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Sample records for gas reservoir bluebell-altamont

  1. Geostatistics applied to gas reservoirs

    SciTech Connect

    Meunier, G.; Coulomb, C.; Laille, J.P. )

    1989-09-01

    The spatial distribution of many of the physical parameters connected with a gas reservoir is of primary interest to both engineers and geologists throughout the study, development, and operation of a field. It is therefore desirable for the distribution to be capable of statistical interpretation, to have a simple graphical representation, and to allow data to be entered from either two- or three-dimensional grids. To satisfy these needs while dealing with the geographical variables, new methods have been developed under the name geostatistics. This paper describes briefly the theory of geostatistics and its most recent improvements for the specific problem of subsurface description. The external-drift technique has been emphasized in particular, and in addition, four case studies related to gas reservoirs are presented.

  2. Atlas of major Texas gas reservoirs

    SciTech Connect

    Kosters, E.C.; Bebout, D.G.; Seni, S.J.; Garret, C.M.; Brown, L.F.; Hamlin, H.S.; Dutton, S.P.; Ruppel, S.C.; Finley, R.J.; Tyler, N.

    1990-01-01

    This volume contains information on more than 1,828 reservoirs, with emphasis on 868 reservoirs that have cumulative gas production of greater than 30 billion cubic feet of natural gas. Texas gas reservoirs are classified into 73 plays, each of which is described in terms of its principal geologic and engineering production characteristics. This assessment of the similarities of gas occurrence within each play will assist in defining controls on gas accumulation, in identifying resources affected by new technology, and in expanding technology to maximize recovery through improved field development and production practices.

  3. Basic gas storage reservoir operations and analysis

    SciTech Connect

    Nowaczewski, S.F. )

    1994-08-01

    Operation and performance analysis of gas storage reservoirs is described in very basic and general terms. Reservoir selection criteria (capacity, deliverability, location, field type, trap type) are reviewed. Well construction considerations and practices (casing sizing, placement, and cementing) are highlighted with regard to the need for long-lived safe operation. Deliverability estimation and prediction and gas inventory methodologies are described. The benefits of high density, high quality data on gas pressure and composition, production rates and volumes, and geologic information to reservoir performance evaluation and prediction are demonstrated.

  4. 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.

  5. Reservoir Greenhouse Gas Emissions at Russian HPP

    SciTech Connect

    Fedorov, M. P.; Elistratov, V. V.; Maslikov, V. I.; Sidorenko, G. I.; Chusov, A. N.; Atrashenok, V. P.; Molodtsov, D. V.; Savvichev, A. S.; Zinchenko, A. V.

    2015-05-15

    Studies of greenhouse-gas emissions from the surfaces of the world’s reservoirs, which has demonstrated ambiguity of assessments of the effect of reservoirs on greenhouse-gas emissions to the atmosphere, is analyzed. It is recommended that greenhouse- gas emissions from various reservoirs be assessed by the procedure “GHG Measurement Guidelines for Fresh Water Reservoirs” (2010) for the purpose of creating a data base with results of standardized measurements. Aprogram for research into greenhouse-gas emissions is being developed at the St. Petersburg Polytechnic University in conformity with the IHA procedure at the reservoirs impounded by the Sayano-Shushenskaya and Mainskaya HPP operated by the RusHydro Co.

  6. Enhanced gas recovery from a moderately strong water drive reservoir

    SciTech Connect

    Chesney, T.P.; Lewis, R.C.; Trice, M.L. Jr.; Bebout, D.G.; Bachman, A.L.

    1981-01-01

    Blowdown performance of several South Texas water drive gas reservoirs indicated a substantial quantity of gas was trapped in water invaded regions. Depressuring of the reservoir by withdrawing large volumes of water in order to recover trapped gas was evaluated. The evaluation, implementation, and results of this enhanced gas recovery technique are discussed for one of these reservoirs.

  7. Accounting for Greenhouse Gas Emissions from Reservoirs ...

    EPA Pesticide Factsheets

    Nearly three decades of research has demonstrated that the impoundment of rivers and the flooding of terrestrial ecosystems behind dams can increase rates of greenhouse gas emission, particularly methane. The 2006 IPCC Guidelines for National Greenhouse Gas Inventories includes a methodology for estimating methane emissions from flooded lands, but the methodology was published as an appendix to be used as a ‘basis for future methodological development’ due to a lack of data. Since the 2006 Guidelines were published there has been a 6-fold increase in the number of peer reviewed papers published on the topic including reports from reservoirs in India, China, Africa, and Russia. Furthermore, several countries, including Iceland, Switzerland, and Finland, have developed country specific methodologies for including flooded lands methane emissions in their National Greenhouse Gas Inventories. This presentation will include a review of the literature on flooded land methane emissions and approaches that have been used to upscale emissions for national inventories. We will also present ongoing research in the United States to develop a country specific methodology. In the U.S., research approaches include: 1) an effort to develop predictive relationships between methane emissions and reservoir characteristics that are available in national databases, such as reservoir size and drainage area, and 2) a national-scale probabilistic survey of reservoir methane em

  8. 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.

  9. Exploitation of subsea gas hydrate reservoirs

    NASA Astrophysics Data System (ADS)

    Janicki, Georg; Schlüter, Stefan; Hennig, Torsten; Deerberg, Görge

    2016-04-01

    Natural gas hydrates are considered to be a potential energy resource in the future. They occur in permafrost areas as well as in subsea sediments and are stable at high pressure and low temperature conditions. According to estimations the amount of carbon bonded in natural gas hydrates worldwide is two times larger than in all known conventional fossil fuels. Besides technical challenges that have to be overcome climate and safety issues have to be considered before a commercial exploitation of such unconventional reservoirs. The potential of producing natural gas from subsea gas hydrate deposits by various means (e.g. depressurization and/or injection of carbon dioxide) is numerically studied in the frame of the German research project »SUGAR«. The basic mechanisms of gas hydrate formation/dissociation and heat and mass transport in porous media are considered and implemented into a numerical model. The physics of the process leads to strong non-linear couplings between hydraulic fluid flow, hydrate dissociation and formation, hydraulic properties of the sediment, partial pressures and seawater solution of components and the thermal budget of the system described by the heat equation. This paper is intended to provide an overview of the recent development regarding the production of natural gas from subsea gas hydrate reservoirs. It aims at giving a broad insight into natural gas hydrates and covering relevant aspects of the exploitation process. It is focused on the thermodynamic principles and technological approaches for the exploitation. The effects occurring during natural gas production within hydrate filled sediment layers are identified and discussed by means of numerical simulation results. The behaviour of relevant process parameters such as pressure, temperature and phase saturations is described and compared for different strategies. The simulations are complemented by calculations for different safety relevant problems.

  10. Monitoring gas reservoirs by seismic interferometry

    NASA Astrophysics Data System (ADS)

    Grigoli, Francesco; Cesca, Simone; Sens-Schoenfelder, Christoph; Priolo, Enrico

    2014-05-01

    Ambient seismic noise can be used to image spatial anomalies in the subsurface, without the need of recordings from seismic sources, such as earthquakes or explosions. Furthermore, the temporal variation of ambient seismic noise's can be used to infer temporal changes of the seismic velocities in the investigated medium. Such temporal variations can reflect changes of several physical properties/conditions in the medium. For example, they may be consequence of stress changes, variation of hydrogeological parameters, pore pressure and saturation changes due to fluid injection or extraction. Passive image interferometry allows to continuously monitor small temporal changes of seismic velocities in the subsurface, making it a suitable tool to monitor time-variant systems such as oil and gas reservoirs or volcanic environments. The technique does not require recordings from seismic sources in the classical sense, but is based on the processing of noise records. Moreover, it requires only data from one or two seismic stations, their locations constraining the sampled target area. Here we apply passive image interferometry to monitor a gas storage reservoir in northern Italy. The Collalto field (Northern Italy) is a depleted gas reservoir located at 1500 m depth, now used as a gas storage facility. The reservoir experience a significant temporal variation in the amount of stored gas: the injection phases mainly occur in the summer, while the extraction take place mostly in winter. In order to monitor induced seismicity related to gas storage operations, a seismic network (the Collalto Seismic Network) has been deployed in 2011. The Collalto Seismic Network is composed by 10 broadband stations, deployed within an area of about 20 km x 20 km, and provides high-quality continuous data since January 1st, 2012. In this work we present preliminary results from ambient noise interferometry using a two-months sample of continuous seismic data, i.e. from October 1st, 2012, to the

  11. 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.

  12. 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.

  13. 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.

  14. 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.

  15. Reservoir model for Hillsboro gas storage field management

    USGS Publications Warehouse

    Udegbunam, Emmanuel O.; Kemppainen, Curt; Morgan, Jim; ,

    1995-01-01

    A 3-dimensional reservoir model is used to understand the behavior of the Hillsboro Gas Storage Field and to investigate the field's performance under various future development. Twenty-two years of the gas storage reservoir history, comprising the initial gas bubble development and seasonal gas injection and production cycles, are examined with a full-field, gas water, reservoir simulation model. The results suggest that the gas-water front is already in the vicinity of the west observation well that increasing the field's total gas-in-place volume would cause gas to migrate beyond the east, north and west observation well. They also suggest that storage enlargement through gas injection into the lower layers may not prevent gas migration. Moreover, the results suggest that the addition of strategically-located new wells would boost the simulated gas deliverabilities.

  16. 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...

  17. Estimation of Carbon Dioxide Storage Capacity for Depleted Gas Reservoirs

    NASA Astrophysics Data System (ADS)

    Lai, Yen Ting; Shen, Chien-Hao; Tseng, Chi-Chung; Fan, Chen-Hui; Hsieh, Bieng-Zih

    2015-04-01

    A depleted gas reservoir is one of the best options for CO2 storage for many reasons. First of all, the storage safety or the caprock integrity has been proven because the natural gas was trapped in the formation for a very long period of time. Also the formation properties and fluid flow characteristics for the reservoir have been well studied since the discovery of the gas reservoir. Finally the surface constructions and facilities are very useful and relatively easy to convert for the use of CO2 storage. The purpose of this study was to apply an analytical approach to estimate CO2 storage capacity in a depleted gas reservoir. The analytical method we used is the material balance equation (MBE), which have been widely used in natural gas storage. We proposed a modified MBE for CO2 storage in a depleted gas reservoir by introducing the z-factors of gas, CO2 and the mixture of the two. The MBE can be derived to a linear relationship between the ratio of pressure to gas z-factor (p/z) and the cumulative term (Gp-Ginj, where Gp is the cumulative gas production and Ginj is the cumulative CO2 injection). The CO2 storage capacity can be calculated when constraints of reservoir recovery pressure are adopted. The numerical simulation was also used for the validation of the theoretical estimation of CO2 storage capacity from the MBE. We found that the quantity of CO2 stored is more than that of gas produced when the reservoir pressure is recovered from the abandon pressure to the initial pressure. This result was basically from the fact that the gas- CO2 mixture z-factors are lower than the natural gas z-factors in reservoir conditions. We also established a useful p/z plot to easily observe the pressure behavior of CO2 storage and efficiently calculate the CO2 storage capacity. The application of the MBE we proposed was demonstrated by a case study of a depleted gas reservoir in northwestern Taiwan. The estimated CO2 storage capacities from conducting reservoir simulation

  18. 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

  19. Gas condensate reservoir characterisation for CO2 geological storage

    NASA Astrophysics Data System (ADS)

    Ivakhnenko, A. P.

    2012-04-01

    During oil and gas production hydrocarbon recovery efficiency is significantly increased by injecting miscible CO2 gas in order to displace hydrocarbons towards producing wells. This process of enhanced oil recovery (EOR) might be used for the total CO2 storage after complete hydrocarbon reservoir depletion. This kind of potential storage sites was selected for detailed studies, including generalised development study to investigate the applicability of CO2 for storages. The study is focused on compositional modelling to predict the miscibility pressures. We consider depleted gas condensate field in Kazakhstan as important target for CO2 storage and EOR. This reservoir being depleted below the dew point leads to retrograde condensate formed in the pore system. CO2 injection in the depleted gas condensate reservoirs may allow enhanced gas recovery by reservoir pressurisation and liquid re-vaporisation. In addition a number of geological and petrophysical parameters should satisfy storage requirements. Studied carbonate gas condensate and oil field has strong seal, good petrophysical parameters and already proven successful containment CO2 and sour gas in high pressure and high temperature (HPHT) conditions. The reservoir is isolated Lower Permian and Carboniferous carbonate platform covering an area of about 30 km. The reservoir contains a gas column about 1.5 km thick. Importantly, the strong massive sealing consists of the salt and shale seal. Sour gas that filled in the oil-saturated shale had an active role to form strong sealing. Two-stage hydrocarbon saturation of oil and later gas within the seal frame were accompanied by bitumen precipitation in shales forming a perfect additional seal. Field hydrocarbon production began three decades ago maintaining a strategy in full replacement of gas in order to maintain pressure of the reservoir above the dew point. This was partially due to the sour nature of the gas with CO2 content over 5%. Our models and

  20. Characterization of oil and gas reservoir heterogeneity

    SciTech Connect

    Sharma, G.D.

    1992-01-01

    The ultimate objective of this cooperative research project is to characterize Alaskan petroleum reservoirs in terms of their reserves, physical and chemical properties, geologic configuration in relation to lithofacies and structure, and development potential. The project has two tasks: Task 1 is a geological description of the reservoirs including petrophysical properties, i.e., porosity, permeability, permeability variation, formation depth, temperature, and net pay, facies changes and reservoir structures as drawn from cores, well logs, and other geological data. Task 2 is reservoir fluid characterization-determination of physical properties of reservoir fluids including density, viscosity, phase distributions and composition as well as petrogenesis-source rock identification; and the study of asphaltene precipitation for Alaskan crude oils. Results are discussed.

  1. Characterization of oil and gas reservoir heterogeneity

    SciTech Connect

    Sharma, G.D.

    1992-01-01

    The ultimate objective of this cooperative research project is to characterize Alaskan petroleum reservoirs in terms of their reserves, physical and chemical properties, geologic configuration in relation to lithofacies and structure, and development potential. The project has two tasks: Task 1 is a geological description of the reservoirs including petrophysical properties, i.e., porosity, permeability, permeability variation, formation depth, temperature, and net pay, facies changes and reservoir structures as drawn from cores, well logs, and other geological data. Task 2 is reservoir fluid characterization -- determination of physical properties of reservoir fluids including density, viscosity, phase distributions and composition as well as petrogenesis -- source rock identification; and the study of asphaltene precipitation for Alaskan crude oils.

  2. Characterization of oil and gas reservoir heterogeneity

    SciTech Connect

    Sharma, G.D.

    1992-01-01

    The ultimate oojective of this cooperative research project is to characterize Alaskan petroleum reservoirs in terms of their reserves, physical and chemical properties, geologic configuration in relation to lithofacies and structure, and development potential. The project has two tasks: Task 1 is a geological description of the reservoirs including petrophysical properties, i.e., porosity, permeability, permeability variation, formation depth, temperature, and net pay, facies changes and reservoir structures as drawn from cores, well logs, and other geological data. Task 2 is reservoir fluid characterization--determination of physical properties of reservoir fluids including density, viscosity, phase distributions and composition as well as petrogenesis--source rock identification; and the study of asphaltene precipitation for Alaskan crude oils. This report presents a summary of technical progress of the well log analysis of Kuparuk Field, Northslope, Alaska.

  3. 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.

  4. 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

  5. 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.

  6. 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.

  7. Efficient computation of the compositional model for gas condensate reservoirs

    NASA Astrophysics Data System (ADS)

    Zhou, Jifu; Li, Jiachun; Ye, Jigen

    2000-12-01

    In this paper, a direct method, unsymmetric-pattern multifrontal factorization, for a large sparse system of linear equations is applied in the compositional reservoir model. The good performances of this approach are shown by solving the Poisson equation. And then the numerical module is embedded in the compositional model for simulating X1/5 (3) gas condensate reservoir in KeKeYa gas field, Northwest China. The results of oil/gas reserves, variations of stratum pressure and oil/gas production, etc. are compared with the observation. Good agreement comparable to COMP4 model is achieved, suggesting that the present model is both efficient and powerful in compositional reservoir simulations.

  8. Gas hydrate reservoir characteristics and economics

    SciTech Connect

    Collett, T.S.; Bird, K.J.; Burruss, R.C.; Lee, Myung W.

    1992-06-01

    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.

  9. Gas hydrate reservoir characteristics and economics

    SciTech Connect

    Collett, T.S.; Bird, K.J.; Burruss, R.C.; Lee, Myung W.

    1992-01-01

    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.

  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, 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...

  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, 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...

  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, 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...

  13. 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.

  14. Accounting for Greenhouse Gas Emissions from Reservoirs

    EPA Science Inventory

    Nearly three decades of research has demonstrated that the impoundment of rivers and the flooding of terrestrial ecosystems behind dams can increase rates of greenhouse gas emission, particularly methane. The 2006 IPCC Guidelines for National Greenhouse Gas Inventories includes ...

  15. 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.

  16. Measuring and managing reservoir greenhouse gas emissions

    EPA Science Inventory

    Methane (CH4) is the second most important anthropogenic greenhouse gas with a heat trapping capacity 34 times greater than that of carbon dioxide on a 100 year time scale. Known anthropogenic CH4 sources include livestock production, rice agriculture, landfills, and natural gas...

  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, 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...

  18. 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.

  19. 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...

  20. 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...

  1. 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...

  2. 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...

  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

    ... 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...

  4. 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.

  5. 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.

  6. 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.

  7. 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.

  8. Nuclear Well Log Properties of Natural Gas Hydrate Reservoirs

    NASA Astrophysics Data System (ADS)

    Burchwell, A.; Cook, A.

    2015-12-01

    Characterizing gas hydrate in a reservoir typically involves a full suite of geophysical well logs. The most common method involves using resistivity measurements to quantify the decrease in electrically conductive water when replaced with gas hydrate. Compressional velocity measurements are also used because the gas hydrate significantly strengthens the moduli of the sediment. At many gas hydrate sites, nuclear well logs, which include the photoelectric effect, formation sigma, carbon/oxygen ratio and neutron porosity, are also collected but often not used. In fact, the nuclear response of a gas hydrate reservoir is not known. In this research we will focus on the nuclear log response in gas hydrate reservoirs at the Mallik Field at the Mackenzie Delta, Northwest Territories, Canada, and the Gas Hydrate Joint Industry Project Leg 2 sites in the northern Gulf of Mexico. Nuclear logs may add increased robustness to the investigation into the properties of gas hydrates and some types of logs may offer an opportunity to distinguish between gas hydrate and permafrost. For example, a true formation sigma log measures the thermal neutron capture cross section of a formation and pore constituents; it is especially sensitive to hydrogen and chlorine in the pore space. Chlorine has a high absorption potential, and is used to determine the amount of saline water within pore spaces. Gas hydrate offers a difference in elemental composition compared to water-saturated intervals. Thus, in permafrost areas, the carbon/oxygen ratio may vary between gas hydrate and permafrost, due to the increase of carbon in gas hydrate accumulations. At the Mallik site, we observe a hydrate-bearing sand (1085-1107 m) above a water-bearing sand (1107-1140 m), which was confirmed through core samples and mud gas analysis. We observe a decrease in the photoelectric absorption of ~0.5 barnes/e-, as well as an increase in the formation sigma readings of ~5 capture units in the water-bearing sand as

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

    NASA Astrophysics Data System (ADS)

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

    2014-12-01

    While scientists are paying increasing attention to the seismicity potentially induced by hydrocarbon exploitation, little is known about the reverse problem, i.e. the impact of active faulting and earthquakes on hydrocarbon reservoirs. The recent 2012 earthquakes in Emilia, Italy, 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. Based on the analysis of over 400 borehole datasets from wells drilled along the Ferrara-Romagna Arc, a large oil and gas reserve in the southeastern Po Plain, we found that the 2012 earthquakes occurred within a cluster of sterile wells surrounded by productive ones. 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. Our findings have two important practical implications: (1) they may allow major seismogenic zones to be identified in areas of sparse seismicity, and (2) suggest that gas should be stored in exploited reservoirs rather than in sterile hydrocarbon traps or aquifers as this is likely to reduce the hazard of triggering significant earthquakes.

  10. Development of Porosity Measurement Method in Shale Gas Reservoir Rock

    NASA Astrophysics Data System (ADS)

    Siswandani, Alita; Nurhandoko, BagusEndar B.

    2016-08-01

    The pore scales have impacts on transport mechanisms in shale gas reservoirs. In this research, digital helium porosity meter is used for porosity measurement by considering real condition. Accordingly it is necessary to obtain a good approximation for gas filled porosity. Shale has the typical effective porosity that is changing as a function of time. Effective porosity values for three different shale rocks are analyzed by this proposed measurement. We develop the new measurement method for characterizing porosity phenomena in shale gas as a time function by measuring porosity in a range of minutes using digital helium porosity meter. The porosity of shale rock measured in this experiment are free gas and adsorbed gas porosoty. The pressure change in time shows that porosity of shale contains at least two type porosities: macro scale porosity (fracture porosity) and fine scale porosity (nano scale porosity). We present the estimation of effective porosity values by considering Boyle-Gay Lussaac approximation and Van der Waals approximation.

  11. Gas reservoir and a method to supply gas to plasma tubes

    DOEpatents

    Stautner, Ernst Wolfgang; Michael, Joseph Darryl

    2017-01-31

    A reservoir for storing and supplying a portion of a reservoir gas into a gas-filled tube is presented. The reservoir includes a first vessel having a thermally conductive surface, a meshed vessel having a lid, and placed inside the first vessel to form a cavity between the meshed vessel and the first vessel, at least one tray placed inside the meshed vessel to divide an inner space of the meshed vessel into a plurality of compartments, a sorbent material placed inside the plurality of compartments in the meshed vessel, a temperature control device positioned such that a first portion of the temperature control device is in physical contact with at least a portion of the thermally conductive surface, and a change in the temperature of the temperature control device changes the temperature of the sorbent material, wherein the reservoir gas is retained by the sorbent material at the storage temperature.

  12. 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.

  13. Prediction of Gas Injection Performance for Heterogeneous Reservoirs

    SciTech Connect

    Franklin M. Orr, Jr; Martin J. Blunt

    1998-03-31

    This project performs research in four main areas: laboratory experiments to measure three-phase relative permeability; network modeling to predict three-phase relative perme- ability; benchmark simulations of gas injection and waterfl ooding at the field scale; and the development of fast streamline techniques to study field-scale oil. The aim of the work is to achieve a comprehensive description of gas injection processes from the pore to the core to the reservoir scale. In this report we provide a detailed description of our measurements of three-phase relative permeability.

  14. 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.

  15. Prediction of Gas Injection Performance for Heterogeneous Reservoirs

    SciTech Connect

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

    1998-04-30

    This report describes research into gas injection processes in four main areas: laboratory experiments to measure three-phase relative permeability; network modeling to predict three-phase relative permeability; benchmark simulations of gas injection and water flooding at the field scale; and the development of fast streamline techniques to study field-scale ow. The aim of the work is to achieve a comprehensive description of gas injection processes from the pore to the core to the reservoir scale. To this end, measurements of three-phase relative pemeability have been made and compared with predictions from pore scale modeling. At the field scale, streamline-based simulation has been extended to compositional displacements, providing a rapid method to predict oil recovery from gas injection.

  16. The Noble Gas Fingerprint in a UK Unconventional Gas Reservoir

    NASA Astrophysics Data System (ADS)

    McKavney, Rory; Gilfillan, Stuart; Györe, Domokos; Stuart, Fin

    2016-04-01

    In the last decade, there has been an unprecedented expansion in the development of unconventional hydrocarbon resources. Concerns have arisen about the effect of this new industry on groundwater quality, particularly focussing on hydraulic fracturing, the technique used to increase the permeability of the targeted tight shale formations. Methane contamination of groundwater has been documented in areas of gas production1 but conclusively linking this to fugitive emissions from unconventional hydrocarbon production has been controversial2. A lack of baseline measurements taken before drilling, and the equivocal interpretation of geochemical data hamper the determination of possible contamination. Common techniques for "fingerprinting" gas from discrete sources rely on gas composition and isotopic ratios of elements within hydrocarbons (e.g. δ13CCH4), but the original signatures can be masked by biological and gas transport processes. The noble gases (He, Ne, Ar, Kr, Xe) are inert and controlled only by their physical properties. They exist in trace quantities in natural gases and are sourced from 3 isotopically distinct environments (atmosphere, crust and mantle)3. They are decoupled from the biosphere, and provide a separate toolbox to investigate the numerous sources and migration pathways of natural gases, and have found recent utility in the CCS4 and unconventional gas5 industries. Here we present a brief overview of noble gas data obtained from a new coal bed methane (CBM) field, Central Scotland. We show that the high concentration of helium is an ideal fingerprint for tracing fugitive gas migration to a shallow groundwater. The wells show variation in the noble gas signatures that can be attributed to differences in formation water pumping from the coal seams as the field has been explored for future commercial development. Dewatering the seams alters the gas/water ratio and the degree to which noble gases degas from the formation water. Additionally the

  17. 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.

  18. 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.

  19. 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.

  20. Compressed air energy storage in depleted natural gas reservoirs: effects of porous media and gas mixing

    NASA Astrophysics Data System (ADS)

    Oldenburg, C. M.; Pan, L.

    2015-12-01

    Although large opportunities exist for compressed air energy storage (CAES) in aquifers and depleted natural gas reservoirs, only two grid-scale CAES facilities exist worldwide, both in salt caverns. As such, experience with CAES in porous media, what we call PM-CAES, is lacking and we have relied on modeling to elucidate PM-CAES processes. PM-CAES operates similarly to cavern CAES. Specifically, working gas (air) is injected through well(s) into the reservoir compressing the cushion gas (existing air in the reservoir). During energy recovery, high-pressure air from the reservoir flows first into a recuperator, then into an expander, and subsequently is mixed with fuel in a combustion turbine to produce electricity, thereby reducing compression costs. Energy storage in porous media is complicated by the solid matrix grains which provide resistance to flow (via permeability in Darcy's law); in the cap rock, low-permeability matrix provides the seal to the reservoir. The solid grains also provide storage capacity for heat that might arise from compression, viscous flow effects, or chemical reactions. The storage of energy in PM-CAES occurs variably across pressure gradients in the formation, while the solid grains of the matrix can release/store heat. Residual liquid (i.e., formation fluids) affects flow and can cause watering out at the production well(s). PG&E is researching a potential 300 MW (for ten hours) PM-CAES facility in a depleted gas reservoir near Lodi, California. Special considerations exist for depleted natural gas reservoirs because of mixing effects which can lead to undesirable residual methane (CH4) entrainment and reactions of oxygen and CH4. One strategy for avoiding extensive mixing of working gas (air) with reservoir CH4 is to inject an initial cushion gas with reduced oxygen concentration providing a buffer between the working gas (air) and the residual CH4 gas. This reduces the potential mixing of the working air with the residual CH4

  1. 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.

  2. 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.

  3. 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

  4. 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

  5. Production decline analysis for a multi-fractured horizontal well considering elliptical reservoir stimulated volumes in shale gas reservoirs

    NASA Astrophysics Data System (ADS)

    Wei, Mingqiang; Duan, Yonggang; Fang, Quantang; Zhang, Tiantian

    2016-06-01

    Multi-fractured horizontal wells (MFHWs) are an effective technique for developing shale gas reservoirs. After fracturing, stimulated reservoir volumes (SRVs) invariably exist around the wellbore. In this paper, a composite elliptical SRV model for each hydraulic fracturing stage is established, based on micro-seismic events. Both the SRV and the outer regions are assumed as single-porosity media with different formation physical parameters. Based on unstructured perpendicular bisection (PEBI) grids, a mathematical model considering Darcy flow, diffusion and adsorption/desorption in shale gas reservoirs is presented. The numerical solution is obtained by combining the control volume finite element method with the fully implicit method. The model is verified by a simplified model solution. The MFHW Blasingame production decline curves, which consider elliptical SRVs in shale gas reservoirs, are plotted by computer programming. The flow regions can be divided into five flow regimes: early formation linear flow, radial flow in the SRV region, transient flow, pseudo radial flow and boundary dominated flow. Finally, the effect of six related parameters, including the SRV area size, outer region permeability, SRV region permeability, Langmuir pressure, Langmuir volume and diffusion coefficient, are analyzed on type curves. The model presented in this paper can expand our understanding of MFHW production decline behaviors in shale gas reservoirs and can be applied to estimate reservoir properties, the SRV area, and reserves in these types of reservoirs by type curve matching.

  6. Gas accumulations in Oligocene-Miocene reservoirs in the Alpine Foreland Basin (Austria): evidence for gas mixing and gas degradation

    NASA Astrophysics Data System (ADS)

    Pytlak, L.; Gross, D.; Sachsenhofer, R. F.; Bechtel, A.; Linzer, H.-G.

    2016-11-01

    Two petroleum systems are present in the eastern (Austrian) sector of the Alpine Foreland Basin. Whereas oil and thermogenic gas in Mesozoic and Eocene reservoir rocks have been generated beneath the Alps in Lower Oligocene source rocks, relative dry gas in Oligocene-Miocene clastic rocks deposited in the deep marine basin-axial channel system (Puchkirchen Channel) is interpreted as microbial in origin. Detailed investigations of the molecular and isotope composition of 87 gas samples from 86 wells, representing all producing fields with Oligocene and Miocene reservoir rocks, suggest that the presence of pure microbial gas is rare and limited mainly to the northern basin flank (e.g., KK field). All other fields contain varying amounts of thermogenic gas, which has been generated from a source rock with oil-window maturity. A relation with the underlying thermogenic petroleum system is obvious. Upward migration occurred along discrete fault zones (e.g., H field) or through low-permeability caprocks. Local erosion of Lower Oligocene sediments, the principal seal for the thermogenic petroleum system, as well as a high percentage of permeable rocks within the Puchkirchen Channel favored upward migration and mixing of thermogenic and microbial gas. All gas samples in Oligocene-Miocene reservoirs are biodegraded. Biodegradation and the formation of secondary microbial gas resulted in gas drying. Therefore, the gas samples analyzed in this study are relative dry, despite significant contributions of thermogenic hydrocarbons. Biodegradation probably continues at present time. The degree of biodegradation, however, decreases with depth.

  7. Relevance of trapping mechanisms in certain Michigan formation stray sandstone gas reservoirs to gas storage operations

    SciTech Connect

    Nowaczewski, S.F. )

    1994-08-01

    The Stray sandstones of the Michigan Formation were early exploration targets in the Michigan basin. Subsequent to primary production, some of these reservoirs were converted to gas storage. Many of the Stray fields were discovered in an underpressured state, whereas peak storage pressures often exceed native brine gradients. It can be demonstrated that the Stray sandstones exist in sheets and lenses throughout the central basin area, and that gas/water contacts exist in the gas reservoirs but behave volumetrically. Various indirect and direct evidence indicates that gas is trapped structurally by the antiformal geometry of the sandstone bodies, by probable fracture-controlled porosity, stratigraphically by the isolation of parts of the sand bodies due to depositional and diagenetic influences, and by structurally controlled stratigraphic relationships. The understanding of the trapping mechanisms allows successful high pressure-gradient gas storage and leads to understanding reservoir behavior, which should result in efficient storage development and operation. Additional direct and secondary benefits of understanding Stray sandstone structure and stratigraphy are demonstrated for gas storage operation nuisances such as water production, and for use of the Stray as a window to or a type for deeper formations.

  8. 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

  9. Delta 37Cl and Characterisation of Petroleum-gas Reservoirs

    NASA Astrophysics Data System (ADS)

    Woulé Ebongué, V.; Jendrzejewski, N.; Walgenwitz, F.; Pineau, F.; Javoy, M.

    2003-04-01

    The geochemical characterisation of formation waters from oil/gas fields is used to detect fluid-flow barriers in reservoirs and to reconstruct the system dynamic. During the progression of the reservoir filling, the aquifer waters are pushed by hydrocarbons toward the reservoir bottom and their compositions evolve due to several parameters such as water-rock interactions, mixing with oil-associated waters, physical processes etc. The chemical and isotopic evolution of these waters is recorded in irreducible waters that have been progressively "fossilised" in the oil/gas column. Residual salts precipitated from these waters were recovered. Chloride being the most important dissolved anion in these waters and not involved in diagenetic reactions, its investigation should give insights into the different transport or mixing processes taking place in the sedimentary basin and point out to the formation waters origins. The first aim of our study was to test the Cl-RSA technique (Chlorine Residual Salts Analysis) based on the well-established Sr-RSA technique. The main studied area is a turbiditic sandstone reservoir located in the Lower Congo basin in Angola. Present-day aquifer waters, irreducible waters from sandstone and shale layers as well as drilling mud and salt dome samples were analysed. Formation waters (aquifer and irreducible trapped in shale) show an overall increase of chlorinity with depth. Their δ37Cl values range from -1.11 ppm to +2.30 ppm ± 0.05 ppm/ SMOC. Most Cl-RSA data as well as the δ37Cl obtained on a set of water samples (from different aquifers in the same area) are lower than -0.13 ppm with lower δ37Cl values at shallower depths. In a δ37Cl versus chlorinity diagram, they are distributed along a large range of chlorinity: 21 to 139 g/l, in two distinct groups. (1) Irreducible waters from one of the wells display a positive correlation between chlorinity and the δ37Cl values. (2) In contrary, the majority of δ37Cl measured on aquifers

  10. 3D modeling of gas/water distribution in water-bearing carbonate gas reservoirs: the Longwangmiao gas field, China

    NASA Astrophysics Data System (ADS)

    Ou, Chenghua; Li, ChaoChun; Ma, Zhonggao

    2016-10-01

    A water-bearing carbonate gas reservoir is an important natural gas resource being developed worldwide. Due to the long-term water/rock/gas interaction during geological evolution, complex gas/water distribution has formed under the superposed effect of sedimentary facies, reservoir space facies and gravity difference of fluid facies. In view of these challenges, on the basis of the conventional three-stage modeling method, this paper presents a modelling method controlled by four-stage facies to develop 3D model of a water-bearing carbonate gas reservoir. Key to this method is the reservoir property modelling controlled by two-stage facies, and the fluid property modelling controlled by another two-stage facies. The prerequisite of this method is a reliable database obtained from solid geological investigation. On the basis of illustrating the principles of the modelling method controlled by four-stage facies, this paper further implements systematically modeling of the heterogeneous gas/water distribution of the Longwangmiao carbonate formation in the Moxi-Gaoshiti area, Sichuan basin, China.

  11. 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.

  12. a Review of Hydropower Reservoir and Greenhouse Gas Emissions

    NASA Astrophysics Data System (ADS)

    Rosa, L. P.; Dos Santos, M. A.

    2013-05-01

    Like most manmade projects, hydropower dams have multiple effects on the environment that have been studied in some depth over the past two decades. Among their most important effects are potential changes in water movement, flowing much slower than in the original river. This favors the appearance of phytoplankton as nutrients increase, with methanogenesis replacing oxidative water and generating anaerobic conditions. Although research during the late 1990s highlighted the problems caused by hydropower dams emitting greenhouse gases, crucial aspects of this issue still remain unresolved. Similar to natural water bodies, hydropower reservoirs have ample biota ranging from microorganisms to aquatic vertebrates. Microorganisms (bacteria) decompose organic matter producing biogenic gases under water. Some of these biogenic gases cause global warming, including methane, carbon dioxide and nitrous oxide. The levels of GHG emissions from hydropower dams are a strategic matter of the utmost importance, and comparisons with other power generation options such as thermo-power are required. In order to draw up an accurate assessment of the net emissions caused by hydropower dams, significant improvements are needed in carbon budgets and studies of representative hydropower dams. To determine accurately the net emissions caused by hydro reservoir formation is required significant improvement of carbon budgets studies on different representatives' hydro reservoirs at tropical, boreal, arid, semi arid and temperate climate. Comparisons must be drawn with emissions by equivalent thermo power plants, calculated and characterized as generating the same amount of energy each year as the hydropower dams, burning different fuels and with varying technology efficiency levels for steam turbines as well as coal, fuel oil and natural gas turbines and combined cycle plants. This paper brings to the scientific community important aspects of the development of methods and techniques applied

  13. Material point method modeling in oil and gas reservoirs

    DOEpatents

    Vanderheyden, William Brian; Zhang, Duan

    2016-06-28

    A computer system and method of simulating the behavior of an oil and gas reservoir including changes in the margins of frangible solids. A system of equations including state equations such as momentum, and conservation laws such as mass conservation and volume fraction continuity, are defined and discretized for at least two phases in a modeled volume, one of which corresponds to frangible material. A material point model technique for numerically solving the system of discretized equations, to derive fluid flow at each of a plurality of mesh nodes in the modeled volume, and the velocity of at each of a plurality of particles representing the frangible material in the modeled volume. A time-splitting technique improves the computational efficiency of the simulation while maintaining accuracy on the deformation scale. The method can be applied to derive accurate upscaled model equations for larger volume scale simulations.

  14. Reservoir controls on the occurrence and production of gas hydrates in nature

    USGS Publications Warehouse

    Collett, Timothy Scott

    2014-01-01

    modeling has shown that concentrated gas hydrate occurrences in sand reservoirs are conducive to existing well-based production technologies. The resource potential of gas hydrate accumulations in sand-dominated reservoirs have been assessed for several polar terrestrial basins. In 1995, the U.S. Geological Survey (USGS) assigned an in-place resource of 16.7 trillion cubic meters of gas for hydrates in sand-dominated reservoirs on the Alaska North Slope. In a more recent assessment, the USGS indicated that there are about 2.42 trillion cubic meters of technically recoverable gas resources within concentrated, sand-dominated, gas hydrate accumulations in northern Alaska. Estimates of the amount of in-place gas in the sand dominated gas hydrate accumulations of the Mackenzie Delta Beaufort Sea region of the Canadian arctic range from 1.0 to 10 trillion cubic meters of gas. Another prospective gas hydrate resources are those of moderate-to-high concentrations within sandstone reservoirs in marine environments. In 2008, the Bureau of Ocean Energy Management estimated that the Gulf of Mexico contains about 190 trillion cubic meters of gas in highly concentrated hydrate accumulations within sand reservoirs. In 2008, the Japan Oil, Gas and Metals National Corporation reported on a resource assessment of gas hydrates in which they estimated that the volume of gas within the hydrates of the eastern Nankai Trough at about 1.1 trillion cubic meters, with about half concentrated in sand reservoirs. Because conventional production technologies favor sand-dominated gas hydrate reservoirs, sand reservoirs are considered to be the most viable economic target for gas hydrate production and will be the prime focus of most future gas hydrate exploration and development projects.

  15. 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.

  16. Reevaluation of the Reservoir Gas Sands of Rashidpur Gas Field: A Case Study

    NASA Astrophysics Data System (ADS)

    Eahsanul Haque, Akm; Ahmed, Nur

    2010-05-01

    Rashidpur Gas Field is located in the west of Srimongal in East Central Bangladesh. The accumulation associated with the Miocene Bhuban-Boka Bil Sandstone Reservoirs in a structural trap. The structure is about 35 km long and 7 km wide with amplitude of some 4900 ft. Rashidpur anticline is a sub-meriodinal axis, elongated, asymmetrical doubly plunging anticline which has two pay sands namely Upper Gas Sand (UGS) and Lower Gas Sand (LGS) indicated in all four wells drilled in the structure. After penetrating the shalebsection beneath LGS, drilling plan was rescheduled to a depth of 9200 ft in order to investigate the deeper sands of potential hydrocarbon accumulation. On reaching a depth of 10073 ft a sudden kick occurred, which halted the drilling operation and forced to kill the well. An immediate sidetrack well (4521 ft) was drilled at Well-4 and an existence of a sealing fault was drawn on the final report. But mud logs of Well-3 and Well-4 based on the hydrocarbon component of UGS and LGS clearly indicate the absence of any fault between Well-3 and Well-4. Recent geological investigation in the study area reveals the updated facts on the two wells of Rashidpur Gas Field. The paper analyses mud logs and other geological data and reevaluates the reservoir gas sands of Rashidpur Gas Field.

  17. CO2 Utilization and Storage in Shale Gas Reservoirs

    NASA Astrophysics Data System (ADS)

    Schaef, T.; Glezakou, V.; Owen, T.; Miller, Q.; Loring, J.; Davidson, C.; McGrail, P.

    2013-12-01

    Surging natural gas production from fractured shale reservoirs and the emerging concept of utilizing anthropogenic CO2 for secondary recovery and permanent storage is driving the need for understanding fundamental mechanisms controlling gas adsorption and desorption processes, mineral volume changes, and impacts to transmissivity properties. Early estimates indicate that between 10 and 30 gigatons of CO2 storage capacity may exist in the 24 shale gas plays included in current USGS assessments. However, the adsorption of gases (CO2, CH4, and SO2) is not well understood and appears unique for individual clay minerals. Using specialized experimental techniques developed at PNNL, pure clay minerals were examined at relevant pressures and temperatures during exposure to CH4, CO2, and mixtures of CO2-SO2. Adsorbed concentrations of methane displayed a linear behavior as a function of pressure as determined by a precision quartz crystal microbalance. Acid gases produced differently shaped adsorption isotherms, depending on temperature and pressure. In the instance of kaolinite, gaseous CO2 adsorbed linearly, but in the presence of supercritical CO2, surface condensation increased significantly to a peak value before desorbing with further increases in pressure. Similarly shaped CO2 adsorption isotherms derived from natural shale samples and coal samples have been reported in the literature. Adsorption steps, determined by density functional theory calculations, showed they were energetically favorable until the first CO2 layer formed, corresponding to a density of ~0.35 g/cm3. Interlayer cation content (Ca, Mg, or Na) of montmorillonites influenced adsorbed gas concentrations. Measurements by in situ x-ray diffraction demonstrate limited CO2 diffusion into the Na-montmorillonite interlayer spacing, with structural changes related to increased hydration. Volume changes were observed when Ca or Mg saturated montmorillonites in the 1W hydration state were exposed to

  18. Three types of gas hydrate reservoirs in the Gulf of Mexico identified in LWD data

    USGS Publications Warehouse

    Lee, Myung Woong; Collett, Timothy S.

    2011-01-01

    High quality logging-while-drilling (LWD) well logs were acquired in seven wells drilled during the Gulf of Mexico Gas Hydrate Joint Industry Project Leg II in the spring of 2009. These data help to identify three distinct types of gas hydrate reservoirs: isotropic reservoirs in sands, vertical fractured reservoirs in shale, and horizontally layered reservoirs in silty shale. In general, most gas hydratebearing sand reservoirs exhibit isotropic elastic velocities and formation resistivities, and gas hydrate saturations estimated from the P-wave velocity agree well with those from the resistivity. However, in highly gas hydrate-saturated sands, resistivity-derived gas hydrate-saturation estimates appear to be systematically higher by about 5% over those estimated by P-wave velocity, possibly because of the uncertainty associated with the consolidation state of gas hydrate-bearing sands. Small quantities of gas hydrate were observed in vertical fractures in shale. These occurrences are characterized by high formation resistivities with P-wave velocities close to those of water-saturated sediment. Because the formation factor varies significantly with respect to the gas hydrate saturation for vertical fractures at low saturations, an isotropic analysis of formation factor highly overestimates the gas hydrate saturation. Small quantities of gas hydrate in horizontal layers in shale are characterized by moderate increase in P-wave velocities and formation resistivities and either measurement can be used to estimate gas hydrate saturations.

  19. 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.

  20. Shallow, low-permeability reservoirs of northern Great Plains - assessment of their natural gas resources.

    USGS Publications Warehouse

    Rice, D.D.; Shurr, G.W.

    1980-01-01

    Major resources of natural gas are entrapped in low-permeability, low-pressure reservoirs at depths less than 1200m in the N.Great Plains. This shallow gas is the product of the immature stage of hydrocarbon generation and is referred to as biogenic gas. Prospective low-permeability, gas-bearing reservoirs range in age from late Early to Late Cretaceous. The following facies were identified and mapped: nonmarine rocks, coastal sandstones, shelf sandstones, siltstones, shales, and chalks. The most promising low-permeability reservoirs are developed in the shelf sandstone, siltstone, and chalk facies. Reservoirs within these facies are particularly attractive because they are enveloped by thick sequences of shale which serve as both a source and a seal for the gas.-from Author

  1. 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.

  2. 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.

  3. 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.

  4. 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...

  5. Analysis of Vapour Liquid Equilibria in Unconventional Rich Liquid Gas Condensate Reservoirs

    NASA Astrophysics Data System (ADS)

    Kuczyński, Szymon

    2014-12-01

    At the beginning of 21st century, natural gas from conventional and unconventional reservoirs has become important fossil energy resource and its role as energy fuel has increased. The exploration of unconventional gas reservoirs has been discussed recently in many conferences and journals. The paper presents considerations which will be used to build the thermodynamic model that will describe the phenomenon of vapour - liquid equilibrium (VLE) in the retrograde condensation in rocks of ultra-low permeability and in the nanopores. The research will be limited to "tight gas" reservoirs (TGR) and "shale gas" reservoirs (SGR). Constructed models will take into account the phenomenon of capillary condensation and adsorption. These studies will be the base for modifications of existing compositional simulators

  6. 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.

  7. Greenhouse gas emissions from reservoir water surfaces: A ...

    EPA Pesticide Factsheets

    Collectively, reservoirs created by dams are thought to be an important source ofgreenhouse gases (GHGs) to the atmosphere. So far, efforts to quantify, model, andmanage these emissions have been limited by data availability and inconsistenciesin methodological approach. Here we synthesize worldwide reservoir methane,carbon dioxide, and nitrous oxide emission data with three main objectives: (1) togenerate a global estimate of GHG emissions from reservoirs, (2) to identify the bestpredictors of these emissions, and (3) to consider the effect of methodology onemission estimates. We estimate that GHG emission from reservoir water surfacesaccount for 0.8 (0.5-1.2) Pg CO2-equivalents per year, equal to ~1.3 % of allanthropogenic GHG emissions, with the majority (79%) of this forcing due tomethane. We also discuss the potential for several alternative pathways such as damdegassing and downstream emissions to contribute significantly to overall GHGemissions. Although prior studies have linked reservoir GHG emissions to systemage and latitude, we find that factors related to reservoir productivity are betterpredictors of emission. Finally, as methane contributed the most to total reservoirGHG emissions, it is important that future monitoring campaigns incorporatemethane emission pathways, especially ebullition. To inform the public.

  8. Evaluation of Gas Production Potential of Hydrate Deposits in Alaska North Slope using Reservoir Simulations

    NASA Astrophysics Data System (ADS)

    Nandanwar, M.; Anderson, B. J.

    2015-12-01

    Over the past few decades, the recognition of the importance of gas hydrates as a potential energy resource has led to more and more exploration of gas hydrate as unconventional source of energy. In 2002, U.S. Geological Survey (USGS) started an assessment to conduct a geology-based analysis of the occurrences of gas hydrates within northern Alaska. As a result of this assessment, many potential gas hydrate prospects were identified in the eastern National Petroleum Reserve Alaska (NPRA) region of Alaska North Slope (ANS) with total gas in-place of about 2 trillion cubic feet. In absence of any field test, reservoir simulation is a powerful tool to predict the behavior of the hydrate reservoir and the amount of gas that can be technically recovered using best suitable gas recovery technique. This work focuses on the advanced evaluation of the gas production potential of hydrate accumulation in Sunlight Peak - one of the promising hydrate fields in eastern NPRA region using reservoir simulations approach, as a part of the USGS gas hydrate development Life Cycle Assessment program. The main objective of this work is to develop a field scale reservoir model that fully describes the production design and the response of hydrate field. Due to the insufficient data available for this field, the distribution of the reservoir properties (such as porosity, permeability and hydrate saturation) are approximated by correlating the data from Mount Elbert hydrate field to obtain a fully heterogeneous 3D reservoir model. CMG STARS is used as a simulation tool to model multiphase, multicomponent fluid flow and heat transfer in which an equilibrium model of hydrate dissociation was used. Production of the gas from the reservoir is carried out for a period of 30 years using depressurization gas recovery technique. The results in terms of gas and water rate profiles are obtained and the response of the reservoir to pressure and temperature changes due to depressurization and hydrate

  9. Preliminary formation analysis for compressed air energy storage in depleted natural gas reservoirs :

    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

  10. 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.

  11. Numerical simulation of heterogeneous fractured gas reservoir systems with turbulence and closure stress effects

    SciTech Connect

    Allam, A.M.; Crichlow, H.B.; Soliman, M.Y.

    1981-01-01

    A numerical technique for analyzing the behavior of a fractured gas reservoir system is presented. The reservoir is simulated by a fully implicit three-dimensional model that incorporates the effects of turbulent flow and closure stress in a finite conductivity fracture. The model utilizes the real gas pseudo-pressure, two-point upstream transmissibilities and a stable iterative process based on a sparse matrix approach to solving the equation systems. This paper presents a description of the model and applications to various reservoirs to illustrate the effects of fracture heights, turbulence and closure pressure on well performance. 16 refs.

  12. GEOLOGIC ASPECTS OF TIGHT GAS RESERVOIRS IN THE ROCKY MOUNTAIN REGION.

    USGS Publications Warehouse

    Spencer, Charles W.

    1985-01-01

    The authors describe some geologic characteristics of tight gas reservoirs in the Rocky Mountain region. These reservoirs usually have an in-situ permeability to gas of 0. 1 md or less and can be classified into four general geologic and engineering categories: (1) marginal marine blanket, (2) lenticular, (3) chalk, and (4) marine blanket shallow. Microscopic study of pore/permeability relationships indicates the existence of two varieties of tight reservoirs. One variety is tight because of the fine grain size of the rock. The second variety is tight because the rock is relatively tightly cemented and the pores are poorly connected by small pore throats and capillaries.

  13. Structurally controlled and aligned tight gas reservoir compartmentalization in the San Juan and Piceance Basins

    SciTech Connect

    Decker, A.D.; Kuuskraa, V.A.; Klawitter, A.L.

    1995-10-01

    Recurrent basement faulting is the primary controlling mechanism for aligning and compartmentalizing upper Cretaceous aged tight gas reservoirs of the San Juan and Piceance Basins. Northwest trending structural lineaments that formed in conjunction with the Uncompahgre Highlands have profoundly influenced sedimentation trends and created boundaries for gas migration; sealing and compartmentalizing sedimentary packages in both basins. Fractures which formed over the structural lineaments provide permeability pathways which allowing gas recovery from otherwise tight gas reservoirs. Structural alignments and associated reservoir compartments have been accurately targeted by integrating advanced remote sensing imagery, high resolution aeromagnetics, seismic interpretation, stratigraphic mapping and dynamic structural modelling. This unifying methodology is a powerful tool for exploration geologists and is also a systematic approach to tight gas resource assessment in frontier basins.

  14. 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.

  15. Search for reservoirs suitable for enhanced gas recovery through co-production in south Louisiana

    SciTech Connect

    Kimbrell, W.C.; David, B.D.; McCulloh, R.P.; Wrighton, F.M.

    1985-12-01

    The co-production enhanced gas recovery technique is a means of enhancing the ultimate recovery of gas in water-driven reservoirs. The technique prescribes production of water from watered-out wells downdip simultaneously with the production of gas updip, in order to lower the abandonment pressure, retard water influx, and increase production during the primary life of the reservoir. Lower pressure results in increased production due to the expansion in the updip areas as well as remobilization of the dispersed gas from watered-out areas downdip. By treating the reservoir as a system instead of regarding single wells as individual profit centers, the operator can manage some reservoirs more efficiently and profitably. The Gas Research Institute is funding the Louisiana Geological Survey/Louisiana State University to evaluate south Louisiana reservoirs based on site geology and operator interest for suitability for co-production. To date, the Louisiana Geological Survey has identified five reservoirs which appear, after preliminary screens, to be excellent candidates for the co-production technique. Computer simulations show approximate, but representative, predictions of substantial increases in production through utilization of co-production.

  16. 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.

  17. 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.

  18. 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.

  19. 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.

  20. 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

    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.

  1. 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

  2. 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.

  3. 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.

  4. 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.

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

    SciTech Connect

    Kim, Jihoon; Moridis, George J.

    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

  6. 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.

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

    PubMed

    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.

  8. 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

  9. 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.

  10. Numerical simulation of the electrical properties of shale gas reservoir rock based on digital core

    NASA Astrophysics Data System (ADS)

    Nie, Xin; Zou, Changchun; Li, Zhenhua; Meng, Xiaohong; Qi, Xinghua

    2016-08-01

    In this paper we study the electrical properties of shale gas reservoir rock by applying the finite element method to digital cores which are built based on an advanced Markov Chain Monte Carlo method and a combination workflow. Study shows that the shale gas reservoir rock has strong anisotropic electrical conductivity because the conductivity is significantly different in both horizontal and vertical directions. The Archie formula is not suitable for application in shale reservoirs. The formation resistivity decreases in two cases; namely (a) with the increase of clay mineral content and the cation exchange capacity of clay, and (b) with the increase of pyrite content. The formation resistivity is not sensitive to the solid organic matter but to the clay and gas in the pores.

  11. 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

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

    DOE PAGES

    Kim, Jihoon; Moridis, George J.

    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 gasmore » 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

  13. 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.

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

    EPA Pesticide Factsheets

    Researchers examined gas and water transport between a deep tight shale gas reservoir and a shallow overlying aquifer in the two years following hydraulic fracturing, assuming a pre-existing connecting pathway.

  15. Hydraulic Fracturing Fluid Reaction with Shale in Experiments at Unconventional Gas Reservoir Conditions

    NASA Astrophysics Data System (ADS)

    Paukert, A. N.; Hakala, A.; Jarvis, K. B.

    2015-12-01

    Despite the marked increase in hydraulic fracturing for unconventional natural gas production over the past decade, reactions between hydraulic fracturing fluids (HFF) and shale reservoirs remain poorly reported in the scientific literature. Shale-HFF interaction could cause mineral dissolution, releasing matter from the shale, or mineral precipitation that degrades reservoir permeability. Furthermore, data are limited on whether scale inhibitors are effective at preventing mineral precipitation and whether these inhibitors adversely affect reservoir fluid chemistry and permeability. To investigate HFF-rock interaction within shale reservoirs, we conducted flow-through experiments exposing Marcellus Shale to synthetic HFF at reservoir conditions (66oC, 20MPa). Outcrop shale samples were cored, artificially fractured, and propped open with quartz sand. Synthetic HFFs were mixed with chemical additives similar to those used for Marcellus Shale gas wells in Ohio and Southwestern Pennsylvania (FracFocus.org). We evaluated differences between shale reactions with HFF made from natural freshwater and reactions with HFF made from synthetic produced water (designed to simulate produced water that is diluted and re-used for subsequent hydraulic fracturing). We also compared reactions with HFFs including hydrochloric acid (HCl) to represent the initial acid stage, and HFFs excluding HCl. Reactions were determined through changes in fluid chemistry and X-ray CT and SEM imaging of the shale before and after experiments. Results from experiments with HFF containing HCl showed dissolution of primary calcite, as expected. Experiments using HFF made from synthetic produced water had significant mineral precipitation, particularly of barium and calcium sulfates. X-ray CT images from these experiments indicate precipitation of minerals occurred either along the main fracture or within smaller splay fractures, depending on fluid composition. These experiments suggest that HFF

  16. Shale gas reservoir characteristics of Ordovician-Silurian formations in the central Yangtze area, China

    NASA Astrophysics Data System (ADS)

    Shan, Chang'an; Zhang, Tingshan; Wei, Yong; Zhang, Zhao

    2017-03-01

    The characteristics of a shale gas reservoir and the potential of a shale gas resource of Ordovician-Silurian age in the north of the central Yangtze area were determined. Core samples from three wells in the study area were subjected to thin-section examination, scanning electron microscopy, nuclear magnetic resonance testing, X-ray diffraction mineral analysis, total organic carbon (TOC) testing, maturity testing, gas-bearing analysis, and gas component and isothermal adsorption experiments. A favorable segment of the gas shale reservoir was found in both the Wufeng Formation and the lower part of the Longmaxi Formation; these formations were formed from the late Katian to early Rhuddanian. The high-quality shale layers in wells J1, J2, and J3 featured thicknesses of 54.88 m, 48.49 m, and 52.00 m, respectively, and mainly comprised carbonaceous and siliceous shales. Clay and brittle minerals showed average contents of 37.5% and 62.5% (48.9% quartz), respectively. The shale exhibited type II1 kerogens with a vitrinite reflectance ranging from 1.94% to 3.51%. TOC contents of 0.22%-6.05% (average, 2.39%) were also observed. The reservoir spaces mainly included micropores and microfractures and were characterized by low porosity and permeability. Well J3 showed generally high gas contents, i.e., 1.12-3.16 m3/t (average 2.15 m3/t), and its gas was primarily methane. The relatively thick black shale reservoir featured high TOC content, high organic material maturity, high brittle mineral content, high gas content, low porosity, and low permeability. Shale gas adsorption was positively correlated with TOC content and organic maturity, weakly positive correlated with quartz content, and weakly negatively correlated with clay content. Therefore, the Wufeng and Longmaxi formations in the north of the central Yangtze area have a good potential for shale gas exploration.

  17. 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 PMID

  18. Secondary natural gas recovery in mature fluvial sandstone reservoirs, Frio Formation, Agua Dulce Field, South Texas

    SciTech Connect

    Ambrose, W.A.; Levey, R.A. ); Vidal, J.M. ); Sippel, M.A. ); Ballard, J.R. ); Coover, D.M. Jr. ); Bloxsom, W.E. )

    1993-09-01

    An approach that integrates detailed geologic, engineering, and petrophysical analyses combined with improved well-log analytical techniques can be used by independent oil and gas companies of successful infield exploration in mature Gulf Coast fields that larger companies may consider uneconomic. In a secondary gas recovery project conducted by the Bureau of Economic Geology and funded by the Gas Research Institute and the U.S. Department of Energy, a potential incremental natural gas resource of 7.7 bcf, of which 4.0 bcf may be technically recoverable, was identified in a 490-ac lease in Agua Dulce field. Five wells in this lease had previously produced 13.7 bcf from Frio reservoirs at depths of 4600-6200 ft. The pay zones occur in heterogeneous fluvial sandstones offset by faults associated with the Vicksburg fault zone. The compartments may each contain up to 1.0 bcf of gas resources with estimates based on previous completions and the recent infield drilling experience of Pintas Creek Oil Company. Uncontacted gas resources occur in thin (typically less than 10 ft) bypassed zones that can be identified through a computed log evaluation that integrates open-hole logs, wireline pressure tests, fluid samples, and cores. At Agua Dulce field, such analysis identified at 4-ft bypassed zone uphole from previously produced reservoirs. This reservoir contained original reservoir pressure and flowed at rates exceeding 1 mmcf/d. The expected ultimate recovery is 0.4 bcf. Methodologies developed in the evaluation of Agua Dulce field can be successfully applied to other mature gas fields in the south Texas Gulf Coast. For example, Stratton and McFaddin are two fields in which the secondary gas recovery project has demonstrated the existence of thin, potentially bypassed zones that can yield significant incremental gas resources, extending the economic life of these fields.

  19. The deep Madden Field, a super-deep Madison gas reservoir, Wind River Basin, Wyoming

    SciTech Connect

    Moore, C.H.; Hawkins, C.

    1996-12-31

    Madison dolomites form the reservoir of a super deep, potential giant sour gas field developed on the Madden Anticline immediately in front of the Owl Creek Thrust along the northern rim of the Wind River Basin, central Wyoming. The Madison reservoir dolomites are presently buried to some 25,000 feet at Madden Field and exhibit porosity in excess of 15%. An equivalent dolomitized Madison sequence is exposed in outcrop only 5 miles to the north on the hanging wall of the Owl Creek thrust at Lysite Mountain. Preliminary comparative stratigraphic, geochemical and petrologic data, between outcrop and available cores and logs at Deep Madden suggests: (1) early, sea level-controlled, evaporite-related dolomitization of the reservoir and outcrop prior to significant burial; (2) both outcrop and deep reservoir dolomites underwent significant recrystallization during a common burial history until their connection was severed during Laramide faulting in the Eocene; (3) While the dolomite reservoir at Madden suffered additional diagenesis during an additional 7-10 thousand feet of burial, the pore systems between outcrop and deep reservoir are remarkably similar. The two existing deep Madison wells at Madden are on stream, with a third deep Madison well currently drilling. The sequence stratigraphic framework and the diagenetic history of the Madison strongly suggests that outcrops and surface cores of the Madison in the Owl Creek Mountains will be useful in further development and detailed reservoir modeling of the Madden Deep Field.

  20. The deep Madden Field, a super-deep Madison gas reservoir, Wind River Basin, Wyoming

    SciTech Connect

    Moore, C.H. ); Hawkins, C. )

    1996-01-01

    Madison dolomites form the reservoir of a super deep, potential giant sour gas field developed on the Madden Anticline immediately in front of the Owl Creek Thrust along the northern rim of the Wind River Basin, central Wyoming. The Madison reservoir dolomites are presently buried to some 25,000 feet at Madden Field and exhibit porosity in excess of 15%. An equivalent dolomitized Madison sequence is exposed in outcrop only 5 miles to the north on the hanging wall of the Owl Creek thrust at Lysite Mountain. Preliminary comparative stratigraphic, geochemical and petrologic data, between outcrop and available cores and logs at Deep Madden suggests: (1) early, sea level-controlled, evaporite-related dolomitization of the reservoir and outcrop prior to significant burial; (2) both outcrop and deep reservoir dolomites underwent significant recrystallization during a common burial history until their connection was severed during Laramide faulting in the Eocene; (3) While the dolomite reservoir at Madden suffered additional diagenesis during an additional 7-10 thousand feet of burial, the pore systems between outcrop and deep reservoir are remarkably similar. The two existing deep Madison wells at Madden are on stream, with a third deep Madison well currently drilling. The sequence stratigraphic framework and the diagenetic history of the Madison strongly suggests that outcrops and surface cores of the Madison in the Owl Creek Mountains will be useful in further development and detailed reservoir modeling of the Madden Deep Field.

  1. Enhanced greenhouse gas emission from exposed sediments along a hydroelectric reservoir during an extreme drought event

    NASA Astrophysics Data System (ADS)

    Jin, Hyojin; Yoon, Tae Kyung; Lee, Seung-Hoon; Kang, Hojeong; Im, Jungho; Park, Ji-Hyung

    2016-12-01

    An active debate has been underway on the magnitude and duration of carbon (C) emissions from hydroelectric reservoirs, yet little attention has been paid to stochastic C emissions from reservoir sediments during extreme climatic events. A rare opportunity for field measurements of CO2 efflux from a hydroelectric reservoir in Korea during an extreme drought event was used to examine how prolonged droughts can affect microbial organic matter processing and the release of CO2, CH4 and N2O from exposed sediments. Chamber measurements of CO2 efflux along an exposed sediment transect, combined with high-frequency continuous sensor measurements of the partial pressure of CO2 (pCO2) in the reservoir surface water, exhibited extraordinary pulses of CO2 from exposed sediments and the turbulent inflowing water in contrast to a small CO2 sink in the main water body of the reservoir and a low efflux of CO2 from the flooded sediment. Significant increases in the production of CO2, CH4 and N2O observed in a laboratory incubation of sediments, together with enhanced activities of phenol oxidase and three hydrolases, indicate a temporary activation of microbial organic matter processing in the drying sediment. The results suggest that drought-triggered pulses of greenhouse gas emission from exposed sediments can offset the C accumulation in reservoir sediments over time scales of years to decades, reversing the trend of declining C emissions from aging reservoirs.

  2. Distribution of sulfur deposition near a wellbore in a sour gas reservoir

    NASA Astrophysics Data System (ADS)

    Hu, Jinghong; Yang, Xuefeng; He, ShunLi; Zhao, Jinzhou

    2013-02-01

    Elemental sulfur precipitates from sour gas when reservoir pressure and temperature decrease. Sulfur deposition in a formation may significantly reduce the inflow performance of sour gas wells. This paper develops a micro-mechanical migration model and experiments which describe the law of sulfur precipitation, plugging and distribution near a wellbore. Based on the analysis of the sulfur deposition law and micro-mechanical migration theory, elemental sulfur mechanical models in pores are presented. The critical velocity of sulfur is calculated and the rule of precipitated sulfur distribution near a wellbore is deduced. Reservoir cores and supersaturated sour gas are utilized to observe sulfur precipitation and plugging in sulfur damage experiments, and the main influential factor is analysed. According to the models and experimental results, precipitated sulfur can decrease reservoir permeability. The liquid bridge force is the most important factor to affect reservoir permeability due to sulfur deposition. Precipitated sulfur cannot be carried away from pores if the liquid bridge force is considered; the critical velocity increases as the diameter of the sulfur particles increases, which may cause serious formation damage. Moreover, it can be seen from the results that the biggest volume of sulfur deposition does not occur at the bottom but near the bottom of a borehole. These results can be used to describe the profile of dynamic sulfur deposition and help a reservoir engineer to develop a plan for removing the sulfur near a wellbore.

  3. 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.

  4. Offshore Adriatic marginal gas fields: An approach to the technique of reservoir development

    SciTech Connect

    Montanari, A.; Bolelli, V.; Piccoli, G.

    1986-01-01

    The application of accelerated gas blowdown and wire line techniques in reservoir development and exploitation is presented for an off-shore Adriatic marginal gas field. The approach discussed in this paper utilizes selective completion, very low reserves/production ratio, sequential production, Through Tubing Bridge Plug and Through Tubing Perforation techniques to avoid the use of costly workover rigs and to allow economically convenient exploitation of a structure which otherwise would have been abandoned.

  5. 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.

  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. 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...

  8. 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.

  9. 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.

  10. The Antrim shale, fractured gas reservoirs with immense potential

    SciTech Connect

    Manger, K.C.; Woods, T.J. Curtis, J.B.

    1996-12-31

    Antrim shale gas production has grown from 0.4 Bcf of gas in 1987 to 127 Bcf in 1994, causing record gas production in Michigan. Recent industry activity suggests the play will continue to expand. The GRI Hydrocarbon Model`s Antrim resource base description was developed in 1991 based on industry activity through 1990. The 1991 description estimated 32 Tcf of recoverable resource, and was limited to northern Michigan which represents only part of the Antrim`s total potential. This description indicated production could increase manyfold, even with low prices. However, its well recovery rate is less than current industry results and projected near term production lags actual production by 1 to 2 years. GRI is updating its description to better reflect current industry results and incorporate all prospective areas. The description in northern Michigan is updated using production and well data through 1994 and results from GRI`s research program. The description is then expanded to the entire basin. Results indicate the northern resource is somewhat larger than the previous estimate and the wells perform better. Extrapolation to the entire basin using a geologic analog model approximately doubles the 1991 estimate. The model considers depositional, structural, and tectonic influences; fracturing; organic content; thermal history; and hydrocarbon generation, migration and storage. Pleistocene glaciation and biogenic gas are also included for areas near the Antrim subcrop.

  11. The Antrim shale, fractured gas reservoirs with immense potential

    SciTech Connect

    Manger, K.C. ); Woods, T.J. ) Curtis, J.B. )

    1996-01-01

    Antrim shale gas production has grown from 0.4 Bcf of gas in 1987 to 127 Bcf in 1994, causing record gas production in Michigan. Recent industry activity suggests the play will continue to expand. The GRI Hydrocarbon Model's Antrim resource base description was developed in 1991 based on industry activity through 1990. The 1991 description estimated 32 Tcf of recoverable resource, and was limited to northern Michigan which represents only part of the Antrim's total potential. This description indicated production could increase manyfold, even with low prices. However, its well recovery rate is less than current industry results and projected near term production lags actual production by 1 to 2 years. GRI is updating its description to better reflect current industry results and incorporate all prospective areas. The description in northern Michigan is updated using production and well data through 1994 and results from GRI's research program. The description is then expanded to the entire basin. Results indicate the northern resource is somewhat larger than the previous estimate and the wells perform better. Extrapolation to the entire basin using a geologic analog model approximately doubles the 1991 estimate. The model considers depositional, structural, and tectonic influences; fracturing; organic content; thermal history; and hydrocarbon generation, migration and storage. Pleistocene glaciation and biogenic gas are also included for areas near the Antrim subcrop.

  12. Transport of Gas Phase Radionuclides in a Fractured, Low-Permeability Reservoir

    NASA Astrophysics Data System (ADS)

    Cooper, C. A.; Chapman, J.

    2001-12-01

    The U.S. Atomic Energy Commission (predecessor to the Department of Energy, DOE) oversaw a joint program between industry and government in the 1960s and 1970s to develop technology to enhance production from low-permeability gas reservoirs using nuclear stimulation rather than conventional means (e.g., hydraulic and/or acid fracturing). Project Rio Blanco, located in the Piceance Basin, Colorado, was the third experiment under the program. Three 30-kiloton nuclear explosives were placed in a 2134 m deep well at 1780, 1899, and 2039 m below the land surface and detonated in May 1973. Although the reservoir was extensively fractured, complications such as radionuclide contamination of the gas prevented production and subsequent development of the technology. Two-dimensional numerical simulations were conducted to identify the main transport processes that have occurred and are currently occurring in relation to the detonations, and to estimate the extent of contamination in the reservoir. Minor modifications were made to TOUGH2, the multiphase, multicomponent reservoir simulator developed at Lawrence Berkeley National Laboratories. The simulator allows the explicit incorporation of fractures, as well as heat transport, phase change, and first order radionuclide decay. For a fractured two-phase (liquid and gas) reservoir, the largest velocities are of gases through the fractures. In the gas phase, tritium and one isotope of krypton are the principle radionuclides of concern. However, in addition to existing as a fast pathway, fractures also permit matrix diffusion as a retardation mechanism. Another retardation mechanism is radionuclide decay. Simulations show that incorporation of fractures can significantly alter transport rates, and that radionuclides in the gas phase can preferentially migrate upward due to the downward gravity drainage of liquid water in the pores. This project was funded by the National Nuclear Security Administration, Nevada Operations Office

  13. Transport of gas-phase radionuclides in a fractured, low-permeability reservoir

    SciTech Connect

    Clay Cooper; Jenny Chapman

    2001-12-01

    The U.S. Atomic Energy Commission (predecessor to the U.S. Department of Energy, DOE) oversaw a joint program between industry and government in the 1960s and 1970s to develop technology to enhance production from low-permeability gas reservoirs using nuclear stimulation rather than conventional means (e.g., hydraulic and/or acid fracturing). Project Rio Blanco, located in the Piceance Basin, Colorado, was the third experiment under the program. Three 30-kiloton nuclear explosives were placed in a 2,134-m-deep well at 1,780, 1,899, and 2,039 m below the land surface and detonated in May 1973. Although the reservoir was extensively fractured, complications such as radionuclide contamination of the gas prevented production and subsequent development of the technology. Two-dimensional numerical simulations were conducted to identify the main transport processes that have occurred and are currently occurring in relation to the detonations, and to estimate the extent of contamination in the reservoir. Minor modifications were made to TOUGH2, the multiphase, multicomponent reservoir simulator developed at Lawrence Berkeley National Laboratories. The simulator allows the explicit incorporation of fractures, as well as heat transport, phase change, and first-order radionuclide decay. For a fractured, two-phase (liquid and gas) reservoir, the largest velocities are of gases through the fractures. In the gas phase, tritium and one isotope of krypton are the principal radionuclides of concern. However, in addition to existing as a fast pathway, fractures also permit matrix diffusion as a retardation mechanism. Another retardation mechanism is radionuclide decay. Simulations show that incorporation of fractures can significantly alter transport rates, and that radionuclides in the gas phase can preferentially migrate upward due to the downward gravity drainage of liquid water in the pores.

  14. Using new reservoir characterization technologies on a giant old gas field (Hugoton Field, Kansas)

    SciTech Connect

    Olson, T.M.; Thompson, K.; Prasad, K.; Boughton, S.

    1996-12-31

    New technologies can profitably be applied to mature fields. Neural networks, geostalistics, new wireline logging tools, and 3-D visualization/computation have all added value to the characterization of Kansas Hugoton Field. This field was discovered in the 1920`s; cumulative production has reached approximately 26 TCFG, and years of productive life remain. Despite this maturity, controls on gas distribution and water production have not been well understood. Once the geologic framework of the reservoir is understood, various technologies can be employed to solve problems of reservoir characterization, especially in a system as complex as the multilayer, mixed-lithology reservoir of the Permian Chase Group in Hugoton. Neural networks provided a better estimation of both porosity and permeability from logs when compared with core data than more conventional methods. Use of geostatistics resulted in more realistic porosity distributions than those from interpolation, by preserving heterogeneity and allowing constraint of imperfect log determinations by core data. Geostatistics also allows for quantification of uncertainty, which is shown by a range of possible pore volumes. 3-D visualization makes quick quality control of data possible, and promotes efforts to test sensitivities and cutoffs and to communicate results. Computation of reservoir parameters (e.g. water saturation) in 3-D alleviates the averaging problems attendant on such computations in 2-D. These techniques, plus new log measurements such as nuclear magnetic resonance and magnetic pulsed induction, have aided our characterization of this reservoir and increased our understanding of and ability to manage, gas and water production.

  15. Using new reservoir characterization technologies on a giant old gas field (Hugoton Field, Kansas)

    SciTech Connect

    Olson, T.M.; Thompson, K. ); Prasad, K.; Boughton, S. )

    1996-01-01

    New technologies can profitably be applied to mature fields. Neural networks, geostalistics, new wireline logging tools, and 3-D visualization/computation have all added value to the characterization of Kansas Hugoton Field. This field was discovered in the 1920's; cumulative production has reached approximately 26 TCFG, and years of productive life remain. Despite this maturity, controls on gas distribution and water production have not been well understood. Once the geologic framework of the reservoir is understood, various technologies can be employed to solve problems of reservoir characterization, especially in a system as complex as the multilayer, mixed-lithology reservoir of the Permian Chase Group in Hugoton. Neural networks provided a better estimation of both porosity and permeability from logs when compared with core data than more conventional methods. Use of geostatistics resulted in more realistic porosity distributions than those from interpolation, by preserving heterogeneity and allowing constraint of imperfect log determinations by core data. Geostatistics also allows for quantification of uncertainty, which is shown by a range of possible pore volumes. 3-D visualization makes quick quality control of data possible, and promotes efforts to test sensitivities and cutoffs and to communicate results. Computation of reservoir parameters (e.g. water saturation) in 3-D alleviates the averaging problems attendant on such computations in 2-D. These techniques, plus new log measurements such as nuclear magnetic resonance and magnetic pulsed induction, have aided our characterization of this reservoir and increased our understanding of and ability to manage, gas and water production.

  16. The Noble Gas Record of Gas-Water Phase Interaction in the Tight-Gas-Sand Reservoirs of the Rocky Mountains

    NASA Astrophysics Data System (ADS)

    Ballentine, C. J.; Zhou, Z.; Harris, N. B.

    2015-12-01

    The mass of hydrocarbons that have migrated through tight-gas-sandstone systems before the permeability reduces to trap the hydrocarbon gases provides critical information in the hydrocarbon potential analysis of a basin. The noble gas content (Ne, Ar, Kr, Xe) of the groundwater has a unique isotopic and elemental composition. As gas migrates through the water column, the groundwater-derived noble gases partition into the hydrocarbon phase. Determination of the noble gases in the produced hydrocarbon phase then provides a record of the type of interaction (simple phase equilibrium or open system Rayleigh fractionation). The tight-gas-sand reservoirs of the Rocky Mountains represent one of the most significant gas resources in the United States. The producing reservoirs are generally developed in low permeability (averaging <0.1mD) Upper Cretaceous fluvial to marginal marine sandstones and commonly form isolated overpressured reservoir bodies encased in even lower permeability muddy sediments. We present noble gas data from producing fields in the Greater Green River Basin, Wyoming; the the Piceance Basin, Colorado; and in the Uinta Basin, Utah. The data is consistent from all three basins. We show how in each basin the noble gases record open system gas migration through a water column at maximum basin burial. The data within an open system model indicates that the gas now in-place represents the last ~10% of hydrocarbon gas to have passed through the water column, most likely prior to permeability closedown.

  17. 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.

  18. Mineral content prediction for unconventional oil and gas reservoirs based on logging data

    NASA Astrophysics Data System (ADS)

    Maojin, Tan; Youlong, Zou; Guoyue

    2012-09-01

    Coal bed methane and shale oil &gas are both important unconventional oil and gas resources, whose reservoirs are typical non-linear with complex and various mineral components, and the logging data interpretation model are difficult to establish for calculate the mineral contents, and the empirical formula cannot be constructed due to various mineral. The radial basis function (RBF) network analysis is a new method developed in recent years; the technique can generate smooth continuous function of several variables to approximate the unknown forward model. Firstly, the basic principles of the RBF is discussed including net construct and base function, and the network training is given in detail the adjacent clustering algorithm specific process. Multi-mineral content for coal bed methane and shale oil &gas, using the RBF interpolation method to achieve a number of well logging data to predict the mineral component contents; then, for coal-bed methane reservoir parameters prediction, the RBF method is used to realized some mineral contents calculation such as ash, volatile matter, carbon content, which achieves a mapping from various logging data to multimineral. To shale gas reservoirs, the RBF method can be used to predict the clay content, quartz content, feldspar content, carbonate content and pyrite content. Various tests in coalbed and gas shale show the method is effective and applicable for mineral component contents prediction

  19. Strategies to diagnose and control microbial souring in natural gas storage reservoirs and produced water systems

    SciTech Connect

    Morris, E.A.; Derr, R.M.; Pope, D.H.

    1995-12-31

    Hydrogen sulfide production (souring) in natural gas storage reservoirs and produced water systems is a safety and environmental problem that can lead to operational shutdown when local hydrogen sulfide standards are exceeded. Systems affected by microbial souring have historically been treated using biocides that target the general microbial community. However, requirements for more environmentally friendly solutions have led to treatment strategies in which sulfide production can be controlled with minimal impact to the system and environment. Some of these strategies are based on microbial and/or nutritional augmentation of the sour environment. Through research sponsored by the Gas Research Institute (GRI) in Chicago, Illinois, methods have been developed for early detection of microbial souring in natural gas storage reservoirs, and a variety of mitigation strategies have been evaluated. The effectiveness of traditional biocide treatment in gas storage reservoirs was shown to depend heavily on the methods by which the chemical is applied. An innovative strategy using nitrate was tested and proved ideal for produced water and wastewater systems. Another strategy using elemental iodine was effective for sulfide control in evaporation ponds and is currently being tested in microbially sour natural gas storage wells.

  20. Short-range, overpressure-driven methane migration in coarse-grained gas hydrate reservoirs

    DOE PAGES

    Nole, Michael; Daigle, Hugh; Cook, Ann E.; ...

    2016-08-31

    Two methane migration mechanisms have been proposed for coarse-grained gas hydrate reservoirs: short-range diffusive gas migration and long-range advective fluid transport from depth. Herein we demonstrate that short-range fluid flow due to overpressure in marine sediments is a significant additional methane transport mechanism that allows hydrate to precipitate in large quantities in thick, coarse-grained hydrate reservoirs. Two-dimensional simulations demonstrate that this migration mechanism, short-range advective transport, can supply significant amounts of dissolved gas and is unencumbered by limitations of the other two end-member mechanisms. Here, short-range advective migration can increase the amount of methane delivered to sands as compared tomore » the slow process of diffusion, yet it is not necessarily limited by effective porosity reduction as is typical of updip advection from a deep source.« less

  1. Short-range, overpressure-driven methane migration in coarse-grained gas hydrate reservoirs

    NASA Astrophysics Data System (ADS)

    Nole, Michael; Daigle, Hugh; Cook, Ann E.; Malinverno, Alberto

    2016-09-01

    Two methane migration mechanisms have been proposed for coarse-grained gas hydrate reservoirs: short-range diffusive gas migration and long-range advective fluid transport from depth. Herein, we demonstrate that short-range fluid flow due to overpressure in marine sediments is a significant additional methane transport mechanism that allows hydrate to precipitate in large quantities in thick, coarse-grained hydrate reservoirs. Two-dimensional simulations demonstrate that this migration mechanism, short-range advective transport, can supply significant amounts of dissolved gas and is unencumbered by limitations of the other two end-member mechanisms. Short-range advective migration can increase the amount of methane delivered to sands as compared to the slow process of diffusion, yet it is not necessarily limited by effective porosity reduction as is typical of updip advection from a deep source.

  2. Short-range, overpressure-driven methane migration in coarse-grained gas hydrate reservoirs

    SciTech Connect

    Nole, Michael; Daigle, Hugh; Cook, Ann E.; Malinverno, Alberto

    2016-08-31

    Two methane migration mechanisms have been proposed for coarse-grained gas hydrate reservoirs: short-range diffusive gas migration and long-range advective fluid transport from depth. Herein we demonstrate that short-range fluid flow due to overpressure in marine sediments is a significant additional methane transport mechanism that allows hydrate to precipitate in large quantities in thick, coarse-grained hydrate reservoirs. Two-dimensional simulations demonstrate that this migration mechanism, short-range advective transport, can supply significant amounts of dissolved gas and is unencumbered by limitations of the other two end-member mechanisms. Here, short-range advective migration can increase the amount of methane delivered to sands as compared to the slow process of diffusion, yet it is not necessarily limited by effective porosity reduction as is typical of updip advection from a deep source.

  3. Terahertz-dependent identification of simulated hole shapes in oil-gas reservoirs

    NASA Astrophysics Data System (ADS)

    Bao, Ri-Ma; Zhan, Hong-Lei; Miao, Xin-Yang; Zhao, Kun; Feng, Cheng-Jing; Dong, Chen; Li, Yi-Zhang; Xiao, Li-Zhi

    2016-10-01

    Detecting holes in oil-gas reservoirs is vital to the evaluation of reservoir potential. The main objective of this study is to demonstrate the feasibility of identifying general micro-hole shapes, including triangular, circular, and square shapes, in oil-gas reservoirs by adopting terahertz time-domain spectroscopy (THz-TDS). We evaluate the THz absorption responses of punched silicon (Si) wafers having micro-holes with sizes of 20 μm-500 μm. Principal component analysis (PCA) is used to establish a model between THz absorbance and hole shapes. The positions of samples in three-dimensional spaces for three principal components are used to determine the differences among diverse hole shapes and the homogeneity of similar shapes. In addition, a new Si wafer with the unknown hole shapes, including triangular, circular, and square, can be qualitatively identified by combining THz-TDS and PCA. Therefore, the combination of THz-TDS with mathematical statistical methods can serve as an effective approach to the rapid identification of micro-hole shapes in oil-gas reservoirs. Project supported by the National Natural Science Foundation of China (Grant No. 61405259), the National Basic Research Program of China (Grant No. 2014CB744302), and the Specially Founded Program on National Key Scientific Instruments and Equipment Development, China (Grant No. 2012YQ140005).

  4. 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

    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.

  5. Some effects of non-condensible gas in geothermal reservoirs with steam-water counterflow

    SciTech Connect

    McKibbin, Robert; Pruess, Karsten

    1988-01-01

    A mathematical model is developed for fluid and heat flow in two-phase geothermal reservoirs containing non-condensible gas (CO{sub 2}). Vertical profiles of temperature, pressures and phase saturations in steady-state conditions are obtained by numerically integrating the coupled ordinary differential equations describing conservation of water, CO{sub 2}, and energy. Solutions including binary diffusion effects in the gas phase are generated for cases with net mass throughflow as well as for balanced liquid-vapor counterflow. Calculated examples illustrate some fundamental characteristics of two-phase heat transmission systems with non-condensible gas.

  6. Reef Reservoir Identification by Wavelet Decomposition and Reconstruction: A Case Study from Yuanba Gas Field in China

    NASA Astrophysics Data System (ADS)

    Cheng, Bingjie; Xu, Tianji; Robbins, Benedict; Shen, ZhongMing

    2015-08-01

    The organic reef is a special type of carbonate reservoir which always dominates the spatial distribution, reserves and accumulations of natural gas. However, it is difficult to determine the organic reef's internal structure and gas reservoirs due to numerous adverse factors such as the low resolution of seismic data, depth of burial, strong anisotropy, irregular spatial distribution and complex internal structure. A case study of wavelet decomposition and reconstruction technology applied to elucidate the features of organic reef reservoirs in the Changxing formation from Yuanba gas field shows that the seismic record reconstructed by high frequency signal can adequately describe the internal properties of organic reef reservoirs. Furthermore, the root mean square amplitude ratio of both low and high frequency data obtained from the reconstructed seismic data clearly show spatial distribution of gas and water in reef reservoirs.

  7. 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.

  8. Numerical simulations of CO2 -assisted gas production from hydrate reservoirs

    NASA Astrophysics Data System (ADS)

    Sridhara, P.; Anderson, B. J.; Myshakin, E. M.

    2015-12-01

    A series of experimental studies over the last decade have reviewed the feasibility of using CO2 or CO2+N2 gas mixtures to recover CH4 gas from hydrates deposits. That technique would serve the dual purpose of CO2 sequestration and production of CH4 while maintaining the geo-mechanical stability of the reservoir. In order to analyze CH4 production process by means of CO2 or CO2+N2 injection into gas hydrate reservoirs, a new simulation tool, Mix3HydrateResSim (Mix3HRS)[1], was previously developed to account for the complex thermodynamics of multi-component hydrate phase and to predict the process of CH4 substitution by CO2 (and N2) in the hydrate lattice. In this work, Mix3HRS is used to simulate the CO2 injection into a Class 2 hydrate accumulation characterized by a mobile aqueous phase underneath a hydrate bearing sediment. That type of hydrate reservoir is broadly confirmed in permafrost and along seashore. The production technique implies a two-stage approach using a two-well design, one for an injector and one for a producer. First, the CO2 is injected into the mobile aqueous phase to convert it into immobile CO2 hydrate and to initiate CH4 release from gas hydrate across the hydrate-water boundary (generally designating the onset of a hydrate stability zone). Second, CH4 hydrate decomposition is induced by the depressurization method at a producer to estimate gas production potential over 30 years. The conversion of the free water phase into the CO2 hydrate significantly reduces competitive water production in the second stage, thereby improving the methane gas production. A base case using only the depressurization stage is conducted to compare with enhanced gas production predicted by the CO2-assisted technique. The approach also offers a possibility to permanently store carbon dioxide in the underground formation to greater extent comparing to a direct injection of CO2 into gas hydrate sediment. Numerical models are based on the hydrate formations at the

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

    DOE PAGES

    Schaef, Herbert T.; Davidson, Casie L.; Owen, Antionette Toni; ...

    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

  10. 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.

  11. 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.

  12. Noble gas as tracers for CO2 deep input in petroleum reservoirs

    NASA Astrophysics Data System (ADS)

    Pujol, Magali; Stuart, Finlay; Gilfillan, Stuart; Montel, François; Masini, Emmanuel

    2016-04-01

    The sub-salt hydrocarbon reservoirs in the deep offshore part of the Atlantic Ocean passive margins are a new key target for frontier oil and gas exploration. Type I source rocks locally rich in TOC (Total Organic Carbon) combined with an important secondary connected porosity of carbonate reservoirs overlain by an impermeable salt layer gives rise to reservoirs with high petroleum potential. However, some target structures have been found to be mainly filled with CO2 rich fluids. δ13C of the CO2 is generally between -9 and -4 permil, compatible with a deep source (metamorphic or mantle). Understanding the origin of the CO2 and the relative timing of its input into reservoir layers in regard to the geodynamic context appears to be a key issue for CO2 risk evaluation. The inertness and ubiquity of noble gases in crustal fluids make them powerful tools to trace the origin and migration of mixed fluids (Ballentine and Burnard 2002). The isotopic signature of He, Ne and Ar and the elemental pattern (He to Xe) of reservoir fluid from pressurized bottom hole samples provide an insight into fluid source influences at each reservoir depth. Three main end-members can be mixed into reservoir fluids (e.g. Gilfillan et al., 2008): atmospheric signature due to aquifer recharge, radiogenic component from organic fluid ± metamorphic influence, and mantle input. Their relative fractionation provides insights into the nature of fluid transport (Burnard et al., 2012)and its relative migration timing. In the studied offshore passive margin reservoirs, from both sides of South Atlantic margin, a strong MORB-like magmatic CO2 influence is clear. Hence, CO2 charge must have occurred during or after lithospheric break-up. CO2 charge(s) history appears to be complex, and in some cases requires several inputs to generate the observed noble gas pattern. Combining the knowledge obtained from noble gas (origin, relative timing, number of charges) with organic geochemical and thermodynamic

  13. 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

  14. 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.

  15. 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.

  16. Seepage flow behaviors of multi-stage fractured horizontal wells in arbitrary shaped shale gas reservoirs

    NASA Astrophysics Data System (ADS)

    Zhao, Yu-Long; Shan, Bao-Chao; Zhang, Lie-Hui; Liu, Qi-Guo

    2016-10-01

    The horizontal well incorporated with massive hydraulic fracturing has become a key and necessary technology to develop shale gas reservoirs efficiently, and transient pressure analysis is a practical method to evaluate the effectiveness of the fracturing. Until now, however, the related studies on the pressure of such wells have mainly focused on regular outer-boundaries, such as infinite, circular and rectangular boundary shapes, which do not always fulfill the practical conditions and, of course, could cause errors. By extending the boundary element method (BEM) into the application of multi-staged fractured horizontal wells, this paper presents a way of analyzing the transient pressure in arbitrary shaped shale gas reservoirs considering ad-/de-sorption and diffusion of the shale gas with the ‘tri-porosity’ mechanism model. The boundary integral equation can be obtained by coupling the fundamental solution of the Helmholtz equation with the dimensionless diffusivity equation. After discretizing the outer-boundaries and the fractures, the boundary integral equations are linearized and the coefficient matrix of the pressure on the boundaries is assembled, after which bottom-hole pressure can be calculated conveniently. Comparing the BEM solution with semi-analytical solution cases, the accuracy of the new solution can be validated. Then, the characteristic curves of the dimensionless pseudo pressure, as well as its derivative for a well in shale gas reservoirs, are drawn, based on which the parameters’ sensitivity analyses are also conducted. This paper not only enriches the well testing theory and method in shale gas reservoirs, but also provides an effective method to solve problems with complex inner- and outer-boundaries.

  17. The noble gas geochemistry of natural CO 2 gas reservoirs from the Colorado Plateau and Rocky Mountain provinces, USA

    NASA Astrophysics Data System (ADS)

    Gilfillan, Stuart M. V.; Ballentine, Chris J.; Holland, Greg; Blagburn, Dave; Lollar, Barbara Sherwood; Stevens, Scott; Schoell, Martin; Cassidy, Martin

    2008-02-01

    Identification of the source of CO 2 in natural reservoirs and development of physical models to account for the migration and interaction of this CO 2 with the groundwater is essential for developing a quantitative understanding of the long term storage potential of CO 2 in the subsurface. We present the results of 57 noble gas determinations in CO 2 rich fields (>82%) from three natural reservoirs to the east of the Colorado Plateau uplift province, USA (Bravo Dome, NM., Sheep Mountain, CO. and McCallum Dome, CO.), and from two reservoirs from within the uplift area (St. John's Dome, AZ., and McElmo Dome, CO.). We demonstrate that all fields have CO 2/ 3He ratios consistent with a dominantly magmatic source. The most recent volcanics in the province date from 8 to 10 ka and are associated with the Bravo Dome field. The oldest magmatic activity dates from 42 to 70 Ma and is associated with the McElmo Dome field, located in the tectonically stable centre of the Colorado Plateau: CO 2 can be stored within the subsurface on a millennia timescale. The manner and extent of contact of the CO 2 phase with the groundwater system is a critical parameter in using these systems as natural analogues for geological storage of anthropogenic CO 2. We show that coherent fractionation of groundwater 20Ne/ 36Ar with crustal radiogenic noble gases ( 4He, 21Ne, 40Ar) is explained by a two stage re-dissolution model: Stage 1: Magmatic CO 2 injection into the groundwater system strips dissolved air-derived noble gases (ASW) and accumulated crustal/radiogenic noble gas by CO 2/water phase partitioning. The CO 2 containing the groundwater stripped gases provides the first reservoir fluid charge. Subsequent charges of CO 2 provide no more ASW or crustal noble gases, and serve only to dilute the original ASW and crustal noble gas rich CO 2. Reservoir scale preservation of concentration gradients in ASW-derived noble gases thus provide CO 2 filling direction. This is seen in the Bravo Dome

  18. 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.

  19. 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.

  20. 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.

  1. Gas hydrate reservoir degassing: thermodynamic and kinetic data as basis for predictions

    NASA Astrophysics Data System (ADS)

    Schicks, J. M.; Girod, M.; Naumann, R.; Erzinger, J.; Horsfield, B.; di Primio, R.

    2008-12-01

    Natural gas hydrates contain predominantly methane but sometimes also other hydrocarbon- and non- hydrocarbon gases such as CO2 or H2S. The amount of other gases beside methane depends on the source of the gas: in case of a microbial origin the gas is almost pure methane whereas gases from thermal origin may contain a high percentage of higher-molecular weight compounds, such as ethane, propane and larger hydrocarbons. Calculated compositions of gas leaking from an oil reservoir also show a significant amount of nitrogen beside the other components. All components in addition to methane have a strong influence on the stability field of the resulting hydrate phase. In the presence of higher hydrocarbons the stability of the resulting gas hydrate is shifted to higher temperatures and lower pressures whereas the enclathration of nitrogen induces a shift of the hydrate stability to higher pressures and lower temperatures in comparison to pure methane hydrate. Furthermore, hydrate formation kinetics also depend on the composition of the gas phase: recent studies have shown the rapid formation of hydrates containing H2S in addition to methane, whereas the formation of hydrates containing small amounts of ethane and propane seemed to be kinetically inhibited. Due to the significant changes in hydrate stability and formation kinetics depending on gas composition thermodynamic and kinetic data for gas mixtures is crucial for all calculations and predictions regarding gas hydrate reservoir degassing as a consequence of climate change. In this study we will present thermodynamic and kinetic data from in-situ measurements (X-ray diffraction and Raman spectroscopy) on gas hydrates that had been synthesized under natural conditions.

  2. 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

  3. Tight gas reservoir simulation: Modeling discrete irregular strata-bound fracture network flow, including dynamic recharge from the matrix

    SciTech Connect

    McKoy, M.L., Sams, W.N.

    1997-10-01

    The US Department of Energy, Federal Energy Technology Center, has sponsored a project to simulate the behavior of tight, fractured, strata-bound gas reservoirs that arise from irregular discontinuous, or clustered networks of fractures. New FORTRAN codes have been developed to generate fracture networks, or simulate reservoir drainage/recharge, and to plot the fracture networks and reservoirs pressures. Ancillary codes assist with raw data analysis.

  4. 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.

  5. Hydrothermal origin of oil and gas reservoirs in basement rock of the South Vietnam continental shelf

    SciTech Connect

    Dmitriyevskiy, A.N.; Kireyev, F.A.; Bochko, R.A.; Fedorova, T.A. )

    1993-07-01

    Oil-saturated granites, with mineral parageneses typical of hydrothermal metasomatism and leaching haloes, have been found near faults in the crystalline basement of the South Vietnam continental shelf. The presence of native silver, barite, zincian copper, and iron chloride indicates a deep origin for the mineralizing fluids. Hydrothermally altered granites are a new possible type of reservoir and considerably broaden the possibilities of oil and gas exploration. 15 refs., 22 figs., 1 tab.

  6. 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

  7. Computing gas solubility in reservoir waters for environmental chemistry applications: the role of satellite observations

    NASA Astrophysics Data System (ADS)

    Rosa, R.; Lima, I.; Ramos, F.; Bambace, L.; Assireu, A.; Stech, J.; Novo, E.; Lorenzeti, L.

    Atmospheric greenhouse gases concentration has increased during the past centuries basically due to biogenic and pyrogenic anthopogenic emissions Recent investigations have shown that gas emission methane as an important example from tropical hydroelectric reservoirs may comprise a considerable fraction of the total anthropogenic bulk In order to evaluate the concentration of gases of potential importance in environmental chemistry the solubility of such gases have been collected and converted into a uniform format using the Henry s law which states that the solubility of a gas in a liquid is directly proportional to its partial pressure However the Henry s law can be derived as a function of temperature density molar mixing ratio in the aqueous phase and molar mass of water In this paper we show that due to the complex temperature variation and water composition measured in brazilian tropical reservoirs as Serra da Mesa and Manso expressive secular variation on the traditional solubility constants concentration of a species in the aqueous phase by the partial pressure of that species in the gas phase can change in a rate of approximately 30 in 6 decades This estimation comes from a computational analysis of temperature variation measured during 6 months in Serra da Mesa and Manso reservoirs taking into account a simulated density and molar mass variation of the aqueous composition in these environments As an important global change issue from this preliminary analysis we discuss its role in the current estimations on the concentration emission rates

  8. Resource target for gas reserves to be developed by management of water-drive gas reservoirs. Topical report, June 1, 1991-December 31, 1992

    SciTech Connect

    Ancell, K.L.; Fairchild, J.W.; Agnew, J.B.

    1993-02-01

    The study analyzed eleven documented projects that all showed incremental reserve potential from water-drive gas reservoirs through the use of management techniques. These projects were characterized by a factor called water-drive strength which was correlated with incremental recovery. The correlation confirmed earlier research that predicted the largest incremental potential in the moderate water-drive category. The parameters necessary to apply the correlation are initial gas in place and water-drive strength. Six hundred forty eight (648) reservoirs were analyzed in Texas, Louisiana Onshore and Louisiana Offshore production areas. Water-drive strength and initial gas-in-place were determined for each reservoir. Based on determinations for the 648 reservoirs, the entire production areas were estimated based on number of fields and reservoirs, number of wells, and cumulative production. The result of the calculation shows that the potential Resource Target is about 17 Tcf.

  9. Imaging pore space in tight gas sandstone reservoir: insights from broad ion beam cross-sectioning

    NASA Astrophysics Data System (ADS)

    Desbois, G.; Enzmann, F.; Urai, J. L.; Baerle, C.; Kukla, P. A.; Konstanty, J.

    2010-06-01

    Monetization of tight gas reservoirs, which contain significant gas reserves world-wide, represents a challenge for the entire oil and gas industry. The development of new technologies to enhance tight gas reservoir productivity is strongly dependent on an improved understanding of the rock properties and especially the pore framework. Numerous methods are now available to characterize sandstone cores. However, the pore space characterization at pore scale remains difficult due to the fine pore size and delicate sample preparation, and has thus been mostly indirectly inferred until now. Here we propose a new method of ultra high-resolution petrography combining high resolution SEM and argon ion beam cross sectioning (BIB, Broad Ion Beam) which prepares smooth and damage free surfaces. We demonstrate this method using the example of Permian (Rotliegend) age tight gas sandstone core samples. The combination of Ar-beam cross-sectioning facility and high-resolution SEM imaging has the potential to result in a step change in the understanding of pore geometries, in terms of its morphology, spatial distribution and evolution based on the generation of unprecedented image quality and resolution enhancing the predictive reliability of image analysis.

  10. 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.

  11. 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.

  12. 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

  13. Well-Production Data and Gas-Reservoir Heterogeneity -- Reserve Growth Applications

    USGS Publications Warehouse

    Dyman, Thaddeus S.; Schmoker, James W.

    2003-01-01

    Oil and gas well production parameters, including peakmonthly production (PMP), peak-consecutive-twelve month production (PYP), and cumulative production (CP), are tested as tools to quantify and understand the heterogeneity of reservoirs in fields where current monthly production is 10 percent or less of PMP. Variation coefficients, defined as VC= (F5-F95)/F50, where F5, F95, and F50 are the 5th, 95th, and 50th (median) fractiles of a probability distribution, are calculated for peak and cumulative production and examined with respect to internal consistency, type of production parameter, conventional versus unconventional accumulations, and reservoir depth. Well-production data for this study were compiled for 69 oil and gas fields in the Lower Pennsylvanian Morrow Formation of the Anadarko Basin, Oklahoma. Of these, 47 fields represent production from marine clastic facies. The Morrow data were supplemented by data from the Upper Cambrian and Lower Ordovician Arbuckle Group, Middle Ordovician Simpson Group, Middle Pennsylvanian Atoka Formation, and Silurian and Lower Devonian Hunton Group of the Anadarko Basin, one large gas field in Upper Cretaceous reservoirs of north-central Montana (Bowdoin field), and three areas of the Upper Devonian and Lower Mississippian Bakken Formation continuous-type (unconventional) oil accumulation in the Williston Basin, North Dakota and Montana. Production parameters (PMP, PYP, and CP) measure the net result of complex geologic, engineering, and economic processes. Our fundamental hypothesis is that well-production data provide information about subsurface heterogeneity in older fields that would be impossible to obtain using geologic techniques with smaller measurement scales such as petrographic, core, and well-log analysis. Results such as these indicate that quantitative measures of production rates and production volumes of wells, expressed as dimensionless variation coefficients, are potentially valuable tools for

  14. 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.

  15. 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.

  16. Paving the road for hydraulic fracturing in Paleozoic tight gas reservoirs in Abu Dhabi

    NASA Astrophysics Data System (ADS)

    Alzarouni, Asim

    This study contributes to the ongoing efforts of Abu Dhabi National Oil Company (ADNOC) to improve gas production and supply in view of increasing demand and diminishing conventional gas reservoirs in the region. The conditions of most gas reservoirs with potentially economical volumes of gas in Abu Dhabi are tight abrasive deep sand reservoirs at high temperature and pressures. Thus it inevitably tests the limit of both conventional thinking and technology. Accurate prediction of well performance is a major challenge that arises during planning phase. The primary aim is to determine technical feasibility for the implementation of the hydraulic fracture technology in a new area. The ultimate goal is to make economical production curves possible and pave the road to tap new resource of clean hydrocarbon energy source. The formation targeted in this study is characterized by quartzitic sandstone layers and variably colored shale and siltstones with thin layers of anhydrites. It dates back from late Permian to Carboniferous age. It forms rocks at the lower reservoir permeability ranging from 0.2 to less than 1 millidarcy (mD). When fractured, the expected well flow in Abu Dhabi offshore deep gas wells will be close to similar tight gas reservoir in the region. In other words, gas production can be described as transient initially with high rates and rapidly declining towards a pseudo-steady sustainable flow. The study results estimated fracturing gradient range from 0.85 psi/ft to 0.91 psi/ft. In other words, the technology can be implemented successfully to the expected rating without highly weighted brine. Hence, it would be a remarkable step to conduct the first hydraulic fracturing successfully in Abu Dhabi which can pave the road to tapping on a clean energy resource. The models predicted a remarkable conductivity enhancement and an increase of production between 3 to 4 times after fracturing. Moreover, a sustainable rate above 25 MMSCFD between 6 to 10 years is

  17. Simulating the gas hydrate production test at Mallik using the pilot scale pressure reservoir LARS

    NASA Astrophysics Data System (ADS)

    Heeschen, Katja; Spangenberg, Erik; Schicks, Judith M.; Priegnitz, Mike; Giese, Ronny; Luzi-Helbing, Manja

    2014-05-01

    LARS, the LArge Reservoir Simulator, allows for one of the few pilot scale simulations of gas hydrate formation and dissociation under controlled conditions with a high resolution sensor network to enable the detection of spatial variations. It was designed and built within the German project SUGAR (submarine gas hydrate reservoirs) for sediment samples with a diameter of 0.45 m and a length of 1.3 m. During the project, LARS already served for a number of experiments simulating the production of gas from hydrate-bearing sediments using thermal stimulation and/or depressurization. The latest test simulated the methane production test from gas hydrate-bearing sediments at the Mallik test site, Canada, in 2008 (Uddin et al., 2011). Thus, the starting conditions of 11.5 MPa and 11°C and environmental parameters were set to fit the Mallik test site. The experimental gas hydrate saturation of 90% of the total pore volume (70 l) was slightly higher than volumes found in gas hydrate-bearing formations in the field (70 - 80%). However, the resulting permeability of a few millidarcy was comparable. The depressurization driven gas production at Mallik was conducted in three steps at 7.0 MPa - 5.0 MPa - 4.2 MPa all of which were used in the laboratory experiments. In the lab the pressure was controlled using a back pressure regulator while the confining pressure was stable. All but one of the 12 temperature sensors showed a rapid decrease in temperature throughout the sediment sample, which accompanied the pressure changes as a result of gas hydrate dissociation. During step 1 and 2 they continued up to the point where gas hydrate stability was regained. The pressure decreases and gas hydrate dissociation led to highly variable two phase fluid flow throughout the duration of the simulated production test. The flow rates were measured continuously (gas) and discontinuously (liquid), respectively. Next to being discussed here, both rates were used to verify a model of gas

  18. Factors Influencing Greenhouse Gas Emissions from Three Gorges Reservoir of China

    NASA Astrophysics Data System (ADS)

    Zhao, Y.; Zhao, X.; Wu, B.; Zeng, Y.

    2013-05-01

    Three gorges reservoir (TGR) of China located in a subtropical climate region. It has attracted tremendous attentions on greenhouse gas (GHG) emissions from TGR, including carbon dioxide (CO2), methane (CH4) and nitrous Oxide (N2O). Results on monthly fluxes and their spatial and seasonal variations have been determined by a static chamber method and have published elsewhere recently. Here we made further discussions on the factors influencing GHG emissions from TGR. We conclude that the hydrodynamic situation was the key parameter controlling the fluxes. TGR was a typical valley-type reservoir and with a complex terrain in the surrounding catchment, where almost 94% of the region was occupied by mountainous, this situation made the reservoir had sufficient allochthonous organic carbon input origin from eroded soil. But no significant relationship between organic carbon (both dissolved and particulate form) and GHG fluxes, we thought that TGR was not a carbon-limited reservoir on the GHG issue. In the mainstream of the reservoir, dissolved CO2 and CH4 were supersaturation in the water, the relative high flow together with the narrow-deep channel result in great disturbance, which would promote more dissolved gas escape into the atmosphere. This could also approved by the differences in CO2 and CH4 fluxes in different reach from up to downstream of the reservoir. In the reservoir tail water, the mainstream remained the high flow rate, both CO2 and CH4 fluxes is relative high, while downwards, the fluxes were gradually dropped, as after the impoundment of the reservoir, flow rate have greatly decreased. Another evidence was the relative higher CO2 and CH4 fluxes in the rainy season. As the rainy season approaches, TGR would empty the storage to prepare for retention and mitigation. The interplay between water inflows and outflows produced marked variations in the water residence times. During the rainy season times, this could be as short as 6 days with higher water

  19. 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.

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

    SciTech Connect

    Franklin M. Orr, Jr.

    2002-03-31

    This report outlines progress in the second quarter of the second year of the DOE project ''High Resolution Prediction of Gas Injection Process Performance for Heterogeneous Reservoirs''. A three-dimensional streamline simulator, developed at Stanford University, has been modified in order to use analytical one-dimensional dispersion-free solutions to multicomponent gas injection processes. The use of analytical one-dimensional solutions in combination with streamline simulation is demonstrated to speedup compositional simulations of miscible gas injection processes by orders of magnitude compared to a conventional finite difference simulator. Two-dimensional and three-dimensional examples are reported to demonstrate the potential of this technology. Finally, the assumptions of the approach and possible extensions to include the effects of gravity are discussed.

  1. 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

  2. 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

  3. 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.

  4. 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

  5. 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

  6. Gas hydrate saturations estimated from fractured reservoir at Site NGHP-01-10, Krishna-Godavari Basin, India

    USGS Publications Warehouse

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

    2009-01-01

    During the Indian National Gas Hydrate Program Expedition 01 (NGHP-Ol), one of the richest marine gas hydrate accumulations was discovered at Site NGHP-01-10 in the Krishna-Godavari Basin. The occurrence of concentrated gas hydrate at this site is primarily controlled by the presence of fractures. Assuming the resistivity of gas hydratebearing sediments is isotropic, th?? conventional Archie analysis using the logging while drilling resistivity log yields gas hydrate saturations greater than 50% (as high as ???80%) of the pore space for the depth interval between ???25 and ???160 m below seafloor. On the other hand, gas hydrate saturations estimated from pressure cores from nearby wells were less than ???26% of the pore space. Although intrasite variability may contribute to the difference, the primary cause of the saturation difference is attributed to the anisotropic nature of the reservoir due to gas hydrate in high-angle fractures. Archie's law can be used to estimate gas hydrate saturations in anisotropic reservoir, with additional information such as elastic velocities to constrain Archie cementation parameters m and the saturation exponent n. Theory indicates that m and n depend on the direction of the measurement relative to fracture orientation, as well as depending on gas hydrate saturation. By using higher values of m and n in the resistivity analysis for fractured reservoirs, the difference between saturation estimates is significantly reduced, although a sizable difference remains. To better understand the nature of fractured reservoirs, wireline P and S wave velocities were also incorporated into the analysis.

  7. Assessment of uncertainty and degasification efficiency in coal seam gas drainage through stochastic reservoir simulation

    NASA Astrophysics Data System (ADS)

    Özgen Karacan, C.

    2016-04-01

    Coal seam degasification improves coal mine safety by reducing the gas content of coal seams and also by generating added value as an energy source. Coal bed reservoir simulation, as a reservoir management and forecasting tool, is one of the most effective ways to help with these two main objectives. However, as in all modeling and simulation studies, reservoir description and whether observed productions can be predicted are important considerations. Using geostatistical realizations as spatial maps of different coal reservoir properties is a more realistic approach than assuming uniform properties across the field. In fact, this approach can help with simultaneous history matching of multiple wellbores to enhance the confidence in spatial models of different coal properties that are pertinent to degasification. The problem that still remains, however, is the uncertainty in geostatistical, and thus reservoir, simulations originating from partial sampling of the seam that does not properly reflect the stochastic nature of coal property realizations. This study demonstrates the use of geostatistical realizations generated through sequential Gaussian simulation and co-simulation techniques and assesses the uncertainty in coal seam reservoir simulations with history matching errors. 100 individual realizations of 10 coal properties were generated using geostatistical techniques. These realizations were used to create 100 realization bundles (property datasets). Each of these bundles was then used in coal seam reservoir simulations for simultaneous history matching of degasification wells. History matching errors for each bundle were evaluated and the single set of realizations that would minimize the error for all wells was defined. Errors were compared with those of E-type and the average realization of the best matches. The study helped to determine the realization bundle that consisted of the spatial maps of coal properties, which resulted in minimum error. In

  8. Numerical simulation of ultrasonic wave transmission experiments in rocks of shale gas reservoirs

    NASA Astrophysics Data System (ADS)

    Chen, Qiao; Yao, Guanghua; Zhu, Honglin; Tan, Yanhu; Xu, Fenglin

    2017-01-01

    Shale gas reservoirs have risen in importance in China's new power source exploration and development program. The investigation of the propagation of ultrasonic waves in shale forms the basis for the full waveform application of acoustic logging data to the exploration of shale gas. Using acoustic wave theory, initial conditions, vibration source conditions, and stability conditions are developed in combination with experimental background of ultrasonic wave transmission. With improved boundary conditions, we performed numerical simulations of the ultrasound transmission experiments in shale using the high-order staggered-grid finite difference method (second-order in the time domain and fourth-order in the space domain). With programs developed within MatLab, the results obtained from numerical simulations agree well with experimental results based on physical models. In addition, using snapshots of the wave field that give a microscopic perspective, the propagation laws for ultrasonic waves can be analyzed. Using this method, human error is avoided, transmission experiments costs can be reduced and efficiency improved. This method extends the scope of experimental investigations regarding the transmission of ultrasonic waves in a shale gas reservoir with increasing stratification, and thus has great theoretical value and practical significance.

  9. Correlation between gas compositions and physical phenomena affecting the reservoir fluid in Palinpinon geothermal field (Philippines)

    SciTech Connect

    D'More F.; Nuti, S.; Ruaya, J.R.; Ramos-Candelaria, M.N.; Seastres, J.S.

    1993-01-28

    Using thermodynamic gas equilibria to calculate temperature and steam fraction in the reservoir, three main physical phenomena due to exploitation of Palinpinon field are identified. 1) Pressure drawdown producing a local increase in the computed steam fraction, with the fluid maintaining high temperature values (close to 300°C). Strong decline in flow rate is observed. 2) Irreversible steam losses from the original high temperature liquid phase during its ascent through fractures in upper zones of the reservoir. Steam is generally lost at temperatures (e.g. 240°C) lower then those of the original aquifer. 3) Dilution and cooling effects due to reinjection fluid returns. These are function of the local geostructural conditions linking through fractures the injectors and production wells. The computed fraction of the recovered reinjected brine can in some case exceed 80% of the total produced fluid. At the same time the computed gas equilibration temperatures can decline from 280-300°C to as low as 215-220°C. Comparing these values with the well bottom measured temperatures, the proposed methodology based on gas chemistry gives more reliable temperature estimate than water chemistry based geothermometers for fluids with high fractions of injected brine.

  10. 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.

  11. Geologic parameters controlling natural gas production from single, deeply buried coal reservoir

    SciTech Connect

    Decker, D.

    1986-05-01

    Methane occluded in coal reservoirs is being commercially produced in the Appalachian, Warrior, San Juan, and Piceance basins. Of these, the Piceance basin, with an estimated 100 tcf of coal-bed methane, represents the largest coal-bed methane resource in the US. Exploration efforts applied to this vast resource have been hampered by lack of appropriate exploration, drilling, completion, stimulation, and production methods. The Deep Coal Seam project sponsored by the Gas Research Institute and operated by Resource Enterprises, Inc., at the Red Mountain site, Mesa County, Colorado, was established to develop, improve, evaluate, and communicate the technology required to produce gas from deeply buried coal reservoirs. Regional geologic studies have established the Red Mountain site as representing most of the coal-bed methane resource within the Piceance basin. The project is focused on the D coal seam, belonging to the Cameo coal group of the Williams Fork formation, Upper Cretaceous Mesaverde Group. The D coal seam thickness ranges from 16 to 20 ft (5 to 6 m) throughout the site, with an average drilling depth of 5500 ft (1700 m). This coal seam is medium-volatile bituminous in rank, with an average gas content of 250 standard ft/sup 3//ton (8 standard cm/sup 3//g).

  12. Relaxation limit of a compressible gas-liquid model with well-reservoir interaction

    NASA Astrophysics Data System (ADS)

    Solem, Susanne; Evje, Steinar

    2017-02-01

    This paper deals with the relaxation limit of a two-phase compressible gas-liquid model which contains a pressure-dependent well-reservoir interaction term of the form q (P_r - P) where q>0 is the rate of the pressure-dependent influx/efflux of gas, P is the (unknown) wellbore pressure, and P_r is the (known) surrounding reservoir pressure. The model can be used to study gas-kick flow scenarios relevant for various wellbore operations. One extreme case is when the wellbore pressure P is largely dictated by the surrounding reservoir pressure P_r. Formally, this model is obtained by deriving the limiting system as the relaxation parameter q in the full model tends to infinity. The main purpose of this work is to understand to what extent this case can be represented by a well-defined mathematical model for a fixed global time T>0. Well-posedness of the full model has been obtained in Evje (SIAM J Math Anal 45(2):518-546, 2013). However, as the estimates for the full model are dependent on the relaxation parameter q, new estimates must be obtained for the equilibrium model to ensure existence of solutions. By means of appropriate a priori assumptions and some restrictions on the model parameters, necessary estimates (low order and higher order) are obtained. These estimates that depend on the global time T together with smallness assumptions on the initial data are then used to obtain existence of solutions in suitable Sobolev spaces.

  13. 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.

  14. 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.

  15. 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

  16. 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.

  17. 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

  18. 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.

  19. Gulf of Mexico Oil and Gas Atlas Series: Play analysis of oligocene and miocene reservoirs from Texas State Offshore Waters

    SciTech Connect

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

    1993-12-31

    The objective of the Offshore Northern Gulf of Mexico Oil and Gas Resource Atlas Series is to define hydrocarbon plays by integrating geologic and engineering data for oil and gas reservoirs with large-scale patterns of depositional basin fill and geologic age. The primary product of the program will be an oil and gas atlas set for the offshore northern Gulf of Mexico and a computerized geographical information system of geologic and engineering data linked to reservoir location. The oil and gas atlas for the Gulf of Mexico will provide a critically compiled, comprehensive reference that is needed to more efficiently develop reservoirs, to extend field limits, and to better assess the opportunities for intrafield exploration. The play atlas will provide an organizational framework to aid development in mature areas and to extend exploration paradigms from mature areas into frontier areas deep below the shelf and into deep waters of the continental slope. In addition to serving as a model for exploration and education, the offshore atlas will aid resource assessment efforts of State, Federal, and private agencies by allowing for greater precision in the extrapolation of variables within and between plays. Classification and organization of reservoirs into plays have proved to be effective in previous atlases produced by the Bureau, including the Texas oil and gas atlases, the Midcontinent gas atlas, and Central and Eastern Gulf Coast gas atlas.

  20. 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

  1. 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

  2. Optimized Design and Use of Induced Complex Fractures in Horizontal Wellbores of Tight Gas Reservoirs

    NASA Astrophysics Data System (ADS)

    Zeng, F. H.; Guo, J. C.

    2016-04-01

    Multistage hydraulic fracturing is being increasing use in the establishment of horizontal wells in tight gas reservoirs. Connecting hydraulic fractures to natural and stress-induced fractures can further improve well productivity. This paper investigates the fracture treatment design issues involved in the establishment of horizontal wellbores, including the effects of geologic heterogeneity, perforation parameters, fracturing patterns, and construction parameters on stress anisotropy during hydraulic fracturing and on natural fractures during hydraulic fracture propagation. The extent of stress reversal and reorientation was calculated for fractures induced by the creation of one or more propped fractures. The effects of stress on alternate and sequential fracturing horizontal well and on the reservoir's mechanical properties, including the spatial extent of stress reorientation caused by the opening of fractures, were assessed and quantified. Alternate sequencing of transverse fractures was found to be an effective means of enhancing natural fracture stimulation by allowing fractures to undergo less stress contrast during propagation. The goal of this paper was to present a new approach to design that optimizes fracturing in a horizontal wellbore from the perspectives of both rock mechanics and fluid production. The new design is a modified version of alternate fracturing, where the fracture-initiation sequence was controlled by perforation parameters with a staggered pattern within a horizontal wellbore. Results demonstrated that the modified alternate fracturing performed better than original sequence fracturing and that this was because it increased the contact area and promoted more gas production in completed wells.

  3. 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.

  4. 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.

  5. 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

  6. Noble gas and hydrocarbon tracers in multiphase unconventional hydrocarbon systems: Toward integrated advanced reservoir simulators

    NASA Astrophysics Data System (ADS)

    Darrah, T.; Moortgat, J.; Poreda, R. J.; Muehlenbachs, K.; Whyte, C. J.

    2015-12-01

    Although hydrocarbon production from unconventional energy resources has increased dramatically in the last decade, total unconventional oil and gas recovery from black shales is still less than 25% and 9% of the totals in place, respectively. Further, the majority of increased hydrocarbon production results from increasing the lengths of laterals, the number of hydraulic fracturing stages, and the volume of consumptive water usage. These strategies all reduce the economic efficiency of hydrocarbon extraction. The poor recovery statistics result from an insufficient understanding of some of the key physical processes in complex, organic-rich, low porosity formations (e.g., phase behavior, fluid-rock interactions, and flow mechanisms at nano-scale confinement and the role of natural fractures and faults as conduits for flow). Noble gases and other hydrocarbon tracers are capably of recording subsurface fluid-rock interactions on a variety of geological scales (micro-, meso-, to macro-scale) and provide analogs for the movement of hydrocarbons in the subsurface. As such geochemical data enrich the input for the numerical modeling of multi-phase (e.g., oil, gas, and brine) fluid flow in highly heterogeneous, low permeability formations Herein we will present a combination of noble gas (He, Ne, Ar, Kr, and Xe abundances and isotope ratios) and molecular and isotopic hydrocarbon data from a geographically and geologically diverse set of unconventional hydrocarbon reservoirs in North America. Specifically, we will include data from the Marcellus, Utica, Barnett, Eagle Ford, formations and the Illinois basin. Our presentation will include geochemical and geological interpretation and our perspective on the first steps toward building an advanced reservoir simulator for tracer transport in multicomponent multiphase compositional flow (presented separately, in Moortgat et al., 2015).

  7. 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.

  8. Sustaining Fracture Area and Conductivity of Gas shale Reservoirs for Enhancing Long-term Production and Recovery

    NASA Astrophysics Data System (ADS)

    Suarez-Rivera, R.; Marino, S.; Ghassemi, A.

    2010-12-01

    Natural gas from organic rich shale formations has become an increasingly important energy resource worldwide over the past decade. Extensive hydraulic fracture networks with massive contact surface areas are frequently required to achieve satisfactory economic production in these highly heterogeneous reservoirs, with permeability in the nano-Darcy range. Current operational experience in gas shale plays indicates that the loss of productive fracture area and loss of fracture conductivity, both immediate and over time, are the major factors leading to reduced flow rates, marginal production, and poor gas recovery. This theoretical and experimental project, funded by a RPSEA (Research Partnership to Secure Energy for America) program, is aimed at understanding the multiple causes of loss of fracture surface area and fracture conductivity. The main objectives of the project are: understand the multiple causes of loss of fracture area and fracture conductivity, and define solutions to mitigate the resulting loss of production. Define the types of fracture networks that are more prone to loosing fracture area and define critical parameters, for each reservoir type, (including proppant concentration, fluid interaction, relative shear displacement and others) to preserve fracture conductivity, and define an integrated methodology for evaluating reservoir properties that result in proneness to loss of fracture area and fracture conductivity, and define adequate solutions for the various reservoir types Current results include the evaluation of reservoir geology, mineralogy, reservoir properties, mechanical properties, including surface hardness, and petrologic analysis on cores representative of Barnett, Haynesville and Marcellus reservoir shales. A comparison of these properties provides an initial reference frame for identifying differences in behavior between the various reservoirs, and for anticipating the potential for embedment and loss of fracture conductivity

  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. The RESOLVE Survey Atomic Gas Census and Environmental Influences on Galaxy Gas Reservoirs

    NASA Astrophysics Data System (ADS)

    Stark, David V.; Kannappan, Sheila J.; Eckert, Kathleen D.; Florez, Jonathan; Hall, Kirsten R.; Watson, Linda C.; Hoversten, Erik A.; Burchett, Joseph N.; Guynn, David T.; Baker, Ashley D.; Moffett, Amanda J.; Berlind, Andreas A.; Norris, Mark A.; Haynes, Martha P.; Giovanelli, Riccardo; Leroy, Adam K.; Pisano, D. J.; Wei, Lisa H.; Gonzalez, Roberto E.; Calderon, Victor F.

    2016-12-01

    We present the H i mass inventory for the REsolved Spectroscopy Of a Local VolumE (RESOLVE) survey, a volume-limited, multi-wavelength census of >1500 z = 0 galaxies spanning diverse environments and complete in baryonic mass down to dwarfs of ˜109 {M}⊙ . This first 21 cm data release provides robust detections or strong upper limits (1.4M H i < 5%-10% of stellar mass M *) for ˜94% of RESOLVE. We examine global atomic gas-to-stellar mass ratios (G/S) in relation to galaxy environment using several metrics: group dark matter halo mass M h, central/satellite designation, relative mass density of the cosmic web, and distance to the nearest massive group. We find that at fixed M *, satellites have decreasing G/S with increasing M h starting clearly at M h ˜ 1012 {M}⊙ , suggesting the presence of starvation and/or stripping mechanisms associated with halo gas heating in intermediate-mass groups. The analogous relationship for centrals is uncertain because halo abundance matching builds in relationships between central G/S, stellar mass, and halo mass, which depend on the integrated group property used as a proxy for halo mass (stellar or baryonic mass). On larger scales G/S trends are less sensitive to the abundance matching method. At fixed M h ≤ 1012 {M}⊙ , the fraction of gas-poor centrals increases with large-scale structure density. In overdense regions, we identify a rare population of gas-poor centrals in low-mass (M h < 1011.4 {M}⊙ ) halos primarily located within ˜1.5× the virial radius of more massive (M h > 1012 {M}⊙ ) halos, suggesting that gas stripping and/or starvation may be induced by interactions with larger halos or the surrounding cosmic web. We find that the detailed relationship between G/S and environment varies when we examine different subvolumes of RESOLVE independently, which we suggest may be a signature of assembly bias.

  11. 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.

  12. 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)

  13. 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)

  14. 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

  15. 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

  16. Non-equilibrium simulation of CH4 production through the depressurization method from gas hydrate reservoirs

    NASA Astrophysics Data System (ADS)

    Qorbani, Khadijeh; Kvamme, Bjørn

    2016-04-01

    Natural gas hydrates (NGHs) in nature are formed from various hydrate formers (i.e. aqueous, gas, and adsorbed phases). As a result, due to Gibbs phase rule and the combined first and second laws of thermodynamics CH4-hydrate cannot reach thermodynamic equilibrium in real reservoir conditions. CH4 is the dominant component in NGH reservoirs. It is formed as a result of biogenic degradation of biological material in the upper few hundred meters of subsurface. It has been estimated that the amount of fuel-gas reserve in NGHs exceed the total amount of fossil fuel explored until today. Thus, these reservoirs have the potential to satisfy the energy requirements of the future. However, released CH4 from dissociated NGHs could find its way to the atmosphere and it is a far more aggressive greenhouse gas than CO2, even though its life-time is shorter. Lack of reliable field data makes it difficult to predict the production potential, as well as safety of CH4 production from NGHs. Computer simulations can be used as a tool to investigate CH4 production through different scenarios. Most hydrate simulators within academia and industry treat hydrate phase transitions as an equilibrium process and those which employ the kinetic approach utilize simple laboratory data in their models. Furthermore, it is typical to utilize a limited thermodynamic description where only temperature and pressure projections are considered. Another widely used simplification is to assume only a single route for the hydrate phase transitions. The non-equilibrium nature of hydrate indicates a need for proper kinetic models to describe hydrate dissociation and reformation in the reservoir with respect to thermodynamics variables, CH4 mole-fraction, pressure and temperature. The RetrasoCodeBright (RCB) hydrate simulator has previously been extended to model CH4-hydrate dissociation towards CH4 gas and water. CH4-hydrate is added to the RCB data-base as a pseudo mineral. Phase transitions are treated

  17. 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.

  18. 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 Ω 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 Ω 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.

  19. 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

  20. Scale-dependent gas hydrate saturation estimates in sand reservoirs in the Ulleung Basin, East Sea of Korea

    USGS Publications Warehouse

    Lee, Myung Woong; Collett, Timothy S.

    2013-01-01

    Through the use of 2-D and 3-D seismic data, several gas hydrate prospects were identified in the Ulleung Basin, East Sea of Korea and thirteen drill sites were established and logging-while-drilling (LWD) data were acquired from each site in 2010. Sites UBGH2–6 and UBGH2–10 were selected to test a series of high amplitude seismic reflections, possibly from sand reservoirs. LWD logs from the UBGH2–6 well indicate that there are three significant sand reservoirs with varying thickness. Two upper sand reservoirs are water saturated and the lower thinly bedded sand reservoir contains gas hydrate with an average saturation of 13%, as estimated from the P-wave velocity. The well logs at the UBGH2–6 well clearly demonstrated the effect of scale-dependency on gas hydrate saturation estimates. Gas hydrate saturations estimated from the high resolution LWD acquired ring resistivity (vertical resolution of about 5–8 cm) reaches about 90% with an average saturation of 28%, whereas gas hydrate saturations estimated from the low resolution A40L resistivity (vertical resolution of about 120 cm) reaches about 25% with an average saturation of 11%. However, in the UBGH2–10 well, gas hydrate occupies a 5-m thick sand reservoir near 135 mbsf with a maximum saturation of about 60%. In the UBGH2–10 well, the average and a maximum saturation estimated from various well logging tools are comparable, because the bed thickness is larger than the vertical resolution of the various logging tools. High resolution wireline log data further document the role of scale-dependency on gas hydrate calculations.

  1. Comparison of the physical and geotechnical properties of gas-hydrate-bearing sediments from offshore India and other gas-hydrate-reservoir systems

    USGS Publications Warehouse

    Winters, William J.; Wilcox-Cline, R.W.; Long, P.; Dewri, S.K.; Kumar, P.; Stern, Laura A.; Kerr, Laura A.

    2014-01-01

    The sediment characteristics of hydrate-bearing reservoirs profoundly affect the formation, distribution, and morphology of gas hydrate. The presence and type of gas, porewater chemistry, fluid migration, and subbottom temperature may govern the hydrate formation process, but it is the host sediment that commonly dictates final hydrate habit, and whether hydrate may be economically developed.In this paper, the physical properties of hydrate-bearing regions offshore eastern India (Krishna-Godavari and Mahanadi Basins) and the Andaman Islands, determined from Expedition NGHP-01 cores, are compared to each other, well logs, and published results of other hydrate reservoirs. Properties from the hydrate-free Kerala-Konkan basin off the west coast of India are also presented. Coarser-grained reservoirs (permafrost-related and marine) may contain high gas-hydrate-pore saturations, while finer-grained reservoirs may contain low-saturation disseminated or more complex gas-hydrates, including nodules, layers, and high-angle planar and rotational veins. However, even in these fine-grained sediments, gas hydrate preferentially forms in coarser sediment or fractures, when present. The presence of hydrate in conjunction with other geologic processes may be responsible for sediment porosity being nearly uniform for almost 500 m off the Andaman Islands.Properties of individual NGHP-01 wells and regional trends are discussed in detail. However, comparison of marine and permafrost-related Arctic reservoirs provides insight into the inter-relationships and common traits between physical properties and the morphology of gas-hydrate reservoirs regardless of location. Extrapolation of properties from one location to another also enhances our understanding of gas-hydrate reservoir systems. Grain size and porosity effects on permeability are critical, both locally to trap gas and regionally to provide fluid flow to hydrate reservoirs. Index properties corroborate more advanced

  2. 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, Shruti

    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.

  3. Application of coiled-tubing-drilling technology on a deep underpressured gas reservoir

    SciTech Connect

    1997-06-01

    The Upper-Mississippian Elkton formation is a dolomitized shallow-water carbonate consisting of dense limestones and porous dolomites. The Elkton was deposited in an open-shelf environment as crinoid grainstones, coral packstones, and lime muds. Deposition of impermeable shales and siltstones of the Lower Cretaceous created the lateral and updip seals. Reservoir thickness can be up to 20 m, with porosities reaching 20% and averaging 10%. The reservoir gas contains approximately 0.5% hydrogen sulfide. Well 11-18 was to be completed in the Harmatten Elkton pool. The pool went on production in 1967 at an initial pressure of 23,500 kPa. At the current pressure of 16,800 kPa, the remaining reserves are underpressured at 6.5 kPa/m, and underbalanced horizontal drilling was selected as the most suitable technique for exploiting remaining reserves. Coiled-tubing (CT) technology was selected to ensure continuous underbalanced conditions and maintain proper well control while drilling. The paper describes the equipment, CT drilling summary, and drilling issues.

  4. Naturally fractured tight gas reservoir detection optimization. Annual report, August 1994--July 1995

    SciTech Connect

    1995-09-01

    This report details the field work undertaken Blackhawk Geosciences and Lynn, Inc. during August 1994 to July 1995 at a gas field in the Wind River Basin in central Wyoming. The work described herein consisted of four parts: 9C VSP in a well at the site; additional processing of the previously recorded 3D P-wave survey on the site and Minivibrator testing; and planning and acquisition of a 3-D, 3-C seismic survey. The objectives of all four parts were to characterize the nature of anisotropy in the reservoir. With the 9C VSP, established practices were used to achieve this objective in the immediate vicinity of the well. The additional processing of the 3-D uses developmental techniques to determine areas of fractures in 3-D surveys. With the multicomponent studies, tests were conducted to establish the feasibility of surface recording of the anisotropic reservoir rocks. The 3-D, 3-C survey will provide both compressional and shear wave data sets over areas of known fracturing to verify the research.

  5. Geomechanical response to seasonal gas storage in depleted reservoirs: A case study in the Po River basin, Italy

    NASA Astrophysics Data System (ADS)

    Teatini, P.; Castelletto, N.; Ferronato, M.; Gambolati, G.; Janna, C.; Cairo, E.; Marzorati, D.; Colombo, D.; Ferretti, A.; Bagliani, A.; Bottazzi, F.

    2011-06-01

    Underground gas storage (UGS) in depleted hydrocarbon reservoirs is a strategic practice to cope with the growing energy demand and occurs in many places in Europe and North America. In response to summer gas injection and winter gas withdrawal the reservoir expands and contracts essentially elastically as a major consequence of the fluid (gas and water) pore pressure fluctuations. Depending on a number of factors, including the reservoir burial depth, the difference between the largest and the smallest gas pore pressure, and the geomechanical properties of the injected formation and the overburden, the porous medium overlying the reservoir is subject to three-dimensional deformation with the related cyclic motion of the land surface being both vertical and horizontal. We present a methodology to evaluate the environmental impact of underground gas storage and sequestration from the geomechanical perspective, particularly in relation to the ground surface displacements. Long-term records of injected and removed gas volume and fluid pore pressure in the "Lombardia" gas field, northern Italy, are available together with multiyear detection of vertical and horizontal west-east displacement of the land surface above the reservoir by an advanced permanent scatterer interferometric synthetic aperture radar (PSInSAR) analysis. These data have been used to calibrate a 3-D fluid-dynamic model and develop a 3-D transversally isotropic geomechanical model. The latter has been successfully implemented and used to reproduce the vertical and horizontal cyclic displacements, on the range of 8-10 mm and 6-8 mm, respectively, measured between 2003 and 2007 above the reservoir where a UGS program has been underway by Stogit-Eni S.p.A. since 1986 following a 5 year field production life. Because of the great economical interest to increase the working gas volume as much as possible, the model addresses two UGS scenarios where the gas pore overpressure is pushed from the current 103

  6. Relationships between water and gas chemistry in mature coalbed methane reservoirs of the Black Warrior Basin

    USGS Publications Warehouse

    Pashin, Jack C.; McIntyre-Redden, Marcella R.; Mann, Steven D.; Kopaska-Merkel, David C.; Varonka, Matthew S.; Orem, William H.

    2014-01-01

    Water and gas chemistry in coalbed methane reservoirs of the Black Warrior Basin reflects a complex interplay among burial processes, basin hydrodynamics, thermogenesis, and late-stage microbial methanogenesis. These factors are all important considerations for developing production and water management strategies. Produced water ranges from nearly potable sodium-bicarbonate water to hypersaline sodium-chloride brine. The hydrodynamic framework of the basin is dominated by structurally controlled fresh-water plumes that formed by meteoric recharge along the southeastern margin of the basin. The produced water contains significant quantities of hydrocarbons and nitrogen compounds, and the produced gas appears to be of mixed thermogenic-biogenic origin.Late-stage microbial methanogenesis began following unroofing of the basin, and stable isotopes in the produced gas and in mineral cements indicate that late-stage methanogenesis occurred along a CO2-reduction metabolic pathway. Hydrocarbons, as well as small amounts of nitrate in the formation water, probably helped nourish the microbial consortia, which were apparently active in fresh to hypersaline water. The produced water contains NH4+ and NH3, which correlate strongly with brine concentration and are interpreted to be derived from silicate minerals. Denitrification reactions may have generated some N2, which is the only major impurity in the coalbed gas. Carbon dioxide is a minor component of the produced gas, but significant quantities are dissolved in the formation water. Degradation of organic compounds, augmented by deionization of NH4+, may have been the principal sources of hydrogen facilitating late-stage CO2 reduction.

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

    SciTech Connect

    Franklin M. Orr, Jr.

    2002-06-30

    This report outlines progress in the third quarter of the second year of the DOE project ''High Resolution Prediction of Gas Injection Process Performance for Heterogeneous Reservoirs''. High order finite difference schemes for one-dimensional, two-phase, multicomponent displacements are investigated. Numerical tests are run using a three component fluid description for a case when the interaction between phase behavior and flow is strong. Some currently used total variation diminishing (TVD) methods produce unstable results. A third order essentially non-oscillatory (ENO) method captures the effects of phase behavior for this test case. Possible modifications to ensure stability are discussed along with plans to incorporate higher order schemes into the 3DSL streamline simulator.

  8. Gas-and water-saturated conditions in the Piceance Basin, Western Colorado: Implications for fractured reservoir detection in a gas-centered coal basin

    SciTech Connect

    Hoak, T.E.; Decker, A.D.

    1995-10-01

    Mesaverde Group reservoirs in the Piceance Basin, Western Colorado contain a large reservoir base. Attempts to exploit this resource base are stymied by low permeability reservoir conditions. The presence of abundant natural fracture systems throughout this basin, however, does permit economic production. Substantial production is associated with fractured reservoirs in Divide Creek, Piceance Creek, Wolf Creek, White River Dome, Plateau, Shire Gulch, Grand Valley, Parachute and Rulison fields. Successful Piceance Basin gas production requires detailed information about fracture networks and subsurface gas and water distribution in an overall gas-centered basin geometry. Assessment of these three parameters requires an integrated basin analysis incorporating conventional subsurface geology, seismic data, remote sensing imagery analysis, and an analysis of regional tectonics. To delineate the gas-centered basin geometry in the Piceance Basin, a regional cross-section spanning the basin was constructed using hydrocarbon and gamma radiation logs. The resultant hybrid logs were used for stratigraphic correlations in addition to outlining the trans-basin gas-saturated conditions. The magnitude of both pressure gradients (paludal and marine intervals) is greater than can be generated by a hydrodynamic model. To investigate the relationships between structure and production, detailed mapping of the basin (top of the Iles Formation) was used to define subtle subsurface structures that control fractured reservoir development. The most productive fields in the basin possess fractured reservoirs. Detailed studies in the Grand Valley-Parachute-Rulison and Shire Gulch-Plateau fields indicate that zones of maximum structural flexure on kilometer-scale structural features are directly related to areas of enhanced production.

  9. 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.

  10. Permeable weak layer in the gas hydrate reservoir presumed by logging-while-drilling log data

    NASA Astrophysics Data System (ADS)

    Suzuki, K.; Fujii, T.; Takayama, T.

    2015-12-01

    One of the specific intervals attracted attention to analyze the 2012 gas-production test from methane-hydrate reservoir, because its pressure and temperature behavior was different from other intervals of the production zone. The pressure and temperature behavior implied the interval should be high permeability. We analyzed the interval to characterize the properties before gas-production test; i.e. the original properties of the interval. We checked the data of the logging-while-drilling data of AT1-MC, which was one of the monitoring wells at the gas-production test. The specific interval was described as 1290-1298m, where was boundary between upper sand and mud alteration layer and middle clayey zone. The first, we noticed that there were several layers that showed broad T2 distributions of nuclear magnetic resonance (NMR). On the basis of the T2 distributions and the resistivity data of the interval, there were large pores that showed the T2 distribution around 100ms, even though some amount of methane hydrate were contained. This result could be explained the interval showed high permeability below the 1294m. After checking their ultra-sonic caliper data in detail, we found interesting difference in the interval. The specific interval of 1294-1295m had different borehole-enlargement direction from other intervals of the methane-hydrate bearing zone, even though diameter of borehole was slightly enlarged. Other layers in the methane hydrate reservoir showed NW-SE directions of enlargement, however, the specific interval had NE-SW direction of enlargement. Hence, H-max stress and H-min stress of this specific interval could be very close values. Thus, near the 1294m, the lithology of the layer was permeable and weak. It might be useful to understand many phenomena occured during the gas-production test. This research was conducted as a part of the MH21 research, and the authors would like to express their sincere appreciation to MH21 and the Ministry of Economy

  11. ATCA detections of massive molecular gas reservoirs in dusty, high-z radio galaxies

    NASA Astrophysics Data System (ADS)

    Heywood, I.; Contreras, Y.; Smith, D. J. B.; Cooray, A.; Dunne, L.; Gómez, L.; Ibar, E.; Ivison, R. J.; Jarvis, M. J.; Michałowski, M. J.; Riechers, D. A.; Werf, P. van der

    2017-02-01

    Observations using the 7-mm receiver system on the Australia Telescope Compact Array have revealed large reservoirs of molecular gas in two high-redshift radio galaxies: HATLAS J090426.9+015448 (z = 2.37) and HATLAS J140930.4+003803 (z = 2.04). Optically, the targets are very faint, and spectroscopy classifies them as narrow-line radio galaxies. In addition to harbouring an active galactic nucleus the targets share many characteristics of sub-mm galaxies. Far-infrared data from Herschel-Astrophysical Terahertz Large Area Survey suggest high levels of dust (>109 M⊙) and a correspondingly large amount of obscured star formation (∼1000 M⊙ yr-1). The molecular gas is traced via the J = 1 → 0 transition of 12CO, its luminosity implying total H2 masses of (1.7 ± 0.3) × 1011 and (9.5 ± 2.4) × 1010 (αCO/0.8) M⊙ in HATLAS J090426.9+015448 and HATLAS J140930.4+003803, respectively. Both galaxies exhibit molecular line emission over a broad (∼1000 km s-1) velocity range and feature double-peaked profiles. We interpret this as evidence of either a large rotating disc or an on-going merger. Gas depletion time-scales are ∼100 Myr. The 1.4-GHz radio luminosities of our targets place them close to the break in the luminosity function. As such they represent 'typical' z > 2 radio sources, responsible for the bulk of the energy emitted at radio wavelengths from accretion-powered sources at high redshift, and yet they rank amongst the most massive systems in terms of molecular gas and dust content. We also detect 115-GHz rest-frame continuum emission, indicating a very steep high-radio-frequency spectrum, possibly classifying the targets as compact steep spectrum objects.

  12. 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

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

    SciTech Connect

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

    2003-01-28

    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 N{sup 2} gas. Subtask 2.2 conducts experiments with CO{sup 2} foam. Subtask 2.3 develops and applies a simulator for foam processes in field application. Regarding Task 1, several key results are described in this report relating to subtask 1.1. In particular, we show how for slimtube experiments, oil recoveries do not increase significantly with enrichments greater than the MME. For field projects, however, the optimum enrichment required to maximize recovery on a pattern scale may be different from the MME. The optimum enrichment is likely the result of greater mixing in reservoirs than in slimtubes. In addition, 2-D effects such as channeling, gravity tonguing, and crossflow can impact the enrichment selected. We also show the interplay between various mixing mechanisms, enrichment level, and numerical dispersion. The mixing mechanisms examined are mechanical dispersion, gravity crossflow, and viscous crossflow. UTCOMP is used to evaluate the effect of these mechanisms on recovery for different grid refinements, reservoir heterogeneities, injection boundary conditions, relative permeabilities, and numerical weighting methods including higher-order methods. For all simulations, the reservoir fluid used is a twelve-component oil displaced by gases enriched above

  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. 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.

  18. ANR Pipeline Company Experience in secondary liquids recovery resulting from gas storage operations in three Michigan reservoirs

    SciTech Connect

    Nowaczewski, S.F. )

    1994-08-01

    ANR Pipeline Company operates 16 gas storage fields in Michigan, three of which produce significant quantities of secondary hydrocarbon liquid. This discussion reviews the basic geologic framework at Loreed (Reed City oil field) gas storage field and the 30-yr history of gas cycling and secondary oil and gasoline liquids production. The high-density well pattern and extensive data acquisition programs of ANR Pipeline Company contribute to identification of the most poorly drained zones and aid the efficiency and probable maximizing of liquids recovery from Loreed. The performance thus far is compared to prestorage estimates of probable recovery, which have been exceeded. Similarly, geologic frameworks and liquids production histories are presented for the Niagaran reef reservoirs Central Charlton 1 and South Chester 15, with comments as to the efficiency of natural gas cycling as a means of secondary condensate recovery and the use of gas composition as an indication of relative cleanup of native hydrocarbons in the storage-affected area of the reservoir. The degree of porosity/permeability stratification in all three reservoirs is perhaps the dominant factor affecting additional secondary recovery.

  19. Micro and nano-size pores of clay minerals in shale reservoirs: Implication for the accumulation of shale gas

    NASA Astrophysics Data System (ADS)

    Chen, Shangbin; Han, Yufu; Fu, Changqin; Zhang, han; Zhu, Yanming; Zuo, Zhaoxi

    2016-08-01

    A pore is an essential component of shale gas reservoirs. Clay minerals are the adsorption carrier second only to organic matter. This paper uses the organic maturity test, Field-Emission Scanning Electron Microscopy (FE-SEM), and X-ray Diffraction (XRD) to study the structure and effect of clay minerals on storing gas in shales. Results show the depositional environment and organic maturity influence the content and types of clay minerals as well as their structure in the three types of sedimentary facies in China. Clay minerals develop multi-size pores which shrink to micro- and nano-size by close compaction during diagenesis. Micro- and nano-pores can be divided into six types: 1) interlayer, 2) intergranular, 3) pore and fracture in contact with organic matter, 4) pore and fracture in contact with other types of minerals, 5) dissolved and, 6) micro-cracks. The contribution of clay minerals to the presence of pores in shale is evident and the clay plane porosity can even reach 16%, close to the contribution of organic matter. The amount of clay minerals and pores displays a positive correlation. Clay minerals possess a strong adsorption which is affected by moisture and reservoir maturity. Different pore levels of clay minerals are mutually arranged, thus essentially producing distinct reservoir adsorption effects. Understanding the structural characteristics of micro- and nano-pores in clay minerals can provide a tool for the exploration and development of shale gas reservoirs.

  20. 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.

  1. Noble gas composition of subcontinental lithospheric mantle: An extensively degassed reservoir beneath Southern Patagonia

    NASA Astrophysics Data System (ADS)

    Jalowitzki, Tiago; Sumino, Hirochika; Conceição, Rommulo V.; Orihashi, Yuji; Nagao, Keisuke; Bertotto, Gustavo W.; Balbinot, Eduardo; Schilling, Manuel E.; Gervasoni, Fernanda

    2016-09-01

    Patagonia, in the Southern Andes, is one of the few locations where interactions between the oceanic and continental lithosphere can be studied due to subduction of an active spreading ridge beneath the continent. In order to characterize the noble gas composition of Patagonian subcontinental lithospheric mantle (SCLM), we present the first noble gas data alongside new lithophile (Sr-Nd-Pb) isotopic data for mantle xenoliths from Pali-Aike Volcanic Field and Gobernador Gregores, Southern Patagonia. Based on noble gas isotopic compositions, Pali-Aike mantle xenoliths represent intrinsic SCLM with higher (U + Th + K)/(3He, 22Ne, 36Ar) ratios than the mid-ocean ridge basalt (MORB) source. This reservoir shows slightly radiogenic helium (3He/4He = 6.84-6.90 RA), coupled with a strongly nucleogenic neon signature (mantle source 21Ne/22Ne = 0.085-0.094). The 40Ar/36Ar ratios vary from a near-atmospheric ratio of 510 up to 17700, with mantle source 40Ar/36Ar between 31100-6800+9400 and 54000-9600+14200. In addition, the 3He/22Ne ratios for the local SCLM endmember, at 12.03 ± 0.15 to 13.66 ± 0.37, are higher than depleted MORBs, at 3He/22Ne = 8.31-9.75. Although asthenospheric mantle upwelling through the Patagonian slab window would result in a MORB-like metasomatism after collision of the South Chile Ridge with the Chile trench ca. 14 Ma, this mantle reservoir could have remained unhomogenized after rapid passage and northward migration of the Chile Triple Junction. The mantle endmember xenon isotopic ratios of Pali-Aike mantle xenoliths, which is first defined for any SCLM-derived samples, show values indistinguishable from the MORB source (129Xe/132Xe =1.0833-0.0053+0.0216 and 136Xe/132Xe =0.3761-0.0034+0.0246). The noble gas component observed in Gobernador Gregores mantle xenoliths is characterized by isotopic compositions in the MORB range in terms of helium (3He/4He = 7.17-7.37 RA), but with slightly nucleogenic neon (mantle source 21Ne/22Ne = 0.065-0.079). We

  2. Monitoring of a gas reservoir in Western Siberia through SqueeSAR

    NASA Astrophysics Data System (ADS)

    Rucci, Alessio; Ferretti, Alessandro; Fokker, Peter A.; Jager, Johan; Lou, Sten

    2014-05-01

    clearly concentrated in the areas with the most producing wells and therefore where the gas production was assumed to be the largest. The potential of the technology is to use the distribution of the subsidence pattern in combination with the gas production characteristics to better assess the flow properties of the reservoir. These characteristics include the sealing behavior of faults causing reservoir compartments and possible activity of connected aquifers.

  3. 3D Reservoir Modeling of Semutang Gas Field: A lonely Gas field in Chittagong-Tripura Fold Belt, with Integrated Well Log, 2D Seismic Reflectivity and Attributes.

    NASA Astrophysics Data System (ADS)

    Salehin, Z.; Woobaidullah, A. S. M.; Snigdha, S. S.

    2015-12-01

    Bengal Basin with its prolific gas rich province provides needed energy to Bangladesh. Present energy situation demands more Hydrocarbon explorations. Only 'Semutang' is discovered in the high amplitude structures, where rest of are in the gentle to moderate structures of western part of Chittagong-Tripura Fold Belt. But it has some major thrust faults which have strongly breached the reservoir zone. The major objectives of this research are interpretation of gas horizons and faults, then to perform velocity model, structural and property modeling to obtain reservoir properties. It is needed to properly identify the faults and reservoir heterogeneities. 3D modeling is widely used to reveal the subsurface structure in faulted zone where planning and development drilling is major challenge. Thirteen 2D seismic and six well logs have been used to identify six gas bearing horizons and a network of faults and to map the structure at reservoir level. Variance attributes were used to identify faults. Velocity model is performed for domain conversion. Synthetics were prepared from two wells where sonic and density logs are available. Well to seismic tie at reservoir zone shows good match with Direct Hydrocarbon Indicator on seismic section. Vsh, porosity, water saturation and permeability have been calculated and various cross plots among porosity logs have been shown. Structural modeling is used to make zone and layering accordance with minimum sand thickness. Fault model shows the possible fault network, those liable for several dry wells. Facies model have been constrained with Sequential Indicator Simulation method to show the facies distribution along the depth surfaces. Petrophysical models have been prepared with Sequential Gaussian Simulation to estimate petrophysical parameters away from the existing wells to other parts of the field and to observe heterogeneities in reservoir. Average porosity map for each gas zone were constructed. The outcomes of the research

  4. Formation and migration of Natural Gases: gas composition and isotopes as monitors between source, reservoir and seep

    NASA Astrophysics Data System (ADS)

    Schoell, M.; Etiope, G.

    2015-12-01

    Natural gases form in tight source rocks at temperatures between 120ºC up to 200ºC over a time of 40 to 50my depending on the heating rate of the gas kitchen. Inferring from pyrolysis experiments, gases after primary migration, a pressure driven process, are rich in C2+ hydrocarbons (C2 to C5). This is consistent with gas compositions of oil-associated gases such as in the Bakken Shale which occur in immediate vicinity of the source with little migration distances. However, migration of gases along porous rocks over long distances (up to 200km in the case of the Troll field offshore Norway) changes the gas composition drastically as C2+ hydrocarbons tend to be retained/sequestered during migration of gas as case histories from Virginia and the North Sea will demonstrate. Similar "molecular fractionation" is observed between reservoirs and surface seeps. In contrast to gas composition, stable isotopes in gases are, in general, not affected by the migration process suggesting that gas migration is a steady state process. Changes in isotopic composition, from source to reservoir to surface seeps, is often the result of mixing of gases of different origins. Examples from various gas provinces will support this notion. Natural gas basins provide little opportunity of tracking and identifying gas phase separation. Future research on experimental phase separation and monitoring of gas composition and gas ratio changes e.g. various C2+ compound ratios over C1 or isomer ratios such as iso/n ratios in butane and pentane may be an avenue to develop tracers for phase separation that could possibly be applied to natural systems of retrograde natural condensate fields.

  5. Evolution of overpressured and underpressured oil and gas reservoirs, Anadarko Basin of Oklahoma, Texas, and Kansas

    USGS Publications Warehouse

    Nelson, Phillip H.; Gianoutsos, Nicholas J.

    2011-01-01

    Departures of resistivity logs from a normal compaction gradient indicate that overpressure previously extended north of the present-day overpressured zone. These indicators of paleopressure, which are strongest in the deep basin, are mapped to the Kansas-Oklahoma border in shales of Desmoinesian age. The broad area of paleopressure has contracted to the deep basin, and today the overpressured deep basin, as determined from drillstem tests, is bounded on the north by strata with near normal pressures (hydrostatic), grading to the northwest to pressures that are less than hydrostatic (underpressured). Thus the pressure regime in the northwest portion of the Anadarko Basin has evolved from paleo-overpressure to present-day underpressure. Using pressure data from drillstem tests, we constructed cross sections and potentiometric maps that illustrate the extent and nature of present-day underpressuring. Downcutting and exposure of Lower Permian and Pennsylvanian strata along, and east of, the Nemaha fault zone in central Oklahoma form the discharge locus where pressure reaches near atmospheric. From east to west, hydraulic head increases by several hundred feet in each rock formation, whereas elevation increases by thousands of feet. The resulting underpressuring of the aquifer-supported oil and gas fields, which also increases from east to west, is a consequence of the vertical separation between surface elevation and hydraulic head. A 1,000-ft thick cap of Permian evaporites and shales isolates the underlying strata from the surface, preventing re-establishment of a normal hydrostatic gradient. Thus, the present-day pressure regime of oil and gas reservoirs, overpressured in the deep basin and underpressured on the northwest flank of the basin, is the result of two distinct geologic events-rapid burial and uplift/erosion-widely separated in time.

  6. 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.

  7. The application of a new second-generation highstrength proppant in tight gas reservoirs

    SciTech Connect

    Callanan, M.J.; Cipolla, C.L.; Lewis, P.E.

    1983-03-01

    An analysis is made to illustrate the effectiveness of a new second generation high strength low density proppant as compared to that of sintered bauxite and Ottawa sand in a variety of applications. This is accomplished through the use of a reservoir simulator and a fracture design program. Gas producing formations are simulated which exhibit permeabilities between 0.001 md and 0.1 md and closure stresses up to 9500 psi. In these simulations the second generation proppant and sintered bauxite yield essentially identical production histories. However, the second generation proppant shows far superior performance to Ottawa sand in all applications. Also shown are cases revealing that tail-ins with the second generation proppant can yield a higher return on investment than pumping all high strength proppant. The simulations reveal the importance of non-Darcy flow and conductivity damage considerations in proppant selection. It is shown that these two factors have much less of an effect on the performance of the second generation proppant than on that of sand. With all of this considered the second generation proppant should prove to have a substantial economic advantage over both sintered bauxite and sand in a variety of applications.

  8. 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.

  9. A MASSIVE MOLECULAR GAS RESERVOIR IN THE z = 5.3 SUBMILLIMETER GALAXY AzTEC-3

    SciTech Connect

    Riechers, Dominik A.; Scoville, Nicholas Z.; Capak, Peter L.; Yan, Lin; Carilli, Christopher L.; Cox, Pierre; Neri, Roberto; Schinnerer, Eva; Bertoldi, Frank

    2010-09-10

    We report the detection of CO J = 2{yields}1, 5{yields}4, and 6{yields}5 emission in the highest-redshift submillimeter galaxy (SMG) AzTEC-3 at z = 5.298, using the Expanded Very Large Array and the Plateau de Bure Interferometer. These observations ultimately confirm the redshift, making AzTEC-3 the most submillimeter-luminous galaxy in a massive z {approx_equal} 5.3 protocluster structure in the COSMOS field. The strength of the CO line emission reveals a large molecular gas reservoir with a mass of 5.3 x 10{sup 10}({alpha}{sub CO}/0.8) M {sub sun}, which can maintain the intense 1800 M {sub sun} yr{sup -1} starburst in this system for at least 30 Myr, increasing the stellar mass by up to a factor of six in the process. This gas mass is comparable to 'typical' z {approx} 2 SMGs and constitutes {approx_gt}80% of the baryonic mass (gas+stars) and 30%-80% of the total (dynamical) mass in this galaxy. The molecular gas reservoir has a radius of <4 kpc and likely consists of a 'diffuse', low-excitation component, containing (at least) 1/3 of the gas mass (depending on the relative conversion factor {alpha}{sub CO}), and a 'dense', high-excitation component, containing {approx}2/3 of the mass. The likely presence of a substantial diffuse component besides highly excited gas suggests different properties between the star-forming environments in z > 4 SMGs and z > 4 quasar host galaxies, which perhaps trace different evolutionary stages. The discovery of a massive, metal-enriched gas reservoir in an SMG at the heart of a large z = 5.3 protocluster considerably enhances our understanding of early massive galaxy formation, pushing back to a cosmic epoch where the universe was less than 1/12 of its present age.

  10. Soil-air greenhouse gas fluxes influenced by farming practices in reservoir drawdown area: A case at the Three Gorges Reservoir in China.

    PubMed

    Li, Zhe; Zhang, Zengyu; Lin, Chuxue; Chen, Yongbo; Wen, Anbang; Fang, Fang

    2016-10-01

    The Three Gorges Reservoir (TGR) in China has large water level variations, creating about 393 km(2) of drawdown area seasonally. Farming practices in drawdown area during the low water level period is common in the TGR. Field experiments on soil-air greenhouse gas (GHG) emissions in fallow grassland, peanut field and corn field in reservoir drawdown area at Lijiaba Bay of the Pengxi River, a tributary of the Yangtze River in the TGR were carried out from March through September 2011. Experimental fields in drawdown area had the same land use history. They were adjacent to each other horizontally at a narrow range of elevation i.e. 167-169 m, which assured that they had the same duration of reservoir inundation. Unflooded grassland with the same land-use history was selected as control for study. Results showed that mean value of soil CO2 emissions in drawdown area was 10.38 ± 0.97 mmol m(-2) h(-1). The corresponding CH4 fluxes and N2O fluxes were -8.61 ± 2.15 μmol m(-2) h(-1) and 3.42 ± 0.80 μmol m(-2) h(-1). Significant differences and monthly variations among land uses in treatments of drawdown area and unflooded grassland were evident. These were impacted by the change in soil physiochemical properties which were alerted by reservoir operation and farming. Particularly, N-fertilization in corn field stimulated N2O emissions from March to May. In terms of global warming potentials (GWP), corn field in drawdown area had the maximum GWP mainly due to N-fertilization. Gross GWP in peanut field in drawdown area was about 7% lower than that in fallow grassland. Compared to unflooded grassland, reservoir operation created positive net effect on GHG emissions and GWPs in drawdown area. However, selection of crop species, e.g. peanut, and best practices in farming, e.g. prohibiting N-fertilization, could potentially mitigate GWPs in drawdown area. In the net GHG emissions evaluation in the TGR, farming practices in the drawdown area shall be taken

  11. 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.

  12. Characterization of oil and gas reservoir heterogeneity. Technical progress report, April 1, 1992--June 30, 1992

    SciTech Connect

    Sharma, G.D.

    1992-10-01

    The ultimate objective of this cooperative research project is to characterize Alaskan petroleum reservoirs in terms of their reserves, physical and chemical properties, geologic configuration in relation to lithofacies and structure, and development potential. The project has two tasks: Task 1 is a geological description of the reservoirs including petrophysical properties, i.e., porosity, permeability, permeability variation, formation depth, temperature, and net pay, facies changes and reservoir structures as drawn from cores, well logs, and other geological data. Task 2 is reservoir fluid characterization-determination of physical properties of reservoir fluids including density, viscosity, phase distributions and composition as well as petrogenesis-source rock identification; and the study of asphaltene precipitation for Alaskan crude oils. Results are discussed.

  13. Characterization of oil and gas reservoir heterogeneity. Technical progress report, January 1, 1992--March 31, 1992

    SciTech Connect

    Sharma, G.D.

    1992-08-01

    The ultimate objective of this cooperative research project is to characterize Alaskan petroleum reservoirs in terms of their reserves, physical and chemical properties, geologic configuration in relation to lithofacies and structure, and development potential. The project has two tasks: Task 1 is a geological description of the reservoirs including petrophysical properties, i.e., porosity, permeability, permeability variation, formation depth, temperature, and net pay, facies changes and reservoir structures as drawn from cores, well logs, and other geological data. Task 2 is reservoir fluid characterization -- determination of physical properties of reservoir fluids including density, viscosity, phase distributions and composition as well as petrogenesis -- source rock identification; and the study of asphaltene precipitation for Alaskan crude oils.

  14. Characterization of oil and gas reservoir heterogeneity. Technical progress report, July 1, 1992--September 30, 1992

    SciTech Connect

    Sharma, G.D.

    1992-12-01

    The ultimate oojective of this cooperative research project is to characterize Alaskan petroleum reservoirs in terms of their reserves, physical and chemical properties, geologic configuration in relation to lithofacies and structure, and development potential. The project has two tasks: Task 1 is a geological description of the reservoirs including petrophysical properties, i.e., porosity, permeability, permeability variation, formation depth, temperature, and net pay, facies changes and reservoir structures as drawn from cores, well logs, and other geological data. Task 2 is reservoir fluid characterization--determination of physical properties of reservoir fluids including density, viscosity, phase distributions and composition as well as petrogenesis--source rock identification; and the study of asphaltene precipitation for Alaskan crude oils. This report presents a summary of technical progress of the well log analysis of Kuparuk Field, Northslope, Alaska.

  15. Characterization of oil and gas reservoir heterogeneity. [Quarterly report], January 1, 1993--March 31, 1993

    SciTech Connect

    Sharma, G.D.

    1993-04-01

    The ultimate objective of this cooperative research project is to characterize Alaskan petroleum reservoirs in terms of their reserves, physical and chemical properties, geologic configuration in relation to lithofacies and structure, and development potential. The project has two tasks: Task I is a geological description of the reservoirs including petrophysical properties, i.e., porosity, permeability, permeability variation, formation depth, temperature, and net pay, facies changes and reservoir structures as drawn from cores, well logs, and other geological data. Task 2 is reservoir fluid characterization--determination of physical properties of reservoir fluids including density, viscosity, phase distributions and composition as well as petrogenesis--source rock identification; and the study of asphaltene precipitation for Alaskan crude oils.

  16. 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.

  17. Modeling of fault activation and seismicity by injection directly into a fault zone associated with hydraulic fracturing of shale-gas reservoirs

    EPA Pesticide Factsheets

    LBNL, in consultation with the EPA, expanded upon a previous study by injecting directly into a 3D representation of a hypothetical fault zone located in the geologic units between the shale-gas reservoir and the drinking water aquifer.

  18. 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.

  19. 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.

  20. 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

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

    SciTech Connect

    Franklin M. Orr, Jr.

    2003-09-30

    This report outlines progress in the first quarter of the extension of the DOE project ''High Resolution Prediction of Gas Injection Process Performance for Heterogeneous Reservoirs''. This report presents experimental results that demonstrate combined scaling effects of viscous, capillary, and gravity crossflow mechanisms that apply to the situations in which streamline models are used. We designed and ran a series of experiments to investigate combined effects of capillary, viscous, and gravity forces on displacement efficiency in layered systems. Analog liquids (isooctane, isopropanol, and water) were employed to control scaling parameters by changing interfacial tension (IFT), flow rate, and density difference. The porous medium was a two-dimensional (2-D) 2-layered glass bead model with a permeability ratio of about 1:4. In order to analyze the combined effect of only capillary and viscous forces, gravity effects were eliminated by changing the orientation of the glass bead model. We employed a commercial simulator, Eclipse100 to calculate displacement behavior for comparison with the experimental data. Experimental results with minimized gravity effects show that the IFT and flow rate determine how capillary and viscous forces affect behavior of displacement. The limiting behavior for scaling groups for two-phase displacement was verified by experimental results. Analysis of the 2-D images indicates that displacements having a capillary-viscous equilibrium give the best sweep efficiency. Experimental results with gravity effects, but with low IFT fluid systems show that slow displacements produce larger area affected by crossflow. This, in turn, enhances sweep efficiency. The simulation results represent the experimental data well, except for the situations where capillary forces dominate the displacement.

  2. 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

  3. Geologic, technical, and economic sensitivity analysis in support of the GRI (Gas Research Institute) Tight Gas Reservoirs Project area. Annual report, November 1984-October 1985

    SciTech Connect

    Brashear, J.P.; Haas, M.; Morra, F.

    1985-11-01

    During 1984-1985, Lewin and Associates, Inc., used the Tight Gas Analysis System (TGAS) as a planning and assessment tool for GRI. During this period TGAS was used to support the GRI Tight Gas Reservoirs Program: (1) evaluation of the benefits of the entire program and its subcomponents; (2) detailed analysis of a single formation (the Travis Peak); and (3) fine grain assessment of the role of information in the decision to drill, develop and produce a tight-gas prospect; (4) assistance in selecting RandD tasks that were most likely to achieve program objectives most cost-effectively and in developing a project-management structure. RandD planning assistance resulted in more quantifiable program objectives and developed a computerized version of several program components to test its usefulness as a management tool. The program analysis demonstrated that RandD in reservoir diagnostics and stimulation technology would make it possible to achieve significant reductions in the cost of gas while adding sizable new quantities of gas to supply. The work has yielded methodology, data and software that are applicable to industry as a whole in addition to serving GRI's needs.

  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. Pingos, craters and methane-leaking seafloor in the central Barents Sea: signals of decomposing gas hydrate releasing gas from deeper hydrocarbon reservoirs?

    NASA Astrophysics Data System (ADS)

    Andreassen, K.; Plaza-Faverola, A. A.; Winsborrow, M.; Deryabin, A.; Mattingsdal, R.; Vadakkepuliyambatta, S.; Serov, P.; Mienert, J.; Bünz, S.

    2015-12-01

    A cluster of large craters and mounds appear on the gas-leaking sea floor in the central Barents Sea around the upper limit for methane hydrate stability, covering over 360 km2. We use multibeam bathymetry, single-beam echo sounder and high-resolution seismic data to reveal the detailed geomorphology and internal structure of craters and mounds, map the distribution gas in the water and to unravel the subsurface plumbing system and sources of gas leakage. Distinct morphologies and geophysical signatures of mounds and craters are inferred to reflect different development stages of shallow gas hydrate formation and dissociation. Over 600 gas flares extending from the sea floor into the water are mapped, many of these from the seafloor mounds and craters, but most from their flanks and surroundings. Analysis of geophysical data link gas flares in the water, craters and mounds to seismic indications of gas advection from deeper hydrocarbon reservoirs along faults and fractures. We present a conceptual model for formation of mounds, craters and gas leakage of the area.

  6. Detailed evaluation of gas hydrate reservoir properties using JAPEX/JNOC/GSC Mallik 2L-38 gas hydrate research well downhole well-log displays

    USGS Publications Warehouse

    Collett, T.S.

    1999-01-01

    The JAPEX/JNOC/GSC Mallik 2L-38 gas hydrate research well project was designed to investigate the occurrence of in situ natural gas hydrate in the Mallik area of the Mackenzie Delta of Canada. Because gas hydrate is unstable at surface pressure and temperature conditions, a major emphasis was placed on the downhole logging program to determine the in situ physical properties of the gas-hydrate-bearing sediments. Downhole logging tool strings deployed in the Mallik 2L-38 well included the Schlumberger Platform Express with a high resolution laterolog, Array Induction Imager Tool, Dipole Shear Sonic Imager, and a Fullbore Formation Microlmager. The downhole log data obtained from the log- and core-inferred gas-hydrate-bearing sedimentary interval (897.25-1109.5 m log depth) in the Mallik 2L-38 well is depicted in a series of well displays. Also shown are numerous reservoir parameters, including gas hydrate saturation and sediment porosity log traces, calculated from available downhole well-log and core data. The gas hydrate accumulation delineated by the Mallik 2L-38 well has been determined to contain as much as 4.15109 m3 of gas in the 1 km2 area surrounding the drill site.

  7. Greenhouse gas emissions from reservoir water surfaces: A new global synthesis

    EPA Science Inventory

    Collectively, reservoirs created by dams are thought to be an important source ofgreenhouse gases (GHGs) to the atmosphere. So far, efforts to quantify, model, andmanage these emissions have been limited by data availability and inconsistenciesin methodological approach. Here we ...

  8. 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.

  9. 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

  10. 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.

  11. Prolific Overton field gas reservoirs within large transverse oolite shoals, Upper Jurassic Haynesville, Eastern Margin East Texas basin

    SciTech Connect

    Glynn, W.G.; Covington, T.E.; Lighty, R.G.; Ahr, W.M.

    1985-02-01

    Late Triassic rifting along a northeast-southwest spreading center in east Texas resulted in basement highs along the eastern margin of the East Texas basin that became sites of extensive ooid shoal deposition during Late Jurassic time. Reservoirs within oolite facies at Overton field contain over 1 tcf of natural gas. These large shoals, each approximately 15 mi (24 km) long and 3 mi (4.8 km) wide, trend north-south as a group and northeast-southwest individually. They are oblique to the basin margin but parallel with Jurassic diffracted tidal currents within the East Texas embayment. Modern Bahamian ooid shoals of similar size, trend, and depositional setting occur at the terminus of the deep Tongue-Of-The-Ocean platform reentrant. Overton field reservoirs are in ooid grainstone shoal facies and in transitional shoal margins of skeletal-oolitic-peloidal grainstones and packstones. Adjacent nonreservoir facies are peloidal-skeletal-siliciclastic wackestones and mudstones. Early diagenesis of grainstone reservoir facies included meteoric dissolution and grain stabilization, resulting in abundant chalky intraparticle porosity and equant and bladed calcite cements filling interparticle porosity. Subsequent burial diagenesis resulted in intense solution compaction and coarse equant calcite and saddle crystal dolomite that occluded remaining interparticle porosity. Whole-rock trace element analysis indicates greatest diagenetic flushing (less magnesium, strontium) in porous zones. Stable isotopes for grains and cements show strong overprint of later burial diagenesis, with greater depletion of delta/sup 18/O in reservoir facies. However, hydrocarbons were emplaced prior to late cementation, and unlike other Jurassic Gulf Coast reservoirs, deep burial diagenesis provided no late-stage formation of porosity.

  12. Comparative modeling of fault reactivation and seismicity in geologic carbon storage and shale-gas reservoir stimulation

    NASA Astrophysics Data System (ADS)

    Rutqvist, Jonny; Rinaldi, Antonio; Cappa, Frederic

    2016-04-01

    The potential for fault reactivation and induced seismicity are issues of concern related to both geologic CO2 sequestration and stimulation of shale-gas reservoirs. It is well known that underground injection may cause induced seismicity depending on site-specific conditions, such a stress and rock properties and injection parameters. To date no sizeable seismic event that could be felt by the local population has been documented associated with CO2 sequestration activities. In the case of shale-gas fracturing, only a few cases of felt seismicity have been documented out of hundreds of thousands of hydraulic fracturing stimulation stages. In this paper we summarize and review numerical simulations of injection-induced fault reactivation and induced seismicity associated with both underground CO2 injection and hydraulic fracturing of shale-gas reservoirs. The simulations were conducted with TOUGH-FLAC, a simulator for coupled multiphase flow and geomechanical modeling. In this case we employed both 2D and 3D models with an explicit representation of a fault. A strain softening Mohr-Coulomb model was used to model a slip-weakening fault slip behavior, enabling modeling of sudden slip that was interpreted as a seismic event, with a moment magnitude evaluated using formulas from seismology. In the case of CO2 sequestration, injection rates corresponding to expected industrial scale CO2 storage operations were used, raising the reservoir pressure until the fault was reactivated. For the assumed model settings, it took a few months of continuous injection to increase the reservoir pressure sufficiently to cause the fault to reactivate. In the case of shale-gas fracturing we considered that the injection fluid during one typical 3-hour fracturing stage was channelized into a fault along with the hydraulic fracturing process. Overall, the analysis shows that while the CO2 geologic sequestration in deep sedimentary formations are capable of producing notable events (e

  13. 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.

  14. 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.

  15. 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.

  16. 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.

  17. 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

  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

    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

  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

    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

  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

    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

  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

    2004-05-01

    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

  2. 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

  3. Synthesis of fluorinated nano-silica and its application in wettability alteration near-wellbore region in gas condensate reservoirs

    NASA Astrophysics Data System (ADS)

    Mousavi, M. A.; Hassanajili, Sh.; Rahimpour, M. R.

    2013-05-01

    Fluorinated silica nanoparticles were prepared to alter rock wettability near-wellbore region in gas condensate reservoirs. Hence fluorinated silica nanoparticles with average diameter of about 80 nm were prepared and used to alter limestone core wettability from highly liquid-wet to intermediate gas-wet state. Water and n-decane contact angles for rock were measured before and after treatment. The contact angle measured 147° for water and 61° for n-decane on the core surface. The rock surface could not support the formation of any water or n-decane droplets before treatment. The functionalized fluorinated silica nanoparticles have been confirmed by the Csbnd F bond along with Sisbnd Osbnd Si bond as analyzed by FT-IR. The elemental composition of treated limestone core surface was determined using energy dispersive X-ray spectroscopy analyses. The final evaluation of the fluorinated nanosilica treatment in terms of its effectiveness was measured by core flood experimental tests.

  4. 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

  5. Integrated exploration strategy for locating areas capable of high gas rate cavity completion in coalbed methane reservoirs

    SciTech Connect

    Klawitter, A.L.; Hoak, T.E.; Decker, A.D.

    1995-10-01

    In 1993, the San Juan Basin accounted for approximately 605 Bcf of the 740 Bcf of all coalbed gas produced in the United States. The San Juan {open_quotes}cavitation fairway{close_quotes} in which production occurs in open-hole cavity completions, is responsible for over 60% of all U.S. coalbed methane production. Perhaps most striking is the fact that over 17,000 wells had penetrated the Fruitland formation in the San Juan Basin prior to recognition of the coalbed methan potential. To understand the dynamic cavity fairway reservoir in the San Juan Basin, an exploration rationale for coalbed methan was developed that permits a sequential reduction in total basin exploration area based on four primary exploration criteria. One of the most significant criterion is the existence of thick, thermally mature, friable coals. A second criterion is the existence of fully gas-charged coals. Evaluation of this criterion requires reservoir geochemical data to delineate zones of meteoric influx where breaching has occurred. A third criterion is the presence of adequate reservoir permeability. Natural fracturing in coals is due to cleating and tectonic processes. Because of the general relationship between coal cleating and coal rank, coal cleating intensity can be estimated by analysis of regional coal rank maps. The final criterion is determining whether natural fractures are open or closed. To make this determination, remote sensing imagery interpretation is supported by ancillary data compiled from regional tectonic studies. Application of these four criteria to the San Juan Basin in a heuristic, stepwise process resulted in an overall 94% reduction in total basin exploration area. Application of the first criterion reduced the total basin exploration area by 80%. Application of the second criterion further winnows this area by an addition 9%. Application of the third criterion reduces the exploration area to 6% of the total original exploration area.

  6. 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.

  7. 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.

  8. 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

  9. 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.

  10. Nurturing the geology-reservoir engineering team: Vital for efficient oil and gas recovery

    SciTech Connect

    Sessions, K.P.; Lehman, D.H. )

    1990-05-01

    Of an estimated 482 billion bbl (76.6 Gm{sup 3}) of in-place oil discovered in the US, 158 billion (25.1 Gm{sup 3}) can be recovered with existing technology and economic conditions. The cost-effective recovery through infill drilling and enhanced oil recovery methods to recover any portion of the remaining 323 billion bbl (51.4 Gm3) will require a thorough understanding of reservoirs and the close cooperation of production geologists and reservoir engineers. This paper presents the concept of increased interaction between geologists and reservoir engineers through multifunctional teams and cross-training between the disciplines. A discussion of several factors supporting this concept is covered, including educational background, technical manpower trends, employee development, and job satisfaction. There are several ways from an organizational standpoint to achieve this cross-training, with or without a formal change in job assignment. This paper outlines three approaches, including case histories where each of the approaches has been implemented and the resulting benefits.

  11. Naturally fractured tight gas reservoir detection optimization. Quarterly report, January--March 1996

    SciTech Connect

    1996-04-01

    This progress report covers field performance test plan and three- dimensional basins simulator. The southern portion of the Rulison Field was originally selected as the location for the seismic program. Due to permitting problems the survey was unable to go forward. The northern Rulison Field has been modeled to determine suitability for the seismic program. The survey has been located over an area that contains the best producing, most intensively fractured wells and the worst, least fractured wells. Western Geophysical surveyed in the 564 vibrator points and 996 receiver stations. Maps displaying the survey design and modeled offset ranges can be found in Appendix A. The seismic acquisition crew is scheduled to arrive on location by April 7th. The overall development of the fracture prediction simulator has led to new insights into the nature of fractured reservoirs. In particular, the investigators have placed them within the context of recent idea on basin compartments. These concepts an their overall view of the physico-chemical dynamics of fractured reservoir creation are summarized in the report included as Appendix B entitled ``Prediction of Fractured Reservoir Location and Characteristics: A Basin Modeling Approach.`` The full three dimensional, multi-process basin simulator, CIRF.B, is operational and is being tested.

  12. 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.

  13. 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.

  14. 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.

  15. 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

  16. Large molecular gas reservoirs in ancestors of Milky Way-mass galaxies nine billion years ago

    NASA Astrophysics Data System (ADS)

    Papovich, C.; Labbé, I.; Glazebrook, K.; Quadri, R.; Bekiaris, G.; Dickinson, M.; Finkelstein, S. L.; Fisher, D.; Inami, H.; Livermore, R. C.; Spitler, L.; Straatman, C.; Tran, K.-V.

    2016-12-01

    The gas accretion and star formation histories of galaxies like the Milky Way remain an outstanding problem in astrophysics 1,2 . Observations show that 8 billion years ago, the progenitors to Milky Way-mass galaxies were forming stars 30 times faster than today and were predicted to be rich in molecular gas 3 , in contrast to the low present-day gas fractions (<10%) 4-6 . Here we show the detection of molecular gas from the CO (J = 3-2) emission (rest-frame 345.8 GHz) in galaxies at redshifts z = 1.2-1.3, selected to have the stellar mass and star formation rate of the progenitors of today's Milky Way-mass galaxies. The CO emission reveals large molecular gas masses, comparable to or exceeding the galaxy stellar masses, and implying that most of the baryons are in cold gas, not stars. The total luminosities of the galaxies from star formation and CO luminosities yield long gas consumption timescales. Compared to local spiral galaxies, the star formation efficiency, estimated from the ratio of total infrared luminosity (L IR) to CO emission, has remained nearly constant since redshift z = 1.2, despite the order of magnitude decrease in gas fraction, consistent with the results for other galaxies at this epoch 7-10 . Therefore, the physical processes that determine the rate at which gas cools to form stars in distant galaxies appear to be similar to that in local galaxies.

  17. 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.

  18. Geologic, geochemical, and geographic controls on NORM in produced water from Texas oil, gas, and geothermal reservoirs. Final report

    SciTech Connect

    Fisher, R.

    1995-08-01

    Water from Texas oil, gas, and geothermal wells contains natural radioactivity that ranges from several hundred to several thousand Picocuries per liter (pCi/L). This natural radioactivity in produced fluids and the scale that forms in producing and processing equipment can lead to increased concerns for worker safety and additional costs for handling and disposing of water and scale. Naturally occurring radioactive materials (NORM) in oil and gas operations are mainly caused by concentrations of radium-226 ({sup 226}Ra) and radium-228 ({sup 228}Ra), daughter products of uranium-238 ({sup 238}U) and thorium-232 ({sup 232}Th), respectively, in barite scale. We examined (1) the geographic distribution of high NORM levels in oil-producing and gas-processing equipment, (2) geologic controls on uranium (U), thorium (Th), and radium (Ra) in sedimentary basins and reservoirs, (3) mineralogy of NORM scale, (4) chemical variability and potential to form barite scale in Texas formation waters, (5) Ra activity in Texas formation waters, and (6) geochemical controls on Ra isotopes in formation water and barite scale to explore natural controls on radioactivity. Our approach combined extensive compilations of published data, collection and analyses of new water samples and scale material, and geochemical modeling of scale Precipitation and Ra incorporation in barite.

  19. 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.

  20. A Combined Micro-CT Imaging/Microfluidic Approach for Understating Methane Recovery in Coal Seam Gas Reservoirs

    NASA Astrophysics Data System (ADS)

    Mostaghimi, P.; Armstrong, R. T.; Gerami, A.; Lamei Ramandi, H.; Ebrahimi Warkiani, M.

    2015-12-01

    Coal seam methane is a form of natural gas stored in coal beds and is one of the most important unconventional resources of energy. The flow and transport in coal beds occur in a well-developed system of natural fractures that are also known as cleats. We use micro-Computed Tomography (CT) imaging at both dry and wet conditions to resolve the cleats below the resolution of the image. Scanning Electron Microscopy (SEM) is used for calibration of micro-CT data. Using soft lithography technique, the cleat system is duplicated on a silicon mould. We fabricate a microfluidic chip using Polydimethylsiloxane (PDMS) to study both imbibition and drainage in generated coal structures for understating gas and water transport in coal seam reservoirs. First, we use simple patterns observed on coal images to analyse the effects of wettability, cleat size and distribution on flow behaviour. Then, we study transport in a coal by injecting both distilled water and decane with a rate of 1 microliter/ min into the fabricated cleat structure (Figure 1), initially saturated with air. We repeat the experiment for different contact angles by plasma treating the microfluidic chip, and results show significant effects of wettability on the displacement efficiency. The breakthrough time in the imbibition setup is significantly longer than in the drainage. Using rapid video capturing, and high resolution microscopy, we measure the saturation of displacing fluid with respect to time. By measuring gas and liquid recovery in the outlet at different saturation, we predict relative permeability of coal. This work has important applications for optimising gas recovery and our results can serve as a benchmark in the verification of multiphase numerical models used in coal seam gas industry.

  1. 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...

  2. 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.

  3. Petrophysical Characterization and Reservoir Simulator for Methane Gas Production from Gulf of Mexico Hydrates

    SciTech Connect

    Kishore Mohanty; Bill Cook; Mustafa Hakimuddin; Ramanan Pitchumani; Damiola Ogunlana; Jon Burger; John Shillinglaw

    2006-06-30

    Gas hydrates are crystalline, ice-like compounds of gas and water molecules that are formed under certain thermodynamic conditions. Hydrate deposits occur naturally within ocean sediments just below the sea floor at temperatures and pressures existing below about 500 meters water depth. Gas hydrate is also stable in conjunction with the permafrost in the Arctic. Most marine gas hydrate is formed of microbially generated gas. It binds huge amounts of methane into the sediments. Estimates of the amounts of methane sequestered in gas hydrates worldwide are speculative and range from about 100,000 to 270,000,000 trillion cubic feet (modified from Kvenvolden, 1993). Gas hydrate is one of the fossil fuel resources that is yet untapped, but may play a major role in meeting the energy challenge of this century. In this project novel techniques were developed to form and dissociate methane hydrates in porous media, to measure acoustic properties and CT properties during hydrate dissociation in the presence of a porous medium. Hydrate depressurization experiments in cores were simulated with the use of TOUGHFx/HYDRATE simulator. Input/output software was developed to simulate variable pressure boundary condition and improve the ease of use of the simulator. A series of simulations needed to be run to mimic the variable pressure condition at the production well. The experiments can be matched qualitatively by the hydrate simulator. The temperature of the core falls during hydrate dissociation; the temperature drop is higher if the fluid withdrawal rate is higher. The pressure and temperature gradients are small within the core. The sodium iodide concentration affects the dissociation pressure and rate. This procedure and data will be useful in designing future hydrate studies.

  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

    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

  5. 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.

  6. 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.

  7. Well Integrity for Natural Gas Storage in Depleted Reservoirs and Aquifers

    SciTech Connect

    Freifeld, Barry M.; Oldenburg, Curtis M.; Jordan, Preston; Pan, Lehua; Perfect, Scott; Morris, Joseph; White, Joshua; Bauer, Stephen; Blankenship, Douglas; Roberts, Barry; Bromhal, Grant; Glosser, Deborah; Wyatt, Douglas; Rose, Kelly

    2016-09-02

    Introduction Motivation The 2015-2016 Aliso Canyon/Porter Ranch natural gas well blowout emitted approximately 100,000 tonnes of natural gas (mostly methane, CH4) over four months. The blowout impacted thousands of nearby residents, who were displaced from their homes. The high visibility of the event has led to increased scrutiny of the safety of natural gas storage at the Aliso Canyon facility, as well as broader concern for natural gas storage integrity throughout the country. Federal Review of Well Integrity In April of 2016, the U.S. Department of Energy (DOE), in conjunction with the U.S. Department of Transportation (DOT) through the Pipeline and Hazardous Materials Safety Administration (PHMSA), announced the formation of a new Interagency Task Force on Natural Gas Storage Safety. The Task Force enlisted a group of scientists and engineers at the DOE National Laboratories to review the state of well integrity in natural gas storage in the U.S. The overarching objective of the review is to gather, analyze, catalogue, and disseminate information and findings that can lead to improved natural gas storage safety and security and thus reduce the risk of future events. The “Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016’’ or the ‘‘PIPES Act of 2016,’’which was signed into law on June 22, 2016, created an Aliso Canyon Natural Gas Leak Task Force led by the Secretary of Energy and consisting of representatives from the DOT, Environmental Protection Agency (EPA), Department of Health and Human Services, Federal Energy Regulatory Commission (FERC), Department of Commerce and the Department of Interior. The Task Force was asked to perform an analysis of the Aliso Canyon event and make recommendations on preventing similar incidents in the future. The PIPES Act also required that DOT/PHMSA promulgate minimum safety standards for underground storage that would take effect within two years. Background on the DOE

  8. Development of hydraulic fracture network propagation model in shale gas reservoirs: 2D, single-phase and 3D, multi-phase model development, parametric studies, and verification

    NASA Astrophysics Data System (ADS)

    Ahn, Chong Hyun

    The most effective method for stimulating shale gas reservoirs is a massive hydraulic fracture treatment. Recent analysis using microseismic technology have shown that complex fracture networks are commonly created in the field as a result of the stimulation of shale wells. The interaction between pre-existing natural fractures and the propagating hydraulic fracture is a critical factor affecting the created complex fracture network; however, many existing numerical models simulate only planar hydraulic fractures without considering the pre-existing fractures in the formation. The shale formations already contain a large number of natural fractures, so an accurate fracture propagation model needs to be developed to optimize the fracturing process. In this research, we first characterized the mechanics of hydraulic fracturing and fluid flow in the shale gas reservoir. Then, a 2D, single-phase numerical model and a 3D, 2-phase coupled model were developed, which integrate dynamic fracture propagation, interactions between hydraulic fractures and pre-existing natural fractures, fracture fluid leakoff, and fluid flow in a petroleum reservoir. By using the developed model, we conducted parametric studies to quantify the effects of treatment rate, treatment size, fracture fluid viscosity, differential horizontal stress, natural fracture spacing, fracture toughness, matrix permeability, and proppant size on the geometry of the hydraulic fracture network. The findings elucidate important trends in hydraulic fracturing of shale reservoirs that are useful in improving the design of treatments for specific reservoir settings.

  9. 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.

  10. 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.; Boulanger, Albert; Bagdonas, Edward P.; Xu, Liqing; He, Wei

    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.

  11. The Iġnik Sikumi Field Experiment, Alaska North Slope: Design, operations, and implications for CO2−CH4 exchange in gas hydrate reservoirs

    USGS Publications Warehouse

    Boswell, Ray; Schoderbek, David; Collett, Timothy S.; Ohtsuki, Satoshi; White, Mark; Anderson, Brian J.

    2017-01-01

    The Iġnik Sikumi Gas Hydrate Exchange Field Experiment was conducted by ConocoPhillips in partnership with the U.S. Department of Energy, the Japan Oil, Gas and Metals National Corporation, and the U.S. Geological Survey within the Prudhoe Bay Unit on the Alaska North Slope during 2011 and 2012. The primary goals of the program were to (1) determine the feasibility of gas injection into hydrate-bearing sand reservoirs and (2) observe reservoir response upon subsequent flowback in order to assess the potential for CO2 exchange for CH4 in naturally occurring gas hydrate reservoirs. Initial modeling determined that no feasible means of injection of pure CO2 was likely, given the presence of free water in the reservoir. Laboratory and numerical modeling studies indicated that the injection of a mixture of CO2 and N2 offered the best potential for gas injection and exchange. The test featured the following primary operational phases: (1) injection of a gaseous phase mixture of CO2, N2, and chemical tracers; (2) flowback conducted at downhole pressures above the stability threshold for native CH4 hydrate; and (3) an extended (30-days) flowback at pressures near, and then below, the stability threshold of native CH4 hydrate. The test findings indicate that the formation of a range of mixed-gas hydrates resulted in a net exchange of CO2 for CH4 in the reservoir, although the complexity of the subsurface environment renders the nature, extent, and efficiency of the exchange reaction uncertain. The next steps in the evaluation of exchange technology should feature multiple well applications; however, such field test programs will require extensive preparatory experimental and numerical modeling studies and will likely be a secondary priority to further field testing of production through depressurization. Additional insights gained from the field program include the following: (1) gas hydrate destabilization is self-limiting, dispelling any notion of the potential for

  12. 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.

  13. Regional and reservoir-scale analysis of fault systems and structural development of Pagerungan Gas Field, East Java Sea, Indonesia

    SciTech Connect

    Davies, R.K.; Medwedeff, D.A. )

    1996-01-01

    Pagerungan gas field lies on a complexly faulted and folded anticline just north of the major Sakala-Paliat Fault System (SPFS) offshore Bali. The Eocene clastic reservoir is affected by two generations of faults: Eocene normal and Neogene compressional faults. Fault geometry, timing and connectivity is determined by combining regional and field-scale methods. Restored regional structure maps and sections indicate the field is located on the L. Eocene, footwall-paleo-high of the south-dipping SPFS. Within the field, smaller normal faults nucleated sub-parallel to the SPFS with both synthetic and antithetic dips. Neogene to Present compression folded the strata creating closure in the field, reversed slip on selected preexisting normal faults, and nucleated new reverse fault sets. Some normal faults are completely inverted, others have net normal offset after some reverse slip, and still others are not reactivated. Reverse faults strike sub-parallel to earlier formed normal faults. The eastern and western parts of the field are distinguished by the style and magnitude of early compressional deformation. 3D seismic analysis indicates the geometry of reservoir faults is similar to the regional fault systems: sub-parallel segments share displacement at their terminations either by distributed deformation in the rock between adjacent terminations or through short cross-faults oriented at a high angle to the principal fault sets. Anomalous trends in the contours of throw projected onto fault surfaces predict the connectivity of complex fault patterns. Integration of regional and field-scale analysis provides the most accurate prediction of fault geometry and lays the foundation for field development.

  14. Regional and reservoir-scale analysis of fault systems and structural development of Pagerungan Gas Field, East Java Sea, Indonesia

    SciTech Connect

    Davies, R.K.; Medwedeff, D.A.

    1996-12-31

    Pagerungan gas field lies on a complexly faulted and folded anticline just north of the major Sakala-Paliat Fault System (SPFS) offshore Bali. The Eocene clastic reservoir is affected by two generations of faults: Eocene normal and Neogene compressional faults. Fault geometry, timing and connectivity is determined by combining regional and field-scale methods. Restored regional structure maps and sections indicate the field is located on the L. Eocene, footwall-paleo-high of the south-dipping SPFS. Within the field, smaller normal faults nucleated sub-parallel to the SPFS with both synthetic and antithetic dips. Neogene to Present compression folded the strata creating closure in the field, reversed slip on selected preexisting normal faults, and nucleated new reverse fault sets. Some normal faults are completely inverted, others have net normal offset after some reverse slip, and still others are not reactivated. Reverse faults strike sub-parallel to earlier formed normal faults. The eastern and western parts of the field are distinguished by the style and magnitude of early compressional deformation. 3D seismic analysis indicates the geometry of reservoir faults is similar to the regional fault systems: sub-parallel segments share displacement at their terminations either by distributed deformation in the rock between adjacent terminations or through short cross-faults oriented at a high angle to the principal fault sets. Anomalous trends in the contours of throw projected onto fault surfaces predict the connectivity of complex fault patterns. Integration of regional and field-scale analysis provides the most accurate prediction of fault geometry and lays the foundation for field development.

  15. Fluid circulation and reservoir conditions of the Los Humeros Geothermal Field (LHGF), Mexico, as revealed by a noble gas survey

    NASA Astrophysics Data System (ADS)

    Pinti, Daniele L.; Castro, M. Clara; Lopez-Hernandez, Aida; Han, Guolei; Shouakar-Stash, Orfan; Hall, Chris M.; Ramírez-Montes, Miguel

    2017-03-01

    Los Humeros Geothermal Field (LHGF) is one of four geothermal fields currently operating in Mexico, in exploitation since 1990. Located in a caldera complex filled with very low-permeability rhyolitic ignimbrites that are the reservoir cap-rock, recharge of the geothermal field is both limited and localized. Because of this, planning of any future geothermal exploitation must be based on a clear understanding of the fluid circulation. To this end, a first noble gas survey was carried out in which twenty-two production wells were sampled for He, Ne, Ar, Kr, and Xe isotope analysis. Air-corrected 3He/4He ratios (Rc) measured in the fluid, normalized to the helium atmospheric ratio (Ra; 1.384 × 10- 6), are consistently high across the field, with an average value of 7.03 ± 0.40 Ra. This value is close to that of the sub-continental upper mantle, indicating that LHGF mines heat from an active magmatic system. Freshwater recharge does not significantly affect He isotopic ratios, contributing 1-10% of the total fluid amount. The presence of radiogenic 40Ar* in the fluid suggests a fossil fluid component that might have circulated within the metacarbonate basement with radiogenic argon produced from detrital dispersed illite. Solubility-driven elemental fractionation of Ne/Ar, Kr/Ar, and Xe/Ar confirm extreme boiling in the reservoir. However, a combined analysis of these ratios with 40Ar/36Ar reveals mixing with an air component, possibly introduced by re-injected geothermal fluids.

  16. 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 μm/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.

  17. Geologic, technical, and economic sensitivity analysis in support of the GRI (Gase Research Institute) Tight Gas Reservoirs Project area. Annual Report, November 1983-November 1984

    SciTech Connect

    Morra, F.; Brashear, J.P.

    1985-02-01

    During 1982 to 1983, Lewin and Associates, Inc. developed the Tight Gas Analysis System (TGAS) as a planning and assessment tool for both GRI and the DOE. During this reporting period Nov. 1983 to Nov. 1984, TGAS was used to support the GRI Tight Gas Reservoirs Project area in three tasks: (1) evaluation of benefits of the entire program and its subcomponents; (2) detailed analysis of a single formation (the Travis Peak); and (3) fine grain assessment of the role of information in the decision to drill, develop and produce a flight gas prospect.

  18. 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.

    2015-08-11

    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.

  19. 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.

  20. Deep Subsurface Biodegradation of Sedimentary Organic Matter in a Methane-Rich Shale Gas Reservoir

    NASA Astrophysics Data System (ADS)

    Formolo, M. J.; Petsch, S.; Salacup, J.; Waldron, P.; Martini, A.; Nusslein, K.

    2006-12-01

    Extensive, sustained subsurface microbial activity in the Antrim Shale (Late Devonian, Michigan Basin, USA) has led to the accumulation of an important unconventional natural gas resource, from which is produced ~14 million m3 of methane per day. Both geochemical and molecular evidence supports a community comprising diverse methanogens, fermentative microorganisms, and little else. The diversity of methanogens is strongly associated with a sharp gradient in formation water salinity spanning 10-4000 mM Cl-1. Analysis of hydrocarbon biomarkers within the Antrim reveal patterns of degradation that are directly associated with zones of active methanogenesis, with marked differences observed between methane- producing and non-producing sections of the formation. Maturity and source indicators show that these patterns do not result from varying degrees of thermal maturity or source inputs across the Basin, but instead demonstrate that biodegradation is confined solely to regions of the Basin exhibiting extensive methanogenesis. Calculated biodegradation indices provide evidence for nearly quantitative loss of saturated hydrocarbons, specifically n-alkanes and acyclic isoprenoids, during biodegradation associated with methanogenesis. These results are the first to document deep subsurface ancient sedimentary organic matter biodegradation associated with the formation of economic microbial gas reserves within low permeability, thermally-immature source rocks. As such, the results provide insight into microbial activity in the deep subsurface, specifically the role that methanogen-dominated communities may play in carbon-rich, electron acceptor-poor sedimentary basins.

  1. CHARACTERIZING MARINE GAS-HYDRATE RESERVOIRS AND DETERMINING MECHANICAL PROPERTIES OF MARINE GAS-HYDRATE STRATA WITH 4-COMPONENT OCEAN-BOTTOM-CABLE SEISMIC DATA

    SciTech Connect

    B.A. Hardage; M.M. Backus; M.V. DeAngelo; R.J. Graebner; P. Murray; L.J. Wood assisted by K. Rogers

    2002-01-01

    -component seismic data will be more valuable than conventional P-wave seismic data for exploiting gas-hydrate reservoirs that cause gas invasion into surrounding strata. Published laboratory studies have shown that the ratio of P-wave velocity (V{sub p}) and SV velocity (V{sub s}) is an important parameter for identifying lithofacies. (In this report, the subscript S that accompanies a parameter can be replaced with the subscript SV to more accurately define the type of shear wave data used in this study.) Seismic estimates of V{sub p}/V{sub s} can be made when multi-component seismic data are acquired. Seismic-based V{sub p}/V{sub s} ratios are being analyzed across the research study area to determine what types of shallow lithofacies can be distinguished by this velocity parameter. These research findings will be summarized in the final project report.

  2. 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.

  3. Petrophysical approach for S-wave velocity prediction based on brittleness index and total organic carbon of shale gas reservoir: A case study from Horn River Basin, Canada

    NASA Astrophysics Data System (ADS)

    Kim, Taeyoun; Hwang, Seho; Jang, Seonghyung

    2017-01-01

    When finding the "sweet spot" of a shale gas reservoir, it is essential to estimate the brittleness index (BI) and total organic carbon (TOC) of the formation. Particularly, the BI is one of the key factors in determining the crack propagation and crushing efficiency for hydraulic fracturing. There are several methods for estimating the BI of a formation, but most of them are empirical equations that are specific to particular rock types. We estimated the mineralogical BI based on elemental capture spectroscopy (ECS) log and elastic BI based on well log data, and we propose a new method for predicting S-wave velocity (VS) using mineralogical BI and elastic BI. The TOC is related to the gas content of shale gas reservoirs. Since it is difficult to perform core analysis for all intervals of shale gas reservoirs, we make empirical equations for the Horn River Basin, Canada, as well as TOC log using a linear relation between core-tested TOC and well log data. In addition, two empirical equations have been suggested for VS prediction based on density and gamma ray log used for TOC analysis. By applying the empirical equations proposed from the perspective of BI and TOC to another well log data and then comparing predicted VS log with real VS log, the validity of empirical equations suggested in this paper has been tested.

  4. 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

  5. Production data as an indicator of gas reservoir heterogenesity in the Vicksburg S sandstones (Oligocene), McAllen Ranch field, Hidalgo County, Texas

    SciTech Connect

    Wermund, E.G.; Langford, R.P. )

    1990-09-01

    To assess reservoir heterogeneity in low-permeability Vicksburg S sandstone reservoirs in McAllen Ranch gas field, production and pressure histories of 49 wells were analyzed; predominant well spacing is 80 acres. These histories were compared both fieldwide and in local areas defined by faults or facies. Production is through casing perforations, which commonly extend over 600 ft gross intervals within vertically stacked potential reservoir sandstones. The S reservoir comprises five sand-rich intervals that together have produced 249 bcf of gas since 1965. Cumulative production per well ranges from 39 bcf for 24 years to 0.8 bcf in 11 years. Average cumulative production is 6.3 bcf per well. To date, the largest average monthly production for a well is over 360 Mmcf; the mean for average monthly production (based on publicly available data) for all wells is 30.5 Mmcf. There is poor correlation among gross thicknesses of perforated intervals and cumulative production (R = 0.024). Wellhead shut-in pressures range from 12,500 psi on completion to 1,300 psi at abandonment. Maps of cumulative production and normalized BHP/Z show good production/pressure correlations. The slopes of regression curves for (1) monthly production decline histories and (2) periodic tests of daily production of adjacent well pairs show little influence from adjacent well completions or refracturing, even at relatively close well spacing. Monthly production in a newly completed or refractured adjacent well commonly exceeds the last production rate of a nearby older well. Production and pressure histories in adjacent well pairs suggest that limited communication occurs between S sandstone reservoirs of paired wells. This limited communication may be a consequence of limited drainage radius due to low permeability and of stratigraphic/diagenetic heterogeneity within the reservoir.

  6. Estimation of Dry Fracture Weakness, Porosity, and Fluid Modulus Using Observable Seismic Reflection Data in a Gas-Bearing Reservoir

    NASA Astrophysics Data System (ADS)

    Chen, Huaizhen; Zhang, Guangzhi

    2017-03-01

    Fracture detection and fluid identification are important tasks for a fractured reservoir characterization. Our goal is to demonstrate a direct approach to utilize azimuthal seismic data to estimate fluid bulk modulus, porosity, and dry fracture weaknesses, which decreases the uncertainty of fluid identification. Combining Gassmann's (Vier. der Natur. Gesellschaft Zürich 96:1-23, 1951) equations and linear-slip model, we first establish new simplified expressions of stiffness parameters for a gas-bearing saturated fractured rock with low porosity and small fracture density, and then we derive a novel PP-wave reflection coefficient in terms of dry background rock properties (P-wave and S-wave moduli, and density), fracture (dry fracture weaknesses), porosity, and fluid (fluid bulk modulus). A Bayesian Markov chain Monte Carlo nonlinear inversion method is proposed to estimate fluid bulk modulus, porosity, and fracture weaknesses directly from azimuthal seismic data. The inversion method yields reasonable estimates in the case of synthetic data containing a moderate noise and stable results on real data.

  7. An experimental model of episodic gas release through fracture of fluid confined within a pressurized elastic reservoir

    NASA Astrophysics Data System (ADS)

    Rocco, Stefano; Woods, Andrew W.; Harrington, Jon; Norris, Simon

    2017-01-01

    We present new experiments that identify a mechanism for episodic release of gas from a pressurized, deformable reservoir confined by a clay seal, as a result of the transition from bulk deformation to channel growth through the clay. Air is injected into the center of a thin cylindrical cell initially filled with a mixture of bentonite clay and water. For sufficiently dry mixtures, the pressure initially increases with little volume change. On reaching the yield stress of the clay-water mixture, the lid of the cell then deforms elastically and an air-filled void forms in the center of the cell as the clay is driven radially outward. With continued supply of air, the pressure continues to increase until reaching the fracture strength of the clay. A fracture-like channel then forms and migrates to the outer edge of the cell, enabling the air to escape. The pressure then falls, and the clay flows back toward the center of the cell and seals the channel so the cycle can repeat. The phenomena may be relevant at mud volcanoes.

  8. 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.

  9. 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.

  10. CO2 is dominant greenhouse gas emitted from six hydropower reservoirs in southeastern United States during peak summer emissions

    DOE PAGES

    Bevelhimer, Mark S.; Stewart, Aurthur J.; Fortner, Allison M.; ...

    2016-01-06

    During August-September 2012, we sampled six hydropower reservoirs in southeastern United States. for CO2 and CH4 emissions via three pathways: diffusive emissions from water surface; ebullition in the water column; and losses from dam tailwaters during power generation. Average total emission rates of CO2 for the six reservoirs ranged from 1,127 to 2,051 mg m-2 d-1, which is low to moderate compared to CO2 emissions rates reported for tropical hydropower reservoirs and boreal ponds and lakes, and similar to rates reported for other temperate reservoirs. Similar average rates for CH4 were also relatively low, ranging from 5 to 83 mgmore » m-2 d-1. On a whole-reservoir basis, total emissions of CO2 ranged nearly 10-fold, from ~51,000 kg per day for Fontana to ~486,000 kg per day for Guntersville, and total emissions of CH4 ranged nearly 20-fold, from ~5 kg per day for Fontana to ~83 kg per day for Allatoona. Emissions through the tailwater pathway varied among reservoirs, comprising from 20 to 50% of total CO2 emissions and 0 to 90% of CH4 emissions, depending on the reservoir. Furthermore, several explanatory factors related to reservoir morphology and water quality were considered for observed differences among reservoirs.« less

  11. 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.

  12. Sweet spots discrimination in shale gas reservoirs using seismic and well-logs data. A case study from the Worth basin in the Barnett shale

    NASA Astrophysics Data System (ADS)

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

    2014-05-01

    Here, we present a case study of sweet spots discrimination in shale gas reservoirs located in the Worth basin of the Barnett shale using seismic and well-logs data. Seismic attributes such the Chaos and the ANT-Tracking are used for natural fractures system identification from seismic data, the maps of the stress and the Poisson ratio obtained from the upscaling of well-logs data of a horizontal well are able to provide an information about the drilling direction which is usually in the minimum horizontal stress profile, the map of the Poisson ratio can provide an information hardness of the source rock. The set of well logs data is used for geo-mechanical and petrophysical discrimination of the sweet spots, after discrimination the identified zones are useful for reserves estimation from unconventional shale gas reservoir.

  13. 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.

  14. Numerical simulation of heterogeneous fractured gas reservoir systems with turbulence and closure stress effects

    SciTech Connect

    Allam, A.M.

    1982-01-01

    Although techniques for designing a fracture treatment are available, the intended results of these techniques are often not attained. The evaluation of fracturing treatments on low permeability gas wells is required to both optimize the fracturing design and form prediction calculations of a treatments effect. This study primarily investigates the effect of fracture height on the performance of vertically fractured wells. The effects of layered media, turbulance, and closure pressure are included in this work. Consider that a well, intercepted by a vertical fracture, is in the center of a squared drainage system with closed outer boundary. Any increase in well productivity will be determined by fracture parameters, which are: fracture length, height, fracture conductivity, and location of the fracture in the formaton. On the basis of the analysis of fluid flow in porous media, the problem solving technique used in this study is the numerical method. A three-dimensional finite difference fully implicit model was written for this. In addition, the Sparse Matrix technique was used as a solver. Furthermore, Slices Source Over Relaxation was used as an iterative method for solving routines. Presented here are the numerical results of the three-dimensional model for a well intercepting a vertical fracture wth finite conductivity. The results are presented in the general form of dimensionless variables. Type curves considering the effect of fracture height on well performance are included. In addition, type curves for turbulent flow in the fracture are also obtained. Finally, other important contributions of this work are the data showing the effect of layered formation on fractured well performance.

  15. Reservoir microfacies and their logging response of gas hydrate in the Qilian Mountain permafrost in Northwest China

    NASA Astrophysics Data System (ADS)

    Liu, H.; Lu, Z.; Zhang, Y.; Sun, Z.

    2012-12-01

    The Qilian Mountain permafrost is located in the north margin of the Qinghai-Tibet Plateau in northwest China. The permafrost area is about 10×104 Km2, and dominated by mountain permafrost. The mean annual ground temperature is 1.5 to 2.4 centigrade and the thickness of permafrost is generally 50 to 139 m. The gas hydrate was sampled successfully in the 133-396m interval from holes DK-1, DK-2 and DK-3 and tested by microRaman spectroscopy in the hydrate laboratory of the Qingdao Institute of Marine Geology during June to September in 2009. The exploratory drilling indicated that gas hydrate and its abnormal occurrence are mainly developed 130-400 m beneath permafrost. The strata belong to the Jiangcang Formation of middle Jurassic. Based on lithology, sedimentary structure and sequence and other facies markers, reservoir microfacies of gas hydrate are identified as underwater distributary channel and interdistributary bay in delta front of delta and deep lake mudstone facies in lacustrine. The underwater distributary channel in delta front of delta is dominated by fine sandstone. It has little mudstone. The grain size generally becomes finer, and scour-filling structure, parallel bedding, cross bedding and wavy bedding develop successively from bottom to top in one phase of channel. In vertical multi-period distributary channels superimpose, forming thick sandstone, and sometimes a thin mudstone develop between two channels. The interdistributaty bay is characterized by mudstone with little siltstone and fine sandstone. The lithology column shows mudstone interbedded with thin sandstone. Horizon bedding and lenticular bedding are the main structure. The gas hydrate usually presents visible white (smoky gray when mixing with mud) ice-like lamina in fissures or invisible micro disseminated occurrence in pores of sandstone. Honeycomb pores formed by the decomposition of gas hydrate are usually found in sandstone. The deep lake is dominated by thick dark grey mudstone

  16. 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

  17. 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 (ΦN), deep Resistivity (Rt) and Bulk Density (ρb) logs were used to model bulk mineralogy and lithology. Biostratigraphic and complete

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

    SciTech Connect

    Rutqvist, Jonny; Rinaldi, Antonio P.; Cappa, Frédéric; Moridis, George J.

    2013-07-01

    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 towards conditions usually encountered in the Marcellus shale play in the Northeastern US at an approximate depth of 1500 m (~;;4,500 feet). Our modeling simulations indicate that when faults are present, micro-seismic events are possible, the magnitude of which is somewhat larger than the one associated with micro-seismic events originating from regular hydraulic fracturing because of the larger surface area that is available for rupture. The results of our simulations indicated fault rupture lengths of about 10 to 20 m, which, in rare cases can extend to over 100 m, depending on the fault permeability, the in situ stress field, and the fault strength properties. In addition to a single event rupture length of 10 to 20 m, repeated events and aseismic slip amounted to a total rupture length of 50 m, along with a shear offset displacement of less than 0.01 m. This indicates that the possibility of hydraulically induced fractures at great depth (thousands of meters) causing activation of faults and creation of a new flow path that can reach shallow groundwater resources (or even the surface) is remote. The expected low permeability of faults in producible shale is clearly a limiting factor for the possible rupture length and seismic magnitude. In fact, for a fault that is initially nearly-impermeable, the only possibility of larger fault slip event would be opening by hydraulic fracturing; this would allow pressure to penetrate the matrix along the fault and to reduce the frictional strength over a sufficiently large fault surface patch. However, our simulation results show that if the fault is initially impermeable, hydraulic fracturing along the fault results in numerous small micro-seismic events along with the propagation, effectively

  19. Carboniferous and older carbonate rocks: Lithofacies, extent, and reservoir quality: Chapter CC in The oil and gas resource potential of the Arctic National Wildlife Refuge 1002 area, Alaska

    USGS Publications Warehouse

    Dumoulin, Julie A.

    1999-01-01

    -stem tests found locally reasonable flow rates (4,220-4,800 bpd) and, in the Flaxman Island area, recovered gas and condensate from these rocks. The Lisburne Group has produced up to 50,000 bbl of oil/ day from the Lisburne field at Prudhoe Bay. Reservoir parameters of the Lisburne in northeastern Alaska range from low (porosities ≤ 5% in most limestones) to good (porosities average 6.5-10% in some dolostones). Reservoir quality in Carboniferous and older carbonate strata in the 1002 area should be greatest where these rocks are highly fractured and (or) truncated by the Lower Cretaceous Unconformity.

  20. EQUILGAS: Program to estimate temperatures and in situ two-phase conditions in geothermal reservoirs using three combined FT-HSH gas equilibria models

    NASA Astrophysics Data System (ADS)

    Barragán, Rosa María; Núñez, José; Arellano, Víctor Manuel; Nieva, David

    2016-03-01

    Exploration and exploitation of geothermal resources require the estimation of important physical characteristics of reservoirs including temperatures, pressures and in situ two-phase conditions, in order to evaluate possible uses and/or investigate changes due to exploitation. As at relatively high temperatures (>150 °C) reservoir fluids usually attain chemical equilibrium in contact with hot rocks, different models based on the chemistry of fluids have been developed that allow deep conditions to be estimated. Currently either in water-dominated or steam-dominated reservoirs the chemistry of steam has been useful for working out reservoir conditions. In this context, three methods based on the Fischer-Tropsch (FT) and combined H2S-H2 (HSH) mineral-gas reactions have been developed for estimating temperatures and the quality of the in situ two-phase mixture prevailing in the reservoir. For these methods the mineral buffers considered to be controlling H2S-H2 composition of fluids are as follows. The pyrite-magnetite buffer (FT-HSH1); the pyrite-hematite buffer (FT-HSH2) and the pyrite-pyrrhotite buffer (FT-HSH3). Currently from such models the estimations of both, temperature and steam fraction in the two-phase fluid are obtained graphically by using a blank diagram with a background theoretical solution as reference. Thus large errors are involved since the isotherms are highly nonlinear functions while reservoir steam fractions are taken from a logarithmic scale. In order to facilitate the use of the three FT-HSH methods and minimize visual interpolation errors, the EQUILGAS program that numerically solves the equations of the FT-HSH methods was developed. In this work the FT-HSH methods and the EQUILGAS program are described. Illustrative examples for Mexican fields are also given in order to help the users in deciding which method could be more suitable for every specific data set.

  1. A detailed view of the injection-induced seismicity in a natural gas reservoir in Zigong, southwestern Sichuan Basin, China

    NASA Astrophysics Data System (ADS)

    Lei, Xinglin; Ma, Shengli; Chen, Wenkang; Pang, Chunmei; Zeng, Jie; Jiang, Bing

    2013-08-01

    at a gas reservoir located in the relatively stable Sichuan Basin, China, mirrors the injection pressure of unwanted water, suggesting that the seismicity is injection induced. Injection under high pressure on a routine basis began on 9 January 2009 and continued to July 2011. During the injection period, over 120,000 m3 of water was pumped under a wellhead pressure of up to 6.2 MPa into the limestone formation of Permian 2.45 to 2.55 km beneath the surface. The injection induced more than 7000 surface-recorded earthquakes, including 2 M4+ (the largest one was ML4.4), 20 M3+, and more than 100 M2+ events. Data observed by a nearby local seismic network and five temporal stations provide a detailed view of the spatiotemporal distribution of the induced earthquakes. Most events were limited to depths ranging from 2.5 to 4 km, which is consistent with the limestone formation of Permian. In a map view, hypocenters are concentrated in a NNW extended ellipsoidal zone approximately 6 km long and approximately 2 km wide centered approximately at the injection well. Multisources of evidence such as the shear mechanism, pattern of hypocenter distribution, and small elevated pore pressure as compared with the least principal stress in the region show that the induced earthquakes occurred as a result of lowering of the effective normal stress on known or unknown preexisting blind faults which are critically loaded under the regional stress field. Epidemic-type aftershock sequence modeling results indicate that injection inducing and earthquake triggering are both important during earlier periods of injection, while later periods are dominated by forced (injection-induced) seismicity.

  2. Real-time detection of dielectric anisotropy or isotropy in unconventional oil-gas reservoir rocks supported by the oblique-incidence reflectivity difference technique

    NASA Astrophysics Data System (ADS)

    Zhan, Honglei; Wang, Jin; Zhao, Kun; Lű, Huibin; Jin, Kuijuan; He, Liping; Yang, Guozhen; Xiao, Lizhi

    2016-12-01

    Current geological extraction theory and techniques are very limited to adequately characterize the unconventional oil-gas reservoirs because of the considerable complexity of the geological structures. Optical measurement has the advantages of non-interference with the earth magnetic fields, and is often useful in detecting various physical properties. One key parameter that can be detected using optical methods is the dielectric permittivity, which reflects the mineral and organic properties. Here we reported an oblique-incidence reflectivity difference (OIRD) technique that is sensitive to the dielectric and surface properties and can be applied to characterization of reservoir rocks, such as shale and sandstone core samples extracted from subsurface. The layered distribution of the dielectric properties in shales and the uniform distribution in sandstones are clearly identified using the OIRD signals. In shales, the micro-cracks and particle orientation result in directional changes of the dielectric and surface properties, and thus, the isotropy and anisotropy of the rock can be characterized by OIRD. As the dielectric and surface properties are closely related to the hydrocarbon-bearing features in oil-gas reservoirs, we believe that the precise measurement carried with OIRD can help in improving the recovery efficiency in well-drilling process.

  3. Real-time detection of dielectric anisotropy or isotropy in unconventional oil-gas reservoir rocks supported by the oblique-incidence reflectivity difference technique.

    PubMed

    Zhan, Honglei; Wang, Jin; Zhao, Kun; Lű, Huibin; Jin, Kuijuan; He, Liping; Yang, Guozhen; Xiao, Lizhi

    2016-12-15

    Current geological extraction theory and techniques are very limited to adequately characterize the unconventional oil-gas reservoirs because of the considerable complexity of the geological structures. Optical measurement has the advantages of non-interference with the earth magnetic fields, and is often useful in detecting various physical properties. One key parameter that can be detected using optical methods is the dielectric permittivity, which reflects the mineral and organic properties. Here we reported an oblique-incidence reflectivity difference (OIRD) technique that is sensitive to the dielectric and surface properties and can be applied to characterization of reservoir rocks, such as shale and sandstone core samples extracted from subsurface. The layered distribution of the dielectric properties in shales and the uniform distribution in sandstones are clearly identified using the OIRD signals. In shales, the micro-cracks and particle orientation result in directional changes of the dielectric and surface properties, and thus, the isotropy and anisotropy of the rock can be characterized by OIRD. As the dielectric and surface properties are closely related to the hydrocarbon-bearing features in oil-gas reservoirs, we believe that the precise measurement carried with OIRD can help in improving the recovery efficiency in well-drilling process.

  4. Real-time detection of dielectric anisotropy or isotropy in unconventional oil-gas reservoir rocks supported by the oblique-incidence reflectivity difference technique

    PubMed Central

    Zhan, Honglei; Wang, Jin; Zhao, Kun; Lű, Huibin; Jin, Kuijuan; He, Liping; Yang, Guozhen; Xiao, Lizhi

    2016-01-01

    Current geological extraction theory and techniques are very limited to adequately characterize the unconventional oil-gas reservoirs because of the considerable complexity of the geological structures. Optical measurement has the advantages of non-interference with the earth magnetic fields, and is often useful in detecting various physical properties. One key parameter that can be detected using optical methods is the dielectric permittivity, which reflects the mineral and organic properties. Here we reported an oblique-incidence reflectivity difference (OIRD) technique that is sensitive to the dielectric and surface properties and can be applied to characterization of reservoir rocks, such as shale and sandstone core samples extracted from subsurface. The layered distribution of the dielectric properties in shales and the uniform distribution in sandstones are clearly identified using the OIRD signals. In shales, the micro-cracks and particle orientation result in directional changes of the dielectric and surface properties, and thus, the isotropy and anisotropy of the rock can be characterized by OIRD. As the dielectric and surface properties are closely related to the hydrocarbon-bearing features in oil-gas reservoirs, we believe that the precise measurement carried with OIRD can help in improving the recovery efficiency in well-drilling process. PMID:27976746

  5. Understanding the interaction of injected CO2 and reservoir fluids in the Cranfield enhanced oil recovery (EOR) field (MS, USA) by non-radiogenic noble gas isotopes

    NASA Astrophysics Data System (ADS)

    Gyore, Domokos; Stuart, Finlay; Gilfillan, Stuart

    2016-04-01

    Identifying the mechanism by which the injected CO2 is stored in underground reservoirs is a key challenge for carbon sequestration. Developing tracing tools that are universally deployable will increase confidence that CO2 remains safely stored. CO2 has been injected into the Cranfield enhanced oil recovery (EOR) field (MS, USA) since 2008 and significant amount of CO2 has remained (stored) in the reservoir. Noble gases (He, Ne, Ar, Kr, Xe) are present as minor natural components in the injected CO2. He, Ne and Ar previously have been shown to be powerful tracers of the CO2 injected in the field (Györe et al., 2015). It also has been implied that interaction with the formation water might have been responsible for the observed CO2 loss. Here we will present work, which examines the role of reservoir fluids as a CO2 sink by examining non-radiogenic noble gas isotopes (20Ne, 36Ar, 84Kr, 132Xe). Gas samples from injection and production wells were taken 18 and 45 months after the start of injection. We will show that the fractionation of noble gases relative to Ar is consistent with the different degrees of CO2 - fluid interaction in the individual samples. The early injection samples indicate that the CO2 injected is in contact with the formation water. The spatial distribution of the data reveal significant heterogeneity in the reservoir with some wells exhibiting a relatively free flow path, where little formation water is contacted. Significantly, in the samples, where CO2 loss has been previously identified show active and ongoing contact. Data from the later stage of the injection shows that the CO2 - oil interaction has became more important than the CO2 - formation water interaction in controlling the noble gas fingerprint. This potentially provides a means to estimate the oil displacement efficiency. This dataset is a demonstration that noble gases can resolve CO2 storage mechanisms and its interaction with the reservoir fluids with high resolution

  6. Spatial and Temporal Correlates of Greenhouse Gas Diffusion from a Hydropower Reservoir in the Southern United States

    DOE PAGES

    Mosher, Jennifer; Fortner, Allison M.; Phillips, Jana Randolph; ...

    2015-10-29

    Emissions of CO2 and CH4 from freshwater reservoirs constitute a globally significant source of atmospheric greenhouse gases (GHGs), but knowledge gaps remain with regard to spatiotemporal drivers of emissions. We document the spatial and seasonal variation in surface diffusion of CO2 and CH4 from Douglas Lake, a hydropower reservoir in Tennessee, USA. Monthly estimates across 13 reservoir sites from January to November 2010 indicated that surface diffusions ranged from 236 to 18,806 mg m-2 day-1 for CO2 and 0 to 0.95 mg m-2 day-1 for CH4. Next, we developed statistical models using spatial and physicochemical variables to predict surface diffusionsmore » of CO2 and CH4. Models explained 22.7 and 20.9% of the variation in CO2 and CH4 diffusions, respectively, and identified pH, temperature, dissolved oxygen, and Julian day as the most informative important predictors. These findings provide baseline estimates of GHG emissions from a reservoir in eastern temperate North America a region for which estimates of reservoir GHGs emissions are limited. Our statistical models effectively characterized non-linear and threshold relationships between physicochemical predictors and GHG emissions. Further refinement of such models will aid in predicting current GHG emissions in unsampled reservoirs and forecasting future GHG emissions.« less

  7. Determination of Shale Volume and Distribution Patterns and Effective Porosity from Well Log Data Based On Cross-Plot Approach for A Shaly Carbonate Gas Reservoir

    NASA Astrophysics Data System (ADS)

    Moradi, Siyamak; Moeini, Mohammad; Kamal Ghassem al-Askari, Mohammad; Hamed Mahvelati, Elaheh

    2016-10-01

    Determination of shale volume distribution is one of the most important factors that has to be considered in formation evaluation, since existence of shale reduces effective porosity and permeability of the reservoir. In this paper, shale volume and distribution (dispersed, laminar and structural) and formation effective porosity are estimated from well log data and cross-plots. Results show that distribution of shale is mainly dispersed with few of laminar ones, and the quality of reservoir (effective porosity) decreases with depth resulting in low productivity of gas wells drilled in lower zones. Good agreement of estimated shale volumes and effective porosities from neutron-density cross-plot with the values determined from gamma ray log (CGR) and core analysis demonstrates the accuracy and applicability of these plots in determination of petrophysical parameters from conventional log data.

  8. 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 μmol L-1 (0.07-2.14 μmol L-1) and 3 times higher at the stations close to the tributaries inputs (up to 7 μmol L-1). In the hypolimnion, CH4 concentration is <100 μmol L-1 in the wet season and can reach up to 400 μmol L-1 in the dry season. The spatial and temporal variability are lower for CO2. Surface CO2 concentration was on average 72 μmol L-1 (up to 300) and hypolimnic concentration ranged between 250 and 1000 μmol 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

  9. ALMA Reveals Large Molecular Gas Reservoirs in Ancestors of Milky Way-Mass Galaxies at z=1.2-1.3

    NASA Astrophysics Data System (ADS)

    Papovich, Casey J.; Labbe, Ivo; Glazebrook, Karl; Quadri, Ryan; Bekiaris, Georgios; Dickinson, Mark; Finkelstein, Steven L.; Fisher, David B.; Inami, Hanae; Livermore, Rachael C.; Spitler, Lee; Straatman, Caroline; Tran, Kim-Vy

    2017-01-01

    The gas accretion and star-formation histories of galaxies like the Milky Way remain an outstanding problem in astrophysics. Observations show that 8 billion years ago, at redshifts z > 1, the progenitors to Milky Way-mass galaxies were forming stars 30 times faster than today and predicted to be rich in molecular gas, in contrast with low present-day gas fractions (<10%). Using ALMA Band 4 observations, we detected the molecular gas using the CO(J=3-2) emission (rest-frame 345.8 GHz) in a sample of galaxies at redshifts z=1.2-1.3, selected to have the stellar mass (Log M*/M⊙ =10.2) and star-formation rate (SFR = 20 M⊙ yr-1) of the main progenitors of today's Milky Way-mass galaxies at this epoch. We show that with relatively short ALMA integrations, we now probe efficiently the CO luminosities of z > 1 star-forming galaxies a factor two lower than was possible previously. The CO emission from these galaxies reveals large molecular gas reservoirs, with a ratio of molecular-gas mass-to-stellar mass of ~100%, indicating most of the baryons are in cold gas, not stars. The ratio of the galaxies' total luminosity from star formation to CO luminosity corresponds to long gas-consumption timescales. Compared to local spiral galaxies, the star-formation efficiency, estimated from the ratio of total IR luminosity to CO emission, has remained nearly constant since redshift z=1.2, despite the order of magnitude decrease in gas fraction, consistent with results for more massive and more luminous galaxies at this epoch. This implies that the the physical processes that determine the rate at which gas cools to form stars in distant galaxies appear to be similar to that in local galaxies.

  10. 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

  11. Integrated seismic study of naturally fractured tight gas reservoirs. Technical progress report for the period: 7/1/93--9/31/93

    SciTech Connect

    Mavko, G.; Nur, A.

    1993-10-23

    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 paths of production. During this eighth quarter of the seismic study of this area, work continued in processing seismic data, collecting additional geological information to aid in the interpretation, and integrating regional structural information and fracture trends with observations of structure in the study area.

  12. 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

  13. Spatial and Temporal Correlates of Greenhouse Gas Diffusion from a Hydropower Reservoir in the Southern United States

    SciTech Connect

    Mosher, Jennifer; Fortner, Allison M.; Phillips, Jana Randolph; Bevelhimer, Mark S.; Stewart, Arthur; Troia, Matthew J.

    2015-10-29

    Emissions of CO2 and CH4 from freshwater reservoirs constitute a globally significant source of atmospheric greenhouse gases (GHGs), but knowledge gaps remain with regard to spatiotemporal drivers of emissions. We document the spatial and seasonal variation in surface diffusion of CO2 and CH4 from Douglas Lake, a hydropower reservoir in Tennessee, USA. Monthly estimates across 13 reservoir sites from January to November 2010 indicated that surface diffusions ranged from 236 to 18,806 mg m-2 day-1 for CO2 and 0 to 0.95 mg m-2 day-1 for CH4. Next, we developed statistical models using spatial and physicochemical variables to predict surface diffusions of CO2 and CH4. Models explained 22.7 and 20.9% of the variation in CO2 and CH4 diffusions, respectively, and identified pH, temperature, dissolved oxygen, and Julian day as the most informative important predictors. These findings provide baseline estimates of GHG emissions from a reservoir in eastern temperate North America a region for which estimates of reservoir GHGs emissions are limited. Our statistical models effectively characterized non-linear and threshold relationships between physicochemical predictors and GHG emissions. Further refinement of such models will aid in predicting current GHG emissions in unsampled reservoirs and forecasting future GHG emissions.

  14. Modeling the Injection of Carbon Dioxide and Nitrogen into a Methane Hydrate Reservoir and the Subsequent Production of Methane Gas on the North Slope of Alaska

    NASA Astrophysics Data System (ADS)

    Garapati, N.; McGuire, P. C.; Liu, Y.; Anderson, B. J.

    2012-12-01

    HydrateResSim (HRS) is an open-source finite-difference reservoir simulation code capable of simulating the behavior of gas hydrate in porous media. The original version of HRS was developed to simulate pure methane hydrates, and the relationship between equilibrium temperature and pressure is given by a simple, 1-D regression expression. In this work, we have modified HydrateResSim to allow for the formation and dissociation of gas hydrates made from gas mixtures. This modification allows one to model the ConocoPhillips Ignik Sikumi #1 field test performed in early 2012 on the Alaska North Slope. The Ignik Sikumi #1 test is the first field-based demonstration of gas production through the injection of a mixture of carbon dioxide and nitrogen gases into a methane hydrate reservoir and thereby sequestering the greenhouse gas CO2 into hydrate form. The primary change to the HRS software is the added capability of modeling a ternary mixture consisting of CH4 + CO2 + N2 instead of only one hydrate guest molecule (CH4), therefore the new software is called Mix3HydrateResSim. This Mix3HydrateResSim upgrade to the software was accomplished by adding primary variables (for the concentrations of CO2 and N2), governing equations (for the mass balances of CO2 and N2), and phase equilibrium data. The phase equilibrium data in Mix3HydrateResSim is given as an input table obtained using a statistical mechanical method developed in our research group called the cell potential method. An additional phase state describing a two-phase Gas-Hydrate (GsH) system was added to consider the possibility of converting all available free water to form hydrate with injected gas. Using Mix3HydrateResSim, a methane hydrate reservoir with coexisting pure-CH4-hydrate and aqueous phases at 7.0 MPa and 5.5°C was modeled after the conditions of the Ignik Sikumi #1 test: (i) 14-day injection of CO2 and N2 followed by (ii) 30-day production of CH4 (by depressurization of the well). During the

  15. Acoustic velocity log numerical simulation and saturation estimation of gas hydrate reservoir in Shenhu area, South China Sea.

    PubMed

    Xiao, Kun; Zou, Changchun; Xiang, Biao; Liu, Jieqiong

    2013-01-01

    Gas hydrate model and free gas model are established, and two-phase theory (TPT) for numerical simulation of elastic wave velocity is adopted to investigate the unconsolidated deep-water sedimentary strata in Shenhu area, South China Sea. The relationships between compression wave (P wave) velocity and gas hydrate saturation, free gas saturation, and sediment porosity at site SH2 are studied, respectively, and gas hydrate saturation of research area is estimated by gas hydrate model. In depth of 50 to 245 m below seafloor (mbsf), as sediment porosity decreases, P wave velocity increases gradually; as gas hydrate saturation increases, P wave velocity increases gradually; as free gas saturation increases, P wave velocity decreases. This rule is almost consistent with the previous research result. In depth of 195 to 220 mbsf, the actual measurement of P wave velocity increases significantly relative to the P wave velocity of saturated water modeling, and this layer is determined to be rich in gas hydrate. The average value of gas hydrate saturation estimated from the TPT model is 23.2%, and the maximum saturation is 31.5%, which is basically in accordance with simplified three-phase equation (STPE), effective medium theory (EMT), resistivity log (Rt), and chloride anomaly method.

  16. Acoustic Velocity Log Numerical Simulation and Saturation Estimation of Gas Hydrate Reservoir in Shenhu Area, South China Sea

    PubMed Central

    Xiao, Kun; Zou, Changchun; Xiang, Biao; Liu, Jieqiong

    2013-01-01

    Gas hydrate model and free gas model are established, and two-phase theory (TPT) for numerical simulation of elastic wave velocity is adopted to investigate the unconsolidated deep-water sedimentary strata in Shenhu area, South China Sea. The relationships between compression wave (P wave) velocity and gas hydrate saturation, free gas saturation, and sediment porosity at site SH2 are studied, respectively, and gas hydrate saturation of research area is estimated by gas hydrate model. In depth of 50 to 245 m below seafloor (mbsf), as sediment porosity decreases, P wave velocity increases gradually; as gas hydrate saturation increases, P wave velocity increases gradually; as free gas saturation increases, P wave velocity decreases. This rule is almost consistent with the previous research result. In depth of 195 to 220 mbsf, the actual measurement of P wave velocity increases significantly relative to the P wave velocity of saturated water modeling, and this layer is determined to be rich in gas hydrate. The average value of gas hydrate saturation estimated from the TPT model is 23.2%, and the maximum saturation is 31.5%, which is basically in accordance with simplified three-phase equation (STPE), effective medium theory (EMT), resistivity log (Rt), and chloride anomaly method. PMID:23935407

  17. Light oil recovery from cyclic CO sub 2 injection; Influence of low pressures, impure CO sub 2 , and reservoir gas

    SciTech Connect

    Monger, T.G.; Ramos, J.C.; Thomas, J. )

    1991-02-01

    This paper is a laboratory and field investigation of the CO{sub 2} huff n puff process for the enhanced recovery of light crude oil. Cyclic CO{sub 2} displacement results with live and dead oils in watered-out Berea cores are presented. Sixty-five single-well cyclic CO{sub 2} field tests conducted in a pressure-depleted reservoir are evaluated.

  18. The Coal-Seq III Consortium. Advancing the Science of CO2 Sequestration in Coal Seam and Gas Shale Reservoirs

    SciTech Connect

    Koperna, George

    2014-03-14

    The Coal-Seq consortium is a government-industry collaborative that was initially launched in 2000 as a U.S. Department of Energy sponsored investigation into CO2 sequestration in deep, unmineable coal seams. The consortium’s objective aimed to advancing industry’s understanding of complex coalbed methane and gas shale reservoir behavior in the presence of multi-component gases via laboratory experiments, theoretical model development and field validation studies. Research from this collaborative effort was utilized to produce modules to enhance reservoir simulation and modeling capabilities to assess the technical and economic potential for CO2 storage and enhanced coalbed methane recovery in coal basins. Coal-Seq Phase 3 expands upon the learnings garnered from Phase 1 & 2, which has led to further investigation into refined model development related to multicomponent equations-of-state, sorption and diffusion behavior, geomechanical and permeability studies, technical and economic feasibility studies for major international coal basins the extension of the work to gas shale reservoirs, and continued global technology exchange. The first research objective assesses changes in coal and shale properties with exposure to CO2 under field replicated conditions. Results indicate that no significant weakening occurs when coal and shale were exposed to CO2, therefore, there was no need to account for mechanical weakening of coal due to the injection of CO2 for modeling. The second major research objective evaluates cleat, Cp, and matrix, Cm, swelling/shrinkage compressibility under field replicated conditions. The experimental studies found that both Cp and Cm vary due to changes in reservoir pressure during injection and depletion under field replicated conditions. Using laboratory data from this study, a compressibility model was developed to predict the pore-volume compressibility, Cp, and the matrix compressibility, Cm, of coal and shale, which was applied to

  19. Hydrologic and geochemical data collected near Skewed Reservoir, an impoundment for coal-bed natural gas produced water, Powder River Basin, Wyoming

    USGS Publications Warehouse

    Healy, Richard W.; Rice, Cynthia A.; Bartos, Timothy T.

    2012-01-01

    The Powder River Structural Basin is one of the largest producers of coal-bed natural gas (CBNG) in the United States. An important environmental concern in the Basin is the fate of groundwater that is extracted during CBNG production. Most of this produced water is disposed of in unlined surface impoundments. A 6-year study of groundwater flow and subsurface water and soil chemistry was conducted at one such impoundment, Skewed Reservoir. Hydrologic and geochemical data collected as part of that study are contained herein. Data include chemistry of groundwater obtained from a network of 21 monitoring wells and three suction lysimeters and chemical and physical properties of soil cores including chemistry of water/soil extracts, particle-size analyses, mineralogy, cation-exchange capacity, soil-water content, and total carbon and nitrogen content of soils.

  20. The ALMA Spectroscopic Survey in the Hubble Ultra Deep Field: Molecular Gas Reservoirs in High-redshift Galaxies

    NASA Astrophysics Data System (ADS)

    Decarli, Roberto; Walter, Fabian; Aravena, Manuel; Carilli, Chris; Bouwens, Rychard; da Cunha, Elisabete; Daddi, Emanuele; Elbaz, David; Riechers, Dominik; Smail, Ian; Swinbank, Mark; Weiss, Axel; Bacon, Roland; Bauer, Franz; Bell, Eric F.; Bertoldi, Frank; Chapman, Scott; Colina, Luis; Cortes, Paulo C.; Cox, Pierre; Gónzalez-López, Jorge; Inami, Hanae; Ivison, Rob; Hodge, Jacqueline; Karim, Alex; Magnelli, Benjamin; Ota, Kazuaki; Popping, Gergö; Rix, Hans-Walter; Sargent, Mark; van der Wel, Arjen; van der Werf, Paul

    2016-12-01

    We study the molecular gas properties of high-z galaxies observed in the ALMA Spectroscopic Survey (ASPECS) that targets an ˜1 arcmin2 region in the Hubble Ultra Deep Field (UDF), a blind survey of CO emission (tracing molecular gas) in the 3 and 1 mm bands. Of a total of 1302 galaxies in the field, 56 have spectroscopic redshifts and correspondingly well-defined physical properties. Among these, 11 have infrared luminosities {L}{IR}\\gt {10}11 {L}⊙ , i.e., a detection in CO emission was expected. Out of these, 7 are detected at various significance in CO, and 4 are undetected in CO emission. In the CO-detected sources, we find CO excitation conditions that are lower than those typically found in starburst/sub-mm galaxy/QSO environments. We use the CO luminosities (including limits for non-detections) to derive molecular gas masses. We discuss our findings in the context of previous molecular gas observations at high redshift (star formation law, gas depletion times, gas fractions): the CO-detected galaxies in the UDF tend to reside on the low-{L}{IR} envelope of the scatter in the {L}{IR}{--}{L}{CO}\\prime relation, but exceptions exist. For the CO-detected sources, we find an average depletion time of ˜1 Gyr, with significant scatter. The average molecular-to-stellar mass ratio ({M}{{H}2}/M *) is consistent with earlier measurements of main-sequence galaxies at these redshifts, and again shows large variations among sources. In some cases, we also measure dust continuum emission. On average, the dust-based estimates of the molecular gas are a factor ˜2-5× smaller than those based on CO. When we account for detections as well as non-detections, we find large diversity in the molecular gas properties of the high-redshift galaxies covered by ASPECS.

  1. 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.

  2. Andrew integrated reservoir description

    SciTech Connect

    Todd, S.P.

    1996-12-31

    The Andrew field is an oil and gas accumulation in Palaeocene deep marine sands in the Central North Sea. It is currently being developed with mainly horizontal oil producers. Because of the field`s relatively small reserves (mean 118 mmbbls), the performance of each of the 10 or so horizontal wells is highly important. Reservoir description work at sanction time concentrated on supporting the case that the field could be developed commercially with the minimum number of wells. The present Integrated Reservoir Description (IRD) is focussed on delivering the next level of detail that will impact the understanding of the local reservoir architecture and dynamic performance of each well. Highlights of Andrew IRD Include: (1) Use of a Reservoir Uncertainty Statement (RUS) developed at sanction time to focus the descriptive effort of both asset, support and contract petrotechnical staff, (2) High resolution biostratigraphic correlation to support confident zonation of the reservoir, (3) Detailed sedimentological analysis of the core including the use of dipmeter to interpret channel/sheet architecture to provide new insights into reservoir heterogeneity; (4) Integrated petrographical and petrophysical investigation of the controls on Sw-Height and relative permeability of water; (5) Fluids description using oil geochemistry and Residual Salt Analysis Sr isotope studies. Andrew IRD has highlighted several important risks to well performance, including the influence of more heterolithic intervals on gas breakthrough and the controls on water coning exerted by suppressed water relative permeability in the transition zone.

  3. Andrew integrated reservoir description

    SciTech Connect

    Todd, S.P.

    1996-01-01

    The Andrew field is an oil and gas accumulation in Palaeocene deep marine sands in the Central North Sea. It is currently being developed with mainly horizontal oil producers. Because of the field's relatively small reserves (mean 118 mmbbls), the performance of each of the 10 or so horizontal wells is highly important. Reservoir description work at sanction time concentrated on supporting the case that the field could be developed commercially with the minimum number of wells. The present Integrated Reservoir Description (IRD) is focussed on delivering the next level of detail that will impact the understanding of the local reservoir architecture and dynamic performance of each well. Highlights of Andrew IRD Include: (1) Use of a Reservoir Uncertainty Statement (RUS) developed at sanction time to focus the descriptive effort of both asset, support and contract petrotechnical staff, (2) High resolution biostratigraphic correlation to support confident zonation of the reservoir, (3) Detailed sedimentological analysis of the core including the use of dipmeter to interpret channel/sheet architecture to provide new insights into reservoir heterogeneity; (4) Integrated petrographical and petrophysical investigation of the controls on Sw-Height and relative permeability of water; (5) Fluids description using oil geochemistry and Residual Salt Analysis Sr isotope studies. Andrew IRD has highlighted several important risks to well performance, including the influence of more heterolithic intervals on gas breakthrough and the controls on water coning exerted by suppressed water relative permeability in the transition zone.

  4. Geologic, technical and economic-sensitivity analysis in support of the GRI (Gas Research Institute) tight-gas reservoirs program. Annual report, November 1985-October 1986

    SciTech Connect

    Brashear, J.P.; Haas, M.

    1987-02-01

    During 1985-86, Lewin and Associates, Inc., used the Tight Gas Analysis System (TGAS) to estimate the potential for tight gas and the effects of changes in economics, technology, and resource assessments. During the reporting period, TGAS was; (1) enhanced in its analytical capabilities in terms of fracture propagation modeling, type curve modeling, run-time efficiencies, and economics routines; (2) used to provide refined estimates of economic tight gas potential from the Travis Peak formation; and (3) used to support GRI managers in RandD planning, evaluation, and technology transfer.

  5. Optimal water resources management and system benefit for the Marcellus shale-gas reservoir in Pennsylvania and West Virginia

    NASA Astrophysics Data System (ADS)

    Cheng, Xi; He, Li; Lu, Hongwei; Chen, Yizhong; Ren, Lixia

    2016-09-01

    A major concern associated with current shale-gas extraction is high consumption of water resources. However, decision-making problems regarding water consumption and shale-gas extraction have not yet been solved through systematic approaches. This study develops a new bilevel optimization problem based on goals at two different levels: minimization of water demands at the lower level and maximization of system benefit at the upper level. The model is used to solve a real-world case across Pennsylvania and West Virginia. Results show that surface water would be the largest contributor to gas production (with over 80.00% from 2015 to 2030) and groundwater occupies for the least proportion (with less than 2.00% from 2015 to 2030) in both districts over the planning span. Comparative analysis between the proposed model and conventional single-level models indicates that the bilevel model could provide coordinated schemes to comprehensively attain the goals from both water resources authorities and energy sectors. Sensitivity analysis shows that the change of water use of per unit gas production (WU) has significant effects upon system benefit, gas production and pollutants (i.e., barium, chloride and bromide) discharge, but not significantly changes water demands.

  6. The natural chlorine cycle - Formation of the carcinogenic and greenhouse gas compound chloroform in drinking water reservoirs.

    PubMed

    Forczek, Sándor T; Pavlík, Milan; Holík, Josef; Rederer, Luděk; Ferenčík, Martin

    2016-08-01

    Chlorine cycle in natural ecosystems involves formation of low and high molecular weight organic compounds of living organisms, soil organic matter and atmospherically deposited chloride. Chloroform (CHCl3) and adsorbable organohalogens (AOX) are part of the chlorine cycle. We attempted to characterize the dynamical changes in the levels of total organic carbon (TOC), AOX, chlorine and CHCl3 in a drinking water reservoir and in its tributaries, mainly at its spring, and attempt to relate the presence of AOX and CHCl3 with meteorological, chemical or biological factors. Water temperature and pH influence the formation and accumulation of CHCl3 and affect the conditions for biological processes, which are demonstrated by the correlation between CHCl3 and ΣAOX/Cl(-) ratio, and also by CHCl3/ΣAOX, CHCl3/AOXLMW, CHCl3/ΣTOC, CHCl3/TOCLMW and CHCl3/Cl(-) ratios in different microecosystems (e.g. old spruce forest, stagnant acidic water, humid and warm conditions with high biological activity). These processes start with the biotransformation of AOX from TOC, continue via degradation of AOX to smaller molecules and further chlorination, and finish with the formation of small chlorinated molecules, and their subsequent volatilization and mineralization. The determined concentrations of chloroform result from a dynamic equilibrium between its formation and degradation in the water; in the Hamry water reservoir, this results in a total amount of 0.1-0.7 kg chloroform and 5.2-15.4 t chloride. The formation of chloroform is affected by Cl(-) concentration, by concentrations and ratios of biogenic substrates (TOC and AOX), and by the ratios of the substrates and the product (feedback control by chloroform itself).

  7. 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.

  8. 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

  9. SMALL, GEOLOGICALLY COMPLEX RESERVOIRS CAN BENEFIT FROM RESERVOIR SIMULATION

    SciTech Connect

    Richard E. Bennett

    2002-06-24

    The Cascade Sand zone of the Mission-Visco Lease in the Cascade Oil field of Los Angeles County, California, has been under water flood since 1970. Increasing water injection to increase oil production rates was being considered as an opportunity to improve oil recovery. However, a secondary gas cap had formed in the up-dip portion of the reservoir with very low gas cap pressures, creating concern that oil could be displaced into the gas cap resulting in the loss of recoverable oil. Therefore, injecting gas into the gas cap to keep the gas cap pressurized and restrict the influx of oil during water injection was also being considered. Further, it was recognized that the reservoir geology in the gas cap area is very complex with numerous folding and faulting and thus there are potential pressure barriers in several locations throughout the reservoir. With these conditions in mind, there were concerns regarding well to well continuity in the gas cap, which could interfere with the intended repressurization impact. Concerns about the pattern of gas flow from well to well, the possibilities of cycling gas without the desired increased pressure, and the possible loss of oil displaced into the gas cap resulted in the decision to conduct a gas tracer survey in an attempt to better define inter-well communication. Following the gas tracer survey, a reservoir model would be developed to integrate the findings of the gas tracer survey, known geologic and reservoir data, and historic production data. The reservoir model would be used to better define the reservoir characteristics and provide information that could help optimize the waterflood-gas injection project under consideration for efficient water and gas injection management to increase oil production. However, due to inadequate gas sampling procedures in the field and insufficiently developed laboratory analytical techniques, the laboratory was unable to detect the tracer in the gas samples taken. At that point, focus

  10. Modeling of fault activation and seismicity by injection directly into a fault zone associated with hydraulic fracturing of shale-gas reservoirs

    DOE PAGES

    Rutqvist, Jonny; Rinaldi, Antonio P.; Cappa, Frédéric; ...

    2015-03-01

    We conducted three-dimensional coupled fluid-flow and geomechanical modeling of fault activation and seismicity associated with hydraulic fracturing stimulation of a shale-gas reservoir. We simulated a case in which a horizontal injection well intersects a steeply dip- ping fault, with hydraulic fracturing channeled within the fault, during a 3-hour hydraulic fracturing stage. Consistent with field observations, the simulation results show that shale-gas hydraulic fracturing along faults does not likely induce seismic events that could be felt on the ground surface, but rather results in numerous small microseismic events, as well as aseismic deformations along with the fracture propagation. The calculated seismicmore » moment magnitudes ranged from about -2.0 to 0.5, except for one case assuming a very brittle fault with low residual shear strength, for which the magnitude was 2.3, an event that would likely go unnoticed or might be barely felt by humans at its epicenter. The calculated moment magnitudes showed a dependency on injection depth and fault dip. We attribute such dependency to variation in shear stress on the fault plane and associated variation in stress drop upon reactivation. Our simulations showed that at the end of the 3-hour injection, the rupture zone associated with tensile and shear failure extended to a maximum radius of about 200 m from the injection well. The results of this modeling study for steeply dipping faults at 1000 to 2500 m depth is in agreement with earlier studies and field observations showing that it is very unlikely that activation of a fault by shale-gas hydraulic fracturing at great depth (thousands of meters) could cause felt seismicity or create a new flow path (through fault rupture) that could reach shallow groundwater resources.« less

  11. Modeling of fault activation and seismicity by injection directly into a fault zone associated with hydraulic fracturing of shale-gas reservoirs

    SciTech Connect

    Rutqvist, Jonny; Rinaldi, Antonio P.; Cappa, Frédéric; Moridis, George J.

    2015-03-01

    We conducted three-dimensional coupled fluid-flow and geomechanical modeling of fault activation and seismicity associated with hydraulic fracturing stimulation of a shale-gas reservoir. We simulated a case in which a horizontal injection well intersects a steeply dip- ping fault, with hydraulic fracturing channeled within the fault, during a 3-hour hydraulic fracturing stage. Consistent with field observations, the simulation results show that shale-gas hydraulic fracturing along faults does not likely induce seismic events that could be felt on the ground surface, but rather results in numerous small microseismic events, as well as aseismic deformations along with the fracture propagation. The calculated seismic moment magnitudes ranged from about -2.0 to 0.5, except for one case assuming a very brittle fault with low residual shear strength, for which the magnitude was 2.3, an event that would likely go unnoticed or might be barely felt by humans at its epicenter. The calculated moment magnitudes showed a dependency on injection depth and fault dip. We attribute such dependency to variation in shear stress on the fault plane and associated variation in stress drop upon reactivation. Our simulations showed that at the end of the 3-hour injection, the rupture zone associated with tensile and shear failure extended to a maximum radius of about 200 m from the injection well. The results of this modeling study for steeply dipping faults at 1000 to 2500 m depth is in agreement with earlier studies and field observations showing that it is very unlikely that activation of a fault by shale-gas hydraulic fracturing at great depth (thousands of meters) could cause felt seismicity or create a new flow path (through fault rupture) that could reach shallow groundwater resources.

  12. ALMA hints at the existence of an unseen reservoir of diffuse molecular gas in the Galactic bulge

    NASA Astrophysics Data System (ADS)

    Gerin, M.; Liszt, H.

    2017-03-01

    Aims: We aim to understand the unexpected presence of mm-wave molecular absorption at -200 km s-1gas in the bulge and disk using circular and non-circular galactic kinematics, deriving N(H I) from a combination of 21 cm emission and absorption and we derive N(H2) from scaling of the HCO+ absorption. We then inverted the variation of near-IR reddening E(J-K) with distance modulus and scale E(J-K) to a total gas column density N(H) that may be compared to N(H I) and N(H2). Results: At galactocentric radii Rgal> 1.5 kpc, conventional measures such as the standard CO-H2 conversion factor and locally observed N(HCO+)/N(H2) ratio separately imply that H I and H2 contribute about equally to N(H), and the gas-derived N(H) values are in broad agreement with those derived from E(J-K). Within the Galactic bulge at Rgal< 1.5 kpc, H I contributes less than 10% of the material inferred from E(J-K), so that the molecular absorption detected here is needed to understand the extinction.

  13. Migration depths of juvenile Chinook salmon and steelhead relative to total dissolved gas supersaturation in a Columbia River reservoir

    USGS Publications Warehouse

    Beeman, J.W.; Maule, A.G.

    2006-01-01

    The in situ depths of juvenile salmonids Oncorhynchus spp. were studied to determine whether hydrostatic compensation was sufficient to protect them from gas bubble disease (GBD) during exposure to total dissolved gas (TDG) supersaturation from a regional program of spill at dams meant to improve salmonid passage survival. Yearling Chinook salmon O. tshawytscha and juvenile steelhead O. mykiss implanted with pressure-sensing radio transmitters were monitored from boats while they were migrating between the tailrace of Ice Harbor Dam on the Snake River and the forebay of McNary Dam on the Columbia River during 1997-1999. The TDG generally decreased with distance from the tailrace of the dam and was within levels known to cause GBD signs and mortality in laboratory bioassays. Results of repeated-measures analysis of variance indicated that the mean depths of juvenile steelhead were similar throughout the study area, ranging from 2.0 m in the Snake River to 2.3 m near the McNary Dam forebay. The mean depths of yearling Chinook salmon generally increased with distance from Ice Harbor Dam, ranging from 1.5 m in the Snake River to 3.2 m near the forebay. Juvenile steelhead were deeper at night than during the day, and yearling Chinook salmon were deeper during the day than at night. The TDG level was a significant covariate in models of the migration depth and rates of each species, but no effect of fish size was detected. Hydrostatic compensation, along with short exposure times in the area of greatest TDG, reduced the effects of TDG exposure below those generally shown to elicit GBD signs or mortality. Based on these factors, our results indicate that the TDG limits of the regional spill program were safe for these juvenile salmonids.

  14. Feasibility of ASD AgriSpec analysis to indicate mineralogy of a potential shale gas reservoir from west Lancashire, UK

    NASA Astrophysics Data System (ADS)

    Fleming, Claire; Hough, Edward; Kemp, Simon; Cave, Mark

    2016-04-01

    Mudrocks rich in organic matter present an attractive exploration target for unconventional gas and oil. The mid-Carboniferous (Visean - Bashkirian) Bowland Shale is developed in a series of fault-bound basins and is considered the principal accumulation of gas-prone shales in the UK. One risk with exploitation of shales is that the rocks may exhibit ductile behaviour and will not respond in an optimal way to hydraulic stimulation programmes. The brittle behaviour of the rock is strongly influenced by mineralogical composition. Approximately 15 m of core from the lower part of the Bowland Shale, has been used to test the feasibility of using Natural Infra-Red (NIR) Spectrometry to characterise the mineralogy of the shale, and compared to analysis using standard XRD techniques (both whole-rock and <2 micron) to confirm the mineralogical constituents of the rock. Clay mineralogy has been the main focus, as their presence within the shale may affect the 'frackability' of the shale. Clay minerals are also easily detected using NIR spectrometry as they display distinctive absorption features in the Short Wave Infrared region of the electromagnetic spectrum. The benefits of using a handheld NIR spectrometer (AgriSpec) is that it provides a rapid, non-destructive and highly portable method for characterising clay mineralogy. This method may represent a simple solution to the initial characterisation of what are challenging rocks to characterise: thick accumulations (locally in excess of 3500 m) with few marker horizons to enable correlation between basins. Results demonstrate that clay minerals such as dickite, kaolinite and smectite (as well as other characteristic minerals such as siderite; calcite and gypsum) can be identified within the Bowland Shale using this technique.

  15. 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.

  16. 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.

  17. Volatile Flux and Composition at Yellowstone Reflects a Gas-Charged Hydrothermal System Above a Basalt-Fueled Silicic Magma Reservoir

    NASA Astrophysics Data System (ADS)

    Lowenstern, J. B.; Hurwitz, S.

    2007-12-01

    Recent papers have documented the immense volatile (CO2, S, Cl-, F-) flux from the Yellowstone Caldera. Carbon dioxide is estimated to escape diffusively through soils at a rate of 45,000 t d-1 (Werner and Brantley, 2003) compared with 137 t d-1 of Cl- released from hot springs into rivers (Hurwitz and others, 2007). These high volatile fluxes and the CO2/Cl- ratio of ~300 are inconsistent with simple degassing of a mid- or upper-crustal silicic intrusion. For example, if the estimated CO2-flux were supplied solely by a 104 km3 silicic-magma reservoir with 500 ppm dissolved CO2, the reservoir would be exhausted in ~1000 years, less than 0.1% of the longevity of the present Yellowstone volcanic field. Moreover, silicate melt inclusions in phenocrysts from erupted rhyolites contain abundant dissolved Cl- and F-, but minimal CO2 and S, the dominant effluents from the hydrothermal system. The carbon budget is explained best by dominant basalt degassing (~0.3 km3 a-1 of magma) in the lower and mid- crust, augmented by metamorphic devolatilization of limestone and other sediments, plus what can be sourced from overlying rhyolitic magma. The volatiles then pass into and through the near-surface hydrothermal system. The relative abundances of emitted CO2 and Cl- appear to require that the shallow subsurface beneath Yellowstone is gas-saturated down to >2 km. Fournier (1989) concluded that the diverse Yellowstone geothermal waters are ultimately derived from a deep parent fluid with 400 ppm Cl-. If Cl- and CO2 are emitted in proportion to their abundance in the hydrothermal system, then given the CO2/Cl- of 300, this parent fluid would contain 12 wt.% CO2 (5 mol%). Solubility constraints reveal that such fluid would be saturated with CO2-rich steam within the upper few kilometers. The presence of a compressible and expandable vapor phase has important implications for the origin and interpretation of ground-surface displacements at active calderas such as Yellowstone

  18. 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.

  19. Tertiary carbonate reservoirs in Indonesia

    SciTech Connect

    Nayoan, G.A.S.; Arpandi; Siregar, M.

    1981-01-01

    Hydrocarbon production from Tertiary carbonate reservoirs accounted for ca. 10% of daily Indonesian production at the beginning of 1978. Environmentally, the reservoirs appear as parts of reef complexes and high-energy carbonate deposits within basinal areas situated mainly in the back arc of the archipelago. Good porosities of the reservoirs are represented by vugular/moldic and intergranular porosity types. The reservoirs are capable of producing prolific amounts of hydrocarbons: production tests in Salawati-Irian Jaya reaches maximum values of 32,000 bpd, and in Arun-North Sumatra tests recorded 200 MMCF gas/day. Significant hydrocarbon accumulations are related to good reservoir rocks in carbonates deposited as patch reefs, pinnacle reefs, and platform complexes. Exploration efforts expand continuously within carbonate formations which are extensive horizontally as well as vertically in the Tertiary stratigraphic column.

  20. 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] 157μm and [O i] 63μm 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

  1. Pockmarks on either side of the Strait of Gibraltar: formation from overpressured shallow contourite gas reservoirs and internal wave action during the last glacial sea-level lowstand?

    NASA Astrophysics Data System (ADS)

    León, Ricardo; Somoza, Luis; Medialdea, Teresa; González, Francisco Javier; Gimenez-Moreno, Carmen Julia; Pérez-López, Raúl

    2014-06-01

    Integrating novel and published swath bathymetry (3,980 km2), as well as chirp and high-resolution 2D seismic reflection profiles (2,190 km), this study presents the mapping of 436 pockmarks at water depths varying widely between 370 and 1,020 m on either side of the Strait of Gibraltar. On the Atlantic side in the south-eastern Gulf of Cádiz near the Camarinal Sill, 198 newly discovered pockmarks occur in three well localized and separated fields: on the upper slope ( n=14), in the main channel of the Mediterranean outflow water (MOW, n=160), and on the huge contourite levee of the MOW main channel ( n=24) near the well-known TASYO field. These pockmarks vary in diameter from 60 to 919 m, and are sub-circular to irregularly elongated or lobate in shape. Their slope angles on average range from 3° to 25°. On the Mediterranean side of the strait on the Ceuta Drift of the western Alborán Basin, where pockmarks were already known to occur, 238 pockmarks were identified and grouped into three interconnected fields, i.e. a northern ( n=34), a central ( n=61) and a southern field ( n=143). In the latter two fields the pockmarks are mainly sub-circular, ranging from 130 to 400 m in diameter with slope angles averaging 1.5° to 15°. In the northern sector, by contrast, they are elongated up to 1,430 m, probably reflecting MOW activity. Based on seismo-stratigraphic interpretation, it is inferred that most pockmarks formed during and shortly after the last glacial sea-level lowstand, as they are related to the final erosional discontinuity sealed by Holocene transgressive deposits. Combining these findings with other existing knowledge, it is proposed that pockmark formation on either side of the Strait of Gibraltar resulted from gas and/or sediment pore-water venting from overpressured shallow gas reservoirs entrapped in coarse-grained contourites of levee deposits and Pleistocene palaeochannel infillings. Venting was either triggered or promoted by hydraulic pumping

  2. 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.

  3. CO2 is dominant greenhouse gas emitted from six hydropower reservoirs in southeastern United States during peak summer emissions

    SciTech Connect

    Bevelhimer, Mark S.; Stewart, Aurthur J.; Fortner, Allison M.; Phillips, Jana Randolph; Mosher, Jennifer J.

    2016-01-06

    During August-September 2012, we sampled six hydropower reservoirs in southeastern United States. for CO2 and CH4 emissions via three pathways: diffusive emissions from water surface; ebullition in the water column; and losses from dam tailwaters during power generation. Average total emission rates of CO2 for the six reservoirs ranged from 1,127 to 2,051 mg m-2 d-1, which is low to moderate compared to CO2 emissions rates reported for tropical hydropower reservoirs and boreal ponds and lakes, and similar to rates reported for other temperate reservoirs. Similar average rates for CH4 were also relatively low, ranging from 5 to 83 mg m-2 d-1. On a whole-reservoir basis, total emissions of CO2 ranged nearly 10-fold, from ~51,000 kg per day for Fontana to ~486,000 kg per day for Guntersville, and total emissions of CH4 ranged nearly 20-fold, from ~5 kg per day for Fontana to ~83 kg per day for Allatoona. Emissions through the tailwater pathway varied among reservoirs, comprising from 20 to 50% of total CO2 emissions and 0 to 90% of CH4 emissions, depending on the reservoir. Furthermore, several explanatory factors related to reservoir morphology and water quality were considered for observed differences among reservoirs.

  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

  5. 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

  6. 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.

  7. Development of Reservoir Characterization Techniques and Production Models for Exploiting Naturally Fractured Reservoirs

    SciTech Connect

    Wiggins, Michael L.; Brown, Raymon L.; Civan, Faruk; Hughes, Richard G.

    2003-02-11

    This research was directed toward developing a systematic reservoir characterization methodology which can be used by the petroleum industry to implement infill drilling programs and/or enhanced oil recovery projects in naturally fractured reservoir systems in an environmentally safe and cost effective manner. It was anticipated that the results of this research program will provide geoscientists and engineers with a systematic procedure for properly characterizing a fractured reservoir system and a reservoir/horizontal wellbore simulator model which can be used to select well locations and an effective EOR process to optimize the recovery of the oil and gas reserves from such complex reservoir systems.

  8. 21 CFR 868.5320 - Reservoir bag.

    Code of Federal Regulations, 2014 CFR

    2014-04-01

    ... device, usually made of conductive rubber, intended for use in a breathing circuit as a reservoir for breathing gas and to assist, control, or monitor a patient's ventilation. (b) Classification. Class...

  9. 21 CFR 868.5320 - Reservoir bag.

    Code of Federal Regulations, 2011 CFR

    2011-04-01

    ... device, usually made of conductive rubber, intended for use in a breathing circuit as a reservoir for breathing gas and to assist, control, or monitor a patient's ventilation. (b) Classification. Class...

  10. 21 CFR 868.5320 - Reservoir bag.

    Code of Federal Regulations, 2010 CFR

    2010-04-01

    ... device, usually made of conductive rubber, intended for use in a breathing circuit as a reservoir for breathing gas and to assist, control, or monitor a patient's ventilation. (b) Classification. Class...

  11. 21 CFR 868.5320 - Reservoir bag.

    Code of Federal Regulations, 2012 CFR

    2012-04-01

    ... device, usually made of conductive rubber, intended for use in a breathing circuit as a reservoir for breathing gas and to assist, control, or monitor a patient's ventilation. (b) Classification. Class...

  12. 21 CFR 868.5320 - Reservoir bag.

    Code of Federal Regulations, 2013 CFR

    2013-04-01

    ... device, usually made of conductive rubber, intended for use in a breathing circuit as a reservoir for breathing gas and to assist, control, or monitor a patient's ventilation. (b) Classification. Class...

  13. Unconventional Reservoirs: Ideas to Commercialization

    NASA Astrophysics Data System (ADS)

    Tinker, S. W.

    2015-12-01

    There is no shortage of coal, oil, and natural gas in the world. What are sometimes in short supply are fresh ideas. Scientific innovation combined with continued advances in drilling and completion technology revitalized the natural gas industry in North America by making production from shale economic. Similar advances are now happening in shale oil. The convergence of ideas and technology has created a commercial environment in which unconventional reservoirs could supply natural gas to the North American consumer for 50 years or more. And, although not as far along in terms of resource development, oil from the Eagle Ford and Bakken Shales and the oil sands in Alberta could have a similar impact. Without advanced horizontal drilling, geosteering, staged hydraulic-fracture stimulation, synthetic and natural proppants, evolution of hydraulic fluid chemistry, and high-end monitoring and simulation, many of these plays would not exist. Yet drilling and completion technology cannot stand alone. Also required for success are creative thinking, favorable economics, and a tolerance for risk by operators. Current understanding and completion practices will leave upwards of 80% of oil and natural gas in the shale reservoirs. The opportunity to enhance recovery through advanced reservoir understanding and imaging, as well as through recompletions and infill drilling, is considerable. The path from ideas to commercialization will continue to provide economic results in unconventional reservoirs.

  14. Activity of sulfate-reducing bacteria under simulated reservoir conditions

    SciTech Connect

    Rosnes, J.T.; Graue, A.; Lien, T. )

    1991-05-01

    This paper reports on sulfate-reducing bacteria (SRB) that have been isolated from hot oilfield waters from subsea oil reservoirs in the North Sea. Experiments with these bacteria in a reservoir simulator indicate that SRB may maintain their activity in the conditions found in most North Sea reservoirs and, if precautions are not taken, may contribute to souring of the oil and gas.

  15. 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.

  16. 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.

  17. Geologic aspects of horizontal drilling in self-sourcing reservoirs

    SciTech Connect

    Illich, H.A. )

    1991-03-01

    Horizontal drilling techniques provide a way to exploit hydrocarbon reserves that are either noneconomic or only marginally economic using vertical drilling techniques. A significant fraction of these reserves is contained in reservoirs that are self-sourcing or in reservoirs that are closely associated with their resources. Most formations drilled as horizontal targets are self-sourcing. The Austin Chalk, Niobrara, Mesaverde, and Bakken are examples of horizontally drilled, self-sourcing reservoir systems. In formations like the Bakken or Austin Chalk, the close relationship between reservoir and source makes risks associated with migration and accumulation less important. Reservoirs of this kind can contain oil or gas and often have little or no associated water. They can be matrix-dominated reservoirs, dual-porosity reservoirs (Mesaverde), or fractured reservoirs (Austin Chalk, Bakken, and Niobrara). Fractured, self-sourcing reservoirs also can possess matrix characteristics that contribute increased recovery efficiency. Most reservoirs drilled horizontally possess matrix characteristics that contribute increased recovery efficiency. Most reservoirs drilled horizontally possess highly heterogeneous reservoir systems. Characterization of the style of reservoir heterogeneity in self-sourcing systems is important if the favorable properties of horizontally oriented bore holes are to be realized. Production data and rock mechanics considerations are important in horizontal drilling ventures. Examples of the use of these data for the purpose of defining reservoir characteristics are discussed. Knowledge of lateral changes in reservoir properties is essential if we are to recover known reserves efficiently.

  18. Oil and gas presence perspectives of weathering layer reservoir of Nurol'ka mega-basin according to data of geothermics

    NASA Astrophysics Data System (ADS)

    Luneva, T.; Lobova, G.; Fomin, A.

    2016-09-01

    Oil perspective areas of the Nurol'ka mega-basin (south-east of Western Siberia) through the M formation (Permian-Triassic weathering crust) on the basis of the results application of geothermometry were identified. Accumulating power distribution and quality of the M formation collectors were taken into account. The priority area for research are weathering layer reservoirs and its development that cover the South beads of Kulan-Igayskaya and Tamradskaya basins and its insulation joint were proposed. Glukhov's oil field that is located in this area approve its high prospectivity.

  19. 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.

  20. High-resolution reservoir characterization of midcontinent sandstones using wireline resistivity imaging, Boonsville (Bend Conglomerate) Gas Field, Fort Worth Basin, TX

    SciTech Connect

    Carr, D.L. ); Elphick, R.Y. ); Foulk, L.S. )

    1996-01-01

    In the absence of abundant core data, Formation MicroScanner* (FMS) and Fullbore Formation Microlmager* (FMI) wireline logs from 3 wells in Boonsville Field provided continuous geologic information in a 1000-foot thick, Pennsylvanian (Atoka) interval. Cores provided the most detailed sequence-stratigraphic information, but only 358 ft of core from 4 wells was available to evaluate the 30 mi[sup 2] project area. The FMS and FMI logs thus served as continuous, oriented [open quote]virtual cores[close quote] that expanded our stratigraphic database and improved our interpretations, which included the identification of key chronostratigraphic surfaces, lithofacies, sedimentary structures, faults, and fractures. Paleocurrents inferred from the FMS and FMI images suggest that most Bend Conglomerate sandstones are lowstand valley-fill deposits derived from the Muenster and Red River Uplifts, rather than Ouachita-derived deltas. Combined analysis of cores and wireline resistivity imaging technology enabled the development of a fine-scale, sequence-stratigraphic framework which formed the basis for correlation and mapping of the major Bend Conglomerate reservoir zones, and helped us to identify compartmentalization mechanisms within these complex reservoirs.

  1. High-resolution reservoir characterization of midcontinent sandstones using wireline resistivity imaging, Boonsville (Bend Conglomerate) Gas Field, Fort Worth Basin, TX

    SciTech Connect

    Carr, D.L.; Elphick, R.Y.; Foulk, L.S.

    1996-12-31

    In the absence of abundant core data, Formation MicroScanner* (FMS) and Fullbore Formation Microlmager* (FMI) wireline logs from 3 wells in Boonsville Field provided continuous geologic information in a 1000-foot thick, Pennsylvanian (Atoka) interval. Cores provided the most detailed sequence-stratigraphic information, but only 358 ft of core from 4 wells was available to evaluate the 30 mi{sup 2} project area. The FMS and FMI logs thus served as continuous, oriented {open_quote}virtual cores{close_quote} that expanded our stratigraphic database and improved our interpretations, which included the identification of key chronostratigraphic surfaces, lithofacies, sedimentary structures, faults, and fractures. Paleocurrents inferred from the FMS and FMI images suggest that most Bend Conglomerate sandstones are lowstand valley-fill deposits derived from the Muenster and Red River Uplifts, rather than Ouachita-derived deltas. Combined analysis of cores and wireline resistivity imaging technology enabled the development of a fine-scale, sequence-stratigraphic framework which formed the basis for correlation and mapping of the major Bend Conglomerate reservoir zones, and helped us to identify compartmentalization mechanisms within these complex reservoirs.

  2. 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...

  3. Acoustic monitoring of co-seismic changes in gas bubble rupture rate in a hydrothermal reservoir: field evaluation of a possible precursor and mechanism for remote seismic triggering

    NASA Astrophysics Data System (ADS)

    Crews, J. B.

    2015-12-01

    Remotely triggered seismicity is a phenomenon in which an earthquake at one location triggers others over distances up to thousands of kilometers. The mechanism by which low-amplitude dynamic oscillations of the confining stress can produce such an effect, often after a time delay of minutes-to-days, is unclear, but a concentration of remotely triggered seismic events in carbon-dioxide-rich volcanic and geothermal regions suggests that an increase in pore fluid pressure associated with the nucleation and growth of carbon-dioxide gas bubbles may reduce the effective stress in critically loaded geologic faults. While this hypothesis has been tested in bench-scale laboratory experiments, field detection of seismically initiated gas bubble growth in groundwater may provide further evidence for this remote triggering mechanism. In the present study, a hydrophone continuously records the acoustic power spectrum in CH-10B, a hydrothermal well located in Long Valley Caldera, California - a site that is susceptible to remotely seismic triggering. This well exhibits co-seismic changes in water level in response to near and distant earthquakes, including every magnitude-six or greater at any location on Earth. Exploiting the inverse relationship between gas bubble radius and the peak acoustic frequency emitted when a gas bubble ruptures, this investigation seeks to detect changes in the acoustic power spectrum arising from a shift in the size-distribution or count rate of rupturing gas bubbles, coincident with a distant earthquake. By resolving the timing and intensity of the onset of a change in gas bubble rupture rate after the passage of seismic wave from a distant source, it may be possible to establish the extent to which seismically initiated gas bubble growth contributes to co-seismic borehole water level response, pore fluid pressure perturbations, and the onset of remotely triggered seismicity.

  4. 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.

  5. Integrated management of multiple reservoir field developments

    SciTech Connect

    Lyons, S.L.; Chan, H.M.; Harper, J.L.; Boyett, B.A.; Dowson, P.R.; Bette, S.

    1995-10-01

    This paper consists of two sections. The authors first describe the coupling of a pipeline network model to a reservoir simulator and then the application of this new simulator to optimize the production strategy of two Mobil field developments. Mobil`s PEGASUS simulator is an integrated all purpose reservoir simulator that handles black-oil, compositional, faulted and naturally fractured reservoirs. The authors have extended the simulator to simultaneously model multiple reservoirs coupled with surface pipeline networks and processes. This allows them to account for the effects of geology, well placement, and surface production facilities on well deliverability in a fully integrated fashion. They have also developed a gas contract allocation system that takes the user-specified constraints, target rates and swing factors and automatically assigns rates to the individual wells of each reservoir. This algorithm calculates the overall deliverability and automatically reduces the user-specified target rates to meet the deliverability constraints. The algorithm and solution technique are described. This enhanced simulator has been applied to model a Mobil field development in the Southern Gas Basin, offshore United Kingdom, which consists of three separate gas reservoirs connected via a pipeline network. The simulator allowed the authors to accurately determine the impact on individual reservoir and total field performance by varying the development timing of these reservoirs. Several development scenarios are shown to illustrate the capabilities of PEGASUS. Another application of this technology is in the field developments in North Sumatra, Indonesia. Here the objective is to economically optimize the development of multiple fields to feed the PT Arun LNG facility. Consideration of a range of gas compositions, well productivity`s, and facilities constraints in an integrated fashion results in improved management of these assets. Model specifics are discussed.

  6. 13. Symposium on reservoir simulation: Proceedings

    SciTech Connect

    1995-12-31

    This is a conference proceedings which deals with the latest developments and trends in reservoir simulation techniques and modeling. It includes papers dealing with multiphase flow in oil and gas wells; flow calculation methods in deviated and horizontal wells; fluid flow in fractured reservoirs; and simulation techniques for enhanced recovery and well stimulation processes. Most papers provide case studies using the various computer models or computer systems, including numerous studies on parallel processing equipment.

  7. 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.

  8. 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.

  9. Prestack seismic inversion and reservoir property prediction

    NASA Astrophysics Data System (ADS)

    Chi, Xingang

    In this dissertation, I have applied the method of prestack seismic inversion with uncertainty analysis. Also, I have developed the methods of the rock physics template analysis, the fluid modulus inversion and the reservoir property inversion from AVO attributes with and without constraint to improve the technique of reservoir characterization. I use the prestack seismic inversion to invert the elastic properties and use the statistical method to derive the posterior probability of the inverted elastic properties for the uncertainty analysis. I use the rock physics template drawn in the cross-plot of the inverted elastic properties to analyze the lithology and fluid property in the target reservoir. I develop the fluid modulus inversion method based on the simplified Gassmann's equation and the empirical rock physics relationship. Using the inverted fluid modulus, I estimate the gas saturation of the target reservoir before drilling. The reservoir property inversion is to predict the porosity, shale volume and water saturation of the reservoir from AVO attributes to enhance the reservoir interpretation and characterization. I apply this method with the statistical analysis together to execute the uncertainty analysis for the inversion results. Two methods of reservoir property inversion from AVO attributes are attempted in this dissertation: one is performed without constraint and the other is performed with the constrained relationship of the porosity and shale volume.

  10. 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.

  11. Ultra trace determination of fluorobenzoic acids in tap and reservoir water using solid-phase extraction and gas chromatography-mass spectrometry.

    PubMed

    Müller, Karsten; Seubert, Andreas

    2012-10-19

    A method for the ultra trace analysis of 21 fluorobenzoic acids (FBAs) via GC-MS based on solid-phase extraction (SPE) and derivatization with BF3·MeOH is described. All fluorobenzoic acids were enriched and determined simultaneously. Solid-phase extraction on hydrophilic-lipophilic-balanced reversed-phase cartridges containing a poly(divinylbenzene-co-N-vinylpyrrolidone) polymer allowed a 250-fold enrichment of the acids if 100mL sample volume is used with extraction efficiencies between 71% and 94%. The method enables the determination of fluorobenzoic acid methyl esters (FBAMEs) down to the range of 6-44 ng L(-1) combined with a fast and easy sample-preparation (pH-adjusting prior to SPE and derivatization within 24 h at 64 °C directly in the vial). It uses low amounts of chemicals and is adaptable to larger and smaller sample volumes. Simultaneous extraction and determination of 21 fluorinated aromatic acids in reservoir samples with high salinity confirmed the applicability and reproducibility of the method.

  12. Integration of reservoir simulation and geomechanics

    NASA Astrophysics Data System (ADS)

    Zhao, Nan

    Fluid production from tight and shale gas formations has increased significantly, and this unconventional portfolio of low-permeability reservoirs accounts for more than half of the gas produced in the United States. Stimulation and hydraulic fracturing are critical in making these systems productive, and hence it is important to understand the mechanics of the reservoir. When modeling fractured reservoirs using discrete-fracture network representation, the geomechanical effects are expected to have a significant impact on important reservoir characteristics. It has become more accepted that fracture growth, particularly in naturally fractured reservoirs with extremely low permeability, cannot be reliably represented by conventional planar representations. Characterizing the evolution of multiple, nonplanar, interconnected and possibly nonvertical hydraulic fractures requires hydraulic and mechanical characterization of the matrix, as well as existing latent or healed fracture networks. To solve these challenging problems, a reservoir simulator (Advanced Reactive Transport Simulator (ARTS)) capable of performing unconventional reservoir simulation is developed in this research work. A geomechanical model has been incorporated into the simulation framework with various coupling schemes and this model is used to understand the geomechanical effects in unconventional oil and gas recovery. This development allows ARTS to accept geomechanical information from external geomechanical simulators (soft coupling) or the solution of the geomechanical coupled problem (hard coupling). An iterative solution method of the flow and geomechanical equations has been used in implementing the hard coupling scheme. The hard coupling schemes were verified using one-dimensional and two-dimensional analytical solutions. The new reservoir simulator is applied to learn the influence of geomechanical impact on unconventional oil and gas production in a number of practical recovery scenarios

  13. 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

  14. 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.

  15. 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.

  16. 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.

  17. Hydrophobic liquid/gas separator for heat pipes

    NASA Technical Reports Server (NTRS)

    Marcus, B. D.

    1972-01-01

    Perforated nonwetting plug of material such as polytetrafluoroethylene is mounted in gas reservoir feed tube, preferably at end which extends into heat pipe condenser section, to prevent liquid from entering gas reservoir of passively controlled heat pipe.

  18. 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.

  19. 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.

  20. 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.

  1. 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.

  2. The Ahuachapan geothermal field, El Salvador: Reservoir analysis

    SciTech Connect

    Aunzo, Z.; Bodvarsson, G.S.; Laky, C.; Lippmann, M.J.; Steingrimsson, B.; Truesdell, A.H.; Witherspoon, P.A.; Icelandic National Energy Authority, Reykjavik; Geological Survey, Menlo Park, CA; Lawrence Berkeley Lab., CA )

    1989-08-01

    These are appendices F through I of the Ahuachapan Geothermal Field Reservoir Analysis. The volume contains: well logs, water chemistry plots, gas chemistry plots, temperature plots, and flow plots. (JEF)

  3. 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.

  4. 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.

  5. 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.

  6. 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... SHELF Oil and 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...

  7. 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...

  8. 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...

  9. 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...

  10. 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...

  11. 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

  12. 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)

  13. 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

  14. 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

  15. 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

  16. Geophysical monitoring in a hydrocarbon reservoir

    NASA Astrophysics Data System (ADS)

    Caffagni, Enrico; Bokelmann, Goetz

    2016-04-01

    Extraction of hydrocarbons from reservoirs demands ever-increasing technological effort, and there is need for geophysical monitoring to better understand phenomena occurring within the reservoir. Significant deformation processes happen when man-made stimulation is performed, in combination with effects deriving from the existing natural conditions such as stress regime in situ or pre-existing fracturing. Keeping track of such changes in the reservoir is important, on one hand for improving recovery of hydrocarbons, and on the other hand to assure a safe and proper mode of operation. Monitoring becomes particularly important when hydraulic-fracturing (HF) is used, especially in the form of the much-discussed "fracking". HF is a sophisticated technique that is widely applied in low-porosity geological formations to enhance the production of natural hydrocarbons. In principle, similar HF techniques have been applied in Europe for a long time in conventional reservoirs, and they will probably be intensified in the near future; this suggests an increasing demand in technological development, also for updating and adapting the existing monitoring techniques in applied geophysics. We review currently available geophysical techniques for reservoir monitoring, which appear in the different fields of analysis in reservoirs. First, the properties of the hydrocarbon reservoir are identified; here we consider geophysical monitoring exclusively. The second step is to define the quantities that can be monitored, associated to the properties. We then describe the geophysical monitoring techniques including the oldest ones, namely those in practical usage from 40-50 years ago, and the most recent developments in technology, within distinct groups, according to the application field of analysis in reservoir. This work is performed as part of the FracRisk consortium (www.fracrisk.eu); this project, funded by the Horizon2020 research programme, aims at helping minimize the

  17. Reservoir Inflation Schedule

    SciTech Connect

    Ponden, Raymond F.

    1991-11-22

    Inflation of the reservoir is to begin on Friday afternoon, November 22 and continue through mid day on Monday, November 25. Inflation of the reservoir shall be accomplished by using only injection pump, HP-2. NOTE: Under no circumstances should injection pump, HP-1 be operated.

  18. Integrated reservoir studies enhance well completions

    SciTech Connect

    Jordan, J.S.; Aud, W.W.; Burns, R.

    1998-03-16

    Integrated reservoir studies, together with modern completion and stimulation techniques, enhance well productivity while lowering completion costs. Results from different areas show that this approach increased productivity from 40% to 100% over previous applied methods. These approaches incorporate detailed production response characterization with a technical examination of past completion and stimulation practices to: Quantify the effectiveness of prior completion methods; Customize completions by specifically tailoring stimulation procedures to match the individual reservoir with its specific producing and fracturing idiosyncrasies. Two case histories, the Deep Red Fork (oil) formation of Oklahoma and the Haynesville (natural gas) formation of Louisiana, are used to illustrate the method.

  19. Geothermal reservoir engineering research

    NASA Technical Reports Server (NTRS)

    Ramey, H. J., Jr.; Kruger, P.; Brigham, W. E.; London, A. L.

    1974-01-01

    The Stanford University research program on the study of stimulation and reservoir engineering of geothermal resources commenced as an interdisciplinary program in September, 1972. The broad objectives of this program have been: (1) the development of experimental and computational data to evaluate the optimum performance of fracture-stimulated geothermal reservoirs; (2) the development of a geothermal reservoir model to evaluate important thermophysical, hydrodynamic, and chemical parameters based on fluid-energy-volume balances as part of standard reservoir engineering practice; and (3) the construction of a laboratory model of an explosion-produced chimney to obtain experimental data on the processes of in-place boiling, moving flash fronts, and two-phase flow in porous and fractured hydrothermal reservoirs.

  20. Production-induced changes in reservoir geomechanics

    NASA Astrophysics Data System (ADS)

    Amoyedo, Sunday O.

    application in reservoir monitoring, typically in gas reservoirs and reservoirs used for CO2 sequestration. There is little or no application yet in oil-bearing reservoir monitoring, due in part to the low density contrast between oil and brine and the high acquisition cost associated with the required survey grid closely spaced. In this study, I model the 4D gravity anomaly over Forties Field. Forties Field 4D gravity model results show that a significant increase in water saturation (10--15%) is required to produce a resolvable 4D gravity anomaly. I observe that time-lapse gravity anomalies can provide vital clues to reservoir compartmentalization and by-passed oil when the saturation change is on the order of 10% or more. Reservoir subsidence can also give rise to a significant 4D gravimetric anomaly. I observe a decreasing resolution of such compaction anomalies as water saturation increases.

  1. Naturally fractured tight gas reservoirs detection optimization

    SciTech Connect

    Hoekstra, P.

    1995-04-01

    This contract is a joint project between METC and Louisiana Land and Exploration, planned to extend for 3 years. Substantial help and key information has been provided at the field by the owner/operator. All their well logs, cores, production data, geologic data, and geophysical data are available for study in this project. Their commitment in this technology development is demonstrated by their proposed contribution in the form of cost sharing: (1) obtaining the P-Wave (compressional wave) 3-D survey, (2) furnishing a borehole in which to acquire the 9-C vertical seismic profile (VSP), and (3) drilling and completing a test well for verification of the seismic anomaly. Also of significance is the direct involvement and participation of their professional staff. This staff has been responsible for generating and maintaining the database at the field and will form part of the team which evaluates the seismic data`s findings.

  2. 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.

  3. Naturally fractured tight gas reservoir detection optimization

    SciTech Connect

    1998-09-30

    The work plan for the quarter of October 1, 1997--December 31, 1997 consisted of two tasks: (1) Present results of Rulison field test at various conferences, seminars, and to Barrett Resources and Snyder Oil Co. and (2) Continue work into developing a predictive quantitative method for locating fault-related natural fractures. The first task was completed during this reporting period. The second task continues the beginning of quantitative fracture mechanics analysis of the geologic processes that are involved for the development of fault-related natural fractures. The goal of this work is to develop a predictive capability of locating natural fractures prior to drilling.

  4. Reservoir Temperature Estimator

    SciTech Connect

    Palmer, Carl D.

    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.

  5. 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.

  6. 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.

  7. Geysers reservoir studies

    SciTech Connect

    Bodvarsson, G.S.; Lippmann, M.J.; Pruess, K. )

    1993-01-01

    Lawrence Berkeley Laboratory is conducting several research projects related to issues of interest to The Geysers operators, including those that deal with understanding the nature of vapor-dominated systems, measuring or inferring reservoir processes and parameters, and studying the effects of liquid injection. All of these topics are directly or indirectly relevant to the development of reservoir strategies aimed at stabilizing or increasing production rates of non-corrosive steam, low in non-condensable gases. Three reservoir engineering studies are described in some detail, that is: (a) Modeling studies of heat transfer and phase distribution in two-phase geothermal reservoirs; (b) Numerical modeling studies of Geysers injection experiments; and (c) Development of a dual-porosity model to calculate mass flow between rock matrix blocks and neighboring fractures.

  8. 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

  9. 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

  10. Geothermal reservoir simulation

    NASA Technical Reports Server (NTRS)

    Mercer, J. W., Jr.; Faust, C.; Pinder, G. F.

    1974-01-01

    The prediction of long-term geothermal reservoir performance and the environmental impact of exploiting this resource are two important problems associated with the utilization of geothermal energy for power production. Our research effort addresses these problems through numerical simulation. Computer codes based on the solution of partial-differential equations using finite-element techniques are being prepared to simulate multiphase energy transport, energy transport in fractured porous reservoirs, well bore phenomena, and subsidence.

  11. 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. W