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Home My WebLink AboutSIO 008• INDEX • STORAGE INJECTION ORDER NO. 8 1. February 1, 2010 Aurora Gas Application for SIO for Gas Storage for Nicolai Creek 2. February 12, 2010 Notice of Public Hearing, Affidavit of publication, e-mail Distribution list, bulk mailing List 3. February 12, 2010 E-mail from DNR to request hearing for Nicolai Creek SIO 4. March 12, 2010 Aurora Gas Additional information request response, Oversized & Log Info filed in the confidential room. 5. March 17, 2010 Hearing sign in sheet 6. March 17, 2010 E-mail from Thor Cutler re: Gas storage exempt UIC 7. March 17, 2010 Public Hearing transcript 8. Apri128, 2010 E-mail re: Gas Storage Jurisdictional Question 9. June 25, 2010 Aurora Gas application to certify gas storage facility at Nicolai Creek 10. July 27, 2010 AOGCC's Certification Storage Injection Order No. 8 • ~ 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 order authorizing underground natural gas storage in well Nicolai Creek Unit No. 2 of the Nicolai Creek Unit, Kenai Peninsula Borough, in conformance with 20 AAC 25.252 and 20 AAC 25.412. Docket Number: SIO-10-01 Storage Injection Order No. 8 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 Jod . Colombie Sbe i 1 Assistant to the Commission f~ STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF Aurora Gas, ) Docket Number: SIO-10-01 LLC for an order authorizing under- ) Storage Injection Order No. 8 ground natural gas storage in well Nicolai ) Creek Unit No. 2 of the Nicolai Creek ) Nicolai Creek Field Unit, Kenai Peninsula Borough, in con- ) Nicolai Creek Unit formance with 20 AAC 25.252 and 20 ~ South Undefined Gas Pool AAC 25.412. ) Kenai Peninsula Borough, Alaska April 16, 2010 IT APPEARING THAT: 1. By application dated February 1, 2010 Aurora Gas, LLC (Aurora) requested a storage injection order from the Alaska Oil and Gas Conservation Commission (Commission) authorizing injection for underground storage of natural gas in the South Undefined Gas Pool of the Nicolai Creek Unit. 2. On February 12, 2010 pursuant to 20 AAC 25.540, the Commission published in the Anchorage Daily News notice of opportunity for public hearing on March 17, 2010. 3. On March 12 and 16, 2010 Aurora submitted supplemental information to the Commission. 4. The Commission held a public hearing on March 17, 2010 at 333 West 7tn Avenue, Suite 100, Anchorage, Alaska 99501. No testimony other than from Aurora was offered. The Commission received no protest nor written comments in response to the public notice. FINDINGS: 1. Operator Aurora Gas, LLC (Aurora) operates the Nicolai Creek Unit (NCU) and the Nicolai Creek Unit No. 2 well (NCU 2), which are located on the west side of the Cook Inlet, Kenai Peninsula Borough, Alaska. 2. Infection Stratal The proposed gas storage reservoir is the South Undefined Gas Pool. The South Undefined Gas Pool is comprised of sandstone reservoirs within the upper portion of the Oligocene- to Miocene-aged Tyonek Formation (Tyonek). The Tyonek ~ All depths presented in this Order are measured depths unless otherwise specified. Stora e Injection Order g J April 16, 2010 Page 2 of 9 reservoirs are overlain by reservoirs assigned to the Miocene-aged Beluga Formation (Beluga). In NCU 2, the Tyonek and Beluga reservoirs are separated by more than 150' of low permeability clay, siltstone, and coal. The proposed injection and storage sands correspond to the depth interval in the NCU 2 well of 2426' to 2916', or 2141' true vertical depth (TVD to 2511' TVD; see Figure 1, below). These Upper Tyonek reservoirs exhibit combination structural and stratigraphic trapping within a closed fold against the dominant east-trending Nicolai Cross Fault and a smaller, north-northeast-trending fault. 3. Proposed Injection Well The proposed injection and withdrawal well is the NCU 2 that was originally drilled and completed as a gas producer in 1966. The surface location of the well is 1999' from the south section line (FSL), 209' from the west section line (FWL), Sec 29, T11N, R12W, Seward Meridian (SM). The Upper Tyonek is entered at 1154' FSL, 702' FWL, Sec 29, T11N, R12W, SM. Aurora plans to work over NCU 2 in order to prepare the well for gas cycling service. 4. Operators /Surface Owners Notification Aurora provided an affidavit affirming that all surface owners and operators within one-quarter mile of the storage injection area were notified of Aurora's subject proposal. Notified entities are the Alaska Department of Natural Resources (DNR) and the Alaska Mental Health Trust. 5. Description of Operation Aurora proposes to inject excess natural gas into the Nicolai Creek South Undefined Gas Pool. Well NCU 2 (alone initially) will alternate between injection and production so that natural gas can be stored during periods of excess supply and be produced to satisfy peak rate requirements during seasonal high demand periods. The maximum injection pressure is estimated to be 1050 psi. 6. Pool Information Nicolai Creek Unit is unusual in that it consists of two non-adjacent areas, the North Participating Area and the South Participating Area, that are separated by the large, east-trending Nicolai Cross Fault. The South Undefined Gas Pool, well NCU 2 and the proposed storage reservoir strata lie in the South Participating Area. Three uppermost Tyonek strata (in descending order, Carya 2-1.1, 2-1.2, and 2-2.1) are currently being drained by NCU 2, and only these are proposed as storage strata. Gas in these strata is trapped within a small, east-trending fold that is bounded to the west and to the east by small, north-northeast-trending faults. Structural dip limits the gas accumulation to the south, structural dip and the Nicolai Cross Fault limit the gas accumulation to the north. Stora e In'ection Order g J April 16, 2010 Page 3 of 9 Correlatwn Q'D~~ Rests Porosay SP <MD RBSD~LD) Df 0 100 2 200 0 TVDSS> TVD Beluga _-- Formation - 1900 noo ': t= _~- 13-3/S" Casing Shce isoo - -6- 2000 _ ieoo ~_. - - -- ~.: -r, 2100 )son J isoo -~-` 2200 Tyonek ~._ =~ Formation 2300 -zooo ~~-'i zsoo 2400 CARYA 2-1.1 PerroraUOna 2500 zzoo -j -I-- -zzoo 2600 2300 CARYA 2-1.2 PBf~Of8U0fl8 2aoD -T-Y-r- 2800 -2600 2500 CARYA 2-2.1 K ~~~~~ -2500 3000 zsoo _ -zsoo 3100 zsoo Figure 1. Nicolai Cre ek Unit No. 2 Well Log Storage Injection Order 8 April 16, 2010 Page 4 of 9 NCU Tyonek sands occur within the Cook Inlet Basin, extending from the Matanuska Valley to the Alaska Peninsula. Hydrocarbon traps in the Cook Inlet Basin are typically tight anticlines and associated structures. Although eight individual sand members exist across the Nicolai Creek Field, South Participating Area reservoir strata are restricted to three Upper Tyonek strata. Porosity in the reservoir strata ranges from 19% to 25% and water saturation varies from 43% to 47%. Permeability is estimated at 120 millidarcies. Beluga sands overlie the Tyonek and are separated by numerous low permeability layers. NCU 2 was drilled in 1966, completed in a deeper Tyonek sand (3270' to 3315'), and produced about 51 million standard cubic feet (MMSCF) gas from 1968 until 1969, at an average of about 1.0 million standard cubic feet per day (MMSCFD). Next production was from the Carya 2-1.1, 2-1.2, and 2-2.1 sands in 2003, with about 806 MMSCF, or about 85% of estimated ultimate recovery, having been produced by December, 2009. Estimated ultimate recovery from NCU 2 is estimated at 947 MMSCF, with original gas in place estimated at 993 MMSCF. Initial average reservoir pressure in the Tyonek sands was about 1157 psi. Working gas storage volume is estimated to be 600 MMSCF to 700 MMSCF. 7. Well Lois Logs of NCU 2 are on file with the AOGCC. 8. Mechanical Integrity and Well Design NCU 2 was constructed in 1966 with 30" casing set at 80', 20" casing at 296', 13- 3/8" casing at 1934', and 7" casing at 3585'. All casing strings were cemented to surface. A cement bond log of the 7" casing confirmed cement from 1900' to 3550', with "good bond characteristics" from 2500' to 3550'. NCU 2 was suspended in 1991 with all perforations squeezed. The 7" casing and 7" x 13-3/8" annulus were plugged with cement. A subsequent well recompletion in 2002 included a 2-7/8" tubing x 7" production casing annulus test to 1000 psi. The plot of NCU 2 P/Z vs. cumulative production can be interpreted as indicating a volumetric reservoir and no fluid migration behind casing. 9. Fluid Type and Source Excess natural gas, either owned by Aurora or purchased from another producer or utility, will be injected in NCU 2 and stored for later reuse. The precise source of injection gas is not presently known. 10. Fluid Compatibility Aurora provided gas analysis representative of native gas originating from the Tyonek Formation and will inject only gas that is compatible with Tyonek gas. Stora e Infection Order • g J April 16, 2010 Page 5 of 9 11. Infection Rates and Pressures, Fracture Information NCU 2 gas injection pressure will vary significantly .depending upon the reservoir's depletion. Maximum injection pressure will be 1050 psi, maintained so that a pressure gradient of 0.46 psi/ft at mid-depth of the perforated interval is not exceeded. 0.46 psi/ft pressure gradient is equivalent to a gas injection rate of approximately 10 MMSCFD, through 3-1/2" tubing. The proposed maximum injection pressure in NCU 2 will not exceed a pressure gradient of 0.46 psi/ft, which is equivalent to about 1072 psi at mid-perforation (2309' TVD). The formation fracture gradient is estimated to be 0.9 psi/ft, or approximately 2078 psi at 2309' TVD. The proposed maximum injection pressure thus should not initiate formation fracturing in the proposed storage or confining strata. Original Upper Tyonek reservoir pressure is estimated to be about 1157 psi. 12. Underground Sources of Drinking Water The nearest drinking water supply well is about 100' deep, and it is located at Shirleyville Camp about 1.6 miles to the east. The nearest registered surface water rights claim is for Markley's Spring, which lies about 2 miles to the east (ref. DNR Case File No. LAS-3400). There are no other surface or subsurface water-rights claims registered with the Alaska Department of Natural Resources within 14 miles of the proposed storage operation. Aurora presented evidence suggesting that the total dissolved solids concentrations within the affected aquifers is less than 10,000 parts per million. Exemption of these aquifers is addressed in a separate order (see Aquifer Exemption Order No. 12). 13. Mechanical Condition of Pool Wells The proposed NCU gas storage area encompasses ten wells besides NCU 2. Six NCU wells have been plugged and abandoned. All wells are cased and cemented so as to not provide a conduit for injected gas to escape the injection zone. No corrective action is required. 14. Monitoring NCU 2 will be tested for mechanical integrity using the standard 30 minute annulus test per 20 AAC 25.412(c). To confirm continued mechanical integrity, Aurora plans to monitor daily injection rates and pressure and notify the AOGCC the next working day if the rates and pressure indicate pressure communication or leakage in any casing, tubing or packer. The rate and pressure data will also be reported to the Commission on a monthly basis. Mechanical integrity will also be monitored by observing the material balance plot (P/Z vs. cumulative gas produced or injected) during gas storage operations. Gas storage reservoir pressure and volume monitoring is a secondary check upon mechanical integrity. Data from the original depletion can be compared with Stora e Injection Order g J April 16, 2010 Page 6 of 9 subsequent injection and production cycles. Although some hysteresis may occur even in volumetric reservoirs, any problems that result in a loss of mechanical integrity will likely be evident from this data. 15. Public Comment The Commission received no protest nor written comments in response to the public notice. CONCLUSIONS: 1. The Nicolai Creek Unit, South Undefined Gas Pool gas storage project meets the requirements of 20 AAC 25.252. 2. There are no compatibility concerns between injected gas and native gas in the NCU South Undefined Gas Pool 3. Construction records, casing and cementing records, a cement bond log and a witnessed mechanical integrity test demonstrate the mechanical integrity of NCU 2 and demonstrate that fluids will not move behind casing beyond the gas storage zone. 4. The proposed injection and storage operations will be conducted in permeable strata, which can reasonably be expected to accept injected fluids at pressures less than the fracture pressure of the confining strata. 5. The thick interval (more than 150') of overlying, low permeability clay, siltstone, and coal that originally trapped gas in the Upper Tyonek reservoirs will prevent upward migration of stored gas. 6. The proposed injection of natural gas into NCU 2 for the purpose of storage will not propagate fractures through the confining zones. 7. Aquifer Exemption Order No. 12 separately addresses exemption of aquifers within the project area. 8. Surveillance of operating parameters for storage and offset wells will provide continued assurance that stored gas remains confined to the NCU South Undefined Gas Pool. 9. Limiting the reservoir pressure to 1050 psi for natural gas storage in the NCU South Undefined Gas Pool eliminates the need for additional pressure monitoring beyond commitments made by Aurora. 10. The proposed injection of natural gas into the NCU South Undefined Gas Pool for the purpose of storage will not cause waste, jeopardize correlative rights, endanger freshwater, or impair ultimate recovery. Stora a Injection Orde~ g J April 16, 2010 Page 7 of 9 NOW THEREFORE IT IS ORDERED that the following rules, in addition to statewide requirements under 20 AAC 25, apply to the underground storage of hydrocarbons by injection operations in the Carya 2-1.1, 2-1.2, and 2-2.1 sands of the well NCU 2 in the affected area described below: Seward Meridian Township 11N, Range 12W Section 29: SE '/ SW '/ NW '/; SW % SE % NW %; SW '/ NW '/ SW %; E'h NW % SW '/; W %2 NE '/ SW %; SW % SW '/; NW '/ SE '/ SW '/ RULE 1: STORAGE INJECTION The Commission approves injection for storage of natural gas in well NCU 2 within the South Undefined Gas Pool interval from 2426' to 2916'. RULE 2: DEMONSTRATION OF MECHANICAL INTEGRITY The mechanical integrity of well NCU 2 must be demonstrated before injection begins, and before returning the well to service following a workover affecting mechanical integrity. ACommission-witnessed mechanical integrity test must be performed after injection is commenced for the first time in the well, to be scheduled when injection conditions (temperature, pressure, rate, etc.) have stabilized. Subsequent tests must be performed at least once every four years thereafter. The Commission shall be notified at least 24 hours in advance of a test. Unless an alternate means is approved by the Commission, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1,500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater. Stabilizing pressure that does not change more than 10 percent during a 30-minute period is required for a valid test. Results of all mechanical integrity tests must be provided to the Commission. RULE 3: WELL INTEGRITY FAILURE AND CONFINEMENT The operator shall maintain a continuous data acquisition system to record flow rates and pressures on all active wells in the field. Field personnel must perform daily visual inspections and maintenance of all active wells and production equipment. Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by injection rates, operating pressure observations, tests, surveys, logs, or other evidence, the operator shall notify the Commission by the next business day and submit a plan of corrective action on a Form 10-403 for Commission approval. The operator shall immediately shut in the well if continued operation would be unsafe or would threaten contamination of freshwater, or if so directed by the Commission. Stora e Injection Order 8 g J April 16, 2010 Page 8 of 9 RULE 4: MAXIMUM RESERVOIR PRESSURE The reservoir pressure for this project shall be limited to 1050 psi. RULE 5: PERFORMANCE REPORTING The Operator shall report disposition of production and injection as required by 20 AAC 25.228, 20 AAC 25.230, and 20 AAC 25.235. An annual report evaluating the performance of the storage injection operation must be provided to the Commission no later than March 15. The report shall include material balance calculations of the gas production and injection volumes and a summary of well performance data to provide assurance of continued reservoir confinement of the gas storage volumes. Additional data collection and analysis will be based on a review of the operating performance and could include temperature surveys, pressure surveys, and production logs. RULE 6: OTHER CONDITIONS a. It is a condition of this authorization that the operator complies with all applicable Commission regulations. b. The Commission may suspend, revoke, or modify this authorization if injected fluids fail to be confined within the designated injection strata. c. As provided in 20 AAC 25.252(j), if storage operations are not begun within 24 months after the date of this Order, the injection approval shall expire unless an application for extension has been approved by the Commission. /// /// /// Storage Injection Order April 16, 2010 Page 9 of 9 RULE 7: ADMINISTRATIVE ACTIONS Unless notice and public hearing are otherwise required, the Commission may administratively waive or amend any rule stated above as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in fluid movement outside of the authorized injection zone. DONE at Anchorage, Alaska and dated April 16, 2010. Daniel T. Seamou~ t, Jr., Commissioner, Chair Alaska Oil and Gad Conservation Commission Gas Consekvati~ Commission Cathy P Foerster, Commissioner Alaska it 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 Co~mnission 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 Cormnission 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 afte~• the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the Commission by the application for reconsideration." • • 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 ~p,/d y/io%U • ~ 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; dapa; 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 (jeff.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 Joch~ J. Colomhie S~~ecial Assistant Alask~e Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK .9.9501 (907)793-1221 (phone) (907}276-7542 (fax) X10 O a ~ ~ SEAN PARNELL, GOVERNOR ALA58A OII, A1~TD GAS 333 W. 7th AVENUE, SUITE 100 CO1~T5FiIiQA'TIO1~T COM~IISSIOI~T ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 CERTIFICATION OF GAS STORAGE FACILITY AND WITHDRAWAL CAPACITY FOR THE NICOLAI CREEK GAS STORAGE FACILITY DOCKET NO. SIO-10-04 Acting upon the application by the owner, dated June 25, 2010, submitted in accordance with AS 31.05.032, for the Nicolai Creek Gas Storage Facility (NCGSF) operated by Aurora Gas, LLC (Aurora), the Alaska Oil and Gas Conservation Commission (Commission) HEREBY CERTIFIES: 1. THAT the NCGSF qualifies as a gas storage facility for purposes of AS 31.05.032, is subject to Commission Storage Injection Order (SIO), and has a working gas storage capacity of at least 500,000,000 cubic feet; 2. THAT the actual working gas storage capacity of the NCGSF is 700,000,000 cubic feet; and 3. THAT the NCGSF is capable of withdrawing a minimum of 10,000,000 cubic feet per day. Pursuant to SIO 008.000 dated April 16, 2010 the Commission authorized injection for underground storage of natural gas in the Nicolai Creek Unit (NCU) South Undefined Gas Pool, identified herein as the NCGSF. The plot of NCU P/Z vs. cumulative gas production indicates volumentric reservoir behavior, with no fluid migration behind well casing. The Commission also finds that the NCGSF has working gas storage capacity of at least 500,000,000 cubic feet of gas other than cushion gas; that the actual gas storage capacity of the NCGSF is 700,000,000 cubic feet; and, that based upon four-point pressure test analysis, well NCU #2 can produce 10,000,000 cubic feet of gas per day at a C~ flowing bottom hole pressure of approximately 670 psi. SIO 008.000's other findings and conclusions remain in effect and are hereby affirmed. If the NGCSF ceases commercial operation, then and in that event, the owner shall give the Commission written notice of such cessation, on or before April 1 of the year immediately following the year in which the gas storage facility ceases commercial Cathy . Foerster Com ` issioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the Commission by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. 2 U CERTIFICATE OF MAILING DOCKET NO. SIO-10-04 • I hereby certify that a true and correct copy of the attached CERTIFICATION OF GAS STORAGE FACILITY AND WITHDRAWAL CAPACITY FOR THE NICOLAI CREEK GAS STORAGE FACILITY (NCGSF) was mailed on July 27, 2010 to each of the following at their addresses of record: Commissioner Thomas Irwin Department of Natural Resources State of Alaska 550 West 7~' Avenue, Suite 1400 Anchorage, Alaska 99501 Commissioner Patrick Galvin Department of Revenue State of Alaska Po Box 110400 Juneau, Alaska 99811 Aurora Gas, LLC 1400 West Benson Blvd., Suite 410 Anchorage, Alaska 99503 Attn: Mr. Bruce Webb Manager, Land and Regulatory Affairs Jod .Col bi Sp al As stant Alaska Oil and Gas Conservation Commission r~ SUBSCRIBED AND SWORN TO before me this~~ day of July, 2010. ~, - `_ ~ ~%']~-- ~` of y Public in an ~ or the State of Alaska My commission expires: 11/11/2010 3 ~9 ~~; June 25, 2010 Mr. Daniel T. Seamount, Jr., Chairman Alaska Oil and Gas Conservation Commission 333 West 7`" Avenue, Suite 100 Anchorage, AK 99501 RE: Nicolai Creek Gas Storage Facility Request for Certification under AS 31.05.032 (HB 280) Dear. Mr. Seamount: Aurora Gas, LLC ("Aurora") wishes to obtain certificatiort of the proposed Nicolai Creek Gas Storage Facility ("NCGSF"). Specifically, Aurora requests the ~~laska Oil and Gas Conservation Commission ("AOGCC") to certify the proposed NCGSF's worl~.i gas storage capacity end the proposed facility's withdrawal capability and that the propgsed?~~:GSF qualifies as a gas storage facility under AS 31.05.032. This request is made in accordance w~House Bill No. 280 which was recently signed into law by Governor Parnell. Reference is made to the AOGCC Storage Injection Order No. ~ ("SIO 8"), issued on April 16, 2010, for the Nicolai Creek Gas Field, South Undefined Gas PoQ(, utilizing the existing Nicolai Creek Unit No. 2 ("NCU 2") well located within the Nicolai Creek Unit. In Finding 6 of SIO 8, the working gas capacity is estimated to be between 600 MMSCF and 700 MMSCF. The estimated ultimate recovery of the NCU 2 reservoir is estimated to° 947 MMSCF. Porosity in the NCU 2 reservoir strata ranges between 19% and 25%, with permeability estimated at 120 millidarcies. In October 2002, afour-point test was performed on the NCU 2 well. Based on this data, the well is estimated to be capable of producing 15,617,000 cubic feet per day at 1,040 psi, using the Ryder Scott Four-Point Test Summary (attached). As a result of this test, the NCU 2 well, separator and production facilities were designed to process 10,000,000 cubic feet per day. In January 2009, PB Energy Storage Services, Incorporated (``PBESS"} was contracted to do a study on the proposed NCGSF. PBESS concluded that the current configuration of the NCU 2 well and reservoir was capable of producing between 11,000,000 and 12,000,000 cubic feet per day. Under AS 31.05.032 (b), the AOGCC shall determine and certify that a gas storage facility have a working gas capacity of at least 500,000,000 cubic feet of gas and be capable of withdrawing a minimum of 10,000,000 cubic feet of gas per day. Based on the above referenced Findings and supporting test and engineering data, the proposed NCGSF exceeds both of these criteria. Therefore, Aurora believes the proposed NCGSF qualifies for the purposes of AS 31.05.032. ~ ~~~ 25~' ~~d~st°~3E ~~a;,~s',a ~a~o~~ ~,i s°3 ~ ~®"9+~d~a~3°w~~9 :~~ ~~~~~ o {~~?~') ~~y -.~ ~$~"~ ®d'~~; ~~~~~ ~^o' ~°.~3eZ'~ June 25, 2010 Dan Seamount, Jr, Chairman Alaska Oil and Gas Conservation Commission Nicolai Creek Gas Storage Facility HB 280 Gas Storage Facility Certification Page 2 • Although AS 31.05.032 (a) states that the application for this certification be on a form prescribed by the AOGCC, in absence of such a form, Aurora requests that this letter serve as a substitute for said form at this time. Aurora will complete the necessary form once it is created by the AOGCC. It is Aurora's desire that the certification process start as soon as reasonably possible. Thank you for your time and consideration of this request. Should you need additional information, please do not hesitate in contacting me. Respectfully, cc~ t'~/~ Bruce D. Webb Manager, Land and Regulatory Affairs Attachment Cc: Temple Davidson, DNR, Division of Oil and Gas • • Ryder Scott WELL NAME: NICOLAI CREEK UNIT NO. 2 -- - _ __ -- __- Reservoir FIELD: NICOLAI CREEK - - --- ~t ~"° _ Solutions LOCATION: T11N, R12W SM. Kenai Borough, West Side Cook Inlet, Alaska ~ __ __ ~ ' (Public) RESERVOIR: Upper Tyonek, 2426-2916' MD (test of 1012002) ' (Protected) , BOTTOMHOLE TEMP, °F: 77 SOUR GAS MOLE GAS GRAVITY: ____ 0.560 -- - NZ 1.06 - _ - HZO GRAVITY, y,„: 1.005 COZ 0.00 - - COND. GRAV., °API: HZS 0.00 TVD, FT: 2,309 MEAS. DEPTH, FT: 2,671 Options Cond. Correl. (Y/N): - - N ^ Check, If Injection Well Corrected Tc, °R - _ - 343.48 - th Pi R h ~ S Corrected* Pc, Psia: 671.84 moo pe ness oug Pressure Base, Psia. 14.730 TUBING ID, IN.: 2.441 * Wichert-Aziz correction for co ntaminants, if any RESULTS AOF, Mcf/d: 15,617 C: 0.218782 n: 0.800868 ~o,ooo 0 X y a i,ooo a POINT NO. Test Data FLOWING (Automatic) Q, Mcf/d BCPD BWPD FTP, Psia WHT, °F BHP, Psia COMMENT SHUT-IN ', 0 - _ 0 ___ ! 0 _ 976 _ 38 1,072 SIBHP 1 i - 1,916 0 8 , 964 _ 26 ~ 1,025 26/64 chk 2 3,513 0 0 , 935 34 1,000 30/64 CHK 3 - - 4,211 _ 0 --- 0 905 33 975 32/64 4 -- 5,078 0 0 833 33 909 38164 These results were prepared using Reservoir Solutions Software . This is not Ryder Scott work product. iao goo ~,ooo ~o,ooo ioo,ooo Flow Rate, Mcf/d • • Colombie, Jody J (DOA) r` From: Ed Jones [jejones@aurorapower.com] Sent: Friday, July 23, 2010 11:59 AM To: Colombie, Jody J (DOA) Cc: 'Bruce D Webb'; 'G Scott Pfoff Subject: Nicolai Creek 2 Storage Volumes Attachments: NCU 2 Log Analysis & Volumtric Reserves.xlsx; NC2 PzCum_RSC2.xls Jody, As requested thru Bruce Webb, I have attached volumetric reservoir volume calculations and supporting log analysis indicating that the NCU 2 reservoir has a capacity of about 950 MMcf (0.95 BCF). This number is confirmed by the attached P/Z plot based on production and BHP's to date. Based on these analyses, and supported by the work done by PB Energy Storge Services, Inc., (PB ESS) a 3rd party expert consulting firm, we believe that the reservoir will support 700 to 750 MMcf (0.7 to .75 BCF) of "working storage volume," leaving a "pad gas" volume of 200-250 MMcf (0.2 to 0.25 BCF). The "working gas" volume is further supported by the fact that the well has produced this much gas, 762 MMcf, since completion in these zones and it is still producing. The exact volume of working gas, however, will be somewhat dependent upon the facility's configuration (i.e., compression and number and type of wells, likely including a horizontal well), which in turn is somewhat dependent upon the needs of the customer of the storage services (out-take rates and time). Please let me know if you would like a copy of the PB ESS report or if you need any other additional information. Regards, Ed J. Edward Jones Executive Vice President, Eng. & Ops. Aurora Gas, LLC 6051 North Course Dr., Ste 200 Houston, TX 77072 281-495-9957 (O) 713-899-8103 (C) ~ WELL NAME: NICOLAI CREEK UNIT NO. 2 Ryder Scott ~~ FIELD: NICOLAI CREEK Reservoir ,,~ COUNTY, STATE: T11 N, R12W SM, Kenai Borough, West Side Cook Inlet, Alaska Solutions -~ ~~ RESERVOIR: Upper Tyonek, 2426-2916' MD (Public) * Wichert-Aziz correction for contaminants, if any (Protected) WELLHEAD TEMP, °F: 45.0 SOUR GAS MOLE % Least Squares Mean Fit Results BOTTOM HOLE TEMP, °F: 77.0 NZ 1.06 Y-Intercept, BHPIz - - 974 WET GAS GRAVITY: 0.5607 COz 0.00 OGIP, MMCF 993 TVD, FEET: 2,309 HZS 0.00 COND. CORR? (Y/N): N EUR, MMCF 947 Corrected Tc, °R: 343.70 Recovery Factor 0.9538 Corrected* Pc, Psia: 671.82 BHP/z @ Abandonment 45 ~-"~° 1,400 •LSMF Data o Excl. Data •EUR = 947 •OGIP = 993 1,200 1, 000 ~a 800 . N a N a ~ m 600 400 ~~ O 200 O 0 0 200 400 600 800 1,000 1,200 Cumulative Production, MMcf POINT NUMBER DATE BHP/Z, CUM PROD, LSMF (Automatic) (Optional) SITP, Psia BHP, Psia Z Psia MMcf Include? (Y/N) 1 11/21/2003 1,016 1,073 0.8721 1,230 0 n -- 2 - 11/22/2003 1,002 1,058 0.8736 1,211 2 n 3 11/22/2003 1,004 1,060 0.8734 1 1,214 2 N 4 2/11/2004 _ 766 807 0.9004 ', _ _ 896 142 y 5 6/15/2004 555 584 0.9264 ' 630 267 _N 6 7/15/2004, 595, 626 0.9213 _ 680 270 y 7 12/31/2004 385~I 404 0.9483 427 461 n 8 4/30/2005 395 415 0.9470 438 470 n _ 9 7/16/2005 415 436 0.9444 462 472 y 10 2/17/2006 225 236 0.9695 ~ 244 554 n _ 11 9/14/2006 168 176 0.9772 180 609 ; n 12 10/3/2006 195'. 204, ___0.9736 210 609 N 13 12/31/2006 240'. 252 0.9675 260 624 N 14 1/18/2007 255' 268 0.9655 277 624 N 15 2/4/2007 275 289 0.9629 300 624 n 16 3/8/2007 300 315 0.9595 ', 328 624 Y 17 4/30/2007 295 310 0.9602 . _ 323 630 Y 18 8/11/2007 2871 _ 301 - ~ 0.9613 313 647 ~ '. Y 19 -~~~ 5/29/2008 124' 130 0.9832 132 712 n 20 ~I 1/31/2009' 255' 268, 0.9655 277 729 Y These results were prepared using Ryder Scott's Gas Material Balance. This is not Ryder Scott work product NICOLAI CREEK UNIT #2 AURORA GAS, LLC LOG ANALYSIS SUMMARY (NT--NuTech NuLook log analysis) DEPTH INTERVAL PERFS ML RESISTV Porosity NT NT SITP BH Temp Rw WTR SAT NT PERM COMMENTS MD MD SHOWS Rd NT Sw Net Pay psig Calc Sw est TVD NET SD (avg) (avg) TVD Calc BHP (avg) (avg) ft units ohm-m % % psia % and Carya 2-1.0 BEHIND PIPE 2206 2212 6 200 16 23.2% 48.0% 6 36 2244 2260 16 1800 20 24.0% 45.0% - 74.0 0.407 42% - looks wet on TDT, 2314 2320 6 100 16 24.0% 48.0% 6 70 but best ML show 1966 2049 21 18 24.0% 44.0% 933 74.0 0.407 44% estimated Carya 2-1.1 2426 2476 50 300 51 960 perfed 2002 2141 2177 36 20 25% 43% 37 1025 75.7 0.399 39% 116.5 0.479 Carya 2-1.2 2700 2716 16 280 0 1010 perfed 2002 2342 2356 14 18 23% 45% 1083 78.1 0.388 44% 0.462 Carya 2-2.1 2893 2916 23 140 13 1090 perfed 2002 2493 2511 18 20 23% 46% 10 1172 79.9 0.380 42% 55 0.470 arya 2-2.3 original perfs 3270 3315 45 300 20 1180 Produced 51 MMcf in 68-69 before water & 27801 2815 35 13 24% 50% 16 1277 83.4 0.365 49% 49.4 sand hit--was 0.459 lu ed back in '91 CURRENT MD PERFS 89 CURRENT TVD PERFS 70 ASSUMPTIONS: Rw @120 ~ 0.45 in Beluga Sw=Sq Rt ((1/POR**1.5 )*(Rw/Rt)) BHT= 80 deg @ 2500' 0.25 in Tyonek 50+1.2*D/100 NICOLAI CREEK UNIT #2 VOLUMETRIC RESERVES TVD TVD CALC TEST COMMENTS INTERVAL NT Net Net Pay POR Sw BHP MCFPD ZONE 2206 2320 10 2426 2476 37 2700 2716 0 2893 2916 10 CURRE NT PERFS S/T 47 3270 3315 16 TOTAL 72 2206 2320 74.0 2426 2476 75.7 2700 2716 78.1 2893 2916 79.9 CURRENT PERFS S/T 3270 3315 ~ 83.4 124 Z 0.888 0.882 0.876 0.87 0.863 933 NOT TESTED Carya 2-1.0 1025 3200 Now producing Carya 2-1.1 1083 4260 Now producing Carya 2-1.2 1172 4700 Now producing Carya 2-2.1 1277 4220 Original completion Carya 2-2.3 407 88 40 0.77 484 90 45 0.77 554 448 90 45 0.77 195 467 90 45 0.77 148 897 MMCF 503 66 40 0.77 55 TOTAL ULTIMATE POTENTIAL 952 MMCF Production thru6/30/10= 762 REMAINING RESERVES= 190 MMCF PROVED-- volumes matches P/Z curve Carya 2-1.0 Carya 2-1.1 Carya 2-1.2 Carya 2-2.1 Carya 2-2.3--produced 55 MMCF before water and sand started. EXPECTED EUR (from P/Z vs. Cum)= 947 MMF NOTE: 1) The Proved Reserves above are all recoverable in current completion. The Carya 2-2.1 has lower perm and seems to pressure up well when SI for long term--P/Z curve is shifting outward with time, indicating that early points were most affected by higher perm zones. 2) the Probable reserves will require a rig workover: drilling out cement and reperforating the Carya 2-2.3, which was probably abandonded permaturely, and perforating the Carya 2-1.0--the cost of this is estimated at $750,000 to $1,000,0000 for 544 MMcf. 3) The P/Z vs. Cum Production curve appears to be shifting to the right, indicating a dual perm system and increased recoveries. Ed Jones Rev. 10/09 21 24% 44% 36 25% 43% 14 23% 45% 18 23% 46% 68 35 24% 50% v Y M ~8 • Page 1 of 2 Regg, James B (DOA) From: Regg, James B (DOA) Sent: Wednesday, April 28, 2010 2:59 PM ~(~~~~ To: 'dennis.hinnah@dot.gov' Cc: Aubert, Winton G (DOA) Subject: RE: Gas Storage Jurisdictional Question I referenced the wrong Swanson River storage injection order; it should have read SIO 6, not SIO 3 Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 907-793-1236 From: Regg, James B (DOA) Sent: Wednesday, April 28, 2010 2:42 PM To: 'dennis.hinnah@dot.gov' Cc: Aubert, Winton G (DOA) Subject: RE: Gas Storage Jurisdictional Question Dennis - Winton and I discussed your request; I also checked with our Stat Tech who handles Monthly Facility Gas Disposition reports. AOGCC does not know the exact source of the gas that goes into storage unless the operator chooses to offer the information as part of one of its required reporting obligations. The operator's application for storage injection is required to identify the injected fluids (source) per 20 AAC 25.252(c)(7) which most often includes provisions for accepting gas from other unnamed sources that have gas compatible with the storage zone formation fluids. For the fields you name, the operator lists the following likely gas sources: SIO 3 -Swanson; application says source of gas will be from Swanson River Field initially and from other Cook Inlet fields in the future; SIO 4 -Pretty Creek; application says source of gas will be from excess Union-owned gas likely from Steelhead platform (McArthur River Field; Trading Bay Unit) and could also be sourced from Beluga River field or other west side properties operated by other operators; SIO 7A -Kenai; application says source of gas will be Kenai and Cannery Loop or sources deemed compatible with Sterling Pool 6; S10.8 - Nicolai Creek; application says source of gas is "not presently determinable"; could come from other Aurora operated fields or purchased from another producer or utility. We checked the annual gas storage performance reports required by injection order rule; these focus on volume injected/produced and ongoing integrity of reservoir/wellbore without identifying the source. Our Storage Injection Order files include copies of the Storage Development Plans field with DNR; those include references to source(s) of gas for the gas storage project. For example, the DNR Storage Development Plan for Kenai Unit indicates gas from only Kenai Unit and Cannery Loop Unit has been injected to date. Because of the Commission's regulatory focus (reservoir and well performance/integrity perspectives) and lack of jurisdication beyond the point of custody transfer, we do not have information on pipeline(s) used to transfer the gas to storage injection well. We also do not have information about any processing facilities between a production well and storage injection well. Regarding inspections, our focus is the wellhead safety valve system, wellbore integrity and custody transfer measurement; we do not perform safety inspections at storage facilities. I think you are going to find there is more likely to be a regulatory gap than there would be regulatory overlap regarding surface facilities servicing gas storage operations. Sounds like your best bet is to obtain information about the source of gas from the operators. 4/28/2010 Page 2 of 2 Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 907-793-1236 From: dennis.hinnah@dot.gov [mailto:dennis.hinnah@dot.gov] Sent: Wednesday, April 28, 2010 11:40 AM To: Aubert, Winton G (DOA); Regg, James B (DOA) Subject: Gas Storage Jurisdictional Question Hi Winton/Jlm, I am trying to figure out a jurisdictional question related to the gas storage fields in Alaska and I am hoping you can help me. As I understand it, these are the four gas storage fields: Swanson River Field, operated by operated by Union Oil Company of California (SIO 3) Pretty Creek Gas Storage Facility, operated by Union Oil Company of California (SIO 4) Kenai Gas Field, operated by Marathon Oil Company (SIO 6) Nicolai Creek Field, operated by Aurora Gas, LLC (SIO 8) PHMSA has jurisdiction in gas storage fields for surface piping, compression, etc. where the source of the gas is from a pipeline regulated by PHMSA. It is not clear what our jurisdiction is if the gas is moved between wells in the same field to get it to a well with higher deliverability or different reservoirs in the same field. There are probably other scenarios that I haven't thought of. I reviewed the Storage Injection Orders and wasn't able to find what I need. For each Storage Injection I would like to know the source of the stored gas, the pipeline(s) it travels through, and any processing facilities between the production well(s) and injection well(s). I included Jim on this email, because I would also like to know the extent of the safety inspections that the AOGCC does at the storage facilities. I don't see much jurisdictional overlap but things such as a pressure relief device that protects both the well and the pipeline or a common cathodic protection system would probably be jurisdictional to both agencies. Some of this could involve DNR or BLM jurisdiction, but so far I haven't seen anything leading me in that direction. I would be happy to discuss this further or if you would like to meet please let me know. Thanks, Dennis Dennis Hinnah, P.E. Deputy Director, Western Region U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration Phone: 907-271-4937 4/28/2010 ~ 7 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 ALASKA OIL AND GAS CONSERVATION COMMISSION Before Commissioners: Daniel T. Seamount, Chair Cathy Foerster John K. Norman In the Matter of the Application of Aurora Gas, LLC, for an Order Authorizing Underground Natural Gas Storage in the South Undefined Gas Pool Well Nicolai Creek number 2 in Conformance with 20 AAC 25.252 and 20 AAC 25.412 ~~ Mq R~~~~~~~ Alaska ®il ~ Gas ~~~` _, '~a~hota~,e ~'~~'~~SS%C~6r ALASKA OIL and GAS CONSERVATION COMMISSION Anchorage, Alaska March 17, 2010 9:00 o'clock a.m. VOLUME I PUBLIC HEARING BEFORE: Daniel T. Seamount, Chair Cathy Foerster, Commissioner John K. Norman, Commissioner R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 • • TABLE OF CONTENTS Opening remarks by Chair Seamount Testimony by Bruce Webb Testimony by Edward Jones R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 03 05 08 1 P R O C E E D I N G S 2 (On record - 9:00 a.m.) 3 CHAIR SEAMOUNT: On the record. I'd like to call this 4 hearing to order. The date is March 17th, 2010, Saint 5 Patrick's Day. It's approximately 9:00 a.m. We're located at 6 333 West Seventh Avenue, Suite 100, Anchorage, Alaska. Those 7 are the offices of the Alaska Oil & Gas Conservation 8 Commission. 9 I'll start by introducing the bench. To my left is 10 Commissioner Cathy Foerster who holds the engineering seat on 11 the Commission, to my right is Commissioner John Norman who 12 holds the public seat on the Commission. And I am Dan 13 Seamount, I'm the Chair and I hold the geological seat. 14 R & R Court Reporting will be recording the proceedings. 15 You can get a copy of the transcript from R & R Court 16 Reporting. 17 We'd like to remind those that are testifying to speak 18 into the microphone so that persons in the rear of the room can 19 hear and so the court reporter can get a clear recording. 20 As far as testifiers, looks like we have a bunch of 21 question marks so we'll address that when we get to it. 22 This is Docket SIO-10-01. That concerns the application 23 of Aurora Gas, LLC for an order authorizing underground natural 24 gas storage in the south undefined gas pool, well Nicolai Creek 25 number 2. And that would be in conformance with 20 AAC 25.252 R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 3 • • 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 and 20 AAC 25.412. Notice of this hearing was published on February 12th, 2010 in the Anchorage Daily News as well as the State of Alaska online notices and the AOGCC website. This hearing is being held in accordance with 20 AAC 25.540 of the Alaska Administrative Code. Those are the regulations governing public hearings. The hearing will be recorded. If there's anyone in the room that would like to ask questions of the witnesses the way to do that is you put your question in writing along with your name and that of the witness that you'd like the question to be asked of and you would hand it to one of our designated Commission representatives, either Ms. Jody Colombie or Ms. Samantha Fisher. She's brand new to the Commission. So welcome, Samantha. Okay. So let's get on with it and go to the first person to testify and I would think that would be a representative of the applicant. Does the applicant wish to testify? MR. WEBB: I believe we were here just to answer questions. CHAIR SEAMOUNT: We have in the record the -- a lot of the testimony, I assume that if you were to testify that would be what you'd testify to. So, Commissioner Norman, you're the one that's best on procedure. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 4 • • 1' 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 COMMISSIONER NORMAN: It is customary to have the applicant come forward and briefly state why we're here today. The purpose being that a year from now someone will read this record and so we're here at the request of the applicant so we look to the applicant to come forward and make an initial request. We do have your written filing, but we would appreciate a brief summary of what you're seeking to accomplish by what you have filed. CHAIR SEAMOUNT: Please raise your right hand. (Oath administered) MR. WEBB: I do. CHAIR SEAMOUNT: And would you wish to be considered an expert witness? It's not necessary. MR. WEBB: Probably not..... CHAIR SEAMOUNT: Okay. MR. WEBB: .....since I'm not a geologist or an engineer. CHAIR SEAMOUNT: Okay. Please state your name and who you represent. BRUCE D. WEBB called as a witness on behalf of Aurora Gas, testified as follows on: DIRECT EXAMINATION MR. WEBB: I work for Aurora Gas. Bruce D. Webb, Aurora Gas. I'm the manager of Land & Regulatory Affairs. The reason for the hearing is we've applied for a storage injection order R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 5 • • 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 i 24 25 to inject dry methane gas into the Nicolai Creek number 2 reservoir which is currently almost depleted. The field is located on the west side of the Cook Inlet, just a short distance southwest of Tyonek. And we have several operating wells in the area, the Nicolai 1, 2, 9, 3 and 11. The injection zones that we're seeking to inject in are the Tyonek, Karia 2-l.l, 2-1.2 and 2-2.1 sands and they are located at a true vertical depth of 2,141 down to 2,494 feet. We've submitted structure maps which we believe indicate the extent of the reservoir. I think that's the basic application right there. CHAIR SEAMOUNT: Thank you, Mr. Webb. Out of curiosity where will the gas be coming from, is it gas that you produce or will it be coming from someone else's production? MR. WEBB: It will be gas that we produce and most likely from the area wells at the Nicolai Creek, but it could also include gas from Moquawkie or Lone Creek. CHAIR SEAMOUNT: Commissioner Norman, do you have any questions? COMMISSIONER NORMAN: I do have a few. Would it be -- and thank you, Mr. Webb, for coming forward and putting that on the record, that sets the stage for what we're about to do. I have a couple of questions and I see others may be here with you. Would it be appropriate to ask them to come forward and respond to questions now or..... R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 6 ~ • 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 i 24 25 MR. WEBB: I believe so. Mr. Ed Jones is our reservoir and drilling engineer so he's probably the most knowledgeable about gasification. COMMISSIONER NORMAN: Very well. And if you are here to answer questions for the applicant Aurora, why don't you come forward and just find a seat at the table. There are two microphones in front of you, but don't be confused by that. One of them is for amplification and the other one is for the benefit of the court reporter. And eventually we will get a new, modern system in this building. These are some question -- or a question, if you know, and if you don't why we have information that may fill in some gaps, but I am curious what water wells are in this area, the vicinity of the proposed injection reservoir, what's the nearest water well? MR. JONES: The nearest water well is probably at Shirleyville camp which is well over a mile away..... COMMISSIONER NORMAN: Okay. MR. JONES: .....and it's very shallow. COMMISSIONER NORMAN: And do you know what depth that would be? MR. JONES: It's less than 100 feet deep, I believe, I don't know the exact depth, but it's very shallow. COMMISSIONER NORMAN: Okay. Any others within that mile or so? R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 7 • • 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 ~~ 22 23 24 25 MR. JONES: Not within a mile or so that we're aware of, no. COMMISSIONER NORMAN: Okay. Very good. And what volume -- if this reservoir were to be filled to the maximum, what volume of gas would it hold? MR. JONES: It would hold just less than 1 bcf. We're thinking the recoverable volume from the reservoir is about 950 million cubic feet of gas. COMMISSIONER NORMAN: Very well. Mr. Chairman, I neglected to suggest that Mr. Jones also be sworn and qualified..... CHAIR SEAMOUNT: Oh, that's true. COMMISSIONER NORMAN: .....and so perhaps we should do that in the..... CHAIR SEAMOUNT: Okay. (Oath administered) MR. JONES: I do. EDWARD JONES called as a witness on behalf of Aurora Gas, testified as follows on: DIRECT EXAMINATION CHAIR SEAMOUNT: And please state your name and who you represent. MR. JONES: Edward Jones, Aurora Gas, LLC. CHAIR SEAMOUNT: I would assume you would want to be R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 8 • • 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 considered an expert witness? MR. JONES: Yes, that's correct. CHAIR SEAMOUNT: Okay. Then please state what you're -- what the subject is and what your qualifications are? MR. JONES: Petroleum engineering is the subject. Qualifications are 35 years of experience and a Bachelor's degree in Engineering. CHAIR SEAMOUNT: And where did you go to school? MR. JONES: Colorado State University. CHAIR SEAMOUNT: Good school. Any questions or -- Commissioner Norman? COMMISSIONER NORMAN: Just a -- I'll ask him a question. Mr. Jones, you understand that the -- prior to being sworn and stating your qualifications, the answers you gave, would you agree that they are under oath and that they were given in your capacity as an expert witness? MR. JONES: I do, yes. COMMISSIONER NORMAN: Thank you. I have nothing further, Mr. Chair. CHAIR SEAMOUNT: Commissioner Foerster from the University of Texas, do you have any questions or concerns, do you disagree -- do you agree that he should be considered an expert witness? COMMISSIONER FOERSTER: Oh, I have no problems with considering Mr. Jones an expert witnesses. Whenever you're R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 9 • • 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 done I have questions. CHAIR SEAMOUNT: I'm done, what's your question? COMMISSIONER FOERSTER: Well, I wanted to clarify on a question that Commissioner Norman asked. He asked you if the reservoir was full how much could it hold. I'm assuming he meant if it were returned to the original reservoir pressure. MR. JONES: Okay. It would be just a little over a bcf total volume, recoverable is about 950 million cubic feet of gas. COMMISSIONER FOERSTER: Okay. So it was a little over a bcf of gas in place? MR. JONES: Yes, that's correct. COMMISSIONER FOERSTER: Okay. You submitted a water sample that has less than 10,000 parts per million, is that correct? MR. JONES: Yes, there are several of them just less than 10,000 parts per million, yes. COMMISSIONER FOERSTER: And -- all right. So I think in this case we would have to consider an aquifer exemption. Are we going to have the testimony related to that by you guys or would..... CHAIR SEAMOUNT: I think what we have to do is notice it..... COMMISSIONER FOERSTER: Okay. CHAIR SEAMOUNT: .....30 day notice and then if someone R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 10 • • 1 2 3 4 5 6 7 8 9 10 11 12 13 14' 15 16 17 18 19 20 21 22 23 24 25 wants a hearing then we'll have the hearing, we'll have testimony at that time. COMMISSIONER FOERSTER: Okay. So we don't need to worry about addressing the aquifer exemption today. CHAIR SEAMOUNT: Except to state that it's prudent, that..... COMMISSIONER FOERSTER: That it -- that we -- that we'll need to get one. CHAIR SEAMOUNT: .....that'll we have to go for an aquifer exemption under law. COMMISSIONER FOERSTER: Okay. Okay. I don't have any other questions at this time. CHAIR SEAMOUNT: Okay. Mr. Jones, originally you were talking about injecting at a higher pressure than the original reservoir pressure and you backed off of that. But there was a statement that, you know, it wouldn't go behind a fracture gradient. However I notice from your structure maps that it looks like the structure is fault sealed on a couple of sides. And do you have any thoughts on, you know, what the fracture gradient of the fault would be, I mean, would that be less than the fracture gradient of the seal? MR. JONES: Well, I would expect that to be the case, but we really don't have any data that would support that. CHAIR SEAMOUNT: Okay. So that would probably be why we were concerned about going too high on the pressure. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 11 • s 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 i 19' 20 21 22 23 24 25 Okay. We have a number of questions from the Department of Natural Resources that it would be fair to ask. And that would be from Temple Davidson who is a petroleum engineer, is that correct? MS. DAVIDSON: I'm a petroleum land manager. CHAIR SEAMOUNT: Petroleum land manager. Okay. (Off record comments) CHAIR SEAMOUNT: Okay. Here's question number 1. Given the boundary of the participating area, could you explain how storage reservoir proposed boundaries are different? MR. JONES: Well, I believe that the proposed boundaries are outside of the reservoir boundaries, in other words, they encompass the reservoir, what we think the reservoir volume to be. And they're straight lines and describable by survey. CHAIR SEAMOLTNT: All right. Are you satisfied, Ms. Davidson? MS. DAVIDSON: I was curious as to just a little bit of description as to the methodology by which the participating area boundaries were arrived at versus what the boundaries of the storage reservoir are. If that's -- you know, the basic question, if that's supposed to be the boundary of the reservoir that's not necessarily reflected (indiscernible - away from microphone)..... MS. COLOMBIE: She needs to go forward so that we can get a good recording. R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 12 • ~ 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19~ 20 21 22 23 24 25 CHAIR SEAMOUNT: Is that appropriate, Mr. AG? MR. BALLENTINE: Well, it would be up to you, but I think probably -- I mean, can we just take like two minutes? CHAIR SEAMOUNT: Okay. We'll take a five minute recess. MS. DAVIDSON: Would it be more appropriate for me to ask that question in a different venue? COMMISSIONER FOERSTER: Yeah. Yes, it would. CHAIR SEAMOUNT: Probably it would be. COMMISSIONER FOERSTER: Yes, it would. MS. DAVIDSON: That's fine. CHAIR SEAMOUNT: Yeah. So, Mr. Jones, you'll be expecting a call. COMMISSIONER FOERSTER: Let's look at the rest of the questions, maybe the rest of the questions are the same thing. CHAIR SEAMOUNT: I think they're either appropriate or could be asked quickly. COMMISSIONER FOERSTER: Yeah. CHAIR SEAMOUNT: Number 2, where will the surface facilities be located? MR. JONES: The surface facilities will be located right where the existing production facilities are essentially which is at the end of the Shirleyville airstrip. There's a -- I believe there's a description of it in the application. CHAIR SEAMOUNT: Okay. Fair enough. Number 3, what is the maximum storage pressure requested. And I think that we've R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 13 • • 1 2 3 4 5 6 7 8 9 10 11 12 13 '' 14 15 16 17 18 19 20 21 22 23 24 25 already answered that question. And what is it, 1,157 psi, is that maximum? MR. JONES: Well, actually we back that off to 1,050..... CHAIR SEAMOUNT: Okay. MR. JONES: .....prig at surface. Yeah. CHAIR SEAMOUNT: Okay. Number 4, what is anticipated working gas? MR. JONES: The volume of working gas would be expected to be obviously someplace less than..... CHAIR SEAMOUNT: Right. MR. JONES: .....than 1 bcf, probably on the order of six or 700 million cubic feet of gas. CHAIR SEAMOUNT: Okay. That's -- okay. That's right. And what's the anticipated cushion gas? MR. JONES: Well, it would be the balance of that which is probably three to 400 million. CHAIR SEAMOUNT: And maximum deliverable rate? MR. JONES: From this well we would expect it to be less than 20 million cubic feet of gas per day. CHAIR SEAMOUNT: And then I believe the total volume nominal -- that's been answered, correct? MS. DAVIDSON: Yes. CHAIR SEAMOUNT: And could you describe the compression operations? MR. JONES: Well, the compression operation will in part R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 14 ~ • 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 depend upon who our customer is, who the client is and what their needs are. We currently have a compressor on site, but we will likely add one or two more just depending on what the deliverabiity will be and the source of gas, what the injection rates will be. So we'll size the compression for the requirement of both injection and depletion. CHAIR SEAMOUNT: Okay. Thank you. And I have a question for our Staff and they can just nod their heads. Do we have all the information we need to make a decision at this time? DR. AUBERT: (Nods affirmatively) CHAIR SEAMOUNT: Okay. Dr. Winton Aubert nodded in the affirmative. Commissioner Foerster, do you have any more questions? COMMISSIONER FOERSTER: Not at this time. CHAIR SEAMOUNT: Commissioner Norman. COMMISSIONER NORMAN: Just two quick ones, Commissioner Seamount. On timing, if everything fell into place ideally in the permitting process and so forth from your operational timetable, when would you see commencement of injection for storage? MR. JONES: Well, there are a number of factors that would influence that. I would expect that probably not until early 2011. COMMISSIONER NORMAN: Okay. And I wanted to make sure I understood you. The reservoir, the storage reservoir, would R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 15 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 • • hold roughly 1 bcf, 1 billion cubic feet of gas? MR. JONES: Right. That's the volume of the reservoir, yes. COMMISSIONER NORMAN: Right. MR. JONES: Now the working volume would be less than that. COMMISSIONER NORMAN: Yes, uh-huh. And that's where my question is going. I understood you to say that cushion gas would be three to 400 mcf or a million cubic..... MR. JONES: Likely. Now it all depends again..... COMMISSIONER NORMAN: .....not thousand, but million? MR. JONES: Yeah. It all depends on the client's need. Obviously the lower the volume in the reservoir the less the rate will be coming out of the reservoir. So it'll -- part of that will depend on what the needs of the client are. We expect the client to have a fairly high volume requirement so that will require the pressure in the reservoir to be maintained at a fairly high level. We could possibly draw it down much lower than that, in fact, right now we believe that there's probably about 200 million remaining in the reservoir. And I wouldn't anticipate it to get any lower than that. It could possibly, but I wouldn't think that would be the case. COMMISSIONER NORMAN: Okay. Thank you. COMMISSIONER FOERSTER: Who's the client? MR. JONES: Well, we do not have a client at this time and R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 16 • • 1 2 3 4 5 6 7 8 9 10 11 12 13 I 14 II 15 16 17 18 19 20 21 22 23 24 25 we -- we're talking to several interested parties, we have not signed a contract. Everyone's sort of -- it's somewhat of a vicious circle, everyone's sort of waiting on the next step and we're trying to just keep the process moving. COMMISSIONER FOERSTER: But the client would be a gas purchaser, not a..... MR. JONES: Yes, a gas user. COMMISSIONER FOERSTER: A gas user, not a storage user? MR. JONES: That's right. COMMISSIONER FOERSTER: Okay. Thank you. CHAIR SEAMOUNT: Okay. If that's -- at this time is it appropriate to take a short recess or should we adjourn? COMMISSIONER FOERSTER: It's always appropriate. CHAIR SEAMOUNT: Is it, you want to take a recess? COMMISSIONER FOERSTER: Sure. CHAIR SEAMOUNT: Okay. We'll take a 10 minute recess and we'll come back and just -- we'll just talk it over and see if we have anymore questions or comments. (Off record) (On record) CHAIR SEAMOUNT: Okay. I want to announce that we broke a record, that's the fastest we've ever gotten back from a recess. And it's the only time we've ever gotten back from a recess in time before we said we would. Okay. We don't have any further questions of the R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 17 • • 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 applicant. It looks like your application is complete. I mentioned that we would be requiring an aquifer exemption and I know that you've gotten your request in for the aquifer exemption, but I was wrong in stating that it was a 30 day notice, it's a 15 day notice. And there will probably be a hearing, but there's a possibility that there won't. Okay. Commissioner Norman, do you have any further comments? COMMISSIONER NORMAN: Nothing more. CHAIR SEAMOUNT: Commissioner Foerster? COMMISSIONER FOERSTER: Nothing. CHAIR SEAMOUNT: Okay. I think it's appropriate that we adjourn then. Are there any other members of the public that would like to testify? Okay. Hearing none, it's appropriate that we adjourn. We are adjourned. (Adjourned - 9:29 a.m.) R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 18 • • 1 C E R T I F I C A T E 2 UNITED STATES OF AMERICA ) )ss. 3 STATE OF ALASKA ) 4 I, Rebecca Nelms, Notary Public in and for the State of Alaska, residing at Anchorage, Alaska, and Reporter for R & R 5 Court Reporters, Inc., do hereby certify: 6 THAT the annexed and foregoing PUBLIC HEARING was taken by Lynn Hall on the 17th day of March 2010, commencing at the hour 7 of 9:00 o'clock a.m. at the State of Alaska Oil and Gas Conservation Commission, 333 West 7th Avenue in Anchorage, 8 Alaska, 9 THAT this Transcript, as heretofore annexed, is a true and correct transcription of the proceedings taken by Lynn Hall and 10 transcribed by same. 11 IN WITNESS WHEREOF, I have hereunto set my hand and affixed my seal this 23rd of March 2010. 12 ~~ c.~~~~-Q~r~~ 13 Notary Public in and for Alaska My Commission Expires: 10/10/10 14 15 16 17 18 19 20 21 22 23 24 25 R& R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274-8982 ANCHORAGE, ALASKA 99501 ~~ • ~ 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); Foerster, (DOA); Norman, John K (DOA); Ballantine, Tab A (LAW) Subject: FW: Gas storage purposes is exempt from UIC regulation Tim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 907-793-1236 Catherine P (DOA); Seamount, Dan T 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) James 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(g) (2) (iv) regarding gas storage. This 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. • • The 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 ~5 • • STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION Nicolai Creek #2 Storage Injection Order March 17, 2010 at 9:00 am NAME AFFILIATION PHONE # TESTIFY (Yes or No) ,~ ,~ ~ ,~ 'C~u1nc,~ra~y ~~ ~r~- ~ • ~z~ f~ ~~ w~w y~~~2,r ~ /~OCi CC tu-esv, C~,~ec~ ~6tA.) ~ r ~s~ ~~ 'v.X~U.Ut~¢JZ[J( cN ~U{ZGLLWI(IU152. l - ~~.e~d ~~~e ~~t-~I/1CpG~ l'e.S ~~,~ ~x ~~ ~ ~n ~Q.s~tr de c ~' ~,ro~~d a,ve. ~ i ~v2ruv~ ~ Z U~l,~ ~~Cl sum(-~re~e ('~G l~~-es ~ ~occ~k-~ed vUln~~k ~s vv~~ccvv~un~v~ ~~f2 3 ~U.~s~u.v~ V~u~esdzd `' ~ tiv~a-~ ~s ec~n„k,,c~~a,~ ~,o,,~ t vn unit Ul~+n~.cUl~-~ ~ ~ ~ d~cuti(o~ ~n~'~xr~~ c~~Cc ~u5~ns? ~~~ ~ Gus~,~~ YCo~cQ uo(uun~ 35502 . ~ 4 r i ~w ~-W:~uror~ ~o~rer i • PB Energy .,` Storage r Services, /nc. Aurora Gas Evaluation of Nicolai Creek For Underground Gas Storage ~. Prepared. by PB Energy Storage Services, Inc. Prepared for Aurora Gas, LLC January 8, 2009 PB Energy __ - torage =` Services, /nc ENGIKEINNG-f.OX5TM1C11tp1-WEpgTpNS-MRWTENRNCE Aurora Gas Evaluation of Nicolai Creek for Underground Gas Storage 1. Introduction Aurora ..Gas, LLC (Aurora Gas) has contracted with PB Energy Storage Services, Inc. (PB ESS) to evaluate the Nicolai Creek gas production field for conversion to an underground gas storage facility. The study procedure was to conduct a due diligence of the field development and production history and to develop an assessment of the potential capacity and deliverability for gas storage. PB ESS did a due diligence review of the field development and production history to verify the geology, estimated reserves and the production rates. The results of the first phase of the study were used to develop an estimate of the capacity and deliverability rates that could be expected for the gas storage operation. 2. Summary ~,; The results of this study were based on the analysis of the data from one: well (Nicolai Creek Unit#2). The results of the PB ESS study of the Nicolai Creek production .field for development as an underground gas storage facility indicated: • PB ESS reviewed the work on the Nicolai Creek field preformed by Aurora Gas and found the work to be accurate and in line with standard engineering .practices. PB ESS made a general evaluation of the Nicolai Creek field (Tyonek reservoir) for use as a gas storage facility. The reservoir appears to have the requirements necessary for storage development: Containment Capacity Potentially Strang Deliverability Rates Location close to the gas pipeline system and gas markets • The fact that the Nicolai Creek was a gas production field indicates that the geologic containment will support the storage of gas re-injected back into the reservoir. • The Carya 2-1.1, Garya 2-1.2 and Carya 2-2.1 are the main gas - producing sand intervals within the Tyonek reservoir considered for i ~ gas storage. The Carya 2-1.0, located above the Carya 2-1.1, should be evaluated for use as another storage reservoir. • The capacity of the three (3) sands considered for storage is ~"orA~e vo~• approximately 870MMcf. This is somewhat less than the average S capacity of gas storage facilities in the U. S. but (as determined by Aurora Gas) sufficient to meet the demands of the potential market. • The deliverability is estimated to be in a range from 11 MMcfd to ~2MMcfd for Unit #2 well. Deliverability could be increased by drilling additional wells. • The permeability and porosity .ismsufficient to warrant drilling horizontal wells to increase the deliverability rates. • Compression will be required to withdraw gas when the field pressure falls below the main pipeline pressure. However some gas re-injection can "free flow" when the pipeline pressure is above the reservoir pressure. 3. Review of the Nicolai Creek. Gas Production Field The Tyonek reservoir at 2,426 ft to 2,916 ft is the main gas reservoir in the Nicolai Creek Gas Production Field. There are five (5) sands within the Tyonek reservoir (Carya 2-1.0, Carya 2-1.1, Carya 2-1.2, Carya 2-2.1 and Carya 2-2.3). The Carya 2-1.0 is behind casing and has not been produced. The Carya 2-2.3 produced a small volume of gas, watered out and production was stopped. See Table 1. The Carya 2-1.1, Carya 2-1.2 and Carya 2-2.1 have been the main gas producing sands and are the sand intervals within the Tyonek reservoir considered for gas storage. Table 1 LOG ANALYSIS SUMMARY (NT-NuTech NuLodt log analyssl DEPTH INTERVAL PERFS ML RESISTV Porosity NT NT SITP BH Temp Rw WFR SAT NT PERM COMMENTS MD MD SHOWS Rd NT Sw Ne! Pay psig Calc Sw esl TVD NET SD (avgJ (avg) TVD Calc BHP (avg( (avg) N units ohm•rn °!e % psia °i, and Carya 2-0.0 BEHIND PIPE 2206 2272 5 200 16 26.8°6 43.5`~a 4 1tS 2244 2260 ~6 18(10 20 240 % 45-0°6 ~ 115 looks wet on TDT, 2314 2320 5 100 16 25.8°c 44.3°ro 6 126 but hest Ml show 1986 2069 21 t9 ~ _ ~. 440°~ 933 Tao OA07 a3"'o , estimated Carya 2.1.1 2426 2476 50 300 50 960 ~•~~'=u 2`.iS2 2111 2177 36 2G 25°~a 43°~ 38 1025 15.1 0.399 40% ~2~ 0.479 Carya 2.1.2 2700 2716 16 260 0 1010 perfect 2002 2342 2756 1t '.8 19% 45°h 1083 18.1 0.368 51% 0.462 Carya &21 2893 2916 23 140 13 1090 perfect 2002 2195 2511 18 20 22% 47";- 10 1172 79-9 0.380 43°~. 0.470 Carya &2.3 original perfs 3270 3315 -5 300 22 1180 Produced 51 MMcf n E8~69 before water 8 2780 2815 35 t 3 24°r'~ 505 17 1277 83 A 0.365 49°ti sand hit-was 0.459 plu ged back in'9t CURRENT MD PERFS 89 CURRENT TVD PERFS 70 i • The initial reservoir pressure (IP) was approximately 1,075Psia (tubing pressure approximately 1,016Psig). The water saturation (Sw) is estimated from the geophysical logs at approximately 45%. This is probably an immobile (and stable) volume of water given that there has been very little water produced during the history of the field. The porosity is estimated at an average 19% and the permeability is estimated at 120Md. The Tyonek reservoir characteristics are considered good to support a gas storage facility. The estimated ultimate recovery (EUR), calculated by Aurora Gas, for the three sands under consideration for storage is estimated at approximately 870MMcf. See Table 2. A plot of the IP and estimated gas recovery vs. a plot of the historic production pressures (extrapolated to total depletion) shows that there is agreement with the calculated EUR. See Figure 1. Table 2 NICOLAI CREEK (UNIT #2) VOLUMERTIC RESERVES ND TVD CALC TEST COMMENTS INTERVAL NT Nel Net Pay POR Sw BHP MCFPD ZONE 22C6 232C 10 21 025 D.44 933.4815 0TTESTED Carya2-1.0 2426 2476 36 36 0.25 0.43 1025 3200 Now produung Carya 2-1.1 2700 2716 D 14 0.19 0.51 1083 4260 Now producing Carve 2-1.2 2893 2916 10 18 022 0.47 1172 4700 Now produdng Carya 2.2.1 CU RRENTPERFS 46 68 3210 3315 17 35 0 24 0.50 1277 4220 Original completion Carya 2.2.3 ~' TOTAL 73 124 INTERVAL BHT 2 MCFIA-F RF ACRES Geo Car PROVED PROB P+P ZONE 22C6 2320 74.0 Q8880 424.36 BB 40 0.T7 241.54 24t 54 Carya 2-1.0 2426 2476 75.7 0.8820 476.00 95 48 0.77 601.68 601.68 Carya 2-1.1 2700 2716 78.1 0.8160 329.35 85 43 0.77 129.77 129.77 Carya 2-12 2893 2916 79.9 0.8700 447.96 90 44 0.77 138.97 138.97 Carya 2-2.1 CURRENT PERFS SIT 870.41 ~ 00 810.11 MMCF 3270 3315 83.4 0.6630 503.19 66 40 0.77 55.00 302.65 357.65 produced 55 MMCF before TOTAL ULTIMATE P07ENTIAL 925.41 544.19 1469.61 MMCF and sand started. Production thru 1?/3L07= 745A0 0.00 745.00 REMAINING RESERVES= 180.41 544.19 724.61 MMCF PROVED- matches P 2 curve EXPECTED EUR (from PQ vs. Cum 871 MMF PROBABLE- untested vdumetnc Draingage area= 33.95 l0 50 acres Depending on net pay 68.OD to 46.17 feet Drainage Radius= 686.12 832.63 feet 2006 RIS EUR 803 MMF NOTE: 1~ The Proved Reserves above are all recoverable in current completion. Tha Carya 2-2.1 has bwar pens and seems to pressure up weN when 81 for long term-P!Z curve is shitting outward with time, indicatlng that eady points were most affected by higher perm zones. 2) The Probable reserves will require a rig workover: drilling out cement and repedaating the Carya 2-2.3, which was probably abandonded permeturely, and perforating the Carya 2-1.0-the wst of tnis s estimated at $750,01X} to St,00t7,0000 fa 544 MMd. 3) The PIZ vs. Cum Produc0on curve appears to be shifting to the rght, indicating a dual perm system and increased recoveries, est. EUR of 871 b1MCF the above is calculated on that basis; a best-fd straight line from ISIP yields only 775 MMd. Ed Jones Rev 1118 08 1,200 --~ I 1,000 _ , t3 II 800 i '~ a 600 - x m 400 -- Prod f4s I j 200 p _~`y~ 0 100,000 200,000 300,000 400,000 500,000 600,000 700,000 800,000 900,000 1,000,000 Cumulative Production (MCA PB ESS re-calculated the estimated reserves for the Tyonek reservoir(s) to verify and make an independent assessment of the gas reserves. The technique was to approach the calculations by a separate method than that used by Aurora Gas. PB ESS used the production history data to calculate the pore volume (Vp) of the Tyonek reservoir and then calculate the gas-in-place (Gp) at the IP. See Figure 2 and Table 3. Figure 2 Storage Capacity Verification Formulas ^ Pore Volume (VP) of Reservoir ~, _ V '' T,, P, _ P, P,, T,Z~ T, Z, ^ Gas-in-Place (GP) in Reservoir . ~_T, ?X~~ ~' f' rz, lay>. Where; Vi -Injection or Withdraw T -Temperature P -Pressure Z -Compressibility Figure 1 BHP vs Cumulative Production i ~ Table 3 Nicolai Crock Pore Yoluma (Pv) -Gas-in-Pl ace (Gp) Calculations POINT NUMBER DATE BHP2, CUM PROD, LSMF (AUtomatiej (Optional} SfTP, Psia BHP, Psla Z Psla MMcf Include? (YIN) BHPa CUMPRD INOROUT ' 1 11!21/03 '. 1016 1,072.647 0.8721 1,229.947 0 n 2 1v22103 ' 1002 1,057.754 0.8736 1210.799 1.9 n 3 17/22/03 ' 1004 7,059.881 0.8734 L2t3.531 1.9 N 4 2!11(04 - 766 807.147 0.9004 89fi.464 141.9 y 5 _ 6f15/04 555 583.853 0.9264 630.261 266.859 ~ N 6 7/15/04 '~ 595 626.126 0.9213 679.597 270 y 7 12t31104i 385 404.492 0.9483 426.536 461 n 8 --- 4/3x05 --- 395 415.030 0,9470 438.256 470 n 9 __ 7A6/05 ~ ~ 475 436.109 0.9444 461.790 472 g 10 2/17!06 225 236.112 0.9695 243.530 554.3 n 11 9n4/06 - - 168 176.225 0.9772 180.336 608.7 n 12 10/3106 _ 194.5 204.O6i. 4.9736 209.587 608,7 N 73 12l31/OS 240 251.881 0.9675 260,333 824 N 14 1118/07 255 262653 0-9655 277.209 624 N 15 2!4/07 275 288.687 0.9629 299,823 624 n 16 3!8107 I 300 314.989 0.9595 328.273 624 Y 17 4130!07! 295 309.728 0.9602 322.567 629 7 Y 18 8!' 110 267 301.311 0.9613 313.454 . 647.1 Y 19 7 5!29/08 123.7 129.715 0.9832 731.934 711,7 Y Paints 7 8 2 were measured by festers before and after 4-point test. Palet 7 was Erom krea gauge after long SI (4t1l0Sj.. Point 3 was measured with crystal recorder after 4-point test antl buildup. Point 12 was measured by Pollard SPIDR after Tong term 51. Point 4 was measuretl with <ryslal recorder when 51 far dehy problems. Points 73-17 era long-lane SIPS from free gauge-well continues to build up over time. PoiMS 5 & 6 were from tree gauge. point 16 is SIP from SPIDR-SI about 45 hrs-still bldg Point 19 is from SPIDR but not long term buildup--0 days vs weeks with other points POINTNUMBER DATE BHP, PSIa CUM PROD, MMc/ Vp Gp 4 2/11!04 807.15 161.90 ~ 10.732 83b,Obb 7 12/31104 404.49 461,00 7 12131!04 404.49 461.00 10,615 B40,bb0 92 1p(3(O6 204.06 608.70 4 2/11104 807.15 141.90 10,758 840,p00 t2 10!3/06 204.06 608.70 The calculated pore volume of the reservoir relies on the fact that there is one (and only one) pressure/gas volume relationship for a reservoir with a ~- constant volume of space. Therefore the calculations for any (accurate) set of gas volume/pressure measurements should result in the same pore volume for the reservoir. PB ESS used those pressure measurements that were taken after a long shut-in period to ensure the pressure was stable and representative of the pressure across the reservoir. The chart at the bottom of Table 3 shows that there is good agreement inthe pore volume calculations from the pressure/gas volume measurements taken from the Tyonek reservoir production history. The estimated reserves calculated from this pore volume are in close agreement with the Aurora Gas calculation of the original reserves. Any differences in the reserve estimates calculated by Aurora Gas and PB ESS can be attributed to the 1~9 , slight differences in the compressibility factors used in the calculations. PB ESS would be in agreement with Aurora Gas that the estimated original reserves in the Tyonek reservoir(s) are approximately 870MMcf and that this is the reservoir capacity that should be used for the development of the reservoir for gas storage. 4. Review of the Nicolai Creek Unit #2 The Nicolai Creek Unit #2 well was drilled in 1966. According to the well diagram the well was drill to 5,011 ft MD (4,086 ft TVD). The well was suspended in 1991. Aurora Gas l_LC received approval to re-enter and re- complete the well in 2002. The well originally was completed with 7 in casing. The cement retainers and plugs were drilled out to the top of a cement plug set at 3,102 ft and the well was re-completed with 2.875 in 5 tubing set in a packer at 2,327 ft. The Carya 2-1.1 was perforated with 5 SPF at 2,426 ft to 2,476 ft, the Carya 2-1.2 was perforated with 5 SPF 2,700 ft to 2,716 ft and the Carya 2-2.1 was perforated with 5 SPF at 2,893 ft to 2,916 ft. Primary production was from these intervals and it is proposed that the storage will be developed in these three sands. PB ESS calculated the potential Tyonek reservoir deliverability from the four-point test data provided by Aurora Gas. See Figure 3. The deliverability was calculated from the standard gas flow equation: Where; Q =Rate of gas flow (deliverability in MMcfd) C =Coefficient of performance (ability of reservoir to transmit gas} P1 =Average reservoir pressure P2 =Flowing bottom hole pressure (or tubing pressure) n =Measure of turbulence in the flowing gas Figure 3 Nicolai Creek Unit # 2 10,000 ~_ d 1,000 ' - 100,000 Dena P"2 1,000,000 5. Evaluation of Tyonek Reservoir for Storage The results of the deliverability calculations can be seen on Figure 4 and ~ Table 4. Overall the deliverability is in a range of 11 MMcfd to12MMcfd. The deliverability (and injection) is directly related to the differential between the reservoir and wellhead pressures. The lower the wellhead pressure is relative to the reservoir pressure, the higher (in general) the deliverability rates. The reverse is true for injection; the lower the reservoir pressure is relative to the wellhead pressure, the higher the injection rates. Figure 4 Nicolai Creek Unit # 2 Deliverability 1 Injection Rates vs. Produced Gas ~ • 400FWHP ^ 200FWF~ . fi00FUUHP ^ In' 12,009 10,000 -~ 8,000 ~_ ° 6,000 4,000 2,000 0 0 100,000 200,000 300,000 400,000 500,000 600,000 100,000 800,000 Gp (Mci) Figure 4 shows the deliverability rates for three (3) scenarios; reservoir pressure against 200Psig, 400Psig and 600Psig wellhead pressures vs. the volume of gas produced. The more gas that has been produced the lower the reservoir pressure and the lower the deliverability rate will be for any set wellhead pressure. The calculations take into account that for each increment of gas produced there is a corresponding decrease in reservoir pressure. This new pressure is compared to the wellhead pressure and a new deliverability rate is calculated. The curve for each wellhead pressure illustrates the deliverability that can be expected for a set wellhead pressure as the reservoir pressure decreases with the gas produced. Ta6~ 4 Tyonelr reservoir Deliverab8ity Rates FWHP 200 FlMIP 400 FWi~ ~0 Days Q9 (Mcfd) GP (Mcf) P (psi) Days Qg (Ncfd) GP (Mcf) P Ipsi) Days Q9 (Mcid) GP (Mci) P Ipso) 0 0 0 1,015 0 0 0 1,015 0 0 0 1,Oi5 1 11,550 11,550 1,001 9 10,353 98,482 691 14 9,662 148,151 831 20 8,888 203,394 111 26 8,169 254,180 110 32 1,501 300,832 654 39 6,181 350,423 594 41 6,029 401,238 534 56 5,265 451,616 413 60 4,950 411,882 449 1 10,861 1Q861 1,002 10 9,508 101,144 693 16 8,618 155,860 828 22 1,901 205,183 169 28 7,112 250,014 115 36 6.266 303,265 651 44 5,428 349,583 596 49 4,934 315,233 565 1 9,593. . 9,593 1,003 12 1,916 104,900 889 18 1,068 149,409 836 26 5,999 201,fD1 114 34 4,981 244,504 722 ,.~.,- Table 4 is a print-out of the deliverability rates vs. the gas produced for each of the three (3) wellhead pressures used to illustrate how the Tyonek reservoir would perform as a storage facility. Based on a minimum deliverability of 5MMcfd: • For the 200Psig wellhead pressure it is expected that approximately 55% (472MMcf) of the total reservoir storage inventory (870MMcf) could be withdrawn when the deliverability rate reached 5MMcfd. The calculations indicate that it will take 60 days to withdraw 55% of the storage capacity. Using the general rule-of-thumb that it takes twice as long to re-inject the gas as to withdraw it, that would be a 180-day turnaround and the working gas could be cycled twice per year. • For the 400Psig wellhead pressure it is expected that approximately 44% (375MMcf) of the total reservoir storage inventory (870MMcf) could be withdrawn when the deliverability rate reached 5MMcfd. The calculations indicate that it will take 49 days to withdraw 44% of the storage capacity. Using the general rule-of-thumb that it takes twice as long to re-inject the gas as to withdraw it, that would be a 147-day turnaround and the working gas could be cycled 2.5 times per year. • For the 600Psig wellhead pressure it is expected that approximately 28% (245MMcf) of the total reservoir. storage inventory (870MMcf) could be withdrawn when the deliverability rate reached 5MMcfd. The calculations indicate that it will take 34 8 days to withdraw 28% of the storage capacity, Using the general ~ e . rule-of-thumb that it takes twice as long to re-inject the gas as to ~~~e '~~ _., withdraw it, that would be a 180-day turnaround and the working gas could be cycled 3.5 times per year. There are. two (2} methods generally employed to operate the storage facility • Base Load • Peaking The base load operation is the traditional way most storage facilities are operated; inject gas during the off-season (Summer) and withdraw the gas during the demand-season (Winter). This method of operation provides a long term supply of gas but incurs a decreasing deliverability with time. Depending on the minimum deliverability required, the working gas vs. base gas ratio is generally 50% to 60%. The peaking operation (AKA Huff n Puff) is designed to provide a high rate of deliverability for short periods of time. The deliverability rate is kept high as gas is re-injected after each withdrawal period. The working gas vs. the base gas ratio is 10% to 25%. This may make the cost-of-service higher because of the higher volume of base gas necessary to maintain the high deliverability rates. Most gas storage operations are a combination of the base load and peaking operations. A reservoir storage facility can supply a large volume of gas and at times during the withdrawal season provide high rate of withdrawal as needed ~to met the market demands. The operation of any storage facility should be designed around the market demands. 6. Conclusions and Recommendations PB ESS made a review of the data collection methods, the data collected and calculations preformed by Aurora Gas to monitor and describe the performance of the Nicolai Creek Tyonek reservoir and found the work to be accurate and in line with standard engineering practice. The Nicolai Creek field (Upper Tyonek reservoir) appears to have the requirements necessary for storage development: Containment Capacity Potentially Strong Deliverability Rates Location close to the gas pipeline system and gas markets The fact that the Nicolai Creek was a gas production field indicates that the geologic containment will support the storage of gas re-injected back into the reservoir. The Carya 2-1.1, Carya 2-1.2 and Carya 2-2.1 are the sand intervals within the Tyonek reservoir considered for gas storage. One other .sand 9 • interval,. Carya 2-1.0, should be evaluated for use as part of the storage reservoirs. The capacity of the three (3) sands considered for storage has been calculated at approximately 870MMcf. This is somewhat less than the average capacity of .gas storage facilities in the U. S. but (as determined by Aurora Gas) sufficient to meet the demands of the potential market. The deliverability was determined from the data collected from afour-point test conducted on the Tyonek reservoir and is estimated to be in a range ~ from 11 MMcfd to ~2MMcfd for the Unit #2 well Deliverability could be increased by drilling additional wells. The permeability and porosity is sufficient to warrant drilling horizontal wells to increase the deliverability rates. Compression will be required to withdraw gas when the field pressure #alls below the main pipeline pressure. However some gas re-injection can "free flow" when the pipeline pressure is above the reservoir pressure. PB ESS has the opinion that the Nicolai Creek (Tyonek reservoirs) should ckµa ~ ~ be considered for conversion to gas storage. However, it is recommended /~-a ~r..~-~~ that a more comprehensive, detailed study. be made to determine the reGv performance of the field, before any physical development of the facility would be started. A computer simulation 'model would aid in the design of the new facility and be useful to monitor and modify the operations to maximize. the efficiency of the operations. 10 # ~ -Aurora Gas LLC 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 RECEIVEC MAR ~ .2'201D -94jN~~~Q6G~' .~R 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 # 1 A: PTD # 166-008-0 Plugged and abandoned per AOGCC requirements on 02/02/02. Nicolai Creek Unit #4: PTD #169-I05-0 Plugged and abandoned per AOGCC requirements on 11/27/71. PTD # 19I -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 03/07172. Nicolai Creek #6: PTD # 179-061-0 Plugged and abandoned per AOGCC requirements on 02107180. 1400 West Benson Bivd., 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 lication 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 09130/02. Nicolai Creek Unit # 10: PTD #206-080-0 Permit to Drill expired on 07/06!08, well never drilled. Nicolai Creek Unit #3: PTD #167-007-0 Straight-hole well that is located approximately 1 mile north of the northern boundary of the proposed injection reservoir and more than 1-1/4 mile from the NCU #2 proposed injection well. No history or indication of any mechanical integrity issues. Nicolai Creek # 11: 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 # 1 B: 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 09/18/02. 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 Application. Additional Information Winton Aubert March 12, 2010 Page 3 of 4 4. Water analysis of formation water far the proposed injection well. An analysis from well logs and produced water samples from the Nicolai Creek Unit # 1 B, #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-l, 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/starage. This is consistent with previous calculations. b) Produced water samples from the Nicolai Creek Unit #1B, 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 74D', 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,$20 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 psis (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 Application Additional Information Winton Aubert March 12, 2010 Page 4 of 4 Bottom Hole Pressure sia) Surface Pressure si) Flow rate (mmscfd) 1070 993 0 1070 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 Storage 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, moo. ~--.~~ 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 # 1 B Cement Bond Log Nicolai Creek Unit #2 Injection Simulation Nicolai Creek Unit #2 4-Paint Pressure Test Summary e ~ . AURORA_ MOQUAWKIE_MSN8105_12 3009_RUN 1 Chandler Engineering Co. Model 292/2920 BTU Analyzer Test time: ~u1y08 93 10:22 Calibr ation #: 8 Test #:3 Locati on No. :8105 S tandard/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/10000F 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 > chan dler Engineering Co. Model 292/2920 BTU Analyzer Test time: ~u1y08 93 09:17 Calibration #: 8 Test #:5 Location No. :8104 s tandard/D ry Analysis _ saturated/wet Analysis Moles 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 Grass 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: ~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 1 MSN: 8104 Page 1 L' AURORA_ MOQUAWKIE_MSN8105_ 123009_RUN 2 Chandler Engineering Co. Model 292/2920 BTU Analyzer Test time: 3u1y08 93 10:38 calibration #: $ Test #:4 vocation No. :8105 St andard/Dry Analysis _ Saturated/wet Analysis Mole% BTU* R.Den.* GPM** Mole% BTU* R.Den.* Methane 9$.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 ( C02 ) 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. **: Eiquid 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+ fast 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: 7u1y08 93 09:00 Calibration #: 8 Test #:8130 Location No. :8103 _ Standard/Dry Analysis _ saturated/wet Analysis MOIe% 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 = 0.99$0 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 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 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 Engineering Co. Model 292/2920 BTU Analyz er Test time: 7u1y08 93 09:38 cali bration #: 8 Test #:6 Loca tion No. :8104 _ s tandard/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 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 CREEK,._MSN8103_ 123009_RUN 1 Chandler Engineering Co. Model 292/2920 BTU Analyzer Test time: ~u1y08 93 08:44 Calibr ation #: 8 Test #:8129 Locati on 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 & 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 Beating 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 ~ t f ,~ Aurr~a 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 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 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 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 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 Aurora 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 8 • 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. 7.25 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 SABATQGE /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 Shirieyville 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 A endix 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-$00-478-9111 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 Auirora Gas, LLC HSE Incident Field Guide Priority 1: Safety of Personnel Priority 2: Protection of the Environment'- Priority 3: Protection of Facilities Iniury 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 Necessary Call for Assistance if Emergency Medical Attention Is Necessary Administer Any First Aid You Are Trained to Provide Report 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 on s (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 ---- - I ~_ Report Reoort the Followinr~ Type of Incident Location Injuries Potential Injuries Release size Source Material Released Possible Hazards 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 Sill 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 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 & 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 . ~ -t FOUR-POINT TEST DATA Oct-02 AURORA GAS, LLC NICOLAI CREEK UNIT N0.2 BHP bomb set at 2279' MD (2020' TVD) Perfs at 2426-2476', 2700-2716', and 2893-2916' MD 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 psis 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 (69,5~~) 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 1530 818 1036 75.8 490 36 6 2.2 1155 30 1609 939 38 1034 75.5 710 36 7.4 3 1943 30 1630 949 26 1048 75.5 490 7.3 3 1916 -- OPEN 32(,6'648 __.__ _.._ 918 ~ _______._~___ _ ~_~1060 .... ___ 75.4_ _.. . _ .. 590_.. 31 _ _ 6.5 4.2---- _ -2389 32 1710 921 1011 580 6.3 4 2205 32 1730 849 1036 600 30 6.4 5.4 3024 1800 866 35 1005 75.5 600 31 6.5 5.7 3242 1820 883 34 999 700 35 7.1 5.6 3479 1845__u,.._ _ __ 920 34___ ...997 75.3 790 _._ 37 __ _. _ Z:3 _ . _ _.,_ 5.5 _ _ _ . ~51~_. 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 _, _890 __ _ _ 33 __ __983 _. ___ 820 - _ . ~LL_~ 41 __,.. ~~ ~~y _7.7 ~ ~ ~~ -~ 6.25 w 421 1 2046 800 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 unloading 5.6 water 8.4 r~s ~ ICING UP 8.4 7~ ~ ,1 ~ r ~f 2200 87 9 33 962 700 40 6.95 8.35 5078 ~ ~' ` `" 8.4 _ .. ___~_. _._.._ . _~ _ .. _ _ _ .. _.._ ~v~.._ SI 2206 _ .___ __ M.. _ .. 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*24/1000 4 min 1044.2 Q= 87.5*H*P 5 min 1044.35 /r~iyJ/r1 !2216 ~ 983 ~-yrn~~ 2230 982 , .~~~~~~ 2236 1044 5 73 8 ~ ~` (2306 ~ , . 1044.85 60 hr 976 1034.3 72.2 atm 17.1 GRADIENT SURVEYS TIME DEPTH DEPTH STATIC GRAD TO DELTA T Grad to TEMP (MD) (TVD) PRESR SURF GRAD Surt (KB) psia psi/ft psi/ft deg/100' deg F 10/23/2003 1510 14 14 19.2 (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 1623 2400 2107 1023.1 0.025 0.902 71 1635 2451 2144 1024.1 0.472 0.027 0.979 73 1641 2500 2179 1025 0.465 0.026 1.010 74 1647 2600 2255 1044.5 0.458 0.257 1.020 75 1659 2708 2337 1085.5 0.459 0.500 1.095 77,6 1705 2800 2411 1121.6 0.460 0.488 1.078 78 1717 2905 2494 1184.4 0.462 0.516 1.067 78.6 Mid pert depth is 2671' MD or 2309' TVD. Extrapolated SIP = 1071.5 psia at 76.4 deg F atm packer mid pert--top set static water level mid pert--middle set mid pert--btm set w ~ . TIME MD TVD PRESSR GRAD /1 GRAD T GRAD TEMP 10/27/2003 1218 14 14 17.7 atm (POH) 1259 2905 2494 1085.7 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 pert--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' ND. Extrapolated SIP = 1040.0 psia at 77.1 deg F (Appears to be cross flow and/or possible depletion; multiple zones a nd water in wellbore make it difficult to analyze). SHORT TESTS OF IND IVIDUAL ?:ONES AFT ER PERFO RATING (isolated and w/o sand control screens) STABLZD FLOW DATE PERF INTERVAL CHOKE FTP RATE TIME SITP TOP BTM 64" PSIG MCFPD MIN PSIG BWPH 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 Nicolai Crek#2 Run in Hole Pressure and Temperature vs Depth Analysis Static 3000 0 Temperature (degrees F) 0 20 40 60 80 ~~ ------o------ P:Measured data ------Q-----• T:Measured data Q __ ; .` i 0 __. .~ O --- m I ' 4 O ~ P . Q ' ~ ~ ~. o, ` _ -` 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 Pressure (psig) Aurora Gas Nicalai Creek# 2 Pull Out of Hole Static Pressure and Temperature vs Depth Analysis Temperature (degrees F) 0 20 40 60 80 ,` - -e - - P:Measured data `, ------Q------ T:Measured data ~~ _ `` O ~. `, '` '~ 4~ -_ ``` ~ ~ ~, } f ____ ~~ -- -- ~ p'~ 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 18i Pressure (psigj 10 i• If Aurora Gas Start Test Date: 2002!1023 1~~~~ ~ 60C 1 41 3 _7 400 ii 0 ~~~ ~ - - - S .~ i' ~~ ~ ~ i ~~ ~ E 6 1 1 _ ~~ ~u ,su 40 50 60 74 $0 ~ Gauge 1 Time , hr NCB 10U ~~n so c m i iD 1 t9 ~n ~ 4T (D 60 X30 100 110 c .. *********,r*,r,r***********a***********,r**** Date: 12-03-2010 • * Neotechnology Consultants Ltd. * Time: 10:56:03 AM * * * * * WELLFLO 7 - Versionr7.231 * * ***************************************** * 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 7 7 - Case Number: 1 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: 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 CALCULA --------------------- .WELLHEAD Pressure: Temperature: ~TTOM-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: 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 i ~ ; `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 --- ------------ ------------- ----------- --- ----- ---- ---------- --------- --------- --------- MAX GAS ------------- ------------ -------------- ESTIMATED TOTAL TOTAL TOTAL VOLUME TOTAL TOTAL STATIC LIQUID CASE 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 • ***************************************** ' * Neotechnology Consultants Ltd. * * * * * WELLFLO 7 - Version 7.231 * * * Licensee: Aurora Power ***************************************** Date: 12-03-2010 Time: 10:56:03 AM ** C A L 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: • 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 CO2 3.0700e-003 HIS 0.000 C1 0.987 C2 6.8000e-004 C3 0.000 2-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-Clb 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 t 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 xz o.ooo 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-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 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) (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 ------------------------------------ SPECIFIED AND CALCULATED SYSTEM DATA TUBING 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) (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: 0.00 MMSCfd Water Volume Flow: 0.00 Bbl/day DETAILED RESULTS S SUPERFICIAL T DENSITY VISCOSITY VELOCITIES PREDICTED E DEPTH (lb/ft3) (cP) (ft/sec) FLOW R (ft) GAS LIQUID GAS LIQUID GAS LIQUID PATTERN 100.0 3 1 200.0 3 1 300.0 3 1 400.0 3 2 500.0 3 1 600.0 3 2 700.0 3 1 800.0 3 2 900.0 3 1 1000.0. 3 1 1100.0 3 1 1200.0 3 2 1300.0 3 1 1400.0 3 1 1500.0 3 1 1600.0 3 1 1700.0 3 1 1800.0 3 1 1900.0 3 1 1934.0 3 2 2034.0 3 1 2100.0 3 VOLUME CALL. PRESSURE DROP CALCULATED FRACTION TEMP. (psi) PRESSURE GAS LIQUID (deg F) FRICTION HYDROST. (psia) .55 N/A 0.0122 N/A 0.000 0.000 SPL 1.0000 0.0000 51.0 0.000 -2.466 1010.37 .55 N/A 0.0122 N/A 0.000 0.000 SPL 1.0000 0.0000 52.1 0.000 -2.464 1012.84 .55 N/A 0..0123 N/A 0.000 0.000 SPL 1.0000 0.0000 53.1 0.000 -2.462 1015.30 .55 N/A 0.0123 N/A 0.000 0.000 SPL 1.0000 0.0000 54.1 0.000 -2.461 1017.76 .54 N/A 0.0122 N/A 0.000 0.000 SPL 1.0000 0.0000 55.1 0.000 -2.442 1020.20 .54 N/A 0.0122 N/A 0.000 0.000 SPL 1.0000 0.0000 56.2 0.000 -2.440 1022.64 .54 N/A 0.0122 N/A 0.000 0.000 SPL 1.0000 0.0000 57.2 0.000 -2.377 1025.02 .54 N/A 0.0123 N/A 0.000 0.000. SPL 1.0000 0..0000 58.2 0.000 -2.376 1027.39 .53 N/A 0.0123 N/A 0.000 0.000 SPL 1.0000 0.0000 .59.3 0.000 -2.249 1029.64 .53 N/A 0.0123 N/A 0..000 0.000 SPL 1.0000 0.0000 60.3 0.000 -2.247 1031.89 .53 N/A 0.0123 N/A 0.000 0.000 SPL 1.0000 0.0000 61.3 0.000 -2.245 1034.14 .53 N/A 0.0123 N/A 0.000 0.000 .SPL 1.0000 0..0000 62.3 0.000 -2.243 1036.38 .52 N/A 0.0124 N/A 0.000 0.000 SPL 1.0000 0.0000 63.4 0.000 -2.061 1038.44 .52 N/A 0.0124 N/A 0.000 0.000 SPL 1.0000 0.0000 64.4 0.000 -2.059 1040.50 .52 N/A 0.0124 N/A 0.000 0.000 SPL 1.0000 0.0000 65.4 0.000 -2.057 1042.56 .51 N/A 0.0124 N/A 0.000 0.000 SPL 1.0000 0.0000 66.5 0.000 -2.055 1044.61 .51 N/A 0.0124 N/A 0.000 0.000 SPL 1 .0000 0.0000 67.5 0.000 -2.053 1046.66 .51 N/A 0.0124 N/A 0.000 0.000 SPL _ 1.0000 0.0000 68.5 0.000 -2.051 1048.72 .50 N/A 0.0125 N/A 0.000 0.000 SPL 1.0000 0.0000 69.5 0.000 -2.049 1050.76 .50 N/A 0.0125 N/A 0.000 .0.000 SPL 1.0000 0.0000 69.9 0.000 -0.696 1051.46 .50 N/A 0.0125 N/A 0.000 0.000. SPL 1.0000 0.0000 70.9 0.000 -1.873 1053.33 .49 N/A 0.0125 N/A 0.000 0.000 SPL 1.0000 0.0000 71.6 0.000 -1.235 1054.57 f 2 n 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 0.0.00 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 O.D00 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: 15204.5 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 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 psis Temperature: 80.0 deg F 0.0 ft Depth C 0.0 ft Depth 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 E DEPTH (lb/ft3) (cP) (ft/sec) FLOW R (ft) GAS LIQUID GAS LIQUID GAS LIQUID PATTERN 100.0 3 200.0 3 l 300.0 3 1 400.0 3 2 500.0 3 1 600.0 3 2 700.0 3 1 800.0 3 2 900.0 3 1 1000.0 3 1 1100.0 3 1 1200.0 3 2 1300.0 3 1 1400.0 3 1 1500.0 3 1 1600.0 3 1 1700.0 3 1 1800.0 3 1 1900.0 3 1 1934.0 3 2 2034.0 3 1 2100.0 3 VOLUME CALL. PRESSURE DROP CALCULATED FRACTION TEMP. (psi) PRESSURE GAS LIQUID (deg F) FRICTION HYDROST. (psis) .61 N/A 0.0123 N/A 14.008 0.000 SPT 1.0000 0.0000 51.0 0.544 -2.507 1024.82 .61 N/A 0.0123 N/A 14.02.5 0.000 SPT 1.0000 0.0000 52.1 0.544 -2.504 1026.78 .60 N/A 0.0123 N/A 14.042 0.000 SPT 1.0000 0.0000 53.1 0.545 -2.501 1028.74 .60 N/A 0.0123 N/A 14.060 0.000 SPT 1.0000 0.0000 54.1 0.546 -2.498 1030.69 .59 N/A 0.0122 N/A 14.077 0,000 SPT 1.0000 0.0000 55.1 0.546 -2.477 1032.62 .59 N/A -0.0122 N/A 14.095 0.000 SPT 1.0000 0.0000 56.2 0.547 -2.474 1034.55 .59 N/A 0.0123 N/A 14.113 0.000 SPT 1.0000 0.0000 57.2 0.548 -2.408 1036.41 .58 N/A 0.0123 N/A 14.132 0.000 SPT 1.0000 0.0000 58.2 0.549 -2.405 1038.27 .58 N/A 0.0123 N/A 14.151 0.000 SPT 1.0000 0.0000 59.3 0.549 -2.275 1039.99 .57 N/A 0.0123 N/A 14.171 0.000 SPT 1.0000 0.0000 60.3 0.550 -2.272 1041.72 .57 N/A 0.0123 N/A 14.191 0.000 SPT 1.0000 0.0000 61.3 0.551 -2.269 1043.43 .56 N/A 0.0124 N/A 14.212 0.000 SPT 1.0000 0.0000 62.3 0.552 -2.265 1045.15 .56 N/A 0.0124 N/A 14.233 0.000 SPT 1.0000 0.0000 63.4 0.553 -2.080 1046.67 .55 N/A 0.0124 N/A 14.256 0.000 SPT 1.0000. 0.0000 64.4 0.553 -2.077 1048.20 .54 N/A 0.0124 N/A 14.279 0.000 SPT 1.0000 0.0000 65.4 0.554 -2.074 1049.72 .54 N/A 0.0124 N/A 14.302 0.000 SPT 1.0000 0.0000 66.5 0.555 -2.070 1051.23 .53 N/A 0.0124 N/A 14.325 0.000 SPT 1.0000 0.0000 67.5 0.556 -2.067 1052.75 .53 N/A 0.0125 N/A 14.347 0.000 SPT 1.0000 0.0000 68.5 0.557 -2.064 1054.25 .52 N/A 0.0125 N/A 14.370 0.000 SPT 1.0000 0.0000 69.5 0.558 -2.061 1055.76 .52 N/A 0.0125 N/A 14.385 0.000 SPT 1.0000 0.0000. 69.9 0.190 -0.700 1056.26 .51 N/A O.D125 N/A 14.402 0.000 SPT 1.0000 0.0000. 70.9 0.559 -1.882 1057.58 .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 1066.8E 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: SPECIFIED WELLHEAD TEMPERATURE: SPECIFIED BOTTOM-HOLE PRESSURE: SPECIFIED BOTTOM-HOLE TEMPERATURE: Predicted Pressure Loss: Friction Loss: Elevation Loss: Kinetic Loss: In-line Facilities Loss: Total Liquid Holdup: Total Gas Pack: Estimated Static Liquid Column Height: Measured Depth: .7 1022.9 psia 50.0 deg F 1070.0 psia 80.0 deg F -47.1 psi 14.7 psi -61.9 psi -0.0 psi 0.0 psi 0.0 bbl 15303.4 scf 0.0 ft 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 0.0.125 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 S 2 . 2200.0 3.53 N/A .0.0125 2 2300.0 3.52 N/A 0.0126 2 2400.0 3.51 N/A 0.0126 1 2426.0 3.50 N/A 0.0126 2 2526.0 3.49 N/A 0.0126 2 2626.0 3.48 N/A 0.0126 1 2654.0 3.47 N/A 0.0126 2 2700.0 3.47 N/A 0.0126 2 2746.0 3.47 N/A 0.0126 1 2849.5 3.47 N/A 0.0126 1 2893.0 3.46 N/A 0.0126 1 2916.0 3.46 N/A 0.0127 SUMMARY: CALCULATED WELLHEAD PRESSURE: SPECIFIED WELLHEAD TEMPERATURE: SPECIFIED BOTTOM-HOLE PRESSURE: PECIFIED BOTTOM-HOLE TEMPERATURE: Predicted Pressure Loss: Friction Loss: Elevation Loss: Kinetic Loss: In-line Facilities Loss: Total Liquid Holdup: Total Gas Pack: Estimated Static Liquid Column Height: Measured Depth: N/A 28.636 0,000 SPT N/A 28.739 0.000 SPT N/A 28.843 0.000 SPT N/A 28.908 0.000 SPT N/A 28.973 0.000 SPT N/A 29.077 0.000 SPT N/A 29.143 0.000 SPT N/A 6.629 .0.000 SPT N/A 6.632 0.000 SPT N/A 6.638 0.000 SPT N/A 6.644 0.000 SPT N/A 6.646 0.000 SPT 1063.7 psia 50.0 deg F 1069.9 psia 80.0 deg F -6.2 psi 57.1 psi -63.3 psi -0.0 psi 0.0 psi O.O bbl 15553.4 scf 0.0 ft 2916.0 ft 1.0000 0.0000 72.6 1.0000 0.0000 73.7 1.0000 0.0000 74.7 1.0000 0.0000 75.0 1.0000 0.0000. 76.0 1.0000 0.0000 77.0 1.0000 0.0000 77.3 1.0000 0.0000 77.8 1.0000 0.0000 78.3 1.0000 0.0000 79.3 1.0000 0.0000 79.8 1.0000 0.0000 80.0 2.204 -1.780 1067.16 2.212 -1.774 1066.72 2.220 -1.768 1066.26 0.579 -0.459 1066.15 2.230 -1.788 1065.70 2.238 -1.782 1065.24 0.628 -0.498 1065.12 0.022 -0.817 1065.91 0.022 -0.867 1066.75 0.050 -1.949 1068.65 0.021 -0.819 1069.45 0.011 -0.442 1069.87 • Case Number: 4 TITLE: INJECTION STRING SPECIFIED AND CALCULATED SYSTEM DATA CASING TUBING 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 0.0 ft Depth 0.0 ft Depth Equivalent Gas Volume Flow: 15.00 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/f t3) (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 1126.07 200.0 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 38.825 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 l 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 28.49.5 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 Asia 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 • Case Number: 5 ------------------------------------ SPECIFIED AND CALCULATED SYSTEM DATA ------------------------------------ TITLE: INJECTION STRING Flow String: Tubing String Length: 2916.0 ft CASING ID De pth (inch) (ft) 6.276 0.0 Roughness: 0.00180 inch @ TUBING 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 0.0 ft Depth @ 0.0 ft Depth Equivalent Gas Volume Flow: 20.00 MMSCfd Water Volume Flow: 0.00 Bbl/day DETAILED RESULTS I SUPERFICIAL T DENSITY VISCOSITY VELOCITIES PREDICTED VOL UME 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 2 200.0 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 • 2 2300.0 3.62 N/A 0.0126 N/A 55.902 0.000 SPT 1.0000 0.0000 73.7 2 2400.0 3.58 N/A 0.0126 N/A 56.474 0.000 SPT 1.0000 0.0000 74.7 2 2426.0 3.56 N/A 0..0126 N/A 56.840 0.000 SPT 1.0000 0.0000 75.0 2 2526.0 3.b4 N/A 0.0126 N/A 57.211 0.000 SPT 1.0000 0.0000 76.0 2 2626.0 3.50 N/A 0.0126 N/A 57.811 0.000 SPT 1.0000 0.0000 77.0 2 2654.0 3.48 N/A .0.0126 N/A 58.202 0.000 SPT 1.0000 0.0000 77.3 2 2700.0 3.47 N/A 0.0126. N/A 13.252 0.000 SPT 1.0000 0.0000 77.8 2 2746.0 3.47 N/A 0.0126 N/A 13.260 0.000 SPT 1.0000 0.0000 78.3 1 2849.5 3.47 N/A 0.0126 N/A 13.273 0.000 SPT 1.0000 0.0000 79.3 1 2893.0 3.46 N/A 0.0126 N/A 13.2.85 0.000 SPT 1.0000 0.0000. 79.8 1 2916.0 3.46 N/A 0.0127 N/A 13.291 0.000 SPT 1.0000 0.0000 80.0 SUMMARY: CALCULATED WELLHEAD PRESSURE: SPECIFIED WELLHEAD TEMPERATURE: SPECIFIED BOTTOM-HOLE PRESSURE: SPECIFIED BOTTOM-HOLE TEMPERATURE: Predicted Pressure Loss: Friction Loss: Elevation Loss: Kinetic Loss: in-line Facilities Loss: Total Liquid Holdup: Total Gas Pack: Estimated Static Liquid Column Height: Measured Depth: 1211.8 psia 50.0 deg F 1069.9 psia 80.0 deg F 141.9 psi 210.2 psi -68.6 psi 0.3 psi 0.0 psi 0.0 bbl 16504.1 scf 0.0 ft 2916.0 ft 8.481 -1.842 1097.04 8.567 -1.824 1090.28 8.655 -1.805 1083.42 2.265 -0.466 1081.61 8.768 -1.811 1074.64 8.860 -1.792 1067.56 2.497 -0.498 1065.55 0.087 -0.817 1066.28 0.087 -0.867 1067.06 0.197 -1.950 1068.82 0.083 -0.819 1069.55 0.044 -0.442 1069.94 ***************************************** Date: 12-03-2010 * Neotechnology Consultants Ltd. * Time: 10:56:03 AM * ~ * * * WELLFLO 7 - Version 7.231 * * * Licensee: Aurora Power ** C A L 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 CALCULATIONMETHODS 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 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 H25 0.000 C1 C2 0.987 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 N-C24 0.000 0.0.00 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 C1 0.987 C2 6.800Oe-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 N-C19 0.000 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 C, Case Number: 1 TITLE: INJECTION STRING CASING L__J TUBING WELLHEAD BOTTOM-HOLE FLOW RATES ------------------------------------ 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 @ 0.0 ft Depth ID OD Depth (inch) (inch) (ft) 2.992 3.500 0.0 Roughness: 0.00180 inch @ 0.0 ft Depth Pressure: to be calculated Temperature: 50.0 deg F Pressure: 1070.0 psia Temperature: 80.0 deg F Equivalent Gas Volume Flow: 0.00 MMSCfd water volume Flow: 0.00 Bbl/day RESULTS ------------ ------------------ ------------ 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: O.O ft Measured Depth: 2916.0 ft • • i Case Number: 2 SPECIFIED AND CALCULATED SYSTEM DATA ------------------------------------ TITLE: INJECTION STR ING Flow String: Tubing String Length: 2.916.0 ft CASING ID Depth (inch) (ft) 6.2.76 0.0 Roughness: 0.00180 inch TUBING 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 RESULTS ------------- ------------- ------------------ CUM. ------------ MEASURED CALCULATED LIQUID CALCULATED DEPTH PRESSURE HOLDUP TEMPERATURE (ft) (psia) (bbl) (deg F) - ---------- ------------ ------------ ------------ 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 0.0 ft-Depth 0.0 ft Depth 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 SPECIFIED AND CALCULATED SYSTEM DATA CASING TUBING r~ 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 O.O ft Depth 0.0 ft Depth Equivalent Gas Volume Flow: 10.00 MMSCfd Water Volume Flow: 0.00 Bbl/day RESULTS CUM. MEASURED CALCULATED LIQUID CALCULATED DEPTH PRESSURE HOLDUP TEMPERATURE (ft) (psia) (bbl) _ (deg F) --------- ------------------ - 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 2.100.00 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 T ~ 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: O.O ft Measured Depth: 2916.0 ft • r 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 psis Temperature: 80.0 deg F FLOW RATES Equivalent Gas Volume Flow: 15.00 MMSCfd Water Volume Flow: 0.00 Bbl/day RESULTS 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 2654.0.0 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: 5.0.0 deg F SPECIFIED BOTTOM-HOLE PRESSURE: 1069.2 psia SPECIFIED BOTTOM-HOLE TEMPERATURE: Predicted Pressure Loss: Friction Loss: Elevation Loss: Kinetic Loss: In-line Facilities Loss: Total Liquid Holdup: Total Gas Pack: Estimated Static Liquid Column Height: Measured Depth: 80.0 deg F 58.4 psi 123.8 psi -65.5 psi 0.1 psi 0.0 psi 0.0 bbl 15949.5 scf 0.0 ft 2916.0 ft • i ~. , Case Number: 5 TITLE: INJECTION STRING CASING TUBING ,~ u 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 ~ O.O 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: 20.00 MMSCfd Water Volume Flow: 0.00 Bbl/day RESULTS ------------ ------------------ ------------ 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.O 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 • C ~3 t i Colombie, Jody J (DOA) From: Davidson, Temple (DNR) Sent: Friday, February 12, 2010 9:38 AM To: Colombie, Jody J (DOA) Cc: Franger, James M (DNR) Subject: RE: Public Hearing, Nicolai Creek #2 HiJody, DNR would like to request a hearing for the Nicolai Creek SIO. Thanks, Temple From: Colombie, Jody J (DOA) Sent: Thursday, February 11, 2010 9:19 AM To: Seamount, Dan T (DOA); Foerster, Catherine P (DOA); Norman, John K (DOA); Colombie, Jody J (DOA); Ramirez, Darlene V (DOA); McIver, Bren (DOA); Aubert, Winton G (DOA); Davies, Stephen F (DOA); Ballantine, Tab A (LAW); Aaron Gluzman; 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; 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, Conde (ASRC Energy Services); Brian Gillespie; Havelock, Brian E (DNR); Bruce Webb; carol smyth; Charles O'Donnell; Chris Gay; Cliff Posey; Crandall, Krissell; Dan Bross; dapa; 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; Rogers, Gary A (DOR); Schultz, Gary (DNR); ghammons; Gordon Pospisil; Gorney, David L.; Gregg Nady; gspfoff; Hank Alford; Harry Engel; Jdarlington (jarlington@gmail.com); jeff.jones@alaskajournal.com; Jones, Jeffery B (DOA); Jerry McCutcheon; Jim White; Jim Winegarner; news@radiokenai.com; John Goring; John S. Haworth; John Spain; John Tower; Katz, John W (GOV); Jon Goltz; Joseph Darrigo; Houle, Julie (DNR); Kari Moriarty; Kaynell Zeman; Keith Wiles; Ostrovsky, Larry Z (DNR); Silliphant, Laura J (DNR); Crockett@aoga.org; Mark Dalton; Mark Hanley (mark.hanley@anadarko.com); Mark Kovac; Mark P. Worcester; Kremer, Marguerite C (DNR); Michael Jacobs; Mike Bill; mike@kbbi.org; Mikel Schultz; Mindy Lewis; MJ Loveland; mjnelson; mkm7200; knelson@petroleumnews.com; Nick W. Glover; NSK Problem Well Supv; Patty Alfaro; Decker, Paul L (DNR); 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; Shannon Donnelly; Sharmaine Copeland; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); Sondra Stewman; Steve Lambert; Moothart, Steve R (DNR); Steven R. Rossberg; Suzanne Gibson; tablerk; sheffield@aoga.org; Taylor, Cammy O (DNR); Ted Rockwell; Davidson, Temple (DNR); Teresa Imm; Terrie Hubble; Thor Cutler; Todd Durkee; Tony Hopfinger; trmjrl; Walter Featherly; Williamson, Mary J (DNR); Winslow, Paul M Subject: Public Hearing, Nicolai Creek #2 Jody J. Colombie Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 (907)793-7221 (phone) (907)276-7542 (fax) "tt'"L n STATE OF ALASKA ADVERTISING ORDER SEE BOTTOM FOR INVOICE ADDRE F AOGCC R 333 W 7th Ave, Ste 100 ° Anchorage, AK 99501 M 907-793-1238 o Anchorage Daily News PO Box 149001 Anchorage, AK 99514 AGENCY CONTACT Jody Colombie PHONE DATE OF A.O. February 11, 2010 PCN DATES ADVERTISEMENT REQUIRED: February 12, 2010 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 Classified ^Other (Specify) SEE ATTACHED SEND INVOICE IN TRIPLICATE AOGCC, 333 W. 7th Ave., Suite 100 TO Anchors e AK 99501 REF TYPE NUMBER AMOUNT 1 VEN s ARD 02910 FIN AMOUNT SY CC PGM 1 10 02140100 2 PAGE 1 OF TOTAL OF 2 PAGES ALL PAGES COMMENTS LC ACCT FY NMR DIST 73451 DIVISION APPROVAL: 02-902 (Rev 3/ 4) Publis~f r Original Copies: Department Fiscal, Department, Receiving ADVERTISING ORDER NO. NOTICE TO PUBLISHER INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED A O_03014022 AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF !'1 ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE DATE AO.FRM • Notice of Public Hearing • STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: The application of Aurora Gas, LLC for an order authorizing underground natural gas storage in the South Undefined Gas Pool, well NCU 2, of the Nicolai Creek Unit, in conformance with 20 AAC 25.252 and 20 AAC 25.412. Surface location: 1999' FSL, 209' FWL, S29 T11N, R12W SM. Bottom hole location: 768' FSL, 925' FWL, S29 T11N, R12W SM. The Commission has tentatively scheduled a public hearing on this matter for March 17, 2010 at 9:00 am. To request that the hearing be held, a written request must be filed by 4:30 p.m. on March 5, 2010. If a request is not timely filed, the Commission may consider the issuance of an order without a hearing. To learn if the Commission will hold a hearing, call 907-793-1221 after March 8, 2010. Written comments regarding the application may be submitted to the Commission, at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. Comments must be received no later than 4:30 p.m. on March 16, 2010, except that, if a hearing is held, comments must be received no later than the conclusion of the hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, ca11907-793-1221 by March 15, 2010. Daniel T. Seamount, Jr. Chair • • Anchorage Daily News Affidavit of Publication 4001 Northway Drive, Anchorage, AK 99508 PRICE OTHER AD # DATE PO ACCOUNT PER DAY CHARGES 738758 02/12/2010 AO-03014 STOF0330 $146.08 $146.08 $0.00 THER OTHER GRAND CHARGES #2 CHARGES#3 TOTAL $0.00 $0.00 $146.08 STATE OF ALASKA THIRD JUDICIAL DISTRICT Shane Drew, being first duly sworn on oath deposes and says that he is an advertising representative of the Anchorage Daily News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and during all said time was printed in an office maintained at the aforesaid place of publication of said newspaper. That the annexed is a-copy of an advertisement as it was published in regular issues (and not in supplemental form) of said newspaper on the above dates and that such newspaper was regularly distributed to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged private individuals. Signed Subscribed and sworn to me before. this date: Notary Public in and for the State of Alaska. Third Division. Anchorage, Alaska MY COMMISSION EXPIRES: l~ ~~t`;tf(f!(f/ ~````~~•~!r A A ~`,QOL%, ~. - - =_ ~U~L,G '~ 1 ~ •~~~~ ~~~• 11 J''~~~~II1111 J )11)11,,\1 , Notice of Fabric Rearing SfAT$ OF AIIASKA Ala9ka OIl end G~ Conservation Commisefpn te: The application of Aurora Gas,: LLC for ah order ,,,.~ cu. FVi(,.ZS.47"L SurFace location: 1999' FSL, 209'. FWL, 829 T11N, R12W 5M. Bottom holelocaUon: 768' FSL, 925' FWL; 829 T11N; R12W$M. The Commission has tentatively scheduled a public .hearing on this matter for March 17, 2010 at 9100 request must~b2 fined by 4;~a p~,ip; pn ry~h 5, 20 On ~.. ui~ wu~rrnssion wlll n01d 8 heerJng, C8 907-793-122T after March 8, 2010. Avenue, Suite 100,`Anchora e, Alaska 99601 on Marnh 6, ©t10, ex~cept~thnat ltf a head Ag~~h~ d; comments must be received no latert~an the conclusion ofthe hearing.. If, because of a disability, special accommodations. may be needed to comment or, attend the hearing, Ball 907-793-1227 by March 15, 2010.: )aniel T. Seamount, Jr. :hair to-o3o1wa2 'Utdished: Feixuary 12, 2(110 • STATE OF ALASKA ADVERTISING ORDER SEE BOTTOM FOR INVOICE ADDRESS .7 NOTICE TO PUBLISHER ADVERTISING ORDER NO. INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED /L O_03014022 AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF /'1 ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE F AOGCC R 333 West 7~' Avenue. Suite 100 ° Anch~rage_ AK 995(11 M 907-793-1238 o Anchorage Daily News PO Box 149001 Anchorage, AK 99514 AGENCY CONTACT I DATE OF A.O. PCN 17V/- /77 -1GG1 DATES ADVERTISEMENT REQUIRED: February 12, 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 PU6LICATION 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 _ • • Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Thursday, February 11, 2010 9:19 AM To: Seamount, Dan T (DOA); Foerster, Catherine P (DOA); Norman, John K (DOA); Colombie, Jody J (DOA); Ramirez, Darlene V (DOA); McIver, Bren (DOA); Aubert, Winton G (DOA); Davies, Stephen F (DOA); Ballantine, Tab A (LAW); 'Aaron Gluzman'; 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; 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 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 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; 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; Todd Durkee; Tony Hopfinger; trmjr1; Walter Featherly; Williamson, Mary J (DNR); Winslow, Paul M Subject: Public Hearing, Nicolai Creek #2 Attachments: S45C-210021109110. pdf Jody J. Colombie Special Assistant Alaska Uil and Gas Conservation Commission 333 West 7th Avenue, Szeite 1 DO Anchorage, AK 99501 (907)793-1221 (phone) (907)276-7542 (fax) Mary Jones David McCaleb Cindi Walker XTO Energy, Inc. IHS Energy Group Tesoro Refining and Marketing Co. Cartography GEPS Supply & Distribution 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 300 Concord Plaza Drive Ft. Worth, TX 76102-6298 Houston, TX 77056 San Antonio, TX 78216 George Vaught, Jr. Jerry Hodgden Richard Neahring PO Box 13557 Hodgden Oil Company NRG Associates Denver, CO 80201-3557 408 18th Street President Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 Mark Wedman Schlumberger Ciri Halliburton Drilling and Measurements Land Department 6900 Arctic Blvd. 2525 Gambell Street #400 PO Box 93330 Anchorage, AK 99502 Anchorage, AK 99503 Anchorage, AK 99503 Baker Oil Tools Ivan Gillian Jill Schneider 4730 Business Park Blvd., #44 9649 Musket Bell Cr.#5 US Geological Survey Anchorage, AK 99503 Anchorage, AK 99507 4200 University Dr. Anchorage, AK 99508 Gordon Severson Jack Hakkila Darwin Waldsmith 3201 Westmar Cr. PO Box 190083 PO Box 39309 Anchorage, AK 99508-4336 Anchorage, AK 99519 Ninilchick, AK 99639 James Gibbs Kenai National Wildlife Refuge Penny Vadla PO Box 1597 Refuge Manager 399 West Riverview Avenue Soldotna, AK 99669 PO Box 2139 Soldotna, AK 99669-7714 Soldotna, AK 99669-2139 Richard Wagner Cliff Burglin Bernie Karl PO Box 60868 PO Box 70131 K&K Recycling Inc. Fairbanks, AK 99706 Fairbanks, AK 99707 PO Box 58055 Fairbanks, AK 99711 North Slope Borough PO Box 69 Barrow, AK 99723 tt ~ ' }/~ ~ i~/ 1 ~~ /~ ~ 1 ~ v ,J {/W V"'~ w ~~~~ ~~ • n :Aurlora has LLC ~r www,aurorapower,com Mr. Daniel Seamount, Chair February 1, 20 i 0 Alaska Oil and Gas Conservation Commission 333 West 7t" Ave., Suite 100 RECEIVED Anchorage, Alaska 99501 FEB ~ 2 2010 RE: Application for Storage Injection Order Nicolai Creek Gas Storage Facility Alaska Oil ~ 683 Cons. Commission Anchorage Dear Mr. Seamount: Enclosed for your information and review are two copies of Aurora Gas, LLC's ("Aurora") Application for Storage Injection Order ("SIO") for the Nicolai Creek Gas Storage Facility ("NCGSF"). The SIO Application is submitted pursuant to the requirements of 20 AAC 25.252 (c) and 20 AAC 25.460(a). Also enclosed is supporting geologic/engineering data. Aurora is the sole working interest owner of the Nicolai Creek area oil and gas leases and is the Operator of the Nicolai Creek Unit. Aurora proposes to be sole Operator of the NCGSF. The NCGSF is proposed to utilize the Nicolai Creek Undefined Gas Field reservoir that has/is producing from the geologic conformities of the Carya 2-l.l, Carya 2-1.2 and Carya 2-2.1 sands encountered in the Nicolai Creek Unit #2 well. There are no other wells currently producing or injecting into these identified sands. In association with the SIO Application, Aurora will be submitting a Sundry Application for the conversion of the Nicolai Creek #2 well, PTD # 1_66 to adual-purpose production / injection well. Thank you for your consideration of this 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 below. Sincerely, ~_.J ~ ~ Bruce D. Webb Aurora Gas, LLC Manager, Land and Regulatory Affairs attachments Zz q - 1355' c.,e,Gl 1400 West Benson B/vd., Suite 410 • Anchorage, AK 99503. (907) 277-1003 • Fax: (907) 277-1006 6051 North Course Drive, Suite 200 • Houston, TX 77072 • (713) 977-5799 • Fax: (713) 977-1347 • • Aurora Gas, LLC Nicolai Creek Gas Storage Facility Application for Storage Injection Order ---- ~. ;air• r ~~s ~. ~~I':~ ._c February 2010 • • Introduction Aurora Gas, LLC ("Aurora") requests a Storage Injection Order ("SIO") within the boundaries of the Nicolai Creek Unit. The Nicolai Creek Gas Storage Facility ("NCGSF"). The SIO Application is submitted pursuant to the requirements of 20 AAC 25.252 (c) and 20 AAC 25.460(a). Aurora is the sole working interest owner of the Nicolai Creek area oil and gas leases and is the Operator of the Nicolai Creek Unit. Aurora proposes to be sole Operator of the NCGSF. The NCGSF is proposed for gas storage injection and production operations for the Nicolai Creek Undefined Gas Field reservoir(s) that has/is producing from the geologic traps containing the Carya 2-1.1, Carya 2-1.2 and Carya 2-2.1 sands as seen in the Nicolai Creek Unit #2 ("NCU 2")well. There are no other wells currently producing from or injecting into the identified sands common to the NCU 2 well. After receiving the necessary approvals, Aurora will be submitting a Sundry Application for the conversion of the NCU 2 well, PTD # 166-038, to adual-purpose production /injection well. Additional wells may possibly be drilled or re-drilled into these same sands in the future to increase deliverability from the NCGSF. Table of Contents Section Re_ugulato , CrY itation Subject A. 20 AAC 25.252(c)(1) Plat Information B. 20 AAC 25.252(c)(2) Operators /Surface Owners C. 20 AAC 25.252(c)(3) Affidavit D. 20 AAC 25.252(c)(4) Description of Operation E. 20 AAC 25.252(c)(4) Storage Zones F. 20 AAC 25.252(c)(4) Geologic Information G. 20 AAC 25.252(c)(4) NCU #2 Production History H. 20 AAC 25.252(c)(5) NCU #2 Well Logs I. 20 AAC 25.252(c)(6) Mechanical Integrity J. 20 AAC 25.252(c)(6) NCU #2 Casing Information K. 20 AAC 25.252(c)(7) L. 20 AAC 25.252(c)(8) M. 20 AAC 25.252(c)(9) N. 20 AAC 25.252(c)(10) O. 20 AAC 25.252(c)(11) P. 20 AAC 25.252(c)(12) Injection Fluid Injection Pressure Fracture Information Formation Fluid ~e Number Freshwater Aquifer Exemptions Wells Within Area 3 3 4 5 5 9 9 11 12 12 14 14 14 14 15 15 Nicolai Creek Gas Storage Injection Order Application page 2 of 15 ~ ~ Section A -Plat The Nicolai Creek Unit is located approximately 50 miles west of Anchorage and 12 miles southwest of the Village of Tyonek, on the west side of the Cook Inlet, Alaska. The NCGSF proposes to utilize the existing NCU 2 well, located on the Nicolai Creek Unit 1, 2, 9 production pad at the west end of the Shirleyville airstrip. Following is a plat of the Nicolai Creek Unit 1, 2, 9 production pad showing the location of the NCU 2 well. ~~ RAD LIMITS s w,orn~,..Ta v»t. ~~. C [pQ14' ill >[G N:~CHHC9 'ti O 13-w' r 7 ?-r C ,. . \ 5' T C ~~ C 7 7 w iT~itifFAHAi:~4; t+ ~ ucra e~! ~ ~ . eEU F*y__ o ~~ s ~./ ~ ~ I / 4 ,~ a --r, ^ _n _ ~ ------- y q r 4 - ~ j .~ ~ _. ,.~ ~- ~ ~ e v~«s.nv.~n C~~ an - PAD L?~WITS -- _,~- - - - ~ ~ ~ -- AUf20RA NICC7LAI CE7EEK nt0.t 2 9 "' " .. .._ ,._. .~. ._e. ~ ~K~ •080IIA tL! 78C P4~C.Q fIQ]"0 nroG r --- aua-~w a~ ~.-~ wu ae ~m B ~ b 3 a ~ r Section B -Operators /Surface Owners The surface ownership and operators within the area of this storage injection order application and extending one-quarter mile beyond the NCU 2 well and within the existing production unit are: • State of Alaska, Department of Natural Resources, Division of Oil and Gas 550 W. 7~' Avenue, Suite 800 Anchorage, AK 99501 • State of Alaska, Mental Health Trust Land Office 718 `L' Street, Suite 202 Anchorage, AK 99510 • Aurora Gas, LLC 1400 W. Benson Blvd., Suite 410 Anchorage, AK 99503 Nicolai Creek Gas Storage Injection Order Application page 3 of 15 • • Section C -Affidavit The parties listed in Section B were furnished a copy of thi application. Following is the affidavit attesting to this. AFFIDAVIT IN SUPPORT OF THE NOTICE AND APPLICATION FOR STORAGE INJECTION ORDER Nicolai Creek Gas Storage Facility I, Bruce D. Webb, Manager of Land and Regulatory Affairs for Aurora Gas, LLC • hereby certifies that the required information contained in the application for Storage Injection Order, pursuant to the Alaska Oil and Gas Conservation Commission regulations for the above proposed gas storage facility, dated February 2010, are true and correct, to the best of my knowledge. Further your affiant sayeth not. Aurora Gas, LLC B ~s"~~- ~--~-~ ~~~+~ Febru 1 2010 Y ~. Bruce D. Webb Dated Manager, Land and Regulatory Affairs IN THE UNITED STATES OF AMERICA STATE OF ALASKA ss. This certifies that on the 1st day of February, 2010, before me a notary public in and for the State of Alaska, duly commissioned and sworn, personally appeared Bruce D. Webb, to me known and known to me to be the person described in, and who executed the foregoing. assignment, who then after being duly sworn according to iaw, acknowledged to me under oath that he executed the same freely and voluntarily for the uses and purposes therein mentioned. Witness my hand and official seal the day and year first above written. Notary Public MARY NOVOTNY State of Aleske My Commission Expires Sep 17, 2013 Notary P lic My Commission Expires: September 17, 2013 lUicoiai Creek Gas Storage Injection Urder Application page 4 of 15 • Section D -Description of Operation C Aurora proposes the injection of natural gas into sands of the Nicolai Creek Undefined Gas Pool for natural gas storage purposes. Aurora intends on utilizing the Tyonek sands within this pool having the geologic marker identification of Carya 2-1.1, Carya 2-1.2 and Carya 2- 2.1,which have the State Formation Codes of 9016, 9017 and 9019, respectively. These sands are expected to be depleted or nearly depleted at the time of gas storage commencement. The storage gas will be injected during periods of excess supply and produced back during periods of increased demand. Initially, the NCU 2 well will be used as the sole well for gas storage operations, both injection and production. Aurora may later decide to drill or re-drill another well to increase deliverability from the NCGSF. Section E - Storage Zones The Tyonek Carya sands are the proposed zones of injection. The reservoir is a combination of stratigraphic and structural sand traps. The top of the sand traps correlates to depths defined in the NCU 2 well. Nicolai Creek Unit #2 Well Top (MD /TVD) Bottom (MD /TVD) Net Thickness Tyonek Carya 2-1.1 Sand 2,426' / 2,141' 2,476' / 2,177' 36' Tyonek Carya 2-1.2 Sand 2,700' / 2,342' 2,716' / 2,356' 14' Tyonek Carya 2-2.1 Sand 2,893' / 2,494' 2,916' / 2,511' 18' NICOLAI CREEK TYPE LOG a SP . O1L ` CARYA Z-1.1 SAND ~ NCU#3 -POP REiRVES (1900-30 J, ~' _ ~ - (FORMERLY 1900 SANOJ NCUx2O POP RNESE ES (2416-6G~Z SANDS CARYA 2-1.2 SAND ~ NCUx3 -POP RESERVE (2005-3Z~. I (FORMERLY 2000 SANOJ Ncuxz POP aEERVE (z7oo-167. -. CARYA 2-2.1 SAND ~ NCUx3 -POP RESERVES (2701-3B~ (FORMERLY 2200 SANOJ NCVx7 - POP RESERVES (7893d916~. CARYA 1-1.2 SAND ~ NCUx3 -POP RESERVES (7303-19~ (FORMERLY2300 SANDJ CARYA 1-1.3 SAND ~ NCUx3 - EX-~P R6ERVES (7360-B0~ W/O. (FORMERLY 2350 SAND) Ncuxz - Ex-PVP RESERVES (3z~o-331s) 7E57ED @ 4.2 MMLFD, C(M7. 51 MMCFG ASSL/MED DEPLETED. _ GIRYA 2-4 ("CJ MAR/Q=R ~: CARYA 2-4.2 SAND ~ NCUx1B - PONPRESERVE (3191-3211 ~. 1- ~ G4RYA 1-S.I SAND ~ NCVxIB-PONP RESERVE (3371-3401 ~. ' ~ , (FORMER[ Y3450 SAND) NcuxlA - Ex-POP RESERVES, 7E57ID @ 33 MMCD (3470-60~ s/1 ~ ..~ __ ~ . ..: ~ _t/ : ' { CARYA 2-6.ISAND ~ NCUxIB-BPREER/E (3660-3576). N x1A Ex POP RESERVE - ~ ^ r - - , cu (FORMER[ Y3650 SANG) TESTED na 29 MM6D (3615-30 J s/1, ' w- ;... .. ~.~...~.~ CVM. 117 MMCEG WITH GRYA 2-6.1 64N0. Nicolai Creek Gas Storage Injection Order Application page 5 of 15 • • Nicolai Creek Field Nicolai Creek Field ~, r too ~ ~9MM~ ]W+NO Nicolai Carya 2-1.1 Isochron IV1ap (Smoothed) Nicolai Creek Gas Storage Injection Order Application page 6 of 15 Carya 2-1.1 Depth Structure Map • • Nicolai Creek Field ., ~'' y:: ,~. vn erg sao 1 Nicolai Creek Field Nicolai Carya 2-1.2 Isochron Map (Smoothed) ~a. A~, Nicolai Creek Gas Storage Injection Order Application page 7 of 15 Carya 2-1.2 Depth Structure Map • • Nicolai Creek Field Nicolai Creek Field ~..~ Nicolai Carya 2-2.1 Isochron Map (Smoothed) ea, ~Qa ..~ a;- o~, o AS4 Nicolai Creek Gas Storage Injection Order Application page 8 of 15 Carya 2-2.1 Depth Structure Map • • ~ Section F -Geologic Information The reservoir sandstones of the NCU 2 belong to the Oligo/Miocene Tyonek Formation. • Only those sands of the Tyonek Formation (Carya 2-1.1, 2-1.2 and 2-1.1) are currently being produced from the NCU 2 well and proposed for gas storage operations. Subsurface geology ~ of the NCU 2 sands of the Nicolai Creek Unit indicates a combination structural and stratigraphic trap with gas trapped in the Upper Tyonek sandstones. These sandstones trapped • within a fold and closed against a dominant west-east cross-fault (the Nicolai Cross Fault) that • splays off the Trading Bay Fault to the east. The Nicolai Cross Fault appears to separate the structure of the Nicolai Creek North Participating Area from that of the South Participating Area which contains the gas storage sands found in the NCU 2 well. Deposition of these sands occurred within the Cook Inlet Basin, a feature characterized as an elongate, northeast trending, fault-bounded forearc basin that extends from the Matanuska Valley south along the Alaska Peninsula. The northwestern reaches of the Cook Inlet forearc basin are defined by a series of tight anticlines and associated structures that deforms the Tertiary section and provides traps for both oil and gas. These features are part of a transpressional regime that results from strain transfer between the Castle Mountain Fault to the north and Bruin Bay Fault to the west. The structures manifested throughout the Nicolai Creek Unit have evolved through such processes. Within the South Participating Area, reservoirs sandstones are restricted to the Upper Tyonek Formation. Eight individual sand members have been identified from log correlation and mapped across the Nicolai Creek field. Within the Nicolai Creek field, individual sands have been assigned names based on standardized industry palynological zonation. The sandstones are within the Carya 2 palynological zone and have been subdivided using an appropriate numeric designation (2-1.1, 2-1.2, 2-2.1, 2-2.2, 2-2.3, 2-4.2, 2-5.1, and 2-6.1). Log data indicate the NCU wells show the relative conformity of the shallower Carya 2-1 through Carya 2-23 section with some possible expansion of the deeper Carya 2-4.2 through Carya 2- 6.1 section. According to electric log and mud log data, the Tyonek Carya sands are separated from the Beluga Tsuga sands by more than 150' of tight (low permeability) sandstone and siltstone, carbonaceous claystone, clay, and 2 coal seams. Section G -NCU #2 Production History The NCU 2 well was originally drilled in 1966 by Texaco, Inc. The well was certified capable of production in paying quantities on October 23, 1966 and subsequently shut-in on November 18, 1966 awaiting the ability to bring it to market. The well began production in October 1968 and flowed through November 1969, producing an average of 1.0 MMCF/day. The well was shut-in again in December 1969 after producing a total of 51 MMCF. In September 1991, under Unocal's ownership, the NCU 2 well was cemented at the surface and placed in suspended status. Aurora took over ownership of the NCU 2 well and became the Operator of the Nicolai Creek Unit in June of 2000. Nicolai Creek Gas Storage Injection Order Application page 9 of 15 i • Aurora began well re-entry operations on the NCU 2 well on July 16, 2002, completing the operations and re-completing the well for production on August 9, 2002. In November 2003, Aurora finished testing the NCU 2 well and installed the necessary production facilities and pipelines. Production in December of 2003 was approximately 3.5 MMCF/day, declining to approximately 0.2 MMCF/day by December 2009. Total production from the NCU 2 well through December 2009 is 805,509 MMCF. The estimated ultimate recovery (EUR) of the NCU 2 well, as calculated in February of 2009, is approximately 947 MMCF. Wichert-AZiz correction for contaminants. if anv Reset•t~oir Solutions (Public) c<i7: WELLHEAD TEMP, °F: U9 SOUR GAS MOLE'': Least Squares Mean Fit Results BOTTOMHOLE TEMP. `F: 7?!J N2 t. A6 Y-Intercept, BHP!z 5~4 WET GAS GRAVITY: 0.5507 COz D 00 OGlP, MMCF 533 TVD. FEET: =.505 Hz5 O.OC wrr v. ~~rrn: lrrnl: cun. mrvr~r Corrected' Tc. °R: 3=3.7: Recovery Factor : 5s38 Corrected' Pe, Psia: 6T:32 BHPrz ~ Abandonmem 4e 1 .400 _ .. _-_ _ `_ __ I •LSMF Date o Excl. Cata • E'..R = 54? • OGIP : yy3 ~~, 1 2D0 , 1 000 , 800 y a a m ~ ~ 6D0 400 ~ co O u- ~3 0 ,R. D D 2co 400 6oD 600 +.oDD ,,aoD Cumulative Production. MMef POINT I•lUR-0B_°R {automati;:i CATE (Ootiona ; SITE. Asia E-F, Fs a - 6HP:L Fsia SUM FROC. Mblcf LSMF Include? i`~+N-~ 1 11ia:0003 L01e t.0?5 '1E?21 1.230 D n 2 11r_2rJ003 t.C'D- t,056 0.6?3E 1,2' 1 2 n 3 '~1r_2:0003 1.C'0' 1,060 0.6?3~ 1,C~4 2 H 4 Zrl'.:2C'04 769 30? D.50D= &e6 142 y 5 9i IJ:2C'D4 EJS Se4 0.526^- 9J0 267 a 7;1.:2DOa s5=. 5J6 0.5215 bee ^?J ~ rJD04 385 404 0.543? 427 461 n ~8 4P-0:2005 35s 415 O.E47J 43E. 4?: n 2 7~1d:2C05 e15 43E D.544= 4e2 4?'_' y 1. 2r1?:2005 228 236 0.552° 2=4 556 n 11 9i 142009 168 176 0.5772 1°_0 60E n 12 1:; 5:2D05 155 204 0.573E 210 606 13 ,Zi'.,,t7e05 240 0.5679 2E0 62a ~~ 1=- trt3i2007 25s Zee. 0.555_. 277 624 R 15 2J4t2J0? 2?S 295 0.562e 3CD 62~ n 1E 36200? 300 315 '1559° 326 62d t7 4!3-02OD7 J95 310 0.560 323 E30 t9 3i1'-:2007 287 3Ct 0.551? 31 .'• 647 '! 12 5:9:2008 124 1?-G '15832 13~ ?12 n 1e3 ~2G09 ~5` 2EE '15589 277 722 These results ~,oere arepa•ed using Ryder Scoh'~as Maferra+ Balance. This is not Ryder Scotr work product. Nicolai Creek Gas Storage Injection Order Application page 10 of 15 • ~ Section H -NCU #2 Well Logs The open-hole logs from the NCU 2 well were delivered to the AOGCC upon completion of the drilling operations. The following is an excerpt of the log analysis for the proposed gas injection horizons by NuTech Energy Alliance in April 2003. Nicolai Creek Gas Storage Injection Order Application page 11 of 15 • • Section I -Mechanical Integrity The NCU 2 well will be tested for mechanical integrity using the standard 30-minute annulus test per 20 AAC 25.412. To confirm continued mechanical integrity, Aurora will monitor daily injection rates and pressures and will notify the AOGCC the next working day if the rates and pressures indicate pressure communication or leakage in any casing, tubing or packer. The rate and pressure data will also be reported to the Commission on a monthly basis. Section J -NCU #2 Casing Information • The NCU 2 well was spudded by Texaco on September 21, 1966 and achieved a total depth of 5,011' MD (4,086' TVD) on October 12, 1966. All referenced depths are based on original RKB, which was approximately 46' AMSL, with a surface grade elevation of 30.4' AMSL. A 20" conductor was set at 286' and cemented with 650 sacks to surface. The 13-3/8" surface casing was set at 1,934' and cemented with 1,600 sacks to the surface as well. The well was drilled to total depth and 7" production casing was set to 3,550' and cemented with 1,500 sacks of cement. A cement bond log showed cement from 1,900' to 3,550', with good bond characteristics from 2,500' to 3,550'. The well was subsequently perforated from 3,270' to 3,315', tested and put into production from October 1968 through November 1969. In 1991, the well was re-entered by Unocal to plug for suspension. An 87 sack balanced cement plug of 15.8 ppg class "G" cement was placed from 3,102' to 3,537' to cover the original perforations. The 7" casing was then perforated at 677', a cement retainer was set at 590' and 215 sacks of 15.8 ppg class "G" cement was pumped through the retainer to squeeze cement into the 7" x 13-3/8" annulus. A 10-sack cement plug was placed on top of the retainer. The 7" casing was again perforated at 298', a cement retainer was set at 248' and 135 sacks of 15.8 ppg class "G" cement was pumped and observed at the surface. The annulus valve was then closed at the surface and a 200 sack squeeze job was performed on the last 7" casing perforations and the annulus with 15.8 ppg class "G" cement pumped at 400 psi and 2 bbl/minute. After the squeeze job, 4 sacks of cement were placed on the retainer and a 50 sack plug of 15.8 ppg class "G" cement was placed from248' to the surface. Aurora began well re-entry and re-completion activities on the NCU 2 well on July 16, 2002. The BOP was installed and tested to 3,000 psi on July 21, 2002. The test was witnessed by • the AOGCC. The cement plugs were drilled out and the wellbore was circulated clean • between July 24 and 28, 2002. The 7" casing was re-perforated between July 29, 2002 and August 6, 2002 from 2,893' to 2,916', 2,700' to 2,716', and 2,426' to 2,476'. Packers were set and the annulus was tested to 1,000 psi between perforation runs. The NCU 2 wellhead and tubing were installed on August 9, 2002 and tested to 3,000 psi for 15 minutes. The well was hooked up to production facilities and pipelines and was put into production on November 21, 2003. Nicolai Creek Gas Storage Injection Order Application page 12 of 15 • • In summary, full zonal isolation is believed to be present in the NCU 2 well. The straight-line P/Z curve on the NCU 2 production and pressure shows both volumetric reservoir and no behind the casing fluid migration. Aurora believes there to be sufficient zonal isolation to allow for gas injection and storage. Following is the current wellbore diagram. ~lcvlai Creek l~nit #2 Wellk~ore diagram 2 7~8" Production Tubing 36" Hole 30" ~ 80' - Ch1T'D to surface W! 340 SX 26" Mote 20" 94# 286' CMTD to surface W 650 SX 17 1.2" Hole 13 3r8" 54.5 ~ 1934' CMTD W~1600 SX 5" Meshrite Screen Original production perforations 4 1~2 SPF from 3270' to 3315' cep nted over during 1991 Suspension Procedure "` 7" 26?r ~ 3585' M D CMTD MYJ14U0 SX TD ~ 5011' MD 4086' TVD 5 SPF ~ 298' Squeezed w' 200 sx in 1991 5 SPF ~ 677' Squeezed w~ 215 sx in 1'.991 TOC ~ ~ 1900` M D in 13 3~'8" X7" annulus 2.313" ID X-flipple at 2288.8' rmanent Packer at 2327' Perforate ~ 5 SPF 2428' - 2475' Perforate ~ 5 SPF 2700' - 2716` Perforate ~ 5 SPF 2893'to 2916' 87 Sk Class "G" Cement Pfug 3102' - 3537' Plug (Baffle Pfatel 3543' MD L~'.'dil'~'V3TTCa~'_~ NICrJLrsl CREEK No. 2 F.~t?it'['^ ~3.T1~'.4p Re'v. '~1 1 1~1'{~~° GFi-~E-2-G-• ~~~'T?t`~.~ 4~. Nicolai Creek Gas Storage Injection Order Application page 13 of 15 • • ~ Section K -Infection Fluid i The type of fluid for the proposed injection at the NCGSF is dry natural gas, which is . predominately methane. The maximum amount of gas to be injected daily will be less than 20 MMCF/day, current estimated daily injection rate is 10 MMCF to 12 MMCF per day. The NCGSF is intended for the injection of excess natural gas, either owned by Aurora or • purchased from another producer or utility. Therefore, the source of the injection gas at the NCGSF is not presently determinable. Since all expected sources of natural gas are predominately methane and very similar to the original reservoir gas produced from the NCU 2 well, no fluid compatibility problems are expected. Section L -Infection Pressure Compression will be used for gas injection and production operations. Injection pressures will vary significantly depending on the state of depletion of the reservoir. However, the maximum injection pressure will be 1,600 psig. Wellhead injection pressures will be maintained such that a gradient of 0.65 psi/ft at the midpoint of the deepest perforations depth of 2,503' TVD (mid-perf depth of Carya 2-2.1 sands) is not exceeded. This corresponds to wellhead pressures of approximately 1,530 psig with the well shut in and 1,600 psig at a 12 MMCF/day injection rate, with 3-1/2" tubing. Section M -Fracture Information The proposed maximum injection pressure at the NCGSF will not initiate fractures in the confining strata which might enable the injection fluid to enter any freshwater aquifers. The proposed maximum injection pressure for the NCU 2 well in the Carya 2-2.1, as previously mentioned, will not exceed a gradient of 0.65 psi/ft at the sandface. With injection gas gravity of 0.562, the fracture gradient at 2,503' TVD is estimated to be about 0.90 psi/ft. The initial equalized reservoir pressure for the NCU2 was obtained by a bottom-hole pressure survey and confirmed by quartz-crystal surface pressures extrapolated to subsea datum. The original reservoir pressure was 1,057 psig at 2,309' TVD (mid-pay depth). Original reservoir pressure for the Carya 2-2.1 sands is estimated at 1,157 psig based on surface pressure extrapolated to depth. Section N -Formation Fluid The characteristics of the NCU 2 reservoir that makes it an ideal candidate of natural gas storage is the fact that it had not produced any remarkable amount of water during its production between November 2003 and November 2009. Total water production from the NCU 2 well has only been 25 bbls in six years, or an average of less than 14 gallons of water per month. Aurora does not believe formation fluid at the proposed NCGSF to be an issue. Nicolai Creek Gas Storage Injection Order Application page 14 of 15 • • Section O -Freshwater Aquifer Exemptions There have been no freshwater exemptions under 20 AAC 25.440 issued for the NCU 2 well. Section P -Wells within Area As depicted on the Plat at page 3, the there are two other wells within'/4 mile of the NCU 2. Both the NCU 1B and NCU 9 wells have surface locations on the same pad as the NCU 2, but neither well penetrates the Carya 2-1.1, Carya 2-1.2 or Carya 2-2.1 sands. There are no other wells within'/4 mile of the proposed NCGSF. Nicolai Creek Gas Storage Injection Order Application page 15 of 15