POOH & change jets from 18's to 15's - RIH to 827' 11:00-12:00 1.00 Rig up & test casing to 1,500 psi for 15 min lost 60 psi. ' 12:00-16:30 16:30-17:00 4.50 0.50 Weld derrick board. Drill cement from 827' to 845'. 17:00-17:30 0.50 Circ bottoms up. 17:30-22:00 4.50 Lay down 1 single & POOH. 22:00-24:00 2.00 PJSM. Rig up Schlumberger & run Temperature & bond logs. 10/05/2008 00:00-01:30 1.50 Rig up & re -run Temperature Logs. 01:30-04:00 2.50 Rig up & run bond log tools. 04:00-07:00 3.00 Rig up & run maps & Temperature logs. ' 07:00-13:00 6.00 Wait on USIT log tools from Kenai (weather hold). 13:00-15:30 2.50 Rig up & run USIT logs. Rig down Schlumberger (lost bow spring). 15:30-22:00 6.50 Wait on junk basket, RTTS & bridge plug (weather hold). Lay down bit, bit sub & float sub. 22:00-24:00 2.00 RIH & wash & ream from 792' to 825'. ' 10/06/2008 00:00-01:00 1.00 Mill cement from 825' to 845'. 01:00-02:30 1.50 Set back power swivel & reverse circ. 02:30-04:30 2.00 POOH SLM. 04:30-07:30 3.00 Lay down junk basket & clean rubber from ports. 07:30-11:00 3.50 RIH. Reverse circ to 846'. POOH. Lay down junk basket - no fish. 11:00-13:30 2.50 Make up EZ Drill packer & RIH to 530'& Set. 13:30-15:30 2.00 Wait on orders for mud weight up (winterize rig). 15:30-17:00 1.50 Weight up 80 bbls from 10.5 to 12.8 ppg & displace 350' casing. 17:00-18:00 1.00 POOH. Lay down running tool. 18:00-0:00 6.00 Hang tarps winterize rig (Rig on stand-by with full crews). Wait on weather to get Cementers to do squeeze. ' 10/07/2008 ' 2 ' DAILY ACTIVITY (I.A.D.C.) Aurora Gas, LLC MOQUAWKIE #4 Time Elapsed Operations Breakdown (hrs) Time 10:30-13:30 00:00-18:30 18.50 Hang tarps winterize rig (Rig on stand-by with full crews). Wait on weather to get Cementers to do 15:30-17:00 1.50 17:00-17:30 squeeze. ' 18:30-20:30 2.00 Finish rigging up Schlumberger. Pick up 2-1/2" PF HSD, 4 SPF, 60° phasing perf gun. RIH & tie in. Perforate from 520' to 525'. POOH - 20 shots fired. Rig down Schlumberger. 20:30-21:00 0.50 Inject 2 bbis mud to verify perfs open - 1.3 bbis/min, 385 psi max, 325 psi at shut down. 21:00-0:00 3.00 Pick up RTTS packer. RIH on 5 stands DC's & continue RIH on DP. Set RTTS at 470'. Finish rigging up BJ. Have PJSM for cement job. 10/08/2008 00:00-03:00 3.00 PJSM on cement squeeze. Pressure test lines to 2,500 psi with BJ - OK. Establish injection at 1, 1.5, 2 & 3 bbis/min=415 psi for a total of 10 bbis pumped - no change on annulus. Mix & pump 82 sx, 21 ' bbl, 14.7 ppg Class G with 2% CaCI + additives, inject at -1.2 bbls/min avg & 300 psi. Cement thick, mix water very hot, switch to displacement. Open reversing valve, reverse out above RTTS at 470'. Lay down 1 joint, reset RTTS at 440', pressure up to 125 psi, held 90 psi for 2 min. Rig down BJ. Cement in place at 03:00. Plan 12 hr WOC. 03:00-13:30 10.50 Continue. winterizing rig while WOC. 13:30-16:30 3.00 Release RTTS. POOH, soft cement in 2nd DC, break circ, run 2 DC back in, circ to clear cement from pipe. POOH. Lay down RTTS. 16:30-0:00 7.50 Rig up Schlumberger. Log 3 passes with Temperature Log - wait 2.5 hrs & 3.0 hr between passes. ' Logs inconclusive. Started last pass about 23:30 hrs. 10/09/2008 00:00-01:00 1.00 Finish running 3`d pass with Temperature Log - logs inconclusive. ' 01:00-02:00 02:00-05:00 1.00 3.00 Rig down Schlumberger wireline. Pick up bit sub & bit. Make up 7-7/8" bit & bit sub. RIH. Make up power swivel. 05:00-06:30 1.50 Tag cement at 452'. Drill soft cement to 510'. Will not wash down, but drills with little to no weight with rotation. 06:30-07:00 0.50 Circ hole clean. 07:00-22:30 15.50 WOC. Continue winterizing rig. ' 22:30-23:00 0.50 Resume drilling soft cement from 510' to 520'. 23:00-24:00 1.00 Shut down to clean fine cement cuttings out of returns ditch in pits. Change screens. 10/1012008 00:00-01:00 1.00 Continue drilling soft cement from 520' to top of EZSV at 528'. Circ hole clean. ' 01:00-02:00 1.00 Stage up to test squeeze perfs. Perfs broke down in test to 260 psi, fell to 180 psi in 10 min. Stage up to establish injection rate. Perfs broke down & started taking more mud at 425 psi & 450 psi. Initial pressure 450 psi fell to 350 psi after injecting 4 bbis at 0.75 bbis/min. Initial shut in pres 180 psi. 02:00-03:30 1.50 Circ hole clean, 50 unit gas spike at bottoms up - circ clear. Rig up to POOH. ' 03:30-05:30 2.00 Blow down & set back power swivel. POOH. 05:30-10:00 4.50 Continue winterizing rig, clear snow around location & rig while planning another squeeze. 10:00-18:00 8.00 Test BOPE to 250 psi/3,000 psi, bag to 250 psi/1,500 psi. Jim Regg, AOGCC waived witnessing test. 18:00-20:00 2.00 Blow down power swivel, manifold & lines. Rig down test equip. 20:00-22:30 2.50 Strap DP. Make up mule shoe, RIH & pick up 17 joints DP. Make up head pin & lines. 22:30-24:00 1.50 Break circ. Tag EZSV 528'. Pick up 1'. Circ & cond mud for squeeze. PJSM. 10/11/2008 ' 00:00-00:30 0.50 00:30-03:00 2.50 �7 0 0 03:00-09:30 6.50 09:30-10:30 1.00 10:30-13:30 3.00 13:30-15:30 2.00 15:30-17:00 1.50 17:00-17:30 0.50 17:30-24:00 6.50 Circ & cond mud, 12.7+ ppg in & out. Mule shoe at 527'. Line up to BJ. Pump 5 bbis water, pres test to 3,000 psi. Mix & pump 75 sx, 15.2 bbls, Class G + 1.1% CaCI + 0.3% CD32, 15.8 to 16.0 ppg. Pump 1.4 bbls water behind. Lay down 8 joints DP, tail at 287', calc top of cement at 331'. Squeeze 2.2 bbl, 0.2 bbis/min, -480 psi, then locked up to 550 psi - 30 min SIP 495 psi. Re -pressure to 536 psi, switch to rig. Cement in place at 02:30. WOC. Continue winterizing rig, cleaning up snow & rig maintenance while monitoring pressure - WOC - 480 psi at 06:00, 345 psi at 09:30. Bleed off pressure. Reverse circ 2 bottoms up. Re-pres to 482 psi. WOC - 416 psi at 13:15. Bleed off pressure. POOH & lay down DP. Set wear ring. Rig up to RIH. Make up bit & drilling assembly. RIH, tag cement at 358'. Circ & cond mud to 12.4 ppg around. Drill out cement from 358' to 420'. Good, firm cement. Note: Calc top of cement with 2 bbis squeezed =-356'. 10/12/2008 00:00-03:30 3.50 Continue drilling cement from 420' to 495'. Last 45' drilled faster, more ratty, with soft spots, had -28 units gas from cuttings. Stop drilling to WOC. 03:30-11:30 8.00 WOC. Continue winterizing rig & rig maintenance. Dump & rebuild some volume for cement contamination. 11:30-12:00 0.50 Grease power swivel & service rig. 12:00-15:30 3.50 Drill 5' of hard cement. Circ bottoms up & verify hard cuttings. Continue drilling hard cement from 500' to 528'- top of EZSV. Circ hole clean. 15:30-16:30 1.00 Blow down & set back power swivel. Rig up test hose. ' DAILY ACTIVITY (I.A.D.C.) Aurora Gas, LLC MOQUAWKIE #4 Time Elapsed Operations Breakdown Mrs) Time 16:30-18:00 1.50 Shut in & stage up to 500 psi to test squeeze perfs, lost 12 psi to 488 psi, in 45 minutes - good test. Bleed off & blow down test line. Rig up to POOH. 18:00-19:30 1.50 POOH. 19:30-0:00 4.50 Strap & caliper tools. Make up 8-1/2" Junk Mill & boot basket. Set wear ring. RIH with milling assembly. ' 10/13/2008 00:00-00:30 0.50 Continue to RIH with 8-1/2" Mill. Pick up power swivel. 00:30-08:30 8.00 Ream out cement skin from 358' to 458'. 08:30-09:30 1.00 Circ bottoms up. Change out wash pipe packing. 09:30-12:00 2.50 Continue reaming out cement from 458' to EZSV at 528'. Circ bottoms up. ' 12:00-12:30 0.50 Shut-in & re -test squeeze perfs to 500 psi for 15 min - OK. 12:30-13:00 0.50 Service rig. 13:00-16:00 3.00 Mill on EZSV from 528' to 529'+. 16:00-17:00 17:00-0:00 1.00 7.00 Pick up off bottom & circ while derrick hand on crown changing out communications antenna. Continue milling on EZSV at 529'+ to 530'. 10/14/2008 00:00-01:30 1.50 Continue milling on EZSV at 530', broke thru & started moving down hole. 01:30-07:30 6.00 Push & ream remains of EZSV down hole, catching on casing collars, from 530' to 837'. ' 07:30-12:00 4.50 Mill on EZSV parts, junk & cement from 837' to 850'. 12:00-13:00 1.00 Circ & weight up mud to 11.5 ppg. Rig up to test casing. 13:00-14:00 1.00 Test 9-5/8" casing to 498 psi, lost 15 psi in 30 min - OK. ' 14:00-00:00 10.00 Continue milling on EZSV parts, junk & cement from 850' to shoe at 854'. Broke thru shoe & wash & ream out 12-1/4" rat hole to 869'. Circ rat hole clean - had 66 units max gas at bottoms up, along with cement chunks, metal & some pieces of coal. 10/15/2008 00:00-01:30 1.50 Drill 5' new hole with mill from 869' to 874'. Last 3' slow. 01:30-02:00 0.50 Circ & cond mud. Shut down & monitor well, static. Blow down kelly hose. 02:00-09:00 7.00 Clean pits. Dump cement contaminated mud. Cond mud, build volume & weight up to 11.5 ppg. Displace hole with mud. Circ & cond mud & hole. 09:00-10:00 1.00 Rig up to POOH. Monitor well, static. ' 10:00-13:00 3.00 POOH. Lay down DP & stand back DC's. Lay down mill & boot basket. 13:00-16:00 3.00 Clean floor. Reset wear ring. Make up 7-7/8" bit & RIH. 16:00-18:00 2.00 Drill 7-7/8" hole from 874' to 889'. Circ & cond mud for FIT/LOT. 18:00-19:30 1.50 Rig up test pump & lines. Perform FIT/LOT, appeared to have leak -off at 14.4 ppg EMW, 137 psi on 11.5 ppg mud. 19:30-21:30 2.00 Drill 7-7/8" hole from 889 to 909' (20' new hole). Circ & cond mud for repeat FIT/LOT. 21:30-22:30 1.00 Retest formation to 210 psi with no leak -off for a 16.2 ppg EMW FIT. Monitor shut-in for 25 min with slow decline to 185 psi. 22:30-23:00 0.50 Wash to bottom. Circ bottoms up. Record slow pump rates. ' 23:00-24 :00 1.00 Drill 7-7/8" hole from 909' to 920'. 10/16/2008 00:00-23:30 23.50 Drill 7-7/8" hole from 909' to 1,386'. Circ out gas spikes & circ bottoms up on connections. At 1,047' had 10' fast drilling break, circ out 702 units max gas. Saw more regular gas spikes below there. ' 1,091' at 306 units, 1,124' at 468 units, 1,190' at 691 units & 1,231' at 567 units. 23:30-00:00 0.50 Circ hole clean. Rig up for survey & short trip. 10/17/2008 00:00-01:30 1.50 Circ &survey, 1-1/4° at 1,350'. Circ bottoms up for short trip. ' 01:30-04:30 3.00 Blow down lines. Set back power swivel. POOH slow to prevent swabbing into shoe to 795'. 04.30-05.30 1.00 RIH. Tag bottom & circ bottoms up with 220 units max trip gas. 05:30-12:00 6.50 Drill 7-7/8" hole from 1,386' to 1510'. Gas peaks: 222 units at 1,419', 178 units at 1,489' & 318 units at 1510'. ' 12:00-12:30 0.50 Service rig &power swivel. 12:30-17:30 5.00 Drill 7-7/8" hole from 1,510' to 1,604'. Gas peaks: 375 units at 1,534', 700 units at 1,541'& 197 units at 1,604'. 17:30-18:30 1.00 Circ & survey (1° at 1572'). Circ 2 bottoms up. 18:30-22:00 3.50 Lay down single. Blow down lines & set back power swivel. POOH into shoe to 824', pull slow & ' work stands to prevent swabbing & get proper hole fill. 22:00-22:30 0.50 Circ 2 bottoms up with minimal gas. Rig up equipment to test choke manifold. 22:30-00:00 1.50 Continue POOH, no swabbing & hole took proper fill. On last stand at midnight. Note: Started testing choke manifold at 23:00 hrs. ' 10/18/2008 00:00-00:30 0.50 POOH, set back last stand & bit. Continue choke manifold test. 00:30-11:00 10.50 Clear rig floor. Pull wear ring. Finish testing choke manifold & lines. Close blinds, open pipe ram ' doors to retrieve test plug o -ring. Set test plug. Test BOPE to 250 psi / 3,000 psi - annular to 250 psi / 1 ' ' DAILY ACTIVITY (I.A.D.C.) Aurora Gas, LLC MOQ UAWKIE #4 Time Elapsed Operations Breakdown (hrs) Time 03:00-04:00 00:00-13:00 13.00 1,500 psi. All good except lower Kelly valve - redressing same. Accumulator capacity test, OK. 13:00-14:30 1.50 Circ bottoms up. Run survey, 2° at 2,644'. Circ bottoms up. Witness of test waived by Jim Regg, AOGCC. Rig down test equipment. ' 11:00-13:30 2.50 Clear rig floor. RIH with Bit & BHA to shoe. Circ once around. 13:30-14:30 1.00 Rig up & re -test rebuilt lower kelly valve to 250 / 3,000 psi - OK. 18:30-19:00 14:30-16:00 1.50 Continue RIH. ' 16:00-17:00 17:00-00:00 1.00 7.00 Wash & ream to bottom. Circ bottoms up with 250 units max trip gas. Drill 7-7/8" hole from 1,604' to 1,700' with 162 units to 218 units max gas. Drill 7-7/8" hole from 3,102' to 3,401'. 10/19/2008 16.50 Drill 7-7/8" hole from 2,676' to 2,916'. ROP slowed to about 10 fph below 2,865'-2,875'. 16:30-17:30 00:00-21:30 21.50 Drill 7-7/8" hole from 1,700' to 2,074'. Max gas peak 473 units at 1758' 0.50 21:30-23:30 2.00 Circ 2 bottoms up. Survey, 2° at 2,074'. Circ bottoms up. Blow down PS POOH. Lay down stabs, float sub & bit. Hole took proper fill. Bit roughly 1/2 worn & 1/16" under 23:30-00:00 0.50 POOH, for short trip. 22:30-24:00 10/20/2008 Pick up 3 more 4-3/4" DC's. Bring in new bit & install nozzles. Fit new crow's foot, old one loose fit ' 00:00-02:00 2.00 POOH slow to 1,575', less swabbing & hole took proper fill. RIH, return volume OK. Wash to bottom & circ bottoms up with minimal gas. 02:00-00:00 22.00 Drill 7-7/8" hole from 2,074' to 2,397'. Max Gas Peak 1,069 units at 2,268'. 0 I I n L I Ll 10/21/2008 0.50 03:00-04:00 00:00-13:00 13.00 Drill 7-7/8" hole from 2,397' to 2,574'. 13:00-14:30 1.50 Circ bottoms up. Run survey, 2° at 2,644'. Circ bottoms up. 14:30-16:00 1.50 Drill 7-7/8" hole from 2,574' to 2,605'. At about 2,576', ROP picked up in sand for rest of joint to 2,605'. 16:00-16:30 0.50 Circ once around. 16:30-18:30 2.00 POOH for short trip to 2050'. RIH. Trip volumes OK. 18:30-19:00 0.50 Circ bottoms up+, -165 units gas at bottoms up. 19:00-00:00 5.00 Drill 7-7/8" hole from 2,604' to 2,676' 10/22/2008 19.50 Drill 7-7/8" hole from 3,102' to 3,401'. 00:00-16:30 16.50 Drill 7-7/8" hole from 2,676' to 2,916'. ROP slowed to about 10 fph below 2,865'-2,875'. 16:30-17:30 1.00 Circ bottoms up. Pick up 30'& run wireline survey - 4-1/4° at 2,885'. 17:30-18:00 0.50 Blow down & set back power swivel. 18:00-22:30 4.50 POOH. Lay down stabs, float sub & bit. Hole took proper fill. Bit roughly 1/2 worn & 1/16" under gauge. 22:30-24:00 1.50 Pick up 3 more 4-3/4" DC's. Bring in new bit & install nozzles. Fit new crow's foot, old one loose fit on survey tool. Prepare to RIH. 10/23/2008 0.50 03:00-04:00 00:00-04:00 4.00 RIH with new bit & BHA #3. Tag up at -2,730'. Pick up & circ bottoms up - had 4,875 units trip gas 05:00-05:30 0.50 peak. Circ gas out. 04:00-09:00 5.00 Ream out under gauge hole from 2,730' to bottom at 2,916'. 09:00-10:00 1.00 Circ bottoms up. Pick up 30'. Repeat wireline survey, 2-1/2° at 2,885'. 10:00-11:30 1.50 Rig down survey. Pump out, lay down 6 joints. Set back power swivel. RIH 3 stands. 11:30-24:00 12.50 Drill 7-7/8" hole from 2,916' to 3,102'. 10/24/2008 00:00-19:30 19.50 Drill 7-7/8" hole from 3,102' to 3,401'. 19:30-20:30 1.00 Circ up samples. Send in mud logs & evaluate same. 20:30-23:00 2.50 Drill 7-7/8" hole from from 3,401' to 3,450'. 23:00-24:00 1.00 Circ up sample. Send in mud logs & evaluate same - called total depth at 3,450'. 10/25/2008 00:00-00:30 0.50 00:30-02:30 2.00 02:30-03:00 0.50 03:00-04:00 1.00 04:00-05:00 1.00 05:00-05:30 0.50 05:30-12:00 6.50 12:00-13:00 1.00 13:00-15:00 2.00 15:00-16:00 1.00 16:00-18:00 2.00 18:00-23:00 5.00 23:00-24:00 1.00 i Rack back power swivel. Short trip 12 stand. Hit tight spots on stands 10 & 11 out at 2,450'- (3 klbs over pull) worked through with no problems. RIH - no tight spots. Mix & pump Hi -Vis sweep. Circ bottoms up. Mix & pump Nut plug sweep. Circ bottoms up. Rig up & take single shot survey at 3,400' - 2°. POOH to shoe with tight spots at 2,040' & 1,900'- 4 klbs over pull. Worked through tight spots with no problems Rig down circ head & blow down circ equipment. Continue POOH with BHA & bit #3. Clean rig floor. Pull wear ring. Rig up to test ROPE, found froze up test pump & lines. Rig up equipment to thaw. Continue to thaw kill line & equipment. Set test plug. Test pipe rams, blind rams, HCR & kill lines to 250 psi low / 3,000' psi high. Test annular to 250 psi low / 1,500 psi high, choke manifold & all valves - all tests good. Performed accumulator test - good. Jim Regg with AOGCC wavied witness of BOPE test. Start BOPE test. Continue to thaw kill line & equipment. Install wear ring, Rig up Schlumberger wireline service for logs. IDAILY ACTIVITY (I.A.D.C.) G 11 Aurora Gas, LLC MOQUAWKIE #4 Time Elapsed Operations Breakdown (hrs) Time 00:00-02:00 2.00 PJSM - Rig up Schlumberger wireline sheave & equipment. Pick up PEX / AITH tools ( run #1 ). 02:00-05:30 3.50 RIH with PEX tools (run #1) with Wireline TD at 3,416'. Log up from 3,416' to 700'. 05:30-12:30 7.00 RIH with DSI tools - (run #2). Wireline TD at 3,420'. Log up from 3,420' to surface. Rig down DSI tools. Pick up CSI tools. 12:30-17:30 5.00 RIH with CSI to 3,400'. Pull up to 3,330', 1 shot fired & tool failed. 17:30-23:00 5.50 POOH with wireline to evaluate tool. Rig down CSI tools. 23:00-24:00 1.00 Rig up CSI tool #2. 10/27/2008 00:00-04:00 4.00 04:00-09:00 5.00 09:00-10:30 1.50 10:30-12:00 1.50 12:00-22:00 10.00 22:00-23:00 1.00 23:00-24:00 1.00 10/28/2008 00:00-04:00 4.00 04:00-04:30 0.50 04:30-07:00 2.50 07:00-10:00 3.00 10:00-10:30 0.50 10:30-13:30 3.00 13:30-15:00 1.50 15:00-16:00 1.00 16:00-21:30 5.50 21:30-22:30 1.00 22:30-24:00 1.50 10/29/2008 00:00-02:00 2.00 02:00-04:00 2.00 04:00-12:00 8.00 ' 12:00-13:00 1.00 13:00-22:00 9.00 22:00-24:00 2.00 10/30/2008 00:00-00:30 0.50 00:30-05:30 5.00 ' 05:30-08:30 3.00 08:30-12:00 3.50 12:00-24:00 12.00 1 Pick up & RIH with Schlumberger wireline - CST run #2. CST core samples from 3,330' to 1,063'. POOH with wireline & CST tools - Rig down & Ld CST tools (19 of 21 shots fired - 18 core samples recovered). Pick up XPT tools - RIH with wireline. Correlate - 21 pressure stations total from 3,335' to 1,082' (10 good tests with 6 dry & 5 lost seals). POOH with wireline. Lay down XPT tools - Rig down Schlumberger wireline sheave & equipment. RIH with Bit - BHA #3 to 9 5/8" casing. Shoe. Attempt to circ - no go due to froze up line in pump room. Thawed line & trouble shot electrical problem in pump room. Circ bottoms up at shoe. Continue RIH to 3,390' with no problems. Make up power swivel & wash last 2 joints to bottom. Circ 4 bottoms up. Note: lots of cuttings noted at shaker. Flow check - blow down & stand back swivel. Short trip 13 stands to 2,636' with minor tight spots. RIH to bottom. Circ 3 bottoms up. Stand back power swivel & flow check well. POOH - lay down 3 1/2" DP. Tioga heater went down - rig up back up heat for rig floor. Continue to lay down 3 1/2" DP. Lay down BHA. Trouble shoot Tioga heater for rig floor. Clean pit #5 & mixed up fresh 50 bbls KCL brine water. Clear rig floor - change 3 1/2" pipe rams to 5 1/2" casing. Function test 5 1/2" casing. Rams - rams not closing properly. Opened door & repositioned ram. Pick up test joint & pull wear ring. Test casing rams & door seals to 250 low / 1,500 psi high for 5 min. ea. Record on chart pressures. Mobilize GBR tools & Rig up to run 5 1/2" casing. Run 80 jts / 15.5# / BTC / J-55 casing. to 3,427' (No tight hole encountered). PJSM - Rig up stand pipe & service lines to BJ cmters. Continue to rig up Cementers - PJSM with crew. Test lines to 3,500 psi from 5 min. Mix & pump 20 bbis Bond seal spacer at 11.0 ppg. Mix & pump 41 bbls Class "G" lead cement at 13.5 ppg. Mix & pump 105 bbls Class "G" tail cmt at 15.8 ppg Displace with 9.3 ppg KCL water - pumped calculated strokes + 1/2 vol shoe track (80.3 bbis). Plug did not bump - bleed press. Floats held (approx 40 bbis good lead cement returns). Note: Full returns throughout job Flush stack, rinse out out flowline & clean up cellar. Open doors on stack & flush out same. Change out rams to 2 7/8". Wait on cement to cure. Clean mud pits & service equipment. Prepare to set slips. Rig down cement head & continue to clean mud pits. 10/31/2008 00:00-01:00 1.00 Continue to nipple down BOPS. 01:00-02:00 1.00 Broke hydraulic on stack - repair. Clean up cellar. 02:00-06:00 4.00 Set slips. Pull 49 klbs. Repair cut off saw. 06:00-14:00 8.00 Pick up stack. Cut 5-1/2" casing with cut off saw. Remove spool & dress same. Install tubing spool & double stud adapter & test to 2400 psi for 10 min - good test. 14:00-20:00 6.00 Dress BOP. Turn stack to adjust for kill line & sub leg - took several attempts to configure. 20:00-22:00 2.00 Make up BOP, kill line & flowline. Continue cleaning mud pits. Mobilize test equipment to rig floor. Rig up to test BOPE. 22:00-24:00 2.00 Pick up test joint & install test plug. Test BOPE. 11/01/2008 00:00-03:30 3.50 Continue BOPE test - 2 7/8" pipe rams, blind rams, HCR & Kill. Test choke manifold & all valves to 250 psi low 13,000 psi high. Test Annular preventer to 250 psi low / 3,000 psi high & record on chart - n i it DAILY ACTIVITY (I.A.D.C.) Aurora Gas, LLC MOQUAWKIE #4 Time Elapsed Operations Breakdown (hrs) Time no failures. Performed Accumulator test - all good. Note: Jim Regg with AOGCC waived witness of BOPE test. 03:30-14:30 11.00 Clear rig floor - Pick up tubing equipment. Power tongs not working. Change out tongs. Continue to pick up, strap & drift 2 7/8" tubing. Continue to thaw pump room suctions & mud pit lines. 14:30-19:30 5.00 Pick up power swivel & drill 6' ice plug. 19:30-24:00 4.50 Pick up & RIH with 2 7/8" tubing from pipe skate (42 joints). 11/02/2008 00:00-08:00 8.00 Strap & drift 2 7/8", 6.5#, J-55 tubing & RIH with same. Change out suction rubber in pit #4. Thaw lines in mud pits & continue to RIH with tubing. Change out 4 bad collars on 2 7/8". Tagged float collar at 3,337'/ 10' in on joint 108. Line up mud pump. 08:00-11:30 3.50 Haul water to mix up 9.4+ ppg KCL water. Thaw lines in mud pits. Rig up filtration equipment. Line up hoses for centrifuge. Rig up heaters to thaw out mud pump suctions. 11:30-14:30 3.00 Pick up kelly & attempt to circ - no good due to frozen flowline. Thaw out flowline & continue preparing KCL fluid in pits. 14:30-24:00 9.50 Break circ & drill float collar at 3,337'. Drill cement from 3,338' - 3,399'. Work on pits & prepare to POOH. 11/03/2008 00:00-01:00 1.00 Attempt to test casing - equipment failure. 01:00-02:00 1.00 Blow down power swivel. Rig up line to circ back to mud pits. 02:00-05:00 3.00 Strap out of hole. Break off bit & bit sub. 05:00-08:00 3.00 Pick up 5 1/2" casing scapper. RIH. 08:00-12:00 4.00 Tagged bottom at 3,399'. Rig up filtration equipment to filter brine. Rig up to test 51/2" casing. 12:00-13:00 1.00 Test 5 1/2" casing to 2,000 psi, bled off 75 psi & stabilized at 1,925 psi - held press for 20 min for a 08:30-10:30 2.00 good test. Note: chart recorder failed during test, but test witnessed by ToolPush, Driller & CoMan. 10:30-12:00 1.50 Bled off press & blew down test equipment. 13:00-16:00 3.00 POOH with clean out assembly. 16:00-17:30 1.50 Rig up Schlumberger wireline equipment. 17:30-21:30 4.00 RIH with Schlumerger wireline - TD 3,398'. Run Cement Bond Log from 3,398' to surf. 21:30-22:30 1.00 Rig down Schlumberger logging tools. 22:30-24:00 1.50 Pick up clean out assembly. RIH. Note: Found error in pipe tally - corrected (BHA / 109 joints 2-7/8" 21:30-24:00 2.50 tubing + 10' pup = 3,399'. 11/04/2008 00:00-01:00 1.00 Continue to RIH & tag bottom at 3,399'. 01:00-03:30 2.50 Repair leaks in hose to centrifuge & filter unit. 03:30-17:00 13.50 Circ & cond brine at 50 spm 1400 psi, Filter & centrifuge brine to 5 micros. Mix! KCL & oil field salt as needed to maintain weight at 9.4+ ppg. Change out liners in #2 pump to 4 1/2". Mobilize Schlumberger tools & lubricate beaver slide. 17:00-21:30 4.50 POOH - strap 2 7/8" tubing on trip. 21:30-24:00 2.50 Clear rig floor. Nipple down riser & nipple up shooting flange. Note: Took a lot longer to clean the brine up than was expected. Note: Total KCL usage from brine = 364 sx. 11/05/2008 00:00-02:30 2.50 Continue to nipple up shooting flange. PJSM with Schlumberger. 02:30-06:00 3.50 Pick up lubricator, BOPS from beaver slide & install on shooting Flange. Pick up #1 run of perf Guns (10'). RIH with Schlumberger wirleline to 300'. Test lubricator to 1,500 psi & held from 10 min -good test. Bled offpress. Rig up to take returns to trip tank & circ through kill line. 06:00-08:30 2.50 RIH to bottom, pick up & correlate guns on depth with PEX log. Perf run #1 - 15' gun - 6 spf with 60° phasing shot at 3,322' to 3,337'- monitor fluid level -static. Note: All runs consistent procedure: 08:30-10:30 2.00 Run #2 - 10' Guns - shot at 3306' to 3,316' (static). 10:30-12:00 1.50 Run #3 - 05' Guns - shot at 2874' to 2,879' (static). 12:00-14:00 2.00 Run #4 - 20' Guns - shot at 2732' to 2,752' (static). 14:00-16:30 2.50 Run #5 - 20' Guns - shot at 2702' to 2,722' (Took 1 bbl). 16:30-18:30 2.00 Run #6 - 10' Guns - shot at 2637' to 2,647' (Took 1 bbl). 18:30-21:30 3.00 Run #7 - 15' Guns - shot at 2600' to 2,615' (Took 1.5 bbl). POOH. Lay down lubricator, sheaves & shooting flange. 21:30-24:00 2.50 Make up riser, bit & scrapper. RIH for cleanout. HALLIBURTON Customer: Aurora Gas, LLC Report#: 2 Well: Moquawkie 4 Date: 9/27/2008 Mpor -y Or1111n53 S®rvic®= Area: Tyonek 06:00 Depth: 238' Lease: Moquawkie Progress 24 hrs: 60' Rig: AWS-1 Rig Activity: Drilling Mudlogger's Morning Report Job No.: AK-AM-0006174381 Report For: Coine/Newton Daily Cost: $3,725 Cumulative Cost: $33,900 ROP&Gas: Current 24 hr Avg 24 hr Max Max @ ft Pump & Flow Data: R.O.P. ft/hr 26.0 15.5 47.0 185 Flow in m 320 1 SPP(Psi) 390 Gas units 12 12 28 182 Fow in s m 113 Gallons/stroke 2.8 Mud Data: Density (ppg) Viscosity filtrate PV YP Chlorides FC PH Solids Depth in out (sec/qt) (cc130 min) I cP (Ib/100ft2) (mg/1) 1(1/32") % 9.0 9.0 73 7 11 23 35,000 1 9.0 1.1 BIT DATA: Type Size TFA Hours Depth in / out Footage WOB RPM Condition Bit # 1 Sec XCL1 N 12.25 0.75 13.7 82 156 1-8 60 Last Bit # Lithology (%): Sd Sst Silt Siltst Cly Clyst Sh Lst Coal Tuff tr 80 20 Connection Gas and Mud Cut Trip gas N/A ft N/A units N/A ppg 178' ft 66 units 9.0 ppg ftunits ppg 24 hour Gas Breakdown Gas (units) Chromatograph (ppm) Depth Max Average C1 C2 C3 C4 Tot C5 Tot Type 182' to 182' 28 23 2942 0 0 0 0 GP 207' to 207' 27 20 3099 0 0 0 0 GP 207 to 237 22 12 2474 0 0 0 0 BG to to to to to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - pumps off gas 24 hr Recap: UD pilot hole BHA. M/U & P/U Sperry BHA 1. TIH to 179', circulate out cave-in cuttings from 155' to 179'. Midnight depth of 165' TIH. Tag bottom 179' at 01:00. Drill 12 1/4" hole to 238'. Note: Samples very poor - appears we are drilling silty clay/claystone with abundant thin coal stringers. Very small gas peaks associated with coal stringers ranging from 15-28 units over a background of 12 units. Logging Engineer: Wayne Hermanson/Danny Kane 10000 units= 100% Gas In Air Customer: Aurora Gas, LLC Report #: 3 ll- ^LLrlsui _rC3M Well: Moquawkie 4 Date: 9/28/2008 Mp®rry Grilling s..-%fl=WM Area: Tyonek 06:00 Depth: 528' Lease: Moquawkie Progress 24 hrs: 290' Rig: AWS -1 Rig Activity: Drilling Mudlogger's Morning Report Job No.: AK -AM -0006174381 Report For: Coine/Newton Daily Cost: $3,725 Cumulative Cost: $37,625 ROP&Gas: Current 24 hr Avg 24 hr Max Max @ ft Pump & Flow Data: SEEM R.O.P. ft/hr 49.0 16.1 146.0 324 Flow in m 450 1 SPP(Psi) 818 Gas units 33 32 3250 345 Fow in s m 160 Gallons/stroke 2.8 Mud Data: Density (ppg) Viscosity filtrate PV YP Chlorides FC PH Solids Depth in out (sec/qt) (cc/30 min) cP (Ib/100ft2) (mg/1) (1/32") % 542 9.2 9.2 52 6 9 21 30 1 9.0 0.8 BIT DATA: Type Size TFA Hours Depth in / out Footage WOB RPM Condition Bit # 1 Sec XCL1 N 12.25 0.75 31.7 82 446' 1-8 70 Last Bit # Lithology (%): Sd Sst Silt Siltst Cly Clyst Sh Lst Coal Tuff 35 20 35 10 Connection Gas and Mud Cut Trip gas N/A ft N/A units N/A ppg ft units ppg ft units ppg 24 hour Gas Breakdown Gas (units) Chromatograph (ppm) Depth Max Average C1 C2 C3 C4 Tot C5 Tot Type 238' to 343' 82 18 9182 0 0 0 0 BG 344' to 344' 3250 241 35128 0 0 0 0 GP 345' to 413' 114 31 10788 0 0 0 0 BG 414' to 414' 439 362 57055 0 0 0 0 GP 415' to 497' 118 39 12178 0 0 0 0 BG 492' to 492' 118 107 14099 0 0 0 0 CG 492' to 528' 131 35 12326 0 0 0 0 BG to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - pumps off gas 24 hr Recap: Continue drilling 12 1/4" hole to 451' as of 00:00. Drill 12 1/4" hole from 451' to 497'. Repair Power Swivel. Drill 12 1/4" hole from 497' to 528'. Highest gas peak 3250/18 units at 344' possibly in a coal. Various small gas peaks associated with coal stringers ranging from 100-500 units over a background of 25 units. Logging Engineer: Wayne Hermanson/Danny Kane " 10000 units= 100% Gas In Air r� Logging Engineer: Wayne Hermanson/Danny Kane " 10000 units= 100% Gas In Air Customer: Aurora Gas, LLC Report #: 4 HALLIBURTON Well: Moquawkie 4 Date: 9/29/2008 Sp®rrr-V Mr-filing Sarvica� Area: Tyonek 06:00 Depth: 867' Lease: Moquawkie Progress 24 hrs: 339' Rig: AWS-1 Rig Activity: Well Control Mudlogger's Morning Report Job No.: AK-AM-0006174381 Report For: Coine/Newton Daily Cost: $3,725 Cumulative Cost: $45,075 ROP&Gas: Current 24 hr Avg 24 hr Max Max @ ft Pump & FIOw Data: R.O.P. ft/hr 29.7 285.0 750 Flow in m SPP (psi) Gas units 40 423 751 Fow in (spm) Gallons/stroke 2.8 Mud Data: Density (ppg) Viscosity filtrate PV YP Chlorides FC PH Solids Depth in out (sec/qt) (cc/30 min) cP (Ib/100ft2) (m /I) (1/32") 867 9.7 9.7 56 7 13 20 1 42,000 1 8.0 1.1 BIT DATA: Type Size TFA Hours Depth in / out Footage WOB RPM Condition Bit # 1 Sec XCL1 N 12.25 0.75 43.1 82 867 785 1-8 80 Last Bit # Lithology (%): Sd Sst Silt Siltst Cly Clyst Sh Lst Coal Tuff 10 10 50 30 Connection Gas and Mud Cut Trip gas see note ft units ppg ft units ppg ft units ppg 24 hour Gas Breakdown Gas (units) Chromatograph (ppm) Depth Max Average C1 C2 C3 C4 Tot C5 Tot Type 570 to 575 252 32 32737 0 0 0 0 GP 590 to 596 168 36 19210 0 0 0 0 GP 624 to 627 135 36 15571 0 0 0 0 GP 640 to 642 116 29 11813 0 0 0 0 GP 653 to 656 115 20 14574 0 0 0 0 GP 676 to 679 147 22 19371 0 0 0 0 GP 683 to 685 109 39 13240 0 0 0 0 GP 722 to 734 119 22 12789 0 0 0 0 GP 747 to 758 423 64 56942 0 0 0 0 GP 760 to 771 179 73 23950 0 0 0 0 GP 777 to 783 162 40 22589 0 0 0 0 GP 791 to 810 255 56 29650 0 0 0 0 GP 844 to 848 188 43 23546 0 0 0 0 GP 854 to 862 246 50 33756 0 0 0 0 GP 864 to 867 214 62 29070 0 0 0 0 WTG 867 to 867 9492 9437 502024 0 0 0 0 Blowout Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - pumps off gas 24 hr Recap: Drilled f/528' to surface hole TD of 867'. Ran slickline survey. Start short trip. Took a kick. Shut in well and venting through diverter. Maximum gas of 9492 units. Attempted to kill twice with 9.2+ ppg mud and 10.2 ppg mud. Building kill mud and awaiting kill sheet from Wild Well Control. Note: connection gas ranged from 30 to 205 units over BG of 10-30 units - 432 units at 803' occurred with incr BG. Various gas peaks associated with coal ranging from 100-425 units over a background of 30-60 units. Gas peaks of 170 U at 845', 240 U at 855', and 190 U at 866' were associated with coal stringers verified by ^-50-70% coal coming across the shakers at those lag depths. Well most likely kicked from potential coal seam at 750' that had a GP of 423 U over BG of 64 U. Logging Engineer: Wayne Hermanson/Danny Kane " 10000 units= 100% Gas In Air HALLIBURTON Customer: Aurora Gas, LLC Report #: Well: Moquawkie 4 Date: 5 9/30/2008 Sp®rrry Or-llling Area: Tyonek 06:00 Depth: 867' Lease: Moquawkie Progress 24 hrs: 0' Rig: AWS -1 Rig Activity: Short Trip Mudlogger's Morning Report Job No.: AK -AM -0006174381 Report For: Coine/Newton Daily Cost: $3,725 Cumulative Cost: $48,800 ROP&Gas: Current 24 hr Avg 24 hr Max Max @ ft Pump & Flow Data: R.O.P. ft/hr N/A N/A N/A Flow in m 0 SPP(psi) 0 Gas units 156 3931 734 Fow in (spm) 0 Gallons/stroke 2.8 Mud Data: Density (ppg) Viscosity filtrate PV YP Chlorides FC PH Solids Depth in out (sec/qt) (cc/30 min) cP (Ib/100ft2) (m /1) (1/32") % 867 12.8 12.8 42 11 17 19 27,000 1 9.0 19.0 BIT DATA: Type Size TFA Hours Depth in / out Footage WOB RPM Condition Bit # 1 Sec XCL1 N 1 12.25 0.75 43.1 82 867 785 1-8 80 Last Bit # ME Lithology (%): Sd Sst Silt I iltst I Cly Clyst Sh Lst Coal Tuff 10I 10 50 30 Connection Gas and Mud Cut Trip gas ft units ppg ft units ppg ft units ppg 24 hour Gas Breakdown Gas (units) Chromatograph (ppm) Bit Depth & Time Max Average C1 C2 C3 C4 Tot C5 Tot Type 734' at 19:16 1686 1683 196961 0 0 0 0 GP 734' at 19:23 3931 3929 386887 0 0 0 0 GP 771' at 23:30 439 439 59794 0 0 0 0 GP 837' at 0:58 455 455 61519 0 0 0 0 GP 832' at 1:28 511 511 51997 0 0 0 0 GP at at to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - pumps off gas 24 hr Recap: Weighted up mud to 13.0 ppg. Kill well by 20:30 Max gas while killing well 3931 units. Monitor well & ream to bottom. Circulate, then work pipe in attempt to induce swabbing. Circulate mud with BG of 30-45 U. Short trip from 867' to 186'. Gas peaks of of 1686 and 39310 units observed while killing the well - see gas breakdown and time above. Logging Engineer: Wayne Hermanson/Danny Kane * 10000 units= 100% Gas In Air I Customer: Aurora Gas, LLC Report #: 7 HALLIBURTON Well: Moquawkie 4 Date: 10/2/2008 Sp®rry Oriiiing S®rvio®� Area: Tyonek 06:00 Depth: 867' Lease: Moquawkie Progress 24 hrs: 0' Rig: AWS-1 Rig Activity: N/U BOP Mudlogger's Morning Report Job No.: AK-AM-0006174381 Report For: Coine/Newton Daily Cost: $3,725 Cumulative Cost: $56,250 ROP&Gas: Current 24 hr Avg 24 hr Max Max @ ft Data: R.O.P. ft/hr N/A N/A N/A N/A :FI(ow 7FIowin0 SPP si 0 Gas units N/A N/A N/A N/A 0 Gallons/stroke 2.8 Mud Data: Density (ppg) Viscosity filtrate PV YP Chlorides FC PH Solids Depth in out (sec/qt) (cc/30 min) cP (Ib/100ftz) (m /1) (1/32") % 867 12.8 12.8 44 10.5 44 19 23,000 2 10.0 16.3 kBMTDATA: Type Size TFA Hours Depth in / out Footage WOB RPM Condition Bit # 1 Sec XCL1 N 1 12.25 0.75 43.1 82 867 785 1-8 80 Last Bit # Lithology (%): Sd Sst Silt Siltst Cly Clyst Sh Lst Coal Tuff 10 10 50 30 Connection Gas and Mud Cut Wiper Trip gas ft units ppg ft units ppg ft units ppg 24 hour Gas Breakdown Gas (units) Chromatograph (ppm) Bit Depth & Time Max Average C1 C2 C3 C4 Tot C5 Tot Type at at at at at at at to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - pumps off gas 24 hr Recap: R/D BJ Services. Wait on cement. Nipple down diverter. Cut casing & weld on wellhead flange. Clean up rig site & wait on Wellhead to cool. 10000 units = 100% Gas In Air Logging Engineer: Wayne Hermanson/Danny Kane 'i HALLIBIJRTON Customer: Aurora Gas, LLC Report #: 9 Well: Moquawkie 4 Date: 10/4/2008 Sp®r-r-y Off-1111ng Sarvicam Area: Tyonek 06:00 Depth: 867' Lease: Moquawkie Progress 24 hrs: 0' Rig: AWS-1 Rig Activity: Drill Cmt @ 808' Mudlogger's Morning Report Job No.: AK-AM-0006174381 Report For: Coine/Newton Daily Cost: $3,725 Cumulative Cost: $63,700 ROP&Gas: Current 24 hr Avg 24 hr Max Max @ ft Pump & Flow Data: R.O.P. ft/hr N/A N/A N/A N/A Flow in m 262 SPP(psi) 555 Gas units N/A N/A N/A N/A Fow in s m 95 Gallons/stroke 2.8 Mud Data: Density (ppg) Viscosity filtrate PV YP Chlorides FC PH Solids Depth in out (sec/qt) (cc/30 min) I cP (V100ft2) (m /1) (1/32") % 867 12.8 12.8 47 11.0 19 23 23,000 2 10.0 16.3 BIT DATA: Type Size TFA Hours Depth in / out Footage WOB RPM Condition Bit # 2 Sec QHC1 S 7.88 0.52 Last Bit # 1 Sec XCL1 N 1 12.25 0.75 43.1 82 867 785 1-8 80 Lithology (%): Sd Sst Silt I Siltst Cly Clyst 1 Sh Lst Coal I Tuff 10 10 1 50 30 Connection Gas and Mud Cut Wiper Trip gas ft units ppg ft units ppg ft units ppg 24 hour Gas Breakdown Gas (units) Chromatograph (ppm) Bit Depth & Time Max Average C1 C2 C3 C4 Tot C5 Tot Type at at at at at at at to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - pumps off gas 24 hr Recap: Finish N/U BOP & BOP test. P/U power swivel & R/B. UD test plug & test joint. UD 6 3/4" DC, clear rig floor of 6 3/4" tools, rack back 4 3/4" DC and RIH w/ BHA #2. Tag cement at 792'. Start drilling cement, drill float collar at 805'. Drill cement to 808' at report time. Note: mud data from yesterdays report. Logging Engineer: Wayne Hermanson/Danny Kane 10000 units= 100% Gas In Air [R:OP&Gas: WUFRTON Customer: Aurora Gas, LLC Report #: 10 Well: Moquawkie 4 Date: 10/5/2008 Mr Ming S6fViC6= Area: Tyonek 06:00 Depth: 867' Lease: Moquawkie Progress 24 hrs: 0' Rig: AWS -1 Rig Activity: Wireline Logs gees Morning Report Job No.: AK -AM -0006174381 Report For: Coine/Newton Daily Cost: $3,725 Cumulative Cost: $67,425 Current 24 hr Avg 24 hr Max Max @ ft Pump & Flow Data: R.O.P. ft/hr N/A N/A N/A N/A Flow in m SPP(psi) Gas units N/A N/A N/A N/A Fow in s m Gallons/stroke 2.8 Mud Data: Density (ppg) Viscosity filtrate PV YP Chlorides FC PH Solids Depth in out (sec/qt) (cc/30 min) cP (Ib/100ft2) (m /1) (1/32") % 867 10.5 10.5 42 11 15 28,000 2 9.5 7.8 BIT DATA: Type Size TFA Hours Depth in / out Footage WOB RPM Condition Bit # 2 Sec QHC1 S 7.88 0.52 Last Bit # 1 Sec XCL1 N 12.25 0.75 43.1 82 867 785 1-8 80 Lithology (%): Sd Sst Silt Siltst Cly Clyst 1 Sh Lst Coal Tuff 10 10 50 30 Connection Gas and Mud Cut Wiper Trip gas ft units ppg ft units ppg ft units ppg 24 hour Gas Breakdown Gas (units) Chromatograph (ppm) Bit Depth & Time Max Average C1 C2 C3 C4 Tot C5 Tot Type at at at at at at at to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - pumps off gas 24 hr Recap: Drill cement to 820'. POOH to replace jets on bit. TIH. Drill cement to 827'. Test casing to 1500 psi for 15 min. Weld & repair derrick boards (fingers). Drill cement from 827' to 845'. Circ bottoms up. POOH. Rig up Schlumberger Run cement bond logs with Schlumberger. Note: Gas perculating up between conductor & casing--R/U Sperry Gas Detector to read ambient air from cellar. max gas 150 units = 1.5% gas in air Logging Engineer: Wayne Hermanson/Danny Kane 10000 units= 100% Gas In Air HALLIBURTON Customer: Aurora Gas, LLC Report #: 11 Well: Moquawkie 4 Date: 10/6/2008 Sperry Drilling Area: Tyonek 06:00 Depth: 867' Lease: Moquawkie Progress 24 hrs: 0' Rig: AWS -1 Rig Activity: Work on junk bask Mudlogger's Morning Report Job No.: AK -AM -0006174381 Report For: Coine/Newton Daily Cost: $3,725 Cumulative Cost: $71,150 ROP&Gas: Current 24 hr Avg 24 hr Max Max @ ft Pump & Flow Data: R.O.P. ft/hr N/A N/A N/A N/A Flow in m SPP(psi) Gas units N/A N/A N/A N/A Fow in (spm) Gallons/stroke 2.8 Mud Data: Density (ppg) Viscosity filtrate PV YP Chlorides FC PH Solids Depth in out (sec/qt) (cc/30 min) cP (Ib/100ft) (mg/1) (1/32") % 867 10.5 10.5 41 4.2 9 13 28,000 2 9.5 7.8 BIT DATA: Type Size TFA Hours Depth in / out Footage WOB RPM Condition Bit # 2 Sec QHC1 S 7.88 10.52 Last Bit # 1 Sec XCL1 N 12.25 0.75 43.1 82 867 785 1-8 80 Lithology (%): Sd Sst Silt Siltst Cly ClystSh Lst Coal Tuff 10 10 50 30 Connection Gas and Mud Cut Wiper Trip gas ft units ppg ft units ppg ft units ppg 24 hour Gas Breakdown Gas (units) Chromatograph (ppm) Bit Depth & Time Max Average C1 C2 C3 C4 Tot C5 Tot Type at at at at at at at to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - pumps off gas 24 hr Recap: Finish Schlumberger CBL & temp logging. Wait on USIT tool, R/U, run USIT. Lost USIT centralizer downhole while R/D Schlumberger. Wait on junk basket, M/U fishing assembly, RIH to 792'& start milling cement for fishing tool from 792' to 845'. POOH to surface, Lay down junk basket. No junk in basket. Clean rubber out of junk basket. Note: Gas perculating up between conductor & casing - monitor with Sperry gas detector 2-4 units with occ up to 50 u. Logging Engineer: Wayne Hermanson/Danny Kane 10000 units= 100% Gas In Air HAI_ILIBURTOIV Customer: Aurora Gas, LLC Report #: 12 Well: Moquawkie 4 Date: 10/7/2008 parry drilling Sarvic®� Area: Tyonek 06:00 Depth: 867' Lease: Moquawkie Progress 24 hrs: 0' Rig: AWS-1 Rig Activity: Standby for BJ Ser. Mudlogger's Morning Report Job No.: AK-AM-0006174381 Report For: Coine/Newton Daily Cost: $3,725 Cumulative Cost: $74,875 ROP&Gas: Current 24 hr Avg 24 hr Max Max @ ft Pump & Flow Data: R.O.P. ft/hr N/A N/A N/A N/A Flow in m SPP(psi) Gas units N/A N/A N/A N/A Fow in (spm) Gallons/stroke 2.8 Mud Data: Density (ppg) Viscosity filtrate PV YP Chlorides FC PH Solids Depth in out (sec/qt) (cc/30 min) I cP (Ib/100ft2) (mg/1) 1(1/32") % 867 12.8 12.8 44 9.4 16 23 24,000 2 9.5 17.3 BIT DATA: Type Size TFA Hours Depth in / out Footage WOB RPM Condition Bit # 2 Sec QHC1 S 7.88 0.52 Last Bit # 1 Sec XCL1 N 12.25 0.75 43.1 82 867 785 1-8 80 __—EMEMMMMMEMEM NOME Lithology (%): Sd Sst Silt Siltst Cly Clyst Sh Lst Coal Tuff 10 10 50 30 Connection Gas and Mud Cut Wiper Trip gas ft units ppg ft units ppg ft units ppg 24 hour Gas Breakdown Gas (units) Chromatograph (ppm) Bit Depth & Time Max Average C1 C2 C3 C4 Tot C5 Tot Type at at at at at at at to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - pumps off gas 24 hr Recap: TIH w/ junk basket for fishing run #2. Reverse circulate on bottom, POOH, UD junk basket, unsuccessful. M/U EZ Drill TIH set EZ Drill at 530'. Displace 40 bbls 10.5ppg mud in hole with 12.8ppg. POOH & UD running tool. Perform ria maintenance & winterization. Standing by for BJ Services to R/U before Schlumberger perforations. Logging Engineer: Wayne Hermanson/Danny Kane * 10000 units = 100% Gas In Air ��I HALLIBURTON Customer: Aurora Gas, LLC Report #: 13 Well: Moquawkie 4 Date: 10/8/2008 parry �rilHng Sarvic®� Area: Tyonek 06:00 Depth: 867' Lease: Moquawkie Progress 24 hrs: 0' Rig: AWS -1 Rig Activity: Wait On Cement Mudlogger's Morning Report Job No.: AK -AM -0006174381 Report For: Coine/Newton Daily Cost: $3,725 Cumulative Cost: $78,600 ROP&Gas: Current 24 hr Avg 24 hr Max Max @ ft Pump & Flow Data: R.O.P. ft/hr N/A N/A N/A N/A Flow in m SPP(psi) Gas units N/A N/A N/A N/A Fow in spmGallons/stroke 2.8 Mud Data: mm'wm Density (ppg) Viscosity filtrate PV YP Chlorides FC PH Solids Depth in out (sec/ t) (cc/30 min) cP (Ib/100ft2) (m /1) (1/32") % 867 12.8 12.8 46 10.4 32 12 21,000 2 9.5 18.0 now MMEMMOMM BIT DATA: Type Size TFA Hours Depth in / out Footage WOB RPM Condition Bit # 2 Sec QHC1 S 1 7.88 0.52 Last Bit # 1 Sec XCL1 N 12.25 0.75 43.1 82 867 785 1-8 80 Lithology (%): Sd Sst Silt I Siltst Cly Clyst Sh Lst Coal Tuff 10 10 50 30 Connection Gas and Mud Cut Wiper Trip gas ft units ppg ft units ppg ft units ppg 24 hour Gas Breakdown Gas (units) Chromatograph (ppm) Bit Depth & Time Max Average C1 C2 C3 C4 Tot C5 Tot Type at at at at at at at to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - pumps off gas 24 hr Recap: R/U Schlumberger, RIH, perforate 520'-525'. POOH, UD Dowell gun, R/D Schlumberger. Close blinds, injectivity test perforations. P/U Halliburton RTTS & sliding sleeve, RIH, set at 470'. Finish R/U BJ Services, inject 21 bbls 14.6 ppg GasX cement at 1 bpm and 300 psi. Release packer, reverse circulate 4 bbls. UD single, squeeze cement for 12 hours at 100psi start at 03:00. *** After cementing finished, gas still percolating between conductor & casing 2-8 units & rarely up to 50 units*** Logging Engineer: Wayne Hermanson/Danny Kane * 10000 units= 100% Gas In Air HALLIBUFITOIV Customer: Aurora Gas, LLC Report #: 14 Well: Moquawkie 4 Date: 10/9/2008 i3p®rry drilling S®rvicas Area: Tyonek 06:00 Depth: 867' Lease: Moquawkie Progress 24 hrs: 0' Rig: AWS -1 Rig Activity: Drilling Cement Mudlogger's Morning Report Job No.: AK -AM -0006174381 Report For: BraidonNllest Daily Cost: $3,725 Cumulative Cost: $82,325 ROP&Gas: Current 24 hr Avg 24 hr Max Max @ ft Pump & Flow Data: R.O.P. ft/hr N/A N/A N/A N/A Flow in m SPP(psi) Gas units N/A N/A N/A N/A Fow in (spm) Gallons/stroke 2.8 Mud Data: Density (ppg) Viscosity filtrate PV YP Chlorides FC PH Solids Depth in out (sec/qt) (cc/30 min) cP (Ib/100ft2) (mg/1) (1/32") % 867 12.8 12.8 44 10.4 32 13 21,500 2 9.5 18.0 BIT DATA: Type Size TFA Hours Depth in / out Footage WOB RPM Condition Bit # 2 Sec QHC1S 7.88 0.52 Last Bit # 1 Sec XCL1 N 12.25 0.75 43.1 82 867 785 1-8 80 Lithology (%): Sd Sst Silt Siltst Cly Clyst Sh Lst Coal Tuff 10 10 50 30 Connection Gas and Mud Cut Wiper Trip gas ft units ppg ft units ppg ft units ppg 24 hour Gas Breakdown Gas (units) Chromatograph (ppm) Bit Depth & Time Max Average C1 C2 C3 C4 Tot C5 Tot Type at at at at at at at to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - pumps off gas 24 hr Recap: WOC cement & winterize rig. Release RTTS packer, POOH. Soft cement in Drill Collars, RIH w/ Drill Collars, circulate out. POOH, rack back collars, UD RTTS & running tool. R/U Schlumberger, run 3 temp logs, R/D Schlumberger. P/U DC, M/U bit sub. RIH. Drill cement from 452' to 470'. Max gas while drilling cement 12 units. Logging Engineer: Wayne Hermanson/Danny Kane " 10000 units= 100% Gas In Air HAL _IBIJFITON Customer: _ Aurora Gas, LLC Report #: 15 Well: Moquawkie 4 Date: 10/10/2008 I3ip®rrry Orflling S®rvic®s Area: _ Tyonek 06:00 Depth: 867' Lease: _ Moquawkie Progress 24 hrs: 0' Rig: _ AWS-1 Rig Activity: WOC Mudlogger's Morning Report Job No.: _ AK-AM-0006174381 Report For: BraidonlWest Daily Cost: $3,725 Cumulative Cost: $86,050 ROP&Gas: Current 24 hr Avg 24 hr Max Max @ ft Pump & Flow Data: R.O.P. ft/hr N/A N/A N/A N/A Flow in m SPP(psi) r nits N/A N/A N/A N/A Fow in s m Gallons/stroke 2.8 Data: Density (ppg) Viscosity filtrate PV YP Chlorides FC PH Solids epth in out (sec/gt) (cc/30 min) cP (Ib/100ftz) (m /1) (1/32") % 867 12.8 12.8 55 11.4 17 16 21,500 2 10.5 19.0 ATA: Type Size TFA Hours Depth in / out Footage WOB RPM Condition Bit # 2 Sec QHC1 S 7.88 0.52 Last Bit # 1 Sec XCL1 N 12.25 0.75 43.1 82 867 785 1-8 80 Lithology (%): Sd Sst Silt Siltst Cly Clyst Sh Lst Coal Tuff 10 10 50 30 Connection Gas and Mud Cut Wiper Trip gas ft units ppg ft units ppg ft units ppg 24 hour Gas Breakdown Gas (units) Chromatograph (ppm) Bit Depth & Time Max Average C1 C2 C3 C4 Tot C5 Tot Type at at at at at at at to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - pumps off gas 24 hr Recap: WOC cement, winterize rig, and continue circulating. Drill out cement from 510'- 520'. Fix overflowing return trough. Drill out cement from 520'- 528' (to EZ Drill packer). R/U & perform casing test--inject 4 bbls at 11 spm and 350 psi. R/D casing test. Circulate bottoms up Max gas 50 units over a background of 10 units. POOH ***Max gas while drilling cement 9 units.*** Logging Engineer: Wayne Hermanson/Danny Kane * 10000 units= 100% Gas In Air NALLIBURTON Customer: Aurora Gas, LLC Report #: 16 Well: Moquawkie 4 Date: 10/11/2008 �p®rry Drilling Sarvi=®mArea: Tyonek 06:00 Depth: 867' Lease: Moquawkie Progress 24 hrs: 0' Rig: AWS -1 Rig Activity: WOC Mudlogger's Morning Report Job No.: AK -AM -0006174381 Report For: BreedonMest Daily Cost: $3,725 Cumulative Cost: $89,775 ROP&Gas: Current 24 hr Avg 24 hr Max Max @ ft Pump & Flow Data: R.O.P. ft/hr N/A N/A N/A N/A Flow in m SPP(psi) Gas units N/A N/A N/A N/A Fow in s m Gallons/stroke 2.8 Mud Data: Density (ppg) Viscosity filtrate PV YP Chlorides FC PH Solids Depth in out (sec/qt) (cc/30 min) cP (Ib/100ft2) (mg/1) (1/32") % 867 12.8 12.8 51 11.2 19 16 21,000 2 10.0 18.0 BIT DATA: Type Size TFA Hours Depth in / out Footage WOB RPM Condition Bit # 2 Sec QHC1S 7.88 0.52 Last Bit # 1 Sec XCL1 N 12.25 0.75 43.1 82 867 785 1-8 80 Lithology (%): Sd Sst Silt Siltst Cly Clyst Sh =LstCoal Tuff10 10 50 0 Connection Gas and Mud Cut Wiper Trip gas ft units ppg ft units ppg ft units ppg 24 hour Gas Breakdown Gas (units) Chromatograph (ppm) Bit Depth & Time Max Average C1 C2 C3 C4 Tot C5 Tot Type at at at at at at at to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - pumps off gas 24 hr Recap: Winterize & clean pad of snow. Test BOPE. M/U mule shoe, RIH w/ 3 1/2" DP. Tag EZ -Drill BP at 528'. Circulate & condition diluted mud back up to 12.8 ppg. R/U BJ Services. Pump 15.2 bbls 15.8 ppg Class G cement. POOH 8 joints to 287'. R/U BJ to squeeze 2 bbls cement at 490 psi and shut in. Turn over to rig, R/D BJ & WOC with 500 psi held on it. Logging Engineer: Wayne Hermanson/Danny Kane 10000 units= 100% Gas In Air HALJ_IBUFRTON Customer: Aurora Gas, LLC Report #: 17 Well: Moquawkie 4 Date: 10/12/2008 �porry Drilling Services Area: Tyonek 06:00 Depth: 867' Lease: Moquawkie Progress 24 hrs: 0' Rig: AWS -1 Rig Activity: WOC Mudlogger's Morning Report Job No.: AK -AM -0006174381 Report For: BreedonMest Daily Cost: $3,725 Cumulative Cost: $93,500 ROP&Gas: Current 24 hr Avg 24 hr Max Max @ ft Pump & Flow Data: R.O.P. ft/hr N/A N/A N/A N/A Flow in m 149 SPP(psi) 179 Gas units 2 10 52 461 Fow in (spm) 51 Gallons/stroke 2.8 Mud Data: Density (ppg) Viscosity filtrate PV YP Chlorides FC PH Solids Depth in out (sec/qt) (cct30 min) CID (Ib/100fe) (m /1) (1/32") % 867 12.7 12.7 38 14.2 16 14 22,000 2 11.9 19.0 BIT DATA: Type Size TFA Hours Depth in / out Footage WOB RPM Condition Bit # 2 Sec QHC1S 7.88 0.52 Last Bit # 1 Sec XCL1 N 1 12.25 0.75 43.1 82 867 785 1-8 80 Lithology (%): Sd Sst Silt Siltsy Clyst I Sh Lst Coal Tuff 10 10 50 30 Connection Gas and Mud Cut Wiper Trip gas ft units ppg ft units ppg ft units ppg 24 hour Gas Breakdown Gas (units) Chromatograph (ppm) Bit Depth Max Average C1 C2 C3 C4 Tot C5 Tot Type to to to to to to to to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - pumps off gas :247hr ecap11 :WOC &perform rig maintenance.Reverse circulate 2x hole volume and then build up pressure to 485 psi & n WOC. Bleed off pressure POOH & UD OE DP & mule shoe. R/U power swivel, P/U drilling BHA #2 (minus one stnd DC) condition & circulate mud, & drill cement fr 358' to 495' w/some gas within cement (see below comments). WOC. Note: Mud data from previous day ***While drilling cement from 451' to 483', GP of 62U over BG of 14U.*** ***While drilling cement from 483' to 495', GP of 29U over BG of 13U.*** Logging Engineer: Wayne Hermanson/Danny Kane * 10000 units= 100% Gas In Air HALLIBIJRTON Customer: Aurora Gas, LLC Report #: 18 Well: Moquawkie 4 Date: 10/13/2008 l3parry o.-u�ir.g se.-..ice®a Area: Tyonek 06:00 Depth: 867' Lease: Moquawkie Progress 24 hrs: 0' Rig: AWS -1 Rig Activity: Milling Cement Mudlogger's Morning Report Job No.: AK -AM -0006174381 Report For: Breedon/West Daily Cost: $3,725 Cumulative Cost: $97,225 ENUMMMENIMM ROP&Gas: Current 24 hr Avg 24 hr Max Max @ ft Pump & Flow Data: R.O.P. ft/hr N/A N/A N/A N/A Flow in m 237 SPP(psi) 246 Gas units 2 3 30 528 Fow in (spm) 85 Gallons/stroke 2.8 Mud Data: Density (ppg) Viscosity filtrate PV YP Chlorides FC PH Solids Depth in out (sec/qt) (cc/30 min) cP (Ib/100ft2) (m /1) (1/32") % 867 12.4 12.4 40 13.6 16 15 20,000 2 11.5 18.6 sun= NEEMMME11111 BIT DATA: Type Size TFA Hours Depth in / out Footage WOB RPM Condition Bit # 2 Sec QHC1S 1 7.88 0.52 Last Bit # 1 Sec XCL1 N 12.25 0.75 43.1 82 867 785 1-8 80 Lithology (%): Sd Sst Silt Siltst Cly Clyst Sh L Coal Tuff 10 10 50 2 Connection Gas and Mud Cut Wiper Trip gas ft units ppg ft units ppg ftunits ppg 24 hour Gas Breakdown Gas (units) Chromatograph (ppm) Bit Depth Max Average C1 C2 C3 C4 Tot C5 Tot Type to to to to to to to to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - pumps off gas 24 hr Recap: WOC & winterize rig. Displace cement contaminated mud w/ new mud & weight up. Drill cement fr 495' to 500' & confirm hard cement. R/U & perform casing pressure test to 500 psi for 1 hr --passed. Bleed pressure, R/U to POOH. POOH to surface. Replace 7 7/8" bit with 8 1/2" mill & junk basket. RIH & tag cement at 351'. Mill cement from 351' to 427'. Note: Mud data from previous day Ldrilling cement from 500'to 528', GP of 29U over BG of 4U.' gineer: Wayne Hermanson/Danny Kane 10000 units= 100% Gas In Air HALLIBIJRTON Customer: Aurora Gas, LLC Report #: 19 Well: Moquawkie 4 Date: 10/14/2008 Sp®rrr-y M-1111ng Sar -%A=®= Area: Tyonek 06:00 Depth: 867' Lease: Moquawkie Progress 24 hrs: 0' Rig: AWS -1 Rig Activity: Milling to Shoe Mudloggees Morning Report Job No.: AK -AM -0006174381 Report For: BreedonNVest Daily Cost: $3,725 Cumulative Cost: $100,950 ROP&Gas: Current 24 hr Avg 24 hr Max Max @ ft Pump & Flow Data: R.O.P. ft/hr N/A N/A N/A N/A Flow in m 250 SPP(psi) 272 Gas units 2 3 5 612 Fow in (spm) 89 1 Gallons/stroke 2.8 Mud Data: Density (ppg) Viscosity filtrate PV YP Chlorides FC PH Solids Depth in out (sec/qt) (cc/30 min) cP (Ib/100ft2) (m /1) (1/32") % 867 11.1 11.1 45 20.0 45 10 19,000 2 10.0 14.1 BIT DATA: Type Size TFA Hours Depth in / out Footage WOB RPM Condition Bit # 2 Sec QHC1S 7.88 0.52 Last Bit # 1 Sec XCL1 N 12.25 0.75 43.1 82 867 785 1-8 80 Lithology (%): Sd Sst Silt Siltst Cly Clyst Sh Lst Coal Tuff 10 10 50 30 Connection Gas and Mud Cut Wiper Trip gas ft units ppg ft units ppg ft units ppg 24 hour Gas Breakdown Gas (units) Chromatograph (ppm) Bit Depth Max Average C1 C2 C3 C4 Tot C5 Tot Type to to to to to to to to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - pumps off gas 24 hr Recap: Mill cement down to 458', stop for rig maintenance. Mill fr 458' to 528', circ btms up, shut in, & close rams. Pressure up to 500psi for 15min to confirm casing & perforation integrity. Mill cementing plug & stop for derrick -mounted communication equip repairs. Mill EZ -Drill BP to 532', then chase remnants downhole. Milling/pushing BP remnants at 740' as of report time. Note: Mud data from previous day Logging Engineer: Wayne Hermanson/Danny Kane 10000 units= 100% Gas In Air it HALLIBURTON Customer: Aurora Gas, LLC Report #: 20 Well: Moquawkie 4 Date: 10/15/2008 mpar-r-y Orilling Servic®s Area: Tyonek 06:00 Depth: 874' Lease: Moquawkie Progress 24 hrs: 7' Rig: AWS-1 Rig Activity: Condition Mud Mudloggees Morning Report Job No.: AK-AM-0006174381 Report For: BreedonMest Daily Cost: $3,725 Cumulative Cost: $104,675 MOINEMEMOM ROP&Gas: Current 24 hr Avg 24 hr Max Max @ ft Pump & Flow Data: R.O.P. ft/hr N/A 10.0 259.0 871 Flow in m SPP(psi) Gas units N/A 3 42 873 Fow in spm Gallons/stroke 2.8 Mud Data: Density (ppg) Viscosity filtrate PV YP Chlorides FC PH Solids Depth in out (sec/qt) (cc/30 min) CID (Ib/100ft2) (m /1) (1/32") % 854 11.5 11.5 44 18.0 11 14 10,00 1 12.0 14.2 NEW MROMEMOMBIT DATA: Type Size TFA Hours Depth in / out Footage WOB RPM Condition Bit # 2 Baker Mill 1 7.88 0.7 867 874 7 7-8 75 Last Bit # 1 Sec XCL1 N 12.25 0.75 43.1 82 867 785 1-8 80 Lithology (%): Sd Sst Silt Siltst Cly Clyst Sh Lst Coal Tuff 10 10 70 10 Connection Gas and Mud Cut Wiper Trip gas ft units ppg ft units ppg ft units ppg 24 hour Gas Breakdown Gas (units) Chromatograph (ppm) Bit Depth Max Average C1 C2 C3 C4 Tot C5 Tot Type 867 to 874 42 18 4846 0 0 0 0 GP to to to to to to to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - pumps off gas 24 hr Recap: Pushed/chased EZ-Drill BP remnants down to 837'. P/U off btm, circ btms up, condition mud to 11.4 ppg, blow down & R/U for casing test. Pressure up to 500 psi for 30 min. Bleed off, blow down & R/D test equip. Mill fr 837' to 857'. Break free of shoe at 857', ream down to 869'. Circulate bottoms up. Mill new formation fr 869' to 874'& circ 2 bottoms up. Clean pits and weight up mud system to 11.5 ppg. Max gas under casing shoe 66 unuts Logging Engineer: Wayne Hermanson/Danny Kane 10000 units= 100% Gas In Air HALLIBIJFITON Customer: Aurora Gas, LLC Report #: 21 Well: Moquawkie 4 Date: 10/16/2008 !ip®rry o.-1111n5a sa.-..ac®s Area: Tyonek 06:00 Depth: 1013' Lease: Moquawkie Progress 24 hrs: 139' Rig: AWS -1 Rig Activity: Drilling 7 7/8" Hole Mudlogger's Morning Report Job No.: AK -AM -0006174381 Report For: BreedonMest Daily Cost: $3,725 Cumulative Cost: $108,400 ROP&Gas: Current 24 hr Avg 24 hr Max Max @ ft Pump & Flow Data: R.O.P. ft/hr N/A 23.0 168.0 989 Flow in m 314 1 SPP(psi) 808 Gas units N/A 33 147 1006' Fow in s m 112 Gallons/stroke 2.8 Mud Data: Density (ppg) Viscosity filtrate PV YP Chlorides FC PH Solids Depth in out (sec/qt) (cc/30 min) cP (Ib/100ft2) (mg/1) (1/32") % 874 11.5 11.5 45 8.0 14 13 20,000 2 12.3 11.5 BIT DATA: Type Size TFA Hours Depth in / out Footage WOB RPM Condition Bit # 2 Baker Mill 1 7.88 6.83 867 1013 146 8 -Feb 75-125 Last Bit # 1 Sec XCL1 N 12.25 0.75 43.1 82 867 785 1-8 80 Lithology (%): Sd Sst Silt I Siltst 1 Cly Clyst 1 Sh Lst Coal Tuff 5 20 75 0 Connection Gas and Mud Cut Wiper Trip gas ft units ppg ft units ppg ft units ppg 24 hour Gas Breakdown Gas (units) Chromatograph (ppm) Bit Depth Max Average C1 C2 C3 C4 Tot C5 Tot Type 874' to 889' 50 16 GP 889' to 909' 113 34 GP 909' to 922' 35 19 GP 922' to 952' 54 23 6140 0 0 0 0 GP 952' to 982' 122 38 13918 29 0 0 0 GP 982' to 1013' 147 56 15216 30 0 0 0 GP to to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - pumps off gas 24 hr Recap: Clean Pit 5 & Sand Trap, build mud vol & wt up to 11.5ppg. Displace hole & trip tank w/ 11.5ppg mud. R/D power swivel, POOH to surface, UD DP & rack back BHA. Replace mill & junk basket w/ 7 7/8" bit. RIH to btm, drill fr 874' to 889', perform FIT #1 to 14.4ppg EMW. Drill fr 889' to 909', perform FIT to 16.Oppg EMW. Drill fr 909' to 1013' as of report time. Logging Engineer: Wayne Hermanson/Danny Kane 10000 units= 100% Gas In Air "ALL-ILIBLJRTON Customer: Aurora Gas, LLC Well: Moquawkie 4 Report #: Date: 22 10/17/2008 Mp®rry Mriiling Services Area: Tyonek 06:00 Depth: 1388' Lease: Moquawkie Progress 24 hrs: 375' Rig: AWS -1 Rig Activity: Drilling 7 7/8" Hole Mudlogger's Morning Report Job No.: AK -AM -0006174381 Report For: BreedonMest Daily Cost: $3,725 Cumulative Cost: $112,125 ROP&Gas: Current 24 hr Avg 24 hr Max Max @ ft Pump & Flow Data: R.O.P. ft/hr 0.0 37.3 335.0 1306' Flow in m 282 SPP(psi) 778 Gas units 15.0 137 702 1051' Fow in s m 101 Gallons/stroke 2.8 Mud Data: Density (ppg) Viscosity filtrate PV YP Chlorides Solids Depth in out (sec/qt) (cc/30 min) cP LCPH (Ib/100fe) (mg/1) % 851 11.5 11.5 40 6.0 16 18 24,000 10.2 11.7 BIT DATA: Type Size TFA Hours Depth in / out Footage WOB RPM Condition Bit# 2 SecQHC1S 1 7.88 16.8 867 1386 519 2-8 75-125 Last Bit # 1 Sec XCL1 N 12.25 0.75 43.1 82 867 785 1-8 80 Lithology (%): Sd Sst Silt I Siltst Cly Clyst Sh Lst Coal Tuff 40 10 25 25 Connection Gas and Mud Cut Wiper Trip gas ft units ppg ft units ppg ft units ppg 24 hour Gas Breakdown Gas (units) Chromatograph (ppm) Bit Depth Max Average C1 C2 C3 C4 Tot C5 Tot Type 1013 to 1044 73 49 8617 0 0 0 0 GP 1044 to 1075 702 322 44053 0 0 0 0 GP 1075 to 1106 306 127 30913 0 0 0 0 GP 1106 to 1170 468 130 27380 61 0 0 0 GP 1170 to 1201 691 202 85012 43 0 0 0 GP 1201 to 1232 567 160 80946 0 0 0 0 GP 1232 to 1263 424 93 2896 0 0 0 0 GP 1263 to 1296 225 74 29905 69 0 0 0 GP 1296 to 1323 472 80 27521 67 0 0 0 GP 1323 to 1355 143 69 15116 0 0 0 0 GP 1355 to 1386 409 180 24905 0 0 0 0 GP to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG -pumps off gas 24 hr Recap: Drill ahead fr 1013' to 1386'. R/U & run wireline survey. R/D survey equipment, peform short trip to within the casing shoe at 854'. RIH to bottom, drill fr 1386' to 1388' as of report time. Gas peaks to 1320' associated with coal seams. Gas peaks at 1350' (GP 371 U BG 31 U) and 1360' (GP 409U BG 35U) assctd with sand -- Pssbly Beluga Tsuga 2-7.2 ' Possibly identified the Beluga Tsuga 2-7.1 @ 1047'*** *—Possibly identified the Beluga Tsuga 2-7.2 @ 1320'- Found coal marker just before formation @ 1250' *** Logging Engineer: Colby Marks/Danny Kane * 10000 units= 100% Gas In Air HALLIBURTON Customer: Aurora Gas, LLC Report #: 23 Well: Moquawkie 4 Date: 10/18/2008 Sperry Drilling S®rvic®� Area: Tyonek 06:00 Depth: 1604' Lease: Moquawkie Progress 24 hrs: 216' Rig: AWS-1 Rig Activity: Testing BOPE Mudloggees Morning Report Job No.: AK-AM-0006174381 Report For: BreedonM/est Daily Cost: $3,725 Cumulative Cost: $115,850 ROP&Gas: Current 24 hr Avg 24 hr Max Max @ ft Pump & Flow Data: R.O.P. ft/hr 0.0 27.0 89.0 1427' Flow in m 0 1 SPP(psi) 6 rDATA-: 2.0 74 711 1541' Fow in s m 0 Gallons/stroke 2.8 Density (ppg) Viscosity filtrate PV YP Chlorides FC PH Solids in out (sec/qt) (cc/30 min) cP (Ib/100ft2) (m /1) 1(1/32") % 11.5 11.5 40 6.2 17 19 29,000 2 9.6 12.9 now nommmom�Type Size TFA Hours Depth in / out Footage WOB RPM Condition Bit # 2 Sec QHC1S 7.88 24.9 867' 1604' 737' 2-8 75-125 Last Bit # 1 Sec XCL1 N 12.25 0.75 43.1 82' 867' 785' 1-8 80 Lithology (%): Sd Sst Silt Siltst Cly Clyst Sh Lst Coal Tuff 10 25 60 5 Connection Gas and Mud Cut Wiper Trip gas ft units ppg ft units ppg ft units ppg 24 hour Gas Breakdown Gas (units) Chromatograph (ppm) Bit Depth Max Average C1 C2 C3 C4 Tot C5 Tot Type 1386' to 1407' 130 55 15800 8 0 0 0 BG 1408' to 1418' 223 106 - - - - - GP 1419' to 1483' 171 57 18203 42 0 0 0 BG 1484' to 1509316 94 29828 58 0 0 0 GP 1510' to 1525' 139 58 14371 0 0 0 0 BG 1526' to 1544' 711 182 87349 0 0 0 0 GP 1545' to 1595' 176 59 11873 25 0 0 0 BG 1595' to 1604' 137 74 15684 33 0 0 0 BG to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - pumps off gas IENEEMENEENEW 24 hr Recap: Drill fr 1386' to 1501'. GP 223 U over 46 U BG at 1413' and GP of 316 U over 60 U at 1496'. Service power swivel drill fr 1501' to 1604'. GP of 711 U over 38 U BG at 1541'. R/U & run wireline survey at 1572'. Condition & circ mud 2x btms up. LID single POOH into shoe, racking back DP. Circ 2x btms up at shoe, continue POOH to surface, racking back DP & BHA (breaking out stabilizers). R/U & perform BOPE test as of report time. *** Max gas of 711 U over 38 U BG at 1541' Logging Engineer: Colby Marks/Danny Kane * 10000 units= 100% Gas In Air ALLIBURTON Customer: Aurora Gas, LLC Well: Moquawkie 4 Report #: Date: 24 10/19/2008 perry Ori111ng S®rrvic®s Area: Tyonek 06:00 Depth: 1604' Lease: Moquawkie Progress 24 hrs: 156' Rig: AWS-1 [ROP&,Gas: Rig Activity: Drilling Ahead Mudloggees Morning Report Job No.: AK-AM-0006174381 Report For: Daily Cost: $3,725 Cumulative Cost: BreedonMest $119,575 Current 24 hr Avg 24 hr Max Max @ ft Pump & Flow Data: R.O.P. ft/hr 44.0 31.2 99.0 1717 Flow in m 301 SPP(psi) 998 Gas units 64.0 97 430 1734 Fow in (spm) 108 Gallons/stroke 2.8 Mud Data: Density (ppg) Viscosity filtrate PV YP Chlorides FC PH Solids Depth in out (sec/qt) (cc/30 min) cP (Ib/100ft2) (mg/1) (1/32") % 1701 11.6 11.6 47 6.4 14 21 25,000 2 9.0 12.6 BIT DATA: Type Size TFA Hours Depth in / out Footage WOB RPM Condition Bit # 2 Sec QHC1S 7.88 32.76 867' 900 2-10 75-125 Last Bit # 1 Sec XCL1 N 7.88 0.75 43.1 82' 867' 785' 1-8 80 Lithology (%): Sd Sst Silt I Siltst Cly Clyst Sh Lst Coal Tuff 70 20 10 Connection Gas and Mud Cut Wiper Trip gas ft units ppg ft units ppg ft units ppg 24 hour Gas Breakdown Gas (units) Chromatograph (ppm) Bit Depth Max Average C1 C2 C3 C4 Tot C5 Tot Type 0 to 1604 380 65 49532 0 0 0 0 POG 1604 to 1650 218 58 17908 37 0 0 0 POG 1650 to 1700 162 44 33527 25 0 0 0 GP 1700 to 1750 430 200 52058 0 0 0 0 GP to to to to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - pumps off gas 24 hr Recap: Completed BOP test TIH and drill ahead. Currently drilling ahead at time of report. *** Max gas of 430 U over 65 U BG at 1541' *** Logging Engineer: Colby Marks/Daniel Sherwood * 10000 units= 100% Gas In Air L6.IBUFRTOIV Customer: Aurora Gas, LLC Report #: Well: Moquawkie 4 Date: 25 10/20/2008 rry Orllling Sarvic®� Area: Tyonek 06:00 Depth: 2080' Lease: Moquawkie Progress 24 hrs: 476' Rig: AWS -1 Rig Activity: FROPa,Gas: Drilling Ahead dlogger's Morning Report Job No.: AK -AM -0006174381 Report For: BreedonMest Daily Cost: $3,725 Cumulative Cost: $123,300 Current 24 hr Avg 24 hr Max Max @ ft Pump & Flow Data: R.O.P. ft/hr 8.0 31.5 91.0 1780 Flow in m 297 1 SPP(psi) 1123 Gas units 21.0 106 473 1758 Fow in (spm) 106 Gallons/stroke 2.8 Mud Data: Density (ppg) Viscosity filtrate PV YP Chlorides FC PH Solids Depth in out (sec/ t) (cc/30 min) I cP (Ib/100ft2) (m /1) (1/32") % 2073 11.6 11.6 47 6.4 14 21 1 25,000 2 9.0 12.6 BIT DATA: Type Size TFA Hours Depth in / out Footage WOB RPM Condition Bit # 2 Sec QHC1 S 7.88 32.76 867' 900 2-10 75-125 Last Bit # 1 Sec XCL1 N 7.88 0.75 43.1 82' 867' 785' 1-8 80 Lithology (%): Sd Sst Silt Siltst I Cly Clyst Sh Lst I Coal Tuff 20 70 10 Connection Gas and Mud Cut Wiper Trip gas ft units ppg ft units ppg ft units ppg 24 hour Gas Breakdown Gas (units) Chromatograph (ppm) Bit Depth Max Average C1 C2 C3 C4 Tot C5 Tot Type 1750 to 1800 473 225 64073 0 0 0 0 GP 1800 to 1900 390 99 48865 129 0 0 0 GP 1900 to 1920 449 169 33571 57 0 0 0 GP 1920 to 1950 410 175 34865 0 0 0 0 GP 1950 to 2073 196 61 25732 0 0 0 0 GP to to to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - pumps off gas 24 hr Recap: Drilled to 2073' and conducted survey. Cir btms up and POOH for short wiper trip 7.5 stnds. RIH to btm cir btms up and commence drilling. Currently drilling ahead at the time of report. *** Max gas of 473 U over 115 U BG at 1758' *** Logging Engineer: Colby Marks/Daniel Sherwood * 10000 units= 100% Gas In Air HALLIBURTON Customer: Aurora Gas, LLC Well: Moquawkie 4 Report #: Date: 26 10/21/2008 Sp®rr-y Orr1111ng 9M6PVIc®w Area: Tyonek 5 :00 Depth: 2449.09 Lease: Moquawkie Progress 24 hrs: 369 Rig: AWS -1 Rig Activity: Drilling Ahead Mudloggees Morning Report Job No.: AK -AM -0006174381 Daily Cost: $3,725 Report For: Cumulative Cost: BreedonMest $127,025 ROP&Gas: Current 24 hr Avg 24 hr Max Max @ ft Pump & Flow Data: R.O.P. ft/hr 5.5 28.6 119.5 2280 Flow in m 300 SPP(psi) 1307 Gas units 32.0 154 1069 2268 Fow in (spm) 109 Gallons/stroke 2.8 Mud Data: Density (ppg) Viscosity filtrate PV YP Chlorides FC PH Solids Depth in out (sec/qt) (cc/30 min) cP (Ib/100ft2) (m /I) (1/32") 2073 11.5 11.5 50 5.0 21 23 28,000 1/- 8.8 12.4 BIT DATA: Type Size TFA Hours Depth in / out Footage WOB RPM Condition Bit # 2 Sec QHC1 S 1 7.88 67.7 867' 1582 2-10 75-150 Last Bit # 1 Sec XCL1 N 7.88 0.75 43.1 82' 867' 785' 1-8 80 Lithology (%): Sd Sst Silt Siltst Cly Clyst Sh Lst I Coal Tuff 10 50 10 5 20 Connection Gas and Mud Cut Wiper Trip gas ft units ppg ft units ppg ft units ppg 24 hour Gas Breakdown Gas (units) Chromatograph (ppm) Bit Depth Max Average C1 C2 C3 C4 Tot C5 Tot Type 2073 to 2120 454 351 47690 0 0 0 0 GP 2120 to 2150 306 -2 _70 42444 0 0 0 0 GP 2150 to 2200 193 190 25352 0 0 0 0 GP 2200 to 2220 418 396 47528 0 0 0 0 GP 2220 to 2250 852 845 106751 0 0 0 0 GP 2250 to 2300 1069 1060 126891 0 0 0 0 GP 2300 to 2350 253 223 31339 82 0 0 0 GP 2350 to 2400 1752 164 20061 22 0 0 0 GP to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - pumps off gas 24 hr Recap: Drilled from 2080' and to 2449' md. *" Max gas of 1069U over 457U BG at 2268' *** Logging Engineer: Colby Marks/Daniel Sherwood * 10000 units= 100% Gas In Air HALLIBURTON Customer: Aurora Gas, LLC Well: Moquawkie 4 Report #: Date: 27 10/22/2008 Sperry iJrllling B®rvic®� Area: Tyonek 5:00 Depth: 2751' Lease: Moquawkie Progress 24 hrs: 302' Rig: AWS-1 Rig Activity: Drilling Ahead Mudlogger's Morning Report Job No.: AK-AM-0006174381 Daily Cost: $3,725 Report For: Cumulative Cost: BreedonMlest $130,750 IMMOSIONNEM MEN= ROP&Gas: Current 24 hr Avg 24 hr Max Max @ ft Pump & Flow Data: R.O.P. ft/hr 15.0 23.2 56.9 2720 Flow in m 298 SPP(psi) 1380 Gas units 60.0 86 296 2490 Fow in (spm) 107 Gallons/stroke 2.8 Mud Data: Density (ppg) Viscosity filtrate PV YP Chlorides FC PH Solids Depth in out (sec/qt) (cc/30 min) cP (Ib/100ftz) (m /1) (1/32") % 2073 11.5 11.5 49 5.0 21 20 30,000 1/- 9.0 11.8 BIT DATA: Type Size TFA Hours Depth in / out Footage WOB RPM Condition Bit # 2 Sec QHC1S 7.88 83.73 867' 1884' 2-10 75-150 Last Bit # 1 Sec XCL1 N 7.88 0.75 43.1 82' 867' 785' 1-8 80 Lithology (%): Sd I Sst Silt Siltst Cly Clyst Sh Lst Coal Tuff 7010 20 Connection Gas and Mud Cut Wiper Trip gas ft units ppg 501 ft 174 units 11.4 ppg ft units ppg 24 hour Gas Breakdown Gas (units) Chromatograph (ppm) Bit Depth Max Average C1 C2 C3 C4 Tot C5 Tot Type 2400 to 2450 165 139 15244 44 0 0 0 GP 2450 to 2500 296 291 37239 74 0 0 0 GP 2500 to 2550 202 190 24837 62 0 0 0 GP 2550 to 2600 218 187 26367 74 0 0 0 GP 2650 to 2680 172 166 19994 52 0 0 0 GP 2680 to 2700 216 205 28475 0 0 0 0 GP to to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - pumps off gas 11 1,11p,11g, 24 hr Recap: Drilled from 2449' md. To 2605' and then performed a short wiper trip to 2105' cir btms up then TIH to btm cir btms up then commenced drilling. Currently drilling ahead with a bit depth of 2751' md. * Max gas of 1069U over 4570 BG at 2268' ' Logging Engineer: Colby Marks/Daniel Sherwood 10000 units= 100% Gas In Air HAILILIBIJFITON Customer: Aurora Gas, LLC Well: Moquawkie 4 Report #: Date: 28 10/23/2008 Wp®rrry Area: Tyonek 5:00 Depth: 2916 Lease: Moquawkie Progress 24 hrs: 165 Rig: AWS -1 Rig Activity: RIH Mudlogger's Morning Report Job No.: AK -AM -0006174381 Report For: Daily Cost: $3,725 Cumulative Cost: BreedonMest $134,475 ROP&Gas: Current 24 hr Avg 24 hr Max Max @ ft Pump & Flow Data: R.O.P. ft/hr 0.0 21.6 45.5 2766 Flow in m 298 SPP(psi) 1607 Gas units 81.0 65 588 2846 Fow in s m 256 Gallons/stroke 2.8 Mud Data: Density (ppg) Viscosity filtrate PV YP Chlorides FC PH Solids Depth in out (sec/qt) (cc/30 min) cP (W100fe) (m /1) (1/32") % 2073 11.4 11.4 50 5.0 21 19 1 30,000 1/- 902.0 11.8 BIT DATA: Type Size TFA Hours Depth in / out Footage WOB RPM Condition MIN Bit# 2 SecQHC1S 7.88 92.87 867' 2916 2049' 2-10 75-150 ,4,SS,A,A,1+/10,ER,pr/hr FDS Smith 7.88 0.45 0 2916' Bit #!Gas ississam mosommm LlthOlOgSd Sst Silt Siltst Cly Clyst Sh Lst Coal Tuff 55 45 Connectiond Mud Cut Wiper Trip gas units ppg 2900 ft 4875 units 10.8 ppg ft units ppg 24 hour Gas Breakdown Gas (units) Chromatograph (ppm) Bit Depth Max Average C1 C2 C3 C4 Tot C5 Tot Type 2700 to 2750 152 145 17550 29 0 0 0 GP 2750 to 2800 n/a 2800 to 2850 339 308 43867 97 1 0 0 GP 2850 to 2870 292 279 36437 83 3 0 0 GP 2870 to 2900 280 206 27150 17 1 0 0 GP 2900 to 2916 4857 399668 0 0 0 0 POG to to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - pumps off gas 24 hr Recap: Drilled from 2751' and to 2916 then POOH for a bit trip. Changed bits and added additional drilling collars and RIH to bottom. Currently TI with a bit depth of 2769' and *** Max gas of 4875U POG' Logging Engineer: Colby Marks/Daniel Sherwood * 10000 units= 100% Gas In Air HALLIBURTON Customer: Aurora Gas, LLC Well: Moquawkie 4 Report #: Date: 29 10/24/2008 Bp®rry �rllling S®rvicas Area: Tyonek 5 :00 Depth: 3161' Lease: Moquawkie Progress 24 hrs: 245' Rig: AWS -1 _ Rig Activity: Drilling Ahead Mudlogger's Morning Report Job No.: AK -AM -0006174381 Report For: Daily Cost: $3,725 Cumulative Cost: BreedonMest $138,200 ROP&Gas: Current 24 hr Avg 24 hr Max Max @ ft Pump & Flow Data: R.O.P. ft/hr 8.0 83.3 3010.0 3010 Flow in m 280 SPP(psi) 1498 Gas units 100.0 109 1000 3103 Fow in (spm) 100 Gallons/stroke 2.8 Ww Mud Data: Density (ppg) Viscosity filtrate PV YP Chlorides FC PH Solids Depth in out (sec/qt) (cc/30 min) cP (Ib/100f) (m /1) (1/32") % 2073 11.5 11.5 51 5.3 19 19 28,000 1/- 9.0 11.9 BIT DATA: Type Size TFA Hours Depth in / out Footage WOB RPM Condition Bit # 2 Sec QHC1S 7.88 92.87 867' 2916 2049' 2-10 75-150 ,4,ss,A,A,1+/10,ER,pr/hr Bit # 3 FDS Smith 7.88 0.45 14.21 2916' 245' 12 -Feb 75-150 ON Lithology (%): Sd I Sst Silt I Silt st Cly Clyst Sh Lst Coal Tuff 10 90 Connection Gas and Mud Cut Wiper Trip gas ft units ppg ft units ppg ft units ppg 24 hour Gas Breakdown Gas (units) Chromatograph (ppm) Bit Depth Max Average C1 C2 C3 C4 Tot C5 Tot Type 2916 to 2950 84 37 5894 7 0 0 0 GP 2950 to 2980 232 176 10030 17 0 0 0 GP 2980 to 2990 681 660 81661 176 24 2 0 GP 2990 to 3000 298 285 36768 0 2 0 0 GP 3000 to 3020 300 295 37467 2 0 0 0 GP 3020 to 3050 215 211 27871 3 0 0 0 GP 3050 to 3100 599 497 77638 128 17 0 0 GP 3100 to 3130 1000 995 113993 223 28 0 0 GP 3130 to 3145 195 187 23639 50 3 0 0 GP 3145 to 3150 466 332 27541 62 4 0 0 GP to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - pumps off gas 24 hr Recap: POOH for a bit trip changed bits and added additional drilling collars and RIH to bottom. Currently drilling ahead with a bit depth of 3161' md. I Max gas of 1000U GP ove BG gas of 40U ' *** Logging Engineer: Colby Marks/Daniel Sherwood * 10000 units= 100% Gas In Air HALLIBURTON Customer: Aurora Gas, LLC Well: Moquawkie 4 Report #: Date: 30 10/25/2008 Sp®r-ry Orrilling S®r-vices Area: Tyonek 5:00 Depth: 3450 Lease: Moquawkie Progress 24 hrs: 289 Rig: AWS -1 Rig Activity: POOH Mudlogger's Morning Report Job No.: AK -AM -0006174381 Report For: BreedonMest Daily Cost: $3,725 Cumulative Cost: $141,925 ROP&Gas: Current 24 hr Avg 24 hr Max Max @ ft Pump & Flow Data: R.O.P. ft/hr 0.0 29.2 78.7 3206 Flow in m 0 SPP(psi) 0 Gas units 0.0 140 667 3212 Fow in (spm) 0 Gallons/stroke 2.8 Mud Data: Density (ppg) Viscosity filtrate PV YP Chlorides FC PH Solids Depth in out (sec/qt) (cc/30 min) cP (Ib/100ft2) (mg/1) 2073 11.5 11.5 53 4.8 21 21 30,000 1/- 9.2 11.8 SEE BIT DATA: Type Size TFA Hours Depth in / out Footage WOB RPM Condition Bit# 2 SecQHC1S 7.88 92.87 867' 2916 2049' 2-10 75-150 ,4,ss,A,A,1+/10,ER,pr/hr Bit # 3 FDS Smith 7.88 0.45 14.21 2916' 534 245' 2--12 75-150 Lithology (%): Sd Sst Silt Siltst Cly Clyst Sh Lst Coal Tuff Chrt 30 5 50 5 10 Connection Gas and Mud Cut Wiper Trip gas ft units ppg ft units ppg ft units ppg 24 hour Gas Breakdown Gas (units) Chromatograph (ppm) Bit Depth Max Average C1 C2 C3 C4 Tot C5 Tot Type 3150 to 3200 466 322 38769 78 6 0 0 GP 3200 to 3250 667 666 n/a n/a n/a n/a n/a GP 3250 to 3280 307 297 36630 86 6 0 0 GP 3280 to 3300 391 378 46637 82 8 0 0 GP 3300 to 3325 321 317 39883 71 7 0 0 GP 3325 to 3350 268 255 36782 41 8 0 0 GP 3350 to 3400 N/A 3400 to 3450 N/A to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - pumps off gas 24 hr Recap: Drilled from 3161' to a final TD of 3450' md. Cir BU then POOH to 2605' cir btms up and RIH to btm cir sweep. Currently preparing to POOH at the time of report. I Max gas of 667U GP over BG gas of 1000 ' *" Logging Engineer: Colby Marks/Daniel Sherwood 10000 units= 100% Gas In Air Logging Engineer: Colby Marks/Daniel Sherwood 10000 units= 100% Gas In Air Customer: Aurora Gas, LLC Report #: 31 HALLIBURTON Well: Moquawkie 4 Date: 10/26/2008 �iparry Oriiiing Sarvica� Area: Tyonek 6:00 Depth: 0 Lease: Moquawkie Progress 24 hrs: N/A Rig: AWS -1 Rig Activity: Testing BOP's Mudlogger's Morning Report Job No.: AK -AM -0006174381 Report For: BreedonMest Daily Cost: $3,725 Cumulative Cost: $145,650 ROP&Gas: Current 24 hr Avg 24 hr Max Max @ ft Pump & Flow Data: R.O.P. ft/hr Flow in m 0 SPP (psi)0 Gas units 0.0 0 38 734 Fow in (spm) 0 Gallons/stroke 2.8 gff Mud Data: Density (ppg) Viscosity filtrate PV YP Chlorides FC PH Solids Depth in out (sec/qt) (cc/30 min) cP (Ib/100fe) (m /1) (1/32") % 2073 11.4 EME 11.4 54 5.2 20 18 27,000 1/- 9.4 12.0 BIT DATA: Type Size TFA Hours Depth in / out Footage WOB RPM Condition Bit # 2 Sec QHC1S 7.88 92.87 867' 2916 2049' 2-10 75-150 ,4,ss,A,A,1+/10,ER,pr/hr Bit # 3 FDS Smith 7.88 0.45 14.21 2916' 534 245' 2--12 75-150 Lithology (%): Sd Sst Silt Siltst I Cly Clyst Sh Lst Coal Tuff Chrt Connection Gas and Mud Cut Wiper Trip gas ft units ppg ft units ppg ft units ppg 24 hour Gas Breakdown Gas (units) Chromatograph (ppm) Bit Depth Max Average C1 C2 C3 C4 Tot C5 Tot Type to to to to to to to to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - pumps off gas r24hrecap: H and blowdown and prepare for BOP test. R/U Schlumberger wireline and testing BOP's at the time of report. Logging Engineer: Colby Marks/Daniel Sherwood 10000 units= 100% Gas In Air Logging Engineer: Colby Marks/Daniel Sherwood * 10000 units= 100% Gas In Air J Customer: Aurora Gas, LLC Report #: 32 HALLIBURTOIV Well: Moquawkie 4 Date: 10/27/2008 8p®rrry M-1111.,9 W®mrl=®w Area: Tyonek 5:00 Depth: 0 Lease: Moquawkie Progress 24 hrs: N/A Rig: AWS -1 Rig Activity: Wireline Survey Mudlogger's Morning Report Job No.: AK -AM -0006174381 Report For: BreedonMest Daily Cost: $2,750 Cumulative Cost: $145,650 ROP&Gas: Current 24 hr Avg 24 hr Max Max @ ft Pump & Flow Data: R.O.P. ft/hr Flow in m 0 SPP(psi) 0 Gas units 0.0 0 0 0 Fow in (spm) 0 Gallons/stroke 2.8 Mud Data: Density (ppg) Viscosity filtrate PV YP Chlorides FC PH Solids Depth in out (sec/qt) (cc/30 min) cP (Ib/100ft2) (m /1) 1(1/32") % 3450 11.5 11.5 72 4.9 23 21 30,000 1/_ 9.3 12.3 BIT DATA: Type Size TFA Hours Depth in / out Footage WOB RPM Condition Bit# 2 SecQHC1S 7.88 92.87 867' 2916 2049' 2-10 75-150 ,4,ss,A,A,1+/10,ER,pr/hr Bit # 3 FDS Smith 1 7.88 0.45 14.21 2916' 534 245' 2--12 75-150 New Lithology (%): Sd Sst Silt Siltst Cly Clyst Sh Lst Coal Tuff Chrt Connection Gas and Mud Cut Wiper Trip gas ft units ppg ft units ppg ft units ppg 24 hour Gas Breakdown Gas (units) Chromatograph (ppm) Bit Depth Max Average C1 C2 C3 C4 Tot C5 Tot Type to to to to to to to to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - pumps off gas 24 hr Recap: Finished the first run of wireline and BOP test currently Dreoarina for a second run of wireline at the time of report. Logging Engineer: Colby Marks/Daniel Sherwood * 10000 units= 100% Gas In Air J Logging Engineer: Colby Marks/Daniel Sherwood * 10000 units= 100% Gas In Air Customer: Aurora Gas, LLC Report #: 33 MALLIB�.JRTON —IMWell: Moquawkie 4 Date: 10/28/2008 Mgawr -y Orilling S®rvica� Area: Tyonek 5:00 Depth: 0 Lease: Moquawkie Progress 24 hrs: N/A Rig: AWS -1 Rig Activity: Wireline Survey Mudlogger's Morning Report Job No.: AK -AM -0006174381 Report For: BreedonNVest Daily Cost: $2,875 Cumulative Cost: $151,275 ROP&Gas: Current 24 hr Avg 24 hr Max Max @ ft Pump Flow Data: R.O.P. ft/hr Flow in m 100 SPP (psi)50 Gas units 0.0 0 9 845' Fow in (spm) 36 Gallons/stroke 2.8 Mud Data: Density (ppg) Viscosity filtrate PV YP Chlorides FC PH Solids Depth in out (sec/qt) (cc/30 min) cP (Ib/100ftz) (mg/1) (1/32") % 3450 11.5 ENNOMMMM 11.5 90 4.5 23 21 30,000 1/- 9.3 12.3 OEM= BIT DATA: Type Size TFA Hours Depth in / out Footage WOB RPM Condition Bit# 2 SecQHC1S 7.88 92.87 867' 2916 2049' 2-10 75-150 4,ss,A,A,1+/10,ER,pr/hr Bit # 3 FDS Smith 1 7.88 0.45 14.21 2916' 534 245' 2--12 75-150 New Lithology (%): Sd Sst Silt Siltst Cly Clyst Sh Lst Coal Tuff Chrt Connection Gas and Mud Cut Wiper Trip gas ft units ppg ft units ppg ft units ppg 24 hour Gas Breakdown Gas (units) Chromatograph (ppm) Bit Depth Max Average C1 C2 C3 C4 Tot C5 Tot Type to to to to to to to to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - pumps off gas 24 hr Recap: Schlumberqer completed wireline logging, RIH for C/O run then POOH and prep to run casing. Logging Engineer: Colby Marks/Daniel Sherwood * 10000 units= 100% Gas In Air i ■i■i M M M = M = r M = = w = = = ■s• HALLIBURTONWELL NAME: Moquawkie 4 OPERATOR: Aurora Gas, LLC CONTRACTOR: AWS -1 Sperry Drilling Services BIT RECORD LOCATION: Tyonek /. AREA: Moquawkie AIROM Gas, LLC STATE: Alaska BHA # Bit # Bit Type Bit I Size Depth IN Depth OUT Footage Bit I Hours TFA AVG ROP WOB max I RPM max SPP (max) FLOW GPM (max) Bit Grade Remarks 1 1 Sec XCL1 N 12.25 80 867 787 43.10 0.750 18.3 1-10 50-100 1160 450 Drill surface hole. Trip to p/u BHA 3 2 Sec QHC1S 7.88 867 2917 2049 92.87 0.520 32.2 2-12 50-150 1487 339 5.4.SS,A,E,1+?16,ER,PR/HR 4 3 Smith FSA 7.88 2917 3450 533 14.21 0.450 26.9 2-12 50-150 1906 302 new Drill to TD 5 4 Smith FSA 4.75 3450 3450 3 6.00 Drill out cement M 1=1 M M M M r M M M M M M M M M M M M HALLIBURMN Casing Record Company: Aurora Gas, LLC Area Cook Inlet, Moquawkie Field Sperry Drilling Services Well Moquawkie 4 Job No: AK -AM -0006174381 13-318" 80 ftMD Rig AWS -1 Spud Date 25 Sep 2008 9-5/8" 854 ft MD Water-based Mud Record Mud Co Baroid TD Date: 24 Oct 2008 5-1/2" 3427 ft MD Date Depth Wt Vis PV YP Gels Flit Rsoonnooinzooiwooirsm Cake Solids waterioii Sd Pm pH MBT Pf/Mf Chlor Hard Remarks ft - MD ppg sec Ib/100 ib/1OW m/30m Rheometer 32nds % % % ppm(k) Ca++ 15 26 -Se 179 9.00 57 3 7 2/3/3 8.0 13/10/7/5/3/2 1 1.1 97.0 0.01 0.10 9.0 2.5 0.10/0.30 22.0 60 Drill 121/4" hole 80-179 „ 27 -Se 240 9.00 73 11 23 9/14/17 7.0 45/34/38/21/10/8 1 1.1 96.0 0.01 0.10 9.0 2.5 0.10/0.20 35.0 80 Pick up BHA drill to 240' 28 -Sep 542 9.20 52 9 21 9/12/13 6.0 39/30/25/19/9/7 1 2.6 93.0 0.01 0.20 9.0 2.5 0.05/0.20 30.0 80 Drill 121/4" hole 240'-542' a 29 -Se 867 9.70 56 13 20 9/14/17 6.0 46/33/27/21/8n 1 4.6 91.0 0.01 - 8.0 2.5 40.15 42.0 80 Drill to 867', circ, take kick 30 -Sep 867 12.80 42 17 19 6/13/17 11.0 53/36/29/20/7/6 1 17.1 81.0 0.01 0.10 9.0 - 0.10/0.20 27.0 60 Weight up & kill kick 1 -Oct 867 12.80 44 19 22 7/11/15 10.5 60/41/32/22/8/6 2 16.3 82.0 0.01 0.20 10.0 2.5 0.10/0.20 23.0 60 Set Casing y` 2 -Oct 867 12.80 47 19 23 6/10/13 11.0 61/42/32/22/7/6 1 16.3 82.0 0.01 0.20 10.0 2.5 0.10/0.20 23.0 60 N/D diverter, Cut csg etc 3 -Oct 867 12.80 46 19 22 7/11/13 11.0 60/41/31/21/7/6 2 16.3 82.0 0.20 10.0 2.5 0.10/0.20 23.0 60 N/D BOP's & test BOP's 4 867 10.50 42 11 15 6/6/7 4.2 37/26/21/15/5/4 2 7.8 90.0 0.25 9.5 0.5 0.20/0.90 28.0 80 RIH &drill cement to 845 -Oct 5 -Oct 867 10.50 41 41 9 5/5/6 4.2 31/22/17/12/5/4 2 7.8 90.0 rO.2 0.20 9.5 1.0 0.20/0.80 28.0 80 CBL withSchlumbe er i) 6 -Oct 867 12.80 44 16 23 6/8/10 9.4 55/39/29/1917/6 2 17.3 81.0 0.20 9.5 2.5 0.10/0.40 24.0 80 Fish for E -Lo an 7 -Oct 867 12.80 46 32 12 6/8/8 10.4 76/44/33/20/6/5 2 18.0 80.50.20 9.5 2.0 0.15/0.25 21.0 40 Cement Squeeze Job8-Oct 867 12.80 46 32 12 6/8/8 10.4 76/44/33/20/6/5 2 18.0 80.5 0.20 9.5 2.0 0.15/0.25 21.0 40 WOW, Perferate & squeeze 9 -Oct 867 12.80 44 32 13 6/8/8 10.4 77/45/33/21/6/5 2 18.0 80.5 - 0.20 9.5 2.0 1 0.15/0.30 21.5 40 WOC, run 3 Ternp Logs = 10 -Oct 867 12.80 51 19 16 5/15/28 11.2 54/35/27/19/5/4 2 18.0 80.5 0.25 0.40 10.0 1.5 0.35/0.90 21.0 200 1130P Test, Squeeze Job 11 -Oct 867 12.70 38 16 14 4/10/14 14.2 46/30/23/15/4/3 2 19.0 79.5 - 0.40 11.9 2.0 0.30/0.90 22.0 300 Hold pres on Cmt, drl curt 12 -Oct 867 12.40 40 16 15 6/12/25 13.6 47/31/26/18/6/4 2 18.6 80.0 - 0.35 11.5 1.0 0.30/1.00 20.0 240 Drl cmtto 530', test cs p 13 -Oct 867 11.50 44 11 14 4/5/8 18.0 36/25/21/15/4/3 1 14.2 85.0 - 0.20 12.0 0.5 0.15/0.35 10.0 120 Mill EZSV, Mix mud a 14 -Oct 869 11.50 44 11 14 4/5/8 18.0 36/25/21/15/4/3 1 14.2 85.0 - 0.20 12.0 0.5 0.15/0.35 10.0 120 Reamin at Hole 15 -Oct 909 11.50 45 14 1 13 5/8/12 8.0 41/27/22/15/4/3 2 11.5 87.0 - 0.20 12.3 1.0 0.20/0.40 20.0 20 Drill 7 7/8" hole 867-909' 16 -Oct 1355 11.50 40 16 18 8/10/12 6.0 50/34/31/22/7/5 2 11.7 86.5 1.00 0.15 10.2 2.0 0.10/0.35 24.0 80 Drill 7 7/8" hole 909'-1355 a 17 -Oct 1450 11.50 40 17 19 8/14/15 6.2 53/36/29/20/7/5 2 12.9 85.0 1.00 0.10 9.6 3.0 0.10/0.20 29.0 140 jDrill 7 7/8" hole 1355'-1604' 18 -Oct 1701 11.60 47 14 21 6/9/12 2.3 49/35/29/21/7/5 2 12.6 85.5 0.50 0.55 9.0 3.5 0.20/2.30 25.0 240 Drill 7 7/8" hole 1604'-1701' 19 -Oct 2073 11.60 50 21 24 6/12/17 5.8 66/45/36/25/7/6 2 12.3 85.5 0.50 0.55 9.0 3.5 0.25/1.6 29.0 880 Drill 7 7/8" hole 1701'-2073 20 -Oct 2396 11.50 50 21 23 5/12/17 5.0 65/44/35/24/7/5 2 12.4 85.5 0.50 0.40 8.8 4.3 0.2/1.4 28.0 680 Drill 7 7/8" hole 2073'-2396 21 -Oct 2672 11.45 49 21 1 20 5/14/19 1.4 62/41/33/22/6/5 1/- 11.8 86.0 0.50 1.00 9.0 5.0 0.25/1.4 30.0 240 Drill 77/8"hole 2396'-2672 22 -Oct 23 -Oct 3097 11.45 51 19 19 5/14/17 5.3 57/38/29/1915/4 1/- 11.9 86.0 0.50 1.10 9.0 6.2 0.22/1.2 28.0 160 Drill 7 7/8" hole -3097' 24 -Oct 3450 11.45 53 21 21 5/15/19 4.8 63/42/32/21/6/4 1/- 11.8 86.0 0.75 1.20 9.2 0.8 0.28/1.2 30.0 120 Drill 7 7/8" hole 3097-3450 25 -Oct 3450 11.35 54 20 18 4/11/18 5.2 58/38/29/19/5/3 1/- 12.0 86.0 0.75 1.20 9.4 7.0 0.28/1.4 27.0 140 TestingBOP'S 26 -Oct 3450 11.45 72 23 21 5/15/21 4.9 67/44/34/22/6/4 1/- 12.3 85.5 0.75 1.20 9.3 7.0 0.28/1.3 30.0 120 Testing BOP's & R/U Wireline 27 -Oct 3450 11.45 90 24 21 5/15/21 4.5 67/44/34/22/6/4 1/- 12.3 85.5 0.75 1.20 9.3 7.2 0.28/1.4 30.0 120 Wireline L in 17.. -. 77M=77 MUM77--k u"M i_. -..ryi ,...._ x,N . - k i �_ Aurora Gas Moquawkie Days -vs- Depth 0 Prognosed Actual Drill 12-1/4" hole 500 Well ontrol, Set 9 /8" Casing, queeze cerr ent 1000 1500 t orat , &run comp tion 2000 L rill 8-1/2" H e N C� G 2500 3000 VTeg, Run 2-1l2" sg, Perf 3500 4000 0 5 10 15 20 25 30 35 40 45 50 Rig Days orat , &run comp tion