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Sample records for gas reservoir bluebell-altamont

  1. Heat pipe with hot gas reservoir

    NASA Technical Reports Server (NTRS)

    Marcus, B. D.

    1974-01-01

    Heat pipe can reverse itself with gas reservoir acting as evaporator, leading to rapid recovery from liquid in reservoir. Single layer of fine-mesh screen is included inside reservoir to assure uniform liquid distribution over hottest parts of internal surface until liquid is completely removed.

  2. Coarse scale simulation of tight gas reservoirs 

    E-print Network

    El-Ahmady, Mohamed Hamed

    2004-09-30

    COARSE SCALE SIMULATION OF TIGHT GAS RESERVOIRS A Dissertation by MOHAMED HAMED EL-AHMADY Submitted to the Office of Graduate Studies of Texas A&M University in partial fulfillment of the requirements for the degree... of DOCTOR OF PHILOSOPHY December 2003 Major Subject: Petroleum Engineering COARSE SCALE SIMULATION OF TIGHT GAS RESERVOIRS A Dissertation by MOHAMED HAMED EL-AHMADY Submitted to Texas A&M University...

  3. Underground natural gas storage reservoir management

    SciTech Connect

    Ortiz, I.; Anthony, R.

    1995-06-01

    The objective of this study is to research technologies and methodologies that will reduce the costs associated with the operation and maintenance of underground natural gas storage. This effort will include a survey of public information to determine the amount of natural gas lost from underground storage fields, determine the causes of this lost gas, and develop strategies and remedial designs to reduce or stop the gas loss from selected fields. Phase I includes a detailed survey of US natural gas storage reservoirs to determine the actual amount of natural gas annually lost from underground storage fields. These reservoirs will be ranked, the resultant will include the amount of gas and revenue annually lost. The results will be analyzed in conjunction with the type (geologic) of storage reservoirs to determine the significance and impact of the gas loss. A report of the work accomplished will be prepared. The report will include: (1) a summary list by geologic type of US gas storage reservoirs and their annual underground gas storage losses in ft{sup 3}; (2) a rank by geologic classifications as to the amount of gas lost and the resultant lost revenue; and (3) show the level of significance and impact of the losses by geologic type. Concurrently, the amount of storage activity has increased in conjunction with the net increase of natural gas imports as shown on Figure No. 3. Storage is playing an ever increasing importance in supplying the domestic energy requirements.

  4. Gas network model allows full reservoir coupling

    SciTech Connect

    Methnani, M.M.

    1998-02-23

    The gas-network flow model (Gasnet) developed for and added to an existing Qatar General Petroleum Corp. (OGPC) in-house reservoir simulator, allows improved modeling of the interaction among the reservoir, wells, and pipeline networks. Gasnet is a three-phase model that is modified to handle gas-condensate systems. The numerical solution is based on a control volume scheme that uses the concept of cells and junctions, whereby pressure and phase densities are defined in cells, while phase flows are defined at junction links. The model features common numerical equations for the reservoir, the well, and the pipeline components and an efficient state-variable solution method in which all primary variables including phase flows are solved directly. Both steady-state and transient flow events can be simulated with the same tool. Three test cases show how the model runs. One case simulates flow redistribution in a simple two-branch gas network. The second simulates a horizontal gas well in a waterflooded gas reservoir. The third involves an export gas pipeline coupled to a producing reservoir.

  5. Geomechanical Development of Fractured Reservoirs During Gas Production 

    E-print Network

    Huang, Jian

    2013-04-05

    Within fractured reservoirs, such as tight gas reservoir, coupled processes between matrix deformation and fluid flow are very important for predicting reservoir behavior, pore pressure evolution and fracture closure. To study the coupling between...

  6. Tight gas reservoirs: A visual depiction

    SciTech Connect

    Not Available

    1993-12-01

    Future gas supplies in the US will depend on an increasing contribution from unconventional sources such as overpressured and tight gas reservoirs. Exploitation of these resources and their conversion to economically producible gas reserves represents a major challenge. Meeting this challenge will require not only the continuing development and application of new technologies, but also a detailed understanding of the complex nature of the reservoirs themselves. This report seeks to promote understanding of these reservoirs by providing examples. Examples of gas productive overpressured tight reservoirs in the Greater Green River Basin, Wyoming are presented. These examples show log data (raw and interpreted), well completion and stimulation information, and production decline curves. A sampling of wells from the Lewis and Mesaverde formations are included. Both poor and good wells have been chosen to illustrate the range of productivity that is observed. The second section of this document displays decline curves and completion details for 30 of the best wells in the Greater Green River Basin. These are included to illustrate the potential that is present when wells are fortuitously located with respect to local stratigraphy and natural fracturing, and are successfully hydraulically fractured.

  7. TDT monitors gas saturation in heterogeneous reservoir

    SciTech Connect

    Hamada, G.M.; Al-Awad, M.N.J.

    1998-05-25

    Thermal decay time (TDT) logs were used for determining the gas/oil contact in wells in the Zeit Bay field in Egypt. Gas/oil contact in the field was revised using the results from the model that was developed. The analysis followed the Polyachenko model of functional relationship between count rates and gas saturation. Several crossplots were made for the same range of porosity and connate water saturation. These crossplots included: formation capture cross section; total selected near detector counts; total selected far detector counts; capture cross section of the borehole; and inelastic far detector counts. Each crossplot gave a definite diagnostic shape around the depth of the gas/oil contact. By using these crossplots, it is possible to calculate gas saturation from a stand-alone run. The model was validated by RFT (reservoir formation tester) and open hole log data from infill wells. Also, the analysis was successfully applied in wells without an ambiguous gas/oil contact.

  8. Carbon sequestration in natural gas reservoirs: Enhanced gas recovery and natural gas storage

    SciTech Connect

    Oldenburg, Curtis M.

    2003-04-08

    Natural gas reservoirs are obvious targets for carbon sequestration by direct carbon dioxide (CO{sub 2}) injection by virtue of their proven record of gas production and integrity against gas escape. Carbon sequestration in depleted natural gas reservoirs can be coupled with enhanced gas production by injecting CO{sub 2} into the reservoir as it is being produced, a process called Carbon Sequestration with Enhanced Gas Recovery (CSEGR). In this process, supercritical CO{sub 2} is injected deep in the reservoir while methane (CH{sub 4}) is produced at wells some distance away. The active injection of CO{sub 2} causes repressurization and CH{sub 4} displacement to allow the control and enhancement of gas recovery relative to water-drive or depletion-drive reservoir operations. Carbon dioxide undergoes a large change in density as CO{sub 2} gas passes through the critical pressure at temperatures near the critical temperature. This feature makes CO{sub 2} a potentially effective cushion gas for gas storage reservoirs. Thus at the end of the CSEGR process when the reservoir is filled with CO{sub 2}, additional benefit of the reservoir may be obtained through its operation as a natural gas storage reservoir. In this paper, we present discussion and simulation results from TOUGH2/EOS7C of gas mixture property prediction, gas injection, repressurization, migration, and mixing processes that occur in gas reservoirs under active CO{sub 2} injection.

  9. Naturally fractured tight gas reservoir detection optimization

    SciTech Connect

    Decker, D.

    1995-05-01

    Exploration strategies are needed to identify subtle basement features critical to locating fractured regions in advance of drilling in tight gas reservoirs. The Piceance Basin served as a demonstration site for an analysis utilizing aeromagnetic surveys, remote sensing, Landsat Thematic Mapper, and Side Looking Airborne Radar imagery for the basin and surrounding areas. Spatially detailed aeromagnetic maps were used to to interpret zones of basement structure.

  10. Feasibility of waterflooding Soku E7000 gas-condensate reservoir 

    E-print Network

    Ajayi, Arashi

    2002-01-01

    We performed a simple 3D compositional reservoir simulation study to examine the possibility of waterflooding the Soku E7 gas-condensate reservoir. This study shows that water injection results in higher condensate recovery than natural depletion...

  11. Evaluation of Devonian shale gas reservoirs

    SciTech Connect

    Vanorsdale, C.R.

    1987-05-01

    The evaluation of predominantly shale reservoirs presents a problem for engineers traditionally educated either to correct for or to ignore such lithologic zones. Currently accepted evaluation techniques and their applicability are discussed to determine the best way to forecast remaining recoverable gas reserves from the Devonian shales of the Appalachian basin. This study indicates that rate/time decline-curve analysis is the most reliable technique and presents typical decline curves based on production data gathered from 508 shale wells in a three-state study area. The resultant type curves illustrate a dual- (or multiple-) porosity mechanism that violates standard decline-curve analysis guidelines. The results, however, are typical not only for the Devonian shales but for all naturally fractured, multilayered, or similar shale reservoirs.

  12. Analysis of gas production methods for methane gas hydrate reservoirs

    NASA Astrophysics Data System (ADS)

    Ivakhnenko, Aleksandr; Baluanov, Bakhytzhan; Shopenova, Aigerim; Gulnur, Asan; Agzomova, Bagdagul

    2015-04-01

    In methane gas hydrate reservoir (MH), pressure and temperature conditions are in the MH stability region in the initial stage. To dissociate MH and produce gas from a MH reservoir, pressure and temperature conditions should be moved to the dissociation region. Therefore, three methods of depressurization, thermal and inhibitor injection have been modeled and analyzed as a basic methods for different conditions that might occur in nature. Furthermore, several methods such as injection of gas other than methane and irradiation of ultrasonic wave were also investigated especially for the MH dissociation and possible gas production. The simulation results allowed to select optimal screening approach for the appropriate production method that can be employed in specific MH conditions.

  13. Naturally fractured tight gas reservoir detection optimization

    SciTech Connect

    1999-06-01

    Building upon the partitioning of the Greater Green River Basin (GGRB) that was conducted last quarter, the goal of the work this quarter has been to conclude evaluation of the Stratos well and the prototypical Green River Deep partition, and perform the fill resource evaluation of the Upper Cretaceous tight gas play, with the goal of defining target areas of enhanced natural fracturing. The work plan for the quarter of November 1-December 31, 1998 comprised four tasks: (1) Evaluation of the Green River Deep partition and the Stratos well and examination of potential opportunity for expanding the use of E and P technology to low permeability, naturally fractured gas reservoirs, (2) Gas field studies, and (3) Resource analysis of the balance of the partitions.

  14. Naturally fractured tight gas reservoir detection optimization

    SciTech Connect

    1998-11-30

    The goal of the work this quarter has been to partition and high-grade the Greater Green River basin for exploration efforts in the Upper Cretaceous tight gas play and to initiate resource assessment of the basin. The work plan for the quarter of July 1-September 30, 1998 comprised three tasks: (1) Refining the exploration process for deep, naturally fractured gas reservoirs; (2) Partitioning of the basin based on structure and areas of overpressure; (3) Examination of the Kinney and Canyon Creek fields with respect to the Cretaceous tight gas play and initiation of the resource assessment of the Vermilion sub-basin partition (which contains these two fields); and (4) Initiation analysis of the Deep Green River Partition with respect to the Stratos well and assessment of the resource in the partition.

  15. Reservoir Engineering for Unconventional Gas Reservoirs: What Do We Have to Consider?

    SciTech Connect

    Clarkson, Christopher R

    2011-01-01

    The reservoir engineer involved in the development of unconventional gas reservoirs (UGRs) is required to integrate a vast amount of data from disparate sources, and to be familiar with the data collection and assessment. There has been a rapid evolution of technology used to characterize UGR reservoir and hydraulic fracture properties, and there currently are few standardized procedures to be used as guidance. Therefore, more than ever, the reservoir engineer is required to question data sources and have an intimate knowledge of evaluation procedures. We propose a workflow for the optimization of UGR field development to guide discussion of the reservoir engineer's role in the process. Critical issues related to reservoir sample and log analysis, rate-transient and production data analysis, hydraulic and reservoir modeling and economic analysis are raised. Further, we have provided illustrations of each step of the workflow using tight gas examples. Our intent is to provide some guidance for best practices. In addition to reviewing existing methods for reservoir characterization, we introduce new methods for measuring pore size distribution (small-angle neutron scattering), evaluating core-scale heterogeneity, log-core calibration, evaluating core/log data trends to assist with scale-up of core data, and modeling flow-back of reservoir fluids immediately after well stimulation. Our focus in this manuscript is on tight and shale gas reservoirs; reservoir characterization methods for coalbed methane reservoirs have recently been discussed.

  16. De Wijk gas field: Reservoir mapping with amplitude anomalies

    SciTech Connect

    Bruijn, B. )

    1993-09-01

    De Wijk field, discovered in 1949, is located in the northeastern part of Netherlands. The main gas accumulation is contained in cretaceous and Triassic sandstone reservoirs trapped in a broad salt-induced structure of around 80 km[sup 2] areal extent. The field contains gas in the tertiary, Chalk, Zechstein 2 Carbonate, and Carboniferous reservoirs as well. De Wijk field is unique in the Netherlands as most gas-producing reservoirs in the Cretaceous/Triassic are of no commercial interest. Post-depositional leaching has positively affected the reservoir properties of the Triassic formations subcropping below the Cretaceous unconformity. Optimum, interpretation of 3-D seismic data acquired in 1989 resulted in spectacular displays highlighting the uniqueness of the field. Most gas-bearing reservoirs are expressed on seismic by amplitude anomalies. Various attribute-measurement techniques show the effect of gas fill, leaching, and sand distribution in the various reservoirs.

  17. Naturally fractured tight gas reservoir detection optimization

    SciTech Connect

    1998-09-30

    During this quarter, work began on the regional structural and geologic analysis of the greater Green River basin (GGRB) in southwestern Wyoming, northwestern Colorado and northeastern Utah. The ultimate objective of the regional analysis is to apply the techniques developed and demonstrated during earlier phases of the project to sweet-spot delineation in a relatively new and underexplored play: tight gas from continuous-type Upper Cretaceous reservoirs of the GGRB. The primary goal of this work is to partition and high-grade the greater Green River basin for exploration efforts in the Cretaceous tight gas play. The work plan for the quarter of January 1, 1998--March 31, 1998 consisted of three tasks: (1) Acquire necessary data and develop base map of study area; (2) Process data for analysis; and (3) Initiate structural study. The first task and second tasks were completed during this reporting period. The third task was initiated and work continues.

  18. Mid-continent natural gas reservoirs and plays

    SciTech Connect

    Bebout, D.G. )

    1993-09-01

    Natural gas reservoirs of the mid-continent states of Oklahoma, Kansas, and Arkansas (northern part) have produced 103 trillion cubic ft (tcf) of natural gas. Oklahoma has produced the most, having a cumulative production of 71 tcf. The major reservoirs (those that have produced more than 10 billion ft[sup 3]) have been identified and organized into 28 plays based on geologic age, lithology, and depositional environment. The Atlas of Major Midcontinent Gas Reservoirs, published in 1993, provides the documentation for these plays. This atlas was a collaborative effort of the Gas Research Institute; Bureau of Economic Geology. The University of Texas at Austin; Arkansas Geological Commission; Kansas Geological survey; and Oklahoma Geological Survey. Total cumulative production for 530 major reservoirs is 66 tcf associated and nonassociated gas. Oklahoma has the highest production with 39 tcf from 390 major reservoirs, followed by Kansas with 26 tcf from 105 major reservoirs. Most of the mid-continent production is from Pennsylvanian (46%) and Permian (41%) reservoirs; Mississippian reservoirs account for 10% production, and lower Paleozoic reservoirs, 3%. The largest play by far is the Wolfcampian Shallow Shelf Carbonate-Hugoton Embayment play with 25 tcf cumulative production, most of which is from the Hugoton and Panoma fields in Kansas and Guymon-Hugoton gas area in Oklahoma. A total of 53% of the mid-continent gas production is from dolostone and limestone reservoirs; 39% is from sandstone reservoirs. The remaining 8% is from chert conglomerate and granite-wash reservoirs. Geologically based plays established from the distribution of major gas reservoirs provide important support for the extension of productive trends, application of new resource technology to more efficient field development, and further exploration in the mid-continent region.

  19. Using multi-layer models to forecast gas flow rates in tight gas reservoirs 

    E-print Network

    Jerez Vera, Sergio Armando

    2007-04-25

    The petroleum industry commonly uses single-layer models to characterize and forecast long-term production in tight gas reservoir systems. However, most tight gas reservoirs are layered systems where the permeability and ...

  20. Geologic characterization of tight gas reservoirs

    SciTech Connect

    Law, B.E.

    1990-12-01

    The objectives of US Geological Survey (USGS) work during FY 89 were to conduct geologic research characterizing tight gas-bearing sandstone reservoirs and their resources in the western United States. Our research has been regional in scope but, in some basins, our investigations have focused on single wells or small areas containing several wells where a large amount of data is available. The investigations, include structure, stratigraphy, petrography, x-ray mineralogy, source-rock evaluation, formation pressure and temperature, borehole geophysics, thermal maturity mapping, fission-track age dating, fluid-inclusion thermometry, and isotopic geochemistry. The objectives of these investigations are to provide geologic models that can be compared and utilized in tight gas-bearing sequences elsewhere. Nearly all of our work during FY 89 was devoted to developing a computer-based system for the Uinta basin and collecting, analyzing, and storage of data. The data base, when completed will contain various types of stratigraphic, organic chemistry, petrographic, production, engineering, and other information that relate to the petroleum geology of the Uinta basin, and in particular, to the tight gas-bearing strata. 16 refs., 3 figs.

  1. Layered Pseudo-Steady-State Models for tight commingled gas reservoirs 

    E-print Network

    El-Banbi, Ahmed

    1995-01-01

    commingled reservoirs' rate performance. A Layered PseudoSteady-State (PSS) Model for gas reservoirs was developed and used to analyze the ratetime data for the hypothetical commingled reservoirs. The model requires only an estimate for the initial reservoir...

  2. Measuring Greenhouse Gas Emissions From China's Reservoirs

    NASA Astrophysics Data System (ADS)

    Yang, Le; Lu, Fei; Wang, Xiaoke

    2014-01-01

    Hydroelectricity has typically been regarded as a green energy source, but reservoirs created for its generation emit greenhouse gases (GHGs) just as natural lakes and rivers do. The role of reservoirs in GHG emissions has been overlooked. Substantial amounts of methane (CH4) are emitted from reservoir surfaces every year, which account for about 20% of the total CH4 emission from inland waters. GHG emissions (transferred into carbon dioxide (CO2) equivalents) from some tropical reservoirs even exceed CO2 emissions from thermal power plants if the same amount of electricity is generated.

  3. 30 CFR 250.121 - What happens when the reservoir contains both original gas in place and injected gas?

    Code of Federal Regulations, 2011 CFR

    2011-07-01

    ... 30 Mineral Resources 2 2011-07-01 2011-07-01 false What happens when the reservoir contains both... reservoir contains both original gas in place and injected gas? If the reservoir contains both original gas in place and injected gas, when you produce gas from the reservoir you must use an...

  4. A Modified Genetic Algorithm Applied to Horizontal Well Placement Optimization in Gas Condensate Reservoirs 

    E-print Network

    Morales, Adrian

    2011-02-22

    horizontal well placement problem is optimized by using a modified Genetic Algorithm. The algorithm presented has been modified specifically for gas condensate reservoirs. Unlike oil reservoirs, the cumulative production in gas reservoirs does not vary...

  5. Naturally fractured tight gas reservoir detection optimization

    SciTech Connect

    1998-11-30

    The work plan for October 1, 1997 to September 30, 1998 consisted of investigation of a number of topical areas. These topical areas were reported in four quarterly status reports, which were submitted to DOE earlier. These topical areas are reviewed in this volume. The topical areas covered during the year were: (1) Development of preliminary tests of a production method for determining areas of natural fracturing. Advanced Resources has demonstrated that such a relationship exists in the southern Piceance basin tight gas play. Natural fracture clusters are genetically related to stress concentrations (also called stress perturbations) associated with local deformation such a faulting. The mechanical explanation of this phenomenon is that deformation generally initiates at regions where the local stress field is elevated beyond the regional. (2) Regional structural and geologic analysis of the Greater Green River Basin (GGRB). Application of techniques developed and demonstrated during earlier phases of the project for sweet-spot delineation were demonstrated in a relatively new and underexplored play: tight gas from continuous-typeUpper Cretaceous reservoirs of the Greater Green River Basin (GGRB). The effort included data acquisition/processing, base map generation, geophysical and remote sensing analysis and the integration of these data and analyses. (3) Examination of the Table Rock field area in the northern Washakie Basin of the Greater Green River Basin. This effort was performed in support of Union Pacific Resources- and DOE-planned horizontal drilling efforts. The effort comprised acquisition of necessary seismic data and depth-conversion, mapping of major fault geometry, and analysis of displacement vectors, and the development of the natural fracture prediction. (4) Greater Green River Basin Partitioning. Building on fundamental fracture characterization work and prior work performed under this contract, namely structural analysis using satellite and potential field data, the GGRB was divided into partitions that will be used to analyze the resource potential of the Frontier and Mesaverde Upper Cretaceous tight gas play. A total of 20 partitions were developed, which will be instrumental for examining the Upper Cretaceous play potential. (5) Partition Analysis. Resource assessment associated with individual partitions was initiated starting with the Vermilion Sub-basin and the Green River Deep (which include the Stratos well) partitions (see Chapter 5). (6) Technology Transfer. Tech transfer was achieved by documenting our research and presenting it at various conferences.

  6. US production of natural gas from tight reservoirs

    SciTech Connect

    Not Available

    1993-10-18

    For the purposes of this report, tight gas reservoirs are defined as those that meet the Federal Energy Regulatory Commission`s (FERC) definition of tight. They are generally characterized by an average reservoir rock permeability to gas of 0.1 millidarcy or less and, absent artificial stimulation of production, by production rates that do not exceed 5 barrels of oil per day and certain specified daily volumes of gas which increase with the depth of the reservoir. All of the statistics presented in this report pertain to wells that have been classified, from 1978 through 1991, as tight according to the FERC; i.e., they are ``legally tight`` reservoirs. Additional production from ``geologically tight`` reservoirs that have not been classified tight according to the FERC rules has been excluded. This category includes all producing wells drilled into legally designated tight gas reservoirs prior to 1978 and all producing wells drilled into physically tight gas reservoirs that have not been designated legally tight. Therefore, all gas production referenced herein is eligible for the Section 29 tax credit. Although the qualification period for the credit expired at the end of 1992, wells that were spudded (began to be drilled) between 1978 and May 1988, and from November 5, 1990, through year end 1992, are eligible for the tax credit for a subsequent period of 10 years. This report updates the EIA`s tight gas production information through 1991 and considers further the history and effect on tight gas production of the Federal Government`s regulatory and tax policy actions. It also provides some high points of the geologic background needed to understand the nature and location of low-permeability reservoirs.

  7. Horizontal Well Placement Optimization in Gas Reservoirs Using Genetic Algorithms 

    E-print Network

    Gibbs, Trevor Howard

    2011-08-08

    PLACEMENT OPTIMIZATION IN GAS RESERVOIRS USING GENETIC ALGORITHMS A Thesis by TREVOR HOWARD GIBBS Submitted to the Office of Graduate Studies of Texas A&M University in partial fulfillment of the requirements for the degree of MASTER... OF SCIENCE May 2010 Major Subject: Petroleum Engineering HORIZONTAL WELL PLACEMENT OPTIMIZATION IN GAS RESERVOIRS USING GENETIC ALGORITHMS A Thesis by TREVOR HOWARD GIBBS Submitted to the Office of Graduate Studies of Texas A...

  8. Integrated Multi-Well Reservoir and Decision Model to Determine Optimal Well Spacing in Unconventional Gas Reservoirs 

    E-print Network

    Ortiz Prada, Rubiel Paul

    2012-02-14

    Optimizing well spacing in unconventional gas reservoirs is difficult due to complex heterogeneity, large variability and uncertainty in reservoir properties, and lack of data that increase the production uncertainty. Previous methods are either...

  9. Microbial Life in an Underground Gas Storage Reservoir

    NASA Astrophysics Data System (ADS)

    Bombach, Petra; van Almsick, Tobias; Richnow, Hans H.; Zenner, Matthias; Krüger, Martin

    2015-04-01

    While underground gas storage is technically well established for decades, the presence and activity of microorganisms in underground gas reservoirs have still hardly been explored today. Microbial life in underground gas reservoirs is controlled by moderate to high temperatures, elevated pressures, the availability of essential inorganic nutrients, and the availability of appropriate chemical energy sources. Microbial activity may affect the geochemical conditions and the gas composition in an underground reservoir by selective removal of anorganic and organic components from the stored gas and the formation water as well as by generation of metabolic products. From an economic point of view, microbial activities can lead to a loss of stored gas accompanied by a pressure decline in the reservoir, damage of technical equipment by biocorrosion, clogging processes through precipitates and biomass accumulation, and reservoir souring due to a deterioration of the gas quality. We present here results from molecular and cultivation-based methods to characterize microbial communities inhabiting a porous rock gas storage reservoir located in Southern Germany. Four reservoir water samples were obtained from three different geological horizons characterized by an ambient reservoir temperature of about 45 °C and an ambient reservoir pressure of about 92 bar at the time of sampling. A complementary water sample was taken at a water production well completed in a respective horizon but located outside the gas storage reservoir. Microbial community analysis by Illumina Sequencing of bacterial and archaeal 16S rRNA genes indicated the presence of phylogenetically diverse microbial communities of high compositional heterogeneity. In three out of four samples originating from the reservoir, the majority of bacterial sequences affiliated with members of the genera Eubacterium, Acetobacterium and Sporobacterium within Clostridiales, known for their fermenting capabilities. In contrast, bacteria belonging to Enterobacteriaceae were the most frequently encountered species in the sample from the water production well. Furthermore, bacterial sequences belonging to thermophiles within the family Thermotogaceae were found in all samples investigated. Archaeal community analysis revealed the dominance of methanogens clustering with members of Methanosarcinaceae, Methanomicrobiaceae and Methanobacteriaceae in three reservoir samples and the sample from the water production well. Cultivations of water samples under an atmosphere of storage gas blended by hydrogen as electron source at in situ-like conditions (45°C, 92 bar, p(H2) = 6 bar) revealed that hydrogen was quickly consumed in all laboratory microcosms with reservoir samples. Quantitative PCR analysis of the gene encoding for methyl-coenzyme M reductase (mcrA) along with reaction educt and product analyses suggested that methanogenesis was primarily responsible for hydrogen consumption during the experiments. While it is currently in question whether or not the laboratory data can be upscaled to actual reservoir conditions, they may allude to fermenting and thermophilic bacteria playing an important role for the investigated reservoir microbiology and also indicate potential stimulation of hydrogenotrophic methanogens if hydrogen would be introduced into the reservoir.

  10. Characterization of oil and gas reservoir heterogeneity

    SciTech Connect

    Tyler, N.; Barton, M.D.; Bebout, D.G.; Fisher, R.S.; Grigsby, J.D.; Guevara, E.; Holtz, M.; Kerans, C.; Nance, H.S.; Levey, R.A.

    1992-10-01

    Research described In this report addresses the internal architecture of two specific reservoir types: restricted-platform carbonates and fluvial-deltaic sandstones. Together, these two reservoir types contain more than two-thirds of the unrecovered mobile oil remaining ill Texas. The approach followed in this study was to develop a strong understanding of the styles of heterogeneity of these reservoir types based on a detailed outcrop description and a translation of these findings into optimized recovery strategies in select subsurface analogs. Research targeted Grayburg Formation restricted-platform carbonate outcrops along the Algerita Escarpment and In Stone Canyon In southeastern New Mexico and Ferron deltaic sandstones in central Utah as analogs for the North Foster (Grayburg) and Lake Creek (Wilcox) units, respectively. In both settings, sequence-stratigraphic style profoundly influenced between-well architectural fabric and permeability structure. It is concluded that reservoirs of different depositional origins can therefore be categorized Into a heterogeneity matrix'' based on varying intensity of vertical and lateral heterogeneity. The utility of the matrix is that it allows prediction of the nature and location of remaining mobile oil. Highly stratified reservoirs such as the Grayburg, for example, will contain a large proportion of vertically bypassed oil; thus, an appropriate recovery strategy will be waterflood optimization and profile modification. Laterally heterogeneous reservoirs such as deltaic distributary systems would benefit from targeted infill drilling (possibly with horizontal wells) and improved areal sweep efficiency. Potential for advanced recovery of remaining mobile oil through heterogeneity-based advanced secondary recovery strategies In Texas is projected to be an Incremental 16 Bbbl. In the Lower 48 States this target may be as much as 45 Bbbl at low to moderate oil prices over the near- to mid-term.

  11. Modeling well performance in compartmentalized gas reservoirs 

    E-print Network

    Yusuf, Nurudeen

    2009-05-15

    -pressure function. He related q (t) / t behavior during boundary dominated flow with a parameter ?uniF020, which varies from 0.5 to 1. The ? = 1 represents the liquid case and corresponds to Arps exponential decline case. One of the limitations of Conventional... correction factor (Eq. 1.4) to convert hydrostatic-test measurement of rock compressibility to reservoir condition by accounting for reservoir boundary effects of no lateral displacement. This uni-axial correction factor depends on rock?s Poisson ratio...

  12. Characterization of oil and gas reservoir heterogeneity

    SciTech Connect

    Not Available

    1991-01-01

    The objective of the cooperative research program is to characterize Alaskan reservoirs in terms of their reserves, physical and chemical properties, geologic configuration and structure, and the development potential. The tasks completed during this period include: (1) geologic reservoir description of Endicott Field; (2) petrographic characterization of core samples taken from selected stratigraphic horizons of the West Sak and Ugnu (Brookian) wells; (3) development of a polydispersed thermodynamic model for predicting asphaltene equilibria and asphaltene precipitation from crude oil-solvent mixtures, and (4) preliminary geologic description of the Milne Point Unit.

  13. Gas content of Gladys McCall reservoir brine

    SciTech Connect

    Hayden, C.G.; Randolph, P.L.

    1987-05-29

    On October 8, 1983, after the first full day of production from Sand No.8 in the Gladys McCall well, samples of separator gas and separator brine were collected for laboratory P-V-T (pressure, volume, temperature) studies. Recombination of amounts of these samples based upon measured rates at the time of sample collection, and at reservoir temperature (290 F), revealed a bubble point pressure of 9200 psia. This is substantially below the reported reservoir pressure of 12,783 psia. The gas content of the recombined fluids was 30.19 SCF of dry gas/STB of brine. In contrast, laboratory studies indicate that 35.84 SCF of pure methane would dissolve in each STB of 95,000 mg/L sodium chloride brine. These results indicate that the reservoir brine was not saturated with natural gas. By early April, 1987, production of roughly 25 million barrels of brine had reduced calculated flowing bottomhole pressure to about 6600 psia at a brine rate of 22,000 STB/D. If the skin factor(s) were as high as 20, flowing pressure drop across the skin would still be only about 500 psi. Thus, some portion of the reservoir volume was believed to have been drawn down to below the bubble point deduced from the laboratory recombination of separator samples. When the pressure in a geopressured geothermal reservoir is reduced to below the bubble point pressure for solution gas, gas is exsolved from the brine flowing through the pores in the reservoir rock. This exsolved gas is trapped in the reservoir until the fractional gas saturation of pore volume becomes large enough for gas flow to commence through a continuous gas-filled channel. At the same time, the gas/brine ratio becomes smaller and the chemistry of the remaining solution gas changes for the brine from which gas is exsolved. A careful search was made for the changes in gas/brine ratio or solution gas chemistry that would accompany pressure dropping below the bubble point pressure. Changes of about the same magnitude as the scatter in the data appear to have occurred in mid-1985 when calculated flowing bottomhole pressure was in the range of 9400 to 9700 psi. After the amount of brine flowing through the rock near to the wellbore has exsolved enough gas for onset of gas mobility through a continuous gas-filled channel, another test for whether the reservoir is below its bubble point becomes possible. This ''bubble test'' consists of suddenly increasing flow rate so that bottomhole pressure drops. Gas expansion then results in a small portion of the free gas from near the wellbore being produced in a short period of time. The resulting ''bubble'' of gas has a higher natural gas liquids content than gas produced before and after the transient. ''Bubble tests'' were performed in February 1986 and April 1987. Neither test liberated enough additional gas to provide a detectable change in produced gas/brine ratio. However, observed small transients in Ethane/Methane and Propane/Methane ratios indicate that some free gas was produced from the near wellbore region. These results suggest that the bubble point pressure must have been in the vicinity of the calculated 9500 psi flowing bottomhole pressure during the second of 1985. They conclude that: (1) Sand No.8 in the Gladys McCall well was not saturated with natural gas at the reported initial reservoir pressure of 12,873 psia; (2) flowing bottomhole pressure became less than the bubble point pressure during 1985; and (3) bubble point pressure was in the range of 9200 to 10,000 psi.

  14. Geotechnology for low-permeability gas reservoirs, 1995

    SciTech Connect

    Brown, S.; Harstad, H.; Lorenz, J.; Warpinski, N.; Boneau, T.; Holcomb, D.; Teufel, L.; Young, C.

    1995-06-01

    The permeability, and thus the economics, of tight reservoirs are largely dependent on natural fractures, and on the in situ stresses that both originated fractures and control subsequent fracture permeability. Natural fracture permeability ultimately determines the gas (or oil) producibility from the rock matrix. Therefore, it is desirable to be able to predict, both prior to drilling and during reservoir production, (1) the natural fracture characteristics, (2) the mechanical and transport properties of fractures and the surrounding rock matrix, and (3) the present in situ stress magnitudes and orientations. The combination of activities described in this report extends the earlier work to other Rocky Mountain gas reservoirs. Additionally, it extends the fracture characterizations to attempts of crosswell geophysical fracture detection using shear wave birefringence and to obtaining detailed quantitative models of natural fracture systems for use in improved numerical reservoir simulations. Finally, the project continues collaborative efforts to evaluate and advance cost-effective methods for in situ stress measurements on core.

  15. Impes modeling of volumetric dry gas reservoirs with mobile water 

    E-print Network

    Forghany, Saeed

    2004-09-30

    .5) The derivation of the diffusivity equation for gas flow starts by substituting Darcy?s law into the continuity equation which yields the generalized density form of the diffusivity equation: 16 t = k ? ? ?? ? ?? ?•? ) µ ?... obtain ??????? ?? ? ? ?? ? ?•? z p tp p ? µ .................................................................................(2.8) If we assume that the effective permeability, k, is constant which is a very reasonable assumption for gas reservoirs...

  16. US Geological Survey publications on western tight gas reservoirs

    SciTech Connect

    Krupa, M.P.; Spencer, C.W.

    1989-02-01

    This bibliography includes reports published from 1977 through August 1988. In 1977 the US Geological Survey (USGS), in cooperation with the US Department of Energy's, (DOE), Western Gas Sands Research program, initiated a geological program to identify and characterize natural gas resources in low-permeability (tight) reservoirs in the Rocky Mountain region. These reservoirs are present at depths of less than 2,000 ft (610 m) to greater than 20,000 ft (6,100 m). Only published reports readily available to the public are included in this report. Where appropriate, USGS researchers have incorporated administrative report information into later published studies. These studies cover a broad range of research from basic research on gas origin and migration to applied studies of production potential of reservoirs in individual wells. The early research included construction of regional well-log cross sections. These sections provide a basic stratigraphic framework for individual areas and basins. Most of these sections include drill-stem test and other well-test data so that the gas-bearing reservoirs can be seen in vertical and areal dimensions. For the convenience of the reader, the publications listed in this report have been indexed by general categories of (1) authors, (2) states, (3) geologic basins, (4) cross sections, (5) maps (6) studies of gas origin and migration, (7) reservoir or mineralogic studies, and (8) other reports of a regional or specific topical nature.

  17. Integrated Hydraulic Fracture Placement and Design Optimization in Unconventional Gas Reservoirs 

    E-print Network

    Ma, Xiaodan

    2013-12-10

    Unconventional reservoir such as tight and shale gas reservoirs has the potential of becoming the main source of cleaner energy in the 21th century. Production from these reservoirs is mainly accomplished through engineered hydraulic fracturing...

  18. A wellbore/reservoir simulator for testing gas wells in high-temperature reservoirs

    SciTech Connect

    Kabir, C.S.; Hasan, A.R.; Wang, X.; Jordan, D.L.

    1996-06-01

    Gas wells frequently exhibit changing storage during a transient test because of high fluid compressibility. Further complications may arise owing to heat exchange between the wellbore fluid and the formation, especially in high-temperature reservoirs. Thus, fluid temperature changes during a transient test, thereby complicating test interpretation when surface measurements must be used in a hostile downhole environment. This paper describes the application of a wellbore/reservoir simulator. this simulator can be run in two modes. In forward modeling, the wellhead pressure, temperature, and bottomhole pressure can be computed as a function of time, given reservoir parameters and well-completion details. In contrast, reverse simulation directly translates measured wellhead pressure (WHP) and temperature (WHT) to bottomhole pressure (BHP) for subsequent analysis. Two field examples obtained from a Gulf Coast gas field are used to illustrate the capabilities of the simulators. Good agreement is noted between the computed and measured BHP`s during both types of simulations.

  19. Gas hydrate reservoir characteristics and economics

    SciTech Connect

    Bird, K.J.; Burruss, R.C.; Lee, M.W.

    1992-05-01

    The primary objective of the DOE-funded USGS Gas Hydrate Program is to assess the production characteristics and economic potential of gas hydrates in northern Alaska. The objectives of this project for FY-1992 will include the following: (1) Utilize industry seismic data to assess the distribution of gas hydrates within the nearshore Alaskan continental shelf between Harrison Bay and Prudhoe Bay; (2) Further characterize and quantify the well-log characteristics of gas hydrates; and (3) Establish gas monitoring stations over the Eileen fault zone in northern Alaska, which will be used to measure gas flux from destabilized hydrates.

  20. 30 CFR 250.1157 - How do I receive approval to produce gas-cap gas from an oil reservoir with an associated gas cap?

    Code of Federal Regulations, 2012 CFR

    2012-07-01

    ... gas from an oil reservoir with an associated gas cap? 250.1157 Section 250.1157 Mineral Resources... Production § 250.1157 How do I receive approval to produce gas-cap gas from an oil reservoir with an... producing gas-cap gas from each completion in an oil reservoir that is known to have an associated gas...

  1. 30 CFR 250.1157 - How do I receive approval to produce gas-cap gas from an oil reservoir with an associated gas cap?

    Code of Federal Regulations, 2013 CFR

    2013-07-01

    ... gas from an oil reservoir with an associated gas cap? 250.1157 Section 250.1157 Mineral Resources... Production § 250.1157 How do I receive approval to produce gas-cap gas from an oil reservoir with an... producing gas-cap gas from each completion in an oil reservoir that is known to have an associated gas...

  2. 30 CFR 250.1157 - How do I receive approval to produce gas-cap gas from an oil reservoir with an associated gas cap?

    Code of Federal Regulations, 2014 CFR

    2014-07-01

    ... gas from an oil reservoir with an associated gas cap? 250.1157 Section 250.1157 Mineral Resources... Production § 250.1157 How do I receive approval to produce gas-cap gas from an oil reservoir with an... producing gas-cap gas from each completion in an oil reservoir that is known to have an associated gas...

  3. 30 CFR 250.121 - What happens when the reservoir contains both original gas in place and injected gas?

    Code of Federal Regulations, 2012 CFR

    2012-07-01

    ...2012-07-01 false What happens when the reservoir contains both original gas in place...250.121 What happens when the reservoir contains both original gas in place and injected gas? If the reservoir contains both original gas in...

  4. 30 CFR 250.121 - What happens when the reservoir contains both original gas in place and injected gas?

    Code of Federal Regulations, 2011 CFR

    2011-07-01

    ...2011-07-01 false What happens when the reservoir contains both original gas in place...250.121 What happens when the reservoir contains both original gas in place and injected gas? If the reservoir contains both original gas in...

  5. 30 CFR 250.121 - What happens when the reservoir contains both original gas in place and injected gas?

    Code of Federal Regulations, 2010 CFR

    2010-07-01

    ...2010-07-01 false What happens when the reservoir contains both original gas in place...250.121 What happens when the reservoir contains both original gas in place and injected gas? If the reservoir contains both original gas in...

  6. 30 CFR 250.121 - What happens when the reservoir contains both original gas in place and injected gas?

    Code of Federal Regulations, 2014 CFR

    2014-07-01

    ...2014-07-01 false What happens when the reservoir contains both original gas in place...250.121 What happens when the reservoir contains both original gas in place and injected gas? If the reservoir contains both original gas in...

  7. 30 CFR 250.121 - What happens when the reservoir contains both original gas in place and injected gas?

    Code of Federal Regulations, 2013 CFR

    2013-07-01

    ...2013-07-01 false What happens when the reservoir contains both original gas in place...250.121 What happens when the reservoir contains both original gas in place and injected gas? If the reservoir contains both original gas in...

  8. Prediction of Gas Injection Performance for Heterogeneous Reservoirs

    SciTech Connect

    Blunt, Martin J.; Orr, Jr., Franklin M.

    1999-12-20

    This report describes research carried out in the Department of Petroleum Engineering at Stanford University from September 1998 - September 1998 under the third year of a three-year Department of Energy (DOE) grant on the ''Prediction of Gas Injection Performance for Heterogeneous Reservoirs''. The research effort is an integrated study of the factors affecting gas injection, from the pore scale to the field scale, and involves theoretical analysis, laboratory experiments and numerical simulation. The research is divided into four main areas: (1) Pore scale modeling of three-phase flow in porous media; (2) Laboratory experiments and analysis of factors influencing gas injection performance at the core scale with an emphasis on the fundamentals of three-phase flow; (3) Benchmark simulations of gas injection at the field scale; and (4) Development of streamline-based reservoir simulator.

  9. 30 CFR 250.1157 - How do I receive approval to produce gas-cap gas from an oil reservoir with an associated gas cap?

    Code of Federal Regulations, 2010 CFR

    2010-07-01

    ... gas from an oil reservoir with an associated gas cap? 250.1157 Section 250.1157 Mineral Resources... do I receive approval to produce gas-cap gas from an oil reservoir with an associated gas cap? (a... from each completion in an oil reservoir that is known to have an associated gas cap. (2) To...

  10. Altering Wettability in Gas Condensate Sandstone Reservoirs for Gas Mobillity Improvement 

    E-print Network

    Fernandez Martinez, Ruth Gabriela

    2012-07-16

    Christine Ehlig-Economides Committee Member, Maria Barrufet Head of Department, Steve Holditch May 2011 Major Subject: Petroleum Engineering iii? ? ? ABSTRACT Altering Wettability in Gas Condensate.... Christine Ehlig-Economides In gas-condensate reservoirs, production rate starts to decrease when retrograde condensation occurs. As the bottomhole pressure drops below the dewpoint, gas- condensate and water buildup impede flow of gas to the surface...

  11. 30 CFR 250.121 - What happens when the reservoir contains both original gas in place and injected gas?

    Code of Federal Regulations, 2012 CFR

    2012-07-01

    ... 30 Mineral Resources 2 2012-07-01 2012-07-01 false What happens when the reservoir contains both... CONTINENTAL SHELF General Performance Standards § 250.121 What happens when the reservoir contains both original gas in place and injected gas? If the reservoir contains both original gas in place and...

  12. 30 CFR 250.121 - What happens when the reservoir contains both original gas in place and injected gas?

    Code of Federal Regulations, 2010 CFR

    2010-07-01

    ... 30 Mineral Resources 2 2010-07-01 2010-07-01 false What happens when the reservoir contains both... SHELF General Performance Standards § 250.121 What happens when the reservoir contains both original gas in place and injected gas? If the reservoir contains both original gas in place and injected...

  13. 30 CFR 250.121 - What happens when the reservoir contains both original gas in place and injected gas?

    Code of Federal Regulations, 2013 CFR

    2013-07-01

    ... 30 Mineral Resources 2 2013-07-01 2013-07-01 false What happens when the reservoir contains both... CONTINENTAL SHELF General Performance Standards § 250.121 What happens when the reservoir contains both original gas in place and injected gas? If the reservoir contains both original gas in place and...

  14. 30 CFR 250.121 - What happens when the reservoir contains both original gas in place and injected gas?

    Code of Federal Regulations, 2014 CFR

    2014-07-01

    ... 30 Mineral Resources 2 2014-07-01 2014-07-01 false What happens when the reservoir contains both... CONTINENTAL SHELF General Performance Standards § 250.121 What happens when the reservoir contains both original gas in place and injected gas? If the reservoir contains both original gas in place and...

  15. Noble Gas Tracing of Fluid Transport in Shale Reservoirs

    NASA Astrophysics Data System (ADS)

    Heath, J. E.; Gardner, W. P.; Kuhlman, K. L.; Robinson, D. G.; Bauer, S. J.

    2014-12-01

    We investigate fluid transport mechanisms in a shale reservoir using natural noble gas tracers. Noble gas tracing is promising due to sensitivity of transport to: pore structure and sizes; phase partitioning between groundwater and liquid and gaseous hydrocarbons; and deformation from hydraulic fracturing and creation of surface area. A time-series of over thirty wellhead fluid samples were collected from two hydraulically-fractured wells with different oil-to-gas ratios, along with production data (i.e., flowrate and pressure). Tracer and production data sets can be combined to infer production flow regimes, to estimate reservoir transport parameters, and to improve forecasts of production decline. Sandia National Laboratories is a multi-program laboratory managed and operated by Sandia Corporation, a wholly owned subsidiary of Lockheed Martin Corporation, for the U.S. Department of Energy's National Nuclear Security Administration under contract DE-AC04-94AL85000.

  16. Calculation of hydrocarbon-in-place in gas and gas-condensate reservoirs - Carbon dioxide sequestration

    USGS Publications Warehouse

    Verma, Mahendra K.

    2012-01-01

    The Energy Independence and Security Act of 2007 (Public Law 110-140) authorized the U.S. Geological Survey (USGS) to conduct a national assessment of geologic storage resources for carbon dioxide (CO2), requiring estimation of hydrocarbon-in-place volumes and formation volume factors for all the oil, gas, and gas-condensate reservoirs within the U.S. sedimentary basins. The procedures to calculate in-place volumes for oil and gas reservoirs have already been presented by Verma and Bird (2005) to help with the USGS assessment of the undiscovered resources in the National Petroleum Reserve, Alaska, but there is no straightforward procedure available for calculating in-place volumes for gas-condensate reservoirs for the carbon sequestration project. The objective of the present study is to propose a simple procedure for calculating the hydrocarbon-in-place volume of a condensate reservoir to help estimate the hydrocarbon pore volume for potential CO2 sequestration.

  17. 30 CFR 250.1157 - How do I receive approval to produce gas-cap gas from an oil reservoir with an associated gas cap?

    Code of Federal Regulations, 2011 CFR

    2011-07-01

    ... gas from an oil reservoir with an associated gas cap? 250.1157 Section 250.1157 Mineral Resources... reservoir with an associated gas cap? (a) You must request and receive approval from the Regional Supervisor: (1) Before producing gas-cap gas from each completion in an oil reservoir that is known to have...

  18. Naturally fractured tight gas reservoir detection optimization

    SciTech Connect

    1999-04-30

    In March, work continued on characterizing probabilities for determining natural fracturing associated with the GGRB for the Upper Cretaceous tight gas plays. Structural complexity, based on potential field data and remote sensing data was completed. A resource estimate for the Frontier and Mesa Verde play was also completed. Further, work was also conducted to determine threshold economics for the play based on limited current production in the plays in the Wamsutter Ridge area. These analyses culminated in a presentation at FETC on 24 March 1999 where quantified natural fracture domains, mapped on a partition basis, which establish ''sweet spot'' probability for natural fracturing, were reviewed. That presentation is reproduced here as Appendix 1. The work plan for the quarter of January 1, 1999--March 31, 1999 comprised five tasks: (1) Evaluation of the GGRB partitions for structural complexity that can be associated with natural fractures, (2) Continued resource analysis of the balance of the partitions to determine areas with higher relative gas richness, (3) Gas field studies, (4) Threshold resource economics to determine which partitions would be the most prospective, and (5) Examination of the area around the Table Rock 4H well.

  19. Fluid and heat flow in gas-rich geothermal reservoirs

    SciTech Connect

    O'Sullivan, M.J.; Bodvarsson, G.S.; Pruess, K.; Blakeley, M.R.

    1983-07-01

    Numerical-simulation techniques are used to study the effects of noncondensible gases (CO/sub 2/) on geothermal reservoir behavior in the natural state and during exploitation. It is shown that the presence of CO/sub 2/ has large effects on the thermodynamic conditions of a reservoir in the natural state, especially on temperature distributions and phase compositions. The gas will expand two-phase zones and increase gas saturations to enable flow of CO/sub 2/ through the system. During exploitation, the early pressure drop is primarily due to degassing of the system. This process can cause a very rapid initial pressure drop, on the order of tens of bars, depending upon the initial partial pressure of CO/sub 2/. The following gas content from wells can provide information on in-place gas saturations and relative permeability curves that apply at a given geothermal resource. Site-specific studies are made for the gas-rich two-phase reservoir at the Ohaki geothermal field in New Zealand. A simple lumped-parameter model and a vertical column model are applied to the field data. The results obtained agree well with the natural thermodynamic state of the Ohaki field (pressure and temperature profiles) and a partial pressure of 15 to 25 bars is calculated in the primary reservoirs. The models also agree reasonably well with field data obtained during exploitation of the field. The treatment of thermophysical properties of H/sub 2/O-CO/sub 2/ mixtures for different phase compositions is summarized.

  20. Mechanistic Processes Controlling Gas Sorption in Shale Reservoirs

    NASA Astrophysics Data System (ADS)

    Schaef, T.; Loring, J.; Ilton, E. S.; Davidson, C. L.; Owen, T.; Hoyt, D.; Glezakou, V. A.; McGrail, B. P.; Thompson, C.

    2014-12-01

    Utilization of CO2 to stimulate natural gas production in previously fractured shale-dominated reservoirs where CO2 remains in place for long-term storage may be an attractive new strategy for reducing the cost of managing anthropogenic CO2. A preliminary analysis of capacities and potential revenues in US shale plays suggests nearly 390 tcf in additional gas recovery may be possible via CO2 driven enhanced gas recovery. However, reservoir transmissivity properties, optimum gas recovery rates, and ultimate fate of CO2 vary among reservoirs, potentially increasing operational costs and environmental risks. In this paper, we identify key mechanisms controlling the sorption of CH4 and CO2 onto phyllosilicates and processes occurring in mixed gas systems that have the potential of impacting fluid transfer and CO2 storage in shale dominated formations. Through a unique set of in situ experimental techniques coupled with molecular-level simulations, we identify structural transformations occurring to clay minerals, optimal CO2/CH4 gas exchange conditions, and distinguish between adsorbed and intercalated gases in a mixed gas system. For example, based on in situ measurements with magic angle spinning NMR, intercalation of CO2 within the montmorillonite structure occurs in CH4/CO2 gas mixtures containing low concentrations (<5 mol%) of CO2. A stable montmorillonite structure dominates during exposure to pure CH4 (90 bar), but expands upon titration of small fractions (1-3 mol%) of CO2. Density functional theory was used to quantify the difference in sorption behavior between CO2 and CH4 and indicates complex interactions occurring between hydrated cations, CH4, and CO2. The authors will discuss potential impacts of these experimental results on CO2-based hydrocarbon recovery processes.

  1. Earthquakes and depleted gas reservoirs: which comes first?

    NASA Astrophysics Data System (ADS)

    Mucciarelli, M.; Donda, F.; Valensise, G.

    2015-10-01

    While scientists are paying increasing attention to the seismicity potentially induced by hydrocarbon exploitation, so far, little is known about the reverse problem, i.e. the impact of active faulting and earthquakes on hydrocarbon reservoirs. The 20 and 29 May 2012 earthquakes in Emilia, northern Italy (Mw 6.1 and 6.0), raised concerns among the public for being possibly human-induced, but also shed light on the possible use of gas wells as a marker of the seismogenic potential of an active fold and thrust belt. We compared the location, depth and production history of 455 gas wells drilled along the Ferrara-Romagna arc, a large hydrocarbon reserve in the southeastern Po Plain (northern Italy), with the location of the inferred surface projection of the causative faults of the 2012 Emilia earthquakes and of two pre-instrumental damaging earthquakes. We found that these earthquake sources fall within a cluster of sterile wells, surrounded by productive wells at a few kilometres' distance. Since the geology of the productive and sterile areas is quite similar, we suggest that past earthquakes caused the loss of all natural gas from the potential reservoirs lying above their causative faults. To validate our hypothesis we performed two different statistical tests (binomial and Monte Carlo) on the relative distribution of productive and sterile wells, with respect to seismogenic faults. Our findings have important practical implications: (1) they may allow major seismogenic sources to be singled out within large active thrust systems; (2) they suggest that reservoirs hosted in smaller anticlines are more likely to be intact; and (3) they also suggest that in order to minimize the hazard of triggering significant earthquakes, all new gas storage facilities should use exploited reservoirs rather than sterile hydrocarbon traps or aquifers.

  2. PREDICTION OF GAS INJECTION PERFORMANCE FOR HETEROGENEOUS RESERVOIRS

    SciTech Connect

    Martin J. Blunt; Franklin M. Orr Jr

    2000-06-01

    This final report describes research carried out in the Department of Petroleum Engineering at Stanford University from September 1996--May 2000 under a three-year grant from the Department of Energy on the ''Prediction of Gas Injection Performance for Heterogeneous Reservoirs''. The advances from the research include: new tools for streamline-based simulation including the effects of gravity, changing well conditions, and compositional displacements; analytical solutions to 1D compositional displacements which can speed-up gas injection simulation still further; and modeling and experiments that delineate the physics that is unique to three-phase flow.

  3. Naturally fractured tight gas reservoir detection optimization. Final report

    SciTech Connect

    1997-11-19

    This DOE-funded research into seismic detection of natural fractures is one of six projects within the DOE`s Detection and Analysis of Naturally Fractured Gas Reservoirs Program, a multidisciplinary research initiative to develop technology for prediction, detection, and mapping of naturally fractured gas reservoirs. The demonstration of successful seismic techniques to locate subsurface zones of high fracture density and to guide drilling orientation for enhanced fracture permeability will enable better returns on investments in the development of the vast gas reserves held in tight formations beneath the Rocky Mountains. The seismic techniques used in this project were designed to capture the azimuthal anisotropy within the seismic response. This seismic anisotropy is the result of the symmetry in the rock fabric created by aligned fractures and/or unequal horizontal stresses. These results may be compared and related to other lines of evidence to provide cross-validation. The authors undertook investigations along the following lines: Characterization of the seismic anisotropy in three-dimensional, P-wave seismic data; Characterization of the seismic anisotropy in a nine-component (P- and S-sources, three-component receivers) vertical seismic profile; Characterization of the seismic anisotropy in three-dimensional, P-to-S converted wave seismic data (P-wave source, three-component receivers); and Description of geological and reservoir-engineering data that corroborate the anisotropy: natural fractures observed at the target level and at the surface, estimation of the maximum horizontal stress in situ, and examination of the flow characteristics of the reservoir.

  4. A Novel Approach For the Simulation of Multiple Flow Mechanisms and Porosities in Shale Gas Reservoirs 

    E-print Network

    Yan, Bicheng

    2013-07-15

    The state of the art of modeling fluid flow in shale gas reservoirs is dominated by dual porosity models that divide the reservoirs into matrix blocks that significantly contribute to fluid storage and fracture networks which principally control...

  5. Quantitative evaluation of oil-leg potential in gas reservoirs

    SciTech Connect

    Lisk, M.; Krieger, F.W.; Eadington, P.J.; O`Brien, G.W.

    1996-12-31

    Oil bearing fluid inclusions in sandstone represent hidden oil shows. The frequency of quartz grains containing these inclusions (GOI number) reflects maximum palaeo-oil saturation irrespective of the present fluid phase. In this way fluid inclusion data can be used to both identify palaeo-oil columns and to map original oil water contacts (OWC) in wells where oil has been displaced by later gas charge. Studies conducted on gas fields from the North West Shelf of Australia have shown that substantial oil columns were once present. Moreover, detailed GOI mapping has been used to define the location of the original OWC in these reservoirs allowing the height of the palaeo-column to be determined and an estimate to be made of original oil in place (OOIP). At Oliver-1 in the Timor Sea the reservoir is presently filled to spill with a 164m gas, and 14.5m oil, column. GOI mapping has, however, delineated a 96m thick palaeo-oil column within the gas leg. This is almost seven times thicker than the present oil leg which suggests that perhaps 170-190 million barrels of oil were displaced from this structure. In the Pepper gas field in the Carnarvon Basin GOI mapping has demonstrated the presence of a gross palaeo-oil column between 15 and 30 m thick, suggesting that between about 50 and 70 million barrels of oil has been displaced. This is more oil than that reservoired in any of the surrounding oil discoveries, which emphasizes the importance, from an exploration standpoint, of defining these remigration pathways.

  6. Quantitative evaluation of oil-leg potential in gas reservoirs

    SciTech Connect

    Lisk, M.; Krieger, F.W.; Eadington, P.J. ); O'Brien, G.W. )

    1996-01-01

    Oil bearing fluid inclusions in sandstone represent hidden oil shows. The frequency of quartz grains containing these inclusions (GOI number) reflects maximum palaeo-oil saturation irrespective of the present fluid phase. In this way fluid inclusion data can be used to both identify palaeo-oil columns and to map original oil water contacts (OWC) in wells where oil has been displaced by later gas charge. Studies conducted on gas fields from the North West Shelf of Australia have shown that substantial oil columns were once present. Moreover, detailed GOI mapping has been used to define the location of the original OWC in these reservoirs allowing the height of the palaeo-column to be determined and an estimate to be made of original oil in place (OOIP). At Oliver-1 in the Timor Sea the reservoir is presently filled to spill with a 164m gas, and 14.5m oil, column. GOI mapping has, however, delineated a 96m thick palaeo-oil column within the gas leg. This is almost seven times thicker than the present oil leg which suggests that perhaps 170-190 million barrels of oil were displaced from this structure. In the Pepper gas field in the Carnarvon Basin GOI mapping has demonstrated the presence of a gross palaeo-oil column between 15 and 30 m thick, suggesting that between about 50 and 70 million barrels of oil has been displaced. This is more oil than that reservoired in any of the surrounding oil discoveries, which emphasizes the importance, from an exploration standpoint, of defining these remigration pathways.

  7. Prediction of Gas Injection Performance for Heterogeneous Reservoirs

    SciTech Connect

    Blunt, Michael J.; Orr, Franklin M.

    1999-05-26

    This report describes research carried out in the Department of Petroleum Engineering at Stanford University from September 1996 - September 1997 under the first year of a three-year Department of Energy grant on the Prediction of Gas Injection Performance for Heterogeneous Reservoirs. The research effort is an integrated study of the factors affecting gas injection, from the pore scale to the field scale, and involves theoretical analysis, laboratory experiments and numerical simulation. The original proposal described research in four main areas; (1) Pore scale modeling of three phase flow in porous media; (2) Laboratory experiments and analysis of factors influencing gas injection performance at the core scale with an emphasis on the fundamentals of three phase flow; (3) Benchmark simulations of gas injection at the field scale; and (4) Development of streamline-based reservoir simulator. Each stage of the research is planned to provide input and insight into the next stage, such that at the end we should have an integrated understanding of the key factors affecting field scale displacements.

  8. Prediction of Gas Injection Performance for Heterogeneous Reservoirs

    SciTech Connect

    Blunt, Martin J.; Orr, Franklin M.

    1999-05-17

    This report describes research carried out in the Department of Petroleum Engineering at Stanford University from September 1997 - September 1998 under the second year of a three-year grant from the Department of Energy on the "Prediction of Gas Injection Performance for Heterogeneous Reservoirs." The research effort is an integrated study of the factors affecting gas injection, from the pore scale to the field scale, and involves theoretical analysis, laboratory experiments, and numerical simulation. The original proposal described research in four areas: (1) Pore scale modeling of three phase flow in porous media; (2) Laboratory experiments and analysis of factors influencing gas injection performance at the core scale with an emphasis on the fundamentals of three phase flow; (3) Benchmark simulations of gas injection at the field scale; and (4) Development of streamline-based reservoir simulator. Each state of the research is planned to provide input and insight into the next stage, such that at the end we should have an integrated understanding of the key factors affecting field scale displacements.

  9. 30 CFR 250.1157 - How do I receive approval to produce gas-cap gas from an oil reservoir with an associated gas cap?

    Code of Federal Regulations, 2011 CFR

    2011-07-01

    ...approval to produce gas-cap gas from an oil reservoir with an associated gas cap...DEPARTMENT OF THE INTERIOR OFFSHORE OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER CONTINENTAL SHELF Oil and Gas Production Requirements...

  10. 30 CFR 250.1157 - How do I receive approval to produce gas-cap gas from an oil reservoir with an associated gas cap?

    Code of Federal Regulations, 2013 CFR

    2013-07-01

    ...approval to produce gas-cap gas from an oil reservoir with an associated gas cap...DEPARTMENT OF THE INTERIOR OFFSHORE OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER CONTINENTAL SHELF Oil and Gas Production Requirements...

  11. 30 CFR 250.1157 - How do I receive approval to produce gas-cap gas from an oil reservoir with an associated gas cap?

    Code of Federal Regulations, 2010 CFR

    2010-07-01

    ...approval to produce gas-cap gas from an oil reservoir with an associated gas cap...DEPARTMENT OF THE INTERIOR OFFSHORE OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER CONTINENTAL SHELF Oil and Gas Production Requirements...

  12. 30 CFR 250.1157 - How do I receive approval to produce gas-cap gas from an oil reservoir with an associated gas cap?

    Code of Federal Regulations, 2014 CFR

    2014-07-01

    ...approval to produce gas-cap gas from an oil reservoir with an associated gas cap...DEPARTMENT OF THE INTERIOR OFFSHORE OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER CONTINENTAL SHELF Oil and Gas Production Requirements...

  13. 30 CFR 250.1157 - How do I receive approval to produce gas-cap gas from an oil reservoir with an associated gas cap?

    Code of Federal Regulations, 2012 CFR

    2012-07-01

    ...approval to produce gas-cap gas from an oil reservoir with an associated gas cap...DEPARTMENT OF THE INTERIOR OFFSHORE OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER CONTINENTAL SHELF Oil and Gas Production Requirements...

  14. Molecular Gas Reservoir in low-z Powerful Radio Galaxies

    NASA Astrophysics Data System (ADS)

    Lim, J.; Leon, S.; Combes, F.; Dinh-v-Trung

    Classical double-lobed radio galaxies are hosted almost exclusively by elliptical galaxies that otherwise resemble normal elliptical galaxies in both their global stellar distribution and kinematics. Given that normal elliptical galaxies usually contain undetectable quantities of neutral gas, what fuels the AGN in powerful elliptical radio galaxies? Here, we present results of a search for molecular gas in radio galaxies at z < 0.031 selected from the revised 3C catalog, comprising the most powerful radio galaxies in the Local Universe. We detected 4 of the 22 galaxies observed, with molecular gas masses ranging from about 107 - 109 Msun; the remaining galaxies were not detected at a typical upper limit of about 108 Msun. We argue that this molecular gas most likely originates from the cannibalism of secondary gas-rich galaxies by the parent elliptical galaxy, rather than the merger of two gas-rich galaxies that spawned a remnant elliptical galaxy. All the galaxies detected possess central dust disks or lanes, and exhibit very broad double-horned line profiles characteristic of a rapidly-rotating disk with an inner depression. We suggest that this molecular-gas disk comprises the gas reservoir for fueling the central supermassive black hole. Finally, we present preliminary results of a follow-up survey to better understand the mass distribution of molecular gas in powerful radio galaxies. The results thus far show that an increasing number of radio galaxies become detectable in molecular gas at lower mass limits, suggesting a broad (at least 3 orders of magnitude) distribution of molecular gas masses in powerful radio galaxies.

  15. Evaluation of Travis Peak gas reservoirs, west margin of the East Texas Basin 

    E-print Network

    Li, Yamin

    2009-05-15

    Gas production from low-permeability (tight) gas sandstones is increasingly important in the USA as conventional gas reservoirs are being depleted, and its importance will increase worldwide in future decades. Travis Peak ...

  16. Methodologies for Reservoir Characterization Using Fluid Inclusion Gas Chemistry

    SciTech Connect

    Dilley, Lorie M.

    2015-04-13

    The purpose of this project was to: 1) evaluate the relationship between geothermal fluid processes and the compositions of the fluid inclusion gases trapped in the reservoir rocks; and 2) develop methodologies for interpreting fluid inclusion gas data in terms of the chemical, thermal and hydrological properties of geothermal reservoirs. Phase 1 of this project was designed to conduct the following: 1) model the effects of boiling, condensation, conductive cooling and mixing on selected gaseous species; using fluid compositions obtained from geothermal wells, 2) evaluate, using quantitative analyses provided by New Mexico Tech (NMT), how these processes are recorded by fluid inclusions trapped in individual crystals; and 3) determine if the results obtained on individual crystals can be applied to the bulk fluid inclusion analyses determined by Fluid Inclusion Technology (FIT). Our initial studies however, suggested that numerical modeling of the data would be premature. We observed that the gas compositions, determined on bulk and individual samples were not the same as those discharged by the geothermal wells. Gases discharged from geothermal wells are CO2-rich and contain low concentrations of light gases (i.e. H2, He, N, Ar, CH4). In contrast many of our samples displayed enrichments in these light gases. Efforts were initiated to evaluate the reasons for the observed gas distributions. As a first step, we examined the potential importance of different reservoir processes using a variety of commonly employed gas ratios (e.g. Giggenbach plots). The second technical target was the development of interpretational methodologies. We have develop methodologies for the interpretation of fluid inclusion gas data, based on the results of Phase 1, geologic interpretation of fluid inclusion data, and integration of the data. These methodologies can be used in conjunction with the relevant geological and hydrological information on the system to create fluid models for the system. The hope is that the methodologies developed will allow bulk fluid inclusion gas analysis to be a useful tool for estimating relative temperatures, identifying the sources and origins of the geothermal fluids, and developing conceptual models that can be used to help target areas of enhanced permeability.

  17. Geological controls on gas accumulation in a unique Zechstein carbonate reservoir

    E-print Network

    Geological controls on gas accumulation in a unique Zechstein carbonate reservoir Craig Duguid clastic reservoir systems. Within the region, the Upper Permian Zechstein Supergroup ­ present across much hydrocarbons as an effective reservoir seal. Deep in the palaeo-basin centre, salts (anhydrite and halite

  18. Prediction of liquid hydrocarbon recovery from a gas condensate reservoir

    SciTech Connect

    Almarry, J.A.; Al-Saadoon, F.T.

    1985-03-01

    A compositional model consisting of material balance (M-B) equations and the Peng-Robinson (P-R) Equation of State (EOS), was developed starting with the work of Bergman, Tek, and Katz. The model simulates constant volume expansion (CVE) as obtained from experimental analyses of gas condensates. The contributions of this paper include the following: evaluation of the phase behavior and fluid properties for an arbitrary mixture of components, development of the material balance equations to compute depletion performance, investigation of P-R EOS as a tool for reproducing measured PVT data, and analysis of the effect of component property estimation on EOS predictions. The North Field Khaff reservoir, which is situated offshore northwest of the northern top of Qatar, and the specific K-4 reservoir description was used as the example in this work. Laboratory measurements for constant volume depletion and phase separations of a condensate fluid sample were obtained from well No. NWD 5 in the K-4 reservoir of the North Field in Qatar. This experimental data was used as a basis for comparing results from the proposed compositional model. The data analysis was carried out up to C/sub 20//sup +/ group hydrocarbons. The experimental data used for comparison with the calculated results were volume percent liquid (retrograde condensation), cumulative produced volume, molecular weight of heavy components (C/sub 7//sup +/) produced, and compressibility factor. In addition to the values calculated above constant composition expansion at different temperatures, a partial phase diagram for K-4 gas condensate, and viscosity were calculated by the model.

  19. Production Characteristics of Oceanic Natural Gas Hydrate Reservoirs

    NASA Astrophysics Data System (ADS)

    Max, M. D.; Johnson, A. H.

    2014-12-01

    Oceanic natural gas hydrate (NGH) accumulations form when natural gas is trapped thermodynamically within the gas hydrate stability zone (GHSZ), which extends downward from the seafloor in open ocean depths greater than about 500 metres. As water depths increase, the thickness of the GHSZ thickens, but economic NGH deposits probably occur no deeper than 1 km below the seafloor. Natural gas (mostly methane) appears to emanate mostly from deeper sources and migrates into the GHSZ. The natural gas crystallizes as NGH when the pressure - temperature conditions within the GHSZ are reached and when the chemical condition of dissolved gas concentration in pore water is high enough to favor crystallization. Although NGH can form in both primary and secondary porosity, the principal economic target appears to be turbidite sands on deep continental margins. Because these are very similar to the hosts of more deeply buried conventional gas and oil deposits, industry knows how to explore for them. Recent improvements in a seismic geotechnical approach to NGH identification and valuation have been confirmed by drilling in the northern Gulf of Mexico and allow for widespread exploration for NGH deposits to begin. NGH concentrations occur in the same semi-consolidated sediments in GHSZs worldwide. This provides for a narrow exploration window with low acoustic attenuation. These sediments present the same range of relatively easy drilling conditions and formation pressures that are only slightly greater than at the seafloor and are essentially equalized by water in wellbores. Expensive conventional drilling equipment is not required. NGH is the only hydrocarbon that is stable at its formation pressures and incapable of converting to gas without artificial stimulation. We suggest that specialized, NGH-specific drilling capability will offer opportunities for much less expensive drilling, more complex wellbore layouts that improve reservoir connectivity and in which gas-water separation can begin within the seafloor, and specialized production techniques. NGH is the only oceanic hydrocarbon deposit in which pressure can be controlled within the reservoir by balancing conversion and extraction. Oceanic NGH has a very low environmental risk, which also serves to distinguish it from other deepwater hydrocarbon deposits.

  20. Atlas of Northern Gulf of Mexico Gas and Oil Reservoirs: Procedures and examples of resource distribution

    SciTech Connect

    Seni, S.J.; Finley, R.J.

    1995-06-01

    The objective of the program is to produce a reservoir atlas series of the Gulf of Mexico that (1) classifies and groups offshore oil and gas reservoirs into a series of geologically defined reservoir plays, (2) compiles comprehensive reservoir play information that includes descriptive and quantitative summaries of play characteristics, cumulative production, reserves, original oil and gas in place, and various other engineering and geologic data, (3) provides detailed summaries of representative type reservoirs for each play, and (4) organizes computerized tables of reservoir engineering data into a geographic information system (GIS). The primary product of the program will be an oil and gas atlas series of the offshore Northern Gulf of Mexico and a computerized geographical information system of geologic and engineering data linked to reservoir location.

  1. Evaluating oil, gas opportunities in western Siberia; Reservoir description

    SciTech Connect

    Connelly, W. ); Krug, J.A. )

    1992-12-07

    In this article, the authors discuss how to use the subsurface data to describe hydrocarbon reservoirs and estimate the original oil in place (OOIP) in western Siberia. The methodology for describing a reservoir and estimating the OOIP in western Siberia is similar to the approach for most reservoirs: Establish stratigraphic correlations across the field; Construct structure maps on key horizons; Construct porosity isopach maps for significant reservoirs; Construct net pay maps; Determine reservoir parameters; and Calculate pore-volume estimates of OOIP.

  2. Advanced Hydraulic Fracturing Technology for Unconventional Tight Gas Reservoirs

    SciTech Connect

    Stephen Holditch; A. Daniel Hill; D. Zhu

    2007-06-19

    The objectives of this project are to develop and test new techniques for creating extensive, conductive hydraulic fractures in unconventional tight gas reservoirs by statistically assessing the productivity achieved in hundreds of field treatments with a variety of current fracturing practices ranging from 'water fracs' to conventional gel fracture treatments; by laboratory measurements of the conductivity created with high rate proppant fracturing using an entirely new conductivity test - the 'dynamic fracture conductivity test'; and by developing design models to implement the optimal fracture treatments determined from the field assessment and the laboratory measurements. One of the tasks of this project is to create an 'advisor' or expert system for completion, production and stimulation of tight gas reservoirs. A central part of this study is an extensive survey of the productivity of hundreds of tight gas wells that have been hydraulically fractured. We have been doing an extensive literature search of the SPE eLibrary, DOE, Gas Technology Institute (GTI), Bureau of Economic Geology and IHS Energy, for publicly available technical reports about procedures of drilling, completion and production of the tight gas wells. We have downloaded numerous papers and read and summarized the information to build a database that will contain field treatment data, organized by geographic location, and hydraulic fracture treatment design data, organized by the treatment type. We have conducted experimental study on 'dynamic fracture conductivity' created when proppant slurries are pumped into hydraulic fractures in tight gas sands. Unlike conventional fracture conductivity tests in which proppant is loaded into the fracture artificially; we pump proppant/frac fluid slurries into a fracture cell, dynamically placing the proppant just as it occurs in the field. From such tests, we expect to gain new insights into some of the critical issues in tight gas fracturing, in particular the roles of gel damage, polymer loading (water-frac versus gel frac), and proppant concentration on the created fracture conductivity. To achieve this objective, we have designed the experimental apparatus to conduct the dynamic fracture conductivity tests. The experimental apparatus has been built and some preliminary tests have been conducted to test the apparatus.

  3. OPTIMIZATION OF INFILL DRILLING IN NATURALLY-FRACTURED TIGHT-GAS RESERVOIRS

    SciTech Connect

    Lawrence W. Teufel; Her-Yuan Chen; Thomas W. Engler; Bruce Hart

    2004-05-01

    A major goal of industry and the U.S. Department of Energy (DOE) fossil energy program is to increase gas reserves in tight-gas reservoirs. Infill drilling and hydraulic fracture stimulation in these reservoirs are important reservoir management strategies to increase production and reserves. Phase II of this DOE/cooperative industry project focused on optimization of infill drilling and evaluation of hydraulic fracturing in naturally-fractured tight-gas reservoirs. The cooperative project involved multidisciplinary reservoir characterization and simulation studies to determine infill well potential in the Mesaverde and Dakota sandstone formations at selected areas in the San Juan Basin of northwestern New Mexico. This work used the methodology and approach developed in Phase I. Integrated reservoir description and hydraulic fracture treatment analyses were also conducted in the Pecos Slope Abo tight-gas reservoir in southeastern New Mexico and the Lewis Shale in the San Juan Basin. This study has demonstrated a methodology to (1) describe reservoir heterogeneities and natural fracture systems, (2) determine reservoir permeability and permeability anisotropy, (3) define the elliptical drainage area and recoverable gas for existing wells, (4) determine the optimal location and number of new in-fill wells to maximize economic recovery, (5) forecast the increase in total cumulative gas production from infill drilling, and (6) evaluate hydraulic fracture simulation treatments and their impact on well drainage area and infill well potential. Industry partners during the course of this five-year project included BP, Burlington Resources, ConocoPhillips, and Williams.

  4. Unconventional gas sources. Executive summary. [Coal seams, Devonian shale, geopressured brines, tight gas reservoirs

    SciTech Connect

    Not Available

    1980-12-01

    The long lead time required for conversion from oil or gas to coal and for development of a synthetic fuel industry dictates that oil and gas must continue to supply the United States with the majority of its energy requirements over the near term. In the interim period, the nation must seek a resource that can be developed quickly, incrementally, and with as few environmental concerns as possible. One option which could potentially fit these requirements is to explore for, drill, and produce unconventional gas: Devonian Shale gas, coal seam gas, gas dissolved in geopressured brines, and gas from tight reservoirs. This report addresses the significance of these sources and the economic and technical conditions under which they could be developed.

  5. Simulation of fracture fluid cleanup and its effect on long-term recovery in tight gas reservoirs 

    E-print Network

    Wang, Yilin

    2009-05-15

    In the coming decades, the world will require additional supplies of natural gas to meet the demand for energy. Tight gas reservoirs can be defined as reservoirs where the formation permeability is so low (< 0.1 md) that ...

  6. Modeling effects of diffusion and gravity drainage on oil recovery in naturally fractured reservoirs under gas injection

    E-print Network

    Jamili, Ahmad

    2010-04-22

    Gas injection in naturally fractured reservoirs maintains the reservoir pressure, and increases oil recovery primarily by gravity drainage and to a lesser extent by mass transfer between the flowing gas in the fracture and the porous matrix...

  7. Characterization of oil and gas reservoirs and recovery technology deployment on Texas State Lands

    SciTech Connect

    Tyler, R.; Major, R.P.; Holtz, M.H.

    1997-08-01

    Texas State Lands oil and gas resources are estimated at 1.6 BSTB of remaining mobile oil, 2.1 BSTB, or residual oil, and nearly 10 Tcf of remaining gas. An integrated, detailed geologic and engineering characterization of Texas State Lands has created quantitative descriptions of the oil and gas reservoirs, resulting in delineation of untapped, bypassed compartments and zones of remaining oil and gas. On Texas State Lands, the knowledge gained from such interpretative, quantitative reservoir descriptions has been the basis for designing optimized recovery strategies, including well deepening, recompletions, workovers, targeted infill drilling, injection profile modification, and waterflood optimization. The State of Texas Advanced Resource Recovery program is currently evaluating oil and gas fields along the Gulf Coast (South Copano Bay and Umbrella Point fields) and in the Permian Basin (Keystone East, Ozona, Geraldine Ford and Ford West fields). The program is grounded in advanced reservoir characterization techniques that define the residence of unrecovered oil and gas remaining in select State Land reservoirs. Integral to the program is collaboration with operators in order to deploy advanced reservoir exploitation and management plans. These plans are made on the basis of a thorough understanding of internal reservoir architecture and its controls on remaining oil and gas distribution. Continued accurate, detailed Texas State Lands reservoir description and characterization will ensure deployment of the most current and economically viable recovery technologies and strategies available.

  8. The urgency of assessing the greenhouse gas budgets of hydroelectric reservoirs in China

    NASA Astrophysics Data System (ADS)

    Hu, Yuanan; Cheng, Hefa

    2013-08-01

    Already the largest generator of hydroelectricity, China is accelerating dam construction to increase the share of hydroelectricity in its primary energy mix to reduce greenhouse gas emissions. Here, we review the evidence on emissions of GHGs, particularly methane, from the Three Gorges Reservoir, and argue that although the hydroelectric reservoirs may release large amounts of methane, they contribute significantly to greenhouse gas reduction by substitution of thermal power generation in China. Nonetheless, more systematic monitoring and modelling studies on greenhouse gas emissions from representative reservoirs are necessary to better understand the climate impact of hydropower development in China.

  9. Naturally fractured tight gas reservoir detection optimization. Quarterly report, January--March 1995

    SciTech Connect

    1995-05-01

    This report describes progress in the following five projects: (1) Geologic assessment of the Piceance Basin; (2) Regional stratigraphic studies, Upper Cretaceous Mesaverde Group, southern Piceance Basin, Colorado; (3) Structurally controlled and aligned tight gas reservoir compartmentalization in the San Juan and Piceance Basins--Foundation for a new approach to exploration and resource assessments of continuous type deposits; (4) Delineation of Piceance Basin basement structures using multiple source data--Implications for fractured reservoir exploration; and (5) Gas and water-saturated conditions in the Piceance Basin, western Colorado--Implications for fractured reservoir detection in a gas-centered coal basin.

  10. Naturally fractured tight gas - gas reservoir detection optimization. Quarterly report, June 1, 1996--September 30, 1996

    SciTech Connect

    Maxwell, J.M.; Ortoleva, P.; Payne, D.; Sibo, W.

    1996-11-15

    This document contains the status report for the Naturally Fractured Tight Gas-Gas Reservoir Detection Optimization project for the contract period 9/30/93 to 3/31/97. Data from seismic surveys are analyzed for structural imaging of reflector units. The data were stacked using the new, improved statics and normal moveout velocities. The 3-D basin modeling effort is continuing with code development. The main activities of this quarter were analysis of fluid pressure data, improved sedimentary history, lithologic unit geometry reconstruction algorithm and computer module, and further improvement, verification, and debugging of the basin stress and multi-phase reaction transport module.

  11. AVO in North of Paria, Venezuela: Gas methane versus condensate reservoirs

    SciTech Connect

    Regueiro, J.; Pena, A.

    1996-07-01

    The gas fields of North of Paria, offshore eastern Venezuela, present a unique opportunity for amplitude variations with offset (AVO) characterization of reservoirs containing different fluids: gas-condensate, gas (methane) and water (brine). AVO studies for two of the wells in the area, one with gas-condensate and the other with gas (methane) saturated reservoirs, show interesting results. Water sands and a fluid contact (condensate-water) are present in one of these wells, thus providing a control point on brine-saturated properties. The reservoirs in the second well consist of sands highly saturated with methane. Clear differences in AVO response exist between hydrocarbon-saturated reservoirs and those containing brine. However, it is also interesting that subtle but noticeable differences can be interpreted between condensate-and methane-saturated sands. These differences are attributed to differences in both in-situ fluid density and compressibility, and rock frame properties.

  12. GLOBAL GREENHOUSE GAS EMISSIONS FROM RESERVOIRS: A MATTER OF METHANE

    EPA Science Inventory

    More than a decade ago, St. Louis et al. demonstrated that, collectively, manmade reservoirs play an important role in the global balance of greenhouse gases (GHGs). To update and build upon this important seminal work, we compiled reservoir CO2, CH4, and N2O flux estimates from...

  13. Analysis of well test data from gas condensate reservoirs using single-phase dry gas methods: guidelines and examples 

    E-print Network

    Bonilla Kalil, Jose Ricardo

    1998-01-01

    -phase solution is much easier, we need not account for saturation with this approach. This thesis will provide example analyses and establish practical guidelines for the analysis and interpretation of well test data in gas condensate reservoirs, using the single...

  14. New Advances in Shale Gas Reservoir Analysis Using Water Flowback Data 

    E-print Network

    Alkouh, Ahmad

    2014-04-04

    ADVANCES IN SHALE GAS RESERVOIR ANALYSIS USING WATER FLOWBACK DATA A Dissertation by AHMAD B A O F ALKOUH Submitted to the Office of Graduate and Professional Studies of Texas A&M University in partial fulfillment of the requirements...

  15. Comparison of Various Deterministic Forecasting Techniques in Shale Gas Reservoirs with Emphasis on the Duong Method 

    E-print Network

    Joshi, Krunal Jaykant

    2012-10-19

    There is a huge demand in the industry to forecast production in shale gas reservoirs accurately. There are many methods including volumetric, Decline Curve Analysis (DCA), analytical simulation and numerical simulation. ...

  16. Production of Natural Gas and Fluid Flow in Tight Sand Reservoirs

    SciTech Connect

    Maria Cecilia Bravo

    2006-06-30

    This document reports progress of this research effort in identifying relationships and defining dependencies between macroscopic reservoir parameters strongly affected by microscopic flow dynamics and production well performance in tight gas sand reservoirs. These dependencies are investigated by identifying the main transport mechanisms at the pore scale that should affect fluids flow at the reservoir scale. A critical review of commercial reservoir simulators, used to predict tight sand gas reservoir, revealed that many are poor when used to model fluid flow through tight reservoirs. Conventional simulators ignore altogether or model incorrectly certain phenomena such as, Knudsen diffusion, electro-kinetic effects, ordinary diffusion mechanisms and water vaporization. We studied the effect of Knudsen's number in Klinkenberg's equation and evaluated the effect of different flow regimes on Klinkenberg's parameter b. We developed a model capable of explaining the pressure dependence of this parameter that has been experimentally observed, but not explained in the conventional formalisms. We demonstrated the relevance of this, so far ignored effect, in tight sands reservoir modeling. A 2-D numerical simulator based on equations that capture the above mentioned phenomena was developed. Dynamic implications of new equations are comprehensively discussed in our work and their relative contribution to the flow rate is evaluated. We performed several simulation sensitivity studies that evidenced that, in general terms, our formalism should be implemented in order to get more reliable tight sands gas reservoirs' predictions.

  17. Synthetic Seismic Study for Hydraulic Fracture in Shale-Gas Reservoirs

    NASA Astrophysics Data System (ADS)

    Xia, Y.; Li, Y.

    2014-12-01

    Many studies have been done regarding performance of hydraulically fractured horizontal wells in the Bakken Shale Play (Wiley et. al., 2004; Mille et. al., 2008; Tabatabaei et. al., 2009). It's of great interest that whether the invaded brine causes the gas shale layer to behave differently in seismic profile due to potentially important application on reservoir monitoring and management for gas shale reservoirs. Because gas shale formations are generally much thinner than their adjacent layers (usually less than 100 meters), it's usually difficult to pick the reflection wave response of gas shale layer from in-situ seismic profile. Therefore, we have designed a workflow to investigate the effects of hydraulic fracture in gas shale reservoir by using synthetic seismic survey on simplified subsurface model. The simplified model mainly consists of several horizontally homogeneous layers of sand and shale, whereas the hydraulic fracture occurs in the middle thin gas shale formation and causes brine invasion in part of it. The goal of the synthetic seismic investigation is to see how the response of the reflection wave from this layer behaves differently due to the hydraulic fracture. Due to the thickness and complex nature of shale reservoir, the greatest challenge would be to pick the seismic response of this formation from the background noise and to study the range of thickness and the depth of burial for this layer to be seismically detectable for the purpose of hydraulic fracture study. Seismic investigation is rarely used in the reservoir monitoring of gas shale reservoir due to seismic resolution limit. Thus, this study will help to explore potential seismic applications for gas shale reservoirs and improve understanding of seismic response of hydraulic fracture on unconventional reservoirs.

  18. Transient pressure analysis of fractured well in bi-zonal gas reservoirs

    NASA Astrophysics Data System (ADS)

    Zhao, Yu-Long; Zhang, Lie-Hui; Liu, Yong-hui; Hu, Shu-Yong; Liu, Qi-Guo

    2015-05-01

    For hydraulic fractured well, how to evaluate the properties of fracture and formation are always tough jobs and it is very complex to use the conventional method to do that, especially for partially penetrating fractured well. Although the source function is a very powerful tool to analyze the transient pressure for complex structure well, the corresponding reports on gas reservoir are rare. In this paper, the continuous point source functions in anisotropic reservoirs are derived on the basis of source function theory, Laplace transform method and Duhamel principle. Application of construction method, the continuous point source functions in bi-zonal gas reservoir with closed upper and lower boundaries are obtained. Sequentially, the physical models and transient pressure solutions are developed for fully and partially penetrating fractured vertical wells in this reservoir. Type curves of dimensionless pseudo-pressure and its derivative as function of dimensionless time are plotted as well by numerical inversion algorithm, and the flow periods and sensitive factors are also analyzed. The source functions and solutions of fractured well have both theoretical and practical application in well test interpretation for such gas reservoirs, especial for the well with stimulated reservoir volume around the well in unconventional gas reservoir by massive hydraulic fracturing which always can be described with the composite model.

  19. Underground natural gas storage reservoir management: Phase 2. Final report, June 1, 1995--March 30, 1996

    SciTech Connect

    Ortiz, I.; Anthony, R.V.

    1996-12-31

    Gas storage operators are facing increased and more complex responsibilities for managing storage operations under Order 636 which requires unbundling of storage from other pipeline services. Low cost methods that improve the accuracy of inventory verification are needed to optimally manage this stored natural gas. Migration of injected gas out of the storage reservoir has not been well documented by industry. The first portion of this study addressed the scope of unaccounted for gas which may have been due to migration. The volume range was estimated from available databases and reported on an aggregate basis. Information on working gas, base gas, operating capacity, injection and withdrawal volumes, current and non-current revenues, gas losses, storage field demographics and reservoir types is contained among the FERC Form 2, EIA Form 191, AGA and FERC Jurisdictional databases. The key elements of this study show that gas migration can result if reservoir limits have not been properly identified, gas migration can occur in formation with extremely low permeability (0.001 md), horizontal wellbores can reduce gas migration losses and over-pressuring (unintentionally) storage reservoirs by reinjecting working gas over a shorter time period may increase gas migration effects.

  20. Visco-plastic properties of organic-rich shale gas reservoir rocks and its implication for stress variations within reservoirs

    NASA Astrophysics Data System (ADS)

    Sone, H.; Zoback, M. D.

    2011-12-01

    We are studying the time-dependent deformational properties of shale gas reservoir rocks through laboratory creep experiments in a triaxial deformation apparatus under room temperature and room humidity conditions. Samples come from the Barnett shale (TX), Eagle Ford shale (TX), Haynesville shale (LA), and Fort St. John shale (Canada). The clay and carbonate content of these shales vary markedly, as well as the total organic content. To cover effective pressures both below and above in-situ conditions, confining pressures were between 10-60 MPa. In order to examine creep processes unrelated to pre-failure crack growth, differential stresses during creep were kept below 50% of the ultimate rock strength. Time dependent creep at constant differential stress increases with clay content (regardless of the carbonate content) and there is a pronounced increase in amount of creep at around 35-40% clay content. The amount of creep strain is relatively insensitive to both the confining pressure and differential pressure. More creep occurs in the bedding-perpendicular direction than the bedding-parallel direction, which correlates with the sample's elastic anisotropy. The constitutive law governing the time-dependent deformation of these rocks is visco-plastic, and creep strain is well-approximated by a power-law function of time within the time scales of the experiment (maximum of 2 weeks). Also an oven-dried sample exhibited much less creep, which suggests that the physical mechanism of the creep is likely a hydrolytically-assisted plastic deformation process. Interpretation of the results through visco-elastic theory shows that the power law exponents of these rocks, which reflects how rapid a rock creeps or relaxes stress, vary between 0.01-0.07. Based on these numbers, we can roughly calculate the visco-elastic accumulation of differential stresses within these reservoirs, by assuming a constant intraplate tectonic strain rate (10^-19 - 10^-17) and by considering the ages of these rocks (100-350 Ma). Results suggest that the current intra-reservoir contrast of differential stresses can become as high as tens of MPa. Such prediction is consistent with the occurence of drilling-induced tensile fractures (DITFs) observed in a vertical well from Barnett shale where DITFs appear and disappear corresponding to the intra-reservoir lithological variation. It is important to characterize such stress variations within a reservoir since production from shale gas reservoirs heavily relies on reservoir stimulation by hydraulic fracturing and in-situ stress is a major control on the outcomes of such operations.

  1. Study of Multi-scale Transport Phenomena in Tight Gas and Shale Gas Reservoir Systems 

    E-print Network

    Freeman, Craig Matthew

    2013-11-25

    will then be validated against core analyses and experiments, and surface flowing gas composition data. Finally the numerical model will be used to generate a model-based analysis technique with the aim of reducing uncertainty in reservoir characteristics. 1... are not analogous to those of coal (Schettler and Parmely 1991). The Langmuir model was based on the theory described above. In its application to desorption in shales and coal, it has been treated as semi-empirically, where the two values of the parameters...

  2. Appraisal of transport and deformation in shale reservoirs using natural noble gas tracers

    SciTech Connect

    Heath, Jason E.; Kuhlman, Kristopher L.; Robinson, David G.; Bauer, Stephen J.; Gardner, William Payton

    2015-09-01

    This report presents efforts to develop the use of in situ naturally-occurring noble gas tracers to evaluate transport mechanisms and deformation in shale hydrocarbon reservoirs. Noble gases are promising as shale reservoir diagnostic tools due to their sensitivity of transport to: shale pore structure; phase partitioning between groundwater, liquid, and gaseous hydrocarbons; and deformation from hydraulic fracturing. Approximately 1.5-year time-series of wellhead fluid samples were collected from two hydraulically-fractured wells. The noble gas compositions and isotopes suggest a strong signature of atmospheric contribution to the noble gases that mix with deep, old reservoir fluids. Complex mixing and transport of fracturing fluid and reservoir fluids occurs during production. Real-time laboratory measurements were performed on triaxially-deforming shale samples to link deformation behavior, transport, and gas tracer signatures. Finally, we present improved methods for production forecasts that borrow statistical strength from production data of nearby wells to reduce uncertainty in the forecasts.

  3. Natural gas plays in Jurassic reservoirs of southwestern Alabama and the Florida panhandle area

    SciTech Connect

    Mancini, E.A. Univ. of Alabama, Tuscaloosa ); Mink, R.M.; Tew, B.H.; Bearden, B.L. )

    1990-09-01

    Three Jurassic natural gas trends can be delineated in Alabama and the Florida panhandle area. They include a deep natural gas trend, a natural gas and condensate trend, and an oil and associated natural gas trend. These trends are recognized by hydrocarbon types, basinal position, and relationship to regional structural features. Within these natural gas trends, at least eight distinct natural gas plays can be identified. These plays are recognized by characteristic petroleum traps and reservoirs. The deep natural gas trend includes the Mobile Bay area play, which is characterized by faulted salt anticlines associated with the Lower Mobile Bay fault system and Norphlet eolian sandstone reservoirs exhibiting primary and secondary porosity at depths exceeding 20,000 ft. The natural gas and condensate trend includes the Mississippi Interior Salt basin play, Mobile graben play, Wiggins arch flank play, and the Pollard fault system play. The Mississippi Interior Salt basin play is typified by salt anticlines associated with salt tectonism in the Mississippi Interior Salt basin and Smackover dolomitized peloidal and pelmoldic grainstone and packstone reservoirs at depths of approximately 16,000 ft. The Mobile graben play is exemplified by faulted salt anticlines associated with the Mobile graben and Smackover dolostone reservoirs at depths of approximately 18,000 ft. The Wiggins arch flank play is characterized by structural traps consisting of salt anticlines associated with stratigraphic thinning and Smackover dolostone reservoirs at depths of approximately 18,000 ft. The Pollard fault system play is typified by combination petroleum traps. The structural component is associated with the Pollard fault system and reservoirs at depths of approximately 15,000 ft. These reservoirs are dominantly Smackover dolomitized oomoldic and pelmoldic grainstones and packstones and Norphlet marine, eolian, and wadi sandstones exhibiting primary and secondary porosity.

  4. Numerical simulation of the environmental impact of hydraulic fracturing of tight/shale gas reservoirs on near-surface groundwater: Background, base cases, shallow reservoirs, short-term gas, and water transport

    SciTech Connect

    Reagan, Matthew T.; Moridis, George J.; Keen, Noel D.; Johnson, Jeffrey N.

    2015-04-18

    Hydrocarbon production from unconventional resources and the use of reservoir stimulation techniques, such as hydraulic fracturing, has grown explosively over the last decade. However, concerns have arisen that reservoir stimulation creates significant environmental threats through the creation of permeable pathways connecting the stimulated reservoir with shallower freshwater aquifers, thus resulting in the contamination of potable groundwater by escaping hydrocarbons or other reservoir fluids. This study investigates, by numerical simulation, gas and water transport between a shallow tight-gas reservoir and a shallower overlying freshwater aquifer following hydraulic fracturing operations, if such a connecting pathway has been created. We focus on two general failure scenarios: (1) communication between the reservoir and aquifer via a connecting fracture or fault and (2) communication via a deteriorated, preexisting nearby well. We conclude that the key factors driving short-term transport of gas include high permeability for the connecting pathway and the overall volume of the connecting feature. Production from the reservoir is likely to mitigate release through reduction of available free gas and lowering of reservoir pressure, and not producing may increase the potential for release. We also find that hydrostatic tight-gas reservoirs are unlikely to act as a continuing source of migrating gas, as gas contained within the newly formed hydraulic fracture is the primary source for potential contamination. Such incidents of gas escape are likely to be limited in duration and scope for hydrostatic reservoirs. Reliable field and laboratory data must be acquired to constrain the factors and determine the likelihood of these outcomes.

  5. Numerical simulation of the environmental impact of hydraulic fracturing of tight/shale gas reservoirs on near-surface groundwater: Background, base cases, shallow reservoirs, short-term gas, and water transport

    NASA Astrophysics Data System (ADS)

    Reagan, Matthew T.; Moridis, George J.; Keen, Noel D.; Johnson, Jeffrey N.

    2015-04-01

    Hydrocarbon production from unconventional resources and the use of reservoir stimulation techniques, such as hydraulic fracturing, has grown explosively over the last decade. However, concerns have arisen that reservoir stimulation creates significant environmental threats through the creation of permeable pathways connecting the stimulated reservoir with shallower freshwater aquifers, thus resulting in the contamination of potable groundwater by escaping hydrocarbons or other reservoir fluids. This study investigates, by numerical simulation, gas and water transport between a shallow tight-gas reservoir and a shallower overlying freshwater aquifer following hydraulic fracturing operations, if such a connecting pathway has been created. We focus on two general failure scenarios: (1) communication between the reservoir and aquifer via a connecting fracture or fault and (2) communication via a deteriorated, preexisting nearby well. We conclude that the key factors driving short-term transport of gas include high permeability for the connecting pathway and the overall volume of the connecting feature. Production from the reservoir is likely to mitigate release through reduction of available free gas and lowering of reservoir pressure, and not producing may increase the potential for release. We also find that hydrostatic tight-gas reservoirs are unlikely to act as a continuing source of migrating gas, as gas contained within the newly formed hydraulic fracture is the primary source for potential contamination. Such incidents of gas escape are likely to be limited in duration and scope for hydrostatic reservoirs. Reliable field and laboratory data must be acquired to constrain the factors and determine the likelihood of these outcomes.

  6. Advancing New 3D Seismic Interpretation Methods for Exploration and Development of Fractured Tight Gas Reservoirs

    SciTech Connect

    James Reeves

    2005-01-31

    In a study funded by the U.S. Department of Energy and GeoSpectrum, Inc., new P-wave 3D seismic interpretation methods to characterize fractured gas reservoirs are developed. A data driven exploratory approach is used to determine empirical relationships for reservoir properties. Fractures are predicted using seismic lineament mapping through a series of horizon and time slices in the reservoir zone. A seismic lineament is a linear feature seen in a slice through the seismic volume that has negligible vertical offset. We interpret that in regions of high seismic lineament density there is a greater likelihood of fractured reservoir. Seismic AVO attributes are developed to map brittle reservoir rock (low clay) and gas content. Brittle rocks are interpreted to be more fractured when seismic lineaments are present. The most important attribute developed in this study is the gas sensitive phase gradient (a new AVO attribute), as reservoir fractures may provide a plumbing system for both water and gas. Success is obtained when economic gas and oil discoveries are found. In a gas field previously plagued with poor drilling results, four new wells were spotted using the new methodology and recently drilled. The wells have estimated best of 12-months production indicators of 2106, 1652, 941, and 227 MCFGPD. The latter well was drilled in a region of swarming seismic lineaments but has poor gas sensitive phase gradient (AVO) and clay volume attributes. GeoSpectrum advised the unit operators that this location did not appear to have significant Lower Dakota gas before the well was drilled. The other three wells are considered good wells in this part of the basin and among the best wells in the area. These new drilling results have nearly doubled the gas production and the value of the field. The interpretation method is ready for commercialization and gas exploration and development. The new technology is adaptable to conventional lower cost 3D seismic surveys.

  7. Characterization of oil and gas reservoir heterogeneity. Final report

    SciTech Connect

    Tyler, N.; Barton, M.D.; Bebout, D.G.; Fisher, R.S.; Grigsby, J.D.; Guevara, E.; Holtz, M.; Kerans, C.; Nance, H.S.; Levey, R.A.

    1992-10-01

    Research described In this report addresses the internal architecture of two specific reservoir types: restricted-platform carbonates and fluvial-deltaic sandstones. Together, these two reservoir types contain more than two-thirds of the unrecovered mobile oil remaining ill Texas. The approach followed in this study was to develop a strong understanding of the styles of heterogeneity of these reservoir types based on a detailed outcrop description and a translation of these findings into optimized recovery strategies in select subsurface analogs. Research targeted Grayburg Formation restricted-platform carbonate outcrops along the Algerita Escarpment and In Stone Canyon In southeastern New Mexico and Ferron deltaic sandstones in central Utah as analogs for the North Foster (Grayburg) and Lake Creek (Wilcox) units, respectively. In both settings, sequence-stratigraphic style profoundly influenced between-well architectural fabric and permeability structure. It is concluded that reservoirs of different depositional origins can therefore be categorized Into a ``heterogeneity matrix`` based on varying intensity of vertical and lateral heterogeneity. The utility of the matrix is that it allows prediction of the nature and location of remaining mobile oil. Highly stratified reservoirs such as the Grayburg, for example, will contain a large proportion of vertically bypassed oil; thus, an appropriate recovery strategy will be waterflood optimization and profile modification. Laterally heterogeneous reservoirs such as deltaic distributary systems would benefit from targeted infill drilling (possibly with horizontal wells) and improved areal sweep efficiency. Potential for advanced recovery of remaining mobile oil through heterogeneity-based advanced secondary recovery strategies In Texas is projected to be an Incremental 16 Bbbl. In the Lower 48 States this target may be as much as 45 Bbbl at low to moderate oil prices over the near- to mid-term.

  8. Geology, reservoir engineering and methane hydrate potential of the Walakpa Gas Field, North Slope, Alaska

    SciTech Connect

    Glenn, R.K.; Allen, W.W.

    1992-12-01

    The Walakpa Gas Field, located near the city of Barrow on Alaska's North Slope, has been proven to be methane-bearing at depths of 2000--2550 feet below sea level. The producing formation is a laterally continuous, south-dipping, Lower Cretaceous shelf sandstone. The updip extent of the reservoir has not been determined by drilling, but probably extends to at least 1900 feet below sea level. Reservoir temperatures in the updip portion of the reservoir may be low enough to allow the presence of in situ methane hydrates. Reservoir net pay however, decreases to the north. Depths to the base of permafrost in the area average 940 feet. Drilling techniques and production configuration in the Walakpa field were designed to minimize formation damage to the reservoir sandstone and to eliminate methane hydrates formed during production. Drilling development of the Walakpa field was a sequential updip and lateral stepout from a previously drilled, structurally lower confirmation well. Reservoir temperature, pressure, and gas chemistry data from the development wells confirm that they have been drilled in the free-methane portion of the reservoir. Future studies in the Walakpa field are planned to determine whether or not a component of the methane production is due to the dissociation of updip in situ hydrates.

  9. Variations in dissolved gas compositions of reservoir fluids from the Coso geothermal field

    SciTech Connect

    Williams, Alan E.; Copp, John F.

    1991-01-01

    Gas concentrations and ratios in 110 analyses of geothermal fluids from 47 wells in the Coso geothermal system illustrate the complexity of this two-phase reservoir in its natural state. Two geographically distinct regions of single-phase (liquid) reservoir are present and possess distinctive gas and liquid compositions. Relationships in soluble and insoluble gases preclude derivation of these waters from a common parent by boiling or condensation alone. These two regions may represent two limbs of fluid migration away from an area of two-phase upwelling. During migration, the upwelling fluids mix with chemically evolved waters of moderately dissimilar composition. CO{sub 2} rich fluids found in the limb in the southeastern portion of the Coso field are chemically distinct from liquids in the northern limb of the field. Steam-rich portions of the reservoir also indicate distinctive gas compositions. Steam sampled from wells in the central and southwestern Coso reservoir is unusually enriched in both H{sub 2}S and H{sub 2}. Such a large enrichment in both a soluble and insoluble gas cannot be produced by boiling of any liquid yet observed in single-phase portions of the field. In accord with an upflow-lateral mixing model for the Coso field, at least three end-member thermal fluids having distinct gas and liquid compositions appear to have interacted (through mixing, boiling and steam migration) to produce the observed natural state of the reservoir.

  10. Results of high resolution seismic imaging experiments for defining permeable pathways in fractured gas reservoirs

    SciTech Connect

    Majer, E.L.; Peterson, J.E.; Daley, T.

    1997-10-01

    As part of its Department of Energy (DOE) Industry cooperative program in oil and gas, Berkeley Lab has an ongoing effort in cooperation with Industry partners to develop equipment, field techniques, and interpretational methods to further the practice of characterizing fractured heterogeneous reservoirs. The goal of this work is to demonstrate the combined use of state-of-the-art technology in fluid flow modeling and geophysical imaging into an interdisciplinary approach for predicting the behavior of heterogeneous fractured gas reservoirs. The efforts in this program have mainly focused on using seismic methods linked with geologic and reservoir engineering analysis for the detection and characterization of fracture systems in tight gas formations, i.e., where and how to detect the fractures, what are the characteristics of the fractures, and how the fractures interact with the natural stresses, lithology, and their effect on reservoir performance. The project has also integrated advanced reservoir engineering methods for analyzing flow in fractured systems such that reservoir management strategies can be optimized. The work at Berkeley Lab focuses on integrating high resolution seismic imaging, (VSP, crosswell, and single well imaging), geologic information and well test data to invert for flow paths in fractured systems.

  11. Production of Natural Gas and Fluid Flow in Tight Sand Reservoirs

    SciTech Connect

    Maria Cecilia Bravo; Mariano Gurfinkel

    2005-06-30

    This document reports progress of this research effort in identifying possible relationships and defining dependencies between macroscopic reservoir parameters strongly affected by microscopic flow dynamics and production well performance in tight gas sand reservoirs. Based on a critical review of the available literature, a better understanding of the main weaknesses of the current state of the art of modeling and simulation for tight sand reservoirs has been reached. Progress has been made in the development and implementation of a simple reservoir simulator that is still able to overcome some of the deficiencies detected. The simulator will be used to quantify the impact of microscopic phenomena in the macroscopic behavior of tight sand gas reservoirs. Phenomena such as, Knudsen diffusion, electro-kinetic effects, ordinary diffusion mechanisms and water vaporization are being considered as part of this study. To date, the adequate modeling of gas slippage in porous media has been determined to be of great relevance in order to explain unexpected fluid flow behavior in tight sand reservoirs.

  12. Spatial and Temporal Variations in Greenhouse Gas Emissions from an Agricultural Reservoir

    NASA Astrophysics Data System (ADS)

    Smolenski, R. L.; Beaulieu, J.; Townsend-Small, A.; Nietch, C.

    2012-12-01

    Reservoirs are being built at an increasing rate each year to provide humans with resources such as hydroelectric power and drinking water. These man-made systems have provided society with important services, but these have come at the cost of enhanced greenhouse gas (GHG) emissions. Recent estimates suggest reservoirs are a globally significant source of GHG emissions, but these estimates are largely based on studies of oligotrophic boreal and tropical reservoirs. Reservoirs draining agricultural basins are common throughout much of the developed world and are subject to high nutrient loading rates from the watershed. Excess nutrient loading stimulates algae blooms and degrades water quality in these reservoirs, but surprisingly little is known about how nutrients and algal blooms affect GHG dynamics. To assess GHG dynamics in an agricultural reservoir we measured GHG emission rates, dissolved concentrations, and nutrient chemistry in William H. Harsha Lake, an agricultural reservoir located in southwestern Ohio (USA), on a monthly basis since October, 2011. Dissolved N2O was negatively related to nitrate (r2=.91, p<0.001) in October 2011, suggesting denitrification was an important source of N2O in the reservoir during fall turnover. Relationships between dissolved N2O and nitrate concentrations were inconsistent during the winter and spring, suggesting nitrate was not limited during these seasons. There was no consistent pattern in dissolved gas concentrations across the length of the reservoir, but concentrations were greater in hypolimnetic than eplimnetic waters during warmer months. The highest N2O and CH4 emissions occurred during lake turn over in the fall (CH4 flux= 4.76E+1 mg CH4 hr-1m-2, N2O flux= 9.24E+1 ?g N2O-N hr-1m-2, and CO2 flux = 8.62E+2 mg CO2 hr-1m-2), while the lowest emission rates were observed during the winter. We found no clear spatial pattern in GHG emission rates across the length of the reservoir. On an annual basis, we estimate the reservoir emits 1.52E+6 kg CH4-C/yr, equivalent to ~11,000 head of dairy cattle. On a per unit area basis, the reservoir was a hotspot of N2O emissions compared to the surrounding agricultural land; however, total annual N2O emissions from the reservoir (3.00E+3 kg N2O-N/yr) constitute only 1% of total watershed N2O emissions due to the much greater area of agricultural lands.

  13. Mesozoic (Upper Jurassic-Lower Cretaceous) deep gas reservoir play, central and eastern Gulf coastal plain

    USGS Publications Warehouse

    Mancini, E.A.; Li, P.; Goddard, D.A.; Ramirez, V.O.; Talukdar, S.C.

    2008-01-01

    The Mesozoic (Upper Jurassic-Lower Cretaceous) deeply buried gas reservoir play in the central and eastern Gulf coastal plain of the United States has high potential for significant gas resources. Sequence-stratigraphic study, petroleum system analysis, and resource assessment were used to characterize this developing play and to identify areas in the North Louisiana and Mississippi Interior salt basins with potential for deeply buried gas reservoirs. These reservoir facies accumulated in Upper Jurassic to Lower Cretaceous Norphlet, Haynesville, Cotton Valley, and Hosston continental, coastal, and marine siliciclastic environments and Smackover and Sligo nearshore marine shelf, ramp, and reef carbonate environments. These Mesozoic strata are associated with transgressive and regressive systems tracts. In the North Louisiana salt basin, the estimate of secondary, nonassociated thermogenic gas generated from thermal cracking of oil to gas in the Upper Jurassic Smackover source rocks from depths below 3658 m (12,000 ft) is 4800 tcf of gas as determined using software applications. Assuming a gas expulsion, migration, and trapping efficiency of 2-3%, 96-144 tcf of gas is potentially available in this basin. With some 29 tcf of gas being produced from the North Louisiana salt basin, 67-115 tcf of in-place gas remains. Assuming a gas recovery factor of 65%, 44-75 tcf of gas is potentially recoverable. The expelled thermogenic gas migrated laterally and vertically from the southern part of this basin to the updip northern part into shallower reservoirs to depths of up to 610 m (2000 ft). Copyright ?? 2008. The American Association of Petroleum Geologists. All rights reserved.

  14. Gas Flow Tightly Coupled to Elastoplastic Geomechanics for Tight- and Shale-Gas Reservoirs: Material Failure and Enhanced Permeability

    SciTech Connect

    Kim, Jihoon; Moridis, George

    2014-12-01

    We investigate coupled flow and geomechanics in gas production from extremely low permeability reservoirs such as tight and shale gas reservoirs, using dynamic porosity and permeability during numerical simulation. In particular, we take the intrinsic permeability as a step function of the status of material failure, and the permeability is updated every time step. We consider gas reservoirs with the vertical and horizontal primary fractures, employing the single and dynamic double porosity (dual continuum) models. We modify the multiple porosity constitutive relations for modeling the double porous continua for flow and geomechanics. The numerical results indicate that production of gas causes redistribution of the effective stress fields, increasing the effective shear stress and resulting in plasticity. Shear failure occurs not only near the fracture tips but also away from the primary fractures, which indicates generation of secondary fractures. These secondary fractures increase the permeability significantly, and change the flow pattern, which in turn causes a change in distribution of geomechanical variables. From various numerical tests, we find that shear failure is enhanced by a large pressure drop at the production well, high Biot's coefficient, low frictional and dilation angles. Smaller spacing between the horizontal wells also contributes to faster secondary fracturing. When the dynamic double porosity model is used, we observe a faster evolution of the enhanced permeability areas than that obtained from the single porosity model, mainly due to a higher permeability of the fractures in the double porosity model. These complicated physics for stress sensitive reservoirs cannot properly be captured by the uncoupled or flow-only simulation, and thus tightly coupled flow and geomechanical models are highly recommended to accurately describe the reservoir behavior during gas production in tight and shale gas reservoirs and to smartly design production scenarios.

  15. Numerical simulation of the environmental impact of hydraulic fracturing of tight/shale gas reservoirs on near-surface groundwater: Background, base cases, shallow reservoirs, short-term gas, and water transport

    PubMed Central

    Reagan, Matthew T; Moridis, George J; Keen, Noel D; Johnson, Jeffrey N

    2015-01-01

    Hydrocarbon production from unconventional resources and the use of reservoir stimulation techniques, such as hydraulic fracturing, has grown explosively over the last decade. However, concerns have arisen that reservoir stimulation creates significant environmental threats through the creation of permeable pathways connecting the stimulated reservoir with shallower freshwater aquifers, thus resulting in the contamination of potable groundwater by escaping hydrocarbons or other reservoir fluids. This study investigates, by numerical simulation, gas and water transport between a shallow tight-gas reservoir and a shallower overlying freshwater aquifer following hydraulic fracturing operations, if such a connecting pathway has been created. We focus on two general failure scenarios: (1) communication between the reservoir and aquifer via a connecting fracture or fault and (2) communication via a deteriorated, preexisting nearby well. We conclude that the key factors driving short-term transport of gas include high permeability for the connecting pathway and the overall volume of the connecting feature. Production from the reservoir is likely to mitigate release through reduction of available free gas and lowering of reservoir pressure, and not producing may increase the potential for release. We also find that hydrostatic tight-gas reservoirs are unlikely to act as a continuing source of migrating gas, as gas contained within the newly formed hydraulic fracture is the primary source for potential contamination. Such incidents of gas escape are likely to be limited in duration and scope for hydrostatic reservoirs. Reliable field and laboratory data must be acquired to constrain the factors and determine the likelihood of these outcomes. Key Points: Short-term leakage fractured reservoirs requires high-permeability pathways Production strategy affects the likelihood and magnitude of gas release Gas release is likely short-term, without additional driving forces

  16. Developing a tight gas sand advisor for completion and stimulation in tight gas reservoirs worldwide 

    E-print Network

    Bogatchev, Kirill Y.

    2009-05-15

    while completing and stimulating TGS reservoirs. The modules include Perforation Selection and Proppant Selection. Based on input well/reservoir parameters these subroutines provide unambiguous recommendations concerning which perforation strategy(s...

  17. CONCEPTUAL MODEL FOR ORIGIN OF ABNORMALLY PRESSURED GAS ACCUMULATIONS IN LOW-PERMEABILITY RESERVOIRS.

    USGS Publications Warehouse

    Law, B.E.; Dickinson, W.W.

    1985-01-01

    The paper suggests that overpressured and underpressured gas accumulations of this type have a common origin. In basins containing overpressured gas accumulations, rates of thermogenic gas accumulation exceed gas loss, causing fluid (gas) pressure to rise above the regional hydrostatic pressure. Free water in the larger pores is forced out of the gas generation zone into overlying and updip, normally pressured, water-bearing rocks. While other diagenetic processes continue, a pore network with very low permeability develops. As a result, gas accumulates in these low-permeability reservoirs at rates higher than it is lost. In basins containing underpressured gas accumulations, rates of gas generation and accumulation are less than gas loss. The basin-center gas accumulation persists, but because of changes in the basin dynamics, the overpressured accumulation evolves into an underpressured system.

  18. New inflow performance relationships for gas condensate reservoirs 

    E-print Network

    Del Castillo Maravi, Yanil

    2004-09-30

    trends for Case 1? Lean gas condensate performance trends........................ 31 3.1 Dimensionless IPR trends for Case 16? gas condensate and dry gas performance trends...)..................................................... 41 3.6 ? g versus N/G and molecular weight of the mixture (Mmixture)..................................................... 42 3.7 Variation of dimensionless IPR shape with the ? o and ? g parameters......................................... 43 3...

  19. Molecular Gas Reservoir in low-z Powerful Radio Galaxies

    E-print Network

    Jeremy Lim; Stephane Leon; Francoise Combes; Dinh-V-Trung

    2002-11-13

    We report a survey for molecular gas in 3C radio galaxies at redshifts z < 0.031. Four of the twenty-three galaxies observed were detected with molecular gas masses in the range 10^7--10^9 Msun. The remainder had typical upper limits in molecular gas masses of ~10^8 Msun.

  20. Modeling of Gas Production from Shale Reservoirs Considering Multiple Transport Mechanisms

    PubMed Central

    Guo, Chaohua; Wei, Mingzhen; Liu, Hong

    2015-01-01

    Gas transport in unconventional shale strata is a multi-mechanism-coupling process that is different from the process observed in conventional reservoirs. In micro fractures which are inborn or induced by hydraulic stimulation, viscous flow dominates. And gas surface diffusion and gas desorption should be further considered in organic nano pores. Also, the Klinkenberg effect should be considered when dealing with the gas transport problem. In addition, following two factors can play significant roles under certain circumstances but have not received enough attention in previous models. During pressure depletion, gas viscosity will change with Knudsen number; and pore radius will increase when the adsorption gas desorbs from the pore wall. In this paper, a comprehensive mathematical model that incorporates all known mechanisms for simulating gas flow in shale strata is presented. The objective of this study was to provide a more accurate reservoir model for simulation based on the flow mechanisms in the pore scale and formation geometry. Complex mechanisms, including viscous flow, Knudsen diffusion, slip flow, and desorption, are optionally integrated into different continua in the model. Sensitivity analysis was conducted to evaluate the effect of different mechanisms on the gas production. The results showed that adsorption and gas viscosity change will have a great impact on gas production. Ignoring one of following scenarios, such as adsorption, gas permeability change, gas viscosity change, or pore radius change, will underestimate gas production. PMID:26657698

  1. Radon in unconventional natural gas from gulf coast geopressured-geothermal reservoirs

    USGS Publications Warehouse

    Kraemer, T.F.

    1986-01-01

    Radon-222 has been measured in natural gas produced from experimental geopressured-geothermal test wells. Comparison with published data suggests that while radon activity of this unconventional natural gas resource is higher than conventional gas produced in the gulf coast, it is within the range found for conventional gas produced throughout the U.S. A method of predicting the likely radon activity of this unconventional gas is described on the basis of the data presented, methane solubility, and known or assumed reservoir conditions of temperature, fluid pressure, and formation water salinity.

  2. Characterization of Tight Gas Reservoir Pore Structure Using USANS/SANS and Gas Adsorption Analysis

    SciTech Connect

    Clarkson, Christopher R; He, Lilin; Agamalian, Michael; Melnichenko, Yuri B; Mastalerz, Maria; Bustin, Mark; Radlinski, Andrzej Pawell; Blach, Tomasz P

    2012-01-01

    Small-angle and ultra-small-angle neutron scattering (SANS and USANS) measurements were performed on samples from the Triassic Montney tight gas reservoir in Western Canada in order to determine the applicability of these techniques for characterizing the full pore size spectrum and to gain insight into the nature of the pore structure and its control on permeability. The subject tight gas reservoir consists of a finely laminated siltstone sequence; extensive cementation and moderate clay content are the primary causes of low permeability. SANS/USANS experiments run at ambient pressure and temperature conditions on lithologically-diverse sub-samples of three core plugs demonstrated that a broad pore size distribution could be interpreted from the data. Two interpretation methods were used to evaluate total porosity, pore size distribution and surface area and the results were compared to independent estimates derived from helium porosimetry (connected porosity) and low-pressure N{sub 2} and CO{sub 2} adsorption (accessible surface area and pore size distribution). The pore structure of the three samples as interpreted from SANS/USANS is fairly uniform, with small differences in the small-pore range (< 2000 {angstrom}), possibly related to differences in degree of cementation, and mineralogy, in particular clay content. Total porosity interpreted from USANS/SANS is similar to (but systematically higher than) helium porosities measured on the whole core plug. Both methods were used to estimate the percentage of open porosity expressed here as a ratio of connected porosity, as established from helium adsorption, to the total porosity, as estimated from SANS/USANS techniques. Open porosity appears to control permeability (determined using pressure and pulse-decay techniques), with the highest permeability sample also having the highest percentage of open porosity. Surface area, as calculated from low-pressure N{sub 2} and CO{sub 2} adsorption, is significantly less than surface area estimates from SANS/USANS, which is due in part to limited accessibility of the gases to all pores. The similarity between N{sub 2} and CO{sub 2}-accessible surface area suggests an absence of microporosity in these samples, which is in agreement with SANS analysis. A core gamma ray profile run on the same core from which the core plug samples were taken correlates to profile permeability measurements run on the slabbed core. This correlation is related to clay content, which possibly controls the percentage of open porosity. Continued study of these effects will prove useful in log-core calibration efforts for tight gas.

  3. Modeling of Devonian shale gas reservoirs. Task 16. Mathematical modeling of shale gas production (2D model). Final report

    SciTech Connect

    Not Available

    1980-07-31

    The Department of Energy (DOE), Morgantown Energy Technology Center (METC) has been supporting the development of flow models for Devonian shale gas reservoirs. The broad objectives of this modeling program are to: (1) develop and validate a mathematical model which describes gas flow through Devonian shales; (2) determine the sensitive parameters that affect deliverability and recovery of gas from Devonian shales; (3) recommend laboratory and field measurements for determination of those parameters critical to the productivity and timely recovery of gas from the Devonian shales; (4) analyze pressure and rate transient data from observation and production gas wells to determine reservoir parameters and well performance; and (5) study and determine the overall performance of Devonian shale reservoirs in terms of well stimulation, well spacing, and resource recovery as a function of gross reservoir properties such as anisotropy, porosity and thickness variations, and boundary effects. During the previous annual period, a mathematical model describing gas flow through Devonian shales and the software for a radial one-dimensional numerical model for single well performance were completed and placed into operation. Although the radial flow model is a powerful tool for studying single well behavior, it is inadequate for determining the effects of well spacing, stimulation treatments, and variation in reservoir properties. Hence, it has been necessary to extend the model to two-dimensions, maintaining full capability regarding Klinkerberg effects, desorption, and shale matrix parameters. During the current annual period, the radial flow model has been successfully extended to provide the two-dimensional capability necessary for the attainment of overall program objectives, as described above.

  4. Characterizing Reservoir Properties Using Monitoring Gas Pressure Data after CO2-Injection

    NASA Astrophysics Data System (ADS)

    Fang, Z.; Hou, Z.; Lin, G.; Fang, Y.

    2012-12-01

    This study evaluate the possibility of characterizing reservoir properties of permeability, porosity and entry pressure using CO2 monitoring data such as spatiotemporal distributions of gas pressure. The injection reservoir was set to be located 1400-1500 m below the ground surface so that CO2 remained in the supercritical state. The reservoir was assumed to contain five homogenous layers with alternating conductive and resistive properties, which is analogous to actual geological formations such as the Mount Simon Sandstone unit. The CO2 injection simulation used a cylindrical grid setting in which the injection well was situated at the center of the domain, which extended up to 8000 m from the injection well. The CO2 migration was simulated using the PNNL-developed simulator STOMP-CO2e (the water-salt-CO2 module). We adopted a nonlinear parameter estimation and optimization modeling software package, PEST, for automated reservoir parameter estimation. We explored the effects of data quality, data worth, and data redundancy on the detectability of reservoir parameters using CO2 pressure monitoring data, by comparing PEST inversion results using data with different levels of noises, various monitoring locations, and different data collection spacing and temporal sampling intervals. This study yielded insight into the use of CO2 monitoring data for reservoir characterization and how to design the monitoring system to optimize data worth and reduce data redundancy.

  5. Spatial and Temporal Variations in Greenhouse Gas Emissions from an Agricultural Reservoir

    EPA Science Inventory

    Reservoirs are being built at an increasing rate each year to provide humans with resources such as hydroelectric power and drinking water. These man-made systems have provided society with important services, but these have come at the cost of enhanced greenhouse gas (GHG) emiss...

  6. Naturally fractured tight gas reservoir detection optimization. Quarterly technical progress report, April 1995--June 1995

    SciTech Connect

    1995-08-01

    Research continued on methods to detect naturally fractured tight gas reservoirs. This report contains a seismic survey map, and reports on efforts towards a source test to select the source parameters for a 37 square mile compressional wave 3-D seismic survey. Considerations of the source tests are discussed.

  7. A placement model for matrix acidizing of vertically extensive, multilayer gas reservoirs 

    E-print Network

    Nozaki, Manabu

    2008-10-10

    the reservoir properties vary along the wellbore. This work provides development and application of an apparent skin factor model which accounts for both damage and mobility difference between acid and gas. Combining this model with a conventional acid........................................................................ 21 3.4 Fluid Interface Tracking Model ........................................................... 24 3.5 Wormholing Model .............................................................................. 26 3.6 Apparent Skin Factor Model...

  8. HIGH RESOLUTION PREDICTION OF GAS INJECTION PROCESS PERFORMANCE FOR HETEROGENEOUS RESERVOIRS

    SciTech Connect

    Franklin M. Orr, Jr.

    2002-12-31

    This report outlines progress in the first quarter of the third year of the DOE project ''High Resolution Prediction of Gas Injection Process Performance for Heterogeneous Reservoirs''. In this report we present an application of compositional streamline simulation in modeling enhanced condensate recovery via gas injection. These processes are inherently compositional and detailed compositional fluid descriptions must be use to represent the flow behavior accurately. Compositional streamline simulation results are compared to those of conventional finite-difference (FD) simulation for evaluation of gas injection schemes in condensate reservoirs. We present and compare streamline and FD results for two-dimensional (2D) and three-dimensional (3D) examples, to show that the compositional streamline method is a way to obtain efficiently estimates of reasonable accuracy for condensate recovery by gas injection.

  9. Comparison of Gross Greenhouse Gas Fluxes from Hydroelectric Reservoirs in Brazil with Thermopower Generation

    NASA Astrophysics Data System (ADS)

    Rogerio, J. P.; Dos Santos, M. A.; Matvienko, B.; dos Santos, E.; Rocha, C. H.; Sikar, E.; Junior, A. M.

    2013-05-01

    Widespread interest in human impacts on the Earth has prompted much questioning in fields of concern to the general public. One of these issues is the extent of the impacts on the environment caused by hydro-based power generation, once viewed as a clean energy source. From the early 1990s onwards, papers and studies have been challenging this assumption through claims that hydroelectric dams also emit greenhouse gases, generated by the decomposition of biomass flooded by filling these reservoirs. Like as other freshwater bodies, hydroelectric reservoirs produce gases underwater by biology decomposition of organic matter. Some of these biogenic gases are effective in terms of Global Warming. The decomposition is mainly due by anaerobically regime, emitting methane (CH4), nitrogen (N2) and carbon dioxide (CO2). This paper compare results obtained from gross greenhouse fluxes in Brazilian hydropower reservoirs with thermo power plants using different types of fuels and technology. Measurements were carried in the Manso, Serra da Mesa, Corumbá, Itumbiara, Estreito, Furnas and Peixoto reservoirs, located in Cerrado biome and in Funil reservoir located at Atlantic forest biome with well defined climatologically regimes. Fluxes of carbon dioxide and methane in each of the reservoirs selected, whether through bubbles and/or diffusive exchange between water and atmosphere, were assessed by sampling. The intensity of emissions has a great variability and some environmental factors could be responsible for these variations. Factors that influence the emissions could be the water and air temperature, depth, wind velocity, sunlight, physical and chemical parameters of water, the composition of underwater biomass and the operational regime of the reservoir. Based in this calculations is possible to conclude that the large amount of hydro-power studied is better than thermopower source in terms of atmospheric greenhouse emissions. The comparisons between the reservoirs studied shown a large variation in the data on greenhouse gas emissions, which would suggest that more care, should be taken in the choice of future projects by the Brazilian electrical sector. The emission of CH4 by hydroelectric reservoirs is always unfavorable, since even if the carbon has originated with natural sources, it is part of a gas with higher GWP in the final calculation. Emissions of CO2 can be attributed in part to the natural carbon cycle between the atmosphere and the water of the reservoir. Another part could be attributed to the decomposition of organic material, caused by the hydroelectric dam.

  10. Naturally fractured tight gas reservoir detection optimization. Quarterly report, July 1, 1996--September 30, 1996

    SciTech Connect

    1998-12-31

    This document contains the status report for the Naturally Fractured Tight Gas-Gas Reservoir Detection Optimization project for the contract period July 1 to September 30, 1996. Data from seismic surveys are analyzed for structural imaging of reflector units as part of a 3-D basin modeling effort. The main activities of this quarter were 3-D, 3-C processing, correlation matrix, and paraxial ray-tracing modeling.

  11. Naturally fractured tight gas reservoir detection optimization. Quarterly report, January 1, 1997--March 31, 1997

    SciTech Connect

    1998-04-01

    This document contains the quarterly report dated January 1-March 31, 1997 for the Naturally Fractured Tight Gas Reservoir Detection Optimization project. Topics covered in this report include AVOA modeling using paraxial ray tracing, AVOA modeling for gas- and water-filled fractures, 3-D and 3-C processing, and technology transfer material. Several presentations from a Geophysical Applications Workshop workbook, workshop schedule, and list of workshop attendees are also included.

  12. Fractured shale gas reservoir performance study - An offset well interference field test

    SciTech Connect

    Fruhne, K.H.; Mercer, J.C.

    1984-02-01

    Gas-production characteristics of naturally fractured Devonian shale have been quantified through a three-well interference field test by use of an established producing well and two offsets placed on the primary and secondary regional fracture trends relative to the producer. Three individual shale zones were evaluated simultaneously by buildup, drawdown, and pulse tests to investigate reservoir gas flow characteristics, natural fracture properties, and gas storage and release mechanisms. Test results show severe permeability anisotropy, indicating elliptical drainage pattern with an 8:1 axis ratio. Essentially all gas is stored in a sorbed state in the shale matrix and is transported toward the wells through the native fracture system.

  13. Numerical simulation of the environmental impact of hydraulic fracturing of tight/shale gas reservoirs on near-surface groundwater: Background, base cases, shallow reservoirs, short-term gas, and water transport

    DOE PAGESBeta

    Reagan, Matthew T.; Moridis, George J.; Keen, Noel D.; Johnson, Jeffrey N.

    2015-04-18

    Hydrocarbon production from unconventional resources and the use of reservoir stimulation techniques, such as hydraulic fracturing, has grown explosively over the last decade. However, concerns have arisen that reservoir stimulation creates significant environmental threats through the creation of permeable pathways connecting the stimulated reservoir with shallower freshwater aquifers, thus resulting in the contamination of potable groundwater by escaping hydrocarbons or other reservoir fluids. This study investigates, by numerical simulation, gas and water transport between a shallow tight-gas reservoir and a shallower overlying freshwater aquifer following hydraulic fracturing operations, if such a connecting pathway has been created. We focus on twomore »general failure scenarios: (1) communication between the reservoir and aquifer via a connecting fracture or fault and (2) communication via a deteriorated, preexisting nearby well. We conclude that the key factors driving short-term transport of gas include high permeability for the connecting pathway and the overall volume of the connecting feature. Production from the reservoir is likely to mitigate release through reduction of available free gas and lowering of reservoir pressure, and not producing may increase the potential for release. We also find that hydrostatic tight-gas reservoirs are unlikely to act as a continuing source of migrating gas, as gas contained within the newly formed hydraulic fracture is the primary source for potential contamination. Such incidents of gas escape are likely to be limited in duration and scope for hydrostatic reservoirs. Reliable field and laboratory data must be acquired to constrain the factors and determine the likelihood of these outcomes.« less

  14. Parametric study of gas-condensate reservoir behavior during depletion: A guide for development planning

    SciTech Connect

    Bourbiaux, B.J.

    1994-12-31

    The results of systematic compositional simulations of gas-condensate depletion in a radial and cross-sectional reservoir model are presented. The effects on productivity, recoveries and fluid distribution are analyzed and quantified when changing various parameters, such as the role of non-Darcy flow, the permeability, the relative permeabilities (kr) in relation with the interfacial tension (IFT), the nature of the fluid. Below the dew point pressure, the drop in gas productivity is linked to the development of a condensate ring around the wellbore. Gas and condensate kr and their dependence on IFT control the time or pressure at which condensate buildup becomes significant and gas productivity drops. Tight reservoirs with lean gas-condensates may pose early and drastic productivity problems. Far from wellbore, condensate may segregate under the low-IFT conditions met during depletion, especially if the reservoir permeability is high and the fluid is rich. In a depletion process, condensate recovery is all the lower as the condensate content of the fluid is higher. The results of this study can be used as a guide during the development planning of a gas-condensate field (1) to estimate the quantitative role played by key rock-fluid parameters during future exploitation, (2) to define the most relevant core-fluid measurements and simulation studies for reducing uncertainties on field performance predictions.

  15. Optimizing Development Strategies to Increase Reserves in Unconventional Gas Reservoirs 

    E-print Network

    Turkarslan, Gulcan

    2011-10-21

    The ever increasing energy demand brings about widespread interest to rapidly, profitably and efficiently develop unconventional resources, among which tight gas sands hold a significant portion. However, optimization of development strategies...

  16. Numerical Simulation of Subsurface Transport and Groundwater Impacts from Hydraulic Fracturing of Tight/Shale Gas Reservoirs

    NASA Astrophysics Data System (ADS)

    Reagan, M. T.; Moridis, G. J.; Keen, N. D.

    2014-12-01

    The use of reservoir stimulation techniques, such as hydraulic fracturing, has grown tremendously over the last decade, and concerns have arisen that reservoir stimulation creates environmental threats through the creation of permeable pathways that could connect the stimulated reservoir to shallower groundwater aquifers. This study investigates, by numerical simulation, gas and water transport between a deeper tight-gas reservoir and a shallower overlying groundwater aquifer following hydraulic fracturing operations, assuming that the formation of a connecting pathway has already occurred. We focus on two general transport scenarios: 1) communication between the reservoir and aquifer via a connecting fracture or fault and 2) communication via a deteriorated, preexisting nearby well. The simulations explore a range of permeabilities and geometries over time scales, and evaluate the mechanisms and factors that could lead to the escape of gas or reservoir fluid and the contamination of groundwater resources. We also examine the effects of overpressured reservoirs, and explore long-term transport processes as part of a continuing study. We conclude that the key factors driving short-term transport of gas include high permeability for the connecting pathway and the overall volume of the connecting feature. Gas production from the reservoir via a horizontal well is likely to mitigate release through the reduction of available free gas and the lowering of reservoir pressure. We also find that fractured tight-gas reservoirs are unlikely to act as a continuing source of large volumes of migrating gas, and incidents of gas escape are likely to be limited in duration and scope. Reliable field and laboratory data must be acquired to constrain the factors and determine the likelihood of these outcomes.

  17. GHG Emissions from Hydropower Reservoirs The role of hydropower reservoirs in contributing to greenhouse gas (GHG) emissions is poorly

    E-print Network

    GHG Emissions from Hydropower Reservoirs The role of hydropower reservoirs in contributing from tropical and boreal reservoirs are significant. In light of hydropower's potential role as a green, climate-neutral energy source, the Department of Energy's Water Technologies Program is working

  18. Application of oil gas-chromatography in reservoir compartmentalization in a mature Venezuelan oil field

    SciTech Connect

    Munoz, N.G.; Mompart, L.; Talukdar, S.C.

    1996-08-01

    Gas chromatographic oil {open_quotes}fingerprinting{close_quotes} was successfully applied in a multidisciplinary production geology project by Maraven, S.A. to define the extent of vertical and lateral continuity of Eocene and Miocene sandstone reservoirs in the highly faulted Bloque I field, Maracaibo Basin, Venezuela. Seventy-five non-biodegraded oils (20{degrees}-37.4{degrees} API) were analyzed with gas chromatography. Fifty were produced from the Eocene Misoa C-4, C-5, C-6 or C-7 horizons, fifteen from the Miocene basal La Rosa and ten from multizone completions. Gas chromatographic and terpane and sterane biomarker data show that all of the oils are genetically related. They were expelled from a type II, Upper Cretaceous marine La Luna source rock at about 0.80-0.90% R{sub o} maturity. Alteration in the reservoir by gas stripping with or without subsequent light hydrocarbons mixing was observed in some oils. Detailed chromatographic comparisons among the oils shown by star plots and cluster analysis utilizing several naphthenic and aromatic peak height ratios, resulted in oil pool groupings. This led to finding previously unknown lateral and vertical reservoir communication and also helped in checking and updating the scaling character of faults. In the commingled oils, percentages of each contributing zone in the mixture were also determined giving Maraven engineers a proven, rapid and inexpensive tool for production allocation and reservoir management The oil pool compartmentalization defined by the geochemical fingerprinting is in very good agreement with the sequence stratigraphic interpretation of the reservoirs and helped evaluate the influence of structure in oil migration and trapping.

  19. Sound velocity of drilling mud saturated with reservoir gas

    SciTech Connect

    Carcione, J.M.; Poletto, F.

    2000-04-01

    Knowledge of the in-situ sound velocity of drilling mud can be used in mud-pulse acoustic telemetry for evaluating the presence and amount of gas invasion in the drilling mud. The authors propose a model for calculating the in-situ density and sound velocity of water-based and oil-based drilling muds containing formation gas. Drilling muds are modeled as a suspension of clay particles and high-gravity solids in water or oil, with the acoustic properties of these fluids depending on pressure and temperature. Since mud at different depths experiences different pressures and temperatures, downhold mud weights can be significantly different from those measured at the surface. Taking this fact into consideration, the authors assume constant clay composition and obtained the fraction of high-gravity solids to balance the formation pressure corresponding to a given drilling plan. This gives the in-situ density of the drilling mud, which together with the bulk moduli of the single constituents allow one to compute the second velocity using Reuss's model. In the case of oil-based muds, they take into account the gas solubility in oil. When gas goes into solution, the mud is compassed of solid particles, live oil and, eventually, free gas. A phenomenological model based on a continuous spectrum of relaxation mechanisms is used to describe attenuation due to mud viscosity. The calculations for water-based and oil-based muds showed that the sound velocity is strongly dependent on gas saturation, fluid composition, and drilling depth.

  20. Calculation of geothermal reservoir temperatures and steam fractions from gas compositions

    SciTech Connect

    D'Amore, F.; Truesdell, A.H.

    1985-01-01

    This paper deals with the chemical equilibria and physical characteristics of the fluid in the reservoir (temperature, steam fraction with respect to total water, gas/steam ratio, redox conditions), which seem to be responsible for the observed concentrations of some reactive species found in the geothermal fluids (CO2, H2, H2S and CH4). Gas geochemistry is of particular interest in vapor-dominated fields where the fluid discharged consists of almost pure steam containing a limited number of volatile chemical species. Considering several geothermal systems, a good correlation has been obtained among the temperatures calculated from the gas geothermometers and the temperatures measured in the reservoir of evaluated by other physical or chemical methods. 24 refs., 5 figs.

  1. Wellbore stability in shale gas reservoirs, a case study of the Barnett Shale (USA).

    NASA Astrophysics Data System (ADS)

    Ouadfeul, Sid-Ali; Aliouane, Leila

    2015-04-01

    Wellbore stability in shale gas reservoirs is one of the major problems during the drilling phase; bad stability can induce the breakouts and drilling induced fractures. Wellbore stability requires the good knowledge of horizontal maximum and minimum stress, the overburden stress and the pore pressure. In this paper, we show a case study of the wellbore stability and how to estimate the mud weight in shale gas reservoir of the Barnett shale formation before drilling. The overburden stress is calculated from the seismic inversion, the minimum stress is calculated using the poro-elastic model, and however the pore pressure is calculated using the Eaton's model. Keywords: Wellbore stability, shale gas, maximum stress, minimum stress, overburden, mud weight, pore pressure.

  2. Analysis of Water Flowback Data in Gas Shale Reservoirs 

    E-print Network

    Aldaif, Hussain

    2014-09-24

    Bukhamseen, Hamed Alhoori and Mohammed AlSamahiji for their support and friendship. vi Finally, I would like to thank my colleagues; Ahmad Alkouh, Basil Alotaibi, Mohammed Kanfar, Pahal Sinurat and Mohit Dohli for their help and support which... the possibility of analyzing water flowback data in shale gas wells. 1.1 Objective Ahmad Alkouh, in his PhD dissertation, introduced a method to estimate the fracture effective volume in shale gas wells using water flowback data. One of his 2 objectives...

  3. Chemical stimulation of gas condensate reservoirs: An experimental and simulation study

    NASA Astrophysics Data System (ADS)

    Kumar, Viren

    Well productivity in gas condensate reservoirs is reduced by condensate banking when the bottom hole flowing pressure drops below the dewpoint pressure. Several methods have been proposed to restore gas production rates after a decline due to condensate blocking. Gas injection, hydraulic fracturing, horizontal wells and methanol injection have been tried with limited success. These methods of well stimulation either offer only temporary productivity restoration or are applicable only in some situations. Wettability alteration of the rock in the near well bore region is an economic and efficient method for the enhancement of gas-well deliverability. Altering the wettability of porous media from strongly water-wet or oil-wet to intermediate-wet decreases the residual liquid saturations and results in an increase in the relative permeability to gas. Such treatments also increase the mobility and recovery of condensate from the reservoir. This study validates the above hypothesis and provides a simple and cost-efficient solution to the condensate blocking problem. Screening studies were carried out to identify the chemicals based on structure, solubility and reactivity at reservoir temperature and pressure. Experiments were performed to evaluate these chemicals to improve gas and condensate relative permeabilities. The improvement in relative permeability after chemical treatment was quantified by performing high pressure and high temperature coreflood experiments in Berea sandstone, Texas Cream limestone and reservoir cores using synthetic gas mixtures at reservoir conditions. Experiments were done at high flow rates and for long time periods to evaluate the durability of the treatment. Single well simulation studies were conducted to demonstrate the performance of the chemical treatment in the field. The experimental relative permeability data was modeled using a trapping number dependent relative permeability model and incorporated in the simulations. Effect of connate water saturation, drawdown pressure, skin, treatment radius and the timing of the treatment during the life of the reservoir were investigated using a compositional simulator. Spectroscopic studies using a scanning electron microscope, neutron magnetic resonance and time of flight-secondary ion mass spectroscopy were used to determine the structural and reactive chemistry of the chemicals used and to evaluate the extent of treatment on the rock surface. The study allows us to postulate and partly verify a detailed mechanism of interaction between the rock surface and the chemical.

  4. Selection of fracture fluid for stimulating tight gas reservoirs 

    E-print Network

    Malpani, Rajgopal Vijaykumar

    2007-04-25

    is reduced which contributes to improved fracture conductivity. Harris et al. 18 shows that how metal and borate cross-linked fluids, linear gel fluids, and surfactant gel fluids can support proppant transport. The capability of polymer based fluids... Based on Proppant Concentration ........................66 24 Cumulative Frequency Distribution for 3-Year Cumulative Gas Production for Both Groups and Both Treatments (Carthage...

  5. Prediction of Gas Injection Performance for Heterogeneous Reservoirs

    SciTech Connect

    Blunt, M.J.; Orr, F.M. Jr.

    2001-03-26

    This report was an integrated study of the physics and chemistry affecting gas injection, from the pore scale to the field scale, and involved theoretical analysis, laboratory experiments and numerical simulation. Specifically, advances were made on streamline-based simulation, analytical solutions to 1D compositional displacements, and modeling and experimental measures of three-phase flow.

  6. Diagenesis of an 'overmature' gas reservoir: The Spiro sand of the Arkoma Basin, USA

    USGS Publications Warehouse

    Spotl, C.; Houseknecht, D.W.; Burns, S.J.

    1996-01-01

    The Spiro sand is a laterally extensive thin sandstone of earliest Atokan (Pennsylvanian) age that forms a major natural gas reservoir in the western Arkoma Basin, Oklahoma. Petrographic analysis reveals a variety of diagenetic alterations, the majority of which occurred during moderate to deep burial. Early diagenetic processes include calcite cementation and the formation of Fe-clay mineral peloids and coatings around quartz framework grains. These clays, which underwent transformation to well-crystallized chamosite [polytype Ib(?? = 90??)] on burial, are particularly abundant in medium-grained channel sandstones, whereas illitic clays are predominant in fine-grained interchannel sandstones. Subsequent to mechanical compaction, saddle ankerite precipitated in the reservoir at temperatures in excess of 70??C. Crude oil collected in favourable structural locations during and after ankeritization. Whereas hydrocarbons apparently halted inorganic diagenesis in oil-saturated zones, cementation continued in the underlying water-saturated zones. As reservoir temperatures increased further, hydrocarbons were cracked and a solid pyrobitumen residue remained in the reservoir. At temperatures exceeding ???140-150??C, non-syntaxial quartz cement, ferroan calcite and traces of dickite(?) locally reduced the reservoir quality. Local secondary porosity was created by carbonate cement dissolution. This alteration post-dated hydrocarbon emplacement and is probably related to late-stage infiltration of freshwater along 'leaky' faults. The study shows that the Spiro sandstone locally retained excellent porosities despite deep burial and thermal conditions that correspond to the zone of incipient very low grade metamorphism.

  7. Stress-dependent permeability on tight gas reservoirs 

    E-print Network

    Rodriguez, Cesar Alexander

    2005-02-17

    B REAL GAS DIFFUSIVITY EQUATION CONSIDERING PRESSURE DEPENDENT PERMEABILITY???????...... 87 APPENDIX C RADIAL AND LINEAR MODELS????????????. 89 APPENDIX D GASSIM DATA FILES..????????????????.. 91 APPENDIX E ANALYTICAL..., radial and linear, is described in Appendix C. In addition, in Appendix D have been included the data files used in GASSIM simulator for each case. 23 CHAPTER IV STRESS-DEPENDENT PERMEABILITY RADIAL CASES This chapter includes results...

  8. Estimation of velocity structure around a natural gas reservoir at Yufutsu, Japan, by microtremor survey

    NASA Astrophysics Data System (ADS)

    Shiraishi, H.; Asanuma, H.; Tezuka, K.

    2010-12-01

    Seismic reflection survey has been commonly used for exploration and time-lapse monitoring of oil/gas resources. Seismic reflection images typically have reasonable reliability and resolution for commercial production. However, cost consideration sometimes avoids deployment of widely distributed array or repeating survey in cases of time lapse monitoring or exploration of small-scale reservoir. Hence, technologies to estimate structures and physical properties around the reservoir with limited cost would be effectively used. Microtremor survey method (MSM) has an ability to realize long-term monitoring of reservoir with low cost, because this technique has a passive nature and minimum numbers of the monitoring station is four. MSM has been mainly used for earthquake disaster prevention, because velocity structure of S-wave is directly estimated from velocity dispersion of the Rayleigh wave. The authors experimentally investigated feasibility of the MSM survey for exploration of oil/gas reservoir. The field measurement was carried out around natural gas reservoir at Yufutsu, Hokkaido, Japan. Four types of arrays with array radii of 30m, 100m, 300m and 600m are deployed in each area. Dispersion curves of the velocity of Rayleigh wave were estimated from observed microtremors, and S-wave velocity structures were estimated by an inverse analysis of the dispersion curves with genetic algorism (GA). The estimated velocity structures showed good consistency with one dimensional velocity structure by previous reflection surveys up to 4-5 km. We also found from the field experiment that a data of 40min is effective to estimate the velocity structure even the seismometers are deployed along roads with heavy traffic.

  9. Potential hazards of compressed air energy storage in depleted natural gas reservoirs.

    SciTech Connect

    Cooper, Paul W.; Grubelich, Mark Charles; Bauer, Stephen J.

    2011-09-01

    This report is a preliminary assessment of the ignition and explosion potential in a depleted hydrocarbon reservoir from air cycling associated with compressed air energy storage (CAES) in geologic media. The study identifies issues associated with this phenomenon as well as possible mitigating measures that should be considered. Compressed air energy storage (CAES) in geologic media has been proposed to help supplement renewable energy sources (e.g., wind and solar) by providing a means to store energy when excess energy is available, and to provide an energy source during non-productive or low productivity renewable energy time periods. Presently, salt caverns represent the only proven underground storage used for CAES. Depleted natural gas reservoirs represent another potential underground storage vessel for CAES because they have demonstrated their container function and may have the requisite porosity and permeability; however reservoirs have yet to be demonstrated as a functional/operational storage media for compressed air. Specifically, air introduced into a depleted natural gas reservoir presents a situation where an ignition and explosion potential may exist. This report presents the results of an initial study identifying issues associated with this phenomena as well as possible mitigating measures that should be considered.

  10. Joule-Thomson Cooling Due to CO2 Injection into Natural GasReservoirs

    SciTech Connect

    Oldenburg, Curtis M.

    2006-04-21

    Depleted natural gas reservoirs are a promising target for Carbon Sequestration with Enhanced Gas Recovery (CSEGR). The focus of this study is on evaluating the importance of Joule-Thomson cooling during CO2 injection into depleted natural gas reservoirs. Joule-Thomson cooling is the adiabatic cooling that accompanies the expansion of a real gas. If Joule-Thomson cooling were extreme, injectivity and formation permeability could be altered by the freezing of residual water,formation of hydrates, and fracturing due to thermal stresses. The TOUGH2/EOS7C module for CO2-CH4-H2O mixtures is used as the simulation analysis tool. For verification of EOS7C, the classic Joule-Thomson expansion experiment is modeled for pure CO2 resulting in Joule-Thomson coefficients in agreement with standard references to within 5-7 percent. For demonstration purposes, CO2 injection at constant pressure and with a large pressure drop ({approx}50 bars) is presented in order to show that cooling by more than 20 C can occur by this effect. Two more-realistic constant-rate injection cases show that for typical systems in the Sacramento Valley, California, the Joule-Thomson cooling effect is minimal. This simulation study shows that for constant-rate injections into high-permeability reservoirs, the Joule-Thomson cooling effect is not expected to create significant problems for CSEGR.

  11. HIGH RESOLUTION PREDICTION OF GAS INJECTION PROCESS PERFORMANCE FOR HETEROGENEOUS RESERVOIRS

    SciTech Connect

    Thomas A. Hewett; Franklin M. Orr Jr.

    2000-12-31

    Gas injection in oil reservoirs offers huge potential for improved oil recovery. However, successful design of a gas injection process requires a detailed understanding of a variety of different significant processes, including the phase behavior of multicomponent mixtures and the approach to multi-contact miscibility in the reservoir, the flow of oil, water and gas underground, and the interaction of phase behavior reservoir heterogeneity and gravity on overall performance at the field scale. This project attempts to tackle all these issues using a combination of theoretical, numerical and laboratory studies of gas injection. The aim of this work is to develop a set of ultra-fast compositional simulation tools that can be used to make field-scale predictions of the performance of gas injection processes. To achieve the necessary accuracy, these tools must satisfy the fundamental physics and chemistry of the displacement from the pore to the reservoir scales. Thus this project focuses on four main research areas: (1) determination of the most appropriate methods of mapping multicomponent solutions to streamlines and streamtubes in 3D; (2) development of techniques for automatic generation of analytical solutions for one-dimensional flow along a streamline; (3) experimental investigations to improve the representation of physical mechanisms that govern displacement efficiency along a streamline; and (4) Theoretical and experimental investigations to establish the limitations of the streamline/streamtube approach. In this report they briefly review the status of the research effort in each area. They then give a more in depth discussion of the development of a CT scanning technique which can measure compositions in a two-phase, three-component system in-situ.

  12. CO2 utilization and storage in shale gas reservoirs: Experimental results and economic impacts

    DOE PAGESBeta

    Schaef, Herbert T.; Davidson, Casie L.; Owen, Antionette Toni; Miller, Quin R. S.; Loring, John S.; Thompson, Christopher J.; Bacon, Diana H.; Glezakou, Vassiliki Alexandra; McGrail, B. Peter

    2014-12-31

    Natural gas is considered a cleaner and lower-emission fuel than coal, and its high abundance from advanced drilling techniques has positioned natural gas as a major alternative energy source for the U.S. However, each ton of CO2 emitted from any type of fossil fuel combustion will continue to increase global atmospheric concentrations. One unique approach to reducing anthropogenic CO2 emissions involves coupling CO2 based enhanced gas recovery (EGR) operations in depleted shale gas reservoirs with long-term CO2 storage operations. In this paper, we report unique findings about the interactions between important shale minerals and sorbing gases (CH4 and CO2) andmore »associated economic consequences. Where enhanced condensation of CO2 followed by desorption on clay surface is observed under supercritical conditions, a linear sorption profile emerges for CH4. Volumetric changes to montmorillonites occur during exposure to CO2. Theory-based simulations identify interactions with interlayer cations as energetically favorable for CO2 intercalation. Thus, experimental evidence suggests CH4 does not occupy the interlayer and has only the propensity for surface adsorption. Mixed CH4:CO2 gas systems, where CH4 concentrations prevail, indicate preferential CO2 sorption as determined by in situ infrared spectroscopy and X-ray diffraction techniques. Collectively, these laboratory studies combined with a cost-based economic analysis provide a basis for identifying favorable CO2-EOR opportunities in previously fractured shale gas reservoirs approaching final stages of primary gas production. Moreover, utilization of site-specific laboratory measurements in reservoir simulators provides insight into optimum injection strategies for maximizing CH4/CO2 exchange rates to obtain peak natural gas production.« less

  13. Role of organic matter fractions in the Montney tight gas reservoir quality

    NASA Astrophysics Data System (ADS)

    Sanei, Hamed; Wood, James M.; Haeri Ardakani, Omid; Clarkson, Chris R.

    2015-04-01

    This study presents a new approach in Rock-Eval analysis to quantify various organic matter fractions in unconventional reservoirs. The results of study on core samples from the Triassic Montney Formation tight gas reservoir in the Western Canadian Sedimentary Basin show that operationally-defined S1 and S2 hydrocarbon peaks from conventional Rock-Eval analysis may not adequately characterize the organic constituents of unconventional reservoir rocks. Modification of the thermal recipe for Rock-Eval analysis, in conjunction with manual peak integration, provides important information with significance for the evaluation of reservoir quality. An adapted Rock-Eval method, herein called the extended slow heating (ESH) cycle, was developed in which the heating rate was slowed to 10°C per minute over an extended temperature range (150 to 650°C). For Montney core samples from the wet gas window, this method provided quantitative distinctions between major organic matter components of the rock. We show that the traditional S1 and S2 peaks can now be quantitatively divided into three components: (S1ESH) free light oil, (S2a ESH) condensed hydrocarbon residue (CHCR), and (S2b ESH + residual carbon) solid bitumen (refractory, consolidated bitumen/pyrobitumen). The majority of the total organic carbon (TOC) in the studied Montney core samples consists of solid bitumen that represents a former liquid oil phase which migrated into the larger paleo-intergranular pore spaces. Subsequent physicochemical changes to the oil environment led to the precipitation of asphaltene aggregates. Further diagenetic and thermal maturity processes consolidated these asphaltene aggregates into "lumps" of solid bitumen (or pyrobitumen at higher thermal maturity). Solid bitumen obstructs porosity and hinders fluid flow, and thus shows strong negative correlations with reservoir qualities such as porosity and pore throat size. We also find a strong positive correlation between the quantities of solid bitumen and pyrite, a relationship confirmed by petrographic evidence showing a close spatial association of bacterially-derived framboidal pyrite with solid bitumen accumulations in the intergranular paleo-pore spaces. These relationships suggest that solid bitumen and framboidal pyrite were both early products of bacterial sulphate reduction of liquid hydrocarbons following initial oil charging of the Montney Formation. Although the CHCR fraction constitutes a small portion of the mass and volume of TOC in Montney samples it has important implications for reservoir quality. This fraction represents a thin film of condensed, heavy molecular hydrocarbon adsorbed onto mineral surfaces and may represent the lighter component of the paleo-oil that migrated into the Montney reservoir. The CHCR fraction potentially plays an important role in wettability alteration by creating hydrophobic matrix pore networks in portions of the reservoir that were not already filled with solid bitumen.

  14. Greenhouse gas emissions (CO2, CH4 and N2O) from perialpine and alpine hydropower reservoirs

    NASA Astrophysics Data System (ADS)

    Diem, T.; Koch, S.; Schwarzenbach, S.; Wehrli, B.; Schubert, C. J.

    2008-09-01

    In eleven reservoirs located at different altitudes in Switzerland depth profiles of greenhouse gas (CO2, CH4, and N2O) concentrations were measured several times during spring and summer. Trace gas emissions were calculated using surface concentrations, wind speeds and transfer velocities. Additionally we assessed methane loss at the turbine and the methane input by inflowing water. All reservoirs were net emitters of CO2 with an average of 1030±780 mg m-2 d-1 and of methane with an average of 0.20±0.15 mg m-2 d-1. One reservoir (Lake Wohlen) emitted methane at a much higher rate (160±110 mg m-2 d-1), most of which (>98%) was due to ebullition. Only lowland reservoirs were sources for N2O (72±22 ?g m-2 d-1), while the subalpine and alpine reservoirs seem to be in equilibrium with atmospheric concentrations. Methane loss at the turbine was as large as the diffusive flux from the surface for two subalpine reservoirs and around five times smaller for a lowland reservoir. The available data suggests greenhouse gas emissions from reservoirs in the Alps are minor contributors to the global greenhouse gas emissions.

  15. CO2-Driven Enhanced Gas Recovery and Storage in Depleted Shale Reservoir-A Numerical Simulation Study

    E-print Network

    Mohaghegh, Shahab

    shale gas reservoir using numerical simulation. The first step in the process of modeling and simulation on the history matched numerical reservoir simulation model are defined and the best practices to enhance methane of fossil fuels, are being linked to global climate change and are of considerable concern. These concerns

  16. Deep microbial life in the Altmark natural gas reservoir: baseline characterization prior CO2 injection

    NASA Astrophysics Data System (ADS)

    Morozova, Daria; Shaheed, Mina; Vieth, Andrea; Krüger, Martin; Kock, Dagmar; Würdemann, Hilke

    2010-05-01

    Within the framework of the CLEAN project (CO2 Largescale Enhanced gas recovery in the Altmark Natural gas field) technical basics with special emphasis on process monitoring are explored by injecting CO2 into a gas reservoir. Our study focuses on the investigation of the in-situ microbial community of the Rotliegend natural gas reservoir in the Altmark, located south of the city Salzwedel, Germany. In order to characterize the microbial life in the extreme habitat we aim to localize and identify microbes including their metabolism influencing the creation and dissolution of minerals. The ability of microorganisms to speed up dissolution and formation of minerals might result in changes of the local permeability and the long-term safety of CO2 storage. However, geology, structure and chemistry of the reservoir rock and the cap rock as well as interaction with saline formation water and natural gases and the injected CO2 affect the microbial community composition and activity. The reservoir located at the depth of about 3500m, is characterised by high salinity fluid and temperatures up to 127° C. It represents an extreme environment for microbial life and therefore the main focus is on hyperthermophilic, halophilic anaerobic microorganisms. In consequence of the injection of large amounts of CO2 in the course of a commercial EGR (Enhanced Gas Recovery) the environmental conditions (e.g. pH, temperature, pressure and solubility of minerals) for the autochthonous microorganisms will change. Genetic profiling of amplified 16S rRNA genes are applied for detecting structural changes in the community by using PCR- SSCP (PCR-Single-Strand-Conformation Polymorphism) and DGGE (Denaturing Gradient Gel Electrophoresis). First results of the baseline survey indicate the presence of microorganisms similar to representatives from other saline, hot, anoxic, deep environments. However, due to the hypersaline and hyperthermophilic reservoir conditions, cell numbers are low, so that the quantification of those microorganisms as well as the determination of microbial activity was not yet possible. Microbial monitoring methods have to be further developed to study microbial activities under these extreme conditions to access their influence on the EGR technique and on enhancing the long term safety of the process by fixation of carbon dioxide by precipitation of carbonates. We would like to thank GDF SUEZ for providing the data for the Rotliegend reservoir, sample material and enabling sampling campaigns. The CLEAN project is funded by the German Federal Ministry of Education and Research (BMBF) in the frame of the Geotechnologien Program.

  17. Facies, faults and potential sweet spots in a tight gas reservoir: Almond Formation, Wyoming

    SciTech Connect

    Martinsen, R.; Iverson, W.; Surdam, R. )

    1996-01-01

    The Almond Formation is a major producer of gas in southwestern Wyoming. Although exploration generally is aimed at finding conventional reservoirs in upper Almond marine sandstones, the majority of Almond gas is contained in the underlying main Almond, a succession of dominantly non-marine, interbedded tight sandstones, siltstones, carbonaceous shales and coals. Production data indicate that some of the best gas wells completed in upper Almond sands show little production decline and have already produced more gas than calculations indicate they contain. This implies that these wells have somehow successfully tapped into the vast supply of gas contained in the main Almond. We believe that the more permeable reservoirs, in addition to providing [open quotes]sweet spots[close quotes] for exploration, also serve as lateral conduits capable of draining gas over a broad area from the main Almond. The [open quotes]sweet spots[close quotes] themselves do not need to be volumetrically large, only permeable and laterally continuous. Previously unrecognized marine sands, similar to those in the upper Almond, are favorably located in the middle of the main Almond succession and may provide additional lateral conduits. Studies also show that syndepositional faults significantly influenced deposition and may also be important in terms of fluid flow. At least some syndepositional faults are associated with anomalously high gas and/or water production within fields, and may be vertical conduits for fluid flow.

  18. Facies, faults and potential sweet spots in a tight gas reservoir: Almond Formation, Wyoming

    SciTech Connect

    Martinsen, R.; Iverson, W.; Surdam, R.

    1996-12-31

    The Almond Formation is a major producer of gas in southwestern Wyoming. Although exploration generally is aimed at finding conventional reservoirs in upper Almond marine sandstones, the majority of Almond gas is contained in the underlying main Almond, a succession of dominantly non-marine, interbedded tight sandstones, siltstones, carbonaceous shales and coals. Production data indicate that some of the best gas wells completed in upper Almond sands show little production decline and have already produced more gas than calculations indicate they contain. This implies that these wells have somehow successfully tapped into the vast supply of gas contained in the main Almond. We believe that the more permeable reservoirs, in addition to providing {open_quotes}sweet spots{close_quotes} for exploration, also serve as lateral conduits capable of draining gas over a broad area from the main Almond. The {open_quotes}sweet spots{close_quotes} themselves do not need to be volumetrically large, only permeable and laterally continuous. Previously unrecognized marine sands, similar to those in the upper Almond, are favorably located in the middle of the main Almond succession and may provide additional lateral conduits. Studies also show that syndepositional faults significantly influenced deposition and may also be important in terms of fluid flow. At least some syndepositional faults are associated with anomalously high gas and/or water production within fields, and may be vertical conduits for fluid flow.

  19. Simulation study to determine the feasibility of injecting hydrogen sulfide, carbon dioxide and nitrogen gas injection to improve gas and oil recovery oil-rim reservoir

    NASA Astrophysics Data System (ADS)

    Eid, Mohamed El Gohary

    This study is combining two important and complicated processes; Enhanced Oil Recovery, EOR, from the oil rim and Enhanced Gas Recovery, EGR from the gas cap using nonhydrocarbon injection gases. EOR is proven technology that is continuously evolving to meet increased demand and oil production and desire to augment oil reserves. On the other hand, the rapid growth of the industrial and urban development has generated an unprecedented power demand, particularly during summer months. The required gas supplies to meet this demand are being stretched. To free up gas supply, alternative injectants to hydrocarbon gas are being reviewed to support reservoir pressure and maximize oil and gas recovery in oil rim reservoirs. In this study, a multi layered heterogeneous gas reservoir with an oil rim was selected to identify the most optimized development plan for maximum oil and gas recovery. The integrated reservoir characterization model and the pertinent transformed reservoir simulation history matched model were quality assured and quality checked. The development scheme is identified, in which the pattern and completion of the wells are optimized to best adapt to the heterogeneity of the reservoir. Lateral and maximum block contact holes will be investigated. The non-hydrocarbon gases considered for this study are hydrogen sulphide, carbon dioxide and nitrogen, utilized to investigate miscible and immiscible EOR processes. In November 2010, re-vaporization study, was completed successfully, the first in the UAE, with an ultimate objective is to examine the gas and condensate production in gas reservoir using non hydrocarbon gases. Field development options and proces schemes as well as reservoir management and long term business plans including phases of implementation will be identified and assured. The development option that maximizes the ultimate recovery factor will be evaluated and selected. The study achieved satisfactory results in integrating gas and oil reservoir management methodology to maximize both fluid recovery and free up currently injected HC gases for domestic consumption. Moreover, this study identified the main uncertainty parameters impacting the gas and oil production performance with all proposed alternatives. Maximizing both fluids oil and gas in oil rim reservoir are challenging. The reservoir heterogeneity will have a major impact on the performance of non hydrocarbon gas flooding. Therefore, good reservoir description is a key to achieve acceptable development process and make reliable prediction. The lab study data were used successfully to as a tool to identify the range of uncertainty parameters that are impacting the hydrocarbon recovery.

  20. FMS/FMI borehole imaging of carbonate gas reservoirs, Central Luconia Province, offshore Sarawak, Malaysia

    SciTech Connect

    Singh, U.; Van der Baan, D. )

    1994-07-01

    The Central Luconia Province, offshore Sarawak, is a significant gas province characterized by extensive development of late Miocene carbonate buildups. Some 200 carbonate structures have been seismically mapped of which 70 have been drilled. FMS/FMI borehole images were obtained from three appraisal wells drilled in the [open quotes]M[close quotes] cluster gas fields situated in the northwestern part of the province. The [open quotes]M[close quotes] cluster fields are currently part of an upstream gas development project to supply liquefied natural gas. Log facies recognition within these carbonate gas reservoirs is problematic due mainly to the large gas effect. This problem is being addressed by (1) application of neural network techniques and (2) using borehole imaging tools. Cores obtained from the M1, M3, and M4 gas fields were calibrated with the FMS/FMI images. Reservoir characterization was obtained at two different scales. The larger scale (i.e., 1:40 and 1:200) involved static normalized images where the vertical stacking pattern was observed based on recognition of bed boundaries. In addition, the greater vertical resolution of the FMS/FMI images allowed recognition of thin beds. For recognition of specific lithofacies, dynamically normalized images were used to highlight lithofacies-specific sedimentary features, e.g., clay seams/stylolites, vugs, and breccia zones. In general, the FMS/FMI images allowed (1) easier recognition of reservoir features, e.g., bed boundaries, and (2) distinction between lithofacies that are difficult to characterize on conventional wireline logs.

  1. HIGH RESOLUTION PREDICTION OF GAS INJECTION PROCESS PERFORMANCE FOR HETEROGENEOUS RESERVOIRS

    SciTech Connect

    Franklin M. Orr, Jr.

    2001-06-30

    This report outlines progress in the third 3 quarter of the first year of the DOE project ''High Resolution Prediction of Gas Injection Process Performance for Heterogeneous Reservoirs.'' A simple theoretical formulation of vertical flow with capillary/gravity equilibrium is described. Also reported are results of experimental measurements for the same systems. The results reported indicate that displacement behavior is strongly affected by the interfacial tension of phases that form on the tie line that extends through the initial oil composition.

  2. The big fat LARS - a LArge Reservoir Simulator for hydrate formation and gas production

    NASA Astrophysics Data System (ADS)

    Beeskow-Strauch, Bettina; Spangenberg, Erik; Schicks, Judith M.; Giese, Ronny; Luzi-Helbing, Manja; Priegnitz, Mike; Klump, Jens; Thaler, Jan; Abendroth, Sven

    2013-04-01

    Simulating natural scenarios on lab scale is a common technique to gain insight into geological processes with moderate effort and expenses. Due to the remote occurrence of gas hydrates, their behavior in sedimentary deposits is largely investigated on experimental set ups in the laboratory. In the framework of the submarine gas hydrate research project (SUGAR) a large reservoir simulator (LARS) with an internal volume of 425 liter has been designed, built and tested. To our knowledge this is presently a word-wide unique set up. Because of its large volume it is suitable for pilot plant scale tests on hydrate behavior in sediments. That includes not only the option of systematic tests on gas hydrate formation in various sedimentary settings but also the possibility to mimic scenarios for the hydrate decomposition and subsequent natural gas extraction. Based on these experimental results various numerical simulations can be realized. Here, we present the design and the experimental set up of LARS. The prerequisites for the simulation of a natural gas hydrate reservoir are porous sediments, methane, water, low temperature and high pressure. The reservoir is supplied by methane-saturated and pre-cooled water. For its preparation an external gas-water mixing stage is available. The methane-loaded water is continuously flushed into LARS as finely dispersed fluid via bottom-and-top-located sparger. The LARS is equipped with a mantle cooling system and can be kept at a chosen set temperature. The temperature distribution is monitored at 14 reasonable locations throughout the reservoir by Pt100 sensors. Pressure needs are realized using syringe pump stands. A tomographic system, consisting of a 375-electrode-configuration is attached to the mantle for the monitoring of hydrate distribution throughout the entire reservoir volume. Two sets of tubular polydimethylsiloxan-membranes are applied to determine gas-water ratio within the reservoir using the effect of permeability differences between gaseous and dissolved methane (Zimmer et al., 2011). Gas hydrate is formed using a confined pressure of 12-15 MPa and a fluid pressure of 8-11 MPa with a set temperature of 275 K. The duration of the formation process depends on the required hydrate saturation and is usually in a range of several weeks. The subsequent decomposition experiments aiming at testing innovative production scenarios such as the application of a borehole tool for thermal stimulation of hydrate via catalytic oxidation of methane within an autothermal catalytic reactor (Schicks et al. 2011). Furthermore, experiments on hydrate decomposition via pressure reduction are performed to mimic realistic scenarios such as found during the production test in Mallik (Yasuda and Dallimore, 2007). In the near future it is planned to scale up existing results on CH4-CO2 exchange efficiency (e.g. Strauch and Schicks, 2012) by feeding CO2 to the hydrate reservoir. All experiments are due to the gain of high-resolution spatial and temporal data predestined as a base for numerical modeling. References Schicks, J. M., Spangenberg, E., Giese, R., Steinhauer, B., Klump, J., Luzi, M., 2011. Energies, 4, 1, 151-172. Zimmer, M., Erzinger, J., Kujawa, C., 2011. Int. J. of Greenhouse Gas Control, 5, 4, 995-1001. Yasuda, M., Dallimore, S. J., 2007. Jpn. Assoc. Pet. Technol., 72, 603-607. Beeskow-Strauch, B., Schicks, J.M., 2012. Energies, 5, 420-437.

  3. Hydrolyzed Polyacrylamide- Polyethylenimine- Dextran Sulfate Polymer Gel System as a Water Shut-Off Agent in Unconventional Gas Reservoirs 

    E-print Network

    Jayakumar, Swathika 1986-

    2012-07-09

    Technologies such as horizontal wells and multi-stage hydraulic fracturing have made ultra-low permeability shale and tight gas reservoirs productive but the industry is still on the learning curve when it comes to addressing various production...

  4. Fracture detection, mapping, and analysis of naturally fractured gas reservoirs using seismic technology. Final report, November 1995

    SciTech Connect

    1995-10-01

    Many basins in the Rocky Mountains contain naturally fractured gas reservoirs. Production from these reservoirs is controlled primarily by the shape, orientation and concentration of the natural fractures. The detection of gas filled fractures prior to drilling can, therefore, greatly benefit the field development of the reservoirs. The objective of this project was to test and verify specific seismic methods to detect and characterize fractures in a naturally fractured reservoir. The Upper Green River tight gas reservoir in the Uinta Basin, Northeast Utah was chosen for the project as a suitable reservoir to test the seismic technologies. Knowledge of the structural and stratigraphic geologic setting, the fracture azimuths, and estimates of the local in-situ stress field, were used to guide the acquisition and processing of approximately ten miles of nine-component seismic reflection data and a nine-component Vertical Seismic Profile (VSP). Three sources (compressional P-wave, inline shear S-wave, and cross-line, shear S-wave) were each recorded by 3-component (3C) geophones, to yield a nine-component data set. Evidence of fractures from cores, borehole image logs, outcrop studies, and production data, were integrated with the geophysical data to develop an understanding of how the seismic data relate to the fracture network, individual well production, and ultimately the preferred flow direction in the reservoir. The multi-disciplinary approach employed in this project is viewed as essential to the overall reservoir characterization, due to the interdependency of the above factors.

  5. Percolation Pore Network Study on the Residue Gas Saturation of Dry Reservoir Rocks

    NASA Astrophysics Data System (ADS)

    Cheng, T.; Tang, Y. B.; Zou, G. Y.; Jiang, K.; Li, M.

    2014-12-01

    We tried to model the effect of pore size heterogeneity and pore connectivity on the residue gas saturation for dry gas reservoir rocks. If we consider that snap-off does not exist and only piston displacement takes place in all pores with the same size during imbibition process, in the extreme case, the residue gas saturation will be equal to zero. Thus we can suppose that the residue gas saturation of dry rocks is mainly controlled by the pore size distribution. To verify the assumption, percolation pore networks (i.e., three-dimensional simple cubic (SC) and body-center cubic (BCC)) were used in the study. The connectivity and the pore size distribution in percolation pore network could be changed randomly. The concept of water phase connectivity zw(i.e., water coordination number) and gas phase connectivity zg (i.e., gas coordination number) was introduced here. zw and zg will change during simulation and can be estimated numerically from the results of simulations through gradually saturated networks by water. The Simulation results show that when zg less than or equal to 1.5 during water quasi - static imbibition, the gas will be trapped in rock pores. Network simulation results also shows that the residue gas saturation Srg follows a power law relationship (i.e.,Srg??r?, where ?r is normalized standard deviation of the pore radius distribution, and exponent ? is a function of coordination number). This indicates that the residue gas saturation has no explicit relationship with porosity and permeability as it should have in light of previous study, pore radius distribution is the principal factor in determining the residue gas saturation of dry reservoir rocks.

  6. Characterization of oil and gas reservoir heterogeneity; Final report, November 1, 1989--June 30, 1993

    SciTech Connect

    Sharma, G.D.

    1993-09-01

    The Alaskan North Slope comprises one of the Nation`s and the world`s most prolific oil province. Original oil in place (OOIP) is estimated at nearly 70 BBL (Kamath and Sharma, 1986). Generalized reservoir descriptions have been completed by the University of Alaska`s Petroleum Development Laboratory over North Slope`s major fields. These fields include West Sak (20 BBL OOIP), Ugnu (15 BBL OOIP), Prudhoe Bay (23 BBL OOIP), Kuparuk (5.5 BBL OOIP), Milne Point (3 BBL OOIP), and Endicott (1 BBL OOIP). Reservoir description has included the acquisition of open hole log data from the Alaska Oil and Gas Conservation Commission (AOGCC), computerized well log analysis using state-of-the-art computers, and integration of geologic and logging data. The studies pertaining to fluid characterization described in this report include: experimental study of asphaltene precipitation for enriched gases, CO{sup 2} and West Sak crude system, modeling of asphaltene equilibria including homogeneous as well as polydispersed thermodynamic models, effect of asphaltene deposition on rock-fluid properties, fluid properties of some Alaskan north slope reservoirs. Finally, the last chapter summarizes the reservoir heterogeneity classification system for TORIS and TORIS database.

  7. Simulator for unconventional gas resources multi-dimensional model SUGAR-MD. Volume I. Reservoir model analysis and validation

    SciTech Connect

    Not Available

    1982-01-01

    The Department of Energy, Morgantown Energy Technology Center, has been supporting the development of flow models for Devonian shale gas reservoirs. The broad objectives of this modeling program are: (1) To develop and validate a mathematical model which describes gas flow through Devonian shales. (2) To determine the sensitive parameters that affect deliverability and recovery of gas from Devonian shales. (3) To recommend laboratory and field measurements for determination of those parameters critical to the productivity and timely recovery of gas from the Devonian shales. (4) To analyze pressure and rate transient data from observation and production gas wells to determine reservoir parameters and well performance. (5) To study and determine the overall performance of Devonian shale reservoirs in terms of well stimulation, well spacing, and resource recovery as a function of gross reservoir properties such as anisotropy, porosity and thickness variations, and boundary effects. The flow equations that are the mathematical basis of the two-dimensional model are presented. It is assumed that gas transport to producing wells in Devonian shale reservoirs occurs through a natural fracture system into which matrix blocks of contrasting physical properties deliver contained gas. That is, the matrix acts as a uniformly distributed gas source in a fracture medium. Gas desorption from pore walls is treated as a uniformly distributed source within the matrix blocks. 24 references.

  8. Hydrocarbon transfer pathways from Smackover source rocks to younger reservoir traps in the Monroe gas field, NE Louisiana

    SciTech Connect

    Zimmerman, R.K. )

    1993-09-01

    The Monroe gas field contained more than 7 tcf of gas in its virgin state. Much of the original gas reserves have been produced through wells penetrating the Upper Cretaceous Monroe Gas Rock Formation reservoir. Other secondary reservoirs in the field area are Eocene Wilcox, the Upper Cretaceous Arkadelphia, Nacatoch, Ozan, Lower Cretaceous, Hosston, Jurassic Schuler, and Smackover. As producing zones, these secondary producing zones reservoirs have contributed an insignificant amount gas to the field. The source of much of this gas appears to have been in the lower part of the Jurassic Smackover Formation. Maturation and migration of the hydrocarbons from a Smackover source into Upper Cretaceous traps was enhanced and helped by igneous activity, and wrench faults/unconformity conduits, respectively. are present in the pre-Paleocene section. Hydrocarbon transfer pathways appear to be more vertically direct in the Jurassic and Lower Cretaceous section than the complex pattern present in the Upper Cretaceous section.

  9. DEVELOPMENT OF MORE-EFFICIENT GAS FLOODING APPLICABLE TO SHALLOW RESERVOIRS

    SciTech Connect

    William R. Rossen; Russell T. Johns; Gary A. Pope

    2003-08-21

    The objective of this research is to widen the applicability of gas flooding to shallow oil reservoirs by reducing the pressure required for miscibility using gas enrichment and increasing sweep efficiency with foam. Task 1 examines the potential for improved oil recovery with enriched gases. Subtask 1.1 examines the effect of dispersion processes on oil recovery and the extent of enrichment needed in the presence of dispersion. Subtask 1.2 develops a fast, efficient method to predict the extent of enrichment needed for crude oils at a given pressure. Task 2 develops improved foam processes to increase sweep efficiency in gas flooding. Subtask 2.1 comprises mechanistic experimental studies of foams with N2 gas. Subtask 2.2 conducts experiments with CO{sub 2} foam. Subtask 2.3 develops and applies a simulator for foam processes in field application.

  10. Tritium Transport at the Rulison Site, a Nuclear-stimulated Low-permeability Natural Gas Reservoir

    SciTech Connect

    C. Cooper; M. Ye; J. Chapman

    2008-04-01

    The U.S. Department of Energy (DOE) and its predecessor agencies conducted a program in the 1960s and 1970s that evaluated technology for the nuclear stimulation of low-permeability natural gas reservoirs. The second project in the program, Project Rulison, was located in west-central Colorado. A 40-kiltoton nuclear device was detonated 2,568 m below the land surface in the Williams Fork Formation on September 10, 1969. The natural gas reservoirs in the Williams Fork Formation occur in low permeability, fractured sandstone lenses interbedded with shale. Radionuclides derived from residual fuel products, nuclear reactions, and activation products were generated as a result of the detonation. Most of the radionuclides are contained in a cooled, solidified melt glass phase created from vaporized and melted rock that re-condensed after the test. Of the mobile gas-phase radionuclides released, tritium ({sup 3}H or T) migration is of most concern. The other gas-phase radionuclides ({sup 85}Kr, {sup 14}C) were largely removed during production testing in 1969 and 1970 and are no longer present in appreciable amounts. Substantial tritium remained because it is part of the water molecule, which is present in both the gas and liquid (aqueous) phases. The objectives of this work are to calculate the nature and extent of tritium contamination in the subsurface from the Rulison test from the time of the test to present day (2007), and to evaluate tritium migration under natural-gas production conditions to a hypothetical gas production well in the most vulnerable location outside the DOE drilling restriction. The natural-gas production scenario involves a hypothetical production well located 258 m horizontally away from the detonation point, outside the edge of the current drilling exclusion area. The production interval in the hypothetical well is at the same elevation as the nuclear chimney created by the detonation, in order to evaluate the location most vulnerable to tritium migration.

  11. A massive reservoir of low-excitation molecular gas at high redshift

    E-print Network

    Padeli Papadopoulos; Rob Ivison; Chris Carilli; Geraint Lewis

    2001-01-03

    Molecular hydrogen is an important component of galaxies because it fuels star formation and accretion onto AGN, the two processes that generate the large infrared luminosities of gas-rich galaxies. Observations of spectral-line emission from the tracer molecule CO are used to probe the properties of this gas. But the lines that have been studied in the local Universe, mostly the lower rotational transitions of J = 1-0 and J = 2-1, have hitherto been unobservable in high-redshift galaxies. Instead, higher transitions have been used, although the densities and temperatures required to excite these higher transitions may not be reached by much of the gas. As a result, past observations may have underestimated the total amount of molecular gas by a substantial amount. Here we report the discovery of large amounts of low-excitation molecular gas around the infrared-luminous quasar, APM 08279+5255 at z = 3.91, using the two lowest excitation lines of 12CO (J = 1-0 and J = 2-1). The maps confirm the presence of hot and dense gas near the nucleus, and reveal an extended reservoir of molecular gas with low excitation that is 10 to 100 times more massive than the gas traced by higher-excitation observations. This raises the possibility that significant amounts of low-excitation molecular gas may lurk in the environments of high-redshift (z > 3) galaxies.

  12. Gas reservoir potential of the Lower Ordovician Beekmantown Group, Quebec Lowlands, Canada

    SciTech Connect

    Dykstra, J.C.F.; Longman, M.W.

    1995-04-01

    The Beekmantown Group in the Quebec Lowlands was deposited as part of an extensive Early Ordovician coastal and shallow marine complex on the eastern margin of the North American craton. The Beekmantown is stratigraphically equivalent to the Beekmantown, Knox, Arbuckle, and Ellenburger rocks of the United States, and is subdivided into two formations: the sandstone-rich Theresa Formation and the overlying dolomite-rich Beauharnois. Dolomites of the Beekmantown provide an important exploration target in both the autochthon and the overlying thrust sheets of the Canadian and U.S. Appalachians. The reservoir potential of the autochthonous Beekmantown Group in the Quebec Lowlands can be determined from seismic data, well logs, cuttings, and petrographic analyses of depositional and diagenetic textures. Deposition of the Beekmantown occurred alongson the western passive margin of the Iapetus Ocean. By the Late Ordovician, the passive margin had been transformed into a foreland basin. Faulting locally positioned Upper Ordovician Utica source rocks against the Beekmantown and contributed to forming hydrocarbon reservoirs. The largest Beekmantown reservoir found to date is the St. Flavien field, with 7.75 bcf of original gas (methane) in place in fractured and possibly karst-influenced allochthonous dolomites within a thrust-fault anticline. Seven major depositional units can be distinguished in cuttings and correlated with wireline logs. Dolomites in the Beekmantown contain vuggy, moldic, intercrystalline, and fracture porosity. Early porosity formed at the top of the major depositional units in peritidal dolomites; however, much of this porosity was later filled by late-stage calcite cement after hydrocarbon migration. Thus, a key to finding gas reservoirs in the autochthonous Beekmantown is to define Ordovician poleostructures in which early and continuous entrapment of hydrocarbons prevented later cementation.

  13. Characteristics and genesis of the Feixianguan Formation oolitic shoal reservoir, Puguang gas field, Sichuan Basin, China

    NASA Astrophysics Data System (ADS)

    Chen, Peiyuan; Tan, Xiucheng; Yang, Huiting; Tang, Ming; Jiang, Yiwei; Jin, Xiuju; Yu, Yang

    2015-03-01

    The Lower Triassic Feixianguan Formation at the well-known Puguang gasfield in the northeastern Sichuan Basin of southwest China produces a representative oolitic reservoir, which has been the biggest marine-sourced gasfield so far in China (discovered in 2003 with proven gas reserves greater than 350×108 m3). This study combines core, thin section, and scanning electron microscopy observations, and geochemical analysis (C, O, and Sr isotopes) in order to investigate the basic characteristics and formation mechanisms of the reservoir. Observations indicate that platform margin oolitic dolomites are the most important reservoir rocks. Porosity is dominated by intergranular and intragranular solution, and moldic pore. The dolomites are characterized by medium porosity and permeability, averaging at approximately 9% and 29.7 mD, respectively. 87Sr/86Sr (0.707536-0.707934) and ?13CPDB (1.8‰-3.5‰) isotopic values indicate that the dolomitization fluid is predominantly concentrated seawater by evaporation, and the main mechanism for the oolitic dolomite formation is seepage reflux at an early stage of eodiagenesis. Both sedimentation and diagenesis (e.g., dolomitization and dissolution) have led to the formation of high-quality rocks to different degrees. Dolomite formation may have little contribution, karst may have had both positive and negative influences, and burial dissolution-TSR (thermochemical sulfate reduction) may not impact widely. The preservation of primary intergranular pores and dissolution by meteoric or mixed waters at the early stage of eogenesis are the main influences. This study may assist oil and gas exploration activities in the Puguang area and in other areas with dolomitic reservoirs.

  14. Destruction of Molecular Gas Reservoirs in Early-Type Galaxies by Active Galactic Nucleus Feedback

    E-print Network

    Kevin Schawinski; Chris J. Lintott; Daniel Thomas; Sugata Kaviraj; Serena Viti; Joseph Silk; Claudia Maraston; Marc Sarzi; Sukyoung K. Yi; Seok-Joo Joo; Emanuele Daddi; Estelle Bayet; Tom Bell; Joe Zuntz

    2009-01-12

    Residual star formation at late times in early-type galaxies and their progenitors must be suppressed in order to explain the population of red, passively evolving systems we see today. Likewise, residual or newly accreted reservoirs of molecular gas that are fuelling star formation must be destroyed. This suppression of star formation in early-type galaxies is now commonly attributed to AGN feedback wherein the reservoir of gas is heated and expelled during a phase of accretion onto the central supermassive black hole. However, direct observational evidence for a link between the destruction of this molecular gas and an AGN phase has been missing so far. We present new mm-wavelength observations from the IRAM 30m telescope of a sample of low redshift SDSS early-type galaxies currently undergoing this process of quenching of late-time star formation. Our observations show that the disappearance of the molecular gas coincides within less than 100 Myr with the onset of accretion onto the black hole and is too rapid to be due to star formation alone. Since our sample galaxies are not associated to powerful quasar activity or radio jets, we conclude that low-luminosity AGN episodes are sufficient to suppress residual star formation in early-type galaxies. This `suppression mode' of AGN feedback is very different from the `truncation mode' linked to powerful quasar activity during early phases of galaxy formation.

  15. Gas reservoir potential of the Lower Ordovician Beekmantown Group, Quebec Lowlands, Canada discussion

    SciTech Connect

    Friedman, G.M.

    1996-10-01

    Dykstra and Longman (1995), in an interesting paper, discussed the gas-reservoir potential of the Lower Ordovician Beekmantown Group of Quebec, Canada. They pointed out that the dolomites of this group provide an important exploration target in both the autochthon and the overlying thrust sheets. They then compare their rocks with those of correlative units in Oklahoma. Nowhere in their paper do they relate their study to the extensive work on these same rocks in the contiguous parts of the same basin in neighboring New York state. The purpose of this discussion is to fill in this lack and provide information on prospective Cambrian-Ordovician reservoirs in New York state, for which the Oil and Gas Investor (Anonymous, 1995a) has predicted counties of western New York are the next frontier for the Cambrian-Ordovician play. Dykstra and Longman (1995) compare their Quebec rocks with those of correlative rocks in faraway Oklahoma and completely overlook those in the same basin in nearby New York. At least one of the boreholes that we have studied in the St. Lawrence Valley is only tens of miles from their boreholes (Harris and Friedman, 1982). During the past 31 yr our team alone has published at least 50 papers and abstracts on the surface and subsurface geology of the Beekmantown Group in New York state. Dykstra and Longman`s (1995) paper provides data identical to those we have obtained for the contiguous New York Beekmantown (for a partial reference list see Friedman, 1993, 1994a, b, 1995). Because no reference to New York state is included in their reference section, I want to quote from an abstract titled {open_quotes}Gas Potential of the Eastern Overthrust...New York{close_quotes}(Friedman, s1992), which compares with their title {open_quotes}Gas Reservoir Potential...of Quebec, Canada{close_quotes} (Dykstra and Longman, 1995).

  16. Western Greece unconventional hydrocarbon potential from oil shale and shale gas reservoirs

    NASA Astrophysics Data System (ADS)

    Karakitsios, Vasileios; Agiadi, Konstantina

    2013-04-01

    It is clear that we are gradually running out of new sedimentary basins to explore for conventional oil and gas and that the reserves of conventional oil, which can be produced cheaply, are limited. This is the reason why several major oil companies invest in what are often called unconventional hydrocarbons: mainly oil shales, heavy oil, tar sand and shale gas. In western Greece exist important oil and gas shale reservoirs which must be added to its hydrocarbon potential1,2. Regarding oil shales, Western Greece presents significant underground immature, or close to the early maturation stage, source rocks with black shale composition. These source rock oils may be produced by applying an in-situ conversion process (ICP). A modern technology, yet unproven at a commercial scale, is the thermally conductive in-situ conversion technology, developed by Shell3. Since most of western Greece source rocks are black shales with high organic content, those, which are immature or close to the maturity limit have sufficient thickness and are located below 1500 meters depth, may be converted artificially by in situ pyrolysis. In western Greece, there are several extensive areas with these characteristics, which may be subject of exploitation in the future2. Shale gas reservoirs in Western Greece are quite possibly present in all areas where shales occur below the ground-water level, with significant extent and organic matter content greater than 1%, and during their geological history, were found under conditions corresponding to the gas window (generally at depths over 5,000 to 6,000m). Western Greece contains argillaceous source rocks, found within the gas window, from which shale gas may be produced and consequently these rocks represent exploitable shale gas reservoirs. Considering the inevitable increase in crude oil prices, it is expected that at some point soon Western Greece shales will most probably be targeted. Exploration for conventional petroleum reservoirs, through the interpretation of seismic profiles and the surface geological data, will simultaneously provide the subsurface geometry of the unconventional reservoirs. Their exploitation should follow that of conventional hydrocarbons, in order to benefit from the anticipated technological advances, eliminating environmental repercussions. As a realistic approach, the environmental consequences of the oil shale and shale gas exploitation to the natural environment of western Greece, which holds other very significant natural resources, should be delved into as early as possible. References 1Karakitsios V. & Rigakis N. 2007. Evolution and Petroleum Potential of Western Greece. J.Petroleum Geology, v. 30, no. 3, p. 197-218. 2Karakitsios V. 2013. Western Greece and Ionian Sea petroleum systems. AAPG Bulletin, in press. 3Bartis J.T., Latourrette T., Dixon L., Peterson D.J., Cecchine G. 2005. Oil Shale Development in the United States: Prospect and Policy Issues. Prepared for the National Energy Tech. Lab. of the U.S. Dept Energy. RAND Corporation, 65 p.

  17. Natural and Induced Fracture Diagnostics from 4-D VSP Low Permeability Gas Reservoirs

    SciTech Connect

    Mark E. Willis; Daniel R. Burns; M. Nafi Toksoz

    2008-09-30

    Tight gas sand reservoirs generally contain thick gas-charged intervals that often have low porosity and very low permeability. Natural and induced fractures provide the only means of production. The objective of this work is to locate and characterize natural and induced fractures from analysis of scattered waves recorded on 4-D (time lapse) VSP data in order to optimize well placement and well spacing in these gas reservoirs. Using model data simulating the scattering of seismic energy from hydraulic fractures, we first show that it is possible to characterize the quality of fracturing based upon the amount of scattering. In addition, the picked arrival times of recorded microseismic events provide the velocity moveout for isolating the scattered energy on the 4-D VSP data. This concept is applied to a field dataset from the Jonah Field in Wyoming to characterize the quality of the induced hydraulic fractures. The time lapse (4D) VSP data from this field are imaged using a migration algorithm that utilizes shot travel time tables derived from the first breaks of the 3D VSPs and receiver travel time tables based on the microseismic arrival times and a regional velocity model. Four azimuthally varying shot tables are derived from picks of the first breaks of over 200 VSP records. We create images of the fracture planes through two of the hydraulically fractured wells in the field. The scattered energy shows correlation with the locations of the microseismic events. In addition, the azimuthal scattering is different from the azimuthal reflectivity of the reservoir, giving us more confidence that we have separated the scattered signal from simple formation reflectivity. Variation of the scattered energy along the image planes suggests variability in the quality of the fractures in three distinct zones.

  18. HIGH RESOLUTION PREDICTION OF GAS INJECTION PROCESS PERFORMANCE FOR HETEROGENEOUS RESERVOIRS

    SciTech Connect

    Franklin M. Orr, Jr.

    2004-05-01

    This final technical report describes and summarizes results of a research effort to investigate physical mechanisms that control the performance of gas injection processes in heterogeneous reservoirs and to represent those physical effects in an efficient way in simulations of gas injection processes. The research effort included four main lines of research: (1) Efficient compositional streamline methods for 3D flow; (2) Analytical methods for one-dimensional displacements; (3) Physics of multiphase flow; and (4) Limitations of streamline methods. In the first area, results are reported that show how the streamline simulation approach can be applied to simulation of gas injection processes that include significant effects of transfer of components between phases. In the second area, the one-dimensional theory of multicomponent gas injection processes is extended to include the effects of volume change as components change phase. In addition an automatic algorithm for solving such problems is described. In the third area, results on an extensive experimental investigation of three-phase flow are reported. The experimental results demonstrate the impact on displacement performance of the low interfacial tensions between the gas and oil phases that can arise in multicontact miscible or near-miscible displacement processes. In the fourth area, the limitations of the streamline approach were explored. Results of an experimental investigation of the scaling of the interplay of viscous, capillary, and gravity forces are described. In addition results of a computational investigation of the limitations of the streamline approach are reported. The results presented in this report establish that it is possible to use the compositional streamline approach in many reservoir settings to predict performance of gas injection processes. When that approach can be used, it requires substantially less (often orders of magnitude) computation time than conventional finite difference compositional simulation.

  19. Geophysical assessments of renewable gas energy compressed in geologic pore storage reservoirs.

    PubMed

    Al Hagrey, Said Attia; Köhn, Daniel; Rabbel, Wolfgang

    2014-01-01

    Renewable energy resources can indisputably minimize the threat of global warming and climate change. However, they are intermittent and need buffer storage to bridge the time-gap between production (off peak) and demand peaks. Based on geologic and geochemical reasons, the North German Basin has a very large capacity for compressed air/gas energy storage CAES in porous saltwater aquifers and salt cavities. Replacing pore reservoir brine with CAES causes changes in physical properties (elastic moduli, density and electrical properties) and justify applications of integrative geophysical methods for monitoring this energy storage. Here we apply techniques of the elastic full waveform inversion FWI, electric resistivity tomography ERT and gravity to map and quantify a gradually saturated gas plume injected in a thin deep saline aquifer within the North German Basin. For this subsurface model scenario we generated different synthetic data sets without and with adding random noise in order to robust the applied techniques for the real field applications. Datasets are inverted by posing different constraints on the initial model. Results reveal principally the capability of the applied integrative geophysical approach to resolve the CAES targets (plume, host reservoir, and cap rock). Constrained inversion models of elastic FWI and ERT are even able to recover well the gradual gas desaturation with depth. The spatial parameters accurately recovered from each technique are applied in the adequate petrophysical equations to yield precise quantifications of gas saturations. Resulting models of gas saturations independently determined from elastic FWI and ERT techniques are in accordance with each other and with the input (true) saturation model. Moreover, the gravity technique show high sensitivity to the mass deficit resulting from the gas storage and can resolve saturations and temporal saturation changes down to ±3% after reducing any shallow fluctuation such as that of groundwater table. PMID:24936391

  20. HIGH RESOLUTION PREDICTION OF GAS INJECTION PROCESS PERFORMANCE FOR HETEROGENEOUS RESERVOIRS

    SciTech Connect

    Franklin M. Orr, Jr.

    2001-03-31

    This report outlines progress in the second 3 months of the first year of the DOE project ''High Resolution Prediction of Gas Injection Process Performance for Heterogeneous Reservoirs.'' The development of an automatic technique for analytical solution of one-dimensional gas flow problems with volume change on mixing is described. The aim of this work is to develop a set of ultra-fast compositional simulation tools that can be used to make field-scale predictions of the performance of gas injection processes. To achieve the necessary accuracy, these tools must satisfy the fundamental physics and chemistry of the displacement from the pore to the reservoir scales. Thus this project focuses on four main research areas: (1) determination of the most appropriate methods of mapping multicomponent solutions to streamlines and streamtubes in 3D; (2) development of techniques for automatic generation of analytical solutions for one-dimensional flow along a streamline; (3) experimental investigations to improve the representation of physical mechanisms that govern displacement efficiency along a streamline; and (4) theoretical and experimental investigations to establish the limitations of the streamline/streamtube approach. In this report they briefly review the status of the research effort in each area. They then give a more in depth discussion of their development of techniques for analytic solutions along a streamline including volume change on mixing for arbitrary numbers of components.

  1. Core acid treatment influence on well reservoir properties in Kazan oil-gas condensate field

    NASA Astrophysics Data System (ADS)

    Janishevskii, A.; Ezhova, A.

    2015-11-01

    The research involves investigation of the influence of hydrochloric acid (HCI-12%) and mud acid (mixture: HCl - 10% and HF - 3%) treatment on the Upper-Jurassic reservoir properties in Kazan oil-gas condensate field wells. The sample collection included three lots of core cylinders from one and the same depth (all in all 42). Two lots of core cylinders were distributed as following: first lot - reservoir properties were determined, and, then thin sections were cut off from cylinder faces; second lot- core cylinders were exposed to hydrochloric acid treatment, then, after flushing the reservoir properties were determined, and thin sections were prepared. Based on the quantitative petrographic rock analysis, involvin 42 thin sections, the following factors were determined: granulometric mineral composition, cement content, intergranular contacts and pore space structure. According to the comparative analysis of initial samples, the following was determined: content decrease of feldspar, clay and mica fragments, mica, clay and carbonate cement; increase of pore spaces while in the investigated samples- on exposure of rocks to acids effective porosity and permeability value range is ambiguous.

  2. New method for gas and oil shale reservoirs characterisation using magnetic analysis

    NASA Astrophysics Data System (ADS)

    Ivakhnenko, Aleksandr; Telman, Meruert; Makarova, Maria; Zhaksylyk, Zhanaim; Abirov, Rustem; Makhatova, Meruyert

    2015-04-01

    This research describes proposed method for determination of total organic content (TOC), clay typing and relative degree of maturation in shale unconventional reservoirs based on analysis of magnetic properties of shales. Experimental measurements were undertaken in shales from United Kingdom (Edinburgh shales) and Kazakhstan for comparison of their magnetic properties, including low field and high field magnetic susceptibilities, together with SEM and XRD analysis. The results showed that studied shales comprised of various clay types had different capacity in accumulation of organic matter, thus, affecting the total organic content and magnetic properties. Based on the results we proposed magnetic indicators (MI) of productive gas and oil shale intervals in order to determine relative TOC, clay typing and a degree of maturation. The set of magnetic measurements, used as a logging tool or core scanning procedure, can potentially provide data about selecting the best shale productive reservoir horizons. This can be a non-destructive and rapid method for shale reservoir characterization, being used routinely in both laboratory and field conditions.

  3. An efficient parallel algorithm for three-dimensional analysis of subsidence above gas reservoirs

    NASA Astrophysics Data System (ADS)

    Schrefler, B. A.; Wang, X.; Salomoni, V. A.; Zuccolo, G.

    1999-09-01

    In this paper an efficient parallel algorithm to solve a three-dimensional problem of subsidence above exploited gas reservoirs is presented. The parallel program is developed on a cluster of workstations. The parallel virtual machine (PVM) system is used to handle communications among networked workstations. The method has advantages such as numbering of the finite element mesh in an arbitrary manner, simple programming organization, smaller core requirements and computation times. An implementation of this parallel method on workstations is discussed, the speed-up and efficiency of this method being demonstrated by a numerical example. Copyright

  4. Application of Fast Marching Method in Shale Gas Reservoir Model Calibration 

    E-print Network

    Yang, Changdong

    2013-07-26

    stream_source_info Thesis_ChangdongYang_revise3.doc.txt stream_content_type text/plain stream_size 92358 Content-Encoding windows-1252 stream_name Thesis_ChangdongYang_revise3.doc.txt Content-Type text/plain; charset=windows-1252... APPLICATION OF FAST MARCHING METHOD IN SHALE GAS RESERVOIR MODEL CALIBRATION A Thesis by Changdong Yang Submitted to the Office of Graduate Studies of Texas A&M University in partial fulfillment of the requirements for the degree of master...

  5. Relief-well requirements to kill a high-rate gas blowout from a deepwater reservoir

    SciTech Connect

    Warriner, R.A. ); Cassity, T.G. )

    1988-12-01

    Relief-well requirements were investigated for a dynamic kill of a high-rate gas blowout from a deepwater reservoir to define any necessary special procedures or equipment. Results of the investigation show that a high injection rate and a special-design large-diameter injection riser are required to dynamically kill such a blowout with seawater. The injection riser is necessary to limit surface pump pressure during the high-rate kill operation. Procedures to complete the kill operation hydrostatically with heavy fluid following the dynamic kill are outlined.

  6. Reservoir characterization of marine and permafrost associated gas hydrate accumulations with downhole well logs

    USGS Publications Warehouse

    Collett, T.S.; Lee, M.W.

    2000-01-01

    Gas volumes that may be attributed to a gas hydrate accumulation depend on a number of reservoir parameters, one of which, gas-hydrate saturation, can be assessed with data obtained from downhole well-logging devices. This study demonstrates that electrical resistivity and acoustic transit-time downhole log data can be used to quantify the amount of gas hydrate in a sedimentary section. Two unique forms of the Archie relation (standard and quick look relations) have been used in this study to calculate water saturations (S(w)) [gas-hydrate saturation (S(h)) is equal to (1.0 - S(w))] from the electrical resistivity log data in four gas hydrate accumulations. These accumulations are located on (1) the Blake Ridge along the Southeastern continental margin of the United States, (2) the Cascadia continental margin off the pacific coast of Canada, (3) the North Slope of Alaska, and (4) the Mackenzie River Delta of Canada. Compressional wave acoustic log data have also been used in conjunction with the Timur, modified Wood, and the Lee weighted average acoustic equations to calculate gas-hydrate saturations in all four areas assessed.

  7. Carbon dioxide and helium emissions from a reservoir of magmatic gas beneath Mammoth Mountain, California

    USGS Publications Warehouse

    Sorey, M.L.; Evans, William C.; Kennedy, B.M.; Farrar, C.D.; Hainsworth, L.J.; Hausback, B.

    1998-01-01

    Carbon dioxide and helium with isotopic compositions indicative of a magmatic source (??13C = -4.5 to -5???, 3He/4He = 4.5 to 6.7 RA) are discharging at anomalous rates from Mammoth Mountain, on the southwestern rim of the Long Valley caldera in eastern California. The gas is released mainly as diffuse emissions from normal-temperature soils, but some gas issues from steam vents or leaves the mountain dissolved in cold groundwater. The rate of gas discharge increased significantly in 1989 following a 6-month period of persistent earthquake swarms and associated strain and ground deformation that has been attributed to dike emplacement beneath the mountain. An increase in the magmatic component of helium discharging in a steam vent on the north side of Mammoth Mountain, which also began in 1989, has persisted until the present time. Anomalous CO2 discharge from soils first occurred during the winter of 1990 and was followed by observations of several areas of tree kill and/or heavier than normal needlecast the following summer. Subsequent measurements have confirmed that the tree kills are associated with CO2 concentrations of 30-90% in soil gas and gas flow rates of up to 31,000 g m-2 d-1 at the soil surface. Each of the tree-kill areas and one area of CO2 discharge above tree line occurs in close proximity to one or more normal faults, which may provide conduits for gas flow from depth. We estimate that the total diffuse CO2 flux from the mountain is approximately 520 t/d, and that 30-50 t/d of CO2 are dissolved in cold groundwater flowing off the flanks of the mountain. Isotopic and chemical analyses of soil and fumarolic gas demonstrate a remarkable homogeneity in composition, suggesting that the CO2 and associated helium and excess nitrogen may be derived from a common gas reservoir whose source is associated with some combination of magmatic degassing and thermal metamorphism of metasedimentary rocks. Furthermore, N2/Ar ratios and nitrogen isotopic values indicate that the Mammoth Mountain gases are derived from sources separate from those that supply gas to the hydrothermal system within the Long Valley caldera. Various data suggest that the Mammoth Mountain gas reservoir is a large, low-temperature cap over an isolated hydrothermal system, that it predates the 1989 intrusion, and that it could remain a source of gas discharge for some time.

  8. Characterization of the deep microbial life in the Altmark natural gas reservoir

    NASA Astrophysics Data System (ADS)

    Morozova, D.; Alawi, M.; Vieth-Hillebrand, A.; Kock, D.; Krüger, M.; Wuerdemann, H.; Shaheed, M.

    2010-12-01

    Within the framework of the CLEAN project (CO2 Largescale Enhanced gas recovery in the Altmark Natural gas field) technical basics with special emphasis on process monitoring are explored by injecting CO2 into a gas reservoir. Our study focuses on the investigation of the in-situ microbial community of the Rotliegend natural gas reservoir in the Altmark, located south of the city Salzwedel, Germany. In order to characterize the microbial life in the extreme habitat we aim to localize and identify microbes including their metabolism influencing the creation and dissolution of minerals. The ability of microorganisms to speed up dissolution and formation of minerals might result in changes of the local permeability and the long-term safety of CO2 storage. However, geology, structure and chemistry of the reservoir rock and the cap rock as well as interaction with saline formation water and natural gases and the injected CO2 affect the microbial community composition and activity. The reservoir located at the depth of approximately 3500 m, is characterised by high salinity (420 g/l) and temperatures up to 127°C. It represents an extreme environment for microbial life and therefore the main focus is on hyperthermophilic, halophilic anaerobic microorganisms. In consequence of the injection of large amounts of CO2 in the course of a commercial EGR (Enhanced Gas Recovery), the environmental conditions (e.g. pH, temperature, pressure and solubility of minerals) for the autochthonous microorganisms will change. Genetic profiling of amplified 16S rRNA genes are applied for detecting structural changes in the community by using PCR- SSCP (PCR-Single-Strand-Conformation Polymorphism), DGGE (Denaturing Gradient Gel Electrophoresis) and 16S rRNA cloning. First results of the baseline survey indicate the presence of microorganisms similar to representatives from other deep environments. The sequence analyses revealed the presence of several H2-oxidising bacteria (Hydrogenophaga sp., Adicdovorax sp., Ralstonia sp., Pseudomonas sp.), thiosulfate-oxidising bacteria (Diaphorobacter sp.) and biocorrosive thermophilic microorganisms, which have not previously been cultivated. Furthermore, several uncultivated microorganisms were found, that were similar to representatives from other saline, hot, anoxic, deep environments. However, due to the hypersaline and hyperthermophilic reservoir conditions, cell numbers are low, so that the quantification of those microorganisms as well as the determination of microbial activity was not yet possible. Microbial monitoring methods have to be further developed to study microbial activities under these extreme conditions to access their influence on the EGR technique and on enhancing the long term safety of the process by fixation of carbon dioxide by precipitation of carbonates. We thank GDF SUEZ for providing the data for the Rotliegend reservoir, sample material and supporting sampling campaigns. The CLEAN project is funded by the German Federal Ministry of Education and Research (BMBF) in the framework of the GEOTECHNOLOGIEN Program.

  9. Geology, reservoir engineering and methane hydrate potential of the Walakpa Gas Field, North Slope, Alaska. Final report

    SciTech Connect

    Glenn, R.K.; Allen, W.W.

    1992-12-01

    The Walakpa Gas Field, located near the city of Barrow on Alaska`s North Slope, has been proven to be methane-bearing at depths of 2000--2550 feet below sea level. The producing formation is a laterally continuous, south-dipping, Lower Cretaceous shelf sandstone. The updip extent of the reservoir has not been determined by drilling, but probably extends to at least 1900 feet below sea level. Reservoir temperatures in the updip portion of the reservoir may be low enough to allow the presence of in situ methane hydrates. Reservoir net pay however, decreases to the north. Depths to the base of permafrost in the area average 940 feet. Drilling techniques and production configuration in the Walakpa field were designed to minimize formation damage to the reservoir sandstone and to eliminate methane hydrates formed during production. Drilling development of the Walakpa field was a sequential updip and lateral stepout from a previously drilled, structurally lower confirmation well. Reservoir temperature, pressure, and gas chemistry data from the development wells confirm that they have been drilled in the free-methane portion of the reservoir. Future studies in the Walakpa field are planned to determine whether or not a component of the methane production is due to the dissociation of updip in situ hydrates.

  10. Influence of depositional environment and diagenesis on gas reservoir properties in St. Peter Sandstone, Michigan basin

    SciTech Connect

    Harrison, W.B. III; Turmelle, T.M.; Barnes, D.A.

    1987-05-01

    The St. Peter Sandstone in the Michigan basin subsurface is rapidly becoming a major exploration target for natural gas. This reservoir was first proven with the successful completion of the Dart-Edwards 7-36 (Falmouth field, Missaukee County, Michigan) in 1981. Fifteen fields now are known, with a maximum of three producing wells in any one field. The production from these wells ranges from 1 to more than 10 MMCFGD on choke, with light-gravity condensate production of up to 450 b/d. Depth to the producing intervals ranges from about 7000 ft to more than 11,000 ft. The St. Peter Sandstone is an amalgamated stack of shoreface and shelf sequences more than 1100 ft in thickness in the basin center and thinning to zero at the basin margins. Sandstone composition varies from quartzarenite in the coarser sizes to subarkose and arkose in the finer sizes. Thin salty/shaly lithologies and dolomite-cemented sandstone intervals separate the porous sandstone packages. Two major lithofacies are recognized in the basin: a coarse-grained, well-sorted quartzarenite with various current laminations and a fine-grained, more poorly sorted subarkose and arkose with abundant bioturbation and distinct vertical and horizontal burrows. Reservoir quality is influenced by original depositional and diagenetic fabrics, but there is inversion of permeability and porosity with respect to primary textures in the major lithofacies. The initially highly porous and permeable, well-sorted, coarser facies is now tightly cemented with syntaxial quartz cement, resulting in a low-permeability, poor quality reservoir. The more poorly sorted, finer facies with initially lower permeabilities did not receive significant fluid flux until it passed below the zone of quartz cementation. This facies was cemented with carbonate which has subsequently dissolved to form a major secondary porosity reservoir.

  11. Evidence for Expulsion of the Star Formation Gas Reservoir by the AGN in Local Blue Ellipticals

    NASA Astrophysics Data System (ADS)

    Schwamb, Megan E.; Lintott, Chris; Smethurst, Rebecca; Kruk, Sandor; Matsushita, Satoki; Wong, Ivy; Wang, Shiang-Yu

    2016-01-01

    The formation and assembly of the local galaxy population remains a major open question. Recent works show that elliptical galaxies can rapidly transition from blue star forming to red quiescent systems. Such rapid reddening of stellar populations implies that gas reservoirs are being depleted on timescales which are much shorter than mere exhaustion thanks to ongoing star formation. Feedback, either from star formation itself or from nuclear activity associated with black hole growth is typically invoked. Yet observational confirmation has remained elusive.Using the 10.4-m CSO, we recently obtained 12CO(2-1) observations for a sample of blue star forming local elliptical galaxies to probe the state of the gas and look at the changes in excitation temperature across the star forming sequence. Previous IRAM 12CO(1-0) measurements indicate this population is undergoing a sudden decline in molecular gas fraction. This drop occurs ~200 Myr after a recent peak in star formation- a timescale suggesting AGN triggered feedback switches on rapidly and is immediately effective. The jets or outflows from the central supermassive black hole likely either heat or expel residual gas cutting off star formation, but the 12CO(1-0) measurements alone were insufficient to distinguish between these two scenarios. The 12CO(2-1) to 12CO(1-0) ratio has previously proved diagnostic of the conditions which exist in star forming galaxies. Combining the new 12CO(2-1) measurements with the previous 12CO(1-0) data, we find evidence for active quenching of star formation due to the expulsion of the gas reservoir by the central massive black holes residing in these galaxies. We will discuss our observations and analysis and compare our results to those from other early type populations.

  12. HIGH RESOLUTION PREDICTION OF GAS INJECTION PROCESS PERFORMANCE FOR HETEROGENEOUS RESERVOIRS

    SciTech Connect

    Franklin M. Orr, Jr.

    2003-06-30

    This report presents a detailed analysis of the development of miscibility during gas cycling in condensates and the formation of condensate banks at the leading edge of the displacement front. Dispersion-free, semi-analytical one-dimensional (1D) calculations are presented for enhanced condensate recovery by gas injection. The semi-analytical approach allows investigation of the possible formation of condensate banks (often at saturations that exceed the residual liquid saturation) and also allows fast screening of optimal injection gas compositions. We describe construction of the semi-analytical solutions, a process which differs in some ways from related displacements for oil systems. We use an analysis of key equilibrium tie lines that are part of the displacement composition path to demonstrate that the mechanism controlling the development of miscibility in gas condensates may vary from first-contact miscible drives to pure vaporizing and combined vaporizing/condensing drives. Depending on the compositions of the condensate and the injected gas, multicontact miscibility can develop at the dew point pressure, or below the dew point pressure of the reservoir fluid mixture. Finally, we discuss the possible impact on performance prediction of the formation of a mobile condensate bank at the displacement front in near-miscible gas cycling/injection schemes.

  13. Numerical Modeling of Fractured Shale-Gas and Tight-Gas Reservoirs Using Unstructured Grids 

    E-print Network

    Olorode, Olufemi Morounfopefoluwa

    2012-02-14

    Various models featuring horizontal wells with multiple induced fractures have been proposed to characterize flow behavior over time in tight gas and shale gas systems. Currently, there is little consensus regarding the effects of non...

  14. Structural-Diagenetic Controls on Fracture Opening in Tight Gas Sandstone Reservoirs, Alberta Foothills

    NASA Astrophysics Data System (ADS)

    Ukar, Estibalitz; Eichhubl, Peter; Fall, Andras; Hooker, John

    2013-04-01

    In tight gas reservoirs, understanding the characteristics, orientation and distribution of natural open fractures, and how these relate to the structural and stratigraphic setting are important for exploration and production. Outcrops provide the opportunity to sample fracture characteristics that would otherwise be unknown due to the limitations of sampling by cores and well logs. However, fractures in exhumed outcrops may not be representative of fractures in the reservoir because of differences in burial and exhumation history. Appropriate outcrop analogs of producing reservoirs with comparable geologic history, structural setting, fracture networks, and diagenetic attributes are desirable but rare. The Jurassic to Lower Cretaceous Nikanassin Formation from the Alberta Foothills produces gas at commercial rates where it contains a network of open fractures. Fractures from outcrops have the same diagenetic attributes as those observed in cores <100 km away, thus offering an ideal opportunity to 1) evaluate the distribution and characteristics of opening mode fractures relative to fold cores, hinges and limbs, 2) compare the distribution and attributes of fractures in outcrop vs. core samples, 3) estimate the timing of fracture formation relative to the evolution of the fold-and-thrust belt, and 4) estimate the degradation of fracture porosity due to postkinematic cementation. Cathodoluminescence images of cemented fractures in both outcrop and core samples reveal several generations of quartz and ankerite cement that is synkinematic and postkinematic relative to fracture opening. Crack-seal textures in synkinematic quartz are ubiquitous, and well-developed cement bridges abundant. Fracture porosity may be preserved in fractures wider than ~100 microns. 1-D scanlines in outcrop and core samples indicate fractures are most abundant within small parasitic folds within larger, tight, mesoscopic folds. Fracture intensity is lower away from parasitic folds; intensity progressively decreases from the faulted cores of mesoscopic folds to their forelimbs, with lowest intensities within relatively undeformed backlimb strata. Fracture apertures locally increase adjacent to reverse faults without an overall increase in fracture frequency. Fluid inclusion analyses of crack-seal quartz cement indicate both aqueous and methane-rich inclusions are present. Homogenization temperatures of two-phase inclusions indicate synkinematic fracture cement precipitation and fracture opening under conditions at or near maximum burial of 190-210°C in core samples, and 120-160°C in outcrop samples. In comparison with the fracture evolution in other, less deformed tight-gas sandstone reservoirs such as the Piceance and East Texas basins where fracture opening is primarily controlled by gas generation, gas charge, and pore fluid pressure, these results suggest a strong control of regional tectonic processes on fracture generation. In conjunction with timing and rate of gas charge, rates of fracture cement growth, and stratigraphic-lithological controls, these processes determine the overall distribution of open fractures in these reservoirs.

  15. Structural-Diagenetic Controls on Fracture Opening in Tight Gas Sandstone Reservoirs, Alberta Foothills

    NASA Astrophysics Data System (ADS)

    Ukar, E.; Eichhubl, P.; Fall, A.; Hooker, J. N.

    2012-12-01

    In tight gas reservoirs, understanding the characteristics, orientation and distribution of natural open fractures, and how these relate to the structural and stratigraphic setting are important for exploration and production. Outcrops provide the opportunity to sample fracture characteristics that would otherwise be unknown due to the limitations of sampling by cores and well logs. However, fractures in exhumed outcrops may not be representative of fractures in the reservoir because of differences in burial and exhumation history. Appropriate outcrop analogs of producing reservoirs with comparable geologic history, structural setting, fracture networks, and diagenetic attributes are desirable but rare. The Jurassic to Lower Cretaceous Nikanassin Formation from the Alberta Foothills produces gas at commercial rates where it contains a network of open fractures. Fractures from outcrops have the same diagenetic attributes as those observed in cores <100 km away, thus offering an ideal opportunity to 1) evaluate the distribution and characteristics of opening mode fractures relative to fold cores, hinges and limbs, 2) compare the distribution and attributes of fractures in outcrop vs. core samples, 3) estimate the timing of fracture formation relative to the evolution of the fold-and-thrust belt, and 4) estimate the degradation of fracture porosity due to postkinematic cementation. Cathodoluminescence images of cemented fractures in both outcrop and core samples reveal several generations of quartz and ankerite cement that is synkinematic and postkinematic relative to fracture opening. Crack-seal textures in synkinematic quartz are ubiquitous, and well-developed cement bridges abundant. Fracture porosity may be preserved in fractures wider than ~100 microns. 1-D scanlines in outcrop and core samples indicate fractures are most abundant within small parasitic folds within larger, tight, mesoscopic folds. Fracture intensity is lower away from parasitic folds; intensity progressively decreases from the faulted cores of mesoscopic folds to their forelimbs, with lowest intensities within relatively undeformed backlimb strata. Fracture apertures locally increase adjacent to reverse faults without an overall increase in fracture frequency. Fluid inclusion analyses of crack-seal quartz cement indicate both aqueous and methane-rich inclusions are present. Homogenization temperatures of two-phase inclusions indicate synkinematic fracture cement precipitation and fracture opening under conditions at or near maximum burial of 190-210°C in core samples, and 120-160°C in outcrop samples. In comparison with the fracture evolution in other, less deformed tight-gas sandstone reservoirs such as the Piceance and East Texas basins where fracture opening is primarily controlled by gas generation, gas charge, and pore fluid pressure, these results suggest a strong control of regional tectonic processes on fracture generation. In conjunction with timing and rate of gas charge, rates of fracture cement growth, and stratigraphic-lithological controls, these processes determine the overall distribution of open fractures in these reservoirs.

  16. Numerical simulations of the Macondo well blowout reveal strong control of oil flow by reservoir permeability and exsolution of gas

    PubMed Central

    Oldenburg, Curtis M.; Freifeld, Barry M.; Pruess, Karsten; Pan, Lehua; Finsterle, Stefan; Moridis, George J.

    2012-01-01

    In response to the urgent need for estimates of the oil and gas flow rate from the Macondo well MC252-1 blowout, we assembled a small team and carried out oil and gas flow simulations using the TOUGH2 codes over two weeks in mid-2010. The conceptual model included the oil reservoir and the well with a top boundary condition located at the bottom of the blowout preventer. We developed a fluid properties module (Eoil) applicable to a simple two-phase and two-component oil-gas system. The flow of oil and gas was simulated using T2Well, a coupled reservoir-wellbore flow model, along with iTOUGH2 for sensitivity analysis and uncertainty quantification. The most likely oil flow rate estimated from simulations based on the data available in early June 2010 was about 100,000 bbl/d (barrels per day) with a corresponding gas flow rate of 300 MMscf/d (million standard cubic feet per day) assuming the well was open to the reservoir over 30 m of thickness. A Monte Carlo analysis of reservoir and fluid properties provided an uncertainty distribution with a long tail extending down to 60,000 bbl/d of oil (170 MMscf/d of gas). The flow rate was most strongly sensitive to reservoir permeability. Conceptual model uncertainty was also significant, particularly with regard to the length of the well that was open to the reservoir. For fluid-entry interval length of 1.5 m, the oil flow rate was about 56,000 bbl/d. Sensitivity analyses showed that flow rate was not very sensitive to pressure-drop across the blowout preventer due to the interplay between gas exsolution and oil flow rate. PMID:21730177

  17. Numerical simulations of the Macondo well blowout reveal strong control of oil flow by reservoir permeability and exsolution of gas.

    PubMed

    Oldenburg, Curtis M; Freifeld, Barry M; Pruess, Karsten; Pan, Lehua; Finsterle, Stefan; Moridis, George J

    2012-12-11

    In response to the urgent need for estimates of the oil and gas flow rate from the Macondo well MC252-1 blowout, we assembled a small team and carried out oil and gas flow simulations using the TOUGH2 codes over two weeks in mid-2010. The conceptual model included the oil reservoir and the well with a top boundary condition located at the bottom of the blowout preventer. We developed a fluid properties module (Eoil) applicable to a simple two-phase and two-component oil-gas system. The flow of oil and gas was simulated using T2Well, a coupled reservoir-wellbore flow model, along with iTOUGH2 for sensitivity analysis and uncertainty quantification. The most likely oil flow rate estimated from simulations based on the data available in early June 2010 was about 100,000 bbl/d (barrels per day) with a corresponding gas flow rate of 300 MMscf/d (million standard cubic feet per day) assuming the well was open to the reservoir over 30 m of thickness. A Monte Carlo analysis of reservoir and fluid properties provided an uncertainty distribution with a long tail extending down to 60,000 bbl/d of oil (170 MMscf/d of gas). The flow rate was most strongly sensitive to reservoir permeability. Conceptual model uncertainty was also significant, particularly with regard to the length of the well that was open to the reservoir. For fluid-entry interval length of 1.5 m, the oil flow rate was about 56,000 bbl/d. Sensitivity analyses showed that flow rate was not very sensitive to pressure-drop across the blowout preventer due to the interplay between gas exsolution and oil flow rate. PMID:21730177

  18. Electrochromically switched, gas-reservoir metal hydride devices with application to energy-efficient windows

    SciTech Connect

    Anders, Andre; Slack, Jonathan L.; Richardson, Thomas J.

    2008-05-05

    Proof-of-principle gas-reservoir MnNiMg electrochromic mirror devices have been investigated. In contrast to conventional electrochromic approaches, hydrogen is stored (at low concentration) in the gas volume between glass panes of the insulated glass units (IGUs). The elimination of a solid state ion storage layer simplifies the layer stack, enhances overall transmission, and reduces cost. The cyclic switching properties were demonstrated and system durability improved with the incorporation a thin Zr barrier layer between the MnNiMg layer and the Pd catalyst. Addition of 9 percent silver to the palladium catalyst further improved system durability. About 100 full cycles have been demonstrated before devices slow considerably. Degradation of device performance appears to be related to Pd catalyst mobility, rather than delamination or metal layer oxidation issues originally presumed likely to present significant challenges.

  19. Timing and Duration of Gas Charge-Driven Fracturing in Tight-Gas Sandstone Reservoirs Based on Fluid Inclusion Observations: Piceance Basin, Colorado

    NASA Astrophysics Data System (ADS)

    Fall, A.; Eichhubl, P.; Laubach, S.; Bodnar, R. J.

    2012-12-01

    Natural fractures are universally present in tight-gas sandstone reservoirs. Fractures are recognized to enhance permeability of the reservoir, provide gas-migration pathways during charge, and boost connectivity with well bore during production of natural gas. "Sweet spots", or higher than average permeability and production regions, have been attributed to the presence of open fractures in the reservoir. Thus it is essential to understand the opening history of natural fractures, such as the timing with respect to hydrocarbon generation and migration in the reservoirs. The natural opening-mode fractures in the tight-gas sandstone of the Mesaverde Group in the Piceance Basin, Colorado, are partially or completely cemented by quartz and/or calcite that precipitated syn- or postkinematically relative to fracture opening. Fluid inclusions trapped in the cements record pressure, temperature, and fluid composition during subsequent fracture opening and cementation. SEM-CL imaging of cements combined with fluid inclusion microthermometry and Raman spectroscopy constrain fluid evolution trends during fracturing, and timing of fracture opening in the tight-gas sandstone reservoirs. Fluid inclusions indicate a thermal history varying from ~150°C to ~188°C to ~140°C in sandstones of the Piceance Basin. Based on microthermometry, Raman spectroscopy, and equation of state modeling calculated pore-fluid pressures varied from ~40 to 100 MPa suggesting fracture opening under significant pore-fluid overpressures. Observed variability in pore-fluid pressure over time is interpreted to reflect dynamic conditions of episodic gas charge. Models of gas and oil generation in the Piceance Basin suggest that fracture opening and elevated pore-fluid pressures coincided with maximum gas generation within the Mesaverde Group. These observations demonstrate that protracted growth of the pervasive fracture system was the consequence of gas maturation and reservoir charge, and that fracture opening lasted for ~35 m.y.

  20. The effect of reservoir heterogeneity on gas production from hydrate accumulations in the permafrost

    SciTech Connect

    Reagan, M. T.; Kowalsky, M B.; Moridis, G. J.; Silpngarmlert, S.

    2010-05-01

    The quantity of hydrocarbon gases trapped in natural hydrate accumulations is enormous, leading to significant interest in the evaluation of their potential as an energy source. Large volumes of gas can be readily produced at high rates for long times from methane hydrate accumulations in the permafrost by means of depressurization-induced dissociation combined with conventional technologies and horizontal or vertical well configurations. Initial studies on the possibility of natural gas production from permafrost hydrates assumed homogeneity in intrinsic reservoir properties and in the initial condition of the hydrate-bearing layers (either due to the coarseness of the model or due to simplifications in the definition of the system). These results showed great promise for gas recovery from Class 1, 2, and 3 systems in the permafrost. This work examines the consequences of inevitable heterogeneity in intrinsic properties, such as in the porosity of the hydrate-bearing formation, or heterogeneity in the initial state of hydrate saturation. Heterogeneous configurations are generated through multiple methods: (1) through defining heterogeneous layers via existing well-log data, (2) through randomized initialization of reservoir properties and initial conditions, and (3) through the use of geostatistical methods to create heterogeneous fields that extrapolate from the limited data available from cores and well-log data. These extrapolations use available information and established geophysical methods to capture a range of deposit properties and hydrate configurations. The results show that some forms of heterogeneity, such as horizontal stratification, can assist in production of hydrate-derived gas. However, more heterogeneous structures can lead to complex physical behavior within the deposit and near the wellbore that may obstruct the flow of fluids to the well, necessitating revised production strategies. The need for fine discretization is crucial in all cases to capture dynamic behavior during production.

  1. Establishment of an oil and gas database for increased recovery and characterization of oil and gas carbonate reservoir heterogeneity. [Jurassic Smackover Formation

    SciTech Connect

    Mancini, E.A.

    1990-01-01

    The objective of this project is to augment the National Reservoir Database (TORIS database), to increase our understanding of geologic heterogeneities that affect the recoveries of oil and gas from carbonate reservoirs in the State of Alabama, and to identify resources that are producible at moderate cost. This objective will be achieved through detailed geological, geostatistical, and engineering characterization of typical Jurassic Smackover Formation hydrocarbon, and engineering characterization of typical Jurassic Smackover Formation hydrocarbon reservoirs in selected productive fields in the state of Alabama. The results of these studies will be used to develop and test mathematical models for prediction of the effects of reservoir heterogeneities in hydrocarbon production. Work to date has focused on completion of Subtasks 1, 2, and 3 of this project. Work on Subtask 4 began in this quarter, and substantial additional work has been accomplished on Subtask 2. Subtask 1 included the survey and tabulation of available reservoir engineering and geological data. Subtask 2 comprises the geologic and engineering characterization of smackover reservoir lithofacies. Subtask 3 includes the geologic modeling of reservoir heterogeneities. Subtask 4 includes the development of reservoir exploitation methodologies for strategic infill drilling. 1 fig.

  2. ALMA probes the molecular gas reservoirs in the changing-look Seyfert galaxy Mrk 590

    NASA Astrophysics Data System (ADS)

    Koay, J. Y.; Vestergaard, M.; Casasola, V.; Lawther, D.; Peterson, B. M.

    2016-01-01

    We investigate if the active galactic nucleus (AGN) of Mrk 590, whose supermassive black hole was until recently highly accreting, is turning off due to a lack of central gas to fuel it. We analyse new subarcsecond resolution Atacama Large Millimetre/submilllimetre Array maps of the 12CO(3-2) line and 344 GHz continuum emission in Mrk 590. We detect no 12CO(3-2) emission in the inner 150 pc, constraining the central molecular gas mass to M(H2) ? 1.6 × 105 M?, no more than a typical giant molecular gas cloud, for a CO luminosity to gas mass conversion factor of ?CO ˜ 0.8 M? (K km s- 1 pc2)- 1. However, there is still potentially enough gas to fuel the black hole for another 2.6 × 105 yr assuming Eddington-limited accretion. We therefore cannot rule out that the AGN may just be experiencing a temporary feeding break, and may turn on again in the near future. We discover a ring-like structure at a radius of ˜1 kpc, where a gas clump exhibiting disturbed kinematics and located just ˜200 pc west of the AGN, may be refuelling the centre. Mrk 590 does not have significantly less gas than other nearby AGN host galaxies at kpc scales, confirming that gas reservoirs at these scales provide no direct indication of on-going AGN activity and accretion rates. Continuum emission detected in the central 150 pc likely originates from warm AGN-heated dust, although contributions from synchrotron and free-free emission cannot be ruled out.

  3. Geochemical analysis of atlantic rim water, carbon county, wyoming: New applications for characterizing coalbed natural gas reservoirs

    USGS Publications Warehouse

    McLaughlin, J.F.; Frost, C.D.; Sharma, S.

    2011-01-01

    Coalbed natural gas (CBNG) production typically requires the extraction of large volumes of water from target formations, thereby influencing any associated reservoir systems. We describe isotopic tracers that provide immediate data on the presence or absence of biogenic natural gas and the identify methane-containing reservoirs are hydrologically confined. Isotopes of dissolved inorganic carbon and strontium, along with water quality data, were used to characterize the CBNG reservoirs and hydrogeologic systems of Wyoming's Atlantic Rim. Water was analyzed from a stream, springs, and CBNG wells. Strontium isotopic composition and major ion geochemistry identify two groups of surface water samples. Muddy Creek and Mesaverde Group spring samples are Ca-Mg-S04-type water with higher 87Sr/86Sr, reflecting relatively young groundwater recharged from precipitation in the Sierra Madre. Groundwaters emitted from the Lewis Shale springs are Na-HCO3-type waters with lower 87Sr/86Sr, reflecting sulfate reduction and more extensive water-rock interaction. To distinguish coalbed waters, methanogenically enriched ??13CDIC wasused from other natural waters. Enriched ??13CDIC, between -3.6 and +13.3???, identified spring water that likely originates from Mesaverde coalbed reservoirs. Strongly positive ??13CDIC, between +12.6 and +22.8???, identified those coalbed reservoirs that are confined, whereas lower ??13CDIC, between +0.0 and +9.9???, identified wells within unconfined reservoir systems. Copyright ?? 2011. The American Association of Petroleum Geologists. All rights reserved.

  4. An evaluation of the deep reservoir conditions of the Bacon-Manito geothermal field, Philippines using well gas chemistry

    SciTech Connect

    D'Amore, Franco; Maniquis-Buenviaje, Marinela; Solis, Ramonito P.

    1993-01-28

    Gas chemistry from 28 wells complement water chemistry and physical data in developing a reservoir model for the Bacon-Manito geothermal project (BMGP), Philippines. Reservoir temperature, THSH, and steam fraction, y, are calculated or extrapolated from the grid defined by the Fischer-Tropsch (FT) and H2-H2S (HSH) gas equilibria reactions. A correction is made for H2 that is lost due to preferential partitioning into the vapor phase and the reequilibration of H2S after steam loss.

  5. Coupling Hydraulic Fracturing Propagation and Gas Well Performance for Simulation of Production in Unconventional Shale Gas Reservoirs

    NASA Astrophysics Data System (ADS)

    Wang, C.; Winterfeld, P. H.; Wu, Y. S.; Wang, Y.; Chen, D.; Yin, C.; Pan, Z.

    2014-12-01

    Hydraulic fracturing combined with horizontal drilling has made it possible to economically produce natural gas from unconventional shale gas reservoirs. An efficient methodology for evaluating hydraulic fracturing operation parameters, such as fluid and proppant properties, injection rates, and wellhead pressure, is essential for the evaluation and efficient design of these processes. Traditional numerical evaluation and optimization approaches are usually based on simulated fracture properties such as the fracture area. In our opinion, a methodology based on simulated production data is better, because production is the goal of hydraulic fracturing and we can calibrate this approach with production data that is already known. This numerical methodology requires a fully-coupled hydraulic fracture propagation and multi-phase flow model. In this paper, we present a general fully-coupled numerical framework to simulate hydraulic fracturing and post-fracture gas well performance. This three-dimensional, multi-phase simulator focuses on: (1) fracture width increase and fracture propagation that occurs as slurry is injected into the fracture, (2) erosion caused by fracture fluids and leakoff, (3) proppant subsidence and flowback, and (4) multi-phase fluid flow through various-scaled anisotropic natural and man-made fractures. Mathematical and numerical details on how to fully couple the fracture propagation and fluid flow parts are discussed. Hydraulic fracturing and production operation parameters, and properties of the reservoir, fluids, and proppants, are taken into account. The well may be horizontal, vertical, or deviated, as well as open-hole or cemented. The simulator is verified based on benchmarks from the literature and we show its application by simulating fracture network (hydraulic and natural fractures) propagation and production data history matching of a field in China. We also conduct a series of real-data modeling studies with different combinations of hydraulic fracturing parameters and present the methodology to design these operations with feedback of simulated production data. The unified model aids in the optimization of hydraulic fracturing design, operations, and production.

  6. Electrical anisotropy of gas hydrate-bearing sand reservoirs in the Gulf of Mexico

    USGS Publications Warehouse

    Cook, Anne E.; Anderson, Barbara I.; Rasmus, John; Sun, Keli; Li, Qiming; Collett, Timothy S.; Goldberg, David S.

    2012-01-01

    We present new results and interpretations of the electricalanisotropy and reservoir architecture in gashydrate-bearingsands using logging data collected during the Gulf of MexicoGasHydrate Joint Industry Project Leg II. We focus specifically on sandreservoirs in Hole Alaminos Canyon 21 A (AC21-A), Hole Green Canyon 955 H (GC955-H) and Hole Walker Ridge 313 H (WR313-H). Using a new logging-while-drilling directional resistivity tool and a one-dimensional inversion developed by Schlumberger, we resolve the resistivity of the current flowing parallel to the bedding, R| and the resistivity of the current flowing perpendicular to the bedding, R|. We find the sandreservoir in Hole AC21-A to be relatively isotropic, with R| and R| values close to 2 ? m. In contrast, the gashydrate-bearingsandreservoirs in Holes GC955-H and WR313-H are highly anisotropic. In these reservoirs, R| is between 2 and 30 ? m, and R| is generally an order of magnitude higher. Using Schlumberger's WebMI models, we were able to replicate multiple resistivity measurements and determine the formation resistivity the gashydrate-bearingsandreservoir in Hole WR313-H. The results showed that gashydrate saturations within a single reservoir unit are highly variable. For example, the sand units in Hole WR313-H contain thin layers (on the order of 10-100 cm) with varying gashydrate saturations between 15 and 95%. Our combined modeling results clearly indicate that the gashydrate-bearingsandreservoirs in Holes GC955-H and WR313-H are highly anisotropic due to varying saturations of gashydrate forming in thin layers within larger sand units.

  7. Accounting for Adsorbed gas and its effect on production bahavior of Shale Gas Reservoirs 

    E-print Network

    Mengal, Salman Akram

    2010-10-12

    ) ................................................................ 16 3.6 SGPA results on plot of fraction of adsorbed gas, free gas to total gas vs time ........................................................................................................ 16 3.7 p/z* and p/z vs Gp (p.../z* values do not resemble p/z values). ................... 17 3.8 p/z* vs Gp and p/z vs Gp (p/z**values similar to p/z values)................... 18 4.1 Plot of [pi ? pwf(t)] / qo vs actual time, constant rate liquid BDF giving a...

  8. Numerical simulations of depressurization-induced gas production from gas hydrate reservoirs at the Walker Ridge 312 site, northern Gulf of Mexico

    SciTech Connect

    Myshakin, Evgeniy M.; Gaddipati, Manohar; Rose, Kelly; Anderson, Brian J.

    2012-06-01

    In 2009, the Gulf of Mexico (GOM) Gas Hydrates Joint-Industry-Project (JIP) Leg II drilling program confirmed that gas hydrate occurs at high saturations within reservoir-quality sands in the GOM. A comprehensive logging-while-drilling dataset was collected from seven wells at three sites, including two wells at the Walker Ridge 313 site. By constraining the saturations and thicknesses of hydrate-bearing sands using logging-while-drilling data, two-dimensional (2D), cylindrical, r-z and three-dimensional (3D) reservoir models were simulated. The gas hydrate occurrences inferred from seismic analysis are used to delineate the areal extent of the 3D reservoir models. Numerical simulations of gas production from the Walker Ridge reservoirs were conducted using the depressurization method at a constant bottomhole pressure. Results of these simulations indicate that these hydrate deposits are readily produced, owing to high intrinsic reservoir-quality and their proximity to the base of hydrate stability. The elevated in situ reservoir temperatures contribute to high (5–40 MMscf/day) predicted production rates. The production rates obtained from the 2D and 3D models are in close agreement. To evaluate the effect of spatial dimensions, the 2D reservoir domains were simulated at two outer radii. The results showed increased potential for formation of secondary hydrate and appearance of lag time for production rates as reservoir size increases. Similar phenomena were observed in the 3D reservoir models. The results also suggest that interbedded gas hydrate accumulations might be preferable targets for gas production in comparison with massive deposits. Hydrate in such accumulations can be readily dissociated due to heat supply from surrounding hydrate-free zones. Special cases were considered to evaluate the effect of overburden and underburden permeability on production. The obtained data show that production can be significantly degraded in comparison with a case using impermeable boundaries. The main reason for the reduced productivity is water influx from the surrounding strata; a secondary cause is gas escape into the overburden. The results dictate that in order to reliably estimate production potential, permeability of the surroundings has to be included in a model.

  9. A Theoretical Investigation of Radial Lateral Wells with Shockwave Completion in Shale Gas Reservoirs

    NASA Astrophysics Data System (ADS)

    Shan, Jia

    As its role in satisfying the energy demand of the U.S. and as a clean fuel has become more significant than ever, the shale gas production in the U.S. has gained increasing momentum over recent years. Thus, effective and environmentally friendly methods to extract shale gas are critical. Hydraulic fracturing has been proven to be efficient in the production of shale gas. However, environmental issues such as underground water contamination and high usage of water make this technology controversial. A potential technology to eliminate the environmental issues concerning water usage and contamination is to use blast fracturing, which uses explosives to create fractures. It can be further aided by HEGF and multi-pulse pressure loading technology, which causes less crushing effect near the wellbore and induces longer fractures. Radial drilling is another relatively new technology that can bypass damage zones due to drilling and create a larger drainage area through drilling horizontal wellbores. Blast fracturing and radial drilling both have the advantage of cost saving. The successful combination of blast fracturing and radial drilling has a great potential for improving U.S. shale gas production. An analytical productivity model was built in this study, considering linear flow from the reservoir rock to the fracture face, to analyze factors affecting shale gas production from radial lateral wells with shockwave completion. Based on the model analyses, the number of fractures per lateral is concluded to be the most effective factor controlling the productivity index of blast-fractured radial lateral wells. This model can be used for feasibility studies of replacing hydraulic fracturing by blast fracturing in shale gas well completions. Prediction of fracture geometry is recommended for future studies.

  10. Eos modeling and reservoir simulation study of bakken gas injection improved oil recovery in the elm coulee field, Montana

    NASA Astrophysics Data System (ADS)

    Pu, Wanli

    The Bakken Formation in the Williston Basin is one of the most productive liquid-rich unconventional plays. The Bakken Formation is divided into three members, and the Middle Bakken Member is the primary target for horizontal wellbore landing and hydraulic fracturing because of its better rock properties. Even with this new technology, the primary recovery factor is believed to be only around 10%. This study is to evaluate various gas injection EOR methods to try to improve on that low recovery factor of 10%. In this study, the Elm Coulee Oil Field in the Williston Basin was selected as the area of interest. Static reservoir models featuring the rock property heterogeneity of the Middle Bakken Member were built, and fluid property models were built based on Bakken reservoir fluid sample PVT data. By employing both compositional model simulation and Todd-Longstaff solvent model simulation methods, miscible gas injections were simulated and the simulations speculated that oil recovery increased by 10% to 20% of OOIP in 30 years. The compositional simulations yielded lower oil recovery compared to the solvent model simulations. Compared to the homogeneous model, the reservoir model featuring rock property heterogeneity in the vertical direction resulted in slightly better oil recovery, but with earlier CO2 break-through and larger CO2 production, suggesting that rock property heterogeneity is an important property for modeling because it has a big effect on the simulation results. Long hydraulic fractures shortened CO2 break-through time greatly and increased CO 2 production. Water-alternating-gas injection schemes and injection-alternating-shut-in schemes can provide more options for gas injection EOR projects, especially for gas production management. Compared to CO2 injection, separator gas injection yielded slightly better oil recovery, meaning separator gas could be a good candidate for gas injection EOR; lean gas generated the worst results. Reservoir simulations also indicate that original rock properties are the dominant factor for the ultimate oil recovery for both primary recovery and gas injection EOR. Because reservoir simulations provide critical inputs for project planning and management, more effort needs to be invested into reservoir modeling and simulation, including building enhanced geologic models, fracture characterization and modeling, and history matching with field data. Gas injection EOR projects are integrated projects, and the viability of a project also depends on different economic conditions.

  11. Star formation, quenching, black hole feedback and the fate of gas reservoirs

    NASA Astrophysics Data System (ADS)

    Schawinski, Kevin

    2015-08-01

    Massive galaxies are broadly split into those forming stars on the main sequence, and those which are quiescent. The physical processes by which galaxies quench their star formation remain poorly understood. I analyze the properties of galaxies and track their evolutionary trajectories as they migrate from the blue cloud of star forming galaxies to the red sequence of quiescent galaxies via the `green valley'. I show that there must be two fundamentally star formation quenching pathways associated with early- and late-type galaxies which are intricately linked to how hydrogen gas reservoirs are destroyed or shut off. In the quenching of late-type galaxies, environment (or halo mass) is a key parameter, while for early-types, an internal mechanism such as black hole feedback is more likely. I will present recent HI observations supporting this picture.

  12. Star formation, quenching, black hole feedback and the fate of gas reservoirs

    NASA Astrophysics Data System (ADS)

    Schawinski, Kevin; Wong, Ivy; Urry, C. Megan; Willett, Kyle; Simmons, Brooke D.; Galaxy Zoo Team

    2015-01-01

    Massive galaxies are broadly split into those forming stars on the main sequence, and those which are quiescent. The physical processes by which galaxies quench their star formation remain poorly understood. I analyze the properties of galaxies and track their evolutionary trajectories as they migrate from the blue cloud of star forming galaxies to the red sequence of quiescent galaxies via the `green valley'. I show that there must be two fundamentally star formation quenching pathways associated with early- and late-type galaxies which are intricately linked to how hydrogen gas reservoirs are destroyed or shut off. In the quenching of late-type galaxies, environment (or halo mass) is a key parameter, while for early-types, an internal mechanism such as black hole feedback is more likely. I will present recent HI observations supporting this picture.

  13. Numerical modeling of gas migration into and through faulted sand reservoirs in Pabst Field (Main Pass East Block 259), northern Gulf of Mexico 

    E-print Network

    Li, Yuqian

    2006-08-16

    The further exploration and development of Pabst Gas Field with faulted sand reservoirs require an understanding of the properties and roles of faults, particularly Low Throw near Vertical Faults (LTNVFs), in gas migration and accumulation at a...

  14. Carbon dioxide and helium emissions from a reservoir of magmatic gas beneath Mammoth Mountain, California

    SciTech Connect

    Sorey, M.L.; Evans, W.C. Kennedy, B.M. Farrar, C.D. Hainsworth, L.J. Hausback, B.

    1998-07-01

    Carbon dioxide and helium with isotopic compositions indicative of a magmatic source ({delta}thinsp{sup 13}C={minus}4.5 to {minus}5{per_thousand}, {sup 3}He/{sup 4}He=4.5 to 6.7 R{sub A}) are discharging at anomalous rates from Mammoth Mountain, on the southwestern rim of the Long Valley caldera in eastern California. The gas is released mainly as diffuse emissions from normal-temperature soils, but some gas issues from steam vents or leaves the mountain dissolved in cold groundwater. The rate of gas discharge increased significantly in 1989 following a 6-month period of persistent earthquake swarms and associated strain and ground deformation that has been attributed to dike emplacement beneath the mountain. An increase in the magmatic component of helium discharging in a steam vent on the north side of Mammoth Mountain, which also began in 1989, has persisted until the present time. Anomalous CO{sub 2} discharge from soils first occurred during the winter of 1990 and was followed by observations of several areas of tree kill and/or heavier than normal needlecast the following summer. Subsequent measurements have confirmed that the tree kills arc associated with CO{sub 2} concentrations of 30{endash}90{percent} in soil gas and gas flow rates of up to 31,000 gthinspm{sup {minus}2}thinspd{sup {minus}1} at the soil surface. Each of the tree-kill areas and one area of CO{sub 2} discharge above tree line occurs in close proximity to one or more normal faults, which may provide conduits for gas flow from depth. We estimate that the total diffuse CO{sub 2} flux from the mountain is approximately 520 t/d, and that 30{endash}50 t/d of CO{sub 2} are dissolved in cold groundwater flowing off the flanks of the mountain. Isotopic and chemical analyses of soil and fumarolic gas demonstrate a remarkable homogeneity in composition, suggesting that the CO{sub 2} and associated helium and excess nitrogen may be derived from a common gas reservoir whose source is associated with some combination of magmatic degassing and thermal metamorphism of metasedimentary rocks. Furthermore, N{sub 2}/Ar ratios and nitrogen isotopic values indicate that the Mammoth Mountain gases are derived from sources separate from those that supply gas to the hydrothermal system within the Long Valley caldera. Various data suggest that the Mammoth Mountain gas reservoir is a large, low-temperature cap over an isolated hydrothermal system, that it predates the 1989 intrusion, and that it could remain a source of gas discharge for some time. {copyright} 1998 American Geophysical Union

  15. The Molecular Gas Reservoirs in Quasar Host Galaxies at Redshift 4: First Constraints from CARMA

    NASA Astrophysics Data System (ADS)

    Riechers, Dominik A.

    2009-01-01

    Detailed investigations of the molecular interstellar medium in quasar host galaxies at the highest redshifts are important for our understanding of the formation and evolution of quasars and their bulges, since it is the molecular gas out of which stars form. I will present the first successful observations of molecular gas at z>4 obtained with the Combined Array for Research in Millimeter-wave Astronomy (CARMA). This study helps to constrain the physical properties in two key active galactic nucleus (AGN)-starburst systems in the early universe. The z=4.41 quasar BRI1335-0417 is currently undergoing a massive, "wet" (gas-rich) merger, leading to the formation of its host galaxy, the active growth of its central black hole, and the buildup of its stellar bulge. The detection of CO(J=4-3) emission in this system helps to constrain its molecular gas excitation, in particular the gas density and temperature. The z=3.91 quasar APM08279+5255 is in an even more extreme phase of its evolution, as shown by its extreme molecular gas excitation. The detection of highly excited emission from the high-level J=6-5 transitions of the dense, star-forming gas tracers HCN and HCO+ is very unusual, and suggests that the dense gas in this system is substantially radiatively (rather than collisionally) excited. This is consistent with the finding that the gas and dust reservoirs in this galaxy are very compact and warm, and that the AGN is highly luminous (even among type-1 quasars), indicating rapid, co-eval growth of the black hole and the stellar component. These observations highlight the importance of understanding the molecular gas properties of key targets among the earliest galaxies to place them in an evolutionary context, and pave the way for future observations with the Expanded Very Large Array (EVLA) and the Atacama Large Millimeter/submillimeter Array (ALMA). DR acknowledges funding from NASA/STScI through Hubble Fellowship HST-HF-01212.01-A.

  16. Prediction of pressure drawdown in gas reservoirs using a semi-analytical solution of the non-linear gas flow equation

    SciTech Connect

    Mattar, L.; Adegbesan, L.O.

    1980-01-01

    The differential equation for flow of gases in a porous medium is nonlinear and cannot be solved by strictly analytical methods. Previous studies in the literature have obtained analytical solutions to this equation by linearlization (i.e., treating viscosity and compressibilty as constant). In this study, the solution for nonlinear gas flow equation is obtained using the semianalytical technique developed by Kale and Mattar which solves the nonlinear equation by the method of perturbation. Results obtained, for prediction of pressure drawdown in gas reservoirs, indicate that the solution of the linearlized form of the equation is valid for both low and high permeability reservoirs.

  17. Fracture Modeling and Flow Behavior in Shale Gas Reservoirs Using Discrete Fracture Networks 

    E-print Network

    Ogbechie, Joachim Nwabunwanne

    2012-02-14

    Fluid flow process in fractured reservoirs is controlled primarily by the connectivity of fractures. The presence of fractures in these reservoirs significantly affects the mechanism of fluid flow. They have led to problems ...

  18. Reservoir characterization in an underground gas storage field using joint inversion of flow and geodetic data

    E-print Network

    Bottazzi, F.

    Characterization of reservoir properties like porosity and permeability in reservoir models typically relies on history matching of production data, well pressure data, and possibly other fluid-dynamical data. Calibrated ...

  19. 3-D geomechanical modelling of a gas reservoir in the North German Basin: workflow for model building and calibration

    NASA Astrophysics Data System (ADS)

    Fischer, K.; Henk, A.

    2013-06-01

    The optimal use of conventional and unconventional hydrocarbon reservoirs depends, amongst others, on the local tectonic stress field. For example, wellbore stability, orientation of hydraulically induced fractures and - especially in fractured reservoirs - permeability anisotropies are controlled by the recent in situ stresses. Faults and lithological changes can lead to stress perturbations and produce local stresses that can significantly deviate from the regional stress field. Geomechanical reservoir models aim for a robust, ideally "pre-drilling" prediction of the local variations in stress magnitude and orientation. This requires a~numerical modelling approach that is capable to incorporate the specific geometry and mechanical properties of the subsurface reservoir. The workflow presented in this paper can be used to build 3-D geomechanical models based on the Finite Element Method (FEM) and ranging from field-scale models to smaller, detailed submodels of individual fault blocks. The approach is successfully applied to an intensively faulted gas reservoir in the North German Basin. The in situ stresses predicted by the geomechanical FE model were calibrated against stress data actually observed, e.g. borehole breakouts and extended leak-off tests. Such a validated model can provide insights into the stress perturbations in the inter-well space and undrilled parts of the reservoir. In addition, the tendency of the existing fault network to slip or dilate in the present-day stress regime can be addressed.

  20. Total Organic Carbon prediction in shale gas reservoirs using fuzzy logic

    NASA Astrophysics Data System (ADS)

    Ouadfeul, Sid-Ali; Aliouane, Leila

    2015-04-01

    Here, we suggest the use the fuzzy logic approach for the prediction of the Total Organic Carbon (TOC) from well-logs data in shale gas reservoirs, two models are used for the estimation of the TOC from well-logs data; the first one is called the Schmoker's model while the second one is called the Passey's model. Scmocker's model requires the continuous measurement of the Bulk density, in case of absence of the bulk density measurement the Schmoker's model is not able to predict the TOC. In this case we suggest the use fuzzy logic system able to predict the total organic carbon in shale gas formations. The input of the fuzzy system is the four raw well-logs data measurements corresponding to the natural gamma ray, the neutron porosity, the slowness of the primary and shear waves. The desired output is the calculated TOC using the Schmoker's model. Application to well-logs data of two horizontal wells drilled in the lower Barnett shale clearly shows the ability of the fuzzy logic approach to suggest values of the total organic carbon in case of no bulk density measurement. Keywords TOC, Schmoker's model, Fuzzy logic, shale gas, Barnett shale, prediction.

  1. The model of the oil-gas bearing molasse reservoirs in the Peri-Adriatic depression, Albania

    SciTech Connect

    Hysen, K.N.; Skender, T.G.

    1996-12-31

    The Peri-Adriatic Depression (PAD) represents the eastern extension of the Cenozoic Adriatic basin into onshore Albania. Several oil, gas condensate, dry gas fields have been discovered in this basin. Dry gas fields occur mainly in the western sector of the basin, whereas the oil fields are found in the eastern one. Reservoir rocks are well sorted to poorly, fine grained to pebbly sandstones and silstones of Miocene (Serravalian) to Pliocene age, deposited in deep water (turbidite), deltaic and littoral environments. Reservoir beds range in thickness from I to 40 in and are generally regionally distributed. The porosity varies from 3 to 37%, the permeability ranges from low values up to 2200-2500 mD. The minimal value of the porosity measured from oil flowing reservoirs varies from 12% to 16% and for the dry gas 12-21%. Geothermal gradient range from 1.4-2 C/100m. The dimensions of the reservoirs are very different and its geometric shape differs from beds to irregular shape. The types of the traps are also different : lithologo-stratigraphic, lithologic, structural-lithologic ones, etc. The upper part of the Pliocene basin belongs to the delta deposits. The deltaic sandstones are coarse grain to conglomeratic ones, of barriers type, saturated with fresh water and have vast distribution.

  2. The model of the oil-gas bearing molasse reservoirs in the Peri-Adriatic depression, Albania

    SciTech Connect

    Hysen, K.N.; Skender, T.G. )

    1996-01-01

    The Peri-Adriatic Depression (PAD) represents the eastern extension of the Cenozoic Adriatic basin into onshore Albania. Several oil, gas condensate, dry gas fields have been discovered in this basin. Dry gas fields occur mainly in the western sector of the basin, whereas the oil fields are found in the eastern one. Reservoir rocks are well sorted to poorly, fine grained to pebbly sandstones and silstones of Miocene (Serravalian) to Pliocene age, deposited in deep water (turbidite), deltaic and littoral environments. Reservoir beds range in thickness from I to 40 in and are generally regionally distributed. The porosity varies from 3 to 37%, the permeability ranges from low values up to 2200-2500 mD. The minimal value of the porosity measured from oil flowing reservoirs varies from 12% to 16% and for the dry gas 12-21%. Geothermal gradient range from 1.4-2 C/100m. The dimensions of the reservoirs are very different and its geometric shape differs from beds to irregular shape. The types of the traps are also different : lithologo-stratigraphic, lithologic, structural-lithologic ones, etc. The upper part of the Pliocene basin belongs to the delta deposits. The deltaic sandstones are coarse grain to conglomeratic ones, of barriers type, saturated with fresh water and have vast distribution.

  3. Uncertainty quantification of volumetric and material balance analysis of gas reservoirs with water influx using a Bayesian framework 

    E-print Network

    Aprilia, Asti Wulandari

    2007-04-25

    ) as a result of combining volumetric and material balance analysis in a water-driven gas reservoir. The results show that we potentially have significant non-uniqueness (i.e., large uncertainty) when we consider only volumetric analyses or material...

  4. Performance analysis of compositional and modified black-oil models for rich gas condensate reservoirs with vertical and horizontal wells 

    E-print Network

    Izgec, Bulent

    2004-09-30

    It has been known that volatile oil and gas condensate reservoirs cannot be modeled accurately with conventional black-oil models. One variation to the black-oil approach is the modified black-oil (MBO) model that allows the use of a simple...

  5. DOE THREE-DIMENSIONAL STRUCTURE AND PHYSICAL PROPERTIES OF A METHANE HYDRATE DEPOSIT AND GAS RESERVOIR, BLAKE RIDGE

    SciTech Connect

    W. Steven Holbrook

    2004-11-11

    This report contains a summary of work conducted and results produced under the auspices of award DE-FC26-00NT40921, ''DOE Three-Dimensional Structure and Physical Properties of a Methane Hydrate Deposit and Gas Reservoir, Blake Ridge.'' This award supported acquisition, processing, and interpretation of two- and three-dimensional seismic reflection data over a large methane hydrate reservoir on the Blake Ridge, offshore South Carolina. The work supported by this project has led to important new conclusions regarding (1) the use of seismic reflection data to directly detect methane hydrate, (2) the migration and possible escape of free gas through the hydrate stability zone, and (3) the mechanical controls on the maximum thickness of the free gas zone and gas escape.

  6. Pore-scale mechanisms of gas flow in tight sand reservoirs

    SciTech Connect

    Silin, D.; Kneafsey, T.J.; Ajo-Franklin, J.B.; Nico, P.

    2010-11-30

    Tight gas sands are unconventional hydrocarbon energy resource storing large volume of natural gas. Microscopy and 3D imaging of reservoir samples at different scales and resolutions provide insights into the coaredo not significantly smaller in size than conventional sandstones, the extremely dense grain packing makes the pore space tortuous, and the porosity is small. In some cases the inter-granular void space is presented by micron-scale slits, whose geometry requires imaging at submicron resolutions. Maximal Inscribed Spheres computations simulate different scenarios of capillary-equilibrium two-phase fluid displacement. For tight sands, the simulations predict an unusually low wetting fluid saturation threshold, at which the non-wetting phase becomes disconnected. Flow simulations in combination with Maximal Inscribed Spheres computations evaluate relative permeability curves. The computations show that at the threshold saturation, when the nonwetting fluid becomes disconnected, the flow of both fluids is practically blocked. The nonwetting phase is immobile due to the disconnectedness, while the permeability to the wetting phase remains essentially equal to zero due to the pore space geometry. This observation explains the Permeability Jail, which was defined earlier by others. The gas is trapped by capillarity, and the brine is immobile due to the dynamic effects. At the same time, in drainage, simulations predict that the mobility of at least one of the fluids is greater than zero at all saturations. A pore-scale model of gas condensate dropout predicts the rate to be proportional to the scalar product of the fluid velocity and pressure gradient. The narrowest constriction in the flow path is subject to the highest rate of condensation. The pore-scale model naturally upscales to the Panfilov's Darcy-scale model, which implies that the condensate dropout rate is proportional to the pressure gradient squared. Pressure gradient is the greatest near the matrix-fracture interface. The distinctive two-phase flow properties of tight sand imply that a small amount of gas condensate can seriously affect the recovery rate by blocking gas flow. Dry gas injection, pressure maintenance, or heating can help to preserve the mobility of gas phase. A small amount of water can increase the mobility of gas condensate.

  7. Establishment of an oil and gas database for increased recovery and characterization of oil and gas carbonate reservoir heterogeneity. Appendix 1, Volume 1

    SciTech Connect

    Kopaska-Merkel, D.C.; Moore, H.E. Jr.; Mann, S.D.; Hall, D.R.

    1992-06-01

    This volume contains maps, well logging correlated to porosity and permeability, structural cross section, graph of production history, porosity vs. natural log permeability plot, detailed core log, paragenetic sequence and reservoir characterization sheet of the following fields in southwest Alabama: Appleton oil field; Barnett oil field; Barrytown oil field; Big Escambia Creek gas and condensate field; Blacksher oil field; Broken Leg Creed oil field; Bucatunna Creed oil field; Chappell Hill oil field; Chatom gas and condensate field; Choctaw Ridge oil field; Chunchula gas and condensate field; Cold Creek oil field; Copeland gas and condensate field; Crosbys Creed gas and condensate field; and East Barnett oil field. (AT)

  8. Establishment of an oil and gas database for increased recovery and characterization of oil and gas carbonate reservoir heterogeneity. [Jurassic Smackover Formation

    SciTech Connect

    Kopaska-Merkel, D.C.; Moore, H.E. Jr.; Mann, S.D.; Hall, D.R.

    1992-06-01

    This volume contains maps, well logging correlated to porosity and permeability, structural cross section, graph of production history, porosity vs. natural log permeability plot, detailed core log, paragenetic sequence and reservoir characterization sheet of the following fields in southwest Alabama: Appleton oil field; Barnett oil field; Barrytown oil field; Big Escambia Creek gas and condensate field; Blacksher oil field; Broken Leg Creed oil field; Bucatunna Creed oil field; Chappell Hill oil field; Chatom gas and condensate field; Choctaw Ridge oil field; Chunchula gas and condensate field; Cold Creek oil field; Copeland gas and condensate field; Crosbys Creed gas and condensate field; and East Barnett oil field. (AT)

  9. Efficiency optimization of a closed indirectly fired gas turbine cycle working under two variable-temperature heat reservoirs

    NASA Astrophysics Data System (ADS)

    Ma, Zheshu; Wu, Jieer

    2011-08-01

    Indirectly or externally fired gas turbines (IFGT or EFGT) are interesting technologies under development for small and medium scale combined heat and power (CHP) supplies in combination with micro gas turbine technologies. The emphasis is primarily on the utilization of the waste heat from the turbine in a recuperative process and the possibility of burning biomass even "dirty" fuel by employing a high temperature heat exchanger (HTHE) to avoid the combustion gases passing through the turbine. In this paper, finite time thermodynamics is employed in the performance analysis of a class of irreversible closed IFGT cycles coupled to variable temperature heat reservoirs. Based on the derived analytical formulae for the dimensionless power output and efficiency, the efficiency optimization is performed in two aspects. The first is to search the optimum heat conductance distribution corresponding to the efficiency optimization among the hot- and cold-side of the heat reservoirs and the high temperature heat exchangers for a fixed total heat exchanger inventory. The second is to search the optimum thermal capacitance rate matching corresponding to the maximum efficiency between the working fluid and the high-temperature heat reservoir for a fixed ratio of the thermal capacitance rates of the two heat reservoirs. The influences of some design parameters on the optimum heat conductance distribution, the optimum thermal capacitance rate matching and the maximum power output, which include the inlet temperature ratio of the two heat reservoirs, the efficiencies of the compressor and the gas turbine, and the total pressure recovery coefficient, are provided by numerical examples. The power plant configuration under optimized operation condition leads to a smaller size, including the compressor, turbine, two heat reservoirs and the HTHE.

  10. PRELIMINARY CHARACTERIZATION OF CO2 SEPARATION AND STORAGE PROPERTIES OF COAL GAS RESERVOIRS

    SciTech Connect

    John Kemeny; Satya Harpalani

    2004-03-01

    An attractive alternative of sequestering CO{sub 2} is to inject it into coalbed methane reservoirs, particularly since it has been shown to enhance the production of methane during near depletion stages. The basis for enhanced coalbed methane recovery and simultaneous sequestration of carbon dioxide in deep coals is the preferential sorption property of coal, with its affinity for carbon dioxide being significantly higher than that for methane. Yet, the sorption behavior of coal under competitive sorptive environment is not fully understood. Hence, the original objective of this research study was to carry out a laboratory study to investigate the effect of studying the sorption behavior of coal in the presence of multiple gases, primarily methane, CO{sub 2} and nitrogen, in order to understand the mechanisms involved in displacement of methane and its movement in coal. This had to be modified slightly since the PVT property of gas mixtures is still not well understood, and any laboratory work in the area of sorption of gases requires a definite equation of state to calculate the volumes of different gases in free and adsorbed forms. This research study started with establishing gas adsorption isotherms for pure methane and CO{sub 2}. The standard gas expansion technique based on volumetric analysis was used for the experimental work with the additional feature of incorporating a gas chromatograph for analysis of gas composition. The results were analyzed first using the Langmuir theory. As expected, the Langmuir analysis indicated that CO{sub 2} is more than three times as sorptive as methane. This was followed by carrying out a partial desorption isotherm for methane, and then injecting CO{sub 2} to displace methane. The results indicated that CO{sub 2} injection at low pressure displaced all of the sorbed methane, even when the total pressure continued to be high. However, the displacement appeared to be occurring due to a combination of the preferential sorption property of coal and reduction in the partial pressure of methane. As a final step, the Extended Langmuir (EL) model was used to model the coal-methane-CO{sub 2} binary adsorption system. The EL model was found to be very accurate in predicting adsorption of CO{sub 2}, but not so in predicting desorption of methane. The selectivity of CO{sub 2} over methane was calculated to be 4.3:1. This is, of course, not in very good agreement with the measured values which showed the ratio to be 3.5:1. However, the measured results are in good agreement with the field observation at one of the CO{sub 2} injection sites. Based on the findings of this study, it was concluded that low pressure injection of CO{sub 2} can be fairly effective in displacing methane in coalbed reservoirs although this might be difficult to achieve in field conditions. Furthermore, the displacement of methane appears to be not only due to the preferential sorption of methane, but reduction in partial pressure as well. Hence, using a highly adsorbing gas, such as CO{sub 2}, has the advantages of inert gas stripping and non-mixing since the injected gas does not mix with the recovered methane.

  11. Compaction bands in high temperature/pressure diagenetically altered unconventional shale gas reservoirs

    NASA Astrophysics Data System (ADS)

    Regenauer-Lieb, K.; Veveakis, M.; Poulet, T.

    2014-12-01

    Unconventional energy and mineral resources are typically trapped in a low porosity/permeability environment and are difficult to produce. An extreme end-member is the shale gas reservoir in the Cooper Basin (Australia) that is located at 3500-4000 m depth and ambient temperature conditions around 200oC. Shales of lacustrine origin (with high clay content) are diagenetically altered. Diagenesis involves fluid release mineral reactions of the general type Asolid ? Bsolid +Cfluid and switches on suddenly in the diagenetic window between 100-200oC. Diagenetic reactions can involve concentrations of smectite, aqueous silica compound, illite, potassium ions, aqueous silica, quartz, feldspar, kerogen, water and gas . In classical petroleum engineering such interlayer water/gas release reactions are considered to cause cementation and significantly reduce porosity and permeability. Yet in contradiction to the expected permeability reduction gas is successfully being produced. We propose that the success is based on the ductile equivalent of classical compaction bands in solid mechanics. The difference being that that the rate of the volumetric compaction is controlled by the diagenetic reactions. Ductile compaction bands are forming high porosity fluid channels rather than low porosity crushed grains in the solid mechanical equivalent. We show that this new type of volumetric instability appears in rate-dependent heterogenous materials as Cnoidal waves. These are nonlinear and exact periodic stationary waves, well known in the shallow water theory of fluid mechanics. Their distance is a direct function of the hydromechanical diffusivities. These instabilities only emerge in low permeability environment where the fluid diffusivity is about an order of magnitude lower than the mechanical loading. The instabilities are expected to be of the type as shown in the image below. The image shows a CT-scan of a laboratory experiment kindly provided by Papamichos (pers.comm.). Periodic compaction bands are clearly detected by the CT analysis of a shale sample compressed under high confining pressure.

  12. Naturally fractured tight gas: Gas reservoir detection optimization. Quarterly report, January 1--March 31, 1997

    SciTech Connect

    1997-12-31

    Economically viable natural gas production from the low permeability Mesaverde Formation in the Piceance Basin, Colorado requires the presence of an intense set of open natural fractures. Establishing the regional presence and specific location of such natural fractures is the highest priority exploration goal in the Piceance and other western US tight, gas-centered basins. Recently, Advanced Resources International, Inc. (ARI) completed a field program at Rulison Field, Piceance Basin, to test and demonstrate the use of advanced seismic methods to locate and characterize natural fractures. This project began with a comprehensive review of the tectonic history, state of stress and fracture genesis of the basin. A high resolution aeromagnetic survey, interpreted satellite and SLAR imagery, and 400 line miles of 2-D seismic provided the foundation for the structural interpretation. The central feature of the program was the 4.5 square mile multi-azimuth 3-D seismic P-wave survey to locate natural fracture anomalies. The interpreted seismic attributes are being tested against a control data set of 27 wells. Additional wells are currently being drilled at Rulison, on close 40 acre spacings, to establish the productivity from the seismically observed fracture anomalies. A similar regional prospecting and seismic program is being considered for another part of the basin. The preliminary results indicate that detailed mapping of fault geometries and use of azimuthally defined seismic attributes exhibit close correlation with high productivity gas wells. The performance of the ten new wells, being drilled in the seismic grid in late 1996 and early 1997, will help demonstrate the reliability of this natural fracture detection and mapping technology.

  13. Influence of environmental variables on diffusive greenhouse gas fluxes at hydroelectric reservoirs in Brazil.

    PubMed

    Rogério, J P; Santos, M A; Santos, E O

    2013-11-01

    For almost two decades, studies have been under way in Brazil, showing how hydroelectric reservoirs produce biogenic gases, mainly methane (CH4) and carbon dioxide (CO2), through the organic decomposition of flooded biomass. This somewhat complex phenomenon is due to a set of variables with differing levels of interdependence that directly or indirectly affect greenhouse gas (GHG) emissions. The purpose of this paper is to determine, through a statistical data analysis, the relation between CO2, CH4 diffusive fluxes and environmental variables at the Furnas, Itumbiara and Serra da Mesa hydroelectric reservoirs, located in the Cerrado biome on Brazil's high central plateau. The choice of this region was prompted by its importance in the national context, covering an area of some two million square kilometers, encompassing two major river basins (Paraná and Tocantins-Araguaia), with the largest installed power generation capacity in Brazil, together accounting for around 23% of Brazilian territory. This study shows that CH4 presented a moderate negative correlation between CO2 and depth. Additionally, a moderate positive correlation was noted for pH, water temperature and wind. The CO2 presented a moderate negative correlation for pH, wind speed, water temperature and air temperature. Additionally, a moderate positive correlation was noted for CO2 and water temperature. The complexity of the emission phenomenon is unlikely to occur through a simultaneous understanding of all the factors, due to difficulties in accessing and analyzing all the variables that have real, direct effects on GHG production and emission. PMID:24789391

  14. Sedimentology and reservoir characteristics of tight gas sandstones, Frontier formation, southwestern Wyoming

    SciTech Connect

    Moslow, T.F.; Tillman, R.W.

    1984-04-01

    The lower Frontier Formation, Moxa arch area, southwestern Wyoming, is one of the most prolific gas-producing formations in the Rocky Mountain region. Lowr Frontier sediments were deposited as strandplains and coalescing wave-dominated deltas that prograding into the western margin of the Cretaceous interior seaway during the Cenomanian. In this study, sedimentologic, petrologic, and stratigraphic analyses were conducted on cores and logs of Frontier wells from the Whiskey Buttes and Moxa fields. Twelve sedimentary facies have been identified. The most common sequence consists of burrowed to cross-bedded near shore marine (delta-front and inner-shelf) sandstones disconformably overlain by crossbedded (active) to deformed (abandoned) distributary-channel sandstones and conglomerates. The sequence is capped by delta-plain mudstones and silty sandstones. Tight-gas sandstone reservoir facies are nonhomogenous and include crevasse splay, abandoned and active distributary channel, shoreface, foreshore, and inner shelf sandstones. Distributary-channel facies represent 80% of perforated intervals in wells in the southern part of the Moxa area, but only 50% to the north. Channel sandstone bodies are occasionally stacked, occur on the same stratigraphic horizon, and are laterally discontinuous with numerous permeability barriers. Percentage of perforated intervals in upper shoreface and foreshore facies increases from 20% in the south to 50% in the north.

  15. Sedimentology and reservoir characteristics of tight gas sandstones, Frontier formation, southwestern Wyoming

    SciTech Connect

    Moslow, T.F.; Tillman, R.W.

    1984-04-01

    The lower Frontier Formation, Moxa arch area, southwestern Wyoming, is one of the most prolific gas-producing formations in the Rocky Mountain region. Lower Frontier sediments were deposited as strandplains and coalescing wave-dominated deltas that prograding into the western margin of the Cretaceous interior seaway during the Cenomanian. In this study, sedimentologic, petrologic, and stratigraphic analyses were conducted on cores and logs of Frontier wells from the Whiskey Buttes and Moxa fields. Twelve sedimentary facies have been identified. The most common sequence consists of burrowed to cross-bedded near shore marine (delta-front and inner-shelf) sandstones disconformably overlain by cross-bedded (active) to deformed (abandoned) distributary-channel sandstones and conglomerates. The sequence is capped by delta-plain mudstones and silty sandstones. Tight-gas sandstone reservoir facies are non-homogenous and include crevasse splay, abandoned and active distributary channel, shoreface, foreshore, and inner shelf sandstones. Distributary-channel facies represent 80% of perforated intervals in wells in the southern part of the Moxa area, but only 50% to the north. Channel sandstone bodies are occasionally stacked, occur on the same stratigraphic horizon, and are laterally discontinuous with numerous permeability barriers. Percentage of perforated intervals in upper shoreface and foreshore facies increases from 20% in the south to 50% in the north.

  16. HIGH RESOLUTION PREDICTION OF GAS INJECTION PROCESS PERFORMANCE FOR HETEROGENEOUS RESERVOIRS

    SciTech Connect

    Franklin M. Orr, Jr.

    2003-03-31

    This report outlines progress in the second quarter of the third year of the DOE project ''High Resolution Prediction of Gas Injection Process Performance for Heterogeneous Reservoirs''. This report presents results of an investigation of the effects of variation in interfacial tension (IFT) on three-phase relative permeability. We report experimental results that demonstrate the effect of low IFT between two of three phases on the three-phase relative permeabilities. In order to create three-phase systems, in which IFT can be controlled systematically, we employed analog liquids composing of hexadecane, n-butanol, isopropanol, and water. Phase composition, phase density and viscosity, and IFT of three-phase system were measured and are reported here. We present three-phase relative permeabilities determined from recovery and pressure drop data using the Johnson-Bossler-Naumann (JBN) method. The phase saturations were obtained from recovery data by the Welge method. The experimental results indicate that the wetting phase relative permeability was not affected by IFT variation whereas the other two-phase relative permeabilities were clearly affected. As IFT decreases the ''oil'' and ''gas'' phases become more mobile at the same phase saturations.

  17. Estimation of original gas in place from short-term shut-in pressure data for commingled tight gas reservoirs with no crossflow 

    E-print Network

    Khuong, Chan Hung

    1995-01-01

    The conventional material balance method (M.B.) , or p/z method, is not applicable for commingled fight gas reservoirs, especially when only short-term shut-in pressure data is available. This is because p/z is not a linear function of cumulative...

  18. Investigation of gas hydrate-bearing sandstone reservoirs at the "Mount Elbert" stratigraphic test well, Milne Point, Alaska

    SciTech Connect

    Boswell, R.M.; Hunter, R.; Collett, T.; Digert, S. Inc., Anchorage, AK); Hancock, S.; Weeks, M. Inc., Anchorage, AK); Mt. Elbert Science Team

    2008-01-01

    In February 2007, the U.S. Department of Energy, BP Exploration (Alaska), Inc., and the U.S. Geological Survey conducted an extensive data collection effort at the "Mount Elbert #1" gas hydrates stratigraphic test well on the Alaska North Slope (ANS). The 22-day field program acquired significant gas hydrate-bearing reservoir data, including a full suite of open-hole well logs, over 500 feet of continuous core, and open-hole formation pressure response tests. Hole conditions, and therefore log data quality, were excellent due largely to the use of chilled oil-based drilling fluids. The logging program confirmed the existence of approximately 30 m of gashydrate saturated, fine-grained sand reservoir. Gas hydrate saturations were observed to range from 60% to 75% largely as a function of reservoir quality. Continuous wire-line coring operations (the first conducted on the ANS) achieved 85% recovery through 153 meters of section, providing more than 250 subsamples for analysis. The "Mount Elbert" data collection program culminated with open-hole tests of reservoir flow and pressure responses, as well as gas and water sample collection, using Schlumberger's Modular Formation Dynamics Tester (MDT) wireline tool. Four such tests, ranging from six to twelve hours duration, were conducted. This field program demonstrated the ability to safely and efficiently conduct a research-level openhole data acquisition program in shallow, sub-permafrost sediments. The program also demonstrated the soundness of the program's pre-drill gas hydrate characterization methods and increased confidence in gas hydrate resource assessment methodologies for the ANS.

  19. Evaluation of the 3-D channeling flow in a fractured type of oil/gas reservoir

    NASA Astrophysics Data System (ADS)

    Ishibashi, T.; Watanabe, N.; Tsuchiya, N.; Tamagawa, T.

    2013-12-01

    An understanding of the flow and transport characteristics through rock fracture networks is of critical importance in many engineering and scientific applications. These include effective recovery of targeted fluid such as oil/gas, geothermal, or potable waters, and isolation of hazardous materials. Here, the formation of preferential flow path (i.e. channeling flow) is one of the most significant characteristics in considering fluid flow through rock fracture networks; however, the impact of channeling flow remains poorly understood. In order to deepen our understanding of channeling flow, the authors have developed a novel discrete fracture network (DFN) model simulator, GeoFlow. Different from the conventional DFN model simulators, we can characterize each fracture not by a single aperture value but by a heterogeneous aperture distribution in GeoFlow [Ishibashi et al., 2012]. As a result, the formation of 3-D preferential flow paths within fracture network can be considered by using this simulator. Therefore, we would challenge to construct the precise fracture networks whose fractures have heterogeneous aperture distributions in field scale, and to analyze fluid flows through the fracture networks by GeoFlow. In the present study, the Yufutsu oil/gas field in Hokkaido, Japan is selected as the subject area for study. This field is known as the fractured type of reservoir, and reliable DFN models can be constructed for this field based on the 3-D seismic data, well logging, in-situ stress measurement, and acoustic emission data [Tamagawa et al., 2012]. Based on these DFN models, new DFN models for 1,080 (East-West) × 1,080 (North-South) × 1,080 (Depth) m^3, where fractures are represented by squares of 44-346 m on a side, are re-constructed. In these new models, scale-dependent aperture distributions are considered for all fractures constructing the fracture networks. Note that the multi-scale modeling of fracture flow has been developed by the authors [Ishibashi et al., in preparation]. For the DFN models with aperture distributions, fluid flow simulations are conducted by GeoFlow. Before entering upon a discussion of the GeoFlow simulations, we show the interesting fact that approximately three-orders-of-magnitude difference in productivity is observed between two neighboring wells in the Yufutsu field. The conventional DFN model simulations can predict which productivity is high between these two wells, but they never reproduce the huge difference in well productivity. One of the reasons for this result is that the conventional DFN simulations ignored the concept of channeling flow. With these views in our mind, we see the result of the GeoFlow simulations. In the GeoFlow simulations, the huge difference in well productivity in the Yufutsu oil/gas field is successfully reproduced. This means that proper evaluation of 3D channeling flow is the key to predict well productivity in fractured reservoirs. Moreover, it is also clarified that the actual flow area is estimated to be around 20-50% of the flow area predicted by conventional DFN models. In this presentation, we will show the detail of the precise fracture network modeling and fluid flow analysis within them. The suggested method would be one of the most effective methods to improve our understanding of 3D channeling flow in fractured type of reservoirs.

  20. Time-dependent deformation of gas shales - role of rock framework versus reservoir fluids

    NASA Astrophysics Data System (ADS)

    Hol, Sander; Zoback, Mark

    2013-04-01

    Hydraulic fracturing operations are generally performed to achieve a fast, drastic increase of permeability and production rates. Although modeling of the underlying short-term mechanical response has proven successful via conventional geomechanical approaches, predicting long-term behavior is still challenging as the formation interacts physically and chemically with the fluids present in-situ. Recent experimental work has shown that shale samples subjected to a change in effective stress deform in a time-dependent manner ("creep"). Although the magnitude and nature of this behavior is strongly related to the composition and texture of the sample, also the choice of fluid used in the experiments affects the total strain response - strongly adsorbing fluids result in more, recoverable creep. The processes underlying time-dependent deformation of shales under in-situ stresses, and the long-term impact on reservoir performance, are at present poorly understood. In this contribution, we report triaxial mechanical tests, and theoretical/thermodynamic modeling work with the aim to identify and describe the main mechanisms that control time-dependent deformation of gas shales. In particular, we focus on the role of the shale solid framework versus the type and pressure of the present pore fluid. Our experiments were mainly performed on Eagle Ford Shale samples. The samples were subjected to cycles of loading and unloading, first in the dry state, and then again after equilibrating them with (adsorbing) CO2 and (non-adsorbing) He at fluid pressures of 4 MPa. Stresses were chosen close to those persisting under in-situ conditions. The results of our tests demonstrate that likely two main types of deformation mechanisms operate that relate to a) the presence of microfractures as a dominating feature in the solid framework of the shale, and b) the adsorbing potential of fluids present in the nanoscale voids of the shale. To explain the role of adsorption in the observed compaction creep, we postulate a serial coupling between 1) stress-driven desorption of the fluid species, 2) diffusion of the desorbed species out of the solid, and 3) consequent shrinkage. We propose a model in which the total shrinkage of the solid (Step 3) that is measured as bulk compaction, is driven by a change in stress state (Step 1), and evolves in time controlled by the diffusion characteristics of the system (Step 2). Our experimental and modeling study shows that both the nature of the solid framework of the shale, as well as the type and pressure of pore fluids affect the long-term in-situ mechanical behavior of gas shale reservoirs.

  1. Research on the methods of splitting and prediction point by point in tight sandstone gas reservoir productivity

    NASA Astrophysics Data System (ADS)

    Sheng-fu, Wen; Bao-zhi, Pan; Bi-ci, Jiang; Li-hua, Zhang; Dan, Liu; Wen-bin, Liu; Yu-hang, Guo

    2015-06-01

    Single-point productivity evaluation and prediction are of important significance for the exploration and development in a tight sandstone gas field. The method of production splitting, multiple linear regression (MLR), and support vector machine regression (SVR) was used to establish the relationship between logging data and the gas production split point-to-point in tight sandstone gas reservoirs. In this study, the western region of the Sulige area in the Ordos Basin was the object of our research. Compared with the traditional KH splitting, the KHK splitting method was better.

  2. Chemical-mechanical interactions during natural fracture growth in tight gas and oil reservoirs: Implications for flow during reservoir charge and production

    NASA Astrophysics Data System (ADS)

    Eichhubl, Peter; Fall, Andras; Prodanovic, Masa; Tokan-Lawal, Adenike; Lander, Robert; Laubach, Steve

    2013-04-01

    Natural fractures in tight sandstone and shale reservoirs are characterized by partial to complete cementation. In all tight-gas sandstone reservoirs and suitable outcrop reservoir analogs, fractures frequently contain crack-seal quartz and carbonate cement that formed during incremental fracture opening. These synkinematic cements may be followed by blocky postkinematic cement occluding any residual fracture porosity. Fluid inclusion microthermometry combined with Raman analyses demonstrate that synkinematic cement formed under conditions close to maximum burial and incipient exhumation under elevated pore fluid pressures and over time spans of 10-50 m.y.. Fracture opening rates, integrated over the kinematic fracture aperture, are on the order of 10 microm/m.y. Based on the textural evidence of synkinematic cement growth, in combination with kinetic models of quartz cementation, we infer that these rates are comparable to rates of dissolution-precipitation reactions in the host rock, and of mass transfer between host rock and fracture. It is thus suggested that dissolution-precipitation creep is a dominant deformation mechanism allowing accommodation of permanent fracture strain under these deep-burial, diagenetically reactive conditions. Synkinematic mineral reactions in the host rock and precipitation of fracture lining cement guarantee that partially cemented natural fractures remain propped open and thus conductive under production conditions. However, cement linings and bridges can inhibit flow between micro-porous host rock and residual fracture porosity resulting in flow barriers. Complex pore geometry in partially cemented fractures may impede multiphase fracture flow and production. In shale, the interface between host rock and fracture cement is frequently mechanically weak potentially allowing fracture reactivation during well completion. Such artificially reactivated fractures may thus increase flow of production fluids even in formation containing otherwise sealed natural fractures.

  3. Chemical-mechanical interactions during natural fracture growth in tight gas and oil reservoirs: Implications for flow during reservoir charge and production

    NASA Astrophysics Data System (ADS)

    Eichhubl, P.; Fall, A.; Prodanovic, M.; Weisenberger, T.; Ukar, E.; Laubach, S.; Gale, J. F.

    2012-12-01

    Natural fractures in tight sandstone and shale reservoirs are characterized by partial to complete cementation. In all tight-gas sandstone reservoirs and suitable outcrop reservoir analogs, fractures frequently contain crack-seal quartz and carbonate cement that formed during incremental fracture opening. These synkinematic cements may be followed by blocky postkinematic cement occluding any residual fracture porosity. Fluid inclusion microthermometry combined with Raman analyses demonstrate that synkinematic cement formed under conditions close to maximum burial and incipient exhumation under elevated pore fluid pressures and over time spans of 10-40 m.y.. Fracture opening rates, integrated over the kinematic fracture aperture, are on the order of 10 ?m/m.y. Based on the textural evidence of synkinematic cement growth, in combination with kinetic models of quartz cementation, we infer that these rates are comparable to rates of dissolution-precipitation reactions in the host rock, and of mass transfer between host rock and fracture. It is thus suggested that dissolution-precipitation creep is a dominant deformation mechanism allowing accommodation of permanent fracture strain under these deep-burial, diagenetically reactive conditions. Synkinematic mineral reactions in the host rock and precipitation of fracture lining cement guarantee that partially cemented natural fractures remain propped open and thus conductive under production conditions. However, cement linings and bridges can inhibit flow between micro-porous host rock and residual fracture porosity resulting in flow barriers. Complex pore geometry in partially cemented fractures may impede multiphase fracture flow and production. In shale, the interface between host rock and fracture cement is frequently mechanically weak potentially allowing fracture reactivation during well completion. Such artificially reactivated fractures may thus increase flow of production fluids even in formation containing otherwise sealed natural fractures.

  4. DEVELOPMENT OF A 400 LEVEL 3C CLAMPED DOWNHOLE SEISMIC RECEIVER ARRAY FOR 3D BOREHOLE SEISMIC IMAGING OF GAS RESERVOIRS

    SciTech Connect

    Bjorn N.P. Paulsson

    2002-09-01

    Borehole seismology is the highest resolution geophysical imaging technique available to the oil and gas industry for characterization and monitoring of oil and gas reservoirs. However, the industry's ability to economically do high resolution 3D imaging of deep and complex gas reservoirs using borehole seismology is currently frustrated by the lack of the acquisition technology necessary to record the large volumes of the high frequency, high signal-to-noise-ratio borehole seismic data needed to do 3D imaging. This proposal takes direct aim at this shortcoming. P/GSI is developing a 400 level 3C clamped downhole seismic receiver array for borehole seismic 3D imaging. This array will remove the acquisition barrier to record the necessary volumes of data to do high resolution 3D VSP or 3D cross well seismic imaging. 3D VSP and long range Cross-Well Seismology (CWS) are two of the borehole seismic techniques that will allow the Gas industry to take the next step in their quest for higher resolution images of the gas reservoirs. Today only a fraction of the original Oil or Gas in place is produced when reservoirs are considered depleted. This is primarily due to our lack of understanding of the detailed compartmentalization of the oil and gas reservoirs. The 400 level 3C borehole seismic receiver array will allow for economic use of 3D borehole seismic imaging for reservoir characterization and monitoring. By using 3C surface seismic or 3C borehole seismic sources the 400 level receiver array will furthermore facilitate 9C reservoir imaging. The 9C borehole seismic data will provide P, SH and SV information for imaging of the complex deep gas reservoirs and allow quantitative prediction of the rock and the fluid types. The data quality and the data volumes from a 400 level 3C array will allow us to develop the data processing technology necessary for high resolution reservoir imaging.

  5. DEVELOPMENT OF A 400 LEVEL 3C CLAMPED DOWNHOLE SEISMIC RECEIVER ARRAY FOR 3D BOREHOLE SEISMIC IMAGING OF GAS RESERVOIRS

    SciTech Connect

    Bjorn N.P Paulsson

    2002-05-01

    Borehole seismology is the highest resolution geophysical imaging technique available to the oil and gas industry for characterization and monitoring of oil and gas reservoirs. However, the industry's ability to economically do high resolution 3D imaging of deep and complex gas reservoirs using borehole seismology is currently frustrated by the lack of the acquisition technology necessary to record the large volumes of the high frequency, high signal-to-noise-ratio borehole seismic data needed to do 3D imaging. This proposal takes direct aim at this shortcoming. P/GSI is developing a 400 level 3C clamped downhole seismic receiver array for borehole seismic 3D imaging. This array will remove the acquisition barrier to record the necessary volumes of data to do high resolution 3D VSP or 3D cross well seismic imaging. 3D VSP and long range Cross-Well Seismology (CWS) are two of the borehole seismic techniques that will allow the Gas industry to take the next step in their quest for higher resolution images of the gas reservoirs. Today only a fraction of the original Oil or Gas in place is produced when reservoirs are considered depleted. This is primarily due to our lack of understanding of the detailed compartmentalization of the oil and gas reservoirs. The 400 level 3C borehole seismic receiver array will allow for economic use of 3D borehole seismic imaging for reservoir characterization and monitoring. By using 3C surface seismic or borehole seismic sources the 400 level receiver array will furthermore facilitate 9C reservoir imaging. The 9C borehole seismic data will provide P, SH and SV information for imaging of the complex deep gas reservoirs and allow quantitative prediction of the rock and the fluid types. The data quality and the data volumes from a 400 level 3C array will allow us to develop the data processing technology necessary for high resolution reservoir imaging.

  6. Application of modified AOGST to study the low frequency shadow zone in a gas reservoir

    NASA Astrophysics Data System (ADS)

    Abdollahi Aghdam, B.; Riahi, M. Ali

    2015-10-01

    The adaptive optimized window generalized S transform (AOGST) variant with frequency and time is a method for the time-frequency mapping of a signal. According to the AOGST method, an optimized regulation factor is calculated based on the energy concentration of the S transform. The value of this factor is 1 for standard S transform where in the AOGST method its value is limited by the interval of [0, 1]. However, AOGST may not produce an acceptable resolution for all parts of the time-frequency representation. We applied aggregation of confined interval-adaptive optimized generalized S transforms (ACI-AOGST) instead of the AOGST method. The proposed method applies the modified AOGST method to specific frequency and time intervals. By calculating regulation factors for limited frequency and time intervals of signal, arranging them in a suitable order and applying the ACI-AOGST one can provide a transformation with lowest distortion and highest resolution in comparison to other transformations. The proposed method has been used to analyse the time-frequency distribution of a synthetic signal as well as a real 2D seismic section of a producing gas reservoir located south of Iran. The results confirmed the robustness of the ACI-AOGST method.

  7. Naturally fractured tight gas reservoir detection optimization. Annual report, September 1993--September 1994

    SciTech Connect

    1994-10-01

    This report is an annual summarization of an ongoing research in the field of modeling and detecting naturally fractured gas reservoirs. The current research is in the Piceance basin of Western Colorado. The aim is to use existing information to determine the most optimal zone or area of fracturing using a unique reaction-transport-mechanical (RTM) numerical basin model. The RTM model will then subsequently help map subsurface lateral and vertical fracture geometries. The base collection techniques include in-situ fracture data, remote sensing, aeromagnetics, 2-D seismic, and regional geologic interpretations. Once identified, high resolution airborne and spaceborne imagery will be used to verify the RTM model by comparing surficial fractures. If this imagery agrees with the model data, then a further investigation using a three-dimensional seismic survey component will be added. This report presents an overview of the Piceance Creek basin and then reviews work in the Parachute and Rulison fields and the results of the RTM models in these fields.

  8. Depositional systems and diagenesis of Travis Peak tight gas sandstone reservoirs, Sabine Uplift Area, Texas

    SciTech Connect

    Fracasso, M.A.; Dutton, S.P.; Finley, R.J.

    1988-03-01

    The Travis Peak formation (lower Cretaceous) in the eastern East Texas basin is a fluvio-deltaic depositional system divided into large-scale facies packages: a middle sandstone-rich fluvial and delta-plain sequence that is gradationally overlain and underlain by a marine-influenced delta-fringe zone with a higher mudstone content. Domes and structural terraces on the west flank of the Sabine Uplift influenced deposition of Travis Peak sediments, and most Travis Peak gas production in this area is from thin sandstones (<25 ft(<7.6 m) thick) in the upper delta-fringe facies. The trapping mechanism is stratigraphic pinch-out of sandstones or porosity zones within sandstone, or both, on the flanks of structures. Detailed mapping of producing sandstone sequences in the uppermost upper delta-fringe on the western flank of the Bethany structure has delineated fluvial channelways, distributary or tidal channels, and barrier of distributary-mouth bars. Most Travis Peak gas production in the Bethany West area is from the bases of channel sandstones in a marine-influenced facies belt. Travis Peak sandstones in the eastern East Texas basin have undergone a complex series of diagenetic modifications. Precipitation of authigenic quartz, ankerite, dolomite, illite, and chlorite and the introduction of reservoir bitumen were the most important causes of occlusion of primary porosity and reduction of permeability. Permeability decreases with depth in the Travis Peak, which suggests that the diagenetic processes that caused extensive cementation and resultant low permeability throughout most of the formation operated less completely on sediments deposited near the top of the succession.

  9. Predicting variations of the least principal stress magnitudes in shale gas reservoirs utilizing variations of viscoplastic properties

    NASA Astrophysics Data System (ADS)

    Sone, H.; Zoback, M. D.

    2013-12-01

    Predicting variations of the magnitude of least principal stress within unconventional reservoirs has significant practical value as these reservoirs require stimulation by hydraulic fracturing. It is common to approach this problem by calculating the horizontal stresses caused by uniaxial gravitational loading using log-derived linear elastic properties of the formation and adding arbitrary tectonic strain (or stress). We propose a new method for estimating stress magnitudes in shale gas reservoirs based on the principles of viscous relaxation and steady-state tectonic loading. Laboratory experiments show that shale gas reservoir rocks exhibit wide range of viscoplastic behavior most dominantly controlled by its composition, whose stress relaxation behavior is described by a simple power-law (in time) rheology. We demonstrate that a reasonable profile of the principal stress magnitudes can be obtained from geophysical logs by utilizing (1) the laboratory power-law constitutive law, (2) a reasonable estimate of the tectonic loading history, and (3) the assumption that stress ratios ([S2-S3]/[S1-S3]) remains constant due to stress relaxation between all principal stresses. Profiles of horizontal stress differences (SHmax-Shmin) generated based on our method for a vertical well in the Barnett shale (Ft. Worth basin, Texas) generally agrees with the occurrence of drilling-induced tensile fractures in the same well. Also, the decrease in the least principal stress (frac gradient) upon entering the limestone formation underlying the Barnett shale appears to explain the downward propagation of the hydraulic fractures observed in the region. Our approach better acknowledges the time-dependent geomechanical effects that could occur over the course of the geological history. The proposed method may prove to be particularly useful for understanding hydraulic fracture containment within targeted reservoirs.

  10. Role of reservoir engineering in the assessment of undiscovered oil and gas resources in the National Petroleum Reserve, Alaska

    USGS Publications Warehouse

    Verma, M.K.; Bird, K.J.

    2005-01-01

    The geology and reservoir-engineering data were integrated in the 2002 U.S. Geological Survey assessment of the National Petroleum Reserve in Alaska (NPRA). VVhereas geology defined the analog pools and fields and provided the basic information on sizes and numbers of hypothesized petroleum accumulations, reservoir engineering helped develop necessary equations and correlations, which allowed the determination of reservoir parameters for better quantification of in-place petroleum volumes and recoverable reserves. Seismic- and sequence-stratigraphic study of the NPRA resulted in identification of 24 plays. Depth ranges in these 24 plays, however, were typically greater than depth ranges of analog plays for which there were available data, necessitating the need for establishing correlations. The basic parameters required were pressure, temperature, oil and gas formation volume factors, liquid/gas ratios for the associated and nonassociated gas, and recovery factors. Finally, the re sults of U.S. Geological Survey deposit simulation were used in carrying out an economic evaluation, which has been separately published. Copyright ?? 2005. The American Association of Petroleum Geologists. All rights reserved.

  11. Secondary natural gas recovery: Targeted applications for infield reserve growth in midcontinent reservoirs, Boonsville Field, Fort Worth Basin, Texas. Topical report, May 1993--June 1995

    SciTech Connect

    Hardage, B.A.; Carr, D.L.; Finley, R.J.; Tyler, N.; Lancaster, D.E.; Elphick, R.Y.; Ballard, J.R.

    1995-07-01

    The objectives of this project are to define undrained or incompletely drained reservoir compartments controlled primarily by depositional heterogeneity in a low-accommodation, cratonic Midcontinent depositional setting, and, afterwards, to develop and transfer to producers strategies for infield reserve growth of natural gas. Integrated geologic, geophysical, reservoir engineering, and petrophysical evaluations are described in complex difficult-to-characterize fluvial and deltaic reservoirs in Boonsville (Bend Conglomerate Gas) field, a large, mature gas field located in the Fort Worth Basin of North Texas. The purpose of this project is to demonstrate approaches to overcoming the reservoir complexity, targeting the gas resource, and doing so using state-of-the-art technologies being applied by a large cross section of Midcontinent operators.

  12. Implementation of the Ensemble Kalman Filter in the Characterization of Hydraulic Fractures in Shale Gas Reservoirs by Integrating Downhole Temperature Sensing Technology 

    E-print Network

    Moreno, Jose A

    2014-08-12

    Multi-stage hydraulic fracturing in horizontal wells has demonstrated successful results for developing unconventional low-permeability oil and gas reservoirs. Despite being vastly implemented by different operators across North America, hydraulic...

  13. Petrophysical Analysis and Geographic Information System for San Juan Basin Tight Gas Reservoirs

    SciTech Connect

    Martha Cather; Robert Lee; Robert Balch; Tom Engler; Roger Ruan; Shaojie Ma

    2008-10-01

    The primary goal of this project is to increase the availability and ease of access to critical data on the Mesaverde and Dakota tight gas reservoirs of the San Juan Basin. Secondary goals include tuning well log interpretations through integration of core, water chemistry and production analysis data to help identify bypassed pay zones; increased knowledge of permeability ratios and how they affect well drainage and thus infill drilling plans; improved time-depth correlations through regional mapping of sonic logs; and improved understanding of the variability of formation waters within the basin through spatial analysis of water chemistry data. The project will collect, integrate, and analyze a variety of petrophysical and well data concerning the Mesaverde and Dakota reservoirs of the San Juan Basin, with particular emphasis on data available in the areas defined as tight gas areas for purpose of FERC. A relational, geo-referenced database (a geographic information system, or GIS) will be created to archive this data. The information will be analyzed using neural networks, kriging, and other statistical interpolation/extrapolation techniques to fine-tune regional well log interpretations, improve pay zone recognition from old logs or cased-hole logs, determine permeability ratios, and also to analyze water chemistries and compatibilities within the study area. This single-phase project will be accomplished through four major tasks: Data Collection, Data Integration, Data Analysis, and User Interface Design. Data will be extracted from existing databases as well as paper records, then cleaned and integrated into a single GIS database. Once the data warehouse is built, several methods of data analysis will be used both to improve pay zone recognition in single wells, and to extrapolate a variety of petrophysical properties on a regional basis. A user interface will provide tools to make the data and results of the study accessible and useful. The final deliverable for this project will be a web-based GIS providing data, interpretations, and user tools that will be accessible to anyone with Internet access. During this project, the following work has been performed: (1) Assimilation of most special core analysis data into a GIS database; (2) Inventorying of additional data, such as log images or LAS files that may exist for this area; (3) Analysis of geographic distribution of that data to pinpoint regional gaps in coverage; (4) Assessment of the data within both public and proprietary data sets to begin tuning of regional well logging analyses and improve payzone recognition; (5) Development of an integrated web and GIS interface for all the information collected in this effort, including data from northwest New Mexico; (6) Acquisition and digitization of logs to create LAS files for a subset of the wells in the special core analysis data set; and (7) Petrophysical analysis of the final set of well logs.

  14. Evaluating reservoir production strategies in miscible and immiscible gas-injection projects 

    E-print Network

    Farzad, Iman

    2004-11-15

    , comprehensive reservoir engineering and project monitoring are necessary for typical miscible flood projects than for other recovery methods. This project evaluated effects of important factors such as injection pressure, vertical-to-horizontal permeability...

  15. Comparison of Single, Double, and Triple Linear Flow Models for Shale Gas/Oil Reservoirs 

    E-print Network

    Tivayanonda, Vartit

    2012-10-19

    reservoirs effectively. Verification and derivation of asymptotic and associated equations from the Laplace space for dual porosity and triple porosity models are performed in order to generate analysis equations. Theories and practical applications...

  16. Stochastic Modeling of a Fracture Network in a Hydraulically Fractured Shale-Gas Reservoir 

    E-print Network

    Mhiri, Adnene

    2014-08-10

    The fundamental behavior of fluid production from shale/ultra-low permeability reservoirs that are produced under a constant wellbore pressure remains difficult to quantify, which is believed to be (at least in part) due to the complexity...

  17. Rate Transient Analysis in Shale Gas Reservoirs with Transient Linear Behavior 

    E-print Network

    Bello, Rasheed O.

    2010-07-14

    . The horizontal well fully penetrates the rectangular reservoir. Convergence skin is incorporated into the linear model to account for the presence of the horizontal wellbore. Five flow regions were identified with this model. Region 1 is due to transient flow...

  18. Improved Upscaling & Well Placement Strategies for Tight Gas Reservoir Simulation and Management 

    E-print Network

    Zhou, Yijie

    2013-07-29

    an uncertainty map form the spatial connectivity analysis and variograms. Combining the quality map and uncertainty map, good infill well locations and drilling sequence can be determined for improved reservoir management. We apply this workflow to design...

  19. Modeling Performance of Horizontal Wells with Multiple Fractures in Tight Gas Reservoirs 

    E-print Network

    Dong, Guangwei

    2011-02-22

    Multiple transverse fracturing along a horizontal well is a relatively new technology that is designed to increase well productivity by increasing the contact between the reservoir and the wellbore. For multiple transverse fractures, the performance...

  20. Preliminary formation analysis for compressed air energy storage in depleted natural gas reservoirs : a study for the DOE Energy Storage Systems Program.

    SciTech Connect

    Gardner, William Payton

    2013-06-01

    The purpose of this study is to develop an engineering and operational understanding of CAES performance for a depleted natural gas reservoir by evaluation of relative permeability effects of air, water and natural gas in depleted natural gas reservoirs as a reservoir is initially depleted, an air bubble is created, and as air is initially cycled. The composition of produced gases will be evaluated as the three phase flow of methane, nitrogen and brine are modeled. The effects of a methane gas phase on the relative permeability of air in a formation are investigated and the composition of the produced fluid, which consists primarily of the amount of natural gas in the produced air are determined. Simulations of compressed air energy storage (CAES) in depleted natural gas reservoirs were carried out to assess the effect of formation permeability on the design of a simple CAES system. The injection of N2 (as a proxy to air), and the extraction of the resulting gas mixture in a depleted natural gas reservoir were modeled using the TOUGH2 reservoir simulator with the EOS7c equation of state. The optimal borehole spacing was determined as a function of the formation scale intrinsic permeability. Natural gas reservoir results are similar to those for an aquifer. Borehole spacing is dependent upon the intrinsic permeability of the formation. Higher permeability allows increased injection and extraction rates which is equivalent to more power per borehole for a given screen length. The number of boreholes per 100 MW for a given intrinsic permeability in a depleted natural gas reservoir is essentially identical to that determined for a simple aquifer of identical properties. During bubble formation methane is displaced and a sharp N2methane boundary is formed with an almost pure N2 gas phase in the bubble near the borehole. During cycling mixing of methane and air occurs along the boundary as the air bubble boundary moves. The extracted gas mixture changes as a function of time and proximity of the bubble boundary to the well. For all simulations reported here, with a formation radius above 50 m the maximum methane composition in the produced gas phase was less than 0.5%. This report provides an initial investigation of CAES in a depleted natural gas reservoir, and the results will provide useful guidance in CAES system investigation and design in the future.

  1. A reservoir of ionized gas in the galactic halo to sustain star formation in the Milky Way.

    PubMed

    Lehner, Nicolas; Howk, J Christopher

    2011-11-18

    Without a source of new gas, our Galaxy would exhaust its supply of gas through the formation of stars. Ionized gas clouds observed at high velocity may be a reservoir of such gas, but their distances are key for placing them in the galactic halo and unraveling their role. We have used the Hubble Space Telescope to blindly search for ionized high-velocity clouds (iHVCs) in the foreground of galactic stars. We show that iHVCs with 90 ? |v(LSR)| ? 170 kilometers per second (where v(LSR) is the velocity in the local standard of rest frame) are within one galactic radius of the Sun and have enough mass to maintain star formation, whereas iHVCs with |v(LSR)| ? 170 kilometers per second are at larger distances. These may be the next wave of infalling material. PMID:21868626

  2. Integrated seismic study of naturally fractured tight gas reservoirs. Technical progress report, January 1, 1994--March 31, 1994

    SciTech Connect

    Mavko, G.; Nur, A.

    1994-04-29

    The study area is located at the southern end of the Powder River Basin in Converse County in east-central Wyoming. It is a low permeability fractured site, with both gas and oil present. Reservoirs are highly compartmentalized due to the low permeabilities, and fractures provide the only practical drainage paths for production. The two formations of interest are: The Niobrara, a fractured shale and limey shale to chalk, which is a reservoir rock, but also its own source rock; and the Frontier, a tight sandstone lying directly below the Niobrara, brought into contact with it by an unconformity. This was the tenth quarter of the contract. During this quarter the investigators (1) continued processing the seismic data, and (2) continued modeling some of the P-wave amplitude anomalies that we see in the data.

  3. Multi-Method Monitoring of Shallow Gas Injection in Saline Coastal Reservoir at Maguelone (Languedoc coastline, France)

    NASA Astrophysics Data System (ADS)

    Denchik, N.; Pezard, P. A.; Lofi, J.; Luquot, L.; Neyens, D.; Jaafar, O.; Perroud, H.; Abdelghafour, H.; Henry, G.; Levannier, A.

    2014-12-01

    Geological storage of CO2 is still a recent technology and many questions remain open, particularly for saline formations. Geological storage in accessible saline formations is, in fact, expected to become over time more important than that in depleted hydrocarbon reservoirs. The Maguelone shallow experimental site, located near Montpellier (Languedoc, France) has been used over the past few years to perform CO2 injection experiments. The geology, petrophysics and hydrology of this site are well known from previous studies. The presence of small saline coastal reservoirs bounded above and below by clay-rich layers provides an opportunity to study a saline formation for geological storage at field laboratory scale with a set of hydrogeophysical (seismic, electrical, sonic, pressure) and geochemical (pH, minor and major ion concentrations) methods, either downhole or at surface. Series of experiments can be run at moderate costs from the shallow depth of one of these reservoirs (13-16 m), offering flexibility for testing different monitoring configurations, performing repeated injection releases with variable injection parameters and type of gas (e.g., N2, CO2), and cross-calibrating the monitoring methods. Moreover, additional methods/boreholes can be easily implemented at this experimental site. Three N2 injections were thus undertaken at Maguelone in 2012 to measure the site response to neutral gas injection. An experiment involving the release of CO2 was successively conducted in January 2013. A volume of 111 m3 of CO2 was injected during 3.5 hours. Both the N2 and CO2 gas plumes were detected by all monitoring techniques, and the response to gas propagation was instantaneous. Integrating the lesson learned from past injection experiments, the next stage of the project will allow to establish the best guidelines for CO2 injection and post-injection monitoring and, in perspective, not only to detect the CO2 plume but to quantify CO2 migration in the subsurface.

  4. Characterization of gas hydrate reservoirs by integration of core and log data in the Ulleung Basin, East Sea

    USGS Publications Warehouse

    Bahk, J.-J.; Kim, G.-Y.; Chun, J.-H.; Kim, J.-H.; Lee, J.Y.; Ryu, B.-J.; Lee, J.-H.; Son, B.-K.; Collett, Timothy S.

    2013-01-01

    Examinations of core and well-log data from the Second Ulleung Basin Gas Hydrate Drilling Expedition (UBGH2) drill sites suggest that Sites UBGH2-2_2 and UBGH2-6 have relatively good gas hydrate reservoir quality in terms of individual and total cumulative thicknesses of gas-hydrate-bearing sand (HYBS) beds. In both of the sites, core sediments are generally dominated by hemipelagic muds which are intercalated with turbidite sands. The turbidite sands are usually thin-to-medium bedded and mainly consist of well sorted coarse silt to fine sand. Anomalies in infrared core temperatures and porewater chlorinity data and pressure core measurements indicate that “gas hydrate occurrence zones” (GHOZ) are present about 68–155 mbsf at Site UBGH2-2_2 and 110–155 mbsf at Site UBGH2-6. In both the GHOZ, gas hydrates are preferentially associated with many of the turbidite sands as “pore-filling” type hydrates. The HYBS identified in the cores from Site UBGH2-6 are medium-to-thick bedded particularly in the lower part of the GHOZ and well coincident with significant high excursions in all of the resistivity, density, and velocity logs. Gas-hydrate saturations in the HYBS range from 12% to 79% with an average of 52% based on pore-water chlorinity. In contrast, the HYBS from Site UBGH2-2_2 are usually thin-bedded and show poor correlations with both of the resistivity and velocity logs owing to volume averaging effects of the logging tools on the thin HYBS beds. Gas-hydrate saturations in the HYBS range from 15% to 65% with an average of 37% based on pore-water chlorinity. In both of the sites, large fluctuations in biogenic opal contents have significant effects on the sediment physical properties, resulting in limited usage of gamma ray and density logs in discriminating sand reservoirs.

  5. Greenhouse Gas Emissions from U.S. Hydropower Reservoirs: FY2011 Annual Progress Report

    SciTech Connect

    Stewart, Arthur J; Mosher, Jennifer J; Mulholland, Patrick J; Fortner, Allison M; Phillips, Jana Randolph; Bevelhimer, Mark S

    2012-05-01

    The primary objective of this study is to quantify the net emissions of key greenhouse gases (GHG) - notably, CO{sub 2} and CH{sub 4} - from hydropower reservoirs in moist temperate areas within the U.S. The rationale for this objective is straightforward: if net emissions of GHG can be determined, it would be possible to directly compare hydropower to other power-producing methods on a carbon-emissions basis. Studies of GHG emissions from hydropower reservoirs elsewhere suggest that net emissions can be moderately high in tropical areas. In such areas, warm temperatures and relatively high supply rates of labile organic matter can encourage high rates of decomposition, which (depending upon local conditions) can result in elevated releases of CO{sub 2} and CH{sub 4}. CO{sub 2} and CH{sub 4} emissions also tend to be higher for younger reservoirs than for older reservoirs, because vegetation and labile soil organic matter that is inundated when a reservoir is created can continue to decompose for several years (Galy-Lacaux et al. 1997, Barros et al. 2011). Water bodies located in climatically cooler areas, such as in boreal forests, could be expected to have lower net emissions of CO{sub 2} and CH{sub 4} because their organic carbon supplies tend to be relatively recalcitrant to microbial action and because cooler water temperatures are less conducive to decomposition.

  6. CO2 utilization and storage in shale gas reservoirs: Experimental results and economic impacts

    SciTech Connect

    Schaef, Herbert T.; Davidson, Casie L.; Owen, Antionette Toni; Miller, Quin R. S.; Loring, John S.; Thompson, Christopher J.; Bacon, Diana H.; Glezakou, Vassiliki Alexandra; McGrail, B. Peter

    2014-12-31

    Natural gas is considered a cleaner and lower-emission fuel than coal, and its high abundance from advanced drilling techniques has positioned natural gas as a major alternative energy source for the U.S. However, each ton of CO2 emitted from any type of fossil fuel combustion will continue to increase global atmospheric concentrations. One unique approach to reducing anthropogenic CO2 emissions involves coupling CO2 based enhanced gas recovery (EGR) operations in depleted shale gas reservoirs with long-term CO2 storage operations. In this paper, we report unique findings about the interactions between important shale minerals and sorbing gases (CH4 and CO2) and associated economic consequences. Where enhanced condensation of CO2 followed by desorption on clay surface is observed under supercritical conditions, a linear sorption profile emerges for CH4. Volumetric changes to montmorillonites occur during exposure to CO2. Theory-based simulations identify interactions with interlayer cations as energetically favorable for CO2 intercalation. Thus, experimental evidence suggests CH4 does not occupy the interlayer and has only the propensity for surface adsorption. Mixed CH4:CO2 gas systems, where CH4 concentrations prevail, indicate preferential CO2 sorption as determined by in situ infrared spectroscopy and X-ray diffraction techniques. Collectively, these laboratory studies combined with a cost-based economic analysis provide a basis for identifying favorable CO2-EOR opportunities in previously fractured shale gas reservoirs approaching final stages of primary gas production. Moreover, utilization of site-specific laboratory measurements in reservoir simulators provides insight into optimum injection strategies for maximizing CH4/CO2 exchange rates to obtain peak natural gas production.

  7. Fracture patterns and their origin in the upper Devonian Antrim Shale gas reservoir of the Michigan basin; a review

    USGS Publications Warehouse

    Ryder, Robert T.

    1996-01-01

    INTRODUCTION: Black shale members of the Upper Devonian Antrim Shale are both the source and reservoir for a regional gas accumulation that presently extends across parts of six counties in the northern part of the Michigan basin (fig. 1). Natural fractures are considered by most petroleum geologists and oil and gas operators who work the Michigan basin to be a necessary condition for commercial gas production in the Antrim Shale. Fractures provide the conduits for free gas and associated water to flow to the borehole through the black shale which, otherwise, has a low matrix permeability. Moreover, the fractures assist in the release of gas adsorbed on mineral and(or) organic matter in the shale (Curtis, 1992). Depths to the gas-producing intervals (Norwood and Lachine Members) generally range from 1,200 to 1,800 ft (Oil and Gas Journal, 1994). Locally, wells that produce gas from the accumulation are as deep as 2,200 (Oil and Gas Journal, 1994). Even though natural fractures are an important control on Antrim Shale gas production, most wells require stimulation by hydraulic fracturing to attain commercial production rates (Kelly, 1992). In the U.S. Geological Survey's National Assessment of United States oil and gas, Dolton (1995) estimates that, at a mean value, 4.45 trillion cubic feet (TCF) of gas are recoverable as additions to already discovered quantities from the Antrim Shale in the productive area of the northern Michigan trend. Dolton (1995) also suggests that undiscovered Antrim Shale gas accumulations exist in other parts of the Michigan basin. The character, distribution, and origin of natural fractures in the Antrim Shale gas accumulation have been studied recently by academia and industry. The intent of these investigations is to: 1) predict 'sweet spots', prior to drilling, in the existing gas-producing trend, 2) improve production practices in the existing trend, 3) predict analogous fracture-controlled gas accumulations in other parts of the Michigan basin, and 4) improve estimates of the recoverable gas in the Antrim Shale gas plays (Dolton, 1995). This review of published literature on the characteristics of Antrim Shale fractures, their origin, and their controls on gas production will help to define objectives and goals in future U.S. Geological Survey studies of Antrim Shale gas resources.

  8. Diagenesis and fluid evolution of deeply buried Permian (Rotliegende) gas reservoirs, Northwest Germany

    SciTech Connect

    Gaupp, R. ); Matter, A.; Ramseyer, K.; Platt, J. ); Walzebuck, J. )

    1993-07-01

    Depositional environment and tectonic setting were important in the diagenesis and evolution of reservoir properties in the Rotliegende sequence of the North German Basin. Facies belts paralleling the edge of a central saline lake controlled the distribution of early and shallow burial cements. Lake shoreline sands with radial chlorite cement show the best reservoir properties in the study area. Juxtaposition of Rotliegende deposits against either Carboniferous Coal Measures or Late Permian (Zechstein) evaporites by faulting resulted in cross-formational fluid exchange. The introduction of fluids from Carboniferous Coal Measures into Rotliegende reservoirs produced intense clay cementation, significantly reducing rock permeabilities. Influx of Zechstein fluids favored precipitation of late carbonate and anhydrite cements. Cross-formational and fault-related fluid flow was enhanced during periods of fault activity. 50 refs., 15 figs., 1 tab.

  9. Laboratory analysis of gas hydrate cores for evaluation of reservoir conditions. For the months January 1, 1984-May 31, 1984

    SciTech Connect

    Holder, G.D.

    1984-01-01

    The objective is to provide technical assistance to METC's effort to develop a leading program in the evaluation of hydrate samples in porous media at reservoir conditions. An existing computer program has been modified to calculate enthalpies of dissociation, equilibrium pressures, and earth temperature-depth profiles for hydrate formation as a function of gas composition. In this report results of the depth-temperature studies are presented. The effect of gas composition, geothermal gradient, permafrost thickness and pressure gradient on the thickness of a hydrate stability zone in permafrost regions is covered. The effect of ocean bottom temperature, gas composition and ocean depth on a hydrate stability zone beneath the ocean is shown. These variables are considered to be among the more important in determining the potential that a particular region has for containing hydrates and they need to be measured in any geological investigation of a region. 24 references, 11 figures, 1 table.

  10. Characterization of oil and gas reservoir heterogeneity. Annual report, November 1, 1990--October 31, 1991

    SciTech Connect

    Not Available

    1991-12-31

    The objective of the cooperative research program is to characterize Alaskan reservoirs in terms of their reserves, physical and chemical properties, geologic configuration and structure, and the development potential. The tasks completed during this period include: (1) geologic reservoir description of Endicott Field; (2) petrographic characterization of core samples taken from selected stratigraphic horizons of the West Sak and Ugnu (Brookian) wells; (3) development of a polydispersed thermodynamic model for predicting asphaltene equilibria and asphaltene precipitation from crude oil-solvent mixtures, and (4) preliminary geologic description of the Milne Point Unit.

  11. Laboratory analysis of gas hydrate cores for evaluation of reservoir conditions. For the months December 1, 1983-April 30, 1984

    SciTech Connect

    Holder, G.D.

    1984-01-01

    The object of this work is to provide technical assistance to Morgantown Energy Technology Center's effort to develop a leading program in the evaluation of hydrate samples in porous media at reservoir conditions. During the period from January to March work done on the project focused on the preparation of the heat transfer and hydrate formation data and on the writing of the previous reports. During the last two months, including April, time has been devoted to the modification of our computer program to generate hydrate stability data in the earth. In addition to this work, the effect of gas composition on dissociation enthalpy is being studied.

  12. UONPR No. 1, Elk Hills, 26R Reservoir, Elk Hills oil and gas field, Kern County, California: Management Review: Surface operations and measurements of production and injection volumes

    SciTech Connect

    Not Available

    1987-01-01

    Evans, Carey and Crozier was given the task to conduct a Management Review of the Surface Operations of the 26R Reservoir in UONPR No. 1, Elk Hills field, Kern County, California. The MER strategy for this reservoir is to maintain pressure, and toward this end, gas injection volumes are scheduled to amount to 110% of calculated withdrawals. In spite of this, however, reservoir pressure continues to decline. The purpose of this study was, therefore, to determine if, and to what extent, field operating practices and accounting procedures may be contributing to this dilemma and to make appropriate recommendations pertaining to correcting any deficiencies which may have been found.

  13. Development of a 400 Level 3C Clamped Downhole Seismic Receiver Array for 3D Borehole Seismic Imaging of Gas Reservoirs

    SciTech Connect

    Bjorn N.P. Paulsson

    2005-08-21

    Borehole seismology is the highest resolution geophysical imaging technique available today to the oil and gas industry for characterization and monitoring of oil and gas reservoirs. However, the industry's ability to economically do high resolution 3D imaging of deep and complex gas reservoirs using borehole seismology is currently hampered by the lack of the acquisition technology necessary to record the large volumes of the high frequency, high signal-to-noise-ratio borehole seismic data needed to do 3D imaging. This project takes direct aim at this shortcoming by developing a 400 level 3C clamped downhole seismic receiver array, and accompanying software, for borehole seismic 3D imaging. This large borehole seismic array will remove the technical acquisition barrier for recording the necessary volumes of data to do high resolution 3D VSP or 3D cross well seismic imaging. Massive 3D VSP{reg_sign} and long range Cross-Well Seismology (CWS) are two of the borehole seismic techniques that will allow the Gas industry to take the next step in their quest for higher resolution images of the gas reservoirs for the purpose of improving the recovery of the natural gas resources. Today only a fraction of the original Oil or Gas in place is produced when reservoirs are considered depleted. This is primarily due to our lack of understanding of the detailed compartmentalization of the oil and gas reservoirs. The 400 level 3C borehole seismic receiver array will allow for the economic use of 3D borehole seismic imaging for reservoir characterization and monitoring by allowing the economic recording of the required large data volumes that have a sufficiently dense spatial sampling. By using 3C surface seismic or 3C borehole seismic sources the 400 level receiver arrays will furthermore allow 3D reservoir imaging using 9C data. The 9C borehole seismic data will provide P, SH and SV information for imaging of the complex deep gas reservoirs and allow quantitative prediction of the rock and the fluid types. The data quality and the data volumes from a 400 level 3C array will allow us to develop the data processing technology necessary for high resolution reservoir imaging.

  14. DEVELOPMENT OF A 400 LEVEL 3C CLAMPED DOWNHOLE SEISMIC RECEIVER ARRAY FOR 3D BOREHOLE SEISMIC IMAGING OF GAS RESERVOIRS

    SciTech Connect

    Bjorn N.P. Paulsson

    2005-03-31

    Borehole seismology is the highest resolution geophysical imaging technique available today to the oil and gas industry for characterization and monitoring of oil and gas reservoirs. However, the industry's ability to economically do high resolution 3D imaging of deep and complex gas reservoirs using borehole seismology is currently hampered by the lack of the acquisition technology necessary to record the large volumes of the high frequency, high signal-to-noise-ratio borehole seismic data needed to do 3D imaging. This project takes direct aim at this shortcoming by developing a 400 level 3C clamped downhole seismic receiver array, and accompanying software, for borehole seismic 3D imaging. This large borehole seismic array will remove the technical acquisition barrier for recording the necessary volumes of data to do high resolution 3D VSP or 3D cross well seismic imaging. Massive 3D VSP{reg_sign} and long range Cross-Well Seismology (CWS) are two of the borehole seismic techniques that will allow the Gas industry to take the next step in their quest for higher resolution images of the gas reservoirs for the purpose of improving the recovery of the natural gas resources. Today only a fraction of the original Oil or Gas in place is produced when reservoirs are considered depleted. This is primarily due to our lack of understanding of the detailed compartmentalization of the oil and gas reservoirs. The 400 level 3C borehole seismic receiver array will allow for the economic use of 3D borehole seismic imaging for reservoir characterization and monitoring by allowing the economic recording of the required large data volumes that have a sufficiently dense spatial sampling. By using 3C surface seismic or 3C borehole seismic sources the 400 level receiver arrays will furthermore allow 3D reservoir imaging using 9C data. The 9C borehole seismic data will provide P, SH and SV information for imaging of the complex deep gas reservoirs and allow quantitative prediction of the rock and the fluid types. The data quality and the data volumes from a 400 level 3C array will allow us to develop the data processing technology necessary for high resolution reservoir imaging.

  15. DEVELOPMENT OF A 400 LEVEL 3C CLAMPED DOWNHOLE SEISMIC RECEIVER ARRAY FOR 3D BOREHOLE SEISMIC IMAGING OF GAS RESERVOIRS

    SciTech Connect

    Bjorn N.P. Paulsson

    2002-12-01

    Borehole seismology is the highest resolution geophysical imaging technique available today to the oil and gas industry for characterization and monitoring of oil and gas reservoirs. However, the industry's ability to economically do high resolution 3D imaging of deep and complex gas reservoirs using borehole seismology is currently frustrated by the lack of the acquisition technology necessary to record the large volumes of the high frequency, high signal-to-noise-ratio borehole seismic data needed to do 3D imaging. This project takes direct aim at this shortcoming by developing a 400 level 3C clamped downhole seismic receiver array, and accompanying software, for borehole seismic 3D imaging. This large borehole seismic array will remove the technical acquisition barrier for recording the necessary volumes of data to do high resolution 3D VSP or 3D cross well seismic imaging. 3D VSP and long range Cross-Well Seismology (CWS) are two of the borehole seismic techniques that will allow the Gas industry to take the next step in their quest for higher resolution images of the gas reservoirs for the purpose of improving the recovery of the natural gas resources. Today only a fraction of the original Oil or Gas in place is produced when reservoirs are considered depleted. This is primarily due to our lack of understanding of the detailed compartmentalization of the oil and gas reservoirs. The 400 level 3C borehole seismic receiver array will allow for the economic use of 3D borehole seismic imaging for reservoir characterization and monitoring by allowing the economic recording of the required large data volumes that have a sufficiently dense spatial sampling. By using 3C surface seismic or 3C borehole seismic sources the 400 level receiver array will furthermore allow 3D reservoir imaging using 9C data. The 9C borehole seismic data will provide P, SH and SV information for imaging of the complex deep gas reservoirs and allow quantitative prediction of the rock and the fluid types. The data quality and the data volumes from a 400 level 3C array will allow us to develop the data processing technology necessary for high resolution reservoir imaging.

  16. DEVELOPMENT OF A 400 LEVEL 3C CLAMPED DOWNHOLE SEISMIC RECEIVER ARRAY FOR 3D BOREHOLE SEISMIC IMAGING OF GAS RESERVOIRS.

    SciTech Connect

    Bjorn N.P Paulsson

    2003-01-01

    Borehole seismology is the highest resolution geophysical imaging technique available today to the oil and gas industry for characterization and monitoring of oil and gas reservoirs. However, the industry's ability to economically do high resolution 3D imaging of deep and complex gas reservoirs using borehole seismology is currently frustrated by the lack of the acquisition technology necessary to record the large volumes of the high frequency, high signal-to-noise-ratio borehole seismic data needed to do 3D imaging. This project takes direct aim at this shortcoming by developing a 400 level 3C clamped downhole seismic receiver array, and accompanying software, for borehole seismic 3D imaging. This large borehole seismic array will remove the technical acquisition barrier for recording the necessary volumes of data to do high resolution 3D VSP or 3D cross well seismic imaging. 3D VSP and long range Cross-Well Seismology (CWS) are two of the borehole seismic techniques that will allow the Gas industry to take the next step in their quest for higher resolution images of the gas reservoirs for the purpose of improving the recovery of the natural gas resources. Today only a fraction of the original Oil or Gas in place is produced when reservoirs are considered depleted. This is primarily due to our lack of understanding of the detailed compartmentalization of the oil and gas reservoirs. The 400 level 3C borehole seismic receiver array will allow for the economic use of 3D borehole seismic imaging for reservoir characterization and monitoring by allowing the economic recording of the required large data volumes that have a sufficiently dense spatial sampling. By using 3C surface seismic or 3C borehole seismic sources the 400 level receiver array will furthermore allow 3D reservoir imaging using 9C data. The 9C borehole seismic data will provide P, SH and SV information for imaging of the complex deep gas reservoirs and allow quantitative prediction of the rock and the fluid types. The data quality and the data volumes from a 400 level 3C array will allow us to develop the data processing technology necessary for high resolution reservoir imaging.

  17. DEVELOPMENT OF A 400 LEVEL 3C CLAMPED DOWNHOLE SEISMIC RECEIVER ARRAY FOR 3D BOREHOLE SEISMIC IMAGING OF GAS RESERVOIRS

    SciTech Connect

    Bjorn N.P Paulsson

    2003-09-01

    Borehole seismology is the highest resolution geophysical imaging technique available today to the oil and gas industry for characterization and monitoring of oil and gas reservoirs. However, the industry's ability to economically do high resolution 3D imaging of deep and complex gas reservoirs using borehole seismology is currently frustrated by the lack of the acquisition technology necessary to record the large volumes of the high frequency, high signal-to-noise-ratio borehole seismic data needed to do 3D imaging. This project takes direct aim at this shortcoming by developing a 400 level 3C clamped downhole seismic receiver array, and accompanying software, for borehole seismic 3D imaging. This large borehole seismic array will remove the technical acquisition barrier for recording the necessary volumes of data to do high resolution 3D VSP or 3D cross well seismic imaging. 3D VSP and long range Cross-Well Seismology (CWS) are two of the borehole seismic techniques that will allow the Gas industry to take the next step in their quest for higher resolution images of the gas reservoirs for the purpose of improving the recovery of the natural gas resources. Today only a fraction of the original Oil or Gas in place is produced when reservoirs are considered depleted. This is primarily due to our lack of understanding of the detailed compartmentalization of the oil and gas reservoirs. The 400 level 3C borehole seismic receiver array will allow for the economic use of 3D borehole seismic imaging for reservoir characterization and monitoring by allowing the economic recording of the required large data volumes that have a sufficiently dense spatial sampling. By using 3C surface seismic or 3C borehole seismic sources the 400 level receiver array will furthermore allow 3D reservoir imaging using 9C data. The 9C borehole seismic data will provide P, SH and SV information for imaging of the complex deep gas reservoirs and allow quantitative prediction of the rock and the fluid types. The data quality and the data volumes from a 400 level 3C array will allow us to develop the data processing technology necessary for high resolution reservoir imaging.

  18. DEVELOPMENT OF A 400 LEVEL 3C CLAMPED DOWNHOLE SEISMIC RECEIVER ARRAY FOR 3D BOREHOLE SEISMIC IMAGING OF GAS RESERVOIRS

    SciTech Connect

    Bjorn N.P Paulsson

    2003-07-01

    Borehole seismology is the highest resolution geophysical imaging technique available today to the oil and gas industry for characterization and monitoring of oil and gas reservoirs. However, the industry's ability to economically do high resolution 3D imaging of deep and complex gas reservoirs using borehole seismology is currently frustrated by the lack of the acquisition technology necessary to record the large volumes of the high frequency, high signal-to-noise-ratio borehole seismic data needed to do 3D imaging. This project takes direct aim at this shortcoming by developing a 400 level 3C clamped downhole seismic receiver array, and accompanying software, for borehole seismic 3D imaging. This large borehole seismic array will remove the technical acquisition barrier for recording the necessary volumes of data to do high resolution 3D VSP or 3D cross well seismic imaging. 3D VSP and long range Cross-Well Seismology (CWS) are two of the borehole seismic techniques that will allow the Gas industry to take the next step in their quest for higher resolution images of the gas reservoirs for the purpose of improving the recovery of the natural gas resources. Today only a fraction of the original Oil or Gas in place is produced when reservoirs are considered depleted. This is primarily due to our lack of understanding of the detailed compartmentalization of the oil and gas reservoirs. The 400 level 3C borehole seismic receiver array will allow for the economic use of 3D borehole seismic imaging for reservoir characterization and monitoring by allowing the economic recording of the required large data volumes that have a sufficiently dense spatial sampling. By using 3C surface seismic or 3C borehole seismic sources the 400 level receiver array will furthermore allow 3D reservoir imaging using 9C data. The 9C borehole seismic data will provide P, SH and SV information for imaging of the complex deep gas reservoirs and allow quantitative prediction of the rock and the fluid types. The data quality and the data volumes from a 400 level 3C array will allow us to develop the data processing technology necessary for high resolution reservoir imaging.

  19. DEVELOPMENT OF A 400 LEVEL 3C CLAMPED DOWNHOLE SEISMIC RECEIVER ARRAY FOR 3D BOREHOLE SEISMIC IMAGING OF GAS RESERVOIRS

    SciTech Connect

    Bjorn N.P. Paulsson

    2004-05-31

    Borehole seismology is the highest resolution geophysical imaging technique available today to the oil and gas industry for characterization and monitoring of oil and gas reservoirs. However, the industry's ability to economically do high resolution 3D imaging of deep and complex gas reservoirs using borehole seismology is currently frustrated by the lack of the acquisition technology necessary to record the large volumes of the high frequency, high signal-to-noise-ratio borehole seismic data needed to do 3D imaging. This project takes direct aim at this shortcoming by developing a 400 level 3C clamped downhole seismic receiver array, and accompanying software, for borehole seismic 3D imaging. This large borehole seismic array will remove the technical acquisition barrier for recording the necessary volumes of data to do high resolution 3D VSP or 3D cross well seismic imaging. 3D VSP and long range Cross-Well Seismology (CWS) are two of the borehole seismic techniques that will allow the Gas industry to take the next step in their quest for higher resolution images of the gas reservoirs for the purpose of improving the recovery of the natural gas resources. Today only a fraction of the original Oil or Gas in place is produced when reservoirs are considered depleted. This is primarily due to our lack of understanding of the detailed compartmentalization of the oil and gas reservoirs. The 400 level 3C borehole seismic receiver array will allow for the economic use of 3D borehole seismic imaging for reservoir characterization and monitoring by allowing the economic recording of the required large data volumes that have a sufficiently dense spatial sampling. By using 3C surface seismic or 3C borehole seismic sources the 400 level receiver array will furthermore allow 3D reservoir imaging using 9C data. The 9C borehole seismic data will provide P, SH and SV information for imaging of the complex deep gas reservoirs and allow quantitative prediction of the rock and the fluid types. The data quality and the data volumes from a 400 level 3C array will allow us to develop the data processing technology necessary for high resolution reservoir imaging.

  20. DEVELOPMENT OF A 400 LEVEL 3C CLAMPED DOWNHOLE SEISMIC RECEIVER ARRAY FOR 3D BOREHOLE SEISMIC IMAGING OF GAS RESERVOIRS

    SciTech Connect

    Bjorn N.P. Paulsson

    2003-12-01

    Borehole seismology is the highest resolution geophysical imaging technique available today to the oil and gas industry for characterization and monitoring of oil and gas reservoirs. However, the industry's ability to economically do high resolution 3D imaging of deep and complex gas reservoirs using borehole seismology is currently frustrated by the lack of the acquisition technology necessary to record the large volumes of the high frequency, high signal-to-noise-ratio borehole seismic data needed to do 3D imaging. This project takes direct aim at this shortcoming by developing a 400 level 3C clamped downhole seismic receiver array, and accompanying software, for borehole seismic 3D imaging. This large borehole seismic array will remove the technical acquisition barrier for recording the necessary volumes of data to do high resolution 3D VSP or 3D cross well seismic imaging. 3D VSP and long range Cross-Well Seismology (CWS) are two of the borehole seismic techniques that will allow the Gas industry to take the next step in their quest for higher resolution images of the gas reservoirs for the purpose of improving the recovery of the natural gas resources. Today only a fraction of the original Oil or Gas in place is produced when reservoirs are considered depleted. This is primarily due to our lack of understanding of the detailed compartmentalization of the oil and gas reservoirs. The 400 level 3C borehole seismic receiver array will allow for the economic use of 3D borehole seismic imaging for reservoir characterization and monitoring by allowing the economic recording of the required large data volumes that have a sufficiently dense spatial sampling. By using 3C surface seismic or 3C borehole seismic sources the 400 level receiver array will furthermore allow 3D reservoir imaging using 9C data. The 9C borehole seismic data will provide P, SH and SV information for imaging of the complex deep gas reservoirs and allow quantitative prediction of the rock and the fluid types. The data quality and the data volumes from a 400 level 3C array will allow us to develop the data processing technology necessary for high resolution reservoir imaging.

  1. DEVELOPMENT OF A 400 LEVEL 3C CLAMPED DOWNHOLE SEISMIC RECEIVER ARRAY FOR 3D BOREHOLE SEISMIC IMAGING OF GAS RESERVOIRS

    SciTech Connect

    Bjorn N.P. Paulsson

    2004-09-30

    Borehole seismology is the highest resolution geophysical imaging technique available today to the oil and gas industry for characterization and monitoring of oil and gas reservoirs. However, the industry's ability to economically do high resolution 3D imaging of deep and complex gas reservoirs using borehole seismology is currently frustrated by the lack of the acquisition technology necessary to record the large volumes of the high frequency, high signal-to-noise-ratio borehole seismic data needed to do 3D imaging. This project takes direct aim at this shortcoming by developing a 400 level 3C clamped downhole seismic receiver array, and accompanying software, for borehole seismic 3D imaging. This large borehole seismic array will remove the technical acquisition barrier for recording the necessary volumes of data to do high resolution 3D VSP or 3D cross well seismic imaging. Massive 3D VSP{reg_sign} and long range Cross-Well Seismology (CWS) are two of the borehole seismic techniques that will allow the Gas industry to take the next step in their quest for higher resolution images of the gas reservoirs for the purpose of improving the recovery of the natural gas resources. Today only a fraction of the original Oil or Gas in place is produced when reservoirs are considered depleted. This is primarily due to our lack of understanding of the detailed compartmentalization of the oil and gas reservoirs. The 400 level 3C borehole seismic receiver array will allow for the economic use of 3D borehole seismic imaging for reservoir characterization and monitoring by allowing the economic recording of the required large data volumes that have a sufficiently dense spatial sampling. By using 3C surface seismic or 3C borehole seismic sources the 400 level receiver arrays will furthermore allow 3D reservoir imaging using 9C data. The 9C borehole seismic data will provide P, SH and SV information for imaging of the complex deep gas reservoirs and allow quantitative prediction of the rock and the fluid types. The data quality and the data volumes from a 400 level 3C array will allow us to develop the data processing technology necessary for high resolution reservoir imaging.

  2. DEVELOPMENT OF A 400 LEVEL 3C CLAMPED DOWNHOLE SEISMIC RECEIVER ARRAY FOR 3D BOREHOLE SEISMIC IMAGING OF GAS RESERVOIRS

    SciTech Connect

    Bjorn N.P. Paulsson

    2004-06-30

    Borehole seismology is the highest resolution geophysical imaging technique available today to the oil and gas industry for characterization and monitoring of oil and gas reservoirs. However, the industry's ability to economically do high resolution 3D imaging of deep and complex gas reservoirs using borehole seismology is currently frustrated by the lack of the acquisition technology necessary to record the large volumes of the high frequency, high signal-to-noise-ratio borehole seismic data needed to do 3D imaging. This project takes direct aim at this shortcoming by developing a 400 level 3C clamped downhole seismic receiver array, and accompanying software, for borehole seismic 3D imaging. This large borehole seismic array will remove the technical acquisition barrier for recording the necessary volumes of data to do high resolution 3D VSP or 3D cross well seismic imaging. 3D VSP and long range Cross-Well Seismology (CWS) are two of the borehole seismic techniques that will allow the Gas industry to take the next step in their quest for higher resolution images of the gas reservoirs for the purpose of improving the recovery of the natural gas resources. Today only a fraction of the original Oil or Gas in place is produced when reservoirs are considered depleted. This is primarily due to our lack of understanding of the detailed compartmentalization of the oil and gas reservoirs. The 400 level 3C borehole seismic receiver array will allow for the economic use of 3D borehole seismic imaging for reservoir characterization and monitoring by allowing the economic recording of the required large data volumes that have a sufficiently dense spatial sampling. By using 3C surface seismic or 3C borehole seismic sources the 400 level receiver array will furthermore allow 3D reservoir imaging using 9C data. The 9C borehole seismic data will provide P, SH and SV information for imaging of the complex deep gas reservoirs and allow quantitative prediction of the rock and the fluid types. The data quality and the data volumes from a 400 level 3C array will allow us to develop the data processing technology necessary for high resolution reservoir imaging.

  3. DEVELOPMENT OF A 400 LEVEL 3C CLAMPED DOWNHOLE SEISMIC RECEIVER ARRAY FOR 3D BOREHOLE SEISMIC IMAGING OF GAS RESERVOIRS

    SciTech Connect

    Bjorn N.P. Paulsson

    2004-12-31

    Borehole seismology is the highest resolution geophysical imaging technique available today to the oil and gas industry for characterization and monitoring of oil and gas reservoirs. However, the industry's ability to economically do high resolution 3D imaging of deep and complex gas reservoirs using borehole seismology is currently frustrated by the lack of the acquisition technology necessary to record the large volumes of the high frequency, high signal-to-noise-ratio borehole seismic data needed to do 3D imaging. This project takes direct aim at this shortcoming by developing a 400 level 3C clamped downhole seismic receiver array, and accompanying software, for borehole seismic 3D imaging. This large borehole seismic array will remove the technical acquisition barrier for recording the necessary volumes of data to do high resolution 3D VSP or 3D cross well seismic imaging. Massive 3D VSP{reg_sign} and long range Cross-Well Seismology (CWS) are two of the borehole seismic techniques that will allow the Gas industry to take the next step in their quest for higher resolution images of the gas reservoirs for the purpose of improving the recovery of the natural gas resources. Today only a fraction of the original Oil or Gas in place is produced when reservoirs are considered depleted. This is primarily due to our lack of understanding of the detailed compartmentalization of the oil and gas reservoirs. The 400 level 3C borehole seismic receiver array will allow for the economic use of 3D borehole seismic imaging for reservoir characterization and monitoring by allowing the economic recording of the required large data volumes that have a sufficiently dense spatial sampling. By using 3C surface seismic or 3C borehole seismic sources the 400 level receiver arrays will furthermore allow 3D reservoir imaging using 9C data. The 9C borehole seismic data will provide P, SH and SV information for imaging of the complex deep gas reservoirs and allow quantitative prediction of the rock and the fluid types. The data quality and the data volumes from a 400 level 3C array will allow us to develop the data processing technology necessary for high resolution reservoir imaging.

  4. DEVELOPMENT OF A 400 LEVEL 3C CLAMPED DOWNHOLE SEISMIC RECEIVER ARRAY FOR 3D BOREHOLE SEISMIC IMAGING OF GAS RESERVOIRS

    SciTech Connect

    Bjorn N.P. Paulsson

    2004-05-01

    Borehole seismology is the highest resolution geophysical imaging technique available today to the oil and gas industry for characterization and monitoring of oil and gas reservoirs. However, the industry's ability to economically do high resolution 3D imaging of deep and complex gas reservoirs using borehole seismology is currently frustrated by the lack of the acquisition technology necessary to record the large volumes of the high frequency, high signal-to-noise-ratio borehole seismic data needed to do 3D imaging. This project takes direct aim at this shortcoming by developing a 400 level 3C clamped downhole seismic receiver array, and accompanying software, for borehole seismic 3D imaging. This large borehole seismic array will remove the technical acquisition barrier for recording the necessary volumes of data to do high resolution 3D VSP or 3D cross well seismic imaging. 3D VSP and long range Cross-Well Seismology (CWS) are two of the borehole seismic techniques that will allow the Gas industry to take the next step in their quest for higher resolution images of the gas reservoirs for the purpose of improving the recovery of the natural gas resources. Today only a fraction of the original Oil or Gas in place is produced when reservoirs are considered depleted. This is primarily due to our lack of understanding of the detailed compartmentalization of the oil and gas reservoirs. The 400 level 3C borehole seismic receiver array will allow for the economic use of 3D borehole seismic imaging for reservoir characterization and monitoring by allowing the economic recording of the required large data volumes that have a sufficiently dense spatial sampling. By using 3C surface seismic or 3C borehole seismic sources the 400 level receiver array will furthermore allow 3D reservoir imaging using 9C data. The 9C borehole seismic data will provide P, SH and SV information for imaging of the complex deep gas reservoirs and allow quantitative prediction of the rock and the fluid types. The data quality and the data volumes from a 400 level 3C array will allow us to develop the data processing technology necessary for high resolution reservoir imaging.

  5. Development of a 400 Level 3C Clamped Downhole Seismic Receiver Array for 3D Borehole Seismic Imaging of Gas Reservoirs

    SciTech Connect

    Bjorn N.P Paulsson

    2006-05-05

    Borehole seismology is the highest resolution geophysical imaging technique available today to the oil and gas industry for characterization and monitoring of oil and gas reservoirs. However, the industry's ability to economically do high resolution 3D imaging of deep and complex gas reservoirs using borehole seismology is currently hampered by the lack of the acquisition technology necessary to record the large volumes of the high frequency, high signal-to-noise-ratio borehole seismic data needed to do 3D imaging. This project takes direct aim at this shortcoming by developing a 400 level 3C clamped downhole seismic receiver array, and accompanying software, for borehole seismic 3D imaging. This large borehole seismic array will remove the technical acquisition barrier for recording the necessary volumes of data to do high resolution 3D VSP or 3D cross well seismic imaging. Massive 3D VSP{reg_sign} and long range Cross-Well Seismology (CWS) are two of the borehole seismic techniques that will allow the Gas industry to take the next step in their quest for higher resolution images of the gas reservoirs for the purpose of improving the recovery of the natural gas resources. Today only a fraction of the original Oil or Gas in place is produced when reservoirs are considered depleted. This is primarily due to our lack of understanding of the detailed compartmentalization of the oil and gas reservoirs. The 400 level 3C borehole seismic receiver array will allow for the economic use of 3D borehole seismic imaging for reservoir characterization and monitoring by allowing the economic recording of the required large data volumes that have a sufficiently dense spatial sampling. By using 3C surface seismic or 3C borehole seismic sources the 400 level receiver arrays will furthermore allow 3D reservoir imaging using 9C data. The 9C borehole seismic data will provide P, SH and SV information for imaging of the complex deep gas reservoirs and allow quantitative prediction of the rock and the fluid types. The data quality and the data volumes from a 400 level 3C array will allow us to develop the data processing technology necessary for high resolution reservoir imaging.

  6. Development of a 400 Level 3C Clamped Downhole Seismic Receiver Array for 3D Borehole Seismic Imaging of Gas Reservoirs

    SciTech Connect

    Bjorn N. P. Paulsson

    2005-09-30

    Borehole seismology is the highest resolution geophysical imaging technique available today to the oil and gas industry for characterization and monitoring of oil and gas reservoirs. However, the industry's ability to economically do high resolution 3D imaging of deep and complex gas reservoirs using borehole seismology is currently hampered by the lack of the acquisition technology necessary to record the large volumes of the high frequency, high signal-to-noise-ratio borehole seismic data needed to do 3D imaging. This project takes direct aim at this shortcoming by developing a 400 level 3C clamped downhole seismic receiver array, and accompanying software, for borehole seismic 3D imaging. This large borehole seismic array will remove the technical acquisition barrier for recording the necessary volumes of data to do high resolution 3D VSP or 3D cross well seismic imaging. Massive 3D VSP{reg_sign} and long range Cross-Well Seismology (CWS) are two of the borehole seismic techniques that will allow the Gas industry to take the next step in their quest for higher resolution images of the gas reservoirs for the purpose of improving the recovery of the natural gas resources. Today only a fraction of the original Oil or Gas in place is produced when reservoirs are considered depleted. This is primarily due to our lack of understanding of the detailed compartmentalization of the oil and gas reservoirs. The 400 level 3C borehole seismic receiver array will allow for the economic use of 3D borehole seismic imaging for reservoir characterization and monitoring by allowing the economic recording of the required large data volumes that have a sufficiently dense spatial sampling. By using 3C surface seismic or 3C borehole seismic sources the 400 level receiver arrays will furthermore allow 3D reservoir imaging using 9C data. The 9C borehole seismic data will provide P, SH and SV information for imaging of the complex deep gas reservoirs and allow quantitative prediction of the rock and the fluid types. The data quality and the data volumes from a 400 level 3C array will allow us to develop the data processing technology necessary for high resolution reservoir imaging.

  7. CHARACTERIZATION OF CONDITIONS OF NATURAL GAS STORAGE RESERVOIRS AND DESIGN AND DEMONSTRATION OF REMEDIAL TECHNIQUES FOR DAMAGE MECHANISMS FOUND THEREIN

    SciTech Connect

    J.H. Frantz; K.G. Brown

    2003-02-01

    There are four primary goals of contract DE-FG26-99FT40703: (1) We seek to better understand how and why a specific iron-related inorganic precipitant, siderite, occurs at the reservoir/wellbore interface in gas storage wells. (2) We plan on testing potential prevention and remediation strategies related to this damage mechanism in the laboratory. (3) We expect to demonstrate in the field, cost-effective prevention and remediation strategies that laboratory testing deems viable. (4) We will investigate new technology for the gas storage industry that will provide operators with a cost effective method to reduce non-darcy turbulent flow effects on flow rate. For the above damage mechanism, our research efforts will demonstrate the diagnostic technique for determining the damage mechanisms associated with lost deliverability as well as demonstrate and evaluate the remedial techniques in the laboratory setting and in actual gas storage reservoirs. We plan on accomplishing the above goals by performing extensive lab analyses of rotary sidewall cores taken from at least two wells, testing potential remediation strategies in the lab, and demonstrating in the field the applicability of the proposed remediation treatments. The benefits from this work will be quantified from this study and extrapolated to the entire storage industry. The technology and project results will be transferred to the industry through DOE dissemination and through the industry service companies that work on gas storage wells. Achieving these goals will enable the underground gas storage industry to more cost-effectively mitigate declining deliverability in their storage fields.

  8. Controls on early retention and late enhancement of microporosity in reefal gas reservoirs, offshore north Sumatra basin

    SciTech Connect

    Moshier, S.O.

    1989-03-01

    Chalky lime-matrix texture is pervasive in 300 m of coralgal and skeletal carbonates in the NSB-A (North Sumatra basin-A) gas field (lower-middle Miocene), offshore northern Sumatra. Much of the reservoir quality can be attributed to matrix with abundant intercrystalline, vuggy, and channel-form micropores. Matrix is composed of calcite microrhombs which are interpreted to have developed during stabilization of the precursor mud. On the same shelf, the smaller NSB-H oil field is composed of more than 45-m thick buildup of similar lithofacies which lack abundant microporosity. In both fields, early diagenesis included dissolution of aragonitic skeletal material, matrix neomorphism, and precipitation of nonluminescent calcite followed by zoned, luminescent calcite cements. Stable isotopes from matrix reflect a more open or water-dominated matrix diagenesis at NSB-H field. More active flushing of oversaturated, organically charged meteoric waters was responsible for thorough matrix cementation and microporosity occlusion at NSB-H field. Calcite cements show progressive enrichment of iron and manganese and depletion of magnesium and strontium during growth. The matrix at NSB-H field contains iron-rich dolomite. At A field, remnant matrix microporosity and intraparticle microporosity in calcitic skeletal material were greatly enhanced after all phases of cementation. Some pore-rimming cements are partially dissolved. At NSB-H field, late-phase dissolution is limited to the vicinity of open fractures where matrix-calcite and dolomite crystals are leached. Reservoir brines have a limey marine origin but are depleted in Ca and Mg relative to seawater, and carbon dioxide accounts for 31% of reservoir gas. If present brines are carbonate undersaturated, they may be substantially enhanced microporosity at NSB-A field. Late-stage dissolution is insignificant at NSB-H field due to the lack of early formed matrix microporosity.

  9. Dry Gas Zone, Elk Hills field, Kern County, California: General reservoir study: Engineering text and exhibits: (Final report)

    SciTech Connect

    Not Available

    1988-08-01

    The Dry Gas Zone in the Elk Hills field is comprised of fourteen separate productive horizons deposited in the MYA Group of the San Joaquin Formation of Pliocene Age. Eighty-six separate Reservoir Units have been identified within the interval over an area roughly ten miles long and four miles wide. One basal Tulare sand, the Tulare B, was also included in the geologic study. Five earlier studies have been made of the Dry Gas Zone; each is referenced in the Appendix of this report. Most of these studies were geologic in nature, and none provided in-depth reservoir analyses. This report is made up of ten (10) separate volumes which include: engineering text and exhibits (white dot); engineering data (black dot); geologic text and tables (green dot); structure and isochore maps (light blue dot); structural cross sections (dark blue dot); stratigraphic cross sections (brown dot); geologic data sheets -book 1 (yellow dot); geologic data sheets - book 2 (orange dot); geologic data sheets - book 3 (red dot); and geologic data sheets - book 4 (pink or coral dot). Basic production, injection, pressure, and other assorted technical data were provided by the US Department of Energy engineering staff at Elk Hills. These data were accepted as furnished with no attempt being made at independent verification.

  10. Sedimentologic and diagenetic controls on reservoir development at Rosevear gas field, Swan Hills Formation (upper Devonian), central Alberta

    SciTech Connect

    Kaufman, J.; Hanson, G.N.; Meyers, W.J.

    1988-02-01

    Carbonate strata at the Rosevear gas field consist of three major sedimentological packages: (1) basal platform, (2) platform reef, and (3) capping platform. Gas production is localized within two narrow trends of porous, massive, replacive dolostone occurring in the platform-reef sequence; tight limestones updip form the reservoir seal. Porosity trends are primarily restricted to the margins of a marine channel developed through the platform reef, but not the basal platform. Channel-margin strata consist mostly of dolomitized branching-stromatoporoid floatstones and rudstones. Massive replacive dolostone is composed of inclusion-rich coarsely crystalline nonferroan euhedral to anhedral rhombs that show a red cathodoluminescence. This dolomite has selectively replaced the limemud matrix; fossils were replaced to a much lesser extent. Fossils not dolomitized were selectively leached, resulting in well-developed biomoldic and vuggy porosity that forms the reservoir. Dolomitization occurred after cementation by clear, equant calcite and after early pressure solution. Secondary porosity in the dolostone trends was only partially reduced during later diagenesis, which consisted of, in order of decreasing age, precipitation of saddle dolomite, anhydrite, and coarsely crystalline calcite. Hydrocarbon migration occurred after the saddle dolomites, but before some late-stage calcite cement.

  11. Active microbial community in gas reservoirs in the North German Plain and the effects of high CO2 concentrations

    NASA Astrophysics Data System (ADS)

    Frerichs, Janin; Gniese, Claudia; Mühling, Martin; Krüger, Martin

    2010-05-01

    From the IPCC report on global warming, it is clear that large-scale solutions are needed immediately to reduce emissions of greenhouse gases. The CO2 capture and storage offers one option for reducing the greenhouse gas emissions. Favourable CO2 storage sites are depleted gas and oil fields and thus, are currently investigated by the BMBF-Geotechnologien RECOBIO-2 project. Our study is focussing on the direct influence of high CO2 concentrations on the autochthonous microbial population and environmental parameters (e.g. availability of nutrients). The gas fields Schneeren in the 'North German Plain' is operated by Gaz de France SUEZ E&V Deutschland GmbH. The conditions in the reservoir formation waters of two bore wells differ in various geochemical parameters (pH, salinity and temperature). In previous studies the community of this gas field was described by Ehinger et al. 2009. Based on these results our study included cultivation and molecular biological approaches. Our results showed significant differences of the community structure in regional distinctions of the gas reservoir. The activity profiles of two wells differed clearly in the inducible activity after substrate addition. The fluids of well A showed a high methane production rate after the addition of methanol or acetate. Well B showed a high sulphide production after the addition of sulphate and hydrogen. The molecular biological analysis of the original fluids supports the activity profile for both sites. The community analysis via real-time PCR showed for the production well head A a higher abundances for Archaea than for B. The community at site B in contrast was dominated by Bacteria. Fluids of both wells were also incubated with high CO2 concentrations in the headspace. These enrichments showed a significant decrease of methane and sulphide production with increasing CO2 levels. Currently, the community composition is analysed to identify changes connected to increased CO2 concentrations. This will provide information about possible biogeochemical and microbiological changes during and after the storage of CO2, and effects on the storage capacity and injectivity of the reservoir formation.

  12. Integral field spectroscopy of H-alpha emission in cooling flow cluster cores: disturbing the molecular gas reservoir

    E-print Network

    R. J. Wilman; A. C. Edge; A. M. Swinbank

    2006-06-13

    We present optical integral field spectroscopy of the H-alpha-luminous (>1E42 erg/s) central cluster galaxies in the cores of the cooling flows A1664, A1835, A2204 and Zw8193. From the [NII]+H-alpha complex we derive 2-D views of the distribution and kinematics of the emission line gas, and further diagnostics from the [SII] and [OI] lines. The H-alpha emission shows a variety of disturbed morphologies with velocity gradients and splittings of several hundred km/s on scales of 20 kpc or more. Despite the small sample size, there are some generic features. The most disturbed H-alpha emission appears to be associated with secondary galaxies within 10-20 kpc (projected) of the central galaxy and close in velocity to the H-alpha. The global H-alpha kinematics match those of CO(1-0) emission in single-dish data. The [NII]/H-alpha, [SII]/H-alpha and [OI]/H-alpha ratios vary little with position, local H-alpha surface brightness or between clusters. We propose that the H-alpha and CO emission arise in molecular clouds heated by a starburst which has been triggered by interaction with a secondary galaxy. Such CO emission is known to trace massive (>1E10 M_sun) compact (reservoirs of cool molecular gas, which an infalling galaxy may disturb, distorting the H-alpha morphology and initiating widespread star formation. We suggest that cloud-cloud collisions in the undisturbed molecular gas reservoir might be an important excitation source for the emission line gas in the cores of lower H-alpha luminosity cluster cores with less intense star formation (abridged).

  13. Inflow Performance Relationships (IPR) for Solution Gas Drive Reservoirs -- a Semi-Analytical Approach 

    E-print Network

    Nass, Maria A.

    2010-07-14

    . (1996) proposed a general polynomial form for the oil mobility function which in turn led to the following form for the IPR formulation: ... 1 3 3 2 21 max, ? ? ? ? ? ? ? ? ? ? ? ? ? ? ? ? ? ? ? ? ? ? ? ? ? ? ? ?? p p a p p a p p a q q wfwfwf o... o ....................................................................(1.15) Where the a 1 , a 2 , a 3 , ... a n coefficients are determined using the mobility function and its derivatives ? all taken at the average reservoir pressure ( p...

  14. Naturally fractured tight gas reservoir detection optimization. Quarterly report, October 1--December 31, 1994

    SciTech Connect

    1995-01-30

    This progress report covers the following tasks: Computational geochemistry (Indiana University Laboratory); and geologic assessment of the Piceance Basin. Computational geochemistry covers; three- dimensional basin simulator; stress solver; two-dimensional basin simulator; organic reactions and multi-phase flow; grid optimization; database calibration and data input; and Piceance Basin initial simulation. Sub-tasks under geologic assessment of the Piceance Basin include: structural analysis; reservoir characterization; stratigraphic interpretation; seismic interpretation; and remote sensing interpretation.

  15. Integrated Reservoir Characterization and Simulation Studies in Stripper Oil and Gas Fields 

    E-print Network

    Wang, Jianwei

    2010-01-14

    to increase recovery from stripper oil and gas fields. The primary objective of this research was to support optimized production of oil and gas from stripper well fields by evaluating one stripper gas field and one stripper oil field. For the stripper gas...

  16. Numerical Simulation and Multiple Realizations for Sensitivity Study of Shale Gas Reservoir

    E-print Network

    Mohaghegh, Shahab

    SPE 141058 Numerical Simulation and Multiple Realizations for Sensitivity Study of Shale Gas. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract Shale gas in the United States the largest conventional gas accumulations in the world. Shale gas success is directly the result

  17. Controls on reservoir quality in the giant Yacheng gas field, South China Sea

    SciTech Connect

    Bloch, S.; Atkinson, C.D. )

    1990-05-01

    Middle Tertiary sandstones from the giant Yacheng field, South China Sea were derived from a basement uplift and range in composition from lithic arkoses to feldspathic litharenites. The effect of chemical diagenesis on the framework composition is relatively limited, as suggested by the compositional similarity between uncemented samples and samples completely cemented by early calcite. Calcite cementation however, is not widespread. Reservoir quality and its distribution in the sandstones is primarily a function of textural and mineralogical parameters related to deposition in different types of paleoenvironments. The paleoenvironments range from basement regoliths and proximal fan-deltaic sediments deposited in lacustrine settings through increasingly more marine, tidally influenced distal fan-delta braided streams and estuarine channels, and eventually littoral beaches and offshore sublittoral bars. A petrologic classification was developed which relates rock composition to depositional environments which explains observed variations in reservoir quality. For a given burial history, there is an excellent correlation between permeability and porosity (dependent variables) and the following depositional facies-controlled, independent physical variables: grain size, sorting, and abundance of matrix and ductile grains. This correlation, in conjunction with a predictive facies distribution model, can be used to predict reservoir quality in future wells in the Yacheng field.

  18. TSR versus non-TSR processes and their impact on gas geochemistry and carbon stable isotopes in Carboniferous, Permian and Lower Triassic marine carbonate gas reservoirs in the Eastern Sichuan Basin, China

    NASA Astrophysics Data System (ADS)

    Liu, Q. Y.; Worden, R. H.; Jin, Z. J.; Liu, W. H.; Li, J.; Gao, B.; Zhang, D. W.; Hu, A. P.; Yang, C.

    2013-01-01

    The Palaeozoic and lowermost Mesozoic marine carbonate reservoirs of the Sichuan Basin in China contain variably sour and very dry gas. The source of the gas in the Carboniferous, Permian and Lower Triassic reservoirs is not known for certain and it has proved difficult to discriminate and differentiate the effects of thermal cracking- and TSR-related processes for these gases. Sixty-three gas samples were collected and analysed for their composition and carbon stable isotope values. The gases are all typically very dry (alkane gases being >97.5% methane), with low (<1%) nitrogen and highly variable H2S and CO2. Carboniferous gas is negligibly sour while the Lower Triassic gas tends to be most sour. The elevated H2S (up to 62%) is due to thermochemical sulphate reduction with the most sour Triassic and Permian reservoirs being deeper than 4800 m. The non-TSR affected Carboniferous gas is a secondary gas that was derived from the cracking of sapropelic kerogen-derived oil and primary gas and is highly mature. Carboniferous (and non-sour Triassic and Permian) gas has unusual carbon isotopes with methane and propane being isotopically heavier than ethane (a reversal of typical low- to moderate-maturity patterns). The gas in the non-sour Triassic and Permian reservoirs has the same geochemical and isotopic characteristics (and therefore the same source) as the Carboniferous gas. TSR in the deepest Triassic reservoirs altered the gas composition reaching 100% dryness in the deepest, most sour reservoirs showing that ethane and propane react faster than methane during TSR. Ethane evolves to heavier carbon isotope values than methane during TSR leading to removal of the reversed alkane gas isotope trend found in the Carboniferous and non-sour Triassic and Permian reservoirs. However, methane was directly involved in TSR as shown by the progressive increase in its carbon isotope ratio as gas souring proceeded. CO2 increased in concentration as gas souring proceeded, but typical CO2 carbon isotope ratios in sour gases remained about -4‰ V-PDB showing that it was not solely derived from the oxidation of alkanes. Instead CO2 may partly result from reaction of sour gas with carbonate reservoir minerals, such as Fe-rich dolomite or calcite, resulting in pyrite growth as well as CO2-generation.

  19. CHARACTERIZATION OF CONDITIONS OF NATURAL GAS STORAGE RESERVOIRS AND DESIGN AND DEMONSTRATION OF REMEDIAL TECHNIQUES FOR DAMAGE MECHANISMS FOUND THEREIN

    SciTech Connect

    J.H. Frantz; K.E. Brown

    2003-02-01

    There are four primary goals of contract DE-FG26-99FT40703: (1) We seek to better understand how and why two damage mechanisms--(1) inorganic precipitants, and (2) hydrocarbons and organic residues, occur at the reservoir/wellbore interface in gas storage wells. (2) We plan on testing potential prevention and remediation strategies related to these two damage mechanisms in the laboratory. (3) We expect to demonstrate in the field, cost-effective prevention and remediation strategies that laboratory testing deems viable. (4) We will investigate new technology for the gas storage industry that will provide operators with a cost effective method to reduce non-darcy turbulent flow effects on flow rate. For the above damage mechanisms, our research efforts will demonstrate the diagnostic technique for determining the damage mechanisms associated with lost deliverability as well as demonstrate and evaluate the remedial techniques in the laboratory setting and in actual gas storage reservoirs. We plan on accomplishing the above goals by performing extensive lab analyses of rotary sidewall cores taken from at least two wells, testing potential remediation strategies in the lab, and demonstrating in the field the applicability of the proposed remediation treatments. The benefits from this work will be quantified from this study and extrapolated to the entire storage industry. The technology and project results will be transferred to the industry through DOE dissemination and through the industry service companies that work on gas storage wells. Achieving these goals will enable the underground gas storage industry to more cost-effectively mitigate declining deliverability in their storage fields. Work completed to date includes the following: (1) Solicited potential participants from the gas storage industry; (2) Selected one participant experiencing damage from inorganic precipitates; (3) Developed laboratory testing procedures; (4) Collected cores from National Fuel Gas Summit No.1527 Well; (5) Analyzed cores from National Fuel Gas Summit No.1527 Well; (6) Began investigating methods to remove damage identified in Summit No.1527 cores; and (7) Began investigating methods to reduce non-darcy turbulent effects.

  20. Development of general inflow performance relationships (IPR`s) for slanted and horizontal wells producing heterogeneous solution-gas drive reservoirs

    SciTech Connect

    Cheng, A.M.

    1992-04-01

    Since 1968, the Vogel equation has been used extensively and successfully for analyzing the inflow performance relationship (IPR) of flowing vertical wells producing by solution-gas drive. Oil well productivity can be rapidly estimated by using the Vogel IPR curve and well outflow performance. With recent interests on horizontal well technology, several empirical IPRs for solution-gas drive horizontal and slanted wells have been developed under homogeneous reservoir conditions. This report presents the development of IPRs for horizontal and slanted wells by using a special vertical/horizontal/slanted well reservoir simulator under six different reservoir and well parameters: ratio of vertical to horizontal permeability, wellbore eccentricity, stratification, perforated length, formation thickness, and heterogeneous permeability. The pressure and gas saturation distributions around the wellbore are examined. The fundamental physical behavior of inflow performance for horizontal wells is described.

  1. The Influence of Local and Large-Scale Environment on Galaxy Gas Reservoirs in the RESOLVE Survey

    NASA Astrophysics Data System (ADS)

    Stark, David V.; Kannappan, Sheila; Baker, Ashley; Berlind, Andreas A.; Burchett, Joseph; Eckert, Kathleen D.; Florez, Jonathan; Hall, Kirsten; Haynes, Martha P.; Giovanelli, Riccardo; Gonzalez, Roberto; Guynn, David; Hoversten, Erik A.; Leroy, Adam K.; Moffett, Amanda J.; Pisano, Daniel J.; Watson, Linda C.; Wei, Lisa H.; Resolve Team

    2015-01-01

    There is growing evidence to suggest galaxy gas reservoirs have been replenished over time, but a clear picture of how this process depends on local and large-scale environment is still an active area of research. I will present an analysis of galaxy gas content with respect to environment using the ~90% complete 21cm census for the volume-limited RESOLVE survey, which yields an unbiased inventory of HI masses (or strong upper limits < 5-10% of the stellar mass) for ~1550 galaxies with baryonic mass greater than 109 M? in >50,000 cubic Mpc of the z=0 universe. We quantify large-scale environment via identification of cosmic web filaments and walls using a modified friends-of-friends technique, while also using photometric redshifts to identify additional potential companions around each galaxy. Combining this powerful data set with estimates of HI profile asymmetries and star formation histories, we examine whether there are local or large-scale environments where cold gas accretion is more effective. Specifically, we investigate whether galaxy interactions can induce enhanced HI content. We also explore whether galaxies residing in large-scale filaments or walls, where simulations show large-scale gas flows, display signatures of enhanced gas accretion relative to other large-scale environments. This project is supported by NSF funding for the RESOLVE survey (AST-0955368), the GBT Student Observing Support program, and a UNC Royster Society of Fellows Dissertation Completion Fellowship.

  2. Optimization of gas condensate Field A development on the basis of "reservoir - gathering facilities system" integrated model

    NASA Astrophysics Data System (ADS)

    Demidova, E. A.; Maksyutina, O. V.

    2015-02-01

    It is known that many gas condensate fields are challenged with liquid loading and condensate banking problems. Therefore, gas production is declining with time. In this paper hydraulic fracturing treatment was considered as a method to improve the productivity of wells and consequently to exclude the factors that lead to production decline. This paper presents the analysis of gas condensate Field A development optimization with the purpose of maintaining constant gas production at the 2013 level for 8 years taking into account mentioned factors . To optimize the development of the filed, an integrated model was created. The integrated model of the field implies constructing the uniform model of the field consisting of the coupling models of the reservoir, wells and surface facilities. This model allowed optimizing each of the elements of the model separately and also taking into account the mutual influence of these elements. Using the integrated model, five development scenarios were analyzed and an optimal scenario was chosen. The NPV of this scenario equals 7,277 mln RUR, cumulative gas production - 12,160.6 mln m3, cumulative condensate production - 1.8 mln tons.

  3. Exploratory Simulation Studies of Caprock Alteration Induced byStorage of CO2 in Depleted Gas Reservoirs

    SciTech Connect

    Gherardi, Fabrizio; Xu, Tianfu; Pruess, Karsten

    2005-11-23

    This report presents numerical simulations of isothermalreactive flows which might be induced in the caprock of an Italiandepleted gas reservoir by the geological sequestration of carbon dioxide.Our objective is to verify that CO2 geological disposal activitiesalready planned for the study area are safe and do not induce anyundesired environmental impact.Gas-water-rock interactions have beenmodelled under two different intial conditions, i.e., assuming that i)caprock is perfectly sealed, or ii) partially fractured. Field conditionsare better approximated in terms of the "sealed caprock model". Thefractured caprock model has been implemented because it permits toexplore the geochemical beahvior of the system under particularly severeconditions which are not currently encountered in the field, and then todelineate a sort of hypothetical maximum risk scenario.Major evidencessupporting the assumption of a sealed caprock stem from the fact that nogas leakages have been detected during the exploitation phase, subsequentreservoir repressurization due to the ingression of a lateral aquifer,and during several cycles of gas storage in the latest life of reservoirmanagement.An extensive program of multidisciplinary laboratory tests onrock properties, geochemical and microseismic monitoring, and reservoirsimulation studies is underway to better characterize the reservoir andcap-rock behavior before the performance of a planned CO2 sequestrationpilot test.In our models, fluid flow and mineral alteration are inducedin the caprock by penetration of high CO2 concentrations from theunderlying reservoir, i.e., it was assumed that large amounts of CO2 havebeen already injected at depth. The main focus is on the potential effectof these geochemical transformations on the sealing efficiency of caprockformations. Batch and multi-dimensional 1D and 2D modeling has been usedto investigate multicomponent geochemical processes. Our simulationsaccount for fracture-matrix interactions, gas phase participation inmultiphase fluid flow and geochemical reactions, and kinetics offluid-rock interactions.The main objectives of the modeling are torecognize the geochemical processes or parameters to which theadvancement of high CO2 concentrations in the caprock is most sensitive,and to describe the most relevant mineralogical transformations occurringin the caprock as a consequence of such CO2 storage in the underlyingreservoir. We also examine the feedback of these geochemical processes onphysical properties such as porosity, and evaluate how the sealingcapacity of the caprock evolves in time.

  4. Conference on the topic: {open_quotes}Exploration and production of petroleum and gas from chalk reservoirs worldwide{close_quotes}

    SciTech Connect

    Kuznetsov, V.G.

    1995-07-01

    More than 170 delegates from 14 countries in Europe, North America, Africa, and Asia took part in a conference on the topic: Exploration and Production of Petroleum and Gas from Chalk Reservoirs Worldwide. The conference was held in Copenhagen, Denmark in September,1994, and was a joint meeting of the American Association of Petroleum Geologists (AAPG), and the European Association of Petroleum Geoscientists and Engineers (EAPG). In addition to the opening remarks, 25 oral and nine poster reports were presented. The topics included chalk deposits as reservoir rocks, the occurrence of chalk deposits worldwide, the North Sea oil and gas fields, and other related topics.

  5. Pore Pressure prediction in shale gas reservoirs using neural network and fuzzy logic with an application to Barnett Shale.

    NASA Astrophysics Data System (ADS)

    Aliouane, Leila; Ouadfeul, Sid-Ali; Boudella, Amar

    2015-04-01

    The main goal of the proposed idea is to use the artificial intelligence such as the neural network and fuzzy logic to predict the pore pressure in shale gas reservoirs. Pore pressure is a very important parameter that will be used or estimation of effective stress. This last is used to resolve well-bore stability problems, failure plan identification from Mohr-Coulomb circle and sweet spots identification. Many models have been proposed to estimate the pore pressure from well-logs data; we can cite for example the equivalent depth model, the horizontal model for undercompaction called the Eaton's model…etc. All these models require a continuous measurement of the slowness of the primary wave, some thing that is not easy during well-logs data acquisition in shale gas formtions. Here, we suggest the use the fuzzy logic and the multilayer perceptron neural network to predict the pore pressure in two horizontal wells drilled in the lower Barnett shale formation. The first horizontal well is used for the training of the fuzzy set and the multilayer perecptron, the input is the natural gamma ray, the neutron porosity, the slowness of the compression and shear wave, however the desired output is the estimated pore pressure using Eaton's model. Data of another horizontal well are used for generalization. Obtained results clearly show the power of the fuzzy logic system than the multilayer perceptron neural network machine to predict the pore pressure in shale gas reservoirs. Keywords: artificial intelligence, fuzzy logic, pore pressure, multilayer perecptron, Barnett shale.

  6. Analysis of condensate banking dynamics in a gas condensate reservoir under different injection schemes 

    E-print Network

    Sandoval Rodriguez, Angelica Patricia

    2002-01-01

    ". This condensate banking significantly affects the well productivity since the gas relative permeability decreases. The formation of the condensate region near the wellbore can be prevented or delayed by gas injection since this reduces the loss of condensate...

  7. Nonassociated gas resources in low-permeability sandstone reservoirs, lower tertiary Wasatch Formation, and upper Cretaceous Mesaverde Group, Uinta Basin, Utah

    SciTech Connect

    Fouch, T.D.; Schmoker, J.W.; Boone, L.E.; Wandrey, C.J.; Crovelli, R.A.; Butler, W.C.

    1994-08-01

    The US Geological Survey recognizes six major plays for nonassociated gas in Tertiary and Upper Cretaceous low-permeability strata of the Uinta Basin, Utah. For purposes of this study, plays without gas/water contacts are separated from those with such contacts. Continuous-saturation accumulations are essentially single fields, so large in areal extent and so heterogeneous that their development cannot be properly modeled as field growth. Fields developed in gas-saturated plays are not restricted to structural or stratigraphic traps and they are developed in any structural position where permeability conduits occur such as that provided by natural open fractures. Other fields in the basin have gas/water contacts and the rocks are water-bearing away from structural culmination`s. The plays can be assigned to two groups. Group 1 plays are those in which gas/water contacts are rare to absent and the strata are gas saturated. Group 2 plays contain reservoirs in which both gas-saturated strata and rocks with gas/water contacts seem to coexist. Most units in the basin that have received a Federal Energy Regulatory Commission (FERC) designation as tight are in the main producing areas and are within Group 1 plays. Some rocks in Group 2 plays may not meet FERC requirements as tight reservoirs. However, we suggest that in the Uinta Basin that the extent of low-permeability rocks, and therefore resources, extends well beyond the limits of current FERC designated boundaries for tight reservoirs. Potential additions to gas reserves from gas-saturated tight reservoirs in the Tertiary Wasatch Formation and Cretaceous Mesaverde Group in the Uinta Basin, Utah is 10 TCF. If the potential additions to reserves in strata in which both gas-saturated and free water-bearing rocks exist are added to those of Group 1 plays, the volume is 13 TCF.

  8. Reservoir oil bubblepoint pressures revisited; solution gasoil ratios and surface gas specific gravities

    E-print Network

    Valkó, Peter

    , for bubblepoint pressure and other fluid properties, require use of stock-tank gas rate and specific gravity; Surface gas specific gravity; Non-parametric regression 1. Introduction A large number of correlations from observable field data is the issue of estimating stock-tank gas rate and specific gravity (shown

  9. Integrated seismic study of naturally fractured tight gas reservoirs. Technical progress report, April 1, 1993--June 31, 1993

    SciTech Connect

    Mavko, G.; Nur, A.

    1993-07-26

    This was the seventh quarter of the contract. During this quarter we (1) continued the large task of processing the seismic data, (2) collected additional geological information to aid in the interpretation, (3) tied the well log data to the seismic via generation of synthetic seismograms, (4) began integrating regional structural information and fracture trends with our observations of structure in the study area, (5) began constructing a velocity model for time-to-depth conversion and subsequent AVO and raytrace modeling experiments, and (6) completed formulation of some theoretical tools for relating fracture density to observed elastic anisotropy. The study area is located at the southern end of the Powder River Basin in Converse County in east-central Wyoming. It is a low permeability fractured site, with both gas and oil present. Reservoirs are highly compartmentalized due to the low permeabilities, and fractures provide the only practical drainage paths for production. The two formations of interest are: The Niobrara: a fractured shale and limey shale to chalk, which is a reservoir rock, but also its own source rock. The Frontier: a tight sandstone lying directly below the Niobrara, brought into contact with it by an unconformity. A basemap is presented with the seismic lines being analyzed for this project plus locations of 13 wells that we are using to supplement the analysis. The arrows point to two wells for which we have constructed synthetic seismograms.

  10. Using Carbon Dioxide to Enhance Recovery of Methane from Gas Hydrate Reservoirs: Final Summary Report

    SciTech Connect

    McGrail, B. Peter; Schaef, Herbert T.; White, Mark D.; Zhu, Tao; Kulkarni, Abhijeet S.; Hunter, Robert B.; Patil, Shirish L.; Owen, Antionette T.; Martin, P F.

    2007-09-01

    Carbon dioxide sequestration coupled with hydrocarbon resource recovery is often economically attractive. Use of CO2 for enhanced recovery of oil, conventional natural gas, and coal-bed methane are in various stages of common practice. In this report, we discuss a new technique utilizing CO2 for enhanced recovery of an unconventional but potentially very important source of natural gas, gas hydrate. We have focused our attention on the Alaska North Slope where approximately 640 Tcf of natural gas reserves in the form of gas hydrate have been identified. Alaska is also unique in that potential future CO2 sources are nearby, and petroleum infrastructure exists or is being planned that could bring the produced gas to market or for use locally. The EGHR (Enhanced Gas Hydrate Recovery) concept takes advantage of the physical and thermodynamic properties of mixtures in the H2O-CO2 system combined with controlled multiphase flow, heat, and mass transport processes in hydrate-bearing porous media. A chemical-free method is used to deliver a LCO2-Lw microemulsion into the gas hydrate bearing porous medium. The microemulsion is injected at a temperature higher than the stability point of methane hydrate, which upon contacting the methane hydrate decomposes its crystalline lattice and releases the enclathrated gas. Small scale column experiments show injection of the emulsion into a CH4 hydrate rich sand results in the release of CH4 gas and the formation of CO2 hydrate

  11. General screening criteria for shale gas reservoirs and production data analysis of Barnett shale 

    E-print Network

    Deshpande, Vaibhav Prakashrao

    2009-05-15

    to thank my parents and my siblings for their patience, love, and support. We all did this project together. I would like to take this opportunity to thank my friends Zuher, Dipin, Romil, Angad, Moses, Tushar and all my colleagues for helping me time... Gas Production Estimations for US Lower 48 and Non-Artic Canada (NPC4) ................ 3 5 Unconventional Gas Production History and Forecast...................................................... 4 6 Gas Shale Resource Pyramid for U.S. Lower...

  12. Numerical modeling of the simulated gas hydrate production test at Mallik 2L-38 in the pilot scale pressure reservoir LARS - Applying the "foamy oil" model

    NASA Astrophysics Data System (ADS)

    Abendroth, Sven; Thaler, Jan; Klump, Jens; Schicks, Judith; Uddin, Mafiz

    2014-05-01

    In the context of the German joint project SUGAR (Submarine Gas Hydrate Reservoirs: exploration, extraction and transport) we conducted a series of experiments in the LArge Reservoir Simulator (LARS) at the German Research Centre of Geosciences Potsdam. These experiments allow us to investigate the formation and dissociation of hydrates at large scale laboratory conditions. We performed an experiment similar to the field-test conditions of the production test in the Mallik gas hydrate field (Mallik 2L-38) in the Beaufort Mackenzie Delta of the Canadian Arctic. The aim of this experiment was to study the transport behavior of fluids in gas hydrate reservoirs during depressurization (see also Heeschen et al. and Priegnitz et al., this volume). The experimental results from LARS are used to provide details about processes inside the pressure vessel, to validate the models through history matching, and to feed back into the design of future experiments. In experiments in LARS the amount of methane produced from gas hydrates was much lower than expected. Previously published models predict a methane production rate higher than the one observed in experiments and field studies (Uddin et al. 2010; Wright et al. 2011). The authors of the aforementioned studies point out that the current modeling approach overestimates the gas production rate when modeling gas production by depressurization. They suggest that trapping of gas bubbles inside the porous medium is responsible for the reduced gas production rate. They point out that this behavior of multi-phase flow is not well explained by a "residual oil" model, but rather resembles a "foamy oil" model. Our study applies Uddin's (2010) "foamy oil" model and combines it with history matches of our experiments in LARS. Our results indicate a better agreement between experimental and model results when using the "foamy oil" model instead of conventional models of gas flow in water. References Uddin M., Wright J.F. and Coombe D. (2010) - Numerical Study of gas evolution and transport behaviors in natural gas hydrate reservoirs; CSUG/SPE 137439. Wright J.F., Uddin M., Dallimore S.R. and Coombe D. (2011) - Mechanisms of gas evolution and transport in a producing gas hydrate reservoir: an unconventional basis for successful history matching of observed production flow data; International Conference on Gas Hydrates (ICGH 2011).

  13. A workflow for building and calibrating 3-D geomechanical models &ndash a case study for a gas reservoir in the North German Basin

    NASA Astrophysics Data System (ADS)

    Fischer, K.; Henk, A.

    2013-10-01

    The optimal use of conventional and unconventional hydrocarbon reservoirs depends, amongst other things, on the local tectonic stress field. For example, wellbore stability, orientation of hydraulically induced fractures and - especially in fractured reservoirs - permeability anisotropies are controlled by the present-day in situ stresses. Faults and lithological changes can lead to stress perturbations and produce local stresses that can significantly deviate from the regional stress field. Geomechanical reservoir models aim for a robust, ideally "pre-drilling" prediction of the local variations in stress magnitude and orientation. This requires a numerical modelling approach that is capable to incorporate the specific geometry and mechanical properties of the subsurface reservoir. The workflow presented in this paper can be used to build 3-D geomechanical models based on the finite element (FE) method and ranging from field-scale models to smaller, detailed submodels of individual fault blocks. The approach is successfully applied to an intensively faulted gas reservoir in the North German Basin. The in situ stresses predicted by the geomechanical FE model were calibrated against stress data actually observed, e.g. borehole breakouts and extended leak-off tests. Such a validated model can provide insights into the stress perturbations in the inter-well space and undrilled parts of the reservoir. In addition, the tendency of the existing fault network to slip or dilate in the present-day stress regime can be addressed.

  14. Development of a 400 Level 3C Clamped Downhole Seismic Receiver Array for 3D Borehole Seismic Imaging of Gas Reservoirs

    SciTech Connect

    Bjorn N. P. Paulsson

    2006-09-30

    Borehole seismology is the highest resolution geophysical imaging technique available today to the oil and gas industry for characterization and monitoring of oil and gas reservoirs. However, the industry's ability to perform high resolution 3D imaging of deep and complex gas reservoirs using borehole seismology has been hampered by the lack of acquisition technology necessary to record large volumes of high frequency, high signal-to-noise-ratio borehole seismic data. This project took aim at this shortcoming by developing a 400 level 3C clamped downhole seismic receiver array, and accompanying software, for borehole seismic 3D imaging. This large borehole seismic array has removed the technical acquisition barrier for recording the data volumes necessary to do high resolution 3D VSP and 3D cross-well seismic imaging. Massive 3D VSP{reg_sign} and long range Cross-Well Seismology (CWS) are two of the borehole seismic techniques that promise to take the gas industry to the next level in their quest for higher resolution images of deep and complex oil and gas reservoirs. Today only a fraction of the oil or gas in place is produced when reservoirs are considered depleted. This is primarily due to our lack of understanding of detailed compartmentalization of oil and gas reservoirs. In this project, we developed a 400 level 3C borehole seismic receiver array that allows for economic use of 3D borehole seismic imaging for reservoir characterization and monitoring. This new array has significantly increased the efficiency of recording large data volumes at sufficiently dense spatial sampling to resolve reservoir complexities. The receiver pods have been fabricated and tested to withstand high temperature (200 C/400 F) and high pressure (25,000 psi), so that they can operate in wells up to 7,620 meters (25,000 feet) deep. The receiver array is deployed on standard production or drill tubing. In combination with 3C surface seismic or 3C borehole seismic sources, the 400 level receiver array can be used to obtain 3D 9C data. These 9C borehole seismic data provide both compressional wave and shear wave information that can be used for quantitative prediction of rock and pore fluid types. The 400-level borehole receiver array has been deployed successfully in a number of oil and gas wells during the course of this project, and each survey has resulted in marked improvements in imaging of geologic features that are critical for oil or gas production but were previously considered to be below the limits of seismic resolution. This added level of reservoir detail has resulted in improved well placement in the oil and gas fields that have been drilled using the Massive 3D VSP{reg_sign} images. In the future, the 400-level downhole seismic receiver array is expected to continue to improve reservoir characterization and drilling success in deep and complex oil and gas reservoirs.

  15. Radionuclide Migration at the Rio Blanco Site, A Nuclear-stimulated Low-permeability Natural Gas Reservoir

    SciTech Connect

    Clay A. Cooper; Ming Ye; Jenny Chapman; Craig Shirley

    2005-10-01

    The U.S. Department of Energy and its predecessor agencies conducted a program in the 1960s and 1970s that evaluated technology for the nuclear stimulation of low-permeability gas reservoirs. The third and final project in the program, Project Rio Blanco, was conducted in Rio Blanco County, in northwestern Colorado. In this experiment, three 33-kiloton nuclear explosives were simultaneously detonated in a single emplacement well in the Mesaverde Group and Fort Union Formation, at depths of 1,780, 1,899, and 2,039 m below land surface on May 17, 1973. The objective of this work is to estimate lateral distances that tritium released from the detonations may have traveled in the subsurface and evaluate the possible effect of postulated natural-gas development on radionuclide migration. Other radionuclides were considered in the analysis, but the majority occur in relatively immobile forms (such as nuclear melt glass). Of the radionuclides present in the gas phase, tritium dominates in terms of quantity of radioactivity in the long term and contribution to possible whole body exposure. One simulation is performed for {sup 85}Kr, the second most abundant gaseous radionuclide produced after tritium.

  16. Effect of flue gas impurities on the process of injection and storage of carbon dioxide in depleted gas reservoirs 

    E-print Network

    Nogueira de Mago, Marjorie Carolina

    2005-11-01

    and water removed) with 99.433 mole% CO2 (Gas B). The main results of this study are as follows. First, the dispersion coefficient increases with concentration of ??impurities??. Gas A exhibits the largest dispersion coefficients, 0.18-0.25 cm2/min, compared...

  17. Anisotropic Velocities of Gas Hydrate-Bearing Sediments in Fractured Reservoirs

    USGS Publications Warehouse

    Lee, Myung W.

    2009-01-01

    During the Indian National Gas Hydrate Program Expedition 01 (NGHP-01), one of the richest marine gas hydrate accumulations was discovered at drill site NGHP-01-10 in the Krishna-Godavari Basin, offshore of southeast India. The occurrence of concentrated gas hydrate at this site is primarily controlled by the presence of fractures. Gas hydrate saturations estimated from P- and S-wave velocities, assuming that gas hydrate-bearing sediments (GHBS) are isotropic, are much higher than those estimated from the pressure cores. To reconcile this difference, an anisotropic GHBS model is developed and applied to estimate gas hydrate saturations. Gas hydrate saturations estimated from the P-wave velocities, assuming high-angle fractures, agree well with saturations estimated from the cores. An anisotropic GHBS model assuming two-component laminated media - one component is fracture filled with 100-percent gas hydrate, and the other component is the isotropic water-saturated sediment - adequately predicts anisotropic velocities at the research site.

  18. Method for identifying subsurface fluid migration and drainage pathways in and among oil and gas reservoirs using 3-D and 4-D seismic imaging

    DOEpatents

    Anderson, R.N.; Boulanger, A.; Bagdonas, E.P.; Xu, L.; He, W.

    1996-12-17

    The invention utilizes 3-D and 4-D seismic surveys as a means of deriving information useful in petroleum exploration and reservoir management. The methods use both single seismic surveys (3-D) and multiple seismic surveys separated in time (4-D) of a region of interest to determine large scale migration pathways within sedimentary basins, and fine scale drainage structure and oil-water-gas regions within individual petroleum producing reservoirs. Such structure is identified using pattern recognition tools which define the regions of interest. The 4-D seismic data sets may be used for data completion for large scale structure where time intervals between surveys do not allow for dynamic evolution. The 4-D seismic data sets also may be used to find variations over time of small scale structure within individual reservoirs which may be used to identify petroleum drainage pathways, oil-water-gas regions and, hence, attractive drilling targets. After spatial orientation, and amplitude and frequency matching of the multiple seismic data sets, High Amplitude Event (HAE) regions consistent with the presence of petroleum are identified using seismic attribute analysis. High Amplitude Regions are grown and interconnected to establish plumbing networks on the large scale and reservoir structure on the small scale. Small scale variations over time between seismic surveys within individual reservoirs are identified and used to identify drainage patterns and bypassed petroleum to be recovered. The location of such drainage patterns and bypassed petroleum may be used to site wells. 22 figs.

  19. Method for identifying subsurface fluid migration and drainage pathways in and among oil and gas reservoirs using 3-D and 4-D seismic imaging

    DOEpatents

    Anderson, Roger N. (New York, NY); Boulanger, Albert (New York, NY); Bagdonas, Edward P. (Brookline, MA); Xu, Liqing (New Milford, NJ); He, Wei (New Milford, NJ)

    1996-01-01

    The invention utilizes 3-D and 4-D seismic surveys as a means of deriving information useful in petroleum exploration and reservoir management. The methods use both single seismic surveys (3-D) and multiple seismic surveys separated in time (4-D) of a region of interest to determine large scale migration pathways within sedimentary basins, and fine scale drainage structure and oil-water-gas regions within individual petroleum producing reservoirs. Such structure is identified using pattern recognition tools which define the regions of interest. The 4-D seismic data sets may be used for data completion for large scale structure where time intervals between surveys do not allow for dynamic evolution. The 4-D seismic data sets also may be used to find variations over time of small scale structure within individual reservoirs which may be used to identify petroleum drainage pathways, oil-water-gas regions and, hence, attractive drilling targets. After spatial orientation, and amplitude and frequency matching of the multiple seismic data sets, High Amplitude Event (HAE) regions consistent with the presence of petroleum are identified using seismic attribute analysis. High Amplitude Regions are grown and interconnected to establish plumbing networks on the large scale and reservoir structure on the small scale. Small scale variations over time between seismic surveys within individual reservoirs are identified and used to identify drainage patterns and bypassed petroleum to be recovered. The location of such drainage patterns and bypassed petroleum may be used to site wells.

  20. Modeling of fault reactivation and induced seismicity during hydraulic fracturing of shale-gas reservoirs

    EPA Science Inventory

    We have conducted numerical simulation studies to assess the potential for injection-induced fault reactivation and notable seismic events associated with shale-gas hydraulic fracturing operations. The modeling is generally tuned toward conditions usually encountered in the Marce...

  1. Optimal Process Design for Coupled CO2 Sequestration and Enhanced Gas Recovery in Carbonate Reservoirs 

    E-print Network

    Odi, Uchenna

    2013-12-09

    Increasing energy demand combined with public concern for the environment obligates the oil industry to supply oil and natural gas to the public while minimizing the carbon footprint due to its activities. Today, fossil ...

  2. Reservoir-Wellbore Coupled Simulation of Liquid Loaded Gas Well Performance 

    E-print Network

    Riza, Muhammad Feldy

    2013-11-12

    Liquid loading of gas wells causes production difficulty and reduces ultimate recovery from these wells. In 1969, Turner proposed that existence of annular two-phase flow at the wellhead is necessary for the well to avoid liquid loading...

  3. Laboratory analysis of gas hydrate cores for evaluation of reservoir conditions. Final report

    SciTech Connect

    Holder, G.D.

    1984-06-01

    Methodology and procedures for the study of hydrate cores are detailed. Topics discussed are the (1) equipment and procedures for the formation and evaluation of hydrate cores in the laboratory, (2) the thermodynamic properties of gas hydrates, (3) the enthalpy of hydrate dissociation, (4) conditions in the earth where hydrates can form, (5) kinetics of hydrate formation and dissociation, and (6) heat transfer to gas hydrates. Empirical correlations for these properties and kinetic behavior are given. 24 references, 39 figures, 10 tables.

  4. Rate and State Frictional Properties of Shale Gas Reservoir Rocks and FIB/SEM Microscopy of Lab-Generated Fault Surfaces

    NASA Astrophysics Data System (ADS)

    Kohli, A. H.; Zoback, M. D.

    2011-12-01

    To investigate the slip behavior of natural faults in shale gas reservoirs under the conditions of hydraulic stimulation, we conduct laboratory investigations of the frictional and hydrologic properties of shale gas reservoir rocks. We report on several initial studies of the frictional properties of cores from the Haynesville and Eagleford shale reservoirs, performed under dry and wet conditions and in-situ confining and pore pressures. The results of velocity-stepping experiments show strongly velocity-strengthening frictional behavior at sliding velocities ranging from 0.1 - 100 ?m/s and sliding displacements of up to 5 mm. Focused ion beam and scanning electron microscopy of the fault sliding surfaces from these experiments reveals slickenside lineations in the direction of fault slip and significant production of sub-micron clay gouge. In addition, fault surface damage is visible in the form of bedding-parallel, micron scale cracks, which form at pre-existing pores in the intact shale matrix, suggesting a mechanism for permeability enhancement during slow slip. These results are evaluated in terms of rate-and-state constitutive models for frictional stability to develop a physical model for induced slip by hydraulic stimulation in shale gas reservoirs.

  5. Using horizontal well technology for enhanced recovery in very mature, depletion drive gas reservoirs - Pirkle No. 2 well, a case history, carthage (Lower Pettit) field, Panola County, Texas

    SciTech Connect

    McCoy, A.W.; Davis, F.A.; Elrod, J.P.; Rhodes, S.L. Jr.; Singh, S.P.

    1996-12-31

    Horizontal well technology has been successfully applied to exploit reservoirs involving thin beds, low permeability zones, naturally fractured reservoirs, high-cost areas, and zones of water coning. The Pirkle No. 2 well represents the first use of horizontal technology to enhance ultimate gas recovery in a very mature, low pressure zone in the Lower Pettit horizon at Carthage Field, Panola County, Texas. The Pirkle No. 2 well was drilled to test the concept that a horizontal well could enhance ultimate recovery by lowering the final abandonment pressure in a very mature, depletion drive gas reservoir. However, numerous technical obstacles existed to the successful drilling and completion of an economic well in a 0.0308 psi/ft pressure gradient environment. This paper outlines the steps taken by OXY team members in planning and executing the project, as well as the results achieved from the Pirkle No. 2 well. Information gained from this project will help others to define appropriate screening criteria and provide dance for planning/application of horizontal technology to guide other mature gas reservoirs worldwide.

  6. Increasing Production from Low-Permeability Gas Reservoirs by Optimizing Zone Isolation for Successful Stimulation Treatments

    SciTech Connect

    Fred Sabins

    2005-03-31

    Maximizing production from wells drilled in low-permeability reservoirs, such as the Barnett Shale, is determined by cementing, stimulation, and production techniques employed. Studies show that cementing can be effective in terms of improving fracture effectiveness by 'focusing' the frac in the desired zone and improving penetration. Additionally, a method is presented for determining the required properties of the set cement at various places in the well, with the surprising result that uphole cement properties in wells destined for multiple-zone fracturing is more critical than those applied to downhole zones. Stimulation studies show that measuring pressure profiles and response during Pre-Frac Injection Test procedures prior to the frac job are critical in determining if a frac is indicated at all, as well as the type and size of the frac job. This result is contrary to current industry practice, in which frac jobs are designed well before the execution, and carried out as designed on location. Finally, studies show that most wells in the Barnett Shale are production limited by liquid invasion into the wellbore, and determinants are presented for when rod or downhole pumps are indicated.

  7. Efficiency analysis of greenhouse gas sequestration during miscible CO2 injection in fractured oil reservoirs.

    PubMed

    Trivedi, Japan; Babadagli, Tayfun

    2008-08-01

    During CO2 injection into naturally fractured oil reservoirs for enhanced oil recovery, the great portion of oil is recovered by matrix-fracture interaction. Diffusive mass transfer between matrix and fracture controls this process if CO2 is miscible with matrix oil. Oil expelled from matrix is replaced by CO2, and the matrix could be potentially a good storage medium for the long-term. For the cooptimization of the oil recovery and CO2 storage, i.e., maximizing the oil recovery while maximizing the amount of CO2 stored, we propose an efficiency analysis using a dimensionless term defined as the global effectiveness factor. The Biot number and Thiele modulus were incorporated in the development of the global effectiveness factor. Diffusion coefficients and the rate of mass-transfer constants were obtained from our previous finite element modeling study. We first defined and derived the dimensionless groups to be used in the efficiency analysis and then formulated a relationship between the dimensionless groups and the efficiency indicators, i.e., the ratios of total solute (oil) produced to total solvent injected and total solvent stored to total solvent injected. It was shown that the efficiency of the process can be represented by a dimensionless group that consists of well-known dimensionless numbers such as the Reynolds number, the Peclet number, the Sherwood number, and the global effectiveness factor. PMID:18754463

  8. ALMA Probes the Molecular Gas Reservoirs in the Changing-Look Seyfert Galaxy Mrk 590

    E-print Network

    Koay, J Y; Casasola, V; Lawther, D; Peterson, B M

    2015-01-01

    We investigate if the active galactic nucleus (AGN) of Mrk 590, whose supermassive black hole was until recently highly accreting, is turning off due to a lack of central gas to fuel it. We analyse new sub-arcsecond resolution ALMA maps of the $^{12}$CO(3-2) line and 344 GHz continuum emission in Mrk 590. We detect no $^{12}$CO(3-2) emission in the inner 150 pc, constraining the central molecular gas mass to $M({\\rm H_2}) \\lesssim 1.6 \\times 10^5\\, {M_{\\odot}}$, no more than a typical giant molecular gas cloud. However, there is still potentially enough gas to fuel the black hole for another $2.6 \\times 10^5$ years assuming Eddington-limited accretion. We therefore cannot rule out that the AGN may just be experiencing a temporary feeding break, and may turn on again in the near future. We discover a ring-like structure at a radius of $\\sim 1$ kpc, where a gas clump exhibiting disturbed kinematics and located just $\\sim 200$ pc west of the AGN, may be refueling the centre. Mrk 590 does not have significantly l...

  9. Ordovician carbonate buildups: Potential gas reservoirs in the Ordos basin, central China

    SciTech Connect

    Huaida Hsu )

    1991-03-01

    The Ordos basin of central China covers an area of about 25,000 km{sup 2}. A series of eastward moving overthrusts developed along its western flank, but most of the basin consists of a stable slope that dips westward less than one degree. The basin contains sediments from Sinian to Middle Ordovician and from the Middle Carboniferous to Cretaceous. Its evolutionary history is similar to that of the Alberta basin. Recently drilled wildcat wells have produced commercial gas flows that are closely associated with Ordovician carbonate buildups and a weathered surface between the Ordovician and Carboniferous. Most of the buildups consist of agal mounds; however, some Middle Ordovician reefs developed in the western portion and along the southern margin of the Ordos basin. More than 200 buildups were delineated using seismic stratigraphic techniques. They can be divided into four distinct types. The growth and distribution of buildups were controlled by sea-level fluctuations. The interpretations made in this study were based on the integration of results from a variety of analyses including vertical profiling, differential interformational velocity analysis, amplitude versus offset comparisons, G-log analysis, seismic modeling techniques, and high-precision gravity surveys. The best gas prospects are the Ordovician carbonate buildups distributed around the basin's central uplift. The delineation of carbonate buildups and the demonstration that they are associated with commercial gas flows open the gate for future gas exploration in this area.

  10. Application of geo-microbial prospecting method for finding oil and gas reservoirs

    NASA Astrophysics Data System (ADS)

    Rasheed, M. A.; Hasan, Syed Zaheer; Rao, P. L. Srinivasa; Boruah, Annapurna; Sudarshan, V.; Kumar, B.; Harinarayana, T.

    2015-03-01

    Microbial prospecting of hydrocarbons is based on the detection of anomalous population of hydrocarbon oxidizing bacteria in the surface soils, indicates the presence of subsurface oil and gas accumulation. The technique is based on the seepage of light hydrocarbon gases such as C1-C4 from the oil and gas pools to the shallow surface that provide the suitable conditions for the development of highly specialized bacterial population. These bacteria utilize hydrocarbon gases as their only food source and are found enriched in the near surface soils above the hydrocarbon bearing structures. The methodology involves the collection of soil samples from the survey area, packing, preservation and storage of samples in pre-sterilized sample bags under aseptic and cold conditions till analysis and isolation and enumeration of hydrocarbon utilizing bacteria such as methane, ethane, propane, and butane oxidizers. The contour maps for the population density of hydrocarbon oxidizing bacteria are drawn and the data can be integrated with geological, geochemical, geophysical methods to evaluate the hydrocarbon prospect of an area and to prioritize the drilling locations thereby reducing the drilling risks and achieve higher success in petroleum exploration. Microbial Prospecting for Oil and Gas (MPOG) method success rate has been reported to be 90%. The paper presents details of microbial prospecting for oil and gas studies, excellent methodology, future development trends, scope, results of study area, case studies and advantages.

  11. Gas reservoir of a hyper-luminous quasar at z = 2.6

    NASA Astrophysics Data System (ADS)

    Feruglio, C.; Bongiorno, A.; Fiore, F.; Krips, M.; Brusa, M.; Daddi, E.; Gavignaud, I.; Maiolino, R.; Piconcelli, E.; Sargent, M.; Vignali, C.; Zappacosta, L.

    2014-05-01

    Context. Understanding the relationship between the formation and evolution of galaxies and their central super-massive black holes (SMBH) is one of the main topics in extragalactic astrophysics. Links and feedback may reciprocally affect both black hole and galaxy growth. Aims: Observations of the CO line at the main epoch of galaxy and SMBH assembly (z = 2-4) are crucial to investigating the gas mass, star formation, and accretion onto SMBHs, and the effect of AGN feedback. Potential correlations between AGN and host galaxy properties can be highlighted by observing extreme objects. Methods: We targeted CO(3-2) in ULAS J1539+0557, a hyper-luminous quasar (Lbol > 1048 erg/s) at z = 2.658, selected through its unusual red colour in the UKIDSS Large Area Survey (ULAS). Results: We find a molecular gas mass of 4.1 ± 0.8 × 1010 M?, by adopting a conversion factor ? = 0.8 M? K-1 km s-1 pc2, and a gas fraction of ~0.4-0.1, depending mostly on the assumed source inclination. We also find a robust lower limit to the star-formation rate (SFR = 250-1600 M?/yr) and star-formation efficiency (SFE = 25-350 L?/(K km s-1 pc2) by comparing the observed optical-near-infrared spectral energy distribution with AGN and galaxy templates. The black hole gas consumption timescale, M(H2) /?acc, is ~160 Myr, similar to or higher than the gas consumption timescale. Conclusions: The gas content and the star formation efficiency are similar to those of other high-luminosity, highly obscured quasars, and at the lower end of the star-formation efficiency of unobscured quasars, in line with predictions from AGN-galaxy co-evolutionary scenarios. Further measurements of the (sub)mm continuum in this and similar sources are mandatory to obtain a robust observational picture of the AGN evolutionary sequence. Based on observations carried out with the IRAM Plateau de Bure Interferometer. IRAM is supported by INSU/CNRS (France), MPG (Germany), and IGN (Spain).

  12. Estimating Effective Seismic Anisotropy Of Coal Seam Gas Reservoirs from Sonic Log Data Using Orthorhombic Buckus-style Upscaling

    NASA Astrophysics Data System (ADS)

    Gross, Lutz; Tyson, Stephen

    2015-04-01

    Fracture density and orientation are key parameters controlling productivity of coal seam gas reservoirs. Seismic anisotropy can help to identify and quantify fracture characteristics. In particular, wide offset and dense azimuthal coverage land seismic recordings offers the opportunity for recovery of anisotropy parameters. In many coal seam gas reservoirs (eg. Walloon Subgroup in the Surat Basin, Queensland, Australia (Esterle et al. 2013)) the thickness of coal-beds and interbeds (e.g mud-stone) are well below the seismic wave length (0.3-1m versus 5-15m). In these situations, the observed seismic anisotropy parameters represent effective elastic properties of the composite media formed of fractured, anisotropic coal and isotropic interbed. As a consequence observed seismic anisotropy cannot directly be linked to fracture characteristics but requires a more careful interpretation. In the paper we will discuss techniques to estimate effective seismic anisotropy parameters from well log data with the objective to improve the interpretation for the case of layered thin coal beds. In the first step we use sonic log data to reconstruct the elasticity parameters as function of depth (at the resolution of the sonic log). It is assumed that within a sample fractures are sparse, of the same size and orientation, penny-shaped and equally spaced. Following classical fracture model this can be modeled as an elastic horizontally transversely isotropic (HTI) media (Schoenberg & Sayers 1995). Under the additional assumption of dry fractures, normal and tangential fracture weakness is estimated from slow and fast shear wave velocities of the sonic log. In the second step we apply Backus-style upscaling to construct effective anisotropy parameters on an appropriate length scale. In order to honor the HTI anisotropy present at each layer we have developed a new extension of the classical Backus averaging for layered isotropic media (Backus 1962) . Our new method assumes layered HTI media with constant anisotropy orientation as recovered in the first step. It leads to an effective horizontal orthorhombic elastic model. From this model Thomsen-style anisotropy parameters are calculated to derive azimuth-dependent normal move out (NMO) velocities (see Grechka & Tsvankin 1998). In our presentation we will show results of our approach from sonic well logs in the Surat Basin to investigate the potential of reconstructing S-wave velocity anisotropy and fracture density from azimuth dependent NMO velocities profiles.

  13. Assessment of undiscovered oil and gas resources in sandstone reservoirs of the Cotton Valley Group, U.S. Gulf Coast, 2015

    USGS Publications Warehouse

    Eoff, Jennifer D.; Biewick, Laura R.H.; Brownfield, Michael E.; Burke, Lauri; Charpentier, Ronald R.; Dubiel, Russell F.; Gaswirth, Stephanie B.; Gianoutsos, Nicholas J.; Kinney, Scott A.; Klett, Timothy R.; Leathers, Heidi M.; Mercier, Tracey J.; Paxton, Stanley T.; Pearson, Ofori N.; Pitman, Janet K.; Schenk, Christopher J.; Tennyson, Marilyn E.; Whidden, Katherine J.

    2015-01-01

    Using a geology-based assessment methodology, the U.S. Geological Survey estimated undiscovered mean volumes of 14 million barrels of conventional oil, 430 billion cubic feet of conventional gas, 34,028 billion cubic feet of continuous gas, and a mean total of 391 million barrels of natural gas liquids in sandstone reservoirs of the Upper Jurassic–Lower Cretaceous Cotton Valley Group in onshore lands and State waters of the U.S. Gulf Coast region.

  14. Modeling of performance behavior in gas condensate reservoirs using a variable mobility concept 

    E-print Network

    Wilson, Benton Wade

    2004-09-30

    " in permeability at some radial distance away from the wellbore. Using our proposed solution we can visualize the effect of the varying gas permeability in time and radius (a suite of (dimensionless) radius and time format plots are provided). In short, we can... transform variable .......................................................................................................................... 9 2DDD r 2.1 Dimensionless pressure type curve for radial flow behavior including wellbore storage and skin...

  15. Fracture detection, mapping, and analysis of naturally fractured gas reservoirs using seismic technology

    SciTech Connect

    Hoekstra, P.; Lynn, H.

    1993-12-31

    There are a number of producing gas fields in the United States where production is controlled by natural fractures. The host rock may consist of low porosity, low permeability formations, and wells completed in the unfractured rock have low productivity. On the other hand, wells intercepting fractured rocks may show good production. The objective of the research under this contract is to improve the technology for detecting fractures by surface geophysical methods. This remote detection of fractures will allow optimum placement of vertical or horizontal wells. The critical components of the project are: (1) Selection of a gas field with known production from naturally occurring fractures. The project scope does not allow for drilling of wells, so that evidence for occurrence of fractures and gas production from fractures must be obtained from existing wells` field production history, and other data. (2) Acquisition of both surface and downhole seismic P-wave and S-wave data. The project will acquire one 9-component (9-C) VSP. In a 9-C VSP survey, seismic events are recorded by 3-C geophones from one P-wave, and two perpendicular oriented S-wave sources (SH and SV). Also, approximately 12 miles of 9-C surface seismic data will be acquired. (3) Processing and interpretation of 9-C VSP and 9-C surface seismic data, and correlating the seismic anomalies observed to all available geologic and production information to show how the variations in seismic response is related to fracture density, fracture orientation, lithology, structure, and production history.

  16. Geophysical investigations of the methane reservoir and gas escape mechanisms on the west Svalbard margin

    NASA Astrophysics Data System (ADS)

    Minshull, T. A.; Westbrook, G. K.; Sinha, M. C.; Weitemeyer, K. A.; Henstock, T.; Chabert, A.; Vardy, M. E.; Sarkar, S.; Goswami, B.; Marsset, B.; Ker, S.; Thomas, Y.; Best, A. I.; Rajan, A.

    2012-12-01

    In 2008, over 250 bubble plumes were discovered close to the landward limit of methane hydrate stability on the west Svalbard continental margin, and sampling of ocean water in the vicinity of some of these plumes showed anomalously high methane concentrations. Many of the plumes occur in the region over which the hydrate stability field has receded during the last three decades due to ocean warming and such thermal erosion of the hydrate stability field may provide a positive feedback effect in global climate change. The presence of hydrate beneath the seabed is evidenced by the presence of a widespread bottom-simulating reflector (BSR) on the lower continental slope and by direct sampling with cores. More limited plume activity was found in deeper water at pockmark features that reach several hundred metres in diameter. During cruises in 2011 and 2012, we conducted further geophysical surveys both in the region of hydrate stability field recession on the continental slope and over a large pockmark on the nearby Vestnesa Ridge sediment drift. We conducted high-resolution seismic reflection surveys using a 90 cu. in. GI gun source and a 60-m, 60-channel hydrophone streamer, and deep-towed seismic surveys using Ifremer's SYSIF vehicle and chirp sources with 220-1050 Hz and 580-2200 Hz sweeps. We recorded both the GI-gun and the lower-frequency Chirp sources on ocean bottom seismometers to determine the velocity structure with high vertical resolution at both sites. We obtained controlled source electromagnetic (CSEM) data from both sites using a deep-towed frequency domain electromagnetic source recorded at 14 seafloor receivers with orthogonal electrodes and a towed three-component electric field receiver. At the slope site, our CSEM profile extends into deep water where a BSR is present. High-resolution and Chirp seismic reflection data show evidence for the widespread presence of subsurface gas at the slope site, both within and beneath the region of hydrate stability field recession. Here, numerous sub-vertical fractures provide conduits for gas transport to the ocean floor. Deeply sourced gas also appears to migrate along stratigraphic horizons. At some locations, gas appears to pond beneath a thin veneer of glacial and post-glacial sediments. At the Vestnesa pockmark site, strong scattering in Chirp images suggests the presence of localised pockets of subsurface gas within the hydrate stability field, and local increases in seismic velocity above the BSR provide evidence for a concentration of hydrate beneath the pockmark. We present initial results and interpretations from both cruises.

  17. Scientific Challenges of Producing Natural Gas from Organic-Rich Shales - From the Nano-Scale to the Reservoir Scale (Louis Néel Medal Lecture)

    NASA Astrophysics Data System (ADS)

    Zoback, Mark D.

    2013-04-01

    In this talk I will discuss several on-going research projects with the PhD students and post-Docs in my group that are investigating the wide variety of factors affecting the success of stimulating gas production from extremely low permeability organic-rich shales. First, I will present laboratory measurements of pore structure, adsorption and nano-scale fluid transport on samples of the Barnett, Eagle Ford, Haynesville, Marcellus and Horn River shale (all in North America). I will also discuss how these factors affect ultimate gas recovery. Second, I present several lines of evidence that indicate that during hydraulic fracturing stimulation of shale gas reservoirs there is pervasive slow slip occurring on pre-existing fractures and faults that are not detected by standard microseismic monitoring. I will also present laboratory and modeling studies that demonstrate why slowly slipping faults are to be expected. In many cases, slow slip on faults may be the most important process responsible for stimulating gas production in the reservoirs. Finally, I discuss our research on the viscoplastic behavior of the shales and what viscoplasticity implies for the evolution of the physical properties of the reservoir and in situ stress magnitudes.

  18. GAS RESERVOIRS AND STAR FORMATION IN A FORMING GALAXY CLUSTER AT zbsime0.2

    SciTech Connect

    Jaffe, Yara L.; Poggianti, Bianca M.; Verheijen, Marc A. W.; Deshev, Boris Z.; Van Gorkom, Jacqueline H.

    2012-09-10

    We present first results from the Blind Ultra-Deep H I Environmental Survey of the Westerbork Synthesis Radio Telescope. Our survey is the first direct imaging study of neutral atomic hydrogen gas in galaxies at a redshift where evolutionary processes begin to show. In this Letter we investigate star formation, H I content, and galaxy morphology, as a function of environment in Abell 2192 (at z = 0.1876). Using a three-dimensional visualization technique, we find that Abell 2192 is a cluster in the process of forming, with significant substructure in it. We distinguish four structures that are separated in redshift and/or space. The richest structure is the baby cluster itself, with a core of elliptical galaxies that coincides with (weak) X-ray emission, almost no H I detections, and suppressed star formation. Surrounding the cluster, we find a compact group where galaxies pre-process before falling into the cluster, and a scattered population of 'field-like' galaxies showing more star formation and H I detections. This cluster proves to be an excellent laboratory to understand the fate of the H I gas in the framework of galaxy evolution. We clearly see that the H I gas and the star formation correlate with morphology and environment at z {approx} 0.2. In particular, the fraction of H I detections is significantly affected by the environment. The effect starts to kick in in low-mass groups that pre-process the galaxies before they enter the cluster. Our results suggest that by the time the group galaxies fall into the cluster, they are already devoid of H I.

  19. The Impacts of Rock Composition and Properties on the Ability to Stimulate Production of Ultra-Low Permeability Oil and Gas Reservoirs Through Hydraulic Fracturing

    NASA Astrophysics Data System (ADS)

    Zoback, M. D.; Sone, H.; Kohli, A. H.; Heller, R. J.

    2014-12-01

    In this talk, we present the results of several research projects investigating how rock properties, natural fractures and the state of stress affect the success of hydraulic fracturing operations during stimulation of shale gas and tight oil reservoirs. First, through laboratory measurements on samples of the Barnett, Eagle Ford, Haynesville and Horn River shales, we discuss pore structure, adsorption and permeability as well as the importance of clay content on the viscoplastic behavior of shale formations. Second, we present several lines of evidence that indicates that the principal way in which hydraulic fracturing stimulates production from shale gas reservoirs is by inducing slow slip on pre-existing fractures and faults, which are not detected by conventional microseismic monitoring, Finally, we discuss how hydraulic fracturing can be optimized in response to variations of rock properties.

  20. Impact of Shallow Convection on the Gas Hydrate Reservoir in the Gulf of Mexico Salt Tectonics Province

    NASA Astrophysics Data System (ADS)

    Wilson, A.; Ruppel, C.

    2005-12-01

    Previous modeling studies have suggested that subseafloor hydrogeology in the northern Gulf of Mexico could be strongly affected by the presence of salt domes, but these efforts were at the time limited to formulations that decoupled thermal and chemical buoyancy. The earlier studies concluded that downwelling associated with the negative buoyancy of dense briny fluids dominated upwelling associated with positive thermal buoyancy near salt domes. In this study, we use modern hydrologic models that fully couple thermal and chemical effects to re-examine this problem with particular focus on Gulf of Mexico gas hydrate reservoirs. We first demonstrate that even slight variations in seafloor bathymetry lead to the onset of shallow convection in marine sediments and that the existence of such convective patterns is not dependent on the presence of salt or the geometry of the salt body. Bathymetric highs are generally the loci of upwelling, while downwelling is concentrated in bathymetric lows. The length scale of the convective cells depends on the wavelength of seafloor topography but is generally hundreds to less than 2000 m, consistent with observational evidence one of us has earlier reported for the Mississippi Canyon and Garden Banks gas hydrate areas. The model calculations are consistent with the observed pattern of chloride, sulfate, and thermal anomalies, suggesting that the modeling results can be used to estimate the variation in the depth of hydrate stability and hydrate occurrence in these highly dynamic systems. Our simulations of the transient evolution of convective regimes near salt domes show that the near-surface, thermally-driven system eventually separates from the deeper, chemically-driven system dominated by stable, dense brines. In this scenario, the gas hydrate stability zone will change as a function of time due to the changing hydraulic regime in the sediments. Superposed on such hydraulic effects on the hydrate stability zone would be the influence of better understood processes such as sedimentation or erosion of the sedimentary column. Finally, we explicitly consider the role of faults in focusing fluids in these systems and conclude that faults can radically perturb the chemical and thermal conditions near salt domes to the point of entirely dominating the flow field and thus the gas hydrate stability field. The results are applied to zones of focused flux, such as the mud mounds in the Garden Banks and Mississippi Canyon areas and the seeps at Bush Hill, and to a zone of 'diffuse advective flux' characterized by a regional BSR at Keathley Canyon.

  1. CHARACTERIZATION OF CONDITIONS OF NATURAL GAS STORAGE RESERVOIRS AND DESIGN AND DEMONSTRATION OF REMEDIAL TECHNIQUES FOR DAMAGE MECHANISMS FOUND THEREIN

    SciTech Connect

    J.H. Frantz Jr; K.G. Brown; W.K. Sawyer; P.A. Zyglowicz; P.M. Halleck; J.P. Spivey

    2004-12-01

    The underground gas storage (UGS) industry uses over 400 reservoirs and 17,000 wells to store and withdrawal gas. As such, it is a significant contributor to gas supply in the United States. It has been demonstrated that many UGS wells show a loss of deliverability each year due to numerous damage mechanisms. Previous studies estimate that up to one hundred million dollars are spent each year to recover or replace a deliverability loss of approximately 3.2 Bscf/D per year in the storage industry. Clearly, there is a great potential for developing technology to prevent, mitigate, or eliminate the damage causing deliverability losses in UGS wells. Prior studies have also identified the presence of several potential damage mechanisms in storage wells, developed damage diagnostic procedures, and discussed, in general terms, the possible reactions that need to occur to create the damage. However, few studies address how to prevent or mitigate specific damage types, and/or how to eliminate the damage from occurring in the future. This study seeks to increase our understanding of two specific damage mechanisms, inorganic precipitates (specifically siderite), and non-darcy damage, and thus serves to expand prior efforts as well as complement ongoing gas storage projects. Specifically, this study has resulted in: (1) An effective lab protocol designed to assess the extent of damage due to inorganic precipitates; (2) An increased understanding of how inorganic precipitates (specifically siderite) develop; (3) Identification of potential sources of chemical components necessary for siderite formation; (4) A remediation technique that has successfully restored deliverability to storage wells damaged by the inorganic precipitate siderite (one well had nearly a tenfold increase in deliverability); (5) Identification of the types of treatments that have historically been successful at reducing the amount of non-darcy pressure drop in a well, and (6) Development of a tool that can be used by operators to guide treatment selection in wells with significant non-darcy damage component. In addition, the effectiveness of the remediation treatment designed to reduce damage caused by the inorganic precipitate siderite was measured, and the benefits of this work are extrapolated to the entire U.S. storage industry. Similarly the potential benefits realized from more effective identification and treatment of wells with significant nondarcy damage component are also presented, and these benefits are also extrapolated to the entire U.S. storage industry.

  2. Using ArcGIS to extrapolate greenhouse gas emissions on the Pengxi River, a tributary of the Three Gorges Reservoir in China

    E-print Network

    Yasarer, Lindsey

    2014-11-19

    ArcGIS to extrapolate greenhouse gas emissions on the Pengxi River, a tributary of the Three Gorges Reservoir in China Lindsey MW Yasarer, PhD Candidate, University of Kansas Dr. Zhe Li, Associate Professor, Chongqing University Dr. Belinda Sturm... ArcGIS geospatial analysis tools. • Compare geospatial analysis with typical method of extrapolating GHG emissions (i.e. using average value) STUDY AREA Samples were collected from seven sampling spots along the 80 km backwater area: (1) Wenquan...

  3. Gas geochemistry of the magmatic-hydrothermal fluid reservoir in the Copahue-Caviahue Volcanic Complex (Argentina)

    NASA Astrophysics Data System (ADS)

    Agusto, M.; Tassi, F.; Caselli, A. T.; Vaselli, O.; Rouwet, D.; Capaccioni, B.; Caliro, S.; Chiodini, G.; Darrah, T.

    2013-05-01

    Copahue volcano is part of the Caviahue-Copahue Volcanic Complex (CCVC), which is located in the southwestern sector of the Caviahue volcano-tectonic depression (Argentina-Chile). This depression is a pull-apart basin accommodating stresses between the southern Liquiñe-Ofqui strike slip and the northern Copahue-Antiñir compressive fault systems, in a back-arc setting with respect to the Southern Andean Volcanic Zone. In this study, we present chemical (inorganic and organic) and isotope compositions (?13C-CO2, ?15N, 3He/4He, 40Ar/36Ar, ?13C-CH4, ?D-CH4, and ?D-H2O and ?18O-H2O) of fumaroles and bubbling gases of thermal springs located at the foot of Copahue volcano sampled in 2006, 2007 and 2012. Helium isotope ratios, the highest observed for a Southern American volcano (R/Ra up to 7.94), indicate a non-classic arc-like setting, but rather an extensional regime subdued to asthenospheric thinning. ?13C-CO2 values (from - 8.8‰ to - 6.8‰ vs. V-PDB), ?15N values (+ 5.3‰ to + 5.5‰ vs. Air) and CO2/3He ratios (from 1.4 to 8.8 × 109) suggest that the magmatic source is significantly affected by contamination of subducted sediments. Gases discharged from the northern sector of the CCVC show contribution of 3He-poor fluids likely permeating through local fault systems. Despite the clear mantle isotope signature in the CCVC gases, the acidic gas species have suffered scrubbing processes by a hydrothermal system mainly recharged by meteoric water. Gas geothermometry in the H2O-CO2-CH4-CO-H2 system suggests that CO and H2 re-equilibrate in a separated vapor phase at 200°-220 °C. On the contrary, rock-fluid interactions controlling CO2, CH4 production from Sabatier reaction and C3H8 dehydrogenation seem to occur within the hydrothermal reservoir at temperatures ranging from 250° to 300 °C. Fumarole gases sampled in 2006-2007 show relatively low N2/He and N2/Ar ratios and high R/Ra values with respect to those measured in 2012. Such compositional and isotope variations were likely related to injection of mafic magma that likely triggered the 2000 eruption. Therefore, changes affecting the magmatic system had a delayed effect on the chemistry of the CCVC gases due to the presence of the hydrothermal reservoir. However, geochemical monitoring activities mainly focused on the behavior of inert gas compounds (N2 and He), should be increased to investigate the mechanism at the origin of the unrest started in 2011.

  4. Radon-222 content of natural gas samples from Upper and Middle Devonian sandstone and shale reservoirs in Pennsylvania—preliminary data

    USGS Publications Warehouse

    Rowan, E.L.; Kraemer, T.F.

    2012-01-01

    Samples of natural gas were collected as part of a study of formation water chemistry in oil and gas reservoirs in the Appalachian Basin. Nineteen samples (plus two duplicates) were collected from 11 wells producing gas from Upper Devonian sandstones and the Middle Devonian Marcellus Shale in Pennsylvania. The samples were collected from valves located between the wellhead and the gas-water separator. Analyses of the radon content of the gas indicated 222Rn (radon-222) activities ranging from 1 to 79 picocuries per liter (pCi/L) with an overall median of 37 pCi/L. The radon activities of the Upper Devonian sandstone samples overlap to a large degree with the activities of the Marcellus Shale samples.

  5. Modeling the gas reservoir of circumstellar disks around young G-type stars

    E-print Network

    Inga Kamp; Fatima Sammar

    2004-07-28

    Interpretation of molecular line observations in tenuous circumstellar disks around young G-type stars in terms of a disk mass is difficult without a model that describes the chemical structure of these disks. This paper now discusses the chemistry in tenuous disks around young solar-type stars based on disk models that take into account the presence of a stellar chromosphere. The example of the disk around a 70 Myr old solar-type star shows that the dissociating radiation from the chromosphere is stronger than the interstellar ultraviolet radiation field up to a distance of ~400 AU from the star. Similar to other studies in this research field, it is found that, due to photodissociation, the CO-to-H_2 ratio is far from the canonical value of 10^-4 for molecular clouds. Moreover, the dust-to-gas mass ratio, as well as the dust grain size play an important role for the H_2 abundance in these disks.

  6. Drill Cuttings-based Methodology to Optimize Multi-stage Hydraulic Fracturing in Horizontal Wells and Unconventional Gas Reservoirs

    NASA Astrophysics Data System (ADS)

    Ortega Mercado, Camilo Ernesto

    Horizontal drilling and hydraulic fracturing techniques have become almost mandatory technologies for economic exploitation of unconventional gas reservoirs. Key to commercial success is minimizing the risk while drilling and hydraulic fracturing these wells. Data collection is expensive and as a result this is one of the first casualties during budget cuts. As a result complete data sets in horizontal wells are nearly always scarce. In order to minimize the data scarcity problem, the research addressed throughout this thesis concentrates on using drill cuttings, an inexpensive direct source of information, for developing: 1) A new methodology for multi-stage hydraulic fracturing optimization of horizontal wells without any significant increases in operational costs. 2) A new method for petrophysical evaluation in those wells with limited amount of log information. The methods are explained using drill cuttings from the Nikanassin Group collected in the Deep Basin of the Western Canada Sedimentary Basin (WCSB). Drill cuttings are the main source of information for the proposed methodology in Item 1, which involves the creation of three 'log tracks' containing the following parameters for improving design of hydraulic fracturing jobs: (a) Brittleness Index, (b) Measured Permeability and (c) An Indicator of Natural Fractures. The brittleness index is primarily a function of Poisson's ratio and Young Modulus, parameters that are obtained from drill cuttings and sonic logs formulations. Permeability is measured on drill cuttings in the laboratory. The indication of natural fractures is obtained from direct observations on drill cuttings under the microscope. Drill cuttings are also the main source of information for the new petrophysical evaluation method mentioned above in Item 2 when well logs are not available. This is important particularly in horizontal wells where the amount of log data is almost non-existent in the vast majority of the wells. By combining data from drill cuttings and previously available empirical relationships developed from cores it is possible to estimate water saturations, pore throat apertures, capillary pressures, flow units, porosity (or cementation) exponent m, true formation resistivity Rt, distance to a water table (if present), and to distinguish the contributions of viscous and diffusion-like flow in the tight gas formation. The method further allows the construction of Pickett plots using porosity and permeability obtained from drill cuttings, without previous availability of well logs. The method assumes the existence of intervals at irreducible water saturation, which is the case of the Nikanassin Group throughout the gas column. The new methods mentioned above are not meant to replace the use of detailed and sophisticated evaluation techniques. But the proposed methods provide a valuable and practical aid in those cases where geomechanical and petrophysical information are scarce.

  7. Paleozoic oil/gas shale reservoirs in southern Tunisia: An overview

    NASA Astrophysics Data System (ADS)

    Soua, Mohamed

    2014-12-01

    During these last years, considerable attention has been given to unconventional oil and gas shale in northern Africa where the most productive Paleozoic basins are located (e.g. Berkine, Illizi, Kufra, Murzuk, Tindouf, Ahnet, Oued Mya, Mouydir, etc.). In most petroleum systems, which characterize these basins, the Silurian played the main role in hydrocarbon generation with two main 'hot' shale levels distributed in different locations (basins) and their deposition was restricted to the Rhuddanian (Lllandovery: early Silurian) and the Ludlow-Pridoli (late Silurian). A third major hot shale level had been identified in the Frasnian (Upper Devonian). Southern Tunisia is characterized by three main Paleozoic sedimentary basins, which are from North to South, the southern Chotts, Jeffara and Berkine Basin. They are separated by a major roughly E-W trending lower Paleozoic structural high, which encompass the Mehrez-Oued Hamous uplift to the West (Algeria) and the Nefusa uplift to the East (Libya), passing by the Touggourt-Talemzane-PGA-Bou Namcha (TTPB) structure close to southern Tunisia. The forementioned major source rocks in southern Tunisia are defined by hot shales with elevated Gamma ray values often exceeding 1400 API (in Hayatt-1 well), deposited in deep water environments during short lived (c. 2 Ma) periods of anoxia. In the course of this review, thickness, distribution and maturity maps have been established for each hot shale level using data for more than 70 wells located in both Tunisia and Algeria. Mineralogical modeling was achieved using Spectral Gamma Ray data (U, Th, K), SopectroLith logs (to acquire data for Fe, Si and Ti) and Elemental Capture Spectroscopy (ECS). The latter technique provided data for quartz, pyrite, carbonate, clay and Sulfur. In addition to this, the Gamma Ray (GR), Neutron Porosity (?N), deep Resistivity (Rt) and Bulk Density (?b) logs were used to model bulk mineralogy and lithology. Biostratigraphic and complete geochemical review has been undertaken from published papers and unpublished internal reports to better assess these important source intervals.

  8. Chemical Changes in Pore Water Composition due to CO2 Injection Under In-Situ P-T Condition of the Altmark Gas Reservoir, Germany

    NASA Astrophysics Data System (ADS)

    Huq, F.; Nowak, M.; Haderlein, S.; Grathwohl, P.

    2012-12-01

    CO2 storage in depleted gas reservoir combined with enhanced gas recovery may be an economically feasible option to mitigate global warming. The Altmark gas field, located in the western part of the Northeast German Basin, is being considered as a potential candidate for this purpose. Under reservoir conditions (50 bars and 125°C), the CO2 saturated water causes dissolution and subsequent precipitation of minerals of the surrounding rock matrix. Therefore, the main objective of the current study was to investigate the chemical changes in fluid composition due to dissolution/precipitation of minerals under controlled laboratory conditions. A dry sandstone plug from the Altmark reservoir was mounted in a newly designed autoclave system and flushed by a pre-equilibrated mixture of water saturated with CO2 at a constant flow rate of 0.25 cm/h for 12 days at reservoir conditions. Fluid samples were taken at regular intervals for major and trace element analysis and pH was measured simultaneously in the partially de-gassed samples. Fluid analysis showed an increased concentration of Na, K and Cl ions at the beginning indicating early leaching of halite and sylvite which initially inhibited the dissolution of alkali feldspars. Feldspar dissolution occurred later and slower indicated by lower concentrations of Na and K reflecting the lower solubility and slow dissolution kinetics of feldspar. Dissolution of anhydrite was predominantly observed from the increased concentration of Ca and SO4 at earlier time periods. However, the Ca/SO4 molar ratio (>1) indicated the concurrent dissolution of both calcite and anhydrite. The presence of carbonates buffered the pH until day 6. Moreover, the mobilization of Mn, Mg, Ba and Fe might be derived from carbonate impurities. Thermodynamic calculations of mineral saturation indices enabled an evaluation of the CO2-water-rock interactions during the experiment and highlighted the dissolution of the Ca-bearing minerals in the studied solution.

  9. Pore- and fracture-filling gas hydrate reservoirs in the Gulf of Mexico Gas Hydrate Joint Industry Project Leg II Green Canyon 955 H well

    USGS Publications Warehouse

    Lee, M.W.; Collett, T.S.

    2012-01-01

    High-quality logging-while-drilling (LWD) downhole logs were acquired in seven wells drilled during the Gulf of MexicoGasHydrateJointIndustryProjectLegII in the spring of 2009. Well logs obtained in one of the wells, the GreenCanyon Block 955Hwell (GC955-H), indicate that a 27.4-m thick zone at the depth of 428 m below sea floor (mbsf; 1404 feet below sea floor (fbsf)) contains gashydrate within sand with average gashydrate saturations estimated at 60% from the compressional-wave (P-wave) velocity and 65% (locally more than 80%) from resistivity logs if the gashydrate is assumed to be uniformly distributed in this mostly sand-rich section. Similar analysis, however, of log data from a shallow clay-rich interval between 183 and 366 mbsf (600 and 1200 fbsf) yielded average gashydrate saturations of about 20% from the resistivity log (locally 50-60%) and negligible amounts of gashydrate from the P-wave velocity logs. Differences in saturations estimated between resistivity and P-wave velocities within the upper clay-rich interval are caused by the nature of the gashydrate occurrences. In the case of the shallow clay-rich interval, gashydrate fills vertical (or high angle) fractures in rather than fillingpore space in sands. In this study, isotropic and anisotropic resistivity and velocity models are used to analyze the occurrence of gashydrate within both the clay-rich and sand dominated gas-hydrate-bearing reservoirs in the GC955-Hwell.

  10. EOS7C Version 1.0: TOUGH2 Module for Carbon Dioxide or Nitrogen inNatural Gas (Methane) Reservoirs

    SciTech Connect

    Oldenburg, Curtis M.; Moridis,George J.; Spycher, Nicholas; Pruess, Karsten

    2004-06-29

    EOS7C is a TOUGH2 module for multicomponent gas mixtures in the systems methane carbon dioxide (CH4-CO2) or methane-nitrogen (CH4-N2) with or without an aqueous phase and H2O vapor. EOS7C uses a cubic equation of state and an accurate solubility formulation along with a multiphase Darcy s Law to model flow and transport of gas and aqueous phase mixtures over a wide range of pressures and temperatures appropriate to subsurface geologic carbon sequestration sites and natural gas reservoirs. EOS7C models supercritical CO2 and subcritical CO2 as a non-condensible gas, hence EOS7C does not model the transition to liquid or solid CO2 conditions. The components modeled in EOS7C are water, brine, non-condensible gas, gas tracer, methane, and optional heat. The non-condensible gas (NCG) can be selected by the user to be CO2 or N2. The real gas properties module has options for Peng-Robinson, Redlich-Kwong, or Soave-Redlich-Kwong equations of state to calculate gas mixture density, enthalpy departure, and viscosity. Partitioning of the NCG and CH4 between the aqueous and gas phases is calculated using a very accurate chemical equilibrium approach. Transport of the gaseous and dissolved components is by advection and Fickian molecular diffusion. We present instructions for use and example problems to demonstrate the accuracy and practical application of EOS7C.

  11. Analytical Estimation of CO2 Storage Capacity in Depleted Oil and Gas Reservoirs Based on Thermodynamic State Functions 

    E-print Network

    Valbuena Olivares, Ernesto

    2012-02-14

    which allows fast and accurate estimations of final storage, which can be used to select target storage reservoirs, and design the injection scheme and surface facilities. Impurities such as nitrogen and carbon monoxide, usually contained in power plant...

  12. Geologic controls on reservoir properties in gas-bearing middle and Upper Devonian rocks, southern Appalachian basin

    SciTech Connect

    Vessell, R.K.; Davies, D.K.

    1988-08-01

    Porosities and permeabilities have been measured for a wide range of nonfractured Devonian lithologies in 23 wells from southeastern Ohio, eastern Kentucky, West Virginia, and Virginia. These reservoir properties can be related directly to the geometry of the pore system. Pore geometry, in turn, is a function of rock lithology and mineralogy. Despite the lithologic complexity of the Devonian sequence, reservoir quality can be related to a small number of differing pore geometries.

  13. Greenhouse gas (CO2 and CH4) emissions from a high altitude hydroelectric reservoir in the tropics (Riogrande II, Colombia)

    NASA Astrophysics Data System (ADS)

    Guérin, Frédéric; Leon, Juan

    2015-04-01

    Tropical hydroelectric reservoirs are considered as very significant source of methane (CH4) and carbon dioxide (CO2), especially when flooding dense forest. We report emissions from the Rio Grande II Reservoir located at 2000 m.a.s.l. in the Colombian Andes. The dam was built at the confluence of the Rio Grande and Rio Chico in 1990. The reservoir has a surface of 12 km2, a maximum depth of 40m and a residence time of 2.5 month. Water quality (temperature, oxygen, pH, conductivity), nitrate, ammonium, dissolved and particulate organic carbon (DOC and POC), CO2 and CH4 were monitored bi-monthly during 1.5 year at 9 stations in the reservoir. Diffusive fluxes of CO2 and CH4 and CH4 ebullition were measured at 5 stations. The Rio grande II Reservoir is weakly stratified thermally with surface temperature ranging from 20 to 24°C and a constant bottom temperature of 18°C. The reservoir water column is well oxygenated at the surface and usually anoxic below 10m depth. At the stations close to the tributaries water inputs, the water column is well mixed and oxygenated from the surface to the bottom. As reported for other reservoirs located in "clear water" watersheds, the concentrations of nutrients are low (NO3-<0.1ppm, NH4+<0.2ppm), the concentrations of DOC are high (2-8 mg L-1) and POC concentrations are low (< 3 mg L-1). Surface CH4 concentrations at the central stations of the reservoirs are 0.5 ?mol L-1 (0.07-2.14 ?mol L-1) and 3 times higher at the stations close to the tributaries inputs (up to 7 ?mol L-1). In the hypolimnion, CH4 concentration is <100 ?mol L-1 in the wet season and can reach up to 400 ?mol L-1 in the dry season. The spatial and temporal variability are lower for CO2. Surface CO2 concentration was on average 72 ?mol L-1 (up to 300) and hypolimnic concentration ranged between 250 and 1000 ?mol L-1. The CO2 diffusive flux is 517±331 mmol m-2 d-1 with little seasonal and spatial variations. At the center of the reservoir, the median diffusive flux of CH4 is 1.75 mmol m-2 d-1 and sporadic high fluxes (>10 mmol m-2 d-1) were observed during the dry season. Close to the tributaries water inputs where the water column is well mixed, the average diffusive flux is 8 mmol m-2 d-1. CH4 ebullition was 3.5 mmol m-2 d-1 and no ebullition was observed for a water depth higher than 5m. The zone under the influence of the water inputs from tributaries represents 25% of the surface of the reservoir but contributed half of total CH4 emissions from the reservoir (29MgC month-1). Ebullition contributed only to 12% of total CH4 emissions over a year but it contributed up to 60% during the dry season. CH4 emissions from the Rio Grande Reservoir contributed 30% of the total GHG emissions (38GgCO2eq y-1). Overall, this study show that the majority of CH4 emissions from this reservoir occur through hotspot and hot moments and that mountainous reservoir located in the tropics could have emission factors as high as Amazonian reservoirs.

  14. Optimizing injected solvent fraction in stratified reservoirs 

    E-print Network

    Moon, Gary Michael

    1993-01-01

    Waterflooding has become standard practice for extending the productive life of many solution gas drive reservoirs, but has the disadvantage of leaving a substantial residual oil volume in the reservoir. Solvent flooding has been offered as a...

  15. Petroleum reservoir data for testing simulation models

    SciTech Connect

    Lloyd, J.M.; Harrison, W.

    1980-09-01

    This report consists of reservoir pressure and production data for 25 petroleum reservoirs. Included are 5 data sets for single-phase (liquid) reservoirs, 1 data set for a single-phase (liquid) reservoir with pressure maintenance, 13 data sets for two-phase (liquid/gas) reservoirs and 6 for two-phase reservoirs with pressure maintenance. Also given are ancillary data for each reservoir that could be of value in the development and validation of simulation models. A bibliography is included that lists the publications from which the data were obtained.

  16. Numerical modeling of self-limiting and self-enhancing caprock alteration induced by CO2 storage in a depleted gas reservoir

    SciTech Connect

    Xu, Tianfu; Gherardi, Fabrizio; Xu, Tianfu; Pruess, Karsten

    2007-09-07

    This paper presents numerical simulations of reactive transport which may be induced in the caprock of an on-shore depleted gas reservoir by the geological sequestration of carbon dioxide. The objective is to verify that CO{sub 2} geological disposal activities currently being planned for the study area are safe and do not induce any undesired environmental impact. In our model, fluid flow and mineral alteration are induced in the caprock by penetration of high CO{sub 2} concentrations from the underlying reservoir, where it was assumed that large amounts of CO{sub 2} have already been injected at depth. The main focus is on the potential effect of precipitation and dissolution processes on the sealing efficiency of caprock formations. Concerns that some leakage may occur in the investigated system arise because the seal is made up of potentially highly-reactive rocks, consisting of carbonate-rich shales (calcite+dolomite averaging up to more than 30% of solid volume fraction). Batch simulations and multi-dimensional 1D and 2D modeling have been used to investigate multicomponent geochemical processes. Numerical simulations account for fracture-matrix interactions, gas phase participation in multiphase fluid flow and geochemical reactions, and kinetics of fluid-rock interactions. The geochemical processes and parameters to which the occurrence of high CO{sub 2} concentrations are most sensitive are investigated by conceptualizing different mass transport mechanisms (i.e. diffusion and mixed advection+diffusion). The most relevant mineralogical transformations occurring in the caprock are described, and the feedback of these geochemical processes on physical properties such as porosity is examined to evaluate how the sealing capacity of the caprock could evolve in time. The simulations demonstrate that the occurrence of some gas leakage from the reservoir may have a strong influence on the geochemical evolution of the caprock. In fact, when a free CO{sub 2}-dominated phase migrates into the caprock through fractures, or through zones with high initial porosity possibly acting as preferential flow paths for reservoir fluids, low pH values are predicted, accompanied by significant calcite dissolution and porosity enhancement. In contrast, when fluid-rock interactions occur under fully liquid-saturated conditions and a diffusion-controlled regime, pH will be buffered at higher values, and some calcite precipitation is predicted which leads to further sealing of the storage reservoir.

  17. Post - sedimentation influence on filtration capacity reservoir rock properties (Pur-Tazov oil\\gas-bearing area)

    NASA Astrophysics Data System (ADS)

    Isaeva, E.; Stolbova, N.; Dolgaya, T.

    2015-11-01

    The processes of the second mineral formation (kaolinite, carbonates and micas) were identified during the post-sedimentation transformation studies in oil?s deposits. Besides, quartz regeneration, solid product destructive formation processes and hydrocarbon oxidation processes were -determined. Correlation analysis of the mineralogy and petrophysics data revealed the post-sedimentation influence factors on the reservoir properties of deposits. It should be noted that the second kaolinite composition increase results in water saturation and density decrease, porosity and, especially, permeability increase. Quartz regeneration and second mica formation deteriorate the reservoir properties or poorly influence them. The hydrocarbon decay and oxidation products, as well as secondary carbonate seal the void space, replace the soluble rock debris and sharply deteriorate the reservoir properties of oil andgas deposits.

  18. Chemical, mineralogical and molecular biological characterization of the rocks and fluids from a natural gas storage deep reservoir as a baseline for the effects of geological hydrogen storage

    NASA Astrophysics Data System (ADS)

    Morozova, Daria; Kasina, Monika; Weigt, Jennifer; Merten, Dirk; Pudlo, Dieter; Würdemann, Hilke

    2014-05-01

    Planned transition to renewable energy production from nuclear and CO2-emitting power generation brings the necessity for large scale energy storage capacities. One possibility to store excessive energy produced is to transfer it to chemical forms like hydrogen which can be subsequently injected and stored in subsurface porous rock formations like depleted gas reservoirs and presently used gas storage sites. In order to investigate the feasibility of the hydrogen storage in the subsurface, the collaborative project H2STORE ("hydrogen to store") was initiated. In the scope of this project, potential reactions between microorganism, fluids and rocks induced by hydrogen injection are studied. For the long-term experiments, fluids of natural gas storage are incubated together with rock cores in the high pressure vessels under 40 bar pressure and 40° C temperature with an atmosphere containing 5.8% He as a tracer gas, 3.9% H2 and 90.3% N2. The reservoir is located at a depth of about 2 000 m, and is characterized by a salinity of 88.9 g l-1 NaCl and a temperature of 80° C and therefore represents an extreme environment for microbial life. First geochemical analyses showed a relatively high TOC content of the fluids (about 120 mg l-1) that were also rich in sodium, potassium, calcium, magnesium and iron. Remarkable amounts of heavy metals like zinc and strontium were also detected. XRD analyses of the reservoir sandstones revealed the major components: quartz, plagioclase, K-feldspar, anhydrite and analcime. The sandstones were intercalated by mudstones, consisting of quartz, plagioclase, K-feldspar, analcime, chlorite, mica and carbonates. Genetic profiling of amplified 16S rRNA genes was applied to characterize the microbial community composition by PCR-SSCP (PCR-Single-Strand-Conformation Polymorphism) and DGGE (Denaturing Gradient Gel Electrophoresis). First results indicate the presence of microorganisms belonging to the phylotypes alfa-, beta- and gamma-Proteobacteria and Actinobacteria. Sequences of these organisms have been found in subsurface environments before, e.g. in saline, hot, anoxic, and deep milieus. Due to the saline and hyperthermophilic reservoir conditions, the quantification of those microorganisms by DAPI staining revealed very low cell numbers of about 102 cells ml-1. Investigations of the microbial community composition, mineralogy and fluid chemistry after 6 months of incubation are in progress to determine to what extent hydrogen injection may contribute to a shift in the microbial community structure and abundance, microbial-mineral interactions and hydrogen-based methanogenesis.

  19. CO emission and associated HI absorption from a massive gas reservoir surrounding the z=3 radio galaxy B3 J2330+3927

    E-print Network

    Carlos De Breuck; Roberto Neri; Raffaella Morganti; Alain Omont; Brigitte Rocca-Volmerange; Daniel Stern; Michiel Reuland; Wil van Breugel; Huub Rottgering; S. A. Stanford; Hyron Spinrad; Mario Vigotti; Melvyn Wright

    2003-02-07

    We present results of a comprehensive multi-frequency study of the radio galaxy B3 J2330+3927. The 1.9" wide radio source, consisting of 3 components, is bracketed by 2 objects in our Keck K-band image. Optical and near-IR Keck spectroscopy of these two objects yield z=3.087+-0.004. The brightest (K=18.8) object has a standard type II AGN spectrum, and is the most likely location of the AGN, which implies a one-sided jet radio morphology. Deep 113 GHz observations with the IRAM Plateau de Bure Interferometer reveal CO J=4-3 emission, which peaks at the position of the AGN. The CO line is offset by 500 km/s from the systemic redshift of the AGN, but corresponds very closely to the velocity shift of an associated HI absorber seen in Lya. This strongly suggests that both originate from the same gas reservoir surrounding the AGN host galaxy. Simultaneous 230 GHz interferometer observations find a ~3x lower integrated flux density when compared to single dish 250 GHz observations with MAMBO at the IRAM 30m telescope. This can be interpreted as spatially resolved thermal dust emission at scales of 0.5" to 6". Finally, we present a tau 2 radio galaxies observed to date with the WSRT. We present mass estimates for the atomic, neutral, and ionized hydrogen, and for the dust, ranging from M(HI)=2x10^7 M_Sun derived from the associated HI absorber in Lya up to M(H_2)=7x10^{10} M_Sun derived from the CO emission. This indicates that the host galaxy is surrounded by a massive reservoir of gas and dust. The K-band companion objects may be concentrations within this reservoir, which will eventually merge with the central galaxy hosting the AGN.

  20. Analytical solution for Joule-Thomson cooling during CO2 geo-sequestration in depleted oil and gas reservoirs

    SciTech Connect

    Mathias, S.A.; Gluyas, J.G.; Oldenburg, C.M.; Tsang, C.-F.

    2010-05-21

    Mathematical tools are needed to screen out sites where Joule-Thomson cooling is a prohibitive factor for CO{sub 2} geo-sequestration and to design approaches to mitigate the effect. In this paper, a simple analytical solution is developed by invoking steady-state flow and constant thermophysical properties. The analytical solution allows fast evaluation of spatiotemporal temperature fields, resulting from constant-rate CO{sub 2} injection. The applicability of the analytical solution is demonstrated by comparison with non-isothermal simulation results from the reservoir simulator TOUGH2. Analysis confirms that for an injection rate of 3 kg s{sup -1} (0.1 MT yr{sup -1}) into moderately warm (>40 C) and permeable formations (>10{sup -14} m{sup 2} (10 mD)), JTC is unlikely to be a problem for initial reservoir pressures as low as 2 MPa (290 psi).

  1. Carbonate petroleum reservoirs

    SciTech Connect

    Roehl, P.O.; Choquette, P.W.

    1985-01-01

    This book presents papers on the geology of petroleum deposits. Topics considered include diagenesis, porosity, dolomite reservoirs, deposition, reservoir rock, reefs, morphology, fracture-controlled production, Cenozoic reservoirs, Mesozoic reservoirs, and Paleozoic reservoirs.

  2. CO2 gas/oil ratio prediction in a multi-component reservoir bycombined seismic and electromagnetic imaging

    SciTech Connect

    Hoversten, G.M.; Gritto, Roland; Washbourne, John; Daley, Tom

    2002-08-28

    Crosswell seismic and electromagnetic data sets taken before and during CO2 flooding of an oil reservoir are inverted to produce crosswell images of the change in compressional velocity, shear velocity and electrical conductivity during a CO2 injection pilot study. A rock properties model is developed using measured log porosity, fluid saturations, pressure, temperature, bulk density, sonic velocity and electrical conductivity. The parameters of the rock properties model are found by an L1-norm simplex minimization of predicted and observed compressional velocity and density. A separate minimization using Archie's law provides parameters for modeling the relations between water saturation, porosity and the electrical conductivity. The rock properties model is used to generate relationships between changes in geophysical parameters and changes in reservoir parameters. The electrical conductivity changes are directly mapped to changes in water saturation. The estimated changes in water saturation are used with the observed changes in shear wave velocity to predict changes in reservoir pressure. The estimation of the spatial extent and amount of CO2 relies on first removing the effects of the water saturation and pressure changes from the observed compressional velocity changes, producing a residual compressional velocity change. The residual compressional velocity change is then interpreted in terms of increases in the CO2 /oil ratio. Resulting images of CO2/oil ratio show CO2 rich zones that are well correlated with the location of injection perforations with the size of these zones also correlating to the amount of injected CO2. The images produced by this process are better correlated to the location and amount of injected CO2 than are any of the individual images of change in geophysical parameters.

  3. Noble gas evidence of an aqueous reservoir near the surface of Mars more recently than 1.3 Ga

    NASA Technical Reports Server (NTRS)

    Drake, Michael J.; Owen, Toby; Swindle, Timothy; Musselwhite, Donald

    1993-01-01

    Considerable evidence points to a Martian origin of the SNC meteorites. One of these meteorites, Nakhla, contains a leachable component which has an elevated Xe-129/Xe-132 ratio relative to its Kr-84/Xe-132 ratio when compared to the approximately linear array defined by Chassigny, most shergottites, and lithology C of EETA 79001. This array is thought to be a mixing line between Martian mantle and Martian atmosphere. The leachable component probably consists in part of iddingsite, an alteration product produced by interaction of olivine with aqueous fluid at temperatures lower than 150 C. The radiogenic Xe component may represent a distinct reservoir in the Martian crust or mantle. More plausibly, it is Martian atmosphere, fractionated by solution in liquid water and by interaction with sediment. The crystallization age of Nakhla is 1.3 Ga. Its low shock state suggests that it was ejected from near the surface of Mars. Liquid water is required for the formation of iddingsite. These observations provide further evidence for the near surface existence of aqueous fluids more recently than 1.3 Ga.

  4. Petrographic and reservoir features of Hauterivian (Lower Cretaceous) Shatlyk horizon in the Malay gas field, Amu-Darya basin, east Turkmenia

    SciTech Connect

    Naz, H.; Ersan, A.

    1996-08-01

    Malay gas field in Amu-Darya basin, eastern Turkmenia, is located on the structural high that is on the Malay-Bagadzha arch north of the Repetek-Kelif structure zone. With 500 km{sup 2} areal coverage, 16 producing wells and 200 billion m{sup 3} estimated reserves, the field was discovered in 1978 and production began in 1987 from 2400-m-deep Hauterivian-age (Early Cretaceous) Shatlyk horizon. The Shatlyk elastic sequence shows various thickness up to 100 m in the Malay structural closure and is studied through E-log, core, petrographic data and reservoir characteristics. The Shatlyk consists of poorly indurated, reddish-brown and gray sandstones, and sandy gray shales. The overall sand-shale ratio increases up and the shales interleave between the sand packages. The reservoir sandstones are very fine to medium grained, moderately sorted, compositionally immature, subarkosic arenites. The framework grains include quartz, feldspar and volcanic lithic fragments. Quartz grains are monocrystalline in type and most are volcanic in origin. Feldspars consist of K- Feldspar and plagioclase. The orthoclases are affected by preferential alteration. The sandstones show high primary intergranular porosity and variations in permeability. Patch-like evaporate cement and the iron-rich grain coatings are reducing effects in permeability. The coats are pervasive in reddish-brown sandstones but are not observed in the gray sandstones. The evaporate cement is present in all the sandstone samples examined and, in places, follows the oxidation coats. The petrographic evidences and the regional facies studies suggest the deposition in intersection area from continental to marine nearshore deltaic environment.

  5. Experimental Determination of P-V-T-X Properties and Adsorption Kinetics in the CO2-CH4 System under Shale Gas Reservoir Conditions

    NASA Astrophysics Data System (ADS)

    Xiong, Y.; Wang, Y.

    2014-12-01

    Shale gas production via hydrofracturing has profoundly changed the energy portfolio in the USA and other parts of the world. Under the shale gas reservior conditions, CO2 and H2O, either in residence or being injected during hydrofracturing or both, co-exist with CH4. One important feature characteristic of shale is the presence of nanometer-scale (1-100 nm) pores in shale or mudstone. The interactions among CH4, CO2 and H2O in those nano-sized pores directly impact shale gas storage and gas release from the shale matrix. Therefore, a fundamental understanding of interactions among CH4, CO2 and H2O in nanopore confinement would provide guidance in addressing a number of problems such as rapid decline in production after a few years and low recovery rates. We are systematically investigating the P-V-T-X properties and adsorption kinetics in the CH4-CO2-H2O system under the reservior conditions. We have designed and constructed a unique high temperature and pressure experimental system that can measure both of the P-V-T-X properties and adsorption kinetics sequentially. We measure the P-V-T-X properties of CH4-CO2 mixtures with CH4 up to 95 vol. %, and adsorption kinetics of various materials, under the conditions relevant to shale gas reservoir. We use three types of materials: (I) model materials, (II) single solid phases separated from shale samples, and (III) crushed shale samples from both the known shale gas producing formations and the shale gas barren formations. The model materials are well characterized in terms of pore sizes. Therefore, the results associated with the model material serve as benchmarks for our model development. Sandia National Laboratories is a multi-program laboratory operated by Sandia Corporation, a wholly owned subsidiary of Lockheed Martin Corporation, for the U.S. Department of Energy's National Nuclear Security Administration under contract DE-AC04-94AL85000. This research is supported by a Geoscience Foundation LDRD.

  6. Chemistry in Protoplanetary Disks: the gas-phase CO/H2 ratio and the Carbon reservoir

    E-print Network

    Reboussin, L; Guilloteau, S; Hersant, F; Dutrey, A

    2015-01-01

    The gas mass of protoplanetary disks, and the gas-to-dust ratio, are two key elements driving the evolution of these disks and the formation of planetary system. We explore here to what extent CO (or its isotopologues) can be used as a tracer of gas mass. We use a detailed gas-grain chemical model and study the evolution of the disk composition, starting from a dense pre-stellar core composition. We explore a range of disk temperature profiles, cosmic rays ionization rates, and disk ages for a disk model representative of T Tauri stars. At the high densities that prevail in disks, we find that, due to fast reactions on grain surfaces, CO can be converted to less volatile forms (principally s-CO$_2$, and to a lesser extent s-CH$_4$) instead of being evaporated over a wide range of temperature. The canonical gas-phase abundance of 10$^{-4}$ is only reached above about 30-35 K. The dominant Carbon bearing entity depends on the temperature structure and age of the disk. The chemical evolution of CO is also sensit...

  7. 30 CFR 250.407 - What tests must I conduct to determine reservoir characteristics?

    Code of Federal Regulations, 2014 CFR

    2014-07-01

    ...What tests must I conduct to determine reservoir characteristics? 250.407 Section...What tests must I conduct to determine reservoir characteristics? You must determine the presence, quantity, quality, and reservoir characteristics of oil, gas,...

  8. 30 CFR 250.1154 - How do I determine if my reservoir is sensitive?

    Code of Federal Regulations, 2010 CFR

    2010-07-01

    ...2010-07-01 false How do I determine if my reservoir is sensitive? 250.1154 Section 250...Gas Production Requirements Classifying Reservoirs § 250.1154 How do I determine if my reservoir is sensitive? (a) You must...

  9. 30 CFR 250.407 - What tests must I conduct to determine reservoir characteristics?

    Code of Federal Regulations, 2010 CFR

    2010-07-01

    ...What tests must I conduct to determine reservoir characteristics? 250.407 Section...What tests must I conduct to determine reservoir characteristics? You must determine the presence, quantity, quality, and reservoir characteristics of oil, gas,...

  10. 30 CFR 250.407 - What tests must I conduct to determine reservoir characteristics?

    Code of Federal Regulations, 2013 CFR

    2013-07-01

    ...What tests must I conduct to determine reservoir characteristics? 250.407 Section...What tests must I conduct to determine reservoir characteristics? You must determine the presence, quantity, quality, and reservoir characteristics of oil, gas,...

  11. 30 CFR 250.407 - What tests must I conduct to determine reservoir characteristics?

    Code of Federal Regulations, 2012 CFR

    2012-07-01

    ...What tests must I conduct to determine reservoir characteristics? 250.407 Section...What tests must I conduct to determine reservoir characteristics? You must determine the presence, quantity, quality, and reservoir characteristics of oil, gas,...

  12. 30 CFR 250.1154 - How do I determine if my reservoir is sensitive?

    Code of Federal Regulations, 2011 CFR

    2011-07-01

    ...2011-07-01 false How do I determine if my reservoir is sensitive? 250.1154 Section 250...Gas Production Requirements Classifying Reservoirs § 250.1154 How do I determine if my reservoir is sensitive? (a) You must...

  13. 30 CFR 250.407 - What tests must I conduct to determine reservoir characteristics?

    Code of Federal Regulations, 2011 CFR

    2011-07-01

    ...What tests must I conduct to determine reservoir characteristics? 250.407 Section...What tests must I conduct to determine reservoir characteristics? You must determine the presence, quantity, quality, and reservoir characteristics of oil, gas,...

  14. Analysis of active microorganisms and their potential role in carbon dioxide turnover in the natural gas reservoirs Altmark and Schneeren (Germany)

    NASA Astrophysics Data System (ADS)

    Gniese, Claudia; Muschalle, Thomas; Mühling, Martin; Frerichs, Janin; Krüger, Martin; Kassahun, Andrea; Seifert, Jana; Hoth, Nils

    2010-05-01

    RECOBIO-2, part of the BMBF-funded Geotechnologien consortium, investigates the presence of active microorganisms and their potential role in CO2 turnover in the formation waters of the Schneeren and Altmark gas fields, which are both operated by GDF SUEZ E&P Germany GmbH. Located to the north west of Hannover the natural gas reservoir Schneeren is composed of compacted Westfal-C sandstones that have been naturally fractured into a subsalinar horst structure. This gas field is characterized by a depth of 2700 to 3500m, a bottom-hole temperature between 80 and 110° C as well as a moderate salinity (30-60g/l) and high sulfate contents (~1000mg/l). During RECOBIO-1 produced formation water collected at wells in Schneeren was already used to conduct long term laboratory experiments. These served to examine possible microbial processes of the autochthonous biocenosis induced by the injection of CO2 (Ehinger et al. 2009 submitted). Microorganisms in particular sulfate-reducing bacteria and methanogens were able to grow in the presence of powdered rock material, CO2 and H2 without any other added nutrients. The observed development of DOC was now proven in another long term experiment using labelled 13CO2. In contrast to Schneeren, the almost depleted natural gas reservoir Altmark exhibits an average depth of 3300m, a higher bottom-hole temperature (111° C to 120° C), a higher salinity (275-350g/l) but sulfate is absent. This Rotliegend formation is located in the southern edge of the Northeast German Basin and is of special interest for CO2 injection because of favourable geological properties. Using molecular biological techniques two types of samples are analyzed: formation water collected at the well head (November 2008) and formation water sampled in situ from a depth of around 3000m (May 2009). Some of the wells are treated frequently with a foaming agent while others are chemically untreated. Despite the extreme environmental conditions in the Altmark gas field, RNA of apparently active microorganisms was successfully extracted from all samples. Sequence analysis of 16S rRNA revealed mainly fermentative bacteria belonging to the phylogenetic group of Actinobacteria (e.g. Propionibacterium spp.) and ?-Proteobacteria (e.g. Hyphomicrobium spp.) possibly involved in the nitrogen cycle. Cell numbers were determined using a PCR-independent molecular detection method (CARD-FISH) with universal 16S rRNA-specific probes (EUB338, ARCH915). The fraction of bacterial cells comprised up to 104 cells per milliliter, which corresponds to the cell numbers obtained with a generic DNA stain (DAPI). Archaeal cells could not be detected by CARD-FISH, though archaeal 16S rRNA gene fragments were amplified from DNA extracts using PCR. So far differences have neither been observed between treated and untreated formation waters nor between well head and in situ sampled formation waters. Further investigations are underway to elucidate whether particular metabolic pathways are present in the microbial assemblage of the Altmark gas field fluids. In addition, microbe-mineral interactions will be assessed using electron microscopic approaches. Ehinger, S., Kassahun, A., Muschlle, T., Gniese, C., Schlömann, M., Hoth, N., Seifert, J. (2009 submitted) Sulfate reduction by novel Thermoanaerobacteriaceae in bioreactor inoculated with gas-field brine. Environmental Microbiology

  15. Establishment of an oil and gas database for increased recovery and characterization of oil and gas carbonate reservoir heterogeneity. Appendix 1, Volume 4

    SciTech Connect

    Kopasaka-Merkel, D.C.; Moore, H.E. Jr.; Mann, S.D; Hall, D.R.

    1992-06-01

    This volume contains maps, well log correlated to lithology, porosity and permeability, structural cross section, graph of production history, porosity vs. natural log permeability plots; detailed core log, porosity vs. natural permeability plot for one lithofacies, paragenetic sequence and reservoir characterization sheet for the following fields in southwest Alabama: Stave Creek oil field; Sugar Ridge oil field; Toxey oil field, Turkey Creed oil field; Turnerville oil field, Uriah oil field; Vocation oil field; Wallace oil field; Wallers Creek oil field; West Appleton oil field; West Barrytown oil field; West Bend oil field; West Okatuppa Creed oil field; Wild Fork Creek oil field; Wimberly oil field; Womack Hill oil field; and Zion Chapel oil field. (AT)

  16. Establishment of an oil and gas database for increased recovery and characterization of oil and gas carbonate reservoir heterogeneity. [Jurassic Smackover Formation

    SciTech Connect

    Kopasaka-Merkel, D.C.; Moore, H.E. Jr.; Mann, S.D; Hall, D.R.

    1992-06-01

    This volume contains maps, well log correlated to lithology, porosity and permeability, structural cross section, graph of production history, porosity vs. natural log permeability plots; detailed core log, porosity vs. natural permeability plot for one lithofacies, paragenetic sequence and reservoir characterization sheet for the following fields in southwest Alabama: Stave Creek oil field; Sugar Ridge oil field; Toxey oil field, Turkey Creed oil field; Turnerville oil field, Uriah oil field; Vocation oil field; Wallace oil field; Wallers Creek oil field; West Appleton oil field; West Barrytown oil field; West Bend oil field; West Okatuppa Creed oil field; Wild Fork Creek oil field; Wimberly oil field; Womack Hill oil field; and Zion Chapel oil field. (AT)

  17. Fundamentals of gas flow in shale; What the unconventional reservoir industry can learn from the radioactive waste industry

    NASA Astrophysics Data System (ADS)

    Cuss, Robert; Harrington, Jon; Graham, Caroline

    2013-04-01

    Tight formations, such as shale, have a wide range of potential usage; this includes shale gas exploitation, hydrocarbon sealing, carbon capture & storage and radioactive waste disposal. Considerable research effort has been conducted over the last 20 years on the fundamental controls on gas flow in a range of clay-rich materials at the British Geological Survey (BGS) mainly focused on radioactive waste disposal; including French Callovo-Oxfordian claystone, Belgian Boom Clay, Swiss Opalinus Clay, British Oxford Clay, as well as engineered barrier material such as bentonite and concrete. Recent work has concentrated on the underlying physics governing fluid flow, with evidence of dilatancy controlled advective flow demonstrated in Callovo-Oxfordian claystone. This has resulted in a review of how advective gas flow is dealt with in Performance Assessment and the applicability of numerical codes. Dilatancy flow has been shown in Boom clay using nano-particles and is seen in bentonite by the strong hydro-mechanical coupling displayed at the onset of gas flow. As well as observations made at BGS, dilatancy flow has been shown by other workers on shale (Cuss et al., 2012; Angeli et al. 2009). As well as experimental studies using cores of intact material, fractured material has been investigated in bespoke shear apparatus. Experimental results have shown that the transmission of gas by fractures is highly localised, dependent on normal stress, varies with shear, is strongly linked with stress history, is highly temporal in nature, and shows a clear correlation with fracture angle. Several orders of magnitude variation in fracture transmissivity is seen during individual tests. Flow experiments have been conducted using gas and water, showing remarkably different behaviour. The radioactive waste industry has also noted a number of important features related to sample preservation. Differences in gas entry pressure have been shown across many laboratories and these may be attributed to different core preparation techniques. Careful re-stressing of core barrels and sealing techniques also ensure that experiments are conducted on near in situ condition. The construction of tunnels within shale clearly aids our understanding of the interaction of engineered operations (borehole drilling or tunnelling) on the behaviour of the rock. References: Angeli, M., Soldal, M., Skurtveit, E. and Aker, E., (2009) Experimental percolation of supercritical CO2 through a caprock. Energy Procedia 1, 3351-3358 Cuss, R.J., Harrington, J.F., Giot, R., and Auvray, C. (2012) Experimental observations of mechanical dilation at the onset of gas flow in Callovo-Oxfordian Claystone. Poster Presentation 5th International Meeting Clays in Natural and Engineered Barriers for Radioactive Waste Confinement, Montpellier, France October 22nd - 25th 2012.

  18. Litho-facies and paleotectonic background of hydrocarbon reservoirs in North Kalinov gas-condensate field (Tomsk Oblast)

    NASA Astrophysics Data System (ADS)

    Ten, T. G.; Panova, E. V.; Abramova, R. N.

    2015-11-01

    Based on micro-macroscopic core analysis, geophysical field data, contour mapping and referencing detailed litho-facies and paleotectonic investigation of Upper Jurassic pay thickness in North Kalinov gas condensate field was conducted. Paleotectonic analysis reflected the structure development history and determined the formation and distribution of oil fields.

  19. High-resolution geostatistical inversion of a seismic data set acquired in a Gulf of Mexico gas reservoir.

    E-print Network

    Torres-Verdín, Carlos

    High-resolution geostatistical inversion of a seismic data set acquired in a Gulf of Mexico gas, UNOCAL Corporation Summary Geostatistical inversion is applied on a Gulf-of-Mexico, 3D post-stack seismic in this paper is located in the Gulf of Mexico, off the coast of Louisiana. Existing development wells reach two

  20. CO(J = 1{yields}0) IN z > 2 QUASAR HOST GALAXIES: NO EVIDENCE FOR EXTENDED MOLECULAR GAS RESERVOIRS

    SciTech Connect

    Riechers, Dominik A.; Carilli, Christopher L.; Maddalena, Ronald J.; Hodge, Jacqueline; Walter, Fabian; Harris, Andrew I.; Baker, Andrew J.; Sharon, Chelsea E.; Wagg, Jeff; Vanden Bout, Paul A.; Weiss, Axel

    2011-09-20

    We report the detection of CO(J = 1{yields}0) emission in the strongly lensed high-redshift quasars IRAS F10214+4724 (z = 2.286), the Cloverleaf (z = 2.558), RX J0911+0551 (z = 2.796), SMM J04135+10277 (z = 2.846), and MG 0751+2716 (z = 3.200), using the Expanded Very Large Array and the Green Bank Telescope. We report lensing-corrected CO(J = 1{yields}0) line luminosities of L'{sub CO} = (0.34-18.4) x 10{sup 10} K km s{sup -1} pc{sup 2} and total molecular gas masses of M(H{sub 2}) = (0.27-14.7) x 10{sup 10} M{sub sun} for the sources in our sample. Based on CO line ratios relative to previously reported observations in J {>=} 3 rotational transitions and line excitation modeling, we find that the CO(J = 1{yields}0) line strengths in our targets are consistent with single, highly excited gas components with constant brightness temperature up to mid-J levels. We thus do not find any evidence for luminous-extended, low-excitation, low surface brightness molecular gas components. These properties are comparable to those found in z > 4 quasars with existing CO(J = 1{yields}0) observations. These findings stand in contrast to recent CO(J = 1{yields}0) observations of z {approx_equal} 2-4 submillimeter galaxies (SMGs), which have lower CO excitation and show evidence for multiple excitation components, including some low-excitation gas. These findings are consistent with the picture that gas-rich quasars and SMGs represent different stages in the early evolution of massive galaxies.

  1. Analysis of real-time reservoir monitoring : reservoirs, strategies, & modeling.

    SciTech Connect

    Mani, Seethambal S.; van Bloemen Waanders, Bart Gustaaf; Cooper, Scott Patrick; Jakaboski, Blake Elaine; Normann, Randy Allen; Jennings, Jim; Gilbert, Bob; Lake, Larry W.; Weiss, Chester Joseph; Lorenz, John Clay; Elbring, Gregory Jay; Wheeler, Mary Fanett; Thomas, Sunil G.; Rightley, Michael J.; Rodriguez, Adolfo; Klie, Hector; Banchs, Rafael; Nunez, Emilio J.; Jablonowski, Chris

    2006-11-01

    The project objective was to detail better ways to assess and exploit intelligent oil and gas field information through improved modeling, sensor technology, and process control to increase ultimate recovery of domestic hydrocarbons. To meet this objective we investigated the use of permanent downhole sensors systems (Smart Wells) whose data is fed real-time into computational reservoir models that are integrated with optimized production control systems. The project utilized a three-pronged approach (1) a value of information analysis to address the economic advantages, (2) reservoir simulation modeling and control optimization to prove the capability, and (3) evaluation of new generation sensor packaging to survive the borehole environment for long periods of time. The Value of Information (VOI) decision tree method was developed and used to assess the economic advantage of using the proposed technology; the VOI demonstrated the increased subsurface resolution through additional sensor data. Our findings show that the VOI studies are a practical means of ascertaining the value associated with a technology, in this case application of sensors to production. The procedure acknowledges the uncertainty in predictions but nevertheless assigns monetary value to the predictions. The best aspect of the procedure is that it builds consensus within interdisciplinary teams The reservoir simulation and modeling aspect of the project was developed to show the capability of exploiting sensor information both for reservoir characterization and to optimize control of the production system. Our findings indicate history matching is improved as more information is added to the objective function, clearly indicating that sensor information can help in reducing the uncertainty associated with reservoir characterization. Additional findings and approaches used are described in detail within the report. The next generation sensors aspect of the project evaluated sensors and packaging survivability issues. Our findings indicate that packaging represents the most significant technical challenge associated with application of sensors in the downhole environment for long periods (5+ years) of time. These issues are described in detail within the report. The impact of successful reservoir monitoring programs and coincident improved reservoir management is measured by the production of additional oil and gas volumes from existing reservoirs, revitalization of nearly depleted reservoirs, possible re-establishment of already abandoned reservoirs, and improved economics for all cases. Smart Well monitoring provides the means to understand how a reservoir process is developing and to provide active reservoir management. At the same time it also provides data for developing high-fidelity simulation models. This work has been a joint effort with Sandia National Laboratories and UT-Austin's Bureau of Economic Geology, Department of Petroleum and Geosystems Engineering, and the Institute of Computational and Engineering Mathematics.

  2. PHYSICS OF A PARTIALLY IONIZED GAS RELEVANT TO GALAXY FORMATION SIMULATIONS-THE IONIZATION POTENTIAL ENERGY RESERVOIR

    SciTech Connect

    Vandenbroucke, B.; De Rijcke, S.; Schroyen, J.; Jachowicz, N.

    2013-07-01

    Simulation codes for galaxy formation and evolution take on board as many physical processes as possible beyond the standard gravitational and hydrodynamical physics. Most of this extra physics takes place below the resolution level of the simulations and is added in a ''sub-grid'' fashion. However, these sub-grid processes affect the macroscopic hydrodynamical properties of the gas and thus couple to the ''on-grid'' physics that is explicitly integrated during the simulation. In this paper, we focus on the link between partial ionization and the hydrodynamical equations. We show that the energy stored in ions and free electrons constitutes a potential energy term which breaks the linear dependence of the internal energy on temperature. Correctly taking into account ionization hence requires modifying both the equation of state and the energy-temperature relation. We implemented these changes in the cosmological simulation code GADGET2. As an example of the effects of these changes, we study the propagation of Sedov-Taylor shock waves through an ionizing medium. This serves as a proxy for the absorption of supernova feedback energy by the interstellar medium. Depending on the density and temperature of the surrounding gas, we find that up to 50% of the feedback energy is spent ionizing the gas rather than heating it. Thus, it can be expected that properly taking into account ionization effects in galaxy evolution simulations will drastically reduce the effects of thermal feedback. To the best of our knowledge, this potential energy term is not used in current simulations of galaxy formation and evolution.

  3. New constraints on the sulfur reservoir in the dense interstellar medium provided by Spitzer observations of S I in shocked gas

    SciTech Connect

    Anderson, Dana E.; Bergin, Edwin A.; Maret, Sébastien

    2013-12-20

    We present observations of fine-structure line emission of atomic sulfur, iron, and rotational lines of molecular hydrogen in shocks associated with several Class 0 protostars obtained with the Infrared Spectrograph of the Spitzer Space Telescope. We use these observations to investigate the 'missing sulfur problem', that significantly less sulfur is found in dense regions of the interstellar medium (ISM) than in diffuse regions. For sources where the sulfur fine-structure line emission is co-spatial with the detected molecular hydrogen emission and in the presence of weak iron emission, we derive sulfur and H{sub 2} column densities for the associated molecule-dominated C-shocks. We find the S I abundance to be ?5%-10% of the cosmic sulfur abundance, indicating that atomic sulfur is a major reservoir of sulfur in shocked gas. This result suggests that in the quiescent dense ISM sulfur is present in some form that is released from grains as atoms, perhaps via sputtering, within the shock.

  4. FRACTURED PETROLEUM RESERVOIRS

    SciTech Connect

    Abbas Firoozabadi

    1999-06-11

    The four chapters that are described in this report cover a variety of subjects that not only give insight into the understanding of multiphase flow in fractured porous media, but they provide also major contribution towards the understanding of flow processes with in-situ phase formation. In the following, a summary of all the chapters will be provided. Chapter I addresses issues related to water injection in water-wet fractured porous media. There are two parts in this chapter. Part I covers extensive set of measurements for water injection in water-wet fractured porous media. Both single matrix block and multiple matrix blocks tests are covered. There are two major findings from these experiments: (1) co-current imbibition can be more efficient than counter-current imbibition due to lower residual oil saturation and higher oil mobility, and (2) tight fractured porous media can be more efficient than a permeable porous media when subjected to water injection. These findings are directly related to the type of tests one can perform in the laboratory and to decide on the fate of water injection in fractured reservoirs. Part II of Chapter I presents modeling of water injection in water-wet fractured media by modifying the Buckley-Leverett Theory. A major element of the new model is the multiplication of the transfer flux by the fractured saturation with a power of 1/2. This simple model can account for both co-current and counter-current imbibition and computationally it is very efficient. It can be orders of magnitude faster than a conventional dual-porosity model. Part II also presents the results of water injection tests in very tight rocks of some 0.01 md permeability. Oil recovery from water imbibition tests from such at tight rock can be as high as 25 percent. Chapter II discusses solution gas-drive for cold production from heavy-oil reservoirs. The impetus for this work is the study of new gas phase formation from in-situ process which can be significantly different from that of gas displacement processes. The work is of experimental nature and clarifies several misconceptions in the literature. Based on experimental results, it is established that the main reason for high efficiency of solution gas drive from heavy oil reservoirs is due to low gas mobility. Chapter III presents the concept of the alteration of porous media wettability from liquid-wetting to intermediate gas-wetting. The idea is novel and has not been introduced in the petroleum literature before. There are significant implications from such as proposal. The most direct application of intermediate gas wetting is wettability alteration around the wellbore. Such an alteration can significantly improve well deliverability in gas condensate reservoirs where gas well deliverability decreases below dewpoint pressure. Part I of Chapter III studies the effect of gravity, viscous forces, interfacial tension, and wettability on the critical condensate saturation and relative permeability of gas condensate systems. A simple phenomenological network model is used for this study, The theoretical results reveal that wettability significantly affects both the critical gas saturation and gas relative permeability. Gas relative permeability may increase ten times as contact angle is altered from 0{sup o} (strongly liquid wet) to 85{sup o} (intermediate gas-wetting). The results from the theoretical study motivated the experimental investigation described in Part II. In Part II we demonstrate that the wettability of porous media can be altered from liquid-wetting to gas-wetting. This part describes our attempt to find appropriate chemicals for wettability alteration of various substrates including rock matrix. Chapter IV provides a comprehensive treatment of molecular, pressure, and thermal diffusion and convection in porous media Basic theoretical analysis is presented using irreversible thermodynamics.

  5. AUTOMATED TECHNIQUE FOR FLOW MEASUREMENTS FROM MARIOTTE RESERVOIRS.

    USGS Publications Warehouse

    Constantz, Jim; Murphy, Fred

    1987-01-01

    The mariotte reservoir supplies water at a constant hydraulic pressure by self-regulation of its internal gas pressure. Automated outflow measurements from mariotte reservoirs are generally difficult because of the reservoir's self-regulation mechanism. This paper describes an automated flow meter specifically designed for use with mariotte reservoirs. The flow meter monitors changes in the mariotte reservoir's gas pressure during outflow to determine changes in the reservoir's water level. The flow measurement is performed by attaching a pressure transducer to the top of a mariotte reservoir and monitoring gas pressure changes during outflow with a programmable data logger. The advantages of the new automated flow measurement techniques include: (i) the ability to rapidly record a large range of fluxes without restricting outflow, and (ii) the ability to accurately average the pulsing flow, which commonly occurs during outflow from the mariotte reservoir.

  6. Foam as an agent to reduce gravity override effect during gas injection in oil reservoirs. Final report

    SciTech Connect

    Chiang, J.C.; Sanyal, S.K.; Castanier, L.M.; Brigham, W.E.; Shah, D.O.

    1980-08-01

    A two-dimensional, vertical, rectangular plexiglas model holding a 45-1/2 in. high by 11-3/8 in. wide by 1/4 in. thick sandpack (1.147 x 0.237 x 0.008 m) was used to investigate gravity override of injected gases in gas drive processes. Saturation of the sandpack by a surfactant solution instead of pure water sharply increased liquid recovery and breakthrough time in a nitrogen flooding process. The improvement in production was shown to be due to a reduction of gravity override caused by in-situ generation of foam at the gas-liquid interface. Solutions of two different surfactants (Suntech IX and IV) of various concentrations with different amounts of alcohol were studied to determine their effectiveness as foamers. Surface tension and rate of drainage of the foamers as functions of surfactant concentration were measured. In-situ foaming in the model increased generally with surfactant concentration until an optimum concentration was reached; above this concentration, additional amounts of surfactant had very little effect on the phenomenon. Alcohols seem to improve the performance of low molecular weight surfactants and exhibitied a negative effect on the others. A similar increase of recovery and delay in the breakthrough time was observed in the oil flooding process. A slug of surfactant solution was injected into the pack which was saturated with a white mineral oil and water at irreducible water saturation, and then nitrogen was injected. Gravity override was much less than in the cases when no surfactant was present.

  7. Exploring the effects of data quality, data worth, and redundancy of CO2 gas pressure and saturation data on reservoir characterization through PEST Inversion

    SciTech Connect

    Fang, Zhufeng; Hou, Zhangshuan; Lin, Guang; Engel, David W.; Fang, Yilin; Eslinger, Paul W.

    2014-04-01

    This study examined the impacts of reservoir properties on CO2 migration after subsurface injection and evaluated the possibility of characterizing reservoir properties using CO2 monitoring data such as saturation distribution. The injection reservoir was assumed to be located 1400-1500 m below the ground surface such that CO2 remained in the supercritical state. The reservoir was assumed to contain layers with alternating conductive and resistive properties, which is analogous to actual geological formations such as the Mount Simon Sandstone unit. The CO2 injection simulation used a cylindrical grid setting in which the injection well was situated at the center of the domain, which extended up to 8000 m from the injection well. The CO2 migration was simulated using the PNNL-developed simulator STOMP-CO2e (the water-salt-CO2 module). We adopted a nonlinear parameter estimation and optimization modeling software package, PEST, for automated reservoir parameter estimation. We explored the effects of data quality, data worth, and data redundancy on the detectability of reservoir parameters using CO2 saturation monitoring data, by comparing PEST inversion results using data with different levels of noises, various numbers of monitoring wells and locations, and different data collection spacing and temporal sampling intervals. This study yielded insight into the use of CO2 saturation monitoring data for reservoir characterization and how to design the monitoring system to optimize data worth and reduce data redundancy.

  8. High-temperature quartz cement and the role of stylolites in a deep gas reservoir, Spiro Sandstone, Arkoma Basin, USA

    USGS Publications Warehouse

    Worden, Richard H.; Morad, Sadoon; Spötl, C.; Houseknecht, D.W.; Riciputi, L.R.

    2000-01-01

    The Spiro Sandstone, a natural gas play in the central Arkoma Basin and the frontal Ouachita Mountains preserves excellent porosity in chloritic channel-fill sandstones despite thermal maturity levels corresponding to incipient metamorphism. Some wells, however, show variable proportions of a late-stage, non-syntaxial quartz cement, which post-dated thermal cracking of liquid hydrocarbons to pyrobitumen plus methane. Temperatures well in excess of 150°C and possibly exceeding 200°C are also suggested by (i) fluid inclusions in associated minerals; (ii) the fact that quartz post-dated high-temperature chlorite polytype IIb; (iii) vitrinite reflectance values of the Spiro that range laterally from 1.9 to ? 4%; and (iii) the occurrence of late dickite in these rocks. Oxygen isotope values of quartz cement range from 17.5 to 22.4‰ VSMOW (total range of individual in situ ion microprobe measurements) which are similar to those of quartz cement formed along high-amplitude stylolites (18.4–24.9‰). We favour a model whereby quartz precipitation was controlled primarily by the availability of silica via deep-burial stylolitization within the Spiro Sandstone. Burial-history modelling showed that the basin went from a geopressured to a normally pressured regime within about 10–15 Myr after it reached maximum burial depth. While geopressure and the presence of chlorite coats stabilized the grain framework and inhibited nucleation of secondary quartz, respectively, stylolites formed during the subsequent high-temperature, normal-pressured regime and gave rise to high-temperature quartz precipitation. Authigenic quartz growing along stylolites underscores their role as a significant deep-burial silica source in this sandstone.

  9. GEOMECHANICS IN RESERVOIR SIMULATION: OVERVIEW OF ...

    E-print Network

    P. LONGUEMARE

    2002-11-12

    Oil & Gas Science and Technology – Rev. IFP, Vol. 57 (2002), No. 5, pp. ... stress changes induced by reservoir thermal variations (cold water injection). The resulting ..... must be paid to the stability of the method (Bévillon and. Masson, 2000).

  10. The molecular gas reservoir of 6 low-metallicity galaxies from the Herschel Dwarf Galaxy Survey. A ground-based follow-up survey of CO(1-0), CO(2-1), and CO(3-2)

    NASA Astrophysics Data System (ADS)

    Cormier, D.; Madden, S. C.; Lebouteiller, V.; Hony, S.; Aalto, S.; Costagliola, F.; Hughes, A.; Rémy-Ruyer, A.; Abel, N.; Bayet, E.; Bigiel, F.; Cannon, J. M.; Cumming, R. J.; Galametz, M.; Galliano, F.; Viti, S.; Wu, R.

    2014-04-01

    Context. Observations of nearby starburst and spiral galaxies have revealed that molecular gas is the driver of star formation. However, some nearby low-metallicity dwarf galaxies are actively forming stars, but CO, the most common tracer of this reservoir, is faint, leaving us with a puzzle about how star formation proceeds in these environments. Aims: We aim to quantify the molecular gas reservoir in a subset of 6 galaxies from the Herschel Dwarf Galaxy Survey with newly acquired CO data and to link this reservoir to the observed star formation activity. Methods: We present CO(1-0), CO(2-1), and CO(3-2) observations obtained at the ATNF Mopra 22-m, APEX, and IRAM 30-m telescopes, as well as [C ii] 157?m and [O i] 63?m observations obtained with the Herschel/PACS spectrometer in the 6 low-metallicity dwarf galaxies: Haro 11, Mrk 1089, Mrk 930, NGC 4861, NGC 625, and UM 311. We derived their molecular gas masses from several methods, including using the CO-to-H2 conversion factor XCO (both Galactic and metallicity-scaled values) and dust measurements. The molecular and atomic gas reservoirs were compared to the star formation activity. We also constrained the physical conditions of the molecular clouds using the non-LTE code RADEX and the spectral synthesis code Cloudy. Results: We detect CO in 5 of the 6 galaxies, including first detections in Haro 11 (Z ~ 0.4 Z?), Mrk 930 (0.2 Z?), and UM 311 (0.5 Z?), but CO remains undetected in NGC 4861 (0.2 Z?). The CO luminosities are low, while [C ii] is bright in these galaxies, resulting in [C ii]/CO(1-0) ? 10 000. Our dwarf galaxies are in relatively good agreement with the Schmidt-Kennicutt relation for total gas. They show short molecular depletion timescales, even when considering metallicity-scaled XCO factors. Those galaxies are dominated by their H i gas, except Haro 11, which has high star formation efficiency and is dominated by ionized and molecular gas. We determine the mass of each ISM phase in Haro 11 using Cloudy and estimate an equivalent XCO factor that is 10 times higher than the Galactic value. Overall, our results confirm the emerging picture that CO suffers from significant selective photodissociation in low-metallicity dwarf galaxies.

  11. Installation of a Devonian Shale Reservoir Testing Facility and acquisition of reservoir property measurements

    SciTech Connect

    Locke, C.D.; Salamy, S.P.

    1991-09-01

    In October, a contract was awarded for the Installation of a Devonian Shale Reservoir Testing Facility and Acquisition of Reservoir Property measurements from wells in the Michigan, Illinois, and Appalachian Basins. Geologic and engineering data collected through this project will provide a better understanding of the mechanisms and conditions controlling shale gas production. This report summarizes the results obtained from the various testing procedures used at each wellsite and the activities conducted at the Reservoir Testing Facility.

  12. Installation of a Devonian Shale Reservoir Testing Facility and acquisition of reservoir property measurements. Final report

    SciTech Connect

    Locke, C.D.; Salamy, S.P.

    1991-09-01

    In October, a contract was awarded for the Installation of a Devonian Shale Reservoir Testing Facility and Acquisition of Reservoir Property measurements from wells in the Michigan, Illinois, and Appalachian Basins. Geologic and engineering data collected through this project will provide a better understanding of the mechanisms and conditions controlling shale gas production. This report summarizes the results obtained from the various testing procedures used at each wellsite and the activities conducted at the Reservoir Testing Facility.

  13. Comprehensive Analysis of Enhanced CBM Production via CO2 Injection Using a Surrogate Reservoir Model Jalal Jalali, Shahab D. Mohaghegh, Dept. of Petroleum & Natural Gas Engineering, West Virginia University

    E-print Network

    Mohaghegh, Shahab

    Comprehensive Analysis of Enhanced CBM Production via CO2 Injection Using a Surrogate Reservoir Reservoir simulation is the industry standard for reservoir management. Complex reservoir models usually contain hundreds of thousands or millions of grid cells. Complexity of reservoir models can result in long

  14. 30 CFR 250.1154 - How do I determine if my reservoir is sensitive?

    Code of Federal Regulations, 2011 CFR

    2011-07-01

    ... 30 Mineral Resources 2 2011-07-01 2011-07-01 false How do I determine if my reservoir is sensitive... SHELF Oil and Gas Production Requirements Classifying Reservoirs § 250.1154 How do I determine if my reservoir is sensitive? (a) You must determine whether each reservoir is sensitive. You must classify...

  15. Robust Optimization of Oil Reservoir Flooding G.M. van Essen, M.J. Zandvliet,

    E-print Network

    Van den Hof, Paul

    Robust Optimization of Oil Reservoir Flooding G.M. van Essen, M.J. Zandvliet, P.M.J. Van den Hof and gas from petroleum reservoirs. One of these new developments is the introduction of so-called "smart to geological uncertainty inherent to reservoir modelling, the mismatch between the reservoir model and the real

  16. A New Method for History Matching and Forecasting Shale Gas/Oil Reservoir Production Performance with Dual and Triple Porosity Models 

    E-print Network

    Samandarli, Orkhan

    2012-10-19

    , at the top of the list for valuable courses that are taught at Texas A&M University. I also want to acknowledge my colleagues in the Reservoir Modeling Consortium: Hasan Al-Ahmadi, Hassan Hamam, Anas Almarzooq, Pahala Sinurat, vii Salman Mengal, Haider...

  17. Production-induced changes in reservoir geomechanics

    NASA Astrophysics Data System (ADS)

    Amoyedo, Sunday O.

    Sand production remains a source of concern in both conventional and heavy oil production. Porosity increase and changes in local stress magnitude, which often enhance permeability, have been associated with severe sanding. On the other hand, sand production has been linked to a large number of field incidences involving loss of well integrity, casing collapse and corrosion of down-hole systems. It also poses problems for separators and transport facilities. Numerous factors such as reservoir consolidation, well deviation angle through the reservoir, perforation size, grain size, capillary forces associated with water cut, flow rate and most importantly reservoir strain resulting from pore pressure depletion contribute to reservoir sanding. Understanding field-specific sand production patterns in mature fields and poorly consolidated reservoirs is vital in identifying sand-prone wells and guiding remedial activities. Reservoir strain analysis of Forties Field, located in the UK sector of the North Sea, shows that the magnitude of the production-induced strain, part of which is propagated to the base of the reservoir, is of the order of 0.2 %, which is significant enough to impact the geomechanical properties of the reservoir. Sand production analysis in the field shows that in addition to poor reservoir consolidation, a combined effect of repeated perforation, high well deviation, reservoir strain and high fluid flow rate have contributed significantly to reservoir sanding. Knowledge of reservoir saturation variation is vital for in-fill well drilling, while information on reservoir stress variation provides a useful guide for sand production management, casing design, injector placement and production management. Interpreting time-lapse difference is enhanced by decomposing time-lapse difference into saturation, pressure effects and changes in rock properties (e.g. porosity) especially in highly compacting reservoirs. Analyzing the stress and saturation sensitivity of the reservoir and overburden shale of Forties Field, I observe that while pore pressure variations have not been significant in most parts of the field, a relatively higher decrease in pore pressure in a region of the reservoir has affected the geomechanical properties of both reservoir and overlying rock strata . I found that strain development in the field accounts, in part, for increased reservoir sand production and a negative velocity change in the overburden, which provides an indication of dilation. I use changes in the AVO intercept and gradient calibrated with laboratory measurements to decouple the time-lapse (4D) difference into saturation and pressure changes. Furthermore, I propose a new modification to time-lapse AVO inversion workflows to account for the effect of porosity change in measurements of time-lapse difference. This is particularly crucial in highly-compacting chalk and poorly consolidated clastic reservoirs. Rock-physics-driven inversion of 3D pre-stack seismic data plays a prominent role in the characterization of both reservoir and overburden rocks. Understanding the rock physics of the overburden rock is required for efficient production of the reservoir and to safeguard wellbore, down-hole assembly and supporting surface facilities. Taking Forties Field as a case study, I observe that while instability and subsequent failure of the overburden in the field can be linked to the rapid decrease of the unconfined compressive strength (UCS) at inclinations close to 45 degrees to the bedding plan, some zones in the overburden are characterized by extreme weakness regardless of the well angle through the rock. I use the correlation between unconfined compressive strength and elastic moduli (Young's and Bulk moduli), coupled with the results of simultaneous inversion to derive 3D elastic moduli, calibrated to laboratory measurements, to characterize the zones of extreme weakness. Time-lapse gravimetry continues to find increasing application in reservoir monitoring, typically in gas reservoirs and reservoirs used for CO2 sequestration.

  18. Please cite this article in press as: Gilfillan, S.M.V., et al., He and Ne as tracers of natural CO2 migration up a fault from a deep reservoir. Int. J. Greenhouse Gas Control (2011), doi:10.1016/j.ijggc.2011.08.008

    E-print Network

    Wilkinson, Mark

    2011-01-01

    of Greenhouse Gas Control journal homepage: www.elsevier.com/locate/ijggc He and Ne as tracers of natural CO2Please cite this article in press as: Gilfillan, S.M.V., et al., He and Ne as tracers of natural CO2 migration up a fault from a deep reservoir. Int. J. Greenhouse Gas Control (2011), doi:10.1016/j

  19. Status of Norris Reservoir

    SciTech Connect

    Not Available

    1990-09-01

    This is one in a series of reports prepared by the Tennessee Valley Authority (TVA) for those interested in the conditions of TVA reservoirs. This overview of Norris Reservoir summarizes reservoir and watershed characteristics, reservoir uses, conditions that impair reservoir uses, water quality and aquatic biological conditions, and activities of reservoir management agencies. This information was extracted from the most up-to-date publications and data available, and from interviews with water resource professionals in various federal, state, and local agencies, and in public and private water supply and wastewater treatment facilities. 14 refs., 3 figs.

  20. Carbon emission from global hydroelectric reservoirs revisited.

    PubMed

    Li, Siyue; Zhang, Quanfa

    2014-12-01

    Substantial greenhouse gas (GHG) emissions from hydropower reservoirs have been of great concerns recently, yet the significant carbon emitters of drawdown area and reservoir downstream (including spillways and turbines as well as river reaches below dams) have not been included in global carbon budget. Here, we revisit GHG emission from hydropower reservoirs by considering reservoir surface area, drawdown zone and reservoir downstream. Our estimates demonstrate around 301.3 Tg carbon dioxide (CO2)/year and 18.7 Tg methane (CH4)/year from global hydroelectric reservoirs, which are much higher than recent observations. The sum of drawdown and downstream emission, which is generally overlooked, represents 42 % CO2 and 67 % CH4 of the total emissions from hydropower reservoirs. Accordingly, the global average emissions from hydropower are estimated to be 92 g CO2/kWh and 5.7 g CH4/kWh. Nonetheless, global hydroelectricity could currently reduce approximate 2,351 Tg CO2eq/year with respect to fuel fossil plant alternative. The new findings show a substantial revision of carbon emission from the global hydropower reservoirs. PMID:24943886

  1. Adsorption of water vapor on reservoir rocks

    SciTech Connect

    Not Available

    1993-07-01

    Progress is reported on: adsorption of water vapor on reservoir rocks; theoretical investigation of adsorption; estimation of adsorption parameters from transient experiments; transient adsorption experiment -- salinity and noncondensible gas effects; the physics of injection of water into, transport and storage of fluids within, and production of vapor from geothermal reservoirs; injection optimization at the Geysers Geothermal Field; a model to test multiwell data interpretation for heterogeneous reservoirs; earth tide effects on downhole pressure measurements; and a finite-difference model for free surface gravity drainage well test analysis.

  2. Reservoir Operation in Texas 

    E-print Network

    Wurbs, Ralph A.

    1985-01-01

    demands being placed upon the surface water resources. The climate of the state is characterized by floods and droughts. Reservoirs are necessary to control and utilize the highly variable streamflow. Numerous reservoirs have been constructed to facilitate...

  3. Predicting reservoir sedimentation 

    E-print Network

    Wooten, Stephanie

    1997-01-01

    sediment accumulation versus exceedance frequency relationship for a specified future multiple-year time period. The sediment prediction procedure was applied to Somerville, Granger, and Aquilla Reservoirs. For each reservoir, the methodology was time...

  4. Potential mammalian filovirus reservoirs

    E-print Network

    Peterson, A. Townsend; Carroll, Darin S.; Mills, James N.; Johnson, Karl M.

    2004-12-01

    Ebola and Marburg viruses are maintained in unknown reservoir species; spillover into human populations results in occasional human cases or epidemics. We attempted to narrow the list of possibilities regarding the identity of those reservoir...

  5. Fractured shale reservoirs: Towards a realistic model

    SciTech Connect

    Hamilton-Smith, T.

    1996-09-01

    Fractured shale reservoirs are fundamentally unconventional, which is to say that their behavior is qualitatively different from reservoirs characterized by intergranular pore space. Attempts to analyze fractured shale reservoirs are essentially misleading. Reliance on such models can have only negative results for fractured shale oil and gas exploration and development. A realistic model of fractured shale reservoirs begins with the history of the shale as a hydrocarbon source rock. Minimum levels of both kerogen concentration and thermal maturity are required for effective hydrocarbon generation. Hydrocarbon generation results in overpressuring of the shale. At some critical level of repressuring, the shale fractures in the ambient stress field. This primary natural fracture system is fundamental to the future behavior of the fractured shale gas reservoir. The fractures facilitate primary migration of oil and gas out of the shale and into the basin. In this process, all connate water is expelled, leaving the fractured shale oil-wet and saturated with oil and gas. What fluids are eventually produced from the fractured shale depends on the consequent structural and geochemical history. As long as the shale remains hot, oil production may be obtained. (e.g. Bakken Shale, Green River Shale). If the shale is significantly cooled, mainly gas will be produced (e.g. Antrim Shale, Ohio Shale, New Albany Shale). Where secondary natural fracture systems are developed and connect the shale to aquifers or to surface recharge, the fractured shale will also produce water (e.g. Antrim Shale, Indiana New Albany Shale).

  6. The Reservoir architecture for

    E-print Network

    Elmroth, Erik

    The Reservoir model and architecture for open federated cloud computing B. Rochwerger D. Breitgand and managed across clouds on an on- demand basis at competitive costs with high-quality service. The Reservoir. To this end, Reservoir could leverage and extend the advantages of virtualization and embed autonomous

  7. Application of integrated reservoir management and reservoir characterization to optimize infill drilling

    SciTech Connect

    1997-04-01

    This project has used a multi-disciplinary approach employing geology, geophysics, and engineering to conduct advanced reservoir characterization and management activities to design and implement an optimized infill drilling program at the North Robertson (Clearfork) Unit in Gaines County, Texas. The activities during the first Budget Period consisted of developing an integrated reservoir description from geological, engineering, and geostatistical studies, and using this description for reservoir flow simulation. Specific reservoir management activities were identified and tested. The geologically targeted infill drilling program currently being implemented is a result of this work. A significant contribution of this project is to demonstrate the use of cost-effective reservoir characterization and management tools that will be helpful to both independent and major operators for the optimal development of heterogeneous, low permeability shallow-shelf carbonate (SSC) reservoirs. The techniques that are outlined for the formulation of an integrated reservoir description apply to all oil and gas reservoirs, but are specifically tailored for use in the heterogeneous, low permeability carbonate reservoirs of West Texas.

  8. Socioeconomic impact of infill drilling recovery from carbonate reservoirs in the Permian Basin, West Texas 

    E-print Network

    Jagoe, Bryan Keith

    1994-01-01

    This investigative study presents results on the socioeconomic impact of infill drilling recovery from carbonate reservoirs in the Permian Basin. The amount of incremental oil and gas production from infill drilling in 37 carbonate reservoir units...

  9. Data quality enhancement in oil reservoir operations : an application of IPMAP

    E-print Network

    Lin, Paul Hong-Yi

    2012-01-01

    This thesis presents a study of data quality enhancement opportunities in upstream oil and gas industry. Information Product MAP (IPMAP) methodology is used in reservoir pressure and reservoir simulation data, to propose ...

  10. Status of Cherokee Reservoir

    SciTech Connect

    Not Available

    1990-08-01

    This is the first in a series of reports prepared by Tennessee Valley Authority (TVA) for those interested in the conditions of TVA reservoirs. This overviews of Cherokee Reservoir summarizes reservoir and watershed characteristics, reservoir uses and use impairments, water quality and aquatic biological conditions, and activities of reservoir management agencies. This information was extracted from the most current reports, publications, and data available, and interviews with water resource professionals in various Federal, state, and local agencies and in public and private water supply and wastewater treatment facilities. 11 refs., 4 figs., 1 tab.

  11. Status of Wheeler Reservoir

    SciTech Connect

    Not Available

    1990-09-01

    This is one in a series of status reports prepared by the Tennessee Valley Authority (TVA) for those interested in the conditions of TVA reservoirs. This overview of Wheeler Reservoir summarizes reservoir purposes and operation, reservoir and watershed characteristics, reservoir uses and use impairments, and water quality and aquatic biological conditions. The information presented here is from the most recent reports, publications, and original data available. If no recent data were available, historical data were summarized. If data were completely lacking, environmental professionals with special knowledge of the resource were interviewed. 12 refs., 2 figs.

  12. The role of technology and decision analysis in reservoir management

    SciTech Connect

    Thakur, G.C.

    1995-11-01

    The need to enhance recovery from the vast amount of remaining oil- and gas-in-place requires better reservoir management practices. Proper timing has a profound effect on the implementation of sound reservoir management technology on recovery efficiency. With this in mind, the goal should be to maximize volumetric sweep early in the project`s life. Trying to squeeze more oil from marginal projects will generally yield marginal to average results. The purpose of this paper is to identify the major attributes of a successful reservoir management organization and program and outline critical reservoir management issues and technical areas, and document benefits received from a team approach to reservoir management. In addition, the decision analysis technique is used to look at value creation as a result of reservoir management activities. Any development of new reservoir management technology and its applications must be subjected to thorough economic screening so that use and support of such technology is justified based upon business needs.

  13. SEISMIC ATTENUATION FOR RESERVOIR CHARACTERIZATION

    SciTech Connect

    Joel Walls; M.T. Taner; Naum Derzhi; Gary Mavko; Jack Dvorkin

    2003-12-01

    We have developed and tested technology for a new type of direct hydrocarbon detection. The method uses inelastic rock properties to greatly enhance the sensitivity of surface seismic methods to the presence of oil and gas saturation. These methods include use of energy absorption, dispersion, and attenuation (Q) along with traditional seismic attributes like velocity, impedance, and AVO. Our approach is to combine three elements: (1) a synthesis of the latest rock physics understanding of how rock inelasticity is related to rock type, pore fluid types, and pore microstructure, (2) synthetic seismic modeling that will help identify the relative contributions of scattering and intrinsic inelasticity to apparent Q attributes, and (3) robust algorithms that extract relative wave attenuation attributes from seismic data. This project provides: (1) Additional petrophysical insight from acquired data; (2) Increased understanding of rock and fluid properties; (3) New techniques to measure reservoir properties that are not currently available; and (4) Provide tools to more accurately describe the reservoir and predict oil location and volumes. These methodologies will improve the industry's ability to predict and quantify oil and gas saturation distribution, and to apply this information through geologic models to enhance reservoir simulation. We have applied for two separate patents relating to work that was completed as part of this project.

  14. Dolomite reservoirs: Porosity evolution and reservoir characteristics

    SciTech Connect

    Sun, S.Q.

    1995-02-01

    Systematic analyses of the published record of dolomite reservoirs worldwide reveal that the majority of hydrocarbon-producing dolomite reservoirs occurs in (1) peritidal-dominated carbonate, (2) subtidal carbonate associated with evaporitic tidal flat/lagoon, (3) subtidal carbonate associated with basinal evaporite, and (4) nonevaporitic carbonate sequence associated with topographic high/unconformity, platform-margin buildup or fault/fracture. Reservoir characteristics vary greatly from one dolomite type to another depending upon the original sediment fabric, the mechanism by which dolomite was formed, and the extent to which early formed dolomite was modified by post-dolomitization diagenetic processes (e.g., karstification, fracturing, and burial corrosion). This paper discusses the origin of dolomite porosity and demonstrates the porosity evolution and reservoir characteristics of different dolomite types.

  15. Top-Down, Intelligent Reservoir Model

    NASA Astrophysics Data System (ADS)

    Mohaghegh, Shahab

    2010-05-01

    Conventional reservoir simulation and modeling is a bottom-up approach. It starts with building a geological model of the reservoir that is populated with the best available petrophysical and geophysical information at the time of development. Engineering fluid flow principles are added and solved numerically so as to arrive at a dynamic reservoir model. The dynamic reservoir model is calibrated using the production history of multiple wells and the history matched model is used to strategize field development in order to improve recovery. Top-Down, Intelligent Reservoir Modeling approaches the reservoir simulation and modeling from an opposite angle by attempting to build a realization of the reservoir starting with the measured well production behavior (history). The production history is augmented by core, log, well test and seismic data in order to increase the accuracy of the Top-Down modeling technique. Although not intended as a substitute for the conventional reservoir simulation of large, complex fields, this novel approach to reservoir modeling can be used as an alternative (at a fraction of the cost) to conventional reservoir simulation and modeling in cases where performing conventional modeling is cost (and man-power) prohibitive. In cases where a conventional model of a reservoir already exists, Top-Down modeling should be considered as a compliment to, rather than a competition for the conventional technique, to provide an independent look at the data coming from the reservoir/wells for optimum development strategy and recovery enhancement. Top-Down, Intelligent Reservoir Modeling starts with well-known reservoir engineering techniques such as Decline Curve Analysis, Type Curve Matching, History Matching using single well numerical reservoir simulation, Volumetric Reserve Estimation and calculation of Recovery Factors for all the wells (individually) in the field. Using statistical techniques multiple Production Indicators (3, 6, and 9 months cum. production as well as 1, 3, 5, and 10 year cum. oil, gas and water production and Gas Oil Ratio and Water Cut) are calculated. These analyses and statistics generate a large volume of data and information that are snapshots of reservoir behavior in discrete slices of time and space. This large volume of data is processed using state-of-the-art in artificial intelligence and data mining (neural modeling, genetic optimization and fuzzy pattern recognition), first using a set of discrete modeling techniques to generate production related predictive models of well behavior. The set of discrete, intelligent models are then integrated using a continuous fuzzy pattern recognition algorithm in order to arrive at a cohesive picture and model of the reservoir as a whole. The Top-Down, Intelligent Reservoir Model is calibrated using the most recent set of wells that have been drilled. The calibrated model is used for field development strategies to improve and enhance hydrocarbon recovery.

  16. MULTIDISCIPLINARY IMAGING OF ROCK PROPERTIES IN CARBONATE RESERVOIRS FOR FLOW-UNIT TARGETING

    SciTech Connect

    Stephen C. Ruppel

    2005-02-01

    Despite declining production rates, existing reservoirs in the US contain large quantities of remaining oil and gas that constitute a huge target for improved diagnosis and imaging of reservoir properties. The resource target is especially large in carbonate reservoirs, where conventional data and methodologies are normally insufficient to resolve critical scales of reservoir heterogeneity. The objectives of the research described in this report were to develop and test such methodologies for improved imaging, measurement, modeling, and prediction of reservoir properties in carbonate hydrocarbon reservoirs. The focus of the study is the Permian-age Fullerton Clear Fork reservoir of the Permian Basin of West Texas. This reservoir is an especially appropriate choice considering (a) the Permian Basin is the largest oil-bearing basin in the US, and (b) as a play, Clear Fork reservoirs have exhibited the lowest recovery efficiencies of all carbonate reservoirs in the Permian Basin.

  17. 95. BOUQUET RESERVOIR LOOKING UP VALLEY TO RESERVOIR LOOKING EAST ...

    Library of Congress Historic Buildings Survey, Historic Engineering Record, Historic Landscapes Survey

    95. BOUQUET RESERVOIR LOOKING UP VALLEY TO RESERVOIR LOOKING EAST - Los Angeles Aqueduct, From Lee Vining Intake (Mammoth Lakes) to Van Norman Reservoir Complex (San Fernando Valley), Los Angeles, Los Angeles County, CA

  18. The Importance of Geochemical Parameters and Shale Composition on Rock Mechanical Properties of Gas Shale Reservoirs: a Case Study From the Kockatea Shale and Carynginia Formation From the Perth Basin, Western Australia

    NASA Astrophysics Data System (ADS)

    Labani, Mohammad Mahdi; Rezaee, Reza

    2015-05-01

    Evaluation of the gas shale mechanical properties is very important screening criteria for determining the potential intervals for hydraulic fracturing and as a result in gas shale sweet spot mapping. Young's modulus and Poisson's ratio are two controlling mechanical properties that dictate the brittleness of the gas shale layers. These parameters can be determined in the laboratory by testing the rock sample under different conditions (static method) or can be calculated using the well-logging data including sonic and density log data (dynamic method). This study investigates the importance of the shale composition and geochemical parameters on the Young's modulus and Poisson's ratio using log data. The data set of this study is coming from five different wells targeting the Kockatea Shale and Carynginia formation, two potential gas shale formations in the Perth Basin, Western Australia. The results show that converse to the common idea the effect of organic matter quantity and maturity on the rock mechanical properties of the gas shale reservoirs is not so much prominent, while the composition of the rock has an important effect on these properties. Considering the weight percentage of shale composition and organic matter quantity it could be concluded that effect of these parameters on rock mechanical properties is dependent on their weight contribution on the shale matrix. As well as effect of thermal maturity on the shale matrix and consequently on the rock mechanical properties of the shales is dependent on the organic matter content itself; therefore, obviously with a low organic matter content thermal maturity has no prominent effect on the brittleness as well.

  19. Coastal barrier reservoirs

    SciTech Connect

    Richardson, J.G.; Sangree, J.B.; Sneider, R.M.

    1988-09-01

    Coastal barriers are long, narrow, wave-built, sandy islands parallel to the shore. Part of the island has a beach, but many have sand dunes and areas of vegetation above the high-tide line. A lagoon or estuary is behind the barrier on the protected side away from the ocean. Coastal barrier reservoirs can hold major accumulations of oil and gas. Coastal barriers can build by three major processes; addition of sand washed onto the beach from breaker bars, addition on one end by sand washed from the other end and moved by riptides, and deposition of sand into the lagoon by waves breaking over the barrier during storms. Galveston Island, offshore Texas, is a good example of a modern coastal barrier. Waves in the Gulf of Mexico have sufficient energy to transport and deposit fine-grained sand on Galveston Island. (Fine-grained sand is the coarsest sand available in upper Texas coastal waters). Other examples of modern coastal barriers are found in the Gulf of California, where medium-sized sands are deposited. An example of an ancient deposit was found in the Elk City field, where the barrier beach was composed of well-sorted gravel and coarse sand.

  20. Pierre Y. Julien Reservoir Sedimentation

    E-print Network

    Julien, Pierre Y.

    1 Pierre Y. Julien Reservoir Sedimentation: Problems and Solutions Department of Civil Engineering Objectives Brief overview of Solutions to Reservoir Sedimentation Problems: 1. Upland Erosion Control; 2. River Sedimentation Solutions; 3. Reservoir Sedimentation Solutions. 1. Upland Erosion Control Tala HE

  1. Validation status of the VARGOW oil reservoir model

    SciTech Connect

    Mayer, D.W.; Arnold, E.M.; Bowen, W.M.; Gutknecht, P.J.

    1980-10-01

    VARGOW, a variable gas-oil-water reservoir model, provides recovery estimates suitable for assessing various reservoir production policies and regulations. Data were collected for a number of reservoirs. From this data base, three reservoirs approximating the model assumptions were selected for model testing purposes. For all three reservoirs, it has been possible to simulate the observed pressures in both interpolative and extrapolative modes. Simulating the gas/oil ratio (GOR) has not been as successful, however. The VARGOW model will predict physically unrealistic results if the reservoir being simulated is not initially at the bubble point pressure of the reservoir fluid. If the discovery pressure is slightly above the bubble point, adjustments to initial conditions can be made using a method that has been outlined in this report. If the discovery pressure is considerably above the bubble point, it is recommended that an undersaturated reservoir model be employed until the bubble point is reached. For simulating reservoirs whose discovery pressure is below the bubble point, the VARGOW model must be modified.

  2. 30 CFR 250.1150 - What are the general reservoir production requirements?

    Code of Federal Regulations, 2014 CFR

    2014-07-01

    ... 30 Mineral Resources 2 2014-07-01 2014-07-01 false What are the general reservoir production... Gas Production Requirements General § 250.1150 What are the general reservoir production requirements? You must produce wells and reservoirs at rates that provide for economic development while...

  3. 30 CFR 250.1150 - What are the general reservoir production requirements?

    Code of Federal Regulations, 2013 CFR

    2013-07-01

    ... 30 Mineral Resources 2 2013-07-01 2013-07-01 false What are the general reservoir production... Gas Production Requirements General § 250.1150 What are the general reservoir production requirements? You must produce wells and reservoirs at rates that provide for economic development while...

  4. 30 CFR 250.1150 - What are the general reservoir production requirements?

    Code of Federal Regulations, 2012 CFR

    2012-07-01

    ... 30 Mineral Resources 2 2012-07-01 2012-07-01 false What are the general reservoir production... Gas Production Requirements General § 250.1150 What are the general reservoir production requirements? You must produce wells and reservoirs at rates that provide for economic development while...

  5. 30 CFR 250.1155 - What information must I submit for sensitive reservoirs?

    Code of Federal Regulations, 2011 CFR

    2011-07-01

    ... reservoirs? 250.1155 Section 250.1155 Mineral Resources BUREAU OF OCEAN ENERGY MANAGEMENT, REGULATION, AND... SHELF Oil and Gas Production Requirements Classifying Reservoirs § 250.1155 What information must I submit for sensitive reservoirs? You must submit to the Regional Supervisor an original and two copies...

  6. Coupling between a reservoir and a surface facilities network Supervisor: Johan Romate (Shell/TUD)

    E-print Network

    Vuik, Kees

    Coupling between a reservoir and a surface facilities network Supervisor: Johan Romate (Shell/TUD) Problem background The production of oil and gas from a reservoir is aided by the use of simulation models. For instance, once wells have been drilled and production has started, reservoir simulators are used to predict

  7. Induced Microearthquake Patterns in Hydrocarbon and Geothermal Reservoirs: W. Scott Phillips

    E-print Network

    Induced Microearthquake Patterns in Hydrocarbon and Geothermal Reservoirs: A Review W. Scott or production of fluids can induce microseismic events in hydrocarbon and geothermal reservoirs. By deploying Patterns in Reservoirs Key Words: induced microseismicity, geothermal, oil and gas, fluid flow, location

  8. Reservoir characterization using wavelet transforms

    NASA Astrophysics Data System (ADS)

    Rivera Vega, Nestor

    Automated detection of geological boundaries and determination of cyclic events controlling deposition can facilitate stratigraphic analysis and reservoir characterization. This study applies the wavelet transformation, a recent advance in signal analysis techniques, to interpret cyclicity, determine its controlling factors, and detect zone boundaries. We tested the cyclostratigraphic assessments using well log and core data from a well in a fluvio-eolian sequence in the Ormskirk Sandstone, Irish Sea. The boundary detection technique was tested using log data from 10 wells in the Apiay field, Colombia. We processed the wavelet coefficients for each zone of the Ormskirk Formation and determined the wavelengths of the strongest cyclicities. Comparing these periodicities with Milankovitch cycles, we found a strong correspondence of the two. This suggests that climate exercised an important control on depositional cyclicity, as had been concluded in previous studies of the Ormskirk Sandstone. The wavelet coefficients from the log data in the Apiay field were combined to form features. These vectors were used in conjunction with pattern recognition techniques to perform detection in 7 boundaries. For the upper two units, the boundary was detected within 10 feet of their actual depth, in 90% of the wells. The mean detection performance in the Apiay field is 50%. We compared our method with other traditional techniques which do not focus on selecting optimal features for boundary identification. Those methods resulted in detection performances of 40% for the uppermost boundary, which lag behind the 90% performance of our method. Automated determination of geologic boundaries will expedite studies, and knowledge of the controlling deposition factors will enhance stratigraphic and reservoir characterization models. We expect that automated boundary detection and cyclicity analysis will prove to be valuable and time-saving methods for establishing correlations and their uncertainties in many types of oil and gas reservoirs, thus facilitating reservoir exploration and management.

  9. The Role of Acidizing in Proppant Fracturing in Carbonate Reservoirs 

    E-print Network

    Densirimongkol, Jurairat

    2010-10-12

    Today, optimizing well stimulation techniques to obtain maximum return of investment is still a challenge. Hydraulic fracturing is a typical application to improve ultimate recovery from oil and gas reservoirs. Proppant fracturing has become one...

  10. A Marine Controlled-Source Electromagnetic Study for the Characterization of Methane Hydrate and Free Gas Reservoirs at the Nyegga CNE03 Pockmark, Norwegian Sea

    NASA Astrophysics Data System (ADS)

    Attias, E.; Weitemeyer, K.; Sinha, M. C.; Minshull, T. A.; Jegen, M. D.; Berndt, C.

    2014-12-01

    In recent years, gas hydrate deposits have attracted growing interest from both academic and industry research, due to their potential as an unconventional energy resource, role in climate change and concern as a geohazard to various marine infrastructures. Methane hydrates are known to accommodate widespread regions of sea sediments at depths ranging from 130 to 2,000 m along offshore continental margins, normally located close to the seafloor and often presenting pockmarks that are underlain by chimney-like structures. The Nyegga region is situated along the west Norwegian continental slope and characterized by an extensive pockmark field. The Nyegga pockmarks are manifested by bathymetric troughs, seep-associated organisms, and rich methane-derived authigenic carbonate rocks. A controlled-source electromagnetic (CSEM) survey was performed along Nyegga CNE03 Pockmark, where high-resolution 3D seismic data was previously collected and analyzed. The aim of this CSEM study is to characterize the hydrate and free gas distribution along the CNE03 pockmark region. 2D CSEM inversions and pseudosections were computed using the data acquired by ocean bottom electrical field receivers (OBE) and the 3-axis towed receiver (Vulcan), respectively. Initial results from both data sets, confirm the existence of a subtle though distinctive resistivity anomaly structure at the CNE03 pockmark, suggesting a shallow anomaly at the chimney center, likely to result from the presence of gas hydrate. Furthermore, a deeper and latterly extensive resistivity anomaly emerged from the 2D inversions, most probably attributed to the existence of a free gas layer beneath the base of the gas hydrate stability zone (BGHSZ). This work will contribute to accurately estimate the amount of methane hydrate and free gas both at the pockmark level and over a larger regional scale, providing valuable information in light of the fact that there are more than 220 known gas hydrate deposits worldwide.

  11. Imaging the Molecular Gas in a z=3.9 Quasar Host Galaxy at 0.3" Resolution: A Central, Sub-Kiloparsec Scale Star Formation Reservoir in APM 08279+5255

    E-print Network

    Dominik A. Riechers; Fabian Walter; Christopher L. Carilli; Geraint F. Lewis

    2008-09-04

    We have mapped the molecular gas content in the host galaxy of the strongly lensed high redshift quasar APM 08279+5255 (z=3.911) with the Very Large Array at 0.3" resolution. The CO(J=1-0) emission is clearly resolved in our maps. The CO(J=1-0) line luminosity derived from these maps is in good agreement with a previous single-dish measurement. In contrast to previous interferometer-based studies, we find that the full molecular gas reservoir is situated in two compact peaks separated by <~0.4". Our observations reveal, for the first time, that the emission from cold molecular gas is virtually cospatial with the optical/near-infrared continuum emission of the central AGN in this source. This striking similarity in morphology indicates that the molecular gas is situated in a compact region close to the AGN. Based on the high resolution CO maps, we present a revised model for the gravitational lensing in this system, which indicates that the molecular gas emission is magnified by only a factor of 4 (in contrast to previously suggested factors of 100). This model suggests that the CO is situated in a circumnuclear disk of ~550 pc radius that is possibly seen at an inclination of <~25 deg, i.e., relatively close to face-on. From the CO luminosity, we derive a molecular gas mass of M_gas=1.3x10^11 M_sun for this galaxy. From the CO structure and linewidth, we derive a dynamical mass of M_dyn(sin i)^2=4.0x10^10 M_sun. Based on a revised mass estimate for the central black hole of M_BH=2.3x10^10 M_sun and the results of our molecular line study, we find that the mass of the stellar bulge of APM 08279+5255 falls short of the local M_BH-sigma_bulge relationship of nearby galaxies by more than an order of magnitude, lending support to recent suggestions that this relation may evolve with cosmic time and/or change toward the high mass end.

  12. Laboratory analysis of gas hydrate cores for evaluation of reservoir conditions. Monthly report No. 5, November 1, 1983-November 31, 1983

    SciTech Connect

    Holder, G.D.

    1983-01-01

    During November work has been focused on two items. These are (a) Analysis of the formation kinetics of synthetic hydrate cores. (b) Analysis of the effect of sediment and heat transfer resistance on the dissociation rate of gas hydrates. The conclusion to be drawn is that dissociation of gas hydrates is severly heat transfer limited after only the shortest periods of time. Even if the conductivities used in this example are not correct, it is clear that the presence of a medium between an injected hot fluid and the hydrate zone must be taken into account in calculating rates at which hydrates will dissociate. 22 references, 4 figures, 4 tables.

  13. Reservoir Characterization Using Intelligent Seismic Inversion

    E-print Network

    Mohaghegh, Shahab

    Reservoir Characterization Using Intelligent Seismic Inversion Emre Artun, WVU Shahab D. Mohaghegh, W.V. SPE Paper # 98012 #12;motivation > Reservoir Modeling Workflow Exploration: Seismic Surveys Exploration Drilling Reservoir Characterization Reservoir Simulation A structural model of the reservoir can

  14. Geothermal-reservoir engineering research at Stanford University. Second annual report, October 1, 1981-September 30, 1982

    SciTech Connect

    Ramey, H.J. Jr.; Kruger, P.; Horne, R.N.; Brigham, W.E.; Miller, F.G.

    1982-09-01

    Progress in the following tasks is discussed: heat extraction from hydrothermal reservoirs, noncondensable gas reservoir engineering, well test analysis and bench-scale experiments, DOE-ENEL Cooperative Research, Stanford-IIE Cooperative Research, and workshop and seminars. (MHR)

  15. Volume 3: Characterization of representative reservoirs -- South Marsh Island 73, B35K and B65G Reservoirs

    SciTech Connect

    Young, M.A.; Salamy, S.P.; Reeves, T.K.; Kimbrell, W.C.; Sawyer, W.K.

    1998-07-01

    This report documents the results of a detailed study of two Gulf of Mexico salt dome related reservoirs and the application of a publicly available PC-based black oil simulator to model the performances of gas injection processes to recover attic oil. The overall objective of the research project is to assess the oil reserve potential that could result from the application of proven technologies to recover bypassed oil from reservoirs surrounding piercement salt domes in the Gulf of Mexico. The specific study objective was to simulate the primary recovery and attic gas injection performance of the two subject reservoirs to: (1) validate the BOAST model; (2) quantify the attic volume; and (3) predict the attic oil recovery potential that could result from additional updip gas injection. The simulation studies were performed on the B-35K Reservoir and the B-65G Reservoir in the South Marsh Island Block 73 Field using data provided by one of the field operators. A modified PC-version of the BOAST II model was used to match the production and injection performances of these reservoirs in which numerous gas injection cycles had been conducted to recover attic oil. The historical performances of the gas injection cycles performed on both the B-35K Reservoir and B-65G Reservoir were accurately matched, and numerous predictive runs were made to define additional potential for attic oil recovery using gas injection. Predictive sensitivities were conducted to examine the impact of gas injection rate, injection volume, post-injection shut-in time, and the staging of gas injection cycles on oil recovery.

  16. Determination of permeability index using Stoneley slowness analysis, NMR models, and formation evaluations: a case study from a gas reservoir, south of Iran

    NASA Astrophysics Data System (ADS)

    Hosseini, Mirhasan; Javaherian, Abdolrahim; Movahed, Bahram

    2014-10-01

    In hydrocarbon reservoirs, permeability is one of the most critical parameters with a significant role in the production of hydrocarbon resources. Direct determination of permeability using Stoneley waves has always had some difficulties. In addition, some un-calibrated empirical models such as Nuclear Magnetic Resonance (NMR) models and petrophysical evaluation model (intrinsic permeability) do not provide reliable estimates of permeability in carbonate formations. Therefore, utilizing an appropriate numerical method for direct determination of permeability using Stoneley waves as well as an appropriate calibration method for the empirical models is necessary to have reliable results. This paper shows the application of a numerical method, called bisection method, in the direct determination of permeability from Stoneley wave slowness. In addition, a linear regression (least squares) method was used to calibrate the NMR models including Schlumberger Doll Research (SDR) and Timur-Coates models as well as the intrinsic permeability equation (permeability from petrophysical evaluations). The Express Pressure Tester (XPT) permeability was considered as an option for the reference permeability. Therefore, all permeability models were validated for the Stoneley permeability and calibrated for the empirical models with the XPT permeability. In order to have a quantitative assessment on the results and compare the results before and after the calibration, the Root Mean Squares Error (RMSE) was calculated for each of the used models. The results for the Stoneley permeability showed that, in many points there was not much difference between the Stoneley permeability calculated by the bisection method and the XPT permeability. Comparing the results showed that the calibration of the empirical models reduced their RMSE values. As a result of the calibration, the RMSE was decreased by about 39% for the SDR model, 18% for the Timur-Coates model, and 91% for the petrophysical evaluations model. Presented bisection method calculates permeability directly without of any inversion or external calibration.

  17. Reservoir characterization of Pennsylvanian sandstone reservoirs. Final report

    SciTech Connect

    Kelkar, M.

    1995-02-01

    This final report summarizes the progress during the three years of a project on Reservoir Characterization of Pennsylvanian Sandstone Reservoirs. The report is divided into three sections: (i) reservoir description; (ii) scale-up procedures; (iii) outcrop investigation. The first section describes the methods by which a reservoir can be described in three dimensions. The next step in reservoir description is to scale up reservoir properties for flow simulation. The second section addresses the issue of scale-up of reservoir properties once the spatial descriptions of properties are created. The last section describes the investigation of an outcrop.

  18. Reservoir Temperature Estimator

    Energy Science and Technology Software Center (ESTSC)

    2014-12-08

    The Reservoir Temperature Estimator (RTEst) is a program that can be used to estimate deep geothermal reservoir temperature and chemical parameters such as CO2 fugacity based on the water chemistry of shallower, cooler reservoir fluids. This code uses the plugin features provided in The Geochemist?s Workbench (Bethke and Yeakel, 2011) and interfaces with the model-independent parameter estimation code Pest (Doherty, 2005) to provide for optimization of the estimated parameters based on the minimization of themore »weighted sum of squares of a set of saturation indexes from a user-provided mineral assemblage.« less

  19. Reservoir Temperature Estimator

    SciTech Connect

    2014-12-08

    The Reservoir Temperature Estimator (RTEst) is a program that can be used to estimate deep geothermal reservoir temperature and chemical parameters such as CO2 fugacity based on the water chemistry of shallower, cooler reservoir fluids. This code uses the plugin features provided in The Geochemist?s Workbench (Bethke and Yeakel, 2011) and interfaces with the model-independent parameter estimation code Pest (Doherty, 2005) to provide for optimization of the estimated parameters based on the minimization of the weighted sum of squares of a set of saturation indexes from a user-provided mineral assemblage.

  20. GAS EXPLORATION Winter 2006 GasTIPS 5

    E-print Network

    Rubin, Yoram

    for predicting changes in pressure and fluid saturation. Predictions of changes in pore pressure can be done whenGAS EXPLORATION Winter 2006 · GasTIPS 5 T he prediction of reservoir parameters such as gas or oil

  1. Modeling the Entrepeñas Reservoir.

    PubMed

    Wiese, Bernd U; Palancar, María C; Aragón, José M; Sánchez, Fernando; Gil, Roberto

    2006-08-01

    The Entrepeñas Reservoir is a monomictic reservoir located in River Tagus (Spain). The aim of this work is to establish a feasible model to predict the depth of the thermocline that is developed in the reservoir during the period of natural thermal stratification. Entrainment, eddy diffusion, inflow of external energy, and other factors are considered to calibrate the parameters of the model. The methodology involves the measure of actual temperature and electrical conductivity profiles, use of meteorological data and reservoir parameters, and selection and application of several models from the literature. The calculations and predictions are integrated to a software packet that is able to predict thermocline depth and water temperature profile during a 1-year period on a day-by-day basis. In the thermocline depth, the prediction error, on the basis of real data, is less than 6% and, in the water temperature, it is 2 degrees C. PMID:17059129

  2. Ebola: Hidden reservoirs

    E-print Network

    Heeney, Jonathan L.

    2015-11-25

    West Africa's Ebola epidemic continues to reveal surprises. Although the animal species that originally passed the virus to people remains a mystery, a virus reservoir and persistent disease have been identified in some human survivors....

  3. Panorama of Amistad Reservoir

    USGS Multimedia Gallery

    Amistad National Recreation Area includes the Amistad Reservoir, a man-made lake along the Texas and Mexico border. It is fed by the Rio Grande, Devils River, and the Pecos River, among others.    ...

  4. Cacti at Amistad Reservoir

    USGS Multimedia Gallery

    Amistad National Recreation Area includes the Amistad Reservoir, a man-made lake along the Texas and Mexico border. It is fed by the Rio Grande, Devils River, and the Pecos River, among others.    ...

  5. Potential Mammalian Filovirus Reservoirs

    PubMed Central

    Carroll, Darin S.; Mills, James N.; Johnson, Karl M.

    2004-01-01

    Ebola and Marburg viruses are maintained in unknown reservoir species; spillover into human populations results in occasional human cases or epidemics. We attempted to narrow the list of possibilities regarding the identity of those reservoir species. We made a series of explicit assumptions about the reservoir: it is a mammal; it supports persistent, largely asymptomatic filovirus infections; its range subsumes that of its associated filovirus; it has coevolved with the virus; it is of small body size; and it is not a species that is commensal with humans. Under these assumptions, we developed priority lists of mammal clades that coincide distributionally with filovirus outbreak distributions and compared these lists with those mammal taxa that have been tested for filovirus infection in previous epidemiologic studies. Studying the remainder of these taxa may be a fruitful avenue for pursuing the identity of natural reservoirs of filoviruses. PMID:15663841

  6. Reservoir and injection technology and Heat Extraction Project

    SciTech Connect

    Horne, R.N.; Ramey, H.H. Jr.; Miller, F.G.; Brigham, W.E.; Kruger, P.

    1989-12-31

    For the Stanford Geothermal Program in the fiscal year 1989, the task areas include predictive modeling of reservoir behavior and tracer test interpretation and testing. Major emphasis is in reservoir technology, reinjection technology, and heat extraction. Predictive modeling of reservoir behavior consists of a multi-pronged approach to well test analysis under a variety of conditions. The efforts have been directed to designing and analyzing well tests in (1) naturally fractured reservoirs; (2) fractured wells; (3) complex reservoir geometries; and, (4) gas reservoirs including inertial and other effects. The analytical solutions for naturally fractured reservoirs are determined using fracture size distribution. In the study of fractured wells, an elliptical coordinate system is used to obtain semi-analytical solutions to finite conductivity fractures. Effort has also been directed to the modeling and creation of a user friendly computer program for steam/gas reservoirs including wellbore storage, skin and non-Darcy flow effects. This work has a complementary effort on modeling high flow rate wells including inertial effects in the wellbore and fractures. In addition, work on gravity drainage systems is being continued.

  7. Session: Reservoir Technology

    SciTech Connect

    Renner, Joel L.; Bodvarsson, Gudmundur S.; Wannamaker, Philip E.; Horne, Roland N.; Shook, G. Michael

    1992-01-01

    This session at the Geothermal Energy Program Review X: Geothermal Energy and the Utility Market consisted of five papers: ''Reservoir Technology'' by Joel L. Renner; ''LBL Research on the Geysers: Conceptual Models, Simulation and Monitoring Studies'' by Gudmundur S. Bodvarsson; ''Geothermal Geophysical Research in Electrical Methods at UURI'' by Philip E. Wannamaker; ''Optimizing Reinjection Strategy at Palinpinon, Philippines Based on Chloride Data'' by Roland N. Horne; ''TETRAD Reservoir Simulation'' by G. Michael Shook

  8. Application of integrated reservoir management and reservoir characterization to optimize infill drilling. Annual report, June 13, 1994--June 12, 1995

    SciTech Connect

    Pande, P.K.

    1996-11-01

    This project has used a multi-disciplinary approach employing geology, geophysics, and engineering to conduct advanced reservoir characterization and management activities to design and implement an optimized infill drilling program at the North Robertson (Clearfork) Unit in Gaines County, Texas. The activities during the first Budget Period have consisted of developing an integrated reservoir description from geological, engineering, and geostatistical studies, and using this description for reservoir flow simulation. Specific reservoir management activities are being identified and tested. The geologically targeted infill drilling program will be implemented using the results of this work. A significant contribution of this project is to demonstrate the use of cost-effective reservoir characterization and management tools that will be helpful to both independent and major operators for the optimal development of heterogeneous, low permeability shallow-shelf carbonate (SSC) reservoirs. The techniques that are outlined for the formulation of an integrated reservoir description apply to all oil and gas reservoirs, but are specifically tailored for use in the heterogeneous, low permeability carbonate reservoirs of West Texas.

  9. Paonia Reservoir Sediment Management

    NASA Astrophysics Data System (ADS)

    Kimbrel, S.; Collins, K.; Williams, C.

    2014-12-01

    Paonia Dam and Reservoir are located on Muddy Creek, a tributary of the North Fork Gunnison River in western Colorado. Since dam closure in 1962, the 2002 survey estimates an annual sedimentation rate of 153,000 m3/y, resulting in a 25% loss of total reservoir capacity. Long before sediment levels completely fill the reservoir, the outlet works have recently plugged with sediment and debris, adversely impacting operations, and emphasizing the urgency of formulating an effective sediment management plan. Starting in 2010-2011, operations were changed to lower the reservoir and flush sediment through the outlet works in early spring before filling the pool for irrigation. Even though the flushing strategy through the long, narrow reservoir (~5 km long and 0.3 km wide) has prevented outlet works plugging, a long term plan is needed to manage inflowing and deposited sediment more efficiently. Reclamation's Sedimentation and River Hydraulics Group is leading an effort to study the past and current sediment issues at Paonia Dam and Reservoir, evaluate feasible sediment management alternatives, and formulate a plan for future operations and monitoring. The study is building on previously collected data and the existing knowledge base to develop a comprehensive, sustainable sediment management plan. The study is being executed in three phases: Phase 1 consisted of an initial site visit to map and sample existing reservoir bottom sediments, a preliminary site evaluation upstream and downstream of the dam, and establishment of time-lapse photo sites and taking initial ground-based photos. Phase 2 includes a bathymetric survey of entire reservoir and 11 km of the river downstream of the dam, continuous suspended sediment monitoring upstream and downstream of the reservoir, and collection of additional core samples of reservoir bottom sediments. Phase 3 involves the evaluation of current and past operations and sediment management practices, evaluate feasible sediment management methods, and providing recommendations for future monitoring and sediment management operations. Data collected during Phases 1 and 2 are used in a one-dimensional numerical sediment transport model for evaluating past, current, and potential future sediment management options.

  10. Sampling the marine gas-hydrate reservoir: Assessing the methane inventory, internal dynamics, and potential of methane discharges to the atmosphere. Final progress report

    SciTech Connect

    Paull, C.

    1993-08-27

    The status of the pore water and sediment core analysis of the surface sediments that overlie a major gas-hydrate field on the Carolina Continental Rise and Blake Ridge is reported here. Funding from NIGEC`s southern regional center provided support for a cruise of the RV Cape Hatteras in September 1992 (CH-11-92) on which 20 piston cores were taken. However, over the last 18 months we have had the opportunity to collect an additional 35 piston cores in this region, in part through the assistance of another DOE funded project that is being run by the USGS. At this date, we have pore water data from 55 piston cores which gives us both a regional and a site-specific insight into the processes in this region. It is our intention to combine the results of all these cores to arrive at a unified understanding of the processes acting on the continental margin which influence gas-hydrate formation and distribution. Some of the highlights of this work and some of accomplishments of this project to-date are outlined.

  11. A petrophysics and reservoir performance-based reservoir characterization of Womack Hill (Upper Smackover) Field (Alabama) 

    E-print Network

    Avila Urbaneja, Juan Carlos

    2002-01-01

    considerable drop in profitability of the field. The field currently produces 640 STB/D of oil and 330 MSCF/D of gas, along with 6,700 STB/D of water, which implies a water cut of over 90 percent. In order to optimize the reservoir management strategies...

  12. Movement of atrazine and deethylatrazine through a midwestern reservoir

    USGS Publications Warehouse

    Fallon, J.D.; Tierney, D.P.; Thurman, E.M.

    2002-01-01

    The three-dimensional visualization of atrazine and deethylatrazine in a reservoir was determined by five "snapshots" over a one-year period using immunoassay analyses, confirmed by gas chromatography-mass spectrometry and visualized with a three-dimensional computer program. The surveys were conducted in Perry Lake in Kansas and showed that spring runoff laden with triazine herbicides entered the reservoir and did not mix immediately. Concentrations varied threefold between the inlet and the public water supply intakes located at the opposite end of the reservoir. The concentration range in the outflow varied much less than the concentration in the reservoir because of mixing throughout the season near the dam and outflow. A major conclusion from the study was that multiple analyses by a low-cost immunoassay technique coupled with computer visualization software gave a good three-dimensional view of the mass of herbicide present in a drinking water reservoir.

  13. Sustainable reservoir operation

    SciTech Connect

    Smith, Brennan T; Jager, Yetta; March, Patrick

    2007-07-01

    Reservoir releases are typically operated to maximize the efficiency of hydropower production and the value of hydropower produced. In practice, ecological considerations are limited to those required by law. We first describe reservoir optimization methods that include mandated constraints on environmental and other water uses. Next, we describe research to formulate and solve reservoir optimization problems involving both energy and environmental water needs as objectives. Evaluating ecological objectives is a challenge in these problems for several reasons. First, it is difficult to predict how biological populations will respond to flow release patterns. This problem can be circumvented by using ecological models. Second, most optimization methods require complex ecological responses to flow to be quantified by a single metric, preferably a currency that can also represent hydropower benefits. Ecological valuation of instream flows can make optimization methods that require a single currency for the effects of flow on energy and river ecology possible. Third, holistic reservoir optimization problems are unlikely to be structured such that simple solution methods can be used, necessitating the use of flexible numerical methods. One strong advantage of optimal control is the ability to plan for the effects of climate change. We present ideas for developing holistic methods to the point where they can be used for real-time operation of reservoirs. We suggest that developing ecologically sound optimization tools should be a priority for hydropower in light of the increasing value placed on sustaining both the ecological and energy benefits of riverine ecosystems long into the future.

  14. CO2 storage resources, reserves, and reserve growth: Toward a methodology for integrated assessment of the storage capacity of oil and gas reservoirs and saline formations

    USGS Publications Warehouse

    Burruss, R.C.

    2009-01-01

    Geologically based methodologies to assess the possible volumes of subsurface CO2 storage must apply clear and uniform definitions of resource and reserve concepts to each assessment unit (AU). Application of the current state of knowledge of geologic, hydrologic, geochemical, and geophysical parameters (contingencies) that control storage volume and injectivity allows definition of the contingent resource (CR) of storage. The parameters known with the greatest certainty are based on observations on known traps (KTs) within the AU that produced oil, gas, and water. The aggregate volume of KTs within an AU defines the most conservation volume of contingent resource. Application of the concept of reserve growth to CR volume provides a logical path for subsequent reevaluation of the total resource as knowledge of CO2 storage processes increases during implementation of storage projects. Increased knowledge of storage performance over time will probably allow the volume of the contingent resource of storage to grow over time, although negative growth is possible. ?? 2009 Elsevier Ltd. All rights reserved.

  15. A reservoir management strategy for multilayered reservoirs in eastern Venezuela 

    E-print Network

    Espinel Diaz, Arnaldo Leopoldo

    1998-01-01

    A reservoir management strategy has been developed for a field located in eastern Venezuela. The field contains deep, high pressure, multilayer reservoirs. A thorough formation evaluation was accomplished using the log data, core data, PVT data...

  16. Optoelectronic Reservoir Computing

    PubMed Central

    Paquot, Y.; Duport, F.; Smerieri, A.; Dambre, J.; Schrauwen, B.; Haelterman, M.; Massar, S.

    2012-01-01

    Reservoir computing is a recently introduced, highly efficient bio-inspired approach for processing time dependent data. The basic scheme of reservoir computing consists of a non linear recurrent dynamical system coupled to a single input layer and a single output layer. Within these constraints many implementations are possible. Here we report an optoelectronic implementation of reservoir computing based on a recently proposed architecture consisting of a single non linear node and a delay line. Our implementation is sufficiently fast for real time information processing. We illustrate its performance on tasks of practical importance such as nonlinear channel equalization and speech recognition, and obtain results comparable to state of the art digital implementations. PMID:22371825

  17. Optoelectronic Reservoir Computing

    E-print Network

    Yvan Paquot; François Duport; Anteo Smerieri; Joni Dambre; Benjamin Schrauwen; Marc Haelterman; Serge Massar

    2011-11-30

    Reservoir computing is a recently introduced, highly efficient bio-inspired approach for processing time dependent data. The basic scheme of reservoir computing consists of a non linear recurrent dynamical system coupled to a single input layer and a single output layer. Within these constraints many implementations are possible. Here we report an opto-electronic implementation of reservoir computing based on a recently proposed architecture consisting of a single non linear node and a delay line. Our implementation is sufficiently fast for real time information processing. We illustrate its performance on tasks of practical importance such as nonlinear channel equalization and speech recognition, and obtain results comparable to state of the art digital implementations.

  18. Directly Imaging Damped Ly-Alpha Galaxies at Redshifts Greater Than 2. III: The Star Formation Rates of Neutral Gas Reservoirs at Redshifts of Approximately 2.7

    NASA Technical Reports Server (NTRS)

    Fumagalli, Michele; OMeara, John M.; Prochaska, J. Xavier; Rafelski, Marc; Kanekar, Nissim

    2014-01-01

    We present results from a survey designed to probe the star formation properties of 32 damped Ly alpha systems (DLAs) at redshifts of approximately 2.7. By using the "double-DLA" technique that eliminates the glare of the bright background quasars, we directly measure the rest-frame FUV flux from DLAs and their neighbouring galaxies. At the position of the absorbing gas, we place stringent constraints on the unobscured star formation rates (SFRs) of DLAs to 2 sigma limits of psi less than 0.09-0.27 solar mass yr(exp -1), corresponding to SFR surface densities sigma(sub sfr) less than 10(exp -2.6)-10(exp -1.5) solar mass yr(exp -1) kpc(exp -2). The implications of these limits for the star formation law, metal enrichment, and cooling rates of DLAs are examined. By studying the distribution of impact parameters as a function of SFRs for all the galaxies detected around these DLAs, we place new direct constraints on the bright end of the UV luminosity function of DLA hosts. We find that less than or equal to 13% of the hosts have psi greater than or equal to 2 solar mass yr(exp -1) at impact parameters b(sub dla) less than or equal to (psi/solar mass yr(exp -1))(exp 0.8) + 6 kpc, differently from current samples of confirmed DLA galaxies. Our observations also disfavor a scenario in which the majority of DLAs arise from bright LBGs at distances 20 less than or equal to b(sub dla) less than 100 kpc. These new findings corroborate a picture in which DLAs do not originate from highly star forming systems that are coincident with the absorbers, and instead suggest that DLAs are associated with faint, possibly isolated, star-forming galaxies. Potential shortcomings of this scenario and future strategies for further investigation are discussed.

  19. Manicouagin Reservoir of Canada

    NASA Technical Reports Server (NTRS)

    2002-01-01

    Recorded by the Space Shuttle Atlantis STS-110 mission, this is a photograph of the ice- covered Manicouagin Reservoir located in the Canadian Shield of Quebec Province in Eastern Canada, partially obscured by low clouds. This reservoir marks the site of an impact crater, 60 miles (100 kilometers) wide, which according to geologists was formed 212 million years ago when a meteorite crashed into this area. Over millions of years, the crater has been worn down by glaciers and other erosional processes. The Space Shuttle Orbiter Atlantis, STS-110 mission, was launched April 8, 2002 and returned to Earth April 19, 2002.

  20. Hydrocarbon Reservoir Parameter Estimation Using

    E-print Network

    van Vliet, Lucas J.

    Hydrocarbon Reservoir Parameter Estimation Using Production Data and Time-Lapse Seismic #12;#12;Hydrocarbon Reservoir Parameter Estimation Using Production Data and Time-Lapse Seismic PROEFSCHRIFT ter

  1. Prickly Pears at Amistad Reservoir

    USGS Multimedia Gallery

    Amistad National Recreation Area includes the Amistad Reservoir, a man-made lake along the border of Texas and Mexico. This view is of the cliffs of Diablo East. Prickly pear cacti are common around the reservoir....

  2. Use of Cutting-Edge Horizontal and Underbalanced Drilling Technologies and Subsurface Seismic Techniques to Explore, Drill and Produce Reservoired Oil and Gas from the Fractured Monterey Below 10,000 ft in the Santa Maria Basin of California

    SciTech Connect

    George Witter; Robert Knoll; William Rehm; Thomas Williams

    2005-09-29

    This project was undertaken to demonstrate that oil and gas can be drilled and produced safely and economically from a fractured Monterey reservoir in the Santa Maria Basin of California by employing horizontal wellbores and underbalanced drilling technologies. Two vertical wells were previously drilled in this area with heavy mud and conventional completions; neither was commercially productive. A new well was drilled by the project team in 2004 with the objective of accessing an extended length of oil-bearing, high-resistivity Monterey shale via a horizontal wellbore, while implementing managed-pressure drilling (MPD) techniques to avoid formation damage. Initial project meetings were conducted in October 2003. The team confirmed that the demonstration well would be completed open-hole to minimize productivity impairment. Following an overview of the geologic setting and local field experience, critical aspects of the application were identified. At the pre-spud meeting in January 2004, the final well design was confirmed and the well programming/service company requirements assigned. Various design elements were reduced in scope due to significant budgetary constraints. Major alterations to the original plan included: (1) a VSP seismic survey was delayed to a later phase; (2) a new (larger) surface hole would be drilled rather than re-enter an existing well; (3) a 7-in. liner would be placed into the top of the Monterey target as quickly as possible to avoid problems with hole stability; (4) evaluation activities were reduced in scope; (5) geosteering observations for fracture access would be deduced from penetration rate, cuttings description and hydrocarbon in-flow; and (6) rather than use nitrogen, a novel air-injection MPD system was to be implemented. Drilling operations, delayed from the original schedule by capital constraints and lack of rig availability, were conducted from September 12 to November 11, 2004. The vertical and upper curved sections were drilled and lined through the problematic shale member without major stability problems. The top of the targeted Monterey was thought to be seen at the expected TVD of 10,000 ft where the 7-in. liner was set at a 60{sup o} hole angle. Significant oil and gas shows suggested the fractured interval anticipated at the heel location had been penetrated. A total of 2572 ft of 6 1/8-in. near-horizontal interval was placed in the shale section, extending planned well length by approximately 470 ft. Very little hydrocarbon in-flow was observed from fractures along the productive interval. This may be a result of the well trajectory falling underneath the Monterey fractured zone. Hydrocarbon observations, cuttings analysis and gamma-ray response indicated additional fractured intervals were accessed along the last {+-}900 ft of well length. The well was completed with a 2 7/8-in. tubing string set in a production packer in preparation for flow and swab tests to be conducted later by a service rig. The planned well time was estimated as 39 days and overall cost as $2.4 million. The actual results are 66 days at a total cost of $3.4 million. Well productivity responses during subsequent flow and swabbing tests were negative. The well failed to inflow and only minor amounts (a few barrels) of light oil were recovered. The lack of production may suggest that actual sustainable reservoir pressure is far less than anticipated. Temblor is currently planning to re-enter and clean out the well and run an Array Induction log (primarily for resistivity and correlation purposes), and an FMI log (for fracture detection). Depending on the results of these logs, an acidizing or re-drill program will be planned.

  3. Use of Cutting-Edge Horizontal and Underbalanced Drilling Technologies and Subsurface Seismic Techniques to Explore, Drill and Produce Reservoired Oil and Gas from the Fractured Monterey Below 10,000 ft in the Santa Maria Basin of California

    SciTech Connect

    George Witter; Robert Knoll; William Rehm; Thomas Williams

    2006-06-30

    This project was undertaken to demonstrate that oil and gas can be drilled and produced safely and economically from a fractured Monterey reservoir in the Santa Maria Basin of California by employing horizontal wellbores and underbalanced drilling technologies. Two vertical wells were previously drilled in this area with heavy mud and conventional completions; neither was commercially productive. A new well was drilled by the project team in 2004 with the objective of accessing an extended length of oil-bearing, high-resistivity Monterey shale via a horizontal wellbore, while implementing managed-pressure drilling (MPD) techniques to avoid formation damage. Initial project meetings were conducted in October 2003. The team confirmed that the demonstration well would be completed open-hole to minimize productivity impairment. Following an overview of the geologic setting and local field experience, critical aspects of the application were identified. At the pre-spud meeting in January 2004, the final well design was confirmed and the well programming/service company requirements assigned. Various design elements were reduced in scope due to significant budgetary constraints. Major alterations to the original plan included: (1) a VSP seismic survey was delayed to a later phase; (2) a new (larger) surface hole would be drilled rather than re-enter an existing well; (3) a 7-in. liner would be placed into the top of the Monterey target as quickly as possible to avoid problems with hole stability; (4) evaluation activities were reduced in scope; (5) geosteering observations for fracture access would be deduced from penetration rate, cuttings description and hydrocarbon in-flow; and (6) rather than use nitrogen, a novel air-injection MPD system was to be implemented. Drilling operations, delayed from the original schedule by capital constraints and lack of rig availability, were conducted from September 12 to November 11, 2004. The vertical and upper curved sections were drilled and lined through the problematic shale member without major stability problems. The top of the targeted Monterey was thought to be seen at the expected TVD of 10,000 ft where the 7-in. liner was set at a 60{sup o} hole angle. Significant oil and gas shows suggested the fractured interval anticipated at the heel location had been penetrated. A total of 2572 ft of 6{Delta}-in. near-horizontal interval was placed in the shale section, extending planned well length by approximately 470 ft. Very little hydrocarbon in-flow was observed from fractures along the productive interval. This may be a result of the well trajectory falling underneath the Monterey fractured zone. Hydrocarbon observations, cuttings analysis and gamma-ray response indicated additional fractured intervals were accessed along the last {+-}900 ft of well length. The well was completed with a 2 and 7/8-in. tubing string set in a production packer in preparation for flow and swab tests to be conducted later by a service rig. The planned well time was estimated as 39 days and overall cost as $2.4 million. The actual results are 66 days at a total cost of $3.4 million. Well productivity responses during subsequent flow and swabbing tests were negative. The well failed to inflow and only minor amounts (a few barrels) of light oil were recovered. The lack of production may suggest that actual sustainable reservoir pressure is far less than anticipated. Temblor attempted in July, 2006, to re-enter and clean out the well and run an Array Induction log (primarily for resistivity and correlation purposes), and an FMI log (for fracture detection). Application of surfactant in the length of the horizontal hole, and acid over the fracture zone at 10,236 was also planned. This attempt was not successful in that the clean out tools became stuck and had to be abandoned.

  4. USE OF CUTTING-EDGE HORIZONTAL AND UNDERBALANCED DRILLING TECHNOLOGIES AND SUBSURFACE SEISMIC TECHNIQUES TO EXPLORE, DRILL AND PRODUCE RESERVOIRED OIL AND GAS FROM THE FRACTURED MONTEREY BELOW 10,000 FT IN THE SANTA MARIA BASIN OF CALIFORNIA

    SciTech Connect

    George Witter; Robert Knoll; William Rehm; Thomas Williams

    2005-02-01

    This project was undertaken to demonstrate that oil and gas can be drilled and produced safely and economically from a fractured Monterey reservoir in the Santa Maria Basin of California by employing horizontal wellbores and underbalanced drilling technologies. Two vertical wells were previously drilled in this area by Temblor Petroleum with heavy mud and conventional completions; neither was commercially productive. A new well was drilled by the project team in 2004 with the objective of accessing an extended length of oil-bearing, high-resistivity Monterey shale via a horizontal wellbore, while implementing managed-pressure drilling (MPD) techniques to avoid formation damage. Initial project meetings were conducted in October 2003. The team confirmed that the demonstration well would be completed open-hole to minimize productivity impairment. Following an overview of the geologic setting and local field experience, critical aspects of the application were identified. At the pre-spud meeting in January 2004, the final well design was confirmed and the well programming/service company requirements assigned. Various design elements were reduced in scope due to significant budgetary constraints. Major alterations to the original plan included: (1) a VSP seismic survey was delayed to a later phase; (2) a new (larger) surface hole would be drilled rather than re-enter an existing well; (3) a 7-in. liner would be placed into the top of the Monterey target as quickly as possible to avoid problems with hole stability; (4) evaluation activities were reduced in scope; (5) geosteering observations for fracture access would be deduced from penetration rate, cuttings description and hydrocarbon in-flow; and (6) rather than use nitrogen, a novel air-injection MPD system was to be implemented. Drilling operations, delayed from the original schedule by capital constraints and lack of rig availability, were conducted from September 12 to November 11, 2004. The vertical and upper curved sections were drilled and lined through the problematic shale member without major stability problems. The top of the targeted Monterey was thought to be seen at the expected TVD of 10,000 ft where the 7-in. liner was set at a 60{sup o} hole angle. Significant oil and gas shows suggested the fractured interval anticipated at the heel location had been penetrated. A total of 2572 ft of 6.-in. near-horizontal interval was placed in the shale section, extending planned well length by approximately 470 ft. Very little hydrocarbon in-flow was observed from fractures along the productive interval. This may be a result of the well trajectory falling underneath the Monterey fractured zone. Hydrocarbon observations, cuttings analysis and gamma-ray response indicated additional fractured intervals were accessed along the last {+-}900 ft of well length. The well was completed with a 2 7/8-in. tubing string set in a production packer in preparation for flow and swab tests to be conducted later by a service rig. The planned well time was estimated as 39 days and overall cost as $2.4 million. The actual results are 66 days at a total cost of $3.4 million. Well productivity responses during subsequent flow and swabbing tests were negative. The well failed to inflow and only minor amounts (a few barrels) of light oil were recovered. The lack of production may suggest that actual sustainable reservoir pressure is far less than anticipated. Temblor is currently investigating the costs and operational viability of re-entering the well and conducting an FMI (fracture detection) log and/or an acid stimulation. No final decision or detailed plans have been made regarding these potential interventions at this time.

  5. Interactive reservoir simulation

    SciTech Connect

    McVay, D.A.; Bastian, P.A. ); Epperson, B.D. )

    1991-11-01

    This paper describes a system that allows engineers to monitor and control a reservoir simulation run during its execution. The system consists of a 3D, three-phase black-oil reservoir simulator running simultaneously with an interactive graphics pre- and postprocessor. Previous authors have described systems that allow monitoring of job execution with simultaneous graphics displays; the system described here is unique in that the engineer can modify simulator and well-control parameters during the execution. While the system will be helpful in detection and correction of time-dependent data problems, it will be very useful in optimizing reservoir management decisions in future performance projections. The system is implemented on an IBM-compatible 486 microcomputer with commercially available multitasking software, although it can be implemented easily on any microcomputer or workstation capable of multitasking. The authors show that implementation of the system required only a moderate amount of modification of the pre- and postprocessor and even less modification of the reservoir simulator.

  6. Imperial Reservoir KOFA NATIONAL

    E-print Network

    Laughlin, Robert B.

    National Park El Centro Naval Auxiliary Air Station Yuma Proving Ground Yuma Marine Corps Air Station National Forest 15 8 10 8 8 8 15 40 Agua Caliente Reservation Augustine Reservation Barona ReservationImperial Reservoir KOFA NATIONAL WILDLIFE REFUGE CIBOLA NATIONAL WILDLIFE REFUGE HAVASU NATIONAL

  7. Reinjection into geothermal reservoirs

    SciTech Connect

    Bodvarsson, G.S.; Stefansson, V.

    1987-08-01

    Reinjection of geothermal wastewater is practiced as a means of disposal and for reservoir pressure support. Various aspects of reinjection are discussed, both in terms of theoretical studies as well as specific field examples. The discussion focuses on the major effects of reinjection, including pressure maintenance and chemical and thermal effects. (ACR)

  8. Appalachian Basin Low-Permeability Sandstone Reservoir Characterizations

    SciTech Connect

    Ray Boswell; Susan Pool; Skip Pratt; David Matchen

    1993-04-30

    A preliminary assessment of Appalachian basin natural gas reservoirs designated as 'tight sands' by the Federal Energy Regulatory Commission (FERC) suggests that greater than 90% of the 'tight sand' resource occurs within two groups of genetically-related units; (1) the Lower Silurian Medina interval, and (2) the Upper Devonian-Lower Mississippian Acadian clastic wedge. These intervals were targeted for detailed study with the goal of producing geologic reservoir characterization data sets compatible with the Tight Gas Analysis System (TGAS: ICF Resources, Inc.) reservoir simulator. The first phase of the study, completed in September, 1991, addressed the Medina reservoirs. The second phase, concerned with the Acadian clastic wedge, was completed in October, 1992. This report is a combined and updated version of the reports submitted in association with those efforts. The Medina interval consists of numerous interfingering fluvial/deltaic sandstones that produce oil and natural gas along an arcuate belt that stretches from eastern Kentucky to western New York. Geophysical well logs from 433 wells were examined in order to determine the geologic characteristics of six separate reservoir-bearing intervals. The Acadian clastic wedge is a thick, highly-lenticular package of interfingering fluvial-deltaic sandstones, siltstones, and shales. Geologic analyses of more than 800 wells resulted in a geologic/engineering characterization of seven separate stratigraphic intervals. For both study areas, well log and other data were analyzed to determine regional reservoir distribution, reservoir thickness, lithology, porosity, water saturation, pressure and temperature. These data were mapped, evaluated, and compiled into various TGAS data sets that reflect estimates of original gas-in-place, remaining reserves, and 'tight' reserves. The maps and data produced represent the first basin-wide geologic characterization for either interval. This report outlines the methods and assumptions used in creating the TGAS data input, and provides basic geologic perspective on the gas-bearing sandstones of the Medina interval and the Acadian clastic wedge.

  9. Sediment pass-through, an alternative to reservoir dredging

    SciTech Connect

    Harrison, L.L.; Lee, W.H.; Tu, S.

    1995-12-31

    Pacific Gas and Electric Company (PG&E) is studying an alternative {open_quotes}Sediment Management Plan{close_quotes} (SMP) to control sediments at Rock Creek Reservoir and the downstream Cresta Reservoir on the North Fork Feather River in Plumas County. The reservoirs are part of the 182,000 kW Rock Creek-Cresta Project hydroelectric development. Approximately 5.4 million cubic meters of sediments, deposited in the two reservoirs since they were placed in service in 1949 and 1950, partially obstruct the dams` low level outlets and pipe inlets supplying water for spillway gate operations. The sediments jeopardize the reliable and efficient operation of the dams and powerhouses. The SMP includes retrofitting Rock Creek and Cresta Dams with additional low-level gated outlets and modification of trash racks at the existing low level outlet pipes at each dam to improve sediment pass-through (SPT) capacity during high flows. Also, to enable construction of the dam modifications and to facilitate the initiation of SPT operation, dredging of approximately 46,000 cubic meters at Rock Creek Reservoir and 57,000 cubic meters at Cresta Reservoir can be accomplished using a new slurry pump dredging technology to minimize turbidity and re-suspension of solids during dredging. It is proposed to deposit the sediment on the reservoir bottoms, upstream of the areas to be dredged. The dredged sediments subsequently would be flushed from the reservoirs during SPT operations to ultimately be deposited in the dead storage volume of a large downstream reservoir, Lake Oroville. The SPT management plan supersedes more costly plans for major dredging, and may preclude the need for future maintenance dredging at the reservoirs.

  10. Status of Blue Ridge Reservoir

    SciTech Connect

    Not Available

    1990-09-01

    This is one in a series of reports prepared by the Tennessee Valley Authority (TVA) for those interested in the conditions of TVA reservoirs. This overview of Blue Ridge Reservoir summarizes reservoir and watershed characteristics, reservoir uses and use impairments, water quality and aquatic biological conditions, and activities of reservoir management agencies. This information was extracted from the most current reports and data available, as well as interview with water resource professionals in various federal, state, and local agencies. Blue Ridge Reservoir is a single-purpose hydropower generating project. When consistent with this primary objective, the reservoir is also operated to benefit secondary objectives including water quality, recreation, fish and aquatic habitat, development of shoreline, aesthetic quality, and other public and private uses that support overall regional economic growth and development. 8 refs., 1 fig.

  11. Reviving Abandoned Reservoirs with High-Pressure Air Injection: Application in a Fractured and Karsted Dolomite Reservoir

    SciTech Connect

    Robert Loucks; Stephen C. Ruppel; Dembla Dhiraj; Julia Gale; Jon Holder; Jeff Kane; Jon Olson; John A. Jackson; Katherine G. Jackson

    2006-09-30

    Despite declining production rates, existing reservoirs in the United States contain vast volumes of remaining oil that is not being effectively recovered. This oil resource constitutes a huge target for the development and application of modern, cost-effective technologies for producing oil. Chief among the barriers to the recovery of this oil are the high costs of designing and implementing conventional advanced recovery technologies in these mature, in many cases pressure-depleted, reservoirs. An additional, increasingly significant barrier is the lack of vital technical expertise necessary for the application of these technologies. This lack of expertise is especially notable among the small operators and independents that operate many of these mature, yet oil-rich, reservoirs. We addressed these barriers to more effective oil recovery by developing, testing, applying, and documenting an innovative technology that can be used by even the smallest operator to significantly increase the flow of oil from mature U.S. reservoirs. The Bureau of Economic Geology and Goldrus Producing Company assembled a multidisciplinary team of geoscientists and engineers to evaluate the applicability of high-pressure air injection (HPAI) in revitalizing a nearly abandoned carbonate reservoir in the Permian Basin of West Texas. The Permian Basin, the largest oil-bearing basin in North America, contains more than 70 billion barrels of remaining oil in place and is an ideal venue to validate this technology. We have demonstrated the potential of HPAI for oil-recovery improvement in preliminary laboratory tests and a reservoir pilot project. To more completely test the technology, this project emphasized detailed characterization of reservoir properties, which were integrated to access the effectiveness and economics of HPAI. The characterization phase of the project utilized geoscientists and petroleum engineers from the Bureau of Economic Geology and the Department of Petroleum Engineering (both at The University of Texas at Austin) to define the controls on fluid flow in the reservoir as a basis for developing a reservoir model. The successful development of HPAI technology has tremendous potential for increasing the flow of oil from deep carbonate reservoirs in the Permian Basin, a target resource that can be conservatively estimated at more than 1.5 billion barrels. Successful implementation in the field chosen for demonstration, for example, could result in the recovery of more than 34 million barrels of oil that will not otherwise be produced. Geological and petrophysical analysis of available data at Barnhart field reveals the following important observations: (1) the Barnhart Ellenburger reservoir is similar to most other Ellenburger reservoirs in terms of depositional facies, diagenesis, and petrophysical attributes; (2) the reservoir is characterized by low to moderate matrix porosity much like most other Ellenburger reservoirs in the Permian Basin; (3) karst processes (cave formation, infill, and collapse) have substantially altered stratigraphic architecture and reservoir properties; (4) porosity and permeability increase with depth and may be associated with the degree of karst-related diagenesis; (5) tectonic fractures overprint the reservoir, improving overall connectivity; (6) oil-saturation profiles show that the oil-water contact (OWC) is as much as 125 ft lower than previous estimations; (7) production history and trends suggest that this reservoir is very similar to other solution-gas-drive reservoirs in the Permian Basin; and (8) reservoir simulation study showed that the Barnhart reservoir is a good candidate for HPAI and that application of horizontal-well technology can improve ultimate resource recovery from the reservoir.

  12. Carbon Dioxide Emissions from Reservoirs in the Lower Jordan Watershed

    PubMed Central

    Alshboul, Zeyad; Lorke, Andreas

    2015-01-01

    We have analyzed monthly hydrological, meteorological and water quality data from three irrigation and drinking water reservoirs in the lower Jordan River basin and estimated the atmospheric emission rates of CO2. The data were collected between 2006 and 2013 and show that the reservoirs, which differ in size and age, were net sources of CO2. The estimated surface fluxes were comparable in magnitude to those reported for hydroelectric reservoirs in the tropical and sub-tropical zones. Highest emission rates were observed for a newly established reservoir, which was initially filled during the sampling period. In the two older reservoirs, CO2 partial pressures and fluxes were significantly decreasing during the observation period, which could be related to simultaneously occurring temporal trends in water residence time and chemical composition of the water. The results indicate a strong influence of water and reservoir management (e.g. water consumption) on CO2 emission rates, which is affected by the increasing anthropogenic pressure on the limited water resources in the study area. The low wind speed and relatively high pH favored chemical enhancement of the CO2 gas exchange at the reservoir surfaces, which caused on average a four-fold enhancement of the fluxes. A sensitivity analysis indicates that the uncertainty of the estimated fluxes is, besides pH, mainly affected by the poorly resolved wind speed and resulting uncertainty of the chemical enhancement factor. PMID:26588241

  13. Carbon Dioxide Emissions from Reservoirs in the Lower Jordan Watershed.

    PubMed

    Alshboul, Zeyad; Lorke, Andreas

    2015-01-01

    We have analyzed monthly hydrological, meteorological and water quality data from three irrigation and drinking water reservoirs in the lower Jordan River basin and estimated the atmospheric emission rates of CO2. The data were collected between 2006 and 2013 and show that the reservoirs, which differ in size and age, were net sources of CO2. The estimated surface fluxes were comparable in magnitude to those reported for hydroelectric reservoirs in the tropical and sub-tropical zones. Highest emission rates were observed for a newly established reservoir, which was initially filled during the sampling period. In the two older reservoirs, CO2 partial pressures and fluxes were significantly decreasing during the observation period, which could be related to simultaneously occurring temporal trends in water residence time and chemical composition of the water. The results indicate a strong influence of water and reservoir management (e.g. water consumption) on CO2 emission rates, which is affected by the increasing anthropogenic pressure on the limited water resources in the study area. The low wind speed and relatively high pH favored chemical enhancement of the CO2 gas exchange at the reservoir surfaces, which caused on average a four-fold enhancement of the fluxes. A sensitivity analysis indicates that the uncertainty of the estimated fluxes is, besides pH, mainly affected by the poorly resolved wind speed and resulting uncertainty of the chemical enhancement factor. PMID:26588241

  14. Naturally fractured tight gas reservoir detection optimization

    SciTech Connect

    1996-09-30

    The focus of this report was on preparing data and modules for Piceance Basin-wide fracture prediction. A review of the geological data input and automated history reconstruction approach was made. Fluid pressure data analysis and preliminary basin simulations were carried out. These activities are summarized briefly below and reviewed in more detail in Appendices A-E. Appendix D is a review of the fluid pressure data and its implications for compartmentation. Preliminary fracture prediction computations on generic basins are presented in Appendix E; these were carried out as part of our code testing activities. The results of these two Appendices are the beginning of what will be the basis of the model testing; fluid pressures are directly comparable with the model predictions and are a key element of fracture nucleation and presentation. We summarize the tectonic and sedimentary history of the Piceance Basin based on our automated history reconstruction and published interpretations. The narrative and figures provide the basic material we have quantified for our CIRF.B basin simulator input. This data supplements our existing well data interpretation approach. It provides an independent check of the automated sedimentary/subsidence history reconstruction module. Fluid pressure data was gathered and analyzed. This data serves two functions. Fluid pressure distribution across the basin provides a quantitative test as it is a direct prediction of CIRF.B. Furthermore, fluid pressure modifies effective stress. It thereby enters fracture nucleation criteria and fracture extension rate and aperture laws. The pressure data is presented in Appendix Din terms of overpressure maps and isosurfaces.

  15. Stochastic imaging of oil and gas reservoirs

    SciTech Connect

    Fehler, M.; Roberts, P.; Xie, Xiao-Bi; Benites, R.; Wu, Ru-Shan

    1996-07-01

    This is the final report of a three-year, Laboratory-Directed Research and Development (LDRD) project at the Los Alamos National Laboratory (LANL). In this project, we have been developing and testing methods for modelling and inversion of wave propagation through complex media. We have developed methods for modelling wave propagation in media that is characterized by both deterministic and stochastic components. Four methods have been successfully developed and tested to date: (1) an efficient but approximate method to model wave propagation in complex media, (2) an exact method for modelling wave propagation in complex media using a boundary integral approach, (3) a method for determining properties of a one-dimensional (lD) media composed of a sequence of thin layers each with random thickness and velocity, and (4) modelling of diffraction and resonance due to a low-velocity body. Our most recent efforts focused on extending the approximate method for modeling wave propagation in complex media to include the effects of singly reflected waves, which is essential for modeling seismic data collected by the petroleum industry. In addition, an effort has been made to quantify the limitations of the method.

  16. EXPLOITATION AND OPTIMIZATION OF RESERVOIR PERFORMANCE IN HUNTON FORMATION, OKLAHOMA

    SciTech Connect

    Mohan Kelkar

    2003-04-01

    West Carney Field produces from Hunton Formation. All the wells produce oil, water and gas. The main objective of this study is to understand the unique behavior observed in the field. This behavior includes: (1) Decrease in WOR over time; (2) Decrease in GOR at initial stages; (3) High decline rates of oil and gas; and (4) strong hydrodynamic connectivity between wells. This report specifically addresses two issues relevant to our understanding of the West Carney reservoir. By using core and log data as well as fluorescence information, we demonstrate that our hypothesis of how the reservoir is formed is consistent with these observations. Namely, oil migrated in water wet reservoir, over time, oil changed the wettability of some part of the reservoir, oil eventually leaked to upper formations prompting re-introduction of water into reservoir. Because of change in wettability, different pore size distributions responded differently to water influx. This hypothesis is consistent with fluorescence and porosity data, as we explain it in this quarterly report. The second issue deals with how to best calculate connected oil volume in the reservoir. The log data does not necessarily provide us with relevant information regarding oil in place. However, we have developed a new material balance technique to calculate the connected oil volume based on observed pressure and production data. By using the technique to four different fields producing from Hunton formation, we demonstrate that the technique can be successfully applied to calculate the connected oil in place.

  17. Open-System Magma Reservoir Affects Gas Segregation, Vesiculation, Fragmentation and Lava/Pyroclast Dispersal During the 1.2 km-deep 2007-2010 Submarine Eruption at West Mata Volcano

    NASA Astrophysics Data System (ADS)

    Rubin, K. H.; Clague, D. A.; Embley, R. W.; Hellebrand, E.; Soule, S. A.; Resing, J.

    2014-12-01

    West Mata, a small, active rear-arc volcano in the NE Lau Basin, erupts crystal and gas rich boninite magma. Eruptions were observed at the summit (1.2 km water depth) during 5 ROV Jason dives in 2009 (the deepest erupting submarine volcano observed to date). Subsequent ROV and ship-based bathymetric mapping revealed that a pit crater formed and the summit eruption ceased in 2010, with roughly simultaneous eruptions along the SW rift zone. During the summit eruption, a combination of water depth, H2O-CO2-rich and high crystallinity magma, a split in the conduit to feed two vent sites, and waxing/waning magma supply led to a range of effusive/explosive eruption styles and volcanic deposit types. The 2-3 vent Hades cluster and the lone Prometheus vent had different eruption characteristics. Petrographic, petrologic and geochemical studies of erupted products indicate a change in magma composition in time and space over a period of 3.5 yrs, suggesting a small, open-system magma reservoir within the volcano. Prometheus (1174m depth) produced mostly pyroclastic material during our observations (e.g., highly vesicular glowing fluidal ejecta that cooled in the water column and rounded recycled dense clasts), but sampling and 210Po radiometric dating show that several months prior pillowed lava flows, subsequently covered with cm-sized pyroclasts, had flowed >50m from the vent. In contrast, vents at Hades (1200m depth) cycled between lava production and vigorous degassing, 10-20m high fire fountains and bursts of glowing lava-skinned bubbles, the products of which froze/broke in the water column, forming unstable cones of spatter and scoria near the vents. We hypothesize that bubbles collapse rather than form lava balloons because of skin brittleness (from high crystal content) and hydrostatic pressure. Clast settling times and patterns suggest >100m water column rise height for 10+ cm-sized fragments. Pillow flows were also observed to be issuing from the base of the Hades cones some 30-50m below, and had traveled 100 m from the vent in the months before. This, plus hydrophone and water column data (Embley et al., G3, in review), and the occurrence of extensive deposits of young, glassy, identical composition cm-sized fragmental material 250 m from Hades suggest an earlier more vigorous phase of the eruption.

  18. New correlations for dew-point, specific gravity and producing yield for gas condensates 

    E-print Network

    Ovalle Cortissoz, Adriana Patricia

    2002-01-01

    This work presents four newly developed correlations to estimate dew-point pressure, current specific gravity and producing yield of gas condensate reservoirs. The first correlation may be used to predict the dew-point pressure of the reservoir gas...

  19. 30 CFR 250.1150 - What are the general reservoir production requirements?

    Code of Federal Regulations, 2011 CFR

    2011-07-01

    ... 30 Mineral Resources 2 2011-07-01 2011-07-01 false What are the general reservoir production requirements? 250.1150 Section 250.1150 Mineral Resources BUREAU OF OCEAN ENERGY MANAGEMENT, REGULATION, AND... SHELF Oil and Gas Production Requirements General § 250.1150 What are the general reservoir...

  20. 30 CFR 250.1159 - May the Regional Supervisor limit my well or reservoir production rates?

    Code of Federal Regulations, 2011 CFR

    2011-07-01

    ... reservoir production rates? 250.1159 Section 250.1159 Mineral Resources BUREAU OF OCEAN ENERGY MANAGEMENT... OUTER CONTINENTAL SHELF Oil and Gas Production Requirements Production Rates § 250.1159 May the Regional Supervisor limit my well or reservoir production rates? (a) The Regional Supervisor may set a...

  1. Upper Almond and Lewis reservoir geometries, southwestern Wyoming and northwestern Colorado

    SciTech Connect

    Hendricks, M.L.

    1996-06-01

    Upper Almond marine sandstones are major petroleum reservoirs in southwestern Wyoming. These sandstones were deposited as part of a transgressive systems tract which capped fluvial and coastal plain sediments of the upper Ericson and lower Almond formations. Marine sandstone reservoirs were deposited in shoreface and tidal channel environments. Shoreface environments in the Echo Springs-Standard Draw trend are extensive and constitute major gas reserves in Carbon County. Shoreface and tidal channel deposits are major oil and gas reservoirs at Patrick Draw Field, Sweetwater County. Major gas resources in upper Almond marine sandstones are yet to be exploited in the deeper portions of the Great Divide, Washakie, and Sand Wash basins. Tapping this basin centered gas resource will require careful reservoir modeling and fracture treatments that significantly increase permeability and reservoir flow. Lewis sandstones are also petroleum reservoirs in the Great Divide, Washakie, and Sand Wash basins. The sandstones are part of the final Cretaceous regressive systems tract in southwestern Wyoming and northwestern Colorado. Well developed clinoforms accompany Lewis and Fox Hills progradation and basin fill. Associated with these progradational systems are correlative density flow and turbidite deposits that locally form reservoirs. These reservoirs commonly occur near the toe of prograding clinoforms and are trapped by rapid facies changes to impermeable siltstones and basinal shales.

  2. Induced Microearthquake Patterns in Hydrocarbon and Geothermal Reservoirs W. Scott Phillips

    E-print Network

    Induced Microearthquake Patterns in Hydrocarbon and Geothermal Reservoirs W. Scott Phillips James T microseismic events in hydrocarbon and geothermal reservoirs. By deploying sensors downhole, data sets have Key Words: induced microseismicity, geothermal, oil and gas, fluid flow, location #12;2 Introduction

  3. URTeC 1620617 Thermal Shock in Reservoir Rock Enhances the Hydraulic

    E-print Network

    Patzek, Tadeusz W.

    URTeC 1620617 Thermal Shock in Reservoir Rock Enhances the Hydraulic Fracturing of Gas Shales Saeid through strain and stress. As the temperature diffuses from hydraulic fracture into reservoir the rock matrix beyond hydraulic fracturing stimulation by cooling down the rock. The physics

  4. Petroleum recovery: Reservoir engineering and recovery methods. (Latest citations from the NTIS bibliographic database). Published Search

    SciTech Connect

    Not Available

    1994-09-01

    The bibliography contains citations concerning field projects and supporting research on petroleum recovery and reservoir technology. Recovery agents and methods are discussed including responsive copolymers, microemulsions, surfactants, steam injection, gas injection, miscible displacement, and thermal processes. Reservoir modeling, simulation, and performance are examined. (Contains 250 citations and includes a subject term index and title list.)

  5. Calculation of CO2 column heights in depleted gas fields from known pre-production gas column heights

    E-print Network

    Wilkinson, Mark

    also requires an estimation of the amount of CO2 that can be safely stored beneath the reservoir seal estimates. However, under reservoir conditions the density of CO2 is substantially higher than natural gas is substantially greater than that of natural gas under reservoir conditions, a column height of CO2 exerts a lower

  6. Calderas and magma reservoirs

    NASA Astrophysics Data System (ADS)

    Cashman, Katharine V.; Giordano, Guido

    2014-11-01

    Large caldera-forming eruptions have long been a focus of both petrological and volcanological studies; petrologists have used the eruptive products to probe conditions of magma storage (and thus processes that drive magma evolution), while volcanologists have used them to study the conditions under which large volumes of magma are transported to, and emplaced on, the Earth's surface. Traditionally, both groups have worked on the assumption that eruptible magma is stored within a single long-lived melt body. Over the past decade, however, advances in analytical techniques have provided new views of magma storage regions, many of which provide evidence of multiple melt lenses feeding a single eruption, and/or rapid pre-eruptive assembly of large volumes of melt. These new petrological views of magmatic systems have not yet been fully integrated into volcanological perspectives of caldera-forming eruptions. Here we explore the implications of complex magma reservoir configurations for eruption dynamics and caldera formation. We first examine mafic systems, where stacked-sill models have long been invoked but which rarely produce explosive eruptions. An exception is the 2010 eruption of Eyjafjallajökull volcano, Iceland, where seismic and petrologic data show that multiple sills at different depths fed a multi-phase (explosive and effusive) eruption. Extension of this concept to larger mafic caldera-forming systems suggests a mechanism to explain many of their unusual features, including their protracted explosivity, spatially variable compositions and pronounced intra-eruptive pauses. We then review studies of more common intermediate and silicic caldera-forming systems to examine inferred conditions of magma storage, time scales of melt accumulation, eruption triggers, eruption dynamics and caldera collapse. By compiling data from large and small, and crystal-rich and crystal-poor, events, we compare eruptions that are well explained by simple evacuation of a zoned magma chamber (termed the Standard Model by Gualda and Ghiorso, 2013) to eruptions that are better explained by tapping multiple, rather than single, melt lenses stored within a largely crystalline mush (which we term complex magma reservoirs). We then discuss the implications of magma storage within complex, rather than simple, reservoirs for identifying magmatic systems with the potential to produce large eruptions, and for monitoring eruption progress under conditions where successive melt lenses may be tapped. We conclude that emerging views of complex magma reservoir configurations provide exciting opportunities for re-examining volcanological concepts of caldera-forming systems.

  7. Squeezed-reservoir lasers

    SciTech Connect

    Marte, M.A.M.; Ritsch, H.; Walls, D.F.

    1988-10-01

    The effects of squeezing the reservoir coupled to the atoms of a laser are compared with the effects of squeezing the electromagnetic vacuum modes entering the laser cavity. The analysis includes the semiclassical theory, a calculation of the phase diffusion rate and the laser linewidth in the rotating-wave van der Pol model of the laser, and squeezing spectra calculated from a linearized theory without adiabatic elimination of the atoms. It is demonstrated that good squeezing is achievable in the laser output if an appropriate classical field driving the atoms is added.

  8. TopTop--Down Intelligent ReservoirDown Intelligent Reservoir Modeling (TDIRM)Modeling (TDIRM)

    E-print Network

    Mohaghegh, Shahab

    TopTop--Down Intelligent ReservoirDown Intelligent Reservoir Modeling (TDIRM)Modeling (TDIRM) A NEW APPROACH IN RESERVOIR MODELING BY INTEGRATING CLASSIC RESERVOIR ENGINEERING WITH ARTIFICIAL INTELLIGENCE2009 AAPG Annual Conference, Denver, Colorado #12;Reservoir SimulationReservoir Simulation Actual

  9. 49 CFR 393.50 - Reservoirs required.

    Code of Federal Regulations, 2014 CFR

    2014-10-01

    ... 2014-10-01 2014-10-01 false Reservoirs required. 393.50 Section 393.50 Transportation...NECESSARY FOR SAFE OPERATION Brakes § 393.50 Reservoirs required. (a) Reservoir capacity for air-braked power units...

  10. 49 CFR 393.50 - Reservoirs required.

    Code of Federal Regulations, 2010 CFR

    2010-10-01

    ... 2010-10-01 2010-10-01 false Reservoirs required. 393.50 Section 393.50 Transportation...NECESSARY FOR SAFE OPERATION Brakes § 393.50 Reservoirs required. (a) Reservoir capacity for air-braked power units...

  11. 49 CFR 393.50 - Reservoirs required.

    Code of Federal Regulations, 2013 CFR

    2013-10-01

    ... 2013-10-01 2013-10-01 false Reservoirs required. 393.50 Section 393.50 Transportation...NECESSARY FOR SAFE OPERATION Brakes § 393.50 Reservoirs required. (a) Reservoir capacity for air-braked power units...

  12. 49 CFR 393.50 - Reservoirs required.

    Code of Federal Regulations, 2012 CFR

    2012-10-01

    ... 2012-10-01 2012-10-01 false Reservoirs required. 393.50 Section 393.50 Transportation...NECESSARY FOR SAFE OPERATION Brakes § 393.50 Reservoirs required. (a) Reservoir capacity for air-braked power units...

  13. 49 CFR 393.50 - Reservoirs required.

    Code of Federal Regulations, 2011 CFR

    2011-10-01

    ... 2011-10-01 2011-10-01 false Reservoirs required. 393.50 Section 393.50 Transportation...NECESSARY FOR SAFE OPERATION Brakes § 393.50 Reservoirs required. (a) Reservoir capacity for air-braked power units...

  14. 21 CFR 868.5320 - Reservoir bag.

    Code of Federal Regulations, 2010 CFR

    2010-04-01

    ...2010-04-01 2010-04-01 false Reservoir bag. 868.5320 Section 868.5320 Food and...Therapeutic Devices § 868.5320 Reservoir bag. (a) Identification. A reservoir bag is a device, usually made of conductive...

  15. 21 CFR 868.5320 - Reservoir bag.

    Code of Federal Regulations, 2012 CFR

    2012-04-01

    ...2012-04-01 2012-04-01 false Reservoir bag. 868.5320 Section 868.5320 Food and...Therapeutic Devices § 868.5320 Reservoir bag. (a) Identification. A reservoir bag is a device, usually made of conductive...

  16. 21 CFR 868.5320 - Reservoir bag.

    Code of Federal Regulations, 2014 CFR

    2014-04-01

    ...2014-04-01 2014-04-01 false Reservoir bag. 868.5320 Section 868.5320 Food and...Therapeutic Devices § 868.5320 Reservoir bag. (a) Identification. A reservoir bag is a device, usually made of conductive...

  17. 21 CFR 868.5320 - Reservoir bag.

    Code of Federal Regulations, 2011 CFR

    2011-04-01

    ...2011-04-01 2011-04-01 false Reservoir bag. 868.5320 Section 868.5320 Food and...Therapeutic Devices § 868.5320 Reservoir bag. (a) Identification. A reservoir bag is a device, usually made of conductive...

  18. 21 CFR 868.5320 - Reservoir bag.

    Code of Federal Regulations, 2013 CFR

    2013-04-01

    ...2013-04-01 2013-04-01 false Reservoir bag. 868.5320 Section 868.5320 Food and...Therapeutic Devices § 868.5320 Reservoir bag. (a) Identification. A reservoir bag is a device, usually made of conductive...

  19. Geothermal Reservoir Well Stimulation Program: technology transfer

    SciTech Connect

    Not Available

    1980-05-01

    A literature search on reservoir and/or well stimulation techniques suitable for application in geothermal fields is presented. The literature on stimulation techniques in oil and gas field applications was also searched and evaluated as to its relevancy to geothermal operations. The equivalent low-temperature work documented in the open literature is cited, and an attempt is made to evaluate the relevance of this information as far as high-temperature stimulation work is concerned. Clays play an important role in any stimulation work. Therefore, special emphasis has been placed on clay behavior anticipated in geothermal operations. (MHR)

  20. 120 GRC BULLETIN Reservoir Engineering

    E-print Network

    Foulger, G. R.

    . Mammoth Mountain is an ac- tive volcano that has been venting carbon dioxide (CO2) at a high rate since in reservoirs through changes of temperature, pres- sure, and phase of pore fluids and the pro- gressive removal for reservoir-wide monitoring of produc- ing geothermal fields. Introduction The removal of fluid from