The URL can be used to link to this page

Home My WebLink AboutSIO 011 • • SIO No. 11 1. March 30, 2011 UNOCAL Application for Gas Storage at Ivan River 2. April 15, 2011 Notice of Hearing, Affidavit of publication, bulk mail list, email list 3. May 26, 2011 Public Hearing Transcript 4. August 4, 2011 Unocal's notice to commence initial gas storage injection — IRU 44 -36 SIO No. 11 • • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF Union Oil Company of ) Docket No. SIO 11 -01 California for an order authorizing underground ) Storage Injection Order No. 11 natural gas storage, in well IRU 44 -36 of the Ivan ) River Unit, Matanuska - Susitna Borough, in ) Ivan River Unit conformance with 20 AAC 25.252 and 20 AAC ) Undefined Gas Pool 25.412. ) Matanuska - Susitna Borough Alaska ) ) June 20, 2011 ) ) 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 20th day of June, 2011. BY DIRECTION OF THE COMMISSION Jody J. Colombie Special Assistant to the Commission • • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF Union Oil ) Docket No. SIO 11 -01 Company of California for an order ) Storage Injection Order No. 11 authorizing underground natural gas ) storage, in well IRU 44 -36 of the Ivan ) Ivan River Unit River Unit, Matanuska - Susitna Borough, ) Undefined Gas Pool in conformance with 20 AAC 25.252 and ) Matanuska - Susitna Borough 20 AAC 25.412. Alaska ) June 20, 2011 IT APPEARING THAT: 1. By application dated March 30, 2011 Union Oil Company of California (Union), operator of the Ivan River Unit (IRU), requested an order from the Alaska Oil and Gas Conservation Commission (Commission), authorizing injection for underground storage of natural gas into the No. 44 -36 well (IRU 44 -36) in the Undefined Gas Pool of the Ivan River Unit. 2. On April 20, 2011, pursuant to 20 AAC 25.540, the Commission published in the Peninsula Clarion, on the State of Alaska's Online Public Notice Web site, and on the Commission's Internet website, notice of opportunity for a public hearing on May 26, 2011. 3. The Commission held the public hearing on May 26, 2011 at 333 West 7 Avenue, Suite 100, Anchorage, Alaska 99501. Only testimony from Union was offered. No protests or written comments were received in response to the public notice. FINDINGS: 1. Operator: Union operates the IRU and IRU 44 -36, the well proposed for gas storage operations. Both are located in the Matanuska - Susitna Borough, Alaska. Injection Strata: Union proposes natural gas storage injection into the ora e inj 2. Injection P p g g J Beluga 71 -3 Sand, which is depleted from regular gas production from the IRU 44 -36 well. This sand has not been completed in, or produced from, any other well within the IRU. The sand appears to transition to overbank siltstone and silty mudstone to the south in the IRU 41 -01 well, indicating that channel sands within the interval that contains the 71 -3 at the north end of the unit are isolated from the channel sands within the same interval at the south end of the unit. • • Storage Injection Order 11 June 20, 2011 Page 2 of 10 Correlation Depth Res is Porosity SP <M D ResD(LD) RHOB -150 MV 50 1.2 OHMM 2001.65 GM'CC 2.65 RHOB T VD S S> ResS(SFLU) NPOR 1.8 GM/CC 1.85 1.2 OHMM 20030 VN C T V D AT20(N!A) DTCP(DT) El 1.2 200200 US/FT 10C GR <MD AT90(WA ) -10 API 240 1.2 200 111j l ',;; (_dnd - Si - b - old Perforated Intervals 6500 -5000 . - -� -- 5100 6600 ±T .,.._."-* -5100 6700 5200 - s -5200 ) z _ - 6,809' MD `Z ■ PC4 Coal - Beluga 71 -3 � . ;1 _ ��;,�'� Strata trata 6900 6,919' MD • — �` PC5 Coal _ 5 PC6 Coal 5400„ 7000 z 4M' -5400 7100 5500 -5500 7----\ C1/4 ... 7200 S s 5600 ' } . Figure 1. Well Log Recorded in Ivan River Unit No. 44 -36 • • Storage Injection Order 11 June 20, 2011 Page 3of10 From 6829' to 6856' measured depth (MD), the Beluga 71 -3 Sand is topped by a section of interbedded siltstone, clay -rich siltstone and mudstone, which is overlain by a 5 -foot thick' coal bed, the PC4 Coal. Above the PC4 Coal is a 50- foot thick siltstone and mudstone interval, which creates an impermeable barrier above the proposed storage interval. No permeable gas sands are identified immediately above the Beluga 71 -3 Sand in any of the IRU wellbores. The Beluga 71 -3 Sand is underlain by 20' of interbedded siltstone and mudstone. Below this interbedded siltstone and mudstone are additional, laterally discontinuous sands interbedded with clay -rich siltstones and mudstones. These are underlain by 4- to 6 -foot thick coal layers (the PC5 Coal and the PC6 Coal) that are laterally continuous across the IRU. The sandstone, siltstone and mudstone between the top of the PC4 Coal and the top of the PC5 Coal are collectively termed the "Beluga 71 -3 Strata" (Figure 1). The siltstone, mudstone, and laterally continuous coal layers above and below the Beluga 71 -3 Sand act as seals. 3. Proposed Injection Well: The IRU 44 -36 well was drilled and completed in March 1993, 742' from the southern section line (FSL) and 777' from the eastern section line (FEL) of Section 1, T13N, R9W, Seward Meridian (SM). The top of the proposed storage interval is at 4,382' FSL, 817' FEL, Section 1, T13N, R9W, SM. Three sands were originally perforated: the Sterling 58 -4 Sand, the Sterling 59 -6 Sand, and the Beluga 71 -3 Sand. A single, 2 -7/8" completion was run with a production packer set above all zones, and production was commingled. After a September 2001 rig workover three deeper sands were opened, and the previous Sterling and Beluga intervals were reperforated. A 2 -7/8" single -string completion was run with packers and sliding sleeves to enable isolated production intervals. Initial attempts at producing deeper zones were unsuccessful due to water, sand and coal production. An isolation plug was set below the Beluga 71 -3 Sand and the sliding sleeve was opened. The Beluga 71 -3 Sand continued to produce with very little associated water until March 2004. With a reservoir pressure of 615 psia, the well was unable to flow into the compressor at the Ivan facility. The Beluga 71 -3 Sand was then isolated and unsuccessful attempts were made to produce the shallower Sterling sand intervals. These intervals brought water and sand into the well bore. The well has not been returned to production since. 4. Operators / Surface Owners Notification: Union has provided an affidavit affirming that surface owners and operators within one - quarter mile of the storage area have been notified. The surface owners and operators within the storage area of review are Union and the State of Alaska Department of Fish and Game. ' All thicknesses are expressed in terms of true vertical feet. • • Storage Injection Order 11 June 20, 2011 Page 4 of 10 5. Description of Operation: Union proposes injecting gas into the nearly depleted Beluga 71 -3 Sand for storage. The IRU 44 -36 well will be the sole well for both production and injection storage operations. Gas will be injected during periods of excess supply and produced during periods of increased demand to help balance gas deliverability requirements. 6. Pool Information: Gas is regularly produced in the IRU from the Lower Sterling, Beluga and Tyonek formations. The Lower Sterling consists of interbedded layers of sandstone, siltstone, mudstone, and coal that were likely deposited in a higher- energy meandering stream to braided stream environment. The Lower Sterling contains the shallowest gas- bearing sands, which extend from about -4850' to - 5,175' TVDSS, or about 320' in thickness. The underlying Beluga Formation consists of sandstone interlayered with abundant siltstones, mudstones and coals that were deposited in thinner, lower energy meandering stream systems. Beluga sandstone deposits are likely laterally discontinuous. This low - energy Beluga section is approximately 2,750' thick at IRU. All Beluga gas production has been from the upper 350' of the formation. The Tyonek Formation is comprised of meander belt and anastomosing stream sandstones, which are often amalgamated into thicker sandstone sections that are interbedded with siltstones, mudstones and thick coals. The Tyonek is approximately 4,850' thick at IRU; all gas production has been from the upper 200' of the formation. The IRU 44 -01 and IRU 11 -06 wells produce gas from the Tyonek. The IRU 44 -36 wellbore did not reach the Tyonek. Estimates of original gas in place for the Beluga 71 -3 Sand were determined by analyzing the material balance plot, Figure 2, below, for the post - September 2001 period when the zone produced 1.7 billion cubic feet (BCF) in isolation from the other Beluga intervals. P/Z vs. cumulative gas produced for this time period is a straight line, indicating volumetric type depletion or a weak aquifer at most. By extrapolating this straight line back to the original reservoir pressure for the sand, a theoretical plot was generated for the zone, had it produced in isolation over the entire depletion period. This approach yields an estimate of 3.9 BCF original gas in place for this zone. Cumulative production from the IRU 44 -36 well is 3.1 BCF of gas and 460 bbl water, the gas production representing about 79.5% of the original gas in place within the Beluga 71 -3 Sand. 7. Well Logs: All open hole logs from wells in the IRU were sent to the Commission once the logs were completed. Figure 1 presents well log information recorded for the Beluga 71 -3 Sand, the proposed injection interval. 2 All thicknesses are expressed in terms of true vertical feet. Storage InjJ ection Order 11 June 20, 2011 Page 5of10 4000 3500 • • 3000 - • 2500 - OGIP = 3.9 bcf nearly depleted 2000 el 1 1500 - 1000 - 500 - 0 0 5 10 15 Cum Gas Produced, bcf y = - 884.89x + 9188.2 Figure 2: P/Z vs Cumulative Production Plot for the IRU 44 -36 We11 8 . Mechanical Integrity and Well Design: IRU 44 -36 13 -3/8" surface casing was set at 908' MD ( -854' TVDSS) with cement returns to surface. A 12 -1/4" hole was then drilled, 9 -5/8" casing was set at 3,449' MD (- 2,890' TVDSS) and cemented to surface. A leakoff test was run to 19.5 ppg equivalent mud weight (EMW). Seven -inch casing was set at 8,308' MD (- 6,382' TVDSS) and cemented in place. A cement bond log found the top of cement at 4,400' MD (- 3,540' TVDSS). Union indicates a variance will be requested to allow more than 200' MD between the packer and perforations. The variance, if approved, will allow a second packer above the gas storage zone to ensure long -term isolation of the Sterling 58 -4 and 59 -6 Sands, in addition to the squeeze cementing that will be performed on those intervals. If this packer is not run, pressure cycling during future MITs may break down the squeeze perforations, creating a mechanical condition that would not allow use of the well until a workover could be performed. Considering the challenging logistics of its location, IRU 44 -36 could be unavailable for several months until a workover could be performed. 3 Plot provided by Union in support of the Application for Injection Order for Gas Storage, Ivan River Gas Storage Facility, received by the Commission March 30, 2011. • • Storage Injection Order 11 June 20, 2011 Page 6 of 10 9. Fluid Type and Source: Proposed injection fluid is dry natural gas, which is predominantly methane. The Ivan River Storage Facility is intended for injection of Union's excess gas. The estimated maximum daily injected gas volume is 20 million cubic feet per day (MMCFD). 10. Fluid Compatibility: Since all expected sources of storage gas are predominantly methane and are very similar in composition to the original gas in the reservoir, no fluid compatibility problems are expected. 11. Injection Rates and Pressures, Fracture Information: Original reservoir pressure for the Beluga 71 -3 Sand in IRU 44 -36 is estimated at 2,894 psi based on the pressure gradient in offset west side wells. Proposed maximum gas injection pressure is 3,050 psig, equivalent to an average reservoir pressure of 3,183 psia or about 10% greater than original reservoir pressure. Wellhead injection pressure will be maintained so that 0.60 psi /ft pressure gradient at the target midpoint of perforations (- 5,250' TVDSS in the Beluga 71 -3 Sand) is not exceeded. This corresponds to wellhead pressures of approximately 2,800 psig with the well shut in. Injecting gas to original reservoir pressure for gas storage will not initiate fractures in confining strata. Maximum injection pressure for IRU 44 -36 in the Beluga 71 -3 Sand will not exceed 0.60 psi /ft pressure gradient at the sand face. Leak off tests conducted while drilling IRU 44 -36 show the fracture gradient at - 867' TVDSS and - 2,900' TVDSS to be 1.35 psi /ft and 1.014 psi /ft, respectively. A formation integrity test (not taken to leak off) in IRU 11 -06 at - 4,880' TVDSS achieved 0.71 psi /ft pressure gradient. 12. Underground Sources of Drinking Water: Proposed gas injection will be at depths of approximately 6,836' to 6,852' MD (- 5,243' to - 5,254' TVDSS). An aquifer exemption is found at Aquifer Exemption Order No. 14. 13. Mechanical Condition of Pool Wells: The proposed IRU gas storage area encompasses six wells besides IRU 44 -36: IRU 14 -31, IRU 13 -31, IRU 11 -06, IRU 41 -01, IRU 44 -01, and IRU 23 -12. These wells are cased and cemented so there are no conduits for injected gas to escape the injection zone. No corrective action is required. 14. Monitoring: Well IRU 44 -36 will be tested for mechanical integrity per 20 AAC 25.412(c). To confirm continued mechanical integrity, Union will monitor daily injection rates and pressure and notify the Commission 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. II • • Storage Injection Order 11 June 20, 2011 Page 7of10 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 subsequent injection and production cycles. 15. Public Comment: The Commission received no protest nor written comments in response to the public notice. CONCLUSIONS: 1. This proposed Ivan River Unit 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 IRU Undefined Gas Pool. 3. Construction records, casing and cementing records, a cement bond log and a witnessed mechanical integrity test on April 29, 2005 demonstrate the mechanical integrity of IRU 44 -36 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 the permeable Beluga 71 -3 Sand, which can reasonably be expected to accept injected fluids at pressures less than the fracture pressure of the confining strata. 5. The Beluga 71 -3 Sand is overlain and underlain by laterally extensive intervals of siltstone, mudstone and coal that provide the primary seals to confine injected fluids in the approved interval and arrest any fractures caused by injection operations. 6. The proposed injection of natural gas into IRU 44 -36 for the purpose of storage will not propagate fractures through the confining zones. 7. Surveillance of operating parameters for storage and offset wells will provide continued assurance that stored gas remains confined to the Beluga 71 -3 Sand of the IRU Undefined Gas Pool. 8. Limiting the reservoir pressure to the original 2,894 psi for natural gas storage in the IRU Undefined Gas Pool eliminates the need for additional pressure monitoring beyond commitments made by Union. 9. The proposed injection of natural gas into the IRU Undefined Gas Pool for the purpose of storage will not cause waste, jeopardize correlative rights, endanger freshwater, or impair ultimate recovery. NOW THEREFORE IT IS ORDERED that the following rules, in addition to statewide requirements under 20 AAC 25, apply to the underground storage of • • Storage Injection Order 11 June 20, 2011 Page 8of10 hydrocarbons by injection operations in the Beluga 71 -3 Sand within the Undefined Gas Pool into well IRU 44 -36. The area described as follows is affected by this order: T13N, R8W, S6: NW %, NW 1/4 SW 1 /, Seward Meridian (SM); T13N, R9W, S 1: E ' /2, SM; T14N, R8W, S31: S 1 /2 SW 'A, NW 'A SW '' , SW 1/ NW %, SM; and T14N, R9W, S36: SE 1/ and SEI /4 NE 1 /, SM. RULE 1: STORAGE INJECTION The Commission approves injection for storage of natural gas in well IRU 44 -36 within in the Beluga 71 -3 Sand of the Undefined Gas Pool between 6,829' and 6,856' MD. RULE 2: DEMONSTRATION OF MECHANICAL INTEGRITY The mechanical integrity of well IRU 44 -36 must be demonstrated before injection begins, and before returning the well to service following a workover affecting mechanical integrity. A Commission - witnessed mechanical integrity test must be performed after injection is commenced for the first time in the well, to be scheduled when injection conditions (temperature, pressure, rate, etc.) have stabilized. 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 operator shall immediate) for Commission approval. The op immediately shut in the well if continued operation would be unsafe or would threaten contamination of freshwater, or if so directed by the Commission. RULE 4: MAXIMUM RESERVOIR PRESSURE • • Storage Injection Order 11 June 20, 2011 Page 9of10 The maximum reservoir pressure for this project shall be limited to 2,894 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. Unless otherwise modified by order of the Commission, compliance with all applicable Commission regulations and statutes is required. 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. 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 geosciences principles, and will not result in fluid movement outside of the authorized injection zone. • • Storage Injection Order 11 June 20, 2011 Page 10 of 10 DONE at Anchorage, Alaska and dated Ju - 20, 21 ti S 0, az. V .' is rr orman, ..s . .: - er 2 Alask 0 and Gas Conservation Commission Ars Iv ' Cathy P Foerster, Commissioner -- ---- Alaska Oil and Gas Conservation Commission RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Cormnission 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 Cormnission 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. • • Fisher, Samantha J (DOA) From: Fisher, Samantha J (DOA) Sent: Monday, June 20, 2011 4:56 PM To: 'Aaron Gluzman'; 'Ben Greene'; Bruno, Jeff J (PCO); 'CA Underwood'; 'Dale Hoffman'; 'David Lenig'; 'Donna Vukich'; 'Elizabeth Bluemink'; 'Eric Lidji'; 'Gary Orr'; Heusser, Heather A (DNR); 'Jason Bergerson'; 'Joe Longo'; King, Kathleen J (DNR); 'Lars Coates'; 'Lois Epstein'; 'Marc Kuck'; 'Marie Steele'; 'Mary Aschoff; 'Matt Gill'; 'Maurizio Grandi'; Ostrovsky, Larry Z (DNR); 'Patricia Bettis'; 'Richard Garrard'; 'Ryan Daniel'; 'Sandra Lemke'; 'Talib Syed'; 'Wayne Wooster'; 'Wendy Wollf; 'William Van Dyke'; '( michael .j.nelson @conocophillips.com)'; '(Von.L .Hutchins @conocophillips.com)'; 'AKDCWeIIIntegrityCoordinator; 'Alan Dennis'; 'alaska @petrocalc.com; 'Anna Raff; 'Barbara F Fullmer; 'bbritch'; 'Becky Bohrer; 'Bill Penrose; 'Bill Walker'; 'Bowen Roberts'; 'Brady, Jerry L'; 'Brandon Gagnon'; 'Brandow, Cande (ASRC Energy Services)'; 'Brian Havelock'; 'Bruce Webb'; 'Chris Gay'; 'Cliff Posey'; 'Crandall, Krissell'; 'D Lawrence'; 'dapa'; 'Daryl J. Kleppin'; 'Dave Matthews'; 'David Boelens'; 'David House'; 'David Scott'; 'David Steingreaber; 'ddonkel @cfl.rr.com; 'Dennis Steffy'; 'Elowe, Kristin'; 'Erika Denman'; 'eyancy'; 'Francis S. Sommer'; 'Fred Steece'; 'Garland Robinson'; 'Gary Laugh lin'; 'Gary Schultz (gary.schultz @alaska.gov)'; 'ghammons'; 'Gordon Pospisil'; 'Gorney, David L.'; 'Greg Duggin'; 'Gregg Nady'; 'gspfoff; 'Harry Engel'; 'Jdarlington (jarlington @gmail.com)'; 'Jeanne McPherren'; 'Jeff Jones'; 'Jeffery B. Jones (jeff.jones @alaska.gov)'; 'Jerry McCutcheon'; 'Jill Womack'; 'Jim White'; 'Jim Winegarner; 'Joe Nicks'; 'John Garing'; 'John Katz (john.katz @alaska.gov); 'John S. Haworth'; 'John Spain'; 'John Tower'; 'Jon Goltz; 'Judy Stanek'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; 'Kelly Sperback'; 'Kim Cunningham'; 'Larry Ostrovsky'; 'Laura Silliphant (Iaura.gregersen @ alaska.gov)'; 'Marilyn Crockett'; 'Mark Dalton'; 'Mark Hanley (mark.hanley @anadarko.com); 'Mark Kovac'; 'Mark P. Worcester'; 'Marguerite kremer (meg.kremer @alaska.gov)'; 'Michael Dammeyer; 'Michael Jacobs'; 'Mike Bill'; 'Mike Mason'; 'Mike) Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'nelson'; 'Nick W. Glover; 'NSK Problem Well Supv'; 'Patty Alfaro'; 'Paul Decker (paul.decker @alaska.gov)'; 'Paul Figel'; 'PORHOLA, STAN T'; 'Randall Kanady'; 'Randy L. Skillern'; 'Rena Delbridge'; 'Renan Yanish'; 'rob.g.dragnich @exxonmobil.com; 'Robert Brelsford'; 'Robert Campbell'; 'Rudy Brueggeman'; 'Ryan Tunseth'; 'Scott Cranswick'; 'Scott Griffith'; 'Shannon Donnelly'; 'Sharmaine Copeland'; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); 'Sondra Stewman'; 'Steve Lambert'; 'Steve Moothart (steve.moothart@alaska.gov)'; 'Steven R. Rossberg'; 'Suzanne Gibson'; 'tablerk'; 'Tamera Sheffield'; Taylor, Cammy 0 (DNR); 'Temple Davidson'; 'Teresa Imm'; 'Terrie Hubble'; 'Thor Cutler; 'Tina Grovier'; 'Todd Durkee'; 'Tony Hopfinger; 'trmjrl'; 'Vicki Irwin'; 'Walter Featherly'; 'Will Chinn'; Williamson, Mary J (DNR); 'Yereth Rosen'; Aubert, Winton G (DOA) (winton.aubert@alaska.gov); Ballantine, Tab A (LAW); Brooks, Phoebe L (DOA) (phoebe. brooks @alaska.gov); Colombie, Jody J (DOA) (jody.colombie @alaska.gov); Crisp, John H (DOA) (john.crisp @alaska.gov); Davies, Stephen F (DOA) (steve.davies @alaska.gov); Foerster, Catherine P (DOA) (cathy.foerster @ alaska.gov); Grimaldi, Louis R (DOA) (Iou.grimaldi @alaska.gov); Herrera, Matt F (DOA); Johnson, Elaine M (DOA) (elaine.johnson @ alaska.gov); Jones, Jeffery B (DOA) (jeff.jones @alaska.gov); Laasch, Linda K (DOA) (linda.laasch @alaska.gov); Maunder, Thomas E (DOA) (tom. maunder @alaska.gov); McIver, Bren (DOA) (bren.mciver @alaska.gov); McMains, Stephen E (DOA) (steve.mcmains @alaska.gov); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA) (bob.noble @alaska.gov); Norman, John K (DOA) (john.norman @alaska.gov); Okland, Howard D (DOA) (howard.okland @alaska.gov); Paladijczuk, Tracie L (DOA) ( tracie.paladijczuk @alaska.gov); Pasqual, Maria (DOA) (maria.pasqual @alaska.gov); Regg, James B (DOA) (jim.regg @alaska.gov); Roby, David S (DOA) (dave.roby @alaska.gov); Saltmarsh, Arthur C (DOA) (art.saltmarsh @alaska.gov); Scheve, Charles M (DOA) (chuck.scheve @alaska.gov); Schwartz, Guy L (DOA) (guy.schwartz @alaska.gov); Seamount, Dan T (DOA) (dan.seamount @alaska.gov) Subject: aeo014 Ivan River Attachments: aeo014. pdf 1 1 • Mary Jones David McCaleb XTO Energy, Inc. IHS Energy Group George Vaught, Jr. Cartography GEPS P.O. Box 13557 810 Houston Street, Ste 200 5333 Westheimer, Suite 100 Denver, CO 80201 -3557 Ft. Worth, TX 76102 -6298 Houston, TX 77056 Jerry Hodgden Richard Neahring Mark Wedman Hodgden Oil Company NRG Associates Halliburton President 408 18 Street 6900 Arctic Blvd. Golden, CO 80401 -2433 P.O. Box 1655 Anchorage, AK 99502 Colorado Springs, CO 80901 Bernie Karl CIRI Baker Oil Tools K &K Recycling Inc. Land Department 795 E. 94 Ct. P.O. Box 58055 P.O. Box 93330 Anchorage, AK 99515 -4295 Fairbanks, AK 99711 Anchorage, AK 99503 North Slope Borough Richard Wagner Gordon Severson Planning Department P.O. Box 60868 3201 Westmar Circle P.O. Box 69 Fairbanks, AK 99706 Anchorage, AK 99508 -4336 Barrow, AK 99723 Jack Hakkila Darwin Waldsmith James Gibbs P.O. Box 190083 P.O. Box 39309 P.O. 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 P.O. Box 2139 Soldotna, AK 99669 -7714 Fairbanks, AK 99701 Soldotna, AK 99669 -2139 ■ i Page 1 of 1 • Maunder, Thomas E (DOA) From: PORHOLA, STAN T [stan.porhola @chevron.com] Sent: Thursday, August 04, 2011 3:13 PM To: Regg, James B (DOA); Maunder, Thomas E (DOA); Aubert, Winton G (DOA) Cc: Walsh, Chantal [Petrotechnical Resources of Alaska (PRA)]; Eastham, Kevin (KEastham); Greenstein, Larry P; Ross, Gary D; Castillo, Flaco; Powell, Dennis A Subject: Notice to Commence Initial Gas Storage Injection - IRU 44 -36 (PTD 193 -022), SIO 11 Jim, Tom, and Winton, This is a notification that Union Oil Company of California plans to start Gas Storage Injection in well IRU 44 -36 (PTD 193 -022) under Storage Injection Order No. 11 around August 15th We will be in contact to coordinate the witnessed MIT after stabilized conditions have been established. Stan Porhola • • Drilling Engineer MidContinent/Alaska Business Unit Chevron North America Exploration and Production 3800 Centerpoint Dr. Suite 100 Anchorage, AK 99503 Tel 907 263 7640 Fax 907 263 7884 Cell 907 229 1769 stan.porhola @chevron.com Mail Confidential Footer Privileged /Confidential information may be contained in, or attached to, this message. If you are not the addressee indicated in this message (or responsible for delivery of the message to such person), you may not copy, forward, disclose, deliver, or otherwise use this message or any part of it in any form whatsoever. If you receive the message in error, you should destroy thi s message after notifying me immediately by replying to the message or contacting me at (907) 263 -7640. 8/4/2011 C) 1 ALASKA OIL AND GAS CONSERVATION COMMISSION 2 Before Commissioners: Daniel T. Seamount, Chairman John K. Norman 3 Cathy Foerster 4 Union Oil of California (UNOCAL) ) 5 by Application dated April 14, 2011) Requests an Order Authorizing ) 6 Underground Natural Gas Storage in ) the Undefined Gas Pool of the Ivan ) 7 River Unit Well IRU 44 -36 in ) Conformance with 20 AAC 25.252 and ) 8 20 AAC 25.412, and an Aquifer ) Exemption Order for the Ivan River ) 9 Unit, in conformance with ) 20 AAC 25.440 ) 10 ) 11 ALASKA OIL and GAS CONSERVATION COMMISSION Anchorage, Alaska 12 May 26, 2011 13 1:00 o'clock p.m. 14 VOLUME I PUBLIC HEARING 15 BEFORE: John K. Norman, Acting Chairman 16 Cathy Foerster, Commissioner 17 18 19 20 21 22 23 24 25 R & R COURT R E PORTER S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 1 TABLE OF CONTENTS 2 Opening remarks by Acting Chairman John K. Norman 03 3 Testimony by Chantell R. Walsh 06 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 R & R COURT REPORTERS 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 . . 1 P R O C E E D I N G S 2 (On record - 1:00 p.m.) 3 ACTING CHAIRMAN NORMAN: We'll go on the record. I'll 4 call this hearing to order. My name is John Norman. I'm a 5 Commissioner of the Alaska Oil & Gas Conservation Commission. 6 To my left to your right is Commissioner Cathy Foerster, the 7 Commission's engineering Commissioner. A quorum being present 8 well proceed with the hearing. 9 This matter comes before the Commission upon the 10 application of Union Oil Company of California for an order 11 authorizing the underground storage of natural gas in the 12 Undefined Gas Pool of the Ivan River Unit and specifically 13 identifying at the injection well Ivan River Unit 44 - 36. This 14 request is made in conformance with 20 Alaska Administrative 15 Code 25.252 and also 20 Alaska Administrative Code 25.412. 16 Additionally, there is a request for an aquifer exemption order 17 for the Ivan River Unit in conformance with Section 25.440 of 18 the Alaska Administrative Code. 19 Before we begin if there's anyone present who may need 20 special assistance to participate in the hearing you can see 21 the Commission's assistant in the back of the room, Jody 22 Colombie, and well provide whatever accommodation may be 23 needed to allow you to participate in these proceedings. 24 This hearing is being recorded by R & R Court Reporting 25 and following the hearing you may obtain a copy 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 3 i 1 transcript by contacting either R & R Court Reporting or seeing 2 the Commission's Special Assistant Ms. Colombie, and she'll 3 facilitate your getting a copy. 4 I'd like to remind all of you who are speaking, you see 5 two speakers in front of you, and one of them is for voice 6 amplification so everyone can hear, the other is for the 7 purpose of enabling the court reporter to obtain a clear 8 transcript. Consequently, be sure to speak as directly as you 9 can into both of the microphones in front of you. 10 Notice of this hearing was duly published on April 20th, 11 2011, as well as being posted on the State of Alaska Online 12 Notices site and on the AOGCC's website. 13 The affected area for the aquifer exemption order and the 14 gas storage area is within Township 13 north, Range 8 west, 15 Section 6 Seward Meridian, and Township 13 north, 9 west, 16 Section 1 Seward Meridian, Township 14 north, 8 west, Section 17 31 Seward Meridian, and Township 14 north, range 9 west, 18 Section 36, again, all being within the Seward Meridian, and 19 all being within the Matanuska - Susitna Borough. 20 The hearing today is being held in accordance with 20 AAC 21 25.540 of the Alaska Administrative Code. And we see we have 22 one person presently signed up to testify. The Commission will 23 allow testimony from other persons if there are others present 24 who upon conclusion of testimony from the applicant wish to 25 testify. R & R COURT REPORTERS 811 G STREET (907)277-0572/Fax 274 -8982 ANCHORAGE, ALASKA 99501 4 1 We will swear witnesses. And if you intend to be 2 recognized as an expert witness then we will ask you to state 3 your credentials, your background, your experience so that we 4 can gauge this. And then the statement I always make because 5 many of you appear before the Commission frequently so 6 requiring you doing this, each hearing stands, the record 7 stands along, and someone in the future may be reading this and 8 so we have to treat this as fresh hearing, and as if you are 9 appearing the first time before the Commission for the purposes 10 of keeping the record clear. 11 Commissioner Foerster, do you have any opening comments? 12 COMMISSIONER FOERSTER: I noticed that there were more 13 people here than on the sign -up sheet and I was just going to 14 ask Ms. Colombie if she'd get this and make sure that 15 people that hadn't signed up get signed up. Thank you. 16 ACTING CHAIRMAN NORMAN: Anything else? 17 COMMISSIONER FOERSTER: Ms. Colombie, there's another 18 person here 19 (Off record comments) 20 ACTING CHAIRMAN NORMAN: Anything else, Commissioner 21 Foerster? 22 COMMISSIONER FOERSTER: Nothing else at this time. 23 ACTING CHAIRMAN NORMAN: Very well. So the representative 24 for the applicant is here. And I'll ask you first to raise 25 your right hand and be sworn. 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 (Oath administered) 2 MS. WALSH: Yes, I do. 3 ACTING CHAIRMAN NORMAN: Very well. 4 MS. WALSH: Can you hear me? I'm sorry, should I check 5 this? Can you hear me? Yes. 6 ACTING CHAIRMAN NORMAN: Okay. 7 COURT REPORTER: Now. 8 MS. WALSH: Can you hear me now? 9 COURT REPORTER Off record. 10 (Off record) 11 (On record) 12 ACTING CHAIRMAN NORMAN: All right. Were back on the 13 record. The time is 1:15 p.m. And the date is Thursday May 14 26th, 2011. The location is at the Commission's offices of 333 15 West 7th Avenue, Anchorage, Alaska. And we have just sworn the 16 representative of the applicant. And now I will ask you to 17 please state your full name and your position and if you wish 18 to be qualified as an expert witness well accept your 19 qualifications after some -- after hearing what you have to say 20 and then you can proceed with the substance of your testimony. 21 CHANTELL R. WALSH 22 called as a witness on behalf of UNOCAL, testified as follows 23 on: 24 DIRECT EXAMINATION 25 MS. WALSH: My name is Chantell Renee Tun- -- Walsh. It's 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 1 been a few years. I'm a petroleum engineer. I have 2 approximately 25 years of oil and gas experience here in Alaska 3 and I'm registered as a professional engineer with the State of 4 Alaska. 5 ACTING CHAIRMAN NORMAN: Are all of you able to hear? 6 Okay. Fine. And the experience is 25 years. And it's all 7 here in the state of Alaska? 8 MS. WALSH: All here in the state of Alaska. 9 ACTING CHAIRMAN NORMAN: And in what area of the state of 10 Alaska? 11 MS. WALSH: The North Slope and the Cook Inlet area. 12 ACTING CHAIRMAN NORMAN: Okay. And what did that 13 experience consist of? 14 MS. WALSH: I was in -- on the North Slope I did both 15 reservoir engineering work, commercial work, and production 16 engineering work. And for the Cook Inlet I've worked in the 17 workover and drilling groups and the reservoir production 18 engineering groups for UNOCAL now Chevron. 19 ACTING CHAIRMAN NORMAN: Very well. Commissioner 20 Foerster? 21 COMMISSIONER FOERSTER: I'm very familiar with Ms. Walsh's 22 qualifications. In fact, I've even terrorized her children, 23 but that doesn't need to go on record. 24 ACTING CHAIRMAN NORMAN: Very well. Ms. Walsh, without 25 opposition the Commission accepts you as a qualified expert R & R COURT REPORTER S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 7 • 1 witness to testify before the Commission on the area of your 2 expertise. Please proceed. 3 MS. WALSH: Thank you. I intend today to give a broad 4 overview for the storage injection order application and the 5 aquifer exemption application for the Ivan River Unit. I'd 6 also like to answer any questions the Commission may have for 7 me. 8 At any time during this presentation please interrupt me 9 to ask the questions. That's perfectly okay with me. We also 10 brought with us today a group of individuals from Chevron 11 who've been working this project. And at any time that a 12 question arises that they may be better qualified for I'd be 13 happy to bring them up here. 14 ACTING CHAIRMAN NORMAN: Thank you. Ms. Walsh, which 15 would you be so -- to keep our record clear, would you be 16 addressing the aquifer exemption order first or the storage 17 injection? 18 MS. WALSH: The storage order first. 19 ACTING CHAIRMAN NORMAN: All right. Please proceed. 20 MS. WALSH: Page number 2. The storage injection order 21 application was submitted to the AOGCC at the end of March of 22 this year. The fresh water aquifer exemption application was 23 submitted about mid - April. Both of these documents were placed 24 on public notice and it's my understanding no comments or 25 questions have arised during that period of time. R & R COURT REPORTERS 811 G STREET (907)277- 0572 /Fax 274-8982 ANCHORAGE, ALASKA 99501 8 1 Page 3. Today's presentation is split into two parts. I 2 intend to start with the storage injection order application 3 and finish the presentation with the aquifer exemption 4 application. 5 Page 4. The location of the Ivan River Unit is on the 6 west side of Cook Inlet. In this area. We currently have two 7 gas production wells and two active disposal wells. After the 8 work this summer we intend to have an additional gas producer 9 as well as the conversion of the Ivan River Unit 44 -36 well for 10 the purpose of gas storage. 11 Slide number 5. This is a structure map of the Ivan River 12 71 -3 Beluga Sand, the target for our gas storage interval. The 13 dark blue outline is the Ivan River Unit boundary. The dashed 14 pink lines represent the requested gas storage interval. And 15 the circular lines, the colored line here in the circle 16 represent the interpretation of highest known water and lowest 17 known gas identifying the Beluga 71 -3 storage area. 18 Slide number 6. Some key technical information from our 19 application. The gas storage formation is the Beluga 71 -3 sand 20 within the Ivan River Unit. The original gas in place for the 21 71 -3 sand is 3.9 Bcf. The cumulative primary recovery out of 22 this interval is 3.1 Bcf. Along with that gas production we 23 produced about 460 barrels of water. 24 For the purposes of this application we requested a 25 maximum reservoir pressure of 3,183 which is 110 percent 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 9 410 411 1 initial reservoir pressure giving us or translating into a 2 maximum shut -in wellhead pressure of about 2,800 at the 3 surface. 4 Its important at this point for me to point out that all 5 of the gas storage fields that Chevron operates, while were 6 operating them we step our way through filling our reservoirs. 7 We monitor after each iteration where we inject into the well a 8 given amount. And while we're asking to go over our original 9 pressure that reasonably is for us to meet expectation during 10 peak gas demands, but we by all means intend to systematically 11 go through the process. We intend to fill the reservoir a 12 certain amount and monitor the progress. We'll do it slowly 13 and, you know, keep the Commission apprised of what's going on 14 with our reservoir. 15 It's our intent to confirm the storage integrity certainly 16 before we fill it to original and very much so prior to 17 stepping up past the original pressure. 18 Through noto (ph) analysis we expect our injection rates 19 to be around 20 million a day at the peak. And we also expect 20 our peak production rate to be around 16 million a day. The 21 base volume we intend to add to the reservoir is about 1.4 B 22 and our working volume will be above that in 1.6 to 1.8 range. 23 Our current reservoir pressure is 615 psi. 24 ACTING CHAIR NORMAN: Ms. Walsh, if I could ask just a 25 clarifying question before we leave this slide. So currently R & R COURT REPORTERS 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 10 . • 1 we have about .8 Bcf in the reservoir and now going down to the 2 bottom of the slide, the base volume you intend to bring that 3 up to 1.5 by adding to what's there, and then you intend to 4 layer on that as working gas up to 1.8 Bcf. So the total that 5 you would envision storing is about 1.3 Bcf, is that -- is my 6 math right on that? I'm adding up 7 MS. WALSH: 3.1 you mean? 8 ACTING CHAIR NORMAN: 1 5 base volume and 1.8 9 COMMISSIONER FOERSTER: So that would be 3.3. 10 ACTING CHAIR NORMAN: 3.3, that's - - is that 11 COMMISSIONER FOERSTER: You said 1.3. 12 ACTING CHAIR NORMAN: Oh, I'm sorry, I misspoke. 3.3. 13 MS. WALSH: Yeah, 3.1 to 3.3 Bcf, yes. 14 ACTING CHAIR NORMAN: Good. Thank you. 15 MS. WALSH: Slide number 7. Critical to a successful gas 16 storage reservoir is the containment. The Beluga 71 - sand is 17 well defined and contained in the Ivan River Field. Above the 18 71 - sand we have a section of -- 15 foot section of 19 interbedded siltstones and clay -rich siltstones and mudstones. 20 Topped above that is the PC4 coal. It's about a 5 foot coal. 21 And what's key about this particular coal is it's laterally 22 extensive and easily seen in all the other wells in the Ivan 23 River Unit. 24 Above the PC4 coal there's a thick 50 foot section of 25 siltstones and mudstones creating yet another impermeable R & R COURT REPORTERS 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 11 • 1 barrier. 2 Below the 71 -3 sand we have a 21 foot section of 3 interbedded siltstones and mudstones. Below that another 20 4 feet of some laterally discontinuous sands interbedded with 5 clays and mudstones and thinner coals that run through that 20 6 foot section. And beneath that we have, again, PC5 and PC6 7 coal that are laterally extensive in the field and picked up in 8 all our other wells. 9 These three coal packages, the PC4, 5 and 6 give us 10 confidence in our correlations in defining our zone. 11 Slide number 8, here we have the open hole log from the 12 44 -36 well showing in the highlighted yellow section the Beluga 13 71 -3 sand. It has -- the depth of 5237 to 5257 TVD. And you 14 can see that we've got the 15 foot section above the sand of 15 interbedded siltstones with the PC4 marker -- PC4 coal right 16 above there giving us that seal, and then yet another seal with 17 the siltstones above that interval. And below the 71 -3, again, 18 the first 20 feet of that is interbedded siltstones and the 19 lower 20 feet is interbedded siltstone and discontinuous 20 sandstones with these thinner coals, and then we have the PC5 21 coal that runs along the base of that interval and is found in 22 all the other wells in the area as well as with the PC6 coal. 23 Slide number 9. Another key components for identifying 24 competency for a gas storage sand is derived from analyzing he 25 material balance. For the 44 dash -- I mean 44 -36 well, 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 12 • 1 initial production for the well depicted with these blue P over 2 Z dots was when the production was commingled with -- the 71 -3 3 Beluga sand was commingled with two Sterling sands. It was at 4 the point in time that we produced the 71 -3 sand by itself, the 5 red /orange triangles, that -- that we fell into a straight 6 falling matric (ph) depletion drive. This is a key depletion 7 that were looking for showing, you know, no indication of 8 aquifer or aquifer drive. 9 Slide number 10. The mechanical integrity of the 44 -36 10 well is important for us to understand. p e stand. The well was designed, 11 a standard design for the Cook Inlet wells. The 13 3 /8ths 12 surface casing was cemented to about 900 feet and the cement 13 went to surface. The intermediate casing was to about 3500 14 feet and also we cemented that to surface. Then the production 15 casing was run. This 7 inch production casing was competently 16 cemented with the top of the cement at 4400 feet. It's well 17 above the Beluga 71 -3 sand which is at about the 6800 foot 18 level. 19 For future monitoring of our mechanical integrity we 20 intend to run an annulus test on 44 -36 during the workover 21 shortly after we've set the packers. And we intend to monitor 22 daily the rates whether it's injection or production and the 23 pressures from the well. And report those -- that information 24 monthly to the AOGCC. And also monitor the material balance 25 plot of whether it's production or injection making sure that 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 13 410 111 1 we are running in line with where we think we should be. 2 ACTING CHAIR NORMAN: Ms. Walsh, what about monitoring the 3 total value in the reservoir, what's the plan for that? 4 MS. WALSH: We monitor that as well on a daily basis and 5 report it on a monthly basis. Yeah, we want -- monitor it 6 daily. 7 ACTING CHAIR NORMAN: And on that subject it is not your 8 intention to have this reservoir ever exceed the original gas 9 -- volume of the original gas in place? 10 MS. WALSH: No, in our application we asked for a 10 11 percent over the original -- the original pressure of the 12 reservoir. 13 ACTING CHAIR NORMAN: But volume? 14 MS. WALSH: Which would correspond to 15 ACTING CHAIR NORMAN: Which would correspond to volume, so 16 you're asking 17 MS. WALSH: volume. 18 ACTING CHAIR NORMAN: to exceed pressure and volume 19 by a factor of 10 percent, right? 20 MS. WALSH: Yes. 21 ACTING CHAIR NORMAN: Thank you. 22 MS. WALSH: I don't think it corresponds exactly to a 23 volume over 10 percent. 24 ACTING CHAIR NORMAN: Yeah. 25 MS. WALSH: Its the pressure that'll define that. R & R COURT REPORTERS 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 14 410 111 1 ACTING CHAIR NORMAN: I understand. 2 MS. WALSH: Okay. 3 COMMISSIONER FOERSTER: On that if you go back to slide 6, 4 if your original gas in place is 3.9 Bcf and your base volume 5 plus your working volume add up to 3.3 Bcf, then 6 MS. WALSH: It's about a .2 Bcf that is from the 110 7 percent. The 1.6 -- the 1.5 and the 1.6 would bring us back to 8 the 3.1 that we depleted out of the reservoir, right? 9 COMMISSIONER FOERSTER: Okay. 10 MS. WALSH: And then the additional 10 percent by bringing 11 the reservoir pressure up to 3183, that corresponds to another 12 .2 Bcf. 13 COMMISSIONER FOERSTER: So your base volume -- so it 14 doesn't add back up to your original gas in place? 15 MS. WALSH: We've -- well, we've pulled out of the 16 wellbore 3.1 Bcf. We intend to put in 1.5 17 COMMISSIONER FOERSTER: Okay. Gotcha. You're going to 18 put in 1.5 19 MS. WALSH: plus an additional 1.6. 20 COMMISSIONER FOERSTER: Gotcha. 21 MS. WALSH: And then the corresponding pressure 22 differential extrapolates back to about .2 Bcf. 23 COMMISSIONER FOERSTER: So you pulled out 3.1 Bcf so 24 there's 0.8 Bcf in there right now and you're going to add to 25 that 0.8 an additional 1.5, so your base volume is going to R & R COURT REPORTERS 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 15 4 11 0 1 1 1 1 be 2 MS. WALSH: The 1.5 plus the remaining 3 COMMISSIONER FOERSTER: plus the point 4 MS. WALSH: point 8. 5 COMMISSIONER FOERSTER: Plus the .8. 6 MS. WALSH: Yes. 7 COMMISSIONER FOERSTER: So -- okay. So slide number 6 8 needs to be omitted (ph), yes? 9 MS. WALSH: Yeah, I would agree because the base volume 10 really should be depicted. An error on my part. It should be 11 depicted as the 1.5 we intend to add plus the .8 that still 12 remains in the reservoir. 13 COMMISSIONER FOERSTER: All right. 'Cause I was confused 14 by that. 15 MS. WALSH: Yeah, that's correct. 16 COMMISSIONER FOERSTER: Okay. Okay. All right. Good 17 question. 18 MS. WALSH: All right. I'm going to move on to slide 19 number 11. These are wells within the area. There are five 20 wellbores that penetrate the 71 -3 sand within a quarter of a 21 mile of the proposed storage reservoir. The first two are 22 disposal wells. They have their six inch casing set such that 23 the 71 -3 sand is well cemented within that interval in both 24 Ivan River 14 -31 and 13 -31. 25 The Ivan River 11 -06 well is the most recent well that we R & R C O U R T R E PORTER S 811 G STREET (907)277-0572/Fax 274 -8982 ANCHORAGE, ALASKA -99501 16 1 put in the field. And we have good containment above and below 2 the intended storage sand. 3 COMMISSIONER FOERSTER: In that well where does the 4 injection interval correlate, what depth? 5 MS. WALSH: The injection, I think, Cathy, its around 70 6 -- Dan? 7 UNIDENTIFIED VOICE: What's that? 8 MS. WALSH: In the 11 -06 well where is the 9 COMMISSIONER FOERSTER: Injection interval? 10 MS. WALSH: 71 -3 sand? 11 UNIDENTIFIED VOICE: 6183. 12 COMMISSIONER FOERSTER: It's what? 13 UNIDENTIFIED VOICE: 6183. 14 MS. WALSH: 6183. 15 COMMISSIONER FOERSTER: So you've only got about 60 feet 16 of 17 MS. WALSH: Yeah. 18 COMMISSIONER FOERSTER: cement? 19 MS. WALSH: Yeah. 20 COMMISSIONER FOERSTER: Okay. 21 UNIDENTIFIED VOICE: It's at 4681 (inaudible). 22 MS. WALSH: Right, but these are all measured depths. 23 UNIDENTIFIED VOICE: For 1371 the 4681 (inaudible) 5300 i 24 foot so there's 700 feet.... 25 COMMISSIONER FOERSTER: So where's the measured depth of R & R COURT REPORT E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 17 411 (II 1 the injection interval in Ivan River Unit 11 -06, measured 2 depth? 3 UNIDENTIFIED VOICE: (Inaudible - away from microphone) 4 correct. 5 COMMISSIONER FOERSTER: Right. Right. 6 MS. WALSH: But the corresponding 7 COMMISSIONER FOERSTER: The injection interval, where do 8 you find that or what depth 9 MS. WALSH: (indiscernible - simultaneous speech) 10 COMMISSIONER FOERSTER: do you find that measured in 11 the injection -- in Ivan River Unit 11 -06, the injection 12 interval can be found at the depth of (makes noise) in Ivan 13 River Unit 11 -06? Fill in the (makes noise). 14 MS. WALSH: Cathy, there's a chart in our application. 15 I'm trying to find it. 16 ACTING CHAIR NORMAN: Is that attachment 3, is that what 17 you're referring to? 18 MS. WALSH: Okay. Cathy, it's actually in our application 19 on page 5 20 COMMISSIONER FOERSTER: Okay. 21 MS. WALSH: that it goes over where the 71 -3 sand is. 22 So corresponding 23 COMMISSIONER FOERSTER: Okay. Great. 24 MS. WALSH: to these measured depth intervals on the 25 11 -06 well the measured depth value of the sand top for the 71- 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 3 is at 6514. 2 COMMISSIONER FOERSTER: Okay. 3 MS. WALSH: And 4 COMMISSIONER FOERSTER: Thank you. 5 MS. WALSH: Okay. 6 COMMISSIONER FOERSTER: So about 400 feet? 7 MS. WALSH: So about 400 feet, yes. 8 COMMISSIONER FOERSTER: Thank you. 9 MS. WALSH: Okay. The Ivan River 41 -01 well is also 10 contained, the sand interval is contained with competent 11 cement. And then in 44 -01 it was actually -- the 9 5 /8ths was 12 the production casing and the cement job was done in two stages 13 in the interval where the 71 -3 sand is, was above the DV color 14 (ph) so it was an extremely competent cement job and we have 15 bond that shows that. 16 That sums up my presentation on the gas storage injection 17 order application. Are there any further questions? 18 COMMISSIONER FOERSTER: I just have one. When you were on 19 slide 6 and you were talking about asking for a 10 percent in 20 excess. You said you were going to fill the reservoir slowly. 21 Could you be more explicit on what slowly means? Is that far 22 as, you know, you're going to get to this pressure and stay at 23 that for a number of days or months, you're going to get -- 24 then you're going to increase, you know what I'm saying? 25 MS. WALSH: Yes, absolutely, Cathy. And we are, in fact, R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 19 410 411 1 going to not get to pressures that -- we do not have the 2 compression capability out at Ivan River for the first two 3 years to get the reservoir much past our base load. So 4 COMMISSIONER FOERSTER: And your base load was? 5 MS. WALSH: The 1.5 plus the existing .8. 6 COMMISSIONER FOERSTER: Okay. 7 MS. WALSH: So we will have a couple of years in that 8 interval area before we've even able to start moving 9 systematically up from there. 10 COMMISSIONER FOERSTER: Okay. So then -- so for two years 11 you're going to have 2.3 Bcf? And then 12 MS. WALSH: Hopefully. 13 COMMISSIONER FOERSTER: what does slowly mean after 14 that? 15 MS. WALSH: And then after that we would probably start 16 marching up towards the original reservoir pressure and produce 17 it through an entire cycle 18 COMMISSIONER FOERSTER: So there's 19 MS. WALSH: at the original 20 COMMISSIONER FOERSTER: not a plan yet? 21 MS. WALSH: There's not a plan. No, I 22 COMMISSIONER FOERSTER: Okay. 23 MS. WALSH: think, Cathy, that's fair to say. 24 There's not a plan 25 COMMISSIONER FOERSTER: Okay. R & R C O U R T R E P O R T E R S 811 G STREET (907)277-0572/Fax 274 -8982 ANCHORAGE, ALASKA 99501 20 1 MS. WALSH: but in the past we've approached it that 2 way where we've run the whole cycle at original prior to 3 marching anywhere beyond that. 4 COMMISSIONER FOERSTER: Okay. Thanks. 5 ACTING CHAIR NORMAN: Anything more, Commissioner 6 Foerster? 7 COMMISSIONER FOERSTER: Nope. 8 MS. WALSH: 9 ACTING CHAIR NORMAN: Okay. My question, Ms. Walsh, also 10 relates to the volume. And if we add the residual gas plus the 11 base volume plus the working volume were now at 4.1 Bcf, is 12 that what you're -- my rough? No. Help me out with that 13 because you have a base volume of 1.5 and you have a working 14 volume of possibly up to 1.8, is that -- that's correct, right? 15 COMMISSIONER FOERSTER: The base volume is really 2.3. 16 MS. WALSH: Yeah, the base volume, I wrote the base volume 17 as the actual amount were going to add. 18 ACTING CHAIR NORMAN: Well then, -- okay. 19 MS. WALSH: So it's .8 plus the 1.5. 20 ACTING CHAIR NORMAN: It's 2.3 21 MS. WALSH: Oh, it's 2.3 22 ACTING CHAIR NORMAN: yeah, that's I said. Okay. 23 Well then, add 1.5, .8 and 1.8, what do you get? 24 COMMISSIONER FOERSTER: 2.3 plus 1.6 and 1.8 is three -- 25 is 4.1. R & R C O U R T R E P O R T E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 21 1 1 ACTING CHAIR NORMAN: I said 4.1, so -- all right. So the 2 answer is 4.1 I think. 3 MS. WALSH: Yes, I'm sorry. You're right. It's 3.9 4 ACTING CHAIR NORMAN: Okay.. 5 COMMISSIONER FOERSTER: Its hard to add when you're 6 testifying. 7 ACTING CHAIR NORMAN: No -- no, yes. 8 MS. WALSH: I'm really an engineer. Really. Really. 9 ACTING CHAIR NORMAN: Sure. Okay. That's fine. I just 10 wanted to set the stage here. So 11 MS. WALSH: You're absolutely right. 12 ACTING CHAIR NORMAN: the Commission to my knowledge 13 has not authorized storage and injection in excess of what the 14 original volumes and pressures were for obvious reasons, 15 because I think there's a certain comfort level in knowing 16 you're putting back what that original reservoir would contain. 17 You're asking now as I understand it to -- for authorization to 18 exceed both the volume and then the pressure by 10 percent. 19 And my question is what can you tell the Commission that would 20 justify us doing what ordinarily I think prudence would dictate 21 not to do? 22 MS. WALSH: We both the Pretty Creek Storage Unit and the 23 64 -5 sand in the -- in the 64 -5 sand at Swanson are able to 24 inject over the original -- inject and store over the original 25 reservoir 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 22 1 ACTING CHAIR NORMAN: By Commission order? 2 MS. WALSH: By Commission order. 3 ACTING CHAIR NORMAN: We authorized that? 4 MS. WALSH: Absolutely. 5 ACTING CHAIR NORMAN: What was the percentage on those, do 6 you recall? 7 MS. WALSH: On Pretty Creek it's 20 percent over. And on 8 Swanson.... 9 UNIDENTIFIED VOICE: 10 percent. 10 MS. WALSH: 10 percent over. 11 ACTING CHAIR NORMAN: All right. 12 COMMISSIONER FOERSTER: It was earlier us that authorized 13 that. 14 ACTING CHAIR NORMAN: Well, sure. But I mean were the 15 Commission whoever was here so that's fine. Then that answers 16 that. I did not have that excess in mind. But again, let me 17 go back to kind of a basic common sense premise for the public 18 member of the Commission. Why would the Commission allow you 19 to put more into that reservoir than -- we have -- we have 20 demonstrated experience that that reservoir can contain 21 adequately a certain volume at a certain pressure. Why would 22 we exceed that based upon what's been provided to us? Can you 23 point to me what -- I mean I know you plan to fill it slowly, 24 et cetera, but you could also come back later on and ask for an 25 amendment based on what you experienced. Why would we start 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 23 1 out authorizing you to exceed original pressures and volumes by 2 some margin? 3 MS. WALSH: We do have -- I mean we have quite a bit of 4 data that shows us that the rock competencies far exceed the 5 kind of gradients that the original pressure would give us. So 6 we feel that -- I mean it's fairly safe to ask for this. It's 7 safe to ask for a 10 percent over. And we would certainly go 8 through filling a reservoir above original pressure with a lot 9 of prudence. 10 ACTING CHAIR NORMAN: And I would expect you would go 11 through it with prudence, but once -- what if -- is it an 12 option to authorize you to -- I want to give you the 13 opportunity to respond because eventually we'll come out with 14 an order so.... 15 MS. WALSH: Right. 16 ACTING CHAIR NORMAN: if the Commission -- let me ask 17 it this way. If the Commission were to come out with an order 18 and say yes, you may fill this reservoir to the original volume 19 at the original pressure, you always have the option to come 20 into the Commission later then with an application to amend 21 based on your experience. And it would just 22 MS. WALSH: Absolutely. 23 ACTING CHAIR NORMAN: strike me that that's the more 24 prudent course of action. 25 COMMISSIONER FOERSTER: I have another question when 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 24 410 411 1 you're done. 2 MS. WALSH: Yes, absolutely we would have the option to 3 come back and ask for raising the reservoir pressure. 4 ACTING CHAIR NORMAN: And you may not be able to ask, but 5 I mean that is a possibility, but that's the way the 6 Commission's order would come out, so if there -- it's critical 7 that you have this extra margin by way of volume and pressure 8 in the original order then I think we'd want in the record or 9 you to direct us in the record. You mentioned the competency 10 formations, et cetera. And your belief is that's all in the 11 record before us what's been provided? 12 MS. WALSH: Yes. 13 ACTING CHAIR NORMAN: You're not relying on something is 14 known to UNOCAL that we don't know? 15 MS. WALSH: No. 16 ACTING CHAIR NORMAN: Okay. 17 COMMISSIONER FOERSTER: I have one more question. 18 ACTING CHAIR NORMAN: Please. 19 COMMISSIONER FOERSTER: Well, how'd you come up with the 20 total volume that you intend to inject? Is that based on 21 anticipation of production overage 22 MS. WALSH: Yeah, it's both 23 COMMISSIONER FOERSTER: during summer months or is it 24 just picking 10 percent and.... 25 MS. WALSH: The 10 percent pressure, when you -- you 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 25 1 extrapolate it back up the P over Z plot is where you end up 2 getting the extra .2 Bcf. And even the extrapolation for the 3 original gas in place for this reservoir is an extrapolation 4 because at the time that the reservoir was opened it was 5 commingled with two other sands, so 6 COMMISSIONER FOERSTER: Okay. 7 MS. WALSH: both of those points are extrapolations. 8 COMMISSIONER FOERSTER: So the 4.1 Bcf wasn't a business 9 decision based on the -- to justify a compulsory (ph) we have 10 to do this or we're going to have this much gas that we have to 11 deal with, it was simply a 10 percent over original? 12 MS. WALSH: Correct. 13 COMMISSIONER FOERSTER: Okay. 14 MS. WALSH: It also gives us the capability when we 15 operate our reservoirs to go right up to the original pressure. 16 'Cause if we limit it to the original pressure we're offering -- 17 we're offering monitoring so much at the tail end that we 18 never actually get to the original pressure. 19 COMMISSIONER FOERSTER: You put a safety factor in? 20 MS. WALSH: Yes. Yeah. 21 COMMISSIONER FOERSTER: Okay. 22 ACTING CHAIR NORMAN: Very well. We -- I think that 23 concludes then, Ms. Walsh, your testimony in support of the 24 storage injection order. And I think you've done a good job 25 with laying it out for us. And, Commissioner Foerster, I'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 26 1 assuming you have no more questions on the storage injection 2 order? 3 COMMISSIONER FOERSTER: Not at this time. But I'd like to 4 suggest that we go ahead and let Ms. Walsh do the aquifer 5 exemption 6 ACTING CHAIR NORMAN: Yes. 7 COMMISSIONER FOERSTER: and then take a short recess 8 to address questions that the staff may have on both 9 ACTING CHAIR NORMAN: Yes. 10 COMMISSIONER FOERSTER: rather than break it up into 11 two pieces. 12 ACTING CHAIR NORMAN: An excellent suggestion. 13 So Ms. Walsh, you can no proceed to address the aquifer 14 exemption order. 15 COMMISSIONER FOERSTER: And if we might have anymore 16 addition questions would you like me to go get my calculator? 17 MS. WALSH: No, I'm going to make somebody else come up 18 here and do the math 19 COMMISSIONER FOERSTER: Okay. 20 MS. WALSH: for me. Okay. Moving along to the 21 Freshwater Aquifer Exemption Application for the Ivan River Gas 22 -- or the Ivan River Field. 23 Slide number 13. This is, again, the structure map that 24 we showed earlier of the 71 -3 sand with, again, the blue line 25 outlining the Ivan River Unit boundary and the pink dashed line 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 27 411 410 1 identifying the proposed boundary of the now aquifer exempt- -- 2 yeah, the aquifer exemption. 3 Slide number 14. This, too, is a repeat of an earlier 4 slide showing the open hole log information from the 44 -36 5 well. Whereas the 71 -3 sand is contained here in the 6 highlighted yellow, the purposes -- for the purposes of the 7 aquifer exemption the Beluga 71 -3 strata is defined as being 8 from the top of the pretty -- the PC4 coal to the top of the 9 PC5 coal, both of these being laterally continuous and good 10 identifiers of a strata. 11 Oops. For the aquifer exemption application we believe 12 that we've met the criteria for 13 COMMISSIONER FOERSTER: Slide 15. 14 MS. WALSH: Slide 15. Thank you, Cathy. For the state 15 regulations for granting an aquifer exemption. The Beluga 71 -3 16 strata does not currently serve nor intend to serve in the 17 future as a source of drinking water. The Beluga 71 -3 18 formation is hydrocarbon bearing. The remoteness of both the 19 Ivan River Unit and the depth of the 71 -3 strata makes 20 recovering water impractical economically. The total dissolved 21 solid contents of the ground water is more than 3000 and less 22 than 10000 parts per gal- -- per million. And it's not 23 reasonable to expect -- accept this as public water sources. 24 And there are numerous shallow freshwater sands that are better 25 for drinking water purposes. 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 28 410 1111M 1 Slide number 16. There are three water wells in the 2 immediate vicinity of Ivan River. Two of them actually on the 3 Ivan River Pad and one at Stump Lake, a pad right next to the 4 Ivan River Unit. These wells are available and show that there 5 are relatively shallow horizons in the water that are 6 freshwater sources. You can see these wells, the deepest of 7 which is 318 feet. 8 Slide number 17 is a -- it's from our application and is 9 exhibit number 6. It shows nine water samples that were taken 10 from the Ivan River Field in the Tyonek and Sterling intervals 11 that surround the proposed storage strata. And they show that 12 our water salinities range from 4300 to 10700 parts per 13 million. 14 Further to describe and understand the water salinities 15 for the sand interval we did two petrophysical analyses. The 16 first we did here 17 COMMISSIONER FOERSTER: On slide 18. 18 MS. WALSH: Thank you, Cathy. Slide 18. The first we 19 used a Pickett Plot where an Rw was identified from the Pickett 20 Plot and a salinity was backed out. And you can see on this 21 actual slide the Beluga 71 -3 is the last sand and identifies a 22 salinity of 9300 parts per million. 23 Slide number 19. This petrophysical analysis was a 24 methodology that computed the apparent Rws using Archie's (ph) 25 equation. Then the open hole logs were tied with the apparent 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 29 1 Rw and a water salinity curve was generated. 2 You can see -- you can't really see, but in the green 3 across the interval which is the 71 -3 sand, we have water 4 salinities that range from eight to 10000 parts per million. 5 This area right across here. 6 With those two approaches and with the water samples that 7 we have we feel like we really have identified the water 8 salinity to be in the range. 9 Slide number 20. So in summary, the freshwater aquifer 10 exemption request meets the criteria for granting of an aquifer 11 exemption. The granting this request will not endanger current 12 or future public drinking water sources. 13 The requested area and strata meet the following 14 regulatory criteria, the first of which is -- it is not a 15 drinking water source. The second, the strata is hydrocarbon 16 bearing. The strata is also at a depth and location making it 17 uneconomic to develop for drinking water. And the high 18 salinity of the strata is not reasonable as a public water 19 source. 20 Slide number 21. The data and evidence submitted in this 21 applications meets the criteria for the granting of the 22 freshwater aquifer exemption for the Beluga 71 -3 strata in the 23 proposed Ivan River Gas Storage Facility. 24 That concludes the aquifer exemption portion of my slides. 25 ACTING CHAIR NORMAN: Commissioner Foerster, questions? R & R COURT REPORT E R S 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 30 410 410 1 COMMISSIONER FOERSTER: I have no questions. 2 ACTING CHAIR NORMAN: Ms. Walsh, I have just one question. 3 If you have -- do you happen to have in front of you page 10, 4 not of the slides but of your original application? 5 MS. WALSH: For the aquifer exemption? 6 ACTING CHAIR NORMAN: Let's see, yeah, I'm looking on page 7 10, I think it was a consolidated, but take it a quick look 8 here and see what it's entitled right here. It's Section 0 on 9 page 10 that I'm looking at. 10 MS. WALSH: That is the application for the injection 11 order. 12 ACTING CHAIR NORMAN: For the injection order? 13 MS. WALSH: Yes. 14 ACTING CHAIR NORMAN: Okay. So -- but it does address 15 aquifer exemption, correct? 16 MS. WALSH: Yes. 17 ACTING CHAIR NORMAN: Okay. And in the addressing of 18 aquifer exemption it states that the Ivan River Unit is 19 exempted as per 147.102(b) of the Code of Federal Regulations. 20 Do you see that? 21 MS. WALSH: Yes. And it was after -- after we submitted 22 the application for our gas storage order we worked with Winton 23 and read back over those and our interpretation was different. 24 We interpreted it as being a quarter mile around the wellbore 25 and the intent of that regulation was a quarter of a mile R & R COURT REPORTERS 811 G STREET (907)277- 0572 /Fax 274 -8982 ANCHORAGE, ALASKA 99501 31 . • 1 around the Ivan storage sand which led us to need to apply for 2 an aquifer exemption for the 71 -3 strata. 3 ACTING CHAIR NORMAN: Okay. I appreciate that then. And 4 so your original application is amended and the slide that will 5 be in the record is what we should rely upon? 6 MS. WALSH: Yes. 7 ACTING CHAIR NORMAN: And then going a bit further here, 8 102(b) says the following aquifers are exempted in accordance 9 with such and such and it goes on to cite. And then it 10 references within the following fields, Swanson River, Beaver 11 Creek, Kenai, the portion of the aquifers beneath Cook Inlet 12 within a quarter mile lying directly below the following 13 fields, Granite Point, McArthur River, Middleground Shoal, 14 Trading Bay, but no where do I find -- how -- why would -- why 15 was that cited as creating an exemption for this particular 16 area? 17 MS. WALSH: It was cited in error. 18 ACTING CHAIR NORMAN: Okay. All right. And I accept 19 that. I know how that is. So this then is superseded by the 20 slide. That's what I wanted to clarify. 21 MS. WALSH: Yes, absolutely, it is. 22 ACTING CHAIR NORMAN: Very well. Thank you. Commissioner 23 Foerster, do you have anymore? 24 COMMISSIONER FOERSTER: I have nothing more (ph). 25 ACTING CHAIR NORMAN: What we would like to do then in 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 32 1 order to economize on everyone's time is the Commissioners will 2 take a 10 minute recess. We'll see if we have any final 3 questions, but the interim it will also be our intention to ask 4 -- perhaps we ought to do that right now. Are there any other 5 persons in the room -- in the hearing room that wish to address 6 the Commission with regard to this particular application? 7 All right. For the record the Chair sees no persons 8 asking to be recognized. So we will take a 10 minute recess 9 and come back on the record at 2:10 p.m. 10 (Off record) 11 (On record) 12 ACTING CHAIR NORMAN: All right. We'll go back on the 13 record. Ms. Walsh, we want to thank you for a good 14 presentation, you and your company, and I think a lot of very 15 valuable information's been provided to us. I don't believe we 16 have questions, but I'm going to leave it open for Commissioner 17 Foerster to interrupt me if she has a question that she would 18 like to ask. 19 COMMISSIONER FOERSTER: Nope. 20 ACTING CHAIR NORMAN: Very well. Then we have all the 21 information we need. And I think we've by our dialogue given 22 you some ideas of questions we have also. The matter will now 23 be submitted. There are no third party protests that have been 24 received. The record will be closed effective when we adjourn 25 at this hearing. By law the matter is then submitted to 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 33 411 411 1 Commissioners and by law within 30 days, but in this instance I 2 think we will be able to make a more -- much more expeditious 3 decision on this matter than that. 4 So I am going to ask one last time, again for the record, 5 if there are any other persons who have any testimony they 6 would like to offer on either the storage injection order 7 application or the aquifer injection application? For the 8 record, again, the Chair sees no one asking to be recognized. 9 And then without objection we will adjourn. 10 (Recessed - 2:10 p.m.) 11 12 13 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 34 • 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 held on May 26th, 2011 was taken by Lynn Hall, commencing at the hour of 7 1:00 o'clock p.m, at the Alaska Oil and Gas Conservation Commission of Alaska in Anchorage, Alaska; 8 THAT this Public Hearing, as heretofore annexed, is a true 9 and correct transcription of the proceedings taken by Lynn Hall and transcribed by myself. 10 IN WITNESS WHEREOF, I have hereunto set my hand and 11 affixed my seal this 2nd day of June 2011 12 13 Notary Public in and for Alaska My Commission Expires:10 /18/14 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 • STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION SIO 11 -01 Ivan River Unit Storage Injection Application May 26, 2011 at 1:OOpm NAME AFFILIATION PHONE # TESTIFY (Yes or No) 411 A b \ C ,e eek,st.61. _1/A SCI 7 6 / C' AJ .t Al (5 4 z-717 Cr L v)c 2 ))"Gv /tir . i IN1f15 Ivi.) cvx r) K -- V 1A1 EA5 4 (,V 2 - 6 3 - N 1/1/(Adv� 0/0o /4' 'DN.) ODD 4-U —R &41- ff17 /Uo c,s�' ` J ► �lacl� G VX z0-71.7z rte r � <5 i+ Porlo CO( 2603 7 )J o 11.,1. cZCnv„.A C A-o Nra iv X 79- /c7/53 AC, 61,11(c) 55 v,l' Chevron Ivan River - Gas Storage Facility S - Storage Injection Order Application - Aquifer Exemption Application Alaska Oil and Gas Conservation Commission • May 26, 2011 © Chevron 2005 Ivan River - Gas Storage Facility: Chevron Storage Injection Order (SIO) Application: • Submitted to AOGCC on March 30, 2011 Freshwater Aquifer Exemption (AE) Application: • Submitted to AOGCC on April 14, 2011 © Chevron 2005 2 Ivan River - Gas Storage Facility: Chevron ■/ ] Storage Injection Order (SIO) Application © Chevron 2005 3 1 Ivan River Unit - Location Map `/ Regional Cook Inlet Location Map tifiCrY OM _... _ . i 1 1 0 i li. , , Ivan River Unit roa eat A Nan . COOK KV .......... ,- s .o * waaataauas SOW „ NW ` _ i .. i.. . s AN rx...€i OP t 'Alum* ATTACHMENT 1 Application for Injection Order for Gas Storage Ivan River Unit 4 © Chevron 2005 I )) sV III! :ir,a1i1 :if :tti, +rr:i111 ,Ir < •. : tti:r .it tirn r..'I III 7tt&Iii11 a'Iftlitt ,aIiir 1,111.1 N4. 4111 ;■41111 r: .11i1 1 in it -----f—,5500— }� 3j :*--- 77 7------- 7 - -.sti ,. to = , z I 40 11 1 111/ - N De r \ . 09 l 4 P •� ~-\, I l I I l H I K ' I- -41-1. : i . \ \ N N. i.„,,,,\ ■ ilia N a { N \ 'N.%.."-... ''''''') ... . I tit tit*n iui?'3r ITii *i'i' ItY71!'ir iilitIr rnI.!r hip +irytl+r IiiI.i sr Minn illittIV hili°t.e` .r+ r i M to v ratil 0 3 4 .9 m - V 0 N 06 9 CO L o cu H et (i) U 0 Ivan River - Gas Storage Facility: Chevron Storage Injection Order (SIO) Application: • Gas storage formation is the Beluga 71 -3 sand, within the Ivan River Unit • Beluga 71 -3 OGIP = 3.9 Bcf • Cumulative (and ultimate) primary recovery = 3.1 Bcf • Cumulative water produced = 460 BW • Application requests a maximum reservoir pressure of 3,183 psia • 110% of initial reservoir pressure (2,894 psia) • Max. SI WHP = 2,800 psig • Maximum expected injection rate = u20 MMcf /d • Maximum expected production rate = .i16 MMcf /d • Base Volume = 1.5 Bcf • Working Volume = 1.6 - 1.8 Bcf • Current reservoir pressure = 615 psi © Chevron 2005 6 Beluga 71 -3 Gas Storage - Containment Chevron IRO Above: • The Beluga 71 -3 sand is topped by a «15' section of interbedded siltstone, clay -rich siltstone and mudstone, which is then topped by a N5' (TVD) coal (PC4 Coal pick). • The PC4 Coal is laterally extensive and easily picked in other wells across the Unit. • Above the PC4 Coal there is a thick, approximately 50 foot section of siltstone and mudstone creating an impermeable barrier above. Below: • The Beluga 71 -3 sand is underlain by N20' (TVD) of interbedded siltstone and mudstone. • Below the first 20 feet there are some laterally discontinuous sands interbedded with clay rich siltstones, mudstones and laterally continuous 4 to 6 foot coals. • The PC5 and PC6 Coals are laterally extensive and easily picked in other wells across the Unit. © Chevron 2005 7 IRU 44 -36 Log Top Bel - . ` Chevron Beluga 71 -3 Sand ' `' ' ' L. orri r . , i: i <-4 ,, - ! i 1 Beluga 71 -3 Sand .-q, __- __ - -__ -- 6,829' - 6,856' MD ( -5237' to -5257' SSTVD) i 0 disi . ,,,,., uninjimmo 1 .,„ ..............„4, 1 . : : \;,..-- , , e ti , t - ` J Cod e1 . � I: - - - ,: 1 - i ..., L , , , } � i" ' t po- .. 11 1111 t#40* , i .; ,.1 , a ± '.� , _ © Chevron 2005 8 Beluga 71 -3 sand - Material Balance Aid Chevron Westside Ivan 44 -36 -- Sterling Beluga P/Z vs Cum Production Plot 4000 3500 • 3000 - • 2500 - • OGIP = 3.9 bcf nearly depleted a2000 - • 1500 - 1000 500 - 0 0 5 10 15 Cum Gas Produced, bcf y = - 884.89x + 9188.2 © Chevron 2005 9 IRU 44 -36- Mechanical Integrity ` i Existing wellbore: • Standard wellbore design: 13 -3/8" surface casing, with a 9- 5/8 "intermediate casing run to 3449' and followed by the 7" production casing to total depth. • 7 -inch casing set at 8,308' MD cemented with 550 sacks of 13.2ppg cement. • Cement bond log shows top of cement at 4,400' MD. Future Monitoring: • IRU 44 -36 will have a standard annulus test during the upcoming wellwork after packers have been set. • Monitoring of daily rates and pressure. Monthly reporting to the AOGCC. • Monitoring of Material Balance Plot of P/Z versus Cumulative Gas (produced and injected). © Chevron 2005 10 Gas Storage Facility - Wells Within Area Chevron ■s/ Well IRU 14 -31: • 7 -inch casing set at 7,018' MD • Cemented to 4,197' MD. Well IRU 13 -31: • 7 -inch casing set at 10,350' MD • Bond log shows cement to 3,453' MD. Well IRU 11 -06: • 7 -inch casing set at 10,020' MD • Bond log shows cement to 6,118' MD. Well IRU 41 -01: • 7 -inch casing set at 9,152' MD • Bond log shows cement to 5,000' MD. Well IRU 44 -01: • 9 -5/8 -inch casing set at 8,948' MD • Two stage cement job. Bond log shows cement from 6,347' - 4050' MD. © Chevron 2005 11 Ivan River - Gas Storage Facility: Chevron Iwo Freshwater Aquifer Exemption (AE Application © Chevron 2005 12 M I )) JN8Ili MUM' '6IT1 ;;.1!,14.1 ■14111 311111:1 ,1+1111111 • .1U1 .m.. .. -4 .T 1 I «'till ,4411' 'x .t I 111 I^. 1111 i r. «,; t r -_,--.— ------ -son— 1 .1 PI 1 I l x t aR , 41e11 — I l 4 � ' 1 'c 1 �. '' - — ' T I I 1 S i 1 -- -- e? -- ,.. C. — 14 1 ime 141 re 4 111 ■ f g. ! r s � ' 1 ,i 1 , '7-43°4\ '"") I . eq I N til \,\,) . { 14l!Ta1` li m +11: 1 1111Vi1" if [WI,' !!1711' I114N'r 11111` ; - 4'r IlrtlIr 11111 11r4w'1- 111I4 111r4 W Q L 13 L DC 0 ma 0 = o 0 N > L O N a CO 0 IRU 44 -36 Log —_ • B a F m , _ ; ! i Chevron Beluga 71 -3 Strata ) t , Gtr d 4 i1 j ! • w 3 r '-'C LI Coal l , r 1 .< I "Beluga 71 -3 strata" r Top of the PC4 Coal - �•��'Fu__ .. _ _—. _ _�_.:., _.._. > Top of the PC5 Coal 6 - 6,919' MD �.0 _ �:.. C; x , Con! e 1 � . - . a - - as ! t I © Chevron 2005 14 Ivan River - Gas Storage Facility: ` t ai Aquifer Exemption (AE) Application: • The application meets the criteria in 20 AAC 25.440 for the granting of an aquifer exemption • The Beluga 71 -3 strata does not currently serve (nor is expected to serve in the future) as a source for drinking water • The Beluga 71 -3 formation is hydrocarbon bearing • The remoteness of the Ivan River Unit and the depth of the Beluga 71 -3 strata makes recovery of water for drinking water purposes economically impractical • The total dissolved solids content of the ground water is more than 3,000 and Tess than 10,000 mg /I, and it is not reasonably expected to supply a public water system • There are numerous shallow freshwater sands which are better sources for drinking water © Chevron 2005 15 Water Well Data: Chevron Three (3) nearby water wells • Two (2) in the Ivan River Unit • One (1) at Stump Lake • Maximum water well depth = 318 ft Exhibit #5 - Local Water Well Data Well / Pad Location Depth Date Ivan River Unit 44-1 SE %SE %Sec. 1, T -13N, R -9 -W SM 247 ft 6 16 -66 Ivan River 44-1 SE'.4SE %Sec. 1. T-13-N. R -9 -W SM 245 ft 8 11 92 Std Lake 44-33 SW AEI °+ Sec. 33, T -14-N, R 9 -W SM 318 ft 1 26 78 (see attached Well Drilling Logs) © Chevron 2005 16 Water Salinity Data • Chevron 1 Nine (9) IRU Tyonek or Sterling water samples ) Y 9 les p Water salinities (TDS) range from 4,300 - 10,700 ppm Exhibit s6 - Ivan River Unit - Water Salinity Data Iran Rivet unit - Water Analyses Reset ey 7D5 Density ^ „J' 2 ICS p+' G 77 F "fell lame Deyc* Cate mg 4 p cm' 3 ppm par onm an Comment R _ 1 9 4'82"575 a 26: • 7030 8 ', , RI., 11-05 9527 4 1 : etc 13083 85' 441.: 1',75 8674 4 82275 6 155 • 3293 9 77 ' W -9375 AL 23-12 Tyarei 99739915 ..' "957 4 312 '.273 8.93 ..'5!.X3 FCT 47 tfvr 3.93 n• -, Speed 700 B D 989 -350 RI. 23.12 Tycm4 997 - 95 1 ! • 1 95' ! 31' • 2:47 893 •91 -70 HCT s' (low 5 })am: bred T90 5 D 589 RL 23-12 Tycmer 9973-95•15 «' -'95" 4 ^' • 2 : 4 7 9,7C '92 7 0 1CTs7 tbw ` 37pr!. Speed 774 B.D 9891 - 9931, HCT 4 , 7 OM Backscutt sarmmp:e); AL 23-12 Ty rte& ien -seta, • • '95' 4 375 • 0737 9.X5 2'3.70 torte 7X 8 D' R. 44-:5 Seerbp 365 983743168 51. 2391 7.28'5 • 37 7,4' sample 1 AL, 44.35 Stria; !8-5 56! 51" 2775 7 075 • 9757 8 1 3 aYnQM s' 1 1 MOMS Cantos C eree Bicarbonate Sit boa •s 4; Ca Sr 8a Fe k Adel 2b*e Ce9r Cate , rr9 ^'9 v rr99 rr9.1 mop I mp 5m9 : n9 i mm9 Inv RL 11-015 S'70 482205 864 3 7o • 295 13 31 1 9 5 5 275.00 524 At; 11-76 r 8933 4 +8 2039 3 82 2.637 77 1 327 29 9' 5 9 0 245.07 2 093 AL 11ab ' 8604 4 8379 • 97' 2270 53 1.335 22 52 2 120 32437 1.334 9891 -992? IL 23- T9one■ 5973 -561! :1 7.,9!' 50 :750 97. '. 197 s a 3 o 2 33 41 989 - 9571 41L 23-12 Ty: ma c 9933 -9915 21 Tye' 57 .2.•90 •07 1 397 E 7 5.4 7 40 43 9091 -9577 .AL 23-'2 Tyneet 99739315 21 196' 57 2.947 943 1 1.35! 8 8 C.Y.' 46 9891 -990• RL2312 Tyomamc 5903.9515 • .1 .187 43 21'5 •'7 1'9! 7 14 83 7 24 50 AL 44-35 3 Stark% 59.0 5 5157-6558 51' 2335 2 854 1 .555 ' MI 52 99 , 4 4 137 07 614 .R.. - 36 548r6i 59.5 5587-5558 5 1 2035 231-- 2,2'5 38 1 828 8' 85 1 3.5 4:0: 479 © Chevron 2005 17 Beluga 71 -3 Water Salinity: Chevron 9,300 ppm (from Pickett Plot analysis) Exhibit # S - Ivan River Unit 44 -36 - Rw and Salinity from Pickett plots Ivan River Unit 44-36 Rw and Salinity from Pickett Plots Marker to , • th bottom de. I a m n Fmtem Rw Salini NaCL , ,:m 36665 4207.0 1 18 2 86 0501 10,000 4207.0 5418.9 1 1. 8 2 94 0380 12,300 51183 5579,3 1 18 2 101 0301 14,700 Sterling Ummnfamiity 55793 59912 1 18 2 107 0.933 4430 Sterl to g 584 64275 61410 1 18 2 112 0161 26,000 Sterling 584 6480.0 6487.0 1 1.8 2 113 0386 10,300 Sterling 59-0 6492.6 6498.0 1 18 2 113 0.418 9,000 Sterling 59-6 65535 6570.0 1 18 2 113 0573 6,600 Sterling 60-0 65993 6604.4 1 18 2 114 0.728 5,200 Sterling 60-2 66192 6623.3 1 18 2 114 0.676 5,400 , Sterling 61-2 57114 671513 1 L8 2 115 0250 15,600 Beluga 71 -3 6832.2 6855.6 1 18 2 117 0415 9,300 © Chevron 2005 18 I RU 44 -36 Water Salinity Profile Log: �j _ 3 Calculated IVAN -36 Salinity Log salinities — ":71:1 i- BEE -- : 1 a -ars.' -co ,. ,; _ range from en S £ . •:.."'".. ,.._5 Y 15C .:5 50 0'.C.>,t' • - :t. : 8,000 - \ 1 c' 10,000 ppm ,,. . _ , ,4 4 4 4.,,4.;,.x.1; fig t 1 -5:S0 — 5a5 Y Lam.. _ is 1 $1 ) t , i _:. : tom- r _t .T , . c lil.-- ' © Chevron 2005 „, „_,.;:_, / j ( 19 Ivan River Aquifer Exemption: Chevron 1/ Summary: • This Freshwater Aquifer Exemption request meets the criteria in 20 AAC 25.440 for the granting of an aquifer exemption. • Granting this request will not endanger current nor future public drinking water sources. • The requested area and strata meet the following specific regulatory criteria: • 20 AAC 25.440(a)(1) - They do not currently serve as a source of drinking water, and cannot now and will not in the future serve as a source of drinking water because ... • 20AAC 25.440(a)(1)(A) - it is hydrocarbon producing or can be demonstrated by the applicant to contain hydrocarbons that, considering their quantity and location, are expected to be commercially producible; • 20 AAC 25.440(a)(1)(B) - They are situated at a depth or location that makes recovery of water for drinking water purposes economically or technologically impractical: • 20 AAC 25.440(a)(2) - the total dissolved solids content of the ground water is more than 3,000 and Tess than 10,000 mg /I, and it is not reasonably expected to supply a public water system. • © Chevron 2005 20 Ivan River Aquifer Exemption: IWO Conclusion: The data and evidence submitted in this application meets the criteria (20 AAC 25.440) for the granting of the Freshwater Aquifer Exemption, for the Beluga 71 -3 strata in the proposed Ivan River Gas Storage Facility. © Chevron 2005 21 N STATE OF ALASKA NOTICE TO PUBLISHER ADVERTISING ORDER NO. ADVERTISING INVOICE AFFIDAVIT MUST OF BE IN PUBLICATION TRIPLICA TE S HOWING 2 OF THIS ADVERTISING FORM) WITH ORDER ATTACHE NO., D CERTIFIED COPY OF /fl O_02114031 r1 ORDER ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE SEE BOTTOM FOR INVOICE ADDRESS F AOGCC AGENCY CONTACT DATE OF A.O. R 333 W 7th Ave, Ste 100 Jody Colombie April 15, 2011 ° Anchorage, AK 99501 PHONE PCN M 907 - 793 -1238 (9071 793 —1221 DATES ADVERTISEMENT REQUIRED: ASAP o Peninsula Clarion P.O. Box 3009 Kenai, AK 99611 ITS ENTIRETY ON TH THE SHOWN. DOUBLE LINES MUST BE PRINTED IN SPECIAL INSTRUCTIONS: Type of Advertisement Legal r ❑ Display Classified ['Other (Specify) SEE ATTACHED IVAN RIVER 44 -36 SEND INVOICE IN TRIPLICATE AOGCC, 333 W. 7th Ave., Suite 100 PAGE 1 OF TOTAL OF TO Anchorage, AK 99501 2 PAGES ALL PAGES$ REF TYPE NUMBER AMOUNT DATE COMMENTS 1 VEN 2 ARD 02910 3 4 FIN AMOUNT SY CC PGM LC ACCT FY NMR DIST LID 1 11 02140100 73451 2 3 4 REQUISITIONED BYx % DIVISION APPROVAL: • 0 Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Docket #'s AEO -11 -01 and SIO 11 -01. Union Oil Company of California (UNOCAL), by application dated April 14, 2011, requests the Alaska Oil and Gas Conservation Commission (Commission) issue an order authorizing underground natural gas storage in the Undefined Gas Pool of the Ivan River Unit, well IRU 44 -36, in conformance with 20 AAC 25.252 and 20 AAC 25.412; and an Aquifer Exemption Order for the Ivan River Unit, in conformance with 20 AAC 25.440. The affected area for both requests is T13N, R8W, S6 SM; T13N, R9W, Si SM; T14N, R8W, S31 SM; and T14N, R9W, S36 SM. The Commission has tentatively scheduled a public hearing on this application for May 26, 2011 at 1:00 pm at the Alaska Oil and Gas Conservation Commission, at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. To request that the tentatively scheduled hearing be held, a written request must be filed by 4:30 p.m. on May 4, 2011. If a request for a hearing is not timely filed, the Commission may consider the issuance of an order without a hearing. To learn if the Commission will hold the hearing, call 793- 1221 after May 9, 2011. In addition, written comments regarding this application may be submitted to the Alaska Oil and Gas Conservation Commission, at 333 West 7 Avenue, Suite 100, Anchorage, Alaska 99501. Comments must be received no later than 4:30 p.m. on May 20, 2011, 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 accommodatio s : : be needed to comment or attend the hearing, contact the Commissio ': ' • - .'a - ssistant Jody Colombie, at 793 -1221, no later than May 23, 2011. /1 . Orman • mssi ner 1 P E ,,. A I N U L A, ,s ?"'iti.' ' . ;:a PO Box 3009, Kenai, AK 99611 - (907) 283 -7551 - Fax (907) 283 -3299 State of Alaska/AOGCC Accounts Payable Invoice # 8706/2074 333 W 7th Ave, Suite 100 AO- 2114031 Anchorage, AK 99501 Date Quanity Total Public Hearing 04/20/11 Legal 11 101.75 AiUkii r Ipts Total Due $101.75 Please include invoice and account numbers on all correspondence PUBLISHER'S AFFIDAVIT UNITED STATES OF AMERICA, STATE OF ALASKA }ss: r Notice of Public Hearing -7 . STATE OF ALASKA Alaska 011 and Gas Conservation Commission Re: Docket #'s AEO -11 -01 and SIO 11 -01. Denise Reece being first duly Union Oil Company of California (UNOCAL), by `application dated April 14, 2011, requests the Alaska sworn, on oath deposes and says: Oil and Gas Conservation Commission (Commission) issue an order authorizing underground natural gas That I am and was at all times here storage in the Undefined Gas Pool of the Ivan River Unit, well IRU 44 -36, in conformance with 20 AAC . in this affidavit mentions, Supervisor of 25.252 and 20 AAC 25.412;. and an Aquifer Exemption Order for the Ivan River Unit, in conformance with 20 Legals of the Peninsula Clarion, a news - AAC 25.440. , The affected area for both requests is T13N, R8W, S6 paper of general circulation and published SM; T13N, R9W, 51 SM; T14N, R8W, 531 SM; and. T14N, R9W, S86 SM. I at Kenai, Alaska, that the The Commission has tentatively scheduled a public Public Hearing hearing on this application for May 26, 2011 at 1:00 pm I at the Alaska 011 and Gas Conservation Commission,' AO- 2114031 at 333, West 7th Avenue, Suite 100, Anchorage, Alaska 99501. To request that the tentatively scheduled ; hearing' be held, -a written request must'be filed by 4:301 a printed copy of which is hereto annexed was p.m. on May 4, 2011. 1 published in said paper one each and If a request for. a 'hearing is not timely filed, She Commission may consider the issuance of an order I for one without a hearing. To learn if the Commission will hold every day successive and the hearing, call 793 -1221 after May 9, 2011. ' consecutive day in the issues on the In addition, written comments regarding this' application may be submitted to the Alaska Oil and 1 following dates: Gas Conservation Commission, at 333 West 7th Avenue, Suite 100, Anchorage, Alaska! April 20, 201 1 99501. Comments must be received no later than 4:301 p.m. on May 20, 2011, except that, if a hearing is held,1 comments must be received no tater than the, conclusion of the hearing. - 1 X .47G) y, 42- ref,t, , If, because of a " disability, special accommodations may be needed to comment or attend the hearing, t c ontact the Commission's Special `Assistant, Jody SUBSCRIBED AND SWORN to me before 1 Colombia, at 793 - 1221, no later than May 23, 2011. i t, ' 6th , , o f May 2011 John K. Norman - . Commissioner , 1 _ I # /-___Z . - 1 J ! 0 COOLISH: 4/20, 2311 8706/20711 NOTARY PUBLIC in favor for the State of Alaska. My Commission expires 26- Aug -12 'Oa, � R(. I 00Tf+kk, ,., , s '�IBLIG STATE OF ALASKA • NOTICE TO PUBLISHER • ADVERTISING ORDER NO. ADVERTISING INVOICE AFFIDAVIT MUST OF PU BE IN BLICATION TRIPLICATE (PART SHOWING 2 OF THIS ADVERTISING FORM) WITH ATTACHED ORDER NO., COPY CERTIFIED OF !1 /� O_02114031 ORDER ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE SEE BOTTOM FOR INVOICE ADDRESS F AOGCC AGENCY CONTACT DATE OF A.O. R 333 West 7 Avenue. Suite 100 Jody Colomhie Anril 15.2011 ° Anchorage_ AK 99501 PHONE PCN M 907 - 793 -1238 0071 793 -1221 DATES ADVERTISEMENT REQUIRED: ASAP Peninsula Clarion O PO Box 3009 Kenai AK 99611 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: AFFIDAVIT OF PUBLICATION United states of America REMINDER State of SS INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. division. A CERTIFIED COPY OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED WITH THE INVOICE. Before me, the undersigned, a notary public this day personally appeared ATTACH PROOF OF PUBLICATION HERE. who, being first duly sworn, according to law, says that he /she is the of Published at in said division and state of and that the advertisement, of which the annexed is a true copy, was published in said publication on the day of 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 02 -901 (Rev. 3/94) AO.FRM Page 2 PUBLISHER • • Fisher, Samantha J (DOA) From: Fisher, Samantha J (DOA) Sent: Friday, April 15, 2011 1:12 PM To: '(foms2 @mtaonline.net)'; '( michael .j.nelson @conocophillips.com)'; '(Von.L .Hutchins @conocophillips.com)'; 'AKDCWeIIIntegrityCoordinator; 'Alan Dennis'; 'alaska @petrocalc.com; 'Anna Raff; 'Barbara F Fullmer'; 'bbritch'; 'Becky Bohrer'; 'Bill Penrose'; 'Bill Walker'; 'Bowen Roberts'; 'Brady, Jerry L'; 'Brandow, Cande (ASRC Energy Services) ; 'Bruce Webb'; 'caunderwood'; 'Chris Gay'; 'Cliff Posey'; 'Crandall, Krissell'; 'D Lawrence'; 'dapa'; 'Daryl J. Kleppin'; 'Dave Matthews'; 'David Boelens'; 'David House'; 'David Steingreaber; 'ddonkel @cfl.rr.com; Delbridge, Rena E (LAA); 'Dennis Steffy'; 'Elowe, Kristin'; 'Erika Denman'; 'eyancy'; 'Francis S. Sommer'; 'Fred Steece'; 'Gary Laughlin'; 'Gary Rogers'; 'ghammons'; 'Gordon Pospisil'; 'Gorney, David L.'; 'Greg Duggin'; 'Gregg Nady'; 'gspfoff; 'Harry Engel'; 'Jdarlington (jarlington @gmail.com)'; 'Jeanne McPherren'; 'Jeff Jones'; 'Jerry McCutcheon'; 'Jill Womack'; 'Jim White'; 'Jim Winegarner; 'Joe Nicks'; 'John Garing'; 'John Katz'; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'Jon Goltz'; 'Judy Stanek; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; 'Kelly Sperback'; 'Kim Cunningham'; 'Larry Ostrovsky'; 'Marilyn Crockett'; 'Mark Dalton'; 'Mark Hanley (mark.hanley @anadarko.com)'; 'Mark Kovac'; 'Mark P. Worcester; '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)'; 'Paul Figel'; 'PORHOLA, STAN T'; 'Randall Kanady'; 'Randy L. Skillern'; ' rob.g.dragnich @exxonmobil.com'; 'Robert Brelsford'; 'Robert Campbell'; 'Ryan Daniel'; 'Ryan Tunseth'; 'Scott Cranswick'; 'Scott Griffith'; Scott, David (LAA); 'Shannon Donnelly'; 'Sharmaine Copeland'; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); 'Sondra Stewman'; 'Steve Lambert; 'Steven R. Rossberg'; 'Suzanne Gibson'; 'tablerk'; 'Tamera Sheffield'; Taylor, Cammy 0 (DNR); 'Teresa Imm'; 'Terrie Hubble'; 'Thor Cutler'; 'Tina Grovier'; 'Todd Durkee'; 'Tony Hopfinger'; 'trmjrl'; 'Valenzuela, Mariam '; 'Vicki Irwin'; 'Walter Featherly'; 'Will Chinn'; Williamson, Mary J (DNR); 'Yereth Rosen'; 'Aaron Gluzman'; Bettis, Patricia K (DNR); caunderwood @marathonoil.com; 'Dale Hoffman'; 'David Lenig'; 'Gary Orr'; 'Jason Bergerson'; 'Joe Longo'; 'Kevin Skiba'; 'Lara Coates'; 'Marc Kuck'; 'Mary Aschoff; 'Matt Gill'; 'Maurizio Grandi'; Ostrovsky, Larry Z (DNR); 'Richard Garrard'; 'Sandra Lemke'; 'Talib Syed'; 'Wayne Wooster'; 'William Van Dyke'; Woolf, Wendy C (DNR); Aubert, Winton G (DOA) (winton.aubert@alaska.gov); Ballantine, Tab A (LAW); Brooks, Phoebe L (DOA) (phoebe.brooks @alaska.gov); Colombie, Jody J (DOA) (jody.colombie @alaska.gov); Crisp, John H (DOA) (john.crisp @alaska.gov); Davies, Stephen F (DOA) (steve.davies @alaska.gov); Foerster, Catherine P (DOA) (cathy.foerster @alaska.gov); Grimaldi, Louis R (DOA) (lou.grimaldi @alaska.gov); Herrera, Matt F (DOA); Johnson, Elaine M (DOA) (elaine.johnson @alaska.gov); Jones, Jeffery B (DOA) (jeff.jones @alaska.gov); Laasch, Linda K (DOA) (linda.laasch @alaska.gov); Maunder, Thomas E (DOA) (tom.maunder @alaska.gov); McIver, Bren (DOA) (bren.mciver @alaska.gov); McMains, Stephen E (DOA) (steve.mcmains @alaska.gov); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA) (bob.noble @alaska.gov); Norman, John K (DOA) (john.norman @alaska.gov); Okland, Howard D (DOA) (howard.okland @alaska.gov); Paladijczuk, Tracie L (DOA) ( tracie.paladijczuk @alaska.gov); Pasqua!, Maria (DOA) (maria.pasqual @alaska.gov); Regg, James B (DOA) (jim.regg @alaska.gov); Roby, David S (DOA) (dave.roby @alaska.gov); Saltmarsh, Arthur C (DOA) (art.saltmarsh @alaska.gov); Scheve, Charles M (DOA) (chuck.scheve @alaska.gov); Schwartz, Guy L (DOA) (guy.schwartz @alaska.gov); Seamount, Dan T (DOA) (dan.seamount @alaska.gov); Shartzer, Christine R (DOA) Subject: Notice of Public Hearing Ivan River Unit 44 -36 AEO -11 -01 Attachments: Ivan River Unit 44 -36 AEO- 11- 01.pdf Sc ncwvt,tha' ia44v O (2, a vud. Via.( Cav;.se4va tio vCoi ni4a - i n (907)793 -1223 (907)276 -7542 (fwx) 1 1 • Mary Jones David McCaleb XTO Energy, Inc. IHS Energy Group George Vaught, Jr. Cartography GEPS P.O. Box 13557 810 Houston Street, Ste 200 5333 Westheimer, Suite 100 Denver, CO 80201 -3557 Ft. Worth, TX 76102 -6298 Houston, TX 77056 Richard Neahring Jerry Hodgden NRG Associates Mark Wedman Hodgden Oil Company Halliburton President 408 18 Street 6900 Arctic Blvd. Golden, CO 80401 -2433 P.O. Box 1655 Anchorage, AK 99502 Colorado Springs, CO 80901 Bernie Karl CIRI Baker Oil Tools K &K Recycling Inc. Land Department 795 E. 94 Ct. P.O. Box 58055 P.O. Box 93330 Anchorage, AK 99515 -4295 Fairbanks, AK 99711 Anchorage, AK 99503 North Slope Borough Richard Wagner Gordon Severson Planning Department P.O. Box 60868 3201 Westmar Circle P.O. Box 69 Fairbanks, AK 99706 Anchorage, AK 99508 -4336 Barrow, AK 99723 Jack Hakkila Darwin Waldsmith James Gibbs P.O. Box 190083 P.O. Box 39309 P.O. 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 P.O. Box 2139 Soldotna, AK 99669 -7714 Fairbanks, AK 99701 Soldotna, AK 99669 -2139 .. 0 ( \19\ \X‘q-C Imam • • Chantal R. Walsh Union Oil Company of California Chevron Petroleum Engineer 3800 Centerpoint Drive, Suite 100 %roil Anchorage, AK 99503 Tel 907 263 7627 %.1 Fax 907 263 7828 Email walshc @chevron.com March 30, 2011 RECO Ms. Cathy Foerster Mr. Dan Seamount Mr. John Norman Alaska Oil and Gas Conservation P Oil 4 Gas Gras. Commission Commission Annorago 333 W. 7` Avenue, Suite 100 Anchorage, AK 99501 -3539 Re: APPLICATION FOR STORAGE ORDER FOR IVAN RIVER GAS STORAGE FACILITY Dear Commissioners: Attached for your review are two copies of the Application for Injection Order for Gas Storage for the Ivan River Gas Storage Facility. The application is submitted by Union Oil Company of Cali- fornia (Union), as Operator. Upon your approval of this application and pending approval of gas storage with the Alaska Department of Natural Resources Division of Oil and Gas, Union plans to commence injection of gas into the IRU 44 -36 Well this summer. Please contact me at 263 -7627 if you have any questions regarding this application. Sincerely, Chantal R. Walsh Petroleum Engineer Union 011 Company of California www.chevron.com . ' • • APPLICATION FOR INJECTION ORDER FOR GAS STORAGE IVAN RIVER GAS STORAGE FACILITY TABLE OF CONTENTS Section /Regulatory Citation Subiect Page A. 20 AAC 25.252(c)(1) Plat information 3 RECEIVED B. 20 AAC 25.252(c)(2) Operators /Surface Owners 3 , ,, , $ ( " r t1 C. 20 AAC 25.252(c)(3) Affidavit 4 N-1411. Oil & Gas Cm. CT ,, ; <ss D. 20 AAC 25.252(c)(4) Description of Operation 5 AncnoPag6 E. 20 AAC 25.252(c)(4) Storage Zones 5 F. 20 AAC 25.252(c)(4) Geologic Information 5 G. 20.AAC 25.252(c)(4) Production History 6 H. 20 AAC 25.252(c)(5) Well Logs 7 I. 20 AAC 25.252(c)(6) Mechanical Integrity 7 J. 20 AAC 25.252(c)(6) Casing Information 8 K. 20 AAC 25.252(c)(7) Injection Fluid 9 L. 20 AAC 25.252(c)(8) Injection Pressure 9 M. 20 AAC 25.252(c)(9) Fracture Information 9 N. 20 AAC 25.252(c)(10) Formation Fluid 10 O. 20 AAC 25.252(c)(11) Aquifer Exemption 10 P. 20 AAC 25.252(c)(12) Wells Within Area 10 1 • IVAN RIVER UNIT APPLICATION FOR INJECTION ORDER FOR GAS STORAGE IVAN RIVER GAS STORAGE FACILITY LIST OF ATTACHMENTS Number Description 1 Regional Cook Inlet Location Map 2 IRU 44 -36 Location Map, 71 -3 Sand 3 IRU 44 -36 Well Log Section Showing 71 -3 Sand 4 IRU 44 -36 Production Chart — Gas and Water Rates 5 Material Balance Plot: P/Z vs Cumulative Gas 6 Current Wellbore Schematic for IRU 44 -36 7 Completion Report and Directional Survey 8 Proposed Wellbore Schematic for IRU 44 -36 9 Sample Gas Analysis from Ivan River Unit 10 Sample Gas Analysis from IRU 44 -36 11 Ivan River Water Analysis 12 Wellbore Schematic for IRU 14 -31 13 Wellbore Schematic for IRU 13 -31 14 Wellbore Schematic for IRU 11 -06 15 Wellbore Schematic for IRU 41 -01 16 Wellbore Schematic for IRU 44 -01 2 • • • IVAN RIVER UNIT IVAN RIVER GAS STORAGE FACILITY APPLICATION FOR STORAGE INJECTION ORDER March 29, 2011 Introduction Union Oil Company of California (Union), as operator of the Ivan River Unit, requests a storage injection order for a gas storage project within the boundaries of the Ivan River Unit. Union specifically requests permission for storage injection operations into the Beluga 71 -3 sand, which is present in the IRU 44 -36 well. After obtaining all necessary approvals, IRU 44 -36 would be converted to gas storage service. Additional wells would possibly be drilled, redrilled or worked over to this same sand in the future to increase deliverability from the storage facility. Section Attachment 1 is a regional map showing the location of the Ivan River Unit relative to other Units in the Cook Inlet area. Attachment 2 is a plat showing the location of the proposed gas storage reservoir in IRU 44 -36: Beluga 71 -3 and the surrounding wells in the Ivan River Unit. Section B — Operators /Surface Owners The surface owners and operators within the area of this injection order and extending one - quarter mile beyond the boundary are: • Union Oil Company of California • State of Alaska Department of Fish and Game 3 • • • Section C — Affidavit Affidavit of Justin R. Black STATE OF ALASKA THIRD JUDICIAL DISTRICT I Justin R. Black, declare and affirm as follows: 1. I am over 19 years of age. I am employed by Union Oil Company of California as a Land Representative. I have personal knowledge of the matters set forth in this affidavit. 2. On J1GrY6)- 30 , 2011, the surface owners /operators listed in section B were provided a copy of this permit application. DATED at Anchorage, Alaska this 30 day of mar6b , 2011. cOl Justin R. Black Subscribed and affirmed before me at Anchorage, Alaska on 4r a, -e4 3 d , 2011. ?( 1P dte' STATE OF ALASKA NOTARY PUBLIC % 1 Zelma M. Clarke Y='__ C ommission Expires Nov 10, 2012 My Notary Public in and for the State of Alaska My commission expires: // / 4 • • Section D — Description of Operation Union proposes injecting gas into the nearly depleted Beluga 71 -3 sand for gas storage purposes. Initially, the IRU 44 -36 well will be used as the sole well for gas storage operations (both production and injection). Union may later decide to redrill or work over an existing Ivan River well or drill a new well for storage operations into this reservoir. The storage gas will be injected during periods of excess supply and produced back during periods of increased demand to help balance gas deliverability requirements. Section E — Storage Zone The Beluga 71 -3 sand is the proposed zone of injection. This zone comprises a stratigraphic interval, the top of which correlates to depths defined in the following Ivan River Unit wells: Well 71 -3 Sand Top (MD) 71 -3 Sand (TVDSS) IRU 44 -36 6829' -5237' IRU 13 -31 7137' -5236' IRU 14 -31 6240' -5238' IRU 11 -06 6514' -5247' IRU 41 -01 5854' -5275' Sand Not Present IRU 44 -01 5363' -5317' IRU 23 -12 6506' -5376' Section F - Geologic Information Gas production from the Ivan River Unit has come from the Lower Sterling, Beluga and Tyonek Formations. The gas sands of Lower Sterling Formation are the shallowest, extending from a depth of approximately -4850 feet SSTVD to the top Beluga, approximately -5175 feet SSTVD. The Lower Sterling is comprised of interbedded sandstone, siltstone, mudstone, and coal. The Sterling Formation was most likely deposited in a higher- energy meandering to braided stream environment. The Lower Sterling section is approximately 320 feet TVD thick at Ivan River Unit. 5 • i Underlying the Sterling is the Beluga Formation. The Beluga sands were deposited in a thinner, lower energy meandering stream system and are likely to be laterally discontinuous. These low- energy Beluga sands are inter - layered with abundant siltstones, mudstones and coals. The Beluga low- energy section is approximately 2750 feet TVD thick at Ivan River Unit. Currently all Beluga gas production has been from the upper 350 feet TVD of the Beluga section. Although gas production continues in the Tyonek sands at Ivan River Unit, the Tyonek section was not reached in the IRU 44 -36 wellbore. The Tyonek is currently producing from gas sands in IRU 44 -01 and IRU 11 -06. The Tyonek Formation is comprised of meander belt and anastomosing stream sandstones, often stacked into thicker sandstone sections interbedded with siltstones, mudstones and thick coals and is approximately 4850 feet thick at Ivan River Unit. Currently all Tyonek gas production has been from the upper 200 feet TVD of the Tyonek Formation. Beluga 71 -3 Sand The 71 -3 sand is a Beluga channel sand that is highly depleted from earlier production in the IRU 44 -36 well. The sand was not completed and produced in any other well. The sand appears to transition to overbank siltstone and silty mudstone to the south in the IRU 41 -01, suggesting that the 71 -3 channel sands at the north end of the unit are isolated from the channel sands at the south end of the unit. The attached log section for IRU 44 -36 (Attachment 3) shows the 71 -3 sand at depths from 6829' to 6856 feet measured depth (MD). The 71 -3 sand is topped by a section of interbedded siltstone, clay -rich siltstone and mudstone, which is topped by a 5 TVD feet of coal (PC4 Coal pick). Above the PC4 Coal there is a thick, approximately 50 foot section of siltstone and mudstone creating an impermeable barrier above; there are no permeable gas sands identified immediately above the 71 -3 sand. The sand is underlain by 20 TVD feet of interbedded siltstone and mudstone. Below the first 20 feet there are some laterally discontinuous sands interbedded with clay rich siltstones, mudstones and laterally continuous 4 to 6 foot coals. The PC4, PC5 and PC6 Coals are laterally extensive and easily picked in other wells across the Unit. These sections above and below the 71 -3 sand will act as a seal. Section G — Production History The IRU 44 -36 Well was drilled and completed in March 1993. Three sands were perforated: the Sterling 58 -4, the Sterling 59 -6, and the Beluga 71 -3 sand. A single 2- 7/8" completion was run with the production packer set above all zones. Attachment 4 shows the production history of the IRU 44 -36 well. The well was first produced with all three sands open and commingled. Peak gas production from the well occurred in September 1993 at 10.731 MMCFD. In January 1995 water 6 • breakthrough occurred. Attempts to chemically plug off the water production were made without success. The well loaded up and was unable to produce after September of 1995. In September 2001, a rig workover was performed on the well. Three deeper sands were opened, and the previous Sterling and Beluga intervals were reperforated. The 2- 7/8" single string completion was run with packers and sliding sleeves to enable isolated production intervals. Initial attempts were unsuccessful at bringing the new deeper zones on due to water, sand and coal production. An isolation plug was set below the Beluga 71 -3 sand and the sliding sleeve was opened. Peak, stand alone, gas production from this interval was in January 2002 at 6.6 MMCFD at 1235 psig flowing tubing pressure. The 71 -3 sand continued to produce with very little associated water (attachment 4) until March 2004. With a reservoir pressure of 615 psia the well was unable to flow into the compressor at the Ivan facility. The 71 -3 sand was isolated as unsuccessful attempts were made to bring on the shallower Sterling sand intervals. These intervals brought water and sand into the well bore and the well has not been returned to production since. Estimates for original gas in place for the Beluga 71 -3 sand were determined by analyzing the material balance plot (Attachment 5) for the post September 2001 period when the zone produced 1.7 bcf in isolation from the other Beluga and Sterling intervals. Note that the P/Z vs. cumulative gas produced plot for this time period is a straight line, indicating volumetric type depletion or a weak aquifer at most. By extrapolating this straight line back to the original reservoir pressure for the sand, we constructed a theoretical plot for the zone had it produced in isolation over the entire depletion period. Using this approach, it is estimated that the original gas in place for this zone is 3.9 bcf. As of June 2005, cumulative production in the 71 -3 sand, from the IRU 44 -36 well, is 3.1 bcf of gas and 460 bbl water, the gas production representing 79.5% of OGIP. It is desired to convert the well to gas storage service at this time. Section H — Well Logs All open hole logs from wells in the Ivan River Unit were sent to the Commission once the logs were completed. Attachment 3 shows the log section for the proposed injection interval in well IRU 44 -36. Section I — Mechanical Integrity The IRU 44 -36 well will be tested for mechanical integrity using the standard 30 minute annulus test per 20 AAC 25.412(c). To confirm continued mechanical integrity, Union Oil Company of California will monitor daily injection rates and pressure and notify the AOGCC the next working day if the rates and pressure indicate pressure 7 • • 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 of P/Z versus Cumulative Gas Produced or Injected during gas storage operations. Monitoring of pressures and volumes in a gas storage reservoir is a secondary check upon mechanical integrity. The data from the original depletion can be compared with subsequent injection and production cycles. Although some hysteresis has been known to occur even in volumetric reservoirs, any problems that result in a loss of mechanical integrity will likely be evident in this data. Section J — Casing Information Well IRU 44 -36 was directionally drilled from a surface location 742 feet from the south line (FSL) and 777 feet from the east line (FEL) in Section 1, Township 13 North, Range 9 West, Seward Meridian to a total depth of 8,308 feet MD (6,438 feet TVD) with a bottom hole location of 156 feet west and 4,836 feet north of the surface location. The top of the gas storage interval at 6,836 feet MD ( -5,245 feet TVDSS) is 65 feet west and 3914 feet north of the surface location. A schematic of the well as currently completed is shown in Attachment 6. Original Construction: The 13 3 /8 surface casing was set at 908 feet MD with cement returns to the surface. A 12 '/ hole was drilled and the 9 % casing run to 3,449 feet MD and cemented with 491 sacks of 12.9 ppg lead and 440 sacks of 15.8 ppg tail cement with cement to surface. A leakoff test was run to 19.5 ppg EMW at 2,941' TVD shoe depth. The 7 -inch casing was set at 8,308 feet MD and cemented in place with 550 sacks of 13.2 ppg cement. A cement bond log was run and found the top of cement at 4,400 feet MD (3,591 feet TVD). Attachment 7 includes the State Completion Report with construction events detailing the casing, cementing, and tubing - packer equipment status. A directional survey is also included in Attachment 7. The 7 -inch casing to 7,789' MD is 29# N -80 with an unsupported burst pressure of 8,160 psi. The new tubing will be either 41/2-inch or 3 1 /2- inch 12.6# L -80 (attachment 8). The unsupported burst pressure is 8,430 psi (4 1/2-inch) or 10,160 psi (3 1 /2- inch). These exceed the maximum bottom hole injection pressure by more than 25% as required by the Alaska Administrative Code 20 AAC 25.412(b). A waiver request will be submitted to allow a variance to 20 AAC 25.412(b) to allow more than 200 feet MD between the packer and perforations. This waiver is being requested to allow a 2 " packer above the gas storage zone to ensure long -term isolation of the Sterling, 58 -4 and 59 -6, zones in addition to the squeeze cementing that 8 will be performed on those intervals. If this packer is not run, pressure cycling during future MITs may break down the squeeze perforations, creating a mechanical condition that would not allow use of the well until a workover could be performed. Considering the challenging logistics of this well location, it could be several months before a workover could be performed, leaving the well unavailable during that time period. Section K — Injection Fluid The type of fluid for proposed injection is dry natural gas, which is predominantly methane. It is intended to use the Ivan River Storage Facility for the injection of excess gas owned by Union. Attachments 9 and 10 are representative gas analyses for gas produced from the Ivan River Unit and from IRU 44 -36. The compositions of these samples are typical of gas from Cook Inlet Units. Since all expected sources of gas are predominantly methane and are very similar to the original gas in the reservoir, no fluid compatibility problems are expected. The estimated maximum amount of gas to be injected daily is 20 mmcfd. Section L — Injection Pressure Compression will be used for gas injection and production operations. The maximum injection pressure will be 3050 psig, which corresponds to a maximum BHP gradient of 0.65 psi /ft at the perforations (71 -3 sand mid perf depth is 5300' TVD). Union requests a maximum average reservoir pressure of 3183 psia, which is 10% over the estimated original reservoir pressure of 2894 psia. The SI WHP associated with this pressure is 2800 psig. Section M — Fracture Information The proposed maximum injection pressures for the gas storage operation will not initiate fractures in the confining strata which might enable the injection or formation fluid to enter freshwater strata. The proposed maximum injection pressure for IRU 44 -36 in the Beluga 71 -3 sand, as previously mentioned, will not exceed a gradient of 0.65 psi /ft at the sand face. Leak off tests conducted while drilling IRU 44 -36 in February, 1993 show the fracture gradient at 918' TVD and 2950' TVD to be 1.35 psi /ft and 1.014 psi /ft, respectively. The offset well IRU 11 -06 conducted a deeper formation integrity test in December of 2009. This FIT test established the formation at 4930' TVD withstood a pressure gradient of .71 psi /ft. Original reservoir pressure in the Beluga 71 -3 sand in IRU 44 -36 is estimated at 2894 psi based on established local pressure gradients in offset wells on the West side and 9 • • the initial reservoir pressure seen in this well when the initial three zones were perforated (the 71 -3 sand was the deepest). Section N — Formation Fluid Attachments 11 are produced water samples collected from IRU on 08/01/90 and 5/11/05. Section 0 — Aquifer Exemption The proposed gas injection will be at depths of approximately 6,836' — 6,852' MD (5,293' - 5,305' TVD). As per 40 CFR 147.102(b) the aquifers in the Ivan River Unit are exempted in accordance with 40 CFR 144.7(b) and 40 CFR 146.4. Section P — Wells Within Area The 1 /4 mile area of review around the top of the proposed gas storage zone in IRU 44- 36 is shown on Attachment 2. This perimeter encompasses three wells: IRU 14 -31, IRU 13 -31 and IRU 11 -06. These wells are cased and cemented so as to not provide a conduit for injected gas to escape the injection Zone. No correction action plans are required. Detailed information on these wells has been provided to the State. Additional copies can be provided if requested. Well IRU 14 -31: Attachment 12 includes the well schematic. The 10 % inch surface casing is set at 2,037 feet MD (1,960 feet TVD). Cement was recorded to the surface and bond logging shows good bonding. The 7 -inch casing was set at 7,018 feet MD (5,829 feet TVD) and cemented to 4,197 feet TVD, which is above the top of the proposed gas storage zone. Second stage cement was placed from 3,646 feet to 625 feet TVD. IRU14 -31 is an active Class II disposal well. Well IRU 13 -31: Attachment 13 includes the well schematic. The 9 % inch surface casing is set at 3,460 feet MD (2,938 feet TVD). Cement was recorded at the surface. The 7 -inch production casing is set at 10,350 feet MD (7,349 feet TVD) and cemented. A cement bond log run on December 2, 2008 showed a cement top at 3,453 feet MD (2,932 feet TVD), which is above the top of the proposed gas storage zone. IRU 13 -31 is an active Class II disposal well. Well IRU 11 -06: Attachment 14 includes the well schematic. The 9 % inch surface casing is set at 6,015 feet MD (4,920 feet TVD) and cemented in two stages. The 1 stage top is estimated at 4,100 feet MD (3,597 feet TVD) and the 2 stage from 3,487 feet MD (3,175 feet TVD) to 900 feet MD (900 feet TVD). The 7 -inch production casing is set at 10,020 feet MD (8,237 feet TVD) and cemented. A cement bond log run on 10 • • February 8, 2009 showed a cement top at 6,118 feet MD (4,992 feet TVD), which is above the top of the proposed gas storage zone. IRU 11 -06 is an active gas producer. Well IRU 41 -01: Attachment 15 includes the well schematic. The 9 % inch surface casing is set at 3,498 feet MD (3,335 feet TVD). Cement was recorded at the surface. The 7 -inch production casing is set at 9,152 feet MD (8,266 feet TVD) and cemented. A cement bond log run on January 21, 1993 showed a cement top at 5,000 feet MD (4,582 feet TVD), which is above the top of the proposed gas storage zone. IRU 41 -01 is an idle gas producer. Well IRU 44 -01: Attachment 16 includes the well schematic. The 13 % inch surface casing is set at 1,999 feet MD (1,999 feet TVD). The initial cement job did not reach surface and a top job was performed from 220' to surface. The 9 % inch production casing is set at 8,948 feet MD (8,948 feet TVD) and cemented in two stages. A cement bond log run on July 18, 1966 showed a cement top for the 1 stage from the shoe at 8,948 feet MD (8,948 feet TVD) to 7,540 feet MD (7,540 feet TVD), and a 2 stage from the DV collar at 6,347 feet MD (6,347 feet TVD) to 4,050 feet MD (4,050 feet TVD), which is across and above the top of the proposed gas storage zone. IRU 44 -01 is an active gas producer. 11 Regional Cook Inlet Location Map MIRK • 1 eauct . ■ Ivan River Unit NINOTC �.Irf - ,tams ■ ■ ZA , sAy ... v 1 ''. 1 MOa-E m an' V J siou l 0 gill MN NM ■ I • • io n to.... 11Cou IN NUS: I • . F 1- miaow one &Vas ATTACHMENT 1 Application for Injection Order for Gas Storage Ivan River Unit g 356000 357000 35800. 359000 360000 361000 362000 363000 364000 365000 . Ys 1 . - --- -E.500 u �O o ; N O - 0 (31 O N . / O / I IRU t 3 -31 r, 9 o ;on � £ RU 131 IV o o N o o 1 0 h e � 1 - _.� _ . _,._..- _ _—_ 4 _ o 1 o - - , 4 ; . ,o; ( ) o 0 N in li TO O CJI ° O _ I i O lir O N o p co 0 1 i 7 5 o d O N 71 -3 Injection 1, 0 --"-----__—) of • ' wi ! Unit Boundry q4 R , I ' ' � 4 -01 ih ii ° _ . �- 317 Planned as in). A CB S _ -.. �( O �CJ o .-- Injection water , O Gas . M . wIC> Dry . O - \ iV W 11/4 Mile Radius 71-3 Sand IRU 44-38 W o o \ 376 COOK PoLET. ALASKA scNe N AN RIVER UaT C MOAN i 50 CHEVRON MN 1: FonnAllen Meek M / � 07/05/2010 : NAD 27 T.HaigNM 1 0 0.: 0. 5 O 0.75 1 1.25miles ail 4 4 ,3 ° �_- c N - iv O 1} I 23 N ■ ° N ... .. 1 . .. �. � ...... 356000 357000 358000 359000 360000 361000 362000 363000 364000 365000 ATTACHMENT 2 Application for Injection Order IVAN RIVER UNIT 2010 ALIAS CID: IVAN R 44- 36:BELUG -STER Cumulative Oil Prod : 0 Mbbl Cumulative Gas Prod : 9826 MMcf Cumulative Water Prod : 12 Mbbl Cumulative Water Inj : 0 Mbbl Monthly Monthly Monthly Monthly Oil Water Gas Water • Oil Water Gas Water Rate Rate Rate Inj Rate Prod Prod Prod Inj (CD) (CD) (CD) (CD) Date bbl bbl Mcf bbl bbl /d bbl /d Mcf /d bbl /d 19930101 * * * * * * * * 19930201 * * * * * * * * 19930301 0.00 0.00 4959.00 * 0 0 160 * 19930401 0.00 5.00 172507.00 * 0 0 5750 * 19930501 0.00 7.00 101003.00 * 0 0 3258 * 19930601 * * * * * * * * 19930701 0.00 5.00 55899.00 * 0 0 1803 * 19930801 0.00 7.00 42830.00 * 0 0 1382 * 19930901 0.00 26.00 218693.00 * 0 1 7290 * 19931001 0.00 31.0 332659.00 * 0 1 10731 * 19931101 0.00 31.00 300896.00 * 0 1 10030 * 19931201 0.00 30.00 322107.00 * 0 1 10391 * 239167812 Sum . 19930651 0.00 11.83 129296.08 0.00 0 0 4233 Average 19940101 0.00 18.00 315979.00 * 0 1 10193 * 19940201 0.00 26.00 277935.00 * 0 1 9926 * 19940301 0.00 26.00 307388.00 * 0 1 9916 * 19940401 0.00 25.00 303888.00 * 0 1 10130 * 19940501 0.00 9.00 302625.00 * 0 0 9762 * 19940601 0.00 0.00 291492.00 * 0 0 9716 * 19940701 0.00 0.00 282222.00 * 0 0 9104 * 19940801 0.00 0.00 292725.00 * 0 0 9443 * 19940901 0.00 0.00 276251.00 * 0 0 9208 * Page 1 1- Monthly Average Rate Attachment 4 ALIAS CID: IVAN R 44- 36:BELUG -STER Cumulative Oil Prod : 0 Mbbl Cumulative Gas Prod : 9826 MMcf Cumulative Water Prod : 12 Mbbl Cumulative Water Inj : 0 Mbbl Monthly Monthly Monthly Monthly Oil Water Gas Water 40 Oil Water Gas Water Rate Rate Rate Inj Rate Prod Prod Prod Inj (CD) (CD) (CD) (CD) Date bbl bbl Mcf bbl bbl /d bbl /d Mcf /d bbl /d 19941001 0.00 0.00 275016.00 * 0 0 8871 * 19941101 0.00 1.00 261693.00 * 0 0 8723 * 19941201 0.00 0.00 260066.00 * 0 0 8389 * 239287812 Sum 19940651 0.00 8.75 287273.33 0.00 0 0 9448 Average 19950101 0.00 0.00 251944.00 0.00 0 0 8127 0 19950201 0.00 0.00 205145.00 0.00 0 0 7327 0 19950301 0.00 0.00 232499.00 0.00 0 0 7500 0 19950401 0.00 0.00 219293.00 0.00 0 0 7310 0 19950501 0.00 0.00 222957.00 0.00 0 0 7192 0 • 19950601 0.00 0.00 208635.00 0.00 0 0 6955 0 19950701 0.00 0.00 175707.00 0.00 0 0 5668 0 19950801 0.00 0.00 192282.00 0.00 0 0 6203 0 19950901 0.00 0.00 152084.00 0.00 0 0 5069 0 19951001 0.00 0.00 167007.00 0.00 0 0 5387 0 19951101 0.00 0.00 184546.00 0.00 0 0 6152 0 19951201 0.00 1.00 174321.00 0.00 0 0 5623 0 239407812 Sum 19950651 0.00 0.08 198868.33 0.00 0 0 6543 Average 19960101 0.00 335.00 151413.00 0.00 0 11 4884 0 Page 2 1- Monthly Average Rate Attachment 4 II I ALIAS CID: IVAN R 44- 36:BELUG -STER Cumulative Oil Prod : 0 Mbbl Cumulative Gas Prod : 9826 MMcf Cumulative Water Prod : 12 Mbbl Cumulative Water Inj : 0 Mbbl Monthly Monthly Monthly Monthly Oil Water Gas Water • Oil Water Gas Water Rate Rate Rate Inj Rate Prod Prod Prod Inj (CD) (CD) (CD) (CD) Date bbl bbl Mcf bbl bbl /d bbl /d Mcf /d bbl /d 19960201 0.00 601.00 145054.00 0.00 0 21 5002 0 19960301 0.00 723.00 128793.00 0.00 0 23 4155 0 19960401 0.00 898.00 86374.00 0.00 0 30 2879 0 19960501 * * * * * * * * 19960601 * * * 0.00 * * * 0 19960701 * * * * * * * * 19960801 * * * * * * * * 19960901 * * * * * * * * 19961001 * * * 0.00 * * * 0 19961101 * * * * * * * * 19961201 * * * * * * * * 239527812 Sum 19960651 0.00 213.08 42636.17 0.00 0 7 1410 Average 19970101 * * * * * * * * 19970201 * * * * * * * * 19970301 * * * * * * * * 19970401 * * * * * * * * 19970501 * * * * * * * * 19970601 * * * * * * * * 19970701 * * * * * * * * 19970801 * * * * * * * * 19970901 * * * * * * * * 19971001 * * * * * * * * Page 3 1- Monthly Average Rate Attachment 4 I II I ALIAS CID: IVAN R 44- 36:BELUG -STER Cumulative Oil Prod : 0 Mbbl Cumulative Gas Prod : 9826 MMcf Cumulative Water Prod : 12 Mbbl Cumulative Water Inj : 0 Mbbl Monthly Monthly Monthly Monthly Oil Water Gas Water Oil Water Gas Water Rate Rate Rate Inj Rate Prod Prod Prod Inj (CD) (CD) (CD) (CD) Date bbl bbl Mcf bbl bbl /d bbl /d Mcf /d bbl /d 19971101 * * * * * * * * 19971201 * * * * * * * * 239647812 Sum 19970651 0.00 0.00 0.00 0.00 0 0 0 Average 19980101 * * * * * * * * 19980201 * * * * * * * * 19980301 * * * * * * * * 19980401 * * * * * * * * 19980501 * * * * * * * * 19980601 * * * * * * * * 19980701 * * * * * * * * 19980801 * * * * * * * * 19980901 * * * * * * * * 19981001 * * * * * * * * 19981101 * * * * * * * * 19981201 * * * * * * * * 239767812 Sum 19980651 0.00 0.00 0.00 0.00 0 0 0 Average 19990101 * * * * * * * * 19990201 * * * * * * * * Page 4 1- Monthly Average Rate Attachment 4 ALIAS CID: IVAN R 44- 36:BELUG -STER Cumulative Oil Prod : 0 Mbbl Cumulative Gas Prod : 9826 MMcf Cumulative Water Prod : 12 Mbbl Cumulative Water Inj : 0 Mbbl Monthly Monthly Monthly Monthly Oil Water Gas Water Oil Water Gas Water Rate Rate Rate Inj Rate Prod Prod Prod Inj (CD) (CD) (CD) (CD) Date bbl bbl Mcf bbl bbl /d bbl /d Mcf /d bbl /d 19990301 * * * * * * * * 19990401 * * * * * * * * 19990501 * * * * * * * * 19990601 * * * * * * * * 19990701 * * * * * * * * 19990801 * * * * * * * * 19990901 * * * * * * * * 19991001 * * * * * * * * 19991101 * * * * * * * * 19991201 * * * * * * * * 239887812 Sum 19990651 0.00 0.00 0.00 0.00 0 0 0 Average Ilk 20000101 * * * * * * * * 20000201 * * * * * * * * 20000301 * * * * * * * * 20000401 * * * * * * * * 20000501 * * * * * * * * 20000601 0.00 143.00 4711.00 * 0 5 157 * 20000701 * * * * * * * * 20000801 * * * * * * * * 20000901 0.00 0.00 479.00 * 0 0 16 * 20001001 * * * * * * * * 20001101 * * * * * * * * Page 5 1- Monthly Average Rate Attachment 4 ALIAS CID: IVAN R 44- 36:BELUG -STER Cumulative Oil Prod : 0 Mbbl Cumulative Gas Prod : 9826 MMcf Cumulative Water Prod : 12 Mbbl Cumulative Water Inj : 0 Mbbl Monthly Monthly Monthly Monthly Oil Water Gas Water Oil Water Gas Water Rate Rate Rate Inj Rate Prod Prod Prod Inj (CD) (CD) (CD) (CD) Date bbl bbl Mcf bbl bbl /d bbl /d Mcf /d bbl /d 20001201 * * * * * * * * 240007812 Sum 20000651 0.00 11.92 432.50 0.00 0 0 14 Average 20010101 * * * * * * * * 20010201 * * * * * * * * 20010301 * * * * * * * * 20010401 * * * * * * * * 20010501 * * * * * * * * 20010601 * * * * * * * * 20010701 * * * * * * * * 20010801 * * * * * * * * III 20010901 * * * * * * * * 20011001 * * * * * * * * 20011101 0.00 19.00 49453.00 * 0 1 1648 * 20011201 0.00 34.00 177111.00 * 0 1 5713 * 240127812 Sum 20010651 0.00 4.42 18880.33 0.00 0 0 613 Average 20020101 0.00 30.00 153845.00 * 0 1 4963 * 20020201 0.00 14.00 145732.00 * 0 1 5205 * 20020301 0.00 15.00 142333.00 * 0 0 4591 * Page 6 1- Monthly Average Rate Attachment 4 ALIAS CID: IVAN R 44- 36:BELUG -STER Cumulative Oil Prod : 0 Mbbl Cumulative Gas Prod : 9826 MMcf Cumulative Water Prod : 12 Mbbl Cumulative Water Inj : 0 Mbbl Monthly Monthly Monthly Monthly Oil Water Gas Water Ili Oil Water Gas Water Rate Rate Rate Inj Rate Prod Prod Prod Inj (CD) (CD) (CD) (CD) Date bbl bbl Mcf bbl bbl /d bbl /d Mcf /d bbl /d 20020401 0.00 11.00 68838.00 * 0 0 2295 * 20020501 * * * * * * * * 20020601 0.00 0.00 661.00 * 0 0 22 * 20020701 * * * * * * * * 20020801 * * * * * * * * 20020901 0.00 5.00 47661.00 * 0 0 1589 * 20021001 0.00 15.00 129797.00 * 0 0 4187 * 20021101 0.00 30.00 102343.00 * 0 1 3411 * 20021201 0.00 31.00 84538.00 * 0 1 2727 * 240247812 Sum 20020651 0.00 12.58 72979.00 0.00 0 0 2416 Average III 20030101 0.00 31.00 54095.00 * 0 1 1745 * 20030201 0.00 28.00 61559.00 * 0 1 2199 * 20030301 0.00 17.00 64041.00 * 0 1 2066 * 20030401 0.00 19.00 44559.00 * 0 1 1485 * 20030501 0.00 62.00 66196.00 * 0 2 2135 * 20030601 0.00 48.00 26316.00 * 0 2 877 * 20030701 0.00 0.00 0.00 * 0 0 0 * 20030801 0.00 17.00 10647.00 * 0 1 343 * 20030901 0.00 0.00 43803.00 * 0 0 1460 * 20031001 0.00 1.00 50483.00 * 0 0 1628 * 20031101 0.00 7.00 54742.00 * 0 0 1825 * 20031201 0.00 8.00 48988.00 * 0 0 1580 * Page 7 1- Monthly Average Rate Attachment 4 ALIAS CID: IVAN R 44- 36:BELUG -STER Cumulative Oil Prod : 0 Mbbl Cumulative Gas Prod : 9826 MMcf Cumulative Water Prod : 12 Mbbl Cumulative Water Inj : 0 Mbbl Monthly Monthly Monthly Monthly Oil Water Gas Water 4 Oil Water Gas Water Rate Rate Rate Inj Rate Prod Prod Prod Inj (CD) (CD) (CD) (CD) Date bbl bbl Mcf bbl bbl /d bbl /d Mcf /d bbl /d 240367812 Sum 20030651 0.00 19.83 43785.75 0.00 0 1 1445 Average 20040101 0.00 8.00 28129.00 * 0 0 907 * 20040201 0.00 7.00 17943.00 * 0 0 619 * 20040301 0.00 2.00 9370.00 * 0 0 302 * 20040401 0.00 0.00 2749.00 * 0 0 92 * 20040501 0.00 0.00 4038.00 * 0 0 130 * 20040601 0.00 0.00 1132.00 * 0 0 38 * 20040701 0.00 0.00 0.00 * 0 0 0 * 20040801 0.00 0.00 0.00 * 0 0 0 * 20040901 0.00 0.00 0.00 * 0 0 0 20041001 0.00 0.00 0.00 * 0 0 0 * 20041101 0.00 0.00 0.00 * 0 0 0 * 20041201 0.00 0.00 0.00 * 0 0 0 * 240487812 Sum 20040651 0.00 1.42 5280.08 0.00 0 0 174 Average 20050101 0.00 0.00 11114.00 * 0 0 359 * 20050201 0.00 0.00 3902.00 * 0 0 139 * 20050301 0.00 0.00 0.00 * 0 0 0 * 20050401 0.00 0.00 0.00 * 0 0 0 * Page 8 1- Monthly Average Rate Attachment 4 ALIAS CID: IVAN R 44- 36:BELUG -STER Cumulative Oil Prod : 0 Mbbl Cumulative Gas Prod : 9826 MIVIcf Cumulative Water Prod : 12 Mbbl Cumulative Water Inj : 0 Mbbl Monthly Monthly Monthly Monthly Oil Water Gas Water Oil Water Gas Water Rate Rate Rate Inj Rate Prod Prod Prod Inj (CD) (CD) (CD) (CD) Date bbl bbl Mcf bbl bbl /d bbl /d Mcf /d bbl /d 20050501 0.00 0.00 695.00 * 0 0 22 * 20050601 0.00 0.00 0.00 * 0 0 0 * 20050701 0.00 0.00 0.00 * 0 0 0 * 20050801 0.00 0.00 0.00 * 0 0 0 * 20050901 0.00 0.00 0.00 * 0 0 0 * 20051001 0.00 0.00 0.00 * 0 0 0 * 20051101 0.00 0.00 0.00 * 0 0 0 * 20051201 0.00 0.00 0.00 * 0 0 0 * 240607812 Sum 20050651 0.00 0.00 1309.25 0.00 0 0 43 Average 20060101 0.00 0.00 0.00 * 0 0 0 * • 20060201 0.00 0.00 0.00 * 0 0 0 * 20060301 0.00 0.00 0.00 * 0 0 0 20060401 0.00 0.00 0.00 * 0 0 0 * 20060501 0.00 0.00 0.00 * 0 0 0 * 20060601 0.00 0.00 0.00 * 0 0 0 * 20060701 0.00 0.00 0.00 * 0 0 0 * 20060801 0.00 0.00 0.00 * 0 0 0 * 20060901 0.00 0.00 0.00 * 0 0 0 * 20061001 * * * * * * * * 1 20061101 0.00 0.00 0.00 * 0 0 0 * 20061201 0.00 0.00 0.00 * 0 0 0 * Page 9 1- Monthly Average Rate Attachment 4 ALIAS CID: IVAN R 44- 36:BELUG -STER Cumulative Oil Prod : 0 Mbbl Cumulative Gas Prod : 9826 MMcf Cumulative Water Prod : 12 Mbbl Cumulative Water Inj : 0 Mbbl Monthly Monthly Monthly Monthly Oil Water Gas Water ill Oil Water Gas Water Rate Rate Rate Inj Rate Prod Prod Prod Inj (CD) (CD) (CD) (CD) Date bbl bbl Mcf bbl bbl /d bbl /d Mcf /d bbl /d 240727812 Sum 20060651 0.00 0.00 0.00 0.00 0 0 0 Average 20070101 * * * * * * * * 20070201 * * * * * * * * 20070301 * * * * * * * * 20070401 0.00 0.00 0.00 * 0 0 0 * 20070501 0.00 0.00 0.00 * 0 0 0 * 20070601 0.00 0.00 0.00 * 0 0 0 * 20070701 0.00 0.00 0.00 * 0 0 0 * 20070801 0.00 0.00 0.00 * 0 0 0 * 20070901 0.00 552.00 43787.00 * 0 18 1460 * 20071001 0.00 744.00 53979.00 * 0 24 1741 20071101 0.00 582.00 31246.00 * 0 19 1042 * 20071201 0.00 741.00 17685.00 * 0 24 570 * 1 i 240847812 Sum 20070651 0.00 218.25 12224.75 0.00 0 7 401 Average 20080101 0.00 744.00 0.00 * 0 24 0 * 20080201 0.00 696.00 1490.00 * 0 24 51 * 20080301 0.00 744.00 0.00 * 0 24 0 * 20080401 0.00 720.00 0.00 * 0 24 0 * 20080501 0.00 744.00 0.00 * 0 24 0 * Page 10 1- Monthly Average Rate Attachment 4 ALIAS CID: IVAN R 44- 36:BELUG -STER Cumulative Oil Prod : 0 Mbbl Cumulative Gas Prod : 9826 MMcf Cumulative Water Prod : 12 Mbbl Cumulative Water Inj : 0 Mbbl Monthly Monthly Monthly Monthly Oil Water Gas Water Oil Water Gas Water Rate Rate Rate Inj Rate Prod Prod Prod Inj (CD) (CD) (CD) (CD) Date bbl bbl Mcf bbl bbl /d bbl /d Mcf /d bbl /d 20080601 0.00 720.00 803.00 * 0 24 27 * 20080701 0.00 744.00 29184.00 * 0 24 941 * 20080801 0.00 560.00 22118.00 * 0 18 713 * 20080901 0.00 444.00 16805.00 * 0 15 560 * 20081001 0.00 0.00 0.00 * 0 0 0 * 20081101 0.00 0.00 0.00 * 0 0 0 * 20081201 0.00 0.00 0.00 * 0 0 0 * 240967812 Sum 20080651 0.00 509.67 5866.67 0.00 0 17 191 Average 20090101 0.00 0.00 0.00 * 0 0 0 * 20090201 0.00 0.00 0.00 * 0 0 0 * II 20090301 0.00 0.00 0.00 * 0 0 0 * 20090401 0.00 0.00 0.00 * 0 0 0 * 20090501 0.00 0.00 0.00 * 0 0 0 * 20090601 0.00 0.00 0.00 * 0 0 0 * 20090701 0.00 0.00 0.00 * 0 0 0 * 20090801 0.00 0.00 0.00 * 0 0 0 * 20090901 0.00 0.00 0.00 * 0 0 0 * 20091001 0.00 0.00 0.00 * 0 0 0 * 20091101 0.00 0.00 0.00 * 0 0 0 * 20091201 0.00 0.00 0.00 * 0 0 0 * 241087812 Sum Page 11 1- Monthly Average Rate Attachment 4 ALIAS CID: IVAN R 44- 36:BELUG -STER Cumulative Oil Prod : 0 Mbbl Cumulative Gas Prod : 9826 MMcf Cumulative Water Prod : 12 Mbbl Cumulative Water Inj : 0 Mbbl Monthly Monthly Monthly Monthly Oil Water Gas Water • Oil Water Gas Water Rate Rate Rate Inj Rate Prod Prod Prod Inj (CD) (CD) (CD) (CD) Date bbl bbl Mcf bbl bbl /d bbl /d Mcf /d bbl /d 20090651 0.00 0.00 0.00 0.00 0 0 0 Average ill Page 12 1- Monthly Average Rate Attachment 4 Westside Ivan 44 -36 -- Sterling Beluga P/Z vs Cum Production Plot 4000 3500 • • 3000 - • 2500 - OGIP = 3.9 bcf nearly depleted x'2000 - N i� 1500 - 1000 _ • 500 - 0 0 5 10 15 Cum Gas Produced, bcf y = - 884.89x + 9188.2 Attachment 5 Material Balance Plot • • hevro IRU 44 -36 Well R U 4s 36 Ivan ` r Actual Wellbore Schematic . � r l ttpieted Q'3'�' RKB: 51' KB: GL: 26.5' MSSL KB•THF: 24' KB Casing and Tubing Detail J , L Size Type WI! Grade Top Bins CONN ! ID Cement 1 Other 20" Sbudual 94#, - Surface 94' - !liven 13-3/8' Surface 68 #, K -55 Surface 908' BTC / 12.415" 115 bbl ! Cmt to Surface 20 c 9-5/8' Surface 47 #, N-80 Surface 3,449' BTC / 8.681' 270 bbl / Cmt to Surface T 29#, N-80 Surface 7,789' BTC 16.184° 115 bbl / Cmt to 4,420' A , 29#, P -110 7,789' 8,308' BTC 16.184° Tubing c 0 « , 2 -7/8' Production 6.4#, 1-80 Surface 7,735' IBT SCC! 2441' Cpig OD = 3.220' 2-3/8" Heater 4.64,1 -80 Surface 2,99(Y IBT SCC! 1 -995' Fluid: Propylene Glycol `t_ "" " Production String Jewelry Detail `''' # Depth (RKB) Length ID OD Item d 2.t3S 1 27 0.30' 2.441 Dual Tubing Hanger, 2 -7 /8' x 2 -318' 10" 5M Vetco Gray (2 -7/8" & 2 -3/8" IBT lift threads) OBL-0C .42":' c 2 3,071' 3.86' 2.313 3.750 Sliding Sleeve, Baker, CMD, 2-7/8" [CLOSED] '.',7. :.. ti Tag 2121X9 3 3,117' 6.40' 2.441 5.980 Packer, FH Retrievable (30K Sheer) 1 4 6,384' 3.85' 2.313 3.750 Sliding Sleeve, Baker, CMD, 2 -7/8' [CLOSED] ,, /..,::,.: , : 5 6,525' 4.71' 2.347 5.970 Packer, Baker SC-2 Ret (Mn ID thru S-22 latch) ; r 6 6,548' 3.87' 2.313 3.750 Sliding Sleeve, Baker, CMD, 2 -7/8' [LEAKING] ;.,. • .r N•4 Fish 1/3 d Pinning Protection Sleeve from 2.5" GR ' • +• 7 6,660' 0.18' - 2100 W . adapter (2.7 OD, /: thick), (lost 2/14/06) 8 6,753' 4.69' 2.347 5.970 Packer, Baker SC -2 Ret (Mn ID t ru S-22 latch) 9 6,805' G -Stop (set 9/5/04) ti { : 10 6,806' - - - Packol (set 9/5 /04) MO. r• ,,r.r i'r`i: } j'.. :l 6 '�' 11 6,807' - - - Separation Tod wf Side Door Choke (set 11/14/01) r {�ti 12 6,807' 3 .87' 2.313 3.750 Sliding Sleeve, Baker, CMD, 2 -718' IBT [OPEN] r 3. k,. 504 13 7,068' 1.14' 2.313 3.500 X Nipple, 2.313' ID, 1' 14 7,107 4.7' 2.347 5.810 Packer, Baker SC-1 Ret (Mn ID l ru S -22 latch) 15 7,127 76 -0' 4.480 5.500 Meshrite sand screen assy. 2 jts at 38' each 4=- - - 16 7,247 3.91' 2.347 5.873 Packer, Baker Model D Perm. , .,, 17 7,701' 1.06' 2.313 3.500 X Nipple, 2.313' ID, (PX Plug set 10/24/01) 9 18 7,735' 0.75' 2.441 3.250 Wirelne Entry Guide 1 18 19 7,815' 438' - 4.500 4 -1/2' TCP Gun, 12 apt (Left in hole 317193) .., a l l 11 12 Perforation Data I. 714 Zone Top Btm Amt apf Comments 58-4 6,431' 6,440' 9' 12,12 4-1/2" TCP (9/4/01), (3/7/93) 1 13 59-6 6,557' 6,568' 11' 12,12 41/2' TCP (9/4/91), (3(7/93) 713 6,836' 6,852' 16' 12.12 41/2° TCP (9/4101), (3/7/93) 74-8 7,117' 7,150' 33' 12 Meshrite Screen, TCP Perf (3/7/93) IN - 753 7,163' 7,184' 21' 12 Meshrite Screen, TCP Perf (3/7/93) 82 -7 7,760' _ 7,772' 12' 12 Isolated below tubing plug, TCP Per( (3/7/93) � R r - 744 .':.+ 754 1s 7" Cement Bond Log (3/5/93) - - 4,400' - 4,600' - Poor 17 4,600' - 4,740' - Fair 4,740' - 8,250' - Good Tagged filUguns 82-7 - 4 7.815'(9:7 :01' • �k,, 19 0C T' g' tr D Data: TD 4,308' PBTD = 8,272' max hole angle = 48.8° at 4,225' MD IRU 44-36 Actual Wei Schematic 2- 21-09.docx Updated by SW 1 -29 -10 Attachment 6 - Current IRU 44 -36 Well Schematic Attachment 7 — Well IRU 44 -36 State Completion Report and Directional Survey State Completion Report Well Drilling History: "IRU 44 -36; API 50- 283 - 20089 -00; PTD: "193 -022" 2/10/93: Spud Well: Grace #154 Rig, • Spud Ivan River Unit 44 -36 @ 2000 hours, February 10, 1993 w/ 17 -1/2" hole. 2/10/93: Drilling Surface Hole: (20" @ 94') • 20" Conductor Driven prior to rig arrival • Drilled 17 -1/2" hole to 916' RKB on 2/12/93. 2/13/93: Run /Cement Surface Casing (20" @ 94') • Ran 908' 13 -3/8" 68# K55 BTC casing. Cement to surface 80 bbl lead / 35 bbl tail. 2/14/93: Drilling Intermediate Hole: (20" @ 94', 13 -3/8" @ 908') • Test casing to 1,500 psi — OK. • Drill out float shoe and open hole t/922' - LOT 26.0 PPG EMW • Directionally drill 12 -1/4" hole t/ 3453' on 2/18/93. 2/20/93: Run /Cement 9 -5/8" Intermediate Casing (20" @ 94', 13 -3/8" @ 908') • Ran 3,449' 9 -5/8" 47# N80 BTC casing. Cement to surface 180 bbl lead / 90 bbl tail. 10/07/93: Drilling 8 -1/2" Production Hole: (20" @ 94', 13 -3/8" © 908', 9 -5/8" @ 3,449') • Test casing to 1,500 psi — OK. • Drill out float shoe and open hole t/3464' - LOT 19.5 PPG EMW • Directionally drill 8 -1/2" hole t/ 8,120' on 2/27/93. • Ran casing caliper inside 9 -5/8" from 0- 3,202'. Minimal wall loss. Test to 4,100 psi — OK. • Ran bond log from 0'- 3,420'. • Directionally drill 8 -1/2" hole t/ 8,308' TD on 3/01/93. 3/03/93: Run /Cement 7" Production Casing (20" @ 94', 13 -3/8" @ 908', 9 -5/8" @ 3,449') • Ran 8,308' 7" 29# N80 BTC and 7" 29# P -110 BTC casing. Cement to 4,400' MD 129 bbl lead. • 0 • Test casing to 1,500 psi - OK. • Tag PBTD at 8,272'. Ran bond log from 3,500' - 8,250'. • Ran TCP guns on 2 -7/8" tubing w/ 2 -3/8" heater string. • Perforate Tyonek zones 6,836'- 6,852', 6,557'- 6,568' and 6,431'- 6,440'. • Dispose of brine down 7" x 9 -5/8" annulus (495 bbl total, 2,300 psi @ 4.8 bpm). • TD = 8,308' MD, 6,438' TVD. • PBTD = 8,272' MD, 6,408' TVD. • Release rig 18:00 hrs 3/09/93. 8/23/01: Workover (20" @ 94', 13 -3/8" @ 908', 9 -5/8" @ 3,449', 7" @ 8,308') • Pull existing completion. • Perforate Tyonek zones 7,760'- 7,772', 7,163'- 7,184', 7,117'- 7,150' and re- perforated 6,836'- 6,852', 6,557'- 6,568' and 6,431'- 6,440'. • Run new completion with multiple packers and sliding sleeves. • Release rig 06:00 hrs 9/13/01. Directional Survey Directional Survey: "Full Survey to TD" MD ft TVD ft TVDSS ft FNUFSL FWUFEL Inc deg Azi deg 0 0.00 51.00 0.00 N 0.00 E 0 0 97 97.00 -46.00 0.31 S 0.28 W 0.5 222 191 190.99 - 139.99 1.23 S 1.11 W 1 222 284 283.98 - 232.98 2.12 S 1.51 W 0.4 154 376 375.97 - 324.97 1.13 S 1.45 W 1.6 356 465 464.89 - 413.89 2.67 N 1.71 W 3.3 356 555 554.67 - 503.67 8.94 N 1.89 W 4.7 360 645 644.26 - 593.26 17.42 N 2.70 W 6.2 351 733 731.60 - 680.60 28.06 N 4.04 W 7.8 355 825 822.70 - 771.70 40.91 N 4.82 W 8.3 358 859 856.30 - 805.30 46.04 N 5.12 W 9.1 355 952 947.90 - 896.90 62.07 N 6.30 W 10.8 356 1,044 1,037.92 - 986.92 81.00 N 7.54 W 13 356 1,135 1,126.19 - 1,075.19 103.02 N 9.27 W 15.1 355 1,227 1,214.49 - 1,163.49 128.71 N 11.83 W 17.5 354 1,319 1,301.68 - 1,250.68 157.90 N 14.81 W 19.7 354 1,411 1,387.65 - 1,336.65 190.41 N 18.69 W 22 352 1,502 1,471.38 - 1,420.38 225.76 N 23.08 W 24.1 354 1,594 1,554.79 - 1,503.79 264.35 N 27.16 W 25.8 354 Attachment 7 • • 1,686 1,636.72 - 1,585.72 306.03 N 30.78 W 28.3 356 1,778 1,716.55 - 1,665.55 351.65 N 33.63 W 31.3 357 1,867 1,791.77 - 1,740.77 399.17 N 35.27 W 33.3 359 1,960 1,868.37 - 1,817.37 451.91 N 35.80 W 35.8 360 2,052 1,941.30 - 1,890.30 507.97 N 35.55 W 39.3 1 2,144 2,010.61 - 1,959.61 568.43 N 34.69 W 42.9 1 2,236 2,077.79 - 2,026.79 631.28 N 33.60 W 43.3 1 2,329 2,146.02 - 2,095.02 694.44 N 31.73 W 42.3 2 2,420 2,212.74 - 2,161.74 756.27 N 29.14 W 43.4 2 2,513 2,280.48 - 2,229.48 819.94 N 26.64 W 43.1 2 2,605 2,347.38 - 2,296.38 883.05 N 24.32 W 43.6 2 2,696 2,412.72 - 2,361.72 946.34 N 22.22 W 44.6 2 2,791 2,479.78 - 2,428.78 1013.62 N 20.64 W 45.6 1 2,883 2,543.81 - 2,492.81 1079.68 N 19.90 W 46.2 0 2,973 2,607.00 - 2,556.00 1143.76 N 19.39 W 44.6 1 3,065 2,672.67 - 2,621.67 1208.18 N 18.72 W 44.3 1 3,158 2,738.89 - 2,687.89 1273.48 N 18.04 W 44.9 1 3,250 2,803.49 - 2,752.49 1338.98 N 18.16 W 45.9 359 3,340 2,865.44 - 2,814.44 1404.26 N 18.67 W 47.1 360 3,400 2,906.67 - 2,855.67 1447.85 N 18.86 W 46.1 360 3,490 2,968.90 - 2,917.90 1512.86 N 18.51 W 46.4 1 3,581 3,031.26 - 2,980.26 1579.14 N 18.17 W 47.1 360 3,672 3,092.91 - 3,041.91 1646.07 N 18.46 W 47.6 360 3,764 3,155.36 - 3,104.36 1713.62 N 19.17 W 46.9 359 3,857 3,219.26 - 3,168.26 1781.18 N 20.05 W 46.3 360 3,949 3,282.82 - 3,231.82 1847.70 N 20.52 W 46.3 360 4,041 3,346.32 - 3,295.32 1914.26 N 21.39 W 46.4 359 4,134 3,410.40 - 3,359.40 1981.64 N 23.09 W 46.5 358 4,225 3,472.87 - 3,421.87 2047.78 N 25.17 W 48.8 358 4,316 3,535.10 - 3,484.10 2114.13 N 27.49 W 46.9 358 4,407 3,597.28 - 3,546.28 2180.51 N 30.45 W 46.9 357 4,498 3,659.11 - 3,608.11 2247.20 N 33.59 W 47.5 358 4,591 3,721.28 - 3,670.28 2316.29 N 36.85 W 48.6 357 4,684 3,783.15 - 3,732.15 2385.66 N 39.94 W 48 358 4,776 3,844.94 - 3,793.94 2453.76 N 42.56 W 47.6 358 4,868 3,906.50 - 3,855.50 2522.09 N 44.94 W 48.4 358 4,959 3,967.40 - 3,916.40 2589.67 N 47.30 W 47.6 358 5,052 4,031.00 - 3,980.00 2657.48 N 49.50 W 46.1 359 5,144 4,095.20 - 4,044.20 2723.37 N 50.59 W 45.4 360 5,235 4,159.26 - 4,108.26 2788.00 N 50.88 W 45.1 360 5,324 4,221.92 - 4,170.92 2851.20 N 50.76 W 45.4 0 5,417 4,286.81 - 4,235.81 2917.82 N 50.42 W 46.1 0 5,509 4,350.72 - 4,299.72 2984.00 N 50.30 W 45.9 360 5,603 4,416.25 - 4,365.25 3051.39 N 50.01 W 45.7 1 5,696 4,481.26 - 4,430.26 3117.88 N 49.31 W 45.6 1 5,785 4,543.26 - 4,492.26 3181.74 N 48.81 W 46.1 0 Attachment 7 • 5,878 4,607.92 - 4,556.92 3248.58 N 48.05 W 45.8 1 5,971 4,673.10 - 4,622.10 3314.90 N 46.89 W 45.2 1 6,064 4,738.63 - 4,687.63 3380.88 N 45.51 W 45.2 1 6,158 4,804.99 - 4,753.99 3447.44 N 44.12 W 45 1 6,251 4,871.04 - 4,820.04 3512.91 N 44.00 W 44.5 359 6,345 4,938.02 - 4,887.02 3578.85 N 45.09 W 44.6 359 6,439 5,004.90 - 4,953.90 3644.89 N 46.76 W 44.7 358 6,532 5,071.96 - 5,020.96 3709.24 N 49.78 W 43 356 6,626 5,141.05 - 5,090.05 3772.83 N 54.17 W 42.4 356 6,719 5,209.56 - 5,158.56 3835.54 N 58.89 W 42.7 356 6,811 5,277.50 - 5,226.50 3897.39 N 63.70 W 42.1 355 6,903 5,345.54 - 5,294.54 3959.11 N 68.67 W 42.5 355 6,995 5,413.37 - 5,362.37 4021.04 N 73.87 W 42.5 355 7,089 5,482.79 - 5,431.79 4084.19 N 79.39 W 42.3 355 7,182 5,551.90 - 5,500.90 4146.14 N 85.19 W 41.7 354 7,275 5,621.66 - 5,570.66 4207.34 N 91.30 W 41.1 354 7,369 5,692.76 - 5,641.76 4268.52 N 97.41 W 40.6 354 7,460 5,762.16 - 5,711.16 4327.09 N 103.25 W 40 354 7,553 5,833.77 - 5,782.77 4386.12 N 109.30 W 39.3 354 7,647 5,906.77 - 5,855.77 4445.05 N 115.13 W 38.8 355 7,738 5,977.94 - 5,926.94 4501.49 N 120.71 W 38.3 354 7,830 6,050.53 - 5,999.53 4557.71 N 126.47 W 37.5 354 7,926 6,126.90 - 6,075.90 4615.58 N 132.40 W 37.1 354 8,020 6,202.17 - 6,151.17 4671.58 N 138.29 W 36.5 354 8,085 6,254.72 - 6,203.72 4709.62 N 142.29 W 35.6 354 8,114 6,278.34 - 6,227.34 4726.35 N 144.04 W 35.3 354 8,206 6,353.66 - 6,302.66 4778.89 N 149.57 W 34.8 354 8,273 6,408.84 - 6,357.84 4816.68 N 153.54 W 34.3 354 8,308 6,437.76 - 6,386.76 4836.30 N 155.60 W 34.3 354 Attachment 7 1 Recompletion Workover Program: Surface Location: Longitude: - 150.7968086° Latitude: 61.24108419° 742' FSL & 777' FEL Sec. 1, T13N R9W SM Total Depth: 8,308' MD (6,437.76' TVD; - 6,386.76' TVDSS) Bottom Hole Location: 4,836.30 feet N; 155.60 feet W Top of Gas Storage Zone: 6,836 feet MD ( -5,245 feet TVDSS) 3,914 feet N, 65 feet W from Surface location Wellbore azimuth: 0.17° Kelly bushing elevation: 51 feet above mean sea level Item and Depth Subsea TVD (RKB) MD (RKB) 20" -43' 94' 94' 13 -3/8" -857' 908' 908' 9 -5/8" - 2,890' 2,941' 3,449' 7" - 6,387' 6,438' 8,308' Top Gas Storage Zone - 5,245' 5,296' 6,836' Base Gas Storage Zone - 5,257' 5,308' 6,852' 1 i • he fro IR1 44 -36 PROPOSED SCHEMATIC PM 51'I®IGU XS' AMSL i .TW; 24' KB Casing and Tubing Detail aas , �a i � . A Size Type Wti Grade Top Btm CONN / ID Cement /Other 20" • •:." a 20" Structural 944, - Surface 94' - Driven 9f 5 ii it , ro ri, 13 -3/8" Surface 68X, K -55 Surface 908' BTC / 12.415' 115 bbl 1 Cmt to Surface a " 9-5/8' Surface 474, N -80 Surface 3,449' BTC / 8.681' 270 bbl / Clint to Surface 13.. r ' , 7" Production ' N-80 Surface 7,789' BTC/ 6.784' 115 bbl / Cmt to 4,420' a 294, P -110 7,789' 8,308' BTC / 6.184' A r ' Q Tubing 4-1+2" 1 Production 1 12.64, L -80 1 Surface 1 6,800' 1 TC -II / 3.958" 1 Cplg OD = 4.932" Production String Jewelry Detail 9 8 Depth (RKB) Length ID OD Item t 3,44, 1 24' 1.0' 3.958 4.500 Tubing Hanger, 4 -112" Vetco Gray 10" 5M 2 2,000' 3.0' 3.813 5.000 Chemical Inj Sub 3.813" ID, 4-1/2" TC -I1 CBI Top: MOO' 3 6,345' 3.5' 3.813 5.000 Sfiging Sleeve. X- profile, 3.813" ID, 4 -1/2" TC -II Z 4 6,400' 5.0' 4.525 5.910 Packer. Baker Premier 5 6,545' 3.5' 3.813 5.000 Sliging Sleeve, X- profile, 3.813" ID, 4 -112" TC -II 3. a 3 6 6,725' 5.0' 4.525 5.910 Packer, Baker Premier 7 6,770' 1.0' 3.813 4.932 X Profile, 3.813" ID , -, 8 6,800' 1.0' 3.950 4.932 Wireline Entry Guide 4 9 7,050' 2.0' - - Cement Retainer y ' — 10 7,107' 4.7' 2.347 5.810 Packer, Baker SC -1 Ret (Min ID thru S -22 latch) e 584 11 7,122' 76.4 4.480 5500 Meshrite sand screen assy. 2 its at 38' each 5 ' , r 12 7,242' 3.91' 2.347 5.673 Packer, Baker Model D Penn. 13 7,701' 1.06' 2.313 3.500 X Nipple, 2.313' ID, (PX Plug set 10/23101) S9b 11 14 7,735' 0.75' 2.441 3.250 Wireline Entry Guide 6 ; 15 7,815' 438' 4.500 4-1/2" TCP Gun, 12 spf (Left in hole 3/7/93) 7 Perforation Data g Zone Top Btm Amt s Comments 713 58-4 6,431' 6,440' 9' 12,12 To be squeezed, TCP Perf (9/4/01), (3/7193) 59-6 6,557' 6,568' 11' 12,12 To be squeezed, TCP Perf (9/4101), (3/7/93) 71 -3 6,836' 6,852' 16' 12,12 TCP Perf (9/4101), (3/7/93) 74-8 7,117' 7,150' 33' 12 To be squeezed, TCP Pert (3/7/93) 75 -3 7,163' 7,184' 21' 12 To be squeezed, TCP Perf (3/7/93) 82 -7 7,760' 7,772' 12' 12 Isolated below tubing plug, TCP Perf (3/7/93) 9 7" Cement Bond Log (3.'5.93) 4.400' - 4.600' - Poor to n 4.600' - 4.740' - Fair S 4.740' - 3.308' - Good 744 11 753 a .y » . , 12' I , e , 14 Taggedtifpms 12 07,lW 1) ,; ,, are 15 7°! ,,it* • ter' ' Directional Data_ TD -8,308' PBTD = 8,272' max hole angle =48.8° at 4,225' MD IRU 44-36 Proposed Well Schematic 3- 24- 11_docx Undated by STP 3 -24 -11 Attachment 8 — Proposed Gas Storage Well Schematic 06- .Jun -96 Unocal Gas Analysis Report Facility: WS IR Meter Number: 7 Date: 4/25/96 Btu /Cf: 1,010.63 Relative Dens: 0.56 CO2: 0.27 H2S: 0.00 N2: 0.22 Methane: 99.40 Ethane: 0.09 Propane: 0.02 Butane: 0.00 N Butane: 0.00 NeoPentane: 0.00 "Pentane: 0.00 NPentane: 0.00 C6: 0.01 UnnormTotal: 103.10 9 Attachment 9 i 4 EG &G Chandler Engineering Model 292 BTU Analyzer t time: Jan.30 02 16:35 Calibration #: 1 1,_.t # :2 Location No. :2046 Standard /Dry Analysis Saturated /Wet Analysis Mole% BTU* R.Den.* GPM ** Mole% BTU* R.Den.* Methane 99.304 1005.32 0.5501 -- 97.576 987.83 0.5405 Ethane 0.077 1.36 0.0008 0.0205 0.075 1.33 0.0008 Moisture 0.000 0.00 0.0000 -- 1.740 0.88 0.0108 Nitrogen 0.263 0.00 0.0025 -- 0.259 0.00 0.0025 ( CO2 ) 0.356 0.00 0.0054 -- 0.350 0.00 0.0053 Total 100.00 1006.7 0.5588 0.0205 100.00 990.0 0.5599 * : Uncorrected for compressibility at 60.OF & 14.730PSIA. * *: Liquid Volume reported at 60.OF. Standard /Dry Analysis Saturated /Wet Analysis Molar Mass = 16.185 16.217 Relative Density = 0.5597 0.5609 Compressibility Factor = 0.9980 0.9979 Heating Value = 23549. Btu /lb 23114. Btu /lb Heating Value = 1008.7 Btu /CF 992.1 Btu /CF Absolute Gas Density = 42.8333 lbm/1000CF 42.9220 lbm /1000CF Wobbe Index = 1326.11 Unnormalized Total : 93.535 Last Calibrated with Calgas of 1057.3 Btu /CF May 05 00 12:26 Cti+ Last Update: GPA 2261 -90. C6+ BTU /CF 5065.8, C6+ lbm /Gal 5.64250, and C6+ Mol.Wt. 92.00. (... f .07._ cv d iga Attachment 10 Ivan River Water Analysis Anions Cations TDS Density CO2 H2S pH Chloride Bicarbonate Sulfate Na Mg Ca Sr Ba Fe K Facility Location Zone Date mg /I g /cm ^3 ppm ppm mg /I mg /I mg /I mg /I mg /I mg /I mg /I mg /I mg /I mg /I Westside IRU 44 -36 5/11/2005 7,286 1.0070 7.47 2,854 1,655 7 1,653 62 99 1 4.0 137.00 814 Westside IRU 44 -36 5/11/2005 7,076 1.0060 8.13 2,323 2,216 38 1,826 61 89 1 3.5 40.00 479 Westside Ivan River Field 8/1/1990 5.40 10,000 Scaling Index and Amount of Scale in Ib /1000bb1 CaCO3 CaSO4.2H2O • 80 100 120 140 80 100 120 140 Facility Location Zone Date 1 A 1 A 1 A I A 1 A I A I A 1 A Westside IRU 44 -36 5/11/2005 0.82 54.63 0.92 60.55 1.03 65.77 1.14 70.64 -3.16 -3.18 -3.18 -3.19 Westside IRU 44 -36 5/11/2005 1.51 68.22 1.54 69.96 1.57 71.35 1.61 72.74 -2.48 -2.50 -2.51 -2.51 Westside Ivan River Field 8/1/1990 Scaling Index and Amount of Scale in Ib /1000bb1 CaSO4 SrSO4 80 100 120 140 80 100 120 140 Facility Location Zone Date I A 1 A I A I A I A I A I A 1 A Westside IRU 44 -36 5/11/2005 -3.23 -3.18 -3.11 -3.02 -3.39 -3.37 -3.35 -3.31 Westside IRU 44 -36 5/11/2005 -2.55 -2.50 -2.43 -2.34 -2.65 -2,64 -2.61 -2.57 Westside Ivan River Field 8/1/1990 Scaling Index and Amount of Scale in Ib /1000bb1 Ba504 CO2 pressure Resistivity 80 100 120 140 80.00 100.00 120.00 140.00 @ 70 F Facility Location Zone Date I A I A I A 1 A ohm /cm Comment Westside IRU 44 -36 5/11/2005 0.31 1.04 0.17 0.70 0.04 0.00 -0.05 0.68 0.91 1.20 1.54 sample 1 Westside IRU 44 -36 5/11/2005 1.00 1.74 0.85 1.74 0.73 1.74 0.64 1.74 0.21 0.33 0.50 0.75 sample 2 Westside Ivan River Field 8/1/1990 • I Attachment 11 IP t 4 Ivan River Field Well 14 -31 SPUD 5/6/75 SUSP 8/18/75 20' 20" 94# @ 421' TTC @ 1238' For 7" CSG. r 2 -7/8' 6.4# N-80 Butt Tubing 10-314" 40.5# X-55 / Baker 3-H Packer at 2903' @ 2037' 1050 SXS / 'F Profile at 2948' (2.312 ID) TrC @ 51' Based on Baker WL Reentry Guide at 2982' Hole Size @ 1318' / w_ Based on Equalization Cement Retainer at 3225' Thru Float Shoe / Isomi Fr Cement Plug 3350' - 3508' Stage Collar @ 4234' 689 SXS 4 Annulus ITC Between (CBL Not Conclusive) -- 6862' - 6882' Sqz'd 200 SX 7" 23, 28 & 29# N-80 Fish #1 BHA Total Length 228' Probably on Bottom at 0,064 @ 7018' 500 SXS 4 Fish #2 2206' of 2 7 /8" D.P. Top @ 7495' Bottom @ 9701' Fish #3 W.O. Assy & D.C.'s Length 380' Top 0 7345' Bottom @ 7725' © Fish #4 2876' 2 -2/3" TBG & 3200' 31/2" D.P. Top @ 3510' Bottom 0 9586' A Cement Plug 7600' - 9927 51/2" Liner 0 10,000' / 1 Cement Plug 10,100' - 10,350' 4 Cement Plug 10,650' - 10,900' _ TD = I 0§ -01-01 Attachment 12: IRU 14 -31 Well Schematic I • jiti° MU 13-31 I to Drill*: I I,„, Chevron Ivan River Una se Senate: ADLO 3637 Field: I Ivan River 1664 API,: 53- 283 - 20086 -00 ORIGINAL RIG Surface Location: W Clpaivaon: Cleo 8 Dis Well ELEVATIONS 687 PSI & 699' FEL 11 Tale1 MOM .575 Sec 1,T13N,R9W,SM pg311 6,1W RIB -01. I' V: ASP4 2,4 � � X: ASP4 359,714 Twg i 3-X 92 1-80, TC-8 4 2450'41 6,373 P (1) 7 Baler Model 49'.1' Dalpp Mir e Set r RKB -MSt. Wes Staus: Active Clap II 51.00 O perator: Chevron Ownership Clenon 100% I GLJASL: 265 Spud Dale: 925192860 PM RKB -M5L: 51.0 other 469 Release Dec 1992; WOYPlugeadl July 1996; CTCO JuVAUg 566 Ceg ' BHP: 8.5 pp Q 4,680' TYD 1197; Plugbec8 Oct 2000; Pad Nov 2000; SL Tag Jul 2007: SL BHT: 85' 6,180 MD Tag Jim 2006 Rig WO Dec 2008 666' Cog Oescription Weight Grade Conn ID „ Top Ben TOC a7'• .. . Structural 20' 94.06 MA Weld 19.124' 166 (7 166' , Driven 12.0 he Cot above DV Surface 1338' 68.06 K-55 BTC 12414 886 0' 666 Surf 45 Ile 801' 2,431' Intermediate 959 47.06 N.80 BTC 8661' 3,460 0' 3,460 Surf 3410 has 0 Production T 2906 N80 BTC 8.14' 10,360 0 10,350' 801' 285 66 DV Color © Liner 5' 15.01 5910 BTC 4 -403 1,547' 80,029' 11,575' 10,026 00 Ms 2,793` MD . Ord bdoe DV - 2873-3,221' Tubing 3172' 921 1-10 TC4I 2292' 5,537' B 5,537 Dea:ryton Depth Leng6h ID OD Tubing Hanger, 3 -12' NSCO Unitised 11' 524, 3 Type F 6li'. 17' 0.49 3000' 11.000' . - 1 T x 5.5' Enneneae SET Eversible Cast' Pace 2757' 400 5.440' 6.023' 2 T Howse 'Foss' DV Caller (0.4 above 8024437) 2,793' 3.85' 6.171' - 3 460 Csg } 3 Baker Model 3'8-1' Packer ad sad bons (4216TVD) 5,458' 7.00 4.000' 5.688' 4 X Prone 5,503' 1.55 2.753 3.875' 5 Wlreline Entry Guide 5,537' 0.84' 2992' 3.813' 6 Squeeze packer al l0 cement op (6180) logged 6,190 200 - - 7 Cut 2 -79' tubing 2/d radial loch 6,204' - 2.441' 3.220' 8 Badge Plug 2/d 20' cement dump bailed on lop (1480) 7,400 - - - TOC (USrT Log) 9 Cement Retainer d Mon op (6196) 9,622' - - - 3,/53' MD k l t l.; I I 10 Punch holes (Pushed 7(96) 10,018' 208' - - -9-1 4 2,937 TVD l l I l 11 TtW Seal assembly 10,037' 4.00 - - ( 0 12 Punch holes (Punched 7/96) 10,080' 2.00' - - l 13 Baker model T1' now mode 11,120' 120 2.257' - 14 Baker TCP gone (not lagged) 7 103.00' Top hg Zone 5,544' MD ` : {: 4,277 TJD Box kg zone 6483' MD .. d,fi81' NO .Z61., - = ® Zane Top Wm Mal Gun Sue SPF Phase Status Dale TOC (Tagged)_ +_ 0 SteringIBeII stTyosek 6.233 MD --i 0 A Who 60-2 6,882' 6,905' 23' 1 -11716 6 0 leo 11 ?00 :Abandoned) 4,714' Tit = 7,7 7: {8 - '_ 0 8 Whoa 73-2 7,322' 7,335 13' 1 -11116 6 0 ho 11100 ;Abandoned) 1 a# - C Beluga 74-8 7,480' 7,490 10 2 -19 3 45 Ise 10 ?00 ;Abandoned) D Beluga 75 -3 7,537 7,559 27' 2 -89 3 45 Iso 10/00 ;Abandoned) 7,420 BP + © E Beluga 75.7 7,570' 7,991' 21' 2.19 3 45 Iso 10/00 ;Abandoned) — 1. 8 r.` ... F Tyo ek 11,206' 11,238' 30 2 -79 6 60 Iso 7/96 (Abandoned) . fir • 1 't) -.= 0 G Tyo ek 11,272' 11,296 24' 2 -79 6 60 ale 796 (Abandoned) W • _ ® H Wading 6,160' 6,180' 20 2 -12 s so O 1298, H)gpJ02506 ., - 20 2 -12 6 60 Open 12188, PJ Omega 2506 9,622' We e ' - m 10,026 TOL I • 10,350 Csg - al IM I _ _L. . , r 11,575 Csg - \ 11,575' ID Coma Sketch Post Rig Workaver on 12/11/08 Pepred By: 524 Pothole Attachment 13: IRU 13 -31 Well Schematic • • 1 Chevron )RU 11-06 Ivan River Unit Permit W : Lease ' 206-1184 84 Lease 8 Serilla A 8 10 Field: I Nan River Unit APIA: 50- 283 - 20130 -00 ORIGINAL RIG Surface Location' Wet ClassmWlon: Development Gas Well ELEVATIONS 585' FSL 8 630' FEL Total Depth: 10,060' Sec 1.113N- R9W,SM PBTD: 9,926' R)B -GL T X: ASP4 359,785 Tubing: 3-K", 920, L-80, EIT -Mod 16.80' I V: ASP4 2,646,275 Tubing: 2 -56', 468, L- 80,18T(SCC) RKB-MSL — - — Wel Status: Shut -In Prod Pkrs: (1) 7" Baker Model *SC -2" Mechanical Set Phu 46.80' LI Operator: UOCC Ownership: Union 04 Company of Cal6oma 100% - GL -MSL: 30.00' Spud Date: 12/22/08 2108 2:10 PM 171' Cs9 .. RKB -MSL: 46.80' Other: Spud Dec 2008: Rig Release Feb 2009 Cot Tubitg Mar 2008. Top Job BHP: 3698 psi a 10,060' MD Sl oktne Apr 2008 150 ppt'67 BHT: 134° 10,060'MD Primary Cmt I 130pp9552sr L.... - Description We/gM Grade Conn ID Length Tap SOn TOC tin 1,01E Csg Stuchsal 20" 1290a X -56 Weld 19.124" 171' 0' 171' Driven 165115 Cmt above DV - Surface 13 3/7 68.08 L-80 BTC 12.415' 1,01E 0 1,016' Surf 911lrs 900- 3,487' intermediate 95/8" 40.06 L-80 BTC 8.681' 6,015 0 6,015 900' 163.5115 12.5 ppg 642 so Production r 2606 L -80 BTC -Mod 6277 4,195' 5,825' 10,000' 6,118' ODtas DV Collar I . J I El 3.487' MD Cod below DV 4,1006,120' Tubing 3 1/2" 9 L -80 IBT -Mel' 2.997 9,495 0' 9495' 12.0 ppg 397 sx • 2 3/8" 4.66 L -80 ET 1.995" 3,501' 0 3.501' d © • - SCC S. al Clearance C• •I is � 1 ~ - Description -� Depth 1—v ID OD . ` I �l a I• © 1 Tubing Hanger, 3 -1/2' NSCO Untread 11" 5M, 3" Type H BPV 17' 0.45' 3.000" 11.007 , s - rim I 2 Hatburton Type 'H' ES DV Collar (Closed 1/16109) 3,487' 2.80 8681' 10.625" = j ' Q 3 9 -5/8' Baker 2XP packer (set 2/4/09) 5,825 1853• 6287 8.317 4 9- 5/8"x7' Baker Flex- Lock III liner hanger (set 2/4/09) 5,844' 965 6276" 8.317 -' 5 Baker Model "SC -2" Retrievable Packer (set 2/10/09) 5,915' 5.45' 4.007 5.967 • U 6 Baker Model 8040 Sealbore w/ GBH -22 Seal Assembly 5,920 9.07 4.007 57/07 6,015 Csg ` , 7 HalNwrion OuraSleeve Sliding Sleeve (Closed 4/3/09) 5,970 4.54' 2.817 4.507 8 Haltbuebn Ported Sub w/ Glass Disk 9,416' 069 2997 4.187 _ 9 Hall481100 WLEG w/ TCP Auto- Release 9,483' 1207 2992" 4250" TOC (USD Log) 10 Inflatable BP (tagged 36' deeper man setting depth 7 /15/09) 9,666' 13.1' 6,110 MD . ,. 11 HaaWfton 4 -5/8" TCP Assembly (Pert 4/4/09, Tagged 4 /6/09) 9,71E 214.00 - 4625 4,997 TVD 12 PBTD - Top of 7' Float equipment (Tagged 26/09) 9,926' - - - - 120ppg 432 sx ' Description (Heat String) a Mule shoe cut on pint, 2 -3/7 TUbbg - - - Zone Top I Btm 1 Amt 1 Gun Sin SPF Phase IStatus Date Sterang/Beluga/Tycnek A Tyonek 9.545' 9,576' 31' 4 -5/8" 6 60 Open 4/409 Repent 5/10/09 A Tyonek 9,587 9,609 27' 4 -5'8' 6 60 Open 4/4109Repesf 5/10109 „, '1 B Tyonek 9,648' 0.698' 50' 4 -518' 6 60 Open 4/409 Isolated ?? • • =I lil i `fit m 4 4 i II 10.060' TD MUD 10.1 ppg Current Well Schematic 941 -06 Prepared By Chris Kanyer Attachment 14: IRU 11 -06 Well Schematic ill III hevro IRI 41 -01 ~'.../ Actual W Vellbore Schematic '4 :51' KnANSt rl r r "` - ' "' K" Casing and Tubing Detail 1F Size Type MI Grade Top Btm CONN / ID Cement I Other 20" Structural 94# Surface 165' Driven 13 -3/8" Surface 680, K-55 Surface 895' Butt 1 12.415" 212 bbl I Cmt to Surface 470, N-80 Surface 144' Butt / 8.681' ii 9-518' Surface 470, S-95 144' 3,498' Butt / 8.681" 281 bbl I Celt to Surface 7" Liner 29#, N-80 Surface 9,152' Butt 16.184' 171 bbl / Cmt to 5,000' t ifi5 Tubing 2 -7/8" Production 6.4#, N-80 Surface 8,693' IBT- Mod2.441' A 1 -1/T Heater 2.75#, J-55 Surface 2,994' 10RD Fluid: Propetyne Glycol 1344$' B N ./ .' - Production String Jewelry Detail x # Depth (RKB) Length ID OD Item 1 2420' Dual Tubing Hanger, 2 -7/8' x 2 -3/8° 12' 5M National (2 -7/8' & 2 -3/8' 8RD lift threads) 2 2,988' 4.00' 2.313' 3.75' Baker CMU Sliding Sleeve 3 3,034' 5.71' 2.441' 5.968' Baker FH Retrievable Packer (40K shear) q „ •;' .. ,1 4 8,628' 0.66' 2.441' 3.75' XO, 2 -7/8' IBT Box x 3-12” EUE 8RD Pin 7 4a3' Baiter 3H Packer w/ mill out extension (Min ID 5 8,629' 4.78' 3.2 5.968' thru Anchor Latch Sea! Assembly) 6 8,640' 0.84' 2.441" 5.00" XO, 4-12' 8RD Box x 2 -7/8" IBT Pin 7 8,643' 0.67' 2.441" 3.50° Baiter "RA" Sub 8 8,650' 1.24' 2250" 3.50' Baker R Profile w/ No-go 9 8,659' 0.63' 2.441" 3.687' Baiter Ported Sub w/ glass disc 10 8,693' 0.82' 2.441" 3.687' Tubing Tail 11 8,895' (est) 183' 3.687' _ FISH: Baker TCP Drop Off Guns Perforation Data ZONE TOP BTM Shot Condition 8,710' 8,725' 12 spf Perfed 1/26/93 Tyonek 8,745' 8,768' 12 spf Perfed 1/26/93 83 8,803' 12 spf Perfect 1/26/93 8,815' 8,875' 12 spf Perfed 126/93 • Ran Expro Camera 7/15/09 to investigate tubing tail obstruction. Tool stopped in 6' pup ' I joint between Baker RA Sub & R Profile. • • Ran RST log above production packer from 8.634' - 5,000' on 7/15/09. = t J • Tagged fill at 8,851' RKB w/ 1.25" GR on 1" knuckled tool string on 7/22/09. • Packer fluid between packers consists of 10% KCL Brine (8.9ppg). ;; • Heater string fluid consists of glycol for freeze protect. t• ..f 1 laggea fill if ..r & AM1' 44.?? 074 , ^.,, r te -. , , it J "[J 4157 TD - PRTD= 9,078' IRU 41-01 Actual Well Schematic 7- 22- 09.doc Updated by STP 12 -14 -09 Attachment 15: IRU 41 -01 Well Schematic • • hevro Ivan River Unit IRU 44 -41 ,,' DV .,., ; ,,, Casing and Tubing Detail — i Size Type WV Grade Top Btm CONN / ID Cement I Other 22' Structural 100* Surface 314' Butt 660 sxs 13-3/8" Surface 61$, Surface 1,999' 8RD 1 12.415° 3,285 sxs 9-5/8" Surface 43.5* P Surface 8,948' Butt & 8RD 1' 1,000 sxs 110 &N 8D Tubing 2 -718' Production 6.4$, N -80 Surface 8,693' SC Butt/2.441" • 2 -318" Heater 2. 75$. J -55 Surface 2,994' SC Butt/1.995" Fluid: Propelyne Glycol 3 s , Production String Jewelry Detail a 4 Depth (RKBI Leng ID OD Item 1 3,005' 3. 97' 2.31" 3.75" Baker CMU Sliding Sleeve (WON'T OPEN) 1 2 3,050' 8.55' 2.441' 8.437" Baker FH Packer 3 7,657' 8.95' 4.00" 8.437" Baker FH Packer 4 7,697' 0.9' 225" 3.5' Baker R Nipple 5 7,831' 4.12' 4.75" 8.44" Baker SC -1 Packer (leaking) 6 7.894' 80.86' 4.75" Gravel Pack w/ 20 -40 sand 7 7 955' 6.36' 4.75" 8.125" Baker Model D Packer 1338 8 8.665' Bridge Plug is I X99 9 8,885' Squeeze Packer iHl' IN ':' ' 1 r 1',.: 4,11' iw °.\I FV ' `'"' Perforation Data ZONE TOP BTM Shot Condition 7,905' 7.955' 1.16' Open behind gravel pack ' Tyonek 8,715' 8,730' 12HPF Isolated 8,780' 8,785' 12HPF Isolated lll r.. aw,.lo.•w , of Iluv All SI u 46,11" il L . 4 , t , TD = 15269' PB TD .8.885' Will 44 -01 Actual Well Schematic 2- 17-09.doc Updated by CVK Attachment 16: IRU 44 -01 Well Schematic