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Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov December 13, 2021 Mr. J. Edward Jones Plugging Inlet, LLC 6733 South Yale Avenue Tulsa, OK 74136 Re: Location Clearances Aspen 1 (PTD #2051110) Moquawkie 1 (PTD #2030690) Kaloa 2 (PTD #2040960) Moquawkie 3 (PTD #2050800) Lone Creek 1 (PTD #1980840) Moquawkie 4 (PTD #2070840) Lone Creek 3 (PTD #2050970) Simpco Moquawkie 1 (PTD #1780470) Lone Creek 4 (PTD #2070910) Simpco Moquawkie 2 (PTD #1780880) Dear Mr. Jones: On December 20, 2019, the Alaska Oil and Gas Conservation Commission (AOGCC) received the final Well Completion Reports for the plugging and abandonment of the following wells: Aspen 1, Kaloa 2, Lone Creek 1, Lone Creek 3, Lone Creek 4, Moquawkie 1, Moquawkie 3, Moquawkie 4, Simpco Moquawkie 1, and Simpco Moquawkie 2. On June 15, 2021, AOGCC waived witness of each location status and an environmental site assessment (ESA) was conducted by Environmental Management, Inc. on June 17, 2021. AOGCC received a copy of the ESA report along with accompanying photographs of each site on December 7, 2021. Each drill site was found to be in compliance with onshore location clearance requirements as stated in 20 AAC 25.170. The AOGCC requires no further work on the subject wells or locations at this time. However, Plugging Inlet, LLC remains liable if any problems were to occur with these wells in the future. Sincerely, Jessie L. Chmielowski Jeremy M. Price Commissioner Chair, Commissioner May 13, 2020 RECEIVED MAY 18 2020 Jeremy M. Price, Chair AOGCC Alaska Oil and Gas Conservation Commission 333 West 7"' Ave., Suite 100 Anchorage, Alaska 99501 RE: Request for Information 20 AAC 25.300 Docket Number: OTH-20-035 Costs to Plug and Abandon Wells on CIRI Leases Dear Mr. Price: Regarding your letter to me of May 1, 2020, the following information is responding to your request for costs incurred to plug and abandon the following wells on mineral interests owned by Cook Inlet Regional, Inc. (CIRI): • ASPEN 1 – API 50-283-20114-00-00 • KALOA 2 – API 50-283-20107-00-00 • LONE CREEK 1– API 50-283-20096-00-00 • LONE CREEK 3 – API 50-283-20112-00-00 • LONE CREEK 4 – API 50-283-20121-00-00 • MOQUAWKIE 1 –API 50-283-10019-90-00 • MOQUAWKIE 4 – API 50-283-20120-00-00 • SIMPCO MOQUAWKIE 1 –API 50-283-20060-00-00 • SIMPCO MOQUAWKIE 2 – API 50-283-20062-00-00 Plugging Inlet, LLC, was the operator of these wells and conducted plugging and abandonment (P&A) operations between October 2018 and November 2019. Costs were tracked on the basis of vendors, not by well or activity. Thus, while some costs, totaling about $1,007,000, were paid to vendors who worked solely on the P&A of the wells (e.g., Schlumberger, Pollard Wireline, and Halliburton), most of the vendor;/contractors also worked on DR&R, cleanup, and waste disposal operations. Thus, the costs of these vendors/contractors for P&A operations were estimated on the basis of the Summary of Operations, based on the daily reports—these include camp costs, air and marine transportation, supervision, welder and roustabouts, trucking, and equipment rental. It is estimated that another $595,000 were paid to these other contractors and vendors for services supporting P&A work for a total estimated cost to P&A the 10 wells of $1,602,000, or $160,200 per well. However, one well, the Lone Creek 1, was particularly problematic to P&A due to its original construction, and the cost to P&A that well is estimated at about $244,000, leaving the average cost to P&A the other 9 wells at $151,000. For clarity, the reported $1.6 million is for actual well plugging and abandoning costs only; in addition, Inlet Plugging LLC incurred approximately $3.4 million for associated lease remediation activities, including required deconstruction & removal of surface production equipment and restoration of the sites, cleanup of contamination (mostly compressor oil leaks under buildings and some small spills), disposal of waste (including historic drill cuttings and mud solids, contaminated gravel and soil, and used oil and glycol), required Mr. Jeremy M. Price 5/13/20 Page 2 surface use payments, transportation of salvaged equipment and waste, and associated expenses. If you have any questions or require additional information, please contact me at 713-899- 8103 or by email at jejones@aurorapower.com. Sincerely, �ZG 9!Edward Jones Operations Consultant for PLUGGING INLET, LLC 6733 South Yale Avenue Tulsa, OK 74136 CC: Suzanne Settle and Colleen Miller, CIRI Thomas Redman, Jim Sullivan, Mark Can, Plugging Inlet, LLC THE STATE "ALASKA May 1, 2020 GOVERNOR MICKNE•L I. DUNLEAFY J. Edward Jones Operations Consultant Plugging Inlet, LLC 6733 South Yale Avenue Tulsa, OK 74136 Re: Request for Information 20 AAC 25.300 Docket Number: OTH-20-035 Dear Mr. Jones: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.alaska.gov The Alaska Oil and Gas Conservation Commission (AOGCC) requests documentation of the actual costs incurred to plug and abandon the following wells: • ASPEN 1 —API 50-283-20114-00-00 • KALOA 2 — API 50-283-20107-00-00 • LONE CREEK 1 —API 50-283-20096-00-00 • LONE CREEK 3 —API 50-283-20112-00-00 • LONE CREEK 4—API 50-283-20121-00-00 • MOQUAWKIE 1 —API 50-283-10019-90-00 • MOQUAWKIE 4 — API 50-283-20120-00-00 • SIMPCO MOQUAWKIE 1 —API 50-283-20060-00-00 • SIMPCO MOQUAWKIE 2 —API 50-283-20062-00-00 The wells are located on mineral interests owned by Cook Inlet Regional, Inc (CIRI). In 2017, Plugging Inlet, LLC was designated operator of record for the wells. This request is made pursuant to 20 AAC 25.300. Should you have any questions about the information request, please contact Guy Schwartz at 907-793-1226. Sincerely, v Jeremy M. Price Chair, Commissioner cc: Suzanne Settle VP Energy, Land, Resources CIRI itCIRI January 14, 2020 James Regg, Senior Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West 71h Avenue, Suite 100 Anchorage, AK 99501 �T ons WrInVeColprwation RE: Onshore location clearance, Plugging Inlet Site located: T12 N R12W, T12N Ri1W, T11N R12W, T12N R11W SM Dear Mr. Regg: This letter is submitted to formally request that the Alaska Oil and Gas Conservation Commission (AOGCC) withhold the site clearance at the location formerly operated by Aurora Gas, LLC. Tyonek Native Corporation (TNC) and Cook Inlet Region, Inc. (CIRI) are the majority landowners within the area and did not have the opportunity to conduct an on-site inspection prior to the 2019 snowfall. CIRI and TNC will conduct an on-site inspection of the property in the spring to ensure the site is reclaimed to the satisfaction of both landowners. TNC and CIRI appreciate the AOGCC's continued cooperation during this process. If you have any questions, please contact Suzanne Settle at (907) 263-5150 or Connie Downing at (907) 272-0707. Sincerely, Tyonek Native Corporation 1 Connie J. Downing Chief Administrative Officer Cook Inlet Region, Inc. Suzanne Settle VP, Energy and Infrastructure Colombie, Jody J (CED) From: Regg, James B (CED) Sent: Monday, January 6, 2020 12:26 PM To: Colombie, Jody J (CED) Cc: Schwartz, Guy L (CED) Subject: FW: Site Clearance - Plugging Inlet See email from CIRI below. Looks like we received the 407s for these December 20 according to the 400 -Logs. Plugging Inlet dragged out the P&As so long this past fall that we were unable to get to locations for site clearance inspections before weather turned (actually had an Inspector and CIRI rep at the airport ready to fly over for site clearance inspections but flights were canceled for weather and there has been snow on the well sites since). Wells affected are: - Aspen #1 (PTD 2051110) - Kaloa #2 (PTD 2040960) - Lone Creek #1 (PTD 1980840) - Lone Creek #3 (PTD 2050970) - Lone Creek #4 (PTD 2070910) - Moquawkie #1 (PTD 2030690) - Moquawkie #3 (PTD 2050800) - Moquawkie #4 (PTD 2070840) - Simpco Moquawkie #1 (PTD 1780470) - Simpco Moquawkie #2 (PTD 1780880) Jim Regg Supervisor, Inspections AOGCC 333 W.7'^ Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907- 793-1236 or iim.reggPalaska.eov. From: Colleen Miller <cmiller@ciri.com> Sent: Monday, January 6, 2020 11:09 AM To: Regg, James B (CED) <jim.regg@alaska.gov> Cc: Connie Downing <cdowning@tyonek.com>; Suzanne Settle <SSettle@ciri.com>; David Kroto <dkroto@tyonek.com> Subject: Site Clearance - Plugging Inlet Good Morning Jim. I hope you had a great holiday! I'm writing to let you know that CIRI and Tyonek will be issuing a joint letter to request that the AOGCC withhold the site clearance on the Westside until CIRI and Tyonek have an opportunity to get boots on the ground in the spring. As always, please call me if you have any questions. Colleen 263-5117 The information contained in this CIRI email message may be privileged, confidential and protected from disclosure. If you are not an intended recipient, please notify the sender by reply email and delete the message and any attachments immediately. The use, disclosure, dissemination, distribution or reproduction of this CIRI message or the information in it or attached to it by any unintended recipient is unauthorized, strictly prohibited by the sender, and may be unlawful. Thank you. The information contained in this CIRI email message may be privileged, confidential and protected from disclosure. If you are not an intended recipient, please notify the sender by reply email and delete the message and any attachments immediately. The use, disclosure, dissemination, distribution or reproduction of this CIRI message or the information in it or attached to it by any unintended recipient is unauthorized, strictly prohibited by the sender, and may be unlawful. Thank you. 2 DLB (corrections) DLB 03/25/20 T12N T12N DSR-3/25/202 xG MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg �_ DATE: P. I. Supervisor ` L FROM: Lou Laubenstein SUBJECT: Petroleum Inspector 10/24/19 Surface Abandonment Aspen #1 Plugging Inlet LLC PTD 2051110; Sundry318-343 10/8/19: 1 arrived on location for the surface abandonment inspection on Aspen #1. 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_Aspen-1_11.docx Page 1 of 3 i � . C �tit� r ' f x���� e� ♦ p M �r } ,. � ,ff' Vit. pyo a tq • Y. z +' `•c ! x'SY'�gK�q���q.",Y i �4• t � as ey 'ai ♦ i i � �!/.�j ty. ,_� ,p r ♦ r /�}l I xr 2.• pi • ` /+'�krc �rsY qtr r> k'na • ter'+ `.�`,qa'' u1 �i '�� � '�.'"st g'ik. 1v Y f i�+' � ' •��'TY' s gg,,�� �„ ��1 v r r♦ , S '��yu, +, ~��•'�' r sic, r ! :�+r> i ,.,.� .y�$'i a. ;,„ ..�,..� . WK �, y�a r;rv. y( fN,�,•' �" R �r � � '�� x n n � r 3+ - i✓ � "��p+Y x i� x >4irh -'� C r"�a i ••4i° � a iy�: • ,+ 4 � �• rr aY� 4�'��r�x',�tr •, �,�. ft��,L ��� MEMORANDUM TO: Jim Regg�� P.I. Supervisor I FROM: Bob Noble Petroleum Inspector State of Alaska Alaska Oil and Gas Conservation Commission DATE: Tuesday, May 21, 2019 SUBJECT: Mechanical Integrity Tests PLUGGING INLET, LLC ASPEN 1 Src: Inspector Reviewed By: P.I. Supry ` r NON -CONFIDENTIAL Comm Well Name ASPEN I API Well Number 50-283-20114-00-00 Inspector Name: Bob Noble Permit Number: 205-111-0 Inspection Date: 5/18/2019 Insp Num: mitRCN190519102410 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well 1 !Type Inj N 'ITVD 2010Tubing o 1900 1s50 1825 -- PTD zosnlo "!Type Test SPT Test psi 1500 IA o zo 9 9 BBL Pumped: 02 IBBL Returned: 0.2 - OA o 0 0 0 ' Interval OTHER p/ Pte/ Notes: MIT -T for injection approval, DIO 32.004 ✓ 1 �S�C,lub-I— a�ac6te� Tuesday, May 21, 2019 Page I of I THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL DISPOSAL INJECTION ORDER NO. 32.004 Mr. George Pollock Consultant to Plugging Inlet, LLC PO Box 90571 Anchorage, AK 99509 Re: Docket Number: DIO-19-001 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 v .aogcc.alaska.gov Request for administrative approval to allow limited duration commercial disposal operations in well Aspen No. 1 (PTD 2051110) to dispose of wastes associated with the bankruptcy of Aurora Gas, LLC (Aurora) and requirements to P&A legacy Aurora wells. Aspen Field operated by Plugging Inlet, LLC Aspen Undefined Waste Disposal Pool Dear Mr. Pollock: By email dated April 23, 2019, Plugging Inlet, LLC (Plugging Inlet), as operator of the Aspen field since August 13, 2018, requested administrative approval (AA) for an extension of the previously issued and now expired DIO 32.003 which authorized limited duration, commercial disposal, water only injection in the Aspen No. 1 (Aspen 1) well. In accordance with Rule 8 of Disposal Injection Order (DIO) 32.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS Plugging Inlet's request for limited duration, restricted commercial disposal, water only injection in the subject well. On September 20, 2018, AOGCC determined that water disposal could safely continue if Aurora complied with the restrictive conditions set out in AA AIO 32.003. Aurora had reported a potential Inner Annulus (IA) x Outer Annulus (OA) pressure communication to AOGCC when the well had an inconclusive Mechanical Integrity Test of the Inner Annulus (MITIA) on May 30, 2014. A follow up state witnessed MITIA failed on July 28, 2014 as the IA demonstrated a higher than permissible pressure drop off during the test. The IA leak is thought to be in the upper perforations that previously had been squeezed with cement between 1368 to 1388 ft. The OA is cemented to approximately 220 ft from surface, well within the 9 5/8" casing set at 693 ft. The 9 5/8" casing was cemented to surface with good returns observed. Testing and diagnostics indicate that during normal injection operations the tubing is isolated from the IA and injected fluid is not entering the previously squeezed perforations and is therefore not out of zone. Aurora has not repaired the well. AIO AA 32.003 required Plugging Inlet to complete a MIT tubing (MITT) test and the last passing state -witnessed MITT was completed on October 14, 2018. This passing MITT demonstrates that its overall integrity remains intact and does not threaten human safety or the environment. On December 12, 2018 (Docket Number: OTH-18-033), AOGCC approved an extension to October 1, 2019 to plug and abandon (P&A) Plugging Inlet operated wells associated with the DIO 32.004 May 1, 2019 Page 2 of 3 Aurora bankruptcy. AOGCC finds that disposal of these P&A wastes is best accomplished by restricted limited duration disposal operations in the Aspen 1 well. Pre -bankruptcy Aurora wells Three Mile Creek 1, 2 and 3 (now operated by Cook Inlet Energy, LLC (CIE)) P&A wastes are authorized. Wastes associated with the Aurora bankruptcy Nicholai Creek wells and tank 129 contents have already been disposed of into Aspen 1 - and so no ongoing Nicholai Creek (operated by Amarok Resources, LLC) wastes are permitted. The multiple operators now associated with various well P&A operations, ongoing production operations, various working interests and close personnel ties within the various operating companies, increases the risk that an unauthorized waste could enter the Aspen 1 disposal waste stream. Procedures, training, reporting, monitoring, and additional conditions must be implemented to ensure only the fluids authorized are injected for disposal. AOGCC hereby grants Plugging Inlet restrictive limited duration approval for disposal in Aspen L AOGCC's approval to continue water injection only (produced water, brine, P&A associated fluids, and cement rinsate) is conditioned upon the following: 1. Plugging Inlet shall record wellhead pressures and injection rate daily; 2. Plugging Inlet shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. Plugging Inlet shall limit the well's IA operating pressure to as low as possible, not to exceed 100 psi; 4. Plugging Inlet shall implement logic to shut down the Aspen No. 1 positive displacement pump at the IA set point of 100 psi, and shall install a red strobe light to visually indicate when this condition occurs; 5. Plugging Inlet shall train personnel on the requirements of the 100 psi IA limitation including the requirement to manually shut down any triplex pumping operation on any indication that the IA pressure has exceeded 100 psi, including activation of the red strobe light; 6. Plugging Inlet shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 7. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; 8. Limited commercial Class II oil field waste disposal is approved. Commercial (third party non -Plugging Inlet generated) Class II oil field waste disposal shall be in compliance with all rules of DIO 32 and associated DIO 32 Administrative Approvals. Only waste fluids associated with the bankruptcy of Aurora (requirements to P&A legacy Aurora wells operated by Plugging Inlet, LLC (Aspen 1, Lone Creek 1, 3 and 4, Kaloa 2, Moquawkie 1, 3, and 4, Simpco Moquawkie 1 and 2) and operated by CIE (Three Mile Creek 1, 2, and 3 wells)) are authorized. No wastes from Nicolai Creek wells operated by Amarok Resources, LLC are authorized; 9. Plugging Inlet shall train personnel (or verify training is current) prior to restarting Aspen 1 operations. Training shall include the requirements for manifesting and correct volume accounting of wastes; 10. Commercial disposal injection details shall be provided to AOGCC in a performance report required within one month of the final P&A. The performance report shall also include: a) an overview of commercial activities for the period; b) a list, based on manifests, naming each company generating waste which was injected, identification of the well or pad where the waste was generated, type of waste, volume, D10 32.004 May 1, 2019 Page 3 of 3 transport company and driver, signature and name of Plugging Inlet person with authority confirming waste as Class II; c) a list of the operators for which Plugging Inlet will be performing disposal and the source of the fluids provided by each such operator has a commercial disposal agreement with; d) a list of operators that Plugging Inlet has a Road Use Agreement (RUA) with; e) a list of Plugging Inlet contractors and employees who have completed the Plugging Inlet commercial Class II training and are authorized to accept waste; f) a review of the Plugging Inlet Waste Analysis Plan (WAP) and any changes to the plan; g) a review of the External Manifest procedures including any changes to the process; and h) a review of the pre -call and approval policy that is designed to ensure the facility is ready and able to accept and process the commercial waste. 11. This administrative approval shall expire whichever occurs first: a. October 1, 2019; b. Aspen I is Plugged and Abandoned; or c. the operator changes for the Aspen 1 well. DONE at Anchorage, Alaska and dated May 1, 2019. 42455� Daniel T. S amount, Jr. Jessie L. Chmielowski Commissioner Commissioner cc: Jim Sullivan Plugging Inlet, LLC 6733 South Yale Avenue Tulsa, OK 74136 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or 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 of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Wallace, Chris D (DOA) From: George Pollock <gpollock@aurorapower.com> Sent: Wednesday, May 1, 2019 7:34 AM To: Wallace, Chris D (DOA) Cc: Colleen Miller; Ed Jones Subject: RE: Extension Request - Administrative Approval DIO 32.003 Chris, OOI DIO 32.003 was written to allow all legacy Class II fluids generated by the former Aurora Gas to be injected. The table in 32.003 identified 2,236 barrels of produced water. The Fluid Transfer Tracking system utilized last year indicated that a total of 2,660 barrels of Class II fluids were transferred to Aspen for injection. At the close of site activity last fall, all produced water associated with the legacy Aurora Gas production facilities had been transferred to Aspen and injected. Nicolai Creek 129 produced water tank on the pad on which the NC1, NC2 and NC9 are located. The Nicolai Creek wells (which include: NC1, NC2, NC3, NC9, NC10 & NC11) are currently operated by Amaroq Resources. Produced fluids from these are not associated with legacy Aurora Gas activity. The Three Mile Creek wells, which include TMC1, TMC2 & TMC3, have not been operational since Aurora Gas ceased. Glacier Oil & Gas (Glacier) is the responsible party to P&A these three wells. It is requested that the proposed D1032.004 allow the injection of Class II fluids generated in the P&A of these wells at the Aspen Facility. The remaining legacy Aurora Gas wells to be cemented this year, consisting of the Lone Creek til, 2 & 3 and the Aspen well, and the completion of the P&A on all wells for which Plugging Inlet is responsible, will be completed by October 1, 2019. It is requested that D1032.004 allow the injection of Class II fluids generated in the P&A of these wells at the Aspen Facility. I trust I have addressed your questions. Let me know if I can provide additional information regarding this request. Respectfully, George Pollock From: Wallace, Chris D (DOA)[mailto:chris.wallace@alaska.gov] Sent: Wednesday, April 24, 2019 9:46 AM To: George Pollock Cc: Colleen Miller; Ed ]ones Subject: RE: Extension Request - Administrative Approval DIO 32.003 George, Reviewing 32.003 and the AOGCC extension for Plugging Inlet operated wells (dated December 12, 2018 extending P&A to October 1, 2019) 1 see that 32.003 included fluids from wells Nicholai Creek 10, 11, 129, and Three Mile Creek 2. Should 32.004 (Aspen 1 disposal time extension) include fluids from Nicholai Creek 10 (844 bbl), 11 (29 bbl), 129 (301 bbl) and Three Mile Creek 2 (12 bbl)? I cannot find well 129 - so maybe that was a typo but the original application had 301 bbl associated with Nicholai Creek 129? Please let me know the current status on the Nicholai Creek and Three Mile wells, and their bankruptcy associated legacy tank volumes. The disposal in Aspen 1, and the possible extension of time for disposal into Aspen 1, is strictly related to the P&A activities and cleanup of the Aurora wells cleanup and bankruptcy. In every way the order should not be construed as allowing Aspen 1 disposal for ongoing production operations of either Glacier or Amaroq. If there is any intent in keeping Aspen 1 operational after the planned P&A by October 1", 2019 it should be forecasted to AOGCC prior to this extension being considered as it is obviously AOGCC understanding that the P&A's and closing of Aspen 1 by October 1, 2019. Thanks and Regards, Chris Wallace, Sr. Petroleum Engineer, Alaska Oil and Gas Conservation Commission, 333 West 7" Avenue, Anchorage, AK 99501, (907) 793-1250 (phone), (907) 276-7542 (fax), chris.wallaceCdalaska.eov 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 Chris Wallace of 907-793-1250 or chris.wallace@alaska.aov. From: George Pollock <gpollock@aurorapower.com> Sent: Tuesday, April 23, 2019 7:39 AM To: Wallace, Chris D (DOA) <chris.waIlace @alaska.gov> Cc: Colleen Miller <cmiller@ciri.com>; Ed Jones <jejones@aurorapower.com> Subject: Extension Request - Administrative Approval DID 32.003 Chris, Plugging Inlet, LLC (PI) formally requests an extension of the Administrative Approval Disposal Injection Order No. 32.003 dated September 20, 2018. PI worked diligently during the late fall/early winter of 2018 to cement six (6) of the ten (10) legacy Aurora Gas, LLC wells required to be plugged & abandoned (P&A). Due to several factors including, health & safety factors, concerns of the local community and the landowner, AOGCC issued an extension for the P&A of the wells until October 1, 2019. Currently, the Aspen injection well is shut-in after injection activities ceased in November 2018. There has been no change in the mechanical of the Aspen well. Injection operations conducted during 2018 were performed in accordance with the conditions of approval presented in D1032.003. A copy of the 2018 Aspen Field Book will be provided. Proposed 2019 Aspen operations will be conducted in accordance with the conditions of approval in D1032.003, inclusive of any additional requirements. Let me know if you require any further information. Regards, George Pollock Consultant 907.351.8286 Wallace, Chris D (DOA) From: George Pollock <gpollock@aurorapower.com> Sent: Tuesday, April 23, 2019 7:39 AM To: Wallace, Chris D (DOA) Cc: Colleen Miller, Ed Jones Subject: Extension Request - Administrative Approval DIO 32.003 Chris, Plugging Inlet, LLC (PI) formally requests an extension of the Administrative Approval Disposal Injection Order No. 32.003 dated September 20, 2018. PI worked diligently during the late fall/early winter of 2018 to cement six (6) of the ten (10) legacy Aurora Gas, LLC wells required to be plugged & abandoned (P&A). Due to several factors including, health & safety factors, concerns of the local community and the landowner, AOGCC issued an extension for the P&A of the wells until October 1, 2019. Currently, the Aspen injection well is shut-in after injection activities ceased in November 2018. There has been no change in the mechanical of the Aspen well. Injection operations conducted during 2018 were performed in accordance with the conditions of approval presented in D1032.003. A copy of the 2018 Aspen Field Book will be provided. Proposed 2019 Aspen operations will be conducted in accordance with the conditions of approval in D1032.003, inclusive of any additional requirements. Let me know if you require any further information. Regards, George Pollock Consultant 907.351.8286 THE STATE ALASKA GocieNOH MitiF DcNFF�� v December 12, 2018 George Pollock Consultant to Plugging Inlet, LLC. PO Box 90571 Anchorage, AK 99509 Re: Docket Number: OTH-18-033 Notice of Violation Failure to plug and abandon wells Aspen 1 (WDSPL) (PTD 205-111) Simpco Moquawkie 1 (PTD 178-047) Simpco Moquawkie 2 (PTD 178-088) Lone Creek I (PTD 198-084) Lone Creek 3 (PTD 205-097) Lone Creek 4 (PTD 207-091) Moquawkie 1 (PTD 203-069) Kaloa 2 (PTD 204-096) Moquawkie 3 (PTD 205-080) Moquawkie 4 (PTD 207-084) Dear Mr. Pollock: Alaska Oil and Gas Conservation Commission 533 w=5� $e P, P."n" snc:hc109e 4r;.0 995013572 fnain 907_,79.:433 Fpa 9('7 776 AOGCC has reviewed your request for an extension of time to plug and abandon the above wells. Your request is GRANTED. Plugging Inlet, LLC. shall have until October 1, 2019 to complete the work. AOGCC reserves the right to pursue an enforcement action in connection with the failure to properly plug and abandon the wells. Sincerely, Hollis S. French Chair, Commissioner cc: Tom Redman President Plugging Inlet, LLC. 6733 South Yale Avenue Tulsa, OK 74136 Docket Number: OTH-I8-033 December 12, 2018 Page 2 of 2 TION As provided in AS 31.05.080(a). within 20 days after written notice of the entry of this order or 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 of the matter determined by it. If the notice was mailed, then the period of time shall be 23 dans. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days afler it is filed. Failure to act on it within l0 -days is a denial of reconsideration. If the AOGCC denies reconsideration.. upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails. OR 30 days if the AOGCC otherwise distributes. the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be riled within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration. this order or decision does not become final. Rather. the order or decision on reconsideration will be the FINAL order or decision of the AOGCC. and it may he appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails. OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration, In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period: the last day of the period is included, unless it falls on a weekend or state holiday. in which event the Mind runs until 5 -nn � m — k. ,,,....�_. __ _ 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 gov). 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 sljckline 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 1—PTD-198-084: Closed sleeves on 11/3/18 and set CIBP in tubing at 1780'. On 11/16/18, pretested tubing an IA, and pumped 15 bbl down OA at 1 BPM. On 11/18/18, tested tubing to 1780 psi and IA to 1700 psi (witnessed). Opened sleeve at 1745'. Prepared to cement as per approved procedure in Sundry, except will likely use light -weight cement to fill IA instead of viscous spacer. Lone Creek 3—PTD 205-097: 11/2-11/5/18 closed all sliding sleeves in the well (PX plug in bottom packer at 2841' from previous operations, so tubing is closed to all perforations). On 11/17/18, tubing and IA were pressure tested (witnessed), tubing tested to 2080 psi and IA to 1500 but dropped to 1225 in 30 minutes—packer leak is suspected. Revised procedure was submitted to AOGCC to add a second plug below top packer on 11/26/18, which was approved on 12/11/18. Lone Creek 4—PTD-207-084: All sleeves are closed and there is a PX plug from earlier operations at 2057'. On 11/17, the tubing and IA were tested (witnessed) to 2200 and 2100 psi, respectively. The tubing was perforated above and below the top packer at 1078-81' and 978-81' in preparation to cement as per procedure. The plan forward is to mobilize in late April or early May depending upon the Schlumberger cementers availability, barging access, and road conditions. At that time, the 3 Lone Creek wells will be submitted as per procedures (approved revised procedure of #3 and an additional 35 bbl of light -weight cement will be pumped in the Lone Creek 1 instead of viscous spacer), which should take 7-10 days, including West Side mobilization and set up. The Wach saw will be mobilized at about that time, the well heads removed and the casing cut off, any top -off of cement will be done, steel plates welded on, and the cellars backfilled. Please let me know if you need additional information. Thanks, Ed J. Edward Jones Petroleum Consultant 4645 Sweetwater Blvd., Suite 200 Sugar Land, TX 77479 713-899-8103(C) 281-495-9957, ext 201 (0) 832-999-4382 (F) From: Schwartz, Guy L (DOA) [mailto:guy.schwartz@alaska.gov] Sent: Monday, March 04, 2019 1:30 PM To: Ed Jones <jeiones@aurorapower com> Cc: George Pollock <gpollock@aurorapower.com> Subject: CIRI P & A well status Ed/George, I never received a final update on the work that was done on these CIRI wells .. last update was in first week of November. I recall you requested a temporary shutdown of operations until spring to finish the wellhead cutoffs. don't have an email or any documentation that I can find for this request. You are requested to provide an update on each of the wells current status and detail your plan to return and finish the P & A wellwork. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission )AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal low. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending if to you, contact Guy Schwartz at )907-793-1226 ) or )Guy schwartz@alaska qov). OF 77i, S S w\ Iyj ,v THE STATE Alaska Oil and Gas ALAS/ Conservation Commission i� sKA _,,,- _ S t 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 �' iM;, Main: 907.279.1433 "ALAS'. Fax: 907.276.7542 www.aogcc.alaska.gov George Pollock Manager—Production, Operations, and Engineering Aurora Gas, LLC 1400 W. Benson Blvd., Ste. 410 Anchorage,AK 99503 SCANNED SS' 2 7 2017 Re: Undefined Field, Undefined WDSP Pool,Aspen 1 Permit to Drill Number: 205-111 Sundry Number: 317-432 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, &AD—CZ Hollis S. French Chair DATED this 9' day of September, 2017. RBDMS L'-SES' 2 5 2017 • RECEIVED ' t • • SEP 142017 STATE OF ALASKA A'1 I ,-7 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION A FOR S .' ., 'y APPROVALS 20 AAC 25.280 1.Type of Request: Abandon I ' Plug Perforations❑'. . Fracture Stimulate ❑ Repair Weil ❑ Operations shutdown Suspend ❑ Perforate ❑ Other Stimulate ® Pull Tubing ❑ Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool Q Re-enter Susp Well ❑ Alter Casing ❑ Other.Temporary Plug ❑ 2.Operator Name: A.Current Well Class: :5.Permit to Drill Number Aurora Gas,LLC' Exploratory ❑ Development ❑ 205-111 r 3.Address: 1400 W.Benson Blvd.Suite 410 Stsatkrapfac ❑ SeritMe ❑•,6.API Number Anchorage,AK 99503 50-283-20114-00 ' 7_If perforating:. .Well Name and Number What Regulation or Conservation Order governs well spacing in this pool? N P- Aspen#1 A Will planned perforations requirea spacing exception? Yes ❑ No AL., 9.Property Designation(Lease Number): 10.Field/Pool(s): C-061663 / FU- Undefined LPJ ,y' ? 11. PRESENT WELL CONDllON SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP{psi): Plugs(MD): Junk(MD): 4485' ' 4485' • 2891' • 2891' • 1200 psi 2891' None Casing Length Size MD TVD Burst Collapse Structural Conductor 83' 13 3/8"548 J55 83° 83' 2730 psi 1130 psi Surface 693' 95/8"368 J55 693' 693' 3520 psi 2020 psi Intermediate Production 4484' 51/2"15.58 J55 4484' 4484° 4910 psi 4040 psi Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tearing i Grade: Tubing MD(It): 2125'-2371' - 2125'-2371' 2 718" 6.5#J55 2010' Packers and SSSV Type: Packers and SSSV MD(ft)and ND(its Retrievable packer Retrievable a 2010' . 12.Attachments: Proposal Summary 0 Wellbore schematic [A 13.Well Class after proposed work: Detailed Operations Program C BOP Sketch ❑ Exploratory ❑ Stratigra oic ❑ Development❑ Service Q , 14.Estimated Date for TBD 15.Well Status after proposed work: Commencing Operations: Q ❑ WINJ ❑ WDSPL ❑ Suspended 16.Verbal Approval: Date: GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ CommissionRepresentative: GYRI ❑ Op rutdovert ❑ Abandoned E. 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: George Pollock George Name: Geatge Pollock Authorized Title: Manager-Pr &Eng Contact Email: QOollockaaurorapower.com Contact Phone: 907-351-8286 Authorized Signature: ..0.------ Date: 14-Sep-17 COMMISSION;USE Y Conditions of approval: Notify Commission so that a representative may witness Sundry Number 31,1-4132 Plug Integrity fr4 BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance Other: ,y Post Initial injection MIT Req'd? Yes ❑ No El Spacing Exception Required? Yes [-LiNoof Subsequent Form Required: `, __4O RBDMS 1 J L J f i7 APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: 1 I i c1 i 1 l 1 ?la 114p- 4 r r NA ei 1 t 1 I f, submit Fexm and v AA1 Form 10-403 Rev412017 iva et for 12 from the date ap avat, e o� ,t J L • • • • AURORA GAS, LLC WELL ABANDONMENT ASPEN #1 WDW September 2017 Version 1.0(9/1317) CURRENT cONDrroi : Max Tbg Pressure-1150 psi (probably much less due to inactivity) KB=14.5 feet CASING: 5-1/2", 15.5#J-55 set at 4484'MD/TVD. Cement Retainer set at 2995' w/ 10 sx cement. PBTD=2891' w/junk CIBP on it, est. at 2881'. TUBING: 2-7/8",6.5#J-55.8 rd-EUE, w/8.9 Wig.inhibited KCI-NaCI brine as packer fluid in tbg-csg annulus above;top packer and with: Sliding Sleeves: None On-Off Tool above Packer at+/-2004' 2.31"X profile Landing Nipple: XN at+/-+/-2030' with 2.812"profile and 2.205" no-go. Packer: Arrowset mechanical at 2010' (See attached well bore and completion diagrams) CAPACITIES: 2-7/8" 6.5# Tubing: 0.00579 bbl/lit; Tubing-Casing Annulus: 0.0158.BPF; 5-1/2", 15.5# Casing: 0.0238 bbl/ft. Tubing volume to packer=11.6 bbl,Annular Volume to top Packer= 31.8 bbl; Volume to deepest perfs: 20 bbl. OPEN PERFS: Beluga Tsuga 2-4: 2125-2145', 2351-2371, Below cement retainer at 2955' Beluga Tsuga 2-5 at 2984-2994', 3006-3026' Beluga Tsuga 2-6 at 3444-3454', 3491-3506', 3811-3831' NOTES: 1) Well is a straight hole. SUMMARY OF PLAN: If a temporary plug has been set (which one has not as of 9/13/17, as additional use is expected for abandonment of other CIRI wells), RU slickline, RIH and pull prong and plug at 2005'. it/H with tubing perf gun,perforate the tubing at about 2000',and dump 8.9 ppg inhibited KI-NaCl brine into tubing to kill well,. Run gauge ring and tag fluid level and NG at+/- 2030'—brush or otherwise clean up to get CIBP down to 2010'. Run CIBP for 2-7/8"tubing and set in top of top packer at 2010'. RU cementers on tree (thru wing valve). Establish circulation pressure with 5-10 bbl KCl water at 3 BPM. Pump 220 sx (253 cf=45.1 bbl) Class G cement(15.8 ppg, 1.15 cf/sk yield) with pump time of 4 hr at 75 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 fad back. Wash out tubing casing annulusto 3-4' below GL. WOC 8 brs,pressure=test to 1500 psi. Bleed Off pressure. MI crane. Remove tree. 'Cut cuff casing strings and tubing 3-4' below(IL. 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. Gra&location. Take soil samples for confirmation of no contaminants. PROCEDURE: 1) Disconnect and remove (skid) conex wellhouse from over well. Notify AOGCC inspector of plans ✓ for plugging operations 2) Move in cementer .b, p tuck/mixer),bulk cant (250 sx Class G),slicklineleleic line combo unit,water tank with 100 bbl fresh water for cementing and open"cuttings"tank for returns. RU cement pump to tree through wing valve. Pump away (inject) any and all produced or wellbore fluids from previous well pluggings. 3) RU wireline lubricator on tree. Open well and check lubricator and tree for leaks. 4) PU and run 1-3/4" (+7-)tubing perforating gun and perf the tubing with 4 JPF at 2000'. Dump 8.9 ppg KCl-NaCl packer fluid from annulus into tubing. Allow tubing to stabilize. 5) Run 2.25"gauge ring(GR)to check for fluid level and tag NG at+1-2030' If restrictions are found, run swage, brushes, etc. to cleanout (probably perfs)to about 2030' to set CIBP in tubing at 2010'. 6) PU CIBP for 2-7/8"tubing, RIH, and set at 2010'. Close casing valve and pressure up on tubing to 1000 psi to confirm that plug is holding—squeeze perfs in casing are known to leak-off, so 30- minute leak-off may occur,but deeper perfs would take measurable fluid at this pressure at '/2 - 1 BPM). Release pressure. 7) COMBINATION PLUG: With cement pumper on wing valve of•tree. Open casing valve(tubing- casing annulus) and pump 5-10 bbl through tubing perfs with fresh water down tubing and establish circulation and pressure at 3 BPM. (NOTE: this is the disposal well and will be the last one plugged, so we want as little left over fluids at possible). Mix and pump 220 sx Class G cement (accelerated for 4 hours pump time at 70 degress,15.8 ppg, 1.15 cf/sk yield) down tubing, circulating cement to surface (3% excess)through casing valve. This is to be a balanced plug— monitor for flow or fall back. 8) When cement tope is stable,disconnect cementer. Wash out tubing,and tubing-casing annulus to 3- 4' below GL. WOC 8 hours. Pressure test both sides(tubing and annulus)to 1500 psi. Release pressure. MI crane. Remove tree. Cut off conductor, surface, and production casing strings and tubing 3-4' below GL. Mix any cement needed to fill any casin sting or tubing to cut-off Release cementers and slickline units to next location. CAA/kr-Yr F"orz. µau 9) Fabricate 1/4" steel marker-plate cap for 9-5/8"conductor casing, not to extend beyond casing OD, 'A and bead-weld the following information onto marker plate; Aurora Gas, LLC )4 ()wart:, pcc. ►e -c was%%.3C & r oPF N -rnct.& PTI)## 205411-0 t-u toc,„ e 14.10 im 401 Aspen 41 API# 50-283-20114-00 10)Following any necessary inspections, remove cellar and bury marker. Dispose of any waste properly. Prepare to demob equipment 11)Remove tree and casing/tubing cut-offs, surface production equipment,trash,and any other materials from the location. Clean up,grade and level location. Take soil samples and send to lab to confirm no contamination. Ed Jones (9/13/2017) • • - 271863#SrdEUEd-55 Tubing t.:'`-4' .1 KB=145' qq Aurora Gas, LLC , ' , 13-3/8".54.54, -55 Structural , Aspen Na. 1 WDW GL o Kductor Bbe driven to 83' Current Configuration �' , September 2008 ., PTD#205-111-0 API#50-283-20444-00 9 5/8"36#Surface Casing set at 693' ' ": .." Cement w/50 bbls 14 ppg lead and 30 bbls 143 ppb Gass-Block"G"w/good FIT performed at returns observed at surface. 720', Had 14.8 ppg ' MWE test prior to breakdown. Annulus filled with 8.9 ppg inhibited , brine above top packer. Perforations: 1368'-1388' -.5 Resqueezed perfs at 1368-1388'w/ Squeezed Off "'"- 50 sx(13 bbls)Type I cement Iv/ additives on 8/26/08. Tested tbg-esg annulus several Perforations: 1760'-1770' a: tines subsequently'. Tested on Squeezed Off 8/29108 to 1500 psi—bled to 1450 in 30 min, Retrievable Packer set at 2010 ft w/ On-Off tool above and w112'spacer pups,XN landing nipple and WEG on tubing tail. Perforations: _;+� I 2125'-2145' '� 2351'-2371' +_ �-- 10 sx balanced cement plug placed on top of retainer—TOC at 2891'. PBTD now at 2881'(CHIP f/1779' pushed down to there) Retainer set at 2955' Perforations: 2984'-2994' a Perforations: 3006'-3026' -�_ Perforations: 3444'-3454' -:.N. Perforations: 3491'-3506' 1111 :--"" Perforations:3811'-3831' . s PBTD 4355' 5 34"15.5#3-55 Casing to 4484'MD(TVD) Drilled 7 5/8"Hole to 4485' 40.6 bbls 13.5 ppg lead cmt and 136 bbls 15.8 ppg tail cement. 0 0 — 2 7/8 65#8rd EUE J-55 Tubing d F s D F * KB=14 5' 1 Aurora Gas, LLC "`" .�," . . *. , g ,''" "" .":- . ,g13-318".545#,J-55 Structural • 9 • * ,t$ a'�' ' 4 Conductor to be driven to 83' Aspen No. 1 WDW `' "' ' ' +- GLor97 KB Proposed P&A , * .. ° ' Configuration + I t t ` ,�� 4 5/8„,36#Surface Casing set at 693' September 2017 . `t :` Cement w/50 bbls 14 ppg lead and 30 PTD#205-111-0 ,* . I ” ! *, ,r + bbls 145 ppg Gas-Block"G"w/good API#50-283-20444-00 ..' ' �.° ' Ix ',, ¢ ,, returns observed at surface. ' Set CEEIP in tubing at 2010'. FIT performed at 720', Had " "" Perf tubing at 2000'. Pump 220 14.8 ppg MWE test prior to breakdown. sx G cement to fill tubing and annulus from surface to 2010' Annulus filled with 8.9 ppg t 1 Yt Combinationfor Plug: Surface, inhibited brine above top packer. Surface Casing Shoe,and Open Perfs. fi '-,c,, Ft, -Y'- Perforations: 1368'-1388' �-1, �� i 4 "* Resqueezed perfs at 1368-1388'wI Squeezed Off — s + ' v N 'r 50 sx(13 bbls)Type I cement w/ ,, : t.** k its hr '%` .1 additives on 8/26/08. K A t !:. % Tested tbg-csg annulus several Perforations: 1760'-1770' '" --* . times subsequently. Tested on Squeezed Off �;- '4 1 . 8/29/08 to 1500 psi—bled to 1450 "' . F Y in 30 min: � iii., Jx Retrievable Packer set at 2010 ft w/ ,+k On-Off tool above(2312"profile) V , `= •y of Tye • hw1:1yy„ s THE STATE Alaska Oil and Gas tv ►: . � „fALAsKA Conservation Commissionjtisitt - - 333 West Seventh Avenue 1 w, GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 OF ALAS"' MFax: 907.276.7542 www.aogcc.alaska.gov George Pollock %AHMED jUL JUL2 62017. Manager Aurora Gas, LLC 1400 W. Benson Blvd., Suite 410 Anchorage, AK 99503 Re: Undefined Field, Undefined Pool, Aspen 1 Permit to Drill Number: 205-111 Sundry Number: 317-268 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, 1XCC Hollis S. French Chair DATED this day of July, 2017. RBDMS L - JUL 1 1 2017 S 0 R EC:E IV ED STATE OF ALASKA JUN 1 6 2017 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS AOGGO 20 AAC 25280 1.Type of Request: Abandon 0 Plug Perforations 0 Fracture Stimulate ci Repair Well 0 Operations shutdown El Suspend 0 Perforate lil Other Stimulate El Pull'tubing El Change Approved Program El Plug for Redrill 0 Perforate New Pool El Re-enter Susp Well 0 Alter Casing 0 Other.Temporary Plug EI• 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number Aurora Gas,LLC Exploratory El Development llil 205-111 • 3.Address: 1400 W.Benson Blvd.Suite 410 D El 6.API Number Stratigraphic Service Anchorage,AK 99503 50-283-20114-00 • 7. If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Aspen#1 • Will planned perforations require a spacing exception? Yes 0 No 0 9.Property Designation(Lease Number): 10.Field/Pool(s): G:954454S— e-ex-,-/ ,41,' ZC'17 Undefined I ' 1 -. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth ND(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): 4485' . 4485'' 2891' ' 2891' • 1200 psi 2891' None Casing Length Size MD TVD Burst Collapse Structural Conductor 83' 13 3/8"54#J55 83' 83' 2730 psi 1130 psi Surface 693' 95/8"36*J55 693' 693' 3520 psi 2020 psi Intermediate Production 4484' 5 1/2"15.5#J55 4484' 4484' 4910 psi 4040 psi Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing kfID(ft): 2125'-2371' 2125'-2371' 27/8" 6.5#J55 2010' Packers and SSSV Type: Packers and SSSV MD(ft)and ND(ft): Retrievable packer Retrievable©2010' 12.Attachments: Proposal Summary El Wellbore schematic 0 13.Well Class after proposed work: -1.c.g/ Detailed Operations Program D BOP Sketch 0 Exploratory El Stratigraphic li Development* Service 14.Estimated Date for TBD 15.Well Status after proposed work: Commencing Operations: OIL 0 WINJ D WDSPL27A)'17 Suspended 111 1 16.Verbal Approval: Date: GAS •:,. ,-• WAG 0 GSTOR D SPLUG 0 Commission Representative: h , -4:'LIGINJ 0 Op Shutdown El Abandoned 0 I• 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: Manag-A00-••rod 0, &Eng Contact Email: Clloallockaaurorapower.com Contact Phone: 907-277-1003 ,-,—/ ---,------ Authorized Signature: Date: 16-Jun-17 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number Plug Integrity 0 BOP Test LI Mechanical Integrity Test D Location Clearance D Other: )/•• Reth.42.0,A0-31-C cetZ. Post Initial Injection MIT Req'd? Yes 0 No D RBDMS 1- ,-- JUL 1 1 2017 Spacing Exception Required? Yes 0 No [?I Subsequent Form Required: ‘0 —AO 4 ad2apz._,.* APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Clia t•-kai‘-1(1 n Submit Form and FoarnA-43 Revised 4/2017 1L) Rrin.erip4As6lid for 12 months from the date of approval. Attachments in Duplicate 1;i „f---76-a7 ...--_, 7 c-7/7 • Aumra GLLC June 16, 2017 Ms. Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 JUNoaf 4 A/M Re: Application for Sundry Approval—Set Temporary Plug �r�, Aspen#1 Well 0 PTD#: 205-111 API #: 50-283-20114-00 Dear Ms. Foerster: Aurora Gas, LLC hereby requests approval to set a temporary plug to secure this onshore Class II UIC injection well on the west side of Cook Inlet, southwest of the Village of Tyonek. This well is currently operational for the injection of produced water 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 2,010' above all open perforated intervals to mechanically isolate the reservoir. After the plug is set, tubing pressure will be monitored for 30 minutes to ensure isolation. The master valve will be closed providing double isolation and the wellhead secured. A follow up pressure reading will be obtained after 24 hours to ensure the integrity of the plug. Please find the attached information as required by 20 AAC 25.110 for your review: • Form 10-403 Sundry Application • Current wellbore diagram illustrating the current well configuration. • Slickline Temporary Plug Set—Generalized Procedure If you have any questions or require any further information,please contact me at (907) 277-1003. 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 • • 2 7/8 6.5#8rd EIDE.1-55 Tubing * r r 0n,'- ''s°, `k; 11,,.. 1.N.' ya.. '+v .f;* ./." < ....«,,_ *5'k'�*4 #.:. Aurora Gas, LLC `*E .s (_ 13-3/8".545#,J-55 Structural i �, . f Y . ' Conductor to be driven to 83' Aspen No. 1 A_ GL or 97'KB Water Disposal Well ."4 Final Configuration API#50-283-20114-00 pry,' +>" PTD#205-111 ` ' '. Y,1 RKB-14.6' . , Sept.2008 ' % .'ik 9 5/8"36#Surface Casing set at 693' w +,. , Cement w/50 bbls 14 ppg lead and 30 bbls 145 ppg Gas-Block"G"w/good FIT performed at returns observed at surface. 720', Had 14.8 ppg • - MWE test prior to breakdown. ' *▪ . -s Resqueezed perfs at 1368-1388'w/ -- 50 sx(13 bbls)Type I cement w/ Perforations: 1368'-1388' -44.4.-_,H additives on 8/26/08. Squeezed Off Tested tbg-csg annulus several t . t t%— times subsequently. Tested on Perforations: 1760'-1770' +,--1 k,--. — 8/29/08 to 1500 psi—bled to 1450 Squeezed Off ° in 30 min, .* .4 Retrievable Packer set at 2010 ft w/ On-Off tool above and w/12'spacer ,` 1 "` pups,XN landing nipple and WEG on tubing tail. Perforations: 2125'-2145' 11 Perforations: 2351'-2371' ! !� `` 10 sx balanced cement plug placed ' 9,x' ,*0,'`' on top of retainer—TOC at 2891'. '' '�' PBTD now at 2881'(C1BP f/1.779' ie t" 31 pushed down to there) * 4Po1�- i 4011_. Retainer set at 2955' Perforations: 2984'-2994' _�, Perforations: 3006'-3026' ▪1111-'•'! 0 # , . 1 Perforations: 3444'-3454' j_, Perforations: 3491'-3506' ' t"' Perforations:3811'-3831' -"4"l • A PBTD 4355' A h 5%2"15.5#J-55 Casing to 4484'MD(TVD) Drilled 7 5/8"Hole to 4485' -- 40.6 bbls 135 ppg lead cmt and 136 bbls 15.8 ppg tail cement. • 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 'A"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. 4 Ie Saua9e(6/11/2017) • • MEMORANDUM O NDUM Stat e of Alaska Alaska Oil and Gas Conservation Commission TO Jim Regg DATE: Wednesday,October 12,2016 P.I.Supervisor ,Sega 10(14 i,( SUBJECT: Mechanical Integrity Tests AURORA GAS LLC 1 FROM: Lou Grimaldi ASPEN 1 Petroleum Inspector Src: Inspector Reviewed By: P.I.Supry ] NON-CONFIDENTIAL Comm Well Name ASPEN 1 • API Well Number 50-283-20114-00-00 Inspector Name: Lou Grimaldi Permit Number: 205-111-0 Inspection Date: 9/29/2016 Insp Num: mitLG161004072807 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well 1 Type Inj W TVD 2010 - Tubing 380 1735 1720 ' 1715 - _ Type PTD 2051110 Test SPT Test psi 1700 - IA o 0 0 0 Interval REQVAR P/F P ✓ OA o 0 0 0 Notes: Tubing test for compliance with variance DIO 32.002.Cat 2 standing valve reportedly set in tubing tail prior to my arrival.<10 gallons pumped,pressure left on tubing. NEED APR 2 1 H117 Wednesday,October 12,2016 Page 1 of 1 • MEMORANDUM • State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg l 3l 15 DATE: Thursday,October 15,2015 P.I.Supervisor ` SUBJECT: Mechanical Integrity Tests AURORA GAS LLC 1 FROM: Matt Herrera ASPEN 1 Petroleum Inspector Src: Inspector Reviewed By: P.I.Supry NON-CONFIDENTIAL Comm Well Name ASPEN I API Well Number 50-283-20114-00-00 Inspector Name: Matt Herrera Permit Number: 205-111-0 Inspection Date: 9/27/2015 Insp Num: mitMFH150930064817 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min ITVD 2010 • Tbi610 610 • 610 1 610 • 610 - Well 1 Type Inj N un g PTD 2051110 - Type Test SPT Nest psi 1500 - IA 0 . 1660 - 1450 . 1270 . 1165 Interval'OTHER P/F F i OA 0 - 0 0 0 0 Notes: DIO 32.002.This is a retest to verify results from a previous test performed an hour earlier same date.IA was bled to 0 psi prior to test.Again wasrecommended Operator do some well diagnostics to investigate well bore leak -- Thursday,October 15,2015 Page 1 of 1 • • MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Re DATE: Thursday,October 08,2015 P.I.Supervisor eget Lt-.,(t l/5- SUBJECT: Mechanical Integrity Tests AURORA GAS LLC 1 FROM: Matt Herrera ASPEN 1 Petroleum Inspector sumo p+6�i�� .j j 0 5 o Y,, Src: Inspector Reviewed By: P.I.Supry ‘.3—&-1- NON-CONFIDENTIAL Comm Well Name ASPEN 1 API Well Number 50-283-20114-00-00 Inspector Name: Matt Herrera Permit Number: 205-111-0 Inspection Date: 9/27/2015 Insp Num: mitMFH150930064128 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min 1 N- 2010 610 - 610 -' 610 610 Well Type InjTVD • 'Tubing PTD 2051110 Type Test SPT Test psi 1500 - IA 325 1705 • 1480- 1 1290 - a Interval OT1-1ER P/F F r OA 0 0 0 0 Notes: DIO 32.002.Wellbore leaking,recommend Operator do some well diagnostics _ 32.-.ovz reg w, c 1Q- A-T wn$- LUi-1 r-A : sxNG.1re Thursday,October 08,2015 Page 1 of 1 . 0 — 2 7/8 6.5#8rd EUE J-55 Tubing I Aurora. Gas LLC **f fiat- � I 1 ��1 ;� � ,�� 13-3/8".54.5#,J-55 Structural j 4 Conductor to be driven to 83' CA2:45'71; 1; : 40'4," Aspen No. 1 ' = GL or 97'KB t�: Water Disposal Well ' ". a " , ' �; 1-X Final Configuration t � I v �J `0 API#50-283-20114-00 w*n4 , � I PTD#205-111 ' "_� 4 ` ' , i RKB-14.6' ° I ., ' Sept. 2008 ,:i44;-'4"-*` ' 9 5/8"36#Surface Casing set at 693' � , Cement w/50 bbls 14 ppg lead and 30 bbls 14.5 ppg Gas-Block"G"w/good FIT performed atreturns observed at surface. 720', Had 14.8 ppg `., �' ";,,. MWE test prior to ?I breakdown. 4., i 1_,' -.. Resqueezed perfs at 1368-1388'w/ Perforations: 1368'-1388' 50 sx(13 bbls)Type I cement w/ Squeezed Off additives on 8/26/08. Tested tbg-csg annulus several NI. 0� 4 4- times subsequently. Tested on Perforations: 1760'-1770' -:; -3 i ,I 8/29/08 to 1500 psi—bled to 1450 Squeezed Off ; i4i0 . -' in 30 min, 1 ', ¶1 lto.; 11 Retrievable Packer set at 2010 ft w/ .4 On-Off tool above and w/12'spacer m a ,,w ' pups,XN landing nipple and WEG '. on tubing tail. Perforations: 2125'-2145' _ 44114 Perforations: 2351'-2371' .* 'A^ 10 sx balanced cement plug placed Vim' tion top of retainer—TOC at 2891'.w� �� _ PBTD now at 2881'(CIBP f/1779' * 4� 1 pushed down to there) �,I Retainer set at 2955' + — „: Perforations: 2984'-2994' q $" Perforations: 3006'-3026' -�■ !!!.� 44,4'.. Perforations: 3444'-3454' N..,'', i ,,,,,..4),:::::',,„'-, Perforations: 3491'-3506' Perforations:3811'-3831' PBTD 4355' A 5 Y�"15.5#J-55 Casing to 4484'MD(TVD) Drilled 7 5/8"Hole to 4485' 40.6 bbls 13.5 ppg lead cmt and 136 bbls 15.8 ppg tail cement. • • MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE: Tuesday,October 13,2015 TO: Jim Regg P.I.Supervisor .-r--) Cl +t I `� i c SUBJECT: Mechanical Integrity Tests AURORA GAS LLC 1 FROM: Guy Cook ASPEN 1 Petroleum Inspector SCANNED 5 ;_Jr�n+ . 1rr Src: Inspector Reviewed By: P.I.Supry J L- NON-CONFIDENTIAL Comm Well Name ASPEN 1 API Well Number 50-283-20114-00-00 Inspector Name: Guy Cook Permit Number: 205-111-0 Inspection Date: 10/9/2015 Insp Num: mitGDC151012092355 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well 1 Type Inj ' N' TVD 2010 - Tubing 400 17001700 • 1700 - PTD 2051110 . Type Test SPT Test psi 1700 ' IA 15 ,r 15 -T 15 - 15 - Interval OTHER P/F P OA 0 - 0 0 • 0 Notes: Tested tubing to 1700 psi. Passed test with no change in pressures during the duration of the entire test. DIO32.002 ,...--- Tuesday, iTuesday,October 13,2015 Page 1 of 1 Image Project Well History File Gover 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. ~~ ~- ~ ~ ~ Well History File Identifier Organizing (aone> ^ Two-sided III IIIIIIIIIII VIII ^ Rescan Needed Ifl IIIIIIII~I IIIIII RESCAN DIGITAL DATA olor Items: ^ Diskettes, No. Greyscale Items: ^ Other, No/Type: ^ Poor Quality Originals: ^ Other: NOTES: BY: ~ Maria f Date: OVERSIZED (Scannable) ^ Maps: ^ Other Items Scannable by a Large Scanner OVERSIZED (Non-Scannable) ^ Logs of various kinds: ^ Other: t~~ /s/ Pro "ect Proofin r II I II it II I I III I I III 1 9 BY: Maria Date: (~ /s/ Scanning Preparation ~ x 30 = ~~ + ~ ~ =TOTAL PAGES (Count does not include cover sheet) BY: ~ Maria Date: ~„ ~ ~~ /s/ Production Scanning Stage 1 Page Count from Scanned File: (count does include cove sheet) Page Count Matches Number in Scanning Pre aration: YES NO BY: Maria Date: a, ~ ©~ /s/ ~nn P 1' Stage 1 If NO in stage 1, page(s) discrepancies were found: YES NO BY: Maria Date: /s/ Scanning is complete at this point unless rescanning is required. II I II'I II I (I II I I III ReScanned III IIIIII I~III II III BY: Maria Date: /s/ Comments about this file: Quality Checked ~~ 10!6/2005 Well History File Cover Page.doc 7,03 Regg, James B (DOA) From: Regg, James B (DOA) Sent: Thursday, February 02, 2012 10:41 AM To: 'Chad Helgeson' `eert 7( 21( Cc: 'Ed Jones' Subject: RE: Aspen #1 Mechanical Integrity Test Chad — Thank you for documenting our phone conversation. Your requested 6 month extension for the Mechanical Integrity Test (MIT) of Aspen #1 disposal injection well (PTD 2051110) is approved. Aspen #1 MIT must be completed not later June 30, 2012, and not exceeding every 2 than Ju e g y ears thereafter. Y Aspen #1 is an intermittent produced water injector approved for use by Disposal Injection Order 32 (February 7, 2008). Data provided and the results of previous MITs demonstrated good mechanical integrity for the well. Short duration, intermittent injection complicates performing the MIT, especially during winter months, and also represents a challenge for AOGCC to witness a test while the well is injecting with thermally stable wellbore conditions. AOGCC agrees that testing during summer months makes more sense for this intermittent injector. Jim Regg AOGCC � C� 333 W. 7th Ave, Suite 100 ( li i"� FEB ftj 8 Zilla Anchorage, AK 99501 ` '° 907 -793 -1236 From: Chad Helgeson [ mailto :chelgesoffaaurorapower.com] Sent: Wednesday, February 01, 2012 3:04 PM To: Regg, James B (DOA) Cc: 'Ed Jones' Subject: RE: Aspen #1 Mechanical Integrity Test Jim, Aurora Gas LLC is requesting a 6 month extension for the Mechanical Integrity Test of the casing on the Aspen #1 Injection /Disposal well, as we discussed on the phone yesterday. The AOGCC Disposal Injection Order #32 issued in 2008 requires that a MIT be completed every 2 years on this well. The last test was completed in January of 2010 and therefore is currently required to be completed. Based on our phone discussion yesterday, I have attached our tubing pressure data for Aspen in a chart format from June 1, 2011 to today. There are some gaps in the data because of power outages, etc. We can't pump when we don't have power and we don't have backup power for running our transmitters, either. We agreed that it makes more sense for these tests to be completed in the summer months, when we know the casing fluid isn't frozen and we can ensure stable tubing temperatures during injection. Please provide us with a 6 month extension for performing the MIT on this well as we request that it be performed in June of 2012 and can reoccur every 2 years thereafter in June (warmer season). The casing pressure has been a steady 0 psi during this entire 6 month period as well, but I did not chart the zero reading for this entire time, but I can chart 0 if you need me to. I can also send you the excel file if you need with all the data points, but it is a pretty large file. If you have any questions or need additional information, please let me know and I will get it to you as soon as possible. 1 • • Regards, Chad Helgeson Manager — Production Operations & Engineering From: Regg, James B (DOA) [mailto jim.reggOalaska.gov] Sent: Monday, January 30, 2012 3:53 PM To: Chad Helgeson Subject: RE: Aspen #1 Mechanical Integrity Test Checking on availability of an Inspector. Thank you for advance notice. Jim Regg AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907 -793 -1236 From: Chad Helgeson [ mailto :chelgesoraaurorapower.com] Sent: Monday, January 30, 2012 12:52 PM To: Regg, James B (DOA) Cc: 'Troy Galleguillos'; 'Ed Jones' Subject: Aspen #1 Mechanical Integrity Test Jim, Aurora Gas is planning to perform a mechanical Integrity Test on Aspen #1 on Thursday of this week. Please let us know if you have an inspector available to witness the testing. Thanks Chad Helgeson Aurora Gas LLC 2 Aurora Gas LLC Aspen #1 Tubing Pressures June 2011 to Feb 2012 1200 1100 - — 1000 • 900 � 4 4 800 i I ' , ' . .,,J t' •', ,!;ii: ii ' el ',' 1 V ', I L . gi! I :i4 :`,', 2.4 \ it ' t„ 0 700 , -- ? z. a �� �° Tubing Pressure (prig) It 600 li 0 _, 1 � � S0 0 _ I 400 -� E ' ' 300 200 [ , 6/1/2011 7/1/2011 8/1/2011 9/1/2011 10/1/2011 11/1/2011 12/1/2011 1/1/2012 2/1/2012 MEMORANDUM TO: Jim Regg ~ 2 I I?(i0 P.I. Supervisor I\'c'~`~ FROM: Jeff Jones Petroleum Inspector State of Alaska • Alaska Oil and Gas Conservation Commission DATE: Friday, February Os, 2010 SUBJECT: Mechanical Integrity Tests AURORA GAS LLC 1 ASPEN I Src: Inspector NON-CONFIDENTIAL Reviewed By: P.I. Suprv ~~Q~ Comm Well Name: ASPEN 1 API Well Number: 50-283-20114-00-00 Inspector Name: Jeff Jones Insp Num: mitJJ10012314092s Permit Number: 20s-111-0 Inspection Date: 1/23/2010 Rel Insp Num: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well ~ "Type Inj. w TVD 02 ~o IA zao »oo ~ I6zo ~sso P.T.D Zos>>>o'iTypeTest sPT Test psi isoo ~ OA ~-~ Interval OTHER pn-, P Tubing 640 680 690 - 700 Notes: One well inspected; no exceptions noted. < 1 BBL water pumped. MITIA for regulatory compliance. ~~ Friday, February Os, 2010 Page 1 of 1 Page 1 of 1 Regg, James B (DOA) From: Chad Helgeson [chelgeson@aurorapower.com] Sent: Friday, January 15, 2010 8:48 AM ~ ~~ s~2~ t" ~~ To: Regg, James B (DOA) Cc: Jones, Jeffery B (DOA) ~ ~~ S - ~ ~ ~ Subject: RE: Aspen MIT Witness Thanks for your patience. I have everything set up and actually did the test on Tuesday, just so I could see how it performed, etc. Find any bugs, etc. I pressured it up to 1500 psi and after 30 min the pressure was 1460 psi. As long as my operators do not borrow any of the pieces, it should be a pretty quick test & witness. Chad From: Regg, James B (DOA) [mailto:jim.regg@alaska.gov] Sent: Friday, January 15, 2010 8:41 AM To: Chad Helgeson Cc: Jones, Jeffery B (DOA) Subject: RE: Aspen MIT Witness Thank you for your attempts. Guess we just need to maintain a "rigid posture of flexibility". Given what I've seen of wester forecasts for the coming week, I'll leave it to Jeff Jones to again attempt to witness MIT after he returns from the Slope on 20th. Jim Regg 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 907-793-1236 From: Chad Helgeson [mailto:chelgeson@aurorapower.com] Sent: Tuesday, January 12, 2010 10:58 AM To: Regg, James B (DOA) Subject: Aspen MIT Witness Jim, We tried again to get the MIT done on our Aspen injection well and we were unsuccessful. Jeff Jones and I planned to do it today, and we were weathered out again. Hopefully we can get it done sometime soon, so we can put this behind us. The weather is supposed to be bad the rest of the week, either wind or snow. Let me know when you have another inspector available for this and we will try it again. We have everything ready, so it should be a pretty easy job once we can fly in and it should only take a few minutes to get it going. Thanks Chad Helgeson 1/15/2010 • Page l~f'3 Regg, James B (DOA) From: Regg, James B (DOA) Sent: Monday, December 14, 2009 3:42 PM To: 'Chad Helgeson' Cc: Grimaldi, Louis R (DOA) Subject: RE: Aspen #1 Water Disposal Delay is ok; Dec 28-30 would be best for us; otherwise, after Jan 1 Jim Regg AOGCC n'` 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 907-793-1236 From: Chad Helgeson [mailto:chelgeson@aurorapower.com] Sent: Monday, December 14, 2009 2:39 PM To: Regg, James B (DOA) Cc: Grimaldi, Louis R (DOA) Subject: RE: Aspen #1 Water Disposal 2v~-~~a Jim, We tried to get the MIT conducted last week on the casing at Aspen, but the weather was not kind to us and Lou got fogged out for a couple days. Lou recommended that I contact you again and see if we can come up with another plan to complete this MIT. My preference for Aurora personnel sake would be the week of the 28th. I am a little short staffed right now with people I feel can safely feel comfortable conducting this MIT. My tech that I would like to use for this MIT is scheduled to come back to work on Monday the 28th and will be onsite for almost 2 weeks. Do you think we can conduct this during that 2 week timeframe? Will that be acceptable to you? Chad From: Grimaldi, Louis R (DOA) [mailto:lou.grimaldi@alaska.gov] Sent: Tuesday, December 08, 2009 10:35 PM To: chelgeson@aurorapower.com Cc: Regg, James B (DOA) Subject: RE: Aspen #1 Water Disposal Chad, Saw this too late to call you today. Please call me at your earliest convenience at h e. I will be available Wednesday or Thursday. Lou Grimaldi 776-5402 (Home) 252-3409 (Cell) From: Regg, James B (DO Sent: Tue 12/8/2009 2: PM To: Grimaldi, Louis OA) 12/14/2009 Page 1 of 3 Regg, James B (DOA) From: Bruce D Webb [bwebb@aurorapower.com] Sent: Friday, August 28, 2009 11:34 AM To: Regg, James B (DOA) Cc: 'G Scott Pfoff; 'Ed Jones'; 'Chad Helgeson'; Maunder, Thomas E (DOA); Davies, Stephen F (DOA) Subject: RE: Aspen Disposal clarification Jim, Thank you for the clarification on allowable injection material. Regarding the July 1 Report on the disposal injection performance, it is my understanding that we are presently working on it, along with the information addition that you had requested from Chad by e-mail back in December. I apologize for the delay in submitting this information to you, we have had a lot of field activity this year and are working as fast as we can. Thank you for your understanding and continued patience. Best regards, -Bruce Bruce D. Webb Manager, Land and Regulatory Affairs Aurora Gas, LLC sump MAY 2 8 ZO14 1400 W. Benson Blvd., Suite 410 Anchorage, AK 99503 (907) 277-1003 office (907) 229-8398 cell (970) 277-1006 fax _ From: Regg, James B (DOA) [mailto:jim.regg©alaska.gov] Sent: Friday, August 28, 2009 11:00 AM To: Bruce D Webb Cc: G Scott Pfoff; Ed Jones; Chad Helgeson; Maunder,Thomas E (DOA); Davies, Stephen F (DOA) Subject: RE: Aspen Disposal clarification Bruce - DIO 32 (approved February 7, 2008) allows for solids injection into Aspen #1; there is no additional authorization required by the Commission. In addition to the phrases you point out in email below (references to solids, mud slurries, Class II fluids), note that the required MIT frequency is every 2 years in Rule 4, the standard we apply to slurry injection wells. In reviewing your request, I looked for the annual performance report for Aspen #1 required per Rule 6 ("Surveillance"). Our records indicate intermittent disposal injection into Aspen #1 commenced in August 2008. When was the Rule 6disposal injection_performance report submitted to the Commission? Jim Regg AOGCC 333 W.7th Avenue,Suite 100 11/6/2009 Page 2 of 3 Anchorage,AK 99501 907-793-1236 From: Bruce D Webb [mailto:bwebb@aurorapower.com] Sent: Wednesday, August 26, 2009 4:47 PM To: Maunder, Thomas E (DOA); Davies, Stephen F (DOA); Regg, James B (DOA) Cc: 'G Scott Pfoff; 'Ed Jones'; 'Chad Helgeson' Subject: Aspen Disposal clarification Gentlemen, I would like clarification from you as to Aurora's ability to inject cuttings (ground and mixed with muds or produced water) into the Aspen Class II oilfield waste injection well. We are currently only injecting muds and produced water, but may want to obtain an authorization for CIRI to inject cuttings as well. In the Application to the Commission, dated May 15, 2007, it was indicated, on page two, paragraph two, that: "The disposal waste stream will consist of produced water, drilling, completion and workover fluids, drill cuttings, rig wash, mud slurries, and other Class II fluids and solids." (emphasis added) In the Disposal Injection Order No. 32, dated February 7, 2008, it states the following terms: Page 1, Item 1: "Class II oil field waste fluids" Page 1, Item 2: "Class II oil field wastes" Page 4, Item 7: "Disposal Fluid Type" "...mud slurries and other Class II fluids and solids" Page 6, Rule 1: "Class II oil field waste fluids" Page 6, Rule 2: "Class II waste fluids" and "injected waste fluids" 20 AAC 25.990. Definitions. reads: (26) "fluid" means any material or substance that flows or moves, whether in a semi-solid, liquid, sludge, gaseous, or other form or state. It is my interpretation that the injection of ground drill cuttings processed into a sludge or slurry is a permitted use of the Aspen Injection well. Further, I have found no reference in 20 AAC 25 which indicates a separate or specific approval is necessary for the injection of drill cuttings. Please let me know your position on this issue. We are in the process of applying for CIRI approval to inject drill cuttings into the Disposal Lease, which is currently prohibited, and would like to know if there are any additional AOGCC authorizations necessary. Thank you for your time and consideration. Best Regards, -Bruce Bruce D. Webb Manager, Land and Regulatory Affairs Aurora Gas, LLC 1400 W. Benson Blvd., Suite 410 Anchorage, AK 99503 (907) 277-1003 office (907) 229-8398 cell (970) 277-1006 fax 11/6/2009 • Page 3 of 3 11/6/2009 Page lnf2 Maunder, Thomas E (DOA) From: Regg, James ' . Sent: Friday, December 05, 2008 3:06 PM To: Maunder, Thomas ' ' (DOA) � � Subject: FW: Aspen # 1 DOS'- � � Attachments: Aspen 1 MIT 11-14-08.zip; Aspen 1 | j 11-14-08.zip ~---------� Jim O AOGCC 000vxnm Avenue, Suite 100 Anchorage, AK 99501 907-793'1e36 KU L M 3 2 From: Bruce D Webb [mailto:bwebb@aurorapower.com] Sent: Friday, December 05, 2008 9:14 AM To: Regg, James B (DOA) Subject: FW: Aspen # 1 Jim. Here are the MIT and Temp. surveys for the Aspen #1 I had printed them off and delivered them to the AOGCC on November 25th with a short cover letter referring to Rule 6, first month injection survey. Chad and i plan on giving you a call this morning concerning the other items in your e-mail request to him. 'Bruce Bruce D. Webb Manager, Land and Regulatory Affairs Aurora Gas, LLC 1400 W. Benson Blvd., Suite 410 Anchorage, AK 99503 (907) 277-1003 office (907) 229'8398 cell (970) 277-1006 fax From: auoonspovver@gci.net[nnai|to:aunonapower@gd'naU Behalf Of Ed Jones Sent: Monday, November 24, 2000 8:01 AM To: 'Bruce DWebb' Co: 'Chad Helgeson' Subject: FW: Aspen # 1 Page 2 of 2 5 days after completion? Has the Completion Notice been submitted? Please let Chad or me know what info you need to submit these reports/meet these requirements. Thanks, Ed .„.. ...„ „.. „ _ .. ..„ . From: aurorapower@gci.net (mailto:aurorapower@gci.net] On Behalf Of Chad Helgeson Sent: Monday, November 17, 2008 7:56 PM To: 'Ed Jones' Subject: FM Aspen # 1 Ed, Attached is the injection survey of the Aspen Well. Chad From: John Butler [mailto:gaslift@alaska.net] Sent: Monday, November 17, 2008 4:36 PM To: Chad Helgeson Subject: Aspen # 1 Chad Here is the data and plots from Aspen # 1. The folder named Aspen 1 MIT is the static with an overlay of the baseline. The folder named Aspen 1 N. is the survey whik we we: r:jerctli included. cak\fwe ,ox,k_kck\ Thars 9/1110()()C) • • I Aurora I WeII:lAspen #1 I Field:lAspen 111 -14 -2008 I C Pressure (psia) 0 200 400 600 800 1000 1200 1400 1600 1800 2000 0 , 200 L I Pressure-Temperature K Profile 1 1. RIH & POOH Overlay RKB 400 T , 600 mis 800 Eill 1000 ;` � 1200 .311 Ili 1 II EL 400 Sk ci Is I 1 1600 Q CI 1800 Eli 2000 El , , 2200 al 2400 I EIN IIKU 2600 ` 2800 - kik 3000 I I I I I I I I 35 40 45 50 55 60 65 70 75 80 Temperature (Deg. F) - Pressure 11 -14 RIH — Perfs Pressure Baseline RIH - 9 -5/8" 13 3/8" 5 -1/2" - 2 7/8" Temperature 11 -14 RIH -- - -Temperature Baseline RIH Report date: 9/30/2009 C2- ..) • 0 I Aurora I WeII:IAspen # 1 I Field:lAspen 111 -14 -2008 I Pressure (psia) 0 200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 ` ! I I .\\ ■ 200 Pressure- Temperature Profile 1. RIH Overlays RKB Baseline, MIT, & Injecting 400 - 1111111 600 11111111MM- ' 800 = _ 11MINE1 - — Baseline Temp Baseline PSIA 1000 '� � 1200 ■ -_- 1 - ' Static Temp 11 -14 -08 Static Psia 11 -14 -08 1400 air ci E 1600 — 151 Inj Temp C Inj. Psia CD 0 1800 ., 2000 Ra m ......... 11111 2200 2400 \\174\ L k ili 2600 2800 3000 I 1 1 I I I 35 40 45 50 55 60 65 70 75 80 Temperature (Deg. F) - Pressure Inj. — Perfs Pressure Baseline RIH - 9 -5/8" 13 3/8" 5 -1/2" - 2 7/8" Psia Static 11 -14 -08 — — — Temperature Inj. RIH — — Temperature Baseline RIH Temp Static 8 -14 -08 Report date: 9/30/2009 Page 1 of 2 Regg, James B (DOA) From: Chad Helgeson [chelgeson@aurorapower.com] Sent: Tuesday, November 03, 2009 2:22 PM To: Regg, James B (DOA) 1- eiq if/5/61 Subject: RE: Aspen#1 Water Disposa Jim, You are correct. I put the wrong depth on for packer depth. I put the depth of the bottom of injection perfs. The packer is set at 2010ft. Chad From: Regg, James B (DOA) [mailto:jim.regg@alaska.gov] Sent: Tuesday, November 03, 2009 12:37 PM To: Chad Helgeson Subject: RE: Aspen #1 Water Disposal MIT - I will have an inspector contact you about witnessing an MIT on Aspen #1 (PTD 2051110). - Packer depth referenced on your MIT form is not consistent with the Well Completion report(Form 10-407); well record indicates Aspen#1 is a straight hole so packer depth should be 2010 ft TVD. If this is incorrect, you will need to resubmit a corrected 10-407. -Attached is current version for the MIT test report form. Annual Disposal Injection Report -Carrying report through July 6 injection is acceptable. - Injection order outlines info that is required to be submitted. Aurora has to address fracture height growth in relation to the confining layers and what was predicted. Jim Regg AOGCC 333 W.7th Avenue,Suite 100 Anchorage,AK 99501 907-793-1236 SCANNED MAY 2 8 2014 From: Chad Helgeson [mailto:chelgeson@aurorapower.com] Sent: Monday, November 02, 2009 2:48 PM To: Regg, James B (DOA) Cc: 'Edward Jones'; 'Bruce D Webb' Subject: Aspen #1 Water Disposal Jim, We are working on the reports and information we are delinquent in providing the state and I want to be sure that we get everything correct in our submittals to you. We can perform a mechanical integrity test anytime on the casing for Aspen #1. I have attached the form that I think we need for this. If you have an inspector available for a witness this week we can perform this test anytime they are available (the sooner the better for us). Do I need to request anything more formal? I am also working on the report evaluating the performance of the well. Since this is our first report, what type of information do you need for the assessment of the fracture geometry and the calculated zone of influence for 11/3/2009 • Page2of2 injection? Do you want a comparison of what we predicted during the permitting process or just the data we have gathered this year? What timeframe and dates should this report cover? Since we are already late in our report, I was planning to have the data going through July 6th where we concluded our last significant injection prior to the end of September, Would this seem reasonable to you? I am sorry this information was delayed in getting to you and hopefully we can provide it in an acceptable manner for you. Thanks Chad Helgeson 277-1003 11/3/2009 L. ( fi • d i,F .1 , . i _ i ° + � 6` ` ) a ) 4 - a " SEAN PARNELL, GOVERNOR r a_ U Lai CO) �d y ALASKA OIL AND GAS 333 W.7th AVENUE,SUITE 100 CONSERVATION COMMISSION I ANCHORAGE,ALASKA 99501-3539 �s PHONE (907)279-1433 FAX (907)276-7542 October 23, 2009 Certified Mail Return Receipt Requested 7005-1160-0001-5753-9196 Mr. G. Scott Pfoff President Aurora Gas,LLC 6051 North Course Drive, Suite 200 Houston, Texas 77072-1628 SCANNED MAY 2 8 201 Re: Notice of Reporting and Testing Violations Aspen 1 (PTD 2051110) Dear Mr. Pfoff: Disposal Injection Order (DIO) 32 authorizes Aurora Gas LLC (Aurora) to use Aspen 1 for the underground injection of Class II oil field waste fluids. The disposal well is located on the west side of Cook Inlet, approximately 4 miles west of Tyonek and proximate to Aurora-operated gas development activities. The Alaska Oil and Gas Conservation Commission (Commission) approved DIO 32 on February 7, 2008. Commission records indicate Aspen 1 commenced injection on or about September 1, 2008 and has been used for infrequent, intermittent injection since the start of injection. DIO 32 requires Aurora to comply with several specific rules covering disposal injection operations. The well, field and injection order files associated with Aspen 1 indicate that Aurora failed to comply with testing and surveillance requirements of DIO 32. Within 14 days of receipt of this letter,Aurora is required to provide the following: - Aurora must perform a Commission-witnessed mechanical integrity test (MIT) as required in DIO 32, Rule 4; - Annual performance report required by DIO 32, Rule 6 covering disposal injection from commencement in August 2008 through June 30, 2009. Aurora must also provide sufficient records to substantiate the findings in its report. DIO 32, Rule 6 states: "A report evaluating the performance of the disposal operation must be submitted to the Commission by July 1 of each year. The report shall include data sufficient to SENDER: COMPLETE THIS SECTION COMPLETE THIS SECTION ON DELIVERY ■ Complete items 1, 2, and 3.Also complete A. Si• :ture item 4 if ated Delivery is desired. X 14 it/ 0 Agent ■ Printyour name and address on the reverse (,V �/C/� 0 Addressee so that we can return the card to you. B. Received/ ,•y(Printed Name) C. Da e of Delivery Ill Attach this card to the back of the mailpiece, (Q) U5 P or on the front if space permits. - D. Is delivery address different from item 1? ■ Yes 1. Article Addressed to: If YES,enter delivery address below: 0 No A11. (7. 5ee T 1p05/ /(,/'IC C() Zit/e x rE �d 3. Service Type i /v- 0 Certified Mail 0 ExpressMail '14111e57 ' 7—y's4 771)7e / '?y 0 Registered 0 Return Receipt for Merchandise 0 Insured Mail 0 C.O.D. 4. Restricted Delivery?(Extra Fee) 0 Yes 2. Article Number 700.5 1160 0001 57,Cy 3 (Transfer from service label) � l' J i I I 1. PS Form 3811,August 2001 Domestic Return Receipt 102595-02-M-0835 U.S. Postal Service-r., � CERTIFIED MAIL:, RECEIPT ,g (Domestic Mail Only;No Insurance Coverage Provided) u^ or delivery information visit our website at www.usps.com; m OFFIC. - L USE tri Postage $ Certified Fee 50 e(� '� 171 Po Return Receipt Fee Q (Endorsement Required) .IC! O •Restricted Delivery Fee u' (� ,..p (Endorsement Required) . rA Total Postage&Fees $ •�� QR.' s� . NV O Sent To co Aix. /3 F , "4644- 605,,t- r- Street, No.; or PO BoxrNo. �65/ /V. (dateu� ��G�d City,State,ZIP+4 � 77 776 207-- PS Form 3800,June 2002 • See Reverse for Instructions Mr.Scott Pfoff October 23,2009 Page 2 of 3 characterize the disposal operation and include,for example:pressures (daily average, maximum and minimum); fluid volumes injected (disposal and clean fluid sweeps); injection rates; an assessment of fracture geometry; a description of any anomalous injection results; a calculated zone of influence for the injection fluids; and the assessment of treatments to remediate scale and precipitates." DIO 32, Rule 4 addresses mechanical integrity of Aspen1: "The mechanical integrity of Aspen 1 must be demonstrated before injection begins and before returning the well to service following a workover affecting mechanical integrity. A Commission-witnessed mechanical integrity test must be performed after injection is commenced for the first time in Aspen 1, to be scheduled when injection conditions (temperature, pressure, rate, etc.) have stabilized Subsequent mechanical integrity tests must be performed at least once every two years. The Commission must be notified at least 48 hours in advance of each such test to enable a representative to witness the test. Unless an alternate means is approved by the Commission, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1,500 psi, or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30 minute period A written record of the results of all mechanical integrity tests must be provided to the Commission within 7 days of test completion." On December 3, 2008 the Commission notified Aurora of several missing regulatory submittals tied to the commencement of disposal injection into Aspen 1, including the pre-injection MIT report, results of a post-initial injection temperature survey, and a post-initial injection MIT. Aurora responded on December 5, 2008 with the post injection temperature survey (completed November 14, 2008) and a second attachment mislabeled as the Aspen 1 MIT but which in fact was the static temperature survey also performed on November 14, 2008. A copy of the chart recorder output for the pre-injection MIT was attached to the Well Completion or Recompletion Report and Log, Form 10-407, received by the Commission on September 10, 2008. No post- injection MIT results were provided. On August 28,2009 the Commission requested the status of the annual disposal injection performance report for Aspen 1 which was due July 1. Aurora responded to the Commission's request on August 28,2009,stating that the report was being prepared. As of the date of this letter, Commission records show no disposal injection performance report has been received for injection from August 2008 through June 2009. In addition,there is neither any record of the post-initial injection MIT being scheduled and performed nor any record that Aurora obtained Commission approval of an alternate means of demonstrating mechanical integrity as provided for in Rule 4 of DIO 32. Further,Aurora has obtained no administrative relief(DIO 32,Rule 8) from well integrity demonstration requirements. Failure to provide the information as outlined in this letter may result in the Commission pursuing further enforcement action in connection with these apparent violations as provided by 20 AAC 25.535 and AS 31.05.150. . + ' Mr. Scott Pfoff October 23,2009 Page 3 of 3 Should you have any questions regarding this correspondence, please contact Mr. James Regg at (907) 793-1236. Sincerely, Daniel T. Seamount,Jr. Chair cc: Tyonek Native Corporation 1689 C Street, Suite 219 Anchorage, AK 99501 AOGCC North Slope Inspectors via e-mail RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a),within 20 days after written notice of the entry of this order or decision,or such further time as the Commission grants for good cause shown,a person affected by it may file with the Commission an application for reconsideration of the matter determined by it. If the notice was mailed,then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the Commission denies reconsideration,upon denial,this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Commission mails,OR 30 days if the Commission otherwise distributes,the order or decision denying reconsideration,UNLESS the denial is by inaction,in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration,this order or decision does not become final. Rather,the order or decision on reconsideration will be the FINAL order or decision of the Commission,and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails,OR 30 days if the Commission otherwise distributes,the order or decision on reconsideration. As provided in AS 31.05.080(b),"[t]he questions reviewed on appeal are limited to the questions presented to the Commission by the application for reconsideration." In computing a period of time above,the date of the event or default after which the designated period begins to mn is not included in the period;the last day of the period is included,unless it falls on a weekend or state holiday,in which event the period runs until 5:00 p.m.on the next day that does not fall on a weekend or state holiday. • • Aurora Gas, LLC ~~~ www.aurorapower.com St~ ~ ®t`u°~sS Alaska ~i9 ~ Gas ~qns. ~q~~~~;:_.~.,,,. September 10, 2008 Ar~chq-~a~2 Mr. Tom Maunder Senior Petroleum Engineer State of Alaska .:~ .,, . Oil and Gas Conservation Commission ~ ~•~ ~ ~= ~ .~; ~ 2~~ 333 W. 7th Avenue, Suite 100 I I Anchorage, AK 99501 ~©~~ Re: Well Recompletion Report, Logs and Injection Test Results Aspen #1 Class II Waste Disposal Well Dear Mr. Maunder: Pursuant 20 AAC 25, the requirements of Sundry Approval 307-172, and Rules 3, 4 and 6 of Disposal Injection Order No. 32, Aurora Gas, LLC (Aurora) hereby submits the following information for you review and consideration: AOGCC Form 10-407, Well Recompletion Report and Log . Aspen No. 1 Final Well Schematic Aspen No. 1 Summary of Daily Operations Copies of Pressure Test Charts Injection Test Report Copies of Injection Rate Charts Baseline Pre-Injection Pressure and Temperature Reports Injection Pressure and Temperature Reports Should questions arise in connection with this request, please contact me in the Anchorage office at 277-1003. Respectfully Submitted By, ~~ ~~ Bruce D. Webb Manager, Land and Regulatory Affairs Attachments, listed above 10333 Richmond Avenue, Suite 710 • Houston, Texas 77042 • (713) 977-5799 • Fax (713) 977-1347 1400 West Benson Blvd., Suite 410 • Anchorage, Alaska 99503 • (907) 277-1003 • Fax (907) 277-1006 STATE OF ALASKA ~ ~ ~ ~~ r_DO8 ~~~ U ~~mr~..~ ALA OIL AND GAS. CONSERVATION COM~$ION WELL COMPLETION OR RECOMP~rE`~'I~~I~~`E~Pt~~T~~D LOG ~-!7°a 1 a. Well Status: Oil ^ Gas ^ Plugged ^ Abandoned ^ Suspended ^ 2oanc2s.~os 2onE+czs.»o G1NJ ^ WINJ ^ WDSPL Q ' WAG ^ Other^ No. of Completions: 16: II Class: Development ^ Exploratory^ Service 0 ~ Stratigraphic Test ^ 2.Operator Name: Aurora Gas, LLC 5. Date Comp., Susp., or Aband.: 9/1!2008 12. Permit to Drill Number: / ~~~ 205-111 3. Address: 1400 W. Benson Blvd., Suite 410, Anchorage, AK 99503 6. Date Spudded: 8/2/2005 13. API Number: 50-283-20114-00 ' 4a. Location of Well (Governmental Section); Surface: T. 12 N., R. 11 W., S.M., Section 33 ~f~lp ~'SL/ 7. Date TD Reached: 6/21/2006 14. Weil Name and Number: Aspen No.1 Top of Productive Horizon: j2~ GW ~• top of Injection Horizon: 2,125' TVD and MD ~ ~ 8. KB (ft above MSL): 448.5' Ground (ft MSL): 18' 15. Field/Pool(s): ~`•b Total Depth: 2,372' TVD and MD /(• 9. Plug Back Depth(MD+TVD): 2,891' / 2,891' Undefined 4b. Location of Well (State Base Plane Coordinates, NAD 27): Surface: x- 278848 y- 2589$11.9 ' Zone- 4 10. Total Depth (Mb + TVD}: 4,485' / 4,485' 16. Property Designation: CIRI Disposal Lease # C-061645 TPI: x- 278848 y- 2589811.9 Zone- 4 Total Depth: x- 278848 y- 2589811.9 Zone- 4 11. SSSV Depth (MD + TVD}: none 17. Land Use Permit: Tyonek Native Cprp. # AR-101765 18. Directional Survey: Yes No ~ (Submit electronic and printed information per 20 AAC 25.050) 19. Water Depth, if Offshore: na (ft MSL) 20. Thickness of Permafrost (TVD): na 21. Logs Obtained (List all logs here and submit electronic and printed information per 20 AAC 25.071): No well or mud logs during this recompletion. Temperature and Injection logs submitted with Sundry 307-172. 22. CASING, LI NER AND CEMENTING RECORD CASING WT. PER GRADE SETTING DEPTH MD SETTING DEPTH TVD HOLE SIZE CEMENTING RECORD AMOUNT F.T. TOP BOTTOM TOP BOTTOM PULLED 13-3/8" 54.5# J-55 18' 95' 78' 95' driven Nq 0' 9-5/8" 36.0# J-55 18' 693' 18' 693' 12-114" Cmt'd to surf. w/80 bbls 0' 5-12" 15.5# J-55 18' 4,484' 18' 4,484' 7-78" Cmt'd to surf. wH77 bbls 0' 23. Open to production or injection? Yes ~ No ^ If Yes, list each 24. TUBING RECORD interval open (MD+TVD of Top & Bottom; Perforation Size and Number): SIZE DEPTH SET (MD) PACKER (MD) 2-7/8" 2,022' 2,010' 2,125' to 2,145' and 2,351' to 2,371' with Perforations at 6 JSPF with a 3- 1/2" HSD DP PowerJet HMX casing gun, w/ 0.44" holes according to 25. ACID, FRACTURE, CEMENT SQUEEZE, ETC. the specs. DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 1,368' -1,388' 50 sx (13 bbls) Type 1 cement w/ additives 26. PRODUCTION TEST Date First Production: NA Method of Operation (Flowing, gas lift, etc.): Date of Test: 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-Bbt: Gas-MCF: Water-Bbl: Oil Gravity -API (corr): 27. CORE DATA Conventional Core(s) Acquired? Yes ^ No Q Sidewall Cores Acquired? Yes ^ No Q If Yes to either question, list formations and intervals cored (MD+TVD of top and bottom of each), and summarize lithology and presence of oil, gas or water (submit separate sheets with this form, if needed). Submit detailed descriptions, core Chips, photographs and laboratory anarytical results per 20 AAC 25.071. NONE ~::,~ ~- :CEP LOQ$ ~--`~~~~~' Form 10-407 Revised 2/2007;' `a `(~ ~ ~ ~ ^ ~ONTINUED ON REVERSE ~~ G g.r •~ 28. GEOLOGIC MARKERS (List all formations and markers encountered): 29. FORMATION TESTS NAME MD TVD Well tested? Yes No If yes, list intervals and formations tested, briefly summarizing test results. Attach separate sheets to this form, if needed, Permafrost -Top and submit detailed test information per 20 AAC 25.071. Permafrost -Base Base of Glacial Wash 722' 722' TSUGA 2-4 1,560' 1,560' All Intervals were tested with no significant rate or TSUGA 2-5 2,550' 2,550' amount of gas being produced during original drilling TSUGA 2-6 3,aso' 3,aso' and production tests. The well was tested for infectivity during well operations in August 2008 and were found to be acceptable in accordance with Disposal Injection Order No. 32. Formation at total depth: 30. List of Attachments: Operations Summary, 10-404 Report of Sundry Operations, Well Schematic, Temperature, Pressure and Infectivity Results 31. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Ed Jones (713) 9775799 Title: Manager of Land and Regulatory Affairs Printed Name: Bruce D. W ebb ~ ~ Signature: ~4~.. i4~ Phone: (907) 277-1003 Date: 9/10/2008 INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. Item 1a: Classification of Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 4b: TPI (Top of Producing Interval). Item 8: The Kelly Bushing and Ground Level elevations in feet above mean sea level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 20: Report true vertical thickness of permafrost in Box 20. Provide MD and TVD for the top and base of permafrost in Box 28. Item 22: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 23: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 26: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 27: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Submit detailed description and analytical laboratory information required by 20 AAC 25.071. Item 29: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Form 10-407 Revised 2/2007 • 2 7/8 6.5# 8rd EUE J-55 Tubing Auirora Gas, LLC 13-3/8" 54.5# J-55 Structural Conductor driven to 80' GL or 95' ItB Aspen No. 1 WDSPL Well Recompletion Ftinal Configuration Drill 7 7/8" Pilot Hole to ,"~+ ` 4-5/8" 36# J-55 Intermediate Casing 700 ft, Open to 12 ''/a" *'~,' set at 693' Cement w/ 50 bbls 14 ppg .,'r` lead and 30 bbls 14S ppg Gas-Block FIT performed at .,~ ~.~:^ "G" w/ good returns observed at 720' , Had 14.8 PPg '+' MWE test prior to ' '' ' breakdown. •~; • , Resqueezed perfs at 1368-1388' w/ S0 sx (13 bbls) Type I cement w/ Perforations: 1368' -1388' -' ~ ~ additives on 8/26/08. Squeezed Off ~. ~;~ ;, ,.,~ Tested tbg-csg annulus several , •r -+ ~ %~ + times subsequently. Tested on Perforations: 1760' -1.770' 8/29/08 to 1500 psi-bled to 1450 Squeezed Off ,A; •-' ,~ ~ ~a-. in 30 min, ,• . ~, •f~ Retrievable Packer set at 2010 ft w/ / -.i' ~,> % On-Off tool above and w/ 12' spacer "~' rte: "~~ ~` pups, XN landing nipple and WEG • ? ,. on tubing tail. Perforations: 2125' - 2145' Perforations: 2351' - 2371' „~ ,• . ,~ . ,~ ~'^~- ,, " ~, 10 sx balanced cement plug placed / •~- ~ on top of retainer-TOC at 2891'. •:.~ ° ~•',~, PBTD now at 2881' (CIBP f/ 1779' ~.i~ T. pushed down to there) '~ ~ ~~ ' ~ .+ Retainer set at 2955 Perforations: 2984' - 2994' "•r Y. '' ' ' ,.' Perforations: 3006' - 3026' :` „~, ~ ~ ,~ ~. Perforations: 3444' - 3454' ~ Perforations: 3491' - 3506' Perforations: 3811' -3831' ~~` ~~ ` ".. .~' PBTD 4355' - ~ to 4484' MD (TVD) 5# J-55 Casin 5-''/ " 15 g Z . Drilled 7 5/8" Hole to 4485' 40.6 bbls 13.5 ppg lead cmt and 136 bbls 15.8 ppg tail cement. AURORA GAS, LLC ASPEN 1 n RE-ENTRY AND CONVERSION TO CLASS it DISPOSAL SUMMARY OF pAILY OPERATIONS 8/14/08: Start mobilizing AWS 1 rig to west side of Cook Inlet via Red Dog landing craft from Nikiski 2 runs. 8115/08-8/19/08: 5 more Red Dog runs. Move to Aspen location and rig up. 8/2_ 4/OS: Finish rig up. Start NU BOPE. 8/2~ 1/08: Test BOP's. Test casing to 1500 psi (to top of 1st cement plug at 1234'1. 8/22/08: Finish BOP test. Drill mousehole. PU BHA-4-3/4" bit, JB, 12 - 3-1/8" SDC's. PU 2-7/8" tubing and RIH. Tag cement at 1234'. PU power swivel (PS). Weight KCi- NaCI brine to $,9 ppg. 8/23108: Wash to 1255'. Drill cmt 1255-1373'. Circ hole clean. Test perfs at 1368-88' to 1500 psi. Leaked off 120 psi in 30 minutes. Drill cement to 1714'. Hit retainer- drilled 1-1/2'. 9.0 ppg brine. 8/24/08: Drill on cmt retainer. POH, LD bit. PU bladed mill. RIH. Drill retainer to 1718'. Drill cement to 1745'. 9.0 ppg brine. $/25/08: Drill cement to 1776'. Circ hole clean. Test casing to 1500 psi-test failed. POH, LD mill. PU casing scraper and RIH. CBU. POH, LD scraper. PU WF AS 1 X packer. TIH and set packer at 1685'. Test perfs at 1760-70' to 1700 psi-held OK. Test annulus (perfs at 1368-88'}-injected 0.5 BPM at 800 psi. Retest perfs at 1760-70' belov packer to 1700 psi---bled to 16 0 psi m minutes. POH to 1343' and set packer. 8/26/08: Test annulus to 1500 psi 1.0 BPM at 1250 psi. SIP-900 x PU RBP and TIH. 5 bbl brine at 0.5 BPM at 750 psi, then at ~s. Release packer. POH, LD WF packer. 8/2'7/08: Set RBP at 1440'. Release from RBP and dump 3 sx sand down tbg onto RBP. POH wt tubing and setting tool, PU HES Champ squeeze packer and RIH- to 14~'. et packer and test RBP to 1500 psi--OK. Release pkr and PU to 1288' and reset pkr. Test annulus to 1500 psi. RU BJ. PJSM. Pump 5 bbl fresh water. dYlix and pump 50 sx Type I cement w/ gas block, dispersant, and FLA X14.5 ppg, 1.47 cu.ft./sk yield}--13.1 bbl. Squeeze perfs at 1368-88' at 1 BPM ~a,690 psi, slowing rate to 0.4 BPM at 760 psi. Bled to 480 psi in 15 minutes. Open ports and reverse out 1.5 bbl cement. WOC. 15 hours. Test squeeze to 500 psi-slowly bled to 400 psi. ~ s 8/28/08: Slowly POH w/ packer. PU bit & DC's and TIH. Tag cement at 1289'. RU PS. W.O.C. 3 hours total of 24 hours WOC time .Drill cement to 13 '. WOC 4 hours (30 hours since pumping). Drill cement to 1395'. Pressure test perfs at 1366-88' to 1500 psi--bled to 1450 psi in 30 minutes. ,Drill cement to 1425'. Wash sand to 1430' and circ clean. POH, LD DC's. 8/29/08: TIH w/ retrieving tool. Tz POH. PU BHA to drill CIBP. Test Crisp TIH w/ milling assembly. 1~ 8/30/08: Mill CIBP to 1779'. RIH to 2775 (pushing CIBP). RU PS. Mill and push remains of CIBP to 2881; . POH w/ junk in JB dragging. TIH w/ mill and scraper, drifting tubing to 2.3 S". 8/31/08: Fin RIH w/ scraper to 2881'. Circ clean. POH, standing back 32 stands and LD remainder of tubing + BHA. PU WF Arrowset packer w/ WEG, XN nipple (2.312" profile and 2.205" no-go), 2 X 6' pups, packer, On-Off tool w/ 2.312" profile. RIH and set packer at 1995; . Test annulus to 1500 psi--OK. RU Pollard. Set plug in XN ,nipple ate. Test tubing to 2500 psi for 30 minutes---OK. Pull plug from XN nipple. Run memory temperature tool for base-line injection temp. survey (2 passes PBTD to packer). Run infectivity test w/ 9.0 ppg brine and some produced water: pump 169 bbl (197 bbl strapped tank volume) at 0.6 to 1.0 BPM at b00-850 psi (floor ~au~e, up to 1020 psi on (820 on chart) in 45 n BPM at 850 psi (1020 bleeding to 17S psi in iniection aoine into tc ?M at SSO psi (680 on chap inutes, 0.8 BPM at 725 psi on chart) in 7S minutes. (S Z hours. Run Pollard men ~ set of perfs at 2125-45'. t) for 45 minutes, 0.72 BPM at 670 (900 on chart) in 45 minutes, and C ee attached spreadsheet). SHIP 3 S_0 Tory temperature survey-it indicat lvo apparent channeling. tSee Poila 9/01/08: Fin temp. surveys and RD Pollard. Rev circ 33 bbl 8.9 ppg brine w/ Baracor corrosion inhibitor for packer fluid. Space outand set packer at 2010'. Land tubing (BPV set in tbg hanger). Test annulus to 1 S00 psi--OK. ND BOP's. NU tree. Test tree to 1 S00 psi--OK. Release rig. Start rig down. 9/2/48: RD and move rig and equipment. 9/3/08: Finish rig down, move rig to Three Mile Creek #2. sand at 1430'. Rev circ to RBP, latch on, and to 1500 psi. Test 3P at 1776'. Ed Jones (9/S/OS) } • . ~'~ ~f ~ 7 ,~. _ ~ -- . ~" QS 0 - 0 '`~ ~A`~°° I 4000 J ~,- o0 3soo 9 ~~ ~ A~ ~ ~ . '. •. O° ,.~ 3p~ J u }.~ ~. _ ~ 25 ~~~~ 00 ~ ~./. L - 2000 ~ .., ~\~ ~'9 Zoo ~ ~O lsoo ~~ 00 2° ' ~ 1 p0 ~~ __ _ - ~ o° \~ _ ~` O p 500 .~ \° 00 ^ 5. U i GRAPHIC CONTR0~8 CORPORATION - yI iFFAL!i NF_N vOr=v ~ ~ . .. ~... ,. N.. .. . O CP O O O O 0 fo'... o ~ ~., ~- ,.., (P . ~ W o ...A.. O °o ° .; Mr ~~ ~' ~ .., l t;r o p o o ~ . ~ c ~ O O _ ~N OF= ,;~ Z .. ~ 'V O O, V p , , .. ... .0 .. O .. O. O .. .. ~ ... O .. _. ~ 0... D ~/ ~ ~J Iii' ~I' h. i II ' ~ 0 ~ ~ ... O ~ O .. ~ ~ f7J'~ I i i q ~ ~_ - - ~~r~~a~ ' ~,~ _ .. _ . . o` . .. : °° oos : ~~~ ~~. oo . ~~ Ooo; . 02 o° .. ~OS! 0~2 '~ 0 ~~~ 000 .°°~ ~ '" ~ OOS~ _ O c rv 00 0 ' O° ~° ~ ~ ';z,.°i ~ ,p - ': Oq O OOS~ ° i , ~ ` 000 _ -~ ,~ °°~, ~, . -. OOS4 ~~ - _ -- F_ - __, ,1 ^~ _ _ =1 ~ a~- S ~ ~ ~~ ~ ~ 1 P~:.. 1 .~y. ~ - ~ . `00 Q COO V i r Q ~ t-=- - __ 000 ~ .~ f 4000 ~, ~ A - K - . .~ 3S0 0 - 9 _ X50 _ ~ ~; 300 . ~0~0 _j ' \,2soo _ _., ~00 --` 2 - 200.0 - ~~ .. oo ° ~ `~SOO - O .Z ~ ~~ '0~0 ,goo '~ 500 - - 0 ` o _ _ \o _ 1 . ,~00 ~ ` ~ ~ ~ti `r~ y - CORPORATION ~ 1 ~~~n I ,.. CHART N0. MP-5000 O ._. .. ,. I ..., _ O O. O Cn .. O ... O ~., A O ..~ O O p ~ ~ ...r ~ _; _. O p O V ~... O O 0 O O - ~ ~ ., ....._. ~ ... I I O ~6~ ~~ , ~5_ _ 00. , o . ~., ~~ _ . ,. ff` ooo, : - o 0 ~ 0 Os~ / ~ 0002 ~ ~ OpO~: ~2 00 , OOS~ c„ .. 000 OOpf, O~c'~ `, ~ /' ~~ 005, 0O~ 0 o ' OO Oa -~_ _ ~ . 005, - = OOc'~ ~ 6 __~ , ,,~ - - . ._ _ , - _ -- t ~, = - _- q _ - - ,~ AURORA GAS, LLC Aspen Injection Test August 31st, 2008 Floor Guage Chart 121 bbls Starting volume Test tim e Pressure Recorder Flow rate Cum voi strapped in tank pits Time min psig psig Strakejmin total strokes BBLjMin Bbl tank volume • RATE 1 1712 0 0 20 10 2715 3 400 600 9-10 0.62 1.85 1720 8 500 630 9-10 0.62 4.93 1725 13 540 650 9-10 100 O.b2 8.00 1730 18 560 700 9 0.62 11.08 1735 23 550 700 9 0.62 14.16 1740 28 545 640 9 0.62 17.24 1745 33 545 6fi0 9 275 0.62 20.32 1755 43 550 680 9 0.62 26.48 1757 45 550 680 9 388 0.62 27.71 avg sjmin 8.62 0.58507937 26.33 28.60 End of pumping RATE 2 1815 0 125 300 1820 5 600 740 1835 20 625 760 1848 33 650 800 1853 38 650 800 1900 45 670 820 11 0 0.72 0 11 0.72 3.60 11 0.72 14.42 11 422 0.72 23.79 11 0.72 27.39 11 478 0.72 32.44 AVG 10.62 0.72079365 32.44 39.60 fnd of pumping RATE 3 1910 0 200 200 1912 2 575 750 1920 10 650 810 1935 25 675 840 1947 37 725 900 • 1955 45 725 900 RATE 4 2039 0 625 600 2045 6 680 820 2053 14 750 920 2057 18 750 920 2059 20 800 960 2107 28 800 980 2120 41 805 980 2125 46 825 980 2133 54 825 1010 2139 60 825 1010 2145 66 840 1010 2151 72 846 1010 2154 75 850 1020 12-13 0 0.80 0 12-13 0.80 1.60 12-13 0.80 8.01 12-13 313 0.80 20.42 12-13 452 0.80 29.63 12-13 532 0.80 36.03 AVG 11.$2 0.84222222 36.1 5$.00 End of pumping (appears to be in error, did not have chance to check) 14 0 0.98 0 i4 86 0.98 5.89 14 211 0.98 13.74 14 302 0.98 17.67 14 0.98 19.63 14 0.98 27.49 14 0.98 40.25 14 667 0.98 45.16 14 803 0.98 53.01 14 881 0.98 58.90 14 0.98 64.79 14 1052 0.98 70.68 14 1085 0.98 73.63 AVG 14.47 0.98166667 73.625 71.00 End of pumping total BBLs 168.48928S7 197.20 Injection pressure -Pressure read off gauge on tubing on rig floor AWS Mad Pump #1 with 6" liners 14 strokes =1bbtJmin BBtS \J BBLS Strokes 1t?0% effi 1 0.07 2 0.14 3 0.21 4 fl.29 5 0.36 6 0.43 7 0.50 8 D.57 9 0.64 10 D.71 11 0.79 12 D.86 13 0.93 14 1.00 15 1.07 cien 95% efficiency D.07 0.14 0.20 0.27 0.34 0.41 0.48 0.54 0.61 0.68 0.75 0.81 0.88 0.95 1.02 -- _ ~ - ___ - 'S 5 _ - - / 5000 ~ ~ ,r ~---+ __ ~ ~--~ '; ~ ~. ; 'SO p000 t~ ~ = _ _ _- _ ~` ~ 3 4000 ~`~ _ ~ - ~_ -+__` = X000 • X000 `, +' ~ _~ ---r- T~ \ ~SOO Y "~~ y = '` ~ 2`'00 ~.-- ,_-+ ,_ ~ 200 '~. ~'~~~ _, x~ ~ x O ~ ~ ---~___,~S ,~/ ~ 0 200 ~' ' ~ 7 f ~ -- ~ ~ ~ i fir.' ~ HOC' '' : - 0 '~ i ~ r ~ '_ - ~ X ~ ~ ~~ `~ ~ l~~r~~~~a r, 5~ ® - ~ ~ ~ ~ ~ i jf i, ~ ,~ ._ ~~Z~ ~ GRAPHIC CCN7ROL3 ORATIp_ ~~~~ ~k i/i CORP t~ h i~ ~~ ~ I t i ~ ~. ~ ~~ ~~ ~1~~ ~ I~~f ~ ~ j1 HART ~;~. ti~~ ~~ (n O O I I I~ ' i I I I I ~ ~~ ~~~ I .Itl1 I ~ i O O O~ - V O ~ O p ~-+~--~~ ~~ 'O LK j i ~-4- ~I ~ ~ ' ~ ~ ~i ~ p, ~ j ~ ry ~ :. ~ .. O ~pp, i /~i 15~~.~~ „r°,G TAKEN DFF ~ I 1 ~ I-' I ~; ~ .1 ~ ,'~~ n.~{~S,~J. 3~.~ 1~E~1 f ; ~~ 5 ~~ - ~~,3ti~ ~ 7 , ,..~ ~ ~ ~,,~ .~ ~ ~~~ _ ,mot-,~ 00 .._ . _. __ 8 .SS00 ~ ,~ ~~ 9 K ~~ ~ ,?' . y\~`~ .~ ~,~ ``~ ~~~\ `, , ~~ ~ ~ ~ ~ y \ \ ~ \ ~ \t ` ~ \ \ ~ ~ ~ ~ ~, ` \y` ~ ~ ~ ~ \~ \~ ` \ 1 ` 11 1 11 , \', `. ~ ~ 1 ~1'~.1 ~,1 ',.Ill ~I, -- 000 ;' -;~ ._ 002 --,c _-1--~_ ~ ; - OOSZ ~ -- - ~ ~pOS" y ~ L i - ] 000 ;_ - - ~ ~-- ,- !-~'~ OOc'~ 00 ;~~-`--r- - a=1 fir-- , - ~/ ~, 000 ~~ '-~' ~~, '' -:,1! 000 ~~~ ~ __` _+_ D00 ~ ~ ~ ~~ , - ~~ ~'~ " - _ ~~, S , OOSS S ``~=~- -_ _ = ~ ~ 00 _ - _ / - . ~! /' cv ~: _ _ ~~-,- ~_- _ - _ - O ~-._ ~ - - - - - -- - ,., --- - , ~~ _ __ ,_ ~~ `'~ _ ~- f - -- +---- - r-- Wd g S ,~/% ~`< Z Z ~;7r' - .yro- -~ ~ _ _-~ _ --r~w~`- ^y .. _- _ .. ~ _ s _. f --F-... _~ '- r~ e _ ~p ~ -- _ - _~ - ._ 00 p ~, ~--_ - ~_ _~ 4,SOO G`~p0 _ - _--r = ~_ - - ~ ~-~ _ 0 0 • •, pp ~ ~",_ -'- _ 1L- _~_- _1\ \;` 3500 x ~- p0 ~ _-+ _ ~--- - ~ - -T~ _ 3000 ." app - 1 ~~_ 2000 \ x >, , . ` p ~ ~ - `~ `4 \ 1` ,~ 2~ p /fi52- /f'i ~ r~~ , ~~' -~pO ~~~~/ ~ ( _ ~On ~ ' ~~ ~ ~ ~ ~/ / ,r ' ,~g0 ~ ~~ ~-~ ~ _~ 500 ~ .~~ >'~`_ ~. ! 1 ' ~ "~''' ~ ~ -' ~ ~~~ ~ ~f~~~ ~~~~~ ~ ~~~ ~ ~ pp a ~ p v~ ,A~~ ~I ~ ~ ~ ~ ' ~ ~ GRAPHIC CONTROLS CORPOR k'' ~ ~`~ 1 ~~ ~f~ ~ CH~.R? N0. M: Mss-6C0~~ ~o~ o ~~o_ I~ ~~ U r} ~ MET = i 1 1~ ~ o°', , ~~ Ili ~ r 1• ~ I ~ I, ~ O O CH RT PUT TAKEN OFF ~-f ~ `` Q~ ` , /~ ! ~ ,~ ~ ' O O O O I O p p' p ~ O O ~~ ~ ~ ~ ~ M G 'y _ !~'~ ~1'u1- i.- - M `,!'~ ~ ' ~ I~ I ~ ~__ ,~ 1. t~J1 k ~ ~ ~1 { . ~ v ~_~ ~ O ~ _ ~ ,', 00 .. O~ ~ ~ ~,jk LOCATfON ~''~~ [1~.1y~,YC^ 1~ S•~h.4 h' :r; ~x~~_ ~~ , ~ I 1 r' ~~ 1 H !'~ ~N. •~ N ~ REMARKS T~~'c.. E 5•t ~`S 7~~1~ -- ~,~ / J / y / , , 1 , ~ ~_~ ~T, ~ pp ,." ~ ~~ti / ~, ~ \ +~ -~-t~~` Eck ~~ \ .~~, - - - ~~~ k v ~ pOp~ / ~~~i ~ 1~7 ~ ~. -- ~ k _ 2 ~, 00~- - ~ ~ ~ pp~ ~ 0 _ s ;%% , 2 ~- ~ - ~~ y :.~ `> ~ ~ 000 -~, _~ - - _ '~ ~ h- pppS. .~ sz=~ o ~'~ p ~ <~ 00 ~, -_ _ - -+- , ,~ ,-~ o ~ Op ~ =mar- --~-- -'- /- ~~ ~ k _ -r__ ~- - i ~~~';~ -~~i, --- _ _ / , 8 X- 9 ~ ~. ~: ~ ~ . , /~ \,~~ A t iili r~i ~~x / ' '' ~ ~ i x %%! ~~ ~ ~ 1+~ Z ~i Z ~/ v i' ~~ ~ ti % a /~' ~ ~a i ~~ y ; 't .~ /,, ~~,° tt iY _ "1~ ~~~ ~ ~ ~ -~_ _ -.---~ - - --F--- _ ~~= ~- ~-- - - -._. - ---- - ----- r - ., •:,~ / ~ S W ~ 2 n.~ • .alb 5 7 ;1 - - i :. - -~ -- ~- - -1 -,~ _ -,--_ -- -- ~- ~l 5 _ ~- ~-! - - _ ~ _ O 1 -. _- __~- - ~ -fir= ~~ Ssi ~_ ~ O ~ ~ - ,~ ll-~ - ~~T-- _~ s~' p~ ~ ~ ~ ~ I- - - - ~~~~ ~~>` ~qp p5 ~ = `~ - - ---z= --- ,y p0 ~,,~ ~ 1 ~.$~ __ _ ~_ _ `3S0 ~4~ y ~ - - _` 2 - ~ ~- ~ ~ ~ ~ - ~=1-_ -_ --~ DOp X ~; ~'~ ,ZgO - IS ~' ~~, ~~ k % ~ ~, p~ /,~ ~ ~ ~ /G- j 2~ fir, ~+ i _ _ 000 ~ 1 r ~~ ~ ~~~ mod. ~ ~~ ~ , ~ ~ - l .~ ~~ .'t Ft~,~~ l~ ' ` ~ ~ GRAPHIC CONTROl9 CORPORATIbiO~ e r'; , "i i~ i I ~ ~ ~ - / 8'PFa. . ~~ ~~ 1 1 ~ ~ i! ~ ~ y ~~ ~~~ ~ rarq Iif f~~~ 1 ~ ~ ,, .~, I ~ ~ ~ r ~~~ ~ f ~ f_~ ~, ~ ~ ~ , ~ ~ `~ ~ ~ CHART (`JO MC MP-6000 ~ ~, o k~ ~ u, I f~ _ \\ o c III ~~ f ~ ~~~ ~~II r-~ I'Ft fIE' ~ i~ ii ( METEr /"~ //~) /~~~~ , ~ O D C ~ 00 O I~~ i~ _li ~ ~ 1~ ~~ 1 i~ 1.~_ ~ I O O - CH ~ ~; i O O O -~ i_ ART l,lT GN T I i ,_; O i O i; f~r~ ~ AKEN OFF { .,. ` 11 I ~.' .aI ' I d I ~ ' 1` O 1 ` ~ ~ If O ~ ~ ~ O~ [ M-~ '~`:~i ` •+~j ~(aC.i1 '~., ~„~ l ~'I_~ /~1/-/,F ~ N1 M ~ O J ~ LOCATIGN.J~ `~.1~ ~ -}a ~ lc I I ~ ~ ~~ ~~ ~~ _ R~,~RKS ie~_l STYE:. ~~~ ~ ~ ~ ;. ~ ,~~ ~ ~ ~ ,, ~ ~. ~ oo , O~ \ ~\ , \ ~~'~ .Y n 4 000 `~f _ ~ ~ ~ -~ ~ \'X' OO .U ~~ SZ - ~ -~---~---~-- ~~~5. < ~~~ i Y (~ r 'tom. ~ - i ~ ~~_:~. ooo~ ~..~ \ ~ -- _. ~ ~X/ OOH i ~ B \ ~~ ~ ~ \ 9 ~~~ ~ ,~. ~', ~k` \\~\ L ~, ~\ ~`, `, --+ ~- Wd 9 S b O ~~ ~ ~ ~ . ~, \\ ~ ~~\ ~ '\ i 1~1• ~1 11 `1\ 1 \ ~ 1 1,, x,11 , ,, ~ ,11 ;1~~ 11,1 1 '~~ I ~I ~i i ~i I ~_ o ill Ip~l Z I ;il~~ ~ T ~ I~.I Z ;~ G'~I~ l~ ~;~~ .~~~ ~ ~ ;<< ' ~' ;~ y / /'. i4~1 x~ i / h' 2 5 ~~~'~ A M ___ _ ~ A _ ,,_ r _ --t- - ~ ~_ _ ~` ~ 8 .~ _ ,_ ') 5 1, . _ _~---+-_ ~- `;-- ~- ~_~ ~ ~ ~ ` 5500 ' __,--- - ~'~~~ ~ cJO~~ ~ I ,:~ -~--f---~- -. ~ ~ SO00 ,.. _ ~, ~ 9 .5 - ~-_ __ __ - _ _ - - . _ ~ \ \x a ~ ,.4 ~ ; 8000 ~ ~ ~ `, p0~~ k ,.~- - ~- - -t - ~ - ~ ~ 3500.. x ;\, \ '~`k ~ X50 _ ~ _ ~- _ _ 000 y~ , ~~ ' ~~ '~ , - ~ ~ X2500 _ ~'~ , ~ _ ~ ~ `, ,5~ . _ ~ ~. ~ ~~k- ~ A ` , ' r 2 ;~ ~ . ~ ~'` O ~ ~~ 5~ T 00 ~ ~ ~ ~ .\ :, 2 _ _ ~~, ~ ~ ~~~ , Off' ~ ~ x~ ~ ~~ '~~ ~ A'~ ~, , -t-- f-SO ~ \ ~, ~ \ _ 0~ _ r~ - 'k _ >< f ~~~~ L ~` ~f ~ 2~~ (~f GRAPHIC CONTROL3 CORPORATION ~l ~ ~`"~ V ~ ~~~~ ~~ ~ ~ '~~ ~ ~ ~ ~ ~ -+ = I ~~I ~~ ~ f r~~ ~fl ~ ~~-~ ~~! ~I~ . { Pll- W lam, ~~ ~ '~ j \ ~ ~ -~. - jI~ 1 CHART nj, 11 ~~ I ~ '~I ~ ~ ~I ~~ ~ ~~ i y j-~.' 1 ` ~, ~"i l'i I'~1 G' -~)~J {~~i ~~ ; 1 1~`. - 1~ ' N ~ t 1 1 ~ . ~-. I I I ~ I ~ ~ J' Q ~, 1 \ CP f. N~''W ~ D i ~ ~~ ~T~ I.~ I~I ~~~ ~ ~~ N)~~ I ~;~T~ METER ~~ ~~)~ ~G~ ~ ~~- ,O ~~ ~ ~" ~0 0~~0 *~`~~~ ~p_,~ IA~ ~ I 'O i ~ ~ 1~4 I. i I I ' ~ ~ -t I J ~_.~-~_ ~ ~ i0 ~'i p i i O ~~ O ;i Cn _U~ ~ i ' v~ O O ~ ~ i ; ~'~-~- - ~ I f- .-l-i-I ~ ~ ~ - i I ~ ~ ~ 10 ~ ' O ~ ~ O ~~~ i- E1.. Ii ~ ~ O t0 00 p0 O ~'i ' ' ~ --~~.~, ~. ~+ CHART PU ON T I i I ~ I i O I i~ ~l O O O ~I O' 4 v- TAKEN i ~ I ~ ii ~ ~ ~ I v ~ ~ ~ O. ~~. ~ _,_ O . ~' ti o ~ , op - `~(j~~,t~! ~''~.3}`~01~' oFF ~ ~ I ~ ~t ~ ~ ' i ' ~ Z I I I r I ~ I 4 ~ N~1 1 N L 71CN /4S th. / ~I~ a ~ M ' ~ i\~; ~ ' ~ -~I1 I ' I I ~ -,, ~-t ~~ R MARKS ~ ~f~ --~pI1 !I /r ~ ~ ~ r ~ =~, I "( 'r.5 10~'~ T l ~ ~ I ~~~ -U ;~- ~- ~~ -- -~- -,-~~. 0 ~ i / v ~ l ~ ~~~ ,. • - ,. ~, ~ ~ ~ ~' .~ ~ O0 r ~. ~ ~ s' ~~; i ,. 2 , - -- - ~ ~ ~ ~~ /~ -°~ ~ - _ _ - ,. - - X ~ ~-\ 'may, 000 - _, _ ,~ ' ,, ~~- ,4 ~~~~ ~~ / ~/J,/;~ , ~.~ 0006 _ ~ -- '/; i O ~~ ~ ///%~i~~ ~~~~ __ _ f- Wd 9 ~ W ~i' W m m N O O • • Pressure (psia) w 0 .~ ~ ~ ~ ~ N 0 0 0 0 °0 0 0 0 0 °o 0 0 0 0 0 0 0 0 0 0 0 W A O I ~ ~ ~ A ~ ~ ~ C (D i~ I m y ~~ ~~ O c m rn 0 f~D D y N 7 a 0 ~, m 0 00 w i N O O ~ U1 O CJl O CT O U1 O Temperature (Deg.F) i i c 7 O (D i I i ~ II ~ ~ I I ~ I v N C OJ (D ~ ~ - - _ ~ - N "' 0 ~ i _._ .. _ __-_._._. __i ______. _ .. ~ ~ o_ _ N ~ ~' ~ o ~~ ~ v o ~ N ~ cn O __ - i --~-- - I I i I I Aurora II: Aspen # 1 t Field: Asp Date: 08-31-2008 Pressure (psia) 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 0 200 ; _ -- Pressure-Temperature Profile 1. Going in hole 2800' RKB I 400 - I 600 - - ! - - - -- - ---- - --- - -- -- - - - 800 - - - - - I II 1000 ! _ -- -- Ij ' I j ~ ' -- -- ---- -- 1200 -- - ---- .-. d y-. ~'' 1400 = - - - -- ~ ~ i ~ ! ~! ~ 1600 '~ - - -- C. O 1800 -- - -- - ~ - - - r -- -,~ i ! - - - 2000 - -- - i i 2200 ~'~ _ . , i ~_ 2400 ~ - - - ~ 2600 - -- - - - 2800 - ~, ~ i ~I I 3000 ~' ~ 48 50 52 54 56 58 60 62 64 66 68 70 72 74 76 78 Temperature (Deg. F) Pressure - Perfs 9-5/8" 13 3/8" 5-1 /2" 2 7/8" Temperature Report date: 9/9/2008 Aurora' II: Aspen # 1 baseline Field: Asp Date: 08-31-2008 Pressure (psia) 900 950 1000 1050 1100 1150 1200 1250 1300 2050 i Pressure-Temperature Profile 2100 -- r - -- 1. Going in hole 2050-2800' Baseline 2 2150 ---- - ' - - - ~ '- 2200 - ~ - - - 2250 - ~ -- 2300 - - - - i I -- .~ 2350 !- --- '' - .-. ~.+ ~ 2400 ~ --- - ~ 2450 ~ i I a=.+ I I ~ 2500 _------- --- 2550 - - - - ~ 2600 - - ~ -- - - j 2650 1 2700 - :, - - --- - -- --- -- -- 2750 - t ~ i ~, ~I - - - _ - - - 2800 ~ - ~~ 2850 64 65 66 67 68 69 70 71 72 73 74 75 76 77 78 Temperature (Deg. F) I - - -- Pressure - Perfs °--9-5/8" 13 3/8" 5-1/2" 2 7/8" Temperature Report date: 9/9/2008 Aurora Well: Aspen # 1 baseiina Field: Aspen 08-31-2008 I I Pressure (psia) 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 0 I ', 200 - - - Pressure-Temperature Profile + _ - 1. RIH 8~ POOH Overlay RKB 400 -- _ _ ~ --- ~ I 600 - - - - - - - _ ~~ , I~ 800 - - l ~ i 1000 - - - _ - 4 .~ 1200 _ _ - _ ~'' 1400 -- - - - ~ ~~ ~ 1600 - ----- d ~ ~ 1800 - -, --- -- _ __ ~ 4 4 2000 - - ---- I i 2200 - - - ' 2400 - -_ 2600 - -- -- -- ~- i 2800 -- -- - 3000 48 50 52 54 56 58 60 62 64 66 68 70 72 74 76 78 Temperature (Deg. F) Pressure R1 RIH - Perfs Pressure R2 POOH 9-518" 13 3/8" 5-1/2" 2 7/8" Temperature R1 RIH ~--~-~ -Temperature R2 POOH Repoli date: 9/9/2008 Aurora Well: Aspen # 1 !:;=s-' ~ :- Field: Aspen 08-31-2008 ~I Pressure (psia) 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 0 200 -- - Pressure-Temaerature Profile _ !, ~ j 1. RIH 8~ POOH Stops RKB 400 I ~ I !~ ~ 600 - - 800 - - - --- - - - - 1000 -- - i .-. 1200 ' --- -- -- -- - - - d \ ' .'' 1400 -- .. --- i ,C 1800 - fl. d ~ 1800 -- - - -- i, 2000 ~~~ -- I ~ - I I 2200 - - - - 2400 - ----- 2600 - \ - 2800 j ----- -- _ _ _ __ -- i I 'I I 3000 48 50 52 54 56 58 60 62 64 66 68 70 72 74 76 78 Temperature (Deg. F) - --- Pressure R1 POOH - Perfs Pressure R2 POOH 9-5/8" 13 3/8" 5-1/2" 2 7/8" Temperature R1 POOH -- -Temperature R2 POOH ~ Report date: 9/9/2008 ~ ~ P04H Stops R1 MD TVD Pressure Temp P-Grad T-Grad (feet) (feet) (psis) (Deg.F) (psilft) L3eg.F/ft 0.6 0.6 11.75 56.74 - - 2a50.0 2050.x 9x7.22 66.28 x.4369 x.47 2094.9 2x94.9 928.64 66.79 x.4771 1.14 2144.9 2144.9 952.66 68.3a x.4804 3.x2 2174.9 2174.9 967.35 68.04 x.4897 -x.87 2319.8 2319.8 1x35.75 69.39 x.4720 0.93 2351 .1 2351.1 1x51 .17 69.74 0.4927 1.12 237x.4 237x.4 1x61.25 70.x0 x.5223 1.35 2400.3 2400.3 1076.00 70.42 x.4933 1.40 2449.8 2449.8 11OOA6 70.93 x.4861 1.x3 2801.2 2801.2 1266.66 74.39 x.4741 x.98 P~7~JH Mops F2~ 0.1 0.1 6.31 51.48 - - 2050.3 2050.3 896.37 66.23 0.4341 0.72 2094.8 2094.8 917.39 66.76 0.4724 1.19 2143.5 2143.5 940.38 68.24 0.4721 3.04 2174.8 2174.8 955.28 67.98 0.4760 -0.83 2320.1 2320.1 1023.18 69.36 0.4673 0.95 2351.0 2351.0 1038.09 69.70 0.4825 1.10 2370.9 2370.9 1047.94 69.97 0.4950 1.36 24x0.8 2400.8 1062.42 70.40 0.4843 1.44 2450.2 2450.2 1085.66 70.92 0.4704 1.05 2800.6 2800.6 1249.50 74.37 0.4676 0.98 Report date: 9/9!2008 Aurora II: Aspen # 1 Field: Asp Date: 08-31-2008 ~ Pressure (psia) 900 950 1000 1050 1100 1150 1200 1250 1300 2050 Pressure-Temperature Profile 2100 ~ 1. POOH 2800' to 2050" RKB -- i 2150 - - - -- -- - 2200 - --- - i _ 2250 - -- -- -- ~ - 2300 ~ - - - - - ~, ~I -- - - ---- I 2350 ------ -- _ - - - ~ 2400 - I - - - -- ... ~ ~_ - ~ 2450 S ~.+ I ~ 2500 - - - - - I 2550 - 2600 - .. _ -- ~ ~ ~ 2650 ~ - - -. - --- - I i 2700 - - - - 2750 ! _ _ _ -_ __ I 2800 - { -- ~- - 2850 64 65 66 67 68 69 70 71 72 73 74 75 76 77 78 ~ Temperature (Deg. F) ~ _----- - - ~ Pressure - Perfs 9-5/8" 13 3/8" 5-1/2" 2 7/8" Temperature Report date: 9/9/2008 Aurora II: Aspen # 1 Field: Asp Date: 08-31-2008 Pressure (psia) 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 0 i ~, 200 '. - -- --- Pressure-Temperature Profile 1. POOH from 2800' RKB Run 2 400 ~ - - I 600 ~ I I ~ 800 ~ - i - - - - - 1000 - - - I I I - - _ ----- .-. 1200 --- -- -- - - ~+ ~ i ~'' 1400 - - --- -------- - Z 1600 ~ - - - ~. as - --. -- - _ ~ lsoo ~ 2000 ~ - - - - - --- - - - - i ~ ~ __ 2200 ~ -!; - _ ~ ~ 2400 - - - -- -- - - - i 2600 + I 2800 ~ - i 3000 48 50 52 54 56 58 60 62 64 66 68 70 72 74 76 78 Temperature (Deg. F) Pressure - Perfs °-~-_•° 9-5/8" 13 3/8" 5-1/2" 2 7/8" Temperature I Report date: 9/9/2008 Pressure -Gradient (psi/ft) -0.4 0.0 0.4 0.8 0 200 400 600 800 1000 1200 ... w m v 1400 a 1600 m 1800 2000 2200 2400 2600 2800 3000 1.2 1.6 i Pressure-Temperature Gradient Profile 1. Going in hole ~_ ~' -15 -10 -5 0 5 Temperature -Gradient (Deg. FI100 ft) ~_ Press Gradient - Perfs Temp Gradient ~~ 10 Pressure -Gradient (psi/ft) -0.4 0.0 0.4 0.8 0 200 400 600 800 1000 1200 m v 1400 t a 1600 m D 1800 2000 2200 2400 2600 2800 3000 1.2 Pressure-Temperature --- -"" - - - ` Gradient Profile 1. POOH - - -- - i 1.6 -15 -10 -5 0 5 10 Temperature -Gradient (Deg. F/100 ft) L Press Gradient - Perfs Temp Gradient Aurora Well: Aspen # 1 Field: Aspen Date: 08-31-2008 2000 I! 1800 1600 1400 • 1200 ~ . N a ~ 1000 H ~l d a` soo 600 • 400 I 200 0 80 75 70 65 D ... m r ea d 60 ~ a~ 55 50 45 21.5 22.0 22.5 23.0 23.5 24.0 24.5 25.0 Time (hrs) L Pressure Temperature Report date: 9/912008 Aurora' II: Aspen # 1 Field: Asp Date: 08-31-2008 Pressure (psia) 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 0 ,~ 200 ' _ -- i, - 1. Going in hole 2800' RKB , ~I ~ Pass 1 After Inj. 400 - ' ! I -, - ------ I 600 = -- -i 800 -i -- ~ ~~ 1000 II -- - -- --- 1200 -- -- - _ - ------ - .~. d ... 1400 -- - - ~ I ~ 1600 --~ - -- - a d D lsoo - - -{ ; _ - 2000 ~, -- - - --- -- - i 2200 ~-_ -- 2400 - - - 2600 - ~ --- - I _ i 2800 - -- - -- -- - ~ i i 3000 48 50 52 54 56 58 60 62 64 66 68 70 72 74 76 78 Temperature (Deg. F) Pressure - Perfs -9-5/8" 13 3/8" 5-1/2" 2 7/8" Temperature Report date: 9/9/2008 Aurora II: Aspen # 1 Field: Asp Date: 08-31-2008 Pressure (psia) 900 950 1000 1050 1100 1150 1200 1250 1300 1350 1400 1450 1500 2050 I - ' ~ I 2100 ~' Pressure-Temaerature Profile ---- -- 1. Going in hole i 2050-2800' Pass 2 after inj. i 2150 - ~ - - ~ ~- i I I 2200 - - - ~ - . _ - - - - - - i ~i 2250 - - I__- - - - I i 2300 2350 ---- --- ~ 2400 -- w .. ~ 2450 _ - --- L - ------ - ~ 2500 2550 - - -- 2600 - - ---- - -- i i 2650 --I - - -+ i i 2700 - - -- ------- -- --- - I 2750 --, - - 2800 - - I i ~ 2850 58 59 60 61 62 63 64 65 66 67 68 69 70 71 72 73 74 75 76 77 78 Temperature (Deg. F) Pressure - Perfs 9-5/8" 13 3/8" 5-1/2" 2 7/8" Temperature Report date: 9!9!2008 • i Aurora Well: Aspen # 1 Field: Aspen 08-31-2008 Pressure (psia) 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 0 200 400 600 800 1000 .~ 1200 d ~'' 1400 D t 1600 a a>' ~ 1800 2000 2200 2400 2600 2800 3000 48 50 52 54 56 58 60 62 64 66 68 70 72 74 76 78 Temperature (Deg. F) Pressure R1 RIH Inj - Perfs Pressure R2 POOH Inj ~ 9-5/8" 13 3/8" 5-1/2" 2 7/8" Temperature R1 RIH ~ Temperature R2 POOH Inj', Report date: 9/9/2008 ! r Aurora Well: Aspen # 1 Field: Aspen 08-31-2008 Pressure (psia) 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 0 200 400 600 800 1000 1200 d 1400 0 ,C 1600 +.+ a d ~ 1800 2000 2200 2400 2600 2800 3000 48 50 52 54 56 58 60 62 64 66 68 70 72 74 76 78 Temperature (Deg. F) Press R1 POOH tnj - Perfs Pressure R2 POOH Inj 9-518" 13 3/8" 5-1/2" 2 7/8" Temperature R1 POOH Inj --- ~wW Temperature R2 POOH Inj Report date: 919/2008 PClf7H *;Fnns R1 ltffar ini MD TVD Pressure Temp P-Grad T-Grad (feet) (feet) (psis) (Deg.F) (psilft) Deg.Flft -0.4 -0.4 342.36 56.05 - - 2050.4 2050.4 1080.04 60.62 0.3597 0.22 2095.1 2095.1 1109.15 60.50 0.6512 -0.27 2145.0 2145.0 1134.48 60.06 0.5076 -0.68 2174.7 2174.7 1152.96 67.17 0.6222 23.94 2320.3 2320.3 1226.01 69.14 0.5017 1.35 2350.3 2350.3 1244.42 69.53 0.6137 1.30 2371.1 2371.1 1259.22 69.79 0.7115 1.25 2399.9 2399.9 1276.95 70.16 0.6156 1.28 2450.0 2450.0 1307.07 70.74 0.6012 1.16 2800.1 2800.1 1484.61 74.35 0.5071 1.03 ru~ri ~i~ps ~ ~r~e r in -0.2 -0.2 132.76 51.90 - - 2050.4 2050.4 1038.66 61.49 0.4418 0.47 2095.8 2095.6 1060.31 61.61 0.4790 0.27 2145.2 2145.2 1083.58 60.87 0.4692 -1.49 2175.0 2175.0 1099.27 67.09 0.5265 20.87 2320.1 2320.1 1169.87 69.11 0.4866 1.39 2350.7 2350.7 1186.50 69.51 0.5435 1.31 2371.3 2371.3 1197.70 69.75 0.5437 1.17 2400.6 2400.6 1213.35 70.16 0.5341 1.40 2450.1 2450.1 1239.12 70.71 0.5206 1.11 2800.8 2800.8 1408.43 74.34 0.4828 1.04 ~~ Report date: 9/9/2008 Aurora II: Aspen # 1 Field: Asp Date: 08-31-2008 ~ i Pressure (psiaj 950 1000 1050 1100 1150 1200 1250 1300 1350 1400 1450 1500 2050 Pressure-Temperature Profile 2100 - - -- - - - 1. POOH 2800' to 2050" RKB ~I ~ After Inj 2150 'i - - - - i I 2200 I I ~I 2250 __ -- - _ ~ i - 2300 - - - - I 2350 - - _- = - ~ -_~_- .-. ~.+ y 2400 _ - w ~ -- ... 2450 - -- S '. ~i ~+ ~ 2500 - - - 0 2550 ---- -,', i -- ---- - 2600 -- ~ i 2650 - -- - - 2700 -- ---- --- ~ II ~ - - -- - 2750 - - - -- i 2800 2850 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 71 72 73 74 75 76 77 78 Temperature (Deg. F) Pressure - Perfs ~~-~___,9-5l8" 13 3/8" 5-1/2" 2 7/8" Temperature) Report date: 9/9/2008 Aurora II: Aspen # 1 Field: Asp Date: 08-31-2008 200 400 600 800 1000 1200 d 1400 O r 1600 ~.+ C. d 1800 2000 2200 2400 2600 2800 3000 48 50 52 54 56 58 60 62 64 66 68 70 72 74 76 78 Temperature (Deg. F) ------- Pressure - Perfs -~°~~ 9-5/8" 13 3/8" 5-1/2" 2 7/8" Temperature __ Report date: 9/9/2008 Pressure (psis) 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 0 Aurora Well: Aspen # 1 Field: Ash Pressure -Gradient (psi/ft) -0.4 0.0 0.4 0.8 0 200 400 600 800 ~ 1000 1200 ,~ ... m v 1400 O o, 1600 m O 1800 2000 2200 2400 2600 2800 3000 08-31-2008 1.2 1.6 -15 -10 -5 0 5 Temperature -Gradient (Deg. F/100 ft) L Press Gradient - Perfs Temp Gradient 10 Aurora Well: Aspen # 1 Field: Aspen 08-31-2008 Pressure -Gradient (psi/ft) -0.4 0.0 0.4 0.8 1.2 1.6 0 200 I aoo soo i ~ soo i 1000 1200 :. m ~_ 1400 D fl, 1600 m O 1800 2000 2200 2400 2600 2800 3000 Pressure-Temperature Gradient Profile 1. POOH Inj - -_ --- - - -_~ 3 i -15 -10 -5 0 5 10 Temperature -Gradient (Deg. F/100 ft) ~_Press Gradient - Perfs -Temp Gradient) MEMORANDUM ~ State of Alaska • Alaska OiI and Gas Conservation Commission DATE: Wednesday, September 03, 2008 TO: Jim Regg ~ ,. j~~ ~ ZGfl ~> P.I. Supervisor { ~ SUBJECT: Mec a n egri es s (~~;~ ~~~ ~ ~ ~`:>'~- [ AURORA GAS LLC ~J 1 FROM: John Cnsp AsPEN t Petroleum Inspector Src: Inspector Reviewed B._y-~ P.I. Suprv J1~- NON-CONFIDENTIAL Comm Well Name: ASPEN 1 API Well Number: 50-283-20 1 1 4-00-00 Inspector Name: John Crisp Insp Num: mitJCr080902 1 1 1446 Permit Number: 2os-111-o Inspection Date: 8/29/2008 Rel Insp Num: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well ~ Type Inj. N I TVD 2a6o I IA ~ o tsoo ~ ~ Faso i ta2o ta2o ~ ta2o p.T. 2ost t to TypeTest ~ sPT~ Test psi t soo OA I o o I o o j o j o Interval oT~R p~F P Tubing j o o ~ o ~ o o ~ o Notes' This well is Aspen # I . A suspended produc er being converted to a Disposal well. PTD 205-11 1. Perforations from 1368' to 1388' & 1760' to 1770' were cement squeezed. Cement was drilled out & CIBP set @ 1779'. I witnessed a press ure test of 5 i/2" casing & cement squeezed perforations. ~~~,NN~~ Sys :~ ~ ?00~ Wednesday, September 03, 2008 Page 1 of l • 9~9~ Stcxm tfxlga looms n GOh+1, 3 pamm~s arirrg tgs evap,atm t ~ ~ ~~~ ~~ ~ ~ ~:p ~t ~`~- ~~• ~ _. _ ~`-~ a':..~: On the road a sin AS t~~h~1- ~ '-t l \ 00 after iti+o-vest pause aurora (was starts rs Ct>ok 1 r.}i't driril.g program o 0 y IYAN UUFV Pe^:slrlmt ~exs = :~ The 2006 drilling shut- ~ • ' ~ , ~ '._ d,.wn n:sulred from bttsirtcss • C t was (A tobcr _ when 006 .. .._ ertaroty- associated with ' Aurnn Gas put Its ARS ~ ...v. h ~ ~ I drilli i ~ y. ,snmwithtacarlSattual ~ . - g m[o ng r - ~? .~ ~ ' " Co-, the main W m. hFalls alts sta,ral ~ G ~~ -~[ttcxattral AlLSka gas utili- Cn seas c years ofdrilling amwtd a ~ - lurota Gas said at the Alaska's Cork Inlet. 1Vuu, : n: of the shutdown And ~{ slier tteatfy two years, the xort t~F ~ l6!kS i.at. Y Francis Oil Co.. 90 tt>trtpany has rtrnmrnrnctd percrnt owrter of Atrtttra Gas, dcveh,ptrtcnt drilling in ics clusts~ of gas fields on dct:idcd it w'as tm lonerwilling ro inve¢ tttotrcy in the west side of the inltx, the rnmpatry announce the Cook Inks. AU_L'- ~'- I ' ~ I We art committing approxirnately 57.2 million 00 tlSO m hi R t s rcrtewsd effort ro find and devebp mort gas But tht tnsta litittation ~- a krwsui[ tevvlrutg in Cwok Ink~t." said Aunxa Gas Presidrnt Scutt see Itl/tOM GAS pale t9 rnor signs session bills Alaska has storied ++eaiher-sensitive worn on gas pipelin~ ~. 10lIS161 '"". The August eQttsetrt of North or 6Q M a'9 News +5 erxtosed Prnakunt .Vev:s ~' '°~ t ,ITn-ial. Cn,c. Sarah P~ ' Exxon rules the roost: Taking Y. I r, xigtred bins pasxd ~ over offshore Hebron o ect `~[` "~ I.emslaturc ' ,t sixcial scsston in ca~ ~ 1\'heiltY yew tiwt[dt3rai P[entia fku,n~ :1ucu~t smarting TtansCan~ I r, , N illiams like's it .x nLK Esxsxtt#obil ~- the - \I.iska on its w-sy towar~: ~ ampam- that sass seta him inw a rtgi[,g P`r'p°w'd gas pipclirte Gum [ S:+tr.. ~ iIN fun- over the txeakdown of rn'2e,*.iatx,tts cr. \~ Sbpc m rttariet an.; hst'at [cams for tln nftsluxc Ik'#Am n - ' " P lot Pri'aitting relief for ALtskans fmm thc• high co of .,; - has takrn an cvtxt tights g^ip -.. ,i•: `°~'-a'- pmvuict's ps~ntkum rashes. the ~govxrttor signal bills for an etrcrQy tthaac it will cam take oa,t ttre opcraux ::r-ic ~ anti rcla[al marstacs:Aug. 25. at Hehrtm tn,m Che.mn Carada pas .Aus. 27 at an Alaska ,AFL-CIO tt,nft:true in Rewtttres, c~urding its Irad posinut in the QAfRiIT INBlIANS llibcmin freld. AlthoU_lt tt0 d;uc 11L hC171 ; Y fOr dtc handles LY, d ith`a'nxl gxtkamtn ~id m a sa3at~nr it will h< `in as ~reh a ntartner First hexa-la s pl~~..i,le;' iaa3iatnna it will oex[tr in weeks natter than months. Srtergies utittl -~ BP targets Schrader Bluff viscou nil. I1C sad that bceau~ L%I 1[L~#t>DII ne'LC IItC i(MTN' al Ih~hCRUa (~. ~~ C -~:lxtrage tae si, the M~1 - - ,nmv;rsQ the i. - of an 1laska Gash nducanrnt - - la:asew TmnsC ahhough it n't e its :AG1A licettsc ;.rap ys, has already stag ~.~a er-srnsititr wor{; in ;\ . ' ,wilt the seal of com- iONT PAt)rfflt ~ g sat open season within iaa~ sears. The perms ofAG41 Prt,~,:;~ that - onW pays a share of rtim- Lwnat>k e. ~ afla the AGLA liamt is issued; becatnt ivn did not rtt'.J:c the kgis6tiun cer LLIS page 13 oral ' Alaska drills Prud;;t~e t+ 1 +\ith siK sidetracks `No ones actually tligre thts before." ells and nsavoirs art lik~ ~cvs and locks: of lWsia tftio~aal b ~4 AIyCSI[0 taktts nest ftep_ : ~ ~ k.;, : r c e.=+ tr am-Alaslw poop's ~tat[P Station 9 nftti a. ra-_ ... ~..... ->i::aaratcr am k w wuti t da: it has fit perfectly. - To unktcl: the star cards of the Orion multi-lateral trcltnologv far decades, rn mic ttxt- oi! plwl within tare ' radcr BIutL a gtt~bg,- ~~ Invt ~~, ~~, ttcade it ptt kin rc fi,rtnarion on Alaska's onh Slope, engin~vs al Alaska, whore curtt4suti~ have used it ui ebt, BP trecdo[I a sptrial k ~ . So this spring and sutrttrter ~~ ~ ~ widt Scleatltt Bluff forrnatioa they drilled L-205: ~ first M:~ta-lateral well in the StiI1, with eight tnombs of plamtirtg, alrttost ha ~- std a half tttomtlts of drilling 29,000 fiat of rnostly A bras-tat is otre well with si'c underground hurinattal PPc std a nearly SI9 trtillian price tag hrattcla<,a--i. • idevac-s. For L-205. this ttteaa.~ sir ~ L-2(K Item-Iatrral well is atrtatg the m>st parallel w .,one lrebw the other, taelt stn.-tchhtg exprnsn~e std tt>nplez wells ever drilled in horizon y inm sic differtrtt uil-hcaing sarxLc ut ~re the ~ Bluff forrrtation. dn,ugh dtillc9s atotmd the world have used see IEXAa1RERAi paKe !8 Vd.13, Na 35 • rrwna.PetroleumNews.twm A weekly oil R gas newspaper based in Anchorage, Alaska YYee1t tNAlgust 31, 2008 • 51.50 Latest Mining News issue inside \\~ ~/ v ~~ PEfROI.EI;M NEN•5 • VYFEN ~ AUGUST 37, 21108 -c.uca:~~~I `mm page AURORA GAS around Auroru Gas's suspension of gas supplies to Ensror because of what Aurtxa Gas characterized az uneconomic gas prices -was settled of April ?OOR. Gaz prices in the Cook Inlet region arc on the rise. And Kaiser Francis has agreed that the time has come to invest further in Cook hdet, to increase dehvembilih~ of gas from Aurora Gas's fields and prex'rve d1e invcsnncnt in those fields, Pfoff told Petroleum News .Aug. ?5. "We've settled with Ens'tar. W'e kel like prices are benez" Pfofi said. "So projects that looked maybe on the Cettcc a couple of years ago bole much more attractive now that w~ can cct market prices for our gas." "4t(e've settled with Enstar. We feel -ike prices are better. So projects that It7oked maybe on the fence a rnuple of years ago Look much more attractive now that wm can get market prices for our gas. -Ataara Gas PrasiAeil Smtt P-afl Pfotf declined to say who will buy his company's new gas but said that Atrrora Gas is negotiating with several compa- nies that are willing to ender into agree- ments. And althnugh there is uncertainty about future Cask inlet prices, the move- ment rowattLs higher pricing in the region should make the development drillin_ viable. " "We think we're going ro be able W successfully markM all dte gas that we drill up at prices that are going ro give us a good realm on our investment." Pfoff said. AWS f9o. 1 rig deployed Thc AWS No. 1 rig haz already becro deploytd to the west side of Cook Inlet and is in the process of re-entering the Ascen Nu. t well, Ed Jones, Aurora Gas's executive vice ptesidr-nt engittcer- ing-operations, told Petroleum News Aug, 26. Thc Aspen well was an unsuc- cessful explorazion venture for Aurora Gas in 2005 and the tympany is trove convening the well into a disposal well for water and drilling mud. Thc various production wells that Aurora Gas operates ate gradually deliv- ering more water along with the gas, Jones explained. The company has been using tanks to evaporarc water and lined pits W store water, but these techniques arc barely keeping up with the water pro- duction. "W'e're able to manage nigh[ now by shutting some wells in and producing them only occasionally W keep water volumes under control," Jones said. "But we'd like to be at such a place that we can produce any will at any time and have a way to get rid of the water." A vacuum truck will tarty wa0.v W the Aspen well, which is locau'd at a fairly central posirion relative ro .4urom Gas's fields Aurora Gas also plans W use the Aspen well ro dispose of drilling mud. "This will cut our drilling costs a fair amount," Jones said. At present [he company disposes of mud using techniques such az setting the mud in cement and putting the solid ccnxnt blocks in a landfill, he said. Devebptttettt drildttg After completion of the drilling oper- ations at Aspen, probably at the begin- ning of S~tcmber, the AW'S No. I rig will m~complete the Three Mile Crcek No. 2 well in the Three Mile Creek field by perforating uime new zones in the well. "it's never performed exceptionally well ... so we are going to add some per- forations ... in hopes of increasing our volumes;' Jones said. The rig will then drill two new devel- opment wells in the Lonc Creek and Moyuawkic fields in (k;tober and early November. Aurora Gas's other two fields, Nicolai Crcek and Kaloa, du nut figure in the 2008 drilling program. At Lone Crcek, which Junes charac- terized as Aurora Gas's best field ro date, the comparry plans to drill the Lonc Star No. 4 well to the north of the rrarent wells. The new Mtpuawkie well will replace the M.quawkie No. I well that was orig- inally drilled in 19b5. In developing the Mtrqunwkie field Aurora Gas rs ena'nd the No. 1 well but there ate probl~7rts with the well casing, Junes said. "W'e're movms up dip a little bit and away from the well W hopefully have another good la:ation," Junes said. Iltwking the new wells inW the exist- ine facilities should take shout six weeks, so that the rtew wells should go on line early im ?009. Jones said that the new wells at Lone Creek and Moyuawkie are expected to each produce at (cast i million cubic feet of gas. The work at Thr<r Mile Crcek should result in another I million cubic feet per day of production, he said. In face az much as 14 million cubic feet per day of additional gas ddivcrability is possible from the drilling progratr~ hi: said. No ettpktratian planted Aurora Gas dots trot have any current plans for new exploration drilling. "It's not at the top of our list." Pfofl said. `I don't sec any pure expbration projects that we would do on our owe in the near fuWre." Thc company still has a joint venture agreement with Swift linergy Co. W see AIRORl1 GeS page 20 /9 Your environmental, engineering and sustainabiliry partner. ~. ~ ~ !,~i c~nwnmaNnes¢,et,a~ ~ "i' . _ Femtltn9 and Cmtp6aace Rttmedation and Raltabiita9on Wati0rral E/NOpM1[BllfB~ ~' Act Contact. wad Peterson attlusOW eutineasT mManager ll~/ i w ENGINEERING ENVIRONMENTAL • KUUKPIK • ~LCME ca`~,..~ u # srrn;es. uchuecture engineering ~. surveyipq:. # ~ s ~„r ,.;~Rrufact rrta$agemeat # io ~. aLw trK„ '. !pwt_x ,^AIR LIQUIDS WELDING SUPPLIES Lincoln Miter Mihraukee S[OOdy Tweco Thermal Mathey ESAB Norton & Yrctor Gas Et7u~ment CYLINDER GASES Ytdtsbiet B4~es/redd FFaat,cavtY MEres. A7efiCal aced Sbaeiaay Lyfriders fd rmr. tease. std pudease BULK LIQUID GASES cxyyE . nrvo~. n.gat. came aa.w.. and ay rye free 800 476.1520 2 rage-6C I5 M9r>DM.•9075611f_'v'bJ .. r ora - 7U89 Van Mon Mil • `a07 l5, a78: ~: ~ ~y~y~,~~_ r"y ':-~ ~_itaixenocr•sarrsse~t ~ - w. r s. t sn~a Mrrr. • eor zas.rtsa at tim tISSl~rMr.• 9e7895.t86r ~: _ ~~ I ....~'~'' ~'~ UDELHO~'] Oilfield S~sttm Jervkes. ServingAluska for over 30 years... ~ Mxhaniwl & Electrical ktspectiort ~ Cottunissaning & AS-Built Pragrattts ~ Rt~tramp ~ Furtctional Qtedc-0trt ~ Ir~trstrial & Moc>ular Fabrication ~ Consfixtion: Mechattiol & Electrical 1 Process Pipetg ~ WeM'ing Arrdwrage ph: 907-344-1577 fz_ 9o7-szz-zstl r8kiski ph: 90T-77fr5185 &: 907-77(i-8105 -rtrdtce Bay ph 907fi59-8093 6r 907LS9-8489 www.ude8roven.com Aurora's AWS-1 rig. zo PF-TKOLEtI~I NE\VS • WEEK OF AUGUST 31, 2naa from page 1 ~,~~~~ "rhrrt re synergies tha[ can be capttmcd by h:r. m also opcrnte I lebron." ":\I I lers havt been no[iti~d and al in agn~cmc dwt this needs to happen s Finally something that expcditionsly possible." [xsonMobl already has dle r3mst really saves you time... stake in 1{ebm at 36.04 pc • lt, with Chclron at ?6.63 rcent, P anada 3,.1; percent and S oillly a[ 9.7 per- salt. The hewfoundla vcmmcnt will And it's FREEI take a 4.9 percen[ i°" nntk~r `" ncvvly negotiated agreement. I Icbroa discov in l I. ha' up to 7110 million bt s of tern . blc crude and could, base on industry esu arcs. cost about CS7 b~ ton to develop and ring on stream in' 16-2018 at 150,000 ba Is per daY, eI Ugll du Wllllams gOVC Clll putt esdmate in the ranee of CS4 ~I- i ', ~ ~~~1 i ~ ads / 1~id0i r i~i ~sit~~~ ~ iw.~r ~~~/~i~~6rii • ~ ~~~ra~c~a: ~ i:Z PAYMFI+~/G ~, ~~~~i~ 1 ijt'~1~~ 1~ ~~~ -. rf ~S~° ~ ~ •_ i billion. ExxonMobil is not rea le art updated estimate. -GARY PARK continued (mm pa;Ge 19 AURORA GAS explore :aurora Gas acreage, Pfoff said. Under that agreement, Swift has a 50 pcvicent interest in sev~'ral Aurora Gas exploration prospects and would fund 50 percent of the cost, were the companies to decide to drill an exploration well. The joint venture drilled a dry oil wildcat well in the Hndeavour prospect, near Anchor Point on the southern Kenai Peninsula, in April 2W6. But because of Aurora Gas's subsequent litigation problems and the shift of Swift's attention into some acquismons and divestitures elsewhere in the world, both compa- nies became diverted from discus- sion of further Cook Inlet explo- ration drilling. Aurora Gas also still has afar- moutagreement dating back w 200> with Trading Bay Oil and Gas rcla[- ing to the Hunna prospect on the west side of Cook Inle[. An initial plan to drill at l lanna was prutponed in ?006. '"That farrnout agreement is still in place;' Pfoff said. "We would like very much to drill that prospect." Flowever, Aurora Gas has been unsuccessful in finding an altema- [ive to Kaiser F'rnncis to fund explo- ration and dues nut currently have fimdine fix any new exploration drilling. In fact, for the past year and a half, Aurora Gas has been trying to find someone m buy out Kaiser Francis's ownership position in Aurora Gas. "We've not been successful in finding anybody who is the right fit that was willing to pay thn price that we feh the company was worth." Pfoff said. So, unless Kaiser Francis has a change of heart wi[h respect to im~csting in Cook Inlet cxplomtion, Aurora Gas will aced a partner for explorndon funding -the company is looking for a partner to participate in some form of tarmout artangc- ment, Pfoff said. But with the AWS No. l rig rotat- ing adrill bit again in an Aurorn Gas project. things have taken a definite rum for the better. "We couldn't be happier ro he back drilling;' Pfoff said. • Page 1 of 1 AAaunder, Thomas E (DOA) From: Regg, James B (DOA) Sent; Tuesday, August 26, 2008 7:48 AM To: Maunder, Thomas E (DOA) Subject: FW: Leak okk test Jim Regg AOGGC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 ~ ~ ~ - l 907-793-1236 From: Romey Newton [maiito:sirromeyo@yahoo.com] Sent: Saturday, August 23, 2008 9:48 AM To: Regg, James B (DOA); DOA AOGCC Prudhoe Bay; Fleckenstein, Robert 1 (DOA); Ed ]ones; David Boelens; Chad Helgeson Subject: Leak okk test This is an the Aspen well. We drilled cement F/ 1234' to 1373' and put 1500 PSI on the perfs and held for 1/2 hr and it dropped 1201bs.Which is less then 10% that the commission required. Please let me know immedatly if your not satisfied.My # 907-632-0083 Thank you Romey 8/26/2008 l Page 1 of 1 _ ~P~ ~ ~ Regg, James B (DOA) ~T--~ 2p~ _ ~~ ~ From: Romey Newton [sirromeyo@yahoo.com] ~ ~. ~=` ~'-~ Sent: Saturday, August 23, 2008 7:19 PM To: Regg, James B (DOA) Subject: FW: chart Attachments:8-21-08.pdf ~ ~Q~t~ ~~~ Aurora Gass Test chart on Aspen #1 well. Romey --- On Sat, 8/23/08, susan burkham ~susanandobrent@hotmail.com> wrote: From: susan burkham <susanandobrent@hotmail.com> Subject: FW: chart To: "Romey Newton" <sirromeyo@yahoo.com> Date: Saturday, August 23, 2008, 7:09 PM '~ +~~~ ~~~ a ~ 2~~8 From: susanandobrent@hotmail.com To: sirromeyo@yahoo.com Subject: chart Date: Sat, 23 Aug 2008 18:57:59 -0800 Get thousands of games on your PC, your mobile phone, and the web with Windows. Game wth_ Windows Talk to your Yahoo! Friends via Windows Live Messenger. _Find_0_u_t How 8/26/2008 ., ~ ~ ~_ ~~~~~~ r~,.~i. a y., . 3~ r ~ ~ .~t ' ~~ Page 1 of 2 • • Maunder, Thomas E (D4A) From: Maunder, Thomas E (DOA) Sent: Tuesday, August 19, 2008 4:39 PM To: 'Bruce D Webb'; 'Ed Jones' Cc: DOA AOGCC Prudhoe Bay Subject: FW: Revised Aspen 1 (205-111) Procedure Attachments: 2008 Re-Entry and Test Procedure.doc Bruce and Ed, I have compared this latest document with what was approved with sundry 307-172 and they are substantially the same. As Ed notes, this revision includes more detail. Nothing further is needed at this time. I will place a copy of this message in the well file. I have spoken with Jim Regg and we will not have an Inspector available tomorrow. If the BOP is tested tomorrow, witness is waived. Please plan to record the test. There are a number of pressure tests planned during this re-entry and completion. Please keep the Inspector's apprised of your progress. You should plan to contact the Inspector for the pressure tests in step 6, although successfully getting to that step is dependent on prior tests as the re-entry proceeds. I am copying the Inspectors with this message and the procedure. Call or message with any questions. Tom Maunder, PE AOGCC From: Bruce D Webb [mailto:bwebb@aurorapower.com] Sent: Tuesday, August 19, 2008 4:18 PM To: Maunder, Thomas E (DOA) ~,~~ A~~ ~ €~ ~~~~ Subject: FW: Revised Aspen 1 Procedure Tom, Please see Ed`s message below. From what I understand, we are starting well operations tomorrow including BOP testing, which will lead up to the other testing in a few days. Thanks, Bruce From: aurorapower@gci.net [mailta:aurorapower@gci.net] On Behalf Of Ed Jones Sent: Tuesday, August 19, 2008 1:54 PM To: sirromeyo@yahoo.com; ']ON ROBERTA WEST; 'Chad Helgeson'; 'Bruce D Webb' Cc: 'David Boeiens'; 'G Scott PfofP Subject: Revised Aspen 1 Procedure Gentlemen, Attached is a slightly revised and more detailed Procedure for the Aspen 1 Re-Entry. Please review and let me know if you have questions, suggestions, or concerns. Bruce, please clarify with the AOGCC when they want to witness tests of tubing and casing, as we'll have to do a Mechanical Integrity Test after we have started injection. Thanks, Ed Ed Jones 8/19/2008 • • Aurora Gas, LLC ASPEN #1 DISPOSAL WELL 2008 RE-ENTRY AND TEST PROCEDURE CAPACITIES: 2-7/8" Tubing: 0.00579 bbl/ft and 5-1/2" 15.5# Casing: 0.0238 bbUft 5-1/2" Casing X 2-7/8" Annular Volume: 0.0158 bbl/ft. Casing Drift ID is 4.825" Tubing ID=2.441 ". Drift ID=2.347". Casing vol. to PBTD of 2891':69 bbl. 8.5 ppg KCl-NaCI brine left in casing KB= 15' above GL (all depths from KB). TD=4485'MD/TVD CURRENT CASING RESTRICTIONS: 160' (19 sx) cement plug at 1265-1373' Cmt Retainer at 1714' 8-sx Cement Plug between retainer and CIBP CIBP at 1779' 10-sx Cement Plug at 2891-2977'-we plan to clean out to top at 2891' CIBP at 2950' (?) RBP at 3843' (?) Casing Float Collar at 4355' EXISTING PERFS: 1368-1388' and 1760-1770' --Squeezed with cement 2125-2145' and 2351-2371' -Open-proposed disposaUinjection 2984-2994', 3006-3026' below plug 3444-3454', 3491-3506', 3811-3831' -below plug 1) Move in, rig up AWS #1 rig w/ single workover pit for mud system (not AG mud system) and support equipment only as needed. 2) Starting with clean mud tank, haul 150 bbl (usable volume) clean produced water from tanks at Moquawkie or Kaloa locations. Add 40# of NaCI per bbl of produced water to raise weight to 8.9+ppg. RU Quadco PVT system. 3) Confirm that well is dead. (If not, must kill by "bullheading" brine into well thru master valve). ND dry-hole tree, NU 3000-psi BOPE. Test to 2000 psi (as required by AOGCC Sundry approval-notify AOGCC 24 hours in advance to witness). NOTE-BOPE must be tested every 7 days. 4) Test casing to 1500 psi. (Casing will have to be tested again and witnessed when clean out in Step 6 is completed). 5) PU 4-3/4" bit, Junk Basket, 12 3-1/8" drill collars, and 2-7/8" tubing, run in hole to about 1260' (or until fill is encountered). RU Power Swivel and circulating lines. RIH to tag cement plug at 1260-65' (or fill above it). • • 6) Drill cement f/ 1,260-1373' (+/-). (:Set torque limits on po«°c;r s~vi~-el tc~ avoid twist o ~1~. Circulate clean. Test casing to 1500 psi-call if pressure does not hold. RIH to retainer @ 1,714'. Drill retainer & cement to CIBP @ 1,779'-DO NOT YET DRILL CIBP. CBU--Close Pipe Rams & verify integrity of squeezed perfs by testing to 1500 psi for 30 minutes on chart recorder. If pressure does not hold, call in, squeeze procedure will be provided. 7) Drill CIBP and circulate clean. RIH and clean well out to cement plug at 2,890'. If bit doesn't drill retainer and/or CIBP, POH and PU mill. 8) Monitor well & POH w/ 2-7/8" tubing. LD collars & bit w/junk basket. 9) PU 5-1/2 X 2-7/8 Weatherford Arrowset (AS1X) Packer with 10' pup, XN nipple, and WL-entry guide on bottom, and On-Off tool on top. TIH to 2,000' on 2-7/8 8rd EUE Tubing. Set Packer @ +/-2,000'. Pressure test tubing casing-annulus to 1500 psi for 30 minutes, recording pressure (AOGCC to be notified 24 hours in advance to zvit~~ess~`). 10) RU Pollard and set plug in XN nipple. Pressure test tubing to 2500 psi for 30 minutes and record pressure on chart. 1*~otify AOGCC 24 hours ir$ advance of testa Run slick line and retrieve plug. Run base temperature using Pollard memory temp. log tool (3 passes 15 minutes apart). 11) Rig up to pump down tubing w/ rig pump. Perform 4-point step-rate test w/ clean produced water (record weight and temperature) as follows. Do not exceed :1500 psi. Record test on chart recorder: a) Pump produced water at'/4 BPM for 60 minutes or until pressure is stable for 15 minutes (a minimum of 30 minutes); b) Pump produced water at'/2 BPM for 60 minutes or until pressure is stable for 15 minutes (a minimum of 30 minutes); c) Pump produced water at 3/4 BPM for 60 minutes or until pressure is stable for 15 minutes (a minimum of 30 minutes); d) Pump produced water at 1 BPM for 60 minutes or until pressure is stable for 15 minutes (a minimum of 30 minutes); e) Stop injection /Shut in well-record pressure as it falls off until pressure is 0 psig or stabilizes for 30 minutes. While SI, RU Pollard and run memory temperature log, being careful not to relieve any pressure on well. Make several passes-1 every 15 minutes. Total time for test: +/- 5 hours. Total volume to be pumped, about 120 bbls of produced water. If pressure reaches 1500 psi, slow rate to keep below-record new rate. Submit data to Anchorage office for approval by agencies. If rates are too low and/or pressures too high, we may need to add perforations AOGCC approval would be required. If so, we will likely drill out cement plug and CIBP at 2891 'and below. 12) Release packer & reverse in 31 bbl of corrosion inhibited brine. 13) Set packer, test tubing-casing annulus to 1500 psi*, & land tubing. Install BPV. 14) ND BOPE & install tree. Test annulus to 1500 psi. Release Rig. Hand well over to production for commissioning. NOTES: 1) A Mechanical Integrity test must be run after injection has commenced and conditions have stabilized-the annulus is to be tested to 1500 psi for 30 minutes with no more than a 10% change in pressure. The AOGCC is to be notified 48 hours in advance of the test, and a written report is to be submitted within 7 days of the test. * This maybe the only test that the AOGCC wants to witness other than the BOP test. (Bruce, please ccrr~fifrrc-a,r;, trtic tli~rra %~'thc~y raE~e~t try w~t~ze~s ttie tests i Steps , 1(1, ~r .1 ~.) 2) Mechanical integrity tests are then to be performed every two years thereafter. 3) Injection pressures and rates are not to exceed 1500 psi and 1 BPM. 4) A temperature log is to be run 1 month after commencement of injection. 5) Daily well head pressures must be taken and documented. 6) An annual report of the performance of the disposal operations must be submitted by July 1St of each year. Jack McDade (2007) Revised --Ed Jones 8/18/08 4 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue,Suite 100 Anchorage,Alaska 99501 Re: THE APPLICATION OF Aurora ) Disposal Injection Order No.32 Gas LLC for disposal of Class II ) oil field wastes by underground ) Beluga Formation injection in the Beluga Formation ) Aspen No. 1 Well in the Aspen No. 1 Well,Section 33, ) T12N,R11W, S.M. ) February 7,2008 IT APPEARING THAT: 1. By correspondence dated August 17, 2007 and received by the Alaska Oil and Gas Conservation Commission ("AOGCC" or "Commission") August 20, 2007, Aurora Gas, LLC ("Aurora") requested that the Commission issue an order authorizing underground disposal of Class II oil field waste fluids into the Beluga Formation through the Aspen No. 1 ("Aspen 1") well bore. The Aspen 1 well is located in Section 33, T12N, R11W, Seward Meridian("S.M."), on the west side of Cook Inlet,Alaska. 2. Aurora originally submitted information to the Commission on May 15, 2007 concerning the proposed disposal injection. A letter sent to Aurora dated July 17, 2007 outlined additional information required before accepting for public notice and comment an application for the underground disposal of Class II oil field wastes. Aurora provided requested information to the Commission on July 18,August 10, and August 17, 2007. 3. Notice of opportunity for a public hearing was published in the ANCHORAGE DAILY NEWS on September 5, 2007 in accordance with 20 AAC 25.540. 4. The Commission did not receive any public comments, protests or a request for a public hearing. Disposal Injection Order 32 Page 6 of 8 Aspen No. I February 7,2008 6. Disposal operations may result in the formation of calcium carbonate scale or precipitates. 7. Surveillance of disposal volumes, daily monitoring of operational parameters, and demonstration of mechanical integrity will reasonably assure the continued mechanical integrity of the well and that waste fluids are contained within the disposal interval. 8. Disposal injection of Class II wastes into Aspen 1 will not cause waste,jeopardize correlative rights, impair ultimate recovery, or contaminate freshwater. NOW, THEREFORE, IT IS ORDERED THAT disposal injection is authorized into Aspen 1 subject to each of the following conditions: RULE 1: Injection Strata for Disposal The underground disposal of Class II well oil field waste fluids is permitted into the Beluga Formation within Aspen 1 in the interval between 2,125 feet and 2,371 feet MD. The Commission may immediately suspend, revoke, or modify this authorization if injected fluids fail to be confined within this interval. RULE 2: Fluids This authorization is limited to Class II waste fluids generated during drilling, production and workover operations. The operator shall treat the injected waste fluids to minimize the formation of scale or precipitates. RULE 3: Injection Rate and Pressure Disposal injection is authorized at(a)rates that do not exceed 1 barrel per minute and (b)surface pressures that do not exceed 1,500 psi. RULE 4: Demonstration of Mechanical Integrity The mechanical integrity of Aspen 1 must be demonstrated before injection begins and before returning the well to service following a workover affecting mechanical integrity. A Commission-witnessed mechanical integrity test must be performed after injection is commenced for the first time in Aspen 1, to be scheduled when injection conditions (temperature, pressure, rate, etc.) have stabilized. Subsequent mechanical integrity tests must be performed at least once every two years. The Commission must be notified at least 48 hours in advance of each such test to enable a representative to witness the test. Unless an alternate means is approved by the Commission, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1,500 psi, or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater,that shows stabilizing pressure and does not change more than 10 percent during a 30 minute period. A written record of the results of all mechanical integrity tests must be provided to the Commission within 7 days of test completion. . .r Disposal Injection Order 32 Page 7 of 8 Aspen No. 1 February 7,2008 RULE 5: Well Integrity Failure and Confinement Whenever any pressure communication, leakage in any casing, tubing, or packer, or lack of injection zone isolation is indicated by the injection rate, an operating pressure observation, a test, a survey, a log, or any other evidence, the operator shall notify the Commission by the next business day and submit a plan of corrective action on Form 10-403 for Commission approval. The operator shall immediately shut in the well if continued operation would be unsafe or would threaten contamination of freshwater, or if so directed by the Commission. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating well integrity failure or the lack of injection zone isolation. RULE 6: Surveillance The operator shall run a baseline temperature log and perform a baseline step rate test prior to initial injection. A subsequent temperature log must be run one month after injection begins, to delineate the receiving zone of the injected fluids. Surface pressures and rates must be monitored continuously during injection for any indications of fracture height growth. The results of daily wellhead pressure observations in Aspen 1 must be documented and available to the Commission upon request. Subsequent temperature surveys or other surveillance logging (e.g., oxygen activation and acoustic) will be based on the results of the initial and follow-up temperature surveys and injection performance monitoring data. A report evaluating the performance of the disposal operation must be submitted to the Commission by July 1 of each year. The report shall include data sufficient to characterize the disposal operation and include, for example: pressures (daily average, maximum and minimum); fluid volumes injected (disposal and clean fluid sweeps); injection rates; an assessment of fracture geometry; a description of any anomalous injection results; a calculated zone of influence for the injection fluids; and the assessment of treatments to remediate scale and precipitates. RULE 7: Notification of Improper Injection The operator must immediately notify the Commission if it learns of any improper injection. The notification requirements of any other state or federal agency remain the operator's responsibility. RULE 8: Administrative Action Unless notice and public hearing are otherwise required, the Commission may administratively waive or amend any rule stated above as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in fluid movement beyond the authorized injection zone. t M 7 Disposal Injection Order 32 Page 8 of 8 Aspen No. 1 February 7,2008 RULE 9: Conditions It is a condition of this authorization that operations be conducted in accordance with the rules set out in this order, AS 31.05, and (unless specifically superseded by Commission order) 20 AAC 25. Failure to comply with an applicable provision of AS 31.05, 20 AAC 25, or these rules may result in the suspension or revocation of this aut I rization. DONE at Anchorage, Alaska, and dated Feb.. :r A 008 la's , ,► ` �� ''411 Jo W C orm: , Comte'r ✓t.G `.. .r ).v; i 4'� �c, `e:!! Cathy P oers,t2;&V/4--- ommissioner AS 31.05.080 provides that,within 20 days after written notice of the entry of an order,a person affected by the order may file with the Commission an application for reconsideration. To be timely filed,the application must be received by 4:30 p.m.on the 23rd day following the date of the order,or the next working day if 23rd day is a state holiday or weekend. The Commission shall grant or refuse the application in whole or in part within 10 days. The Commission can refuse the application by not acting on it within the 10-day period. A person that submitted an application for reconsideration has 30 days from the date the Commission refused the application or mailed(or otherwise distributed) an order on reconsideration,both being the final order of the Commission,to appeal the decision to Superior Court. Where an application for reconsideration is denied by nonaction of the Commission, the 30-day period for appeal to Superior Court runs from the date on which the application is deemed denied(i.e., 10th day after the application for reconsideration was filed). 4 ~ ~ ~,4 ~ ~ DATA SUBMITTAL COMPLIANCE REPORT 10/16/2007 Permit to Drill 2051110 Well Name/No. ASPEN 1 MD 4485 TVD 4485 Completion Date 9/6/2005 REQUIRED INFORMATION Operator AURORA GAS LLC Completion Status SUSP Current Status SUSP API No. 50-283-20114-00-00 UIC N Mud Log Yes Samples No Directional Survey DID y+lt- DATA INFORMATION Types Electric or Other Logs Run: Comp. Neutron, GR, Litho-Density, Arry Induction, S P, CBL, Cal, FMI, Well Log Information: Log/ Electr Data Digital Dataset Log Log Run T pe Med/Fmtt Number a Scale Media No ----- -__ .--- -- - _ - y -- - -- - ~D C Las 13316 Induction/Resistivit - __---- --- ---- - ~g Mud Log 2 Col i ti it L I d ti /R 25 Bl 1 n v og uc on es s y u >/Log Sonic i ~ 5 Col 2 ~ og Formation Micro Ima 5 Blu 2 ., :.Log Cement Evaluation 5 Blu 1 DLO Perforation 9 5 Blu 1 ED C Las 142971~fnduction/Resistivity 1 693 4471 Open 10/17/2005 PEX-AIT DSI CBL MudLog (.las .pdf .pds) Directional Survey (.las) 96 4485 Open 10/17/2005 Mud Log (Horizon WeII Logging Inc) 693 4462 Open 10/17/2005 PEX, Array Induction, Comp Neutron, Triple-Litho Dens, GR 730 4416 Open 10/17/2005 Dipole Sonic Lager Monopole P & S /Lower Dipole 693 4470 Open 10/17/2005 Fullbore Micro-Imager Two- Axis Caliper / GR Dip Presentation 120 4340 Case 10/17/2005 Slim Cement Mapping Tool, Cement Bond Log, GR, CCL Correlation 1368 3831 Case 10/17/2005 Perf Record 3.5" HSD PowerJet Guns 6 SPF / 60 Deg Phasing 693 4471 Open 12/18/2006 LIS Veri, GR, HRCC, HRDD, MCFL, Induct-Res w/Graphics Well Cores/Samples Information: Na Cuttings (data taken from Logs Portion of Master Well Data Maint Interval OH / Start Stop CH Received Comments Sample Interval Set Start Stop Sent Received Number Comments 90 4485 1162 Cores and/or Samples are required to be submitted. This record automatically created from Permit to Drill Module on: 8/1/2005. DATA SUBMITTAL COMPLIANCE REPORT 10/16/2007 Permit to Drill 2051110 Well Name/No. ASPEN 1 Operator AURORA GAS LLC MD 4485 TVD 4485 Completion Date 9/6/2005 Completion Status SUSP Current Status SUSP ADDITIONAL INFORM?~ION Well Cored? Y /\ftl-~~ Daily History Received? N Chips Received? Y N Formation Tops l~i/ N Analysis Y / N Received? API No. 50-283-20114-00-00 UIC N Comments: Compliance Reviewed By: Date: • ®~ C011ISERQATIOI~T COMI~IISSIOIQ J. Edward Jones Executive Vice President, Engineering and Operations Aurora Gas, LLC 1400 West Benson Blvd., Suite 410 Anchorage, AK 99503 Re: Undefined, Aspen No. 1 Sundry Number: 307-172 Dear Mr. Jones: SARAH PALIN, GOVERNOR 333 W. 7th AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. Approval of the Sundry Application does not authorize Aurora Gas LLC to inject into Aspen # 1. Any work undertaken prior to Commission approval of a Disposal Injection Order is at the sole risk of Aurora. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (907) 659-3607 (pager). As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unle~ rehearing has been requested. / } N DATED this ~ t day of May, 2007 Encl. ~b~~~l STATE OF ALASKA ALA OiL AND GA5 CONSERVATION COM SiON APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 i~ G~E~ V ~D MAY 2 3 007 1. Type of Request: Abandon^ Suspend ^ Operational shutdown ^ Perforate ^ Waivgr^ OtherCl After casing^ Repair well ^ Plug Perforations ^ Stimulate ^ Ti~t~eiaarQib$t[~as Cons. Commi$SiU i Change approved program^ Pull Tubing^ Perforate New Pooi ^ Re-enter Suspended Well ~1ChOf8Q,B 2.Operator Name: 4, Current Weil Glass: 5. Permit to Drill Number: Aurora Gas, LLC Development ® Exploratory ^ 205-111 3. Address: Stratigraphic ^ Service ~ 6. API Number: 1400 West Benson Blvd., St. 410, Anchorage AK 99503 50-283-20114-00 ' 7. if perforating, closest approach in pool(s) opened by this opera#ion to nearest 8. Weil Name and Number. property line where ownership or landownership changes: Spacing Exception Requiter}? Yes ^ No C1 ~ AS en NO, 1 ~ 9. Property Designation: 10. KB Elevation (ft): 11. Fieid/Pool(s): CIRI Lease OC-61387 ~ 448.5' AMSL Undefined 12- PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft}: Effective Depth TVD (ft}: Plugs (measured): Junk (measured): 4,485' ~ 4,485' 2,891' 2,891' 1;779` & 2,950 None Gasing Lengtt- Size MD TVD Burst Collapse Structurai Conductor 83' 13-318" 99' 99' 3,450 1,950. Surface 677° 9-5/8" 693' 693' 7,930 6,620 Intermediate Production 4,469' 5-112" 4,485' 4,485` 4,810 4,640 Liner Perforation Depth MD (ft): Perforation Depth TVD (ft}: Tubing Size: Tubing Grade: Tubing MD (ft): 2,125'-45' 8~ 2,352'-71` 2,125'-45' 8 2,351'-71` None None N1A Packers and SSSV Type: None Packers and SSSV MD (ft}: None 13, Attachments: Description Summary of Proposal {Q, 14. Weil CPass after proposed work: Detailed Operations Program ^ BOP Sketch ^ Exploratory ^ Development ^ Service CJ 15. Estimated Oate for 1-Aug-07 16. Well Status after proposed work: Commencing Operations: Oii ^ Gas ^ Plugged ^ Abandoned ^ 17. Verbal Approval: Date: WAG ^ GiNJ ^ WfNJ ^ WDSPL E] Commission Representative: 18. l hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Prirrted Name J. Edward Janes Title Executive Vice President, Engineering and Operations Signature i` ~} Phone 713-$77-5799 Date , ~ ' ,`~~ ~~-~-~> 907 277-1003 -~ E- ~ ~-' ~ ~ -~=~ GOMMISSION USE ONLY Conditions of appr~rai: Notify Commission so th t a representative may witness Sundry Number: 30~ ~ ? 7skao l ~ ~ l ~s + ~ u tetrt~{ 3eP~ 4v ies-- ~1.~~ ~-+~ Luc e~c ? ~; ,~~. -I~,ts M/ 3~ - Mechanical integrity Test t ~ Location Clearance ^ Piug integrity ^ BOP Test C ~ ~ ~Uli't"kYC.t P2,-~ Cal~~~bR~ Cet~eu~- J ~~tJ ~ Z(XSf i t -Iti ISZY~~'Si Other: _ I t?y~4- C.~i;Si ~ .-e~ -~. --~, Z5cz;c ~s; R BFL MAY 3 1 20D, +s; c: t ir?av > - ~ ~ • o ~cL Jest- art - 4PE Slet~ !„ ~~~`F''1 ~'YlJU1SJra'~ ?.".i: VQn%^"}tiln,~ -~ ~1i:~55 Clot ~,fQ~ J~-s O Can~Ktii1~ Uv17i91 `~"u ~(~.'7v'PGA Subsequent Form Required; ~ +'~i~'~r~ C 1~~~f~t,~4 )u~-Av ~ APPROVED BY ~! D 2 '" ~• ~ Approved by: COMMISSIONER THE COMMISSION Date: ~ ~RIGfNAL Farm 10-403 Revised 0612006 ~~ ~I~`''I/~ 5 L~ • °~ ~~ s~r~ Submit in Duplicate STATE OF ALASKA ~ ALAS OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL ~n oar ~~ nn~ RE~FIVED M~~Y 2 I ?007 ~~_"~., nct Q, r,~r rnns:_ ~:oirlmission 1a. Type of Work: Drill ^ Redrill ^ Re-entry [] -- 1b. Current Well Class: Exploratory ^ Stratigraphic Test ^ Service ^ MuNiple Zone ^ - - Development Oil ^ Development Gas ^ Single Zone ^ 1c. Specify if well is proposed for. AnChOP8g8 Coalbed Methane ^ Gas Hydrates ^ Shale Gas ^ 2. Operator Name: Aurora Gas L.LC 5. Bond: Blanket ~ Single Well ^ Bond No. NZS 429815 11. Well Name and Number: ASPEN 1 3. Address: 2500 City West Blvd., Suite 2500 Houston, TX 77042 6. Proposed Deptfi: MD: 2881' TvD: 2891' 12. Fiekl/Pool{s): 4a. Location of Well (Governmental Section): Surface: 940' FSL, 324' FWL, Sec 33, T72N, R11 W SM 7. Property Designation: CiRI Lease OC-61387 Undefined Top of Productive Horizon: 940' FSL, 324' FWL, Sec 33, T72N, R11 W SM 8. Land Use Permit: T onek Native Co ration AR-101765. 13. Approximate Spud Date: Re-En A ust 2007 Total Depth; 940' FSL, 324' FWL, Sec 33, T72N, R11 W SM 9. Acres in Property: 2,225 acres, more or less ~ ~, 14. Distance to Nearest Property: 1.5 mile 4b. Location of WeN (State Base Plane Coordinates): Surface: x 278848' y- 258981.9` Zone- 4 10. KB E~vation V (Height above GL): 1 feet . 15. Distance to Nearest Well Within Pool: 1!2 mile +/- 16. Devia#ed we9s: N,A, Kickoff depth: feet Maximum Hole Angle: degrees 17. Maxknum Anticpat~ Press in psig (see 20 AAC 25.035) Downhole: 1,875 Surface: 1,436 18. Casing Program: Specifications To p -Setting -Bottom Cemen# Qua , c.f. or sacks Hole Casing Weight Grade Coupling Length MD MD TW (inducting stage data) 17 1 /2" 13318" 54.5 N~ft J-55 BTC 95' 0' 0' 95' 95' w/ driN & cement 12 114" 9518" 38 Ib/ft J-55 BTC 684' 0' 700' 700' 81 bbls ~ 100% OH excess 7 7/8" 5112" 15.5 N~Jft J-55 BTC 3,974' 0' 3,990' 3,990' 161 bbl ~ 25% OH excess 19. PRESENT WEt.L CONDITION SUM MARY {To be for Redrill and Re-Entry Operations) Total Depth MD (ft): 4485' Total Depth TVD (ft): 4485' Plugs (measured): 1,779' & 2,950' ct. Depth MD (ft): 4,439' Effect. Depth TVD (ft): 4,439' Junk (measured}: None Casing Lengtl>I Size Cement Volume MD TVD CondudoriStrudurai 83' 133/8" Drive 83' 83' Surface 693' 95/8" 80 1 Class G Cement 693' 693' intemrediate 4,485' 51/2' 176 bbl Class G Cement 4,485' 4,485` Production Liner Perfora#ion Depth MD (ft): 2351-71', 2984-94', 26', 3444- 1368-88', 1760-70', 2125-45', Perforation Deptt- TVD (ft}: (same) (Continued) 3491-3506', 3811-31' 20. Attachments: Filing Fee [~ BOP tch ^ Drilling Program Q Time v. Depth Plot ^ Shallow Hazard Analysis ^ Property Plat ^ Dirn;rte Sketch ^ Seabed Report ^ Drilling Fluid Program ^ 20 AAC 25.050 requirements ^ 21. Verbal Approval: Commission Representativ 22. I hereby certify that the foregoing is true and rect. Printed Name J. Edward Jone Signature ~~~ Date Contact Title Executive Vice President, Engineering and Opelrations Phone 713-977-5799 Date 5/fs,/O Commission Use Only Permit to D ' Number. 111 API Nu 283-20114-00 Permit Approval Date: See cover letter for other requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales:^ Other: Samples req'd: Yes^ No^ Mud tog req'd: Yes^ No^ HZS measures: Yes^ No^ Directional svy req'd: Yes^ No^ APPROVED SY THE COMMISSION DATE: ,COMMISSIONER Form 10-401 Revised 12/2005 ~ ~' ~"1 ~ Submit in Duplicate IV-+ NA L ~Aurrora Gas, LLC www.aurorapower.com May 15, 2007 a ~~ ~~ Z~.t~~ 9a Re: Applicatio to Drill Re- ntry of Aspen No. 1, Cook Inlet Alaska Original Permit to Dri11205-111-0 MqY X ~ Ol Anchora eAAK 99501 to 100 A/aska Q;~~ 6as Co 20 ~~l g ' Anchor ns. ~0~ission John K. Norman, Chairman State of Alaska ~~~d~ Oil and Gas Conservation Commission ~/ Dear Mr. Norman: Aurora Gas, LLC (Aurora) hereby requests approval of the attached P~,~e-Bri[il' orm 10-401) for its plan to re-enter the Aspen No. 1 exploratory well, as anon-hazardous Class II Oilfield Waste injection well. This well will become an integral part of our ongoing exploration and development of oil and gas on the northwest side of the Cook Inlet. An Application for Disposal of Oilfield Waste is being submitted under separate cover. Aurora plans to re-enter the Aspen No. 1 well and begin workover operations in late summer or early fall of 2007, depending on permitting and logistics. Upon receipt of all necessary permits and approvals, Aurora will mobilize the Aurora Well Service No. 1 rig and support equipment. After the rig is in place and inspected, a BOP stack will be installed and tested, well work operations will be initiated. The well is presently in abandoned status, as depicted in Attachment 1. During the original abandonment procedure, a series of cement plugs were placed along the course of the wellbore. Accompanying the Permit to Drill Application is the supporting well and engineering data, which include the following: 1) AOGCC Form 10-401. Application for Permit to Drill (3 copies) 2) $100.00 Filing Fee payable to the State of Alaska 3) Well Prognosis and Discussion of Operational Considerations 4) Location Plat and Area Map 5) Re-entry, Wellbore Integrity and Testing Procedure 2500 Citywest Blvd., Suite 2500 • Houston, Texas 77042 • (713) 977-5799 • Fax (713) 977-1347 1400 West Benson Blvd., Suite 410 • Anchorage, Alaska 99503 • (907) 277-1003 • Fax (907) 277-1006 6) Rig Acceptance Checklist 7) Wellbore, Wellhead, choke and BOP Schematics and/or narratives 8) Formation Water Salinity Determination The following are Aurora Gas, LLC's designated contacts for reporting responsibilities to the Commission: - Completion Report (20 AAC 25.070) Ed Jones, Executive Vice President (713) 977-5799 - Geologic Data and Information (20 AAC 25.071) - Injection Reporting (20 AAC 25.432) Andy Clifford, Executive Vice President (713) 977-5799 Ed Jones, Executive Vice President (713) 977-5799 Should questions arise in connection with this request or supporting data, please contact either myself or Mr. J. Edward Jones in the Houston office at (713) 977-5799. Respectfully Submitted By, ~~~~ Bruce D. Webb Manager, Land and Regulatory Affairs attachments ~~ ~ ~ i ~~ ._ F<'~ `_`~~€~ It (SAY 1 6 2007 ~~aS{(8 (lil Rr (;ac ('.nnc f'n,,, 1~. °~~ ~~~~ !tl ~t+~t~~t ~'`J~ ~ ~f~ ~:~~1tt~~z>~-~ ;' CB~Ve~' €a~r=~ ~r€1 ~~ f ~di €~ K€sc~~~e 3 f~C_ - _ Anc hor~} €,~ ~~ ~:~~~ ~ ~=~~f€ ~~~F~ ~~~~ a ~~€ _~. u ~ ~ ~~ > ~~~~.ff~}~~3 €.~~~ ~ :~~~~~.~ ~~~~h~~~ ~ , ~ ~ ~ ~ ~ ~ ~~ F~ ~ `~ ~. _ _ o~M~ ~. ~ _ - ~ ~ _ t3~~°~~T$C1r ~~;1"Yf?: .o, ~ m~~ ~ . ~ .. _ .,z ~£ "°~. ~~aa_ -3iRt,~~t~ ~, 3ts~( ~~,.~. "7 ~, ~~ ~~i[l4~ ~T~ ~dt~tl'3,~~> ®q ~` ~~ ~!ig&y f ga ;{ 4 ~~ ~~{t>a~aY4T. s 'V~'' i~4 ~tt ~~.*~~~~i' ~ ((''~~ m.~,~n... ~-,-~.-.. o~'~'~r"JL{i L~~§~_ • g- i~ A ~s ~-.5...ps~.q.. '-.`-..d,1 C"~~6~a~e~. ( ~g is (~ 'dry;~{ _ ° ~. @ (}t;~s~}~~ ill ~~*§}~~Tt"fA~ f+rTi SE~~J~'~ _<.f.,.>a«_ ti= ~_~m= z ~.; . .• ~~ n f ~£.fl"~ 1c'Pt4Y9 ~ ) ~tzt~L'~.h°l~f~ J ~ €rf~€ ~` ~ ,~'~4' F1IS1~, ~~,. 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E . !. ~rr~€I mad n~~ ~ ~ .~ .~€. rM,r. ~,€ .~r~s~~€~~ c,.~y ., ~r~t~€~!~~. ~~~ t~~di~ -° ~ra€€~e~ it ~~~=~s ~~~ ~th~€ a~~Enn€~~ r~~~ -: ~ '~€~ [ i~ ,~ - E °~ :~'c# :~~~~~ €~ t g ~ SR r9 _;? {T`f.~aC~$Sd.€f~a ?~£w`-i~ kt~.:_ =.€~[ ~^ - ( E3 ~, 47$ Tf~ €~t3~~:.i. !C~ ..mi °~`-" t € S 8 f { r ~.:-t`°"; 1n~Ck ~;~c`~' 1~;°~t~a O 1 \ I~ I 1 Y I 1 t=tssf i~€ €a~Ii ~-u STATE OF ALASKA ALAS OIL AND GAS CONSERVATION COM SIGN PERMIT TO DRILL 20 AAC 25.005 1a. Type of Work: Drill ^ Redrill ^ Re-entry Q 1b. Current Well Class: Exploratory ^ Stratigraphic Test ^ Service Q Multiple Zone ^ Development Oil ^ Development Gas ^ Single Zone ^ 1c. Specify if well is proposed for: Coalbed Methane ^ Gas Hydrates ^ Shale Gas ^ 2. Operator Name: Aurora Gas LLC 5. Bond: Blanket Q Single Well ^ Bond No. NZS 429815 11. Well Name and Number: ASPEN 1 3. Address: 2500 City West Blvd., Suite 2500 Houston, TX 77042 6. Proposed Depth: MD: 2891' TVD: 2891' 12. Field/ ool(s): 4a. Location of Well (Governmental Section): Surface: 940' FSL, 324' FWL, Sec 33, T12N, R11 W SM 7. Property Designation: CIRI Lease OC-61387 Undefined Top of Productive Horizon: 940' FSL, 324' FWL, Sec 33, T12N, R11W SM 8. Land Use Permit: T onek Native Cor oration AR-101765 13. Approximate Spud Date: Re-Ent Au ust 2007 Total Depth: 940' FSL, 324' FWL, Sec 33, T12N, R11 W SM 9. Acres in Property: 2,225 acres, more or I 14. Distance to Nearest Property: 1.5 mile 4b. Location of Well (State Base Plane Coordinates): Surface: x- 278848' y- 258981.9' Zone- 4 10. KB Elevation (Height above GL): ~ 16 feet 15. Distance to Nearest Well Within Pool: 1/2 mile +/- 16. Deviated wells: N,A, Kickoff depth: feet Maximum Hole Angle: degrees 17. Maximum Antici ressures in psig (see 20 AAC 25.035) Downhole: 1,875 Surface: 1,436 18. Casing Program: Specifications To - g Depth -Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling Length MD MD TVD (including stage data) 17 1/2" 13 3/8" 54.5 Ib/ft J-55 BTC 95' 0' 95' 95' w/drill & cement 12 1 /4" 9 5/8" 38 Ib/ft J-55 BTC 684' 0' 700' 700' 81 bbls @ 100% OH excess 7 7/8" 5 1/2" 15.5 Ib/ft J-55 BTC 3,974' 0' 0' 3,990' 3,990' 161 bbl @ 25% OH excess 19. PRESENT WELL CONDITION SUMMARY (T a mp eted for Redrill and Re-Entry O perations) Total Depth MD (ft): 4485' Total Depth TVD (ft): 4485' Plugs (measured): 1,779' & 2,95 ' Effect. Depth MD (ft): b 4,439' Effect. Depth TVD (ft): 4,439' Junk (measured): None Casing Length Size Cement Volume MD TVD ConductoNStructural 83' 13 3/8" Driven 83' 83' Surface 693' 9 5/8" 80 bbl Class G Cement 693' 693' Intermediate 4,485' S 1/2' 176 bbl Class G Cement 4,485' 4,485' Production Liner Perforation Depth MD (ft): 2351-71', 2984-94' 006- ', 3444-5 1368-88', 1760-70', 2125-45', Perforation Depth TVD (ft): (same) (Continued) 3491-3506', 3811-31' 20. Attachments: Filing Fee Q BO Sketch ^ Drilling Program Q Time v. Depth Plot ^ Shallow Hazard Analysis ^ Property Plat ^~ Div er Sketch ^ Seabed Report ^ Drilling Fluid Program ^ 20 AAC 25.050 requirements ^ 21. Verbal Approval: Commission Representati e: 22. I hereby certity that the foregoing is true a correct. Printed Name J. Edward Jon Signature ~-~J ~ ~ Date Contact Title Executive Vice President, Engineering and Operations Phone 713-977-5799 Date S" /,~ D `7 Commission Use Only Permit to Drill Number: 205-111 API Number. 50- 283-20114-00 Permit Approval Date: See cover letter for other requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce Coalbed methane, gas hydrates, or gas contained in shales:^ Other: Samples req'd: Yes^ No^ Mud log req'd: Yes^ No^ H2S measures: Yes^ No^ Directional svy req'd: Yes^ No^ APPROVED BY THE COMMISSION DATE: ,COMMISSIONER Form 10-401 Revised 12/2005 Submit in Duplicate ~ ~ Aurora has, LLC Aspen # 1 Disposal Well Conversion August 2007 PTD #: 205-111 API #: SO-283-20114-00 Prepared by Jack McDade Aspen #1 Disposal Well Procedure Aspen #1 Background & Present Condition Aspen #1 is a biogenic gas prospect drilled in during the summer of 2005. It was drilled as vertical well & all depths referenced are form the original RKB of 16'. The pad is 432.5' AMSL. RKB would be 448.5' AMSL. The well was drilled to TD of 4,485' in order to explore the gas production potential of the Tyonek sands. Production casing was run to depth of 4,485'. The well was perforated & subsequent testing revealed no ~ economical hydrocarbon production. The well was suspended with plans to convert into a .,i Class II injection well for produced water & drilling waste disposal. This well consists of a 13-3/8" conductor that was driven to refusal @ 83'. A 12-'/4° surface hole was drilled to 700' and 693'of 9-5/8", 53.5 # L-80 surface pipe was run and cemented w/ 50 bbls of 14 ppg lead & 30 bbl 14.5 ppg Gas Block "G" cement. Cement returns to surface were verified by wt. & PH. A 7-7/8" intermediate hole was drilled to 4,485'. Following completion of open hole logging 4,485' of 5-1/2", 15.5# J-55 BTC was run & cemented w/ 40.6 bbls 13.Sppg lead cement & 136 bbl of 15.8 ppg tail slurry. A cement bond log was run & the well was then perforated at the following depths: 1,368'-1,388' 1,760'-1,770' 2,125'-2,145' 2,351'-2,371' 2,984'-2,994' 3,006'-3,026' 3,444'-3,454' 3,491 '-3,506' 3,811 '-3,831 ' After testing operations were completed the well was suspended as follows: A cement retainer was set at 2,950' and 10 sx of class "G" cement was pumped on top. This plug was pressure tested and tagged @ 2,891'. A cast iron bridge plug was set 1,779'. A cement retainer was set @ 1,714' &perfs f/ 1,760'-1,770' were squeezed w/ 8 sx of class "G" cement. A 19 sx class "G" balanced plug was then laid across perfs f/ 1,368' to 1,388'. The plug was tagged at 1,260' and after rippling down the BOPE & installing the dry hole tree the rig was released. No surface plug was set in anticipation of future use as a disposal well. Planned work consists of moving AWS #1 onto the well in the workover configuration. The integrity of the casing will then be confirmed through pressure testing casing. The retainer @ 1,714', CIBP at 1,779' & cement will be drilled out and the well cleaned out to 2,891'. Completion equipment will consist of a Weatherford Arrowset mechanical packer on 2-7/8", 6.5# J-55 EUE Tubing. A 4-point step rate test will be conducted and the test data will be sent to Anchorage for fracture modeling. After landing completion and installing tree AWS #1 will move off and the well will be commissioned pending agency approval. Procedure: 1) MIRU AWS # 1 onto Aspen #1 wellsite in the workover configuration w/ only required support equipment. Aurora Gas, LLC Page 1 of 5 Prepared by Jack McDade Rev 1.0 Aspen #1 Disposal Well Procedure 2) ND tree, NU 3000-psi BOPE. Test to 2000 psi (or as required by AOGCC Sundry approval). (Notify AOGCC fir witness of pressure test) 3) Test Casing to 1,500 psi f130 minutes. Maximum allowable pressure drop is 10% or 150 psi f/ 30 minutes. Chart record all results. (Notify AOGCC for witness of pressure test) 4) Fill pits w/ 8.9 ppg NaCI brine & load pipe rack with 2 7/8" EUE workstring while testing BOPE. 5) RIH w/ 4 3/4° bit on 18, 3-1/8" Weatherford Collars w/junk basket & 2-7/8" EUE Tubing. Be prepared to tag cement @ 1,260' 6) Drill f/ TOC @ 1,260' feet to retainer @ 1,714'. CBU-Close Pipe Rams & verify integrity of squeezed perfs f/ 1,368' to 1,388' by testing to 1,500 psi f/ 30 minutes. Maximum allowable pressure drop is 10% or 150 psi f/ 30 7 dg~ minutes. Chart record all results. If successful continue to step fI o ~, i~i~~ prepare to conduct squeeze operations. Procedure to be issued. (Notify AOGCC for witness of pressure test) 7) Drill retainer @ 1,714' & cement to CIBP @ 1,779'. CBU-Close Pipe Rams & verify integrity of squeezed perfs f/ 1,760' to 1,770' by testing to 1,500 psi f/ 30 minutes. If successful continue to ste~If not prepare to conduct squeeze operations. (Notify AOGCC for witnes of pressure test) Jg~~- ~@a~ _.. _°_ c~ D 8) Drill CIBP & clean well out to TOC. Should tag cement at ~ 2,890'. (Set torque iimits on power swivel to avoidl twist off} 9) Monitor well & POH w/ 2-7/8" tubing. LD collars & bit w/junk basket. 10) PU 5-%' X 2-7/8" Weatherford Arrowset Packer w/ pup jt. / WLEG & RIH to 2,000' on 2-7/8" EUE Tubing. Install XN-nipple below packer if not included. Set Packer @ ~ 2,000'. Pressure test tubing to 2,500 psi f/ 30 minutes. 11) Rig up to pump down tubing w/ rig pump. Perform 4-point step rate test w/ produced water @'/2 bpm increments. Do not exceed 1,500 psi. Record test on chart recorder. Submit data to Anchorage office for approval by agencies. If infectivity rate is not high enough at acceptable pressures, additional perforations will be added. 12) Release packer & reverse in 31 bbl of corrosion inhibited brine. 13) Set packer & land tubing. Test Install BPV. Aurora Gas, LLC Page 2 of 5 Prepared by Jack McDade Rev 1.0 Aspen #1 Disposal Well Procedure 14) ND BOPE & install tree. Release Rig. Hand well over to production for commissioning. (Consider using rig to get rid of drilling waste from previous season to empty tankage for use on upcoming wells). Proposed Work Start Date: Well work is tentatively scheduled to start August 1, 2007. Duration of activities estimated at 5 - 8 days. Rig Information: The rig "Aurora Well Service Rig No. 1"and auxiliary support equipment will be used. Rig configuration and BOP equipment will be the same as on previous work Aurora has undertaken on its gas properties on the NW side of Cook Inlet. Aurora Gas, LLC Page 3 of 5 Prepared by Jack McDade Rev 1.0 Aspen #1 Disposal Well Procedure Current Well Configuration: Aspen # 1 Aurora Gas Disposal Well Conversion Drill 71/8" Pilot Hole to 700'-open to 12 '/." Fit to 14.8 ppg EMW @ 720' 19 sx Balanced Cement Plug @ 1,260' Bridge plug @ 1,714' Bridge plug @ 1,779' 6 n n u ^~ 13-3/8", 68# J-55 Casing driven to 83' 9-5/8" 53.5# L-80 set @ 693"-Cemented w/ 50 bbls of 14 ppg lead & 30 bbl 14.5 ppg Gas Block G w! good returns observed on surface Perfs f/ 1,368'-1,388' (Squeezed w/ 11 bbl Class "G" Cement) Perfs f/ 1,760'-1,770' (Squeezed w/ 8 sx Class "G" Cement) Perfs f/ 2,125'-2,145' 10 sz Cement Plug @ J~ .~~I 2,891' ~~LItLA(Cf/~ ~ Plc, ~4`I ~ = z`J~7' ~~0~- 1~--40.7 Bridge Plug @ 2,950' S~ZS~o7 PBTD 4355' Dri117-7/8"Hole to 4,448' 1- Hnndbook* - *u mark of Schl umberger Aurora Gas, LLC Prepared by Jack McDade Perfs F 2,351'-2,371' Perfs f/ 2,984'-2,994' Perfs f/ 3,006'-3,026' Perfs f/ 3,444'-3,454' Perfs U 3,491'-3,506' Perfs f/ 3,811'-3,831' 5'/:15.5# J-55 Casing set @ 4,485' TVD Cemented w/ 40.6 bbl 13.5 lead cement & 136 bbl 15.8 ppg tail cement Page 4 of 5 Rev 1.0 Aspen #1 Disposal Well Procedure Proposed Configuration: Aspen # 1 Aurora Gas Disposal Well Conversion Dri117 7/8"Pilot Hole to 700'-open to 12'/." Fit to 14.8 ppg EMW @ 720' 6 _ 2 7/8" 6.5# J-55 8rd EUE to 2,000 ft. w/ Weatherford Arrowset Mechanical Packer, X-nipple & pup w/ WLEG ~` 13-3/8", 68# J-55 Casing driven to 83' 9-5/8" 53.5# L-80 set @ 693'- Cemented w/ 50 bbls of 14 ppg lead & 30 bb114.5 ppg Gas Block G w/ good returns observed on surface Perfs f/ 1,368'-1,388' (Squeezed w/ 11 bbl Class "G" Cement Perfs f/ 1,760'-1,770' (Squeezed w/ 8 sx Class "G" Cement) Perfs f/ 2,125'-2,145' Top of Cement Plug @ 2,891' Perfs f/ 2,351'-2,371' Bridge Plug @ 2,950' Perfs f/ 2,984'-2y94' Perfs f/ 3,006'-3,026' Perfs f/ 3,444'-3,454' Perfs F 3,491'-3,506' Perfs f/ 3,811'-3,831' PBTD 4355' Dri117-7/8"Hole to 4,448' i- Hnndbook* - *a mark of Schlumberger Aurora Gas, LLC Prepared by Jack McDade 5 `/a",15.5# J-55 Casing set @ 4,485''TVD Cemented w/ 40.6 bbl 13.5 lead cement & 136 bb115.8 ppg tail cement Page 5 of 5 Rev 1.0 NOTES 1) BASIS OF COORDINATES IS ALASKA STATE PLANE NAD 27 ZONE 4 FROM A DIRECT TIE TO ADL NO. 31270. 2) BASIS OF ELEVATION IS FROM TIDAL OBSERVATION ON 9-22-93. DATUM IS MLLW. ALL ELEVATIONS SHOWN HEREON WERE TAKEN ON GROUND. NORTH 3) SECTION LINES SHOWN HEREON ARE BASED ON PROTRACTED VALUES. Grid scams 1 inch = 400 ft. 0 40o soo aoo S33 T12N R11W '°Rop U.S. SURVEY NO. 1865 ~ ~Eo p / qp ASPEN NO. 1 WELL AS-STAKED ```"~~11 / GRID N: 2589811.910 ~~ OF A ICI GRID E: 278847.780 ~ ~~..••••••.~.9 S ~ '~ ' ,F ~~ •. LATITUDE: 61'04'57.937"N ~P•• 324' FWL \ LONGITUDE: X151°14'57.061"W ~* .' TH ~~*~j ELEV 432 5 4 9 \ . . ~....... .- .................. . ........................ 'QOp ~ ~ '•_M. SCOTT McLANEff J OS ~ ~I~ `~ '• 4928-S 5 ~ cu ,,~ ~` ~ ss ~ ~~~~~~~~ S32 S33 T12N S5 S4 T11 N N 2588878.16 ~ E 278506.16 S~~NG Ro PO X~ E ASPEN NO. 1 AS-STAKED Consulting C~'rouP SURFACE LOCATION DIAGRAM Iv~cLane Testing APPLICANT: ENGINEERING/MAPPING/SURVEYING/TESTING P.O. BOX 468 SOLDOTNA, AK. 99669 VOICE: (907) 283-4218 FAX: (907) 283-3265 -- ,;°,~.~~ ~~,' '"~ EMAIL: msmclane®mclanecg.com PROJECT NO. DRAWN BY: DATE: 10/26/04 OFFSETS: LOCATION: PROTRACTED SECTION 33 043050 MSM 320' FWL TOWNSHIP 12 NORTH, RANGE 11 WEST SLD 940' FSL SEWARD MERIDIAN, ALASKA Aurora Gas LLC, Rig Acceptance Checklist Rig: Aurora Well Service #1 Well: Ascen #1 Re-entry Inspection Date: Inspected 8y: I. DRILL SITE _ a AUTHORIZED PERSONNEL signs posted _ b. HARD HAT/SAFETY GLASSES signs posted _ c. NO SMOKING areas designated _ d. H2S controls if applicable _ e. Escape and guy lines flagged _ f. Hard hats/Safety glasses available for visitors II. DOG HOUSE _ a. Adequate exits, doors installed properly, operate freely _ b. Approved heaters used _ c. General housekeeping _ d. First aid kit and facilities _ e. Crew trained in first aid _ f. Emergency phone numbers posted _ g. Two-way radio provided _ h. Safety equipment available _ i. Crew wearing hard hats and safety glasses _j. Crew wearing hard-toed shoes _ k. Proper Gothing worn by crew _ I. No hazardous jewelry worn _ m. NO SMOKING rules observed _ n. OSHA log posted _ accidents _ o. B.O.P. drills, test logged _ p. Safety meetings logged q. Driller at or near controls _ r. Toolpusher/Rig Manager at rig kxztion _ s. Approved and adequate lighting _ t. Hazard communication/MSDS Sheet on site III. DRILLING FLOOR AREA _ a. Rotary table area _ b. Kelly bushing guard used _ c. Controls adequate if no guard used _ d. Rotary chain drive guarded _ e. All unused floor holes covered _ f. General housekeeping, lighting _ g. Pipe slips, dies _ h. Racking floor area _ i. Vee door gate provided, in place _ j. Makeup and breakout tongs _ k. Tong snubbing lines, clamps _ I. Tong counter weights _ m. Tong body and jaws condition _ n. Tong safety handle pin secured o Tong dies sharp, keeper used _ p. Air hoist line, guide guarded _ q. Catheads _ r. Catlines _ t. Spinning chain, headache post _ u. Crown-O-Matic device, operating _ v. Drilling line _ w. Drawworks and overrunning clutch _ x. Driller's controls _ y. Hand tools, bench grinders _ z. Gauges and meters functional _ aa. Safety valve and wrench accessible _ bb. Tong counter weight in guides, cable and sheave condition cc. Subs properly stored _ dd. Mud box used when required, in good condition and properly rigged _ ee. Doghouse heater not an ignition source _ ff. Geolograph, flow-show, PVT equipment properly working _ gg. BOP procedures, maximum allowable casing pressure, fill-up information posted _ hh. Overall condition of all rope, chains, slings and hooks used for liffing _ ii. Choke panel operational, gauges and controls function properly IV. STAIRS, HANDRAILS, GUARDRAILS _ a. Adequate stairs provided off rig _ b. Stairs level, secure, no obstructions _ c. Adequate handrails provided (stairs) _ d. Stair treads uniform, of non-skid type _ d. Flashing red light on crown e. Bumper sills installed on crown _ f. Hinge points, structural cross members free of damage, cracks, and excessive corrosion _ g. Derrick ladder in safe condition h. Crown block in good condition; regularly maintained VI. BLOWOUT PREVENTERS _ a. B.O.P. properly installed, tested _ b. Wheels and stems in place _ c. Stack properly stabilized _ d. All hydraulic lines connected _ e. All unused lines capped _ f. Accumulator unit property located _ g. Gauges properly located _ h. Housekeeping, drainage i. Choke manifold and line, secured _ j. Blocey line used, pilot light used _ k. Approved and adequate lighting _ I. Signage _ j. BOPE rated working pressure adequate for planned work _ k. Remote Dosing station properly located _ I. No short bolts, loose or missing nuts _m. Adequate number of BOPE closing methods handrails or laid across walkways _n. Accumulator controls labeled, handles in open or Dosed position with blind handle guarded _o. Accumulator relief line vented to hydraulic tank p. Control line condition, steel or armored hose _ q. Blast points on headers protected by targeted plugs r. Personnel trained in operation of BOP's, crew assignments for shut-in procedures posted _ s. ROPE securely braced to substructure _t. Mud gas separator secured VII. PIPE RACK AREA _ a. Ends of pipe racks chocked _ b. Layers of pipe chocked, spacers used Y c. Pipe racks level, stable _ d. Stairs with handrails provided e. Vee door slide, pipe stops used _ f. Pipe tubs and bridles _ g. Derrick stand and ladder _ h. General housekeeping, lighting _ i. Dead end of drilling line elevated _ j. Employees not on top of pipe V{II. DERRICK BOARD AREA _ a. Denick ladder _ b. Derrick climber installed and used _ c. Safety bek, safety catch _ d. Safety lines or lanyards used e. Derrick emergency escape line ~_ f. Geronimo on line and ready for use _ g. Pipe fingers and tools secured _ h. Mud standpipe secured _ i. Mudhose snubbed on both ends IX. MUD PUMP AREA _ a. Drive hefts, pony rods guarded _ b. Head and valve covers fully bolted _ c. Shear pin pop-off valve covered/tested _ d. Ends of mud vibrator hose snubbed _ e. Ends of relief lines secured f. General housekeeping _ g. Approved and adequate Lighting X. MUD MIXING AREA _ a. Bagged material propedy stacked _ b. Walkways and guardrails _ c. Condition of walkways, free from obstruction _ d. Guardrails provided on crossovers _ e. Approved and adequate lighting _ f. Eye protection required warning signs _ g. Shale shaker guarded h. General housekeeping r_ i. Explosive-proof equipment at shale shaker j. Agitator shafts and couplings guarded _ k. Mud guns and jetting hoses secured _ 1. Desander, desilter, degasser unRs KI. MUD TANKS AND PITS _ a. Adequate stairs with handrails b. Adequate personal protective equipment ~_ c. Adequate eyewash available _ d. General housekeeping XII. GENERATOR AREA _ a. Generators properly located _ b. All generator moving parts secured _ c. Generators properly grounded _ d. Cover panels on electrical control boxes _ e. Emergency lighting provided in SCR building f: HIGH VOLTAGE warning signs used _ g. 5CR doors closed, A.C. unit properly working _ h. All electrical tools grounded i. Condition of electrical wiring _j. Electrical wires properly strung _ k. Unused electrical outlets covered _ i. Air compn:ssors properly guarded _ m. Air storage tanks equipped with pop-off _ n. General housekeeping, IighGng _ o. Hearing protection available _ p. Wiring, motors, receptacles, switches, lighting, etc. meet code requirements _ q. Use of household electric outlets on rig or associated equipment prohibfted r. Electrical control boxes marked "Danger High Voltage' and state voltage _ s. Dielectric mats in front of all electric control boxes t. S.O. electric cords properly routed -not tied to XIII. FUEL STORAGE TANKS _ a. Fuel storage tanks properly located _ b. All storage valves marked as to connects _ c. Discharge nozzles, hoses, valves _ d. Piping and fuel lines _ e. General housekeeping, lighting _ f. Stationary ladders on storage tanks XIV. FIRE PROTECTION _ a. Adequate fire extinguishers _ b. Tanks properly vented _ c. Flammables in U.L. safety cans _ d. NO SMOKING rules enforced _ e. Flare area clear of combustibles f. Boiler and its safety controls _ g. Welding performed safely _ h. Spark and heat an•ester on engines _ i. Fire extinguishers inspected, charged, tagged and sealed _ j. Personnel are trained in the use of portable fire extinguishers _ k. Flammable/combustible liquids are propedy labeled and stored _ I. Oily rags/waste picked up and stored in Dosed metal containers _ m. Engines equipped with spark arresting mufflers and emergency shutdown device XV. HYDROGEN SULFIDE _ a. Appropriate warning signs _ b. H25 monitors, alarms _ c. Briefing areas, breathing equipment _ d. Site specfic training e. Contingency Plans available XVI. HOISTING EQUIPMENT _ a. Number of wraps on hoisting drum _ b. Drilling Line conditions, ton miles records available, slipped and cut as required _ c. Condition of brake pads and flanges, brake linkage adjustment, retainer pins in place _ d. Weight indicator installed, maintained and calibrated _ e. Condition of bails and elevators f. Boom line and pole in good condition _ g. Lifting chain/slings inspected and tagged h. Traveling block and hook in good condition {VII. ENVIRONMENTAL _ a. No fuel spills, trash in reserve pit, reserve pit leaks _ b. Spill Contingency Plans (SPCC) _ c. Trash container provided and used _ d. Oil container (drip pans) under engines and pumps XVIII. TOOLS AND MACHINERY _ a. Hand tools clean, inspected and properly stored _ b. Broken or damaged tools remove from service c. Moving parts properly guarded _ d. Equipment repaired or adjusted by authorized personnel e. Power source locked out and/or tagged AURORA GAS, LLC ASPEN 1 WATER DISPOSAL WELL Rw and SALINITY FROM OPEN-HOLE LOGS DEPTH SSP EST Rmf Rt Rs Rxo Rm Rs/Rm RxolRm RxolRt bed thick hole dia hld EsplEspcorr Kc Rw Calculated Sand Adjacent my BHT @ BHT AIT•H90 (AIT•H90) (AIT H10) @ BHT h d (from SLB Corrected SALINITY Bed deg F ft ft SP•3 chart) SSP ppm NaCI ft ft (1) (2) (3) (4) (5) (6) (7) (8) (9) (1D) (11) 2138 2150 14 71.38 0.127 30 15 5 0.160 93.64 31.21 0.17 12 0.65625 18.29 0.63 222 70.5 0.263 26,000 2176 2206 19 71.76 0.127 40 15 8 0.159 94.09 50.18 0.20 8 0.65625 12.19 0.4 47.5 70.5 0.598 10,000 2290 2337 22 72.9 0.125 23 9 6 0.157 57.27 38.18 0.26 30 0.65625 45.71 0.82 26.8 70.7 0.300 22,000 2366 2337 17 73.66 0.124 50 9 7 0.156 57.82 44.97 0.14 24 0.65625 36.57 0.8 21.3 70.8 0.247 26,000 2446 2432 15 74.46 0.123 32 10 6 0.154 64.88 38.93 0.19 30 0.65625 45.71 0.82 18.3 70.9 0.222 29,000 2554 2542 20 75.54 0.121 30 8 6 0.152 52.59 39.44 0.20 8 0.65625 12.19 0.45 44.4 71.0 0.511 11,800 2622 2641 13 76.22 0.120 35 5.5 10 0.151 36.45 66.28 0.29 16 0.65625 24.38 0.6 21.7 71.1 0.242 26,000 2740 2755 16 77.4 0.118 40 11 6 0.149 73.94 40.33 0.15 22 0.65625 33.52 0.75 .21.3 71.3 0.236 26,000 NOTES: 1) Where SSP= Static Spontaneuos Potential, which is the difference between the SP reading of the sand and the SP reading of the surroundingladjacent formations}, (usually shale or silt) 2) From open-hole logs, BHT was measured at 95 deg F at 4471'. Thus, BHT=50+DI100~1.0 deg/100' 3) From log header, Rmf was measured a 0.135 ohm-m at 67 deg F. Rmf at depth D=Rmf at 67"(67+7)/(BHT at D+7) 4) Rt=AIT 90 of sand (true resistivity of sand} 5) Rs=AIT 90 of surrounding beds (shales/silts) 6) Rxo=AIT H•10 (invaded sand resistivity) 7) From log header, Rm was measured at 0.172 ohm-m at 66 deg F. Rm at depth D=Rm at 66'(66+7)1(BHT at D+7) 8) EsplEspcorr-correction ratio for SSP from Schlumberger Log Interpretation Chart SP-3,using the best matcl Rs/Rm, Rxo/Rt, h/d, Rxo/Rm 9) Kc=61+.133'BHT 10) Rw=Rmf/(POWER(10,SSPcorrl-Kc) 11) SALINITY is from Schlumberger Log Interpretation Chart Gen-9, Resisitivity of NaCI Solutions, using Rw just calculated and BHT, M ~~~°T~ C3 ~'tUFti x ~;,~ ;=~r~~, 2~.2~r~ ,yz~ ~f ~?~q€_re~t: r'lb<^a~clcr.~ ..~ S~Eg~t• _.i ~~peratcanaP shr€:~~~~r~'._..~ f'E;rfer. w?~] vL'~ir~r~l ~tf~~r: ~ 1 r:T~=" ~2~EfSC~j_,,; P~~ry3t€M4£T'i ~~ ~;l!~=--'~i~~Yc'i41Qi15 ...# ~f3iY71.t~dtr'" _i ~3ft~G'~,~.$~[ie,':~~5 t r~~s~G~ a[>.r,~rrve~3 pirag€~~ ~u„ ~'l~taino~ P~rt~,r~ ~~~ ~~ ~ ._~ R~-enf~r ~~st;~;rt~~t7 ~ at! t ~. 4€~-~ _ _ ~r~~~~: ~. ~urr~rat ~I€s€l ~ta~~: ~ ~. ~ermif t~ I"~f1t €~urrs,: X~~€~ra tsas. f.i..+:; s~~~~;ic~pr:t~r , ~ i ~=xpl~rrf~€y~ "f 2t}~-'i 3" . ~, k~ryr~s~: ~~~<~ _§~~ ra~?rEic i"""} ~~.~r~i~ Ci ~_~ fi. ~~I ?~`u :~~r: ~'~} .~~;~st ~~nsos~ E33tid ; -~;. ~1C7, ~erscher~ze ~.~t 9~~L?;~ ~ ,. : . ,~ ~-t':r20' ~-Qv .. . ..... i~,L~G(1'•L=l ci I:TQ: Gi V'.s~~. ~S.i'g51 ($t`~"~ Ef$ J~~~~ °J ~~Ey yy.. y4 .~ w ~.." # ~ UV~?~L~"Ld V~ ti71$ V;,}~~.1 'i~4iC~bT GL~ ~~L~r('';`~, s V. 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X~zeL'.3i:6~ ~'j ~,f•;:s.[3CEL, €~'I?~l€`€~~CS Si€~ ~9'k~ ~~#?f~~%~3 YZ.:~ „ ~ , `. - v .m .~ ~ ~ ,;.: g{~~-277-~~4f3 r 9 ~ ., . i ~E~~tfl~ e~S~ ~~~L ..~ ~ _ ~ ,~~.~ ~C -~nr, t3n~ cP ~g~prt,~~ `,totfy W~n~rv~i~~i~ap~ sr: §~~t rip=~s~ntas:~:~ may= ~ritrz~ss ~'u'brY t„u€~~~r: I r ~t,a~ inter€r~ ~..~ '~ .:t- ~~;t !- ~~~~~f~it ' .f~c~rif~ ~~st ~ ~_~~~ti~+rt ~#zarartr~,~ E_T ~, e v ~_i C~t~~r: ~~ab~~~; "f Fc~~rE ~f>?~;a:rec a ;~'2i:'e'Rr`w'~CI ~', (pp~'rt3u~'~ h :tf~C+~I~s~``t~~~:~ T't-l~ i.€JP>•tt1~iS~'s,~}l~! i3~t~: t"€~rr~ ~ J-4Q3 R~*ri~€ f~~~i2'~w~ cibmtt E~ ~ us~ii;.~t Re: Aspen #1 (205-111) ~ i Subject: Re: Aspirn #1 (205-111) From: "Thomas Maunder <ttnn_maunder@achilin.state.ak.us> hate: ~fon,'1 ~1.1~. ?tl~i~' 16:Ci(:~1 -i~ij0 To: bweE~b(a-~aurorai~owcr.com ('C:'Ed Junes' _jej~~ne~.~iaurora~~rnrca~.com=,'Jack ~1cUade' <mcdadejc(ci;hoh»aiLcui~~%. 'Steve r)a~ies' °"stove da~ics<<;a~h»in.statc.ak.us~- Bruce, et al, You are correct, Nicolai Creek #5 was plugged and abandoned in 1972 by Unocal. When Aurora proposed to re-enter in 2002, a 401 was needed (see 20 AAC 25.005). Since Aspen #1 was suspended, a sundry is the proper form to submit. Now if new hole was being drilled in Aspen # 1, then both forms would be needed. In order to have considered Aspen P&A, the wellhead would have to have been cut off with the marker plate attached. Hope this helps. Call or message with any questions. Tom Maunder, PE AOGCC Bruce D. Webb wrote, On 5/21/2007 3:55 PM: Tom, This was my mistake. I fashioned the Aspen submittal after the Nicolai Creek #5 submittal. In both cases, the wells were cemented. In the Nicolai Creek Submittal (see below), both a 401 and 403 were submitted, and the 403 was returned stating that it was not needed for the re-entry and the 401 superceded the 403. I incorrectly assumed the Aspen well was considered abandoned, however, I have just spoken to Christine who has informed me that the AOGCC has the Aspen well listed as "suspended". Despite both the Aspen and Nicolai wells being cemented and requiring re-entry, I believe the subtle difference is that the Nicolai Creek well was actually classified as "abandoned" and therefore needed a new permit -whereas the original Aspen permit is actually still considered open. Is this a correct assumption? I would like to not make the same mistake twice. r 1.: U?*t:a[t ;~a~i~ regulat* ~ befa~ , . ;jclb; ' , : : ,, . . :fit tip ~~ti13. Potty 1+1-~t lt,@i~"a1; : ; . 1 of 2 5/23/2007 4:39 PM Re: Aspen #1 (205-111) i I apologize for the confusion. -Bruce -----Original Message----- From: Thomas Maunder [mailto:tom. mau~~cler~i)aclmin,state,al~.us] Sent: Monday, May 21, 2007 6:00 PM To: Ed Jones Cc: Bruce Webb; Steve Davies; Tracie Paladijczuk Subject: Aspen #1 (205-111) Ed, We have received a Permit to Drill application for the planned work on Aspen #l. Since no new hole will be drilled, the correct form to submit should be a 10-403 (Sundry Notice ...). Please submit 2 copies of the sundry and we will attach the documents already submitted. We will refund the $100 application fee. Call or message with any questions. Tom Maunder, PE AOGCC 2 of 2 5/23/2007 2:52 PM Subject: RE: Aspen #1 (205-ll 1) From: "Bnice D. Webb" <bwebb!~i~auror<~~x>~l~cr.com> Date: ~~ton, Zl ~bla~ ~~)(1 l ~:~>a)2 -U~OO To: 'l Noma; i~~lauiidcr' tom m~iunder«l~aclmin.statc.a(~.u~=~. 'Ecj Joncs' ~~~JeJoi~esici aw~cra~,o«cr.com>.'Jack ~~teDade' <=mcdadcjc(~i~hutmail.com=- ('(': 'Stc~~c Da~~ics' ~=ste~~e da~~ie~~a<a~ltnin.~tate.akus:- Tom, This was my mistake. I fashioned the Aspen submittal after the Nicolai Creek #5 submittal. In both cases, the wells were cemented. In the Nicolai Creek Submittal (see below), both a 401 and 403 were submitted, and the 403 was returned stating that it was not needed for the re-entry and the 401 superceded the 403. I incorrectly assumed the Aspen well was considered abandoned, however, I have just spoken to Christine who has informed me that the AOGCC has the Aspen well listed as "suspended". Despite both the Aspen and Nicolai wells being cemented and requiring re-entry, I believe the subtle difference is that the Nicolai Creek well was actually classified as "abandoned" and therefore needed a new permit -whereas the original Aspen permit is actually still considered open. Is this a correct assumption? I would like to not make the same mistake twice. I apologize for the confusion. -Bruce • • -----Original Message----- From: Thomas Maunder [mailto:tom maunder@admin.state.ak.us] Sent: Monday, May 21, 2007 6:00 PM To: Ed Jones Cc: Bruce Webb; Steve Davies; Tracie Paladijczuk Subject: Aspen #1 (205-111) Ed, We have received a Permit to Drill application for the planned work on Aspen #l. Since no new hole will be drilled, the correct form to submit should be a 10-403 (Sundry Notice ...). Please submit 2 copies of the sundry and we will attach the documents already submitted. We will refund the $100 application fee. Call or message with any questions. Tom Maunder, PE AOGCC Re: Aspen # 1 (205-111) • • ~'~"~ Csr sd mid I~ii~e.~rf was l.~ri~lt. ~i ~d repair ~ca~ ..~. , °. ~ ftrr:~3'zr~l~c ~is~ Tom, ~ I apologize for the confusion. -Bruce -----Original Message----- From: Thomas Maunder mailto:tnm ma~znder~ir`adlnin.state.ak.~~s] Sent: Monday, May 21, 2007 6:00 PM To: Ed Jones Cc: Bruce Webb; Steve Davies; Tracie Paladijczuk Subject: Aspen #1 (205-111) Ed, We have received a Permit to Drill application for the planned work on Aspen #1. Since no new hole will be drilled, the correct form to submit should be a 10-403 (Sundry Notice ...). Please submit 2 copies of the sundry and we will attach the documents already submitted. We will refund the $100 application fee. Call or message with any questions. Tom Maunder, PE AOGCC 2 of 2 5/23/2007 4:39 PM DATA TRANSMITTAL Please reply to: AURORA GAS, LLC 2500 CITYWEST BLVD, STE. 2500 HOUSTON, TX 77042 ATTN: ANDY CLIFFORD 333 W. 7~ Avenue Suite 100 Anchora e AK 99501 ATTENTION: Howard Okland Enclosed CD From Aurora Gas LLC Area MocLuawkie Area Cook Inlet Alaska Date: 13 December, 2006 CD: 1. Aspen #1 well data: LAS, PDS and PDF files for Directional Survey, Platform Express, Dipole Sonic Imager, Perforating Record, Cement Bond Log plus mudlog. OWLEDGE RECEIPT OF DATA BY SIGNIN )PY BACK TO AURORA GAS FOR OUR FIL Received by: Date: W AURORA GAS, LLC, 2500 CITYWEST BLVD, STE 2500, HOUSTON, TX 77042 TEL: 713-977-5799, FAX: 713-977-1347 ~S ~l ~ ~ l~l~~" • tiAur~ora Gas, www.aurorapower.com June 15, 2006 Mr. John Norman, Chair Alaska Oil and Gas Conservation Commission 333 West 7~' Ave., Suite 100 Anchorage, Alaska 99501 RE: Well Completion Report Aurora Gas, LLC: Aspen #1 (PTD 205-111) Dear Commissioner Norman: ~~~~/~~ ~~~ r ~ Alaska Gil & Gas C 9 2006 Anch°ra9a fission Aurora Gas, LLC hereby submits its Well Completion Report for the work performed in drilling its Aspen #1 exploration well on the west side of Cook Inlet. Please find enclosed the following information for your files: 1) Form 10-407 Well Completion or Re-completion Report and Log 2) Wellbore Schematic 3) Well Operations Summary 4) CD containing the mud log and all wireline logs run If you have any questions or require additional information, please contact me at (713) 977-5799 or Bill Penrose at Fairweather at 258-3446. Sincerely, AURORA GAS, LLC J. Edward Jones Vice President, ] enclosures and Operations c: Mr. Bill Penrose -Fairweather ^',t~~ -' ~ L ~ LLC 10333 Richmond Avenue, Suite 710 • Houston, Texas 77042 • (713) 977-5799 • Fax (713) 977-1347 1400 West Benson Blvd., Suite 410 • Anchorage, Alaska 99503 • (907) 277-1003 • Fax (907) 277-1006 STATE OF ALASKA {~~~~•~~ ALAS~IL AND GAS CONSERVATION COMMI~N C ~~ WELL COMPLETION OR RECOMPLETION REPORT AND L~-~~ o 1a. Well Status: Oil^ Gasp ~ Plugged ^ Abandoned^ `,y~•f7b zonnc zs.~os GINJ^ WINJ^ WDSPL^ No. of Completions Suspended^ WAG^ 2onnc 2s.~~o Other 1b. Well Cla BSka Qjf Development ^ Service ^ Straf 2.Operator Name: Aurora Gas, LLC 5. Date Comp., Susp., or Aband.: 9/6/05 12. Permit to Drill Number: 205-111 3. Address: 1400 W. Benson Blvd., Suite 410, Anchorage, AK 99503 6. Date Spudded: ,t, ,~y~y.31; X005 ~~~ 13. API Number: 50-283-20114-00 ' 4a. Location of Well (Governmental Section): Surface: 940' FSL, 324' FWL, Sec 33, T12N, R11W, SM 7. Date TD Reached: ~ August 15, 2005 ~,• 7~' 14. Well Name and Number. ~ Aspen #1 Top of Productive Worizon: Same 8. KB Elevation (ft): 18' AGL ' 15. Fieki/Pool(s): Total Depth: Same 9. Plug Badc Depth(MD+TVD): 1,265' Exploratory 4b. Location of Well (State Base Plane Ordinates): Surface: x- 278848 y- 2589811.9 Zone- 4 10. Total Depth (MD + TVD): 4,485' MD/TVD ~ 16. Property Designation: C-061387 TPI: x- 278848 y- 2589811.9 Zone- 4 Total Depth: x- 278848 y- 2589811.9 Zone- 4 11. Depth Where SSSV Set: N/A 17. Land Use Permit: N/A 18. Directional Survey: Yes ^ No ~ 19. Water Depth, if Offshore: N/A feet MSL 20. Thickness of Permafrost: N/A 21. Logs Run: Comp. Neutron, GR, Litho-Der-stty, Array Induction, SP, CBL, Cal, FMI, DSI, Pert, Mud Log 22. CASING, LI NER AND CEMENTING RECORD EASING WT. PER GRADE SETTING DEPTH MD SETTING D EPTH TVD HOLE SIZE CEMENTING RECORD AMOUNT ~ TOP BOTTOM TOP BOTTOM PULLED 13-3/8" 54.5# J-55 18' 95' 18' 95' ' Driven N/A 0' 9-518" 36# J-55 18' 693' 18' 693' 12-1/4" Cmt'd to surf w/ 80 bbls 0' 5-1/2" 15.5# J-55 18' 4,484' 18' 4,484' 7-7/8" Cmt'd to surf w/ 177 bbls . 0' 23. Perforations open to Production (MD + TVD of Top and Bottom 24. TUBING RECORD Interval, Size and Number; if none, state "node"): SIZE DEPTH SET (MD) PACKER SET (MD) None N/A 25. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD} AMOUNT AND KIND OF MATERIAL USED WA 26. PRODUCTION TEST Date First Production: N/A Method of Operation (Flowing, gas lift, etc.): N/A Date of Test: Wours Tested: Production for Test Period Oil-Bbl: Gas-MCF: Water-Bbl: Choke Size: Gas-0il 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 nece ry). Submit core chips; if none, state "none". n , • ;~~~ None „t .r . ~Q~S ~~~- JUN ~ ~ 2006 `~• ~ Z 6 S&[{fR `•~',. a ~ -~~~a 28. GEOLOGIC MARKE 29. FORMATION TESTS NAME TVD Indude and briefly s rite test results. List intervals tested, and attach detailed supporting da as necessary. If no tests were conducted, state Base of Glacial Wash 722' 722' "None". TSUGA 2.4 1560' 1,560' All intervals were tested with no significant rate or amount of gas TSUGA 2-5 2,550' 2,550' being produced. / TSUGA 2-6 3,480' 3,480' , 30. List of Attachments: O "ons Summa Wellbore Schematic Di ital C ies of All L 31. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Bitt Penrose 258-3448 Printed Name: ~, ~ Jones Title: Vice Presid~rrt, Engineering and Production S~ nature: Phone: 713-977-5799 pate: ~ ~ ~ Q to U o t / ,, INSTRUCTIONS / General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is chanced. Item 1 a: Classification of Service wells: Gas Injection, Water Injection, Water-Attemating-Gas Injection, Salt 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 sepreaated. Each seoreoated pool is a completion. Item 4b: TPI (Top of Producing Interval). Item 8: The Kelly Bushing elevation in feet above mean low low water. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 20: True vertical thickness. Item 22: Attached supplemental records for this well should show the details of any muRiple stage cementing and the location of the cementing tool. Item 23: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producng intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to tie separately produced. showing the data pertinent to such intervaD. 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 ~s._~4u-ara CsBS, LLC Aspen No. 1 Final Configuration 13 3/8" 54SS J-55 Structural Conductor driven to refusal (95') ~ 5/8" 36b Surface Casing set at 693' ~enaent w/ 50 bbls 14 ppg lead and 30 ibls 14S ppg Gas-$loc~ "G" w/ good xdu'ns observed at surface. Perforations: 1368' -1388' Squeezed Off Perforattong: 1760' -1770' Squeezed Olt Perforations: 2125' - 2145' Perforatbns: 2351' -2371' Balanced cement plug 1,265' to 1,373' Retainer ~ 1,714' Cmt between retainer & CIBP (8 S:) CIBP ~ 1,779' 85 H balanced cement plug 2,891' to 2,977' Perforations: 2984' • 2994' Perorations: 3006' -3026' Perforations: 3444' -3454' Peroratioas: 3491' -3506' Perforations: 381 l' -3831' RBP ~ 3,843' PBTD 4355' Drilled 7 5/8" Hole to 4485' _ . _ _..5ii J-55 Casing to 4484' 1ND ('I'VD) 40.6 bbls 13.5 ppg lead cmt and 136 bbls 15.8 ppg t8il romwnt, t • OPERATIONS SUMMARY Aurora Gas, LLC Aspen #1 7/28/05 Lay down felt and Herculite and prep pad for setting in rig components. Mobilize in Aurora Well Service Rig #1 from Lone Creek No. 3 wellsite. 7/29/05 Set matting boards, and spot rig modules. 7/30/05 Mobilize in and spot rig modules, RU. PU hammer to drive conductor. Bevel and weld pipe as driven. Hit refusal at 68'. LD hammer and prepare to drill out (drill and drive) to gain additional footage. RU power swivel. 7/31/05 RU rig floor, tong lines, tongs, kelly hose, etc. RU riser on conductor, drill hole. Install flow line. PU 12 '/a°' bit and drill OH for conductor. 8/1/05 Continue drill and drive operations, drill 12 '/4" hole for conductor installation. POOH, LD swivel, PU hammer, weld on section of 13 3/8" conductor, and finish driving conductor to 95' RKB. LD hammer. Install starter head and diverter. RU mud loggers, install gas detectors and PVT system. Provided notice 08/01/05 @ 0830 hrs to AOGCC for opportunity to witness diverter test on following day. 8/2/05 Continue NU of diverter system, check Koomey bottles, haul in mud and test gas sensors. Modify flow line and install flow sensor. RU trip tank and work on PVT system. RU control panel for diverter and function test entire system. Witness waived. PU 7 7/8" BHA to drill pilot hole and spud well. TD at midnite 160 ft. Mud weight 11 ppg. 8/3/05 Drill ahead on pilot hole. Survey at 509 ft, 2 deg. Drill ahead to 700 ft. Mud wt 11 ppg. 8/4/05 TOOH to c/o BHA. LD 7 7/8" pilot hole BHA assembly and pick-up 12 1/a" assembly to open pilot hole to 12 1/a" to 700 ft. CBU and prepare for round trip to condition hole for surface casing. Mud weight 11 ppg. 8/5/05 Pump and back-ream out of hole. On trip back in hole, hit bridge at 350 ft. PU swivel and pump /rotate through and continue TIH to 700 ft. Condition mud for casing. Pump out of hole, stand back jars and DC's, LD NB stab and bit. RU to run 9 5/8" surface ~ • casing. Run 9 5/8" surface casing, tag fill at 685 ft. RU and circulate/ wash to 693 ft. Circulate hole clean, RU cementers and cement surface casing using 50 bbls 14.0 ppg cement and 30 bbls 14.5 ppg Gas-Block "G" cement w/ good returns observed at surface. Cement displaced w/ rig pumps, plug bumped, floats checked, OK. RD cementers, wash lines, drain diverter and wash out, center pipe w/ annular on diverter and WOC. 8/6/05 Cleaning surface equipment, WOC. ND diverter, cut and lay out 9 5/8" stub, remove diverter. Cut and dress 9 5/8" casing for installation of casing head. Weld on 11" 3M casing head, allow to cool. Test wellhead t/ 2500 psi f/ 10 min. NU BOPE and RU to test complete BOP system and choke. 8/7/05 Finish NU of BOPE. Function test all and cavity test stack in preparation for AOGCC witness of full test. Test stack w/ AOGCC witness, c/o kelly valve, set back swivel. PU BHA and RIH. Wash /circulate from 635 ft - 655 ft, while conditioning mud. Test surface casing to 1500 psi for %z hr, OK. Repair pop-off on mud pump. Drill out float equipment and 20 ft of new hole. Circulate bottoms up and RU for MWE FIT. Perform FIT, formation broke down at 14.8 ppg MWE. Continue drill ahead to 760 ft. Mud weight 9.5 ppg. 8/8/05 Drill ahead to 1042 ft, wellbore survey at 1010' (2 deg). Drill ahead to 1540 ft, wellbore survey at 1506' (4 deg). Drill ahead to 1696 ft, perform short trip of 5 stands, well good, no fill. Drill ahead to 1976 ft. Mud weight 9.5 ppg. 8/9/05 Drill ahead to 2041 ft. CBU and wellbore survey at 2005 ft (3.75 deg). Drill ahead to 2453 ft, shut down to repair pump #1. Drill ahead to 2540 and wellbore survey at 2506 ft (3.75 deg). Short trip to 1610 ft, TIH, hole slick, no fill. TIH, work pipe while repairing pump. Mud weight 9.5 ppg. 8/10/05 Work pipe and circulate while completing rig repairs. Drill ahead to 2955 ft. Stop drilling and work pipe while repairing pump. Drill ahead to 3041 ft, CBU and wellbore survey at 3007 ft (2.75 deg). Drill ahead to 3103 ft. Mud weight 9.5 ppg. 8/11/05 Drill from 3103ft - 3228ft, CBU and monitor well. Perform wiper trip to 2509ft, hold kick drill. PU swivel and wash back to bottom, had loft fill. Drill to 3538ft, CBU and wellbore survey at 3505ft (1.5 deg). Drill ahead to 3600ft. Shut down 1.5 hrs while repairing pump. Mud weight 9.5 ppg. 8/12/05 Drill ahead to 3885ft, CBU, pump dry job and TOH for bit. Change out jars and repair pump. 8/13/05 • • TIH, tag fill at 3767 ft. LD 4 jts DP and wash/ream to 3885 ft. Drill ahead to 4034ft. Wellbore survey at 4000 ft, 3 deg. Repair pump, drill ahead to 4156ft. Repair pump. Mud weight 9.5 ppg. 8/14/05 Down for pump repairs. Drill ahead to 4410ft, broke torque arm on power swivel, shut down and repair same. Drill ahead to TD at 4448ft. Mud weight 9.5 ppg. 8/15/05 Drill ahead to TD at 4485ft. CBU and wellbore survey at 4470ft, 4 deg. POOH, started swabbing at 4100ft. Pump out, hole tight from 3751ft - 3315ft. Work on swivel, unable to repair, decision made to POOH for repair. POOH, pull wear bushing, set test plug, RU to test BOPE. Test BOP's 250 / 3000 psi. Test gas alarms. Repair power swivel torque arm. 8/ 16/05 Rig repairs contd. RIH w/ BHA and 5 stands DP, i.e. 690ft. PU swivel, break circulation. Hold PJSM, break out saver sub, install lower valve on swivel, TIH washing and reaming last 45ft to bottom. Circulate and condition for wireline logs. POOH for logs. RU Schlumberger, PJSM, PU Schlumberger logging tools. RIH w/ Platform Express logging suite, log to WLD of 4470ft. POOH w/ tools and PU suite #2 consisting of FMI and DSI. RIH w/ run #2. Mud weight 9.5 ppg. 8/ 17/05 Finish logging run #2. POOH, LD tools and RD Schlumberger. Perform rig maintenance and repairs while wait on orders. Mud weight 9.5 ppg. 8/18/05 Rig repairs and maintenance while waiting on orders. RIH w/ DP, hold BOP drill while RIH. Kelly up and wash last 16ft to bottom. 440 units trip gas on bottoms up. Circulate and condition hole while waiting on orders to run casing. Mud weight 9.6 ppg. 8/19/05 Circulate and condition hole while waiting on orders. Repair pumps. Pump dry job and POOH laying down drillpipe and BHA in preparation for running casing. LD DP and BHA. LD power swivel and subs. PU tongs and RU to run 5 %z" casing. Install 5 %z" rams and pressure test stack. RIH w/ 5 %z" 15.5# BTC casing. Mud weight 9.6 ppg. 8/20/05 Finish RIH w/ casing and RU to circulate and cement. Cement casing in place w/ 30 bbls 10 ppg spacer, 40.6 bbls 13.5 ppg Lead Cmt, 136 bbls 15.8 Tail cement and displace w/ 106.5 bbls water. Did not bump plug. Plugs never left head until 3 bbls after start of displacement. Check floats, OK. RD cementers, clean lines, drain and wash stack and mud cross. Prep for nipple down. Clean pits. Water weight 8.4 ppg. 8/21/05 WOC, clean pits and start ND of stack. PU BOP's, set slips w/ 22k down, cut off excess 5 1/z" casing, dress, install pack-off and tubing spool. Test OK. NU BOP's. Attempt to • • test door seals to 3000 psi, failed. Change out rams and rubbers, check blinds and retest, failed. Work on problem while wait on tech from town. Water weight 8.4 ppg. 8/22/05 Work on double gate BOP body. Inspect and function test all in attempt to locate problem. Discover cement in ram body. Clean and retest all 200 / 3000 psi, OK. PU 4 3/a" bit and casing scraper. RIH PU singles to 4355 ft. Tag up on top of plug. RU swivel and circulate. Test casing to 2000 psi for 30 min, OK. Circulate and weight up brine while cleaning w/ filter and centrifuge. 8/23/05 Continue filter brine. POOH w/ bi t and csg scraper. RU Schlumberger wireline. Run CBL, GR and CCL log. POOH, RU shooting flange, lubricator, test all to 1500 psi, OK. RIH shoot the following intervals using 3 '/Z" HSD DP PJ HMX guns at 6 spf and 60 deg phasing: Run 1: 3811 - 3831 (20 ft) Run 2: 3491- 3506 (15 ft) Run 3: 3444 - 3454 (10 ft) Run 4: 3006 - 3026 (20 ft) Run 5: 2984 - 2994 (10 ft) Run 6: 2351 - 2371 (20 ft) Run 7: 2125 - 2145 (20 ft) Run 8: 1760 - 1770 (10 ft) Run 9: 1368 - 1388 (20 ft) 8/24/05 RIH w/ bit and casing scraper to 4352 ft, jets plugged, TOH /w wet string find scraper ID packed off w/ sand and scale. Clean out, RIH to 4350, reverse circulated out sand and debris and filter brine. POOH, LD bit and scraper, PU and RIH w/ WOT test packer assembly. RU test separator and lines. Set RBP at 3843 ft, POOH and set test packer at 3761 ft. RU swab tee, swab head and prepare to test. Wait until daylight to begin swabbing operations to initiate test. 8/25/05 Wait on daylight. Swab tubing to 3,700' (recovered 19 bbls), no influx of water or gas. R/D swab. Fill tubing and unseat unloader valve. Reverse circulate one hole volume, show of gas on BU. Move packer uphole to 3,389' and set. R/U to swab. Swab tubing to 3,350' (recovered 21 bbls), gas show increased to 5,000 units. S/I tubing for one hour, pressure built to 16 psi. Bleed down and attempt additional swabbing - no fluid recovered. Change swab cups, swab well, recovered % bbl brine. Pressure built to 17 psi while shut in. Conduct additional swabbing, recovered 0.9 bbl brine. R/D swab and S/I well. Pressure built to 24 psi in 2.25 hours. 8/26/05 Monitor pressure buildup. 98 psi at 0400 hrs. Blow down, fill tubing, open unloader valve, CBU, release pkr, CBU. POH to 2,920', set pkr at 2,953'. Swab 17 bbls brine. S/I well for %2 hr - 60 psi buildup. Swab 1.3 bbls and drop soap sticks. 100 psi buildup in 1 hr. Swab 1.1 bbls, monitor SITP. Built to 230 psi in 3 hrs. Open to flare, pressure • • fell off to <10 psi. Swab 0.25 bbl, monitor build-up. 320 psi in 2 hrs. FSITP 360 psi, bleed off, prep to kill well. 8/27/05 Fill tubing, release packer, POH, L!D x-nipple and pkr. RIH, set pkr at 2,083' w/ tailpipe at 3,278', commence Test #4. Swab fluid level down to 3,000' (recovered 47 bbls). Check chlorides -down to 56,000 mg/1. R/D swab, fill tbg, unseat pkr and move to 2,394' for Test #5. Swab 37.77 bbls brine from well. S/I well and monitor. Built to 175 psi in 1-3/4 hrs. Bleed down and prep to kill well. 8/28/05 Fill well, unseat pkr and POH, L/D 32 jts tbg. Observe static fluid loss for 30 min. - 6 bbUhr. P/LJ stinger, RIH to 2,920'. C&C brine, reducing weight to 8.9 ppg. Pump 10 sx Class G cement, P/LJ 3 stands, reverse out, POH. P/U perf d bull nose stinger and pkr and RIH. WOC. Set pkr and test below it to 1,500 psi for 30 min - OK. RIH, tag cmt at 2,891'. POH, L/D 16 jts tbg. 8/30/05 POH, L/D pkr. P/U CIBP, RIH, set at 1,779'. POH, P/U retainer, RIH. Set at 1,714'. Sqeeze 8 sx Class G cement below retainer. Unsting, circulate out tbg, POH to 1,390'. Spot 8 sx Class G cement. P/U to 1,270', pump well to 100 psi. WOC. POH, L!D stinger, P/LT x/o's motor and mill. 8/31 /OS RIH, tag cmt at 1,374'. WOC, CBU test Hydril to 400 psi - OK. Drill cmt from 1,374' to 1,388'. P/LJ, close Hydril for 1,200 psi test. Broke down at 800 psi. POH w/ motor, RIH open-ended to 1,422'. Pump 19.5 sx Class G cmt. Squeeze away cmt w/ 500 psi. WOC, POH. P/U BHA, RIH, tag cmt at 1,313'. Test with 1,000 psi - OK. WOC. 9/1/05 Drill hard cmt from 1,313' to 1,400'. Attempt to test perfs, pumps away at 800 psi. POH, L/D BHA. Test BOP's. M/U 4-3/4" bit & scraper, RIH to 1,403'. Wash to 1,434', C&C, POH. RIH w/ OEDP 9/2/05 Bleed off pressure, R/D swivel head, L/D 6 jts, POOH. P/U BHA, RIH, tag cmt at 1,221'. P/LT swivel, break circ, WOC. Clean out cmt from 1,221' to 1,400' -void at 1,394'. Test csg at 1,400' - no good. Wash to 1,433', circ, POOH. P/U bit and csg scraper, TIH to 1,433', POH. P/U pkr, TIH to 1,400', break circ. Set pkr, test csg to 1,500 psi for 10 min. -good test. Release pkr, pull up to 1,150', set pkr. Establish injection rate of 2 bpm at 1,000 psi. Pump and squeeze 12 bbls cmt below pkr. 9/3/05 WOC 12 hrs while holding 500 psi on tbg. Bleed off pressure, release pkr, POH. P/U motor and mill, RIH, tag cmt at 1,264'. CO cmt, 5' soft then hard to 1,380'. Void from 1,380' to 1,412'. C&C. Pressure up to test perfs, broke down at 1,300 psi. Establish injection rate of 2.25 bpm at 1,000 psi. Wash to 1,443', circ clean. POH, L/D motor. P/LJ tail pipe and pkr, RIH. Set pkr at 1,151' (tail pipe at 1,187'). • • 9/4/05 Squeeze 49 sx Class G cmt below pkr. WOC 6 hrs while holding 500 psi on tbg. Bleed off pressure, unseat pkr, POH. RIH w/ motor, tag cmt at 1,220'. WOC. Drill cement from 1,220' to 1,412', void at 1,370'. Test perfs -broke down at 1,300 psi. Injection rate 0.5 bpm at 1,300 psi. POH. RIH w/ 10 stands below packer -tailpipe at 1,497' and pkr at 869'. 9/5/05 Set packer, squeeze 11 bbls cmt out tailpipe. Release pkr, POH 8 stands, set pkr, squeeze 5.7 bbls cmt out tailpipe. WOC 12 hrs. Release pkr, POH. RIH w/bit, tag cmt at 1,202'. Wash from 1,202' to 1,373' (soft to 1,373' where string weight began stacking out). 9/6/05 CBU, POH, L/D 44 jts tbg. RIH open ended to 1,364'. Pump 5 bbls cmt. POH and WOC 12 hrs. RIH, tag cement at 1,265, stack out lOK lbs. POH, L/D all tbg. N/D BOPE, N/U tree, release rig. , [Fwd: Aspen #1 (205-111)] • • Subject:-[Fwd~lspcn r 1 (2115-1 t I )] From: T}~oznas 1~Taunder<tom_maunder@admin.state.ak.us=> Date: Thu. X12 R~1ar 2O0~ 10:22: I 1 -0900 To:.fohn Breitmcier <john.breitmeicr(i;~~,fair-~weather.com> John, Here is a message trail regarding Aspen # 1. I don't show that we have yet received any completion report for this well. Your assistance will be appreciated. Call or message with any questions. Tom Maunder, PE AOGCC -------- Original Message -------- Subject:Aspen #1 (205-111) Date:Tue, 07 Feb 2006 15:42:56 -0900 From:Thomas Maunder <torx~ maunder(aadmin.state.ak.us> Organization:State of Alaska To:Jesse Mohrbacher <jesse(dfaia-~veather.con2'--> CC:Richard Tisch <richard(c~~fairweather.com>, Steve McMains <steve zncmains~~;adrnin.statc.ak.us> Jesse and Richard, I was checking one of our summary reports over here and on checking the file noted that no completion report has been filed for Aspen #l. A sundry was issued September 6, 2005 authorizing suspension of the well for possible future use. It is noted on the returned Form 10-403 that a completion report (Form 10-407) should be submitted. Based on the weekly report of operations, it would appear that all well work was completed on September 6 so the completion report should have been submitted to the Commission about October 6. Your filing of the necessary completion report will be appreciated as will your early attention to this matter. Call or message with any questions. Tom Maunder, PE AOGCC 1 of 1 3/2/2006 3:13 PM • DATA TRANSMITTAL Please reply to: AURORA GAS, LLC 10333 RICHMOND, STE. 710 HOUSTON, TX 77042 ATTN: ANDY CLIFFORD Anchorage, AK 99501 ATTENTION: Howard Okland Enclosed CDs and Paper Prints From Aurora Gas, LLC Area Moquawkie Area, Cook Inlet, Alaska Date: 17 October, 2005 cD:#13 3 ~ ~ 1. Ashen #1 well data: LAS, PDS and PDF files for Directional Survey, Platform Express, Dipole Sonic Imager, Perforating Record, Cement Bond Log. 2. Ashen #1 well data: LAS data for Horizon mudlog. P,per Prints: 1. Aspen #1 well data: SCMT/Cement Bond Log 5"/100', Perforating Record 5"1100', Directional Survey, Platform Express 2" 1100' plus 5"/100', Dipole Sonic Imager 5"l100', Fullbore Micro-Imager (Unprocessed) 5"1100', Horizon Mudlog 2"/100'. E JAS FOR OUR F S. Received by: Date: ? al,~ ,~ AURORA GAS, LLC, 10333 RICHMOND, STE 710, HOUSTON, TX 77042 TEL: 713-977-5799, FAX: 713-977-1347 a~~~~~t~ ~~~~. ~Aur~ora Gas, LLC www.aurorapowercom Sept. 12, 2005 Mr. John Norman, Chair Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501-3539 RE: Weekly Report of Operations: Aurora Gas, LLC, Aspen #1 (PTD #205-111) Dear Mr. Norman: Aurora Gas, LLC hereby submits its final weekly report of operations for the period of August 25 -September 6, 2005 for its Aspen #1 well. The following operations took place on the dates indicated: 8/25/05 Wait until daylight hours to initiate swabbing. Swab tubing with 2 bbls pulls to 3700', no influx of water, no sign of gas. Recovered 19 bbls, rig down swabbing equipment. Fill tubing and unseat unloader valve, reverse circulate hole volume. Move packer up hole to 3389', set packer and rig up to swab. Swab tubing with 2 bbls pulls to 3350', recover 21 bbls. Gas show increase to 5000 units. Shut in tubing for 1 hour, pressure built to 16 psi, bleed down to swab again. RIH with swab to 3250', milk swab 2x fro 400' pull, pull up 1200', run into 3250' (tag. fluid at 3100'), milk 400' x5, POOH got 0.5 bbls of brine to pits. Total recovered = 21.5 bbls. Pressure built to 17 psi when shut in. RIH with swab, milk hole 4 x 500', POH with swab. Gain of 0.9 bbls to pits, shut in well and rig down lubricator and swab line. Pressure built to 22 psi in I hour, bleed down to 15 psi through gas buster, pressure built to 22 psi, bleed down to 15 psi. through gas buster. Pressure build up to 32 psi, bleed to 10 psi, builds up to 24 psi.. 8/26/05 Continue to monitor pressure buildup, 40 psi at 01:00 hours. 68 psi at 02:00 hours, bleed to 20 psi, let pressure build to 44 psi at 03:00 hours, 70 psi at 03:30 hours and 98 psi at 04:00 hours. Kill and fill tubing, open unloader valve, circulate bottoms up and lay down head. POOH to 2920' set packer. Rig up to swab, packer at 2953', recover 17 bbls. brine. Shut in well for pressure build up; SITP 60 psi at 10:00 hours, swab 1.3 bbls. Monitor SITP, drop soap stick, 100 psi build up in one hour. Bleed down to 0 psi, monitor for flow, shut in for pressure build up. RIH and swab from 2925', recovered 1.1 bbls of brine. Monitor SITP, flow to gas buster, shut in for pressure build up, 230 psi at 16:00 hours, bleed to 100 psi and shut in again, build to 216 psi in one hour (16:30 -.17:30 hours). Open to flare, pressure bleed off to <10 psi. Make two swab runs, 25 bbls gain in pits. Monitor pressure build up for two hours, build to 320 psi. Bleed to 200 psi thru gas buster, monitor pressure buildup, final shut in pressure at 24:00 hours is 360 psi, bleed of and prep to kill well. 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 • • ,. Mr. John Norman Page 2 8/27/05 Bleed off tubing, lay down swab, fill tubing and release packer. POOH and lay down x-nipple and packer. RIH, set packer at 2083', tail pipe at 3278'. Test #4, rig up to swab, function test and lubricate swab valve. Swab fluid level down to 3000', 15 runs, recovered 47 bbls. Make 4 runs checked chlorides dropped to 56000. Rig down swab, fill tubing and unseat packer, move packer to 2394' for test #5. Rig up to swab, make 11 runs unloading 37.77 bbls total from well. Last swab got no lirive to .surface. Rig down-swab lubricator, head and shut in well. Pressure build up to 50 psi in 34`mnutes; 90 psi in one hour; 175 psi in 1.75 hours. Bleed pressure to 100 psi, shut in well for build up, build to 120 psi and then it started to bleed off on its own, adjust choke, pressure continued to bleed to 25 psi where it held. Rig up to kill well. 8-28-OS Bleed off pressure, lay down swab "T", rig up circulating head, kill well, unseat packer and circulate bottoms up. RIH to 3753' tag fill, rig up circulating head and wash down having to circulate bottoms up before each connection, wash down to RBP, circulate bottoms up, rig down circulating head and POH 14 stands. Circulate and condition brine, POH to 1913', set RBP for next test, POH with remainder. Test #5 assembly, RIH with 360' of tail pipe Ion packer, set packer at 1339' and tubing tail at 1726'. Swab well in, zone producing water, t tal of 57 bbls swabbed. Rig down lubricator and swab "T" and kill well. RIH to 1990', rig up circulating head and wash down to RBP, circulated bottoms up, latch up on RBP and POH. Pick u retainer, RIH to 2955' and set retainer;-'hole taking fluid (22 bbls), do static loss, 6 bph equivale t, reduce brine weight in pits. POH, stand back tubing. 8/29/05 Lay down 32 joints of tubing. Do 30 minute static test, fluid loss 3 bbls. Pick up tinger, RIH to 2920' and rig up to circulate, circulate and condition brine, build volume while reducing brine weight to 8.9 ppg. Rig up BJ Services, hold PJSM and test lines. Pump balance plug 10 sacks type G cement, pull 3 stands and reverse out to clean tubing. POOH with tubing d pick up perf bull nose stinger and Arrowset IX packer, RIH to tag cement, test and WOC. Rig up to test cement plug, test to 1500 psi for 30 minutes, RIH and tag cement at 2891'. POO and lay down 16 jnintc ~nf ?, 7/R gibing: 8/30/05 POH and lay down packer, pick up retainer run in hole and set at 1779'. POH, lay down running tool and rebuild same. Pick up CIBP and run in hole with retainer and set at 1714'. Hold PJSM, test lines, sting in and establish injection rate, unsting. Mix and pump 8 sacks G type cement, displace with 7.65 bbls brine, stab into retainer, hesitation squeeze to 400 psi. Unsting from retainer and. circulate the long way, POH to 1390'. Rig up to cement, mix and pump 8 sacks; displace cement with 7 bbls brine and POH to 1270'. Rig up BJ to pump, pump up to 100 psi, bleed down to 50 psi, pump up to 100 psi, shut in pressure and hold, holding pressure on tubing with head pin. Rig up power swivel and shuck, blow down choke manifold and POH, lay down stinger, and pick up xo's, motor and mill. 8/31/05 • Mr. John Norman Page 3 • Make up BHA, RIH with 21 stands of tubing, tag cement at 1374'. Rig up to circulate with power swivel while waiting on cement. Circulate bottoms up, close Hydril for 400 psi test, held solid. Drill cement from 1374' to 1388', circulate bottoms up, close Hydril for 1200 psi test, broke down at 800 psi. Set power swivel back, POH wet, with motor. RIH open ended to1422', circulate to balance hole while rigging up cementers. PJSM, test lines, mix and pump 19.5 sacks class G cement with additives, POH to 650'+/-. Squeeze away cement wit 500 psi, WOC, rig down cement lines, POH, pick up BHA and RIH, tag cement at 1313'. Pick up swivel, circulate bottoms up and test perfs to 1000 psi. WOC. 9-1-OS Drill hard cement from 1313' to 1381', trouble shoot power swivel, drill cement from 1381' to 1390', void to 1400'. Attempt to test perfs, pump away at .75 bpm at 800 psi, POH and lay down a single with motor and mill. Repair hydraulic motor on power swivel. Test BOPE. Make up 4 3/a" bit and scraper, RIH, SLM to 1403', wash to 1434' and circulate. POH and RIH to circulate for squeeze job. PJSM, test lines to 2000 psi, mix and pump 6 bbls cement holding back pressure with choke, follow with 1 bbl of water and 5 bbls of brine. Lay down single and POH 10 stands, pick up single and set packer at 505', pressure up to 1500 psi with .6 bbls pumped, bleed to 1370 psi in 10 minutes, pressure up to 1500 psi and monitor, rig down BJ equipment. WOC, monitor pressure. 9-2-OS Bleed off pressure, rig down swivel head, and lay down 6 joints of tubing and POH. Pick up BHA, RIH and tag cement at 1221'. Pick up swivel, break circulation at 1990', circulate out air, WOC. Clean out cement from 1221' to 1400', void at 1394', test casing at 1400'. Circulate, wash to 1433', circulate and POH with motor. Work on BOP's and Koomey unit. Pickup motor and test, locked up, lay down motor, pick up bit and scraper. Pick up packer, TIH to 1433', TOH with bit and scraper. Pick up packer and TIH to 1400', break circulation. PJSM, set packer and test lines to 2000 psi, test casing to 1500 psi for 10 minutes. Bleed off and release packer, POH to 1150', test lines to 2000 psi. Set packer, establish injection rate, 2 bpm at 1000 psi. Mix and pump 10 bbls of Class G cement at 14.5 ppg w/ additives, follow with 2 bbls tail cement at 1.5.8 ppg. Displace ~~ith 1 hbl of water and 8.5 bblc brine, Final pressure 733 t~si at ;75 bpm, 10 minute pressure at 562 psi. 9-3-OS WOC, hold 500 psi on tubing. Bleed off pressure and release packer, POH. Pick up motor and mill, RIH tag cement at 1264', clean out cement from 1264', 5' soft, hard cement to 1380', void to 1412', circulate clean. Rig up and test perfs, broke down at 1300 psi, establish injection rate, 2.25 bpm at 1000 psi. Wash to 1433', circulate clean, TOH and lay down motor. Pick up tail pipe and packer, TIH. Rig up to cement, PJSM, break circulation, test lines to 2000 psi, set packer at 1151', tail pipe at 1187'. 9-4-OS Establish injection rate, 2.2 bpm at 1100 psi. Mix and pump 49 sacks of class G at 15.8 ppg + additives, displace with 1 bbl water followed with 5 bbls of brine. Slow rate to .4 bpm, after 7 • • Mr. John Norman Page 4 bbls pressure at 770 psi, after 8 bbls pressure at 1000 psi, bleed to 880, after 3 minutes at 8.12 bbls 2000 psi, bleed to 1950 psi. WOC with 500 psi SITP, bleed 100 psi off, watch for flow back. Unseat packer and POH for motor and mill. RIH with motor, tag cement at 1220', WOC. Drill cement from 1220' to 1412', void at 1370, circulate bottoms up, test perfs, broke down at 1300 psi, check surface equipment, establish injection rate, .5 bpm at 1300 psi. POOH check motor, service rig, RIH with motor to 1505'. POH, pick up 10 stands of tail pipe and RIH, pick up packer and continue to RIH to 1497' (packer at 869'), rig up BJ Services. 9-5-OS PJSM, break circulation, test lines to 4000 psi, set packer and establish injection rate. Rate 2 bpm at 1300 psi, release packer, pump 2.7 bbls water, batch and pump 11 bbls Type I cement at 14.8 ppg + additives, displace with 4 bbls brine. POH 8 stands, set packer at 370', squeeze away 5.7 bbls cement, FIP 1300 psi at .4 bpm; bleed to 950 psi in 3 minutes. WOC, attempt to release packer, no travel, (discuss options, line up tools). Work and release packer, POH, no signs of cement on packer or tail pipe. Pick up bit and RIH, tag cement at 1202', wash from 1202' to 1373'. 9-6-OS Circulate bottoms up, POH and lay down 44 joints of 2 7/8" tubing, TIH open ended to 1364' and rig up to cement. PJSM, break circulation with 2.7 bbls water, test lines to 1000 psi, mix and pump 19 sacks Type I cement at 15.2 ppg + additives, 1 bbl water and 5 bbls brine. POH, to 932', reverse tubing volume, POH. WOC, clean pits, rebuild test pump, rig down choke line and super choke. RIH, tag cement at 1260', stack lOK at 1265', POH and lay down tubing. RIH with 7 stands, POH laying down tubing. Nipple down BOPE and nipple up tree. If you have any questions or require additional information, please contact me at 277-1003 or Richard Tisch at 258-3446. Sincerely, AURORA GAS, LLC 4 `~. ~d Jones Executive Vice Presi ent Engineering -Operations cc: Duane Vaagen Richard Tisch Jesse Mohrbacher tiAurnra Gas, LLC www.aurorapowercom August 25, 2005 - -- Mr. John Norman, Chair =~ .~ « , Alaska Oil & Gas Conservation Commission 333 West 7~' Avenue, Suite 100 Anchorage, Alaska 99501-3539 RE: Weekly Report of Operations: Aspen #1(PTD #205-111) Dear Mr. Norman, Aurora Gas, LLC hereby submits its report of operations for the week of August 18 - August 24, 2005 for its Aspen #1 well. The following operations took place on the dates indicated: 8/18/05 Rig repairs and maintenance while waiting on orders. RIH w/ DP, hold BOP drill while RIH. Kelly up and wash last 16 ft to bottom. 440 units trip gas on bottoms up. Circulate and condition hole while waiting on orders to run casing. Mud weight 9.6 ppg. 8/19/05 Circulate and condition hole while waiting on orders. Repair pumps. Pump dry job and POOH laying down drillpipe and BHA in preparation for running casing. LD DP and BHA. LD power swivel and subs. PU tongs and RU to run 5 %2" casing. Install 5 '/2" rams and pressure test stack. RIH w/ 5 '/2" 15.5# BTC casing. Mud weight 9.6 ppg. 8/20/05 Finish RIH w/ casing and RU to circulate and cement. Cement casing in place w/ 30 bbls 10 ppg spacer, 40.6 bbls 13.5 ppg Lead Cmt, 136 bbls 15.8 Tail cement and displace w/ 106.5 bbls water. Did not bump plug. Plugs never left head until 3 bbls after start of displacement. Check floats, OK. RD cementers, clean lines, drain and wash stack and mud cross. Prep for nipple down. Clean pits. Water weight 8.4 ppg. 8/21 /OS WOC, clean pits and start ND of stack. PU BOP's, set slips w/ 22 k down, cut off excess 5 '/2" casing, dress, install pack-off and tubing spool. Test OK. BU BOP's. Attempt to test door seals to 3000 psi, failed. Change out rams and rubbers, check blinds and retest, failed. Work on problem while wait on tech from town. Water weight 8.4 ppg. 8/22/05 Work on double gate BOP body. Inspect and function test all in attempt to locate problem. Discover cement in ram body. Clean and retest al1200 / 3000 psi, OK. PU 4- 3/4" bit and casing scraper. RIH PU singles to 4355 ft. Tag up on top of plug. RU swivel 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 ~ } ` 1 4 Mr. John Norman Page 2 and circulate. Test casing to 2000 psi for 30 min, OK. Circulate and weight up brine while cleaning w/ filter and centrifuge. 8/23/05 Continue filter brine. POOH w/ bit and csg scraper. RU Schlumberger wireline. Run CBL, GR and CCL log. POOH, RU shooting flange, lubricator, test all to 1500 psi, OK. RIH shoot the following intervals using 3 '/2" HSD DP PJ HMX guns at 6 spf and 60 deg phasing: Run 1: 3811 - 3831 (20 ft) Run 2: 3491- 3506 (15 ft) Run 3: 3444 - 3454 (10 ft) Run 4: 3006 - 3026 (20 ft) Run 5: 2984 - 2994 (10 ft) Run 6: 2351- 2371 (20 ft) Run 7: 2125 - 2145 (20 ft) Run 8: 1760 -1770 (10 ft) Run 9: 1368 -1388 (20 ft) 8/24/05 RIH w/ bit and casing scraper to 4352 ft, jets plugged, TOH /w wet string find scraper ID packed off w/ sand and scale. Clean out, RIH to 4350, reverse circulated out sand and debris and filter brine. POOH, LD bit and scraper, PU and RIH w/ WOT test packer assembly. RU test separator and lines. Set RBP at 3843 ft, POOH and set test packer at 3761 ft. RU swab tee, swab head and prepare to test. Wait until daylight to begin swabbing operations to initiate test. If you have any questions or require additional information, please contact me at 277- 1003 or Duane Vaagen at 258-3446. Sincerely, AURORA GAS, LLC J,iEdward (Ed) Jo~ xecutive Vice Pr sident Engineering -Operations cc: Duane Vaagen ,. • ~Aurrora Gas, LLC www.aurorapower.com August 23, 2005 Mr. John Norman, Chair Alaska Oil & Gas Conservation Commission 333 West 7~' Avenue, Suite 100 Anchorage, Alaska 99501-3539 RE: Weekly Report of Operations: ~ 1 4 *~;~~1~ ~~ .~ ,~.c. ~' ~ ~i~:w t„~) ~ .. Dear Mr. Norman, Aurora Gas, LLC hereby submits its report of operations for the week of August 11 - August 17, 2005 for its Aspen #1 well. The following operations took place on the dates indicated: 8/11/05 Drill from 3103 ft - 3228 ft, CBU and monitor well. Perform wiper trip to 2509 ft, hold kick drill. PU swivel and wash back to bottom, had 10 ft fill. Drill to 3538 ft, CBU and wellbore survey at 3505 ft (1.5 deg). Drill ahead to 3600 ft. Shut down 1.5 hrs while repairing pump. Mud weight 9.5 ppg. 8/12/05 Drill ahead to 3885 ft, CBU, pump dry job and TOH for bit. Change out jars and repair p~P• 8/13/05 TIH, tag fill at 3767 ft. LD 4 jts DP and wash/ream to 3885 ft. Drill ahead to 4034 ft. Wellbore survey at 4000 ft, 3 deg. Repair pump, drill ahead to 4156 ft. Repair pump. Mud weight 9.5 ppg. 8/14/05 Down for pump repairs. Drill ahead to 4410 ft, broke torque arm on power swivel, shut down and repair same. Drill ahead to TD at 4448 ft. Mud weight 9.5 ppg. 8/15/05 Drill ahead to TD at 4485 ft. CBU and wellbore survey at 4470 ft, 4 deg. POOH, started swabbing at 4100 ft. Pump out, hole tight from 3751 ft - 3315 ft. Work on swivel, unable to repair, decision made to POOH for repair. POOH, pull wear bushing, set test plug, RU to test BOPE. Test BOP's 250 / 3000 psi. Test gas alarms. Repair power swivel torque arm. 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 ~ a ~ e • Mr. John Norman Page 2 8/16/05 Rig repairs contd. RIH w/ BHA and 5 stands DP, i.e. 690 ft. PU swivel, break circulation. Hold PJSM, break out saver sub, install lower valve on swivel, TIH washing and reaming last 45 ft to bottom. Circulate and condition for wireline logs. POOH for logs. RU Schlumberger, PJSM, PU Schlumberger logging tools. RIH w/ Platform Express logging suite, log to WLD of 4470 ft. POOH w/ tools and PU suite #2 consisting of FMI and DSI. RIH w/ run #2. Mud weight 9.5 ppg. 8/17/05 Finish logging run #2. POOH, LD tools and RD Schlumberger. Perform rig maintenance and repairs while wait on orders. Mud weight 9.5 ppg. If you have any questions or require additional information, please contact me at 277- 1003 or Duane Vaagen at 258-3446. Sincerely, AURO AS, LLC _~ d Jone Executi e Vice President Engineering -Operations cc: Duane Vaagen ~, J ~' ~ , ~ ~ - ,#~ r~ ~ ~ ~~ ~,~ ~ ~ °? ~ FRANK H. MURKOWSK/, GOVERNOR ~~ OI~ ~ t7[0~7 333 W. 7'" AVENUE, SUITE 100 COI~TSERQA~1'IO1~T CO1rII~'IISSIOI~T ~ ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Jesse Mohrbacher ~ Engineer ~, Aurora Gas, LLC 1400 W. Benson Blvd, Ste 410 Anchorage, AK 99503 Re: Aspen # 1 Sundry Number: 305-263 Dear Mr. Mohrbacher: 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. Please provide at least twenty-four (24) hours notice for a representative of the Commission to witness any required test. Contact the Commission's petroleum field inspector at (907) 659-3607 (pager). As provided in AS 31.05.080, within 20 days. after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a 'day or weekend. A person may not appeal a Commission decision S erior Court unless rehearing has been requested. /f Ch DATED this day of September, 2005 Encl. K. • E & P SERVICES,INC. September 8, 2005 Mr. John Norman, Chair Alaska Oil and Gas Conservation Commission 333 W. 7~' Avenue, Suite 100 Anchorage, Alaska 99501-3539 Re: Proposed Aspen No. 1 Well Suspension Dear Mr. Norman: Aurora Gas, LLC proposes to suspend the Aspen No. 1 exploration well for future ~~ consideration for conversion to a Class II injection well. The work that has been performed is outlined in the attached procedure. Attached please find a completed Form 10-403 for the work, an outline procedure. and a current wellbore schematic. If you have any questions, please contact the undersigned at 907-258-3446. Sincerely, FAIRWEATHER E&P SERVICES, INC. ,~///f Jesse ohrbacher Attachments: 10-403 Application for Sundry Approvals Outline Procedure Current Wellbore Schematic STATE OF ALASKA ~ ~~ C3 /C ALAS~OIL AND GAS CONSERVATION COMMI9~JN L ~7 APPLICATION~FOR SUNDRY APPROVALS ~n AA(: ~~ ~Rn q~glz4~r ~: 1. Type of Request: Abandon Suspend ~ Operational shutdown Perforate W9iver Other ' Alter casing ^ Repair well ^ Plug Perforations ^ Stimulate ^ Time Extension Change approved program Q Pull Tubing ^ Perforate New Pool ^ Re-enter Suspended Well ^ , 2. Operator Name: 4. Current Well Class: / 5. Permit to Drill Number: Aurora Gas, LLC Development ^ Exploratory ^~ -111. 3. Address: Stratigraphic ^ Service ^ 6. API Number: 1400 W. Benson Blvd, Ste 410, Anchorage, AK 99503 50-283-20114-00 r` 7. KB Elevation (ft): 9. Well Name and Number: 448.5' MLLW, 16' AGL Aspen No.1 ~ 8. Property Designation: 10. Field/Pools(s): C-061387 Wildcat 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth ND (ft): Effective Depth MD (ft): Effective Depth ND (ft): Plugs (measured): Junk (measured): Casing Length Size MD TVD Burst Collapse Structural 80 11.875 80 ~ 80 NA NA Conductor Surface 676 9.625 693 693 3520 2020 Intermediate Production 4469 5.5 4484 ~ 4484 4810 4040 Liner Perforation Depth MD (ft): Perforation Depth ND (ft): Tubing Size: Tubing Grade: Tubing MD (ft): Multiple Zones 1368'-3831' Same as MD Packers and SSSV Type: retainers, CIBP Packers and SSSV MD (ft): retnr@2934', CIBP@1780', retnr@1714' 12. Attachments: Description Summary of Proposal 13. Well Class after proposed work: Detailed Operations Program ^~ BOP Sketch ^ Exploratory Q ~ Development ^ Service ^ 14. Estimated Date for 15. Well Status after proposed work: / Commencing Operations: 9/5/2005 Oil ^ Gas ^ Plugged ^~ Abandoned ^ ,~- 16. Verbal Approval: Date: 5- p WAG ^ GINJ ^ WINJ ^ WDSPL ^ Commission Representative: Winton Aubert 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Printed Name Jesse Mohrbacher Title Engineer Signature ~..f?hone 907-258-3446 Date 8-Sep-05 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: ~~ -~~ 3 Plug Integrity ^ BOP Test ^ Mechanical Integrity Test ^ Location Clearance ^ Other: {~-~ d,<, ~l t~ rvC tj [1 I~t ~`1 tM, hC ~ .~D r L1~1~ ~OJ.i~L.C3GG'~E'a(..~ , Subsequent F eq 'r _ A ~. °7 S f"~ ,~j~~ ~ ~ ~~~5 "` [ APPROVED BY Approved COMMISSIONER THE COMMISSION Date: O - ~~ ~_ Form 10-403 Revised 07/2005 _ 4 ..~... / ,/ Submit in Duplicate • Aspen No. 1 Well Suspension Program September 6, 2005 Current Prognosis: The Aspen No. 1 well is currently configured as in Attachment I. Rather than plugging the well as a dry hole, the well was considered for conversion for possible Class II waste disposal prior to demobilization of the rig. Repeated squeezes on the perforated interval from 1368'-1388' were unsuccessful when tested to 1500 psi as required by 20 AAC 25.412 (c) after drilling out the cement in the 5-1/2 inch casing. After these squeezes, limited on-site cement supplies precluded additional squeezing and therefore Aurora Gas, LLC has elected to suspend the well for possible future conversion to a Class II disposal ~ well or P&A, if necessary. Per 20 AAC 25.110, Aurora believes there is sufficient justification to suspend the well pending possible use as a service well in the future. No abnormally geopressured strata are present in the well and the well will be left in the status identified in Attachment 1. Cement and mechanical plugs in the well are also identified in Attachment 1. Aurora will maintain the integrity of the Aspen No. 1 location and provide the Commission with a well status report every five years and clear the location upon final P&A of the well. The following procedure was used to suspend the well after consultation with Winton Aubert of the AOGCC on September 5, 2005. Procedure 1. RU BJ Services and required cementing equipment. 2. Pre-mix water on-board BJ's truck with sufficient CaC12 fora 1.5% solution as mix water, add friction reducer as specified by BJ Services Engineering for ~ procedure 3. RIH and seta 12 bbl balanced cement plug from 1490 to 986 feet. POOH to 870 feet. Close pipe rams and squeeze 5 bbl cement into perforations from 1368 to 1388 feet. Shut in well. Wait on cement 12 hours. 4. POOH and PU bit or mill, prepare to TIH to tag cement. 5. Verify cement minimum 100 feet above perforations at 1368 feet (i.e. cement / must be no deeper than 1268 feet) by stacking string weight on plug. 6. Circulate as necessary to leave 9.0 ppg kill weight fluid in well. 7. POOH and nipple down BOP stack. 8. Nipple up wellhead tree on tubing spool. Move to Kaloa #4 well. ~ 9. File well completion report with the AOGCC. jrm 6-SEP-OS Rev. 2.0 -1- Specifications and Info: MASP: Use fracture gradient of 12 ppg MWE. • = 12 ppg (Frac Grad) - 9.2 ppg (Brine Grad) x .052 x 2722 ft = 396 (400 psi) Conservative number for uppermost hesitation squeeze pressure at surface. Yld on Neat "G" is 1.15 ft3 slurry /sack Water required / sk = 4.97 gal /sack Weight = 15.8 ppg or 118.31b /ft3 1 bbl = 5.614 ft3 5 '/z" 15.5 lb/ft casing volume = .0238 bbl/ft = .1336 ft3 / ft 2 7/8" 6.5 lbJft tubing volume = .00579 bbl/ft = .0325 ft3 / ft 2 7/8" tbg x 5 %" csg annular volume = .0158 bbl/ft = .0886 ft3 / ft -2- Auno~r'~ s, LLC Aspen No. 1 September 6, 2005 Proposed Suspended Configuration FIT performed at 720', had 14.8 u ppg MWE test prior to breakdown. Perforations: 1368' -1388' Perforations: 1760' -1770', squeezed with IS sx G - Perforations: 2125' - 2145' Perforations: 2351' - 2371' - Perforations: 2984' - 2994' Perforations: 3006' - 3026' - Perforations: 3444' - 3454' Perforations: 3491' - 3506' Perforations: 3811' - 3831' - PBTD 4355' Drilled 7 5/8" Hole to 4485' • Wellhead tree installed on tubing spool. 11 7/8" 71.8# Structural Conductor to be driven to 80' or refusal 5/8" J55, 36# Surface Casing set at 93' ;ement w/ 50 bbls 14 ppg lead and 30 ~bls 14.5 ppg Gas-Block "G" w/ good 3alanced cement plug from 1490' to 1263' / 'ested Wet. CI" 12,000 ppm l Retainer @ 1714, ;IBP @ 1780' Tested Wet. CI" 55,000+ ppm ~ 75 ft balanced cemeut plug placed on ton of retainer. Retainer set at 2934' l 'ested Gas: Maz Flow rate 40 icfd at 25 psi. 5'/z" 15.5# J-55 Casing to 4484' MD (TVD) 40.6 bbls 13.5 ppg lead cmt and 136 bbls 15.8 ppg tail cement. + - ~` r ~,' ~ , ~-. ' ~ ~f - 1 I I +, _ e' ~- :, , f, -., ti ~~ _. ,, i ~,~ • ' 4 4 ~~ _ ~_ ^ ~1 ~ . • ,, . ~, Attachment I -3- a • ~ ~~i I ~~~ ~ ~ ~~ ~ a ~ ~~ ~ ~ ~ ~ ,~ , FRANK H. MURKOWSK/, GOVERNOR ~-7~ OIL otsil ~,5 333 W. 7"' AVENUE, SUITE 100 CO~S~R~~iiOa` CO~~IISSIO~ ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 J. Edward Jones Exec, Vice President Aurora Gas, LLC 1400 W. Benson Blvd. Ste 410 Anchorage, AK 99503 Re: Wildcat Aspen # 1 Sundry Number: 305-260 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. Please provide at least twenty-four (24) hours notice for a representative of the Commission to witness any required test. Contact the Commission's petroleum field inspector at (907) 659-3607 (pager). As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd .day falls on holiday or weekend. A person may not appeal a Commission decisi t Superior Court unless rehearing has been requested. ____~ K. Norma DATED this day of September, 2005 Encl. Sent By: AURORA#POWER; 7139771347; Sep-1 16: ; Page 2 ~~ STATE OF ALASKA ALASKA Olt. ANp GAS CQNSERVATION COMMISSIO ~~~ APPL,~CATION FOB ~UNQRY APPRQVALS - 2o AAC 2s.2so 1. Type of Request: Abandon Su$pend ^ Operational shutdown Perforate Vllaiver Othet Alter aaeina ^ Repair well © Plug Perforatidn9 ^ Stimulate ^ Time Extension ^ Change approved prayram ^ pull 1'ubrng ^ Perforate New Poot ^ f3e-enter Suspended Well ^ 2. Operator Name: 4, Currsnt Weil Class: 5- Permit to brill Number; Aurora Goa, LLG Development ^ Exploratory Q ~i~117 ~ 3. Addres6: Stratigraphlc [] Service ^ 8. APr Number: i 1400 W. Benson Blvd. Ste 410, Anchorage, AK 99503 50-283-20114-04 7. KB Elevation (ft): S. WeN Name and Number 446.5' MLLW, 16' AC3L Aspen No.i /~ 8, Property Desi~ft8tidn: 10. Field/Poots{s): j C-081397 WUdcat 11, PRESENT WELL CONDITIt)N SUMMARY Total Depth MD (ft): ToCel Depth TVI7 {tt): Effective Depth MD (ft): EftectNe pepth TVD (tt): Plugs {measured): Junk (measured): Casing Length Size MD TVO Burst Collapse Structural 80 71.875 80 60 NA fJA conduaor Surface 677 9,825 699 B93 3520 2029 Intertnedia#e Production 4467 5,5 4484 +tA84 4810 4040 liner Perforation Depth MD {ft): Perforation Depth TVD (ft): Tubing Slza: Tubing Grade' Tuhinp MD (ft}: Multiple Zones 1368'3831' Same as MD PBCkere and 8SSV Type: Packers and SSSV MD (h); 7Z. AttaChment6; Description Summary of Proposal 13. Weu Gass after propo~ ~1 work; ~ y.~(~/+- Detailed operations program ~ BOP Sketch ^ Exploratory I~ ~ evelopmerrt ^ SeNlce -~--' ~4. Estimated 17ate for 15. Wetl Status attar proposed work: Commencing Optlfatinns: 8/30/2005 Oil ^ Gas ^ Plugged ^ 4bandaned ^ 16. Verbal Approval; bete; 29-Aug WAG ^ GiNJ ^ WrNU ^ 'NDSPI. Q Commission Repreaerna#Ive: Winton Aubert 17. I hereby certify that the foregoing is hue and cprfact td the best of my knowledge. Contact Prinked Nam EAward Jo s Title Exec, VIGe President Phone Signature 713-977-5799 Date ~ - ---- 9!112005 ~ COMMISSION tlSE ONLY Conditions o1 approval: Notify Camml~ion so that a representative may witness Sundry Numt)er: ~ - ~~,! . Plug Integrity ^ BOP Test ^ Mechanical Integrity Test [v~'~ Location Glearanee (~ ®~AS ~3FL sEr~ n 7 200 Other: ~~., ;;.,,.. !.) ~ 2Q05 Subsequent F m R uir - ~ ~ 4 A#PROVEO 6Y ` i A"ryr~ coMMISSIONER Tt1E COMMIS610N .bate: Q Form 10-403 Revised 07!2005 ~~~~~~ ~bmit i a prate • Aspen No. l Cement Squeeze and Completion Program Current Proctnosis: The Aspen No. 1 well is currently configured as in Attachment I. To convert well for possible Class II oilfield waste disposal prior to demob of the rig, the upper (2) sets of perforations from 1368' - 1388' and from 1760' - 1770' need to be squeezed off to insure the 2 7/8" x 5'/s" annulus has sufficient mechanical integrity to hold 1500 psi as required by [20 AAC 25.412 (c)]. The following procedure is a guideline for performing the squeeze procedures on the perforation intervals indicated. NOTE: Before undertaking any procedure below, all volumes to be validated based on actual field conditions by field personnel, i.e. Company men and cementers. Procedure 1. RU BJ Services and required equipment. 2. Pre-mix water on-board BJ's truck with sufficient CaCl2 fora 1.5% solution as mix water, add friction reducer as specified by BJ Services Engineering for procedure 3. RIH w/ dril{able bridge plug and set at 1780ft. PU cmt retainer, RIH on fibg, and set at 1718ft. Establish injection then squeeze off perforations from 1760ft - 1770ft with "G" w/ 1.5% CaCl2 and friction reducer as follows: Cement Procedure ^ Insure treating packer is set and backside of tubing is full. ^ Fill tubing prior to cementing to establish that formation is still taking fluid. This can be 5 bbls fresh H2O displacement ahead of cement. ^ Blend and displace 5 sacks (1 bbl) 15.8+ cement down tubing ^ Due to difference in density between cement and brine, tubing will likely go on vacuum. ^ After cement is pumped, be ready to displace away with 9.95 bbls of brine (tubing vo{ume to be verified}. ^ After displacement, pump additional'/2 bbl brine or until pressure increase noted and shut in. TOC should now be 20ft above upper perforation. ^ Wait 20 minutes and slowly start pumping while observing pump pressure. When pump pressure climbs 10 psi stop pumping and allow to bleed off. When pressure bled off approximately 2/3 start pumping again increasing surface pressure by 5 psi. r Repeat above steps increasing pump in pressure in 5 psi increments until no more bleed off is observed when pumping stops. Pressure up 400 psi over last recorded pump in pressure and hold monitoring bleed off. If no further bleed off, cease operations and unsting from retainer. Prepare for next squeeze procedure. 4. POOH to 1390 ft. Circulate out any cement debris from stab in tool and perform second squeeze procedure as follows which will be bradenhead squeeze: ^ Pump 5 bbls fresh water pre-flush ^ Mix and displace 1.5 bbls (7.5 sks) "G" cement w/ 1.5% CaCl2 and friction reducer for 60 ft balanced plug across perforations from 1368ft -- 1388ft. Plug should balance pumping 5 bbls fresh water, 1.5 bbls cement and 1.8 bbls fresh water finally displaced w/ 6 bbls brine and TOC at 1320.5 ft inside of tubing. Close annular preventer and control u-tube effect with choke or valve while displacing cement. ^ Open valves and allow plug to equalize, POOH with 3 jts of tubing followed by reversing out any residual cement. ^ Close annular preventer and insure choke and kill lines are closed. ^ Perform hesitation squeeze as before incrementing pressures and bleed offs until no further bleed off. After pressure up of 400 psi over last injection validates no further bleed-off, POOH and WOC. 5. PU Weatherford mud motor and mill, prepare to TIH to drill cement. 6. After WOC 12 hrs, proceed to drill out cement. Drill out interval from 1368ft - 1388ft. Pressure up to 1500 psi for 30 minutes and record results. Test is considered successful if pressure drop is less than 150 psi in 30 minutes, i.e. less than 10% drop in pressure. If casing fails to test, repeat squeeze procedure in step #4 after consulting with office in town. 7. If test successful, continue RIH and wash down to top of retainer at 1718 ft. Drill up retainer and mill out cement to top of bridge plug set at 1780 ft. Insure clean returns then initiate casing integrity test. Test as before using test pump. Pressure up to 1500 psi for 30 minutes and record results. Test is considered successful if pressure drop is less than 150 psi in 30 minutes, i.e. less than 10% drop in pressure. 8. If test successful, proceed with drilling out bridge plug at 1780 ft and clean out hole to TOC below open perforations at 2850 from earlier lower wellbore abandonment procedure. 9. If test unsuccessful, POOH prior to drilling out bridge plug, PU treating packer, RIH and re-squeeze perforations after consultation with town concerning procedure and volumes. 10. When squeeze work finished, POOH, PU and RIH w/ retrievable completion packer w/ pup jt below and wireline entry guide. Install x- nipple below packer if not already included in packer. RIH with packer on r1 LJ r1 LJ 2 7/8" tubing string and set packer at 2000ft. RIH and set profile plug in x landing nipple. Pressure test tubing to 2500 psi. 11. If tubing test ok, set BPV in hanger, RD stack, install wellhead and release rig. 12. File appropriate paperwork on completion and proceed w/generation of Class II Disposal Injection Order application. dv 29-Aug-05 Rev. 1.0 Specifications and Info: MASP: Use fracture gradient of 12 ppg MWE. = 12 ppg (Frac Grad) - 9.2 ppg (Brine Grad) x .052 x 2722 ft = 396 (400 psi) Conservative number for uppermost hesitation squeeze pressure at surface. Yld on Neat "G" is 1.15 ft3 slurry /sack Water required / sk =.4.97 gal /sack Weight = 15.8 ppg or 118.3 Ib /ft3 1 bbl = 5.614 ft3 5 %i" 15.5 Ib/ft casing volume = .0238 bbl/ft = .1336 ft3 / ft 2 7/8° 6.5 Ib/ft tubing volume = .00579 bbl/ft = .0325 ft3 / ft 2 718" tbg x 5'/z" csg annular volume = .0158 bbl/ft = .0886 ft3 / ft • :Aurora Gas, LLC Aspen No.~ August 31, 2005 Configuration Drill 7 7/8" Pilot Hole to 70v ii, Gpen io i2 a" FIT performed at 720', I;.sd 14.A YYg MWE test prior to breakdown Perforations: 1368' -1388' Perforations: 1760' -1770' PerF'yrafinn~; 'f12G~ _'f14G~ Perforations: 2351' -2371' Perforations: 2984'-2994' Perforations: 3006' - 3026' Perforations: 3444' -3454' Perforations: 3491' - 3506' Perforations: 3811' - 3831' i;# t~ ~~ t. ~~. ~ 4'~. • 117/8" 71.8# Structural Conductor to be driven to 80' or refusal 9 518" J55, 36# Surface Casing set at 693' Cement w/ 50 bbls 14 ppg lead and 30 bbls 14.5 ppg Gas-Block "G" w/ good 1 Tested Wet. CT 12,000 ppm J 1 Tested Wet. CC 55,000+ ppm Attachment I Tested Gas: Max Flow rate 40 mcfd at 25 psi PBTD 4355' 5'/Z" 15.5# J-55 Casing to 4484' MD (TVD) l.~r»ed 7 crm* Ireie ro ee8c' 40.5 bbls 13.5 rl•'s Asa cmt :nd 136'v!~le 1 C 8 ppg tail cement. • • ''. 7/8 6.5# 8rd EUE J-55 'Ibbing -=i .Aurora Gas, LLC I Aspen N o. 1 Proposed Final I %vuiiguraiivu Drill 7 7/8° Pilot Hole to 700 ft, Open to 12'/a" r tt i performed at 720' , Had 14.8 ppg MWE test prior to 'uiroui~uvwi~ Perforations: 1368' -1388' C nv~nA ()ff ~'--'--~ Perforations: 1760' -1770' Squeezed Off it 7 0" 7i.~ Csaiw^.tiir8i Conductor to be driven to 80' or refusal ~ 518" J55, 36# Surface Casing set at .93' :ement w/ 50 bbls 14 ppg lead and 30 ibis 14.5 ppg comas-Bioek »Gri w/ good ~a"x a"" Ys" casing aruruiets to pressure tested fo 15ttD psi x with loss of no greater titan n, pr ~s:~ ~: t:5g pit f :.. 3~ totes after tfrit/tng 'out and yr to running completion. rievable Packer set at z 2000 ft h spacer joint, landing nipple and :G on tubing tail. Perforations: 2125' - 2145' Perforations: 2351' -2371' T5 ft balanced cement plug placed on top of retainer. Reta6ier set at 2934' (50' max above perforations. Perforations: 2984' - 2994' Perforations: 3006' - 3026' Perforations: 3444' - 3454' Perforations: 3491' - 3506' Perforations: 3811' -3831' PBTD 4355' Drilled 7 5/8" Hole to 4485' Attachment 11 _ - _ -_.~ J-55 Casing to 4484' Iv""iu tTi~'D j 40.6 bbls 13.5 ppg lead cmt and 136 bbls 15.8 ppg tail cement. Sent By: AURORA#POWER; ~ 7139771347; 5ep~5 16:38; Page 1 10333 RICHMOND, STE 710, HOUSTON, 7X 77ty42. 713-9T7-5799 - 713W977-1347 (Fax} 1400 W, BENSON, STE 410, ANCHORAGE, AK 99503 907277-10103 - 907-277-1 f306 (Fax) ~dX To: .rte C~- ~^ /' .. Fram: Ed .lOfte5 (ielon~S(C~auf4f~gower.com) Fax: a --_ ~~~ ~ mm~~1 ~- Pagas: ~ ._ _.,.. _...- ~.S~~N ~'% ._ ^ Urgent ^ For Revlew d Please Comment C] Please Reply f~ Please Recycle / ~~ ~1 1/~l~r/9~ (/lr~~' rf7 ~~9c~ ~JC~..1'..I~' /y/Q~Ir~~?.C~'/ ~ /' /~ dry i',-~iuc~,- ~ 1, (L.~ ~ G~1%/ ~~- ~j~~~ i ~ Aurrora Gas, LLC www.aurorapower.com August 2S, 2005 Mr. John Norman, Chair Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501-3539 RE: Weekly Report of Operations: Aspen #1 'i'll) Dear Mr. Norman, Aurora Gas, LLC hereby submits its report of operations for the week of August 18 - August 24, 2005 for its Aspen #1 well. The following operations took place on the dates indicated: 8/18/OS Rig repairs and maintenance while waiting on orders. RIH w/ DP, hold BOP drill while RIH. Kelly up and wash last 16 ft to bottom. 440 units trip gas on bottoms up. Circulate and condition hole while waiting on orders to run casing. Mud weight 9.6 ppg. 8/19/OS Circulate and condition hole while waiting on orders. Repair pumps. Pump dry job and POOH laying down drillpipe and BHA in preparation for running casing. LD DP and BHA. LD power swivel and subs. PU tongs and RU to run S %Z" casing. Install S i/2" rams and pressure test stack. RIH w/ S %" 1S.S# BTC casing. Mud weight 9.6 ppg. 8/20/OS Finish RIH w/ casing and RU to circulate and cement. Cement casing in place w/ 30 bbls 10 ppg spacer, 40.6 bbls 13.5 ppg Lead Cmt, 136 bbls 15.8 Tail cement and displace w/ 106.5 bbls water. Did not bump plug. Plugs never left head until 3 bbls after start of displacement. Check floats, OK. RD cementers, clean lines, drain and wash stack and mud cross. Prep for nipple down. Clean pits. Water weight 8.4 ppg. 8/21/OS WOC, clean pits and start ND of stack. PU BOP's, set slips w/ 22 k down, cut off excess S '/2" casing, dress, install pack-off and tubing spool. Test OK. BU BOP's. Attempt to test door seals to 3000 psi, failed. Change out rams and rubbers, check blinds and retest, failed. Work on problem while wait on tech from town. Water weight 8.4 ppg. 8/22/OS Work on double gate BOP body. Inspect and function test all in attempt to locate problem. Discover cement in ram body. Clean and retest all 200 / 3000 psi, OK. PU 4- 3/4" bit and casing scraper. RIH PU singles to 4355 ft. Tag up on top of plug. RU swivel 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 ~ • Mr. John Norman Page 2 and circulate. Test casing to 2000 psi for 30 min, OK. Circulate and weight up brine while cleaning w/ filter and centrifuge. 8/23/05 Continue filter brine. POOH w/ bit and csg scraper. RU Schlumberger wireline. Run CBL, GR and CCL log. POOH, RU shooting flange, lubricator, test all to 1 S00 psi, OK. RIH shoot the following intervals using 3 %2" HSD DP PJ HMX guns at 6 spf and 60 deg phasing: Run 1: 3811 - 3831 (20 ft) Run 2: 3491- 3506 (15 ft) Run 3: 3444 - 3454 (10 ft) Run 4: 3006 - 3026 (20 ft) Run 5: 2984 - 2994 (10 ft) Run 6: 2351- 2371 (20 ft) Run 7: 2125 - Z 145 (20 ft) Run 8: 1760 -1770 (10 ft) Run 9: 1368 -1388 (20 ft) 8/24/05 RIH w/ bit and casing scraper to 4352 ft, jets plugged, TOH /w wet string find scraper ID packed off w/ sand and scale. Clean out, RIH to 4350, reverse circulated out sand and debris and filter brine. POOH, LD bit and scraper, PU and RIH w/ WOT test packer assembly. RU test separator and lines. Set RBP at 3843 ft, POOH and set test packer at 3761 ft. RU swab tee, swab head and prepare to test. Wait until daylight to begin swabbing operations to initiate test. If you have any questions or require additional information, please contact me at 277- 1003 or Duane Vaagen at 258-3446. Sincerely, AURORA GAS, LLC J,iEdward (Ed) Jo~ xecutive Vice Pr sident Engineering -Operations cc: Duane Vaagen • trrrsora Gas, L www.aurorapower.com -~' August 11, 2005 ~~~ ~ 205 Mr. John Norman, Chair ~~~~~ Q91 ~~~ C~r~• 0~~~~s~se Alaska Oil & Gas Conservation Commission f~~-~~'~''~~~ '~~~ 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501-3539 RE: Weekly Report of Operations: Aspen #1(PTD #205-111) Dear Mr. Norman: Aurora Gas, LLC hereby submits its report of operations for the week of August 4 - August 10, 2005 for its Aspen #1 well. The following operations took place on the dates indicated: 8/4/05 TOOH to c/o BHA. LD 7 7/8" pilot hole BHA assembly and pick-up 12 '/4" assembly, open pilot hole to 12 '/a" from 97' to 700 ft. CBU and prepare for round trip to condition hole for surface casing. Mud weight 11 ppg. 8/5/05 Pump and back-ream out of hole. On trip back in hole, hit bridge at 350 ft. PU swivel and pump /rotate through and continue TIH to 700 ft. Condition mud for casing. Pump out of hole, stand back jars and DC's, LD NB stab and bit. RU to run 9 5/8" surface casing. Run 9 5/8" surface casing, tag fill at 685 ft. RU and circulate/ wash to 693 ft. Circulate hole clean, RU cementers and cement surface casing using 50 bbls 14.0 ppg cement and 30 bbls 14.5 ppg Gas-Block "G" cement w/ good returns observed at surface. Cement displaced w/ rig pumps, plug bumped, floats checked, OK. RD cementers, wash lines, drain diverter and wash out, center pipe w/ annular on diverter and WOC. 8/6/05 Cleaning surface equipment, WOC. ND diverter, cut and lay out 9 5/8" stub, remove diverter. Cut and dress 9 5/8" casing for installation of casing head. Weld on 11" 3M casing head, allow to cool. Test wellhead t/ 2500 psi f/ 10 min. NU BOPE and RU to test complete BOP system and choke. 8/7/05 Finish NU of BOPE. Function test all and cavity test stack in preparation for AOGCC witness of full test. Test stack w/ AOGCC witness, c/o kelly valve, set back swivel. PU BHA and RIH. Wash /circulate from 635 ft - 655 ft, while conditioning mud. Test surface casing to 1500 psi for `/2 hr, OK. Repair pop-off on mud pump. Drill out float 10333 Richmond Avenue, Suite 710 • Houston, Texas 77042 • (713) 977-5799 • Fax (713) 977-1347 1400 West Benson Blvd., Suite 410 • Anchorage, A/asks 99503 • (907) 277-1003 • Fax (907) 277-1006 • • Mr. John Norman Page 2 equipment and 20 ft of new hole. Circulate bottoms up and RU far MWE FIT. Perform FIT, formation broke down at 14.8 ppg MWE. Continue drill ahead to 760 $. Mud weight 9.5 ppg. 818!05 Drill ahead to 1042 ft, wellbore survey at 1010' (2 deg). Drill ahead to 1540 ft, wellbore survey at 1506' (4 deg). Drill ahead to 1696 ft, perform short trip of 5 stands, well good, no fill. Drill ahead to 1976 ft. Mud weight 9.5 ppg. $/9/05 Drill ahead to 2041 ft. CBU and wellbore survey at 2005 ft (3.75 deg). Drill ahead to 2453 ft, shut down to repair pump #l. Drill ahead to 2540 ft and wellbore survey at 2506 ft (3.75 deg). Short trip to 1610 ft, TIH, hole slick, no fill. TIH, work pipe while repairing pump. Mud weight 9.5 ppg. 8/10/05 Work pipe and circulate while completing rig repairs. Drill ahead to 2955 ft. Stop drilling and work pipe while repairing pump. Drill ahead to 3041 ft, CBU and wellbore survey at 3007 ft (2.75 deg). Drill ahead to 3103 ft. Mud weight 9.5 ppg. If you have any questions or require additional information, please contact me at 277- 1003 or Duane Vaagen at 258-3446. Sincerely, AURORA GAS, LLC ~,F` 1 Lam. Edward (Ed) Jo ~ Executive Vice President Engineering -Operations cc: Duane Vaagen • ti Aurora Gas, www.aurorapower.com August 8, 2005 Mr. John Norman, Chair Alaska Oil & Gas Conservation Commission 333 West 7a' Avenue, Suite 100 Anchorage, Alaska 99501-3539 RE: Weekly Report of Operations: Aspen #1 Dear Mr. Norman, LLC A~ , ~41~5~~ C ~ ~ ~~ ~i0 ~~ ~~'~C r~~'~ d~~r~~ Aurora Gas, LLC hereby submits its report of operations for the week of July 28 -August 3, 2005 for its Aspen #1 well. The following operations took place on the dates indicated: 7/28/05 Lay down felt and Herculite and prep pad for setting in rig components. Mobilize in Aurora Well Service Rig #1 from Lone Creek No. 3 wellsite. 7/29/05 Set matting boards, and spot rig modules. 7/30/05 Mobilize in and spot rig modules, RU. PU hammer to drive conductor. Bevel and weld pipe as driven. Hit refusal at 68'. LD hammer and prepare to drill out (drill and drive) to gain additional footage. RU power swivel. 7/31/05 RU rig floor, tong lines, tongs, kelly hose etc... RU riser on conductor, drill hole. Install flow line. PU 12 '/4" bit and drill OH for conductor. 8/1/05 Continue drill and drive operations, drill 12 '/4" hole for conductor installation. POOH, LD swivel, PU hammer, weld on section of 13 3/8" conductor, and finish driving conductor to 95' RKB. LD hammer. Install starter head and diverter. RU mud loggers, install gas detectors and PVT system. Provided notice 08/01/05 @ 0830 hrs to AOGCC for opportunity to witness diverter test on following day. 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 r1 LJ ~ Mr. John Norman Page 2 • 8/2/05 Continue NU of diverter system, check Koomey bottles, haul in mud and test gas sensors. Modify flow line and install flow sensor. RU trip tank and work on PVT system. RU control panel for diverter and function test entire system. Witness waived. PU 7 7/8" BHA to drill pilot hole and spud well. TD at midnite 160 ft. Mud weight 11 ppg. 8/3/05 Drill ahead on pilot hole. Survey at 509 ft, 2 deg. Drill ahead to 700 ft. Mud wt 11 ppg. If you have any questions or require additional information, please contact me at 277- 1003 or Duane Vaagen at 258-3446. Sincerely, AURORA GAS, J. Edward (Ed) es Executive Vice President Engineering -Operations cc: Duane Vaagen Aspen # 1 Subject: Aspen #1 From: duane vaagen <duane@fairweather.com> Date: Mon, 08 Aug 2005 09:17:04 -0800 To: Thomas Maunder <tom maunder@admin.state.ak.us> Tom: • As an update on the Aspen No. 1 well. Last night while performing the FIT, the formation broke down at^„14.8 ~, ppg MWE. In our drilling program we indicated that we would attempt to achieve a MWE 16.5 ppg FIT as this has normally been achievable for the region. We have made note of the above and are currently drilling ahead, at 1290 ft. I will have the weekly activity report for this well to you today. As an update on other activities, we are investigating a couple of different locations for further drilling on the Three Mile field and should be submitting PTD applications on them soon. We are also surveying in a site for the proposed Long Lake No. 2 well, to further evaluate that structure further west. There is a strong possibility that the rig will go down for 2 - 4 weeks after the Aspen well. Regards Duane Vaagen Project Engineer Fairweather E&P Services, Inc. duane~fairweather.com Office: (907)258-3446 Cell: (907)240-1107 wQ~-cJh~- ~ ice.\.I ~~~~~ l ~~~ ~i 1 of 1 8/8/2005 9:29 AM JOB STATUS REPORT TIME 07/29/2005 14:24 NAME AOGCC FAX# 9072767542 TEL# SER.# BR02J2502370 DATE,TIME 07/29 14:23 FAX N0./NAME 2795740 DURATION 00:00:50 PAGE(S) 04 RESULT OK MODE STANDARD ECM • • Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501-3539 Phone: (907) 279-1433 Fax: (907) 276-7542 Fax Transmission The information contained in this fax is conpdentia/ and/or privileged. This fax is intended to be reviewed initially by only the individual named below. if the reader of this transmittal page is not the intended recipient or a representative of the intended recipient, you are hereby notified that any review, dissemination or copying of this fax or the information contained herein is prohibited. if you have received this fax in error, please immediately nofify the sender by telephone and return this fax to the sender at the above address. Thank you. To: A>JCs.V~~ ~~~~C Vim. From: ~ p ~~,~ ~ ~``.. Phone #: Subject: S ('~~ _-_~~ Message: Fax #: ~ C ~ '~ ~ ~ ~ V' Date: ~ ~. ~~ Pages (including cover sheet): ~c ~r~ .*xas a~~~ ~CS"C€~~{ v.9cRht er ciS ~ iu~o~~ ~o.~ ~ 1 ~T 5 c~ ~~ ~n.~.~ ~a~' ro ~~e er~G ~r-~ I,~~~ ~e~~ ~ ` c~S<<v.~C~~ .~~ ~'. . ~~ If you do not receive all the pages or have any problems with this fax, please call for assistance at (907) 793-1223. C] ~ ~ ~ ~ ~ , ;~ } ~ ~ t ; , ~~ ~' ~ ~ ~, (, s~ FRANK H. MURKOWSK/ GOVERNOR ~~ O~ ~ v0-7 v 333 W. 7"' AVENUE, SUITE 100 COI~TSERQATIOI~T CO1rIMISSIOIQ ~ ANCHORAGE, ALASKA 99501-3539 ~ PHONE (907) 279-1433 FAX (907) 276-7542 J. Edward Jones Executive Vice President of Operations and Engineering Aurora Gas, LLC Address-1400 West Benson Blvd, Suite 410 Anchorage, Alaska 99503 Re: Aspen # 1 Aurora Gas, LLC Permit No: 205-111 Surface Location: 940' FSL, 324' FWL, SEC. 33, T12N, R11W, SM Bottomhole Location: 940' FSL, 324' FWL, SEC. 33, T12N, R11W, SM Dear Mr. Jones: Enclosed is the approved application for permit to drill the Aspen # 1 exploration well. This permit to drill does not exempt you from obtaining additional permits required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required permitting determinations are made. A weekly status report is required from the time the well is spudded until it is suspended or plugged and abandoned. The report should be a generalized synopsis of the week's activities and is exclusively for the Commission's internal use. 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 conductor pipe. All dry ditch sample sets submitted to the Commission must be in no greater than 30' sample intervals from below the conductor or from where samples are first caught and 10' sample intervals through target zones. The Commission hereby denies Aurora's requested waiver of 20 AAC 25.035 (c) (1) (B) to allow drilling 12-1 / 4" hole with a 10" diverter line. The blowout prevention equipment (BOPE) must be tested in accordance with 20 AAC 25.035. Please note that since this is an exploration well, the BOP test interval is < 7 days. Sufficient notice (approximately 24 hours) of the diverter function test and BOPE tests must be given so that a representative of the Commission may witness the tests. Notice may be given by contacting the. ~ • Commission petroleum field inspector on the North Slope pager at (907) 659- 3607. DATED this /"day of July, 2005 cc: Department of Fish 8v Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. RE: Current Aurora Schedule • • Subject: RE: Current Aurora Schedule From: duane vaagen <duane@fairweather.com> Date: Tue, 26 Ju12005 08:23:32 -0800 To: Thomas Maunder <tom maunder@admin.state.ak.us> Tom: Yes, at this time. They will only be 3500 - 4500 ft deep. If they come up with another deeper test objective, i.e. deep oil test at Tyonek Reserve re-entry that requires a bigger rig, then will maybe work those in with alternate rig depending on time of year. Duane -----Original Message----- From: Thomas Maunder [mailto:tom maunder~a.dm.in.state.ak.us Sent: Tuesday, July 26, 2005 7:35 AM To: duane vaagen Subject: Re: Current Aurora Schedule Thanks Duane, Will the "Aurora Rig" be drilling the Three Mile Creeks?? Tom duane vaagen wrote: Tom: Per our phone conversation, it appears that the following will likely be the schedule for the remainder of the year for Aurora's west side Cook Inlet work this year. ', Lone Creek No. 3 (Finished up today, w/ rig down and release rig ', tomorrow for move to Aspen). Aspen No. 1 Exploratory gas well, ex ected s ud Frida or Saturda at the soonest. Likely will not get conductor driven unti Friday. Kaloa No. 3 Horizontal Tyonek gas test i Three Mile Creek Unit No. 2 Drilled as offsets to TMCU #1 well drilled and completed winter 2005. ', Three Mile Creek Unit No. 3 Drilled as offsets to TMCU #1 well drilled and completed winter 2005. The above will likely carry them over into October / November sometime. Regards ', Duane vaagen ', Project Engineer ', Fairweather E&P Services, Inc. duane~~fair~aeather.r_om <mailto:duanec--f airweather.com> Office: (907)258-3446 Cell: (907)240-1107 1 of 1 7/26/2005 5:13 PM r tiAurora Gas, LLC ~~~~~~. www.aurorapower.com ~u~ ~ o zaa~ :~~±ask~ ail & Gay Cana. (~ommissien 4r!c!!orage July 19, 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: Aspen No. 1 Dear Mr. Norman: Aurora Gas, LLC hereby applies for a Permit to Drill an onshore natural gas exploration well on the Northwest side of the Cook Inlet. The well, Aspen No. 1, will be located approximately 3-% miles northwest of Tyonek, Alaska. Aurora Gas, LLC proposes to spud the Aspen No. 1 on July 25, 2005. The Aspen No. 1 well will be drilled on a new pad currently being constructed with access over a new access road with the location of the pad and road being on CIRI lands. 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. 10333 Richmond Avenue, Suite 710 • Houston, Texas 77042 • (713) 977-5799 • Fax (713) 977-1347 1400 West Benson Blvd., Suite 410 • Anchorage, Alaska 99503 • (907) 277-1003 • Fax (907) 277-1006 STATE OF ALASKA " ,~~+~~~~~ ~ASKA OtL AND GAS CONSERVATION (~sV11SSION J~~ O 200c~ PERMIT TO DRILL ~ `~ 20 AAC 25.005 Ai~~ka Oil & Gas Cons. E,'tsrnrnisson 1a. Type of Work: Drill ^ Redrill ^ Re-entry ^ 1b. Current Well Class: Exploratory Q Development C~~C~B.rMultiple Zone ^ Stratigraphic Test ^ Service ^ Development Gas ^ HS~ingle Zone ~ 2.Operator Name: Aurora Gas, LLC 5. Bond: Blanket ~ Single Well ^ Bond No. NZS 429815 11. Well Name and Number: Aspen No. 1 3. Address: 140D W. Benson Blvd, Ste 410, Anchorage, AK 99503 6. Proposed Depth: MD: 3990' TVD: 3990 12. Field/Pool(s): 4a. Location of Weli (Governmental Section): Surface: ~ 940' FSL, 324' FWL, Sec 33, T12N, R31 W SM ~ 7. Property Designation: C-081387 Wildcat Top of Productive Horizon: same 8. Land Use Permit: 13. Approximate Spud Date: 7/2612005 Total Depth: same 9. Acres in Property: 2225 14. Distance to Nearest •*-/.~ Property: ?• 7 4b. Location of Well (State Base Plane Coordinates): Surface:x- 278848 ' y- 2589811.9 Zone- 4 10. KB Elevation (Height above GL): 16 feet 15. Distance to Nearest Well Within Pool: NIA, > 2 miles 16. Deviated wells: Kickoff depth: Wa - Maximum Hole Angle: - feet degrees 17. Maximum Anticipated Pressures in psig (see 2b AAC 25.035) Downhole: 1875 psig Surface: 1436 si r 18: Casing Program: Size Specifications Setting Depth Top Bottom Quantity of Cement c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (inGuding stage data) 17 112" 13 3/8" 54.5 J-55 BTC 95 0 0 95 95 w/ drill and cmt 12 114" 9 518" 36 J-55 BTC 884 0 0 700 700 81 bbls ~ 100 % OH Excess 7 7/8" 5 1/2" 15.5 J-55 BTC 3974 0 0 399D 3990 181 bbls ~ 25% OH Excess 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Total Depth MD (ft): To#at Depth TVD {ftj: Plugs {measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measun+d): Casing Length Size Cement Volume MD TVD Structural Conductor Surface Intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ftj: 20. Attachments: Filing Fee ~ BOP Sketch Drilling Program Time v. Depth Plot ~ Shallow Hazard Analysis Property Plat ~ Diverter Sketch ^ Seabed Report ^ Drilling Fluid Program ^ 20 AAC 25.050 requirements ^ 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Printed Name J. Edward Jones Title Executive Vice President Engineering-0perations Signature ~ Phone 907-277-1003 Date 19-Jul-05 / i Commission Use Only Permit to 'll Number. ~~ ~~~ API u er: 50- ~ 3-- Zd ~~~~ Ud Permit Approv ~--- Date: 7 p1,~s ~ S See cover letter for other requirements. Conditions of approval: ~~ ~ c~v~v@~' @n~~ Sam fired Yes J~J No ^ Mud log required Yes ~ No ^ e de measures Yes ^ No ~' Directional survey required Yes ~~ No ^ Other. s 4~w~. ~Q'ti'ty~•t~~o.tv4~ L ~.~Cr,~S ~~.~a/~n~-fi'~. bn(~ sur/c~ • f~j. `` APPROVED BY ~ f~ Approv by THE COMMISSION Date: v •oS ~~ Fo m~1 40 vi 081200{ ~ ~uoma muupncate \ l S ' ` . d u.~ i..._ =•., ~ w. • • NOTES 1) BASIS OF COORDINATES IS ALASKA STATE PLANE NAD 27 ZONE 4 FROM A DIRECT TIE TO ADL NO. 31270. 2) BASIS OF ELEVATION IS FROM TIDAL OBSERVATION ON 9-22-93. DATUM 1S MLLW. ALL ELEVATIONS SHOWN HEREON WERE TAKEN ON GROUND. NORTH 3) SECTION LINES SHOWN HEREON ARE BASED ON PROTRACTED VALUES. Grid S33 T12N R11W AR~p ` ~F~ p / q0 ~~ 324' FWL ~ scam 1 inch = 400ft. o aoo soo soo U.S. SURVEY NO. 1865 ASPEN NO. 1 WELL AS-STAKED GRID N: 2589811.910 GRID E: 278847.780 LATITUDE: 61'04'57.937"N LONGITUDE: 151'14'57.061 "W ~ ELEV. 432.5' A~ ~ ~ oS O o ~ FS~ ~ S \ rn \ S32 S33 T12N S5 S4 T11 N N 2588878.16 E 278506.16 ,~~.OF A~q ~~I . * ~ TH •. ~t .....:.49.- ................. i' •~ ~ i .A .: .............................~ •;M. SCOTT McLANE;',ff . ~ ~~ ~' 4928-S ~I CFO •'' • • ...... • ~~~ EX\5~\NG RO PO ASPEN NO. 1 AS-STAKED Consulting Clroup SURFACE LOCATION DIAGRAM Iv~cLane Testing APPLICANT: ENGINEERING/MAPPING/SURVEYING/TESTING ~~ P.O. BOX 468 SOLDOTNA, AK. 99669 ; =~: '~y~~ VOICE: (907) 283-4218 FAX: (907) 283-3265 EMAIL: msmclane®mclanecg.com PROJECT NO. DRAWN BY: DATE: OFFSETS: LOCATION: 10/26/04 PROTRACTED SECTION 33 043050 MSM 320' FWL TOWNSHIP 12 NORTH, RANGE 11 WEST SLD 940' FSL SEWARD MERIDIAN, ALASKA .~i~r•vr~c~ CTC~xs, Ll..~ ~~a~aa N'~~. 1 13rtllea~c Prr~~;a°trraa Drilling Program: Aspen No. 1 1. File and insure all necessary permits and applications are in place. 2. Install (new) 13 3/8" 54.5 #/ft, structural conductor to ~ 100 ft or refusal. Install 13 5/8" 5M starter head. 3. Rig up diverter (see attached diagram) and mud loggers. 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 ~10+ ppg. 6. Drill 12'/" hole to 700 ft, using 6 3/4" stabilized BHA. Watch for gas in shallow coals and sands. Increase mud weight as needed to 10 - 11 ppg. 7. Condition hole for running 9 5/8" surface casing, POOH, LD 12 1/4" BHA. 8. Run and cement (new) 9 5/8" 36 #/ft, J-55 LTC surface casing at 700' 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. Centralizers to be installed w/ stop collars centered on 1St four joints run and every other joint there-after to surface. 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 8'/z" bit on slick drilling assembly and RIH, drill out float equipment and cement and 20' new hole. Pull back into shoe, treat mud for cement contamination and perform FIT with MWE to 16.5 ppg, record results. 11. POOH, LD 8'/2" bit, PU 7 7/8" mill-tooth bit and 6'/<<" stabilized BHA. 12. 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! 13. Proceed to drill ahead, 7 7/8" hole. Monitor well and volumes caref Imo, Be prepared to shut well in and weight up immediately if flow or excessive gas build up in mud is noticed. 14. Drill to TD at 3990 ft MD & TVD, depending on lithology encountered. 15. Short trip and condition hole as needed for running wireline logs. 16. 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. 17. RD wireline, RIH with drilling BHA as before to TD. Circulate and condition hole for running casing. 18. INSURE all cementing equipment, casing accessories, and casing running equipment is on location and functional. POOH, LD DP and BHA. 19. 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. 20. RIH with (new) 5'/z" 15.5 #/ft J-55 BTC casing, installing 1 centralizer / joint centered on 1St 4 joints above shoe, and 1 centralizer every 2"d joint 1ur•{ar•cx Cicr.s L1.C". ~'cr~;~~ I ~af`1'(1 Kai. ?. C) 7%?(1,~'?€10 .~rar•vr~cz Cris. /:1:~ ~~~~ra i~r'~. I .l~rillin~ T-'rr~~;r°rzrrx ~~"/~- ~t,c ~`~~~~7-~~(~ there after. Centralizers to be installed (1) every third joint for the interval inside of the" surface casing. Run casing to 3990'. Keep pipe moving when casing is at TD and while waiting for cementers to get hooked up. 21. 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 %2" CH x 7 7/8" OH annulus to 1000 ft. See attached cementing info for preliminary volume estimates. While pumping cement, reciprocate pipe a minimum of 20 feet until. Displace cement w/ brine to minimize contamination on clean-out. displacement is finished. Bump plug and check floats, drain and wash down stack, check annulus for flow, center casing w/ annular preventer and WOC. 22. RD cementers, nipple down stack, land casing in slips and cut casing. 23. 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. 24. C/O~pipe rams to 2 7/8" for workstring. PU bit and casing scraper 5~) a- t ~~lea nbrineltforb erforatin f b a unnlinr throur h centrif g e and f tenndebris, p 9 Y g g 9 9~ ~~~ S~Q`G~ POOH LD bit and casing scraper. 25. PU wireline BOP s, lubricator, pressure test all. PU perforating guns, RIH to depth as determined from OH logs and perforate. Watch for pressures in casing after shooting. POOH, LD perf gun. 26. RU and RIH with test packer assembly on workstring. Connect to surface flow test equipment. Swab in well for flow test, record results. Kill well. 27. Repeat steps 24 and 25 until sufficient intervals have been penetrated for production. 28. POOH, RD wireline. 29. Pick up and assemble completion assembly which will use retrievable type packers, sand exclusion screen, sliding sleeves and other. Exact configuration to be determined by test results. Please see Figure I for proposed completion scenario. 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, pull blanking plug. 30. RU and swab in well, allow to clean up, record rates and pressures then shut in. 31. Install BPV at surface, nipple down and remove BOP stack. Install wellhead tree. RD and remove all rig equipment. 32. Prepare site for well testing and surface production facilities. 33. File completion reports with proper agencies. .F~u~°raa~cz C~as LI~C". ~'rx~;e? of'It'1 .~1~~r•c:ar~ct Crus..I:1.~ ~~~~r2 N~~. 1 .Drrllintr 1'r°~~br°arfia Site Access: The Aspen No. 1 will be accessible via a new gravel access road being constructed off an existing trunk road that allows access between Tyonek and Shirleyville. Rig: Aurora Well Service, Rig No. 1 (AWS 1) will be used to drill the Aspen No. 1 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. ~~~~CQ~~ t7-~'~~` `~ l3 C1. r~ Survey Program: The Aspen No. 1 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 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 %2" 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: Aspen No. 1 Proposed Logging Program Well Section De the ft OH CH Lo T e 12 1/4" Surface 0 - 700 N/A: No open-hole logs planned for surface at this time. " Surface 0 - 700 GR Cs 7 7/8" Prod 700 - 3990 Platform Express: Array Induction, Compensated Neutron, Litho-Density, SP, GR, DSI and FMI. Also MDT and Sidewall cores. i 5 1/2" Prod Cs 700 - 3990 CBL, GR, CCL Surface - TD 0 - 3990 Mud Lo in Services GEOPROG: The following table highlights the estimated location of formation tops as anticipated by Aurora Gas. These intervals are known natural gas production intervals in the Cook Inlet Basin. Formation To De th MD De th TVD TSUGA 2-3 771.3 771.3 TSUGA 2-4 1420.8 1420.8 TSUGA 2-5 2451.0 2451.0 TSUGA 2-6 2820.6 2820.6 TSUGA 2-7 a-marker 3415.8 3415.8 TSUGA 2-8 b-marker 4139.6 4139.6 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: ;~fur•~a~~u Gus LI1G". 7'a~;~~ 3 ~af~l(I Irv. ?. C) 7-'?C),'?(t(15 .hut~r~r•u Crus, .L1: ~~~~°r~ iv~~. 1 TJrillinb P~r~~r•rrt~~ 12 1/4" surface hole: While drilling the 12 1/4" surface hole, a 13 5/8" 5M annular w/ 13 5/8" diverter spool 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 information from offset wells in the region, the closest are the Moquawkie No.(s) 1 and 3 and the Lone Creek Unit No. 1 which are 2 3/" and 3 miles distant respectively, and based on average pore pressures observed in the region, a conservative pore pressure gradient of .47 will be used for engineering purposes. Maximum anticipated surface pressures "MASP" can be calculated by subtracting the gas gradient of .11 psi/ft from pore pressure gradient of .47 psi / ft and multiplying by the total TVD depth. =>MASP = (.47 - .11) * 3990 = 1436 psi 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 12'/4" Hole Section to 700': Beluga Formation Base Fluid Density PV YP API Filtrate Total Solids Gel & Polyrr 3% KCL 10 - 11 ppg 22 - 30 20 - 30 <5 15-25% ier mud system Drilling Fluid Properties While Drilling 7 7/8" Hole Section to 3990': Beluga and Tyonek Formations Base Fluid 5% KCL Density 9.5 - 10 ppg PV 22 - 30 YP 20 - 30 API Filtrate < 5 Total Solids 15 - 25 1ur•car~u Oxus L,I.C". ~'~~;e 4 ref • 1() .~:l~rr•c~r~c~ Cr~xs, .I:.I:~~ Polymer mud system Drilling Fluid Handling System: ~~c:~r~ iit~~. 1 .I~rillin~; I'rr~ba•crr~a 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 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. At this time, we are proposing to drill a 17 '/z" hole for installation of the 13 3/8" conductor and cementing it into place by installing tubing in the annulus and grouting the outside or through use of a stab- in shoe. If equipment available, the conductor may be driven. Aspen No. 1, 13 3/8" 54.5# J-55 Conductor Analysis and Cementing Program The 13 3/8" conductor will be installed by the rig. It is proposed to drill either a 17 %2" or 16" hole, pending bit availability, and run the casing. Joints will be threaded. Conductor will be cemented by either grouting annulus of 13 3/8" csg / OH with tubing inserted in the annulus or by use of stab in shoe, pending availability. Please see attached Conductor Analysis with specifications. Aspen No. 1, 9 5/8" 36# J-55 BTC Surface Casing Analysis and Cementing Program The 9 5/8" surface casing will be cemented in fully from the proposed set depth of 700' to surface with a 14.5 ppg "G" lead cement system. Where: 12 '4" OH Capacity = .1458 bbl/ft 9 5/8" 36# Csg x 12 1/4" OH capacity = .0558 bbl / ft 9 5/8" 36# Csg capacity = .0773 bbl/ft OH x Csg: 700 ft x .0558 bbl / ft x 100 % excess = 78 bbls Shoe Jt: 38ft x .0773 bbl/ft = 2.94 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 ~ppq) Volume Required Gas-Block enhanced 14.5 81 bbls @ 100% OH Excess .R1ui~fat~c~ bras LLC;. f'~~;c~ .~ ~af'1t'1 ~7ac-~~x i'~`t~. 1 Pralli~b Pro~r-cx~~t Please see attached 9 5/8"surface casing analysis and specifications. Aspen No. 1, 5 1/2" 15.5# J-55 LTC Production Casing Cementing Program The 5 %2" production casing will be cemented in fully from the proposed set depth of 4500' 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 %" 17# csg X 9 5/8"36# annular capacity = .0479bb1/ft 5 %" 17# csg displacement = .00614 bbl/ft Lead System: 9 5/8"CH x 5 %"Csg: = 700ft 700ft x .0479 bbls/ft x 1 (0% excess)=33.50 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 = 45 bbls Tail System: 7 7/8"OH x 5 %" Csg: 3990ft - 1000ft = 2990ft 2990ft x .0309bb1/ft x 1.25(25% excess= 115.5 bbls Shoe Joint = 38' x .0232 bbl/ft = .88 bbls Total Tail Cmt Volume = 116 bb/s Cement S sY tem Type Cement Weight (ppg) Volume(a~% Excess Lead "G" 13.5 45 bbls @ 25% OH Tail "G" 15.8 116bb1s @ 25% 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 :~.Ltrcarct Crrzs..I:I:C ~~~ra Nc~. 1 I~r~ICinb Pr~bt°crttx 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 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 Aspen No. 1. The nearest known wells are operated by Aurora Gas, LLC and are the Lone Creek No. 1, which is ~ 3 miles to the northwest and the Moquawkie No.(s) 1 and 3 wells which are ~ 2.75 miles to the west. The well is intended to access stratigraphy encountered in the drilling of the Tyonek Reserve No. 1, a plugged and abandoned oil exploration attempt by the Humble Oil Company in 1964. While no gas was found in the Tyonek Reserve No. 1, recent seismic suggests that there is potential for a natural gas deposit higher on structure. Other: Sticky bentonitic clays, boulders, lost returns & differential sticking w/ overbalanced muds (+12.5ppg) and gas influx while cementing. Rev. ?. C) 7%?(~'?t)()5 .~t~r•ra~°c~ Crus, LL~ ~~~~°rt N~~, 1 .I~rillin~; ,l'r°f~~;r~czr7z Aspen No. 1 Summary of Drilling Hazards POST THIS NOTICE IN DOGHOUSE ~ There is potential for abnormal pressured shallow gas. ~ ~I 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 Aspen No. 1 WELL PLAN FOR ADDITIONAL INFORMATION. 1ur~c~t~cz Crag LI;C.". ~'a~;e cis ~~f~ JCI .gar°vr~c~ Crc.~s, .L1:~ ~~3~rt N'n. t .I~rallin~; ~r~)~;r°czr7z ~°~ ~~;~~ `,~~~;~~ Aspen No. 1 Days vs. Depth Days From Spud 0 ° _ ~ 100 200 300 400 500 600 700 12 114" Hole to 700', Set / cement 9 5/8"surface casing at 700. NU BOPE, P-test, Drill out and FIT to 16 ppg MWE - 800 900 1000 1100 1200 1300 140 0 1500 1600 1700 1800 .~ 19 . 00 2000 ^ 2100 2200 2300 TD @ 3990', Condition hole, run OH logs, Run 5 1/2"casing and cement. Perforate, test and comple well. t 2400 Q . ~ 2500 ^ 2600 2700 2800 2900 3 000 3100 3200 3300 3400 3500 3600 3700 3800 3900 4000 4100 4200 4300 4400 4500 <1u~~f~l~ct ~iL1.S.LLC,'. ~'a~;c~ .9 af~1(1 ~.~rar°r~lx~ Crrzs..I.f..C . ,r,~, Aspen No. 1 Proposed Configuration Drill 12 1/4" Hole 2 7/8" X 5'/:" annulus to be displaced over to inhibited packer fluid w/ diesel freeze protect at surface following completion. 2 7/8" 6.5# EUE 8rd Tubing to Top of Screen Beluga Perforation Intervals to be determined by open-hole logging. Dri117 5/8" Hole PBTD est at 3974' ' ~~:~rt i~t~. 1 I~ritlin~ I'ra~r°czna ? 7/8 6.5# 8rd EUE J-55 Tubing 13 3/8" 54.5# J-55 Conductor to be installed to 95' or refusal 9 5/8" 36# Surface Casing set at 700' Cement w/ 14.5 ppg Gas-Block enhanced cement (~ 55 bbls cmt @ 100% Excess) ileeve 1 joint above packer w/ Profile ing plug Retrievable type Seal-bore action Packer 90' above perforation Attachment I Exclusion Screen across all rations. All Screen sized to 5'/z" 5# J-55 Casing to 3990' MD (TVD) ,i ~ 45 bb113.5 ppg Lead at 25 % and 14.5 ppg Tail at 25%(Top of Tail to ~,..~.... ~01000' MD) .F1 ur~at•c~ ~a.4 I:CC'. f'rz~;=c~ 1 t? caf' 1`(1 Rev. ?, C) 7f?(),'?(~()5 • • Well ID Aurora Gas, LLC Aspen No. 1 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 5 1/2" Production Casing Properties: Size OD: 5 1/2 Grade: J-55 Weight ppf: 15.50 Coupling: BTC Set Depth ft 3990.00 (ft)MD 3990.00 (ft)TVD Next Casing Depth 3990.00 (ft)MD 3990.00 (ft)TVD FIT Test Depth 720.00 (ft)MD 720.00 (ft)TVD Collapse Resistance (psi) 4040.00 Internal Yield (psi) 4810.00 Joint Strength (psi) x 1000 300.00 300,000.00 "Tensile Limits Body Yield (psi) x 1000 248.00 248,000.00 * Tensile Limits API Drift Diameter (in) 4.825 Wall Thickness (inl 0.275 Formation & Fluid Properties: Material Weight ppg Gradient psi/ft Mud Weight 10.50 0.546 psi/ft i 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 Set Point 20 1.040 psi/ft Est. Pore Pressure Gradient @ Shoe 9.1 0.473 psi/ft Est. Pore Pressure Gradient @ Next Csg Pt. 18.5 0.962 psi/ft Gas Gradient (psi/ft) 0.110 psi/ft Mud Backup Gradient ppg 8.95 0.465 psi/ft Fluid Drop for Collapse Calculation (Enter #1 55 0.55 • • Tensile Calculations: Weight in Air (Ibs) 61,845.00 Bouyant Weight in Mud (Ibs) 51,915.76 Maximum setting depth (ft) 16,000.00 In Air: = Jt Strength / Wt.ppf Joint Strength Safety Factor 4.85 In Air: = Jt Strength / (Wt ppf "set depth) (At proposed depth) Body Yield Safety Factor 4.01 In Air: =Body Yld / (Wt ppf' set depth (At proposed depth) Collapse Calculations: Collapse Safety Factor 5.18 Collapse Res / (Depth TVD' % Fluid Drop'(Mud B-up Grad -Gas Grad)) Collapse SF while cementing 2.84 Collapse Res /Depth TVD' (Cmt Grad - B-up Mud Grad) No lost Circulation/Evacuation occurs Burst Calculations: Assumeseawaterbackupgradient,.465psi/itforburstdesignpurposes Assume worst case by using anticipated frac gradient and pore press gradients at shoe wi TD (TVD) of next hole section forASP calculations MASP (Maximum Anticipated Surface 2, 880.78 (Frac Grad -Gas Grad)* Next Casing Set Depth (TVD) Pressure Using Frac Gradient @ TD) MASP (Maximum Anticipated Surface 1, 449.17 (Pore Press Grad -Gas Grad)' Next Casing Set Depth (TVD) Pressure Using Known Area PP) Top Burst Safety Factor 3.32 Tube burst rating /ASP 2.79 Using PP (Based on Most Realistic MASP above) Bottom Burst Safety Factor 2.31 (Int.Yld+DepthTVD'SeawaterGrac 4.60 Using PP Summary of: 5 1/2 Safety Factors Body Yield 4.01 in air "Tensile" OK Joint Strength 4.85 in air "Tensile" OK Collapse 5.18 OK Collapse 2.84 while cementing OK Top Burst 3.32 OK Bottom Burst 2.31 OK • • ~~ ~~ Aurora Gas, LLC Aspen No. 1 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 9 518" Surtace Casing Casing Properties: Size OD: 9 5/8 Grade: J-55 Weight ppf: 36.00 Coupling: BTC Set Depth ft 700.00 (ft)MD 700.00 (ft)TVD Next Casing Depth 3990.00 (ft)MD 3990.00 (ft)TVD FIT TEST OR TD Depth 720.00 (ft)MD 720.00 (ft)TVD Collapse Resistance (psi) 2020.00 Internal Yield (psi) 3520.00 Joint Strength (psi) x 1000 639.00 639,000.00 * Tensile Limits Body Yield (psi) x 1000 564.00 564,000.00 * Tensile Limits API Drift Diameter (in) 8.765 Wall Thickness (in) 0.352 Formation &Fluid Properties: Material Weight ppg Gradient psi/ft Mud Weight 11.00 0.572 psi/ft Anticipated Mud Wt Next Csg Pt. 10.50 0.546 psi/ft Calculated Bouyancy Factor @ Mud Wt: 0.83 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 9.1 0.473 Est. Pore Pressure Gradient @ Next Csg Pt. 9.1 0.473 Gas Gradient (psi/ft) 0.110 Mud Backup Gradient ppg 8.95 0.465 `~~~`Fluid Drop for Collapse Calculation (Enter #) 55 0.55 • • Tensile Calculations: Weight in Air (Ibs) 25,200.00 Bouyant Weight in Mud (Ibs) 20,961.47 Maximum setting depth (ft) 15, 666.67 In Air: = Jt Strength / Wt.ppf Joint Strength Safety Factor 25.36 In Air: = Jt Strength / (Wt ppf * set depth) (At proposed depth) Body Yield Safety Factor 22.38 In Air: =Body Yld / (Wt ppf "` set depth (At proposed depth) Collapse Calculations: Collapse Safety Factor 14.76 Collapse Res / (Depth TVD' % Fluid Drop *(Mud B-up Grad -Gas Grad)) Collapse SF white cementing 8.10 Collapse Res/Depth TVD ` (Cmt Grad - B-up Mud Grad) No lost Circulation/Evacuation occurs BUI'St CalCUlat1o11S: Assume seawater backup gradient, .465 psi/1t for burst design purposes Assume worst case by using anticipated frac gradient and pore press gradients at sh with TD(TVDJ of next hole section for MASP calculations MASP (Maximum Anticipated Surface 2, 880.78 (Prat Grad -Gas Grad)' Next Casing Set Depth TVD Pressure using Frac Grad) MASP (Maximum Anticipated Surface 1, 449.17 (Pore Press Grad -Gas Grad)' Next Casing Set Depth TVD Pressure Using Known Area Pore P) Top Burst Safety Factor 2.43 Tube burst rating /ASP (Based on most realistic MASP above) Bottom Burst Safety Factor 1.33 (Int.Yld+DepthTVD'SeawaterGrad)lASP Summary of: 9 5/8 Safety Factors Body Yield 22.38 in air "Tensile" OK Joint Strength 25.36 in air "Tensile" OK Collapse 14.76 OK Collapse 8.10 while cementing OK Top Burst 2.43 OK Bottom Burst 1.33 OK s • ~~ ~~ Aurora Gas, LLC Aspen No. 1 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 73 3/8" Conductor Casing Properties: Size OD: 13 3/8 Grade: LSS Weight ppf: 54.50 Coupling: BTC Set Depth ft 95.00 (ft)MD 95.00 (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) 1130.00 Internal Yield (psi) 2730.00 Joint Strength (psi) x 1000 909.00 909,000.00 "Tensile Limits Body Yield (psi) x 1000 853.00 853,000.00 * Tensile Limits API Drift Diameter (in) 12.459 Wall Thickness (in) 0.38 Formation & Fluid Properties: Material Weight ppg Gradient psi/ft Mud Weight 9.30 0.484 psi/ft Anticipated Mud Wt Next Csg Pt. 11.00 0.572 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. 9.1 0.473 Gas Gradient (psi/ft) 0.110 Mud Backup Gradient ppg 8.95 0.465 %~Fluid Drop for Collapse Calculation iEnter#) 55 0.55 • • Tensile Calculations: Weight in Air (Ibs) 5,177.50 Bouyant Weight in Mud (Ibs) 4,441.25 Maximum setting depth (ft) 15,651.38 In Air: = Jt Strength / Wt.ppf Joint Strength Safety Factor 175.57 In Air: = Jt Strength / (Wt ppf' set depth) (At proposed depth) Body Yield Safety Factor 164.75 In Air: =Body Yld / (Wt ppf "' set depth (At proposed depth) Collapse Calculations: Collapse Safety Factor 60.85 Collapse Res / (Depth TVD ` % Fluid Drop `(Mud B-up Grad -Gas Grad)) Collapse SF while cementing 45.30 Collapse Res /Depth TVD ` (Cmt Grad - B-up Mud Grad) No lost Circulation/Evacuation occurs Burst Calculations: Assume seawater backupgradient,.465psi/ltforburstdesignpurposes Assume worst case by using anticipated frac gradient for TD ofnext 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 5.40 Tube burstratinglASP Bottom Burst Safety Factor 5.49 (Int. Yld + Depth TVD `Seawater Grad) /ASP Summary of: 13 3/8 Safety Factors Body Yield 164.75 in air "Tensile" OK Joint Strength 175.57 in air "Tensile" OK Collapse 60.85 OK Collapse 45.30 while cementing OK Top Burst 5.40 OK Bottom Burst 5.49 OK • • Mr. Norman July 19, 2005 Page 2 If you have any questions or require additional information, please contact the undersigned at 277-1003, or Duane Vaagen, Project Engineer with Fairweather E&P Services, tnc at 258-3446. Sincerely, J~ ,~ tom' J. Edward Jones Executive Vice President Engineer-Operations Aurora Gas, LLC Attachments cc: Andy Clifford Duane Vaagen Sublecr. Fw: n~a~~ ~... ~ . Rn .., i ~ . ~ _ ~~ u.. ~.. i. _,. .. i~,. _~~.~., _ o,. _. i~~._. .~..~~.~ Steve: _~~,/ Please see the Ed's response below on observed pressure trends observed with MDT's on (2) recent wells which should be fairly correlative with what we would expect at Aspen No. 1. This data is from the just drilled Lone Creek No. 3 and the recently drilled Three Mile Creek Unit No. 1. As indicated, these are Asia and almost without exception, the MDT's have shown pressures higher than what we see when testing, possibly from charging due to overbalance mud. Please note comments in tables as well concerning individual tests. Mr. Ed Jones was on site and witnessed all testing personally. Also, in table below, actual SITP numbers are presented based on preliminary testing on the wells indicated. Note these are field gauge readings at surface, and while we try to maintain an accurate set of gauges for testing purposes there may be some inaccuracies. For purposes of this communication, they should suffice to show typical gradients expected. That is with the exception of the Lone Creek No. 3, for which we now have test facility which has dedicated measurement equipment. Well Top Perf SITP (psig) MWE w/o gas grad subtraction Calc. Gradient w/o subtracting gas column NCU 9 1320 650 9.46 .49 Moquawkie 1 * 2636 1175 8.57 .45 Kaloa 2 3250 1400 8.28 .43 LC 3 2620 1177 8.63 .45 Albert Kaloa No. 1 * * 3516 1580 8.64 .45 * The Mobil Moquawkie No. 1 appears to have been slightly overpressured w/ estimates showing a possible gradient of .58 psi/ft, excluding gas-column subtraction, this from old well records. **Based on Albert Kaloa No. 1 records. In answer to question No. 1 below, I believe Andy answered that in his email this morning, but based on rather extensive research of the region by myself, Andy Clifford and Ed Jones, not indication of H2S has been made in any of the deeper oil exploration wells drilled in the region surrounding the Aspen prospect. I hope this information is sufficient for the processing of the permit paperwork. Please call or email with any concerns or questions. Duane Vaagen Fairweather E&P Services, Inc. 907-258-3446 -----Original Message----- From: Ed Jones (mailto:jejones@aurorapower.com] Sent: Friday, July 22, 2005 2:50 PM To: duane vaagen Subject: RE: Aspen No. 1: Questions Duane, I have attached 2 summaries of local MDT tests {data is in Asia, which adds a little to the gradients, as they are usually based an psig). The Beluga tends to be a little overpressured, but .47 is not unreasonable. Nate that the Beluga gradient numbers in LC #3 are quite likely due to supercharging of the formation by 11.2 ppg mud; as we drilled it with 10.2 ppg I believe {weighting up at 1190'; if I remember correctly). Ed, that is correct, they got a little over-ambitious w1 • • the ~rrteiht up. t(hv Ed Ed Jones Vice President Engineering & Operations Aurora Gas, LLC 713-977-5799 (Houston) 907-277-1003 (Anchorage -----Original Message----- From: Stephen Davies [mailto:steve_davies@admin.state.ak.us] Sent: Friday, July 22, 2005 1:11 PM To: Andy Clifford Cc: Randy Jones; duane vaagen Subject: Aspen No. 1: Questions Andy, Regarding Aspen No. 1: 1. Has any H2S been observed/recorded in wells in the Aspen No. 1 area? 2. Could you please provide data and analyses to support your estimate of 0.47 psi/ft for the pore pressure gradient at the Aspen No. 1 location? 3. Have you seen any evidence of shallow gas or abnormal pressure hazards within the seismic or velocity data from the Aspen No. 1 area? Thanks for your help, Steve Davies AOGCC __ II Content-Decriprion: LC 3 fvfi)i Data Sum.xls '§LC 3_MDT Data Sum.xls: Content-T~Pc applic~tionh~ndmscxcel Content-Em-udiny: buxxl - __ z. Content-Description: TMC IvSDI Data SumxL ITMC_MDT Data Sum.xls~'. Content-Type: application/vnd.mscxcel ', Content-Encoding: baseG4 LONE CREEK #3 MDT TESTS July 16, 2005 Zone Measured DRWDN FORMN GRAD GRADNT DELTA Calc Calc Slmbgr Depth TVD MOB RATIO PRESSR from surf EMW GRAD Surf TP* Gas Grad CHECK COMMENTS Test No. Ft Ft MD/CP PSIA psi/ft PPG psi/ft psia psi/ft BHP Carya 2-6.0 4 2886.0 2877.9 32.86 1326.60 0.461 8.86 1254.4 0.025 1327 good test 5 2870.0 2862.0 34.35 1320.37 0.461 8.87 0.392 1248.9 0.025 1320 good test Just above GWC? 9 2858.0 2850.0 11.78 1 344.83 0.472 9.07 -2.038 1272.4 0.025 1345 questionable--gas in flow line earlier in te st number--better? 1320.30 0.463 8.91 0.006 see test log 7 2854.0 2846.0 24.20 1339.29 0.471 9.05 -1.183 1267.2 0.025 1339 questionable--gas in flow line earlier in te st number--better? 1320.26 0.464 8.92 0.007 see test log 8 2800.0 2792.0 4.70 1328.26 0.476 9.15 0.204 1258.1 0.025 1328 appears good--but why higher? Carya 2-5.2 10 2676.0 2668.0 3.03 861.78 0.323 6.21 818.2 0.016 862 still bldg--too slow, aborted test 14 2674.0 2666.0 5.46 1359.41 0.510 9.81 0.510 1290.8 0.026 1359 seal failure--did not charge for it 11 2646.0 2638.0 160.25 1265.45 0.480 9.23 3.356 1202.2 0.024 1265 good test 12 2626.0 2618.0 581.17 1265.16 0.483 9.29 0.014 1202.4 0.024 1265 good test Carya 2-4.2 15 2370.1 2362.3 0.85 1068.99 0.453 8.70 0.767 1021.0 0.020 1069 Slb chart wrong--see test log 17 2315.0 2307.4 0.61 1068.13 0.463 8.90 0.016 1021.3 0.020 1068 Slb chart wrong--see test log 21 2285.9 2278.3 357.44 1067.82 0.469 9.01 0.011 1021.6 0.020 1068 Carya 2-4.1 23 2097.9 2090.7 1.51 1086.00 0.519 9.99 -0.097 1042.8 0.021 1086 Slb chart wrong--see test log Carya 2-3-1 25 1818.0 1812.7 16.70 891.90 0.492 9.46 0.698 861.0 0.017 892 Slb chart wrong--see test log 29 1803.1 1797.3 18.23 881.73 0.491 9.43 0.660 851.5 0.017 882 appears wet Carya 2-1.1 33 1452.9 1449.9 4.97 766.29 0.529 10.16 0.332 745.0 0.015 766 35 1390.0 1387.3 1.52 ~ 42 ~ 5 0.535 10.30 0.376 723.0 0.014 743 Slb chart wrong--see test log 36 1353.9 1348.5 13.83 736.91 0.546 10.51 0.151 717.9 0.014 737 Gas on water? Tsuga 37 980.9 979.3 5.93 575.44 0.588 11.30 0.437 564.6 0.011 575 hydrostatic? Questionable test 38 947.0 946.3 6.72 532.47 0.563 10.82 1.302 522.8 0.010 532 C~` *Pwh=Pbh/e**.0000347*G*D Ed Jones 7/18/2005 • ~ THREE MILE CREEK UNIT #1 MDT TESTS DECEMBER 2004 DRWDN FORMN GRAD DELTA Calc Calc Test Depth/FT TVD/FT MOB RATIO PRESSR from suit GRAD Surt TP* Gas Grad MD/CP PSIA psUft psi/ft psia psi/ft CHECK 3 2400. 38 2290.24 63. 69 CHECK Pbh=Ps*1.16 4 8015. 02 7844.24 7.01 3714. 07 0.473 3189.0 0.067 3714.07 3699.209 5 7984. 01 7813.27 18.99 3700. 28 0.474 0.445 3179.0 0.067 3700.28 3687.693 6 7939. 95 7769.26 3686. 99 0.475 0.302 3170.3 0.066 3686.99 3677.592 7 7928. 01 7757.33 0.47 3687. 47 0.475 -0.040 3171.5 0.067 3687.47 3678.923 9 7775. 63 7605.12 0.95 3574. 50 0.470 0.742 3083.4 0.065 3574.5 3576.779 10 7758. 01 7587.53 1.47 3480. 19 0.459 5.362 3003.1 0.063 3480.19 3483.599 11 7223. 99 7054.07 0.36 3665. 07 0.520 -0.347 3195.6 0.067 3665.07 12 7225. 02 7055.10 0.000 0.0 0 13 7222. 94 7053.02 0.16 3603. 25 0.511 58.876 3141.8 0.065 3603.25 14 6395. 99 6226.85 0.82 3144. 40 0.505 0.555 2786.0 0.058 3144.4 16 6396. 98 6227.84 0.51 3204. 00 0.514 60.202 2838.8 0.059 3204 17 6395. 03 6225.89 0.25 3201. 92 0.514 1.067 2837.1 0.059 3201.92 18 6006. 05 5837.13 0.000 0.0 0 19 6004. 99 5836.07 0.000 0.000 0.0 0 20 5751. 94 5583.09 129.73 2887. 97 0.517 0.488 2591.1 0.053 2887.97 21 5572. 98 5404.18 0.000 0.0 0 23 5304. 03 5135.28 61.12 2651. 86 0.516 0.527 2400.0 0.049 2651.86 25 4969. 99 4801.30 2108.56 2487. 43 0.518 0.492 2265.9 0.046 2487.43 27 4964. 01 4795.31 0.000 0.0 0 28 4889. 99 4721.32 0.000 0.000 0.0 0 30 4892. 98 4724.30 191.15 2450. 38 0.519 0.481 2235.4 0.045 2450.38 32 4788. 02 4619.43 0.66 2378. 05 0.515 0.690 2173.9 0.044 2378.05 33 4595. 98 4427.76 0.12 2295. 33 0.518 0.432 2106.1 0.043 2295.33 35 4579. 99 4411.78 0.000 0.0 0 36 4511. 97 4343.89 0.20 1075. 81 0.242 14.541 988.7 0.020 1075.81 38 4420. 02 4252.12 i1.OG0 0.0 0 41 4141. 96 3974.72 0.58 1868. 22 0.470 -2.146 1729.4 0.035 1868.22 44 3695. 90 3535.82 287.85 1832. 65 0.518 0.081 1711.0 0.034 1832.65 46 3561. 94 3406.45 3.63 1660. 75 0.488 1.329 1554.4 0.031 1660.75 47 3539. 93 3385.22 3.85 1636. 51 0.483 1.142 1532.3 0.031 1636.51 48 3309. 98 3153.70 1.86 1644. 25 0.521 -0.033 1546.5 0.031 1644.25 49 3174. 07 3032.70 2.50 1417. 15 0.467 1.877 1336.0 0.027 1417.15 50 3070. 00 2932.53 0.92 1451. 70 0.495 -0.345 1371.3 0.027 1451.7 52 2985. 03 2850.92 6.79 1359. 70 0.477 1.127 1286.4 0.026 1359.7 54 2949. 98 2817.27 0.000 0.0 0 55 2743. 98 2619.09 2.45 1209. 01 0.462 0.650 1149.0 0.023 1209.01 56 2729. 95 2605.60 1.70 1215. 29 0.466 -0.466 1155.3 0.023 59 2559. 94 2442.21 0.000 *Pwh=Pbh/e**.0000347*G*D 12/21 /04 • • .z©~~ /~~ All dry ditch sample sets submitted to the Commission must be in no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. • • ~~-~~r Sub}eu: RE: ,Atipcn Na. I ~, ... ~, From: Amly Clifford F .Fill ,, n Dai e~*:f..n ~?".~.. ~ ~.~., Tl n i,~. -. rl.i ,_uri, ~. ilc dk ii!. Ct t r.-.,.~. ~~i. ~.~i.~ .. ,.m 'P:4 J~,nr.~. iejoues(a,aura., ~~n ,.,in Steve, I believe that Ed Jones or Duane Vaagen is preparing responses to the first two questions. With respect to the third question, the answer is no, there is no evidence of any shallow gas or abnormal pressure hazards in and around the Aspen-1 area. We have a closely spaced grid of high quality 2D data as well as the offsetting Tyonek Reserve-1 well to support this assessment. The Aspen-1 well will drill into the Beluga Formation Tsuga 2-8 interval to evaluate bypassed gas seen in the Tyonek Reserve-1 and Tyonek Reserve (Moquawkie) 44-8 wells. There have been no recorded instances of H2S in the vicinity. Regards, Andy Clifford. From: Stephen Davies [mailto:steve_davies@admin.state.ak.us] Sent: Friday, July 22, 2005 3:11 PM To: Andy Clifford Cc: Randy Jones; duane vaagen Subject: Aspen No. 1: Questions Andy, Regarding Aspen No. 1: l .Has any H2S been observed/recorded in wells in the Aspen No. 1 area? 2. Could you please provide data and analyses to support your estimate of 0.47 psi/ft for the pore pressure gradient at the Aspen No. 1 location? 3. Have you seen any evidence of shallow gas or abnormal pressure hazards within the seismic or velocity data from the Aspen No. 1 area? Thanks for your help, Steve Davies AOGCC • • NOTE TO FILE Aurora Gas, LLC Diverter Waiver Request Aspen #1 (205-111) Aurora Gas, LLC (Aurora) has applied for an exception to 20 AAC 25.035(c)(1)(B) that requires the diverter line size to be equal to or greater than the drilled hole size. Aurora believes that sufficient drilling information is available in the general area to demonstrate that a 12-1/4" hole may be safely drilled employing a 10" diverter line. Aurora is proposing to employ the 10" diverter line since that size is all that was available from their equipment supplier. Aurora has previously secured waivers for drilling surface hole with an area up to 13% greater than the diverter line size. In this case, the hole area is 50% greater than the diverter line size. This document considers Aurora's request and recommends that it be denied. When drilling the initial sections of a well, the earth does not generally have sufficient strength to contain energized fluids in the wellbore. In order to allow some measure of personnel and equipment safety, equipment and techniques have been developed to allow an uncontrolled flow to be diverted some horizontal distance away from the wellbore. Due to the unfavorable experiences from actual divert situations on the North Slope (Cirque #1) and Cook Inlet (Steelhead), the Commission revised its diverter regulations requiring that at a minimum the initial hole size must be less than the diverter line size. The Commission was given discretion to allow a variance if the variance provided at least equally effective means of diverting flow away from the drill rig or if drilling experience in the near vicinity indicates that a diverter system is not necessary [20 AAC 25.035 (h) (2)]. The requirement to have a diverter line size greater than the initially drilled hole size is to prevent the diverter line from acting like a choke if a divert situation were to occur. Where Aurora has previously proposed 12-1/4" hole with a 10" diverter line size (Nikolai Creek #9), they have rightly planned to drill a pilot hole. Aurora cites the experience of past operators as well as their own in support of their request. Where Aurora has drilled surface holes, they have not experienced difficulties. For this particular well the surface hole is only planned to be 700' deep and TD should still be in the over-compacted glacial sediments. As on these other surface holes, Aurora is proposing to keep their mud weight high in order to prevent any more than drilled gas entering the mud column. Thus far, Aurora has been successful however the differential area between the hole and diverter line sizes has not been so great. To my knowledge, there has only been 1 recent well drilled with the 12-1/4" hole 10" line combination, Pelican Hill's N. Beluga #1. This well was drilled as a direct offset (< 200' distant) to a previously drilled (determined dry) well. Control for that particular well was much better than exists for Aspen #1 where the nearest well is approximately 3000' distant. If this request is denied, the consequence will be that Aurora will have to drill and open a pilot hole. At 700', the time penalty should be less than a day. I r commend denial of Aurora's request. ~4~a~ Tom Maunder, PE Sr. Petroleum Engineer July 26, 2005 G:\common\tommaunder\Well Information\By Subject\BOP-Diverter\Waivers\050726- note Aspen #1 diverter line.doc • • tiAurrora Gas, LLC www.aurorapower.com 22-July-2005 Mr. Tom Maunder P.E. Senior Petroleum Engineer 333 W. 7th Ave., Ste. 100 Anchorage, AK 99501 Re: Diverter line size waiver request, Aspen No. 1. Dear Mr. Maunder: RECEIVED JUL ~ ~ 2~Q5 Alaska Oil & Gas Cons. Cammi~siurt Anchorage Aurora Gas, LLC recently submitted under separate cover an Application for Permit to Drill, for the Aspen No. 1 well. The proposed wellbore geometry includes installation of a 13 3/$" conductor, drilling 12-'/4" surface hole, setting 9- /$" surface casing and drilling out to TD w/ 7-'/$" bit. Aurora Gas has available for use a 13 s/a" 5M diverter spool w/ single 10" ID outlet. Per 20 AAC 25.035 (c)(1)(A) there is a requirement that the diverter line outlet size be at least 16" in diameter or (B) at least as large as the hole size being drilled, unless one can show through historical precedent or other that drilling a hole size larger than the diverter line outlet size can be done safely. For reasons indicated below, Aurora is hereby requesting a waiver of the diverter line size requirements as required in the above mentioned regulation. Offset Well History: There has been numerous oil exploration wells drilled in the region. Though unsuccessful and P&A'd, these offset attempts provide information however on pressure gradients that might be encountered in the shallower horizons Aurora is interested in. The nearest offset drilling attempt is the Tyonek Reserve No. 1 drilled by the Humble Oil and Refining Company in 1965 and is located approximately 3108 ft +/- to the south of the proposed Aspen 1 well. Review of available drilling records for the Tyonek Reserve No. 1 show no indication that other than normal pressure gradients exist for the immediate area. Aurora also expects that the same strata will be encountered in the Aspen 1 well as was encountered in the Tyonek Reserve well, only up dip. For this reason, Aurora feels the intervals to be drilled through do not pose swell-control risk. Aurora also feels there is enough information available to safely drill the surface hole interval without benefit of first drilling a pilot hole. Based on the historical well information indicated above, Aurora hereby requests a waiver of the pilot hole requirement per both 20 AAC 25.035 (c)(1)(B) and 20 AAC 25.035 (h)(2). Please do not hesitate to contact the undersigned at 277-1003, or Duane Vaagen (Fairweather E&P) at 258-3446 with any questions or concerns. Sincerely; ~~ ;~ ~__ ,,, J. Edward Jones '~ ~%~ -.r Executive Vice Pr~s'rdent Engineering-Operations Aurora Gas LLC. 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 • • ASPEN-1: X= 278847.78 ASPEN -1 v=2589811.91 PREFERRED LOCATION ON SEISMIC LINE AP04-05 Z O H a ,~ V O Z -~ W ~ ~• W ~ ~ Q ~ W W a • • ~~AurOra POWer FIRST NATIONAL BANK ALASKA ANCHORAGE, AK 99520 2.286 °~~., ~ 1400 WEST BENSON, SUITE 41-0 89-6/1252 ANCHORAGE, AK 59503 f ` PH: (907) 277-1003 7/15/2Q07 PAY TO THE AOGCC ORDER OF ~- One Hundred and 00/100****************** Alaska-Oil and Gas APD Kaloa #3 ~,,,~° I ~ ** 100.00 "~ "'"JM DOLLARS ~ ~' ,~- ~~~„~ 11'00 2 28611' e: 1 2 5 200060: 30 20 389 711• Aurora Power FIRSANCHORAGE AK 9 5 0 SKA 2 8 8 1400 WEST BENSON, SUITE 41'0 89-6/1252 ANCHORAGE, AK 99503 PH: (907) 277-1003 ~%20%2005 'AY TO THE State of Alaska ' ~ ** 100.00 )RDER OF One Hundred and OOi100************~***'*************;~****************~**************~****~***************************** .DOLLARS `State of Alaska APD Aspen # I ~~ Nr lEMO 11'00 2 28811' ~: L 25 20006011: 30 20 389 711' ~ • TRANSMITAL LETTER CHECK LIST CIRCLE APPROPRIATE LETTER/PARAGRAPHS TO BE INCLUDED IN TRANSMITTAL LETTER WELL NAME s eh I PTD# 2d $ ~ ~~ 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 25.005(f), all (PIS records, data and togs 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 ZO AAC 25.055. Approval to perforate and groduce/infect is contingent upon issuance of a conservation order approving a spacing exception. (Company Name1 assumes the liability of any protest to the spacing exception that may occur. DRY DITCH All dry ditch sample sets submitted to the SAMPLE Commission must be in no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Rev: 04/01/05 C\jody\transmittal_checklist WELL PERMIT CHECKLIST Field & Pool Well Name: ASPEN 1 Program EXP Well bore seg ^ PTD#:2051110 Company AURORA GAS LLC Initial Classltype EXP / PEND GeoArea 820 Unit OnfOff Shore On Annular Disposal ^ Administration I1 Permit_feeattached___.__--____.-____ Yes- _-_-_._____________ _____________________________________________________ 12 Lease number appropriate. _ - _ _ - - _ - Yes - _ - - CIRI•Fee_ lease C-61387: have Designation of Operator fo[m on fle. 7125/05; receive-Notice of Change of Owner _ 3 Unique well_nameand number _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _Yes _ _ _ . _ _ -ship-fo[m for 61387 along with Notice of Change of Ownership & Designation of Operator forms fgr adjacent _ _ _ _ 4 Well located in a_defnedpool_ - - _ - _ - _ No- - _ leases C-61388, C-61391.and C-61392, which_were passed_to Commissioners forapproval and sgnatur_e.-$FD _ . 5 Well located proper distance from drilling unitboundary_ - - _ , - . _ Yes - - - _ - . - _ - - . - - - - 6 Welllgcatedproperdistancef[omotherwells___________________ ___________Yes_ -_--__ 7 Sufficient acreageayailablein_drillingunit---______---_._____ ___________ Yes_ ___----__-.--_____-___ __-.-_-__-__,_____----_________.__--__-__._--.__- 8 If deviated, is-wellboreplat_included______________________- -_____--__- NA__ _.-_Verticalwell-____________ ---------------------------------------------- 9 Operator onty affected party- - - - - _ _ - - _ - - - _ - - _ Yes _ - Landgwner of all affected leases is CI_RI; owner of all a_ffected_leases is Aurora, 10 Operator has-appropriate.bond in force - - - - -- - - - - - - - - - - - - - -- - - - - - - -- - - - -Yes . ... - .. letter of C[edit: NZS429815 _ _ _ _ _ .. _ _ _ _ _ 11 Pe[mitcartbeissuedwithoutconservationorder_________________ ___________Yes_ ______--.-____-----__-.-.--___--.-_--__..-_----..--_-_-.-___-.-._---_ Appr Date 12 Permit can be issued without administrative_approyal _ - - - _ _ _ - - _ Yes - - - - - - - - - -- - - - - - - - SFD 7/25/2D05 13 Can permit be approved before 15-day wait Yes X 14 Well located within area and-strataauth4rizedby_InjQCtionO[de[#(putJO#in _comments)_(F4r_NA-- ---------------------------------__--.-..-___--.--__-..---__.---.-__--- 15 Allwellswithin114_mileareaof[eyiewidentified(Forserv_iicewellonly)____ ___________NA__ __.__-__________.__-__-_._______-.__,_....______-.__________ 16 Pre-produ_cedipjector: duration of pre production lessthan_3months_(Forservicewellonly)-_NA_- -.-___--____-______-_.________________________________________________ 17 ACMP-Finding of Consistency.has been issued-for this project. _ - _ . - - - . - NA_ ACMP deter_m_inationno Jonger required prior to issging apermit to-drill.- - - - - _ _ . - - Engineering 18 Conductorstripg_provided___________________-__--.____ -__-_______Yes_ _-.----_-..--__..--.-_--..---__--_---- 19 Surface casing_prQtectsoll kncwn_ USDWS - - - - - - - .. - _ . - - - Yes Surface and_production casing will_protect any_FW Sands.. - - _ - 2D _C_MT vol-adequate to circulate-on conductor & surf rsg _ - Yes - _ _ _ - - _ _ 21 CMT-vol adeggate to tie-in long string to surf ag _ - _ _ _ - _ . Yes _ _ - Prooduction_ eosin is I_anned to be cemented to_surface.- _ _ _ 9 p - - 22 CMT-will coverall known_pro_ductive horizons. - _ _ _ _ - - - - _ _ _ - _ _ _ _ _ _ - _ - _ _ _ Yes - _ _ _ - - - - _ _ 23 Casingdesgnsadeguatef_orC,T,B&_permafrost___________ _____ ________Ye5- -_,-_-..---_- 24 Adequate tankage_or reserve pit _ - - _ - - Yes Rig is-equipped with steel-pits. .Although relatively small, Aurora has successfully drilled similar_wells _ - - - 25 If_a_re-drill, has_a_ 10-403 for abandonment been approved , _ . _ _ - NA- - . - - using this rig. Drilling waste like handled via EnYi[otech._ 26 Adequatewellboreseparation_proposed_______________________ __________Yes- __,___Nea_restwellbore~1 mile SE,-___--_-____,__-__-____-_-______-______ 27 If_diverter required, does it meet-regulations_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ _ _ - -Aurora should-dril_I a pilot hole to meet the regulations. _ _ _ _ - . - _ _ Appr Date 28 Drilling fluid_program schematic & equip list adequate. - . _ - - Yes _ _ Maximum expected formation pressure up to 9.0 EMW at TD.. Up to_ 10.0_EMW in surface-hole, - TEM 7/2612DD5 29 BOPEs,-dolheymeet_regu_lotion--.-- ------------------- ----------Yes- ------ --------- ------ ---- ---- --- - - -- -- ---- ----- ----.--------,---- ~rlw I -- 30 BQPE_press rating appropriate; test to_(put prig in comments)_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Y_es _ _ _ _ - - _ MASP calculated at 1436psi, 3000-psi_test p[oposed._ _ _ - - _ _ _ _ _ _ - _ - - _ _ _ _ _ l 31 _C_hgke_manifoldcgmpliesw/APLRP-53(May84)__________________ __________Yes_ ____-_-_____--____--_._______-____________.--___-_ 32 Work will occur without operation shutdown- _ - Yes 33 Is presence_of H2S gasprobable_ No_ H2S has not been reported in gasproduced without oil, Rigis equipped with.sensors and alarms. 34 Mecha_nicalconditionofwellswithinAORuerified(For_servicewellon_ly)___ ____--_-- NA_- -________ _______________________________ -__---_______- ____---___-_-- Geology , ~ 35 Permitcan be issued wlo hydrogen_sulfide measures No- - - - - _ No H2S has been observed-in exploratory wells within this. region. - - _ - - 36 Data-presented on potential gverpressure zones Yes Supplimenta_I data received July 25, 2005 indicates expected gradient is 0.43 0.49 psilft-($.$ -9 4 ppg EMW), Appr Date 3T Seismic analysis-of shallow gas-zones- - - - - - - - - - - - - ~ Yes - - Will be drilled with 9.5 -1-1,0 ppg mud.. ~ SFD 7!2512005 38 -Seabed condition survey_(ifoff-shore) - _ _ _ - . _ - NA_ ~:i There is no evidence cf any shallow_gas or_abnormal pressure hazards in_the area. _A. Clifford, 7 5 005. - ti1 ~~ 39 _Contactnam_elphoneforweeklyprogress_reports[exploratoryonly)______ __________Yes. ~ ---__DuaneVaagen 258-3446--_-____-_________-_______--_____-__-_____-__-__- Geologic Engineering P ~ Date: Date Date A s acin exce tion will not be re cored u on Commissioner a royal and si nature of Notice of Chan a of Ownershi and p 9 p q p pp 9 9 p Commissioner: /~ ~ p Commissioner: issi ' ~ O I designation of Operator forms for leases C-61387, C-61388, C-61319, and C-61392, as the landowner, owner, and operator ~ will then be the same on all affected leases. SFD 7!2512005 ;J U ~ ~ ~~~5 U ~~ O •
