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DIO 035
• 0 INDEX DISPOSAL INJECTION ORDER NO. 35 Sterling Formation Ivan River Unit Well 13-31 1. September 8, 2008 Unocal's application for Disposal of Class II Oilfield Waste by Underground Injection for Ivan River 13-31 2. September 11, 2008 Notice of Hearing -Anchorage Daily News, Affidavit of Publication, and mailings 3. October 20, 2008 AOGCC e-mail to operator requesting additional information 4. November 8, 2008 Unocal's revised application for Disposal of Class II Oilfield Waste by Underground Injection for Ivan River 13-31 5. December 4, 2008 Unocal's 2nd revised application for Disposal of Class II Oilfield Waste by Underground Injection for Ivan River 13-31 6,-------------------- Maps generated by AOGCC 7. December 10, 2008 Unocal's request to dispose precipitation in IRU Well 13-31 (DIO 35-001) 8. February 13, 2009 Unocal's request for authorization for emergency disposal at Ivan River Disposal Wells 9. ---------------------- Annual Reports 10. May 26, 2009 E-mail re: construction requirements into IRU 13- 31 well INDEX DISPOSAL INJECTION ORDER NO. 35 • • 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 California for disposal of Class II oil field wastes by underground injection in the Sterling Formation in Ivan River Unit We1113-31, Section 1, T13N, R9W, S.M. Disposal Injection Order No. 35 Sterling Formation Ivan River Unit Well 13-31 December 9, 2008 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 9th day of December, 2008. BY DIRECTION OF THE COMMISSION ~olombie 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 Company of California for ) disposal of Class II oil field wastes ) by underground injection in the ) Sterling Formation in Ivan River ) Unit We1113-31, Section 1, T13N, ) R9W, S.M. ) IT APPEARING THAT: Disposal Injection Order No. 35 Sterling Formation Ivan River Unit Well 13-31 December 9, 2008 Union Oil Company of California (Union), a wholly owned indirect subsidiary of Chevron Corporation, requested that the Alaska Oil and Gas Conservation Commission (Commission) issue an order authorizing underground disposal of Class II oil field waste fluids into the Sterling Formation through Ivan River Unit (IRU) Well 13-31. The application was received by the Commission on September 8, 2008. 2. In accordance with 20 AAC 25.540, notice of opportunity for a public hearing was published in the ANCHORAGE DAILY NEWS on September 11, 2008, on the State of Alaska Online Notices on September 9, 2008, and on the Commission's Web site on September 9, 2008. The scheduled hearing date was October 21, 2008. 3. The Commission did not receive any comments, protests or requests for a public hearing. 4. The public hearing was vacated on October 20, 2008. 5. The Commission requested clarification of certain items on October 20, 2008. Union responded on November 3 and November 8, 2008 with clarifications. 6. The information submitted by Union and public well history records for IRU wells are the basis for this order. Disposal Injection Order 35 ~ ~ Page 2 of 8 IRU 13-31 December 9, 2008 FINDINGS: L Location of Adjacent Wells (20 AAC 25.252(c)(1)) IRU Well 13-31 is a gas development well drilled in 1992 to a total depth of 8167 feet true vertical depth (TVD) (11,575 feet measured depth (MD)). The surface location is in Section 1, Township 13N, Range 9W, Seward Meridian (S.M.) (682 feet from south line, 699 feet from east line). The bottom hole location is in Section 31, Township 14N, Range 8W, S.M.. IRU Well 13-31 penetrates the injection zone within Section 1. Six wells were constructed to develop gas reserves within the IRU; all wells are active except for one plugged and abandoned well. Two IRU wells penetrate the proposed injection zone within a'/4-mile radius of IRU Well 13-31. 2. Notification of Operators/Surface Owners (20 AAC 25.252(c)(2) and 20 AAC 25.252(c)(3)) Union is the only operator and the State of Alaska is the only surface owner within a '/4-mile radius of the proposed disposal well. 3. Geological Information on Disposal and Confining Zones (20 AAC 25.252(c)(4)) The proposed disposal injection interval lies within the Sterling Formation, and it extends from 4272 feet to 4681 feet TVD (5544 feet to 6183 feet MD) in IRU Well 13-31. This interval consists of a series of very fine- to coarse-grained sandstone and conglomerate beds that are generally rich in metamorphic and igneous lithic grains and commonly contain tuffaceous matrix. The proposed disposal interval is divided into three major members that are each about 125 true vertical feet thick. These members are separated by intervals of interbedded tuffaceous mudstone, sandstone, and coal have an aggregate thickness of about 20 true vertical feet. Upper confinement for the disposal injection interval is provided by a stacked sequence of siltstone, mudstone, and coal that extends from approximately 4254 feet to 4272 feet TVD (5515 feet to 5544 feet MD) (i. e., about 20 true vertical feet thick). Lower confinement is provided by a sequence of coal, mudstone, claystone, and siltstone. This sequence extends from 4681 feet to 4696 feet TVD (6183 to 6207 feet MD) (i. e., about 15 true vertical feet thick). Additional upper confinement is provided by the thick sequence of mudstone and siltstone between 3469 feet and 3643 feet TVD (4290 and 4560 feet MD) (i. e., about 270 true vertical feet thick). The thick coals and abundant mudstone beds of the lowermost Sterling, between 4824 feet and 5220 feet TVD (6435 and 7030 feet MD)( i. e., about 400 true vertical feet thick), will provide additional lower confinement. 4. Evaluation of Confining Zones (20 AAC 25.252(c)(9)) The injection of drilling mud and slurried cuttings will require pressure sufficient to fracture the formation. Union used fracture modeling to predict fracture behavior for IRU Well 13-31 disposal injection. The results were included in the disposal injection order application. Rock property information used in the fracture model was obtained from log data generated Disposal Injection Order 35 • ~ Page 3 of 8 IRU 13-31 December 9, 2008 during the drilling of IRU 13-31 and other nearby IRU wells. The fracture modeling included a base case run with the expected injection rate, slurry density, injected volume, and injection operating practice. Numerous model runs were performed -including runs simulating extreme conditions - by varying the injection rate, slurry density, and injected volume to test the sensitivity of these parameters on fracture geometry. The fracture modeling predicts maximum fracture heights up to 100 feet true vertical thickness and a maximum half-length up to approximately 1000 feet. Using injection rate, slurry density, and injection volumes that are expected to occur in IRU 13-31, Union's fracture modeling predicts a fracture height up to 60 feet true vertical thickness and a fracture half-length up to nearly 800 feet. Commercial gas production at IRU occurs from the Tyonek, Beluga, and Lower Sterling Formations. The shallowest gas production occurs from the lowermost Sterling Formation in IRU We1144-36. The shallowest productive strata lie about 200 true vertical feet deeper than the base of the proposed injection interval in IRU Well 13-31. 5. Standard Laboratory Water Analysis of the Formation (20 AAC 25.252(c)(10)); Aquifer Exemption 20 AAC 25.252(c)(11)) The Commission issued Aquifer Exemption Order (AEO) 6 on July 23, 2001 and amended it as AEO 6A on December 5, 2008. AEO 6A extends the approved aquifer exemption depth interval to include portions of the freshwater aquifers between 2340 feet and 4202 feet TVD (2500 feet and 5435 feet MD) in, and within a '/z-mile radius of, IRU Well 14-31, which is the reference well for AEO 6 and AEO 6A. The equivalent depth range in IRU Well 13-31 is from about 2365 feet to 4681 feet TVD (2530 feet to 6183 feet MD). IRU Well 13-31 disposal injection will occur within the aquifer exemption area established in AEO 6A. 6. Well Logs (20 AAC 25.252(c)(5)) Log data from IRU Well 13-31 are on file with the Commission. Union provided a type log for IRU Well 13-31 illustrating the proposed injection and confining zones. 7. Demonstration of Mechanical Integrity and Disposal Zone Isolation (20 AAC 25.252(c)(6)) IRU Well 13-31 produced 14.3 billion cubic feet of gas before it was shut in December 2007. The well is constructed as follows: 20-inch conductor casing driven to 166 feet TVD (166 feet MD); 13-3/8-inch surface casing set at 866 feet TVD (866 feet MD); 9-5/8-inch intermediate casing set at 2938 feet TVD (3460 feet MD); 7-inch production casing set at 7352 feet TVD (10350 feet MD); and 5-inch liner installed from 7113 feet to 8167 feet TVD (10,028 feet MD to 11,575 feet MD). The well's plug-back depth is 5435 feet TVD (7400 feet MD).1 Union will perform a well workover to pull the production tubing and packer, install a casing patch across a leaking casing collar, and reinstall the tubing and packer. The injection completion will consist of 3.5-inch tubing run to 4260 feet TVD (5525 feet MD) ~ A slickline survey of the well in June 2008 found fill above the tubing plug-back at a depth of 4770 feet TVD (5561 feet MD). Disposal Injection Order 35 • IRU 13-31 December 9, 2008 Page 4 of 8 and permanent packer installed at 4212 feet TVD (5450 feet MD), thereby establishing the Sterling Formation as the intended zone for Class II waste disposal injection. Union reports that the 7-inch casing in IRU Well 13-31 is cemented from surface to the 9- 5/8-inch casing shoe at 2938 feet TVD (3460 feet MD), and from 3925 feet to 7352 feet TVD (5000 feet to 10,350 feet MD). Cement bonding in the 7-inch casing section opposite the injection and confining layers was not evaluated during well construction. The reported cement top of 3925 feet TVD (5000 feet MD) was calculated from the volume of cement pumped and an assessment of the cement placement operation. Union plans to run a bond log from 2340 feet to 4710 feet TVD (2500 feet to 6250 feet MD) to evaluate the cement integrity adjacent to the upper confining, injection and lower confining zones prior to installing tubing and packer. A mechanical integrity test will be performed before injection commences and, after injection is begun, as required by the Commission. Union indicates it will comply with the Commission's requirements for testing, monitoring, and reporting waste slurry injection activities. 8. Disposal Fluid Type Composition Source Volume and Compatibility with Disposal Zone (20 AAC 25.252(c)(7)) IRU Well 13-31 will be the second active waste disposal well located on the IRU drillsite. Union intends to use IRU Well 13-31 to dispose of drilling, production, completion, workover wastes, and other associated wastes that are intrinsically derived from primary field operations. Union projects the injection volume into IRU Well 13-31 could be as much as 1,135,000 barrels of Class II wastes over the expected life of the well. Union expects the injection to occur in daily batch volumes averaging 155 barrels and not exceeding 1000 barrels, with rates up to 4 barrels per minute. Fracture modeling evaluated the effect of injection rates up to 4 barrels per minute, injected batch volumes up to 2500 barrels per day, and fluid densities up to 10.1 pounds per gallon. No compatibility concerns relating to the injected fluids and in-situ formation fluids have been identified by Union in connection with the injection of a similar waste fluid stream into the Sterling Formation at the nearby IRU Well 14-31. To date, Union has injected more than 45,500 barrels of Class II wastes into IRU Well 14-31. 9. Estimated Injection Pressures (20 AAC 25.252(c)(8)) Union estimates that the average surface injection pressure will be between 1800 psig and 2800 psig. The maximum surface injection pressure could reach 5000 psig if sporadic plugging of perforations or fracture flow channels occurs. 10. Mechanical Condition of Wells Penetrating the Disposal Zone Within a '/4-Mile Radius of IRU Well 13-31 (20 AAC 25.252(cZ 12)) IRU Well 14-31 and IRU Well 44-36 penetrate the Sterling disposal injection zone within a '/4-mile radius of IRU Well 13-31. Union's review of well construction records shows that Disposal Injection Order 35 IRU 13-31 December 9, 2008 Page 5 of 8 both wells are cased and cemented to prevent the movement of injected fluids beyond the well's confinement zones. Records documenting the drilling, casing, cementing, and testing of these wells are in the Commission's files. CONCLUSIONS: 1. The 20 AAC 25.252 requirements for approval of an underground disposal application are met. 2. The Sterling disposal zone is approximately 400 true vertical feet thick. Upper confinement is provided by a stacked sequence of siltstone, mudstone and coal that is laterally continuous throughout the affected area. Lower confinement is provided by a sequence of coal, mudstone, claystone, and siltstone that is laterally continuous across the affected area. No significant faults are present in the vicinity of the proposed operations. Although these confining intervals are relatively thin, well log correlations indicate they are laterally continuous throughout the affected area. Additional upper confinement is provided by an overlying, 270-foot thick sequence of mudstone and siltstone, and additional lower confinement is provided by about 400 feet of underlying coal and mudstone in the lowermost Sterling. 3. AEO 6A exempts from underground sources of drinking water freshwater aquifers between 2365 feet and 4681 feet TVD (2530 feet and 6183 feet MD). 4. Commercial gas accumulations are sufficiently separated and isolated from the proposed injection zone that IRU gas production should not be adversely affected by the proposed IRU Well 13-31 disposal operations. 5. Injected fluids should be compatible with the lithology and resident water of the injection zone. This conclusion is based on operating experience and data from disposal injection within the Sterling Formation at IRU Well 14-31 involving similar materials and performance parameters (e.g., pressures, rates, and volumes). There have been no reported compatibility issues associated with disposal injection into the Sterling Formation at other fields in the Cook Inlet area. 6. Based on the fracture modeling results, including the extreme case sensitivities considered for injection into IRU Well 13-31, reasonable grounds exist to conclude that waste fluids should be contained within the receiving interval by the confining lithologies within the Sterling Formation, cement isolation of the well bore, and operating conditions. 7. Modeling predicts a zone of influence (i. e., waste plume area) for injected materials equal to a fracture domain potentially extending up to 1000 feet laterally from the well. An area of review within a 1/4-mile radius of IRU Well 13-31 is appropriate given the fracture modeling results. The wells penetrating this area have sufficient mechanical integrity to prevent the migration of fluids from the proposed IRU Well 13-31 injection zone. Disposal Injection Order 35 • IRU 13-31 December 9, 2008 • Page 6 of 8 8. Disposal injection operations in IRU Well 13-31 as described and modeled are not expected to fracture through the confining zones. Therefore, oil field wastes injected into IRU Well 13-31 should be confined to an isolated zone within the Sterling Formation. 9. Supplemental mechanical integrity demonstrations and the surveillance of injection operations-including baseline and subsequent temperature surveys, monitoring of injection performance (i. e., pressures and rates), and analyses of the data for indications of anomalous events-are appropriate to ensure that waste fluids remain within the disposal interval. NOW, THEREFORE, IT IS ORDERED THAT disposal injection is authorized into the Sterling Formation within Ivan River Unit Well 13-31 subject to each of the following requirements: RULE 1: Infection Strata for Disposal The underground disposal of Class II oil field waste fluids is permitted into the Sterling Formation within IRU Well 13-31 in the interval from 4272 feet to 4681 feet TVD (5544 feet to 6183 feet MD). The Commission may immediately suspend, revoke, or modify this authorization if injected fluids are not confined by the upper and lower confining zones. RULE 2• Fluids This authorization is limited to Class II oil field waste fluids generated during drilling, production or workover operations. RULE 3: Infection Rate and Pressure Disposal injection is authorized at (a) rates that do not exceed 4 barrels per minute and (b) surface pressures that do not exceed 5000 psig. RULE 4: Demonstration of Mechanical Inte~ritV The mechanical integrity of IRU Well 13-31 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 IRU Well 13-31. That test must be performed when injection conditions (temperature, pressure, rate, etc.) have stabilized. Subsequent mechanical integrity tests must be performed at least once every two years after the date of the first Commission- witnessed test. The Commission must be notified at least 24 hours in advance of each such test to enable a representative to witness the test. Unless an alternate means is approved by the Commission, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test that meets the following conditions: (1) uses a surface pressure of either 1,500 psig, or 0.25 psig/ft multiplied by the vertical depth of the packer, whichever is greater; (2) shows stabilizing pressure; and (3) does not change more than 10 percent during a 30-minute period. The results of all mechanical integrity demonstrations and Union's interpretation of those results shall be provided to the Commission and be readily available for Commission inspection. RULE 5: Well Integrity Failure and Confinement Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by the injection rate, an operating pressure observation, a test, a survey, a log, or any other Disposal Injection Order 35 • IRU 13-31 December 9, 2008 • Page 7 of 8 evidence, the operator. shall notify the Commission by the next business day and submit a plan of corrective action (on Form 10-403) for Commission approval. The operator shall immediately shut in the well if continued operation would be unsafe or threaten contamination of freshwater, or if so directed by the Commission. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for IRU Well 13-31 indicating any well integrity failure or lack of injection zone isolation. RULE 6: Surveillance The operator shall run a baseline temperature log and perform a baseline step-rate test prior to initial injection. A subsequent temperature log must be run one month after injection begins to delineate the receiving zone of the injected fluids. Surface pressures and rates must be monitored continuously during injection for any indications of anomalous conditions. Results of daily wellhead pressure observations in IRU Well 13-31 must be documented and available to the Commission upon request. The conduct of subsequent temperature surveys or other surveillance logging (e.g., water flow; acoustic) will be based on the results of the initial and follow-up temperature surveys and injection performance monitoring data. A report evaluating the performance of the disposal operation must be submitted to the Commission by July 1 of each year. The report shall include data sufficient to characterize the disposal operation, including, among other information, the following: injection and annuli pressures (i. e., daily average, maximum, and minimum pressures); fluid volumes injected (i. e., in disposal and clean fluid sweeps); injection rates; an assessment of the fracture geometry; a description of any anomalous injection results; and a calculated zone of influence for the injected fluids. RULE 7: Notification of Improper Class II Infection The operator must immediately notify the Commission if it learns of any improper Class II injection. Complying with the notification requirements of any other local, state or federal agency remains the operator's responsibility. RULE 8: Administrative Action Unless notice and public hearing are otherwise required, the Commission may administratively waive or amend any rule stated above as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in fluid movement outside of the authorized injection zone. Disposal Injection Order 35 IRU 13-31 December 9, 2008 Page 8 of 8 RULE 9: Compliance Operations must be conducted in accordance with the requirements of this order, AS 31.05, and (unless specifically superseded by Commission order) 20 AAC 25. Noncompliance may result in the suspension, revocation, or modification of this authorization and other penalties. ENTERED at Anchorage, Alaska, and dated December 9, 2008. oerster, Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the Commission by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Mary Jones David McCaleb Cindi Walker XTO Energy, Inc. IHS Energy Group Tesoro Refining and Marketing Co. Cartography GEPS Supply & Distribution 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 300 Concord Plaza Drive Ft. Worth, TX 76102-6298 Houston, TX 77056 San Antonio, TX 78216 George Vaught, Jr. Jerry Hodgden Richard Neahring PO Box 13557 Hodgden Oil Company NRG Associates Denver, CO 80201-3557 408 18th Street President Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 Mark Wedman Schlumberger Ciri Halliburton Drilling and Measurements Land Department 6900 Arctic Blvd. 2525 Gambell Street #400 PO Box 93330 Anchorage, AK 99502 Anchorage, AK 99503 Anchorage, AK 99503 Baker Oil Tools Ivan Gillian Jill Schneider 4730 Business Park Blvd., #44 9649 Musket Bell Cr.#5 US Geological Survey. Anchorage, AK 99503 Anchorage, AK 99507 4200 University Dr. Anchorage, AK 99508 Gordon Severson Jack Hakkila Darwin Waldsmith 3201 Westmar Cr. PO Box 190083 PO Box 39309 Anchorage, AK 99508-4336 Anchorage, AK 99519 Ninilchick, AK 99639 James Gibbs Kenai National Wildlife Refuge Penny Vadla PO Box 1597 Refuge Manager 399 West Riverview Avenue Soldotna, AK 99669 PO Box 2139 Soldotna, AK 99669-7714 Soldotna, AK 99669-2139 Richard Wagner Cliff Burglin Bernie Karl PO Box 60868 PO Box 70131 K&K Recycling Inc. Fairbanks, AK 99706 Fairbanks, AK 99707 PO Box 58055 Fairbanks, AK 99711 North Slope Borough PO Box 69 Barrow, AK 99723 p . Page 1 of 1 • Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Tuesday, December 09, 2008 3:00 PM Subject: DIO 35 Ivan River 13-31 Attachments: dio35.pdf BCC:'Aaron Gluzman'; caunderwood@marathonoil.com; 'Dale Hoffman'; Fridiric Grenier; 'Joe Longo'; 'Lamont Frazer'; Marc Kuck; 'Mary Aschoff; Maurizio Grandi; P Bates; Richard Garrard; 'Sandra Lemke'; 'Scott Nash'; 'Steve Virant'; Tom Gennings; 'Willem Vollenbrock'; 'William Van Dyke'; Woolf, Wendy C (DNR); 'Aleutians East Borough'; 'Anna Raff ; 'Barbara F Fullmer'; 'bbritch'; 'Bill Walker'; 'Brad McKim'; 'Brandon Gagnon'; 'Brian Gillespie'; 'Brian Havelock'; 'Brit Lively'; 'Bruce Webb'; 'buonoje'; 'Cammy Taylor'; 'Cande.Brandow'; 'carol Smyth'; 'Cary Carrigan'; 'Charles O'Donnell'; 'Chris Gay'; 'Cliff Posey'; 'Dan Bross'; 'dapa'; 'Daryl J. Kleppin'; 'David Brown'; 'David Hall'; David House; 'David L Boelens'; 'David Steingreaber'; 'ddonkel'; 'Deborah J. Jones'; 'doug_schultze'; 'Eric Lidji '; 'Evan Harness'; 'eyancy'; 'foms2@mtaonline.net'; 'Francis S. Sommer'; 'Fred Steece'; 'Garland Robinson'; 'Gary Laughlin'; 'Gary Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil'; 'Gregg Nady'; 'gregory micallef ; 'gspfoff ; 'Hank Alford'; 'Harry Engel'; 'jah'; 'James Scherr'; 'Janet D. Platt'; 'jejones'; 'Jerry McCutcheon'; 'Jim Arlington'; 'Jim White'; 'Jim Winegarner'; 'Joe Nicks'; 'John Garing'; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'John W Katz'; johnny.aiken@north-slope.org; 'Jon Goltz'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; knelson@petroleumnews.com; 'Krissell Crandall'; 'Kristin Dirks'; 'Laura Silliphant'; 'Lois'; 'Lynnda Kahn'; 'mail=akpratts@acsalaska.net'; 'mail=fours@mtaonline.net'; 'Marilyn Crockett'; 'Mark Dalton'; 'Mark Hanley'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marguerite kremer'; 'Matt Rader'; Melanie Brown; 'Mike Bill'; 'Mike Mason'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'Nick W. Glover'; NSK Problem Well Supv; NSU, ADW Well Integrity Engineer; 'Patty Alfaro'; 'Paul Decker'; 'Paul Winslow'; Pierce, Sandra M (DNR); 'Randall Kanady'; 'Randy L. Skillern'; 'rcrotty'; Rice, Cody J (DNR); 'rmclean'; 'Rob McWhorter '; rob.g.dragnich@exxonmobil.com; 'Robert Campbell'; 'Robert Fowler'; 'Robert Province'; 'Roger Belman'; 'Rudy Brueggeman'; 'Scott Cranswick'; 'Shannon Donnelly'; 'Sharmaine Copeland'; 'Sondra Stewman'; 'Sonja Frankllin'; 'Stan Porhola'; 'stanekj'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'tablerk'; 'Tamera Sheffield'; 'Temple Davidson'; 'Terrie Hubble'; 'Tim Lawlor'; 'Todd Durkee'; Tony Hopfinger; 'trmjrl'; Von Gemmingen, Scott E (DOR); 'Walter Featherly'; 'Walter Quay'; 'Wayne Rancier'; Birnbaum, Alan J (LAW); Crisp, John H (DOA); Davies, Stephen F (DOA); Fleckenstein, Robert J (DOA); Foerster, Catherine P (DOA); Grimaldi, Louis R (DOA); Johnson, Elaine M (DOA); Jones, Jeffery B (DOA); Laasch, Linda K (DOA); Mahnken, Christine R (DOA); Maunder, Thomas E (DOA); McIver, C (DOA); McMains, Stephen E (DOA); Noble, Robert C (DOA); Norman, John K (DOA); Okland, Howard D (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Saltmarsh, Arthur C (DOA); Scheve, Charles M (DOA); Seamount, Dan T (DOA); Smith, Chasity R (DOA); Williamson, Mary J (DOA) Attachments:dio35.pdf; Jody J. Colombie Special Assistant to the Commission Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 (907) 793-1221 Direct Line (907) 276-7542 Fax 12/9/2008 • 0 o a d a SARAH PALIN, GOVERNOR ALAs~ OI~ A1`D rIIAS 333 W. 7th AVENUE, SUITE 100 CO~-51'rRQATIOAT COl-II-iISSIOI~T ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL NO. DIO 35.001 Ms. Sharon Sullivan Planning & Permitting Specialist Chevron North America Exploration and Production P.O. Box 196247 Anchorage, AK 99519-6247 Re: Disposal Injection Fluids DIO 35 Dear Ms. Sullivan: Disposal Injection Order (DIO) 35 approved the injection of Class II waste fluids into the Sterling formation within Ivan River Unit (IRU) Well 13-31. On December 10, 2008 Union Oil Company of California (Union) requested clarification concerning the fluids eligible for Class II disposal injection. Union's. specific request to include precipitation accumulating within production impoundment areas associated with exploration and development activities is APPROVED. In its DIO application, Union provided a partial list of fluids it considers eligible for Class II disposal injection based on an exemption to the Resource Conservation Recovery Act (RCRA), i.e., EPA Publication 530-K-95-003 (May 1995), Crude Oil and Gas Exploration and Production Wastes: Exemption from RCRA Subtitle C Regulations.l Included in Union's request was the broad category "other associated wastes". Union delineates "other associated wastes" by noting the fluids are "generated in connection with oil and gas development activities" and by using phrases such as "intrinsically derived from primary field operations". Rule 2 of DIO 35 authorizes the disposal injection of "Class II oil field waste fluids generated during drilling, production or workover operations." The Commission's use of the broad term "Class II oil field waste fluids" is intended to cover those fluids obviously eligible for Class II disposal injection (fluids returned to surface from downhole), and to allow for other fluids to be injected into IRU 13-31 that the Commission deems appropriate on a case by case basis. The ~RCRA exempt oil and gas wastes include drill cuttings, mud, produced fluids reserve pit waste; rig wash, formation materials, completion fluids, workover fluids, stimulation fluids and solids, tracer materials, glycol dehydration wastes, naturally occurring radioactive material scale slurries, precipitation accumulating within production impoundment areas, tank bottoms, production chemicals used in wells. DIO 35.001 • December 12, 2008 Page 2 of 3 Commission agrees with Union's position that the fluids listed in the RCRA exemption are eligible for Class II disposal injection. Union operates several production pads and facilities on the west side of Cook Inlet, each with a variety of secondary containment areas designed to capture any release of solid and liquids that could result in pollution. Secondary containment areas include but are not limited to areas around drilling rigs; grind and inject equipment; drilling and production material storage; well cellars; and reserve pits. Materials within these secondary containment areas include both fluids that have been downhole or are intended to be placed in the well to accomplish a specific purpose. The volume of precipitation that collects within these areas can be significant. Recovered fluids from secondary containment areas provide some beneficial reuse (e.g., periodic flushes of IRU Well 13-31; make-up water for injected solids-laden slurries). Confinement of fluids to the intended injection zone in IRU 13-31 has been evaluated and is a basis for approved DIO 35. Well integrity has been demonstrated by evaluating the well construction (cement and casing). Required pressure testing of the well's tubing-casing annulus prior to injection and monitoring the well's tubing and annuli pressures during injection will confirm the well's mechanical integrity. The disposal injection of precipitation and any spilled materials recovered from secondary containment areas (including but not limited to areas around drilling rigs, grind and inject equipment, drilling and production material storage, and well cellars) into IRU 13-31 will have no detrimental effect on the confinement of fluids. Well integrity and correlative rights will not be negatively impacted because of the proposed inclusion of the recovered precipitation and any spilled materials in the disposal injection fluid stream. Waste will also not occur because of the addition of recovered fluids from the secondary containment/production impoundment areas. IRU 13-31 is one of two Class II disposal injection wells operated by Union on the west side of Cook Inlet. The Commission approved a similar request regarding the disposal injection of precipitation collected from various areas into IRU Well 14-31 (administrative approval DIO 23.002, dated October 29, 2008). A consistent approach to the fluids eligible for injection in both IRU disposal wells will minimize confusion for the Union personnel. Approval applies only to this specific request and is not intended to provide for a blanket authorization to inject these or similar non-hazardous fluids down other Class II disposal wells. DONE at Anchorage, Alaska and dated Dece~ Cat y P. oerster Commissioner Commissioner DIO 35.001 . i December 12, 2008 Page 3 of 3 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the Commission by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Page 1 of 1 ~ i Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Friday, December 12, 2008 10:40 AM Subject: DIO 35-001 Ivan River 13-31 Attachments: dio35-001.pdf BCC:'Aaron Gluzman'; caunderwood@marathonoil.com; 'Dale Hoffman'; Fridiric Grenier; 'Gary Orr'; 'Joe Longo'; 'Lamont Frazer'; Marc Kuck; 'Mary Aschoff; Maurizio Grandi; P Bates; Richard Garrard; 'Sandra Lemke'; 'Scott Nash'; 'Steve Virant'; Tom Gennings; 'Willem Vollenbrock'; 'William Van Dyke'; Woolf, Wendy C (DNR); 'Aleutians East Borough'; 'Anna Raff ; 'Barbara F Fullmer'; 'bbritch'; 'Bill Walker'; 'Brad McKim'; 'Brandon Gagnon'; 'Brian Gillespie'; 'Brian Havelock'; 'Brit Lively'; 'Bruce Webb'; 'buonoje'; 'Cammy Taylor'; 'Cande.Brandow'; 'carol smyth'; 'Cary Carrigan'; 'Charles O'Donnell'; 'Chris Gay'; 'Cliff Posey'; 'Dan Bross'; 'dapa'; 'Daryl J. Kleppin'; 'David Brown'; 'David Hall'; David House; 'David L Boelens'; 'David Steingreaber'; 'ddonkel'; 'Deborah J. Jones'; 'doug_schultze'; 'Eric Lidji '; 'Evan Harness'; 'eyancy'; 'foms2@mtaonline.net'; 'Francis S. Sommer'; 'Fred Steece'; 'Garland Robinson'; 'Gary Laughlin'; 'Gary Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil'; 'Gregg Nady'; 'gregory micallef; 'gspfoff ; 'Hank Alford'; 'Harry Engel'; 'jah'; 'James Scherr'; 'Janet D. Platt'; 'jejones'; 'Jerry McCutcheon'; 'Jim Arlington'; 'Jim White'; 'Jim Winegarner'; 'Joe Nicks'; 'John Garing'; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'John W Katz'; johnny.aiken@north-slope.org; 'Jon Goltz'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; knelson@petroleumnews.com; 'Krissell Crandall'; 'Kristin Dirks'; 'Laura Silliphant'; 'Lois'; 'Lynnda Kahn'; 'mail=akpratts@acsalaska.net'; 'mail=fours@mtaonline.net'; 'Marilyn Crockett'; 'Mark Dalton'; 'Mark Hanley'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marquerite kremer'; 'Matt Rader'; Melanie Brown; 'Mike Bill'; 'Mike Mason'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'Nick W. Glover'; NSK Problem Well Supv; NSU, ADW Well Integrity Engineer; 'Patty Alfaro'; 'Paul Decker'; 'Paul Winslow'; Pierce, Sandra M (DNR); 'Randall Kanady'; 'Randy L. Skillern'; 'rcrotty'; Rice, Cody J (DNR); 'rmclean ; 'Rob McWhorter '; rob.g.dragnich@exxonmobil.com; 'Robert Campbell'; 'Robert Fowler'; 'Robert Province'; 'Roger Belman'; 'Rudy Brueggeman'; 'Scott Cranswick'; 'Shannon Donnelly'; 'Sharmaine Copeland'; 'Sondra Stewman'; 'Sonja Frankllin'; 'Stan Porhola'; 'stanekj'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'tablerk'; 'Tamera Sheffield'; 'Temple Davidson'; 'Terrie Hubble'; 'Tim Lawlor'; 'Todd Durkee'; Tony Hopfinger; 'trmjrl'; Von Gemmingen, Scott E (DOR); 'Walter Featherly'; 'Walter Quay'; 'Wayne Rancier'; Birnbaum, Alan J (LAW); Crisp, John H (DOA); Davies, Stephen F (DOA); Fleckenstein, Robert J (DOA); Foerster, Catherine P (DOA); Grimaldi, Louis R (DOA); Johnson, Elaine M (DOA); Jones, Jeffery B (DOA); Laasch, Linda K (DOA); Mahnken, Christine R (DOA); Maunder, Thomas E (DOA); McIver, C (DOA); McMains, Stephen E (DOA); Noble, Robert C (DOA); Norman, John K (DOA); Okland, Howard D (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Saltmarsh, Arthur C (DOA); Scheve, Charles M (DOA); Seamount, Dan T (DOA); Smith, Chasity R (DOA); Williamson, Mary J (DOA) Attachments:dio35-001.pdf; Jody J. Colombie Special Assistant to the Commission Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 (907) 793-1221 Direct Line (907) 276-7542 Fax 12/12/2008 ~ ~ Mary Jones David McCaleb Cindi Walker XTO Energy, Inc. IHS Energy Group Tesoro Refining and Marketing Co. Cartography GEPS Supply & Distribution 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 300 Concord Plaza Drive Ft. Worth, TX 76102-6298 Houston, TX 77056 San Antonio, TX 78216 George Vaught, Jr. Jerry Hodgden Richard Neahring PO Box 13557 Hodgden Oil Company NRG Associates Denver, CO 80201-3557 408 18th Street President Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 Mark Wedman Schlumberger Ciri Halliburton Drilling and Measurements Land Department 6900 Arctic Blvd. 2525 Gambell Street #400 PO Box 93330 Anchorage, AK 99502 Anchorage, AK 99503 Anchorage, AK 99503 Baker Oil Tools Ivan Gillian Jill Schneider 4730 Business Park Blvd., #44 9649 Musket Bell Cr.#5 US Geological Survey Anchorage, AK 99503 Anchorage, AK 99507 4200 University Dr. Anchorage, AK 99508 Gordon Severson Jack Hakkila Darwin Waldsmith 3201 Westmar Cr. PO Box 190083 PO Box 39309 Anchorage, AK 99508-4336 Anchorage, AK 99519 Ninilchick, AK 99639 James Gibbs Kenai National Wildlife Refuge Penny Vadla PO Box 1597 Refuge Manager 399 West Riverview Avenue Soldotna, AK 99669 PO Box 2139 Soldotna, AK 99669-7714 Soldotna, AK 99669-2139 Richard Wagner Cliff Burglin Bernie Karl PO Box 60868 PO Box 70131 K&K Recycling Inc. Fairbanks, AK 99706 Fairbanks, AK 99707 PO Box 58055 Fairbanks, AK 99711 North Slope Borough PO Box 69 Barrow, AK 99723 /~,/d ia~6~~ X10 FW: IRU_13-31_MIT_OS-06-09 Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Friday, February 19, 2010 1:58 PM To: 'Greenstein, Larry P' Cc: Regg, James B (DOA) Subject: RE: IRU_13-31_(192-088)_MIT_05-06-09 • Page 1 of ~ ~ Larry, I have reviewed the injection order and the documents previously submitted regarding IRU 13-31. So far as I can determine, Unocal/Chevron has complied with the construction requirements and demonstrations necessary to allow Class II waste disposal injection into the wellbore in accord with DIO 35. Call or message with any questions. --"- Tom Maunder, PE AOGCC From: Greenstein, Larry P [mailto:Greensteinlp@chevron.com] Sent: Thursday, February 18, 2010 10:20 AM To: Maunder, Thomas E (DOA) Subject: FW: IRU_13-31_MIT_05-06-09 From: Greenstein, Larry P Sent: Wednesday, December 30, 2009 8:17 AM To: 'Regg, James B (DOA)' Subject: FW: IRU_13-31_MIT_05-06-09 Jim, I'm reviewing all of our MIT records for the year and noticed we hadn't officially received approval for the use of the IRU 13-31 well for disposal. We had that April meeting and you wanted all the paperwork we had put together on this well which I believe was completed with the e-mail below. With the IRU 14-31 well being used regularly and due for an MIT late in 2010, should something happen to that well, I wanted to make sure we both agree that we have the IRU 13-31 well available for disposal. Please review this data and let me know if we have missed anything. Thanks Jim. Hope you had a great Xmas and Happy New Year. Larry From: Greenstein, Larry P Sent: Tuesday, May 26, 2009 3:30 PM To: 'Maunder, Thomas E (DOA)'; 'Jim Regg; 'bob.fleckenstein@alaska.gov'; 'doa.aogcc.prudhoe.bay@alaska.gov' Cc: PORHOLA, STAN T; Walsh, Chantal [Petrotechnical Resources of Alaska (PRA)]; Lynch, Mark T (Anchorage); Ross, Gary D; Brandenburg, Tim C; Myers, Chris S; Bonnett, Nigel (Nigel.Bonnett) 2/19/2010 DSO boll 2�50 22y° 2°°° > S " O 0 O O 2 �SOO O O 1000 O \25 �S0 \O00 500: �O 1 ps0 00 h GRAPHIC CONTROLS CORPORATION CHART NO. MC MP-3000 o.. o a o METER v p p CHART EUT 0 OFF CV N p0 p O O~ M �� l7 M N r � N 0 O N l 2 3 j LOCATION / J .. 7 / REMARKS 76 ao 00,0 0001 00 e O S41 _ 00 00s2 O�L2 '4 WA 0 S ~ ~ Hilcorp Alaska, LLC 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Phone: 907-777-8300 Fax: 907-777-8580 June 9, 2022 Mr. Chris Wallace, Senior Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Subject: 2021 Annual Disposal Report for Ivan River Unit 13-31 & 14-31 (DIO 35 & 23) Dear Mr. Wallace: In accordance with DIO 35 (Rule 6) and DIO 23 (Rule 4), Hilcorp Alaska, LLC hereby submits the annual disposal report for Ivan River Unit 13-31 (PTD # 192-088) and Ivan River Unit 14-31 (PTD # 175-008) for the year 2021. Surveillance Summary Both IRU 13-31 and IRU 14-31 were used for disposal operations in 2021. Injection and annuli pressures indicate no mechanical concerns. All indications from the injection rates and pressures are that the injected fluid is contained to the approved disposal zone. Specific items to note for this reporting period (applicable to both 14-31 and 13- 31): • The biennial MIT’s will be performed in June 2022. • The regulatory limit of 4.0 bpm and 5000 psi were not exceeded. • Maximum injection pressure in either well was below 2000 psi. • In 2021, the fluids injected into IRU 14-31 (1811 bbls) and IRU 13-31 (3216 bbls) were produced water from the Ivan River, Pretty Creek, and Lewis River fields. Should you have questions, please contact Chris Stone at 777-8378 or Josh Allely at 777-8505. Sincerely, Chris Stone Reservoir Engineer Date Tubing IA OA Water Injection 12/31/2021 0 0 0 30 12/30/2021 0 0 0 27 12/29/2021 0 0 0 37 12/28/2021 0 0 0 0 12/27/2021 1088 0 0 41 12/26/2021 1140 0 0 33 12/25/2021 1120 0 0 30 12/24/2021 1124 0 0 47 12/23/2021 1115 0 0 40 12/22/2021 0 0 0 0 12/21/2021 1118 0 0 29.3 12/20/2021 1050 0 0 25.2 12/19/2021 1053 0 0 31.31 12/18/2021 1149 0 0 33.3 12/17/2021 1190 0 0 26.3 12/16/2021 1206 0 0 38.6 12/15/2021 16 0 0 0 12/14/2021 1251 0 0 66.3 12/13/2021 879 0 0 10 12/12/2021 1159 0 0 26.4 12/11/2021 1203 0 0 28.5 12/10/2021 14 0 0 0 12/9/2021 12 0 0 0 12/8/2021 11 0 0 0 12/7/2021 1517 0 0 121.2 12/6/2021 1120 0 0 16 12/5/2021 1120 0 0 20 12/4/2021 1183 0 0 31.7 Date Range: 01/01/2021 - 12/31/2021 Well: IRU 14-31 Desc: Disposal Permit to drill: 1750080 Admin Approval: DIO #23 API: 50-283-20045-00-00 12/3/2021 1079 0 0 18 12/2/2021 5 0 0 0 12/1/2021 7 0 0 0 11/30/2021 1105 0 0 38 11/29/2021 1 0 0 0 11/28/2021 1092 0 0 29 11/27/2021 188 100 0 42.2 11/26/2021 12 0 0 0 11/25/2021 1095 0 0 29.5 11/24/2021 0 0 0 0 11/23/2021 1080 0 0 21 11/22/2021 1127 0 0 18.2 11/21/2021 1067 0 0 21.2 11/20/2021 1096 0 0 29.5 11/19/2021 1138 0 0 25.1 11/18/2021 1078 0 0 24 11/17/2021 1162 0 0 34 11/16/2021 0 0 0 0 11/15/2021 0 0 0 0 11/14/2021 1050 0 0 35 11/13/2021 11 0 0 0 11/12/2021 1139 0 0 30 11/11/2021 16 0 0 0 11/10/2021 12 0 0 0 11/9/2021 1017 0 0 57 11/8/2021 11 0 0 0 11/7/2021 1185 0 0 29 11/6/2021 0 0 0 0 11/5/2021 0 0 0 0 11/4/2021 0 0 0 0 11/3/2021 0 0 0 0 11/2/2021 0 0 0 0 11/1/2021 0 0 0 0 10/31/2021 0 0 0 0 10/30/2021 0 0 0 0 10/29/2021 0 0 0 0 10/28/2021 0 0 0 0 10/27/2021 0 0 0 0 10/26/2021 0 0 0 0 10/25/2021 0 0 0 0 10/24/2021 0 0 0 0 10/23/2021 0 0 0 0 10/22/2021 0 0 0 0 10/21/2021 0 0 0 0 10/20/2021 0 0 0 0 10/19/2021 0 0 0 0 10/18/2021 0 0 0 0 10/17/2021 0 0 0 0 10/16/2021 0 0 0 0 10/15/2021 0 0 0 0 10/14/2021 0 0 0 0 10/13/2021 0 0 0 0 10/12/2021 0 0 0 0 10/11/2021 0 0 0 0 10/10/2021 0 0 0 0 10/9/2021 0 0 0 0 10/8/2021 0 0 0 0 10/7/2021 0 0 0 0 10/6/2021 0 0 0 0 10/5/2021 0 0 0 0 10/4/2021 0 0 0 0 10/3/2021 0 0 0 0 10/2/2021 0 0 0 0 10/1/2021 0 0 0 0 9/30/2021 0 0 0 0 9/29/2021 0 0 0 0 9/28/2021 0 0 0 0 9/27/2021 0 0 0 0 9/26/2021 0 0 0 0 9/25/2021 0 0 0 0 9/24/2021 0 0 0 0 9/23/2021 0 0 0 0 9/22/2021 0 0 0 0 9/21/2021 0 0 0 0 9/20/2021 0 0 0 0 9/19/2021 0 0 0 0 9/18/2021 0 0 0 0 9/17/2021 0 0 0 0 9/16/2021 0 0 0 0 9/15/2021 0 0 0 0 9/14/2021 0 0 0 0 9/13/2021 0 0 0 0 9/12/2021 0 0 0 0 9/11/2021 0 0 0 0 9/10/2021 0 0 0 0 9/9/2021 15 0 0 0 9/8/2021 15 0 0 0 9/7/2021 15 0 0 0 9/6/2021 15 0 0 0 9/5/2021 15 0 0 0 9/4/2021 15 0 0 0 9/3/2021 15 0 0 0 9/2/2021 0 0 0 0 9/1/2021 0 0 0 0 8/31/2021 0 0 0 0 8/30/2021 0 0 0 0 8/29/2021 0 0 0 0 8/28/2021 0 0 0 0 8/27/2021 0 0 0 0 8/26/2021 0 0 0 0 8/25/2021 0 0 0 0 8/24/2021 15 0 0 0 8/23/2021 15 0 0 0 8/22/2021 15 0 0 0 8/21/2021 14 0 0 0 8/20/2021 14 0 0 0 8/19/2021 14 0 0 0 8/18/2021 14 0 0 0 8/17/2021 14 0 0 0 8/16/2021 14 0 0 0 8/15/2021 14 0 0 0 8/14/2021 14 0 0 0 8/13/2021 14 0 0 0 8/12/2021 14 0 0 0 8/11/2021 14 0 0 0 8/10/2021 14 0 0 0 8/9/2021 14 0 0 0 8/8/2021 14 0 0 0 8/7/2021 13 0 0 0 8/6/2021 14 0 0 0 8/5/2021 15 0 0 0 8/4/2021 15 0 0 0 8/3/2021 12 0 0 0 8/2/2021 12 0 0 0 8/1/2021 12 0 0 0 7/31/2021 890 0 0 74 7/30/2021 1200 0 0 127 7/29/2021 0 0 0 0 7/28/2021 1289 0 0 39 7/27/2021 18 0 0 0 7/26/2021 19 0 0 0 7/25/2021 18 0 0 0 7/24/2021 18 0 0 0 7/23/2021 18 0 0 0 7/22/2021 18 0 0 0 7/21/2021 18 0 0 0 7/20/2021 16 0 0 0 7/19/2021 16 0 0 0 7/18/2021 16 0 0 0 7/17/2021 16 0 0 0 7/16/2021 16 0 0 0 7/15/2021 16 0 0 0 7/14/2021 16 0 0 0 7/13/2021 15 0 0 0 7/12/2021 15 0 0 0 7/11/2021 14 0 0 0 7/10/2021 7 0 0 0 7/9/2021 1096 0 0 32 7/8/2021 1130 0 0 60 7/7/2021 1160 0 0 84 7/6/2021 1110 0 0 70 7/5/2021 26 0 0 0 7/4/2021 26 0 0 0 7/3/2021 27 0 0 0 7/2/2021 27 0 0 0 7/1/2021 27 0 0 0 6/30/2021 27 0 0 0 6/29/2021 27 0 0 0 6/28/2021 27 0 0 0 6/27/2021 27 0 0 0 6/26/2021 27 0 0 0 6/25/2021 27 0 0 0 6/24/2021 27 0 0 0 6/23/2021 27 0 0 0 6/22/2021 27 0 0 0 6/21/2021 27 0 0 0 6/20/2021 27 0 0 0 6/19/2021 27 0 0 0 6/18/2021 27 0 0 0 6/17/2021 27 0 0 0 6/16/2021 25 0 0 0 6/15/2021 27 0 0 0 6/14/2021 27 0 0 0 6/13/2021 27 0 0 0 6/12/2021 27 0 0 0 6/11/2021 27 0 0 0 6/10/2021 27 0 0 0 6/9/2021 26 0 0 0 6/8/2021 27 0 0 0 6/7/2021 27 0 0 0 6/6/2021 27 0 0 0 6/5/2021 27 0 0 0 6/4/2021 26 0 0 0 6/3/2021 26 0 0 0 6/2/2021 26 0 0 0 6/1/2021 26 0 0 0 5/31/2021 26 0 0 0 5/30/2021 27 0 0 0 5/29/2021 26 0 0 0 5/28/2021 26 0 0 0 5/27/2021 25 0 0 0 5/26/2021 25 0 0 0 5/25/2021 25 0 0 0 5/24/2021 25 0 0 0 5/23/2021 25 0 0 0 5/22/2021 24 0 0 0 5/21/2021 24 0 0 0 5/20/2021 22 0 0 0 5/19/2021 19 0 0 0 5/18/2021 28 0 0 0 5/17/2021 27 0 0 0 5/16/2021 28 0 0 0 5/15/2021 28 0 0 0 5/14/2021 28 0 0 0 5/13/2021 28 0 0 0 5/12/2021 28 0 0 0 5/11/2021 28 0 0 0 5/10/2021 28 0 0 0 5/9/2021 28 0 0 0 5/8/2021 27 0 0 0 5/7/2021 27 0 0 0 5/6/2021 27 0 0 0 5/5/2021 27 0 0 0 5/4/2021 27 0 0 0 5/3/2021 27 0 0 0 5/2/2021 25 0 0 0 5/1/2021 23 0 0 0 4/30/2021 1116 0 0 40 4/29/2021 48 0 0 0 4/28/2021 48 0 0 0 4/27/2021 48 0 0 0 4/26/2021 47 0 0 0 4/25/2021 47 0 0 0 4/24/2021 47 0 0 0 4/23/2021 47 0 0 0 4/22/2021 48 0 0 0 4/21/2021 48 0 0 0 4/20/2021 48 0 0 0 4/19/2021 48 0 0 0 4/18/2021 48 0 0 0 4/17/2021 48 0 0 0 4/16/2021 48 0 0 0 4/15/2021 48 0 0 0 4/14/2021 48 0 0 0 4/13/2021 48 0 0 0 4/12/2021 48 0 0 0 4/11/2021 48 0 0 0 4/10/2021 47 0 0 0 4/9/2021 49 0 0 0 4/8/2021 48 0 0 0 4/7/2021 47 0 0 0 4/6/2021 47 0 0 0 4/5/2021 47 0 0 0 4/4/2021 48 0 0 0 4/3/2021 48 0 0 0 4/2/2021 47 0 0 0 4/1/2021 48 0 0 0 3/31/2021 48 0 0 0 3/30/2021 48 0 0 0 3/29/2021 48 0 0 0 3/28/2021 47 0 0 0 3/27/2021 48 0 0 0 3/26/2021 48 0 0 0 3/25/2021 48 0 0 0 3/24/2021 48 0 0 0 3/23/2021 48 0 0 0 3/22/2021 48 0 0 0 3/21/2021 48 0 0 0 3/20/2021 48 0 0 0 3/19/2021 48 0 0 0 3/18/2021 48 0 0 0 3/17/2021 47 0 0 0 3/16/2021 48 0 0 0 3/15/2021 48 0 0 0 3/14/2021 47 0 0 0 3/13/2021 47 0 0 0 3/12/2021 47 0 0 0 3/11/2021 48 0 0 0 3/10/2021 48 0 0 0 3/9/2021 48 0 0 0 3/8/2021 48 0 0 0 3/7/2021 48 0 0 0 3/6/2021 48 0 0 0 3/5/2021 48 0 0 0 3/4/2021 48 0 0 0 3/3/2021 48 0 0 0 3/2/2021 48 0 0 0 3/1/2021 49 0 0 0 2/28/2021 48 0 0 0 2/27/2021 48 0 0 0 2/26/2021 48 0 0 0 2/25/2021 49 0 0 0 2/24/2021 48 0 0 0 2/23/2021 48 0 0 0 2/22/2021 48 0 0 0 2/21/2021 48 0 0 0 2/20/2021 48 0 0 0 2/19/2021 48 0 0 0 2/18/2021 48 0 0 0 2/17/2021 48 0 0 0 2/16/2021 47 0 0 0 2/15/2021 47 0 0 0 2/14/2021 47 0 0 0 2/13/2021 45 0 0 0 2/12/2021 45 0 0 0 2/11/2021 43 0 0 0 2/10/2021 1083 0 0 16 2/9/2021 19 0 0 0 2/8/2021 26 0 0 0 2/7/2021 26 0 0 0 2/6/2021 26 0 0 0 2/5/2021 26 0 0 0 2/4/2021 25 0 0 0 2/3/2021 25 0 0 0 2/2/2021 25 0 0 0 2/1/2021 25 0 0 0 1/31/2021 25 0 0 0 1/30/2021 26 0 0 0 1/29/2021 26 0 0 0 1/28/2021 26 0 0 0 1/27/2021 25 0 0 0 1/26/2021 25 0 0 0 1/25/2021 26 0 0 0 1/24/2021 26 0 0 0 1/23/2021 26 0 0 0 1/22/2021 26 0 0 0 1/21/2021 26 0 0 0 1/20/2021 26 0 0 0 1/19/2021 26 0 0 0 1/18/2021 26 0 0 0 1/17/2021 25 0 0 0 1/16/2021 25 0 0 0 1/15/2021 25 0 0 0 1/14/2021 25 0 0 0 1/13/2021 25 0 0 0 1/12/2021 25 0 0 0 1/11/2021 25 0 0 0 1/10/2021 25 0 0 0 1/9/2021 25 0 0 0 1/8/2021 25 0 0 0 1/7/2021 25 0 0 0 1/6/2021 25 0 0 0 1/5/2021 25 0 0 0 1/4/2021 25 0 0 0 1/3/2021 25 0 0 0 1/2/2021 25 0 0 0 1/1/2021 26 0 0 0 Date Tubing IA OA OOA Water Injection 12/31/2021 0 180 0 0 0 12/30/2021 0 180 0 0 0 12/29/2021 0 190 0 0 0 12/28/2021 0 190 0 0 0 12/27/2021 0 190 0 0 0 12/26/2021 0 190 0 0 0 12/25/2021 0 190 0 0 0 12/24/2021 0 190 0 0 0 12/23/2021 0 190 0 0 0 12/22/2021 0 190 0 0 0 12/21/2021 0 180 0 0 0 12/20/2021 0 180 0 0 0 12/19/2021 0 180 0 0 0 12/18/2021 0 180 0 0 0 12/17/2021 0 180 0 0 0 12/16/2021 0 180 0 0 0 12/15/2021 0 180 0 0 0 12/14/2021 0 180 0 0 0 12/13/2021 0 180 0 0 0 12/12/2021 0 180 0 0 0 12/11/2021 0 180 0 0 0 12/10/2021 0 180 0 0 0 12/9/2021 0 180 0 0 0 12/8/2021 0 180 0 0 0 12/7/2021 0 180 0 0 0 12/6/2021 0 180 0 0 0 12/5/2021 0 180 0 0 0 12/4/2021 0 180 0 0 0 Date Range: 01/01/2021 - 12/31/2021 Well: IRU 13-31 Desc: Disposal Permit to drill: 1920880 Admin Approval: DIO #35 API: 50-283-20086-00-00 12/3/2021 0 180 0 0 0 12/2/2021 0 180 0 0 0 12/1/2021 0 180 0 0 0 11/30/2021 0 180 0 0 0 11/29/2021 0 180 0 0 0 11/28/2021 0 185 0 0 0 11/27/2021 0 185 0 0 0 11/26/2021 0 185 0 0 0 11/25/2021 0 185 0 0 0 11/24/2021 0 200 0 0 0 11/23/2021 0 200 0 0 0 11/22/2021 0 200 0 0 0 11/21/2021 0 200 0 0 0 11/20/2021 0 200 0 0 0 11/19/2021 0 200 0 0 0 11/18/2021 0 200 0 0 0 11/17/2021 0 200 0 0 0 11/16/2021 0 200 0 0 0 11/15/2021 0 200 0 0 0 11/14/2021 0 200 0 0 0 11/13/2021 0 200 0 0 0 11/12/2021 0 200 0 0 0 11/11/2021 0 220 0 0 0 11/10/2021 0 220 0 0 0 11/9/2021 0 220 0 0 0 11/8/2021 0 220 0 0 0 11/7/2021 0 220 0 0 29 11/6/2021 0 220 0 23 11/5/2021 0 220 0 0 17 11/4/2021 1 220 0 0 39.2 11/3/2021 1 220 0 0 36.1 11/2/2021 2 220 0 0 43.3 11/1/2021 1 220 0 0 38.6 10/31/2021 1 220 0 0 0 10/30/2021 1 220 0 0 0 10/29/2021 1259 220 0 0 67.8 10/28/2021 0 220 0 0 0 10/27/2021 0 220 0 0 40.5 10/26/2021 0 220 0 0 0 10/25/2021 1487 220 0 0 59 10/24/2021 0 220 0 0 0 10/23/2021 1521 220 0 0 30 10/22/2021 1449 220 0 0 35.3 10/21/2021 0 220 0 0 0 10/20/2021 0 220 0 0 0 10/19/2021 28 220 0 0 0 10/18/2021 1452 220 0 0 27 10/17/2021 1512 220 0 0 30.7 10/16/2021 0 220 0 0 0 10/15/2021 1436 220 0 0 27 10/14/2021 0 220 0 0 0 10/13/2021 1440 220 0 0 16.2 10/12/2021 1420 240 0 0 21 10/11/2021 1518 240 0 0 36.7 10/10/2021 0 200 0 0 0 10/9/2021 0 200 0 0 0 10/8/2021 0 200 0 0 0 10/7/2021 16 200 0 0 0 10/6/2021 1409 200 0 0 95 10/5/2021 1426 200 0 0 66 10/4/2021 1509 200 0 0 129 10/3/2021 28 200 0 0 0 10/2/2021 28 200 0 0 8 10/1/2021 30 200 0 0 28 9/30/2021 0 225 0 0 0 9/29/2021 0 225 0 0 0 9/28/2021 0 225 0 0 25.9 9/27/2021 0 225 0 0 13.6 9/26/2021 0 225 0 0 12.5 9/25/2021 1635 225 0 0 79.6 9/24/2021 0 220 0 0 26 9/23/2021 0 186 0 0 0 9/22/2021 1620 220 0 0 78 9/21/2021 1750 220 0 0 71 9/20/2021 1500 220 0 0 259 9/19/2021 1485 220 0 0 26 9/18/2021 0 220 0 0 0 9/17/2021 0 220 0 0 0 9/16/2021 1535 220 0 0 62.7 9/15/2021 0 220 0 0 16.8 9/14/2021 1543 205 0 0 22.1 9/13/2021 1475 210 0 0 62.2 9/12/2021 1355 200 0 0 27 9/11/2021 1350 210 0 0 21 9/10/2021 0 210 0 0 0 9/9/2021 1350 200 0 0 32 9/8/2021 1385 225 0 0 26.2 9/7/2021 15 205 0 0 0 9/6/2021 5 205 0 0 0 9/5/2021 22 205 0 0 0 9/4/2021 22 210 0 0 0 9/3/2021 22 215 0 0 0 9/2/2021 22 220 0 0 0 9/1/2021 1305 330 0 0 15 8/31/2021 1048 330 0 0 9 8/30/2021 1198 330 0 0 9 8/29/2021 0 330 0 0 0 8/28/2021 1297 325 0 0 11.5 8/27/2021 1382 340 0 0 12 8/26/2021 1382 300 0 0 32 8/25/2021 0 220 0 0 0 8/24/2021 1390 280 0 0 28 8/23/2021 0 215 0 0 0 8/22/2021 0 215 0 0 0 8/21/2021 0 215 0 0 19.7 8/20/2021 0 215 0 0 0 8/19/2021 1300 215 0 0 28.75 8/18/2021 1299 210 0 0 36 8/17/2021 1329 210 0 0 9.6 8/16/2021 1357 215 0 0 16.8 8/15/2021 129 200 0 0 11 8/14/2021 160 185 0 0 17 8/13/2021 129 200 0 0 0 8/12/2021 1329 200 0 0 56 8/11/2021 1345 230 0 0 94 8/10/2021 1423 230 0 0 105 8/9/2021 1470 230 0 0 121 8/8/2021 1410 230 0 0 123 8/7/2021 1140 210 0 0 127 8/6/2021 350 245 0 0 12.8 8/5/2021 1200 200 0 0 117 8/4/2021 1190 200 0 0 121 8/3/2021 1200 200 0 0 80 8/2/2021 1230 200 0 0 42 8/1/2021 1136 200 0 0 82 7/31/2021 0 200 0 0 0 7/30/2021 0 200 0 0 0 7/29/2021 0 200 0 0 0 7/28/2021 0 200 0 0 0 7/27/2021 0 200 0 0 0 7/26/2021 0 200 0 0 0 7/25/2021 0 200 0 0 0 7/24/2021 0 200 0 0 0 7/23/2021 0 200 0 0 0 7/22/2021 0 200 0 0 0 7/21/2021 0 200 0 0 0 7/20/2021 0 200 0 0 0 7/19/2021 0 200 0 0 0 7/18/2021 0 200 0 0 0 7/17/2021 0 200 0 0 0 7/16/2021 0 200 0 0 0 7/15/2021 0 200 0 0 0 7/14/2021 0 200 0 0 0 7/13/2021 0 200 0 0 0 7/12/2021 0 200 0 0 0 7/11/2021 0 200 0 0 0 7/10/2021 0 200 0 0 0 7/9/2021 0 200 0 0 0 7/8/2021 0 200 0 0 0 7/7/2021 0 200 0 0 0 7/6/2021 0 200 0 0 0 7/5/2021 0 200 0 0 0 7/4/2021 0 200 0 0 0 7/3/2021 0 200 0 0 0 7/2/2021 0 200 0 0 0 7/1/2021 0 200 0 0 0 6/30/2021 0 200 0 0 0 6/29/2021 0 200 0 0 0 6/28/2021 0 200 0 0 0 6/27/2021 0 200 0 0 0 6/26/2021 1300 220 0 0 19 6/25/2021 1300 200 0 0 46 6/24/2021 0 200 0 0 0 6/23/2021 0 200 0 0 0 6/22/2021 0 200 0 0 0 6/21/2021 0 200 0 0 0 6/20/2021 0 200 0 0 0 6/19/2021 0 200 0 0 0 6/18/2021 0 200 0 0 0 6/17/2021 0 200 0 0 0 6/16/2021 0 204 0 0 0 6/15/2021 1250 190 0 0 10 6/14/2021 0 190 0 0 0 6/13/2021 0 190 0 0 0 6/12/2021 0 190 0 0 0 6/11/2021 0 190 0 0 0 6/10/2021 0 185 0 0 0 6/9/2021 0 185 0 0 0 6/8/2021 0 185 0 0 0 6/7/2021 0 185 0 0 0 6/6/2021 0 185 0 0 0 6/5/2021 0 185 0 0 0 6/4/2021 0 185 0 0 0 6/3/2021 0 185 0 0 0 6/2/2021 0 185 0 0 0 6/1/2021 0 185 0 0 0 5/31/2021 0 185 0 0 0 5/30/2021 0 185 0 0 0 5/29/2021 0 190 0 0 0 5/28/2021 0 190 0 0 0 5/27/2021 0 190 0 0 0 5/26/2021 0 190 0 0 0 5/25/2021 0 190 0 0 0 5/24/2021 0 190 0 0 0 5/23/2021 0 190 0 0 0 5/22/2021 0 190 0 0 0 5/21/2021 0 190 0 0 0 5/20/2021 0 190 0 0 0 5/19/2021 0 190 0 0 0 5/18/2021 0 190 0 0 0 5/17/2021 0 190 0 0 0 5/16/2021 0 190 0 0 0 5/15/2021 0 190 0 0 0 5/14/2021 0 190 0 0 0 5/13/2021 0 190 0 0 0 5/12/2021 0 190 0 0 0 5/11/2021 0 190 0 0 0 5/10/2021 0 190 0 0 0 5/9/2021 0 190 0 0 0 5/8/2021 0 190 0 0 0 5/7/2021 0 190 0 0 0 5/6/2021 0 190 0 0 0 5/5/2021 0 190 0 0 0 5/4/2021 0 190 0 0 0 5/3/2021 0 190 0 0 0 5/2/2021 0 190 0 0 0 5/1/2021 0 190 0 0 0 4/30/2021 0 190 0 0 0 4/29/2021 0 183 0 0 0 4/28/2021 0 183 0 0 0 4/27/2021 0 183 0 0 0 4/26/2021 0 185 0 0 0 4/25/2021 0 185 0 0 0 4/24/2021 0 185 0 0 0 4/23/2021 0 185 0 0 0 4/22/2021 0 0 0 0 4/21/2021 0 185 0 0 0 4/20/2021 0 185 0 0 0 4/19/2021 0 185 0 0 0 4/18/2021 0 180 0 0 0 4/17/2021 0 180 0 0 0 4/16/2021 0 180 0 0 0 4/15/2021 0 190 0 0 0 4/14/2021 0 190 0 0 0 4/13/2021 0 190 0 0 0 4/12/2021 0 190 0 0 0 4/11/2021 0 190 0 0 0 4/10/2021 0 190 0 0 0 4/9/2021 0 190 0 0 0 4/8/2021 0 190 0 0 0 4/7/2021 0 190 0 0 0 4/6/2021 0 190 0 0 0 4/5/2021 0 190 0 0 0 4/4/2021 0 190 0 0 0 4/3/2021 0 190 0 0 0 4/2/2021 0 190 0 0 0 4/1/2021 0 190 0 0 0 3/31/2021 0 190 0 0 0 3/30/2021 0 190 0 0 0 3/29/2021 0 190 0 0 0 3/28/2021 0 190 0 0 0 3/27/2021 0 190 0 0 0 3/26/2021 0 190 0 0 0 3/25/2021 0 190 0 0 0 3/24/2021 0 190 0 0 0 3/23/2021 0 190 0 0 0 3/22/2021 0 190 0 0 0 3/21/2021 0 190 0 0 0 3/20/2021 0 190 0 0 0 3/19/2021 0 190 0 0 0 3/18/2021 0 190 0 0 0 3/17/2021 0 190 0 0 0 3/16/2021 0 190 0 0 0 3/15/2021 0 190 0 0 0 3/14/2021 0 190 0 0 0 3/13/2021 0 190 0 0 0 3/12/2021 0 190 0 0 0 3/11/2021 0 190 0 0 0 3/10/2021 0 190 0 0 0 3/9/2021 0 190 0 0 0 3/8/2021 0 190 0 0 0 3/7/2021 0 190 0 0 0 3/6/2021 0 190 0 0 0 3/5/2021 0 190 0 0 0 3/4/2021 0 190 0 0 0 3/3/2021 0 190 0 0 0 3/2/2021 0 190 0 0 0 3/1/2021 0 190 0 0 0 2/28/2021 0 190 0 0 0 2/27/2021 0 190 0 0 0 2/26/2021 0 190 0 0 0 2/25/2021 0 190 0 0 0 2/24/2021 0 190 0 0 0 2/23/2021 0 190 0 0 0 2/22/2021 0 190 0 0 0 2/21/2021 0 190 0 0 0 2/20/2021 0 190 0 0 0 2/19/2021 0 190 0 0 0 2/18/2021 0 190 0 0 0 2/17/2021 0 190 0 0 0 2/16/2021 0 190 0 0 0 2/15/2021 0 190 0 0 0 2/14/2021 0 190 0 0 0 2/13/2021 0 190 0 0 0 2/12/2021 0 190 0 0 0 2/11/2021 0 190 0 0 0 2/10/2021 0 200 4 0 0 2/9/2021 0 200 4 0 0 2/8/2021 0 200 4 0 0 2/7/2021 0 200 4 0 0 2/6/2021 0 200 4 0 0 2/5/2021 0 190 0 0 0 2/4/2021 0 190 0 0 0 2/3/2021 0 190 0 0 0 2/2/2021 0 190 0 0 0 2/1/2021 0 190 0 0 0 1/31/2021 0 190 0 0 0 1/30/2021 0 190 0 0 0 1/29/2021 0 190 0 0 0 1/28/2021 0 190 0 0 0 1/27/2021 0 190 0 0 0 1/26/2021 0 190 0 0 0 1/25/2021 0 190 0 0 0 1/24/2021 0 190 0 0 0 1/23/2021 0 190 0 0 0 1/22/2021 0 190 0 0 0 1/21/2021 0 190 0 0 0 1/20/2021 0 190 0 0 0 1/19/2021 0 190 0 0 0 1/18/2021 0 190 0 0 0 1/17/2021 0 190 0 0 0 1/16/2021 0 190 0 0 0 1/15/2021 0 190 0 0 0 1/14/2021 0 190 0 0 0 1/13/2021 0 190 0 0 0 1/12/2021 0 190 0 0 0 1/11/2021 0 190 0 0 0 1/10/2021 0 190 0 0 0 1/9/2021 0 190 0 0 0 1/8/2021 0 190 0 0 0 1/7/2021 0 190 0 0 0 1/6/2021 0 190 0 0 0 1/5/2021 0 190 0 0 0 1/4/2021 0 190 0 0 0 1/3/2021 0 190 0 0 0 1/2/2021 0 190 0 0 0 1/1/2021 0 190 0 0 0 Hilcorp Alaska, LLC Post Office Box 244027 Anchorage, AK 99524-4027 3800 Centerpolnt Drive Suite 100 Anchorage, AK 99503 Jul 2 2019 Phone: 907/777-8322 July Fax: 907/777-8580 Mr. Hollis S. French, Chair Alaska Oil & Gas Conservation Commission JUL 0 Z M9333 W. 7a' Avenue, Suite 100 Anchorage, Alaska 99501-3539 AOUaiC Re: 2018 Annual Disposal Report for the 13-31 & 14-31 Wells in the Ivan River Unit Dear Mr. French, This is the 2018 Annual Report for the UIC Class II disposal operation in the IRU 13-31 (DIO 35) and IRU 14-31 (DIO 23) wellbores. The attached plots shows that injection rates and pressures for both wells were well below the regulatory limit of 4 barrels per minute and 5000psig. Furthermore, injection and annuli pressures indicate no mechanical concerns and that the injected fluid was contained to the approved disposal zone. Specific items to note for this reporting period: • A MIT is required every two years and the last MIT was performed 5-20-18. • In 2018, the fluids injected into the IRU 13-31 and 14-31 (17,525 and 10,991 barrels, respectively) wells were produced water from the Ivan River, Pretty Creek, and Lewis River fields. • Maximum pressures in both wells during injection never exceeded 2,000 psig. Sincerely, �t&4 ��tt Trudi Hallett Reservoir Engineer Attachment 1 — IRU 13-31 Injection rates and pressures Attachment 2 — IRU 14-31 Injection rates and pressures �011I�S 1500- Eu�zs 500- a IRU 013-31 WDW 01/2018 02/2018 03/2018 04/2018 05/2018 06/2018 07/2018 08/2018 09/2018 10/2018 11/2018 12/2018 — Tubing — IA — OA OOA — Water Injection .wo MC 400 SKO 200 100 0 Well: IRU 13-31 Desc: Disposal Permit to drill: 1920880 Admin Approval: DID #35 API:50-283-20086-00-00 Date Range: 01/01/2018 - 12/31/2018 Date Tubing IA OA ODA Water Injection 12/31/2018 1401 410 0 0 336 12/30/2018 1466 410 0 0 294 12/29/2018 1422 410 0 0 336 12/28/2018 1346 410 0 0 346 12/27/2018 1432 400 0 0 231 12/26/2018 1253 420 0 0 273 12/25/2018 1050 280 0 0 220 12/24/2018 1175 280 0 0 323 12/23/2018 0 200 0 0 0 12/22/2018 1250 230 0 0 249 12/21/2018 1000 185 0 0 120 12/20/2018 0 185 0 0 0 12/19/2018 0 185 0 0 0 12/18/2018 0 180 0 0 0 12/17/2018 0 1S0 0 0 0 12/16/2018 0 180 0 0 0 12/15/2018 0 180 0 0 0 12/14/2018 0 180 0 0 0 12/13/2018 0 180 0 0 0 12/12/2018 0 180 0 0 0 12/11/2018 0 ISO 0 0 0 12/10/2018 0 1S0 0 0 0 12/9/2018 0 280 0 0 0 12/8/2018 0 280 0 0 0 12/7/2018 0 280 0 0 0 12/6/2018 0 280 0 0 0 12/5/2018 0 285 0 0 0 12/4/2018 0 280 0 12/3/2018 0 280 0 12/2/2018 0 280 0 12/1/2018 0 280 0 11/30/2018 0 280 0 11/29/2018 0 280 0 11/28/2018 0 280 0 11/27/2018 0 280 0 11/26/2018 0 350 0 11/25/2018 0 350 0 11/24/2018 0 350 0 11/23/2018 0 300 0 11/22/2018 1307 300 390 11/21/2018 1288 300 340 11/20/2018 1323 300 325 11/19/2018 1325 320 450 11/18/2018 1317 320 290 11/17/2018 1350 320 200 11/16/2018 1350 320 116 11/15/2018 1330 150 26 11/14/2018 1332 150 100 11/13/2018 1234 150 378 11/12/2018 1195 150 163 11/11/2018 1225 150 144 11/10/2018 1349 150 220 11/9/2018 1114 150 220 11/8/2018 1081 150 135 11/7/2018 1150 150 459 11/6/2018 1279 150 336 11/5/2018 1231 150 336 11/4/2018 1272 150 0 0 335 11/3/2018 1280 150 0 0 303 11/2/2018 1154 150 0 0 186 11/1/2018 1136 150 0 0 284 10/31/2018 1163 150 0 0 362 10/30/2018 1075 150 0 0 0 10/29/2018 1164 150 0 0 287 10/28/2018 1100 155 0 0 112 10/27/2018 720 155 0 0 0 10/26/2018 720 155 0 0 0 10/25/2018 720 155 0 0 0 10/24/2018 720 155 0 0 0 10/23/2018 720 160 0 0 0 10/22/2018 720 178 0 10/21/2018 740 178 0 10/20/2018 746 176 0 10/19/2018 760 176 0 10/18/2018 760 176 0 10/17/2018 780 176 0 10/16/2018 920 145 80 10/15/2018 1125 140 354 10/14/2018 1150 140 275 10/13/2018 1050 140 228 10/12/2018 1000 140 0 0 40 10/11/2018 1100 180 0 0 120 10/10/2018 1100 190 0 0 120 10/9/2018 1110 188 101 10/8/2018 1120 188 101 10/7/2018 1120 188 40 10/6/2018 1110 188 85 10/5/2018 1220 186 105 10/4/2018 1120 186 140 10/3/2018 0 186 0 10/2/2018 880 186 0 10/1/2018 1150 186 127 9/30/2018 1112 186 107 9/29/2018 1120 184 112 9/28/2018 1120 184 130 9/27/2018 1096 184 120 9/26/2018 1020 178 60 9/25/2018 1080 182 0 9/24/2018 1100 184 96 9/23/2018 1094 184 125 9/22/2018 1096 188 80 9/21/2018 1060 188 108 9/20/2018 1040 180 0 0 38 9/19/2018 0 180 0 9/18/2018 0 180 0 0 0 9/17/2018 1100 220 0 0 40 9/16/2018 1100 220 0 0 50 9/15/2018 1100 220 0 0 50 9/14/2018 0 180 0 0 45 9/13/2018 0 180 0 0 45 9/12/2018 1100 220 0 0 145 9/11/2018 1100 220 0 0 60 9/10/2018 1100 220 0 0 65 9/9/2018 1000 180 0 0 140 9/8/2018 0 16S 0 0 0 9/7/2018 0 165 0 0 0 9/6/2018 0 165 0 0 0 9/5/2018 0 165 0 0 0 9/4/2018 750 200 0 9/3/2018 748 178 0 9/2/2018 750 178 0 9/1/2018 1150 178 34 8/31/2018 1050 178 78 8/30/2018 1089 178 118 8/29/2018 745 178 0 0 0 8/28/2018 780 176 0 8/27/2018 850 210 0 8/26/2018 1150 226 117 8/25/2018 1100 220 60 8/24/2018 1050 220 60 8/23/2018 1050 220 70 8/22/2018 800 220 0 8/21/2018 1050 220 0 0 98 8/20/2018 1100 190 0 0 46 8/19/2018 1100 180 0 0 126 8/18/2018 1100 200 0 0 131 8/17/2018 1000 190 0 0 113 8/16/2018 0 190 0 0 0 8/15/2018 0 190 0 0 0 8/14/2018 20 200 0 0 0 8/13/2018 1050 200 0 0 37 8/12/2018 1100 200 0 0 37 8/11/2018 1050 200 0 0 36 8/10/2018 1040 200 0 0 43 8/9/2018 1000 240 0 0 68 8/8/2018 1100 240 0 0 132 8/7/2018 1100 250 0 0 0 8/6/2018 1200 260 0 0 0 8/5/2018 1200 260 0 0 0 8/4/2018 1050 250 0 0 0 8/3/2018 1075 245 0 0 0 8/2/2018 1050 255 0 0 0 8/1/2018 1050 260 0 0 0 7/31/2018 1100 230 0 0 0 7/30/2018 1100 230 150 7/29/2018 1100 230 80 7/28/2018 1100 230 150 7/27/2018 0 230 22 7/26/2018 11 230 100 7/25/2018 1000 230 175 7/24/2018 0 230 80 7/23/2018 50 230 0 7/22/2018 50 230 0 7/21/2018 50 230 0 7/20/2018 50 230 0 7/19/2018 50 230 0 7/18/2018 1000 230 50 7/17/2018 1010 236 0 7/16/2018 1012 236 51 7/15/2018 1008 234 50 7/14/2018 1032 230 50 7/13/2018 1024 230 112 7/12/2018 1040 230 100 7/11/2018 48 230 0 7/10/2018 1020 230 100 7/9/2018 48 230 0 7/8/2018 1025 230 64 7/7/2018 1020 222 17 7/6/2018 1020 222 90 7/5/2018 1020 220 72 7/4/2018 1020 218 0 0 40 7/3/2018 48 218 0 7/2/2018 48 218 0 7/1/2018 48 218 0 6/30/2018 880 216 0 6/29/2018 880 216 0 6/28/2018 920 216 0 6/27/2018 950 218 0 6/26/2018 1020 240 50 6/25/2018 1020 240 60 6/24/2018 100 220 60 6/23/2018 1200 235 120 6/22/2018 1100 230 120 6/21/2018 20 200 0 6/20/2018 20 200 0 6/19/2018 1100 240 0 6/18/2018 1150 240 50 6/17/2018 1100 250 53 6/16/2018 1100 260 53 6/15/2018 20 200 0 6/14/2018 20 220 0 6/13/2018 1050 220 50 6/12/2018 1050 220 0 6/11/2018 1040 220 35 6/10/2018 1250 200 12 6/9/2018 1100 220 55 6/8/2018 1050 245 92 6/7/2018 1200 225 32 6/6/2018 1200 220 0 6/5/2018 2000 240 110 6/4/2018 2000 240 57 6/3/2018 1200 240 55 6/2/2018 1200 240 60 6/1/2018 1200 240 100 5/31/2018 1200 240 120 5/30/2018 1200 240 118 5/29/2018 950 200 50 5/28/2018 80 200 25 5/27/2018 80 200 0 5/26/2018 80 200 0 5/25/2018 80 200 0 5/24/2018 80 200 18 5/23/2018 80 200 0 5/22/2018 78 206 0 5/21/2018 78 200 0 5/20/2018 74 164 0 5/19/2018 75 165 0 5/18/2018 75 165 0 5/17/2018 75 165 0 5/16/2018 75 165 0 5/15/2018 75 165 0 0 5/14/2018 1100 165 0 34 5/13/2018 78 165 0 0 5/12/2018 77 165 0 0 5/11/2018 1058 165 0 33 5/10/2018 78 165 0 0 5/9/2018 76 165 0 0 5/8/2018 1064 165 0 28.4 5/7/2018 1100 165 0 28.6 5/6/2018 1166 160 0 29.5 5/5/2018 80 160 0 0 5/4/2018 1122 160 0 30 5/3/2018 80 160 0 0 5/2/2018 1144 160 0 27 5/1/2018 1210 160 0 15 4/30/2018 1201 160 0 30 4/29/2018 80 160 0 0 4/28/2018 80 160 0 0 4/27/2018 80 160 0 0 4/26/2018 80 160 0 0 4/25/2018 80 165 0 0 4/24/2018 80 165 0 0 4/23/2018 80 165 0 0 4/22/2018 80 165 0 0 4/21/2018 80 165 0 0 4/20/2018 80 165 0 0 4/19/2018 80 170 0 0 4/18/2018 80 175 0 0 4/17/2018 80 170 0 0 4/16/2018 80 175 0 0 4/15/2018 80 175 0 0 4/14/2018 80 175 0 0 4/13/2018 80 175 0 0 4/12/2018 80 170 0 0 4/11/2018 80 160 0 0 4/10/2018 80 160 0 0 4/9/2018 80 160 0 0 4/8/2018 80 160 0 0 4/7/2018 80 160 0 0 4/6/2018 80 160 0 0 4/5/2018 80 160 0 0 4/4/2018 80 160 0 0 4/3/2018 80 160 0 0 4/2/2018 80 160 0 0 4/1/2018 80 160 0 0 3/31/2018 80 160 0 0 3/30/2018 80 160 0 0 3/29/2018 80 160 0 0 3/28/2018 80 160 0 3/27/2018 80 160 0 3/26/2018 80 160 0 3/25/2018 80 160 0 3/24/2018 80 160 0 3/23/2018 80 160 0 3/22/2018 80 160 0 3/21/2018 80 160 0 0 0 3/20/2018 81 160 0 0 0 3/19/2018 80 160 0 0 0 3/18/2018 79 160 0 0 0 3/17/2018 81 160 0 0 0 3/16/2018 80 160 0 0 0 3/15/2018 80 160 0 0 0 3/14/2018 80 160 0 0 0 3/13/2018 80 160 0 0 0 3/12/2018 80 160 0 0 0 3/11/2018 80 160 0 0 0 3/10/2018 80 160 0 0 0 3/9/2018 80 160 0 0 0 3/8/2018 80 160 0 0 0 3/7/2018 80 160 0 0 0 3/6/2018 80 160 0 0 0 3/5/2018 80 160 0 0 3/4/2018 80 160 0 0 3/3/2018 80 160 0 0 3/2/2018 80 160 0 0 3/1/2018 80 160 0 0 2/28/2018 80 170 0 2 2/27/2018 80 170 0 2 2/26/2018 80 170 0 2 2/25/2018 80 170 0 2 2/24/2018 80 170 0 2 2/23/2018 80 170 0 2 2/22/2018 80 170 0 2 2/21/2018 80 170 0 2 2/20/2018 80 170 0 0 2/19/2018 80 170 0 0 2/18/2018 80 170 0 0 2/17/2018 80 170 2/16/2018 80 180 2/15/2018 80 180 2/14/2018 80 180 2/13/2018 80 180 2/12/2018 80 180 2/11/2018 80 180 2/10/2018 80 180 2/9/2018 80 180 2/8/2018 80 180 2/7/2018 80 180 0 2/6/2018 80 180 0 2/5/2018 80 180 0 2/4/2018 80 180 0 2/3/2018 80 180 0 2/2/2018 80 180 0 2/1/2018 80 170 0 1/31/2018 100 170 0 1/30/2018 100 170 0 1/29/2018 100 170 0 1/28/2018 100 170 0 1/27/2018 100 170 0 1/26/2018 80 170 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1/25/2018 80 170 1/24/2018 80 170 0 0 1/23/2018 80 170 0 0 1/22/2018 80 170 0 0 1/21/2018 80 170 0 0 1/20/2018 80 170 0 0 1/19/2018 80 170 0 0 1/18/2018 80 170 0 0 1/17/2018 80 170 0 0 1/16/2018 80 170 0 1/15/2018 80 170 0 1/14/2018 80 180 0 0 1/13/2018 80 180 1/12/2018 80 180 0 0 1/11/2018 80 182 0 0 1/10/2018 80 180 0 0 1/9/2018 80 180 0 0 1/8/2018 80 180 0 0 1/7/2018 80 182 0 0 1/6/2018 80 180 0 0 1/5/2018 80 180 0 0 1/4/2018 80 180 0 0 1/3/2018 80 180 0 0 1/2/2018 80 170 0 0 1/1/2018 80 170 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Hileorp Alaska, LLC July 7, 2017 Post Office Box 244027 Anchorage, AK 99524-4027 3800 Centerpoint Drive Suite 100 Anchorage, AK 99503 Phone: 907/777-8322 Fax: 907/777-8580 Mr.Hollis S. French, Chair Ala RECEIVED Alaska Oil &Gas Conservation Commission 333 W. 7`s Avenue, Suite 100 JUL 1 0 2011 Anchorage, Alaska 99501-3539 ff A%r-%^r-I-%CC Re: 2016 Annual Disposal Report for the 13-31 & 14-31 Wells in the Ivan River Unit Dear Mr. French, This is the 2016 Annual Report for the UIC Class II disposal operation in the IRU 13-31 (DIO 35) and IRU 14-17 (DIO 23) wellbores. The attached plots shows that injection rates and pressures for both wells were well below the regulatory limit of 4 barrels per minute and 5000psig. Furthermore, injection and annuli pressures indicate no mechanical concerns and that the injected fluid was contained to the approved disposal zone. Specific items to note for this reporting period: • A MIT is required every two years and the last MIT was performed 6-28-16. • In 2016, the fluids injected into the IRU 13-31 and 14-31 (432 and 314 barrels, respectively) wells were produced water from the Ivan River, Pretty Creek, and Lewis River fields. • Maximum pressures in both wells during injection never exceeded 1600psig. Sincerely, q J�� Jim Young Reservoir Engineer Attachment 1 - IRU 13-31 Injection rates and pressures Attachment 2 - IRU 14-31 Injection rates and pressures Vanessa Hughes Reservoir Engineer O'. C p O O p \O SISd H ti 00 O O O O W 10 R N p N H Well: IRU 13-31 Desc Shut -In Permit to drill: 1920880 Admin Approval: DIO #35 API: 50-283-20086-00-00 Date Range: l2/30/2015-01/02/2017 Date Tubing IA OA OOA Water Injection 1/2/2017 20 170 0 0 0 1/1/2017 30 170 0 0 0 12/31/201 141 170 0 0 0 12/30/201 141 170 0 0 0 12/29/201 141 170 0 0 0 12/28/201 141 170 0 0 0 12/27/201 141 180 0 0 12/26/201 141 180 0 0 0 12/25/201 141 180 0 0 0 12/24/201 141 180 0 0 0 12/23/201 141 180 0 0 0 12/22/201 141 180 0 0 0 12/21/201 141 180 0 0 0 12/20/201 50 170 0 12/19/201 50 170 0 12/18/201 50 170 0 12/17/201 50 170 0 12/16/201 50 170 0 12/15/201 50 170 0 12/14/201 50 170 0 12/13/201 0 12/12/201 120 170 0 0 0 12/11/201 120 170 0 0 0 12/10/201 120 170 0 0 0 12/9/2016 120 170 0 0 0 12/8/2016 0 12/7/2016 140 170 0 0 0 12/6/2016 55 175 0 0 0 12/5/2016 55 175 0 0 0 12/4/2016 55 175 0 0 0 12/3/2016 55 175 0 0 0 12/2/2016 55 175 0 2 0 12/1/2016 55 175 0 2 0 11/30/201 55 175 0 2 0 11/29/201 55 175 0 2 0 11/28/201 120 175 0 0 0 11/27/201 120 175 0 0 0 11/26/201 120 175 0 0 0 11/25/201 120 175 0 0 0 11/24/201 120 175 0 0 0 11/23/201 100 170 0 0 0 11/22/201 100 170 0 0 0 11/21/201 100 170 0 0 0 Date Tubing IA OA ODA Water Injection 11/20/201 100 170 0 0 0 11/19/201 100 170 0 0 0 11/18/201 52 178 0 2 0 11/17/201 52 178 0 2 0 11/16/201 52 178 0 2 0 11/15/201 52 178 0 2 0 11/14/201 52 178 0 2 0 11/13/201 52 178 0 2 0 11/12/201 52 178 0 2 0 11/11/201 52 178 0 2 0 11/10/201 52 178 0 2 0 11/9/2016 52 178 0 2 0 11/8/2016 52 178 0 2 0 11/7/2016 52 178 0 2 0 11/6/2016 52 178 0 2 0 11/5/2016 52 178 0 2 0 11/4/2016 52 178 0 2 0 11/3/2016 52 178 0 2 0 11/2/2016 52 180 0 2 0 11/1/2016 52 180 0 2 0 10/31/201 52 180 0 2 0 10/30/201 52 180 0 2 0 10/29/201 52 180 0 2 0 10/28/201 52 180 0 2 0 10/27/201 52 180 0 2 0 10/26/201 52 180 0 2 0 10/25/201 52 180 0 10/24/201 52 180 0 10/23/201 2 180 0 10/22/201 52 180 0 10/21/201 52 180 0 10/20/201 52 1S0 0 10/19/201 52 180 0 10/18/201 52 180 0 2 0 10/17/201 52 180 0 2 0 10/16/201 52 180 0 2 0 10/15/201 52 180 0 2 0 10/14/201 52 180 0 2 0 10/13/201 52 180 0 2 0 10/12/201 52 180 0 2 0 10/11/201 52 180 0 10/10/201 52 180 0 10/9/2016 52 180 0 10/8/2016 52 185 0 10/7/2016 52 185 0 10/6/2016 52 185 0 10/5/2016 52 185 0 10/4/2016 52 185 0 2 0 10/3/2016 52 185 0 2 0 10/2/2016 52 185 0 2 0 10/1/2016 52 185 0 2 0 Date Tubing IA OA ODA Water Injection 9/30/2016 52 185 0 2 0 9/29/2016 52 185 0 2 0 9/28/2016 51 185 0 2 0 9/27/2016 1140 185 0 2 19 9/26/2016 56 185 0 2 0 9/25/2016 56 185 0 2 0 9/24/2016 54 185 0 2 0 9/23/2016 54 185 0 2 0 9/22/2016 53 185 0 2 0 9/21/2016 50 185 0 2 0 9/20/2016 54 185 0 2 0 9/19/2016 54 185 0 2 0 9/18/2016 53 185 0 2 0 9/17/2016 53 185 0 2 0 9/16/2016 53 185 0 2 0 9/15/2016 53 185 0 2 0 9/14/2016 50 185 0 2 0 9/13/2016 50 185 0 2 0 9/12/2016 50 185 0 2 0 9/11/2016 50 185 0 2 0 9/10/2016 48 185 0 2 0 9/9/2016 46 185 0 2 0 9/8/2016 44 185 0 2 0 9/7/2016 60 185 0 2 0 9/6/2016 60 180 0 2 0 9/5/2016 60 180 0 2 0 9/4/2016 60 180 0 2 0 9/3/2016 60 180 0 2 0 9/2/2016 60 180 0 2 0 9/1/2016 60 180 0 2 0 8/31/2016 60 180 0 2 0 8/30/2016 60 180 0 2 0 8/29/2016 60 180 0 2 0 8/28/2016 60 180 0 2 0 8/27/2016 60 180 0 2 0 8/26/2016 60 180 0 2 0 8/25/2016 60 180 0 2 0 8/24/2016 60 180 0 2 0 8/23/2016 60 180 0 2 0 8/22/2016 60 180 0 2 0 8/21/2016 60 180 0 2 0 8/20/2016 60 180 0 2 0 8/19/2016 60 180 0 2 0 8/18/2016 60 180 0 2 0 8/17/2016 60 180 0 2 0 8/16/2016 60 180 0 2 0 8/15/2016 60 180 0 2 0 8/14/2016 60 180 0 2 0 8/13/2016 60 180 0 2 0 8/12/2016 60 180 0 2 0 8/11/2016 60 180 0 2 0 Date Tubing IA OA ODA Water Injection 8/10/2016 60 180 0 2 0 8/9/2016 60 180 0 2 0 8/8/2016 60 180 0 2 0 8/7/2016 60 180 0 2 0 8/6/2016 60 180 0 2 0 8/5/2016 60 180 0 2 0 8/4/2016 60 180 0 2 0 8/3/2016 60 180 0 2 0 8/2/2016 60 195 0 2 0 8/1/2016 60 195 0 2 0 7/31/2016 1223 215 0 2 5 7/30/2016 62 195 0 2 0 7/29/2016 62 195 0 2 0 7/28/2016 62 195 0 2 0 7/27/2016 62 195 0 2 0 7/26/2016 61 195 0 2 0 7/25/2016 1341 195 0 2 14 7/24/2016 60 195 0 2 0 7/23/2016 1277 195 0 2 14 7/22/2016 61 195 0 2 0 7/21/2016 61 195 0 2 0 7/20/2016 61 195 0 2 0 7/19/2016 61 195 0 2 0 7/18/2016 61 195 0 2 0 7/17/2016 61 195 0 2 0 7/16/2016 61 195 0 2 0 7/15/2016 61 195 0 2 0 7/14/2016 61 195 0 2 0 7/13/2016 61 195 0 2 0 7/12/2016 61 195 0 2 0 7/11/2016 61 195 0 2 0 7/10/2016 61 195 0 2 0 7/9/2016 61 195 0 2 0 7/8/2016 61 195 0 2 0 7/7/2016 61 195 0 2 0 7/6/2016 61 195 0 2 0 7/5/2016 61 195 0 2 0 7/4/2016 61 195 0 2 0 7/3/2016 1373 290 0 2 26.5 7/2/2016 45 160 0 2 0 7/1/2016 45 160 0 2 0 6/30/2016 45 160 0 2 0 6/29/2016 45 160 0 2 0 6/28/2016 45 160 0 2 0 6/27/2016 50 175 0 2 0 6/26/2016 50 175 0 2 0 6/25/2016 50 175 0 2 0 6/24/2016 50 175 0 2 0 6/23/2016 50 175 0 2 0 6/22/2016 50 175 0 2 0 6/21/2016 44 175 0 2 0 Date Tubing IA OA OOA Water Injection 6/20/2016 44 175 0 2 0 6/19/2016 44 175 0 2 0 6/18/2016 44 175 0 2 0 6/17/2016 44 175 0 2 0 6/16/2016 44 175 0 2 0 6/15/2016 44 175 0 2 0 6/14/2016 44 175 0 2 0 6/13/2016 44 175 0 2 0 6/12/2016 44 175 0 2 0 6/11/2016 44 175 0 2 0 6/10/2016 44 175 0 2 0 6/9/2016 44 175 0 2 0 6/8/2016 43 175 0 2 0 6/7/2016 43 175 0 2 0 6/6/2016 44 175 0 2 0 6/5/2016 44 175 0 2 0 6/4/2016 60 170 0 2 0 6/3/2016 60 170 0 2 0 6/2/2016 60 170 0 2 0 6/1/2016 60 170 0 2 0 5/31/2016 60 170 0 2 0 5/30/2016 60 170 0 2 0 5/29/2016 60 170 0 2 0 5/28/2016 60 170 0 2 0 5/27/2016 60 170 0 2 0 5/26/2016 60 170 0 2 0 5/25/2016 60 170 0 2 0 5/24/2016 60 165 0 2 0 5/23/2016 60 165 0 2 0 5/22/2016 60 165 0 2 0 5/21/2016 60 160 0 2 0 5/20/2016 60 160 0 2 0 5/19/2016 60 160 0 2 0 5/18/2016 60 160 0 2 0 5/17/2016 60 160 0 2 0 5/16/2016 60 160 0 2 0 5/15/2016 1363 160 0 2 32 5/14/2016 60 160 0 2 0 5/13/2016 1273 160 0 2 32 5/12/2016 61 160 0 2 0 5/11/2016 61 160 0 2 0 5/10/2016 61 160 0 2 0 5/9/2016 61 160 0 2 0 5/8/2016 1298 225 0 2 36 5/7/2016 60 165 0 2 0 5/6/2016 60 165 0 2 0 5/5/2016 1350 225 0 2 31 5/4/2016 62 160 0 2 0 5/3/2016 1328 160 0 2 38 5/2/2016 1424 160 0 2 38 5/1/2016 1342 160 0 2 32 Date Tubing IA OA OOA Water Injection 4/30/2016 63 160 0 2 0 4/29/2016 63 160 0 2 0 4/28/2016 63 160 0 2 0 4/27/2016 63 160 0 2 0 4/26/2016 63 160 0 2 0 4/25/2016 63 160 0 2 0 4/24/2016 63 160 0 2 0 4/23/2016 63 160 0 2 0 4/22/2016 63 160 0 2 0 4/21/2016 63 160 0 2 0 4/20/2016 63 160 0 2 0 4/19/2016 63 160 0 2 0 4/18/2016 63 160 0 2 0 4/17/2016 63 160 0 2 0 4/16/2016 63 160 0 2 0 4/15/2016 63 160 0 2 0 4/14/2016 63 160 0 2 0 4/13/2016 63 160 0 2 0 4/12/2016 63 160 0 2 0 4/11/2016 63 160 0 2 0 4/10/2016 63 160 0 2 0 4/9/2016 63 160 0 2 0 4/8/2016 63 160 0 2 0 4/7/2016 63 160 0 2 0 4/6/2016 63 160 0 2 0 4/5/2016 63 160 0 2 0 4/4/2016 63 160 0 2 0 4/3/2016 63 160 0 2 0 4/2/2016 63 160 0 2 0 4/1/2016 63 170 0 4 0 3/31/2016 63 170 0 4 0 3/30/2016 63 170 0 4 0 3/29/2016 63 170 0 4 0 3/28/2016 63 170 0 4 0 3/27/2016 63 170 0 4 0 3/26/2016 63 170 0 4 0 3/25/2016 63 170 0 4 0 3/24/2016 1251 220 0 3 14 3/23/2016 58 160 0 3 0 3/22/2016 58 160 0 3 0 3/21/2016 58 160 0 3 0 3/20/2016 58 160 0 3 0 3/19/2016 58 160 0 3 0 3/18/2016 58 160 0 3 0 3/17/2016 58 160 0 3 0 3/16/2016 58 160 0 3 0 3/15/2016 58 160 0 3 0 3/14/2016 56 160 0 3 0 3/13/2016 53 160 0 3 0 3/12/2016 50 160 0 3 0 3/11/2016 47 160 0 3 0 Date Tubing IA OA OOA Water Injection 3/10/2016 44 160 0 3 0 3/9/2016 63 160 0 3 0 3/8/2016 63 160 0 3 0 3/7/2016 63 160 0 3 0 3/6/2016 63 160 0 3 0 3/5/2016 63 160 0 3 0 3/4/2016 63 160 0 3 0 3/3/2016 63 160 0 3 0 3/2/2016 63 160 0 3 0 3/1/2016 63 160 0 3 0 2/29/2016 63 160 0 3 0 2/28/2016 63 160 0 3 0 2/27/2016 63 160 0 3 0 2/26/2016 63 160 0 3 0 2/25/2016 63 160 0 3 0 2/24/2016 63 160 0 3 0 2/23/2016 63 160 0 3 0 2/22/2016 63 160 0 3 0 2/21/2016 63 160 0 3 0 2/20/2016 63 160 0 3 0 2/19/2016 63 160 0 3 0 2/18/2016 63 160 0 3 0 2/17/2016 63 160 0 3 0 2/16/2016 63 160 0 3 0 2/15/2016 63 160 0 3 0 2/14/2016 63 160 0 3 0 2/13/2016 63 160 0 3 0 2/12/2016 63 160 0 3 0 2/11/2016 63 160 0 3 0 2/10/2016 63 160 0 3 0 2/9/2016 63 160 0 3 0 2/8/2016 63 160 0 3 0 2/7/2016 63 160 0 3 0 2/6/2016 63 160 0 3 0 2/5/2016 63 160 0 3 0 2/4/2016 63 160 0 3 0 2/3/2016 63 160 0 3 0 2/2/2016 63 160 0 3 0 2/1/2016 63 160 0 3 0 1/31/2016 63 160 0 3 0 1/30/2016 63 160 0 3 0 1/29/2016 63 160 0 3 0 1/28/2016 63 165 0 3 0 1/27/2016 53 165 0 3 0 1/26/2016 53 165 0 3 0 1/25/2016 59 165 0 3 0 1/24/2016 61 165 0 3 0 1/23/2016 59 165 0 3 0 1/22/2016 63 165 0 3 0 1/21/2016 1277 165 0 3 16 1/20/2016 63 165 0 3 0 Date Tubing IA OA OOA Water Injection 1/19/2016 63 165 0 3 0 1/18/2016 63 165 0 3 0 1/17/2016 63 165 0 3 0 1/16/2016 63 165 0 3 0 1/15/2016 63 165 0 3 0 1/14/2016 63 165 0 3 0 1/13/2016 58 165 0 3 0 1/12/2016 58 165 0 3 0 1/11/2016 63 165 0 3 0 1/10/2016 62 165 0 3 0 1/9/2016 1464 165 0 3 30 1/8/2016 1579 165 0 3 55 1/7/2016 58 165 0 3 0 1/6/2016 46 165 0 3 0 1/5/2016 46 165 0 3 0 1/4/2016 46 165 0 3 0 1/3/2016 48 165 0 3 0 1/2/2016 48 165 0 3 0 1/1/2016 46 165 0 3 0 12/31/201 44 165 0 3 0 12/30/201 63 165 0 3 0 o � slaa u _- 0 0 G o C pisd N 111 L 0 0 0 0 0 0 Well: IRU 14-31 Desc: Disposal Permit to drill: 1750080 Admin Approval: DIO #23 API: 50-283-20045-00-00 Date Range: l2/30/2015-01/02/2017 Date Tubing IA OA OOA Water Injection 1/2/2017 44 118 18 0 0 1/1/2017 44 118 18 0 0 12/31/201 44 118 18 0 0 12/30/201 44 118 18 0 0 12/29/201 44 118 18 0 0 12/28/201 44 118 18 0 0 12/27/201 44 118 18 0 0 12/26/201 43 118 18 0 0 12/25/201 41 118 18 0 0 12/24/201 1160 118 18 0 20 12/23/201 40 118 18 0 0 12/22/201 41 118 18 0 0 12/21/201 42 118 18 0 0 12/20/201 42 118 0 12/19/201 42 118 0 12/18/201 42 118 0 12/17/201 42 118 0 12/16/201 42 118 0 12/15/201 42 118 0 12/14/201 42 118 0 12/13/201 0 12/12/201 100 118 0 18 0 12/11/201 100 118 0 18 0 12/10/201 100 118 0 18 0 12/9/2016 100 118 0 18 0 12/8/2016 0 12/7/2016 100 118 0 18 0 12/6/2016 40 118 0 18 0 12/5/2016 39 118 0 18 0 12/4/2016 1207 118 0 18 13 12/3/2016 42 118 0 18 0 12/2/2016 1021 110 0 20 14 12/1/2016 100 110 0 20 0 11/30/201 100 110 0 20 0 11/29/201 100 118 0 20 0 11/28/201 100 110 0 0 0 11/27/201 75 110 0 0 0 11/26/201 60 110 0 0 0 11/25/201 53 110 0 0 0 11/24/201 52 110 0 0 0 11/23/201 50 110 0 0 0 11/22/201 50 110 0 0 0 11/21/201 50 110 0 0 0 Date Tubing IA OA OOA Water Injection 11/20/201 50 110 0 0 0 11/19/201 50 110 0 0 0 11/18/201 50 110 0 0 0 11/17/201 50 110 0 0 0 11/16/201 44 118 0 0 0 11/15/201 44 118 0 0 0 11/14/201 44 118 0 0 0 11/13/201 44 118 0 0 0 11/12/201 44 118 0 0 0 11/11/201 44 118 0 0 0 11/10/201 44 118 0 0 0 11/9/2016 44 118 0 0 0 11/8/2016 43 118 0 0 0 11/7/2016 44 118 0 0 0 11/6/2016 43 118 0 0 0 11/5/2016 43 120 0 0 0 11/4/2016 43 120 0 0 0 11/3/2016 43 120 0 0 0 11/2/2016 43 130 0 0 0 11/1/2016 43 130 0 0 0 10/31/201 42 130 0 0 0 10/30/201 42 130 0 0 0 10/29/201 42 130 0 0 0 10/28/201 42 130 0 0 0 10/27/201 42 130 0 0 0 10/26/201 42 130 0 0 0 10/25/201 42 130 0 10/24/201 42 130 0 10/23/201 42 130 0 10/22/201 42 130 0 10/21/201 42 130 0 10/20/201 42 130 0 10/19/201 42 130 0 10/18/201 42 130 0 0 0 10/17/201 41 130 0 0 0 10/16/201 41 130 0 0 0 10/15/201 42 130 0 0 0 10/14/201 40 130 0 0 0 10/13/201 1071 130 0 0 33 10/12/201 42 130 0 0 0 10/11/201 42 130 0 10/10/201 41 130 0 10/9/2016 41 130 0 10/8/2016 40 100 0 10/7/2016 40 100 0 10/6/2016 40 100 0 10/5/2016 40 100 0 10/4/2016 38 100 0 0 0 10/3/2016 1088 100 0 0 23 10/2/2016 41 100 0 0 0 10/1/2016 41 100 0 0 0 Date Tubing IA OA ODA Water Injection 9/30/2016 41 100 0 0 0 9/29/2016 41 100 0 0 0 9/28/2016 41 100 0 0 0 9/27/2016 41 100 0 0 0 9/26/2016 41 120 0 0 0 9/25/2016 41 120 0 0 0 9/24/2016 41 120 0 0 0 9/23/2016 41 120 0 0 0 9/22/2016 41 120 0 0 0 9/21/2016 41 120 0 0 0 9/20/2016 41 120 0 0 0 9/19/2016 41 120 0 0 0 9/18/2016 41 120 0 0 0 9/17/2016 41 120 0 0 0 9/16/2016 41 120 0 0 0 9/15/2016 41 120 0 0 0 9/14/2016 41 120 0 0 0 9/13/2016 41 120 0 0 0 9/12/2016 41 120 0 0 0 9/11/2016 41 120 0 0 0 9/10/2016 41 120 0 0 0 9/9/2016 41 120 0 0 0 9/8/2016 41 120 0 0 0 9/7/2016 41 120 0 0 0 9/6/2016 40 120 0 0 0 9/5/2016 40 120 0 0 0 9/4/2016 38 120 0 0 0 9/3/2016 39 120 0 0 0 9/2/2016 38 120 0 0 0 9/1/2016 33 120 0 0 0 8/31/2016 1000 120 0 0 17 8/30/2016 43 120 0 0 0 8/29/2016 41 120 0 0 0 8/28/2016 995 120 0 0 22 8/27/2016 43 120 0 0 0 8/26/2016 43 120 0 0 0 8/25/2016 42 120 0 0 0 8/24/2016 42 120 0 0 0 8/23/2016 42 120 0 0 0 8/22/2016 42 120 0 0 0 8/21/2016 42 120 0 0 0 8/20/2016 42 120 0 0 0 8/19/2016 41 120 0 0 0 8/18/2016 41 120 0 0 0 8/17/2016 41 120 0 0 0 8/16/2016 34 120 0 0 0 8/15/2016 41 120 0 0 0 8/14/2016 41 120 0 0 0 8/13/2016 41 120 0 0 0 8/12/2016 41 120 0 0 0 8/11/2016 41 120 0 0 0 Date Tubing IA OA OOA Water Injection 8/10/2016 41 120 0 0 0 8/9/2016 41 120 0 0 0 8/8/2016 40 120 0 0 0 8/7/2016 40 140 0 0 0 8/6/2016 40 140 0 0 0 8/5/2016 41 140 0 0 0 8/4/2016 37 140 0 0 0 8/3/2016 1030 140 0 0 20 8/2/2016 37 105 0 0 0 8/1/2016 972 105 0 0 30 7/31/2016 50 105 0 0 0 7/30/2016 50 105 0 0 0 7/29/2016 50 105 0 0 0 7/28/2016 50 105 0 0 0 7/27/2016 50 105 0 0 0 7/26/2016 50 105 0 0 0 7/25/2016 50 105 0 0 0 7/24/2016 50 105 0 0 0 7/23/2016 50 105 0 0 0 7/22/2016 50 105 0 0 0 7/21/2016 50 105 0 0 0 7/20/2016 50 105 0 0 0 7/19/2016 50 105 0 0 0 7/18/2016 50 105 0 0 0 7/17/2016 50 105 0 0 0 7/16/2016 50 110 0 0 0 7/15/2016 50 110 0 0 0 7/14/2016 50 110 0 0 0 7/13/2016 50 110 0 0 0 7/12/2016 50 110 0 0 0 7/11/2016 50 110 0 0 0 7/10/2016 50 105 0 0 0 7/9/2016 50 105 0 0 0 7/8/2016 50 105 0 0 0 7/7/2016 50 105 0 0 0 7/6/2016 50 105 0 0 0 7/5/2016 50 105 0 0 7/4/2016 50 105 0 0 7/3/2016 50 95 0 0 0 7/2/2016 50 95 0 0 0 7/1/2016 50 95 0 0 0 6/30/2016 43 95 0 0 0 6/29/2016 43 95 0 0 0 6/28/2016 43 95 0 0 0 6/27/2016 42 35 0 0 0 6/26/2016 42 35 0 0 0 6/25/2016 42 35 0 0 0 6/24/2016 42 35 0 0 0 6/23/2016 42 35 0 0 0 6/22/2016 42 35 0 0 0 6/21/2016 37 35 0 0 Date Tubing IA OA OOA Water Injection 6/20/2016 37 35 0 0 6/19/2016 37 35 0 0 6/18/2016 43 35 0 0 6/17/2016 43 35 0 0 6/16/2016 43 35 0 0 6/15/2016 43 35 0 0 6/14/2016 43 35 0 0 0 6/13/2016 43 35 0 0 0 6/12/2016 43 35 0 0 0 6/11/2016 43 35 0 0 0 6/10/2016 43 35 0 0 0 6/9/2016 43 35 0 0 0 6/8/2016 61 35 0 0 0 6/7/2016 61 35 0 0 0 6/6/2016 60 35 0 0 0 6/5/2016 60 35 0 0 0 6/4/2016 60 35 0 0 0 6/3/2016 60 35 0 0 0 6/2/2016 60 35 0 0 0 6/1/2016 54 35 0 0 0 5/31/2016 42 35 0 0 0 5/30/2016 42 35 0 0 0 5/29/2016 42 35 0 0 0 5/28/2016 42 35 0 0 0 5/27/2016 42 35 0 0 0 5/26/2016 42 35 0 0 0 5/25/2016 42 35 0 0 0 5/24/2016 42 40 0 0 0 5/23/2016 42 40 0 0 0 5/22/2016 42 40 0 0 0 5/21/2016 42 40 0 0 0 5/20/2016 42 40 0 0 0 5/19/2016 42 40 0 0 0 5/18/2016 42 40 0 0 0 5/17/2016 42 40 0 0 0 5/16/2016 42 40 0 0 0 5/15/2016 42 40 0 0 0 5/14/2016 42 40 0 0 0 5/13/2016 42 40 0 0 0 5/12/2016 42 40 0 0 0 5/11/2016 42 40 0 0 0 5/10/2016 42 40 0 0 0 5/9/2016 42 40 0 0 0 5/8/2016 42 40 0 0 0 5/7/2016 42 40 0 0 0 5/6/2016 42 40 0 0 0 5/5/2016 42 40 0 0 0 5/4/2016 42 40 0 0 0 5/3/2016 42 40 0 0 0 5/2/2016 42 40 0 0 0 5/1/2016 42 40 0 0 0 Date Tubing IA OA OOA Water Injection 4/30/2016 42 40 0 0 0 4/29/2016 40 40 0 0 0 4/28/2016 961 40 0 0 33 4/27/2016 44 40 0 0 0 4/26/2016 44 40 0 0 0 4/25/2016 44 40 0 0 0 4/24/2016 44 40 0 0 0 4/23/2016 44 40 0 0 0 4/22/2016 44 40 0 0 0 4/21/2016 44 40 0 0 0 4/20/2016 43 40 0 0 0 4/19/2016 43 40 0 0 0 4/18/2016 43 40 0 0 0 4/17/2016 43 40 0 0 0 4/16/2016 43 40 0 0 0 4/15/2016 43 40 0 0 0 4/14/2016 42 40 0 0 0 4/13/2016 43 40 0 0 0 4/12/2016 43 40 0 0 0 4/11/2016 43 40 0 0 0 4/10/2016 43 40 0 0 0 4/9/2016 43 40 0 0 0 4/8/2016 43 40 0 0 0 4/7/2016 40 40 0 0 0 4/6/2016 40 40 0 0 0 4/5/2016 1089 40 0 0 28 4/4/2016 63 40 0 0 0 4/3/2016 62 40 0 0 0 4/2/2016 62 40 0 0 0 4/1/2016 62 40 0 0 0 3/31/2016 63 40 0 0 0 3/30/2016 63 40 0 0 0 3/29/2016 63 40 0 0 0 3/28/2016 63 40 0 0 0 3/27/2016 63 40 0 0 0 3/26/2016 63 40 0 0 0 3/25/2016 63 40 0 0 0 3/24/2016 63 40 0 0 0 3/23/2016 63 40 0 0 0 3/22/2016 63 40 0 0 0 3/21/2016 63 40 0 0 0 3/20/2016 63 40 0 0 0 3/19/2016 63 40 0 0 0 3/18/2016 63 40 0 0 0 3/17/2016 44 40 0 0 0 3/16/2016 44 40 0 0 0 3/15/2016 44 40 0 0 0 3/14/2016 44 40 0 0 0 3/13/2016 44 40 0 0 0 3/12/2016 44 40 0 0 0 3/11/2016 44 40 0 0 0 Date Tubing IA OA OOA Water Injection 3/10/2016 44 40 0 0 0 3/9/2016 43 40 0 0 0 3/8/2016 43 40 0 0 0 3/7/2016 43 40 0 0 0 3/6/2016 43 40 0 0 0 3/5/2016 43 40 0 0 0 3/4/2016 43 40 0 0 0 3/3/2016 43 40 0 0 0 3/2/2016 43 40 0 0 0 3/1/2016 42 40 0 0 0 2/29/2016 42 40 0 0 0 2/28/2016 42 40 0 0 0 2/27/2016 43 40 0 0 0 2/26/2016 42 40 0 0 0 2/25/2016 42 40 0 0 0 2/24/2016 40 60 0 0 0 2/23/2016 1108 60 0 0 37 2/22/2016 42 60 0 0 0 2/21/2016 42 60 0 0 0 2/20/2016 42 60 0 0 0 2/19/2016 42 60 0 0 0 2/18/2016 40 60 0 0 0 2/17/2016 1079 60 0 0 24 2/16/2016 45 30 0 0 0 2/15/2016 45 30 0 0 0 2/14/2016 45 30 0 0 0 2/13/2016 45 30 0 0 0 2/12/2016 45 30 0 0 0 2/11/2016 45 30 0 0 0 2/10/2016 44 30 0 0 2/9/2016 44 30 0 0 2/8/2016 44 30 0 0 2/7/2016 44 30 0 0 2/6/2016 44 30 0 0 2/5/2016 58 30 0 0 2/4/2016 58 30 0 0 2/3/2016 58 30 0 0 2/2/2016 58 30 0 0 2/1/2016 58 30 0 0 1/31/2016 58 30 0 0 1/30/2016 58 30 0 0 1/29/2016 58 30 0 0 1/28/2016 58 25 0 0 1/27/2016 58 25 10 0 1/26/2016 58 25 0 0 1/25/2016 58 25 10 0 1/24/2016 58 25 10 0 1/23/2016 58 25 10 0 1/22/2016 58 25 10 0 1/21/2016 58 24 10 0 1/20/2016 58 24 10 0 Date Tubing IA OA OOA Water Injection 1/19/2016 58 24 0 0 1/18/2016 58 24 0 0 1/17/2016 58 24 0 0 1/16/2016 58 24 0 0 1/15/2016 58 24 0 0 1/14/2016 58 24 0 0 1/13/2016 58 24 0 0 1/12/2016 58 25 0 0 1/11/2016 58 25 0 0 1/10/2016 58 25 0 0 1/9/2016 58 25 0 0 1/8/2016 58 25 0 0 1/7/2016 43 25 0 0 1/6/2016 58 25 0 0 1/5/2016 43 25 0 0 1/4/2016 43 25 0 0 1/3/2016 43 25 0 0 1/2/2016 43 25 0 0 1/1/2016 43 25 0 0 12/31/201 43 25 0 0 12/30/201 43 25 0 • • Hilcorp Alaska, LLC July 3, 2013 5 W3 JUL 0 Mr. Guy Schwartz AOGCC Alaska Oil & Gas Conservation Commission 333 W. 7th Avenue, Suite 100 Anchorage, Alaska 99501-3539 Post Office Box 244027 Anchorage, AK 99524-4027 3800 Centerpoint Drive Suite 100 Anchorage, AK 99503 Phone: 907/777-8440 Fax: 907/777-8580 jallen@hilcorp.com Re: 2012 Annual Disposal Report for the 13-31 Well in the Ivan River Unit Dear Mr. Schwartz: This is the 2012 Annual Report for the UIC Class II disposal operation in the IRU 13-31 wellbore. These disposal operations are governed by AOGCC Disposal Injection Order #35 issued 12/09/08. The attached plot shows injection pressures are stable and do not indicate any reservoir or mechanical concerns. Specific items to note for this reporting period: • On October 26, 2012 a successful MIT was witnessed by Jim Regg on the 13-31. A MIT is required every two years. • In 2012 the fluids injected into the IRU 13-31 well were essentially produced water from the Ivan River, Pretty Creek, and Lewis River fields. • The average monthly injection volume into IRU 13-31 during the reporting time period was 1892 barrels/month (-62 barrels/day). Water was injected intermittently over the year causing the injection rates to fluctuate from 0 to 17,431 barrels of water each month. • The average injection pressure was 156 psig and the maximum injection pressure was 3000 psig which is below the permitted 5000# maximum injection pressure. • Injection rates averaged 0.04 bpm for the year and never exceeded 2.5 BPM on any given day. These injection rates and injection pressures are lower than the injection rates estimated to fracture through confining zones. • Injection is contained within receiving intervals by confining lithologies within the Sterling formation, cement isolation of the wellbore, and the operating conditions. If you have any questions regarding the enclosed information please contact me at 777-8440. Sincerely, ��, U;Adi6--/ Jeff Allen Reservoir Engineer Ivan River 13-31- Pressure and Injection Rates vs Time 4000 3500 --- —Tubing Pressure 3500 3000 7" Casing Pressure 9-5/8" Casing Pressure 3000 2500 Water Injected 2500 J m O° 2000 i 2000 ; 3 FA c ar a 1500 1500 3 1000 1000 500 500 0 0 Jan-12 Feb-12 Apr-12 May-12 Jul-12 Sep-12 Oct-12 Dec-12 Date • • • • Date Tubing 7 9 5/8 Water Injection 1/1/2012 100 810 0 0 1/2/2012 100 810 0 0 1/3/2012 100 810 0 0 1/4/2012 1001 810 0 0 1/5/2012 100 810 0 0 1/6/2012 100 810 0 0 1/7/2012 100 810 0 0 1/8/2012 100 810 0 0 1/9/2012 100 810 0 0 1/10/2012 100 810 0 0 1/11/2012 100 810 0 0 1/12/2012 100 810 0 0 1/13/2012 100 810 0 0 1/14/2012 100 810 0 0 1/15/2012 100 810 0 0 1/16/2012 100 800 0 0 1/17/2012 100 800 0 0 1/18/2012 100 800 0 0 1/19/2012 100 800 0 0 1/20/2012 100 800 0 0 1/21/2012 100 800 0 0 1/22/2012 100 800 0 0 1/23/2012 100 800 0 0 1/24/2012 100 800 0 0 1/25/2012 100 800 0 0 1/26/2012 100 800 0 0 1/27/2012 100 800 0 0 1/28/2012 100 800 0 0 1/29/2012 100 800 0 0 1/30/2012 100 800 0 0 1/31/2012 100 800 0 0 2/1/2012 100 800 0 0 2/2/2012 100 800 0 0 2/3/2012 100 800 0 0 2/4/2012 100 800 0 _ 0 2/5/2012 100 800', 0 0 2/6/2012 100 800 0 0 2/7/2012 100 800 0 0 2/8/2012 100 800 0 0 2/9/2012 100 800 0 0 2/10/2012 100 800 0 0 2/11/2012 100 800 0 0 2/12/2012 100 800 0 0 2/13/2012 100 800 0 0 2/14/20121 1001 800 0 0 2/15/20121 1001 8001 0 0 • 2/16/2012 100 800 0 0 2/17/2012 100 800 0 0 2/18/2012 100 800 0 0 2/19/2012 100 800 0 0 2/20/2012 100 800 0 0 2/21/2012 100 800 0 0 2/22/2012 100 800 0 0 2/23/2012 100 800 0 0 2/24/2012 100 800 0 0 2/25/2012 100 800 0 0 2/26/2012 100 800 0 0 2/27/2012 100 800 0 0 2/28/2012 100 800 0 0 2/29/2012 100 800 0 0 3/1/2012 100 800 0 0 3/2/2012 100 800 0 0 3/3/2012 100 800 0 0 3/4/2012 100 800 0 0 3/5/2012 100 800 0 0 3/6/2012 150 800 0 0 3/7/2012 150 800 0 0 3/8/2012 150 800 0 0 3/9/2012 200 800 0 0 3/10/2012 150 800 0 0 3/11/2012 150 800 0 0 3/12/2012 150 800 0 0 3/13/2012 150 800 0 0 3/14/2012 200 800 0 0 3/15/2012 150 800 0 0 3/16/2012 150 800 0 0 3/17/2012 150 800 0 0 3/18/2012 150 800 0 0 3/19/2012 150 800 0 0 3/20/2012 100 800 0 0 3/21/2012 100 800 0 0 3/22/2012 100 800 0 0 3/23/2012 100 800 0 0 3/24/2012 100 800 0 0 3/25/2012 100 800 0 0 3/26/2012 100 800 0 0 3/27/2012 100 800 0 0 3/28/2012 100 800 0 0 3/29/2012 100 800 0 0 3/30/2012 100 800 0 0 3/31/2012 1001 800 0 0 4/1/2012 1001 800 0 0 4/2/2012 1101 800 0 0 0 • 4/3/2012 110 800 0 0 4/4/2012 150 800 0 0 4/5/2012 150 800 0 0 4/6/2012 150 800 0 0 4/7/2012 150 800 0 0 4/8/2012 150 800 0 0 4/9/2012 150 800 0 0 4/10/2012 150 800 0 0 4/11/2012 150 800 0 0 4/12/2012 150 800 0 0 4/13/2012 150 800 0 0 4/14/2012 150 800 0 0 4/15/2012 150 800 0 0 4/16/2012 150 800 0 0 4/17/2012 150 800 0 0 4/18/2012 150 800 0 0 4/19/2012 150 800 0 0 4/20/2012 150 800 0 0 4/21/2012 150 800 0 0 4/22/2012 150 800 0 0 4/23/2012 150 800 0 0 4/24/2012 150 800 0 0 4/25/2012 150 800 0 0 4/26/2012 150 800 0 0 4/27/2012 150 800 0 0 4/28/2012 150 800 0 0 4/29/2012 150 800 0 0 4/30/2012 150 800 0 0 5/1/2012 150 800 0 0 5/2/2012 150 800 0 0 5/3/2012 150 800 0 0 5/4/2012 61 800 0 10 5/5/2012 61 800 0 0 5/6/2012 61 800 0 0 5/7/2012 3 800 0 0 5/8/2012 3 800 0 0 5/9/2012 3 800 0 0 5/10/2012 9 800 0 0 5/11/2012 9 800 0 0 5/12/2012 4 800 0 0 5/13/2012 4 800 0 0 5/14/2012 4 800 0 0 5/15/2012 4 800 0 0 5/16/2012 4 800 0 0 5/17/2012 41 800 0 0 5/18/2012 31 800 0 0 5/19/2012 31 800 0 0 • :7 5/20/2012 3 800 0 0 5/21/2012 3 800 0 0 5/22/2012 3 800 0 0 5/23/2012 3 800 0 0 5/24/2012 0 800 0 14 5/25/2012 0 800 0 14 5/26/2012 0 800 0 0 5/27/2012 0 800 0 0 5/28/2012 0 800 0 0 5/29/2012 0 800 0 0 5/30/2012 0 800 0 0 5/31/2012 72 800 0 30 6/1/2012 0 800 0 0 6/2/2012 0 800 0 0 6/3/2012 0 800 0 0 6/4/2012 0 800 0 0 6/5/2012 0 800 0 0 6/6/2012 0 800 0 0 6/7/2012 0 800 0 0 6/8/2012 0 800 0 0 6/9/2012 0 800 0 0 6/10/2012 0 800 0 0 6/11/2012 0 800 0 0 6/12/2012 0 800 0 0 6/13/2012 0 800 0 0 6/14/2012 0 800 0 0 6/15/2012 0 800 0 0 6/16/2012 0 800 0 0 6/17/2012 0 800 0 0 6/18/2012 0 800 0 0 6/19/2012 0 800 0 0 6/20/2012 0 800 0 0 6/21/2012 0 800 0 0 6/22/2012 0 800 0 0 6/23/2012 0 800 0 0 6/24/2012 0 800 0 0 6/25/2012 0 800 0 0 6/26/2012 0 800 0 0 6/27/2012 0 800 0 0 6/28/2012 0 800 0 0 6/29/2012 0 800 0 0 6/30/2012 0 800 0 0 7/1/2012 0 800 0 0 7/2/2012 0 800 0 0 7/3/2012 0 8001 OF 0 7/4/2012 ol 8001 ol 0 7/5/2012 ol 8001 ol 0 E 7/6/2012 0 800 0 0 7/7/2012 0 800 0 0 7/8/2012 0 800 0 0 7/9/2012 0 800 0 0 7/10/2012 0 800 0 0 7/11/2012 0 800 0 0 7/12/2012 0 800 0 0 7/13/2012 0 800 0 0 7/14/2012 0 800 0 0 7/15/2012 2600 800 0 665 7/16/2012 3000 800 0 2659 7/17/2012 3000 800 0 3594 7/18/2012 3000 900 0 3314 7/19/2012 3000 650 0 3599 7/20/2012 3000 750 0 3600 7/21/2012 125 750 0 0 7/22/2012 125 550 0 0 7/23/2012 125 550 0 0 7/24/2012 125 550 0 0 7/25/2012 125 550 0 0 7/26/2012 125 550 0 0 7/27/2012 125 550 0 0 7/28/2012 125 550 0 0 7/29/2012 125 550 0 0 7/30/2012 125 550 0 0 7/31/2012 125 550 0 0 8/1/2012 125 550 0 0 8/2/2012 125 550 0 0 8/3/2012 125 550 0 0 8/4/2012 125 550 0 0 8/5/2012 125 550 0 0 8/6/2012 125 550 0 0 8/7/2012 125 370 0 0 8/8/2012 125 370 0 0 8/9/2012 125 370 0 0 8/10/2012 125 370 0 0 8/11/2012 125 370 0 0 8/12/2012 125 370 0 0 8/13/2012 125 370 0 0 8/14/2012 125 370 0 0 8/15/2012 125 370 0 0 8/16/2012 125 370 0 0 8/17/2012 125 370 0 0 8/18/2012 125 370 0 0 8/19/2012 125 360 0 0 8/20/2012 1251 360 0 0 8/21/2012 30001 360 0 1768 • is 8/22/2012 24 425 0 0 8/23/2012 24 360 0 0 8/24/2012 24 360 0 0 8/25/2012 24 360 0 0 8/26/2012 24 360 0 0 8/27/2012 24 360 0 0 8/28/2012 24 360 0 0 8/29/2012 24 360 0 0 8/30/2012 24 360 0 0 8/31/2012 24 360 0 0 9/1/2012 24 300 0 0 9/2/2012 24 300 0 0 9/3/2012 24 300 0 0 9/4/2012 24 300 0 0 9/5/2012 24 300 0 0 9/6/2012 24 300 0 0 9/7/2012 24 300 0 0 9/8/2012 24 300 0 0 9/9/2012 24 300 0 0 9/10/2012 24 300 0 0 9/11/2012 24 300 0 0 9/12/2012 24 300 0 0 9/13/2012 2900 300 0 1717 9/14/2012 24 300 0 0 9/15/2012 24 300 0 0 9/16/2012 24 300 0 0 9/17/2012 24 300 0 0 9/18/2012 24 300 0 0 9/19/2012 24 300 0 0 9/20/2012 24 300 0 0 9/21/2012 24 300 0 0 9/22/2012 24 300 0 0 9/23/2012 24 300 0 0 9/24/2012 24 300 0 0 9/25/2012 24 300 0 0 9/26/2012 50 250 0 0 9/27/2012 24 250 0 0 9/28/2012 24 300 0 0 9/29/2012 24 300 0 0 9/30/2012 24 300 0 0 10/1/2012 24 300 0 0 10/2/2012 24 300 0 0 10/3/2012 24 300 0 0 10/4/2012 24 300 0 0 10/5/2012 29001 300 0 771 10/6/2012 ol 125 0 0 10/7/2012 ol 1251 0 0 • • 10/8/2012 0 125 0 0 10/9/2012 0 0 0 0 10/10/2012 0 0 0 0 10/11/2012 24 0 0 0 10/12/2012 24 0 0 0 10/13/2012 24 0 0 0 10/14/2012 24 40 0 0 10/15/2012 10 100 0 0 10/16/2012 10 100 0 0 10/17/2012 10 100 0 0 10/18/2012 10 100 0 0 10/19/2012 10 100 0 0 10/20/2012 10 100 0 0 10/21/2012 10 100 0 0 10/22/2012 10 100 0 0 10/23/2012 10 100 0 0 10/24/2012 10 100 0 0 10/25/2012 10 100 0 0 10/26/2012 12 100 0 0 10/27/2012 12 100 0 0 10/28/2012 12 100 0 0 10/29/2012 12 100 0 0 10/30/2012 12 100 0 0 10/31/2012 12 100 0 0 11/1/2012 60 100 0 51 11/2/2012 226 140 0 68 11/3/2012 226 140 0 59 11/4/2012 220 140 0 30 11/5/2012 257 140 0 0 11/6/2012 218 140 0 60 11/7/2012 218 140 0 11 11/8/2012 510 140 0 160 11/9/2012 0 140 0 0 11/10/2012 488 140 0 37 11/11/2012 488 140 0 30 11/12/2012 0 140 0 0 11/13/2012 418 140 0 0 11/14/2012 0 140 0 0 11/15/2012 10 140 0 0 11/16/2012 525 140 0 43 11/17/2012 623 140 0 120 11/18/2012 545 140 0 43 11/19/2012 572 140 0 80 11/20/2012 ol 140 0 0 11/21/2012 554 140 0 46 11/22/2012 554 1401 ol 0 11/23/2012 409 1401 ol 5 • • 11/24/2012 409 100 0 42 11/25/2012 621 100 0 29 11/26/2012 3 100 0 0 11/27/2012 3 100 0 0 11/28/2012 3 100 0 0 11/29/2012 3 100 0 0 11/30/2012 3 100 0 0 12/1/2012 3 100 0 0 12/2/2012 4 100 0 0 12/3/2012 686 100 0 44 12/4/2012 119 100 0 0 12/5/2012 119 100 0 0 12/6/2012 104 100 0 0 12/7/2012 97 100 0 0 12/8/2012 91 100 0 0 12/9/2012 80 100 0 0 12/10/2012 50 120 0 0 12/11/2012 50 120 0 0 12/12/2012 50 120 0 0 12/13/2012 50 120 0 0 12/14/2012 50 100 0 0 12/15/2012 50 120 0 0 12/16/2012 50 120 0 0 12/17/2012 50 120 0 0 12/18/2012 50 120 0 0 12/19/2012 50 120 0 0 12/20/2012 50 120 0 0 12/21/2012 50 120 0 0 12/22/2012 50 120 0 0 12/23/2012 50 120 0 0 12/24/2012 50 120 0 0 12/25/2012 50 120 0 0 12/26/2012 50 120 0 0 12/27/2012 50 120 0 0 12/28/2012 50 120 0 0 12/29/2012 50 120 0 0 12/30/2012 50 120 0 0 12/31/20121 50 120 0 0 • 0 Chevron July 19, 2012 Philip M. Ayer Petroleum Engineer Mr. James Regg Alaska Oil & Gas Conservation Commission (AOGCC) 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Re: Disposal Report for the 13-31 Well in the Ivan River Unit Dear Mr. Regg: Union Oil Company of California P.O. Box 196247 Anchorage, AK 99519-6247 Tel 907 263 7620 Fax 907 263 7607 Email pmayer@chevron.com RECEIVED JUL 2 4 2012 AOGCC This is a revised 2011 Annual Report for UIC Class II disposal operations in the IRU 13-31 wellbore. These disposal operations are governed by AOGCC Disposal Injection Order #35 issued 12/09/08. The attached IRU 13-31 well injection history plot for 2011 shows injection pressures are stable and do not indicate any reservoir or mechanical concerns. Specific items to note for this reporting period: • On April 29, 2011 a successful MIT was witnessed by the SOA on IRU 13-31. A MIT is required every two years. • In 2011 the fluids injected into the IRU 13-31 well were essentially produced water from the Ivan River, Pretty Creek, and Lewis River fields. • The two large volumes injected in July were from the workovers on IRU 44-36 and 41-01. • The average monthly injection volume into IRU 13-31, during the reporting time period, was approximately 174 barrels/month (less than 6 b/d). Water was injected intermittently every two to three weeks resulting in water rate fluctuations from 0 to 1850 bbls of water each month. • The average injection pressure was approximately 236 psig which is below the permitted 5000 psig maximum injection pressure. • Injection rates and pressures were lower than the maximum allowable rates estimated to fracture through confining zones as well as lower than the fracture propagation pressure. Injection is contained within receiving intervals by confining lithologies within the Sterling Formation, cement isolation of the wellbore and operating conditions. • The calculated zone of influence for the injection fluids was an area within an approximate 33 foot radius surrounding the perforated injection interval. As you are aware, Union sold its Cook Inlet Oil and Gas operations to Hilcorp Alaska LLC. The closing date was December 31, 2011. If you have any questions or concerns going forward about Union Oil Company of California / A Chevron Company http://www.chevron.com 0 • Mr. Jim Regg AOGCC 7/19/12 Page 2 the enclosed information, please contact Larry Greenstein, who now works for Hilcorp. His phone number is 777-8322. Sincerely, *T44 I" Philip M Ayer Petroleum Engineer Attachment cc: Larry Greenstein - Hilcorp Alaska LLC File Union Oil Company of California / A Chevron Company http://www.chevron.com P essure & Rate vs Time - Well IVAN R 13 1200 3000 ------------ .. 7" _9 5/8" 1000 2500 13 3/8" _ 20" -Tubing -Vol 13-31 WD 800 2000 N 600p�p cu1500 [C 400 1000 200 500 0 A 0 0 M O t\ M Date 7" 9 5/8" 13 3/8" 20' Tubing TIO Report 01/01/12 $10 0 0 0 100 . 12/31/11 810 0 0 0 100 Data Sheet 12/30/11 810 0 0 0 100 12/29/11 810 0 0 0 100 12/28/11 810 0 0 0 100 0 IVAN R 13-31 12/27/11 810 0 0 0 100 0 12/26/11 810 0 0 0 100 0 12/25/11 800 0 0 0 100 0 FLOWING 12/24/11 800 0 0 0 100 0 12/23/11 80o 0 0 0 100 0 12/22/11 800 0 0 0 100 0 Permit # 12/21/11 800 0 0 0 100 0 12/20/11 800 0 0 0 100 0 12/19/11 800 0 0 0 100 0 API # 50-283-20086-00 12/18/11 800 0 0 0 100 0 12/17/11 Soo 0 0 0 100 0 12/16/11 800 0 0 0 100 0 12/31/2010 to 01/01/2012 12/15/11 800 0 0 0 100 0 12/14/11 Soo 0 0 0 100 26 12/13/11 810 0 0 0 100 0 12/12/11 810 0 0 0 100 0 12/11/11 810 0 0 0 100 0 12/10/11 810 0 0 0 100 9 12/09/11 810 0 0 0 100 12/08/11 810 0 0 0 100 0 12/07/11 810 0 0 0 100 0 12/06/11 810 0 0 0 100 0 12/05/11 810 0 0 0 100 0 12/04/11 810 0 0 0 100 0 12/03/11 810 0 0 0 100 0 12/02/11 810 0 0 0 100 0 12/01/11 810 0 0 0 100 0 11/30/11 810 0 0 0 100 0 11/29/11 810 0 0 0 100 0 11/28/11 810 0 0 0 100 0 11/27/11 0 0 0 100 0 7/19/2012 11:15 PM - TIO Reports 7e.xls IRU 13-31 14-31.xlsx IVAN R 13-31 • • Chevron David A. Cole Union Oil Company of California Technical Team Lead Ops P.O. Box 196247 Anchorage, 99519-6247 Tel el 907 7 7 263 7805 Fax 907 263 7847 Email dcole @chevron.com January 30, 2012 RECEIVED Mr. Tom Maunder Alaska Oil & Gas Conservation Commission (AOGCC) FEB 0 2 2012 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Alaska Oil & Gas Cons. Commission Anchorage Re: Disposal Report for the 13 -31 Well in the Ivan River Unit - �-- --- Dear Mr. Maunder: PAD z -o 3 This is the 2011 Annual Report for UIC Class II disposal operations in the IRU 13 -31 wellbore. These disposal operations are governed by AOGCC Disposal Injection Order #35 issued 12/09/08. The attached plot shows injection pressures are stable and do not indicate any reservoir or mechanical concerns. Specific items to note for this reporting period: • On April 29, 2011 a successful MIT was witnessed by the SOA on IRU 13 -31. A MIT is required every two years. • In 2011 the fluids injected into the IRU 13 -31 well were essentially produced water from the Ivan River, Pretty Creek, and Lewis River fields. • The two large volumes injected in July were from the workovers on IRU 44 -36 and 41 -01. As you are aware, Union sold its Cook Inlet Oil and Gas operations to Hilcorp Alaska LLC. The closing date was December 31, 2011. If you have any questions or concerns going forward about the enclosed information, please contact Larry Greenstein, who now works for Hilcorp. His phone number is 777 -8322. Sincerely, David A. Cole Technical Team Lead - Operations Attachment Union Oil Company of California / A Chevron Company http: / /www.chevron.com • Plot Prcere & Rate vs Time - Well IVAN R 13 -31 • - 1200 3000 7 " 1000 9 5/8 2500 13 3/8" x — Tubing — Vo113 -31 WD 800 2000 I a U N 6002 N a` 1500 I 400 1000 pp __ � JI_ ........ 200 500 — 0∎ i■■A•4■i ■A r wiimANIEC \■ J, .1 0 o a o i ' n rn co n m <o Q m O m Q M N N N N N N N n i75 n co n co Date 7" 9 5/8" 13 3/8" 20" Ictbing voll TIO Report 01/01/12 810 0 0 0 100 12/31/11 0 0 0 0 100 Data Sheet 12/30/11 10 0 0 0 100 12/29/11 810 0 0 0 100 12/28/11 810 0 0 0 100 o IVAN R 13 -31 12/27/11 810 0 0 0 100 0 12/26/11 810 0 0 0 100 0 12/25/11 800 0 0 0 100 o FLOWING 12/24/11 j 800 0 0 0 100 0 12/23/11 800 0 0 0 100 0 12 /22/11 800 0 0 0 100 0 Permit # 12/21/11 800 0 0 0 100 0 ICZ ' 12/20/11 800 0 0 0 100 0 12/19/11 > 800 0 0 0 100', o API # 50- 283 - 20086 -00 12/18/11 800 0 0 0 100, 0 12/17/11 800 0 0 0 100 0 12 /16/11 800 0 0 0 100 0 12/31/2010 to 01/01/2012 12/15/11 800 0 0 0 100, 0 12/14/11 800 0 0 0 100, 26 12 /13/11 810 0 0 0 100 0 12/12/11 4 810 0 0 0 100 0 12/11/11 810 0 0 0 100 0 12 /10 /11 810 0 0 0 100 9 12/09/11 810 0 0 0 100 12/08/11 4 810 0 0 0 100 0 12/07/11 810 0 0 0 100', 0 12/06/11 810 0 0 0 100 0 12/05/11 810 0 0 0 100 0 12/04/11 810 0 0 0 100 0 12/03/11 810 0 0 0 100 0 12/02/11 810 0 0 0 100 0 12/01/11 810 0 0 0 100 0 11/30/11 - 810 0 0 0 100 0 11/29/11 810 0 0 0 100', 0 11/28/11 810 0 0 0 100 0 11/27/11 810 0 0 0 100 0 • • Regg, James B (DOA) From: Larry Greenstein [Ireenstein ©hilcorp.com] Sent: Thursday, February 02, 2012 3:50 PM To: Regg, James B (DOA) Z I I r� Cc: Brandenburg, Tim C Subject: RE: DIO #28A Annual Report - NNA #1 Attachments: DIO #35 Annual Report (IRU 13 -31); DIO #28A Annual Report - NNA #1 1' t l -DeA Jim, I believe Dave Cole was trying to complete these annual reports for the calendar year 2011 prior to his leaving Chevron's employment. It appears that in trying to get this done quickly (as he is gone now) he missed the specific requirements you highlighted in your e- mails. These deficiencies are being sent to Chevron for completion and I will follow up with them. Hilcorp plans to submit these reports by the July 1 dates covering the previous calendar year (ie by July 1, 2013 for the 2012 calendar year) just as Chevron has been doing. Chevron was completing these reports (for DIO #28 & DIO #35) — early just due to the special circumstance of the Cook Inlet Asset sale to Hilcorp. Sorry for the inconvenience. Larry From: Regg, James B (DOA) [mailto:jim.regg(aalaska.gov] Sent: Thursday, February 02, 2012 2:14 PM To: Larry Greenstein Subject: DIO #28A Annual Report - NNA #1 Report we received from David Cole is incomplete per requirements of DIO # :A, Rule 5. I've highlighted what is missing. RULE 5: Surveillance The operator shall obtain a baseline temperature log and a b.:eline step rate test prior to initial injection. A subsequent temperature log must be pe 'ormed 1 month after injection begins to demonstrate the receiving zone of the injecte uids. Additional temperature survey requirements will be based on the results of t► - initial and follow -up temperature surveys. An annual report for the calendar year evaluati : the performance of the disposal operation must be submitted by July 1 of eac' year. The report shall include pressures, fluid volumes (disposal and clean fluid sw eps), fluid make -up, injection rates, an assessment of fracture height growth, snd a description of any anomalous injection results. During the first year of injecti .n, a monthly evaluation of injection monitoring results must be provided to the Co ission with an emphasis on fracture height growth. Also regarding the Annual DIO r; sorts for this and DIO 35 (separate email), will Hilcorp be submitting partial year reports (due by July 1) or will - ports be for calendar years (carrying forward the Chevron rpts)? Jim Regg AOGCC 1 • • Regg, James B (DOA) From: Regg, James B (DOA) Sent: Thursday, February 02, 2012 2:05 PM To: 'Larry Greenstein' Subject: DIO #35 Annual Report (IRU 13 -31) Report we received from David Cole is incomplete per requirements of DIO #35, Rule 6. I've highlighted what is missing. RULE 6: Surveillance The operator shall run a baseline temperature log and perform a baseline step -rate test prior to initial injection. A subsequent temperature log must be run one month after injection begins to delineate the receiving zone of the injected fluids. Surface pressures and rates must be monitored continuously during injection for any indications of anomalous conditions. Results of daily wellhead pressure observations in IRU Well 13 -31 must be documented and available to the Commission upon request. The conduct of subsequent temperature surveys or other surveillance logging (e.g., water flow; acoustic) will be based on the results of the initial and follow -up temperature surveys and injection performance monitoring data. A report evaluating the performance of the disposal operation must be submitted to the Commission by July I of each year. The report shall include data sufficient to characterize the disposal operation, including, among other information, the following: injection and annuli pressures (i.e., daily average, maximum, and minimum pressures); fluid volumes injected (i.e., in disposal and clean fluid sweeps); injection rates; an assessment of the fracture geometry; a description of any anomalous injection results; and a calculated zone of influence for the injected fluids. Jim Regg AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907 - 793 -1236 1 0 Chevron Chantal Walsh Union Oil Company of California Petroleum Engineer P.O. Box 196247 Anchorage, AK 99519 6247 7 Tel 907 263 7627 Fax 907 263 7828 Email walshc @chevron.com June 7, 2011 Mr. Tom Maunder ECE \ ED Alaska Oil & Gas Conservation Commission ( AOGCC) JUN 0 9 201i 333 West 7 Avenue, Suite 100 Anchorage, AK 99501 itti3riha GAA (ii a ` f;,,IiU8Sl0g Re: Disposal Report for the 13 -31 Well in the Ivan River Unit t`orag@ O Dear Mr. Maunder: O SC, This is the 2010 Annual Report for UIC Class II disposal operations in the IRU 13 -31 wellbore. These disposal operations are governed by AOGCC Disposal Injection Order #35 issued 12/09/08. During 2010 IRU 13 -31 was not used for injection. The attached plot shows injection pressures are stable and do not indicate any reservoir or mechanical concerns. Specific items to note for this reporting period: • On May 6, 2009 a successful MIT was witnessed by the SOA on IRU 13 -31. A MIT is required every two years. • Injection into IRU 13 -31 has occurred in 2011 and will be subject to next year's reporting. Please contact me if I can be of further assistance at 907 - 263 -7627. Best regards, Chantal Walsh cc: Dave Whitacre Gary Ross Larry Greenstein Well File Union Oil Company of California / A Chevron Company http: / /www.chevron.com I M Plot Pressure & Rate vs Time - Well IVAN R 13 -31 3500 3000 7 „ 3000 2500 ■Tubing 2500 Vol 13 -31 WD 2000 2000 __ __ W 3 LL N v a 1500 150 1000 1000 - 500 500 - O T0 o o o o 0 0 0 o o O o o o 0 5 0 0 0 0 0 0 0 5 0 0 g i`+ C Q Q P Q 0, C Q s,`+ co D ate 12/31/2009 820 365 0 1/1/2010 820 365 0 TIO Report 1/2/2010 820 365 0 Data Sheet 1/3/2010 820 365 0 1/4/2010 820 365 0 Ivan R 13 -31 1/5/2010 820 365 0 1/6/2010 820 365 0 Injection 1/7/2010 820 365 0 1/8/2010 820 365 0 Permit # 1920880 1/9/2010 820 365 0 1/10/2010 820 365 0 API # 50- 283 - 20086 -00 1/11/2010 820 365 0 1/12/2010 820 365 0 12/31/2009 to 1/01/2011 1/13/2010 820 365 0 1/14/2010 820 365 0 1/15/2010 820 365 0 1/16/2010 820 365 0 1/17/2010 820 365 0 1/18/2010 820 365 0 1/19/2010 820 365 0 1/20/2010 820 365 0 1/21/2010 820 365 0 1/22/2010 820 365 0 1/23/2010 820 365 0 1/24/2010 820 365 0 1/25/2010 820 365 0 1/26/2010 820 365 0 1/27/2010 820 365 0 1/28/2010 820 365 0 1/29/2010 820 365 0 1/30/2010 820 365 0 1/31/2010 820 365 0 1 • • (hevr'on two Chantal Walsh Union Oil Company of California Petroleum Engineer P.O. Box 196247 Anchorage, 99519-6247 Tel el 907 7 7 263 7627 Fax 907 263 7828 Email walshc @chevron.com Dec 14, 2010 Mr. Tom Maunder --.- , 0 ;4 r r, Alaska Oil & Gas Conservation Commission (AOGCC) 333 West 7 Avenue, Suite 100 Anchorage, AK 99501 4:k, ;in Re: Disposal Report for the 13 -31 Well in the Ivan River Unit ;. k tmcnt r, Dear Mr. Maunder: This is the 2009 Annual Report for UIC Class II disposal operations in the IRU 13 -31 welibore. These disposal operations are governed by AOGCC Disposal Injection Order #35 issued 12/09/08. The attached plot shows injection pressures are stable and do not indicate any reservoir or mechanical concerns. Specific items to note for this reporting period: • On May 6, 2009 a successful MIT was witnessed by the SOA on IRU 13 -31. • After produced water and fluids from drilling and completion operations on the West Side of Cook Inlet were completed in April 2009, there were no further injection operations during the 2009 year. Please contact me if I can be of further assistance at 907 - 263 -7627. Best regards, I C hantal Walsh cc: Dave Whitacre Gary Ross Larry Greenstein Well File Union Oil Company of California / A Chevron Company http: / /www.chevron.com Plot Pressure & Rate vs Time - Well IVAN R 13 -31 3500 -- - 3000 3000 I •■•9 5/8" - I , 13 3/8" I 2500 16" 20" 2500 Tubing — Vol 1331 WO 2000 2000 — - L LL H V a 150 1500 — I 1 1000 1000 .• 500 500 – , 1 , , :, , , , 0 - . _____.... 0 0 0 0 0 0 0 0 0 0 o m m r� n . Date ?" 9 5/8" 13 3/8" 16" 20" vol TIO Report 01/01/10 820 0 0 0 0E 365 12/31/09 820 0 0 0 0 365 0 Data Sheet 12/30/09 820 0 0 0 0 365 0 365 12/29/09 820 0 0 0 0 3 12/28/09 820 0 0 0 0 365 0 IVAN R 13 -31 12/27/09 820 0 0 0 365 0 12/26/09 820 0 0 0 365 0 12/25/09 820 0 0 0 365 o INJECTION 12/24/09 820 0 0 0 365 0 12/23/09 820 0 0 0 365 0 12/22/09 820 0 0 0 365 0 Permit # 1920880 12/21/09 820 0 0 0 365 0 12/20/09 820 0 0 0 365 0 12/19/09 820 0 0 0 365 0 API # 50- 283 - 20086 -00 12/18/09 820 0 0 0 365 0 12/17/09 820 0 0 0 365 0 12/16/09 820 0 0 0 365 o 12/31/2008 to 01/01/2010 12/15/09 820 0 0 0 365 0 12/14/09 820 0 0 0 365 0 12/13/09 820 0 0 0 0 365 0 12/12/09 820 0 0 0 0 365 0 12/11/09 820 0 0 0 0 365 0 12/10/09 820 0 0 0 0 365 0 12/09/09 820 0 0 0 0 365 0 12/08/09 820 0 0 0 0 365 0 12/07/09 820 0 0 0 0 365 0 12/06/09 820 0 0 0 0 365 0 12/05/09 820 0 0 0 0 365 12/04/09 820 0 0 0 0 365 12/03/09 820 0 0 0 0 365 0 12/02/09 820 0 0 0 0 365 0 12/01/09 820 0 0 0 0 365 0 11/30/09 820 0 0 0 0 365 0 11/29/09 820 0 0 0 365 0 11/28/09 820 0 0 0 365 0 11/27/09 820 0 0 0 365 0 12/14/2010 1:59 PM - TIO Reports 7e.xls J J Doer Master Well List TIO Report 2010 01 01.xIs IVAN R 13 -31 ~ ' Chevron ~ ~ July 14, 2009 Chantal Walsh Petroleum Engineer Mr. Jim Regg Alaska Oil & Gas Conservation Commission (AOGCC) 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Re: Disposal Report for the 13-31 Well in the Ivan River Unit Dear Mr. Regg: \J Union Oil Company of California P.O. Box 196247 Anchorage, AK 99519-6247 Tel 907 263 7627 Fax 907 263 7828 Emaii walshc@chevron.com This is the 2008 Annual Report for UIC Class II disposal operations in the IRU 13-31 wellbore. These disposal operations are governed by AOGCC Disposal Injection Order #35 issued 12/09/08. The attached plot shows the well was a depleted gas well that was converted to a Class II disposal well in November 2008. Injection pressures are stable and do not indicate any reservoir or mechanical concerns. Specific items to note for this reporting period: • In 2008 the fluids injected into the IRU 13-31 well were essentially produced water and fluids from drilling and completion operations on the West Side of Cook Inlet. • On December 9, 2008 a successful work over MIT was completed on IRU 13-31. • A total volume of 4,274 bbls, over the course of 5 disposals, was injected into the well bore. The zone of influence for this volume is well within the confinements of the disposal injection intervaL • The fracture geometry has been modeled - including runs simulating extreme conditions. The simulated fracture dimensions were contained within the disposal interval for rates of up to 8 bpm and batch volumes in excess of 8640 bbls. The 2008 injection rates and volume were well below the maximum scenarios modeled. Please contact me if I can be of further assistance at 907-263-7627. Best regards, ~ f~~~,,,~ C Chantal Walsh ~,~ _~~-. cc: Dave Whitacre Chris Holden Larry Greenstein Well File Union Oil Company of California / A Chevron Company http://www.chevron.com IRU 13-31 Pressure Observations 1400 4000 ~ _~_.s.,,~_ ~~. ;.__~ _ .c_~~ ~Tubing " 3500 -7 1200 ~9 5/8" ~13 3/8" ~20~~ 3000 - --------- _ _ -_- - - -- -Rate 1000 2500 -- 800 d d ~ N 2000 a, a` o ~ 600 1500 400 - 1000 ----- -- 200 500 ~ 0 11/14/07 O1/03/08 02/22/08 04/12/08 06/O1/08 Tim e 07/21/08 09/09/08 10/29/08 12/18/O8 02/06/09 i • Printed on 7/14/2009 at 11:35 AM IRU 13-31 Pressure Data 2008 12 31.x1s # IRU 13-31 Pressure Observations 2008 STATDATE FLOW HOURS TBGPRESS CSGPRESS MEASVOL 12/31 /08 24 3400 1200 945 12/30/08 24 200 0 12/29/08 0 0 0 12/28/08 0 0 0 12/27/08 0 0 0 12/26/08 24 3350 1850 690 12/25/08 24 3500 1650 650 12/24/08 24 3400 1000 832 12/23/08 24 200 0 12/22/08 0 0 0 12/21 /08 0 0 0 12/20/08 0 0 12/19/08 0 0 12/18/08 24 3725 1600 1157 12/17/08 24 200 0 12/16/08 0 0 0 12/15/08 0 0 0 12/14/08 0 0 0 12/13/08 0 0 0 12/12/08 0 0 0 12/11/08 0 0 0 12/10/08 0 0 12/09/08 0 0 0 12/08/08 0 0 0 12/07/08 0 0 0 12/06/08 0 0 0 12/05/08 0 0 0 12/04/08 0 0 0 12/03/08 0 0 0 12/02/08 0 0 0 12/01 /08 0 0 0 ~ 8 Request for Authorization for ~ergency Disposal at Ivan River Disposal Wells Page 1 of 5 Regg, James B (DOA) From: Havelock, Brian E (DNR) Sent: Tuesday, February 17, 2009 3:47 PM To: Regg, James B (DOA) Subject: RE: Request for Authorization for Emergency Disposal at Ivan River Disposal Wells I see. That could happen easily as the permitting is not coordinated, like ACMP reviews are. I may not hear anything from my people on this (info usually only travels upward). Let me know if your internal talks generate any ideas we should act on or discuss. Brian Havelock Natural Resource Specialist Division of Oil &, Gas Alaska Department of Natural Resources 550 W 7th A~%emae, Suite 800 Anchorage, Alaska 995{)1 907-269-8807 Division of Ct.t. and Gas Home Page. From: Regg, James B (DOA) Sent: Tuesday, February 17, 2009 3:05 PM To: Havelock, Brian E (DNR) Cc: Taylor, Cammy O (DNR); Woolf, Wendy C (DNR); Rader, Matthew W (DNR) Subject: RE: Request for Authorization for Emergency Disposal at Ivan River Disposal Wells Thank you - my main concern is that the Commission is not authorizing injection activities that would conflict with DNWADF&G requirements Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 907-793-1236 From: Havelock, Brian E (DNR) Sent: Tuesday, February 17, 2009 2:03 PM To: Regg, James B (DOA) Cc: Taylor, Cammy O (DNR); Woolf, Wendy C (DNR); Rader, Matthew W (DNR) Subject: RE: Request for Authorization for Emergency Disposal at Ivan River Disposal Wells Jim Thanks for this D10 and yaur explanation below. I receive DIOs and other Commission actions from Jody's email distribution, which is excellent communication. I do not need additional notification regarding these operations from a surface permitting perspective, but the unit managers have concern for the subsurface, and l will copy them an this email thread so they can evaluate your questions too. Ta explain Chevron's request and the reply a little more, it is up to the aperator to tell us what they are doing on the surfaced more sa at Ivan than other fields because DNR and ADFG have faint management authority aver the surface in the Susitna Flats State Game Refuge. This activity would not require our permission or 2/ 17/2009 Request for Authorization for ~ergency Disposal at Ivan River Disposal Wells Page 2 of 5 • consultation in most established fields, like Beluga. This permitting office issued a production phase unit plan of operations permit last year for IRU that covers most activities, but the emergency hauling and injecting of unknown quantities of BRU fluids was not in the plan. My request for a notification and report from Chevron is driven not by a concern over how much volume is injected downhole {because that is covered by you), but by a concern over how many and how often water trucks are bouncing up and down the road system {public ROWS maintained by Chevron) in all kinds of weather, and how operatianally safe and sound that practice would be in the refuge as a routine operation. Brian Brian Havelock Natural Resource Specialist Division of C?il f~ Gas Alaska. Department of Natural Resources 550 LV ith Avenue, Suite fi00 Anchorage, Alaska 99501 907-a~9-saa7 Division of_O_il and Gas Home Page. From: Regg, James B (DOA) Sent: Tuesday, February 17, 2009 11:30 AM To: Havelock, Brian E (DNR) Cc: Maunder, Thomas E (DOA); Roby, David S (DOA); Colombie, Jody J (DOA) Subject: RE: Request for Authorization for Emergency Disposal at Ivan River Disposal Wells Underground injection is in part a primacy issue assigned to the AOGCC from EPA. I am the Commission"s UIC Program Manager. While I oversee the entire Underground Injection Control (UIC} program, I typically coordinate waste disposal issues, and the reservoir engineers normally coordinate FOR injection. Specific to the authorization for emergency disposal injection at IRU {Befogs River Class II fluids}, there is no specific approval required from AOGCC. We authorized Class ll fluids generally in DIO 35 (Ivan River; copy attached} without qualifiers {source, specific fluid types, etc.} so there are no restrictions except to limit injection to Class II fluids. If Union wants to accept 3rd party wastes, that is their businesslliability. Interesting comment about CPAI permitting a second disposal well at Beluga - haven'ty heard about that one. Perhaps they are planning a Class I well (EPA jurisdiction} as is being done far North Cook Inlet (Tyonek platform}. We have in the past been advised by DNR staff that there was na need for the operator/Commission to notify DNR when the Commission receives an injection order application, Based on references to DNR and ADF&G below, I°m curious if this should be reconsidered. Are there UIC activities that DNR and ADF&G are engaged with that impact decisions being made by the Commission when addressing underground injection applications {monitoring, reporting, surveillance, eligible fluids, etc.)? Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 907-793-1236 From: Colombie, Jody J (DOA) Sent: Tuesday, February 17, 2009 10:57 AM To: Regg, James B (DOA) Subject: RE: Request for Authorization for Emergency Disposal at Ivan River Disposal Wells 2n~i2ao9 Request for Authorization for ~ergency Disposal at Ivan River Disposal Wells Page 3 of 5 Sorry, Brian sent it to me this morning. Shall I assign it to you? From: Regg, James B (DOA) Sent: Tuesday, February 17, 2009 10:53 AM To: Colombie, Jody J (DOA) Subject: FW: Request for Authorization for Emergency Disposal at Ivan River Disposal Wells This should have been sent to me Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 907-793-1236 From: Roby, David S (DOA) Sent: Tuesday, February 17, 2009 10:42 AM To: Regg, James B (DOA) Cc: Maunder, Thomas E (DOA); Davies, Stephen F (DOA); Colombie, Jody J (DOA) Subject: FW: Request for Authorization for Emergency Disposal at Ivan River Disposal Wells Jim, Wouldn't we have to approve this? Had you heard about this? Dave Roby {907)793-1232 From: Colombie, Jody J (DOA) Sent: Tuesday, February 17, 2009 10:39 AM To: Maunder, Thomas E (DOA); Davies, Stephen F (DOA); Roby, David S (DOA) Subject: FW: Request for Authorization for Emergency Disposal at Ivan River Disposal Wells From: Havelock, Brian E (DNR) Sent: Tuesday, February 17, 2009 10:24 AM To: Colombie, Jody J (DOA) Subject: FW: Request for Authorization for Emergency Disposal at Ivan River Disposal Wells Jody I meant to copy AOGCC on this. Can you forward this email to the Ivan River/Befogs River field contact{s)? Thanks Brian Tian veloc Natural Resaurce Specialist Division of Oil ~ Gas 2/17/2009 Request for Authorization for ~ergency Disposal at Ivan River Disposal Wells Page 4 of 5 i Alaska Department of Natural. Resources 550 V4' 7th Avemie, Suite 800 Anchorage, Alaska 995(1 l 907-`269-8807 L}zvisio~ of Oil_anti_Gas Ht~me_Page From: Sullivan, Sharon T [mailto:SullivanS@chevron.comJ Sent: Friday, February 13, 2009 5:43 PM To: Havelock, Brian E (DNR) Subject: RE: Request for Authorization for Emergency Disposal at Ivan River Disposal Wells Thanks far the approval, Brian! 1 appreciate the quick turnaround! Sharon 'I'. SuIlit~an Planning & I?emittng Specialist, HES Group Chevron North America E:~ploration and Pr•ocicECtioii Company MdC`ontrzerib`Alaska Business unit 3800 Cente~pont Drive, Anchorage; AK 990 Office 907.263.7839 Cell. 907.830.1521 Fax 866.801...5194 I/n3ail St~IhvanS(~xChevron.corn From: Havelock, Brian E (DNR) [mailto:brian.havelock@alaska.gov] Sent: Friday, February 13, 2009 4:02 PM To: Sullivan, Sharon T Cc: Rader, Matthew W (DNR); Bouwens, Kenneth A (DFG) Subject: RE: Request for Authorization for Emergency Disposal at Ivan River Disposal Wells Sharon The Division has no objectian to this contingency aperatian at Ivan River in the event of an emergency situation. If this event accurs, please 1} notify me immediately via email, and 2} repart in the next aperatians status repart the sources, valumes, and rates of all fluids transported and injected. If this activity were to continue far an extended period of time the Division will evaluate whether a separate authorization may be required. via aveloc Natural Reso~€rce Specialist Diti~ision of Oil 8s Gas Alaska Department of Natural ResaLtrces 550 W 7th Avenue, Sti.ite 800 Anchorage, Alaska 99501 907-269-8807 Division of Oil, and Gas Hc?mc Page. From: Sullivan, Sharon T [mailto:SullivanS@chevron.com] Sent: Friday, February 13, 2009 12:39 PM To: Havelock, Brian E (DNR) Cc: Bouwens, Kenneth A (DFG) Subject: Request for Authorization for Emergency Disposal at Ivan River Disposal Wells 2/17/2009 Request for Authorization for ~ergency Disposal at Ivan River Disposal Wells Page 5 of 5 Brian, As part of a backup plan that Conoco Phillips (CPAI) is developing for the Beluga River Field (BRF), they are trying to identify disposal options for the field's Class II produced water in the event that their one disposal well in Beluga is not operational. As I understand it, CPAI is in the process of permitting a second disposal well in the Beluga River Field which will provide backup in the event the current well is not operational. It is anticipated that the second well would be available in late 2009. Until a second well becomes available for disposal, CPAI has asked if it would be possible to dispose the BRF produced water in our Ivan River Class II disposal wells in an emergency where their disposal well is not operational. Please note that Union Oil Company of California is a partner with CPAI in the BRF so we have an interest in this matter. This action, however, is not a desirable option due to the increased cost associated with hauling fluids to Ivan River and would only occur under emergency conditions and cannot be a long term solution. talked with ADF&G and they will allow this activity to occur as long as the fluids are generated from operations located within the refuge and if ADNR-DOG does not object. ADF&G said they will require a Special Area Permit for CPAI to transport the fluids to Ivan River Pad for disposal. Please let me know if ADNR-DOG will approve this emergency-only activity. Thank you! Sharon `I".:~ullivan Planning ~ Permitting Specialisi, FIES Graup Chevron ~;orth America Exploration and Produc#ion Company 1W1idC;c~ntincn#.`Alaska Business C~ni# ;844 Centerlx>int Dive, t~ncl~arage, AK 99543 Office 947.2b3.7839 Cell 947.8 34. f 821 Fay 8(16.841.5194 Email. Stalliva:€~S(c~C'hevron.conl 2/17/2009 ~7 Request to dispose precipitation in IRU - X1.113-3`, - ~~~ ~`~ • Page 1 of 5 Regg, James B (DOA) From: Sullivan, Sharon T [SullivanS@chevron.com] Sent: Wednesday, December 10, 2008 10:02 AM To: Regg, James B (DOA) Subject: Request to dispose precipitation in IRU Well 13-31 Importance: High Ni Jim, ~ ~1~~~ ~~s 35.~~ ,~ ~ ~PP`~~~~- i received an electronic copy of the Disposal Injection Order No. 35 for IRU Well 13-31 yesterday. Thank you very much for moving it through the system! Would you please confirm whether Rule #2 -Fluids authorizes "precipitation accumulating within production impoundment areas" as was agreed upon in a voicemail message from you on 10f01108 {please see e-mail trail below}. This would include "disposal injection of precipitation and any spilled materials recovered from secondary containment area {including but not limited to areas around drilling rigs, grind and inject equipment, drilling and production material storage, and well cellars)" as authorized in Administra#ive Approval No. DIO 23.002 for IRU Well 14-31, as well as drilling makeup water for slurry and reserve pit fluid materials. The precipitation language was included on Page 26 of the IRU Well 13-31 DIO application but does not appear to be present in the findingslconclusionslrules sections of D10 No. 35 for IRU Well 13-31. Union Oil Company's intent was to have the same fluids authorized for disposal in IRU Weil 13-31 that are allowed for disposal in IRU Weil 14-31 and we would appreciate your concurrence in this matter. Thank you! Sharon T. SuIlivan Plannning & Permitting Specialist, HES Group Chevron North America 1!axploration and Production ('oinpany~ ~.fidC:ontinent,'Alaska Business Init 3800 Centerpoint Drive, Anchorage, AK 99503 Office 907.263.7839 Cell 907.830.1821 Fax BEiEi,Bt}1.5194 E~nai SullivanS(cuChevron.con~ From: Sullivan, Sharon T Sent: Wednesday, October 01, 2008 4:29 PM To: SMITH, JEFFREY A; Bodeau, Jean Subject: RE: Request to dispose precipitation in IRU 14-31 (DI023) I received a voicemail trressage from Jinn Regg alb ~10GCC. today at 3:24. I-Ie said he missed seeing that part in the DI(J application. ~~~herc tl~e precipitation fluids c~~ere listed at~d he deems that statetnent regarding the precipitation in production impoundment areas is srtfticient and. he will include drat fluid. type an the authorized list of fluids in the forthcoming IRU 13-31 disposal order. Sharon T. Sullivan Planning & Permitting Specialist:, :HES Group Chevron North :aia-erica l;eploration and Production ('ompany 12/11/2008 Request to dispose precipitation in IRU 14-31 (DI023} Page 2 of 5 • • ±~1idContizient-`Alaska B~zsiness [.;nit 909 ~L"est 9th Avenue, flnchorage, AK 99501 Office 907.263.7839 Cell 907.530.1521 Tar 907.263.7901 Email SullivanS(ci%Che~7on.eoni From: Sullivan, Sharon T Sent: Wednesday, October 01, 2008 8:40 AM To: Bodeau, Jean; SMITH, JEFFREY A Subject: RE: Request to dispose precipitation in IRU 14-31 (DI023) Jean, The fluid type "precipitation accumulating within production impoundment areas", which was the phrase used in other DIO approvals, was intended to be included in the list of injectable fluids requested for well IRU 13-31 and I included this in the third paragraph in the waste sources section of the DIO application for that weft (see attached excerpt). However, it might have been more appropriate to have included it in the second paragraph of that section under'bther associated wastes". I'm not sure whether 1 need to clarify this formally with Jim or if an e-mail will suffice. Sharon 'i'. Sullivan Planning c4c Pemlitting Specialist, HES Ciroup Chevron forth America Exploration and Praduction Company MidContinent-Alaska I3usiz~ess init 909 ~~'est 9th. ,Avenue, Anchorage.:Al~ 99401 Oftzcc; 907.263.7539 Ce11907.830.1$21 I'ax 907.263.7901 Email SullivanS(~>Chevron.cozn From: Bodeau, Jean Sent: Tuesday, September 30, 2008 7:02 PM To: Sullivan, Sharon T; SMITH, JEFFREY A Subject: FW: Request to dispose precipitation in IRU 14-31 (DI023) Sharon, Jeff, Please see Jim Regg's email below. It seems that he is giving us the opportunity to include precip from containment in the disposal injection order for Ivan river 13-31. What should I tell Jim in response to his email? Thanks. Jean From: Regg, James 8 (DOA) [mailto:jim.regg@alaska.gov] Sent: Tuesday, September 30, 2008 1:35 PM To: Bodeau, Jean Subject: RE: Request to dispose precipitation in IRU 14-31 (DI023) Thank you for noting the specific containment areas. A couple items of ciarification regarding your response pertaining to fluids being Class IID eligible: 12/11/2008 Request to dispose precipitation in IRU 14-31 (DI023) Page 3 of 5 • 1 }Necessary compliance with AOGCC requirements by conducting operations in a safe and skillful manner, in accordance with good oilfield engineering practices, and as required to protect freshwater does not make a fluid Class II eligible; 2} Nonhazardous is also not a sole justification for Class IID eligibility; 3} l wish interpretation of the phrase "uniquely associated with oil and gas exploration, production and development" were criteria - as you and I understand it -accepted for decisions about Class IID eligibility; if that were the case, decisions about fluids eligible for Class IID injection would be more consistent and understandable; unfortunately, EPA does not interpret the phrases "uniquely associated" and "directly associated with" the way we do; EPA says Class IID is just those fluids that have been down hole for their intended purpose are eligible for Class IID. From a strict sense, the request to inject precipitation collected from secondary containment is not eligible. You are correct that the Commission has authorized the disposal injection of precipitation collected in secondary containment (both on drill pads and deck drainage on platforms) under several DIOs. I am working on an admin approval authorizing this under DIO 23 (Ivan River}. Noticed that Chevron's new request far DIO at IRU (Well 13-31 }does not include request for precip collected in secondary containment - is that intentional or just an oversight? Now would be the time to address it if that is Chevron's intent. Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 907-793-1236 From: Bodeau, Jean [mailto:BodeauJ@chevron.com] Sent: Thursday, September 25, 2008 3;31 PM To: Regg, James B (DOA) Subject: RE: Request to dispose precipitation in IRU 14-31 (DI023) Dear Mr. Regg, Thanks for your response and the opportunity to clarify the basis of this request. In the letter sent previously, I detailed the specific containment areas where precipitation might be gathered for possible injection disposal, as follows: l am writing to request approval to dispose precipitation collected from bermed secondary containment areas associated with exploration and development in our Westside fields, such as those around the drill rig, G&l facility, drilling material storage areas, production material storage areas, and wel! cellars. The primary rationale for requesting this approval is the precedence of existing AOGCC Class II Disposal Injection Orders that authorize this fluid as compatible with Class II disposal. The Injection Orders where this is noted include: • DIO 26.003 (Kustatan Field Well #1) • DIO 28A (NNA-1) • DIO 30A (NNA-2) -admittedly this is expired DIO 16.001 (WMRU 4D) -one time authorization In addition, the AOGCC regulations 20 AAC 25.526 on Conduct of Operations state: An operator shall carry on all operations and maintain the property at all times in a safe and skillful manner in accordance with good oil field engineering practices and having due regard for the preservation and conservation of the property and protection of freshwater. Controlling runoff is necessary to comply with this regulatory requirement. All of these areas are uniquely associated with oil and gas exploration, production and development, and are a fundamental part of these operations. Without the oil and gas operations, there would be no need to have these areas or control runoff. The precipitation is non-hazardous, and injection disposal is the most environmentally sound disposal method available (compared with discharge to pad, or 12/11/2008 Request to dispose precipitation in IRU 14-31 (DI023) Page 4 of 5 • • shipping offsite for disposal). Thank you again for your consideration. Please contact me if you require additiona! information, or with a determination. Sincerely, Jean Bodeau Jean M. Bodeau, CPG Hydrogeologist Waste Specialist Chevron North America F~cploration and Production Company P.O. Box 196247 Anchorage, AK 99519-6247 Tel. (907) 263-7308 Fax (907)263-7321 Mobile (907) 382-1678 Bodea_ uJ a(7chevron.com From: Regg, James B (DOA) [mailto:jim.regg@alaska.gov] Sent: Thursday, September 25, 2008 9:18 AM To: Bodeau, Jean Subject: RE: Request to dispose precipitation in IRU 14-31 (DI023) please describe "exploration and production-related secondary containment areas" and why you believe this is Class IID eligible. Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 907-793-1236 From: Bodeau, Jean [mailto:BodeauJ@chevron.com] Sent: Wednesday, September 24, 2008 3:24 PM To: Regg, James B (DOA) Subject: Request to dispose precipitation in IRU 14-31 (DI023) Dear Mr. Regg, f am writing to request authorization via administrative approval (similar to Ffuid Clarification D10 26.003 issued for Forest Oil Kustatan Well #1 } to dispose precipitation collected from exploration and production-related secondary containment areas into IRU 14-31 (DIO 23) in the Ivan River Unit on the west side of Cook Inlet. The attached letter contains more details. For your reference, I will forward separately an email from you authorizing a similar request for our NNA-1 well in November 2007. Please contact me if you have any additional questions or concerns. Thank you very much for your assistance. Best Regards, 12/11/2008 Request to dispose precipitation in IRU 14-31 (DIO23) Page 5 of 5 • • Jean «Westside D1023.pdf» Jean M. Bodeau, CPG Hydrogeologist Waste Specialist Chevron North America Exploration and Production Company P.O. Box 196247 Anchorage, AK 99519-6247 Tel. (907) 263-7308 Fax (907) 263-7321 Mobile (907) 382-1678 Bod_e_ auJ_ @chev_ron.com 12~11~2~0g FW: IRU 13-31 USIT Log 12/3/08 • Regg, James B (DOA) From: Maunder, Thomas E (DOA) Sent: Wednesday, December 03, 2008 3:36 PM To: Regg, James B (DOA) Subject: FW: IRU 13-31 USIT Log 12/3/08 Attachments: Chevron_iru_13-31_Combined.zip ~~~~ i2~3~~'t~ From: Bonnett, Nigel (Nigel.Bonnett) [mailto:Nigel.Bonnett@chevron.com] Sent: Wednesday, December 03, 2008 3:31 PM To: Maunder, Thomas E (DOA) Cc: Santos, Ronilo; PORHOLA, STAN T Subject: FW: IRU 13-31 USIT Log 12/3/08 Tom, As stipulated in the approved 10-403 Sundry for 13-31 well conversion, I attach the PDS file of the USIT log. Page 1 of 1 TOG in the 7" casing was picked at 3460 ft, which met our criteria of being above the top of the planned injection zone (5544 ft MD}. Regards, Nigel From: Bothner, Joseph A. Sent: Wednesday, December 03, 2008 12:18 AM To: Tyler, Steve L; Bonnett, Nigel (Nigel.Bonnett); Harness, Evan; rsmyth@slb.com Subject: IRU 13-31 USIT Log 12/3/08 Log was tied in to DV collar @ 2793'. «Chevron_iru_13-31 _Combined.zip» Joseph Bothner Drill Site Manager jbdz@chevron.com Chevron North America Exploration and Production MCA Business Unit 11111 S. Wilcrest Houston, TX 77099 Mobile 281 620 6139 Fax 1 866 480 5386 12/3/2008 ~~ Ivan River Unit 13-31 Unocal Fracture Study Case Results: Estimated Fracture Heights i. 4200 5450 -41so 4~~~~ -416 0 5500 "`40 _e~nn g Interval ~~ Upper Lobe 5700 -43~ 1a 1d 1e 1h 2a 2d 2e 2h u 3a ~3d ~ 3e ~31i "4a 4d 4e -4340 44uo 4420 - - 5800 4440 -4380 -_- --~` > A .~. +~~ -4400 4c 5850 -1460 3g 3c 1 c 1 g 2c 2g '~ l Middle Lobe 5900 44"' . z .~ ~ I 5950 -44s o ~ 4~ao -4500 -4520 4580 6050 4;00 -4540 -456 U 6100 41.20 45ao Lower Lobe 6150 ~~;,~~ 46i~~ ~~ 1b 1f 2b '' 3b 1; 3f 2f ~ 4b _ _ _ _ ~ -4660 6250 4~zo r -4680 ~'-. Exempt Aquifer (AEO 6A) ' 14,800 ppm TDS Exempt Aquifer (AEO 6A) 8,900 ppm TDS 6,500 ppm TDS 2,800 ppm TDS 3,100 ppm TDS 2,000 ppm TDS 2,900 ppm TDS Exempt Aquifer (AEO 6A) 2,200 ppm TDS Base of Exempt Aquifer AOGCC 081208_Log_1920t380_IRU 13-31_Fracture_Study_Results.ppt SFD 12/8/2008 ~5 • Chevron December 4, 2008 Sharon T. Sullivan HES Planning and Permitting Specialist MidContinent/Alaska SBU ~J Chevron North America Exploration and Production P.O. Box 196247 Anchorage, AK 99519-6247 Tel 907.263.7839 Fax 866.801.5194 Cell 907.830.1821 Email Sullivan5@Chevron.com #~ ~. Daniel T. Seamount, Jr., Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: AMENDED APPLICATION FOR DISPOSAL INJECTION ORDER IVAN RIVER UNIT WELL 13-31, SECTION 1, T13N, R9W, S.M. WEST SIDE COOK INLET, ALASKA Dear Commissioner Seamount: Union Oil Company of California (Union Oil), awholly-owned indirect subsidiary of Chevron Corporation, is hereby enclosing two (2) amended Class II Disposal Injection Order applications for underground disposal of oil field wastes in Ivan River Unit (IRU) Well 13-31. Class II exempt wastes would be injected in the interval between 5,544 and 6,183 feet measured depth (4,221 to 4,630 feet true vertical depth) in IRU Well 13-31. The original Class II Disposal Injection Order was submitted on September 8, 2008. This amended disposal injection order application provides additional information and clarification requested by the Alaska Oil and Gas Conservation Commission (AOGCC). This application is in conjunction with Union Oil's request for a depth extension to the existing Aquifer Exemption Order No. 6 for IRU Well 14-31, in order to capture the base of the proposed injection zone in IRU Well 13-31. The aquifer exemption order amendment request submitted by Union Oil on July 15, 2008, was approved by the AOGCC on November 25, 2008 and submitted to the Environmental Protection Agency (EPA) for concurrence on November 26, 2008. The Aquifer Exemption Order No. 6 Amendment is currently pending approval from the EPA. Thank you for your assistance with this project. Sincerely, ~~~}~ ~ ~~y~~~ Sharon T. Sullivan Planning/Permitting Specialist Enclosures: Two (2) Amended Class II Disposal Injection Order Applications for Ivan River Unit Well 13-31 • • evron Chevron North America Exploration and Production Application for Disposal Injection Order Ivan River Unit Development Project Cook Inlet Basin 20 AAC 25.252 Well IRU 13-31 Union Oil Company of California 3800 Centerpoint Drive Anchorage, AK 99503 November 2008 (Revision 3) ~ • Table of Contents Well Locations Surface Owners and Operators Geologic Details Well Logs Well Construction Waste Sources, Types and Volumes Injection Pressure Waste Confinement Formation Water Salinity and Aquifer Exemption Wells within the Area of Review Mechanical Integrity of Injection Well 20 AAC 25.252 (c) 1 ....................................... 1 20 AAC 25.252 (c) 2 & 3 ............................... . 4 20 AAC 25.252 (c) 4 ...................................... . 5 20 AAC 25.252 (c) 5 ..................................... 12 20 AAC 25.252 (c) 6 ..................................... 13 20 AAC 25.252 (c) 7 ..................................... 26 20 AAC 25.252 (c) 8 ..................................... 28 20 AAC 25.252 (c) 9 ..................................... 29 20 AAC 25.252 (c) 10 & 11 .......................... 35 20 AAC 25.252 (c) 12 ................................... 36 20 AAC 25.252 (d) & (e} ............................... 39 Table of Exhibits Exhibit 1 Regional Area Map, North Cook Inlet, Alaska Exhibit 2 Unit Boundaries and Well Locations and Paths Exhibit 3 Type Log -Well IRU 13-31 Exhibit 4 Ivan River Unit Cross Section Exhibit 5 Structure Map -Top Upper Confining Zone Exhibit 6 Structure Map -Top Injection Zone Exhibit 7 Structure Map -Top Lower Confining Zone Exhibit 8 Current IRU 13-31 Well Schematic Exhibit 9 Well IRU 13-31 State Completion Report and Directional Survey Exhibit 10 Proposed Injection Well Schematic Exhibit 11 Proposed Injection Well Schematic Contingency Exhibit 12 Injection Zone With Major Sand Members Exhibit 13 Average Fracture Dimensions Exhibit 14 Forecasted Geometry after Flush at End of Injecting 1,000 bbls of 9.5 ppg Slurry at 2.5 BPM in the "Lower Lobe" Exhibit 15 Forecasted Geometry after Flush at End of Injecting 1,000 bbls of 9.5 ppg Slurry at 2.5 BPM in the "Middle Lobe" Exhibit 16 Forecasted Geometry after Flush at End of Injecting 2,500 bbls of 10.1 ppg Slurry at 2.5 BPM in the "Middle Lobe" Exhibit 17 Forecasted Geometry after Flush at End of Injecting 2,500 bbls of 10.1 ppg - Slurry at 4.0 BPM in the "Middle Lobe" Exhibit 18 IRU 14-31 Well Schematic Exhibit 19 IRU 44-36 Well Schematic Appendix A: Fracture Modeling Report u Well Locations 20 AAC 25.252 (c) 1 f The map on the following page (Exhibit 1) is a regional map showing the general location of the Ivan River Field within the Upper Cook Inlet Basin. Exhibit 2 shows the Ivan River Unit (IRU) boundaries and the well courses within the field with associated depths presented as true vertical depth subsea (TVDSS). The IRU 13-31 well surface location is 682 feet south and 699 feet east of the northwest corner of Section 1, T13N, R9W, Seward Meridian, on State of Alaska lease number ADL-032930. The'/4 mile area of review is shown at the top of the injection interval in well IRU 13-31 at a depth of 5,544 feet measured depth (MD) [-4,221 feet TVDSS]. Two wells lie within the '/4 mile area of review, IRU 14-31 and IRU 44-36. Lswia River P riw ~k n~N ww ~ ~nw TfW MY nix uw Tux Mw TY~NauW T1Yl MAW TIM R1]W TfYl R12W ax M1W Ttrx MOw ~~".~VV~11 `" Beluga River '~ 1 /IVan River C.~ nrx xsw J/'//^/// ~J nZx~ Moquawlda North Cook Inlet T11N RAV .. - Granite Point nov asv North Trading Bay ' Trading Bay „xa~ r Chevron ~ Middle Ground Ivan River UnR ur Shoal Swanson River s , ~ 18N RSY - °i Regional Area P North Cook Inlet, Kaska 'i. ~ ..:. Location Map RsdOUaf Beaver Creek T)N RSW NNrM Jay 1, rope MOnw axrnxwn ,_.. shoal 0 367 r-~--- ~~y ~` - FEET Exhibit 1 -Regional Area Map, North Cook Inlet, Alaska • •i 2 • • I I ~~ T14N R9W ~~ I T14N R8W I - I Section 36 I Section 31 I I IAN RNER UNIT 13-31 1/4 mile radius around I I I top of proposed injection 1777 zone in IRU 13-31 I IVAN RIVER UNIT 14-31 I IVAN RIVER UNIT 44- _____ _-- ---- fi IVAN RIVER UNIT 4 - 1 b636 I I 243 I 2z/ I I .BS 4 $eCtlOn 6I $eCllOn 1 666 I ~~,267 I Wells within the 1/4 mile II I radius of the injection I zone in IRU 13-31 ~``, I IVAN RIVE~2 UNIT ~01 -4:293 ~ T 13 T 13 N R9W A698 I - +r' Chevron ~ I ~ I ~ ~J Ivan River Unit 337 •~4s Unit Area I Section 12 Section 7 and Well Paths I I Revised July 2, 2008 N RNER U IT 23-12 1 ~~. ~ ~ I ~73 t Ufllt oundry FEET -a- Exhibit 2 -Unit Boundaries and Well Locations and Paths • • Surface Owners and Oaerators 20 AAC 25.252 (c) 2 & 3 The State of Alaska is the only surface owner within the Ivan River Unit and no other operators are in the development area. Therefore, no copies of the application need to be distributed and no notification affidavits are required. The State of Alaska is also the royalty owner. 4 • • Geologic Details 20 AAC 25.252 (c14 Deposition/Lithologv/Stratig ra phv The Ivan River Structure is a broad doubly plunging anticline. At the shallower depths that are the focus of this application, the structure is nearly flat, and is unfaulted. A thick layer of glacial outwash deposits covers the surface. These sediments were deposited by high-energy braided streams and are comprised of bedload sands and gravels, interlayered with low permeability floodplain deposits consisting of clay-rich sandy silts, and shales. The thickness of these glacial deposits is difficult to determine due to their lithologic similarity to the underlying Sterling Formation, although they appear to extend down to a depth of approximately 3,100 feet MD. The sediments of the Sterling Formation were deposited by a meander bel!< stream system (Hayes et. al., 1976). The resulting deposits generally include fining-upward sequences of bedload conglomerates overlain by thick quartz-rich sands which are often capped by flood plain siltstone and mudstones. Because deposition was rapid as the meanders migrated across the flood plain, the siltstones and mudstones were not completely eroded. The result of this process is extensive lateral continuity of both the coarse grained and fine grained lithologies. Coals are also common and represent the vegetative cover of abandoned meanders. The effective winnowing of the high-energy channel deposits and their relatively poor consolidation creates excellent porosity and permeability in many of the Sterling ,Formation sands. This formation is approximately 2,000 feet thick at the Ivan River Field. Underlying the Sterling Formation are the meander belt and braided stream deposits of the Beluga Formation. This unit is comprised of fine grained sandstones, siltstones and coals, with minor conglomerates. Due to the nature of their deposition, the sands in the Beluga are much thinner than those of the Sterling Formation and they are relatively limited in lateral extent. These sands are also relatively rich in clay which decreases their permeability. The thickness of the Beluga Formation at the Ivan River Field is approximately 2,600 feet. Underlying the Beluga Formation is the Tyonek Formation. Like the Sterling Formation, these sediments were deposited in a meander belt stream system and consist of laterally extensive sandstones, siltstones, shales and coals. The Tyonek Formation is over 4,500 feet thick at Ivan River. The location of existing wells at Ivan River Field is shown on Exhibit 2. Primary gas production is from the Tyonek Formation. The IRU 44-01 well currently produces gas from the Tyonek Formation at a vertical depth of 7,800 to 7,900 feet below sea level. Secondary gas production comes from the Lower Sterling (top at -4,848 feet TVDSS) and Beluga (top at -5,180 feet TVDSS). ~ • Injection and Confining Zones As the Exhibit 3 type log and Exhibit 4 cross section illustrate, the injection is proposed in the IRU 13-31 well into very fine- to coarse-grained sandstones and conglomerates at 5,544 to 6,183 feet MD (4,221 to 4,630 feet TVDSS). The injection zone is in sandstones above the productive Lower Sterling. These sands are shown on the IRU 13-31 type log in Exhibit 3 and on the cross section presented as Exhibit 4. The injection sands are individually 80 to 120 feet, totaling 390 to 415 feet in thickness. The structure maps for the top of the injection zone and top of the confining zones are based on well data and seismic data mapping. The structure maps illustrate that the. injection sands are part of a doubly plunging anticline and have no faulting or fracturing in the area of review. The 810 to 855 foot thick upper confining zone is part of the thick laterally extensive sands of the Lower Quaternary and Upper Sterling formations. The 175 to 190 foot thick lower confining zone is contained within the base of the Upper Sterling Formation. The coals and shales within the lower confining zone are laterally extensive within the area and .act as a barrier for vertical migration of fluids. Structural maps of the upper confining zone, the injection zone, and the lower confining zone, with depths presented in TVDSS, are shown in Exhibits 5 through 7, respectively. Reservoir Properties The injection interval within the Lower Quaternary and Upper Sterling formations have average porosities of 25% to 33% with expected permeabilities ranging from 100 millidarcies to greater than 500 millidarcies. No core data or testing is available for these sands to verify the permeabilities. • • Exhibit 5 .. .., ~~ 380000 380800 %1800 362400 ~~ 357600 354100 359200 ~. '~~: 756800 .... . ,__... ..... ~ - IRU ~ 3-31 ~ N ~ ~ ~ rg ~ '~ ~ ~ ~ ,~ o o ~~ ~. ~ ~ ~ ,_ I ° ' 3~5 R~1 14-31 ' "' M "0 ~ 1n ~ ~ ~ ~ , ~~~,o o~oo IRU 44-36 ', _ _ ----- ~ ~ ------- --h-- - ~ ch ,' IRU 41-0 ~' ~` ,1' ~ ~ ,' ~ ~ ~~ ~ ~ /' _3400 ~' ~~ a -3438 ~ , ~ ~i ~ IRU 44-01 / ° -3, 51 _. ~ - --- -~ ~ ------------------ -- ~ 3 ~ ;'~ S ~, . ... ~ ~ , 381800 382400 383200 359200 380000 380800 3r,~800 357800 358400 0 Sao ~~ lsoo 2000 ~„ Top Upper Confining Zone Structure r r _1~ --- rraaar "----~~ Nan Rlvo Unit 1:13107 ---.---- ~- u Dato o77xenooa r. rrua~st Exhibit 5 -Structure Map -Top Upper Confining Zone 9 w Vii/ ~. ~ a5° 00 o° ~i ~ I I Exhibit 6 ,200 760000 36CB00 381800 38Y~ ~~ IRU 13-31 ~ ~, ~ ~~ U 14-31 ~ ~ ~.. ~ o° v v ~~ ~ ~ ~ ;~ w o i8 a'5 ~ r rr ~ /' ~' 4250 ~ '' j /~ ~ ~~ / ~ 8 O ~~O ~~O X00 00 ~ #... / " '~~ 757600 358400 739200 78 o soo ,ooo ,soo loco 2saon _To~ r r tit rss~=-._ >.~ Nen, , ,3,07 82400 383200 e Map ~~ Exhibit 6 -Structure Map -Top Injection Zone 10 • • Exhibit 7 868800 357600 358400 389200 360000 760800 36,600 38T400 383200 ~,' ~ ~ ~ IRU ~ 3-31 . ~, ~ '~ ~ , j o ;~ m ~ ~ / RAJ 14-31 ~ o m"' ~ " ~ ~ ~ 00 ~ ~t s ~ ,~ o h IRU 44- v, -__+ ~ ~ ~ o i ~- i---- o------------~- i-----~ i o / ~ ~~ ~~ i ~ IRU 41-0 j / ~ I I ( '~ ~ J ~~ ~~ o ~ ~ ~'~ p ; ~~ -4680 ~ .q65~ i s / ~ ~ ~, ~ / ~~ ~ / IRU 44-01 ~ '~ asst o + o r------------------~-----_ ~- - .- ----r -- _~...--- ~ _ ~ ~o° __ ~ ti~ 388600 387800 758400 359200 780000 J808C0 78,600 762400 367200 0 500 ,ooo ,soo T000 26008 Top Lower Confining Zone Structure ~j ~ 17107 Ivan RNs- Unk '.Cook /nMt AK ~ts+ 1371 Obposal Pro/set Exhibit 7 -Structure Map -Top Lower Confining Zone 11 • Wel 20 AAC 25.252 (c) 5 • Well logs from the Ivan River Unit wells and adjacent exploratory holes have been provided to the Alaska Oil and Gas Conservation Commission (AOGCC). Additional copies can be provided if necessary. 12 s • Well Construction 20 AAC 25.252 (c16 IRU 13-31 Well IRU 13-31 was directionally drilled from a surface location 682 feet from the south line (FSL) and 699 feet from the east line (FEL) in Section 1, Township 13 North, Range 9 West, Seward Meridian to a total depth of 11,575 feet MD (8,167 feet TVD) with a bottom hole location of 1,404.84 feet east and 6,859.86 feet north of the surface location. The top of the injection interval at 5,544 feet MD (-4,221 feet TVDSS) is 2,886 feet north and 262 feet west of the surface location. A schematic of the well as currently completed is shown in Exhibit 8. Original Construction: The 13 3/a surface casing was set at 866 feet MD with cement returns to the surface. A 12 '/e hole was drilled and the 9 % casing run to 3,460 feet MD and cemented with 849 sacks. A leakoff test was run to 18.6 ppg EMW. The 7-inch casing was set at 10,350 feet MD and cemented in place with a calculated top of cement at 5,000 feet MD (-3,874 feet TVDSS). There is no bond log above 6,400 feet MD to confirm this depth. A 5-inch liner was set at 11,575 feet MD (-8,116 feet TVDSS) with the top at 10,028 feet MD (-7,084 feet TVDSS) and cemented in place. On June 6, 1996, the lower hole was abandoned and the 2 %a X 7-inch annulus was cemented to a theoretical top of 6,250 feet MD (-4,673 feet TVDSS) using a cement retainer set in the long string at 9,622 feet MD (-6,821 feet TVDSS). Exhibit 9 includes the State Completion Report with construction events detailing the casing, cementing, and tubing-packer equipment status. A directional survey is also included in Exhibit 9. The 7-inch casing is 29# N-80 with an unsupported burst pressure of 8,160 psi. The new tubing will be 3'h-inch 9.2# L-80. The unsupported burst pressure is 10,160 psi. This exceeds the maximum bottom hole injection pressure by more than 25% as required by the Alaska Administrative Code (AAC) 25.412(b). A waiver request will be submitted to allow a variance to AAC 25.412(b) to allow more than 200 feet MD between the packer and perforations. This waiver is being requested to allow thru-tubing access to the entire requested disposal zone. 13 • ~ Exhibit 8 - Current IRU 13-31 Well Schematic 14 c: Exhibit 9 -Well IRU 13-31 State Completion Report and Directional Survey State Completion Report Well Drilling History: Spudded 9/25/1992 "IRU 13-31; API 50-283-20086-00 PTD: "192-088" 9/25/92: Spud Well: Grace #154 Rig, • Spud Ivan River Unif 13-31 @ 1600 hours, September 26, 1992 (Different from AOGCC) w/ 17-1/2" hole. 9/25/92: Drilling Surface Hole: (20" @ 166') • 20" Conductor Driven prior to rig arrival • Drilled 17-1/2" hole to 876' RKB on 9/28/92. 9/28/92: Run/Cement Surface Casing (20" @ 166') • Ran 866' 13-3/8" 68# K55 BTC casing. Cement to surface 158 bbl lead / 67 bbl tail. 9/30/92: Drilling Intermediate Hole: (20" @ 166', 13-3/8" @ 866') • Test casing to 1,500 psi - OK. • Drill out float shoe and open hole t/886' -LOT 23.5 PPG EMW • Directionally drill 12-1/4" hole t/ 3467' on 10/03/92. 10/04/92: Run/Cement 9-5/8" Intermediate Casing (20" @ 166', 13-3/8" @ 866') • Ran 3,460' 9-5/8" 47# N80 BTC casing. Cement to surface 235 bbl lead / 44 bbl tail. 10/07/92: Drilling 8-1/2" Production Hole: (20" @ 166', 13-3/8" @ 866', 9-5/8" @ 3460') • Test casing to 1,500 psi - OK. • Drill out float shoe and open hole t/3480' -LOT 18.6 PPG EMW • Directionally drill 8-1/2" hole t/ 11,575' TD on 11/12/92. • Ran casing caliper inside 9-5/8" from 0-3,236'. Some wall loss up to 2/3 of wall. Test to 1,800 psi - OK. • Ran bond log from 0'-3,392'. 11/16/92: Run/Cement 7" Production Casing (20" @ 166', 13-3/8" @ 866', 9-5/8" @ 3,460') • Ran 10,350' 7" 29# N80 BTC casing. Cement to 4,981' MD 144 bbl lead / 61 bbl tail. • Test casing above DV collar to 3,000 psi - OK. • Pump 47 bbl cement @ 16.0 ppg thru DV collar taking returns to surface. Ran bond log from 0'-2,790'. • Dispose of mud and cuttings thru DV collar down 7" x 9-5/8" annulus (7,200 bbl total, 2,300 psi @ 3 bpm). 11/28/92: UR below Production Casing (20" @ 166', 13-3/8" @ 866', 9-5/8" @ 3460', 7" @ 10,350') • UR hole below 7" shoe w/ 8.25" underreamer t/ 11,575' TD on 11/29/92. 11/29/92: Run/Cement Liner (20" @ 166', 13-3/8" @ 866', 9-5/8" @ 3,460', 7" @ 10,350') • Ran 1,547' 5" 15# N80 BTC liner w/ packer. Top @ 10,028'. Bottom @ 11,575'. 15 • • • Cement liner (no detail found). • Tag PBTD @ 11,444'. Ran 2 bond logs between 6,400'-11,447'. Ran gyro survey surface to 11,444'. • Test 5" liner top and casing, including 7" below DV collar to 2,500 psi - OK. • Ran TCP guns on 2-7/8" tubing w/ 2-1/16"x1-1/2" heater string. • Perforate Tyonek zones 11,208'-11,238' and 11,272'-11,296'. 12/15/92: Release rig (20" @ 166', 13-3/8" @ 866', 9-5/8" @ 3,460', 7" @ 10,350', 5" @ 11,575') • TD = 11,575' MD, 8,167' TVD. • PBTD = 11,444' MD, 8,052' ND. Directional Survey Directional Survey: "Partial Survey above current PBTD of 7,400' MD" MD ft Inc de Azim ND ft NDSS ft X Off ft Y Off ft DLS 0 0 0 0 51 0 0 0.00 100 1.6 202 99 -48 0 -1 1.60 150 1.6 203 149 -98 -1 -2 0.06 200 1.5 204 199 -148 -1 -3 0.21 249 1.2 206 249 -198 -2 -4 0.62 300 1.1 211 300 -249 -2 -5 0.28 350 1 213 350 -299 -3 -6 0.21 400 0.9 214 400 -349 -3 -7 0.20 449 0.8 217 449 -398 -4 -7 0.22 500 0.7 214 499 -448 -4 -8 0.21 549 0.8 215 549 -498 -4 -8 0.21 599 0.7 220 599 -548 -5 -9 0.24 650 0.7 219 649 -598 -5 -9 0.02 699 0.7 227 699 -648 -6 -10 0.20 749 0.6 228 749 -698 -6 -10 0.20 799 0.5 230 799 -748 $ -11 0.20 849 0.5 232 849 -798 -7 -11 0.03 899 0.4 241 899 -848 -7 -11 0.24 949 0.4 296 949 -898 -7 -11 0.74 1,000 1.1 330 999 -948 -8 -11 1.57 1,049 1.7 334 1,049 -998 -8 -9 1.24 1,099 2 334 1,099 -1,048 -9 -8 0.60 1,149 2.5 337 1,149 -1,098 -10 -6 1.03 1,199 3.5 345 1,199 -1,148 -11 -4 2.16 1,250 4.9 350 1,249 -1,198 -11 0 2.83 1,299 6.6 353 1,299 -1,248 -12 4 3.52 1,349 8.7 354 1,348 -1,297 -13 10 4.21 1,399 10.1 355 1,398 -1,347 -13 19 2.82 1,499 14.3 352 1,495 -1,444 -16 40 4.25 1,525 15.8 351 1,520 -1,469 -16 46 5.85 1,550 17.4 351 1,544 -1,493 -17 53 6.40 1,575 19.3 352 1,567 -1,516 -18 61 7.70 1,600 20.4 352 1,591 -1,540 -19 69 4.40 1,625 21.2 353 1,614 -1,563 -20 78 3.50 1,650 21.9 354 1,637 -1,586 -21 87 3.16 1,675 22.6 354 1,661 -1,610 -22 97 2.80 1,700 22.4 354 1,684 -1,633 -23 106 0.80 16 • • MD ft inc de Azim ND ft NDSS ft X Off ft Y Off ft DLS 1,725 22.4 353 1,707 -1,656 -24 116 1.52 1,750 22.4 353 1,730 -1,679 -25 125 0.00 1,775 22.6 353 1,753 -1,702 -27 135 0.80 1,800 22.9 353 1,776 -1,725 -28 144 1.20 1,825 23.4 353 1,799 -1,748 -29 154 2.00 1,850 24.4 353 1,822 -1,771 -30 164 4.00 1,875 25.4 353 1,845 -1,794 -31 175 4.00 1,900 26.3 353 1,867 -1,816 -32 185 3.60 1,925 27.5 354 1,889 -1,838 -33 197 5.13 1,950 28.3 354 1,912 -1,861 -34 208 3.20 1,975 29 354 1,933 -1,882 -36 220 2.80 2,000 29.2 354 1,955 -1,904 -37 232 0.80 2,025 29.8 354 1,977 -1,926 -38 245 2.40 2,050 30.4 354 1,999 -1,948 -39 257 2.40 2,075 30.7 354 2,020 -1,969 ~0 270 1.20 2,100 31.1 354 2,042 -1,991 -41 282 1.60 2,125 31.9 354 2,063 -2,012 -43 295 3.20 2,150 33.4 354 2,084 -2,033 -44 309 6.00 2,175 34.9 354 2,105 -2,054 -45 323 6.00 2,200 36.4 354 2,125 -2,074 -47 337 6.00 2,225 37.5 353. 2,145 -2,094 -48 352 5.01 2,250 38.6 353 2,165 -2,114 -50 368 4.40 2,275 40 353 2,184 -2,133 -52 383 5.60 2,300 41.2 353 2,203 -2152 -54 400 4.80 2,325 43 352 2,222 -2,171 -56 416 7.68 2,350 43.9 352 2,240 -2,189 -58 433 3.60 2,375 44.3 352 2,258 -2,207 -60 451 1.60 2,400 44.7 352 2,276 -2,225 -62 468 1.60 2,425 45.5 352 2,293 -2,242 -64 485 3.20 2,450 46.3 352 2 311 -2 260 -67 503 3.20 2,475 46.5 352 2,328 -2,277 -69 521 0.80 2,500 47.5 352 2,345 -2,294 -71 539 4.00 2,525 48.6 352 2,362 -2,311 -74 558 4.40 2,550 50.2 352 2,378 -2,327 -76 576 6.40 2 575 51.4 353 2 394 -2 343 -78 596 5.71 2,600 52.1 353 2,409 -2,358 -81 615 2.80 2,625 51.8 353 2,425 -2,374 -83 635 1.20 2,650 51.8 353 2,440 -2,389 -85 655 0.00 2,675 51.8 354 2,456 -2,405 -87 674 3.14 2,700 52 354 2,471 -2,420 -89 694 0.80 2,725 52.5 354 2,486 -2 435 -91 713 2.00 2,750 52.6 354 2,501 -2,450 -92 733 0.40 2,775 52.6 355 2 517 -2 466 -94 753 3.18 2,800 52.7 355 2,532 -2,481 -95 773 0.40 2,825 52.6 355 2,547 -2,496 -97 793 0.40 2 850 52.5 356 2,562 -2,511 -98 812 3.20 2 875 52.8 356 2,577 -2,526 -99 832 1.20. 2,900 52.8 357 2,592 -2,541 -100 852 3.19 2,925 52.9 357 2,607 -2,556 -101 872 0.40 2,950 52.9 358 2,623 -2,572 -101 892 3.19 2,975 52.8 358 2,638 -2,587 -102 912 0.40 3,000 52.3 359 2,653 -2 602 -102 932 3.75 3,025 52 359 2,668 -2,617 -102 951 1.20 3,050 51.9 359 2,684 -2,633 -102 971 0.40 3,075 52.1 359 2,699 -2,648 -102 991 0.80 3,100 52.4 359 2,714 -2,663 -102 1,010 1.20 3 125 52.3 359 2,730 -2 679 -102 1 030 0.40 3,150 52.3 358 2,745 -2,694 -103 1,050 3.16. 17 • • MD ft Inc de Azim ND ft NDSS ft X Off ft Y Off ft DLS 3,175 52 358 2,760 -2,709 -103 1070 1.20 3,200 51.8 357 2,776 -2,725 -104 1,090 3.25 3,225 51.9 356 2,791 -2,740 -105 1,109 3.17 3,250 51.8 356 2,807 -2,756 -106 1,129 0.40 3,275 51.8 356 2,822 -2,771 -107 1,148 0.00 3,300 51.7 356 2,837 -2,786 -108 1,168 0.40 3,325 51.7 356 2,853 -2,802 -109 1,187 0.00 3,350 51.7 356 2,868 -2,817 -110 1,207 0.00 3,375 51.5 356 2,884 -2,833 -112 1,227 0.80 3,400 51.3 356 2,900 -2,849 -113 1,246 0.80 3,425 51.1 355 2,915 -2,864 -114 1,266 3.22 3,450 51 355 2,931 -2,880 -116 1,285 0.40 3,475 50.7 356 2,947 -2,896 -117 1,304 3.33 3,500 50.8 355 2,963 -2,912 -118 1,324 3.12 3,525 50.9 355 2,978 -2,927 -119 1,343 0.40 3,550 50.9 355 2,994 -2,943 -121 1,362 0.00 3,575 51.3 355 3,010 -2,959 -122 1,382 1.60 3,600 51.3 355 3,026 -2,975 -124 1,401 0.00 3,625 51.4 355 3,041 -2,990 -125 1,421 0.40 3,650 50.9 355 3,057 -3,006 -126 1,440 2.00 3,675 50.8 355 3,073 -3,022 -128 1,459 0.40 3,700 50.8 355 3,088 -3,037 -129 1,479 0.00 3,725 50.6 355 3,104 -3,053 -131 1,498 0.80 3,750 50.5 355 3120 -3,069 -132 1,517 0.40 3,775 50.4 355 3,136 -3,085 -134 1,537 0.40 3,800 50.4 355 3,152 -3,101 -135 1,556 0.00 3,825 50.1 355 3,168 -3,117 -137 1,575 1.20 3,850 50.1 354 3,184 -3,133 -138 1,594 3.07 3,875 50.2 354 3 200 -3,149 -140 1,613 0.40 3,900 49.9 354 3,216 -3,165 -142 1,632 1.20 3,925 50 354 3,232 -3,181 -143 1,651 0.40 3,950 50.1 354 3,248 -3,197 -145 1,670 0.40 3,975 49.8 354 3 264 -3,213 -147 1,689 1.20 4,000 49.9 354 3,280 -3 229 -148 1,708 0.40 4,025 49.7 354 3,297 -3,246 -150 1727 0.80 4,050 49.9 354 3,313 -3,262 -152 1,746 0.80 4,075 49.6 354 3,329 -3,278 -153 1,765 1.20 4,100 49.6 354 3,345 -3,294 -155 1,784 0.00 4,125 49.7 354 3,361 -3,310 -157 1,803 0.40 4,150 49.4 354 3,377 -3,326 -158 1,822 1.20 4,175 49.6 354 3,394 -3,343 -160 1 841 0.80 4,200 49.5 354 3410 -3,359 -162 1,860 0.40 4,225 49.6 354 3,426 -3 375 -164 1 879 0.40 4,250 49.5 354 3,442 -3,391 -166 1,898 0.40 4,275 49.3 354 3,459 -3,408 -167 1,917 0.80 4,300 49.3 354 3475 -3,424 -169 1,936 0.00 4 325 49.5 354 3,491 -3 440 -171 1,955 0.80 4,350 49.6 354 3,507 -3,456 -173 1,974 0.40 4,375 49.6 354 3,524 -3,473 -174 1,993 0.00 4,400 49.7 354 3,540 -3,489 -176 2,011 0.40 4,425 49.7 354 3,556 -3,505 -178 2,031 0.00 4,450 49.7 354 3,572 -3 521 -180 2,049 0.00 4,475 49.8 354 3,588 -3,537 -182 2,069 0.40 4,500 49.7 354 3,605 -3,554 -183 2,088 0.40 4,525 50 354 3,621 -3,570 -185 2,107 1.20 4,550 50 354 3,637 -3,586 -187 2,126 0.00 4,575 50 354 3653 -3,602 -189 2,145 0.00 4,600 50 354 3,669 -3,618 -191 2,164 0.00 18 • • MD ft Inc de Azim TVD ft NDSS ft X Off ft Y Off ft DLS 4,625 50 354 3,685 -3,634 -192 2,183 0.00 4,650 50.1 354 3,701 -3,650 -194 2,202 0.40 4,675 49.9 354 3,717 -3,666 -196 2,221 0.80 4,700 50.1 354 3,733 -3,682 -198 2,240 0.80 4,725 50.1 354 3,749 -3,698 -200 2,259 0.00 4,750 50.1 354 3,765 -3,714 -201 2,278 0.00 4,775 50.1 354 3,781 -3,730 -203 2,297 0.00 4,800 50.2 354 3,797 -3,746 -205 2,316 0.40 4,825 50.3 354 3,813 -3,762 -207 2,335 0.40 4,850 50.2 354 3,829 -3,778 -209 2,355 0.40 4,875 50.3 354 3,845 -3,794 -211 2,374 0.40 4,900 50.3 354 3,861 -3,810 -212 2,393 0.00 4,925 50.3 354 3,877 -3,826 -214 2,412 0.00 4,950 50.3 354 3,893 -3,842 -216 2,431 0.00 4,975 50.3 354 3,909 -3,858 -218 2,450 0.00 5,000 50.2 354 3,925 -3,874 -220 2,469 0.40 5,025 50.2 354 3,941 -3,890 -222 2,488 0.00 5,050 50.4 354 3,957 -3,906 -224 2,508 0.80 5,075 50.5 354 3,973 -3,922 -225 2,527 0.40 5,100 50.4 354 3,989 -3,938 -227 2,546 0.40 5,125 50.4 354 4,005 -3,954 -229 2,565 0.00 5,150 50.4 354 4,021 -3,970 -231 2,584 0.00 5,175 50.5 354 4,037 -3,986 -233 2,604 0.40 5,200 50.3 354 4 053 -4,002 -235 2 623 0.80 5,225 50.4 354 4,069 -4,018 -237 2,642 0.40 5,250 50.4 354 4,084 -4,033 -239 2,661 0.00 5,275 50.4 354 4,100 -4,049 -241 2,680 0.00 5,300 50.4 353 4,116 -4,065 -243 2,699 3.08 5,325 50.4 353 4,132 -4,081 -245 2 719 0.00 5 350 50.5 353 4,148 -4 097 -247 2,738 0.40 5,375 50.3 353 4,164 -4,113 -249 2,757 0.80 5,400 50.3 353 4,180 -4,129 -250 2,776 0.00 5 425 50.3 353 4,196 -4,145 -252 2, 795 0.00 5,450 50.3 353 4,212 -4 161 -254 2 814 0.00 5,475 50.4 353 4 228 -4,177 -256 2,833 0.40 5,500 50.2 353 4,244 -4,193 -258 2,853 0.80 5,525 50.4 353 4,260 -4,209 -260 2,872 0.80 5,550 50.3 353 4 276 -4,225 -262 2,891 0.40 5,575 50.4 353 4,292 -4,241 -264 2,910 0.40 5,600 50.3 353 4,308 -4,257 -266 2,929 0.40 5,625 50.1 353 4,324 -4,273 -268 2,948 0.80 5 650 50.3 353 4,340 -4 289 -270 2 967 0.80 5,675 50.1 353 4,356 -4,305 -272 2,986 0.80 5,700 50.2 353 4,372 -4,321 -274 3,006 0.40 5,725 50.2 353 4,388 -4,337 -276 3,025 0.00 5,750 50.1 353 4,404 -4 353 -278 3,044 0.40 5 775 49.9 353 4,420 -4,369 -280 3 063 0.80 5,800 50.2 353 4,436 -4,385 -282 3,082 1.20 5,825 50.3 353 4,452 -4,401 -284 3,101 0.40 5,850 50.2 353 4,468 -4,417 -286 3,120 0.40 5,875 50.2 353 4,484 -4,433 -288 3,139 0.00 5,900 50.2 353 4,500 -4 449 -290 3 158 0.00 5,925 50.2 353 4,516 -4,465 -292 3,177 0.00 5,950 50.2 353 4,532 -4,481 -294 3,196 0.00 5,975 50 353 4,548 -4,497 -296 3,215 0.80 6,000 50.3 353 4,564 -4,513 -299 3,235 1.20 6 025 50.3 353 4,580 -4,529 -301 3,254 0.00 6,050 50.3 353 4,596 -4,545 -303 3,273 0.00 19 • • MD ft Inc de Azim ND ft NDSS ft X Off ft Y Off ft DLS 6,075 50.2 353 4,612 -4,561 -305 3,292 0.40 6,100 50.1 353 4,628 -4,577 -307 3,311 0.40 6,125 50.3 353 4,644 -4,593 -309 3,330 0.80 6,150 50.2 353 4,660 -4,609 -311 3,349 0.40 6,175 50.1 353 4,676 -4,625 -313 3,368 0.40 6,200 50.2 353 4,692 -4,641 -315 3,387 0.40 6,225 50 353 4,708 -4,657 -317 3,406 0.80 6,250 50.2 353 4,724 -4,673 -319 3,425 0.80 6,275 50 353 4,740 -4,689 -321 3,444 0.80 6,300 50.1 353 4,756 -4,705 -323 3,464 0.40 6,325 50.1 353 4,772 -4,721 -325 3,483 0.00 6,350 50.2 353 4,788 -4,737 -327 3,502 0.40 6,375 50.1 353 4,804 -4,753 -330 3,521 0.40 6,400 50 353 4,820 -4,769 -332 3,540 0.40 6,425 50 353 4,836 -4,785 -334 3,559 0.00 6,450 49.7 353 4,852 x,801 -336 3,578 1.20 6,475 49.8 353 4,869 -4,818 -338 3,597 0.40 6,500 49.9 353 4,885 -4,834 -340 3,616 0.40 6,525 49.8 352 4,901 x,850 -343 3,635 3.08 6,550 50.1 352 4,917 -4,866 -345 3,654 1.20 6,575 50.2 352 4,933 -4,882 -347 3,673 0.40 6,600 50.3 352 4,949 -4,898 -350 3,692 0.40 6,625 50.3 352 4,965 -4,914 -352 3,711 0.00 6,650 50.4 352 4 981 -4 930 -354 3,730 0.40 6,675 50.2 352 4,997 -4,946 -357 3,749 0.80 6,700 50.1 352 5,013 -4,962 -359 3,768 0.40 6,725 50 352 5,029 -4,978 -361 3,787 0.40 6,750 49.8 352 5,045 -4,994 -364 3,806 0.80 6,775 50 352 5,061 -5,010 -366 3,825 0.80 6 800 50.2 352 5,077 -5,026 -368 3 844 0.80 6,825 50.4 353 5,093 -5,042 -371 3,863 3.18 6,850 50.5 353 5,109 -5,058 -373 3,882 0.40 6,875 51.1 354 5125 -5,074 -375 3,902 3.92 6 900 51.8 355 5,140 -5 089 -377 3,921 4.20 6,925 52 356 5,156 -5,105 -378 3,941 3.25 6,950 52 357 5,171 -5,120 -379 3,960 3.15 6,975 52.1 358 5,187 -5,136 -379 3,980 3.18 7,000 52.3 359 5,202 -5151 -379 4,000 3.26 7,025 52.2 360 5,217 -5,166 -379 4,020 3.19 7,050 51.9 0 5,233 -5,182 -379 4,039 1.20 7,075 52 1 5,248 -5,197 -379 4 059 3.18 7 100 52 2 5,263 -5 212 -378 4,079 3.15 7,125 52.1 2 5,279 -5,228 -377 4,098 0.40 7,150 52 3 5,294 -5,243 -376 4,118 3.18 7,175 51.8 4 5,310 -5,259 -375 4,138 3.25 20 • • Recompletion Workover Program: A schematic of the proposed injection well recompletion is shown in Exhibit 10. Exhibit 11 shows a schematic of the proposed injection well recompletion contingency. Surface Location: Longitude: -150.79636514 Latitude: 61.240920100 682' FSL & 699' FEL Sec. 1, T13N R9W SM Total Depth: 11,575' MD (8,167.41' TVD; -8,116.41' TVDSS) Bottom Hole Location: 1,404.84 feet E; 6,859.86 feet N Top of Injection Zone: 5,544 feet MD (-4,221 feet TVDSS) 2,886 feet N, 262 feet W Wellbore azimuth: 11.57° Kelly bushing elevation: 51 feet above mean sea level Item and Depth Subsea TVD (RKB) MD (RKB) 20" -115' 166' 166' 13-3/8" -835' 886' 866' 9-5/8" -2,887' 2,938' 3,460' 7" -7,301' 7,352' 10,350' 5" -8,118' 8,169' 11,575' Top Upper Confining Zone -3,412' 3,463' 4,280' Top Injection Zone -4,221' 4,272' 5,544' Base Injection Zone -4,630' 4,681' 6,183' Top Lower Confining Zone -4,630' 4,681' 6,183' Base Lower Confining Zone -4,821' 4,872' 6,478' 21 • • 22 Exhibit 10 - Proposed Injection Well Schematic • • Exhibit 11 -Proposed Injection Well Schematic Contingency 23 • • Workover Procedure: PRE-RIG OPERATIONS (Surface work, E-line, Wellhead) 1. Prep location for Nabors 129 footprint. Build extension into reserve pit for rig catwalk. 2. RU E-line on IRU 13-31. RIH and set WRP plug at +/- 2,000'. Pump lease water on plug. Set 8PV in LS/SS. Ensure annulus has at least 2,000' of glycol (should have glycol to surface). 3. CONTINGENCY: If BPV won't set in LS (bad threads previously found and not repaired), set 2"d WRP plug as deep as practical in place of BPV. 4. ND Tree. Remove well house and place at Lewis River D-pad. Level location to accept rig. 5. RU E-line on IRU 44-01. RIH and set WRP plug at +/- 2,000'. Pump lease water on plug. Set BPV in LS/SS. Ensure annulus has at least 2,000' of glycol (should have glycol to surface). 6. ND Tree. Remove well house and place at Lewis River D-pad. Level location to accept rig. Well anticipated stickup of 6"-12". 7. RU E-line on IRU 41-01. RIH and set WRP plug at +/- 2,000'. Pump lease water on plug. Set BPV in LS/SS. Ensure annulus has at least 2,000' of glycol (should have glycol to surface). 8. ND Tree. Remove well house and place at Lewis River D-pad. Level location to accept rig. Well anticipated stickup of 36"-48". RIG OPERATIONS (Rig, Slickline, E-line) 1. Skid Rig #129 over IRU 13-31 well. NU BOPs. Test to 250/3,000 psi. 2. RU Slickline. Pull BPV in LS/SS. Pull WRP plug. Monitor well. 3. RU E-line. RIH w/ tbg punch (1-11/16") to 5,555'. Punch tbg. POOH. 4. PU dual tbg hanger. Pull to release FH packer. RIH w/ radial torch (1-11/16") to 5,550'. Cut tbg. 5. PU to confirm tbg cut. Lay down dual hanger, long string and heater string tbg and packer. 6. CONTINGENCY: If tbg/pkr won't pull free, RIH and make 2"d cut w/ radial torch at 5,545'. 7. CONTINGENCY: If tbg/pkr won't pull free, RIH and make 3"' cut w/ radial torch below packer. Fish remaining tubing down to fill at 5,561'. 8. RIH w/ 5-3/4" overshot w/ 800' washpipe on 4" DP. Washover tubing down to cement top of 6,250'. TOC is based on calculated volume. If no cement encountered, wash to 6,260' to confirm no cement then POOH. 9. CONTINGENCY: If cement found above 6,250', discuss with town. If milling required, RIH and mill cement around OD of tubing to 6,250'. POOH w/ mill. 10. RIH w/ OD tbg cutter. RIH to 5,800'. Cut tbg and recover +/- 250' of tbg. 24 • • 11. RIH w/ OD tbg cutter. RIH to 6,050'. Cut tbg and recover +/- 250' of tbg. 12. RIH w/ OD tbg cutter. RIH to 6,250'. Cut tbg and recover +/- 200' of tbg. 13. RIH w/ 6" scraper assembly w/ 6" bit to cut tbg at 6,250'. Key areas are 2,793' (DV collar) and 5,544'-6,183' (disposal zone). POOH. 14. RU E-line. RIH w/ USIT log. Log from 6,250' to 2,500'. POOH. 15. CONTINGENCY: If cement found below 5,544', discuss with town. May modify permitted disposal interval w/ AOGCC. If cement squeeze desired, set bridge plug, pert casing above TOC, set cement retainer and attempt isolation squeeze w/ cement retainer. Make require multiple squeezes as needed. Drill out cement. 16. RIH w/ Cmt Retainer on DP. Set retainer at 6,240' or 10' above tbg cut depth. Stack out 10k to confirm retainer set. 17. Stab into retainer and establish injection rate. Squeeze up to 15 bbl abandonment cement below retainer. Unsting from retainer and lay 50' (2.0 bbl) on top. Circ 2 btms up above cement top. POOH. 18. RIH w/ 6" scraper assembly w/ 6" bit to cmt top. Drill cement to 6,215'. POOH. 19. RU E-line. RIH w/ FB-1 packer and tail pipe. Set at 5,450'. POOH. 20. Set SB-1 packer plug. POOH. 21. Dump bail 10' CaC03 on plug. POOH. 22. RU to run Enventure SET casing patch. Set patch across DV collar at 2,793'. Test patch to 3,000 psi. POOH. 23. RIH w/ junk mill and watermelon mill. Mill out shoe. RIH to bottom and Circ out CaC03. 24. RU E-line. Pull SB-1 packer plug. 25. RIH w/ 3-1/2" Hydril 503 tubing. Stab thru FB-1 packer seal bore. Space out and land tubing hanger. 26. RU slickline. RIH w/ N-Test tool. Set in XN profile. Test tubing to 5,000 psi. POOH. 27. Test casing (3-1/2" x 7") to 1,500 psi (Official MIT). Record w/ chart recorder or SPIDR gauge. 28. RU E-line. RIH w/ 20' 6 spf 2-1/4" Big Hole guns. Perforate 6,163'-6,183' MD. POOH. 29. RU G&I to perform infectivity test on disposal zone. 30. CONTINGENCY: If .injection rates are too low or injection pressures too high, plan to reperf existing or add additional perfs above. Top of injection zone = 5,544' MD. Btm of injection zone = 6,183' MD. 31. Lay down landing jt. Set BPV. ND BOP. NU Tree. Pull BPV. Set TWC. Test Tree. Pull TWC. 32. RU flowlines. RD and prep for pad move. 33. "**Rig move to IRU 14-31X grass roots well*** 25 • • Waste Sources. Tvpes and Volumes 20 AAC 25.252 (c) 7 Sources and Volumes of Waste Resource Conservation Recovery Act (RCRA) exempt Class II wastes will be injected in the disposal well. This will include drilling fluids and cuttings; produced water not usable for enhanced recovery and a class of wastes termed "other associated waste". Other associated wastes specifically include waste materials intrinsically derived from primary field operations associated with the exploration, development, or production of crude oil and natural gas. "Intrinsically derived from primary field operations" is intended to distinguish exploration, development and production activities from transportation and manufacturing. With respect to crude oil, primary field operations include activities occurring at or near the wellhead and before the point where the oil is transferred from an individual field facility or a centrally located facility to a carrier for the transport to a refinery or a refiner. It also includes the primary, secondary and tertiary production operations. Crude oil processing, such as water separation, de-emulsifying, degassing, and storage at tank batteries associated with a specific well or wells, are examples of primary field operations. In general, the exempt status of an exploration and production waste depends on how the material was used or generated as waste, not necessarily whether the material is hazardous or toxic. A list of exempt oil and gas wastes are included in EPA publication 530-K-95-003 (May 1995). Crude Oil and Gas Exploration and Production Wastes: Exemption from RCRA Subtitle C Regulations. This includes but is not limited to drill cuttings, mud, produced fluids, reserve pit waste, rig wash, formation materials, completion fluids, workover fluids, stimulation fluids and solids, tracer materials, glycol dehydration wastes, naturally occurring radioactive material scale slurries, precipitation accumulating within production impoundment areas, tank bottoms, production chemicals used in wells, and other fluids brought to surface and generated in connection with oil and gas development activities. Maximum Disposal Volume by Major Category: Drill cuttings, mud, flush water 11 % (125,000 bbl) Well workover fluids and flush 9 % (100,000 bbl) Produced water and other clear exempt fluids 64 % (730,000 bbl) Reserve pit cuttings and fluids 16 % (180,000 bbl) Total Volume (20+ years) 1,135,000 bbl Injection Rate and Volume: The average daily injection rate is estimated to be 155 BPD, with excursions up to 1,000 +/- BPD. If the well remains active in this fashion for 20 years this would generate a cumulative disposal volume of 1,135,000 barrels. This would generate a radial plume in the injection zone of 180 +/- feet if not skewed by fracturing. 26 • • Compatibility of Fluids and Formation Towards this end log data for the wells within the field are the basis for the description included in Section (c) 4. The lithology of the injection zone is typical of local existing injection wells, being comprised of conglomeratic gravels, inert quartz and clay matrix material. The resident aquifer is typical for injection wells within the area that have operated without incident over the last 15 years and is therefore compatible with the same wastes being injected in similar storage reservoirs. 27 • Infection Pressure 20 AAC 25.252 (c) 8 • Injection pressure is estimated to average between 1,800 to 2,800 psi while injecting either mud or slurried cuttings because the densities and other properties will be similar. This should also be a reasonable pressure to expect when injecting produced water and other clear fluids because the decrease in hydrostatic gradient relative to the mud is offset by the more mobile liquid. This pressure is probably above the fracture gradient and the flow mechanism will involve fractures in some form. A maximum pressure of 5,000 +/- psi could be reached intermittently should sporadic plugging of the perforations or gradual plugging of the fracture flow channels occur due to settling or packing of solids. zs • • Waste Confinement 20 AAC 25.252 (c19 Injection of drilling mud and slurried cuttings will require pressures greater than the breakdown pressure of the formation. Initially a single planar vertical fracture should develop. This primary fracture can be expected to gradually plug with solids and also experience tip screen out. As the local stress regime is altered, appendages can develop creating a radial fracture system of some oblique fashion. The dimensions of the fracture domain will depend upon the amount of mud/cuttings injected and the rock properties controlling storage mechanics. The development of multiple fractures will have the effect of minimizing the lateral, and to some extent, the vertical growth of a primary fracture plane. A modeling study was undertaken to help quantify the behavior of injecting solids-slurry into the Sterling Formation. An industry available three dimensional hydraulic fracturing simulator was used to predict fracture growth during slurry injection. A prominent licensed commercial product was employed, built and maintained by Meyer and Associates, Inc. for industry use. The study was conducted by a Western Energy Services geophysical expert working at the University of Utah. Rock properties used in the model were based on well data calculated from well IRU 13-31 geophysical logs. The fracture gradient was itself then calibrated to break down data obtained from numerous other wells in the area. The fracture report of Appendix A details the model input data. The lower sand within the injection interval is planned to be utilized first with additional perforations being added above the initial perforations within the injection interval as the need arises. The main three sand members that constitute the modeled injection zone are shown on Exhibit 12. Injection of drilling and reserve pit wastes will generally be made in batches of approximately 1,000 barrels or less. The slurry will typically be 9.1 to 10.1 pounds per gallon (ppg) and is planned to be injected at a rate of 2.5 to 4.0 BPM. Exhibit 13 shows the forecasted fracture dimensions for the expected cases. Exhibit 14 shows the forecasted fracture geometry resulting from the planned injection equipment if the well was completed only in the lower sand lobe. Exhibit 15 is the result if only the middle lobe was used. Exhibit 16 and 17 show typical results under the most extreme conditions of injecting a 2,500 barrel batch of 10.1 ppg slurry at an elevated rate. Other cases are included in Appendix A. In all cases injection does not penetrate the upper confining zone or breach the lower confining shale. The worst-case fracture modeling indicates the upper confining zone will not be penetrated even if only the upper member of the injection zone is used for disposal (perforations at approximately -4,300 feet TVDSS). With plans to perforate in the lowest member at approximately -4,600 feet TVDSS, and with 200 feet of confining zone below, there is no reason to suspect either the upper or lower confining zones can be breached. This is supported by the performance of nearby injection well IRU 14-31 which has been in operation for 7 years, in a similar lithology shallower than IRU 13-31, and has successfully confined 46,500 barrels of slurry material. 29 Monitoring for cement channeling will verify wastes are confined at IRU 13-31. With no faulting in the area and the offset wells adequately cemented, the risk of not confining wastes and breaching the 700 foot thick upper confining zone should be insignificant. Reservoir Faulting: The geologic mapping in Exhibits 4 to 7 show there are no transmissive faults in the area. Uncemented Wellbores: Within the %4 mile area of review there are no improperly cased or cemented wells. An overview of these wells can be found in Section (c) 12. Conclusions: Wastes are expected to be confined within the injection zone just as has been experienced by the slurry injection in nearby well IRU 14-31, in a similar formation shallower than the IRU 13-31 disposal zone. 30 • 5400 5500 5600 5700 Y 5800 ~ 5900 0 6000 6100 6200 6300 6400 Vshale ~- -Gamma ~ - - 3- Upper Lobe - -~_ [perforations 5710-5680 ft] -~j^ _~~ _ _-- - -~ ~- := Middle Lobe _ _ - °-~ _~ - [perforations 5915-5860 ft] ;-=~ ~- - - ~~ - -- ---------------- ---------- ------------Z----- - Lower Lobe - ;=~ [perforations 6120-6160 ft] s ~- -. ~ ~- - 0 20 40 60 80 Gamma Ray (GAPI) Exhibit 12. Injection Zone with Major Sand Members • Shale Volume (fractional) 0.00 0.50 1.00 - 5400 31 5500 5600 5700 5800 Y oc 5900 ~ 6000 0 6100 6200 6300 6400 • • 1000 bbl of Slurry 2500 bbl of Slurry d Carse (g.5 ppg slurry ir~Cbed at 2.5 BPM) Fracture Half-Length (ft) [approximate] 327-506 482-782 Fracture Total Height (up and down) (ft) [approximate] 45-57 48-59 Fracture Width [inches, approximate] 0.13-0.24 0.14-0.26 Rabe Sensitivity (9.5 ppg slurry injected at 4 BPM) Fracture Half-Length (ft) [approximate] 337-616 573-963 Fracture Total Height (up and down) (ft) [approximate] 49-62 52-62 Fracture Width [inches, approximate] 0.15-0.27 0.16-0.29 Heavy Slung Sensitivity (10.1 ppg slurry inked at 2.5 BPM) Fracture Half-Length (ft) [approximate] 238-363 312-409 Fracture Total Height (up and down) (ft) [approximate] 71-78 82-100 Fracture Width [inches, approximate] 0.21-0.32 0.23-0.32 Heavy Slurry and Rabe Sensitivity {10.1 ppg slang in~c~ed at 4 BPI+1) Fracture Half-Length (ft) [approximate] 253-325 339-473 Fracture Total Height (up and down) (ft) [approximate] 44-88 49-98 Fracture Width [inches, approximate] 0.22-0.32 0.26-0.35 Exhibit 13. Average Fracture Dimensions (Varies According to How the Well is Completed) 32 • • 471 _ 472 q 7 H era 45 v Q 45 H Stress Width Profiles V4'idth Contours 3000 4000 -0 % l.~n ^a ^ zo 40 ® 60 ®80 i. 90 95 ~ 99 w~mh (ia) o o.oz 0.04 ._-_._.'._....___.._.'..._......._......._........_ 0.06 0.08 ._...._.-...... _._.__.. ......__.....-. _. _~.._. 0.1 I 0.12 ~ 0.14 _._.__ 0.16 0.18 I 0.2 0.22 0.24 ..__ ~ 0.26 - i I -- -- -- i 0 100 200 300 400 500 600 700 800 900 1000 Stress (psi) Width (ui.) Leugth (ft) Exhibit 14. Forecasted Geometry after Flush at End of Injecting 1,000 bbls of 9.5 ppg Slurry at 2.5 BPM in the "Lower Lobe" Stress V4'idth Profiles `t'idth Contours Stress (psi) Width (ui.) Length (ft) Exhibit 15. Forecasted Geometry after Flush at End of Injecting 1,000 bbls of 9.5 ppg Slurry at 2.5 BPM in the "Middle Lobe" 33 3000 4000 -0 Q F-' Q F Stress (psi) Width (ui.) Length (R) Exhibit 17. Forecasted Geometry after Flush at End of Injecting 2,500 bbls of 10.1 ppg Slurry at 4.0 BPM in the "Middle Lobe" 34 • Stress • Width Contours w~a~n tea) 0 o.os o. t o.ts oz i o.zs 0.3 0.35 i ~ 0.4 -}- i 0.45 u. i I 0 100 200 300 400 500 600 100 800 900 1000 Stress (psi) Width (ui.) Length (R) Exhibit 16. Forecasted Geometry after Flush at End of Injecting 2,500 bbls of 10.1 ppg Slurry at 2.5 BPM in the "Middle Lobe". Stress Width Profiles Width Contours 3000 4000 )o Width Profiles • • Formation Water Salinity and Aauifer Exemption 20 AAC 25.252 (c110 & 11 The Alaska Oil and Gas Conservation Commission issued Aquifer Exemption Order No. 6 to Union Oil Company of California on July 23, 2001. The order, based on formation water salinity data, exempts portions of freshwater aquifers between 2,500 feet and 3,420 feet MD and within a'/z mile radius of well IRU 14-31 for Class II injection. The'/z mile radius was granted to allow for the possible permitting of a second disposal well near the well IRU 14-31 injection zone. On July 15, 2008, Union Oil requested an extension of this freshwater aquifer exemption from 3,420 feet MD down to 5,435 feet MD to exempt freshwater aquifers between 2,500 feet and 5,435 feet MD in IRU Well 14-31. The extended exemption area would capture the base of the injection zone of the proposed disposal well IRU Well 13-31, which lies well within the YZ mile radius of the injection zone in well IRU 14-31. The aquifer exemption depth extension is pending approval by the AOGCC. 35 • • Wells Within the Area of Review 20 AAC 25.252 (cl 12 The'/4 mile area of review around the top of the proposed injection zone in IRU 13-31 is shown on Exhibit 2. This perimeter encompasses two wells: IRU 14-31 and IRU 44-36. Both wells are cased and cemented so as to not provide a conduit for injected wastes 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: Exhibit 18 includes the well schematic. The 10 3/< 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 injection zone. Second stage cement was placed from 3,646 feet to 625 feet TVD, thus cement is across the injection zone and both ends of the upper confining zone. This well is an active Class II disposal well that has injected 46,500 barrels to date. Well IRU 44-36: Exhibit 19 includes the well schematic. The 9 % inch surface casing is set at 3,449 feet MD (2,941 feet TVD). Cement was recorded at the surface; logging shows good bonding from 3,449 to 2,400 feet MD, with fair bond up to 1,600 feet MD. The 7-inch casing logging shows good bond up to 4,400 feet MD with some cement to 4,250 feet MD, the top of the logged interval. Calculations place the top of cement at 3,591 feet TVD, which is across the injection zone and very near the top of the upper confining zone. This well is an active gas producer. 36 • Ivan River Field Well 14-31 a za 20" 9411®421' ®1238' For 7" CBG. 10/4" 40.51E K-55 20.97" 1050 SXS TTC t 51' Bassd on Hole Size ®1318' Based on Equalimtton Thru Float Shoe Stage Collar ~ 4234' 689 SXS Annulus TTC Between 4845' and 4056' (CBL Not Conclusive) 7" 23, 28 d~ 29# N-80 ® 7018' 500 SXS 51/2" Liner ®10,000' I '-----) SUSP t~18n61 •7/8° 8.4# N-80 Butt Tubing raker 3-H Packer at 2903' Profile at 2948' (2.312 ID) raker WL Reentry Guide at 2982' cement Retainer at 3226' sment Plug 3350' -3508' X882' -8882' Sgz'd 200 5X ~ish #1 BHA Total Len h 228' ~robaby on Bottom at 0,084' ~ish #2 2208' of 2 7/8° D.P. 'op d• 7495' Bottom 9llt 9701' •ish #3 W.O. Asst' ~ D.C.'s length 380' 'op Q 7345' Bottom 8t 7725' lsh #4 2878' 2-2l3" TBG &3200' 31/2' D.P. 'op ®3510' Bottom f$ 9588' :ement Plug 7800' -9927' :ement Plug 10,100' -10,350' Cement Plug 10,850' -10,900' TD =10,958' Exhibit 18: IRU 14-31 Well Schematic 37 Chevron • IvaD River We1144-36 Actual CompletioD 9/12/01 Fill onn G,:n; IRLi.LI_;6 \~BD 9-I_-Ol ccx.doc CASING AND TtiBING DETAIL SIZE NT GRADE COVN ID TOP BTAI. 1?-38" 6S K-55 Buttress Surfnce 908' 9-~ 3"~ 37 \-80 Butrtess Swfnce ?.d39~ ?"- _'9 \-SO Hntvess 6.181 Srufncr ?.789' - ?9 P-110 Brttrcess 6.183 7JS9" 8.308" i¢biug -7 8` 6.1 L-80 Burt SC 2.331 _'3.05' ?.TS- ?-? 8" 1,6 L-80 Bntt SC 1.995 ??.OS' '.950' JEWELRY DETAIL NO. tb ID OD Item I Ihkil hrbing Hanger- S" t ' t 3` Vetco Gtay 10" 5na _ ?.060" 2.31J 3.500 Sliding Sleet'e. Baker. CMD. '-7 S~ Bntt ? ?.106' _.431 x.930 Packer. Baker FH Ren'ievable ~ 6.?73" 2.313 ?.500 Slidtn¢ Sleeve. Baker. CND. '-? $"" Butt 5 6.5IS' '.337 5.9?0 Packrr. Baker SC-: Ret. 1 Yim H) tlurnish S-" SAap Latch Seal Assc- 6 6.5?'~ ?.313 3.?50 Slidto¢ Sleeve. Baker. CND. '-? $"' Butt - 6.77?" '.?4' S.97n Packer. Baker SC-' Ret. 1Nut ID through S-" SllAp Latch) 3 6.796' 2.313 ?.750 Slidm¢ Sleeve. Baler. CND. '-7 $" Butt 9 7.05?' ±.313 3500 Sipple. X. '.31=~' lD. '-% 3" Butt 10 '.096" '.?37 5.310 Packrr. Baker SC-1 Ret. (Nm ID tluou¢h S-" Snap Latch) i l 7.111 3.3$0 5. SQQ Ne51A7te ialild Sl'fePn AiSt'. . )t5 at ?$ each 1' ?_'??' '.?37 5.6'; Packer. Baker Nod. D. (Nat ID tlunu¢h S_"_ Sttap Latch) 13 ?.690" 2.313 3.500 Sipple. %. '.?1;" H). '-? $"' Btttt IS J'3~ ' 331 ±_'S0 R'irelme Enm~ Etude Heater String A '9^0" _-. S". 3.6=. N-SO Butt Tubins n'ttlt Nnle Shoe PERFORATION HISTORY IltP ll'A ff11I6 MP 0116 O IIII 5 'OtNOegtS 9? i3-3 6.331' 6.330' 9' I $ Relxtfed 9 3 0l 7 93 59-6 655 T 6.565' I C I3 R ~etfrd 9 3 01 :793 ?l-? 6.S?6' 6.55" 16' lS R fed 9301 9301 i3-S ?.ll?' 7.150' I? NesluiteScreett 9 3 Ol 75-? 7.16?' ?.133' ' I' I _' >lesluite Sa~ee» 9 3 01 3'-' 7J60' - I" 6 ETD = 8.272'. TD = 8,308' BIAS Hole Aggle = ~8 deg rn x,225' DR-1\~'1 Bl": tcb RE\-ISED: 9 .S UI Exhibit 19: IRU 44-36 Well Schematic 38 i Mechanical Integrity of Infection Well 20 AAC 25.252 (d) & (e) Ivan River 13-31 Mechanical Integrity Once the tubing is pulled, and the existing perforations are isolated, a patch will be run across the leaking DV collar in the 7" casing at 2,793 feet MD. The patch and 7-inch casing will be pressure tested to 3,000 psi and the 7-inch by 9 % inch annulus pressure tested to 1,500 psi to ensure mechanical integrity of the well bore prior to perforating the injection zone. Formation Testing and Integrity Initial formation testing will involve apump-in step rate test. up to a planned 6 BPM, if equipment is available for this rate, followed by a pressure fall off to obtain a base line formation pressure. A channel log or temperature log will be run after the well is injecting to confirm waste confinement. Subsequent testing, monitoring, and reporting will conform to the AOGCC requirements for slurry disposal wells. 39 • • Appendix A Fracture Modeling Report • C7 Simulation of Slurry Injection: Ivan River Unit 13-31 Prepared for: Chevron North America Exploration and Production Company MidContinent/Alaska Business Unit 909 West 9th Avenue, Anchorage, AK 99501 Prepared by: Western Energy Consultants LLC WEC-08-03 August 2008 WESTERN ENERGY CONSULTANTS • Chevron North America Exploration and Production Company Page 2 Ivan River Unit 13-31 TABLE OF CONTENTS Background ................................................................................................. 3 Matrix Of Simulations ....................................................................................3 Resu Its ........................................................................................................ 4 Appendix A -Input Parameters ................................................................... 10 Appendix B -Results ................................................................................. 22 WESTERN ENERGY CONSULTANTS ~, Chevron North America Exploration and Production Company Ivan River Unit 13-31 Page 3 BACKGROUND Simulations were carried out in support of an application to dispose Class II oil field waste fluids by underground injection into well IRU 13-31, located in the Ivan River Field, Matanuska-Susitna Borough, Alaska. Hydraulic fracturing simulations were carried out using commercial and proven software (MFracT"') to assess the evolution of fractures associated with injection into this well. MATRIX OF SIMULATIONS Appendix A summarizes the input material properties. The variables adopted in the simulations were: • Four completion schemes. Perforations are shown in Figure 1 and Table 1. Table 1. Perforated and Barefoot intervals Measured Zone Depth of Comments Depth of Perforations Perforations (feet TVD RKB) feet RKB 5680-5710 Upper Lobe 4362.5- 4383.2 Estimated completed zone 5860-5915 Middle Lobe 4500.4-4543.4 Estimated completed zone 6120-6160 Lower Lobe 4703.6-4734.8 Estimated completed zone Initial simulations considered injection in the lowermost lobe only. Additional simulations considered injection exclusively into the middle or upper zones. A final scenario considered contemporaneously accessing all three perforated zones 1. Injection into the Lower Lobe (perforated 6120 to 6160 ft. 2. Injection into the Middle Lobe (perforated 5860 to 5915 ft. 3. Injection into the Upper Lobe (perforated N5680 to 5710 ft. 4. All three perforated zones open to injection • Three fluids were used in the simulations. These were neat produced water or seawater (no solids) at an estimated temperature of 70°F (at the sandface), a 9.5 ppg slurry [equivalent to a base fluid with approximately 1.5 ppa (pounds of proppant - solids -added)], and a 10.1 ppa slurry [equivalent to a base seawater fluid with approximately 2.4 ppa solids]. Power law rheologies for these fluids were specified and these are shown in Table 2. Table 2. Fluid Rheology Fluid n' K' (Ibf-s"~/ftZ) Weight (ppg) Specific Gravity Seawater/PW (base fluid) 1.0 1.313 x 10-5 8.66 1.04 9.5 ppg slurry 0.7 1.022 x 10"3 9.5 1.14 10.1 ppg slurry 0.7 7.156 x 10.3 10.1 1.21 • WESTERN ENERGY CONSULTANTS • • Chevron North America Exploration and Production Company Page 4 Ivan River Unit 13-31 • Several schedules were adopted for assessing slurry injection. Various parametric simulations were run and key results are reported for the following scenarios. 1. Case 1 (Base Case): a. 1000 bbls of 9.5 ppg slurry with a spearhead and flush at 2.5 BPM. b. 2500 bbls of 9.5 ppg slurry with a spearhead and flush at 2.5 BPM. 2. Case 2: a. 1000 bbls of 9.5 ppg slurry with a spearhead and flush at 4 BPM. b. 2500 bbls of 9.5 ppg slurry with a spearhead and flush at 4 BPM. 3. Case 3: a. 1000 bbls of 10.1 ppg slurry with a spearhead and flush at 2.5 BPM. b. 2500 bbls of 10.1 ppg slurry with a spearhead and flush at 2.5 BPM. 4. Case 4: a. 1000 bbls of 10.1 ppg slurry with a spearhead and flush at 4 BPM. b. 2500 bbls of 10.1 ppg slurry with a spearhead and flush at 4 BPM. The methods for developing the input data are included in Appendix A. RESULTS Results of the fracturing simulations are summarized in Table 3. Figures for the various cases are provided in Appendix B. Based on the results, the anticipated dimensions for a batch injection are shown in Table 4. General observations are that good injection practices (in terms of displacement) may be important because of the inclination of the well; and, the heavier slurry tends to have less length development and more height and width development, as would be expected. WESTERN ENERGY CONSULTANTS • • Chevron North America Exploration and Production Company Page 5 Ivan River Unit 13-31 5400 5500 5600 5700 Y 5800 oc D ~ 5900 Q 0 6000 6100 6200 6300 5500 5600 5700 5800 Y o' 5900 ~ Q. 6000 0 6100 6200 6300 6400 6400 0 20 40 60 80 Gamma Ray (GAPI) Figure 1. Targeted zones are shown with potential perforation clustering shown. - Vshale -Gamma t - -T i. ~_ ~~ ~_ .-_ ~~~ Upper Lobe - _,. _ [perforations 5710-5680 ft] - ,-- ® ~ ~':= Middle Lobe - [perforations 5915-5860 ft] :. .y,... --- .~__,~ _. a,-•z -. ~~_ _ ~~ Lower Lobe ~; ~:=- [perforations 6120-6160 ft] _ -- - ~ _ _ _ - ,~~ _- _ Y. -~ - I~ -~ Shale Volume (fractional) 0.00 0.50 1.00 5400 WESTERN ENERGY CONSULTANTS Chevron North America Exploration and Production Company Page 6 Ivan River Unit 13-31 Table 3. Summary of Fracture Dimensions at the End of Injection Case i Completion x Zone Rate (BPM) In ection ~ Fluid Total Volume; (bbl) Fracture Half- a Length (ft) Upper Heights (~) Lower Height (~) Maximum Wellbore Width ~ (inches) EO78 Net Pressure (psi) la All 2.5 9.5 ppg slurry 1,000 Lower < 19 159 199 Middle Upper 489 29 16 .176 156 lb Lower Lower 2.5 9.5 ppg slurry 1,000 327 23 34 .125 81 is Middle Middle 2.5 9.5 ppg slurry 1,000 506 29 21 .243 84 ld Upper Upper 2.5 9.5 ppg slurry 1,000 489 29 16 .176 156 1e All 2.5 9.5 ppg slurry 2,500 Lower < 19 159 199 Middle Upper 706 31 17 .193 165 if Lower Lower 2.5 9.5 ppg slurry 2,500 482 25 34 .14 87 1 This designates which zone is open. The upper zone would be perforated. The Lower Sand will tentatively be barefoot. Perforations are also potentially open in the shale (above the shoe and below the perforations in the Upper Sand). z Designates zone where fracture growth occurs. s Excluding displacement volume (spearhead and flush). a Fracture half-length is the length from the wellbore to the tip of one wing of an assumed symmetrical fracture (i.e., the modeling presumes that two identical fracture wings grow diagonally away from the wellbore in the direction of the maximum horizontal principal stress. s Designates the vertical upwards growth at the wellbore from the center of the specified zone. s Designates the vertical downwards growth at the wellbore from the center of the specified zone. ~ Maximum wellbore width is the maximum fracture width at any position along the wellbore. $ EOJ (end of job) implies after flush, at shut-in. Net pressure is the difference between the sandface injection pressure and the in-situ stress at the mid-depth of the completed zone. 9 Recedes. WESTERN ENERGY CONSULTANTS Chevron North America Exploration and Production Company Page 7 Ivan River Unit 13-31 Case i Completion 2 Zone Rate (gPM) Injection Fluid Total3 Volume (bbl) Fracture Half- Length4 (ft) Upper Heights (~) Lower Height6 (ft) Maximum Wellbore Width (inches)' EO)8 Net Pressure (psi) lg Middle Middle 2.5 9.5 ppg slurry 2,500 782 29 21 .263 91 lh Upper Upper 2.5 9.5 ppg slurry 2,500 706 31 17 .193 165 2a All 4 9.5 ppg slurry 1,000 Lower <19 159 219 Middle Upper 557 31 18 .198 167 2b Lower Lower 4 9.5 ppg slurry 1,000 337 28 34 .145 97 2c Middle Middle 4 9.5 ppg slurry 1,000 616 30 22 .267 93 2d Upper Upper 4 9.5 ppg slurry 1,000 557 31 18 .198 167 2e All 4 9.5 ppg slurry 2,500 Lower <19 149 219 Middle Upper 751 32 22 .22 171 2f Lower Lower 4 9.5 ppg slurry 2,500 573 28 34 .163 95 2g Middle Middle 4 9.5 ppg slurry 2,500 963 30 22 .288 104 2h Upper Upper 4 9.5 ppg slurry 2,500 751 32 23 .221 171 3a All 2.5 10.1 ppg slurry 1,000 Lower < 19 159 199 Middle Upper 288 39 34 .262 172 3b Lower Lower 2.5 10.1 ppg slurry 1,000 238 44 34 .208 104 3c Middle Middle 2.5 10.1 ppg slurry 1,000 363 48 23 .317 93 3d Upper Upper 2.5 10.1 ppg slurry 1,000 288 39 35 .262 172 WESTERN ENERGY CONSULTANTS Chevron North America Exploration and Production Company Page 8 Ivan River Unit 13-31 Case i Completion 2 Zone Rate (BPM) In action ~ Fluid Total Volume3 (bbl ) Fracture Half- a Length (ft) Upper Heights (ft) Lower Height6 (ft) Maximum Wellbore Width (inches)' EOJ8 Net Pressure (psi) 3e All 2.5 10.1 ppg slurry 2,500 Lower <19 159 199 Middle Upper 396 45 37 .29 175 3f Lower Lower 2.5 10.1 ppg slurry 2,500 312 59 34 .229 101 3g Middle Middle 2.5 10.1 ppg slurry 2,500 409 77 23 .317 65 3h Upper Upper 2.5 10.1 ppg slurry 2,500 396 45 37 .29 175 4a All 4 10.1 ppg slurry 1,000 Lower X19 139 259 Middle Upper 325 44 40 .297 178 4b Lower Lower 4 10.1 ppg slurry 1,000 253 59 34 .224 103 4c Middle Middle 4 10.1 ppg slurry 1,000 283 88 24 .316 56 4d Upper Upper 4 10.1 ppg slurry 1,000 325 44 37 .297 178 4e All 4 10.1 ppg slurry 2,500 Lower ~i9 79 259 Middle Upper 473 49 37 .328 187 4f Lower Lower 4 10.1 ppg slurry 2,500 339 60 44 .264 103 4g Middle Middle 4 10.1 ppg slurry 2,500 419 98 24 .348 58 4h Upper Upper 4 10.1 ppg slurry 2,500 473 49 37 .328 187 WESTERN ENERGY CONSULTANTS • • Chevron North America Exploration and Production Company Page 9 Ivan River Unit 13-31 Table 4. Average Fracture Dimensions (vary according to how the well is completed) 1,000 bbl of Slurry 2500 bbl of Slurry Case (9S ppg ~W'~lf injected at 2.5 BPM) Fracture Half-Length (ft) [approximate] 327-506 482-782 Fracture Total Height (up and down) (ft) [approximate] 45-57 48-59 Fracture Width [inches, approximate] 0.13-0.24 0.14-0.26 Rafie Sa~iibhrily (9.5 ppg slurry igjeti.ed at 4 BPM) Fracture Half-Length (ft) [approximate] 337-616 573-963 Fracture Total Height (up and down) (ft) [approximate] 49-62 52-62 Fracture Width [inches, approximate] 0.15-0.27 0.16-0.29 ~Y Slurry Senootivliy (10.1 ppg shiny Irk at 2.5 BPM) Fracture Half-Length (ft) [approximate] 238-363 312-409 Fracture Total Height (up and down) (ft) [approximate] 71-78 82-100 Fracture Width [inches, approximate] 0.21-0.32 0.23-0.32 Heavy Slurry and Rate Sensitivity (10.1 ppg shiny injected at 4 BpM) Fracture Half-Length (ft) [approximate] 253-325 339-473 Fracture Total Height (up and down) (ft) [approximate] 44-88 49-98 Fracture Width [inches, approximate] 0.22-0.32 0.26-0.35 WESTERN ENERGY CONSULTANTS • • Chevron North America Exploration and. Production Company Page 10 Ivan River Unit 13-31 APPENDIX A INPUT PARAMETERS WESTERN ENERGY CONSULTANTS ~ • Chevron North America Exploration and Production Company Page 11 Ivan River Unit 13-31 A.1. Well Information: The completions considered are shown in Table A-1 and Figure A-1. Table A-1. Perforated and Openhole Sections Measured Depth of Perforations feet RKB Zone Depth of Perforations feet TVD RKB Comments 5680-5710 Upper Lobe 4362.5- 4383.2 Estimated completed zone 5860-5915 Middle Lobe 4500.4-4543.4 Estimated completed zone 6120-6160 Lower Lobe 4703.6-4734.8 Estimated completed zone A.2 Survey Information: The survey data are shown in Figure A-2. A.3 Porosity Information Figure A-3 shows a representation of porosity. Since a substantial portion of the data were unreliable or not reported, they were synthesized using relationships from IRU 14-31. This was determined as multivariate linear regression on information considered to be subjectively reliable. The relationship used was: DPHI (decfma~ _ -0.15416 + 0.002927 x DTC (,u sec/ ft) + 0.00146 x GR (GAPI) - - 0.0013 7 x ILD (ohm - m) + 0.000173 x ILM (ohm - m) Figure A-4 shows bulk density synthesized from the density porosity, assuming a sandstone matrix (SG = 2.65), 100 percent water saturation and a fluid specific gravity of 1.04. With all of the uncertainties, the simplistic relationship used was: pb (RHOBg/cm3)=2.65(1-DPHI)+1.04DPHI A.4. Ftuid Loss Properties The permeability was estimated using experience-based relationships (Figure A-5) where the relationship with porosity is: k (md) _ -9.4983VS,~,e + 6.4983 Vs~re - GR - GRSg„d ~ GRSa„d =10 °API; GRsrure = 70 °API GRS~,~eGRsand Figure A-5 shows the inferred permeability. To be conservative, spurt loss (instantaneous loss in fluid when new fracture surface is created) was taken as being zero. The wall building fluid loss coefficient (Figure A-6) was estimated as follows (analog situations): CW = 0.0007841oglok + 0.0.00243 ft/minuteli2 WESTERN ENERGY CONSULTANTS • • Chevron North America Exploration and Production Company Page 12 Ivan River Unit 13-31 5400 5500 5600 5700 Y 5800 oc ~ 5900 0 6000 6100 6200 6300 5500 5600 5700 5800 Y D 5900 ~ 6000 0 6100 6200 6300 6400 6400 0 20 40 60 80 Gamma Ray (GAPI) Figure A-1. Targeted zones are shown with potential perforation clustering also shown. - Vshale ~ -Gamma . -~ ~- . - ~~ .. ~ _ _ ~~ Upper Lobe - [perforations 5710-5680 ft] _ ------------~-. . --------------------r`- -_ _------ -- -3 -- _ -~_= ' ~ ~= Middle Lobe _ .:~~ ~ -~.. [perforations 5915-5860 ft] -' -_- -~=; "-~'~ - - Lower Lobe =~' [perforations 6120-6160 ft] .. _ -~- ~, ~~ r Shale Volume (fractional) 0.00 0.50 1.00 5400 WESTERN ENERGY CONSULTANTS • • Chevron North America Exploration and Production Company Page 13 Ivan River Unit 13-31 0 0 1000 2000 m Y ~ 3000 0 4000 5000 6000 Figure A-2. Plot of TVD versus MD. A.5. Mechanical Properties and Stress Synthesis Moduli were also estimated from inferences of the shear wave slowness (Figure A-7). These were based on the Greenwood-Castagna relationships, since no other information was available. The relationship used to estimate the shear wave slowness was: 5.59 - 8.6DPHI (decimal) - 2.18V~~~, (decimal) DTS (,u sec/ ft) = DTC (,u sec/ ft) 3.52 - 6.1DPHI (decimal) -1.89V~,~, (decimal) V~r~ = Vsr~re Vsnare - GR - GRsa„a ~ GRsana =10 °API; GRsn~re = 70 °API GRSnaieGRsaur The correction from dynamic (logging) to static (for simulation) values was based on analog data. Poisson's ratio is shown in Figure A-8; Young's modulus is shown in Figure A-9. The stresses were then estimated using Poisson's ratio, bulk density, and moduli [refer to Figure A-10] Trajectory 13-31 MD (R KB) 1000 2000 3000 4000 5000 6000 7000 WESTERN ENERGY CONSULTANTS • • Chevron North America Exploration and Production Company Page 14 Ivan River Unit 13-31 Porosity Porosity (fractional) 0.00 0.50 3500 1.00 -~ 3500 - DPHI - Gamma 4000 4500 .. m ~ 5000 0 a 5500 a~ 0 6000 6500 4000 4500 .-. m 5000 ~ 0 .. 5500 ~ a~ 0 6000 6500 7000 7000 0 20 40 60 80 Gamma Ray (GAPI) Figure A-3. DPHI -from measured data and from synthetic data using a multivariate linear regression on data from IRU 14-31. A maximum porosity of 0.35 was specified. WESTERN ENERGY CONSULTANTS • • Chevron North America Exploration and Production Company Page 15 Ivan River Unit 13-31 Bulk Density 1.50 3500 r 4000 4500 m ~ 5000 0 .., a 5500 a~ 0 6000 6500 2.50 -~ 3500 4000 4500 .-. m 5000 ~ 0 .~ 5500 a a~ 0 6000 6500 7000 7000 0 20 40 60 80 Gamma Ray (GAPI) Figure A-4. RHOB -from measured data and from synthetic porosity data using a sandstone matrix and 100 percent brine saturation. Bulk Density (gm/cm3) 2.00 - RHOB - Gamma WESTERN ENERGY CONSULTANTS Chevron North America Exploration and Production Company Ivan River Unit 13-31 Page 16 P21'C112a bl ~ I~/ Permeability -Gamma Ray Estimated Absolute Permeability (md) 0.001 0.01 0.1 1 10 100 1000 10000 5500 5600 5700 5800 m 5900 0 ~ 6000 a 0 6100 6200 6300 6400 6500 5500 5600 5700 5800 5900 m oc 0 6000 ~ ... n 6100 0 6200 6300 6400 6500 0 20 40 60 80 100 Gamma Ray (GAPI) Figure A-5. Permeability estimates. WESTERN ENERGY CONSULTANTS • r Chevron North America Exploration and Production Company Page 17 Ivan River Unit 13-31 F~UId LOSS C02ffIC12Clt - Fluid Loss Coefficient o.ooool 3500 r 4000 4500 .. m ~ 5000 0 5500 0 6000 6500 - Gamma Estimated CW (ft/minutei~z) o.oool 0.001 0.01 0.l 3500 4000 4500 ,- m 5000 ~ 0 5500 0 6000 6500 7000 ' 7000 0 20 40 60 80 100 Gamma Ray (GAPI) Figure A-6. Wall building fluid loss coefficient estimates. WESTERN ENERGY CONSULTANTS r • Chevron North America Exploration and Production Company Page 18 Ivan River Unit 13-31 Synthetic Shear Wave 5000 5200 5400 5600 m 5800 Y $ 6000 .. ~. 0 6200 6400 6600 6800 Slowness (µsec/ft) 0 100 200 300 400 500 5000 5200 5400 5600 5800 m Y D 6000 ~ a 6200 0 6400 6600 6800 7000 7000 0 20 40 60 80 100 120 140 160 180 200 Gamma Ray (GAPI) Figure A-7. Compressional and shear wave slowness. ~~ - DTS DTC - Gamma WESTERN ENERGY CONSULTANTS • ~ Chevron North America Exploration and Production Company Ivan River Unit 13-31 3500 4000 4500 m ~ 5000 0 n 5500 a~ 0 6000 6500 Page 19 Young's MOCIU~US Young's Modulus -Gamma Young's Modulus (106 psi) 0.0 0.3 0.5 0.8 1.0 1.3 1.5 1.8 2.0 3500 7000 ' 0 20 40 60 Gamma Ray (GAPI) 80 4000 4500 .~ m 5000 ~ 0 .~ 5500 0. a~ 0 6000 6500 7000 Figure A-8. Young's modulus (calculated from the bulk density and the P- and S-wave slownesses, and calibrated using analog data). WESTERN ENERGY CONSULTANTS • • Chevron North America Exploration and Production Company Page 20 Ivan River Unit 13-31 3500 4000 4500 m ~ 5000 0 5500 0 6000 6500 POISSOCI~S Rat10 -- Poisson's Ratio - Gamma Poisson's Ratio 0.0 0.1 0.2 0.3 0.4 0.5 3500 7000 ' 0 20 40 60 80 100 Gamma Ray (GAPI) Figure A-9. Poisson's ratio. 4000 4500 m 5000 ~ 0 5500 0 6000 6500 7000 WESTERN ENERGY CONSULTANTS Chevron North America Exploration and Production Company Page 21 Ivan River Unit 13-31 - Vertical -Formation Pressure Gradients Minimum Horizontal -Gamma Ray Stress and Pressure Gradients (psi/ft) 0.0 0.2 0.4 0.6 0.8 1.0 5000 i ~; 5000 ~, I =- 5200 5400 5600 m 5800 Y oC ~ 6000 s o. 0 6200 6400 6600 6800 6000 ~ 6200 0 6400 6600 6800 7000 ' 7000 0 20 40 60 80 100 Gamma Ray (GAPI) Figure A-10. Stresses and formation pressure gradients. Hydrostatic pressure was assumed for the formation pressure. There is no substantial data available for calibrating the log predictions. 5200 5400 5600 5800 m Y WESTERN ENERGY CONSULTANTS • Chevron North America Exploration and Production Company Page 22 River Unit 13-31 APPENDIX B RESULTS WESTERN ENERGY CONSULTANTS Chevron North America Exploration and Production Company Page 23 Ivan River Unit 13-31 th Profiles Width Contours ~_ Q H Stress (psi) Width (ui.) Length (ft) Figure B-1. This is the inferred geometry after flush (displacement volume) at shut-in for Case is (2.5 BPM, 9.5 ppg slurry, 1,000 BBL, injection into all three lobes). Stress Width Profiles Width C'~nt~urs 4". Q H wam 0 0 oz o.oa -- '- ----~ - - o oc 0 os _. 0.1 o.iz 0.14 --- -- 0.16 ~'~, 0.18 02 ~'', 0.22 0.24 ..__ - .~.__...__ ',,. 0.26 I i ,. - _. i 0 100 200 300 400 500 600 700 800 900 1000 Stress (psi) Width (ni.) Length (ft) Figure B-2. This is the inferred geometry after flush (displacement volume) at shut-in for Case ib (2.5 BPM, 9.5 ppg slurry, 1,000 BBL, injection into the "Lower Lobe'7. WESTERN ENERGY CONSULTANTS Stre< ~- s Chevron North America Exploration and Production Company I R' U't1331 van aver ni - ~~a~ Stress Width Profiles V4'idth Contours Length ^0 ^ 20 ^ 40 ^ 60 ^ 80j/J, ^ 99 7 1 `w' Q E-~ 2000 3000 4000 -0 Page 24 Stress (psi) ~Yidth (in.) Length (ft) Figure B-3. This is the inferred geometry after flush (displacement volume) at shut-in for Case is (2.5 BPM, 9.5 ppg slurry, 1,000 BBL, injection in the "Middle Lobe"). ._._ Stress Width Protiles Width Contours Lcgth ^0 ^ 20 ^ 40 ^ 60 ®80 ^ 90 ^ 99 4"' Q H 2000 3000 4000 -0.15 -0.05 0.05 0.15 snn ~n 70 Stress (psi) Width (ui.) Length (ft) Figure B-4. This is the inferred geometry after flush (displacement volume) at shut-in for Case ld (2.5 BPM, 9.5 ppg slurry, 1,000 BBL, injection into the "Upper Lobe"). WESTERN ENERGY CONSULTANTS • • Chevron North America Exploration and Production Company Ivan River Unit 13-31 Stress V6'idth Protiles Vl'idth C~ntc-urs ~_ Q r~ H -0 Length ^o ^ zo ^ 40 ® 60 Q 80 ^ 90 ^ 95 ^ 99 .75 -0.05 0.05 0. Page 25 wmn [m) 0 0.02 0.04 0.06 0.08 __ 0.1 _.__... 0.12 0.14 0.16 _~ ~ ___0.18 _.. 0.2 15 0 100 200 300 400 500 600 700 800 900 1000 Stress (psi) Width (in.) Length (ft) Figure B-5. This is the inferred geometry after flush (displacement volume) at shut-in for Case 1e (2.5 BPM, 9.5 ppg slurry, 2,500 BBL, injection into all three lobes). Stress Width Protiles R'idth Contours ~_ Q J E-~ -0 ],eng th ^o ^ zo ^ 40 ^ 60 ^ 90 ^ 95 ^ 99 ~'1 1 75 -0.05 0.05 0. 75 vrau, ~ ) 0 0.03 0.06 - _ __ 0.09 0.12 __ _.__ 0.75 0.18 0.21 0.24 0.27 i .: l 0 100 200 300 400 500 600 700 800 900 1000 Stress (psi) Width (in.) Length (ft) Figure B-6. This is the inferred geometry after flush (displacement volume) at shut-in for Case if (2.5 BPM, 9.5 ppg slurry, 2,500 BBL, injection into the "Lower Lobe'7. WESTERN ENERGY CONSULTANTS • ~ Chevron North America Exploration and Production Company Page 26 Ivan River Unit 13-31 ..__ Stress V~'idth Profiles Width Contours % Len 0 zo 40 ® 60 80 90 95 ~ 99 4". Q E-" 2000 3000 4000 -0 wd~n (m ~ o 0.03 0.06 0.09 _ _. -___- 0.12 0.15 0.78 021 -- 0 24 X027 15 0 100 200 300 400 500 600 700 800 900 10 00 Stress (psi) Width (ui.) Length ($) Figure B-7. This is the inferred geometry after flush (displacement volume) at shut-in for Case ig (2.5 BPM, 9.5 ppg slurry, 2,500 BBL, injection in the "Middle Lobe"). ._._ Stress Width Profiles Width Contours rte. ^0 ^ zo 40 ®60 ®80 90 95 ~ 99 ~_ Q J H 2000 3000 4000 -0.15 -0.05 0.05 0.15 0 100 200 300 400 500 600 700 800 900 1000 Stress (psi) Width (ui.) Length (ft) Figure B-8. This is the inferred geometry after flush (displacement volume) at shut-in for Case ih (2.5 BPM, 9.5 ppg slurry, 2,500 BBL, injection into the "Upper Lobe"). WESTERN ENERGY CONSULTANTS • • Chevron North America Exploration and Production Company Ivan River Unit 13-31 Stress Width Profiles Width Contours +~`'-. Q H ~ 0 20 40 ® 60 ®60 90 95 99 -0 Page 27 ', w,~~m~ 0 0.02 _- - - ~ 0.04 _.._mw_ i 0.06 f 0.08 0.1 . __ _.._.__.. 0.12 I 0.14 . 0.16 0.18 0 100 200 300 400 500 600 700 800 900 1000 Stress (psi) Width (ui.) Length (ft) Figure B-9. This is the inferred geometry after flush (displacement volume) at shut-in for Case 2a (4 BPM, 9.5 ppg slurry, 1,000 BBL, injection into all three lobes). ___ Stress Width Profiles Width Contours 47 w_ Q J F-+ ^o ^ zo 40 ®60 ®80 ~ 90 95 99 ~n _n 900 Stress (psi) Width (ni.) Length (ft) Figure B-10. This is the inferred geometry after flush (displacement volume) at shut-in for Case 2b (4 BPM, 9.5 ppg slurry, 1,000 BBL, injection into the "Lower Lobe'. WESTERN ENERGY CONSULTANTS Chevron North America Exploration and Production Company Ivan River Unit 13-31 ,~~~ Slress Width Profiles Width Contours ~o ^ zo ^ 40 ^ 60 ^ 80 ^ 90 ^ 95 ~_ Q .! H 2000 3000 4000 -0 Page 28 wmn ( ~ 0 0.03 0.06 0.09 -.:: , 0.72 . ''. 0.15 0.18 0.21 I ~ 0.24 0.27 0 100 200 300 400 500 600 700 800 900 1000 Stress (psi) Width (ui.) Length (ft) Figure B-11. This is the inferred geometry after flush (displacement volume) at shut-in for Case 2c (4 BPM, 9.5 ppg slurry, 1,000 BBL, injection in the "Middle Lobe'7. Stress Width Profiles Width Contours ^o ^ zo ^ 40 Q 60 Q 80 ^ 90 ^ 95 ^ 99 ~_ Q H 2000 3000 4000 -0 wam ~m> 0 0 oz 0.04 0.06 .;+s. _.-. 0.08 - 0.1 _ 0.12 0.14 .,.. i .0.16 0.18 •__- .__._- 0.2 --- -- ~! .. .-~ 3 '. x' '.. ...._ ._...I y. .... .__. i '. '~ '. o loo zoo 30o aoo 50o soo 70o soo soo looo Stress (psi) Width (in.) Length (ft) Figure B-12. This is the inferred geometry after flush (displacement volume) at shut-in for Case 2d (4 BPM, 9.5 ppg slurry, 1,000 BBL, injection into the "Upper Lobe'7. WESTERN ENERGY CONSULTANTS • Chevron North America Exploration and Production Company Page 29 Ivan River Unit 13-31 .___ Stress Width Profiles Width Contours C~ Q H 2000 4000 6000 -0 9-o u~ ^o ^ zo 40 ® 60 ® 80 90 95 99 I ' W~~ cm1 0 0.02 0.04 0.06 0.08 0.1 0.12 0.14 0.16 0.18 0.2 0.22 0.24 I i 0 100 200 300 400 500 600 700 800 900 1000 Stress (psi) ~Yidth (in.) Length (ft) Figure B-13. This is the inferred geometry after flush (displacement volume) at shut-in for Case 2e (4 BPM, 9.5 ppg slurry, 2,500 BBL, injection into all three lobes). .___ Stress Width Profiles Width Contours r.~ ^0 20 40 60 ^ 80 90 95 ~ 99 tt~ Q J H 2000 3000 4000 -0 w~c~ 0 0 03 0.06 - 0.09 0.12 ..- _...... 0.15 0.18 I 0.21 -- ._ 0.24 0.27 i 03 1'~ 5 0 100 200 300 400 500 600 700 800 900 1000 Stress (psi) Width (ni.) Length (ft) Figure B-14. This is the inferred geometry after flush (displacement volume) at shut-in for Case 2f (4 BPM, 9.5 ppg slurry, 2,500 BBL, injection into the ~~Lower Lobe"). WESTERN ENERGY CONSULTANTS • Chevron North America Exploration and Production Company Ivan River Unit 13-31 Page 30 Stress Vl'idth Protil t«~,~ ^o ~ zo 40 60 90 95 fr' 99 451 W Q 45i E-~ 2000 3000 4000 -0 Width Contours snn ~n IS ~o Stress (psi) ~Yidth (ui.) Length (ft) Figure B-15. This is the inferred geometry after flush (displacement volume) at shut-in for Case 2g (4 BPM, 9.5 ppg slurry, 2,500 BBL, injection in the "Middle Lobe'7. ._._ Stress Width Profiles Width Contours ~~i i Zo 40 Q 60 ^ 80 90 1 ® 95 Il 99 4:. Q E-' 2000 3000 4000 -0 l0 Stress (psi) ~Yidth (ni.) Length (ft) Figure B-16. This is the inferred geometry after flush (displacement volume) at shut-in for Case 2h (4 BPM, 9.5 ppg slurry, 2,500 BBL, injection into the "Upper Lobe"). WESTERN ENERGY CONSULTANTS Chevron North America Exploration and Production Company Ivan River Unit 13-31 Page 31 w", u Q H Width Profile: l0 -0 ~0 20 40 60 D 80 90 ~ 95 Width Contours w~~m, 0 ' 0.03 _ ____ - i ___ 0.06 ,. ~ .__ __ _ ___ __ _ __.. 0.09 '~ _ 0.12 0.15 0.18 0.21 0.24 0.27 I I i I 0 100 200 300 400 500 600 700 800 900 1000 Stress (psi) Width (in.) Length (ft) Figure B-17. This is the inferred geometry after flush (displacement volume) at shut-in for Case 3a (2.5 BPM, 10.1 ppg slurry, 1,000 BBL, injection into all three lobes). .___ Stress Width Profiles Width Contours ~ 471 Q F 472 2000 3000 4000 -0.2 -0.1 0 0.1 0.2 0 100 200 300 400 500 600 700 800 900 1000 Stress (psi) Width (vi.) Length (ft) Figure B-18. This is the inferred geometry after flush (displacement volume) at shut-in for Case 3b (2.5 BPM, 10.1 ppg slurry, 1,000 BBL, injection into the "Lower Lobe"). WESTERN ENERGY CONSULTANTS ~tre« • • Chevron North America Exploration and Production Company Page 32 Ivan River Unit 13-31 Stress V~'idth Pmtiles V~'idth Crnrtrnirs Q H 30 Figure B-19. This is the inferred geometry after flush (displacement volume) at shut-in for Case 3c (2.5 BPM, 10.1 ppg slurry, 1,000 BBL, injection in the "Middle Lobe'. ..__ Stress Width Profiles Width Contours Q J E-~ 44101 5 1 2000 3000 4000 -I ', vra~h(m) I o 0.03 ~. ___ ~_ 0.06 0.09 I 0.12 0.15 0.18 __ ._._. _....._._ 021 _ ~ ~~~ ~ 024 0.27 ;r~^.. ~ I ..._ i i I _ I - i 0 100 200 300 400 500 600 700 800 900 1000 Stress (psi) Width (vr.) Length (ft) Figure B-20. This is the inferred geometry after flush (displacement volume) at shut-in for Case 3d (2.5 BPM, 10.1 ppg slurry, 1,000 BBL, injection into the "Upper Lobe'. WESTERN ENERGY CONSULTANTS Stress (psi) Width (ui.) Length (ft) • • Chevron North America Exploration and Production Company Ivan River Unit 13-31 Stre~~ Width Profiles Page 33 Width Contours 0.24 Q H Length (ft) Figure B-21. This is the inferred geometry after flush (displacement volume) at shut-in for Case 3e (2.5 BPM, 10.1 ppg slurry, 2,500 BBL, injection into all three lobes). Stress Width Profiles Width Contours ~_ Q J H 4660 ^o 4670 ^ 20 40 ®60 80 4680 ~ 90 95 99 4690 4700 4710 4720 4730 4740 4750 4760 ~ ~ 2000 3000 4000 -0.2 -0.1 0 0.1 0.2 SU~ess (psi) Width (ui.) Length (ft) Figure B-22. This is the inferred geometry after flush (displacement volume) at shut-in for Case 3f (2.5 BPM, 10.1 ppg slurry, 2,500 BBL, injection into the "Dower Lobe'. WESTERN ENERGY CONSULTANTS Stress (psi) Width (ui.) • Chevron North America Exploration and Production Company Page 34 Ivan River Unit 13-31 Stress Width Profiles Width Contours 4 `. 7 ~~__ 4460 i, z } C ~ 4520 _. ___. 4540 4560 2000 3000 Stress (psi) Q 4500 H DO Figure B-23. This is the inferred geometry after flush (displacement volume) at shut-in for Case 3g (2.5 BPM, 10.1 ppg slurry, 2,500 BBL, injection in the ~~Middle Lobe"). „~~ Stress Width Profiles V4'idth Contours Q H Stress (psi) Figure B-24. This is the inferred geometry after flush (displacement volume) at shut-in for Case 3h (2.5 BPM, 10.1 ppg slurry, 2,500 BBL, injection into the ~~Upper Lobe'. WESTERN ENERGY CONSULTANTS Width (ui.) Length (ft) Width (ui.) Length (ft) • Chevron North America Exploration and Production Company Ivan River Unit 13-31 Stress ~_ Q ~- Width Profiles Width Contours Page 35 Figure B-25. This is the inferred geometry after flush (displacement volume) at shut-in for Case 4a (4 BPM, 10.1 ppg slurry, 1,000 BBL, injection into all three lobes). Stress Width Profiles Width Contours w_ Q J F Length (tt) Figure B-26. This is the inferred geometry after flush (displacement volume) at shut-in for Case 4b (4 BPM, 10.1 ppg slurry, 1,000 BBL, injection into the "Lower Lobe"). WESTERN ENERGY CONSULTANTS • Stress (psi) Width (ui.) Length (ft) DO -i Stress (psi) ~'Vidtli (ui.) • • Chevron North America Exploration and Production Company Page 36 Ivan River Unit 13-31 Stress o, 0.15 0.2 0.25 0.3 0.35 04 0.45 C.. Q F+ zuou 30D0 4000 2 0 100 200 300 400 500 600 700 800 900 1000 Stress (psi) ~Yidth (vi.) Length (ft) Figure B-27. This is the inferred geometry after flush (displacement volume) at shut-in for Case 4c (4 BPM, 10.1 ppg slurry, 1,000 BBL, injection in the "Middle Lobe'. ,~^~ Stress Width Profiles Width Contours Q H ~~~~ s~u~ 4000 -~ ~ -~., ~ u , u 2 ~o Stress (psi) Width (ui.) Length (ft) Figure B-28. This is the inferred geometry after flush (displacement volume) at shut-in for Case 4d (4 BPM, 10.1 ppg slurry, 1,000 BBL, injection into the "Upper Lobe"). Vi-'idth Contours WESTERN ENERGY CONSULTANTS Width Profiles • • Chevron North America Exploration and Production Company Page 37 Ivan River Unit 13-31 Stress Width Profiles Width Contours 0.28 Q J H -0.2 -0.1 0 0.1 02 0 100 200 300 400 500 600 700 800 900 1000 Stress (psi) Width (ui.) Length (ft) Figure B-29. This is the inferred geometry after flush (displacement volume) at shut-in for Case 4e (4 BPM, 10.1 ppg slurry, 2,500 BBL, injection into all three lobes). Rtress Width Profiles Width C:nntnurs ~_ Q H zooo 300o aooo -o z -a1 0 0.1 o z Stress (psi) ~Vidtli (ui.) Length (ft) Figure B-30. This is the inferred geometry after flush (displacement volume) at shut-in for Case 4f (4 BPM, 10.1 ppg slurry, 2,500 BBL, injection into the ~~Lower Lobe'7. WESTERN ENERGY CONSULTANTS s • Chevron North America Exploration and Production Company Page 38 Ivan River Unit 13-31 ..__ Stress Width Profiles Width Contours 0 H 3000 4000 Stress (psi) 3i Length (ft) JO Figure B-31. This is the inferred geometry after flush (displacement volume) at shut-in for Case 4g (4 BPM, 10.1 ppg slurry, 2,500 BBL, injection in the "Middle Lobe"). Stre~c Q H Width Protles Width Contours ~o -c Figure B-32. This is the inferred geometry after flush (displacement volume) at shut-in for Case 4h (4 BPM, 10.1 ppg slurry, 2,500 BBL, injection into the "Upper Lobe"). WESTERN ENERGY CONSULTANTS \Vidth (vi.) Width (ui.) Length (ft) Stz-ess (psi) ~ 4 • • ~~~ Chevron North America Exploration and Production ~Q ~ Q ~QQ~ Alaska pil & Gas Cons. Co-rnnissior~ A~hor Application for Disposal Injection Order Ivan River Unit Development Project Cook Inlet Basin 20 AAC 25.252 Well IRU 13-31 Union Oil Company of California 3800 Centerpoint Drive Anchorage, AK 99503 November 2008 C~~/~ ~~ (Revision~l'~ Z J U Table of Contents • Well Locations 20 AAC 25.252 (c) 1 .............................. ......... 1 Surface Owners and Operators 20 AAC 25.252 (c) 2 & 3 ....................... ......... 4 Geologic Details 20 AAC 25.252 (c) 4 .............................. ......... 5 Well Logs 20 AAC 25.252 (c) 5 .............................. ....... 12 Well Construction 20 AAC 25.252 (c) 6 .............................. ....... 13 Waste Sources, Types and Volumes 20 AAC 25.252 (c) 7 .............................. ....... 26 Injection Pressure 20 AAC 25.252 (c) 8 .............................. ....... 28 Waste Confinement 20 AAC 25.252 (c) 9 .............................. ....... 29 Formation Water Salinity and Aquifer Exemption 20 AAC 25.252 (c) 10 & 11 .......................... 35 Wells within the Area of Review 20 AAC 25.252 (c) 12 ............................ ....... 36 Mechanical Integrity of Injection Well 20 AAC 25.252 (d) & (e) ........................ ....... 39 Table of Exhibits Exhibit 1 Regional Area Map, North Cook Inlet, Alaska Exhibit 2 Unit Boundaries and Well Locations and Paths ( xhlB~l'0 7ySe LF~j - We~S 8 13-31 Exhibit 4 Ivan River Unit Cross Section ( xhlH~l'~ 6~Fi~hA$ 0 DS- 7RS8 SSeU&f~llning ZF~e ( xhlB~l't>S 61id6Fib1@ 0 DS- 7RS ,n~lFi~ ZF~e (xhIBW 61bliFir~ 0 DS- 7RS LF~veU&F~Ilning ZF~e Exhibit 8 Current IRU 13-31 Well Schematic Exhibit 9 Well IRU 13-31 State Completion Report and Directional Survey Exhibit 10 Proposed Injection Well Schematic Exhibit 11 Proposed Injection Well Schematic Contingency Exhibit 12 Injection wone With Major Sand Members Exhibit 13 Average Fracture Dimensions Exhibit 14 Forecasted Geometry after Flush at End of Injecting 1,000 bbls of 9.5 ppg Slurry at 2.5 BPM in the "Lower Lobe" Exhibit 15 Forecasted Geometry after Flush at End of Injecting 1,000 bbls of 9.5 ppg Slurry at 2.5 BPM in the "Middle Lobe" Exhibit 16 Forecasted Geometry after Flush at End of Injecting 2,500 bbls of 10.1 ppg Slurry at 2.5 BPM in the "Middle Lobe" Exhibit 17 Forecasted Geometry after Flush at End of Injecting 2,500 bbls of 10.1 ppg Slurry at 4.0 BPM in the "Middle Lobe" Exhibit 18 IRU 14-31 Well Schematic Exhibit 19 IRU 44-36 Well Schematic Appendix AW Fracture Modeling Report WeIF Locations 20 AAC 25.252 (c) 1 s The map on the following page (Exhibit 1) is a regional map showing the general location of the Ivan River Field within the Upper Cook Inlet Basin. Exhibit 2 shows the Ivan River Unit (IRU) boundaries and the well courses within the field with associated depths presented as true vertical depth subsea (TVDSS). The IRU 13-31 well surface location is 682 feet south and 699 feet east of the northwest corner of Section 1, T13N, R9W, Seward Meridian, on State of Alaska lease number ADL-032930. The'/4 mile area of review is shown at the top of the injection interval in well IRU 13-31 at a depth of 5,544 feet measured depth (MD) X4,221 feet TVDSS]. Two wells lie within the Y4 mile area of review, IRU 14-31 and IRU 44-36. Lawla River Stump L rr.n w,w ~ ~"' ..v H,Se, r.v r,r„s ..,.. ,., .w r„„a~.,, ,., v,.., r~,r, N~a.. Pretty Creak ,v ww rw ~,.w„e. .av new Ivan Rlwr "'" "~•~' Beluga River i tzr, ksv. Moquawkie Nonh Cook Inlet Grantta Point .mr„NOrth TladlnQ Bay Trading Bay r~^ ~ ~ Chevron 4 .. .~ . ~,~ Middle Ivan River Unit r Ground Swanson River "~ ShoN ® ~ .~ _.. Replonsl Arq t North Cook InIsR Nasky _ n location Map J\ 1 ~ a..~,w ,w x aaos •ea.w eYw~.~ Redoubt B r Creek Shoal ^: 0967 aa~,a~~'' FEET Exhibit 1 -Regional Area Map, North Cook Inlet, Alaska • • 2 • • Exhibit 2 -Unit Boundaries and Well Locations and Paths L J Surface Owners and Operators 20 AAC 25.252 (c12 ~ 3 The State of Alaska is the only surface owner within the Ivan River Unit and no other operators are in the development area. Therefore, no copies of the application need to be distributed and no notification affidavits are required. The State of Alaska is also the royalty owner. • Geologic Details 20 AAC 25.252 (c) 4 Deposition/Litholoav/Stratig raphv • The Ivan River Structure is a broad doubly plunging anticline. At the shallower depths that are the focus of this application, the structure is nearly flat, and is unfaulted. A thick layer of glacial outwash deposits covers the surface. These sediments were deposited by high-energy braided streams and are comprised of bedload sands and gravels, interlayered with low permeability floodplain deposits consisting of clay-rich sandy silts, and shales. The thickness of these glacial deposits is difficult to determine due to their lithologic similarity to the underlying Sterling Formation, although they appear to extend down to a depth of approximately 3,100 feet MD. The sediments of the Sterling Formation were deposited by a meander belt stream system (ea yes et. al., 1976). The resulting deposits generally include fining-upward sequences of bedload conglomerates overlain by thick quartz-rich sands which are often capped by flood plain siltstone and mudstones. Because deposition was rapid as the meanders migrated across the flood plain, the siltstones and mudstones were not completely eroded. The result of this process is extensive lateral continuity of both the coarse grained and fine grained lithologies. Coals are also common and represent the vegetative cover of abandoned meanders. The effective winnowing of the high-energy channel deposits and their relatively poor consolidation creates excellent porosity and permeability in many of the Sterling Formation sands. This formation is approximately 2,000 feet thick at the Ivan River Field. Underlying the Sterling Formation are the meander belt and braided stream deposits of the Beluga Formation. This unit is comprised of fine grained sandstones, siltstones and coals, with minor conglomerates. Due to the nature of their deposition, the sands in the Beluga are much thinner than those of the Sterling Formation and they are relatively limited in lateral extent. These sands are also relatively rich in clay which decreases their permeability. The thickness of the Beluga Formation at the Ivan River Field is approximately 2,600 feet. Underlying the Beluga Formation is the Tyonek Formation. Like the Sterling Formation, these sediments were deposited in a meander belt stream system and consist of laterally extensive sandstones, siltstones, shales and coals. The Tyonek Formation is over 4,500 feet thick at Ivan River. The location of existing wells at Ivan River Field is shown on Exhibit 2. Primary gas production is from the Tyonek Formation. The IRU 44-01 well currently produces gas from the Tyonek Formation at a vertical depth of 7,800 to 7,900 feet below sea level. Secondary gas production comes from the Lower Sterling (top at -4,848 feet TVDSS) and Beluga (top at -5,180 feet TVDSS). • A Iniection and Confining Zones As the Exhibit 3 type log and Exhibit 4 cross section illustrate, the injection is proposed in the IRU 13-31 well into very fine- to coarse-grained sandstones and conglomerates at 5,544 to 6,183 feet MD (4,221 to 4,630 feet TVDSS). The injection zone is in sandstones above the productive Lower Sterling. These sands are shown on the IRU 13-31 type log in Exhibit 3 and on the cross section presented as Exhibit 4. The injection sands are individually 80 to 120 feet, totaling 390 to 415 feet in thickness. The structure maps for the top of the injection zone and top of the confining zones are based on well data and seismic data mapping. The structure maps illustrate that the injection sands are part of a doubly plunging anticline and have no faulting or fracturing in the area of review. The 810 to 855 foot thick upper confining zone is part of the thick laterally extensive sands of the Lower n uaternary and Upper Sterling formations. The 175 to 190 foot thick lower confining zone is contained within the base of the Upper Sterling Formation. The coals and shales within the lower confining zone are laterally extensive within the area and act as a barrier for vertical migration of fluids. Structural maps of the upper confining zone, the injection zone, and the lower confining zone, with depths presented in TVDSS, are shown in Exhibits 5 through 7, respectively. Reservoir Properties The injection interval within the Lower nua ternary and Upper Sterling formations have average porosities of 25% to 33% with expected permeabilities ranging from 100 millidarcies to greater than 500 millidarcies. No core data or testing is available for these sands to verify the permeabilities. Exhibit 3 -Type Log -Well IRU 13-31 Exhibit 4 -Ivan River Unit Cross Section • • Exhibit 5 ;1863r.C :.. .... _-. :':0 JS; E:C 36tG0.; 782400 363700 ~ aRU ~3-31 ~~. ~~ ~ ~ i' ~ $ j ,~ ,- ~ ~ ,~' ~ X50 ~ o ~ ~ i1 - !~ R~J 14-31 0 ~ ~ ~ ~ ~ w t{;. s ~c,~° mac,°° tRU 44-36 '~ ~ ~' ° ~ '~ ~, ~ M {;;g { ~ ~ { IRU 41-0 ° +~ 1 °' ~~ ~ 1 ~ ~ J - ~~~~ ~ wry. i /' -342,7 ~ $ ~, i ~ ~, .. :3438 ~ ~ IRU 44-01 ' j -3,851 , ---------r___~C_-_....--_---- -_. --~-~-------1- 338000 357800 ..358400 369200 381;i1^C JSOc7:7 7o ~ECJ 0 600 ,ooo vsoo iooo 2:AOtY ToP lJpper' ConFlnin~g Zone Structure, ~_Bt t1t--"_~:-___.::::~~ --___.:._ _ ._._..-. ,'13107 ~~ ~~ '~ ~~ . r.Cfdk 0/11Rj, ~ ,~/'AaShY __ lRtf 13?i Dlspo~ We~e+t Sxrntuaa Abp ~Cantour ina i Q~Ps Scats (Tsar name T, fd7leq~K 1:t3l0? ftittk __'_ Exhibit 5 -Structure Map -Top Upper Confining Zone 9 • • Exhibit 6 366600 DbiECO ,.YfaEG _~5?f0 3cCGC0 36~?CO 387600 3 ° 82400 3Fi3300 N . IRU 13-31 ~ s` ~ ~' ~ h ~ ~ a~,o ~~ ° ~ U14-31 ~ o ~ ~ Q ~~ ~~ y ' IRU 44-~6 e o ~ ' ~ t i s~ ~ m ~ s 0 ~° IRU 41-Q ~ 5 ~ a ~_ ~ ~~' ~ ~ -4250 ; ~ i , '~ t.nza° r , i ~' ~ ~ '~ i IRU 44-01 .' ~ , _' + ~ { -427?,.' J . ~, ,-. - - p, ,~ ; . 336800 357800 35tlsr~0 3 ] c;. iSCCCC 380800 381800 __ 382400 Top Infection Zone Structure Map 383200 ~~ o soo ,ooo r ryr--- _.1~ ,soo 2000 2500n =---' ~ _ _.: _._ _ ,Nan RNe~ Unit ~I L13101 ~_,,._._ Cook lntat AK - - ~ . __.__.~ A/aska rIRU 1331 Wspasal PmJatt Exhibit 6 -Structure Map -Top Injection Zone 10 • • Exhibit 7 •. li~1.l '~ S-3'I -~~ ~' a N 1 ~ ~5: i J C7 ~ .. y R~}.'14_3'~ O ~ ~ i ~ ~ V'~' i ,N ~ ~ 1~ tRU 4~#- ~~ .A ~' ~ R~----~------ -..._ - -_ --~--- ~ ----- s a< f ~ %,~`~ Ri ~ ~ 8 $ ~~~ ~~ -0 4 f ~ ~ ~` ~ g ~ /~ ~ 11 °v ,,d63 ~; ~~ ~ ~ , -4664 ~ ~ ~ ~~~ ~, 1 '~ ~ ~%' 1fZU 44-1 f -asst; ~ , ~` ~ c~ ; ~ rs ~ 3seow ~S~cLO ~:a~oo 3_s2ec ~~ , , _ _.. _. _s .._ =_,:;c _. __ o wo fpW f~70 aaw .wat To~9 LOtAT$C ~ItI~_ZdflB_~t[[rGf[f~@ 3r Ytsr~tt--i~~i ~~ i'. f3T07 titPl ~f ~ ti9tg7 ~ h11e1A ._ ~ 1 Exhibit 7 -Structure Map -Top Lower Confining Zone 11 • ~ Well Loas 20 AAC 25.252 (c15 Well logs from the Ivan River Unit wells and adjacent exploratory holes have been provided to the Alaska Oil and Gas Conservation Commission (AOGCC). Additional copies can be provided if necessary. ~2 • • Well Construction 20 AAC 25.252 (c16 IRU 13-31 Well IRU 13-31 was directionally drilled from a surface location 682 feet from the south tine (FSL) and 699 feet from the east line (FEL) in Section 1, Township 13 North, Range 9 West, Seward Meridian to a total depth of 11,575 feet MD (8,167 feet TVD) with a bottom hole location of 1,404.84 feet east and 6,859.86 feet north of the surface location. The top of the injection interval at 5,544 feet MD (-4,221 feet NDSS) is 2,886 feet north and 262 feet west of the surface location. A schematic of the well as currently completed is shown in Exhibit 8. Original Construction: The 13 3/ surface casing was set at 866 feet MD with cement returns to the surface. A 12 '/4 hole was drilled and the 9 % casing run to 3,460 feet MD and cemented with 849 sacks. A leakoff test was run to 18.6 ppg EMW. The 7-inch casing was set at 10,350 feet MD and cemented in place with a calculated top of cement at 5,000 feet MD (-3,874 feet TVDSS). There is no bond log above 6,400 feet MD to confirm this depth. A 5-inch Liner was set at 11,575 feet MD (-8,116 feet TVDSS) with the top at 10,028 feet MD (-7,084 feet TVDSS) and cemented in place. On gune 6, 1996, the lower hole was abandoned and the 2 '/8 u 7-inch annulus was cemented to a theoretical top of 6,250 feet MD (-4,673 feet TVDSS) using a cement retainer set in the long string at 9,622 feet MD (-6,821 feet TVDSS). Exhibit 9 includes the State Completion Report with construction events detailing the casing, cementing, and tubing-packer equipment status. A directional survey is also included in Exhibit 9. The 7-inch casing is 29# N-80 with an unsupported burst pressure of 8,160 psi. The new tubing will be 3'/cinch 9.2# L-80. The unsupported burst pressure is 10,160 psi. This exceeds the maximum bottom hole injection pressure by more than 25% as required by the Alaska Administrative Code (AAC) 25.412(b). A waiver request will be submitted to allow a variance to AAC 25.412(b) to allow more than 200 feet MD between the packer and perforations. This waiver is being requested to allow thru-tubing access to the entire requested disposal zone. 13 • IRU i3J1 Ivan RMr UnH ORIGINAL RIG ELEVATIONS 3-GL 24.50' 94v13L 51.00' 186' Csq ~ - ~ ' 886' Cag a Cmt above DV 500'-2.590' DV Co1ar 2,793' MD Crt4 bekw DV 2.616'x,460' 3.480' Cag Cek TOC 5.000' MD 3.925' ND Cak TOC 6.250' MD 4,724' ND 7 420' BP 9827 Rtnr 10,028' TOL 10.350' Cag 11,575' Cag 11,575' TD A 8 C D E F G 0 Exhibit 8 -Current IRU 13-31 Well Schematic I I] 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 1,T13N,R9W.SM • i Dri11M: 192-0>b Sariagt: O.DL-06!788 1997: Plugback Oct 2000; Part Nov 2000; SL Teg Jun 2007; SL lag Jun 2008 14 • ~ Exhibit 9 -Well IRU 13-31 State Completion Report and Directional Survey State Completion Report Well Drilling History: Spudded 9/25/1992 "IRU 13-31; API 50-283-20086-00 PTD: "192-088" 9L25192V'6pud WeIIV'Grace #154 Rig, • Spud Ivan River Unit 13-31 @ 1600 hours, September 26, 1992 (Different from AOGCC) w/ 17-1/2" hF~. 9/25/92: DU~tg 6 uUDFe HF~: (20" # 166') • 20" &Fd~QaFU4~1DU,~en SUfi~Ug DUliDO • DU~G17-1/2" hF~ 11Q876' S. %Fd1 9/28/92. 9L28192V'6eunLCement Surf~Fe &Dving (20" # 166') • 5 ~h 866' 13-3/8" 68# . 55 %7& FGMg. &eP enV11aWUDFe 158 FFfJ~DG/ 67 EEUfSI~ 9/30/92: DU;~g ,n~lPeC-1UAIHRO: (20" # 166', 13-3/8" # 866') • 7 eW'FD~Ang 11Q 1, 500 SUL- 2 . . • Dll'OFdrVWC9GIWiF~ DnGRSen hR@ V'i686' - L2 7 23.5 33G (0 W • DIl.~F1~Df~ C~12-1/4" hFa@ W3467' Fdi 10/03/92. 10/04/92: 5 un/&eP enV'®-5/8" ,n1~lP eC~D~&Duing (20" # 166', 13-3/8" # 866') • 5 Gh 3,460' 9-5/8" 47# 1 80 °/7& FGMg. &eP enV1F~~GUDFe 235 EEO~DG/ 44 ~G 10/07/92: DUi~g 8-1/2" 3U~F111~t HIS: (20" # 166', 13-3/8" # 866', 9-5/8" # 3460') • 7eW'FD~Ang 1FQ 1,500 SYL- 2 . . • Dt1~diVWtE!UIVihF~ DnGRSen hR@ Vrd480' - L2 7 18.6 33G (0 W • DIl@Fi~D(iiii Q11Z8-1/2" hPo@ W11,575' 7D F~ 11/12/92. • 5G?~ FDulctg FDQSeUInUL~ 9-5/8" IU~P 0-3,236'. 6RPew[~NuS11Q2/3 RI wD®7eWW 1,800 SVL- 2 . . • 5 Dn 6~G~1g IU~P 0'-3,392'. 11/16/92: 5 un/&eP enVP" 3 U~F~ &Dving (20" # 166', 13-3/8" # 866', 9-5/8" # 3,460') • 5 Dn 10,350' 7" 29# 1 80 %7& FD1Mg. &eP enV11Q4,981' 0 D 144 ~DG/ 61 ~O • 7eW'FUMg DERVe D9 FRgDUlIQ3,000 S1~L-2. . • Pump 47 bbl cement @ 16.0 ppg thru DV collar taking returns to surface. Ran bond log IUiP 0'-2,790'. • DLVSR~k Po PuGDnGFuVtmigVV~ D9 FR®Uffdnm 7" x 9-5/8" DnnuOV(7,200 EEQ1Q161U 2,300 psi @ 3 bpm). 11/28/92:85 EetStrv 3U~Fi~ &GMg (20" # 166', 13-3/8" # 866', 9-5/8" # 3460', 7" # 10,350') • 85 hF~ Ee~v 7" ~hf~ w/ 8.25" unC~U~DPeUW11,575' 7D F~ 11/29/92. 11 /29/92: 5 un/&eP enV'ILIneU(20" # 166', 13-3/8" # 866', 9-5/8" # 3,460', 7" # 10,350') • 5Dn 1,547' S" 15# 1 80 °/d& @ieUw/ SDFf~U7RS# 10,028'. °/~ # 11,575'. 15 • • • Cement liner (no detail found). • 7 Dg 3 °/~ D # 11,444'. 5 Dn 2 B~G~V 6eVAieen 6,400'-11,447'. 5 On gyUZ~GI~Yey VGUCFe Uq 11,444'. • 7eW'ra" ~eW~.S DnGFDving, InFOCing 7" Ee~v D9 FR®UVQ2,500 S1iL- 2 . . • 5 Dn 7&3 gunVF~ 2-7/8" ~dE]ng w/ 2-1/16"x1-1/2" heD~UVlAlig. • 3 eURI.D~A17yF~eN] Fd~eV 11,208'-11,238' OnG 11,272'-11,296'. 12/15/92: 5e®CMe ~ (20" # 166', 13-3/8" # 866', 9-5/8° # 3,460', 7° # 10,350', 5" # 11,575') • 7D 11,575' 0 D, 8,167' 79 D. • 3 °/7 D 11,444' 0 D, 8,052' 79 D. Directional Survev Directional Survey: "Partial Survey above current PBTD of 7,400' MD" MD ft Inc de Azim ND ft TVDSS ft X Off ft Y Off ft DLS 0 0 0 0 51 0 0 0.00 100 1.6 202 99 -48 0 -1 1.60 150 1.6 203 149 -98 -1 -2 0.06 200 1.5 204 199 -148 -1 -3 0.21 249 1.2 206 249 -198 -2 -4 0.62 300 1.1 211 300 -249 -2 -5 0.28 350 1 213 350 -299 -3 -6 0.21 400 0.9 214 400 -349 -3 -7 0.20 449 0.8 217 449 -398 -4 -7 0.22 500 0.7 214 499 -448 -4 -8 0.21 549 0.8 215 549 -498 -4 -8 0.21 599 0.7 220 599 -548 -5 -9 0.24 650 0.7 219 649 -598 -5 -9 0.02 699 0.7 227 699 -648 -6 -10 0.20 749 0.6 228 749 -698 -6 -10 0.20 799 0.5 230 799 -748 -6 -11 0.20 849 0.5 232 849 -798 -7 -11 0.03 899 0.4 241 899 -848 -7 -11 0.24 949 0.4 296 949 -898 -7 -11 0.74 1,000 1.1 330 999 -948 -8 -11 1.57 1,049 1.7 334 1,049 -998 -8 -9 1.24 1,099 2 334 1, 099 -1, 048 -9 -8 0.60 1,149 2.5 337 1,149 -1,098 -10 -6 1.03 1,199 3.5 345 1,199 -1,148 -11 -4 2.16 1,250 4.9 350 1,249 -1,198 -11 0 2.83 1,299 6.6 353 1,299 -1,248 -12 4 3.52 1,349 8.7 354 1,348 -1,297 -13 10 4.21 1,399 10.1 355 1,398 -1,347 -13 19 2.82 1,499 14.3 352 1,495 -1,444 -16 40 4.25 1,525 15.8 351 1,520 -1,469 -16 46 5.85 1,550 17.4 351 1,544 -1,493 -17 53 6.40 1,575 19.3 352 1,567 -1,516 -18 61 7.70 1,600 20.4 352 1,591 -1,540 -19 69 4.40 1,625 21.2 353 1,614 -1,563 -20 78 3.50 1,650 21.9 354 1,637 -1,586 -21 87 3.16 1,675 22.6 354 1,661 -1,610 -22 97 2.80 1,700 22.4 354 1,684 -1,633 -23 106 0.80 16 • ~~ MD ft Inc de Azim TVD ft NDSS ft X Off ft Y Off ft DLS 1,725 22.4 353 1,707 -1,656 -24 116 1.52 1,750 22.4 353 1,730 -1,679 -25 125 0.00 1,775 22.6 353 1,753 -1,702 -27 135 0.80 1,800 22.9 353 1,776 -1,725 -28 144 1.20 1,825 23.4 353 1,799 -1,748 -29 154 2.00 1,850 24.4 353 1,822 -1,771 -30 164 4.00 1,875 25.4 353 1,845 -1,794 -31 175 4.00 1,900 26.3 353 1,867 -1,816 -32 185 3.60 1,925 27.5 354 1,889 -1,838 -33 197 5.13 1,950 28.3 354 1,912 -1,861 -34 208 3.20 1,975 29 354 1,933 -1,882 -36 220 2.80 2,000 29.2 354 1,955 -1,904 -37 232 0.80 2,025 29.8 354 1,977 -1,926 -38 245 2.40 2,050 30.4 354 1,999 -1,948 -39 257 2.40 2,075 30.7 354 2,020 -1,969 -40 270 1.20 2,100 31.1 354 2,042 -1,991 -41 282 1.60 2,125 31.9 354 2,063 -2,012 -43 295 3.20 2,150 33.4 354 2,084 -2,033 -44 309 6.00 2,175 34.9 354 2,105 -2,054 ~5 323 6.00 2,200 36.4 354 2,125 -2,074 ~7 337 6.00 2,225 37.5 353 2,145 -2,094 -48 352 5.01 2,250 38.6 353 2,165 -2,114 -50 368 4.40 2,275 40 353 2,184 -2,133 -52 383 5.60 2,300 41.2 353 2,203 -2,152 -54 400 4.80 2,325 43 352 2,222 -2,171 -56 416 7.68 2,350 43.9 352 2,240 -2,189 -58 433 3.60 2,375 44.3 352 2,258 -2,207 -60 451 1.60 2,400 44.7 352 2,276 -2,225 -62 468 1.60 2,425 45.5 352 2,293 -2,242 ~4 485 3.20 2,450 46.3 352 2,311 -2,260 -67 503 3.20 2,475 46.5 352 2,328 -2,277 -69 521 0.80 2,500 47.5 352 2,345 -2,294 -71 539 4.00 2,525 48.6 352 2,362 -2,311 -74 558 4.40 2,550 50.2 352 2,378 -2,327 -76 576 6.40 2,575 51.4 353 2,394 -2,343 -78 596 5.71 2,600 52.1 353 2,409 -2,358 -81 615 2.80 2,625 51.8 353 2,425 -2,374 -83 635 1.20 2,650 51.8 353 2,440 -2,389 -85 655 0.00 2,675 51.8 354 2,456 -2,405 -87 674 3.14 2,700 52 354 2,471 -2,420 -89 694 0.80 2,725 52.5 354 2,486 -2,435 -91 713 2.00 2,750 52.6 354 2,501 -2,450 -92 733 0.40 2,775 52.6 355 2,517 -2,466 -94 753 3.18 2,800 52.7 355 2,532 -2,481 -95 773 0.40 2,825 52.6 355 2,547 -2,496 -97 793 0.40 2,850 52.5 356 2,562 -2,511 -98 812 3.20 2,875 52.8 356 2,577 -2,526 -99 832 1.20 2,900 52.8 357 2,592 -2,541 -100 852 3.19 2,925 52.9 357 2,607 -2,556 -101 872 0.40 2,950 52.9 358 2,623 -2,572 -101 892 3.19 2,975 52.8 358 2,638 -2,587 -102 912 0.40 3,000 52.3 359 2,653 -2,602 -102 932 3.75 3,025 52 359 2,668 -2,617 -102 951 1.20 3,050 51.9 359 2,684 -2,633 -102 971 0.40 3,075 52.1 359 2,699 -2,648 -102 991 0.80 3,100 52.4 359 2,714 -2,663 -102 1,010 1.20 3,125 52.3 359 2,730 -2,679 -102 1,030 0.40 3,150 52.3 358 2,745 -2,694 -103 1,050 3.16 17 • • MD ft Inc de Azim ND ft NDSS ft X Off ft Y Off ft DLS 3,175 52 358 2,760 -2,709 -103 1,070 1.20 3,200 51.8 357 2,776 -2,725 -104 1,090 3.25 3,225 51.9 356 2,791 -2,740 -105 1,109 3.17 3,250 51.8 356 2,807 -2,756 -106 1,129 0.40 3,275 51.8 356 2,822 -2,771 -107 1,148 0.00 3,300 51.7 356 2,837 -2,786 -108 1,168 0.40 3,325 51.7 356 2,853 -2,802 -109 1,187 0.00 3,350 51.7 356 2,868 -2,817 -110 1,207 0.00 3,375 51.5 356 2,884 -2,833 -112 1,227 0.80 3,400 51.3 356 2,900 -2,849 -113 1,246 0.80 3,425 51.1 355 2,915 -2,864 -114 1,266 3.22 3,450 51 355 2,931 -2,880 -116 1,285 0.40 3,475 50.7 356 2,947 -2,896 -117 1,304 3.33 3,500 50.8 355 2,963 -2,912 -118 1,324 3.12 3,525 50.9 355 2,978 -2,927 -119 1,343 0.40 3,550 50.9 355 2,994 -2,943 -121 1,362 0.00 3,575 51.3 355 3,010 -2,959 -122 1,382 1.60 3,600 51.3 355 3,026 -2,975 -124 1,401 0.00 3,625 51.4 355 3,041 -2,990 -125 1,421 0.40 3,650 50.9 355 3,057 -3,006 -126 1,440 2.00 3,675 50.8 355 3,073 -3,022 -128 1,459 0.40 3,700 50.8 355 3,088 -3,037 -129 1,479 0.00 3,725 50.6 355 3,104 -3,053 -131 1,498 0.80 3,750 50.5 355 3,120 -3,069 -132 1,517 0.40 3,775 50.4 355 3,136 -3,085 -134 1,537 0.40 3,800 50.4 355 3,152 -3,101 -135 1,556 0.00 3,825 50.1 355 3,168 -3,117 -137 1,575 1.20 3,850 50.1 354 3,184 -3,133 -138 1,594 3.07 3,875 50.2 354 3,200 -3,149 -140 1,613 0.40 3,900 49.9 354 3,216 -3,165 -142 1,632 1.20 3,925 50 354 3,232 -3,181 -143 1,651 0.40 3,950 50.1 354 3,248 -3,197 -145 1,670 0.40 3,975 49.8 354 3,264 -3,213 -147 1,689 1.20 4,000 49.9 354 3,280 -3,229 -148 1,708 0.40 4,025 49.7 354 3,297 -3,246 -150 1,727 0.80 4,050 49.9 354 3,313 -3,262 -152 1,746 0.80 4,075 49.6 354 3,329 -3,278 -153 1,765 1.20 4,100 49.6 354 3,345 -3,294 -155 1,784 0.00 4,125 49.7 354 3,361 -3,310 -157 1,803 0.40 4,150 49.4 354 3,377 -3,326 -158 1,822 1.20 4,175 49.6 354 3,394 -3,343 -160 1,841 0.80 4,200 49.5 354 3,410 -3,359 -162 1,860 0.40 4,225 49.6 354 3,426 -3,375 -164 1,879 0.40 4,250 49.5 354 3,442 -3,391 -166 1,898 0.40 4,275 49.3 354 3,459 -3,408 -167 1,917 0.80 4,300 49.3 354 3,475 -3,424 -169 1,936 0.00 4,325 49.5 354 3,491 -3,440 -171 1,955 0.80 4,350 49.6 354 3,507 -3,456 -173 1,974 0.40 4,375 49.6 354 3,524 -3,473 -174 1,993 0.00 4,400 49.7 354 3,540 -3,489 -176 2,011 0.40 4,425 49.7 354 3,556 -3,505 -178 2,031 0.00 4,450 49.7 354 3,572 -3,521 -180 2,049 0.00 4,475 49.8 354 3,588 -3,537 -182 2,069 0.40 4,500 49.7 354 3,605 -3,554 -183 2,088 0.40 4,525 50 354 3,621 -3,570 -185 2,107 1.20 4,550 50 354 3,637 -3,586 -187 2,126 0.00 4,575 50 354 3,653 -3,602 -189 2,145 0.00 4,600 50 354 3,669 -3,618 -191 2,164 0.00 18 • ~ MD ft Inc de Azim ND ft TVDSS ft X Off ft Y Off ft DLS 4,625 50 354 3,685 -3,634 -192 2,183 0.00 4,650 50.1 354 3,701 -3,650 -194 2,202 0.40 4,675 49.9 354 3,717 -3,666 -196 2,221 0.80 4,700 50.1 354 3,733 -3,682 -198 2,240 0.80 4,725 50.1 354 3,749 -3,698 -200 2,259 0.00 4,750 50.1 354 3,765 -3,714 -201 2,278 0.00 4,775 50.1 354 3,781 -3,730 -203 2,297 0.00 4,800 50.2 354 3,797 -3,746 -205 2,316 0.40 4,825 50.3 354 3,813 -3,762 -207 2,335 0.40 4,850 50.2 354 3,829 -3,778 -209 2,355 0.40 4,875 50.3 354 3,845 -3,794 -211 2,374 0.40 4,900 50.3 354 3,861 -3,810 -212 2,393 0.00 4,925 50.3 354 3,877 -3,826 -214 2,412 0.00 4,950 50.3 354 3,893 -3,842 -216 2,431 0.00 4,975 50.3 354 3,909 -3,858 -218 2,450 0.00 5,000 50.2 354 3,925 -3,874 -220 2,469 0.40 5,025 50.2 354 3,941 -3,890 -222 2,488 0.00 5,050 50.4 354 3,957 -3,906 -224 2,508 0.80 5,075 50.5 354 3,973 -3,922 -225 2,527 0.40 5,100 50.4 354 3,989 -3,938 -227 2,546 0.40 5,125 50.4 354 4,005 -3,954 -229 2,565 0.00 5,150 50.4 354 4,021 -3,970 -231 2,584 0.00 5,175 50.5 354 4,037 -3,986 -233 2,604 0.40 5,200 50.3 354 4,053 -4,002 -235 2,623 0.80 5,225 50.4 354 4,069 -4,018 -237 2,642 0.40 5,250 50.4 354 4,084 -4,033 -239 2,661 0.00 5,275 50.4 354 4,100 -4,049 -241 2,680 0.00 5,300 50.4 353 4,116 -4,065 -243 2,699 3.08 5,325 50.4 353 4,132 -4,081 -245 2,719 0.00 5,350 50.5 353 4,148 -4,097 -247 2,738 0.40 5,375 50.3 353 4,164 -4,113 -249 2, 757 0.80 5,400 50.3 353 4,180 -4,129 -250 2,776 0.00 5,425 50.3 353 4,196 -4,145 -252 2,795 0.00 5,450 50.3 353 4,212 -4,161 -254 2,814 0.00 5,475 50.4 353 4,228 -4,177 -256 2,833 0.40 5,500 50.2 353 4,244 -4,193 -258 2,853 0.80 5,525 50.4 353 4,260 -4,209 -260 2,872 0.80 5,550 50.3 353 4,276 -4,225 -262 2,891 0.40 5,575 50.4 353 4,292 -4,241 -264 2,910 0.40 5,600 50.3 353 4,308 -4,257 -266 2,929 0.40 5,625 50.1 353 4,324 -4,273 -268 2,948 0.80 5,650 50.3 353 4,340 -4,289 -270 2,967 0.80 5,675 50.1 353 4,356 -4,305 -272 2,986 0.80 5,700 50.2 353 4,372 -4,321 -274 3,006 0.40 5,725 50.2 353 4,388 -4,337 -276 3,025 0.00 5,750 50.1 353 4,404 -4,353 -278 3,044 0.40 5,775 49.9 353 4,420 -4,369 -280 3,063 0.80 5,800 50.2 353 4,436 -4,385 -282 3,082 1.20 5,825 50.3 353 4,452 -4,401 -284 3,101 0.40 5,850 50.2 353 4,468 -4,417 -286 3,120 0.40 5,875 50.2 353 4,484 -4,433 -288 3,139 0.00 5,900 50.2 353 4,500 -4,449 -290 3,158 0.00 5,925 50.2 353 4,516 -4,465 -292 3,177 0.00 5,950 50.2 353 4,532 -4,481 -294 3,196 0.00 5,975 50 353 4,548 -4,497 -296 .3,215 0.80 6,000 50.3 353 4,564 -4,513 -299 3,235 1.20 6,025 50.3 353 4,580 -4,529 -301 3,254 0.00 6,050 50.3 353 4,596 -4,545 -303 3,273 0.00 19 • • MD ft Inc de Azim ND ft NDSS ft X Off ft Y Off ft DLS 6,075 50.2 353 4,612 -4,561 -305 3,292 0.40 6,100 50.1 353 4,628 -4,577 -307 3,311 0.40 6,125 50.3 353 4,644 -4,593 -309 3,330 0.80 6,150 50.2 353 4,660 -4,609 -311 3,349 0.40 6,175 50.1 353 4,676 -4,625 -313 3,368 0.40 6,200 50.2 353 4,692 -4,641 -315 3,387 0.40 6,225 50 353 4,708 -4,657 -317 3,406 0.80 6,250 50.2 353 4,724 -4,673 -319 3,425 0.80 6,275 50 353 4,740 -4,689 -321 3,444 0.80 6,300 50.1 353 4,756 -4,705 -323 3,464 0.40 6,325 50.1 353 4,772 -4,721 -325 3,483 0.00 6,350 50.2 353 4,788 -4,737 -327 3,502 0.40 6,375 50.1 353 4,804 -4,753 -330 3,521 0.40 6,400 50 353 4,820 -4,769 -332 3,540 0.40 6,425 50 353 4,836 -4,785 -334 3,559 0.00 6,450 49.7 353 4,852 -4,801 -336 3,578 1.20 6,475 49.8 353 4,869 -4,818 -338 3,597 0.40 6,500 49.9 353 4,885 -4,834 -340 3,616 0.40 6,525 49.8 352 4,901 -4,850 -343 3,635 3.08 6,550 50.1 352 4,917 -4,866 -345 3,654 1.20 6,575 50.2 352 4,933 -4,882 -347 3,673 0.40 6,600 50.3 352 4,949 -4,898 -350 3,692 0.40 6,625 50.3 352 4,965 -4,914 -352 3,711 0.00 6,650 50.4 352 4,981 -4,930 -354 3,730 0.40 6,675 50.2 352 4,997 -4,946 -357 3,749 0.80 6,700 50.1 352 5,013 -4,962 -359 3,768 0.40 6,725 50 352 5,029 -4,978 -361 3,787 0.40 6,750 49.8 352 5,045 -4,994 -364 3,806 0.80 6,775 50 352 5,061 -5,010 -366 3,825 0.80 6,800 50.2 352 5,077 -5,026 -368 3,844 0.80 6,825 50.4 353 5,093 -5,042 -371 3,863 3.18 6,850 50.5 353 5,109 -5,058 -373 3,882 0.40 6,875 51.1 354 5,125 -5,074 -375 3,902 3.92 6,900 51.8 355 5,140 -5,089 -377 3,921 4.20 6,925 52 356 5,156 -5,105 -378 3 941 3.25 6,950 52 357 5,171 -5,120 -379 3 960 3.15 6,975 52.1 358 5,187 -5,136 -379 3,980 3.18 7,000 52.3 359 5,202 -5,151 -379 4,000 3.26 7,025 52.2 360 5,217 -5,166 -379 4,020 3.19 7,050 51.9 0 5,233 -5,182 -379 4,039 1.20 7,075 52 1 5,248 -5,197 -379 4,059 3.1$ 7,100 52 2 5,263 -5,212 -378 4,079 3.15 7,125 52.1 2 5,279 -5,228 -377 4,098 0.40 7,150 52 3 5,294 -5,243 -376 4,118 3.18 7,175 51.8 4 5,310 -5,259 -375 4,138 3.25 20 • Recompletion Workover Program: A schematic of the proposed injection well recompletion is shown in Exhibit 10. Exhibit 11 shows a schematic of the proposed injection well recompletion contingency. Surface LocationW LongitudeW150.79636514 LatitudeV'61.240920100 682')6L&699')(L 6eF.1,7131 59W60 7 F~1CDeS1f1~ 11,575' 0 D (8,167.41' 79 D; -8,116.41' 79 D6 6 ) Bottom a ole LocationW 1,404.84 feet E; 6,859.86 feet N Top of Injection vwneW 5,544 feet MD (-4,221 feet TVDSS) 2,886 feet N, 262 feet W Wellbore azimuthal 11.57° helly bushing elevationW 51 feet above mean sea level Item and Depth Subsea ND (RKB) MD (RKB) 20" -115' 166' 166' 13-3/8" -835' 886' 866' 9-5/8" -2,887' 2,938' 3,460' 7" -7,301' 7,352' 10,350' 5" -8,118' 8,169' 11, 575' 7RS 8 SSeUB~Fd~llning Zfd~e -3,412' 3,463' 4,280' 7RS,nI~Fi~ ZF~e -4,221' 4,272' 5,544' °/dam ,nl~Fi~ ZF~e -4,630' 4,681' 6,183' 7RS LF~veU&Fdillning Zl~e -4,630' 4,681' 6,183' °/d7u~ LF3~veU&i~llning ZF~e -4,821' 4,872' 6,478' 21 • • 22 Exhibit 10 - Proposed Injection Well Schematic • • 23 Exhibit 11 -Proposed Injection Well Schematic Contingency • r Workover Procedure: PRE-RIG OPERATIONS (Surface work, E-line, Wellhead) 1. Prep location for Nabors 129 footprint. Build extension into reserve pit for rig catwalk. 2. RU E-line on IRU 13-31. 5,H DnGVeVW53 S(Dg DJV +2,000'. 3uP S O~VewCaNeU l~ SOg. 6eW °/d~Ln L6/66. (n ~(.iUeDmuOlsf hDV x,000' RI g9FF2~ (Vhf have glycol to surface). 3. CONTINGENCY: ,I °/a39 w f~'WkV'ILnL6 (EDGWtl~Q/ Sf~vL~IVQIIaanGDnGnRW repaired), set 2"d WRP plug as deep as practical in place of BPV. 4. ND Tree. Remove well house and place at Lewis River D-pad. Level location to accept rig. 5. RU E-line on IRU 44-01. 5,H DnGVeVW53 SOg DJV +2,000'. 3uP S O~VewCUVeU Fd~ SOg. 6eW °/~ln L6/66. (n WUeDmuOl~f hDV x,000' RI s9FF0 (VhG~ have glycol to surface). 6. ND Tree. Remove well house and place at Lewis River D-pad. Level location to DFFeSV1DL~IVe® 61~FL[;t~J~@VWLFNIdl36'-12". 7. RU E-line on IRU 41-01. 5,H DnGVeVW53 SOg [7111/ +2,000'. 3uP S O®VewDJVeU F~ SOg. 6eW °/~ln L6/66. (n WUeDmuOisl hDV x,000' RI g9FFt~ (Vh6t~ have glycol to surface). 8. ND Tree. Remove well house and place at Lewis River D-pad. Level location to CFFeSVIDL~IVe® [~l~NFl13~VWLFI~kd>;36"-48". RIG OPERATIONS (Rig, Slickline, E-line) 1. Skid Rig #129 over IRU 13-31 well. NU BOPs. Test to 250L~000 psi. 2. RU Slickline. Pull BPV in LSL~. Pull WRP plug. Monitor well. 3. 58 ( -Ols~ 5, H w/ WE~LnFh (1-11/16") WI,9,555'. 3unFh ~kj. 322H. 4. 38 Gi.DQ~hChgeU 3uO'®t ~®Uk )H S DFNeI~,H w/ lIDCIL®f8'IOFI~1-11/16")11i~ 5,550'. &uV 5. PU to confirm tbg cut. Lay down dual hanger, long string and heater string tbg and packer. 6. CONTINGENCY: ,I 1~g~SNU 1~'W~Imle~S, H GhGP DNe2"d cut wLradial torch DJV,~45'. 7. CONTINGENCY: , I WgISNU ~id~-'W ~I~le~ 5, H L1~GP DNe3`~ cut wLradial torch EeGtwSdTIeU)LVh UeFDLrLrg Wi6g GFdvn WIROf0~,561'. 8. 5,H w/ 5-3/4" I~eUVh6m/ dr600' wDVh~e F~ 4" D3. WDVIR~eUW6bg C~tvv~ WR FePenVV11~R16,250'. 72& LVED/eGl~ FDOF~&~ROBe. ,I nR F~enW enFR~n1~U6,wDVhW18,260' WIERriLB nRFePenWl~ri 322 H. 9. CONTINGENCY: ,I FePenVWFdanGCEF~e 6,250', C~VFuWwLWV9~vn. ,I P L(~ig UduLU~,S,H DnGP IDI:kPenV'0U6hG2D RI WuEg WI8,250'. 322H w/ P LOO 10. 5,H w/ 2 D 1~g FuV00(Ielg,H W~,800'. &uVWE~GU~RveU+/- 250' RI 1l~ 24 • 11. 5,H w/ 2 D ~g FuV00f/e19,H W19,050'. &uVWE§anGU~R~eU+/- 250' RI 1l~ 12.5,H w/ 2 D 1~g FuV00Vetg,H W(8,250'. &uVWE~GU£R~eU+/- 200' RI V~ 13. 5,H w/ 6" VFUC~JDWeFEOyw/ 6" EMiRl~~1IVB~DiN Q,50'.. ey DUem' DJe2,793' (D9 FR~ffiJpriG5,544'-6,183' (GltSRV® fie). 322H. 14. 58 (- Olen 5,H w/ 8 6,7 ®tg Lf~ IURP6,250' WF2,500'. 322 H. 15. CONTINGENCY: ,I FePenVWFdanGEe~v 5,544', C~VFuWwLWV~vn. 0 Dy P Rc~y permitted disposal interval wLAOGCC. If cement squeeze desired, set bridge plug, pert casing above TOC, set cement retainer and attempt isolation squeeze wLcement retainer. Make require multiple squeezes as needed. Drill out cement. 16.5,H w/ &P Vffie WDeURn D3. 6e W N1~eU f~,240' FdJ U' CERre WE§uW ~SW1[ Stack out 10k to confirm retainer set. 17. Stab into retainer and establish injection rate. Squeeze up to 15 bbl DED~C3~rPenW F~enV'Ee®:wUeiiD~IheU. 8rW/~riURPU~VDeUDnGOp50' (2.0 E®) on top. Circ 2 btms up above cement top. POOe. 18. 5,H w/ 6" VFUC~AWeFl=Oyw/ 6" EM~PVWR~UI~CF@enVWl9,215'. 32 2H. 19.58 (- Ols~ 5,H w/) %-1 SOFNdJ ®GW®fiLSe. 6eV'OW,~50'. 322H. 20. Set SB-1 packer plug. POOe. 21. DuP S EDIT 0' &D~&23 Rn SOg. 322H. 22.58 V~2 Uun(n venWlle6(7 FDVIng SOWFF6e W ®`VYh CFURW DI9ROD ~V X93'. Test patch to 3,000 psi. POOe. 23. Rle wL jurk mill and watermelon mill. Mill out shoe. Rle to bottom and circ out CaC03. 24. RU E-line. Pull SB-1 packer plug. 25.5,H w/ 3-1/2" HyC~JLfliD3 W6bg. 6WDVUfiu)%-1 SDFNeWe® BUe6Sffe FdaV'~G land tubing hanger. 26. RU slickline. Rle wL NTest tool. Set in uN profile. Test tubing to 5,000 psi. POOe. 27.7eW'RDVLg~(3-1/2" x 7") WR,500 S~L(21 IIFL® Q7). 5e FRU6er/ FhaJVI~IERUt3~lg1 SPIDR gauge. 28.58 ( -Ols~ 5, H w/ 20' 6 V9 2-1/4" %L~--IRO~unV. 3eUIRUC~I'8,163'-6,183' 0 D. POOe. 29. RU G8~1 to perform infectivity test on disposal zone. 30. CONTINGENCY: If injection rates are too low or injection pressures too high, plan to reperf existing or add additional perfs above. Top of injection zone Z 5,544' 0 D. %Wi4~l InMeFF~bH~ Rre 6,1 83' 0 D. 31. Lay down landing jt. Set BPV. ND BOP. NU Tree. Pull BPV. Set TWC. Test Tree. Pull TWC. 32. RU flowlines. RD and prep for pad move. 33. GGGRigove to IRU 14-31u grass roots weIIGGG 25 • • Waste Sources, Types and Volumes 20 AAC 25.252 (c) 7 Sources and Volumes of Waste Resource Conservation Recovery Act (RCRA) exempt Class II wastes will be injected in the disposal well. This will include drilling fluids and cuttings; produced water not usable IRIJ ~hL1~FeGU£f~eUyC)iGDF®W RI W~A~V 1~CJF~G"R'N~U m'VVF~IDVY.~Wa/We Other associated wastes specifically include waste materials intrinsically derived from primary field operations associated with the exploration, development, or production of FWaC~ RLCLI~G nDiOYImQjDV. ",n1aEiVIFD(~ C~lJfveG I IIRP Sl1P ~1' Ile(G RSeIID~iV' N In1bhC~G to distinguish exploration, development and production activities from transportation and manufacturing. With respect to crude oil, primary field operations include activities occurring at or near the wellhead and before the point where the oil is transferred from an individual field facility or a centrally located facility to a carrier for the transport to a refinery or a refiner. It also includes the primary, secondary and tertiary production operations. Crude oil processing, such as water separation, de-emulsifying, degassing, and storage at tank batteries associated with a specific well or wells, are examples of primary field operations. In general, the exempt status of an exploration and production waste depends on how the material was used or generated as waste, not necessarily whether the material is hazardous or toxic. A list of exempt oil and gas wastes are included in EPA publication 530-h-95-003 (May 1995). Crude Oil and Gas Exploration and Production WastesV~Exemption ftom RCRA Subtitle C Regulations. This includes but is not limited to drill cuttings, mud, produced fluids, reserve pit waste, rig wash, formation materials, completion fluids, workover fluids, stimulation fluids and solids, tracer materials, glycol dehydration wastes, naturally occurring radioactive material scale slurries, precipitation accumulating within production impoundment areas, tank bottoms, production chemicals used in wells, and other fluids brought to surface and generated in connection with oil and gas development activities. Maximum Disposal Volume by Major Category: Drill cuttings, mud, flush water 11 % (125,000 bbl) Well workover fluids and flush 9 % (100,000 bbl) Produced water and other clear exempt fluids 64 % (730,000 bbl) Reserve pit cuttings and fluids 16 % (180,000 bbl) Total Volume (20+ years) 1,135,000 bbl Injection Rate and Volume: The average daily injection rate is estimated to be 155 BPD, with excursions up to 1,000 li BPD. If the well remains active in this fashion for 20 years this would generate a cumulative disposal volume of 1,135,000 barrels. This would generate a radial plume in the injection zone of 180 H6 feet if not skewed by fracturing. 26 • • Compatibility of Fluids and Formation Towards this end log data for the wells within the field are the basis for the description included in Section (c) 4. The lithology of the injection zone is typical of local existing injection wells, being comprised of conglomeratic gravels, inert quartz and clay matrix material. The resident aquifer is typical for injection wells within the area that have operated without incident over the last 15 years and is therefore compatible with the same wastes being injected in similar storage reservoirs. 27 • Infection Pressure 20 AAC 25.252 (c18 Injection pressure is estimated to average between 1,800 to 2,800 psi while injecting either mud or slurried cuttings because the densities and other properties will be similar. This should also be a reasonable pressure to expect when injecting produced water and other clear fluids because the decrease in hydrostatic gradient relative to the mud is offset by the more mobile liquid. This pressure is probably above the fracture gradient and the flow mechanism will involve fractures in some form. A maximum pressure of 5,000 Fi psi could be reached intermittently should sporadic plugging of the perforations or gradual plugging of the fracture flow channels occur due to settling or packing of solids. 2a • ~ Waste Confinement 20 AAC 25.252 (c) 9 Injection of drilling mud and slurried cuttings will require pressures greater than the breakdown pressure of the formation. Initially a single planar vertical fracture should develop. This primary fracture can be expected to gradually plug with solids and also experience tip screen out. As the local stress regime is altered, appendages can develop creating a radial fracture system of some oblique fashion. The dimensions of the fracture domain will depend upon the amount of mudlcuttings injected and the rock properties controlling storage mechanics. The development of multiple fractures will have the effect of minimizing the lateral, and to some extent, the vertical growth of a primary fracture plane. A modeling study was undertaken to help quantify the behavior of injecting solids-slurry into the Sterling Formation. An industry available three dimensional hydraulic fracturing simulator was used to predict fracture growth during slurry injection. A prominent licensed commercial product was employed, built and maintained by Meyer and Associates, Inc. for industry use. The study was conducted by a Western Energy Services geophysical expert working at the University of Utah. Rock properties used in the model were based on well data calculated from well IRU 13-31 geophysical logs. The fracture gradient was itself then calibrated to break down data obtained from numerous other wells in the area. The fracture report of Appendix A details the model input data. The lower sand within the injection interval is planned to be utilized first with additional perforations being added above the initial perforations within the injection interval as the need arises. The main three sand members that constitute the modeled injection zone are shown on Exhibit 12. Injection of drilling and reserve pit wastes will generally be made in batches of approximately 1,000 barrels or less. The slurry will typically be 9.1 to 10.1 pounds per gallon (ppg) and is planned to be injected at a rate of 2.5 to 4.0 BPM. Exhibit 13 shows the forecasted fracture dimensions for the expected cases. Exhibit 14 shows the forecasted fracture geometry resulting from the planned injection equipment if the well was completed only in the lower sand lobe. Exhibit 15 is the result if only the middle lobe was used. Exhibit 16 and 17 show typical results under the most extreme conditions of injecting a 2,500 barrel batch of 10.1 ppg slurry at an elevated rate. Other cases are included in Appendix A. In all cases injection does not penetrate the upper confining zone or breach the lower confining shale. The worst-case fracture modeling indicates the upper confining zone will not be penetrated even if only the upper member of the injection zone is used for disposal (perforations at approximately -4,300 feet TVDSS). With plans to perforate in the lowest member at approximately -4,600 feet TVDSS, and with 200 feet of confining zone below, there is no reason to suspect either the upper or lower confining zones can be breached. This is supported by the performance of nearby injection well IRU 14-31 which has been in operation for 7 years, in a similar lithology shallower than IRU 13-31, and has successfully confined 46,500 barrels of slurry material. 29 • Monitoring for cement channeling will verify wastes are confined at IRU 13-31. nth no faulting in the area and the offset wells adequately cemented, the risk of not confining wastes and breaching the 700 foot thick upper confining zone should be insignificant. Reservoir Faulting: The geologic mapping in Exhibits 4 to 7 show there are no transmissive faults in the area. Uncemented Wellbores: Within the '/4 mile area of review there are no improperly cased or cemented wells. An overview of these wells can be found in Section (c) 12. Conclusions: Wastes are expected to be confined within the injection zone just as has been experienced by the slurry injection in nearby well IRU 14-31, in a similar formation shallower than the IRU 13-31 disposal zone. 30 • 5400 5500 5600 5700 Y 5800 D ~ 5900 a 0 6000 6100 • Shale Volume (fractional) 0.00 0.50 1.00 Vshale -~°= -Gamma -` ~a~°T Upper Lobe A~~`~ [perforations 5710-5680 ft] ..:~;. - -- -~~: ~~-:-:_ Middle Lobe _.~.~.r, [perforations 5915-5860 ft] .~=~.. '~ Lower Lobe - [perforations 6120-6160 ft] 6200 6300 6400 _- ~- _ -- - ,_ .. ___ :- =: ~ __ _ 0 20 40 60 80 Gamma Ray (GAPI) Exhibit 12. Injection Zone with Major Sand Members 5400 5500 5600 5700 5800 Y 0 5900 ~ 6000 0 6100 6200 6300 6400 31 • • 1000 bbl of Slurry 2500 bbl of Slurry Expected Casa (9.5 ppg slurry injected at 2.5 BPM) Fracture Half-Length (ft) [approximate] 327-506 482-782 Fracture Total Height (up and down) (ft) [approximate] 45-57 48-59 Fracture Width [inches, approximate] 0.13-0.24 0.14-0.26 Rate Sensitivity (9.5 ppg slurry injected at 4 BPM) Fracture Half-Length (ft) [approximate] 337-616 573-963 Fracture Total Height (up and down) (ft) [approximate] 49-62 52-62 Fracture Width [inches, approximate] 0.15-0.27 0.16-0.29 Heavy Slurry Sensitivity (10.1 Pp9 slurry injected at 2.5 BPM) Fracture Half-Length (ft) [approximate] 238-363 312-409 Fracture Total Height (up and down) (ft) [approximate] 71-78 82-100 Fracture Width [inches, approximate] 0.21-0.32 0.23-0.32 Heavy Shiny and Rate Sensitivity (10.1 ppg slurry injected at 4 BPM) Fracture Half-Length (ft) [approximate] 253-325 339-473 Fracture Total Height (up and down) (ft) [approximate] 44-88 49-98 Fracture Width [inches, approximate] 0.22-0.32 0.26-0.35 Exhibit 13. Average Fracture Dimensions (Varies According to How the Well is Completed) 32 • ~ H 451 re 457 u y ~- Stras~ ~~ iclth Pr,.~iilcs t~~iclth (r;~ntL~lrr % Lmgch~ 0 20 40 60 80 ~+i 90 ~ ~ ~ 95 Jr1, 99 111 ~1 -0 W,~ ~,~ 1 0 0 G. 004 _:.____..._....' ....................'.....__..._...._'_..._ 006 0 08 _.. O1 0 12 0.14 ._ _ 0 16 ' `=` 0.18 02 0.22 0.24 .. _... ~'._-..._ ___ 0.26 - e.. ._..._......._ ................_...........................__... L..........__..._.',.____ 15 0 700 200 300 400 500 600 700 800 900 10i lU Stress 11~i ~3i`rilfh 1-ui;~ Ler~fli ], ft;~ Exhibit 14. Forecasted Geometry after Flush at End of Injecting 1,000 bbls of 9.5 ppg Slurry at 2.5 BPM in the "Lower Lobe" :trzss ~~~izlth Pixtil~s ~~"~clth (~~nt~,tu•s ~u~ ~o 20 40 60 j 80 3000 4000 -C is -oos oos o i`. Strew i l„i:l iZ-rilfh'~ ni Lsiigfli i, it,, Exhibit 15. Forecasted Geometry after Flush at End of Injecting 1,000 bbls of 9.5 ppg Slurry at 2.5 BPM in the "Middle Lobe" 33 to I~ E-~ ~- Stress (psi) ~~'idth (ni.) Length (n) Exhibit 17. Forecasted Geometry after Flush at End of Injecting 2,500 bbls of 10.1 ppg Slurry at 4.0 BPM in the "Middle Lobe" 34 • Stress Width Profiles Leng': 0 20 i ^ 40 ®60 80 90 9~ ~ 99 f 07 -01 0 0.1 0< • «~idth Contours Stress (psi) Z`'i~fith (uL) Length (n) Exhibit 16. Forecasted Geometry after Flush at End of Injecting 2,500 bbls of 10.1 ppg Slurry at 2.5 BPM in the "Middle Lobe". fit•-•e~ti Width Profiles Width Contours • • Formation Water Salinity and Aquifer Exemption 20 AAC 25.252 (c110 8~ 11 The Alaska Oil and Gas Conservation Commission issued Aquifer Exemption Order No. 6 to Union Oil Company of California on guly 23, 2001. The order, based on formation water salinity data, exempts portions of freshwater aquifers between 2,500 feet and 3,420 feet MD and within a'/2 mile radius of well IRU 14-31 for Class II injection. The'/z mile radius was granted to allow for the possible permitting of a second disposal well near the well IRU 14-31 injection zone. On guly 15, 2008, Union Oil requested an extension of this freshwater aquifer exemption from 3,420 feet MD down to 6,195 feet MD to include the base of the proposed well IRU 13-31 injection zone, which lies well within the'/z mile radius of the injection zone in well IRU 14-31. The aquifer exemption depth extension is pending approval by the AOGCC. 35 • • Wells Within the Area of Review 20 AAC 25.252 (c) 12 The'/4 mile area of review around the top of the proposed injection zone in IRU 13-31 is shown on Exhibit 2. This perimeter encompasses two weIIsVWRU 14-31 and IRU 44-36. Both wells are cased and cemented so as to not provide a conduit for injected wastes to escape the injection wone. 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: Exhibit 18 includes the well schematic. The 10 3/4 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 injection zone. Second stage cement was placed from 3,646 feet to 625 feet TVD, thus cement is across the injection zone and both ends of the upper confining zone. This well is an active Class It disposal well that has injected 46,500 barrels to date. Well IRU 44-36: Exhibit 19 includes the well schematic. The 9 %8 inch surface casing is set at 3,449 feet MD (2,941 feet TVD). Cement was recorded at the surface; logging shows good bonding from 3,449 to 2,400 feet MD, with fair bond up to 1,600 feet MD. The 7-inch casing logging shows good bond up to 4,400 feet MD with some cement to 4,250 feet MD, the top of the logged interval. Calculations place the top of cement at 3,591 feet ND, which is across the injection zone and very near the top of the upper confining zone. This well is an active gas producer. 36 • • hr~n R~r-elr Fie~~! ~l7SP ~1 ~5 1° ~ 1~i13' Ftsr~"' 1rS~. +a" 40.E K-ab ~ 7' 119517 3X~ 'TTC ?~ Vi'i' B~s+9d v~ I~c~i~ 51~s ~ i~l~' Basil on Egtn Thai FJ~t ;3h~a ~~pUar ~ 4~i4' Ar~tu TTC ~e~+ 7~#'i' end ' (CEL N+~~ ~G~€ncl~~,~ ~ , a2fi .$ 29~ 1d~$ii ~q18' 900 73x1; ~ ire" ;llnar ~ 311~,~D~' ~~' 6, I~ es.ilt Tui Ba)aer ~-F~ Faker art €3' 'F' IPrc~iie ~xt ' X2.312 l Baker lA1L F~eentry i~s~~e a# 2~2' C~men# inner g3 ~' M Ph~g ~' - ~8' 65~' - ~ ,~z'titt~il ~X Fish ~1 BMA Tca~a1 Leng#h 2213' Prat~blp ran Br~tttam et #p;Q54' Fish X06' of ~ 71A" D~P. T~ ~ ~' Sa#tor~ ~ 1~7{7~' Fish #S 1N+,1~. ~ssy ~ [7.1;,'~ l~en~h ' Yvp ~~' 8cm ~' Fish ~# 2876' 2-21;3" T13G 3 321N9' 31.J2" D.i:', 7'op ~ ~5~ 0' Sc~tlc3rn ~ 1~i86' 1ernarrt Plug 7~13d '1}827' ~s~mer>r Plug 11;1,~Y -1{~,35tY Gamen# Plug 11?5a1,3' - 117,x' Exhibit 18: IRU 14-31 Well Schematic 37 lY 9' • Chevron • Ivan Ricer R-ell d#-36 Actual Completion 9:1'_~U1 F: et G': IRL" 44-~6 R'BD J-1-0I c.x.da< \O. De tb ID JER ELRY DETAIL OD Item } Ihtal Tubirs Hvtger. 2-?:8'~ t 2-3 C" 4'etco Chat' 1:'" Ss{ 3.060 2.313 3500 Sliding Sleeve, Baker. C'hID. ?-?S-' Bntt -, 3.106 :.441 3 9S0 Packer. Bakes FH Rririerable 4 6.374- 2.313 3.500 Slidtua Sleeve. Baker.. CsiD. ?-- ~ ~ Butt 3 6.314 ? 347 5.9?0 Packer.. Baker SC-_ Itzt C}iin ID throush S-'] Snap Latch Szal Asst. 6 6.537' 2.313 3.?50 Slidme Sleets. Baker. CsiD. 3-?~' Butt 7 b.??3' ?.347 5 9?0 Packer.. Baker SC-? Rtt. stint ID ilubugh S-" Suap Latcht S 6J9b' 2:313 3J50 Stidms. Sleeve. Baker. C'\.fD._-. 8~ Btttt 9 7.05?' 2.313 3300 \ipple. k. 2313" ID, '-?R'~ Butt 10 ?.096' _'.347 3.810 Packer. Baker SC-t Rzt. slnt ID through 5-" Snap Latcht 11 7.111' 4.480 5 300 sieshnte sand ureeu asst'. _' jts at 33 each 1'_ 7?32 ~ 2.34 7 5 6?3 Packer. Baker ~Ioit- D. (situ ID through S-37 Sttap~ Latch i 13 7.690' 2.313 3300 \ipplz. X. '.31s~ ID. ' ? $` Butt 14 7.?24' 2.441 3 250 R'irehne Evtr;~ Cxtide Heater Striug A 2.980 _-. o ~ 4.6=. N-50 Butt 1ltbiug urth slulr Shit CASING ~i\D 1-L-BL~G DETAIL SIZE ~1T GRADE COQ'? ID 7OP BT\L gyp- - 93 i3-3 8" 68 k-35 Butness Srufa<e 908' 9-5 8'" 47 N-SO Buttress Surface 3.449 ?" 29 ti-80 Btuness 6.18.4 Surfa~t 7.?89' _'9 P-I10 Butmss 6.184 7.?89~ 8,308' Tabuaq ' 2-7.8" 64 L-80 Bun SC _'.4-11 23.05 ?.J.4 -38" 4.6 L-80 Bun SC 1.993 '3.03' 2.980' PERFOILaiIO~ HISTURI- tnca _ ccam ate ne tin Amt s omtneuts 3'93 55-4 6.4?1' 6.44i~ 9" IS .~ftcl itaitl _ ? 9; 59-6 6.`S" 6. i68' I I' IS ~ fzd 9 4 iU ?.93 ?1-3 b.236' 6.55'. 16' IS efzi194O1 9 ~ OI ?4-S % t 1 T ?.150' 1. slzsluite Screen 9 4 01 ?5-? ' l63' ?-15.1' 21' I? \}rsluite Screen ~i 4 i~l S:-- ' 'ti0' - L'" 6 EiD = 8.272'. TD = 8,308' ~Iai Hole.],ogle = 48 deg ;a 4,225' DR4«'~ BI': tcb RED-ISED: 4^_~'Ol Exhibit 19: IRU 44-36 Well Schematic 38 • • Mechanical Intearity of infection Well 20 AAC 25.252 (dl ~ (e) Ivan River 13-31 Mechanical Integrity Once the tubing is pulled, and the existing perforations are isolated, a patch will be run CFl11ZW fhb ®CNng D9 FR(iIIiUln 1fNe 7" FL7~Mg Dd~,793 Iee1M D. The SDJ6h G1~G 7-InFh casing will be pressure tested to 3,000 psi and the 7-inch by 9 5/ inch annulus pressure tested to 1,500 psi to ensure mechanical integrity of the well bore prior to perforating the injection zone. Formation Testing and Integrity Initial formation testing will involve apump-in step rate test up to a planned 6 BPM, if equipment is available for this rate, followed by a pressure fall off to obtain a base line formation pressure. A channel log or temperature log will be run after the well is injecting to confirm waste confinement. Subsequent testing, monitoring, and reporting will conform to the AOGCC requirements for slurry disposal wells. 39 Page 1 of 3 • Colombie, Jody J (DOA) From: Regg, James B (DOA) Sent: Monday, November 03, 2008 5:37 PM To: Colombie, Jody J (DOA) Subject: FW: Ivan River Unit Aquifer Exemption Extension -Additional Information Needed Attachments: DIO Permit App_IRU 13-31_rev1.pdf Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 907-793-1236 From; Sullivan, Sharon T [mailto:SullivanS@chevron.com] Sent: Monday, November 03, 2008 5:34 PM To: Regg, James B (DOA) Subject: RE: Ivan River Unit Aquifer Exemption Extension -Additional Information Needed Hi Jim, I have attached a revised IRU 13-31 DIO application that provides the following in accordance with your e-mail below: . Clarifies the depth information throughout the document per Item #2 of your a-mail, Changes the formation name from Beluga to Sterling in Exhibits 10 and 11 as identified in Item #4 of your request, and Provides the additional information you requested in Item #1 below in the Waste Confinement section of the attached revised application. Please note that I have also changed our address on the title page since we have recently located to a new building in mid-town The following answers are in response to items #3, #5, and #6 in your e-mail below: 3.) The TOC of 6250' is cement inside the 2-7/8" x 7" annulus. The PBTD of 7400' is cement inside the 2-7l8" tubing. There is fill inside the tubing down to 5561', covering perforations at 6882-6905 and 7322-7335. These perforations could be accessed with a cleanout run, but we've made the determination that a cleanout run w/ coil tubing could lead to sticking the coil tubing due to the restriction at 2996' from a permanent tubing patch. Therefore, a PBTD of 7400' should be appropriate. 5.) and 6.) The references to 5600' MD are assuming that the proposed USIT log that will be performed during the proposed workover finds that the cement top behind the 7" casing is not at 5000' MD (calculated value) but at 5600' MD. Therefore, remedial cementing would be required. Please note that we are working on the information request that Steve Davies submitted and hope to have our responses to you later this week. However, I wanted to provide you with the information you requested beforehand in the event it might advance the approval process. If you have any questions or require additional information regarding this submittal, please let me know. Once you receive all the information and deem it to be satisfactory, I will send you final hardcopy versions. Thank you! 11 /4/2008 Page 2 of 3 Sharon 'T. Sullivan Planning & Permitting Specialist, HES Group Chevron North America Exploration and Production Company MidContinent/Alaska Business Unit 3800 Centerpoint Drive, Anchorage, AK 99503 Office 907.263,7839 Cell 907.830.1821. lax 866.801.5194 Email SullivanS@Chevron.com From: Regg, James B (DOA) [mailto:jim.regg@alaska.gov] Sent: Monday, October 20, 2008 5:44 PM To: Sullivan, Sharon T Subject: FW: Ivan River Unit Aquifer Exemption Extension -Additional Information Needed Listed below are questions/requests posed by our Sr. Geologist that are needed before we can complete the amendment to AEO 6. These are equally important for us to complete the DIO application for IRU 13-31. In addition to the questions/requests for the AEO 6 amendment, please address the following specific to IRU 13-31: 1) there needs to be a more detailed discussion of the upper confinement and why Chevron believes it will confine the injected fluid stream; 2} there is a mix of depths used throughout the application (MD and TVD); the datum (MD, TVD, TVDss} is not referenced on several of the exhibits (e.g., Exhibits 2,5,6,7) -please clarify; 3} Exhibit 8 indicates a top of cement (TOC) at 6250 ft that appers to represent the well's plug back depth; header for the well schematic references plug back depth (PBTD) as 7400 feet -please clarify; 4) Exhibits 10 and 11 show proposed injection perfs as Beluga formation; the remainder of the application references proposed disposal injection perfs in the Sterling formation -please clarify; 5) Exhibit 11 indicates TOC for 7" csg is 5600 feet; other well schematics for IRU 13-31 show it at 5000 feet -please clarify 6) Exhibit 11 indicates a USIT was used to establish TOC in IRU 13-31-only bond log information in Commission files are sepia copies of segmented bond logs for portions of 7" (surface to 2800 ft) and 9-5/8" casing (1470 to 3400 ft); provide USIT log data Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 907-793-1236 sulliyans~chevroncom From: Davies, Stephen F (DOA) Sent: Monday, October 20, 2008 10:13 AM To: Regg, James B (DOA) Cc: Roby, David S (DOA); Maunder, Thomas E (DOA) Subject: Ivan River Unit Aquifer Exemption Extension -Additional Information Needed Jim, Since you are coordinating this AEO extension, I thought it best to relay these questions and requests for the operator through you. The structure at the level of the proposed injection zone in Ivan River Unit 13-31 is relatively flat, the stratigraphy is not complicated, there are several nearby wells, and mud logs from those wells suggest that gas may be present within the downward. expansion of the aquifer exempted by Aquifer Exemption Order No. 6. In order to ensure that water-quality standards are met and 11 /4/2008 Page 3 of 3 that natural gas resources will not be wasted, additional information is needed. Formation temperature calculations Please discuss derivation of the temperature gradient from surface through the proposed injection interval, incorporating maximum temperature readings recorded in wells 41-01, 44-36, 14-31 and 13-31. Is any additional temperature information available? If so, please provide copies to the Commission. Lithology Please provide a detailed lithologic description of the proposed injection zone and the proposed expanded exemption zone. How do the lithologic components affect gamma ray, SP, sonic, density and neutron measurements throughout the expanded exemption zone? For log analysis purposes, would the sand beds within the proposed injection zone be considered clean or shaly? Please explain. Are additional data, such as core or sidewall core descriptions available? If so, please provide copies to the Commission. Porosity Please describe techniques used to calculate porosities provided in the application to expand the aquifer exemption. Justify their use over other techniques in this instance. Mud logs from nearby wells 44-01, 41-01 and 44-36 suggest that methane gas is present throughout the proposed expanded aquifer exemption interval. Please explain and demonstrate how wireline porosity measurements were corrected to compensate for any affect of any gas present. Were shale corrections utilized in your calculations? If so, please describe the techniques and demonstrate their validity. Total Dissolved Solids Since the stratigraphy is relatively uncomplicated and there are several closely spaced wells, TDS calculations within a given interval in well 13-31 should be replicated in stratigraphically equivalent beds logged in nearby wells 44-36 and 14-31. Please provide confirming TDS calculations in representative beds for well 13-31 and these nearby wells. Were environmental corrections made to any of the well log measurements? If so, describe what was done and. demonstrate validity of the corrections. Were any waters recovered from any of the Ivan River Unit wells analyzed for TDS content? If so, please provide copies to the Commission. Natural Gas Content Please explain why the proposed injection activities will not result in waste of natural gas resources. Provide water saturation analyses and test or production information from representative sand beds within the proposed expanded exemption zone demonstrating whether or not commercial quantities of gas are present. Explain and justify the choice of technique(s) and critical parameters such as Rw. Please describe and demonstrate how these parameters were obtained. Thanks, Steve Davies Sr. Petroleum Geologist Alaska Oil and Gas Conservation Commission Telephone: (907) 793-1224 Fax: (907) 276-7542 New Email Address: steve.davies@alaska.gov I 1 /4/2008 ~3 . ~ Page 1 of 2 Colombie, Jody J (DOA) From: Regg, James B (DOA) Sent: Monday, October 20, 2008 5:46 PM To: Davies, Stephen F (DOA); Maunder, Thomas E (DOA) Cc: Colombie, Jody J (DOA) Subject: FW: Ivan River Unit Aquifer Exemption Extension -Additional Information Needed Called Sharon Sullivan ealier today and left msg that this info request was forthcoming. I also advised that we are vacating tomorrow's hearing. Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 907-793-1236 From: Regg, James B (DOA) Sent: Monday, October 20, 2008 5:44 PM To: 'sullivans@chevron.com' Subject: FW: Ivan River Unit Aquifer Exemption Extension -Additional Information Needed Listed below are questions/requests posed by our Sr. Geologist that are needed before we can complete the amendment to AEO 6. These are equally important for us to complete the DIO application for IRU 13-31. In addition to the questions/requests for the AEO 6 amendment, please address the following specific to IRU 13-31: 1) there needs to be a more detailed discussion of the upper confinement and why Chevron believes it will confine the injected fluid stream; 2) there is a mix of depths used throughout the application (MD and TVD); the datum (MD, TVD, TVDss) is not referenced on several of the exhibits (e.g., Exhibits 2,5,6,7) -please clarify; 3) Exhibit 8 indicates a top of cement (TOC) at 6250 ft that appers to represent the well's plug back depth; header for the well schematic references plug back depth (PBTD) as 7400 feet -please clarify; 4) Exhibits 10 and 11 show proposed injection perfs as Beluga formation; the remainder of the application references proposed disposal injection perfs in the Sterling formation -please clarify; 5) Exhibit 11 indicates TOC for 7" csg is 5600 feet; other well schematics for IRU 13-31 show it at 5000 feet -please clarify 6) Exhibit 11 indicates a USIT was used to establish TOC in IRU 13-31-only bond log information in Commission fifes are sepia copies of segmented bond logs for portions of 7" (surface to 2800 ft) and 9-5/8" casing (1470 to 3400 ft); provide USIT log data Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 907-793-1236 sullivans@chevron.com. From: Davies, Stephen F (DOA) Sent: Monday, October 20, 2008 10:13 AM To: Regg, James B (DOA) Cc: Roby, David S (DOA); Maunder, Thomas E (DOA) Subject: Ivan River Unit Aquifer Exemption Extension -Additional Information Needed 10/22!2008 Page 2 of 2 Jim, Since you are coordinating this AEO extension, I thought it best to relay these questions and requests for the operator through you. The structure at the level of the proposed injection zone in Ivan River Unit 13-31 is relatively flat, the stratigraphy is not complicated, there are several nearby wells, and mud logs from those wells suggest that gas may be present within the downward expansion of the aquifer exempted by Aquifer Exemption Order No. 6. In order to ensure that water-quality standards are met and that natural gas resources will not be wasted, additional information is needed. Formation temperature calculations Please discuss derivation of the temperature gradient from surface through the proposed injection interval, incorporating maximum temperature readings recorded in wells 41-O1, 44-36, 14-31 and 13-31. Is any additional temperature information available? If so, please provide copies to the Commission. Lithology Please provide a detailed lithologic description of the proposed injection zone and the proposed expanded exemption zone. How do the lithologic components affect gamma ray, SP, sonic, density and neutron measurements throughout the expanded exemption zone? For log analysis purposes, would the sand beds within the proposed injection zone be considered clean or shaly? Please explain. Are additional data, such as core or sidewall core descriptions available? If so, please provide copies to the Commission. Porosity Please describe techniques used to calculate porosities provided in the application to expand the aquifer exemption. Justify their use over other techniques in this instance. Mud logs from nearby wells 44-01, 41-01 and 44-36 suggest that methane gas is present throughout the proposed expanded aquifer exemption interval. Please explain and demonstrate how wireline porosity measurements were corrected to compensate for any affect of any gas present. Were shale corrections utilized in your calculations? If so, please describe the techniques and demonstrate their validity. Total Dissolved Solids Since the stratigraphy is relatively uncomplicated and there are several closely spaced wells, TDS calculations within a given interval in well 13-31 should be replicated in stratigraphically equivalent beds logged in nearby wells 44-36 and 14-31. Please provide confirming TDS calculations in representative beds for well 13-31 and these nearby wells. Were environmental corrections made to any of the well log measurements? If so, describe what was done and demonstrate validity of the corrections. Were any waters recovered from any of the Ivan River Unit wells analyzed for TDS content? If so, please provide copies to the Commission. Natural Gas Content Please explain why the proposed injection activities will not result in waste of natural gas resources. Provide water saturation analyses and test or production information from representative sand beds within the proposed expanded exemption zone demonstrating whether or not commercial quantities of gas are present. Explain and justify the choice of technique(s) and critical parameters such as Rw. Please describe and demonstrate how these parameters were obtained. Thanks, Steve Davies Sr. Petroleum Geologist Alaska Oil and Gas Conservation Commission Telephone: (907) 793-1224 Fax: (907) 276-7542 New Email Address: stevedavics~c~,alaska,.g_oy. 10/22/2008 LiVA STATE OF ALASKA NOTICE TO PUBLISHER ADVERTISING ORDER NO. ADVERTISING ORDER INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE A O_02914008 f1 SEE BOTTOM FOR INVOICE ADDRESS F R AOGCC 333 W 7th Ave, Ste 100 ~ AGENCY CONTACT Jod Colombie DATE OF A.O. Se tember 9 2008 ° M Anchorage, AK 99501 907-793-1238 PHONE - PcN DATES ADVERTISEMENT REQUIRED: o Anchorage Daily News PO Box 149001 Anchora e AK 99514 g ~ September 11, 2008 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Advertisement to be published was e-mailed Type of Advertisement Legal® ^ Display Classif ied ^Other (Specify) SEE ATTACHED SEND INVOICE IN TRIPLICATE TO AOGCC, 333 W. 7th Ave., Suite 100 Anchora e AK 99501 PAGE 1 OF 2 PAGES TOTAL OF ALL PAGES$ REF TYPE NUMBER AMOUNT DATE COMMENTS 1 VEN ~ A1~ 02910 FIN AMOUNT SY CC PGM LC ACCT FY NMR DIST LIO ~ 08 02140100 73451 2 REQ ISITIO ED B DIVISION APPROVAL: 02-902 (Re4) `~ Publisher/Original Copies: Department Fiscal, Department, Receiving AO.FRM • • Notice of Public Hearing State of Alaska Alaska Oil and Gas Conservation Commission Re: Request for Disposal Injection Order for Ivan River Unit Well 13-31, located within Section 1, T13N, R9W, Seward Meridian, Westside Cook Inlet, Alaska Union Oil Company of California (UNOCAL), by letter dated and received September 8, 2008 has applied for a disposal injection order in accordance with 20 AAC 25.252. An order would authorize disposal of Class II drilling and production wastes into the Sterling formation using existing Ivan River Unit (IRU) Well 13-31. The proposed disposal injection is located within Section 1, T13N, R9W, Seward Meridian. The receiving zone for this well is proposed at an approximate depth range of 4221 to 4630 feet true vertical depth subsea. Unocal's application may be reviewed at the offices of the Commission, 333 West 7th Avenue, Suite 100, Anchorage, Alaska, or a copy may be obtained by phoning the Commission at (907) 793-1221. The Commission has tentatively scheduled a public hearing on this application for October 21, 2008 at 1:30 pm at the offices of the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. A person may request that the tentatively scheduled hearing be held by filing a written request with the Commission no later than 4:30 pm on September 25, 2008. 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 public hearing, please call 793-1221 after October 1, 2008. In addition, a person may submit a written protest or written comments regarding this application and proposal to the Alaska Oil and Gas Conservation Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. Protests and comments must be received no later than 4:30 pm on October 13, 2008, except that if the Commission decides to hold a public hearing, protests or comments must be received no later than the conclusion of the October 21, 2008, hearing. If you are a person with a disability who may need special accommodations in order to comment or to attend the public hearing, please contact the Commission's Special Assistant Jody Colombie at 793-12 Cathy . Foerster Comm ssioner Anchorage Daily News ~i~~~~ols Affidavit of Publication 1001 Northway Drive, Anchorage, AK 99508 PRICE OTHER OTHER OTHER OTHER OTHER GRAND AD# DATE PO ACCOUNT PER DAY CHARGES CHARGES#2 CHARGES#3 CHARGES#4 CHARGES#5 TOTAL 549279 09/11/2008 02914008 STOF0330 $222.44 $222.44 $0.00 $0.00 $0.00 $0.00 $0.00 $222.44 t .. . STATE OF ALASKA THIRD JUDICIAL DISTRICT Shane Drew, being first duly sworn on oath deposes and says that he is an advertising representative of the Anchorage Daily News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and during all said time was printed in an office maintained at the aforesaid place of publication of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and not in supplemental form) of said newspaper on the above dates and that such newspaper was regularly distributed to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged private individuals. r - _ Signed ~ ~/~'w`A- - ~'~~.~1'~ Subscribed and sworn to me before this date: ~/r~/~~' Notary Public in and for the State of Alaska. Third Division. Anchorage, Alaska MY COMMISSION EXPIRES: ~ ~ /v' ~ ~A((r ~ r ~. ® ... JJ~f~~/~~l* Ill}1>1~,, 1)) ~~ Notice of Public Hearing. Stateof Alaska Alaska 031 and Gas Consetvation Commission Re: RequestfOr DiSposallnjection Order for Ivan River Unit Well 'i3-31, located within Section 1, T13N, R9W,`Seward Meridian, westside Cook Inlet, Alaska Union Oil. Companyof California (UNOCAIJ, by letter dated and receivedSeptember 8, 2008 has applied for a disposal injection order in accoedance with 20 AAC 25:252. An order would authorize disposal of Class 11 drilling and production wastes into the Sterling formation using ezistmg Ivan River Unit (IRU) Well 13-31: The .proposed disposal injection is IOCate(1 withinSectiOn 1,.713N, R9W,.Seward Meridian. The receiving zone for. thig well is proposed stab approximate depth range ot4221 to 460 feet true vertical depth subsea. Unocal's application mayy be reviewed at the offices of the CommisSlon, 333 West 73h Avenue,-Suite 100, AnchorsSe, Alaska, ors. copy may be obtained by :phoning the Commission at (907) 793-1221. The Commission has tentatively scheduled a public. hearing on this application for October 21, 2008 at 1:30 pm, afthe offices of the Alaske Oif and Gas COnServati0n Commission at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. A persore may reqquest that the tentatively. scheduled hearing be fleltl byflling a written request with the. commission no later than a:30 pm on September 25, tops. If a request fora hearing is-not timely filed, fhe Commission may consider the issuance of ah order without a hearing. 70 learn if the'Commissionwill hold the public hearing, please call 793-1221 after October 1, 2008> In addition, a person may submit a written protest or written comments regarding this application arrd proposal to the Alaska oil and Gas Conservation Commission at 333 West ZthAvenue, Suite 100, Anchorage, Alaska 99501, Protests and comments must be received no later than 4:30 pm on October .13, 2008, except that if the Commission'decides to hold a public hearing, protests or comments must. be received. no later than:the conclusion of the October 21, 2008, hearing. If you are a person with a disability who may need special accommodations in order to comment or to attend the public hearing, please contact the Commission s Speciafassistant Jody Colombie at 793-1221 Cathy P. Foerster Comn~ioiler AD-02914008 Published: September 11, 20QS • .~ ADVERTISING INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED /~ 0_02914008 AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF F1 ORDER gDVERTISEMENT MUST BE SUBMITTED WITH INVOICE SEE BOTTOM FOR INVOICE ADDRESS F ADGCC AGENCY CONTACT DATE OF A.O. R Suite 100 333 West 7th Avenue ° . Anchcra~e. AK 99501 PHONE PCN M 907-793-1238 - DATES ADVERTISEMENT REQUIRED: o Anchorage Daily News September 11 2008 , PO Box 149001 Anchora e AK 99514 g THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN ~ . SPECIAL INSTRUCTIONS: Account # STOF0330 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 2008, and thereafter for consecutive days, the last publication appearing on the day of , 2008, 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 2008, Notary public for state of My commission expires • • Mary Jones David McCaleb Cindi Walker XTO Energy, Inc. IHS Energy Group Tesoro Refining and Marketing Co. Cartography GEPS Supply & Distribution 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 300 Concord Plaza Drive Ft. Worth, TX 76102-6298 Houston, TX 77056 San Antonio, TX 78216 George Vaught, Jr. Jerry Hodgden Richard Neahring PO Box 13557 Hodgden Oil Company NRG Associates Denver, CO 80201-3557 408 18th Street President Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 John Levorsen Mark Wedman Baker Oil Tools 200 North 3rd Street, #1202 Halliburton 4730 Business Park Blvd., #44 Boise, ID 83702 6900 Arctic Blvd. Anchorage, AK 99503 Anchorage, AK 99502 Schlumberger Ciri Ivan Gillian Drilling and Measurements Land Department 9649 Musket Bell Cr.#5 2525 Gambell Street #400 PO Box 93330 Anchorage, AK 99507 Anchorage, AK 99503 Anchorage, AK 99503 Jill Schneider Gordon Severson Jack Hakkila US Geological Survey 3201 Westmar Cr. PO Box 190083 4200 University Dr. Anchorage, AK 99508-4336 Anchorage, AK 99519 Anchorage, AK 99508 Darwin Waldsmith James Gibbs Kenai National Wildlife Refuge PO Box 39309 PO Box 1597 Refuge Manager Ninilchick, AK 99639 Soldotna, AK 99669 PO Box 2139 Soldotna, AK 99669-2139 Penny Vadla Richard Wagner Cliff Burglin 399 West Riverview Avenue PO Box 60868 PO Box 70131 Soldotna, AK 99669-7714 Fairbanks, AK 99706 Fairbanks, AK 99707 Bernie Karl North Slope Borough Williams Thomas K&K Recycling Inc. PO Box 69 Arctic Slope Regional Corporation PO Box 58055 Barrow, AK 99723 Land Department Fairbanks, AK 99711 PO Box 129 Barrow, AK 99723 ~% i ~~~ y//Z/!J c~ Page 1 of 1 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Tuesday, September 09, 2008 2:51 PM Subject: Public Notice Ivan River Unit Well 13-31 Attachments: Ivan River 13-31 Public Notice.pdf BCC:'Dale Hoffman'; Fridiric Grenier; Joseph Longo; 'Lamont Frazer'; 'Mary Aschoff; Maurizio Grandi; P Bates; 'Scott Nash'; Tom Gennings; 'Willem Vollenbrock'; 'William Van Dyke'; 'Aleutians East Borough'; 'Anna Raff; Arion, Teri A (DNR); 'Arthur Copoulos'; 'Barbara F Fullmer'; 'bbritch'; 'Bill Walker'; 'Brad McKim'; 'Brandon Gagnon'; 'Brian Gillespie'; 'Brian Havelock'; 'Brit Lively'; 'Bruce Webb'; 'buonoje'; 'Cammy Taylor'; 'Cande.Brandow'; 'carol smyth'; 'Cary Carrigan'; caunderwood@marathonoil.com; 'Charles O'Donnell'; 'Chris Gay'; 'Christian Gou-Leonhardt'; 'Cliff Posey'; 'Dan Bross'; 'dapa'; 'Daryl J. Kleppin'; 'David Brown'; 'David Hall'; David House; 'David L Boelens'; 'David Steingreaber'; 'ddonkel'; 'Deborah J. Jones'; 'doug_schultze'; 'Eric Lidji '; 'Evan Harness'; 'eyancy'; 'foms2@mtaonline.net'; 'Francis S. Sommer'; 'Fred Steece'; 'Garland Robinson'; 'Gary Laughlin'; 'Gary Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil'; Gould, Greg M (DEC); 'Gregg Nady'; 'gregory micallef ; 'gspfoff ; 'Hank Alford'; 'Harry Engel'; 'jah'; 'James Scherr'; 'Janet D. Platt'; 'jejones'; 'Jerry McCutcheon'; 'Jim Arlington'; 'Jim White'; 'Jim Winegarner'; 'Joe Nicks'; 'John Garing'; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'John W Katz'; johnny.aiken@north-slope.org; 'Jon Goltz'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; knelson@petroleumnews.com; 'Krissell Crandall'; 'Kristin Dirks'; 'Laura Silliphant'; 'Lois'; 'Lynnda Kahn'; 'mail=akpratts@acsalaska.net'; 'mail=fours@mtaonline.net'; 'Marilyn Crockett'; 'Mark Dalton'; 'Mark Hanley'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marguerite kremer'; 'marty'r 'Matt Rader'; 'Meghan Powell'; Melanie Brown; 'Mike Bill'; 'Mike Mason'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'Nick W. Glover'; NSK Problem Well Supv; NSU, ADW Well Integrity Engineer; 'Patty Alfaro'; 'Paul Decker'; 'Paul Winslow'; Pierce, Sandra M (DNR); 'Randall Kanady'; 'Randy L. Skillern'; 'rcrotty'; Rice, Cody J (DNR); 'rmclean'; 'Rob McWhorter'; rob.g.dragnich@exxonmobil.com; 'Robert Campbell'; 'Robert Fowler'; 'Robert Province'; 'Roger Belman'; 'Rudy Brueggeman'; 'Scott Cranswick'; 'Shannon Donnelly'; 'Sharmaine Copeland'; 'Sondra Stewman'; 'Sonja Frankllin'; 'Stan Porhola'; 'stanekj'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'tablerk'; 'Tamera Sheffield'; 'Temple Davidson'; 'Terrie Hubble'; 'Tim Lawlor'; 'Todd Durkee'; Tony Hopfinger; 'trmjrl'; 'Walter Featherly'; 'Walter Quay'; 'Wayne Rancier'; Birnbaum, Alan J (LAW); Crisp, John H (DOA); Davies, Stephen F (DOA); Fleckenstein, Robert J (DOA); Foerster, Catherine P (DOA); Grimaldi, Louis R (DOA); Johnson, Elaine M (DOA); Jones, Jeffery B (DOA); Laasch, Linda K (DOA); Mahnken, Christine R (DOA); Maunder, Thomas E (DOA); McIver, C (DOA); McMains, Stephen E (DOA); Noble, Robert C (DOA); Norman, John K (DOA); Okland, Howard D (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Saltmarsh, Arthur C (DOA); Scheve, Charles M (DOA); Seamount, Dan T (DOA); Smith, Chasity R (DOA); Williamson, Mary J (DOA) Attachments:Ivan River 13-31 Public Notice.pdf; Jody J. Colombie Special Assistant to the Commission Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 (907) 793-1221 Direct Line (907) 276-7542 Fax 9/9/2008 *' 1 Chevron Sharon T. Sullivan HES Planning and Chevron North America Exploration and Production Permitting Specialist P.O. Box 196247 MidContinent/Alaska SBU Anchorage, AK 99519-6247 Tel 907 263 7839 Fax 907 263 7901 Cell 907 830 1821 Email SullivanS@Chevron.com September 8, 2008 Daniel T. Seamount, Jr., Commissioner Alaska Oil and Gas Conservation Commission ~; ~ ~ p $ 2008 333 West 7th Avenue; Suite 100 Anchorage, Alaska 99501 ,~~~~ ~ Chi! ~~ ~~ns• C~mr~i~sio~ Anchr~r~e Re: APPLICATION FOR DISPOSAL INJECTION ORDER IVAN RIVER UNIT WELL 13-31, SECTION 1, T13N, R9W, S.M. WEST SIDE COOK INLET, ALASKA Dear Commissioner Seamount: Union Oil Company of California, (a wholly owned indirect subsidiary of Chevron Corporation), in accordance with 20 AAC 25.252, is hereby enclosing an application requesting the Commission to authorize the underground disposal of oil field wastes suitable for disposal in a Class II well, as defined in 40 CFR 144.6(b) as revised as of July 1, 1998. Exempt wastes would be injected in the interval between 5,544 and 6,183 feet MD (4,221 to 4,630 feet TVD). This application is in conjunction with my letter of July 15, 2008 requesting a depth extension to the existing Aquifer Exemption Order No. 6. It is anticipated that drilling mud, slurried drill cuttings, and other exempt wastes would be injected during a three well rig program on the West Side of Cook Inlet beginning November 2008. Subsequently, small amounts of produced water associated with production of natural gas would be disposed. Injection pressures will be above the fracture gradient. While fractures will develop, it has been shown that they will be minor in nature. Numerous confining intervals exist between the injection zone and the fresh water sands that lie above 2,500 feet MD (2,350 feet TVD). Injected wastes should not penetrate the confining sand member at 4,300 feet MD (3,430 feet TVD). Please let me know if you need any additional information. Thank you for your assistance with this project. Sincerely, Sharon T. Sullivan Planning/Permitting Specialist Enclosure: Two (2) Class II Disposal Injection Order Applications -Ivan River Well 13-31 • M ~~p Q $ 2008 ev ro n Chevron North America Exploration and Production Alas~~ ~~6 ~ Cyr ~:r~;~~,y ~;~;~~~ssior ~rtc~~: ~~,~ Application for Disposal Injection Order Ivan River Unit Development Project Cook Inlet Basin 20 AAC 25.252 Well IRU 13-31 Union Oil Company of California 909 West 9t" Avenue Anchorage, AK 99501 September 2008 • Table of Contents C_I Well Locations 20 AAC 25.252 (c) 1 ........... ............................1 Surface Owners and Operators 20 AAC 25.252 (c) 2 & 3 ..... ............................4 Geologic Details 20 AAC 25.252 (c) 4 ........... ............................5 Well Logs 20 AAC 25.252 (c) 5 ........... ..........................12 Well Construction 20 AAC 25.252 (c) 6 ........... ..........................13 Waste Sources, Types and Volumes 20 AAC 25.252 (c) 7 ........... ..........................26 Injection Pressure 20 AAC 25.252 (c) 8 ........... ..........................28 Waste Confinement 20 AAC 25.252 (c) 9 ........... ..........................29 Formation Water Salinity and Aquifer Exemption 20 AAC 25.252 (c) 10 & 11 . .......................... 35 Wells within the Area of Review 20 AAC 25.252 (c) 12 ......... .......................... 36 Mechanical Integrity of Injection Well 20 AAC 25.252 (d) & (e) ..... ..........................39 Table of Exhibits Exhibit 1 Regional Area Map, North Cook Inlet, Alaska Exhibit 2 Unit Boundaries and Well Locations and Paths Exhibit 3 Type Log -Well IRU 13-31 Exhibit 4 Ivan River Unit Cross Section Exhibit 5 Structure Map -Top Upper Confining Zone Exhibit 6 Structure Map -Top Injection Zone Exhibit 7 Structure Map -Top Lower Confining Zone Exhibit 8 Current IRU 13-31 Well Schematic Exhibit 9 Well IRU 13-31 State Completion Report and Directional Survey Exhibit 10 Proposed Injection Well Schematic Exhibit 11 Proposed Injection Well Schematic Contingency Exhibit 12 Injection Zone With Major Sand Members Exhibit 13 Average Fracture Dimensions Exhibit 14 Forecasted Geometry after Flush at End of Injecting 1,000 bbls of 9.5 ppg Slurry at 2.5 BPM in the "Lower Lobe" Exhibit 15 Forecasted Geometry after Flush at End of Injecting 1,000 bbls of 9.5 ppg Slurry at 2.5 BPM in the "Middle Lobe" Exhibit 16 Forecasted Geometry after Flush at End of Injecting 2,500 bbls of 10.1 ppg Slurry at 2.5 BPM in the "Middle Lobe" Exhibit 17 Forecasted Geometry after Flush at End of Injecting 2,500 bbls of 10.1 ppg Slurry at 4.0 BPM in the "Middle Lobe" Exhibit 18 IRU 14-31 Well Schematic Exhibit 19 IRU 44-36 Well Schematic Appendix A: Fracture Modeling Report • • Well Locations 20 AAC 25.252 (c) 1 The map on the following page (Exhibit 1) is a regional map showing the general location of the Ivan River Field within the Upper Cook Inlet Basin. Exhibit 2 shows the Ivan River Unit (IRU) boundaries and the well courses within the field. The IRU 13-31 well surface location is 682 feet south and 699 feet east of the northwest corner of Section 1, T13N, R9W, Seward Meridian, on State of Alaska lease number ADL-032930. The %4 mile area of review is shown at the top of the injection interval in well IRU 13-31 at a depth of 5,544 feet measured depth (-4,221 feet SSTVD). Two wells lie within the %4 mile area of review, IRU 14-31 and IRU 44-36. Lewis River Pretty Crwk ~ nu1 Rsw nw ww T1Ul RMJ Nl ROW nJx Rwv TtJR M1W nlN R10W nN1 Rrw Tt~p R10W T1Y10.1~W T141 Rtny T1JN R12W Ivan River T13N 8010 BeWge Rives Rsw Moquawkie North Cook Inlet TtOR R0W q - Granite Point T10R R6W North Trading Bay I Trading Bay ~~ ~ Chevron Mideie Ivan River Unit ~. ur Ground Swanson River Shoal Tai RbW Regional Area NoRh Cook Inlet, Alaska nR RSw Location Map RMrO July f, 2008 AMwv aucwun RedouM Beaver Creek Shoal o =_ _39.967 FEET Exhibit 1 -Regional Area Map, North Cook Inlet, Alaska 2 • • I I I I I ~ J ~ T13N R9W T14N R9W Section 36 I Section 31 I I I`~AN RIVER UNIT 13-31 1/4 mile radius around I I I top Of proposed injection zone in IRU 13-31 I IVAN RIVER UNIT 14-31 I IVAN RIVER UNIT 44- I ~~~ ~~ ~~~~ ~~~~~~~ IVAN RIVER UNIT 4 - 1 b635 I 243 I ,721 I I ~ ~l5 ~~ Section 1 Section 6 I ,267 I I Wells within the 1/4 mile i~ I radius of the injection I zone in IRU 13-31 I IVAN RIV I UNIT ~01 I -493 ,4,696 I ~ T 14 T13N R9W I _ I ~ Chevron I ~ ~/ Ivan River Unit ~~ •~~. Unit Area I S lion 12 Section 7 and Well Paths I I Revised July 2, 2008 N RIVER IT 23-12 073 Utllt I:SOUfldf'y FEET Exhibit 2 -Unit Boundaries and Well Locations and Paths 3 • • Surface Owners and Operators 20 AAC 25.252 (c) 2 & 3 The State of Alaska is the only surface owner within the Ivan River Unit and no other operators are in the development area. Therefore, no copies of the application need to be distributed and no notification affidavits are required. The State of Alaska is also the royalty owner. 4 • • Geologic Details 20 AAC 25.252 (c) 4 DepositionlLitholopv/Stratigraphy The Ivan River Structure is a broad doubly plunging anticline. At the shallower depths that are the focus of this application, the structure is nearly flat, and is unfaulted. A thick layer of glacial outwash deposits covers the surface. These sediments were deposited by high-energy braided streams and are comprised of bedload sands and gravels, interlayered with low permeability floodplain deposits consisting of clay-rich sandy silts, and shales. The thickness of these glacial deposits is difficult to determine due to their lithologic similarity to the underlying Sterling Formation, although they appear to extend down to a depth of approximately 3,100 feet. The sediments of the Sterling Formation were deposited by a meander belt stream system (Hayes et. al., 1976). The resulting deposits generally include fining-upward sequences of bedload conglomerates overlain by thick quartz-rich sands which are often capped by flood plain siltstone and mudstones. Because deposition was rapid as the meanders migrated across the flood plain, the siltstones and mudstones were not completely eroded. The result of this process is extensive lateral continuity of both the coarse grained and fine grained lithologies. Coals are also common and represent the vegetative cover of abandoned meanders. The effective winnowing of the high-energy channel deposits and their relatively poor consolidation creates excellent porosity and permeability in many of the Sterling Formation sands. This formation is approximately 2,000 feet thick at the Ivan River Field. Underlying the Sterling Formation are the meander belt and braided stream deposits of the Beluga Formation. This unit is comprised of fine grained sandstones, siltstones and coals, with minor conglomerates. Due to the nature of their deposition, the sands in the Beluga are much thinner than those of the Sterling Formation and they are relatively limited in lateral extent. These sands are also relatively rich in clay which decreases their permeability. The thickness of the Beluga Formation at the Ivan River Field is approximately 2,600 feet. Underlying the Beluga Formation is the Tyonek Formation. Like the Sterling Formation, these sediments were deposited in a meander belt stream system and consist of laterally extensive sandstones, siltstones, shales and coals. The Tyonek Formation is over 4,500 feet thick at Ivan River. The location of existing wells at Ivan River Field is shown on Exhibit 2. Primary gas production is from the Tyonek Formation. The IRU 44-01 well currently produces gas from the Tyonek Formation at a vertical depth of 7,800 to 7,900 feet below sea level. Secondary gas production comes from the Lower Sterling (top at -4,848 feet) and Beluga (top at -5,180 feet). • • Iniection and Confining Zones As the Exhibit 3 type log and Exhibit 4 cross section illustrate, the injection is proposed in the IRU 13-31 well into very fine- to coarse-grained sandstones and conglomerates at 5,544 to 6,183 feet MD (4,221 to 4,630 feet SSTVD). The injection zone is in sandstones above the productive Lower Sterling. These sands are shown on the IRU 13-31 type log in Exhibit 3 and on the cross section presented as Exhibit 4. The injection sands are individually 80 to 120 feet, totaling 390 to 415 feet in thickness. The structure maps for the top of the injection zone and top of the confining zones are based on well data and seismic data mapping. The structure maps illustrate that the injection sands are part of a doubly plunging anticline and have no faulting or fracturing in the area of review. The 810 to 855 foot thick upper confining zone is part of the thick laterally extensive sands of the Lower Quaternary and Upper Sterling formations. The 175 to 190 foot thick lower confining zone is contained within the base of the Upper Sterling Formation. The coals and shales within the lower confining zone are laterally extensive within the area and act as a barrier for vertical migration of fluids. Structural maps of the upper confining zone, the injection zone, and the lower confining zone are shown in Exhibits 5 through 7, respectively. Reservoir Properties The injection interval within the Lower Quaternary and Upper Sterling formations have average porosities of 25% to 33% with expected permeabilities ranging from 100 millidarcies to greater than 500 millidarcies. No core data or testing is available for these sands to verify the permeabilities. • • Exhibit 5 381800 382400 383200 N NN O O O NpU O Np~ Np8 a N 1 o~ O xO 0 O O O P NpJ O N~ W O Exhibit 5 -Structure Map -Top Upper Confining Zone 9 ~ soo +ooo +soo 2000 2saort To U er C_Onfining Zone_Structure 3f0 ta3+o~ Ivan Rlve- Unlt Cook IMs4 AK AJaeke - IRI/ 13-310lsposal Project - --- - • • Exhibit 6 S ~_ 0 N tl~p oN O 0 500 1600 1300 2000 23008 V r--rF- i~~,~~ 1:13107 362400 363200 O O ~' ~ ~ I Exhibit 6 -Structure Map -Top Injection Zone 10 • Exhibit 7 365400 359200 360000 3E 1.l li ..i~~....~~,..~..., .I,. / IRU 13 ~ , / ~ I\~ '/ j \ S ~ IRU 41-0 ~ ~~ \\ ~` ~lI o v o, 'i _.~l65p - ~~/ a ~ ' ~ ~~ A I IRU 4~-01 g ~--------------------~ -- --~~ - -4660 1~ • -J , 358800 357!00 358400 359200 360000 380801 0 500 ,ooo ,Soo `~ iTop Lower Confining Zone Structure rj ,:,3,0~ Exhibit 7 -Structure Map -Top Lower Confining Zone N O ONi 0 P O A N O 11 .] Well Logs 20 AAC 25.252 Ic) 5 • Well logs from the Ivan River Unit wells and adjacent exploratory holes have been provided to the Alaska Oil and Gas Conservation Commission (AOGCC). Additional copies can be provided if necessary. 12 • • Well Construction 20 AAC 25.252 (c) 6 IRU 13-31 Well IRU 13-31 was directionally drilled from a surface location 682 feet from the south line (FSL) and 699 feet from the east line (FEL) in Section 1, Township 13 North, Range 9 West, Seward Meridian to a total depth of 11,575 feet MD (8,167 feet TVD) with a bottom hole location of 1,404.84 feet east and 6,859.86 feet north of the surface location. The top of the injection interval at 5,544 feet MD (-4,221 feet SSTVD) is 2,886 feet north and 262 feet west of the surface location. A schematic of the well as currently completed is shown in Exhibit 8 Original Construction: The 13 3/ surface casing was set at 866 feet with cement returns to the surface. A 12 %4 hole was drilled and the 9 5/ casing run to 3,460 feet and cemented with 849 sacks. A leakoff test was run to 18.6 ppg EMW. The 7-inch casing was set at 10,350 feet and cemented in place with a calculated top of cement at 5,000 feet MD (-3,874 feet SSTVD). There is no bond log above 6,400 to confirm this depth. A 5-inch liner was set at 11,575 feet MD (-8,116 feet SSTVD) with the top at 10,028 feet MD (-7,084 feet SSTVD) and cemented in place. On June 6, 1996, the lower hole was abandoned and the 2 '/8 X 7-inch annulus was cemented to a theoretical top of 6,250 feet MD (-4,673 feet SSTVD) using a cement retainer set in the long string at 9,622 feet MD (-6,821 feet SSTVD). Exhibit 9 includes the State Completion Report with construction events detailing the casing, cementing, and tubing-packer equipment status. A directional survey is also included in Exhibit 9. The 7-inch casing is 29# N-80 with an unsupported burst pressure of 8,160 psi. The new tubing will be 3'/2-inch 9.2# L-80. The unsupported burst pressure is 10,160 psi. This exceeds the maximum bottom hole injection pressure by more than 25% as required by the Alaska Administrative Code (AAC) 25.412(b). A waiver request will be submitted to allow a variance to AAC 25.412(b) to allow more than 200 feet measured depth between the packer and perforations. This waiver is being requested to allow thru-tubing access to the entire requested disposal zone. 13 • • C h c~vrc~ n I Nan River Unil I I~: N"a ~"a: ~ 878„ i,T 13N,R9W,SM 24.50' ~ ~I(B-MSL 51.00' r 166' Csg 866' Csg Cmt above DV 500'-2,590' DV Cdlaf 2,793' MD Cmt below DV 2,816'-3,460' 3,460' Csg Calc TOC 5,000' MD 3,925' ND talc roc 6,250' MD 4,724' ND 7 420' BP 9,627 Rlnr 10,028' TOL 10,350' Csg 11,575' Csg 11,575' TD BHP: 5.2 5,085' TVD 1997, Plugback Od 2000; PeA Nov 2000; SL Tag Jun 2007; SL o.f. ~~„ .a, ~ ~, ~~~ Tag Jun 2008 O Liner 9^ 4^ Tubin Heat strip a s^ 1 z-7i6^ BPv 2 T'HOwco'1 3 Owen Tubir 4 Baker CMU 5 7" Baker Fi 6 Baker mode 7 Punch hole 8 Tagged fill ~ 9 Britl a PIu 10 Cement Re 11 Punch hole 12 TIW Seal a 13 Punch hole 14 Baker mods 15 Baker TCP A C A~ B C~ C D 0-0 E F •~~ G ._ E~ 10 Exhibit 8 -Current IRU 13-31 Well Schematic 14 ORIGINAL RIG ELEVATIONS i i Exhibit 9 -Well IRU 13-31 State Completion Report and Directional Survey State Completion Report Well Drilling History: Spudded 9/25/1992 "IRU 13-31; API 50-283-20086-00 PTD: "192-088" 9/25/92: Spud Well: Grace #154 Rig, • Spud Ivan River Unit 13-31 @ 1600 hours, September 26, 1992 (Dififerent from AOGCC) w/ 17-1/2" hole. 9/25/92: Drilling Surface Hole: (20" @ 166') • 20" Conductor Driven prior to rig arrival • Drilled 17-1/2" hole to 876' RKB on 9/28/92. 9/28/92: Run/Cement Surface Casing (20" @ 166') • Ran 866' 13-3/8" 68# K55 BTC casing. Cement to surface 158 bbl lead / 67 bbl tail. 9/30/92: Drilling Intermediate Hole: (20" @ 166', 13-3/8" @ 866') • Test casing to 1,500 psi - OK. • Drill out float shoe and open hole t/886' -LOT 23.5 PPG EMW • Directionally drill 12-1/4" hole t/ 3467' on 10/03/92. 10/04/92: Run/Cement 9-5/8" Intermediate Casing (20" @ 166', 13-3/8" @ 866') • Ran 3,460' 9-5/8" 47# N80 BTC casing. Cement to surface 235 bbl lead / 44 bbl tail. 10/07/92: Drilling 8-1/2" Production Hole: (20" @ 166', 13-3/8" @ 866', 9-5/8" @ 3460') • Test casing to 1,500 psi - OK. • Drill out float shoe and open hole t/3480' -LOT 18.6 PPG EMW • Directionally drill 8-1/2" hole t/ 11,575' TD on 11/12/92. • Ran casing caliper inside 9-5/8" from 0-3,236'. Some wall loss up to 2/3 of wall. Test to 1,800 psi - OK. • Ran bond log from 0'-3,392'. 11/16/92: Run/Cement 7" Production Casing (20" @ 166', 13-3/8" @ 866', 9-5/8" @ 3,460') • Ran 10,350' 7" 29# N80 BTC casing. Cement to 4,981' MD 144 bbl lead / 61 bbl tail. • Test casing above DV collar to 3,000 psi - OK. • Pump 47 bbl cement @ 16.0 ppg thru DV collar taking returns to surface. Ran bond log from 0'-2,790'. • Dispose of mud and cuttings thru DV collar down 7" x 9-5/8" annulus (7,200 bbl total, 2,300 psi @ 3 bpm). 11/28/92: UR below Production Casing (20" @ 166', 13-3/8" @ 866', 9-5/8" @ 3460', 7" @ 10,350') • UR hole below 7" shoe w/ 8.25" underreamer t/ 11,575' TD on 11/29/92. 11/29/92: Run/Cement Liner (20" @ 166', 13-3/8" @ 866', 9-5/8" @ 3,460', 7" @ 10,350') • Ran 1,547' S" 15# N80 BTC liner w/ packer. Top @ 10,028'. Bottom @ 11,575'. 15 • • • Cement liner (no detail found). • Tag PBTD @ 11,444'. Ran 2 bond logs between 6,400'-11,447'. Ran gyro survey surface to 11,444'. • Test 5" liner top and casing, including 7" below DV collar to 2,500 psi - OK. • Ran TCP guns on 2-7/8" tubing w/ 2-1/16"x1-1/2" heater string. • Perforate Tyonek zones 11,208'-11,238' and 11,272'-11,296'. 12/15/92: Release rig (20" @ 166', 13-3/8" @ 866', 9-5/8" @ 3,460', 7" @ 10,350', 5" @ 11,575') • TD = 11,575' MD, 8,167' TVD. • PBTD = 11,444' MD, 8,052' TVD. Directional Survey Directional Survey: "Partial Survey above current PBTD of 7,400' MD" MD ft Inc de Azim TVD ft SSTVD ft X Off ft Y Off ft DLS 0 0 0 0 51 0 0 0.00 100 1.6 202 99 -48 0 -1 1.60 150 1.6 203 149 -98 -1 -2 0.06 200 1.5 204 199 -148 -1 -3 0.21 249 1.2 206 249 -198 -2 -4 0.62 300 1.1 211 300 -249 -2 -5 0.28 350 1 213 350 -299 -3 -6 0.21 400 0.9 214 400 -349 -3 -7 0.20 449 0.8 217 449 -398 -4 -7 0.22 500 0.7 214 499 -448 -4 -8 0.21 549 0.8 215 549 -498 -4 -8 0.21 599 0.7 220 599 -548 -5 -9 0.24 650 0.7 219 649 -598 -5 -9 0.02 699 0.7 227 699 -648 -6 -10 0.20 749 0.6 228 749 -698 -6 -10 0.20 799 0.5 230 799 -748 -6 -11 0.20 849 0.5 232 849 -798 -7 -11 0.03 899 0.4 241 899 -848 -7 -11 0.24 949 0.4 296 949 -898 -7 -11 0.74 1,000 1.1 330 999 -948 -8 -11 1.57 1,049 1.7 334 1,049 -998 -8 -9 1.24 1,099 2 334 1,099 -1,048 -9 -8 0.60 1,149 2.5 337 1,149 -1,098 -10 -6 1.03 1,199 3.5 345 1,199 -1,148 -11 -4 2.16 1,250 4.9 350 1,249 -1,198 -11 0 2.83 1,299 6.6 353 1,299 -1,248 -12 4 3.52 1,349 8.7 354 1,348 -1,297 -13 10 4.21 1,399 10.1 355 1,398 -1,347 -13 19 2.82 1,499 14.3 352 1,495 -1,444 -16 40 4.25 1,525 15.8 351 1,520 -1,469 -16 46 5.85 1,550 17.4 351 1,544 -1,493 -17 53 6.40 1,575 19.3 352 1,567 -1,516 -18 61 7.70 1,600 20.4 352 1,591 -1,540 -19 69 4.40 1,625 21.2 353 1,614 -1,563 -20 78 3.50 1,650 21.9 354 1,637 -1,586 -21 87 3.16 1,675 22.6 354 1,661 -1,610 -22 97 2.80 1,700 22.4 354 1,684 -1,633 -23 106 0.80 16 • • MD ft Inc de Azim TVD ft SSTVD ft X Off ft Y Off ft DLS 1,725 22.4 353 1,707 -1,656 -24 116 1.52 1,750 22.4 353 1,730 -1,679 -25 125 0.00 1,775 22.6 353 1,753 -1,702 -27 135 0.80 1,800 22.9 353 1,776 -1,725 -28 144 1.20 1,825 23.4 353 1,799 -1,748 -29 154 2.00 1,850 24.4 353 1,822 -1,771 -30 164 4.00 1,875 25.4 353 1,845 -1,794 -31 175 4.00 1,900 26.3 353 1,867 -1,816 -32 185 3.60 1,925 27.5 354 1,889 -1,838 -33 197 5.13 1,950 28.3 354 1,912 -1,861 -34 208 3.20 1,975 29 354 1,933 -1,882 -36 220 2.80 2,000 29.2 354 1,955 -1,904 -37 232 0.80 2,025 29.8 354 1,977 -1,926 -38 245 2.40 2,050 30.4 354 1,999 -1,948 -39 257 2.40 2,075 30.7 354 2,020 -1,969 -40 270 1.20 2,100 31.1 354 2,042 -1,991 -41 282 1.60 2,125 31.9 354 2,063 -2,012 -43 295 3.20 2,150 33.4 354 2,084 -2,033 -44 309 6.00 2,175 34.9 354 2,105 -2,054 -45 323 6.00 2,200 36.4 354 2,125 -2,074 -47 337 6.00 2,225 37.5 353 2,145 -2,094 -48 352 5.01 2,250 38.6 353 2,165 -2,114 -50 368 4.40 2,275 40 353 2,184 -2,133 -52 383 5.60 2,300 41.2 353 2,203 -2,152 -54 400 4.80 2,325 43 352 2,222 -2,171 -56 416 7.68 2,350 43.9 352 2,240 -2,189 -58 433 3.60 2,375 44.3 352 2,258 -2,207 -60 451 1.60 2,400 44.7 352 2,276 -2,225 -62 468 1.60 2,425 45.5 352 2,293 -2,242 -64 485 3.20 2,450 46.3 352 2,311 -2,260 -67 503 3.20 2,475 46.5 352 2,328 -2,277 -69 521 0.80 2,500 47.5 352 2,345 -2,294 -71 539 4.00 2,525 48.6 352 2,362 -2,311 -74 558 4.40 2,550 50.2 352 2,378 -2,327 -76 576 6.40 2,575 51.4 353 2,394 -2,343 -78 596 5.71 2,600 52.1 353 2,409 -2,358 -81 615 2.80 2,625 51.8 353 2,425 -2,374 -83 635 1.20 2,650 51.8 353 2,440 -2,389 -85 655 0.00 2,675 51.8 354 2,456 -2,405 -87 674 3.14 2,700 52 354 2,471 -2,420 -89 694 0.80 2,725 52.5 354 2,486 -2,435 -91 713 2.00 2,750 52.6 354 2,501 -2,450 -92 733 0.40 2 775 52.6 355 2,517 -2,466 -94 753 3.18 2,800 52.7 355 2,532 -2,481 -95 773 0.40 2,825 52.6 355 2,547 -2,496 -97 793 0.40 2,850 52.5 356 2,562 -2,511 -98 812 3.20 2,875 52.8 356 2,577 -2,526 -99 832 1.20 2,900 52.8 357 2,592 -2,541 -100 852 3.19 2,925 52.9 357 2,607 -2,556 -101 872 0.40 2,950 52.9 358 2,623 -2,572 -101 892 3.19 2,975 52.8 358 2,638 -2,587 -102 912 0.40 3,000 52.3 359 2,653 -2,602 -102 932 3.75 3,025 52 359 2,668 -2,617 -102 951 1.20 3,050 51.9 359 2,684 -2,633 -102 971 0.40 3,075 52.1 359 2,699 -2,648 -102 991 0.80 3,100 52.4 359 2,714 -2,663 -102 1,010 1.20 3,125 52.3 359 2,730 -2,679 -102 1,030 0.40 3,150 52.3 358 2,745 -2,694 -103 1,050 3.16 17 • • MD ft Inc de Azim TVD ft SSTVD ft X Off ft Y Off ft DLS 3,175 52 358 2,760 -2,709 -103 1,070 1.20 3,200 51.8 357 2,776 -2,725 -104 1,090 3.25 3,225 51.9 356 2,791 -2,740 -105 1,109 3.17 3,250 51.8 356 2,807 -2,756 -106 1,129 0.40 3,275 51.8 356 2,822 -2,771 -107 1,148 0.00 3,300 51.7 356 2,837 -2,786 -108 1,168 0.40 3,325 51.7 356 2,853 -2,802 -109 1,187 0.00 3,350 51.7 356 2,868 -2,817 -110 1,207 0.00 3,375 51.5 356 2,884 -2,833 -112 1,227 0.80 3,400 51.3 356 2,900 -2,849 -113 1,246 0.80 3,425 51.1 355 2,915 -2,864 -114 1,266 3.22 3,450 51 355 2,931 -2,880 -116 1,285 0.40 3,475 50.7 356 2,947 -2,896 -117 1,304 3.33 3,500 50.8 355 2,963 -2,912 -118 1,324 3.12 3,525 50.9 355 2,978 -2,927 -119 1,343 0.40 3,550 50.9 355 2,994 -2,943 -121 1,362 0.00 3,575 51.3 355 3,010 -2,959 -122 1,382 1.60 3,600 51.3 355 3,026 -2,975 -124 1,401 0.00 3,625 51.4 355 3,041 -2,990 -125 1,421 0.40 3,650 50.9 355 3,057 -3,006 -126 1,440 2.00 3,675 50.8 355 3,073 -3,022 -128 1,459 0.40 3,700 50.8 355 3,088 -3,037 -129 1,479 0.00 3,725 50.6 355 3,104 -3,053 -131 1,498 0.80 3,750 50.5 355 3,120 -3,069 -132 1,517 0.40 3,775 50.4 355 3,136 -3,085 -134 1,537 0.40 3,800 50.4 355 3,152 -3,101 -135 1,556 0.00 3,825 50.1 355 3,168 -3,117 -137 1,575 1.20 3,850 50.1 354 3,184 -3,133 -138 1,594 3.07 3,875 50.2 354 3,200 -3,149 -140 1,613 0.40 3,900 49.9 354 3,216 -3,165 -142 1,632 1.20 3,925 50 354 3,232 -3,181 -143 1,651 0.40 3,950 50.1 354 3,248 -3,197 -145 1,670 0.40 3,975 49.8 354 3,264 -3,213 -147 1,689 1.20 4,000 49.9 354 3,280 -3,229 -148 1,708 0.40 4,025 49.7 354 3,297 -3,246 -150 1,727 0.80 4,050 49.9 354 3,313 -3,262 -152 1,746 0.80 4,075 49.6 354 3,329 -3,278 -153 1,765 1.20 4,100 49.6 354 3,345 -3,294 -155 1,784 0.00 4,125 49.7 354 3,361 -3,310 -157 1,803 0.40 4,150 49.4 354 3,377 -3,326 -158 1,822 1.20 4,175 49.6 354 3,394 -3,343 -160 1,841 0.80 4,200 49.5 354 3,410 -3,359 -162 1,860 0.40 4,225 49.6 354 3,426 -3,375 -164 1,879 0.40 4,250 49.5 354 3,442 -3,391 -166 1,898 0.40 4,275 49.3 354 3,459 -3,408 -167 1,917 0.80 4,300 49.3 354 3,475 -3,424 -169 1,936 0.00 4,325 49.5 354 3,491 -3,440 -171 1,955 0.80 4,350 49.6 354 3,507 -3,456 -173 1,974 0.40 4,375 49.6 354 3,524 -3,473 -174 1.,993 0.00 4,400 49.7 354 3,540 -3,489 -176 2,011 0.40 4,425 49.7 354 3,556 -3,505 -178 2,031 0.00 4,450 49.7 354 3,572 -3,521 -180 2,049 0.00 4,475 49.8 354 3,588 -3,537 -182 2,069 0.40 4,500 49.7 354 3,605 -3,554 -183 2,088 0.40 4,525 50 354 3,621 -3,570 -185 2,107 1.20 4,550 50 354 3,637 -3,586 -187 2,126 0.00 4,575 50 354 3,653 -3,602 -189 2,145 0.00 4,600 50 354 3,669 -3,618 -191 2,164 0.00 18 • • MD ft Inc de Azim TVD ft SSTVD ft X Off ft Y Off ft DLS 4,625 50 354 3,685 -3,634 -192 2,183 0.00 4,650 50.1 354 3,701 -3,650 -194 2,202 0.40 4,675 49.9 354 3,717 -3,666 -196 2,221 0.80 4,700 50.1 354 3,733 -3,682 -198 2,240 0.80 4,725 50.1 354 3,749 -3,698 -200 2,259 0.00 4,750 50.1 354 3,765 -3,714 -201 2,278 0.00 4,775 50.1 354 3,781 -3,730 -203 2,297 0.00 4,800 50.2 354 3,797 -3,746 -205 2,316 0.40 4,825 50.3 354 3,813 -3,762 -207 2,335 0.40 4,850 50.2 354 3,829 -3,778 -209 2,355 0.40 4,875 50.3 354 3,845 -3,794 -211 2,374 0.40 4,900 50.3 354 3,861 -3,810 -212 2,393 0.00 4,925 50.3 354 3,877 -3,826 -214 2,412 0.00 4,950 50.3 354 3,893 -3,842 -216 2,431 0.00 4,975 50.3 354 3,909 -3,858 -218 2,450 0.00 5,000 50.2 354 3,925 -3,874 -220 2,469 0.40 5,025 50.2 354 3,941 -3,890 -222 2,488 0.00 5,050 50.4 354 3,957 -3,906 -224 2,508 0.80 5,075 50.5 354 3,973 -3,922 -225 2,527 0.40 5,100 50.4 354 3,989 -3,938 -227 2,546 0.40 5,125 50.4 354 4,005 -3,954 -229 2,565 0.00 5,150 50.4 354 4,021 -3,970 -231 2,584 0.00 5,175 50.5 354 4,037 -3,986 -233 2,604 0.40 5,200 50.3 354 4,053 -4,002 -235 2,623 0.80 5,225 50.4 354 4,069 -4,018 -237 2,642 0.40 5,250 50.4 354 4,084 -4,033 -239 2,661 0.00 5,275 50.4 354 4,100 -4,049 -241 2,680 0.00 5,300 50.4 353 4,116 -4,065 -243 2,699 3.08 5,325 50.4 353 4,132 -4,081 -245 2,719 0.00 5,350 50.5 353 4,148 -4,097 -247 2,738 0.40 5,375 50.3 353 4,164 -4,113 -249 2,757 0.80 5,400 50.3 353 4,180 -4,129 -250 2,776 0.00 5,425 50.3 353 4,196 -4,145 -252 2,795 0.00 5,450 50.3 353 4,212 -4,161 -254 2,814 0.00 5,475 50.4 353 4,228 -4,177 -256 2,833 0.40 5,500 50.2 353 4,244 -4,193 -258 2,853 0.80 5,525 50.4 353 4,260 -4,209 -260 2,872 0.80 5,550 50.3 353 4,276 -4,225 -262 2,891 0.40 5,575 50.4 353 4,292 -4,241 -264 2,910 0.40 5,600 50.3 353 4,308 -4,257 -266 2,929 0.40 5,625 50.1 353 4,324 -4,273 -268 2,948 0.80 5,650 50.3 353 4,340 -4,289 -270 2,967 0.80 5,675 50.1 353 4,356 -4,305 -272 2,986 0.80 5,700 50.2 353 4,372 -4,321 -274 3,006 0.40 5,725 50.2 353 4,388 -4,337 -276 3,025 0.00 5,750 50.1 353 4,404 -4,353 -278 3,044 0.40 5,775 49.9 353 4,420 -4,369 -280 3,063 0.80 5,800 50.2 353 4,436 -4,385 -282 3,082 1.20 5,825 50.3 353 4,452 -4,401 -284 3,101 0.40 5,850 50.2 353 4,468 -4,417 -286 3,120 0.40 5,875 50.2 353 4,484 -4,433 -288 3,139 0.00 5,900 50.2 353 4,500 -4,449 -290 3,158 0.00 5,925 50.2 353 4,516 -4,465 -292 3,177 0.00 5,950 50.2 353 4,532 -4,481 -294 3,196 0.00 5,975 50 353 4,548 -4,497 -296 3,215 0.80 6,000 50.3 353 4,564 -4,513 -299 3,235 1.20 6,025 50.3 353 4,580 -4,529 -301 3,254 0.00 6,050 50.3 353 4,596 -4,545 -303 3,273 0.00 19 • • MD ft Inc de Azim TVD ft SSTVD ft X Off ft Y Off ft DLS 6,075 50.2 353 4,612 -4,561 -305 3,292 0.40 6,100 50.1 353 4,628 -4,577 -307 3,311 0.40 6,125 50.3 353 4,644 -4,593 -309 3,330 0.80 6,150 50.2 353 4,660 -4,609 -311 3,349 0.40 6,175 50.1 353 4,676 -4,625 -313 3,368 0.40 6,200 50.2 353 4,692 -4,641 -315 3,387 0.40 6,225 50 353 4,708 -4,657 -317 3,406 0.80 6,250 50.2 353 4,724 -4,673 -319 3,425 0.80 6,275 50 353 4,740 -4,689 -321 3,444 0.80 6,300 50.1 353 4,756 -4,705 -323 3,464 0.40 6,325 50.1 353 4,772 -4,721 -325 3,483 0.00 6,350 50.2 353 4,788 -4,737 -327 3,502 0.40 6,375 50.1 353 4,804 -4,753 -330 3,521 0.40 6,400 50 353 4,820 -4,769 -332 3,540 0.40 6,425 50 353 4,836 -4,785 -334 3,559 0.00 6,450 49.7 353 4,852 -4,801 -336 3,578 1.20 6,475 49.8 353 4,869 -4,818 -338 3,597 0.40 6,500 49.9 353 4,885 -4,834 -340 3,616 0.40 6,525 49.8 352 4,901 -4,850 -343 3,635 3.08 6,550 50.1 352 4,917 -4,866 -345 3,654 1.20 6,575 50.2 352 4,933 -4,882 -347 3,673 0.40 6,600 50.3 352 4,949 -4,898 -350 3,692 0.40 6,625 50.3 352 4,965 -4,914 -352 3,711 0.00 6,650 50.4 352 4,981 -4,930 -354 3,730 0.40 6,675 50.2 352 4,997 -4,946 -357 3,749 0.80 6,700 50.1 352 5,013 -4,962 -359 3,768 0.40 6,725 50 352 5,029 -4,978 -361 3,787 0.40 6,750 49.8 352 5,045 -4,994 -364 3,806 0.80 6,775 50 352 5,061 -5,010 -366 3,825 0.80 6,800 50.2 352 5,077 -5,026 -368 3,844 0.80 6,825 50.4 353 5,093 -5,042 -371 3,863 3.18 6,850 50.5 353 5,109 -5,058 -373 3,882 0.40 6,875 51.1 354 5,125 -5,074 -375 3,902 3.92 6,900 51.8 355 5,140 -5,089 -377 3,921 4.20 6,925 52 356 5,156 -5,105 -378 3,941 3.25 6,950 52 357 5,171 -5,120 -379 3,960 3.15 6,975 52.1 358 5,187 -5,136 -379 3,980 3.18 7,000 52.3 359 5,202 -5,151 -379 4,000 3.26 7,025 52.2 360 5,217 -5,166 -379 4,020 3.19 7,050 51.9 0 5,233 -5,182 -379 4,039 1.20 7,075 52 1 5,248 -5,197 -379 4,059 3.18 7,100 52 2 5,263 -5,212 -378 4,079 3.15 7,125 52.1 2 5,279 -5,228 -377 4,098 0.40 7,150 52 3 5,294 -5,243 -376 4,118 3.18 7,175 51.8 4 5,310 -5,259 -375 4,138 3.25 20 Recompletion Workover Program: A schematic of the proposed injection well recompletion is shown in Exhibit 10. Exhibit 11 shows a schematic of the proposed injection well recompletion contingency. Surface Location: Longitude: -150.79636514 Latitude: 61.240920100 682' FSL & 699' FEL Sec. 1, T13N R9W SM Total Depth: 11,575' MD (8,167.41' TVD; -8,116.41' SSTVD) Bottom Hole Location: 1,404.84 feet E; 6,859.86 feet N Top of Injection Zone: 5,544 feet MD (-4,221 feet SSTVD) 2,886 feet N, 262 feet W Wellbore azimuth: 11.57° Kelly bushing elevation: 51 feet above mean sea level Item and Depth Subsea TVD (RKB) MD (RKB) 20" -115' 166' 166' 13-3/8" -835' 886' 866' 9-5/8" -2,887' 2,938' 3,460' 7" -7, 301' 7, 352' 10, 350' 5" -8,118' 8,169' 11, 575' Top Upper Confining Zone -3,412' 3,463' 4,280' Top Injection Zone -4,221' 4,272' 5,544' Base Injection Zone -4,630' 4,681' 6,183' Top Lower Confining Zone -4,630' 4,681' 6,183' Base Lower Confining Zone -4,821' 4,872' 6,478' 21 • • Chevron I Ivan Rlvx Unk ~ ~ arEe ~°~„al ~: 1ppi-0-0~5H7H, Field: Ivan River Unit API#: 50-283-20086-00 ORIGINAL RIG ELEVATIONS SuRace Locat ion: Well Classdicaton: Develo ment Gas WNI 682' FSL & 69 9' FEL Total De the 11,575' Sec 1,T13N,R 9W,SM pBTD: 6,215' RKB-GL ~ X ASP4 359,714 Tubin 3-%", 9.3#, L-80, H ril 503 24.50' V: ASP4 2,646,373 Prod Pkrs: t 7" Baker Model "FB-1" Wireline Set Pkr RKB-MSL Well Status: PROPOSED' 51.00' r O erator Chevron Ownershi CheVfon 100% GL-MSL: 26.5 S ud Da te: 9/25/92 8:00 PM RKB-MSL: 51.0 Other. Rig Release DeC 1992; WO/Plugback July 19%; CTCO Jul/AUg 166' Csg BHP'. 5 2 ppg 5,085 ' NO 1997: Plugback Oct 2000; PeR Nov 2000; SL Tap Jun 2007; SL BHT: 107° 6,900' MD Tag Jun 2008 866' Csg Des<R t ion Wei ht Grade Conn ID Len h To Btm TOC r SWCtural 20' 94.0# WA Weltl 19.124" 166' 0 166' Ddven 12.O hrs Cmt above DV Surface 133/8" 68.0# K-55 BTC 12.415" 866' 0 866' SuR 64.5 hrs 500'-2,590' Intermediate 95/8" 47.0# N-80 BTC 8.681" 3,460' 0 3,460' SuR 341.0 hrs Production T' 29.0# N-80 BTC 6.184" 10.350 0 10.350' 500' 28.5 hrs DV Conar ~ Liner 5" 15.0# N-80 BTC 4.408" 10,028' 1,54T 11,575' 10,028' O.0 hrs 2,793' MD Cmt below Dv 2,816'-3,460' Tubiny 31i1" 'l !'J I_80 Hyd 503 2.992" 5,525' 0' 5,525' 3,460' Csg Cale TOC 5,000 MD 3,925' ND Top Inj Zone 5,544' MD 4,272' ND ease Inj Zone 6,183' MD 4,681' ND Cale TOC 6,250' MD 4,724' ND 7,420' BP 9,822' Rtnr 10,028' TOL 10,350 Csg 11,575' Csg 11,575' TD A B C D E F G H Patch I Beluga 18.183' 18.1H3' I 20 I 2-1/4 I B I 60 IPROP IPRO PO SED I Exhibit 10 -Proposed Injection Well Schematic 1 7" x 5.5" Enventure 2 7" Fbwco "Noss" DV 3 Baker Model 'FB-1' 4 xN Pro01e no 0 5 Wireline Ent Guir 8 Cement retainer wl 7 Cut 2-7/8"tubin w 8 Britl a Plu w/ 20 c. 9 Cement Retainer w/ 10 Punch holes Punch 11 TI W Seal assemDl 12 Punch holes Punch 13 Baker model'R'no- 14 Bakef TCP uns nc a 22 • Chevron ORIGINAL RIG ELEVATIONS !-Gl 24.50' - I-MSL 51.00' 188' Cs<I 866' Csg Cml above DV soo'-z,ssa DV Collar 2,793'MD Crt4 below DV 2,818-3,480' 3,460' Csg USIT TOC 5,600'MD 4,308' ND Top Inj Zone 5,544' MD 4,277 ND Base Inj Zone 8,183' MD 4,881' ND Calc TOC 8,250' MD 4,724' ND 7,420' BP 9,622' RNr 10,028' TOL 10,350' Csg 11,575' Csg 11,575' TD A 8 C D E F G H J ~, to DrIItM: 182-088 8 Ser1a1N: ADL-068788 PlugDack Oc12000; PeA Nov 2000; SL Tag Jun 2007; SL Tag 2008 Exhibit 11 -Proposed Injection Well Schematic Contingency 1 2 3 6 7 6 s 10 11 12 13 14 15 ~~ IRU 17J1 Ivan Rfver UnN 1,T13N.R9W,SM 23 ~ • Workover Procedure: PRE-RIG OPERATIONS (Surface work, E-line, Wellhead) 1. Prep location for Nabors 129 footprint. Build extension into reserve pit for rig catwalk. 2. RU E-line on IRU 13-31. RIH and set WRP plug at +/- 2,000'. Pump lease water on plug. Set BPV in LS/SS. Ensure annulus has at least 2,000' of glycol (should have glycol to surface). 3. CONTINGENCY: If BPV won't set in LS (bad threads previously found and not repaired), set 2"d WRP plug as deep as practical in place of BPV. 4. ND Tree. Remove well house and place at Lewis River D-pad. Level location to accept rig. 5. RU E-line on IRU 44-01. RIH and set WRP plug at +/- 2,000'. Pump lease water on plug. Set BPV in LS/SS. Ensure annulus has at least 2,000' of glycol (should have glycol to surface). 6. ND Tree. Remove well house and place at Lewis River D-pad. Level location to accept rig. Well anticipated stickup of 6"-12". 7. RU E-line on IRU 41-01. RIH and set WRP plug at +/- 2,000'. Pump lease water on plug. Set BPV in LS/SS. Ensure annulus has at least 2,000' of glycol (should have glycol to surface). 8. ND Tree. Remove well house and place at Lewis River D-pad. Level location to accept rig. Well anticipated stickup of 36"-48". RIG OPERATIONS (Rig, Slickline, E-line) 1. Skid Rig #129 over IRU 13-31 well. NU BOPs. Test to 250/3,000 psi. 2. RU Slickline. Pull BPV in LS/SS. Pull WRP plug. Monitor well. 3. RU E-line. RIH w/ tbg punch (1-11/16") to 5,555'. Punch tbg. POOH. 4. PU dual tbg hanger. Pull to release FH packer. RIH w/ radial torch (1-11/16") to 5,550'. Cut tbg. 5. PU to confirm tbg cut. Lay down dual hanger, long string and heater string tbg and packer. 6. CONTINGENCY: If tbg/pkr won't pull free, RIH and make 2"d cut w/ radial torch at 5,545'. 7. CONTINGENCY: If tbg/pkr won't pull free, RIH and make 3`d cut w/ radial torch below packer. Fish remaining tubing down to fill at 5,561'. 8. RIH w/ 5-3/4" overshot w/ 800' washpipe on 4" DP. Washover tubing down to cement top of 6,250'. TOC is based on calculated volume. If no cement encountered, wash to 6,260' to confirm no cement then POOH. 9. CONTINGENCY: If cement found above 6,250', discuss with town. If milling required, RIH and mill cement around OD of tubing to 6,250'. POOH w/mill. 10. RIH w/ OD tbg cutter. RIH to 5,800'. Cut tbg and recover +/- 250' of tbg. 24 r~ LJ 11. RIH w/ OD tbg cutter. RIH to 6,050'. Cut tbg and recover +/- 250' of tbg. 12. RIH w/ OD tbg cutter. RIH to 6,250'. Cut tbg and recover +/- 200' of tbg. 13. RIH w/ 6" scraper assembly w/ 6" bit to cut tbg at 6,250'. Key areas are 2,793' (DV collar) and 5,544'-6,183' (disposal zone). POOH. 14. RU E-line. RIH w/ USIT log. Log from 6,250' to 2,500'. POOH. 15. CONTINGENCY: If cement found below 5,544', discuss with town. May modify permitted disposal interval w/ AOGCC. If cement squeeze desired, set bridge plug, perf casing above TOC, set cement retainer and attempt isolation squeeze w/ cement retainer. Make require multiple squeezes as needed. Drill out cement. 16. RIH w/ Cmt Retainer on DP. Set retainer at 6,240' or 10' above tbg cut depth. Stack out 10k to confirm retainer set. 17. Stab into retainer and establish injection rate. Squeeze up to 15 bbl abandonment cement below retainer. Unsting from retainer and lay 50' (2.0 bbl) on top. Circ 2 btms up above cement top. POOH. 18. RIH w/ 6" scraper assembly w/ 6" bit to cmt top. Drill cement to 6,215'. POOH. 19. RU E-line. RIH w/ FB-1 packer and tail pipe. Set at 5,450'. POOH. 20. Set SB-1 packer plug. POOH. 21. Dump bail 10' CaCO3 on plug. POOH. 22. RU to run Enventure SET casing patch. Set patch across DV collar at 2,793'. Test patch to 3,000 psi. POOH. 23. RIH w/ junk mill and watermelon mill. Mill out shoe. RIH to bottom and circ out CaCO3. 24. RU E-line. Pull SB-1 packer plug. 25. RIH w/ 3-1/2" Hydril 503 tubing. Stab thru FB-1 packer seal bore. Space out and land tubing hanger. 26. RU slickline. RIH w/ N-Test tool. Set in XN profile. Test tubing to 5,000 psi. POOH. 27. Test casing (3-1/2" x 7") to 1,500 psi (Official MIT). Record w/ chart recorder or SPIDR gauge. 28. RU E-line. RIH w/ 20' 6 spf 2-1/4" Big Hole guns. Perforate 6,163'-6,183' MD. POOH. 29. RU G&I to perform infectivity test on disposal zone. 30. CONTINGENCY: If injection rates are too low or injection pressures too high, plan to reperf existing or add additional perfs above. Top of injection zone = 5,544' MD. Btm of injection zone = 6,183' MD. 31. Lay down landing jt. Set BPV. ND BOP. NU Tree. Pull BPV. Set TWC. Test Tree. Pull TWC. 32. RU flowlines. RD and prep for pad move. 33. ***Rig move to IRU 14-31X grass roots well*** 25 • Waste Sources. Tyaes and Volumes 20 AAC 25.252 (c) 7 Sources and Volumes of Waste Resource Conservation Recovery Act (RCRA) exempt Class II wastes will be injected in the disposal well. This will include drilling fluids and cuttings; produced water not usable for enhanced recovery and a class of wastes termed "other associated waste". Other associated wastes specifically include waste materials intrinsically derived from primary field operations associated with the exploration, development, or production of crude oil and natural gas. "Intrinsically derived from primary field operations" is intended to distinguish exploration, development and production activities from transportation and manufacturing. With respect to crude oil, primary field operations include activities occurring at or near the wellhead and before the point where the oil is transferred from an individual field facility or a centrally located facility to a carrier for the transport to a refinery or a refiner. It also includes the primary, secondary and tertiary production operations. Crude oil processing, such as water separation, de-emulsifying, degassing, and storage at tank batteries associated with a specific well or wells, are examples of primary field operations. In general, the exempt status of an exploration and production waste depends on how the material was used or generated as waste, not necessarily whether the material is hazardous or toxic. A list of exempt oil and gas wastes are included in EPA publication 530-K-95-003 (May 1995). Crude Oil and Gas Exploration and Production Wastes: Exemption from RCRA Subtitle C Regulations. This includes but is not limited to drill cuttings, mud, produced fluids, reserve pit waste, rig wash, formation materials, completion fluids, workover fluids, stimulation fluids and solids, tracer materials, glycol dehydration wastes, naturally occurring radioactive material scale slurries, precipitation accumulating within production impoundment areas, tank bottoms, production chemicals used in wells, and other fluids brought to surface and generated in connection with oil and gas development activities. Maximum Disposal Volume by Major Category: Drill cuttings, mud, flush water 11 % (125,000 bbl) Well workover fluids and flush 9 % (100,000 bbl) Produced water and other clear exempt fluids 64 % (730,000 bbl) Reserve pit cuttings and fluids 16 % (180,000 bbl) Total Volume (20+ years) 1,135,000 bbl Injection Rate and Volume: The average daily injection rate is estimated to be 155 BPD, with excursions up to 1,000 +/- BPD. If the well remains active in this fashion for 20 years this would generate a cumulative disposal volume of 1,135,000 barrels. This would generate a radial plume in the injection zone of 180 +/- feet if not skewed by fracturing. 26 • • Compatibility of Fluids and Formation Towards this end log data for the wells within the field are the basis for the description included in Section (c) 4. The lithology of the injection zone is typical of local existing injection wells, being comprised of conglomeratic gravels, inert quartz and clay matrix material. The resident aquifer is typical for injection wells within the area that have operated without incident over the last 15 years and is therefore compatible with the same wastes being injected in similar storage reservoirs. 27 • • Infection Pressure 20 AAC 25.252 (c) 8 Injection pressure is estimated to average between 1,800 to 2,800 psi while injecting either mud or slurried cuttings because the densities and other properties will be similar. This should also be a reasonable pressure to expect when injecting produced water and other clear fluids because the decrease in hydrostatic gradient relative to the mud is offset by the more mobile liquid. This pressure is probably above the fracture gradient and the flow mechanism will involve fractures in some form. A maximum pressure of 5,000 +/- psi could be reached intermittently should sporadic plugging of the perforations or gradual plugging of the fracture flow channels occur due to settling or packing of solids. 2s • • Waste Confinement 20 AAC 25.252 (c) 9 Injection of drilling mud and slurried cuttings will require pressures greater than the breakdown pressure of the formation. Initially a single planar vertical fracture should develop. This primary fracture can be expected to gradually plug with solids and also experience tip screen out. As the local stress regime is altered, appendages can develop creating a radial fracture system of some oblique fashion. The dimensions of the fracture domain will depend upon the amount of mud/cuttings injected and the rock properties controlling storage mechanics. The development of multiple fractures will have the effect of minimizing the lateral, and to some extent, the vertical growth of a primary fracture plane. A modeling study was undertaken to help quantify the behavior of injecting solids-slurry into the Sterling Formation. An industry available three dimensional hydraulic fracturing simulator was used to predict fracture growth during slurry injection. A prominent licensed commercial product was employed, built and maintained by Meyer and Associates, Inc. for industry use. The study was conducted by a Western Energy Services geophysical expert working at the University of Utah. Rock properties used in the model were based on well data calculated from well IRU 13-31 geophysical logs. The fracture gradient was itself then calibrated to break down data obtained from numerous other wells in the area. The fracture report of Appendix A details the model input data. The lower sand within the injection interval is planned to be utilized first with additional perforations being added above the initial perforations within the injection interval as the need arises. The main three sand members that constitute the modeled injection zone are shown on Exhibit 12. Injection of drilling and reserve pit wastes will generally be made in batches of approximately 1,000 barrels or less. The slurry will typically be 9.1 to 10.1 pounds per gallon (ppg) and is planned to be injected at a rate of 2.5 to 4.0 BPM. Exhibit 13 shows the forecasted fracture dimensions for the expected cases. Exhibit 14 shows the forecasted fracture geometry resulting from the planned injection equipment if the well was completed only in the lower sand lobe. Exhibit 15 is the result if only the middle lobe was used. Exhibit 16 and 17 show typical results under the most extreme conditions of injecting a 2,500 barrel batch of 10.1 ppg slurry at an elevated rate. Other cases are included in Appendix A. In all cases injection does not penetrate the upper confining zone or breach the lower confining shale. Reservoir Faulting: The geologic mapping in Exhibits 4 to 7 show there are no transmissive faults in the area. Uncemented Wellbores: Within the %4 mile area of review there are no improperly cased or cemented wells. An overview of these wells can be found in Section (c) 12. 29 C Conclusions: • Wastes are expected to be confined within the injection zone just as has been experienced by the slurry injection in nearby well IRU 14-31, in a similar formation shallower than the IRU 13-31 disposal zone. 30 • • 5400 5500 5600 5700 Y 5800 oc ~ 5900 ~., Q 0 6000 6100 6200 6300 6400 - Vshale -Gamma - _- _~ _- __~ -_ Upper Lobe °. [perforations 5710-5680 ft] _ _ _ _ - ---- -- ---- -- ----I ------------ ~~ -~- --= 2~__ --~ -_- Middle Lobe ~ [perforations 5915-5860 ft] '~ Lower Lobe [perforations 6120-6160 - ~ - ft] ~~ ~i ~~ _..~ - 0 20 40 60 80 Gamma Ray (GAPI) Exhibit 12. Injection Zone with Major Sand Members Shale Volume (fractional) 0.00 0.50 1.00 - 5400 31 5500 5600 5700 5800 Y 5900 ~ 6000 0 6100 6200 6300 6400 C] 1000 bbl of Slurry 2500 bbl of Slurry Expected Case (9.5 p~ siun~y injBCCed at 2.5 BPM) Fracture Half-Length (ft) [approximate] 327-506 482-782 Fracture Total Height (up and down) (ft) [approximate] 45-57 48-59 Fracture Width [inches, approximate] 0.13-0.24 0.14-0.26 Rate sity (9.5 l~ slurry it~ecbed at 4 BPM) Fracture Half-Length (ft) [approximate] 337-616 573-963 Fracture Total Height (up and down) (ft) [approximate] 49-62 52-62 Fracture Width [inches, approximate] 0.15-0.27 0.16-0.29 Heavy Slurry Sensi~tity (10.1 ppg slurry ird at 2.5 BPM) Fracture Half-Length (ft) [approximate] 238-363 312-409 Fracture Total Height (up and down) (ft) [approximate] 71-78 82-100 Fracture Width [inches, approximate] 0.21-0.32 0.23-0.32 Heavy Slurry aml Rate Sensitivity (10.1 ppg slurry injected at 4 BPM) Fracture Half-Length (ft) [approximate] 253-325 339-473 Fracture Total Height (up and down) (ft) [approximate] 44-88 49-98 Fracture Width [inches, approximate] 0.22-0.32 0.26-0.35 Exhibit 13. Average Fracture Dimensions (Varies According to How the Well is Completed) 32 ~_ Q J E-' .. Q H • Stress Width Profiles 0 = zo 40 ^ 60 ® 80 90 95 ~ 99 i • Width Contours Stress (psi) \Vidth (ui.) Length (ft) Exhibit 14. Forecasted Geometry after Flush at End of Injecting 1,000 bbls of 9.5 ppg Slurry at 2.5 BPM in the "Lower Lobe" Stress Width Profiles Width C.'ontours 3000 4000 -0 -o Stress (psi) ~Yidth (in.) Length (ft) Exhibit 15. Forecasted Geometry after Flush at End of Injecting 1,000 bbls of 9.5 ppg Slurry at 2.5 BPM in the "Middle Lobe" 33 .. v~ Q J F-' • Stress Width Profiles 00 Width Contours Stress (psi) \Vidth (ui.) Length (ft) Exhibit 16. Forecasted Geometry after Flush at End of Injecting 2,500 bbls of 10.1 ppg Slurry at 2.5 BPM in the "Middle Lobe". Width Contours ~..~ Q H w;am ~~ ~ 0 0.04 _ o os f 01z 0.16 02 0.24 0.28 '. ~ 0.32 0.36 i i ~y ~_ ---- 0 100 200 300 400 500 600 700 800 900 1000 Stress (psi) Width (ui.) Length (tt) Exhibit 17. Forecasted Geometry after Flush at End of Injecting 2,500 bbls of 10.1 ppg Slurry at 4.0 BPM in the "Middle Lobe" 34 Stress V4'idth Profiles • Formation Water Salinity and Apuifer Exemption 20 AAC 25.252 (cl 10 & 11 The Alaska Oil and Gas Conservation Commission issued Aquifer Exemption Order No. 6 to Union Oil Company of California on July 23, 2001. The order, based on formation water salinity data, exempts portions of freshwater aquifers between 2,500 feet and 3,420 feet MD and within a'/z mile radius of well IRU 14-31 for Class II injection. The'/ mile radius was granted to allow for the possible permitting of a second disposal well near the well IRU 14-31 injection zone. On July 15, 2008, Union Oil requested an extension of this freshwater aquifer exemption from 3,420 feet MD down to 6,195 feet MD to include the base of the proposed well IRU 13-31 injection zone, which lies well within the'/2 mile radius of the injection zone in well IRU 14-31. The aquifer exemption depth extension is pending approval by the AOGCC. 35 • • Wells Within the Area of Review 20 AAC 25.252 (c) 12 The'/4 mile area of review around the top of the proposed injection zone in IRU 13-31 is shown on Exhibit 2. This perimeter encompasses two wells: IRU 14-31 and IRU 44-36. Both wells are cased and cemented so as to not provide a conduit for injected wastes 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: Exhibit 18 includes the well schematic. The 10 3/ 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 injection zone. Second stage cement was placed from 3,646 feet TVD to 625 feet TVD, thus cement is across the injection zone and both ends of the upper confining zone. This well is an active Class II disposal well that has injected 46,500 barrels to date. Well IRU 44-36: Exhibit 19 includes the well schematic. The 9 5/8 inch surface casing is set at 3,449 feet MD (2,941 feet TVD). Cement was recorded at the surface; logging shows good bonding from 3,449 to 2,400 feet, with fair bond up to 1,600 feet. The 7-inch casing logging shows good bond up to 4,400 feet with some cement to 4,250 feet MD, the top of the logged interval. Calculations place the top of cement at 3,591 feet TVD, which is across the injection zone and very near the top of the upper confining zone. This well is an active gas producer. 36 • ~ Ivan River Field Well 1431 susPenenst 20" 94t1 ®421 ®1238' For 7" CSG 10.9J4" 40,58 K-5! ~ 203T 1060 SX~ TTC ®51' Based or Hole stxe ®laie Based vn EquailzatMr Thru Floelt 8hor Stage Collar a 4234 BM 8X: Annulus TTC 8stwesr 4845' and 4066 (CBL Not Conclusive 7" 2S, 28 8 29i N"81 ® 7018' 600 SXl 51/2" User ~ 10,00 I ~_.---~ -718' 8.4# N-80 Butt Tubing lalcer 3-H Packer at 2903' Profile et 2948' (2.312 ID) lalaer WL Reentry t3uide at 298'2' :ement Retainer at 3225' :ement Plug 3360' - 36011' .882' -8882' Sgtd 200 SX . ~Ish #1 BHA Total Length 228' ~r~ably on Bottom at i 0,084' ~ish #i2 2208' of 2 7/B" D.P. ~op 18 7496' Bottom ®9701' ~ish #3 W.O. Asay & D.C.'s Length 380" 'op ®7345' Bottom ®7725' lah #4 2876' 2-2/3' TBQ &3200' 31/2" D.P. 'op ~ 3510' Bottom @ 96~' :ement Plug 7800' -9927' ;ement Plug 10,100' -10,360' Cement Plug 10,850' -10,900' TD =10,958' Exhibit 18: IRU 14-31 Well Schematic 37 a 20~ • Chevron • Ivan River We1144-3ti Actual Completion 9/12/01 Ftu outs Gun; I IRL 41-;6 WBD 9-1'_-01 c~s.doc CASL~G A.~TD TL'BI\G DETAIL SIZE \\T GR.~DE COVr m TOP BT:1t 13-3:'3" 68 ItiSS Bumess Surface 908' 9-~ S-- 47 \-SO Buttress Surface 3-449' 29 K-80 Buttress 6.184 Surface 7.759' 29 P-IIO Buttress 6.139 7.789' 3.305' Tobinq _-73" 6.4 L-80 Butt SC' 2.441 23.05' 7.7_'4' '-3 S" 4.6 L-80 Bun SC' 1.991 ?3.05' ?.980' \O. De t6 H) JE\\ELRY DE?AIL OD Item 1 Ih4a1 I'ubina Hanaer. '- S~' x '-3 S` Ferco Gr2c_ 10" SbI _ 3.060 2.313 3.500 Sliduta Slees•r. Baker. CMD. '-7 8` Butt _ 3.106 2.441 5.950 Packer. Baker FH Retrievable ~ 6.374" 2.3]3 3.500 Slidma Sleeve. Baker. C>1D. _'-7 ;i ~ Butt 5 6.514' 2.347 5.970 Packer. Baker SC-' Ret. i ~1m ID thrunglr 5-'? Snap Latch Seal Assv. 6 6.53 T 2.313 x.750 Slidma Sleeve Baker. C'J1D. 2-' 9° Butt 6.773' 2.347 5.970 Packer. Baker SC'-' Ret. t]Sm ID tlvunah S-22 Snap Latch) S 6.796 2.313 3.750 Slidma Sleeve. Baker. C _\iD. _'-7 3~~ Butt 9 LO'T ?.313 3500 \ipple. S. '.313" m. 2-? 8" Butt LO 7.096' ?.347 5.g10 Packer. Baker SC-1 Ret. (~1m ID tlvuuglt S-]' Snap Latch) I l 7.1 I1' i.4S0 5.500 Vieshnte sand scrrett assn. _' jts 2t 39' each 12 1?32- 2.347 5.673 Packer. Baker ~fud. D. ('sltn ID tln•ogah 5-22 Snap Latch) 13 7.690' 2.313 3.500 Vipple. X. ?.313" m. Z-7 3" Butt 14 7.724' 2.441 3.250 R'irehue Entn~ Gtude Heater 5trlug A ?.950 _-_ 5~~. 4.6=. N-SO Butt Iubina setth \]ulr 51toe PERFORATIO\ HISTORY tter~a , cculn ate ue io tm atnt s ommeots 3 ' 93 55-4 6.331' ti.440' 9' t5 Reprtfed a 4 UL 3 ' 93 59-6 6. ~"' 6.565' I t' t S R afed 9 4 OI 3 ' 93 71-3 6.536' 6.55" t6 1S R .fed 9 4 OI 94U1 74-3 7.117 7.150' 3~ t' ~lesluiteScreen 9 ~ 01 ~5-3 7.163' 7.154' 21' L' ~Inhrite Scrcwn 9 4 G 1 - '.760' '.772' L' 6 ETD = 8,272'. TD = 8,308' ~1as Hole angle = J8 deg !rt a.225' DRA\\'~ Bl": tcb REVISED: 92ti01 Exhibit 19: IRU 44-36 Well Schematic 38 • • Mechanical Integrity of Infection Well 20 AAC 25.252 (d) & (e) Ivan River 13-31 Mechanical Integrity Once the tubing is pulled, and the existing perforations are isolated, a patch will be run across the leaking DV collar in the 7" casing at 2,793 feet MD. The patch and 7-inch casing will be pressure tested to 3,000 psi and the 7-inch by 9 5/$ inch annulus pressure tested to 1,500 psi to ensure mechanical integrity of the well bore prior to perforating the injection zone. Formation Testing and Integrity Initial formation testing will involve apump-in step rate test up to a planned 6 BPM, if equipment is available for this rate, followed by a pressure fall off to obtain a base line formation pressure. A channel log or temperature log will be run after the well is injecting to confirm waste confinement. Subsequent testing, monitoring, and reporting will conform to the AOGCC requirements for slurry disposal wells. 39 • r Appendix A Fracture Modeling Report • • Simulation of Slurry Injection: Ivan River Unit 13-31 Prepared for: Chevron North America Exploration and Production Company MidContinent/Alaska Business Unit 909 West 9th Avenue, Anchorage, AK 99501 Prepared by: Western Energy Consultants LLC WEC-08-03 August 2008 VYESTERN ENERGY CONSULTANTS l Chevron North America Ex loration and Production Com an ~ Pa e 2 p p Y 9 Ivan River Unit 13-31 TABLE OF CONTENTS Background .................................................................................................. 3 Matrix Of Simulations ..................................................................................... 3 Resu Its ......................................................................................................... 4 Appendix A -Input Parameters .....................................................................10 Appendix B -Results ...................................................................................22 WESTERN ENERGY CONSULTANTS • Chevron North America~ploration and Production Company Page 3 Ivan River Unit 13-31 BAC KG RO U N D Simulations were carried out in support of an application to dispose Class II oil field waste fluids by underground injection into well IRU 13-31, located in the Ivan River Field, Matanuska-Susitna Borough, Alaska. Hydraulic fracturing simulations were carried out using commercial and proven software (MFracT"') to assess the evolution of fractures associated with injection into this well. MATRIX OF SIMULATIONS Appendix A summarizes the input material properties. The variables adopted in the simulations were: • Four completion schemes. Perforations are shown in Figure 1 and Table 1. Table 1. Perforated and Barefoot Intervals Measured Zone Depth of Comments Depth of Perforations Perforations (feet TVD RKB) feet RKB 5680-5710 Upper Lobe 4362.5- 4383.2 Estimated completed zone 5860-5915 Middle Lobe 4500.4-4543.4 Estimated completed zone 6120-6160 Lower Lobe 4703.6-4734.8 Estimated completed zone Initial simulations considered injection in the lowermost lobe only. Additional simulations considered injection exclusively into the middle or upper zones. A final scenario considered contemporaneously accessing all three perforated zones 1. Injection into the Lower Lobe (perforated N6120 to N6160 ft. 2. Injection into the Middle Lobe (perforated 5860 to 5915 ft. 3. Injection into the Upper Lobe (perforated N5680 to 5710 ft. 4. All three perforated zones open to injection Three fluids were used in the simulations. These were neat produced water or seawater (no solids) at an estimated temperature of 70°F (at the sandface), a 9.5 ppg slurry [equivalent to a base fluid with approximately 1.5 ppa (pounds of proppant - solids -added)], and a 10.1 ppa slurry [equivalent to a base seawater fluid with approximately 2.4 ppa solids]. Power law rheologies for these fluids were specified and these are shown in Table 2. Table 2. Fluid Rheology Fluid n' K' (Ibf-s"~/ft2) Weight (ppg) Specific Gravity Seawater/PW (base fluid) 1.0 1.313 x 10-5 8.66 1.04 9.5 ppg slurry 0.7 1.022 x 10-3 9.5 1.14 10.1 ppg slurry 0.7 7.156 x 10-3 10.1 1.21 WESTERN ENERGY CONSULTANTS Chevron North America~ploration and Production Com an Pa e 4 p Y 9 Ivan River Unit 13-31 • Several schedules were adopted for assessing slurry injection. Various parametric simulations were run and key results are reported for the following scenarios. 1. Case 1 (Base Case): a. 1000 bbls of 9.5 ppg slurry with a spearhead and flush at 2.5 BPM. b. 2500 bbls of 9.5 ppg slurry with a spearhead and flush at 2.5 BPM. 2. Case 2: a. 1000 bbls of 9.5 ppg slurry with a spearhead and flush at 4 BPM. b. 2500 bbls of 9.5 ppg slurry with a spearhead and flush at 4 BPM. 3. Case 3: a. 1000 bbls of 10.1 ppg slurry with a spearhead and flush at 2.5 BPM. b. 2500 bbls of 10.1 ppg slurry with a spearhead and flush at 2.5 BPM. 4. Case 4: a. 1000 bbls of 10.1 ppg slurry with a spearhead and flush at 4 BPM. b. 2500 bbls of 10.1 ppg slurry with a spearhead and flush at 4 BPM. The methods for developing the input data are included in Appendix A. RESULTS Results of the fracturing simulations are summarized in Table 3. Figures for the various cases are provided in Appendix B. Based on the results, the anticipated dimensions for a batch injection are shown in Table 4. General observations are that good injection practices (in terms of displacement) may be important because of the inclination of the well; and, the heavier slurry tends to have less length development and more height and width development, as would be expected. WESTERN ENERGY CONSULTANTS Chevron North America~ploration and Production Company Ivan River Unit 13-31 Page 5 5400 5500 5600 5700 Y 5800 oc 0 ~ 5900 0 6000 6100 6200 6300 6400 Shale Volume (fractional) 0.00 0.50 1.00 Vshale _~ -Gamma - ~~ Upper Lobe [perforations 5710-5680 ft] Middle Lobe [perforations 5915-5860 ft] --- Lower Lobe [perforations 6120-6160 ft] f i ~ ~ ~- _- i ~ ~= 5400 5500 5600 5700 5800 Y 0 5900 ~ n 6000 0 6100 6200 6300 6400 0 20 40 60 80 Gamma Ray (GAPI) Figure 1. Targeted zones are shown with potential perforation clustering shown. WESTERN ENERGY CONSULTANTS Chevron North America Exploration and Production Company Page 6 Ivan River Unit 13-31 Table 3. Summary of Fracture Dimensions at the End of Injection Case Completion) Zone2 Rate (BPM) Injection Fluid Total Volume3 (bbl) Fracture Half- a Length (ft) Upper Heights (~) Lower Height6 (ft) Maximum Wellbore Width ~ (inches) EO]8 Net Pressure (psi) is All 2.5 9.5 ppg slurry 1,000 Lower <19 159 199 Middle Upper 489 29 16 .176 156 ib Lower Lower 2.5 9.5 ppg slurry 1,000 327 23 34 .125 81 lc Middle Middle 2.5 9.5 ppg slurry 1,000 506 29 21 .243 84 1d Upper Upper 2.5 9.5 ppg slurry 1,000 489 29 16 .176 156 ie All 2.5 9.5 ppg slurry 2,500 Lower < 19 159 199 Middle Upper 706 31 17 .193 165 1f Lower Lower 2.5 9.5 ppg slurry 2,500 482 25 34 .14 87 1 This designates which zone is open. The upper zone would be perforated. The Lower Sand will tentatively be barefoot. Perforations are also potentially open in the shale (above the shoe and below the perforations in the Upper Sand). z Designates zone where fracture growth occurs. s Excluding displacement volume (spearhead and flush). a Fracture half-length is the length from the wellbore to the tip of one wing of an assumed symmetrical fracture (i.e., the modeling presumes that two identical fracture wings grow diagonally away from the wellbore in the direction of the maximum horizontal principal stress. s Designates the vertical upwards growth at the wellbore from the center of the specified zone. e Designates the vertical downwards growth at the wellbore from the center of the specified zone. ~ Maximum wellbore width is the maximum fracture width at any position along the wellbore. $ EOJ (end of job) implies after flush, at shut-in. Net pressure is the difference between the sandface injection pressure and the in-situ stress at the mid-depth of the completed zone. 9 Recedes. • WESTERN ENERGY CONSULTANTS Chevron North America Exploration and Production Company Page 7 Ivan River Unit 13-31 Case Com letionl p Zone2 Rate (BPM) In ection j Fluid s Volume (bbl) Fracture Half- Length4 (ft) Upper H (~) is Lower H (ft) t6 Maximum Wellbore Width ~ (inches) EO]8 Net Pressure (psi) 1g Middle Middle 2.5 9.5 ppg slurry 2,500 782 29 21 .263 91 lh Upper Upper 2.5 9.5 ppg slurry 2,500 706 31 17 .193 165 2a All 4 9.5 ppg slurry 1,000 Lower < 19 159 219 Middle Upper 557 31 18 .198 167 2b Lower Lower 4 9.5 ppg slurry 1,000 337 28 34 .145 97 2c Middle Middle 4 9.5 ppg slurry 1,000 616 30 22 .267 93 2d Upper Upper 4 9.5 ppg slurry 1,000 557 31 18 .198 167 2e All 4 9.5 ppg slurry 2,500 Lower <i9 149 219 Middle Upper 751 32 22 .22 171 2f Lower Lower 4 9.5 ppg slurry 2,500 573 28 34 .163 95 2g Middle Middle 4 9.5 ppg slurry 2,500 963 30 22 .288 104 2h Upper Upper 4 9.5 ppg slurry 2,500 751 32 23 .221 171 3a All 2.5 10.1 ppg slurry 1,000 Lower < 19 159 199 Middle Upper 288 39 34 .262 172 3b Lower Lower 2.5 10.1 ppg slurry 1,000 238 44 34 .208 104 3c Middle Middle 2.5 10.1 ppg slurry 1,000 363 48 23 .317 93 3d Upper Upper 2.5 10.1 ppg slurry 1,000 288 39 35 .262 172 • • WESTERN ENERGY CONSULTANTS Chevron North America Exploration and Production Company Page 8 Ivan River Unit 13-31 Case i Completion z Zone Rate (BPM) Injection Fluid Total3 Volume (bbl) Fracture Half- a Length (ft) Upper Heights (ft) Lower Height6 (ft) Maximum Wellbore Width ~ (inches) EOJ$ Net Pressure (psi) 3e All 2.5 10.1 ppg slurry 2,500 Lower < 19 159 199 Middle Upper 396 45 37 .29 175 3f Lower Lower 2.5 10.1 ppg slurry 2,500 312 59 34 .229 101 3g Middle Middle 2.5 10.1 ppg slurry 2,500 409 77 23 .317 65 3h Upper Upper 2.5 10.1 ppg slurry 2,500 396 45 37 .29 175 4a All 4 10.1 ppg slurry 1,000 Lower ~ 19 139 259 Middle Upper 325 44 40 .297 178 4b Lower Lower 4 10.1 ppg slurry 1,000 253 59 34 .224 103 4c Middle Middle 4 10.1 ppg slurry 1,000 283 88 24 .316 56 4d Upper Upper 4 10.1 ppg slurry 1,000 325 44 37 .297 ,178 4e All 4 10.1 ppg slurry 2,500 Lower X19 79 259 Middle Upper 473 49 37 .328 187 4f Lower lower 4 10.1 ppg slurry 2,500 339 60 44 .264 103 4g Middle Middle 4 10.1 ppg slurry 2,500 419 98 24 .348 58 4h Upper Upper 4 10.1 ppg slurry 2,500 473 49 37 .328 187 v WESTERN ENERGY CONSULTANTS Chevron North America Ex loration and Production Com an • p p y Page 9 Ivan River Unit 13-31 Table 4. Average Fracture Dimensions (vary according to how the well is completed) 1,000 bbl of Slurry 2500 bbl of Slurry E~ecbed Case (9.5 ppg slurry ie~ec6ed at 2.5 BPM} Fracture Half-Length (ft) [approximate] 327-506 482-782 Fracture Total Height (up and down) (ft) [approximate] 45-57 48-59 Fracture Width [inches, approximate] 0.13-0.24 0.14-0.26 hate Sevity (9.5 ppg slurry injected at 4 BPM) Fracture Half-Length (ft) [approximate] 337-616 573-963 Fracture Total Height (up and down) (ft) [approximate] 49-62 52-62 Fracture Width [inches, approximate] 0.15-0.27 0.16-0.29 Heavy Slurry Sensitivity (1A.1 ppg slurry injected at 2.5 BPM) Fracture Half-Length (ft) [approximate] 238-363 312-409 Fracture Total Height (up and down) (ft) [approximate] 71-78 82-100 Fracture Width [inches, approximate] 0.21-0.32 0.23-0.32 Heavy 51•urty and Rate Se~ivity (10.1 ppg slurry ind at 4 BPM} Fracture Half-Length (ft) [approximate] 253-325 339-473 Fracture Total Height (up and down) (ft) [approximate] 44-88 49-98 Fracture Width [inches, approximate] 0.22-0.32 0.26-0.35 WESTERN ENERGY CONSULTANTS Chevron North America Exploration and Production Company Page 10 Ivan River Unit 13-31 APPENDIX A INPUT PARAMETERS WESTERN ENERGY CONSULTANTS • Chevron North America loration and Production Com an Pa a 11 p p Y 9 Ivan River Unit 13-31 A.1. Well Information: The completions considered are shown in Table A-1 and Figure A-1. Table A-1. Perforated and Openhole Sections Measured Depth of Pertorations feet RKB Zone Depth of Perforations feet TVD RKB Comments 5680-5710 Upper Lobe 4362.5- 4383.2 Estimated completed zone 5860-5915 Middle Lobe 4500.4-4543.4 Estimated completed zone 6120-6160 Lower Lobe 4703.6-4734.8 Estimated completed zone A.2 Survey Information: The survey data are shown in Figure A-2. A.3 Porosity Information Figure A-3 shows a representation of porosity. Since a substantial portion of the data were unreliable or not reported, they were synthesized using relationships from IRU 14-31. This was determined as multivariate linear regression on information considered to be subjectively reliable. The relationship used was: DPHI (decimal) _ -0.15416 + 0.002927 x DTC (,u sec/ ft) + 0.00146 x GR (GAPI) - - 0.00137 x ILD (ohm - m) + 0.000173 x ILM (ohm - m) Figure A-4 shows bulk density synthesized from the density porosity, assuming a sandstone matrix (SG = 2.65), 100 percent water saturation and a fluid specific gravity of 1.04. With all of the uncertainties, the simplistic relationship used was: pb (RHOBg/cm3)=2.65(1-DPHI)+1.04DPHI A.4. Fluid Loss Properties The permeability was estimated using experience-based relationships (Figure A-5) where the relationship with porosity is: k (md) _ -9.4983VShQ,e + 6.4983 Vshare - GR - GRSQ„d ~ GRsa„a -10 °API; GRShQ,e = 70 °API GRshalevRsand Figure A-5 shows the inferred permeability. To be conservative, spurt loss (instantaneous loss in fluid when new fracture surface is created) was taken as being zero. The wall building. fluid loss coefficient (Figure A-6) was estimated as follows (analog situations): CW = 0.0007841oglok + 0.0.00243 ft/minuteliZ WESTERN ENERGY CONSULTANTS Chevron North America Ex loration and Production Com an Pa a 12 P P Y 9 Ivan River Unit 13-31 5400 5500 5600 5700 Y 5800 0 ~ 5900 n 0 6000 6100 6200 6300 5500 5600 5700 5800 Y 0 5900 ~ n 6000 0 6100 6200 6300 6400 6400 0 20 40 60 80 Gamma Ray (GAPI) Figure A-1. Targeted zones are shown with potential perforation clustering also shown. Vshale - - -Gamma ~_- --- ~_ - ;~;F. Upper Lobe [perforations 5710-5680 ft] ~_ _- :._- ---- ------- ~ _3 Middle Lobe [perforations 5915-5860 ft] _: _ . ~' Lower Lobe - [perforations 6120-6160 ft] ~:- y r` ~~- ~~ Shale Volume (fractional) 0.00 0.50 1.00 - 5400 WESTERN ENERGY CONSULTANTS Chevron North America Ex loration and Pr p oduction Company Page 13 Ivan River Unit 13-31 0 0 1000 2000 3000 4000 5000 6000 Figure A-2. Plot of TVD versus MD. A.S. Mechanical Properties and Stress Synthesis Moduli were also estimated from inferences of the shear wave slowness (Figure A-7). These were based on the Greenwood-Castagna relationships, since no other information was available. The relationship used to estimate the shear wave slowness was: 5.59 - 8.6DPHI (decimal) - 2.18V~lay (decimal) DTS (,u sec/ ft) = DTC (,u sec/ ft) 3.52 - 6.1DPHI (decimal) -1.89V~lay (decimal) Vclay = Vshale V - GR - GRSand • GR 10 °API • GR - 70 °API shale GR GR ~ sand - ~ shale shale sand The correction from dynamic (logging) to static (for simulation) values was based on analog data. Poisson's ratio is shown in Figure A-8; Young's modulus is shown in Figure A-9. The stresses were then estimated using Poisson's ratio, bulk density, and moduli [refer to Figure A-10] Trajectory 13-31 MD (ft KB) 1000 2000 3000 4000 5000 6000 7000 WESTERN ENERGY CONSULTANTS i Chevron North America Exploration and Production Company Ivan River Unit 13-31 Page 14 Porosity 3500 1.00 ~ 3500 DPHI - Gamma 4000 4500 ,-, m ~ 5000 0 fl. 5500 a~ 0 6000 6500 4000 4500 .- m 5000 ~ 0 5500 n a~ 0 6000 6500 7000 L ' ' ' 7000 0 20 40 60 80 Gamma Ray (GAPI) Figure A-3. DPHI -from measured data and from synthetic data using a multivariate linear regression on data from IRU 14-31. A maximum porosity of 0.35 was specified. Porosity (fractional) 0.00 0.50 WESTERN ENERGY CONSULTANTS • Chevron North America• loration and Production Com an Pa a 15 p P Y 9 Ivan River Unit 13-31 Bulk Density Bulk Density (gm/cm3) 1.50 2.00 2.50 3500 4000 4500 .-. m ~ 5000 0 .~ 5500 0 6000 6500 7000 3500 4000 4500 .-. m 5000 ~ 0 .~ 5500 0 6000 6500 7000 0 20 40 60 80 Gamma Ray (GAPI) Figure A-4. RHOS -from measured data and from synthetic porosity data using a sandstone matrix and 100 percent brine saturation. WESTERN ENERGY CONSULTANTS Chevron North America Exploration and Production Com an p Y Ivan River Unit 13-31 Page 16 Permeability Permeability Gamma Ray Estimated Absolute Permeability (md) 0.001 0.01 0.1 1 10 100 iooo loooo 5500 - 5500 5600 5700 5800 m 5900 Y D ~ 6000 Q 0 6100 6200 6300 6400 6500 ~- 0 20 40 60 80 100 Gamma Ray (GAPI) Figure A-5. Permeability estimates. 5600 5700 5800 5900 m Y D 6000 ~ fl. 6100 0 6200 6300 6400 6500 WESTERN ENERGY CONSULTANTS i Chevron North America~ploration and Production Company Page 17 Ivan River Unit 13-31 F~ U ld LOSS C02ff IC121'lt -- Fluid Loss Coefficient 0.00001 3500 r 4000 4500 ,-, m ~ 5000 0 5500 0 6000 6500 - Gamma Estimated C,,,, (ft/minute1~2) 0.0001 0.001 0.01 0.1 3500 4000 4500 .- m 5000 ~ 0 5500 0 6000 6500 7000 7000 0 20 40 60 80 100 Gamma Ray (GAPI) Figure A-6. Wall building fluid loss coefficient estimates. WESTERN ENERGY CONSULTANTS Chevron North America Ex loration and Production Com an • p p Y Ivan River Unit 13-31 Synthetic Shear Wave 5000 5200 5400 5600 Y 5800 o= 0 ~ 6000 fl. p 6200 6400 6600 6800 Slowness (µsec/ft) 0 100 200 300 400 500 5000 5200 5400 5600 5800 Y o! 0 6000 ~ fl. 6200 0 6400 6600 6800 7000 7000 0 20 40 60 80 100 120 140 160 180 200 Gamma Ray (GAPI) Figure A-7. Compressional and shear wave slowness. Page 18 ~~ - DTS DTC - Gamma WESTERN ENERGY CONSULTANTS Chevron North America Exploration and Production Com an • P Y Ivan River Unit 13-31 Page 19 3500 4000 4500 ,-. m ~ 5000 0 5500 0 6000 6500 Young's MOCIUIUS - Young's Modulus Gamma Young's Modulus (106 psi) 0.0 0.3 0.5 0.8 1.0 1.3 1.5 1.8 2.0 3500 4000 4500 ,-, m 5000 ~ 0 .~ 5500 0 6000 7000 ~_ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 7000 0 20 40 60 80 Gamma Ray (GAPI) Figure A-8. Young's modulus (calculated from the bulk density and the P- and S-wave slownesses, and calibrated using analog data). 6500 WESTERN ENERGY CONSULTANTS Chevron North America•loration and Production Com an p Y Ivan River Unit 13-31 3500 4000 4500 ,-. m ~ 5000 0 .~ 5500 0 6000 6500 7000 Figure A-9. Poisson's ratio. 4000 4500 ,-. m 5000 ~ 0 5500 0 6000 6500 7000 Page 20 Poisson's Ratio Poisson's Ratio Gamma Poisson's Ratio 0.0 0.1 0.2 0.3 0.4 0.5 3500 0 20 40 60 80 100 Gamma Ray (GAPI) WESTERN ENERGY CONSULTANTS Chevron North America•loration and Production Com an Pa a 21 P P Y 9 Ivan River Unit 13-31 - Vertical -Formation Pressure Gradients Minimum Horizontal - Gamma Ray Stress and Pressure Gradients (psi/ft) 0.0 0.2 0.4 0.6 0.8 1.0 5000 5200 5400 5600 m 5800 Y ~ .. 6000 ~. 0 6200 6400 6600 6800 7000 5000 5200 5400 5600 5800 m Y D 6000 ~ .~ a 6200 0 6400 6600 6800 7000 0 20 40 60 80 100 Gamma Ray (GAPI) Figure A-10. Stresses and formation pressure gradients. Hydrostatic pressure was assumed for the formation pressure. There is no substantial data available for calibrating the log predictions. WESTERN ENERGY CONSULTANTS ` Chevron North America~ploration and Production Com an Pa a 22 p Y 9 Ivan River Unit 13-31 APPENDIX B RESULTS WESTERN ENERGY CONSULTANTS Chevron North America xploration and Production Company Ivan River Unit 13-31 Stress ~'irlth PrnfilPC UVirlth Cnntr~iirc r ~ r`-' ~ j Q ;:5~ ~~ H t~" ~ ,~ ,~i•$ % Length ~o ~ zo ®°`~ I 60 £0 90 ` ~> ~ 99 ~~9 -o z o oz Page 23 warn (+~ ) 0 0 oz 004 0 06 0 08 01 0.12 0.14 0.16 0 18 ~: nn son onn lnnr Stress (psi) Width (ui.) Length (ft) Figure B-1. This is the inferred geometry after flush (displacement volume) at shut-in for Case 1a (2.5 BPM, 9.5 ppg slurry, 1,000 BBL, injection into all three lobes). Stress V6'idth Prnfil~e ~iirlth ('nntnnrc Q J _ H -; D ~Y A> rQ ~(j ~. Lec~gth 0 20 40 ® 60 p so ®90 -0 nnc n. '', Width (inJ 0 0 02 0.04 0 og _._....... _....-. 0.1 0.12 I 0.14 __-- -~- --. 0.16 . 0.18 02 0 22 024 _- 026 .. -~---- i i 0 100 200 300 400 500 600 700 800 900 1000 Shess (psi) Width (ui.) Length (ft) Figure B-2. This is the inferred geometry after flush (displacement volume) at shut-in for Case ib (2.5 BPM, 9.5 ppg slurry, 1,000 BBL, injection into the °Lower Lobe"). WESTERN ENERGY CONSULTANTS i Chevron North America Exploration and Production Company Ivan River Unit 13-31 __ Stress Width Profiles Width Contour Q H 2000 300D 4000 -0 Page 24 Stress (psi) Width (ui.) Leugd7. (ft) Figure B-3. This is the inferred geometry after flush (displacement volume) at shut-in for Case is (2.5 BPM, 9.5 ppg slurry, 1,000 BBL, injection in the "Middle Lobe"). ._._ Stress Width Profiles Width Contours Q J H 2000 3000 4000 -0 Lertith 0 20 40 Q 60 ^ 80 90 ®95 99 ~ ~~ 15 -0.05 0.05 01 Width (in.) 0 0.02 0.04 0.06 0.08 --I-----.- 0.1 0.12 _ 0.14 _~ ~ .:. _ _..____.016 _, 0.18 i I i 0 100 200 300 400 500 600 700 800 900 1000 5 Stress (psi) Width (ui.) Length (ft} Figure B-4. This is the inferred geometry after flush (displacement volume) at shut-in for Case id (2.5 BPM, 9.5 ppg slurry, 1,000 BBL, injection into the "Upper Lobe"). WESTERN ENERGY CONSULTANTS • Chevron North America Exploration and Production Company Page 25 Ivan River Unit 13-31 Stress V~'idth Prntilec ~'irlth (`nntniirc ~_ Q E-' )0 -0 % Length ~o ~ zo ^ 40 ® 60 80 ~~ 90 I~ 95 99 ~j 15 -0.05 0.( werh ~;~ ) 0 0 oz 0.04 ......._.____-.....,. _ 0.06 0.08 01 ___ 0.12 0.14 0.16 018 __ ~- - 02 i i i i -- -___ -- --...i--- --- --- -----+-._ I 0 100 200 300 400 500 600 700 800 900 1000 Stress (psi) ~Vldth (lll.) Length (ft) Figure B-5. This is the inferred geometry after flush (displacement volume) at shut-in for Case 1e (2.5 BPM, 9.5 ppg slurry, 2,500 BBL, injection into all three lobes). ~tre~s ~'irlth Prntil~c ~i'irlth (`nntnnrc u~ Q F Lengtl~ 0 20 40 90 © 9 `' Jttfff ~~,~~y -o J Stress (psi) Width (ui.) Length (ft) Figure B-6. This is the inferred geometry after flush (displacement volume) at shut-in for Case if (2.5 BPM, 9.5 ppg slurry, 2,500 BBL, injection into the "Lower Lobe"). WESTERN ENERGY CONSULTANTS Chevron North America Exploration and Production Company Page 26 Ivan River Unit 13-31 Stress C~ Q E-~ 2000 3000 4000 -0 lth Proti Lerigri~~ 0 20 ®40 ® 60 80 90 ®95 1 99 St 15 _n ns n nF n 15 Width Contours Width (m ) 0 .. 0.03 0.06 0.09 - - -°-"-~-^-+- 0.12 - 0.15 0.18 0.21 :~'g ~ 0.24 0.29 r 0 100 200 300 400 500 600 700 800 900 1000 Stress (psi) Width (uL.) Length (ft) Figure B-7. This is the inferred geometry after flush (displacement volume) at shut-in for Case ig (2.5 BPM, 9.5 ppg slurry, 2,500 BBL, injection in the "Middle Lobe"). .~._ Stress Width Profiles Width Contours ~ { Q If H i Length 0 20 40 ®60 ^ 80 90 ®95 ~ 99 Wam(~) 0 0 02 004 0 06 0 08 01 0 12 ` 0 14 - 0 16 018 02 0 100 200 300 400 500 600 700 800 900 1000 i - 4390 2000 3000 4000 -0 Stress (psi) Width (u><.) Length (ft) Figure B-8. This is the inferred geometry after flush (displacement volume) at shut-in for Case lh (2.5 BPM, 9.5 ppg slurry, 2,500 BBL, injection into the "Upper Lobe"). WESTERN ENERGY CONSULTANTS Chevron North America Ex loration and Production Com an p p Y Ivan River Unit 13-31 ~~'~~~ W'idth Profiles width Contours G~ Q f-' ^0 ^ 20 S 40 ^ 60 ^ 80 90 ©95 99 -0 Page 27 5i 10 Stress (psi) Width (ui.) Length (ft) Figure B-9. This is the inferred geometry after flush (displacement volume) at shut-in for Case 2a (4 BPM, 9.5 ppg slurry, 1,000 BBL, injection into all three lobes). .___ Stress V~'idth Profiles Width Contours .••. Q J E-' 4750 ~~ r also 2000 3000 4000 -0 Widrh (m ) 0 0.03 0.06 _._- -...._. _........____.. . 0.09 0.12 ....... _._.._._. __._.........._ ................... _... 0.15 0.18 021 __. -_ ~~ ___..__ 0.24 027 03 5( Stress (psi) Width (ui.) Length (ft) Figure B-10. This is the inferred geometry after flush (displacement volume) at shut-in for Case 2b (4 BPM, 9.5 ppg slurry, 1,000 BBL, injection into the "Lower Lobe"). WESTERN ENERGY CONSULTANTS Chevron North America Ex loration and Production Com an P P Y Ivan River Unit 13-31 ,.~~ Stress Width Profiles Width Contours 451 .-. ~_ Q 452 J F-' 2000 3000 4000 -0 % L<~ 0 20 ^ 40 ^ 60 ^ 80 90 95 ~ 99 Page 28 Si Stress (psi) Width (ui.) Length (ft) Figure B-11. This is the inferred geometry after flush (displacement volume) at shut-in for Case 2c (4 BPM, 9.5 ppg slurry, 1,000 BBL, injection in the "Middle Lobe"). ._._ Stress Width Profiles Width Crnitours Length 0 20 40 ~60 'I' ^ 80 90 ~~ ~ 99 Q H V ' b ~ 2000 3000 4000 -0. 5 JO Stress (psi) Width (ui.} Length (ft) Figure B-12. This is the inferred geometry after flush (displacement volume) at shut-in for Case 2d (4 BPM, 9.5 ppg slurry, 1,000 BBL, injection into the "Upper Lobe"). WESTERN ENERGY CONSULTANTS Chevron North America Exploration and Production Company Ivan River Unit 13-31 Stresti Width Pr~tile~ V~-idth (:c~ntcxirti w Q E-' zooo aaoo sooo -o r ~o ^ 40 ^ 20 60 80 99 ~r Page 29 wam C~ ~ 0 0 oz 004 '-____..--. ~--- ~ ~ ~ 0.06 0.08 01 0.12 0.14 0 16 0.18 ' ------- '- -- - ' - .. 0.2 0.22 0.24 i I i ~-_ 15 0 100 200 300 400 500 600 700 800 900 1000 Stress (psi) Width (ui.) Length (ft) Figure B-13. This is the inferred geometry after flush (displacement volume) at shut-in for Case 2e (4 BPM, 9.5 ppg slurry, 2,500 BBL, injection into all three lobes). .___ Stress Width Profiles VG'idth Contours 4 .-~ ~_ Q J H 2000 3000 4000 -0 r<~ ^o ^ 20 40 60 ^ 80 ' 90 99 00 Stress (psi) Width (ui.) Length (ft) Figure B-14. This is the inferred geometry after flush (displacement volume) at shut-in for Case 2f (4 BPM, 9.5 ppg slurry, 2,500 BBL, injection into the ~~Lower Lobe"). WESTERN ENERGY CONSULTANTS Chevron North America Exploration and Production Com an Pa a 30 P Y 9 Ivan River Unit 13-31 .,__ Stress Width Profiles Width Contours Q J F Length 0 20 40 Q 60 ^ 80 ~ 90 95 ~ 99 n ns n 51 2000 3000 4000 -0 Stress (psi) Width (ui.) Length (ft) Figure B-15. This is the inferred geometry after flush (displacement volume) at shut-in for Case 2g (4 BPM, 9.5 ppg slurry, 2,500 BBL, injection in the "Middle Lobe"). _ _ Stress Width Profiles Width Contours Width 0 . 01 0.14 0.16 0.18 0.2 .-~ w_ Q J E-' 2000 3000 4000 -0 m Fnn an Stress (psi) Width (ui.) LenQth (ft) Figure B-16. This is the inferred geometry after flush (displacement volume) at shut-in for Case 2h (4 BPM, 9.5 ppg slurry, 2,500 BBL, injection into the "Upper Lobe"). WESTERN ENERGY CONSULTANTS . Chevron North America Exploration and Production Company Page 31 ~_ Q F-~ ~treti~ l0 -0 rh Prof 0 - 20 ^ 40 © 60 ^ 80 9U 95 99 V4'idth Contours W~~ ~~, 0 0 03 - _... 0.06 .......} .. ........ _._ _.. 0.09 - ~ ~-- 0.12 0.15 ---- 0.18 0.21 0.24 0.27 i __ ~.__ ---------'-------- --. -f-._. f _ ~ 0 100 200 300 400 500 600 700 800 900 1000 Stress (psi) ~Vidtli (ui.) Length (ft) Figure B-17. This is the inferred geometry after flush (displacement volume) at shut-in for Case 3a (2.5 BPM, 10.1 ppg slurry, 1,000 BBL, injection into all three lobes). .~,~ Stress Width Profiles V~'idth Contours 47 ~ 47 Q ,E'er„ 47 47 47 2000 3000 4000 -( i Stress (psi) Width (vi.) Length (ft) Figure B-18. This is the inferred geometry after flush (displacement volume) at shut-in for Case 3b (2.5 BPM, 10.1 ppg slurry, 1,000 BBL, injection into the "Lower Lobe"). WESTERN ENERGY CONSULTANTS ,, Chevron North America Ex loration and Production Com an p p Y Ivan River Unit 13-31 Page 32 aa,~ Stress Width Profiles ~=~ Q 451 J H 2000 3000 4000 -( V4'idth Contours Width (in.) 0 ~ 0.03 ~ -----.. 0.06 0.09 0 12 0 15 0 18 021 0.24 0.27 ~03 ~~.-~ .__ -::.,: 0.33 _L. Stress (psi) Width (ui.) Length (ft) Figure B-19. This is the inferred geometry after flush (displacement volume) at shut-in for Case 3c (2.5 BPM, 10.1 ppg slurry, 1,000 BBL, injection in the "Middle Lobe"). „~~ Stress Width Profiles Width Contours .. ~_ Q 4410 2000 3000 4000 -i i Stress (psi) Width (u>_) Length (ft) Figure B-20. This is the inferred geometry after flush (displacement volume) at shut-in for Case 3d (2.5 BPM, 10.1 ppg slurry, 1,000 BBL, injection into the "Upper Lobe"). WESTERN ENERGY CONSULTANTS • Chevron North America Ex loration and Production Com an • P P Y Ivan River Unit 13-31 Stress ~~idth Profiles wain ~,~ ~ 0.03 0 06 __ e.T. ____. 0.09 -._.+-.......---....._ ~ ......__.__. 0 t2 0.15 _.;.----_ 0 18 021 .-. ~_ Q H 4 2000 4000 6000 -( Width Contours Page 33 0.24 027 l0 200 300 400 500 600 700 800 900 Stress (psi) Width (ui.) Length (ft) Figure B-21. This is the inferred geometry after flush (displacement volume) at shut-in for Case 3e (2.5 BPM, 10.1 ppg slurry, 2,500 BBL, injection into all three lobes). ,~~~ Stress Width Profiles Width Contours w Q a71 J E-~ 4750 4760 2000 3000 4000 -( w~am (~ ) 0 0 04 0 os olz 0.16 0.24 0.28 0.32 0.36 i i ~- 0 100 200 300 400 500 600 700 800 900 1000 Stress (psi) Nidth (ur.) Length (t}) Figure B-22. This is the inferred geometry after flush (displacement volume) at shut-in for Case 3f (2.5 BPM, 10.1 ppg slurry, 2,500 BBL, injection into the °Lower Lobe"). WESTERN ENERGY CONSULTANTS • • Chevron North America Exploration and Production Company Ivan River Unit 13-31 Page 34 Stress Width Profiles 44 .. Q 45 ~- 2000 3000 4000 Vdidth Contours l0 Stress (psi) `Vidth (ui.) Length (ft) Figure 8-23. This is the inferred geometry after flush (displacement volume) at shut-in for Case 3g (2.5 BPM, 10.1 ppg slurry, 2,500 BBL, injection in the ~~Middle Lobe"). ,~~~ Stress Width Profiles Width Contours ~. ~_ Q H 44101 4 I 2000 3000 4000 -C Stress (psi) Width (ui.) Length (ft) Figure B-24. This is the inferred geometry after flush (displacement volume) at shut-in for Case 3h (2.5 BPM, 10.1 ppg slurry, 2,500 BBL, injection into the ~~Upper Lobe"). WESTERN ENERGY CONSULTANTS Chevron North America E•x loration and Production Com an P P Y Ivan River Unit 13-31 Page 35 Width Contours 4". Q J H )0 -0.2 -0.1 0 0.1 0.2 warn ~~ 1 0 0 03 0 06 __ - ._.__ __-_._.._L_...-_-... --____ - _.. 0.09 .. _ T.-____._. 0.12 ................ O 15 _;____ _.-- __ _ . ___.__....__..__ 0 18 0 21 0 24 0.27 03 ~__ ..__.__._. ..._._..._._._ ..__...__.._i-.-_._. _._~_r.. I ........L-_ .. 0 100 200 300 400 500 600 700 800 900 1000 Stress (psi) Width (ui.) Length (ft) Figure B-25. This is the inferred geometry after flush (displacement volume) at shut-in for Case 4a (4 BPM, 10.1 ppg slurry, 1,000 BBL, injection into all three lobes). Stress V~'idth Prnfiles VG'i~tth C:nnt~nrs Q E-' l0 -i warn (m 0 0 04 0 os 01z 0 16 ,_ __...._j.....__._._...... _._.__.___ .__.___. 0.2 0.24 0.28 `~ ~ ~ __,0.32 0.36 i _ I !~ I ~, j i D 100 200 300 400 500 600 700 800 900 1000 Stress (psi) Width (ui.) Length (ft) Figure B-26. This is the inferred geometry after flush (displacement volume) at shut-in for Case 4b (4 BPM, 10.1 ppg slurry, 1,000 BBL, injection into the ~~Lower Lobe"). WESTERN ENERGY CONSULTANTS Stress Width Profiles . ~ Chevron North America•loration and Production Com an p p Y Ivan River Unit 13-31 ~tres~ V4'idth Profiles Width Contours Q H Page 36 Stress (psi) Width (v>.) Length (ft) Figure B-27. This is the inferred geometry after flush (displacement volume) at shut-in for Case 4c (4 BPM, 10.1 ppg slurry, 1,000 BBL, injection in the ~~Middle Lobe"). .___ Stress Width Profiles V~'idth Contours w_ Q E- 44101 s I 2000 3000 4000 warn (m ) 0 0 03 0 06 i 0.09 0.12 0.15 -_- 0.18 0.21 0 24 027 I _----..---. _..------I-.._ i I 0 100 200 300 400 500 600 700 800 900 1000 Stress (psi) Width (ui.) Length (ft) Figure B-28. This is the inferred geometry after flush (displacement volume) at shut-in for Case 4d (4 BPM, 10.1 ppg slurry, 1,000 BBL, injection into the "Upper Lobe"). WESTERN ENERGY CONSULTANTS . • ' Chevron North America Ex loration and Production Com an p p Y Ivan River Unit 13-31 ~trP,cr V4'idth Profiles V4'idth Contours w_ Q J E-~ Page 37 Width ( ) 0 . .. ,. 0.04 ._ _ 0.08 _ _~ ~ _._ 0.12 0.16 - -i_..._._.__....._. 0.2 ....... _ 0.24 0.28 0.32 0 36 I i i I I i __, --- - - -----a---I---- - ---1-- i I 0 100 200 300 400 500 600 700 800 900 1000 Stress (psi) Width (u>..) Length (ft) Figure B-29. This is the inferred geometry after flush (displacement volume) at shut-in for Case 4e (4 BPM, 10.1 ppg slurry, 2,500 BBL, injection into all three lobes). ,~~~ Stress V~'idth Profiles Width Contours w Q J F a ZUUU 3000 4000 Stress (psi) ~Vidd>< (ui.) Length (ft) Figure B-30. This is the inferred geometry after flush (displacement volume) at shut-in for Case 4f (4 BPM, 10.1 ppg slurry, 2,500 BBL, injection into the "Lower Lobe'7. WESTERN ENERGY CONSULTANTS .' . Chevron North America Ex loration and Production Com n p pa y Ivan River Unit 13-31 aa~n Stress Width Profiles R'idth Contours .. Q H 2000 3000 4000 Page 38 JO Stress (psi) Width (ui.) Length (ft) Figure B-31. This is the inferred geometry after flush (displacement volume) at shut-in for Case 4g (4 BPM, 10.1 ppg slurry, 2,500 BBL, injection in the "Middle Lobe"). „~~ Stress Width Profiles Width Contours .. w_ Q J F- 2000 3000 4000 l0 Stress (psi) Width (ui.) Length (ft) Figure B-32. This is the inferred geometry after flush (displacement volume) at shut-in for Case 4h (4 BPM, 10.1 ppg slurry, 2,500 BBL, injection into the "Upper Lobe"). WESTERN ENERGY CONSULTANTS
