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Home My WebLink About205-097Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov December 13, 2021 Mr. J. Edward Jones Plugging Inlet, LLC 6733 South Yale Avenue Tulsa, OK 74136 Re: Location Clearances Aspen 1 (PTD #2051110) Moquawkie 1 (PTD #2030690) Kaloa 2 (PTD #2040960) Moquawkie 3 (PTD #2050800) Lone Creek 1 (PTD #1980840) Moquawkie 4 (PTD #2070840) Lone Creek 3 (PTD #2050970) Simpco Moquawkie 1 (PTD #1780470) Lone Creek 4 (PTD #2070910) Simpco Moquawkie 2 (PTD #1780880) Dear Mr. Jones: On December 20, 2019, the Alaska Oil and Gas Conservation Commission (AOGCC) received the final Well Completion Reports for the plugging and abandonment of the following wells: Aspen 1, Kaloa 2, Lone Creek 1, Lone Creek 3, Lone Creek 4, Moquawkie 1, Moquawkie 3, Moquawkie 4, Simpco Moquawkie 1, and Simpco Moquawkie 2. On June 15, 2021, AOGCC waived witness of each location status and an environmental site assessment (ESA) was conducted by Environmental Management, Inc. on June 17, 2021. AOGCC received a copy of the ESA report along with accompanying photographs of each site on December 7, 2021. Each drill site was found to be in compliance with onshore location clearance requirements as stated in 20 AAC 25.170. The AOGCC requires no further work on the subject wells or locations at this time. However, Plugging Inlet, LLC remains liable if any problems were to occur with these wells in the future. Sincerely, Jessie L. Chmielowski Jeremy M. Price Commissioner Chair, Commissioner May 13, 2020 RECEIVED MAY 18 2020 Jeremy M. Price, Chair AOGCC Alaska Oil and Gas Conservation Commission 333 West 7"' Ave., Suite 100 Anchorage, Alaska 99501 RE: Request for Information 20 AAC 25.300 Docket Number: OTH-20-035 Costs to Plug and Abandon Wells on CIRI Leases Dear Mr. Price: Regarding your letter to me of May 1, 2020, the following information is responding to your request for costs incurred to plug and abandon the following wells on mineral interests owned by Cook Inlet Regional, Inc. (CIRI): • ASPEN 1 – API 50-283-20114-00-00 • KALOA 2 – API 50-283-20107-00-00 • LONE CREEK 1– API 50-283-20096-00-00 • LONE CREEK 3 – API 50-283-20112-00-00 • LONE CREEK 4 – API 50-283-20121-00-00 • MOQUAWKIE 1 –API 50-283-10019-90-00 • MOQUAWKIE 4 – API 50-283-20120-00-00 • SIMPCO MOQUAWKIE 1 –API 50-283-20060-00-00 • SIMPCO MOQUAWKIE 2 – API 50-283-20062-00-00 Plugging Inlet, LLC, was the operator of these wells and conducted plugging and abandonment (P&A) operations between October 2018 and November 2019. Costs were tracked on the basis of vendors, not by well or activity. Thus, while some costs, totaling about $1,007,000, were paid to vendors who worked solely on the P&A of the wells (e.g., Schlumberger, Pollard Wireline, and Halliburton), most of the vendor;/contractors also worked on DR&R, cleanup, and waste disposal operations. Thus, the costs of these vendors/contractors for P&A operations were estimated on the basis of the Summary of Operations, based on the daily reports—these include camp costs, air and marine transportation, supervision, welder and roustabouts, trucking, and equipment rental. It is estimated that another $595,000 were paid to these other contractors and vendors for services supporting P&A work for a total estimated cost to P&A the 10 wells of $1,602,000, or $160,200 per well. However, one well, the Lone Creek 1, was particularly problematic to P&A due to its original construction, and the cost to P&A that well is estimated at about $244,000, leaving the average cost to P&A the other 9 wells at $151,000. For clarity, the reported $1.6 million is for actual well plugging and abandoning costs only; in addition, Inlet Plugging LLC incurred approximately $3.4 million for associated lease remediation activities, including required deconstruction & removal of surface production equipment and restoration of the sites, cleanup of contamination (mostly compressor oil leaks under buildings and some small spills), disposal of waste (including historic drill cuttings and mud solids, contaminated gravel and soil, and used oil and glycol), required Mr. Jeremy M. Price 5/13/20 Page 2 surface use payments, transportation of salvaged equipment and waste, and associated expenses. If you have any questions or require additional information, please contact me at 713-899- 8103 or by email at jejones@aurorapower.com. Sincerely, �ZG 9!Edward Jones Operations Consultant for PLUGGING INLET, LLC 6733 South Yale Avenue Tulsa, OK 74136 CC: Suzanne Settle and Colleen Miller, CIRI Thomas Redman, Jim Sullivan, Mark Can, Plugging Inlet, LLC THE STATE "ALASKA May 1, 2020 GOVERNOR MICKNE•L I. DUNLEAFY J. Edward Jones Operations Consultant Plugging Inlet, LLC 6733 South Yale Avenue Tulsa, OK 74136 Re: Request for Information 20 AAC 25.300 Docket Number: OTH-20-035 Dear Mr. Jones: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.alaska.gov The Alaska Oil and Gas Conservation Commission (AOGCC) requests documentation of the actual costs incurred to plug and abandon the following wells: • ASPEN 1 —API 50-283-20114-00-00 • KALOA 2 — API 50-283-20107-00-00 • LONE CREEK 1 —API 50-283-20096-00-00 • LONE CREEK 3 —API 50-283-20112-00-00 • LONE CREEK 4—API 50-283-20121-00-00 • MOQUAWKIE 1 —API 50-283-10019-90-00 • MOQUAWKIE 4 — API 50-283-20120-00-00 • SIMPCO MOQUAWKIE 1 —API 50-283-20060-00-00 • SIMPCO MOQUAWKIE 2 —API 50-283-20062-00-00 The wells are located on mineral interests owned by Cook Inlet Regional, Inc (CIRI). In 2017, Plugging Inlet, LLC was designated operator of record for the wells. This request is made pursuant to 20 AAC 25.300. Should you have any questions about the information request, please contact Guy Schwartz at 907-793-1226. Sincerely, v Jeremy M. Price Chair, Commissioner cc: Suzanne Settle VP Energy, Land, Resources CIRI itCIRI January 14, 2020 James Regg, Senior Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West 71h Avenue, Suite 100 Anchorage, AK 99501 �T ons WrInVeColprwation RE: Onshore location clearance, Plugging Inlet Site located: T12 N R12W, T12N Ri1W, T11N R12W, T12N R11W SM Dear Mr. Regg: This letter is submitted to formally request that the Alaska Oil and Gas Conservation Commission (AOGCC) withhold the site clearance at the location formerly operated by Aurora Gas, LLC. Tyonek Native Corporation (TNC) and Cook Inlet Region, Inc. (CIRI) are the majority landowners within the area and did not have the opportunity to conduct an on-site inspection prior to the 2019 snowfall. CIRI and TNC will conduct an on-site inspection of the property in the spring to ensure the site is reclaimed to the satisfaction of both landowners. TNC and CIRI appreciate the AOGCC's continued cooperation during this process. If you have any questions, please contact Suzanne Settle at (907) 263-5150 or Connie Downing at (907) 272-0707. Sincerely, Tyonek Native Corporation 1 Connie J. Downing Chief Administrative Officer Cook Inlet Region, Inc. Suzanne Settle VP, Energy and Infrastructure Colombie, Jody J (CED) From: Regg, James B (CED) Sent: Monday, January 6, 2020 12:26 PM To: Colombie, Jody J (CED) Cc: Schwartz, Guy L (CED) Subject: FW: Site Clearance - Plugging Inlet See email from CIRI below. Looks like we received the 407s for these December 20 according to the 400 -Logs. Plugging Inlet dragged out the P&As so long this past fall that we were unable to get to locations for site clearance inspections before weather turned (actually had an Inspector and CIRI rep at the airport ready to fly over for site clearance inspections but flights were canceled for weather and there has been snow on the well sites since). Wells affected are: - Aspen #1 (PTD 2051110) - Kaloa #2 (PTD 2040960) - Lone Creek #1 (PTD 1980840) - Lone Creek #3 (PTD 2050970) - Lone Creek #4 (PTD 2070910) - Moquawkie #1 (PTD 2030690) - Moquawkie #3 (PTD 2050800) - Moquawkie #4 (PTD 2070840) - Simpco Moquawkie #1 (PTD 1780470) - Simpco Moquawkie #2 (PTD 1780880) Jim Regg Supervisor, Inspections AOGCC 333 W.7'^ Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or iim.reggPalaska.eov. From: Colleen Miller <cmiller@ciri.com> Sent: Monday, January 6, 2020 11:09 AM To: Regg, James B (CED) <jim.regg@alaska.gov> Cc: Connie Downing <cdowning@tyonek.com>; Suzanne Settle <SSettle@ciri.com>; David Kroto <dkroto@tyonek.com> Subject: Site Clearance - Plugging Inlet Good Morning Jim. I hope you had a great holiday! I'm writing to let you know that CIRI and Tyonek will be issuing a joint letter to request that the AOGCC withhold the site clearance on the Westside until CIRI and Tyonek have an opportunity to get boots on the ground in the spring. As always, please call me if you have any questions. Colleen 263-5117 The information contained in this CIRI email message may be privileged, confidential and protected from disclosure. If you are not an intended recipient, please notify the sender by reply email and delete the message and any attachments immediately. The use, disclosure, dissemination, distribution or reproduction of this CIRI message or the information in it or attached to it by any unintended recipient is unauthorized, strictly prohibited by the sender, and may be unlawful. Thank you. The information contained in this CIRI email message may be privileged, confidential and protected from disclosure. If you are not an intended recipient, please notify the sender by reply email and delete the message and any attachments immediately. The use, disclosure, dissemination, distribution or reproduction of this CIRI message or the information in it or attached to it by any unintended recipient is unauthorized, strictly prohibited by the sender, and may be unlawful. Thank you. 2 -00 DLB DLB 03/25/20 DSR-3/25/2020 xG MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim ReggT�c I Z �, f DATE: P. I. Supervisor l l FROM: Lou Laubenstein SUBJECT: Petroleum Inspector 10/24/19 Surface Abandonment Lone Creek #3 - Plugging Inlet LLC PTD 2050970; Sundry 318-340 10/8/19: 1 arrived on location for the surface abandonment inspection on Lone Creek #3. David Wallingford was the Company representative on location for the day's inspection. Solid cement was confirmed at surface in the cutoff well. The casing cutoff depth was only cut to 3-4 feet below the current pad grade and not the proper depth of 3 feet minimum below original ground level — this was discussed with Mr. Wallingford. The hole was filled with debris and trash that needs to be removed prior to backfill. Also, there is another piece of casing that was used during the drilling process that should be cut off to the proper depth. I departed location and communicated the deficiencies to AOGCC Inspection Supervisor Jim Regg. 10/24/19: 1 arrived on location for a second inspection to check for proper cut-off depth of the well. The casing had been cut to the required 3 feet below natural grade satisfying the current regulation. Information on the marker plate was verified and installed. Attachments: Photos (4) 2019-1024_Surface_Abandon _LoneCk-3 11.docx Page 1 of 3 ! OF ��° I F Ya 4114jr t d" "a `' e ' 9 a . b 2y a• . :,�� O p a :A �U in It A P tx,ti �`Y til �•�* W • rr +' � i `~ tF�`',� t 1 i 1��. � eas {;z ♦ � �- � F ; ,�►� i i 9 y T 44 S. ;s, Mcphee, Megan S (DOA) 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 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 aovI. 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 sijckline 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-204096: 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 i—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) [ma ilto:lzuy.schwa rtz@alaska eovl Sent: Monday, March 04, 2019 1:30 PM To: Ed Jones <jejones@auroraoower com> Cc: George Pollock <gpollock(@auroraoower 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 (907-793-1226 ) or (Guy schwariz@alaska aov). of Tye • • 9 �\oyyy � • THE STATE Alaska Oil and Gas 4, of LAc Conservation Commission A333 West Seventh Avenue k ►�; e, Alaska 99501-3572 Anchorage,GOVERNOR BILL WALKER g re Main: 907.279.1433 OF ALAS' Fax: 907.276.7542 www.aogcc.alaska.gov George Pollock A orManagea Gas, LLCr pNNED SEP 12,0 17, 1400 W Benson Blvd., Suite 410 Anchorage, AK 99510 Re: Lone Creek Field, Undefined Gas Pool, Lone Creek 3 Permit to Drill Number: 205-097 Sundry Number: 317-409 Dear Mr. Pollock.: 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, Cathy Foerster e1A-day Commissioner DATED this of September, 2017. RBDIV[S j,k/ SEP - 7 2017 . - • • Aura Gas, Operations Summary Set Temporary Plug Lone Creek#3Well july24,2017 1100 hours Mobilize to location from LC1 1130 hours R/U WL, PT lubricator w/wellbore -1200-hours -RIH-w/2.33"-gattge-rirtg-to-1270"—KB,Tag-nipple,-POOH 1230 hours RIH w/2.4"brush to 1270',brush profile,.POOH 1300 hours RIH w12-7/8"X-Line w/PX Plug to 1270',WT,set plug,POOH 1330 hours RIH w/2" SB w/Prong to 1270',WT, set Prong, POOH 44004otws „Bleed-offwell,_monitor=Pressure 30-minutes,Pressure-=-50 PSI,=Fail 1430 hours RIHw/2"gauge ring to 1270',WT,tap downon Prong, POOH 1500 hours Bleed off well,monitor Pressure 30 minutes,Pass 1600 hours RD WL r • • Aurora Gas, LLC ' V. 4', ...' 'r 27/86.5#8rdELT J-55 Tubing LONE CREEK UNIT . ,4A. .,_ , , , =` 44 #3 ,, PTD#: 205-097 $ .-{ 11-7/8"71.8#Structural API#:50-283-20112-00-00 *. Conductor driven to 80'GL RKB 14.4ft _4 As Run October 2013, 8-5/8"32#Surface Casing set at Updated July 2017 700' Cement w/145.ppg Gas-Block • " '' "I enhanced Cement Drill 10-5/8"Hole to 710' . 2-7/8" a 5-1/2"annulus displaced with 10.4 ppg 3%KCl- NaCl-Naar packer fluid XA Sliding Sleeve @ 1265' • PJC Plug @1270' ,, . _ ►lit� ' AL Hy Packer at 1308' w/On-Off Tool at 1306' Carya 2-1 1348-58' �.. t I1Shrouded 1378-98 ... - Sliding Sleeve at 1381' 1408-18' NM s, (o pe* 1445-65' _i.,; .�_'>'. Carya 2-2 Hydraulic Set Packer(a?,1579' 1674-82' — „G Shrouded Sliding Sleeve at 1660' New, ¢-". 1 _ 4 (Open 12/16/15) LL, Hydraulic Packer at 1705' Carya 2-3 , ,� Shrouded Sliding Sleeve at 1752' ., t- =• 1798-1818' tOnen 1011551 NeN i" « * e Hydraulic Packer @ 2052' Carya 2-4.1 • « ,,:* 2092-2106' •$/ ' NosShrouded Sliding Sleeve @ 2100' (Open on 1/28/15) Hydraulic Packer @ 2208'w/ Carya 2-4.2 On-Off tool*2206' 2282-2317' Shrouded Sliding Sleeve at 2252' (Closed) 2363-78' Carya 2-5.1 -2420-25' """ --... Carya 2-5.2 2620-70' ""` Ell Permanent Seal-bore Packer @ 2841'with Carya 2-6 2796-2816' ' ' j X nipple at 2848'w/PX plug ' If TOT @2860' 284,4-64 P1TD @ 2928'MD 5-1/2"17#2-55 Casing to 3018'MD cemented Drill 7-7/8"Hole to 3025'MD, w/34 bbf 13.5 ppg lead+79 hbf 15.8 ppg tail 3015'TVD • • 0 • RECEIVED , STATE OF ALASKA '73-'5 AUG 2 5017ci (pi t 7 ALASKA OIL AND GAS CONSERVATION COMMISSION AOG - -* APPLICATION FOR SUNDRY APPROVALS 20 AAC 25 280 r- n---,1Type of Request- Abandon __ Plug Perforations ...:-:: Fracture Stimulate , Repar'Ned r---- Operations snUfdowri ' __.. Suspend :11 Pe _ rforate i Other Stimulate - : Pub-oiaing 7 :Thenitkci ce oonvec Progofam li i..._... Plug for Redd! 71 Perforate New Pool .11; Re-enter Suso Welt r-_-„ Alter Casing LOther.Te11001ary Plug 2 Operator Name. 4- Current Weil Class 15 Penh,:to Dft'Nt;mcat. 'Aurora Gas,LLC .. Exploratory , ; Development 1.---. 205-39:7 • 13.Address. O0 W.Benson Blvd Suite 410 ,-- 6 A„cfi Ni2,rnoe, Stratigraphic Servf. __ , Anchorage.AK 99503 I l i I -- 7 If perforating. 18 Weil Name and Numoer What Regulation or Conservation Order governs wet'speong,n this poo'' P- Lone Creek 3 ' Will planned perforations require a spacing exception"; Yes ,_ No / *b i 9 Property Designation(Lease Numbefi. 1 16. cos, C-061500 ' ( Lone Creek Undefined Gas • 11 PRESENT WELL cosornott SUMMARY Total Depth MD(ft) 'Total Depth TVD tfti 'Effective Depth MD. !Effective Depth TVD I-MPSP ipsiji. 1Pcgs.MDi !dunk ND) 3025' • 1 3025' N 2968' ' ; 2968' , i 375 Ps; i 2E43 None Casing Length Size I MO TVD Burst i Collapse Structurati { Conductor I 80' 11 718"72* 1 30' i 30" i I Surface 700" 6,5.'8"32*N80 I 70,3' I 7:"."(3' I 1 ':'',:',...'s i 335.0;..'s. Intermediate Production 3018' 1 5 lir 17*.)55 3013' i 3018' 522C CS.i 4910 psi 1 4 1 I I I Liner Il I i i i i i Perforation Depth MO e,ftt: 'Perforation Depth TVD fftl. iT,...1bir,ro Size. Tubing Grade „,,,tt In;VD,ft 348'-2884. • 1348"-2864' I 2 718" 5 5=..!,55 2963' Packers and SSSV Type: !Packers and SSSV MO(ft l and TVD-hi Hydraulic set and permanent seabore packers l',-tydraultc g 1308* 1579'175Z&222-3'so Pe-Tanen':seal core t 234-• , „ 12. ,4 Attachments: Proposal Summary 12.: Wellbore schematic 7' 13 13 Well Class alter proposed work: I __..... ......_ 'Detailed Operations Program - BOP Sketch , ' , Exploratory _ Suatchapr C _ 'elx,Ttetf: :.:Li - Seh,.cc 14.Estimated Date for TBD (15.Well Status after proposed work Commencmg Operations !al._ 11, WIN..J --- if,:SP.... I Susnehded --, 16 VerbalApproval Date GAS WAG .,,,..,j (:,,STOR ,,, j SPLLG -- O.:Sri.:...:ott- I, . ..- .:.3 -7 ! Commission Represen,tat,ve GiN, ,-- neic ....'.._ • I — 17 I hereby certify that the foregoing is true and me procedure approved heren will no,: be deviated from without prior written approval 1 Authorized Name, George Pollock Nae -GPonoe 0.i'iO.C., Contact n^ - Authorized Title- Manager-Pr s&Eng Contact Erna,, .,, Contact P-i:ne 91:T-7.K'--81,7j147: Authonzed Signature. .0.- ___ Date 24-Aug-17 COMMISSION USE ONLY Conditions oc approvai. Notify Commission so that a representative may witness Izzaffh'*1 ',4u,:r1)5:- 1 3 t 7— '10 1 'NI integrity _A BOP Test _ Artechanical tmegnty Test , , Location Ciearainni Other i PtiOW 1-30L.A.A.V-4 01- 1: C_Ae ILe. CAKti- OFF t N1/4AkeV--e.17-- ruAlc , Post Mittel injection MIT Reo'd7 Yes Spacing Exception Required? Yes ri, No / Subsequent Form Required. \0--401 RBDMS 1L- FD - 7 2017 APPROVED BY Approved by ij 0-e11-0•—•—"' COMMISSIONER THE COMMISSION Date q_ _/7 -Pm gl oli?-. 4,64 /7 MA-V.-._ Otli I li Subs-1z Form and Form f7i-403 Revsed 5,2017 lt,• • °It • ' alid for 12 months from the date of approval. ktoo-t-e---m.,.-.-,Duoitate • • AURORA GAS, LLC WELL ABANDONMENT LONE CREEK UNIT#3 August 2017 Version 2.1 (8/14/17) CURRENT CON 'ON CURRENT STATUS : Shut-in with PX plug set in profile at 1265' Last SITP-400 psi; last Test: Flowing 80 mcfpd at 130 psi with 6 BWPD. KB=14.4 feet CASING: 5-1/2", 17# J-55 set at 3018'MD/3010' TVD. TUBING: 2-7/8",6.5#J-55'8 rd EUE,w/ 10.4ppg KCI-NaCl-Naar'°brine as packer fluid in tbg-csg annulus above top packer and with: Sliding Sleeves at: XA at 1265'(closed—opens upward--closed); Shrouded XO at 1381' (open); Shrouded XO at 1660' (open); Shrouded XO at 1754' (open); (open); Shrouded XO at 2100' (open), and Shrouded XO at 2256' (closed). All sleeves have 2.31"X landing nipple just above opening. Packers: HRP's at 1308', 1579', 1705',2052', and 2208' with on-off tool at 2206'. Permanent Seal-Bore Packer at 2841' with PX plug in X nipple at 2848'. EOT-2860'. (see attached well bore and:completion diagrams) CAPACITIES: 2-7/8" 6.5# J-55 EUE Tubing: 0.00579 bbl/ft; (Burst rating=7260 psi). Tubing-Casing Annulus: 0.0152 bbl/ft; 5-1/2", 17# Casing: 0.0232 bbl/ft. Tubing volume to PX plug at 2'848'=16.5 bbl, PERFS: Carya 2-1 at 1348-58', 4378-98', 1408-18', and 1445-65'. Carya 2-2 at 1674-82, Carya 2-3 at 1798-1818' Carya 2-4.1 at 2092-2106' Carya 2-4.2 at 2282-2317', 2363-78' behind Sleeve at 2206' Carya 2-5.1 at 2420-25' also behind Sleeves at 2206' Carya 2-5.2 at 2620'-70" behind Sleeve at 2206' Carya 2-6 at 2796-2816', 2830-40'behind Sleeve at 2206' 2844-64' below packer and plug at 2841' NOTES: 1) Well essentially a straight hole. SUMMARY OF PLAN: Set BPV. Replace master valve. Pull BPV. RU slickline. Pull PX prong and plug at 1265'. Open sleeve at 1265' and dump 10.4ppg Kcl-NaCl-NaBr brine into tubing to kill well—add additional clean produced water to tubing and annulus to fill if needed to kill(not likely). Run gauge ring on slick line and tag fluid level and bottom. Close all sliding sleeves.fill tubing and casing with-clean field produced water or 3%KCl water. Run CIBP for • • 2-7/8"tubing and set in top of top packer at 1308'. Test CIBP to 1500 psi. Run tubing perforating gun and perforate tubing at 1300' with 4 SPF. RU cementers on tree(thru wing valve). Establish circulation pressure with 5-10 bbl KCl water at 3 BPM. Pump 140 sx(161 cf-28.7 bbl)Class G cement(15.11 ppg, 1.15:cf/sk yield) with pump time of 4 hr at 70 degrees- 4%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 plug. Monitor for flow or fall back. Wash out tubing casing annulus to 3-4' below GL. WOC 8 hrs,pressure test to 1500 psi. Bleed off pressure. MI crane. Remove tree. Cut off casing strings and tubing 3-4' below GL. Mix any cement needed to fill any casing sting or tubing to cut-off Weld on permanent marker cap. Call inspector. Upon approval, remove cellar and bury marker. Remove surface equipment from location. Grade,locations Take soil samples for confirmation of no contaminants. DETAILED PROCEDURE: I) Pick and move we lhouse. Notify AOGCC inspector of plans for plugging operations. 2) Mobilize GE wellhead service man. Check well for surface—should be 0. Set BPV in tubing hanger, Remove and replace leaking master valve. Pull BPV, release GE. 3) 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. 4) RU slickline lubricator on tree. RIH and pull prong from PX plug at 1265' KB (1270' SLM). Allow pressure to equalize (expect maximum of 400 psi). Check lubricator and tree for leaks. If none,pull PX plug body. V5) Kill well by opening sleeve at 1265' and dumping 10.4 ppg Kcl-NaCI-NaBr packer fluid from annulus into tubing. Allow tubing to stabilize, bleed off pressure. Add clean produced water of 3%KC1 water to fill tubing and casing if needed to kill well. (Tubing volume to deepest open sleeve is 12.2 bbl). 6) Run 2.25"gauge ring(GR)to check for fluid level and tag bottom (expected to be 2848',top of PX plug in pup joint below permanent packer). Tf restrictions are found`, rumbailer, brushes,etc.to cleanout to about 2300'. 7) RIH with shifting too. Confirm that sleeve at 2256' is closed and close sliding sleeves at 2100', 1752', 1660', and 1381'. Fill tubing and casing—close sleeve at 1265'. Pressure up on tubing to 1500 psi to confirm that all sleeves are closed. Release pressure. RD slickline lubricator. 8) RU electric line lubricator(see Note I below). I U CIBP for 2-7f8"CIBP,RIH and set inside top packer at about 1308'. 'PO( . teure test CIBP to 1500 tis i. Release pressure, PU 1- 1/2" gun with 4 SPF for large holes,RIII, tag CIBP,pull up to 1300', and perforate 4 shot in 1' at 1300' . POOH. 9) 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,10.4 ppg KCI-NaC1- NIaBr brine—cateh and use subsequent wells.Mix and pump 140,sx Class G cement (accelerated for 4 hours pump time at 70 degress,15.&ppg, 1.15 disk yield),clown tubing, circulating cement to surface (4%excess). Catch annular brine for use in subsequent welts, • • divert to open tank as soon as returns are cement colored. This is tobe a balanced plug— monitor for flow or fall back. 10)When cement top is stable, disconnect cementer. Wash out tubing, and tubing-casing annulus to 3-4' below GL. WOC S hours. Pressure test,be&sides(tubing andannulus)to 1500 psi.Release pressure. MI crane. Remove tree. Cut off conductor,surface, and e,N*aa-T production casing strings and tubing 3-4' below GL. Mix any cement needed to fill any , F1). casing sting or tubing to cut-off. Release cementers and slickline units to next location. "30 11)Fabricate 1/4" steel marker-plate cap for 11-7/8" conductor casing,not to extend beyond casing OD, and bead-weld the following information onto marker plate; a. Aurora Gas, LLC rir+o-to co(.A...A6,6,4 G L.,ct- ( c A b. PTD #205-097 err (w.k2uFsc. eL.... e- c. Lone Creek No. 3ttK 10-40-1Yv► d. API# 50-283-20112-00 , 12)Following any necessary inspections,remove cellar and bury marker. Dispose of any waste. Haul KC1 water,tanks, and any support equipment to next location. 13)Remove tree and casing/tubing cut-offs, surface production equipment,trash, and any other materials from the location. Clean up,;gradeand level location. Take soil samples and send to dab to confirm no contamination. J 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. Ed Jones (8/14/2017) urs 0' so%id /Wadi,oh04 rie welt U.Ctt!<� �- Cc,�cur. /�'1r-e! jr recofplere The we I/ au ev ocrofer 26l6 �rtf�/ f 1° 0 v r I. '4/ lJ ✓fe (PI c0 ex r 0,-At D r C* r6 hG r'�1nc 1 rd o�VG�Z(� M n0!off,ate ' tvei r 1 �,f r+ �� or r � � 00/' • • I Aurora Gas, LLC 2 713 6.5#8rd ECCE.1-55 Tubing LONE CREEK UNIT ", r ` #3 P #•205-097 , _ 11-7/8"71.8#Structural API#•50-283-20112-00-00 Conductor driven to 80'GL RKB•14.41t .s As Run October 2013, 1 i 8-5/8"32#Surface Casing set at Updated 1/16 { 700' f j Cement w114.5.ppg Gas-Block • enhanced Cement Dry to-5/8'fie to 71W 2-7/8" x 5-1/2"annulus *,', displaced with 10.4 ppg 3%KC1- La , , ' NaCl-Naar packer fluidst 4; XA Sliding Sleeve n 12,65' Hydraulic Packer at 1308' w/On-Off Tool at 1306' »e Carya 2-1 . .:.r 1348-58' tiii 114 OS Shrouded 1378-98' "`_ `„,,,21i.-hasSlydin Sleeve at 1381' 1408-18' S . ( n) 1445-65' w_ All new ItYli -0 Carya 2-2 ' , Hydraulic Set Packer*1579' ”„ 1674-82' "'. ",; Shrouded Sliding Sleeve at 1660' Ems 12/16/15) Hydraulic Packer at 1705' Carya 2-3 Shrouded Sliding Sleeve at 1752' 1798-1818' ,�1 Z.--V--" (Oven 10/151 N4 4. Hydraulic Packer(a`2052' Carya 2-4.1 2092-2106' Shrouded Sliding Sleeve v 2100' _.4, ". (Open on 1/28/15) Hydraalc Packer @ 2208'w/ Cary.a 2-4.2 (3n-Of1 toot'@2286' 2282-2317' Shrouded Sliding Sleeve at :: 2252' (Closed) 2363-?8' Carya 2-5.1 -2420-25' "- .., .: Cana 2-5.2 Ma in 2620-70' kisi MB Larva 2-6 2796-2816' Permanent Seal-bare Packer®2841'with 2830 40' .5 X nipple at 2848'w/PX plug 2811 64' FOO a 2860' PBTD @ 2928'MD 5-'1/2"1'#.1-55 Casing to 3018'Ml)cemented Drill 7-7/8"Hole to 3025'MD, wit 34 bbl 13.5 ppg lead-4-79 bbl 15.8 ppg tail 3015'TVD • 0 = Aurora Gas, LLC _ --__ 2 7/8 6.5#8rd EUE 3-55 Tubing LONE CREEK UNIT ,' ` 1 # #3 ( • 1 PTD#:205-097 .; API##:50-2S3-20112-00-00 11-7/8"71.8#Structural RKB 14.4ftConductor driven to 80'GL PROPOSED PLUG& ',' . ABANDONMENT g Drill 10-5/8"Hole to 710' 8-5/8"32//Surface Casing set at 700' 2-7/8" z 5-1/2"annulus displaced with 10.4 ppg 3%KCI- r Cement w/14.5„ppg Gas Black NaCl-NaBr packer fluid . # ,•+ , ! enhanced Cement "COMBINATION" PLUG— 135 SX, 1300'to Surface-3' *1 ,, (Plugging Perls,surface casing ` sloe,and sa face) XA Sliding Sleeve @ 1265' , . -. PERF TUBING AT 1300' Tubing CIBP at 1308' DEPTHS TO SCALE Carya 2-1 i ' ,' Hydraulic Packer at 1308' 1348-58' T w/On-Off Tool at 1306' 1378-98' siair ►!/ Shrouded Sliding Sleeve at 1381' 1408-18' -,, 1445-65' ,0_ _ " Hydraulic Set Packer @ 1579' Shear-out Safety joint @1590' Cary*2-2 :IR Shrouded Sliding Sleeve at 1660' 1674-82' F. ` Hydraulic Packer at 1705' Carya 2-3 ' Shrouded Sliding Sleeve at 1752' 1798-1818' 41 "CY Hydraulic Packer @ 2052' Carya 2-4.1 Shrouded Sliding Sleeve 2042-2106' -, _ 2100' Hydraulic Packer®2208'11/On- Carya 2-4.2 $ 4' Off tool®.2206' 2282-2317' II Shrouded Sliding Sleeve at 2252' 2363-78' Carya2-5.1 -2420-25' Carva 2-5.2 2620-70' Carya 2-6 2796-2516' _...' 2830-40' Permanent Seal-bore Packer n2841'with 2844-64' ' 13 X nipple at 2848'w/PX plug letii PBTD @ 2928'MD '� _ EOT @28611' Drill 7-7/8"Hole to 302_5'MD, P 5-1/2"17#355 Casing to 3018'MD cemented 3015'TVD w/34 bbl 13.5 ppg lead+79 bbl 15.8 ppg tail • ti OF T�� • • 4w\-„ lyy� s THE STATE Alaska Oil and Gas �} �, Of e T e C Conservation Commission :. 1ZL1ZV}(j\S t �� 333 West Seventh Avenue k. �.: ' GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 ^h. - _ Main: 907.279.1433 C)F ALA �� Fax: 907.276.7542 www.aogcc.alaska.gov George Pollock Manager ® ,1iit. ' 2D17,Aurora Gas, LLC " 1400 W. Benson Blvd., Suite 410 Anchorage, AK 99503 Re: Lone Creek Field, Undefined Gas Pool, Lone Creek 3 Permit to Drill Number: 205-097 Sundry Number: 317-271 Dear Mr. Pollock: 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, 62T --- Hollis S.French �L Chair DATED this -4 day of July, 2017. RBDMS L L JUL 1 1 2017 • 0 RECEIVED STATE OF ALASKA jUN 1 6 2017 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS AOGCC 20 AAC 25.280 1.Type of Request: Abandon 0 Plug Perforations 0 Fracture Stimulate 0 Repair Well 0 Operations shutdown 0 Suspend 0 Perforate 0 Other Stimulate 0 Pull Tubing 0 Change Approved Program 0 Plug for Redrill 0 Perforate New Pool [] Re-enter Susp Well 0 Alter Casing 0 Other Temporary Plug 0• 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number Aurora Gas,LLC Exploratory 0 Development 0• 205-097 • 3.Address: 1400 W.Benson Blvd.Suite 410 n 6.API Number Stratigraphic 0 Senrice Anchorage,AK 99503 50-283-20112-00 ' 7.If perforating: 8.Well Name and Number What Regulation or Conservation Order governs well spacing in this pool? Lone Creek#3 Will planned perforations require a spacing exception? Yes 0 No 0 9.Property Designation(Lease Number): 10.Field/Pool(s): C-061500 '- Lone Creek Undefined Gas • 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth ND(ft): Effective DepthMI& Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): 3025' • 3025' • Z1443:2928- ,4,-o i'iCkgskar--4 0- 7.--4-1 7 375 psi 2848° None -1- Casing Length Size MD TVD Burst Collapse Structural Conductor 80' 11 7/8"72# 80' 80' Surface 700" 85/8"32#N80 700' 700' 5710 psi 3050 psi Intermediate Production 3018' 5 1/2"17#J55 3018' 3018' 5320 psi 4910 psi Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(it): 1348'-2864' 1348'-2864' 2718" 6.5#J55 2860° Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): Hydraulic set and permanent seal bore packers Hydraulic @ 1308',1579'1752°&2208'and permanent seal bore r 2841' 12.Attachments: Proposal Summary 0 Wellbore schematic 0 13.Well Class after proposed work: Detailed Operations Program 0 BOP Sketch 0 Exploratory 0 Stratigraphic 0 Development 0 . Service 0 14.Estimated Date for TBD 15.Well Status after proposed work: Commencing Operations: OIL 0 WINJ 0 WDSPL 0 Suspended 11 16.Verbal Approval: Date: GAS • WAG 0 GSTOR El SPLUG E Commission Representative: GINJ 0 Op Shutdown D Abandoned 0 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. George Pollock George Pollock Authorized Name: Contact Name: Authorized Title: Manager-Pr ps&Eng Contact Email: a pollock aaurorapower.com -',% -2------- Contact Phone: 907-277-1003 Authorized Signature: .0 Date: 16-Jun-17 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number 27 Plug Integrity 0 BOP Test 0 Mechanical Integrity Test 0 Location Clearance 0 Other: * .--)--- 1 Et•ArOTZV-4 flAkt, Pee-t, k•'t-7.- Pi1/4 Cr i-Z-kMkAtRetskaSITS c-CW--• -SV`CPC-1"4Strii° 0 11- 4. 461/4 Post Initial Injection MIT Req'd? Yes LI] No 0 Spacing Exception Required? Yes Eil No V Subsequent Form Required: k-u . 4Q4- RBDMS t JUL 1 1 2017 APPROVED BY Approved by: tif2127—\_,.....- COMMISSIONER THE COMMISSION Date: ' I 1 k' , .. CA t‘A-E-v -ill n AI- 7-s-•/7 Submit Form and Form10-44evised 4/2017 0 Rierilt+A Ladd for 12 months from the date of approval. Attachments in Duplicate 1 I .de t 47 • • Aurora Gas, L June 16, 2017 Ms. Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 7 'Avenue, Suite 100 ��ItE ri Anchorage, AK 99501 JUN 6 lorf � 201? Re: Application for Sundry Approval—Set Temporary Plug Lone Creek#3 Well PTD #: 205-097 API #: 50-283-20112-00 Dear Ms. Foerster: Aurora Gas, LLC hereby requests approval to set a temporary plug to secure this onshore development well in the Lone Creek Undesignated Gas Field on the west side of Cook Inlet,northeast 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 1,265' above all open perforated intervals to mechanically isolate the reservoir. After the plug is set, tubing pressure will be monitored for 30 minutes to ensure isolation. A back pressure valve will be set and the master valve repaired and then will be closed providing double isolation and the wellhead secured. A follow up pressure reading will be obtained after 24 hours to ensure the integrity of the plug. Please find the attached information as required by 20 AAC 25.110 for your review: • Form 10-403 Sundry Application • Current wellbore diagram illustrating the current well configuration. • Slickline Temporary Plug Set—Generalized Procedure If you have any questions or require any further information, please contact me at(907) 277-1003. Sincerely, George Pollock Manager—Production Operations& Engineering 4645 Sweetwater Boulevard,Suite 200* Sugarland,TX 77479 * (832) 939-8991 1400 W Benson Blvd, Suite 410 *Anchorage,AK 99503 * (907) 277-1003 • ! • _. Aumra Gas, LLC ,�,r ',r'-.j_r, r°` ," , ,' 2 7/8 65#8rd ELIE J-55 Tubing LONE CREEK UNIT �` �' :_ ' ` #3 PTD#: 205-097 e , +` 11-7/8"71.8#Structural API#: 50-283-20112-00-00 '" •. ._.. .; Conductor driven to 80'GL RKB 14.4ft _ * ' As Run October 2013, . '' 8-5/8"32#Surface Casing set at Updated 1/16 .. 700' , ` . Cement w/145.ppg Gas-Block " `` " ' '" ' -14enhanced Cement Drill 10-5/8"Hole to 710' `.� . � ` „ A . a e ter` 2 -7/8 x 5-1/2"annulus ,,, °; y. displaced with 10.4 ppg 3%KCl- ._ .+ .^ *4 NaCI-NaBr packer fluid . XA Sliding Sleeve @ 1265' • Hydraulic Packer at 1308' w/On-Off Tool at 1306' Carya 2-1 -- 1348-58 v . -I. ` 4 Shrouded 1378-98' Sliding Sleeve at 1381' 1408-18' # (Open) 1445-65' . g iii ®91 Hiil Carya 2-2 �ji (d *a Hydraulic Set Packer 1579' 1674-82' ..,� �-°5 '.'� �''` Shrouded Sliding Sleeve at 1660' '''" 2] (Open 12/16/15) Hydraulic Packer at 1705' Carya 2-3 ,° . ,"; Shrouded Sliding Sleeve at 1752' 1798-1818' ® (Open 10/15) ,,, _‘ 11.101.1111&,,,., , Hydraulic Packer @ 2052' Carya2-4.1 = ,< q� _ 4 2092-2106' `` ee ca Shrouded Sliding Sleeve @ 2100' Ems (Open on 1/28/15) Hydraulic Packer @ 2208'w/ Carya 2-4.2 --.■ '' On-Off tool @ 2206' 2282-2317' ""�!� Shrouded Sliding Sleeve at �� ` E.; 2252' (Closed) 2363-78' Carya 2-5.1 -2420-25' ---..... Carya 2' —+1 1 2620-70' 11i�.- Carya 2-6 2796-2816' Permanent Seal-bore Packer @ 2841'with 2 ;{ _ 4 X nipple at 2848'w/PX plug 2844.64' ' '---- EOT @ 2860' PBTD@2928'MD 5-1/2"17#.1-55 Casing to 3018'MD cemented Drill 7-7/8"Hole to 3025'MD, . n& w/34 bbl 13.5 ppg lead+79 bbl 15.8 ppg tail 3015'TVD S 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 1/2"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. Zyee Saaaye(6/11/2017) Image Project Welf 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. c~,Q~ - Q~ ~ Well History File Identifier Organizing (done) RESCAN Color Items: ~Greyscale Items: ^ Poor Quality Originals: ^ Other: ,~ ..a~ iuimmiiiiuii ^ Diskettes, No. ^ Other, No/Type: .. ae,~a~~ee~d iuuiuiuiouii OVERSIZED (Scannable) ^ Maps: ^ Other Items Scannable by a Large Scanner OVERSIZED (Non-Scannable) ^ Logs of various kinds: NOTES: BY: Maria Date: ~ ~ ~ ~ ^ Other:: /s/ Project Proofing III IIIIIIIIIII II III BY: aria Date: ~ ~ 3 ~ ~ /s/ Scanning Preparation ~ x 30 = ~I V + ~ =TOTAL PAGES_~ Count does not include cover sheet) BY: Maria Date: ~' ~~ I ~ ~ lsl Production Scanning Stage 7 Page Count from Scanned File: ~ U (Count does include cov r sheet) Page Count Matches Number in Scanning Preparation: YES NO BY: .Maria Date: ` ! /~O D ~/ /s/ ! ' 1 I l r 1•M Stage 7 If NO in stage 1, page(s) discrepancies were found: YES NO BY: Maria Date: /s/ Scanning is complete at this point unless rescanning is required. III Il l(Il IIIII I I Ill ReScanned III Il'III IIIII II Ill BY: Maria Date: lsl Comments about this file: o , ~~kee iiiimmuumu 10/6/2005 Well History File Cover Page.doc • ewe.ic 3 Regg, James B (DOA) From: Company Man [wellsitesuper@aurorapower.com] (3 Sent: Monday, October 21, 2013 12:27 PM e�(t l To: Regg, James B (DOA) Subject: RE: AWS 1 BOP 10-19-13 Attachments: BOP charts.pdf Here are the charts Shane McGeehan 701-651-3344 From: Regg,James B (DOA) [mailto:jim.regg @alaska.gov] Sent: Monday, October 21, 2013 10:22 AM To: Company Man; Brooks, Phoebe L(DOA); DOA AOGCC Prudhoe Bay Subject: RE:AWS 1 BOP 10-19-13 I asked for charts also Jim Regg AOGCC SCANNED 1:� 2 o 2�ai , 333 W.7th Ave,Suite 100 Anchorage,AK 99501 907-793-1236 From: Company Man [mailto:wellsitesuper@aurorapower.com] Sent: Sunday, October 20, 2013 2:07 PM To: Regg, James B (DOA); Brooks, Phoebe L(DOA); DOA AOGCC Prudhoe Bay Subject: AWS 1 BOP 10-19-13 1 • • STATE OF ALASKA Yk-� + OIL AND GAS CONSERVATION COMMISSION No \l" Test Report Submit to: lim.regq ac alaska.aov AOGCC.Inspectorsaalaska.aov phoebe.brooks(a,alaska.qov Contractor: Aurora Rig No.: 1 - DATE: 10-19-2013 Rig Rep.: Donnie Williams Rig Phone: 907-632-0583 Rig Fax: N/A Operator: Aurora Well Service Op. Phone: 701-651-3344 Op. Fax: N/A Rep.: Shane McGeehan E-Mail wellsitesuper @aurorapower.com Well Name: Lone Creek#3 • PTD# 2050970 • Operation: Drig: Workover: X Explor.: Test: Initial: X - Weekly: Bi-Weekly Test Pressure: Rams: 250/2500 Annular: 250/1500 Valves: 250/2500 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result Test Result Quantity Test Result Location Gen.: P Well Sign P Upper Kelly 1 NA Housekeeping: P Drl. Rig P - Lower Kelly 1 NA PTD On Location P Hazard Sec. P Ball Type 1 P Standing Order Posted P Misc NA Inside BOP 1 P FSV Misc 0 NA BOP STACK: Quantity Size/Type Test Result MUD SYSTEM: Visual Alarm Stripper 0 NA Trip Tank P P Annular Preventer 1 11" P Pit Level Indicators P P #1 Rams 1 2 7/8" • P Flow Indicator P P #2 Rams 1 Blinds - P - Meth Gas Detector P P #3 Rams 0 NA H2S Gas Detector P P #4 Rams 0 NA MS Misc 0 NA #5 Rams 0 NA #6 Rams 0 NA Quantity Test Result Choke Ln. Valves 1 3 1/16 P Inside Reel valves 0 NA HCR Valves 2 3 1/16 P Kill Line Valves 2 3 1/16 P Check Valve 0 NA ACCUMULATOR SYSTEM: BOP Misc 0 NA Time/Pressure Test Result System Pressure 3100 P CHOKE MANIFOLD: Pressure After Closure 1800 P Quantity Test Result 200 psi Attained 17 P No. Valves 13 FP ✓ Full Pressure Attained 85 - P Manual Chokes 1 P - Blind Switch Covers: All stations Yes Hydraulic Chokes 1 P . Nitgn. Bottles (avg): 4 @ 1900 CH Misc 0 NA ACC Misc 0 NA Test Results Number of Failures: 3 Test Time: 10.0 Hours Repair or replacement of equipment will be made within same days. Notify the AOGCC of repairs with written confirmation to:AOGCC.Inspectors @alaska.gov Remarks: Choke vavle#6 failed, replace stem packing retest. Choke valve#8 failed, rebuild retest. Spacer spool leaked, tighten retesf. �— 24 HOUR NOTICE GIVEN YES X NO Waived By Jim Regg Date 10-16-2013 Time 11:00 am Witness Test start 9:00am Finish 6:00pm Form 10-424 (Revised 03/2013) 2013-1019_BOP_AWS1_LoneCk-3.xlsx _ ., • • PI) 2,066 '7c NOON to _ r--- s, 2 /' / '' "_:::::____-- � - r,t 1 t s�`•.. : fit, ^ f , - r '' _.____:, _________, _-_-_.._ ----, L." '', ty .o Cr- �1J z 41. s -.. / -./... ,,, l •- ,._. . '' 't '''''''':: r I�_.c-r - o k . - i o \ �� a N �` , s - �,r fz • f A_____Ir..\c„,_ 4 ., O _ _ 1/1/ / , NX ,Y ,� ,sa i-_ ),, tom,, t/ ff r pp /J • 1~ 5 ' r -k— S _... ;— __ f� , r , icy. f `�. /� .i�O !. !.. i % pp / / 1. i f //' / �J I ' \ ,(.- -/DC , \„. • - -- I k "----... .. ..-' ------------ • --, _v...1 .---cf .,,,..-.,--` y,,,', ..,/ , . '' 44/ / -� .i,3• � � -� -. __ �-'" -rte No / f : ' _ _ ass — .'' 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O yS cR R� . !' 1 per'" R� i , 04 R�' ;i i , o 1 f a ' � f r :`_ , , \ � i f , - 0 . //',,,, ...„ o�(:)0(..).._.,, ...,, ..., 'S.:4 , ,� / f-y--- 00g- o� • • -_.__ 0002 ''-`` ------1 ------ ;- i-k VIP L - 8 191 3/3 OF 7' • • \ I v THE■ THE STATE Alaska Oil and Gas � ►: �� • °f sKA - _ Conservation Commission GOVERNOR SEAN PARNELL 333 West Seventh Avenue O P Anchorage, Alaska 99501-3572 ALAS 907.279.1 433 Fax: 907.276.7542 J. Edward Jones President ° "' SCANNED ,., Aurora Gas, LLC 1400 West Benson, Suite 410 a05-° Anchorage, AK 99503 Re: Lone Creek Field, Undefined Gas Pool, Lone Creek No. 3 Sundry Number: 313-452 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. 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, Cathy P Foerster Chair DATED this LI) day of August, 2013. Encl. I , . #14, RECEIVED e • . . STATE OF ALASKA �4�'� AU G 21 2013 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS AOGCC 20 AAC 25.280 1.Type of Request: Abandon❑ Plug for Redrill[1 P rforate New Pool❑ Repair Well❑ Change Approved Program❑ Suspend❑ Plug Perforations[a. 434 Perforate El- Pull Tubing 21- Time Extension❑ Operations Shutdown❑ Re-enter Susp.Well❑ Stimulate❑ Alter Casing❑ Other: ('/04+ T.s* CV ' 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Aurora Gas, LLC Exploratory ❑ Development El• 205-097 ' 3.Address: Stratigraphic ❑ Service Ell 6.API Number: 1400 West Benson, Suite 410,Anchorage,AK 99503 50-283-20112-00• 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO No. 557 Lone Creek No. # 3 Will planned perforations require a spacing exception? Yes ❑ No El 9.Property Designation(Lease Number): 10.Field/Pool(s): ,0I 13 ? d 2t,I13 �� G-96+500 G- 6 139S FEE Lone Creek- Undefined 6AS 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD(ft): Effective Depth ND(ft): Plugs(measured): Junk(measured): .3025 . 3025 • 2968 • 2968 NA NA Casing Length Size MD TVD Burst Collapse Structural Conductor 80' 11-7/8",71.8# 94.5' 94.5' 9430 psi 5290 psi Surface 710' 8-5/8", 32# 710' 710' 2200 psi 2860 psi Intermediate Production 3018' 5-1/2", 17# 3018' 3018' 5320 psi 4910 psi Liner Perforation Depth MD(ft): Perforation Depth ND(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 2282'-2864' • 2282'-2864' 2-7/8", 6.5# J-55 2857' Packers and SSSV Type: No SSSV. Packers and SSSS VLMD(ft)Znd ND(ft): No SSSV 2 HRP's&1 Mech Ret Pkrs at 2229',2621',& X273-13 'MD/ND '?rlU,,t'b 12.Attachments: Description Summary of Proposal 0' 13.Well Class after proposed work: Detailed Operations Program 21 BOP Sketch 121. Exploratory ❑ Stratigraphic❑ Development ell ' Service ❑ 14.Estimated Date for 1-Sep-13 15.Well Status after proposed work: Commencing Operations: Oil ❑ Gas 12 • WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG ❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Ed Jones Email teio 1es()aurorpoWer.com Printed Name J. Edward Jones Title President Signature r' Phone 907-277-1003 Date 8/21/2013 , Td,,,,,,,,,,(-- COMMISSION USE ONLY Conditio f approval: Notify Commis ' n so that a representative may witness Sundry Number: 31/� Li Plug Integrity ❑ BOP Test [V/ El d✓H Mechanical Integrity Test ❑ Location Clearance OC) Other: 256o fS fDo S RB f OCT 1 0 20 I Spacing Exception Required? Yes ❑ No �] Subsequent Form Required: I' C) — '161 // APPROVED BY Approved by: l W f COMMISSIONER THE COMMISSION Date: & !8 _ 13 .t'' I Submit Form and ` Form 10-403(Revised 10/2012) Approve v 1' r nths from the date of approval. Attachments in p• e �\^_A) "l. ` (C • • RECEIVED 4urora Gas, LLC AUG 21 2013 www.aurorapower.com AOGCC August 13,2013 Ms. Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Ave., Suite 100 Anchorage,Alaska 99501 RE: Application for Sundry Approval Lone Creek#3 Well PTD#205-097 and API#50-283-20112-00 Perforate New Intervals and Recomplete Dear Ms. Foerster: Aurora Gas, LLC hereby requests approval to add new perforated interval to this onshore gas development well in the Lone Creek Field—Undesignated, on the west side of the Cook Inlet, northeast of the village of Tyonek. The well is now completed in Upper Tyonek Sands, the Carya 2-4.2 thru the Carya 2-6, and the planned perforations are shallower Upper Tyonek Sands, the Carya 2-1, 2-2, 2-3, an d 2-4.1 intervals, all to test for gas. 1'-°J The AWS#1 rig may be used to4, l this well, following the drilling of the Nicolai Creek Unit #13. The rig's well control systems are on file with the Commission. The rig is expected to be ready for the work to start about September 1,2013. Please find attached information as required by 20 AAC 25.280 for your review. Pertinent information attached to this application includes the following: 1) Form 10-403 Sundry Application 2) Proposed Summary and Detailed Workover Procedure 3) Schematics of the current and proposed wellbore and completion. 4) BOP Sketch If you have any questions or require additional information, please contact me at (907) 277-1003 or 713-899-8103 (cell). Sincerely, AURORA GAS,LLC L./// Edward Jones President CC: CIRI 6051 North Course Drive, Suite 200•Houston,Texas 77072•(713)977-5799•Fax(713)977-1347 1400 West Benson Blvd., Suite 410•Anchorage,Alaska 99503• (907)277-1003•Fax(907)277-1006 A STATE OF ALASKA RECEIVED A OIL AND GAS CONSERVATION CO SIGN REPORT OF SUNDRY WELL OPERATIONS JAN 2 3 2018 1.Operations Abandon Li Plug Perforations LI Fracture Stimulate LI Pull Tubing Li , .; •e LI ' Performed: Suspend B Perforate LI Other% nate El Alter casing El Change +',' -4.Program LI Plug for:Reda' fl Perforate New Pool ❑ Repair Weil El Re-eater Susp Well 0 Temporary Plug D 2.Operator Aurora Gas,LLC 4.Well Class Before Work: 5.Permit to Drat Number Name: Development Exploratory❑ 205-097 3.Address: 3705 Arctic Blvd.#2114 Anchorage,AK 99503 Skatigraphic Q Service.Q 6.API Number 283-20112-00 7.Property Designation(Lease Number): 8.Well Name and Number: C-061500 Lone Creek#3 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): NA Lone Creek Undefined Gas 11.Present Well Condition Summary: "ToteMetth measured.;i -feet plugs measured 12/11-1a8443 :feel true vertical 3025 feet Junk measured None feet Effective Depth 'measured 2968 feet Packer measured 1308-2841 feet true vertical 2968 feat true vertical 1308-2841 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 80 VI7/8.72# 80 80 Surface 700 8 5/8 32#N80 700 700 5710 psi 3050 psi Intermediate Production 3018 51/217#155: 3015 3018 5320 psi 4910 psi Liner Perforation depth Measured depth 1348-2864 feet True Vertical depth 1348-:2864 ;feet Tubing(size,grade,measured end true vertical depth) 2 7/8 ,6.5#J55 2860 2860 Packers and SSSV(type,measured and true Yerticalelepth) 12.Stimulation or cement squeeze summary: Intervals treated(measured): NA SC 1 NNED JAN . 'if a Treatment descriptions including volumes used and final pressure: NA 13. Representative Daily Average Production or Injection Data i Oilab1 t Gas-Mef. € Wates-Bwbl.- y Casing Pressure l' Tubing Pressure Prior to well operation: 100 8 110 Subsequent to operation: 0 0 0 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations LI Exploratory D Development Q Service Li Stratigraphic Copies of Logs and Surveys Run 0 16.Welt Status after work: Oil a Gas WDSPL Q Printed and Electronic Fracture Stimulation Data El GSTOR a WINJ a WAG 0 GINJ❑ SUSP:0 SPLUG a 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or NAV C.O.Exempt: 317-271 Authorized Name: George Pollok Contact Name: i Authorized Title: A+�°M. -I Prod. Email: oAollocka1aurorapower.o Authorized Signature: .-i�7 d' Dab 1/2312018 Contact Phone: 907.351.8286 Form 10-404 Revised 4/2017 A ,/ii, R B D M S �/I A I ? r: ,„10 Submit Original Only (✓ J U • . AURORA GAS, LLC RIG RECOMPLETION WORKOVER PROCEDURE LONE CREEK UNIT#3 September 2013 Version 1.1 (8/21/13) CURRENT CONDITONS: CURRENT STATUS : SITP-1000 psi; Flowing 1.5 MMCfpd at 880 psi w/20 BWPD KB=14.4 feet CASING: 5-1/2", 17#J-55 set at 3018'MD/3010' TVD. TUBING: 2-7/8",6.5#J-55 8 rd EUE, w/9.7 ppg KC1-NaC1 brine as packer fluid in tbg-csg annulus above top packer and with: Sliding Sleeves at: WXA at 2194' (closed—opens upward—closed); WXO at 2330' (closed); WXO at 2521' (closed): 2.31"X nipple at 2579' (open): and On-Off Tool w/ 2.31"X landing nipple at 2611' (open), and 2.25" (assumed)XN nipple at 2771' (open) Packers: HRP's at 2229'and 2557' and Arrowset IX at 2732' 4" Screens at: 2617-2668', 2804-15', and 2826-57' w/bull plug EOT--2857.4'. (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 On-Off Tool=21.8 bbl,Annular Volume to top Packer=33.9 bbl;to On-Off Tool= 86.3 bbl(bottoms up); Casing Volume to Arrowset Packer at 3767'= 146 bbl. PERFS: Carya 2-4.2 at 2282-2317',2363-78' behind Sleeve at 2330' and 2521' (depleted) Carya 2-5.1 at 2420-25' also behind Sleeves at 2330' and 2521'(depleted) Carya 2-5.2 at 2620-260' behind Screen at 2617-68' (open but mostly depleted) Carya 2-6 at 2796-2816', 2830-40', 2844-64' (Now flowing) NOTES: 1)Well essentially a straight hole. SUMMARY OF PLAN: Kill well,release packers,circulate out,pull existing completion,run retrievable packer to test open perfs at 2282-2317'. Run new 2 or 3 new packers to isolate productive open perforated intervals, set plug in tubing in on-off tool above top packer,release from packers, circulate well with 10.4 ppg brine,pull tubing,perforate shallower sand intervals,run upper completion with 4 packers on tubing, set packers, swab in and test. DETAILED ROCEDURE: 1) Pick and move wellhouse. • . 2) 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 choke skid,test unit,and flare. 3) Starting with clean mud pit,mix 150 bbl(usable volume) 9.0 ppg 3%KC1-NaC1 brine (3%KC1- 11#/bbl+weight up with oilfield salt, 34#/bbl),using clean produced water from tanks on location and add fresh water as needed. Max expected kill weight of open any perfs is 8.8 ppg,but may have to deal with losses into depleted intervals. 4) Set GE 2-way check in hanger. ND tree,NU 3000-psi BOPE. Test to 2500 psi(or as required by AOGCC Sundry approval). Pull 2-way check—release GE. 5) Kill well: RU Pollard w/pump-in sub on lubricator w/choke and HP hose back to mud pit. a) RIH and open WXA sleeve at 2194' (opens upward)—fluid will"U-tube"up tubing. b) Pump down casing to fill casing and equalize tubing and casing pressures. c) "Bull head"down tubing into open perfs if well is not dead at this point. d) RD Pollard. 6) Screw into tubing hanger,and release hold downs. Then pull tubing and completion as follows: a. Pull to release the two hydraulic packers(approx 43,000#overpull) b. Reverse circulate out any gas seen in casing and equalize brine weight—should be no more than 9.1 ppg with addition of 9.7 ppg annular fluid. Monitor loses (depleted perfs at 2282- 2670' now open). c. If losses are serious, greater than 5 BPH,reduce brine weight in pits to 8.9 ppg. Release from On-Off tool at 2611'. Pull up 2' or more.Mix and circulate 20 bbl"Baraplug"LC pill if needed(see Notes below) d. When losses are controlled,re-latch onto On-Off tool,and release Arrowset packer at 2732'. Reverse Circulate out any gas(pumping thru screens). Monitor losses. Note: cannot pump additional Baraplug pill to control at this point due to screens. If needed,must open tubing(lowest sleeve at 2521' or perforate tubing just above On-Off tool at about 2600') before pumping. e. When well is dead and losses are contained,then POH, standing back tubing and laying down packers and sliding sleeves. Strap out of hole and keep good records. Monitor hole and keep full. Expect some losses(and gas if hole not kept nearly full). 7) PU RBP and Retrievable Test Packer and RIH, set RBP at 2340' and packer at+/-2250'. Swab test 7 at, av perfs at 2282-2317',monitoring water production, gas rate, and pressures. Kill well,release packer, ��0 1- retrieve RBP, well, and POH. 8) Determine if zone tested was a"keeper"and isolate accordingly: a. If zone at 2283-2317' is productive,isolate with packers by running permanent seal-bore packer w/X profile on stinger below, on wireline to set at 2841', PU and run tubing anchor assembly, 16 jts of tubing w/sliding sleeve w/X profile at 2376', hydraulic packer(to set at +1-2340), 3 jts tubing, sliding sleeve(at+/-2240), 1 jt tubing,hydraulic packer with On-Off tool(at+/-2206'). RU Pollard, set plug in X profile in sliding sleeve at 2376'. Pressure up TO 2500 psi(or as prescribed by tool hand)and set hydraulic packers. Retrieve PX plug, reset in On-Off tool at 2206'. Release from ON-Off Tool and POH. b. If only deepest zone in productive, set permanent packer as in a. above ,and run only one hydraulic set packer with On-Off tool to set at 2206' with only one sliding sleeve one joint below that packer. Set packer and POH. • • 9) Build 100 bbl of 10.4 ppg 3%KC1-NaCl-NaBR brine(formula to be provided by Baroid). Filter thru 10 micron filters until clean. THIS IS EXPENSIVE FLUID—$160/BBL--DO NOT DILUTE, CONTAMINATE,NOR DISPOSE WITHOUT DISCUSSING WITH ME. 10) Dump 2 sx sand(15')of sand onto On-Off tool set at 2206'. RIH OE to tag bottom. Pull up and circulate hole with 10.4 ppg brine, circulating out and separating the 9.1 ppg brine. Continue circulating and filtering brine until clean and consistent 10.4 ppg. POH, standing back tubing. 11) RU perforators w/lubricator. Run GR/CCL correlation log and correlate to Platform Express log of 7/20/05. a) PU 3-3/8" Millenium Deep-Penetrating perforating guns, test lubricator to 1500 psi, and RIH to perforate "2-4.1 Sand" at 2092-2106' (14'—expected max pressure-9.9 ppg) w/ 6 SPF w/ 60-deg phasing. Watch for gas, pressures, and fluid level in casing while shooting. b) Perforate the"2-3 Sand"at 1798-1818' (20'—expected max pressure-9.4 ppg) c) Perforate the"2-2 Sand"at 1674-1682' (8') d) Perforate the"2-1 Sands"at 1445-65' (20') e) And 1408-18' (10') f) And 1378-1398 (20') g) And 1348-58' (10'—expected max pressure-10.3 ppg) h) POOH,LD perf guns,RD wireline. (7 runs, 102' of perforations). 12) PU casing scraper and bit and run thru new perfs,to tag bottom at 2206', circulate sand off On-Off tool, and circulate wellbore clean. POH and LD bit. . 13) PU following completion BHA and RIH on 2-7/8"tubing,visually inspecting and replacing questionable collars or whole joints, as follows: a) On-Off tool OS/skirt b) 4 jts 2-7/8"tubing,I) 2-7/8" Sliding Sleeve to be set at+/-2080' d) 1 jt 2-7/8"tubing, dam' e) Hydraulic-set packer to be set about 2045' f) 9 jts 2-7/8"tubing, g) 2-7/8" sliding sleeve at about 1766', h) 1 jts 2-7/8"tubing, i) Hydraulic Packer at about 1730' j) 2 jts 2-7/8"tubing, k) Sliding Sleeve at 1670', 1) 2 jts 2-7/8"tubing, m) Expansion Joint or Safety Joint, n) Hydraulic-set Packer to 1590' o) 7 jts 2-7/8"tubing, p) Sliding Sleeve at 1370', q) 2 jts 2-7/8"tubing, r) Hydraulic-set Packer at about 1300' w/On-Off tool, s) 1 jt 2-7/8"tubing, t) XA sliding sleeve, u) 2-7/8"tubing to surface • • \P 14) Latch onto On-Off tool at 2206'. Space out, land tubing, and lock down.. Pressure test tubing to / ' v 2500 psi,then pressure up to set hydraulic packers (against existing plug in profile in on-off tool'l Q at 2206'). Bleed off pressure. Install BPV. ND BOP. NU and test tree. Pull BPV. (Be rigging up kf ab AG test choke manifold, separator, and flare stack,connected with hardline during this time). 15) RU Pollard slickline unit and lubricator,test lubricator to 1500 psi. RIH w/shifting tool and open sliding sleeve at 2080'. POOH. RD Pollard(but do not release to go to town,will have other work in field for them to do). 16)RU to swab and swab in Carya 2-4.1 perfs at 2092-2106' and test thru test separator. SEE SUPPLEMENTAL TEST PROCEDURE,Note II below. Allow to cleanup. SI for 1 hr buildup. Open to flow and allow to stabilize at about 80% (or more)of SITP. SI,and watch buildup for 1 hr. 17)RU Pollard. Test lubricator to tubing pressure. Open and close sleeve at 2080'. en sleeve at gP 1766'. RD Pollard. Test 2-3 sand perfs at 1798-1818' as in Step 19 above. Tubing s/b essentially dry so no swabbing should be needed,unless perfs are making water. 18)RU Pollard. RIH and close sleeve at 1766' and open sleeve at 1670' to test interval 1674-82' as in Step 19 above. NOTE: AWS rig will be released when 2 zones are successfully tested at rates above 1 MMcfpd each w/o significant drawdown(FTP>75% SIP). 19)RU Pollard. RIH and close sleeve at 1670' and open sleeve at 1370' to test interval 1348-1470' as in Step 19 above. 20)Based on test results,determine initial configuration of well for production(probably deepest,driest interval)and RIH w/Pollard to pull plug and/or open sleeves to facilitate configuration. RD Pollard. RD AG test equipment. Turn well to operators to reconnect flowline and put to sales thru 3-10 production facility. 21) If rates are lower than expected,may set plug in On-Off tool at 1300',pull tubing and perforate the✓ Beluga sands at 942-972',run an additional hydraulic packer, and test. Supplemental procedure will be provided at this time. Ed Jones (8/7/13)Rev 8/21/13 NOTES: I. BARAPLUG RECIPE System Formulation: Saturated Salt Water- .888 bbl Salt- 109 ppb System Formulation: Sized Salt Bridging Pill Product Concentration Saturated Brine 0.83 bbl Baradefoam HP 0.1 ppb Citric acid 0.5 ppb BARAZAN D+ 2.0 ppb N-DRIL HT+ 4 ppb caustic .1 ppb(to a 9.0 pH) Baraplug 20 30 ppb Baraplug 50 27.5 ppb Baraplug 6/300 10 ppb Aldacide G 0.1 ppb • • Special Mixing Instructions: • Mix in order as listed • Please note that we will manipulate the pH to speed the additions of polymer • A can of X-Cide 207 must be added to any pills mixed. Adjust the pH of the brine for the pill to a 5.0 or less with citric acid. Then the BARAZAN D+ and N- DRIL HT+ can be added rapidly though the hopper. After all the polymer is added, adjust the pH back up to a 9-9.5 with caustic. The polymer will then yield. Check the YP after adding the caustic. The YP should then be adjusted to the 35-40 range with BARAZAN D+ if needed. The Aldacide G should be mixed in all fluid entering the wellbore. If possible, add it in the suction pit or below the mud line (inline chemical injection pump on the suction?). The Mud Man will make all additions of Aldacide G or supervise closely. Further additions of fluids will require the additions of Aldacide G. When pumping a kill pill, remove suction and DP screens. Pump pill at a fast rate as this will help maintain the integrity of the pill. When the pill gets to the perfs slow the pumps down to 1-1.5 bbl/min. Continue pumping until 200-400 extra psi is observed. Shut the pump down and watch for the pressure to bleed off. Repeat this procedure until it takes 10-15 minutes for the pressure to bleed off. Be careful not to over displace while squeezing and wash the pill away. If no squeeze pressure can be obtained, stop pumping and let the pill soak into the perfs. 3%KCI Saturated NaCI brine: 0.888 bbls Water+11 ppb KCI+98 ppb NaCI Saturation will be a 9.9+ppg MW 9.3 ppg 3 %KC1 NaC1 Brine: 11 ppb KC1 and 55 ppb NaC1 II. TEST SUPPLEMENTAL PROCEDURE A. Prepare for test: 1)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; 2)Record test separator water meter reading; 3)install new chart on Barton recorder; 4)install fresh nitrogen bottle onto skid for instrumentation(or use separator pressure); 5)install Pollard SPIDR surface pressure recorder(or new 2000-psi pressure gauge)near test head, isolated with needle valve(upstream from valve that will shut in well for buildup—will want it to record and show SI pressures),and 6) confirm electric clock on chart recorder is on and set to 12 hrs. B. RU to swab. Swab in perfs below 2260-2362' and flow test until clean and stable,as follows: 1) swab in,unloading fluid to shaker/possum belly until well is gassing and/or kicks off to flow; 2)when significant gas is at surface(whether swabbing or flowing)or the well is flowing, divert flow to test separator: a) shut down momentarily to light flare stack,then bring back on,adjusting choke size until well is flowing strongly to cleanup,but holding significant back pressure on it(probably start at 24/64's and adjust accordingly,target flow at 75%of SITP(expect SITP to be 1000+ psi, so target stabilized flowing tubing pressure above 750 psi). • • bi)Flow for an hour or more and until rate and pressure have stabilized for 15 minutes(i.e.,pressure on SPYDR changes less than 2 or 3 psi in 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 bottom of top set of perfs has been recovered,up to 15 bbl or rate has stabilized . Flow for a minimum of 1 hour. Probably more (2-3 hours), depending upon water production and cleanup. c) Test meter has 1-1/2"orifice in it. Flow rate in mcf/day=static reading(blue)X differential reading(red)X 70,(if temperature reading (green) is 5.5-6.0, slightly higher for lower green reading and lower for higher green reading). If red chart reading is below 3, change to 1.0"orifice; if it is above 8 change to 2.0"orifice. Meter factors change to 31 or 130, respectively. Orifices may be changed by experienced operator while flowing w/the Daniel Sr. orifice fitting. d) Catch water samples thru out(downstream of test separator)—have tested by mud man for chlorides and weight—record both and time of sample. Produced water should have chlorides of less than 20,000 ppm and and weight is less than 8.5 ppg—if water is trending in that direction, continue to flow until these properties have stabilized, if the gas rate is above 1000 mcf/day.Keep last sample of produced water to send to lab in Anchorage—label thoroughly. 3) SI for pressure buildup(at least 2 times longer than flow period or until pressure is building at less than 1 psi/15 minutes on SPIDR). III. 10.4 ppg Brine Formula(to be provided by Baroid) • • 2 7/8 6.5#8rd EUE.1-55 Tubing 11 7/8"71.8#Structural Conductor driven to 80' -tiAurora Gas, LLC ; • Lone Creek No. 3 Configuration . As of August 14.2013 8, 8 5/8"32#Surface Casing set at 700' hk Cement w/14.5 ppg Gas-Block Td enhanced cement(—39 bbls cmt @ 50%Excess) Sliding Sleeve at 2194' (CLOSED) —s O PEP Hydraulic Retrievable Packer at 3229'' Emir- 6 SPF—2282'—2317' / --�® CARYA 2-4.2 Sliding Sleeve at 2330'(closed) 6 SPF—2363'—2378' CARYA 2-4.2b =� 6 SPF—2420'—2425' CARYA 2-5.0 I Sliding Sleeve at 2521'(closed) 1_r.11 . Hydraulic Retrievable Packer at X-Nipple at 2579' (Plug removed 8/13/13—open) lit , On Off Tool at 2611' 6 SPF- 2620'-2670' 4"Sand Exclusion Screen CARYA 2-5.2 _4 Arrowset IX Packer at 2732' . ��• , X-Nipple at 2771'(plug removed oi 8/13/13--open) 6 SPF- 2796'-2816' "".. 2830'-2840' _.___ Illo...— 4" Sand Exclusion Screens 2844'-2864'• —.ma immow"" CARYA 2-6 ��a ..— PBTD at 2968' 5'/z"17#J-55 Casing to 3018'MD(TVD) TD 3025' A k Cmtd w/34 bbl 135 ppg Lead at 20%excess and 79 bbls 15.8 ppg Tail at 20%excess 302.5' I Fairweather E&P Services,Inc. I Lone Creek No.3 Rev.1.0 1 6/08/2005 DHV I Drawing Not To Scale • • • ar Aurora Gas, LLC 2 7/8 6.5#8rd EUE J-55 Tubing 0 LONE CREEK UNIT #3 11-7/8"71.8#Structural PTD#: 205-097 Conductor driven to 80'GL API#: 50-283-20112-00-00 RKB 14.4ft 8-5/8"32#Surface Casing set at (To be run September 2013) 700' Cement w/14.5.ppg Gas-Block enhanced Cement Drill 10-5/8"Hole to 710' 2-7/8" x 5-1/2"annulus displaced with 10.4 ppg 3%KCI- NaCI-NaBr packer fluid XA Sliding Sleeve @ 1270' 1;11 Hydraulic Packer at 1300' w/On-Off Tool Carya 2-1 1348-58' I 111 I 1378-98' Sliding Sleeve at 1370' 1408-18' 1445-65' Hydraulic Set Packer @ 1590' Carya 2-2 1674-82' Expansion joint @ 1600' Sliding Sleeve at 1670' Hydraulic Packer at 1730' Carya 2-3 1798-1818' 111 Sliding Sleeve at 1766' Hydraulic Packer @ 2045' Carya 2-4.1 2092-2106' Sliding Sleeve @ 2080' r �I Hydraulic Packer @ 2206'w/ Carya 2-4.2 On-Off tool 2282-2317' Sliding Sleeve at 2240' 2363-78' Hydraulic Packer at 2340' onow- Carya 2-5.1 -2420-25' i— Carya 2-5.2 2620-70' Sliding Sleeve @ 2376, Carya 2-6 2796-2816' 2830-40' Permanent Seal-bore Packer @ 2841' 2844-64' _, EOT @ 2860' PBTD @ 2928'MD 5-1/2"17#J-55 Casing to 3018'MD cemented Drill 7-7/8"Hole to 3025'MD, w/34 bbl 13.5 ppg lead+79 bbl 15.8 ppg tail 3015'TVD • kV- Well c 'ce Rig No. 1: Proposed 3M BOP ftfiguration Aurora ell S v>� g Fa t0/1/6 C ewe U,ui r- • 3 B_ BellNipple with flow line to pits Fill Up Line 3 3M Schaffer Annular Preventer i Pipe Rams sized ( i 1 to work string. t 11"3M Double Gate w127 7�&'pipe 1 rams installed. i r"3M Mud Cross Blind Rams 3"5M Manual Valve (Choke Line) 3" 5M Manual Valve(Kill Line) _ 3"5M Hydraulic Valve �� - t (Kill Line) . .} -3"5M Hydraulic Valve 0,.- ' R� ail _tt,* Hie!! (Choke Line) Fluid-flaw direction �� d ._ '�- R� 1 1(4 r� �� while reverse circulating _it,_ I 7-'/(fm Cl I ', ■milIMMIftw B4 B7 ,,rial{ 111 �I !y B9 1 I/ C2 !Yil ! I Iji -Bi1• "!vim fl B12 Bb B5 irn te t% IAI B2 B3 BIO A5 "� 4:\ ��' B14 . III 1 �I 4`'i liiN! B13 r: A6 TA I.,, �. 11 6.,.. it -' i A2 111 r A3 A4 Al 2-7/8' OD TBG -------- I _-' ❑D CSG ALL DIMENSIONS ARE APPROX. I W01 fv.ale) 5-1/2' OD CSG f • Aurora Well Service gig No. 1 Proposed Choke 1 Kill Manifold Configuration All valves are 3" rated at 5000 psi. Inlet from Output to Pits Power Swivel (Reverse Circulation Mode) I • ...w 2"5M Rated 1111. Valves Hydraulic Remote Activated choke 14• Inlet from BOP ,'rte v r I-- Choke tine �- r.r 3"5M Rated III Valves — rnam r.r ■ Bleed Flare Line to irk 3"5M Rated Open Flare Pit Valves 3"5M Rated WIN Valves ' . #■ :1.1 Manual Choke 2"5M Rated Valves To Gas Buster "Atmospheric Degasser" Aurora Wei Service Choke f tanifold , I Orawino Not to Scale y 1 t Sent By: AURORA#POWER; • 7139771347; Jun-~5 15:21; Page 1/3 ~ ~~~ -~~~ Aurora Gasp LLC 10333 Richmond, Suite 710 Houston, Texas 77042 Phone: 713-977-5799 ' 1~~` Fax: 713-977-1347 - 1 ~~ ~~~~~ J ~a~ Transrxwittat Form ~'~///'''~~~ ~ `~ s!? 4.~ ~°' From: Fax: [)ate: ? ~ `'~ -. _. __. phone: Pales: __..... ...---- L.._- . ~ .-.. -.. _ . _ .... -. ' Rc: ~ ^ Urgent ^ For Revie~rv Ll Pioase Comrt~ent ^ Please Reply !:] Please Re~ycie Messag red : Q~ ~ In..~- ~~ z ~1~ APR ~ ~ 20(}8 NOTE: The jrsfurrnahon coHtamc~d in this fax js confidential and/or privjleged, Thjs fax is intended for the sole use on the mdivjd- ual Harried ,above. if the reader of this rron:,mitt~l page i5 noL the intended recipient or a representative of the INtended rec_i;~irnt, you are hereby Notified that any review, dissemination, djStrjUuCion, or copying of this fax or the information con[aincd i~trei i is~ prOhfI71CCd, IF yOiJ ha VC rCCCIVCd Ch15 fix Irt error, please immQdiately notify [he 9Cr'~dcr by telephone anti return 1,t,iy hX to the sender ai the address above. r Sent By: AURORA#POWER; • 7139771347; Jun-~5 15:21; ,, ~.. ~~~ ~~~i~ ~~~ www.aurorapowercom Alaska Ui.l and C7a5 ~onsgrv8tion Commission 333 W 7th Avenue, Suite No. lUU Anchorage, Alaska 9951)1-3539 Attn; Mr. Steve Davies Petroleum Gc;ologist Gentlemen: June 23, 2005 RE: hpplication for Permit to mill Lane Creek Na.3 Weil C-6] SUU Moquawkie Arca Page 2/3 ltefeTence is made to the previously submitted Application for Permit to Drill (API7) in behalf of Aurora Gas, LLC (AURORA), as Operator of the captioned prapose~i development well. Although the APD contained an erroneous lease number, which will be corrected, this leper respectfully requests the APD be approved with certain limitation placed upon Ai.7RC1RA, as discussed below. The Lone Creek No.1 Well is currently producing has from a sur!'acc location situated in the S W4 Sl/4 of Section 18, Township l 2 North, Range 1 l West, SM and the proposed captioned well is also planned to test gas at seven (7) intervals, but unfortunately is situated in the SW/4 NE4 ofthe aforementioned Section 18. Both well are situated within the confines of the Lonc Creek Unit, (f%k/a the Moquawkie Unit). Consequently, the proposed captioned well will require a spacing exception location pursuant to 20 A11.C 25.540. IIawever, it should be known since AURORA was under the misunderstanding that since these intervals were behind pipe in the Lonc C:rcck No.'I na spacing exception was required and thus had planned to spud the captioned proposed well an ar before .I<uly 1, 2UQ~. Consequently, ibis letter respectfully requests the AOGCC give favorable consideration to approving AiJRORA's APD, but prohibiting AURORA'S ability to produce said well from the producing gone i~t the lone Creek No. 1, the Darya 2-4.2 sand sc;r:n at 24UUm246U', until the completion of the spacing exception process. 'I his proposal, if approved by the AOGCC, would allow AURQRA to comtncner, drilling operaiions and test the intervals of interest, as identified on Exhibit "A", but not produce hydrocarbons from this C'arya 2-4.2 Zone in the well until the spacing exception pracessin concluded. AUROItA's operational, drilling and tcstin~; prograrn is briefly discussed below for yourbenefit. AURORA plans to drill the proposed Lone Creek No. 3 Well to sufficient depth to test seven t7pper Tyonek ("Carya") sands that appear to be potentiall~r productive in the Lone Crcck No. l well bore. A11 sands are expected to be structurally higher in the No. 3 than in the Na. 1 Wolf, soirir; by as tttuclz as 280 feet. only one sand was tested in the Lone Creek No. 1: the Carya 2-4.Z sand at 2,40(1-Z,4(ill', and the No. 1 well is completed solely in that zone, which has proved to be very productive, producint; more than. 3.2 RC".~' to date, and still producint; at a rate of about 1.7 MMef~pd. Althaugl-. 10333 Richr»ond Avenue, Suite T10 • Houston, Texea T7042 • {7f 3) 977-5799 + Fax (T13) 9T7-73'47 1400 West Benson Blvd., Suite X10 • anchorage, Alaska 99503 • (907') 27y-1003 • Fsx (90T) 27T-1aQ6 Sent By` AURORA#POWER; ~ 7139771347; Jun-~5 15:22; . '"'",+ ~~~ Gas, L~,C www.aurorapowercom Alaska Oil and Ga.s Conservation C:~mmi5wion 333 W 7th Avenue, Suite No. lt)U An41-i~rtt1;C, A,la51c;~ 99501-3539 June 23, 20(15 Attn: Mr. Steve Davies Pctrolcurn Geologist Gentlemen. RE: Application for Permit to Drill Lone Creek No.3 Well C'-6150() Moquawkie Area RePerencc: is made m the previously subrniltcrl Application t'or Permit to Dril{ (Al'll) in behalf of Aurora Gas, T,T,C (AT~RORA), as C~ieratvr of the captiotlcd propose:. developmelit well. Although tho APD contained a.n. errotlcous lease nEtt~lber, which will be corrected, this letter respcctiully royuests the A.PI) be approved with certain litnitatiar:. placed upon .ALTROIZ.A, as discussed below. The l,otle Creek No.l Wet] is carrerttly producing gas from a surface location situated itl the S W4 5E4 of Sc ~~7 $, Tv lup 12 North, Range 11 West, SM and the proposed captioneel well is s planned to les gas at seven (7) intervals, but Emf(~rlunately iS 5ltuated In e S~4 NE4 of th afnrernetltioncd Section 18. Both wells are situated within the confi cs ol'thc Lonc C eek Unit, (f/k/a the Moquawkie Unit). Consequently, the proposed c tinned w ill require a spacing exception location pursuant to 2q AAC 25.540. l lowever, it should be known since AURORA was under the tni.suncierstandillg that since these intervals were behind pipe in the Lone Creek No. l rto spacing exception was rec{uired and thus had plart.r~ed to spud the captioned proposed well on or before July 1, 2005. Consequently, this letter respccifirlly requests file AUC;CC give favorable consideration to approving AURQRA's A,F'I), but prohibiting ALTRQR,q,'s ability to produce saicl well from the producing lone in the Lone Creek No. 1, the C'arya 2-4.2 sand seen at 2400-2460', until the completion of the spacing exception process. "Phis proposal, il'approved by the AOGCC, would allow AURORA to commence dnll.iltg operations and test the intervals of interest, as idcntilied on Exhibit "A", but not proiluee hydrocarbons from this Carya 2-4.2 Lonc in the well until the spacing cxccptirni process in concluded. AURORA'S Operational, drilling and testing program is briefly discussed below Cor your bencrt. AURQRA plans to drill the proposed Lune Creek No. 3 Well to sufficient depth to test seven Upper Tyonek ("Carya") sands t17at appear to be potentially productive in the Lonc Creek No.l well bore. All sands arc expected to be structurally higher in the No. 3 th:ui in the No. I Well, sorne by as trluch as 2i3U feet. Only one sand ryas tested in the Lone Creek No. 1: the Carya 2-4.2 sand at 2,40(1-2,4G0', and the No. i well is cvtrrpleted solely in that zone, which has proved to be very productive, producing tllorc t11ar13.2 BCF to date, and still prndueint; a.t a. ra.tG otabout 1.7 1VIMcfpd. Although Page 3/3 10333 Richmond Avenue, Suite 71p • Hauaton, Texas 77042 • (7f3) 977-5788 + Fi+x (7f3) 877 19~J 1400 Weat Benson Blvd., Suite 410 • Anchorage, Alaska 89503 • (807) 277-i0Q3 • Fax (907) 277-1 D06 Sent By; AURORA#POWER; • 7139771347; Jun-~5 15:23; Page 1 ~I~ 10333 Richmond, Suite 710 Houston, Texas 77Q42 Phone: 713-977-5799 Fax:7~3-977-1347 FIX Transmittal Form To: Pax: Phone; Re: ^ Urgent p For RQVIew ^ Pleasd Contmpnt ^ Please Reply D Please Recycle f~~ irk r j ~., NOTES The information contained In this fax is confidential and/or privileged. This fax 15 Intended for the sole use ors the individ- ual named above. If the reader of this transmittal page Is not the intended reCiplent or a representative of the Intend ad recipient, you are hereby nddfled that any review, dissemination, distribution, or copying of this fax or the information contained herein is prohibited, If you have received this fax In error, please immediately notify the sender by telephone and return this f~~x to the sender at the address ahnve. Sent By: AURORA#POWER; • 7139771347; Jun~S 15:23; .Aur~or~ Cas, LLC www.aurorapower.cam Alaska Oil and C7as Cun;~crvatiun C<.>m,rission 333 W 7th Avenue, Suite No. 700 Anchorage, Alaska 99501-3539 Attn: Mr. Steve Davies Petroleum Geologist Geatlcmcn: June 23, 2(lU5 Kl:: Application for Permit to Drill [..,one Creek No.3 Well C-61500 Moquawkic Area Reference is made to the previously submitted Application for Permit to Drill {APD) in bchalfof Aurora Uas, LLC {AiJRC)RA), as Operaior of the captioned proposed development well. Although tl~.e A.PD co.~atained an erroneous lease; number, which will he corrected, this letter respectfully requests the AID be approved with certain limitation placed upon AURORA, as discussed below. The Lone Creek Nv.1 Well is currently producing ,gas from a surface locatic-n situated in the S W4 SE4 of Section L S, Township 12 North, Range 31 West, SM and the proposed captioned well is also plaru'ied to test gas at seven (7) intervals, but unfo-~tunately is situated in the SWf4 NB4 of the aforementioned Section 18. Both wells are si#uatcd within the confines of the Lone Creek i.Jnit, (f/k/a the Moquawkie Unit). Consequently, the proposed captioned well will require a spacing exception location pursuant to 20 AAC 25.40, Page 2 However, it should be known since AURORA was under the misunderstanding that since these i~~tervals were behind pipe in the Lone Creek No. i no spacing exception was required and thus had planned to spud the captioned proposed well on or before July I, 2Qp5. Consequently, this letter respectfully requests the AOGC;C; give favorable considcra.tion to approving AURQRA's APD, but prohibiting AURC)i2A's ability to produce said well from the producing zone in the Lone Creek No. 1, the Darya 2-4.2 sand seen at 2400-241>U', until the completion of the spacing exception process. This proposal, if approved by the AC)GCC, would allow AU~IZORA to commence drilling operations and test the intervals vi'interest, as identified on Exhibit "A", but not produce hydrocarbons from this Carya 2-4.2 zone in the well until the spacing exception process in concluded. AtJRORA's operational, drilling and testing program is briefly discussed below for your benefit. AURORA plans to drill the proposed Lone Creek No. 3 Well to sutTicicnt depth to test seven Upper Tyonek ("Carya") sands that appear to he potentially productive in the l.onc C'rcck Nai well bore. All sands are expected to be structurally Higher i~t the No. 3 than in the Nv. 1 Well, 3UIfIe:' by d.6 Iilll(;il as 2$b fc;c;t. Only une; sand was tested in the Lone Creek No. 1. Ehe Carya 2-4.2 sand at 2,4(lI)-2,4GU', and the No. 1 well. is cornpleted solely in that zone, which has proved to be very productive, prodttcin~; rnorc than 3.2 BCF to date;, and still producing at a rate of about 1.'71V1Mcfpd. Although 10333 Richmond Avenue, Suite T10 • Nouaton, Tsxaa 77042 • (713) 87T-5783 • Fax (773) 97T-1347 7400 Weet Benson blvd., Suite 410 • Anchorarge, Alaska 88503 • (807) 277-fpp3 • r*~x ~9or~ sir-.iooe Sent By: AURORA#POWER; • Jun~S 15:24; Page 3 not tested, lob analysis indicates that some of these other sands may he productive in that. well bori; aiid that all have sufficient apparent porosity and permeability to produce gas if the reservoirs are gas hearing at the up dip location of the No. 3. The total net thicknesses of these sands is about 24~' in the No. 1 well bore (,but are expected to be somewhat thinner in the No. 3), 55' of which is the producing Carya 2-4.2 zone, so there is a high percentage of poten.tia] pay to be tested. The plan is to drill the well to 3,2001eet Mf7/`l"V f) and rwi a full suite of open- hole loll, probably including: array induction, forms~tion density, cornpcnsated neutron, di-pole sonic, formation micro imager, side-wall cores and formation pressure tests (Schlumberger's MDT tool}. Foilowiang the setting and cementing of 5-112" production easing rind analysis of these logs, the wail will be perforated-probably all zones that - appear to be gas productive without water will be perforated in one set up in an overbalanced well bore condition. The zones will be isolated with packer (and bridge plugs, as needed) and briefly tested individually (nr in getups of 2-3 adjacent zones with similar log characteristics), from the bottom up, to get gas production rates and to determine if water will be produced-the Carya 2-4.2 will be tested individually. iJpon determuiativn of productivity of each zone, the completion string will be run. If multiple; zones are productive, including the Carya 2-4.2, multiple packers (2 or 3) and sliding sleeves anil retrievable X-profile plugs will be used for selective eompletians to isolate the Carya 2-4.2 zone from the other productive zones and to prevent the Carya 2-4.2 from producing until the spacing exception process is completed. It should be noted there are no issues regarding airy injury to the correlative rigl2ts of any offsetting owners. Attached hereto as Exhibit `i3' is a plat of tl~e Lone Creek Unit. As you can see the offsetting landowner of the tract to the north of the drillsite lease for the captionul well, C-61500 is the Cook inlet Region, Inc. zu~d the minerals under said tract arc leased to Aurora (ias, 1~f,.C being C-61395 lease. The offsetting landowner of the tract t~ the east and south of the captioned well is also the Cook Inlet Region inc. and - th.e minerals under both tracts are also leased tv Aurora Cxas, LLC being 061396 lease. 'fhe offsetting landowner of the tract to the west of the drillsite lease is the Mental Heal#::i Trust and although these MlI"Y minerals are unleased said tract is in excess of - approximately 3,90U' from the proposed drillsite. Exhibit "Ii" reveals the location of the proposed captioned well for which the spacing exception is sought, all other completed or drilling wells on the drillsite lease C-G1504, as well as the entire Lone Creek Unit, and adjoining properties. Please incorporate this request with the revised AFD submittal coming from Fairweather and give favorable consideration to AiJR~RA's propos~il. If you require additional inIorn2ation regarding this request, please contact Mr. Ed 3oncs, Yice I'residcnt, Engineering at the number below or the undersigned. 7139771347; Sent By: AURORA#POWER; ~ 7139771347; Jun~5 15:24; Page 4/6 .. Your prompt attention to this matter is sincerely appreciated. Vcry Truly Yours, Rartdallll. ones, 1'L Manager, Land & Negotiations rj ones~~aurorapower.com Enc:losure5 cc;1~.. Clifford S. Pfoff E. Jones Duane "V'aagen lone crrekaogccspacing exceptionrequesl lc3 Sent By: AURORA#POWER; ~ 7139771347; Jun~5 15:24; P2ge 5/6 EXHIBIT " A " LONE CREEK 3 MD~FT 0.00 LONE CREEK 3 TVDSS FT 442.00, 57.20 384.80 1,0$7.00 -702.20 1,282.00 -897,2p 1.672.00 .. -1287.20 1,782.00 .. -1397,2p 2,112.00 -1`1'27.20 2,247.00 -1,86220 .. _ 2,422.00 _..: -2037.20 2 722.00 3 200.00 -2337,20 -2815,20 FORMATION TOP KB ELEVATIQN SURFACE ELENATION CARYA 2-1 (TOP TYUNEK) CARYA 2-1.1 SAND CARYA 2-2.3 SAND CARYA 2-3.1 SAND CARYA 2-4.2 SAND CARYA 2-5.1 SAND CARYA 2-5.2 SAND CARYA 2-6.0 SAND TD LONE CREEK 1 LONE CREEK 1 HIGH TO LONE MI~(FT) TVCISS FT CREEK 1 0.00 442,75 29.75 413.00 1,390.00 -977.Q0 1,440.00 -1,027,00 -129.80 ` 1,778,00 -1,385.00 -77.80 1,860.00 -1,447.00 -49.80 Z,4p0.Oq -1,9$7.00 -259,80 2,546.00 -2,133.00 270,50 2,732.00 -2,319.OD -281.80 2,940,00 -2,527.00 -189.80 11,487.00 -1,1074.00 Sent By: AURORA#POWER; ~ 7139771347; Jun~05 15:24; Page 8/6 ,~ Exhib~ B ~t"lU~1l~ki~ ~1'1t~ Bt~U~d- PH~LIP~A~ ks tnc. N Urni Area 3~ ~36 31 AL#848 ~4 ALK' 443= ~HT1 ~ ~ Aq ~3 R ~ ApC . 50 PAl~~O ~ PA150 `~. pA15f} APC ~p ~ .~` 2 C4615o2 . !7 ~ 7 74A ~ ~ ~ ~.~ , LC 1 ,~t,,, c~~o~ ~ ~ ~ P ~~ so r ~~ ,~ M) I 0 ~C.08~ C 1396 ~ ~~~~ . LC 3 ~ ~~' - - ~ ~~~ . ~.... ~ • • r 10333 Richmond, Suite 710 Houston, Texas 77p4z Phone; 713-377-5799 Fax: 713-977-1347 Fax Transmittal Form _. _. _ Te. i Fax: Phone: Re: ,. _.__.. i ---... ` I From: .---- .._ .. __ Date: -- -- urges; _ .- .._- .. CG. .. . , ,, __. .. _ I _ _~ 1-l Urgent ^ t=ar Review i_7 Please Comment f.J Please Reply n Please Recycle Message: ~~ NpTE; ! he intorntalion c:nnt:~rned in this Fax is confidential arnJlc~r privileged. This Fax is intended tnr tl~e sale use nn tl~~e irr,lrvrd- uaf named above. If' the reader c~E this tr~ansrttittal page is not the lrttended reCipierlt or a rrpr?Sentative of the intended reCi~>ier7t, you arP herPhy notified that arty review, disCrnination, distrihution, ur copying of'this fax or tht? information contiained hProir~ is prohibited, If you have received this fax In error, please immcdi.,tely notify the sCrid~r by telephone and r•Q[urrl Lhis €ax to rho, ;r~ndcr ~t the address about, ~~Aur~ara Gas, LLC www.aurorapowarcom Alaska Uil And Cias Conservation (_-omnrissiun 333 W 7th Avc;mie, Suite No. 1~(? Anchorage, Alaska 99501-3539 June 23, 2005 Attn: Mr. Steve Davies Pctraleunt ecologist G entlctncn: IZE: Application f'ar l~erntit to Uril( Lone Creek No.3 Well C'-615 UU Moqua:wkie Area. Rctcrvnce is made to the previously submitted A.pplicaiion. for Permit to Drill (APD) in heltall'of Aurora Gas, 1..1,,C (AiIkORA), as Operator of the captioned pt'op~secl development well. Although the App cocrtainetl art erroneous base ztjtmber, which will be corrccte;d, this letter respectfully xequcsts the AYD be approved with certain limita.tiotY placed upon AURORA, as discussed below. The; Lt>ne C'reek No_ l Well is currently producing gas lrorrA a surtaee location situated in the SW4 SE4 of Section 18, Township 12 Nnrth, Range 1 1 West, SM and the proposed captioned well is also planned to test gas at seven (7) intervals, but unfortunately is situated in the SW/4 NE4 of the aforementioned Scetioa~ 18. Both walls arc situated within the contincs of the Lone Creek Unit, (f/k/a tFte Mayuawkie Unit)_ Cottse;yuently, fire proposed captioned well will regtcire a spacing exception location pursuant to 20 AAC' 25.540. l-lowcver, ii should be known since AURORA was under the tnisunderstandi.ttg that since these intervals were behind pipe in the Tone Creek No.l no spacing exception was required and thus had planned to spud tltt; captioned proposed well an or before July 1, 2005. Consequently, this letter respectfully requests the AQGCC give favorable consideratio~~. to approving AURURA's Al?f), but prohibiting A[JJtORA's ability to produce said well from the producing gone in the Lonc Creek Nv, i, tl~e Carya 2-4.2 sand seen at 2400-2460', until the completion of the spacing exception pmeess. This proposal, if approved by the AOCiC:C, would allow ALFRURA to commence drilling operations artd test the intervals cif interest, as idcntifieti on Exhibit "A", but not produce hydrocarbons firom this Carya z-4.2 zone in the well until the spacing exception process in concluded. A.URORA's operational, drilling and testing program is briefly discussed below f'or your benefit. AITROCiA plans to dull the propase;d Lone Creek No. 3 Well to sufficient depth to test seven Lipper Tyonek ("Carya") sands that appear to he potentially productive in the Lotte Creek No..l well bore. All sands are expected to be; slructuraiiy higher io fire No. 3 than in the No. 1 Wcll, sort;e by as mach as 280 f'ect. Only one sand was tested in the Lone Creek No. l : the Carya 2-4.2 sand at 2,400-2,4(iU', and the No. 1 well is completed sc-lely in that zone, which has proved to be very productive, producing tx~ore than 3.2 .BCF to date, and still producing at a rate of about 1.7 MMcfpd. Although 10333 Richmond Avenue, Suite 710 • Houstpn, Texas 77042 •(713) 97T--5759 • Fax (713) 97T•1347 1400 West 9enson Blvd., Suite 410 • Anchorage, Ataaka 99503 + (907) 2TT-1003 • Fax (907) 277-1006 • • 110t tL'SILCI, log analysis indicates that soraae of these other sands tlla.y be productive in that well born; and t11at all have sufficicylt appar•etit porosity and permeability to produce gas if the reservoirs are gas bearing; at the up dip location of the No. 3. The total net thickricsses of these sands is about 24U' in the No. 1 well bare (bat are expected to be somewhat thinner in the No. 3), SS' of which is the producing Carya 2-4.2 zone, so there is a high percentage of potential pay to be tcsied_ The plan is to drill the well to 3,200 feet 1VII?/TVI) and run a full suite of apett- hole logs, probably including: aiTay induction, formation density, compensated neutron, di-pole sonic, .formation micro imager, side-wall cores acid fc>l~nation pressure tests (Schlumbcrger's MDT tool). following the setting and cementing of 5-1/2" production casinp; and analysis of these logs, the well will be perforated-probably a.ll zones that. appear to be gas productive without water will be perforated in one setup in an overbalanced well bore condition. 1'he canes will be isnlated with packer {and bridge l,ll)gs, as needed} and briefly tested individually (or in groups oft-3 adjacent canes with similar log characteristics), fi-om the bottunl up, to get gas production rates and to dctenlline .if water will be produced-the Carya 2-4.2 will be tested individually. LTpon d.eterminatian of productivity of each ~c1ne, the conlplet.ian string will be run- Ifnlultiple zones are productive, including the Carya 2-4.2, multiple packers (2 or 3) and sliding sleeves and retricvahle X-profile plugs will he used for selective completions to isolate the Carya 2-4,2 zone from the other productive zones and to prevent the Carya 2-4.2 £rom producing until the spacing exception process is completed. It should be noted i}lere are na issues regarding any injury to tllc correlative rights of any offsetting owners. Attached hereto as Exhibit `B' is a plat of the Lone Creek Unit. As you can see the offsetting landowner of the tract to the north of the drihsitc lease for the captioned well, C-615UU is the Cook Inlet Region, Inc. and the minerals under said tract are leased to Attrara Cas, LLC tieing C-fi1:395 least. The offsetting landowner of the tract tcy the e.35t and south of the captioned well is also the C..oolS Inlet Region Inc. ~u~d the minerals under bath tracts are also leased to Aurcira Gas, LLC being C-61396 lease. The offsetting Landowner of the tract to the west of the drillsite lease is tl~.e Mental Health Trust and although these MH'l' minerals are unleaseci said tract is in excess of approximately 3,900' fmm the proposed drillsite. Exl-tibit "B" reveals the location of the prapascd captioned well for which the spacing exception is sought, all other completed or drilling wells on the drillsite lease C-G1500, as well as tlic entire 1.~OnC Crcck Unit, and adjainitla properties. Please incorporate this request with the revised APD submittal corning from rairweather and give f2.vorable consideration to AURORA'S proposal. if you require additiartal information regarding this request, please contact Mr. Ed Jones, Vice 1?reside:nt, Engiixeerint; at the nutnbe;r below or the undersigned. • • Your prompt a.ttcnlion to t~~is rlYalter is sinccrcly apprcciatcsi. Vcry Truly Yours, ~tandall l~_ , c-nes, .PL Mai~agcr, Land & Nc~;olixlions ij <mes(u,)aurorapawer.cotn 1:'nclusures cc: A. C~litl~r(i S. E'foff F'. ,~OtleS Duane Vaa~;en l~nc crrek~ra~ccsl~acin~ e;xceptior~requCSt lc3 • EXHI~rT " A • FORMATtON TbP ....__ LONE GREEK 3 M~(FT~ LANE CREEK 3 TVDSS FT LONE CREEK 1 LONE CREEK 1 MD(FT} TVCISS(Fi") ` HIGH TO LONE CREEK 1 KB ELEVATION 0.00 . 442.00 0.00 442 75 "~ SURFACE ELEVATION _.... 57,20 __ 384.$0 . 29.75 413.00 CARYA 2-1 (TOP TYbNCK) ~ 1,087.00 -702.20 1,390.p0 -977 00 CARYA 2-1.1 SANTO 1,282.00 _ -897,20 , 1,440.00 -1 027.00 -129 80 CARYA 2-2.3 SANG CARYA 2-3.1 SAND _,1,672.00 9,782.00 -1287,20 -1397,20 , 1,778,00 -1,365.00 1,860.00 -1 447 00 . -77.80 49 80 CARYA 2-4.2 SAND __ 2,112.00 _ -1727,20 , . 2,400.pp -1 987 00 , -259 80 CARYA 2-5.1 SAND _ 2,247.00 ; _ -1,862.20 , . 2,546.00 -2 133 00 ~ . 270 80 CARYA 2-52 SAND 2,422.00 -203720 , . 2,732.00 -2,319.00 . -281 80 CARYA 2-6.0 SAND 2,72200 -2337.20 2 940.00 -2 527 00 . -189 80 j TC _ ....... 3,200.00 -2$15.20 , , , 11,487.00 _ -1,1074.00 . j • • ~c ~ Q LC 3 Exhibit B Ma~qua~rk~~ Unit Boundary (~tloNl,'~~J~s~r+r~ Cf~ ~ `~ Scare: NTS tr19-fit tf~(550~C?A+'fF. PHILLIPS At~sic~I1 Inc. ' _' ~ r ~ iilx~Nry m muyi A ~.~ C6YrW,Mf ' ~ •~ ~~ ~ Unit Area a tr 3~ ~i E. A1~484~3 ~ ~ ,'.~ 34 ALi4 ~$bd 3~ MH~3~401 ~ ADL3 33 ~ ~ r P,41 ~b ~ 50 PA! ~ ABC 50 ~ z~-?? 2-2 -03 a~.acsos a;~3 3: AQ!~31 Ab1~70419D X46) f;f}$f5~D2 A 50 .. - 7 ~ . i~0 rG1AYf~[iE~ 7 ~. 744 ~ ~ _~ ~o~. Un t Ate-. cas~~s~ arts . 384. . C#a~ ~ ~ ~ PA. 64 I~PC ~0 ,~re.t j~.frrC "_ ``~ 07~t-66 ~ AI SQ ` ~sa~ ~~ ~ Al L~~ t 7 i5 -~~ Ira C 1398 ,, ~~ it soornQ . cas7~nc; ~ Q~ -_ -~~ ~ . C G ~ I 22 r -~ ~ ~ ~ f'~''; ~ i ` A ~r` P 5 ~'~~~ ~ f ~ CNJ ~ /one / / ~ ~ ~ / ~ •l r L / /' v~ r ~xiV /fr' ~ r North Slope SpiN R®port ~ C3anerated on: i3P ~xpioration(Alasita),INC. 9tl0 East eensan Blvd. Anchorage, AK 99519612 27106/2005 t~ BPX Spill Rpti#; 05-149 Total fn Contalnment(Galions): 25 [late of Spill (DD/MM/YYYYj 22/06/2005 Total Outside Cantainmont(Gal)~ 0 I Time (>~iM;MM): 11:30:00 AM Recycled/Reused (Gal): 0 I~I Report Status: Fnal 17ispased (Gal}: .25 ~ -; 1 „; Locationl: West Surface Area Impacted (Sq.Ft): 1 ' +~ ~ ~s Locatlon2: Well Pad N All Secondary Containment? Y NRC Rpt#: Tundra Affectotl? N ,~ ; Company: Doyen Drilling water Affected? N °~.~ ,, Mater'~ai Name Amount (Gal)' ~~ , ~----• R v~MAT,~ -- ~ ~ C,.auso: A brass ball valve on a tine that injects Aqua Mate Into a boiler system for corrosion prevention failed. This caused appraxirnataly 1 pint of aqua mate to leak onto the bailer room floor and onto the secondary containment below the floor. Clean-Up: Tho product that spilled veto the boner room floor w as cleaned up w ith absorbent pads as well as the product that leaked onto the herculita. The contaminated absorbent pads w ere taken to an approved NS6 oily w astQ dumpster. Disposal: Tate contaminated absorbent pads w era taken to an approved N58 oily w dste dumpster. Environmentallmpact: None, all of the contaminated material has been cleaned up w ith absorbent pads. Pravgntative Action: i IThe defective ball valve w as replaced, I Additional tnformat)on; ° This report satisfies the notification requirements of t8 AAC 07b.300 Submitted By 7alephona P~ga7ofl ~~ . ~ent,tiy: AUFiUHA#NUWEH; ~ 7139771347; Jun-~5 15:16; Page 1 ~~~ / O ~ ,~...~i11Y ~.. may. ~ • ~~~~~ ~ ~.~ 10333 RichmOrtd, Suite 710 Wouston, Texas 77042 Rhone: 7~,3-97T-57~~ F~x:713-97T-1347 Fax Transmittal Form _.. ---. . ' To. From; Fax. __._ .. date: t , ~.. ~~~ Q,~ _.. Pht~ne: _. ... .. ..............._. Pages; _. _. _.... Re: J ~N. ~ /T... / _._... ..._ I-1 Urgent 11 For Review L] Please Comment Cl Please Raply ^ Please Recycle Message: ~~~~ . ~ ..a ". _ ~ ~ ~~ C~ ~ ~ NOTE: The into~marion r.~niained in tftis fax is confidential an<iJar f]rivd~gr~i, this tax is intended for the sole use an tfre individ- ual jldrtted above. 1f t.hr reader of this transmittal pa9? is nol ttte intended recipient or a representative of the intendedf reel gent, you dre !tetchy notified that arty review, dissemin~ition, di5irihutiorl, or copying of this fax or the information contained herein i5 prohibited, If you have received this fax in error, i~lcasE>. irrtrrre?cii~tely nr~t{fV the sender by tclephnnp and rr~turn Chime, fax t~~ thr• sender at thr addr~;S above. s Sent~By: AURORA#POWER; ~ 7139771347; Jun-~5 15:16; ..~ Au~r`~t ~r~~~ ~.LC www.aurorapower.com Page 2 _~ ~ ~~ ~~ ~_ _.. - ~ i V'''~ . Alaska (3i1 a.nd CAS Conservation Commissii~n 333 W 71h Avcnuc, ~uilc; No. lUU Anchora.~;c, Alaska 99501-3539 June 23, 2005 ~ ~~, .;; .., - Y . ~ :„ 9'.7 ~' `~.TI'f Attn: Mr. Steve Davies Petroleum Geologist Gentlemen: RE: Ap1?lication for Permit to Drill 1•/ane Creek No.:3 Weil C-61500 Moquar~vkie Area Reference is made; to the previously submitted Applicalio~.t for Yennit to Drill (APD) in behalf of Aurora tias, LLC (Ai1RC)RA), as Operator of t:he captioned propnsed development well. Although the APD contained an erroneous le~ese number, which will he corrected, this letter respectfully requests the APD be approved with certain iimitatior placed upon AURORA, as discussed below. The Lone Creek No.1 Well is currently producing gas from a surface location situated in the S W4 SE4 of Section 18, Townslup 12 North, Range 11 West, SM and the proposed captioned well is also platuied to test gas at seven ('~) intervals, but unfortunately is situated in the SE4 NE4 of the aforementioned Section 18. Both wells are situated within the confines of the Tone Creek Unit, {f/k/a tl~e 1Vloqu.awkie Ut~itj. Consequently, the proposed captioned well will require a spacing exception location pursuant to 20 AAC 25.540. .However, it should be known since AURORA was under the misunderstanding LhaE since ihes~ intervals were behind pipe in the l.Une Creek No.1 no spacing exception was required and thus had plaru~ed to spud the captioned proposed well on or before Jul~~ 1, 2005. Consequently, this letter respectfully requests the; AOCxCC give favorable consideration to approving AURURA's APD, but prohibiting AtTRORA's ability to produce said well from the producing zone in the Lonu Creek No. 1, the Carya 2-4.2 stuui seen at 240UT24fiU', until the eonlpietion oI` the spacing cxccption process- This proposal, if approved by the AOGCC, would allow AURORA to commence drilling; operations and lest the intervals of interest, as identified on Exhibit "A", but not produce hydrocarbons from this Carya 2-4.2 zone in the well until the spacing cxccption process in concluded. AUTtORA's operational, drilling and testing program is briefly discussed below for your benef 1. A.URC>RA plans to drill the proposed Lone Creek No. 3 Well to sufficient depth to lest seven Upper Tyoalek {"Carya") sands that appear to be potentially productive in the Lone Crock No.l well bore. All sands are expected to be structurally higher in lho No. 3 than in tho No. I Well, some by as much as 280 feel Only one sand was tested in the l,,one Creek. No. 1: the C:arya 2-4.2 sand at 2,400-2,460', and the No. 1. well is completed solely in that zone, which has proved to be very productive, producing more thaai 3.2 $CF to date, and still producing at a rate of about 1.7 MlVlcfpd. Although 70333 Riohmand Avtnue, Suite 710 • Houstart, texas 77042 • (J'13) 977-5799 • Fax (Tf3~ 977-1ad7 1a00 West Benson Blvd., Suite 410 • Anchprage, Alaska 995x? • (90T) 2TT--7003 • Pax (907) ?77.1008 Sent~By: AURdRA#POWER; Jun~05 15:16; not tested, lag analysis indicates that some otthese other sands maybe productive in that well bore and that all have sutf cient apparent porosity and penneabi lity to produce gas i1' the reservoirs are gas bearing at the up dip location of the Na. 3. The total net thicknesses of these sands is about 244' in the No. 1 well bore (but arc expected to be somewhat thinner in the Na. 3}, SS' of which is the producing Carya 2-4.2 zone, so there is a high percentage of potential pay to be tested. The plan is to drill the well to 3,200 feet MD/TVD and run a lull suite ofopen- hole logs, probably including: array induction, formation density, compensated neutron, di-pole sonic, far7nation micro imager, side-wall cores and formation pressure tests (Sclilumberger's MDT tool). Following the setting and cementing of 5-1/2" production casing and analysis ofthcse lags, the well will be perforated probably all zones that appear to be gas productive without water will be perforated in one set up in az~ overbalanced well bore condition. The zones will be isolated with packer (and bridge plugs, as needed) and briefly tested individually (or in groups of 2-3 adjacent zones with similar lag characteristics), from the bottom up, to get gas production rates and to determine if water will be produced-the Carya 2-4.2 will be tested individually. Upon determination of productivity of each zone, the completion string will be run. ifmultiple~ cones are productive, including the Carya 2-4.2, multiple packers (2 or 3) and sliding sleeves and retrievable X-proftlc plugs will be used for selective completions to isolate the Carya 2-4.2 zone from the other productive zones and to prevent tl~e Carya 2-4.2 (ruin producing until the spacing exception process is completed.. It should be Hated thorn are no issues regarding; any injury to the correlative rilht;s of any offsetting owners. Attached hereto as Exhibit `B' is a plat of the Lone Creek Unit. As you can see the offsetting landowner of the tract to the north of the drillsite lease for the captioned well, C-61500 is the Cook Inlet Region, Inc. and the minerals under said tract are leased to Aurora Gas, 1~1,C being C-61395 lease. The offsetting landowner ni' the tract to the east and south of the captioned well is also the Cook Inlet Region Inc. anti the minerals under both tracts are also leased to Aurora Cxas, LLC being C-61396 lease. The offsetting; landowner of the tract to the west of the drillsitc: lease is the Mental 1-(ealth Trust and although these MHT minerals are unleascd said tract is in excess of approximately 3,x)()0' from the proposed drillsitc. Exhibit "B" reveals the location of the proposed captioned well for which the spacing exception is sought, all other completed or drilling wells an the drillsite lease C-61500, as well as the entire I.vne Creek Unit, and ad}Dining properties. Please incorporate this request with the revised A.l~1J submittal coming from Fairweather and give favorable consideration to AURaRA's proposal. if you require additional infornYation regarding this request, please contact Mr. Ed Jones> Vice President, Engineering; at the number below or the undersigned. 7139771347; Page 3 Sent`By: AURORA#POUlER; ~ 7139771347; Jun~S 15:16; Page 4/6 Yaur prompt. attention to this matter is sincerely arpreciated. Very Tnily Yours, Randall D. apes, Pl,,, Manager, Land & Negotiations rj oncs(a)a.urorapowcr. cam rnc] asures cc: A. Clifford S. Pfaff E. Jones Duane Vaagen Ione cn•e~Caagccspacing exeeptionrequest le:i Se,nt• By: AURORA#PONJER; ~ 7139771347; Jun•05 15:16; P2ge 5/6 EXHYBIT " A " FORMATFON TOP LONE CREEK 3 LONE CREEK 3 LONE CRI1=K 1 LONE CREEK 1 HIGW TO LONE MD FT TVL7S3 FT MD FT _ 7VDSS(FT) CREEK 1 ~ KB ELEVATION 0.00 _442,00 0.00 442.75 SURFACE ELEVATION 57.20 384.80 29.75 413.00 CARYA 2-1 (TQP TYONEK) 1,087.00 -702.20 1,390.00 -977.00 i CARYA 2-1.1 SAND 1,282.00 -897.20 1,440.OD -1,027.00 -129.80 ~ CARYA 2-2.3 SAND 1,672.00 -128720 1,778.OD -1,365.00 I -77.80 CARYA 2-3.1 SAND __ 1,782.00 - -1397.20 - 1,860.00 -1,447.00 ~ -49.80 CARYA 2-4.2 SAND 2,'{_12.00 -1727.20 -- ~ 2,400,00 -1,987.00 -259.80 CARYA2-5.1 SAND 2,247.D0 -1,862.20 2,546.D0 -2,133.OD 270.80 CARYA 2-5.2 SAND 2,422.D0 _ -2037.20 ! 2,732.00 -2,319.00 -281.80 ~ CARYA 2-6.0 SAND __.,, 2,722.00, _2337.20 2,940.00 -2,527.00 -189.80 TQ 3 200,00 -2815.20 11,487.00 -1,1074.00 T Send By: AURORA#POWER; 7139771347; Ju -05 15:17; Page 6/6 • Exh~ik~t B Mo~quar~kie Unit ~ourrdary sc.~ r~r$ ~~r'~~` ~rf ~~~-m c~osazovxa~ PN~ 1P"S A~ Nao U~ttAree ~ . ~ ~ PAI 6b PA15Q PA1 ~0 arc ~ Z ~ -oa soar i~ :. cosr~ c~~ ~-~~ u~r~ie ~ 7 8 .~ f.~rr~ A~''w' !50 5b ~C 54 f ~ ~ ~ ~t 46 Zi. ~ ~~~ ~~ 22 . . C r r ~z ~ ~ P ~ f ~ ~~ _, I ~ i ~ ~~ J f ~ ~ ~ ~ ~ . f i / ~ ~ ,J /~ '~ :I: a~- ~..~ DATA SUBMITTAL COMPLIANCE REPORT 7/19/2007 Permit to Drill 2050970 Well Name/No. LONE CREEK 3 Operator AURORA GAS LLC API No. 50-283-20112-00-00 MD 3025 TVD 3025 Completion Date 7/25/2005 Completion Status 1-GAS Current Status 1-GAS UIC N REQUIRED INFORMATION Mud Log No Samples No Directional Surve Yes .~ DATA INFORMATION Types Electric or Other Logs Run: Schlumberger platform express, array induction, Dipole sonic imager, I Well Log Information: Log/ Electr Data Digital Dataset Log Log Run (data taken from Logs Portion of Master Well Data Maint Interval OH / type meairrmt rvumoer Name Scale meaia No Start Stop CH Received Comments C Las 13246 Induction/Resistivity 1 706 3013 Open 8/4/2005 CBL, PEX-AIT & DSI data, Dir Survey, Pert record, FMI, MDT og Mud Log 2 Col 80 3025 Open 8/4/2005 Wide Format og Mud Log 2 Col 80 3025 Open 8/4/2005 Narrow Format og Induction/Resistivity 25 Blu 1 706 3013 Open 8/4/2005 PEX Array Induction/Compensated Neutron Triple-Litho Density/ S P/G R/C a l i p e r og Formation Micro Ima 5 Blu 2 706 3012 Open 8/4/2005 Fulibore Micro-Imager Dual Axis Caliper "'Dip Presentation`° Log Sonic 5 Col 2 706 2961 Open 8!4/2005 Dipole Sonic Imager Monopole P & S /Lower Dipole og Formation Tester 5 Blu 4 980 2886 Open 8/4/2005 Modular Dynamics Tester ~- Formation Pressure i pt Directional Survey 1 706 3000 Open 8/4/2005 og Cement Evaluation 5 Blu 1 600 2957 Case 8/4/2005 Slim Cement Mapping ' Tool, Cement Bond Log w/GR/CCL Correlation og Perforation 5 1 2282 2864 Case 8/4/2005 Perf Record, 3.5" HSD Powerjet Guns 6 SPF/60 Deg Phasing 'Nell Cores/Samples Information: Sample Interval Set Name Start Stop Sent Received Number Comments DATA SUBMITTAL COMPLIANCE REPORT 7I19I2007 Permit to Drill 2050970 Weli Name/No. LONE CREEK 3 Operator AURORA GAS LLC API No. 50-283-20112-00-00 MD 3025 TVD 3025 Completion Date 7/25/2005 Completion Status 1-GAS Current Status 1-GAS UIC N Cuttings 60 3030 1156 ~__ ADDITIONAL INFORM-AT~~ION Wefl Cored? Y /V~ Daily History Received? ~N Chips Received? ''t.,~-,~ Formation Tops ~ N Analysis ~f~' .- Received? Comments: Compliance Reviewed By: Date: L._J STATE OE ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 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 Dritl Number: Aurora Gas, LLC July 25, 2005 205-097 3. Address: 6. Date TD Reached: 12. API Number: 1400 West Benson Blvd., Suite 410 Anchorage AK 99503 July 15, 2005 50- 283-20112-00 4a. Location of Well (Governmental Section): 7. KB Elevation (ft): 13. Well Name and Number: Surface: 1579' FNL 1,368' FEL Sec 18, T12N, R11 W SM 385.5' AMSL Lone Creek #3 Top of Productive Horizon: 8. Plug Back Depth(MD+TVD): 14. Field/Pool(s): Same 2,968' MD, 2,968' TVD Lone Creek Total Depth: 9. Total Depth (MD + TVD): Same 3,025 MD, 3,025' TVD 4b. Location of Well (State Base Plane Coordinates): 10. Land Use Permit: 15. Property Designation: surface: x- 272198.24$ y- 2608542.844 Zone- 4 Private C-061500 TPI: x- Safne Y- Zone- 16. Type of Completion (Describe): Total Depth: x- Same y- Zone- Multi-packer Selective w/ screens across lower perforations 17. Casing Size Weight per foot, Ib. I.D. in inches Set at ft. 19. Perforations: From To 5-1/2" 17# a.s92 3,020' SWS 3-1/2" HSD DP PJ HMX 6 spf 18. Tubing Size Weight per foot, Ib. I.D. in inches Set at ft. 2,844'-2,864', 2,830'-2,840' 2-7/8" s.5# 2.441 2,857' 2,796'-2,816', 2,620'-2,670' 20. Packer set at ft: 21. GOR cf/bbl: 22. API Liquid Hydrocardbons: 23. Speck Gravity Flowing Fluid (G): 2,556' N/A None 0.562 24a. Producing through: 24b. Reservoir Temp: 24c. Reservoir Pressure: 24d. Barometric Pressure (Pa): Tubing ^ Casing 92 F° 1,285 psia @ Datum 2,742 TVDSS 14.65 psia 25. Length of Flow Channel (L): Vertical Depth (H): Gg: % COZ: % NZ: % H2S: Prover: Meter Run: Taps: 2,742 2,742 0 1.34 0 Daniel Sr. 4.016 Flange 26. FLOW DATA TUBING DATA CASING DATA No. Prover Choke Line X Orifice pressure Diff. Temp. Pressure Temp. Pressure Temp. Duration of Flow Size (in.) Size (in.) Psig Hw F° psig F° psig F° Hr. 1. 4 X 2 5/8 1,156 61 2 hrs. 2• 4 X 2 5/8 1,116 61 2.25 hrs. 3• 4 X 2 5/8 1,078 63 2.25 hrs. 4• 4 X 2 5/8 996 67 1.75 hrs. 5. X N Basic Coefficient 24 H ~ Pressure Flow Temp. Gravity Factor Super Comp. Rate of Flow o. ( - our) h Pm Factor F g Factor O Mcfd Fb or Fp Ft Fpv 1. 235 Calculated using Daniel Sr. 4,441 2. 235 Orifice Meter Readings 6,Q49 3. 235 7,348 4. 235 9,428 5. Temperature for Separator for Flowing No. Pr T Tr z Gas Fluid Gg G 1. 2. 3• Critical Pressure 4• Critical Temperature 5. Form 10-421 Revised 1/2004 CONTINUED ON REVERSE SIDE Submit in Duplicate Pc 1,207 pct 1,456,849 1,285 p{~ 1,651,225 No. Pt Ptz Pct-Ptz ~ Pw2 PcZ-Pv~ Ps Ps2 P~-P s 1. 1,156 1,336,336 120,513 1,248 1,557,504 93,721 2. 1,116 1245,456 211,393 1,221 1,a9o,841 1so,384 3. 1,076 1,157,776 299,073 1,196 1,430,416 220,809 a. 996 992,016 464,833 1,149 1,320,201 331,024 5. 25. AOF (Mcfd) 24,568 Remarks: All flows calculated using Ryder Scott Software. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed _(~G~!~~~~'y~--' Title Operations Manager n 0.599548 Date 5/a/2oo7 DEFINITIONS OF SYMBOLS AOF Absolute Open Flow Potential. Rate of Flow that would be obtained if the bottom hole pressure opposite the producin 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= ~ 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 1/2004 Side 2 Ryder Scott Reservoir ~~ Solutions ~~+ (Public) (Protected) WELL NAME: LONE CREEK NO.3 _ FIELD: _ LONE CREEK LOCATION: WEST SIDE OF COOK INLET, ALASKA RESERVOIR: UPPER IYONEK CARYA 2-5.2 and 2-6.0 BOTTOMHOLE TEMP, °F: 92 SOUR GAS MOLE % GAS GRAVITY: 0.560 N2 1.00 _ Hz0 GRAV17'Y, yW: 1.040 COZ 0.05 COND. GRAV., °API: HZS 0.00 TVD. FT. 2742 1 MEAS. DEPTH, FT: 2,742 Options Cond. Correa. (YIN): N ~ Ch c If I ti W ll Corrected* Tc, °R: 343.45 e k, njec on e Corrected* Pc, Psia: 671.90 0 Smooth Pipe Roughness Pressure Base, Psia: 14.650 TUBING ID, IN.: 2.441 ~~* Wa:hert-flziz correction for contaminants, if arty _o X a i,ooo n° Na RESULTS AOF, Mcf/d: 24,568 C: 4.595876 n: 0.599548 p - - -- ---~- ~; I k 100 ' , 100 1,000 10,000 100,000 Firnv Rate, Mcfld POINT NO. Test Data FLOWING (Automatic) Q, Mcffd BCPD BWPD FTP, Psia WHT, °F BHP, Psia COMMENT SHUT-IN ' 0 0 0 1,207 60 1,285 SIBHP 1 2 I 3 4 4,441 6,049 7,348 9,428 0 0 `~ 0 0 0 0 0 1,156 1,116 1,076 996 61 61 63 67 1,248 1,221 7,196 _1,149 _ __ These results were prepared using Reservoir Solotions Software. This is not Ryder Scott work product. ~-~ Ryder Scott WELL NAME: LONE CREEK NO. 3 AURORA GAS, LLC WELL TEST REPORT WELL: _ LONE CREEK NO. 3 4-POINT TEST--LOWER COMPLETION (CARYA 2-6.0 AND 2-5.2) DATE: 9/1/2005 i~ DATE ACTIVITY T PRESS WH CHOKE SEP OR IFICE MET ER METER RATE CUM WATER TIME PERFS SPYDR, PSI TEMP de F _ /64" PRESS si STATIC blue DFF red TEMP reen FACTOR Q MCF/D VOL MCF METER BBLS 235 0 235 0 1230 shut in tubin si 1193 235 0 200 o en to flare 1193 24 740 6.4 4.4 7.8 235 6617.6 215 1160 27 700 8.2 6.3 6.25 235 9179.1 X430 1147.6 30 700 8.3 2.9 82 235 4293.45 1445 1146.5 30 700 6.3 2.9 6.2 235 4293.45 1500 1159.7 30 680 6.2 2.5 6.15 235 3642.5 1515 1141 30 700 6,3 3.1 6.2 235 4589.55 1530 1142.3 30 700 6.3 3 6.2 235 4441.5 1545 1145 30 700 6.3 3 6.35 235 4441.5 1600 1141.2 30 700 6.3 3 6.35 235 4441.5 1615 1144.8 30 700 6.3 3 6.4 235 4441.5 f$30 1149 30 710 6.3 3 6,4 235 4441..5 1645 1141.5 30 700 8.3 3 6,4 35 4441.5 1645 o en choke 34/64 34 235 0 1700 1104 34 700 6.3 4.1 6.5 235 6070A5 1715 1102.6 34 800 6.3 4 6.5 235 5922 1730 1102.5 34 700 5.9 4.4 6.4 235 6100.6 1745 1098.4 34 720 5.9 4.3 6.4 23`r 5961.~~5 1800 1099.4 34 690 . 5.$ 4.5 6,4 2a:i , 613y.5 ~ 1815 1100.2 34 700 5.85 4.4 6.4 'i 22 80~""' `~ 9 '' 1830 1101 34 700 5.8 4.4 8.4 23 ; 2 5i~' ~ 184b o en choke 38/64 1101.2 34 700 5.85 4.4 6.4 2 a 8 )~ 9 ;~~_ 1900 1055.7 38 700 5.85 5.35 6.45 2"' 735' 3 1917 1050.6 38 700 5.85 5.3 6.5 Z.i 729: 5 1931 1056.2 38 700 5.85 5.3 8.5 2-' 729 5 1945 1060.2 38 700 5.9 5.3 6.5 73' S 2 ' 2000 1062.7 38 700 5.9 5.3 6.5 ~ 2~' 73' 5 POINT 1 POINT 2 C J 2015 1064 38 700 5.9 5.3 6.5 235 7348.45 2030 1062.2 38 700 5.9 5.3 6.5 235 7348.45 2045 1060.9 38 700 5.85 5.25 6.5 235 7217.438 21~ 1061.4 38 700 5.9 5.3 6.5 235 7348.45 2115 1021.3 41 700 5.8 6.05 6.6 235 8246.15 2130 958.43 42 700 5.9 6.65 6.7 235 9220.225 2145 963.77 42 700 5.9 6.6 6.7 235 9150.9 2200 976.36 42 700 5.9 6.7 6.7 235 9289.55 2215 981.2 42 700 5.9 6.8 6.7 235 9428.2 2230 983.51 42 700 5.9 6.8 6.7 235 9428.2 2245 981.43 42 700 5.9 6.8 6.7 235 9428.2 2300 978.14 2301 Shut in for buildu 1192.2 2302 1192.7 2303 1192.8 2304 1192.7 2305 1192.7 2310 1192.9 POINT 3 POINT 4 2315) ~ 1183 9/5/2005 730 Long SITP 1192 STATE OF ALASKA ALAS OIL AND GAS CONSERVATION COMMISSION GAS WELL OPEN FLOW POTENTIAL TEST REPORT 1a. Test: / Initial Annual Special 1b. Type Test: Stabilized Non Stabilized / Multipoint ^ Constant Time ^ Isochronaf ^ Other 2. Operator Name: 5. Date Completed: 11. Permit to Drill Number: Aurora Gas, LLC July 25, 2005 205-097 3. Address: 6. Date TD Reached: 12. API Number: 1400 West Benson Blvd., Suite 410 Anchorage AK 99503 July 15, 2005 50- 283-20112-00 4a. Location of Well (Governmental Section): 7. KB Elevation (ft): 13. Well Name and Number: Surface: 1578' FNL 1,367' FEL Sec 18, T12N, R11 W SM 385.5' ASML GL@ 371' Lone Creek #3 Top of Productive Horizon: 8. Plug Back Depth(MD+TVD): 14. Field/Pool(s): Same 2,968' Lone Creek Total Depth: 9. Total Depth (MD + TVD): Same 3,025' 4b. Location of Well (State Base Plane Coordinates): 10. Land Use Permit: 15. Property Designation: Surface: x- 272198.24 y- 2608542.844 Zone- 4 Private C-061500 TPI: x- Same Y- Zone- 16. Type of Completion (Describe): Total Depth: x- $arpg y- Zone- Multi-packer Selective w/ Screens across lower perforations 17. Casing Size Weight per foot, Ib. I.D. in inches Set at ft. 19. Perforations: From To 5-1/2" 17# a.ss2 3,020' SWS 3-1/2" HSD DP PJ HMX 6 spf 18. Tubing Size Weight per foot, Ib. I.D. in inches Set at ft. 2,420'-2,425', 2,363'-2,378' 2-7/8" s.5# 2.441 2,s57' 2,282'-2,317' 20. Packer set at ft: 21. GOR cf/bbl: 22. API Liquid Hydrocardbons: 23. Specific Gravity Flowing Fluid (G): 2,229' N/A None 0.562 24a. Producing through: 24b. Reservoir Temp: 24c. Reservoir Pressure: 24d. Barometric Pressure (Pa): Q Tubing ^ Casing 92 F° 1,008 psia @ Datum 2,340 TVDSS 14.65 psia 25. Length of Flow Channel (L): Vertical Depth (H): Gg: °lo COZ: % NZ: % HZS: Prover: Meter Run: Taps: 2,340' 2,340 0 1.34 0 Daniel Sr. 4.016 Flange 26. FLOW DATA TUBING DATA CASING DATA No. Prover Choke Line X Orifice pressure Diff. Temp. Pressure Temp. Pressure Temp. Duration of Flow Size (in.) Size (in.) Psig Hw F° psig F° psig F° Hr. 1 • 4 X 2 925 61 2.5 hrs. 2• 4 X 2 860 61 5.75 hrs. 3• 4 X 2 829 63 3 hrs. 4. 4 X 2 797 67 3.5 hrs. 5. 4 X 2 N Basic Coefficient 24 H h~ pressure Flow Temp. F Gravity Factor Super Comp. Rate of Flow o. our) ( - Pm actor Fg Factor Q~ Mcfd Fb or Fp Ft Fpv 1. 131 Calculated using Daniel Sr. 1,737 2. 131 Orifice Meter Readings 3,210 3. 131 4,127 4. 131 5,180 5. Temperature for Separator for Flowing ' No. Pr T Tr z Gas Fluid Gg G 1. 2. 3. Critical Pressure 4• Critical Temperature 5. Form 10-421 Revised 1/2004 CONTINUED ON REVERSE SIDE Submit in Duplicate Pc 1,008 pct 1,016,064 ~ 1,063 p~ 1,129,969 No. Pt Ptz Pct-Ptz ~ Pv~ PcZ-Pv~ Ps Psz Pf -Ps2 1. 925 855,625 160,439 986 972,16 157,773 2. 860 739,600 276,464 921 sas,2a1 281,728 3. 829 6$7,241 328,823 895 801,025 328,944 a. 797 635,209 380,855 870 756,900 373,069 5. 25. AOF (Mcfd) 15,658 Remarks: All flows calculated using Ryder Scott Software. n I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed (/~,~~ Title Operations Manager Date 5!sl2oo7 DEFINITIONS OF SYMBOLS AOF Absolute Open Flow Potential. Rate of Flow that would be obtained if the bottom hole pressure opposite the producin face were reduced to zero psis 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= ~ 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 1!2004 Side 2 Ryder Scott WELL NAME: LONE CREEK #3 _ ~ ~ ~ Reservoir FIELD: LONE CREEK UNIT ~`~. Solutions _ LOCATION: _ SEC 18, T12N, R11W SM, WEST SIDE OF COOK INLET, ALASKA \~ (Public) RESERVOIR: CARYA 2-4.2 8, 2-5.1 (Protected) tio,ooo - _ _ _ _ I I -~- -- I i I I i TVD, FT: 2,340 _ x ~ I ~, i - I ' - - - - - a ~.ooo - - a - - ~, ;1 * Wicftert-Aziz correction for contaminants, if any ~ I i ~ 1 ~ .. ' ~~ ~ ~I ~ ~ goo , ~ goo ~,ooo ~o,ooo ~oo,ooo Flow Rate, MCf/d BOTTOMHOLE TEMP, °F: 84 SOUR GAS MOLE GAS GRAVITY: 0.562 N2 1.34 HZO GRAVITY, yv,,: 1.130_ COZ 0.00 COND. GRAV., °API: HZS 0.00 MEAS. DEPTH, FT: 2,350 Options Cond. Corral. (Y!N): - N -- ^ If Injectlon Well Check Corrected' Tc, °R: 343.49 , Corrected* Pc, Psia: 671.31 0 Smooth Pipe Roughness Pressure Base, Psia: 14.650 TUBING ID, IN.: 2.441 POINT NO. Test Data FLOWING (Automatic) Q, Mcf/d BCPD BWPD FTP, Psia WHT, °F BHP, Psia COMMENT SHUT_-IN 1 0 ~ 1,737 ~ 0 ; 0 i _ 0 22 1,008 925 60 - --_ 56 1,063 ~ 986 SIBHP ___ 2 3,210 I ___ _ 17 ~ 880 60 _ 921 __ 3 _ 4,127 ~- _ 0 _ _ _ J 11 __8_29 ~ 62 895 4 5,180 0 0 797 64 870 - - -- I RESULTS _ AOF, Mcf/d: 15,658 _C: 0.013854 n: 1.000000 These results were prepared using Reservoir Solutions Software . This is not Ryder Scott work product. AURORA GAS, LLC WELL TEST REPORT WELL: _ LONE CREEK NO.3 4-POINT TEST--UPPER COMPLETION (CARYA 2-4.2 AND Z-5.0) DATE: 9/6/2005 I• DATE ACTIVITY T PRESS Wli CHOKE SEP OR IFICE MET ER METER RATE CUM WATER TIME PERFS SPYDR, PSI TEMP de F ^ /84" PRESS si STATIC blue DIFF r®d TEMP teen FACTOR Q MCF/D VOL MCF METER BBLS 8:00 Shut-in since 993.2 2.0"orifice 1900 hrs on 9/5/05 67.193 8:13 O en to test unit 993.21 131 0 907.9 24 500 4.9 2.3 6.7 131 1476.37 825 o en choke 26/64 980.18 26 500 4.9 2.3 6.7 131 1476.37 831 970.24 26 480 5 2.1 6.5 131 1375.5 845 choke 24/64 892.$7 24 480 5 2.1 6,5 131 1375.5 845 895.55 24 510 5.05 2.9 6.31 131 1918.495 900 901.5 24 500 5.1 2.8 6.1 131 1870.68 915 904.82 24 510 5.05 2.7 6.1 131 1786.185 930 905.73 24 510 5.1 2.7 6.1 131 1803.87 947 906.9 24 520 5.1 2.7 6.05 131 . 180 .8T 1000 907.74 24 520 5.1 2.7 6.05 131 1803.87 1015 1.85bbls H2O (sam ie) 908.1 24 520 5.1 2.$ 6.15 131 870.68 1030 909.07 24 520 5.1 2.6 6.1 131 1737.06 1045 909.69 24 520 5.1 2.6 6.1 131 1737;6' 1100 910.24 24 520 5.1 2.6 6.1 131 1737. J6 1115 886.44 28 500 4.9 3.45 6.1 131 2214 555 1130 887.17 28 500 4.9 3.4 6.05 131 1€4~. 46 -~ 1145 o en choke 857.87 29 520 5.05 3.95 6.1 131 261: `23 ~ .~~ 1200 873. i 4 29 520 5 4 6,1 131 ' `~ ?0 1215 852.49 29 520 5.05 4.45 6. 131 294` .3~ ~. 1230 choke 28/8412:18 m 825.5 28 5 5.1 5.05 6.3 131 337" 15 1245 1235 closed choke 840.03 27 510 5 4.9 6.3 131 `3 ~ ~.5 0:00 ~ 1.75 27 520 4:95 4.8 6.3 131 3 "~ i6 _ 0:00 834.4$ 27 520 5 4.9 6.3 131 '~ .: " 1330 837.56 27 520 5 4.9 6.3 131 1345 837:61 27 520 5 4.9 6.;~ 131 `J ~.fi, 1400 836.48 27 520 5 4.9 6.3 131 ~5 ~ 1415 847.85 27 520 5 4.8 6,2~ 131 ;_ ' ~ 1430 844.58 27 520 4.9 5 6.3~ 131 _ ~ .°-~ _ 1445 o en choke 30/64 799.77 30 500 4.95 5.2 6.4 131 3 ~ 3A ~_ ~ 1500 798.9 30 500 4:95 6 6.4 131 ~ . ~ ~. ~~.-. initial reading POINT 1 POINT 2 1515 808.12 30 510 5 5.9 6.4 131 3864.5 1530 788.04 30 510 5 6.1 6.45 131 3995.5 1545 801.31 30 510 5 6.1 6.45 131 : 3995.5 1600 $01.03 30 510 5 6.15 6.45 131 4028.25 1615 803.81 30 510 5 6.2 6.45 131 4061 1630 807.52 30 510 5 6.3 6.45 131 . 4126.5 1645 811.74 30 510 5 6.25 6.45 131 4093.75 1700 809.12 30 510 5 6.25 6.5 131 4093.75 1715 816.04 30 510 5 6.3 6.45 131 4126.5 13'30 814.71 30 510 5 6.3 6.45 131 4126.5 1745 o en choke 35/64 738.93 35 500 5 7.5 6.6 131 4912.5 1800 755.5 35 500 5 7.7 6.6 131 5043.5 1815 759.88 35 500 5 7,7 6.6 131 5043.5 1830 759.09 35 500 5 7.7 6.6 131 5043.5 1845 765.76 35 500 5 7.75 6.6 131 5076.25 1900 773.83 35 500 5 7.75 6.6 131 5076.25 1915 768.11 35 500 5 7.7 6.6 131 . 5043.5 1930 768.11 35 500 5 7.8 6.6 131 5109 1946 777.66 35 500 5 7.8 6.6 131 5109 2000 771.07 35 500 5 7.85 6.6 131 5141.75 2015 780.41 35 500 5 7.8 6.65 131 5109 2030 778.72 35 500 5 7.9 6.6 131 5174.5 2045 780.31 35 500 5 7.8 6.6 131 5109 2100 Shut in for buildu 782.2 35 500 5 7.9 6.55 131 5174.5 2102 968.21 131 0 2103 990.56 131 0 2104 991.07 131 0 2105 991.39 131 0 2106 991.56 131 0 2107 991.73 131 0 2108 991.87 131 0 2109 991.9 131 0 2110 991.95 131 0 2111 991.95 131 0 9/7/2005 131 0 711 10hr build-u 992.52 131 0 131 0 131 0 131 0 131 0 POINT 3 PAINT 4 s • -~Aurrora Gas, LLC www.aurorapower.com February 8, 2006 Mr. John Norman, Chair Alaska Oil and Gas Conservation Commission 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 Re: Revised final well completion report forms for Lone Creek #3 (API # 50-283-20112-00) & Moquawkie #3 (API#50-283-20111-00) Dear Mr. Norman: Aurora Gas, LLC hereby submits Revised well completion Report forms Moquawkie #3 and Lone Creek #3. As discussed, well test data and formation tops have been entered in the appropriate places. If you have any questions or require additional information, please contact the undersigned at (713) 977-5799, or John Breitmeier at Fairweather E&P Services, Inc (907) 258-3446. Jones ice President Aurora Gas, LLC Engineering cc: Keith Sanders, CIRI John Breitmeier, Fairweather 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 R~CE11/ED STATE OF ALASKA ALASKA CND GAS CONSERVATION COMMISSIC~ Revised FEB 1 3 2006 WELL COMPLETION OR RECOMPLETION REPOR~e~~~ins 1a. Well Status: Oil^ GasO Plugged ^ Abandoned^ 20AAC 25.105 GINJ^ WINJ^ WDSPL^ No. of Completions Suspended^ WAG^ 2oAAC 25.»o Other 1b. Well Class: AfiChOfB~@ Develgpment (] Explora ry^ Service ^ Stratigraphic Test^ 2. Operator Name: Aurora Gas, LLC 5. Date Comp., Susp., or Completed: 25~Ju1-05 12. Permit to Drill Number: 205-097 3. Address: 1400 West Benson Blvd, Suite 410 Anchorage, AK. 99503 6. Date Spudded: July 4, 2005 13. API Number: 50-283-20112-00 4a. Location of Well (Governmental Section): Surface: 1578' FNL, 1367' FEL, S18, T12N, R11W, SM 7. Date TD Reached~,~ly Jul-605 ~ ~ 14. Well Name and Number: Lone Creek No. 3 Top of Productive Horizon: Same 8. KB Elevation (ft): 385.5' AMSL GL @ 371' 15. FieldlPool(s): Total Depth: Same 9. Plug Back Depth(MD+TVD): 2968' MD, 2968' TVD Lone Creek 4b. Location of Well (State Base Plane Coordinates): Surface: x- 272198.248 y- 2608542.844 Zone- 4 10. Total Depth (MD + ND): 3025' MD, 3025' TVD 16. Property Designation: C-061500 TPI: x- 272198.248 y- 2608542.844 Zone- 4 Total Depth: x- 272198.248 y- 2608542.844 Zone- 4 11. Depth Where SSSV Set: N!A 17. Land Use Permit: 18. Directional Survey: Yes ^ No ~ Wireline Surveys w/ extrapolated pt at TD. 19. Water Depth, if Offshore: N/A feet MSL 20. Thickness of Permafrost: N/A 21. Logs Run: Schlumberger Platform Express, Array Induction, Dipole Sonic Imager, Inclinometer, MDT and SWC's 22. CASING, LI NER AND CEMENTING RECORD CASING WT. PER GRADE SETTING DEPTH MD SETTING DEPTH TVD HOLE SIZE CEMENTING RECORD AMOUNT F.I. TOP BOTTOM TOP BOTTOM PULLED 117/8 71.8# P-110 Surface 80' Surface 80' driven 8 5/8" 32# WC-50 Surface 700' Surface 710' 10 5/8 40 bbls 14.5 ppg GasBlk "G" 5 1/2" 17# J-55 Surface 3018' Surface 3018' 7 7/8" 34 bbls 13.5 #!g Lead 79.2 bbls 15.8 #/g Tail 23. Perforations open to Production (MD + TVD of Top and Bottom 24. TUBING RECORD Interval, Size and Number; if none, state "none"): SIZE DEPTH SET (MD) PACKER SET (MD) Guns: 3 1/2" HSD PD PJ HMX @ 6 SPF& 60 Deg Phasing: 2 7/8" 6.5# 8rd EUE 2857.5' 2229' & 2556' & 2732' 2282' - 2317', 2363' - 2378', 2420' - 2425', 2620' - 2670', 2796' - 2816', ' ' ' 25. ACID, FRACTURE, CEMENT SQUEEZE, ETC. - 2840 , 2844 - 2864 . 2830 DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED All Depths MD & TVD. Directional Tendency is minor, MD & TVD within .5 ft. 26. PRODUCTION TEST Date First Production: July 22, 2005 Method of Operation (Flowing, gas lift, etc.): Date of Test: 7/24/2005 Hours Tested: 1.0 Production for Test Period Oil-Bbl: 0 Gas-MCF: 310 Water-Bbl: 0 Choke Size: 40/64 Gas-Oil Ratio: NA Flow Tubing Press. 920 Casing Press: Calculated 24-Hour Rate ~.~- Oil-Bbl: 0 Gas-MCF: 7435 Water-Bbl: 0 Oil Gravity -API (corr): NA 27. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water (attach separate sheet, if necessary). Submit core chips; if none, state "none". ' sion Form 10-407 Revised 12/2003 ' (~ ~ R ~ ~ TINUED ON REVERSE I~; p R -V-, 'v 28. GEOLOGIC MARKER 29. ORMATION TESTS NAME TVD Include and briefly su ze test results. List intervals tested, and attach KB ELEVATION 0.00 0.00 detailed supporting data as necessary. If no tests were conducted, state SURFACE ELEVATION 14.40 14.40 'None". TSUGA 2-8 COAL 445.00 445.00 2796-28x4'. 6739 mcfd.1000nsia. 36/64";2620-2670'. 7000mcfd. 960 TSUGA2-8 1 SAND 605 00 605 00 psia.36/64";2383-2425'. 2395mcfd.525osia.28/64";2620-2864'.7435 . TSUGA 2 82 SAND . _ _ __ -~- 9 0 Q0 - - ._ ____ - 50 0 --y mcfd 920 sic 40/64"~ Please S e Attached Flow Te t Information. - . 5 9 0 CARYA 2-1 (TOP TYONEK) ~ 1055.00 1055.00 CARYA 2-2 COAL 1245.00 1245.00 CARYA 2-2.1 SAND ------------------ 1325.00 --------------------- 1325.00 CARYA 2-3.1 SAND 2092.00 2092.00 CARYA 2-4.2 SAND 2282:00 2282:00___ CARYA 2-5.1 SAND __- - - 2420.00 --- -- - 2420.00 CARYA 2-5.2 SAND 2608.00 2608.00 CARYA 2-6.0 SAND 2790.00 2790.00 30. List of Attachments: Wellbore & Com letion Schematic Drillin and O erations re ort. 31. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Printed Name: J. Edward Jones Title: Executive Vice President Engineering-Operations Date: Si nature: `-- ~-~ Phone: '~~ -' ~~ ~~> ~~ ~~ ~ ~ ~~O j INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and tog on alt types of lands and teases in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the dawnhole well design is chanced. Item 1a: Classification of Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Satt Water Disposal, Water Supply for 1 njection, Observation, or Other. Multiple completion is defined as a well producing from more than one pool with production from each pool completely seareaated. Each seareaated 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 far 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 welt is completed for separate production from more than one interval (multiple completion), sa 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. showina 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 STATE OF ALASKA ALA OIL AND GAS CONSERVATION COM ON JAN 3 0 2006 WELL COMPLE~N OR RECOMPLETION PORT_~Nll~. LOG _ 1a. Well Status: Oil Gas ~ Plugged Abandoned 20AAC 25.105 GINJ^ WINJ^ WDSPL^ No. of Completions Suspended WAG 20AAC 25.110 Other 1b. Well Class: ~1, Development ^ aD~~~ry ^ Service ^ StratigraphicTest^ 2. Operator Name: Aurora Gas, LLC 5. Date Comp., Susp., or Completed: 25-Jul-05 12. Permit to Drill Number: 205-097 3. Address: 1400 West Benson Blvd, Suite 410 Anchorage, AK. 99503 6. Date Spudded: July 4, 2005 13. API Number: S0-283-20112-00 4a. Location of Well (Governmental Section): Surface: 1578' FNL, 1367' FEL, S18, T12N, R11W, SM 7. Date TD Reached: J 5 JAS 14. Well Name and Number: Lone Creek No. 3 Top of Productive Horizon: Same 8. KB Elevation (ft): ,y 385.5' AMSL GL @ 371' 15. Field/Pool(s): Total Depth: Same 9. Plug Back Depth(MD+TVD): 2968' MD, 2968' TVD Lone Greek 4b. Location of Well (State Base Plane Coordinates): Surface: x- 272198.248 ' y- 2608542.844 ' Zone- 4 10. Total Depth (MD + TVD): ~ 3025' MD, 3025' TVD 16. Property Designation: C-061500 TPI: x- 272198.248 y- 2608542.844 Zone- 4 Total Depth: x- 272198.248 y- 2608542.844 Zone- 4 11. Depth Where SSSV Set: N/A 17. Land Use Permit: Private 18. Directional Survey: Yes No ~ Wireline Surveys wl extrapolated pt at TD. 19. Water Depth, if Offshore: N/A feet MSL 20. Thickness of Permafrost: N/A 21. Logs Run: Schlumberger Platform Express, Array Induction, Dipole Sonic Imager, Inclinometer, MDT and SWC's 22. CASING, LINER AND CEMENTING RECORD CASING WT. PER GRADE SETTING DEPTH MD SETTING DEPTH TVD HOLE SIZE CEMENTING RECORD AMOUNT FT TOP BOTTOM TOP BOTTOM PULLED 117/8 71.8# P-110 Surface 80' Surface 80' driven 8 5/8'° 32# WC-50 Surface 710 Surface 710' 10 5/8 40 bbls 14.5 ppg GasBlk "G" 5 1/2" 17# J-55 Surface 3018' Surface 3018' 7 7/8" 34 bbls 13.5 #/g Lead 79.2 bbls 15.8 #/g Tail 23. Perforations open to Production (MD + TVD of Top and Bottom 24. TUBING RECORD Interval, Size and Number; if none, state "none"): SIZE DEPTH SET (MD) PACKER SET (MD) Guns: 3 1/2" HSD PD PJ HMX @ 6 SPF& 60 Deg Phasing: 2 7/8" 6.5# 8rd EUE 2857.5' 2229' & 2556' & 2732' ' ' ' ' ' ' ' ' ' ' 2282 - 2317 , 2363 - 2378 , 2420 - 2425 , 2620 - 2670 , 2796 - 2816 , 2830' - 2840' 2844 - 2864' 25. ACID, FRACTURE, CEMENT SQUEEZE, ETC. , , DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED All Depths MD & TVD. Directiona{ Tendency is minor, MD & ND within .5 ft. 26. PRODUCTION TEST Date First Production: July 22, 2005 Method of Operation (Flowing, gas lift, etc.): FIOWIfI Date of Test: Multiple Hours Tested: Production for Test Period Oil-Bbl: Gas-MCF: Water-Bbl: Choke Size: Gas-Oil Ratio: Flow Tubing Press. Casing Press: Calculated 24-Hour Rate ~.- Oil-Bbl: Gas-MCF: Water-Bbl: Oil Gravity -API (corr): 27. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water (attach separate sheet, if necessary). Submit core chips; if none, state "none". None pI~S ~~~. ~~~ ~- ~ao~ ~ ~ 2~5~ a 1~~~.~~; b ~ ~ ,. Form 10-407 Revised 12/2003 ~ CONTINUED ON REVERSE 28. GEOLOGIC MARKER 29. ORMATION TESTS NAME TVD Inducts and briefly su test results. List intervals tested, and attach detailed supporting data as necessary. If no tests were conducted, state "None". Test results attached 30. List of Attachments: Wellbore & Com letion Schematic Drilli and rations rt wellhead d' ram. 31. I hereby certify that the foregoing is true and correct to the best of my knowledge. .Contact: Printed Name: J. Ed rd Jones Title: Executive Vice President Engineering-Operations S' nature: Phone: 907-277-1003 Date: 1/26/2006 _~ __ INSTRUCTIONS General: This form is designed for submitting a complete and cerrect 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 chanced. Item 1 a: Classification of Service wells: Gas Injection, Water Injection, Water Akemating-Gas Injection, Salt Water Disposal, Water Supply for njection, Observation, or Other. Multiple completion is defined as a well producing from more than one pool with production from each pool cksmpletely segregated. Each seareoated Wool 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 ltem 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 1212003 • ~<: Lone Creek No. 3 Configuration 6 SPF - 2282' - 2317 6 SPF - 2363' - 2378' 6 SPF - 2420' - 2425' 6 SPF - 2620' - 2670' 6 SPF - 2796' - 2816' 2830'-2840' 2844'-2864' PBTD at 2968' TD 3025' • 2 7/8 6.5# 8rd EUE J-55 Tubing 11 7/8" 71.8# Structural Conductor driven to 80' i 5/8" 32# Surface Casing set at 700' :ement w/ 14.5 ppg Gas-Block :nhanced cement (~ 39 bbls cmt @ .0% Excess) ling Sleeve at 2194' Iraulic Retrievable Packer 2229' ling Sleeve at 2330' ling Sleeve at 2521' lraulic Retrievable Packer !557' fipple at 2579' Off Toot at 2611' sand Exclusion Screen owsetIX Packer !732' fipple at 2771' Sand Exclusion Screens 17# J-55 Casing to 3018' MD (TVD) v/ 34 bbl 13.5 ppg Lead at 20 % excess ...... 79 bbls 15.8 ppg Tail at 20% excess F~inn~aothor FRP Coniiroc Inr 1 nnc (:ruo4 Pln '3 Rnv 1 !1 R/(1A/9(1l1~. I11-J\/ Ilrn~.dnn AIn4 Tn G~Ic Client: Aurora Gas Lease: [~l ~ ~ Address: 1400 W. Benson nivd, Suite 410 Fieid Lone Creek #3 .lnchor~ e, AK 99503 OCS-G Platform: Com an Man Keener McDade Well Number: Phone T e of O eraHon: Completion Itei roSuxface Tool Descri tion Tool O ~ Tool ~ Len h ~ Tie th ~~ fl KB Correction 12.64 ~ j ~ Hanger & Pup 4.4 2 7/8 Tubing 17-85 2177.35 XA Sliding sleeve 2.31X 3.625 2.310 3.12 2194.39 Tubing Joint # 16 2.875 2.441 31.60 5 1/2 HRP Hydraulic packer 4.500 2.440 6.30 2229.11 2235' (36000 shear) 2 7/8 Tubing 13-15 2.875 2.441 94.83 2 7/8 WXO Sliding Sleeve 3.625 2.310 3.12 2330.24 2330' 2 7/8 Tubing 7-12 2.875 2.441 188.49 2 7/8 WXO Sliding Sleeve 3.625 2.310 3.12 2521.85 ~~ 2 7/8 tubing jt #6 2.875 2.441 31.59 5 1/2 HRP Hydraulic Pkr. 4.500 2.440 6.30 2556.56 2550" (36000 shear) it 2 7/8 tubing pups 2.875 2.441 16.36 2.31 X nipple 1.00 2579.22 2 7/8 tubing jt #5 2.875 2.441 31.63 2 7/8 On Off tool 4.500 2.310 4.25 2611.85 2 7/8 EU- 3 1/2 Nil Xover 4.250 2.440 0.65 Screen 4.060 2.990 51.70 2616.75 2620'-70 2 7/8 EU- 3 112 NCl Xover 4.250 2.440 0.50 2 7/8 Tubing jt 3-4 2.875 2.441 63.37 5 1/2 Arrowset IX Packer 4.625 2.440 6.97 2732.32 2740' ~ 2 7/8 Tubing Jt #2 2.875 2.441 31.68 ~ 2.31 X N Nipple 1.00 2770.97 2 7/8 Tubing jt #1 2.875 2.441 31.67 2 7/8 EU- 3 1/2 NU Xover 4.250 2.440 0.65 ~'' ` ` Screen 4.060 2.990 10.60 2804.29 2800-2810 ° 2 7/8 EU- 3 1/2 NU Xover 4.250 2.440 0.50 ~ ail i 2 7/8 Tubing 2.875 2.441 10.18 ~ ~ ,r; f.'~ 2 7/8 EU- 3 1/2 NU Xover 4.250 2.440 0.65 ` ` ` : Screen 4.060 2.990 30.72 2826.22 2830-60 .; i ~=; ° ~ 2 7/8-3 1/2 NU X over 4.250 2.440 0.50 Bull Plug 2857.44 Total Len th of 13.H.A.:- 870.91 Meters) 2857.44 Feet B.H.A Pre ared b Date :- Pleaseaote that all-O/Q's antl IID's are approximate, and are given as a guideline only (B.H.A. #) (Run #) Michael D_ Gray 21-Jun-OS • Aurora Gas, LLC Lone Creek #3 Well Operations Summary Background Information: • The Lone Creek #3 well was permitted as a natural gas exploration well by Aurora Gas, LLC with approval given on April, 2003, via Permit to Drill # 205-097. The well was drilled on a newly constructed pad using Nabors Alaska Drilling Rig #129. Rig mobilization operations began July 1, 2005, the well was spudded July 4, 2005, reached TD July 15, 2005 and was completed July 25, 2005 after testing operations. Prior to rig mobilization and spud, the conductor was installed to a depth of 80 ft BKB. After installation of the conductor, the drilling rig was moved to the site and rigged up to drill the Lone Creek #3 well. The following well work summary details the drilling and completion work chronologically. Dates indicated reflect the day the morning report(s) were received in the office and reflect site activities over previous 24 hour period, i.e. 0600 hours on day previous to 0600 hours on the date of report generation and submittal. Figure 1 is a schematic of the well as completed. Attachment I is a tally and diagram of the actual completion equipment in the well at this time and Attachment II is a diagram of the wellhead and production tree installed on the well. Work Summary and Daily Activities: July 1, 2005 Set and plumb sub-base, set slop tanks and brine pit, rig up shock hoses and build berms. Run wiring and rig up power swivel, hammer up diverter and knife valves, make up mud lines. July 2, 2005 Continue plumbing on pumps and running wiring. Set catwalks and trip tank. Rig up beaver slide, rat hole and mouse hole. Nipple up flowline, level derrick, hook-up gas alarms. Set pipe racks, organize yard and finish hooking up diverter line. July 3, 2005 Pick up drill collars, function test Diverter and pick up Kelly hose. Continue to rig up #3 mud pump, function test gas alarms. Rig up power swivel and prep to drill out mouse hole. Level diverter, hook up trip tank, fill tank and hole to check for leaks. July 4, 2005 Strap BHA, test mud line to 2000 psi, calibrate Horizon's equipment. Drill from 80' to 541'. Circulate and survey at 508'. • • July 5, 2005 Drill from 541' to 710', circulate for short trip, and check for flow. Set back power swivel, short trip to 600' and circulate hole clean. TOH to 200' circulate out gas. Back ream out and lay down single, lay down BHA. Rig up run casing; lay down mouse hole, makeup shoe joint and float collar joint, check circulation. July 6, 2005 Run 16 joints of 8 5/8" 32# casing to 700' with 5 centralizers. Rig up cement head, circulate, hold pre job safety meeting. Test lines to 2000 psi. Mix and pump 198 sacks of type 1, 14.5 ppg cement plus additives, displace and bump plug, cement to surface. Check floats, OK. Clean out cement from surface equipment and cellar, WOC. Nipple down diverter, cut casing and weld on casing head, allow to cool. Set gas buster and bolt up, nipple up choke and kill line hoses. July 7, 2005 Nipple up BOP's, test BOPE and choke manifold, 250 psi low 3000 psi high. Test gas alarms. Change out tugger line. Mix mud and prep to pick up BHA. Pick up BHA and RIH. July 8, 2005 TIH, pick up swivel, make up kelly hose, tag cement @ 658', CBU. Test casing to 1500 psi, lost 50 lbs in 30 minutes. Hold safety meeting, discuss kick drill job duties. Drill out rubber and float collar, test upper kelly valve, and adjust brakes on draworks. Drill from 664' to 731', CBU. Test formation to 16.5 EMW. Drill from 731' to 1039' and circulate bottoms up, check for flow. July 9, 2005 Wireline survey @ 1004', 4 degrees. Drill from1039' to 1195', ream each joint and check for flow. Flow on connection, 2200 units of gas, shut in well, SICP 145 psi, and circulate out gas. Weight up to 10.4 ppg, still flowing, increase weight to 10.7 ppg, still flowing, increase weight to 10.9 ppg. Drill from 1195' to 1351', ream each joint and check for flow, circulate bottoms up and weight up to 11.1 ppg. Drill from 1351' to 1514'. July 10, 2005 Drill from 1514' to 1540', circulate bottoms up. Wireline survey at 1504', 7 degrees. Drill form 1540' to 1562', pump dry job and check for flow, TOH. Well swabbing at 818', RIH 1 stand and shut in well, rig up to circulate out gas. TIH, circulate out gas on bottom, 1600 units. Drill from 1562' to 1729', drill with 2 to 5 K and ream each joint. Attempt to drop angle. July 11, 2005 Drill from 1729' to 1770', survey at 1767', no survey. Drill from1770' to 1802', survey at 1780', first run no survey, second run 20 degrees, attempt to confirm. Circulate bottoms up and work pipe, survey - no survey. TOH (pump out), lay down singles. Repair control valve on Power swivel at 853', continue to TOH, at 692' stand back pipe. 2 • • July 12, 2005 TOH, pick up BHA #3 and TIH, break circulation at shoe, TIH to 1500', circulate bottoms up and monitor well. Wash and ream from 1500' to 1802', 3 feet of fill. Drill from 1802' to 1823', ream each joint twice, circulate bottoms up and monitor well. Survey at 1820', 6.5 degrees. Drill from1884' to 2071', ream each joint twice, circulate bottoms up and monitor well. Survey at 2006', 4.5 degrees. July 13, 2005 Drill from 2071' to 2103', check for flow, shut in we110 psi; circulate gas out through gas buster. Drill from 2103' to 2460'. July 14, 2005 Drill from 2460' to 2568', circulate bottoms up and monitor well, well static. Wireline survey at 2504', 3 '/4 degrees. Pump and back ream out to 1823'. TIH to 2537' and pick up swivel. Wash and ream to 2568', 8 feet of fill, circulate bottoms up, 40 units of gas. Drill from 2568' to 2781'. July 15, 2005 Drill from 2722' to 3025', circulate bottoms up and monitor well, static. Wireline survey at 2926', 1 degree. Pump and back ream out to shoe and lay down singles. July 16, 2005 RIH, set kelly swivel back, pick up singles and RIH, took weight at 2963'. Work through tight spot, 6 feet of fill, pick up kelly and wash to bottom. Circulate and condition mud and hole. Pump a slug and set back kelly swivel. POOH lay down stabilizers and x- overs, monitor well. Rig up Schlumberger, pick up Platform Express loggings tools. PJSM for radioactive source. RIH, to bottom and log out, C/O tools for FMUDSI, Wireline TD was 3021'. RIH to bottom and log out. Hold PJSM for side wall cores, pick up tools to SWC's. RIH make depth correlations and shoot. July 17, 2005 Shoot SWC's, POOH with same, good recovery (39 shots), pick up MDT tool and RIH with same, calibrate and start logging at 04:30 hours. Rig down Schlumberger. RIH to 690', hang blocks and work on draworks brakes. RIH to 2995', pick up Kelly swivel and wash 30' to bottom, no fill. Circulate and condition mud and the hole, pump a slug and monitor well. POOH and lay down drill pipe, lay down BHA. July 18, 2005 Lay down bit, near bit stabilizer and drill collars. Change rams to 5 %", test doors and test to run casing. Make up shoe and float collar, install centralizers as per plan, run in hole with casing. Circulate and condition mud and hole. Hold PJSM with BJ Services. Pump 30 bbls MCS-4D pre-flush at 10.5#, 34 bbls 13.5 ppg lead cement and 79.2 bbls of 15.8 ppg tail cement. Flush lines release top plug and displace with 69.5 bbls water. FCP 1140 psi at 2 bpm, bump plug to 1800 psi, floats held. Drain and flush stack, flowline, shakers and cellar. Rig down BJ and start to clean pits while WOC. Change rams to 3 • • 2 7/8", break bolts on stack. Test cement at 20:30 hours, not set well enough, WOC till midnight, continue to clean pits. July 19, 2005 Nipple down BOP's, pick up stack, set slips, hang 20K on slips, cut casing and set packoff. Nipple down tubing spool and DSA; set stack down over DSA. Clean pits. Nipple up BOP's ,pick up test joint and set plug, fill stack. Test BOP's, all test were 250 low 3000 high. Pump through all mud lines, choke and gas buster with water. Lay down power swivel and shuck, clear rig floor and pick up tubing tongs. Make up bit, scraper and x-over, continue to clean pits and strap tubing. Test casing to 3000 psi for 30 minutes. Pick up 2 7/8" tubing and RIH with bit and scraper. July 20, 2005 RIH picking up 6.5# EUE 8 round tubing, tag cement at 2968'. Mix brine to 9.7+ while circulating and filtering. POOH with tubing, bit and scraper. Hold PJSM, rig up Schlumberger and run in hole with CBL, tool failed, POOH and wait on new tool. Clean up around drilling rig, rig up new CBL and run log. Nipple up shooting flange and lubricator for perforating; hold PJSM. July 21, 2005 Pick up lubricator; wait on Schlumberger to pick up perf guns, test lubricator to 1500 psi. RIH with guns, shoot perforations from 2282' - 2317', 2363' - 2378', 2420' - 2425', 2620' - , 2670', 2796' - 2816', 2830' - 2840' and 2844 - 2864' with 6 spf in 10 runs. POOH and rig down Schlumberger's lubricator, rig up flowline and trip tank lines. RIH with bit scraper and tubing to 2908'. Rig up and circulate bottoms up, twice. Circulate hole the long way, filter and centrifuge to clean up brine. Float collar is at 2968', shoe is at 3018'. July 22,.2005 Circulate and filter brine, observe we115 minutes. POOH, lay down scraper and bit; pick up x-nipple, unloader and test packer, RIH. Set packer at 2748', rig up lubricator and swab head. Hold PJSM and make 2 swab runs, unload 15 bbls to pits thru poorboy gas buster. SITP 1180 psi. Transport test skid and flare boom from South Moquawkie location to Lone Creek location and rig up. Flow test well, shut in well for pressure buildup, pressure increase to 1220 psi in one minute. Kill well (lost 6 bbls down hole); reverse circulate bottoms up, twice; circulate the longway one bottoms up. Rig up to POOH, observe well, start to POOH slowly watching annulus continuously while POOH. July 23, 2005 POOH with test packer assembly #1. Pick up FBP and retrieving tool; RIH for LC #3, well test #2. Set RBP at 2748', pick up to 2688', set packer and test to 1500 psi. Release test packer, pick up to 2570' and set packer. Rig up to swab well for test #2. Swab, pull 300' well came on, unload well thru poorboy; shut in well and monitor pressure. Flow well to test skid, pressure stabilized at 994 psi, 7.44 MMCFD, initial SITP 1170 psi. PJSM to kill well; line up on trip tank and fill hole. Reverse circulate bottoms up 3 times, check for flow. Unseat test packer, RIH, wash down to RBP; release and circulate bottoms up. Pull up hole to 2570' and attempt to set RBP, no go. Circulate bottoms up 4 • • and attempt to set RBP again, no go. POOH and lay down RBP, pick up new RBP and RIH. Set RBP AT 2560', pick up to 2510', set test packer and test to 1500 psi. Pull up to 2338', rig up swab head and lubricator, hold PJSM on swabbing, make two swab runs (750' and 1500') well started coming on; SITP 220 psi. 6 bbl gain in pits while rigging down lubricator. Flow test well to flare; midnight 460 psi, 1.665 MMCFD. Final test pressure 544 psi with 28/64 choke, 300 separator pressure at 2.5 MMCFD. July 24, 2005 Flow test zone #3; pressure 544, choke 28!64, separator 300, 2.5 MMCFD. Pressure build up from 750 psi to 991 psi in 5 minutes, 998 psi in 10 minutes. Kill well thru unloader, choke to gas buster, reverse circulate 3 tubing volumes, RIH to RBP, release RBP and circulate the long way thru choke bottoms up twice. POOH with RBP and test packer, lay down test packer and x-overs. Pick up production screens and packer. TIH with 2.7/8" tubing, set lower packer at 2732', release on/off tool and space out, land tubing in hanger with 16K up/down weight. Rig up Pollard Wireline, run gage ring to XN nipple at 2771', attempt to set plug in X profile at 2579', two attempts failed. Run scratch tool through area of profile, re-run plug and got plug to set. July 25, 2005 Set plug in X nipple at 2579', set prong in plug. Set packers, test tubing to 2500 psi for 30 minutes, test annulus to 1000 psi for 15 minutes. Pollard opened SS at 2194', reverse circulate in corrosion inhibitor and close SS. Set back pressure valve with Vetco Gray, lay down 4 stands of tubing that were in the derrick, lay down mouse hole and nipple down stack. Nipple down adapter, nipple up tree, test packoff to 3000 psi for 30 minutes, pull back pressure valve and set two-way check. Test tree to 3000 psi for 10 minutes. Pull two-way check valve. Rig up Pollard and lubricator, test lubricator to 2000 psi for 5 minutes. Pull plug in x-nipple at 2579' and rig up to swab. First swab from 300', well came on, divert to pits through poorboy, flow well until pressure stabilizes; 40/64 choke, 2.625" orifice, 930 on SPYDR, and 7.7 MMCFD. Shut in pressure went to 1195 in one minute. Pollard set plug in x-nipple at 2579', then opened SS at 2521'. Unload brine through separator, flare gas while unloading. Close SS, pull prong out of plug and pull plug from x-nipple. Rig down Pollard and release rig. Wait on Vetco Gray to set BPV in the morning. 5 • • i} A. i. 3i:_. ~r ,.. r' ~. ,,7 k 1'.s 2i Li lcw. L7 _.. v.w. - .._..._.. .._....._...._ ....-- .._._._.__.._._......._.......... ~ ~ _ _ a .:_ -- ~ ~ r-- ~ ~..~~ 1¢ _ _ _ _ _ W __ ______ __._ _ .~ _... -~ t (i ~Qri.i ~ F` E.ti ~i~c~ Fd ~E t~_.E. ~~ ~ 3 ~-oon _. A T; ~ <-~., s: r . ~c ifX.t! s ~i~:~L~: hlft ~P~r~tdtt,~ i~ i ~l ~., ix1 LI ~'~ , , 4~~~ __ SEC 7 SEC 8 ~,~, y ~ .~,~ ~~ ` ~' ` SEC 18 SEC 1 i ~`' ' ~ . GRID N:2610096.260 ` ~~":f' SCALE y ~ GRID E:273592.570 - '~ i inch = 500 ft - ` ` :' ~ , ~;- LATITUDE: 61°08'16.647"N ` -a ;. ' ' ° ' " 0 500 7so ~ooo 51.967 W LONGITUDE: 151 16 ' Grid.. ~ ~' ~p ~ t .~: ~ ,.~ '~~~ z ~` ~ ~r.f , + ORTH e • b ~: E ~,',.~..5~ `"~ : , ' ~. ~ ~. F ~ ~ .T t. ~ ~ «~ a fi ' k `~ '~ NOTES ' "'" ~ ~ ~~ ~ 1) BASIS OF COORDINATES IS ALASKA STATE ~" * PLANE NAD 27 ZONE 4 FROM A DIRECT TIE ~ ~ *`' ~ _ ~ 6 "~,` ~- ~ ~ _ # ~' .~{~ ~ ~` fr 1'~' ,~~ ~ TO ADL NO. 31270. , f''ti ~ ~~~ < , "2) BASIS OF ELEVATION IS FROM TIDAL ~~"~'r pia ~" , ,~ ~ ~ . ~, ~ A _~;. 'Rt ~~ ~ "~ ~ -, ~ ~ . ~ ~ ~ ~ ~ ~ ' ~ OBSERVATION ON 9-22-93. DATUM IS MLLW. ~, ,~ ~~ ~ ;~,~r ,~ j ~y = " * ~, , ' '` ALL ELEVATIONS SHOWN HEREON WERE ~LUF'IF - ~ ~. ~ E ,~ ~ . ~.;1 a°,~, ~~ - _ ~_' ~ *',?`: TAKEN ON GROUND. 3) SECTION LINES SHOWN HEREON ARE ~ ~ r + `'' ~ / 1367 FEL ' BASED ON PROTRACTED VALUES. ~ q - - LONE CREEK NO. 3 AS-BUILT ~~,WETLAND GRID N:2608542.844'" €. 3 GRID E:272198.248 , • ° ' ' " ~ ~ ~ ~`~ ``~~~ ~ + 1 LATITUDE: 61 01.083 N 08 ° " ~~ ° g.F " ~ ' ` `~ F 11 LONGITUDE: 151 1T19.738 W ! P~~ 0... AL,9s I, ELEV. 371° - ~.-~ ''3~+.A,,rfrt !~ ~~ <; !! ~ / / / '- ; `> %- .... / '~~, • .M. SCOTT McLANE:' ,8 ~ ~ . "'~ t, ~ { ~ ' ' I~,srF •'• 4928-S .•'~ ~ ~•~........ ~ ~ ; SEC 18 ~. • • '" ~~f r . ,~ ~ ~r~-. ~~ K~ , ^~ P _ . ~, ~~ , . J ~. -~~ A - T12N R11W S M ~~ , . , `4 ~... h. ,. LONE CREEK NO. 3 ir1/ELL AS-BUILT SURFACE LOCATION DIAGRAM McLane Consulting Inc APPLICANT: ENgNEERiNG/MAPPING/SURVEYING/TESTING __ ~~~~~ ~~~ ~~~ P O BOX 468 SOLDOTNA AK 99669 -~~_" I . . . , VOICE: (907) 283-4218 FAX: (907) 283-3265 ~ EMAIL• msnclone®mclonecg.com PROJECT NO. DRAWN BY: DATE: July 7, 05 SEC. LINE OFFSETS: LOCATION: PROTRACTED SECTION 18 o5soas MSM 1578' FNL TOWNSHIP 12 NORTH, RANGE 11 WEST 1 4F, 7' FF{ r,~r~,~,,~7As~~r !"e~4r'n1~9:6,.`'I. ~ 9 ,14~E31~, AURORA GAS, LLC WELL TEST REPORT Well: Lone Creek #3 Date: 7/22/2005 Lower Perfs: 2796-2884' U. Tvonek Carva 2-6.0 DATE ACTIVITY T PRESS WH CHOKE SEP ORIFICE METER METER RATE CUM TIME 22„Jul PERFS SPYDR, PSIA TEMP de F _ /64" PRESS si STATIC blue DIFF red TEMP reen FACTOR Q MCF/D VOL MCF 17:30 en ck to 6/64 1080 24 540 5.2 .1 7.6 70 17;45 1017 26 520 5 8.5 2975 17:50 han a orifice to 2" 1000 30 520 5.1 6.6 6.8 o en c oke to 30 18:00 en ck to 1 0 30 520 5.2 7.5 6.8 125 4875 1 o en ck to 3 1 0 32 530 5.2 7. 6.8 125 5070 1 0 44 3 40 5. 9. 43 18: 46 3 4 5 4 5 1 :45 1 36 0 .3 .95 6.9 125 592 1 0 9 2 3 700 6 .8 7 125 6600 9 :15 85 3 720 6 8.8 7 125 00 1 0 9 6 7 0 6 8. 5 7 125 713 1 :45 95 3 20 6 8.95 7.1 125 6713 20:00 7 36 720 6 9 7.1 1 5 6750 0:15 1 00 36 7 0 6 9.05 7.1 125 6788 20:3:0 102 6 70 6 9. 1 7.1 5 633 0:45 1 4 36 72 6 .1 7.1 1 5 6825 21:0 10 7 36 720 6 9.1 7.1 125 6825 H T WELL IN 21:1 1220 1:02 12 1 21: 1222 21:20 1 22 21:3 1223 1:45 1223 22:0 1223 22:30 1223 C7 • • • AURORA GAS, LLC Remarks: Two swabs; 750 8~ 1500') recover 6 bbls; well came on; SITP w/ rigging down lubricator 220 WELL TEST REPORT #3 psi. Line up on test choke and separator, fluid unloaded from well to sep = 9.48 bbls; total 15.48 from well. Final fluid weight = 9.7+ w/155000 CI on brine sample. SITP after 1 min = 750 psi; 5 min = 991; 10 Well: Lone Creek #3 min = 998; 1 hour = 999 psi Date: 7/23/2005 Perfs: 2,363'-2,425' U. T onek Ca a 2-4.2b & 2-5.1 DATE ACTIVITY T PRESS WH CHOKE SEP OR IFICE METER METER RATE CUM Water TIME 23~1u1 PERFS SPYDR, PSIA TEMP de F _ /64" PRESS si STATIC blue DIFF red TEMP reen FACTOR Q MCF/D VOL MCF Meter Readin 2: 5 pen to separator 2 0 4 0 2 : 0 360 26 100 2.3 2 7.5 125 575 5 316 26 100 2. 2.1 7.5 125 6 e ressure inc 417 26 2 0 2 7.6 125 7 0 :40 4 8 2 200 3.1 2.4 7.4 125 930 :47 4 26 0 3. 2.5 7.3 1 5 6 e ressure inc 4 6 2.5 7. 125 1 4 i ni ht choke increase 4 3 2 3.6 7.2 125 440 30 270 3.6 4.1 7.2 125 1845 457 30 26 3.6 4.3 7.1 25 1935 choke decrease 4 5 28 2 0 3. 125 :45 491 8 2 .6 4. 7 1 5 2160 :54 a ressure inc 28 300 125 5 2 28 300 3.8 4.9 6.95 125 2328 :15 8 00 3. 5 .9 1 5 2375 1: 4 29 2 3 0 3. 5.2 6. 1 5 2470 1:45 536 8 300 3.8 5.3 6.85 125 2518 :00 544 28 300 3.8 5.3 6.8 125 2517.5 • C] • FW: Data for well completion reports ~~/~~ ~ ~~ i..i~'~ Subject:, Fes: Data for welleompletion reports Frorn: John F3retmeier <john.braitmeier c~ fairweather.com-=~ Date: I~~lon, 0~~ Feb 2006 13:53:21 -4900' ~To: Robert Fleckenstein <bob Fleckenstein%ri;admin.st~le.al..us> Bob, Here are the fiormation tops for Moquawkie 3 and Lone Creek 3. I checked with Ed Jones and our file copies and I believe Aurora did send in the well Test data. John _. Content-Description: MOQ #3 FORMATION TOPS.xIs MOQ #3 FORMATION TOPS.xIs' Content-Type: applicationJvnd.ms-excel Content-Encoding: base64 ___ __ Content-Description: LC #3 FORMATION TOPS.xIs LC #3 FORMATION TOPS.xIs Content-Type: application/vnd.ms-excel Content-Encoding: base64 1 of 1 2/7(2006 6:56 AM FORMATION TOP LONE CREEK 3 LONE CREEK 3 MD(FT) TVDSS(FT) KB ELEVATION 0.00 385.39 SURFACE ELEVATION 1 4:40 371 :00 TSUGA 2-8 COAL TSUGA 2-8.1 SAND ................. . ................ 445.00 605.00 . ............, ................ _ _ -74.00 -234.00 TSUGA 2-8.2 SAND CARYA 2-1 (TOP TYONEK) ............................................. 950.00 1055.00 ....... ........ ....... ...... .............................................. -579.00 -684.00 . CARYA 2-2 COAL ... ..... ...... ... 1245.00 . .... ......................................... -874.00 CARYA 2-2.1 SAND ............................................ 1325.00 .. . ............................................. -954.00 CARYA 2-3.1 SAND ........ .................................. 2092.00 .............................................. -1706.00 CARYA 2-4.2 SAND ............................................. 2282.00 ............................................. -1896.00 CARYA 2-5.1 SAND 2420.00 -2034.00 CARYA 2-5.2 SAND 2608.00 .... ... . -2232.00 CARYA 2-6.0 SAND ...... .......... ..................... 2790.00 ............................................. -2404.00 • DATA TRANSMITTAL Please reply to: AURORA GAS, LLC 10333 RICHMOND, STE. 710 HOUSTON, TX 77042 ATTN: ANDY CLIFFORD 33 Anchorage, AK 99501 ATTENTION: Howard Okland Enclosed CDs and Pa er Prints From Aurora Gas, LLC _ Area Moquawkie Area, Cook Inlet Alaska Date: 3 August, 2005 CDs: t~ ~~~ 1. Lone Creek #3 well data: CBL, PEX-AIT &DSI LAS data, Directional Survey, plus CBL, Perforation Record, PEX-AIT Composite, DSI, FMI, MDT & Directional Survey PDS files. 2. Moquawkie #3 well data: CBL, PEX-AIT &DSI LAS data, Directional Survey, MDT Pressures Record, plus CBL, Perforation Record, PEX-AIT, DSI & MDT PDS files. Paper Prints: 1. Lone Creek #3 well data: Cement Bond Log 5"/100', Perforating Record 5"/100', Directional Survey, Platform Express 2"/100' plus 5"/100', Dipole Sonic Imager 5"l100', Fullbore Micro-Imager (Unprocessed) 5"/100', Modular Dynamics Tester, Horizon Mudlog 2"/100' in wide~'gc narrow 'lots. 2. Moquawkie #3 well data: Cement Bond Log 5"/100', Perforating Record 5"/100', Platform Express 2"/100' plus 5"/100', Dipole Sonic Imager 5"/100' Modular Dynamics Tester. PLEASE ACKNOWLEDGE RECEIPT OF DATA BY SIGNING BELOW AND SENDING A COPY BACK TO AURORA GAS FOR OUR FILES ~, Received by: ~.~k~~,-~-~..~~ ~.1 L • Date: ~/ (~.~..~ :~ :';-tii "_ AURORA GAS, LLC, 10333 RICHMOND, STE 710, HOUSTON, TX 77042 TEL: 713-977-5799, FAX: 713-977-1347 • Aurora Gas, LLC www.aurorapower.com January 26, 2406 Mr. John Norman, Chair Department of Natural Resources 333 West 7~' Ave., Suite 100 Anchorage, Alaska 99501 Re: Final well completion report and operations summary: Lone Creek No. 3 (PTD#: 205-09'n Dear Mr. Norman: ~ECEiVED ~An€ 3 o Zoos Alaska Oil & Gas Cans. Corrx-tissiot~ Anchorage Aurora Gas, LLC hereby submits the fina.~ vgell report, which covers the completion of Lone Creek No. 3. Operations were completed. on July 25, 2005. ~ Pertinent information included under cover of this letter includes the following: 1) Form 10-407 "Well Completion Repprt--and Log" - 2 copies. 2) Wellbore schematic 3) Completion schematic 4) Summary of daily well work and operations 5) As-Built plat. Copies of electrical well logs, mud-logging reports and well test results will be submitted under separate cover. If you have any questions or require additional information, please contact the undersigned at (907) 277-1003, or John Breitmeier at (907) 258-3446. Sincerely, '' .Edward Jones Vice President Operations and Engineering Aurora Gas, LLC cc: Keith Sanders, CIRI John Breitmeier, Fairweather 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 Re: BOP Test Schedule Subject: Re: BOP Test Schedule From: Thomas Maunder <tom maunder@admin.state.ak.us> ~®~'~0 1. Date: Wed, 13 Ju12005 08:51:16 -0800 To: duane vaagen <duane@fairweather.com> CC: Ed Jones <jejones@aurorapower.com>, "David L. Boelens" <dboelens@aurorapower.com>, AOGCC North Slope Office <aogcc~rudhoe_bay@admin.state.ak.us> Duane, You are correct, I did not specify a test schedule. Based on what I understand is Aurora's acceptable testing practice, it is acceptable to move to the 14 day schedule for development wells. If the well is an exploratory well or a workover is being performed, then the 7 day schedule applies. One caution, 14 days is a hard time limit and exceptions to exceed 14 days are unlikely except for extraordinary circumstances. Tom Maunder, PE AOGCC duane vaagen wrote: Tom: This note is to inquire as to whether we can move to a (2) week BOP test schedule on the Aurora Well Service Rig No. 1. Historically we have been instructed in the approved Permit to Drill to test on a weekly basis. The permit "PTD 205-097" issued for the current well "Lone Creek No. 3" did not specify how often we must test. Based on the new rules regarding production drilling and BOPE test intervals, can we start testing on a (2) week schedule? As of noon today, we will running up on our deadline to notify an AOGCC inspector if we are to test on the weekly schedule. Regards Duane Vaagen Project Engineer Fairweather E&P Services, Inc. duane(a~fairweather. com Office: (907)258-3446 Cell: (907)240-1107 1 of 1 7/13/2005 11:11 AM Re: Lone Creek No. 3 ~ ~ Subject: Re: Lone Creek No. 3 ~ ~S,_~~t--1 From: Thomas Maunder <tom maunder@admin.state.ak.us> Date: Mon, 11 Ju12005 07:26:27 -0800 To: duane vaagen <duane@fairweather.com> CC: "Ed Jones /Aurora Gas, LLC." <jejones@aurorapower.com> Duane, This is acceptable. There is no collision risk with no other wells nearby. Tom Maunder, PE AOGCC duane vaagen wrote: Tom: This email is being sent to update the Alaska Oil and Gas Conservation Commission on the drilling progress at Lone Creek No. 3. The latest wellbore survey we have taken indicates we are unintentionally building hole angle and are currently showing an angle of 7 deg inclination at 1504 ft. The previous survey at 1004' indicated 4 degrees. We intend to continue drilling while monitoring inclination. We feel the bit is probably walking up dip on structure based on geologic mapping that is available and for lease reasons are not overly concerned about the build at this time. We plan to monitor while drilling and adjust our BHA as needed if the build becomes excessive and will get a full wellbore survey at TD to get an accurate bottom-hole location at that time. I hope this meets with your approval. Please feel free to call with any further questions or concerns. Duane Vaagen Project Engineer Fairweather E&P Services, Inc. duane'€~fairweather.cam <mailto:duane~xfairweather.com> Office: (907)258-3446 Cell: (907)240-1107 1 of 1 7/11/2005 7:26 AM r • Aurrora Gas, I.LC www.aurorapowercom "` AFFIDAVIT OF FACTS Regarding Spacing Exception Application, Lone Creek Unit, _, Kenai Peninsula Borough, Cook Inlet, Alaska Alaska Oil and Gas Conservation Commission 333 W 7th Avenue, Suite No. 100 Anchorage, Alaska 99501-353 Attn: Mr. Steve Davies Petroleum Geologist The purpose of this AFFIDAVIT OF FACTS dated effective June 15, 2005 is to describe certain facts and stipulations regarding the ownership of the minerals under certain lands, leases, leasehold and surface ownership of lands situated within the captioned borough and subject to a Spacing Exception Application recently submitted by Aurora Gas, LLC, as Operator of the proposed well, AURORA'S Lone Creek No.3 Well, cited in the Application, to the Alaska Oil and Gas Conservation Commission, hereinafter referred to as the "AOGCC", pursuant to 20 AAC 25.055. My name is Randall D. Jones, CPL and I am employed as Manager, LAND & Negotiations at Aurora Gas, LLC, hereinafter referred to as "AURORA". I have over twenty-five years of experience in Land Management and my present responsibilities encompass all Land Management duties at AURORA allowing me to be knowledgeable about the facts contained within this AFFIDAVIT. NOW, THEREFORE, let it be known AURORA'S Lone Creek No.l Well is currently producing gas from a surface location situated in the SW4SE4 of Section 18, Township 12 North, Range 11 West, SM and AURORA'S proposed Lone Creek No.3 Well is also planned to test gas at seven (7) intervals, and is situated in the SW4NE4 of the aforementioned Section 18 at a surface location of 1,597 FNL, 1,368 FEL, Section 18 and that puts the SL in the SW4NE4 of Section 18. Both wells are situated within the con Ines of the Lone Creek Unit, (f/k/a the Moquawkie Unit). Consequently, the proposed captioned well will require a Spacing Exception location pursuant to 20 AAC 25.540. Reference is herein made to that certain Oil & Gas Lease dated August 20, 1998 and dated effective February 27, 1998 covering certain lands being all of Section 18, Township 12 North, Range 11 West, SM, hereinafter referred to as the "LEASE", from Cook Inlet Region, Inc., as Lessor, and ARCO Alaska, Inc. and Anadarko Petroleum Corporation, as Lessees. The LEASE has been subsequently assigned by the Lessees to AURORA. AURORA is the only owner (leaseholder) of the LEASE, CIRI is the only mineral rights owner, owner, of the LEASE and the surface of the LEASE is all owned by Tyonek Native Corp. 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 r • • It should also be noted there are no issues with any potential injury to the correlative rights of any landowners, owners nor operators offsetting the LEASE and within 3,000' of the proposed drillsite location, pursuant to the requirements of 20 AAC 25.540. As you will note on the attached plat, the offsetting landowner of the tract to the north of the drilisite LEASE for the captioned well, C-61500, is the Cook Inlet Region, Inc. and the minerals under said tract are leased to AURORA being AURORA'S C-61395 lease. The offsetting landowner of the tract to the east and south of the LEASE and proposed well is also the Cook Inlet Region, Inc. and the minerals under both tracts are also leased to AURORA being AURORA'S C-61396 lease. The offsetting landowner of the tract to the west of the LEASE is the Mental Health Trust (MHT) and although these MHT minerals are unleased said tract is in excess of approximately, 3,900' from the proposed drillsite location. ~° Futhermore, no written notice to all owners, landowners, and operators of all properties within 3,000 feet of a well or portion of the well requiring the spacing exception that is to be drilled for gas has been done since there are no owners, landowners, and operators of all properties within 3,000 feet of the proposed drillsite. Therefore, no proof of such mailing reflecting the date of such mailing with a list of addresses to which a notice would be sent is included herewith. Please be advised the reasons for the proposed well's current planned location are: a.) to utilize an existing previously disturbed area for the drilling pad thereby minimizing environmental disturbance (an old staging area) and existing roads (it runs right to the pad) without disturbing new, virgin areas which avoids the many wetlands in the general vicinity of the proposed well, and b.) the drilling pad is located in an optimal placement based on current geological interpretation such that it is in a favorable position geologically (structurally high and near the center of the structure, as seen on seismic lines and subsurface mapping) for a straight hole. .EXEC TED this~~date of July, 2005. BY: ~~ Randall D. Jo ,CPL TITLE: Manager, Land & Negotiations EMAIL: riones(a~aurorapower.com IN THE UNITED STATES OF AMERICA) ss. STATE OF TEXAS ) i ~1~ This certifies that on the 6t~ day of #l~~' , 2005, before me a notary public in and for the State of Texas, duly commissioned and sworn, personally appeared Randall D. Jones, CPL , to me known and known to me to be the person described in, and who executed the foregoing assignment, who acknowledged to me that he executed the same freely and voluntarily for the uses and purposes therein mentioned. • • Witness my hand and official seal the day and year in this certificate first above written. ~/.ssG~ S. ~/,9a~ s,~c~ .~ AUSSA S. VADBOLSKIUA Notary Public ~, No~t~rrueucs~~~o~toas COEiE11EEtOM EMPIRES: JANUARY 19, 2009 My Commission Expires: qti ~9 ~~~ lone creek 3 affidavit i - ~ • Exhik~it B ~~~U~~i~ ~t~lt BC1U11~~~"~1 •7(K{~c 1'I Iy3 ~{/-~~+~ JJ4UU64'iFnJSi// RHIL~,IP$ A~8$k8~ IRC. ~ s ~,.;E]It BLS 0 .. ~ I ~•~ j ~ I ~' Att~484~ ,_ 3 4 ALK .`$4~l 3 LC 1 Q LC 3 P 5~ 5 ~ APC . 5~ PAI 5th AP ~~ PA15b ~ pAi~~4 ~APC 50 1~7~ 431 ADI~43i~~ :.:~~:.:::`~.~. Cfa6i~tl ~ t;OeSisU2 AP • 50 .. 7 ~ - _ tt• f}a~•~ '~~ 3,JC?0'~ radius frt5rrt:•:d~~lsite .~ ll~It 1~1'~~•. ~ ~ ~ • arr~:.: ~ 394. . i..~r~~ {''-` ~ Age: 50 AP~C ~~ ~~aX F~ ( ~ ~ A PAI Sfi tt~ i~r,r~x~ I '~-- 47~~~s ~y~ 'S~ Ali 4 AC7L 31 ~ C~ ~ 396 ~ ~ ~. • .,•~`` . ~~ iT ~~a~o . cos~5ac ~ ~4~ . r f ,,~ / ~ ~. ~~~ .,_ C 9~ ~'P'(G~ 5~ i ~'. ` ~ . • . ~ 145 ~ • , 89/ ~ ~, Lone Creek No. 3 Lease Info +~ a .. ~"~ • Subject: Lobe CreekNo. 3 Lease Info From:duane vaagen<duat~e@Fairweather.com> Datc: ~~'e~i, 0(i Jul ~iiU~ 1 1:U L~~) -(»i~(i Tai: Stclah~n 1)~ivic~ ~~=stc~ee ~la~~t,~a,:admin.~tatc.ak uy- Steve: Per our phone conversation this morning, please find attached a plat indicating the relationship of Aurora's Lone Creek No. 3 well w/ respect to Lease No. C061500. I hope this is sufficient for your records. Please call more information is required. Thanks Duane Vaagen Project Engineer Fairweather E&P Services, Inc. duane(r,~fairweather.com Office: (907)258-3446 Cell: (907)240-1107 Lone Creek Unit plat.ppt Content-Description: Lone Creek Unit plat.ppt Content-Type: application/vnd.ms-powerpoint Content-Encoding: base64 I of 1 7/6/2005 1:45 PM • LC 1 Q LC 3 • Exhibit- ~ Moqua~kie Unit Boundary (~a u1 ~~rl~ ~ ~ ~~~ ~~11 S TS cale: N ~6-19-Q1 ~~~C~O?C21~,~ PHILLIPS Alaska Inc. ~ SsucMh Y MF~l~t3 -OT:I~.PIIY ~.7W'?7!Y ;~50 ~ M~ " Unit Area :, •-a ? ~ ~ 3 E ~ I _ :~ i AL~'4~48 ; i ~ 4 ALK 844 3 MH7930t101~ A p~.3 33 P 50 AP 50 5 ~w 50 APC 50 ~w ~o PA150 ~PC 50 2 ~-?i ALlf503 2-2 -03 ALK~33 3. AD! (K]31 006150 ADLGOC31~3 ('Oc,"i502 . APr 50 Pp~~~ II~OO~ll71~[I~ ~. - ~ ( 1 ~ - 744 ~ :000 radius ~ - rom'drills~te '0 l~nlt ABB. ~ 046 1 9 ~' ~ ~~ ~--q ~^`~ I~~~ G~oX ' ~ ~ ~-_ ( Air 50 ~~ 5~ 50 q C APC 5~ PAI 50 . 394 _- O ~ ~#~f 1 ~ ~~ ~~ ~4t 071-66 r ~ 6 3~ ~~ M! IT 300010 _ ADL 315 Co6150G C ~ 396 + ,~ Q, ' ~ ~ ~. 4-~ ~ I ~/~ ~~~ ~ .~ c ss ~~ zz ,~ , ` .., ' ~ .ALK ~ ~ ~, ~1P~G. 5 . i ~- ~~ ~' ~ fi1453 f 5~ ~~"~'~ i ' . ~ J f ~ ~ ~ ~~~3~ r / P 5~ ^^ ~ A2-i' ~3 /~ , ~ ~ . ~ '' ~~ ~ ~ f . ~ ~' f ~ , f ~ I ~ ~ f ~ ~ ~~ ~ ~~ - ~~/~ / ::i ~ ~" • r '~ 9 ~ ~ ( ~ ~° ~ ~ ~ ~ ( ~ ~ ~ 1 ( ~ a ~,~ ' , j ~ ~ ' ~ ~ FRANK H. MURKOWSKI, GOVERNOR dy[>•'~ OII/ ~ ti0-7 ~ 333 W. 7"' AVENUE, SUITE 100 COlYSERV~TIOlY COMh'IISSI014 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 27&7542 J. Edward Jones Executive Vice President of Operations and Engineering Aurora Gas, LLC 1400 West Benson Blvd, Suite 410 Anchorage, Alaska 99503 Re: Lone Creek #3 Aurora Gas, LLC Permit No: 205-097 Surface Location: 1597 FNL, 1368' FNL, SEC 18, T12N, R11W, SM Bottomhole Location: same 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. A SPACING EXCEPTION WILL NOT BE REQUIRED TO DRILL AND OPERATE LONE CREEK #3 SO LONG AS THE RESERVOIRS OPEN TO THE WELL BORE ARE NOT OPEN IN THE LONE CREEK # 1 WELL, WHICH IS LOCATED WITHIN THE SAME GOVERNMENTAL SECTION. IF IT IS YOUR INTENT TO PERFORATE ANY COMMON RESERVOIR, A SPACING EXCEPTION MUST BE APPROVED PRIOR TO ANY TESTING OR REGULAR PRODUCTION OF HYDROCARBONS FROM THE COMMON RESERVOIR. AURORA GAS, LLC ASSUMES ALL LIABILITY AND RISK OF EXPENSE IF A SPACING EXCEPTION FOR THE COMMON RESERVOIR IS NOT GRANTED. 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 • r 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 petroleu field inspector at (907) 659- 3607 (pager). j~ DATED this ~%~day of June, 2005 Norman cc: Department of Fish 8s Game, Habitat Section w/o encl. Department of Environmental Conservation w/ o encl. Mr. Duane Vaugen, Fairweather E8sP STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL ~n vnr. ~~ nn~ .. ~a~l 1a. Type of Work: Drill Q Redrill ~ 1b. Current Well Class: Exploratory Q Development Oil Multiple Zone Re-entry ~ Stratigraphic Test ~ Service ~ Development Gas ~ Single Zone 2. Operator Name: 5. Bond: Blanket Q Single Well 11. Well Name and Number: Aurora Gas, LLC Bond No. NZS 429815 - Lone Creek #3 3. Address: 1400 W. Benson Blvd, Suite 410 6. Proposed Depth: 12. Field/Pool(s): Anchorage, Alaska 99503 MD: 3200' - TVD: 3200' w Lone Creek 4a. Location of Well (Governmental Section): , 7. Property Designation: L` . ~~,~~5-~ Surface: Sec. 18, T12N, R11W, S.M. - FNL159T FEL 1368' C-§a3g5~ xj ~,. ~~. h Top of Productive Horizon: Same 8. Land Use Permit: 13. Approximate Spud Date: 6/26/2005 Total Depth: Same 9. Acres in Property: 14. Distance to Nearest 603 Property: 1368' FEL 4b. Location of Well (State Base Plane Coordinates): 10. KB Elevation 15. Distance to Nearest Well Surface: x- 272197.96 ~ y- 2608542.61 Zone- (Height above GL): 390 feet Within Pool: 3527 ft 16. Deviated wells: Kickoff depth: feet 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: degrees Downhole: 1472 psig Surface: 1120 psig i o. %asiny` Program: Specifications Setting Depth Quantity of Cement Size Top Bottom c.f. or sacks Hole Casing Weight Grade Coupling Length MD ND MD ND (including stage data) Driven 11 7/8" 61# P-110 Welded 80' 0 0 80' 80' No cement,driven 10 5/8" 8 5/8" 32# WC-50 STC 684' 0 0 700' 700' 54.5 bbls at 100% OH excess 5 1/2" 17# J-55 LTC 3184' 0 0 3200 3200 120 bbls @ 25% OH excess '1hl 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 Structural Conductor Surface Intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): 20. Attachments: Filing Fee ~ BOP Sketch Drilling Program Time v. Depth Plot ~ Shallow Hazard Analysis Property Plat ~ Diverter Sketch ~ Seabed Report ~ Drilling Fluid Program Q 20 AAC 25.050 requirements 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Printed N e Duane H. Vaagen Title Project Engineer (Fairweather E&P Services, Inc) t Signature ~ - ~'<_ v~ r~ ~~ ~, ~~ ~Ga ~., Phone 907-258-3446 Date 17-Jun-05 Commission Use Only Permit to Drill A I Number: Permit Approval See cover letter for other Number: .~J`~""C~~? 50- ~3' Zd ~~Z- ~~ Date: requirements. Conditions of approval Sam i Yes ~ No ~ Mud log required Yes ~ No [~ y r n sul measures Yes ~ No ®' Directional survey required Yes ~ No '~ Other: ~~ ~ =ncl ~,nr,:~~. ~r° Na _.~ `, .u.~ BY ORDER OF ~~~ Approve THE COMMISSION Date: a Form 10-401 Revi 2/2003 `'" ~`" 9 ~ ' ~, S mit inDuplicate Aurora Gas, LLC. Drilling Program: Lone Creek No. 3 Lone Creek No. 3 Drilling Program 1. File and insure all necessary permits and applications are in place. ~ 2. Install drive shoe and drive (new) 11 7/8" 61 #/ft, structural conductor to 80 ft or refusal. Install 13 5/8" 5M starter head. 3. Rig up diverter (see attached diagram) and mud Ioggers~Test and calibrate all PVT and gas sensor equipment. 4. Notify AOGCC and pertinent agencies when ready to start drilling operations. 5. Prepare mud system, weight up to ~9.5 ppg. ~ 6. Drill 10 5/8" hole to 700 ft, using 6 3/" stabilized BHA. Watch for gas in shallow coals and sands. Increase mud weight as needed to 9.8 - 10 ppg• 7. Condition hole for running 8 5/8" surface casing, POOH, LD 10 5/8" BHA. f2, Rhin and rament (neW) R 5/8" 32 #/ft, WC-50 STI~; g~rfare racing at 7(](l' and cement to surface./Shoe joint connection at shoe and float collar must be Baker-Locked. Cementing will be single stage with float collar and shoe installed using 14.5 ppg cement at 100% excess volume. 9. RU and test 11 " 3M BOP stack and 5M choke manifold. Test stack and surface equipment to 3000 psi. Pressure test casing to 1500 psi or as required on approved permit. 10. PU 7 7/8" mill-tooth bit, RIH with 6'/4" DC's and 3'/Z" DP to float collar. Drill out float equipment and shoe. Drill ~20' OH. Pull back into shoe and perform FIT with MWE to 16.5 ppg, record results. 11. Condition and circulate mud system, build mud weight to 9.5 ppg., and be prepared to weight up more if required. Do not exceed fracture gradient determined in step 10! 12. Proceed to drill ahead, 7 7/8" hole. Monitor well and volumes carefully. Be prepared to shut well in and weight up immediately if flow or excessive gas build up in mud is noticed. 13. Drill to TD at 3200 ft maximum, depending on lithology encountered. 14. Short trip and condition hole as needed for running wireline logs. 15. POOH, rack back drillstring and RU wireline BOP's and lubricator and logging tools. Log cased hole section w/gamma ray sensor, Log OH section with logging suite as indicated by Aurora Gas. 16. RD wireline, RIH with drilling BHA as before to TD. Circulate and condition hole for running casing. 17. INSURE all cementing equipment, casing accessories, and casing running equipment is on location and functional. POOH, LD BHA, rack back DP. 18. RU casing equipment /crew, make up shoe joint with shoe and float collar, baker- locking both to joint during make-up. Install 5 1/2" pipe rams for casing. 19. RIH with (new) 5'/2" 17 #/ft J-55 casing, installing 1 centralizer /joint centered on 1St 4 joints above shoe, and 1 centralizer every 2nd joint there after. Centralizers to be installed 1 every third joint for the interval inside Aurof°a Gas LL,C. t'age 1 of 1 D Rev. 1.0 h'17,/?00~ Aurora Gas, LLC. • Lvne Creek No. 3 Df°illin~ Program of the 8 5/8" surface casing. Run casing to 3200'. Keep pipe moving when casing is at TD and while waiting for cementers to get hooked up. 20. RU cementers, cement per attached cementing program from TD back to surface. A 13.5 ppg lead and 15.8 ppg tail cement system will be used. Tail slurry to be of sufficient volume to cover 5'/Z" CH x 7 7/8" OH annulus to 1000 ft. While pumping cement, reciprocate pipe a minimum of 20 feet until displacement is finished. Land casing in tension and WOC. 21. RD cementers, check annulus and casing for pressure. Nipple down stack and cut casing. 22. Install 11" X 7 1/16" tubing spool, 7 1/16" X 11" DSA, mud cross and reinstall BOP stack. Pressure test BOP and surface equipment to 3000 psi. Pressure test casing to 2000 psi and record results. PU casing scraper and RIH with DP to top of float collar. Circulate out mud and cement with high-vis sweeps as necessary. Swap mud system over to clean filtered KCI. POOH LD DP and casing scraper, 23. RU lubricator for wireline work. Change out 3'/s" pipe rams with rams for 2 7/8" work string. Pressure test all. 24. PU wireline BOP's, lubricator and perforating guns, RIH to depth as determined from OH logs and perforate. Watch for pressures in casing ~ after shooting. POOH, LD perf gun. 25. RU and RIH with test packer on workstring. Connect to surface flow test equipment. Swab in well for flow test, record results. Kill well. 26. Repeat steps 21 and 22 until sufficient intervals have been penetrated for production. 27. POOH, RD wireline. Prepare completion assembly. 28. Pick up and assemble retrievable type packer w/sealbore assembly, millout extension, profile nipple, crossovers and sand exclusion screen assembly. Packer is to be 75 ft minimum above upper-most screen. RIH and hang off (depth to be determined by depth of perforations). POOH with workstring, RIH with 2 7/8" 6.5# EUE 8rd production tubing, space out and stab into packer, hang off in tubing head and lock down. Install blanking plug in profile nipple, Pressure test tubing to 2000 psi. 29. Install BPV at surface, nipple down and remove BOP stack. Install wellhead tree. RD and remove all rig equipment. 30. Prepare site for well testing and surface production facilities. 31. File completion reports with proper agencies. Site Access:Lone Creek No. 3 will be accessible via existing gravel road from Lone Creek No. 1 site and active producing facility. Rig: Aurora Well Service, Rig No. 1 (AWS 1) will be used to drill the Lone Creek No. 3 well. The Alaska Oil and Gas Conservation Commission has information on this equipment as it has been in use for the last (3) years on other Aurora Gas operations. The pits, BOP system and mud equipment configuration will be similar to that used for previous work. Aur~i°a Gas L LC. Page 2 of .10 Kev. 1.0 6/17,%2005 • ~~urora Gas; LLC. • Line Creek No. 3 DrilZinK Pragrcam Survey Program: The Lone Creek No. 3 well will be drilled as a vertical well. Wellbore surveys (inclination only single-shot) will be obtained at 500' intervals in accordance with rules laid out in 20 AAC 25.050 (a) (1) & (2). Logging Program: Aurora will have mud loggers on site for the duration of r/f drilling activities. Schlumberger will provide wireline logging services and will run their Platform Express suite in open-hole and a CBL will be run in the 5 %" cased hole prior to perforating and testing. A gamma ray log will be obtained to surface while logging out of the hole on one of the Platform Express runs. Proposed logs at this time are: Lone Creek #3 Proposed Logging Program Well Section De the ft OH CH Lo T e 10 5/8" Surface 0 - 700 N/A: No open-hole logs planned for surface at this .;....,. ~~~ ~ ~~. 8 5/8" Surface 0 - 700 GR Cs 7 7/8" Prod 700 - 3200 Platform Express: Array Induction, Compensated Neutron, Litho-Density, SP, GR, DSI and FMI. Also MDT and Sidewall cores. 5 1/2" Prod Cs 700 - 3200 CBL, GR, CCL Surface - TD 0 - Mud Lo in Services BOP Equipment: Aurora Gas, LLC will the same BOP system they have been using for the last (3) years which will consist of the following: 10 5/8" surface hole: While drilling the 10 5/8" surface hole, a 13 5/8" 5M annular w/ 13 5/8" diverter spool and 10" diverter line will be used. Information on this system is already on file at the AOGCC. 7 7/8" Production Hole: An 11" (3M) Schafco BOP system will be used which is configured with an 11" 3M annular preventer, (1) 3M double gate with a set of blind rams and one set of pipe rams sized to fit the pipe being run and (1) 11" 3M 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. Pressure Considerations: From offset wells in the immediate area and actual pressure data from the nearby offset well Lone Creek No. 1, maximum anticipated bottom-hole pressures should not exceed 1500 psi at 3200 ft. Pressures measured at the Lone Creek No. 1 well indicated a gradient of ~.46 psi/ft with abottom-hole pressure of 1100 psi recorded at 2400 ft. Maximum anticipated surface pressures "MASP" can be calculated by subtracting the gas gradient of .11 psi/ft from pore pressure gradient of .46 psi / ft and multiplying by the total TVD depth. =>MASP = (.46 - .11) * 3200 = 1120 psi ~ ..- Aurn~°a Gas .TLC'. Page 3 o f 10 Rev. 1.0 6%1 ~'200~ i • Aurora Gas, LLC. Lone Creek No. 3 Df•illing Program Drilling Fluids: The drilling fluids are being furnished by Baroid Drilling Fluids. Baroid has extensive experience with drilling activities in this area. An experienced mud engineer will be on site at all times while drilling to monitor ~ rheologies and make recommendations. Drilling Fluid Properties While Drilling Surface 10 5/8 Hole Section to 700': Beluga Formation Base Fluid Density PV YP 3% KCL 9.8 - 10 ppg 22 - 30 20 - 30 API Filtrate < 5 Total Solids 15 - 25 Gel & Polymer mud system Drilling Fluid Properties While Drilling 7 7/8" Hole Section to 3200': Beluga and Tyonek Formations Base Fluid Density PV YP API Filtrate Total Solids Polymer mu 5% KCL 9.3 - 10 ppg 22 - 30 20 - 30 <5 15-25 d system Drilling Fluid Handling System: Shale Shaker, Mud Cleaner, Centrifuge, PVT monitors 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 11 7/8" conductor will be cemented in place using industry standard casing cementing techniques utilizing a casing shoe, float equipment and wiper plugs and centralizers installed as needed. Aur°a~°a Gas L,.I C. .Page 4 of IO Rev. 1.0 ~/.l 7/200 • Aurora Gas, LLC'. • Lone Creek ~'o. 3 Drilling I'r~ogram Lone Creek No. 3, 11 7/8" 71.8# LSS Conductor Analvsis and Cementing Program The conductor for Lone Creek No. 3 will be driven to -- 80' or refusal. Joints will be welded and a drive shoe will be welded to the bottom joint. No cementing is required. Please see attached Conductor Analysis with specifications. Lone Creek No. 3, 8 5/8" 32# WC-50 STC Surface Casing Analvsis and Cementing Program The 8 5/8" surface casing will be cemented in fully from the proposed set depth of 700' to surface with a 14.5 ppg "G" tail cement system. Where: 10 ~~8" OH Capac;ty = 1097 bbl//± 8 5/8" 32# Csg x 10 5/8" OH capacity = .0374 bbl / ft 8 5/8" 32# Csg capacity = .0609 bbl/ft OH x Csg: 700 ft x .0374 bbl / ft x 100 % excess = 52.4 bbls Shoe Jt: 35ft x .0609 bbl/ft = 2.135 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 to utilize alias-Block type additive to minimize potential for gas entrainment and or channeling. Cement System Weight ppg) Volume Required Gas-Block enhanced 14.5 54.5 bbls @ 100% Please see attached 8 5/8"surface casing analysis and specifications. Lone Creek No. 3, 5 1/2" 17# J-55 LTC Production Casing Cementing Program The 7" production casing will be cemented in fully from the proposed set depth of 3200' 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. Where: 5 %" 17# csg capacity = .0232 bbl/ft 5 %"17# csg X 7 7/8" OH capacity = .0309 bbl/ft 5 '2" 17# csg X 8 5/8"32# annular capacity = .0316 bbl/ft 5 %" 17# csg displacement = .00614 bbl/ft Auror°a Gas T L,C". Page ~ of 10 Rev. 1. D (/.17/2D0~ Aurora Gas, LLC. Lone Creek ~o. 3 Drilling Pro~rarn Lead System: 8 5/8"CH x 5 %"Csg: = 700ft 700ft x .0316 bbls/ft x 1 (0% excess)=22.12 bbls 7 7/8"OH x 5 %" CSG: 1000ft - 700ft = 300ft 300ft x .0309bb1/ft x 1.25 (25% excess) = 11.6 bbls Total Lead System = 34 bbls Tail System: 7 7/8"OH x 5 %" Csg: 3200ft - 1000ft = 2200ft 2200ft x .0309bb1/ft x 1.25(25% excess= 85 bbls Shoe Joint = 35' x .0232 bbl/ft = .812 bbls Total Tail Cmt Volume = 86 bb/s Cement System Type Cement Weight (ppq) Volume _% Excess I earl "C;" 1:x,5 34 bblc @ 25°1° OH Tail "G" 15.8 98 bbls @ 25°I° OH Please see attached 5 1/2" production casing analysis and specifications, Drilling Hazards: / Drilling in the South Central Region of Alaska offers its own challenges. Common known hazards are as follows: Shallow gas: Shallow gas is a known hazard which exists throughout the area. The northwest side of Cook Inlet is noteworthy for its shallow gas hazard. All responsible personnel will be made aware and a notice of such hazards will be posted in the rig doghouse. There is no record of H2S in the region, however; a gas detection system capable of detecting H2S as well as methane will be installed on the rig with detectors at the floor level, the shale shaker and in the cellar. Coal Seams: The Cook Inlet region is rich in coal seams, inter-bedded between the sands, gravels and shale's 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 A. urora Gas I L C'. .Page 6 o f .I Q Rev. 1.0 ~i,/.17,/20() • Aurora Gas, LLC'. • Lane Creek No. 3 Drilling Program 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 your drilling fluid to properly remove the coals drilled up, and to hold flowing coals in place. Again, heed the recommended drilling fluid program and advice offered by the on-site Mud Engineer. Nearby Well's: There are no known active wells in close proximity to Lone Creek No. 3. The nearest known well is Lone Creek No. 1, which is 1 mile to the south. The Chuit State No. 1 and No. 2 well's, both of which are P&A'd are within 1 mile. Other: Sticky bentonitic clays, boulders, lost returns & differential sticking wl overbalanced muds (+12.5ppg) and gas influx while cementing. - Aur°ar°a GasI,LC'. Page 7 of 10 .Rev. 1.0 6/17/200 s ~ Aurora Gas, LLC.. Line Creek No. 3 Drilling Program Lone Creek No. 3 Summary of Drilling Hazards POST THIS NOTICE IN DOGHOUSE ~ There is potential for abnormal pressured shallow gas. ~~~ ~l There is potential for stuck pipe in coals encountered while drilling from surface to TD. Be extra vigilant while performing hole opener run. ~ There is no H2S risk anticipated for this well. ~ Due to potential for shallow gas kick, very little response time will be afforded to respond. PVT and gas detection systems must be fully operational and functioning at all times, visual flow checks and pit level monitoring are critical. CONSULT THE LONE CREEK No. 3 WELL PLAN FOR ADDITIONAL INFORMATION. Auroi°a Gas I.,I,C. .Page 8 of 10 .Rev. 1.0 6/17/200 aurora Gas, .LLC. Lone Creek No. 3 Drilling Program ~~~~~~ ~„ .~, Lone Creek No. 3 Days vs. Depth Days From Spud U - _.,...... _._._... _ .... ._ ............. _.._..... _.... 100 I 200 10 5/s" Hole to 700', Set / I I 300 cements 5/8" surtace casing NU BOPE at 700 P-test Drill ~ 400 . , , out and FIT to 16 ppg MWE 500 600 700 800 900 1000 ~ i I 1100 1200 1300 1400 .-. 1500 ~ 1600 ~ TD Ru ~ n 3 5 1 20 /2" 0', c C as on ing diti a on nd h ce ole m , r en un t P O e H l rto og rat s, e 1700 tes t a nd c om pl e w el l. . , 1$00 t Q 1900 d I 2000 ~ 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 3100 3200 3300 3400 3500 3600 5 Aurora Gas I.,I.,C. Page 9 of .10 .Rev. 1.0 ~,il 7,!?00~ Aurora Gas, LLC'. Lone Creek No. 3 Drilling Program =-:~t~l~a/"~t sue, t.LC , Lone Creek No. 3 Proposed Configuration Drill 10 5/8" Hole , Z 7/8" X 5'/:" annulus to be disp-aced over to inhibited packer fluid w/diesel freeze protect at surface following completion. Top Beluga ~ 500' E Top Tyonek --1500' , w 2 7/8" 6.5# EUE 8rd Tubing to Top of Screen Tyonek Perforation Intervals to be determined by open-hole logging. Dri117 5/8" Hole ~ PBTD est at 3160' Auror°a Gas .I.,.I.,C'. Rev. 1.0 2 7/8 6.5# 8rd EUE J-55 Tubing 11 7/8" 71.8# Structural Conductor to be driven to 80' or refusal 8 5/8" 32# Surface Casing set at 700' Cement w/ 14.5 ppg Gas-Block enhanced cement (~ 55 bbls cmt @ 100% Excess) Sliding Sleeve 1 joint above packer @ 2280' w/ 2.66" X-Profile for landing plug 5 %:" Retrievable type Seal-bore Production Packer 90' above upper perforation 2.66" X-Profile 1 Joint below packer Attachment I ' Sand Exclusion Screen across all perforations. All Screen sized to 5'/z" casing. 5 '/:" 17# J-55 Casing to 3200' MD (TVD) Cmtd w/ 34 bbl 13.5 ppg Lead at 25 % and 86 bbls 14.5 ppg Tail at 25%(Top of Tail to extend to 1000' MD) Page 10 of .10 ~!17,'200~ • • (~ ~~ Aurora Gas, LLC Lone Creek No. 3 Min. Safety Factors To Be Used: Body Yield: 1.5 Jt. Strength: 1.8 Collapse 1.5 Collapse While Cementing 1.5 Top Burst 1.1 Bottom Burst 1.1 11 7/8" Conductor Casing Properties: Size OD: 11 7/8 Grade: P-110 !,.'eight ppt: 71.80 Coupling: Welded Set Depth ft 80.00 (ft)MD 80.00 (ft)TVD Next Casing Depth 700.00 (ft)MD 700.00 (ft)TVD FIT TEST OR TD DEPTH N/A (ft)MD N/A (ft)TVD Collapse Resistance (psi) 5290.00 Internal Yield (psi) 9430.00 Joint Strength (psi) x 1000 1988.00 1,988,000.00 'Tensile Limits Body Yield (psi) x 1000 2271.00 2,271,000.00 "Tensile Limits API Drift Diameter (in) 10.625 Wall Thickness (in) 0.58 Formation 8~ Fluid Properties: Weight ppg Gradient psi/ft Mud Weight 9.30 0.484 psi/ft ' Anticipated Mud Wt Next Csg Pt. 10.50 0.546 psi/ft Calculated Bouyancy Factor @ Mud Wt: 0.86 Anticipated Cement Weight (ppg) 14 0.728 psi/ft Sea Water Gradient (ppg) 8.94 0.465 psi/ft Frac Gradient at Shoe(ppg) 13 0.676 psi/ft Frac Gradient at Next Casing Point 16 0.832 Est. Pore Pressure Gradient @ Shoe 8.4 0.437 Est. Pore Pressure Gradient @ Next Csg Pt. 13.2 0.686 Gas Gradient (psi/ft) 0.110 Mud Backup Gradient ppg 8.95 0.465 ~° ~ Fluid Drop for Collapse C~Iculation (Enter #). 55 0.55 • • Tensile Calculations: Weight in Air (Ibs) 5,744.00 Bouyant Weight in Mud (Ibs) 4,927.19 Maximum setting depth (ft) 27,688.02 In Air: = Jt Strength / Wt.ppf Joint Strength Safety Factor 346.10 In Air: = Jt Strength / (Wt ppf * set depth) (At proposed depth) Body Yield Safety Factor 395.37 In Air: =Body Yld / (Wt ppf "set depth (At proposed depth) Collapse Calculations: Collapse Safety Factor 338.29 Collapse Res / (Depth TVD " % Fluid Drop *(Mud B-up Grad -Gas Grad)) Collapse SF while cementing 251. $1 Collapse Res /Depth ND * (Cmt Grad - B-up Mud Grad) No lost Circulation/Evacuation occurs Burst Calculations: Assume seawater backup gradient, .465psureforburstdesignpurposes Assume worst case by using anticipated hat gradient for TD of next hole section (TVD) for MASP calculations MASP (Maximum Anticipated Surface 505.40 (Prat Grad -Gas Grad)* Next Casing Set Depth (TVD) Pressure) Top Burst Safety Factor 18.66 Tube burst rating /ASP Bottom Burst Safety Factor 18.73 (Int. Yld + Depth TVD * Seawater Grad) /ASP Summary of: 11 718 Safety Factors Body Yield 395.37 in air "Tensile" OK Joint Strength 346.10 in air "Tensile" OK Collapse 338.29 OK Collapse 251.81 while cementing OK Top Burst 18.66 OK Bottom Burst 18.73 OK • • (~ ~~ Aurora Gas, LLC Lone Creek No. 3 Min. Safety Factors To Be Used: Body Yield: 1.5 Jt. Strength: 1.8 Collapse 1.5 Collapse While Cementing 1.5 Top Burst 1.1 Bottom Burst 1.1 8 5/8" Surface Casing Casing Properties: Size OD: 8 5/8 Grade: WC-50 \A/ninht npf; .,.y. , r 32 nn Coupling: STC Set Depth ft 700.00 (ft)MD 700.00 (ft)TVD Next Casing Depth 3200.00 (ft)MD 3200.00 (ft)TVD FIT TEST OR TD Depth 720.00 (ft)MD 720.00 (ft)TVD Collapse Resistance (psi) 2440.00 Internal Yield (psi) 3600.00 Joint Strength (psi) x 1000 341.00 341,000.00 * Tensile Limits Body Yield (psi) x 1000 457.00 457,000.00 * Tensile Limits API Drift Diameter (in) 7.796 Wall Thickness (in) 0.352 Formation &Fluid Properties: Material Weight ppg Gradient psi/ft Mud Weight 10.50 0.546 psi/ft Anticipated Mud Wt Next Csg Pt. 10.50 0.546 psi/ft Calculated Bouyancy Factor @ Mud Wt: 0.84 Anticipated Cement Weight (ppg) 15.8 0.822 psi/ft Sea Water Gradient (ppg) 8.94 0.465 psi/ft Frac Gradient at Shoe(ppg) 16 0.832 psi/ft Frac Gradient at Next Casing Point 16 0.832 Est. Pore Pressure Gradient @ Shoe 13.2 0.686 Est. Pore Pressure Gradient @ Next Csg Pt. 13.2 0.686 Gas Gradient (psi/ft) 0.110 Mud Backup Gradient ppg 8.95 0.465 °~ Fkiid Drop fer Collapse Calculation (Enter #). 55 0.55 • • Tensile Calculations: Weight in Air (Ibs) 22,400.00 Bouyant Weight in Mud (Ibs) 18,803.67 Maximum setting depth (ft) 10,656.25 In Air: = Jt Strength / Wt.ppf Joint Strength Safety Factor 15.22 In Air: = Jt Strength / (Wt ppf * set depth) (At proposed depth) Body Yield Safety Factor 20.40 In Air: =Body Yld / (Wt ppf * set depth (Af proposed depth) Collapse Calculations: Collapse Safety Factor 17.83 Collapse Res / (Depth ND * °h Fluid Drop *(Mud B-up Grad -Gas Grad)) car •~ voliapse ar tivhire cL~eirtiiry` -~n . r ~ Coiiapse Res i Depur TJD * (Cori Gr-eu' - B-up Mud Grad) No lost Cin;ulation/Evacuation occurs Burst Calculations: Assume seawater backup gradient, .465psi/Rforburstdesignpurposes Assume worst case by using anticipated fret gradient and pore press gradients at shoe with TD(TVD) of next hole section for MASP calculations MASP (Maximum Anticipated Surface 2,310.40 (Prat Grad -Gas Grad>* Next Casing Set Depth ND Pressure using Frac Grad) MASP (Maximum Anticipated Surface 1, 844.48 (Pore Press Grad -Gas Grad)* Next Casing Set Depth ND Pressure Using Known Area Pore P) Top Burst Safety Factor 1.95 Tube burst rating /ASP (Based on most realistic MASP above) Bottom Burst Safety Factor 1.70 (Int. Yld + Depth ND * Seawater Grad) /ASP Summary of: 8 5/8 Safety Factors Body Yield 20.40 in air "Tensile" OK Joint Strength 15.22 in air "Tensile" OK Collapse 17.83 OK Collapse 9.79 while cementing OK Top Burst 1.95 OK Bottom Burst 1.70 OK • ~ ~ ~~ Aurora Gas, LLC Lone Creek No. 3 Min. Safety Factors To Be Used: Body Yield: 1.5 Jt. Strength: 1.8 Collapse 1.5 Collapse While Cementing 1.5 Top Burst 1.1 Bottom Burst 1.1 Properties: e OD: 5 1/2 ade: J-55 sight ppf: 17.00 upling: LTC t Depth ft 3200.00 (ft)MD xt Casing Depth 3200.00 (ft)MD Test Depth 720.00 (ft)MD (lapse Resistance (psi) :mal Yield (psi) nt Strength (psi) x 1000 dy Yield (psi) x 1000 I Drift Diameter (in) 4.767 dl Thickness (in) 0.304 51/2" Production 3200.00 (ft)TVD 3200.00 (ft)TVD 720.00 (ft)TVD 4910.00 5320.00 247.00 273.00 Formation & Fluid Properties: (Material Weight ppg Gradient psi/ft 247,000.00 "` Tensile Limits 273,000.00 `Tensile Limits Weight 10.50 0.546 psi/ft ~ ;ipated Mud Wt Next Csg Pt. 10.50 0.546 psi/ft ulated Bouyancy Factor @ Mud Wt: 0.84 ;ipated Cement Weight (ppg) 15.8 0.822 psi/ft Water Gradient (ppg) 8.94 0.465 psi/ft Gradient at Shoe(ppg) 16 0.832 psi/ft Gradient at Next Casing Set Point 20 1.040 psi/ft Pore Pressure Gradient @ Shoe 13.2 0.686 psi/ft Pore Pressure Gradient @ Next Csg Pt. 18.5 0.962 psi/ft Gradient (psilft) 0.110 psi/ft Backup Gradient ppg 8.95 0.465 psi/ft Fluid Drop for Collapse Calculation (Enter #). 55 0.55 • • Tensile Calculations: Weight in Air (Ibs) 54,400.00 Bouyant Weight in Mud (Ibs) 45,666.06 Maximum setting depth (ft) 14,529.41 In Air: = Jt Strength / Wt.ppf Joint Strength Safety Factor 4.54 In Air: = Jt Strength / (Wt ppf * set depth) (At proposed depth) Body Yield Safety Factor 5.02 In Air: =Body Yld / (Wt ppf * set depth (At proposed depth) Collapse Calculations: Collapse Safety Factor 7.85 Collapse Res / (Depth TvD' % Fluid Drop'(Mud 6-up Grad -Gas Grad)) voliap~e ~J~r-viiiiie Ce~i~ei~ting 4.~1 CoiiapseResiDepthiVD`(CmiGrad-FS-up MudGradj No lost Circulation/Evacuafion occurs Burst Calculations: Assume seawater backup gradient, .455psi/kforburstdesignpurposes Assume worst case by using anticipated frac gradient and pore press gredienfs at shoe with TD (TVD) of next ho/e section for ASP calculations MASP (Maximum Anticipated Surface 2, 310.40 (Prat Grad -Gas Grad)' Next Casing Set Depth (TVD) Pressure Using Frac Gradient @ TD) MASP (Maximum Anticipated Surface 1, 844.48 (Pore Press Grad -Gas Grad)' Next Casing Set Depth (TVD) Pressure Using Known Area PP) Top Burst Safety Factor 2.88 Tube burst rating /ASP 2.66 Using PP (Based on Most Realistic MASP above) Bottom Burst Safety Factor 2.95 (Int. Yld + Depth TVD' Seawater Gra 3.69 Using PP Summary of: 51/2 Safety Factors Body Yield 5.02 in air "Tensile" OK Joint Strength 4.54 in air "Tensile" OK Collapse 7.85 OK Collapse 4.31 while cementing OK Top Burst 2.88 OK Bottom Burst 2.95 OK • • E & P SERVICES, ING. June 17, 2005 Mr. John Norman, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Ave., Suite 100 Anchorage, Alaska 99501 Attn: Mr. Tom Maunder P.E. RE: Application for Permit to Drill: Lone Creek No. 3 Dear Mr. Norman: Aurora Gas, LLC hereby applies for a Permit to Drill an onshore exploration well in the Lone Creek Gas Field of Alaska. The well, Lone Creek No. 3, will be located approximately 6 3/4 miles northwest of Tyonek, Alaska. Aurora Gas, LLC proposes to spud the Lone Creek No. 3 on June 25, 2005. Aurora has already submitted under separate cover, a request to cancel the original Lone Creek No. 3 drilling permit (PTD # 203-062). The Lone Creek No. 3 well will be drilled on a pad originally constructed for use as a staging area in the mid 1960's by Superior Oil Company for the drilling of the Chuit State No.(s) 1 and 2 wells and access will be over existing roads in the area constructed for that use. This well will be approximately 3527 ft north of the Lone Creek No. 1 well. '- Pertinent information in and attached to this application includes the following: 1) Form 10-401 Application for Permit to Drill - 2 copies 2) Fee of $100.00 payable to the State of Alaska 3) Location As-Staked plat 4) Days vs. Depth drilling curve 5) Drilling Procedure 6) Wellbore Schematic 7) Pressure and casing design and property information. 8) Description of the BOP equipment to be used per 20 AAC 25.035 (a)(1) and (b) 9) Cement program description 10) Drilling fluid program description 11) A summary of potential well hazards. 2000 East 88th Avenue • Anchorage, Alaska 99507 • (907) 258-3446 • FAX (907) 279-5740 650 North Sam Houston Parkway East, Suite 505 • Houston, Texas 77060 • (281) 445-5711 • FAX (281) 445-3388 ,,,c • • Mr. Norman May 20, 2005 Page 2 If you have any questions or require additional information, please contact the undersigned at 258-3446, or Mr. J. Edward Jones (Vice President of Engineering and Operations, Aurora Gas, LLC) at (907)277-1003. Upon approval of this application, please forward a copy of the approved packet to Fairweather's office as well for implementation. incerely, r--._. Duane H. Vaagen ' ~ " `~ "° ~~~, (.~C Project Engineer Attachments cc: J. Edward Jones Andy Clifford Duane Vaagen • ~'a~~ ,g, .- ~^ i "'~"' • ~`. `- SEC 7 SEC 8 - r_ ` ,~,,, > ~ ~y SEC 18 SEC 1 i ..~ . ~ "? ~4 %,r ~,,,~«~ , "` .~,. • GRID N:2610096.260 ~ -; . ,~. f~„~,,.~,,,...v , ':~ ~d~~~ .~ ~~f '~;-. _ GRID E:273592.570 t .~ ''~ •''•' 1' catch 5~~~ ~ LATITUDE: 61°08'16.647"N ~~ .,i~o~-,~ LONGITUDE: 151°16'51.967"W ~' ~` ~~ ~~ Grid ~ ,~ . ~ ~~-~ -~ , . ~ r. ~'..~ .'- ,~* ;.~~ ~ *. NORTH , . y t' ~~ ~' ~ s: r~'~'~:-~. %~ ~~ ~~{ ~ _ ,,. ,~ i " 1) BASIS OF COORDINATES IS ALASKA STATc ~ ~' , •, , ~~ ~;.~- ~,,~~5S ` , , • w ~, f ~'~ '. PLANE NAD 27 ZONE 4 FROM A DIRECT TIE '~!' ~ ~~ i ./ +~,~! ~r~~y ' TO ADL NO. 31270. ' ' ,~ _~~` . •• r!1- .~. ~,......~'~;P ;~ ~ ,~ • ..' 2) BASIS OF ELEVATION IS FROM TIDAL ~,~. • + ~... ~ ~ ~ ~ -~ OBSERVATION ON 9-22-93. DATUM IS MLLW. ~ + ~ ~ ~ ~-'Z ,~,,~ ~ ~~i . ~' ~~ ALL ELEVATIONS SHOWN HEREON WERE !` ~ ~ •` ~"y* +t- ~ • • :.. ' ,±i-~ ; ' TAKEN ON GROUND. . `~• i 136$' FEL fir- ~• ~'• 3) SECTION LINES SHOWN HEREON ARE fY~'4 • ~, • _ ~ `' BASED ON PROTRACTED VALUES. t ~ ,,,,'' .+~'~~~ - ~ • ~~ ETLAND LONE CREEK NO. 3 AS-STAKED , ~.'~+ , ; ' ~~ ~ : ~' '':GRID N:2608542.613 r ' ~ ~+~' ~°~''~r .~ , _ GRID E:272197.963 • ~' ~~` - °'"' LATITUDE: 61°08'01.081"N i~ ~~ ~ '~ r , ~• 1 LONGITUDE: 151°1719.744"W ~ `~~ -', ~ - ~. ~~ : ~~ OF, A~q ~-~ ~,. =rtt'*-'ELEV. 370' ~ ~ ~.. ..,, Y~. _! ~ ,* .. M . *:•49T-" '.* ~` , ., L'iY r~yr: ~ •~ to ~TIr '~ • ' !'t ................. ~ ~, ~ ; ,,, // ~, , ~~,~ ,. % Asir` ~ M. SCOTT MceANE~ >~ i $~~';I~~ ~~„ z r ~. t ~'~ sr •~• 4928 S •.•' J~' /r / ~ .. C /' . `~ ~,~ ~'OFESSIONPL ,~~,y,.6' ~~ ., w :. ~ ~ ~ ~ . ~y,~ .{~ 714 s.., , ~ '~ •~~~;s..so .,~~r fi ../ , .y -V{R, - r ~~ < ,~ ~ ~~' ~,,, "f'~' ~S, L ff\\ _ ir' , ~ `~ ~ 1 ~~*.,. .~~' '~~. 'yr i~4 +.Y ._~ '`fry` ~ =r-~,~~'$i LONE CREEK NO. 3 WELL AS-STAKED SURFACE LOCATION DIAGRAM McLane Consulting Inc APPLICANT: ENGINEERING/MAPPING/SURVEYING/TESTING _-~~ - A~~r~ ~~~~ ~~ P.O. BOX 468 SOLDOTNA, AK. 99669 l't_-- VOICE: (907) 283-4218 FAX: (907) 283-3265 EMAIL: msmclane®mclanecg.com SEC. LINE LOCATION: PROJECT NO. DRAWN BY: DATE: OFFSETS: PROTRACTED SECTION 18 May 27, 05 1579' FNL TOWNSHIP 12 NORTH.. RANGE 11 WEST 053033 MSM 1368' FEL SEWARD MERIDIAN, ALASKA i ~~~ ~~~~? Petroleum Corporation C ~ c~ t-c e ~z ~ -~~ Inter-Office Correspondence ` ~ ~ August 2, 2000 ~~ TO: P. Leach/T. Thompson G-z I ~ `=' FROM: M. P. Globe SUBJECT: Formation water salinities on the Moquawkie Anticline Attached are formation water analyses on two wells on the Moquawkie Anticline, the Simpco E. Moquawkie #1, and the Lone Creek #1 st1. In these two logs, formation water resistivity has been calculated with two different methods, the Rwa method, and the Rw from SP. Rwa is a technique that calculates apparent formation water resistivity from computed log porosity and measured formation resistivity using the Archie relationship Ro=Rw/Phi"' where Ro is the resistivity of the water saturated formation, Rw the formation water resistivity, Phi the formation porosity, and m the cementation exponent. In the Rwa technique, the solution to this equation yields Rwa =Rt* Phi"' (Rt is the true formation resistivity). Phi can be calculated from density, neutron, and/or sonic logs, Rt is measured with a resistivity device, and m must be either measured from core, or inferred from rock type. In the case where formations are fully water saturated, Rwa is a close approximation of true formation resistivity, and thus salinity. In hydrocarbon bearing zones, the Rwa technique will yield an apparent formation water resistivity that is higher than true formation water resistivity. In these analyses, Rt was taken from the deep resistivity measurement, and porosity was calculated using the density/neutron crossplot technique. The exponent m was assumed to be equal to 1.8 based on cuttings descriptions that indicate that the formations penetrated are slightly to moderately consolidated. The cementation exponent, m, is a function of a number of formation characteristics that affect the tortuosity of the resistivity paths in the rock. Typica{ly, as formation consolidation/cementation increases, m increases. The world-wide average for m is very close to 2. The Reservoirs Inc. World Wide rock catalog has measured m values from over 40 cores. In this catalog, m ranges from a minimum of 1.68 to a maximum of 2.26, with a mean value of 1.93. Increasing m will decrease the calculated Rwa value. The Rw from SP method uses the equation SSP=-Klog(Rmfe/Rwe), where SSP is the static spontaneous potential value, K a temperature based constant (K=61 +.133*Temperature), Rmfe the chemical activity equivalent of drilling mud filtrate resistivity, and Rwe the chemical activity equivalent of formation water. Methods for converting from Rwe and Rmfe to Rw and Rmf respectively are documented in the Schlumberger Log Interpretation Chart #SP-2. The Rw from SP method is complicated by the SP measurement's inability to resolve thin zones, suppression of SP response in low permeability and hydrocarbon bearing intervals, the accuracy (or lack thereof) of the Rmf value, and the presence of SP baseline drift. Sp baseline drift is a problem that is particularly bad in the Cook Inlet area where good SP grounds are difficult to attain. For the Rw from SP calculation presented in this report, SP curves were baseline shifted to remove drift, and Rw was calculated using Rmf values reported on the Schlumberger log headings. • • The attached fogs (figures 1 and 2) include computed shale volume (curve name VSH), baseline shifted SP (curve name SBL), Rwa (Curve name RWA1.8), Rw from SP (curve name RWSP), and resistivity curves. Rwa has been calculated in the sands only. Also included on the plots is a curve labeled "LIM". This curve denotes the resistivity equivalent of a 3000 ppm NaCI brine versus depth. The resistivity equivalent value decreases with depth due toincreasing formation temperature. Resistivity is inversely proportional to salinity, so a decreasing Rwa value corresponds to an increase in salinity. In those places where the Rwa and RWSP curves are to the left of the LIM curve, the zones ave formation water salinities in excess of 3000 ppm a I equiva en . The match between Rwa and RWSP in the Lone Creek #1 st1 is exceptionally good, particularly taking into account the relatively poor quality SP curve from this well. In the Simpco E. Moquawkie #1, the Rwa and RWSP curves track each other well, but there is an offset between the two curves that is consistent throughout the well. This is most likely due to an incorrectly reported Rmf value on the log heading. An additional RWSP curve with the curve mnemonic RWSP.5, was calculated for this well, assuming that the Rmf value was off by a factor of two (a large but not unusual error, particularly with this vintage log). This adjusted RWSP.5 curve is in good agreement with the Rwa value computed in the well. It should be noted that the Rw from SP values are valid only in the permeable intervals. Impermeable intervals will have no or little SP deflection. To further corroborate the calculated formation water resistivities, our files were searched for measured formation water resistivity and salinity values. Attached are copies of the water analysis reports on zones in both wells. An RFT in the Lone Creek #1 st1 recovered water from 5589.5', with a salinity of 25,300 to 31,700 ppm Chlorides (approximately 46,000 ppm NaCI equivalent) with resistivity of .125 to .111 Ohm-m at 66F. Based on the high Potassium content in this water, 'it is probably highly contaminated with drilling mud filtrate. A somewhat more conclusive result was attained from a DST done in the Simpco E. Moquawkie #1 over the interval from 8490 to 8512. This test yielded water with NaCI equivalent concentrations in the range of 6382 ppm to 6650 ppm, and resistivity values in the range of 1.06 to 1.1 ohm-m. Expanded plots of the two wells over these intervals (figures 3 and 4), comparing the recovered water resistivity values to those calculated from SP and Rwa techniques are included here. On Figure 3, the plot of the Lone Creek #1, the temperature adjusted recovered water resistivity is represented by the curve named RWRFT. On Figure 4, the plot of the Simpco E. Moquawkie #1, the temperature adjusted recovered water resistivity is represented by the curve named RWDST. Copies of the formation water analyses are also attached. It should also be noted when considering the issue of contamination of the fresh water table on the Moquawkie anticline, that the Lone Creek #1 encountered what Anadarko believes to be gas charged sands in sands as shallow as 1000'. ~- ~~~`' '"`~ Sr,.c.~~z4ti~ .6~ lam; wcz~` It is evident from the attached figures, that the Rwa, RWSP, and produced water data -' L,y and interpretations are corroborative, and that at a minimum, from the top of the "C ~~~`~ Marker" strati raphic section down, all water-saturated sands have formation water sa mines well in excess of 3000 ppm NaCI. Those sands within these sections at exhibit Rwa va ues above the 30 ppm line are fully or partially gas saturated. A word about the Lor~reek #1 st1 to stem (hopefully} ar,otential'confusion: Due to drilling difficulties, the Lone Creek #1 well was sidetracked below the interval included in this analysis, and below the depth at which the RFT that is the source of the attached water analysis was run. Both the Lone Creek #1 and the Lone Creek #1 st1 are exactly the same well bore through the interval interpreted in this report. Because our digital log database is more complete in the Lone Creek' #1 st1 version of the data, this "well" was used for the petrophysical interpretation. Please contact me with any questions or comments. • • 3 ~~~~--~ ~`'' w G"'- GP C- 1 SA ND E M A R K ER D E COA L D MARKER _ ~ - - - - ~ - - - ~+ - R = _ - - OSE MARKS MARKER < m - - - - - --- - - - - - - 2 - ^ - S _ e - - - - - - - - - - - - - - - ~ - - - - ~ - - - - - - - - - ~ A 3 ~. I - _ _ _ _ _ _ _ _ _ _ ~ I _ _ _ ~ _ _ _ _ _ _ _ _ _ _ _ 3 'n _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ I ~ o - - _ - _ - _ - _ - _ - _ - _ - _ - _ - _ - _ - _ - _ - _ - _ - _ - _ - -_ - - -- - - _ - _ - ~ _ - - - - - - - - - - 70 A - O ~ O F L'rJ _ - _ - - - - - - - - - - - - - - - - _ _ - _ - - - - - - _ = - - - - - o y ~ s ~ fm E ~" ~ ~' `n 3 ~ 3 u 3 '° 3 r ~ -~ - - - - - - - - - - - i O .C - - - - - - - - - - - - - - - - - - C - - - - - - -_ - - - - -_ - - - - - - - - - - - - m ~ -_ - - - - - - - - - - - - - - _ - ~ A g g~~ ~° S g ~° b p pspT~ee E b ~p95? S g g ~q ~ 5o ``~~ E ¢ ~ ~ QQ E~ ~ ~ g g QQ S~ ~ g ~~ psps b .~ ~~ g }QQ} 8 55 `~$ S ~ g~ ~ g yy E S g~ `Q`~ E g ~ ~ ~ g ~ ~ g QQ `Q`~ S S ~ g ~ y y^^~~++ ~ b~ ~~ `Q`~ ~ E ¢¢ S ~ - ~ y r _ _ _ _ _ _ _ _ I _ _ _ _ _ _ _ _ _ _ _ + _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - - - - - - - - - - - - - - ~ S 3 3 0 ~' S ~ 3 ° 3 r 0 _ _ _ _ = _ _ _ - _ _ _ _ = = _ _ ' _ _ _ _ _ _ _ _ _ _ _ _ _ _ = _ _ _ _ _ _ _ _ = _ _ _ us e S ° ~::.: :,::: ~w ~. ,~+ ~ •~: 4 :: t. ;. - E MARKER ;N IN p~a Qa o~ .e a e ;~i Ig f r d z rn c7 m m N m w • Figure 4 __ Lone Creek 3 -~~M,4 Exploratory WeII 2050970 '~~~~~'~"~ ~~" ~'~~ Confidential wells are red S F D 6/21 /2006 _ ,~ _ • ..£ ~ ~0 el~'"l .~ "d 4't f iYYY~~~~tC r:NU ! ;e • Lone Creek No. 3 t~ ~~;~rEr.'~'?Y I' _ r , Q1 'C __ ,~ _ ~ ~_ N ~~ ~ r., ~ o ~~ 3 ._, 1dt1G' 1~.'HYIE ~ ^~' a; h4i'i .~ kY r_ t ;r ~ ~~G'{ 0 4,S?00 8,fl0d `- Vic, n ~j ' ~c~tz ~:c.. f~.~ t~4 ! ~ C./ ~ ~ !fir- f~~ ~zuc_~. . ~ V Z ,6.L/cr~/ , , .3 ~r~ ~-r /~C C i li-z ~ r/ ~ `' 1~G,C~ ~(SZU ~~c~- z Sl~c, ~ (~-°d Zs i~o - Z.,~bO 2 7 4~ ~~ Gg~U-~~~ • ~~4urora Power FIRST NATIONAL BANK ALA9KA 2 2 7 7 ~ ANCHORAGE, AK 99520 1400 WEST BENSON, SUITE 410 89-6/1252 ANCHORAGE, AK 99503 ~'H: (907) 277-1003 6/17/2005 f PAY TO THE State of Alaska I ~ ** 100.00 ORDER OF --- One Hundred and 00/100***************************~~*k~+#+~*****,~*:r,.******~*~*****~s********************************* _ -- - DOLLARS ~ ~' State of Alaska 5700 E. Tudor Rd Anchorage, AK 99507 Permit to Drill Lone CreekNo. 3 ,~/ ,N. MEMO --- ~/~~'~ ----- 11'00 2 2 7 ?II' ~: i 2 5 200060: 30 20 389 Iii' • TRANSMITAL LETTER CHECK LI5T CIRCLE APPROPRIATE LETTER/pARAGRAPHS TO BE INCLUDED IN TRANSMITTAL LETTER WELL NAME PTD# ~~~ - ~~ 7 CHECK WHAT ADD-ONS "CLUE" APPLIES (OPTIONS} MULTI The permit is for a new wellbore segment of LATERAL existing well , Permit No, API No. (If API number Production should continue to be reported as last two (2) digits a function of the original API number stated are between 60-69) above. PILOT HOLE In accordance with 20 AAC 25.OOS(f), all (pig records, data and logs acquired for the pilot hole must be clearly differentiated in both name (name on permit plus PH) and API number (50 - 70/80) from records, data and logs acquired for well (name on permit). SPACING The permit is approved subject to full EXCEPTION compliance with 20 AAC 25.055. Approval to ,= perforate and produce/infect is contingent 1 upon issuance of a conservation order approving a spacing exception. (Comaanv Name assumes the liability of any protest to the spacing exception that may occur. ` ~ DRY DITCH All dry ditch sample sets submitted to the 30' th t ~ U SAMPLE an er Commission must be in no grea r ~~ ~C ~ sample intervals from below the permafrost ~ or from where samples are first caught and 10' sample intervals through target zones. Rev: 04/01/05 C\jody\transmittal_checklist WELL PERMIT CHECKLIST Field & Pool LONE CREEK, UNDEFINED GAS - 505500 Well Name: LONE CREEK 3 Program EXP Well bore seg ^ PTD#:2050970 Company AURORA GAS LLC Initial ClasslType EXP ! PEND GeoArea 820 Unit OnlOff Share On Annular Disposal ^ Administration 1 Permit_feeattached_____________ ____.._,_____.____-_ __.__._-Yes_ .-__._-__-__ 2 Lease number appropriate_ _ . - - - - _ . _ _ , - - _ - No- _ _ _ - Correction made to_ 1.0-401 form:- the number of the affected leage_is C-061500._ _ 3 Unigpe well-name and number _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ - . _ _ - - Two previous permit applications for Lone Creek 3 were withdrawn_(PTD 2001440) and eanc@Iled (.PTD 2030620).- 4 Well located inadefined_pool.---.-_---------------------- --------No__ _-_.Undefnedgaspool_-----------------------------------------_---- 5 Well located p[oper diskance,hom drilling unitboundary- - - - - - - - - - - - - - - - - - Yes _ - - . - . Well wijl be located 1_,368'_from boundary with CIRI Lease C-461388, but owner &_landowner a[e the_same.- . _ . - 6 Well,locatedproperdiskancefromotherwells__.____,__.__.__ ___-_.__Yes_ _-__.Wellis3,52TfromLone_Creek_1,agasproducer-----------------__---_-__-,__--_--__ 7 Sufficient acreage available in drilling unit- - - - - - - - - - - - - - - - - - - - - - No_ _ _ Dulled ender statewide regulations. which, for a gas well, specify gne_well in a pool per gove[nmental_section . - 8 If deviated,is_wellboreplatincluded______-_________________ _________ NA__ ______Thiswillbethe2ndwellinSection-18,Verticalwell._---_----_-_,_-_-_- 9 Operator gnly affected party, _ . _ _ - - . - . _ _ _ _ _ . -Yes _ _ _ -Lies within the "LCne_Creek Unit," Aurora-is ownerl_CIRI-landowner ofall affected eases. - . _ . - _ _ - _ - - 10 OperaoorhasappropriatebondinfQrGe________________________ _________ Yes_ __--._LetterofCreditN~$429815for$200,OQQ_____._.__._,___,_..___._.__._,__,__,_,_,-_ 11 Permitcanbeissuedwithoutcongervationorder__________________ _________ No.- __.____--_-__,_-.____-_--__-___----_-_. -- - - Appr Date 12 Permit can be issued without administrativ_e-approyal_.____-._-___ ____-._.Yes_ _.____-_.-_____--__-____-__ ~- - - - - - SFD 6/23/2005 13 Can permit be approved before 15-day wait No 14 Well located within area and strata authorized by-InjectionOrde[#(put1O#incomments)-(For. No_- -_-_--___.__--_._-_--_-__---___-.____-__________________________ 15 All wells-within,114_mile area.of review identified (For service well only) _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA_ , . _ , _ _ _ _ - . 16 Pre-Rroducedinjector; duration of pre--prodnctionl_ess than3months_(F4rservicewelloNy)_.NA- ____._-____-____-__._,-_--__-----------------_,--__.__.-____---_, 17 ACMP,Finding of Consistency_ha5 been issued_fo[this project- - - - - - - - - - - - - - - NA_ , _ _ _ , _ Consistency_determination n4 Longer aff_ecks the_approval process for a permitto drill- _ _ . _ - _ _ _ - - _ Engineering 18 Conductor string_provided _ . _ _ . _ _ _ _ _ _ _ . _ _ _ _ _ .. _ _ _ _ _ . _ - _ _ _ Yes . _ . - _ _ . _ - - - - - - - 19 Surface casing-protects all known. USDWs _ .. - - - - - - - - - - - - - - - - - Yes , - , - As proposed, casing strings set and_cemented to sprf_ace will _prQteet any shallow waker,_Gas- iS possiblly_ . - - - 2D CMT-v_ol. adeguate_to circulateon conductor & surf_csg _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _Yes - _ - - _ _ _ present above 1000'. SFD . _ _ . _ _ _ _ . _ - - - - 21 CMT-vol_adequate_tQ kie-in long string to surf csg. _ .. _ _ _ _ .. _ _ - _ . - _ _ . _ _ _ Yes _ _ - _ - _ - _ _ _ _ _ _ - - _ - - - - - 22 CMT willccyerallknown_productiyehorizpns_,__,__.__-___._ _-.-_-_-Yes_ _______________- .-___, - - - 23 Casingdesgnsadeq~ratef_orC,TB&_permafrost--,--.--- ----- - --.-- --Yes- --------.-------------------------------------------------------_-..-. 24 Adequate tankage_or reserve pit - - - - - - - - - - - - - Yes - - . - - . -Rig is_equipped with steel_pits. _~xcess capacity_is not large, Rig has been_used on similaj wells for 3_year- - _ . 25 If a_re-drill, has-a 1.0-403 for abandonment been approved _ _ - _ _ . _ - _ _ - - - _ - _ NA_ _ _ Drilling waste to be processed/handled by Enuirotech. _ - - _ - _ _ - _ - - _ _ _ - _ - _ _ _ - 26 Adequatewellboreseparation-proposed_____.__,_„____________ ___ ______Yes_ __-__,____-- 27 If diverter required, does it meet regulations_ _ - _ - , _ _ _ Yes _ - - .Hole size slightly greater than diverter line._ Arrangement previously approved.. - - . _ _ . _ _ - _ Appr Date 28 Drilling fluidprogram schematic & equip list adequate, _ .. _ _ - - _ .. - - - - _ Yes - - .. .Maximum expected formation presspre 8,8_ENIW._ Planned mud weights up to_ 10,0-ppg._ - _ _ - . _ _ - TEM 612112005 29 BOPES,dothe meet_regulation- - - y ___-_,_Yes_ -_____--_ -------------__.__--__ - - 30 BOPS-press rating appropriate; test to_(put prig in comments)__ _ _ _ _ _ _ _ _ _ _ __ _ _Yes . - _ - _ MA$P calculated at 11.20 psi, 3000. is_BOP test tanned, p p - - 31 Chokemanifoldcompliesw/APl_RP-53(May84)-_____,_-..______ _________Yes_ __-__-__.__.._ - - 32 Work willoccurwithoutoperaiionshutdown-_______------------ ---------Yes_ __-__-__.__-__- - - - - - 33 Is presence ofH2Sgasprobable_.__-____________________ _________ No__ _--_.H2$isngtlepo[ted in shallowCi_gas.,Righassensorsand.alarms.._-____.___.__.____-___.___ 34 Mechanical condition of wells withinAORverkfiedGFor_servicewellonly)-.__ ___-._--_ NA__ ____-_-__._,-,_____--_--__------------------_-_,--_-.----_-__---- -_- Geology 35 Permit-can be issued w1o hydrogen sulfide measures - _ - - .. - . - .. - - - _ . _ Yes _ - - _ _ H2S is not kn4wn_tQ occur in this area, but detectors will be used. Well will be mudlogged._ _ 38 _D_ata_presented on_potential overpressure zones . . . . . . .. . . . . . . . . . .. No_ _ - - _ _ -Well will be drilled within, samegov't sactioq as Lone Creek No._ 1-. _Shallow_gas is still a possibility,_is Appr Date 37 Seismic analysisof shallow gas zones_ . - - - .. - _ . .. _ _ - _ - _ - NA. _ - .. _ - addressed.in Trilling Hazards_section.- Well will be mudlogged,_and gas and PVT sensorswill_be_used. - . , _ , SFD 6123!2005 38 Seabed condition survey_(if off-shore) _ , _ , - _ - - NA - - - - - - Geologic Engineering P blic Date: Date Date SPACING EXCEPTION REQUIRED. Second well in overnmental section. 0 erator will re uest that Permit to Drill be 9 p q Commissioner: ~~ Commissioner: inner j ~/ ~ ~ C~~~ {p~2~ ~~ approved to allow drilling and testing but not production from the Carya 2.4.2 sand, which produces in Lone Creek #1, until ,{ ,/^ exception is granted. Collection of cuttings samples waived far this well because of close proximity to the Lone Creek No. 1 S exploratory well, which has cuttings samples from 24D' to 11,48T. Well will be mudlogged. ~~ // ~ d