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Home My WebLink AboutDIO 038 • Disposal Injection Order #38 Kenai Loop #3 1. March 13, 2012 Buccaneer Application for DIO 2. April 15, 2012 Notice of Public Hearing, Affidavit of Publication, E -mail list, Bulk mail list 3. Emails 4. May 22, 2012 Hearing sign -in sheet 5. May 17, 2012 May 22, 2012 Public Hearing Transcript (cont. from May 17, 2012) Disposal Injection Order #38 Kenai Loop #3 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7 Avenue, Suite 100 Anchorage, Alaska 99501 Re: THE APPLICATION OF Buccaneer ) Disposal Injection Order No. 38 Alaska Operations, LLC for disposal ) of Class II oil field wastes by ) Sterling and Beluga Formations underground injection in the Sterling ) Kenai Loop # 3 Well and Beluga Formations in well Kenai ) Kenai Peninsula Borough, Alaska Loop # 3, Section 33, T6N, RI 1 W, ) S.M. (PTD 2110970) ) November 28, 2012 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 28th day of November, 2012. BY DIRECTION OF THE COMMISSION kb i i Jod / . Colom s ie Spe■ :1 Assistant to the Commission I STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7 Avenue, Suite 100 Anchorage, Alaska 99501 Re: THE APPLICATION OF Buccaneer ) Disposal Injection Order No. 38 Alaska Operations, LLC for disposal ) of Class II oil field wastes by ) Sterling and Beluga Formations underground injection in the Sterling ) Kenai Loop # 3 Well and Beluga Formations in well Kenai ) Kenai Peninsula Borough, Alaska Loop # 3, Section 33, T6N, R11 W, ) S.M. (PTD 2110970) ) November 28, 2012 IT APPEARING THAT: 1. Buccaneer Alaska Operations, LLC (Buccaneer) requested that the Alaska Oil and Gas Conservation Commission (AOGCC) issue an order authorizing underground disposal of Class II oil field waste fluids into well Kenai Loop #3. Buccaneer's Application for Disposal Injection Order was received by the AOGCC on March 16, 2012. 2. In accordance with 20 AAC 25.540, notice of opportunity for a public hearing was published in the Alaska Journal of Commerce on April 15, 2012. In addition, on April 10, 2012 the AOGCC published that notice of opportunity for public hearing on the State of Alaska Online Public Notices website, on the AOGCC's website, electronically transmitted the notice to all persons on the AOGCC' s email distribution list, and mailed printed copies of the notice to all persons on the AOGCC's mailing distribution list. The tentatively scheduled hearing date was May 17, 2012, but the hearing was subsequently rescheduled to May 22, 2012. 3. The AOGCC has authority to issue a disposal injection order. 20 AAC 25.252. 4. The AOGCC held the May 22, 2012 hearing despite not receiving any comments, protests or requests for a public hearing. Buccaneer provided testimony, and the hearing record was left open to allow Buccaneer to respond to questions from the AOGCC. 5. The AOGCC requested clarification of certain items on May 31, 2012. Buccaneer responded on June 5, 2012 with clarifications. 6. The AOGCC requested additional clarification on June 26, 2012. Buccaneer responded on July 5, 2012 with clarifications. 7. The information submitted by Buccaneer and public well history records for Kenai Loop #3 are the basis for this order. Disposal Injection Order 38 • • Page 2 of 9 Kenai Loop #3 November 28, 2012 FINDINGS: 1. Location of Adjacent Wells (20 AAC 25.252(c)(1)) Kenai Loop #3 is a gas development well drilled in 2011 to a total depth of 11,368 feet measured depth (MD), which is equivalent to 11,001' true vertical depth (TVD). The surface location is 3,394 feet from south line and 1,124 feet from west line of Section 33, Township 6N, Range 11W, Seward Meridian (S.M.). The bottom -hole location is 1,597 feet from the south line and 1,458 feet from the west line of Section 33, Township 6N, Range 11W, S.M. Kenai Loop #3 was the second well drilled to evaluate gas reserves within the Tyonek Formation of the Kenai Loop Field. The well did not find commercial quantities of natural gas, and it was suspended in accordance with AOGCC regulations in 2011. Nearby gas development well Kenai Loop Kenai Loop #1 was placed on regular production in December 2011. Kenai Loop #1 is the only well that penetrates the proposed injection zone within a %- mile radius of Kenai Loop #3. 2. Notification of Operators /Surface Owners (20 AAC 25.252(c)(2) and 20 AAC 25.252(c)(3)) Buccaneer is the only operator within a' -mile radius of the proposed disposal well. Surface property owners within % -mile radius of Kenai Loop #3 are State of Alaska, Mental Health Trust, and Cook Inlet Region, Inc., and they were provided copies of the disposal injection order application for Kenai Loop #3. 3. Geological Information on Disposal and Confining Zones (20 AAC 25.252(c)(4)) The proposed disposal injection operations will affect strata that are assigned to the Sterling Formation and the underlying Beluga Formation. Upper confinement for the proposed injection interval consists of numerous, laterally continuous tuffaceous claystone and siltstone layers and thin coal seams that lie within the Sterling Formation between 3,065' MD / TVD and 3,980' MD (3,961' TVD), a total true vertical thickness of 896'. Fracture - arrest and additional upper confinement will be provided by several laterally persistent, tuffaceous siltstone, claystone and thin coal layers that lie within the Beluga Formation between 5,453' and 5,720' MD (5,289' and 5,530' TVD), an interval that is 241 true vertical feet thick. Buccaneer's p lanned injection interval lies in the Beluga Formation between 5,721' and 7,025' MD (5,531' and 6,704' TVD), an interval that is 1,173 true vertical feet thick. Such a large interval is requested because, in this portion of the Cook Inlet Basin, Beluga Formation sediments were deposited by a network of small meandering and anastomosing rivers and streams that cut through a silt -and clay -rich alluvial plain. In this area, the Beluga Formation typically has a low net - sand -to- gross - thickness ratio and a low median permeability because of abundant diagenetic clay. The proposed injection interval contains several thin layers of fluvial sandstone. Laboratory measurements performed on nine rotary sidewall cores from these layers yielded a median Unless otherwise indicated, all depth- and thickness- related footages presented herein refer to the Kenai Loop #3 well. Disposal Injection Order 38 • Page 3 of 9 Kenai Loop #3 November 28, 2012 porosity of 21% (range: 1.9% to 29.1%) and a median permeability of 1 millidarcy (abbreviated as md; range: 0.001 and to 128 md). Buccaneer conducted two drill stem tests within the proposed injection interval. One test recovered formation water. The second test did not flow. Lower confinement and fracture arrest will be provided by laterally continuous layers of tuffaceous claystone, siltstone and thin coal seams that are common between 7,026' and 7,539' MD (6,705' and 7,191' TVD), an interval within the Beluga Formation that is 486 true vertical feet thick. Additional lower confinement for injected fluids will be provided by Beluga Formation tuffaceous siltstone, claystone and coal layers that lie between 7,539' and 8,554' MD (7,191' and 8,193' TVD), a total true vertical feet thickness of 1,002'. Maps provided by the operator do not display any faults within the confining intervals or the injection interval within the affected area. 4. Evaluation of Fluid Confinement (20 AAC 25.252(c)(9)) Buccaneer's application for a disposal injection order suggests Kenai Loop #3 could serve as a central Class II waste disposal injection facility supporting onshore and offshore oil and gas development activities in the Cook Inlet area. Disposal injection of drilling mud and slurried cuttings will require pressure sufficient to fracture the Beluga Formation. In support of fracture modeling, Buccaneer evaluated drilling and production wastes generated from the Cook Inlet area to determine a range of expected fluid densities. Buccaneer also evaluated rock properties from well data collected during the drilling of Kenai Loop wells #1 and #3. Buccaneer's fracture modeling effort addressed injected fluid densities, and rates and pressures for both expected and extreme injection conditions. Modeling predicts a radially - fractured zone of influence (i.e., waste plume area) — dependent on volume of injection and rock properties within the injection zone — that may extend as much as 1,600 feet laterally from the well and as much as 40 feet above and below the perforated interval. The only well penetrating this area — Kenai Loop #1 — has sufficient mechanical integrity to prevent the migration of fluids from the proposed injection zone. The potential 1,600 -foot lateral fracture extent renders a' /4 -mile area of review around Kenai Loop #3 too small for evaluating the worst -case scenario. Extending the area of review to ' /2- mile radius around Kenai Loop #3 accommodates the worst case lateral fracture, but does not add any additional wells for evaluation. Future wells within 1/2-mile must be constructed to ensure they do not serve as a conduit for fluid migration from the disposal zone. 5. Aquifer Exemption (20 AAC 25.252(c)(11)); Standard Laboratory Water Analysis of the Formation (20 AAC 25.252(c)(10)) Buccaneer applied for a Freshwater Aquifer Exemption (Aquifer Exemption Order No. 15, abbreviated as AEO 15) simultaneous to the application for this disposal injection order, received by the AOGCC on March 16, 2012. A standard laboratory analysis of Beluga Formation water is not available. However, a formation water sample was recovered during drill -stem testing within the planned disposal Disposal Injection Order 38 • Page 4 of 9 Kenai Loop #3 November 28, 2012 interval. Onsite analysis of that water sample yielded a measurement of 6,000 mg /1 chlorides. Based on well log calculations, Buccaneer concludes that the total dissolved solids (TDS) concentration of formation waters within proposed disposal interval is greater than 3,000 mg /l. Using similar methods, the AOGCC calculated TDS concentrations ranging from 6,500 to 8,500 mg /1 for the proposed disposal interval and the associated confining intervals. 6. Well Logs (20 AAC 25.252(c)(5)) Log data from Kenai Loop #3 are on file with the AOGCC. In their application, Buccaneer provided a type log that illustrates the proposed injection and confining zones. 7. Demonstration of Mechanical Integrity and Disposal Zone Isolation (20 AAC 25.252(c)(6)) Kenai Loop #3 is constructed as follows: 16 -inch conductor casing driven to 120 feet MD (120 feet TVD); 10 -3/4 -inch surface casing set at 3,027 feet MD (3,060 feet TVD); 7-5/8 - inch intermediate casing set at 8,330 feet MD (7,969 feet TVD); and 4.5 -inch liner installed from 8,100 feet MD to 11,362 feet MD (7,631 feet to 11,001 feet TVD). The well's plug - back depth is 6,375 feet MD (6,116 feet TVD). Buccaneer will perform a well workover to set up Kenai Loop #3 for disposal injection. Work will include drilling out the uppermost abandonment plug to expose existing perforations in the Beluga Formation at 6,435 feet to 6,450 feet MD (6,170 feet to 6,183 feet TVD) and 6,950 feet to 6,960 ft MD (6,634 feet to 6,643 feet TVD). The injection completion will consist of 3.5 -inch tubing and a permanent packer installed at 5,500 feet MD (5,331 feet TVD). An alternate setting depth for the injection packer was approved by AOGCC (Sundry No. 312 -100; May 14, 2012) as part of reconfiguring the well for disposal injection. Buccaneer reports that the 7 -5/8 -inch casing is cemented from the casing shoe to 4,850 feet MD (4,548 feet TVD), providing an estimated 1,585 feet of annular cement above the upper most injection perforations. Cement bonding in the 7 -5/8 -inch casing section opposite the injection and confining layers was evaluated with a cement bond log. The reported cement top of 5,000 feet MD (3,925 feet TVD) was calculated from the volume of cement pumped and an assessment of the cement placement operation. Buccaneer commits to performing mechanical integrity tests of the tubing and tubing- casing annulus (including packer) as part of the workover operations before injection commences. Additional baseline assessments and subsequent evaluations will be necessary to confirm the well has the proper mechanical integrity for disposal injection as proposed. 8. Disposal Fluid Type, Composition, Source, Volume, and Compatibility with Disposal Zone (20 AAC 25.252(c)(7)) Buccaneer requests approval to dispose of drilling, production, completion, workover wastes, and other associated wastes that are intrinsically derived from primary field operations. The volume of wastes to be injected into Kenai Loop #3 could be as much as 1,135,000 barrels of 2 Kenai Loop #3, Daily Drilling Report, October 25, 2011, in AOGCC Well History File No. 211 -097 (all information from this well are currently held confidential; the scheduled public release date is November 25, 2013) s AOGCC's calculation techniques are compatible with EPA Guidance Document "Survey of Methods to Determine Total Dissolved Solids Concentrations" (EPA LOE Contract No. 68 -03 -3416, Work Assignment No. 1 -0 -13, KEDA Project No. 30- 956, October 1988, Revised October 1989). Disposal Injection Order 38 • • Page 5 of 9 Kenai Loop #3 November 28, 2012 Class II wastes over the expected life of the well. Buccaneer expects daily injection volumes of 155 barrels with excursions up to approximately 1,000 barrels, rates up to 4 barrels per minute, and slurry densities up to 10.5 pounds per gallon. Fracture modeling evaluated several conservative slurry injection scenarios, including: a single 2,500- barrel batch injected at 6 barrels per minute; and injecting 155 barrels per day at a rate of 3 barrels per minute for 5 years. Buccaneer states that injected slurry will not penetrate the upper or lower confining layers based on the slurry fracture modeling, nor will it intersect any well penetrating the injection zone. Injected fluids are expected to be compatible with the lithology and resident water of the injection zone based on operating experience and performance (e.g., pressures, rates, and volumes) of numerous disposal injection wells in surrounding fields that have the same receiving formation —the Beluga Formation —as proposed for Kenai Loop #3. There have been no reported compatibility issues associated with disposal injection into the Beluga Formation at other fields in the Cook Inlet area. 9. Estimated Injection Pressures (20 AAC 25.252(c)(8)) Buccaneer estimates that the average surface injection pressure will be between 1,800 psig and 3,000 psig. The maximum surface injection pressure could reach 6,000 psig if sporadic plugging of perforations or fracture flow channels occurs. 10. Mechanical Condition of Wells Penetrating the Disposal Zone Within a 1 /4 -Mile Radius of Kenai Loop #3 (20 AAC 25.252(c)(12)) Kenai Loop #1 is the only well to penetrate the proposed disposal injection zone within 1 /4- mile radius of Kenai Loop #3. Well construction records show that both the proposed injection well and producing well Kenai Loop #1 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 AOGCC's files. CONCLUSIONS: 1. The 20 AAC 25.252 requirements for approval of an underground disposal application are met. 2. Kenai Loop #3 was drilled as a gas exploration well, but it did not find commercial quantities of gas. 3. Buccaneer's planned injection interval in Kenai Loop #3 lies in the Beluga Formation between 5,721' (5,531' TVD) and 7,025' (6,704' TVD), an interval that is about 1,173 true vertical feet thick. This large interval is necessary because, in this portion of the Cook Inlet Basin, the Beluga Formation displays a low net - sand -to- gross - thickness ratio and low permeability. 4. Upper confinement will be provided by 896 true vertical feet of laterally continuous tuffaceous claystone and siltstone layers and thin coal seams within the Sterling Formation. Fracture- arrest and additional upper confinement will be provided by 241 true vertical feet of tuffaceous siltstone, claystone layers and thin coal seams within the underlying Beluga Formation. Disposal Injection Order 38 • • Page 6 of 9 Kenai Loop #3 November 28, 2012 5. Lower confinement and fracture arrest will be provided by 486 true vertical feet of laterally continuous layers of Beluga Formation tuffaceous claystone, siltstone and thin coal seams. Additional lower confinement will be provided by 1,002 true vertical feet of tuffaceous siltstone, claystone layers and thin coal seams. 6. No significant faults are present near area that will be affected by the proposed injection operations. 7. TDS content of formation water within the proposed injection and confining intervals is greater than 3,000 mg/1 and less than 10,000 mg/l. AEO 15 (Corrected)— issued by the AOGCC on November 28, 2012 —exempts aquifers occurring in the Sterling and Beluga Formations that are stratigraphically equivalent to, and lie within a radius of V2 mile of, the interval from 3,980 to 7,539 feet MD in well Kenai Loop #3. 8. No compatibility concerns relating to the injected fluids and in -situ formation fluids have been identified in connection with the injection of a similar waste fluid streams into the Beluga Formation at other locations within the Cook Inlet Basin. 9. Fracture modeling indicates that disposed waste fluids will be contained within the receiving interval by confining lithologies, cement isolation of the well bore, and planned operating conditions. Modeling of the most extreme injection conditions predicts that fractures will not penetrate the upper confining zone, or breach the lower confining zone. Within the predicted fracture geometry for the most extreme injection conditions modeled, Kenai Loop #1 is the only penetration. Sufficient mechanical integrity has been demonstrated in Kenai Loop #1 to from the proposed injection zone. The adequacy prevent the migration of fluids p p injection q y of mechanical integrity for new wells constructed within the worst -case predicted fracture geometry surrounding Kenai Loop #3 will be assessed in each well's permit to drill to ensure injected fluids remain confined to the intended receiving interval. 10. 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. 11. Actual performance information gained during drilling, injection and remedial well operations must be monitored during the life of the disposal project to ensure appropriate operation of the field. A requirement for formal review of the disposal injection performance every five years will ensure the findings, conclusions, and rules of this order remain valid. THEREFORE, IT IS ORDERED THAT disposal injection is authorized into the NOW, P J Beluga Formation within well Kenai Loop #3 subject to each of the following requirements: RULE l: Injection Strata for Disposal The underground disposal of Class II oil field waste fluids is permitted into the Beluga Formation within Kenai Loop #3 in the interval from 5,721 feet to 7,025 feet MD (5,531 feet to 6,704 feet TVD). The AOGCC may immediately suspend, revoke, or modify this authorization if injected fluids are not confined by the upper and lower confining zones. Disposal Injection Order 38 0 • Page 7 of 9 Kenai Loop #3 November 28, 2012 RULE 2: Authorized Fluids This authorization is limited to Class II oil field waste fluids generated during drilling, production, workover, or abandonment operations, specifically: Drilling fluids; drill cuttings; well workover fluids; stimulation fluids and solids; produced water; rig wash water; formation materials; naturally occurring radioactive materials; scale; tracer materials; glycol dehydration; reserve pit fluids; chemicals used in the well or for production processing at the surface (in direct contact with produced fluids); and precipitation accumulating in drilling and production impoundment areas. Administrative action under Rule 8 of this order is required prior to initiating commercial Class II disposal injection in Kenai Loop #3. RULE 3: Injection Rate and Pressure Injection pressures must be maintained such that the injected fluids do not fracture the confining intervals or migrate out of the approved injection stratum. Disposal injection is authorized at (a) rates that do not exceed 4 barrels per minute and (b) wellhead injection pressures that do not exceed 6,000 psig. RULE 4: Demonstration of Mechanical Integrity The mechanical integrity of Kenai Loop #3 must be demonstrated before injection begins and before returning the well to service following a workover affecting mechanical integrity. An AOGCC- witnessed mechanical integrity test must be performed after injection is commenced for the first time in Kenai Loop #3, to be scheduled when injection conditions (temperature, pressure, rate, etc.) have stabilized. Subsequent mechanical integrity tests must be performed at least once every two years after the date of the first AOGCC- witnessed test. Mechanical integrity tests must be conducted in accordance with AOGCC Industry Guidance Bulletin No. 10 -02, "Mechanical Integrity Testing" and done to a test pressure equal to the maximum anticipated surface injection pressure. The AOGCC must be notified at least 24 hours in advance of each such test to enable a representative to witness the test. The results of all mechanical integrity demonstrations and Buccaneer's interpretation of those results shall be provided to the AOGCC within seven (7) days of completing the test. RULE 5: Well Integrity Failure and Confinement Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by injection rate, operating pressure observation, test, survey, log, or any other evidence, the Operator shall notify the AOGCC within 24 hours and submit a plan of corrective action on a Form 10 -403 for AOGCC 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 AOGCC. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the AOGCC for Kenai Loop #3 if the well indicates any well integrity failure or lack of injection zone isolation. Disposal Injection Order 38 • • Page 8 of 9 Kenai Loop #3 November 28, 2012 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 Kenai Loop #3 must be documented and available to the AOGCC 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 AOGCC by April 1 of each year covering injection operations during the previous calendar 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. An assessment of the applicability of the injection order findings, conclusions, and rules based on actual performance shall be included with the annual performance report. RULE 7: Notification of Improper Class II Injection Injection of fluids other than those listed in Rule 2 without prior authorization is considered improper Class II injection. Upon discovery of such an event, the operator must immediately notify the AOGCC, provide details of the operation, and propose actions to prevent recurrence. Additionally, notification requirements of any other State or Federal agency remain the operator's responsibility. If fluids are found to be fracturing through a confining interval or migrating out of the approved injection stratum, the Operator must immediately shut in well. Upon discovery of such an event, the operator must immediately notify the AOGCC, provide details of the operation, and propose actions to prevent recurrence. Injection may not be restarted unless approved by the AOGCC. RULE 8: Administrative Action Upon proper application, or its own motion, and unless notice and public hearing is otherwise required, the AOGCC may administratively waive the requirements of any rule stated herein or administratively amend this order 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 an increased risk of fluid movement into freshwater or outside of the authorized injection zone. RULE 9: Compliance Operations must be conducted in accordance with the requirements of this order, AS 31.05, and (unless specifically superseded by AOGCC order) 20 AAC 25. Noncompliance may result in the suspension, revocation, or modification of this authorization and other penalties. Disposal Injection Order 38 II Page 9 of 9 Kenai Loop #3 November 28, 2012 RULE 10: Reauthorization The Operator must apply to reauthorize disposal injection at intervals not exceeding five (5) years from the effective date of this Order. The application shall include an assessment of the Order findings, conclusions, and rules taking into account actual injection performance. DONE at Anchorage, Alaska, and dated November 28, 2012. i 1� sir 1 ` � / :� L Cath P. Foerster Daniel T. Seamount, Jr. * ► *man q.,� -, _ Cha r, Commissioner Commissioner • om _ issioner ',,:k ,,, f , I RECONSIDERATION AND APPEAL NOTICE "' - a.* 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 a§+tyi °° ; >i. aves, AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration oft c matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[tlhe questions reviewed on appeal are limited to the questions presented to the AOGCC by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. 1 1 �, ® Bend al ong line to • Easy Peel® Labels ' — -- ' 0, AVERY® ssonn 1 ' ed Paper expose Pop -up Edge"' d Use Avery ® Template 5160® j, Mary Jones David McCaleb XTO Energy, Inc. IHS Energy Group George Vaught, Jr. Cartography GEPS P.O. Box 13557 810 Houston St., Ste. 200 5333 Westheimer, Ste. 100 Denver, CO 80201 -3557 Ft. Worth, TX 76102 -6298 Houston, TX 77056 Richard Neahring man Mark Wed Jerry Hodgden NRG Associates Mark Wed Hodgden Oil Company President Hal 40818` St. 6900 Arctic Blvd. Golden, CO 80401 -2433 P.O. Box 1 Springs, Anchorage, AK 99502 Colorado Springs, CO 80901 Bernie Karl CIRI Tools K &K Recycling inc. Land Department 795 E. Baker Oil it Ct. P.O. Box 58055 P.O. Box 93330 Anchorage, AK 99515 -4295 Fairbanks, AK 99711 Anchorage, AK 99503 North Slope Borough Richard Wagner Gordon Severson Planning Department P.O. Box 60868 3201 Westmar Cir. P.O. Box Fairbanks, AK 99706 Anchorage, AK 99508-4336 Barrow, AK K 99723 Jack Hakkila Darwin Waldsmith James Gibbs P.Q. Box 190083 P.O. Box 39309 P.O. Box 1597 Anchorage, AK 99519 Ninilchik, AK 99639 Soldotna, AK 99669 Penny Vadla 399 W. Riverview Ave. Soldotna, AK 99669 -7714 *a c... • ‘_ .\ , Q c. (r25C(Q-2A -, 1.\ i ® Re p l iez la ha chure afro de W WW . RVe o • 7 v OR Etiquettes faciles a peter S ens d Repliez dr ' ... , ,_ _ ...r A• ...midi1 I ) r..eAO Easy Peel® Labels 1 • OM. Bend along line to I 0 AVERY® 5960TM ; Use Avery® Template 5160® j eed Paper expose Pop -up Edgerm j j Mark R. Landt Buccaneer Alaska, LLC 952 Echo Ln., Ste. 420 Houston, TX 77024 .t W2s20 \Z I i k .•.. Irtiquettes faciles a peter ........ � � 1 • Repliez a la hachure afin del www.avery.com _ Sens de _ nnr I i_ann_rn_evoav 1 S • Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Wednesday, November 28, 2012 3:11 PM To: Singh, Angela K (DOA); Ballantine, Tab A (LAW); Bettis, Patricia K (DOA); Brooks, Phoebe L (DOA); Colombie, Jody J (DOA); Crisp, John H (DOA); Davies, Stephen F (DOA); Ferguson, Victoria L (DOA); Fisher, Samantha J (DOA); Foerster, Catherine P (DOA); Grimaldi, Louis R (DOA); Johnson, Elaine M (DOA); Jones, Jeffery B (DOA); Laasch, Linda K (DOA); Bender, Makana K (DOA); McIver, Bren (DOA); McMains, Stephen E (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Norman, John K (DOA); Okland, Howard D (DOA); Paladijczuk, Tracie L (DOA); Pasqua!, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Wallace, Chris D (DOA); Aaron Gluzman; Aaron Sorrell; Bruce Williams; Bruno, Jeff J (DNR); caunderwood @marathonoil.com; Casey Sullivan; Dale Hoffman; David Lenig; Donna Vukich; Eric Lidji; Erik Opstad; Franger, James M (DNR); Gary Orr; Smith, Graham 0 (PCO); Greg Mattson; Heusser, Heather A (DNR); James Rodgers; Jason Bergerson; Jennifer Starck; jill .a.mcleod @conocophillips.com; Joe Longo; King, Kathleen J (DNR); Lara Coates; Lois Epstein; Marc Kuck; Steele, Marie C (DNR); Matt Gill; Melissa Okoola; Ostrovsky, Larry (DNR sponsored); Bettis, Patricia K (DOA); Perrin, Don J (DNR); Peter Contreras; Pexton, Scott R (DNR); Richard Garrard; Ryan Daniel; Sandra Lemke; Talib Syed; Terrace Dalton; Wayne Wooster; Woolf, Wendy C (DNR); William Hutto; William Van Dyke; (michael.j.nelson @conocophillips.com); AKDCWeIIIntegrityCoordinator; alaska @petrocalc.com; Alexander Bridge; Anna Raff; Barbara F Fullmer; bbritch; bbohrer @ap.org; Bill Penrose; Bill Walker; Bowen Roberts; Bruce Webb; Claire Caldes; Cliff Posey; Crandall, Krissell; D Lawrence; Daryl J. Kleppin; Dave Harbour; Dave Matthews; David Boelens; David Duffy; David House; Scott, David (LAA); David Steingreaber; Davide Simeone; ddonkel @cfl.rr.com; Elowe, Kristin; Francis S. Sommer; Gary Laughlin; schultz, gary (DNR sponsored); ghammons; Gordon Pospisil; Gorney, David L.; Greg Duggin; Gregg Nady; Gregory Geddes; gspfoff; Jdarlington (jarlington @gmail.com); Jeanne McPherren; Jones, Jeffery B (DOA); Jerry McCutcheon; Jill Womack; Jim White; Jim Winegarner; Joe Lastufka; news @radiokenai.com; Easton, John R (DNR); John Garing; John Spain; Jon Goltz; Jones, Jeffrey L (GOV); Judy Stanek; Houle, Julie (DNR); Julie Little; Kari Moriarty; Kaynell Zeman; Keith Wiles; Kelly Sperback; Gregersen, Laura S (DNR); Luke Keller; Marc Kovak; Mark Dalton; Mark Hanley (mark.hanley @anadarko.com); Mark P. Worcester; Kremer, Marguerite C (DNR); Michael Jacobs; Mike Bill; mike @kbbi.org; Mike Morgan; Mikel Schultz; Mindy Lewis; MJ Loveland; mjnelson; mkm7200; knelson @petroleumnews.com; Nick W. Glover; NSK Problem Well Supv; Patty Alfaro; Decker, Paul L (DNR); Paul Mazzolini; Randall Kanady; Randy L. Skillern; Randy Redmond; Delbridge, Rena E (LAA); Renan Yanish; Robert Brelsford; Robert Campbell; Ryan Tunseth; Scott Cranswick; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); Sondra Stewman; Stephanie Klemmer; Moothart, Steve R (DNR); Steven R. Rossberg; Suzanne Gibson; sheffield @aoga.org; Taylor, Cammy 0 (DNR); Davidson, Temple (DNR); Teresa Imm; Thor Cutler; Tim Mayers; Tina Grovier; Todd Durkee; Tony Hopfinger; trmjrl; Vicki Irwin; Walter Featherly; yjrosen@ak.net Subject: AEO 15 and DIO 38 (Kenai Loop Field) Attachments: aeo015.pdf; dio038.pdf Jody J. Colombie Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907)793 -1221 (phone) (907)276 -7542 (fax) 1 4 i • 1 ALASKA OIL AND GAS CONSERVATION COMMISSION 2 In the Matter of Buccaneer Alaska ) 3 Operations, LLC's Request for ) 4 the Exemption of Fresh Water ) 5 Aquifers in the Kenai Loop Field ) 6 and a Disposal Injection Order ) 7 for Kenai Loop No. 3. ) 8 ) 9 Docket No.: AEO -12 -001 10 DIO -12 -002 11 ALASKA OIL and GAS CONSERVATION COMMISSION 12 VOLUME I 13 PUBLIC HEARING 14 Anchorage, Alaska 15 May 17, 2012 16 9:00 o'clock a.m. 17 BEFORE: Cathy Foerster, Chair 18 Daniel T. Seamount, Commissioner 19 John K. Norman, Commissioner 20 Recorded and Transcribed by: 21 Computer Matrix Court Reporters 22 135 Christensen Drive, Suite 2 23 Anchorage, Alaska 99501 24 (907) 243 - 0668 /sahile @gci.net • • 1 TABLE OF CONTENTS 2 Remarks by Chair Foerster 03 2 • • 1 P R O C E E D I N G S 2 (On record - 9:00 a.m.) 3 CHAIR FOERSTER: All right. We're going to call 4 this hearing to order. Today is May 17th, 2012, it's a 5 little after 9:00 a.m. Were located at 333 West Seventh 6 Avenue, Suite 100, Anchorage, Alaska, the offices of the 7 Alaska Oil & Gas Conservation Commission. 8 I'm Commissioner Cathy Foerster, to my left is 9 Commissioner Dan Seamount and to my right is Commissioner 10 John Norman. 11 Computer Matrix Court Reporters will be recording 12 today's proceedings, you can get a copy of the transcript 13 from Computer Matrix Court Reporters. 14 The Commissioners look around the room and see 15 that the person requesting this hearing or the entity 16 requesting this hearing is not present. Mr. Regg is 17 sitting up front, Mr. Regg from the AOGCC. Can you tell 18 us what you know about -- were they notified, did they 19 know to be here? 20 MR. REGG: We exchanged electronic mail messages 21 on April 17. They asked what were -- where we were at in 22 terms of processing the application and we told them we 23 were doing a technical review. On May 3rd they again 24 requested some clarification that there was a hearing on 25 May 17th, they were aware of a hearing on May 17th based 3 • • II I 1 on our public notice and as to how they should proceed. 2 We returned an electronic mail message to them and told 3 them it is unlikely the hearing will be vacated so you 4 will need to be prepared to address the items listed in 5 AOGCC's public hearing guidelines which are posted online 6 at doa.alaska.gov /aogcc, the pubic hearing guidelines. 7 So they were aware that we were expecting them to testify 8 at this time. 9 CHAIR FOERSTER: Has anyone heard anything from 10 them to your knowledge? 11 MR. REGG: I have not anything from Buccaneer 12 since May 3rd. 13 CHAIR FOERSTER: Okay. Ms. Fisher or Ms. 14 Colombie, Mr. Davies, has anyone -- has any of you heard 15 anything from them? 16 IN UNISON: No. 17 CHAIR FORESTER: Okay. Probably the right thing 18 to do would be to continue this hearing and give them 19 another chance to come and present their case. Do you 20 guys have any problem with that? Dan. 21 COMMISSIONER SEAMOUNT: I've got something to say 22 before 23 CHAIR FOERSTER: Okay. 24 COMMISSIONER SEAMOUNT: I make a motion -- 25 what do I do, make a motion? 4 1 • 1 CHAIR FOERSTER: Yeah. 2 3 COMMISSIONER SEAMOUNT: Okay. Mr. Davies, could 4 you ask Buccaneer to provide a better type log? 5 MR. DAVIES: Certainly. Y 6 COMMISSIONER SEAMOUNT: One that's more readable. 7 So, I mean, it could be expanded, not just eight and a 8 half by 11, they could make it big so we can see what's 9 going on in those confining and -- proposed confining and 10 injection zones. 11 CHAIR FOERSTER: Commissioner Norman, do you have 12 any problem with that? 13 COMMISSIONER NORMAN: No, I don't. I think we 14 ought to move -- it sounds to me like 9:30 on Tuesday the 15 22nd would be the appropriate time so I would move that 16 this hearing be continued until 9:30 a.m. on Tuesday the 17 22nd. 18 COMMISSIONER SEAMOUNT: I second. 19 CHAIR FOERSTER: All right. All opposed. 20 (No opposing votes) 21 CHAIR FOERSTER: All in favor. 22 IN UNISON: Aye. 23 CHAIR FOERSTER: All right. Well, this hearing 24 is therefore continued to 9:30 on May 22nd and let's make 25 sure that Buccaneer knows they're supposed to be here. 5 • 1 So I would ask, Mr. Regg, you contact your contact, Mr. 2 Davies, you contact yours, Ms. Colombie, you contact 3 yours. If they get three communications with the same 4 information in it then there should be less confusion for 5 them next time. 6 And if no one else has anything to add 7 COMMISSIONER NORMAN: Move to recess and 8 continue. 9 COMMISSIONER SEAMOUNT: I second. 10 CHAIR FOERSTER: All in favor. 11 IN UNISON: Aye. 12 CHAIR FOERSTER: Opposed. 13 (No opposing votes) 14 CHAIR FOERSTER: Okay. This hearing is recessed 15 to reconvene on May 22nd at 9:30. 16 (Recessed - 9:05 a.m.) 17 (END OF PROCEEDINGS) 6 • 1 TRANSCRIBER'S CERTIFICATE 2 I, Salena A. Hile, hereby certify that the 3 foregoing pages numbered 02 through 07 are a true, 4 accurate, and complete transcript of proceedings in 5 Docket No.'s AEO -12 -001, DIO -12 -002, Volume I transcribed 6 under my direction from a copy of the electronic sound 7 recording to the best of our knowledge and ability. 8 9 10 Date Salena A. Hile, Transcriber 11 7 S • 1 ALASKA OIL AND GAS CONSERVATION COMMISSION 2 In the Matter of Buccaneer Alaska ) 3 Operations, LLC's Request for ) 4 the Exemption of Fresh Water ) 5 Aquifers in the Kenai Loop Field ) 6 and a Disposal Injection Order ) 7 for Kenai Loo p No. 3. ) 8 ) 9 Docket No.: AEO -12 -001 10 DIO -12 -002 11 ALASKA OIL and GAS CONSERVATION COMMISSION 12 VOLUME II 13 PUBLIC HEARING 14 Anchorage, Alaska 15 May 22, 2012 16 9:30 o'clock a.m. 17 BEFORE: Cathy Foerster, Chair 18 Daniel T. Seamount, Commissioner 19 John K. Norman, Commissioner 20 Recorded and Transcribed by: 21 Computer Matrix Court Reporters 22 135 Christensen Drive, Suite 2 23 Anchorage, Alaska 99501 24 (907) 243 - 0668 /sahile @gci.net S • 1 TABLE OF CONTENTS 2 Opening remarks by Chair Foerster 10 3 Testimony by Mr. Hennigan 14 Y Y g 9 • 1 P R O C E E D I N G S 2 (On record - 9:30 a.m.) 3 CHAIR FOERSTER: I'd like to call this hearing 4 to order. Today is May 22nd, it's about 9:30 a.m. 5 We're located at 333 West Seventh Avenue, Suite 100, 6 Anchorage, Alaska, those are the offices of the Alaska 7 Oil & Gas Conservation Commission. 8 I'm Commissioner Cathy Foerster, to my left is 9 Commissioner Dan Seamount and to my right is 10 Commissioner John Norman. Reporters will be 11 Computer Matrix Court Re P 12 recording today's proceedings, you can get a copy of 13 the transcript from Computer Matrix Court Reporters. 14 The Commissioners would like to remind those 15 who are testifying to speak into the microphones so 16 that persons in the back of the room can hear and so 17 that the court reporter can get a clear recording. 18 Today'we're reviewing Docket Nos. AE0 -12 -001 19 and DIO -12 -002. Buccaneer Alaska Operations, LLC has 20 applied for an order exempting fresh water aquifers in 21 the Kenai Loop Field, Kenai Peninsula Borough, in 22 conformance with 20 AAC 25.440 as well as a disposal 23 injection order authorizing the injection of used 24 drilling mud and other UIC program class two eligible 25 fluids into the Sterling and Beluga formations in the 10 • • I I 1 Kenai Loop Field. 2 Notice of this hearing was published on April 3 15th, 2012 in the Journal of Commerce as well as the 4 state of Alaska online notices and the AOGCC website on 5 April 10, 2012. This hearing is being held in 6 accordance with 20 AAC 25.540 of the Alaska 7 Administrative Code. The hearing will be recorded. 8 All right. Before we begin do you have any 9 words of wisdom, Commissioner Seamount? 10 COMMISSIONER SEAMOUNT: Not at this time, Madam 11 Chair. 12 CHAIR FOERSTER: Commissioner Norman. 13 COMMISSIONER NORMAN: Nothing. 14 CHAIR FOERSTER: Let the record reflect that 15 neither one of them chose to be wise. 16 Let's see, I think we have a representative 17 from Buccaneer here. 18 19 CHAIR FOERSTER: And you're Mr. Hennigan? 20 MR. HENNIGAN: Yes, ma'am. 21 CHAIR FOERSTER: And you'd like to testify? 22 MR. HENNIGAN: Yes, ma'am, I would. 23 CHAIR FOERSTER: Okay. Would you like to be 24 considered as an expert witness in an area of expertise 25 like petroleum engineering, geology, law, land? 11 • • 1 MR. HENNIGAN: My area of concentration is 2 engineering. 3 CHAIR FOERSTER: Okay. All right. So would 4 you like to be considered as an expert engineering 5 witness? 6 7 CHAIR FOERSTER: All right. Could you please 8 explain to us what your qualification -- your education 9 and qualifications and experience are to be so that we 10 can make a decision as to whether to consider you as an 11 expert witness. 12 MR. HENNIGAN: Yes, ma'am. I'd like to do 13 that, but first I'd like to apologize for last week, it 14 was my ignorance and my error and I take full 15 responsibility and I apologize because the monies and 16 the time it took away from the state of Alaska. 17 CHAIR FOERSTER: Well, thank you, Mr. Hennigan. 18 MR. HENNIGAN: Okay. My area of expertise is 19 that -- my initial degree is in mathematics, I did a 20 master's plus curriculum in mathematics, but never did 21 finish my thesis defense. 22 I went to work for 23 (Off record comments - microphone) 24 MR. HENNIGAN: I went to work for Bayroid 25 Drilling Fluids and was area manager for Bayroid in 12 • • 1 both drilling mud and completion fluids. And I worked 2 with the state of Louisiana in their 29B conversion 3 from their old records -- old methodology. I went to 4 work in a -- for Solids Control & Completion Filtration 5 Company and then Maratho n. I worked and did my 6 master's in engineering management at night, worked 10 7 years at Marathon as both a drilling engineer and as a 8 specialist, then as a drilling foreman on the rigs, 9 both deepwater and onshore and all over the world. 10 Following that I went to work for Petroleum Engineers 11 International as a consultant and have worked for 12 Forest Oil, Kerr - McGee, 20 or 30 clients all over the 13 world. And when I was at Marathon I did consulting for 14 the group that was working on the Steelhead in Kenai, 15 did some of their work. 16 And that's my basic background. 17 CHAIR FOERSTER: Okay. Do you have any 18 questions? 19 COMMISSIONER SEAMOUNT: Mr. Hennigan, do you 20 have any experience in petroleum geology? 21 MR. HENNIGAN: Minimal. 22 COMMISSIONER SEAMOUNT: So you're mainly a 23 drilling engineer? 24 MR. HENNIGAN: Drilling and completion. 25 COMMISSIONER SEAMOUNT: Okay. All right. And 13 • • 1 what offices did you work out of for Marathon? 2 MR. HENNIGAN: I worked out of the Lafayette 3 and Houston offices and worked mostly on a 28 and 28 4 rotational basis. 5 COMMISSIONER SEAMOUNT: Okay. Thank you. I've 6 no further questions. 7 CHAIR FOERSTER: Commissioner Norman. 8 COMMISSIONER NORMAN: Did we swear Mr. 9 Hennigan? 10 CHAIR FOERSTER: No, we did not. Let's -- do 11 we do that 12 COMMISSIONER NORMAN: Yes. Mr. Hennigan, we're 13 about to swear you in which is a customary practice and 14 then would appreciate it if as part of that you would 15 acknowledge that all of your testimony that preceded 16 that is covered by the oath that you've given. 17 MR. HENNIGAN: I 18 COMMISSIONER NORMAN: Thank you so much. 19 CHAIR FOERSTER: All right. I'm kind of new to 20 this chair thing and I was going to swear you in after 21 we decided to accept you. All right. 22 (Oath administered) 23 MR. HENNIGAN: So help me god, I do. 24 STEPHEN F. HENNIGAN 25 called as a witness on behalf of Buccaneer Alaska 14 • 1 Operations, LLC, stated as follows on: 2 DIRECT EXAMINATION 3 CHAIR FOERSTER: Okay. And your name for the 4 record again? 5 MR. HENNIGAN: My name is Stephen F. Hennigan. 6 CHAIR FOERSTER: And you represent? 7 MR. HENNIGAN: Buccaneer Alaska Operations, 8 LLC. 9 CHAIR FOERSTER: Okay. All right. Did you 10 have any other questions? 11 COMMISSIONER NORMAN: Nothing further. 12 CHAIR FOERSTER: Okay. 13 COMMISSIONER SEAMOUNT: I have one more 14 question. 15 CHAIR FOERSTER: All right. 16 COMMISSIONER SEAMOUNT: Are you a regular 17 employee of Buccaneer or are you consulting for them? 18 MR. HENNIGAN: I'm a consultant for them. 19 COMMISSIONER SEAMOUNT: What's the name of your 20 consulting company? 21 MR. HENNIGAN: Petroleum Engineers, Inc., a 22 subsidiary of Hamilton Group. 23 COMMISSIONER SEAMOUNT: Okay. Thank you. 24 25 (No comments) 15 • • 1 CHAIR FOERSTER: I have a question. Did you 2 say, and maybe I missed it, where you got your degrees? 3 MR. HENNIGAN: I did not say where I got my 4 degrees. My first degree was from McNeese State 5 University in Lake Charles, Louisiana, my master's in 6 engineering management was from -- it's now called 7 University of Lafayette -- University of Louisiana at 8 Lafayette. 9 CHAIR FOERSTER: Used to be USL? 10 MR. HENNIGAN: Used to be USL. 11 CHAIR FOERSTER: Okay. Commissioner Seamount, 12 13 expert witness in the 14 COMMISSIONER SEAMOUNT: I have none. 15 CHAIR FOERSTER: field of engineering? 16 COMMISSIONER NORMAN: No objection. I move 17 that we accept this witness as an expert witness in the 18 area of engineering as he described. 19 COMMISSIONER SEAMOUNT: I second. 20 CHAIR FOERSTER: Okay. All in favor. 21 IN UNISON: Aye. 22 CHAIR FOERSTER: All opposed. 23 (No opposing votes) 24 CHAIR FOERSTER: All right. You have been 25 accepted as an expert witness. Please proceed with 16 • • 1 your testimony and if you have any written documents 2 that you're submitting we'd appreciate it if you'd give 3 a copy to the court reporter for her records as well. 4 MR. HENNIGAN: I have one that I'll leave with 5 the courtroom reporter. If you don't mind I'd like to 6 talk from that 1 7 CHAIR FOERSTER: Okay. 8 MR. HENNIGAN: is that okay? 9 CHAIR FOERSTER: Okay. It would be good if you 10 had -- if you could leave copies for us and for her, 11 but 12 MR. HENNIGAN: Ma'am, I'm really sorry, I had 13 no idea, I could have made copies -- a hundred copies, 14 I have -- I apologize. 15 CHAIR FOERSTER: Why don't we take just a three 16 minute recess and our Special Assistant, Jody Colombie, 17 will get some copies made. 18 MR. HENNIGAN: Sure. 19 CHAIR FOERSTER: Okay. Were recessed. 20 (Off record) 21 (On record) 22 CHAIR FOERSTER: Mr. Hennigan, you can proceed 23 with your testimony. 24 MR. HENNIGAN: Which would you like addressed 25 first, the disposal injection or the aquifer? 17 • • 1 CHAIR FOERSTER: Let's do the aquifer 2 exemption, is that okay? 3 MR. HENNIGAN: That's fine. If you have the 4 aquifer exemption order in front of you, there are a 5 couple of attachments there at the back that illustrate 6 our analysis of the fresh water placement in the 7 potential zones that were looking to -- that were 8 applying for the exemption on. Typically it shows that 9 the fresh water kind of stops at about 3,300 feet and 10 then begins again at approximately 8,500 feet. This is 11 -- that illustrates to us that the area were asking 12 for an exemption on is in the three to 10,000 area of 13 classification and it's typically the Sterling and 14 Beluga formations. Sterling starts at approximately 15 3,300, 3,400 foot and the base of the Beluga's about 16 8,400 foot. 17 And to give you a little bit of analysis there 18 is that with the studies that I've been able to find 19 throughout the Cook Inlet area that it appears that the 20 water contains a large amount of bicarbonates and other 21 total dissolved solids. So the reading on the 22 resistivity log is typically slightly in error and that 23 makes the interpretation much more difficult. But we 24 were fortunate -- oh, and most of the calculations and 25 taking the resistivity values back to equivalent part 18 II I • I I 1 per million of chloride used a -- the arches used a 2 certain standard for the constants where we're able to 3 get a sample of tested water from the Buccaneer Kenai 4 Loop Number 1 and it tested 6,000 chlorides. And we 5 went back and we happened to have -- and placed that at 6 the equivalent perf depth and did a recalculation of 7 the salinities. So what we have shown on that graph is 8 the minimal total dissolved solids, so it should be 9 higher. And we feel that meets all the criteria and 10 we're asking for an exemption in those depths. 11 And that's the engineering idea. 12 CHAIR FOERSTER: Okay. Is that 13 MR. HENNIGAN: Oh, we did a complete survey of 14 the area, we called the Department of Hydrology, they 15 gave us all the listings of all the water wells and 16 there's nothing that is of impact anywhere close, far 17 outside 18 CHAIR FOERSTER: You mean that go to the depths 19 that you're 20 MR. HENNIGAN: The greatest depth was the city 21 of Kenai and I think it's 360 feet talking from the top 22 of my head, and that was the deepest water well and 23 it's close 24 CHAIR FOERSTER: Okay. 25 MR. HENNIGAN: probably one of the closest 19 • • 1 wells and its by the airport. 2 CHAIR FOERSTER: Okay. Do you have any 3 questions, Commissioner Seamount? 4 COMMISSIONER SEAMOUNT: Three hundred -sixty 5 feet is the depth of my water well. 6 MR. HENNIGAN: Most of them -- going out 7 further most of them we checked were around 50 feet and 8 they're like half mile, mile away. 9 COMMISSIONER SEAMOUNT: Uh -huh. Okay. I do 10 have a question on this Figure 1 of the AEO 11 application. I see data points all over the place and 12 I realize you say that the minimum salinity or the -- 13 is it the minimum, yeah, minimum salinity is shown 14 right at the edge here, right? 15 MR. HENNIGAN: Yes, sir, that's the 3,000 part 16 per million. 17 COMMISSIONER SEAMOUNT: Okay. And what you did 18 19 saturation was 100 on this 20 MR. HENNIGAN: Uh -huh. 21 COMMISSIONER SEAMOUNT: is that correct? 22 MR. HENNIGAN: Yes, sir. 23 COMMISSIONER SEAMOUNT: Okay. And all these 24 that go way out here into the super high salinity, is 25 that just due to clay? 20 • • 1 MR. HENNIGAN: My guess is it is. 2 COMMISSIONER SEAMOUNT: Okay. Thank you. 3 MR. HENNIGAN: And some of the ones that go 4 real close to 3,000 are probably the coals. 5 CHAIR FOERSTER: Any other questions? 6 7 CHAIR FOERSTER: Commission Norman, do you have 8 any questions for this witness? 9 COMMISSIONER NORMAN: Just I understood that 10 the range of salinity of the water is between three and 11 10, that was what you said? 12 MR. HENNIGAN: We were looking at something 13 that was over three to be truthful about it and most of 14 them appeared in that interval to be between three and 15 10 even though there's a lot that's higher. 16 COMMISSIONER NORMAN: All right. Thank you. 17 CHAIR FOERSTER: Is this the -- all that you 18 have to offer on the 19 MR. HENNIGAN: (Inaudible response) 20 CHAIR FOERSTER: Okay. Is there any other 21 party that would like to testify on this, the aquifer 22 exemption. 23 (No comments) 24 CHAIR FOERSTER: All right. Mr. Hennigan, 25 you're not off the hook, let's hear your testimony for 21 • • 1 the disposal injection order. And you're still under 2 oath and you're still an expert witness. 3 MR. HENNIGAN: Ma'am? 4 CHAIR FOERSTER: You're still under oath and 5 you're still an expert witness. 6 MR. HENNIGAN: Yes, ma'am. We have provided a 7 complete packet on the disposal injection order showing 8 the areas under lease which Buccaneer has expanded 9 their leasehold in that area. I can provide a map if 10 that so interests the group. And I got with their 11 geologists who are -- and also in this I provided a map 12 from the hydrology department showing the major wells -- 13 water wells in the area because I think that is 14 critical. Just to give you -- and your protection of 15 the drinking of the water is very, very serious and 16 very admired. In Louisiana, in Texas, even going by 17 all the requirements there have been exceptions to the 18 salt water and other things being injected broaching to 19 the surface. It's very critical that we identify all 20 the potential areas that are close by and I think these 21 are so far away it would not be am impact, but they 22 still need to be a matter of record. And anything 23 that's done subsequent to this, Buccaneer needs to take 24 the responsibility to make sure that they're monitored 25 as well. 22 • . 1 COMMISSIONER NORMAN: Madam Chair. 2 CHAIR FOERSTER: Yes. 3 COMMISSIONER NORMAN: If I could just follow -up 4 on that point. It isn't just the existing wells as you 5 know too, it's a potential well that might be drilled a 6 year from now or two years from now that we would to be 7 sure. And so as you're talking can you address the 8 confining layer and what might prevent migration into 9 these zones where a well might in the future be 10 drilled. 11 MR. HENNIGAN: Yes, sir, I will. And -- but I 12 was just saying that anything as far as water wells, we 13 need to make sure -- Buccaneer needs to make sure that 14 they're of no potential impact should anything occur, 15 they need to make a mark, look, we know these wells are 16 here, you know, we've got to watch them. You know, and 17 that is a development area that the city of Kenai is 18 doing is that they want to develop that area so there's 19 a greater chance of water wells in the future than 20 there is now. 21 Just to give a little overview before we go 22 into the confining areas. You know, Buccaneer drilled 23 their first well, Kenai Loop No. 1, early last year and 24 drilled a straight hole and made a discovery, came back 25 later last year and drilled the Kenai Loop 3 which -- 23 • • 1 so 1 and 3, let's -- and they drilled that to the 2 south. And somewhere below 8,500 foot they crossed a 3 fault so everything that they were targeting was wet. 4 So this made this well basically an expendable well. 5 So it could have been either plugged or abandoned or 6 put to future utility. The sidetracking options at the 7 time and still are minimal to go to where their targets 8 are, so it would have -- the well would have been 9 plugged and abandoned. In this area here with the two 10 wells, seven or 800 foot apart where you could identify 11 the different zones and it -- according to the 12 geologist now, is that there is a confine -- a series 13 of shales and other things that are -- there's several 14 different confining zones, but the major ones, let's 15 talk about the aquifer exemption order, at about 34, 16 3,500 foot, there's another group around 5,500 foot and 17 then when you hit the Tyonek at about 8,500 feet that 18 is a confining area as well, a large, mass -- massive 19 shale for the area, large for the area. 20 COMMISSIONER NORMAN: Sir, could you -- who is 21 the geologist you're referring to, according to the 22 geologist, who 23 MR. HENNIGAN: David Doroty. 24 25 MR. HENNIGAN: And the geophysicist is Craig 24 • • 1 Moore. 2 COMMISSIONER SEAMOUNT: Where are they located? 3 MR. HENNIGAN: They're located in Houston, 4 Texas. 5 COMMISSIONER SEAMOUNT: And you say that 6 there's a fault separation between the number 3 and the 7 number 1 well? 8 MR. HENNIGAN: Yes, sir. 9 COMMISSIONER SEAMOUNT: And the number 3 was 10 wet, yet it's structurally higher than the number 1? 11 MR. HENNIGAN: As -- in the -- that's -- that's 12 13 COMMISSIONER SEAMOUNT: So you think you have a 14 fault trap? 15 MR. HENNIGAN: They think there's a fault trap 16 for the number 1, but the number 3, where I was told 17 they cross the fault was much deeper and that's why it 18 was wet. 19 COMMISSIONER SEAMOUNT: The number 3 was 20 deeper? 21 MR. HENNIGAN: Where they crossed the fault 22 was 23 COMMISSIONER SEAMOUNT: I'm looking at your 24 structure map, it's Exhibit 10 of the application, and 25 there's not a fault on the map and it shows the number 25 • 1 3 being shallower than the number 1 well. 2 CHAIR FOERSTER: In the Beluga formation. 3 COMMISSIONER SEAMOUNT: IN the Beluga. 4 MR. HENNIGAN: Yes, sir, that's correct, but 5 from what I know of the geology, the fault that they 6 cross to get into the wet zones of the Tyonek was 7 deeper. 8 COMMISSIONER SEAMOUNT: Oh, okay. I gotcha. 9 CHAIR FOERSTER: Tyonek not Beluga. 10 MR HENNIGAN: It was around 85, 8,600 feet, 11 that's 12 COMMISSIONER SEAMOUNT: All right. 13 MR. HENNIGAN: what I understand. 14 COMMISSIONER SEAMOUNT: And if we're getting 15 into areas of confidentiality regarding your discovery 16 let me know that we can't talk about it on the record. 17 CHAIR FOERSTER: Because anything you do say on 18 the record will be public. 19 MR. HENNIGAN: I understand. Truthfully I've 20 only been told not to talk to any of my other customers 21 about this -- about the well and I haven't. So 22 COMMISSIONER SEAMOUNT: Okay. 23 MR. HENNIGAN: I don't really know what's 24 on. 25 Mr. Norman, there's a pretty detailed 26 • • 1 discussion of the injection and confining zones. It -- 2 the primary injection zone is proposed in the upper 3 Beluga between 5,700 feet measured depth and 7,000 feet 4 measured depth. 5 CHAIR FOERSTER: Could you tell us what pages 6 in the 7 MR HENNIGAN: Its on Page 14. 8 COMMISSIONER SEAMOUNT: And that's -- is that 9 in the number 3 or the number 1 well? 10 MR. HENNIGAN: Number 3 well. 11 COMMISSIONER SEAMOUNT: Number 3. Okay. 12 MR. HENNIGAN: The -- as the geologist defined 13 it, the upper confining zone is between the top Beluga 14 at 5,721 feet and the base of the lowest massive and 15 overlying Sterling at 5,332 feet which is about a true 16 vertical thickness of approximately 350 feet. 17 COMMISSIONER NORMAN: I did look at this last 18 week, but I don't have it in mind. Could you give -- 19 what's the top again on that, just the depth, it's at 20 30 -- what did you say, you mentioned 21 MR. HENNIGAN: The top is 22 COMMISSIONER NORMAN: 5,300 feet, but the 23 other depth was what 30? 24 MR. HENNIGAN: Well 25 COMMISSIONER NORMAN: Say -- if you wouldn't 27 • 1 mind if you could just start over and say -- and define 2 again the zone. 3 MR. HENNIGAN: Okay. Firstly is that the 4 target area that we're defining for this disposal 5 injection order, the upper confining zone is between 6 the top Beluga at 5,721 and the base of the lowest 7 massive sand in the overlying Sterling at 5,332 which 8 is about 350 feet true vertical thickness. 9 COMMISSIONER NORMAN: Good. Thank you. 10 MR. HENNIGAN: It's very shaley and has inter - 11 bedded siltstone, claystone and a few thin coal seams, 12 et cetera. The lower confining zone is -- occurs 13 between the measured depths of 7,052 feet and 7,250 14 [sic] feet or a thickness of approximately 650 feet. 15 It's similar confining characteristics with inter - 16 bedded mudstone, shale, siltstone, coal stringers and 17 very low permeability sandstones. 18 COMMISSIONER SEAMOUNT: What was the depth of 19 the base of that lower confining zone? 20 MR. HENNIGAN: Seventy -- hmmm, I think I have 21 a typo here, 7,750. I have in the -- I wrote 7,250. 22 CHAIR FOERSTER: Okay. In our application it 23 says 7,250, but that's incorrect? 24 MR. HENNIGAN: That's incorrect, 7,750. 25 CHAIR FOERSTER: Who complied this application? 28 • • 1 MR. HENNIGAN: Ma'am? 2 CHAIR FOERSTER: Was this an application that 3 came from Buccaneer's offices? 4 MR. HENNIGAN: Yes, ma'am, and I actually typed 5 it and had it reviewed and I apologize. 6 CHAIR FOERSTER: Okay. 7 MR. HENNIGAN: And the basic reservoir 8 properties in the Beluga where we're proposing to 9 inject, you can see that we had several rotary cores 10 with average core porosity of 22.6 and -- but fairly 11 low permeabilities on the 128 millidarcies range. 12 The well in itself as it stands is very, very 13 good condition as far as structural integrity, 14 mechanical integrity. Cement bond logs show that we 15 have good cement bonding that fully covers the proposed 16 area of injection up to about 4,850 feet. So we're 17 quite -- and we did have very good leak -off test below 18 19 issues down deep. So as far as giving barriers, I 20 think we have numerous barriers to prevent any upset to 21 allow breaching of any sort. 22 Related to the breaching of any sort, I've done 23 studies on this in other areas and other formations and 24 it's really the injection methodology has a lot to do 25 with the chances of breaching. If you inject at a very 29 . . 1 high pressure and a very high rate, typically, and this 2 was done -- proved by a study at TerraTech in Nevada, 3 the fractures actually go up and then they go out and 4 then they begin to fall. They go up because of the 5 pressure, they go up and then they hit a barrier and 6 7 a little weaker, go up and then the pressure that 8 exists begins to be degraded because of velocities and 9 friction and all that, then the fractures tend to go 10 down. So most fractures go up, out and down at the 11 same time. Well, that's one of the reasons why you 12 don't want to start out with extremely high pressure so 13 Buccaneer's plan is to start out with a very stable 14 pressure and just do a slow frac injection where you 15 minimize the chances of it going up and you basically 16 are conducting a series of radial fractures. 17 In the shale studies many years ago is that 18 they felt like they could fracture across many 19 formations, but what we want to do is that we want to 20 direct the fracture where it goes out in a radial. And 21 if we do it at a low enough rate, but we sustain the 22 rate and pressure, as it begins to plug at the end 23 it'll begin to fracture. So most of the cuttings and 24 mud and cement and water will be basically near 25 wellbore. And it's controlling the pressure minimizes 30 • 1 the chances of it going higher. Everybody's heard 2 about all the stuff and issues that have occurred with 3 fracking for production in all the shales, well most of 4 the issues are number 1, either the offset wells 5 weren't abandoned properly or number 2, is that they 6 got such a high rate that it just kept going up into a 7 zone where it had connectivity with the other wells. 8 So monitoring the injection pressures is very key to 9 having this -- for everybody to sleep well at night. 10 COMMISSIONER NORMAN: Mr. Hennigan, when you -- 11 when you're talking about the fractures going up I was 12 thinking you are talking about the trajectory of a 13 fracture as opposed to the number of fractures going 14 up? 15 MR. HENNIGAN: That is correct. 16 COMMISSIONER NORMAN: Thank you. 17 MR. HENNIGAN: Submitted along with the 18 application was a frac study done by a company called 19 Drill Cuttings Injections Company which actually work 20 on -- off the platforms in the Cook Inlet many years 21 ago, 20, 25 years ago. I had other studies done by 22 Baker, B.J., and pulled in some data that I had which 23 are not even part of this and the technology as 24 presented by the fracking companies indicates that if 25 we -- steady and not erratic well be much better off 31 ! • 1 in the long run and that's what we've proposed here. 2 In the application we try to be very thorough 3 in defining all the physical properties of the zones of 4 interest, initial zones of interest that we're looking 5 at so they're available for your review or I can get 6 other copies. But are there any questions on the 7 technical parts? 8 COMMISSIONER NORMAN: Just a question on the 9 pressure, the pressure that will be applied on 10 injection. What will that pressure be and how will 11 that be monitored in the future? 12 MR. HENNIGAN: That'll be monitored at the 13 surface and it'll be monitored on a chart basis. And 14 let me go back to my notes here, and what we'll do is 15 well establish -- we'll actually establish a fracture 16 of the grave -- of the well, we'll take the well to 17 leak -off. I don't remember the numbers in there, but 18 I'm guessing 3,000 pounds, 4,000 pounds. Once we take 19 it to leak -off then we'll establish a steady injection 20 and try not to exceed that. Occasionally what will 21 happen is even the perforations and all that will plug 22 up with cuttings or mud or whatever and you'll have to 23 exert more pressure, but it's -- can only be a 24 nanosecond and it should dissipate down to the end. 25 Overall the plans are to inject at less than 3,000 32 • • 1 pounds. 2 CHAIR FOERSTER: So you're going to stay below 3 frac pressure? 4 MR. HENNIGAN: Yes, ma'am. Once you get the 5 frac going, if you -- if you're looking -- actually 6 there's an example in here. 7 CHAIR FOERSTER: Tell us what page it's on. 8 MR. HENNIGAN: When we -- when we did the leak - 9 off test at the different zones what happens is that as 10 you inject your pressure with volume goes up and then 11 it breaks off. When it goes up and begins to -- begins 12 to curve over that's called the leak -off or the initial 13 fracture initiation. Go a little bit more and you have 14 your fracture. When you have your fracture the 15 pressure drops off and that would be the sustained 16 pressure that we'd like to target while we're injecting 17 the well. WE don't want to create a lot of new 18 fractures, we want one that we know where it's at. 19 COMMISSIONER SEAMOUNT: Did you -- Mr. 20 Hennigan, did you say you'd performed a baseline study 21 of the water wells in the area? 22 MR. HENNIGAN: Yes, sir. 23 COMMISSIONER SEAMOUNT: Did you -- what did you 24 25 MR. HENNIGAN: No, sir. 33 • • 1 COMMISSIONER SEAMOUNT: Okay. Because some of 2 the wells do contain gas, but farther to the south 3 MR. HENNIGAN: Yes, sir. 4 COMMISSIONER SEAMOUNT: up in the valley. 5 MR. HENNIGAN: Actually Mr Ireland in the 6 hydrology department helped me out quite a bit on this. 7 COMMISSIONER SEAMOUNT: Are you going to 8 continue to sample the water or just assume it's going 9 to be good until someone says it isn't? 10 MR. HENNIGAN: Let -- you know, as -- I'm a 11 representative of Buccaneer, but I can't commit to a 12 13 request. 14 COMMISSIONER SEAMOUNT: Well, it's probably 15 prudent I would think. 16 MR. HENNIGAN: I think it would be darn prudent 17 especially on the deeper well. 18 COMMISSIONER SEAMOUNT: Now your disposal 19 material is going to be only drilling material or do 20 you foresee using it for other types of disposal as 21 these wells produce, like produced water, that kind of 22 stuff? 23 MR. HENNIGAN: Yes, sir, we do anticipate 24 produced water. Actually as time goes on the bulk of 25 the injection will be produced water. 34 • • 1 CHAIR FOERSTER: Do you have any other 2 questions, Commissioner Norman? 3 COMMISSIONER NORMAN: I don't. 4 MR. HENNIGAN: I have something I'd like to add 5 which I've learned since this started and I want to 6 tell you I've actually been working on it since October 7 of last year and didn't submit anything until March. 8 And since March what I've found out in doing other work 9 for Buccaneer and others is that the place for disposal 10 of materials in the Kenai area is very critical. 11 There's not a lot of people taking it and even if it's 12 meeting all the criteria there's just a room issue. 13 For example, the disposal facility at Soldotna, at the 14 Kenai Peninsula Borough facility is limiting what you 15 can -- how much you can dispose there over a period of 16 time, other public -- not public, but commercial 17 facilities have pretty much run out of room so we're in 18 a critical issue in the Kenai area. And I've -- 19 frankly in doing work with -- I would rather have the 20 junk down hole than on the surface, I don't care what 21 form it's in. 22 And one other little issue here is that if you 23 would look at a full million barrels and, you know, you 24 think a million barrels and you say it's going to be a 25 lot, well, it is a lot, but when you look at the area 35 • 1 or space that it would take, assuming the maximum frac 2 wing, half frac of 500 and something feet, okay, you 3 take just that frac wing, 50 feet thick of the 4 injection interval, it's only 225 feet wide is a 5 million barrels. It's not a lot so if we take care of 6 it properly well keep it very close to the existing 7 wellbore. 8 CHAIR FOERSTER: Mr. Hennigan, is -- in your 9 application is there a maximum volume that you're 10 requesting? 11 MR. HENNIGAN: I think it's 1,150,000 barrels. 12 COMMISSIONER SEAMOUNT: Did you include the 13 calculation for the area of endangerment in the 14 application, the formula that you used? 15 MR. HENNIGAN: Educate me. 16 COMMISSIONER SEAMOUNT: You say a 50 foot thick 17 zone taking a million barrels would only go out how 18 many feet? 19 MR. HENNIGAN: Five hundred feet 20 COMMISSIONER SEAMOUNT: Okay. 21 MR. HENNIGAN: and then 225 feet wide. 22 COMMISSIONER SEAMOUNT: So I'm interested in 23 knowing what the formula was to calculate that? 24 MR. HENNIGAN: I just used straight -- took a 25 million barrels, 5.61 cubic foot per barrel and then 36 • • 1 just made it a rectangle just to see for myself really. 2 COMMISSIONER SEAMOUNT: Did you assume a 3 certain porosity 4 MR. HENNIGAN: No, sir, I 5 COMMISSIONER SEAMOUNT: fracture 6 (indiscernible - simultaneous speech) 7 MR. HENNIGAN: assumed the frac -- frac 8 studies. 9 COMMISSIONER SEAMOUNT: Okay. 10 CHAIR FOERSTER: So you're saying the frac is 11 going to grow to 225 foot in width? 12 MR. HENNIGAN: No, ma'am, I was just -- the 13 point I was trying to make is that when you look at the 14 area -- at the actual area that a million barrels takes 15 up, it's -- you know, when we hear a million we say 16 man, that's huge, huge, but when you actually look at 17 the volume that it takes up it's not that big, you 18 know, by comparison standards. And we do -- you know, 19 the maximum frac -- half frac is 500 and something feet 20 and lord, that's what we -- we darn sure want to stay 21 within that, you know, and that's a worst case 22 scenario. 23 CHAIR FOERSTER: So if you dispose of a million 24 barrels of disposal fluid you're frac's only going to 25 grow out 500 feet in each direction? 37 • 1 MR. HENNIGAN: Yes, ma'am. 2 CHAIR FOERSTER: And what's the frac width? 3 MR. HENNIGAN: Frac width is about 50 feet if I 4 recall correctly. 5 CHAIR FOERSTER: Do we need to take a recess, I 6 don't think it would hurt? 7 COMMISSIONER NORMAN: I have one final question 8 and then we can take a recess. 9 CHAIR FOERSTER: Okay. Do that. 10 COMMISSIONER NORMAN: Thank you, Mr. Hennigan, 11 I think you've covered quite a bit. My question is 12 along the lines of -- and you're welcome to sit down if 13 you're more comfortable too. My question is along the 14 lines of in any trial or presentation there comes a 15 time then when you have a final closing argument or 16 summary of what you believe you've presented and 17 communicated. So I would appreciate it if you could 18 19 the most important points from the perspective that you 20 might be talking to a public meeting in Kenai of people 21 worried about their aquifer and potential contamination 22 as a result of this operation. What safeguards do you 23 think that you've identified for us, what's their 24 confine -- everything from confining layer all the way 25 to in the future on change out of personnel, how are 38 • • 1 they going to know to monitor this, what are the 2 company's practices, things like that. And speak if 3 you would as much as you could in layman's terms so 4 that someone reading this would understand the 5 precautions being taken. 6 7 December the 13th I had to do this for a county or 8 parish in Louisiana, there was a lot of concerns on 9 fracking and disposal wells and water and all this. 10 So to the public. I'm very concerned about 11 disposal wells and salt water disposal wells of any 12 sort. I don't care if it's state approved or EPA 13 approved, it's a big concern to me as a citizen of the 14 country and a citizen of whatever local area I work in 15 is that before -- I have a personal obligation and I 16 have a legal engineering obligation to recommend what 17 is most right technically and for the people. And a 18 lot of people don't understand that, but I have a 19 master's in engineering and one of the things was -- 20 the courses I had to take was legal -- the legal parts 21 of it. So I have an obligation there and then also 22 working for the company. Were an engineering company, 23 we have legal obligations as well. So we have to 24 address everything from number 1, both the technical 25 aspect first and then I have to address it from a 39 • • 1 personal aspect. 2 Excuse me for speaking to the public. 3 CHAIR FOERSTER: That's what he asked you to 4 do. 5 MR. HENNIGAN: The first thing is that we have 6 designed this well based upon what we can determine 7 from well logs and well test to make sure that any 8 fluids or solids that we put back into the formation is 9 confined in a place for the future as we could ever 10 anticipate it to be. We have the wellbore integrity, 11 we have the cement isolation above the potential zones 12 of injection and the geologists have defined from what 13 they can see as an upper barrier and a lower barrier. 14 As a matter of fact they have defined several upper 15 barriers, one being at the top of the Sterling at about 16 3,500 feet and the other one being at about 5,500 foot 17 and, of course, the lower's at the base of the Beluga. 18 So we have two confining layers for this disposal as 19 the geologists have defined where it's a restriction of 20 flow and the hardness of the shale and the porosity and 21 permeability which is ability to flow, if you will, is 22 very minimal at that point. Then mechanically we have 23 it isolated with casing and cement. So that is the 24 mechanical aspects of the barriers. 25 The other thing that of -- we don't -- we need 40 • • 1 to have control on is monitoring, is that every day 2 when we inject we monitor the pressure and we monitor 3 the volume and we keep records and we submit them to 4 the AOGCC for evaluation every so -- I think it's 5 monthly if I remember correctly. And also every year 6 we have to -- or one to two years depending on the 7 criteria, we have to do a mechanical integrity test. 8 Mechanical integrity test means that we test all of the 9 equipment, all of the casing and everything to make 10 sure it still falls within the criteria of which we are 11 asking for this injection order today. If it doesn't 12 fall within that criteria then we have to do something 13 to correct that issue and that will come back to the 14 AOGCC for approval. So they will look -- approve the 15 mechanical aspects of it. 16 The other thing is that -- you know, I'm 17 thanking god for the mechanical integrity test 18 requirement that the AOGCC has. Not all states, not 19 all parts of the country have these requirements. If 20 we are to protect our kids and grandkids for the future 21 we have to make sure that we monitor everything about 22 this well until its last day. And then subsequent to 23 that there should be occasional monitoring to make sure 24 there's no issues that we can't see. 25 Also related to this is that I've done many 41 • • 1 studies including, and this goes back many, many years, 2 on our environment. And when my daughter who's now 38 3 was 12 she did a study on how to get rid of crude oil. 4 Surprisingly enough there's a lot of things that you 5 can do in a warm climate, there's not a lot you can do 6 in a cold climate to take care of crude oil. So there 7 are a lot of natural things that can take care of crude 8 oil. Salt water's an issue that plagues everybody 9 wherever we go. The thing that we need to do is to 10 keep it where it cannot impact us in our daily lives 11 both now and the future which is down in the ground. 12 So my thoughts are if we bind it with sawdust and other 13 chemicals and put it in a public disposal, nobody has 14 done studies over the years to see what's going to 15 happen to that, you know, there have been no long -term 16 studies, maybe 25 years, but what's going to happen in 17 another 25 or another 25. We have no idea and anybody 18 that tells you they do, you need to look at their 19 background. But we know that subject to some unknown 20 major catastrophe is that if we put it down deep it 21 will dehydrate and it will solidify and it will become 22 pretty much like the natural formation. And what 23 Buccaneer has proposed is to put it deeper than any 24 25 grandfathered in disposal wells in Cannery Loop and a 42 • • 1 couple others, they're only at 13 or 1,400 feet. Those 2 are the ones that need to be worried about because 3 they're still in the quote, fresh 4 water range. My -- our proposal is to put it down much 5 deeper where it's not in the fresh water range. 6 Any questions from the public? 7 COMMISSIONER NORMAN: Commissioner Foerster, 8 three quick follow -up questions. Thank you for doing 9 that. I understood that your maximum injection 10 pressure and if it came out in an order this would be 11 accepted is 300 or 3,000 psi; is that right? 12 13 exception that is noted that says occasionally you may 14 see a pressure as high as 6,000 pounds, but that's only 15 to get the material moving near wellbore. 16 COMMISSIONER NORMAN: All right. And the 17 maximum amount of fluid to be injected I understood is 18 1.15 million barrels? 19 MR. HENNIGAN: Yes, sir, I just took an 20 assumption of X amount per day for 15 years, that's a 21 very approximated amount. I sus 22 COMMISSIONER NORMAN: And that's barrels? 23 MR. HENNIGAN: That's barrels, yes, sir. 24 COMMISSIONER NORMAN: And I'm sorry, did I 25 interrupt you or 43 • i 1 MR. HENNIGAN: No, sir. 2 COMMISSIONER NORMAN: And my last question, on 3 a part of your testimony you added a qualification 4 that, of course, I'm just a consultant and not 5 authorized to speak for the company. So I want to find 6 out does that qualification apply just to that one 7 little thing you said or are there any others of your -- 8 areas of your testimony that you're not authorized to 9 speak to? 10 MR. HENNIGAN: It's a good point. I thought I 11 said commit to a specific request, you know. As far as 12 the testimony I'm authorized in everything that I'm 13 testifying, but a special request would have to be 14 approved by the company. 15 COMMISSIONER NORMAN: Okay. Thank you, 16 Commissioner Foerster. 17 CHAIR FOERSTER: All right. Do you have any 18 questions? 19 (No questions) 20 CHAIR FOERSTER: All right. Were going to 21 take a 10 minute recess and we will reconvene at 10:33. 22 Recessed. 23 (Off record) 24 (On record) 25 CHAIR FOERSTER: Were back on the record at 44 • • 1 10:45. Mr. Hennigan, we have several questions 2 MR. HENNIGAN: Yes, ma'am. 3 CHAIR FOERSTER: left and there are some 4 inconsistencies in your testimony and the documents 5 that you provided to us and so what we would like to do 6 is leave the record open for -- well leave the record 7 open until June the 5th and we will get our questions 8 to you within the next day or so and we want you to get 9 them back to us by June the 5th. And then we will 10 either make a decision or if we have more need for 11 answers or testimony we will renotice for an additional 12 hearing. 13 MR. HENNIGAN: Yes, ma'am. 14 CHAIR FOERSTER: Okay. Any comments, 15 questions? 16 COMMISSIONER SEAMOUNT: No, I don't. 17 COMMISSIONER NORMAN: No questions. 18 CHAIR FOERSTER: All right. Do I have a motion 19 to adjourn. 20 COMMISSIONER NORMAN: Move to adjourn. 21 COMMISSIONER SEAMOUNT: I second. 22 CHAIR FOERSTER: All in favor. 23 IN UNISON: Aye. 24 CHAIR FOERSTER: Opposed. 25 (No opposing votes) 45 • • 1 CHAIR FOERSTER: We're adjourned. 2 (Adjourned - 10:48 a.m.) 3 (END OF PROCEEDINGS) 46 • 1 TRANSCRIBER'S CERTIFICATE 2 I, Salena A. Hile, hereby certify that the 3 foregoing pages numbered 08 through 47 are a true, 4 accurate, and complete transcript of proceedings in 5 Docket No.'s AEO -12 -001, DIO -12 -002, Volume II 6 transcribed under my direction from a copy of the 7 electronic sound recording to the best of our knowledge 8 and ability. 9 10 11 Date Salena A. Hile, Transcriber 12 47 44 • STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION KENAI LOOP AQUIFER EXEMPTION AND DISPOSAL INJECTION APPLICATIONS May 22, 2012 at 9:30 am NAME AFFILIATION PHONE # TESTIFY (Yes or No) - 'AM) /4 ) 4A ) kl,'C'''f(eer' 33?ge/76 "0 yes ,7Y,kf\c)co-Ocick ;6CC 1Ci3- 223 0 cpD/ (( / c — 70 � i / /7d L(A. 11( pvJR& 406 7? 3 7232.. Atij Ro GcC '3 IC- 3 4-;i'3 Nc 4 -c4e,c �3 �, �' • • Regg, James B (DOA) From: Regg, James B (DOA) 4)./3 Sent: Thursday, May 31, 2012 9:32 AM To: 'Stephen Hennigan' Cc: 'Andy Rike'; Fisher, Samantha J (DOA); Davies, Stephen F (DOA) Subject: Questions /Clarification regarding Kenai Loop DIO /AEO Applications Attachments: KL3 DIO Questions for Buccaneer.pdf; RE: Continued Hearing for Buccaneer June 5 930am Mr. Hennigan: Attached is a document that includes AOGCC comments, questions and requests for clarification based on our review and testimony you provided at the May 22, 2012 hearing (Kenai Loop DIO /AEO applications). As you know the AOGCC left the record open until June 5, 2012 for Buccaneer to respond to AOGCC's questions. These is some confusion regarding what AOGCC intends to do on June 5, and I apologize if I have added to the confusion by stating in my 5/25 email that Buccaneer is expected to be present for the continuation of the May 22 hearing. June 5 was set as the due date for Buccaneer's responses to AOGCC questions. There is no need for Buccaneer to be present at AOGCC offices on June 5. Decision about closing the record will be made based on AOGCC's review of the responses provide by Buccaneer. Jim Regg AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907 - 793 -1236 1 . • • Questions for Buccaneer Kenai Loop #3 DIO and AEO Applications May 30, 2012 The following comments are provided to Buccaneer Alaska Operations LLC (Buccaneer) regarding its applications for disposal injection order and aquifer exemption order at Kenai Loop Field well #3. These questions follow reviews by AOGCC staff and the testimony provided by Mr. Steve Hennigan during the public hearing held May 22, 2012. Buccaneer's response to these questions and clarification, as needed, are required before the AOGCC can complete its action on the Kenai Loop orders. Comments DIO, Page 1, Well Locations Last sentence should read "...no other wells other than Buccaneer's Kenai Loop #1 that come into play" DIO, Page 3, Exhibit 2, "Hydrologic Survey general map" It is unclear what the red circle represents. Exhibit provides no scale, no legend, and is not labeled. DIO, Page 3, Exhibit 3, "Hydrologic Survey Water Wells Map" Exhibit is unclear. It appears these are the water wells located within some area of review. Is this a % -mile or 1/2-mile area of review? Exhibit provides no scale. DIO, Page 9, Exhibit 8, "Aerial Map" Again, a poor quality exhibit. Unclear the intent of this graphic but does not seem to have any relevance to the injection order application. DIO, Page 14 - 15, "Injection and Confining Zones" Clarify the depths of the upper confining zone, lower confining zone, and injection zone. There appears to be inconsistent depths, overlap between the injection zone and lower confining zone, and perforations into the lower confining zone based on the depths reference in the DIO application. According to Buccaneer's application: Upper confining zone: 5332 — 5721 ft MD (5068 — 5418 ft TVD) Injection zone: 5721 — 7025 ft MD (5418 — 6591 ft TVD) Injection perforations: 6435 — 6450 ft MD (6170 — 6183 ft TVD) 6950 — 6960 ft MD (6634 — 6643 ft TVD) Lower confining zone: 7052 — 7250 ft MD (6152 — 6802 ft TVD). Testimony by Mr. Steve Hennigan on 5/22/12 indicated the lower confining zone measured depths should be 7052 ft and 7750 ft; he did not provide revised true vertical depths. The discussion on page 12 ( "Geologic Details ") describes different (additional ?) upper confinement ( "vertical barriers to movement of fluids occur at 3068' (3066' TVD...), and —3200 (3197' TVD...) to 3300' (3297'TVD...)). Kenai Loop #3 Disposal Injecterder • Questions and Clarification Required May 30, 2012 Page 2 of 4 On page 22 ( "Well Construction and Integrity "), Buccaneer indicates the top of the injection interval is 5030 ft. Please also verify depths of aquifer exemption being requested (page 42 and Aquifer Exemption Order application) to the extent they are impacted by any changes resulting from the review of confining and injection zone depths. DIO, Page 23 -25, "General Conversion Procedure" Work procedures should be consistent with approved Sundry 312 -100 (dated 5/14/12). DIO, Page 33, "Waste Sources, Types and Volumes" Disposal volume is reported differently: - DIO, Page 33: Total Volume (20+ years) = 1,135,000 bbl - Appendix B, Page 3: 67,000 bbls /year for 15 years - Appendix B, Page 8: 1,000,000 bbls each year for 15 years - Appendix B, Page 9: 2,500 bbls /day; 15 years - Appendix B, Page 16: 1,000,000 bbls over a 15 -year disposal injection period (identified as "worst case ") - Public Hearing testimony 5/22/12: 1,150,000 bbls total disposal injection volume, calculated by assuming a daily volume (barrels) for 15 years Buccaneer estimates a "radial plume would be generated in the injection zone of 180 ft if not skewed by fracturing." Please describe how you calculate this zone of influence, including values for porosity, thickness of the zone receiving injection; perforated interval considered in the determination, and any other relevant factors. Also provide the sources of the input parameters for the calculation. The relevance of a 180 -foot radial plume is unclear given the slurry injection fracture study that is included as Appendix B. That study provides modeled fracture propagation for a 1,000,000 barrel slurry injection case that extends laterally more than 400 feet from the wellbore, and 45 feet beyond both the upper and lowermost perforations. DIO, Page 34, "Compatibility of Fluids and Formation" According to the DIO application on page 34: "The resident zone is typical for injection wells within the area that have operated without incident over the last 15 years and is therefore comparable with the same wastes being injected in similar storage reservoirs." [emphasis added] During public hearing testimony by Mr. Hennigan on May 22, 2012, it was suggested Buccaneer's proposed disposal injection at Kenai Loop #3 is safer than other injection wells in the area because they have proposed to inject "deeper than any grandfathered in disposal wells in Cannery Loop and a couple others" that are injecting "at 13 or 1400 feet ". Mr. Hennigan continued by suggesting the other disposal wells in the area "are the ones that need to be worried about because they're still in the quote, fresh water range." AOGCC records indicate that there are no disposal injection wells in Cannery Loop. Of those disposal injection wells closest to the Kenai Loop #3 Disposal Injectltrder • Questions and Clarification Required May 30, 2012 Page 3 of 4 Kenai Loop field, only one well is injecting at a depth shallower than 4000 feet TVD, and that well is limited to produced water disposal injection, with extensive performance monitoring and fracture propagation modeling in support of continued operation. Please clarify which wells are injecting at a depth of 1300 to 1400 feet which represent a concern based on Buccaneer's research. Has there been any compatibility analysis done to evaluate the proposed injected materials interaction with the formation and in situ fluids? DIO, Page 35, "Injection Pressure" Buccaner estimates an average injection pressure up to 3000 psi with "occasional" excursions to 6000 psi when refracturing of the formation occurs because existing fractures become plugged. While not referenced in the "Injection Pressure" write -up, Section 4.4 of Appendix B presents a conglomeration of pressures, rates and concentrations versus time. Too much information is presented on this single graphic, and the colors of the individual lines cannot be distinguished, making it confusing. It appears from the graph (Alaska SFI 1 Day Inj BHTP & Surf Press.) that bottomhole tubing injection pressure is modeled to exceed 6500 psi continuously for 14 hours while injecting, hardly an occasional occurance. DIO, Page 38, Exhibit 19, "Mechanical Properties Output Graph" Poor quality graphic; unreadable. DIO, Page 39, Exhibit 20, "Fracture Half Wing Model, 50,000 Bbls" Poor quality graphic; unreadable. DIO, Page 39, Exhibit 21, "Fracture Half Wing Model, 155 BPD, 3 BPM, 5 Year Duration" There are conflicting descriptions of the modeled parameters on this graphic. Heading indicates this is a batch injection model run (155 BPD @ rate of 3 barrels per minute, for 5 years) while the title above the graph indicates this is single event model (2500 barrels continuously injected at 6 barrels per minute). Which is it? DIO, Page 41, Exhibit 21A, "Fracture Half Wing, High Rate, One Time Injection" Poor quality graphic; unreadable. What is the injection pressure associated with this scenario? DIO, Appendix B, "Buccaneer Central Injection Site Fracture Model & Study ", Page 3, "Executive Summary" Reference is made to the potential use of a "proprietary viscosifier blend" for maintaining gel strength in cutting slurry. Buccaneer must disclose to AOGCC the components of this proprietary viscosifier if it is to be used. DIO, Appendix B, "Buccaneer Central Injection Site Fracture Model & Study ", Page 21, Figure 4.3, "Mechanical Properties Output Graph" Poor quality graphic; unreadable. Kenai Loop #3 Disposal InjectSrder Questions and Clarification Required May 30, 2012 Page 4 of 4 DIO, Appendix B, "Buccaneer Central Injection Site Fracture Model & Study ", Page 26, "Geologic Discussion" Reference is made to a "large dirty sandy formation at 5000 feet" as providing a "significant barrier to upward slurry growth ". Is this a third level of confinement? It is unclear why this is so non - specific given the details of the upper and lower confining zones in the DIO application. DIO, Appendix B, "Buccaneer Central Injection Site Fracture Model & Study ", Page 27, "Summary and Conclusions" The summary should include specifics about the modeling results, such as fracture growth, lateral extension, modeling parameters used and why they are representative (or exceed the expected slurry injection volumes, pressures, rates, etc.) Aquifer Exemption Order, Cover Letter; and "Attachment A — Supporting Information" Buccaneer indicates it is requesting an aquifer exemption for the Sterling and Beluga formations as the zones for injection of Class II wastes (depth interval 3300 feet TVD to 8050 feet TVD). Page 42 of Buccaneer's DIO application requests the aquifer exemption for depths that coincide with the planned disposal injection interval only: 5721 — 7025 ft MD (5418 — 6591 ft TVD). Please clarify. AEO, Figure 1, "Calculated TDS vs Depth (MD)" The labeled upper confining layers, disposal zone, and lower confining layers are inconsistent with those identified in the DIO. Depths shallower than approximately 5,000 ft MD and deeper than approximately 7,000 ft MD show calculated total dissolved solids (TDS) values less than 3,000 milligrams per liter, which would constitute a major exemption and likely require processing under Federal regulations at 40 CFR 145.32, at EPA's discretion. Buccaneer references a (single ?) water sample taken during the well testing phase for Kenai Loop #3 after drilling was completed (page 42). No depth was identified and no analysis has been provided with either the DIO or AEO applications, except to note (in the DIO) that the total chlorides was determined to be approximately 6000 parts per million. Provide the water sample depth and analysis. • • Colombie, Jody J (DOA) From: Davies, Stephen F (DOA) Sent: Thursday, May 17, 2012 9:43 AM To: Foerster, Catherine P (DOA); Seamount, Dan T (DOA); Norman, John K (DOA) Cc: Regg, James B (DOA); Colombie, Jody J (DOA); Ballantine, Tab A (LAW) Subject: Buccaneer AEO /DIO Hearing -- Follow -up Cali Cathy, Dan and John: 1 spoke with Steve Hennigan of Petroleum Engineers, a contractor who provides engineering support to Buccaneer. We spoke about Buccaneer's lack of representation at the DIO /AEO hearing. His story morphed as the conversation went on. First he said that he wasn't aware of the hearing. Then he said he called AOGCC and was told that they didn't need to attend. I asked who he talked with at AOGCC, but he couldn't remember. I told him the hearing notice is published on AOGCC's website under the heading "Hearings and Meetings" and then the subheading "Public Meetings." He then said that he was aware there was a hearing but was told that Buccaneer didn't need to attend by Bob Britch (an Anchorage -based permitting agent). Steve wasn't sure where Bob got that information. I mentioned to Steve that the hearing has been continued to May 22 at 9:30 AM and asked him to confirm it with Jody. I also asked that Buccaneer provided enlarged, legible prints of the well log displays in advance of the hearing. He said that Buccaneer would take care of it this week. Steve D. 1 • • Colombie, Jody J (DOA) From: Regg, James B (DOA) Sent: Thursday, May 17, 2012 10:44 AM To: Stephen Hennigan; Bob Britch; Steve Ward; Andy Rike Cc: Schwartz, Guy L (DOA); Davies, Stephen F (DOA); Colombie, Jody J (DOA); Ballantine, Tab A (LAW) Subject: RE: Buccaneer AEO, DIO Applications Attachments: AEO 12 -001 (Kenai Loop Field).pdf; DIO 12 -002 (Kenai Loop Field).pdf Mr. Hennigan, Mr. Britch, Mr. Ward, and Mr. Rike: The AOGCC Commissioners have rescheduled the public hearing regarding Disposal Injection Order and Aquifer Exemption Order applications for Kenai Loop #3 since Buccaneer was a no -show today. The rescheduled hearing will be held May 22, 2012 at 9:30 am. You are reminded that it is Buccaneer's responsibility to contact AOGCC prior to the planned date of a hearing to confirm the schedule. Copies of the notices (attached) were sent to Buccaneer, posted on AOGCC webpage, and sent to an email distribution on April 10, 2012. I advised on May 3, 2012 that Buccaneer would need to be prepared to address - at the May 17 hearing - the items listed in AOGCC's Public Hearing Guidelines (see hyperlink below). I understand you have spoken with Steve Davies (AOGCC Sr. Geologist) about this already and will address his request for a legible copy of the type log section covering the injection zone, and upper and lower confining layers that correspond to your discussion in the application. You should also be prepared to discuss the proposed fluids to be injected in a Class II well, specifically your interpretation that the broad category of RCRA exempt fluids are eligible for Class II disposal injection. Questions of a technical nature regarding the injection and aquifer exemption orders should be directed to me; questions related to the hearing schedule and needs for your presentations should be coordinated with Jody Colombie (907 -793- 1221). Jim Regg AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907- 793 -1236 From: Regg, James B (DOA) Sent: Thursday, May 03, 2012 11:42 AM To: 'Stephen Hennigan' Cc: Schwartz, Guy L (DOA); Davies, Stephen F (DOA); Bob Britch; Andy Rike; Steve Ward Subject: RE: Buccaneer AEO, DIO Applications It is unlikely the hearing will be vacated, so you will need to be prepared to address the items listed in AOGCC's Public Hearing Guidelines, which are posted online at http: / /doa.alaska.gov /ogc /hear /PubHrgGuid.pdf. Jim Regg AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907 -793 -1236 From: Stephen Hennigan [mailto:shenniganCa�peiinc.com] Sent: Thursday, May 03, 2012 9:04 AM To: Regg, James B (DOA) 1 Cc: Schwartz, Guy L (DOA); Davies, Step•F (DOA); Bob Britch; Andy Rike; Steve AP Subject: RE: Buccaneer AEO, DIO Applications Jim As you stated below " hearing on May 17 ", how do you anticipate the timing in days to proceed from that point? Would it be beneficial if I (and /or others) were present at the hearing? Is there anything we should be doing now? s /� /Agr (337) 984 -2603 (337) 849 -5345 (c) PETROLEUM ENGINEERS, INC. From: Regg, James B (DOA) [mailto:jim.regg@alaska.gov] Sent: Tuesday, April 17, 2012 7:53 PM To: Stephen Hennigan Subject: RE: Buccaneer AEO, DIO Applications We are currently in the technical and public review which will be followed by a hearing (tentatively set for May 17, 2012). During this time AOGCC is evaluating info provided and may have questions; if so, we will forward them to you. Also during this time, AOGCC will begin drafting the text for each order (DIO and AEO). Attached is a general flow diagram of our injection order process (Area Injection Order shown but there is no procedural difference for other types of injection orders). We have learned that the flow diagram is not accurate regarding EPA review process associated with Aquifer Exemption Order; EPA will not initiate their review until the AOGCC has developed the AEO and can provide a complete application (defined to include your filing; draft AEO; transcript from public hearing, if held). EPA has up to 45 days after receiving complete application to concur or reject AOGCC findings /action (no action from EPA is presumed concurrence). Jim Regg AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907 - 793 -1236 From: Stephen Hennigan Jmailto:shennigan(apeiinc.coml Sent: Tuesday, April 17, 2012 2:55 PM To: Regg, James B (DOA) Subject: RE: Buccaneer AEO, DIO Applications Jim 2 What is the step in the process for the Buccaneer AEO and DIO applications are we in 4 ,104 , 47,r4001#400ef (337) 984 -2603 (337) 849 -5345 (c) - PETROLEUM w ENGINEERS, INC. From: Regg, James B (DOA) [mailto:jim.re•gOalaska.gov] Sent: Monday, April 09, 2012 5:08 PM To: Stephen Hennigan Subject: RE: Buccaneer AEO, DIO Applications Attached survey plat has inconsistent info: plat shows 1590 ft FSL but text to right indicates 1590 ft FNL; I'm guessing this is a typo and the real BHL is 1590 ft FSL and 1032 ft FWL. Jim Regg AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907 - 793 -1236 From: Stephen Hennigan f mailto:shenniganOpeiinc.coml Sent: Monday, April 09, 2012 3:40 AM To: Regg, James B (DOA) Subject: RE: Buccaneer AEO, DIO Applications From lease lines 3691'fnl 1590'fsl 1032'fwl 1606'fel (337) 984 -2603 (337) 849 -5345 (c) PETROLEUM ENGINEERS, INC. 3 • • From: Regg, James B (DOA) [mailto:jim.re•gOalaska.gov] Sent: Wednesday, April 04, 2012 7:28 PM To: Stephen Hennigan Subject: RE: Buccaneer AEO, DIO Applications I need the bottom hole location for KL #3 (Section, Township, Range; distance from lease lines). Thank you. Jim Regg AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907- 793 -1236 From: Regg, James B (DOA) Sent: Wednesday, April 04, 2012 8:27 AM To: Davies, Stephen F (DOA); 'Stephen Hennigan' Cc: Schwartz, Guy L (DOA); Roby, David S (DOA) Subject: RE: Buccaneer AEO, DIO Applications Public notices for DIO and AEO applications are being prepared. Jim Regg AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907- 793 -1236 From: Davies, Stephen F (DOA) Sent: Wednesday, April 04, 2012 7:44 AM To: Stephen Hennigan Cc: Schwartz, Guy L (DOA); Roby, David S (DOA); Regg, James B (DOA) Subject: RE: Buccaneer AEO, DIO Applications Stephen, Art retired earlier this week and two engineers have left the AOGCC within the past 6 months, Tom Maunder and Winton Aubert. 1 believe that these three were working on the Buccaneer AEO and DIO applications. From this point forward, these applications will be reviewed by me - geologist, Guy Schwartz - drilling engineer, Dave Roby - reservoir engineer, and Jim Regg - petroleum engineer. Picking up Art's work load as well as my own thrown me behind. I will pull these applications later today or tomorrow to see what has been done on them. 111 keep you informed. Regards, Steve Davies Sr. Petroleum Geologist Alaska Oil and Gas Conservation Commission (AOGCC) 333 West 7 Avenue, Suite 100 Anchorage, Alaska 99501 Steve's phone: 907 - 793 -1224 AOGCC's receptionist: 907 - 793 -1223 AOGCC's fax: 907 - 276 -7542 4 • AOGCC's website: http: / /doa.alaska.g /ogc From: Stephen Hennigan [mailto:shennigan@ peiinc.com,] Sent: Wednesday, April 04, 2012 7:11 AM To: Schwartz, Guy L (DOA); Saltmarsh, Arthur C (DOA); Davies, Stephen F (DOA) Subject: RE: Buccaneer AEO, DIO Applications Who do I contact about these? . itrrratii 4%r nWr /rev (337) 984 -2603 (337) 849 -5345 (c) PETROLEUM 7 ENGINEERS, INC. From: Stephen Hennigan [mailto:shennigan(apeiinc.com] Sent: Monday, April 02, 2012 3:40 PM To: Guy Schwartz (guy.schwartz(aalaska.gov); Art Saltmarsh (art.saltmarshCaalaska.gov); Davies, Stephen F (DOA) (steve.davies(aalaska.gov) Subject: Buccaneer AEO, DIO Applications Who do we need to contact to see where in the system these are? 4 n' / #4r (337) 984 -2603 (337) 849 -5345 (c) PETROLEUM 7 ENGINEERS, INC. 5 f � '�it STATE OF ALASKA NOTICE TO PUBLISHER • ADVERTISING ORDER NO. I N ADVERTISING ORDER NO. CERTIFIED INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING - 16 AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF AO 022140 ORDER ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE SEE BOTTOM FOR INVOICE F AOGCC AGENCY CONTACT DATE OF A.O. April 10, 2012 R 333 W 7th Ave, Ste 100 Jody Colombie ° Anchorage, AK 99501 PHONE PCN M (9071 791 —1221 DATES ADVERTISEMENT REQUIRED: o Alaska Journal of Commerce ASAP 301 Arctic Slope Avenue, Suite 350 Anchorage AK 99518 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Type of Advertisement SEE ATTACHED SEND INVOICE IN TRIPLICATE AOGCC, 333 W. 7th Ave., Suite 100 PAGE 1 OF TOTAL OF TO Anchoraue, AK 99501 2 PAGES ALL PAGES$ REF TYPE NUMBER AMOUNT DATE COMMENTS 1 VEN 2 ARD 02910 FIN AMOUNT SY CC PGM LC ACCT FY NMR DIST LID 1 12 02140100 73451 2 REQUISITIONED BY: DIVISION APPROVAL: 02 -902 (Rev. 3/94) Publisher /Original Copies: Department Fiscal, Department, Receiving AO.FRM • • Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Docket No. DIO -12 -002. Buccaneer Alaska Operations, LLC has applied for a Disposal Injection Order (DIO) for Kenai Loop #3, located within the Kenai Loop field, Kenai Peninsula Borough, Alaska. The DIO — if approved — would authorize the injection of used drilling mud and other Underground Injection Control program Class II eligible fluids into the Sterling and Beluga formations in the Kenai Loop field penetrated by Kenai Loop #3. The Surface and Bottomhole locations of Kenai Loop #3 are as follows: Surface: 3394 ft FSL, 1124 ft FWL Section 33, T6N, R11 W, S.M. Bottomhole: 1590 ft FSL, 1032 FWL Section 33, T6N, R11 W, S.M. The Commission has tentatively scheduled a public hearing on this application for May 17, 2012 at 9:00 a.m. at the Alaska Oil and Gas Conservation Commission, at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. To request that the tentatively scheduled hearing be held, a written request must be filed with the Commission no later than 4:30 p.m. on May 1, 2012. If a request for a hearing is not timely filed, the Commission may consider the issuance of an order without a hearing. To learn if the Commission will hold the hearing, call 793- 1221 after May 3, 2012. In addition, written comments regarding this application may be submitted to the Alaska Oil and Gas Conservation Commission, at 333 West 7 Avenue, Suite 100, Anchorage, Alaska 99501. Comments must be received no later than 4:30 p.m. on May 16, 2012, except that, if a hearing is held, comments must be received no later than the conclusion of the May 17, 2012 hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the Commission's Special Assistant, Jody Colombie, at 793 -1221, no later than May 14, 2012. P Cathy . Foerster Chair, Commissioner STATE OF ALASKA NOTICE TO PUBLISHER ADVERTISING ORDER NO. ADVERTISING INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED /f, O_02214016 ORDER AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF I"1 ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE SEE'BOTTOMFOR INVOICE ADDRES r: _ F AOGCC AGENCY CONTACT DATE OF A.O. R 333 West 7 Avenue. Suite 100 Jody Colomhie Anril 10.2012 O Anchorage_ AK 99501 PHONE PCN M (907) 793 -1221 DATES ADVERTISEMENT REQUIRED: T • Alaska Journal of Commerce ASAP 301 Arctic Slope Avenue, Suite 350 Anchorage AK 99518 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: AFFIDAVIT OF PUBLICATION United states of America REMINDER State of AIASka ss INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE 1 THE ADVERTISING ORDER NUMBER. „ a � ti c� � 6iSfri C- 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 A Notice of Public Hearing DN HERE. lamriakilac who, being first duly sworn, according to law, says that STATE OF ALASKA Alaska Oil and Gas Conservation he /she is theBus, i Skn - (h.rMl Commission I Re: Docket No. D10 -12 -002. Bucca- Published at Q tpQC� A \i KG in said divisio .JU C neer Alaska Operations, LLC has ap- 1. ! plied for a Disposal Injection Order (Dl0) for Kenai Loop #3, located state of &1SO.. and that the advertisement, of which the annexed within the Kenai Loop field, Kenai Peninsula Borough, Alaska. The DIO - is a true co was published in said publication on the 1 day of if approved - would authorize the it PY. P P Y jection of used drilling mud and othe• Underground Injection Control pro Agri 1 2012, and thereafter for consecutive days, the last gram Class II eligible fluids into the Sterling and Beluga formations in the Kenai Loop field penetrated by Kenai publication appearing on the ( of I. F r I ) , 2012, and that the Loop #3. The Surface and Bottomhole locations rate charged thereon is not in exces of the rate charged private individuals. of Kenai Loop #3 are as follows: Surface: 3394 ft FSL, 1124 if FWL Section 33, T6N, R11W, S.M. Bottomhole: 1590 ft FSL, 1032 FWL Section 33, T6N, R11W, S.M. Subscribed and sworn to before me The Commission has tentatively scheduled a public hearing on this ap- h plication for May 17, 2012 at 9:00 This of ]\('1 I � (p 2012, a.m. at the Alaska Oil and Gas Conser- jj vation Commission, at 333 West 7th Avenue, Suite 100, Anchorage, Alaska +, a �,.i �� \�1 • \L�! — 99501. To request that the tentatively Notary public for state of ‘ 1 I TARY PUBLIC scheduled hearing be held, a written BELINDA CUMM request must be filed with the Com- My commission expires mission no later than 4:30 p.m. on STATE OF ALASKA May 1, 2012. MY COMMISSION ES June 1 4. �n12 If a request for a hearing is not timely EXPIRES 1 4 XP .�.. SJun 14 .r ..,.�s.. filed, the Commission may consider • ALASKA Journal 0 Commerce Alaska Oil & Gas Conservation Commission Public Notices FILE NO: A0- 02214016 Ad #: 10161868 A0- 02214016 DIO AFFIDAVIT OF PUBLICATION UNITED STATES OF AMERICA, STATE OF ATTACH PROOF OF PUBLICATION HERE ALASKA, THIRD DISTRICT BEFORE ME, THE — Notice of Public Hearing UNDERSIGNED, A NOTARY PUBLIC THIS DAY PERSONALLY APPEARED Lara Bickford STATE OF ALASKA WHO, BEING FIRST DULY SWORN, Alaska Oil and Gas Conservation Commission ACCORDING TO THE LAW, SAYS THAT SHE er OF THE ALASKA n ee Docket No. D10-12-002. has IS THE Business Manager Weer Alaska Operations, LLC has ap- JOURNAL OF COMMERCE PUBLISHED AT 301 plied for a Disposal Injection Order ARTIC SLOPE AVENUE, SUITE 350, IN SAID (DI0) for Kenai Loop #3, located within the Kenai Loop field, Kenai THIRD DISTRICT AND STATE OF ALASKA Peninsula Borough, Alaska. The DIO - AND THAT ADVERTISEMENT, OF WHICH THE if approved - would authorize the in- ANNEXED IS A TRUE COPY, WHICH WAS Under Unof derground used drilling C mud and other Underground Injection Control pro - PUBLISHED IN SAID PUBLICATION 'gram Class 11 eligible fluids into the Sterling and Beluga formations in the Kenai Loop field penetrated by Kenai 04/15/2012 Loop #3. 15th DAY OF APRIL 2012 The Surface and Bottomhole locations of Kenai Loop #3 are as follows: AND THERE AFTER FOR 1 Surface: 3394 ft FSL, 1124 ft FWL Section 33, T6N, R11W, S.M. CONSECUTIVE WEEK(S) AND THE Bottomhole: 1590 if FSL, 1032 FWL LAST PUBLICATION APPEARING ON Section m is n R11W, S.M. The Commission has tentatively 04/15/2012 scheduled a public hearing on this ap- 15th DAY OF APRIL 2012 plication for May 17, 2012 at 9:00 a.m. at the Alaska Oil and Gas Conser- vation Commission, at 333 West 7th 114 Avenue, Suite 100, Anchorage, Alaska - p 99501. To request that the tentatively scheduled hearing be held, a written request must be filed with the Com- Bickfor� mission no later than 4:30 p.m. on Lara May 1,2012. Business Manager If a request for a hearing is not timely SUBSCRIBED AND SWORN BEFORE ME filed, s h a Commission of an may without a consider the issuance of an order without a THIS 16th DAY OF April 2012 hearing. To learn if the Commission will hold the hearing, call 793 -1221 after May 3, 2012. In addition, written comments regard - .0 _�a, kit id . , ing this application may be submitted to the Alaska Oil and Gas Conserva- NOTARY PUBLIC STATE OF ALAS tion Commission, at 333 West 7th MY • y _ s ` 6/14/12 Avenue, Suite 100, Anchorage, Alaska 99501. Comments must be received NOTARY PUBLIC no later than 4:30 p.m. on May 16, BEUNDA CUMMINGS 2012, except that, if a hearing is held, comments must be received no later STATE OF ALASKA than the conclusion of the May 17, MY COMMISSION EXPIRES June 14, 2012 2012 hearing. MI If, because of a disability, special ac- commodations may be needed to comment or attend the hearing, con- tact the Commission's Special Assis- tant, Jody Colombie, at 793 -1221, no later than May 14, 2012. By: /s /Cathy P. Foerster Chair, Commissioner Pub: 4/15/2012 Ad #10161868 . • • STATE OF ALASKA NOTICE TO PUBLISHER ADVERTISING ORDER NO. ADVERTISING INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED /L O_ 02214016 AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF I`1 ORDER ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE SEE BOTTOM FOR INVOICE ^ADDRESS F AOGCC AGENCY CONTACT DATE OF A.O. R 333 West 7 Avenue. Suite 100 Jody Colorable Anril 10.2012 ° Anchorage_ AK 99501 PHONE PCN M (9071 793 -1221 DATES ADVERTISEMENT REQUIRED: o Alaska Journal of Commerce ASAP 301 Arctic Slope Avenue, Suite 350 Anchorage AK 99518 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: AFFIDAVIT OF PUBLICATION United states of America REMINDER State of ss INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. division. A CERTIFIED COPY OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED WITH THE INVOICE. Before me, the undersigned, a notary public this day personally appeared ATTACH PROOF OF PUBLICATION HERE. who, being first duly sworn, according to law, says that he /she is the of Published at in said division and state of and that the advertisement, of which the annexed is a true copy, was published in said publication on the day of 2012, and thereafter for consecutive days, the last publication appearing on the day of , 2012, 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 2012, Notary public for state of My commission expires • • Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Tuesday, April 10, 2012 3:27 PM To: Aaron Gluzman; Ben Greene; Bruce Williams; Bruno, Jeff J (DNR); CA Underwood; Casey Sullivan; Dale Hoffman; David Lenig; Donna Vukich; Eric Lidji; Erik Opstad; Franger, James M (DNR); Gary Orr; Graham Smith; Greg Mattson; Heusser, Heather A (DNR); Jason Bergerson; Jennifer Starck; Jill McLeod; Joe Longo; King, Kathleen J (DNR); Lara Coates; Lois Epstein; Marc Kuck; Marie Steele; Mary Aschoff; Matt Gill; Maurizio Grandi; Ostrovsky, Larry Z (DNR); Patricia Bettis; Perrin, Don J (DNR); Peter Contreras; Pexton, Scott R (DEC); Richard Garrard; Ryan Daniel; Sandra Lemke; Talib Syed; Ted Rockwell; Wayne Wooster; Wendy Wolff; William Hutto; William Van Dyke; ( michael .j.nelson @conocophillips.com); ( Von. L.Hutchins @conocophillips.com); AKDCWeIIlntegrityCoordinator; Alan Dennis; alaska @petrocalc.com; Anna Raff; Barbara F Fullmer; bbritch; Becky Bohrer; Bill Penrose; Bill Walker; Bowen Roberts; Brandon Gagnon; Brandow, Cande (ASRC Energy Services); Brian Havelock; Bruce Webb; caunderwood; Chris Gay; Claire CaIdes; Cliff Posey; Crandall, Krissell; D Lawrence; dapa; Daryl J. Kleppin; Dave Harbour; Dave Matthews; David Boelens; David House; David Scott; David Steingreaber; ddonkel @cfl.rr.com; Dennis Steffy; Elowe, Kristin; Erika Denman; Francis S. Sommer; Fred Steece; Garland Robinson; Gary Laughlin; Gary Schultz (gary.schultz @alaska.gov); ghammons; Gordon Pospisil; Gorney, David L.; Greg Duggin; Gregg Nady; Gregory Geddes; gspfoff; Jdarlington (jarlington @gmail.com); Jeanne McPherren; Jeff Jones; Jeffery B. Jones (jeff.jones @alaska.gov); Jerry McCutcheon; Jill Womack; Jim White; Jim Winegarner; Joe Nicks; John Easton; John Garing; John Katz (john.katz @alaska.gov); John S. Haworth; John Spain; Jon Goltz; Jones, Jeffrey L (GOV); Judy Stanek; Julie Houle; Kari Moriarty; Kaynell Zeman; Keith Wiles; Kelly Sperback; Kim Cunningham; Larry Ostrovsky; Laura Silliphant (laura.gregersen @alaska.gov); Luke Keller; Marc Kovak; Mark Dalton; Mark Hanley (mark.hanley @anadarko.com); Mark P. Worcester; Marguerite kremer (meg.kremer @alaska.gov); Michael Dammeyer; Michael Jacobs; Mike Bill; Mike Mason; Mike Morgan; Mikel Schultz; Mindy Lewis; MJ Loveland; mjnelson; mkm7200; nelson; Nick W. Glover; NSK Problem Well Supv; Patty Alfaro; Paul Decker (paul.decker @alaska.gov); Paul Figel; Paul Mazzolini; Randall Kanady; Randy L. Skillern; Rena Delbridge; Renan Yanish; rob.g.dragnich @exxonmobil.com; Robert Brelsford; Robert Campbell; Ryan Tunseth; Scott Cranswick; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); Sondra Stewman; Stephanie Klemmer; Steve Lambert; Steve Moothart (steve.moothart @afaska.gov); Steven R. Rossberg; Suzanne Gibson; tablerk; Tamera Sheffield; Taylor, Cammy 0 (DNR); Temple Davidson; Teresa Imm; Terrie Hubble; Thor Cutler; Tim Mayers; Tina Grovier; Todd Durkee; Tony Hopfinger; trmjrl; Vicki Irwin; Walter Featherly; Will Chinn; Williamson, Mary J (DNR); Yereth Rosen; Ballantine, Tab A (LAW); Brooks, Phoebe; Colombie, Jody J (DOA); Crisp, John H (DOA); Davies, Stephen F (DOA); Fisher, Samantha J (DOA); Foerster, Catherine P (DOA); Grimaldi, Louis R (DOA); Herrera, Matt F (DOA); Johnson, Elaine M (DOA); Jones, Jeffery B (DOA); Laasch, Linda K (DOA); Makana Bender; Matt Herrera; Maunder, Thomas E (DOA sponsored); McIver, Bren (DOA); McMains, Stephen E (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Norman, John K (DOA); Okland, Howard D (DOA); Paladijczuk, Tracie L (DOA); Pasqua!, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Saltmarsh, Arthur C (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA) Subject: 2 Public Notice AEO and DIO Kenai Loop #3 Attachments: AEO 12 -001 (Kenai Loop Field).pdf; DIO 12 -002 (Kenai Loop Field).pdf Jody J. Colornhie Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907)793 -1221 (phone) (907)276 -7542 (fax) 1 • • Mary Jones David McCaleb XTO Energy, Inc. IHS Energy Group George Vaught, Jr. Cartography GEPS P.O. Box 13557 810 Houston Street, Ste 200 5333 Westheimer, Suite 100 Denver, CO 80201 -3557 Ft. Worth, TX 76102 -6298 Houston, TX 77056 Jerry Hodgden Richard Neahring Mark Wedman Hodgden Oil Company NRG Associates Halliburton President 408 18 Street 6900 Arctic Blvd. Golden, CO 80401 -2433 P. Box 1655 Anchorage, AK 99502 Colorado Springs, CO 80901 Bernie Karl CIRI Baker Oil Tools K &K Recycling Inc. Land Department 795 E. 94 Ct. P.O. Box 58055 P.O. Box 93330 Anchorage, AK 99515 -4295 Fairbanks, AK 99711 Anchorage, AK 99503 North Slope Borough Richard Wagner Gordon Severson Planning Department P.O. Box 60868 3201 Westmar Circle P.O. Box 69 Fairbanks, AK 99706 Anchorage, AK 99508 -4336 Barrow, AK 99723 Jack Hakkila Darwin Waldsmith James Gibbs P.O. Box 190083 P.O. Box 39309 P.O. Box 1597 Anchorage, AK 99519 Ninilchick, AK 99639 Soldotna, AK 99669 Penny Vadla Cliff Burglin 399 West Riverview Avenue 319 Charles Street Soldotna, AK 99669 -7714 Fairbanks, AK 99701 \,e 401 • Davies, Stephen F (DOA) From: Davies, Stephen F (DOA) Sent: Thursday, May 17, 2012 11:30 AM To: 'David Doherty' Cc: Regg, James B (DOA) Subject: RE: KL -3 logs in x- section David, No. The Commissioners request that Buccaneer provide larger- scale, legible prints of the well logs displayed on Exhibits 25 and 26 of Buccaneer's Application for Disposal Injection Order dated March 13, 2012. The well logs shown on those exhibits are small and of poor quality. Also, I have searched through the AOGCC's files and cannot find digital well log data for the Kenai Loop No. 1 well, which are required by 20 AAC 25.071. We have paper copies of the well logs, but a page -by -page search of the well history and correspondence file for Kenai Loop No. 1 did not yield a transmittal letter or any other evidence that AOGCC ever received these digital data. I also did not find the end -of -well mud log report or paper prints or digital data for the mud log from Kenai Loop No. 1 that is required by the permit to drill and by 20 AAC 25.071. Could you please provide these in advance of the public hearing that has been continued until May 22, 2012 at 9:30 am? Thank you, Steve Davies Sr. Petroleum Geologist Alaska Oil and Gas Conservation Commission ( AOGCC) 333 West 7 Avenue, Suite 100 Anchorage, Alaska 99501 Steve's phone: 907- 793 -1224 AOGCC's receptionist: 907- 793 -1223 AOGCC's fax: 907 -276 -7542 AOGCC's website: http: / /doa.alaska.gov /ogc From: David Doherty [ mailto :DDohertyftbuccaneeralaska.com] Sent: Thursday, May 17, 2012 10:14 AM To: Stephen Hennigan (shennigan@ peiinc.com); Davies, Stephen F (DOA) Subject: KL -3 logs in x- section Steve, does this help? It's a large of file in powerpoint. Dave 1 • • OVERSIZED DOCUMENT INSERT This file contains one or more oversized documents. These materials may be found in the original hard file or check the parent folder to view it in digital format. • • BUC CANEER A L A S K A March 13, 2012 Ms. Cathy Foerster, Chair RECEIVED Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 MO ? 6 2012 Ar3s .e LJlt ;x (as Cons. Cornrjssion RE: Application for Disposal Injection Order: Anchorage Buccaneer Alaska Operations, LLC - Kenai Loop #3 (Drill Permi Dear Ms. Foerster, Buccaneer Alaska Operations, LLC hereby applies for a Disposal Injection Order to inject used drilling mud and miscellaneous fluids in the Kenai Loop #3 exploratory well. The well was drilled, tested, and T&A'd per AOGCC regulations and is needed as a disposal well. Buccaneer plans to use Marathon Glacier #1 Rig or another capable rig to perform the conversions per AOGCC regulations. Please find attached the Application for Disposal Injection including the requirements of 20 AAC 25.252. In addition, the Sundry form 10 -403 with backup is provided to perform the conversion If there are any questions and /or any additional information desired, please contact me at 713 - 468 -1678 or Stephen Hennigan at 337 - 849 -5345. Sincerely, / A,,ti. ' E.A. Rike Executive Vice'President of Operations Enclosures cc: Allen Huckabay - Buccaneer Alaska Operations, LLC Stephen Hennigan - Petroleum Engineers for Buccaneer Alaska Operations, LLC Buccaneer Alaska Operations, LLC 952 Echo Lane, Suite 420 Houston, TX 77024 713 -468 -1678 • • BUCCANEER Buccaneer Alaska Operations, LLC Application for Disposal Injection Order Kenai Loop # 3 Kenai Loop Offset Block/Sec 33 6n 11w Wildcat 0 Kenai Peninsula 0 Alaska Ser #.: 211 097 Prepared By Buccaneer Alaska Operations, LLC and Petroleum Engineers, Inc (337) 9842603 PETROLEUM ENGINEERS • • Table of Contents Well Locations 20 AAC 25.252 (c) 1 1 Surface Owners and Operators 20 AAC 25.252 (c) 2 & 3 11 Geologic Details 20 AAC 25.252 (c) 4 12 Well Logs 20 AAC 25.252 (c) 5 21 Well Construction and Integrity 20 AAC 25.252 (c) 6 22 Waste Sources, Types and Volumes 20 AAC 25.252 (c) 7 33 Injection Pressure 20 AAC 25.252 (c) 8 35 Waste Confinement 20 AAC 25.252 (c) 9 36 Formation Water Salinity and Aquifer Exemption 20 AAC 25.252 (c) 10 & 11 42 Wells within the Area of Review 20 AAC 25.252 (c) 12 43 Mechanical Integrity of Injection Well 20 AAC 25.252 (d) & (e) 47 Table of Exhibits Exhibit 1 Area Map - Kenai, Alaska Exhibit 2 Hydrologic Survey Map Exhibit 3 Hydrologic Survey Water Wells Map Exhibit 4 Plat NAD 27 Exhibit 5 Plat NAD 83 Exhibit 6 Lease NAD 83 Exhibit 7 Topographic Map Exhibit 8 Aerial Map Exhibit 9 Kenai Loop Pad Well Paths Exhibit 10 Structure Map, Base Upper Confining Zone Exhibit 11 Structure Map, Mid Injection Zone Exhibit 12 Structure Map, Top Lower Confining Zone Exhibit 13 Current Kenai Loop #3 Well Bore Diagram Exhibit 14 Leak -Off Test 1 Exhibit 15 Leak -Off Test 2 Exhibit 16 MWD Final Survey Exhibit 17 Proposed Disposal Well Bore Diagram Exhibit 18 Sand — Formation Layers with Mechanical Properties Exhibit 19 Mechanical Properties Output Graph Exhibit 20 Half Wing Models Exhibit 21 Half Wing Model —155 BPD Exhibit 21a Half Wing — High Rate Exhibit 22 Kenai Loop #1 Completed Well Bore Schematic Exhibit 23 Kenai Loop #1 7-5/8" Top of Cement Exhibit 24 Kenai Loop #1 10 -3/4" Surface Cement Exhibit 25 Type Log Exhibit 26 Cross Section Appendix A Affidavit Appendix B Fracture Study • • 20 AAC 25.252 c 1 Well Locations The map on the following page (Exhibit 1) is a regional map showing the general location of the well on the Peninsula. Exhibits 2 and 3 shows the specific area with water well information provided by the Hydrologic survey department of the DNR. Exhibits 4 and 5 are the as drilled locations of the well of interest and the only close well. Exhibit 6 shows the boundaries and lease owners. Exhibits 7 and 8 are the topo and aerial survey maps. Exhibit 9 graphically shows the well courses. The Y mile area of review (for the injection interval) indicates that there are no wells other than the Buccaneer that come into play. 1 • • roSS/ 1 V0/0/0 Nordaq Energy Permitting second well plus road and development � facilities on Shadura prospect based on encouraging 7, - � ;as shows from initial exploration well. i` Birch Hih SHADURA1 f *SUNRISE 2 'South Swanson River Middle Ground Beaver ,� Shoal Creek Nikiski y Buccaneer • BCLiaorg& 19 Completed and tested the Kenai Loop No. 1 well. Tested 2 zones at a rate of 10 mmcfpd. Estimate 31.5 BCF of proven reserves. Satamatof Signed supply contract with Enstar to provide 5 mmcfpd starting in 2012. • • Kenai Loop 1 Deliniation well Kenai Loop No.3 bottom hole location 1700' to south Kenai Cannery 4 . — Kenai Loop encountered sands depleted by Cannery Loop Unit Production. t Loop "• Cooper r • Soldotna Landing • t, KBU 42 -6 `' Kll 22-6X CINGSA (Enstar) Kenai / KBL' 11 -17X DNR issued a gas storage lease (7/1/2011) for Sterling C sands in the Cannery Loop field. C ar'iAery fir, ,..: L 0 p U , , --, 11 - -,, I 1 ' Area of Proposed , i -. 1_ I Kenai Loop #3 11114/Arm ' t f Disposal Well N Al dell 1� ' 1___ +- 16 ��111 Ig I.w -. !'r t , I � Exhibit 1- Area Map - Kenai, Alaska 2 • • T • 30061411h S 1 2W I • • r.. • ra T II • • • 1 • eta r3 / $ • irrill ___,______-- • it..... • 0. su u•� / . / ( • N �.. " �} i. • 1! F .. - • • •, / I � • I r\ r 1 ! 1 1 ( 1' � H - :1 \ \ �, • V . " \N ` / - r ✓ -- ' ` r r I \ � . . , til, � I 1 Exhibit 2 — Hydrologic Survey general map 3 q r4 1.1i �1 7-1. L31 1 r�1r�w..MA + Luau A'RI H 1 01 ,, ........ _ r .! ,,,, . , . lit i. . , . .f. „E„,, I. . ... ., . ,..., ry11..:.... :..1..., 111111011 ...y _ r a Al a CO ,f. - 1 . 1 11 • 111 11.111 n iar.ati .• a..A e I MOSS • ;••= -a - i3_ il•'2set �' - UV Per y Ti ..1 iT—�JT 1 . . h• Aaa. vi ii fyal � b�r',�� I��u _.., �., e, 5kr 1 CM 4111 ll 1111116 .1.M a.Y:SI Ii . .. 111111 I u•1. „... or. T rortrswoo • 1.o.. :n•u� L W f - w. .1vu.I 41 r•.aq L Q s +i1•■.i1�'AII .S �fl••••■••■-11 ...S•4 -s . I y yMM ■o+ - �— _ �—. _�� _ e k I I +I I Migild p dogs; amyl _Lam l • • S 29 S 28 , CITY of KENAI SEC 28 1/4 S 32 • S 33 SECTION LI oit TO SCALE • ' • — • I i ' SEC 33 �.‘�. • T ' ' 1 •• ` '' 4 Q q S '• I r y • i _ *I. � •• .*0 ' � _ ( � :. .. Y,,.•.... - NORTH I \ S A. TAN YDLAlE ; .. ��, -. -�. I I ' / / I .. 4837-S - W • , ' ' .1 11.1, • %% SCALE • . 1 l I r 0 200 400 � 031 o ; 1 L F� . � .• g. zre p D '_ _ + • oI i I m 0 3 p a CITY OF KENAI ~ w r �i UNSUBDIVIDED f z 7.4 y 3 ;! 1 PORTION OF z z • 0 • � SEC 33 TEN R11 W DO e LLI s. W lo i i ! 24• woe Access ROAD 1 O . °J l .6 °I uj 1 •" ( I f BUCCANEEF O.0 w I I ! • KENAI LOOP III PAD . • l ORLL NJG PAD I , , . ELEV. Sts srAGNG AREA ks KENAI LOOP III \ ' N-1134 1134 3 • - . 1503•— —N \,.. $ @ T om\ i I 51 g o • . 0, s .I t C OF KENAI KENAI LOOP NO.3 WELL I ! RACT - AS-STAKED SURFACE 1 1 I r 0 LOCATION I � ; SEC 33 TON R11 W NAD27 ASP ZONE 4 i • � ' LL•3 GRID N.2402267.308 I I GRID E: 279614.700 , I ' . ;. I LATITUDE: 80'34'11.498' N ` LONGITUDE: 151'13'30.280' W t i ' ELEV. 92.5 NAVD88 I 1134' FWL I ( 1888' FNL • t SECTION 33 TO6N RI1W SM AK I • + 1. BASIS OF HORIZONTAL AND VERTICAL CONTROL WAS 1 1 DETERMINED BY AN NGS OPUS SOLUTION FROM CORS BASE • STATIONS'KEN1 PID AF9548 ",'TSEA PID A10957 AND'ZAN1 PID DE9153' OBSERVED AUGUST 17, 2007 FOR MCI CONTROL STATION I I I KERR : ALASKA STATE PLANE NAD 83 ZONE 4 EPOCH 2003 DATUM N: 2367475.381 • E: 1409643.183 I ELEVATION: 133.963 GEOID 06 NAVD88 DATUM I COORDINATES WERE CONVERTED FROM NAD83 TO NAD27 UTIUZING CORPSON VERSION 6.0.1. 2) SECTION LNE OFFSETS DETERMINED FROM DIRECT SURVEY I TIES TO THE TO EXISTING BLM CORNERS RECOVERED AND NOT 3 32 THE PROTRACTED SECTION CORNER VALUES, S 33 O6G LEASE BNDRY TEN • 9 5 • S 4 SECTION LINE NOT TO SCALE • • ' • — • ' • •—•— • — • — • • —1u. S . 4 BUCCANEER ALASKA, LLC PROJECT REVISOR t 952 ECHO LANE DATE 01JI9 SUITE 420 KENAI LOOP NO.3 WELL AS- STAKED DRAWN SY: Ord NIYY A��a�O HOUSTON, TX 77024 SURFACE LOCATION DIAGRAM NAD 27 SCAM 1•.20p PROJECT NO. JISOS? SNssOO6NNG tMAPPNO rINAVK/rNMESTPIO BOOK NO • ____ApPLEHE Inc P.O. BOX MN tOLOOTNA AK MS LOCATION S EC. 33 T6N R11 W SHEET LOOM NO) -42IS FAX OCR MOONS SA CLANE(TMCANEOICON SEWARD MERIDIAN, ALASKA 1 °F1 Exhibit 4 - Plat NAD 27 5 ID • S 29 S 28 } — —" CITY OF KEt4A9 SEC 28 1k S 32 • S 33 ' SECTION LIN NE OT TO SCA --- LE • �- • '-" ` 1 SEC 33 1 T i • • `` �t�.\11 4 I P�� o F q�'IS4�I \ I ? * * f, NORTH • STAN A. urAANE : — L — • �� `,ILLS W N • ° y SCALE w O gig: to: . 0 200 400 z o o; L / I z Iii • y ' ! a CITY OF KENAI I FEET I } W z Z ' I I 1 ;y • - UNSUBD9VIDED . O • w ' o PORTI OF z ? SEC 33 TON R1I W m -J O J I I r w n • �` - • �IO r 1 p • N WM ACCESS ROAD P;13 • 1 r I BUCCANEEF ` O °0 I W I UJ f - KENAI LOOP #1 PAD ` i DRUM PAO \ E,EV, gLE STACWG AREA ' • • r 1 `\ KENAI LOOP AI 1 / : + _ 1 503 – ----1134' � • .- FWL g —�I Ps b F 40\ ' W .,. D o- CITY OF KENAI KENAI LOOP NO. WELL I I I !g I ! TRACT A-1- Kt4 0970051 ° LOCATION SURFACE I � ' ; SEC 33 T8N R11W e' GRID 3 02029.888 GRID E:1419635.016 ; I LATITUDE: 60'341)9.446' N ' LONGITUDE 151 W I ELEV. 92.5' NAVD88 I 1130• FWL I 1886' FNL . SECTION 33 TORN R11 IN SM AK • 1 . 1. BASIS OF HORIZONTAL AND VERTICAL. CONTROL WAS I I DETERMINED BY AN NGS OPUS SOLUTION FROM CORS BASE ' STATIONS "KEN1 PID AF9548 ", 'TSEA PIO A10952" AND "ZAN1 PID . DE9153" OBSERVED AUGUST 17, 2007 FOR MCI CONTROL STATION I KERR : ALASKA STATE PLANE NAD 83 ZONE 4 EPOCH 2003 DATUM I N: 2367475.381 E: 1409643.183 • ELEVATION: 133.963 GEOID 06 NAVD88 DATUM I I 2) SECTION LNE OFFSETS DETERMINED FROM DIRECT SURVEY TIES TO THE TO EXISTING BLM CORNERS RECOVERED AND NOT I THE PROTRACTED SECTION CORNER VALUES. : 3 5 2 . S 33 O&G LEASE BNDRY T6N • S 4 SECTION LINE NOT TO SCALE T5N " �' _� �� •�� !4• S . S4 PROJECT REVISIOIK 1 F = BUCCANEER ALASKA, LLC DATE 07/10120n t3 ' 952 ECHO LANE SUITE 420 KENAI LOOP NO.3 WELL AS- STAKED DRAWN 0Y: ,I 0� x.11„ HOUSTON, TX 77024 SURFACE LOCATION DIAGRAM NAD 83 SCAM 1.400. • PROJECT NO MOP BOOK Kt - ENWff.ERINOI ~PIMP SuRVENIIIII/TES T NO cam a l� . HIM u ° F, O E. `0CATIDN SEC. 33 T6N R11 W SHEET WAIL SEWARD MERIDIAN, ALASKA 1 OF 1 Exhibit 5 - Plat NAD 83 6 • I BUCCANEER ALASKA, LLC BUCCANEER ALASKA, LLC MHT 9300082 MHT 9300082 SEC 29 SEC 28 NORTH SEC 32 SEC 33 CITY OF KENAI T 6N R 11W SEC 33 SEWARD MERIDIAN KN 2004017 W112 SEC 33 LYING NORTH OF KENAI SPUR HWY cc CIRI PENDING LEASE z Z o U. LL 6D F., o - 2 0 z w BUCCANEER -j KENAI PAD - 1124' FWL - , rye -- 1513' FEL — 1064' FWL -1 573' FEL KENAI LOOP NO. 1 KENAI LOOP NO. 3 WELL AS -BUILT WELL AS -BUILT SURFACE LOCATION SURFACE LOCATION BUCCANEER ALASKA, LLC ADL 391094 BUCCANEER ALASKA, LLC ADL 391094 ti LG U. LL 0) Cl m BUCCANEER ALASKA, LLC MHT 9300082 { CIRI PENDING LEASE SEC 32 SEC 33 SEC 5 SEC 4 MARATHON ■ KENAI LOOP CANNERY LOOP UNIT SCALE NO. 3 DATA 0 800 1600 ( I I 1111 KENAI LOOP FEET NO. 1 DATA BUCCANEER ALASKA, LLC PROJECT REVISION: ' 2500 TANGLEWILDE AVE., SUITE 340 KENAI LOOP NO. 1 & 3 WELL DA 2728/12 HOUSTON, TX 77063 OIL & GAS LEASE BOUNDARIES DRAWN BY: 1308 SCALE: 1'°800' NAD 83 PROJECT NO. 123005 ENGINEERING I MAPPING / SURVEYING / TESTING BOOK NO. - IN Conwl$ng A, Inc P.D. Sox 459 SOLOOTN AK. 99699 LOCATION SEC. 33 T6 N R 11 W SHEET VOICE: (907) 253.1215 FAX: (907)2633265 EMAIL: SAMCLANE@MCUNECG.COM SEWARD MERIDIAN, ALASKA 1 OF 1 Exhibit 6 - Kenai Loop Lease NAD 83 7 • 0 �! + 1 • - • • 1 t • • — • fi r• 0 . !III' i ♦ It!— w • t 1 // 4 a • • • 4 • • 1 1 I � ' 3 _ 2 33 I � , I / . e r . .c o b • } . w 4 r.' / . - ` ,f.. • ' 1 ' j+ L. .• • • It • . • • ') 1 1S ♦ • • # * • lb - i .� • • • /' v , 1 -- _ 1 r r • Sj .r �1 1 1 ♦ + ,. I, 1 44 7 3 • u , 1 • 'l` ,� •_ • 9 Scale 0 1 'Miles I t I Exhibit 7 - Topographic Map 8 • • 1 • it - S _ t 4Ift f , '.. f e C7 , 4 a - w a , t V� Y .. 9 it , . ) 4 r i 1 Q N . r. I 4 e r Exhibit 8 - Aerial Map 9 • • Buccaneer Energy, Inc. Vain! ilk. , Location: Cook Inlet, Alaska (Kenai Peninsula) BAKER Field: Kenai LWp HUGHES Facility: Kenai Loop Pad 1 BUCCANEER Plot reference wellpalh is New MWD <207 1oea0c E; 1 I R <; y True vertical depths are referenced to Glacier #1 (RKB) _ _ Gnd System: NAD27 I TM Alaska 8P. Zone 4 (5004). US feet - - - Measured depths are referenced to Glacier 01 (RKB) North Reference: True north Gacier $I (RKB) to Mean Sea Level: 113.3 feet Scale distance — _Mean Sea Level to Mud fine (At Slot .SSlot y1): 0 feet Depths are in feet _ Coordnetes ore In feet referenced to Slot Greeted M. 1onethoh on 22- Nov -11 e.b inch Easting (ft) - 500 -975 -250 -125 0 125 260 975 500 _ 1 1 1 I 1 I I 1 I' Slot #1 Slot #2 0 — 1000 11 i� — 0 2000 — 5V8 7000 •••• 4000 10000 , e4 . ,C -376 - - - 375 -500 ■ ■ , bop -025 ■ - 425 5000 -750 - - -750 - 876 - - -875 0 rn c t 5 . c to 0 R, Z .1000 - - -1000 I -1125 - - -1125 6000 1 - -1250 - - -1375 _1500 ■ - -1500 7000 -1625 - ■ - 1625 -1750 - ■ -1750 rrr � �\ -1876 .- c \ - -1875 1 I I 1 I I I I I - 500 - 975 -250 -125 0 125 250 975 500 400rorh.2501 Easting (ft) Exhibit 9 - Kenai Loop Pad well paths 10 • 20AAC25.252c2and3 Surface Owners and werators There are no other operators in the development area. State of Alaska, Mental Health Trust (MHT) and Cook Inlet Region, Inc. (CIRI) are the surface owners in the development area. A copy of the application was provided to MHT and CIRI and a copy of the affidavit is attached (Appendix A) showing that MHT and CIRI were provided a copy of the application. 11 • 1 20 AAC 25.252 c 4 Geologic Details The Kenai Loop #3 well is located on a north plunging anticline. The focus of the exploration efforts has primarily been in the Tyonek Formation. At the shallower depths that are the focus of this application the structure is unfaulted near the borehole. A thick sequence of Pleistocene glacial outwash deposits covers the ground surface. These glacial sediments were deposited by high - energy braided streams. These sediments are comprised of sands, gravels, sandy gravels, and pebbly sands, inter - bedded with low permeability glacial flood lain deposits, consisting of clay-rich sandy silts silty-claystones. y g p p g y y is and silty claystones. The thickness of these deposits is difficult to determine due to their lithologic similarities to the underlying Sterling Formation of Pliocene age. The contact between the Pleistocene glacial outwash deposits and the underlying Sterling Formation is estimated to be at a measured depth of 3276' (3273' TVD, -3160' TVDss). In this part of the section there are potential barriers including bentonites and thin coal seams together with some clayey mudstone. For example vertical barriers to movement of fluids occur at 3068' (3066 TVD, -2953' TVDss), and ^'3200 (3197' TVD, -3084' TVDss) to 3300' (3297' TVD, -3184' TVDss). This 100 ft thick interval contains a section that more silty and muddy then overlying deposits.. The Sterling Formation consists of a thick sequence of braided stream deposits representing a broad braid -plain across much of the Cook Inlet. The Sterling Formation in the Kenai Loop wells is approximately 2300' thick with the base of the Sterling at a measured depth of 5,580', It consists of multiple thick sandstones and conglomeratic sandstones inter - bedded with thin siltstone sequences often with thin coal seams. The coals are more abundant and thicker in the lower Sterling Formation. The sandstones of the Sterling Formation are poorly consolidated and form excellent gas reservoirs due to their high porosity and permeability. The siltstones represent flood plain and local flood basin deposition. The associated coals represent swamps and marshes developed on the flood basin deposits. Underlying the Sterling Formation is the Beluga Formation of upper Miocene age. The top of the Beluga Formation is at a depth of 5721' MD (5531' TVD) in the KL -3 well, and at 5580' MD (5577' TVD) in the KL -1 well. The base of the Beluga Formation sits on the mid -lower Miocene age Tyonek Formation at a depth of 8,333' MD (8329' TVD) in the KL -1 well and at a depth of 8554' MD ((8193' TVD) in the Kenai Loop #3 well. The Beluga formation in the Kenai Loop wells is 2750' thick. There is a marked contrast between the Sterling and Beluga Formations on logs and in outcrop. The Beluga Formation consists of a network of multiple small meandering and anastomosing streams related to an axial drainage system generally flowing to the south (down the axis of the basin). The Beluga formation is a muddy sequence consisting of abundant thinly 12 • 20 AAC 25.252 c 4 inter - bedded siltstones, mudstones, and sandstones, with abundant thin coal seams ( <1 -2' thick). Diagenetic clays are abundant in the Beluga resulting in lower permeability in much of the Beluga. The Beluga is also a major gas reservoir bearing formation throughout much of the basin. The Tyonek formation is approximately 6,000' thick in this part of the basin. The Tyonek formation is a thick sequence of basinal deposits consisting of large and small meandering stream deposits with associated fluvial and local lacustrine deposits. The Tyonek contains numerous relatively thick coals (generally less than 10 feet in thickness with occasional deposits of 30 -40' coal. The Tyonek contains a thick section of mostly siltstone interbedded with occasional sands related to the axial fluvial system deposits. Along the flanks of the basin, braided streams have built a series of coalescing alluvial fan deposits in the Tyonek formation. These alluvial fan deposits thin into the center of the basin. The Tyonek formation contains an oil reservoir nearby in the Beaver Creek Field to the northeast of the Kenai Loop area. It is a significant gas producer in nearby gas fields such as the Cannery Loop and Kenai fields. Sand at 9700' MD in the Kenai Loop #1 is now producing gas at commercial rates. The Kenai Loop #1 and #3 wells were drilled by Buccaneer Alaska as gas exploration wells. Reservoirs in the Tyonek were the major targets in this drilling. Production was established in the KL -1 well in two zones in the upper Tyonek. The KL -3 well was drilled from the KI -1 pad and was deviated to the south to catch the Tyonek sands in an up -dip position. Results suggest that the KL -3 well is separated from the KL -1 well in the Tyonek by a down -to- the -north normal fault. Tyonek reservoirs in the KL -3 well were tested as wet. In addition, the 9700' sand in the KL -1 well is not present in the KL -3 well. 13 • 20 AAC 25.252 c 4 injection and Confining Zones As the type Log (Exhibit 25) and cross section (Exhibit 26) illustrate, the injection zone that is proposed in the upper Beluga between 5721' MD (- 5418'TVD -ss) and 7025' MD ( -6591' TVD -ss). The injection interval is about 1173' thick and is in a portion of the Beluga formation that contains several thin fluvial sandstones. Several rotary cores were attempted in the proposed injection interval. A summary of results is listed below. Porosity and Permeability of Sands within the Proposed injection interval Measured Depth TVD and TVD-ss Permeability Porosity Comments (feet) (md) (%) 5928 5717'tvd, - 5604'tvd ss 128 20.7 6207 5967' tvd, -5854' tvd ss --- -- 29.1 6275 6028' tvd, -5915' tvd ss 0.105 26.2 6342 6087' tvd, -5974' tvd ss 0.165 25.2 6441 6175' tvd, -6062' tvd ss -- - - -- 6542 6266' tvd, -6153' tvd ss 1.85 18.5 6698 6405' tvd, - 6292' tvd ss - --- 22.7 6745 6447' tvd tvd, -6334' ss - -- 19.9 6796 6493' tvd, -6380' tvd ss 0.001 1.9 6953 6637' tvd, -6524' tvd ss 13.2 16.6 The fine grained confining units are laterally extensive over the area and act as a vertical barrier to vertical migration of fluids. Structure maps of the top of the lower confining zone (Exhibit 12), top of a mid -point sandstone in the proposed injection zone (Exhibit 11), and the base of the upper confining zone (Exhibit 10) were constructed to better illustrate the zones of interest in the Kenai Loop #3 well. 14 • • 20 AAC 25.252 c 4 The upper confining zone is between the Top Beluga formation (5721' MD ( -5418' TVD -ss)) and base of the lowest massive sand in the overlying Sterling formation (5332' MD ( -5068' TVD -ss)), a true vertical thickness of 350'. This interval is rather shaley and contains inter- bedded siltstone, claystone, mudstone, thin coal seams and occasional thin sandstones. The lower confining zone in the Kenai Loop #3 well occurs between measured depths of 7052' � ( -6152' TVD -ss), and 7250' ( -6802' TVD -ss), a thickness of 650'. The lower confining is similar to the upper confining with nearly identical Lithology: inter - bedded mudstone, shale, siltstone, ° siltstone, thin coal stringers, and occasional low permeability sandstones. Reservoir Properties The proposed injection interval within the upper Beluga formation contains numerous sands with an average rotary core porosity of 22.6 %. Permeabilities are generally low in these sands, but some are up to 128 md. Two DSTs were attempted in sands within this interval. DST #6 (6435 -6450' MD) sampled 6000 ppm CI water. The other test had no flow. 15 i • BELUGA Depth Structure (subsea) Structure Map — Base Upper Confining Zone k Grid: kenai BELUGA 5S Dpth Struct_From_CntrEdits 120223 (CEM) (Red), Data Type Depth (Active Contour Kenai BELUGA SS Dpth 5truct 12... o i O-1 'i E3 i Feet 285600 CP ,0 -5T 00 45 00 • 6.' ., ..s,. Q 1 7---- - .00 '. , cs, , / 111111111/11/ 500 BKLI - 5465 - -- ^ 14 33 34 -- -- -5414 0 M,,4 B 2400 fr Ili -5214 \\ •, � to .7 , . o -5206 Scale =1:13690 t II � .. p* ) 1000 2000 3000 n L' r r X:288505.60, Y:2408274.09 Feet, Let:60'351224248• Long- 151'10'34.55269• Depth 5888.77 Feet Exhibit 10 - Structure Map, Base Upper Confining Zone 16 0 • Structure Map — Mid - Injection Zone ij, Gnd• Kenai KL3_Drsposal Sand S5_Dpth_Stwctj20223 (CEM) (Blue), Data Type. Depth (Active Contour. Kenai_KL3_DisposaL Sand_SS_Dpth_Str t !I E3 I ral ®1 ■;4�J.L001 _ I I SOi . ©ejo®ra XR _. _ Feet 35600 ge,OC ` W ge ° � 0 .. ' 6 g0° - 6300 ' 2 00 s 6 030 a i 6,p0 -6200 L HKL" III 0\ 00 h$ 3 ' B 10, G -N57.- 7 I 41N ot ( 1.13KL3 2400070 -) f I O. A,/s ` Sub - 1:12000 .�_._.Q, . 1000 2000 3000 n - X277381.00. Y:2408033 00 Feet, Let60157 85791". Long - 151'14'17.13976", Depth - 7119.49 Feet Exhibit 11 - Structure Map, Mid Injection Zone 17 • . Structure Map — Top Lower Confining Zone 1 k Grid Keenm_KL3_BASE Disposal Sand SS_Dpth Struct_120223 (CEMt (Red), Data Type. Depth (Active Contour Kenai KL3_BASE Disposal Sand . = O I i l ea e . , * a l 01 — I ° I , : . I Y i . 1 0 / C) I c , - 1:21 El 61 X 285600 Feet_ _ .�00 6 1 5� 1000 , -69 2 0 0 .._ N. 68 L , , , i , f i ., BKLI 33 'sue 111144 �� - 6650 . -BKL3 24 t v^, 66� oa r s� o 4 3• Scale - 1:12000 is � C 1000 2000 3000 R i' t X290423.00, Y:2408019.00 Feet. Lat60'358.28011 " Long 151'1316.24585'. Depth: - 717718 Feet Exhibit 12 - Structure Map, Top Lower Confining Zone 18 • • Buccnnoor Atom, Kenai Loop #1 1 c Log rii Depth(ft) , 3000 - a `IV!!' UM a :'ae WE 3100 - Eli .. NI Etii g'Ii3 I it'. El 3200 - 3300 - t!! 'AI ®llni €: Ell I III El Kenai Loop #1 Eli WI , . i lfl lti� AIWA �A El 3400 - LIE 9171E2 Irl Type Log 3500 - a'; Ei III ° — 111 1 3600 - swirl a alit .99�' i AI Fs 3 700 - IC:: dB . , RI Fii. " ligl a s In 3800 - E '" gi tit, -!e a p v m 3900 - u- ,� ' "' 3,Dltir =- -111 Measured Depth (ft) 4000 - M SI III; mil: ES 4100 - � . ,. E i lli�. `s_Ifl i is I 111 4200 - IV= ia: O° s i it : tail a ill as 4300 - i .' i e°EE .. iii Nip NAPA I A 4 a$ 4400 - ' r_-- ma - air !LIM III 4500 - t l ElIlk,MII!B! 4600 - . i a It Illiu all a R-.1 as 4700 - �, 1 OHM ICU 4. 3 a'a is 4800 - j illl alit, VII 111 III 4900 - `1' 01 ... 1E104 Ai3 I El ill - O • :VI IN EIii6 - .1!1 i 33i I$ 5100 - IR NE iail EliiG AEI MI El 5200 - -sas iii car, lin a 116;.: asc 5300 �� 'Ai': +tee • a 11C...- - !IrI ii; IIII11I 11 �- � - 5500 - g � Ve IK, Ell i � � 5600 - M ": - MI INN. 'ill I I0€ _E 5700 - so nr• VW ■ Wr. aa>s 5800 - W IN alm; .3111 i 60 00 - M "M siI rat : 43;3 a 6100 - EL 4 w MINI , ..1111111E 6100 - MIL El OS :;lit I IL 0 6200 - I =' Ii Ei3 ilia a la ral 6300 - li�pr • ■ aaar ZS 6400 - ��.� , .. - w � � s cl i a +sae sit za a cllc= �!Iw a aaa: 6500 - C MI =�:ilai 6600 - 1- OE ME .a Ent . :; I It 3 6700 - NE :i IN IEEE • +liai I Ilt; iii 6800 - CD Mg *Willi Ili I IS NI 6900 - '-w . 13 ,. ii €liE'c aiiaii — 7 - Ent lo - v ;a 3 `:I Elili! M I IC 7200 7300 - m Et r$ 11 II!t ill I $ Ill 7400 - 1$ iiii Ellin iill iii i$ II al1E� 1{ I t� al 7500 - : !E I.... a MC la ;1.3 a le 7600 - i 1" ' DI EtiiK 'AEI a 7700 - it ' $ il Ilt .lip i or ii 7800 - We .3� ' " WEE: •Ila a L9 7000 - §_•�+1 .. IIIEWAiI "' 8000 - !a ' i l l :4 1E1 MI 8100 - a: = a:1Ni 't1i 8200 - Al 1 a « 11 r, i ■ 'mg' .- si>tm_ l ,.. 8300 - v/ Melt -,-L bra y,r eu:m: _lei ■ ass a 8400 - i , Exhibit 25 Type Log 19 • • <0.02MI> .< } Buccaneer Alaska TVD ss (ft) Buccaneer Alaska Operations Kenai Loop #1 Kenai Loop 1 3 MEN ...ljrzumm moNIIIINIero •milmi hem s._ MINE1.'kaa■ MME • Milli 4.800 it a= Elk Mill 1MIME Eil III 119,.) IP MI iiiiiIli i 111111 Be NM nil Nil k- lila 5006 11111® E111111 11111211111111111 1.1. ' 1` 111$1® ar 11111111111 11111wMOElla111 alli® s nil f ifl - - ai ff I : NN i 0E mid fir - a! I. M I w . : MINI m rlr • am M -5400 1,1 t L Ei Ill a. p � �1p 1 . E 57011 ,` till!! i` N fl11 -5r. II ill IP'NI F - 44 Mb RiI arz mil 15922. MT AMIN PERM -129 94"92% PC IF r� nth" i MEM - S If .8 .. gym•• °�IIU ice -SA 00 ->l - Ir'-ai UM .4 1I • rr 6.146) ! a Ir 1 — am G� — P 1e! ✓�.. NO PERM , P08 = 29 9% ^ ' 1 ' 1 ' �s.35��. .�_ . ' 'NI 8W S - e _ � _ _ PERM = 0105 MO PC -44 = IMP . rP11M S!. : I , R 41 - . 11 1 IMF !!1 •-�1 (6 371) 1 " PERM = 0 165 md. POR = iIX .r MEM IriiiI 7-111.111Z11:1 Mir 1» a de . .- Y t _ - - - 6200 11 1 I♦ MO lag M 1 -8.200 •ur 1N = Ss. VFG SHALE; : I l (6 III 6 ing; 4 1/ IP 1.,59) m r erm P - i 88 md, PaosN SINN -6400 lit I I/ SI - -6.100 . ilt - IN 11i I mo. it? 11111 (6 �11' p I 2 16,817) o o w si - @0001 md. Pe" lEr E ' -6.600 AI I a - 8 n T . 6011 BE !I m _ min II IF Ai 13 2 and Porosry = It i ''.7,•' ill ® AIM:icei'i le i' .: ;.. 11 11 Mk NI IP a _ .8 lilt MI gill lil • ( 961 �:: =M I In t + _ — -� v 246' �sr SX NM OD . k = . e �a y 1 ¢w¢1 a� � _ I azo {711 .1 i� .., •7 its { �a Pe TO t Pnosry = E. i ' in i i M li SS VFG WELL CEMENTS imi= mo _ VENNI III i =I r ."1 mai maring i1 in. Perm no, measured Paost i -7200 21E1U - -. 111111111 'zei -7200 Mir : el a NM �I 1 i r` u VF.OPLCAREOANL WAKE (7,316) �fi • ��I � lb 21 Mr .� .. [ �� II IBA Perm nd meesxed. PUSaraait IBM Nip --- INI rrrl .� FF.; --em Ir IN O NE. ie N •7.400 >– U1 IMP -11Z1 be V _IX -7.100 Meow 11 11 ,E iiZia CNP51 co.ered • No P &P ( 1 , -INI ■ctrl Wit -- .8 ') NM MIMEO II MI6 ' r _��NI 101 111 =oat _ " 1. 311•1111 IS MCI. = -7 Ili : � R 1 111 Z i.. . EV ; �IpI II 0 11 NE _IN= .71.1 9 91N 1 � � e C N•rfe 3 i s �.r , 1 iiiµ Zi .I - 7.663 ilk iii1k AI 1111ANIIIIIVZ -claw" (6.2r4) i•Nl c,ilIG i c Ms" - 8.000 � - � - 6,600 MEE OM ^ ■ � �•�� IM ., ,1' I = 7gi�I I �' $ li i � @ (. I !lp g E¢ NJ •8.206 1: •i -6266 Mk IUC tiZ Exhibit 26 Cross Section PE,RA 7!13 2 11 33 PM 20 1 20AAC25.252c5 Well Logs Well logs from the Kenai Loop area have been provided to the AOGCC. Additional copies can be provided if necessary. 21 • • 20 AAC 25.252 c 6 Well Construction and Integrity Kenai Loop #3 was directionally drilled from a surface location 1134' FWL, 1888' FNL of SECTION 33 TO6N R11W SM AK. It was directionally drilled to 11362'MD/11000'TVD on a +-180 deg AZ (Exhibit 9). The well closest is the producing Kenai Loop #1 1037' FWL, 1888' FNL of SECTION 33 TO6N R11W SM AK and is also noted on the spider. The top of the injection interval (upper boundary @ +- 5030'0 in KL #3 is approximately 575' from the KL #1 wellbore. It is also approximately 725'(Vert sec) from the surface (751'south and 41' west). Original Construction The well was drilled and tested in 2011. A schematic of the well as it is currently temporarily suspended after testing is shown in Exhibit 13. Additional pertinent exhibits (Exhibit 14,15 & 16) are also attached. Waiver Request A waiver request will be submitted to allow a variance to MC 25.412(b) to allow more than 200' between packer and injection zone. This will allow through- tubing access to the entire requested disposal zone. The proposed well configuration is shown in Exhibit 17. 22 ! S 20 AAC 25.252 c 6 General Conversion Procedure Pre - service work Procedure: 1. Review with all vendors and be sure logistics are predetermined. 2. Be sure permits are applied for and in place. 3. Tree and wellhead were installed in 2011. Review details. 4. Make sure all valves, gauges, etc. are installed and working properly. 5. Review and record all pressures 6. Prep for cased hole work. General CONVERSION Procedure: Part I 1. Notify regulatory agencies at least 24 hours prior to operations. All operations will comply with AOGCC regulations. 2. Move in and rig up well service or drilling rig. 3. Mob to location, conduct pre job safety meeting, perform JSA's, begin RU of equipment and establish RKB. Adjust all elevations to RKB indicated on welibore diagrams unless noted otherwise in the daily reports. Note: KB on log is 21'. 4. Ensure all permits are in place. Perform prejob "spud" meeting. 5. Check all tubing and casing strings for pressure and record. 6. Conduct safety and operations meeting. 7. Based on excerpts from reports below, REMOVE wellcap and NU BOPe. Test per AOGCC to 5000 psi. 10/26/11 R/U Pollard E -line - M/U Baker setting tool to EZ drill CIBP - RIH, correlate - set CIBP at 6,400' Tag plug- POOH - RID E -line R/U pollard slick line - Dump 60 gallons cement on top of CIBP - TOC 6370' + - R/D slick line Test 7 5/8" casing plug to 1500 psi, chart 30 minutes - test good 10/27/2011 N/ D BOP stack and clean pits Start to L/D Top drive - install well cap w/ Vetco Gray 23 • 20 AAC 25.252 c 6 8. PU bit, bha w/ scraper & TIH. Bit should be capable of drilling a 7 5/8 EZ -SV Cast iron drillable bridge plug. 9. Tag cement and circulate and condition fluid in hole. Test casing to 3800 psi. (70% of Burst =4823 psi, original casing test was 3800 psi). d'tW'Lll'{.,<? .�. d l l�'Tc [ �� 3u i= ,.,..x Fs� `9` `. !� a...t-, r Y¢ � '0 wall -- wall N80HC Welded 14.822" 45.50 L80 ' s BTC 9.875" 2478 5210 1040 1063 29.70 180 BTC 6.750" 4790 6890 683 721 10. Once fluid weight and properties are stable, begin drilling cement making sure that all cuttings are circulated out of the hole. 11. When bridge plug is tagged circulate hole clean. Make sure fluid weight is at LEAST 8.7 ppg. 12. Drill bridge plug. (May not be able to drill and circulate pieces out, so push down to TOL at 8100'MD. Be careful when pushing thru existing perforations. Also be aware of fluid losses to the formation.) 13. Circulate hole clean. POOH. 14. Pick up an AS1 -X retrievable packer on tubing. RU and run 3 W' 9.2 L80 tubing w/ an xn profile above packer. Premium 9.2 L80 Conn 2.992" 10160 _ 10540 207400 xxxx 15. Space out and land tubing hanger setting packer @ ±5500'. 16. RU slickline and RIH w/ N -Test tool. Set in profile and test tubing to 7000 psi recording on a chart for 30 min. 17. Test casing/pkr to 3500 psi also recording on a chart for 30 min. 18. Pull test tool. 19. RU to perform injectivity test on disposal zone. NOTE: CONTINGENCY: If injection rates are too low, or injection pressures too high, reperf, add perfs, acidize or other as approved by the AOGCC. 20. Lay down landing jt. Set BPV. ND BOPe. NU tree. Pull BPV. Set TWC. Test tree. Pull TWC. 21. Demob rig. 24 • 20 AAC 25.252 c 6 Part II 22. RU Flowlines and test. 23. Install equipment and test. 24. Begin injection. Injection Test Procedure: 1. Fill tank with mud or salt water. Make note of initial volumes. Record weight of fluid. 2. Tubing Volume is 334 @ ±5500 ft = approx. 45 bbls. 3. Break down formation and Record Pressure. 4. Pump at rate of 0.5 bpm, for 3 minutes, Record Injection Pressure. 5. Shut down, record initial shut in pressure; wait 5 minutes or until stabilized whichever is longer (no more 30 minutes), monitoring and recording pressure bleed down, then record final pressure or stabilized pressure. 6. Inject at 1 bpm for 3 minutes, record injection pressure. 7. Shut down, record initial shut in pressure, wait 5 minutes or until stabilized whichever is longer (no more 30 minutes), monitoring and recording pressure bleed down, then record final pressure or stabilized pressure. 8. Pump at rate of 2.0 bpm, for 3 minutes, Record Injection Pressure. 9. Shut down, record initial shut in pressure; wait 5 minutes or until stabilized whichever is longer (no more 30 minutes), monitoring and recording pressure bleed down, then record final pressure or stabilized pressure. 10. Pump at rate of 3.0 bpm, for 3 minutes, Record Injection Pressure. 11. Shut down, record initial shut in pressure, wait 5 minutes or until stabilized whichever is longer (no more 30 minutes), monitoring and recording pressure bleed down, then record final pressure or stabilized pressure. 12. Pump at rate of 4 bpm for 3 minutes, Record Injection Pressure. 13. Shut down, record initial shut in pressure, wait 5 minutes or until stabilized whichever is longer (no more 30 minutes), monitoring and recording pressure bleed down, then record final pressure or stabilized pressure. 14. Pump at rate of 5 bpm for 3 minutes, Record Injection Pressure. Note: Be sure to continuously record initial start-up pressure thru pressure stabilization, then instantaneous shut in pressure and bleed down until stabilized or no longer than 30 minutes. It is preferred to perform injection test with mud or gel water. If mud is used it is desirable to displace /flush three times tbg volume at 5 bpm to suspend well until cuttings arrive. 25 • • Current Permit #: 211097 API #: 50- 133 - 20597 -00 -0 Kenai Loop #3 Prop. Des: MHT 9300070 Pad 1 KB elevation: 92.5' (21' AGL) WitilkiNW 3394' FSL, 1134' FWL Lo Lonnt gitu tude: ' Spud: 9/1/2011 BU A L A 3 K A I. TD: 9/26/2011 1. L Rig Released: Structural Pipe 16" X -56 84 ppf Top Bottom MD Surf 120' ND Surf 120' Surface Casing '~ 10 -3/4" L-80 45.5ppf Top Bottom MD 0' 3,027' ND 0' 3,026' Max Inc 28 degrees 4 Cement Top @ Intermediate Casing Cast Iron Bridge 4850' MD 7 -5/8" L -80 29.7 ppf 4548'TVD Top Bottom Plug MD 0' 8,330' set @ 6400' MD ND 0' 7,969" w/ 25 ft of �� i Perforations 6435' - cement on top cc - ♦,J 6450' MD cc a Li OIL H 4 -1/2" L -80 12.6 ppf Hydril 521 Perforations _= CPC Bottom 6,950 - 6,960' � a MD 8,100' 11,368' ND 7,631' 11,000" Baker Flex 27C Lok Liner Hanger A . w/ P Pkr and PBR top @ 8100' MD ,4 - -- - - _ Tu_ bins 1 . } ' 2 7/8" L-80 ppf , :. ∎ Cast Iron bridge Top Bottom g a s ' plug w/25 ND MD ,. cement on top Perforations `,, _ set at 9,750' MD 9,790'- 9,815'MD - ' 1 '=4 - _ packer w/ sealbore / "X" profile @ 10,045' it 1 MD. "X" plug r Perforations - 10,223' - - 10,248' MD -, packer w /sealbore / ., r ,__.- 'X" profile in "XN" nipple @ 10,300' Perforations - ( r MD. "X" plug � � „ installed w /sand 10,520'- 10,545' MD packer w/ sealbore @ 1 1 10,700' MD Perforations - 10,920' - 10,945' '" 2 - 7/8" tubing tall, "X" nipple and 10' Estimated Formation Tops MD ND 1 • - pup cut @ 10,730.5' _ MD. Dropped to TD PBTD bottom 11,388' MD , ' MD ' 1 11,000' ND ' TVD Well Name & Number. Kenai Loop #3 Lease: Kenai Loop County or Parish: Kenai Penisula Borough State: Alaska ' Country:' USA Perforations (MD): Perf (ND): Angle @KOP and Depth: Angle @ Perfs: KOP ND: Date Completed: RKB: 21' Prepared By: Last Revision Date: Exhibit 13 - current KL #3 Well Bore Diagram 26 • • Ex 14 KL3 leak-off test 1 PRESSURE INTEGRITY TEST InsRuctlons Fill in shaded areas COMPLETELY! OPERATOR Bucanneer WELL NAME Kenai Loop#3 DATE: 912/11 Co. Rep. Larry Mac L Benjamin RIG TYPE Lend COUNTRYIARt alaska Kenai RIG Glacier GERM CASING SIZE 10314' MUD WT 8.8 ELEVATION ABOVE MSL KB 113' DESCR. GRADENVT L410 INFORM PV 10 (RKB) ABOVE ML DEPTHS SHOE(IVO) 3026' VP 19 PUMP TYPE Triples OH (NO) 3067 FL 8 BPS 0 04663 SHOE (NO) 302T GELS 8/10111 EFFICIENCY 96% OH(MO) 3070' CASING TEST( 3000 Psi FORM /NTEG. TEST (FIT) Morntor RATE 0.42 BPM FLOWBACK 2.0 Ebla APPR RATE, 0.50 BPM FLOWBACK 2.0 bbls Time: 0.1 mkt Plotted Rate. 0A2 BPM TIME Plotted Rate. 0.50 BPM T1ME CUM. VOL. PRESSURE POINTS Cale Time CUM. VOL. PRESSURE EMW 0.00 0.00 1 0 0.00 0 0.00 0.42 100 2 t 0.50 0 8.80 0.84 350 3 2 1.00 .11 8.93 __ 1.26 _ 825 __ 4 a 1.50 40 9.30 168 1190 5 . 2.00 100 10.68 _ 2.10 1560 6 s 2.50 550 12.25 2.52 2000 7 e 3.00 741 13.44 2.94 2475 _ 8 r 3 50 900 14.44 3.36 2925 _ _ 9 a 4.00 1 000 15.07 3.63 3011 10 9 4.50 950 14.75 5.00 1• to 5.00 960 14.82 5.50 12 to 5.00 8.80 5.50 to 5.00 8.80 5.50 to 5.00 8.80 5.50 to 5.00 8.80 5.50 to 5.00 8.80 5.50 to 5,00 8.80 5.50 __ _ to 5.00 8.80 5.50 i to 5.00 8.80 5.50 to 5.00 8.80 5.50 to 5.00 8.80 5.50 to 5.00 8.80 5.50 to 5.00 8.80 5.50 _ . io 5.00 8.80 5.50 to 5.00 8.80 5.50 _ _ to 500 8.80 5.50 to 5.00 8.80 550 to 5.00 8.80 5.50 to 5.00 8.80 5.50 to 5.00 8.80 5.50 to 5.00 8.80 5 50 to 5.00 180 5.50 m 5.00 810 5.50 _ to 5.00 8.80 5.50 to 100 8.80 550 ___ to 5.00 8.80 5.50 to 500 8.80 5.50 to 5.00 • 8.80 5.50 to 5.00 8.80 5 50 - 10 5.00 8.80 5.50 ISIP 5.00 • 14.82 1 Comments SPR Y PSI GPS INCR. TIME» 6.0 750 13.50 #1 INCR. TIME» 7.0 730 1137 #2 ME INCR. TIME» 9,0 710 13.25 Retest of shoe after squeezing. Previous casing test INCR. TIME» 9.0 690 13.12 with 9.2 wbm incl for reference. INCR. TIME» 10.0 e75 13.03 PRESSURE VS. VOLUME - �_ OUeELS i IT ff 3500. t I I , I I I t I ! I I -o -Fir I ! � f • �. ELM ♦ Bleed of EMW 3000 - , 1,09 1 1 - Msamurn Volume Lb. I ,' 1 I ! • m rime 2500 - -- ••• 1 • I - � 4 Inctemen - 1_-. . . ' t I 1. I I® i j -}- a 2000 ■ j (e 1 - . i ' .. t , I ' l_.�� y � + 1500 - !.. -._. i-- I , • ( 1- • 1000 4. f t 1 ! I I i I` I . Y..y I _ t d' J r 0 1 ✓ . ! 500 - . / - /{ • � . ) , + , ► I ,t ; 1 i i I D •i 1: Lai'' • e 1 -' 1' l 1 i i 1 1 1 1 0 0 1 2 3 4 5 8 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 TIME and EMW (ppIK- -- - - --'. VOLUME PUMPED AND TIME AFTER SHUT4N Exhibit 14 - KL3 Leak -off Test 1 Stephen F. (Steve) Hennigan 3114/2012 27 al el Ex 15 KL3 leak off test 2 PRESSURE INTEGRITY TEST i -...r crops r In shaped areas COMPLETELY OPERATOR Bucanneer WELL NAME Kenal Loop #3 DATE! 973/11 Co. Rep. Larry Mac L Benjamin RIG TYPE Land COUNTRY /ARI alaske Kenai RIG Glacier GD #1 CASING SIZE 103/4' MUD WT 8.8 ELEVATION ABOVE MSL KB 113 DESCR. GRADE/WT L -80 INFORM PV 10 (RKB) ABOVE ML DEPTHS SHOE (TVD) 3026 YP 19 PUMP TYPE Triplex OH (ND) 3431' FL 8 BPS 004663 SHOE (MD) 3027' GELS 8/10/11 EFFICIENCY 96 % OH (MD) 3433' CASING TEST ( 3000 Psi FORM INTEL. TEST (FIT) Monito, RATE 0.42 BPM FLOWBACK 2. 0 bbla APPR RATE: 0.50 RPM FLOWBACK 2.0 bbls 77me: 0.1 min Plotted Rate. 0.42 BPM TIME Plotted Rate: 0.50 BPM TIME CUM. VOL. PRESSURE POINTS Colo Time CUM. VOL. PRESSURE EMW 0.00 0.00 1 0 0.00 0 0.00 0.42 2 1 0.50 -70 8.86 0 84 3 v 1.00 Se 9.08 1.26 4 3 1.50 10.03 1.68 __ 5 4 2.00 11.15 2 10 6 s 2.50 12.16 2,52 7 a 3.00 13.06 2.94 8 r 3.50 1345 3.36 9 8 4.00 13.73 3.63 10 a 4.50 13.84 5.00 11 to 500 13.96 5.50 12 10 5.00 8,80 5.50 to 5.00 8.80 5.50 to 5.00 8.80 5.50 to 5.00 8,80 5.50 to 5.00 8.80 5.50 to 5.00 8.80 5.50 to 5.00 8.80 5.50 to 500 8.80 5.50 to 5.00 8.80 5.50 to 5.00 8.80 5.50 10 5 00 8.80 5.50 to 5.00 8.80 550 to 5.00 8.80 5.50 10 5.00 8.80 5.50 to 5.00 8.80 5.50 to 5.00 8,80 5.50 to 5.00 8.80 5.50 to 5 D0 8.80 5.50 10 5.00 8.80 550 10 5.00 810 5.50 to 5.00 8.80 5.50 to 5.00 8.80 5.50 m 5.00 8.80 5.50 to 5 00 8.80 5.50 .___._..__. 10 5.00 8.80 5.50 10 5.00 8.80 _.._- .....___, 1a 500 5.50 8.80 _ _...._ - 1 500 550 8.80 .. . 5.50 _... -._ to 500 8.80 550 ISM 5.00 14.18 Comm.ntB �SPR # PSI On INCR. TIME» 6.0 750 13.00 #1 P r -- 7� INCR TIME» 70 730 12.89 #2 SO 70 INCR. TIME» 80 710 12.78 Retest of shoe after squeezing. Previous casing test INCR. TIME» 9.0 690 12.67 watt 9.2 wbm incl for reference. INCR. TIME,. 10.0 575 12.55 PRESSURE VS. VOLUME IAada ..n. pT ` 1500. - • - - , - I • ' I 1 ��14T I` 1 ! �f Mood olfEMW • -.- Memwn Yokel* like I I I I I - xmlemeawtrr WOO -- 1 .I. 1 i _ - 1,. , [ti 1j .1 . , f 1 1 �., :.. i I iI} I I 0 ►' 6 1 a A A 1' 1' M �a� I i' . >1 1 1' i i' . ' I 6• f! S ' a 0 I 2 3 4 5 6 7 8 9 10 11 1 1 3 14 15 1e 17 15 19 20 21 22 23 24 25 TIME and EMW(pp99 - ' - ► 1 VOLUME PUMPED AND TIME AFTER SHUT Exhibit 15 - KL3 Leak -off test 2 Stephen F. (Steve) Hennigan 3/14/2012 2 p 8 0.10.6 • ctua " e pat eo • • rap is ' e • • ort Report Generated '‘' -ep -11 at 07:33:33 Projection System D27 . asks P. one ' 'i r'I IL ' Operator Buccaneer Energy, Inc. North Reference - True Area Cook Inlet, Alaska (Kenai Peninsula) Scale 0.999955 Field Kenai Loop Horizontal Reference Point Slot Facility 'enai Loop Pad 1 Vertical Reference Point aacler #1 (RKB) Slot Slot #2 MD Reference Point - #1 (RKB) Well Kenai Loop #3 Field Vertical Reference -1,- Mean Sea Level Wettbore Kenai Loop #3 Glacier #1 (RKB) to Mean Sea level 1111111111111110 113.30 ft Wetrpath ,, a °: 11367> Glacier #1 (RKB) to Mean Sea Level 113.30 ft Wellbore Last Revised -' 09/142011 Mean Sea level to Mud Line (Facility) IMP 0.00 idetrack from (none) Section Origin X R E 0.00 U ser Jonethoh Section Origin Y N0.00ft Calculation method _ Minimum curvature Section Azimuth 182.97• Local North t_o, al East Grid East Grid North Letitude Longitude (ft) Ill] )US ft) [US ft] - _ Slot Location 11111111111111111111111111.1111111p 0.50 59.88 279604.59 2402267.99 60'3411.502N 151 °1130.483"W Facility Reference P t 279544.71 2402268.61 601411.498"N 151 °1131.6BM Field Reference Pt 279544.71 2402268.61 60 "N 151 °13'31.681 "W TVD from MD Inclination Azimuth TVD rld Ref North East Grid East Grid North I atitude Longitude DLS Tootle Build Rate Turn Rate Vert Sect Comments In] IN 11 (ttl fill Iftl id] (U5 u) IUS nl 11 rt10011 I°nooftl [ft) 0.00 0.00 52.01 0.00 - 113.30 0.00 0.00 279804.59 2402267.99 80'34'11.503"N 151 13'30.4831N, 0.00 52.01 0.00 0.00 0.00 • 0 110 208.00 52 0 -- .90 1 - .01 207.99 94.69 ' 1.01 129 ' 279606.90 2402268.97 60'3411.5131 1151 13'30.45714 0 .43 104.19 • • 0.43 ' 000 -1.07 268.00 l 0.88 58.73 267.98 154.88 T 1.53 205 279606.67 . 240226949 60•34'11.518'N '1519310.442W 0.18 •177.71 4.03 ( -1 1120 .64 32740 0,89 , 58.10 326.98 213.68 1.96 2.74 _ 279607.37 ` 2402269.90 } - 60'3411.5224 1519310.4281N 0.32 - 155.26 4.32 407 -210 388.00 t 0.59 53.54 387.97 1 270.67 2.34 3.31 ; 279607.94 240227027 1 60'34'11.52814 1519330.417W 0.18 _2 -202 ; -0.16 -7.48 .51 __ _ 44700 0.75 53.11 448.97 333.67 2.75 3.86 279608 50 • 2402270.67 00•3411.590"4 4 ,151 . 13'30.406"8 0.27 .104.94 0.27 -o.73 -2.95 50400 19.86 50347 990.67 0.74 3.21 4.44 279609.09_ 240227112 60'34'11.534 - N 151°1330.39481 0.08 i 3234 -0.02 -5.70 3.4{ 56300 0.80 _.j_ 53.30 5622.96 } 44968 I 3.70 f 5.06 279609.72 1 2402271.60 80'34'11.532N 151°1330.382W 0.13 I 174.75 ' 0.10 563 -3.96 6 0.50 I 58.47 622.96 509.68 1 4.10 1 5.61 279610.28 2402271.98 60'34'11.543"N J151 1310.371"8 0.50 y -120.23 t -250 -4,38 I. 683.00 045 42.50 682.95 56965 i 4,42 i+ 599 279610.88 240227229 60'34'11.548"N 151•13'30.383'W 0.21 - 154,48 -0.08 1 -2 5.26 3.28 -472 74300 0.33 32.03 1 742.95 I 629.85 4,74 6.24 ( 279810.92 2402272.61 80'34'11.549"N 151 1310. 0.23 2.13 -0.20 y 1 _ -17.45 -5.05 J 1 806.00 0.52 32.81 805.95 69265 5.13 6.49 279811.18 I 2402273.00 I 60•34'11.553"N 151 0.30 - 178.78 0.30 124 -546 t • 869.00 0.47 J 32.68 868.95 755.65 5,59 6.79 279811.48 ! 2402273.45 60'3411.558'N �151 0.08 40.89 I -0.08 -221 -5.93 933.00 0.61 45.27 932.95 819.65 0.06 ' 717 279611.87 2402273.90 ' 80'34'11.562'N 451'13'30.339"W 0.29 • 9.70 0. 22 1967 -6.41 997.00 . 1 109 49.56 996.94 883.64 6.68 788 279812.59 ' 2402274.53 F 60 ° 3411.589'N .151 0.76 I 33.27 0.75 6.70 -7.08 1 _ 1080.00 I 1.15 51.50 1059.93 946.63 7.47 8.83 - 279613.56 2402275.29 60 °34'11.578'N 151'1310.306"W, 0.11 - 179.94 ••, 0.10 3.08 -7.91 1124.00 -,- 0.99 5149 j 1123.92 , 1010.62 8.21_ _ 0.76 27961450 _^ 2402278.02 $ 60'34'11.584'N 151 0.25 , 164.26 I 4.25 f -0.02 -8.71 _ 1187.00 0.62 6142 i 1188.91 1073.61 8.71 I 10.49 279615.24 2402278.51 601411.589'4 151' 1310.273WI 0.83 - 149.85 -0.59 15.78 -9.24 1250.00 0.38 l 38.54 _ ' 1249.91 1138.61 l 9.04 10.91 279815.67 i 2402278.83 * 60'3411.59rN 151 0.51 13.66 rt 4.38 49.49 -9.60 1313.00 ` _ 0.67 1 41.14 1312.91 1199.61 I 9.45 11.24 279616.01 I 2402277.23 6o- 34'11.595 N 151 0.31 - 137.55 030 7.30 -10.02 1376.00 ' 0.39 3.01 -I 1375.90 . 1262.80 9,90 11.46 279616.23 2402277.67 60°34'11.600'4 1519310.254W 0.57 94.41 -0.29 ' -00.52 -10.48 1439.00 I _ 039 11.83 4 . 1438 . 90 1325.80 10.32 F 11.52 279616.30 2402278.09 60'34'11.6041 1511310.253"W 0.10 -1.65 0.00 I 14_00 1 -10.90 fff 1503.00 0 47 11.55 , 1502.90 - 1389.60 10.79 1161 279616.40 f 2402278.56 60°34'11.6024 '1519310.251W - 0.13 - 146.11 0.12 4.44 -11.38 1586.00 0.28 336.05 1585.90 , 1452.60 11.19 11.90 279618.40 2402278.96 60 °34'11.6131 1519310.251W 0.46 -13535 -0.30 , -56.35 . -11.77 1830_00 028 332.00 L 1629.90 _ 1516.60 11.46 11.47 279616.27 . 2402279.23 80'3411.616'N '151'13'30.253"W 0.04 52.66 -0_03 d -8.33 -12.04 -- 1891.00 ' 0.28 337.11 _ 1690.90 ' 1577.60 11.72 j 11.35 1 279818.15 ) 2402279.49 i 60'3411 818"4 115193'30.256"W 0.05 -154.26 8.38 .2 26 _ 0.03 1 -12.29 175500 019 323.06 4 . 1754.90 1641.60 11.95 11.22 , 279616.03 I 2402279.72 1 60'3411.620'N 151 13'30 258'W 0.17 -37.03 -0.14 -2195 r -12.51 1819.00 0 , � 1882.0 L 191.58 312.14 I 1818.90 1705.60 ' 1213 11.05 279615.86 2402279.91 60°34'11.622'4 151 0.13 - 143.35 0.11 -17.06 -12.68 rt - 0 _ 0.40 26 1881.90 i 1766.80 1201 10.90 279815.71 2402279.79 80'3411.5211 151 9330.2858 0.92 30.79 0.22 -191.37 -12.56 I • 1945.00 0.80 175 ° 1944.89 1831.59 11.90 10.89 279615.69 - 2402279.14 60'3411.8151 1 0.68 -8.68 0.83 -25.33 -11.90 2009.00 i 0.94 I 174.32 ` 2008.88 1895.58 10.39 10.98 279615.76 i 240227517 f 80'3411.6051 1519310.283"W 0.22 81.28 0.22 -2.03 - 10.94 2073.00 1.02 181.68 I 2072.88 t 1959.58 ■ 9.29 11.01 27981577 _ 240227708 1 60°3411.5941 4 ,151 1330.2638 0.23 -169 39 0.12 T 11 -985 2135.00 I 0.72 177.17 2134.87 1 2021.57 8.35 11.01 27961576 2402278.14 60'34"11.588 0.50 42.43 - -0.48 _ -7.27 I 4.91 2199.00 _ 0.81 182.76 2198.88 2085.56 ■ 226300 I 0 7.50 11.01 279815.74 - I 2402275.28 60'3411.5771 t 111 •11330.2638 0.16 - 132.06 I 0.14 -• 8.72 -8.05 .80 181.95 , 2 62.88 : 2149.56 6.60 10.98 27961569 240227439 60•34115881 11519310.263W 0.02 - 1377 -202 4.25 -7.15 232640 142 _ 178-94 t 2325.85 I 2212.56 580 10.97 279615.68 2402273.39 80 °3411 558'N 115193'30.263"W 0.36 139.27 0.35 - 4.78 -516 2390.00 _ 0.88 216.37 1 2389.64 1 2276,54 473 10.76 1 279815.43 2402272.51 60'34'11.549"N 151 1330 268W 0.99 " 133.59 -0.53 58.48 -5.28 2452.00 0.55 j 233.53 2451.84 .. 2338.54 4.25 10.30 279614.97 # 240227'2.05 80•34'11.545"N X 151'13'30.277'W 0.36 33.77 -0.21 { 27.68 -4.78 2518.00 1 0.73 242.54 _ 2515.83 ' 2402.53 3.88 9.69 _ 279614.35 , 2402271.69 60°34'11.54?? 151•13'30.289W 0.32 I -38.98 1 0.28 14.08 .4 38 I _ 257900 1 0.90 23424 2578.83 1 2485.53 3.41 _ 593 27981358 240227123 60'3411.538"N 151 13'30 304W 033 -944 0.27 _ -13.17 .87 264340 I 1.03 233.04 2642.82 252952 277 L 8.07 279612.71 2402270.61 60'34'11.530'N 1519310.322W 0.21 401 0.20 1 -1.88 - 4 4.18 1 270640 1.16 233.413 , 270581 259251 2.05 7.10 279611.73 240228.9 80'3411.52314 151'1310.341'W 221 92.02 221 0.71 1 -2.41 276940 1.16 I 237.52 2768.79 2655.49 • 133 6.05 27961266 240226920 60•1411.516'N T 310362W 0.13 -2623 040 6.40 -1.64 283100 1128 _L 235.30 + 2832.78 • 2719.48 258 4.93 279609.52 2402268.48 60'3411.509'N 1519310.384W 0.17 -2420 0.16 -3.47 -283 289500 138 233.08 ' 2895.76 2782.48 4.27 3.75 27960833 2402267.65 • 60'34'11.5001 1 151 3'30.405 W 0.21 55.18 ' 0.19 -3.52 0 08 2960.00 1.45 23831 _ 2959.74 2848.44 -1.17 2.43 279607.00 2402266.78 , 60•34'11.4911 '151'1312434 0.28 4239 0.16 8.17 1.04 2993.00 154 t 23550 299273 2879.43 -1.64 ! 1.70 279808 26 } 2 402260 31 60 151 1310 4498 0.29 -12.25 0.18 -8.52 1.55 3053.00 1 81 23 65 9052.71 293941 2.88 I 0.27 279604 81 240226532 60•34'11472N ' .151°1310.477W 0.46 -28.94 045 I 408 -- zeal 311700 3.31 220.05 3116.64 3003.34 4.68 111_ } =1. -4.58 279599.84 2402259.19 8014'11.415 73 279602.77 2402263.35 60'34'11 457'N 151°1330.518W 2.51 -21.04 , 2.34 -21.25 . 478 318100 583 210 - 76 I 3180.43 3067.13 -8.88 _ " 151'13'30.57 4.09 I -7.28 ii 394 -14.52 4 9_11 , 3244.00 7.37 209.23 3243.01 3129.71 , -15.16 -8.19 279596.12 2402252.99 1 601411.35414 151 246 . -37.32 i 2.44 -2.43 , 15.58 . . Ex 16 KL3 MWD Final Survey 29 TVD from MD Inclination Azimuth TVD Fld Ref North East Grid East Grid North Latitude Longitude DLS Toolface Build Rate Turn Rate Vert Sect Comments [ft) ['I 1' 1 Itti [ft) Ittl (nl lus ft) lus ft] [ (°f100n1 1 VI 3307.00 9.20 200.93 3305.36 319206 -23.39 -11.96 27959219 2402244.83 • 60 1 151'1310.722"W 3.48 37.39 2.90 •13.17 _ 23.98 _ 3370.00 • 10.21 ; 196.89 3367.45 _ -_ 3254.15 • -33.44 1 -15.37 : 279588.60 240229484 60 °34'11.174'N 151 1.98 I -9215 1 -8.73 I 34.20 3433.00 1 10.44 l 182.14 j 3429.44 •. 3316.14 ' -44.50 -17.18 279588.58 • 240222382 160 °34'11.062'N_1151 4.14 -26.92 • 0.37 -23.10 I 45.33 I i 1111 3497.00 l 10.94 180.81 349233 3379.03 -56.37 - 17.49 279586.06 2402211.96 160'34'10.448•N 151 0.87 135.90 0.78 -20 57.20 ; 3559.00 ,_ 10.83 181.38 3653.22 3439.92 -88.07 -17.71 , 279585.62 2402200.26 60•34'10.833'4 151°13'30.832W _ 0.25 21.37 -0.18 092 - 68.90 ' 362200 1 11.25 t 18222 3818.05 j 3501.75 -60.13 •18.09 279585.01 2402188.22 60'34'10.714'4 151 0.71 -6.78 0.87 1.33 • 80.98 t • _ 3888.00 44 12.04 181.77 4 3877.73 3664.43 -93.04 -18.54 27958432 • 2402175.92 °34'10.587N 1 151.1730 .854 1.24 -15.81 1.23 1 -070 93.88 3750.00 12.91 (- 180.87 3740.22 • 9628.92 - 108.88 -1283 279583.78 2402161.50 80'34'10.451 15193'30 1.41 -11.16 1.38 , -1.72 107.89 ,-_ _ 3814.00 14.33 t 179.54 3802.42 1 3889.12 - 121.93 -18.88 279683.48 2402148.44 60'3410.302"N 1 226 •7.03 2.22 -1.77 122.74 • 3877.00 + 18.08 178.77 4 3863.22 ' 3749.92 - 138.44 -18.60 I 279583.42 ' 2402129.93 80'34°10.140'4 151 276 _ 21.28 275 ' - 1.22 139.22 • 3940.00 ■ 17.95 _ 1 181.14 3923.46 3810.16 - 156.�8 1260 279583.07 2402111.51 60'34'09.958'N 151 3.19 ' 26.96 3.00 378 157.61 =coo 1 19.78 , 189.86 3984.02 1 3870.72 - 177.53 ?- -19.53 279581.76 ! 2402090.87 ' 60'34'09.755 "N ;151 °1330.874" 3.17 10.22 286 4.25 178.30 4087.00 21.78 184.83 • 4042.92 3929.62 [ - 199.8 , -21.21 ' 27957944 _ 2402068.62 60'34'09.535 151°1330.908"1 3.21 1 -2.80 ' 217 1.54 200.64 4190.00 24.63 184.52 4100.82 . 3987.52 - 224.55 -23.25 279577.16 •. 2402043.92 60'34'09.292'N '151'1310.948"W! 4.53 -48.67 . 4.52 i. -0.49 225.45 4199.00 r 25.29 182.79 4 4157.93 1 4044.83 - 251.08 -24.94 279574.98 I 2402017.43 60'34'09.030"N ;151•1330.982•W 1.56 1 - 145.04 1.05 -2.75 252.03 4257.00 24.90 -,- 182.14 • 4216.89 410259 - 278.20 26.11 I 279573.31 2401990.34_4 60'343278314 11519311.005W. 0.75 1 41.77 -0.81 -1.02 i 279.18 431000 25.27 1 181.37 4272.95 - 4159.65 304.89 f 4 8.92 279571.99 2401963.87 60'34'0&500"N 1151 0.76 i •17.93 • 0.59 -1.22 ' 305.88 4383 1 27.29 17995 4329.44 4216.14 33278 2 7. 23� 279571.16 4 2401935.79 - 80°34'02226"N ! 151 1331.028 wi 3.38 154.08 I 3.21 -2.25 _ 333.78 _ 26 81 4446.00 , 180 69 y 4384.70 - 4271.40 - 300.88 -27,39 279570.49 1 .. 2401907.70 60'3437.949"N ' 151 031 W 1.22 - 178.28 -1.10 _ 1.19 _ 361.81 4509.00 i 25.75 18083 4442.14 4328.84 - 389.11 -27.71 I 279569.64 2401879.48 j 60'3437.671"N 151.1311.037" f 1.34 • -12.92 • •144 1 -0.09 390.03 i I 26.35 180.32 4499.64 4388.34 417.22 - 27.95 c 279568.88 2401851.38 60 °34'07.394"N 151 0.98 - 104.14 0.94 _ -0.48 418.11 _ 463540 4555.20 26.33 180.14 I 45' 4441.90 44473 111 - 28.06 279588.26 1 2401823.88 80 °34'07.123"N 15193'31.044" 0.13 186.86 _ •003 _ _ :0.29 _ 4699.00 26.16 180.23 181260 • 4499.30 473 03 -28.15 J 279587.64 i 2401795.59 60°34'06 845"N . 151 . 1331.048W _ 0.27 -173.03 -0.27 0.14 473.85 476200 1 25.58 ' 180.06 4669.29 ; 4555.99 - 500.51 - 28.22 279567.06 2401758.12 60 °3408.574•N 1151 0.96 1 68.61 i -095 I 0.27 501.30 4828.00 ; 25.82 - 181.54 1 4728.97 I 4813.87 - 528.25 - 28.61 279586.15 I 2401740239 60 °34'06.301"N • 151 1.08 j 10958 0.41 2.31 529.02 I-- • 4890.00 25.82 18288 4784.63_ _ 4871.33 -558.00 -29.68 279564.57 2401712.67 60°34'06.028'N 151•1331.077°" 0.98 • 11.18 -0.31 • 209 556,79 4952.00 I 26.11 _ 1 183.10 4840.41 4727.11 -583.01 -31.09 ,- 279682.85 2401885.69 • 60'34'05.762'N 1519331.105" 0.81 30.85 4 0.79 035 y 583.84 5015.00 t 26.94 184.18_ 898.18 I 478348 411.09 -32 88 . 279680.34 2401857.55 T60°34'05.485 1 151 1.52 72.59 , 1.92 L 1.71 611.97 • 611.9739 507800 2895 1 184.25 t 495'2.94 r 4839.64 f -639.56 -34.98 • 279657.71 2401829.23 " 60 °3405.205'N 151 0.05 7 - 16594 ,_ 0.02 011 640.51 i 5142.00 ; 2840 183.94 5010.13 4898.83 -888.21 -37.03 279555.13 . - 1 2401600.61 : W 60 °3x'04.922 51 0.89 -98 4.86 -0 48 869.24 I. 5208.00 } 28.34 182.99 5067.47 4954.17 - 896.50 -38.75 279552.88 2401572.28 ' 60°34'04.843"N ;1519311.252W 0.87 - 118.83 -0.09 -1.48 697.66 5268.00 • 2612 18207 5123.09 1 5009.79 - 723.96 •3996 279551.18 2401544.93 • 60°34'04.373N 151'1231.282W 0.75 43.74 -0.35 -1 48 725.06 , 720.062 5331.00 26.18 182.20 51797964 1 5068.34 -751.71 -40.99 279549.61 2401517.21 60°34104.100N 1151'1331.303"W 0.13 -144.91 0.10 0.21 752.82 752.8267 1 5395.00 25.95_ I 181.83 5237.13 • 5123.83 _779.81 T - 41.98 279548.10 1 2401489.13 60 °34'03.623'N 151°1331.323"W 0.44 - 138.16 -0.38 -0.58 780.94 1 780.9392 1 545800 • 25.90 181.72 5293.79 .} 5180.49 - 807.94 1 42.83 L_ 279546.73 2401481.62 1 60'34'03.552 1151'1331.340" 0.11 168.81 4.08 ' -0.17 - 808.48 5621.00 25.79 181.77 5350.49 • 5297.19 -834.79 43 87 279545.38 2401434.19 60 282°4 ' 151°13'31.357"W 0.18 - -126 09 � -0.17 008 • 835.94 __ t 5584.00 I 25.73 181.58 5407.23 5293.93 -86216 i -44.47 279544.07 I 2401408.85 • 60 "N 15113'31.373'W 0.16 ' 93.99 4 -0.10 _ -0.30 1 863.31 5647.00 25.84 181,75 5483.96 , 5350.88 -889.56 I ' 45.27 279542.77 ; 2401379.47 _80 "N 151°13'31.389"W 0.21 1 118.83 ' 0.17 0.27 890.71 • 5710.00 25.64 + 18260 1 5520.71 5 407.4 1 ' - - 916.89 1 -46.30 ! 279541.22 240135216 60 151 13'31.409" 0.67 i 76.80 -0.32 1.35 918.06 • • 5773.00 1 25 75 183.65 -t- 5577.48 5464.18 - 9 44.17 47.79 278539.22 2401324.92 80°34112208'4 151 °13'31.439 " 0.74 -158.14 0.17 1.67 945.38 6838.00 i 25.61 183.52 5633.35 5520.05 - - 970.98 -49.47 279537,04 ' 2401298.14 1 80'34'01.941'N '151'1311.473"W 0.24 -25.20 -0.23 -0.21 972.24 5899.00 25.79 183.39 .1 569104 I 5577.74 -99826 ,, -51.15 279534.66 i 2401270.51 80 • 151'1331.506"W, 5 0.21 I 108.25 0.19 t I -020 999.97 5963.00 25.72 ; 183.32 5748.69 5635.39 - 1026.39 52.77 ° 279532.72 2401242.81 60•3431.395"N 151'1391.5392 0.05 1 155.19 4.02 1- -0.11 1027.74 6028.00 : 25.58 183.47 J 5805.48 5692.18 - 1053.61 -54.39 279530.60 2401215.62 80•3431.127"N 1 151 . 1311.571" 0.24 ' -10.56 -0.22 • 0.24 106201 8090.00 • 26.22 i 163.20 1 5863 06 5749.76 - 1081.52 t -56.01 279528.45 1 2401187.75 80'34'00 85YN 15193'31.6041 1.02 •9.09 1.00 -0.42 108297 8153.00 r 27.46 1 182.77 iT 5919.27 5805.97 - 1109.93 I -5749 1 I 2401159.38 1 60'94'00 573'4 151 . 9331.833 W 1.99 � 125.99 ,r 1.97 1 -0.88 1111.41 ' 8217.00 27.39 _ 182.98 5976.07 6862.77 . ;-1139.37 -58.97 279524.42 2401129.97 80'34'00.28314 1 1 51'13'31.663'W 0.19 177.38 - -0.11 I 0.33 __ 1140.69 - t 6280.00 ` _ 2729 ; 182.99 1 603204 T 591274 1 -1168.28 1 -60.48 1 27952137 , 2401101/1 80'34'00.000N . 1519331.693"W 0.16 -40.51 -0.16 0.02 1169.82 6343.00 ' 27.36 182.88 6088.01_ 5974.71 - 119714 -61.06 279520.36 r , 2401072.27 6033'59.71 151•1331.722" 0.15 ; - 162.46 0.11 -0.21 1198.74 t 6408.00 _ 26.86 182.51 6144.09 6030.79 -1225.82 -09.30 279518.48 2401049.62 , 60'3359.431'N 11519311.747W, 0.83 169.27 -0.79 -0 .58 ` 1227.45 • _ 6469.00 4 - 28.53 182.65 6200 37 608 7.0 7 - 1264.09 - -64.57 279516.68 2401015.38 00°33'59.153°N I 151 . 1331.775W 0.53 -28.29 -0.52 4 0.22 I 1255.75 853200 I 26.69 4 182.53 6258 71 I 6143.41 I - 128225 -65.84 279514.88 2400987.25 1 80 "N 151 1331.8002' 0.18 I 158.34 0.18 -0.19 1283.94 6 • 59800 , 28 54 182.61 6313.95 6200.85 , -1310.87 - 6 279513.07 2400958.66 60'33'58.594'N 4 151'1331.823W W 0.15 5.69 , -0.14 0 09 1 78 012_ 131258 24008 74.92 • 60 .768'4 ' 151 13 I. 6859.00 8 94 6370.28 69.98 -0 " 151 13 31.852 0.14 -175.28 0.14 _ 340 - -1394.70 - -70.77 279507.87 I, '3357'31.877" 0.76 -165.42 4.78 6786.00 -0.14 1368.78 6722.00 1 24.111 24.25 181.94 • 6484. 6371.11 6428.34 1421 1394 _ 59.68 279506.47 2400848.62 60 °33'57.509"4 151 ° 13'31.8992' 1.58 178 21 _ °1.53 -0.94 , 1396.49 I 8849.00 • 151°13'31.91 7", 1.46 170 84 -1.46 • 0.11 142282 6912.00 23.46 .. 4 . _ 182.33 1 6599.26 6485.96 - 1446.48 -72.64 279505.03 2400823.19 60 °3357258"N `15113'31.938 "W 1.27 169.04 -1.25 0.51 1448.30 6975.00 22.55 i 18279 • 6657.24 6543.94 - 1471.07 -73.74 • 279503.48 ' 2400798.61 60°33'57.013N 1 151'13'31 .958' W 1.47 165.44 •1.44 0_73 I 1472.92 , 7040.00 21.67 183.41 6717.46 6604.16 - 1495.50 _ - 7506 , 279501.70 1 2400774.22 1 60 776'N 151 1.40 • - 170.31 1 -1.95 095 •1- 1497.38 L. 7102.00 20.58 .y 182.87 6775.30 6662.00 -1517.80 -76.28 • 279500.06 2400751.94 1 60 151 13'32.009"W 1.82 179.31 -0.87 -1.79 - -0 87 1519.72 718800 I 19.46 I 182.91 � 3'5 4. 8835.44 4 6722.14 _ - 1539.67 - 77.39 279498.55 2400730.10 60 °33'56.341°4 151 ° 1312.031"Y - 1.72 - 176.58 1 -1.72 0.06 1541.81 i 7229.00 : 18/6 18278 5894.96 6781.66 - 1560.27 -78.41 1 279497.14 2400709.62 60 136"N J 1519312052"W 111 -176.49 - -1111 1_ - -0 21 1562.24 7293.00 18.30 68 182.69 , 8956.85 42.35 - 168059 - 7938 279495.79 240068923 80°33'55.938'N 151•1332.071W• 0.72 174.82 4.72 ! -0.14 1582.58 7358.00 r _ 17.75 '1 162.86 1 7016.55 &902.25 - 1600 06 -8232 i 279494.49 2400869.78 ,j 60'33'55.746"N 151 "1 0.88 138.64 r -0.67 0.27 1802.07 7419.00 1 17.23 4 184.54 7075.64 i 6962.34 - 1618.95 -81.64 279492.92 A 2400850.91 50'33'55.560"N 151•13'32.114W1 , 1.15 ' 158.83 4.83 ; 2.67 1621.00 7482.0 L 1 823 14 - 7197.39 7084.09 - 1654.98 -8463 27948916 2400614.97 60 °33'55.205"N 151 1.83 7135.91 7022.81 -1837.24 -83.12 ;_ 279491.00 ' 240063266 ••~ 1. l - 165.95 -0. i 1,27 1 1639.34 7548.00 15.83 184.40 6033'55.380"N 1511332.148"W 1- -162.09 -1.58 I -1.47 1857.12 ` f 7608.00 14.93 T 18252 52 7257.20 I 7143.90 -1671.26 -85 76 279487.72 2400598.70 I : 60 151 119 -161.72 •1.13 -1.42 1673.45 7873.00 14.01 II 7320.13 1 ,, - 720683 -168747 -86.59 279486.60 2400582.50 60 . 151'1332.215W 1.50 -172.88 j -1.42 1 -1.94 • 69. 1669 7735.00 12.82 181.59 • 7380.44 7287.14 - 1701.85 5708 279485.84 2400568.14 60'33'54.74314 151'1312.222W 1.94 1 161.93 -1.92 -108 "_ 1704.08 7798.00 11.82 183.19 t 7441.99 _ • 7328.69 • - 1715.28 -87.63 27948204 2400554.72 60•33'54.611°N 151 13'32.23814 1.68 -177.60 -1.50 254 1717.52 7861.00 _ _11.00 j 183.01 1503.74 t 7390.44 - 1727.72 ' -88.30 1 279484.13 2400542.29 60 151•1232.250'W 1.30 -175.92 - 1,90 _ -029 1729.98 ' 7928.00 � 948 1 182.59 , 7567.a _ j - 1739.54 -88.88 279483.33 2400530.48 80'33'54.372"N ,151 1312.261 "1 L57 177.87 _ -1.57 -065 • 1741.81 _ 7989.00 , 8.78 182.91 7629.81 7516.51 - 1749.80 -89.37 279482.65 2400520.24 60•33'54.271"1.1 1.91 - 168.84 -1.90 0.51 , 175208 , Ex 16 KL3 MWD Final Survey 30 TVD from MD Inclination A ,m TVO Fld Ref North East Grid East Grid North Latitude t. on_ptude DLS TOOQace Build Rate Turn Rate Vert Sect Comments _ !tt1 I'1 1"1 IRI 0 t Ili' lit! [US ttl !us ttl 1 °1 1°!lflOtt1 I°l1OOt l IttI 8052.00 7.39 180,73 769218 757828 1 -1758.65 _ -89.67 : 27948219 I 2400511.39 160'33'54.184'N 1 151•13'32277'94, 226 - 175.13 - 2.21 4.48 1780.94 _ Y 8116.00 6. 1 179.91 2,775579 764243 1766.30 -,72 ( 279482.015 60'3354109N 151 1.88 , 17449 1.E6� -1_28 , 176857 8179.00 - t 5.09 16126 7818.41 770111 177257 -89,77 , 27948183 2400497.49 _ 60'33' 1 - � 1. 98 _ 16526 -1,97 ' 2.14 177484 8243.00 3.76 x, '186,87 + 7882.22 - 1777.49 -90.08 279481 1- 2400492.57 1 80 151'1312,285'94 2.18 i 147,76 1 - 208 8.45 1779.77` 8277,00 - _ 1 3.33 191.47 • 7916.16 • 7802.86 - 1779.66 - 90.41 279481 07 2400490,50 00'33'53.978N -• 1 151 1.54 16403 -1.26 1 14.12 d , 178186 8426.00 2.24 206,12 8064 24 95 ; 795166 ' 279478.80 2400483.69 .60'33'53.9111 -TIT •13'32 w y 0.87 - 146.94 -0.73 ' 9.83 1788.81 8490,00 2.09 20.5.40 8120238015.63 _ - 1788.42 L 4256 •1788.61 - 93.56 1 279477.74 I 2400481:51 16O 353.889'N !151 W 0.28 130.70 -0,23 425 179106 8552.00 8077.59 - 179087 44.47 279476,79 2400479.48 60'33'53.889'N 151 0,07 136.57 2.06 204,36 8190,89 . • -0.05 1.58 1 1793.16 8615.00 - 201372 1.99 x - 1792.68 1 _ -05.42 279475.80 2400477.48 60'33'51849"N 115193'32397W 0.16 ' -122.08 -0.11 3.08 1795 ^ 21 L _ 8676.00_ 1. 1.94 203.88 818.82 8203.52 -1794.63 4834 27947485 1 2400475.55 I 80 0.15 147.17 1 -0.06 -3.87 , 1797.21 I _ 8742.00 _ 1.49_ 191.61 _' 8380.79 8267.49 I - 1796.44 ' _96.95 279474 -21 2400473,75 80'33'53.817'N 151•13324221NI 0.90 l - 130.59 • -0.70 I -18.88 , 1799.05 8805.00 1: 121 -1• 17197 ; 8443,77 -t- 8330.47 1 -17979 47,02 279474.11 +240047229 60'33'53.798"N 1151 : 6 0 1655.52 t -0.44 -31,49 1800.51 8868.00 0.87 177.84 __ 8506.76 Y 8393.46 -1799.03 -96.91 279474.20 2400471.16 I 151 0.56 J 17118 -0.54 9.32 1801.64 893110 1 0.55 • 1 178,32 I 8589.75: 845645 I - 1799.82 89 279474.21 2400470.38 80 151 •13'32.421'WI 0.51 I •152,30 L .0 51 0.76 1 180242 8994,00 0.26 _105.55 8632.75 851905 X1800.16 •98.74 I 279174.35 2400470.03 1 60 1151 0.85 -80,31 -0.46 i -11551 1802.75 9058.00 '- 0.53 54,16 j 869875 - 8583.45 1800_02 1 -96.38 i - 279474,73 2400470 60'33'53.777N 151 W 0.86 4 141.82 0.42 -80_30 1 180280 • - 912100 037 78.29_ 8759,75 8646.4 1 17 45.92 • 279475.17 240047018 60'33'53.779'N 151•13'32. 0.39 48.42 •025 38.30 1838 02 918400 0.43 86.15 8822.75 , 870945 - 1799,75 -95.49 279475,61 12400470.41 J60'33'53.779'N 1151 0.13 a - 139.49 ' 0.10 t 12.48 • 180228 1 • 9249.00 • j 0 .26 40.67 1 8887,76 6774.4511799.621 -95.14 279475.96 2400470,54 80.3353,75TN 151•1392.38894 0.47 1 -81,68 -0.23 -09.97 1802.13 . 9311,00 - 0.37 I 7,46 894175 ' 8836.45 - 1799.30 4522 1 27947809 *_240047185 60'33'53784 - N 151 0.33 159.97 115 -53.53 • 1801.81 - 44,95 1 279476.16 2400471.19 160' 33'53.78TN 151'13' 32367W 1 119 118.99 -0,17 15,02 1801.47 1 937400 0.28 �_ -.-_ 4 • 901275 8899 - 9437,00 i ; 0.23 37 90 75.74 ' 8962.44 1798_73 -94.83 279476.28 ' 240047143 60'3333 789N 151.13'32,3801 1 4 _ 0.15 7485 -0.05 32.40 ' 10 1801,22 9499.00 0.25 - ^ 49.48 9137.74» 9024.44 I - 1798.54 L -94.56 -I 279476.47 2400471.61 80'33 1151•1332.317WI 0.09 127.72 - 0,03 19.56 1 1801.03 9561.00 0.21 108_86 I 9199,74 9086 .44 - 1798.48 1 -94.44 279476,68 1 . 2400471,66 • 603'53.792'N I151 0.98 -19,90 I 4,06 9256 . 180006 1'N t 411 9623.00 _ 022 26 105.92 9261,74 9148.441 1798798.55 44.28 278476.11 2400471.59 ' 60 151 0.02 22,06 i 0.02 -1,52 ' 1801,02 I tt 9887.00 0 109,45 9325,74 9212 - 12.44 ,89 -- -93 96 1 279477.15 2400471.50 ; 10'3353.797N 151 0.07 75.28 • 0.06 �_ 5.52 1801 .08 9750,00 033 13509 , 9388,74 41 9275.4796.81 i -93.70 ' 279477,41 1 2400471.32 1 60.33'53. 789'N 1151'1 3323571 .23 0 , -131.47 y 011 40,70 1801,25 9813.00 ____ 0.25 85.17 9451.74 9338.44 k 1798.93 - 93.43 279477.88 240047120 60 33'53 151 0.41 3436 1 -0.13 -79.24 1801_35 I 9875.00 1 0.41 .- 7091 - - 1 '_ 9513.74 9400.44 - 1798.84 -93.09 279478.02 2400471.28 60'33'53.788'N , 1519332.345'W 0.29 8480 1 0.26 . -22.95 _ 160125 9838.00 043 87 1 83. 9576.74 • 9469.44 - 1796.74x' 42.54 J 27 ' 2400471,37 80'33 1151 *1 0.15 90.10 0.03 20.52 1 _ 1801,13 -_ 10001.00 0.43 84,08 _ 9630.74 9628.4 •1798.89 42.17 279418,94 240047141 60'33'53.790N 151.1332 0.00 _ ,13 1 •12482 . 0.00 . 0.30 1801,05 _10084.00 " 0. 40 21,18 9702.74 95814 - 1798.48 - -91,88 I 27947926 2400471,63 60 151•13'32.321"W 0.69 -12035 -99.81 1830.81 , _ - 10126.00 0.37 I 11.82 I 9764,73 1 9651.43 -1798,07 + -91.74 1 27947939 1 2400472.03 80'33'53.796'N ;151'133231M .11 I 146_23 -106 l -1510 1800,40 L_ 10189.00_ 47.25 9827,73 914,43 1797,78 -91.61 -- 27947952 ' 240047231 60'33'53,799'N 151'13323161N 0.36 J 92,49 -024 56.24 180012 10251,00 I 0.22 5222 9889.73 9776.43 I - 1797.63 -.-- -91.43 279479.71 - 2400472.48 60'33'53.80014 •151 0.03 144.01 1 0.00 8.02 179995 • 10316.00 0 _ 1 x_112.27 9954.73 • 9841.43 -1797.58 - 91.28 . 272479.88 240047250 1 60'33'63.801' •151•1332.309"WL 0.29 21.19 1 -0.14 4._ 92.38 1799.90 ; _ 10381 0.20 119.87 10019,73 t 9906.431 - 1797.67 41.09 279480.04 2400472.42 1 60 181 0.11 L 44.86 0.11 11.89 179997 ' 10442.071 146.03 10080.73 9967.43 - 1797,9140.87 279480.28 2400472.16 1- 60'3353.797'N .151 0.45 2122 0.30 42.89 , 1800.21 10504.00 • 0.60 153.96 ^ a - 179840_,___90.59 1 279480.53 2400471.67 60'33'53.793'N 151'1332.29S'W 0,28 -145.55 -� 12.79 1800,68 1 ` 10567.00 0.45 139.45 10205,7 • 10092,43 1 - 1798,89 • -90.29 27948082 1 2400471,18 1 0.32 48.11 .024 4 . _23.03 1801,15 - 10331.00 ' 0.51 145.50 10289.72 10188.42 •1799.32 -89.97 ' 279481.13 2400470.75 • ' 60'93'53.7847 1151'13'32.283941 0.13 I 90.90 0.09 11.02 I 1801.56 ____ - 10804.00 , 0,51 ' I - 180.41 - 10332.72 10219,42 •1799.81 -89.72 I 279451,37 : 240047024 60'33'53,779'4 151 0,20 12712 I j 220 000 6 . 180204 10756.00 0.47 16744 10394.12 1028142 1 800322 - 89.57 279481.51 j 2400469.73 80 1 0.12 18.37 -0.06 1134 180254 , 10819.00 0.67 - • 155.65 • 10457.72 • 10344.42 - 1800.91 -89.36 r 27948171 2400489.14 1 !151.1332.271'W 0.37 - 1 20.35 0.32 -18 .71 ' 1803.12 ' � 80'3313J11-71.-4 _ _ 10882.00 0,54 121 _ _ 10520.71 1 10407.41 -1801.40 -88.96 _1 279482.10 2400468.64 1519312.263'W 0.59 4, - 17182 _ -0.21 -53.48 1803.59 _ -._ 10945.00_ t 0.04 _ 46.57 10583 71 10470.41 1801.50 88.69 _ 27948237 2400468. T 60'33'53.762N �L151 0.84 132 79 20 ' t. -0 119.67 1803.72 1 11008.00 0.18 -i 6.77 281.07 1 1064 10533.41 1801.54 - 88.76 1 F 2400468.50 60'33'53.782'1 1151 WT 0.31 10224 0.19 , - 230.95 1803 72 j 1 • 11071.00 '0.33 187.11 10709.71 ! 10598.41 i - 1801 T -88.87 1 279482 19 2400468.30 80'33'53.780N 151 0.52 -57.50 0.27 - 117.40 1 1803.92 _ 11138.00 • 0,44 16182 • 1077471 10861.41 -88 27948220 240046747 1 6033 '53,755'1 151'1332260"W 0.25 _ -31,47 t 0.17 _ I -28.14 1804,35. I 11198.00 0.58 __I 160.88 . 10836:71 1 10723.41 - 1802,70 f _ -88,70 279482.34 2400487.94 • 60 i 151•1332,25TW 025 -' - 175,82 0,23 - 1804.87 1 11262.00 0.39 150.13 10900.71 • 10787.41 I - 180321 -88.51 279482.52 2400466.83 60'60'33'53.745T4 151 0.30 I 64.50 •0.30 -242 180137 I 11303.00 0,48 1 173_70 1 0941_.70_ 10828.40. _-1803,50 - 88_-4_4 - 279482.5 2400_ 46653 �'33 7161 W 0.31 0.00 1 117 t. 36.64 ; 1805.68 __ - - - 1803.97 + -88.39 . 0.00 - 0.00 0.00 - 1806.13 tProlected Data - NO SURVEY , 11362.00 i 8.46 173.70 11000.70 ! 10887.40 ,_ 279482.62 2400466.06 80'33'53.738 - N 151•1332.25194 0.00 Ex 16 KL3 MWD Final Survey 31 I • Permit #: 211 -097 Converted to Disposal API #: 50 -133- 20597 -00 -0 Kenai Loop #3 Prop. Des: MHT 9300070 p KB elevation: 92.5' (21' AGL) lAiL Pad 1 Latitude: 3394' FSL, 1134' FWL Longitude: S33 T6N R11W S.M S 9/1/2011 BiJc A. E ER TD: 9/26/2011 r. Rig Released: Structural Pipe SLB CBL 09/02/2011 16" X-56 84 Bottom MD Surf 120' 1400 sxs Type I Cement + 0.05% bwoc Static TVD Surf 120' - Free + 0.6% bwoc CD -32 + 1 gals /100 sx FP -6L + 15% bwoc LW -5E, 100# Carton + 20% bwoc Surface Casing A AI. MPA -1 + 83.8% Fresh Water - yld 2.3, 12.0 ppg 10 -3/4" L -80 45.5ppf 80 bbls cmt to surface , floats held Top Bottom 3 1/2" 9.2ppf L80 t• ■ Max Inc 28 MD 0' 3,027' degrees Pollard CBL 9/16/2011 Intermediate Casing nipple profile @ ±547 ' 7 -5/8" L -80 29.7 ppf Est Cement Top Top Bottom c • MD 0' 8,330' MD Pr @ 145448' ' TVD 8 45 Packer @ ±550 ,r f - Lined for injection - 4-1/2" L-80 12.6 ottof Hydril 521 Perforations 6435' - Top ppf MD 80' 11,368' 6450' MD (6170 - TVD 7,631' 11,000" CIC acs BC Perforations 6,950 rE. Tubina 2 7/8" L -80 ppf - 6,960' MD (663 ' a= as Baker Flex Lok Liner Hanger Top Bottom 6643'TVD) w/ 2XP Pkr and PBR MD k - Y top @ 8100' MD TVD Drilled CIBP & ad: cmt pushed on I Cast Iron b ridge 311 sxs Class G Cement + 10% bwoc BA -90 + top of liner top plug w/25' 0.05% bwoc Static Free + 2.5% bwoc BA -56 + i ■ r.1 cement on top 0.5% bwoc EC -1 + 0.5% bwoc CD-32 + 0.1% bwoc Perforations – Set at 9,750' MD ASA -301 + 1 gals /100 sx FP -6L + 1% bwoc Na 9,790' - 9,815' MD ---- "O' - _ Metasilicate + 82% FW - yid 1.83, 13.5 ppg . packer w/ sealbore / Tail: "X" profile @ 10,045' 241 sxs Class G Cement + 0.05% bwoc Static MD. "X" plug Free + 0.3% bwoc R -3 + 0.5% bwoc EC -1 + 0.6% Perforations - 10,223' ' ` bwoc FL -63 + 0.3% bwoc CD -32 + 1 gals /100 sx - -10,248' MD , .. – FP -6L + 43.7% RN - yld 1.16, 15.8 ppg packer w /sealbore / "X' profile in "XN" nipple @ 10,300' 1 MD. "X" plug Perforations - L _ •' lied w /sand 10,520' 10,545' MD �- packer w/ sealbore @ 678 sxs Class G Cement + 0.05% bwoc Static 10,700' MD Free + 1.2% bwoc BA -56 + 0.4% bwoc R -3 + 3% bwow Potassium Chloride + 0.5% bwoc EC -1 +0.4% Perforations- bwoc CD -32 + 1 gals /100 sx FP -6L + 0.2% bwoc 10,920' - 10,945' 2 -7/8" tubing tail, AID "X" nipple and 10' Na Metasilicate + 43.9% FW- 1.18 yld. 15.8 ppg II I pup cut @ 10,730.5' MD. Dropped to r — - - - -- -- - - -- -- 1 TD { r PBTD bottom Estimated Formation Tops MD TVD 11,388' MD i ' MD 11,000'TVD j 'TVD Well Name 8 Number: Kenai Loop #3 Lease: Kenai Loop County or Parish: Kenai Penisula Borough State: Alaska 1 Country:I USA Perforations (MD): Perf (TVO): Angle @KOP and Depth: Angle @ Perfs: KOP TVD: Date Completed: RKB: 21' Prepared By. Last Revision Date: Exhibit 17 - KL3 Disposal Well Bore Diagram 32 • r► 20 AAC 25.252 c 7 Waste Sources, Types and Volumes Sources and Volumes of Waste Resources Conservation Recovery Act (RCRA) exempt Class II wastes will be injected in the disposal well. This will include drilling fluids, 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 011 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 Anticipated 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. 33 i • 20AAC25.252c7 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 4. The lithology of the injection zone is typical of local exiting injection wells, being comprised of conglomeratic gravels, inert quartz and clay matrix material. The resident zone 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. II 34 • • 20 AAC 25.252 c 8 Injection Pressure Injection pressure is estimated to average between 1800 - 3000 psi while injecting either mud or slurried cuttings as densities and other properties should be similar. This range should also be reasonable to expect when injecting produced water and other clear fluids because the decrease in hydrostatic pressure (water density vs. cuttings density) may be offset by the more fluid liquid. The combined pump pressure and hydrostatic is generally above the fracture gradient and the flow will cause creation of fractures and closure as the product is being injected. A maximum pressure of ±6000 psi could be reached occasionally should sporadic plugging and refracturing of the formation and or plugging of existing perforations occur. V III 35 • • 20 AAC 25.252 c 9 Waste Confinement 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 /water and miscellaneous 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 Beluga Formation. A three dimensional hydraulic fracturing simulator was used to predict fracture growth during slurry injection. A prominent injection company and a prominent fracturing company conducted analyses that were reviewed. Rock properties used in the model were based on well data calculated from Kenai Loop #1 and Kenai Loop #3 well logs. The fracture gradient was itself then calibrated to break down data obtained from those wells. The fracture report of Appendix B details the model input data. The perforated sands within the injection interval are planned to be utilized first with additional perforations being added above the initial perforations within the injection interval as the need arises. The sand members that constitute the modeled injection zone are shown on Exhibit 18 and as modeled in Exhibit 19. 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 10.5 pounds per gallon (ppg) and is planned to be injected at a rate of 2.5 to 4.0 BPM. Exhibit 20 shows the forecasted fracture dimensions for a 50000bbl case and the forecast over the life of the well. Exhibit 21 shows the forecasted fracture geometry resulting from the planned injection if the well was completed only in the modeled sand lobe and continuous injection occurs over a 5 year period. Exhibit 21A shows typical results under the most extreme conditions of injecting a 2,500 barrel batch of 10.1 ppg slurry at an elevated rate. Additional discussion is included in Appendix B. In all cases, injection does not penetrate the upper confining zone or breach the lower confining shale or intersect the closest welibore. Reservoir Faulting: The geologic mapping previously discussed show there are no transmissive faults in the area. Uncemented WelIbores: Within the % mile area of review, there are no improperly cased or cemented wells. There is only one well. An overview of this well can be found in Section (c)12. Conclusions: Wastes are expected to be confined within the injection zone just as proposed by the fracture analysis calculations. 36 iiiiRMIRMITIMPlilfritralaiWilifittl r t K i i iI L V J V J v V V J 1 6 f ��11��sg ��QSyW/QS� ��Q�pj ep� M w w�q�� gyNpN, q ua 1ag7�N Ig p e MNMO aari V N 0015111 bt1 o V 1P BOO11w W ODD 55 W liiII V MM I M 0 , • �' r . IIIIIMIIIII151115011111111118155551i/IIRIEBRIT g g e o ooe oofa ooeee eopoaoopQ peoo 0 g) g i ...i H O ii ''�jyw� M L, �p YlpY �,/1 pjWpelW lW W �Rwj Wijyp W W 41 'i iiiPR �O1 i i W i P � Ii m 1 eo e0000ee oeoe 0000ao a oeo¢p¢oo¢eoo Qe o0 0 0 as a a a aoaa vwwJ gi R 0 411 .. s . 0. m _ m H 0 o 0 0 0 0 0 0 o a 0 0 0 0 0 0 0 0 0 0 0 o e 0 0 0 0 0 0 o 0 o 0 0 0 0 0 0 0 o e e e o 0 0 0 0 f n M 0 [ W H. _ n a pppp 44 e oo ppp o oo QQ 0o0000 p pp p Qoo oo OO H ro n 0 b m m Ct W m N w J • • Exhibit 19 MECHANICAI. PROPERTIES OUTPUT GRAPH , Stress Ciratlitiit Strl-sb n Youg's Modulub Puittsutt's Ratio 'I'ouvfults 414 ilk a. rig hii. , _ __ 10 i-_-_____--- D Mill ' I T 1 --- 111 , 7 14 ♦.cl 4 a1 11P KC 4-all. 11,.l) Iy :11 4,1n1 Exhibit 19 38 • • Exhibit 20 FRACTURE HALF WING. MODEL, 5u,000 Bbls. F rt ss Width Profiles -- — = Y. Lm - . "`I ..." m ` s U 00]01 •U moil ' i.iU " ' Nu n Onax s0 k ' °ml +e. � r 93 00111 S. v 011• n°n• 00]10 7-s: � 1 11 L '7. 1 IP IIIIIIIIIIIIIIIP i0:f 1 ell Tit= 1 r. U. , — ,CtZ ftro' We a 001 U r, r01 C i fr Tl '' 1Cr 9'11 SW]'ese (psi) Width (in ) Length (fl) FRACTU1tE HALF WING LONG DURATION MODEL, 1,000,000 Bbls. amt Streaa Width Profilta _ - -.-- -- _ A n i v s •. ` u n Ma 2 j p n oa01 Gpan 0 00aa � ,y f _... "Tip" emn we., r , n± v n •r- a _.. Ivy •a-n arnl Stress (Psi) Width (in.) Length (ii) Exhibit 20 39 • • Exhibit 21 FRACTURE HALF WING MODEL, 155 BPD, 3 BPM, 5 YEAR DURATION 6300 Stress Width Profiles tasks. SFI 2500 bbl continuous c(D6bpm, Concentration/Area (EOJ) I lbmlft 2 0 0.0005 _ 0.0035 I 000q i 0.0045 lir_ k 0.005 6330 o.o05s �-- - 0.006 6350 6360 I 6300 4000 6000 6000 -O 004 0 0.004 0 300 600 900 Stress (psi) Width (in.) Length (ft) Exhibit 21 40 • • Exhibit 21A FRACTURE HALF WING, HIGH RATE, ONE TIME INJECTION F. (0... ;• - It le 5 0 1 7i. r:. 70 81 ' . • 6310 2500 Bbls 6320 I°1•411111101 6 BPNI 6330 Cuttings Slurry 6350 One Time Injection 60 4 t Exhibit 21A 41 • • 20 AAC 25.252 c 10 and 11 Formation Water Salinity and Aquifer Exemption On October 25, 2011, during the well testing phase for Kenai Loop #3, a sample of the water from the formation was analyzed on -site by MI- Swaco. Total chlorides were determined to be ±6000ppm. Buccaneer Alaska Operations, LLC is applying for an Aquifer Exemption Order for the depths of 5418'TVD -ss (Top of Beluga) to 6591' 1VD-ss. 42 • 20 AAC 25.252 c 12 Wells within Area of Review The % mile area of review around the top of the proposed injection zone in Kenai Loop #3 has been previously shown to only include Kenai Loop #1. This well has been cased and cemented so as not to provide a conduit for injected wastes to escape the proposed injection zone. No corrective action plans are required. Detailed information on this well, and the original Kenai Loop #3, has been provided to the AOGCC. Summary of Kenai Loop #1 The AS- Completed schematic (WBS) is shown in Exhibit 22. The surface casing was cemented to SURFACE and shows very good top of cement at ±1806'. The intermediate casing CBL shows top of cement to ±4900'. These are demonstrated in Exhibits 23 and 24. The Kenai Loop #1, as well as the Kenai Loop #3, has more than single adequate barriers to protect known usable drinking water in the area. 43 • CMPLTN WELLBORE (6) • Stephen F. (Steve) Hennigan 3/14/2012 Buccaneer Alaska Opns LLC 0 Kenai Loop g 7 Block/Sec 33 6N 11W Wildcat 0 Kenai Peninsula 0 Alaska Ser #.: 211 043 ,n tree " c % "r.(. • IIlM r MM UMW Eat Rkb Air Gap D Wtr. Dpth R.4 N 8 9.8 123' pen - TAi r .5# N801IC Welded Drl . Se » 16 " ROP4Gas log COnd/Drive to TD. li I: I . I " ertemlcal Inj Mandrel ±bUU' I: _ � '\ /4" SS 0.049 wall chem Inj line 2 7/8" 6.5 L80 2.347'YD API EUE 8rd M 11 i " 5GSSV ±565' I' li I: k..GBL EXPRO 04-29-2011 90 16.0 ttlpiea nbe 3 ;: i .145.54 2.80 RTC 13 1/2" 055' I r 10 3/4" i Pump 42 bbls Mud Clean II with red dye Pump 3 bbls i LOT #2 @ 3352' MD 14.7 ppg emw water. Test lines to 2k psi Cmt to surf @ 520 bbls. Pump 564 bbls 12 ppg cmt. Pump 5 bbls water to clear lines. Switch to rig pumps to displace w/45 bbis 8.8 p mud. Floats heidUnsting. CIP @ 21.000 rot' u900m• LOT #1 15. pg emw 1 hrs - R/u BJ for Cmt Job PJSM for Cmt Job - Tst Surf Lines 4000 Psi - I - OK 0.25 hrs - Repair BJ H2O Line ( cement plug in line) 1 hrs - Mx & E 10.2 ppg NaCL/KCL Pump 30 Bbl 1 OPPG Spacer & Mx 3 Bbls Cmt - (Packing over/heating - . S /dn & Observe) 2.25 hrs - Mx & Pump 126.5 Bbl Lead to Slurry wt 13.5 - ' PPG - Follow w/ 52 Bbls Tail to Slurry Wt 15.8 PPG Shut/dn - Drop Plug • & Pump 5 Bbls H2O - Skin & Displace w/ Rig Pump - Plu - Calculated Displacement - Press /up 1000 Psi (1900) & hold 5 Min - Bleed /off - Floats HeldCIP = 06:05 HrsNote: Btm Shoe @ 8024' & Fl at - Collar @ 7938' -_ ,QEL EXPRO 05 19 2011 n I #:3 13.b ppg emw - 2 r� 1 Quart Cont. plat 8024' ` 29.7# L80 BTC top! "am bt, 9 7/8" 8021' * [¢ 7 5/8" 2¢ , • _ . ("{2 I) B T 5 -1/2" 175 x 7 -5/8 " 29.7 - 395 ; 2¢ -' '. [¢2 80 KSt Hyd Flex Lock Liner hanger w/ 2¢ I 1¢ ZXP LT Packer 20 I - - 2 ITOL 7892" MD,7888'TVD / 875 " 9687.14' 2¢ (¢2 C ' string a *98C9' 2¢ l ' [ ¢2 20 [¢ Baker Model D Pkr @ 9666' (9659'TVD) 20 (¢2 26 [¢2 s Top Perforation (RDX) 9705 " = Bottom Perforation (6 SPF) 9724.85' 2¢ [0 (9698' 9717' TVD) 2¢ [02 _ [d Top Perforation (RDX) 10008.15 = Bottom Perforation (6 SPF) 10049.17 NOTE: Test guns DID NOT release. -,y Z1F (10000' 10040' TVD) Cut string @±9689'. String fell. 2¢ [¢2 < 20 > 4t [¢2 Estimated top of fish 10240'MD 2Y¢{' 6y [/2 2 t ry115 [ 02 7 ( PBTD 10565'DPM ¢ [ ¢2 Drill 2 y [ j2 CBL EXPRO 05 19 2011 ! 4 16.5 Qu d Comm, pu, 10680 n 2¢ [0 12.65 L80 TCA 6 3/4" 1086 4 112" Test to 4500 psi. Mix and pump 40 bbls sealbond sweep at 12.5ppg 672 sx 141.2 slurry Class G + 1.2% BA -56, 3% KCL, .5%% EC -1, .4% CD -32, .2% A- 2..2 %R -3, .05% Static Free, 1 ghs FP -6L. Yld 1.18 cu risk, 9.82' marker jl @ 8324' 15.8 ppg 4.951 gl H2O sk, 3.32 pumping time. 79.216 bbls water to mix. Landing collar 10591. Float collar @ 10633' Displace w 11.4 ppg mw. Tagged (ai 10565' DPM Csg shoe 10676' Exhibit 22 - KL #1 Completed WBD 44 • • 7 5/8" Top of Cement per CBL KL #1 TOC ±4900' 1/ 1/ I 1 I ) I 1 . - -- - •- -- --- — 1- - • . 4900 -- - ---7r.- i'..., '... I ' -::. _ _ -- t ■—t--________-- i . . . il . _-.. ? . 4 I I .411 EST. TOP OF CEMENii! I III' 1 , 1 ■ .----- I , :NZ 4 r . ..• s '" ... r.....i ...' : =T. t. 4.... . , 4 i 1 • i ....7.7.... . . t - — :- -- ---r-j- — — 4950 — - - - _T.,. ____ f I ' c' - ■''''.. I 1 ■ ... s . ....., 1 • • •i■ : " ■ • r.. r . 7 . j or..:.......... - 1 -J ----- i I .." — — : .. I I I % 1 I i ....-A- , . — — — ----------------- I . -../ — -- — — -' ---------------- ff f tto'fri 1 .- -- -- _, .... ... ---4,.—. 5000 .- , • .......... i ; ...____ :.-2. I , I i , 1 r ..,—, , .. ----- :: ::::::::__ _ _ 4 - I - 4 a i ... _ _ .‚ , — . i 1 1 1 % 1: ' I . — _-- - ' * t, I a ',Z..... 4 I — •••• "'' 4 '''' '''''' ''. ''' 4 ------------------ 1/ 1 Sill , I i ...,• ■ ,., ... ..::: S.:. ... .... . . . : . L • . 17 : ■ . . , 5050 ,," 1 . ., .-.7.-.4..?2'.."*„. .....' , . ' - - - -4- - -• -, ; 1 1 -........ i i . ,.... ,.- - Ex 23-7 5/8 Intm CBL Top of Cement 4 5 0 • 10 %" Surface Cement per CBL KL #1 (Top @ ±1806') dti' L. -L -. - ... -.. _ —_ 1750 ...- 1 ii 4 t r iliV j . { i . flit s. 1 t t tt 4 # • t t I ,' i _ 1850 —_ =_ _ _ i - • I - . ,i la ` is i 111 'a �_= s.._ } t + 111 • , „, _ • 1900 �, -- _____ ♦ s - _i Z. 1 = - - - -- - -_ t / - �', — • t ..' • s . J — — — 1950 Sc` !i" ' . . ; _ • Ex 24 —10 %" CBL Cement KL #1 46 • 20 AAC 25.252 d and e Mechanical Integrity of Injection Well Wel!bore Integrity Prior to drilling out the existing cement and plug in the Kenai Loop #3 well, the casing will be tested to 3800 psi. The intermediate was tested prior to well test to that pressure on Oct 6, 2011 report. The cement and plug will be drilled out. Tubing (3 34" L80 9.2 ppf) and packer will be run and the tubing will be tested to 7096 of burst (7000 psi). These exceed the requirements of 20 AAC 25.412. However, it is requested that the well be exempt from placing the packer within 200' of the perforations so that maximum utilization of the interval could be allowed. It is desired to place the packer within 200' of the base of the upper confining zone. Reporting will be as per 20 AAC 25.432. Formation Testing and Integrity Initial formation evaluation will include an injectivity test (step rate to maximum 6 bpm). Breakdown and injection pressures and shut in pressures following injection will be analyzed for formation integrity. Upon establishing a baseline, subsequent monitoring, testing and reporting will meet and /or exceed AOGCC requirements. II 47 • • AFFIDAVIT OF DELIVERY STATE OF TEXAS ) ) SS. COUNTY OF HARRIS ) E. A. Rike, Jr., being first duly sworn upon oath, deposes and says as follows: I am employed by Buccaneer Alaska Operations, LLC and state that a true copy of the Application for Disposal Injection Order on Kenai Loop #3 was sent, via electronically, to each of the following parties: Alaska Mental Health Trust Land Office 2600 Cordova Street, Suite 100 Suite 100 Anchorage, AK 99503 Cook Inlet Region, Inc. ( "CIRI ") 2525 C Street, Suite 500 P.O. Box 93330 Anchorage, AK 99509 -3330 7 Il I f E. )e Jr. '� Date Executive Vice President of Operations THIS CERTIFIES that on the 14 day of March, 2012, before me appeared E. A. Rike, Jr., known to me to be the person named who executed this affidavit and acknowledged voluntarily signing it. Paula Hastreiter i % (AEA t I ? a My Commission Expires - . 4 \ `'t 07/18/2015 giitary Public My Commission expires: July 18, 2015 410 Appendix B • Buccaneer Central Injection Site Fracture Model & Study BUCCANEER CENTRAL INJECTION SITE FRACTURE MODEL AND FEASIBILITY STUDY CLASS 11 INJECTION WELL Prepared for: Steve Hennigan Petroleum Engineers, Intl. ELBE CUTTING DISPOSAL SPECIALIST DRILL CUTTINGS DISPOSAL COMPANY Page 1 Appendix B • • Buccaneer Central Injection Site Fracture Model & Study Table of Contents 1.0 Executive Summary 2.0 Introduction 3.0 Basis of Study 4.0 DCDC Fracture Model 5.0 Geologic Discussion 6.0 Summary and Conclusions 7.0 Recommendations 8.0 DCDC Attachments 9.0 Buccaneer Well Attachments DRILL CUTTINGS DISPOSAL COMPANY Page 2 • • Buccaneer Central Injection Site Fracture Model & Study 1.0 EXECUTIVE SUMMARY Buccaneer is investigating the feasibility of setting up a central injection site for the disposal of drill cuttings collected from its planned future offshore and land development wells, in and around the Cooks Inlet of Alaska. The initial intention is to inject drill cuttings via 3 '/2 inch tubing, cased, completed and perforated at approximately 6300 feet, TVD. Petroleum Engineers, Steve Hennigan has estimated that this project will run for at least 15 years, with 67,000 barrels of cuttings slurry and produced water injected per year, into a Class II injection well. DCDC was asked to review the feasibility and produce fracture models of this cuttings injection scenario. DCDC has reviewed the feasibility of grinding and injecting cuttings from a number of these offshore and land wells, into subsurface formations near the Cooks Inlet of Alaska, and has produced models that predict the safe disposal of all cuttings slurries injected over the 15 year period, based upon DCDC "s philosophy, experience and methodology. For this study, DCDC utilized existing geotechnical data that was available from previous Buccaneer Drilling Operations in this area and has no reason to dispute the data. The subsurface data is consistent with other subsurface disposal wells which we have been involved in, on other Cooks Inlet Projects. DCDC is a pioneer in Cuttings Re- Injection technology on a global basis, beginning in the mid 1980's and maintains an excellent performance record using our proprietary cuttings reinjeciton process for permanently disposing of drill cuttings and other rig wastes. We have successfully completed well over 372 projects around the world, injecting in excess of 3.5 million barrels of cuttings waste. Including injecting cuttings slurries and waste for Phillips for several years on a platform in the Cooks Inlet and grinding and injecting cuttings from wells drilled by Anadarko on land just off the Cooks Inlet. DCDC has used its technology to safely inject drill cuttings on every continent in the world, many of which were in environmentally sensitive, high profile, heavily regulated areas. It is important to note that significant differences exist in DCDC /Apollo's injection methodology and that suggested by other subsurface study experts. While other's quote 300 micron grind size, DCDC grinds it's cuttings slurries to D90 <100 micron, while most of the slurry particle sizes are less than 40 and 10 micron. Unlike others, DCDC does not create large fractures, to dispose of the cuttings. DCDC's disposal process is based upon applying low hydraulic horsepower into the slurry/formation, long -term injection, low injection rates and slurry Theological control designed for matrix injection with minimal fracturing. The DCDC methodology allows more cuttings to be successfully • entombed per zone, than injecting slurries with particles 3 times larger by others. The results of this study are based on DCDC's methodology. The expected injection pressures will be in the range of 2200 psi, depending upon the hydrostatic head of the slurry, injection rates and the development of formation change over time. The expected injection rates will vary as the quantity of cuttings to dispose change. The study is based upon injecting cuttings slurry, continuously and batch. Gel strength's can be maintained without the use of a viscosifier in much of the cuttings slurries prepared, but when a viscosifier is needed DCDC recommends its proprietary viscocifier blend that has worked well for many years. DRILL CUTTINGS DISPOSAL COMPANY Page 3 4 • Buccaneer Central Injection Site Fracture Model & Study DCDC's model predicts that the formation will safely handle the volume of cuttings generated over the 15 year project, well within the immediate injection zone. The formations were reviewed and it was determined that there were no abnormalities within the injection zone that could affect the injection process. The lithological makeup of the formations has properties experienced by DCDC on many of our injection projects. The models were run with significantly higher volumes of cuttings slurry to produce a more conservative model, thus the author is comfortable with the horizontal and vertical extent shown in the model half lengths, for even larger volumes of disposal. Well tubular/head strengths should allow for safe 3500 psi working pressures to insure safe handling of the disposal slurries over time. We expect that the first set of pelf's will receive the slurry and the second set of perf's are redundant. No formation injection test data was available for this review, at this depth. DCDC recommends that, at the appropriate time, injectivity tests be performed with approximately 9.5 to 10.0ppg mud, to further develop the disposal plan. I • 116 , .3 0 A --,.:: ' "-- -.._,„,,, , ..„, ,,,,,, --„..„..... • , ..._ 1, 1 J*.• lik -•,..1 ,,,,,,,, ------„,„„ ..... „...,,, ..... L ., -_,p." .,::,„ ..,, i DRILL CUTTINGS DISPOSAL COMPANY Page 4 4111 • Buccaneer Central Injection Site Fracture Model & Study 2.0 INTRODUCTION A feasibility study was prepared, to review the methods, procedures and down -hole requirements for successful Cuttings Reinjection Operations in the Cooks Inlet area of Alaska. Slurry Injection Data has been collected by DCDC over the last 30 years from the successful work performed around the world and specifically, in the Cooks Inlet area. DCDC utilizes its in house fracture- modelling methodology, adjusted for cuttings reinjection data, which has been collected by us from all over the world. DCDC's resulting fracture modelling is designed specifically with cuttings reinjection methods and quality controlled injection procedures utilized DCDC and therefore, should not be misconstrued as a "road map ", if you will, for any service company's injection process. DCDC's trade secrets include much technological advancement which is not available to industry, which significantly impact the quantity and quality of cuttings slurry that we can inject successfully - in zone. Interestingly, Fracture modelling for cuttings reinjection is significantly different than typical fracturing for increased production. These differences make typical fracture model evaluation wholly unacceptable for use in designing cuttings injection operations. Figure 1 details the differences between fracturing for production stimulation and fracturing for cuttings placement "in zone ". It is these very differences from which DCDC has recorded a sizeable database of subsurface rock reactions to cuttings slurry placement, from projects completed successfully around the world and provides DCDC the ability to optimise cuttings slurry placement, operational procedures and continued success. FIGURE 1 Cuttings Fracture Theory Production Fracture Models Cuttings Fracture Models • Design to stimulate production High Injections • Uses brittle large particles • One particle size • Just the Opposite • High in fluid horsepower • Short in duration • Excellent fluid properties - Low Fluid Loss DRILL CUTTINGS DISPOSAL COMPANY Page 5 Buccaneer Central Injection Site Fracture Model & Study The readers of this study should respect the difference between pumping anything down, wherever it goes, as compared with a scientific, predetermined, quality controlled, CRI program and its impact on subsurface formations. Only very forgiving formations with excellent containment formations and cement above the injection zone, allow for an unscientific approach. Additionally, as the formation receives cuttings slurries, the ability of the formation to receive the cuttings slurry changes and the method of slurry preparation and pumping may need to change. Therefore, continuous formation reading and slurry preparation/injection methods and fluid property adjustment's, is a requirement for long -term cuttings reinjection success. DCDC's slurries have been measured as 100 micron maximum particle size (the majority below 40 micron), by our customers. Find attached our a. Partial Job Experience b. Guidelines Publication c. Cuttings Robot for offshore cuttings containment operations d. See website www. DrillCuttingsDisposalCoinpanv .com for our SPE papers and other information DRILL CUTTINGS DISPOSAL COMPANY Page 6 • • Buccaneer Central Injection Site Fracture Model & Study I 3.0 BASIS OF DESIGN Find attached the Buccaneer mud log, gamma ray log, wellbore schematic DRILL CUTTINGS DISPOSAL COMPANY Page 7 • • Buccaneer Central Injection Site Fracture Model & Study 3.1 VOLUME OF CUTTINGS SLURRY Given was that the wells planned to be drilled, would generate cuttings and fluids of twice the hole volume for disposal in the central injection facility. Multiple Wells Drilled over 15 year period, both offshore and on land. The volume of cuttings slurry generated was given to be 1,000,000 Barrels of prepared slurry and produced water, injected each year for fifteen years. DRILL CUTTINGS DISPOSAL COMPANY Page 8 • • Buccaneer Central Injection Site Fracture Model & Study 3.2 PLANNED PUMP RATES FOR THE FRACTURE MODEL Cuttings, Mud and Waste fluids will be brought to the central injection site and stored/collected for efficiently processing, grinding and injecting in properly prepared DCDC slurry, minimizing the use of any additional water and/or chemicals. Operations will typically be conducted during daylight hours on a 12 hour shift basis, processing cuttings at rates high enough to dispose of cuttings, mud and waste fluids to keep up with the well drilling progress. SLURRY INJECTION SCHEDULE: Pump Schedule 2 I DAY 1: 3 BPM 2000 BBLS SLURRY, 500 BBLS PRODUCED WATER, SHUT IN DAY 2: DITTO DAY 3: DITTO 15 Years with same injection cycle. 1,000,000 Bbls. Cuttings Slurry and Produced Water Shut in times may vary from 12 hours to several weeks. DURATION 15 YEARS DRILL CUTTINGS DISPOSAL COMPANY Page 9 • Buccaneer Central Injection Site Fracture Model & Study 3.3 INJECTION PRESSURES Injection Pressures were estimated from Eaton curve data and from past experience. Drilling these types of wells in the Cooks Inlet of Alaska Area has generated cuttings slurries on past DCDC projects in the range of 9.0 to 10.5 ppg slurries. The initial injection pressure values are typical of injecting these slurry densities with particle sizes of D90 Less Than 100 microns for this area. Initial Inj. Pressure = 15.2 ppg (Easton Chart) x 6300 — (8.30 x 6300 x .052) = 2280 psi With sea water Injection Pressure = 15.2 ppg x 6300 — (9.5 x 6300 x .052) = 1887 psi With 9.5 ppg slurry Actual injectivity tests will be performed to further delineate expected injection pressures and rates over time. DRILL CUTTINGS DISPOSAL COMPANY Page 10 • • Buccaneer Central Injection Site Fracture Model & Study 3.4 DCDC SLURRY PROPERTIES, based upon the Cooks Inlet Area N' =.36 K' _ .09032 Cp = 161 @ 170 r /sec S.G. = 1.26 D90 Less than 100- micron particle size DCDC SLURRY PARTICLE SIZE - MEASURED BY BRITISH GAS System number 5226 Diode DR473 Limestone Formation Malvern Instruments Easy Particle Sizer M6.1 M Date 28 -02 -89 Time 09 -58 100 1111111111111111 11111111II! i •1111111111111 20 1101Ni11111111111•/:%1111 ■1111111M fl UI1111ii11111►%i11111 � •I111111 ■21Ru111111 s0 � 111a1i11/' 10 111111111111111M1 1111•1111111111 •11111111111111 �111� ___ .1111111 Ri1I1111111 HMI _1E111111■ o ��_- - --- "4 1 •aii1111M 10 100 1000 Particle Size DRILL CUTTINGS DISPOSAL COMPANY Page 11 • Buccaneer Central Injection Site Fracture Model & Study 3.5 Input Data (Rock Properties) Listed in this section are properties utilized for fracture analysis. Some rock properties were derived from the information obtained in the reference material and from estimates, based on experience. Rock Type The primary rock contained in this zone. Typical rock types are taken from the Ethology logs and are listed in our layering data. These rocks are dirty, calcified, non - uniform and heterogeneous, in nature. Top TVD True vertical depth from the surface to the top of the Zone. Top MD Measured depth from the surface to the top of the Zone. Gross Height True vertical height of the zone. The difference between the top TVD of the current zone and the top TVD of the next zone is the gross height of the zone. Leak off Height The portion of the zone into which fluids will leak off. Zones may be the aggregate of a number of geologic formations. The leak off height is included in order to account for the impermeable sections of a zone. Water Saturation The fraction of the zone pore space occupied by water. This value can be found on well logs or the core analysis. Porosity The ratio of the volume of connected pore space to the total volume of rock Permeability Rock Permeability: A measure of the rock's resistance to the flow of a fluid through its pore space. DRILL CUTTINGS DISPOSAL COMPANY Page 12 • Buccaneer Central Injection Site Fracture Model & Study Fracture Gradient The bottom hole pressure required to propagate a fracture divided by the true vertical depth of the center of the layer. This quantity depends on the strength of the formation and the stresses present in the formation. The units on the fracture gradient are psi /ft. Typical values range from 0.6 to .75 for normally pressured, shallow rock zones; to 0.8 -1.0 for deep, high pressure, and hard formations. This value can be calculated from the Minimum In -Situ Stress obtained from a Step -Rate test. If the Zone's top TVD, Height and Minimum In -Situ Stress have been entered, the fracture gradient will be calculated automatically. DCDC injectivity tests will provide in situ data to further develop our model. Minimum In -situ Stress The minimum principle stress for the layer of rock. The smallest of the three components of the diagonal stress tensor. The Step -Rate Test and Flow back are tests to be performed to measure this value. Extended leak off test information can be utilized to firm up the disposal zone characteristics. Reservoir Pressure The pressure that exists in a reservoir under equilibrium conditions. Expressed in psi. The reservoir pressure can be obtained from well logs or from well tests, i.e. the RFT (repeat formation tester) LOG. Young's Modulus Pressure on the rock after pre - existing micro- cracks have closed produces bulk rock compression where pores deform and grains compress at a more linear rate. This linear form is represented by the coefficient of proportionality, which is termed the Young's Modulus. Young's Modulus is really a measure of the stiffness of the rock, or the parameter expressing the resistance to deformation that a rock has for a given load condition. Young's Modulus is important because it directly affects hydraulic fracture geometry and governs how wide the fracture will open at a given down hole pressure. The length and width of a man -made fracture depend on the stiffness of the rock. You can get the dynamic Young's Modulus from the Well Log and convert it to static. Typically the dynamic is 35% greater than the static. For porosity up to 10% multiply the dynamic by 0.65 to get the static. For porosity up to 20% multiply the dynamic by 0.6 to get the static. The lower the porosity, the closer the static is to the dynamic value. In cases of very high porosity, it is very difficult to differentiate the static Young's Modulus from the dynamic Young's Modulus. DRILL CUTTINGS DISPOSAL COMPANY Page 13 • . Buccaneer Central In'ection Site Fracture Model & Study Poisson's Ratio Poisson's ratio is the ratio of a rock's lateral expansion to its longitudinal contraction. During a fracture, the compressive force on a cylinder of rock will cause deformation. If the rock is compressed in one direction, it shortens along the direction of applied compression and expands in lateral directions. The effect of Poisson's Ratio is small in that it is used in the term (1 —v2) where V is Poisson's Ratio. Typical values are: Rock Type Poisson's Ratio Sandstone 0.2 Carbonates 0.15 Shale 0.25 Claysiltstone 0.30 Fracture Toughness The ability of the rock to resist fracturing. In rocks with a Young's Modulus less than 1,000,000, fracture development may be toughness driven. For values over 1,000,000 the toughness number has very little effect on the fracture development. Specific Gravity The specific gravity of the rock is the density of the rock divided by the density of water. Typical values are: Rock Type Specific Gravity Sandstone 2.5 Limestone 2.71 Dolomites 2.95 Shale 2.3 Anhydrite 2.2 Rock Compressibility A measure of the change in connected pore volume with the change in fluid pressure. Typical values are: Rock Type Compressibility(oil field) Compressibility(metric) Limestone 6E-6 1/psi 8.7E-7 1/kPa Soft Sandstone 3.5E -6 1 /psi 5.1E -7 1/kPa Hard Sandstone 5E -6 1 /psi 7.3E -7 1/kPa DRILL CUTTINGS DISPOSAL COMPANY Page 14 • • Buccaneer Central Injection Site Fracture Model & Study Embedment Streneth Rock embedment strength is defined as the force required to push a 1/8 in. diameter sphere 1/16 in. into the rock. This data can be obtained from laboratory tests. The following is a range of data corresponding to different rock types: Rock Type Strength (oil field) Strength (metric) Chalk 5000 psi to 20000 psi 34474 kPa to 137895 kPa Limestone 40000 psi to 100000 psi 275790 kPa to 689476 kPa Dolomite 50000 psi to 200000 psi 344738 kPa to 1378952 kPa Heat Capacity The amount of heat required to raise the temperature of a unit mass of the rock 1 degree. Typical values are: Rock Type Btu/lb. /deg F kJ/kg/deg C Chalk 0,215 0.90 Coal 0.30 1.25 Dolomite 0.222 0.93 Limestone 0.217 0.91 Sandstone 0.22 0.92 Thermal Conductivity A measure of the ease with which heat may be transferred to or from the rock to a stimulation production fluid. Rock Type Btu/ft/h/deg F W /m/C Carbonate 1.16 2.0 Sandstone 3.0 5.2 Permeability Components • Kx - Rock permeability in X direction that is parallel to the direction of the fracture length. Ky - Rock permeability in Y direction that is perpendicular to the direction of the fracture length and the vertical well. Kz - Rock permeability in Z direction that is parallel to a vertical well. This permeability is only used for horizontal well production prediction. Perforation Zones: The well will be perforated with .42 inch holes, 12 shots per foot, 50 feet. DRILL CUTTINGS DISPOSAL COMPANY Page 15 • • Buccaneer Central Injection Site Fracture Model & Study 3.6 Output Data: Shown in this report is a single fracture wing that predicts medium term injection of drill cuttings (50,000 Bbls.) in one injection cycle, and one which depicts worst case scenario over a long term injection project, lasting approximately 15 years (1,000,000 Bbls). A 3 dimensional matrix fracture view is also depicted for 1,000,000 Bbls of cuttings and fluids. Cuttings Injection Projects last for months, if not years. Therefore, fractures open and close and rotate around the well bore, taking the path of least resistance. The actual formation affect will be similar to the single fracture wing, but in different planes, resulting in the same graphic shape, taken at different views, rotated around the well bore centreline, as the axis. Therefore, the slurry volume can be multiplied by the number of planes that the sluryy rotates thru, as it seals itself in one direction and rotates to the next path of least resistance. Thus, resulting in matrix injection. This has been proven by DCDC, as DCDC has performed many injection projects, with its methodology, where many wells are drilled from a single platform and DCDC has monitored the other well bores to determine if and when cuttings slurries reached another well bore. Over time, we have learned to understand how the initial fractures turn into matrix injection described above. Among other things, we have learned that our fracture predictions are generally worst case, as we have yet to see a project where our injecting waste slurry has reached out as far as the models predict. Proppant design summary: DCDC's proppant size is variable, D90 less than 100 microns. Wellbore Hydraulic Width: The width of the fracture created by the model. This view is to be looked at as if you are sitting in the well bore and looking out at one of the fracture planes. These planes will wagon wheel around the formation as the formation changes over disposal material time. As you get further from the well bore the hydraulic power depletes, the slurry fracture tip stop's expanding and new fractures propagate and wagon wheel around, causing mini fractures or fissures. Estimated Closure Time This is the simulator's calculated time for the fracture to close. To model the complete pressure history during closure, this should be less than the time entered into the Shut -In Time field on the initial module window. End -of -Job Hydraulic Fracture Half - Length This is the fmal hydraulic fracture penetration at the end of the job. Half - length is the length of one wing of the fracture. DRILL CUTTINGS DISPOSAL COMPANY Page 16 • • Buccaneer Central In'ection Site Fracture Model & Study Maximum Hydraulic Fracture Half - Length The maximum final hydraulic fracture penetration at the end of the job. Half - length is the length of one wing of the fracture. End -of -Job Hydraulic Width at Well This is the average width of the fracture at the well and at the end of job. End -of -Job Hydraulic Height at Well This is the average height of the fracture at the well and the end of job. DRILL CUTTINGS DISPOSAL COMPANY Page 17 • Buccaneer Central Injection Site Fracture Model & Study 4.0 DCDC CUTTINGS RE- INJECTION SUB - SURFACE MODEL Operator : Buccaneer Well : Injection Well Field • Well Location : FA -23 State : Alaska Country Prepared for : Steve Hennigan, Petroleum Engineeers, Intl. Date Prepared : 1/09/2012 Prepared by : Jeff Reddoch Phone : 337 - 988 -9078 E -Mail Address: reddjefl @yahoo.com DRILL CUTTINGS DISPOSAL COMPANY Page 18 • , Buccaneer Central Injection Site Fracture Model & Study 4.1: PERFORATION DATA Perforation Data Top Top Bottom Bottom Shot Number Diameter MD TVD MD TVD Density (ft) (ft) (ft) (ft) (shot/ft) () (in) 6320.0 6320.0 6370.0 6370.0 12.00 600 0.42 DRILL CUTTINGS DISPOSAL COMPANY Page 19 • • Buccaneer Central In'ection Site Fracture Model & Study 4.2 FORMATION LAYERS WITH MECHANICAL PROPERTIES Zone Name TVD at MD at Stress Stress Young's Poisson's Fracture Critical Stress Bottom Bottom Gradient (psi) Modulus Ratio Toughness Stress interpolation ft ft .si/ft .•i .si- in ^1/2 .si Siitstone7 6242 6242 0.817 5099.7 3.33e+06 0.2 2200 0 Off Shy Siltstone6 6248 6248 0.828 5173.3 3.62e+06 0.26 2250 0 Off Siltstone7 6250 6250 0.817 5106.3 3.33e+06 0.2 2200 0 Off SndySiltstone7 6253 6253 0.795 4971.1 3.33e+06 0.23 2150 0 Off Siltstone7 6255 6255 0.817 5110.3 3.33e+06 0.2 2200 0 Off SndySiltstone7 6257 6257 0.795 4974.3 3.33e+06 0.23 2150 0 Off Shy Siltstone6 6260 6260 0.828 5183.3 3.62e+06 0.26 2250 0 Off SndySiltstone7 6262 6262 0.795 4978.3 3.33e+06 0.23 2150 0 Off Calcite3 6264 6264 0.883 5531.1 5.07e+06 0.28 3000 0 Off SndySiltstone7 6266 6266 0.795 4981.5 3.33e+06 0.23 2150 0 Off Pyrite3 6268 6268 0.883 5534.6 5.07e+06 0.27 3000 0 Off SndySiltstone7 6273 6273 0.795 4987 3.33e+06 0.23 2150 0 Off Shy vfSS 6275 6275 0.698 4380 3.62e+06 0.26 2050 0 Off Calcite3 6277 6277 0.883 5542.6 5.07e+06 0.28 3000 0 Off Shy v1SS 6279 6279 0.698 4382.7 3.62e+06 0.26 2050 0 Off Coalorhole5 6280 6280 0.972 6104.2 8.7e+05 0.38 3800 0 Off Pyrite3 6283 6283 0.883 5547.9 5.07e+06 0.27 3000 0 Off Calcite3 6285 6285 0.883 5549.7 5.07e+06 0.28 3000 0 Off SndySiltstone7 6289 6289 0.795 4999.8 3.33e+06 0.23 2150 0 Off Pyrite3 6290 6290 0.883 5554.1 5.07e+06 0.27 3000 0 Off Siltstone7 6299 6299 0.817 5146.3 3.33e +06 0.2 2200 0 Off Shy Siltstone6 6301 6301 0.828 5217.2 3.62e+06 0.26 2250 0 Off Calcite3 6304 6304 0.883 5566.4 5.07e+06 0.28 3000 0 Off Shy Siltstone6 6306 6306 0.828 5221.4 3.62e+06 0,26 2250 0 Off Coalorhole5 6309 6309 0.972 6132.3 8.7e+05 0.38 3800 0 Off SndySiltstone7 6320 6320 0.795 5024.4 3.33e+06 0.23 2150 0 Off Shy vfSS 6325 6325 0.698 4414.8 3.62e+06 0.26 2050 0 Off Pyrite3 6327 6327 0.883 5586.7 5.07e+06 0.27 3000 0 Off Shy vfSS 6329 6329 0.698 4417.6 3.62e+06 0.26 2050 0 Off Calcite3 6332 6332 0.883 5591.2 5.07e+06 0.28 3000 0 Off Shy vfSS 6342 6342 0.698 4426.7 3,62e+06 0.26 2050 0 Off Siltstone7 6356 6356 0.817 5192.9 3.33e+06 0.2 2200 0 Off SndySiltstone7 6372 6372 0.795 5065.7 3.33e+06 0.23 2150 0 Off Siltstone7 6380 6380 0.817 5212.5 3.33e+06 0.2 2200 0 Off SndySiltstone7 6388 6388 0.795 5078.5 3.33e+06 0.23 2150 0 Off Shy vfSS 6398 6398 0.698 4465.8 3.62e+06 0.26 2050 0 Off SndySiltstone7 6400 6400 0.795 5088 3.33e+06 0.23 2150 0 Off Coalorhole5 6402 6402 0.972 6222.7 8.7e+05 0.38 3800 0 Off Siltstone7 6407 6407 0.817 5234.5 3.33e+06 0.2 2200 0 Off Shy Siltstone6 6408 6408 0.828 5305.8 3.62e+06 026 2250 0 Off Siltstone7 6411 6411 0.817 5237.8 3.33e+06 0.2 2200 0 Off Shy Siltstone6 6414 6414 0.828 5310.8 3.62e+06 0.26 2250 0 Off Coalorhole5 6416 6416 0.972 6236.4 8.7e+05 0.38 3800 0 Off Siltstone7 6430 6430 0.817 5253.3 3.33e+06 0.2 2200 0 Off Coalorhole5 6433 6433 0.972 6252.9 8.7e+05 0.38 3800 0 Off Pyrite3 6435 6435 0.883 5682.1 5.07e+06 0.27 3000 0 Off Siltstone7 6445 6445 0.795 5123.8 3.33e+06 0.23 2150 0 Off DRILL CUTTINGS DISPOSAL COMPANY Page 20 • 411) Buccaneer Central Injection Site Fracture Model & Study 4.3 MECHANICAL PROPERTIES OUTPUT GRAPH Sti Ci� `:tie YOUn ' s?ladulus Pui ssc'n Rat Tuu}tlui.ss F Mg IlL 2 saw , r ,.‘ ,. ,,p, III C }..). V .01 Of Or DRILL CUTTINGS DISPOSAL COMPANY Page 21 • • Buccaneer Central Injection Site Fracture Model & Study 4.4 INJECTION PRESSURE GRA Injection Pressures were estimated from Easton curve data and from past experience. The pressure values obtained from our model are consistent with the pressure required for formation breakdown. The following graph shows injection pressures developed by our model over ti 8000 Alaska SFI 1 Day Inj BHTP & Surf. Press. 4 o 2.4 7000 _ _ — Si r face PressurpI (pci) + — BIl- Rat#{bluxy- BHTP (psi) i + ;,'urfa. Rate (bpni) 6000 _ — BH i c. (lbm/ga1 0 --- Surfaceit;onc. (Itm : 8l) • r 1 5000 _ ■ _ CIL4 ! I ` y 4 _ 4 4000 ' ! 2.0 0 cn cn I i 1 1.2 0 3000 \ I °? 2000 I 1.0 l Eri 0.6 g I I ! low __ - . + I I j 0 !, l.1 , ,, it i :, I ;, , 1,,,i, II;,, „Ii.,,tii 0.0 0 100 200 300 400 500 600 700 800 9000.0 Time (min) DRILL CUTTINGS DISPOSAL COMPANY Page 22 • • Buccaneer Central Injection Site Fracture Model & Study 4.5 FRACTURE HALF WING MODEL, 50,000 Bbls. 6300 -- Stress Width Profiles 0 20 0 0002 40 0.0004 60 0.0006 6320 80 0.0008 - 90 0 001 95 0.0012 99 0.0014 0.0016 0.0018 6340 _.. 0.002 C.. 6380, , 1 6400 6420 4011) 8000 8000 -0.001 0 0 001 0 100 200 300 400 500 Stress (psi) Width (in.) Length (ft) DRILL CUTTINGS DISPOSAL COMPANY Page 23 • • Buccaneer Central Injection Site Fracture Model & Study 4.6 FRACTURE HALF WING LONG DURATION MODEL, 1,000,000 Bbls. 6280 Stress Width Profiles -- — - V • l, 0 ® 4 0 0 0.0004 610 J 0.0006 _ 80 0.0008 90 0.001 95 0.0012 0.0014 :cry 00016 0.0018 0002 0 0022 6340 6360 6380 8400 - 64 4000 6000 8000 -0 -002 0 0.002 0 500 1003 1500 2000 Stress (psi) Width (in.) Length (ft) DRILL CUTTINGS DISPOSAL COMPANY Page 24 • • Buccaneer Central Injection Site Fracture Model & Study Fracture Propagation Model 111712012 Run 4 .$ /tJ 16936 MAO* Perfe6320' -6370' ND Drill Cuttings/ Waste Rheology4A Pump Sch. 2, see schedule Fracture Half Wag BUCCANEER SFI DISPOSAL FACILITY CUTTING ISPOSAL SPECIALIST I DRILL CUTTINGS DISPOSAL COMPANY Page 25 • Buccaneer Central Injection Site Fracture Model & Study 5.0: GEOLOGIC DISCUSSION The limited subsurface engineering review performed by the DCDC engineering team has indicated that we know of no anomalies within the injection horizons which could adversely affect the success of this cuttings reinjeciton project. The sum of the geological review indicates that the physical down hole organization contains traits typical of other successful cuttings reinjection project's in the Cooks Inlet Area. All geologic information provided by Buccaneer, indicates that no significant faulting exists in the disposal affected formations, which could allow slurry to penetrate another well or reach vertically higher than preducted. Containment of the disposal plume can be assured due to the fact that no faulting exists to present a pathway through the slurry containment formations. The clay /siltstone /sandy formations are massive enough to contain the planned slurry quantities of properly prepared and injected slurries. Considering the uniformity of the formations that will contain the disposal plume, DCDC'S current experience indicates that the fractures created during cuttings reinjection will travel outward with a trend upwards and downwards depending upon the actual formation properties, well within normal operating parameters. In DCDC's disposal operations, one fracture has been proven not to occur. As the disposal plume propagates into the formation away from the well bore with the fine spread of particle sizes generated by DCDC'S slurry unit, enhancing the leak off characteristic of the slurry, the slurry wall cake will hold open the fracture until the fracture tip hydraulic force fmally diminishes to a point where the liquids leave faster than the injection rate leaving the solids in place and the fracture sealing itself. Once this occurs, a new fracture plane is created. The result is a wagon wheel affect, looking straight down the well bore. The majority of the slurry is placed in an elliptical pattern; with the major slurry deviation from the well bore initiating perpendicular to the weakest plane. The majority of slurry particle sizes being less than 10 micron will create a wall cake, allowing for slurry entrapment and movement of the cuttings away from the well bore, resulting in slow leak off. From a geological standpoint, considering the review from the data supplied by Buccaneer, all indications lead to the conclusion that a successful cutting reinjection program can be instituted with fully controlled disposal plume containment. The large dirty sandy formation at 5000 feet, is a significant barrier to upward slurry growth, if the slurry would reach that high in actual injection disposal. If the slurry were to reach this depth, the finely ground slurries produced by DCDC would disperse into these sands and could not penetrate any higher. DRILL CUTTINGS DISPOSAL COMPANY Page 26 • Buccaneer Central Injection Site Fracture Model & Study 6.0 SUMMARY AND CONCLUSIONS: DCDC has performed Cuttings Reinjection successfully in many parts of the world. The reasons for our success are common. The reasons for Cuttings Reinjection failures are exactly the opposite. DCDC Methodology used successfully for over 30 years was utilized in this review. Fracture modelling was performed based upon data supplied by Buccaneer and upon data, which DCDC has experienced, on other projects in the Cooks Inlet, Alaska area. Due to the nature of the subsurface formations, it is indicated that the massive claystone /siltstone /sandy formations will contain the slurry adequately. The subsurface formations are massive in nature and are more than adequate to contain the relatively small quantities of slurry. Real time data adjusts the forecasted injection models, which were developed to determine the feasibility of cuttings injection, because the formations react over time in a different way than when they are first minimally fractured. DCDC will continue to monitor the progress of this operation, as in all of our CRI operations, to maintain injectivity. In conclusion, DCDC's engineering team has found no reason to suspect that our CRI program would not be successful utilizing this well. DRILL CUTTINGS DISPOSAL COMPANY Page 27 • Buccaneer Central Injection Site Fracture Model & Study 7.0 RECOMMENDATIONS: 1. Review additional formation information, such as, further formation strength data, offset leak off data, etc., as data becomes available and compare to this study. 2. Continue to collect data in the future that further supports CRI engineering, such as, mini fracture tests run once the injection well has been perforated. 3. Continue keeping regulators in the communicative loop. 4. Set up new drill wells for Injector Candidates, if feasible. 5. Review shallower injection zones, if practical. 6. Insure that the disposal well is properly cemented for formation seal integrity. 7. Insure that the disposal well has sufficient rat hole. 8. Setup a central injection facility to with capacities to correspond with Buccaneers future drilling plans. DCDC have ample experience in designing and setting up these types of facilities. DRILL CUTTINGS DISPOSAL COMPANY Page 28 • • Buccaneer Central Injection Site Fracture Model & Study Disclaimer Notice: This information is presented in good faith, but no warranty is given by and DCDC assumes no liability for advice or recommendations made concerning results to be obtained from the use of any product or service. The results given are estimates based on calculations produced by a computer model including various assumptions on the well, reservoir and treatment The results depend on input data provided by Buccaneer and estimate as to unknown data and can be no more accurate than the model, the assumptions and such input data. The information presented is DCDC's best estimate of the actual results that may be achieved and should be used for comparison purposes rather than absolute values. The quality of input data and hence results, may be improved through the use of certain tests and procedures which DCDC can assist in selecting. Buccaneer has superior knowledge of the well, the reservoir, the field and conditions affecting them. If Buccaneer is aware of any conditions whereby a neighbouring well or wells might be affected by the treatment proposed herein, it is Buccaneer's responsibility to notify the owner or owners of the well or wells accordingly. DRILL CUTTINGS DISPOSAL COMPANY Page 29 • Buccaneer Central Injection Site Fracture Model & Study 8.0 DCDC ATTACHMENTS DRILL CUTTINGS DISPOSAL COMPANY Page 30 I SLASHING COST CUTTINGS DISPOSAL :,01, ►� ' 1000m of 12 _ Hole = 20 skips of clean dry cuttings ROBOT LIILI,,, - :.. - ONE Robot does all - CRI, Skips, Bulk, Dryer � CRI since '85 Bad Weather Doesn't Matter 11 Units still working in N. Sea (sold 02) GOALS: Millions of Bbls Disposed Worldwide ill No Hands, 0 Risk/Cost To Haul and Dispose & On Every Continent and for all Majors Recover Good Mud New: A "C Replaces Bulk Shipment Subs urface Cont rol Audits ssured Disposal and Engineering Faster Drill Rate 150m/hr Drill Floor Smaller Footprint �+�'' ✓ �r _ r••••. _ . it 07:1111r...---.....) ' Cuttings Dryer Pioneer Rig Shakers See our New Patent Technology 440 1116, ,00000 Injecting & Drying since Mud Companies did mud only and before Swaco, Brandt, etc. --- had linear motion shale shakers ' CUTTINGS DISPOSAL ROBOTS M , s 111 Il -- I • < -c lir � - r 2%OiI on Cuttings (note:one line under cuttings boxes) ,!� • • Originally '(� j • January 2008 issue, pgs 69 -70. DRILLING appreared in: �' 1' 011 Posted with permission. Why cuttings reinjection doesn't work everywhere Or does it? Although there have been failures in some areas, new techniques and equipment have been established over the years that would make reinjection feasible in those areas. Jeff Reddoch, Drill Cuttings Disposal Co., Houston Cuttings reinjection is conceptually Cuttings reinjection is simply the low- Most operators, in appropriate situa- simple, as seen in Fig. 1. With many est cost, easiest course of action for most Lions, would choose CRI if it could be years of focusing, designing and oper- drilling operations. I have documented done with minimal trouble and not slow sting Cuttings Reinjection (CRI) proj- costs of CRI operations in the expensive or shut down the drilling operation. As ects all over the world, in all types and North Sea environment, as low as $5 /bbl. in all other drilling operations, where depths of formations, the reason why CRI gets less expensive as the knowledge you get your advice and who you choose CRI sometimes didn't work for others and experience of your CRI service pro- is critical. Some considerations are: was, frankly, simple and obvious. The vider grows. • Use a qualified, experienced service company I founded, Apollo (now part of Alternatives, such as bulk shipping or company Baker Hughes), was successful at inject- skip /ship, thermally /chemically treating • Engineer the subsurface disposal ing drill cuttings everywhere it was given and ultimate storing cuttings for eternity, system with experience and judgment the opportunity to do so, and in over are significantly more problematic and ex- • Understand the formation change 90% of the CRI case histories, we had pensive. In some situations, where the op- to slurry placement over time only one disposal conduit to work with erator believed that CRI was not the right • Plan the project from subsurface to and /or had to drill future wells within choice, the operator chose to use a high- surface equipment, preparing for all con - 50 ft of where we had injected drill cut- price, synthetic mud and dry the cuttings tingencies tings slurries. Many of the CRI projects to meet environmental guidelines. Most if • Expect failure if the plan is not fol- with which I was involved were the first not all disposal techniques other than CRI lowed. ever attempted in that part of the world, store the cuttings /waste in the environ- even in countries that had either no pre- ment and are still a liability for the opera- SUBSURFACE EXPERIENCE vious offset well information to derive tor. Thus, the spending still hasn't ended, physical /rheological properties. it just has been postponed. CRI, of course, So why did CRI, to my knowledge, On projects that I took over or ana- not only permanently disposes of cuttings, work on every job that I was associated lyzed for operators, I was able to get the but also allows the mud and location to be with, even in cases where experts advised cuttings injected successfully or able to run cleaner, because there is no underlying against it? I believe success begins with a point out "what not to do" in the future. force to minimize waste streams. good foundation, and with CRI, a good Subsequently, the operator foundation begins with under- achieved significant savings standing how the subsurface over other waste disposal so- from s dit osa formation will react to cuttings P bulk transferor skips lutions. Fortunately, the CRI Shaker unit Triplex pump injection, not just at first, but vacuum all the way through the prof success stories far outweigh dump + Ili 1! �' the failures. Mill I ect. It goes without saying that, 1 ®� i .l: ■ ! � as drill cuttings into the operator was advised by I have heard cases where I f_ you in j ect dri cuttin g Wellhead the formation, the formation others that CRI was not suit- Tank # Tank #2 I :� _ will change. As the formation able for the location or that the 1,1 �s_,,.,, !�I changes, how and what you formation filled up. This state- hi - continue to inject is crucial. tam '• ®'�� i q ment shows a complete lack of l For instance, if you are inject- Electric CSP ing into a sand, you fill the • understanding of subsurface motor grinder g , as Y strata. Formations do not fill l II sand pores with hydrated clay up! From my experience being O Drill cuttings 1 1 - from the cuttings slurry, you I 1 U nprocessed slurry Inject into r 1 now have a hydrated clay /sand able to inject anywhere in the formation �;-- world in many different types I !Screened slurry fo rmation. and depths of formations, even In "less than simple" CRI in impermeable rock, I do not projects, the new formation believe there is a drilling loca- Fig. 1. Basic setup and flow for drill cuttings reinjection. reacts differently than when tion that is unsuitable for CRI. CRI operations began. If the JANUARY 2008 World Oil DRILLING • 0 become concerned Drill Cut s Execution: install/interface about the feasibil- Operations Quality assurance ity of injecting cut - Health and safety rings in some areas. D i sposal Co. Execution Job planning: Rig When a CRI project Surface equipment Personnel runs afoul, it is dif- Job planning Logistics ficult for operators, Customs who manage the en- Design disposal well: Injection formation tire actually drilling d e Agenc Ava Disposal l method: Annular to fully understand Design disposal well Injection wet, old production what ll y went well, etc. ) Permit requirement wrong. Separating what didn't work Fig. 2. Elements of a well- designed cuttings reinjection job. from what did work CDilt I Dry, Vac is critical in design - U V service company does not change how/ ing future CRI operations. Anywhere what they are injecting, then the forma- Consequently, there still are areas that tion either plugs up, fills up (as some call operators do not inject and have instead 20 + years Exp. it), or breaches to the surface. Inciden- used amazing, problematic, expensive so- tally, I have not heard of anyone plug- lutions to get the cuttings off the rig and ging a formation at the beginning of a to a storage /treatment facility. New tech - CRI project. niques and equipme have been estab- The injection formation is the place to lished that would make these areas feasible Subsurface Modeling start when planning a CRI project. As in for injection. To reduce cost and simplify With 600 plus Project building a drilling rig, every other part, operations, operators will likely look more while important, is useless without agood to CRI as the lowest -cost fluids and waste Worldwide Data base foundation. Analyzing the subsurface de- management solution as time goes on. sign is only one of the many difficulties WO CRI planners face. Other challenges in- clude designing the disposal conduit and deciding what type of unit to install on THE AUTHOR 100's of Satisfied the drilling rig or platform, how to get Jeff Reddoch is former owner and founder of the necessary utilities, where to put the Apollo Services. Before its sale to Baker Hughes, Customers, Majors CRI unit, how to get the cuttings to the Apoll was the wo rld leader in CRI services and the largest indepe ndent company for cuttings And Independents CRI unit, who to manage and run the skip /ship, vacuuming, drying and injection. Mr. CRI operation (you certainly don't want Reddoch is a registered mechanical engineer. your most talented personnel running a He earned a BSc degree from the University of simple operation that would bore them Louisiana at Lafayette. He has over 30 years of domestic and international drilling and waste to tears), what slurry properties to use, management experience. As chief engineer Many First's and what the injection program should be, of a prominent drilling contractor, his responsi- t working with the operators management bilities were to design, build and operate drill- Records Achieved ing rigs, some of which required zero - discharge team, etc., Fig. 2. modifications and cuttings - handling /processing Inadequately meeting just one of these equipment. With over 15 patents, three SPE challenges will result, and has resulted, papers and several new patents pending, Mr. in slowing or shutting down rigs, plug - Reddoch duce many operators and r ging formations and caus operators to regulators around de world, Past 01h ner, Mgr, Founder Apollo Services, CRI P Over 40 projects Ongoing Worldwide when sold, from North Sea To Australia jeffre @cox.net www .thedrillcuttingsdisposnlco.com Article copyright © 2008 by Gulf Publishing Company. All rights reserved. Printed in U.S.A. Not to be oistributed in electronic or printed form, or posted on a website, without express written permission of copyright holder. • • Management Team of Drill Cuttings Disposal Company, LLC Experience of Cuttings Grinding and Injection Units Partial List Manufactured " IN HOUSE" Date Operator Yard Built Worked Type Status 1988 Chevron USA Apollo USA Land became rental unit 1988 Shell USA Apollo USA Jack Up became rental unit 1989 ChevronUnocal USA Apollo USA Jack Up became rental unit 1994 Chevron Unocal USA Apollo Thailand Platform returned to Singapore 1996 Chevron Unocal USA Apollo Thailand Platform returned to Singapore= 1990 Pemex USA Apollo Mexico Jack Up after 2 years, returned to USA 1990 Pemex USA Apollo Mexico Jack Up after 2 years, returned to USA 1993 British Gas USA Apollo Tunisia Jack Up after 3 years, returned to USA 1993 Enron India USA Apollo India Jack Up after 4 years, ret. to Singapore 1994 Enron India USA Apollo India Jack Up after 4 years, ret. to Singapore 1995 shell Brent Bravo UK A&13 North Sea Platform ongoing 1997 Shell Auck UK Apollo North Sea Platform ongoing 1998 Shell Cormorant UK Apollo North Sea Platform ongoing 1999 Shell Sakhalin USA Apollo Russia offst Platform ongoing 1995 BP Andrew USA Apollo North Sea Platform ongoing 1997 BP Wytch Farm, UK Apollo UK land Platform 3 years UK ental unit 1998 fW Venezuela USA Apollo Venezuela [large 4 year- Venezuela rental 1998 Exxon Mobil Jade USA Apollo Equitorial G Platform returned to USA as rental unit 1997 Exxon Flower Gardens t USA Apollo USA GOM Platform returned to USA as rental unit 1998 Exxon Hondo USA Apollo USA pacific platform ongoing 1998 Exxon Harmoney USA Apollo USA pacific platform ongoing 1998 Exxon Heritage USA Apollo USA pacific platform ongoing 2001 Exxon Chad USA Apollo Chad land central site ongoing 2000 Exxon Sakhalin USA Apollo Russia offst jack up ongoing 1998 Encana USA Apollo NorthAtlantjack up returned to USA as rental unit 1998 Phillips USA Apollo Alaska Platform after 3 years, returned to USA 1998 Kerr McGee Nirri<ara Cen UK Apollo North Sea Platform ongoing 1998 Kerr McGee Ninlan Sou UK Apollo North Sea Platform ongoing 1999 Total Dunbar UK Apollo North Sea Platform ongoing 1999 Total Alwyn UK Apollo North Sea Platform ongoing 2001 Talisman Claymore UK Apollo North Sea Platform returned to UK as rental unit 2001 Talisman Fulmar UK Apollo North Sea Platform returned to UK as rental unit 2001 Talisman Clyde UK Apollo North Sea Platform ongoing 2008 Encana USA DCDC USA land Land 2008 Encana USA DCDC USA land Land 2008 Encana USA DCDC USA land Land 2009 Samson USA DCDC USA land Land 2009 Premier Environmental USA DCDC USA land Land ongoing Note Cents alized SFI facility for oily production and drilling waste, noted in "red" Units constructed by DCDC Management /key personnel for long term contracts became rental units after the contract finished • • Eigi LE CUTTINGS RE- INJECTION (PARTIAL CASE HISTORY UST) I • =rator Location Rig Type Land/ Maximum Volume Comments 1 ! Offshore Hole Sire Injected ;British gas Miskar Field Jack Up 0 12 -1/4" 10,409 'British gas Miskar Field Jack Up 0 12 -1/4" 8,940 British gas Miskar Field Jack Up 0 12 -1/4" 9,478 British gas Miskar Field Jack Up 0 12 -1/4" 18,773 ;British gas Miskar Field Jack Up 0 12 -1/4" 11,022 British gas Miskar Field Jack Up 0 12 -1/4" 14,960 British gas Miskar Field Jack Up 0 12 -1/4" 9,277 British gas Miskar Field Jack Up 0 12 -1/4" 10,435 British gas Miskar Field Jack Up 0 12 -1/4" 12,973 British gas Miskar Field Jack Up 0 12 -1/4" 11,752 British gas Miskar Field Jack Up 0 12 -1/4° 11,936 British gas Miskar Field Jack Up 0 12 -1/4" 12,279 British gas Miskar Field Jack Up 0 12 -1/4" 10,422 Hunt Oil Cameron Parish, La Land 1 PIT 56,250 Hunt Oil Cameron Parish, La Land L PIT 44,129 Hunt Oil Acadia Parish, La Land L PIT 42,777 Hunt OR Cameron Parish, La Land L PIT 31,258 • US.A. Zapata, Tx. Land L PIT 39,360 • U.S.A. EI, Camp, Tx. Land Rig L 8-1/2" 9,880 • hell Oil Engene Isle #158 Semi 0 12 -1/4" 12,200 Hunt Oil Vermillion Parish, La Land L PIT 39,843 Hunt 011 Vermillion Parish, Pa Land L PIT 67,532 Hunt 011 Fort Stockton, Texas Land L PIT 118,580 Kelly 011 Terrebonne Parish, La Land L 171/2" 85,923 i hell 011 Eugene Isle #188 Jack Up 0 12 -1/4" 11,427 Unocal Ship Shoal 253 Jack Up 0 12 -1/4" 18,154 r ilkHa West Cam #53 Jack Up 0 12 -1/4" 11,086 'rco W.C. 201 Jack Up 0 8-1/2" 10,196 merada Hess Keene, N.C. Land L PIT 48,452 PEI -Sonat Mexico Jack Up 0 12 -1/4" 9,539 I I PEI -Sonat Mexico Jack Up 0 12 -1/4" 8,673 , PEI -Sonat Mexico Jack Up 0 12 -1/4" 9,128 I PEI -Sonat Mexico ladle Up 0 12 -1/4" 7,978 1PEI -Sonat Mexico Jack Up 0 12 -1/4" 8,317 PEI- Quintana King Ridge Field 211-19 Barge 12 -1/4" 23,773 PEI South Gueydun, La Falcon 48 L 12 -1/4" 18,462 11 Unocal- Thailand Guff of Thailand Platform 0 Mercury 4,880 eagull West Baton Rouge Land L PIT 38,976 Shell Vermillion 200 C. Discovery 0 8 -1/2" 12,860 j hell Eugene Is. 188 C. Discovery 0 8 -1/2" 17,908 ;Shell Eugene Is. 331 Jack Up 0 12 -1/4" 16,518 Unocal SS 253 Jack Up 0 8-1/2" 7,500 Unocal SS 253 Jack Up 0 8-1/2" 9,263 hevron S.T. 176-D Platform 0 8 -1/2" 13,639 afters Matagory Is. 565 Jack Up 0 12 -1/4" 11,348 alters Matagory Is. 545 Jack Up 0 12 -1/4" 10,832 1 alters M.I. Jack Up 0 12 -1/4" 12,463 Murphy SS. #93 Jack Up 0 NORM 674 Murphy S.S. #117 Jack Up 0 NORM 1,187 N Exp East Baton Rouge Land L NORM 685 I tone Lockport, LA Land L NORM 5,245 Hunt West Texas Land L PIT 12,765 Hunt Cassinade Field Land L PIT 154,083 Kerr McGee Ship Shoal 218 Tom Jobe 0 12 -1/4" 28,913 'Kerr McGee Shop Shoal 239 Tom Jobe 0 12 -1/4" 25,679 ill • RCM Egli CUTTINGS RE- INJECTION (PARTIAL CASE HISTORY UST) 6 • Location Rig Type Land/ Maximum Volume Comments- ' Offshore Hole Size Injected Houston Exp. Brazos Marine 301 0 12 -1/4" 11,326 1 RT Des Almonds N/A L NORM 450 I WRT Des Almonds N/A L NORM 326 (Delmar East Texas PIT L PIT 21,458 I D !mar Main Pass 259 Nabors 78 0 12 -1/4" 32,436 Delmar Main Pass 259 Nabors 78 0 12 -1/4" 24,925 ;Delmar East Texas PIT L PIT 21,854 1 hell Eugene Is. 158 Adriatic III 0 8 -1/2" 22,773 I. hell Eugene 15. 259C Adriatic III 0 8 -1/2" 36,588 hevron Grand Isle 85 Platform 0 NORM 873 hevron Grand Isle 85 Platform 0 NORM 456 hevron Grand Isle 85 Platform 0 NORM 763 hevron Grand Isle 85 Platform 0 NORM 559 onoco Grande Isle Platform 0 NORM 23,239 onoco E.C. 56 Ocean Titan 0 8-1/2" 21,842 .P. Operating Wilcox Field Land L 28,320 orcen Exp. E1 F# 162 Enterprise 0 8 -1/2" 17,595 OHO Palestine, La Land L PIT 12,486 reat Western Edgar, La Diamond 829 L PIT 18,476 Unocal S.M.I. #49 High Is. 2 0 8 -1/2" 21,426 Unocal Verm. #38 High Is. 4 0 8 -1/2" 17,822 Forest 011 Vermillion, Blk, 255 Jackup 0 8 -1/2" 5,693 hevron, USA Holly Beach Land 0 12 -1/4" 13,639 j Basin Exploration Eugene island Blk #65 Jackup 0 13 3/8" 12,240 . hell Main Pass BIk # 239 Jackup 0 13 3/8" 8,879 • hell UK Brent'B' N /Sea Platform 0 12 -1/4" 10,910 • hell UK Brent 'B' N /Sea Platform 0 12 -1/4" 9,155 hell UK Brent 'B' N/Sea Platform 0 6" 4,423 . hell UK Brent '8' N /Sea Platform 0 12 -1/4" 18,972 • hell UK Brent 'B' N /Sea Platform 0 12 -1/4" 7,594 hell UK Brent 'B' N/Sea Platform 0 12 -1/4" 8,499 British Pet. BP Andrew B.PAndrew N /Sea Platform 0 16" 34,525 British Pet. BP Andrew B.P.Andrew N /Sea Platform 0 16" 265 c ritlsh Pet. BP Andrew B.PAndrew N /Sea Platform 0 16" 43,641 [British Pet. BP Andrew B.PAndrew N/Sea Platform 0 16" 26,165 I British Pet. BP Andrew North Sea Platform 1 16" 8,908 I British Pet. Venezuela BARGE 0 N/a 60,000 British Pet. Wytch Farm Wytch Farm Land rig 0 BULK 156,700 Exxon Hetlage Platform 12 -1/4" 79,450 Exxon Harmony Platform 12 -1/4" 64,642 otal Dunbar North Sea Platform 12 -1/4" 74,560 otal Alwyn North Sea Platform 12 -1/4" 28,902 alisman Clyde North Sea Platform 16" 59,123 Exxon Sakhalin Island Russia Jack -up 17 -1/2" 21,010 1 I alisman Fulmer North Sea Platform 12 -1/4" 21,532 Kerr McGee Ninian Central North Sea Platform 12 -1/4" 16,300 Kerr McGee Ninian N h South North Sea Platform 12 -1/4" 14,780 hell Cormorant A North Sea Platform 12/1/4" 33,235 hell Auk A North Sea Platform 171/2 " 29,373 alisman Claymore Norht Sea Platform 121/4" 8,178 • • STRATEGY UTILIZING PASSIVE SEISMIC MONITORING TO MAXIMIZE DISPOSAL SAFELY Fracture Measurement Real Time --- `'`,,. / r - . --""" a Q 7 - o—. ,y ' \ a O • O f /" Q Q /„,- Plan View (Is ' 1 S + 1 O p D ` iI/ 4 p 0 D D Plan View P8 ssive Sakmic Budd Array a 6 ° o 4 D D 0 ° p -- 66 s c Cr, D - 4 a ° o D a D a a 90 ° 0 D ° 3 0 a Cross Section View ■ , JO li EC • 16LIIIIP Cur irvu D1sPOSAr SPGCIAlrs7 • Bottom Hole Pressure Gauge and Running Equipment Side Pocket Mandrel Gauge Carrier DESCRIPTION /APPLICATION: The Side Pocket Mandrel Gauge Carrier, threaded with same threads as the tubing string, makes up in the tubing string, generally just above the packet. FEATURES /BENEFITS: f Convenient two piece design makes the installation of the carrier to the production string simple and fast, reducing rig time f Portable for sensing either tubing (internal) or annulus (external) pressure f Available in any material and desired tubing threads f Available in any regular size, from 2 -3/8" to 7" f Full open ID, maximizing flow area f Shaped to protect the gauge while running it into or pulling it out of the hole f By -pass for additional upcoming lines such as ESP power cable, injection lines, etc The gauge carrier provides both a mechanical and hydraulic interface between the pressure gauge and completion string. The carrier is threaded to suit customer requirements. Ample clearance is designed into the offset sidemount body which prevents gauge contact with the casing wall. The sidemount body is manufacture is from a one piece steel bar - no welded parts, where material selection and manufacturing process are per the guidelines laid down in API 5CT and NACE MR 01 -75. As a minimum, the carrier will match the mechanical properties of the production tubing. Hydraulic connection from the gauge to the tubing is made through the ported sidemount body. BOT gauges are designed with metal to metal seals at the instrument to carrier interface. No elastomers are used in the construction of this pressure barrier. Components are designed to allow an efficient assembly of the gauge to the carrier requiring very little rig time. The interface connection relies on a conical Autoclave metal sealing arrangement which can be redressed for multiple usage. For grade L80 Carbon Steel typically AISI 4130 is used giving the following properties: DRILL CUTTINGS DISPOSAL COMPANY Page 1 • Downhole Instrument Cable Tubular Encased Conductor (TEC) Wire is designed as a rugged cable for permanent gauge systems or other downhole applications where long -term reliability is required. The outer metal jacket serves as a mechanical protector for the conductor as well as a dependable electrical ground, centering the conductor functions as an effective shield to electrical and electromagnetic noise. Center -Y TEC is available in 316L SS, nickel alloy 825 and other corrosion - resistant materials in accordance with NACE MR- 01 -75. An optional outer encapsulation of Santoprene ® or other material to increase abrasion resistance is available. Instrument cable is used to power the permanent downhole instruments from surface, while at the same time, transmitting data back to surface. These cables are available in various different materials, configurations and dimensions, although the standard package comprises of 0.25" (6.35mm) diameter steel tube, inside which is a mono- conductor insulated with a Teflon sleeve. The annular space between the tube and Teflon insulator is filled with a proprietary filler medium, supporting the mono - conductor along the entire length of the cable. This cable can be manufactured in splice -free lengths of up to 34,000 ft (12,000 m), making it ideal for use in horizontal or extended reach wells. A custom designed encapsulation is applied to the outside of the tube providing the cable with increased crush, abrasion and erosion resistance. Technical Data Sheet: 0 I. Tube (28011) 2. C' ore (26117) Material Ci ulvanizcd Carbon Steel Conductor Solid Copper. Outer Diameter 0.15" 16 AWCi. Wall 1 hikl.ness 0.035" - 5 5 ;10001i Insulation 0.102" 00 [PC I05"C max. 500 volts max Outer t.xtrusiun I It)l'L Nominal OD 0.174 121 ''C 1 kai Softening Lrmp DRILL CUTTINGS DISPOSAL COMPANY Page 2 ! ! Cable Splices Splices serve two functions in the wellbore, one as a needed termination device the second as a repair. In the first condition some applications require that the TEC and control lines must be cut to pass through or terminate into a device in the well such as a packer this would be an application for a splice. The second condition is that there must be a contingency to cover accidental damage to cables while running the completion. Preference has been to avoid NPT threads and use a compression fitting where the seal cone is machined integral to the splice body. Cable Splice The cable is physically connected with a crimp thus avoiding the use of soldering irons on the rig floor and reducing the make up time while increasing reliability with precision crimp pliers and avoiding dry solder joints. Post crimping pressure sensitive tape is applied; this acts as secondary sealing to the metal tube seals. Primary sealing is dual metal /metal with a compression fitting, along with dual elastic backup seals, material selection is to match the TEC cable. Mechanical Properties Typical Working Pressure 10,000 psi Collapse Pressure _ >24,000 psi Burst Pressure >16,000 psi Temperature Rating 150° C (302° F) 0 43 ocoaa.v.40.40440041.mwow.004-140s, DRILL CUTTINGS DISPOSAL COMPANY Page 3 • Cable Protectors General Description Standard universal protectors are installed on each production tubing joint coupling and /or integral joint connection to prevent damage to Tubing Encapsulated Conductor (TEC) cables, control- A line tubing, and chemical injection capillary tubing. The standard protectors are manufactured from mild carbon steel, and applied with hydraulic installation tools to achieve a secure compression -fit it .1 l4 over each tool joint connection. The protective channel between the gripping elements is designed to enclose & protect the TEC and /or control -line tubing as it is deployed during the well completion. The protector also provides resistance to rotational and longitudinal movement. The standard Universal protectors are easily assembled on the production tubing tool joints using a tapered pin. The locking I collars contain a unique compressive indent that ensures uniform make up for all collar sizes. The protectors are a reusable asset in the event the control -line bundles are retrieved during remedial intervention. The installation tools for the Universal protectors are easily maneuverable on the rig floor, light - weight, reliable and effective. The protector channel and locking collars are produced from heavy -duty 11 gauge mild carbon steel hot- rolled, pickled and oiled sheet carbon steel that which meets ASTM -A- ± 569/570 specifications. The tapered pins are produced from 1040 -1045, 11 gauge mild carbon steel hot rolled, pickled and oiled which meets ASTM -A -568 specifications. After forming, the protector I .. i is heat treated and quenched to a Rockwell C hardness of RC 16 -22. The hinge pin is produced from 1008 mild carbon steel material, .245" +/- .0015" diameter, cold- heading quality, carbon steel wire, which meets ASTM -A- 545 -82 specifications. Attributes Length: -25.25" Running OD: Connection type & size dependent Weight: -6.5 lbs. ea Channel/ Locking Collars Material : 11 gauge low carbon steel specified to ASTM -A- 569/570 Tapered Pin Material: (1040 - 1045) 11 gauge carbon steel specified to ASTM -A -568 Hinge Pin Material: 1008 carbon steel specified to ASTM -A- 545 -82 Available materials 316L Stainless Steel. Monet 400, Alloy 825 Make Up : 2500psi to 3500psi DRILL CUTTINGS DISPOSAL COMPANY Page 4 • 0 ow BAP SEMEN CALCULATED RUNNING 00. NO CABxO 01F1 �� 1 - Q433 0.0. QJOMSLATEO 7lRE ' IVO PROOVCiION TIBNO (0.1 � *31r COIIN:C70N 0.0 �� ' 4.0r CALCULATED RUNNING OD. 6.7110 0.05110 Dan e `� Mtitil:A1NI.Y P! \: 35011-A-06 , 7. 526• CASINO PR000Cf10N MONO 10 0380E 7 Bar �� sago PPE fiYSNO wm+ A SAW �o. AFA A 6.760 DIET 1 PRO ECIOp B 'NWOLED ON 3.000% � j PH-6 PROWIMA MONO WM A 4.313' f ; ill I 0.0. CONNECTION �� 1) / + mM 3433 0.0. ENCAPSUUTFA TUBE \ V\44444. � I � GGNAWED NED RUNNMONO OA.: BN' c \ / N ED MO NO CLEARANCE: .: e /, I 1.57 TB DOT "'�• -- UNT MONT: 000 IDS '''s. ISTCNIMINdilkk" • I DCDC Nib' WZ — END VIEW Of ache aNIRN su R 1rAlAA1E 3500 -A -06 mar GAP arniteu IMMO C1.0. dO =NO D / B j BO T -1626 J A NaIen•• IIIRAIM N Ow i dH graft I • et.. 1 . E 133s 01/3011* w •_PNt� wR.en eeera w.we q r r MY YM1nYnb — Y�ysn same• — 11 OM.. IM YAn Yom. iii�l�n6 �� O M _.. p� in r g r 01.00 balm 1.11 e DRILL CUTTINGS DISPOSAL COMPANY ! • ■ �r p : o , , ( ..■ I. A ti••/ oaml I (2u) 01 �"',;"""' CANNON SERVICES. LTD. M aw.ar. Ar• In Who P.O. OM I31a PH: (251) 4141-2110 A .aar .•r".. 2TA1s01o, mIA9 77497 420* (491) +88-6117 Mawr •c SIDE NEW OF QTY PART NUMBER DESCRIPTION MATERIAL SPECIFlCADON /MM... 3500 — 2 11000 -03 3.500 LEFT COLLAR AST I —A -1011 wow r en 2 11010 -03 3.500' RICHT COLLAR ASTM —A -1011 a.v 9 I B T -1627 A 1 11004 O.430" X 20a CHANNEL A5111 M• I ems 1 r ri. 2 r I Iry 09/30/18 • 4 11009 HINGE PIN A 6111— A — s r • rsr. r r "r r..r i�sr me 11/ .rr . r mu:~ 2 11001 TAPER PIN AM—A- 566 /569 rr. . 0 ....4 r r rr r arm aaaa .... �v.r or �7.. WOW wT•rrrq_25 • ar M. W we el a..2. DRILL CUTTINGS DISPOSAL COMPANY • S Buccaneer Central Injection Site Fracture Model & Study 9.0 BUCCANEER WELL ATTACHMENTS DRILL CUTTINGS DISPOSAL COMPANY Page 31 • Permit #: 211 -097 Kenai Loop #3 API #: 50- 133 - 20597 -00 -0 Pad 1 Prop, Des: MHT 9300070 3394' FSL, 1134' FWL KB elevation: 92.5' (21' AGL EltAit■ S33 T6N R11 W S.M. Lo Lonnt gitu tude: 1 Spud:, 9/1/2011 BL - IIC A S E E A TD: 9/26/2011 Rig Released: Structural Pipe 1 16" X-56 84 ppf Top Bottom MD Surf 120' 1400 sxs Type I Cement + 0.05% bwoc Static TVD Surf 120' ol Free + 0.6% bwoc CD -32 + 1 gals/100 sx FP -6L + 15% bwoc LW -5E, 100# Carton + 20% bwoc Surface Casing MPA -1 + 83.8% Fresh Water- yld 2.3, 12.0 pug 10 -314" L -80 45.5ppf Top Bottom MD 0' 3,027' TVD 0' 3,026' Intermediate Casing 7 -5/8" L -80 29,7 ppf Max Inc 28 Top Bottom „fill degrees , 14850' MD Cement Top @ MD TVD 0' 0' 8,330' — 7,969” Cast Iron Bridge ±4548' TVD Plug Liner set © 6400' MD 4 -112" L-80 12.6 ppf Hydril 521 w/ 25 ft of _ ' Perforations 6435' - MD 8,100' Bottom cement on top 6450' MD (6170- TVD 7,631' 11,000" MCC 4---------- 6183' TVD) CAC Perforations 6,950 - r - , Tubing ,LY 6,960' MD (6634 -' I Baker Flex Lok Liner Hanger 2 718" L-80 ppf w/ ZXP Pkr and PBR Top Bottom 6643'TVD) �` 1 MD top @ 8100'MD TVD A ,, . ` ;, -ad: Cast Iron bridge 311 sxs Class G Cement + 10% bwoc BA -90 + plug w/25' 0.05% bwoc Static Free + 2.5% bwoc BA -56 + cement on top set 0.5% bwoc EC -1 + 0.5% bwoc CD -32 + 0.1% bwoc gals/100 sx FP -6L + 1% bwoc Na Perforations ' at 9,750' MD ASA -301 + 1 9 – 9,790' - 9,815' MD ------0 – Metasilicate + 82% FW - yld 1.83, 13.5 ppg packer w/ seatbore / Tail: "X" profile @ 10,045' 241 sxs Class G Cement + 0.05% bwoc Static ( �° MD. "x" plug installed w /sand Free + 0.3% bwoc R -3 + 0.5% bwoc EC -1 + 0.6% Perforations - 10,223' - , / – bwoc FL -83 + 0.3% bwoc CD -32 + 1 gals /100 sx 10,248' MD - FP -6L + 43.7% FW - yld 1.16, 15.8 ppg I packer w /sealbore / "X" profile In "XN" nipple @ 10,300' Perforations - 10,520 MD. "X" plug 10,545' MD insta e• . • • '- packer w/ sealbore @ 678 sxs Class G Cement + 0.05% bwoc Static ' i 10,700' MD Free + 1.2% bwoc BA -56 + 0.4% bwoc R -3 + 3% bwow Potassium Chloride + 0.5% bwoc EC -1 +0.4% Perforations- bwoc CD -32 + 1 gals /100 sx FP-6L + 0.2% bwoc 10,920' - 10,945' 2 -7/8" tubing tall, Na M etasilicate + 43.9% FW- 1,18 yld, 15.8 MD " ,� ' ` "X" nipple and 1 0' Y ppg • ' pup cut @ 10,730.5' MD. Dropped to TM PDT!) Estimated Formation Tops MD TVD 11,388' MD ' MD 11,000' TVD 1 ' TVD Well Name & Number: Kenai Loop #3 Lease: Kenai Loop County or Parish: Kenai Penisula Borough State: Alaska 1 Country:+ USA Perforations (MD): Perf (TVD): Angle r@KOP and Depth: Angle C Ports: Roc WIT Date Completed: RKB: 21' Prepared By: Last Revision Date: A Z: d 1 ll ^ k VIA A '''.1. , j, l r an( c _ i x = Y, �.c., � - t < ?. -c)s:1. , Welltest Permeability vs Log Porosity 9 All GOT (n =156) 10,000.0 — 1 1 y = 0.0306e — ♦ All GOT - ssd n - 15 2 — Pailin, m ( ) = _ 66 r --- R 0.5055 5 Erawan y = 0.00034e f — e Satun R = 0.4761 to Erawan (n =21) 1,000.0 • JFG ' ./IY y = 0.7512e 21.631X � 4 k . c / , Y � : • _ — ' - a Pailin, all ® ♦ �// R2 = 0.4041 l 5° , : — — Erawan o ° • A © �''� �� a :, — — Satun _ 2 / Satun (n =41) g -° 100.0 = ., JFG -- •- --_. �� '� 34.622x .ii = � �% fir y = 0 .PC - 10 as 1 — — Pailin, all R,t� p / , ® R = 0.575 .i — — Pailin, mssd r a> I JFG (n =27) - 9 o_ Pailin: us2, hgr A . ' r ef t 4 a na 10.0 _ . . GOT A A/ . is * y = 0 0256e 37.649x ) - I . ■r R = 0.5426 Tun C . — 1 Pailin: us2,hgr (n =21) Pailin (n =47) y = 0.0094e • 1.0 0 R = 0.3926 y = 0.0074e 8 ci R2= 0.4528 v o — — 0.1 0 s% 10% 15% 20% 25% 30% 35% Log Porosity GOT also includes tests from Trat (9), Moragot (2), W Dara (1), Baanpot (1), Platong (4), Plamuk (2), Pakarang (1) K phi 7/23/1999 • 0 _ Houston, TX ( E. CA Formation Loa MD A (337) 364 -2322 Anchorage, AK COMPANY Buccaneer Alaska Operation Copyright 02(x)3 by Epoch Well Services, Inc. (907) 561 -2465 WELL Kenai Loop #1 LOG INTERVAL CASING DATA ' FIELD Wildcat DEPTHS: 138' TO i REGION Kenai Peninsula 16" AT 138' �! COORDINATES 1888' FNL 1037' FWL DATES: 4/14/2011 TO 10 3/4' AT 3057' Sec 33 TO6N R11 W SI SCALE: 2" = 100' 7 5/8" AT ELEVATION GL: 134' MUD TYPES 4 1/2" AT RT: 155' Gel /Gelex Spud Mud TO 3075' HOLE SIZE I COUNTY, STATE Kenai Borough, Alaska 13 1/2" TO 3075' API INDEX 50 - 133 - 20595 - 00 - 00 3% KCL Flo -Pro TO 9 7/8" TO SPUD DATE April 14, 2011 TO 6 3/4" TO I CONTRACTOR Inlet Drilling TO CO. REP. Larry McCallister Larry Drisk TO RIG/TYPE Glacier No.1 /Land /Double ABBREVIATIONS LOGGING UNIT ML030 NB NEWBIT PV PLASTIC VISCOSITY LC LOST CIRCULATION RRB RERUN BIT YP YIELD POINT CO CIRCULATE OUT GEOLOGISTS John Lundy Craig Silva CB CORE BIT FL FLUID LOSS NR NO RETURNS Ralph Winkelman WOB WEIGHT ON BIT CL PPM CLORIDE ION TG TRIP GAS RPM ROTARY REV /MIN Rm MUD RESISTIVITY SG SURVEY GAS ADD. PERSONS Greg Hammond PP PUMP PRESSURE Rmf FILTRATE RESISTIVITY WG WIPER GAS SPM STROKES /MIN PR POOR RETURNS CG CONNECTION GAS CO. GEOLOGIST Dave Doherty MW MUD WEIGHT LAT LOGGED AFTER TRIP V/S FUNNEL VISCOSITY LAS LOGGED AFTER SURVEY k ---..c. -1 ALTERED ZONE tf CHERT - GLASSY 7' FELSIC SILIC DIKE '" MARL - CALC [.'. SANDSTONE 4* ANDESITE AE1 CHERT - PORCEL 7 .--1 , FOSSIL METAMORPHICS +::I SANDSTONE - TUFFACEOUS r ANHYDRITE El CHERT - TIGER STRIPE gg GABBRO MUDSTONE Ft SERICITIZATION x x BASALT CHERT - UNDIFF GLASSY TUFF OBSIDIAN 11 SERPENTINE BENTONITE CLAY t:''.' GRANITE -i PALEOSOL [ SHALE BIOTITIZATION h _ ; CLAY- MUDSTONE TONE GRANITE WASH ,.. PHOSPHATE 77 SHALE TUFFACEOUS f'ivpt] BRECCIA ' ='a CLYST - TUFFACEOUS Hi GRANODIORITE 1 R 1 PORCELANITE y SHELL FRAGMENTS CALCARENITE ,.17. CHLORITIZATtON 0 GYPSUM PORCELANEOUS CLYST 0 SIDERITE rzY1 CALCAREOUS TUFF COAL ` -, - HALITE ti PYRITE SILICIFICATION Y EN CALCILUTITE GI CONGLOMERATE I HORNBL- QTZ -DIO P.>`> PYROCLASTICSI SILTSTONE ^:•:I CARBONATES 1!.t! CONGL, SAND r, IGNEOUS (ACIDIC) it : QUARTZ DIORITE Vt SILTST- TUFFACEOUS 1'661 CARBONACEOUS MAT L____ '�; CONGL. SANDSTONE : :. IGNEOUS (BASIC) ('t $ I QUARTZ LATITE TUFF '-' CARBONACEOUS SH COQUINA t I INTRUSIVES M QUARTZ MONZONITE VOLCANICLASTICS SEDS M CEMENT CONTAM. j DACITE frri KAOLINITIC RECRYSTALLIZED M 1 RECRYSTALLIZED CALCITE � VOLCANICS M� a CHALK DIATOMITE LIMESTONE y , RHYOLITE CRYSTALLINE TUFF >i DIORITE LRHIC TUFF . SALT it 4 1 CHERT - ARGILL i .. DOLOSTONE j - 1 MARL - DO SAND uccaneer Alaska ---- Operations Kenai L oop #1 I 4/26/2011 do Meth C -1 /00K> PPm MO ROP 0> Depth Lithology Olt <o Ttl Gas 100> e10 Ethn C -2 100K> Remarks it/hr units <10 Prop C -3 100K> Survey Data, Mud Reports, Other Info. 50 Avg WOB 0> <0 Ctgs Gas 100 > <10 Butn C -4 100K> klbs units <10 Pent C -5 100K> — /MINERAL GRAINS; TRACE MICA; OCCASIONAL •:.' :O 11 ). ! INTACT ASHY SANDSTONE /CONGLOMERATE ' FRAGMENTS; MATERIAL APPEARS TO BE PRIM • . ' • ... ;.' :O I ; ` I . AIRILY MATRIX SUPPORTED, LOCALLY HAS ...011 SOME PARTIAL GRAIN SUPPORT; SLIGHTLY • • : ,:011 I CALCAREOUS. . - • • • :' :01111 :!:011/1 CONGLOMERATIC SAND/ TUFFACEOUS SAND - • • • • .0011H STONE/SAND (5060 -5160) = MEDIUM TO MED- • • • • . :O' 1 _ IUM LIGHT GRAY WITH A MARKED BROWNISH — -- -- • • • • 01, , ; — _ SECONDARY HUE; DIS AGGREGATED TO SOFT • • • : OI .1 AND SLIGHTLY FIRM; MODERATELY TO POORLY :01111 SORTE G FRIABLE IN PARE SUB- ROUNDED TO ' .1 SUB-ANGULAR, MODERATELY ROUNDED AND ' COARSE, GRANULE SMALL T P BBL AND SCAT - TERED ANGULAR PEBBLE FRAGMENTS; 50 -60% O I I I TRANSLUCENT WHITE TO CLEAR COLORLESS j .111 11 __ 1 1 AAND DARK LITH , 30% MEDIUM TO LIGHT CS; COMMON DARK GRAY S p : 011 i I TO BLACK CHERT GRAINS; COMMON ORANGE TO BRICK RED JASPER; TRACE YELLOW, GRAY- 41111 I GREEN, GLUE- GRAY,GREEN AND BROWN LITHIC/ :'.1111 MINERAL GRAINS; TRACE MICA; OCCASIONAL • ...0 0 INTACT ASHY SANDSTONE /CONGLOMERATE • • . . . • 0 O 1 i l F NE TO F NE GRAIN MORE ASITY SA SANDSTONE SCE • • ::01111 MATERIAL APPEARS TO BE PRIMARILY MATRIX : :00:1 S • SUPPORTED; LOCALLY DISPLAYS AT LEAST • • • • ';'::001 1_. ._ PARTIAL GRAIN SUPPORT; SLIGHTLY • ...011 CALCAREOUS. • • .:01 , 0011 SAND /SANDSTONE/CONGLOMERATIC SAND/ • •';,':':0,,,,,, CONGLOMERATE/TUFFACEOUS SANDSTONE • • ''' 0 0111111 »OP DRILL I( 5160 ' - 5400') = PRIMARY OLIVE GRAY WITH y WITH NON -COLOR SATURATED MEDIUM GRAY TO :$ :': 0 0 SURVEY @ 5184' MEDIUM DARK GRAY AS STRONG SECONDARY O 01:1 :;•:00:::I_ 1 INC 0.61, P 47 — HUES; COMMON LOCALIZED SLIGHT SHIFTS IN '" O • : TVO— 5180.95' \ � LIGHTNESS VALUE RANGING FROM NEAR LIGHT N _ „ __. OLIVE GRAY (HIGHER) TO OLIVE BLACK -DARK O • • '•'.....01 1 GRAY (LOWER); ALSO OCCASIONAL FAINT c :':O 01111 BROWNISH GRAY AND GREENISH GRAY SECONDARY HUES; NOTE THAT OVERALL COLOR � DERIVED FROM TOTAL ABUNDANCE OF DARK 0 0 1 I I I .. LITHIC FRAGMENTS AND GREENISH COLORATION O 0011 FROM LITHIC FRACTION OF GREENSTONES 00I I OVERALL COLOR AND COMPOSITION ARE FAIRLY 0011 (HOMOGENEOUS; DIVERSITY OF SAND GROUPS IS . oo:u: • %%0:1 GRAIN SIZE DRIVEN; POOR TO OCCASIONALLY ........ 'oo: 1 MODERATE SORTING; RANGE FROM FINE UPPER 0 01 — \ TO PEBBLE; MOST SAND AT MEDIUM UPPER TO O 111, , I COARSE UPPER, BUT COMMON INTERVALS WITH FAIRLY EVEN DISTRIBUTION OF SIZE GROUPS 0 01111 FROM MEDIUM THROUGH CONGLOMERATE0'11 1 D TO BE ARE MOSTLY SIZE . 0 , I' I 1 ISUUBANGULAR TO SU ROU DED, COARSER SANDS ., , 001, 1 MOSTLY SUBROUNDED TO ROUNDED, MOST " OI I 1 GRAINS OF ALL SIZES ARE FAIRLY EQUANT ------'---- °-- • • • .'. •; O 111, , i _ AND SUBSPHERICAL TO SPHERICAL, BUT . • .'.':O I I I I (" CONSTANT MINOR FRACTION OF MORE ANGULAR - •: 0 : 1 1 111 1 : AND DISCOIDAL GRAINS; NOTE THAT ABUNDANT •:•: 01 1 ' CONGLOMERATE APPEARS TO BE GRADATIONAL "O.. COARSE END OF FINING UPWARD SEQUENCES, • • % o I 1 BUT EQUALLY ABUNDANT FRACTION APPEARS TO BE SECOND MODE IN FINER SANDS; OVERALL 1 1 / — TUFFACEOUS SANDSTONE WEAKLY SUPPORTED I BY SOFT VOLCANIC DERIVED MATRIX THAT - 7.111:11 >_ • • DISPLAYS ABUNDANT DISCERNIBLE GLASS IMICROSHARD AND IS NON VERY SLIGHTLY 0 _ — _ j - -, CALCAREOUS; TUFF SS EASILY DISINTEGRATED .':O O I I I I I 1 BY DRILLING; OVERALL COMPOSITIONAL ;.!.001111:1 GRAYWACKE (>30% lithics) AND LITHIC .r, O O, 1, 1 J GLEST 35-55% QUARTZ, 15-20% O 0 < GLASS, TRACE FELDSPAR, 10 -20% VARI OUS N • O 011 ' CRYPTOSILCA (CHALCEDONY, CHERT) AND .0 0 OTHER NON DI FERENTIATED SILICA, 25 -40% 0011 DIVERSE LITHICS AND MAFIC MINERALS; NOTE • *:!:00111111 DARK GRAY - BLACK, BLUISH BLACK, BROWNISH %%001111 T BLACK AND MANY OTHER COLORED MINERALS AND ROCK FRAGMENTS MOSTLY NON - !DIFFERENTIATED, BUT DISTINCTIVE BLACK IN , ..... , , , ■ , ARGILLITE RK FRGS, VARIEGATED GREEN • GREENSTONES, AND SPARSE BUT V DISTINCTIV " ORANGISH RED VOLC RK FRGS. 111111111W SURVEY @ 5437 , 'TUFFACEOUS SANDSTONE (5400'- 5490') _ • • • • •• 1 I I I I I I I I I INC 0,4, AZI 57.69', I ILGHT OLIVE GRAY TO GREENISH GRAY TO "' I + TVO x Mal 95' MEDIUM LIGHT GRAY; DISTINCTIVE FAINT IIIIII I 1 1 11 11111 I FROM FINE LOWER TO VERY COARSE LOWER; v ` . • " " " " "" �S � . MOSTLY MODERATELY SORTED IN FINE "I 111 ( \ UPPER TO COARSE LOWER; APPARENT FINING r i UPWARD, AND OCCASIONAL BIMODAL; NOTE IIIIIIIIII ' APPEAR TO BE GLASS SHARDS WINNOWED FROM , ' 1 ; / SAND EQUANT SUBD DAL TO SPHERICAL NDED 1111, � ,,s SHAPE; NEARLY ALL SAME CHARACTERISTICS • !e() Rt 0> -'- i '•' I <0 tll � 1 O><1D C•1 \ , 100K? IMMEDIATELY HIGHER IN ARACT BUT . i' PROMINENT FRAGILE MATRIX SUPPORT BY Ayg W• j 0> p _,<=---- M _ < 0 s 1l)O t rl C_ 4QQK O )1 j I „ ABUNDANT MICRO -SHARD RICH VOLCANIC ASH; �i`i} ASHY COMPOSITIONAL GRAYWACKE; CONTINUED - , t ;; <1b , f 1 C , 2 CONTRAST OF ORANGISH RED VOLCANIC ROCK ��'• I y <1p , i , � q � } )! A Cr e. , , OOK >FRAGS AGAINST DIVERSE GREENSTONES. -- - ` - I ' '' 'F't' ` i TUFFACEOUS CLAYSTONE/TUFFACEOUS _ _m . <10 ` C' 1QQl > SILTS} ONENOLCANICASH (5390'- 5600')= - ote feiluie of electrical f ` APPARENT CLAY- D VOLCANIC ASH = : ' R r s a t 553 ou rce 4 - G togas t _rg� aS m otreaor ding _ DERIVED MUDSTONE WITH MANY LOCAL = °` s SLIGHT VARIATIONS, BUT GENERALLY MANY r • =: € ; • are onYly the ambient gas SHARED CHARACTERISTICS; BASE COLOR IS i tinning through the trap MEDIUM LIGHT GRAY WITH STRONG LIGHT + . z -• I pvhtIe the prob le m was AND DISTINCTIVE GREENISH —= : BROWNISH GRAY A t being corrected. (GRAY SECONDARY HUES, BUT NOTE MANY . -.-------_,,,...-_-=-_,-_! `; I f ' S VARIATIONS IN GRAY, OLIVE GRAY ° ;; �ANDBROWNPRIMARYCOLORSANDSECONDARY j r. '.HUES; ALSO MANY LOCALIZED LIGHTNESS VALUE SHIFTS ESPECIALLY TO HIGHER VALUE j • 0 __. �-- - D { )LIGHTER COLORED ROCKS; CLAYEY TO SILTY c TO ASHY TO VARIOUS SOFT MATTE AND i _• - !TEXTURES; EARTHY TO DIFFUSE GLASS MIXED - -"� .v.,,,==faT- 1 I -- LUSTRES; EXCEPT SPOTTY INTERBEDS OF NON- _._ _ :r ! 3 i . ; DIFFERENTIATED CLAYSTONE AND SILTSTONE, _ 4 NEARLY ALL ROCKS HAVE SPOTTY TO ABUNDANT t zr � NEAR _ ,DISCERNIBLE GLASS MICRO- SHARDS; ALL _ __ " . -I CONSTITUENT LITHOLOGIES ARE GRADATIONAL TO ONE ANOTHER, ALL REWORKED VOLCANIC - . ASH; HYDRATED SOFT CLAYS: POOR TO � -_ = O ! _ 'MODERATE COHESIVENESS, MODERATE TO GOOD 1. ! ADHESIVENESS, HYDROPHILIC, AT LEAST ' :O ; \ 'PARTIALLY SOLUBLE; COMMON FLOATING SAND _` ' ' 'GRAINS AND COAL/CARBONACEOUS PARTICLES. i '; 7. 0 j ` TUFFACEOUS CLAYSTONE/TUFFACEOUS ift. . 1 1 `vi.... , O , - SILTSTONE (5600'•5760') =NOTE SUBTLE '' "sue } BUT DISTINCTIVE CHANGE IN OVERALL BULK 'COLR AT 5600' FROM GREENISH GRAY-MEDI ,,,�,_ O SURVEY @ 5692` J -•' LIGGH GRAY TO MEDIUM BLUISH GRAY-LIGHT UM - 5- INC 4 49 AZI 29 6 BLUISH GRAY - MEDIUM LIGHT GRAY; ALSO NOTE --r— � = = s ' --- TVD = 56-88.a ti CLEANER SEPARATION OF CLAYSTONE FROM pp O ___�,.,_. ) THE MIXED CLAY -SILT MUDSTONE ROCKS; r DOMINANTLY SOFT TO SLIGHTLY FIRM; MOST - ; . ^• -:- ra „ APPEARS HYDROPHILIC, SOLUBLE; MINOR ' FRACTION TO CLAYSTONE IS BRITTLE TO � � MARGINALLY HARD -TOUGH AND ALSO OFTEN • j . ` 11 - + ` , t. SLIGHT TO MODERATELY CALCARE CLAYEY - te r= ' ) �TO SILTY TO ASHY TO MATTE SSOC TEXTEURD SAE; ND ALSO -- ' 'EAR LUSTRE; NOTE A M T s ,, • j J 'DI SPLAYS CHANGE IN CHARACTERISTICS WITH IL ,: , FEW GREENST AND ABNT PHYLLITE LITHICS. • ,.,..., ----. ---- ` ! TUFFACEOUS CLAYSTONEfTUFFACEOUS u c ' s3 SILTSTONE (5760 -5840) = MEDIUM LIGHT TO _-=-.-___ r te " i ^ ARACT MEDIUM GRAY WITH A DISTINCT BLUISH SEC - ONDARY HUE, SLIGHTLY FIRM TO SOFT, _ ( GLOBULAR TO IRREGULAR ERODED FRAGMENTS; = , r; `, STICKY; CLAYEY TEXTURE; DULL EARTHY TO = • • SILTY LUSTER; MODERATELY HYDROPHILIC; -�.,•_... - -_ HYDROPHILIC, • _ MODERATELY ADHESIVE/COHESIVE; E FRAGMENTS 1 x . ,.... ' _._ ! _<. ; r 'COMMONLY COATED WITH RE- WORKED SAND; TRACE MICRO -THIN CARBONACEOUS FOSSLE ;PLANT REMAINS; COMMON INCLUDED VOLCANIC • ' GLASS SHARDS; SLIGHTLY SANDY IN PART; I. MATERIAL DISINTEGRATES IMMEDIATELY WITH a ,x_sr (APPLICATION OF HCL; VERY SLIGHTLY CALCAEOUS. .•.•ec : • SAND (5800 -5960) = MEDIUM GRAY; DIS -AGG- ' REGATED LOOSE SAND; MODERATELY TO MOD _- - _, " ERAELY WELL SORTED; SUB - ROUNDED TO -- • °' -' = SUB- ANGULAR AND MODERATELY ROUNDED; = ='.' • � • "MEDIUM LOWER TO FINE UPPER AND MEDIUM PER GRAIN PREDOMINATES; TRACE COARSE R AND SCATTERED GRANULE ARE TYPICALLY MOD _- .4. -.” SWRV Y bBZ Q 7 ERATELY ROUNDED; SCATTERED 3 TO 7 MM INC 0,28, 7 j PEBBLES; 50 TO 60% MEDIUM TO LIGHT AND ___ GRAY LITHICS; BALLANCE IS TRANS- _. L WHITE TO CLEAR COLORLESS Ul _ ""` j QUARTZNOLCANICS; TRACE GREENISH GRAY � ='3876. 9 �4 , I ' p " ; AND BLUE -GRAY LITHICS; TRACE BRRWN AND ,.:j 0 -:^-, ^zsz ^ , • GRAY -BROWN LITHICS; INTERBEDDED WITH . I THIN TUFFACEOUS CLAYSTONE/SILTSTONES n:;.a .�», - • ; i ; . . AND OCCASIONAL THIN COALS AND CARBON- .ACEOUS SHALES; MATERIAL APPEARS TO BE - - I TO I LIGHT GRAY CLAYST OWASH; LOCALLY ` !GRAIN SUPPORTED; RARE INTACT SANDSTONE (FRAGMENTS NOTED; OCCASIONAL MASSES OF _ SOFT ASHY MATRIX SUPPORTED TUFFACEOUS _ 'SANDSTONE CONTAINING VARIABLE AMOUNTS OF _.�_. THE TYPICAL SAND AND ABUNDANT FINE TO _'='=' = : • • •:•; , ' !MEDIUM GRAIN SUB - SPHEROIDAL VOLCANICS; BULK SAMPLES HAVE A SLIGHT BUT UN- ;INDICATORS; VERY SLIGHTLY CALCAREOUS L TAKAB 1 MISTAKABLE BLUISH SECONDARY HUE; NO OI S;V a :II O I - 'MW 9.0 VIS40 PV9YP 19FL7.6 I } 'GEL 8 /101 - CK 1 SOL 5 OIL /95 SD 025 200 RO• 0> c a t, <0 _ • Ttl Gas 1 10 _ Meth C-I pt ?1(>MBT 4 PH 9.5 CL 28000 CA 600 50 Avg W A B 0> 0 <0 128� 00>-<10 , Ethn C -2 ' 1 TUFFACEOUS CLAYSTONE/TUFFACEOUS • 4/2 4/c011 - �c iOpK SILTSTONE (5920-6060) = MEDIUM LIGHT TO t • , :; 10 Prop C•3 < ,LIGHT GRAY WITH A SLIGHT BLUISH SEC- • ':I I I GRAY MAX GAS 1446 „ 10 Bum C 4 I Op ONDARY HUE; SLIGHTLY FIRM TO SOFT; SOFT GLOBULAR MASSES AND OCCASIONAL O ' I SLGHTLY FIRM ERODED FRAGMENTS; DULL c 1 p Pent C -S 10 0K> EARTHY TO GRITTY LUSTER; SILKY TO :; -- r • . , ' ! I. ' ; I! + :'SANDY /SILTY TEXTURE; MODERATELY HYDRO ' c : =M•' • !. I i i + I i ' , r t ! + ri I': PHILIC; MODERATELY ADHESIVE/COHESIVE; I ' J I I I 1 1111611 1 , I I 1 I COMMONLY COATED WITH RE- WORKED SAND; • _ • , � ; t : f I I i • I 41 1 1 11, 1 1 1 + 0( ,q 1 _ , I I 1 ,, t,' RACE MICRO -THIN CARBONACEOUS FOSSLE • ' ! i i ` ' f ' � � ,o 11 1 i } � j �' 1 I / I I'' 1 4 .,, PLANT REMAINS; COMMON INCLUDED VOLCANIC � I r • I4 GLASS SHARDS; SLIGHTLY SANDY IN PART; I :1111 11,1 .. t ITUFFACEOUS SAND/TUFFACEOUS CONGLOMERATIC r M ;;1 t t 1; 111! t SAND- CONGLOMERATE (6050 -6 = MEDIUM r LIGHT GRAY WITH A SLIGHT BLUISH SEC - O , r ®o • • :I;II , I ! t i ' HUE; DIS- AGGREGATED SAND AND .1 , ' • PEBBLES /PEBBLE FRAGMENTS WITH OCCASIONAL —'" p O 1 �" — i l ' I LOOSELY AGGREGATED TUFFACEOUS MATRIX - S r s I i I 1 H h 1 ; t FRAGMENTS; POORLY TO LOCALLY MODERATELY _ i 1. 11 • f , 1 4 , / ! i ; 1 � • i 7 S UPPER TO COARSE AND I . ORTED; MEDIUM U PER O ,' 111 t 1 i � y I' 1 f , 1 1 ,, G WITH 10 T030% PEBBLES AND PEBBL R• --?=' ' 011 1 I, ! ' 1 n t ;,FRAGMENTS TO 9 MM - AVERAGE ABOUT 4 MM; %%0011 1 1 I 1 11 MEDIUM TO DARK AND LIGHT GRAY LITHICS II :" 00' 1 . + I j I I 1 I ` - I iii • ' PREDOMINATE; ABUNDANT TO VERY ABUNDANT : O 00 , , 1 I :;;;;;;`,:y_•144: :0 ' 1 i TRANSLUCENT WHITE TO CLEAR COLORLESS ; I . f �, . 1, I I : ; 1 i • : ` QUARTZ; TRACE CHLORITE STAINED QUARTZ; I . i 1 )J COMMON VERY DARK GRAY TO BLACK CHERT • :: re5 , t , I, , III PARTICULARLY IN THE COARSE TO PEBBLE ' ▪ ` :O 11 • ;- , ; RANGE; ALL LOOSELY HELD IN SOFT LIGHT j 001 ' ' I 1 + I , t + ' ' ' GRAY TO OFF WHITE ASH /CLAY MATRIX; INTER • ?'- 9 : 1 ' �i+ , I I I i'� I_ + • i 1 1 'BEDDED WITH SIMILAR APPEARING MEDIUM ,LOWER TO FINE LOWER GRAIN TUFFACEOUS :O ),1 �;I 1 SANDSTONE, LIGHT TO MEDIUM LIGHT GRAY . .- :O 11 '+' . TUFFACEOUS SILT /CLAYSTONE AND FINE OFF ' • %11 ' I WHITE ASH/TUFF; NO VISIBLE POROSITY; e O i — - I : ;111' , TR CAL OIL INDICATORS; VERY SLIGHTLY TO 10 r - ��o TRACE CALCAREOUS ' 0 M me.. . • , I , , . ITUFFACEOUS CLAYSTONE/TUFFACEOUS • a I SILTSTONE (6180 -6280) = MEDIUM LIGHT TO • ' ''LIGHT GRAY WITH A SLIGHT BLUISH SEC- - . . :SOFT; HUE; IN PART; SLIGHTLY FIRM TO • j SOFT; ERODED GLOBULAR MASSES AND 3 • O , „ • t RARE SLIGHTLY FIRM FRAGMENTS; DULL Ss • !:!;1111 11 . ,EARTHY TO GRITTY LUSTER; SILKY TO (SANDY /SILTY TEXTURE MODERATELY HYDRO '�" • :OI 1 1 PHILIC; MODERATELY ADHESIVE /COHESIVE; x "'COMMONLY COATED WITH RE- WORKED SAND; • " A TRACE FRAGMENTS HAVE ABUNDANT CARBON- -• J ; ACEOUS MICRO - LAMINA AND PLANT REMAINS; •• X.w _ INTERBEDDED WITH SOFT OFF WHITE VERY y � �� FINE GRAIN SANDY ASH/TUFF, CARBONACEOUS • 7.24144 3 SHALE, MEDIUM GRAY NON TUFFACEOUS € , CLAYSTONE AND THIN SAND /CONGLOMERATIC $3135 3 .' (SAND INTERVALS; TRACE CALCAREOUS. T "; �-- 4- • :, , =\. ' TUFFACEOUS SANDSTONE/TUFFACEOUS SILT - €SS °II 1 ;STONE (6280 -6340) = LIGHT GRAY TO MEDIUM {]! 11 4 S ( `c >33SF+ : , • ' !LIGHT GRAY; SOFT TO VERY SLIGHTLY 'FIRM; HYDROPHILIC; FINE LOWER TO MEDIUM CONNECTION ENHANC•D •'LOWER; MODERATELY WELL SORTED; TRACE ¢� 1 11 1 MAX GAS 152u SURVEY I 6323' LARGER GRAINS;NOTE VERY FINE MATRIX SAND ` ;141 ' • '' " ' INC 0.15, AZI 1 &4.80 FRACTION IS GLASS SHARDS WINNOWED FROM • 7 , ,. -1 • x : 1 I , , TVD 631 9.93' ASH; ANGULAR (Fn) TO ROUNDED (Med);EQUAL 4 - I ; I (PH QUARTZ -COLA GLASS AND DARK GRAY r � 1 -� I(PHYL LITE) LITHICS; ABNT SILT FRACTION ; _IiAR GA938 u — — APPEARS AS GLASSY-ASHY-GRITTY "FLOUR". _ " "" ' ; DEGA ON f . SAND /CONGLOMERATIC SAND/TUFFACEOUS , , , , , , , SANDSTONE (6340'- 6580') = BULK COLOR «G o , , , „ , „ ' ' MEDIUM LIGHT GRAY TO MEDIUM GRAY, TUFF % %111111 ' .% /� SS MEDIUM LIGHT GRAY TO MARGINAL LIGHT ' '..,:': I , , ; f GRAY, LOOSE SD -COL SD MEDIUM GRAY TO • ' 1 111: ' .''DARK GRAY TUFF SS. GRADATIONAL TO SANDY e , RUFF CLYST; MATRIX INTERGRAIN OF TUFF ',t ma t L VOLC ASH, DISCERNIBLE MICROSHARDS --- -'' ; ' , 1 " �._ , AND FLOATING CARBONACEOUS PARTICLES; O ; =:.;° : 2 1 I SPOTTY VERY FINE TUFF SS FORMED BY O „,, REDEPOSITED- REDISTRIBUTED GLASS SHARDS c----; =-,: . ' I III ; �� , 'WINNOWED FROM THE ASH; SHARES MANY ;CHARACTERISTICS WITH TUFF CLAYST AS -' °-'-" :11 MATRIX VOLUME INCREASES; SOFT TO SLI ' r oc;: i, .FIRM; MORE ANGULAR - SUBANGULAR AND ,-...•••••••••••;;;•=;•••••••••.; i i I DISCOIDAL THAN SURROUNDED- ROUNDED AND ;�.- ._:zsx._ �:: I 1 ISPHERICAL;SLI MORE QUARTZ AND VOLC GLASS I � I , ;GRAINS THAN METALITHIC ROCK FRAGMENTS; _ .• I _ j , I I f OFTEN HYDROPHILIC, SOLUBLE AND OBVIOUS - i ., , EASILY DISINTEGRATED; SAND /CONGLOMERATIC • — _ = ▪ '"" "" . - 4 I ''1! f 1 +� ' j SAND OCCASIONALLY ALSO GRAYISH BLACK ' , s. = = s � `; i � • r . ' , + 1+ rt II! } jWHEN SEPARATED FROM CLAYS; LOCAL GRAYISH _ I ; : �� :+-1 x : , ': ' ' 1 I ; I' , � j 'DIRTY" PEPPER AND SALT APPEARANCE; FINE { ;.r; . , . 1 .` , (i t) I' : LOWER TO PEBBLE RANGE; DOMINANT MOD TO ` _ x: ; ' I D ' I I+' I t - POORLY SORTED AT FINE UPPER TO COARSE yf -"' + ; 1 ' , t Itjl�h I� }I r• # I , 1 , t LOWER; FINING UPWARD IF MASSIVE; VERY r ' I ' I ', ; , i ' DOMINANT ANGULAR - SUBANGULAR AND MORE O _ Y+ -n „1 i I . . <D � U Gas >< 10 tttrl C -2 DISCOIDAL THAN EQUANT; DISAGGREAGATED TO 5 A �s -xn�� .•' 1 I 1 h C - 100M�>TUFF CLAY MATRIX SUPPORT; COMPOSITIONAL 2 +i ' ROP 0> �. 0 Met GRAYWACKE(>30% I(thics);LITHICS FRACTION q vg WO 0> O - .r %It < sl G4 1 x1 9DiK ( RANGES AS HIGH AS 80 %; NOTE THAT 80 -90% I 10 Pro C•3 00K OF ALL LITHICS ARE DARK GRAY TO GRAYISH " -, ?^ p BLACK PHYLLITE META ROCK FRAGMENTS WITH _ -;. 11 ART @ 4 t 00K > V DISTINCTIVE PARTIAL- WEATHERED, ROUGH, �� 11 ,i0, , AZI ,6 ` MICRO- GRAINY, SUB- SCHISTOSE TEXTURE; ^ • ▪ • = 1 508 aa P e n C - 00 ASSOC ARGILLIT DOMINATED ERGS AND DARK VARIEGATED � ' .. T ' GREEN GREENST FRGS; DOM BLACK MAFICS. • - _ -- ,"" , I 1 ■ 4 -1 �TUFFACEOUS CLAYSTONE/TUFFACEOUS - --- ` x 1 STONE 8280' -6580' = DOM MED GRAY ter. BUT MANY GRAY AND BROWN COLORS -HUES; _-�' = I , . : SOFT TO SLI FRM; HYDRPHLC;SOLB, CLY SLT- - ' 1 1 j ' ° - MATTE TEXTS; EARTHY LSTR;COM FNT BLU ;; -CRY COLOR;COM COAUCARB LA S /PARTICLES; WIper Trip at 6i ,.,,.• • • • • ':I I 1N MODERATE TO THICKLY BEDDED WITH NUMER- .. MAX'GAS 203u . " ' OUS THIN TO VERY THIN TUFFACEOUS SAND/ • ' ! I ! ' : 'CONGLOMERATIC SAND INTERBEDS AN OCC- i 1� I ' ) _ - :A SIONAL VERY THIN COAL AND CARBONACEOUS • I ' , t i ' I I ' :r SHALS; TRACE MEDIUM GRAY NON TUFFACEOUS I { ,_, CLAYSTONE; COMMON TO TRACE SILTY OFF 1 f } ) • ; WHITE TO VERY LIGHT GR ASH/TUFF; VERY .1 SLIGHT TRACE CALCAREOUS. _ 1 - - SAND/TUFFACEOUS SAND /CONGLOMERATIC SAND I 1 I I I • (6580- 6760) =MEDIUM TO MEDIUM DARK GRAY _ • ! 1, . IJ 1 1 11 4 l ! I if � BULK SAMPLE HAS A SLIGHT BLUISH SECOND- • :? I P • I ; 1'( AIRY HUE; GENERALLY DISAGGREGATED; RARE - ) Au " • ;TO TRACE INTACT TUFFACEOUS SANDSTONE I " TRANSLUCENT WHITE ee ) , 1 i i ■ ), FRAGMENTS HAVE A SLIGHT YELLOWISH TO ee _ t 1 I I ! , ,• BROWNISH SECONDARY HUE; MODERATELY t I i t 1 t i 1 � 1) 11 I I I1 1 l III I I , SORTED; SUB - ANGULAR TO ANGULAR AND SUB - ' ! t V ':I ! S 1 t L.j f j tIl • ,,` SPHEROIDAL; MEDIUM LOWER TO FINE UPPER i 1 i � I ' , t I i '1� ( GRAIN PREDOMINATE; TRACE TO COMMON FINE ■ 1 ' GRAIN AND VERY FINE UPPER GRAIN; LARGER 'LOWER ' �- I 1 • ' i ( 1111 I 1 `1111, DOMINATED(60 %) BY MEDIUM TO MEDIUM I , III I s -• -R �� j DARK GRAY LTTHtCS;403; I I ' i o ' ▪ sa • ' I - TO CLEAR COLORLESS QUARTZNOLCANICS, - ! > __- _ '� 'TRACE YELLOWISH QUARTZ; NOTE COMMON ' p ` ERED CRYSTAL FACES ON QUARTZ; v UNWEATHERED I _ TRACE TO COMMON LIGHT GRAY LITHICS;TRACE BROWNISH GRAY AND BLUE -GRAY CITRIC' I, ,_ S ) ; I ; ; ,,'! MINERAL GRAINS; TRACE VERY FINE TO FINE I , ` GRAIN TUFFACEOUS SANDSTONE AN YELLOWISH I I — . - - i WHITE TO WHITE SANDY ASH /TUFF; GRADES TO MAX GAS 129u AND INTERBEDDED WITH ASSOCIATED TUFF- F ACEOUS SILTSTONE; OCCASIONAL VERY THIN COAL AND CARBONACEOUS STRINGERS; NON TO _ -_ _, s r, 1 I. • ,TRACE CALCAEOUS. ; ' ; i ! . i ' TUFFACEOUS SILTSTONE/TUFFACEOUS SURVEY � 67T � CLAYSTONE (6760'- 6860) = MEDIUM TO MED . • ' _ S'"..7,, . 44: • . „. I INC 0,77 AZl 194.98 , IIUM LIGHT GRAY; SLIGHT BROWNISH STAIN ON - ...�- TVD = 6763.92 :BEDDING SURFACES; BULK SAMPLE HAS A I 1 = AX GAS 201u ;SLIGHT BLUISH SECONDARY HUE, BECOMING t _ _ ' sA, ';LESS PRONOUNCED AND WITH A N ADDITIONAL BROWNISH CAST; FIRM TO SLIGHTLY FIRM AND • ;, - --- • 31r3'- "" - ' SOFT; IRREGULAR TO BLOCKY FRAGMENTS; DULL EARTHY LUSTER; SLIGHT MICRO- SPARKLY . .. - .. . ta ' s 1 APPEARANCE IN PART; SILTY TO SANDY AND , 7.6.., .. I , _ 'SMOO CLAYEY TEXTURE; SILTY FRACTION D SPLAYS ABUNDANT CARBON - • Fro' I I ACEOUS MICRO - LAMINA; INTERBEDDED WITH AND GRADING TO THIN TUFFACEOUS SANDSTONE -_ s ?� - ' • • ASH/TUFF AND OCCASINAL VERY THIN COAU ,,� . • . „ COHESVEiS�GHTL R; ADH 8 LIGHTLY Y 117 ,HYDROPHILIC; TRACE CALCAREOUS. ' M _ AX AS 168u, ,� ”" 1111 . 9.1VIS41 PV9YP19FL7 •• •''i -` ' GEL 7/10/11 CK 1 SOL 5 OIL /95 SD 0.25 -- afft 7 MBT 6 PH 9.6 CL 32000 CA 400 117.2:1-7i',..-,... r „ ' 3 , - / TUFFACEOUS SIL TUFFACEOUS ' ' ' CLAYSTONE (6860'- 6960') = MEDIUM TO MED , - '.'.Fft.i F- • . ' ; ''` IIUM LIGHT GRAY; SLIGHT BROWNISH STAIN ON y''i,.1--= • i ' ;SOME BEDDING SURFACES; VERY SLIGHT J2512011 w :� � . • _.-.) ;BLUISH TO PRONOUNCED BROWNISH SEC - cri �p � ^' _ • �� ONDARY HUE; SOFT TO SLIGHTLY FIRM; SOFT 0 0 ': - GLOBULAR TO IRREGULAR SUB - BLOCKY FRAG- I MENTS; DULL EARTHY TO SILKY LUSTER; i ,-- GRITTY /SLIGHTLY SANDY TEXTURE; SILTY " ' C J • FRACTION COMMONLY DISPLAYS ABUNDANT CAR I MICRO - LAMINA; ABUNDANT MICRO - LAMINA FRAGMENTS; INTERBEDDED WITH AND - ? 'TO VERY FINE GRAIN VERY TUFFACEOUS SAND- - , , I / ;STONE, OCCASIONAL THIN CONGLOMERATIC / TUFFACEOUS SANDS AND THIN COALS; TRACE II _ • CARBONACEOUS. 1 i I I I SAND/TUFFACEOUS SAND (6960- 7100') _ MEDIUM LIGHT TO MEDIUM GRAY; SLIGHT 'I' BLUISH TO BROWNISH SECONDARY HUE IN mi r �Z IBULK;GENERALLY AS FLUFFY SOFT ASH MATRIX ma 1 :SUPPORTED GLOBULAR MASSES AND VARIABLE 1 AMOUNTS OF LOOSE SAND; FRAGMENTS J , _, i ' DISPLAY A SLIGHT YELLOWISH TO BROWNISH gi RO 0> g �z rS� a0 ttl G 1 D - M B ) I1 C } SECONDARY HUE; MODERATELY WELL 70 5 Avg W i ' 0> O ; r3 ;*s <0 C ,tgs G , 100x10 E. C 2 y ,y� MODERATELY SORTED; SUB - ANGUL TO ' }, , , , ' SUB- ROUNDED, ANGULAR AND SUB SPHEROIDAL; '" FINE UPPER TO MEDIUM LOWER AND FINE ®a • i F <to 'Rrdit C-3 0DF LOWER GRAIN ;; TRACE MEDIUM UPPER; SCAT- ] J ' n I , 7 • — TERED LARGER GRAINS; PRIMARILY TRANS- <10 BLItn C•4 1 LUCENT 1 : 1 ' ARTZ/V WHITE TO SMOKY GRAY AND CLEAR <10 P ent C•5 t 1 oDK ' O U OLCANICS, 30 TO 40% OF LOOSE 1_. 1.v 1 !.. : ( / � SAND IS MEDIUM TO MEDIUM LIGHT GRAY 1 1 THICS; TRACE BROWN AND BLUE -GRAY w • 1 - LITHICS; TRACE MICA FLAKES; INTERBEDDED • �� VF • SSHAKEFjS; ]SSRA <EA SC�IEEN WITH AND GRADING TO TUFFACEOUS SILTSTONE AND VERY FINE GRAIN TUFFACEOUS SAND; ° mm i COMMON TO ABUNDANT THIN AND MICRO -THIN I , PLATY FRAGMENTS; ' CARBONACEOUS LAMINA AND TI, , I I TRACE TO COMMON LIGHT GRAY CALCAREOUS ___ TUFF AND CALCITE CEMENTED VERY FINE ' I I GRAIN SANDSTONE, ; TRACE OUT - CASING IN I I �TUFFACEOUS SILTSTONE; SLIGHTLY CAL - , „ ' ` \�``XGA$ C2 3 Cl :ICAREOUSOVERALL. O C 1 1, , ' ' , y 7 TUFFACEOUSSILTSTONE/TUFFACEOUS • c CLAYSTONE (7100 MEDIUM TO MED I j I ( ) ' i j ,. Y MPAX ,A S 1 — - I P ONOUNCED BROWNISH HUE N BU K TO I , , 1 . , , , „ , , . ' ' ! ' �ONDARY O HUE; SOFT NO SLIGHTLY FIRM; OFT !+ 1 1 111 I I' ` I •' ' GLOBULAR TO IRREGULAR SUB- BLOCKY FRAG- : ° o01 I 1 11 I I , VENTS; DULL EARTHY TO SILKY LUSTER; ! � " = . y 10 I X GAS 392u . ! ., • (GRITTY /SLIGHTLY SANDY TEXTURE; BROWN - z•2b �1��' f ' !, p 'CARBONACEOUS IN PART; INTERBEDDED WITH, I , , , , ' I I ( Ij j AND GRADING TO TUFFACEOUS SANDSTONE; 1.11lidi ii • ' I ! 1 I . x � 1 1 . f f i �' j F -�i� . : , i I t+ � 1 � r � + � ! ' CARBONACEOUS TUFFACEOUS CLAYSTONE MAY W I I s ` x r ,� 1 ( ( Ij 1 1 1 { i r HAVE GENERALIZED DISTRIBUTION OF VERY ► ; i_ _ • _ ' I I 1 1 I II FINE CARBONACEOUS MATERIAL AND /OR THIN I ! i z € 1 t I - 1 1 1 1 i F ` j' it " � II ! i I I 9 LAMINATIONS, LAMINAR STREAKS - FLAKES AND } . .1 l y _ KWii; ∎ i ( ! j I ft . I • I j j,� i { . PARTICLES OF COAUCARBONACEOUS SHALE; I i I I 1 , 1 NOTE THAT PARTINGS OF TUFF CLAYSTONE ARE r r S, i f f t iI r 1' ROUGH PARALLEL ORIENTATION (GENERALLY IN t I I � - `" •1,1, ; I � , ' 1 J' ; II I AND E X P OSEMICRO-THIN LAMINATIONS OF N K 3a > a � ° " ; j ' lit. j ' j I I� I CARB MATERIAL OR SAND SILT. 1 8 _ i I • � - zi t i } j 1 ;I � j 3 3 ►' I I TUFFACEOUS CLAYSTONE/TUFFACEOUS I f 1 i = . • �.:; x zsi I I ( : <--'� ; Ill 11, } lilt j ISILTSTONE/VOLCANIC ASH (7180 = , L. i ( ' - ` • • 1 };!;;!I I I. i- I ;1 ;.,.. ; " f sz- a + ;`� ! " CLAY -SILT -ASH MUDSTONE LARGELY DERIVED FROM REDEPOSITED VOLCANIC ASH; I I 1 i_ i 1 '- =•`rim _ , . , , MANY SHARED CHARACTERISTICS DESPITE _ I � +ROCK TYPE VARIATIONS; BULK COLOR AND !- I ,1 } I .j , Y t i ' ' II 1 1 I --1 DOMINANT CLAY COLOR IS MEDIUM GRAY; NOTE I j I •so j 1 1 •1; I OCCASIONAL BROWNISH GRAY SECONDARY HUE 1 � t l . • • '''''4.7. - ) _-- 11 1 p i WHEN CARBONACEOUS; MANY LOCALIZED SUBTLE • ; T t I ` 4. * f I l � ! � 1 I a r f '' I i!Ii1 I } I 1 I i ! VARIATIONS IN GRAY, BROWNISH GRAY AND HUES; NOTE MANY SECONDARY LOCALIZED SHIFTS IN srEv p I ! 1 ' I ! ij I ! III il LIGHTNESS VALUE, MOST COMMONLY DOWNWARD • i , -sa ' I ; 1 1 1! { 1 ' i! i 1 ! . i i' ; 1 I -1 ' III TO DARKER GRAY COLORS; CLAYEY TO SILTY -.1.- 3S€€ii' �•Yes'rs3 .. P 1 . ' i 'TO ASHY TO VARIOUS SOFT MATTE AND MIXED a 4 TEXTURES•EARTHY TO "SOFT" GLASSY LUSTRE; .x. . :-.... .. 1 ; j y4 _:� =_ . i , « ; FRACTION FROM TRACE TO VERY GLASS SHARDS -, - g •= '=��11 I i! ;-;111 l RANGES FROM TRACE TO VERY ABUNDANT; =mss• +•, - (Z z=3'+• ," _1 i • 1 !1 Il • ' ' 1 1 ' 1 ' , :' CONSTITUENT LITHOLOGIES ALL GRADATIONAL — O •'"t•—- ::- - .�--- :HIT } . 1 1 1i ro THE OTHERS; HYDROPHILIC SOLUBLE SOFT 0 _ _ ` } 1 Ii+11f 1 i t .' F I + , 1 I ( I ICLAYSTONES DISPLAY POOR TO MODERATE • .= = ..s } } 1 I i I I ! ' ! j ! COHESIVENESS, MODERATE TO GOOD I � + •rzz3 11 _ .. ' '1i ', 1 ! I l 1 ' ADHESIVENESS; FLOATING SAND GRAINS AND • I ' �";.._ ..,oar f I ROOCKS; NOTE TRAC US PARTICLES IN MANY SOFT _' _: 1. i V ^-; 1§ �� ! P l : i , RCKS; NOE TRACES OF VERY CALCAREOUS • -_ . 1; 1, BRITTLE TO HARD MEDIUM GRAY CALCAREOUS - :z . - TUFF; NOTE COMMON WELL DISTRIBUTED VERY • • FN CARBONACEOUS MATERIAL IN THIN ZONES; • - -__ '°=_= xs' zf ____ I I i ,F_ •,_,_ MOST MASSIVE CLAYSTONE ALSO HAS THIN - . ' LAMINATIONS, LAMINAR STREAKS OR FLAKES .' :m•- : ' , I „ AND PARTICLES OF COAUCARBONACEOUS SHALE PARTINGS OF CLAYSTONE-SILTSTONE USUALLY • - - _5€era ' 'IIN ROUGH PARALLEL ORIENTATION ON THE ,n �j O • B OR AT SAND ASH -"•.. •: ;LINEATIONS; CONSISTENT SPOT FRACTION OF 1- :.. -_... z -e3 • .. . 1 . ,. l FIRM TO BRITTLE BRITTLE CLAYSTONE-SILST • 1 _ • •1 WITH IRREGULAR TO BLOCKY CUTTINGS HABIT. SAND /SANDSTONE/TUFFACEOUS SANDSTONE - - ' 1(7400'- 7600') = MEDIUM GRAY TO DARK GRAY • • - WITH FAINT OLIVE GRAY TO OLIVE BLACK TO m a t ' "',BROWNISH BLACK SECONDARY HUES; VERY a �- •FIINE LOWER TO VERY COARSE UPPER TOTAL . �,..,, ••"_ Note electrical circuit RANGE; MOSTLY MODERATE TO MODERATELY ' ......... , 1 ' failure to QGMtrapp motor. f 'POOR SORTING AT FINE LOWER TO COARSE - ..,,,, . • • Ambient gas only Fecorded LOWER; LARGEST FRACTION IS MEDIUM; ABNT - •••= rW 3$e • • •• 17' to 7439' ; FRACTIONS OF DISAGGREGATED LOOSE GRAINS, Ad"-- ,' � !FINE- MEDIUM VERY CALCAREOUS CONSOLIDATED y • -- ' : SANDSTONE FRAGMENTS, AND MINOR FRACTION 1 b 4- OF SOFT SHARD-RICH TUFFACEOUS SANDSTONE; I j . CALCAREOUS SANDSTONE IS BOTH MATRIX AND tt�>: 'GRAIN SUPPORTED, APPARENTLY ASSOCIATED - % . _ - 'WITH TRACE - SPOTTY PRESENCE OF CALCAREOUS rr. `M• • • : • •• T ,TUFF, STRONGLY EFFERVESCENCT, MEDIUM ! • : _. ` ' ;(HARD AND TOUGH MOSTLY ANGULAR SUBANGULAR • iAND DISCOIDAL - IRREGULAR SHARP EDGED, BUT SPOTTY (FINE) MODE ROUNDED GRAINS; c2b0 ROP 0 :.11 1 1 <0 Ttl Gas 100 10 Mesh C -1. 1b a NOTE CONSOLIDATED SANDSTONE DISPLAYS 5d Avg We': 0 8 : < `` 0 Gtgs Gas 1 Q0 10 Ethn C -2 100 CUTTINGS FRAGMENTS WITH BOTH POOR AND t ; ' ; ;; 1 FAIR VISIBLE POROSITY; COMPOSITIONAL \,'`' C -2, - , ' GRAYWACKE (>30% tithes) AND LITHIC 10 Prop C• 1 +. I a ! 7 ARENITE; SOME OF THE TUFFACE SS IS I • ! ' U t 1 , : 1 . ' ' ' C -4 • e •K FAIRLY "DIRTY LOOKING" WITH MATRIX SILT- C -3 CLAY IN ADDTION TO ASH EST 30 -60% QUARTZ - I i n i C5 It 1 r • 10 -20% VOLC GLASS, TRACE FELDPAR, 10 -15% ( �_ .) , I 1 CRYPTOSILICA (CHALCEDONY,CHERT) AND • F ( i r 1p , * P e � 6 f 1 ; j j OTHER NON - DIFFERENTIATED SILICA, 25-65% I ----. . . l } I _ 1 I +sm-z� \ j t 1 j � S AND MAFIC MINERALS; NOTE THAT 80 85 / 80 85 / OF ALL LffHICS ARE MEDIUM TO DARK ! j ;. —w +• I .. _t t _ _ _ I , (GRAY PHYLLITE ROCK FRAGMENTS WITH .•=•=•,z •'-`•. I j I I DISTINCTIVE SLIGHTLY WEATHERED SCHISTOSE I • j I1 I - 1 1 - ��_ ' ! ;TEXURE, REMAINING L ITHICS MIX OF ASSOC - i - : 1, , \ i • • j ' DK GRAY ARGILLITE FRGS AND GREENSTONE j I I t_ 1 t i r I .11 1 I r � I { I ' : FRAGMENTS. i - I I ss : ' • 1' • 1 1 ' j ± 3 _, i , ; SAND /SANDSTONE/TUFFACEOUS SANDS " • • I "'1 f ( ) ' 1 , (7600'- 7700') = MEDIUM GRAY TO DARK GRAY 8a ' ; j 1 1 • l WITH FAINT OLIVE G TO OLIVE BLACK TO § *' a • 1 1 i + BROWNISH BLACK SECONDARY HUES; MOD G z z .... ' 1111 11 + I, , I ERATELY TO MODERATELY WELL SORTED; . ins - FINE UPPER TO MEDIUM LOWER GRAIN PREDOM- . 3 13 INATE; LOCALLY COMMON MEDIUM LOWER TO i I MEDIUM UPPER AND COARSE LOWER NOTABLY .= , °ir z" i ` ANGULAR TO SUB-ANGULAR AN SUB ROUNDED; • ' ` MATERIAL TENDS TO BE MORE ROUNDED/ • ' AX GAS 417u C3 ' , C2 Cl C1 SP CAL; PREDOMINANTLY TRANSLUCENT , y4 > .11111 I ; • - • — / COARSER MATERIAL MRENDB O MDST DARK T M 1 1- , I : i } , - -- I t r '.7 ;MEDIUM GRAY R TE D; S; PRINCIPALLY TUFF • ',;MATRIX SUPPORTED; SOME LOCAL GRAIN -• I 1. I j 3--- -- SUPPORTED SANDSTONE WITH SOME VISIBLE • f 1 • R H IR j I 4. N3b33 j_ �! TUFFACEOUS POROSITY; INTE SILTSTONE; BEDDED SILTY WIT S FRACTION MILA ! 1 , 1 "`i1F �� i I + IS OCCASIONALLY VERY CARBONACEOUS AND I ",=T. .« <,zzz= : ; I I 1 1 HAS ASSOCIATED THIN COAL AND CARBON- , .. " 1/ - -. _. . ..... ._ ._ _ � -_.. -.. _ � ._ ,sue—.- .� r✓`. �........� J.....^�. f .., . - _ - .. �,,!•. /`. - v, ,.`• / '^..�.'•` /• '�,'.1 • d • i•• � � ' .A ..\-"‘, r - ; i vv ., .' ' • Ir .- . w -.,9,. ,,, "sr , a 1 I I I I I I I I 1 I I • co 5 oozy I I l I I I I I I 1 1 1 j 1 ,I 0 I . i � I I II 1 1 V \ v ` ! \ �, % , 11 _, �,- ✓�, \I \ `rlV l r r�j\�,.i V' rn \/1 r J /1 j AAI AA11/11_. ^./1 V 11-\f` /V I,- l ■ ji\J\1,1\AIV.-,\./v\i`A\e‘ilvv-j./),t-\\M/VV\i v I I 1 I I } I I I 111 I l I rw ww ww w Y - -1 -- e - ii 1 4 1 . r-- 1 .„..„........„ •. v ., .. , , ..„•..,.... ..„.• ,./. ,,,,,' \ A • ,".... (.. f \ .- .14 j 1 r ig.", w. t 14 1 i . 1 1 , I tI 0 OOGG Oobg I I I I 4 I . : I I I I I n I I I I I I I I A 0 I+ 1, 1 I I 1 it 1 I 1 ; 1 /� I i [I I 1 .11I1" / ,1 I ) 1 { (\ „ P d , \./ 1 �� I I ^\ 1/%0' .0N 1 N � li ' ^^,./‘ 1 / 1 1 r`'f� h , - \� -': '� 1,_ �� I \ ti l \ i 1 , , J / � /�`.r/ \,,\ %/ I'', �./ tit/ ;{/'' , 1 1 I:✓� v\ r 114 I : I ii I .. 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P, 1 --..,-.^ 1 :' -1 . - *\ - - .-- —ft-- -- .---- ..-- \ -, , . - „.0. -%." ■ . ••■0 • • %,... I . l , ,. , ....„, \.,- - `,,r./ f -.1.4'- -....../ - %., ,' ',/ •„, ..• „ „ v v.• - - -, -,....• ---- 1....1.." I ! ° I I I '' a , I l il . I �� I ^ ~ \� I k 1 i y 1 I I i I 1 A � f- 1 / \dv` \/ \ I -Aj 11 , r � 1 - .r IN 1 1 ` ,•� l - � t 1 ✓` J v 1 I/ 1 1 VIA It 1I I V AdI j j v \� 1 h , � t 1 of 1, i 1 ' , a �I ! i( l i I I Hr l ' dl I 0 I I I ,� I I I 6900 7000 7100. I f ) . V `I 4 l 1 P A 1 4 A 10 IL. ‘ ( I V 1 I , W . 4 i t t I 1 '� • f - k `� .. v ✓ , r , .-- .✓ - - - -' J , r te . f J _ / k J . i 1x ,'./