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Home My WebLink AboutAEO 012 AQUIFER EXEMPTION ORDER # 12 Nicolai Creek Unit 1. March 12, 2010 Aurora Gas application for an SIO Nicolai Creek Unit 2. March 17, 2010 E-mail from Thor Cutler 3. March 19, 2010 Notice of Hearing ADN and Peninsula Clamer, March 24, 2010 affidavit of publication, a-mail distribution list and bulk mailing list 4. ------------------- Water analysis AQUIFER EXEMPTION ORDER #12 • ~ 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 an Aquifer Exemption Order for portions of the Nicolai Creek Unit in Township 11 North, Range 12 West, Seward Meridian, Kenai Peninsula Borough, in conformance with 20 AAC 25.440. Docket Number: AEO-10-01 Aquifer Exemption Order No. 12 Nicolai Creek Field Nicolai Creek Unit South Undefined Gas Pool Kenai Peninsula Borough, Alaska April 16, 2010 NOTICE CLOSING DOCKET BY THE COMMISSION: The Commission has the closed the Docket in the above captioned matter. ENTERED AND EFFECTIVE at Anchorage, Alaska and this 16th day of April, 2010. BY DIRECTION OF THE COMMISSION Jo~~ J. Colombie Sn ial Assistant to the Commission • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7t" Avenue, Suite 100 Anchorage, Alaska 99501 Re: THE APPLICATION OF Aurora Gas, LLC for an Aquifer Exemption Order for portions of the Nicolai Creek Unit in Township 11 North, Range 12 West, Seward Meridian, Kenai Peninsula Borough, in conformance with 20 AAC 25.440. Docket Number: AEO-10-01 Aquifer Exemption .Order No. 12 Nicolai Creek Field Nicolai Creek Unit South Undefined Gas Pool Kenai Peninsula Borough, Alaska April 16, 2010 IT APPEARING THAT: 1. On March 16, 2010, the Alaska Oil and Gas Conservation Commission (Commission) received the application of Aurora Gas, LLC (Aurora) for an aquifer exemption order for portions of Section 29, Township 11N, Range 12W, Seward Meridian (SM), below 2000' true vertical depth (TVD) within the Nicolai Creek Unit (NCU), Kenai Peninsula Borough, Alaska. 2. The same date, the Commission requested and received additional information from Aurora. 3. On March 22, 2010 pursuant to 20 AAC 25.540, the Commission published in the Anchorage Daily News notice of opportunity for public hearing on April 15, 2010. It was also published in Peninsula Clarion on March 24, 2010. The Commission has jurisdiction in this matter under 20 AAC 25.440. 4. Aurora's proposed underground storage of "hydrocarbons which are of pipeline quality and are gases at standard temperature and pressure" is specifically excluded from federal Underground Injection Control ("UIC") regulations. 5. The Commission has authority to issue an aquifer exemption in accordance with the standards set forth in 20 AAC 25.440. 6. No protests to the application or requests for hearing were received. 7. Because Aurora's submittals and the Commission's public records provide a sufficient basis upon which to make an informed decision, the Commission determined the request could be resolved without a hearing. The public hearing was vacated on April 12, 2010. Aquifer Exemption Order Nicolai Creek Unit No. 2 April 16, 2010 FINDINGS: Operator Page 2 Aurora operates the NCU and the NCU No. 2 well (NCU 2) located on the west side of Cook Inlet, approximatelyl.6 miles west of Shirleyville Camp and 11.5 miles west-southwest of Tyonek. 2. Extent of Aquifer Exemption Area Aurora's NCU 2 well is a gas production well proposed for conversion to gas storage injection service. Data in the record supports an aquifer exemption covering an area within Township 11N, Range 12W, SM, specifically described as: Section 29: SE % SW '/ NW %; SW % SE % NW %; SW '/ NW '/ SW I/; E 'h NW '/ SW '/ ; W 'h NE 1/ SW 1/; SW '/ SW 1/ ; NW '/ SE '/ SW 3. Geology and Groundwater Hydrology The stratigraphic column on the western margin of the Cook Inlet includes clastic rocks of Quaternary through Tertiary age that lie unconformably on top of Mesozoic-aged basement rocks. Glacial, Pleistocene shallow sand and gravel deposits are locally 400' to 500' thick and contain freshwater. The underlying Beluga and Tyonek Formations (in descending stratigraphic order), consist mainly of a series of reservoir and non-reservoir fluvial-derived rocks. The Beluga Formation, approximately 1,550' thick within the affected area, is comprised of clay, siltstone, coal and sand. Individual sand beds within the Beluga Formation are generally less than 30' thick and are separated by numerous low-permeability layers, resulting in a heterogeneous sequence of rocks with very poor or no vertical connectivity or permeability. Three uppermost Tyonek sandstone strata (in descending order, Carya 2-1.1, 2- 1.2, and 2-2.1) that range in thickness from 15' to 35' are currently being drained by gas production well NCU 2. Only these three strata are proposed for use as storage reservoirs. Gas in these strata is trapped within a small, east-trending fold bounded to the west and to the east by small, north-northeast-trending faults. The Carya 2-1.1, 2-1.2, and 2-2.1 reservoir strata are separated from the overlying Beluga Formation by more than 150' of low permeability clay, siltstone, and coal that persist laterally across the area proposed for aquifer exemption. 4. Formation Water Salinity The very low water yield from NCU 2 (only 1 barrel of water was reported during the most recent year of production) precluded sampling and analysis of produced water from the proposed storage reservoirs. A produced water sample obtained during July 2007 from Beluga reservoirs in nearby well NCU 9 measured 9,820 ppm total dissolved solids (TDS). During February, 2010, a commingled Beluga and Upper Tyonek produced water sample from nearby well NCU 3 measured 1 All thicknesses presented herein are expressed as true vertical feet unless otherwise specified. Aquifer Exemption Order 1~ Nicolai Creek Unit No. 2 April 16, 2010 Page 3 3,500 ppm chlorides, equal to approximately 7,200 ppm TDS2. Other February, 2010 produced-water analyses reported by Aurora from the Beluga in NCU 9 and Upper Tyonek in NCU 1B, measured 19,000 and 18,000 ppm chlorides (39,000 and 16,400 ppm TDS3), respectively. Calculated TDS concentrations using well log data from the Beluga and Upper Tyonek reservoirs are not reliable for NCU 2 due to significant amounts of methane present at depths greater than 650' below sea level. 5. Suitability of NCU 2 Sediments as Drinking Water Aquifers Under 20 AAC 25.440 (a)(1) the Commission may grant a aquifer exemption if the aquifer "is hydrocarbon producing" or "is situated at a depth or location that makes recovery of water for drinking purposes economically or technologically impractical". The aquifer exemption requested by Aurora is supported by the following: a. the area has plentiful surface and groundwater available to a depth of approximately 450' below sea level; b. mud logs from wells drilled to date nearby NCU 2 show that hydrocarbon gas, primarily methane, frequently occur at depths greater than 650' below sea level; c. the proposed storage reservoirs produce, or have produced, commercial quantities of hydrocarbon gas; d. produced water samples suggest that the Beluga and Upper Tyonek reservoirs in the storage area have TDS concentrations between 3,000 and 10,000 ppm, or greater than 10,000 ppm; and e. at the March 17, 2010 public hearing for Storage Injection Order No. 8 regarding NCU 2, Aurora testified that the nearest drinking water wells are located at Shirleyville Camp, about 1.6 miles to the east, and are less than 100' below ground surface. According to the Alaska Department of Natural Resources' Water Rights Geographic Information System and Land Administration System Case Abstracts websites, the nearest registered surface water rights claim is for Markley's Spring, which lies about 2 miles east of the proposed storage project (ref. DNR Case File LAS 3400). There are no other surface or subsurface water rights claims recorded within 14 miles of the proposed storage operation. z The July, 2007 Beluga reservoir produced water sample from NCU 9 measured 4790 ppm chlorides and 9820 ppm TDS. Applying that same ratio (1 to 2.05) to the NCU 1B sample that measured 3500 ppm chlorides yields 7175 ppm TDS. s Conversion from chloride concentration to TDS concentration is based on the 1 to 2.05 ratio of chlorides to TDS established in footnote 1, above. Aquifer Exemption Order 1. Nicolai Creek Unit No. 2 April 16, 2010 CONCLUSIONS: Page 4 1. Those portions of freshwater aquifers occurring deeper than 2000' below sea level within NCU 2 wellbore and affected area do not currently serve as a source of drinking water. All known and foreseeable ground water consumption from the NCU vicinity is consistent with usable surface and ground water resources occurring above a depth of about 450' below sea level; 2. those portions of freshwater aquifers occurring deeper than 2000' below sea level within the NCU 2 wellbore and affected area contain hydrocarbon gases, TDS concentrations between 3,000 ppm and 10,000 ppm or exceeding 10,000 ppm, and are situated at locations and depths that make recovery of these waters for drinking water purposes economically impractical; 3. those portions of aquifers occurring deeper than 2000' below sea level within the affected area cannot reasonably be expected to serve as underground sources of drinking water; and 4. those portions of aquifers occurring in the NCU 2 storage injection strata within the affected area and deeper than 2000' below sea level qualify as exempt freshwater aquifers under 20 AAC 25.440(a)(1)(A), 20 AAC 25.440(a)(1)(B), and 20 AAC 25.440(a)(2). NOW, THEREFORE, IT IS ORDERED THAT the aquifers or portions of aquifers occurring deeper than 2000' below sea level in the following areas within T11N, R12W, SM, are exempt as provided by 20 AAC 25.440 for the purposes of gas storage injection operations: Section 29: SE '/ SW '/ NW '/o; SW '/o SE % NW '/; SW '/ NW % SW %; E % NW % SW %; W'/z NE % SW ~/; SW '/ SW'/; NW ~/ SE % SW '/ /// /// /// Aquifer Exemption Order 1~ Nicolai Creek Unit No. 2 April 16, 2010 Page 5 Note that this Order does not authorize the injection of any fluids or gas within the exemption area. Storage Injection Order No. 8 governs storage injection operations within the exemption area. DONE at Anchorage, Alaska, and dated April 16, 2010. Daniel T. Seamount, r., Commissioner, Chair Alaska Oil and Ga 1Conservation Commission Gas Con~,~on Commission / -7~~ Cathy P. Foerster, Commissioner Alaska Oil and Gas Conservation Commission 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 3].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 unti15:00 p.m. on the next day that does not fall on a weekend or state holiday. • Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Friday, April 16, 2010 2:59 PM To: (foms2@mtaonline.net); (michael.j.nelson@conocophillips.com); (Von.L.Hutchins@conocophillips.com); Alan Dennis; alaska@petrocalc.com; Anna Raff; Barbara F Fullmer; bbritch; Becky Bohrer; Bill Walker; Bowen Roberts; Brad McKim; Brady, Jerry L; Brandon Gagnon; Brandow, Cande (ASRC Energy Services); Brian Gillespie; Brian Havelock; Bruce Webb; carol smyth; caunderwood; Charles O'Donnell; Chris Gay; Cliff Posey; Crandall, Krissell; Dan Bross; daps; Daryl J. Kleppin; David Boelens; David House; David Steingreaber; 'ddonkel@cfl.rr.com'; Deborah J. Jones; doug_schultze; Elowe, Kristin; Evan Harness; eyancy; Francis S. Sommer; Fred Steece; Garland Robinson; Gary Laughlin; Gary Rogers; Gary Schultz; ghammons; Gordon Pospisil; Gorney, David L.; Gregg Nady; gspfoff; Harry Engel; Jdarlington Qarlington@gmail.com); Jeff Jones; Jeffery B. Jones Qeff.jones@alaska.gov); Jerry McCutcheon; Jim White; Jim Winegarner; Joe Nicks; John Garing; John S. Haworth; John Spain; John Tower; John W Katz; Jon Goltz; Joseph Darrigo; Julie Houle; Kari Moriarty; Kaynell Zeman; Keith Wiles; Larry Ostrovsky; Laura Silliphant; Marilyn Crockett; Mark Dalton; Mark Hanley (mark.hanley@anadarko.com); Mark Kovac; Mark P. Worcester; Marguerite kremer; 'Michael Dammeyer'; Michael Jacobs; Mike Bill; Mike Mason; Mikel Schultz; Mindy Lewis; MJ Loveland; mjnelson; mkm7200; nelson; Nick W. Glover; NSK Problem Well Supv; Patty Alfaro; Paul Decker (paul.decker@alaska.gov); PORHOLA, STAN T; Rader, Matthew W (DNR); Raj Nanvaan; Randall Kanady; Randy L. Skillern; Rob McWhorter; rob.g.dragnich@exxonmobil.com; Robert A. Province (raprovince@marathonoil.com); Robert Campbell; Roberts, Susan M.; Rudy Brueggeman; Scott Cranswick; Scott, David (LAA); Shannon Donnelly; Sharmaine Copeland; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); Sondra Stewman; Steve Lambert; Steve Moothart; Steven R. Rossberg; Suzanne Gibson; tablerk; Tamera Sheffield; Taylor, Cammy O (DNR); Temple Davidson; Teresa Imm; Terrie Hubble; Thor Cutler; Tina Grovier; Todd Durkee; Tony Hopfinger; trmjr1; Walter Featherly; Williamson, Mary J (DNR); Winslow, Paul M; 'Aaron Gluzman'; Bettis, Patricia K (DNR); 'Dale Hoffman'; Frederic Grenier; 'Gary Orr'; Jerome Eggemeyer; 'Joe Longo'; 'Lamont Frazer'; Marc Kuck; 'Mary Aschoff; Maurizio Grandi; Ostrovsky, Larry Z (DNR); P Bates; Randy Hicks; Richard Garrard; 'Sandra Lemke'; 'Scott Nash'; Talib Syed; 'Tiffany Stebbins'; 'Wayne Wooster'; 'Willem Vollenbrock'; 'William Van Dyke'; Woolf, Wendy C (DNR); Aubert, Winton G (DOA); Ballantine, Tab A (LAW); Brooks, Phoebe; Davies, Stephen F (DOA); Fisher, Samantha J (DOA); Foerster, Catherine P (DOA); Johnson, Elaine M (DOA); Laasch, Linda K (DOA); Mahnken, Christine R (DOA); Maunder, Thomas E (DOA); McIver, Bren (DOA); McMains, Stephen E (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); Schwartz, Guy L (DOA); Seamount, Dan T (DOA) Subject: SIO 8 (Nicolai Creek Field), AEO 12 (Nicolai Creek) A1025A-006 (PBU Polaris Oil Pool) Attachments: aio25A-006.pdf; sio8.pdf; aeo12.pdf Joclj%J. Colombie Special AssistanX ACaska Oil and Gas Conservation Commission 333 West ?th Avenue, Suile 100 anchorage, AK 99501 (907)793-1221 (phone) (907)276-7542 (fax) Mary Jones David McCaleb George Vaught, Jr. XTO Energy, Inc. IHS Energy Group PO Box 13557 Cartography GEPS Denver, CO 80201-3557 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 Ft. Worth, TX 76102-6298 Houston, TX 77056 Jerry Hodgden Richard Neahring Mark Wedman Hodgden Oil Company NRG Associates Halliburton 408 18th Street President 6900 Arctic Blvd. Golden, CO 80401-2433 PO Box 1655 Anchorage, AK 99502 Colorado Springs, CO 80901 Schlumberger Ciri Baker Oil Tools Drilling and Measurements Land Department 4730 Business Park Blvd., #44 2525 Gambell Street #400 PO Box 93330 Anchorage, AK 99503 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 Cliff Burglin Refuge Manager 399 West Riverview Avenue 319 Charles Street PO Box 2139 Soldotna, AK 99669-7714 Fairbanks, AK 99701 Soldotna, AK 99669-2139 Richard Wagner Bernie Karl North Slope Borough PO Box 60868 K&K Recycling Inc. PO Box 69 Fairbanks, AK 99706 PO Box 58055 Barrow, AK 99723 Fairbanks, AK 99711 ~ 4 • s Davies, Stephen F (DOA) From: Bruce D Webb [bwebb~aurorapower.com] Sent: Tuesday, March 16, 2010 2:41 PM Ta: Davies, Stephen F (DOA); Aubert, Winton G (DOA) Cc: 'Ed Jones ; 'Chad Helgeson' Subject: FW: Produced Water Samples 2-28-10 (NC3, NC1, NC9) Attachments: NCU9 Water Analysis 2007.pdf Steve, The only actual lab results that show TDS's was done in 2007 from the Nicolai Creek Unit #9 well. The water produced, sampled and tested was from the lower Tsuga perforations from 1,552' to 1,904' MD/TVD. The other salinity results were from field analysis by Baroid for the Nicolai Creek Unit #1, #3 and #9 wells, see a-mail at bottom. The Nicolai Creek Unit #2 well has really not produced any water to speak of over it's life. The water reported in the ACC reports have always been rounded up to 1 bbl, however, much of that water is likely from pipeline hydratesting, condensation and other mechanical sources, and not from the actual formation. Presently, we can put a suction on the well to get as much gas as possible out of the reservoir and not produce any water. Ed jones and Chad Helgeson will be present in tomorrow mornings hearing. We will answer any questions to the best of our ability. Regards, -Bruce From. Davies, Stephen F (DOA) [mailto:steve.davies@alaska.gov] Sent: Tuesday, March 16, 2010 11:54. AM To: Bruce D Webb Cc: Aubert, Winton G (DOA) Subject: Nicolai Creek Water Analyses Bruce, To follow up on our phone conversation of this morning, water sample analytical data are important as the Commission determines whether or not an aquifer exemption is needed for Aurora's gas storage project. For the hearing record, could Aurora please provide additional information listed below? 1. Please provide laboratory analytical reports for all water samples referenced in Aurora's application for storage injection and in Aurora's additional information submittal dated March 12, 2010. The values Aurora provided for water analyses in your submittals were stated in terms of concentrations of chloride or sodium chloride. Commission regulations specify concentrations in terms of total dissolved solids (TDS). The laboratory analytical reports for the water samples will provide the total dissolved solids measurements that AOGCC needs. 2. For each water sample, please provide a listing of all perforations open to flow when the sample was obtained. We need to know precisely which perforated intervals may have contributed to the water sample. When wells contain selective completions, it is difficult for us to tell with certainty which intervals were open during sampling. Whomever presents expert testimo~at the hearing should also be prepared discuss aquifers, calculated TDS concentrations, water sample analyses (in terms of TDS concentrations}, and intervals open during water sampling. Thank you for your help, Steve Davies AOGCC 907-793-1224 From: Chad Helgeson [mailto:chelgeson@aurorapower.com] Sent: Tuesday, March 16, 2010 9:46 AM To: 'Bruce D Webb' Cc: 'Ed Jones' Subject: F1N: Produced Water Samples 2-28-10 (NC3, NCi, NC9) Bruce, We collected the water samples and took them to Baroid for a field analysis of chlorides. We did not get laboratory analysis of the produced water from NC3, NC1 and NC9 for Chlorides last month. Attached is a lab analysis of NCU #9 water collected in 2007. Chad From: Megan Wesselman [mailto:Megan.Wesselman@HALLIBURTON.com] Sent: Tuesday, March 02, 2010 8:58 AM To: Chad Helgeson Subject: Produced Water Samples 2-28-10 (NC3, NC1, NC9) Chad - Please find the results of the samples dropped off yesterday: NC3 Produced Water 2-28-10 Wt - 8.4+ Pp9 CI - 3,500 "~ NC1 Produced Water 2-28-10 Wt - 8.5 ppg cl - 8,000 ---~ NC9 Produced Water 2-28-10 ~' ~~a~- ~~~ /Dpi :mac` Z3~~~'~'~ ~~ r~, ~ y~ * ~~ ~ ~~a ~ -~ . --`j ~, Wt - 8.7 ppg CI -19,000 ~ Thanks. J • Megan Wesselman Technical Professional Halliburton saroia 907.275.2612 mepan.wesselman(a~halliburton.com This a-mail, including any attached files, may contain confidential and privileged information for the sole use of the intended recipient. Any review, use, distribution, or disclosure by others is strictly prohibited. If you are not the intended recipient (or authorized to receive information for the intended recipient), please contact the sender by reply e-mail and delete all copies of this message. ~~ ~ Labor~ry Analysis Report 200 W. Potter Drive Anchorage, AK 99518-1605 Tel: (907) 562-2343 Fax: (907) 561-5301 Web: httpJ/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 Report Date: August 18, 2007 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, 904019045, 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 may be found on your report which will serve to further qualify the data. pQI, 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. ~} 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 i Surrogate out of control limits. Q QC parameter out of acceptance range. M A matrix effect was present. ~, 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. - I'KELII~~lIN:1'Rl' - SGS Ernironmental Services Inc. ~ 200 W Potter Ih Anch ee AK 99518-1605 t (907156~?343 f (~07) 561 5301 www us sss com • w '~~c~ ~ SGS Ref.# 1073467001 All Dates/Times are Alaska Standard Time Client Name Aurora Gas Printed Date/1'ime 08/18/2007 8:20 project NameJ# Aspen Injection r ~ ' ~ Collected Date/1'ime 07/19/2007 0:00 Client Sample ID , PW NCU #9 J, ~~^i f/~~ - 190 Received Date/1'ime 07/19/2007 9:22 Matrix Water (Surface, Eff., Ground) ~~ /z.-/c~ Technical Director Stephen C Ede Sample Remarks: Revised Report -The sample ID has been corrected per client request. Allowable Prep Analysis Parameter Results PQL Units Method Container ID Limits Date Date !nit 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!26107 07/31/07 MH Potassium 1170000 5000 ug/L EP200.8 D 07/26/07 07/31/07 MH Silicon 5360 2000 uglL 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 % SM201030E A 08/10/07 BAH Chloride 4790 100 mg/L EPA 300.0 A 07/31107 07/31!07 JDS Total Nitrate/Nitrite-N ND 0.100 mglL SM20 4500N03-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 07/31107 07/31/07 JDS Alkalinity 198 10.0 mg/L SM20 23208 C 07/24/07 TRM HG03 Alkalinity 198 10.0 mg/L SM20 23208 C 07(24/07 TRM C03 Alkalinity ND 10.0 mg/L SM20 2320E 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 = Pi2ELlilTI'~,"~I~Y _ ~G~ ~ SGS Ref.# 1073467005 Client Name Aurora Gas Project Name/# Aspen Injection Client Sample ID PW NCU #9 Matrix Water (Surface, Eff., Ground) • All Dates/Times are Alaska Standard Time Printed Date/Time 08!18/2007 8:20 Collected DatelPime 07/19/2007 0:00 Received Date/1'ime 07/19/2007 9:22 Technical Director Stephen C. Ede Sample Remarks: Revised Report -The sample ID has been corrected per client request. Allowable Prep Analysis paz.~~ Results PQL Units Method Co~ainer ID Limits Date Date !nit Dissolved Metals by ICP/MS Barium 1590 Calcium 81100 Iron 30700 Magnesium 51800 Potassium 1130000 Sodium 2810000 Silicon 3640 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 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 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 - YKE:LI~!fTNARS' - `J • Davies, Stephen F (DOA) From: Bruce D Webb (bwebb@aurorapower.com] Sent: Tuesday, March 16, 2010 2:41 PM To: Davies, Stephen F (DOA); Aubert, Winton G (DOA) Cc: 'Ed Jones'; 'Chad Helgeson' Subject: FW: Produced Water Samples 2-28-10 (NC3, NC1, NC9) Attachments: NCU9 Water Analysis 2007.pdf Steve, The only actual lab results that show TDS's was done in 2007 from the Nicolai Creek Unit #9 well. The water produced, sampled and tested was from the lower Tsuga perforations from 1,552' to 1,904' MD/TVD. The other salinity results were from field analysis by Baroid for the Nicolai Creek Unit #1, #3 and #9 wells, see a-mail at bottom. The Nicolai Creek Unit #2 well has really not produced any water to speak of over it's life. The water reported in the AOGCC reports have always been rounded up to 1 bbl, however, much of that water is likely from pipeline hydrotesting, condensation and other mechanical sources, and not from the actual formation. Presently, we can put a suction on the well to get as much gas as possible out of the reservoir and not produce any water. Ed jones and Chad Helgeson will be present in tomorrow mornings hearing. We will answer any questions to the best of our ability. Regards, -Bruce From: Davies, Stephen F (DOA) [mailto:steve.davies@alaska.gov] Sent: Tuesday, March 16, 2010 11:54 AM To: Bruce D Webb Cc: Aubert, Winton G (DOA) Subject: Nicolai Creek Water Analyses Bruce, To follow up on our phone conversation of this morning, water sample analytical data are important as the Commission determines whether or not an aquifer exemption is needed for Aurora's gas storage project. For the hearing record, could Aurora please provide additional information listed below? 1. Please provide laboratory analytical reports for all water samples referenced in Aurora's application for storage injection and in Aurora's additional information submittal dated March 12, 2010. The values Aurora provided for water analyses in your submittals were stated in terms of concentrations of chloride or sodium chloride. Commission regulations specify concentrations in terms of total dissolved solids (TDS). The laboratory analytical reports for the water samples will provide the total dissolved solids measurements that AOGCC needs. 2. For each water sample, please provide a listing of all perforations open to flow when the sample was obtained. We need to know precisely which perforated intervals may have contributed to the water sample. When wells contain selective completions, it is difficult for us to tell with certainty which intervals were open during sampling. i ~ • ~ AURORA_ MOQUAWKIE_MSN8105_123009_RUN 1 chandler Engineering Co. Model 292/2920 BTU Analyzer Test time: ~u1y08 93 10:22 Test #:3 calibration #: 8 vocation No. :8105 _ standard/Dry Analysis _ Mole% BTU* R.Den.* GPM~~ Methane 98.949 996.28 0.5481 -- Ethane 0.124 2.19 0.0013 0.0330 Propane 0.009 0.24 0.0001 0.0026 Moisture 0.000 0.00 0.0000 -- Nitrogen 0.695 0.00 0.0067 -- ( Cot ) 0.223 0.00 0.0034 -- saturated/wet Analysis Mole% BTU* R.Den.* 97.218 978.85 0.5385 0.122 2.15 0.0013 0.009 0.23 0.0001 1.750 0.88 0.0109 0.683 0.00 0.0066 0.219 0.00 0.0033 Ideal 100.00 998.7 0.5596 0.0355 * Uncorrected for compressibility at 60.0E & 14.650PSIA. ~*: liquid volume reported at 60.OF. standard/Dry Analysis saturated/wet Analysis Molar Mass = 16.208 16.239 Relative Density = 0.5605 0.5616 Compressibility Factor = 0.9980 0.9979 Gross weating value = 23457. Btu/lb 23022. Btu/lb Gross Heating value = 1000.7 Btu/CF 984.1 Btu/CF Absolute Gas Density = 42.6594 lbm/1000CF 42.7471 lbm/1000CF wobbe Index = 1314.55 unnormalized Total 98.877 past Calibrated with Calgas of 1050.7 Btu/CF 7an.04 93 02:07 C6+ past update: 7une03 08 19:37 C6+ BTU/CF 5065.8, C6+ lbm/Gal 5.64250, and C6+ Mol.wt. 92.00. AURORA MOQUAWKIE 8105 Temp: 42 Deg. F Press: 886 sample Date: 130/09 RUN 1 MSN: 8105 Page 1 • AURORA_ LONE CREEK_MSN8104_123009_RUN 1 > Chandler Engineering Co. Model 292/2920 BTU Analyzer Test time: ~u1y08 93 09:17 Calibration #: 8 Test #:5 Location No. :8104 standard/Dry Analysis _ Saturated/wet Analysis Mole% BTU R.Den.* GPM** Mole% BTU R.Den.~ Methane 98.222 988.96 0.5440 -- 96.503 971.65 0.5345 Ethane 0.186 3.28 0.0019 0.0493 0.182 3.22 0.0019 Propane 0.042 1.05 0.0006 0.0115 0.041 1.03 0.0006 Moisture 0.000 0.00 0.0000 -- 1.750 0.88 0.0109 Nitrogen 1.551 0.00 0.0150 -- 1.524 0.00 0.0147 Ideal 100.00 993.3 0.5616 0.0608 * uncorrected for compressibility at 60.0E & 14.650P5IA. **: Liquid volume reported at 60.OF. standard/Dry Analysis saturated/wet Analysis Molar Mass = 16.265 16.296 Relative Density = 0.5625 0.5636 Compressibility Factor = 0.9981 0.9980 Gross Heating value = 23247. Btu/lb 22818. Btu/lb Gross Heating value = 995.2 Btu/CF 978.8 Btu/CF Absolute Gas Density = 42.8111 lbm/1000CF 42.8961 lbm/1000CF wobbe Index = 1305.08 unnormalized Total 98.757 Last Calibrated with Calgas of 1050.7 Btu/cF ~an.04 93 02:07 C6+ Last update: 7une03 08 19:37 C6+ BTU/CF 5065.8, c6+ lbm/Gal 5.64250, and C6+ Mol.wt. 92.00. AURORA LONE CREEK 8104 Temp: 42 Deg F Press: 886# Sample Date: 12/12/09 Run Date: 12/30/09 RUN 1 MSN: 8104 Page 1 • • AURORA_ MOQUAWKIE_MSN8105_123009_RUN 2 Chandler Engineering Co. Model 292/2920 BTU Analyzer Test time: ~u1y08 93 10:38 Calibr ation #: 8 Test #:4 Locati on No. :8105 T s tandard/D ry Analysis _ Saturated/wet Analysis Mole% BTU* R.Den.* GPM** Mole% BTU* R.Den.* Methane 98.960 996.40 0.5481 -- 97.229 978.96 0.5385 Ethane 0.123 2.17 0.0013 0.0326 0.121 2.13 0.0013 Propane 0.009 0.21 0.0001 0.0023 0.008 0.21 0.0001 Moisture 0.000 0.00 0.0000 -- 1.750 0.88 0.0109 Nitrogen 0.689 0.00 0.0067 -- 0.677 0.00 0.0065 ( Cot ) 0.219 0.00 0.0033 -- 0.215 0.00 0.0033 Ideal 100.00 998.8 0.5595 0.0350 * uncorrected for compressibility at 60.0E & 14.650PSIA. **: Liquid volume reported at 60.OF. standard/Dry Analysis Saturated/wet Analysis Molar Mass = 16.205 16.237 Relative Density = 0.5604 0.5616 Compressibility Factor = 0.9980 0.9979 Gross Heating value = 23462. Btu/lb 23027. Btu/lb Gross Heating value = 1000.7 Btu/CF 984.2 Btu/CF Absolute Gas Density = 42.6539 lbm/1000CF 42.7417 lbm/1000CF wobbe Index = 1314.74 unnormalized Total 98.267 past Calibrated with Calgas of 1050.7 Btu/cF ]an.04 93 02:07 c6+ past update: ~une03 08 19:37 C6+ BTU/CF 5065.8, C6+ lbm/Gal 5.64250, and C6+ Mol.wt. 92.00. AURORA MOQUAWKIE 8105 Temp: 42 Deg. F Press: 886 sample Date: 130/09 RUN 2 MSN: 8105 Page 1 • ~ AURORA_ NIKOLAI CREEK_MSN8103_123009_RUN 2 Chandler Engineering Co. Model 292/2920 BTU Analyzer Test time: ]u1y08 93 09:00 Test #:8130 calibration #: 8 rotation No. :8103 Standard/Dry Analysis ~ saturated/wet Analysis Mole% BTU* R.Den.* GPM** Mole% BTU* R.Den.* Methane 98.605 992.82 0.5462 -- 96.880 975.45 0.5366 Ethane 0.066 1.16 0.0007 0.0175 0.065 1.14 0.0007 Moisture 0.000 0.00 0.0000 -- 1.750 0.88 0.0109 Nitrogen 0.931 0.00 0.0090 -- 0.915 0.00 0.0088 ( C02 ) 0.399 0.00 0.0061 -- 0.392 0.00 0.0060 Ideal 100.00 994.0 0.5619 0.0175 * Uncorrected for compressibility at 60.0E & 14.650P5IA. **: liquid volume reported at 60.OF. Standard/Dry Analysis saturated/wet Analysis Molar Mass = 16.274 16.305 Relative Density = 0.5628 0.5639 Compressibility Factor = 0.9980 0.9979 Gross Heating value = 23251. Btu/lb 22822. Btu/lb Gross Heating value = 995.9 Btu/CF 979.5 Btu/CF Absolute Gas Density = 42.8347 lbm/1000CF 42.9193 lbm/1000CF wobbe Index = 1305.65 unnormalized Total 98.452 past Calibrated with Calgas of 1050.7 Btu/CF ]an.04 93 02:07 C6+ past update: ]une03 08 19:37 C6+ BTU/CF 5065.8, C6+ lbm/Gal 5.64250, and C6+ Mol.wt. 92.00. AURORA NIKOLA CREEK 8103 Temp: 44 peg F Press: 894# Sample Date: 12/11/09 Run Date: 12/30/09 RUN 2 MSN: 8103 Page 1 • • AURORA_ LONE CREEK_MSN8104_123009_RUN 2 chandler En ineering co. Model 292/2920 BTU Analyzer Test time: ]u1y08 93 09:38 Calibration #: 8 Test #:6 Location No. :8104 _ Standard/Dry Analys is _ Saturated/wet Analysis Mole% BTU* R.Den.* GPM** Mole% BTU* R.Den.* Methane 98.235 989.09 0.5441 -- 96.516 971.79 0.5346 Ethane 0.182 3.21 0.0019 0.0484 0.179 3.16 0.0019 Propane 0.043 1.09 0.0007 0.0119 0.043 1.07 0.0006 Moisture 0.000 0.00 0.0000 -- 1.750 0.88 0.0109 Nitrogen 1.539 0.00 0.0149 -- 1.512 0.00 0.0146 Ideal 100.00 993.4 0.5616 0.0603 * uncorrected for compressibility at 60.0E & 14.650PSIA. **: Liquid volume reported at 60.OF. standard/Dry Analysis saturated/wet Analysis Molar Mass = 16.264 16.295 Relative Density - 0.5624 0.5635 Compressibility Factor = 0.9981 0.9980 Gross Heating value = 23251. Btu/lb 22822. Btu/lb Gross Heating value = 995.3 Btu/CF 978.9 Btu/CF Absolute Gas Density = 42.8073 lbm/1000cF 42.8924 lbm/1000CF wobbe Index = 1305.29 Unnormalized Total 98.364 Last calibrated with Calgas of 1050.7 Btu/CF 7an.04 93 02:07 C6+ Last update: ~une03 08 19:37 C6+ BTU/CF 5065.8, c6+ lbm/Gal 5.64250, and C6+ Mol.wt. 92.00. AURORA LONE CREEK 8104 Temp: 42 Deg F Press: 886# Sample Date: 12/12/09 Run Date: 12/30/09 RUN 2 MSN: 8104 Page 1 • • AURORA_ NIKOLAI CREEIC_MSN8103_123009_RUN 1 Chandler Engineering Co. Model 292/2920 BTU Analyzer Test time: ]u1y08 93 08:44 Test #:8129 Calibration #: 8 Location No. :8103 _ standard/Dry Analysis _ saturated/wet Analysis Mole% BTU R.Den.* GPM*~ Mole% BTU* R.Den.* Methane 98.583 992.59 0.5460 -- 96.858 975.23 0.5365 Ethane 0.066 1.17 0.0007 0.0176 0.065 1.15 0.0007 Moisture 0.000 0.00 0.0000 -- 1.750 0.88 0.0109 Nitrogen 0.951 0.00 0.0092 -- 0.934 0.00 0.0090 ( C02 ) 0.400 0.00 0.0061 -- 0.393 0.00 0.0060 Ideal 100.00 993.8 0.5620 0.0176 uncorrected for compressibility at 60.0E b 14.650PSIA. *~: Liquid volume reported at 60.OF. standard/Dry Analysis saturated/wet Analysis Molar Mass = 16.277 16.307 Relative Density = 0.5629 0.5640 Compressibility Factor = 0.9980 0.9979 Gross Heating value = 23241. Btu/lb 22813. Btu/lb Gross Heating value = 995.7 Btu/CF 979.3 Btu/CF Absolute Gas Density = 42.8423 lbm/1000CF 42.9269 lbm/1000CF wobbe Index = 1305.26 Unnormalized Total 99.000 Last Calibrated with Calgas of 1050.7 Btu/CF ]an.04 93 02:07 C6+ Last update: ]une03 08 19:37 C6+ BTU/CF 5065.8, C6+ lbm/Gal 5.64250, and C6+ Mol.wt. 92.00. 292: Standard/Dry Analysis 292: Up/Down to view data.. AURORA NIKOLA CREEK 8103 Temp: 44 Deg F Press: 894# Sample Date: 12/11/09 Run Date: 12/30/09 RUN 1 MSN: 8103 Page 1 Aurora Gas, ttC Emergency Action Plan Scope: Alaska Cook Inlet Operations Revision Date: March 1, 2010 Issue Date: October 10, 2005 Next Review Date: Janu 1, 2011 Table of Contents 1.0 FIRST 10 MINUTES OF AN EMERGENCY ................................................. 2 2.0 MEDICAL ILLNESS OR INJURY .................................................................. 2 3.0 FATALITY ....................................................................................................... 3 4.0 FIRE /EXPLOSION ......................................................................................... 3 5.0 GAS /VAPOR RELEASE ............................................................................... 4 6.0 HAZARDOUS MATERIAL SPILL OR RELEASE ........................................ 4 7.0 EARTHQUAKE ............................................................................................... 5 8.0 SABATOGE /TERRORISM ........................................................................... 6 9.0 VOLCANO .......................................................................................................6 APPENDIX A EMERGENCY CONTACT INFORMATION APPENDIX B HSE FIELD GUIDE REFERENCE APPENDIX C AURORA WELL /FACILITY LOCATIONS (COORDINATES) Print Date: 3/1/2010 Emergency Action Plan Page 1 of 8 • • Aurora Gas, LLC This emergency action plan gives guidelines for a multitude of incidents. These procedures should be followed but must be considered on a case-by-case basis in order to satisfy the main goal, which is the protection of human life. 1.0 FIRST 10 MINUTES OF AN EMERGENCY The following are general guidelines of actions to be taken during the first 10 minutes of an emergency: 1.1 Personnel take defensive actions to isolate the problem and/or evacuate, as appropriate. 1.2 Discovery and reporting of the incident. Refer to the attached (Appendix A) for contact information in the case of any and all emergencies. 1.3 Activate the Aurora Emergency Action Plan. Tasks include: 1.3.1 Gather information on the type /nature of the incident. 1.3.2 Evacuate as required. 1.3.3 Assure that headcounts are taken. 1.3.4 The first responding Aurora person will be the responsible charge until. turned over to the emergency responders or management personnel. Primary tasks include: ^ Isolate the azea and deny entry to all non-essential personnel. ^ Establish an on-scene Meeting Place. ^ Gather information from Construction /Operations /Drilling personnel. ^ Perform a headcount when applicable. ^ Devise a response strategy. DANGER: Only those individuals directly involved in the emergency response effort, properly trained, wearing the proper level of personal protective clothing, and working in pairs shall be allowed access into the hazard area. All on-scene personnel work under the authority of the Aurora Employee in charge. 2.0 MEDICAL ILLNESS OR INJURY 2.1 Any serious or life threatening illness or injury must be immediately reported to emergency personnel (see Appendix A). Then promptly notify the supervisor or Aurora Management. 2.2 Any trained first responder may treat minor injuries requiring only on-site treatment. Incident must be reported to shift supervisor and necessary reports completed. This category does not include serious, life threatening, or illness due to hazardous materials. 2.3 Immediate Actions- Serious injuries or illnesses 2.3.1 The observer of incident will, if safe, protect and render assistance to injured or sick. Take appropriate action to make azea safe and secure. 2.3.2 Notify appropriate emergency personnel about location, identification, hazards and condition of the victim and action taken. (see Appendix A) 2.3.3 If trained assist victim with first aid. 2.3.4 Aurora Supervisor or Operator on the scene will assume responsibility and direct emergency treatment of victim. 2.3.5 Further reporting actions to Aurora Management should be conducted as soon as the situation permits. Print Date: 3/1/2010 Emergency Action Plan Page 2 of 8 • Aurora Gas, LLC Note: An accident investigation may be required, thus the accident area may not be disturbed until investigation is complete. 3.0 FATALITY 3.1 It is very important not to assume a person(s) death. A licensed medical doctor, EMT, Paramedic or Alaska State Trooper, must do pronouncement of death. This will generally not occur until the victim has been transported to a hospital. Basic life support treatment will be administered and continued until such appropriate pronouncement or certification of death is made. 3.2 If there is any suspicion of contagious disease or exposure to hazardous material, adequate precautions must be taken to isolate the area and remove other personnel from further contact. Identify others who have or may have been contaminated and require that they isolate themselves until help has arrived. 3.3 If a death has occurred, make sure the site is left alone, because an investigation will be necessary. 3.4 Immediate Actions 3.4.1 Observer of incident will protect himself or herself, and to assist victim on the basis that death is not presumed. Take action to secure area and reduce hazards in area. 3.4.2 Notify appropriate emergency personnel about location, identification, hazards, condition of the victim and action taken. (see Appendix A) 3.4.3 Aurora Supervisor or Operator on the scene will assume responsibility and direct emergency treatment of victim. 3.4.5 When conditions permit, basic life support is to be preformed until help arrives. 3.5 Secondary Action 3.5.1 Secure the area and equipment. Take precaution not to disturb the area. If unavoidable, take careful note of status prior to disturbance (e.g. valves open/closed, number of turns; etc.). Take photographs of area where and when possible. 3.5.2 Further reporting actions to Aurora Management should be conducted as soon as the situation permits. 3.5.3 Aurora Supervisor will commence preliminary investigation. in the death(s) and prepare for visits from external investigators. 4.0 FIRE /EXPLOSION 4.1 In the case of a fire/ explosion at an Aurora Facility, actions should be designed to protect human life and to control the emergency as rapidly as possible. All steps should be considered, however the sequence could be altered for circumstances on a case-by-case basis to accomplish safe and controlled emergency response. 4.2 Immediate action 4.2.1 Determine if any human safety concerns exist. These concerns include injured, missing, or unaccounted persons. 4.2.2 Determine the type of fire and the best method to control the fire with the equipment and personnel available. Print Date: 3/1/2010 >;mergency Action Plan Page 3 of 8 • • tiAurora Gas, LLC 4.2.3 If the incident is beyond the capacity of equipment and personnel available, the following procedures pertain.. 4.3 Initial Response 4.3.1 1f safely accessible, initiate the Emergency Shutdown (ESD) button on convex or at the edge of pad. 4.3.2 Notify local fire department and provide information regarding size and location of fire. 4.3.3 If safe to isolate fuel source, direct personnel to do so. 4.3.4 If properly trained and properly equipped personnel should help to fight fire, direct them to use appropriate fire extinguishing equipment. 4.4 Incident Command Transfer 4.4.1 Upon arrival of fire department, Aurora supervisor or Operator will introduce himself or herself to the arriving officer(s) and transfer command to fire department. 4.4.2 Aurora Supervisor is required to provide updated information to size, location, current action taken and injury to Aurora Management. 5.0 GAS /VAPOR RELEASE 5.1 In the event of a gas or vapor release at an Aurora unit, actions should be taken to protect human life and to gain control of the situation as quickly as possible. All steps listed should be considered, but may be altered to fit individual circumstances. 5.2 Immediate Action 5.2.1 Eliminate all ignition sources, including vehicles, and any hot work. 5.2.2 Attempt to safely control the source of release. 5.2.3 Restrict access to area until vapor cloud has reached a safe level. 5.2.4 Notify Aurora Supervisor of size, source and material released. 5.2.5 Gas release inside facility buildings will automatically initiate the ESD as necessary. 5.2.6 Aurora Supervisor or Operator will assume role of responsible charge when others are present on pad, unless it is turned over to emergency responders. 5.3 Secondary Action 5.3.1 Aurora Supervisor is required to provide updated information to size, location, current action taken and injury to Aurora Management. 6.0 HAZARDOUS MATERIAL SPILL OR RELEASE 6.1 A hazardous material spill includes any element or compound, which can be classified as a danger to health, safety or the environment. 6.2 Recoenition of material Identify the substance involved and it's characteristics. These characteristics include: ^ Flammability ^ Toxicity Print Date: 3/1/2010 Emergency Action Plan Page 4 of 8 ^ Asphyxiant ^ Reactivity ^ Sources of information include: a. Material Safety Data Sheets b. DOT labeling and place carding c. NFPA and HMIS labeling • Aurora Gas, LLC 6.3 Evaluation Using information from the recognition stage, develop a plan for safe mitigation of the incident. Be sure to consider: ^ Weather conditions ^ Incident stability ^ Skill level of personnel ^ Degree of hazard ^ Rate of release ^ Air monitoring results 6.4 Control Control the event by eliminating the source or reducing the impact of the hazard. This may include: ^ Stopping the release ^ Containment of material ^ Clean up of material 6.5 Immediate Actions 6.5.1 Approach incident from upwind and upgrade direction. 6.5.2 Warn others of incident and notify Aurora Supervisor. 6.5.3 Initiate the ESD as necessary. 6.5.4 Do not enter the effected area without proper PPE and training. 6.5.5 Attempt to identify the material, volume and source of material being released. 6.5.6 Aurora Supervisor to establish initial action plan and safe zones. 6.5.7 Clean up and mitigation should be done if the proper equipment and personnel are available. If necessary notify emergency responders and spill clean up teams. 6.5.8 Reporting of spills and hazards to ADEC and EPA is required in some situations. Refer to the Aurora HSE Incident Reporting Procedure for detailed instructions. Reporting is to be conducted by Aurora Management only. 7.0 EARTHQUAKE 7.1 The Aurora facility is in an earthquake zone, where there are earthquakes of many different magnitudes, including severe. It is possible that a sever earthquake could cause damage and injury, which could interrupt operations for a significant period of time. Earthquakes occur without warning and thus recommended actions should save human life, mitigate damage to property and the environment. Although Tsunami's are reportedly not likely in the Cook Inlet region, employees that are in low elevation areas such as Shirleyville, should be prepared to respond in the unlikely event that a Tsunami is reported following a major earthquake. Print Date: 3/1/2010 Emergency Action Plan Page 5 of 8 • • Aurora Gas, LLC 7.2 Immediate Actions 7.2.1 In the event of an earthquake the Aurora Supervisor or Operator will evaluate the earthquake size and if he/she suspects the loss of integrity, actions should first be taken to protect life then shut down the facility. 7.2.2 Account for all personnel. 7.2.3 First responding Aurora personnel will secure systems, with the exception of those systems required for firefighting and life safety. 7.2.4 Aurora Supervisor will notify Aurora Management of situation. 7.2.5 In the event of a threat to personnel, those not required for securing of the unit shall be evacuated. In the event of a fire or vapor release, the proper section of this plan should be initiated. 7.3 Secondary Actions 7.3.1 When the quake has subsided, and if conditions permit, conduct a thorough examination of the location. The main focus of examination is not for brining production back on line, but to check for possible fire/explosion sources, leaks, structural integrity and personnel hazards. 7.3.2 The unit should not be put back online until a thorough examination, approval from the Operations Supervisor or Operator and the consideration of possible aftershocks. 7.3.3 After a major earthquake, employees will need to establish radio communication in order to receive warnings and reports from local authorities. Employees at low elevation areas will want to be especially aware of any Tsunami warnings that may follow a major earthquake. 8.0 SABATOGE /TERRORISM 8.1 The main priorities in the event of any threat or incident are to comply with the immediate wishes of any persons who are armed or threatening any personnel. After incident or threat, immediate attention must be given to safeguarding life and reporting details to the proper authorities. 8.2 Safe guarding life is most likely going to involve moving personnel to a safe area. If a bomb has been placed or the threat of a bomb, the area must be searched and a all clear given by authorities before personnel can return. 8.3 The Alaska State Troopers are responsible for the detailed response to any threat. They will utilize the area and other response agencies as they see fit. 8.4 This procedure is designed to provide the proper instruction to the individuals who will be involved in the response to a bomb threat. There are specific instructions to individuals and general guidelines for bomb threat search procedures. 8.5 Immediate Actions 8.5.1 Keep the caller on the line as long as possible. Ask the caller to repeat the message. Record, if possible every word spoken by the caller. Use the Threat Checklist. 8.5.2 If the caller does not indicate the locations of the bomb(s) or the time of detonation, the person receiving the call should request this information. 8.5.3 It is advisable to inform the caller that the facility is occupied and a bomb detonation could result in injury or death to innocent people. 8.5.4 Pay attention to sounds or background noise from the caller. Try to write down as many things as possible about the caller. Print Aate: 3/1/2010 Emergency Action Plan Page 6 of 8 • • -Aurora Gas, LLC 8.5.5 If possible, have another person contact the Alaska State Troopers and request a line trace. 8.5.6 DO not discuss the call with others. Report directly to a supervisor. 8.5.7 Notify the Aurora supervisor, as he/she will become the incident commander. 8.5.8 The Aurora Supervisor will coordinate along with the Alaska State Troopers an appropriate plan of action. 8.5.9 If necessary evacuate facility. 8.6 Secondary Actions 8.6.1 Consider isolation of systems to the maximum extent possible to ensure the greatest reliability in the event of damage. 8.6.2 If there are armed persons in control of the facility, concede as necessary to avoid violence. Do not resist. 8.6.3 Carefully explain to terrorist each routine action normally done for the safety of the facility. This should be done so that routine actions do not cause a misunderstanding. 8.7 Bomb Search procedures 8.7.1 The Aurora Supervisor or Management shall assist the Alaska State Troopers in developing a specific bomb threat search procedure. The critical elements in the procedure are: 1. A search team shall be pre-designated. All facilities shall be segmented. 2. All search personnel shall be trained on the appropriate search methods. 3. Remove all unnecessary personnel to safe areas. 4. Inform search party of where a blast could cause the most damage. 5. Ensure emergency equipment is in working order. 6. If a bomb or suspicious device is found: ^ DO NOT DISTURB the device ^ Clear and mark the location for Alaska State Troopers ^ Note the device and its qualities (e.g. is it in a box? Color of box? Etc.) ^ Notify incident commander 7. Incident commander will utilize existing evacuation plan, but it will be cleared by Alaska State Troopers before put into action. 9.0 VOLCANO 9.1 The Aurora facilities are in an volcano zone of potential impact from ash in nearby Volcanoes (Redoubt, Spurr, Augustine). It is possible that an eruption from any of these volcanoes could interrupt operations for a significant period of time. Ash fall may occur with little warning and therefore the following recommended actions should save human health and mitigate damage to property. 9.2 Immediate Actions 9.2.1 In the event of a volcanic eruption the Aurora Supervisor or Operator will evaluate the impact from ashfall. If he/she suspects it may have significant ash fall, actions should first be taken to protect life then protect equipment. 9.2.2 Air filters, breathing masks, goggles, water are all stored at the Moquawkie office and Shirleyville Camp. 9.2.3 Aurora Supervisor will notify Aurora Management of situation and planned actions to protect equipment. Print Date: 3/1/2010 Emergency Action Plan Page 7 of 8 • • :Aurora Gas, LLC 9.3 Secondary Actions 9.3.1 When the ash fall has stopped, and if conditions permit, conduct a thorough examination of the equipment before bringing back online. Personnel should be looking for ash in buildings, heaters, air intake on engines, etc. Revision Log Revision Date Authority Custodian Revision Details October 14, 2005 Ed Jones Ed Jones Initial Procedure February 1, 2009 Chad Helgeson Chad Helgeson Volcano Addition March 1, 2010 Chad Helgeson Chad Helgeson Review Print Date: 3/1/2010 Emergency Action Plan Page 8 of 8 Appendix A Emergency Contact Information DIAL 911 FOR ANY MEDICAL EMERGENCY NIKISKI FIRE DEPT (TRUCKS, FIREFIGHTERS, ETT's AT BELUGA RIVER): ^ (907)-776-8400 ^ At CONOCOPHILLIPS BELUGA RIVER UNIT: (907)-263-3910 OR (907)-263- 3930 (cell) VILLAGE OF TYONEK EMT: ^ (907)-583-2461 VILLAGE OF TYONEK FIRE DEPT: ^ (907)-583-2271 (PETER MERRYMAN) GRANITE POINT TANK FARM ETT: ^ 907-776-6610 PROVIDENCE HOSPITAL AIR AMBULANCE: ^ (907)-261-3070 OR 1-800-478-5433 PROVIDENCE EMERGENCY ROOM: ^ (907)-261-3111 ALASKA REGIONAL HOSPITAL LIFEFLIGHT AIR AMBULANCE: ^ 1-800-478-9111 AK REGIONAL EMERGENCY ROOM: ^ (907)-264-1222 OR 276-1131 SOLDOTNA CENTRAL PENINSULA HOSPITAL EMERGENCY ROOM: ^ 907-262-8123 OR -4404 U.S. COAST GUARD: ^ *24 FROM CELL PHONE OR 1-800-478-5555 ERA HELICOPTERS: ^ 907-776-8215 (OSK DOCK, NIKISKI) ^ 248-4422 (ANCHORAGE) CLOSEST HELIPAD: UNOCAL GRANITE POINT TANK FARMCOORDINATES: ^ 61 DEG 01.10 MIN N, 151 DEG 25.25 MIN W CLOSEST LIGHTED AIRSTRIPS: NATIVE VILLAGE OF TYONEK COORDINATES: ^ 61 DEG 4.00 MIN N, 151 DEG 8.00 MIN W CONOCO-PHILLIPS BELUGA RIVER FIELD AIRSTRIP COORDINATES: ^ 61 DEG 10.25 MIN N, 151 DEG 2.28 MIN W KENAI AVIATION: 907-283-4124 SPERNAK AIRWAYS (ANCHORAGE): 272-9475 GREAT NORTHERN AIR (ANCHORAGE): 243-1968 REDISKE AIR (NIKISKI) (907) 776-8985 Appendix A -Emergency Action Plan ~Aur~ra Gas, ttC HSE Incident Field Guide Priority 1: Safety of Personnel Priority 2: Protection of the Environment Priority 3: Protection of Facilities Imo- ENVIRONMENT Iniurv or Illness Abnormal Condition or Disorder A Bum, Cut, Fracture, Sprain, Amputation, Skin Disease, Poisoning, or Respiratory Disorder Don't Move an Injured Person Unless Absolutely Call for Assistance if Emergency Medical Attention Is Necessary Administer Any First Aid ,You Are Trained to Provide Repo Vehicle Accident Any Accident Where Injury or Damage Occurs Keep the Accident from Getting Worse, Use Hazard Lights and Other Temporary Warning ~- Report Immediately Report Any HSE Incident or Near Miss to: ~ Ed Jones (713) 977-5799 Houston (907) 277-1003 Anchorage (713) 899-8103 Mobile jejones~aurorapower.com Fire or Explosion Any Occurrence of Fire or Explosion Your Safety Comes First, be Aware of Smoke and Noxious Fumes _- Notify Fire Department Attempt to Safely Control the Release Source i.e. Shut-in Well and Pipeline Report Regort the Following: Type of Incident Location Injuries Potential Injuries Release size Source Material Released Possible Hazards Attempt to Safely Control the Release Source i.e. Close Any Accessible Valves Evacuate Area of Release. Report Gas Release An Uncontrolled Release of Gas from the Facility that Is Not Planned or Part of Normal Operations Shutdown All Ignition Sources Any Unplanned Loss of Material from Primary Containment i.e.: Oil, Chemicals, Produced water, Domestic Wastewater, Hazardous Substances, Glycol, Methanol, or Drilling Mud Evaluate Safety, be Aware of Exposure Isolate the Source of the Spill Prevent the Spilled Material from Spreading Report it Initiate Cleanup Actions Also Report a "Near Miss" An Unplanned Event, which, Under Slightly Different Circumstances Could Have Resulted in Harm to People, Damage to the Environment, Damage to Property, Loss of Production, or Non- compliance. • • Issue Date: October 22, 2003 Appendix C Aurora Emergency Action Plan AURORA GAS WELL/FACILITY LOCATIONS LONE CREEK NO. 1 WELL AND PRODUCTION FACILITY 6-1/2 MILES NORTHWEST OF THE NATIVE VILLAGE OF TYONEK (10 MILES BY ROAD) AND 10 MILES WEST-SOUTHWEST OF BELUGA GAS FIELD/AIRSTRIP (12 MILES BY ROAD) COORDINATES: 61 DEG, 7.44 MIN N LATITUDE. 151 DEG, 17.47 MIN W LONGITUDE LONE CREEK N0.3 WELL LOCATION: 61 DEG. 8.02 MIN N, 151 DEG 17.33 MIN. W MEDEVAC LOCATION: 0.9 MILES SOUTH AT THE LONE CREEK NO. 1 WELL AND PRODUCTION FACILITY: 6-1/2 MILES NORTHWEST OF THE NATIVE VILLAGE OF TYONEK (10 MILES WEST-SOUTHWEST OF BELUGA GAS FIELD/AIRSTRIP (12 MILES BY ROAD) COORDINATES: 61 DEG, 7.44 MIN N LATITUDE 151 DEG, 17.47 MIN W LONGITUDE NICOLAI CREEK UNIT NO.1,2,3 8~ 9 WELL LOCATIONS LOCATION: WEST END OF SHIRLEYVILLE (NICOLAI CREEK) AIRSTRIP COORDINATES: 61 DEG 00.83 MIN N LATITUDE 151 DEG 26.04 MIN W LONGITUDE MOQUAWKIE NO. 1 8~ 3 WELL LOCATIONS MOQUAWKIE AIRSTRIP COORDINATES: 61 DEG 04' 16.139" N LATITUDE 151 DEG 19' 07.766" W W LONGITUDE • THREE MILE CREEK UNIT NO. 1 PAD AND FACILITY LOCATION: 7.5 MILES NORTH NORTHWEST OF THE NATIVE VILLAGE OF TYONEK (13 MILES BY ROAD) AND 5.75 MILES WEST OF BELUGA GAS FIELD/AIRSTRIP (15 MILES BY ROAD) COORDINATES: (OLD SUPERIOR AIRSTRIP, WHERE ROAD CROSSES STRIP): NAD 27 UTM: • N: 2,616,324, E: 285,003 ZN 4 OR NAD 83 LATILONGS: 61 DEG, 09.30 MIN N LATITUDE 151 DEG, 13.17 MIN W LONGITUDE ASPEN NO. 1 WELL LOCATION HELICOPTER LANDING ZONE AT WELL SITE GPS COORDINATES: 61 DEG 04' 53.94" N LATITUDE 151 DEG 15' 06.90" W W LONGITUDE KALOA 2 ~ 4 WELL SITES AND FACILITY HERC STRIP AT GRANITE POINT COORDINATES: NORTH LATITUDE 61 DEG, 01.149 MIN WEST LONGITUDE 151 DEG, 20.056 MIN Appendix C -Aurora Emergency Action Plan ~3 ~~ i STATE OF ALASKA NOTICE TO PUBLISHER ', ADVERTISING ORDER NO. ADVERTISING INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED A O-03014027 AFFIDAVIT OF PUBLICATION (PART2 OF THIS FORM) WITH ATTACHED COPY OF I'1 ORDER ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE SEE BOTTOM FOR INVOICE ADDRESS F AOGCC AGENCY CONTACT DATE OF A.O. March 19, 2010 R 333 W 7th Ave, Ste 100 Jod Colombie ° Anchorage, AK 99501 PHONE PCN M 907-793-1238 - DATES ADVERTISEMENT REQUIRED: o Anchorage Daily News 2010 March 22 , PO Box 149001 Arichora e AK 99514 g 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 AOGCC, 333 W. 7th Ave., Suite 100 PAGE 1 OF TOTAL OF TO Anchora e AK 99501 2 PAGES ALL PAGES$ REF TYPE NUMBER AMOUNT DATE COMMENTS 1 VEN s ARn 02910 FIN AMOUNT SY CC PGM LC ACCT FY NMR DIST LIO 1 10 02140100 73451 2 REQUISITIONED B'Y• ~' DIVISION APPROVAL: ~';~ ~ ~/~i1 I 02-902 (Rev. 3/94) ~,e ~ Publisher/Original Copies: Department Fiscal, Department, Receiving AO.FRM • • Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Docket # AEO-10-01. The application of Aurora Gas, LLC, by a letter dated and received March 12, 2010, requests the Alaska Oil and Gas Conservation Commission (Commission) issue an order for aquifer exemption at depths greater than 2000 feet true vertical depth below the surface, for portions of the Nicolai Creek Unit at T11N, R12W SM, Kenai Peninsula Borough, in conformance with 20 AAC 25.440. The proposed location is as follows: Location: Seward Meridian, Township 11N, Range 12W, Section 29: SE'/4 SW'/4 NW '/4; S W '/4 SE '/4 NW '/4; SW '/4 NW 1/4 S W t/a; E '/2 NW '/4 S W '/4; W '/2 NE '/4 S W t/a; S W '/a SW '/a; NW 1/a SE '/a SW '/a. The Commission has tentatively scheduled a public hearing on this application for April 15, 2010 at 9:00 a.m. at the Alaska Oil and Gas Conservation Commission, at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. To request that the tentatively scheduled hearing be held, a written request must be filed with the Commission no later than 4:30 p.m. on April 8, 2010. If a request for a hearing is not timely filed, the Commission may consider the issuance of an order without a hearing. To learn if the Commission will hold the hearing, ca11793- 1221 after April 12, 2010. In addition, written comments regarding this application may be submitted to the Alaska Oil and Gas Conservation Commission, at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. Comments must be received no later than 4:30 p.m. on April 15, 2010. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the Commission's Special Assistant, Jody Colombie, at 793-1221, no later than April 12, 2010. Daniel T. Seamount, Jr. Chair * • 3/2?/2010 RECEIUE~ Anchorage Daily News Affidavit of Publication 1001 Northway Drive, Anchorage, AK 99508 PRICE OTHER OTHER AD # DA1' P~ ACCOUNT PER DAY CHARGES CHARGES #2 749906 03/22/2010 AO-03014 STOF0330 $175.96 $175.96 $0.00 $0.00 STATE OF ALASKA THIRD JUDICIAL DISTRICT Shane Drew, being first duly sworn on oath deposes and says that he 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. Signed Subscribed and sworn to me before this date: MAR 3 0 2010 Notary Public in and for the State of Alaska. Third Division. Anchorage, Alaska MY COMMISSION EXPIRES: o~ ~3 ,~ ``tic t f u~<<~,~P v• ~®TA/Qy ~, ./~ • .. ~, ~llffl~~~~l)11}~~1, MAR ~ ~ za~o ON~IGr88Co~• '~10f' OTHER GRAND CHARGES #3 TOTAL $0.00 $175.96 Notice of Fabric Hearing $T1ITB OPAUY3KA Aia 1~ and GaaCoeaesvatton Comtn~to~ Re: Docket # AE©-i0~Q1. The fic~atlon of Aurora ' Gas, LLC, DY a ietterdated and re€ewed Mart:h 12, 2010, rreeqquests the Alaska ijlF and Gas Ganserv8tion Comrrx'ssion {Gommisswn) i an order for atplifer exemption at depths greater than 2000 Poet true vertical depth below d1e surface, for portions of the Nicolal. Creek t)nit at T11N, R12W SM, Kenai Peninsu{a Borough, in conformance with 2p AAC , 25.440: The proposed locatlon is aS follows: Lo€atiron: Seward Meridian, Township 1TN, Range 12W, Setrtton 29: SE 1/4 SW 114 NW 1/4; SW 1/4 SE 1/4 NW 1l4; $W 1/4 NW 1/4 5W 1/4; E 112 NW 1/4 SW 1/4; W 1/2 NE 1/4 SW 1/4; SW 1/4 SW 1/4; NW 1/4 SE 1/4 5W 1/4. The Commission has, tenfativelYy scheduled a public hearing on this application for April 15, 2010 at 4:F1D a:m: at.the Alaska bif and Gas Conservation Commission, at 333 West Xth Avenue; Suite top, Anchorage, Alaska 99501. To request that the. i tentatively schedWed hearing be held, # written request must be filed with the Commission no later than 4i~ P.m. on April 8, 2010. If a request for a hearing is not timely flied, the Commission may consider the issuance of an order without a hearing: To team if the Commission will hold 191e hearing, eau 793-1221 after April 12, 2010. In addition, writtQn comments regardingg this , application maybe submitted to the Alaska 0"tl and Gas Conservation Commission, at 333 West 7th Axenue, Suite.100. Anchoragge,~ Alaska 99501; Commehts must Ile received'rks motet' tli~r 4:30 p.m. on A{Nft 15,2010. If, beeausa of a disability, special accommodations may be needed to comment or Rtt~td the heai7~1$. contact the Commission's Spe€tat AssiStam, Joay .: Cotomb~,'at 793-1221, no later than April 12, 2010. DanietT. Seamourit, k. ' Char art-o~l~a7 Published: Mar€h 2a, 2010 STATE OF ALASKA ADVERTISING ORDER SEE BOTTOM FOR INVOICE AD • NOTICE TO PUBLISHER ADVERTISING ORDER NO. INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED /t• O_03014027 AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF /'1 ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE F AOGCC R 333 West 7th Avenue. Suite 100 Anch~rage_ AK 995(11 "" 907-793-1238 AGENCY CONTACT i DATE OF A.O. PCN IRED: o Anchorage Daily News PO Box 149001 Anchorage, AK 99514 March 22, 2010 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Account # STOF0330 United states of America State of division. AFFIDAVIT OF PUBLICATION REMINDER ss INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. 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 2010, and thereafter for consecutive days, the last publication appearing on the day of .2010, 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 2010, 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 A O-03014028 /`1 SEE BOTTOM FOR INVOICE ADDRESS F R A~GCC 333 W 7th Ave, Ste 100 AGENCY CONTACT Jod Colombie DATE OF A.O. March 17 2010 ° M Anchorage, AK 99501 907-793-1238 PHONE - PCN DATES ADVERTISEMENT REQUIRED: ASAP o Peninsula Clarion P.O. Box 3009 Kenai AK 99611 ~ 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 Anchors e AK 99501 PAGE 1 OF 2 PAGES TOTAL OF ALL PAGES$ REF TYPE NUMBER AMOUNT DATE COMMENTS 1 VEN s A>~ 02910 3 4 FIN AMOUNT SY CC PGM LC ACCT FY NMR DIST LIO ~ 08 02140100 73451 2 3 4 REQUISITIONED BY: DIVISION APPROVAL: LJ .Notice of Public Hearing C, J STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Docket # AEO-10-01. The application of Aurora Gas, LLC, by a letter dated and received March 12, 2010, requests the Alaska Oil and Gas Conservation Commission (Commission) issue an order for aquifer exemption at depths greater than 2000 feet true vertical depth below the surface, for portions of the Nicolai Creek Unit at T11N, R12W SM, Kenai Peninsula Borough, in conformance with 20 AAC 25.440.. The proposed location is as follows: Location: Seward Meridian, Township 11N, Range 12W, Section 29: SE I/4 SW `/4 NW '/a; S W '/4 SE '/a NW '/a; S W '/4 NW I/4 S W '/4; E 1/2 NW 1/4 S W t/a; W %2 NE `/4 S W '/a; S W `/4 S W 1/4; N W 1/4 S E 1/4 S W t/4. The Commission has tentatively scheduled a public hearing on this application for April 15, 2010 at 9:00 a.m. at the Alaska Oil and Gas Conservation Commission, at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. To request that the tentatively scheduled hearing be held, a written request must be filed with the Commission no later than 4:30 p.m. on Apri18, 2010. If a request for a hearing is not timely filed, the Commission may consider the issuance of an order without a hearing. To learn if the Commission will hold the hearing, ca11793- 1221 after April 12, 2010. In addition, written comments regarding this application may be submitted to the Alaska Oil and Gas Conservation Commission, at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. Comments must be received no later than 4:30 p.m. on April 15, 2010. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the Commission's Special Assistant, Jody Colombie, at 793-1221, no later than April 12, 2010. Daniel T. Seamount Chair • C] PUBLISHER' S AFFIDAVIT UNITED STATES OF AMERICA, STATE OF ALASKA ss: Denise 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-3014028 a printed copy of which is hereto annexed was published in said paper one each and every daY for one successive and consecutive daY in the issues on the following dates: March 24, 2010 X ~iA1. ~a~~[.P., SUBSCRIBED AND SWORN to me before thi 24th day of March 2010 NOTARY PUBLIC in favor for the State of Alaska. My Commission expires 26-Auf;-12 ~' r~~~~~~~a~~~~~~. i ` rlw~as °~ ~ f ~ 1 Alaska awd ilkls Commission Re: Docket # AE0-10-01. The application of Aurora Gas, LLC, by a letter dated and received"_Maroh `12, 2010„ requests the Alaska Oil and Gas Gonservation Commission (Commission) issue an Order for, aquifer,: exemption , at depths greater than 2000 feet true "vertical depth below the surface, for portions of the Nicolai Creek Unk of T11 N, R12W SM, Kenai P®ninsula f Borough in conformance with 20 AAG 25.440. The 'proposed location is as folbws: 'location: Seward Meridian, Township 11 N, Range i ``/a,2' SW 'e NW '/< SW E; E `'S/z NW %a SW ~''/S W ''/z NE''fa SW ~''/a; $W ye SW %a; NW'/e$E'/a SW %. The Commission has tentatively scheduled a public hearing on this application for. Aprill5, 2010 at_9:00 f,a.m. at th@ Alaska Oil and Gas: Conservation' Crommission, at 333 West 7th Avenue, Suite 100, i Anchorage, Alaska. 99501. 'To request that the tentatively scheduled hearing beheld, a written request must be filed with the Commission no later than 4:30' ' p.m, on April 8, 2010. r ' ' If a request for a hearing is not timely filed, that Commissbn may consider the issuance of an order' without a hearing. To learn of the Commission will hold the hearing, call 793-1221 after April 12, 2010. In addition, written comments regarding this application may be submitted to the Alaska Oil .and Gas: Consen+ation Commission, at 333 West 7th r Avenue, Suite 100, Anchorage, Alaska 98501.. Comments must be received no later than 4:30 p.m. on April 15, 2010. !f, `because of a disability, special accommodations may be needed to comment or attend the hearing, contact the `Commission's Special Assistant,. Jody Colombie, at.793-1221, no later than April 12, 2010. Daniel T. Seamount, Jr. ' Chair Lust-$`~¢=2-1=---.....~ 7aa-no74! SR NOTARY ~~ ~°UBL1G 02-902 (Rev. 3/94) Publish~iginal 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 /~ 0_03014028 AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF /"1 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 ° Anchnrage_ AK 99561 PHONE PCN M 907-793-1238 - DATES ADVERTISEMENT REQUIRED: ASAP o Peninsula Clarion PO Box 3009 Kenai AK 99611 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN N ~ ITS ENTIRETY ON THE DATES SHOW . SPECIAL INSTRUCTIONS: AFFIDAVIT OF PUBLICATION 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 2009, and thereafter for consecutive days, the last li I publication appearing on the day of .2009, 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 2009, Notary public for state of My commission expires 02-901 (Rev. 3/94) AO.FRM Page 2 PUBLISHER • • Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Friday, March 19, 2010 1:36 PM To: Aubert, Winton G (DOA); Ballantine, Tab A (LAW); Brooks, Phoebe; Crisp, John H (DOA); Darlene Ramirez; Davies, Stephen F (DOA); Fisher, Samantha 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, Bren (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); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); 'Aaron Gluzman'; Bettis, Patricia K (DNR); caunderwood@marathonoil.com; 'Dale Hoffman'; Frederic Grenier; 'Gary Orr'; Jerome Eggemeyer; 'Joe Longo'; 'Lamont Frazer'; Marc Kuck; 'Mary Aschoff; Maurizio Grandi; Ostrovsky, Larry Z (DNR); P Bates; Randy Hicks; Richard Garrard; 'Sandra Lemke'; 'Scott Nash'; Talib Syed; 'Tiffany Stebbins'; 'Wayne Wooster'; 'Willem Vollenbrock'; 'William Van Dyke'; Woolf, Wendy C (DNR); (foms2@mtaonline.net); (michael.j.nelson@conocophillips.com); (Von.L.Hutchins@conocophillips.com); alaska@petrocalc.com; Anna Raff; Barbara F Fullmer; bbritch; Becky Bohrer; Bill Walker; Bowen Roberts; Brad McKim; Brady, Jerry L; Brandon Gagnon; Brandow, Cande (ASRC Energy Services); Brian Gillespie; Brian Havelock; Bruce Webb; carol smyth; Charles O'Donnell; Chris Gay; Cliff Posey; Crandall, Krissell; Dan Bross; daps; Daryl J. Kleppin; David Boelens; David House; David Steingreaber; 'ddonkel@cfl.rr.com'; Deborah J. Jones; doug_schultze; Elowe, Kristin; Evan Harness; eyancy; Francis S. Sommer; Fred Steece; Garland Robinson; Gary Laughlin; Gary Rogers; Gary Schultz; ghammons; Gordon Pospisil; Gorney, David L.; Gregg Nady; gspfoff; Hank Alford; Harry Engel; Jdarlington (jarlington@gmail.com); Jeff Jones; Jeffery B. Jones Qeff.jones@alaska.gov); Jerry McCutcheon; Jim White; Jim Winegarner; Joe Nicks; John Garing; John S. Haworth; John Spain; John Tower; John W Katz; Jon Goltz; Joseph Darrigo; Julie Houle; Kari Moriarty; Kaynell Zeman; Keith Wiles; Larry Ostrovsky; Laura Silliphant; Marilyn Crockett; Mark Dalton; Mark Hanley (mark.hanley@anadarko.com); Mark Kovac; Mark P. Worcester; Marguerite kremer; 'Michael Dammeyer'; Michael Jacobs; Mike Bill; Mike Mason; Mikel Schultz; Mindy Lewis; MJ Loveland; mjnelson; mkm7200; nelson; Nick W. Glover; NSK Problem Well Supv; Patty Alfaro; Paul Decker (paul.decker@alaska.gov); PORHOLA, STAN T; Rader, Matthew W (DNR); Raj Nanvaan; Randall Kanady; Randy L. Skillern; Rob McWhorter; rob.g.dragnich@exxonmobil.com; Robert A. Province (raprovince@marathonoil.com); Robert Campbell; Roberts, Susan M.; Rudy Brueggeman; Scott Cranswick; Scott, David (LAA); Shannon Donnelly; Sharmaine Copeland; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); Sondra Stewman; Steve Lambert; Steve Moothart; Steven R. Rossberg; Suzanne Gibson; tablerk; Tamera Sheffield; Taylor, Cammy O (DNR); Ted Rockwell; Temple Davidson; Teresa Imm; Terrie Hubble; Thor Cutler; Tina Grovier; Todd Durkee; Tony Hopfinger; trmjr1; Walter Featherly; Williamson, Mary J (DNR); Winslow, Paul M Subject: Public Notice Nicolai Creek AEO Attachments: Public Notice AEO Nicolai Creek.pdf Jody J. Colombie Special Assistant Alaska Oil and Gcks Conservation Commission 333 West 7th Avenue, Suite 1 DO Anchorage, AK 99501 (907) 793-1221 phone) (907)276-7542 (fax) Mary Jones David McCaleb George Vaught, Jr. XTO Energy, Inc. IHS Energy Group PO Box 13557 Cartography GEPS Denver, CO 80201-3557 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 Ft. Worth, TX 76102-6298 Houston, TX 77056 Jerry Hodgden Richard Neahring Mark Wedman Hodgden Oil Company NRG Associates Halliburton 408 18th Street President 6900 Arctic Blvd. Golden, CO 80401-2433 PO Box 1655 Anchorage, AK 99502 Colorado Springs, CO 80901 Schlumberger Ciri Baker Oil Tools Drilling and Measurements Land Department 4730 Business Park Blvd., #44 2525 Gambell Street #400 PO Box 93330 Anchorage, AK 99503 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 Cliff Burglin Refuge Manager 399 West Riverview Avenue 319 Charles Street PO Box 2139 Soldotna, AK 99669-7714 Fairbanks, AK 99701 Soldotna, AK 99669-2139 Richard Wagner Bernie Karl North Slope Borough PO Box 60868 K&K Recycling Inc. PO Box 69 Fairbanks, AK 99706 PO Box 58055 Barrow, AK 99723 Fairbanks, AK 99711 ~. ~ • Colombie, Jody J (DOA) From: Aubert, Winton G (DOA) Sent: Wednesday, March 17, 2010 2:24 PM To: Colombie, Jody J (DOA) Subject: FW: Gas storage purposes is exempt from UIC regulation pursuant to 40 CFR 144.1(g)(2)(iv) -----Original Message----- From: Regg, James B (DOA) Sent: Wednesday, March 17, 2010 9:00 AM To: Aubert, Winton G (DOA); Maunder, Thomas E (DOA); (DOA); Norman, John K (DOA); Ballantine, Tab A (LAW) Subject: FW: Gas storage purposes is exempt from UIC Tim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 907-793-1236 Foerster, Catherine P (DOA); Seamount, Dan T regulation pursuant to 40 CFR 144.1(g)(2)(iv) -----Original Message----- From: Cutler.Thor@epamail.epa.gov [mailto:Cutler.Thor@epamail.epa.gov] Sent: Wednesday, March 17, 2010 8:03 AM To: Regg, James B (DOA) Cc: Thor Cutler; contreras.peter@epa.gov Subject: Gas storage purposes is exempt from UIC regulation pursuant to 40 CFR 144.1(g)(2)(iv) lames Regg, Last week, you asked about gas storage wells and the role of Federal aquifer exemptions. I hope I answered your question and I defer to you regarding any state regulations, that said... Short answer, no, the state does not need an aquifer exemption from the UIC program as injection of natural gas for purposes of storage is clearly exempted from UIC program regulation but if the state is going to use their own process to exempt the aquifer to allow for storage, it would be nice if the state shared the information with the EPA Region-10 prior to issuing the exemption. However, the state is not obligated to do this. EPA regulations that discuss aquifer exemptions include but not limited to 40 CFR 144.7, 40 CFR 144.12 and 40 CFR 146.4. See 40 CFR 144.1(8) (2) (iv) regarding gas storage. Theis matter was not articulated in the preamble to the UIC framework regulation in the 1980s. Aquifer exemptions are usually associated with permits. Specifically, if the gas being stored is a gas at standard temp. and pressure and is of "pipeline quality", then yes the injection of the gas for storage purposes is exempt from UIC regulation pursuant to 40 CFR 144.1(g)(2)(iv). This is the key specific regulation, in my review. A lawyer may always have another view. 1 ~ • T#~e purpose of aquifer exemptions is to allow injection that would otherwise violate 40 CFR 144.12 into an injection zone that meets the definition of an underground source of drinking water. Since the injection activity (pursuant to 40 CFR 144.1(g)(2)(iv)) is beyond the scope of the UIC program, there appears to be no need or requirement pursuant to Federal UIC regulations to exempt the injection zone for gas storage purposes. That having been said, what the state does, or is required to do, is dependent on the state program(s) and state regulations. Most primacy states incorporated their UIC programs into their existing NPDES ground water protection programs (as you know, the NPDES program is in the process of being delegated to Alaska, which may take years) so the state jurisdiction and requirements for ground water protection may (are likely to) extend beyond just UIC. So it's possible that your state may have extended their regulatory aquifer exemption requirements, or some similar ground water protection requirements, beyond just UIC-regulated activities. Therefore the state may have some sort of requirements for injecting gas (Based on our past discussions over the years, I am sure you are familiar with them), or any contaminant, into a zone that meets the definition of a "waters of the state" and also has the potential to serve as a drinking water source (assuming the prospective zone has that potential to serve as a USDW). So long as the state meets their regulatory requirements in making your permitting decision, establishing appropriate permit restrictions, etc., the state is not required to comply with the Federal UIC aquifer exemption criteria or process (unless the state regulations require the state to do so for gas storage facilities. I am not aware of such requirements in state regulations in Alaska). The EPA would not have to concur for an aquifer exemption for underground injection that is not within the scope of the applicable State UIC program. If the state were to exempt an aquifer for gas storage operations, the exempted zone (as EPA would apply it) would be limited to an area associated with the injection zone. If a gas storage well is drilled through the USDW, it does not mean the gas storage operation may contaminate the USDW. It should still be protected by state regulations. I hope this is helpful. Please call if I can be of further assistance. Sincerely, Thor Cutler Please note new fax floor, and mailstop: Thor Cutler, LEG, LHG, LG, CPG EPA (mailstop: OCE-127) (12th floor) 1200 Sixth Avenue Seattle Wa 98101 Phone: 206-553-1673 Fax 206-553-8509 Email cutler.thor @epa.gov 2 _.t.l,. l ! • ..=Aurora Gay LLC r~`~ www.aurorapower, co~ Mr. Winton Aubert Alaska OiI and Gas Conservation Commission 333 West 7th Ave., Suite 100 Anchorage, Alaska 99501 RE: Application for Storage Injection Order Nicolai Creek Gas Storage Facility Response to Additional Information Request Dear Mr. Aubert: March 12, 2010 RECEIVE Mai ~ 2 ~zo~fl ~~ ~~' Aurora gas, LLC is pleased to supply the Commission with the additional information you have requested. Please consider the following in your evaluation of our SIO request: 1. Gas analysis of proposed injection gas. Attached are gas analysis reports from the 8103, 8104 and 8105 gas meters which handle gas from Aurora's Nicolai Creek, Lone Creek and Moquawkie gas fields. As you can see, the proposed injection gas at all meters is dry gas consisting of more than 98% methane with trace amounts of ethane, propane, nitrogen and Cot. 2. Emergency Action Plan. As requested, I have attached a copy of Aurora's Emergency Action Plan. 3. Statement of mechanical integrity for wells within'/4 mile of the injection reservoir. Nicolai Creek State #1: PTD #165-027-0 Plugged and abandoned per AOGCC requirements on 03/11/66. Nicolai Creek State # i A: PTD #166-008-0 Flugged and abandoned per AOGCC requirements on 02/02/02. Nicolai Creek Unit #4: PTD #169-105-0 Plugged and abandoned per AOGCC requirements on 11/27/71. PTD # 191-100-0 Plugged and abandoned per AOGCC requirements on 09/09/91. Nicolai Creek Unit #5: PTD #171-030-0 Plugged and abandoned per AOGCC requirements on 03/07/72. Nicolai Creek #6: PTD # 179-061-0 Plugged and abandoned per AOGCC requirements on 02/07/80. 1400 West Benson Blvd., Suite 410 • Anchorage, AK 99503 • (907) 277-1003 • Fax: (907) 277-1006 6051 North Course Drive, Suite 200 • Houston, TX 77072 • (281) 495-9957 . Fax: (281) 495-1473 Nicolai Creek SIO A licatior~ pp Additional Information Winton Aubert March 12, 2010 Page 2 of 4 Nicolai Creek Unit #5: PTD #202-107-0 Well cancelled after submitting application on 07/09/04. Nicolai Creek Unit #7: No Permit to Drill. Well site was staked and evaluated and never permitted or drilled. Nicolai Creek Unit #8: PTD #202-194-0 Well cancelled after submitting application on 09/30/42. Nicolai Creek Unit # 10: PTD #206-080-0 Permit to Drill expired on 07/06/08, well never drilled. Nicolai Creek Unit #3: PTD #i67-007-0 Straight-hole well that is located approximately 1 mile north of the northern boundary of the proposed injection reservoir and more than 1-1 J4 mile from the NCU #2 proposed injection well. No history or indication of any mechanical integrity issues. Nicolai Creek #1 L• PTD #209-067-0 New straight-hole well that is located more than 1/4 mile west of the western boundary of the proposed injection reservoir and more than 1/4 mile from the NCU #2 proposed injection well. No history or indication of any mechanical integrity issues. There has been indication of any pressure communication with this well and the NCU #2 or other area wells. Nicolai Creek Unit #1B: PTD #202-162-0 Well located on the same pad as the proposed injection well. No history or indication of any mechanical integrity issues. Attached is the Cement Bond Log dated 09/I8/02. There has been no indication of any pressure communication with this well and the NCU #2 or other area wells. A mechanical integrity test will be performed as necessary in accordance with any Storage Injection Order. Nicolai Creek Unit #9: PTD #202-208-0 Well located on the same pad as the proposed injection well. No history or indication of any mechanical integrity issues. An Ultrasonic Cement and Casing Imager Log is in the AOGCC log files for this permit to drill. There has been no indication of any pressure communication with this well and the NCU #2 or other area wells. A mechanical integrity test will be performed as necessary in accordance with any Storage Injection Order. Nicolai Creek Unit #2: PTD #166-038-0 This is the proposed injection well. No history or indication of any mechanical integrity issues. A Cement Bond Log is in the AOGCC log files for this permit to drill. There has been no indication of any pressure communication with this well and other area wells. A mechanical integrity test will be performed as necessary in accordance with any Storage Injection Order. Nicolai Creek SIO A licatio~ pp Additional Information Winton Aubert March 12, 2010 Page 3 of 4 4. Water analysis of formation water for the proposed injection. well. An analysis from well logs and produced water samples from the Nicolai Creek Unit #1B, #2 and #9 wells have been completed, with the following results: a) The calculated salinity from the original open-hole electric log, using Schlumberger Log Interpretation Charts, SP-1, SP-2, SP-3, Sp-4, and Gen-9, was 12,000 ppm NaCI. This calculation was from a SSP (static spontaneous potential) of 14 mV for the sand at 2426' MD (upper Tyonek Carya 2-1.1) in the Nicolai Creek Unit #2 well for the top zone targeted for gas injection/storage. This is consistent with previous calculations. b) Produced water samples from the Nicolai Creek Unit # 1 B, which is in a different reservoir but also has Upper Tyonek Carya 2-1, 2-2, and 2-3 sands open, tested at 13,200 ppm NaCI on 2/28/10. This sample was from the separator for that well, as the well has not produced for some time (8,000 ppm CI x 1.65 provides the ppm NaCI. c) Earlier calculations from the Nicolai Creek Unit #21ogs done by Aurora's geologist / geophysicist indicated salinities of the shallower Beluga sands in the well to be: 7,000 ppm at 630', 9,200 ppm at 740', 6,500 ppm NaCI at 1,060', and 7,700 ppm NaCI at 1,410'. An analysis was from a produced water sample of the Beluga sands in the Nicolai Creek Unit #9 confirms this range this range to be 9,820 ppm NaCI. The cement bond logs, historical performance of the Nicolai Creek Unit #2 well and the reservoir production history indicates that the wellbore and injection reservoir are geologically and mechanically separated from any fresh water aquifer. However, as a prudent environmental measure, Aurora hereby requests the AOGCC to obtain a Fresh Water Aquifer Exemption, on behalf of Aurora Gas, LLC, for the Nicolai Creek Gas Storage Facility below a true vertical depth 2,000 feet below the surface. 5. Injection pressure. The initial reservoir pressure of the Nicolai Creek Unit #2 well at mid-perf depth of 2,671' MD / 2,309' TVD was measured by down-hole pressure gauges at 1,071.5 psia (1,056 psig, using a 15 psia atmospheric pressure}--actual measurements were taken at 2,255' and 2,337' TVD, and interpolated to 2,309' to get this pressure. This gives an average formation pressure gradient of 0.458 psi/ft. back to surface. The table below indicates the variable surface pressures with a constant bottom-hole injection pressure. Aurora proposes to not exceed a surface injection pressure of 1,050 psig, unless a higher pressure is approved by the AOGCC. This maximum injection pressure will not exceed a gradient of 0.46 psi per foot (the fracture gradient for this formation is believed to be about 0.90 psi per foot). Nicolai Creek SIO A licatio~ pP Additional Information Winton Aubert March 12, 2010 Page 4 of 4 Bottom Hole Pressure sia Surface Pressure si Flow rate (mmscfd) 1070 993 0 1.070 1008 5 1070 1049 10 1070 1113 15 1070 1197 20 Attached is the injection model showing the wellbore pressures, flow rates and temperatures during gas injection. Also attached are the summary results of the four-point pressure test. After cycling the gas within the injection reservoir(s) to establish the performance characteristics, Aurora believes that subsequent reservoir studies and fracture analysis modeling could result in the ability to increase the bottom-hole pressure above the initial reservoir pressures, thereby providing an increase in gas storage capacity. Thank you for your consideration of this additional information in support of the Stprage Injection Order application. If you need additional information, please do not hesitate to contact either myself or Mr. Ed Jones at the Anchorage and Houston, respectively, telephone numbers on the bottom of first page. Sincerely, O `'~J cs~ Bruce D. Webb Aurora Gas, LLC Manager, Land and Regulatory Affairs Attachments: Gas Analysis of meters 8103, 8104 and 8105 (2 each, 6 total) Aurora Gas, LLC Emergency Action Plan Nicolai Creek Unit #1B Cement Bond Log Nicolai Creek Unit #2 Injection Simulation Nicolai Creek Unit #2 4-Point Pressure Test Summary • AURORA_ MOQUAWKIE_MSN8105_123009_RUN 1 Chandler Engineering Co. Model 292/2920 BTU Analyzer Test time: ~u1y08 93 1 0:22 Calibr ation #: 8 Test #:3 Locati on No. :8105 _ St andard/Dry Analysis saturated/wet Analysis Mole% BTU* R,Den.* GPM** Mole% BTU* R.Den.* Methane 98.949 996.28 0.5481 -- 97.218 978.85 0.5385 Ethane 0.124 2.19 0.0013 0.0330 0.122 2.15 0.0013 Propane 0.009 0.24 0.0001 0.0026 0.009 0.23 0.0001 Moisture 0.000 0.00 0.0000 -- 1.750 0.88 0.0109 Nitrogen 0.695 0.00 0.0067 -- 0.683 0.00 0.0066 ( Cot ) 0.223 0.00 0.0034 -- 0.219 0.00 0.0033 Ideal 100.00 998.7 0.5596 0.0355 * uncorrected for compressibility at 60.0E & 14.650PSIA. **: Liquid volume reported at 60.OF. standard/Dry Analysis saturated/wet Analysis Molar Mass = 16.208 16.239 Relative Density = 0.5605 0.5616 Compressibility Factor = 0.9980 0.9979 Gross Heating value = 23457. Btu/lb 23022. Btu/lb Gross Heating value = 1000.7 Btu/CF 984.1 Btu/CF Absolute Gas Density = 42.6594 lbm/1000CF 42.7471 lbm/1000CF wobbe Index = 1314.55 unnormalized Total 98.877 Last Calibrated with Calgas of 1050.7 Btu/CF ~an.04 93 02:07 C6+ Last Update: ]une03 08 19:37 c6+ BTU/CF 5065.8, C6+ lbm/Gal 5.64250, and C6+ Mol.wt. 92.00. AURORA MOQUAWKIE 8105 Temp: 42 Deg. F Press: 886 Sample Date: 130/09 RUN 1 MSN: 8105 Page 1 • • AURORA_ LONE CREEK_MSN8104_123009_RUN 1 > chandler Engineering Co. Model 292/2920 BTU Analyzer Test time: 7u1y08 93 09:17 Calibration #: 8 Test #:5 Location No. :8104 standard/Dry Analysis _ saturated/wet Analysis Mole% BTU* R.Den.* GPM** Mole% BTU* R.Den.* Methane 98.222 988.96 0.5440 -- 96.503 971.65 0.5345 Ethane 0.186 3.28 0.0019 0.0493 0.182 3.22 0.0019 Propane 0.042 1.05 0.0006 0.0115 0.041 1.03 0.0006 Moisture 0.000 0.00 0.0000 -- 1.750 0.88 0.0109 Nitrogen 1.551 0.00 0.0150 -- 1.524 0.00 0.0147 Ideal 100.00 993.3 0.5616 0.0608 * uncorrected for compressibility at 60.0E & 14.650PSIA. **: Liquid volume reported at 60.OF. standard/Dry Analysis saturated/wet Analysis Molar Mass = 16.265 16.296 Relative Density = 0.5625 0.5636 Compressibility Factor = 0.9981 0.9980 Gross Heating value = 23247. Btu/lb 22818. Btu/lb Gross Heating value = 995.2 Btu/CF 978.8 Btu/CF Absolute Gas Density = 42.8111 lbm/1000CF 42.8961 lbm/1000CF wobbe Index = 1305.08 Unnormalized Total 98.757 Last Calibrated with Calgas of 1050.7 Btu/CF ~an.04 93 02:07 c6+ Last update: 7une03 08 19:37 C6+ BTU/CF 5065.8, C6+ lbm/Gal 5.64250, and C6+ Mol.wt. 92.00. AURORA LONE CREEK 8104 Temp: 42 Deg F Press: 886# Sample Date: 12/12/09 Run Date: 12/30/09 RUN 1 MSN: 8104 Page 1 • • AURORA_ MOQUAWKIE_MSN8105_123009_RUN 2 Chandler Engineering Co. Model 292/2920 BTU Analyzer Test time: ~u1y08 93 10:38 calibr ation #: 8 Test #:4 vocati on No. :8105 st andard/Dry Analysis _ Saturated/wet Analysis Moie% BTU* R.Den.* GPM** Mole% BTU* R.Den.* Methane 98.960 996.40 0.5481 -- 97.229 978.96 0.5385 Ethane 0.123 2.17 0.0013 0.0326 0.121 2.13 0.0013 Propane 0.009 0.21 0.0001 0.0023 0.008 0.21 0.0001 Moisture 0.000 0.00 0.0000 -- 1.750 0.88 0.0109 Nitrogen 0.689 0.00 0.0067 -- 0.677 0.00 0.0065 ( Cot ) 0.219 0.00 0.0033 -- 0.215 0.00 0.0033 Ideal 100.00 998.8 0.5595 0.0350 * Uncorrected for compressibility at 60.0E & 14.650PSIA. **: liquid volume reported at 60.OF. standard/Dry Analysis saturated/wet Analysis Molar Mass = 16.205 16.237 Relative Density = 0.5604 0.5616 Compressibility Factor = 0.9980 0.9979 Gross Heating value = 23462. Btu/lb 23027. Btu/lb Gross Heating value = 1000.7 Btu/CF 984.2 Btu/CF Absolute Gas Density = 42.6539 lbm/1000CF 42.7417 lbm/1000CF wobbe Index = 1314.74 unnormalized Total : 98.267 past Calibrated with Calgas of 1050.7 Btu/CF 7an.04 93 02:07 C6+ past update: 7une03 08 19:37 C6+ BTU/CF 5065.8, C6+ lbm/Gal 5.64250, and C6+ Mol.wt. 92.00. AURORA MOQUAWKIE 8105 Temp: 42 Deg. F Press: 886 sample Date: 130/09 RUN 2 MSN: 8105 Page 1 J AURORA_ NIKOLAI CREEK_MSN8103_123009_RUN 2 Chandler Engineering Co. Model 292/2920 BTU Analyzer Test time: 7u1y08 93 09:00 Test #:8130 calibration #: 8 Location No. :8103 Standard/Dry Analysis _ saturated/wet Analysis Mole% BTU* R.Den.* GPM** Mole% BTU* R.Den.* Methane 98.605 992.82 0.5462 -- 96.880 975.45 0.5366 Ethane 0.066 1.16 0.0007 0.0175 0.065 1.14 0.0007 Moisture 0.000 0.00 0.0000 -- 1.750 0.88 0.0109 Nitrogen 0.931 0.00 0.0090 -- 0.915 0.00 0.0088 ( C02 ) 0.399 0.00 0.0061 -- 0.392 0.00 0.0060 Ideal 100.00 994.0 0.5619 0.0175 * uncorrected for compressibility at 60.0E & 14.650PSIA. **: Liquid volume reported at 60.OF. standard/Dry Analysis Saturated/wet Analysis Molar Mass = 16.274 16.305 Relative Density = 0.5628 0.5639 Compressibility Factor = 0.9980 0.9979 Gross Heating value = 23251. Btu/lb 22822. Btu/lb Gross Heating value = 995.9 Btu/CF Absolute Gas Density = 42.8347 lbm/1000cF wobbe Index = 1305.65 unnormalized Total 98.452 Last Calibrated with Calgas of 1050.7 Btu/CF C6+ Last update: 7une03 08 19:37 C6+ BTU/CF 5065.8, C6+ lbm/Gal 5.64250, AURORA NIKOLA CREEK 8103 Temp: 44 peg F Press: 894# Sample Date: 12/11/09 Run Date: 12/30/09 RUN 2 MSN: 8103 979.5 Btu/CF 42.9193 lbm/1000CF 7an.04 93 02:07 and c6+ Mol.wt. 92.00. Page 1 • • AURORA_ LONE CREEK_MSN8104_123009_RUN 2 chandler En ineering co. Model 292/2920 BTU Analyzer Test time: 7u1y08 93 09:38 Test #:6 calibration #: 8 vocation No. :8104 _ Standard/Dry Analysis ~ saturated/wet Analysis Mole% BTU* R.Den.* GPM** Mole% BTU R.Den.* Methane 98.235 989.09 0.5441 -- 96.516 971.79 0.5346 Ethane 0.182 3.21 0.0019 0.0484 0.179 3.16 0.0019 Propane 0.043 1.09 0.0007 0.0119 0.043 1.07 0.0006 Moisture 4.000 0.00 0.0000 -- 1.750 0.88 0.0109 Nitrogen 1.539 0.00 0.0149 -- 1.512 0.00 0.0146 Ideal 100.00 993.4 0.5616 0.0603 ~ Uncorrected for compressibility at 60.0E & 14.650PSIA. **: Liquid volume .reported at 60.OF. standard/Dry Analysis saturated/wet Analysis Molar Mass = 16.264 16.295 Relative Density = 0.5624 0.5635 Compressibility Factor = 0.9981 0.9980 Gross Heating value = 23251. Btu/lb 22822. Btu/lb Gross Heating Value = 995.3 Btu/CF 978.9 Btu/CF Absolute Gas Density = 42.8073 lbm/1000CF 42.8924 lbm/1000cF wobbe Index = 1305.29 unnormalized Total 98.364 past Calibrated with Calgas of 1050.7 Btu/CF 7an.04 93 02:07 C6+ past update: 7une03 08 19:37 C6+ BTU/CF 5065.8, C6+ lbm/Gal 5.64250, and C6+ Mol.wt. 92.00. AURORA LONE CREEK 8104 Temp: 42 Deg F Press: 886# Sample Date: 12/12/09 Run Date: 12/30/09 RUN 2 MSN: 8104 Page 1 • • AURORA_ NIKOLAI CREEK_MSN8103_123009_RUN 1 Chandler Engineering Co. Model 292/2920 BTU Analyzer Test time: ~uly0$ 93 08:44 Calibration #: 8 Test #:8129 Location No. :8103 standard/Dry Analys is _ saturated/wet Analysis Mole% BTU* R.Den.* GPM** Mole% BTU* R.Den.~ Methane 98.583 992.59 0.5460 -- 96.858 975.23 0.5365 Ethane 0.066 1.17 0.0007 0.0176 0.065 1.15 0.0007 Moisture 0.000 0.00 0.0000 -- 1.750 0.88 0.0109 Nitrogen 0.951 0.00 0.0092 -- 0.934 0.00 0.0090 ( C02 ) 0.400 0.00 0.0061 -- 0.393 0.00 0.0060 Ideal 100.00 993.8 0.5620 0.0176 * uncorrected for compressibility at 60.0E & 14.650PSIA. ~*: Liquid volume reported at 60.OF. standard/Dry Analysis saturated/wet Analysis Molar Mass = 16.277 16.307 Relative Density = 0.5629 0.5640 Compressibility Factor = 0.9980 0.9979 Gross Heating value = 23241. Btu/lb 22813. Btu/lb Gross +~eati ng value = 995.7 Btu/CF 979.3 Btu/CF Absolute Gas Density = 42.8423 lbm/1000CF 42.9269 lbm/1000CF wobbe Index = 1305.26 unnormalized Total 99.000 Last Calibrated with Calgas of 1050.7 Btu/CF ]an.04 93 02:07 C6+ Last update: 7une03 08 19:37 C6+ BTU/CF 5065.8, C6+ lbm/Gal 5.64250, and C6+ Mol.wt. 92.00. 292: Standard/Dry Analysis 292: Up/Down to view data.. AURORA NIKOLA CREEK 8103 Temp: 44 Deg F Press: 894# Sample Date: 12/11/09 Run Date: 12/30/09 RUN 1 MSN: 8103 Page 1 -Aurora Gas, LLC Emergency Action Plan Scope: Alaska Cook Inlet Operations Revision Date: March 1, 2010 Issue Date: October 10, 2005 Next Review Date: January 1, 2011 Table of Contents 1.0 FIRST 10 MINUTES OF AN EMERGENCY ................................................. 2 2.0 MEDICAL ILLNESS OR INJURY .................................................................. 2 3.0 FATALITY ....................................................................................................... 3 4.0 FIRE /EXPLOSION ......................................................................................... 3 5.0 GAS /VAPOR RELEASE ............................................................................... 4 6.0 HAZARDOUS MATERIAL SPILL OR RELEASE ........................................ 4 7.0 EARTHQUAKE ............................................................................................... 5 8.0 SABATOGE /TERRORISM ........................................................................... 6 9.0 VOLCANO .......................................................................................................6 APPENDIX A EMERGENCY CONTACT INFORMATION APPENDIX B HSE FIELD GUIDE REFERENCE APPENDIX C AURORA WELL /FACILITY LOCATIONS (COORDINATES) Print Date: 3/1/2010 Emergency Action Plan Page 1 of 8 Aurora Gas, LLC This emergency action plan gives guidelines for a multitude of incidents. These procedures should be followed but must be considered on a case-by-case basis in order to satisfy the main goal, which is the protection of human life. 1.0 FIRST 10 MINUTES OF AN EMERGENCY The following are general guidelines of actions to be taken during the first 10 minutes of an emergency: 1.1 Personnel take defensive actions to isolate the problem and/or evacuate, as appropriate. 1.2 Discovery and reporting of the incident. Refer to the attached (Appendix A) for contact information in the case of any and all emergencies. 1.3 Activate the Aurora Emergency Action Plan. Tasks include: 1.3.1 Gather information on the type /nature of the incident. 1.3.2 Evacuate as required. 1.3.3 Assure that headcounts are taken. 1.3.4 The first responding Aurora person will be the responsible charge until turned over to the emergency responders or management personnel. Primary tasks include: ^ Isolate the area and deny entry to all non-essential personnel. ^ Establish an on-scene Meeting Place. • Gather information from Construction /Operations /Drilling personnel. ^ Perform a headcount when applicable. ^ Devise a response strategy. DANGER: Only those individuals directly involved in the emergency response effort, properly trained, wearing the proper level of personal protective clothing, and working in pairs shall be allowed access into the hazard area. All on-scene personnel work under the authority of the Aurora Employee in charge. 2.0 MEDICAL ILLNESS OR INJURY 2.1 Any serious or life threatening illness or injury must be immediately reported to emergency personnel (see Appendix A). Then promptly notify the supervisor or Aurora Management. 2.2 Any trained first responder may treat minor injuries requiring only on-site treatment. Incident must be reported to shift supervisor and necessary reports completed. This category does not include serious, life threatening, or iflness due to hazardous materials. 2.3 Immediate Actions- Serious injuries or illnesses 2.3.1 The observer of incident will, if safe, protect and render assistance to injured or sick. Take appropriate action to make area safe and secure. 2.3.2 Notify appropriate emergency personnel about location, identification, hazards and condition of the victim and action taken. (see Appendix A) 2.3.3 If trained assist victim with first aid. 2.3.4 Aurora Supervisor or Operator on the scene will assume responsibility and direct emergency treatment of victim. 2.3.5 Further reporting actions to Aurora Management should be conducted as soon as the situation permits. Print Date: 3/1/2010 Emergency Action Plan Page 2 of 8 i +~ Aarora Gas, LLC Note: An accident investigation may be required, thus the accident area may not be disturbed until investigation is complete. 3.0 FATALITY 3.1 It is very important not to assume a person(s) death. A licensed medical doctor, EMT, Paramedic or Alaska State Trooper, must do pronouncement of death. This will generally not occur until the victim has been transported to a hospital. Basic life support treatment will be administered and continued until such appropriate pronouncement or certification of death is made. 3.2 If there is any suspicion of contagious disease or exposure to hazardous material, adequate precautions must be taken to isolate the area and remove other personnel from further contact. Identify others who have or may have been contaminated and require that they isolate themselves until help has arrived. 3.3 If a death has occurred, make sure the site is left alone, because an investigation will be necessary. 3.4 Immediate Actions 3.4.1 Observer of incident will protect himself or herself, and to assist victim on the basis that death is not presumed. Take action to secure area and reduce hazards in area. 3.4.2 Notify appropriate emergency personnel about location, identification, hazards, condition of the victim and action taken. (see Appendix A) 3.4.3 Aurora Supervisor or Operator on the scene will assume responsibility and direct emergency treatment of victim. 3.4.5 When conditions permit, basic life support is to be preformed until help arrives. 3.5 Secondary Action 3.5.1 Secure the area and equipment. Take precaution not to disturb the area. If unavoidable, take careful note of status prior to disturbance (e.g. valves open/closed, number of turns; etc.). Take photographs of area where and when possible. 3.5.2 Further reporting actions to Aurora Management should be conducted as soon as the situation permits. 3.5.3 Aurora Supervisor will commence preliminary investigation in the death(s) and prepare for visits from external investigators. 4.0 FIRE /EXPLOSION 4.1 In the case of a fire/ explosion at an Aurora Facility, actions should be designed to protect human life and to control the emergency as rapidly as possible. All steps should be considered, however the sequence could be altered for circumstances on a case-by-case basis to accomplish safe and controlled emergency response. 4.2 Immediate action 4.2.1 Determine if any human safety concerns exist. These concerns include injured, missing, or unaccounted persons. 4.2.2 Determine the type of fire and the best method to control the fire with the equipment and personnel available. Print Date: 3/1/2010 Emergency Action Plan Page 3 of 8 :Aurora Gas, LLC 4.2.3 If the incident is beyond the capacity of equipment and personnel available, the following procedures pertain. 4.3 Initial Response 4.3.1 If safely accessible, initiate the Emergency Shutdown (ESD) button on convex or at the edge of pad. 4.3.2 Notify local fire department and provide information regarding size and location of fire. 4.3.3 If safe to isolate fuel source, direct personnel to do so. 4.3.4 If properly trained and properly equipped personnel should help to fight fire, direct them. to use appropriate fire extinguishing equipment. 4.4 Incident Command Transfer 4.4.1 Upon arrival of fire department, Aurora supervisor or Operator will introduce himself or herself to the arriving officer(s) and transfer command to fire department. 4.4.2 Aurora Supervisor is required to provide updated information to size, location, current action taken and injury to Aurora Management. 5.0 GAS /VAPOR RELEASE 5.1 In the event of a gas or vapor release at an Aurora unit, actions should be taken to protect human life and to gain control of the situation as quickly as possible. All steps listed should be considered, but may be altered to fit individual circumstances. 5.2 Immediate Action 5.2.1 Eliminate all ignition sources, including vehicles, and any hot work. 5.2.2 Attempt to safely control the source of release. 5.2.3 Restrict access to area until vapor cloud has reached a safe level. 5.2.4 Notify Aurora Supervisor of size, source and material released. 5.2.5 Gas release inside facility buildings will automatically initiate the ESD as necessary. 5.2.6 Aurora Supervisor or Operator will assume role of responsible charge when others are present on pad, unless it is turned over to emergency responders. 5.3 Secondary Action 5.3.1 Aurora Supervisor is required to provide updated information to size, location, current action taken and injury to Aurora Management. 6.0 HAZARDOUS MATERIAL SPILL OR RELEASE 6.1 A hazardous material spill includes any element or compound, which can be classified as a danger to health, safety or the environment. 6.2 Recognition of material Identify the substance involved and it's characteristics. These characteristics include: ^ Flammability ^ Toxicity Print Date: 3/1/2010 Emergency Action Plan Page 4 of 8 Aunvra Gas, LLC ^ Asphyxiant ^ Reactivity ^ Sources of information include: a. Material Safety Data Sheets b. DOT labeling and place carding c. NFPA and HMIS labeling 6.3 Evaluation Using information from the recognition stage, develop a plan for safe mitigation of the incident. Be sure to consider: ^ Weather conditions ^ Incident stability ^ Skill level of personnel • Degree of hazard ^ Rate of release ^ Air monitoring results 6.4 Control Control the event by eliminating the source or reducing the impact of the hazard. This may include: ^ Stopping the release • Containment of material ^ Clean up of material 6.5 Immediate Actions 6.5.1 Approach incident from upwind and upgrade direction. 6.5.2 Warn others of incident and notify Aurora Supervisor. 6.5.3 Initiate the ESD as necessary. 6.5.4 Do not enter the effected area without proper PPE and training. 6.5.5 Attempt to identify the material, volume and source of material being released. 6.5.6 Aurora Supervisor to establish initial action plan and safe zones. 6.5.7 Clean up and mitigation should be done if the proper equipment and personnel are available. If necessary notify emergency responders and spill clean up teams. 6.5.8 Reporting of spills and hazards to ADEC and EPA is required in some situations. Refer to the Aurora HSE Incident Reporting Procedure for detailed instructions. Reporting is to be conducted by Aurora Management only. 7.0 EARTHQUAKE 7.1 The Aurora facility is in an earthquake zone, where there are earthquakes of many different magnitudes, including severe. It is possible that a sever earthquake could cause damage and injury, which could interrupt operations for a significant period of time. Earthquakes occur without warning and thus recommended actions should save human life, mitigate damage to property and the environment. Although Tsunami's are reportedly not likely in the Cook Inlet region, employees that are in low elevation areas such as Shirleyville, should be prepared to respond in the unlikely event that a Tsunami is reported following a major earthquake. Print Date: 3/1/2010 Emergency Action Plan Page 5 of S • 7.2 Immediate Actions • ,,:Aurora Gas, LLC 7.2.1 In the event of an earthquake the Aurora Supervisor or Operator will evaluate the earthquake size and if he/she suspects the loss of integrity, actions should first be taken to protect life then shut down the facility. 7.2.2 Account for all personnel. 7.2.3 First responding Aurora personnel will secure systems, with the exception of those systems required for firefighting and life safety. 7.2.4 Aurora Supervisor will notify Aurora Management of situation. 7.2.5 In the event of a threat to personnel, those not required for securing of the unit shall be evacuated. 1n the event of a fire or vapor release, the proper section of this plan should be initiated. 7.3 Secondary Actions 7.3.1 When the quake has subsided, and if conditions permit, conduct a thorough examination of the location. The main focus of examination is not for brining production back on line, but to check for possible fire/explosion sources, leaks, structural integrity and personnel hazards. 7.3.2 The unit should not be put back online until a thorough examination, approval from the Operations Supervisor or Operator and the consideration of possible aftershocks. 7.3.3 After a major earthquake, employees will need to establish radio communication in order to receive warnings and reports from local authorities. Employees at low elevation areas will want to be especially aware of any Tsunami warnings that may follow a major earthquake. 8.0 SABATOGE /TERRORISM 8.1 The main priorities in the event of any threat or incident are to comply with the immediate wishes of any persons who are armed or threatening any personnel. After incident or threat, immediate attention must be given to safeguarding life and reporting details to the proper authorities. 8.2 Safe guarding life is most likely going to involve moving personnel. to a safe area. If a bomb has been placed or the threat of a bomb, the area must be searched and a all clear given by authorities before personnel can return. 8.3 The Alaska State Troopers are responsible for the detailed response to any threat. They will utilize the area and other response agencies as they see fit. 8.4 This procedure is designed to provide the proper instruction to the individuals who will be involved in the response to a bomb threat. There are specific instructions to individuals and general guidelines for bomb threat search procedures. 8.5 Immediate Actions 8.5.1 Keep the caller on the line as long as possible. Ask the caller to repeat the message. Record, if possible every word spoken by the caller. Use the Threat Checklist. 8.5.2 If the caller does not indicate the locations of the bomb(s) or the time of detonation, the person receiving the call should request this information. 8.5.3 It is advisable to inform the caller that the facility is occupied and a bomb detonation could result in injury or death to innocent people. 8.5.4 Pay attention to sounds or background noise from the caller. Try to write down as many things as possible about the caller. Print Date: 3/1/2010 Emergency Action Plan Page 6 of 8 -Aurora Gas, LLC 8.5.5 If possible, have another person contact the Alaska State Troopers and request a line trace. 8.5.6 DO not discuss the call with others. Report directly to a supervisor. 8.5.7 Notify the Aurora supervisor, as he/she will become the incident commander. 8.5.8 The Aurora Supervisor will coordinate along with the Alaska State Troopers an appropriate plan of action. 8.5.9 If necessary evacuate facility. 8.6 Secondary Actions 8.6.1 Consider isolation of systems to the maximum extent possible to ensure the greatest reliability in the event of damage. 8.6.2 If there are armed persons in control of the facility, concede as necessary to avoid violence. Do not resist. 8.6.3 Carefully explain to terrorist each routine action normally done for the safety of the facility. This should be done so that routine actions do not cause a misunderstanding. 8.7 Bomb Search procedures 8.7.1 The Aurora Supervisor or Management shall assist the Alaska State Troopers in developing a specific bomb threat search procedure. The critical elements in the procedure are: 1. A search team shall be pre-designated. All facilities shall be segmented. 2. All search personnel shall be trained on the appropriate search methods. 3. Remove all unnecessary personnel to safe areas. 4. Inform search party of where a blast could cause the most damage. 5. Ensure emergency equipment is in working order. 6. If a bomb or suspicious device is found: ^ DO NOT DISTURB the device ^ Clear and mark the location for Alaska State Troopers • Note the device and its qualities (e.g. is it in a box? Color of box? Etc.) ^ Notify incident commander 7. Incident commander will utilize existing evacuation plan, but it will be cleared by Alaska State Troopers before put into action. 9.0 VOLCANO 9.1 The Aurora facilities are in an volcano zone of potential impact from ash in nearby Volcanoes (Redoubt, Spurr, Augustine). It is possible that an eruption from any of these volcanoes could interrupt operations for a significant period of time. Ash fall may occur with little warning and therefore the following recommended actions should save human health and mitigate damage to property. 9.2 Immediate Actions 9.2.1 In the event of a volcanic eruption the Aurora Supervisor or Operator will evaluate the impact from ashfall. If he/she suspects it may have significant ash fall, actions should first be taken to protect life then protect equipment. 9.2.2 Air filters, breathing masks, goggles, water are all stored at the Moquawkie office and Shirleyville Camp. 9.2.3 Aurora Supervisor will notify Aurora Management of situation and planned actions to protect equipment. Print Date: 3/1/2010 Emergency Action Plan Page 7 of 8 ,Aurora Gas, LLC 9.3 Secondary Actions 9.3.1 When the ash fall has stopped, and if conditions permit, conduct a thorough examination of the equipment before bringing back online. Personnel should be looking for ash in buildings, heaters, air intake on engines, etc. Revision Log _ Revision Date Authority Custodian Revision Details October 14, 2005 Ed Jones Ed Jones Initial Procedure February 1, 2009 Chad Helgeson Chad Helgeson Volcano Addition March 1, 2010 Chad Helgeson Chad Helgeson Review Print Date: 3/1/2010 Emergency Action Plan Page 8 of 8 Appendix A Emergency Contact Information DIAL 911 FOR ANY MEDICAL EMERGENCY NIKISKI FIRE DEPT (TRUCKS, FIREFIGHTERS, ETT's AT BELUGA RIVER): ^ (907)-776-8400 ^ At CONOCOPHILLIPS BELUGA RIVER UNIT: (907)-263-3910 OR (907)-263- 3930 (cell) VILLAGE OF TYONEK EMT: ^ (907)-583-2461 VILLAGE OF TYONEK FIRE DEPT: ^ (907)-583-2271 (PETER MERRYMAN) GRANITE POINT TANK FARM ETT: • 907-776-6610 PROVIDENCE HOSPITAL AIR AMBULANCE: ^ (907)-261-3070 OR 1-800-478-5433 PROVIDENCE EMERGENCY ROOM: ^ (907)-261-3111 ALASKA REGIONAL HOSPITAL LIFEFLIGHT AIR AMBULANCE: ^ 1-800-478-9111 AK REGIONAL EMERGENCY ROOM: ^ (907}-264-1222 OR 276-1131 SOLDOTNA CENTRAL PENINSULA HOSPITAL EMERGENCY ROOM: • 907-262-8123 OR -4404 U.S. COAST GUARD: ^ *24 FROM CELL PHONE OR 1-800-478-5555 ERA HELICOPTERS: ^ 907-776-8215 (OSK DOCK, NIKISKI) ^ 248-4422 (ANCHORAGE) CLOSEST HELIPAD: UNOCAL GRANITE POINT TANK FARMCOORDINATES: ^ 61 DEG 01.10 MIN N, 151 DEG 25.25 MIN W CLOSEST LIGHTED AIRSTRIPS: NATIVE VILLAGE OF TYONEK COORDINATES: ^ 61 DEG 4.00 MIN N, 151 DEG 8.00 M1N W CONOCO-PHILLIPS BELUGA RIVER FIELD AIRSTRIP COORDINATES: ^ 61 DEG 10.25 MIN N, 151 DEG 2.28 MIN W KENAI AVIATION: 907-283-4124 SPERNAK AIRWAYS (ANCHORAGE): 272-9475 GREAT NORTHERN AIR (ANCHORAGE): 243-1968 REDISKE AIR (NIKISKI) (907) 776-8985 Appendix A -Emergency Action Plan :Aurora Gas, ZtC HSE Incident Field Guide Priority 1: Safety of Personnel Priority 2: Protection of the Environment Priority 3: Protection of Facilities ~ ENVIRt?IVMENT J~ or Illness Abnormal Condition or Disorder A Bum, Cut, Fracture, Sprain, Amputation, Skin Disease, Poisoning, or Respiratory Disorder Don't Move an Injured Person Unless Absolutely Call for Assistance if Emergency Medical Attention Is Necessary Administer Any First Aid You Are Trained to Provide Report Vehicle Accident Fire or Explosion Any Accident Where Injury Any Occurrence of Fire or or Damage Occurs Explosion Keep the Accident from Getting Worse, Use Hazard Lights and Other Temporary Warning C Report Your Safety Comes First, be Aware of Smoke and Noxious Fumes Immediately Report Any HSE Incident or Near Miss to: d o s (713) 977-5799 Houston (907) 277-1003 Anchorage (713) 899-8103 Mobile jejones~aurorapower.com Cotify Fire Department - Attempt to Safely Control the Release Source i.e. Shut-in Well and Pipeline ~ i C Report Gas Release An Uncontrolled Release of Gas from the Facility that Is Not Planned or Part of Normal Operations Shutdown All Ignition Sources Attempt to Safely Control the Release Source i.e. Close Any Accessible Valves Evacuate Area of Release. Report the Followina: Type of Incident Location Injuries Potential Injuries Release size Source Material Released Possible Hazards Report Swill Any Unplanned Loss of Material from Primary Containment i.e.: Oil, Chemicals, Produced water, Domestic Wastewater, Hazardous Substances, Glycol, Methanol, or Drilling Mud Evaluate Safety, be Aware of Exposure Isolate the Source of the Spill Prevent the Spilled Material from Spreading Report Initiate Cleanup Actions Also Report a "Near Miss" An Unplanned Event, which, Under Slightly Different Circumstances Could Have Resulted in Harm to People, Damage to the Environment, Damage to Property, Loss of Production, or Non- compliance. ~~ Issue Date: October 22, 2003 Appendix C Aurora Emergency Action Plan AURORA GAS WELL/FACILITY LOCATIONS LONE CREEK NO. 1 WELL AND PRODUCTION FACILITY 6-1/2 MILES NORTHWEST OF THE NATIVE VILLAGE OF TYONEK (10 MILES BY ROAD) AND 10 MILES WEST-SOUTHWEST OF BELUGA GAS FIELD/AIRSTRIP (12 MILES BY ROAD) COORDINATES: 61 DEG, 7.44 MIN N LATITUDE 151 DEG, 17.47 MIN W LONGITUDE LONE CREEK NO.3 WELL LOCATION: 61 DEG. 8.02 MIN N, 151 DEG 17.33 MIN. W MEDEVAC LOCATION: 0.9 MILES SOUTH AT THE LONE CREEK NO. 1 WELL • AND PRODUCTION FACILITY: 6-1/2 MILES NORTHWEST OF THE NATIVE VILLAGE OF TYONEK (10 MILES WEST-SOUTHWEST OF BELUGA GAS FIELD/AIRSTRIP (12 MILES BY ROAD) COORDINATES: 61 DEG, 7.44 MIN N LATITUDE 151 DEG, 17.47 MIN W LONGITUDE NICOLAI CREEK UNIT NO. 1,2,3 & 9 WELL LOCATIONS LOCATION: WEST END OF SWIRLEYVILLE (NICOLAI CREEK) AIRSTRIP COORDINATES: 61 DEG 00.83 MIN N LATITUDE 151 DEG 26.04 MIN W LONGITUDE MOQUAWKIE NO. 1 8- 3 WELL LOCATIONS MOQUAWKIE AIRSTRIP COORDINATES: 61 DEG 04' 16.139" N LAT-TUDE 151 DEG 19' 07.766" W W LONGITUDE THREE MILE CREEK UNIT NO. 1 PAD AND FACILITY LOCATION: 7.5 MILES NORTH NORTHWEST OF THE NATIVE VILLAGE OF TYONEK (13 MILES BY ROAD) AND 5.75 MILES WEST OF BELUGA GAS FIELD/AIRSTRIP (15 MILES BY ROAD) COORDINATES: (OLD SUPERIOR AIRSTRIP, WHERE ROAD CROSSES STRIP): NAD 27 UTM: N: 2,616,324, E: 285,003 ZN 4 OR NAD 83 LATILONGS: 61 DEG, 09.30 MIN N LATITUDE 151 DEG, 13.17 MIN W LONGITUDE ASPEN NO. 1 WELL LOCATION HELICOPTER LANDING ZONE AT WELL SITE GPS COORDINATES: 61 DEG 04' 53.94" N LATITUDE 151 DEG 15' 06.90" W W LONGITUDE KALOA 2 8~ 4 WELL SITES AND FACILITY HERC STRIP AT GRANITE POINT COORDINATES: NORTH LATITUDE 61 DEG, 01.149 MIN WEST LONGITUDE 151 DEG, 20.056 MIN Appendix C -Aurora Emergency Action Plan FOUR-POINT TEST DATA Oct-02 BHP bomb set at 2279' M® (2020' TVD) AURORA GAS, LLC Perfs at 2426-2476', 2700-2716', and 2893-2916' MD NICOLAI CREEK UNIT NO. 2 DATE TIME SURFACE WH MEASRD BHT TEST SEP MTR ORIFICE METER RATE CUM CHOKE TBG PRES TEMP BHP PRESS TEMP STATIC DIFF MCFPD WTR psig deg F psia deg F psig deg F (bbl) atm 19.2 gauge at surface 974.7 47.5 24-Oct-02 1344 961 37.6 1021.7 72.1 (6g 5°°) 26 1400 883 980 72.2 490 26 1440 881 1029 75 390 4.9 1.5 643 1510 755 1002 75.2 500 36 5.8 2.3 1167 unloading 1530 818 1036 75.8 490 36 6 2.2 1155 5.6 water 30 1609 939 38 1034 75.5 710 36 7.4 3 1943 8.4 30 1630 948 26 1048 75.5 490 7.3 3 1916 (; ¢- OPEN 32~d 1648 918 1060 75.4 590 39 6.5 4,2 2389 32 1710 921 1011 580 6.3 4 2205 ICING UP 32 1730 849 1036 600 30 6.4 5.4 3024 1800 866 35 1005 75.5 600 31 6.5 5.7 3242 8.4 1820 883 34 999 700 35 7.1 5.6 3479 1845 .__ _ _ _ 320 34 997 75. 3 790 37 7.3 5.5 51 3 3 .' ~ trt 1900 _._ 905 _ __ _ _ .... _ _ _ _. 995 . . _ ... _ _ 790 _ _ 37 7.4 ~_ , _ _ 5.7 , .. , 3691 , ~ 1949 892 988 75.1 810 7.6 6.4 4256 2017 897 986 820 41 7.7 5.8 3908 2030 894 986 820 41 7.7 6.1 4110 38 2036 .~ X90_ . _ _ 33 983 _ _ _. _. _._ 820_. 41 7.7 6.25 4211 ~f ~'° 2046 8Q0 33 969 770 39 6.8 7.75 _ 4611 2100 850 970 74.5 750 40 7.3 7.7 4918 2130 835 962 74.8 730 40 7.1 8.15 5063 2200 819 .~ ~ _ ..._ 33 962 700 40 6.95 8.35 5078 '?~ '~ `° 8.4 SI 2206 _ .959 74.6 10 sec 973 20 sec 997 30 sec 1013 • • 40 sec 1024 ORIFICE METER PARAMETERS: 50 sec 1032 4.026" RUN; 1-1/2" ORIFICE, 1 min 1036 0-1500 PSI, 0-200" , L-10 CHARTS 2 min 1042 M=5.477; C'= 665.6974 3 min 1043.5 Q (mcfpd)= M*C'*H*P*24J1000 4 min 1044.2 Q= 87.5*H*P 5 min 1044.35 /(J~d,~f,~ ~ 2216 ~ 983 ~. y~ ~ri 2230 982 ~D®~~.-~ 2236 1044,5 73.8 r~ ~ F' (2306 l 1044.85 60 hr 976 1034.3 72.2 atm 17.1 GRADIENT SURVEYS 71ME DEPTH DEPTH STATIC GRAD TO DELTA T Gead to TEMP ( MD) (TVD) PRESR SURF GRAD Suef ( KB) psis psitft psiJft degJ100' deg F 10/23/2003 1510 14 14 19.2 atm (RIH) 1517 14 14 975.7 52 1534 500 496.5 986 0.021 0.000 52 1547 1000 978 996.8 0.022 -0.102 51 1558 1500 1412 1006.9 0.023 0.354 57 1608 2000 1813 1016 0.023 0.607 63 1617 2327 2054 1021.8 0.024 0.828 69 packer 1623 2400 2107 1023.1 0.025 0.902 71 1635 2451 2144 1024.1 0.472 0.027 0.979 73 mid pert--top set 1641 2500 2179 1025 0.465 0.026 1.010 74 1647 2600 2255 1044.5 0.458 0.257 1.020 75 static water level 1659 2708 2337 1085.5 0.459 0.500 1.095. 77.6 mid pert--middle set 1705 2800 2411 1121.6 0.460 0.488 1.078 78 1717 2905 2494 1164.4 0.462 0.516 1.067 78.6 mid pert--btm set Mid pert depth is 2671' M D or 2309' TVD. Extrapolate d SIP = 1071.5 psis at 76.4 deg F TIME nAD TVD PRESSR GRAD n GRAD T GRAD TEIwP 10/27/2003 1218 14 14 17.7 atm ~POH) 1259 2905 2494 1085.1 0.431 1.047 76.1 mid pert--btm set 1305 2800 2411 1043.6 0.428 0.500 1.132 77.3 1316 2705 2335 1040.6 0.441 0.039 1.195 77.9 mid pert--middle set 1322 2600 2255 1038.7 0.456 0.024 1.233 77.8 1328 2500 2179 1037.1 0.471 0.021 1.271 77.7 1338 2451 2144 1036.3 0.479 0.023 1.269 77.2 mid perf--top set 1344 2400 2107 1035.6 0.487 0.019 1.248 76.3 1350 2327 2054 1034.4 0.023 1.237 75.4 packer 1358 2000 1813 1028.8 0.023 1.269 73 1408 1500 1412 1019.6 0.023 1,282 68.1 1416 987 966 1009.1 0.024 1.387 63.4 1425 500 496.5 998 0.024 1.531 57.6 1434 14 14 986.3 0.024 50 Mid pert depth is 2671' MD or 2309' TVD. Extrapolated SIP = 1040.0 psis at 77.1 deg F (Appears to be cross fl ow and/or possible depletion: multiple zones and water in wellbore make it difficult to analyze). SHORT TESTS OF IN DIVIDUAL ZONES AFT ER PERFORATING (isolated and w/o sand control screens) STABLZD FLOW DATE PERF INTERVAL CHOKE FTP RATE TIAAE SITP TOP BTM 64"' PSIG IIACFPD RAIN PSIG 13~flIPH 8/1/2002 2893 2916 28 840 4988 60 It mist Very stable, clean up slightly 1080 build up in 1 min 1090 30 min SI 8/3/2003 2700 2716 20 450 4241 30 0.7 drying up 16 550 4407 30 choke washing out 12 875 1855 40 940 1 min SI 1000 30 min 8/6/2003 2426 2476 40 725 3289 60 4.2 32 760 3366 60 2.8 drying up 920 1 min SI 1-3/4" ORIFICE, Q= 120.4758 * H*P 960 30 min SI Aurora Gas hlicolai Crel~#2 Run in Hole Pressure and Temperature vs Depth Analysis Static Temperature (degrees Fj 0 20 40 60 3000 -F a 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 Pressure (psig~ Aurora Gas Nicalai Creek # ~ Pull Out of Hole Static Pressure and Temperature vs Depth Analysis Temperature (degrees Fj 0 2a 40 60 3000 -F 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 Pressure (psigj i• Aurora Gas Start Test Date: 2002J10~23 120 v 60C a` a~ rn m ~~ IU 20 30 q0 ~~~ 0 i s B i f~ a$~ i 50 60 70 g0 90 100 Gauge 1 Time , hr NCB 10p 90 60 c m ~~ rn lL 70 ~ co m N 1~ 40 110 ***************w************************* Date: 12-03-2010 * Neotechnology Consultants Ltd. * Time: 10:56:03 AM * * * WELLFLO 7 - Version•7.231 * * Licensee: Aurora Power ***************************************** ** CAL C U L A T I O N O P T I O N S ** -------------------------------------------------------------------------------- TITLE: -------------------------------------------------------------------------------- INPUT DATA FILE: NC2 Inj simulation 3-11-10 1065psi.WFW OUTPUT FILES: NC2 Inj simulation 3-11-10 1065psi.MIN NC2 Inj simulation 3-11-10 1065psi.MAX NC2 Inj simulation 3-11-10 1065psi.SUM NC2 Inj simulation 3-11-10 1065psi.PLT CALCULATION DIRECTION: Top to Bottom FLOW DIRECTION: Injection FLOW PATH: Tubing FLUID SYSTEM: Compositional CALCULATION METHODS SELECTIONS FOR VERTICAL UPFLOW OVERALL SELECTION: Gregory et al FLOW REGIME PREDICTION: Gregory et al LIQUID HOLDUP CALCULATION: Gregory FRICTION LOSS CALCULATION: Gregory ANNULAR-MIST FLOW MODEL: Gray Revised SLUG OPTION: Original Method SELECTIONS FOR VERTICAL DOWNFLOW OVERALL SELECTION: Beggs and Brill Revised FLOW PATTERN PREDICTION: Beggs and Brill Revised LIQUID HOLDUP CALCULATION: Beggs and Brill Revised FRICTION LOSS CALCULATION: Beggs and Brill SELECTIONS FOR HORIZONTAL AND INCLINED FLOW OVERALL SELECTION: Eaton, Oliemans FLOW PATTERN PREDICTION: Taitel and Dukler LIQUID HOLDUP CALCULATION: Eaton FRICTION LOSS CALCULATION: Olieman UPHILL CORRECTION: No Correction DOWNHILL CORRECTION: Recovery Based on Gas Density FLUID TEMPERATURE PROFILE: Specified Case Number: 1 ------------------------------------ SPECIFIED AND CALCULATED SYSTEM DATA WELLHEAD Pressure: to be calculated Temperature: 50.0 deg F BOTTOM-HOLE Pressure: 1070.0 psia Temperature: 80.0 deg F FLOW RATES Equivalent Gas Volume Flow: 0.00 MMSCfd Water Volume Flow: 0.00 Bbl/day Case Number: 2 - ------------------------------------ SPECIFIED AND CALCULATED SYSTEM DATA ------------------------------------ WELLHEAD Pressure: to be calculated Temperature: 50.0 deg F BOTTOM-HOLE Pressure: 1070.0 psia Temperature: 80.0 deg F FLOW RATES Equivalent Gas Volume Flow: 5.00 MMSCfd Water Volume Flow: 0.00 Bbl/day Case Number: 3 ------------------------------------ SPECIFIED AND CALCULATED SYSTEM DATA ------------------------------------ WELLHEAD Pressure: to be calculated Temperature: 50.0 deg F BOTTOM-HOLE Pressure: 1070.0 psia LOW RATES Temperature: 80.0 deg F Equivalent Gas Volume Flow: 10.00 MMSCfd Water Volume Flow: 0.00 Bbl/day Case Number: 4 --------------------- SPECIFIED AND CALCULA --------------------- WELLHEAD Pressure: Temperature: BOTTOM-HOLE Pressure: Temperature: FLOW RATES --------------- TED SYSTEM DATA --------------- to be calculated 50.0 deg F 1070.0 psia 80.0 deg F Equivalent Gas Volume Flow: 15.00 MMscfd Water Volume Flow: 0.00 Bbl/day Case Number: 5 ------------------------------------ SPECIFIED AND CALCULATED SYSTEM DATA ------------------------------------ WELLHEAD Pressure: to be calculated Temperature: 50.0 deg F BOTTOM-HOLE Pressure: 1070.0 psia Temperature: 80.0 deg F FLOW RATES Equivalent Gas Volume Flow: 20.00 MMSCfd water volume Flow: 0.00 Bbl/day INJECTION PARAMETERS AND RESULTS MA7{ GAS ESTIMATED TOTAL TOTAL TOTAL VOLUME TOTAL TOTAL STATIC LIQUID CA SE GAS HC LIQUID WATER Ptop Pbot Ttop Tbot FRACTION LIQ. HOLDUP GAS PACK COLUMN HEIGHT (MMSCfd) (Bbl/day) (Bbl/day) (psia) (psia) --- (deg F) --------- (deg F) -------- --------- (bbl) --------------- (scf) ------------ (ft) ------------- -- ---- 1 ------------ 0.000 ------------- 0.000 -------------- 0.000 ----------- 1007.9 ------- 1069.2 50.0 80.0 1.0000 0.0 15204.8 0.0 2 4.989 0.000 0.000 1022.9 1070.0 50.0 80.0 1.0000 0.0 15303.4 0.0 3 9.977 0.000 0.000 1063.7 1069.9 50.0 80.0 1.0000 0.0 15553.4 0.0 4 14.966 0.000 0.000 1127.6 1069.2 50.0 80.0 1.0000 0.0 15949.5 0.0 5 19.954 0.000 0.000 1211.8 1069.9 50.0 80.0 1.0000 0.0 16504.1 0.0 ***************************************** Date: 12-03-2010 * Neotechnology Consultants Ltd. * Time: 10:56:03 AM * * * WELLFLO 7 - Version 7.231 * ***************************************** * Licensee: Aurora Power ** CAL C U L A T I O N O P T I O N S ** -------------------------------------------------------------------------------- TITLE: -------------------------------------------------------------------------------- INPUT DATA FILE: NC2 Inj simulation 3-11-10 1065psi.WFW OUTPUT FILES: NC2 Inj simulation 3-11-10 1065psi.MIN NC2 Inj simulation 3-11-10 1065psi.MAX NC2 Inj simulation 3-i1-10 1065psi.SUM NC2 Inj simulation 3-11-10 1065psi.PLT CALCULATION DIRECTION: Top to Bottom FLOW DIRECTION: Injection FLOW PATH: Tubing FLUID SYSTEM: Compositional CALCULATION METHODS SELECTIONS FOR VERTICAL UPFLOW OVERALL SELECTION: FLOW REGIME PREDICTION: LIQUID HOLDUP CALCULATION: FRICTION LOSS CALCULATION: ANNULAR-MIST FLOW MODEL: SLUG OPTION: Gregory et al Gregory et al Gregory Gregory Gray Revised Original Method SELECTIONS FOR VERTICAL DOWNFLOW OVERALL SELECTION: Beggs and Brill Revised FLOW PATTERN PREDICTION: Beggs and Brill Revised LIQUID HOLDUP CALCULATION: Beggs and Brill Revised FRICTION LOSS CALCULATION: Beggs and Brill SELECTIONS FOR HORIZONTAL AND INCLINED FLOW OVERALL SELECTION: FLOW PATTERN PREDICTION: LIQUID HOLDUP CALCULATION: FRICTION LOSS CALCULATION: UPHILL CORRECTION: DOWNHILL CORRECTION: Eaton, Oliemans Taitel and Dukler Eaton Olieman No Correction Recovery Based on Gas Density FLUID TEMPERATURE PROFILE: Specified FLUID PROPERTIES Compositional Fluid Properties Procedure Recomendation Basis: User Specified PVT Behaviour and Transport Property Procedures EQUATION OF STATE: VMG APRD LIQUID DENSITY: Calculated by Equation of State WATER TREATED AS: free water Production Fluid Component Mole Fraction HELIUM 0.000 H2 0.000 N2 9.1700e-003 C02 3.0700e-003 H2S 0.000 C1 -0.987 C2 6.S000e-004 C3 0.000 I-C4 0.000 N-C4 0.000 I-CS 0.000 N-CS 0.000 N-C6 6.0000e-005 N-C7 0.000 N-C8 0.000 N-C9 0.000 N-C10 0.000 N-C11 0.000 N-C12 0.000 N-C13 0.000 N-C14 0.000 N-C15 0.000 N-C16 0.000 N-C17 0.000 N-C18 0.000 N-C19 0.000 N-C20 0.000 N-C21 0.000 N-C22 0.000 N-C23 0.000 N-C24 0.000 N-C25 0.000 N-C26 0.000 N-C27 0.000 N-C28 0.000 N-C29 0.000 N-C30 0.000 BENZENE 0.000 TOLUENE 0.000 ETHYLBENZENE 0.000 O-XYLENE 0.000 M-XYLENE 0.000 P-XYLENE 0.000 CYCLO-CS 0.000 M-CYCLO-CS 0.000 CYCLOHEXANE 0.000 M-CYCLO-C6 0.000 1,2,4 TMB 0.000 AMMONIA 0.000 CARBON MONOXIDE 0.000 OXYGEN 0.000 ARGON 0.000 GAS VISCOSITY: Dean and Stiel (Compositional) LIQUID VISCOSITY: Van Velzen et al/Letsou and Stiel ETHYLENE 0.000 PROPYLENE 0.000 1-BUTYLENE 0.000 I-BUTENE 0.000 CIS-2-BUTYLENE 0.000 TRANS-2-BUTYLENE0.000 PENTENE 0.000 REXENE 0.000 HEPTENE .0.000 OCTENE 0.000 PROPADIENE 0.000 1,2 BUTADIENE 0.000 1,3 BUTADIENE 0.000 WATER 0.000 METHANOL 0.000 ETHYLENE GLYCOL 0.000 TEG 0.000 Compositional Fluid #1 Component Mole Fraction HELIUM 0.000 H2 0.000 N2 9.1700e-003 CO2 3.0700e-003 H2S 0.000 Cl 0.987 C2 6.8000e-004 C3 0.000 I-C4 0.000 N-C4 0.000 I-CS 0.000 N-CS 0.000 N-C6 6.OOOOe-005 N-C7 0.000 N-C8 0.000 N-C9 0.000 N-C10 0.000 N-C11 0.000 N-C12 0.000 N-C13 0.000 N-C14 0.000 N-C15 0.000 N-C16 0.000 N-C17 0.000 N-C18 0.000 N-C19 0.000 N-C20 0.000 N-C21 0.000 N-C22 0.000 N-C23 0.000 N-C24 0.000 N-C25 0.000 N-C26 0.000 N-C27 0.000 N-C28 0.000 N-C29 0.000 N-C30 0.000 BENZENE 0.000 TOLUENE 0.000 ETHYLBENZENE 0.000 O-XYLENE 0.000 M-XYLENE 0.000 P-XYLENE 0.000 CYCLO-CS 0.000 M-CYCLO-CS 0.000 CYCLOHEXANE 0.000 M-CYCLO-C6 0.000 1,2,4 TMB 0.000 AMMONIA 0.000 CARBON MONOXIDE 0.000 OXYGEN 0.000 ARGON 0.000 ETHYLENE 0.000 PROPYLENE 0.000 1-BUTYLENE 0.000 I-BUTENE 0.000 CIS-2-BUTYLENE 0.000 TRANS-2-BUTYLENE0.000 PENTENE 0.000 HEXENE 0.000 HEPTENE 0.000 OCTENE 0.000 PROPADIENE 0.000 1,2 BUTADIENE 0.000 1,3 BUTADIENE 0.000 WATER 0.000 METHANOL 0.000 ETHYLENE GLYCOL 0.000 TEG 0.000 Drilling Profile Report Inclination Azimuth Measured Depth (deg) (deg) (ft) 0.000 0.000 0.000 4.000 0.000 400.000 10.000 0.000 600.000 19.000 0.000 800.000 28.000 0.000 1200.000 37.000 0.000 1934.000 42.000 0.000 2100.000 45.000 0.000 2426.000 40.000 0.000 2700.000 37.000 0.000 2893.000 37.000 0.000 3100.000 42.000 0.000 5011.000 Case Number: 1 TITLE: INJECTION STRING CASING TUBING ------------------------------------ SPECIFIED AND CALCULATED SYSTEM DATA ------------------------------------ Flow String: Tubing String Length: 2916.0 ft ID Depth (inch) (ft) 6.276 0.0 Roughness: 0.00180 inch C~ ID OD Depth (inch) (inch) (f t) 2.992 3.500 0.0 Roughness: 0.00180 inch 0.0 ft Depth ~ 0.0 ft Depth WELLHEAD Pressure: to be calculated Temperature: 50.0 deg F BOTTOM-HOLE Pressure: 1070.0 psia Temperature: 80.0 deg F FLOW RATES Equivalent Gas Volume Flow: 0.00 MMSCfd Water Volume Flow: 0.00 Bbl/day DETAILED RESULTS I SUPERFICIAL T DENSITY VISCOSITY VELOCITIES PREDICTED VOLUME CALL. PRESSURE DROP CALCULATED E DEPTH (lb/ft3) (cP) (ft/sec) FLOW FRACTION TEMP. (psi) PRESSURE R (ft) GAS LIQUID GAS LIQUID GAS LIQUID PATTERN GAS LIQUID (deg F) FRICTION HYDROST. (psia) 100.0 3.55 N/A 0.0122 N/A 0.000 0.000 SPL 1.0000 0.0000 51.0 0.000 -2.466 1010.37 200.0 3.55 N/A 0.0122 N/A 0.000 0.000 SPL 1.0000 0.0000 52.1 0.000 -2.464 1012.84 1 300.0 3.55 N/A 0.0123 N/A 0.000 0.000 SPL 1.0000 0.0000 53.1 0.000 -2.462 1015.30 1 400.0 3.55 N/A 0.0123 N/A 0.000 0.000 SPL 1.0000 0.0000 54.1 0.000 -2.461 1017.76 2 500.0 3.54 N/A 0.0122 N/A 0.000 0.000 SPL 1.0000 0.0000 55.1 0.000 -2.442 1020.20 1 600.0 3.54 N/A 0.0122 N/A 0.000 0.000 SPL 1.0000 0.0000 56.2 0.000 -2.440 1022.64 2 700.0 3.54 N/A 0.0122 N/A 0.000 0.000 SPL 1.0000 0.0000 57.2 0.000 -2.377 1025.02 1 800.0 3.54 N/A 0.0123 N/A 0.000 0.000 SPL 1.0000 0.0000 58.2 0.000 -2.376 1027.39 2 900.0 3.53 N/A 0.0123 N/A 0.000 0.000 SPL 1.0000 0.0000 59.3 0.000 -2.249 1029.64 1 1000.0 3.53 N/A 0.0123 N/A 0.000 0.000 SPL 1.0000 0.0000 60.3 0.000 -2.247 1031.89 1 1100.0 3.53 N/A 0.0123 N/A 0.000 0.000 SPL 1.0000 0.0000 61.3 0.000 -2.245 1034.14 1 1200.0 3.53 N/A 0.0123 N/A 0.000 0.000 SPL 1.0000 0.0000 62.3 0.000 -2.243 1036.38 2 1300.0 3.52 N/A 0.0124 N/A 0.000 0.000 SPL 1.0000 0.0000 63.4 0.000 -2.061 1038.44 1 1400.0 3.52 N/A 0.0124 N/A 0.000 0.000 SPL 1.0000 0.0000 64.4 0.000 -2.059 1040.50 1 1500.0 3.52 N/A 0.0124 N/A 0.000 0.000 SPL 1.0000 0.0000 65.4 0.000 -2.057 1042.56 1 1600.0 3.51 N/A 0.0124 N/A 0.000 0.000 SPL 1.0000 0.0000 66.5 0.000 -2.055 1044.61 1 1700.0 3.51 N/A 0.0124 N/A 0.000 0.000 SPL 1.0000 0.0000 67.5 0.000 -2.053 1046.66 1 1800.0 3.51 N/A 0.0124 N/A 0.000 0.000 SPL 1.0000 0.0000 68.5 0.000 -2.051 1048.72 1 1900.0 3.50 N/A 0.0125 N/A 0.000 0.000 SPL 1.0000 0.0000 69.5 0.000 -2.049 1050.76 1 1934.0 3.50 N/A 0.0125 N/A 0.000 0.000 SPL 1.0000 0.0000 69.9 0.000 -0.696 1051.46 2 2034.0 3.50 N/A 0.0125 N/A 0.000 0.000 SPL 1.0000 0.0000 70.9 0.000 -1.873 1053.33 1 2100.0 3.49 N/A 0.0125 N/A 0.000 0.000 SPL 1.0000 0.0000 71.6 0.000 -1.235 1054.57 2 2200.0 3.49 N/A 0.0125 N/A 0.000 0.000 SPL 1.0000 0.0000 72.6 0.000 -1.758 1056.32 1 2300.0 3.49 N/A 0.0125 N/A 0.000 0.000 SPL 1.0000 0.0000 73.7 0.000 -1.756 1058.08 1 2400.0 3.48 N/A 0.0126 N/A 0.000 0.000 SPL 1.0000 0.0000 74.7 0.000 -1.754 1059.84 1 2426.0 3.48 N/A 0.0126 N/A 0.000 0.000 SPL 1.0000 0.0000 75.0 0.000 -0.456 1060.29 2 2526.0 3.48 N/A 0.0126 N/A 0.000 0.000 SPL 1.0000 0.0000 76.0 0.000 -1.779 1062.07 1 2626.0 3.47 N/A 0.0126 N/A 0.000 0.000 SPL 1.0000 0.0000 77.0 0.000 -1.777 1063.85 1 2654.0 3.47 N/A 0.0126 N/A 0.000 0.000 SPL 1.0000 0.0000 77.3 0.000 -0.497 1064.34 1 2700.0 3.47 N/A 0.0126 N/A 0.000 0.000 SPL 1.0000 0.0000 77.8 0.000 -0.816 1065.16 2 2746.0 3.47 N/A 0.0126 N/A 0.000 0.000 SPL 1.0000 0.0000 78.3 0.000 -0.866 1066.03 1 2849.5 3.46 N/A 0.0126 N/A 0.000 0.000 SPL 1.0000 0.0000 79.3 0.000 -1.948 1067.97 1 2893.0 3.46 N/A 0.0126 N/A 0.000 0.000 SPL 1.0000 0.0000 79.8 0.000 -0.818 1068.79 1 2916.0 3.46 N/A 0.0127 N/A 0.000 0.000 SPL 1.0000 0.0000 80.0 0.000 -0.441 1069.22 SUMMARY: CALCULATED WELLHEAD PRESSURE: 1007.9 psia SPECIFIED WELLHEAD TEMPERATURE: 50.0 deg F SPECIFIED BOTTOM-HOLE PRESSURE: 1069.2 psia SPECIFIED BOTTOM-HOLE TEMPERATURE: 80.0 deg F Predicted Pressure Loss: -61.3 psi Friction Loss: 0.0 psi Elevation Loss: -61.3 psi Kinetic Loss: 0.0 psi In-line Facilities Loss: 0.0 psi Total Liquid Holdup: 0.0 bbl Total Gas Pack: 15204.8 scf Estimated Static Liquid Column Height: 0.0 ft Measured Depth: 2916.0 ft Case Number: 2 TITLE: INJECTION STRING ------------------------------------ SPECIFIED AND CALCULATED SYSTEM DATA ------------------------------------ CASING TUBING 0.0 ft Depth C1 0.0 ft Depth Flow String: Tubing String Length: 2916.0 ft ID Depth (inch) (ft) 6.276 0.0 Roughness: 0.00180 inch Q ID OD Depth (inch) (inch) (ft) 2.992 3.500 0.0 Roughness: 0.00180 inch WELLHEAD Pressure: to be calculated Temperature: 50.0 deg F BOTTOM-HOLE Pressure: 1070.0 psia Temperature: 80.0 deg F FLOW RATES Equivalent Gas Volume Flow: 5.00 MMSCfd Water Volume Flow: 0.00 Bbl/day DETAILED RESULTS I SUPERFICIAL T DENSITY VISCOSITY VELOCITIES PREDICTED VOLUME CALL. PRESSURE DROP CALCULATED E DEPTH (lb/ft3) (cP) (ft/sec) FLOW FRACTION TEMP. (psi) PRESSURE R (ft) GAS LIQUID GAS LIQUID GAS LIQUID PATTERN GAS LIQUID (deg F) FRICTION HYDROST. (psia) 100.0 3.61 N/A 0.0123 N/A 14.008 0.000 SPT 1.0000 0.0000 51.0 0.544 -2.507 1024.82 200.0 3.61 N/A 0.0123 N/A 14.025 0.000 SPT 1.0000 0.0000 52.1 0.544 -2.504 1026.78 1 300.0 3.60 N/A 0.0123 N/A 14.042 0.000 SPT 1.0000 0.0000 53.1 0.545 -2.501 1028.74 1 400.0 3.60 N/A 0.0123 N/A 14.060 0.000 SPT 1.0000 0.0000 54.1 0.546 -2.498 1030.69 2 500.0 3.59 N/A 0.0122 N/A 14.077 0.000 SPT 1.0000 0.0000 55.1 0.546 -2.477 1032.62 1 600.0 3.59 N/A 0.0122 N/A 14.095 0.000 SPT 1.0000 0.0000 56.2 0.547 -2.474 .1..034.55 2 700.0 3.59 N/A 0.0123 N/A 14.113 0.000 SPT 1.0000 0.0000 57.2 0.548 -2.408 1036.41 1 800.0 3.58 N/A 0.0123 N/A 14.132 0.000 SPT 1.0000 0.0000 58.2 0.549 -2.405 1038.27 2 900.0 3.58 N/A 0.0123 N/A 14.151 0.000 SPT 1.0000 0.0000 59.3 0.549 -2.275 1039.99 1 1000.0 3.57 N/A 0.0123 N/A 14.171 0.000 SPT 1.0000 0.0000 60.3 0.550 -2.272 1041.72 1 1100.0 3.57 N/A 0.0123 N/A 14.191 0.000 SPT 1.0000 0.0000 61.3 0.551 -2.269 1043.43 1 1200.0 3.56 N/A 0.0124 N/A 14.212 0.000 SPT 1.0000 0.0000 62.3 0.552 -2.265 1045.15 2 1300.0 3.56 N/A 0.0124 N/A 14.233 0.000 SPT 1.0000 0.0000 63.4 0.553 -2.080 1046.67 1 1400.0 3.55 N/A 0.0124 N/A 14.256 0.000 SPT 1.0000 0.0000 64.4 0.553 -2.077 1048.20 1 1500.0 3.54 N/A 0.0124 N/A 14.279 0.000 SPT 1.0000 0.0000 65.4 0.5.54 -2.074 1049.72 1 1600.0 3.54 N/A 0.0124 N/A 14.302 0.000 SPT 1.0000 0.0000 66.5 0.555 -2.070 1051.23 1 1700.0 3.53 N/A 0.0124 N/A 14.325 0.000 SPT 1.0000 0.0000 67.5 0.556 -2.067 1052.75 1 1800.0 3.53 N/A 0.0125 N/A 14.347 0.000 SPT 1.0000 0.0000 68.5 0.557 -2.064 1054.25 1 1900.0 3.52 N/A 0.0125 N/A 14.370 0.000 SPT 1.0000 0.0000 69.5 0.558 -2.061 1055.76 1 1934.0 3.52 N/A 0.0125 N/A 14.385 0.000 SPT 1.0000 0.0000 69.9 0.190 -0.700 1056.26 2 2034.0 3.51 N/A 0.0125 N/A 14.402 0.000 SPT 1.0000 0.0000 70.9 0.559 -1.882 1057.58 1 2100.0 3.51 N/A 0.0125 N/A 14.423 0.000 SPT 1.0000 0.0000 71.6 0.370 -1.241 1058.46 2 2200.0 3.50 N/A 0.0125 N/A 14.444 0.000 SPT 1.0000 0.0000 72.6 0.561 -1.765 1059.66 1 2300.0 3.50 N/A 0.0125 N/A 14.471 0.000 SPT 1.0000 0.0000 73.7 0.562 -1.761 1060.86 1 2400.0 3.49 N/A 0.0126 N/A 14.498 0.000 SPT 1.0000 0.0000 74.7 0.563 -1.758 1062.06 1 2426.0 3.49 N/A 0.0126 N/A 14.515 0.000 SPT 1.0000 0.0000 75.0 0.147 -0.457 1062.37 2 2526.0 3.48 N/A 0.0126 N/A 14.532 0.000 SPT 1.0000 0.0000 76.0 0.564 -1.783 1063.58 1 2626.0 3.48 N/A 0.0126 N/A 14.558 0.000 SPT 1.0000 0.0000 77.0 0.565 -1.779 1064.80 1 2654.0 3.47 N/A 0.0126 N/A 14.575 0.000 SPT 1.0000 0.0000 77.3 0.158 -0.498 1065.14 2 2700.0 3.47 N/A 0.0126 N/A 3.314 0.000 SPT 1.0000 0.0000 77.8 0.006 -0.817 1065.95 2 2746.0 3.47 N/A 0.0126 N/A 3.316 0.000 SPT 1.0000 0.0000 78.3 0.006 -0.867 1066.81 1 2849.5 3.47 N/A 0.0126 N/A 3.319 0.000 SPT 1.0000 0.0000 79.3 0.013 -1.949 1068.75 1 2893.0 3.46 N/A 0.0126 N/A 3.321 0.000 SPT 1.0000 0.0000 79.8 0.005 -0.819 1069.56 1 2916.0 3.46 N/A 0.0127 N/A 3.323 0.000 SPT 1.0000 0.0000 80.0 0.003 -0.442 1069.99 SUMMARY: CALCULATED WELLHEAD PRESSURE: 1022.9 psia SPECIFIED WELLHEAD TEMPERATURE: 50.0 deg F SPECIFIED BOTTOM-HOLE PRESSURE: 1070.0 psia SPECIFIED BOTTOM-HOLE TEMPERATURE: 80.0 deg F Predicted Pressure Loss: -47.1 psi Friction Loss: 14.7 psi Elevation Loss: -61.9 psi Kinetic Loss: -0.0 psi In -line Facilities Loss: 0.0 psi Total Liquid Holdup: 0.0 bbl Total Gas Pack: 15303.4 scf Estimated Static Liquid Column Height: 0.0 ft Measured Depth: 2916.0 ft Case Number: 3 TITLE: INJECTION STRING CASING TUBING ------------------------------------ SPECIFIED AND CALCULATED SYSTEM DATA ------------------------------------ Flow String: Tubing String Length: 2916.0 ft ID Depth (inch) (ft) 6.276 0.0 Roughness: 0.00180 inch @ ID OD Depth (inch) (inch) (ft) 2.992 3.500 0.0 Roughness: 0.00180 inch 0.0 ft Depth @ 0.0 ft Depth WELLHEAD Pressure: to be calculated Temperature: 50.0 deg F BOTTOM-HOLE Pressure: 1070.0 psia Temperature: 80.0 deg F FLOW RATES Equivalent Gas Volume Flow: 10.00 MMscfd water Volume Flow: 0.00 Bbl/day DETAILED RESULTS I SUPERFICIAL T DENSITY VISCOSITY VELOCITIES PREDICTED VOLUME CALC. PRESSURE DROP CALCULATED E DEPTH (lb/ft3) (cP) (ft/sec) FLOW FRACTION TEMP. (psi) PRESSURE R (ft) GAS LIQUID GAS LIQUID GAS LIQUID PATTERN GAS LIQUID (deg F) FRICTION HYDROST. (psia) 100.0 3.78 N/A 0.0124 N/A 26.800 0.000 SPT 1.0000 0.0000 51.0 2.063 -2.621 1064.27 .. 200.0 3.77 N/A 0.0124 N/A 26.879 0.000 SPT 1.0000 0.0000 52.1 2.069 -2.613 1064.81 2 300.0 3.75 N/A 0.0124 N/A 26.957 0.000 SPT 1.0000 0.0000 53.1 2.075 -2.605 1065.34 2 400.0 3.74 N/A 0.0124 N/A 27.035 0.000 SPT 1.0000 0.0000 54.1 2.081 -2.598 1065.86 2 500.0 3.73 N/A 0.0123 N/A 27.114 0.000 SPT 1.0000 0.0000 55.1 2.087 -2.572 1066.35 2 600.0 3.72 N/A 0.0123 N/A 27.193 0.000 SPT 1.0000 0.0000 56.2 2.093 -2.564 1066.82 2 700.0 3.71 N/A 0.0124 N/A 27.274 0.000 SPT 1.0000 0.0000 57.2 2.099 -2.492 1067.21 2 800.0 3.70 N/A 0.0124 N/A 27.355 0.000 SPT 1.0000 0.0000 58.2 2.105 -2.485 1067.59 2 900.0 3.69 N/A 0.0124 N/A 27.439 0.000 SPT 1.0000 0.0000 59.3 2.112 -2.347 1067.83 2 1000.0 3.68 N/A 0.0124 N/A 27.525 0.000 SPT 1.0000 0.0000 60.3 2.119 -2.339 1068.05 2 1100.0 3.67 N/A 0.0124 N/A 27.610 0.000 SPT 1.0000 0.0000 61.3 2.125 -2.332 1068.25 2 1200.0 3.65 N/A 0.0124 N/A 27.697 0.000 SPT 1.0000 0.0000 62.3 2.132 -2.325 1068.45 2 1300.0 3.64 N/A 0.0124 N/A 27.786 0.000 SPT 1.0000 0.0000 63.4 2.139 -2.131 1068.44 2 1400.0 3.63 N/A 0.0124 N/A 27.878 0.000 SPT 1.0000 0.0000 64.4 2.146 -2.124 1068.42. 2 1500.0 3.62 N/A 0.0125 N/A 27.970 0.000 SPT 1.0000 0.0000 65.4 2.153 -2.117 1068.38 2 1600.0 3.61 N/A 0.0125 N/A 28.062 0.000 SPT 1.0000 0.0000 66.5 2.160 -2.110 1068.33 2 1700.0 3.59 N/A 0.0125 N/A 28.155 0.000 SPT 1.0000 0.0000 67.5 2.167 -2.103 1068.27 2 1800.0 3.58 N/A 0.0125 N/A 28.248 0.000 SPT 1.0000 0.0000 68.5 2.174 -2.096 1068.19 2 1900.0 3.57 N/A 0.0125 N/A 28.341 0.000 SPT 1.0000 0.0000 69.5 2.182 -2.090 1068.10 1 1934.0 3.56 N/A 0.0125 N/A 28.404 0.000 SPT 1.0000 0.0000 69.9 0.743 -0.709 1068.07 2 2034.0 3.56 N/A 0.0125 N/A 28.470 0.000 SPT 1.0000 0.0000 70.9 2.191 -1.904 1067.78 1 2100.0 3.55 N/A 0.0125 N/A 28.552 0.000 SPT 1.0000 0.0000 71.6 1.451 -1.253 1067.59 2 2200.0 3.53 N/A 0.0125 N/A 28.636 0.000 SPT 1.0000 0.0000 72.6 2.204 -1.780 1067.16 2 2300.0 3.52 N/A 0.0126 N/A 28.739 0.000 SPT 1.0000 0.0000 73.7 2.212 -1.774 1066.72 2 2400.0 3.51 N/A 0.0126 N/A 28.843 0.000 SPT 1.0000 0.0000 74.7 2.220 -1.768 1066.26 1 2426.0 3.50 N/A 0.0126 N/A 28.908 0.000 SPT 1.0000 0.0000 75.0 0.579 -0.459 1066.15 2 2526.0 3.49 N/A 0.0126 N/A 28.973 0.000 SPT 1.0000 0.0000 76.0 2.230 -1.788 1065.70 2 2626.0 3.48 N/A 0.0126 N/A 29.077 0.000 SPT 1.0000 0.0000 77.0 2.238 -1.782 1065.24 1 2654.0 3.47 N/A 0.0126 N/A 29.143 0.000 SPT 1.0000 0.0000 77.3 0.628 -0.498 1065.12 2 2700.0 3.47 N/A 0.0126 N/A 6.629 0.000 SPT 1.0000 0.0000 77.8 0.022 -0.817 1065.91 2 2746.0 3.47 N/A 0.0126 N/A 6.632 0.000 SPT 1.0000 0.0000 78.3 0.022 -0.867 1066.75 1 2849.5 3.47 N/A 0.0126 N/A 6.638 0.000 SPT 1.0000 0.0000 79.3 0.050 -1.949 1068.65 1 2893.0 3.46 N/A 0.0126 N/A 6.644 0.000 SPT 1.0000 0.0000 79.8 0.021 -0.819 1069.45 1 2916.0 3.46 N/A 0.0127 N/A 6.646 0.000 SPT 1.0000 0.0000 80.0 0.011 -0.442 1069.87 SUMMARY: CALCULATED WELLHEAD PRESSURE: 1063.7 psis SPECIFIED WELLHEAD TEMPERATURE: 50.0 deg F SPECIFIED BOTTOM-HOLE PRESSURE: 1069.9 psia SPECIFIED BOTTOM-HOLE TEMPERATURE: 80.0 deg F Predicted Pressure Loss: -6.2 psi Friction Loss: 57.1 psi Elevation Loss: -63.3 psi Kinetic Loss: -0.0 psi In-line Facilities Loss: 0.0 psi Total Liquid Holdup: 0.0 bbl Total Gas Pack: 15553.4 scf Estimated Static Liquid Column Height: 0.0 ft Measured Depth: 2916.0 ft Case Number: 4 TITLE: INJECTION STRING ------------------------------------ SPECIFIED AND CALCULATED SYSTEM DATA ------------------------------------ CASING TUBING 0.0 ft Depth c] 0.0 ft Depth Flow String: Tubing String Length: 2916.0 ft ID Depth (inch) (ft) 6.276 0.0 Roughness: 0.00180 inch ~ ID OD Depth (inch) (inch) (ft) 2.992 3.500 0.0 Roughness: 0.00180 inch WELLHEAD Pressure: to be calculated Temperature: 50.0 deg F BOTTOM-HOLE Pressure: 1070.0 psia Temperature: 80.0 deg F FLOW RATES Equivalent Gas Volume Flow: 15.00 MMSCfd Water Volume Flow: 0.00 Bbl/day DETAILED RESULTS I SUPERFICIAL T DENSITY VISCOSI TY VELOCITIES PREDICTED VOLUME CALL. PRESSURE DROP CALCULATED E DEPTH (lb/ft3) (cP) (ft/sec) FLOW FRACTION TEMP. (psi) PRESSURE R (ft) GAS LIQUID GAS LIQUID GAS LIQUID PATTERN GAS LIQUID (deg F) FRICTION HYDROST. (psia) 100.0 4.04 N/A 0.0126 N/A 37.622 0.000 SPT 1.0000 0.0000 51.0 4.331 -2.800 1126.07 1 200.0 4.01 N/A 0.0126 N/A 37.818 0.000 SPT 1.0000 0.0000 52.1 4.353 -2.786 1124.50 2 300.0 3.99 N/A 0.0126 N/A 38.015 0.000 SPT 1.0000 0.0000 53.1 4.376 -2.771 1122.89 2 400.0 3.97 N/A 0.0126 N/A 38.214 0.000 SPT 1.0000 0.0000 54.1 4.399 -2.757 1121.25 2 500.0 3.95 N/A 0.0125 N/A 38.415 0.000 SPT 1.0000 0.0000 55.1 4.422 -2.723 1119.54 2 600.0 3.93 N/A 0.0125 N/A 38.618 0.000 SPT 1.0000 0.0000 56.2 4.445 -2.709 1117.81 2 700.0 3.91 N/A 0.0125 N/A 38.625 0.000 SPT 1.0000 0.0000 57.2 4.469 -2.626 1115.96 2 800.0 3.89 N/A 0.0125 N/A 39.034 0.000 SPT 1.0000 0.0000 58.2 4.493 -2.612 1114.08 2 900.0 3.87 N/A 0.0125 N/A 39.248 0.000 SPT 1.0000 0.0000 59.3 4.518 -2.461 1112.02 2 1000.0 3.85 N/A 0.0125 N/A 39.466 0.000 SPT 1.0000 0.0000 60.3 4.543 -2.447 1109.92 2 1100.0 3.83 N/A 0.0125 N/A 39.687 0.000 SPT 1.0000 0.0000 61.3 4.568 -2.434 1107.78 2 1200.0 3.80 N/A 0.0125 N/A 39.910 0.000 SPT 1.0000 0.0000 62.3 4.594 -2.420 1105.61 2 1300.0 3.78 N/A 0.0125 N/A 40.139 0.000 SPT 1.0000 0.0000 63.4 4.620 -2.213 1103.20 2 1400.0 3.76 N/A 0.0125 N/A 40.374 0.000 SPT 1.0000 0.0000 64.4 4.648 -2.200 1100.75 2 1500.0 3.74 N/A 0.0125 N/A 40.611 0.000 SPT 1.0000 0.0000 65.4 4.675 -2.187 1098.26 2 1600.0 3.72 N/A 0.0126 N/A 40.851 0.000 SPT 1.0000 0.0000 66.5 4.702 -2.174 1095.72 2 1700.0 3.69 N/A 0.0126 N/A 41.093 0.000 SPT 1.0000 0.0000 67.5 4.730 -2.162 1093.15 2 1800.0 3.67 N/A 0.0126 N/A 41.338 0.000 SPT 1.0000 0.0000 68.5 4.759 -2.149 1090.54 2 1900.0 3.65 N/A 0.0126 N/A 41.585 0.000 SPT 1.0000 0.0000 69.5 4.787 -2.136 1087.89 1 1934.0 3.64 N/A 0.0126 N/A 41.752 0.000 SPT 1.0000 0.0000 69.9 1.634. -0.723 1086.98 2 2034.0 3.62 N/A 0.0126 N/A 41.924 0.000 SPT 1.0000 0.0000 70.9 4.826 -1.940 1084.08 2 2100.0 3.60 N/A 0.0126 N/A 42.141 0.000 SPT 1.0000 0.0000 71.6 3.202 -1.274 1082.15 2 2200.0 3.58 N/A 0.0126 N/A 42.362 0.000 SPT 1.0000 0.0000 72.6 4.877 -1.805 1079.08 2 2300.0 3.56 N/A 0.0126 N/A 42.633 0.000 SPT 1.0000 0.0000 73.7 4.908 -1.794 1075.96 2 2400.0 3.54 N/A 0.0126 N/A 42.908 0.000 SPT 1.0000 0.0000 74.7 4.939 -1.782 1072.80 1 2426.0 3.52 N/A 0.0126 N/A 43.082 0.000 SPT 1.0000 0.0000 75.0 1.289 -0.461 1071.98 1 2526.0 3.51 N/A 0.0126 N/A 43.257 0.000 SPT 1.0000 0.0000 76.0 4.980 -1.796 1068.78 2 2626.0 3.49 N/A 0.0126 N/A 43.537 0.000 SPT 1.0000 0.0000 77.0 5.012 -1.785 1065.55 1 2654.0 3.47 N/A 0.0126 N/A 43.718 0.000 SPT 1.0000 0.0000 77.3 1.409 -0.498 1064.65 2 2700.0 3.47 N/A 0.0126 N/A 9.948 0.000 SPT 1.0000 0.0000 77.8 0.049 -0.817 1065.40 2 2746.0 3.47 N/A 0.0126 N/A 9.954 0.000 SPT 1.0000 0.0000 78.3 0.049 -0.867 1066.22 1 2849.5 3.46 N/A 0.0126 N/A 9.963 0.000 SPT 1.0000 0.0000 79.3 0.111 -1.948 1068.06 1 2893.0 3.46 N/A 0.0126 N/A 9.972 0.000 SPT 1.0000 0.0000 79.8 0.047 -0.818 1068.83 1 2916.0 3.46 N/A 0.0127 N/A 9.976 0.000 SPT 1.0000 0.0000 80.0 0.025 -0.441 1069.24 SUMMARY: CALCULATED WELLHEAD PRESSURE: 1127.6 psia SPECIFIED WELLHEAD TEMPERATURE: 50.0 deg F SPECIFIED BOTTOM-HOLE PRESSURE: 1069.2 psia i SPECIFIED BOTTOM-HOLE TEMPERATURE: 80.0 deg F Predicted Pressure Loss: 58.4 psi Friction Loss: 123.8 psi Elevation Loss: -65.5 psi Kinetic Loss: 0.1 psi In-line Facilities Loss: 0.0 psi Total Liquid Holdup: 0.0 bbl Total Gas Pack: 15949.5 scf Estimated Static Liquid Column Height: 0.0 ft Measured Depth: 2916.0 ft • Case Number: 5 TITLE: INJECTION STRING ------------------------------------ SPECIFIED AND CALCULATED SYSTEM DATA ------------------------------------ CASING TUBING 0.0 ft Depth ~ 0.0 ft Depth Flow String: Tubing String Length: 2916.0 ft ID Depth (inch) (ft) 6.276 0.0 Roughness: 0.00180 inch ~ ID OD Depth (inch) (inch) (ft) 2.992 3.500 0.0 Roughness: 0.00180 inch WELLHEAD Pressure: to be calculated Temperature: 50.0 deg F BOTTOM-HOLE Pressure: 1070.0 psia Temperature: 80.0 deg F FLOW RATES Equivalent Gas Volume Flow: 20.00 MMSCfd Water Volume Flow: 0.00 Bbl/day DETAILED RESULTS I SUPERFICIAL T DENSITY VISCOSITY VELOCITIES PREDICTED VOLUME CALL. PRESSURE DROP CALCULATED E DEPTH (lb/ft3) (cP) (ft/sec) FLOW FRACTION TEMP. (psi) PRESSURE R (ft) GAS LIQUID GAS LIQUID GAS LIQUID PATTERN GAS LIQUID (deg F) FRICTION HYDROST. (psia) 100.0 4.38 N/A 0.0128 N/A 46.202 0.000 SPT 1.0000 0.0000 51.0 7.081 -3.040 1207.77 200.0 4.35 N/A 0.0128 N/A 46.556 0.000 SPT 1.0000 0.0000 52.1 7.135 -3.017 1203.64 2 300.0 4.31 N/A 0.0128 N/A 46.915 0.000 SPT 1.0000 0.0000 53.1 7.190 -2.994 1199.44 2 400.0 4.28 N/A 0.0128 N/A 47.280 0.000 SPT 1.0000 0.0000 54.1 7.246 -2.971 1195.16 2 500.0 4.25 N/A 0.0127 N/A 47.650 0.000 SPT 1.0000 0.0000 55.1 7.303 -2.927 1190.77 2 600.0 4.21 N/A 0.0127 N/A 48.027 0.000 SPT 1.0000 0.0000 56.2 7.360 -2.904 1186.31 2 700.0 4.18 N/A 0.0127 N/A 48.412 0.000 SPT 1.0000 0.0000 57.2 7.419 -2.808 1181.69 2 800.0 4.15 N/A 0.0127 N/A 48.804 0.000 SPT 1.0000 0.0000 58.2 7.480 -2.786 1176.99 2 900.0 4.11 N/A 0.0127 N/A 49.207 0.000 SPT 1.0000 0.0000 59.3 7.541 -2.617 1172.05 2 1000.0 4.08 N/A 0.0127 N/A 49.620 0.000 SPT 1.0000 0.0000 60.3 7.604 -2.595 1167.04 2 1100.0 4.05 N/A 0.0127 N/A 50.040 0.000 SPT 1.0000 0.0000 61.3 7.669 -2.574 1161.93 2 1200.0 4.01 N/A 0.0127 N/A 50.467 0.000 SPT 1.0000 0.0000 62.3 7.734 -2.552 1156.74 2 1300.0 3.98 N/A 0.0127 N/A 50.907 0.000 SPT 1.0000 0.0000 63.4 7.802 -2.327 1151.25 2 1400.0 3.94 N/A 0.0127 N/A 51.360 0.000 SPT 1.0000 0.0000 64.4 7.871 -2.306 1145.68 2 1500.0 3.91 N/A 0.0127 N/A 51.822 0.000 SPT 1.0000 0.0000 65.4 7.942 -2.286 1140.01 2 1600.0 3.87 N/A 0.0127 N/A 52.292 0.000 SPT 1.0000 0.0000 66.5 8.014 -2.265 1134.25 2 1700.0 3.84 N/A 0.0127 N/A 52.771 0.000 SPT 1.0000 0.0000 67.5 8.087 -2.244 1128.39 2 1800.0 3.80 N/A 0.0127 N/A 53.260 0.000 SPT 1.0000 0.0000 68.5 8.162 -2.224 1122.44 2 1900.0 3.77 N/A 0.0126 N/A 53.759 0.000 SPT 1.0000 0.0000 69.5 8.239 -2.203 1116.39 2 1934.0 3.74 N/A 0.0126 N/A 54.098 0.000 SPT 1.0000 0.0000 69.9 2.819 -0.744 1114.32 2 2034.0 3.72 N/A 0.0126 N/A 54.448 0.000 SPT 1.0000 0.0000 70.9 8.344 -1.992 1107.95 2 2100.0 3.69 N/A 0.0126 N/A 54.889 0.000 SPT 1.0000 0.0000 71.6 5.552 -1.304 1103.69 2 2200.0 3.66 N/A 0.0126 N/A 55.343 0.000 SPT 1.0000 0.0000 72.6 8.481 -1.842 1097.04 2 2300.0 3.62 N/A 0.0126 N/A 55.902 0.000 SPT 1.0000 0.0000 73.7 8.567 -1.824 1090.28 2 2400.0 3.58 N/A 0.0126 N/A 56.474 0.000 SPT 1.0000 0.0000 74.7 8.655 -1.805 1083.42 2 2426.0 3.56 N/A 0.0126 N/A 56.840 0.000 SPT 1.0000 0.0000 75.0 2.265 -0.466 1081.61 2 2526.0 3.54 N/A 0.0126 N/A 57.211 0.000 SPT 1.0000 0.0000 76.0 8.768 -1.811 1074.64 2 2626.0 3.50 N/A 0.0126 N/A 57.811 0.000 SPT 1.0000 0.0000 77.0 8.860 -1.792 1067.56 2 2654.0 3.48 N/A 0.0126 N/A 58.202 0.000 SPT 1.0000 0.0000 77.3 2.497 -0.498 1065.55 2 2700.0 3.47 N/A 0.0126 N/A 13.252 0.000 SPT 1.0000 0.0000 77.8 0.087 -0.817 1066.28 2 2746.0 3.47 N/A 0.0126 N/A 13.260 0.000 SPT 1.0000 0.0000 78.3 0.087 -0.867 1067.06 1 2849.5 3.47 N/A 0.0126 N/A 13.273 0.000 SPT 1.0000 0.0000 79.3 0.197 -1.950 1068.82 1 2893.0 3.46 N/A 0.0126 N/A 13.285 0.000 SPT 1.0000 0.0000 79.8 0.083 -0.819 1069.55 1 2916.0 3.46 N/A 0.0127 N/A 13.291 0.000 SPT 1.0000 0.0000 80.0 0.044 -0.442 1069.94 SUMMARY: CALCULATED WELLHEAD PRESSURE: 1211.8 psia SPECIFIED WELLHEAD TEMPERATURE: 50.0 deg F . SPECIFIED BOTTOM-HOLE PRESSURE: 1069.9 psia SPECIFIED BOTTOM-HOLE TEMPERATURE: 80.0 deg F Predicted Pressure Loss: 141.9 psi Friction Loss: 210.2 psi Elevation Loss: -68.6 psi Kinetic Loss: 0.3 psi In-line Facilities Loss: 0.0 psi Total Liquid Holdup: 0.0 bbl Total Gas Pack: 16504.1 scf Estimated Static Liquid Column Height: 0.0 ft Measured Depth: 2916.0 ft u ******,r*w******************a***w***r.**,r** Date: 12-03-2010 * Neotechnology Consultants Ltd. * Time: 10:56:03 AM * * * WELLFLO 7 - Version '7.231 * ***************************************** * Licensee: Aurora Power ***************************************** ** CAL C U L A T I O N O P T I O N S ** -------------------------------------------------------------------------------- TITLE: -------------------------------------------------------------------------------- INPUT DATA FILE: NC2 Inj simulation 3-11-10 1065psi.WFW OUTPUT FILES: NC2 Inj simulation 3-11-10 1065psi.MIN NC2 Inj simulation 3-11-10 1065psi.MAX NC2 Inj simulation 3-11-10 1065psi.SUM . NC2 Inj simulation 3-11-10 1065psi.PLT CALCULATION DIRECTION: Top to Bottom FLOW DIRECTION: Injection FLOW PATH: Tubing FLUID SYSTEM: Compositional CALCULATION METHODS SELECTIONS FOR VERTICAL UPFLOW OVERALL SELECTION: Gregory et al FLOW REGIME PREDICTION: Gregory et al LIQUID HOLDUP CALCULATION: Gregory • FRICTION LOSS CALCULATION: Gregory ANNULAR-MIST FLOW MODEL: Gray Revised SLUG OPTION: Original Method SELECTIONS FOR VERTICAL DOWNFLOW OVERALL SELECTION: Beggs and Brill Revised FLOW PATTERN PREDICTION: Beggs and Brill Revised LIQUID HOLDUP CALCULATION: Beggs and Brill Revised FRICTION LOSS CALCULATION: Beggs and Brill SELECTIONS FOR HORIZONTAL AND INCLINED FLOW OVERALL SELECTION: FLOW PATTERN PREDICTION: LIQUID HOLDUP CALCULATION: FRICTION LOSS CALCULATION: UPHILL CORRECTION: DOWNHILL CORRECTION: Eaton, Oliemans Taitel and Dukler Eaton Olieman No Correction Recovery Based on Gas Density FLUID TEMPERATURE PROFILE: Specified FLUID PROPERTIES Compositional Fluid Properties Procedure Recomendation Basis: User Specified PVT Behaviour and Transport Property Procedures EQUATION OF STATE: VMG APRD _ LIQUID DENSITY: Calculated by Equation of State WATER TREATED AS: free water Production Fluid Component Mole Fraction HELIUM 0.000 H2 0.000 N2 9.1700e-003 CO2 3.0700e-003 H2S 0.000 • C1 0.987 C2 6.8000e-004 C3 0.000 I-C4 0.000 N-C4 0.000 I-CS 0.000 N-CS 0.000 N-C6 6.OOOOe-005 N-C7 0.000 N-CS 0.000 N-C9 0.000 N-C10 0.000 N-C11 0.000 N-C12 0.000 N-C13 0.000 N-C14 0.000 N-C15 0.000 N-C16 0.000 N-C17 0.000 N-C18 0.000. N-C19 0.000 N-C20 0.000 N-C21 0.000 N-C22 0.000 N-C23 0.000 N-C24 0.000 N-C25 0.000 N-C26 0.000 N-C27 0.000 N-C28 0.000 N-C29 0.000 N-C30 0.000 BENZENE 0.000 TOLUENE 0.000 ETHYLBENZENE 0.000 O-XYLENE 0.000 M-XYLENE 0.000 P-XYLENE 0.000 CYCLO-CS 0.000 M-CYCLO-CS 0.000 CYCLOHEXANE 0.000 M-CYCLO-C6 0.000 1,2,4 TMB 0.000 AMMONIA 0.000 CARBON MONOXIDE 0.000 OXYGEN 0.000 ARGON 0.000 GAS VISCOSITY: Dean and Stiel (Compositional) LIQUID VISCOSITY: Van Velzen et al/Letsou and Stiel ETHYLENE 0.000 PROPYLENE 0.000 1-BUTYLENE 0.000 I-BUTENE 0.000 CIS-2-BUTYLENE 0.000 TRANS-2-BUTYLENE0.000 PENTENE 0.000. HEXENE 0.000 HEPTENE 0.000 OCTENE 0.000 PROPADIENE 0.000 1,2 BUTADIENE 0.000 1,3 BUTADIENE 0.000 WATER 0.000 METHANOL 0.000 ETHYLENE GLYCOL 0.000 TEG 0.000 Compositional Fluid #1 Component Mole Fraction HELIUM 0.000 H2 0.000 N2 9.1700e-003 CO2 3.0700e-003 H25 0.000 Cl 0.987 C2 6.8000e-004 C3 0.000 I-C4 0.000 N-C4 0.000 I-CS 0.000 N-CS 0.000 N-C6 6.OOOOe-005 N-C7 0.000 N-C8 0.000 N-C9 0.000 N-C10 0.000 N-C11 0.000 N-C12 0.000 N-C13 0.000 N-C14 0.000 N-C15 0.000 N-C16 0.000 N-C17 0.000 N-C18 0.000 N-C19 0.000 N-C20 0.000 N-C21 0.000 N-C22 0.000 N-C23 0.000 N-C24 0.000 N-C25 0.000 N-C26 0.000 N-C27 0.000 N-C28 0.000 N-C29 0.000 N-C30 0.000 BENZENE 0.000 TOLUENE 0.000. ETHYLBENZENE 0.000. O-XYLENE 0.000 M-XYLENE 0.000 P-XYLENE 0.000 CYCLO-CS 0.000 M-CYCLO-CS 0.000 CYCLOHEXANE 0.000 M-CYCLO-C6 0.000 1,2,4 TMB 0.000 AMMONIA 0.000 CARSON MONOXIDE 0.000 OXYGEN 0.000 ARGON 0.000 ETHYLENE 0.000 PROPYLENE 0.000 1-BUTYLENE 0.000 I-BUTENE 0.000 CIS-2-BUTYLENE 0.000 TRANS-2-BUTYLENE0.000 PENTENE 0.000 REXENE 0.000 HEPTENE 0.000 OCTENE 0.000 PROPADIENE 0.000 1,2 BUTADIENE 0.000 1,3 BUTADIENE 0.000 WATER 0.000 • METHANOL 0.000 ETHYLENE GLYCOL 0.000 TEG 0.000 Drilling Profile Report inclination Azimuth Measured Depth (deg) (deg) (f t) 0.000 0.000 0.000 4.000 0.000 400.000 10.000 0.000 600.000 19.000 0.000 800.000 28.000 0.000 1200.000 37.000 0.000 1934.000 42.000 0.000 2100.000 45.000 0.000 2426.000 40.000 0.000 2700.000 37.000 0.000 2893.000 37.000 0.000 3100.000 42.000 0.000 5011.000 ~J Case Number: 1 TITLE: INJECTION STRING CASING • TUBING ------------------------------------ SPECIFIED AND CALCULATED SYSTEM DATA ------------------------------------ Flow String: Tubing String Length: 2916.0 ft ID Depth (inch) (ft) 6.276 0.0 Roughness: 0.00180 inch @ ID OD Depth (inch) (inch) (ft) 2.992 3.500 0.0 Roughness: 0.00180 inch 0.0 ft Depth Q 0.0 ft Depth WELLHEAD Pressure: to be calculated Temperature: 50.0 deg F BOTTOM-HOLE Pressure: 1070.0 psia Temperature: 80.0 deg F FLOW RATES RESULTS Equivalent Gas Volume Flow: 0.00 MMSCfd Water Volume Flow: 0.00 Bbl/day ------------ ------------------ ------------ CUM. -------------- MEASURED CALCULATED LIQUID CALCULATED DEPTH PRESSURE HOLDUP TEMPERATURE (ft) (psia) (bbl) (deg F) 0.00 1007.90 0.00 50.00 400.00 1017.76 0.00 54.12 600.00 1022.64 0.00 56.17 800.00 1027.39 0.00 58.23 1200.00 1036.38 0.00 62.35 1934.00 1051.46 0.00 69.90 2100.00 1054.57 0.00 71.60 2426.00 1060.29 0.00 74.96 2654.00 1064.34 0.00 77.30 2700.00 1065.16 0.00 77.78 2893.00 1068.79 0.00 79.76 2916.00 1069.23 0.00 80.00 SUMMARY: CALCULATED WELLHEAD PRESSURE: 1007.9 psia SPECIFIED WELLHEAD TEMPERATURE: 50.0 deg F SPECIFIED BOTTOM-HOLE PRESSURE: 1069.2 psia SPECIFIED BOTTOM-HOLE TEMPERATURE: 80.0 deg F Predicted Pressure Loss: -61.3 psi Friction Loss: 0.0 psi Elevation Loss: -61.3 psi Kinetic Loss: 0.0 psi In-line Facilities Loss: 0.0 psi Total Liquid Holdup: 0.0 bbl Total Gas Pack: 15204.8 scf Estimated Static Liquid Column Height: 0.0 ft Measured Depth: 2916.0 ft • Case Number: 2 ------------------------------------ SPECIFIED AND CALCULATED SYSTEM DATA ------------------------------------ TITLE: INJECTION STRING CASING TUBING Flow String: Tubing String Length: 2916.0 ft ID Depth (inch) (ft) 6.276 0.0 Roughness: 0.00180 inch Q ID OD Depth (inch) (inch) (ft) 2.992 3.500 0.0 Roughness: 0.00180 inch WELLHEAD Pressure: to be calculated Temperature: 50.0 deg F BOTTOM-HOLE Pressure: 1070.0 psia Temperature: 80.0 deg F 0.0 ft Depth 0.0 ft Depth FLOW RATES Equivalent Gas Volume Flow: 5.00 MMSCfd Water Volume Flow: 0.00 Bbl/day RESULTS ------------ ------------------ ------------ CUM. -------------- MEASURED CALCULATED LIQUID CALCULATED DEPTH PRESSURE HOLDUP TEMPERATURE (ft) sia) (bbl) (deg ~) --- ------(p ------ ---- --- -- - ----- 0.00 1022.86 0.00 50.00 400.00 1030.69 0.00 54.12 600.00 1034.55 0.00 56.17 800.00 1038.26 0.00 58.23 1200.00 1045.14 0.00 62.35 1934.00 1056.26 0.00 69.90 2100.00 1058.46 0.00 71.60 2426.00 1062.36 0.00 74.96 2654.00 1065.14 0.00 77.30 2700.00 1065.95 0.00 77.78 2893.00 1069.56 0.00 79.76 2916.00 1070.00 0.00 80.00 SUMMARY: CALCULATED WELLHEAD PRESSURE: 1022.9 psia SPECIFIED WELLHEAD TEMPERATURE: 50.0 deg F SPECIFIED BOTTOM-HOLE PRESSURE: 1070.0 psia SPECIFIED BOTTOM-HOLE TEMPERATURE: 80.0 deg F Predicted Pressure Loss: -47.1 psi Friction Loss: 14.7 psi Elevation Loss: -61.9 psi Kinetic Loss: -0.0 psi In-line Facilities Loss: 0.0 psi Total Liquid Holdup: 0.0 bbl Total Gas Pack: 15303.4 scf Estimated Static Liquid Column Height: 0.0 ft Measured Depth: 2916.0 ft • Case Number: 3 TITLE: INJECTION STRING CASING • TUBING ------------------------------------ SPECIFIED AND CALCULATED SYSTEM DATA ------------------------------------ Flow String: Tubing String Length: 2916.0 ft ID Depth (inch) (ft) 6.276 0.0 Roughness: 0.00180 inch (~ ID OD Depth (inch) (inch) (ft) 2.992 3.500 0.0 Roughness: 0.00180 inch 0.0 ft Depth 0.0 ft Depth WELLHEAD Pressure: to be calculated Temperature: 50.0 deg F BOTTOM-HOLE Pressure: 1070.0 psia Temperature: 80.0 deg F FLOW RATES RESULTS Equivalent Gas Volume Flow: 10.00 MMSCfd Water Volume Flow: 0.00 Bbl/day ------------ ------------------ ------------ CUM. -------------- MEASURED CALCULATED LIQUID CALCULATED DEPTH PRESSURE HOLDUP TEMPERATURE (ft) sia) - (bbl) (deg F> --- p ----- ----- ---- ---- -- - - - -- 0.00 1063.71 0.00 50.00 400.00 1065.86 0.00 54.12 600.00 1066.82 0.00 56.17 800.00 1067.59 0.00 58.23 1200.00 1068.45 0.00 62.35 1934.00 1068.06 0.00 69.90 2100.00 1067.58 0.00 71.60 2426.00 1066.14 0.00 74.96 2654.00 1065.11 0.00 77.30 2700.00 1065.91 0.00 77.78 2893.00 1069.45 0.00 79.76 2916.00 1069.88 0.00 80.00 SUMMARY: CALCULATED WELLHEAD PRESSURE: 1063.7 psia SPECIFIED WELLHEAD TEMPERATURE: 50.0 deg F SPECIFIED BOTTOM-HOLE PRESSURE: 1069.9 psia SPECIFIED BOTTOM-HOLE TEMPERATURE: 80.0 deg F Predicted Pressure Loss: -6.2 psi Friction Loss: 57.1 psi Elevation Loss: -63.3 psi Kinetic Loss: -0.0 psi In-line Facilities Loss: 0.0 psi Total Liquid Holdup: 0.0 bbl Total Gas Pack: 15553.4 scf Estimated Static Liquid Column Height: 0.0 ft Measured Depth: 2916.0 ft • Case Number: 4 TITLE: INJECTION STRING CASING • TUBING ------------------------------------ SPECIFIED AND CALCULATED SYSTEM DATA ------------------------------------ Flow String: Tubing String Length: 2916.0 ft ID Depth (inch) (ft) 6.276 0.0 Roughness: 0.00180 inch ID OD Depth (inch) (inch) (ft) 2.992 3.500 0.0 Roughness: 0.00180 inch 0.0 ft Depth 0.0 ft Depth WELLHEAD Pressure: to be calculated Temperature: 50.0 deg F BOTTOM-HOLE Pressure: 1070.0 psia Temperature: 80.0 deg F FLOW RATES RESULTS Equivalent Gas Volume Flow: 15.00 MMSCfd Water Volume Flow: 0.00 Bbl/day ------------ ------------------ ------------ CUM. -------------- MEASURED CALCULATED LIQUID CALCULATED DEPTH PRESSURE HOLDUP TEMPERATURE (ft) (psia) (bbl) (deg F) 0.00 1127.60 0.00 50.00 400.00 1121.25 0.00 54.12 600.00 1117.81 0.00 56.17 800.00 1114.08 0.00 58.23 1200.00 1105.61 0.00 62.35 1934.00 1086.97 0.00 69.90 2100.00 1082.15 0.00 71.60 2426.00 1071.97 0.00 74.96 2654.00 1064.64 0.00 77.30 2700.00 1065.41 0.00 77.78 2893.00 1068.83 0.00 79.76 2916.00 1069.25 0.00 80.00 SUMMARY: CALCULATED WELLHEAD PRESSURE: 1127.6 psia SPECIFIED WELLHEAD TEMPERATURE: 50.0 deg F SPECIFIED BOTTOM-HOLE PRESSURE: 1069.2 psia SPECIFIED BOTTOM-HOLE TEMPERATURE: 80.0 deg F Predicted Pressure Loss: 58.4 psi Friction Loss: 123.8 psi Elevation Loss: -65.5 psi Kinetic Loss: 0.1 psi in-line Facilities Loss: 0.0 psi Total Liquid Holdup: 0.0 bbl Total Gas Pack: 15949.5 scf Estimated Static Liquid Column Height: 0.0 ft Measured Depth: 2916.0 ft r Case Number: 5 TITLE: INJECTION STRING CASING TUBING ------------------------- - --------- SPECIFIED AND CALCULATED SYSTEM DATA ------------------------------------ Flow String: Tubing String Length: 2916.0 ft ID Depth (inch) (ft) -6.276 0.0 Roughness: 0.00160 inch @ ID OD Depth (inch) (inch) (ft) 2.992 3.500 0.0 Roughness: 0.00180 inch 0.0 ft Depth @ 0.0 ft Depth WELLHEAD Pressure: to be calculated Temperature: 50.0 deg F BOTTOM-HOLE Pressure: 1070.0 Asia Temperature: 80.0 deg F FLOW RATES RESULTS Equivalent Gas Volume Flow: 20.00 MMSCfd Water Volume Flow: 0.00 Bbl/day ------------ ------------------ ------------ CUM. -------------- MEASURED CALCULATED LIQUID CALCULATED DEPTH PRESSURE HOLDUP TEMPERATURE (ft) (psia) (bbl) (deg F) --------- - ----------------- --- ------- 0.00 1211.82 0.00 50.00 400.00 1195.16 0.00 54.12 600.00 1186.31 0.00 56.17 800.00 1176.99 0.00 58.23 1200.00 1156.74 0.00 62.35 1934.00 1114.32 0.00 69.90 2100.00 1103.69 0.00 71.60 2426.00 1081.61 0.00 74.96 2654.00 1065.55 0.00 77.30 2700.00 1066.28 0.00 77.78 2893.00 1069.55 0.00 79.76 2916.00 1069.95 0.00 80.00 SUMMARY: CALCULATED WELLHEAD PRESSURE: 1211.8 psia SPECIFIED WELLHEAD TEMPERATURE: 50.0 deg F SPECIFIED BOTTOM-HOLE PRESSURE: 1069.9 psia SPECIFIED BOTTOM-HOLE TEMPERATURE: 80.0 deg F Predicted Pressure Loss: 141.9 psi Friction Loss: 210.2 psi Elevation Loss: -68.6 psi Kinetic Loss: 0.3 psi In-line Facilities Loss: 0.0 psi Total. Liquid Holdup: 0.0 bbl Total Gas Pack: 16504.1 scf Estimated Static Liquid Column Height: 0.0 ft Measured Depth: 2916.0 ft •