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DIO 032
INDEX DISPOSAL INJECTION ORDER NO. 32 Beluga Formation Aspen No.l Well 1. -------------------- Aurora Gas, LLC's (Aurora) application for disposal of class II oilfield waste by underground injection 2. July 17, 2007 Letter from AOGCC to Aurora re: deficiencies in request 3. July 18, 2007 Aurora's submittal of deficient information for disposal of class II oilfield waste by underground injection 4. August 3, 2007 AOGCC's response to Aurora's submittal of information dated July 28, 2007 5. September 4 and 5, 2007 Notice of Public Hearing, Affidavit of Publication, and mailings 6. October 9, 2007 Transcript 7. October 11, 2007 Confinement Information Aspen #1 8. October 16, 2007 Transcript 9. -------------------- Emails 10. November 21, 2008 Aurora's request to dispose freeze protection fluids into Aspen #1 (DIO 32.001) 11. -------------------- Emails 12. -------------------- Annual Aspen #1 Injection Surveillance Reports No. 1 13. -------------------- Annual Aspen #1 Injection Surveillance Reports No. 2 14. July 13, 2012 Annual Aspen #1 Injection Surveillance Report No. 4 15. August 8, 2013 Annual Aspen #1 Injection Surveillance Report No. 5 16. December 19, 2013 Letter from AOGCC to Operator closing an investigation of unauthorized pump rates 17. August 14, 2014 Aurora's request for Administrative Approval for an Operational Variance of the Aspen No. 1 well to allow for continued operation of Aspen until such time that a viable long-term corrective action is identified (DID 32.002) 18. September 10, 2018 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. (DIO 32-003) 19. April 23, 2019 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 (DIO 32.004) 20. May 21, 2019 CIRI non -objection to Amaroq's request 21. May 22, 2019 Amaroq;s request for reconsideration of DIO 32.004 22. June 2, 2019 AOGCC Denied Reconsideration of Amaroq • • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: THE APPLICATION OF Aurora Gas LLC for disposal of Class II oil field wastes by underground injection in the Beluga Formation in the Aspen No. 1 Well, Section 33, T12N, R11W, S.M. IT APPEARING THAT: Disposal Injection Order No. 32 Beluga Formation Aspen No. 1 Well February 7, 2008 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 • Aspen No. 1 February 7, 2008 Page 2 of 8 5. A public hearing was held October 9, 2007. A brief project summary was provided by an Aurora representative. The Commission requested additional information concerning injected fluid confinement. The hearing was continued until October 16, 2007. Aurora submitted the requested information on October 11, 15 and 16, 2007. 6. The public hearing was reconvened on October 16, 2007. At the hearing, Commission senior staff confirmed that the additional information requested had been submitted. 7. Information submitted by Aurora and public well history records are the basis for this order. The Aspen 1 well history file, including well logs, was publicly released on October 6, 2007. FINDINGS: 1. Location of Adjacent Wells (20 AAC 25.252(c)(1)) There are no wells with surface or bottomhole locations within aone-quarter mile radius of the Aspen 1 well. The nearest known water well is a 50-foot deep domestic water well located about 3.5 miles to the northwest at the Chuit River Lodge. 2. Notification of Operators/Surface Owners (20 AAC 25.252(c)(2) and 20 AAC 25.252(c)(3)) Aurora is the operator of the Aspen 1 well, which was drilled as a gas exploration well and suspended in 2005. The sole surface owner within aone-quarter mile radius of the Aspen 1 well is Tyonek Native Corporation ("TNC"). Cook Inlet Regional Incorporated ("CIRI") is the sole subsurface owner. Aurora submitted an affidavit showing that TNC and CIRI were provided a copy of the disposal application and thereby notified of the proposed waste disposal injection into the Beluga Formation using Aspen 1. 3. Geologic Information on Disposal and Confining Zones (20 AAC 25.252(c)(4)) Aspen 1 encountered the Beluga Formation ("Beluga") from a depth of 722 feet measured depth ("MD") to the total depth of the well at 4,485 feet MD. In the Aspen 1 well, the Beluga is dominated by claystone and clay intervals that are interspersed with beds of coal (generally less than 5 feet thick, but occasionally from 6 feet to 12 feet thick) and thin beds (1 foot to 5 feet thick) of sand, sandstone, or siltstone. Sand and sandstone beds within the Beluga are discontinuous, and they are interpreted to have been deposited by shifting, shallow, braided streams (Hayes, J.B., Harms, J.C., and Wilson, T.W., 1976, in Miller, T.P., ed., Recent and Ancient Sedimentary Environments in Alaska, Alaska Geological Society Symposium Proceedings, p.Jl-J27). Aurora proposes to conduct disposal operations in the Aspen 1 well in the Beluga between 2,125 feet and 2,371 feet MD. This receiving zone consists of interbedded sand, claystone and coal. Well and mud log information indicate that the sand beds are up to 4 feet thick and composed of very fine-grained to coarse-grained sand partially cemented by calcite. The claystone beds are up to 5 feet thick. The coal beds are up to 6 feet thick and scattered throughout the injection interval. Disposal Injection Order 32 Aspen No. 1 February 7, 2008 Page 3 of 8 Aurora proposes to utilize two perforated zones for the Class II disposal injection. The upper zone would be between 2,125 feet and 2,145 feet MD. This interval's effective porosity is about 25 percent, based on calculations using well log data. The lower perforated zone will also be 20 feet thick, with the top at 2,351 feet MD. This interval's effective porosity is about 22 percent. Upper, lower and lateral confinement will result from interlayered claystone, clay, siltstone and coal beds as described in Finding 9 below. 4. Aspen 1 Logs (20 AAC 25.252(c~5)~ The logs of the Aspen 1 well are on file at the AOGCC. 5. Aspen 1 Casing Description 20 AAC 25.252(c)(6)(A)) There are three strings of casing as follows: • Conductor Casing: 13-3/8", 68 pounds per foot, J-55 casing driven to 77 feet true vertical depth ("TVD")1; • Surface Casing: 9-5/8", 53.5 pounds per foot, L-80 casing, shoe depth 675 feet TVD, cemented to surface with 30 barrels of cement; • Production Casing: 5-%z", 15.5 pounds per foot, J-55 casing, shoe depth 4,467 feet TVD, cemented to surface with 41 barrels of lead (13.5 pounds per gallon ("ppg")) and 136 barrels of tail (15.8 ppg) slurry. 6. Demonstration of Mechanical Integrity and Disposal Zone Isolation (20 AAC 25.252 (c)(6)) Proposed workover operations were approved by the Commission on May 29, 2007 allowing Aurora to reconfigure Aspen 1 for Class II oil field waste disposal purposes. Sundry approval 307-172 authorizes Aurora to reenter Aspen 1 to confirm casing integrity, remove suspension plugs, install 2-7/8" injection tubing and packer in the well, and install the injection tree. A cement quality log is available for Aspen 1. It evidences the existence of adequate bonding across the upper and lower confining intervals to ensure disposed fluids are appropriately isolated. The top of the cement for the innermost casing is at 220 feet MD, which is approximately 470 feet above the surface casing shoe. Aspen 1 was perforated between 1,368 feet and 1,388 feet MD and flow tested as part of the exploration evaluation. Those perforations were abandoned with a balanced plug set from 1,265 feet to 1,373 feet MD prior to suspending the well. In the approved work plan, Aurora will drill out this plug and install 2-7/8" injection tubing and packer to isolate the uppermost perforations behind pipe. ' Aspen 1 is a vertical well; TVD equals MD. Disposal Injection Order 32 ~ ~ Page 4 of 8 Aspen No. 1 February 7, 2008 Prior to initiating disposal operations, Aurora will perform a pressure test of the tubing by production casing annulus as required by 20 AAC 25.412(c). Aurora has also committed to a one-time temperature survey during the initial injection to demonstrate that the injected fluids are confined. 7. Disposal Fluid Type, Source, Volume and Compatibility with Disposal Zone (20 AAC 25.252(c)(7)) The wastes planned for disposal in Aspen 1 would consist of produced water, drilling, completion and workover fluids, rig wash, mud slurries and other Class II fluids and solids. The composition and constituents of the waste stream are heavily dependent on the type of activity (drilling, stimulation, production, maintenance, etc.). Fluids associated with production at the Three Mile Creek Unit ("TMCU") and Nicolai Creek Unit ("NCU") are currently stored in a nearby produced water impoundment. These fluids would be disposed of in Aspen L Laboratory analyses of the produced fluids from TMCU 1, TMCU 2, and NCU 9 and the fluids temporarily stored in the produced water impoundment were provided to the Commission. Calculations to determine the scaling tendencies of the produced waters were also provided. Produced water from the Beluga Formation within the TMCU 1 and TMCU 2 wells may cause calcium carbonate scale or precipitates to form when injected into Aspen 1. None of the other Aspen 1 proposed waste stream fluids are likely to form scale or precipitates. 8. Estimated Injection Pressure (20 AAC 25.252(c)(8)) A 4-point step rate test (which is a test designed to validate the injection rate and pressures used in fracture modeling) would be performed prior to any disposal injection operations using water from the produced water impoundment. The test would be designed to establish the actual injection rate and pressure characteristics of the Beluga Formation. Aurora's fracture modeling predicts injection pressures between 1,200 psi and 1,600 psi at disposal rates of 1 barrel per minute and fluid densities ranging from 8.4 pounds per gallon to 9.7 pounds per gallon. 9. Evaluation of Confining Zones (20 AAC 25.252(c)(9)) Disposed wastes will be prevented from migrating upward by interlayered claystone, clay, siltstone and coal occurring from 1,400 to 2,125 feet MD in Aspen 1. This upper confining interval totals 725 feet gross thickness, of which 40% is clay, claystone or coal. Downward migration will be prevented by claystone, clay, siltstone and coal occurring between 2,372 and 3,480 feet MD in the well. This lower confining interval totals 1,108 feet of gross thickness, of which 60 percent is clay, claystone or coal. Beluga sand and sandstone beds are thin and discontinuous. Encapsulating clay, claystone and coal will prevent significant lateral migration of injected fluids. Disposal Injection Order 32 Aspen No. 1 February 7, 2008 Page 5 of 8 Low injection pressures, low injection rates, and the limited amount of disposed fluids ensure that fractures will not propagate through the confining intervals. Aurora's computer modeling study indicates that, under the proposed operating conditions, fractures created by fluid injection may extend upward about 30 feet MD above the receiving interval and downward about 40 feet MD below the receiving interval2. 10. Standard Laboratory Water Analysis of the Disposal Zone (20 AAC 25.252(c)(10)) A formation water salinity determination was provided with the disposal injection application. Aurora calculated a salinity range of 10,000 to 29,000 parts per million ("ppm") for the Beluga Formation within the injection interval. Aurora's salinity calculations were confirmed by the Commission using wireline log data and methods compatible with the RWa method endorsed in the U.S. Environmental Protection Agency.3 11. Freshwater Exemption (20 AAC 25.252(cZ 11 ~~ A freshwater aquifer exemption issued under 20 AAC 25.440 is not required because the total dissolved solids of the formation water exceed 10,000 ppm in the target injection zone. 12. Mechanical Condition of Wells Penetratin tg he Di~osal Zone Within 1/4 Mile of Aspen 1 (20 AAC 25.252(c~(12~ There are no wells within aone-quarter mile radius of the Aspen 1 well. CONCLUSIONS: 1. The requirements of 20 AAC 25.252(b) and (c) are met. 2. A freshwater aquifer exemption is not required. The total dissolved solids of the receiving zones' waters are greater than 10,000 ppm. 3. Waste fluids will be contained within the receiving interval-and, therefore, will not contaminate freshwater, oil, or gas sources-by the confining lithologies, Aspen 1 well's construction (i. e., casing and cement), and the proposed disposal injection operating conditions. 4. Disposal injection operations in the Aspen 1 well will be conducted at rates and pressures below those that would fracture through the confining zone. 5. Evaluation of surveillance and operational performance data will reasonably assure there is no fracturing through the confining zone. z See Bruce Webb letter to Commission, received on Oct. 15, 2007, at 2. s See U.S. EPA, "Survey of Methods to Determine Total Dissolved Solids Concentration" (KEDA Project No. 30- 956). 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: Infection 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: Infection 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 psifft 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. Disposal Injection Order 32 Aspen No. 1 February 7, 2008 Page 7 of 8 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 Improver Infection 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. 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 revo DONE at Anchorage, Alaska, and dated I 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). Cathy P oerst r, Commissioner • • Mary Jones David McCaleb Cindi Walker XTO Energy, Inc. IHS Energy Group Tesoro Refining and Marketing Co. Cartography GEPS Supply & Distribution 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 300 Concord Plaza Drive Ft. Worth, TX 76102-6298 Houston, TX 77056 San Antonio, TX 78216 George Vaught, Jr. Jerry Hodgden Richard Neahring PO Box 13557 Hodgden Oil Company NRG Associates Denver, CO 80201-3557 408 18th Street President Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 John Levorsen Michael Parks Mark Wedman 200 North 3rd Street, #1202 Marple's Business Newsletter Halliburton Boise, ID 83702 117 West Mercer St, Ste 200 6900 Arctic Blvd. Seattle, WA 98119-3960 Anchorage, AK 99502 Baker Oil Tools Schlumberger Ciri 4730 Business Park Blvd., #44 Drilling and Measurements Land Department Anchorage, AK 99503 2525 Gambell Street #400 PO Box 93330 Anchorage, AK 99503 Anchorage, AK 99503 Ivan Gillian Jill Schneider Gordon Severson 9649 Musket Bell Cr.#5 US Geological Survey 3201 Westmar Cr. Anchorage, AK 99507 4200 University Dr. Anchorage, AK 99508-4336 Anchorage, AK 99508 Jack Hakkila Darwin Waldsmith James Gibbs PO Box 190083 PO Box 39309 PO Box 1597 Anchorage, AK 99519 Ninilchick, AK 99639 Soldotna, AK 99669 Kenai National Wildlife Refuge Penny Vadla Richard Wagner Refuge Manager 399 West Riverview Avenue PO Box 60868 PO Box 2139 Soldotna, AK 99669-7714 Fairbanks, AK 99706 Soldotna, AK 99669-2139 Cliff Burglin Bernig Karl North Slope Borough PO Box 70131 K&K Recycling Inc. PO Box 69 Fairbanks, AK 99707 PO Box 58055 Barrow, AK 99723 Fairbanks, AK 99711 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 /f I ~/ Page 1 of 1 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Thursday, February 07, 2008 11:18 AM Subject: DIO 32 Aspen #1 Attachments: dio32.pdf BCC:Cynthia B Mciver (bren.mciver@alaska.gov); 'Alan Birnbaum <""Alan J Birnbaum "> (alan.birnbaum@alaska.gov)'; 'Aleutians East Borough'; 'Anna Raff ; Arion, Teri A (DNR); 'Arthur C Saltmarsh'; 'Arthur Copoulos'; 'Barbara F Fullmer'; 'bbritch'; 'Bill Walker'; 'Brad McKim'; 'Brandon Gagnon'; 'Brian Gillespie'; 'Brian Havelock'; 'Brit Lively'; 'Bruce Webb'; 'buonoje'; 'Cammy Taylor'; 'Cande.Brandow'; 'carol Smyth'; 'Cary Carrigan'; caunderwood@marathonoil.com; 'Charles O'Donnell'; 'Chris Gay'; 'Christian Gou-Leonhardt'; 'Cliff Posey'; 'Dan Bross'; 'dapa'; 'Daryl J. Kleppin'; 'David Brown'; 'David Hall'; 'David L Boelens'; 'David Steingreaber'; 'ddonkel'; 'Deanna Gamble'; 'Deborah J. Jones'; 'doug_schultze ; 'Evan Harness'; 'eyancy ; 'foms2@mtaonline.net ; 'Francis S. Sommer'; 'Fred Steece'; 'Garland Robinson'; 'Gary Laughlin'; 'Gary Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil'; 'Gregg Nady'; 'gregory micallef; 'gspfoff; 'Hank Alford'; 'Harry Engel'; 'jah'; 'James B Regg'; 'James M. Ruud'; 'James Scherr'; 'Janet D. Platt'; 'jdarlington'; 'jejones'; 'Jerry McCutcheon'; 'Jim White'; 'Jim Winegarner'; 'Joe Nicks'; 'John Garing'; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'John W Katz'; johnny.aiken@north-slope.org; 'Jon Goltz'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; knelson@petroleumnews.com; 'Kristin Dirks'; 'Laura Silliphant'; 'Lois'; 'Lynnda Kahn'; 'mail=akpratts@acsalaska.net'; 'mail=Crockett@aoga.org'; 'mail=fours@mtaonline.net'; 'Mark Dalton'; 'Mark Hanley'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marguerite kremer'; 'marty'r 'Matt Rader'; 'mckay'; 'Meghan Powell'; 'Mike Bill'; 'Mike Mason'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'Nick W. Glover'; NSK Problem Well Supv; NSU, ADW Well Integrity Engineer; 'Patty Alfaro'; 'Paul Decker'; Pierce, Sandra M (DNR); 'Randall Kanady'; 'Randy L. Skillern'; 'rcrotty'; Rice, Cody J~ (DNR); 'rmclean'; rob.g.ciragnich@exxonmobil.com; 'Robert Campbell'; 'Robert Fowler'; 'Robert Province'; 'Roger Belman'; 'Rudy Brueggeman'; 'Scott Cranswick'; 'Shannon Donnelly'; 'Sharmaine Copeland'; 'Sondra Stewman'; 'Sonja Frankllin'; 'Stan Porhola'; 'stanekj'; 'Stephen F Davies'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'tablerk'; 'Tamera Sheffield'; 'Temple Davidson'; 'Terrie Hubble'; 'Tim Lawlor'; 'Todd Durkee'; 'trmjrl'; 'Walter Featherly'; 'Walter Quay'; 'Wayne Rancier' Attachments: dio32.pdf; Jody Colombie Special Assistant Alaska Oil & Gas Conservation Commission Direct: 907-793-1221 Fax: 907-276-7542 "Note new email address 2/7/2008 Page 1 of 1 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Thursday, February 07, 2008 1:46 PM To: 'rlauriguet@bhb.com' Subject: DIO 32 Aspen #1 Attachments: dio32.pdf Per your request. Jody Colombie Special Assistant Alaska Oil & Gas Conservation Commission Direct: 907-793-1221 Fax: 907-276-7542 *Note new email address 2/7/2008 u U d 0 ~ o 0 SARAH PALIN, GOVERNOR t~i/,C,~7~C'1 OII/ ~ ~ 333 W. 7th AVENUE, SU17E 100 C01~5~R~A'1`IO1~T COMl-IISSIOrT ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL NO. DIO 32.001 Mr. Bruce D. Webb Manager, Land and Regulatory Affairs Aurora Gas, LLC 1400 W. Benson Boulevard, Suite 410 Anchorage, AK 99503 Re: Disposal Injection Fluids Dear Mr. Webb: Disposal Injection Order (DIO) 32 approved the injection of Class II waste fluids into the Beluga Formation within Aspen Well No. 1 (Aspen 1). By letter dated November 21, 2008, Aurora Gas LLC (Aurora) requested approval to dispose of freeze protect fluids proposed for use in Aspen 1. Aurora also requested the Commission to delineate the fluids eligible for Class II disposal in Aspen 1. Your request to inject freeze protect fluids -namely methanol, and triethylene glycol (used and unused) is APPROVED. Aspen 1 is at the time of this approval Aurora's only Class II disposal injection well in Alaska. The well is proximate to Aurora's exploration and gas production activities at the Three Mile Creek Unit, Lone Creek gas field, and Nicolai Creek Unit located on the west side of Cook Inlet. Confinement of fluids to the intended injection zone in Aspen 1 was evaluated and deemed sufficient for approval of DIO 32. Well integrity has been demonstrated by a successful mechanical integrity test performed on September 1, 2008 and the well head pressures that are monitored during injection. Results of the baseline temperature survey and a subsequent temperature survey performed on November 14, 2008 confirm all injected fluids to date are entering and remain confined to the intended injection zone. Protecting the injection well and associated surface piping is necessary to ensure continued mechanical integrity of the Aspen 1 waste disposal injection operation, particularly given the periodic batch injection performed. The addition of small amounts of methanol or triethylene glycol (freeze protect fluids) following batch injection (particularly during winter months) will have no detrimental effect on the confinement of fluids. Well integrity and correlative rights will not be negatively impacted because of the proposed inclusion of small amounts of freeze protect fluids in the disposal injection fluid stream. Waste will also not occur because of the addition of small amounts of freeze protect fluids. DIO 32.001 • • December 11, 2008 Page 2 of 2 DIO 32 authorizes the disposal injection of Class II waste fluids generated during drilling, production and workover operations. In general, fluids eligible for Class II disposal injection can be described as those waste fluids that have been brought to the surface, fluids in contact with those brought to surface (e.g., used for treating the produced fluids), and fluids placed in the'well for a specific purpose such as freeze protection fluids. At Aurora's request the Commission provides the following clarification to DIO 32: RULE 2: Fluids The waste fluids authorized for injection in Aspen 1 include produced water, drilling, completion and workover fluids, rig wash; drilling mud slurries; and other Class II fluids generated from drilling, production, workover and completion operations. DONE at Anchorage, Alaska Daniel T. Seamount, Jr. Chair 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 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. Page 1 of 1 • • Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Thursday, December 11, 2008 3:54 PM Subject: dio32-1 Aspen #1 Attachments: dio32-1.pdf BCC:'Aaron Gluzman'; caunderwood@marathonoil.com; 'Dale Hoffman'; Fridiric Grenier; 'Joe Longo'; 'Lamont Frazer'; Marc Kuck; 'Mary Aschoff; Maurizio Grandi; P Bates; Richard Garrard; 'Sandra Lemke'; 'Scott Nash'; 'Steve Virant'; Tom Gennings; 'Willem Vollenbrock'; 'William Van Dyke'; Woolf, Wendy C (DNR); 'Aleutians East Borough'; 'Anna Raff ; 'Barbara F Fullmer'; 'bbritch'; 'Bill Walker'; 'Brad McKim'; 'Brandon Gagnon'; 'Brian Gillespie'; 'Brian Havelock'; 'Brit Lively'; 'Bruce Webb'; 'buonoje'; 'Cammy Taylor'; 'Cande.Brandow'; 'carol smyth'; 'Cary Carrigan'; 'Charles O'Donnell'; 'Chris Gay'; 'Cliff Posey'; 'Dan Bross'; 'dapa'; 'Daryl J. Kleppin'; 'David Brown'; 'David Hall'; David House; 'David L Boelens'; 'David Steingreaber'; 'ddonkel'; 'Deborah J. Jones'; 'doug_schultze'; 'Eric Lidji '; 'Evan Harness'; 'eyancy'; 'foms2@mtaonline.net'; 'Francis S. Sommer'; 'Fred Steece'; 'Garland Robinson'; 'Gary Laughlin'; 'Gary Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil'; 'Gregg Nady'; 'gregory micallef ; 'gspfoff ; 'Hank Alford'; 'Harry Engel'; 'jah'; 'James Scherr'; 'Janet D. Platt'; 'jejones'; 'Jerry McCutcheon'; 'Jim Arlington'; 'Jim White'; 'Jim Winegarner'; 'Joe Nicks'; 'John Garing'; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'John W Katz'; johnny.aiken@north-slope.org; 'Jon Goltz'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; knelson@petroleumnews.com; 'Krissell Crandall'; 'Kristin Dirks'; 'Laura Silliphant'; 'Lois'; 'Lynnda Kahn'; 'mail=akpratts@acsalaska.net'; 'mail=fours@mtaonline.net'; 'Marilyn Crockett'; 'Mark Dalton'; 'Mark Hanley'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marguerite kremer'; 'Matt Rader'; Melanie Brown; 'Mike Bill'; 'Mike Mason'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'Nick W. Glover'; NSK Problem Well Supv; NSU, ADW Well Integrity Engineer; 'Patty Alfaro'; 'Paul Decker'; 'Paul Winslow'; Pierce, Sandra M (DNR); 'Randall Kanady'; 'Randy L. Skillern'; 'rcrotty'; Rice, Cody J (DNR); 'rmclean'; 'Rob McWhorter '; rob.g.dragnich@exxonmobil.com; 'Robert Campbell'; 'Robert Fowler'; 'Robert Province'; 'Roger Belman'; 'Rudy Brueggeman'; 'Scott Cranswick'; 'Shannon Donnelly'; 'Sharmaine Copeland'; 'Sondra Stewman'; 'Sonja Frankllin'; 'Stan Porhola'; 'stanekj'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'tablerk'; 'Tamera Sheffield'; 'Temple Davidson'; 'Terrie Hubble'; 'Tim Lawlor'; 'Todd Durkee'; Tony Hopfinger; 'trmjrl'; Von Gemmingen, Scott E (DOR); 'Walter Featherly'; 'Walter Quay'; 'Wayne Rancier'; Birnbaum, Alan J (LAW); Crisp, John H (DOA}; Davies, Stephen F (DOA); Fleckenstein, Robert J (DOA); Foerster, Catherine P (DOA); Grimaldi, Louis R (DOA); Johnson, Elaine M (DOA); Jones, Jeffery B (DOA); Laasch, Linda K (DOA); Mahnken, Christine R (DOA); Maunder, Thomas E (DOA); McIver, C (DOA); McMains, Stephen E (DOA); Noble, Robert C (DOA); Norman, John K (DOA); Okland, Howard D (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Saltmarsh, Arthur C (DOA); Scheve, Charles M (DOA); Seamount, Dan T (DOA); Smith, Chasity R (DOA); Williamson, Mary J (DOA) Attachm ents: dio32- l .pdf; Jody J. Colombie Special Assistant to the Commission Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 (907) 793-1221 Direct Line (907) 276-7542 Fax 12/11/2008 Mary Jones David McCaleb Cindi Walker XTO Energy, Inc. IHS Energy Group Tesoro Refining and Marketing Co. Cartography GEPS Supply & Distribution 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 300 Concord Plaza Drive Ft. Worth, TX 76102-6298 Houston, TX 77056 San Antonio, TX 78216 George Vaught, Jr. Jerry Hodgden Richard Neahring PO Box 13557 Hodgden Oil Company NRG Associates Denver, CO 80201-3557 408 18th Street President Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 Mark Wedman Schlumberger Ciri Halliburton Drilling and Measurements Land Department 6900 Arctic Blvd. 2525 Gambell Street #400 PO Box 93330 Anchorage, AK 99502 Anchorage, AK 99503 Anchorage, AK 99503 Baker Oil Tools Ivan Gillian Jill Schneider 4730 Business Park Blvd., #44 9649 Musket Bell Cr.#5 US Geological Survey Anchorage, AK 99503 Anchorage, AK 99507 4200 University Dr. Anchorage, AK 99508 Gordon Severson Jack Hakkila Darwin Waldsmith 3201 Westmar Cr. PO Box 190083 PO Box 39309 Anchorage, AK 99508-4336 Anchorage, AK 99519 Ninilchick, AK 99639 James Gibbs Kenai National Wildlife Refuge Penny Vadla PO Box 1597 Refuge Manager 399 West Riverview Avenue Soldotna, AK 99669 PO Box 2139 Soldotna, AK 99669-7714 Soldotna, AK 99669-2139 Richard Wagner Cliff Burglin Bernie Karl PO Box 60868 PO Box 70131 K&K Recycling Inc. Fairbanks, AK 99706 Fairbanks, AK 99707 PO Box 58055 Fairbanks, AK 99711 North Slope Borough PO Box 69 Barrow, AK 99723 %1~,/~ is /i~/~~ THE STATE °'ALASKA GOVERNOR SEAN PARNELL Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL DISPOSAL INJECTION ORDER NO.32.002 Mr. George Pollock Manager, Production Operations & Engineering Aurora Gas, LLC. 1400 W. Benson Blvd., Suite 410 Anchorage, AK 99503 Re: Request for administrative approval to allow well Aspen No. online in water only injection service with a known communication. Aspen Field Aspen Undefined Waste Disposal Pool Dear Mr. Pollock: 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 1 (PTD 2051110) to be inner annulus pressure By letter dated August 14, 2014, Aurora Gas, LLC (Aurora) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 8 of Disposal Injection Order (DIO) 32.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS Aurora's request for administrative approval to continue water only injection in the subject well. Aurora reported a potential Inner Annulus (IA) x Outer Annulus (OA) pressure communication to AOGCC when the well had an inconclusive Mechanical Integrity Tests 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 pressure drop off over the time period than allowed. The IA leak is thought to be in the upper perforations that had previously been squeezed with cement between 1,368 to 1,388 feet. The OA is cemented to approximately 220 feet from surface which is well within the 9 5/8" casing set at 693 feet. The 9 5/8" casing was cemented to surface with good returns observed. The 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. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. DIO 32.002 August 19, 2014 Page 2 of 2 AOGCC's approval to continue water injection only in Aspen No. 1 is conditioned upon the following: 1. Aurora shall record wellhead pressures and injection rate daily; 2. Aurora 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. Aurora shall perform a mechanical integrity test of the tubing (MITT) annually to 1700 psi; 4. Aurora shall limit the well's IA operating pressure to as low as possible and not to exceed 100 psi; 5. Aurora shall implement logic to shut down the Aspen No. 1 positive displacement pump at the IA set point of 100 psi, and to install a red strobe light to visually indicate when this condition occurs; 6. Aurora shall train personnel on the requirements of the 100 psi IA limitation including the requirement to manually shut down any triplex pumping operation on activation of the red strobe light. 7. Aurora shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 8. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 9. The MIT anniversary date will be set as the date of the AOGCC witnessed MITT that is to be completed once the well is returned to water only injection and stabilization is achieved. The Commission must be provided the opportunity to witness the MIT for a test to establish a new test due date. DONE at Anchorage, Alaska and dated August 19, 2014. Daniel T. Seamount, Jr. avid J. Mayberry Commissioner Commissioner RECONSIDERATION AND APPEAL 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 maybe 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. Com 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 Singh, Angela K (130A) From: Carlisle, Samantha J (DOA) Sent: Wednesday, August 20, 201410:07 AM To: Ballantine, Tab A (LAW); Bender, Makana K (DOA); Bettis, Patricia K (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha 1 (DOA); Colombie, Jody J (DOA); Crisp, John H (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Ferguson, Victoria L (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Hill, Johnnie W (DOA); Hunt, Jennifer L (DOA); Jackson, Jasper C (DOA); Jones, Jeffery B (DOA); Kair, Michael N (DOA); Mayberry, David J (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA); (michael j.nelson@conocophillips.com); AKDCWellIntegrityCoordinator, Alexander Bridge; Andrew Vandedack, Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Barron, William C (DNR); Bill Penrose; Bill Walker; Bob Shavelson; Brian Havelock; Burdick, John D (DNR); Cliff Posey; Colleen Miller, Corey Cruse; Crandall, Krissell; D Lawrence; Daryl J. Kleppin; Dave Harbour, Dave Matthews; David Boelens; David Duffy; David Goade; David House; David McCaleb; David Scott; David Steingreaber; David Tetta; Davide Simeone; ddonkel@cfl.rr.com; Dean Gallegos; Delbridge, Rena E (LAA); Donna Ambruz; Dowdy, Alicia G (DNR); Dudley Platt; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Francis S. Sommer, Frank Molli; Gary Schultz (gary.schultz@alaska.gov); George Pollock; ghammons; Gordon Pospisil; Gorney, David L.; Greg Duggin; Gregg Nady; gspfoff, Jacki Rose; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jerry McCutcheon; Jim White; Joe Lastufka; news@radiokenai.com; John Adams; Easton, John R (DNR); John Garing; Jon Goltz; Jones, Jeffrey L (GOV); Juanita Lovett; Judy Stanek; Houle, Julie (DNR); Julie Little; Kari Moriarty; Keith Wiles; Kelly Sperback; Klippmann; Gregersen, Laura S (DNR); Leslie Smith; Lisa Parker, Louisiana Cutler, Luke Keller, Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark P. Worcester; Mark Wedman; Kremer, Marguerite C (DNR); Michael Jacobs; Michael Moora; Mike Bill; mike@kbbi.org; Mikel Schultz; Mindy Lewis; MJ Loveland; mjnelson; mkm7200, Morones, Mark P (DNR); knelson@petroleumnews.com; Nichole Saunders; Nick W. Glover, Nikki Martin; NSK Problem Well Supv; Oliver Sternicki; Patty Alfaro; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Randy Redmond; Renan Yanish; Robert Brelsford; Ryan Tunseth; Sandra Haggard; Sara Leverette; Scott Griffith; Shannon Donnelly, Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Steve Kiorpes; Moothart, Steve R (DNR); Suzanne Gibson; sheffield@aoga.org; Tania Ramos; Ted Kramer, Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Thor Cutler, Tim Mayers; Tina Grovier; Todd Durkee; Tony Hopfinger; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Walter Featherly; yjrosen@ak.net; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater, Anne Hillman; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; David Lenig; Diane Richmond; Donna Vukich; Eric Lidji; Erik Opstad; Gary Orr, Smith, Graham 0 (PCO); Greg Mattson; Hans Schlegel; Heusser, Heather A (DNR); Holly Pearen; James Rodgers; Jason Bergerson; Jennifer Starck; jill.a.mcleod@conocophillips.com; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Kenneth Luckey, King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Matt Gill; Franger, James M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Peter Contreras; Richard Garrard; Richard Nehring; Robert Province; Ryan Daniel; Sandra Lemke; Pexton, Scott R (DNR); Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Terence Dalton; Todd, To: Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster, Wendy Wollf, William Hutto; William Van Dyke Subject: Disposal Injection Order 32.002 (Aspen Field) Attachments: dio32-002.pdf Please see attached. Samantha CarlisCe Executive Secretary II Alaska Oil and Gas Conservation Commission 333 West 71h Avenue, Suite 100 Anchorage, AK 99501 (907) 793-1223 (phone) (907) 276-7542 (fax) 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 Samantha Carlisle at (907) 793-1223 or Samantha.Carlisle@alaska.gov. CIRI Land Department James Gibbs Jack Hakkila Post Office Box 93330 Post Office Box 1597 Post Office Box 190083 Anchorage, AK 99503 Soldotna, AK 99669 Anchorage, AK 99519 Bernie Karl K&K Recycling Inc. Gordon Severson Penny Vadla 55 580 Post Office Box 3201 Westmar Cir. 399 W. Riverview Ave. Fairbanks, AK 580 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 George Vaught, Jr. Richard Wagner Darwin Waldsmith Post Office Box 13557 Post Office Box 60868 Post Office Box 39309 Denver, CO 80201-3557 Fairbanks, AK 99706 Ninilchik, AK 99639 Mr. George Pollock Manager, Production Operations & Engineering Aurora Gas, LLC. 1400 W. Benson Blvd., Ste. 410 Anchorage, AK 99503 4"v d S0%-L' 20 i "k a", CL---�s-il� Angela K. Singh. THE STATE °fALASKA GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL DISPOSAL INJECTION ORDER NO. 32.003 Mr. George Pollock Gryphon Resources, LLC 3743 Richard Evelyn Byrd Anchorage, AK 99517 333 west Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907,279,1433 Fax. 907.276.7542 www.aogcc.olaska.gov Re: Docket Number: DIO-18-002 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 letter dated September 10, 2018, Plugging Inlet, LLC (Plugging Inlet), as operator of the Aspen field since August 13, 2018, requested administrative approval for 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, commercial disposal, water only injection in the subject well. In August 2014, AOGCC determined that water disposal could safely continue if Aurora complied with the restrictive conditions set out in AA AIO 32.002. 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 32.002 required Aurora to complete annual MIT tubing (MITT) testing. The last passing state -witnessed MITT was September 29, 2016. Aspen 1 must pass an MITT prior to DIO 32.003 September 20, 2018 Page 2 of 3 recommencing disposal operations to demonstrate that its overall integrity remains intact and does not threaten human safety or the environment. The multiple operators now associated with various well P&A operations 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 1. AOGCC's approval to continue water injection only (produced water, brine, 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 perform a mechanical integrity test of the tubing (MITT) to 1700 psi prior to recommencing disposal operations; 4. Plugging Inlet shall limit the well's IA operating pressure to as low as possible, not to exceed 100 psi; 5. 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; 6. 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; 7. Plugging Inlet shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 8. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; 9. 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 and requirements to P&A legacy Aurora wells are authorized including the wells Aspen 1, Lone Creek 1, 3 and 4, Kaloa 2, Moquawkie 1, 3, and 4, Simpco Moquawkie 1 and 2, Nicolai Creek 10, 11, and 129, and Three Mile Creek 2; 10. Plugging Inlet shall train personnel prior to restarting Aspen 1 operations. Training shall include the requirements for manifesting and correct volume accounting of wastes; 1.1. 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, transport company and driver, signature and name of Plugging Inlet person with authority confirming waste as Class II; DIO 32.003 September 20, 2018 Page 3 of 3 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. 12. This administrative approval shall expire whichever occurs first: a. January 1, 2019; b. Aspen 1 is Plugged and Abandoned; or c. the operator changes for the Aspen 1 well. DONE at Anchorage, Alaska and dated September 20, 2018. Cathy Foofster Daniel T. Sean Com Issioner Commissioner cc: Jim Sullivan Plugging Inlet, LLC 6733 South Yale Avenue Tulsa, OK 74136 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 Sled 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. 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 www. a ogcc.o laska.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 1. 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 I, 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 I 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, DIO 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 1 is Plugged and Abandoned; or c. the operator changes for the Aspen 1 well. DONE at Anchorage, Alaska and dated May 1,, 2/n019. C�� Daniel T. S amount, Jr. =ielowski Commissioner Commissioner cc: Jim Sullivan Plugging Inlet, LLC 6733 South Yale Avenue Tulsa, OK 74136 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. TILL STATE " Alaska Oil and Gas ALASKA Conservation Commission f10VERNPR MIt. H.{CI I. 11UNI LAVI' 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 ADMINISTRATIVE APPROVAL Fax: 907.276.7542 DISPOSAL INJECTION ORDER NO. 32.004 ww .aogcc.alaska.gov Mr. George Pollock Consultant to Plugging Inlet, LLC PO Box 90571 Anchorage, AK 99509 Re: Docket Number: DIO-19-001 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 AID 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 1. 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, DIO 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 1 is Plugged and Abandoned; or c. the operator changes for the Aspen 1 well. DONE at Anchorage, Alaska and dated May 1, 2019. //signature on file// Daniel T. Seamount, Jr. Commissioner //signature on file// Jessie L. Chmielowski Commissioner cc: Jim Sullivan Plugging Inlet, LLC 6733 South Yale Avenue Tulsa, OK 74136 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. Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Penny Vadla 399 W. Riverview Ave. Soldotna, AK 99669-7714 George Vaught, Jr. Darwin Waldsmith Richard Wagner P.O. Box 13557 P.O. Box 39309 P.O. Box 60868 Denver, CO 80201-3557 Ninilchik, AK 99639 Fairbanks, AK 99706 22 THE STATE June 2, 2019 °fALASKA GOVERNOR MIKE DUNLEAVY Mr. G. Scott Pfoff President Amaroq Resources, LLC. 4665 Sweetwater Blvd, Suite 103 Sugar Land, Texas 77479 Ms. Susanne Settle Senior Vice President, Energy and Infrastructure Cook Inlet Regional Corporation 725 East Fireweed Lane, Suite 800 Anchorage, Alaska 99503 Mr. Edward Jones Plugging Inlet, LLC 6733 South Yale Avenue Tulsa, OK 74136 Alaska Oil and Gas Conservation Commission 333 west Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 wv w.aogcc.oloska.gov Re: Docket Number: DIO-19-001 Request to modify Disposal Injection Order (DIO) 32.004 to allow Amaroq Resources, LLC (Amaroq) to dispose of produced fluids into Aspen No. 1 (PTD 2051110) Aspen Field operated by Plugging Inlet, LLC (Plugging Inlet) Aspen Undefined Waste Disposal Pool Dear Mr. Pfoff, Ms. Settle and Mr. Jones: By letter dated May 22, 2019, Amaroq Resources, LLC (Amaroq) requested reconsideration and modification of administrative approval (AA) Disposal Injection Order (DIO) 32.004. In accordance with Rule 8 of DIO 32.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby DENIES Amaroq's request to modify the AA to allow Amaroq to dispose of fluids unassociated with the Aurora Gas, LLC (Aurora) wells requiring plugging and abandonment (P&A). DIO 32.004, issued May 1, 2019, as an extension of lapsed DIO 32.003, authorized specific limited -duration commercial disposal operations in well Aspen No. 1 to dispose of remaining wastes which had been generated by Aurora as well as wastes associated with the requirements to P&A Aurora's legacy wells. Plugging Inlet's request did not seek authorization for commercial disposal of Amaroq wastes, specifically noted that DIO 32.003 had been "written to allow all legacy Class II fluids generated by the former Aurora Gas to be injected," and stated that produced fluids from wells operated by Amaroq were not within the ambit of Plugging Inlet's request. As a result, Condition 8 of DIO 32.004 specifically precludes the disposal of wastes from Nicolai Creek wells. I Docket No: DIO-19-001 June 2, 2019 Page 2 of 2 Because commercial disposal of Amaroq fluids was specifically excluded from Plugging Inlet's request, Amaroq's request for reconsideration does not comply with AOGCC's regulations governing disposal injection order applications. The commercial agreement between Aurora and CIRI does not vitiate AOGCC's regulatory requirements for a DIO. A DIO application must originate from the operator of the disposal well, and neither CIRI nor Amaroq is the operator of Aspen No. 1. Although the request for reconsideration is denied, AOGCC is aware that Plugging Inlet will need a water supply for its P&A operations (cement mixing, etc.) and disposal well flushing requirements. Plugging Inlet has indicated an interest in beneficially re -using some of the produced water available from Amarok's operation of the Nicolai Creek wells. Such use is permitted for that specific purpose. However, injection of produced water disposal into Aspen No. 1 for any other purpose than an associated P&A or well flushing benefit is prohibited. The importance of Aspen 1 disposal availability to the P&A campaign is such that it is not prudent to put the well at greater risk by injecting non -beneficial fluids. If disposal operations beyond the scope of those authorized by DIO 32.004 are desired, Amaroq or Plugging Inlet must submit an application compliant with 20 AAC 25.252 and AOGCC will hold a hearing. AOGCC notes that expansion of disposal operations other than those permitted within DIO 32.004 would require the operator to demonstrate the mechanical integrity of Aspen No. 1 as required by 20AAC 25.412. DONE at Anchorage, Alaska and dated June 2, 2019. 4_0e . XV dL_,_ Daniel T. Seamount, Jr. Jessielowski Commissioner Commissioner APPEAL NOTICE This order or decision is 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. 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. 21 Colombie, Jody J (CED) From: Scott Pfoff <gspfoff@aurorapower.com> Sent: Wednesday, May 22, 2019 11:30 AM To: Wallace, Chris D (CED) Cc: Colombie, Jody J (CED); Ed Jones; George Pollock, Colleen Miller Subject: Re: [AOGCC_Public_Notices) DIO 32-004 Attachments: 2019-05-21 - Amaroq_AOGCC support letter_executed[1].pdf Importance: High Chris, Amaroq Resources, LLC requests the AOGCC reconsider the portion of this order that precludes the injection of water produced at Nicolai Creek Unit. Amaroq, as successor to Aurora Gas, LLC operations at Nicolai acquired the rights associated with a commercial agreement between Cook Inlet Region, Inc. and Aurora Gas to dispose of produced water at Aspen SWD. We met with representatives of CIRI and they do not object to Amaroq's continued disposal of water into the Aspen SWD until such time as the well is plugged (please see attached correspondence). We do not propose any delay in the proper plugging, we simply want to use the well as long as it remains in operation. We understand AOGCC's concern with regard to unauthorized waste. We are willing to subject ourselves to extensive monitoring to ensure this does not occur from Amaroq's activities. As a result of the short timeline involved, we would appreciate expedited consideration of this request. �7 Amaroq Resources, LLC G. Scott Pfoff, President 4665 Sweetwater Blvd., Suite 103 Sugar Land, Texas 77479 (832) 9994603 — direct (713) 816-6870 — mobile From: Jody Colombie <]ody.colombie@alaska.aov> Date: Friday, May 3, 2019 at 1:14 PM To: AOGCC—Public—Notices <AOGCC Public Notices@ list.state.ak.us> Subject: [AOGCC—Public—Notices] DIO 32-004 Re: Docket Number: DIO-19-001 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 Jody J. Colombie Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7" Avenue Anchorage, AK 99501 (907) 793-1221 Direct (90 7) 2 76- 7542 Fax List Name: AOGCC Public Notices@ list.state.ak.us You subscribed as: gspfoff@aurorapower.com Unsubscribe at: http://list.state.ak.us/mailman/options/aogcc public notices/gspfoff%40aurorapower.com zo May 21, 2019 Jessie Chmielowski, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Dear Chairperson Chmielowski: Re: Amaroq, Nicolai Creek, Aspen well Amaroq Resources, LLC (Amaroq) has requested authorization to inject produced water from its Nicolai Creek wells into the Aspen No. 1 until such time as the well has been properly plugged and abandoned. The injection of produced water from these wells has been explicitly denied under Disposal Injection Order 32.004 (DID 32.004). Amaroq acquired the Nicolai Creek assets through the Aurora Gas, LLC (Aurora) bankruptcy estate. Through the acquisition, Amaroq became the successor to a certain commercial agreement between CIRI and Aurora. The agreement authorizes disposal of Class II Materials from state leases ADL 17598 and ADL 391472 (State Leases) to be injected into the Aspen No. 1 well in exchange for certain considerations. Amaroq has continued to meet the obligations under that certain agreement and therefore, CIRI does not object to the injection of produced water from the specified State Leases into the Aspen No. 1 well until the extension period of October 1, 2019 or until such time as the well is plugged and abandoned, subject to the following: 1. Amaroq only injects produced water that conforms to the requirements under DOI 32.004 including, but not limited to, pressure, rate and fluid restrictions and limitations, and timely complies with all other reporting or testing obligations required by the Alaska Oil and Gas Commission (AOGCC). 2. Immediately upon the direction of either Plugging Inlet, LLC or the AOGCC, Amaroq agrees to cease all injections and vacate the premises, including removal of all Amaroq equipment. 3. Amaroq coordinates and schedules injections with Plugging Inlet, LLC or its designated representative in a manner satisfactory to Plugging Inlet, LLC. 4. Amaroq will report to CIRI and Plugging Inlet, LLC the aggregate amount of produced water that it injects on a weekly basis. Sincerely, COOK INLET REGION, INC. Suzanne Settle Senior Vice President, Energy and Infrastructure cc: Edward Jones, Plugging Inlet, LLC George Pollock, Plugging Inlet, LLC Scott Pfoff, Amaroq Resources, LLC 19 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, D(o'(1-00( 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 NCI, NC2 and NC9 are located. The Nicolai Creek wells (which include: NCI, 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 #1, 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 Jones 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 V, 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`h 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 at 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.wallace@alaska.gov> Cc: Colleen Miller <cmiller@ciri.com>; Ed Jones <jejones@aurorapower.com> 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 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 01ALASKA Go\ ER oIt MIKE DL'NLEA\'Y 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 I (WDSPL) (PTD 205-111) Simpco Moquawkie I (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') (PTD 205-080) Moquawkie 4 (PTD 207-084) Dear Mr. Pollock: Alaska Oil and Gas Conservation Commission 333 west Se,enth. Avenue Anchorage Alosko 99501-3572 Main: 907.279.1433 Fax 907.2?67542 -"�Iogcc.olaj a,Jc+ 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-18-033 December 12, 2018 Page 2 of 2 TION AND As provided in AS 31.05.080(x), 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 pan within 10 days after it is tiled. 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 he appealed to superior court. The appeal M UST be tiled within 33 days after the date on which the AOGCC mails. OR 30 days if the AOGCC otherwise distributes. the order or decision denving reconsideration. UNLESS the denial is by inaction, in which case the appeal MUST be tiled 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 nest day that does not fall on a weekend or state holiday_ Se ptember 1U, 211121 Mr. Hollis French SEP t G U Chair Commissioner .� Alaska Oil and Gas Conservation Commission AOGCC 333 West Seventh Avenue Anchorage, AK 99501 Ke: Kequest for Administrative Approval to allow limited duration commercial disposal operations in the Aspen 1 well to dispose of wastes associated with the bankruptcy of Aurora Gas, LLC and. requirements to P&A legacy Aurora Gas, L ILC well Dear Mr. French: 1'luggrng Inlet, ik (Ylugging lnlet) is the current operator of the Aspen -No. 1 Class II disposal well (Aspen 1). The requested operatorship of Aspen 1 will be for a defined period of time terminating with either the plugging and abandonment (P&A) of the Aspen I wall or until January 1, 2019. Plugging Inlet proposes to inject approved Class II fluids, produced water and brine, generated by the legacy Aurora Gas, LLC (Aurora) wells. The Alaska Oil and Gas Conservation Commission (AOGCO issued Uisposal injection Order (DTO) 32 on February -7, 2008 authorizing the underground disposal of Class II oil field waste into the Beluga Formation through the Aspen I well bore. Aurora has operated Aspen 1 since that time and the well is located in Section 33, T12N, R11 W, Seward Meridian (SM) on the west side of Cook Inlet, Alaska. Background: in June of 2W6, Aurora entered Chapter 11-barikruptcy proceedings. Under Chapter 11, Aurora continued to operate multiple gas fields located on the west side of Cook Inlet, some of which were on State of Alaska mineral leases (Nicoiai Creek and Three Mile Creek) and some of which were on Cook Inlet Region Incorporated (GIRT) mineral leases (Moquawkie, Albert Kaloa and Lone Creek). Aspen 1 accepted produced water from all gas fields operated by Aurora until July of _2U17/. At this time a prospective buyer for the Nicolai Creek field was identified, however the wells on the remaining gas fields appeared to be headed towards conversion to Chapter 7. As a precondition to the conversion, the bankruptcy court required temporary plugs be installed in the remaining gas wells operated by Aurora. At this time, the Aspen 1 well was identified as having significant value for two reasons. First, when the temporary plugs were run the gas wells on the Moquawkie, Kaloa, Lone Creek and Three Mile Creek gas fields, the produced water from theses wells was not injected and remains in the tanks located on-site. Secondly, the installation of the temporary plugs did not remove the requirement to plug and abandon (P&A) the twelve wells. A quantity of cement rinsate water will be generated in the P&A .process that will need to be disposed of properly. On -September 14, ZUI /, an Order 'Gran ring -Motions (l) uo Reject and Lerminate Surface Use Agreement and Mineral Leases Pursuant To "1"1 USC 365 (a) and (2) To Transfer Aspen Disposal Well Subsurface Lease was filed. This order effectively set the stage for the conversion to Chapter 7 whale allowing the option for the Aspen l well to be used to inject water produced while the wells were operated by Aurora and cement rinsate water generated while the wells are P&A'ed. In early 10116, six Nicolai Creek gas wells and associated facilities were sold out of Chapter 11 bankruptcy and all other assets of Aurora were converted to Chapter -7 bankruptcy. Plugging Inlet is the entity that has been established by a prior owner of Aurora to address legacy P&A and disassembly, removal and restoration (DR&R) obligations for the wells and facilities located on CIRI mineral leases. Plugging Inlet is the operator of record for the I'&1 of the nine former gas producing wells and Aspen I which are located on CIRI mineral leases. Sundry approvals to P&A 10 wells have recently been issued by AOGCC and the work is slated to begin in the near future. Amaroq Resources, LLC (Amaroq) is the current operator of the Nicolai Creek wells and associated facilities that were sold out of the Aurora bankruptcy. Nicolai Creek represents the only assets of the former Aurora that remain in production. Discussions are currently under way to Y&A the -three Mile Creek wells in conjunction with the other legacy Aurora wells this fall. This activity may be performed with Glacier ;Oil & Gas Corp (Glacier) as operator. Glacier was a 30% working interest owner in the Three Mile Cmeek field. Aspen 1 Current Condition: The Aspen I well is currently shutm at the wellhead. The tubing_ pressure is currently 100 psi and the inner annulus pressure is 0 psi. The Aspen I disposal well accepts approved Class II' fluids from all natural gas producing fields operated by Aurora Gas, LLC in accordance with two administrative approvals issued under DIO 32. On December 11, 2008, Administrative Approval DIO 32.001 was approved allowing for the injection of -freeze .protect -fluids including methanol and tiiethylene glycol. 1^ollowing a failed mechanical integrity test (vIIT) of Aspen 1 in July of 2014, DIC) 32.002 granted administrative approval to continue fluid only injection. The well is not in good mechanical condition. The above noted inner annulus (IA) to outer annulus (OA) pressure communication prevents the well from passing the MIT. The source of the IA pressure leakage is suspected to be a set of upper perforations that had previously been squeezed with cement between I368' to 198'. In the DIC) 32.002. discussion, AOGCC agreed that normal injection operations where the tubing is isolated from the IA ensuring that ir4ected fluid is not entering the foxmexly squeezed pexfoxations axe permed. The aequaaemaew of an annual r -M-11 11 Tubing to verity fluids are only injected only into.pexrnitted zones is required. The annual MIT Tubing will be performed to 1700 .psi, disposal injection is limited to 1500 psi, inner annulus :operating pressure is limited to 100 psi and monthly monitoring. Class II Fluid To Be Injected: Legacy Class Tl fluids consisting of produced water and -brine tiom the welts formerly operated by Aurora are presented in the following table. Operatos Well. Quantity BB.I. Plugging Inlet Aspen 1 534 Lone Creek 1 160 Lone Creek 3 13 Lone Creek 4 7 t<aloa 2 173 Mo uawkie 1 122 Moguawkie 4 36 Sim co Mo uawkie 2 5 Subtotal 1050 Amaron I Nicolai Creek 129 3.01 Nicolai Creek 11 29 Nicolai Creek 10 844 Subtotal 1174 Glacier Tbree Mike Creek 2 12 Subtotal 12 TOTAL 2236 Note, of the 11 74 barrels of fluids currentlyintanks at the Nicolar Creek field, 36/ barrels have been generated by the currently operator, Amaroq. Some of this produced water/brine has been identified for beneficial reuse as make up water for cement to be used to P&A the wells. Proposed Aspen 1 Operations: Upon approval of this request prior to the injection of any fluids, M—u tubing will be performed to 1700 psi. AOGCC will be notified at least 48 hours in advance of the test to allow an inspector to witness. Upon successful completion the MIT Tubing, Aspen 1 will be operational. Disposal injection will be limited r to pressure not to exceed 1500 psi and the inner annulus will be monitored and operations shut down if greater than 100 psi is observed. Unly produced water and -brine will -be -injected into As 1. t mullion and produced solids will be segregated and stored in separate containers for disposal at the appropriate facility. In addition to the quantity of fluids in the table above, cement rinsate water generated during the P&A of the former Aurora wells will be injected. the requested -limited duration of operations may be construed to meet the requirements of commercial disposal operations as fluids from more than a single operator will be accepted. In accordance with accepted methodologies for commercial operations, Plugging Inlet will provide additional information to AOGCC to ensure Class Il fluids eligibility verification, pressure monitoring and volume accounting. Plugging Inlet will implement an enhanced custody and manifest system for the transport of the fluids in the table above and cement rinsate water. A dedicated field logistics person will be accountable for determining that each load arriving at the Aspen fwAty,meets the amepnence and ehgiljility mquimments. In the event a non - manifested load arrives, an isolated holding tank will be utilized to segregate the fluid until verification and manifest can be generated, or the load will be rejected. These steps will ensure eligibility of the fluids to be injected. All held,personnel employed to inject Hinds at Aspen have been selected based on their experience performing the task historically for Aurora. This included Tyonek Contractors personnel that transport the fluids in their vac truck as well as personnel that will operate the inject purnp at Aspen. At the beginning of operations, all personnel will be given a site-specific briefing on the required volume and pressure monitoring requirements. Sign in sheets for this briefing will be completed and retained for documentation purposes. Please -tee! -tree to contact me if you have any questions or require any additional information regarding this request. Respec Suba , i v eorge Pollock Consultant,Tlugging inlet, LLC #17 Aurora Gas, LLC August 14, 2014 AUG 18 2014 Mr. Chris Wallace Petroleum Engineer /'A1 W Alaska Oil & Gas Conservation Commission 333 West 7 h Avenue, Suite 100 Anchorage, AK 99501 Re: Request for Administrative Approval — Operational Variance Aspen No. 1 Well — Disposal Injection Order No. 32 Dear Mr. Wallace: Aurora Gas, LLC (Aurora) requests the Alaska Oil and Gas Conservation Commission (AOGCC) grant Administrative Approval for an Operational Variance of the Aspen No. I well (Aspen) under Disposal Injection Order No. 32 (DIO) dated February 7, 2008. This variance is requested to allow for continued operation of Aspen until such time that a viable long-term corrective action is identified, approved by AOGCC and implemented through a drilling rig work over by Aurora. On July 28, 2014 Aurora performed a Mechanical Integrity Test (MIT) with AOGCC personnel present to witness the test. This test was a repeat of the May 30, 2014 test that was not witnessed by AOGCC and deemed to be inconclusive. The test was repeated twice on July 28`" with an initial pressure of 1,710 psi for both runs. During the 30 minute tests, the pressure leaked off 280 and 350 psi, which corresponds to a pressure loss of 16% and 20%, respectively. Aspen is a critical infrastructure component utilized throughout the year as an intermittent injection well to manage produced water in a safe and environmentally sustainable manner that is protective of source drinking water. A freshwater exemption is not required for Aspen due to the total dissolved solids measured in the formation waters exceeds 10,000 parts per million in the target injection zone. Aurora proposes to implement a program of engineering controls and mitigation measures to ensure the safe and environmentally sustainable operation of Aspen throughout the time period the Operational Variance is in effect. The proposed measures are as follows: 1. Monitoring of annulus pressure, 2. Pressure initiated shutdown of injection pumps, and 3. Annual tubing integrity testing. 4645 Sweetwater Boulevard, Suite 200 * Sugarland, TX 77479 * (832) 939-8991 1400 W Benson Blvd, Suite 410 * Anchorage, AK 99503 * (907) 277-1003 These measures will be presented in greater detail in following sections of this letter. This letter will also present the current configuration and condition of Aspen, an operational overview of Aspen and related facilities and a discussion of the impacts of the proposed Operational Variance on the findings and rules of the DIO. Current Configuration and Condition: Aspen No. 1 Aspen was drilled as vertical, exploratory gas well (PTD 205-111) in the summer of 2005 to evaluate the commercial potential of the Beluga sands. The well consists of a 13 3/8- inch conductor driven to refusal at 83-feet (all depths referenced are based on a rotary kelly bushing elevation of 16-feet). A 12 1/4-inch surface hole was drilled to 700-feet; in which 693-feet of 9 5/8-inch, 53.5#, J-55 surface casing was run and cemented with 50 barrels (bbl) of 14 pound per gallon (ppg) lead and 30 bbl of 14.5 ppg class-G cement. Cement returns were to surface and verified by weight and pH. A 7 7/8-inch intermediate hole was drilled to 4,485-feet; in which 4,485-feet of 5 1/2-inch, 15.54, J-55 BTC casing was run and cemented with 41 bbl of 13.5 ppg lead and 136 bbl of 15.8 tail slurry. Top of cement was observed at 220-feet in the cement bond log, which indicated good cement quality. A total of nine (9) intervals were perforated and tested, refer to the enclosed Aspen Well Bore Diagram. After testing the well, it was suspended. A cement retainer was set at 2,955-feet and 10 sacks of class-G cement were pumped on top. This cement plug was tagged at 2,891-feet and pressure tested. This plug isolated the bottom five perforations. A cast iron bridge plug was set at 1,779-feet. A cement retainer was set at 1,714-feet and the perforated interval from 1,760- to 1,770-feet was squeezed with 8 sacks of class-G cement. A balanced plug was then placed across the perforations from 1,368- to 1,388-feet with 19 sacks of class-G cement. The top of the plug was tagged at 1,260-feet. At that time, a surface plug was not set as the well was being evaluated for use as an injection well. In the summer of 2008, Aurora re-entered and converted Aspen to a Class II disposal well under AOGCC Sundry Approval 307-172. The cement plugs were drilled out and a retrievable packer was used to test the integrity of the perforated intervals behind cement. The perforations behind the balance plug from 1,368- to 1,388-feet were pressured up to 1,500 psi and leaked off 120 psi in 30 minutes, whereas the squeezed perforations from 1,760- to 1,770-feet were pressured up to 1,700 psi and leaked off 20 psi in 30 minutes. A second cement squeeze was performed on the 1,368- to 1,388-feet interval by setting a retrievable bridge plug at 1,440-feet and a retrievable packer at 1,288-feet and pumping 50 sacks Type I cement with gas block. After the second squeeze, the perforated interval from 1,368- to 1,388-feet was pressured up to 1,500 psi and leaked off 50 psi in 30 minutes. The remaining cement was drilled out, the bridge plug milled and the casing circulated clean. The completion was then run on 2 7/8-inch, 6.5#, 8 round, EUE, J-55 tubing as shown on the attached Well Bore Diagram. A retrievable packer was set at 1,995-feet with an on/off tool (2.312-inch profile) above; and two 6-feet pup joints, an XN nipple (2.312-inch profile and 2.205-inch no-go), and a wireline entry guide below. A plug was set in the XN nipple at 2,014-feet and the tubing pressure tested to 2,500 psi for 30 minutes. At this point in time, two perforated intervals, 2,125- to 2,145-feet and 2,351- to 2,371- feet, were open the Beluga formation. A baseline temperature survey and an injectivity test were performed. The post injectivity test temperature survey indicated that all the injected fluid went into the upper perforated interval from 2,125- to 2,145-feet with no apparent channeling observed. After the successful injectivity test, the completion was set. First, 8.9 ppg brine with corrosion inhibitor was reverse circulated in the annulus between the tubing and the casing above the packer. The packer was spaced out and set at 2,010-feet. The tubing was landed in the tubing hanger and a back pressure valve was set in the hanger. The annulus was pressure tested to 1,500 psi followed by a pressure test of the injection tree to 1,500 psi. The well was then ready for service. Aspen Operational Overview Aspen functions primarily as an intermittent produced water injection well, however it is permitted to accept other oil field waste materials such as drilling, completion and workover fluids; rig wash; mud slurries; and other Class II fluids and solids. In the standard operational mode, produced water is trucked to Aspen and transferred into an open top sand removal tank. This 400 bbl tank has multiple internal baffles and screens to remove solids. The screened produced water is transferred to a 150 bbl holding tank. Two, table -mounted positive displacement pumps connected in parallel are used to inject the produced water. Each pump has a maximum rate of 0.14 bbl per minute (6 gallons per minute) at a maximum pressure of 1,100 psi. A master totalizing flow meter records the injection volume, rate and pressure. The pumps can only be manually started at the facility and are locally controlled through a low and high pressure shutdown as well as a low level in the produced water holding tank. There is no remote control capability through Aurora's SCADA system. Additional local controls include shutdown of the transfer pump based on a low level from the sand tank or a high level from the produced water holding tank. In the event larger volumes of produced water or drilling muds or slurries are to be injected, a triplex pump can be connected upstream of the master totalizing flow meter. An array of 500 bbl tanks can be used to store the fluids. Solids can be removed by running the drilling fluids over shaker screens. The solids can be ground to in a ball mill and suspended in slurry for injection. The triplex pump has a maximum rate of 1.0 bbl per minute and a high pressure shutdown set at of 1,300 psi. Operation of the triplex pump is completely manual with no remote monitoring capability. Proposed Engineering Controls & Mitigation Measures Based on the detailed history of the Aspen well and the observations during the recent failed MIT, the evidence strongly suggests that the cement squeezed perforations from 1,368- to 1,388-feet and from 1,760- to 1,770-feet have failed. The failure is allowing pressure to leak off greater than the percentage specified in the DIO. However, the cement squeezed perforations continue to provide a barrier to the migration of annular fluids. Historically, Aurora has not observed any recordable pressure on annulus during injection using either the positive displacement or the triplex pumps. Aurora proposes to implement the following engineering controls and mitigation measures to ensure the safe and environmentally sustainable operation of Aspen until such time a rig work over can address the casing integrity. 1. Monitoring of annulus pressure, 2. Pressure initiated shutdown of injection pumps, and 3. Annual tubing integrity testing. Aurora will install a pressure transducer and monitor and record the real-time annulus pressure. For standard operating conditions, a pressure initiated shutdown of the positive displacement pumps will be established. In the event the annular pressure exceeds 100 psi, the positive displacement pumps will be automatically shut down and a red strobe will be activated as a visual indicator. If the triplex pump is in manually operated on the pad, the red strobe will indicate a pressure exceedance and trigger the operator to manually shut down pumping operations. Aurora will also conduct an integrity test of the tubing on an annual basis. The proposed testing regime will consist of pressure the tubing to 1,700 psi and observe the leak off over a 30 minute interval. Impacts of Operational Variance The impacts of the above measures will be evaluated in terms findings and rules adopted in the DIO. Finding 1 — Location of Well No change. Finding 2 - Notification of Operators/Surface Owners Tyonek Native Corporation is the sole surface owner and Cook Inlet Region Incorporated is the sole subsurface owner within a one -quarter mile radius of Aspen. Both parties have been notified regarding this request. Finding 3 — Geologic Information on Disposal and ConfiningZones ones The two perforated zones currently permitted for Class II disposal injection receive all fluids injected. Finding 4=Aspen Logs No change. Finding 5 - Aspen Casing Description No change. Finding 6 — Demonstration of Mechanical Integrity and Disposal Zone Isolation During operation of Aspen, the integrity of the tubing and packer provide for the isolation of the disposal zone. At no time in the past has pressure been observed on the annulus during injection. The proposed engineering controls and mitigation measures will ensure fluids injected for disposal only go into the perforations from 2,125- to 2,145-feet and from 2,351- to 2,371-feet. Finding 7 — Disposal Fluid Type Source Volume and Compatibility with Disposal Zone No change. Finding 8 — Estimated Infection Pressure No change. Finding 9 — Evaluation of Confining Zone No change. Finding 10 — Standard Laboratory Water Analysis of Disposal Zone No change. Finding 11 — Freshwater Exemption No change. Finding 12 — Mechanical Condition of Wells Penetrating the Disposal Zone Within'/4 Mile of Aspen No change. Rule 1— Injection Strata for Disposal All fluids injected are confined within the interval from 2,125- to 2,371-feet. Rule 2 — Fluids No change. Rule 3 — Infection Rates and Pressures No change. Rule 4 — Demonstration of Mechanical Integrity Aurora has complied with this rule by properly communicating the results of the failed MIT. Rule 5 — Well Integrity Failure and Confinement Upon failure of the MIT, Aurora notified AOGCC and received verbal authorization to continue normal injection operations while this document was prepared for submission. The engineering controls and mitigation measures presented herein have been developed to ensure Aspen can operate in a safe and environmentally sustainable manner protective of source drinking water. Aurora is currently identifying long-term corrective actions for the breakdown of the squeeze perforations. An AOGCC Form 10-403 will be submitted for approval that will present to the finalized corrective action plan. A monthly report presenting the daily tubing pressure, casing annulus pressure and the injection rate has been prepared and is enclosed with this request. Rule 6 — Surveillance The annual surveillance report is in preparation and will be submitted in the near future. Rule 7 — Notification of Improper Injection No change. . Rule 8 — Administrative Action It is the express intent of this request to obtain authorization through administrative action for the continued operation of Aspen until a rig work over can be completed. Rule 9 — Conditions No change. Let me know if you require any further information to process this request. Sincerely, George Pollock Manager, Production Operations & Engineering cc: Ms. Colleen Miller — CIRI Ms. Connie Downing — TNC Enclosures: Aspen Well Bore Diagram Aspen Monthly Report — July 2014 1 Aurora Gas, LLC Aspen No. 1 Water Disposal Well Final Configuration API# 50-283-20114-00 PTD# 205-111 RKB —14.6' Sept. 2008 FIT performed at 720' , Had 14.8 ppg MWE test prior to breakdown. Perforations: 1368' —1388' Squeezed Off Perforations: 1760' -1770' Squeezed Off Perforations: 2125' - 2145' Perforations: 2351' — 2371' Perforations: 2984' - 2994' Perforations: 3006' — 3026' Perforations: 3444' — 3454' Perforations: 3491' — 3506' Perforations: 381 V — 3831' PBTD 4355' Drilled 7 5/8" Hole to 4485' 7/8 6S# 8rd EUE J-55 Tubing 13-3/8". 54.5#, J-55 Structural Conductor to be driven to 83' GL or 97' KB 5/8" 36# Surface Casing set at 693' .ement w/ 50 bbis 14 ppg lead and 30 bis 14.5 ppg Gas -Block "G" w/ good eturns observed at surface. squeezed perfs at 1368-1388' w/ sx (13 bbis) Type I cement w/ ditives on 8/26/08. sted tbg-csg annulus several ies subsequently. Tested on >.9/08 to 1500 psi —bled to 1450 30 min, trievable Packer set at 2010 ft w/ i-Off tool above and w/ 12' spacer ps, XN landing nipple and WEG tubing tail. 10 sx balanced cement plug placed on top of retainer—TOC at 2891'. PBTD now at 2881' (CIBP U 1779' pushed down to there) Retainer set at 2955' 5# J-55 Casing to 4484' MD (TVD) 40.6 bbls 13.5 ppg lead cmt and 136 bbis 15.8 ppg tail cement. Aurora Gas, L L C Aspen No.1 Monthly Report —July 2014 Date Tubing Pressure (psi) Casing Pressure (psi) Injection Rate (bpm) Total Injected (bbl) Static Injecting 1 300 - 0 - 0 2 298 - 0 - 0 3 297 - 0 - 0 4 296 - 0 - 0 5 295 - 0 - 0 6 294 - 0 - 0 7 293 - 0 - 0 8 292 - 0 - 0 9 291 - 0 - 0 10 290 - 0 - 0 11 289 - 0 - 0 12 288 - 0 - 0 13 287 - 0 - 0 14 286 - 0 - 0 15 286 - 0 - 0 16 285 - 0 - 0 17 284 612 0 0.15 117 18 451 681 0 0.15 159 19 378 - 0 - 0 20 347 643 0 0.15 94 21 488 711 0 0.15 150 22 412 - 0 - 0 23 374 - 0 - 0 24 358 644 0 0.14 68 25 475 708 0 0.14 127 26 414 - 0 - 0 27 382 - 0 - 0 28 370 673 0 0.15 145 29 542 734 0 0.14 167 30 453 - 0 - 0 31 11 0 - 0 4645 Sweetwater Boulevard, Suite 200 * Sugarland, TX 77479 * (832) 939-8991 1400 W Benson Blvd, Suite 410 * Anchorage, AK 99503 * (907) 277-1003 #16 ti OF 7, • • THE STATE Alaska Oil and Gas of A LASKA GOVERNOR SEAN PARNELL 333 West Seventh Avenue OF Anchorage, Alaska 99501-3572 ALAS Main: 907.279.1433 December 19, 2013 Fax: 907.276.7542 Certified Return Receipt 7012 3050 0001 4812 5832 Mr. George Pollock Manager, Production Operations and Engineering Aurora Gas, LLC. 1400 W. Benson Blvd, Suite 410 Anchorage, AK 99503 Re: Investigation of unauthorized pump rates at Aspen No. 1 (PTD 2051110) Disposal Injection Order (DIO) 032.000 Aspen Field, Undefined Unit, Beluga Formation Class II Dear Mr. Pollock: On September 18, 2013 Aurora Gas, LL (Aurora) provided the Alaska Oil and Gas Conservation Commission (AOGCQ an email follow-up on a verbal notification that the pump rates at Aspen No. 1 exceeded the maximum authorized in the DIO 32 (42 gpm) due, to anew injection pump being placed into operation. Specifically, during August 2013 the maximum rate of 51.4 gpm was recorded with eleven rates greater than 42 gpm recorded. The email confirms that the maximum pump pressure authorized in DIO 32 (1500 psi) was not exceeded, with maximum pressure recorded of 1025 psi and an average of 996 psi. The pump rates exceeding 1 barrel per minute are a violation of Rule 3 of DIO 32. However, the rates are within the original DIO fracture analysis modeling, and pressures recorded during the maximum injection rates are in line with normal pressure trends and the original injectivity step rate testing performed by Aurora. In addition, the pressure response of the well during and after the time the authorized rates were exceeded indicates no damage to the wellbore, no fracture propagation, and no indication that injected fluids failed to be confined within the permitted formation. Because the AOGCC is in agreement with Aurora's proposed corrective actions, at this time the AOGCC does not intend to take enforcement action against Aurora in connection with these violations. Sincerely, Cathy P Foerster Chair, Commissioner Investigation of unauthorized pu0ates Aspen No. 1 December 10, 2013 Page 2 of 2 cc: Thor Cutler, USEPA, Region 10 AOGCC Inspectors 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. As provided in AS 31.05.080(b), "[tlhe questions reviewed on appeal are limited to the questions presented to the AOGCC 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 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. 2 • m(Domestic Mail Onir No Insurance Coverage Provided) rD ul rlJ ?h,,,,x .:: t co Postage $ Certified Fee C3 Return Receipt Fee Postmark a(Endorsement Required) Here Restricted Delivery Fee O (Endorsement Required) LrIl �Total Postage & Fees ru Sent To r-i _ StrBat, Apt No.; Mr. George Pollock r%- or PO Box No. Manager City, State, ZIP+ Production Operations and Engineering Aurora Gas, LLC 1400 W. Sensor. Blv,� r r Anchorage, AK 9950 3 mo 3 2. ■ Complete items 1, 2, and 3. Also complete item 4 if Restricted Delivery is desired. ■ Print your name and address on the reverse so that we can return the card to you. ■ Attach this card to the back of the mailpiece, or on the front if space permits. 1. Article Addressed to: Mr. George Pollock Manager Production Operations and Engineering Aurora Gas, LLC 1400 W. Benson Blvd., Ste. 410 Anchorage, AK 99503 2. Article Number (transfer from service Iabeo PS Form 3811, February 2004 A. Sig e/ ❑Agent ❑ Addressee B: Received by (Printed Name) I C. Date of Delivery D. Is delive address different from item 11^1:1 Yes If YES, enter delivery address below: ❑ No ,s 3. Service Type ❑ Certified Mail ❑ Express Mail ❑ Registered ❑ Return Receipt for Merchandise ❑ Insured Mail ❑ C.O.D. 4. Restricted Delivery? (Eetra Fee) ❑ Yes 7012 3050 0001 4812 5832 Domestic Return Receipt 102595-02-M-1540 ; #15 ,.-,-.-,,.,Aurora Gas, LLC August 8, 2013 Cathy Foerster, Chairman State of Alaska Oil and Gas Conservation Commission 333 W. 7' Avenue, Suite 100 Anchorage, AK 99501 Re: Annual Surveillance Report No. 5 Disposal Injection Order 32, Aspen No.1 Dear Ms. Foerster: In accordance with the requirements of Disposal Injection Order 32 (DIO 32) Rule 6, Aurora Gas, LLC (Aurora) has prepared this Annual Surveillance Report for the Aspen No.l Injection well. The Aspen injection facilities did not have any facility upgrades in the last year. The permanent injection facilities are currently capable of a max injection rate of 12 gallons per minute (gpm) and injection pressure of 1000 pounds per square inch (psi). From July 2012 to June 2013, fluids were injected into the Aspen disposal well a total of 150 days and a total of 26,041 barrels (bbls) of fluids were injected. Drilling muds were not injected during this time period. The Maximum pressure on the well from July 2012 to June 2013 was 1018 pounds per square inch (psi) on July 22, 2012 at a rate of 5.9 gallons per minute (gpm) (0.14 barrels per minute (bpm)). The minimum pressure seen on the well during this period was 357 psi on June 22, 2011 while the well was not injecting. - The average wellhead pressure for this timefiame was 680 psi. The maximum flow rate recorded on the well was the well saw was 23.3 gpm (0.55 bpm) on June 11, 2013. The average injection rate during the year was 6.3 gpm (0.15 bpm). The data from the new monitoring is available, however it is not feasible to print out for this report and can be made available electronically if requested. Enclosed is a separate report on the reservoir performance of the well created by Nutech Energy Alliance. The injected fluids are being pumped into two separate perforations; 2,125-2,145ft (Interval 2) and 2,351-2,371ft (Interval 1). Simulations based on the injection pressures, flow rates and volumes injected were used to determine the fracture geometry and 6051 North Course Drive, Suite 200 - Houston, Texas 77072 - (281) 495-9957 - Fax (281) 495-1473 1400 West Benson Blvd, Suite 410 - Anchorage, Alaska 99503 - (907) 277-1003 - Fax (907) 277-1006 zone of influence for this well and can be found in the Attached report. Below is a summary of the findings from this report. Maximum Created Fracture Dimensions Interval Perforations Top Frac Depth (Ft) Bottom Frac Depth t) Frac Len (Ft) 2 2,125 — 2,145' 2,116 2,151 84 1 2,351— 2,371' 2,348 2,375 155 Do not hesitate to contact me if you have any questions regarding this report. Respectfully, eorge Pollock Manager, Production Operations & Engineering Aurora Gas, LLC Enclosure cc Dara Glass Cook Inlet Region Incorporated 2525 C St Ste 500 Anchorage, AK 99503 • 0 Wallace, Chris D (DOA) From: George Pollock [gpollock@aurorapower.com] Sent: Thursday, September 19, 2013 2:26 PM To: Wallace, Chris D (DOA) Cc: 'Ed Jones' Subject: RE: Aurora Gas Aspen #1 (DIO 32.000) No Z Attachments: 2013 Aspen Surveillance Report08Aug2013.pdf Chris, The Annual Surveillance Report was submitted on August 8, 2013 and is attached to this message. Let me know if you need anything further. Regards, George Pollock Manager, Production Operations 8s Engineering Aurora Gas, LLC 1400 W. Benson Blvd., Suite 410 Anchorage, AK 99503 (907) 277-1003 Main (907) 351-8286 Cell From: Wallace, Chris D (DOA) [mailto:chris.wallace@alaska:gov] Sent: Thursday, September 19, 2013 11:24 AM To: George Pollock Cc: Ed Jones Subject: RE: Aurora Gas Aspen #1 (DIO 32.000) George, When reviewing our file on DIO 32, 1 do not see the annual Aspen Injection Surveillance Report required by Rule 6 and due by July 1, 2013? Thanks and Regards, Chris Wallace Sr. Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1250 (phone) (907) 276-7542 (fax) chris.wallace@alaska.gov From: George Pollock [mailto:apollockC&aurorapower.com] Sent: Wednesday, September 18, 2013 3:11 PM To: Wallace, Chris D (DOA) Cc: Ed Jones Subject: Aurora Gas Aspen #1 (DIO 32.000) • • Chris, As we discussed on the phone, a new injection pump placed into operation for Aurora Gas, LLC (Aurora) at the Aspen #1 Injection Well resulted in injection rates that exceeded the maximum rate presented in Disposal Injection Order 32.000 (DIO). Per the DIO, the injection rate is not to exceed 42 gallons per minute (gpm) and the pressure is not to exceed 1,500 pounds per square inch (psi), based on fracture analysis conducted by Aurora. During the month of August 2013, eleven (11) events were recorded where the injection rate exceeded 42 gpm. Cumulatively, these events had an average injection rate of 47.6 gpm and an average injection pressure of 996 psi. The maximum injection rate was 51.4 gpm and the maximum pressure was 1025 psi. Note, that when the injection rate exceeded the maximum allowed, the injection pressure remained within acceptable limits. Aurora has implemented a set of engineering controls to ensure this exceedance of the maximum injection rate does not occur in the future. These actions include: A manual choke valve has been installed to keep injection rate at acceptable levels. Communicate to operators the maximum injection rate and pressure allowable. Aurora is also evaluating modifying the gear ratio of the pump. The intermittent exceedence events self -reported in this message will be included in the Annual Surveillance Report prepared for AOGCC as a condition of the DIO. Aurora does not believe the limited injection rate exceedences represent the potential for any adverse impacts to the Aspen #1 Injection Well. The fact that the pressures observed during the times when the injection rate exceeded the allowed maximum remained within the range typically observed strongly indicate the mechanical integrity of the well remains intact. Do not hesitate to contact me if you require any further information regarding these events. George Pollock Manager, Production Operations & Engineering Aurora Gas, LLC 1400 W. Benson Blvd., Suite 410 Anchorage, AK 99503 (907) 277-1003 Main (907) 351-8286 Cell x$14 IP tiAu rora Gas, L C July 13, 2012 RECEIVED Dan Seamount, Chairman JUL 1 2012 State of Alaska Oil and Gas Conservation Commission A®GCC 333 W. 7 Avenue, Suite 100 Anchorage, AK 99501 Re: Annual Aspen Injection Surveillance Report No. 4 DIO 32, Aspen No. 1 Dear Mr. Seamount: In accordance with the requirements of Disposal Injection Order 32, Rule 6 Aurora Gas LLC (Aurora) has prepared this Annual Performance Report for the Aspen No.1 Injection well. The Aspen injection facilities did not have any facility upgrades in the last year. The permanent injection facilities are currently capable of a max injection rate of 12 gpm and 1000 psi. When drilling occurs and drilling mud needed to be injected a rental pump and mixing tank were used to separate from the permanent PW injection system. The same meter is used to monitor all flow going into the well. Drilling mud from the Nicolai Creek #11 and Three Mile Creek #3 wells were injected in the fall of 2011. From July 2011 to June 2012, fluids were injected into the Aspen disposal well a total of 189 days during this timeframe and a total of 39,864 bbls of fluids were injected. A total of 2430 bbls of mud was injected for Nicolai Creek #11 well and 2,580 bbls of mud was injected for Three Mile Creek #3 well. The Maximum pressure on the well between June 1, 2011 and June 4 2011, was 1170.6 psi on October 24 2011 at a rate of 38.7 gpm (0.92 bbls /min). The minimum pressure seen on the well during this period was 305.4 psi on June 22, 2011, while the well was not injecting. The average wellhead pressure for this timeframe was 694.6 psi. The maximum flow rate recorded on the well was the well saw was 80.4 gpm (1.91 bbls /min) on 9/4/11. The average injection rate during the year was 9.34 gpm (0.22 bbls /min) The data from the new monitoring is available; however it is not feasible to print out for this report and can be made available electronically if requested. Attachment A is a separate report on the fracture geometry from injectivity in the well prepared by Nutech Energy Alliance. The injected fluids are being pumped into two 6051 North Course Drive, Suite 200 • Houston, Texas 77072 • (281) 495 -9957 • Fax (281) 495 -1473 1400 West Benson Blvd., Suite 410 • Anchorage, Alaska 99503 • (907) 277 -1003 • Fax (907) 277 -1006 • • separate perforations; 2,125- 2,145ft (Interval 2) and 2,351 -2,371 ft. (Interval 1). Simulations based on the injection pressures, flow rates and volumes injected were used to determine the fracture geometry and zone of influence for this well and can be found in the Attached report. Below is a summary of the findings from this report. Maximum Created Fracture Dimensions Interval Perforations Top Frac Bottom Frac Frac Depth (Ft) Depth (Ft) Length (Ft) 2 2,125 — 2,145' 2119 2,150 35 1 2,351— 2,371' 2,330 2,385 501 If you have any questions regarding this report, please contact me via email (ieiones @aurorapower.com) or by phone at 281- 495 -9957. Respectfully, J. Edward Jones President Aurora Gas LLC Attachments Attachment A —Assessment of Fracture Geometry Analysis by Nutech, July 9, 2012 c.c. David Goade Cook Inlet Region Incorporated 2525 C St Ste 500 Anchorage, AK 99503 NM I NM MN N I 1111111 MI I N NM NM NM 1111111 r MN MN OM k _ . 3 �� i `� a : : S i I MPI L �"t�a a 3a =s S : � S t ;AT! 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F: . �. �.• r = :i� : iiiiYI :1 :3 " t. : i = 5 k « w x nu S 3 :: :: " 4 4 11M 111." 4 " . a rr ir : ,: ..r. . d e , { INS :::..:":: . r 3 •i•..i p 36Et"6.a� . r: :: •• =�■IYY:p :2 g :a : 3a � i 1r :�" s . 'r�:3 Hi p :t• ki r 30 .... F •Y as • " y ^'�'" r�p � ' :rrr� : aY iY M3 a.� .,r Y aS3:• \ :p� :« ni • ==ill :lr.r ;y�4 June 2011 — June 2012 x s:: i s :::• g : :_ .ri g . o.r r i : ..r.■ finals ui S ... "a.. . 5 s �:� i p x tx = =i 3 = _: • • ; :....s• :s : m3m =5a•i 3 3 S�r3 • S •. .. • . . . �C` r r tart : t. °�: ° t =r =_ q__ Pro # 1 795 4 4111 — .. iaa. • • : S : """ 3M " 3 a i a1tS i • S " a " S . "s July 9 2012 - The following report is based on sound engineering practices, but because of variable well conditions and other information which must be relied upon, NuTech Energy Alliance makes no warranty, express or implied, as to the accuracy of the data or of any calculations or opinions expressed herein. You agree that NuTech Energy Alliance shall not be liable for any loss or damage whether due to negligence or otherwise arising out of or in connection with such data calculations or opinions. a. Nu T ec k: x p r �cu� i M' = E MI NM = = I' I =' MI N = MI i Inglowasoargamaggerus • . ??? #, , +. " . � „„ .. S. < s4, ,.*.r:. Well , '. v. ., :..r. L . �� >.� , .r �.., ,,,.. ”` r Two zones in the Aspen #1 are open' or use as infection zonem s . • Recent injection data has been provided to NuTech in order to model the injections and determine what the created fracture dimensions are and what zones have been influenced by the injected fluids. • In order to accomplish this, a NuPro fracture simulation has been performed on the injection zones utilizing the reservoir petrophysical and geomechanical characteristics previously identified and summarized in the `Analysis of Injection Project' report dated August 8, 2007. • This analysis is designed to meet the requirements defined by the Alaska Oil and Gas Conservation Commission. 4 :4' N N ut in ► ILLdIMK'I. :Sti GWl.Vt3M+i: i MN MI MN M 1 I MN MI EN MI MN N N VeStOMUCVARZONI* f.0. .e 0 . 1 a : er,,a, xv, ..,,<"'.y' ..� .. °' "^'.. ,st. ., ^S . a''.°. .. ,,.., .x »c .�.nr::,. .. ..:``;^."?`^ �` �;3..t+.s+nv �•;...,... ,, .'"..'.'k...'�s. :' a^''+ �' t`! x,:' s��`,.'*. , : :..k �+»�+"n„�'',w�;.a '�:. a'.'xa.C'., • Reservoir Description • The NuLook analysis dated 8/18/2005 provides a petrophysical description of the reservoir and it's properties. This includes (but not limited to) the porosity, permeability, texture, lithology and water saturation. • The NuStim process is used to create a reservoir and injection model with emphasis on the NuLook analysis. This process will utilize the NuLook processed data to determine additional geomechanical reservoir properties such as Young's modulus, Poisson's ratio and a stress profile. • In this case sonic data is also available and is used in calculating the rock properties. This data was used in order to build a calibrated geomechanical model that will enable the prediction of rock properties for other wells in the field with which sonic data was not provided. • Injection Performance and Fracture Characteristics • The NuStim model is then used to predict the characteristics of the actual injection into these intervals. ,u fftl A'i.7 14l140(: N .., ., . $fnllw41p0a1:M1fIM NM OM ., .._,....“.._ ,....,,... 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Y t« .. t t kaxa a * t k «*.*P. *a.i *Pt ry Detailed fracture modeling is provided for up to thirty completion »Ras xx.7x7SS.*.% #1 #*a#.7.t k k x ##aks #P #R4R * * #7R# #P71ped7 tit « «tt4* - � � - � � - , #.stet« # «. � ..- � - = • � � • � , � • � ' - -� # * **1* * #• scenarios, allowing for the comparison of treatment volume, fluid • 7.1:41 . at PP 9 p 7 P «t Pie* . an proppant type, '°^°77.7'^7° 8. Production Evaluation t #a • d"e 1 $ perforation selection # 4 111 .d # «. !*# � i ", Wellsite data is obtained and P P "4 «t e S *y e* injection rate, and " i !a « i ncorpora t e d i n t o th process �� ', � proppant concentration. 4 #p ". # #R #,tap. . ..174 .. ! 1 ^�� } via NuPro'". Comparisons and Each NuStimT" features enhancements are made, refining Stimulation •Y1SIOD detailed fracture t calibration sets and enhancing modeling, surpassing • future predictions for the next well. all current commercial - . PROCESS OBJECTIVE; 7. 1 Tree Into pred obse Establish the Link Between a Consistent accu Reservoir Evaluation and Well Completion Results for a Field. .i r ; r t � (JJ N US J e r i I, • r AI l Ldtii 1 SOVW.1111401 Vittae' NuPro Product i ,. „ .. ...._ „! ...., .. m, . , ,.. ., . ; . Al. - $O` *x PMPm. « iI: # « XP:#+a « ##* ra an:0 1 �# * « «P#. # *. f* P # ### «P «. 2 fib rated Rock Pro Log RM.r r *,ii�,i�+ « «an, . «f *sa++ii`#+ »i' #* t e Fa * l it tr 'sial� *# ft , t#M e p*## #*+!wino #xafs 1 , 1n, The NuStim'" process incorporates a well•specltic tt # �*# r *a .* t « # ii�tt *r"tt 'P;*� °��#«�« &,#��ql rock properties log, defined at six inch resolution, by which the fracture behavior is governed. These properties are calibrated to measured 3. Incorporation of Field Parameters I 1. 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Applicable when completion optimization is not the primary objective. 7., i Tra nto • Provides analysis of past completions obi — Decline curve analysis N u P ro A. imps a"' — Production history matching Look B Ek — Fracture pressure matching — Incorporation of well test and tracer / production logs — Is the observed production response due to reservoir or completion? • NuStim process calibration for a new field %...1 • Project remaining reserves , I 4- w. 5 N ii ' " fim 5 e P it Xt,l dI∎f /kW A MI = = E I MN = MI N MI M MI N MI MI = = MN MN u a 4C: "^lt: ' try ye f »,Pk " 11444 +f� *�, ;f 1 �.° i "'�. . .,., �. � ✓ � '� #"£. F r� ''+:} "S°� ,' s �by � � .:i �;. ` � s �,^'� �'b& +�`� ��,. ��Y' it `V"ka: `. ` A L a- \ . ` r 4, "a, i % ' ., "' a t' *. t k ; tr, ,, 'r ' " i� 0 � 1 ` ' 'Si. . A. k k , , •v ,`.R <, ,.,,, i s ais : �. *yr,': 1 ,40 , ,...N. :ta'. , ,,,,z ,,.: ; ., 2. Calibrated Rock Properties Log The NuStim'" process incorporates a well•specific *fin` r "' ,a* * *`.'"`* **.£r + *w r* *n * *„ ., a rock properties log, defined at six inch resolution, * " ,1* +r** * ' „.* ,***** a” by which the fracture behavior is governed. These properties are calibrated to measured 3. Incorporation of Field Parameters / 1. Textural Reservoir Description data, including: fracture and NuFlT'" analysis, Operator Input The NuLook'" evaluation process provides a normalized tracer logs, microseismic fracture mapping, Field parameters such as historic stimulation and consistent reservoir description, enabling the NuStim "" and production history matching. challenges, field hydrocarbon properties, reservoir "� " x.. o,^ „� process calibration extent tubular data current completion ° ** 011 r /[t i sets to be predictive. - �� _ practices , and field -. i Fr ' The key components s t : economic parameters i I i I of the Nulook'* process ' } ' all factor into the ' �� �.� � k ., include: log normalization, ddff II II I 1 � r tic * , completion analysis. _ " * "1” * °° e i clay volume and lithology If +* a{ determination, textural f 9 r li ' I 1 I r ... 6 . � permeability distribut I K,/lf, , • —, d/ ■It ":;ls Ott i 1 _ . _. 1. Textural Reservoir Description The NuLookTM evaluation process provides a normalized and consistent reservoir description, enabling the NuStimTM process calibration sets to be predictive. The key components of the NuLookTM process include: log normalization, clay volume and lithology determination. ... textural permeability distribution, and bound and free fluid identification. preuriav ane meat observations allow for ,....7 improved prediction – i _ accuracy in the field. 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E _ i RR F F- 2 O a I 11111111111111111111111111111 I CI; t 11 , 1 , E _ Lila �I111INi►11 111i/� a _' I o I�w� s Q ( 1) itli irli 1 � d �z 1 41 �: Q I! ! •! 1 , Ili 1 i ' � '''" ' ' "'' ^ air Q ....,...i..,.:4,........... -J 0 Tani i s on mom s ii ^i MUM niu Nr Arun♦ r m. ...■ om 117 ;w r■w Mi sL■ a■ 1 /. r■ I Wigan IMMii BOM A p e l u i lia • Y ■•r ••N• N■ • [r•i 1Ja)[ CGGOW 42M I J Jaa»22a23 r _. : Y a I -® N MN r r- r- M r r OM r I r• r Geomechanical Properties Listin 1 I Gross Net Effective Stress Frac Rock Top Depth Bottom Interval Interval Porosity NuPerm Stress Gradient Gradient Embedment Specific Specific Thermal ft) Depth (ft) (ft) (ft) ( %) Sw (md) BHT ( ° F) YM (e6) PR BHP (psi) (psi) (psi /ft) BHTP (psi) (psi /ft) Strength (psi) Gravity Heat Conductivity • rr ®r © ® ®1=011 1. 606 MEM 0. 5803 rr:=111711 0.841 111•131=1711 80412 E161311 0. 247103 INIEBIES ®i ®i ���®i : 88 11111131111111:2111 1009 0. 898 ® 0. 249372 2.293669 NE NE ����� 88.1 0.6359 0.369 EmommEmixegmEn smogs 80004 MEMEI 0.254642 2.430699 tmmgmur■li®. 6. 0648 IIMEI 0 8625 IMIEggirmumgaz 0.816 1889 0.3trig 80000 =gm 0. 25424 ®" ®i gE ompoNNEINEggig 0.99 0.001 ENEEE 0.6861 0.369 magmEEBNErmaiErg 0.894 •: r r 0.256003 2. 466065 1111111132111IFEM1111111111=11111111EIBIIIIIIIMEME111111111311 0. 6748 IIIIERCIMEMIIIMCCEI 1 846 MIGil 80148 111BEEB 0.248376 IIMEZE® ®111=111® •0. 08427 MEE 0.6914 INIZEIIIIIIMMINEM 0.796 111110EBEIMEIRIEI 0.247503 ® ®11111112:1•MEM 0. 98 0.07262 IEEE 0.69 =3131311111111:911311111611MEIMIO 0. 901 INIMISZIEIBEIIII 0. 247684 . ® 1.INNEENNo®ogrffi 3.6458 0.7304 0.369 ENEEHINEmimmi 1 904 0.896 80000 0.25291 mama IIIER®© ©t1=1111 9.40215 IMEMI 0.7434 0.369 =3-11:1® 0.816 =KIM= 79996 EIEIIII3 0.250116 ME= 11111115210111111112:1® IMIZI®i : ®i ®i ®i ®i. NE ; r IMEM®i :: 80050 1111:110112111311 2.39092 111111101111E011311®© 111113:111111MM 1•113111=31 MMEINIIIIIISINCEM 80004 MIMI 0. 254987 2.439667 ® ® ©MIIIII •®111112ZE =EMI =GM MIME 1909 =ME 80000 MIZE DEEM 2.440832 ® ® ©1IIIKEI®MICEI 0. 0392 =7.1=1301111111E03111:1138=1:3111111:1121 80000 EICEMCIMICIEKEIBE ' • ® © ®min Eon 14. 86998 0 6935 0.369 ®=mgENEE3 0.902 80002 Emil 0.254744 ® ■© ®11111110EI 06105 •MEEE® 80000 1111ECIIIIREIMEMETIEI 111111EIMIEREEMIEIIIMIEBEE111111131311E11319111MIXIMEIMENICEBIIMMINIE1711 0.836 IIIIIEISMID 80000 NIECIM 0.254627 2.430302 iiRflINEESI®11111111111111EMMINICEEIIEMEIMI11311EIBMIIIIME311111131® 1949 MOM 80000 ®EMZE1 ®"MEM © ©1111E131113® MI MEE 0.389 MIIIIIMMEEMEIME MEM IIIIICIDEI 80000 11110E1211136123:11 !�!�� © ©� 0064 r �7�7 ���® �� 79996 2. 266675 � � . �ai� ® ®�� SiJIIBIES 0. 6485 0.383 IIIIIRMINIFIE 0. 829 MIEMIIIIICIEBEI 80000 MEM 0.255059 IMEIMMI MISMIERECIIIMME1■31allintillIIMITEIIIIIIIMIMEM r 0. 7497 �� ®� 1 948 0.907 79998 2.29965 �� IMICEI 21 48 . 5 ©����i[lii 1111:11133�' ® r :r 0.881 80004 111:113:21112711111== ', . S ®■11:1®i MMIXIIIIEICil 0 09901. 0.61 1111Ecomoi® 0 . 9 14 IIIIIMEEE111111012211EITEMINNIMM , , P 4 t1 0.99 0.02945 1040 111111EIMIC1111111321111131211111111110EM 2.274442 0.223424 111111111ME illmmeffsts®milmoram 0.86 0.04815 0. 8761 ®r :'niffm EmErm 0.846 Eszsa /no 80000 2.40595 0.244913 =MI ® ®=ICI 1111121:011111111311 0. 0393 IEDEEIMEMIIMEMINECE13• MIME 80000 112:63111C1111111 2.19443 1111E1E1E32211•1•113 NIKE I I I I M E 1 1 1 1 1 1 1 1 : 1 1 7 1 0.07935 MUM MEM MIME ' 1 046 =BM 0 NEM 0. 901 79998 ii333 0.247076 2.233966 2 ®11111111•31=113=31! 0.1066 MOE IMITIS MIMI INIIIIIIIIIIMEMMEMEIMMINIEEII 80000 MEER 0.247037 3IEN23■3111111111:1111EME1111111111:1 0. 0524 11111113 1. 0902 �+ ®11111CIEMIIIMED 0.893 80000 MIME= IME3121111111612/12 j=811111®MIIIIXI®MICES 0 01979 INEIE111/131111110CHIMBIMINITIEI 0.874 1111113111 0. 962 80006 2.499463 0.249084 11MEMEI®® 1111113'I' 0. 5799 IIIIIIIIISIEMBEIIIIIIIIIIEMINE23111111111:101111111112E11111111E1 - 80000 IIIIIIMITIKEZIE11111Effilifil . • ® •®111113:11:2111101:1111 . 0. 1074 1 MIIEMIIIEIMIIIIEIFIEIOIIIIEIEIIIIIHECIIIIIIICEIIIEEEEIIIIIIICEIIIIIIIIIZEMIEIEEIEI 0246971 IIIIIIEIEMEESMIIIIIIIIECIIIIIIIIEIIIIEEMIIIIIIIM .. 0.001 NEM 0. 6748 6r •'1l' ti 0. 826 0. 909 2. 304516 0. 24467 111111111ME ®11111INCINIMIS 0. 111113318111111EDEI 0. 6569 IIMEIG0® 1 804761E2E2 0.245207 ®omixormammixi 0.18032 89 7 0.8781 momplurEmsgm 0 8 91111EINEI 0.901 .80503 Enos 0.248964 2.283054 1111118931111EVE111111111111111111=IIMCCOMEINIM111111111E111 0.8907 ®I .. 11111111110111111137:111 0 81 2096 11117111 80448 ® 0 248176 ® ®11M11211111111211 0.91105 89 7 0.881 1111DMIIIIIECIIIIEBENIEFLEINE123111111631111MEEKE1111 0 246904 2 229494 ® ®ENE 20 69 0 96 0 11708 NEIN 0.8068 NEna® 1860 Ng= 2046 0. 858 .81 398 lElar011 0. 241796 2.096703 1 ®� ®��® 9.081 89.7 tw ' ®�i • • ®+ : ® 0 895 8 090 ®: r 0. 247671 2 249459 SS51EIN3®111.11111D® 0. 94 0.05395 89;8 Ur 0.349 11=31111111ffia 0 794 0.874 ®: r 0 251584 1111116113521 •1111311,213101111111113111111111111 1 8 . 63 ®i . 3t : 1. 8607 ®i ® 1 842 IIIIESECIIIIIECEI 0.856 79996 NO= 0 248047 • • • •• t • ®11111113/4 4.96942 89.8 0.9961 ® or .O . �. '. 79999. INIESIDEBEIMBIIIIIMEMEE 11111111EMIIIIEUMMIIIIIIIIIIIIIIIIIRIIIIES11111113151 31 93875 MITI 0.9186 =1411 1111111011 0.851 80002. mon 2.417436 111115111113523111111111111311111111111111111521110111113111 0.3 3897 89.8 0.8541 � wr ' • rJ : r r 0.837 80421 0.246758 y ��® 0001 89.9 �'SfM'Si 0389 0.82® 0. 902 36498 1. 532649 • . r : 0.992 • : 2.3081 0 243 2.1 4988 1 2386 ® 0 3t 0,244 • • 0:6934 0 e 3 � ® ® 0.894 D 244 •e 22.48 r;• >0 .64298 0.69 11 ELI. •:• 238 INF22311111EGIIMMIIIMIN11111111•62111111111111CIEMENNEE 0. 7441 0.366. IMIEB1111111627.4 0 804 0. 884 : r r 2.29045 r ' r � . 0 98 10.0884 0:7876 r 11 48 r ®' "' r 0. 878 81640. IIIMEIZEI 0 249271 III= r ® 0. ongemoszn 0.7079 0 3 6 4 • r 0:798 e : : r 80632 • • 0.24458 2 169062 r : .0 .906 60093. r 1.8 • °• °° •�� 0 99 r r °t 0. 8652 r r 1r, � 1 2400 r r r • r 0. 0. 794 2098 0: �• r • •21 0 2468 111111MENEE • t r - 0. 872 : r r 2.0905 • • r r :. -? 0 '+ 0 &762 r . .. 4N lk, I 2 A u ec 04*G Y AUJANCt All. I t .,. S sm.iosotio„ , viii0.11100 I N i - • r 1- NM MI r r UM NM o NM - UM IIIM Geomechanical Properties 1 1 NuStim Model vs. Sonic Model _ ^.. . ,-.. N, - .m ,•� . ..., ,.,., .. 5 ,< ,. , r+ , :a:. .. ,.w „ °> k"im*' rc*a. S� :::'a,.. -z. . r. +�°�� ck. c'- ,.;rn+� =. "'w�, ,-�.:�„ of e;,� *,t' �.?; �w .. -;-z(. �b +.a'�k.+vcbxa,�t .ifa -�.,; �5 n it • The NuStim model matches the reservoir characteristics measured from the sonic data - .. _,,. ,, very well. -ra • The plots below compare the Poisson's Ratio and Young's Modulus calculated from the measured data vs. the model predictions using the NuLook outputs and triple combo based data only. • This model may now be applied to future wells without measured shear and compressional inputs within this field. Poison's Ratio Young's Modulus 0.5 3 r 0.45 f 2.5 1 _ f l i t ' ' ,4� )4, 1 't, t,,1\,v1.(vv ilkil.i\i ,., 2 . '' 41*. ' t i , >r - 0. 35 .� t ^ 1.5 : 1 , '.. _.... j _ _ : .� - .: �1 1, 1 i ` 0 25 ... _.; 0 5 l. -. =` — NuStim Model — NuStim Model -- Sonic Model -- Sonic Model' 0 2 ...... - ___ ___ -__ _... _. ____ ___. _._ _____ 0 2000 2050 2100 2150 2200 2250 2300 2350 2400 2000 2050 2100 2150 2200 2250 2300 2350 2400 Depth (ft) Depth (ft) AIPS ' N r NuS ..,... . ..,...... ,namr.r atimpact .'' ‘ • . , a MI Mil MN MI MN ' NM MI OM MN IIIRIIIININIIIIUIIMIIIMIIIIIIIIIIIIIIIIIIIIO Nu Lo ok 0r �. . 'ta40,a: ,a 44144. .`' "' .. ' I ,lb . , '', .,, ,,,b +.+ ,tcx h >� t�-h 4,3:144,04004 ,` �:` 2. Calibrated Rock Properties Log The NuStim'" process incorporates a well- specific rock properties log, defined at six inch resolution, by which the fracture behavior is governed. These properties are calibrated to measured 3. Incorporation of Field Parameters I 1. Textural Reservoir Description data, including: fracture and NuFIT'" analysis, Operator Input The NuLook'" evaluation process provides a normalized tracer logs, microseismic fracture mapping, Field parameters such as historic stimulation and consistent reservoir description, enabling the NuStim`" and production history match challenges, field hydrocarbon properties, reservoir arm: _ process calibration extent, tubular data, current field completion ! sets to be predictive. € _ practices, and field .t. i� . The k ey componenprocess t * 'I - economic P P% i�a xt ° n % is i , + o f t Nut.00k' -. `. all fa ctor parameters into the i include log nor a completion analysis :eaPi" i *"%� as r t clay volume and lithology , i .,, P,: k - hi i #e. >+iPP w: I y dt� - 'r• `j YP #iii i# %iPP . • $ % An A ( determination, textural ` '! ie * #; � � r f :h ... P #P iiP iPi #Pi #P 5 �Y ss ar#PiP #i I � , t � 4 iP #MRt u PPP Rii PP iiP dil6Jfi se %x ' D Y I Kw. v .� ermeabitit distribution, Pii J f r 4 * Pi Pi Reand bound and free fluid .,- #iJ1 M# e e ? . P'rte RI1Rfr•y y�t�Ai 1"... 14-1. � s#rp #iY11 Ri +tl1F %i l%1i# YFii#iMYPiitr ••. ...r.r.:,n ♦.acx P} i� - M � u � " 4i {tPiP•i{ #KRY#RrtIFPHi{ %RRR i YRMRfiii #a #R #i#AtR # %if#iP #11PR'Mfi PPN>P�RR V � RR t% P•RPR R #i '� � NRRt4 * #*****. ## P #iP % %ii %ii R# % Py ,#y1 # 1 }p P R P %P IY i { � Y F# , ♦ y�F�� >i�•iY #F ♦ k #Pi1 i% y iiYY �: ♦q �{A�1{ t i ¢PYit•% % # %R bt fY Eiii%IrIA Y :"...Lii } .. >iC1: Mifil# a._ tx - • x s# i% l # #P i {# % # #iP i # iP iRP #ii P91 &# f ib PP # Y PRi P _ » ��gg � r�a° Wi #P P PRPi P R i RP P Ri #fit% P { ; i Y## # P R # #: % r * # *i P%. . %. .y Pi PtY s e e i # au3xs n# &»R. #PY' # 6 #Y# ##ex♦ <aa "#G # #MA aK • #A# # # #fi #t #P A bP ._ ..__ 3. Incorporation of Field Parameters /Operator Input Field parameters such as historic stimulation challenges, field hydrocarbon properties, reservoir extent, tubular data, current field completion practices, and field economic parameters all factor into the completion analysis. I re nNat information is obtained at the wensite, and incorporated Into the process via NuPro' and NuFIT` ". Comparisons of the model's predictions and these observations allow for •' "' " _ improved prediction u q L ;•r•, _ accuracy in the field. 7 • ' ` ' ' ` iw t . r 4 SOMIll on Waren • r O M MN M M r 011111 S ! M B IIIMI I MI MI NM • Incorporation of Field Parameters /0 • erator In • Wellbore schematic provided. • Two perforation intervals open to injection at: • 2,125 — 2,145 Ft (6 SPF) • 2,351 — 2,371 Ft (6 SPF) • 5.5" 15.5 # J -55 Casing to 4,484 Ft MD F , • 2 7/8" 6.5# 8rd EUE J -55 Tubing set with packer at 2,010 Ft • 7 7/8" Hole • Actual injection data detailing: • Injection time, rate, pressure and density & type of injection fluid. 1111114 g.4. `' NuTe ' n ... N— NM MN NM MI OM I ■■o MN MN — — — MI NM NM MI r z. -r AW. .. a �.,e ♦ * • y.. "*}""r�[ :Yip.- +4; "x. 4.i-. '+ � 144 ¢ : .},x. 4,k+414i..}a.e,.� +.r. +.;.og. (. :Hsa -i-r? - F4i + 44-ki vi r.. • s x#1A a ...-4 4 . w 4 ,sm1 #A se s, i r r 1 ,, 4 r ,” r” wwr ,.q p, r ” a� il. # Ica s 'snkst da 11 +d `pri�[ ir a 't 3 .. ,... :tf. .. . ., .. a �, ..... ....... ... :. n... >r. ..., o�li�. .,:. ,, ,s.,, ae '� ... e�.T ...viR.= lti� -. , ..: l ��. F" '. e �. c <a.., n�S'aw a +v � � A,# The NuStimT" process incorporates a well- specific rock properties log, defined at six inch resolution, by which the fracture behavior is governed. These properties are calibrated to measured 3. Incorporation of Field Parameters I 1. Textural Reservoir Description data, including: fracture and NuFITT" analysis, Operator Input The Nulook'" evaluation process provides a normalized tracer logs, microseismic fracture mapping, Field parameters such as historic stimulation and consistent reservoir description, enabling the NuStim'" and production history matching. challenges, field hydrocarbon properties, reservoir ° " = -s process calibration extent, tubular data, current field completion Are >9tµ # # # =m r.� a r I sets to be predictive. -; •. .. practices, and field # '"�" 1 � 111 The key components k� "[ - o} the Nulook'" process a y � r �� include: log normalization, + i :411:: f t�! clay volume and lithology [ a e": "� determination, textural . S ,,..x A >Rx „ permeability distribution, ,� , , Av # a # ## ssA � J � F .} # # #e " i+ix #" r r� and bound and free fluid r " *"� " + •#A ## . 1FR#t # #f # � ... : I� o !i' .. { t #i1rA MR# AI5 , }} # " �t # # #A # * i i! identification. . <,# #AS " # #A# # #a# "il . 1 i #Ak #A#"f • }rAA# A t [ it Art: # ## #AAA ### M# i r ;= .. _ 111:1!!!"”P141512:13742141." ## A AASi## A# h A" # # #A #• # #A #A# #"d f�' �It s 1Y t # � A YIX rt ii #4AUFLMAA1+g .YAN# #< MARi #lYle # A # AA M YiA #". AAL # ## C " #!s EecA AbbASan tWemdNAx# ♦ # i # FkAYANii]{ ' Nxu #A A# f @# + e: s aAx r r' .I If . A Y iY a 7. Treatment Execution and Evaluation Treatment information is obtained at the wellsite, and i • incorporated into the process via NuProTM and NuFITTM. � . M , Comparisons of the model's predictions and these "-I, these k observations allow for improved prediction accuracy in the field. Treatment information is obtained at the wellsite, and incorporated 8. Production Evaluation Wellsite data is obtained and incorporated into the process via NuProTM. Comparisons and enhancements are made, refining calibration sets and enhancing future predictions Rquo for the next well. i4.. t • • ruWG r 4 ttMilKf L tJ" . . yt MN MN MN MN MI OM MI M MO I MN I MN E r MI MN Results • The actual data provided for this analysis shows that the injection rate was more varied this past year when compared to the previous year's analysis and contained some periods of higher injection rates. • The injection rates varied from 0.5 — 80.4 gallons /minute. • The injection is occurring into two intervals, an upper and a lower section as shown on the NuLook (slides 7 & 8). • The upper section (interval 2) has a significantly larger permeability - feet than the lower (interval 1) section. • The modeling shows that interval 1 creates a fracture during the injection cycle. • The modeling shows that interval 2 does not create a fracture during a majority of the the injection cycle and stays within the flow limits of the matrix, except for a short period during some of the higher rate injections which create a small fracture. NuTech „ 17 NuStini€ SBmWatwn Wsidt MO MN I MN MN 11111111 I NM NM IMI NM NM IMIll N NM MI i INIII • ? " q,+ .} to K ,., :a � a' s H t x ; , * Aurora Aspen #1 Injection Profile Interval #1 ki: " 01 ,E 1200 120 S. ..._ Surface Pressure (psi) ; —.6—Frac Upper Ht (ft) E Frac Lower Ht (ft) a 1000 100 • _ 80 800 L Oq i li 1 ti d a 3 600 60 2 a I 1 I ;i I I I l I I I l '11114‘ 0 ii I P N I I 0 25 50 75 100 125 150 175 200 225 250 275 300 325 350 375 Time (days) k ' NuTe. l ' ► _ t rifliGV ttteANC $tlatufsaron.lAJu + t M I N IIIIIII = r UM M MI IIIIII 1.1111 MI = MI OM O Interval Modeled Fr c D '' '� " "',�- ax^sC+ .2 r� ' -...'� ..,_ {.,. , ?..;a:?;�";? €•° '�,. •x �. 52: ,4 '� '°.`ti :- sa�;'�w"+.`*� :"ht�«.u�*;W *,:r ,,°E "ham ,. :, '� , ^`v>`'' '? „” :,�`: =a?,. `s'�; �s 's': .;z? ,a°a.; ;s..aa Aurora Aspen #1 Injection Profile Interval #2 1200 - — 120 - Surface Pressure (psi) 1 —Frac Upper Ht (ft) — Frac Lower Ht (ft) 1000 — — 100 Af 11'4ioi , liti , , if g0 800 L ea •N 2 O h. O. ea i l i iltif\ / i1\ 1 1111 k/ 600 mi \1 Cl. y a O. 6. n u 400 I 40 to At the reported injection rates this interval 200 — does not fracture except for a short period - 20 during some of the higher rate injections which create a small fracture. I I III I N. 0 0 0 25 50 75 100 125 150 175 200 225 250 275 300 325 350 375 Time (days) IF a 4 si N i, V €€aescr uueuc€ : N uSt i r r Maximum Fracture Dimensions Created Interval 1 cRC FW_FtAG DEPTH I ARtlO PHIDEDIT _ HDRA « CLAY SW NUPERM � 0 GAPI 150 6 0 FT F 10 2 0HMM 200 0 6 DEC 0 0 2WC).25 1 0 0 01 0 1 1 DEC -1 0.1 MD 1000 0.05 0 IIIMINI _ _ _CS - - F DTC AHT20 PDSS NMIN TEXGM SMALL BVW W , 6 IN 16 0 6 IISIiB 0.2 OHMM 200 0.6 DEC 0 0 OHM 20 1 NUMATR 0.1 100 0 1 0.6 DEC 0 0.1 MD 1000 1.5 3 5 M. SPRL LW_FLAG I R 1 AHT30 _ MISS H MEDIUM PHIE - 120 MY 30 0 6 1700 0.2 011MM 200 0.6 DEC 0 0 OHMM20 0 t 0.6 DEC 0 NUPERM 1000 NUSPEC4 CO A0160 PSSS LARGE 81/1 it en_I I i ..I I I. I 0 The vertical permeability is unknown in this sW interval. This height shown here assumes that the al . injection from the perforations is contacting the 1• ■111M10.111 MN Mt ■11M a - " �.� IIIII — :1 entire porous interval of this sand. E I • ■ia■■1■tl 2300 . 1 Maximum Created Fracture Dime po■■■■� ■ ■■s..n. 3 B • 111111111111111111a 4 1111111 LO PER ill :. Top Length To Frac Bottom Frac Frac Len th a 1�i::::i 1` ■i Interval Perforations 1 irIIIIII O� Depth (FT) Depth (FT) (FT) �1MMWMM ► III I ;N 2 2,125'- 2 2119 2150 35 - I ■ ■ ■ ■ ■ !� OM II ■■■► ii 1 2, 351 -2, 371 2330 2385 501 —� - ��� ■ ■■ ■■■r I) or mia■■■—_- Ia:I II �II: :a!�17:EllnwrimI;■■U1111111111` I "!■ ::: iiirl 11111 !11111, i111111iiLiil.■7■�■Ln1u. 1... -I...-. - . iE ■ ■iI' ■1 ■■ � Ellin ■ iiis \ ■� ■ ■■ [OIIIl111 ■ ■ ■ ■ ■ ■.. i!liiiLliiii 11111Ii1111U1111111i ■ ■ ■ ■Y ■r ■■ ■1111111111 s IIII ■II ii■ ■uuli ■i ■� 11111 ■111111■!■ ■■i ■11■■ ■1111111111 _i ■ ■ ■■■■1 iii ■ ■ ■uuuu 1111111 MI) VIM 11 IIuP.iiri ■..1111111111 m`. IIII■ ■I ir•••••••• 111111 MIL I ■111111 ■ 1.1111•111•••'4111111111111111 IIIII IL uE■ ■i ■if ■■ ■ 11111 111111' !111111 ■ Eii1ACEEi:1111i1111 1 l _■■■■■N0- ■!■ ■ ■ ■\ ■i ■■ 11111 ■1111 •c111111■ ISM --ii7 ■ ■1iiiiiiiii i■■ ■i■i ■11■iiiii� 11111 11111 c111111NI riijcie ■■■ uu11A1111 . ■ ■I■ ■■4 iii •••ii•••� .r. -. _ 11111111111111•111 MI i ■ ■ ■ICEMB� Maximum Height i 1111•11/1111111 r i■■■i1■■u■� _ i ' iiiiii� iii iii ■iril / • � Contacted by 1 I® IIIII■■ 1111 rlirliill∎ 7 <• 1 mt IIIIIII ■e■■■ra■■n■■ . 1 F - ■■■■■ ■■ ieiicm■i171 Injection Fluid w,,.. 11:12116 RIII■. i■■■ii■■i■� *� ! ..nil 1111•••••••• 2 I I H i■••••••11 • - _7 111 ■ 1111 'ito4;ilicii(�IIrtiuuui7111I111 t 7111' EM ■e■■■11■Ilir 111 Mill, . iYRU■ ■11Sau■iuuu 1111111111 - 11M■■■■. .... i■ ■■i■i■li■iiiii� ' 111 ■1111101111111■■MMEG Il■■■�,IIIlln11 I t MI■■■■ ■f iciiii ■ ■■ ■∎ 111 111111 r /111111 • Willi MOM 1,111111111 I — iII•■■1 uuici IIII i'ii ■■� 111 111111 I ■III b�� ■■ : ■\11Gii ■ ■ ■ ■� III ■11111 \ .::I ■itiiiiilii. ■C I IIII ■IIIII MION IIIIMIMINIM 111 •1111 IMii!I ii I ■ ■ ■ ■ ■ ■M ■ ■■ i ■■■uri ■i ■ii IMI 1111 111111111N N� !!i ■11ENN('111111111 I I I l ■ ■ ■ ■ ■[ 31111111 111 1111 !11111 Inn!' • iie■I14/111111 Ioluuul 11111 !1111 111111 • iiii 1 - r �IIIIIr iii■itliiii ! ��Yiii1 111111111 - I ` :IIII, mil ■ ■ ■ ■ ■IJ ■ii ■� liiiIilllll !:111111 ■ ■ ■7w_�M ■ ■ ■NIIIIIIII - --t • J ■ ■ ■ ■ ■-._ -- iiiiiiiii ■ 11111U1111 �111111iiC2�t3NSIr1iil.:iid111 I IIIIIIIP -� urnuUu i ■i■ iiiii� IIII I inlet r ?IIIII ■III 5 .■■ii I'IUUnu - I -' - ' I 1 it ■■■ ■■r- 'II •II•■•YYil1i� 11111. 111Wi:Illllliiii ■PY ■Ni ■1'I11O1n ' I -- I I I I' II.....� 20 A N uT e / I, fl#iSY...AIlCf h ... IMO SaerortaNwnT,simr N 1 1 1 1 1 1 1 1 1 1 1 1 1 l I I 1 I 1 Maximum Fracture Dimensions Created Interval 2 GRC FW_FLAG DEPTH TVD AH110 P_HIDEDIT _ BRA p . CLAY SW NUPERM 0 GPI 150 6 0 FT F ','1 0.2 0HMM 200 0.6 DEC 0 7 0 Wei. 25 1 0 0 0.1 0 1 1 DEC -1 0.1 MD 1000 0.05 0 21 CI - - FF_ •R FLAG DTC AHL20 PDSS HMIN TEXGM SMALL B\W `' W 6 IN 16 0 6 R 0.2 OHMM 200 0.6 DEC 0 0 0HMM20 1 NUMATR 0.1 100 0 1 0.6 DEC 0 0.1 MD 1000 1.5 3.5 23 SPRI LW_FLAG [TSNRM AH130 _ P_CNSS _ _ HMNO MEDIUM PHIE -120 MV 30 0 6 1700 0.2 OHMM 200 0.6 1EC 0 0 OHMM20 0 1 0.6 DEC 0 NUPERM 1000 NUSPEC4 CO FHC_FIAG AHT60 PSSS - _ LARGE BVI TSNRM 0.2 OHMM 200 0.6 DEC 0 OMEN HMNO 4 1 0.6 DEC 0 ,. 0 6 " ■ ■ NNNN� '; .N ■■•N ■ ■■ / 1111111 •111113 1111111 • s■P ■sso 1111111111 ' I ,b , >», im Ii► mmm■ N 7 NNNN� a..m 1111111 s111111�MIIIII■ pr'A.:i 1 I ���. ■N..NN1NN ■ I I 111111N 1111111W :116 1N . T I 1 I I I f •I•IE••••••• .■■N. i'... •••111111111 . 111111I.11n' - . 111111 • stitasNN■■■i'111I111111 1 •- - .......C' - IN .nn,.- ...�,. - �1 ff II 77 I......NI11•.. °��� M aximum Created Fracture Dimensions N MI iii n� n I sliiiiii 4111•11 �o Top Frac Bottom Frac Frac Length -+ � ii:::::, 1E11 ■N Interval Perforations UN Depth (FT) Depth (FT) (FT) - , �� ����, _ GAS W) ■ LO PERM NM 2 2,125 2,145' 2119 2150 35 -1--, IB ���MMI F NM 1 2, 351-2, 371' 2330 2385 501 - N. .N■.NN...NNS.. —. ■iU iiiiiiiiiiiid LNiiiiii I mom mai: 1 111111111 r mmmmmslir lul lill ,._...,,_ , . 11.1 ���! . ■.■■NNN1 ■7 - 5 E��Ea oqli�m 1 ` - .....1 DAMS 1111111111 ■� _ I ---.-, spasms "MMus ■m "'"` "" 1 _ EM , �����, -.11I •11••••••11• -A Maximum Height .NNNIN M 111.110 111111B v....�_ GAS w mimes nl■ � -- .rr11■ .N. C by !1 -. ���i . ..... . -m••• II . LO TO MEOW ann ill - NR` IM:11P GOOD PER INNN11NI11N monsa a . ... .N■ ■a■.■. •••• NE I njection Fluid _ _ .... �� .N ■N. ■ ■ ■IN • ►7... ■ , 1 1111 N.NI.NIIU .� -- -- I tip....- !111 Ill I e��::e:= ��l`�;; ow in this l I �- ri _ . • The vertical permeability 1 = = so osoonia :; interval, This height shown here assumes that the 1 II i n j ection from the perforations is contacting the �; _- so mit .1 entire porous interval of this sand, El 1.1 IL-- - -.1•111•10.- mow 111111.111111r111 snows L .........1 .. .■NN.NNS.N NNNN� ; IIIIIII.IIIP "iii ■.■■NN lortmo J I4.I BIM Ill - -- ........w' -- .11NNN■N...7 ' IIIIIIINS01Y1:l1111 ■ ■ ■ ■s11NNiU ■1111111111 - `.10.....' - ••••••••�111 11111111E111111 NIEIIII■.NNNRNI'• sUN1,111111111 I I i _.— .N•■■■ ••11• ■ 111111111I11r 111 !IIII • IN•■.Il••1• 1111111111 ----, � — ■1......■ . ' Inn 1111•11111110 11111ssu111L'n11• i 1:1 L , � 1 GAS W/ 9NNIl•$ 7 2200 111111 ■11111111111■ IINr1•• 17 - ! -� r -- rr: .I.N.IINN11. 2200 IIIII1■ IIIII .IIi1I■ ...Nn11NN.o1.IIIIII1l1 §.....I LO PER , I ■INI COMM NNE 3 1111111 NMI T911111N !SINGMaNN 1 1111111111 ........ Ilf •••••••••• MINIM .Intl .111111 mini. ■ranssomas I — ■� - ......N' ■.UN. ■L7s es 111011!!!H 11NIN1■.■N.. /.1111. 111111 - - t ......I 6 2 1 .1/4. r11110 1.' tN aGY *WANG x Sernutat,Ort 413 • 4urrora June 3 Wh, 2010 Dan Seamount, Chairman State of Alaska Oil and Gas Conservation Commission 333 W. 7d' Avenue, Suite 100 Anchorage, AK 99501 • Gas, LLC www.aurorapower.com Re: Annual Aspen Injection Surveillance Report No.2 DIO 32, Aspen No.1 Dear Mr. Seamount: RECEIVED JUL 0 i 2010 Alaska Of & 'Cu Cars. Comr.;L,ian Anz+tonge In accordance with the requirements of Disposal Injection Order 32, Rule 6 Aurora Gas LLC (Aurora) has prepared this Annual Performance Report for the Aspen No.I Injection well. On January 23rd, 2010 a mechanical integrity test of the tubing/casing annulus was performed on Aspen No. 1 and witnessed by Jeff Jones with the Commission. The casing was pressured to 1,700 psi and after 30 minutes was 1,580 psi. One upgrade to the Aspen injection surface facilities was completed in the fall of 2009, which was the installation of a backup/redundant injection pump. The permanent injection facilities are currently capable of a max injection rate of 12 gpm and 1000 psi. In September and October 2009, Aurora contracted with Aurora Well Service to pump away the drilling mud remaining from the drilling of the Nicolai Creek #11 well and also emptied, cleaned and closed out the Aurora large water storage containment. Attachment A is the data collected during injection. From July 7d' 2009 to June 30`h 2010, fluids were injected in the Aspen disposal well a total of 83 days during this timeframe and a total of 15,780 bbls of fluids were injected. The fluids injected were approximately 6,950 bbls of produced water from the Aurora producing wells, but also included approximately 4,500 bbls of water from the produced water storage containment, 940 bbls of mud from leftover drilling Nicolai Creek #11, and approximately 3,400 bbls of wash/rinse water for cleaning tanks, pits, and washing the cuttings in the produced water storage containment in October 2009. The Maximum pressure on the well between July 7t', 2009 and June 30d', 2010 was 1,275 psi on October 21 st, 2009 at a rate of 0.95 bbls/min (40 gpm) The minimum pressure seen on the well during this period was 150 psi on April 5', 2010. 6051 North Course Drive, Suite 200 • Houston, Texas 77072 • (713) 977-5799 • Fax (713) 977-1347 1400 West Benson Blvd., Suite 410 • Anchorage, Alaska 99503 • (907) 277-1003 • Fax (907) 277-1006 Attachment B is a separate report on the reservoir performance of the well created by Nutech Energy Alliance. The injected fluids are being pumped into two separate perforations; 2,125-2,145ft (Interval 2) and 2,351-2,371ft. (Interval 1). Simulations based on the injection pressures, flow rates and volumes injected were used to determine the fracture geometry and zone of influence for this well and can be found in the Attached report. Below is a summary of the findings from this report. Maximum Created Fracture Dimensions Interval Perforations Top Frac Depth (Ft) Bottom Frac Depth (Ft) Frac Length (Ft) 2 2,125 — 2,145' 2,090 2,183 603 1 2,351 — 2,371' 2,306 2,389 592 If you have any questions regarding this report, please contact me via email (chel eg songaurorapower.com) or 907-277-1003. Respectfully, Chad Helgeson Manager — Production Operations & Engineering Aurora Gas LLC Attachments Attachment A — Injection Data for July 2009-June 2010 Attachment B — Reservoir Analysis by Nutech, June 2010 c.c. Kim Cunningham Cook Inlet Region Incorporated 2525 C St Ste 500 Anchorage, AK 99503 • • Attachment A Injection Data for July 2009-June 2010 0 • Aspen #1 well Total injected volume of fluid is 15,780 bbis July 7, 2009 to June 30, 2010 Date Time Tubing Pressure prig o a Volume (gal) Flow Rate Comments 9/14/2009 11:30AM 260 5.2 No water pumped from 7/7/09 9/5/2009 6:30AM 565 358353 5 to 9/14/09 9/16/2009 6:30AM 270 358353 0 9/19/2009 1:12AM 300 358361 5.5 9/19/2009 8:25PM 525 5 9/20/2009 8:50PM 380 9/28/2009 11:OOPM 750 42 AWS Pumps 9/29/2009 12:OOAM 750 42 AWS Pumps 9/29/2009 1:OOAM 750 43 AWS Pumps 9/29/2009 2:OOAM 750 42 AWS Pumps 9/29/2009 3:OOAM 750 42 AWS Pumps 9/29/2009 4:OOAM 800 39 AWS Pumps 9/29/2009 5:OOAM 800 39 AWS Pumps 9/29/2009 6:OOAM 800 39 AWS Pumps 9/29/2009 7:OOAM 825 386608 38.5 AWS Pumps 9/29/2009 8:OOAM 800 387814 29.5 AWS Pumps 9/29/2009 9:OOAM 800 389429 29.8 AWS Pumps 9/29/2009 8:OOPM 600 389529 21.5 AWS Pumps 9/29/2009 9:OOPM 650 390849 22 AWS Pumps 9/29/2009 10:OOPM 700 392529 28 AWS Pumps 9/29/2009 11:OOPM 700 394329 30 AWS Pumps 9/30/2009 12:OOAM 700 394962 21 AWS Pumps 9/30/2009 2:OOAM 700 394962 27 AWS Pumps 9/30/2009 3:OOAM 700 396582 27 AWS Pumps 9/30/2009 4:OOAM 800 398202 27 AWS Pumps 9/30/2009 5:OOAM 800 399822 27 AWS Pumps 9/30/2009 6:OOAM 850 401955 27 AWS Pumps 9/30/2009 7:OOAM 900 403327 27 AWS Pumps 9/30/2009 7:30AM 900 403973 27 AWS Pumps 10/1/2009 6:OOPM 750 403973 46 AWS Pumps 10/1/2009 7:OOPM 800 406733 46 AWS Pumps 10/1/2009 8:OOPM 900 409493 46 AWS Pumps 10/1/2009 9:OOPM 900 412253 46 AWS Pumps 10/1/2009 10:OOPM 950 415013 46 AWS Pumps 10/1/2009 11:OOPM 950 417773 46 AWS Pumps 10/2/2009 12:OOAM 1000 420533 46 AWS Pumps 10/2/2009 1:OOAM 1000 422840 46 AWS Pumps 10/2/2009 2:OOAM 1000 425900 45 AWS Pumps 10/2/2009 3:OOAM 950 427270 23 AWS Pumps 10/2/2009 4:OOAM 950 428650 23 AWS Pumps 10/2/2009 5:OOAM 950 430050 23 AWS Pumps 10/2/2009 6:OOAM 950 430933 23 AWS Pumps 10/2/2009 7:30AM 950 432459 30.6 AWS Pumps 10/2/2009 8:30AM 975 434350 30.8 AWS Pumps 10/2/2009 5:OOPM - 435399 AWS Pumps 10/2/2009 6:OOPM 700 436486 22.1 AWS Pumps 10/3/2009 12:OOAM 700 436486 23 AWS Pumps 10/3/2009 1:OOAM 900 437866 23 JAWS Pumps 10/3/2009 2:OOAM 900 T 439320 23 JAWS Pumps Aspen Injection History Appendix A July 7, 2009 to June 30, 2010 Page 1 of 12 Date Time Tubing Pressure psig Total Volume (gal) Flow Rate Comments 10/3/2009 3:OOAM 900 440660 23 AWS Pumps 10/3/2009 3:15AM 900 441034 23 AWS Pumps 10/4/2009 12:OOAM 850 441034 23 AWS Pumps 10/4/2009 1:OOAM 850 442414 23 AWS Pumps 10/4/2009 2:OOAM 850 443794 23 AWS Pumps 10/4/2009 3:OOAM 900 445180 23 AWS Pumps 10/4/2009 4:OOAM 900 446542 23 AWS Pumps 10/4/2009 5:OOAM 900 447910 23 AWS Pumps 10/4/2009 5:15AM 900 448227 23 AWS Pumps 10/4/2009 7:OOPM 700 448227 20 AWS Pumps 10/4/2009 8:OOPM 800 449607 23 AWS Pumps 10/4/2009 9:OOPM 900 450999 23 AWS Pumps 10/4/2009 10:OOPM 900 452410 23 AWS Pumps 10/4/2009 11:OOPM 900 453760 23 AWS Pumps 10/4/2009 11:30PM 900 454434 23 AWS Pumps 10/5/2009 6:30PM 0 454434 35 AWS Pumps 10/5/2009 12:OOAM 800 455484 22 AWS Pumps 10/5/2009 1:OOAM 900 456375 22 AWS Pumps 10/5/2009 2:OOAM 1000 458075 25 AWS Pumps 10/5/2009 3:OOAM 1000 459796 25 AWS Pumps 10/5/2009 4:OOAM 1000 461149 20 AWS Pumps 10/5/2009 5:OOAM 1000 461438 18 AWS Pumps 10/6/2009 12:OOAM 900 461438 20 AWS Pumps 10/6/2009 1:OOAM 950 462438 20 AWS Pumps 10/6/2009 4:OOAM 800 462438 22 AWS Pumps 10/6/2009 5:OOAM 800 463083 22 AWS Pumps 10/6/2009 6:OOAM 900 464403 22 AWS Pumps 10/6/2009 7:OOAM 1000 465910 22 AWS Pumps 10/6/2009 8:OOAM 1000 467258 22 AWS Pumps 10/6/2009 11:OOPM 1000 468513 20 AWS Pumps 10/7/2009 12:OOAM 1000 469687 20 AWS Pumps 10/7/2009 4:30AM 900 469687 20 AWS Pumps 10/7/2009 5:30AM 1050 470509 20 AWS Pumps 10/7/2009 5:OOPM 975 471885 20 AWS Pumps 10/7/2009 6:OOPM 1000 472766 22 AWS Pumps 10/7/2009 6:15PM 1000 472766 32 AWS Pumps 10/7/2009 7:OOPM 1000 474866 35 AWS Pumps 10/7/2009 8:OOPM 1050 476366 20 AWS Pumps 10/7/2009 9:OOPM 1050 478166 30 AWS Pumps 10/7/2009 10:OOPM 1050 478947 15 AWS Pumps 10/8/2009 5:OOAM 1050 478947 30 AWS Pumps 10/8/2009 5:30AM 1050 480202 35 AWS Pumps 10/8/2009 3:45AM 975 480355 30 AWS Pumps 10/8/2009 2:45PM 1000 481755 32 AWS Pumps 10/8/2009 3:45PM 1000 483576 32 AWS Pumps 10/8/2009 4:45PM 1075 484276 32 AWS Pumps 10/8/2009 5:45PM 1100 485766 30 AWS Pumps 10/8/2009 6:OOPM 1050 485766 30 AWS Pumps 10/8/2009 7:OOPM 1050 487566 30 AWS Pumps 10/8/2009 8:OOPM 1050 488332 28 AWS Pumps 10/8/2009 8:15PM 1050 488523 28 JAWS Pumps 10/9/2009 3:OOAM 900 488523 20 JAWS Pumps Aspen Injection History Appendix A July 7, 2009 to June 30, 2010 Page 2 of 12 • • Date Time u ing Pressure psig Total Volume (gal) Flow Rate Comments 10/9/2009 4:OOAM 1100 489794 22 AWS Pumps 10/9/2009 1:00PM 925 1 489850 27 AWS Pumps 10/9/2009 2:OOPM 1000 491152 27 AWS Pumps 10/9/2009 3:OOPM 1050 492497 25 AWS Pumps 10/9/2009 3:15PM 1050 493059 27 AWS Pumps 10/9/2009 6:30PM 1000 493059 25 AWS Pumps 10/9/2009 7:OOPM 1000 493624 25 AWS Pumps 10/9/2009 8:OOPM 1050 494848 25 AWS Pumps 10/9/2009 9:OOPM 1050 496133 25 AWS Pumps 10/9/2009 10:OOPM 1050 497365 25 AWS Pumps 10/9/2009 11:30PM 1050 498637 25 AWS Pumps 10/10/2009 4:30AM 1000 498637 25 AWS Pumps 10/10/2009 5:OOAM 1000 498841 10 AWS Pumps 10/10/2009 8:OOPM 1100 498841 32 AWS Pumps 10/10/2009 9:OOPM 1100 500873 32 AWS Pumps 10/10/2009 10:OOPM 1100 502399 32 AWS Pumps 10/10/2009 10:15PM 1100 502901 32 AWS Pumps 10/11/2009 12:OOPM 1000 502901 32 AWS Pumps 10/11/2009 1:OOPM 1000 - 32 AWS Pumps 10/11/2009 2:OOPM 1000 - 32 AWS Pumps 10/11/2009 3:OOPM 1100 504242 25 AWS Pumps 10/11/2009 4:OOPM 1100 505695 25 AWS Pumps 10/11/2009 5:OOPM 1050 507518 30 AWS Pumps 10/11/2009 6:OOPM 1050 507518 30 AWS Pumps 10/11/2009 6:30PM 1000 507566 38 AWS Pumps 10/11/2009 7:OOPM 1050 508359 32 AWS Pumps 10/11/2009 8:OOPM 1100 509859 25 AWS Pumps 10/11/2009 9:OOPM 1100 511661 25 AWS Pumps 10/11/2009 10:OOPM 1050 513977 25 AWS Pumps 10/11/2009 11:OOPM 1100 515077 30 AWS Pumps 10/11/2009 11:20PM 1100 515406 30 AWS Pumps 10/12/2009 1:30PM 1100 515406 24 AWS Pumps 10/12/2009 2:30PM 1100 518793 25 AWS Pumps 10/12/2009 4:OOPM 1100 - 25 AWS Pumps 10/12/2009 5:OOPM 1100 520792 17 AWS Pumps 10/12/2009 6:OOPM 1050 522167 20 AWS Pumps 10/12/2009 7:OOPM 1100 523287 25 AWS Pumps 10/12/2009 8:OOPM 1050 524505 22 AWS Pumps 10/12/2009 9:OOPM 1100 526797 25 AWS Pumps 10/12/2009 10:OOPM 1100 527449 25 AWS Pumps 10/12/2009 11:00PM 1100 528710 25 AWS Pumps 10/13/2009 12:30PM 1000 528821 25 AWS Pumps 10/13/2009 1:30PM 1100 530762 25 AWS Pumps 10/13/2009 2:30PM 1100 531713 25 AWS Pumps 10/13/2009 3:30PM 1100 533098 22 AWS Pumps 10/13/2009 4:30PM 1100 534084 22 AWS Pumps 10/13/2009 5:30PM 1100 535152 22 AWS Pumps 10/13/2009 6:OOPM 1050 535665 22 AWS Pumps 10/13/2009 7:OOPM 1050 536737 22 AWS Pumps 10/13/2009 8:OOPM 1025 538181 20 AWS Pumps 10/13/2009 9:OOPM 1100 538933 20 AWS Pumps 10/13/2009 10:OOPM 1000 539974 20 AWS Pumps Appendix A Page 3 of 12 Aspen Injection History July 7, 2009 to June 30, 2010 Date Time Tubing Pressure psig o a Volume (gal) Flow Rate Comments 10/13/2009 4:50AM 900 539974 6 AWS Pumps 10/13/2009 5:OOAM 900 539999 6 AWS Pumps 10/14/2009 3:OOPM 1125 535999 22 AWS Pumps 10/14/2009 4:OOPM 1125 541817 20 AWS Pumps 10/14/2009 5:OOPM 1100 542989 22 AWS Pumps 10/14/2009 6:OOPM 1100 544468 22 AWS Pumps 10/14/2009 7:OOPM 1050 545249 22 AWS Pumps 10/14/2009 8:OOPM 1100 546802 22 AWS Pumps 10/14/2009 8:30PM 1100 546869 22 AWS Pumps 10/14/2009 10:OOPM 1100 546905 18 AWS Pumps 10/14/2009 11:OOPM 1100 548772 20 AWS Pumps 10/15/2009 12:OOAM 1050 550185 25 AWS Pumps 10/15/2009 4:OOPM 1050 550185 20 AWS Pumps 10/15/2009 5:OOPM 1100 551610 20 AWS Pumps 10/15/2009 5:30PM 1100 552150 18 AWS Pumps 10/15/2009 8:OOPM 1050 552257 22 AWS Pumps 10/15/2009 9:OOPM 1050 553435 22 AWS Pumps 10/15/2009 10:OOPM 1100 554928 22 AWS Pumps 10/15/2009 11:OOPM 1100 556227 22 AWS Pumps 10/15/2009 12:OOAM 1100 557212 22 AWS Pumps 10/16/2009 2:30PM 1150 557212 22 AWS Pumps 10/16/2009 3:30PM 1100 559368 22 AWS Pumps 10/16/2009 4:30PM 1100 559368 22 AWS Pumps 10/16/2009 6:OOPM 1150 560251 22 AWS Pumps 10/16/2009 9:OOPM 1150 560251 25 AWS Pumps 10/16/2009 10:OOPM 1100 561697 22 AWS Pumps 10/16/2009 11:OOPM 1150 563031 22 AWS Pumps 10/16/2009 12:OOPM 1150 565415 22 AWS Pumps 10/17/2009 1:OOAM 1000 565927 22 AWS Pumps 10/17/2009 3:OOPM 1150 565927 28 AWS Pumps 10/17/2009 4:OOPM 1200 567777 26 AWS Pumps 10/17/2009 5:OOPM 1150 569229 22 AWS Pumps 10/17/2009 6:OOPM 1150 570124 20 AWS Pumps 10/17/2009 7:OOPM 1150 572267 20 AWS Pumps 10/17/2009 8:OOPM 1200 573075 25 AWS Pumps 10/17/2009 9:OOPM 1225 575298 25 AWS Pumps 10/17/2009 10:OOPM 1000 576775 25 AWS Pumps 10/18/2009 2:OOPM 1100 576775 20 AWS Pumps 10/18/2009 3:OOPM 1150 577806 22 AWS Pumps 10/18/2009 4:OOPM 1150 578837 22 AWS Pumps 10/18/2009 5:OOPM 1150 579869 22 AWS Pumps 10/18/2009 6:OOPM 1150 580875 22 AWS Pumps 10/18/2009 7:OOPM 1200 583546 35 AWS Pumps 10/18/2009 8:OOPM 1200 585007 35 AWS Pumps 10/18/2009 9:OOPM 1200 587287 35 AWS Pumps 10/18/2009 10:OOPM 1150 590529 35 AWS Pumps 10/18/2009 11:OOPM 1200 591350 40 AWS Pumps 10/18/2009 12:OOAM 1200 593626 40 AWS Pumps 10/19/2009 12:30AM 1200 594972 40 AWS Pumps 10/19/2009 3:15AM 1200 594972 35 AWS Pumps 10/19/2009 4:OOAM 1175 596898 35 AWS Pumps 10/19/2009 5:OOAM 1200 599830 35 AWS Pumps Appendix A Page 4 of 12 Aspen Injection History July 7, 2009 to June 30, 2010 Date Time Tubing Pressure psig Total Volume (gal) Flow Rate Comments 10/19/2009 6:OOAM 1200 600480 35 AWS Pumps 10/19/2009 7:OOAM 1150 601882 20 AWS Pumps 10/19/2009 8:OOAM 1150 602857 22 AWS Pumps 10/19/2009 9:OOAM 1150 603832 22 AWS Pumps 10/19/2009 10:OOAM 1200 605077 30 AWS Pumps 10/19/2009 11:OOAM 1200 606322 30 AWS Pumps 10/19/2009 12:OOPM 1250 607567 40 AWS Pumps 10/19/2009 1:OOPM 1250 608812 40 AWS Pumps 10/19/2009 2:OOPM 1225 612669 40 AWS Pumps 10/19/2009 3:OOPM 1225 614983 38 AWS Pumps 10/19/2009 4:OOPM 1225 616499 38 AWS Pumps 10/19/2009 5:OOPM 1225 618015 38 AWS Pumps 10/19/2009 6:OOPM 1225 619542 38 AWS Pumps 10/19/2009 7:OOPM 1225 623454 35 AWS Pumps 10/19/2009 8:OOPM 1250 624172 40 AWS Pumps 10/19/2009 9:OOPM 1250 626026 40 AWS Pumps 10/19/2009 9:30PM 1250 626026 40 AWS Pumps 10/19/2009 10:OOPM 1250 627770 40 AWS Pumps 10/19/2009 11:OOPM 1250 630267 40 AWS Pumps 10/20/2009 2:30PM 1200 630267 40 AWS Pumps 10/20/2009 3:30PM 1200 632467 38 AWS Pumps 10/20/2009 4:30PM 1200 634667 40 AWS Pumps 10/20/2009 5:30PM 1250 637265 40 AWS Pumps 10/20/2009 6:OOPM 1250 637892 38 AWS Pumps 10/20/2009 6:30PM 1250 638870 38 AWS Pumps 10/20/2009 8:OOPM 1250 638870 40 AWS Pumps 10/20/2009 9:OOPM 1250 642315 40 AWS Pumps 10/20/2009 10:OOPM 1250 643817 40 AWS Pumps 10/20/2009 11:OOPM 1250 646467 40 AWS Pumps 10/21/2009 12:OOPM 1275 648099 40 AWS Pumps 10/21/2009 1:OOAM 1150 649396 40 AWS Pumps 10/21/2009 2:30PM 1200 649396 35 AWS Pumps 10/21/2009 3:30PM 1200 651923 35 AWS Pumps 10/21/2009 4:30PM 1200 653973 36 AWS Pumps 10/21/2009 5:30PM 1200 655689 36 AWS Pumps 10/21/2009 6:OOPM 1225 657124 36 AWS Pumps 10/21/2009 7:OOPM 1250 658976 36 AWS Pumps 10/21/2009 8:OOPM 1200 660333 36 AWS Pumps 10/21/2009 9:OOPM 1225 662700 36 AWS Pumps 10/21/2009 10:OOPM 1250 664154 36 AWS Pumps 10/21/2009 11:OOPM 1250 666729 36 AWS Pumps 10/22/2009 12:OOPM 1250 668202 36 AWS Pumps 10/22/2009 3:30AM 1200 668291 36 AWS Pumps 10/22/2009 4:30AM 1200 676000 36 AWS Pumps 10/22/2009 5:30AM 1200 671605 36 AWS Pumps 10/22/2009 9:30AM 1250 671605 34 AWS Pumps 10/22/2009 10:30AM 1150 673505 30 AWS Pumps 10/22/2009 11:30AM 1175 675528 32 AWS Pumps 10/22/2009 1:30PM 1125 675528 34 AWS Pumps 10/22/2009 2:30PM 1175 677567 34 AWS Pumps 10/22/2009 3:30PM 1175 1 679433 1 34 1AWS Pumps 10/22/2009 4:30PM 1175 1 681037 34 JAWS Pumps Appendix A Page 5 of 12 Aspen Injection History July 7, 2009 to June 30, 2010 • • Date Time Tubing Pressure Psig o a Volume (gal) Flow Rate Comments 10/23/2009 12:OOAM 1125 681037 24 AWS Pumps 10/23/2009 1:OOAM 1125 682642 26 AWS Pumps 10/23/2009 1:30AM 1125 683214 26 AWS Pumps 10/23/2009 2:OOPM 1150 683214 24 AWS Pumps 10/23/2009 3:OOPM 1200 684934 34 AWS Pumps 10/23/2009 4:OOPM 1200 686853 34 AWS Pumps 10/23/2009 5:OOPM 1200 688678 34 AWS Pumps 10/23/2009 5:30PM 1200 689903 34 AWS Pumps 10/23/2009 11:00PM 1150 689903 28 AWS Pumps 10/24/2009 12:OOAM 1150 691237 28 AWS Pumps 10/24/2009 1:OOAM 1150 692602 25 AWS Pumps 10/24/2009 1:30AM 1150 692867 25 AWS Pumps 10/24/2009 1:30PM 1050 692867 25 AWS Pumps 10/24/2009 2:30PM 1075 694171 28 AWS Pumps 10/24/2009 3:30PM 1150 695852 28 AWS Pumps 10/24/2009 4:30PM 1125 696953 25 AWS Pumps 10/24/2009 5:30PM 1125 698310 25 AWS Pumps 10/24/2009 6:30PM 1125 699815 25 AWS Pumps 10/24/2009 7:30PM 1125 700898 25 AWS Pumps 10/24/2009 8:30PM 1125 702368 25 AWS Pumps 10/24/2009 9:30PM 1125 702897 20 AWS Pumps 10/24/2009 10:OOPM 1125 703036 18 AWS Pumps 10/25/2009 4:30AM 1050 703036 19 AWS Pumps 10/25/2009 5:30AM 1100 704139 19 AWS Pumps 10/25/2009 6:OOAM 1100 704302 15 AWS Pumps 10/25/2009 3:30PM 1100 704302 15 AWS Pumps 10/25/2009 4:30PM 1050 705263 18 AWS Pumps 10/25/2009 5:30PM 1050 706182 18 AWS Pumps 10/26/2009 1:OOAM 1025 706182 18 AWS Pumps 10/26/2009 2:OOAM 1150 707866 15 AWS Pumps 10/26/2009 3:OOAM 1150 707866 15 AWS Pumps 10/26/2009 4:OOAM 1150 708690 15 AWS Pumps 10/26/2009 5:OOAM 1150 709404 18 AWS Pumps 10/26/2009 5:30AM 1025 710027 18 AWS Pumps 10/26/2009 9:OOAM 1025 710027 15 AWS Pumps 10/26/2009 10:OOAM 1075 711085 22 AWS Pumps 10/26/2009 11:OOAM 1075 713160 26 AWS Pumps 10/26/2009 12:OOPM 1075 714938 28 AWS Pumps 10/26/2009 1:OOPM 1050 715508 26 AWS Pumps 10/26/2009 2:OOPM 1100 717603 28 AWS Pumps 10/26/2009 3:OOPM 1100 719624 28 AWS Pumps 10/26/2009 4:OOPM 1075 721154 28 AWS Pumps 10/26/2009 5:OOPM 1100 724091 30 AWS Pumps 10/26/2009 6:06PM 1100 725587 30 AWS Pumps 10/26/2009 6:OOPM 1100 725587 30 AWS Pumps 10/26/2009 8:OOPM 1050 725587 25 AWS Pumps 10/26/2009 9:OOPM 1100 727176 25 AWS'Pumps 10/26/2009 10:OOPM 1100 727742 15 AWS Pumps 10/26/2009 11:OOPM 1100 728356 22 AWS Pumps 10/27/2009 11:OOAM 1150 728356 30 AWS Pumps 10/27/2009 12:OOPM 1150 729954 38 JAWS Pumps 10/27/2009 1:OOPM 1150 1 732387 35 AWS Pumps Appendix A Page 6 of 12 Aspen Injection History July 7, 2009 to June 30, 2010 • 0 Date Time Tubing Pressure psig o a Volume (gal) Flow Rate Comments 10/27/2009 1:30PM 1150 733383 35 AWS Pumps 10/27/2009 4:OOPM 1050 733383 22 AWS Pumps 10/27/2009 5:OOPM 1125 734774 34 AWS Pumps 10/27/2009 6:OOPM 1150 736575 36 AWS Pumps 10/28/2009 8:OOAM 1125 736575 34 AWS Pumps 10/28/2009 9:OOAM 1125 738992 32 AWS Pumps 10/28/2009 10:OOAM 1125 741408 34 AWS Pumps 10/28/2009 11:OOAM 1100 743373 32 AWS Pumps 10/28/2009 2:OOPM 1050 743373 28 AWS Pumps 10/28/2009 3:OOPM 1050 744504 24 AWS Pumps 10/28/2009 4:OOPM 1050 745625 22 AWS Pumps 10/28/2009 5:OOPM 1050 746973 24 AWS Pumps 10/28/2009 6:OOPM 1050 748083 24 AWS Pumps 10/29/2009 7:OOAM 1150 748083 34 AWS Pumps 10/29/2009 8:OOAM 1175 749373 36 AWS Pumps 10/29/2009 9:OOAM 1150 750872 34 AWS Pumps 10/29/2009 10:OOAM 1150 753899 38 AWS Pumps 10/29/2009 11:OOAM 1150 755463 38 AWS Pumps 10/30/2009 6:30AM 1050 755463 26 AWS Pumps 10/30/2009 7:30AM 1125 757011 34 AWS Pumps 10/30/2009 8:30AM 1100 759089 36 AWS Pumps 10/30/2009 9:30AM 1100 761606 36 AWS Pumps 10/30/2009 10:30AM 1025 762789 18 AWS Pumps 10/30/2009 1:OOPM 1000 762789 16 AWS Pumps 10/30/2009 2:OOPM 1000 763901 16 AWS Pumps 10/30/2009 3:OOPM 1150 764980 38 AWS Pumps 10/30/2009 4:OOPM 1150 765945 34 AWS Pumps 10/30/2009 5:OOPM 1150 769136 38 AWS Pumps 10/31/2009 10:OOAM 1050 769136 8 AWS Pumps 10/31/2009 11:OOAM 1050 769761 22 AWS Pumps 10/31/2009 12:OOAM 1050 772045 28 AWS Pumps 10/31/2009 1:OOPM 1050 773983 28 AWS Pumps 10/31/2009 2:OOPM 1100 774683 26 AWS Pumps 10/31/2009 3:OOPM 1050 775337 34 AWS Pumps 10/31/2009 4:OOPM 1050 777767 28 AWS Pumps 10/31/2009 5:OOPM 1050 779568 32 AWS Pumps 10/31/2009 5:30PM 1050 780537 32 AWS Pumps 11/1/2009 0 no reading 11 /2/2009 1050 794194 24 11/3/2009 0 no reading 11 /4/2009 740 801758 5.5 11 /5/2009 0 no reading 11/6/2009 0 no reading 11 /7/2009 680 0 11 /8/2009 680 801758 0 11/9/2009 0 no reading 11/10/2009 0 no reading 11/11/2009 0 no reading 11/12/2009 0 no reading 11/13/2009 0 no reading 11/14/2009 0 no reading 11/15/2009 0 no reading Appendix A Page 7 of 12 Aspen Injection History July 7, 2009 to June 30, 2010 • 0 Date Time Tubing Pressure psig o a Volume (gal) Flow Rate Comments 11 /16/2009 540 0 11 /17/2009 530 0 11 /18/2009 520 0 11 /19/2009 510 0 11 /20/2009 500 0 11 /21 /2009 500 0 11 /22/2009 480 0 11 /23/2009 480 0 11 /24/2009 460 0 11 /25/2009 460 801758 0 11 /26/2009 925 807342 5.6 11 /27/2009 460 0 11 /28/2009 440 0 11 /29/2009 430 807311 5.6 11/30/2009 0 no reading 12/1/2009 0 no reading 12/2/2009 0 no reading 12/3/2009 0 no reading 12/4/2009 1015 400 807311 0 12/5/2009 1100 800 808133 5.1 12/6/2009 1000 400 812980 0 12/7/2009 900 380 812980 0 12/8/2009 1000 370 812980 0 12/9/2009 930 480 812991 3 12/10/2009 1130 480 813005 3 12/11 /2009 1130 800 813005 4.2 12/12/2009 1030 380 813005 0 12/13/2009 1200 360 813005 0 12/14/2009 945 340 813005 0 12/15/2009 1045 330 813005 0 12/16/2009 1000 330 813005 0 12/17/2009 1030 330 813005 0 12/18/2009 no reading 12/19/2009 1020 400 813005 0 12/20/2009 1015 340 815562 6 12/21 /2009 1000 360 818152 6 12/22/2009 950 800 818195 6 12/23/2009 1020 320 822024 6 12/24/2009 950 300 822024 0 12/25/2009 330 300 822024 0 12/26/2009 930 360 826244 6 12/27/2009 1025 340 826244 0 12/28/2009 1045 320 826244 0 12/29/2009 1030 310 826244 0 12/30/2009 1020 390 831418 6 12/31 /2009 1030 560 834133 6 1 /1 /2010 9:55 380 838723 0 1 /2/2010 19:00 310 838723 0 1 /3/2010 10:30 300 838723 0 1 /4/2010 10:30 300 838723 0 1 /5/2010 6:30 290 838723 0 1 /6/2010 12:00 280 8387231 0 Appendix A Page 8 of 12 Aspen Injection History July 7, 2009 to June 30, 2010 Date Time Tubing Pressure psig o a Volume (gal) Flow Rate Comments 1 /7/2010 10:30 260 838723 0 1 /8/2010 10:30 260 838723 0 1 /9/2010 11:00 260 838723 0 1 /10/2010 10:15 250 838723 0 1 /11 /2010 11:00 250 838723 0 1 /12/2010 9:30 240 838723 0 1 /13/2010 11:00 240 844531 0 1/14/2010 10:45 300 844531 0 1 /15/2010 11:10 280 844531 0 1 /16/2010 8:59 280 844531 0 1 /17/2010 8:07 260 844531 0 1/18/2010 10:06 260 844531 0 1 /19/2010 9:55 260 844531 0 1 /20/2010 10:25 240 844531 0 1 /21 /2010 9:30 800 849209 11.8 1 /22/2010 9:45 270 849560 0 1 /23/2010 10:05 250 849875 0 1 /24/2010 10:30 260 850159 0 1 /25/2010 9:35 240 850159 0 1 /26/2010 9:25 370 856122 0 1 /27/2010 9:10 300 856122 0 1 /28/2010 10:00 280 856122 0 1 /29/2010 9:30 260 856122 0 1 /30/2010 115 250 856122 0 1 /31 /2010 1145 240 856122 0 2/1/2010 1030 am 240 856122 0 2/2/2010 835 am 240 856122 0 2/3/2010 830 am 230 856122 0 2/4/2010 1045 am 230 856127 6 2/5/2010 1030 am 230 856127 0 2/6/2010 930 am 220 856127 0 2/7/2010 1000 am 220 856127 0 2/8/2010 930 am 220 856127 0 2/9/2010 600 am 220 856127 0 2/10/2010 845 am 220 856127 0 2/11 /2010 900am 220 856127 0 2/12/2010 615 pm 330 861383 6 2/13/2010 930 am 240 861383 0 2/14/2010 1015 am 220 861383 0 2/15/2010 1030 am 220 861383 0 2/16/2010 1140 am 210 861383 0 2/17/2010 557 pm 200 861383 0 2/18/2010 923 am 200 861383 0 2/19/2010 922 am 200 861383 0 2/20/2010 942 am 190 861383 0 2/21 /2010 1123 am 190 861383 0 2/22/2010 935 am 180 861383 0 2/23/2010 200 pm 180 861383 0 2/24/2010 845 am 180 861383 0 2/25/2010 1014 am 260 866408 6 2/26/2010 1030 am 1 2401 866408 0 2/27/2010 700 am 1 2101 8664081 0 Appendix A Page 9 of 12 Aspen Injection History July 7, 2009 to June 30, 2010 0 Date Time Tubing Pressure psig o a Volume (gal) Flow Rate Comments 2/28/2010 1105 am 200 866408 0 3/1 /2010 10:05 190 866408 0 3/2/2010 10:00 180 866408 0 3/3/2010 1140 am 180 866408 12.2 3/4/2010 12:50 220 869700 12.2 3/5/2010 9:30 270 874930 0 3/6/2010 10:15 230 874930 0 3/7/2010 9:50 220 874930 0 3/8/2010 10:25 210 874930 0 3/9/2010 11:30 200 874930 0 3/10/2010 13:45 190 874930 0 3/11 /2010 11:15 180 874930 0 3/12/2010 10:20 180 874930 0 3/13/2010 9:35 180 874930 0 3/14/2010 14:11 180 874930 0 3/15/2010 11:20am 180 874930 0 3/16/2010 9:53 180 874930 0 3/17/2010 9:15 180 874930 0 3/18/2010 9:15 300 880755 6.1 3/19/2010 10:00 250 880755 0 3/20/2010 9:30 200 880755 0 3/21/2010 12:00pm 250 880755 0 3/22/2010 10:30 180 880755 0 3/23/2010 1100am 170 880755 0 3/24/2010 1000am 170 880755 0 3/25/2010 900am 160 880755 0 3/26/2010 10:00 160 880755 0 3/27/2010 1035 am 2301 885963 6.2 3/28/2010 920 am 200 885963 0 3/29/2010 930am 180 885963 0 3/30/2010 1210 pm 160 885963 0 3/31 /2010 1100 am 160 885963 0 4/1/2010 435 pm 160 885963 0 4/2/2010 810 am 150 885963 6.2 4/3/2010 900am 190 888854 0 4/4/2010 945 am 160 888854 0 4/5/2010 105 pm 150 888854 0 4/6/2010 1000am 150 888854 0 4/7/2010 915 am 150 888854 6.2 . 4/8/2010 750 am 240 894030 0 4/9/2010 915 am 190 894030 0 4/10/2010 6.2 4/11 /2010 9:45 220 900092 0 4/12/2010 9:30 300 905640 6.2 4/13/2010 9:40 250 905640 0 4/14/2010 814 am 230 905640 0 4/15/2010 950am 210 905640 0 4/16/2010 915 am 200 905640 0 4/17/2010 936 am 200 905640 0 4/18/2010 945 am 200 905640 0 4/19/2010 1045am 200 905640 0 4/20/2010 830am 1901 9056401 0 Appendix A Page 10 of 12 Aspen Injection History July 7, 2009 to June 30, 2010 • • Date Time Tubing Pressure Psig o a Volume (gal) Flow Rate Comments 4/21 /2010 930 am 190 905640 0 4/22/2010 915 am 3201 911588 6.2 4/23/2010 902 am 580 917200 6.1 4/24/2010 851 am 250 917200 0 4/25/2010 905 am 210 917200 0 4/26/2010 955 am 200 917200 0 4/27/2010 900 am 190 917200 0 4/28/2010 1000 am 180 917200 0 4/29/2010 840 am 180 917200 0 4/30/2010 940 am 180 917200 0 5/1 /2010 830 am 180 917200 6.1 5/2/2010 135 pm 360 922914 0 5/3/2010 940 am 220 922914 0 5/4/2010 940 am 200 922914 0 5/5/2010 320 pm 200 922914 0 5/6/2010 915 am 200 922914 0 5/7/2010 1047 am 190 922914 0 5/8/2010 1020 am 190 922914 0 5/9/2010 1049 am 190 922914 0 5/10/2010 1100 am 180 922914 0 5/11 /2010 1000 am 180 922914 0 5/12/2010 180 922914 0 5/13/2010 1015 am 180 922914 0 5/14/2010 849 am 260 928642 6 5/15/2010 1030 am 270 934191 12 5/16/2010 800 am 800 939784 5.9 5/17/2010 913 am 830 948618 6 5/18/2010 923 am 440 954718 6 5/19/2010 909 am 320 954718 0 5/20/2010 915 am 440 959446 6 5/21 /2010 923 am 440 967890 12 5/22/2010 815 am 360 967890 0 5/23/2010 850 am 300 967890 12.1 5/24/2010 830 am 360 973930 12 5/25/2010 635 am 420 982212 12 5/26/2010 920 am 460 990517 0 5/27/2010 840 am 380 990517 0 5/28/2010 820 am 340 990517 0 5/29/2010 215pm 320 990517 0 5/30/2010 1030 am 300 990517 0 5/31 /2010 815 am 300 990517 0 6/1 /2010 7:05 280 990517 0 6/2/2010 14:09 260 990517 0 6/3/2010 11:06 240 990517 6/4/2010 9:21 360 996601 6 6/5/2010 10:33am 380 1002344 6 6/6/2010 300 1002344 0 6/7/2010 11:00am 290 1002344 0 6/8/2010 6/9/2010 9:00 260 1002344 0 6/10/2010 9:38am 1 540 1008294 6 6/11 /2010 8:41 am 1 2801 1008294 0 Appendix A Page 11 of 12 Aspen Injection History July 7, 2009 to June 30, 2010 Date Time Tubing Pressure psig o a Volume (gal) Flow Rate Comments 6/12/2010 10:24am 260 1008294 0 6/13/2010 320 1012966 6 6/14/2010 260 1012966 0 6/15/2010 260 1012966 0 6/16/2010 250 1012966 0 6/17/2010 737 1017704 6 6/18/2010 10:00:00 314 1017704 0 6/19/2010 1017704 0 6/20/2010 1017704 0 6/21 /2010 1017704 0 6/22/2010 15:50:00 248 1017704 0 6/23/2010 10:00:00 210 1017704 0 6/24/2010 10:00:00 204 1017704 0 6/25/2010 10:00:00 199 1017704 0 6/26/2010 7:00:00 702 1021112 6 6/27/2010 10:00:00 218 1021112 0 6/28/2010 10:00:00 205 1021112 0 6/29/2010 10:00:00 197 1021112 0 6/30/201 Or 10:00:00 191 10211121 0 Aspen Injection History Appendix A July 7, 2009 to June 30, 2010 Page 12 of 12 • 0 Attachment B Reservoir Analysis by Nutech, June 2010 "ror-D.N. ..... .- ... ... . ..? . .. As.sessmen of Fracture Geometry .. ........................................... . ......................................... .............................................. F,arri /r ctiv�t ................................................................................. September 2009 June AM' 0 ....................................................................................................................... Pr oJ # 364 6 June 25 2010 ...............................................................,...............,...................... .......................................................................................... The following report is based on sound engineering practices, but because of variable well conditions and other information which must be relied upon, Nu Tech Energy Alliance makes no warranty, express or implied, as to the accuracy of the data or of any calculations or opinions expressed herein. You agree that Nu Tech Energy Alliance shall not be liable for any loss or damage whether due to negligence or otherwise arising out of or in connection with such data calculations or opinions. Scope of Project Two zones in the Aspen #1 well are open for use as disposal injection zones. • Recent injection data has been provided to NuTech in order to model the injections and determine what the created fracture dimensions are and what zones have been influenced by the injected fluids. • In order to accomplish this, a NuPro fracture simulation has been performed on the injection zones utilizing the reservoir petrophysical and geomechanical characteristics previously identified and summarized in the `Analysis of Injection Project' report dated August 8, 2007. • This analysis is designed to meet the requirements defined by the Alaska Oil and Gas Conservation Commission. ��NuTeth�.� Project Methodology -2 • Reservoir Description r • The NuLook analysis dated 8/18/2005 provides a petrophysical description of the reservoir and it's properties. This includes (but not limited to) the porosity, permeability, texture, lithology and water saturation. • The NuStim process is used to create a reservoir and injection model with emphasis on the NuLook analysis. This process will utilize the NuLook processed data to determine additional geomechanical reservoir properties such as Young's modulus, Poisson's ratio and a stress profile. • In this case sonic data is also available and is used in calculating the rock properties. This data was used in order to build a calibrated geomechanical model that will enable the prediction of rock properties for other wells in the field with which sonic data was not provided. • Injection Performance and Fracture Characteristics • The NuStim model is then used to predict the characteristics of the actual injection into these intervals. 'N 1, (WROYUUAW NuStim Process Yporatioii of FVeld P;�ra�yu�ter5i:: oe Input ':: !l9E9�7l i6iliiEE. 6l E6ige ::gpM....ma R!...... tmoler,:.. iadisiEilir'l6rie'mIEEEIEo#3iiuEi�3e ii .Rm#9iE!!3<x!6!lEeEiiiii ii!!6lIEEEEE#lE�E3iEEHEliig "iiliiBt" "iKEgeeEaeiEeE ee sm• >o ss2N.si?iiEms iiiEliiEEl93i;li3f..:EdEafiiEE#i ii�g36iiE;'lEEEEeEEii>~9s izi2igeiieiEagEsioiEEem6iie" saii9Ee i�. iic6igri+igeiiieie36ie'x7ie ..... ... ... ... ... ... ... ..... ....... ..... ,... :•: 7]: ::: ::: :[:. A AV mom: q"�'fl II A ••••� -��� �� PROCESS OBJECT/ VEI ................. ................ II A�s� s s s�A i sssiAAzlii: ................. ............ t,.. s .. a= .. :. ; ..... , ..II.,..A.,, :gA;. IIz gA:. z,..a• IIII a c Y"If "`. ........... Establish the Link Between a Consisten ... ....... :iff ..... Reservoir Eva/cation and Well Comp/ x i Results for a Field., top vismn 1 It HU,g`:53i'= xEyiuoiaiil� l .:eeell =:: qq. :::::�iilsii':BBe6�:c:iiaiira"E°... ...........,....ee...................................... :� :::::::::.. ................ fM 0 T17 I Performance Visto .. V. pplicable when completion opts ry wr ry objectid rigNNUNNUMMIN :11 .... ..,:.... .; • Provides analysis of past completicirs :_ "'" LaQ,:k, v M. 9 N: x, ............ . ............................................... t- Decline curve analysis ....................................N. ... _ ., Production history matching Fractu re e pressur e matching —Incorporation of well test and tracer /production"logs """"""" — Is the observed production response due to reservoir or completion? Ilk • NuStim process calibration for a new field • Project remaining reserves 5 nrujro moo 1. It! XturtI 1 11 acK jwrocess I F7elA Par:rmOTE voir Description _ ' ...:_. . T x ural Re ry T NuLook evaluation process- provides a nlWhlized a irnd .. consistedFireservoir description, enabling the NuStimT'" process calibration sets to be predictive. The key components of the NuLookTM process include: log norrimUzation, clay volume and lithology determination, textural permeability distribution, and bound and free fluid identification ::: S e r Se v weeS w .. .. etrophysica/Ana/ysis; ;1—nt 6 i; Va7 nNNNnNIINN7 IUIP.NiuVIN1IUINNNNNnCNNNiI.ii.ii 7....0 'IIII Nwrnru.iri nninnueemlrurw�rw..rnnnno �� i......I NwuErwrurr� " nuiruriuwn■oNNNNrwEawnueun111umSEES.. 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LAU11111112-0 ......... ....... ck Prope process incorporates a well -specific rock properties log, defined at six inch resolution, by which the fracture behavior is governed. These properties are calibrated to measured data, including: fracture and NuFIT TM analysis, tracer logs, microseismic fracture maDDinn,--and-nmduction history matching. ........... mom Od .................... ............ NNNN:N!", .... ...... . .............. ..... ..... ............. . .................................................................... LM . ..... ......... ....................... . ......................... I H. ......................... s!!J. ... � ......... ................................................. ...... ... in -UNN: ..................... ........................... munn., ........ .. . . .. . .......... ............ Geomechanica ode/ - Interva GROSS TOTAL IN -SITU FRAC Stage TOP DEPTH BOTTOM EFT POR- BHTP YM GRAD - Stage Name (FT) DEPTH (FT) HEIGHT NET PAY OSITY (%) (PSI) STRESS BHST (°F) (10, PSI) PERM {MD) SW BHP (PSI) TENT (FT) (FT) (PSI) 10 ;31 VIS zm 5-11 I'Mi. ot"W3 wiJIMM :.A. ISM }Mss % W."y WWI CIA P r 10 1 0 M cce o 111J 10.0 D IM 1:CT.CX .0 CI 1. rLC PESf I CAJF., I s POU 9HE Dori, N -.b u 6 b c ;o I UJIIA'k I Jt ckc W :01.0 Jd 1 3Ini Me jv IIAS %44w ot NBC a q Pi Pc M FI —2:1-- ctc RC I'LA: LAACE ell I K1 IlAn 0 ok*Af VIO t.t4 IC041 0 6 OE. Phil 0A, C' MAO S%tU.L PLOW.- rt MUM I C 1,; C,,kL I 'Merval 2 1 2,122.0 1 2148.5 1 26.5 1 23.00 1 24.88 1 1,929 1 1,754 1 88.3 1 0.70 1 0.6003 1 0.69 1 1,025 0.902 Nv j. Nu�L ie 0 Top Depth Bottom (ff) Depth (ft) 2100 2101.5 2102 2102.5 2103 2103.5 2104 2104.5 2105 2105.5 2106 2106.5 2107 2111.5 2112 2121.5 2122 2125.5 1_ 2126 2127.5 �►I' 2128 2129.5 2130 2130.5 21311 2131.5 21315 2135.5 2137.5 2138.5 2139.5 2141.5 2143.5 2145.5 r 2146 2147.5 _ 2148 2148.5 2149 2157.5 2158 2175.5 217E 2176.5 2177 2177.5 2178 2179.5 2180 2180.5 2181 2181.5 2182 2193.5 2194 2195.5 219E 2227.5 2320 2347.5 2348 2349.5 2350 2352.5 2353 2353.5 2354 2354.5 2355 2356.5 2357 2361.5 2362 2364.5 2365 2365.5 2366 2369.5 2370 2371.5 2372 2375.5 2376 2385.5 2386 2387.5 2389 2390.5 2391 2391.5 #' 2392 2392.5 - 2393 2393.5 2394 2399.5 2400 2402.5 2403 2421.5 Nu Gross Interval (ft) Net Interval (ff) Effective Porosity W Sw NuPerm (md) BHT ('F) YM (e6) PR BHP (psi) Stress (psi) Stress Gradient (psi/ft) BHTP (psi) Frac Gradient (psi/ft) Rock Embedment Strength (psi) Specific Gravity Specific Heat Thermal Conductivity 2 1.5 22.75 0.83 1.606 88.1 0.5803 0.395 1008 1766 0.841 1943 0.925 80412 2,270075 0.247103 2.23467 1 1 24.57 0.81 2.739 88.1 0.6553 0.373 1009 1716 0.816 1888 0.898 80412 2.2753 0.249372 2.293669 1 1 26.51 0,65 22.9332 88.1 0.6359 0.369 1010 1706 0.811 1877 0.892 80004 2.2436 0.254642 2,430699 1 1 25.02 0.74 6.0648 88.2 0.6625 0,372 1010 1717 0,816 1889 0.897 80000 2.2674 0.25424 2.420237 1 0 24.52 0.991 0.001 88.2 0.6861 0.369 10111 17111 0.813 1882 0.894 80072 2.2754 0.256003 2.466065 1 1 24.2 0.8 1.93215 88.2 0.6748 0.359 1011 1678 0397 1846 0,877 80148 2.2621 0.248376 2.267765 5 0.5 22.25 0.98 0.08427 88.2 0.6914 0.358 1012 1678 0.796 1846 0,875 81147 2.29847 0.247503 2,245081 30 1 21.95 0.98 0.07262 88.2 0.69 0.375 1016 1734 0.819 1908 0.901 81214 2.311665 0.247684 2.249781 4 4 23.55 0.73 3.6458 88.3 0.7304 0.369 1019 1731 0,815 1904 0.896 80000 2.29035 0.252916 2.385821 2 2 23.62 0.51 9.40215 88.3 0.7434 0.369 1021 1735 0.816 1908 0.897 79996 2.287625 0.250116 2.31301E 2 2 25.36 0.8 5.39772 88.3 0.732 0,357 1022 1706 0,802 1877 0.882 80050 2,263225 0.253112 2,390922 1 1 26.98 0.8 9.4512 88.3 0,7428 0.351 1023 1698 0.797 1867 0,877 80004 2.248 0.254987 2.439667 1 1 18.8 0.59 2.59895 88.3 1.2272 0.342 1023 1735 0.8141 1909 0,895 80000 23838 0.255032 2.440832 2 0.5 17.2 0.91 0.0392 89.3 1.4814 0.34 1024 1785 0.837 1963 0,921 80000 2.401625 0.257813 2.513138 2 1.5 28.95 0.83 14.86998 88.3 0.6935 0.369 1025 1751 0.82 1926 0.902 80002 2.202875 0.254744 2.433348 2 2 25.1 0.74 9.1801 88.4 0.6105 0.384 1026 1771 0.829 1948 6.912 80000 2.2688 0.257432 2.503232 1 1 27.38 0.68 22.5451 88.4 0.5483 0,391 1026 1788 0.836 1967 0.92 80000 2,2401 0.254627 2.430302 1 1 28.54 0.62 36.0125 88.4 0,5129 0.386 1027 1771 0.828 1949 0.911 80000 2.213 0.253526 2.401676 2 2 26.35 0.65 12.8497 88.4 0.5519 0.389 1028 1781 0.832 1959 0,915 80000 2.241925 0.253307 2.395982 2 2 25.08 0.64 10.65348 88.4 0.5925 0.385 1029 1775 0.828 1952 0.911 79996 2.266675 0.2543 2,421795 2 2 24.79 0.53 22.3802 88.4 0,6485 0.383 1029 1779 0.829 1956 0,912 80000 2.27655 0.255059 2,441531 2 0.5 2134 034 2.53713 88.4 0.7497 0.375 1030 1771 0.825 1948 0.907 79998 2,29965 0.255053 24441375 1 0.5 24.12 0.83 2.2625 88.4 0.6828 0.362 1031 1721 0.801 1893 0.881 80004 2.2926 0.250880 2,332889 9 0.5 8.2E 0.97 0..9901 88.5 0.6399 0.397 1034 1789 0.831 1967 0.914 31304 2.29485 0.217937 1.415263 18 0.5 30.23 0.99 0.02945 88.5 0.6645 0.393 1040 1797 0.829 197E 0.912 4482E 2.274442 0.223424 1.574578 1 0 16.14 0.8E 0. 44815 88.E 0.8761 0.389 3045 1841 0.84E 2025 0.93 80000 2.40595 0.244913 2.177738 1 0 14,9E 0.87 D.0393 86.E 0.9557 0.381 3045 1825 0.838 2008 0.922 80000 2.42655 0.245555 2.19443 2 0.5 14.87 017 0.07935 88.6 1.0583 0.363 1046 1785 0.819 1963 0.901 79998 2.4301 0.24707E 2.23396E 1 1 14.56 0,71 0.1066 88.6 1POS021 0.36 1047 1781 0.817422144 0.898 80000 2.435E 0.247037 2.232962 2.27399 2.286189 2.323521 2,231241 2.271424 2.185369 2.283054 2.262577 2.229494 1 0 14.27 0.79 0,0524 88.E 1.0902 0.357 1047 1050 1053 1062 1771 1913 1756 1770 0.812 0.874 0.8 0.8 0.826 0 83 0.819 0.81 0.797 2119 2096 2065 0.893 0.962 0.88 0.88 0.909 0.913 0.901 0.891 0.877 80000 80006 80000 80274 82394 80476 80503 80448 80272 2,4443 2.499463 2.30585 2.378805 2.30452E 2.3251 2.359417 2.3317 2.32865 0.248615 0.249084 0.25052 0.246971 014467 0.245207 0.248964 0.248176 0.246904 12 0.5 11.1 0.97 0.01979 88.7 88.7 88.8 2.0261 0.9113 1.1026 0.341 0.355 0,343 2 32 1.5 3.5 18.89 16.65 0.7E 0.95 0.5799 0410741 28 0 21.15 3 0.001 89.6 0.6748 0.385 1120 1928 2 0 20.2 0.99 0.0212 89.7 89.7 89.7 89.7 0.6569 0.8781 0.8907 0.881 0.39 0.372 0.363 0.356 1127 1129 1130 1130 1949 1927 1905 1877 3 0.5 19.25 0.9 0.18032 1 1 20.91 0.79 0.8893 0,93105 1 1 20.91 0.77 2 5 0 0 20.69 18 0.96 1 0.11708 0.001 0,05395 1.01175 4.96942 11.93875 0.33897 0.001 0.044 0.64298 0.5551 0.0884 0.6355 0.02771 0,03373 0.001 89.7 89.7 89PS1 89.8 89.8 89.8 89.8 89.9 89.9 89.9 89.9 90 90 90 901 90.1 0.8068 0.8793 1.0554 1.0607 0.9961 0.9186 0.8541 0.7165 0.6934 0.6911 0.7441 03876 0.7079 0.8652 0.9682 0.8762 0.354 0.37 0,348 0.335 0.333 0.334 0.329 0389 0.38 0376 0.366 0.359 0.364 0.382 0.352 0.356 1131 1132 1134 1135 1137 1138 1139 1143 1146 1147 1148 1148 11491 1150 1153 1158 1860 1919 1877 1842 1837 1835 1807 1952 1957 1941 1921 1910 19101 1974 1907 1913 0.789 0.813 0.794 0.779 0.776 0.774 0.761 0.82 0.82 0.813 0.804 0.798 0.7981 0.824 0.794 0.793 2046 2111 2065 2026 2021 2019 1987 2147 2153 2135 2114 2101 2101 2171 2098 2304 0.868 0.895 0.874 0.856 0.853 0,851 0.837 0.9D2 0.902 0.894 0.884 0,878 0.878 0.90E 0.874 0.872 81398 81090 80325 79996 79999 80002 80421 36498 81476 80376 80220 81640 80632 60093 803991 80376 2.336825 2.37805 2.395933 2.3765 2.335738 2.252475 2.294275 2.32153 2.3081 2,23975 2.29045 2.29745 2.2926 2.354583 2.3784 2.32745 0.241796 0.247671 0.251584 0.248047 0.253521 0.254132 0.246758 0.222217 0.243842 0.244564 0.251798 04249271 0.24458 0.23232E 0.2468. 0.241558 2.096703 2.249459 2.351193 2.259234 2.401537 2.417436 2.225712 1.532649 2.149881 2.16865E 2,356759 2.291055 2/169082 1.82548E 2.226791 2.090513 31 1 4 2 4 10 2 3 1 1 11 6 31 19 0 1 4 2 1 0 0 1 0.5 0 0.51 0 01 0 17.22 18.63 21.31 23.24 22.28 9.57 22.32 22.48 23.2 2314 23.4 12.7E 17.961 17.86 0.94 0.67 0.57 0.55 0.95 1 0.98 0.89 0.92 0.98 0.89 0.99 1 1 0 1 Geomec very well. The plots below compare the Poisson's Ratio and Young's Modulus calculated from th measured data vs. the model predictions using the NuLook outputs and triple combo based data only. • This model may now be applied to future wells without measured shear and compressional inputs within this field._ 13 ............................................................. ............................................................ ............................................. .... ................................................ ........ i..7eex4eittek Re*ervotvpe se iao i ii3�3ie�E3oiEs`?'rii�eei3onaeueeaa'o�aiu'ii�se6: ............................................. ieoiiSl ...RH Look Back Process varametc ...�............. '�i'S:iai.. ...3�...:.. 33SSS ..3.e ..=Ee3..s.s3.... 's: ..3.. :a.. aie i .................................................. .: ::: :.... .:.. .... SS CS ii S i gyration of Field Parar�ne#ers/tperator input __ ::ig FieldA parameters such as historic stimulation challenges, field hydrocarbon properties, reservoir extent, tubular data current field completion practices, and field economic parameters all factor into the completion analysis. — mims�sim:�tssoa a:eu osatmi� tesssoi}soama ......... ... a...... _.-... .. .. _......... ..... R ::: S'T.................................................. .. ........._..................................... ... l:.=Ti:.:.::'mafk .ewa a wide Si.a.::ieE=3==..................... .. .. .. ... .. • 14 ...................>..• +5..+,k + l+.l,» a.�r! 7� de:.� 4x s+._.. / a� /7�- Incorporation of Field Parameters/Operator Input k ` • Wellbore schematic provided. • Two perforation intervals open to injection at: • 2,125 — 2,145 Ft (6 SPF) • 2,351 — 2,371 Ft (6 SPF) • 5.5" 15.5 # J-55 Casing to 4,484 Ft MD • 2 7/8" 6.5# 8rd EUE J-55 Tubing set with packer at 2,010 Ft • 7 7/8" Hole • Actual injection data detailing: • Injection time, rate, volume and density & type of injection fluid. ku''Pro- Look Back Process .................. a P:tr:irnetF 1 ........................ ..a....................................................................................... .............................. i' .......... .......... ........................... ............ ......11111101:: ..................... :::UM:NS::: IM:: 7. " Treatment Execution and Evaluation` , __��_���I�����_�����: TW.reatment information is obtained at the wellsiteHH., and:,.MIN WNW incorporated into the process NuProTm and NuFITTM� Comparisons of the model's pr actions and these :.: HIN:_:: observations allow for improved prediction accuracy in the MM field. MN 1M : YfCt'dttaU'it.... VW:......... lnr.oa lot.ttri:C ......•••••• .................. 8tio■ _. Wellste data is obtained and incorporate into the process via NuProTM. Comparisons and enhancements are made, refining calibration sets and enhancing future predictions AM for the next well. _,. 16 eo a „^^ Aurora Aspen #1 Injection Profile Interval 1 .,,, E E Aurora Aspen #1 Injection Profile Interval #2 A A rl rN -7„ 0 • IIIII Bill. milli m mmmNmBNlIlB H{111{111 IIIII ■111. I fl1111'I ■ ■mmmfiBNimmll{{{{{II{ 11111 mill' I11111111 ■mmmmmmilmm1f11111111 111I I ■Ill.1 eYlnll ■ NONE* SEVEN {IIII IIIII loll I ■illi111111111 ■ ■mmm91lml1mm 11IOII1/1 MIT 111111, tlllllll ■ mmmmm■ IIIII milli 111111111 ■ loll I BIIII I 1111111 ■ mmm� IIII I milli 4111111 ■ IIII I !IIII 1111111 ■ B� IIII I milli l 1111111 ■ mmmmm■ IIIII milli 11/111111 ■ Bmm�l Illlil m{III' illlllll ■ mmmmm■ 11114 m1111 lwIllll ■ lommmmmm� 1lmm�m:; melmmmEngmiu.. 1lmmmmmm■ 1111,m11C ' 11111mmmmmlmmllmm Dm �� IIII'1. milli 1111111111941 in ■mmmamm7mm Im� M HIM milli 1i11111immmmim[Immm N IIIII ■IIIII ■IIII'iI ■ mmmm[1l/mmm rl■ i nlrl lour l}:15i1 ■ nm[ilrrlBBB milli %i IIIII 1111111'I i ira°iiiliii !mom I N IIIIIII ■IIIIII rnVl1ll'I on oli mm� F1!Bor101! on III ■IIII 11IGi111l ON mmmmm■ I 1 iiiii ■{IIII \� i:b ■ PSC112 willimm mmmmmmm■ IIIII !IIII' tilll'l ■ a25*lillimm ■m mmmmm■ IIII).. 011111911111I m mmmlY melons 1m Bmmmm■ 111111', 01111111111110 Issue ■Ilmmm IIIIIBm■liiililSN .Y!! IIIIIIIII ■mlllIl "I on E= w 11111■111Ow35Ym mBm! mm� M ■m FM■mB IIIII ■IIIIIi"IIIII■ Ism I IIIId milli VAN ■ ON Now MEMO 19 I'x IM aximum Fracture Dimensions Crea 111111,.111!�1 ■../1oi■ri7...Irr 1911111 Irm ON Inol ■ ur1l.r.u.11u on, ���111I���n91 ■ u.r�.l\uMe nu nnlo./lua nI11...orua... u1 111M Illllll.rll!II 111111....9. ■►\r.■ �.11 11111 111111'..111i! IIIII...■Il\OL\.710 IIIIIIIrIIPk 111111.■■17w■f11 M111111.11 rftf>•f>• 11111i■t1i:IRlloll, u■nw■n■u1n Ma;; ibA Height Contacted byA"" 111 lift ection Fluid ' 3 1 11111:IIiG1.IS11�..\.eN� II.1// Illllli OIIIL'■ Ilpl■■..C■■�■■■Irr IIIIIU OIIiI 1G!I ■ ■■.O\■�■■.Irr 1111111 ■.fi'I IIIII ■..... P1...11/ 1111111.111111 1SIII ■ �^--• •-""'"' ^7 L'Str IIIIIU.111111 ':'till■7...\i"■■.L:! mlll.rml Iiu.anw.u.m Illllli.rlllll tl III ■ ■�I'w'u:C�e�■■i uG nnll.nlll �1m ■ nlla.■• u.lu nnn!o.nl � nu �wrnorw.l.1',u .ulrnlr: nnll■.r.-.2wc...cn1 1111111.r1hi 11111.+7■.■9!A...■Irr Illltll OIIIII ' Fiiaria!Qi M.■■■C:! IIIIIIL111111 +IIII ■ d1713r...rrr �� Illllll.olllll 6N1 III ■'a�i99i■ia./7: IIIIIU plllll NPI C \►■■ IIIII■..oOw..E2.19111III ■ ■....SERIES U/R ■ ■■■.0 ■...E FOR .ru....�.� .ruu.r\.+� iiiiliiiiii�t Itm.u...■�mrslinurnn null nnla lol ■ u....cc.nlnnnn ■wu....,v � ulrl nmu 1�101 ■ u.11w.►�r.nlanuuu rrrr� IIII I SIIIII' III E EESE.Il.r1.111/IIIU11 ,...Ul.S!/E ■wu■ wuu. t_ nu 1.nun �Inun . uui...�..lauuun olim",iiizi iimmmiin(loolowliiiiiiiii ..ES.r...■� 1161IR �11111aMEREi.�'7.SE1O1/lo11 ■■\.\.E■■■.1.� Ill I .rlllll I11111I ■ ■awl.\�\\E11lo11lo I \.\.■■il■\■� IIIII ma111il 1,:111111■■■■E\■/.mo liloll Rollo 20 12 • • 4Aurora Gas, LLC wwwaurorapower.com September 15 2011 RECEIVED Dan Seamount, Chairman SEP 2 6 7[!1' State of Alaska Oil and Gas Conservation Commission Aaska Oil & Gas Cons. Commission 333 W. 7 Avenue, Suite 100 Anchor gc Anchorage, AK 99501 Re: Annual Aspen Injection Surveillance Report No.3 DIO 32, Aspen No.1 Dear Mr. Seamount: In accordance with the requirements of Disposal Injection Order 32, Rule 6 Aurora Gas LLC (Aurora) has prepared this Annual Performance Report for the Aspen No.1 Injection well. The Aspen injection facilities only had one facility upgrade in the last year and that was the addition of an additional tank to help separate the solids before the water is injected into the well. Additional improvements were made to the data collection and SCADA information on the system. The pressure, flow rate, time and date were recorded on a 5min interval to 30 min interval every day of the year with power. The addition of an automated shutoff valve was also installed on the injection pumps. The permanent injection facilities are currently capable of a max injection rate of 12 gpm and 1000 psi. Only produced water and brine were injected into the well from July 2010 to August 2011. From July 2010 to June 2011, fluids were injected into the Aspen disposal well a total of 112 days during this timeframe and a total of 18,954 bbls of fluids (all produced water and brine) were injected. The Maximum pressure on the well between July 1 2010 and June 30 2011 was 929.6 psi on May 21st, 2011 at a rate of l l gpm (0.26 bbls /min). The minimum pressure seen on the well during this period was 92.2 psi on July 10, 2010 while the well was not injecting. The average wellhead pressure for this timeframe was 421 psi. The maximum flow rate the well saw was 12 gpm (0.29 bbls /min) on 9/10/11. The data from the new monitoring is available, however it is not feasible to print out for this report and can be made available electronically if requested. Attachment B is a separate report on the reservoir performance of the well created by Nutech Energy Alliance. The injected fluids are being pumped into two separate 6051 North Course Drive, Suite 200 • Houston, Texas 77072 • (713) 977 -5799 • Fax (713) 977 -1347 1400 West Benson Blvd., Suite 410 • Anchorage, Alaska 99503 • (907) 277 -1003 • Fax (907) 277 -1006 • • perforations; 2,125- 2,145ft (Interval 2) and 2,351- 2,371ft. (Interval 1). Simulations based on the injection pressures, flow rates and volumes injected were used to determine the fracture geometry and zone of influence for this well and can be found in the Attached report. Below is a summary of the findings from this report. Maximum Created Fracture Dimensions Interval Perforations Top Frac Bottom Frac Frac Depth (Ft) Depth (Ft) Length (Ft) 2 2,125 — 2,145' 2,120 2,150 N/A 1 2,351 — 2,371' 2,346 2,384 240 If you have any questions regarding this report, please contact me via email (chelgeson@aurorapower.com) or 907 - 277 -1003. Respectfully, Chad Helgeson Manager — Production Operations & Engineering Aurora Gas LLC Attachments Attachment A — Reservoir Analysis by Nutech, June 2011 c.c. Kim Cunningham Cook Inlet Region Incorporated 2525 C St Ste 500 Anchorage, AK 99503 • • Attachment A Reservoir Analysis by Nutech, June 2011 INIII NM =I 1111111 111111 MI OM NM MN INII MO 1= MI MN Mil INII MN i • :......: ' : *-1::::Ii_ r : c m •:.... . .. A . = ...... . ;Fr. ......h m .... ....... „„ . „, A uror a .. I .•••...•::::z... ... .. G as, . .as. .. Er. - .,.„, . . .... . .... M . . ... , ._ :,......... .. . ... . . . . . . .. ... . . ..... ... wOOOsotti06,41.010/1.1.111A%;■•./.;■■■■.■5161.dhti,)“..lit......1....... 7 ,I a 0.6,481 .... 111. .. . ...... MIMI ....... II .... ; .. INN101111111WON.••.•■•...O.0■0•••■••••••■• ....... a .... • ... soomal . . ,., ••••mmoserisomm ..... 1 : : ::::::::••••••••■•••••••■•••••••••■ ......... • ....... ..... monoolemom:onolo:ommo • , 4 , ,, ...... Ma . •11111.....■••••••••■ . 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I m 11111 -1 ---: :1 ' ' NM:ininlial iiio ' : 11111WEHOMM. , , .11O 1 1111 1 111801111 . 11 1. 11 1 11 - ' ISIMIIIMI WA egg a man annum NI 1 iMM - _ INE le MI lea li . LZEIIIIII: . 81111111111.111111d NM . IIII:IMal Ilh NMI - SWUM ' ' allir C " E•211111. i• ilMia.......,,,, l'AIN 101111114. - 77:321;11: inviii:m - - in Pon •1131114.123111111 . .. , 4 .,, '-11101111:1 ,„ - --4:-.3 ..... mmus '' - - - - ' ' ' "'''' • wilim II I .-- - 1 - 11111__ lir ' tuisteignion GROSS TOTAL IN-SITU FRAC Stage TOP DEPTH BOTTOM EFF POR- BHIP YM GRAD- Stage DEPTH (FT) OSITY (%) (PSI) SS HEIGHT NET PAY STRE BHST (°F) (10 PSI) PERM (MD) SW BHP (PSI) Name (FT) IENT (PSI) (PSI/FT) 2 Interval 2 2,122.0 2148.5 26.5 23.00 24.88 1,929 1,754 88.3 0.70 0.6003 0.69 1,025 0.902 , 4 N ,., 1 6 Te '' , moor .441•Apici U er H e , ,„,„ u, ir 0 N -St ''-..- StimuJotran 1Astan MI 1 • IIM INIII NM = MN 1 MN N 111111 1 IIIMI IINII 1111111 IMI1 NM at Geomechan Properties L Gross Net Effective Stress Frac Rock Top Depth Bottom Interval Interval Porosity NuPerm Stress Gradient Gradient Embedment Specific Specific Thermal (ft) Depth (ft) (ft) (ft) ( %) Sw )md) BHT ( °F) YM (e6) PR BHP (psi) (psi) (psi /ft) BHTP (psi) (psi /ft) Strength (psi) Gravity Heat Conductivity 2100 2101.5 2 1.5 22.75 0.83 1.606 88.1 0.5803 0.395 1008 1766 0.841 1943 0.925 80412 2.270075 0.247103 2.23467 2102 2102.5 1 1 24.57 0.81 2.739 88.1 0.6553 0.373 1009 1716 0.816 1888 0.898 80412 2.2753 0.249372 2.293669 2103 2103.5 1 1 26.51 0.65 22.9332 88.1 0.6359 0.369 1010 1706 0.811 1877 0.892 80004 2.2436 0.254642 2.430699 2104 2104.5 1 1 25.02 0.74 6.0648 88.2 0.6625 0.372 1010 1717 0.816 1889 0.897 80000 2.2674 0.25424 2.420237 �� 2105 2105.5 1 0 24.52 0.99 0.001 88.2 0.6861 0.369 1011 1711 0.813 1882 0.894 80072 2.2754 0.256003 2.466065 R 2106 2106.5 1 1 24.2 0.8 1.93215 88.2 0.6748 0.359 1011 1678 0.797 1846 0.877 80148 2.2621 0.248376 2.267765 2107 2111.5 5 0.5 22.25 0.96 0.08427 88.2 0.6914 0.358 1012 1678 0.796 1846 0.875 81147 2.29847 0.247503 2.245081 2112 2121.5 10 1 21.95 0.98 0.07262 88.2 0.69 0.375 1016 1734 0.819 1908 0.901 81214 2.311665 0.247684 2.249781 2122 2125.5 4 4 23.55 0.73 3.6458 88.3 0.7304 0.369 1019 1731 0.815 1904 0.896 80000 2.29035 0.252916 2.385821 2126 2127.5 2 2 23.62 0.51 9.40215 88.3 0.7434 0.369 1021 1735 0.816 1908 0.897 79996 2.287625 0.250116 2.313016 2128 2129.5 2 2 25.36 0.8 5.39772 88.3 0.732 0.357 1022 1706 0.802 1877 0.882 80050 2.263225 0.253112 2.390922 0 2130 2130.5 1 1 26.98 0.8 9.4512 88.3 0.7428 0.351 1023 1698 0.797 1867 0.877 80004 2.248 0.254987 2.439667 2131 2131.5 1 1 18.8 0.59 2.59895 88.3 1.2272 0.342 1023 1735 0.814 1909 0.895 80000 2.3838 0.255032 2.440832 .„: � ' 2132 2133.5 2 0.5 17.2 0.91 0.0392 88.3 1.4814 0.34 1024 1785 0.837 1963 0.921 80000 2.401625 0.257813 2.513138 I , T f + i '"` ..d ■ 2134 2135.5 2 1.5 28.95 0.83 14.86998 88.3 0.6935 0.369 1025 1751 0.82 1926 0.902 80002 2.202875 0.254744 2.433348 ' ' 2136 2137.5 2 2 25.1 0.74 9.1801 88.4 0.6105 0.384 1026 1771 0.829 1948 0.912 80000 2.2688 0.257432 2.503232 2138 2138.5 1 1 27.38 0.68 22.5451 88.4 0.5483 0.391 1026 1788 0.836 1967 0.92 80000 2.2401 0.254627 2.430302 2139 2139.5 1 1 28.54 0.62 36.0125 88.4 0.5129 0.386 1027 1771 0.828 1949 0.911 80000 2.213 0.253526 2.401676 *y ? Q „ 2140 2141.5 2 2 26.35 0.65 12.84 88.4 0.5519 0.389 1028 1781 0.832 1959 0.915 80000 2.241925 0.253307 2.395982a� 4 �#." T. � 2142 2143.5 2 2 25.08 0.64 10.65348 88.4 0.5925 0.385 1029 1775 0.828 1952 0.911 79996 2.266675 0.2543 2.421795 s, , . , , , iv ; , y ' >,.f � 2144 2145.5 2146 2147.5 2 2 24.79 0.53 22.3802 88.4 0.6485 0.383 1029 1779 0.829 1956 0.912 80000 2.27655 0.255059 2.441531) i 7 _ k-:'" f 2 0.5 23.34 0.84 2.53713 88.4 0.7497 0.375 1030 1771 0.825 1948 0.907 79998 2.29965 0.255053 2.441375 1 ' 2 ` ' 2148 2148.5 1 0.5 24.12 0.83 2.2625 88.4 0.6828 0.362 1031 1721 0.801 1893 0.881 80004 2.2926 0.25088 2.332889 fr 2149 2157.5 9 0.5 8.26 0.97 0.09901 88.5 0.6199 0.397 1034 1788 0.831 1967 0.914 31304 2.29485 0.217937 1.415263 2158 2175.5 18 0.5 10.23 0.99 0.02945 88.5 0.6645 0.393 1040 1797 0.829 1976 0.912 44826 2.274442 0.223424 1.574578 2176 2176.5 1 0 16.14 0.86 0.04815 88.6 0.8761 0.389 1045 1841 0.846 2025 0.93 80000 2.40595 0.244913 2.177738 2177 2177.5 1 0 14.96 0.87 0.0393 88.6 0.9557 0.381 1045 1825 0.838 2008 0.922 80000 2.42655 0.245555 2.19443 2178 2179.5 2 0.5 14.87 0.77 0.07935 88.6 1.0583 0.363 1046 1785 0.819 1963 0.901 79998 2.4301 0.247076 2.233966 1 2180 2180.5 1 1 14.56 0.71 0.1066 88.6 1.0802 0.36 1047 1781 0.817 1959 0.898 80000 2.4356 0.247037 2.232962 l d` 2181 2181.5 1 0 14.27 0.79 0.0524 88.6 1.0902 0.357 1047 1771 0.812 1948 0.893 80000 2.4443 0.248615 2.27399 r ;' i 2182 2193.5 12 0.5 11.1 0.97 0.01979 88.7 2.0261 0.341 1050 1913 0.874 2104 0.962 80006 2.499463 0.249084 2.286189. 1 2 1.5 18.89 0.76 0.5799 88.7 0.9113 0.355 1053 1756 0.8 1932 0.88 80000 2.30585 0.25052 2.323521: 2196 2227.5 32 3.5 16.65 0.95 0.10741 88.8 1.1026 0.343 1062 1770 0.8 1947 0.88 80274 2.378805 0.246971 2.231241 2320 2347.5 28 0 21.15 1 0.001 89.6 0.6748 0.385 1120 1928 0.826 2120 0.909 81394 2.304516 0.24467 2.171424 2348 2349.5 2 0 20.2 0.99 0.0212 89.7 0.6569 0.39 1127 1949 0.83 2144 0.913 80476 2.3251 0.245207 2.185369 ,`x t.•an- ,:^& 2350 2352.5 3 0.5 19.25 0.9 0.18032 89.7 0.8781 0.372 1129 1927 0.819 2119 0.901 80503 2.359417 0.248964 2.283054 2353 2353.5 1 1 20.91 0.79 0.8893 89.7 0.8907 0.363 1130 1905 0.81 2096 0.891 80448 2.3317 0.248176 2.262577 2354 2354.5 1 1 20.91 0.77 0.91105 89.7 0.881 0.356 1130 1877 0.797 2065 0.877 80272 2.32865 0.246904 2.229494 dPAM% 2355 2356.5 2 0 20.69 0.96 0.11708 89.7 0.8068 0.354 1131 1860 0.789 2046 0.868 81398 2.336825 0.241796 2.096703 ,',,.;14 s'f„ 2357 2361.5 5 0 18 1 0.001 89.7 0.8793 0.37 1132 1919 0.813 2111 0.895 81090 2.37805 0.247671 2.249459 '?,,,?',',V,;,'::,4,:, ' r 2362 2364.5 3 0 17.22 0.94 0.05395 89.8 1.0554 0.348 1134 1877 0.794 2065 0.874 80325 2.395933 0.251584 2.351193 2365 2365.5 1 1 18.63 0.67 1.01175 89.8 1.0607 0.335 1135 1842 0.779 2026 0.856 79996 2.3765 0.248047 2.259234 a . 2366 2369.5 4 4 21.31 0.57 4.96942 89.8 0.9961 0.333 1137 1837 0.776 2021 0.853 79999 2.335738 0.253521 2.401537 ` ., ^'s t 2370 2371.5 2 _ - 2 23.24 0.55 11.93875 89.8 0.9186 0.334 1138 1835 0.774 2019 0.851 80002 2.252475 0.254132 2.417436 r Y :"4 � & 2372 2375.5 4 1 22.28 0.95 0.33897 89.8 0.8541 0.329 1139 1807 0.761 1987 0.837 80421 2.294275 0.246758 2.225712 4 3 P . , , - 2376 2385.5 10 0 9.57 1 0.001 89.9 0.7165 0.389 1143 1952 0.82 2147 0.902 36498 2.32153 0.222217 1.532649 2386 2387.5 2 0 22.32 0.98 0.044 89.9 0.6934 0.38 1146 1957 0.82 2153 0.902 81476 2.3081 0.243842 2.149881 :< .... 2390.5 3 1 22.48 0.89 0.64298 89.9 0.6911 0,376 1147 1941 0.813 2135 0.894 80376 2.23975 0.244564 2.168656 2391 2391.5 1 0.5 23.2 0.92 0.5551 89.9 0.7441 0.366 1148 1921 0.804 2114 0.884 80220 2.29045 0.251798 2.356759 2392 2392.5 1 0 23.14 0.98 0.0884 90 0.7876 0.359 1148 1910 0.798 2101 0.878 81640 2.29745 0.249271 2.291055 : 2393 2393.5 2394 2399.5 1 0.5 23.4 0.89 0.6355 90 0.7079 0.364 1149 1910 0.798 2101 0.878 80632 2.2926 0.24458 2.169082 6 0 12.76. 0.99 0.02771 90 0.8652 0.382 1150 1974 0.824 2171 0.906 60093 2.354583 0.232326 1.825486 2400 2402.5 3 0 17.96 1 0.03373 90 0.9682 0.352 1153 1907 0.794 2098 0.874 80399 2.3784 0,2468 2.226791 MIMI 2403 2421.5 19 0 17.86 1 0.001 90.1 0.8762 0.356 1158 1913 0.793 2104 0.872 80376 2.32745 0.241558 2.090513 , v • s !fQ® .utuwCF N , . Samtafretb Os MN - J- M_ M M MI NM N w M MI NM = M I Geomechanical Pro pertie " • NuStim Model vs. Sonic Model • The NuStim model matches the reservoir characteristics measured from the sonic data very well. • The plots below compare the Poisson's Ratio and Young's Modulus calculated from the measured data vs. the model predictions using the NuLook outputs and triple combo based data only. • This model may now be applied to future wells without measured shear and compressional inputs within this field. 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IFNIMGY AULANCI 18 A ..., Nuotfitit,fio Strfnutonazi Vision a.. aim 11:40 Interval 2 Modeled Frac Dimensions Aurora Aspen #1 Injection Profile Interval #2 1000 50 900 45 II 800 ill 40 700 i_ 35 1 a) = r= u) 30 3 0 CI) 500 25 a c c cn as a 400 20 I ' i km 15 300 — t U) , 1 � u_ 200 } At the reported injection rates this interval 10 does not fracture, only matrix injection occurs. The maximum reported injection — Surf Pressure (psi) 100 rate is 12 gpm for both intervals combined. — Frac Lower HT (ft) — 5 - Frac Upper Ht (ft) 0 0 0 30 61 91 122 152 182 213 243 274 304 334 365 Time (days) di I Nu 4W NUSti 5 SW/NAM - ran Wsrarr Maximum Fracture Dimensions Created Interval 1 GRC FW_FLAG DEPTH 1VD AHT10 MODEM HDRA . 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I" _ ' ■ ■■ ■ ■ ■Ir 1111 iMNNNINNI,Nj7 A� a f �� " M i Maximum Height J... j ■ ■ ■ ■r -: MIMNMFAME r Nrt. - ri M■■■■r NINNNINUIN ■ NM I' , _ MI injection GAS W IMO/ M■M - M. 1 I♦II I ■■■, • ■ill FAIR PER MNMN►MNNIiN 1111 ■1111 1l':)NNNNNIIIr1NNN7.1un111 ' —. 1. . ■■■ MNNNMLi � U■uuM 11111 ■IIL• 1111111■U1elaNEMMEN11111111111 NM!.= • l :7■ ■■■■. Ii■■ -• � nMi■N■■N■N� IIII! ■ MI111au MIEN 1 ::::::1111I III MMMEMNONNMMMMMM■ 1111 ■11111; /111111 ■NN ■GIN■11N■■ L111111111 0. I I MIiMNMMINMM=NEM 1111 ■111111IIIIIINiiilINIM MN'111111/111 I l`��� M EI =NNNMM� 1111 ■11111\_w4 ■141133Nilri•i 1 1 MINIMI 6666661 1111 ■IIII •4nIIII M �_ . _ I "Ifill MMMENM.NIN0� i r - r - , . — �IIIIII' "..16.1. • ■0000 ■1000 (111111111 I i _g 7 ■ ■ ■ ■f M MM�MN/OMMM Pc11 s I \■■■MI■1 NENNMIINNIN� MNNMNINYMNMIUUI'1U NM■NINNNN■A IIII ■ 111111 :IIIIIININ7M !CMNNN1111111111 ` ■ ■ ■ ■ ■�_ NNMNM�rNNMMMMMM■ IN ■ 1111 ' I t-- - L■■■■■■�r�'� 100011. ■ ■1■� 111 ■ IIIIIi:11111NNiiiStYNNP11111 ■11 -. 1 7■■■■ ■r' '�II MMMENNENNN 1111 ■ 11111E :1111!1 ■MMNPNNNMM 1'10111'111 I ■■■■■■■. 7 at A N uTi. ' Vu St t MD Slimigs von .wiion r- Maximum Fracture Dimensions Created Interval 2 ti ,:: GRC FW_FIAG DEPTH ND AH[lO P_HIDEDIT HDRA CLAY SW NUPERM 1 0 GA% 1DEC 25` 50 6 0 FT F 1 0.2 OHMM 200 0.6 DE 0 -0C1 25 1 0 0 0.1 0 1 1 DEC 1 0.1 MD 1000 0.05 0 2 6 _ _ _ I _ _ _ FF DTC AHT20 PDSS HMIN _ TEXGM_ SMALL BAY • :JDE: IN 16 0 6 1878 0.2 OHMM 200 06 DEC 0 0 OHMM20 1 NUMATR 01 100 0 1 06 DEC 0 0. MD 1000 1.5 3.5 23 - SPBL LW_FLAG [TSNRII1 AHT30 P NMRO MEDIUM PHIE -120 MY 30 0 6 1700 02 OHMM 200 0 _ 6 DEC 0 0 0HMM20 0 1 0 6 DEC 0 NUPERM 1000 NUSPEC4 Ct3 t FHC_FRAG AHF60 PSSS LARGE 801 - 0 6 0.2 OHMM 200 0.6 DEC 0 HMI• HMNO 0 1 0.6 DEC 0 nmi1.nm I • N n.M l I I rMMMrMMMrM� / 111111.1116 IIIIII MP.Mrrrlr lUlI.III ..tea► M� . 1111111.111116 0/111111 ■ •r'A!S 1 I - ..MMr.. NMrru.•NM 1NNNNNNI 1111111 n11111 VAR! 1 1 -- • I T E .. ..■..• ■. ' +++ . __ Maximum Created Fracture Dimensions -1- •••• III ■.!! ■! • � Ci N�..► a. Top Frac Depth Bottom Frac Frac Length .. zz• . ...._ n�1 ,� Interval Perforations (FT) Depth (FT) (FT) M = ���� 1 ���M•L II - GAS WT 2 2,125'-2,145' 2121 2150 N/A �, Lam.. .. 4- LO PERM III 1 2.351'- 2,371' 2346 2384 240 ..IMINI..I 1� j ..�... • ME1M.fu� 111111•1119 1NN••N11111111111 _. „ 1 g ..�..• I•MM ∎ -■m m 1 E 1111NI0 W1 it / w . 1 _f.. _ 1. i. ---L a l ' Y 1MMM U - 1N•••N•N�� .. NMI,. 1 - r r 7�..• MIMEO N ll• 1 1=1 .� L _ i�1 • 1 11.•••N•1 Maximum Height j • MM1 1M .. " Imp •!N•7•NNN• A ..A' 1 -> : �>..�_ j tGAS WI .1MlS•••11• -� Co ntacted by - - a ---- -- NNNNCNNNIIN • � r 1 : - 7 � 1 ! _._ GOOD PER ••••• \••1110 MI 1 1 Qom.■ Injection Fluid 1••1•••11• J f 1 - y'aiiil;Jai;i� ?i ii ' '= R:.u1o11u ' I . ...•IM..s.. - MPI•••.••U_ 111111111111111 a1 . NrMen MrMMM . : - -- I -- ______- Ill M•••11zs Holism t .11111■ raiin,!•1M -MM ■- .�. 1 I - .. - _ 1•• •TI•••WWI• 1111111■ 1111111.!11111 ■■•ReM�J•N• - _ 1. - 1 I I ,i{',7 ■..r •c•Mnr•••• uul ■11@11 s Ii• 1 I 1 1 m II•MMM The vertical permeability is unknown in this interval. ; : !! : : This height shown here assumes that the injection 11_ !■m■■ ■: from the perforations is contacting the entire porous j: =:::: interval of this sand. 1.•.••1 1.MIM..../ 7 11111. MITI . '•rill • •••MrI • 4 1 • ••••■�...• MMMM.MMMIM•� IIIIiI.H61 MISII 1•••M12R•0 1 mini a of II, �J�.a , •N•111aN•11• 1111111 •1111 WIN N N•••1NNM71N 1.111111111 - I 1 ..�...Ir ism mom= 1111111 .1u11111tu1n■ i ri - 2 e I , _ . ,-, .� .M...1 " '1..11.0 _ 11 T 1111$ •11111MI111■ 11111••17 A 1 ' 1 g ,�,m...r ••••••••••r 2200 ■ IIIH .HII ZOS,tl • ••••MII.•• 1 IIIII.I1 . I -1' - rm1 • - 1!•.••••••∎ 3 11111 N1111�PI11111 • seersN�J•1C1111111111 1 I .„,, ... mini... ERM moms IIIII .HIII • Mi M. •.IM MM• 1111111111 - 1 .. ••10••••••,,,..• mom. mom. �� 111111M11111111IIII11■ .. ���I II111. /t ... - I � . ,g . :'���� 4011114 ' NuS irrs S6mWarwn Wsion ---Aurora Gas, LLC www. aurorapower. com November 12 2009 R ECEIVED NOV 1 3 2009 Dan Seamount, Chairman State of Alaska jaska Oil &Gas COi1S. Commission Oil and Gas Conservation Commission Anchorage 333 W. 7 Avenue, Suite 100 Anchorage, AK 99501 Re: Annual Aspen Injection Surveillance Report No.1 DIO 32, Aspen No.1 Dear Mr. Seamount: In accordance with the requirements of Disposal Injection Order 32, Rule 6 Aurora Gas LLC (Aurora) has prepared this Annual Performance Report for the Aspen No.1 Injection well. In August, 2008, Aurora successfully completed a workover of the Aspen No. 1 well to convert the well to an injection well. The Aurora Well Service Rig. #1 was used to complete this work and finished the well work on September 1 where the well was in a condition for injection. A baseline temperature log was performed on September 1 with a baseline step rate test. The step rate test was performed on August 31st. See the table below for results of step rate test. Step Rate Test Aspen #1 WDW August 30, 2008 Step Duration Pressure Flow Rate (Min) (psig) (BBL /Min) 1 45 527 0.58 2 45 639 0.72 3 45 670 0.80 4 75 786 0.98 The rig was removed from location and the 1 injection into the reservoir, not including fluids during the step rate test, occurred on September 19 The fluid injected was water from the Aurora Gas Produced Water Storage Facility and injected using temporary injection tanks and pump from the drilling rig. Additional injection of produced water from the surface storage pond recommenced on November 11, 2008, using the temporary rig equipment. Injection with the temporary 6051 North Course Drive, Suite 200 Houston, Texas 77072 (713) 977 -5799 Fax (713) 977 -1347 1400 West Benson Blvd., Suite 410 Anchorage, Alaska 99503 (907) 277 -1003 Fax (907) 277 -1006 equipment was monitored continuously, checking pressures, injection rates, looking for leaks, and servicing the equipment. The second temperature log was performed on November 14 after a total of 4,398 bbls of water had been injected. Attachment A is the graph of three temperature surveys performed on the well; baseline, after injection of 4,398 bbls and during injection at 1 bbl /min. Attachment B is the data collected daily during injection. From September 1 2008 to July 6 2009, fluids were injected in the Aspen disposal well a total of 36 days and a total of 19,370 bbls of fluids were injected. The fluids injected were primarily produced water from the Aurora produced water surface storage facility. Which included produced fluids from the wells and precipitation that collected in this containment. A small amount of brine and drilling mud was also injected into the well during the year from several of Aurora's wells drilled in 2006 and 2008. A total of 2,000 bbls of mud was injected into the well. The Maximum pressure on the well during this timeframe, was 1,140 psi on July 5 2009. The minimum injection pressure recorded during injection was 350 psi on May 6 2008, and occurred at the start of the injection on that day. The daily average injection for these 36 days was 799 psi. The highest average injection pressure was 1091 psi on May 11 2009. The lowest average injection pressure was 417 psi on May 6 2009. During these 36 days of injection the temporary injection equipment from the AWS Rig #1 was used 19 days. Aurora Gas installed permanent facilities for continuous injection on June 11 2009. These permanent facilities include, pumps, storage tanks, a meter that records all fluids and rates injected into the well. The permanent injection tanks and pumps have enough capacity to handle the injection requirements for the normal water production from Aurora operating wells. Currently the facility is capable of storing 200 BBLs of water on location, and injecting at a rate of 0.25 bbls /min and 1000 psig. Additional pump capacity and equipment is planned for this facility. No scale inhibitor or additives have been added to this well except methanol for freeze protection. Attachment C is a separate report on the reservoir performance of the well created by Nutech. The fluids are being injected into two separate perforations; 2,125- 2,145ft (Interval 2) and 2,351- 2,371ft. (Interval 1). Simulations based on the injection pressures, flow rates and volumes injected were used to determine the fracture geometry and zone of influence for this well and can be found in the Attached report. Below is a summary of the findings from this report. Maximum Created Fracture Dimensions Interval Perforations Top Frac Bottom Frac Frac Depth (Ft) Depth (Ft) Length (Ft) 2 2,125 2,145' 2,105 2,159 196 1 2,351 2,371' 2,328 2,384 156 If you have any questions regarding this report, please contact me via email (chelgeson@aurorapower.com) or 907 277 -1003. Respectfully, Chad Helgeson Manager Production Operations Engineering Aurora Gas LLC Attachments Attachment A Temperature Log (Baseline, post injection, during injection) Attachment B Injection Data for September 2008 -July 2009 Attachment C Reservoir Analysis by Nutech c.c. Kim Cunningham Cook Inlet Region Incorporated 2525 C St Ste 500 Anchorage, AK 99503 Attachment A Temperature Log (Baseline, post injection, during injection) 'Aurora I Well: 'Aspen 1 I Fieid:'Aspen 111 -14 -20081 Pressure (psia) 0 200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 0 _1 200 Pressure- Temperature Profile r 1. RIH Overlays RKB 400 ill Baseline, MIT, Injecting 600 it 800 I. lill Baseline Temp i Baseline PSIA 1000 ,a. Baseline 1200 'In Static Tem p 11 -14 -08 1P11111111111111k Static Psia 11-14-08 1400 as C 2 Q 1600 1i Inj Temp 1800, Inj. Psia CI II Ku 2000 1 f 2200 m i 2400 MI 2600 2800 3000 I f 1 i 1 1 35 40 45 50 55 60 65 70 n 80 Temperature (Deg. F) Pressure Inj. Perts 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: 11112/1009 Attachment B Injection Data for September 2008 -July 2009 0 0 Aurora Gas LLC Aspen #1 Injection Log September 2008 to July 2009 Total Pressure flowrate Volume Fluid Date Time PSIG BPM Injected Injected Pump 9/19/2008 4:00 AM 500 1 435 PW AG Rig Pump 9/19/2008 4:35 AM 600 0.8 460 PW AG Rig Pump 9/19/2008 5:00 AM 660 1.0 490 PW AG Rig Pump 9/19/2008 5:30 AM 700 1.1 524 PW AG Rig Pump 9/19/2008 6:00 AM 710 1.0 555 PW AG Rig Pump 9/19/2008 6:30 AM 715 1.1 588 PW AG Rig Pump 9/19/2008 7:00 AM 750 1.0 618 PW AG Rig Pump 9/19/2008 7:30 AM 750 1.1 650 PW AG Rig Pump 9/19/2008 7:40 AM 0.3 660 PW AG Rig Pump 9/19/2008 12:30 PM 600 0.0 660 PW AG Rig Pump 9/19/2008 1:00 PM 700 0.9 688 PW AG Rig Pump 9/19/2008 1:30 PM 710 1.2 723 PW AG Rig Pump 9/19/2008 2:00 PM 750 1.0 754 PW AG Rig Pump 9/19/2008 2:30 PM 750 1.1 786 PW AG Rig Pump 9/19/2008 3:00 PM 750 0.9 813 PW AG Rig Pump 9/19/2008 4:45 PM Started Pump 9/19/2008 5:00 PM 700 827 PW AG Rig Pump 9/19/2008 5:30 PM 750 1.1 860 PW AG Rig Pump 9/19/2008 6:00 PM 760 1.1 892 PW AG Rig Pump 9/19/2008 6:30 PM 800 1.1 925 PW AG Rig Pump 9/19/2008 7:00 PM 800 1.0 955 PW AG Rig Pump 9/19/2008 7:30 PM 800 1.3 995 PW AG Rig Pump 9/19/2008 8:00 PM 800 0.8 1020 PW AG Rig Pump 9/19/2008 8:30 PM 800 1.1 1054 PW AG Rig Pump 9/19/2008 9:00 PM 810 0.9 1082 PW AG Rig Pump 9/19/2008 9:30 PM 850 1.1 1115 PW AG Rig Pump 9/19/2008 10:00 PM 875 1.2 1150 PW AG Rig Pump 11/11/2008 11:00 PM 700 1 1656 PW AG Rig Pump 11/11/2008 11:30 PM 700 1 1686 PW AG Rig Pump 11/12/2008 12:00 AM 700 1 1718 PW AG Rig Pump 11/12/2008 12:30 AM 700 0.8 1747 PW AG Rig Pump 11/12/2008 1:00 AM 700 0.8 1774 PW AG Rig Pump 11/12/2008 1:30 AM 650 1 1791 PW AG Rig Pump 11/12/2008 2:10 AM 750 1 1844 PW AG Rig Pump 11/12/2008 2:38 AM 700 0.9 1873 PW AG Rig Pump 11/12/2008 3:00 AM 750 1 1891 PW AG Rig Pump 11/12/2008 3:30 AM 700 1 1923 PW AG Rig Pump 11/12/2008 4:00 AM 700 1 1955 PW AG Rig Pump 11/12/2008 4:30 AM 700 0.8 1985 PW AG Rig Pump 11/12/2008 5:00 AM 700 0.85 2011 PW AG Rig Pump 11/12/2008 5:30 AM 750 0.95 2039 PW AG Rig Pump 11/12/2008 6:00 AM 750 1 2066 PW AG Rig Pump 11/12/2008 6:30 AM 750 1 2093 PW AG Rig Pump 11/12/2008 7:00 AM 800 1 2123 PW AG Rig Pump 11/12/2008 7:30 AM 800 1 2153 PW AG Rig Pump 11/12/2008 8:00 AM 800 1 2183 PW AG Rig Pump 11/12/2008 8:30 AM 800 1 2213 PW AG Rig Pump Aspen Injection Log #1 Sept. 2008 to July 6, 2009 Page 1 of 12 0 0 Total Pressure flowrate Volume Fluid Date Time PSIG BPM Injected Injected Pump 11/12/2008 9:00 AM 800 1 2243 PW AG Rig Pump 11/12/2008 9:30 AM 850 1 2273 PW AG Rig Pump 11/12/2008 10:00 AM 850 1 2303 PW AG Rig Pump 11/12/2008 10:30 AM 800 0.88 2329 PW AG Rig Pump 11/12/2008 11:00 AM 800 0.81 2354 PW AG Rig Pump 11/12/2008 11:30 AM 800 0.5 2369 PW AG Rig Pump 11/12/2008 12:00 PM 750 0.4 2381 PW AG Rig Pump 11/12/2008 12:30 PM 800 0.43 2394 PW AG Rig Pump 11/12/2008 1:00 PM 800 0.9 2421 PW AG Rig Pump 11/12/2008 1:30 PM 550 0.9 2448 PW AG Rig Pump 11/12/2008 2:00 PM 500 0.95 2476 PW AG Rig Pump 11/12/2008 2:30 PM 500 0.5 2491 PW AG Rig Pump 11/12/2008 4:00 PM 800 0.9 2518 PW AG Rig Pump 11/12/2008 4:30 PM 850 0.7 2539 PW AG Rig Pump 11/12/2008 5:00 PM 800 0.81 2563 PW AG Rig Pump 11/12/2008 5:30 PM 850 0.8 2575 PW AG Rig Pump 11/12/2008 6:00 PM 800 0.8 2605 PW AG Rig Pump 11/12/2008 6:30 PM 850 1 2631 PW AG Rig Pump 11/12/2008 7:00 PM 850 0.97 2664 PW AG Rig Pump 11/12/2008 7:30 PM 850 1 2700 PW AG Rig Pump 11/12/2008 8:00 PM 750 1 2733 PW AG Rig Pump 11/12/2008 8:30 PM 800 1 2763 PW AG Rig Pump 11/12/2008 9:00 PM 750 0.95 2785 PW AG Rig Pump 11/12/2008 9:30 PM 800 1 2814 PW AG Rig Pump 11/12/2008 10:00 PM 700 0.5 2834 PW AG Rig Pump 11/12/2008 10:30 PM 700 0.6 2854 PW AG Rig Pump 11/12/2008 11:00 PM 750 0.85 2878 PW AG Rig Pump 11/12/2008 11:30 PM 800 1 2917 PW AG Rig Pump 11/13/2008 4:00 AM 600 0.5 2920 PW AG Rig Pump 11/13/2008 4:30 AM 500 0.26 2929 PW AG Rig Pump 11/13/2008 5:00 AM PW AG Rig Pump 11/13/2008 5:30 AM 650 1 2941 PW AG Rig Pump 11/13/2008 6:00 AM 700 1.02 2981 PW AG Rig Pump 11/13/2008 6:30 AM 750 0.8 3002 PW AG Rig Pump 11/13/2008 7:00 AM 750 1.01 3034 PW AG Rig Pump 11/13/2008 7:30 AM 750 1.08 3063 PW AG Rig Pump 11/13/2008 8:00 AM 750 1.08 3096 PW AG Rig Pump 11/13/2008 8:30 AM 800 1.04 3129 PW AG Rig Pump 11/13/2008 9:00 AM 800 1.06 3161 PW AG Rig Pump 11/13/2008 9:30 AM 750 1 3191 PW AG Rig Pump 11/13/2008 10:00 AM 800 1.01 3226 PW AG Rig Pump 11/13/2008 10:30 AM 800 1.04 3249 PW AG Rig Pump 11/13/2008 11:00 AM 750 0.98 3282 PW AG Rig Pump 11/13/2008 11:30 AM 750 1.01 3314 PW AG Rig Pump 11/13/2008 12:00 PM 800 1.01 3347 PW AG Rig Pump 11/13/2008 12:30 PM 800 1.01 3377 PW AG Rig Pump 11/13/2008 1:00 PM 800 1.01 3406 PW AG Rig Pump 11/13/2008 1:30 PM 800 1.02 3435 PW AG Rig Pump 11/13/2008 2:00 PM 800 1.01 3463 PW AG Rig Pump Aspen Injection Log #1 Sept. 2008 to July 6, 2009 Page 2 of 12 1 0 Total Pressure flowrate Volume Fluid Date Time PSIG BPM Injected Injected Pump 11/13/2008 2:30 PM 800 0.99 3496 PW AG Rig Pump 11/13/2008 3:00 PM 800 0.98 3525 PW AG Rig Pump 11/13/2008 3:30 PM 800 0.92 3555 PW AG Rig Pump 11/13/2008 4:00 PM 800 0.97 3584 PW AG Rig Pump 11/13/2008 4:30 PM 800 0.9 3613 PW AG Rig Pump 11/13/2008 5:00 PM 800 0.99 3642 PW AG Rig Pump 11/13/2008 5:30 PM 800 0.95 3670 PW AG Rig Pump 11/13/2008 6:00 PM 750 0.98 3700 PW AG Rig Pump 11/13/2008 6:30 PM 800 0.98 3730 PW AG Rig Pump 11/13/2008 7:00 PM 750 0.97 3759 PW AG Rig Pump 11/13/2008 7:30 PM 700 0.48 3776 PW AG Rig Pump 11/13/2008 8:00 PM 850 0.4 3787 PW AG Rig Pump 11/13/2008 8:30 PM 900 0.7 3803 PW AG Rig Pump 11/13/2008 9:00 PM 900 0.82 3825 PW AG Rig Pump 11/13/2008 9:30 PM 900 0.81 3850 PW AG Rig Pump 11/13/2008 10:00 PM 950 0.77 3872 PW AG Rig Pump 11/13/2008 10:30 PM 900 0.75 3891 PW AG Rig Pump 11/13/2008 11:00 PM 900 0.76 3913 PW AG Rig Pump 11/13/2008 11:30 PM 900 0.74 3935 PW AG Rig Pump 11/14/2008 12:00 AM 950 0.74 3957 PW AG Rig Pump 11/14/2008 12:30 AM 900 0.72 3978 PW AG Rig Pump 11/14/2008 1:00 AM 950 0.7 3998 PW AG Rig Pump 11/14/2008 1:30 AM 950 0.68 4018 PW AG Rig Pump 11/14/2008 2:00 AM 950 0.65 4038 PW AG Rig Pump 11/14/2008 2:30 AM 950 0.65 4058 PW AG Rig Pump 11/14/2008 3:00 AM 900 0.98 4087 PW AG Rig Pump 11/14/2008 3:30 AM 950 0.95 4101 PW AG Rig Pump 11/14/2008 4:00 AM 950 0.95 4150 PW AG Rig Pump 11/14/2008 4:30 AM 975 0.9 4185 PW AG Rig Pump 11/14/2008 5:00 AM 950 0.9 4211 PW AG Rig Pump 11/14/2008 5:30 AM 950 0.9 4238 PW AG Rig Pump 11/14/2008 6:00 AM 950 0.85 4264 PW AG Rig Pump 11/14/2008 6:30 AM 950 0.84 4289 PW AG Rig Pump 11/14/2008 7:00 AM 950 0.84 4314 PW AG Rig Pump 11/14/2008 7:30 AM 950 0.78 4335 PW AG Rig Pump 11/14/2008 8:00 AM 950 0.79 4358 PW AG Rig Pump 11/14/2008 8:30 AM 950 0.77 4381 PW AG Rig Pump 11/14/2008 9:00 AM 950 0.77 4398 PW AG Rig Pump 11/14/2008 6:00 PM 800 0.46 4399 PW AG Rig Pump 11/14/2008 6:30 PM 950 0.77 4413 PW AG Rig Pump 11/14/2008 7:00 PM 950 0.7 4435 PW AG Rig Pump 11/14/2008 7:30 PM 950 0.69 4456 PW AG Rig Pump 11/14/2008 8:00 PM 975 0.65 4475 PW AG Rig Pump 11/14/2008 8:30 PM 975 0.62 4493 PW AG Rig Pump 11/14/2008 9:00 PM 975 0.6 4505 PW AG Rig Pump 11/14/2008 9:30 PM 900 0.56 4507 PW AG Rig Pump 11/14/2008 10:00 PM 975 0.84 4524 PW AG Rig Pump 11/14/2008 10:30 PM 975 0.72 4546 PW AG Rig Pump 11/14/2008 11:00 PM 975 0.7 4566 PW AG Rig Pump Aspen Injection Log #1 Sept. 2008 to Jul 6, 2009 Page 3 of 12 July g r Total Pressure flowrate Volume Fluid Date Time PSIG BPM Injected Injected Pump 11/14/2008 11:30 PM 975 0.53 4580 PW AG Rig Pump 11/15/2008 12:00 AM 975 0.8 4599 PW AG Rig Pump 11/15/2008 12:30 AM 975 0.75 4621 PW AG Rig Pump 11/15/2008 1:00 AM 975 0.73 4644 PW AG Rig Pump 11/15/2008 1:30 AM 975 0.7 4664 PW AG Rig Pump 11/15/2008 2:00 AM 975 0.7 4684 PW AG Rig Pump 11/15/2008 2:30 AM 975 0.67 4705 PW AG Rig Pump 11/15/2008 3:00 AM 975 0.7 4726 PW AG Rig Pump 11/15/2008 3:30 AM 900 0.93 4751 PW AG Rig Pump 11/15/2008 4:00 AM 925 0.93 4779 PW AG Rig Pump 11/15/2008 4:30 AM 975 0.92 4806 PW AG Rig Pump 11/15/2008 5:00 AM 975 0.9 4833 PW AG Rig Pump 11/15/2008 5:30 AM 975 0.86 4854 PW AG Rig Pump 11/15/2008 6:00 AM 975 0.84 4881 PW AG Rig Pump 11/15/2008 6:30 AM 975 0.81 4903 PW AG Rig Pump 11/15/2008 7:00 AM 975 1 4937 PW AG Rig Pump 11/15/2008 7:30 AM 975 1.02 4970 PW AG Rig Pump 11/15/2008 8:00 AM 975 0.95 4996 PW AG Rig Pump 11/15/2008 8:30 AM 975 0.94 5024 PW AG Rig Pump 11/15/2008 9:00 AM 975 0.92 5052 PW AG Rig Pump 11/15/2008 9:30 AM 975 0.9 5078 PW AG Rig Pump 11/15/2008 10:00 AM 975 0.88 5105 PW AG Rig Pump 11/15/2008 10:30 AM 975 0.85 5131 PW AG Rig Pump 11/15/2008 11:00 AM 975 0.93 5157 PW AG Rig Pump 11/15/2008 11:30 AM 975 1 5169 PW AG Rig Pump 11/15/2008 12:00 PM 950 1 5174 PW AG Rig Pump 11/15/2008 12:30 PM 950 0.9 5207 PW AG Rig Pump 11/15/2008 1:00 PM 950 0.88 5231 PW AG Rig Pump 11/15/2008 1:30 PM 950 0.94 5253 PW AG Rig Pump 11/15/2008 2:00 PM 950 1 5285 PW AG Rig Pump 11/15/2008 2:30 PM 950 1.02 5313 PW AG Rig Pump 11l15/20A8 4:00 PM 0.4 5338 PW AG Rig Pump 11/15/2008 4:30 PM 0.2 5344 PW AG Rig Pump 11/15/2008 5:00 PM 0.4 5348 PW AG Rig Pump 11/15/2008 5:30 PM 975 0.97 5361 PW AG Rig Pump 11/15/2008 6:00 PM 975 1 5402 PW AG Rig Pump 11/15/2008 6:30 PM 980 0.72 5428 PW AG Rig Pump 11/15/2008 7:00 PM 980 0.74 5450 PW AG Rig Pump 11/15/2008 7:30 PM 975 0.83 5474 PW AG Rig Pump 11/15/2008 8:00 PM 980 0.84 5498 PW AG Rig Pump 11/15/2008 8:30 PM 980 0.88 5525 PW AG Rig Pump 11/15/2008 9:00 PM 5540.55 PW AG Rig Pump 5/6/2009 1500 350 0.75 5540.55 PW AG Rig Pump 5/6/2009 1530 400 0.75 5548.50 PW AG Rig Pump 5/6/2009 1600 450 0.75 5570.50 PW AG Rig Pump 5/6/2009 1630 450 0.77 5589.00 PW AG Rig Pump 5/6/2009 1700 440 0.81 5622.00 PW AG Rig Pump 5/6/2009 1730 440 0.83 5650.00 PW AG Rig Pump 5/6/2009 1800 390 0.94 5675.00 PW AG Rig Pump Aspen Injection Log #1 Sept. 2008 to July 6, 2009 Page 4 of 12 Total Pressure flowrate Volume Fluid Date Time PSIG BPM Injected Injected Pump 5/7/2009 600 0 0 0.00 PW AG Rig Pump 5/7/2009 630 0 0.95 5686.00 PW AG Rig Pump 5/7/2009 700 390 0.95 5690.00 PW AG Rig Pump 5/7/2009 730 400 0.95 5719.00 PW AG Rig Pump 5/7/2009 800 400 1.00 5744.00 PW AG Rig Pump 5/7/2009 830 480 0.95 5763.00 PW AG Rig Pump 5/7/2009 900 500 0.95 5789.00 PW AG Rig Pump 5/7/2009 930 500 0.95 5818.00 PW AG Rig Pump 5/7/2009 1000 500 0.95 5848.00 PW AG Rig Pump 5/7/2009 1030 520 0.95 5872.00 PW AG Rig Pump 5/7/2009 1100 5 40 0.95 5900.00 PW AG Rig Pump 5/7/2009 1130 540 0.90 5929.00 PW AG Rig Pump 5/7/2009 1200 5 45 0.95 5960.00 PW AG Rig Pump 5/7/2009 1230 600 0.95 5986.00 PW AG Rig Pump 5/7/2009 1300 600 1.14 6016.00 PW AG Rig Pump 5/7/2009 1330 600 1.00 6048.00 PW AG Rig Pump 5/7/2009 1400 600 0.93 6073.00 PW AG Rig Pump 5/7/2009 1430 600 0.95 6099.00 PW AG Rig Pump 5/7/2009 1500 600 0.98 6131.00 PW AG Rig Pump 5/7/2009 1530 600 0.90 6161.00 PW AG Rig Pump 5/7/2009 1600 600 0.95 6190.00 PW AG Rig Pump 5/7/2009 1630 610 0.90 6221.00 PW AG Rig Pump 5/7/2009 1700 610 0.92 6255.00 PW AG Rig Pump 5/7/2009 1730 612 0.75 6282.00 PW AG Rig Pump 5/7/2009 1800 640 0.98 6311.00 PW AG Rig Pump 5/7/2009 1830 640 0.98 6338.00 PW AG Rig Pump 5/7/2009 1900 660 0.98 6371.00 PW AG Rig Pump 5/7/2009 1930 680 0.98 6388.00 PW AG Rig Pump 5/7/2009 2000 680 0.97 6418.00 PW AG Rig Pump 5/7/2009 2030 700 0.98 6449.00 PW AG Rig Pump 5/7/2009 2100 700 0.99 6478.00 PW AG Rig Pump 5/7/2009 2130 690 0.98 6504.00 PW AG Rig Pump 5/8/2009 800 660 0.98 6505.00 PW AG Rig Pump 5/8/2009 830 660 0.96 6518.00 PW AG Rig Pump 5/8/2009 900 660 6545.00 PW AG Rig Pump 5/8/2009 930 660 6574.00 PW AG Rig Pump 5/8/2009 1000 660 0.99 6603.00 PW AG Rig Pump 5/8/2009 1030 6 60 0.97 6631.00 PW AG Rig Pump 5/8/2009 1100 680 0.97 6661.00 PW AG Rig Pump 5/8/2009 1130 680 0.98 6690.00 PW AG Rig Pump 5/8/2009 1200 680 0.97 6719.00 PW AG Rig Pump 5/8/2009 1230 680 0.97 6748.00 PW AG Rig Pump 5/8/2009 1300 680 0.98 6705.00 PW AG Rig Pump 5/8/2009 1330 680 0.98 6778.00 PW AG Rig Pump 5/8/2009 1400 680 0.97 6817.00 PW AG Rig Pump 5/8/2009 1430 690 0.98 6846.00 PW AG Rig Pump 5/8/2009 1500 690 0.98 6874.00 PW AG Rig Pump 5/8/2009 1530 700 0.97 6903.00 PW AG Rig Pump 5/8/2009 1600 700 0.97 6932.00 PW AG Rig Pump Aspen Injection Log #1 Sept. 2008 to July 6, 2009 Page 5 of 12 Total Pressure flowrate Volume Fluid Date Time PSIG BPM Injected Injected Pump 5/8/2009 1630 720 0.97 6960.00 PW AG Rig Pump 5/8/2009 1700 740 0.96 6989.00 PW AG Rig Pump 5/8/2009 1730 740 7018.00 PW AG Rig Pump 5/8/2009 1800 740 7046.00 PW AG Rig Pump 5/8/2009 1830 740 7075.00 PW AG Rig Pump 5/8/2009 1900 740 0.90 7104.00 PW AG Rig Pump 5/8/2009 1930 740 0.98 7133.00 PW AG Rig Pump 5/8/2009 2000 740 0.97 7161.00 PW AG Rig Pump 5/8/2009 2030 740 0.97 7190.00 PW AG Rig Pump 5/8/2009 2100 740 0.98 7218.00 PW AG Rig Pump 5/8/2009 2130 760 0.99 7296.00 PW AG Rig Pump 5/8/2009 2200 760 0.97 7266.00 PW AG Rig Pump 5/9/2009 600 720 0.98 7266.00 PW AG Rig Pump 5/9/2009 630 720 0.97 7287.00 PW AG Rig Pump 5/9/2009 700 720 0.97 7316.00 PW AG Rig Pump 5/9/2009 730 740 0.97 7345.00 PW AG Rig Pump 5/9/2009 800 760 0.98 7373.00 PW AG Rig Pump 5/9/2009 830 780. 0.98 7402.00 PW AG Rig Pump 5/9/2009 900 780 0.97 7431.00 PW AG Rig Pump 5/9/2009 930 780 0.96 7461.00 PW AG Rig Pump 5/9/2009 1000 790 0.96 7488.00 PW AG Rig Pump 5/9/2009 1030 790 0.88 7519.00 PW AG Rig Pump 5/9/2009 1100 800 0.83 7547.00 PW AG Rig Pump 5/9/2009 1130 800 0.92 7576.00 PW AG Rig Pump 5/9/2009 1200 800 0.85 7604.00 PW AG Rig Pump 5/9/2009 1230 800 0.86 7634.00 PW AG Rig Pump 5/9/2009 1300 810 0.96 7662.00 PW AG Rig Pump 5/9/2009 1330 810 0.94 7691.00 PW AG Rig Pump 5/9/2009 1400 810 0.98 7718.00 PW AG Rig Pump 5/9/2009 1430 810 0.97 7747.00 PW AG Rig Pump 5/9/2009 1500 810 0.95 7766.00 PW AG Rig Pump 5/9/2009 1530 810 0.97 7790.00 PW AG Rig Pump 5/9/2009 1600 820 1.00 7818.00 PW AG Rig Pump 5/9/2009 1630 820 0.99 7855.00 PW AG Rig Pump 5/9/2009 1700 820 0.97 7864.00 PW AG Rig Pump 5/9/2009 1730 820 0.99 7891.00 PW AG Rig Pump 5/9/2009 1800 840 0.99 7919.00 PW AG Rig Pump 5/9/2009 1830 860 0.99 7949.00 PW AG Rig Pump 5/9/2009 1900 860 0.99 7977.00 PW AG Rig Pump 5/9/2009 1930 860 0.99 8004.00 PW AG Rig Pump 5/9/2009 2000 890 0.99 8034.00 PW AG Rig Pump 5/9/2009 2030 860 0.97 8065.00 PW AG Rig Pump 5/9/2009 2100 880 0.99 8093.00 PW AG Rig Pump 5/9/2009 2130 880 0.98 8122.00 PW AG Rig Pump 5/9/2009 2200 880 0.99 8159.00 PW AG Rig Pump 5/9/2009 2230 880 0.98 8183.00 PW AG Rig Pump 5/9/2009 2300 880 0.97 8203.00 PW AG Rig Pump 5/9/2009 2330 880 0.99 8235.00 PW AG Rig Pump 5/9/2009 2400 880 0.99 8264.00 PW AG Rig Pump Aspen Injection Log #1 Sept. 2008 to July 6, 2009 Page 6 of 12 Total Pressure flowrate Volume Fluid Date Time PSIG BPM Injected Injected Pump 5/10/2009 30 890 0.99 8293.00 PW AG Rig Pump 5/10/2009 100 890 0.97 8320.00 PW AG Rig Pump 5/10/2009 130 890 0.97 8350.00 PW AG Rig Pump 5/10/2009 200 890 0.97 8378.00 PW AG Rig Pump 5/10/2009 230 900 0.98 8407.00 PW AG Rig Pump 5/10/2009 300 900 0.94 8435.00 PW AG Rig Pump 5/10/2009 330 900 0.94 8462.00 PW AG Rig Pump 5/10/2009 400 900 0.91 8491.00 PW AG Rig Pump 5/10/2009 430 900 0.86 8519.00 PW AG Rig Pump 5/10/2009 500 900 0.91 8549.00 PW AG Rig Pump 5/10/2009 530 900 0.99 8577.00 PW AG Rig Pump 5/10/2009 600 920 0.97 8608.00 PW AG Rig Pump 5/10/2009 630 920 0.95 8633.00 PW AG Rig Pump 5/10/2009 700 940 0.96 8663.00 PW AG Rig Pump 5/10/2009 730 940 0.97 8690.00 PW AG Rig Pump 5/10/2009 800 940 0.94 8717.00 PW AG Rig Pump 5/10/2009 830 940 0.98 8741.00 PW AG Rig Pump 5/10/2009 900 940 0.96 8771.00 PW AG Rig Pump 5/10/2009 930 960 0.96 8801.00 PW AG Rig Pump 5/10/2009 1000 980 1.68 8820.00 PW AG Rig Pump 5/10/2009 1030 980 0.96 8858.00 PW AG Rig Pump 5/10/2009 1100 980 0.87 8885.00 PW AG Rig Pump 5/10/2009 1130 980 0.96 8914.00 PW AG Rig Pump 5/10/2009 1200 980 0.97 8942.00 PW AG Rig Pump 5/10/2009 1230 980 0.97 8972.00 PW AG Rig Pump 5/10/2009 1300 980 0.99 9000.00 PW AG Rig Pump 5/10/2009 1330 980 0.97 9028.00 PW AG Rig Pump 5/10/2009 1400 980 1.00 9056.00 PW AG Rig Pump 5/10/2009 1430 980 0.98 9096.00 PW AG Rig Pump 5/10/2009 1500 980 0.98 9115.00 PW AG Rig Pump 5/10/2009 1530 980 0.98 9143.00 PW AG Rig Pump 5/10/2009 1600 1000 0.98 9171.00 PW AG Rig Pump 5/10/2009 1630 1000 0.97 9200.00 PW AG Rig Pump 5/10/2009 1700 1000 0.98 9228.00 PW AG Rig Pump 5/10/2009 1730 1000 0.98 9259.00 PW AG Rig Pump 5/10/2009 1800 1000 0.98 9285.00 PW AG Rig Pump 5/10/2009 1830 1000 0.96 9319.00 PW AG Rig Pump 5/10/2009 1900 1010 0.98 9343.00 PW AG Rig Pump 5/10/2009 1930 1020 0.98 9374.00 PW AG Rig Pump 5/10/2009 2000 1020 0.98 9402.00 PW AG Rig Pump 5/10/2009 2030 1020 0.98 9430.00 PW AG Rig Pump 5/10/2009 2100 1020 0.98 9457.00 PW AG Rig Pump 5/10/2009 2130 1020 0.96 9486.00 PW AG Rig Pump 5/10/2009 2200 1020 0.98 9514.00 PW AG Rig Pump 5/10/2009 2230 1020 0.96 9542.00 PW AG Rig Pump 5/10/2009 2300 1020 0.96 9564.00 PW AG Rig Pump 5/10/2009 2330 1040 0.97 9593.00 PW AG Rig Pump 5/10/2009 2400 1040 0.97 9622.00 PW AG Rig Pump 5/11/2009 30 1040 0.97 9651.00 PW AG Rig Pump Aspen Injection Log #1 Sept. 2008 to July 6, 2009 Page 7 of 12 Total Pressure flowrate Volume Fluid Date Time PSIG BPM Injected Injected Pump 5/11/2009 100 1040 0.98 9680.00 PW AG Rig Pump 5/11/2009 130 1040 0.98 9710.00 PW AG Rig Pump 5/11/2009 200 1040 0.98 9738.00 PW AG Rig Pump 5/11/2009 230 1040 0.98 9770.00 PW AG Rig Pump 5/11/2009 300 1040 0.98 9797.00 PW AG Rig Pump 5/11/2009 330 1040 0.98 9824.00 PW AG Rig Pump 5/11/2009 400 1040 0.97 9852.00 PW AG Rig Pump 5/11/2009 430 1050 0.94 9880.00 PW AG Rig Pump 5/11/2009 500 1050 0.95 9908.00 PW AG Rig Pump 5/11/2009 530 1050 1.01 9939.00 PW AG Rig Pump 5/11/2009 600 1050 0.98 9968.00 PW AG Rig Pump 5/11/2009 630 1050 0.94 9997.00 PW AG Rig Pump 5/11/2009 700 1060 0.96 10025.00 PW AG Rig Pump 5/11/2009 730 1060 0.97 10052.00 PW AG Rig Pump 5/11/2009 800 1060 1.01 10082.00 PW AG Rig Pump 5/11/2009 830 1060 0.98 10106.00 PW AG Rig Pump 5/11/2009 900 1080 0.96 10137.00 PW AG Rig Pump 5/11/2009 930 1080 0.96 10167.00 PW AG Rig Pump 5/11/2009 1000 1080 0.96 10195.00 PW AG Rig Pump 5/11/2009 1030 1080 0.92 10222.00 PW AG Rig Pump 5/11/2009 1100 1080 0.94 10251.00 PW AG Rig Pump 5/11/2009 1130 1080 0.96 10279.00 PW AG Rig Pump 5/11/2009 1200 1080 1.00 10312.00 PW AG Rig Pump 5/11/2009 1230 1080 0.95 10337.00 PW AG Rig Pump 5/11/2009 1300 1080 0.96 10368.00 PW AG Rig Pump 5/11/2009 1330 1080 0.96 10395.00 PW AG Rig Pump 5/11/2009 1400 1080 0.94 10424.00 PW AG Rig Pump 5/11/2009 1430 1100 0.94 10445.00 PW AG Rig Pump 5/11/2009 1500 1100 0.98 10476.00 PW AG Rig Pump 5/11/2009 1530 1100 0.97 10500.00 PW AG Rig Pump 5/11/2009 1600 1100 0.97 10533.00 PW AG Rig Pump 5/11/2009 1630 1100 0.98 10560.00 PW AG Rig Pump 5/11/2009 1700 1100 0.97 10587.00 PW AG Rig Pump 5/11/2009 1730 1100 0.96 10616.00 PW AG Rig Pump 5/11/2009 1800 1100 0.98 10644.00 PW AG Rig Pump 5/11/2009 1830 1100 0.97 10669.00 PW AG Rig Pump 5/11/2009 1900 1100 0.99 10697.00 PW AG Rig Pump 5/11/2009 1930 1100 0.98 10731.00 PW AG Rig Pump 5/11/2009 2000 1110 0.98 10759.00 PW AG Rig Pump 5/11/2009 2030 1110 0.97 10787.00 PW AG Rig Pump 5/11/2009 2100 1110 0.98 10816.00 PW AG Rig Pump 5/11/2009 2130 1110 0.98 10844.00 PW AG Rig Pump 5/11/2009 2200 1120 0.96 10871.00 PW AG Rig Pump 5/11/2009 2230 1120 10900.00 PW AG Rig Pump 5/11/2009 2300 1120 10928.00 PW AG Rig Pump 5/11/2009 2330 1120 0.33 101958.00 PW AG Rig Pump 5/11/2009 2400 1120 0.96 10987.00 PW AG Rig Pump 5/11/2009 30 1120 0.99 11018.00 PW AG Rig Pump 5/11/2009 100 1120 0.98 11046.00 PW AG Rig Pump Aspen Injection Log #1 Sept. 2008 to July 6, 2009 Page 8 of 12 Total Pressure flowrate Volume Fluid Date Time PSIG BPM Injected Injected Pump 5/11/2009 130 1120 0.98 11076.00 PW AG Rig Pump 5/11/2009 200 1120 0.98 11105.00 PW AG Rig Pump 5/11/2009 230 1120 0.96 11131.00 PW AG Rig Pump 5/11/2009 300 0.98 PW AG Rig Pump 5/11/2009 330 0.97 PW AG Rig Pump 5/11/2009 400 1120 0.96 11142.00 PW AG Rig Pump 5/11/2009 430 1120 0.97 11169.00 PW AG Rig Pump 5/11/2009 500 1120 0.99 11199.00 PW AG Rig Pump 5/11/2009 530 1120 0.85 11228.00 PW AG Rig Pump 5/11/2009 600 1120 11257.00 PW AG Rig Pump 5/11/2009 630 1120 11285.00 PW AG Rig Pump 5/11/2009 700 1120 11311.00 PW AG Rig Pump 5/11/2009 730 1120 11342.00 PW AG Rig Pump 5/11/2009 800 1120 11370.00 PW AG Rig Pump 5/11/2009 830 1120 11397.00 PW AG Rig Pump 5/11/2009 900 1120 11428.00 PW AG Rig Pump 5/11/2009 930 1120 11460.00 PW AG Rig Pump 5/11/2009 1000 1120 11485.00 PW AG Rig Pump 6/1112009 9:30 AM 640 0.15 PW AG Wanner Pump 6/11/2009 4:11 AM 640 0.15 PW AG Wanner Pump 6/11/2009 10:28 PM 640 0.15 PW AG Wanner Pump 6/12/2009 8:18 AM 660 0.15 12423 PW AG Wanner Pump 6/12/2009 11:14 PM 740 0.13 PW AG Wanner Pump 6/13/2009 8:15 AM 530 0.00 12567 PW AG Wanner Pump 6/13/2009 11:54 AM 400 0.00 PW AG Wanner Pump 6/13/2009 12:20 AM 700 0.15 PW AG Wanner Pump 6/14/2009 11:28 AM 700 0.15 PW AG Wanner Pump 6/14/2009 1:35 PM 700 0.15 PW AG Wanner Pump 6/14/2009 10:27 PM 750 0.14 PW AG Wanner Pump 6/15/2009 7:55 AM 700 0.14 PW AG Wanner Pump 6/15/2009 3:35 PM 700 0.14 PW AG Wanner Pump 6/16/2009 12:40 AM 760 0.14 PW AG Wanner Pump 6/16/2009 8:07 AM 700 0.14 PW AG Wanner Pump 6/17/2009 1:25 AM 800 0.14 PW AG Wanner Pump 6/17/2009 3:38 AM 800 0.14 PW AG Wanner Pump 6/17/2009 12:08 PM 750 0.14 PW AG Wanner Pump 6/17/2009 8:00 PM 750 0.15 PW AG Wanner Pump 6/18/2009 3:03 AM 750 0.14 PW AG Wanner Pump 6/18/2009 2:50 PM PW AG Wanner Pump 6/20/2009 7:23AM 630 0.15 13479 PW AG Wanner Pump 6/21/2009 3:36 PM 620 0.15 PW AG Wanner Pump 6/21/2009 4:58 PM 660 0.15 PW AG Wanner Pump 6/21/2009 8:39 PM 680 0.15 PW AG Wanner Pump 6/22/2009 5:05 AM 700 0.15 PW AG Wanner Pump 6/22/2009 9:15 AM 700 0.15 13855 PW AG Wanner Pump 6/22/2009 11:55 AM 720 0.15 PW AG Wanner Pump 6/22/2009 10: PM 780 0.15 PW AG Wanner Pump 6/23/2009 6:15 AM 780 0.14 PW AG Wanner Pump Aspen Injection Log #1 Sept. 2008 to July 6, 2009 Page 9 of 12 I Total Pressure flowrate Volume Fluid Date Time PSIG BPM Injected Injected Pump 6/23/2009 9:12 AM PW AG Wanner Pump 6/24/2009 6:30 AM 600 0.07 PW AG Wanner Pump 6/24/2009 10:30 AM 700 0.14 PW AG Wanner Pump 6/24/2009 2:30 PM 760 0.14 PW AG Wanner Pump 6/24/2009 7:30 PM 780 0.14 PW AG Wanner Pump 6/25/2009 6:15 AM 780 0.14 14152 PW AG Wanner Pump 6/25/2009 6:15 AM 780 0.14 PW AG Wanner Pump 6/25/2009 7:00 AM 800 0.14 PW AG Wanner Pump 6/26/2009 3:00 PM 700 0.15 14250 PW AG Wanner Pump 6/27/2009 6:40 AM 720 0.15 14405 PW AG Wanner Pump 6/27/2009 12:25 PM 760 0.14 PW AG Wanner Pump 6/27/2009 4:37 PM 760 0.14 PW AG Wanner Pump 6/28/2009 8:07 AM 780 0.14 PW AG Wanner Pump 6/28/2009 10:43AM 780 0.14 14648 PW AG Wanner Pump 6/28/2009 12:45 PM 6/28/2009 2:12 PM 6/28/2009 2:45Pm 820 0.86 14656 AWS Rig Pump 6/28/2009 3:45Pm 820 0.77 14696 AWS Rig Pump 6/28/2009 4:45PM 850 0.79 14718 AWS Rig Pump 6/28/2009 5:45PM 850 0.70 14753 AWS Rig Pump 6/28/2009 6:45PM 850 1.02 14804 AWS Rig Pump 6/28/2009 7:45PM 850 1.02 14870 AWS Rig Pump 6/28/2009 8:45PM 850 0.83 14936 AWS Rig Pump 6/28/2009 9:45PM 850 0.48 14955 AWS Rig Pump 6/28/2009 10:45PM 1000 1.02 14972 AWS Rig Pump 6/28/2009 11:45PM 1050 0.83 15043 AWS Rig Pump 6/29/2009 12:45AM 1050 1.05 15097 AWS Rig Pump 6/29/2009 01:45AM 1000 0.71 15160 AWS Rig Pump 6/29/2009 02:45AM 1000 0.76 15215 AWS Rig Pump 6/29/2009 03:45AM 1050 0.74 15257 AWS Rig Pump 6/29/2009 04:45AM 1050 0.71 15306 AWS Rig Pump 6/29/2009 05:45AM 1100 0.71 15323 AWS Rig Pump 6/29/2009 06:08AM 820 0.14 15324 AWS Rig Pump 6/29/2009 07:15AM 920 0.14 15333 AWS Rig Pump 6/29/2009 10:35AM 820 0.14 15344 AWS Rig Pump 6/29/2009 0.00 15346 AWS Rig Pump 6/29/2009 4:15PM 0.14 AWS Rig Pump 6/29/2009 5:30 PM 0.00 AWS Rig Pump 6/29/2009 10:26PM 0.14 AWS Rig Pump 6/30/2009 7:37AM 800 0.14 AWS Rig Pump 6/30/2009 1400HRS 850 0.83 15551 AWS Rig Pump 6/30/2009 3:00PM 950 0.88 15610 AWS Rig Pump 6/30/2009 4:00PM 1000 0.86 15670 AWS Rig Pump 6/30/2009 5:00PM 1000 0.90 15729 AWS Rig Pump 6/30/2009 5:50PM 1000 0.90 15776 AWS Rig Pump 6/30/2009 5:55PM 850 0.14 15776 AWS Rig Pump 7/1/2009 6:40AM 800 0.14 15886 AWS Rig Pump 7/1/2009 6:50AM 0.93 15886 AWS Rig Pump Aspen Injection Log #1 Sept. 2008 to July 6, 2009 Page 10 of 12 0 0 Total Pressure flowrate Volume Fluid Date Time PSIG BPM Injected Injected Pump 7/1/2009 8:00 AM 925 0.98 15934 AWS Rig Pump 7/1/2009 9:00 AM 975 0.95 16007 AWS Rig Pump 7/1/2009 10:00 AM 1025 1.00 16064 AWS Rig Pump 7/1/2009 11:00 AM 880 0.95 16108 AWS Rig Pump 7/1/2009 12:00PM 975 0.95 16168 AWS Rig Pump 7/1/2009 1:00PM 975 0.98 16228 AWS Rig Pump 7/1/2009 1200 pm 975 0.95 16168 AWS Rig Pump 7/1/2009 100 pm 975 0.98 16228 AWS Rig Pump 7/1/2009 200 pm 975 0.98 16290 AWS Rig Pump 7/1/2009 305 pm 1000 0.88 16345 AWS Rig Pump 7/1/2009 340 pm 0.00 7/1/2009 350 pm 900 0.14 16345 AG Wanner Pump 7/2/2009 745 am 875 0.14 16502 AG Wanner Pump 7/2/2009 745 am 900 0.83 AWS Rig Pump 7/2/2009 847 am 1000 0.86 16554 AWS Rig Pump 7/2/2009 1010 am 1000 0.86 16633 AWS Rig Pump 7/2/2009 1100 am 975 0.86 16666 AWS Rig Pump 7/2/2009 1200 pm 975 0.86 16722 AWS Rig Pump 7/2/2009 100 pm 1025 0.83 16775 AWS Rig Pump 7/2/2009 200 pm 1025 0.83 16819 AWS Rig Pump 7/2/2009 300 pm 1025 0.83 16877 AWS Rig Pump 7/2/2009 443 pm 1025 0.83 16961 AWS Rig Pump 7/2/2009 530 pm 1025 0.83 17001 AWS Rig Pump 7/2/2009 530 pm 925 0.13 AG Wanner Pump 7/2/2009 735 pm 860 0.14 AG Wanner Pump 7/2/2009 850 pm 860 0.14 AG Wanner Pump 7/3/2009 700 am 800 0.14 17112 AG Wanner Pump 7/3/2009 700 am 900 0.93 17112 AWS Rig Pump 7/3/2009 800 am 980 0.93 17160 AWS Rig Pump 7/3/2009 900 am 980 0.90 17218 AWS Rig Pump 7/3/2009 1000 am 1000 0.93 17273 AWS Rig Pump 7/3/2009 1100 am 1000 0.93 17330 AWS Rig Pump 7/3/2009 1200 pm 1000 0.90 17397 AWS Rig Pump 7/3/2009 100 pm 1000 0.90 17440 AWS Rig Pump 7/3/2009 200 pm 1000 0.90 17513 AWS Rig Pump 7/3/2009 300 pm 1000 0.90 17545 AWS Rig Pump 7/3/2009 400 pm 1075 0.90 17601 AWS Rig Pump 7/3/2009 500 pm 1075 0.90 17656 AWS Rig Pump 7/3/2009 600 pm 960 0.13 17688 AG Wanner Pump 7/3/2009 1028 pm 880 0.14 AG Wanner Pump 7/4/2009 630 am 900 0.14 17795 AG Wanner Pump 7/4/2009 645 am 1000 0.83 17795 AWS Rig Pump 7/4/2009 730 am 1000 0.83 17837 AWS Rig Pump 7/4/2009 830 am 1000 0.90 17889 AWS Rig Pump 7/4/2009 930 am 1000 0.90 17948 AWS Rig Pump 7/4/2009 1030 am 1000 0.90 17993 AWS Rig Pump Aspen Injection Log #1 Sept. 2008 to July 6, 2009 Page 11 of 12 Total Pressure flowrate Volume Fluid Date Time PSIG BPM Injected Injected Pump 7/4/2009 1130 am 1000 0.90 18045 AWS Rig Pump 7/4/2009 1230 pm 1020 0.90 18106 AWS Rig Pump 7/4/2009 130 pm 1050 0.90 18163 AWS Rig Pump 7/4/2009 230 pm 1040 0.90 18209 AWS Rig Pump 7/4/2009 340 pm 1050 0.90 18278 AWS Rig Pump 7/4/2009 440 pm 1050 0.90 18334 AWS Rig Pump 7/4/2009 545 pm 1050 0.90 18379 AWS Rig Pump 7/4/2009 550 pm 950 0.12 AG Wanner Pump 7/4/2009 615 pm 950 0.12 AG Wanner Pump 7/5/2009 635 am 900 0.14 AG Wanner Pump 7/5/2009 645 am 1000 0.79 18486 AWS Rig Pump 7/5/2009 745 am 1100 0.76 18560 AWS Rig Pump 7/5/2009 900 am 1025 0.76 18590 AWS Rig Pump 7/5/2009 1000 am 1025 0.81 18625 AWS Rig Pump 7/5/2009 1100 am 1100 0.88 18662 AWS Rig Pump 7/5/2009 1247 pm 1100 0.90 18753 AWS Rig Pump 7/5/2009 145 pm 1050 0.90 18805 AWS Rig Pump 7/5/2009 300 pm 1075 0.86 18882 AWS Rig Pump 7/5/2009 400 pm 1050 0.86 18921 AWS Rig Pump 7/5/2009 550 pm 1055 0.86 AWS Rig Pump 7/5/2009 555 pm 1050 0.86 19011 AWS Rig Pump 7/5/2009 700 pm 1140 0.86 19065 AWS Rig Pump 7/5/2009 745 pm 1140 0.86 19100 AWS Rig Pump 7/5/2009 800 pm 1000 0.11 AG Wanner Pump 7/6/2009 700 am 920 0.14 19192 AWS Rig Pump 7/6/2009 710 am 1000 0.95 19192 AWS Rig Pump 7/6/2009 820 am 1000 0.90 19271 AWS Rig Pump 7/6/2009 920 am 900 0.83 19291 AWS Rig Pump 7/6/2009 1000 am 1080 0.86 19324 AWS Rig Pump 7/6/2009 1100 am 0.00 19358 AWS Rig Pump 7/6/2009 145 pm 1080 1.00 19358 AWS Rig Pump 7/6/2009 200 pm 0.00 19370 AWS Rig Pump Installed new pump and meter, changed the meter from a PD meter to a mag flow meter And added new meter totals to old mew totals for total volumen injected 1 Aspen Injection Log #1 Sept. 2008 to July 6, 2009 Page 12 of 12 Aspen Injection Well Daily Injection Averages Average Date Pressure 9/19/2008 736 11/12/2008 752 Max Pressure 11/13/2008 787 1140 psi 7/5/2009 11/14/2008 947 11/15/2008 968 Min Pressure 5/6/2009 417 350 psi 5/6/2009 5/7/2009 578 5/8/2009 703 5/9/2009 818 5/10/2009 966 5/11/2009 1091 6/11/2009 640 6/12/2009 700 6/13/2009 543 6/14/2009 717 6/15/2009 700 6/16/2009 730 6/17/2009 775 6/18/2009 750 6/20/2009 630 6/21/2009 653 6/22/2009 725 6/23/2009 780 6/24/2009 710 6/25/2009 787 6/26/2009 700 6/27/2009 760 6/28/2009 863 6/29/2009 979 6/30/2009 921 7/1/2009 948 7/2/2009 964 7/3/2009 975 7/4/2009 1004 7/5/2009 1054 7/6/2009 997 Average 799 Attachment C Reservoir Analysis by Nutech Ai ei tonal ll liali o R 0 C o y 0 O m° 'h c t c o o zuc e ii z 0 ,0 0 0 w o o 11: C 3 C 10 41114 41 Lehi 06 O H C in flu limn" iiii 4111 1. C 44 ih. lit km" u s 'Q R k y 33 6. Li Etifik—ilk Z 44 illif fa% It qui 464!::::: u oww C m 4 E z T, a' it y tts 4. c� LIM II R C R h Nal R O Q S. 1 E ll illt v O 3 C 'CI O y t y U i 0 y v y 1:3 k 13 y2 m 0 R C oz C thiLlik 41 In .41 j C O O O r 4' Q. v lb L til .0 C,Q.O� ID O H 3 z si mg c El vi O •r, c N O V O CU a) CO malle N O c c U a) •1 E a) N U) a) a) c Q -o o L 6 CO (o a) to D U D c 40 Z (a 5 c U a) a cn 70 (a a) E p a) O L L (l5 E L 4 O o U a) I E a) Q a) L r O U Q a) L L L cu N cu O 0 0_ a) r 4 0 O R _C a) Z N O O N• 2 a) L D Z_C T N U) ,_E 4= a l Q c1 n c U N Q 2 -0 N O-C O N L a3 L .42 4- a) C ai U a) U c i a p 't cn cn W t6 U O C N N O U j Cl O (D c a) CO U N _c U (6 l5 p 0 L O N u) U :7 E co O U 0_ CO ,fir lurr Project Methodology • Reservoir Description • The NuLook analysis dated 8/18/2005 provides a petrophysical description of the reservoir and it's properties. This includes (but not limited to) the porosity, permeability, texture, lithology and water saturation. • The NuStim process is used to create a reservoir and injection model with emphasis on the NuLook analysis. This process will utilize the NuLook processed data to determine additional geomechanical reservoir properties such as Young's modulus, Poisson's ratio and a stress profile. • In this case sonic data is also available and is used in calculating the rock properties. This data was used in order to build a calibrated geomechanical model that will enable the prediction of rock properties for other wells in the field with which sonic data was not provided. • Injection Performance and Fracture Characteristics • The NuStim model is then used to predict the characteristics of the actual injection into these intervals. �G�NuTeeP�_.. 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IIII C■1111 / Owm:�:llriSnII1111 �� .a ■■■■■■ -- IIIII' IIIIIE`IIIIIIIIiE1o511rHill ■r Nommumnskipfv_ iilV® lLt., g11111 I■■■■rIII111c 11I111/IIf�S.IrrU101110111 �: ■■■■■■r, IIIII!IIIII'IVL..;ri�@rfYrrrri:•9i1111 ;.;i,,,,,,,,■■■■■■■.rr IllI milli !!I ■ dE13Y11EEEE:!VIIIIII ••• • " " ■■■■■■■■■■ 11111 milliI i`AllI ■ i� �iEiiill:::■■IIII }""'r ■■■■■■mmw- W Mill Nu > r,; �: 7,1 ~~~ • • Regg, James B (DOA) From: Bruce D Webb [bwebb@aurorapower.com] Sent: Friday, December 05, 2008 9:14 AM ~~~ ~ + ~~~' ~ ~ To: Regg, James B (DOA) Subject: FW: Aspen # 1 Attachments: Aspen 1 MIT 11-14-08.zip; Aspen 1 Inj. 11-14-08.zip Page 1 of 2 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 a-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: aurorapower@gci.net [mailto:aurorapower@gci.net] On Behalf Of Ed Jones Sent: Monday, November 24, 2008 8:01 AM To: 'Bruce D Webb' Cc: 'Chad Helgeson' Subject: FW: Aspen # 1 Bruce, Here are the injection surveys for Aspen, to meet Rule 6 (temp. survey in first month of injection). How do you think we should send these to the AOGCC--with some interpretation? (all the fluid appears to be going in the top set of perfs, and no channeling is apparent). Also, was Ruie 4 satisfied (Mechanical Integrity--a report submitted 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: FW: Aspen # 1 Ed, Attached is the injection survey of the Aspen Well. Chad 12/5/2008 From: John Butler [mailto:gaslift@alaska.net] Sent: Monday, November 17, 2008 4:36 PM To: Chad Helgeson Subject: Aspen # 1 Page 2 of 2 Chad Here is the data and plots from Aspen # 1. The folder Warned Aspen 1 MIT is the static with an overlay of the baseline. The folder named Aspen included. Thanks John B. Pollard Wireline Inj. is the survey while we were injecting and has all three overlays 12/5/2008 urora Well: Aspen # 1 Field: Aspen 11-14-2008 Pressure (psia) 0 200 400 600 800 1000 1200 1400 1600 1800 2000 0 200 400 800 800 1000 .-. 1200 w ~'' 1400 IO Z 1800 a.. Q d ~ 1800 2000 2200 2400 2800 2800 3000 35 40 45 Pressure 11-14 RIH 9-5/8" 2 7/8" 50 55 60 65 70 75 80 Temperature (Deg. F) Perfs m~w •~°-Pressure Baseline RIH 13 3/8" 5-1 /2" Temperature 11-14 RIH - -Temperature Baseline RIH Report date: 12/10/2008 ~vliC I ~'~ SC-t,~~ urora II: Aspen # 1 Field: Asp Date: 11-14-2008 Pressure (psia) 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 0 ~.....~,.,_,_, - --- --- -.....----- ------ i 200 -..._. __ _ ...................__................._.. ___ -- - -- _ - -. Pressure-Temperature Profile - ___ - - - C 1. Going in hole 2800' RKB _. ....__.....___....__..._....._ , _ , 400 - -.... ------ --- _ _ - __ 600 - _ _....._ _..... _ - _... ......._ __ ._ . _ _, ..::. i __._ ; 800 _. _. ..... -- i ~ - 1000- -- - ~ _ _ - ~ ' - -- - - 1200 -- -- ~ ~ - -- --- -- -- _ -- ~.+ _. ~ ...._ --- f _ - ~ ._ ......._. I - _ ~ -. - - - - ... `.' 1400 _.. _... _._... __ ~ _ -- Q - - -- _..... ..... - .... _ - ~ - - -__ - -- ~ 1600 _ - -- - - - -_ - ', - - - - -- - - ~ --- I --- --- --- - 0 1800 - - --- ----' --- - -- --- - - i }- _.._ ..._ -_ _._ --.- __ ... _ 2000 _... - - I - _.. _.- ._ -- --. -- _ ..- . _... _ ............._..................................._ .._........................_ .a~.. 2200 _ _ ._.._ _.._ 2400 _..... _ ...... _ i ... .. :.. _ _.. ---- - - - - - - _. - - ~ -- --- l _... l 2600 _ - - - _. - I __ - - - --- _ - --.._ _. __ _._._... _._: _.._._-_. - -- -..__.. :: -- - - _ _ _:._-__-__---- .:::-:.::.--::.-:::__:.-:.::_-_.-.--:~::.:--.--::::.-__.-::.:::::..- :-:: .:-~: -: --::..-::.: --::.-:..-:.-..:::::_: I 2800 _ _ __. _ _. _ 3000 35 40 45 50 55 60 65 70 75 80 Temperature (Deg. F) F~~s'~lr~~20~s Perfs 9-5/8" -° 13 3/8" 5-1/2" 2 7/8" Temperature _ ~}~ c T~~ ~- J # 1 Field: Asp Date: 11-14-2008 Pressure (psia) 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 0 200 400 600 800 1000 1200 ;.+ d `'' 1400 ~ 1600 Q 1800 2000 2200 2400 2600 2800 3000 35 40 45 50 55 60 65 70 75 Temperature (Deg. F) se~t~~sl~~nop$ Perfs ° °•--~••° 9-5/8" ------13 3/8" 5-1/2" 2 7/8" Temperature) 80 ~II:~Aspen#1 ~ Field:~Aspd~ Date:~11-142008 Pressure (psia) 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 0 200 400 600 800 1000 1200 .~. d d `'' 1400 D ~ 1600 a m 1800 2000 2200 2400 2600 2800 3000 35 40 45 50 55 60 65 70 75 Temperature (Deg. F) -- ~5~lr~~20os Perfs °- -~ -° 9-5/8" -°-~-13 3/8" 5-1/2" 2 7/8" Temperature ~~`~ 80 urora Well: Aspen # 1 Field: Aspen 11-14-2008 Pressure -Gradient (psi/ft) -0.4 0.0 0.4 0.8 1.2 1.6 0 200 400 600 800 1000 1200 ... r m 1400 O Q, 1600 m D 1800 2000 2200 2400 2600 2800 3000 -15 -10 -5 0 5 10 Temperature -Gradient (Deg. F/100 ft) Press Gradient - Perfs Temp Gradient ,,~~,~ Te,~ ~~ t.~ urora Well: Aspen # 1 Field: Aspen 11-14-200E Pressure -Gradient (psi/ft) -0 4 0 0 0 4 0.8 1.2 1.6 0 200 400 600 800 1000 1200 m w 1400 Q, 1600 m D 1800 2000 2200 2400 2600 2800 3000 -15 -10 -5 0 5 Temperature -Gradient (Deg. F/100 ft) Press Gradient - Perfs Temp Gradient 10 • (~•fiad) a~n~e~adwal O O N r r r N 0 OD f~ ~ t~ Cfl ~ ~ ~ ~ M O O r T O ~~ C C 0 .~ ~ L N D ~ ~ (0 O N O m ~ 7 N f0 a N a m -~ _ . .~ O r L w~ r a _ N L m ~- ~_ I ~ ~ _ 7 O ~ r y ~ N a` I co 0 O O O O O O O O O O O ~ 0 O N O o p t0 ~ N OO c0 ~ (V r r r r r (eisd) a~nssa~d 0 0 N O r N r m w N '~ O 4 d' J J urora Well: Aspen # 1 Field: Aspen 11-14-2008 Pressure (psia) 0 200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 0 200 400 600 800 1000 1200 w `'~ 1400 t 1600 a a~ 0 1800 2000 2200 2400 2600 2800 3000 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: 12/10/2008 ~~ c~,~ ,ra II: Aspen # 1 Field: Asp Date: 11-14-2008 Pressure (psia) 600 800 1000 1200 1400 1600 1800 2000 2200 2400 0 - - __ - - Pressure-Temperature Profile - ..................... 200 --- -- -_ ---- - _.__......_....__ 1. Going in hole 2840' RKB __.........._._ ............._....._. _- - Injecting 11-14-08 -.-.: ^__:_:_ 400 _._ 600- - -- - 800 - -- 1000 _.. _ - _ _... _.. _...... ...._..... ~ ........ _. ...... 1200 - _ ---- _.._ ~ -- - - -_ _ ~ - -.- `.' 1400 - - -- ~ 1600 - - - - C. ---- G~ - 1800 - - - -- --- - _..._ 2000 _......_ . _.- .. ------ -- -.._.__._._.. _.. --- 2200 - -- - _.. __ 2400 - - - 2600 - --------------- - ----- ---- ---------- --- --- ___ __ 2800 ------ --__-----------------..._......._..___....._._.._...-- -...._.......__----- ----___......_......._...____.._.._..--.._ 3000 35 40 45 50 55 60 65 70 75 80 Temperature (Deg. F) ~~s'~/r~~20~a Perfs °-°~•-~ 9-5/8" 13 3/8" 5-1/2" 2 7/8" Temperature Date: 11-14-200 0 200 400 600 800 1000 1200 .~. `'' 1400 O ~ 1600 Q 1800 2000 2200 2400 2600 2800 3000 Pressure (psia) 600 800 1000 1200 1400 1600 1800 2000 2200 2400 35 40 45 50 55 60 65 70 75 80 Temperature (Deg. F) ~~~s~~lr~~20QS Perfs 9-5/8" 13 3/8" 5-1/2" 2 7/8" Temperature • --~,~~c =~, ~ urora Well: Aspen # 1 Field: Aspen 11-14-2008 Pressure -Gradient (psi/ft) -0.4 0.0 0.4 0.8 1.2 0 200 400 600 800 1000 1200 .:. d v 1400 D t a 1600 d D 1800 2000 2200 2400 2600 2800 3000 -15 -10 -5 0 5 Temperature -Gradient (Deg. FI100 ft) Press Gradient - Perfs Temp Gradient 1.6 10 I -0.4 0 200 400 600 = 800 1000 1200 ... .. m v 1400 - o, 1600 m 1800 2000 = 2200 2400 2600 2800 3000 C 0.0 ~n # 1 Field: Aspen Pressure -Gradient (psi/ft) 0.4 0.8 ~~~~ ~~, 1.2 1.6 Pressure-Temperature Gradient Profile 1. POOH -15 -10 -5 0 5 10 Temperature -Gradient (Deg. F/100 ft) Press Gradient - Perfs Temp Gradient Aurora Well: Aspen # 1 Field: Aspen Date: 11-14-2008 i 2400 ~ 80 2200 - ~- - ~ - - - -- - 75 2000 - _ - - ~ - I, 70 ', 1800 ~ - -- - I -. ~ ~I Run in hole ~ 1600 Gauge at depth - ~ 65 _ 2840' KB Pulling out of II LL i hole Making ~ ~ ~ 1400 - - -. - ~ - d •~ stops ~ 60 ~ a ~ 1200 - - % - r N ! ~I 55 a d d 1000 _ _ d H 50 800 - , - I - - 600 - - - - - - - T- - II ~ 45 400 - -- - - ~- - + - 40 200 ~ --- j - - - ~ ' I~, 0 35 18.5 19.0 19.5 20.0 20.5 21.0 21.5 22.0 22.5 23.0 Time (hrs) Pressure Temperature • • ~.l ~~ '~' ~~, Report date: 12/10/2008 • Page l ~I~,~ Regg, James B (DOA) From: Regg, James B (DOA) ,, I ~~ Sent: Wednesday, December 03, 2008 12:04 PM ~~`/] (~1~'~ To: 'chelgeson@aurorapower.com' C~ Cc: Maunder, Thomas E (DOA) Subject: Aspen Well Integrity Information Attachments: MIT Form OA (2007-1127).xls Chad - I received your voice message left yesterday (12/2). It's probably better to respond in writing so I can elaborate a bit and reference Area Injection Order 32 (Aspen) requirements that back up our request. As we discussed by phone on Monday, 12/1/2008, there are several items that the Commission has not received documentation for relating to the commencement of injection at Aspen: Pre-injection MIT (DIO 32, Rule 4) - passing MITIA performed 9/1/2008; test charts are in Commission files - provide MIT test report to Commission in electronic form; template is attached for your use Post-injection MIT ~DIO 32 Rule 4) -Commission witnessed MIT was required after commencing first injection; should have been performed in September 2008 - Commission witnessed MIT needs to be scheduled Baseline Std Rate Test X10 32 Rule 6) -performed 8/31/2008; results are in Commisson files - no action needed Baseline Temp Surv~ (DIO 32 Rule 6) -performed 8/31/2008; results are in Commisson files - no action needed Subsequent Temp Surve r~(DIO 32 Rule 6) - 2nd temperature survey required 1 month after commencing injection; given the type of injection, it should be done immediately following batch injection - you indicated survey was done in conjunction with November batch injection; there is nothing in Commission files to substantiate - provide results of subsequent temperature survey to Commission Daily Wellhead Pressure and Rate Observations (DIO 32, Rule 6) - surface pressures and rates must be monitored continuously during injection - provide surface pressures (tubing and annulus) and rates to Commission Also, in the November 21 letter requesting administrative approval (freeze protect fluids) and clarification of fluids eligible for Class II disposal injection in Aspen, Bruce Webb indicates the batch disposal injection volume would be approximately 80 to 160 barrels per month. Looking at injection to date, I note that initial batch injection was substantially higher than the referenced rate (1170+ barrels during a 3 day injection period in September). Is the September injection an anomaly? I'd appreciate some clarification. Once the listed information is received, I will complete processing the administrative approval request submitted by Aurora on November 21. Jim Regg AOGCC 333 W.7th Avenue, Suite 100 12/3/2008 ~~o • • ~Au-~ora Gas, LLC www.aurorapower.com November 21, 2008 ~ "' ~~"~'` ~ ~ ° -~`~ Mr. James Regg ~ ~ ~ Senior Petroleum Engineer Alaska Oil and Gas Conservation Commission ~1 333 W. 7~' Avenue, Suite 100 Anchorage, AK 99501 Re: Aspen Class II Oilfield Waste Disposal Well Application for Disposal of Freeze Protection Fluids by Underground Injection and Clarification of Eligible Fluids pursuant to Disposal Injection Order No. 32 Tyonek Formation, Cook Inlet Alaska Section 33, Township 12 North, Range 11 West, Seward Meridian Dear Mr. Regg: In accordance with the requirements of Alaska Statute 31.05 and 20 AAC 25, Aurora Gas, LLC ("Aurora") requests administrative approval for the underground injection of freeze protection fluids (non-hazardous Class II Oilfield waste) into the Beluga Formation at the Aspen # 1 waste disposal well. Freeze protection fluids are necessary at this well because the injection of water-based muds and produced water (brine) is intermittent. Aurora is planning for the batch disposal of approximately 80 to 160 bbls per month of muds and produced water, with freeze protection fluid of approximately 5 to 7 gallons after each batch injection period, to fill the piping, wellhead and tubing down to 15 feet, during winter months. Supplemental freeze protection will be achieved by electrical heat-tracing. Aurora proposes to use either: 0 New Methanol; 0 Used Triethylene Glycol (already Class II waste as used in the gas dehydration process); Q New Triethylene Glycol (only if there is no methanol or used triethylene glycol available) as freeze protection fluids. These fluids are all water-based and soluble in water. Attached, please find the MSDS for these freeze protection fluids that show they are water soluble products and should not have any compatibility issues with the Class II fluids we will normally be injecting. Additionally, Aurora requests the AOGCC's administrative approval to delineate the fluids eligible for Class II disposal in the Aspen #1 injection well. Should questions arise in connection with this request or supporting data, please contact either myself or Mr. Chad Helgeson in the Anchorage office at 277-1003. Respectfully Submitted By, ~~~2~Q ~~ Bruce D. Webb Manager, Land and Regulatory Affairs attachments 10333 Richmond Avenue, Suite 710 • Houston, Texas 77042 • (713) 977-5799 • Fax (713) 977-1347 1400 West Benson Blvd., Suite 410 • Anchorage, Alaska 99503 • (907) 277-1003 • Fax (907) 277-1006 ~ a V univnR Material Safety Data Sheet LA1183 Methanol 1. CHEMICAL PRODUCT AND COMPANY IDENTIFICATION Product Id: LA1183 Product Name: Methanol Synonyms: Methyl alcohol, methyl hydrate, wood spirit, methyl hydroxide Chemical Family: Alcohol Application: Solvent, fuel, feedstock Distributed By: Univar Canada Ltd. 9800 Van Horne Way Richmond, BC V6X 1 W 5 Prepared By: The Safety, Health and Environment Department of Univar Canada Ltd. Preparation date of MSDS: 03/12/2004 Telephone number of preparers 1-866-686-4827 24-Hour Emergency Telephone Number (CHEMTREC): (800) 424-9300 2. COMPOSITION/INFORMATION ON INGREDIENTS HAZARDOUS COMPONENTS In redients Percenta a LD50s and LC50s Route 8< S ecies: Methanol 99.85 Dermal LD50 (Rabbit) 15800 mg/kg 67-56-1 Oral LD50 (Rat) 5628 mg/kg Inhalation LC50 (Rat) 64000 mg/kg Oral LD50 Mouse 7300 m /k Notes: No additional remark. 3. HAZARDS IDENTIFICATION Potential Acute Health Effects: Eye Contact: Vapor and/or liquid causes irritation. Symptoms of exposure may include: eye irritation, burning sensation, pain, watering and/or change of vision. Eye injury which may persist for several days. Skin Contact: May cause skin irritation. May be absorbed through the skin in toxic or lethal amounts. Symptoms of exposure may include: Prolonged or repeated skin contact may cause drying, cracking or irritation. Central nervous system depression with headache, stupor, uncoordinated or strange behaviour or unconsciousness. Prolonged and or repeated skin contact with methanot soaked material has produced toxic effects including vision effects and death. inhalation: Inhalation of high airborne concentrations can irritate mucous membranes, cause headaches, sleepiness, nausea, confusion, loss of consciousness, digestive and visual disturbances and death. Ingestion: May be fatal if swallowed. A small amount of methanol (usually two or more ounces) can cause mental sluggishness, nausea and vomiting leading to severe illness, and may produce adverse effects on vision with possible blindness or death if treatment is not received. LA1183 Methanol Page 1 of 7 • ~ 4. FIRST AID MEASURES Eye Contact: Flush immediately with gentle running water for a minimum of 15 minutes, ensuring all surfaces and crevices are flushed by lifting tower and upper lids. Obtain medical attention. Skin Contact: In case of contact, immediately flush skin with plenty of water for at least 15 minutes. Get medical attention. Remove contaminated clothing and discard. Inhalation: Remove to fresh air, restore or assist breathing if necessary, obtain medical attention immediately. Ingestion: If swallowed, do not induce vomiting. Never give anything by mouth to an unconscious person. Obtain medical help immediately. Onset of symptoms may be delayed for 18 to 24 hours after ingestion. Swallowing methanol is life threatening. Notes to Physician: Acute exposure to methanol, either through ingestion or breathing high airborne concentrations can result in symptoms appearing between 40 minutes and 72 hours after exposure. Symptoms and signs are usually limited to CNS, eyes and gastrointestinal tract. Because of the initial CNS's effects of headache, vertigo, lethargy and confusion, there may be an impression of ethanol intoxication. Blurred vision, decreased acuity and photophobia are common complaints. Treatment with ipecac or lavage is indicated in any patient presenting within two hours of ingestion. A profound metabolic acidosis occurs in severe poisoning and serum bicarbonate levels are a more accurate measure of severity than serum methanol levels. Treatment protocols are available from most major hospitals and early collaboration with appropriate hospital is recommended. In cases of methanol poisoning, medical care must emphasize the control of acidosis. The use of intravenous bicarbonate has been lifesaving. Evidence shows that the treatment of methanol absorption in enhanced through the administration of ethanol, which should be given to produce a blood level of at least 0.1%. Ethanol diminishes the production of the toxic metabolites of methanol. A blood methanol level of 50 mg/100m1 is an indication for hemodialysis, which has improved the prognosis of methanol intoxification. 5. FIRE FIGHTING MEASURES Flash Point: 11 °C 152 °F Flash Point Method: Tag Closed Cup Autoignition Temperature: 385 °C / 725 °F Flammable Limits in Air (%): Lower: 6 Upper: 36 Extinguishing Media: Use aqueous film forming foam for large fires. Use carbon dioxide or dry chemical media for small fires. Water may not be effective tv extinguish fire. Special Exposure Hazards: Flammable Liquid. Methanol bums with a clean clear flame that is almost invisible in daylight. Stay upwind. Isolate and restrict area access. Concentrations of greater than 25% methanol in water can be ignited. Use fine water spray or fag to control fire spread and cool adjacent structures or containers. Contain fire control water for later disposal. Special Protective Equipment: Fire fighters must wear full face, positive pressure, self-contained breathing apparatus and appropriate protective clothing. Protective fire fighting structural clothing is not effective protection from methanol. Do not walk through spilled product. Thoroughly decontaminate bunker gear and other fire-fighting equipment before re-use. NFPA RATINGS FOR THIS PRODUCT ARE: HEALTH 1, FLAMMABILITY 3, REACTIVITY 0 HMIS RATINGS FOR THIS PRODUCT ARE: HEALTH 1, FLAMMABILITY 3 ,REACTIVITY 0 6. ACCIDENTAL RELEASE MEASURES Personal Precautionary Measures: Restrict access to unprotected personnel. Full-face, positive pressure self- contained breathing apparatus or airline and protective clothing must be worn. Do not walk through spilled product as it may be on fire and not visible. Environmental Precautionary Measures: Prevent from entering sewers, waterways or low areas. Consult local authorities. Procedure for Clean Up: flammable liquid. Release can cause an immediate firelexplosion hazard. Eliminate all ignition sources. Stop leak. Use absorbent materials. Contain spill by diking. Fluorocarbon alcohol resistant foams may be applied to spill to duninish vapour and fire hazard. Maximize recovery far recycling or reuse. Collect liquid with explosion proof pumps. For small spills, collect with non-combustible absorbent. Prevent spilled material from entering sewers, confined spaces, drains, or waterways. Do not walk through spi8ed product as it may be on fire and not visible. 7. HANDLING AND STORAGE Handling: No smoking or open flame in storage, use or handling areas. Use explosion proof electrical equipment. Ensure proper electrical grounding procedures are in place. LA1183 Methanot Page Z of 7 Storage: Tanks must be groun~nd vented and should have vapour emiss~ontrols. Tanks must be diked. Avoid storage with incompatible materials. Anhydrous methanol is non-corrosive to most metals at ambient temperatures except lead and magnesium. However coatings of copper (or copper alloys), zinc (including galvanized steel) or aluminium are unsuitable for storage as they are attacked slowly. Mild steel is the recommended construction material. 8. EXPOSURE CONTROLS/PERSONAL PROTECTION Engineering Controls: Local exhaust ventilation as necessary to maintain exposures to within applicable limits. Use explosion proof equipment. Respiratory Protection: NIOSH approved supplied air respirator when airborne concentrations exceed exposure limits. Based on workplace contaminant level and working limits of the respirator, use a respirator approved by NIOSH. The following is the minimum recommended equipment for an occupational exposure level. For concentrations > 1 and < 100 times the occupational exposure level: Use Type C full facepiece supplied-air respirator operated in positive-pressure or continuous-flow mode. For concentrations > the IDLH level or unknown concentration (such as in emergencies): Use self-contained breathing apparatus with full facepiece in positive-pressure mode or Type Cpositive-pressure full facepiece supplied-air respirator with an auxiliary positive-pressure self-contained breathing apparatus escape system. Gloves: Butyl rubber gloves. Nitrite gloves. Skin Protection: Wear chemical resistant pants and jackets, preferably butyl or nitrite rubber. Eyes: Chemical goggles; also wear a face shield if splashing hazard exists. Other Personal Protection Data: Ensure that eyewash stations and safety showers are proximal to the work-station location. Chemical resistant footwear. Ingredients Exposure Limit - ACGIH Exposure Limit -OSHA Immediately Dangerous to Life or Health -IDLH Methanol 200 ppm TWA 200 ppm TWA 6000 ppm 250 ppm STEL 250 ppm STEL 260 mg/m' TWA 325 m lm' STEL 9. PHYSICAL AND CHEMICAL PROPERTIES Physical State: Liquid Color: Clear/ Colorless Odor: Slight Alcohol pH Not applicable. Specific Gravity: 0,792 Boiling Point: 64.7 °C / 14$.5 °F Freezing/Melting Point: -97.8 °C / -144 °F Vapor Pressure: 127 mmHg @ 25 C Vapor Density: 1.11 Volatile by Volume: 100% Evaporation Rate: 2.1 Solubility: Soluble. VOCs (Ibs/gallon): Not Available. Viscosity: Not Available. Molecular Weight: 32.04 10. STABILITY AND REACTIVITY Chemical Stability: Stable. Hazardous Polymerization: Will not occur. Conditions to Avoid: Incompatible materials. Avoid any source of ignition. Materials to Avoid: Strong oxidizers. Strong inorganic acids. Strong bases. May be corrosive to lead and aluminium. Hazardous Decomposition Products: Formaldehyde. Carbon dioxide. Carbon monoxide. Additional Information: No additional remark. LA1183 Methanol Page 3 of 7 • • ~ 11. TOXICOLOGICAL INFORMATION ~ Principle Routes of Exposure Ingestion: May be fatal if swallowed. A small amount of methanol (usually two or more ounces) can cause mental sluggishness, nausea and vomiting leading to severe illness, and may produce adverse effects on vision with possible blindness or death if treatment is not received. Skin Contact: May cause skin irritation. May be absorbed through the skin in toxic or lethal amounts. Symptoms of exposure may include: Prolonged or repeated skin contact may cause drying, cracking or irritation. Central nervous system depression with headache, stupor, uncoordinated or strange behaviour or unconsciousness. Prolonged and or repeated skin contact with methanol soaked material has produced toxic effects including vision effects and death. Inhalation: Inhalation of high airborne concentrations can irritate mucous membranes, cause headaches, sleepiness, nausea, confusion, Joss of consciousness, digestive and visual disturbances and death. Eye Contact: Vapor and/or liquid causes irritation. Symptoms of exposure may include: eye irritation, burning sensation, pain, watering and/or change of vision. Eye injury which may persist for several days. Additional Information: NOTE: The odour threshold of methanol is several times higher than the TLV-TWA. Repeated exposure by inhalation or absorption may cause systemic poisoning, brain dosorders, impaired vision and blindness. Inhalation may worsen conditions such as emphysema or bronchitis. Repeated skin contact may cause dermal irritation, dryness and cracking. Effects of sub lethal doses may be nausea, headache, abdominal pain, vomiting and visual disturbances ranging from blurred vision to light sensitivity. Methanol is toxic by inhalation and ingestion. Inhalation of vapors may cause cyanosis, lethargy, loss of consciousness and death. The effects from inhalation may be delayed. Ingestion may cause malaise, discomfort, and death if not treated promptly. Medical conditions aggravated by exposure include: skin disorders and allergies, liver disorders and eye disease. Undocumented reports suggest that this product may form a siloxane polymer on the eyes, lungs, or other mucous membranes. Long term exposure to methanol has been associated with headaches, giddiness, conjunctivitis, insomnia and impaired vision. Dermal absorption of significant amounts of methanol resulted in death in several animal species. Toxic effects in animals exposed to methanol by inhalation include eye irritation, blindness and nasal discharge. Toxic effects observed in animals exposed to methanol by ingestion include anesthetic effects, damage to the optic nerve and acidosis. Acute Test of Product: Acute Oral LD50: >5,000 (Rat) Acute Dermal LD50: 20 mL/kg (Rabbit) Acute Inhalation LC50: 64, 000 ppm (Rat} Carcinogenicity: In redients IARC - Carcino ens ACGIH - Carcino ens Methanol Not listed. Not listed. Carcinogenicity Comment: Not listed with IARC, NTP, ACGIH or OSHA as a carcinogen. Reproductive Toxicity! Teratogenicity/ Embryotoxicity/ Mutagenicity: Methanol is reported to cause birth defects in rats exposed to 20 000 ppm. In experimental animals, methanol is fetotoxic, teratogenic and has produced significant behavioral abnormalities in offspring at dose levels not producing maternal toxic effects. Behavioural abnormalities were observed in the offspring of rats given drinking water containing 2% methanol. Tests of methanol in bacterial or mammalian cell cultures, and in animals demonstrate no mutagenic activity. LA1183 Methanol Page 4 of 7 `'rl. ECOLOGICAL INFORMA'11dN Ecotoxicolog ical Information: Ingredients Ecotoxicity -Fish Species Data Acute Crustaceans Toxici Ecotoxicity -Freshwater AI ae Data Methanol LC50 (rainbow trout Not Available. Not Available. (fingerling)) 13 mg/L LC50 (fathead minnow (28 days ofd)) 29400 mg/L LC50 trout 8000 m /L Other Information: Methanol in fresh or salty water may have serious effects on aquatic life. A study on methanol's toxic effects on sewage sludge bacteria reported little effect on digestion at 1.0 % while 0.5% methanol retarded digestion. Methanol will be broken down to carbon dioxide and water. 13. DISPOSAL CONSIDERATIONS Disposal of Waste Method: Incineration is the recommended disposal method. Biological treatment may be used on dilute aqueous waste methanol. Methanol wastes are not suitable for underground. injection. Waste materials must be disposed of in accordance with your municipal, state, provincial and federal regulations. Contaminated Packaging: Waste materials must be disposed of in accordance with your municipal, state, provincial and federal regulations. 14, TRANSPORT INFORMATION DOT (U.S.): DOT Shipping Name: Methyl Alcohol DOT Hazardous Class 3 (6.1) DOT UN Number: UN1230 DOT Packing Group: II DOT Reportable Quantity (Ibs): 5000 Notes: No additional remark. Marine Pollutant: No. ICAO/IATA: IATA Proper Shipping Name: Methanol IATA Hazard Class: 3 (6.1) UN Number: UN1230 Packing Group: II IATA Label: Flammable liquid. IATA Remarks: No additional remark. IMDG: IMOG Proper Shipping Name: Methanol Hazard Class: 3 (6.1) UN Number: UN1230 Packing Group: 11 Marine Pollutant: No. IMDG Label: Flammable. Toxic. Remarks: No additional remark. TDG (Canada): TDG Proper Shipping Name: Methanol Hazard Class: 3 (6.1) UN Number: UN1230 Packing Group: tl Note: No additional remark. Marine Pollutant: No. LA1183 Methanol Page 5 of 7 15, REGULATORY INFORMATION U.S. TSCA Inventory Status: All components of this product are either on theToxic Substances Control Act (TSCA) Inventory List or exempt. Canadian DSL Inventory Status: All components of this product are either on the Domestic Substances List (DSL) or the Non-Domestic Substances List (NDSL} or exempt. U.S. Regulatory Rules Ingredients CERCLAISARA -Section 302: SARA (311, 312) Hazard Class: CERCLA/SARA -Section 313: Methanol Not Listed. LISTED LISTED California Proposition 65: Not Listed. MA Right to Know List: Not Listed. New Jersey Right to-Know List: Nat Listed. Pennsylvania Right to Know List: Not Listed. WHMIS Hazardous Class: BZ FLAMMABLE LIQUIDS D1 B TOXIC MATERIALS D2A VERY TOXIC MATERIALS D2B TOXIC MATERIALS ~r ~ T LA1183 Methanol Page 6 of 7 ~ ~ 16. OTHER INFORMATION Additional Information: This product has been classifred in accordance with the hazard criteria of the Canadian Controlled Products Regulations (CPR) and the MSDS contains all the information required by the CPR. Disclaimer: NOTICE TO READER: Univar, expressly disclaims all express or implied warranties of merchantability and fitness for a particular purpose, with respect to the product or information provided herein, and shall under no circumstances be liable for incidental or consequential damages. Do not use ingredient information and/or ingredient percentages in this MSDS as a product specification. For product specification information refer to a Product Specification Sheet and/or a Certificate of Analysis. These can be obtained from your local Univar Sales Office. A!I information appearing herein is based upon data obtained from the manufacturer and/or recognized technical sources. While the information is believed to be accurate, Univar makes no representations as to its accuracy or sufficiency. Conditions of use are beyond Univar's control and therefore users are responsible to verify this data under their own operating conditions to determine whether the product is suitable for their particular purposes and they assume all risks of their use, handling, and disposal of the product, or from the publication or use of, or reliance upon, information contained herein. This information relates only to the product designated herein, and does not relate to its use in combination with any other material or in any other process. ***END OF MSDS*** LA1183 Methanol Page 7 of 7 02~nd~~`~5y~~ ~~~~~~~g~N~~~~08 10:40:13 AM PAGE PRODUCT NAME: MSDS NUMBER: DATE ISSUED: SUPERSEDES: ISSUED BY: TRIETxYLENE GLYCOL UCN0262M 03/07/2007 07/21/2006 008360 ~08 Fax Server ********~************************************~r*****************~*****~***** Material Safety Data Sheet 1. Product and Company Identification Product Name TRIETHYLENE GLYCOL COMPANY IDENTIFICATION The Dow Chemical Company 2030 Willard H. Dow Center Midland, MI 48674 USA Customer Information Number: 800-258-2436 EMERGENCY TELEPHONE NUMBER 24-Hour 8mergency Contact: 989-636-4400 Local Emergency Contact: 989-636-4400 2. Hazards Identification Emergency Overview Color: Colorless Physical State: Liquid Odor: Mild Hazards of product: CAUTION! May cause skin irritation. OSHA Hazard Communication Standard This product is a "Hazardous Chemical" as defined by the OSHA Hazard Communication Standard, 29 CFR 1910.1200. Potential Health 8ffects Eye Contact: May cause slight temporary eye irritation. Mist may cause eye irritation. Skin Contact: Prolonged contact may cause skin irritation with local redness. May cause more severe response if skin is abraded (scratched or cut). Skin Absorption: Prolonged skin contact is unlikely to result in absorption of harmful amounts. Massive contact with damaged skin or of material sufficiently hot to burn skin may result in absorption of potentially lethal amounts. Inhalation: At room temperature, exposure to vapor is minimal due to low volatility. Mist may cause irritation of upper respiratory tract (nose and throat} . Ingestion: Small amounts swallowed incidentally as a result of normal handling operations are net likely to cause injury; however, swallowing larger amounts may cause injury. May cause nausea and vomiting. May cause abdominal discomfort or diarrhea. May cause dizziness and drowsiness. Oral toxicity is expected to be greater in humans due to triethylene glycol even though tests in animals show a lower degree of toxicity. Effects of Repeated Exposure: Based an available data, repeated exposures are no~n~~~~c~~~ ~~Xt~~~~~rs~~~~#~~ ~gv~~s~3e~ec~QG~xce~ ve~~Xh~~~iv~[Lrosol concentrations. Repeated xcessive aerosol exposures ma cause respiratory tract irritation and even death. Birth DefectsJDevelopmental Effects: Triethylene glycol did not cause birth defects in animals; reduced fetal body weight effects were seen only at very high doses. 3. Composition Infornwtion Component CAS # Amount Triethylene glycol 112-2?-6 >= 99.5 ~ 4. First-aid measures Eye Contact: Flush eyes thoroughly with water for several minutes. Remove contact lenses after the initial 1-2 minutes and continue flushing for several additional minutes. If effects occur, consult a physician, preferably an ophthalmologist. Skin Contact: Wash skin with plenty of water. Inhalation: Move Berson to fresh air. If not breathing, give artificial respiration; if by mouth to mouth use rescuer protection (pocket mask, etc}. If breathing is difficult, oxygen should be administered by qualified personnel. Call a physician or transport to a medical facility. Ingestion: Do not induce vomiting. Seek medical attention immediately. If person is fully conscious give 1 cup or 8 ounces (240 ml) of water. If medical advice is delayed and if an adult has swallowed several ounces of chemical, then give 3-4 ounces (1/3-1/2 Cup} (90-120 ml} of hard liquor such as 80 proof whiskey. For children, give proportionally less liquor at a dose of 0.3 ounce (1 1/2 tsp.) (8 ml) liquor for each 10 pounds of body weight, or 2 ml per kg body weight (e.g., 1.2 ounce (2 1/3 tbsp.} for a 40 pound child or 36 ml for an 18 kg child). Notes to Physician: Due to structural analogy and clinical data, this material may have a tts3chanism of intoxication similar to ethylene glycol. On that basis, treatment similar to ethylene glycol intoxication may be of benefit. In cases where several ounces (60 - 100 ml} have been ingested, consider the use of ethanol and hemadialysis in the treatment. Consult standard literature for details of treatment. If ethanol is used, a therapeutically effective blood concentration in the range of 100 -- 154 mg/dl may be achieved by a rapid loading dose followed by a continuous intravenous infusion. Consult standard literature for details of treatment. 4-Methyl gyrazole (Antizol*) is an effective blocker of alcohol dehydrogenase and should be used in the treatment of ethylene glycol (EG}, di- or triethylene glycol (DEG, TEG), ethylene glycol butyl ether (EGBE), or methanol intoxication if available. Fomepizole protocol (Brent, J. et al., New England Journal of Medicine, Feb. 8, 2001, 344:6, p. 424-9}: loading dose 15 mg/kg intravenously, follow by bolus dose of 10 mg/kg every 12 hours; after 48 hours, increase bolus dose to 15 mg/kg every 12 hours. Continue fomepizole until serum methanol, EG, DEG, TEG ar EGBE are undetectable. The signs and symptoms of poisoning include anion gap metabolic acidosis, CNS depression, renal tubular injury, and possible late stage cranial nerve involvement. Respiratory symptoms, including pulmonary edema, may be delayed. Persons receiving significant exposure should be observed 24-48 hours for signs of respiratory distress. Maintain adequate ventilation and oxygenation of the patient. In severe poisoning, respiratory support with mechanical ventilation and positive end expiratory pressure may be required. If lavage is performed, suggest endotracheal and/ar esophageal control. Danger from lung aspiration must be weighed against toxicity when considering emptying the stomach. Treatment of exposure should be directed at the central of symptoms and the clinical condition of the patient. 5. Fire Fighting Measures Extinguishing Media: Water fog or fine spray. Dry chemical fire extinguishers. Carbon dioxide fire extinguishers. Foam. Do not use direct water stream. May spread fire. Alcohol resistant foams (ATC type) are preferred. General purpose synthetic foams (including AFFFy or protein foams ma~n~~i~~tYS~k, F$~f~ed°aT~g~ $~/~~~~O~~f~~t~~e13 AM PAGE 4/005 Fax Server Eire Fighting Procedures: Keep people away. Isolate fire and deny unnecessary entry. Use water spray to cool fire exposed containers and fire affected sons until fire is out and danger of reignition has passed. Fight fire from protected location or safe distance. Consider the use of unmanned hose holders or monitor nozzles. Immediately withdraw all personnel from the area in case of rising sound from venting safety device or discoloration of the container. Burning liquids may be extinguished by dilution with water. Do not use direct water stream. May spread fire. Move container from fire area if this is possible without hazard. Burning liquids may be moved by flushing with water to protect personnel and minimize property damage. Special Protective Equipment for Firefighters: Wear positive-pressure self- contained breathing apparatus (SCSAj and protective fire fighting clothing (includes fire fighting helmet, coat, trousers, boots, and gloves). If protective equipment is not available or not used, fight fire from a protected location or safe distance. Unusual Fire and Explosion Hazards: Container may rupture from gas generation in a fire situation. Violent steam generation ar eruption may occur upon application of direct water stream to hot liquids. Hazardous Combustion Products: During a fire, smoke may contain the original material in addition to combustion products of varying composition which may be toxic and/or irritating. Combustion products may include and are not limited to: Carbon monoxide. Carbon dioxide. 5. Accidental Release Measures Steps to be Taken if Material is Released or Spilled: Small spills: Absorb with materials such as: Dirt, Sand, Sawdust, Vermiculite, Perlite, Zorb-all*, Oil-Dri or equivalent filler. Large spills: Dike area to contain spill. Pump into suitable and properly labeled containers. See Section 13, Disposal Considerations, for additional information. Personal Precautions: Keep unnecessary and unprotected personnel from entering the area. Use appropriate safety equipment. Far additional information, refer to Section 8, Exposure Controls and Personal 'Protection. Environmental Precautions: Prevent from entering into soil, ditches, sewers, waterways and/or groundwater. See Section l2, Ecological Information. 7. Handling and Storage Handling General Handling: Avoid contact with skin and clothing. Wash thoroughly after handling. Spills of these organic materials on hot fibrous insulations may lead to lowering of the autoignition temperatures possibly resulting in spontaneous combustion. See Section S, EXPOSURE CONTROLS AND FERSONAL PROTECTION. Storage Do not store near food, foodstuffs, drugs or potable water supplies. Additional storage and handling information on this product may be obtained by calling your sales or customer service contact. Ask for a product brochure. 8. Exposure Controls / Fersonal Protection Exposure Limits Component List Type Value Triethylene glycol Dow IHG TWA Total 100 mg/m3 Personal Protection Eye/Face Protection: Use safety glasses. If there is a potential far exposure to particles which could cause eye discomfort, wear chemical goggles. Skin Protection: When prolonged or frequently repeated contact could occur, use protective clothing chemically resistant to this material. Selection of specific items such as faceshield, boots, apron, or full-body suit will depend on the task. When handling hot material, protect skin from thermal burns as well as from skin absorption. U$~~i~rp~~4e~~~~~t~v~'~el~~~ib~~d~~e~Qa~i~ly3r~~is~~~i~ to5~~4~ ma~~~i~~r~b~tLn prolonged or frequently repeated contact could occur_ If hands are cut or scratched, use gloves chemically resistant to this material even for brief exposures. Use gloves with insulation for thermal protection, when needed. Examples of preferred glove barrier materials include: Butyl rubber. Polyethylene. Ethyl vinyl alcohol laminate ("EVAL"). Examples of acceptable glove barrier materials include: Viton. Neoprene. Natural rubber ("latex"), Polyvinyl chloride ("PVG" or "vinyl"). Nitrile/butadiene rubber ("nitrile" or "NBR°). NOTICE: The selection of a specific glove for a particular application and duration of use in a workplace should also take into account all relevant workplace factors such as, but not limited to; Other chemicals which may be handled, physical requirements (cut/puncture protection, dexterity, thermal protection), potential body reactions to glove materials, as well as the instructions/specifications provided by the glove supplier. Respiratory Protection: Respiratory protection should be worn when there is a potential to exceed the exposure limit requirements or guidelines. If there are no applicable exposure limit requirements or guidelines, wear respiratory protection when adverse effects, such as respiratory irritation or discomfort have been experienced, or where indicated by your risk assessment process. In misty atmospheres, use an approved particulate respirator. The following should be effective types of air-purifying respirators: Organic vapor cartridge with a particulate pre-filter. Ingestion: Use good personal hygiene. Do not consume or store food in the work area. Wash hands before smoking or eating. Engineering Controls Ventilation: Use local exhaust ventilation, or other engineering controls to maintain airborne levels below exposure limit requirements or guidelines. If there are no applicable exposure limit requirements or guidelines, general ventilation should be sufficient for most operations. Local exhaust ventilation may be necessary for some operations. 9. Physical and Chemical Properties Physical State Color Odor Flash Point - Closed Cup Flammable Limits In Air Autoignition Temperature Vapor Pressure Boiling Paint (760 mmHg) Vapor Density (air = i) Specific Gravity jH24 = 1) Freezing Point Melting Point Solubility in Water (by weight) PH Dynamic Viscosity 10. Stability and Reactivity Liquid Colorless Mild 177 C (351 F} ASTM D93 Lower: 0.9 ~(V) Calculated Upper: 9.2 AS(V) Estimated 349 C (660 F) Literature C 0.01 mmSg @ 20 C Literature 288 C (550 F} Literature Decomposes. 5.2 Literature 1.1255 20 C/20 C Literature -4.3 C (24.3 F) Literature No test data available 100 ~ Literature 8 Literature 49 cps @ 2D C Literature Stability/Instability Thermally stable at typical use temperatures. Conditions to Avoid: Exposure to elevated temperatures can cause product to decompose. Generation of gas during decomposition can cause pressure in closed systems. Incompatible Materials: Avoid contact with: Strong acids. Strang bases. Strong oxidizers. Hazardous Polymerization Will not occur. Th~g~~rD~~~m~~~~~~8~r 11/21/2008 Decomposition products depend upo of other materials. Decomposition to: Aldehydes. Alcohols. Ethers. 11. Toxicological Information 10:40;13 AM PAGE 6!009 Fax Server n temperature, air supply and the presence products can include and are not limited Acute Toxicity Ingestion LD50, Rat 16,800 - 22,060 mg/kg Skin Absorption LD50, Rabbit > 18,016 mg/kg Inhalation LC50, 4 h, Aerosol, Rat > 4.5 mg/1 Repeated Dose Toxicity Based on available data, repeated exposures are not expected to cause significant adverse effects except at very high aerosol concentrations, Repeated excessive aerosol exposures may cause respiratory tract irritation and even death. Chronic Toxicity and Carcinogenicity Did not cause Dancer in laboratory animals_ Develogmental Toxicity Triethylene glycol did not cause birth defects in animals; reduced fetal body weight effects were seen only at very high doses. Reproductive Toxicity In animal studies, did not interfere with reproduction. Genetic Toxicology In vitro genetic toxicity studies were negative. 12. Ecological Information CHEMICAL FATE Data for Component: Triethylene glycol Movement & Partitioning Bioconcentration potential is low (BCF less than 100 or log Fow less than 3). Potential for mobility in soil is very high (Koc between 0 and 50). Henry's Law Constant (H}: 4.37E-1D atm*m3/mole; 25 C Estimated Partition coefficient, n-octanol/water (log Paw): -1.75 Estimated Partition coefficient, sail organic carbonjwater (Koc): 10 Estimated Persistence and Degradability Material is ultimately biodegradable (reaches > 70~ mineralization in OECD test(s~ for inherent biodegradability). Material is readily biodegradable_ Passes OECD test(sy for ready biodegradability. Indirect Photodegradation with OH Radicals Rate Constant Atmospheric Half-life Method 3.64E-11 cm3/s 3.5 h Estimated OECD Biodegradation Tests: Biodegradation Exposure Time Method 25 - 92 ~ OECD 301C Test > 70 - 45 ~ 2 - 14 d OECD 302E Test Biological oxygen demand {BOD): BOD 5 BOD 10 BOD 20 BOD 28 12 - 32 ~ 15 - 64 $ 17 - 86 ~ Theoretical Oxygen Demand: 1.60 mg/mg ECOTOXICITY Data for Component: Triethylene glycol Material is practically non-toxic to aquatic organisms on an acute basis (LC50/EC50 >100 tttig/L in the most sensitive species tested). Fish Acute & Prolonged Toxicity LC50, bluegill (Lepomis macrochirus), 96 h: 61,000 mg/1 Aquatic Invertebrate Acute Toxicity EC50, water flea Daphnia magna, 48 h: 49,000 mg/1 Toxicity to Micro-organisms U~~~~r $a~~t~~~~~r~'~~w~~/ $~,fi~$4~ib$ ~ ~8e~~ ~nsPi~Ereat~E'~4~n) , ~~34: §g~;'~~omg/1 Aquatic Invertebrates Chronic Toxicity Value: ChV Value mg/1 Species Test Type Endpoint Exposure Time 10607 mg/1 water flea static renewal growth 21 d Daphnia magna 13. Disposal Considerations DO NOT DUMP INTO ANY SEWERS, ON THE GROUND, OR INTO ANY BODY OF WATER. All disgosal practices must be in compliance with all Federal, State/Provincial and local laws and regulations. Regulations may vary in different locations. Waste characterizations and compliance with applicable laws are the responsibility solely of the waste generator. WE HAVE NO CONTROL OVER THE MANAGEMENT PRACTICES OR MANUFACTURING PROCESSES OF PARTIES HANDLING OR USING THIS MATERIAL. THE INFORMATION PRESENTED HERE PERTAINS ONLY TO THE PRODUCT AS SHIPPED IN ITS INTENDED CONDITION AS DESCRIBED IN MSDS SECTION: Composition Information. FOR UNUSED & UNCONTAMINATED PRODUCT, the preferred options include sending to a licensed, permitted: Reclaimer. As a service to our customers, we can provide names of information resources to help identify waste management companies and other facilities which recycle, reprocess or manage chemicals or plastics, and that manage used drums. Please contact our Customer Information Group (telephone number in Section 1 of this document} for further details. 14. Transport Information DOT Non-Bulk NOT REGULATED DOT Bulk NOT REGULATED IMDG NOT REGULATED ICAO/IATA NOT REGULATED This information is not intended to operational requirements/information transportation system information ca or customer service representative. transporting organization to follow rules relating to the transportation convey all specific regulatory or relating to this product. Additional n be obtained through an authorized sales It is the responsibility of the all applicable laws, regulations and of the material. 15. Regulatory Information OSHA. Hazard Communication Standard This product is a "Hazardous Chemical" as Communication Standard, 29 CFR 1910.1200. Superfund Amendments and Reauthorization Planning and Community Right-to-Know Act Immediate (Acute) Health Hazard No Delayed (Chronic) Sealth Hazard Yes Fire Hazard No Reactive Hazard No Sudden Release of Pressure Hazard No defined by the OSHA Hazard Aet of 1986 Title III {Emergency of 1986} Sections 311 and 312 Superfund Amendments and Reauthorization Act of 1986 Title III {Emergency Planning and Community Right-to-Know Act of 1986) Section 313 To the best of our knowledge, this product does not contain chemicals at levels which require reporting under this statute. Pennsylvania {Worker and Community Right-To-Know Act): Fennsylvania Hazardous Substances List andfor Pennsylvania Environmental Hazardous Substance List: The following product components are cited in the Pennsylvania Hazardous Su~$~~f~&eU£~s~a~t~@}~~3~rt1~~~~~{~~i~~~v~~i$Q~~~i~nm~~~~l S~i~~~nceF~~s~er~~~ are present at levels which require reporting. Component CAS # Amount Triethylene glycol 112-27-6 >= 99.5 ~ Pennsylvania (Worker and Community Right-To-Know Act}: Pennsylvania Special Hazardous Substances List: To the best of our knowledge, this product does not contain chemicals at levels which require reporting under this statute. California Proposition 65 (Safe Drinking Water and Toxic Enforcement Act of 1986} WARNING: This product contains a chemical(s) known to the State of California to cause cancer. Component CAS # Amount Formaldehyde 50-00-0 <= 47.0 PPM Acetaldehyde 75-07-0 <= 15.6 PPM U.S. Toxic Substances Control Act All components of this product are on the TSCA Inventory or are exempt from TSCA Inventory requirements under 40 CFR 720.30 European Inventory of Existing Commercial Chemical Substances (EINECS} The components of this product are an the EINECS inventory or are exempt from inventory requirements. CEPA - Domestic Substances List (DSL} All substances contained in this product are listed on the Canadian Domestic Substances List (DSL} or are not required to be listed. 16. Other Information Product Literature Additional information on this and other products we offer may be obtained by contacting our Customer Information Group. Ask far a product information brochure or data on how to access our website. Hazard Rating System NFPA Health Fire Reactivity 1 1 0 Recommended Uses and Restrictions Far industri al use only. Gas treating. It is recommended that you use this product in a manner consistent with the recommended use. If your intended use is not consi stent with the recommended use, please contact our Customer Information Group (telephone number in Section 1 of this document}. Legend NjA Not available WjW WeightjWeight OEL Occupational Exposure Limit STEL Short Term Exposure Limit TWA Time Weighted Average ACGIH American Conference of Governmental Industrial Hygienists, Inc. DOW IHG Dow Industrial Hygiene Guideline WEEL Workplace 8nviranmental Exposure Level HA2 DES Hazard Designation Action Level A value set by OSHA that is lower than the PEL which will trigger the need for activities such as exposure monitoring and medical surveillance if exceeded. * Indicates a Trademark -------------------------- FOR ADDITIONAL INFORMATION -------- CONTACT: MSDS COORDINATOR UNIVAR USA INC. DURING BUSINESS HOURS, PACIFIC TIME 1425)869-3400 ------------------------------------ NOTICE --------__-__----------------------- *********** UNIVAR USA INC ("UNIVAR"} EXPRESSLY DISCLAIMS __lIUiYar_iI~a_Eax~~ry~r_111Z1LZD4~_11~~44+1~_8M__PBDE___U144~___Eax_~Ur~t~r________ ALL EXPRESS OR IMPLIED WARRANTIES OF MERCHANTABILITY AND FITNESS FOR A -------------------------------------------------------------------------------- PARTICULAR PURPOSE, WITH RESPECT TO THE PRODUCT OR INFORMATION PROVIDED HEREIN, -------------------------------------------------------------------------------- AND SHALL UNDER NO CIRCUMSTANCES BE LIABLE FOR INCIDENTAL OR CONSEQUENTIAL DAMAGES.** DO NOT USE INGREDIENT INFORMATION AND/OR INGREDIENT PERCENTAGES IN THIS MSDS AS A PRODUCT SPECIFICATION. FOR PRODUCT SPECIFICATION INFORMATION REFER TO A PRODUCT SPECIFICATION SHEET AND/OR A CERTIFICATE OF ANALYSIS. THESE CAN BE OBTAINED FROM YOUR LOCAL UNIVAR SALES OFFICE. ALL INFORMATION APPEARING HEREIN IS BASED UPON DATA OBTAINED FROM THE MANUFACTURER AND/OR RECOGNIZED TECHNICAL SOURCES. WHILE THE INFORMATION IS BELIEVED TO BE ACCURATE, UNIVAR MAKES NO REPRESENTATIONS AS TO ITS ACCURACY OR SUFFICIENCY. CONDITIONS OF USE ARE BEYOND UNIVARS CONTROL AND THEREFORE USERS ARE RESPONSIBLE TO VERIFY THIS DATA UNDER THEIR OWN OPERATING CONDITIONS TO DETERMINE WHETHER THE PRODUCT IS SUITABLE FOR THEIR PARTICULAR PURPOSES AND THEY ASSUME ALL RISKS OF THEIR USE, HANDLING, AND DISPOSAL OF THE PRODUCT, OR FROM THE PUBLICATION OR USE OF, OR RELIANCE UPON , INFORMATION CONTAINED HEREIN. THIS INFORMATION RELATES ONLY TO THE PRODUCT DESIGNATED HEREIN, AND DOES NOT RELATE TO TTS USE IN COMBINATION WITH ANY OTHER MATERIAL OR IN ANY OTHER PROCESS. *** E N D O F M S D S • • Page 1 of 3 Regg, James B (DOA) From: Regg, James B (DOA) Sent: Thursday, November 20, 2008 4:55 PM ~ G I{~ ~ I~~ To: 'Bruce D Webb' (, Subject: RE: Freeze protect Aspen Well make sure you address fluid compatibility in your application; should be laboratory analyses or other evidence of compatibility of fluids that were net already addressed in DIO {freeze protection fluids} Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 907-793-1236 From: Bruce D Webb [mailto:bwebb@aurorapower.com] Sent: Thursday, November 20, 2008 3:12 PM To: Regg, James B (DOA); Maunder, Thomas E (DOA) Subject: RE: Freeze protect Aspen Well Gentlemen, I will prepare and request for Administrative Approval of the fluids, and amounts, that we would like to use for freeze protection, and request for a delineation of all fluids general) eligible for Class II disposal. Once again, thank you for your time and guidance. -Bruce From: Regg, James B (DOA) [mailto:jim.regg@alaska.gov] Sent: Thursday, November 20, 2008 2:50 PM To: Maunder, Thomas E (DOA); Bruce D Webb Subject: RE: Freeze protect Aspen Well We could include freeze protect fluids in injection orders; we have not routinely included in the past DIOs. I think it is understood as failing under the "other fluids" eligibility standard for Class II injection that takes acase-by-case approach for approval. Afiter looking over the past several DIOs, what appears as inconsistent wording is attributed to the way the applications address fluids eligible for Class II injection. All orders have the admin approval clause to address fluids not specifically identified {good reason for general reference to Class II fluids instead of listing specific fluids). In 2003-04, EPA had heartburn over BP's freeze protect fluids for Class I wells on the Slope. In my mind, BP really restricted the definition for freeze protect fluids {at least for Class I wells} with what they told EPA to get approval, i.e., diesel and methanol are unused, and are not recycled or reclaimed fluids from some other operation. Fortunately, Class II injection was not included in the discussion/decision. The Commission considers freeze protection as being incidental to and integrally necessary for the safe operation of an injection well {particularly one that is used intermittently}; by operation, I mean bath the fluid and the likely injection of the fluid into the formation since flowback is usually impractical. Since the freeze protect fluid is placed downhole for a very specific purpose {and not being cycled in the well just so it can be disposed}, I believe there is no question about Class II disposal injection eligibility of fluids that have been in the wellbore for freeze protection. 11 /20/2008 • Page 2 of 3 ( suppose the Aspen DIO could be interpreted as being restrictive regarding eligible fluids. After looking at the DIO application and what is suggested below, it may be appropriate for Aurora to request admin approval to delineate the fluids eligible for Class 11 disposal. Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 907-793-1236 From: Maunder, Thomas E (DOA) Sent: Thursday, November 20, 2008 9:39 AM To: Regg, James B (DOA) Subject: FW: Freeze protect Aspen Well Freeze protecting is a necessary operation in cold climates. Is freeze protecting something that should be acknowledged in the DIO? Tom From: Bruce D Webb [mailto:bwebb@aurorapower.com] Sent: Thursday, November 20, 2008 9:09 AM To: Maunder, Thomas E (DOA) Subject: FW: Freeze protect Aspen Well Tom, Because of winter conditions, and the fact that we are primarily injecting water at Aspen, what are we allowed to use as freeze protection in the wellhead/tubing? Whatever we use will end up being injected the next time we inject fluids. See Chad's comments below. Thank you. -Bruce From: Bruce D Webb [mailto:bwebb@aurorapower.com] Sent: Wednesday, November 19, 2008 4:34 PM To: 'Chad Helgeson' Subject: RE: Freeze protect Aspen Well I mentioned this to Pirtle yesterday and he said CIRI would defer to the AOGCC, so I will call AOGCC tomorrow. From: aurorapower@gci.net [mailto:aurorapower@gci.net] On Behalf Of Chad Helgeson Sent: Wednesday, November 19, 2008 4:22 PM To: 'Bruce D Webb' Subject: Freeze protect Aspen Well Bruce, Can you find out what we can put in the Aspen well for freeze protection? Check with both the state and CIRI? I would like to have the option for Methanol, used triethylene glycol (class II waste as production fluid), and/or new glycol.. This is something that I would like to do after we inject every time, so I would like to get something in writing for our 11 /20/2008 Page 3 of 3 options for freeze protection fluids. Chad 11 /20/2008 • • Page 1 of 1 Regg, James B (DOA) From: Bruce D Webb [bwebb@aurorapower.com] Sent: Monday, November 19, 2007 9:53 AM ilyl ~l~t~'l(~ 7 To: Regg, James B (DOA) Subject: RE: Aspen Water Disposal Well injection Order Jim, It does appear the depths indicated in the 5/15/07 letter were in error. The lower depth indicated in the letter had two numbers transposed. In the Well Schematic supplied with the permit and letter ofi 5/15/07, it indicates the disposal perforations to be 2,125 to 2,371 (md), AND IN Ed Jones most recent e-mail of 10/11/07 he stated, in part: "The NuTech frac study indicated that the fractures created by injection mud of water will be confined between 2098' and 2412' (top proposed pert is at 2125' and bottom pert at 2371'. Thus, the injected fluids should confined within this interval, as there are hundreds of feet of impermeable layers above this depth." 1 apologize for the mis-information and any inconvenience it has caused. The injected fluids will be confined between 2,098' and 2,412' {MD) and the perforated interval for injection of the fluids will be between 2,125' and 2,371' (MD). I hope this clarifies the conflicting information. Have a wonderful holiday season. Regards, -Bruce 11/19/2007 Page 1 of 1 • Davies, Stephen F {DOA} From: Chad He{geson [chelgeson~aurorapower.com] Sent: Tuesday, October 16, 2007 9:18 AM To: Davies, Stephen F (DOA) Cc: 'Bruce D Webb ; 'Ed Jones' Subject: Aspen Disposal Well Water Analysis Attachments: Water Scaling Calculations.pdf L~ Steve, Please find attached the calculations I performed to determine the scaling tendencies of the water from the laboratory anatysis that was completed in August of 2007. The data used in these calculations is from the Laboratory report we have already provided you. In summary Calcium Carbonate Scaling Two of the water anayses indicate that calcium carbonate scales or precipitates may form in the water. These were the Three Mile Creek #1 and #2 wells producing water from. the Beluga formation. The calculations do not indicate scaling as being likely from the Nicolai Creek #9 Well producing from the Tyonek Formation or the produced water storage pond. We have seen some precipitates forming in our compressor at Three Mile Creek where the gas temperatures are close to 300 deg F. Calcium Sulfate Scaling None of the water analyses indicate that Calcum Sulfate scaling or preapitation is likely to form. The calcium carbonate scaling can be monitored with coupons and monitoring injection pressures. I will follow-up this email with a phone call to discuss. Chad i ai16~2o0~ • M Produced Water Scaling Calculations Reference: Oilfield Water Systems by Charles Patton Campbell Petroleum Series {pages 220-224) Well: Nicolai Creek #9 Water Analysis collected Juiy 19, 2007 Ion Concentration (mg /I) Conversion factor Ionic Strength Calc Na+ 2820 0.000022 0.06204 Ca++ 86.1 0.00005 0.004305 Mg++ 54.8 0.000082 0.0044936 CI- 4790 0.000014 0.06706 C03- 0 0.000033 0 HC03- 198 0.0000082 0.0016236 S04- 1.08 0.000021 0.00002268 Total Ionic Strength 0.13954488 =u Temp (deg C) 20 Calcium Carbonate Scaling Index pH 6.5 K 2.56 From Appendix 10 (graph) pCa 2.657 From Appendix 11 (graph) pAlk 2.5 From Appendix 11 (graph) Scaling Index -1.217=pH-(K+pCa+pAlk) SI<0, so CaC03 scale is unlikely Calcium Sulfate Solubility Calculation K 0.0004 From Appendix 12 (graph) 4xK 0.0016 Ion Conc (mg/I) Conv Factor M (moles/I) Ca++ 86.1 0.000025 0.0021525 S04- 1.08 0.0000104 0.000011232 deltaM 0.002141268 =X Solubility 38.04206188 =S=1000*[SQRT{{0.147+4K)x10^-4)-X] Ion Conc (mg/I) Equiv. Wt. Conc I~..ii OG A 'ff~ A SO4-- 1.08 48 S>actual, so CaSO4 scale is unlikely Actual Concentraion NCU #9 Page 1 of 1 • • Produced Water Scaling Calculations Reference: Oilfield Water Systems by Charles Patton Campbell Petroleum Series (pages 220-224) Well: Three Mile Creek #1 Water Analysis collected July 19, 2007 Ion Concentration (m g/I) Conversion factor Ionic Strength Calc Na+ 5690 0.000022 0.12518 Ca++ 47.6 0.00005 0.00238 IVIg++ 69.6 0.000082 0.0057072 CI- 6400 0.000014 0.0896 CO3-- 0 0.000033 0 HCO3- 1730 0.0000082 0.014186 SO4- 5.61 0.000021 0.00011781 Total Ionic Strength 0.23717101 =u Temp (deg C} 20 Calcium Carbonate Scaling Index pH 7.7 K 2.96 From Appendix 10 (graph) pCa 2.9 From Appendix 11 {graph) pAlk 1.55 From Appendix 11 (graph) Scaling Index r- 0.29 =pH-(K+pCa+pAlk} SI>0, so CaCO3 scale may occur Galcium Sulfate Solubility Calculation K 0.00058 From Appendix 12 (graph} 4xK 0.00232 Ion Conc (mgn) Conv Factor M (moles/I) Ca++ 47.6 0.000025 0.00119 504- 5.61 0.0000104 0.000058344 deltaM 0.001131656 =X Solubility 23.25481566 =S=1000*[SQRT((0.147+4K}x10^-4}-X Ion Conc {mg/I) Equiv. Wt. Conc (meg/I) Ca++ ~ 47.6 20 2.38 Actual Concentraion SO4- 5.61 48 0.116875 S>actual, so CaSO4 scale is unlikely TMC#1 Page 1 of 1 • M Produced Water Scaling Calculations Reference: Oilfield Water Systems by Charles Patton Campbell Petroleum Series {pages 220-224) Well: Three Mile Creek #2 Water Analysis collected July 19, 2007 Ion Concentration (m g/I) Conversion factor Ionic Strength Calc Na+ 706 0.000022 0.015532 Ca++ 49.8 0.00005 0.00249 Mg++ 29.2 0.000082 0.0023944 CI- 331 0.000014 0.004634 CO3-- 0 0.000033 0 HCO3- 1290 0.0000082 0.010578 SO4- 0 0.000021 0 Total Ionic Strength 0.0356284 =u Temp (deg C) 20 Calcium Carbonate Scaling Index pH 8.1 K 2.1 From Appendix 10 (graph) pCa 2.9 From Appendix 11 (graph) pAlk 1.7 From Appendix 11 (graph} Scaling Index 1.4 =pH-(K+pCa+pAlk) SI>0, so CaCO3 scale may occur Calcium Sulfate Solubility Calculation K 0.00018 (Appendix 12) 4K 0.00072 Ion Conc (mg/I) Conv Factor M (moles/I) Ca++ 49.8 0.000025 0.001245 SO4- 0 0.0000104 0 deltaM 0.001245 =X Solubility 12.70849419 =S=1000*[SQRT((0.147+4K}x10^-4)-X] Ion Conc {m /I Equiv. Wt. Conc (me /I Ca++ 49.8 20 2.49 Actual Concentraion SO4- 0 48 0 S>actual, so CaSO4 scale is unlikely TMC#2 Page 1 of 1 • M Produced Water Scaling Calculations Reference: Oilfield Water Systems by Charles Patton Campbell Petroleum Series (pages 220-224) Well: Produced Water Storage Pond Water Analysis collected July 19, 2007 Ion Concentration (mg/I) Conversion factor Ionic Strength Calc Na+ 6250 0.000022 0.1375 Ca++ 214 0.00005 0.0107 Mg++ 56.3 0.000082 0.0046166 CI- 9900 0.000014 0.1386 CO3-- 0 0.000033 0 HCO3- 846 0.0000082 0.0069372 SO4- 31.9 0.000021 0.0006699 Total Ionic Strength 0.2990237 =u Temp {deg C) 20 Calcium Carbonate Scaling Index pH 5.65 K 3.07 From Appendix 10 (graph) pCa 2.27 From Appendix 11 (graph) pAlk 1.95 From Appendix 11 (graph) Scaling Index -1.64 =pH-(K+pCa+pAlk) SI<0, so CaCO3 scale is unlikely Calcium Sulfate Solubility Calculation K 0.00072 From Appendix 12 {graph) 4xK 0.00288 Ion Conc (mgll) Conv Factor M (moles/l) Ca++ 214 0.000025 0.00535 SO4-- 31.9 0.0000104 0.00033176 deltaM 0.00501824 =X Solubility 22.08711003 =S=1000*[SQRT((0.147+4K)x10^-4)-X] Ion Conc (mgll) Equiv. Wt. Conc Ca++ 214 20 ~ 10.7 Actual Concentraion SO4-- 31.9 48 0.664583333 S>actual, so CaSO4 scale is unlikely PWP Page 1 of 1 Page 1 of 3 Colombie, Jody J (DOA) From: Regg, James B (DOA) Sent: Monday, October 15, 2007 8:38 AM To: Colombie, Jody J (DOA); Davies, Stephen F (DOA) Cc: Maunder, Thomas E (DOA); Roby, David S (DOA) Subject: FW: Aspen Water Disposal Well injection Order Too many points of contact; I have what I need to complete the DIO; they previously submitted fluid compatibility and water analysis Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 phone: 907-793-1236 fax: 907-276-7542 From: Bruce D Webb [mailto:bwebb@aurorapower.com] Sent: Friday, October 12, 2007 4:10 PM To: Regg, James B (DOA) Subject: RE: Aspen Water Disposal Well injection Order Jim, I have prepared a fetter which reiterates the information that Ed Jones has supplied. It also amends the application requesting a maximum injection rate of 3 bbl/min. The 5bbl/min was a remnant of the Nicolai Creek #5 application which I had used as a guide and inadvertently did not change following the fracture analysis study for the Aspen well. I am planning on talking to Steve Davies when he returns on Monday to verify that he had received everything he needed concerning the water analysis and fluid compatibility. Once that is verified, I will submitthe letter to the Commission, along with copies of the certified receipts of the Notice mailed to the landowners. After reviewing the information that Ed has supplied to you, could you let me know if it is satisfactory, or if you need anything else? I appreciate your time and understanding. -Bruce From: Ed Jones [mailto:jejones@aurorapower.com] Sent: Friday, October 12, 2007 1:13 PM To: 'Regg, James B (DOA)' Cc: 'Bruce D Webb'; 'Chad Helgeson' Subject: RE: Aspen Water Disposal Well injection Order Jim, Thanks for your quick response. Let me address these outstanding concerns: 1) As we have done more work on this project, it appears that the Request for DIO should be amended: I don't foresee ever needing a rate over 3 BPM. The mention of maximum pressure of 1500 psi was worded in such a way to give us some flexibility pending the outcome of the step-rate test, but it was anticipated as the highest maximum that we'd need. (The reason for limiting it to 1500 psi is that is the pressure to which we propose testing 10/15/2007 Page 2 of 3 the casing above the packer. However, with a packer in the well, the annular pressure monitored, and good casing cement, which the bond log indicates that we have, this should not be a concern). We plan to do a step- rate test to determine what pressures are needed (but as time goes on, the injection pressures will likely increase somewhat), but I do not foresee a need for a maximum higher than 1500 psi. The NuTech NuStim analysis was run at 1 BPM for produced water and indicated that the injection pressures will be lower than 1500 psi (see the NuStim "Analysis of Injection Project" report, pages 17 and 19)--note that the modeling assumes all the water (and rate) goes into one interval, and we will have 2 intervals open (i.e, each interval, 2125-45' [Interval 2] and 2351-2371' [Interval 1], was modeled separately, so all the rate is assumed to go into one interval). In reality, with both intervals open, as is the plan, the rate will be divided between the 2 intervals, with the Interval 2 taking more rate at a given pressure than Interval 1--thus, we should not see pressures as high as modeled. This is even more true for the injection of drilling mud. The highest pressure (and the only case in which 1500 psi was exceeded) was with drilling mud injected into only Interval 1 at 3 BPM(note that the 3 batch injections over the 84 days are at increasing rates, the first is at 1 BPM, the second at 2 BPM, and the third at 3BPM--this increasing pressure is due to the increased rate, not so much injected volume, although there appears to be a slight increase in static pressure due to injected volume, but it is not significant compared to the increase of injection pressure due to increased rate). Again, with both zones open, the rate going into Interval 1 will likely not exceed 1 BPM, so the pressure should be 1100 psi or so--about the same pressure on Interval 2 at 2 BPM (see pages 18 and 20 of the NuStim report}. Thus, we do not anticipate a maximum allowable surface injection pressure of 1500 psi being a problem. 2) Regarding the injection of drilled cuttings, this year we are disposing most of our cuttings (and some mud) in the Kenai Borough land fill after mixing with Portland cement. Some larger materials were screened out, washed, and will be used as road/pad fill, as a Beneficial Use. In the future we will likely again separate the larger material and dispose in the landfill or as Beneficial Use, and dispose of only the cuttings fines (passing thru a 150 or 200 mesh screen) along with the drilling mud by injecting into this well. Shall we write a letter to the AOGCC to amend this DIO rate to 3 BPM maximum, or will you do that as part of the approval process? Please let me know the best way to handle this, and also let me know if you have additional questions, need more clarification, or need any other information. Thanks, Ed Jones (713-977-5799) From: Regg, James B (DOA) [mailto:jim.regg@alaska.gov] Sent: Friday, October 12, 2007 2:48 PM To: Ed Jones Cc: Bruce D Webb; Chad Helgeson Subject: RE: Aspen Water Disposal Well injection Order Thank you for the information. The other item from the hearing was a request for Aurora to clarify what appear to be inconsistencies between the "Analysis of Injection Project" (Analysis) dated August 8, 2007 and initial request for DIO provided May 15, 2007. The specific concern regards injection rates and pressures. The May 15 application identifies injection rates up to 5 bbl per minute and pressures up to 1500 psi; the Analysis indicates 1 bbl per min rates was used for all frac modeling and indicates resulting surface pressures up to 1600 psi (est) after just 3 of the batch injections. One other clarification needed: the application indicates the disposal waste stream will include drill cuttings; Mr. Webb indicated during the hearing that cuttings will be disposed at the Kenai Peninsula land fill. Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 phone: 907-793-1236 fax: 907-276-7542 10/15/2007 Page 3 of 3 From: Ed Jones [mailto:jejones@aurorapower.com] Sent: Thursday, October 11, 2007 2:25 PM To: Regg, James B (DOA) Cc: 'Bruce D Webb'; 'Chad Helgeson' Subject: Aspen Water Disposal Well injection Order Jim, Bruce Webb informed me that one of the issues coming out of the Aspen Injection Order hearing on Tuesday, Oct. 9th was: Geologic Formation information on how the injection fluids are going to be confined. What assurance or certainty do we have, that we can exhibit to them, that the fluids will not migrate upwards into potential fresh water aquifers? The best response to this concern is to look at the Horizon Well Logging mud log of Aspen #1 (August 2005)--a copy was submitted to the AOGCC on a CD on June 15, 2006 (let me know if you need acopy--I'd attach one but it is a 9 MB .pdf file). The mud log indicates that the lithology descriptions of the samples over the interval of 1400-1900' MD is mostly "claystone," or "clay" with a few small, thin sands and coals interspersed (based on the lithology symbols, some sand in samples of only 120' of the 500'--usually 10% of those samples, at most 20%). By the lithological symbols used in the descriptions, there was some coal (usually 20%) in samples of about 100' of the 500', but the bulk of the samples are clay, siltstone, and claystone. These three components have very little effective permeability, allowing essentially no migration of fluids (including gas) in measurable time. The NuLook log by NuTech (copy attached), a computerized composite petrophysical analysis using all available electric logs, indicates that the effective permeability over this same section is very low. In the section from 1810-1980', there are 10 intervals with any indicated perm, all perms are less than 2 md, and all "permeable intervals" are less than 10' thick and usually separated by 10-20' of impermeable formation. In the interval from 1410' to 1750', there are (by NuTech's evaluation) numerous thin intervals with perms of 0.5 to 10 md, but all are separated by impermeable intervals of 5' to 20' thickness. Furthermore, the interval from 1300' up to 700' is much the same--very little sand in the sample descriptions on the mud log (none in the samples from 780' to 980'), a few thin coal stringers, and claystone, clay, and siltstone matrix. While the NuLook logs indicates that there are several fairly permeable sands in this interval, but all are isolated by impermeable layers, including several that are 20-25' thick. The NuTech frac study indicated that the fractures created by injection mud of water will be confined between 2098' and 2412' (top proposed perf is at 2125' and bottom perf at 2371'. Thus, the injected fluids should confined within this interval, as there are hundreds of feet of impermeable layers above this depth. The Cement Bond Log (Schlumberger SCMT of 23 August 2005) indicates that the top of cement is at about 220' (inside the surface casing), and there is much good to excellent bond between the perfs and shallower potential fresh water aquifers. Furthermore, the bond around the perfs is very good. Subsequent to that log, perforations at 1368-88' and 1760-70' were squeezed with cement, which should have improved the bond in those proximities (although the bond around 1760-70' was already excellent by the log). These factors all combined indicate that the injected fluids should be confined vertically to the proximity of the perfs and not migrate upward. Please let me know if you have any questions or concerns after reviewing this data. Regards, Ed J. Ed Jones Vice President Engineering & Operations Aurora Gas, LLC 713-977-5799 (Houston) 907-277-1003 (Anchorage) 10/15/2007 Page 1 of 3 Regg, James B (DOA) From: Regg, James B (DOA) Sent: Friday, October 12, 2007 3:46 PM To: 'Ed Jones' Subject: RE: Aspen Water Disposal Well injection Order I missed the notes on the charts "Predicted Frac Dimensions" for the drilling mud; thank you for pointing that out and clarifying the rate and pressures; I do not see a need for you to request an amendment to the DIO; we can handle this in the findings, conclusions and rules of the injection order based on this exchange of information; copy of this email will be placed in the file. Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 phone: 907-793-1236 fax: 907-276-7542 From: Ed Jones [mailto:jejones@aurorapower.com] Sent: Friday, October 12, 2007 1:13 PM To: Regg, James B (DOA) Cc: 'Bruce D Webb'; 'Chad Helgeson' Subject: RE: Aspen Water Disposal Well injection Order Jim, Thanks for your quick response. Let me address these outstanding concerns: 1) As we have done more work on this project, it appears that the Request for DIO should be amended: I don't foresee ever needling a rate over 3 BP .The mention of maximum pressure of 1500 psi was worded in such a way to give us some flexibility pending the outcome of the step-rate test, but it was anticipated as the highest maximum that we'd need. (The reason for limiting it to 1500 psi is that is the pressure to which we propane testing the casing above the packer. However, with a packer in the well; the annular pressure monitored, and good casing Dement; which the bond log indicates that we have, this should not be a concern). We plan to do a step-rate test to determine what pressures are needed (but as time goes on, the injection pressures will likely increase somewhat), but I do not foresee a need for a maximum higher than 1500 psi. The I~JuTeDh NuSti analysis was run at 1 BPM for produced water and indicated that the injection pressures will be lower than 1500 psi (see the iditi '°alysis of trtjectio Project" report, pages 17 and 19)--note that the modeling assumes all the water (and rate} goes into one interval, and we will have 2 intervals open (i.e, each interval, 2125- 45" [Interval j and 2351-2371' [interval 1], was modeled separately, so all the rate is assumed to go info one interval). In reality, with both intervals open, as is the plan, the rate will be divided between the 2 intervals, with the interval 2 taking more rate at a given pressure than Interval 1--thus, we should not see pressures as high as modeled. This is even more true for the injection of drilling mud. The highest pressure (and the only case in which 1500 psi was exceeded) was with drilling mud injected into only Interval 1 at B (note that the 3 batch injections over the 84 days are at increasing rates, the first is at '! BPM, fibs second at 2 BPM, and the third at 3BPM--this increasing pressure is dun to the increased rate, not so muDh injected volume, although there appears to be a slight increase in static pressure due to injected volume, but it is not significant compared to the increase of injection pressure due to increased rate). Again, with both zones open, the rate going into Interval 1 will likely not exceed 1 BPM; so the pressure should be 1100 psi or so--abaut the same pressure on interval 2 at 2 BPM (see pages 18 and 20 of the NuStim report). Thus, we do not anticipate a maximum allowable surface injection pressure of 1500 psi being a problem. 2) Regarding the injection of drilled cuttings, this year we are disposing most of our cuttings {and some mud) in the Kenai Borough land fill after mixing with Portland cement. Some larger materials were sDreened out, washed, and will be used as roadlpad fill, as a ,Beeficfat t1se. In the future we will likely again separate the larger material and dispose in the landfill or as Beneficial Use, and dispose of only the cuttings fines (passing thru a 150 or 200 mesh screen) along with the drilling mud by injecting into this well. Shall we write a letter to the AOGCC to amend this DIO rate to 3 BPM maximum; or will you do that as part of the 10/15/2007 Page 2 of 3 approval process? Please let me kno~e best way to handle this, and also let m~w if you have additional questions, need more clarification, or Head any other information. Thanks, Ed Jones (713-977-5799) From: Regg, James B (DOA) [mailto:jim.regg@alaska.gov] Sent: Friday, October 12, 2007 2:48 PM To: Ed Jones Cc: Bruce D Webb; Chad Helgeson Subject: RE: Aspen Water Disposal Well injection Order Thank you for the information. The other item from the hearing was a request for Aurora to clarify what appear to be inconsistencies between the "Analysis of Injection Project" (Analysis} dated August 8, 2047 and initial request for DIO provided May 15, 2007. The specific concern regards injection rates and pressures. The May 15 application identifies injection rates up to 5 bbl per minute and pressures up to 1500 psi; the Analysis indicates 1 bbl per min rates was used for all frac modeling and indicates resulting surface pressures up to 1600 psi (est) after just 3 of the batch injections. One other clarification needed: the application indicates the disposal waste stream will include drill cuttings; Mr. Webb indicated during the hearing that cuttings will be disposed at the Kenai Peninsula land fill. Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 phone: 907-793-1236 fax: 907-276-7542 From: Ed Jones [mailto:jejones@aurorapower.com] Sent: Thursday, October 11, 2007 2:25 PM To: Regg, James B (DOA) Cc: 'Bruce D Webb'; 'Chad Helgeson` Subject: Aspen Water Disposal Well injection Order Jim, Bruce Webb informed me that one of the issues coming out of the Aspen Injection Order hearing on Tuesday, Oct. 9th was: Geologic Formation information on how the injection fluids are going to be confined. What assurance or certainty do we have, that we can exhibit to them, that the fluids will not migrate upwards into potential fresh water aquifers? The best response to this concern is to look at the Horizon Well Logging mud log of Aspen #1 (August 2005)--a copy was submitted to the AOGCC on a CD on June 15, 2006 (let me know if you need acopy--I'd attach one but it is a 9 MB .pdf file). The mud log indicates that the lithology descriptions of the samples over the interval of 1400-1900' MD is mostly "claystone," or "clay" with a few small, thin sands and coals interspersed (based on the lithology symbols, some sand in samples of only 120' of the 500'--usually 10% of those samples, at most 20%). By the lithological symbols used in the descriptions, there was some coal (usually 20%) in samples of about 100' of the 500', but the bulk of the samples are clay, siltstone, and claystone. These three components have very little effective permeability, allowing essentially no migration of fluids (including gas) in measurable time. The NuLook log by NuTech (copy attached), a computerized composite petrophysical analysis using all available electric logs, indicates that the effective permeability over this same section is very low. In the section from 1810-1980', there are 10 intervals with any indicated perm, all perms are less than 2 md, and all "permeable intervals" are less than 10' thick and usually separated by 10-20' of impermeable formation. In the interval from 1410' to 1750', there are (by NuTech's evaluation) numerous thin intervals with perms of 0.5 to 10 md, but all are separated by impermeable intervals of 5' to 20' thickness. Furthermore, the interval from 1300' up to 700' is much the same--very .little sand in the sample descriptions on the mud log (none in the samples from 780' to 980'), a few thin coal stringers, and claystone, clay, and siltstone matrix. While the NuLook logs indicates that there are several fairly permeable sands in this interval, but all are isolated by impermeable layers, including several that are 20-25' thick. The NuTech frac study indicated that the fractures created by injection mud of water will be confined between 2098' and 10/15/200'7 Page 3 of 3 2412' (top proposed perf is at 2125' a~ottom perf at 2371'. Thus, the injected fl~should confined within this interval, as there are hundreds of feet of impermeable layers above this depth. The Cement Bond Log (Schlumberger SCMT of 23 August 2005) indicates that the top of cement is at about 220' (inside the surface casing), and there is much good to excellent bond between the perfs and shallower potential fresh water aquifers. Furthermore, the bond around the perfs is very good. Subsequent to that log, perforations at 1368-88' and 1760-70' were squeezed with cement, which should have improved the bond in those proximities (although the bond around 1760-70' was already excellent by the log). These factors all combined indicate that the injected fluids should be confined vertically to the proximity of the perFs and not migrate upward. Please let me know if you have any questions or concerns after reviewing this data. Regards, Ed J. Ed Jones Vice President Engineering & Operations Aurora Gas, LLC 713-977-5799 (Houston) 907-277-1003 (Anchorage) 10/15/2007 • • Page 1 of 3 Regg, James B (DOA) From: Bruce D Webb [bwebb@aurorapower.com] Sent: Friday, October 12, 2007 4:10 PM To: Regg, James B (DOA) Subject: RE: Aspen Water Disposal Well injection Order Jim, I have prepared a letter which reiterates the information that Ed Jones has supplied. It also amends the application requesting a maximum injection rate of 3 bbl/min. The 5bbl/min was a remnant of the Nicoiai Creek #5 application which I had used as a guide and inadvertently did not change following the fracture analysis study for the Aspen well I am planning on talking to Steve Davies when he returns on Monday to verify that he had received everything he needed concerning the water analysis and fluid compatibility. Once that is verified, I will submit the letter to the Commission, along with copies of the certified receipts of the Notice mailed to the landowners. After reviewing the information that Ed has supplied to you, could you let me know if it is satisfactory, or if you need anything else? I appreciate your time and understanding. -Bruce From: Ed Jones [mailto:jejones@aurorapower.com] Sent: Friday, October 12, 2007 1:13 PM To: 'Regg, James B (DOA)' Cc: 'Bruce D Webb'; 'Chad Helgeson' Subject: RE: Aspen Water Disposal Well injection Order Jim, Thanks far your quick response. L.et me address these outstanding concerns: 1 } As we have done more work on this project, it appears that the Request for Di0 should b amended: I dan't fiaresee ever needing rate aver 3 BPM. The mention of maximum pressure of 1500 psi was worded in such a way to give us some flexibility pending the outcome of the step-rate test, but it was anticipated as the highest maximum that we'd need. (The reason for limiting it to 1500 psi is that is the pressure to which we propose testing the casing above the packer. However, with a packer in the well; the annular pressure monitored, and good casing cement; which the bond log indicates ttaat we have, this should not be a concern). We plan to do a step-rate test to determine what pressures are needed (but as time goes on, the injection pressures will likely increase somewhat), but 1 do not foresee a need for a maximum higher than 1500 psi. The NuTech IVSti analysis was run at 1 BPM for produced water and indicated that the injection pressures will be lower than 1500 psi (see the NStlm "Analysis of Injection Project" report, pages 17 and 19}--note that the modeling assumes all the water (and rate) goes into one interval, and we will have 2 intervals open (i.e, each interval, 2125- 45' [Interval 2] and 2351-2371' [Interval 1], was modeled separately, so ail the rate is assumed to go into one interval). In reality; with both intervals open, as is the plan, the rate will be divided between the 2 intervals, with the IntervaN 2 taking more rate at a given pressure than Interval 1--thus, we should not see pressures as high as modeled. This is even more true for the injection of drilling mud. The highest pressure (and the only case in which 1500 psi was exceeded) was with drilling mud Infected ~nta only Interval 1 at 3 P (note that the 3 batch injections over the 84 days are at increasing rates, the first is at 1 BPM; the second at 2 BPM, and the third at 3BPM--this increasing pressure is due to the increased rate, not so much injected volume, although there appears to be a slight increase in static pressure due to injected volume, but it is not significant compared to the increase of injection pressure due to increased rate). Again, with both zones open, the rate going inta Interval '1 will likely not exceed 1 BPM, sa the pressure should be 1100 psi ar sa--about the same pressure on Interval 2 at 2 BPM (see pages 18 and 20 of the NuStim report). Thus, we do not anticipate a maximum allowable surface injection pressure of 1500 psi being a problem. 2) Regarding the injection of drilled cuttings, this year we are disposing mast of our cuttings (and same mud) in the Kenai Barough land fill after mixing with Portland cement. Some larger materials were screened out, washed, and will be used as roadfpad fill, as a beneficial Llse. In the future we will likely again separate the larger material and dispose in the landfill or as Beneficial Use, and dispose of anly the cuttings fines (passing thru a 150 or 200 mesh screen) along with the drilling mud by injecting into this well. 10/15/2007 • • Page 2 of 3 Shall we write a letter to the AOGCC to amend this DIO rate to 3 BPM maximum, or will you do that as part of the approval process? Please let me know the best way to handle this, and also let me know if you have additional questions, need more clarification, or need any other information. Thanks, Ed Jones (713-977-5799} From: Regg, James B (DOA) [mailto:jim.regg@alaska.gov] Sent: Friday, October 12, 2007 2:48 PM To: Ed Jones Cc: Bruce D Webb; Chad Helgeson Subject: RE: Aspen Water Disposal Well injection Order Thank you for the information. The other item from the hearing was a request for Aurora to clarify what appear to be inconsistencies between the "Analysis of Injection Project" (Analysis) dated August 8, 2007 and initial request for DIO provided May 15, 2007. The specific concern regards injection rates and pressures. The May 15 application identifies injection rates up to 5 bb! per minute and pressures up to 1500 psi; the Analysis indicates 1 bbl per min rates was used for all frac modeling and indicates resulting surface pressures up to 1600 psi (est} after just 3 of the batch injections. One other clarification needed: the application indicates the disposal waste stream will include drill cuttings; Mr. Webb indicated during the hearing that cuttings will be disposed at the Kenai Peninsula land fill. Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 phone: 907-793-1236 fax: 907-276-7542 From: Ed Jones [mailto:jejones@aurorapower.com] Sent: Thursday, October 11, 2007 2:25 PM To: Regg, James B (DOA) Cc: 'Bruce D Webb'; 'Chad Helgeson' Subject: Aspen Water Disposal Well injection Order Jim, Bruce Webb informed me that one of the issues coming out of the Aspen Injection Order hearing on Tuesday, Oct. 9th was: Geologic Formation information on how the injection fluids are going to be confined. What assurance or certainty do we have, that we can exhibit to them, that the fluids will not migrate upwards into potential fresh water aquifers? The best response to this concern is to look at the Horizon Well Logging mud log of Aspen #1 (August 2005)--a copy was submitted to the AOGCC on a CD on June 15, 2006 (let me know if you need acopy--I'd attach one but it is a 9 MB .pdf file). The mud log indicates that the lithology descriptions of the samples over the interval of 1400-1900' MD is mostly "claystone," or "clay" with a few small, thin sands and coats interspersed (based on the lithology symbols, some sand in samples of only 120' of the 500'--usually 10% of those samples, at most 20%). By the lithological symbols used in the descriptions, there was some coal (usually 20%} in samples of about 100' of the 500', but the bulk of the samples are clay, siltstone, and claystone. These three components have very little effective permeability, allowing essentially no migration of fluids (including gas) in measurable time. The NuLook log by NuTech (copy attached), a computerized composite petrophysical analysis using all available electric logs, indicates that the effective permeability over this same section is very low. In the section from 1810-1980', there are 10 intervals with any indicated perm, all perms are less than 2 md, and all "permeable intervals" are less than 10' thick and usually separated by 10-20' of impermeable formation. In the interval from 1410' to 1750', there are (by NuTech's evaluation) numerous thin intervals with perms of 0.5 to 10 md, but all are separated by impermeable intervals of 5' to 20' thickness. Furthermore, the interval from 1300' up to 700' is much the same--very little sand in the sample descriptions on the mud log (none in the samples from 780' to 980'), a few thin coal stringers, and claystone, clay, and siltstone matrix. While the NuLook logs indicates that there are several fairly 10/15/2007 Page 3 of 3 permeable sands in this interval, but~re isolated by impermeable layers, incluc~several that are 20-25' thick. The NuTech frac study indicated that the fractures created by injection mud of water will be confined between 2098' and 2412' (top proposed perf is at 2125' and bottom pert at 2371'. Thus, the injected fluids should confined within this interval, as there are hundreds of feet of impermeable layers above this depth. The Cement Bond Log (Schlumberger SCMT of 23 August 2005) indicates that the top of cement is at about 220' (inside the surface casing), and there is much good to excellent bond between the perfs and shallower potential fresh water aquifers. Furthermore, the bond around the perfs is very good. Subsequent to that log, perforations at 1368-88' and 1760-70' were squeezed with cement, which should have improved the bond in those proximities (although the bond around 1760-70' was already excellent by the log). These factors all combined indicate that the injected fluids should be confined vertically to the proximity of the perfs and not migrate upward. Please let me know if you have any questions or concerns after reviewing this data. Regards, Ed J. Ed Jones Vice President Engineering & Operations Aurora Gas, LLC 713-977-5799 (Houston) 907-277-1003 (Anchorage} 10/15/2007 ~~ • • 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 ALASKA OIL AND GAS CONSERVATION COMMISSION Before Commissioners: John K. Norman, Chairman Daniel T. Seamount Cathy Foerster In the Matter of the Application for a Disposal Injection Order Under 20 AAC 25.252 for disposal of Class II drilling and production wastes into the Beluga Formation using Aspen No. 1 exploration well by AURORA GAS, LLC ALASKA OIL and GAS CONSERVATION COMMISSION Anchorage, Alaska October 16, 2007 1:00 o'clock p.m. VOLUME II PUBLIC HEARING BEFORE: John K. Norman, Chairman Daniel T. Seamount, Commissioner R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 • • TABLE OF CONTENTS Remarks by Chairman Norman R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 18 • • 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 P R O C E E D I N G S Tape 1 0050 (On record - 1:00 p.m.) CHAIRMAN NORMAN: Good afternoon. This is a hearing before the Alaska Oil & Gas Conservation Commission. The time is 1:00 o'clock p.m. on the afternoon of Tuesday, October 16th. The hearing is being held at the offices of the Commission at 333 West Seventh Avenue, Suite 100, Anchorage, Alaska. The matter originally came before the Commission upon an application filed by Aurora Gas, LLC, seeking a disposal injection order pursuant to the provisions of Chapter 20 of the Alaska Administrative Code, Section 25.252. The Commission took initial testimony, reviewed the matter. There were a few trailing items and questions the Commission had and consequently rather than renotice this the Commission recessed the hearing stating at that time that we would reconvene at this time to complete the process. The requested injection order seeks approval for the injection of Class II wastes at a location utilizing the Aspen No. 1 well which is situated within Section 33, Township 12 North, Range 11 West, Seward Meridian. This originally was a suspended exploratory well and the proposal is to utilize it for injection purposes. The -- one of the questions the Commission asked and it R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 18 • • 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 I does appear has been satisfied related to notification to both the surface and subsurface owners. We asked for a copy of the certified return receipts to be filed and I note that those copies are now in the file. However if there are representatives of either CIRI or Tyonek Native Corporation, they will certainly be welcome to speak and offer any comments they may have. It might expedite matters if I could ask a representative of the Commission staff to come forward, either Mr. Davies or Mr. Regg, just for purposes of the record to see if the staff is satisfied now with the additional information concerning the characteristics of the water and injected fluids. I think -- would -- would you, please, state your name for the record, please? MR. DAVIES: My name is Steve Davies, D-a-v-i-e-s, I'm a geologist here on the staff of the Commission. CHAIRMAN NORMAN: And I should note for the record that present with me is Co-Commissioner Dan Seamount, a quorum being present we are proceeding with the hearing. Mr. Davies, or if you should choose to call on Mr. Regg,. the simple question is we did have some trailing items and we wanted to be sure that the information had been provided to the Commission in response to an exchange of e-mails. I believe you were traveling at the time of the last hearing. So the question for you and Mr. Regg is whether the information now R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 19 ~ • 1 21 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 provided meets those questions that were posed of the applicant? MR. DAVIES: Yes, it does. The outstanding items I had, the geologic information and evidence on compatibility of fluids, they've submitted information to satisfy those. CHAIRMAN NORMAN: Okay. I'll ask then the applicant, Mr. Webb, do you have anything additional that you would like to say or offer at this time? MR. WEBB: No, sir, I -- I don't. CHAIRMAN NORMAN: Very well. Then I will ask if there are any other persons present -- I see there's a representative of Cook Inlet Region, it's not necessary, but there is an opportunity. Mr. Bates, you're well known to the Commission, we welcome you, it's nice to see you again. Is there anything that you would like to say? MR. BATES: Not at this time. CHAIRMAN NORMAN: Commissioner Seamount, do you have any questions? COMMISSIONER SEAMOUNT: I notice the projector's on, is -- does Mr. Regg have anything to say or..... MR. REGG: No. COMMISSIONER SEAMOUNT: Okay. I guess I don't have anything. CHAIRMAN NORMAN: Very well. Then as I'd indicated last time, injection orders are something that the Commission takes R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 20 • • 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 very seriously for the protection of all of Alaska, for our freshwater sources, the underground sources of freshwater and, in this instance we particularly wanted to make sure, which has been done, that both the subsurface owner, Cook Inlet Region, Inc., and the surface owner, Tyonek Native Corporation, were aware and had no additional comments or objections. I see nothing in the record and hear nothing by way of objection in that regard. And additionally it's incumbent on the Commission to ensure compatibility of injected fluids both for purposes of conservation issues and also again to make sure that the injected substance stays where it is to be put in the ground. That's a primary concern of the Commission. I believe from what Mr. Davies has indicated that we now have everything we need to proceed to make a decision on this. And so unless any of the other parties have anything I think we can conclude the recessed hearing. For the record the Commission sees no one else asking to be recognized and accordingly we will recess at the hour -- or we will adjourn at the hour of 1.07 p.m. And the Commission's decision in the form of an order will be forthcoming. Thank you. 0200 (Recessed - 1:07 p.m.) R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 21 1 C E R T I F I C A T E 2 UNITED STATES OF AMERICA ) )ss. 3 STATE OF ALASKA ) 4 I, Rebecca Nelms, Notary Public in and for the State of Alaska, residing at Anchorage, Alaska, and Reporter for R & R 5 Court Reporters, Inc., do hereby certify: 6 THAT the annexed and foregoing Public Hearing In the Matter of the Application to for a Disposal Injection Order 7 Under 20 AAC 25.252 for disposal of Class II drilling and production wastes into the Beluga Formation using Aspen No. 1 8 exploration well by AURORA GAS, LLC, was taken by William P. Rice on the 16th day of October, 2007, commencing at the hour 9 of 1:00 p.m., at the Alaska Oil and Gas Conservation Commission, Anchorage, Alaska; 10 THAT this Hearing Transcript, as heretofore annexed, is a 11 true and correct transcription of the proceedings taken by William P. Rice and transcribed by Lynn Hall; 12 IN WITNESS WHEREOF, I have hereunto set my hand and 13 affixed my seal this 24th day of October, 2007. 14 15 Notary Public in and for Alaska My Commission Expires: 10/10/10 16 17 18 19 20 21 22 23 24 25 R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 • • STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION Aurora Gas Disposal Injection Aspen #1 Continuation Hearing October 16, 2007 at 1:00 pm NAME -AFFILIATION ADDRESS/PHONE NUMBER TESTIFY (Yes or No) (PL`EASE i~P((RrINT) ~7l - ~ C~ (,' In 4~ c~ H e 1 c~.~S t~ r - f~y~~iyt `ate ~ ~`S 1 `C© t) C,J~S ~' ~~ns G n ~ (v~ , ? i ~,3 `~e-S ~i2..~ ~~~ ~ \ ~~ ~ ~ Colombie, Jody J (DOA) From: Regg, James B (DOA) Sent: Friday, October 12, 2007 10:25 AM To: Davies, Stephen F (DOA); Maunder, Thomas E (DOA) Cc: Colombie, Jody J (DOA) Subject: FW: Aspen Water Disposal Well injection Order Attachments: NuLook Aspen #1.pdf Info about confinement we requested at Aspen DIO hearing Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 phone: 907-793-1236 fax: 907-276-7542 From: Ed Jones [mailto:jejones@aurorapower.com] Sent: Thursday, October 11, 2007 2:25 PM To: Regg, James B (DOA) Cc: 'Bruce D Webb'; 'Chad Helgeson' Subject: Aspen Water Disposal Well injection Order Page 1 of 2 Jim, Bruce Webb informed me that one of the issues coming out of the Aspen Injection Order hearing on Tuesday, Oct. 9th was: Geologic Formation information on how the injection fluids are going to be confined. What assurance or certainty do we have, that we can exhibit to them, that the fluids will not migrate upwards into potential fresh water aquifers? The best response to this concern is to look at the Horizon Well Logging mud log of Aspen #1 (August 2005)--a copy was submitted to the AOGCC on a CD on June 15, 2006 (let me know if you need acopy--I'd attach one but it is a 9 MB .pdf file). The mud log indicates that the lithology descriptions of the samples over the interval of 1400-1900' MD is mostly "claystone," or "clay" with a few small, thin sands and coals interspersed (based on the lithology symbols, some sand in samples of only 120' of the 500'--usually 10% of those samples, at most 20%). By the lithological symbols used in the descriptions, there was some coal (usually 20%) in samples of about 100' of the 500', but the bulk of the samples are clay, siltstone, and claystone. These three components have very little effective permeability, allowing essentially no migration of fluids (including gas) in measurable time. The NuLook log by NuTech (copy attached), a computerized composite petrophysical analysis using all available electric logs, indicates that the effective permeability over this same section is very low.. In the section from 1810-1980', there are 10 intervals with any indicated perm, all perms are less than 2 md, and all "permeable intervals" are less than 10' thick and usually separated by 10-20' of impermeable formation. In the interval from 1410' to 1750', there are (by NuTech's evaluation) numerous thin intervals with perms of 0.5 to 10 md, but all are separated by impermeable intervals of 5' to 20' thickness. Furthermore, the interval from 1300' up to 700' is much the same--very little sand in the sample descriptions on the mud iog (none in the samples from 780' to 980'), a few thin coal stringers, and claystone, clay, and siltstone matrix. While the NuLook logs indicates that there are several fairly permeable sands in this interval, but all are isolated by impermeable layers, including several that are 20-25' thick. The NuTech frac study indicated that the fractures created by injection mud of water will be confined between 2098' and 2412' (top proposed pert is at 2125' and bottom pert at 2371'. Thus, the injected fluids should confined within this interval, as there are hundreds of feet of impermeable layers above this depth. The Cement Bond Log (Schlumberger SCMT of 23 August 2005) indicates that the top of cement is at about 10/12/2007 Page 2 of 2 220' (inside the surface casing), and there is much good to excellent bond between the perfs and shallower potential fresh water aquifers. Furthermore, the bond around the perfs is very good. Subsequent to that log, perforations at 1368-88' and 1760-70' were squeezed with cement, which should have improved the bond in those proximities (although the bond around 1760-70' was already excellent by the log). These factors all combined indicate that the injected fluids should be confined vertically to the proximity of the perfs and not migrate upward. Please let me know if you have any questions or concerns after reviewing this data. Regards, Ed J. Ed Jones Vice President Engineering & Operations Aurora Gas, LLC 713-977-5799 (Houston) 907-277-1003 (Anchorage) 10/12/2007 n. ,.~ _- _ ~ - _.- ENERGYALLIANCE -"°~ Advanced Petrophysical Evaluafion . _ i~ :'a. '~` '% Textural Vision Evaluated For: UPI: AURORA050817_4939 AURORA GAS Completed: 8/18/2005 Company AURORA GAS,LLC. Well ASPEN N0. 1 Field WILDCAT County KENAI State ALASKA Country USA Location Sec. 33,T12N-R11W Section 33 Township 12N Range S1W API Num Permanent Datum GROUND L Elevation 432.5000 K.B. 447 Log Measured From KELLY BU , 14.50 Above Perm Datum D.F. 446 Drilling Meas From KELLY BU G.L. 432.5 Run 1 Run 2 Run 3 Date 16-AD6-2005 Depth - Ddller 4485' DepM-Logger 4471' Bfm Log Interval 4462' Tap Log Interval 693' Casing - DNllar 9.625' @ 693' Casing-logger 693' Bltalze 7.875' Typo Fluid In Hole KCL/FZ MUD Dens. /Visc. 9.7/47 pH /Fluid Loss 8.4 / 5.2 Source of Sample BOWLINE Rm@Meas. temp ,172@9fi F Rmf @Meas. Temp .135 @ fi7 F Rmc@ Meas, Temp .255 @ fig F Source: Rmt/Rmc PpE55 / PRE55 Rm@BHT - .121@96 Max. Rec. temp. 96 .....a.*w. a.s~.a~rr. r.. str. *'" CURVE MNEMONICS "` ......+""...:......""...rrr GR - GAMMA RAV BVW -CONVENTIONAL BULK VOLUME WATER SP. [SPBL] - SPONTANEOUS POTENTIAL. [BASELINE SHI FTEDI BVI, BVIC, MBVI, MXBVI, BFV - IRREDUCIBLE WATER CAL, CALI, HCAL, DCAL - CALIPER PHIE, MPHI. CMRP - EFFECTIVE POROSITY PEF, PE - PHOTO-ELECTRIC EFFECT SW -WATER SATURATION P1-P9/CBPI-CBPB/BIN1-BIN9 - BINS F/NMR DEVICE BASED ON T2 TIMES MSIG, TCMR - TOTAL POROSITY FROM NMR FF FLAG -NMR-BASED FREE FLUID FLAG PDSS, PDLS. PHID, DPHI - DENSITY POROSITY - FHC FLAG -NMR BASED FREE HYDROCARBON FLAG PCNSS, PCNLS, NPH I, NPOR, PHIN - NEUTRON POROSITY LW FLAG - LOW WATER FLAG PE, PEF, PEFZ - PHOTO ELECTRIC FACTOR KF FLAG - FAIR PERMEABILITY FLAG PERM, MPERM -TOTAL PERMEABILITY KG FLAG -GOOD PERMEABILITY FLAG P, PP, CBP - IMAGE OF NMR 72 DATA MDR FLAG - RES[STIVITV MINERAL FLAG SWB, SWBAV -CLAY BOUND WATER SATURATION SP FLAG - PERMEABILITY MINERAL FLAG SWB, SWBAV -CLAY BOUND WATER SATURATION ND FLAG -GAS MINERAL FLAG HMIN, HMNO, MINV, MNOR, RLML, RNML - MICROLOG CURVES FLAG - POROSITY MINERAL FLAG PHIE SPHI. PSSS - SONIC POROSITY _ FLAG - NMR MINERAL FLAG T2 TGAS -TOTAL GAS FROM MUDLOG _ ILO. LLD, HORS, A`90, M`R9 - DEEP RESISTIVITY W -TEXTURAL PARAMETER ILM. LLS, HMRS, A+30, M'3 -MEDIUM RESISTIVITY CODE -PAY pUAL ITY INDICATOR SFL, SFLU, RFOC, DFL, MSFL - SHALLOW RESISTIVITY PAYFLAG - POTENTIAL PAY INTERVAL r.....". r"""r. rras r.." "* PARAMETERS "' "s."""""rrr rr."...r "` REMARKS "*" Rw = TOP - BTM RW75 K 75 °F M = TOP - BTM I W All interpretations are op inions basetl on inferences from el ecf ri<al or other Rw @ _°F M = - = - measurements. and we canno t antl do not guarantee [he accuracy or correctness of Rw _ _ °F N = TOP - BTM - @ 2 any interpretation, and we shall not, except in the case of gross negligence on Ru _ _ _ °F N = - @ = - ' our part, be liable or res ponsible for any loss, costs, damages or expenses Rw _ _ _ _ °F = ' @ incurred or sustained by a nyone resulting from any interpretations made by any Rw _ _ _ _ °F Perm ' @ = officers, agents or employ ees of NuTech Energy Alliance. These interpretations _ _ _ _ Coeff = TOP - BTH T(192) are also subject to Clauze A of our General Terms and Conditions as set out in RHO M = 70P - BTM 2.65 Coeff = - I our current Price Schedule . RHOM _ _ f = - ~ I ~ I _ - RHOM = ~ I F, toffs I DTMtx = TOP - BTM _ _ VClay = .4 Free Fluid = .03 I PROJ. ID: AURORA050817_4939 DTMtx = _ _ Kmin = .1 Free Water = .O1 I JMF DTMYX = _ _ Kfair = 1 TooMuchWtr = .015 I Kgood = 10 LowHyd rcbn = .6 I ASPEN N0.1 18 Aug 2005 @ 13:11 DEPiH (F~ Interval: 705.00 to 4450.00 Depth Scale Ratio: 1/240 FWG DEPTH ND TENS I PH OU NUPERM CLAY -~ NIIBPEC' 000 0 O 0 GAPI 150 6 0 -0.3fJC1.25 1 0.2 ONM M 200 0.6 DEC ~1 0.1 MD 1 0.05 1 1 D C 0 0 0.1 0 F FlAG I P TE%GM SMALL 1~~~ NUN i ' W EC ~ ~ ~ 6 N I6 0 6 EC 0 0 OHMM20 1 ~SpB 0.2 OHMM 200 0.6 ODO 1.5 3.5 0 0.1 VD 1 0.6 D NUMATR D.1 100 0 120 SMVL 30 OW F~G6 1700 0.2 OHTMM 200 0.6 PDECS 0 D OHMM 20 0 MEDIUM 1 0.6 DEC 0 NUPERM 1000 NUSPEC4 OFHC FIA 6 SNRM 0.2 OHTMM 200 D.6 PDEC 0 HMIN HMNO 0 LARGE 1 0.6 DEC 0 OKF FlAG6 0.2 0 MM 200 PD ~ NSS 1 VDECL D 1 SW OKG_FLAG6 0.02 OHM7M 20 D CLAY BVW BVI FW_FIAG 0 CLAY SMALL PHIE BVW 0 FF FLAG SMALL~.~.~'.MEDIUM BW D FFLW FLAG MEDIU~ RGE LFH G VCOAL . ••.• 0 FHKF FLAG 1 1 _ ......~._, rttY:::: -.. ~~ }{. 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Seamount 3 Cathy Foerster 4 In the Matter of the Application ) 5 for a Disposal Injection Order ) Under 20 AAC 25.252 for disposal of ) 6 Class II drilling and production ) wastes into the Beluga Formation ) 7 using Aspen No. 1 exploration well ) by AURORA GAS, LLC ) 8 ) 9 ALASKA OIL and GAS CONSERVATION COMMISSION Anchorage, Alaska 10 October 9, 2007 it 9:00 o'clock a.m. 12 VOLUME I PUBLIC HEARING 13 BEFORE: John K. Norman, Chairman 14 Daniel T. Seamount, Commissioner 15 16 17 18 19 20 21 22 23 24 25 R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 • • TABLE OF CONTENTS Opening remarks by Chairman Norman Testimony by Bruce D. Webb R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 03 05 • • 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 P R O C E E D I N G S Tape 1 0050 (On record - 9:00 a.m.) CHAIRMAN NORMAN: Good morning. I'll call the hearing to order.. This is a hearing before the Alaska Oil and Gas Conservation Commission being held on the morning of October 9th, 2007 at the hour of 9:00 o'clock a.m. The hearing is being held at the Commission's offices at 333 West Seventh Avenue, Suite 100, Anchorage, Alaska. Present are Commissioners Norman and Seamount. Commissioner Foerster is traveling, however, we do have a quorum present and, therefore, can proceed with the conduct of legal business. Before beginning I would like to mention briefly the requirements of the Americans with Disabilities Act. If there are any persons present at this hearing who may have a need for a special accommodation to enable you to participate in the hearing, please, see the Commission's special assistant, Ms. Jody Colombie and we will do our utmost to accommodate you. R & R Court Reporting will be recording these proceedings. If you wish to obtain a transcript following the conclusion of the proceedings you may do so by contacting R & R Court Reporting or contact the Commission's special assistant and she will facilitate your request. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 3 • • 1 2 3' 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 We would like to remind persons who are present and will be testifying to speak into both microphones which are in front of you at the tables. The one microphone is for purposes of amplification so that your testimony can be clearly heard and the other is for purposes of creating the transcript of these proceedings. The purpose of this hearing this morning is to consider a request filed by Aurora Gas, LLC for a disposal injection order for the Aspen number 1 well located in the Cook Inlet Basin Region. Aurora Gas, LLC applied for a disposal injection order under 20 AAC 25.252 to authorize the disposal of Class 2 drilling and production wastes into the Beluga Formation using the Aspen number 1 well. Aurora had originally drilled and then suspended this well from an onshore location in 2005. The well is drilled on a CIRI lease and I believe -- and we may get clarification that the surface owner is the Tyonek Native Corporation. Aurora was granted approval by the Alaska Oil and Gas Conservation Commission of a sundry application to re-enter the Aspen number 1 -- to re-complete that well as a disposal injector. The proposed disposal injection is located within Section 33, Township 12 north, range 11 west, Seward Meridian. The receiving zone for the proposed injection well is at an approximate depth of 2,125 feet down to approximately 2,730 R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 4 ~ • 1 2 3' 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 I 22 23 24 25 feet measured depth. The Notice of this hearing was duly published and the file so reflects on September 4th, 2007 in the Anchorage Daily News and also published in the Peninsula Clarion on September 5th, 2007. Additionally notice of the hearing has been posted on the State of Alaska's on line notice system, as well as on the Alaska Oil and Gas Conservation website. The file before me does not reflect that there have been any protests, objections or comments by any other parties. The file does reflect an exchange of correspondence between Commission Staff and Aurora requesting certain additional information in order to proceed with processing this application. I will now ask before beginning the hearing if Commissioner Seamount has anything to add? COMMISSIONER SEAMOUNT: I have nothing at this time. CHAIRMAN NORMAN: Very well. Is there a representative of the applicant, Aurora Gas, LLC present? Would you come forward, please? Would you be seated at a place that's comfortable for you. Will you first, please, raise your right hand? (Oath Administered) MR. WEBB: I do. BRUCE D. WEBB CHAIRMAN NORMAN: Okay. Please state your full name, your R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 5 • • 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 I 22 I 23 24 25 affiliation for the record? MR. WEBB: Bruce D. Webb. I'm the manager of land and regulatory affairs for Aurora Gas, LLC. CHAIRMAN NORMAN: And you have knowledge of the information contained in the application? MR. WEBB: I do. CHAIRMAN NORMAN: If you do -- if it does get into expert testimony concerning the composition of the receiving reservoir, fracture characteristics and so forth we will want -- we may want some expert testimony so for that purpose I'd ask you to please state your background now so that we can gauge whether you have the requisite information. MR. WEBB: My background is primarily in permitting and land affairs, not geology or reservoir engineering. CHAIRMAN NORMAN: Very well. And then what we -- if there are questions then of a technical nature we may need to leave the record open till we get those resolved one way or the other. MR. WEBB: Okay. CHAIRMAN NORMAN: There may be some land ownership questions and so I will ask you then to remember that you are under Oath. And you do have a background in permitting and land ownership matters, leasing? MR. WEBB: That's correct. CHAIRMAN NORMAN: Okay. All right. We have before us the R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 6 • • 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 application and do you wish to make a brief presentation for the record on the purpose of the application? MR. WEBB: Sure, I can do that. The purpose of the application is to dispose primarily of our produced water and muds. The cuttings we plan to still dispose of at the Kenai Peninsula land fill. The Aspen well was drilled. It was a dry hole. Produced a little saltwater and currently we have a surface disposal -- well, it's actually a surface storage pond of our produced water and it's getting to a point where we keep having to increase the size of the berm. So the only real good, environmentally acceptable way of getting rid of the produced water is to inject it and that will allow us to continue our production and drilling activities, so that's the main purpose. CHAIRMAN NORMAN: And the -- I think I stated and it's our understanding in the notice, that the receiving zone is at a depth of 2,125 down to 2,730 feet measured depth, is that right? MR. WEBB: I believe that's correct. CHAIRMAN NORMAN: And do you know what the true vertical depth would be as opposed to measured depth? MR. WEBB: It's going to be very close. It was a straight hole. CHAIRMAN NORMAN: Okay. The file contains copies of the card showing the certified mailings. We do not have evidence R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99561 7 • • 1 2 31 4 9' 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 in the file of a signed receipt showing that the Tyonek Native Corporation and Cook Inlet Region received those. Were those returned to Aurora and if so do you have copies showing receipt? MR. WEBB: They were returned to Aurora and I didn't bring the copies. Actually this is my first hearing and I wasn't -- didn't know I needed to do that. I can get those back to you today. CHAIRMAN NORMAN: Please. Commissioner Seamount. COMMISSIONER SEAMOUNT: Okay. Mr. Webb, it's your first hearing, but it's nothing to be concerned about. A lot of people come in for their first hearing. There appears to be some missing information that we need to process the application and are you aware of that -- of what we need? MR. WEBB: No, I thought we submitted everything we were requested. COMMISSIONER SEAMOUNT: Okay. I'll probably want Mr. Regg to clarify what that missing information is, but before I do that in 2002 Aurora submitted an application for disposal injection order and it was approved. It was disposal injection order number 24 for Nicolai Creek Unit Number 5. Is there any reason why you don't want to get that disp- -- I mean, why -- why are you going to a different well now when I think that Nicolai Creek Number 5 is really close to your operations? MR. WEBB: Nicolai Creek is primary close to the Nicolai R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 8 • • 1 21 3 4 51 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 I 23 24 25 I Creek facilities. Most of the wells that it's my understanding are producing a lot of the water are the Three Mile Creek, Lone Creek, Moquawkie and those are on the other side of the Chuit River and..... COMMISSIONER SEAMOUNT: Okay. Okay, so -- okay. So it's a logistic thing? MR. WEBB: It's centrally located. COMMISSIONER SEAMOLTNT: Okay. MR. WEBB: And the pad itself is really big and flat. COMMISSIONER SEAMOUNT: Okay. At this time then I'd like to ask Mr. Regg, our senior petroleum engineer, to clarify what information we need and if you could get that to us as soon as possible we'd appreciate it. MR. WEBB: Okay. CHAIRMAN NORMAN: Mr. Regg, if you would, please, first state your name for the record and your position? MR. REGG: Of course. My name is James Regg. The last name is R-e-g-g. And I'm a petroleum engineer here with the Commission. As we've gone through the Aspen disposal injection order we did send a letter to Aurora requesting additional information and the date of that letter was July 17, 2007. One of the items we outlined in the letter as needing additional information was regarding the confinement of the fluids. There is a fracture analysis which was provided and R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/fax 274-8982 ANCHORAGE, ALASKA 99501 9 • ~ 1 2~ 3' 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 there's some information in here regarding the geologic setting. However, you know, we don't have a description of the confinement and what mechanisms are there, whether it's formation, what type of geologic setting would create the confinement of those fluids. There's also some -- what I would characterizes as some inconsistencies between the fracture analysis that was provided and the rates and pressures identified by Aurora in their application. The fracture analysis appears to have been modeled at one barrel per minute and -- and volumes that are outlined there. The application actually identifies rates up to five barrels per minute and injection pressures around 1,500 psi -- up to 1,500 psi so I would encourage Aurora to go back and examine those and try to resolve any differences there. The confinement really is the one major missing piece in all this and I would hope that they could provide that in a relatively quick manner and then we could close this out. COMMISSIONER SEAMOUNT: Do you have any questions, Mr. Webb? MR. WEBB: No, I -- I understand what he needs and we'll ask Andy Clifford our geologist to supply that. COMMISSIONER SEAMOUNT: Okay, okay. You -- Aurora has a geologist, they don't -- is Andy an Aurora employee or..... MR. WEBB: Yes, he's the --..... COMMISSIONER SEAMOUNT: Okay. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 10 • • 1 2 3 4 51 6' 7 8 91 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 I MR. WEBB: .....he is a vice president of the company. COMMISSIONER SEAMOUNT: Oh, that's right, okay. I notice the signatures on the Nicolai number 5 was J. Edward Jones. MR. WEBB: He's the drilling engineer. COMMISSIONER SEAMOUNT: Okay. MR. WEBB: And a vice present as well. COMMISSIONER SEAMOUNT: Okay. And, Mr. Regg have you and our geologist, Steve Davies been talking to Mr. Clifford directly? MR. REGG: I can't speak for Mr. Davies. I have not spoken to him. I believe there has been some and in the record there should be copies of some e-mail exchanges. The discussions, I think, centered on the water quality and the compatibility of the fluids that would be injected at the location. COMMISSIONER SEAMOUNT: Would it be helpful for you to talk directly with Mr. Clifford? MR. REGG: I could do that. COMMISSIONER SEAMOUNT: Okay. Or Mr. Davies could. MR. REGG: I believe Mr. Davies is out this week so, you know, I'm available. COMMISSIONER SEAMOUNT: Okay. I have no further questions. Thank you Mr. Webb, Mr. Regg. CHAIRMAN NORMAN: I wonder if we might go off the record 25~~ for just a moment, please. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 11 • • 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 I 22 23 24 25 (Off record - 9:17 a.m.) (On record - 9:22 a.m.) CHAIRMAN NORMAN: The Commission has taken a brief recess and we're back on the record now at 9:21 a.m. We have indicated to the applicant that there are some additional pieces of information that the Commission will need in order to complete processing this application. Mr. Webb, I believe you've indicated you understand what the Commission is looking for, is that correct? MR. WEBB: That's correct. CHAIRMAN NORMAN: Right. And we would invite you to contact Commission Staff as you're preparing it if you have any question about that. The Commission then will continue this hearing for one week and we will reconvene to compete our consideration of this application at the hour of 1:00 p.m. on Tuesday, October 16th, 2007. Do you have any questions about that, Mr. Webb? MR. WEBB: No, sir. CHAIRMAN NORMAN: I think you'll find the Commission good to work with. The area of subsurface injections including fracturing is an area that is something that the Commission watches very carefully because to the citizens of Alaska, many of whom depend on sources of fresh drinking water and so forth it's extremely sensitive and, therefore, we do absolutely want R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 12 • ~ 1 2 3 4 5 6 71 8 9 10 I 11 I 12 13 14 15 16 17 18 19 20 21 22 23 24 25 to make sure that when a substance is injected into the ground beneath the surface of the earth it stays where it's put and it doesn't find its way back up to the surface. Should that occur that constitutes a failure of the system and it also, I think, creates problems for everyone involved and brings into question the whole concept of subsurface disposal. MR. WEBB: Um-hum. CHAIRMAN NORMAN: So, I offer that brief explanation because I don't believe you've appeared before us before. We look forward to seeing you many times in the future, but we want to make sure, absolutely sure that the receiving zone and the confining layer and so forth and the fracture analysis is complete. And additionally I'm not clear through the exchange of e-mails whether the Commission has everything it needs concerning the quality of the formation water and the compatibility of fluids. It does appear there was some information exchanged, but you might also check with Mr. Steve Davies and find out if there's anything in that area that we still need in order to process this. MR. WEBB: Okay. CHAIRMAN NORMAN: Mr. Regg, do you have anything more within this week that you would like to have from Aurora? MR. REGG: There is one other question. Aurora does have an approved sundry for re-entering the Aspen well to R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 13 • • 1 2 3 I 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 reconfiguration it and I was curious if Mr. Webb might have a comment on when they were anticipating starting operations? MR. WEBB: It's not going to be until the summer of 2008 at the earliest. MR. REGG: Thank you. CHAIRMAN NORMAN: Any final questions, Commissioner..... COMMISSIONER SEAMOUNT: Well, the only thing I'd add is if there's, you know, any question at all about, you know, what sort of statements we're looking for when this information is provided, a really good go by is the application from Aurora in January of 2002 for disposal injection order at Nicolai Creek number 5 and that resulted in approval of the disposal injection Order number 24. And that's all I have to say. CHAIRMAN NORMAN: Very well. Any further questions, Mr. Webb? MR. WEBB: No, sir. CHAIRMAN NORMAN: Well, we're happy to see you before the Commission and we look forward to seeing you one week from today. And if there's nothing further, without objection we'll stand in recess at the hour of 9:25 a.m. (Recessed - 9:25 a.m.) R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 14 • ~ l 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 C E R T I F I C A T E UNITED STATES OF AMERICA ) )ss. STATE OF ALASKA ) I, Rebecca Nelms, Notary Public in and for the State of Alaska, residing at Anchorage, Alaska, and Reporter for R & R Court Reporters, Inc., do hereby certify: THAT the annexed and foregoing Public Hearing In the Matter of the Application to for a Disposal Injection Order Under 20 AAC 25.252 for disposal of Class II drilling and production wastes into the Beluga Formation using Aspen No. 1 exploration well by AURORA GAS, LLC, was taken by Suzan Olson on the 9th day of October, 2007, commencing at the hour of 9:00 a.m., at the Alaska Oil and Gas Conservation Commission, Anchorage, Alaska; THAT this Hearing Transcript, as heretofore annexed, is a true and correct transcription of the proceedings taken and transcribed by Suzan Olson; IN WITNESS WHEREOF, I have hereunto set my hand and affixed my seal this 10th day of October, 2007. ~~'.~- Notary Public in and for Alaska My Commission Expires: 10/10/10 R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 • • STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION Aurora Gas Disposal Injection Aspen #1 October 9, 2007 at 9:00 am NAME -AFFILIATION ADDRESSfPHONE NUMBER TESTIFY (Yes or No) (PLEASE P T) ..J1 ~ /~~-CG ~~rn ~ civ~ ~ ~s~ 1,X7 .~ 5 STATE OF ALASKA NOTICE TO PUBLISHER ~ ADVERTISING ORDER NO. ADVERTISING ORDER INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION (PART2 OF THIS FORM) WITH ATTACHED COPY OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE AO-02814012 SEE BOTTOM FOR INVOICE ADDRESS F R AOGCC 333 W 7th Ave, Ste 100 AGENCY CONTACT Jod Colombie DATE OF A.O. Au ust 31 2007 ° M Anchorage, AK 99501 907-793-1238 PHONE PCN DATES ADVERTISEMENT REQUIRED: o Anchorage Daily News PO Box 149001 Arichora e AK 99514 g ~ September 4, 2007 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Advertisement to be published was e-mailed Type of Advertisement Legal® ^ Display Classif ied ^Other (Specify) SEE ATTACHED SEND INVOICE IN TRIPLICATE TO AOGCC, 333 W. 7th Ave., Suite 100 Anchora e AK 99501 PAGE 1 OF 2 PAGES TOTAL OF ALL PAGES$ REF TYPE NUMBER AMOUNT DATE COMMENTS 1 VEN 2 ARD 02910 FIN AMOUNT SY CC PGM LC ACCT FY NMR oisT un ~ 08 02140100 73451 2 REQUISITION BY: x``~.. ~ DIVISION APPROVAL: `-'..vim --- - ~__._. 02-902 (Rev. 3/94) J Publisher/Original Copies: Department Fiscal, Department, Receiving AO.FRM • • Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Disposal Injection Order for Aspen No. 1 Aurora Gas LLC ("Aurora") has applied for a Disposal Injection Order under 20 AAC 25.252, authorizing disposal of Class II drilling and production wastes into the Beluga formation using the Aspen No. 1 exploration well. Aurora drilled and suspended the Cook Inlet basin onshore well in 2005 from a Cook Inlet Regional Incorporated lease. Aurora was granted Alaska Oil and Gas Conservation Commission ("Commission") approval of a sundry application (307-172; 5/29/2007) to reenter Aspen No.l to recomplete as a disposal injector. The proposed disposal injection is located within Section 33, T12N, Rl 1 W, Seward Meridian. The receiving zone for this well is proposed at an approximate depth range of 2125 feet to 2730 feet measured depth. A public hearing on Aurora's application has tentatively been scheduled for October 9, 2007 at 9:00 a.m. at the Commission offices at 333 West 7~' Avenue, Suite 100, Anchorage, Alaska 99501. To request that the tentatively scheduled hearing be held, file a written request with the Commission no later than 4:30 p.m. on September 21, 2007. If a written request for a hearing is not timely filed, the Commission may issue an order without a hearing. To learn if the Commission will hold the public hearing, call the Commission's Special Assistant, Ms. Jody Colombie, at 907-793-1221. In addition, a written protest or written comments regarding the application may be submitted to the Commission at 333 West 7`" Avenue, Suite 100, Anchorage, Alaska 99501. Any written protest or comments must be received by 4:30 p.m. on October 5, 2007 except that, if the Commission holds a public hearing, a written protest or comments must be received by the conclusion of the October 9, 2007 hearing. If, because of a disability, spe -~a commodations may be needed to submit a written protest or comments e u lic hearing, call Ms. Colombie at 907-793- 1221 before September 2 , 2007,.E Page 1 of 1 Colombie, Jody J (DOA) From: Ads, Legal [legalads@adn.com} Sent: Friday, August 31, 2007 1:07 PM To: Colombie, Jody J (DOA) Subject: RE: Public Notice Attachments: 02814012.pdf; 02814012(2).pdf Following is the confirmation information on your legal notice. Please review and let me know if you have any changes or questions. Account number: STOF0330 Ad number: 325155 PO/AO #: Run dates: Sept. 4, 2007 Total cost of notice: $161.02 Thank you for using Anchorage Daily News! Customer Service Rep. Christine L. Clark Phone: 257-4421 Fax: 279-8170 E-Mail: cclarkC~adn.com -----Original Message----- From: Colombie, Jody J (DOA) [mailto:jody.colombie@alaska.gov] Sent: Friday, August 31, 2007 10:37 AM To: Ads, Legal Subject: Public Notice Please publish on Tuesday September 4, 2007. 8/31 /2007 Anchorage Daily News '''~°' 20°' Affidavit of Publication 1001 Northway Drive, Anchorage, AK 99508 PRICE OTHER OTHER OTHER OTHER OTHER GRAND AD # DATE PO ACCOUNT PER DAY CHARGES CHARGES #2 CHARGES #3 CHARGES #4 CHARGES #5 TOTAL 325155 09/04/2007 02814012 STOF0330 $161.02 $161.02 $0.00 $0.00 $0.00 $0.00 $0.00 $161.02 STATE OF ALASKA THIRD JUDICIAL DISTRICT Christine Clark, being first duly sworn on oath deposes and says that she is an advertising representative of the Anchorage Daily News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and during all said time was printed in an office maintained at the aforesaid place of publication of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and not in supplemental form) of said newspaper on the above dates and that such newspaper was regularly distributed to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged private individuals. ~ and sworn to me Notary Public in and for the State of Alaska. Third Division. Anchorage, Alaska Nodce of 17ubllo Hearing STATH OP ALASICA A1a3ka0ilandGas " Conservation Commission Re: Disppoos~aalI Injection Order IorASpen No.1 Aurora Gas LiC ("Aurora") has applied for a Dsposaltn)ection Order under 2QAAC 25.252, au- thorizing disposafpf Class II drilling and-prpductign wastes into the Beluga formation using the Aspen' No. t' exploration well Au; in 2005 from a a sundry application (307-172; 5/29/2007) to re- enter Aspen No.1 to recomplete as a disposal injector::The-.proposed disposal injection is io- cated within Section 33, T12N, R11w;SewardMe- ridian, The receivingzone for this well is proposed at an approximate tlepth range Of 2125 feet to 2730 feet measured depth. A.public'hearing on Aurora's application has tentatively been scheduled '-for October 9, 2007 at 9:00 a.m. at-the Commissionof- fices at 333 West 7th Av- enue, Suite 100, Anchor, a¢e:.Alaska 99501. To with the Commission no later than 4:30 p.m. on Septemb2r21, 2007. ` It a written _request for a ~olOmbfe, at vo7-793-~zri In addRion,:a written pro- test orwritten comments: regarding the application maybe submitted to the GOmrfll$SIOn'8t333 West, 7th Avenue; Suite 100, an- chorage,.Alaska 99501. Ahy written protest or cnmmants`musi be re- MY COMMISSION EXPI ~ IS/~~ toper s, 2uv~ excepr ds a if the Gommission hd ., .public hearing, a written • "~ protest or comments must be received by the'conclu- . sion of the October 9, 2007 - hearing. ~ r~~/ P If, because of a disability, mmodations l ~ ~ `4~~~ ~, (' . ~ +~~ • ~ / , acco specia may be needed to submita wntten protest or coin - ~ ~ ~ `. ~ .' ~ i• OTI~ meats or attend the publi c R ~• ~„ ~ ~ •... ~ •• ~ hearing, call. Ms.COlombie at 907-793-1221 before ' ~" ~ v „~ v September 27, 2007. yBL~v „^~ y y "~ V- .~~ B ~ J e~ ~ ~ ~ 1 • John K. Norman Chairma n .~ ~ ~ ~• 1 ~J, . ~ A • _~ ,1 AO 02814012 Publish: Sept. 4th, 2007 ,~~~ ~~l 1~ ~ ~ ~~fs l j , i ~~ .~ ADVERTISING INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION PART 2 OF THIS FORM WITH ATTACHED COPY OF AO-02814012 ORDER ( ) ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE `SEE BOTTOM FOR INVOICE ADDRESS F AOGCC AGENCY CONTACT DATE OF A.O. R 333 West 7th Avenue. Suite 100 ° Anchnra~e_ AK 99SO1 PHONE PCN M 907-793-1238 PATES ADVERTISEMENT REQUIRED: o Anchorage Daily News September 4 2007 , PO Box 149001 Arichora e AK 99514 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN g ~ ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Account # STOF0330 AFFIDAVIT OF PUBLICATION United states of America REMINDER State of ss INVOICE MUST BE !N TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. division. A CERTIFIED COPY OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED WITH THE INVOICE. Before me, the undersigned, a notary public this day personally appeared ATTACH PROOF OF PUBLICATION HERE. who, being first duty sworn, according to law, says that he/she is the of Published at in said division and state of and that the advertisement, of which the annexed is a true copy, was published in said publication on the day of 2007, and thereafter for consecutive days, the last publication appearing on the day of 2007, and that the rate charged thereon is not in excess of the rate charged private individuals. Subscribed and sworn to before me This day of 2007, Notary public for state of My commission expires STATE OF ALASKA • NOTICE TO PUBLISHER ~ ADVERTISING ORDER NO. ADVERTISING ORDER INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE AO-02814011 SEE BOTTOM FOR INVOICE ADDRESS F R AOGCC 333 W 7th Ave, Ste 100 AGENCY CONTACT Jod Colombie DATE OF A.O. Au ust 31 2007 ° M Anchorage, AK 99501 907-793-1238 PHONE PcN DATES ADVERTISEMENT REQUIRED: o Peninsula Clarion P.O. Box 3009 Kenai AK 99611 ~ September 5, 2007 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN 1T3 ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Advertisement to be published was e-mailed Type of Advertisement Legal® ^ Display Classif ied ^Other (Specify) SEE ATTACHED .SEND INVOICE IN TRIPLICATE TO AOGCC, 333 W. 7th Ave., Suite 100 Anchora e AK 99501 PAGE 1 OF 2 PAGES TOTAL OF ALL PAGES$ REF TYPE NUMBER AMOUNT DATE COMMENTS 1 VEN z ARD 02910 3 4 FIN AMOUNT SY CC PGM LC ACCT FY NMR oisr ua ~ 08 02140100 73451 2 3 4 ~' REQUISITIONED Y: ~~~ DIVISION APPROVAL: • i Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Disposal Injection Order for Aspen No. 1 Aurora Gas LLC ("Aurora") has applied for a Disposal Injection Order under 20 AAC 25.252, authorizing disposal of Class II drilling and production wastes into the Beluga formation using the Aspen No. 1 exploration well. Aurora drilled and suspended the Cook Inlet basin onshore well in 2005 from a Cook Inlet Regional Incorporated lease. Aurora was granted Alaska Oil and Gas Conservation Commission ("Commission") approval of a sundry application (307-172; 5/29/2007) to reenter Aspen No.l to recomplete as a disposal injector. The proposed disposal injection is located within Section 33, T12N, R11W, Seward Meridian. The receiving zone for this well is proposed at an approximate depth range of 2125 feet to 2730 feet measured depth. A public hearing on Aurora's application has tentatively been scheduled for October 9, 2007 at 9:00 a.m. at the Commission offices at 333 West 7t1i Avenue, Suite 100, Anchorage, Alaska 99501. To request that the tentatively scheduled hearing be held, file a written request with the Commission no later than 4:30 p.m. on September 21, 2007. If a written request for a hearing is not timely filed, the Commission may issue an order without a hearing. To learn if the Commission will hold the public hearing, call the Commission's Special Assistant, Ms. Jody Colombie, at 907-793-1221. In addition, a written protest or written comments regarding the application may be submitted to the Commission at 333 West 7~' Avenue, Suite 100, Anchorage, Alaska 99501. Any written protest or comments must be received by 4:30 p.m. on October 5, 2007 except that, if the Commission holds a public hearing, a written protest or comments must be received by the conclusion of the October 9, 2007 hearing. If, because of a disability, spe .~a commodations may be needed to submit a written protest or comments e u lic hearing, call Ms. Colombie at 907-793- 1221 before September 2 , 2007; • • PUBLISHER' S AFFIDAVIT UNITED STATES OF AMERICA, STATE OF ALASKA ss: Denise Reece being first duly sworn, on oath deposes and says: That I am and was at all times here in this affidavit mentions, Supervisor of Legals of the Peninsula Clarion, a news- paper of general circulation and published at Kenai, Alaska, that the .Public Hearing AO-2814011 a printed copy of which is hereto annexed was published in said paper one each and every ~y for one successive and consecutive day in the issues on the following dates: September 5, 2007 1,~1f~ ~ ~~~~ SUBSCRIBED AND SWORN to me before t 3th da of S ,n. 2007 NOTARY PUBLIC in favor for the State of Alaska. 1 Notice ~ Publk Flsvinp 1 8tn0a of AMeka 1 ~ Alaska OII and Gat C Commission 1 Re: Disposal Injection Order for Aspen No. 1 1 1 Aurora Gas LLC ("Aurora"), has applied fora 1 Disposal Injection Order under 20 AAC .25,252,1 1 authorizing disposal of Class II drilling and production l ~ wastes into the Beluga formation using the Aspen No.' 1 1 exploration well. Aurora drilled and suspended the 1 1 Cook Inlet basin onshore welt in 2005 from a Cook 1 1 Inlet. Regional Incorporated'lease. Aurora was grant- ~ 1 ed Alaska Oil and Gas Conservation .Commission 1 1("Commission'=) approval. of a sundry application 1(307-172; 5/29/2007) to reenter Aspen No.1 to 1 rscomplete as a disposal injector. The proposed dis- 1 1 posal injection is located. within Section 33, T72N, 1 1 RiiW, Seward Meridian: The receiving zone forthis 1 w~ is proposed at an approximate depth range of 12125 feet to 2730 feet measured depth. 1 1 A'public hearing on Aurora's application. has ten- 1 tatively been scheduled. fore October 9, 2007 at 9~ 1 1 a.m. at the Commission offices at 333 West 7th 1 1 Avenue, Suke "1.00, Anchorage, Alaska 99501. To 1 ~ request that the tentatively scheduled. , hearirp bi ~ 1 heM, file a written request with the Commission no 1 1 {ater than 4:30 p.m. on September 2l, 2007. ~ 1 ff a written request for a hearing is not !Imply 1 1 filed, ttre Commission may is§ue an order without a l 1 hearing. To learnrf the Commission will hold the pair 1 1 lic hearing, call,the Commission's Special Assistant, 1 Ms. Jody Colombie, at 907-793-1221. 1 fn addition, a written protest or written Dorn- 1 1 merits regarding the application may be submitted to ( I the Commission at 333 West 7th Avenue, Suitslfu3,.i f Anchorage, Alaska 99501: Any written. protest or 1 comments must be received by 4:30 p.m. on October 1 1 B, 2007 except that,rf_the Commission holds a public 1 hearing, a written. protest or .comments must be ~ 1 received. by the conclusion of the October 9,2007 1. 1 hearing. 1 1 If, because of a disability, special acx;ommoda- I Ltions may be needed to submit a written protest or 1 comments or attend the public hearing, call Ms. 1 1 Colombie at 907-793-1221 before September 27,'1 2007. ~ 1 PUBLISH: t#l5, 2007 74 1 ~_- ----_____~... .r_~ My Commission expires 26-Aug-08 02-902 (Rev. 3/94) Publishe~ginal Copies: Department Fiscal, Depart Receiving AO. FRM STATE OF ALASKA NOTICE TO PUBLISHER ADVERTISING ORDER NO. ADVERTISING INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION PART 2 OF THIS FO WITH ATTACHED COPY OF AO-02814011 ORDER ( RM) ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE SEE BOTTOM FOR INVOICE ADDRESS F AOGCC AGENCY CONTACT DATE OF A.O. R 333 West 7~' Avenue. Suite 100 Anchnra~e_ AK 9951 PHONE PCN M 907-793-1238 DATES ADVERTISEMENT REQUIRED: o Peninsula Clarion 2007 September 5 , PO Box 3009 Kenai AK 99611 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ~ ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: AFFIDAVIT OF PUB LICATION United states of America REMINDER State of ss INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. division. A CERTIFIED COPY OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED WITH THE INVOICE. Before me, the undersigned, a notary public this day personally appeared ATTACH PROOF OF PUBLICATION HERE. who, being first duly sworn, according to law, says that he/she is the of Published at in said division and state of and that the advertisement, of which the annexed is a true copy, was published in said publication on the day of 2007, and thereafter for consecutive days, the last publication appearing on the day of 2007, and that the rate charged thereon is not in excess of the rate charged private individuals. Subscribed and sworn to before me This day of 2007, Notary public for state of My commission expires 02-901 (Rev. 3/94) AO.FRM Page 1 of 1 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Friday, August 31, 2007 11:33 AM Subject: Public Notice Aspen 1 Attachments: Aspen 1 DIO Public Notice.pdf BCC:McIver, C (DOA); Regg, James B (DOA); 'Alan Birnbaum <""Alan J Birnbaum "> (alan.birnbaum@alaska.gov)'; 'Aleutians East Borough'; 'Anna Raff ; 'Arthur C Saltmarsh'; 'Arthur Copoulos'; 'Barbara F Fullmer'; 'bbritch'; 'Bill Fowler'; 'Bill Walker'; 'Brad McKim'; 'Brandon Gagnon'; 'Brian Gillespie'; 'Brian Havelock'; 'Brit Lively'; 'Bruce Webb'; 'buonoj e'; 'Cammy Taylor'; 'carol Smyth'; 'Cary Carrigan'; 'Catherine P Foerster ; 'Charles O'Donnell'; 'Chris Gay'; 'Christian Gou-Leonhardt'; 'Christine Hansen'; 'Cliff Posey'; 'Cody Rice'; 'Dan Bross'; 'dapa'; 'Daryl J. Kleppin'; 'David L Boelens'; 'David Steingreaber'; 'ddonkel'; 'Deanna Gamble'; 'Deborah J. Jones'; 'doug_schultze'; 'Evan Harness'; 'eyancy ; 'Francis S. Sommer'; 'Fred Steece'; 'Garland Robinson'; 'Gary Laughlin'; 'Gary Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil'; 'Gregg Nady'; 'gregory micallef; 'gspfoff; 'Hank Alford'; 'Harry Engel'; 'jah'; 'James B Regg'; 'James M. Ruud'; 'James Scherr'; 'Janet D. Platt'; 'jdarlington'; 'jejones'; 'Jerry McCutcheon'; 'Jim White'; 'Jim Winegarner ; 'Joe Nicks'; 'John Garing ; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'John W Katz'; 'Jon Goltz'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; keelson@petroleumnews.com; 'Kristin Dirks'; 'Laura Silliphant'; 'Lois'; 'Lynnda Kahn'; 'mail=akpratts@acsalaska.net'; 'mail=Crockett@aoga.org'; 'mail=fours@mtaonline.net'; 'Mark Dalton'; 'Mark Hanley'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marguerite kremer'; 'marty'r 'Matt Rader'; 'mckay'; 'Meghan Powell'; 'Mike Bill'; 'Mike Mason'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'Nick W. Glover'; 'Patty Alfaro'; 'Paul Decker'; 'Paul Winslow'; 'Randall Kanady'; 'Randy L. Skillern'; 'rcrotty'; 'rmclean'; 'Robert Campbell'; 'Roger Belman ; 'Rosanne M. Jacobsen'; 'Rudy Brueggeman'; 'Scott Cranswick'; 'Shannon Donnelly'; 'Sharmaine Copeland'; 'Sondra Stewman'; 'Sonja Frankllin'; 'stanekj'; 'Stephen F Davies'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'tablerk'; 'Tamera Sheffield'; 'Temple Davidson'; 'Terrie Hubble'; 'Thomas E Maunder'; 'Tim Lawlor'; 'Todd Durkee'; 'Tricia Waggoner'; 'trmjrl'; 'Walter Featherly'; 'Walter Quay'; 'Wayne Rancier' Attachments:Aspen 1 DIO Public Notice.pdf; 8/31 /2007 Mary Jones David McCaleb Mona Dickens XTO Energy, Inc. IHS Energy Group Tesoro Refining and Marketing Co. Cartography GEPS Supply & Distribution 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 300 Concord Plaza Drive Ft. Worth, TX 76102-6298 Houston, TX 77056 San Antonio, TX 78216 George Vaught, Jr. Jerry Hodgden Richard Neahring PO Box 13557 Hodgden Oil Company NRG Associates Denver, CO 80201-3557 408 18th Street President Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 John Levorsen Michael Parks Mark Wedman 200 North 3rd Street, #1202 Marple's Business Newsletter Halliburton Boise, ID 83702 117 West Mercer St, Ste 200 6900 Arctic Blvd. Seattle, WA 98119-3960 Anchorage, AK 99502 Baker Oil Tools Schlumberger Ciri 4730 Business Park Blvd., #44 Drilling and Measurements Land Department Anchorage, AK 99503 2525 Gambell Street #400 PO Box 93330 Anchorage, AK 99503 Anchorage, AK 99503 Ivan Gillian Jill Schneider Gordon Severson 9649 Musket Bell Cr.#5 US Geological Survey 3201 Westmar Cr. Anchorage, AK 99507 4200 University Dr. Anchorage, AK 99508-4336 Anchorage, AK 99508 Jack Hakkila Darwin Waldsmith James Gibbs PO Box 190083 PO Box 39309 PO Box 1597 Anchorage, AK 99519 Ninilchick, AK 99639 Soldotna, AK 99669 Kenai National Wildlife Refuge Penny Vadla Richard Wagner Refuge Manager 399 West Riverview Avenue PO Box 60868 PO Box 2139 Soldotna, AK 99669-7714 Fairbanks, AK 99706 Soldotna, AK 99669-2139 Cliff Burglin Bernie Karl North Slope Borough PO Box 70131 K&K Recycling Inc. PO Box 69 Fairbanks, AK 99707 PO Box 58055 Barrow, AK 99723 Fairbanks, AK 99711 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 ¢~ f~ Y~hl~o~ ~4 Page 1 of 2 Davies, Stephen F (DOA) From: Davies, Stephen F (DOA) Sent: Friday, August 03, 2007 4:10 PM To: 'bwebb c~Daurorapower.com' Cc: Maunder, Thomas E (DOA); Roby, David S (DOA) Subject: RE: Aspen Injection Order Application Attachments: 070726_Aquifer Exemption_CFR_147.102.pdf Bruce, My apologies for the delayed response to your email of July 18tH 1. Is this any exemption issued that we have requested, or any at all? I do not know of any that we have requested or have been issued. If it is any in the area... how do I find that out? I don't know of any that cover the Aspen area. Exemptions can be found: a. within a Commission Aquifer Exemption Order that covers the project area or lies nearby (listed on AOGCC's web site at http://www.aogcc.alaska.gov/orders/aeo/aeoindex.shtml), b. within an EPA order (you'd have to check with EPA to see if there is a list of aquifer exemptions for Alaska), or c. within the Federal register at 40 CFR 147.102(b). I've attached a scan of this section of the register for you. 2. A water analysis (salinity) report from the open hole logs (attached) was submitted with the application. Is my understanding correct that this wasn't adequate to satisfy either the "standard laboratory water analysis for water quality° or for "compatibility of fluids to be injected with existing formation fluids"? Quality of the formation water: The analysis attached to your email is fine for purposes of demonstrating that the formation water exceeds 10,000 ppm. There wasn't a salinity report attached to the disposal application, and I overlooked your handwritten note at the bottom the signature page that said the analysis accompanied the application for the permit to drill (which was submitted two years ago). The Commission tries to make every order and application a complete document that stands by itself, so the reader doesn't have to go searching through our files for a key piece of data that was submitted at a different time and for a different reason. Compatibility of fluids: This is a completely separate issue from the quality of the formation water. The Commission needs evidence that whatever fluids are proposed for injection will be compatible with the existinq formation water. This ensures efficient injection by minimizing formation damage and scaling. Laboratory compatibility studies are best. If you don't have them, then successful analog injection projects are generally acceptable, if rock type, fluids and pressure/temperature conditions are similar. Aurora may be asked to perform laboratory compatibility studies if you all don't have them. 3. It is my understanding that the deficiency letter referred to above was suppose to have been mailed out in late June (about a month ago). If we obtain a letter of non.--objection from the surface and sub-surface owner (Tyonek and CIRI) of the well area and several miles radius around the well, is there any way to expedite the review 1 public notice period? No. Letters of non-objection are always helpful, especially when the Commission is deciding whether or not to hold a hearing on a topic that has not received any comments or requests for hearing. But the Commission cannot circumvent or shorten the 30-day public comment period. From complete application to published order takes 6 to 8 weeks if there are no comments or requests for a hearing. If a hearing is required, then the process takes 8 to 10 weeks. Please tet me know if you have any additional questions. Thanks, Steve Davies 8/3/2007 Page 2 of 2 From: Bruce D. Webb [mailto:bwebb~aurorapower.com] Sent: Wednesday, July 18, 2007 11:19 AM To: Davies, Stephen F (DOA) Subject: Aspen Injection Order Application Good morning Steve, We are working on providing the information deficiencies outlined in the July 17, 2007 letter regarding the application for the Aspen Class II disposal injection order. I have three questions: 1. "reference to any applicable freshwater exemption issued in accordance with 20 AAC 25.440." Is this any exemption issued that we have requested, or any at all? I do not know of any that we have requested or have been issued. If it is any in the area... how do I find that out? 2. A water analysis (salinity) report from the open hole logs (attached) was submitted with the application. Is my understanding correct that this wasn't adequate to satisfy either the "standard laboratory water analysis for water quality" or for "compatibility of fluids to be injected with existing formation fluids"? 3. It is my understanding that the deficiency letter referred to above was suppose to have been mailed out in late June (about a month ago). If we obtain a letter of non-objection from the surface and sub-surface owner (Tyonek and CIRI) of the well area and several miles radius around the well, is there any way to expedite the review /public notice period? Obviously, I am new at this, so I apologize up front for my lack of understanding - but I am a quick study, so you only have to tell me once. Thanks, -Bruce 8/3/2007 #3 • Davies, Stephen F (DOA) From: Bruce D. Webb [bwebb@aurorapower.com] Sent: Wednesday, July 18, 2007 11:19 AM To: Davies, Stephen F (DOA) Subject: Aspen Injection Order Application Attachments: ASPEN 1 Rw SALINITY.xIs Good morning Steve, Page 1 of 1 We are working on providing the information deficiencies outlined in the July 17, 20071etter regarding the application for the Aspen Class II disposal injection order. I have three questions: 1. "reference to any applicable freshwater exemption issued in accordance with 20 AAC 25.440." Is this any exemption issued that we have requested, or any at all? I do not know of any that we have requested or have been issued. If it is any in the area... haw do I find that out? 2. A water analysis (salinity) report from the open hole logs (attached) was submitted with the application. Is my understanding correct that this wasn't adequate to satisfy either the "standard laboratory water analysis for water quality" or for "compatibility of fluids to be injected with existing formation fluids"? 3. It is my understanding that the deficiency letter referred to above was suppose to have been mailed out in late June (about a month ago}. If we obtain a letter of non-objection from the surface and sub-surface owner (Tyonek and CIRI) of the well area and several miles radius around the well, is there any way to expedite the review /public notice period? Obviously, I am new at this, so I apologize up front for my lack of understanding - but I am a quick study, so you only have to tell me once. Thanks, -Bruce 8/3/2007 ~2 I ~ ~ i ` ;,~, ~ r ,=~ ; ~ ~ SARAH PALIN, GOVERNOR ~+~1 L>•i/[J•-7R~ OIL ~ liLa-7 333 W. 7th AVENUE, SUITE 100 CO~*7s/RQ~ilOis CODIl~IISSIO~ ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 July 17, 2007 Mr. Bruce Webb Manager, Land and Regulator Affairs Aurora Gas, LLC 2500 Citywest Blvd, Suite 2500 Houston, TX 77042 Dear Mr. Webb: The Alaska Oil and Gas Conservation Commission ("Commission") has done a completeness review of the Aurora Gas LLC ("Aurora") application for disposal of Class II oilfield wastes using the Aspen No.l exploratory well. The application provided to the Commission consists of a two-page letter. An application for permit to drill, which was subsequently returned to Aurora as the improper form for converting Aspen No.l to injection, serves as the only supporting information provided by Aurora. The Aspen disposal injection order application is deficient in a number of areas. The Commission has not yet accepted it for public comment. The most serious deficiency is the lack of information for the Commission to make a determination that the injected fluids will remain confined to the intended disposal injection zone. Commission regulations at 20 AAC 25.252 define the required contents for a disposal injection order. Before the Commission can initiate the public review process for the injection order application, the following additional information must be provided: - a land plat showing the location of the proposed disposal well, abandoned or other unused wells, production wells, dry holes, and any other wells within one-quarter mile; - affidavit showing the surface owners within one-quarter mile of Aspen No. 1 have been notified and provided a copy of the application for disposal; - geologic information (name, thickness, lithologic descriptions) for both the intended injection zone and the confining zones; included should be a type log and geologic cross section; please note that the application incorrectly refers to both Tyonek and Beluga formations for disposal injection; - standard laboratory water analysis, or the results of another method acceptable to the Commission, to determine the quality of the water within the formation into which disposal is proposed; - reference to any applicable freshwater exemption issued in accordance with 20 AAC 25.440; - laboratory analyses or other evidence of compatibility of fluids to be injected into Aspen No. 1 with existing formation fluids, or information about injection elsewhere that is analogous to that planned for Aspen; and - fracture modeling and analysis that clearly presents rates, pressures, volumes, and type of injection (batch or continuous) modeled, the resulting fracture propagation, and the Mr. Bruce Webb July 17, 2007 Page 2 of 2 arresting characteristics of the injection zone that prevent fracture propagation through the through the confining layer. As part of our preliminary completeness review, we have begun to evaluate the mechanical integrity of Aspen No. 1. In addition to the shallow zone where Aurora intends to inject wastes, there are numerous other existing perforations in the well (some up hole of the disposal injection zone) that complicate well integrity decisions. Aurora should evaluate the opportunity to use other tools for demonstrating continued well integrity and confinement of fluids in addition to the short duration mechanical integrity testing mentioned in the application. Examples include oxygen activation logs and temperature surveys. Aurora has been given approval for sundry operations to reenter and work over Aspen No. 1 (Sundry Permit No. 307-172) beginning in August 2007. Aurora is reminded that no waste disposal injection may be commenced into Aspen No. 1 until a disposal injection order has been approved by the Commission. cc: Aurora Gas LLC 1400 West Benson Blvd, Suite 410 Anchorage, AK 99503 ~~. ~ ! Aurora Gas, LLC www.aurorapower.com October 15, 2007 ~~ ~~~~'~ John K. Norman, Chairman State of Alaska ~~ ` ~ - Oil and Gas Conservation Commission ~~~~~~ ~~ ;, 333 W. 7~' Avenue, Suite 100 Anchorage, AK 99501 Re: Application for Disposal of Class II Oilfield Waste by Underground Injection Beluga Formation, Cook Inlet Alaska Section 33, Township 12 North, Range 11 West, Seward Meridian Dear Mr. Norman: Pursuant to your request at the Hearing on October, 9, 2007, I have attached copies of the Certified Mail Return Receipts from the Cook Inlet Region Inc. and the Tyonek Native Corporation. Regarding the geologic and other means of assurances that the injected fluids will be confined, the following information was sent to Mr. Jim Regg via e-mail on October 11, 2007 for his review and consideration. This e-mail also indicated the availability of Mr. Ed Jones, Vice President of Engineering, to discuss the particulars with Mr.Regg. "The best response to this concern is to look at the Horizon Well Logging mud log ofAspen #1 (August 2005)--a copy was submitted to the AOGCC on a CD on June 15, 2006 (let me know if you need acopy--1'd attach one but it is a 9 MB .pdf file). The mud log indicates that the lithology descriptions of the samples over the interval of 1400-1900' MD is mostly "claystone, " or "clay" with a few small, thin sands and coals interspersed (based on the lithology symbols, some sand in samples of only 120' of the 500'--usually 10% of those samples, at most 20%) By the lithological symbols used in the descriptions, there was some coal (usually 20%) in samples of about 100' of the 500; but the bulk of the samples are clay, siltstone, and claystone. These three components have very little effective permeability, allowing essentially no migration of fluids (including gas) in measurable time. The NuLook log by NuTech (copy attached), a computerized composite petrophysical analysis using all available electric logs, indicates that the effective permeability over this same section is very low. In the section from 1810-1980; there are 10 intervals with any indicated perm, all perms are less than 2 md, and all "permeable intervals" are less than 10' thick and usually separated by 10-20' of impermeable formation. In the interval from 1410' to 1750; there are (by NuTech's evaluation) numerous thin intervals with perms of 0.5 to 10 md, but all are separated by impermeable intervals of 5' to 20' thickness. Furthermore, the interval from 1300' up to 700' is much the same--very little sand in the sample descriptions on the mud log (none in the samples from 780' to 980), a few thin coal stringers, and claystone, clay, and siltstone matrix. 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 • • While the NuLook logs indicates that there are several fairly permeable sands in this interval, but all are isolated by impermeable layers, including several that are 20-25' thick. The NuTech frac study indicated that the fractures created by injection mud of water will be confined between 2098' and 2412' (top proposed perf is at 2125' and bottom perf at 2371'. Thus, the injected fluids should be confined within this interval, as there are hundreds of feet of impermeable layers above this depth. The Cement Bond Log (Schlumberger SCMT of 23 August 2005) indicates that the. top of cement is at about 220' (inside the surface casing), and there is much good to excellent bond between the pen`s and shallower potential fresh water aquifers. Furthermore, the bond around the perfs is very good. Subsequent to that log, perforations at 1368-88' and 1760-70' were squeezed with cement, which should have improved the bond in those proximities (although the bond around 1760-70' was already excellent by the log). These factors all combined indicate that the injected fluids should be confined vertically to the proximity of the pen`s and not migrate upward. Please let me know if you have any questions or concerns after reviewing this data. On October 12, 2007, Mr. Regg requested additional information from Mr. Jones, which was immediately responded to, stating: 1) As we have done more work on this project, it appears that the Request for DIO should be amended: 1 don't foresee ever needing a rate over 3 BPM. The mention of maximum pressure of 1500 psi was worded in such a way to give us some flexibility pending the outcome of the step-rate test, but it was anticipated as the highest maximum that we'd need. (The reason for limiting it to 1500 psi is that is the pressure to which we propose testing the casing above the packer. However, with a packer in the well, the annular pressure monitored, and good casing cement, which the bond log indicates that we have, this should not be a concern). We plan to do a step-rate test to determine what pressures are needed (but as time goes on, the injection pressures will likely increase somewhat), but I do not foresee a need for a maximum higher than 1500 psi. The NuTech NuStim analysis was run at 1 BPM for produced water and indicated that the injection pressures will be lower than 1500 psi (see the NuStim "Analysis of Injection Project"report, pages 17 and 19)--note that the modeling assumes all the water (and rate) goes into one interval, and we will have 2 intervals open (i.e, each interval, 2125-45' Interval 2J and 2351-2371' (Interval 1J, was modeled separately, so all the rate is assumed to go into one interval). In reality, with both intervals open, as is the plan, the rate will be divided between the 2 intervals, with the Interval 2 taking more rate at a given pressure than Interval 1--thus, we should not see pressures as high as modeled. This is even more true for the injection of drilling mud. The highest pressure (and the only case in which 1500 psi was exceeded) was with drilling mud injected into only Interval 1 at 3 BPM(note that the 3 batch injections over the 84 days are at increasing rates, the first is at 1 BPM, the second at 2 BPM, and the third at 3BPM--this increasing pressure is due to the increased rate, not so much injected volume, although there appears to be a slight increase in static pressure due to injected volume, but it is not significant compared to the increase of injection pressure due to increased rate). Again, with both zones open, the rate going into Interval 1 will likely not exceed 1 BPM, so the pressure should be 1100 psi or so--about the same pressure on Interval 2 at 2 • ~ BPM (see pages 18 and 20 of the NuStim report). Thus, we do not anticipate a maximum allowable surface injection pressure of 1500 psi being a problem. 2) Regarding the injection of drilled cuttings, this year we are disposing most of our cuttings (and some mud) in the Kenai Borough land fill after mixing with Portland cement. Some larger materials were screened out, washed, and will be used as road/pad fill, as a Beneficial Use. In the future we will likely again separate the larger material and dispose in the landfill or as Beneficial Use, and dispose of only the cuttings fines (passing thru a 150 or 200 mesh screen) along with the drilling mud by injecting into this well Thus, Aurora Gas believes the disposal injection zones are adequately confined both stratigraphically and through the mechanical integrity of the well bore. We further respectfully amend the injection rate of the application to be at a maximum rate of 3 bbl per minute. Lastly, in a conversation with Mr. Steve Davies regarding the salinity and compatibility of fluids in the injection zone, he indicated that we had supplied all necessary information and supporting data. This should satisfy all outstanding deficient information in the Application for Injection of Class II Drilling Wastes. Your approval and issuance of a Disposal Injection Order is greatly appreciated. Should you have additional questions or concerns, please do not hesitate in contacting either myself or Ed Jones at (713) 977-5799. Respectfully Submitted By, ,,,-'' -~' Bruce D. Webb Manager, Land and Regulatory Affairs attachment _- ~_ ,_ _. m _. _ ~ . 1 ^ Complete items 1, 2,'and 3. Also complete A. Signature item 4 if Restricted Delivery is desired. ~pnt ^ Print your name and address on the reverse:. ^ Addressee so that we can return the card to you. ~ ^ Attach this card to the back of the mailpiece, B. Received by (Pr/nfed Name) C. Date of Delivery ~/ ~~ or on the front if space permits. , . t. Article Addressed to: D. Is delivery address different from item 1? ^ Yes I if YES, enter delivery address below: ^ No .< T~ ~.. `~ t l0 89 G' s~~~zl9 - ~~~ ~ ~ ~~ 3. Se ice Type ~g~ ~ Certified Mail ^ Express Mail ^ Registered ^ Return Receipt for Merchandise , ^ Insured Mail -- ^ C.O.D. 4. Restricted Delivery? ( Fee) ^ Y~ 2. Article Number ~ ~ f { { ; ; i , y i , ~ 3 :, ~ # ~~a~ (Transfer from sere ce labs{) s i = ~ _ : ; ; { ; _ ; , ; ~3ga~ ~oa~oa~= 6o99i 542 ~ ~ PS~Forrra 3•'811 ~Fetirr~tahy X004 { { { { ©omestic Return Receipt to2595-oz n+.-~ a~~ , __._.. _ ^ Complete items 1, 2,'erld 3. Also complete A. s' nature ~ ~/, '~ • '' ^ Agent item 4 if Restricted Delivery is desired. ,~~ ~ "" Add ~ ^ .Print your name and address on the reverse _ ressee so that we can return the card to you. B. Received by ( fed Name) C. Date of Delivery ' ^ Attach this card to the back of the mailpiece, ' ~ 4 ~~..1~ 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: ^ No i ~ G / S ~ ~~- ~~ U- ~~ ~ 3 ~~ 3. Service Type ~ ~`~~,~ ~ '^4: (rj ~ eta, ~Cert'rfi+Bd Mail ^ Express Mall 1 'V _ r ® ~ " ^ Registered ^ Return Receipt for Merchandise _ ,? ^ Insured Mail ^ C~QsD: 5 ~,,, ~~ 4. Restricted Delivery? (Extra Fee) ^ Yes r •: 2. Article Number ~ & ~ "` r (transfer item service iaben ' ' A 7 0 ~ 5 4] 3 9^ ~ ~! [~ ~ 6 ~ 9 9 _5 I-F=2 5 I, €~ #P~ F;oj'r,~n 381'~,;`•Fe`,bru~ry~?00~ ~ ~ ~ ~ ~Dor~ic Return Receipt 102595-oz-M-lSao f ~ Aurrora Gas, LLC www.aurorapower.com August 17, 2007 John K. Norman, Chairman State of Alaska Oil and Gas Conservation Commission 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 ~EGEl~ED ~u~2ozaa7 Alaska Oil ~ Gas Cons. Commission Anchorage Re: Application for Disposal of Class II Oilfield Waste by Underground Injection Beluga Formation, Cook Inlet Alaska Section 33, Township 12 North, Range 11 West, Seward Meridian Dear Mr. Norman: Pursuant to your request ,dated July 17, 2007, for the deficient information contained in our original submittal, I here by submit the remaining items: 1. A revised Page 22 of the Fracture Modeling and Analysis that was submitted last week. The original page had conflicting and confusing terminology regarding "stages" as opposed to "intervals". This submission is for clarification only. 2. Standard water analysis and evidence of compatibility of injected fluids with formation fluids. The water samples included are:. - NWU #9 is a NCU #9 Produced water sample -This is water from the Beluga Formation and is approximately the same depths as proposed at Aspen. - TMC#1 is a sample from Three Mile Creek #1 Well which is also from the Beluga formation and similar depths of Aspen. - TMC#2 is a sample from Three Mile Cree?, #2 Well, which was analyzed to show a well that has been producing quite a bit of water. - PWP is a sample from the Produced Water Pond, which will be the initial fluids injected into the well, and are comprised of produced water from our wells, brine water used during drilling and workovers of wells, and precipitation (rain or snow). 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 ~ • AOGCC John Norman August 17, 2007 Page 2 Additionally, Aurora proposes cone-time temperature survey log during the initial injection from the Produced Water Pond to evaluate and demonstrate the well integrity and containment of fluids. This should satisfy all outstanding deficient requirements in the Application for Injection of Class II Drilling Wastes. Your approval and issuance of a Disposal Injection Order is greatly appreciated. Should you have additional questions or concerns, please do not hesitate in contacting me. Respectfully Submitted By, ~l'Y.~-' Bruce D. Webb Manager, Land and Regulatory Affairs attachments 'r' y d Conciusions a •Interval 1 and 2 both show containment of the injected fluid as shown on the PredictedR Fracture Dimension Plots. • Interval 1 and 2 both show greater fracture height growth with the drilling mud. This is because of the increased viscosity of this fluid (modeled as 46 cp) which effects fracture dimensions because it creates an increase in fracture width and has a lower rate of leak - off. • Interval #2 simulates a smaller (shorter) fracture than Interval #1 due to the higher permeability -Ft calculated in zone. • Both intervals appear to be good injector candidates and do not show fracture growth outside of the zone of interest. Laboratory Analysis Report 200 W. Potter Drive Anchorage, AK 99518-1605 Tel; (907) 562-2343 Fax: (907)561-5301 Web: http://www.us.sgs.com Chad Helgeson Aurora Gas 1400 W Benson Blvd Ste 410 Anchorage, AK 99503 Work Order: 1073467 Aspen Injection Released by: Client: Aurora Gas Bryan J. Arnold Report Date: August 14, 2007 ~~u~.~J- ~.~,.-~oC 2007.08.14 a,~o,.:~o~~o,~Mw~. 13:27:54 - Enclosed are the analytical results associated with the above workorder. As required by the state of Alaska and the USEPA, a formal Quality Assurance/Quality Control Program is maintained by SGS. A copy of our Quality Assurance Plan (QAP), which outlines this program, is available at your request. The laboratory certification numbers are AK971-OS (DW), UST-005 (CS) and AK00971 (Micro) for ADEC and 001582 for NELAP (RCRA methods: 1010/1020; 1311, 6000/7000, 9040/9045, 9056, 9060, 9065, 8015B, 8021B, 8081A/8082, 8260B, 8270C). Except as specifically noted, all statements and data in this report are in conformance to the provisions set forth by the SGS QAP, the National Environmental Laboratory Accreditation Program and, when applicable, other regulatory authorities. If you have any questions regarding this report or if we can be of any other assistance, please contact your SGS Project Manager at 907-562-2343. The following descriptors maybe found on your report which will serve to further qualify the data. PQL Practical Quantitation Limit (reporting limit). U Indicates the analyte was analyzed for but not detected. F Indicates value that is greater than or equal to the MDL. J The quantitation is an estimation. ND Indicates the analyte is not detected. B Indicates the analyte is found in a blank associated with the sample. * The analyte has exceeded allowable regulatory or control limits. GT Greater Than D The analyte concentration is the result of a dilution. LT Less Than ! Surrogate out of control limits. Q QC parameter out of acceptance range. M A matrix effect was present. JL The analyte was positively identified, but the quantitation is a low estimation. E The analyte result is above the calibrated range. Note: Soil samples are reported on a dry weight basis unless otherwise specified. SGS Environmental Services Inc. 1200 W. Potter Dr. Anchorage AK. 99518-1605 t (9071562-2343 f (9071561-5301 www.ussgs.com • SGT SGS Ref.# 1073467001 Client Name Aurora Gas Project Name/# Aspen Injection Client Sample ID PW NWU #9 Matrix Water (Surface, Eff., Ground) • All Dates/Times are Alaska Standard Time Printed Date/Time 08/1412007 9:55 Collected Date/Time 07/19/2007 0:00 Received Date/Time 07/19/2007 9:22 Technical Director Stephen C. Ede Sample Remarks: Allowable Prep Analysis Parameter Results PQL Units Method Container ID Limits Date Date Init Metals by ICP/MS Barium 1670 30.0 ug/L EP200.8 D 07/26/07 07/31/07 MH Calcium 86100 5000 ug/L EP200.8 D 07/26/07 07/31/07 MH Iron 65200 2500 ug/L EP200.8 D ~ 07/26/07 07/31/07 MH Magnesium 54800 500 ug/L EP200.8 D 07/26/07 07/31/07 MH Potassium 1170000 5000 ug/L EP200.8 D 07/26/07 07/31/07 MH Silicon 5360 2000 ug/L EP200.8 D 07/26/07 07/31/07 MH Sodium 2820000 20000 ug/L EP200.8 D 07/26/07 07/31/07 MH Waters Department Difference 7.2 0.0100 % SM20 1030E A 08/10/07 BAH Chloride 4790 100 mg/L EPA 300.0 A 07/31/07 07/31/07 JDS Total Nitrate/Nitrite-N ND 0.100 mg/L SM20 4500NO3-F E (<10) 07/25/07 JDS Sulfate 1.08 0.500 mg/L EPA 300.0 A 07/30/07 07/30/07 JDS Salinity from Chloride 7.91 ppT EPA 300.0 07/31/07 07/31/07 JDS Alkalinity 198 10.0 mg/L. SM20 2320B C 07/24/07 TRM HCO3 Alkalinity 198 10.0 mg/L SM20 2320B C 07/24/07 TRM CO3 Alkalinity ND 10.0 mg/L SM20 2320B C 07/24/07 TRM OH Alkalinity ND 10.0 mg/L SM20 23208 C 07/24/07 TRM pH 6.50 0.100 pH units SM20 4500-H B C 07/19/07 CLS Resistivity 0.667 0.0100 ohm-m SM19 2510A C 07/26/07 CLS Total Dissolved Solids 9820 160 mg/L SM20 2540C C 07/20/07 CLS • ~G~ SGS Ref.# 1073467002 Client Name Aurora Gas Project Name/# Aspen Injection Client Sample ID PW TMC #1 Matrix Water (Surface, Ef£, Ground) • All Dates/Times are Alaska Standard Time Printed Date/Time 08/14/2007 9:55 Collected Date/Time 07/19/2007 0:00 Received Date/Time 07/19/2007 9:22 Technical Director Stephen C. Ede Sample Remarks: 4500-N03 -Total Nitrate/Nitrite -The matrix spike recovered below the QC criteria. The batch LCS is within QC limits. Allowable Prep Analysis Parameter Results PQL Units Method Container ID Limits Date Date Init Metals by ICPjMS Barium 2330 30.0 ug/L EP200.8 D 07/26/07 07/31/07 MH Calcium 47600 5000 ug/L EP200.8 D 07/26/07 07/31/07 MH Iron 39800 2500 ug/L EP200.8 D 07/26/07 07/31/07 MH Magnesium 69600 500 ug/L EP200.8 D 07/26/07 07/31/07 MH Potassium 1860000 20000 ug/L EP200.8 D 07/26/07 07/31/07 MH Silicon 11800 2000 ug/L EP200.8 D 07/26/07 07/31/07 MH Sodium 5690000 50000 ug/L EP200.8 D 07/26/07 07/31/07 MH Waters Department Difference 20 0.0100 % SM20 1030E A 08/10/07 BAH Chloride 6400 100 mg/L EPA 300.0 A 07/31/07 07/31/07 JDS Total Nitrate/Nitrite-N 0.305 0.100 mg/L SM20 4500N03-F E (<10) 07/25/07 JDS Sulfate 5.61 0.500 mg/L EPA 300.0 A 07/30/07 07/30/07 JDS Salinity from Chloride 10.6 ppT EPA 300.0 07/31/07 07/31/07 JDS Alkalinity 1730 10.0 mg/L SM20 2320B C 07/31/07 CLS HC03 Alkalinity 1730 10.0 mg/L SM20 2320B C 07/31/07 CLS C03 Alkalinity ND 10.0 mg/L SM20 2320B C 07/31/07 CLS OH Alkalinity ND 10.0 mg/L SM20 2320B C 07/31/07 CLS pH 7.70 0.100 pH units SM20 4500-H B C 07/19/07 CLS Resistivity 0.323 0.0100 ohm-m SM19 2510A C 07/26/07 CLS Total Dissolved Solids 23600 160 mg/L SM20 2540C C 07/20/07 CLS • • ~~. SGS Ref.# 1073467003 Client Name Aurora Gas Project Name/# Aspen Injection Client Sample ID PW TMC #2 Matrix Water (Surface, Eff., Ground) All Dates/Times are Alaska Standard Time Printed Date/Time 08/14/2007 9:55 Collected Date/Time 07/19/2007 0:00 Received Date/Time 07/19/2007 9:22 Technical Director Stephen C. Ede Sample Remarks: Parameter Results PQL Units Method Allowable Container ID Limits Prep Analysis Date Date Init Metals by ICP/MS Barium 636 30.0 ug/L EP200.8 D 07/26/07 07/31/07 MH Calcium 49800 5000 ug/L EP200.8 D 07/26/07 07/31/07 MH Iron 7690 2500 ug/L EP200.8 D 07(26/07 07(31/07 MH Magnesium 29200 500 ug/L EP200.8 D 07/26/07 07/31/07 MH Potassium 116000 5000 ug/I, EP200.8 D 07/26/07 07/31/07 MH Silicon 14200 2000 ug/L EP200.8 D 07/26/07 07/31/07 MH Sodium 706000 5000 ug/L EP200.8 D 07/26/07 07/31/07 MH Waters Department Difference 4.7 0.0100 % SM20 1030E A 08/10/07 BAH Chloride 331 1.00 mglL, EPA 300.0 A 07/31/07 07!31/07 7DS Total Nitrate/Nitrite-N 1.47 0.100 mg/L SM20 4500N03-F (<10) 07/31/07 JDS Sulfate ND 0.100 mg/L EPA 300.0 A 08/07/07 08/07/07 JDS Salinity from Chloride 0.546 ppT EPA 300.0 A 07/31/07 07/31/07 JDS Alkalinity 1290 10.0 mg/L SM20 2320B C 07/31/07 CLS HC03 Alkalinity 1290 10.0 mg/L SM20 2320B C 07/31/07 CLS C03 Alkalinity ND 10.0 mg/L SM20 2320B C 07/31/07 CLS OH Alkalinity ND 10.0 mg/L SM20 2320B C 07/31/07 CLS pH 8.10 0.100 pH units SM20 4500-H B C 07/19/07 CLS Resistivity 0.333 0.0100 ohm-m SM19 2510A C 07/26/07 CLS Total Dissolved Solids 2580 160 mg/L SM20 2540C C 07/20/07 CLS • ~G~ SGS Ref.# Client Name Project Name/# Client Sample ID Matrix 1073467004 Aurora Gas Aspen Injection PWP Water (Surface, Ef£, Ground) • All Dates/Times are Alaska Standard Time Printed Date/Time 08/14/2007 9:55 Collected Date/Time 07/19/2007 0:00 Received DatelTime 07/19/2007 9:22 Technical Director Stephen C. Ede Sample Remarks: Allowable Prep Analysis Parameter Results PQL Units Method Container ID Limits Date Date Init Metals by ICP/MS Barium 4200 30.0 ug/L EP200.8 D 07/26/07 07/31/07 MH Calcium 214000 5000 ug/L EP200.8 D 07/26/07 07/31/07 MH Iron 11000 2500 ug/L EP200.8 D 07/26/07 07/31/07 MH Magnesium 56300 500 ug/L EP200.8 D 07/26/07 07/31/07 MH Potassium 2710000 20000 ug/L EP200.8 D 07/26/07 07/31/07 MH Silicon 8540 2000 ug/L EP200.8 D 07/26/07 07/31/07 MH Sodium 6250000 50000 ug/L EP200.8 D 07/26/07 07/31/07 MH Waters Department Difference 3.3 0.0100 % SM20 1030E A 08/10/07 BAH Chloride 9900 100 mg/L EPA 300.0 A 07/31/07 08/01/07 JDS Total Nitrate/Nitrite-N 0.139 0.100 mg/L SM20 4500NO3-F (<10) 07/31/07 JDS Sulfate 31.9 0.500 mg/L EPA 300.0 A 07/30/07 07/30!07 JDS Salinity from Chloride 16.3 ppT EPA 300.0 07/31/07 08/01/07 JDS Alkalinity 846 10.0 mg/L SM20 2320B C 07/24/07 TRM HCO3 Alkalinity 846 10.0 mg/L SM20 2320B C 07/24/07 TRM CO3 Alkalinity ND 10.0 mg/L SM20 2320B C 07/24/07 TRM OH Alkalinity ND 10.0 mg/L SM20 2320B C 07/24/07 TRM pH 5.65 0.100 pH units SM20 4500-H B C 07119107 CLS Resistivity 0.323 0.0100 ohm-m SM19 2510A C 07/26/07 CLS Total Dissolved Solids 21400 160 mg/L SM20 2540C C 07/20/07 CLS r: • ~fi~_ SGS Ref.# 1073467005 Client Name Aurora Gas Project Name/# Aspen Injection Client Sample ID PW NWU #9 Matrix Water (Surface, Eff., Ground) All Dates/Times are Alaska Standard Time Printed Date/Time 08/14/2007 9:55 Collected Date/Time 07/19/2007 0:00 Received Date/Time 07/19/2007 9:22 Technical Director Stephen C. Ede Sample Remarks: Allowable Prep Analysis Parameter Results POL Units Method Container ID Limits Date Date Init Dissolved Metals by ICP/MS Barium 1590 30.0 ug/L EP200.8 A 07/24/07 07/31/07 MH Calcium 81100 5000 ug/L EP200.8 A 07/24/07 07/31/07 MH Iron 30700 2500 ug/L EP200.8 A 07/24/07 07/31/07 MH Magnesium 51800 500 ug/L EP200.8 A 07/24/07 07/31/07 MH Potassium 1130000 5000 ug/L EP200.8 A 07/24/07 07/31/07 MH Sodium 2810000 20000 ug/L EP200.8 A 07/24/07 07/31/07 MH Silicon 3640 2000 ug/L EP200.8 A 07124J07 07131/07 MH • _~ SGS Ref.# 1073467006 Client Name Aurora Gas Project Name/# Aspen Injection Client Sample ID PW TMC #1 Matrix Water (Surface, Eff., Ground) :7 All Dates/Times are Alaska Standard Time Printed Date/Time 08/14/2007 9:55 Collected Date/Time 07/19/2007 0:00 Received Date/Time 07/19/2007 9:22 Technical Director Stephen C. Ede Sample Remarks: Allowable Prep Analysis Parameter Results PQL Units Method Container ID Limits Date Date Init Dissolved Metals by ICP/MS Barium 1950 Calcium 49300 Iron 24500 Magnesium 75300 Potassium 1800000 Silicon 11300 Sodium 6140000 30.0 ug/L EP200.8 A 07/24/07 07/31/07 MH 5000 ug/L EP200.8 A 07/24/07 07/31/07 MH 2500 ug/L EP200.8 A 07/24/07 07/31/07 MH 500 uglL EP200.8 A 07/24/07 07/31/07 MH 20000 ug/L EP200.8 A 07/24/07 07/31/07 MH 2000 ug/L EP200.8 A 07/24/07 07/31/07 MH 50000 ugJL EP200.8 A 07124!07 07/31/07 MH • ~~ SGS Ref.# 1073467007 Client Name Aurora Gas Project Name/# Aspen Injection Client Sample ID PW TMC #2 Matrix Water (Surface, Eff., Ground) • All Dates/Times are Alaska Standard Time Printed Date/Time 08/14/2007 9:55 Collected Date/Time 07/19/2007 0:00 Received Date/Time 07/19/2007 9:22 Technical Director Stephen C. Ede Sample Remarks: Allowable Prep Analysis Parameter Results PQL Units Method Container ID Limits Date Date Init Dissolved Metals by ICP/MS Barium 532 Calcium 47600 Iron 8940 Magnesium .28400 Potassium 117000 Sodium 705000 Silicon 12100 30.0 uglL EP200.8 A 07/24/07 07131107 MH 5000 ug/L EP200.8 A 07/24/07 07/31/07 MH 2500 ug/L EP200.8 A 07/24/07 07/31/07 MH 500 ug1I, EP200.8 A 07{24107 07/31/07 MH 5000 ug/L EP200.8 A 07/24/07 07/31/07 MH 5000 ug/L EP200.8 A 07/24/07 07/31/07 MH 2000 ug/L, EP200.8 A 07/24/07 07131/07 MH r -~ SGS Ref.# 1073467008 Client Name Aurora Gas Project Name/# Aspen Injection Client Sample ID pWp Matrix Water (Surface, Eff., Ground) • All Dates/1'imes are Alaska Standard Time Printed Date/Time 0$/14/2007 9:55 Collected Date/Time 07/19/2007 0:00 Received Date/Time 07/19/2007 9:22 Technical Director Stephen C. Ede Sample Remarks: Allowable Prep Analysis Parameter Results PQL Units Metbod Container ID Limits Date Date Init Dissolved Metals by ICP/MS Barium 4360 Calcium 183000 Iron 9950 Magnesium 51100 Potassium 2490000 Silicon 7360 Sodium 5510000 3.00 ug/L EP200.8 A 08/02/07 08/08/07 TK 5000 ug/L EP200.8 A 08/02/07 08/08/07 TK 250 ug/L EP200.8 A 08/02/07 08/08/07 TK 500 uglL EP200.8 A 08{02107 08108/07 TK 50000 ug/L EP200.8 08/02/07 08/10/07 TK 200 ug/L EP200.8 A 08/02/07 08/08/07 TK 500000 ug/L EP200.8 08/02/07 08/10/07 TK CHAtN OF CUSTODY RECORD SGS,.Environmlental Selrvices Inc. cuENT: SGS Reference: ~ PAGE' l OF (-. CONTACT: PHONE NO:(o { ` a f ) 2 i. ~ _ ~ ~ a ~ t~~ Z Z ~,' C O 3 Y1. v1 /'TC~ Preservable PROJECT: ( SITE/PWSID# : N o SAMPLE TYPE used ' ~$ f ~ ~Cj'~ \ Analysis REPORTS C:~` : +'~,~ o,ZS do E-MAIL: CLiG~oJ~SQ ~ or.wt'0{2~.~lpe.F.!' C,r,: F}, FAX NO.:( ) ~~ ~ T c~ ~ Requued ~ O ~ i INVOICE TO: QUOTE # P.O. NUMBER 2 A E GRAB ~' ~, ~ ` I. ~ ~ '"~' ~V~ , P , ~ ~ Q LAB NO. /~ ,, SAMPLE IDENTIFICATION DATE TIME MATRIX R $ ~ ~ . ~~ ~ ; , REMARKS ~c.J a,~.~ ~ G . 7~ ~ X j I F~ a.. w T N1 L ~ 1,.) ~ ; , S.; Q pr,.5 -t-m c.~# 2 t~ ~ ~-s c 1 S i i 5 4 I Collected/Relinquished By:(1) /}' p 1 ~ ~„ ~.~. ~Dy Date 71~f ~~ Time ~O ~ P~`~ Received By: ' Date Time Shipping Cagier: Shipping Ticket No: '~. Samples Received fold? (Circle) YES No Temperature JC:1~7~ 6- ° v Relingtished By: (2) Date Time Received By: Date Time Special Delivera~e Requirements: Chain of Custody Seal: (Circle). INTACT BROKEN ~ ~ ABSENT 'Relinquished By: (3) Date Ti Received By: Date Time Special Instructions: i Relinquished By: (4) _ "Date eceiv y: Date 7 _ Time Requested7umaround Time ..~: ^ RUSH ~ D STD Date ceded l] 200 W Potter Drive Anchorage, AK 98518 Tel: (9W) 582-2343 Fax: (907) 561 ^ 1270 Greenbrier Street Charleston; WV 25311 Tel: (304) 346-0725 Fax: (304) 348A767 ' Nubile - Retained. by Lab -Yellow•.Returriedwith'~Remrti r~ LJ .~ SAMPLE RECEIPT FORM: Yes INo NA ~-~- {- Are samples RUSH, priority, or w/n 72 hrs f hold t~ e~ Ctilti+-ed If yes have you. done a-mail notif'' ? ~ -Are samples wrthiri 24 hrs. of old.time r due.dste? /.(f yes, -have you spoken with sor? /Archiving bottles..- `if req:, are they properly marked,? _„~ Are there any problems? PM Notified? ~ Were samples preserved correctly and pH verified? ~- , ~ ~ a ~, ./ If this is for PWS, provide PWSID. `~ Wily courier charges apply? _ _......-Method _of~payment?... _..._ -- _ .--- __._ ./ Data package required? (Level: 1 / 2 / 3 / 4 ) Notes: Is this a DoD project? (USAGE, Navy, AFCEE) Tkis section must be.filled out for DoD uroiects (USAGE, Navy. AFCEE) Yes No Is received temperature 4 +_ 2°C? Exceptions: 'Samples/Analyses Affected: Rad Screen performed? Result: Was there an airbill? .(Note # above in the right hand column) Was cooler sealed with custody seals? # /where: ' Were seal(s) intact upon arrival? Was there a COC with cooler? Was COC sealed in plastic bag & taped inside lid of cooler? Was the COC filled out properly? Did the COC indicate COE / AFCEE /Navy project? Did the COC and samples correspond? Were all sample packed to prevent breakage? Packing material: Were all samples unbroken and clearly labeled? Were all samples sealed in separate plastic bags? Were all VOCs free of headspace and/or McOH preserved? Were correct container /sample sizes submitted? Is sample condition good? Was copy of CoC, SRF, and custody seals given to PM to fax? Notes: ,~~ . ~i •1- re~_~s~-_i _ s c~: ter--~ ~; T- - ~~~ -- -1 a?347 r •~~~ II IIIIIIII~INII i~ -: sGSwo#: IN8111NIIIIIIIINIIUIIIIN Due. Date: - ~ Deceived Date: ~ ~ -~7 Received Time: .(5`12-~ Is dateltiriiie conversion necessary? # of hours to AK Local Time: Thermometer ID: 'Z1~ Cooler Ib Tem Blarik CoolerTemp ~_ ~ ~_°C ~~ °C °C °C °C ._. - " 'Tmpeie[ure readings m2lude thermofiefet" fatiC°rs Delivery method (circle all that apply): Bent / Alert Courier /-UPS / FedEx / USPS / AA Goldstreak / NAC /ERA / PenAir / Carlile Lynden /SGS /Other: Airbill # Additional Sample Remarks: (~ if applicable) Extra Sample Volume? Limited Sample Volume? Field preserved for volatiles? Field-filtered for dissolved? /Lab-filtered for dissolved? Ref Lab required? ' Foreign Soil? This section must be filled ifnroblems are found Yes No Was client notified of problems? Individual contacted: Via: Phone /Fax / Email (circle one) Date/Time: . Reason for contact: ' Change Order Required? SGS Contact: ~~ d ,~ ~~/ti~~ Completed by (sign): Login proof (checked required F004r15.doc ~- (print): performed by: Form # F004r15 6/6/: ~u SAMPLE RECE/PT FORM (page 2) ~. ~ ~ ~ , ,., .8 ~ ~~ ,;, .. ; ~ ~ , ; : Container Volume Container e - # ' Q ~ - Test V ~ ,~ ~ ~ a ~ ~ ~ ., '~ .. `~ Other c7 ~ C7 U W ^~ ~ :; •= v ;q ~ . a ~ ~ ~ ~I1 11111111 7 Preservative p U !y7HO'-! ~Oy x p 1x~ Other . ^ pyN ~ d fr .~. ~• Completed by: ~ Date: ~ ~ ~ : tTT , Foam. # F004r14 : 05%17/04.. • ~ y '~ ...:..,. RECEIVED AUG 1 0 700? f ~ -~ ,~. b t L ~ ~ w s Project Methodology fir` • Reservoir Description • The NuLook analysis dated 8/18/2005 provides a petrophysical description of the reservoir and it's properties. This includes (but not limited to) the porosity, permeability, texture, lithology and water saturation. • The NuStim process is used to create a reservoir and injection model with emphasis on the NuLook analysis. This process will utilize the NuLook processed data to determine additional geomechanical reservoir properties such as Young's modulus, Poisson's ratio and a stress profile. • In this case sonic data is also available and is used in calculating the rock properties. This data was used in order to build a calibrated geomechanical model that will enable the prediction of rock properties for other wells in the field with which sonic data was not provided. • Injection Performance and Fracture Characteristics • The NuStim model is then used to predict the characteristics of the planned injection into these intervals. The injection will be modeled to see if it is above the matrix injection rate of the zone and if so, the dimensions of the produced fracture. ..~ .,.. ,.,...- ~N ~- ~.. . . + `~~ ~Y~ ~L_'~ v .~. . w: .. _ eQca..: ~t: .hv . _ I~~~~I~ ~~I~~~i~~~~ If~~ Il l • --.~.. 3' hN~.7~ :~:, ~^4'u-- 1' 1 t _t.._ ~ ~ _ -. ~;~ -,. _ ... ~~ ,. U ~~. nit , .., ,.~ . ,r,.. _ _ c1 _ _ FF_FIaG 6 IH IB 0 6 SPSL LW FLAG 120 AN 30 0 6 FHC FlA0 0 8 NF FLAG D_-6 ^K6 F1AOc Daps o.z oHMmD -200 0.6 DEC o 0 oNMM2o 1 00 0,2 OHMMO 200 0.0 ~ DECS 0 0 OFMN120 NAN 0.2 ONMM 200 0.6 D CS 0 HMIN HMNO 0.2 OAHMM 200 PDSS NSS nnn ~.±, 5. ~~ 1 NUMATR 0.1 TE%l1M 100 0 SMALL 1 06 DEC 0 0.1 MO 1 1.6`13.5 MEDIUM PHIE 0 1 06 DEC 0 NIRERM 1000 SPECG LARGE_ _ BYI 0 1 0 6 DEC 0 VCOAL 1 DEC 0 1 S4'. 2300 3 z3oo PAYFT RANK VCLAY PH IE SW N U PERM BVtot BVhyd BVwtr BVbnd BVfree HydPorFT N UPE RM FT 8 2.1 0.120 0.220 0.609 6.282 0.220 0.086 0.134 0.134 0.000 1.759 50.257 TO T AVGX AVGX AVG X AVG X AVGX AVGX AVGX AVGX AVGX AVG X CUM CU M 2 Nu . ' Textural Vision ~~ ~/ .,, , ~ r 0 _ ~ i~ 6Fll FtAGO DES ND m!S 0.2 OHNM1 0.8 PNDEC D 0 ~O.~CD25 1 0 0 ~ 0.1 0 COY 1 1 DEC •1 0.1 ~MD At lOW 0.05 0 28 6 N3 16 -120 SMYI 30 0 F~08 Ow ~8 18/B 0.2 OHMM 2 0.8 DEC 0 0 OMMM20 1 NUMATR 0.1 TFxOM 100 0 SMALL 1 06 DEC 0 0.1 MD 1 1.5Y+3.6 1700 0.2 OHMMO ~2 0.8 ~~DECS ~ 0 OHA%120 0 MEDIUM 1 06 DEC 0 NtRERht 1000 NUSPEC< 23 C~3 0 C ~8 NA6 0.2 ONMM 2 0.8 DEC 0 NMIA HMNO 0 ~~ 1 06 DEC 0 NE FLAG D 8 AHI90 0.2 ONMM 200 PDSS PCNSS 4COAL 1 DEC 0 1 S4. NG FlAO ~ 6 _ Rri75 ___ 0.02 OHM~M 20 ~~~ 0 CLAY BNY BYI PAYFT RANK VCLAY PHIE SW NUPERM BVtot BVhyd BVwtr BVbnd BVfree HydPorFT NUPER MFT 22 2.2 0.104 0.251 0.677 11.575 0.251 0.081 0.170 0.170 0.000 5.521 254.65 TO T AVG X AVGX AV GX AV GX AVGX AVGX AVGX AVGX AVGX AVG X CUM C UM 2100 3 Nu ~ Nv' " ,...1~.. 1.,,•.- r~rw~ ~ ~ '-- -. + i - ~ , . -t--- ~ t..- { ~ , YY -- ~~ ;i !. : _ I ;. ~ J f ~ J... ~ • ' I l 1 .L..... 1 1 i xJ ..'y ._.~ ? i ,.: i ,_ _ MMM .. , - r -, ~;. ;, ,;- ,. :. r V ~ .. ii ~ ~: :;. ~ L I ~. I A • A • . ~.. ~ I I i ~ 1 r ~ ; ,'i'~ ~ _ :..'~. I f 1 1. 1. 1 I _ :. ~~ ' f ~ 1 f ~ ~, ,, ~ " ~ 1 I i I ~.i I i I I t ~ i + -I i. ~F! + i +' - + t,{ i - ,:• f r i'- i ~ ~,r~ r ,; .. j.. .:I . ,.. r a ..; ~~ .. I ;..... I I~ r 1 hY„ . _. . ~ { r ~ _.: .. ... ...,. ~ y - r II I ~ .. . , . 9 ~ ~ i i '1117. "j~. ... ' -. + _ _ .. _. _. {~ act I Dort :. ~ ~_ 1~ .. '.-,, .. .. ~. .. -, , . ,~ •, .,. .. .. _. :. ... ... . ~;: :: X -t -- .. . . r ... .. .~ ::. y ,' n . ~ f/`f D1 - iis::2:i i ~o $SI: oor~ ,~ - IIAIi rsevl nnc3ti :nl:~ ~ ~ W~103W '"'Jltf E711 N."- . Vtttvs lm oav m o ro Am 0 ura Mf ~ ~ nd3 31Nd E 091 t 9 0 - if•fi bf~ OM Ihi RdB 0 L f 0 fI1. fnl 1M 00{ ~ a • Oi0 9r, t 0 ~• 0 t IFB 30•t1 pM11 ON) CO .• O:W t10 'OCOt. _ _~!r_ .. ~0 0 O110t /•O/W ~1 - 0>D I I 0 ~.1ffM OI ~0 sOa~ ~1 0 of iK of 1T3N03df I2NNd10t _~ ~ 0.1 W Mf It'IC3M ~ r Qnl Ml 1Gf I 0 OOOC 'r 0 ~I BE OEOt CW SO' 0 030 00 I 0 •11gf•I I Ot 0' o B 0 0 Bt q tl30.OIOPJ _ _ ~- uNB ~ ~ - icG091Gi6 ... ~ 3hld s ~Tlf9 I;VtItR1 PLd ON y ... SJ .. OS ~ IfI11 0 OEOi ~IM~ G OOOL 0 E000COCS ® 0 OJ•t OW :'0 ~0 030 f'0 T 7 ~0 T 01 DYT s V 0 B OGS Id70 _ IIiA'.100 QYty N ffONIY r0- •Y~ Ytl]WIM Mlq .Y'.; ~' f7f•i710 CLL NWY.t 0'Vy-Mr 70• -~.A~'~-~II ~~1 •I•)/.1//~+)/ll'~I F~Y_ Ill!•Y_ j Geomechanical Mode/ - Interva WIN�e6, t�� 111= :Mr 11—:12MMEN 1 E gffIn Mist�� ®-®o■ m1111 ors � MEW =a 20111iin'ili'�i�11ii SOON ra rarrarara...... u...r ■ r_ r_r_r_�...... ter...■ ... Imm CC �� rarr�rara.Now ��n...r ..� a� _ �—���i�ii �aiiii it l�. � small =Fj" 11QC=in11E' 1 GROSS TOTAL IN -SITU FRAC Stage TOP DEPTH BOTTOM EFF POR- BHTP YM GRAD - Stage Name (FT) DEPTH (FT) HEIGHT NET PAY OSITY (%) (PSI) STRESS BHST (`F) (��6 PSI) PERM (MD) SW BHP (PSI) TENT (FT) (FT) (PSI) (PSIIFT) Nus. SamWaoon V.siwr 0 N N N N N N N N _ ( V. - f V - f y C j ( V, , . ~ , N , ., py }ay{ }Qa{ 8 p m }Qaj '}~ ~ Qj{ }~y{$ }Qa ~ { Q~ j } ~Q5{ $} aj( } ~ Qa { ~ ~}Q{$ ~ ~ ~ } Qa{ }Qa{ }~Q ${ }jQ{~ 1}~ ${ y ~p Qp Qa ~ ~ ~ ~ f} ~a{ {~ p{ ~ Q p f~ ~ l}j~ a~ { Y~ 0 0 W f 9 0 W N W m 0 QI W G l 0 W 0 W 1 0 0 W l0 m 0. l0 ~ ~~ . (O l7 l6 ~ W 1D ~ W E O G D W O 0 O m O b O O np O G l O ~ 0 ~ 0 0 0 N~ 0 ~ ~ 0 0 W 0 W p 0 W 0 W W 0 0 W O 0 l 0 ~ 0 W 0 W 0 0 W O 0 l U~ 0 0 p GWp 0 0 1 0 ~ Q W O O O I' ~ ~ O b ~ 0 ~ t~D n 0 0 0 N OO' 0 ~ 0 d 0 W 0 0 QY 0 W ~ ~ 0 O 01. O W. O d ~ ~_ R .-. Yy W ~ ~ ~ ~ ~ a my U W mp ~ pm W ~ ~p 0 mp b W W mN W ma t W W O C W ~ @ ~ ~ ( m 0 Ap 1 ~ m II y O VV mp O N ~ W ~ ~ ~ W V Ol N N N im 0 Q V p ~ ~ 1~ ` Q N pp (Np t O. O ~ ~n O W p ~ ~ ~ .` o - s+ ~ h +r ~ ~ l N N N N N N r N N l~ ( V N N _ fy yy 1 W m O O D .- 0 G tp EO 0 M m 0 n r 0 ~ W n m 0 0 ' m 0 ~ 9 m 9 0 d n b m m b O 0 O ND m O O NN t 0 O M~ m m O b c m a O ~ D O pp 0 O m O cN~ ~ m G O yp D O ~o yo aD a b D m O O m O m O O 0 W O O . m p ~ n A 0 0 -aU ~ 0 0 ! ~ 1~ W 0 0 1 ~ 1~ nW 0 0 O O S a? 0 O G 0~ O aP O ~~ Q O O ! ~ ~l O v { t n pp D~ n pp ~ O n ~ ~ ` n r ~o ~~ ro ~ C1 ( n n L~ mil O r yy pp m 1~l n ~~ 7~ n N nn pm n~ p ^ A r ~A ^^ ^^ rA r ~m ~ p r ~ m ~~ rr A N ~~ p NN ~ ~ 0~ { ~y ~~ ~p ~O pp D~W ~ Ny ~~ SS ~0 1(^^1( 0~0 ~~ yy ~f yy Y®W ( ~ W,n (Z p~ a mp g O_ mp O ~ O O_ O O_ ~ O_ ~ O ~ N ~ O O ~ O W O O ~ . O - Cl t O O ~ 7 Q ~ ~ N ~ O ~ O ~~D O O ~ ~ y any 0 O ~ y (W O O_ ~ ~ O O_ ' ~_ ~_ oQ V O . ~ p~ O - ~~ e - ~ ~ ~ Q O O~ ~ ~ m O N~ ~ N~ o (~l ~ ~ ~ y ' ~ ~+ i . O ~ m i t~ fm ~ {~ tl O ~ ~ ~ e pp . Q Y - ~ p V ~ ~ ~ ~ n n N ~ m ~ t . b m ~ V . N lW 0 ~ {W{pp l7 N m M ~ ~ ~ ln~ l ~ ~ ~ Q tO~I C l Q ~m p t~l ~ fW~ p mm ~® l t~f ~ pN f t7 N p ~ fn~ pN l !~ ~ n l fW~ f ~ ~ lW~l N p I p p t7 ~ 0 y ~ f~ pN l l~ ] W ~ Ym ~ ~l p . N ~Mp t7 (~ f ~ ~ d ~ I ~ l ~~ y} (~1 M ~ 0 St pp ~ t' ~y p l' [~ yp (N ~ ~{ l l7. ( 7 . d o d d d d o 0 o d d d d o 0 0 0 0 0 0 o d d d d o d 0 0 0 0 0 0 0 o. d . o 0 0 0 0 . 0. - o o ' o d.o . ~ . ~. ~ ~ ~ O Yi ~ O ~ O ~ ~ O O m m b 0 o eXn ~ 0 0 ~ i°- ~ G ~ ~ m m G O ~ G m v' O b ~ ~ O ~ °n O G 8 C S m 0 3 ~ 0 0 3i F 0 S ~ i5 ~ ~ o l G f b $ m 0 ao ~ ~ p u ~ m o ~ ' $ ~ ~n m ~ . ~~'n ~S ~ ~ ~ - C r 0 O O O ~- 0 0 0 0 O. O . O O' O ' Q ~~p W p ~mp 0 'mm- 0 N mNm ~ 9 N ~N ~ / p mN D G O M tmm ~ 0 7 mN ED pPmpl lmm~ 0 0 l ~1m7p 0 lmm~ mQm 0 0 mQ CD Q pQm ~ m p pQp OD ~Qp mQ CD G mQ p 4 ~O D ~ YI Imm ~ 0 p m Imm ~ 0 p ump UO Ipmpp pn 0 C p ~n D Y p ~0p 1p n D a0 .,m m n m 0 n n ~ m . n 'm m G m m D UD 6 EWO GW l O ~ W mWm mWm m m ~ O . .' W ~. ' ~ 4 ~ M N m~ O ~ ~ O ~ ~ ~ N ~ N ~ W ~ ~ W0~ ~ ~ py m N p ~y ~ Y f ~ ~ ~y ma O O n p O ~ 0 O ~ O t ~ ~ ~ O ~ O O ~ ~ O O p^p ~ (((~~~ 8 Q' O ~ ;;;jjj _ ~ ~ yv ~ 2$ 00 _ ~ E 4 v N O O O I Y > N V t~! , Q 4 . . ~~yy U p 4p t~ 0 W r W mm Q 0 mm 0 n N ~ ~~ ~ m r pp f0 YY 0 ~O ~~ ~ ~~yy VI ~ ~ r 0 q@~ ~ 1 W 4 p O rr W~ r r 0 r W m ~. W . e r KK ~p r O !.'. ~ bn. N y YI O ~ l. `. {Ny ~ m m p ~ m 40 ~ m Ol~ 0 0 0 o d o 0 0 o d o 0 0 0 o d o 0 0 0 0 0 0 o d o 6 d d d b o b b .. ti d~d 0 0 d d ~d o tf ~ ~ . ~ ~ 1~ N N N N N N O N N N ~ N N N ~ N m N ~~pp M mm O~ m r " ~ u N ~mp j l~ ~~ ~p O Q r t7 ~ ~p N ~ ~ ~ O m ~p ^^ W m Q Q ~ Q N rte Q ~ W '. 40 ~ ~ ~ m N N W WW 6Y T ffyy m N n m~ aa}} N N h (h W m (P~ ~~N N IV jj~ ~Qj N j M ~ N n . R ~• "s r N N N N N N N N N N N N ~ M ~- N N N m N H . N ~iC ~ ~ O ~ d ~ Q N N ~ ~ N d N N ~ ~ ~ N N N N d ~( d ] N d O O d O N d r p N d N i . b O O m Y1 ~ ~~ O ~ 6 0 ~ lV r ~ N c b tt 9 N gg ~ ~ ~- N O Q N N e~ ~ N N N ~ ~ N N N N ~ W 0 ~ ~ N ~ ~ N N N dU N (~! fV 4 In ~^ '^ N ~ Q N Q C7 ~ ~ ~ ~^ t0 N K O N N~y O V N O N b ~ O N N N ~ ~ N N ~(f N N b N N N N N N N N O~ N (7 M N V N ~ N h h ~ M N N Nmm 1~1 N h~ M Q N ~Y~yyI Q N Y ~ Q I ~Npp V N N ' H N N ~( r~ N N I rNr N A~ N N YOOl 0 N N Y m~ ` N f h ~ N ryry ~!! N r~{yy J' '.1~ OJ ~~ N N tfUUtyyV~~ N N rn ~~pp ~ N N N <<~p ~ N ~A N m® ~ N N M M N N ~~ ~~~~yy{{ ~ p N ~ 01 lW!~~ N . N 4> . W R M p? ~~y p ~. N j-v? . ~ ( N N f N N N N ( V N ~ N (V N N . p ~ y ~ y t p O y ~ p p ~ p ~ p m ^ t p x O O O S O~ O ~ N N N l~ M tNh (7 f7 ~~ Q V~ Q Y V~ r 1~ r~ UU m~ W ~~~~~ ~_r ~ A A b ~ W ~. 8: iD ' 41 f 1 ~ Q " lY Cr N N N N N N N N N N N N N N N N N N N N N N N N N t N~~ 1 V N Cl N N CI N N N N N N Cl Cl ~ Y ~ ~ N~ i V . .. .. - '. - ' ' ' ' ' '~ ' - ~ . . .. .. .. . .. F ~ _..:' a, '..'..'..'. Q ,_ I . i~~~ _e, `' -V 3~1. • 0.5 0 45 . 0 4 . 35 0 . 0 3 . 0 5 .2 0 2 . 2000 2050 2100 2150 Poison's Ratio Young's Modulus 3 2.5 2 ~ 1.5 1 0.5 0 2000 2050 2100 2150 2200 2250 2300 2350 Dspth (R) r. .. , 2200 2250 2300 2350 241 uPro Look Forward Procd, rporn an arnmeters g orl"Put .... __ ............ NNNNNNINI .. N.I.M.N." .;.;; .:: M., ... ............. .......... ............. .......... .................. ............. .......... .................. ............. .......... ............. .......... ........................ .. ........................ .. ............... ........................ .......... ... ........................ . ..... *.*,:::,::"*, 3 Incorporation of Field Parameters/Operator Input Field parameters such as historic stimulation challenges, field hydrocarbon properties, reservoir extent, tubular data, current field completion practices, and field economic parameters all factor into the completion analysis. ............ * ...... 'IT Como ...... ; ......................... ... ; ...... :;.;; ..... ......... ........ ;.' .... I ... ........... ...................................................................... ...... * ....... ...................................................................... ......... N. ............. ..................... the ge .41wr ("V for j$q... ........... ............... ................ ........ ... ..................... ............... r. t Oh -------------------------- ! -------- --- M. ..................... ......................................................... No ....... ...... ......................................................................... ... ......................... ............... ....... .......... "'.- ro-Wel-F 0OW&C.? AIIJAWO ~ ~ew~ ind u ~, ~ ~-; ~. ~~ ~ ~ ~ _. -~ ~W m ~a~ ~ la u n ~ n ~e d ~c r A M - xrn n ~ ~~r+~ ~. ~ i i ' a i r I I I l I I I ~i ~~~ i 1 ' ` ` r. ~ i i I i . i 1 I i i.. ~ r 1 . R ' ' ..J 1 , 1 , . ~. ~ ,_ n i ,: , ~ 1 i I ' - ~ ' 1 ~' 4 .. :.. I ;: I ~ .. , i i I I ;1 1 ~ r~ f ~~- ~ ~:~~ ~/ ~r r ; ~ ~r~ _ ! 1 ,. _ ~ :, i _.. _ : _ _..: _ _ _ ._ ._ _ z - ,.. ; F r- ~ ~ `x . ~ 1 I I.:. t «: L . • _ • t i i ~ ~ !. ~ I ~ I t i ... . . ~. i -.. ..r. I I 4 .: ! i L ~ i ~ ~ I ~ t F ~ I I ~ ~ _..~ , • V F .~ L~ I ~ .~.~I ~ ' I.:..: ' ~ . ~:.. ~ .. ... '.. ~n L-nEiz~kc rrL ..; .~! 1 i i p.:. ~ Fl d~ r l ' : I . ~ . i ~ 7 J ~1 .-~ ~ 1 .: . .I r- ~ ~i-' J 1 rl ~ ~:. r--' 1 ref .- ,I r r r ~r~ ~ rJ r ~ ~ ~,f / f-. t .. ~.... ~„ i,„~,,,I~. y... ,... .. .. _ i .. ~ t ti -.L txL, II ~ 1 _ _~ ~ ~ r. ..~. Pressure and Frac Dimensions for 1 bbllmin Injection Initial Injection of 10,000 bbl then Monthly Injections of 504 bbls ~~ ~ ~I ~ ~ ~ ~ ¢ E n ~. - ~ ~ ~u ~ - ... During injection pressures are approximately 1,270 psi. After one year on injection cycles the maximum fracture dimensions obtained are a top fracture depth of 2,339' and a bottom fracture depth of 2,411'. --Surface Pressure (psi) -Frac Lower Height (ft) --Frac U er Hei ht (ft) pp g Dimensions for Multiple Rate In -f 1,000 bbls at6 Week Intervals A a The three flow periods here represent mud being pumped into the well at six week intervals. The injection rates are 1, 2 and 3 bbllmin respectively. As the rate is increased the treating pressure and overall fracture height increase The maximum Surface Pressure (psi) . pressure obtained was during the 3 bpm injection at 1,641 psi. The maximum dimensions in these simulations show a fracture top depth of 2,325' and -Prat Lower Height (ft) -Prat Upper Height (ft) fracture bottom depth of 2,412'. • 1500 1000 500 N a 0 N N 4. 500 -1000 -1500 0 Pressure and Frac Dimanslons for 1 bbllmin Injection Initial Injection of 10,000 bbl then Monthly Injections of 500 bbls 72 60 48 r 36 ~~ 24 12 350 :.~ 50 100 150 200 250 300 Tim• Idaysl • • 1500 Pressure and Frac Dimensions for 1 bbllmin Injection Initial Infection of 10,000 bbl then Monthly Injections of 500 bbis ..... _ _ .__ .. , . _._ __ _. ,.._.~W_-_-___~ , The three flow periods here represent mud being pumped into the well at six week intervals. The injection rates are 1, 2 and 3 bbl/min respectively. As the rate is increased the treating pressure and overall fracture height increase. The maximum pressure obtained was during the 3 hpm injection at -- Surface Pressure (psi) 1,050 psi. The maximum dimensions in these simulations show a fracture top depth of 2,099' and fracture bottom depth of 2 220'. -Frac Lower Height (ft) -Frac Upper Height (ft) , 120 Petroph,ysicai Display with seated Fractures After Two Water Iniection Cvcies ,.. ,. n 3 , w IFN �mm�r� r,n. mnuun�nm �nrr rnv �ie;�renamnnr 21 ki ,. x-,= -- " aumss-m-tshm,ulatgn VFsron .. Page 1 of 1 Colombie, Jody J (DOA) From: Bruce D. Webb [bwebb@aurorapower.com] Sent: Friday, August 10, 2007 2:53 PM To: Davies, Stephen F (DOA) Cc: Colombie, Jody J (DOA) Subject: Aspen Disposal Injection Order (application) Steve, I will. be dropping off the Fracture Modeling, that was performed by NuTech Energy, to your office this afternoon. It is my understanding that the Plat, Affidavit of Owners, and statement regarding no applicable freshwater exemptions that I sent over on July 18, 2007 were acceptable. I further understand that Andy Clifford had sent the AOGCC the required geologic information. To the best of my knowledge, the only data lacking for the Application for disposal of Class II oilfield wastes is the water analysis and formation fluid compatibility. This information should be available to you next week. If l am forgetting something, please let me know. Thank you. -Bruce Bruce D. Webb Manager, Land and Regulatory Affairs Aurora Uas, L1:.,C 1400 W. Benson Blvd., Suite 410 Anchorage, AK 99503 'I'ele: (907) 277-1003 Fay: (907) 277-1006 Cell: 229-8398 8/21 /2007 -~.:-Aurora Gas, L C www.aurorapower.com July 18, 2007 V G~ JUL 1 ~ 2.007 John K. Norman, Chairman State of Alaska ia~a Qi~ ~ Gas ~°~s~ Commission Oil and Gas Conservation Commission Ancr~r~~~ 333 W. 7a' Avenue, Suite 100 Anchorage, AK 99501 Re: Application for Disposal of Class II Oilfield Waste by Underground Injection Beluga Formation, Cook Inlet Alaska Section 33, Township 12 North, Range 11 West, Seward Meridian Dear Mr. Norman: Pursuant to your request ,dated July 17, 2007, for the deficient information contained in our original submittal, I here by submit the following items: 1. A plat showing the location of the proposed disposal well, abandoned or other unused wells, production wells, dry holes, and an other wells within one-quarter mile. As you can see, there are no wells of any category within ahalf--mile or more of the proposed Aspen Disposal well. 2. Affadavits showing surface owners within one-quarter mile of the of the Aspen No. 1 have been notified and supplied a copy of the application for disposal. 3. There are no references to any applicable freshwater exemptions issued in accordance with 20 AAC 25.440. 4. The original application heading mistakenly listed the Tyonek Formation, instead of the Beluga Formation. The remaining deficient items; geologic information, water samples and laboratory analysis, and fracture modeling will be delivered under separate cover, as soon as they become available. Respectfully Submitted By, ~~~ ~'<:- Ci~ Bruce D. Webb Manager, Land and Regulatory Affairs attachments 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 Beluga Area ~ I ~ ~ Well Locations ~ ~ ~ ~' ~ ~•N,r~K~SB~ ~ ; ~ ~,lfiEE YILE d( 111.1 ~ ; • ¢iF11EE 14LE CK IIIIIT 11 . 35 38 31 32 I 33 ~ 34 • 35 I 38 31 32 33 ! " C ~ 1 1 T1REE MILE CK 111ff 3 ~_ ~ J 1 .. _.T..... I I 1 ~ C- ! 1 61 06 I ! ~ nIREEVtLE , ~ ! I I I , i ' ! 3 2 1 I ~ I I S ~ •-' 4 i . 1 3 2 1 8 5 1 i i I i i C-0615( 8 C-061502 i i ! i _ ~ i _ -••- - 1 - - -••-• ~ 1 ~ i • C-06 1395 , : i C-0 1394 1 i i ~ i 7 ~ 1 8 t 10 11 12 I 7 • 8 C 1 0 9 10 ! 11 12 ! 512 CIKR STI ~ i i ,: NN': 1 IANE CREB( - !S RN Sf08,951 -. .~. _. _. I _. _.C . :• ~. 1 ~.. i• ~. L g% I i i 15 14 13 ! 18 i ~ i 1 I 18 ! 1S 11 13 ~ 18 t7 26 I ~ -~ C-O6 389 1 ~_ i I 35 i 38 1 I 2 I 1 1 11 I I ~ I I 11 a ®~~~~ i .~ i C-06 393 I 23 _i i '~M ! .~ KALOAI ,,.. ,, ,,,,,, ! C-061500~~ CREEK, ._.._. .._ • ~ 1 i I I i 06139 C 1 i • ~ 1 ~ ? , ,~ i ~.._.._ ._. - i I I • I -'! i L --.~•-, ~ i . C-061453 I • 19 i - i i i 21 I 22 23 24 19 _. 1 ! I '< ~ i _ t i i • ' ~ ~ LOIBi CREEK z j 1 . 29 U•--tD•--- 1 • ~ 26 28 - 27 25 30 i i I i I ` 1 r ! i I C-0 1388 !i 1 ! - - l ' i i •sBlrco E ! I WID C-0 1387 E 710( 1 , A ! I C !I ! ' 32 ~ . ~ 33 34 35 i 38 31 ~ EYOOUA 1 i ! ~E -YOBY YII ~ M11~, ~' I ! I • EYOOUIIWKIE ~ A RESERVE 1 1~ w L i RESERVE, ~ S j i 4 3 ! 2 ~YDBL AWKI Z i `~SBiCO CMKfIM,X ! ~T I ^~ I 1 - ; ~ ~ ~ ~-e=o r3s ~ : e-o t39 1 !! I ! i . ! ~ i t ~ 7 8 I ~ 10 ! 11 9 12 I !! C ~I • i 1 I I .._.._.._ ._.._.._.._ !~ .._.. .._.._.._.._. • ! ..A TY K RESERVE B 1 T '' ! 15 I j C-06149 2 1 19 ~ ~ ~ ~ ~ ~~ i i •SBAPCO KALDA '~ - I HAB tINA 1... end N Le i Miles g CIRI SE + 0 0.5 1 2 : ! CIRI SSE 3 " i• CIRI SE/SSE Cook Inlet Region, Inc. Subsurface Horizon • :-- i ~ ~ og_units MoquewlLie O d G Unit •- ~ . NEK ST 17586 T BRK 612T06 a~aswrAwe,.eno..a ~w~.m ~ Leases ~ ~ "< ~1VONEK 5T 175872 s rw.uw.n.wvw.u. ~•w~-~~ '°""~°'" ~`p6~~~`B oa u+~+na nul Pipelines '. ~ ~^ AWers L~,a, Area-AK, nnelers 7Yg1E • AOGCC Wells List Nopuewkie O8G UNt_w81Uytl1 Beluga Area 27 26 NE Well Locations ►. .C+N TYONEK STS E' 1 THREE MILE CK UWT 4; 1 �:. .:.THREE OLE CK UNrr t �. 1 !. 35 36 31 32 33 !: 34 � a 35 1 36 31 32 33C 1 l I,. iMEE MILE CK UNR 3 .It. 1 •`• I i tl•C 0611.06.a� ! ! 4�-THREE MILE CKi T, 3 2 1 1. 6 I I 5 I -� 4 13 ! 2 1 S' C-061561 I1 C-061502 ! j. 1f ! C-061395 1.. i j.._.._..e.C-0 7394 i 10 11 12 7 .�. 8 C I' 9 10 !' 11 12 7 8 ST204UITST, L_ 1 i uRNaRlvsms,e31 '• 1 - - * Ti EK3 1 15 14 13 16 ",• i I i. 16 ! 15 14 13 '18 - 17 150 C-060r LNE CREEK, 4:1_`—� ' C-06139 ' . _. C-06145 I 1. 1 l ? s Ali I i 23�• • J •, ! ! ]9 1 1 — — j i 21 22 23 24 18 .e • '''• `� 'LONE GREEK2 �; 1 � "•'• � ' t �� ;. _ 2 26__.___ l U.__}_- `.29 ,. 1 28 27 ` 26 25 30 i' C-06 389[ C-0 1388 1 I. j -OSIMPCOE MOGA•'WKIE2KK C-0 1387 i + F 35 ,. ' 36 ! ! 41 32 ! I 33 34 ! 35 - 36 31 MOBIL Vl, y�Kl� 1 `>r' PCO E MOOUA f I i j.- ASPEN, • ,$. I 1 ! JdPDllta��1. ti EMOd1AW10E _ l' ^ ONEK RESERVE M ONEK RESERVE,QwU j 2 1 I 2 1 AWKaIE 5 ' I 1 4 3 j MOBIL AWKiI($1SIMPC0CHHTINAI i 01tGjC 1 ^s " z le&�o6 � 9" 1 oDun 2 ' l i . ... ` i •"� n.�—E'-D 139 C-0 t39 "��1 1 1• �11�° 1 ! ya 7 8 1• 9 10 ! 11 12 1;`q ._.. -- _ TY KRESERYEBl1 000 r, ' C-061452 ! 1s 11 14 1 _ 16 i 17 16 +SJMPCO KALD HAB�110.1- N Legend •,,� � s i ��,"�-' ;� _ Mlles ' CIRI SE i C-06 39 1 CIRI SSE j23'F 1: KaLOA 3 r .. CIRI SE/SSE i "t ! Cook Inlet Region, Inc. Subsurface Horizon T KAfl0At ��' LL Og ER_units Moquawkie O & G Unit ��`� n�q 2 014 sT-17 � � ; SF F a� -w ....... . u' . Leases BRK 6127105 �uceo�r�wq.ernsaawx� 1 aw�►u+ovroso uaL..wsar Beluga, Almka 12n2" Pipelines "e TYONEKST175872 � � Y �TYONE AbomEqual ,tiae-AK,r�s AOGCC Wells List Noquawlcb OaO UNt walh.ptli • C AFFIDAVIT IN SUPPORT OF THE NOTICE OF APPLICATION FOR CLASS II WASTE INJECTION ORDER Aspen No. 1 Infection Well I, Bruce D. Webb, Manager of Land and Regulatory Affairs for Aurora Gas, LLC hereby certifies that the required Notice of an Application for a Disposal Order to allow for the underground injection ofnon-hazardous Class II Oilfield waste fluids, pursuant to the Alaska Oil and Gas Conservation Commission regulations, utilizing the above referenced well, dated May 15, 2007, are true and correct, to the best of my knowledge. Further your affiant sayeth not. AURORA GAS, LLC By: `" ~ ~~ Bruce D. Webb Manager, Land and Regulatory Affairs ~ ~~ ~~4 '~ Dated IN THE UNITED STATES OF AMERICA STATE OF ALASKA ss. This certifies that on the 18th day of July, 2007, before me a notary public in and for the State of Alaska, duly commissioned and sworn, personally appeared Bruce D. Webb, to me known and known to me to be the person described in, and who executed the foregoing assignment, who then after being duly sworn according to law, acknowledged to me under oath that he executed the same freely and voluntarily for the uses and purposes therein mentioned. Witness my hand and official seal the day and year first above written. OFPIGAL SEAL STATE OF ALASKA NnTARY PU3L~C i'R'SSA F,~YSON Tres: ~`~.: ~..~--. . My Comm. exp ~'-... ~,,,.,,,, Notary Public My Commission Expires: ~ • ~. 3 ~ ~~ • • NOTICE OF APPLICATION FOR CLASS II WASTE INJECTION ORDER Aspen No. 1 Infection Well Aurora Gas, LLC has applied for a Disposal Order to allow for the underground injection ofnon-hazardous Class II Oilfield waste fluids, pursuant to the Alaska Oil and Gas Conservation Commission regulations [20 AAC 25]. The proposed well to be used for the Injection of Class II waste is located in Section 33, Township 12 North, Range 11 West, of the Seward meridian. The subject well is a suspended exploratory well located east of the Moquawkie Unit located on the west side of the Cook Inlet. The nearest well, approximately 1/2 mile south, is the Tyonek Reserve No. 1. The next nearest well, over a mile to the west, is the Simpco East Moquawkie No. 1. There are no other wells capable of production within two miles of the proposed Aspen Class II injection well. Aurora Gas, LLC is the lessee of the lands (C-061387), owned and managed by the Cook Inlet Region, Inc. (CIRI). The address of record for CIRI is: Tyonek Native Corporation 1689 C' Street Suite 219 Anchorage, AK 99501 Attn: Mr. Ted S. Kyoto Alaska Division Manager There are no other affected owners, landowners, lessees or operators within two miles of the proposed Aspen Class II injection well. A copy of the current application, dated May 15, 2007, is attached to this Notice. Dated this 18th day of July, 2007, in Anchorage, Alaska. _ __.__ ~; tiAurora Gas, LLC ' ~~~~~~~~~~ 2500 Citywest Blvd., Suite 2500 ~~~~ F'~ -- ;t~ r •° a . ~;~ Houston, Texas 77042 ~ ~''^~~~ ~5« ~" `~~~ ~ 7805 8390 0000 6099 5432 ~ ~~t- t~ ~-~ o~~tGW~~~ • ~ ______._._J..._ Tyonek Native Corporation 1689 C' Street Suite 219 Anchorage, AK 99501 , II ~ Complete items 1, 2, and 3. Also complete , _ A. Signature ~ ~I item 4 if Restricted Delivery is desired. X ^ ggent { II ^ Print your name and address on the reverse ^ Addressee { so that we can return the card to you. '1 ^ Attach this card to the back of the rnalpiece, 'I B. Received by (Printed Name) C. Date of Delivery ,{ I or on the front if space permits: I , 1. Article Addressed to: D. is delivery address different from item 1? ^ Yes Jf YES, enter delivery address below: ^ No ~ J !v ~ m. d gy I q ,~ ~ ~ $ 1 ~ f ~~'~ J it ' I ~~~~ ~ ~ ~~ 3. Se ice Type I it ~I ~~ ~ Certified Mail ^ Express Mail it ^ Registered ^ Retum Receipt for Merchandise- { ~ '- ~: ~ _ ^ Ihsured Mail ^ C.O.D. ,~ '"~I 4. Restricted Delivery? (Extra Fee) ~ y~ 1 II P. Article Number __ ___ _. _ __ --- -- ---- -- _. _ - - ~ (irartsfer from service far~en ~ 7 0 0 5 0 3 9 0 0 0 0 0. 6 0 9 9 5 4 3 2 I i I Ps Form 3811, February 2004 Domestic Return .Receipt 102595-0 2-M- 1 p • u AFFIDAVIT IN SUPPORT OF THE NOTICE OF APPLICATION FOR CLASS II WASTE INJECTION ORDER Asuen No. 1 Infection Well I, Bruce D. Webb, Manager of Land and Regulatory Affairs for Aurora Gas, LLC hereby certifies that the required Notice of an Application for a Disposal Order to allow for the underground injection of non-hazardous Class II Oilfield waste fluids, pursuant to the Alaska Oil and Gas Conservation Commission regulations, utilizing the above referenced well, dated May 15, 2007, are true and correct, to the best of my knowledge. Further your affiant sayeth not. AURORA GAS, LLC By: "" `-~ ~,rS EGG ~ ® ~ Bruce D. Webb Dated Manager, Land and Regulatory Affairs IN THE UNITED STATES OF AMERICA STATE OF ALASKA ss. This certifies that on the 18th day of July, 2007, before me a notary public in and for the State of Alaska, duly commissioned and sworn, personally appeared Bruce D. Webb, to me known and known to me to be the person described in, and who executed the foregoing assignment, who then after being duly sworn according to law, acknowledged to me under oath that he executed the same freely and voluntarily for the uses and purposes therein mentioned. Witness my hand and official seal the day and year first above written. ,..t.~~^~"""'""'"'"""" OFFICIAL SEAL STATF OF ALASKA NOTARY PUBLIC Notary Public I TR'SSda ~~ySON . ..... My Commission Expires: ~ • ~ 3 ~~~ a3...:_.._..- Comm, expves:~a+-.~°-° S MY ..,..Ana+.weeww^^'^^,,,n,u.M,v.,.,wv NOTICE OF APPLICATION FOR CLASS II WASTE INJECTION ORDER Aspen No. 1 Infection Well Aurora Gas, LLC has applied for a Disposal Order to allow for the underground injection ofnon-hazardous Class II Oilfield waste fluids, pursuant to the Alaska Oil and Gas Conservation Commission regulations [20 AAC 25]. The proposed well to be used for the Injection of Class II waste is located in Section 33, Township 12 North, Range 11 West, of the Seward meridian. The subject well is a suspended exploratory well located east of the Moquawkie Unit located on the west side of the Cook Inlet. The nearest well, approximately 1/2 mile south, is the Tyonek Reserve No. 1. The. next nearest well, over a mile to the west, is the Simpco East Moquawkie No. 1. There are no other wells capable of production within two miles of the proposed Aspen Class II injection well. Aurora Gas, LLC is the lessee of the lands (C-061387), owned and managed by the Cook Inlet Region, Inc. (GIRT). The address of record for CIRI is: Tyonek Native Corporation 1689 C' Street Suite 219 Anchorage, AK 99501 Attn: Mr. Ted S. Kyoto Alaska Division Manager There are no other affected owners, landowners, lessees or operators within two miles of the proposed Aspen Class II injection well. A copy of the current application, dated May 15, 2007, is attached to this Notice. Dated this 18th day of July, 2007, in Anchorage, Alaska. _ _ ._ __. _ s , ~:: tiAuirora Gas, LLC 2500 Citywest Blvd., Suite 2500 Houston, Texas 77042 Tyonek Native Corporation 1689 C' Street Suite 219 Anchorage, AK 99501 ~ ~~~9ff3R~~i~~ ~,~~' ~-, n. _ ~ ~• ~ I ... ~ r .. .,, ,u• ...:.. i~ ^~ Complete items 1, 2, and 3. Also complete , A. Signature ~ I II item 4 if Restricted Delivery is desired. X ^ Agent I ll ^ Print your name and address on the reverse ^ addressee ~ ~ So that we can return the card to you. I ^ Atkach this card to the back of the maitpiece; ' B, Received by (Printed Name) C. Date of Delivery ,I I I or on the front if space permits: I 1. Article Addressed to; D. Is delivery address different from item 1? ^ Yes I If YES, enter delivery address below: ^ No I 'I />fyJ~~~j ~ ~ t 3. Service Type I it a II qg~ ` i~Certified Mail ^ Express Mall ;I ^ Registered ^ Retum Receipt for Merchandise- I t ;I '> ~ O Ihsured Mail ^ C.O.D. I `II ~ 4, Restricted Delivery? (Extra Fee) ^ Yes I ~I 2. Article Number _ _ -.--_ --- - __ -- - ---- - .__. ___- '~ (Transfer from service labeq ~ 7 0 5 3 3 9 i717 0 ~ 6 0 9 9 5 4 3 2 ~ I PS Form 3811, February 2004 Domestic Retum :Receipt 7o25s5-o2-M-1.540 ~ r a. • AFFIDAVIT IN SUPPORT OF THE NOTICE OF APPLICATION FOR CLASS II WASTE INJECTION ORDER Asaen No. l Infection Well I, Bruce D. Webb, Manager of Land and Regulatory Affairs for Aurora Gas, LLC hereby certifies that the required Notice of an Application for a Disposal Order to allow for the underground injection ofnon-hazardous Class II Oilfield waste fluids, pursuant to the Alaska Oil and Gas Conservation Commission regulations, utilizing the above referenced well, dated May 15, 2007, are true and correct, to the best of my knowledge. Further your affiant sayeth not. AURORA GAS. LLC By: ~ Bruce D. Webb Manager, Land and Regulatory Affairs 1N THE UNITED STATES OF AMERICA ) ss. STATE OF ALASKA ) ~GL~/©~ Dated This certifies that on the 18th day of July, 2007, before me a notary public in and for the State of Alaska, duly commissioned and sworn, personally appeared Bruce D. Webb, to me known and known to me to be the person described in, and who executed the foregoing assignment, who then after being duly sworn according to law, acknowledged to me under oath that he executed. the same freely and voluntarily for the uses and purposes therein mentioned. Witness my hand and official seal the day and year first above written. OFFIC~At SEA STATE ©F ALASKA NOTARY PU6UC T~3~ss~ ~r1~vs®2~ ~( ..-.--- My Comm. exP..,,.N.w...we,^,...,,~~,.,,~, Notary Public My Commission Expires: ~ • ~?, .- ~{ ~ • NOTICE OF APPLICATION FOR CLASS II WASTE INJECTION ORDER Aspen No. 1 Infection Well Aurora Gas, LLC has applied for a Disposal Order to allow for the underground injection ofnon-hazardous Class II Oilfield waste fluids, pursuant to the Alaska Oil and Gas Conservation Commission regulations [20 AAC 25]. The proposed well to be used for the Injection of Class II waste is located in Section 33, Township 12 North, Range 11 West, of the Seward meridian. The subject well is a suspended exploratory well located east of the Moquawkie Unit located on the west side of the Cook Inlet. The nearest well, approximately 1 /2 mile south, is the Tyonek Reserve No. 1. The next nearest well, over a mile to the west, is the Simpco East Moquawkie No. 1. There are no other wells capable of production within two miles of the proposed Aspen Class II injection well. Aurora Gas, LLC is the lessee of the lands (C-061387), owned and managed by the Cook Inlet Region, Inc. (CIRI). The address of record for CIRI is: Tyonek Native Corporation 1689 C' Street Suite 219 Anchorage, AK 99501 Attn: Mr. Ted S. Kroto Alaska Division Manager There are no other affected owners, landowners, lessees or operators within two miles of the proposed Aspen Class II injection well. A copy of the current application, dated May 15, 2007, is attached to this Notice. Dated this 18th day of July, 2007, in Anchorage, Alaska. .Auiriora Gas, LLC ~ , -- ~~+~~~~~ 2500 Citywest Blvd., Suite 2500 ~..~ '.; G~ -°- a . Houston, Texas 77042 ®~~~ ~'~.~1t# ~~"~~~ ~" ~~~ ~ 7005 0390 OOOO 6099 5432 {~~ ~~~ t~~~,4 s~~~~1r~~ ,. ~ _ . Tyonek Native Corporation 1689 C' Street Suite 219 Anchorage, AK 99501 i~ ^` Complete items 1, 2, and 3. Aiso complete , A. Signature I II iterrt 4 if Restricted Delivery is desired. X ^ Agent I II ^ Print your name and address on the reverse ^ Addressee ~ I so that. we can return the card to you. I ^ Attach this card to the back of the rnalpiece; ~ B. Received by ('rutted Name) C. Date of Delivery I I or on the front ifs ace I P Permits: , ~ I 1. A rt i cle Addressed to: D. is delivery address different from item 1? ^ Yes I If YES, enter delivery address below: ^ No ~ ^ T ~ 1 /~ ~ . ~", !I . 1 ~f+ ~ ~ ~ f ~~ ~ + Q `I ~ ~b~ ~ ~ ~ ~~ 3. Se ice Type I ~ ilQ I A q ! ~ ~ l Certified Mail ^ Express'Matl ;I O Registered ^ Retum Receipt for Merchandise- ~ ;I ^ Ihsured Mail ^ C.O.D. ,I ''~I I 4. Restricted Delivery? (Extra Fee) p y~ I 2. Article Number _ __ --- -- ___ - ------ - _ _ _- - a i ,I (transfer from senr)ce labeq 7005 0390 a00a 6099 5432 I I I PS Form 3811, February 2004 Domestic Return Receipt 702595-o2-M-1540 ~ i • • AFFIDAVIT IN SUPPORT OF THE NOTICE OF APPLICATION FOR CLASS II WASTE INJECTION ORDER Ashen No. 1 Infection Well I, Bruce D. Webb, Manager of Land and Regulatory Affairs for Aurora Gas, LLC hereby certifies that the required Notice of an Application for a Disposal Order to allow for the underground injection ofnon-hazardous Class II Oilfield waste fluids, pursuant to the Alaska Oil and Gas Conservation Commission regulations, utilizing the above referenced well, dated May 15, 2007, are true and correct, to the best of my knowledge. Further your affiant sayeth not. AURORA GAS, LLC By: ,, Bruce D. Webb Manager, Land and Regulatory Affairs IN THE UNITED STATES OF AMERICA STATE OF ALASKA ss. 7~~7 0~ Dated This certifies that on the 17th day of July, 2007, before me a notary public in and for the State of Alaska, duly commissioned and sworn, personally appeared Bruce D. Webb, to me known and known to me to be the person described in, and who executed the foregoing assignment, who then after being duly sworn according to law, acknowledged to me under oath that he executed the same freely and voluntarily for the uses and purposes therein mentioned. Witness my hand and official seal the day and year first above written. OfFiGAt SEAL STATE OF ALASKA $ NOTARY PUBLIC T~tE55A BRYSON ,,~~gg~~ My Comm. exp~res:~.:.~.~.:.`-S~L....- y}yYY1Y1b1h~t41NWN i Notary Public My Commission Expires: ~ ~~ 3 ~~ • • NOTICE OF APPLICATION FOR CLASS II WASTE INJECTION ORDER Aspen No. 1 Infection Well Aurora Gas, LLC has applied for a Disposal Order to allow for the underground injection ofnon-hazardous Class II Oilfield waste fluids, pursuant to the Alaska Oil and Gas Conservation Commission regulations [20 AAC 25]. The proposed well to be used for the Injection of Class II waste is located in Section 33, Township 12 North, Range 11 West, of the Seward meridian. The subject well is a suspended exploratory well located east of the Moquawkie Unit located on the west side of the Cook Inlet. The nearest well, approximately 1/2 mile south, is the Tyonek Reserve No. 1. The next nearest well, over a mile to the west, is the Simpco East Moquawkie No. 1. There are no other wells capable of production within two miles of the proposed Aspen Class II injection well. Aurora Gas, LLC is the lessee of the lands (C-061387), owned and managed by the Cook Inlet Region, Inc. (CIRI). The address of record for CIRI is: Cook Inlet Region, Inc. P.O. Box 93330 2525 C Street, Suite 500 Anchorage, AK 99509-3330 Attn: Keith Sanders Senior Vice President, Land and Legal Affairs There are no other affected owners, landowners, lessees or operators within two miles of the proposed Aspen Class II injection well. A copy of the current application, dated May 15, 2007, is attached to this Notice. Dated this 17t'' day of July, 2007, in Anchorage, Alaska. tiAurora Gas, LLC 2500 Citywest Blvd., Suite 2500 Houston,.Texas 77042 Cook Inlet Region, Inc. P.O. Box 93330 2525 C Street, Suite 500 Anchorage, AK 99509-3330 ,, __ __ li ^ Complete items 1, 2, and-3. Also complete item 4 if Restricted Delivery is desired. ^ Print your name and address on the reverse so that we can return the card to you. ^ Attach this card to the back of the mailpiece or on the front if space permits. I 1. Article Addressed to: I I Z.i'Z.'~ G ~?'fit ~ . ~=U_ ~~l q 3330 '' ~ ~ 9cSd ~- 333v ~~ '~ 2, Article Number { _ ~ (Transfer from service label) L RS Form 3811, February 2004 A. Signature X ^ Agent ~ ^ Addressee ~ B. Received by (Pr/nted Name)' C. Date of Delivery J I D. Is delivery address different from item 1? ^ Yes H YES, enter delivery address below: ~_ I ^ No I V i 3. Service Type Gertifled Mall ^ Express Mall I ^ Registered ^ Return Receipt for Merchandise .~ ^ Insured Mail ^ C.O.D. ~ ~ 4. Restricted Delivery? (Extre,Fee) ^ Yeq I --- ------ __ -s -- - __ 7005 ~39~ 0017 699 5425 I I Domestic Return Receipt 102595-02-M-1540 ~E~P ~~.~'41~ $5.?~'Q '~~v~t~i ~ ~ ~ ~~ I i • ~ AFFIDAVIT IN SUPPORT OF THE NOTICE OF APPLICATION FOR CLASS II WASTE INJECTION ORDER Aspen No. 1 Infection Well I, Bruce D. Webb, Manager of Land and Regulatory Affairs for Aurora Gas, LLC hereby certifies that the required Notice of an Application for a Disposal Order to allow for the underground injection ofnon-hazardous Class II Oilfield waste fluids, pursuant to the Alaska Oil and Gas Conservation Commission regulations, utilizing the above referenced well, dated May 15, 2007, are true and correct, to the best of my knowledge. Further your affiant sayeth not. AURORA GAS, LLC By; `~~.~. 7 ~r 7 b 7 Bruce D. Webb Dated Manager, Land and Regulatory Affairs IN THE UNITED STATES OF AMERICA STATE OF ALASKA ss. This certifies that on the 17th day of July, 2007, before me a notary public in and for the State of Alaska, duly commissioned and sworn, personally appeared Bruce D. Webb, to me known and known to me to be the person described in, and who executed the foregoing assignment, who then after being duly sworn according to law, acknowledged to me under oath that he executed .the same freely and voluntarily for the uses and purposes therein mentioned. Witness my hand and official seal the day and year first above written. ~K1K„S,NM1~ OfFlClAL SEAL STATE OF ALASKA NOTARY PtJBUC 'fB,E55A BRYS®A~ My Comm. expires:.: a.~.~'..~--- I Notary Public My Commission Expires: ~ ~~ 3 ~c~ • ~ NOTICE OF APPLICATION FOR CLASS II WASTE INJECTION ORDER Aspen No. 1 Iniection Well Aurora Gas, LLC has applied for a Disposal Order to allow for the underground injection ofnon-hazardous Class II Oilfield waste fluids, pursuant to the Alaska Oil and Gas Conservation Commission regulations [20 AAC 25]. The proposed well to be used for the Injection of Class II waste is located in Section 33, Township 12 North, Range 11 West, of the Seward meridian. The subject well is a suspended exploratory well located east of the Moquawkie Unit located on the west side of the Cook Inlet. The nearest well, approximately 1/2 mile south, is the Tyonek Reserve No. 1. The next nearest well, over a mile to the west, is the Simpco East Moquawkie No. 1. There are no other wells capable of production within two miles of the proposed Aspen Class II injection well. Aurora Gas, LLC is the lessee of the lands (C-061387), owned and managed by the Cook Inlet Region, Inc. (GIRT). The address of record for CIRI is: Cook Inlet Region, Inc. P.O. Box 93330 2525 C Street, Suite 500 Anchorage, AK 99509-3330 Attn: Keith Sanders Senior Vice President, Land and Legal Affairs There are no other affected owners, landowners, lessees or operators within two miles of the proposed Aspen Class II injection well. A copy of the current application, dated May 15, 2007, is attached to this Notice. Dated this 17"' day of July, 2007, in Anchorage, Alaska. i4urora Gas, LLC 2500 Cityuiiest Blvd., Suite 2500 Houston, Texas 77042 Cook Inlet Region; Inc. P.O. Box 93330 2525 C Street, Suite 500 Anchorage, AK 99509-3330 _. , , _... ..n.~.um..._.__.~I.I~f:krii.3.!\L~~~~'~C~t7. ~\t;l i.. .,_i-.,~: ,.'~.'. ... ,1... ........ _..... .._..__ __..._.... _._. _.. _. i ^ Complete items 1, 2, and 3. Also complete , item 4 if Restricted Delivery is desired. ~ Print your Hams and address on the reverse so that we can retrJm the card to you.. ^ Attach this card to the back of the mailpiece, or on the frontJf space permits. ~ 7. Article Addressed to: ~ C-~,~ ~,U_ ~e~C ~' 3330 I ,i , ~ y - 333 `i 2., Article Number ~ .(Transfer from servke /abet) ~ RS Form 3811, February 2004 A. Signature t~~~~>I~~~~~ ~* 3 ~~;~~~~i7 ~~ ~~ $5.~~tt $5.~~~3 '~~a~1~i ~, .~ ~ . ~ a ~ ~" .~ _ r ..-~ ~`'~! ~ -. __r_._.._.,.~,.W....._-- ~ ..,...........~,.,.,.~...., ~.....ma..,_., X ^ Agent ,~ ^ Addressee 8. Received by (Printed Name) C. Date of Delivery { I D. Is delivery address different from item Y? ^ Yes ~ If YE$, enter delivery address below: ^ No ~~ I 3. Service Type ~'Certitied Mail [^ Express Mail p Registered C) Return Receipt for Merchandise ,~ m ^ Insured Mail ^ G.O.D. i 4. Restricted Delivery? (Extra, Fee) ^ Yes I ~ao5 o~9a o Domestic Return Receipt ~ 609.9 5425 ~ 102595.02-M-150.01 s • . , • • AFFIDAVIT IN SUPPORT OF THE NOTICE OF APPLICATION FOR CLASS II WASTE INJECTION ORDER Aspen No. 1 Infection Well I, Bruce D. Webb, Manager of Land and Regulatory Affairs for Aurora Gas, LLC hereby certifies that the required Notice of an Application for a Disposal Order to allow for the underground injection ofnon-hazardous Class II Oilfield waste fluids, pursuant to the Alaska Oil and Gas Conservation Commission regulations, utilizing the above referenced well, dated May 15, 2007, are true and correct, to the best of my knowledge. Further your affiant sayeth not. AURORA GAS, LLC B. a~ `1~r7c~ Y' Bruce D. Webb Dated Manager, Land and Regulatory Affairs IN THE UNITED STATES OF AMERICA STATE OF ALASKA ss. This certifies that on the 17th day of July, 2007, before me a notary public in and for the State of Alaska, duly commissioned and sworn, personally appeared Bruce D. Webb, to rr~e known and known to me to be the person described in, and. who executed the foregoing assignment, who then after being duly sworn according to law, acknowledged to me under oath that he executed the same freely and voluntarily for the uses and purposes therein mentioned. Witness my hand and official seal the day and year first above written. wm pfFiClAL SEAL STATE OF ALASKA NOTARY PUBLIC 'N`kRE55A BRYS®N My Comm. expires:~.:.~:.~. »Q~ ww t Notary Public My Commission Expires: ~ ~ ~ 3 ~~ • • NOTICE OF APPLICATION FOR CLASS II WASTE INJECTION ORDER Aspen No. 1 Infection Well Aurora Gas, LLC has applied for a Disposal Order to allow for the underground injection ofnon-hazardous Class II Oilfield waste fluids, pursuant to the Alaska Oil and Gas Conservation Commission regulations [20 AAC 25]. The proposed well to be used for the Injection of Class II waste is located in Section 33, Township 12 North, Range 11 West, of the Seward meridian. The subject well is a suspended exploratory well located east of the Moquawkie Unit located on the west side of the Cook Inlet. The nearest well, approximately 1/2 mile south, is the Tyonek Reserve No. 1. The next nearest well, over a mile to the west, is the Simpco East Moquawkie No. 1. There are no other wells capable of production within two miles of the proposed Aspen Class II injection well. Aurora Gas, LLC is the lessee of the lands (C-061387), owned and managed by the Cook Inlet Region, Inc. (CIRI). The address of record for CIRI is: Cook Inlet Region, Inc. P.O. Box 93330 2525 C Street, Suite 500 Anchorage, AK 99509-3330 Attn: Keith Sanders Senior Vice President, Land and Legal Affairs There are no other affected owners, landowners, lessees or operators within two miles of the proposed Aspen Class II injection well. A copy of the current application,~dated May 15, 2007, is attached to this Notice. Dated this 17t'' day of July, 2007, in Anchorage, Alaska. Aurora Gas, LLC 2500 Citywest Blvd., Suite 2500 Houston, Texas 77042 Cook Inlet Region, Inc. P.O. Box 93330 2525 C Street, Suite 500 Anchorage, AK 99509-3330 . m. ew„ , - g'4!~. 72'"~'Ca'.:~.,,n. ~.Ta%;R"a~'Zq' r..•d^-~~rR- -'G-,'Q .. 7T"^,;--'~;°-? T ~ 'ci^~;"'.F ~ ,.. .... _ ..... .. _... _. -...-w••..--~--. ~ _.-__--.-~ li -._ _ ^ Complete items 1, 2, and 3. Also complete item 4 if Restricted Delivery is desired. ^ Print your name and address on the reverse so that we can return the card. to you, ^ Attach this card to the back of the mailpiece or on the fron# if space permi#s. I 1. Article Addressed to: I GI ~,c ~ y- ~I 2.~ Z~ ~ ~7 ~ ~;O_ ~~C q 3330 ~~i . ~ ~ g9c~b~_ 3~33C~ A. Signature X ^ Agent ~ ^ Addressee ~ B. Received by (Printed Namef C. Date of Delivery I I D. Is delivery address different from item 1? ^ Yes If YES, enter delivery address below: ~~ I ^ No I I i I 3. Service Type 1 'Certified Matl ^ Expresso Mail O Registered ^ Return Receipt for Merchandise ,~ ^ Insured Mail ^ C.O.D. s ~ 4. Restricted Delivery? (~xtra.fee) . ^ Yes ~~ 2., Article Number _____ __ -~---- =--_s -- __ _----- (Transfer fromservlcelabe~ ~ ~ 705 17390. DO017 6099 5425 ~ I PS Form 3811, February 2004 Domestic Return Receipt tozs95-oz-M-lSao I ~..~~. ~~~~~i ~~ ~~~' ~~ `~ }} . r.~ ~~4~iEit, i~+4~? ~it~~t~,~,a :~ ,m ............. _....,....,_ -_....,. • -~ • Aurrora Gas, L C www.aurorapower.com May 15, 2007 John K. Norman, Chairman State of Alaska Oil and Gas Conservation Commission 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 Re: Application for Disposal of Class II Oilfield Waste by Underground Injection Tyonek Formation, Cook Inlet Alaska ~~r~E`vE~ Section 33, Township 12 North, Range 11 West, Seward Meri i MAY 1 ~ ZQ07 Dear Mr. Norman: Al~ske Cliff $ Gas Cons. Ca+~mssion Anoha~r~~~ In accordance with the requirements of Alaska Statute 31.05 and 20 AAC 25.252, Aurora Gas, LLC (Aurora) requests authorization of a Disposal Order to allow for the underground injection ofnon-hazardous Class II Oilfield waste fluids into the Beluga Formation in the Aspen No. 1 exploratory well, which has been requested for conversion to a Class II disposal well under separate cover. Aurora is the operator and lessee in the Cook Inlet Region Incorporated (CIRI) lease where the Aspen No. 1 well is located, as well as the surrounding leases. The Aspen No. l well is a vertical well located on CIRI lease C-061387, and was drilled to a depth of 4,485 feet in August of 2005. Aurora proposes to conduct disposal operations in the Aspen No. 1 well between 2,125 feet and 2,730 feet, measured depth (MD). There are no other oil and gas lessees within five miles of the wellbore. There are no wells within aone-half mile radius of the Aspen No. 1 well. There are no recorded domestic water supply wells within three miles of the proposed injection site. The closest known domestic water well is located at the Chuit River Lodge, three and one-half miles northwesterly in the northeast'/ Section 19, Township 12 North, Range 11 West, Seward Meridian, at a depth of approximately 50 feet. The next-nearest drinking water supply sources are located in the Village of Tyonek situated in the southeast 1/ of Section 1, Township 11 North, Range 11 West, Seward Meridian, approximately four miles to the east. These sources include Second Lake and surface water discharges. The Chuitna River runs from west to east approximately one and one-half miles to the north from the Aspen well pad. 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 • • Aurora will test the mechanical integrity of the Aspen No. 1 well in accordance with the requirements of 20 AAC 25.412. After the surface plug is drilled out, the casing will be cleaned, flushed, and pressure tested to 1500 psi for 30 minutes. After running the completion packer and tubing, the casing/tubing annulus will be pressure tested to 1500 psi for 30 minutes. Pressure on the tubing/casing annulus will be monitored each day during injection operations to ensure continued mechanical integrity of the completion. 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. The composition of the waste stream and constituent volumes will vary depending on drilling, stimulation, produced water, and maintenance activities. The average daily injection volume will vary from as little as 30 barrels per day (BPD) to as much as 1,000 BPD, at rates ranging up to a maximum of 5 barrels per minute (BPM). The daily volume will depend on the number of producing wells, drilling activity and well work conducted annually. At this proposed injection rate, the maximum surface injection pressure is estimated to be less than 1500 psi, under normal operating conditions. However, a step rate test will be performed after perforating the disposal interval to establish injection rate and pressure characteristics of the formation. The formation accepting the injection is expected to fracture as the disposal interval begins to plug with injected solids and waste. Fractures (dissaggregation of the clogged pores and rock matrix) will provide pathways to transport and assist the migration of waste fluids to the undamaged storage volume within the formation's disposal interval. The injection pump will be continually monitored by a pressure recorder and automatic shut- down controls during operations at the Aspen No. 1 well. The wellhead and annulus pressure of the well will be checked and recorded prior to and after each injection cycle. Total injection volumes will be recorded after each injection cycle and reported as specified in the AOGCC Disposal Injection Order, pursuant to 20 AC 25.432. Documentation of the reports, tests, and analysis referenced herein are attached for your review. 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 5~-~ /~'Pvrcr~ n o-~ Fo(z- J ~~^'` ~~ ~ ~ ~"` "/ C
