WorldWideScience

Sample records for hydrocarbon reservoir rocks

  1. Imaging fluid/solid interactions in hydrocarbon reservoir rocks.

    Science.gov (United States)

    Uwins, P J; Baker, J C; Mackinnon, I D

    1993-08-01

    The environmental scanning electron microscope (ESEM) has been used to image liquid hydrocarbons in sandstones and oil shales. Additionally, the fluid sensitivity of selected clay minerals in hydrocarbon reservoirs was assessed via three case studies: HCl acid sensitivity of authigenic chlorite in sandstone reservoirs, freshwater sensitivity of authigenic illite/smectite in sandstone reservoirs, and bleach sensitivity of a volcanic reservoir containing abundant secondary chlorite/corrensite. The results showed the suitability of using ESEM for imaging liquid hydrocarbon films in hydrocarbon reservoirs and the importance of simulating in situ fluid-rock interactions for hydrocarbon production programmes. In each case, results of the ESEM studies greatly enhanced prediction of reservoir/borehole reactions and, in some cases, contradicted conventional wisdom regarding the outcome of potential engineering solutions.

  2. Impact of rock salt creep law choice on subsidence calculations for hydrocarbon reservoirs overlain by evaporite caprocks

    NARCIS (Netherlands)

    Marketos, G.; Spiers, C.J.; Govers, R.

    2016-01-01

    Accurate forward modeling of surface subsidence above producing hydrocarbons reservoirs requires an understanding of the mechanisms determining how ground deformation and subsidence evolve. Here we focus entirely on rock salt, which overlies a large number of reservoirs worldwide, and specifically

  3. Gamma ray spectrometry logs as a hydrocarbon indicator for clastic reservoir rocks in Egypt

    International Nuclear Information System (INIS)

    Al-Alfy, I.M.; Nabih, M.A.; Eysa, E.A.

    2013-01-01

    Petroleum oil is an important source for the energy in the world. The Gulf of Suez, Nile Delta and South Valley are important regions for studying hydrocarbon potential in Egypt. A thorium normalization technique was applied on the sandstone reservoirs in the three regions to determine the hydrocarbon potentialities zones using the three spectrometric radioactive gamma ray-logs (eU, eTh and K% logs). The conventional well logs (gamma-ray, deep resistivity, shallow resistivity, neutron, density and sonic logs) are analyzed to determine the net pay zones in these wells. Indices derived from thorium normalized spectral logs indicate the hydrocarbon zones in petroleum reservoirs. The results of this technique in the three regions (Gulf of Suez, Nile Delta and South Valley) are in agreement with the results of the conventional well log analyses by ratios of 82%, 78% and 71% respectively. - Highlights: ► The positive DRAD values indicate the hydrocarbon zones in petroleum reservoirs. ► Thorium normalization was applied to determine the hydrocarbon potentialities. ► The conventional well logs are analyzed to determine the net pay zones in wells. ► Determining hydrocarbon potentialities zones using spectrometric gamma-ray logs

  4. Gamma ray spectrometry logs as a hydrocarbon indicator for clastic reservoir rocks in Egypt.

    Science.gov (United States)

    Al-Alfy, I M; Nabih, M A; Eysa, E A

    2013-03-01

    Petroleum oil is an important source for the energy in the world. The Gulf of Suez, Nile Delta and South Valley are important regions for studying hydrocarbon potential in Egypt. A thorium normalization technique was applied on the sandstone reservoirs in the three regions to determine the hydrocarbon potentialities zones using the three spectrometric radioactive gamma ray-logs (eU, eTh and K% logs). The conventional well logs (gamma-ray, deep resistivity, shallow resistivity, neutron, density and sonic logs) are analyzed to determine the net pay zones in these wells. Indices derived from thorium normalized spectral logs indicate the hydrocarbon zones in petroleum reservoirs. The results of this technique in the three regions (Gulf of Suez, Nile Delta and South Valley) are in agreement with the results of the conventional well log analyses by ratios of 82%, 78% and 71% respectively. Crown Copyright © 2012. Published by Elsevier Ltd. All rights reserved.

  5. Hydrocarbon Potential in Sandstone Reservoir Isolated inside Low Permeability Shale Rock (Case Study: Beruk Field, Central Sumatra Basin)

    Science.gov (United States)

    Diria, Shidqi A.; Musu, Junita T.; Hasan, Meutia F.; Permono, Widyo; Anwari, Jakson; Purba, Humbang; Rahmi, Shafa; Sadjati, Ory; Sopandi, Iyep; Ruzi, Fadli

    2018-03-01

    Upper Red Bed, Menggala Formation, Bangko Formation, Bekasap Formation and Duri Formationare considered as the major reservoirs in Central Sumatra Basin (CSB). However, Telisa Formation which is well-known as seal within CSB also has potential as reservoir rock. Field study discovered that lenses and layers which has low to high permeability sandstone enclosed inside low permeability shale of Telisa Formation. This matter is very distinctive and giving a new perspective and information related to the invention of hydrocarbon potential in reservoir sandstone that isolated inside low permeability shale. This study has been conducted by integrating seismic data, well logs, and petrophysical data throughly. Facies and static model are constructed to estimate hydrocarbon potential resource. Facies model shows that Telisa Formation was deposited in deltaic system while the potential reservoir was deposited in distributary mouth bar sandstone but would be discontinued bedding among shale mud-flat. Besides, well log data shows crossover between RHOB and NPHI, indicated that distributary mouth bar sandstone is potentially saturated by hydrocarbon. Target area has permeability ranging from 0.01-1000 mD, whereas porosity varies from 1-30% and water saturation varies from 30-70%. The hydrocarbon resource calculation approximates 36.723 MSTB.

  6. Variations of the petrophysical properties of rocks with increasing hydrocarbons content and their implications at larger scale: insights from the Majella reservoir (Italy)

    Science.gov (United States)

    Trippetta, Fabio; Ruggieri, Roberta; Lipparini, Lorenzo

    2016-04-01

    Crustal processes such as deformations or faulting are strictly related to the petrophysical properties of involved rocks. These properties depend on mineral composition, fabric, pores and any secondary features such as cracks or infilling material that may have been introduced during the whole diagenetic and tectonic history of the rock. In this work we investigate the role of hydrocarbons (HC) in changing the petrophysical properties of rock by merging laboratory experiments, well data and static models focusing on the carbonate-bearing Majella reservoir. This reservoir represent an interesting analogue for the several oil fields discovered in the subsurface in the region, allowing a comparison of a wide range of geological and geophysical data at different scale. The investigated lithology is made of high porosity ramp calcarenites, structurally slightly affected by a superimposed fracture system and displaced by few major normal faults, with some minor strike-slip movements. Sets of rock specimens were selected in the field and in particular two groups were investigated: 1. clean rocks (without oil) and 2. HC bearing rocks (with different saturations). For both groups, density, porosity, P and S wave velocity, permeability and elastic moduli measurements at increasing confining pressure were conducted on cylindrical specimens at the HP-HT Laboratory of the Istituto Nazionale di Geofisica e Vulcanologia (INGV) in Rome, Italy. For clean samples at ambient pressure, laboratory porosity varies from 10 % up to 26 % and P wave velocity (Vp) spans from 4,1 km/s to 4,9 km/s and a very good correlation between Vp, Vs and porosity is observed. The P wave velocity at 100 MPa of confining pressure, ranges between 4,5 km/s and 5,2 km/s with a pressure independent Vp/Vs ratio of about 1,9. The presence of HC within the samples affects both Vp and Vs. In particular velocities increase with the presence of hydrocarbons proportionally respect to the amount of the filled

  7. Gas sealing efficiency of cap rocks. Pt. 1: Experimental investigations in pelitic sediment rocks. - Pt. 2: Geochemical investigations on redistribution of volatile hydrocarbons in the overburden of natural gas reservoirs; Gas sealing efficiency of cap rocks. T. 1: Experimentelle Untersuchungen in pelitischen Sedimentgesteinen. - T.2: Geochemische Untersuchungen zur Umverteilung leichtfluechtiger Kohlenwasserstoffe in den Deckschichten von Erdgaslagerstaetten. Abschlussbericht

    Energy Technology Data Exchange (ETDEWEB)

    Leythaeuser; Konstanty, J.; Pankalla, F.; Schwark, L.; Krooss, B.M.; Ehrlich, R.; Schloemer, S.

    1997-09-01

    New methods and concepts for the assessment of sealing properties of cap rocks above natural gas reservoirs and of the migration behaviour of low molecular-weight hydrocarbons in sedimentary basins were developed and tested. The experimental work comprised the systematic assesment of gas transport parameters on representative samples of pelitic rocks at elevated pressure and temperature conditions, and the characterization of their sealing efficiency as cap rocks overlying hydrocarbon accumulations. Geochemical case histories were carried out to analyse the distribution of low molecular-weight hydrocarbons in the overburden of known natural gas reservoirs in NW Germany. The results were interpreted with respect to the sealing efficiency of individual cap rock lithologies and the type and extent of gas losses. (orig.) [Deutsch] Zur Beurteilung der Abdichtungseigenschaften von Caprocks ueber Gaslagerstaetten und des Migrationsverhaltens niedrigmolekularer Kohlenwasserstoffe in Sedimentbecken wurden neue Methoden und Konzepte entwickelt und angewendet. In experimentellen Arbeiten erfolgte die systematische Bestimmung von Gas-Transportparametern an repraesentativen Proben pelitischer Gesteine unter erhoehten Druck- und Temperaturbedingungen und die Charakterisierung ihrer Abdichtungseffizienz als Deckschicht ueber Kohlenwasserstofflagerstaetten. In geochemischen Fallstudien wurde die Verteilung niedrigmolekularer Kohlenwasserstoffe in den Deckschichten ueber bekannten Erdgaslagerstaetten in NW-Deutschland analysiert und im Hinblick auf die Abdichtungseffizienz einzelner Caprock-Lithologien bzw. Art und Ausmass von Gasverlusten interpretiert. (orig.)

  8. Petroleum geochemical responses to reservoir rock properties

    Energy Technology Data Exchange (ETDEWEB)

    Bennett, B.; Larter, S.R. [Calgary Univ., AB (Canada)

    2008-07-01

    Reservoir geochemistry is used to study petroleum basin development, petroleum mixing, and alterations. In this study, polar non-hydrocarbons were used as proxies for describing reservoir properties sensitive to fluid-rock interactions. A core flood experiment was conducted on a Carboniferous siltstone core obtained from a site in the United Kingdom. Core samples were then obtained from a typical upper shoreface in a North Sea oilfield. The samples were extracted with a dichloromethane and methanol mixture. Alkylcarbazoles and alkylfluorenones were then isolated from the samples. Compositional changes along the core were also investigated. Polar non hydrocarbons were studied using a wireline gamma ray log. The strongest deflections were observed in the basal coarsening upwards unit. The study demonstrated the correlations between molecular markers, and indicated that molecular parameters can be used to differentiate between clean sand units and adjacent coarsening upward muddy sand sequences. It was concluded that reservoir geochemical parameters can provide an independent response to properties defined by petrophysical methods. 6 refs., 2 figs.

  9. Source rock hydrocarbons. Present status

    International Nuclear Information System (INIS)

    Vially, R.; Maisonnier, G.; Rouaud, T.

    2013-01-01

    This report first presents the characteristics of conventional oil and gas system, and the classification of liquid and gaseous non conventional hydrocarbons, with the peculiar case of coal-bed methane. The authors then describe how source rock hydrocarbons are produced: production of shale oils and gases (horizontal drilling, hydraulic fracturing, exploitation) and of coal-bed methane and coal mine methane. In the next part, they address and discuss the environmental impact of source rock hydrocarbon production: installation footprint, water resource management, drilling fluids, fracturing fluids composition, toxicity and recycling, air pollution, induced seismicity, pollutions from other exploitation and production activities. They propose an overview of the exploitation and production of source rock gas, coal-bed gas and other non conventional gases in the world. They describe the current development and discuss their economic impacts: world oil context and trends in the USA, in Canada and other countries, impacts on the North American market, on the world oil industry, on refining industries, on the world oil balance. They analyse the economic impacts of non conventional gases: development potential, stakes for the world gas trade, consequence for gas prices, development opportunities for oil companies and for the transport sector, impact on CO 2 emissions, macro-economic impact in the case of the USA

  10. Potential Development of Hydrocarbon in Basement Reservoirs In Indonesia

    Directory of Open Access Journals (Sweden)

    D. Sunarjanto

    2014-07-01

    Full Text Available DOI: 10.17014/ijog.v8i3.165Basement rocks, in particular igneous and metamorphic rocks are known to have porosity and permeability which should not be ignored. Primary porosity of basement rocks occurs as the result of rock formation. The porosity increases by the presence of cracks occurring as the result of tectonic processes (secondary porosity. Various efforts have been carried out to explore hydrocarbon in basement rocks. Some oil and gas fields proved that the basement rocks are as reservoirs which so far have provided oil and gas in significant amount. A review using previous research data, new data, and observation of igneous rocks in some fields has been done to see the development of exploration and basement reservoirs in Indonesia. A review on terminology of basement rock up till the identification of oil and gas exploration in basement rocks need to be based on the latest technology. An environmental approach is suggested to be applied as an alternative in analyzing the policy on oil and gas exploration development, especially in basement reservoirs.

  11. Direct hydrocarbon exploration and gas reservoir development technology

    Energy Technology Data Exchange (ETDEWEB)

    Kwak, Young Hoon; Oh, Jae Ho; Jeong, Tae Jin [Korea Inst. of Geology Mining and Materials, Taejon (Korea, Republic of); and others

    1995-12-01

    In order to enhance the capability of petroleum exploration and development techniques, three year project (1994 - 1997) was initiated on the research of direct hydrocarbon exploration and gas reservoir development. This project consists of four sub-projects. (1) Oil(Gas) - source rock correlation technique: The overview of bio-marker parameters which are applicable to hydrocarbon exploration has been illustrated. Experimental analysis of saturated hydrocarbon and bio-markers of the Pohang E and F core samples has been carried out. (2) Study on surface geochemistry and microbiology for hydrocarbon exploration: the test results of the experimental device for extraction of dissolved gases from water show that the device can be utilized for the gas geochemistry of water. (3) Development of gas and gas condensate reservoirs: There are two types of reservoir characterization. For the reservoir formation characterization, calculation of conditional simulation was compared with that of unconditional simulation. In the reservoir fluid characterization, phase behavior calculations revealed that the component grouping is more important than the increase of number of components. (4) Numerical modeling of seismic wave propagation and full waveform inversion: Three individual sections are presented. The first one is devoted to the inversion theory in general sense. The second and the third sections deal with the frequency domain pseudo waveform inversion of seismic reflection data and refraction data respectively. (author). 180 refs., 91 figs., 60 tabs.

  12. Geophysical monitoring in a hydrocarbon reservoir

    Science.gov (United States)

    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

  13. Enhanced characterization of reservoir hydrocarbon components using electromagnetic data attributes

    KAUST Repository

    Katterbauer, Klemens

    2015-12-23

    Advances in electromagnetic imaging techniques have led to the growing utilization of this technology for reservoir monitoring and exploration. These exploit the strong conductivity contrast between the hydrocarbon and water phases and have been used for mapping water front propagation in hydrocarbon reservoirs and enhancing the characterization of the reservoir formation. The conventional approach for the integration of electromagnetic data is to invert the data for saturation properties and then subsequently use the inverted properties as constraints in the history matching process. The non-uniqueness and measurement errors may however make this electromagnetic inversion problem strongly ill-posed, leading to potentially inaccurate saturation profiles. Another limitation of this approach is the uncertainty of Archie\\'s parameters in relating rock conductivity to water saturation, which may vary in the reservoir and are generally poorly known. We present an Ensemble Kalman Filter framework for efficiently integrating electromagnetic data into the history matching process and for simultaneously estimating the Archie\\'s parameters and the variance of the observation error of the electromagnetic data. We apply the proposed framework to a compositional reservoir model. We aim at assessing the relevance of EM data for estimating the different hydrocarbon components of the reservoir. The experimental results demonstrate that the individual hydrocarbon components are generally well matched, with nitrogen exhibiting the strongest improvement. The estimated observation error standard deviations are also within expected levels (between 5 and 10%), significantly contributing to the robustness of the proposed EM history matching framework. Archie\\'s parameter estimates approximate well the reference profile and assist in the accurate description of the electrical conductivity properties of the reservoir formation, hence leading to estimation accuracy improvements of around

  14. Enhanced characterization of reservoir hydrocarbon components using electromagnetic data attributes

    KAUST Repository

    Katterbauer, Klemens; Arango, Santiago; Sun, Shuyu; Hoteit, Ibrahim

    2015-01-01

    Advances in electromagnetic imaging techniques have led to the growing utilization of this technology for reservoir monitoring and exploration. These exploit the strong conductivity contrast between the hydrocarbon and water phases and have been used for mapping water front propagation in hydrocarbon reservoirs and enhancing the characterization of the reservoir formation. The conventional approach for the integration of electromagnetic data is to invert the data for saturation properties and then subsequently use the inverted properties as constraints in the history matching process. The non-uniqueness and measurement errors may however make this electromagnetic inversion problem strongly ill-posed, leading to potentially inaccurate saturation profiles. Another limitation of this approach is the uncertainty of Archie's parameters in relating rock conductivity to water saturation, which may vary in the reservoir and are generally poorly known. We present an Ensemble Kalman Filter framework for efficiently integrating electromagnetic data into the history matching process and for simultaneously estimating the Archie's parameters and the variance of the observation error of the electromagnetic data. We apply the proposed framework to a compositional reservoir model. We aim at assessing the relevance of EM data for estimating the different hydrocarbon components of the reservoir. The experimental results demonstrate that the individual hydrocarbon components are generally well matched, with nitrogen exhibiting the strongest improvement. The estimated observation error standard deviations are also within expected levels (between 5 and 10%), significantly contributing to the robustness of the proposed EM history matching framework. Archie's parameter estimates approximate well the reference profile and assist in the accurate description of the electrical conductivity properties of the reservoir formation, hence leading to estimation accuracy improvements of around 15%.

  15. Seismic Evaluation of Hydrocarbon Saturation in Deep-Water Reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Michael Batzle

    2006-04-30

    During this last period of the ''Seismic Evaluation of Hydrocarbon Saturation in Deep-Water Reservoirs'' project (Grant/Cooperative Agreement DE-FC26-02NT15342), we finalized integration of rock physics, well log analysis, seismic processing, and forward modeling techniques. Most of the last quarter was spent combining the results from the principal investigators and come to some final conclusions about the project. Also much of the effort was directed towards technology transfer through the Direct Hydrocarbon Indicators mini-symposium at UH and through publications. As a result we have: (1) Tested a new method to directly invert reservoir properties, water saturation, Sw, and porosity from seismic AVO attributes; (2) Constrained the seismic response based on fluid and rock property correlations; (3) Reprocessed seismic data from Ursa field; (4) Compared thin layer property distributions and averaging on AVO response; (5) Related pressures and sorting effects on porosity and their influence on DHI's; (6) Examined and compared gas saturation effects for deep and shallow reservoirs; (7) Performed forward modeling using geobodies from deepwater outcrops; (8) Documented velocities for deepwater sediments; (9) Continued incorporating outcrop descriptive models in seismic forward models; (10) Held an open DHI symposium to present the final results of the project; (11) Relations between Sw, porosity, and AVO attributes; (12) Models of Complex, Layered Reservoirs; and (14) Technology transfer Several factors can contribute to limit our ability to extract accurate hydrocarbon saturations in deep water environments. Rock and fluid properties are one factor, since, for example, hydrocarbon properties will be considerably different with great depths (high pressure) when compared to shallow properties. Significant over pressure, on the other hand will make the rocks behave as if they were shallower. In addition to the physical properties, the scale and

  16. Adsorption of hydrocarbons in chalk reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Madsen, L.

    1996-12-31

    The present work is a study on the wettability of hydrocarbon bearing chalk reservoirs. Wettability is a major factor that influences flow, location and distribution of oil and water in the reservoir. The wettability of the hydrocarbon reservoirs depends on how and to what extent the organic compounds are adsorbed onto the surfaces of calcite, quartz and clay. Organic compounds such as carboxylic acids are found in formation waters from various hydrocarbon reservoirs and in crude oils. In the present investigation the wetting behaviour of chalk is studied by the adsorption of the carboxylic acids onto synthetic calcite, kaolinite, quartz, {alpha}-alumina, and chalk dispersed in an aqueous phase and an organic phase. In the aqueous phase the results clearly demonstrate the differences between the adsorption behaviour of benzoic acid and hexanoic acid onto the surfaces of oxide minerals and carbonates. With NaCl concentration of 0.1 M and with pH {approx_equal} 6 the maximum adsorption of benzoic acid decreases in the order: quartz, {alpha}-alumina, kaolinite. For synthetic calcite and chalk no detectable adsorption was obtaind. In the organic phase the order is reversed. The maximum adsorption of benzoic acid onto the different surfaces decreases in the order: synthetic calcite, chalk, kaolinite and quartz. Also a marked difference in adsorption behaviour between probes with different functional groups onto synthetic calcite from organic phase is observed. The maximum adsorption decreases in the order: benzoic acid, benzyl alcohol and benzylamine. (au) 54 refs.

  17. Multiscale properties of unconventional reservoir rocks

    Science.gov (United States)

    Woodruff, W. F.

    A multidisciplinary study of unconventional reservoir rocks is presented, providing the theory, forward modeling and Bayesian inverse modeling approaches, and laboratory protocols to characterize clay-rich, low porosity and permeability shales and mudstones within an anisotropic framework. Several physical models characterizing oil and gas shales are developed across multiple length scales, ranging from microscale phenomena, e.g. the effect of the cation exchange capacity of reactive clay mineral surfaces on water adsorption isotherms, and the effects of infinitesimal porosity compaction on elastic and electrical properties, to meso-scale phenomena, e.g. the role of mineral foliations, tortuosity of conduction pathways and the effects of organic matter (kerogen and hydrocarbon fractions) on complex conductivity and their connections to intrinsic electrical anisotropy, as well as the macro-scale electrical and elastic properties including formulations for the complex conductivity tensor and undrained stiffness tensor within the context of effective stress and poroelasticity. Detailed laboratory protocols are described for sample preparation and measurement of these properties using spectral induced polarization (SIP) and ultrasonics for the anisotropic characterization of shales for both unjacketed samples under benchtop conditions and jacketed samples under differential loading. An ongoing study of the effects of kerogen maturation through hydrous pyrolysis on the complex conductivity is also provided in review. Experimental results are catalogued and presented for various unconventional formations in North America including the Haynesville, Bakken, and Woodford shales.

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

    Science.gov (United States)

    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).

  19. Advances and Applications of Rock Physics for Hydrocarbon Exploration

    Directory of Open Access Journals (Sweden)

    Valle-Molina C.

    2012-10-01

    Full Text Available Integration of the geological and geophysical information with different scale and features is the key point to establish relationships between petrophysical and elastic characteristics of the rocks in the reservoir. It is very important to present the fundamentals and current methodologies of the rock physics analyses applied to hydrocarbons exploration among engineers and Mexican students. This work represents an effort to capacitate personnel of oil exploration through the revision of the subjects of rock physics. The main aim is to show updated improvements and applications of rock physics into seismology for exploration. Most of the methodologies presented in this document are related to the study the physical and geological mechanisms that impact on the elastic properties of the rock reservoirs based on rock specimens characterization and geophysical borehole information. Predictions of the rock properties (litology, porosity, fluid in the voids can be performed using 3D seismic data that shall be properly calibrated with experimental measurements in rock cores and seismic well log data

  20. X-ray microtomography application in pore space reservoir rock

    Energy Technology Data Exchange (ETDEWEB)

    Oliveira, M.F.S.; Lima, I. [Nuclear Instrumentation Laboratory, COPPE/UFRJ, P.O. Box 68509, 21.941-972, Rio de Janeiro (Brazil); Borghi, L. [Geology Department, Geosciences Institute, Federal University of Rio de Janeiro, Brazil. (Brazil); Lopes, R.T., E-mail: ricardo@lin.ufrj.br [Nuclear Instrumentation Laboratory, COPPE/UFRJ, P.O. Box 68509, 21.941-972, Rio de Janeiro (Brazil)

    2012-07-15

    Characterization of porosity in carbonate rocks is important in the oil and gas industry since a major hydrocarbons field is formed by this lithology and they have a complex media porous. In this context, this research presents a study of the pore space in limestones rocks by x-ray microtomography. Total porosity, type of porosity and pore size distribution were evaluated from 3D high resolution images. Results show that carbonate rocks has a complex pore space system with different pores types at the same facies. - Highlights: Black-Right-Pointing-Pointer This study is about porosity parameter in carbonate rocks by 3D X-Ray Microtomography. Black-Right-Pointing-Pointer This study has become useful as data input for modeling reservoir characterization. Black-Right-Pointing-Pointer This technique was able to provide pores, grains and mineralogical differences among the samples.

  1. Palynofacies characterization for hydrocarbon source rock ...

    Indian Academy of Sciences (India)

    source rock potential of the Subathu Formation in the area. Petroleum geologists are well aware of the fact that the dispersed organic matter derived either from marine or non-marine sediments on reach- ing its maturation level over extended period of time contributes as source material for the produc- tion of hydrocarbons.

  2. Iron speciation and mineral characterization of upper Jurassic reservoir rocks in the Minhe Basin, NW China

    Energy Technology Data Exchange (ETDEWEB)

    Ma, Xiangxian; Zheng, Guodong, E-mail: gdzhbj@mail.iggcas.ac.cn; Xu, Wang [Chinese Academy of Sciences, Key Laboratory of Petroleum Resources, Gansu Province / Key Laboratory of Petroleum Resources Research, Institute of Geology and Geophysics (China); Liang, Minliang [Chinese Academy of Geological Sciences, Institute of Geomechanics, Key Lab of Shale Oil and Gas Geological Survey (China); Fan, Qiaohui; Wu, Yingzhong; Ye, Conglin [Chinese Academy of Sciences, Key Laboratory of Petroleum Resources, Gansu Province / Key Laboratory of Petroleum Resources Research, Institute of Geology and Geophysics (China); Shozugawa, Katsumi; Matsuo, Motoyuki [The University of Tokyo, Graduate School of Arts and Sciences (Japan)

    2016-12-15

    Six samples from a natural outcrop of reservoir rocks with oil seepage and two control samples from surrounding area in the Minhe Basin, northwestern China were selectively collected and analyzed for mineralogical composition as well as iron speciation using X-ray powder diffraction (XRD) and Mössbauer spectroscopy, respectively. Iron species revealed that: (1) the oil-bearing reservoir rocks were changed by water-rock-oil interactions; (2) even in the same site, there was a different performance between sandstone and mudstone during the oil and gas infusion to the reservoirs; and (3) this was evidence indicating the selective channels of hydrocarbon migration. In addition, these studies showed that the iron speciation by Mössbauer spectroscopy could be useful for the study of oil and gas reservoirs, especially the processes of the water-rock interactions within petroleum reservoirs.

  3. Pore Type Classification on Carbonate Reservoir in Offshore Sarawak using Rock Physics Model and Rock Digital Images

    International Nuclear Information System (INIS)

    Lubis, L A; Harith, Z Z T

    2014-01-01

    It has been recognized that carbonate reservoirs are one of the biggest sources of hydrocarbon. Clearly, the evaluation of these reservoirs is important and critical. For rigorous reservoir characterization and performance prediction from geophysical measurements, the exact interpretation of geophysical response of different carbonate pore types is crucial. Yet, the characterization of carbonate reservoir rocks is difficult due to their complex pore systems. The significant diagenesis process and complex depositional environment makes pore systems in carbonates far more complicated than in clastics. Therefore, it is difficult to establish rock physics model for carbonate rock type. In this paper, we evaluate the possible rock physics model of 20 core plugs of a Miocene carbonate platform in Central Luconia, Sarawak. The published laboratory data of this area were used as an input to create the carbonate rock physics models. The elastic properties were analyzed to examine the validity of an existing analytical carbonate rock physics model. We integrate the Xu-Payne Differential Effective Medium (DEM) Model and the elastic modulus which was simulated from a digital carbonate rock image using Finite Element Modeling. The results of this integration matched well for the separation of carbonate pore types and sonic P-wave velocity obtained from laboratory measurement. Thus, the results of this study show that the integration of rock digital image and theoretical rock physics might improve the elastic properties prediction and useful for more advance geophysical techniques (e.g. Seismic Inversion) of carbonate reservoir in Sarawak

  4. Integration of rock typing methods for carbonate reservoir characterization

    International Nuclear Information System (INIS)

    Aliakbardoust, E; Rahimpour-Bonab, H

    2013-01-01

    Reservoir rock typing is the most important part of all reservoir modelling. For integrated reservoir rock typing, static and dynamic properties need to be combined, but sometimes these two are incompatible. The failure is due to the misunderstanding of the crucial parameters that control the dynamic behaviour of the reservoir rock and thus selecting inappropriate methods for defining static rock types. In this study, rock types were defined by combining the SCAL data with the rock properties, particularly rock fabric and pore types. First, air-displacing-water capillary pressure curues were classified because they are representative of fluid saturation and behaviour under capillary forces. Next the most important rock properties which control the fluid flow and saturation behaviour (rock fabric and pore types) were combined with defined classes. Corresponding petrophysical properties were also attributed to reservoir rock types and eventually, defined rock types were compared with relative permeability curves. This study focused on representing the importance of the pore system, specifically pore types in fluid saturation and entrapment in the reservoir rock. The most common tests in static rock typing, such as electrofacies analysis and porosity–permeability correlation, were carried out and the results indicate that these are not appropriate approaches for reservoir rock typing in carbonate reservoirs with a complicated pore system. (paper)

  5. A Percolation Study of Wettability Effect on the Electrical Properties of Reservoir Rocks

    DEFF Research Database (Denmark)

    Zhou, Dengen; Arbabi, Sepehr; Stenby, Erling Halfdan

    1997-01-01

    Measurements of the electrical resistivity of oil reservoirs are commonly used to estimate other properties of reservoirs, such as porosity and hydrocarbon reserves. However, the interpretation of the measurements is based on empirical correlations, because the underlying mechanisms that control...... the electrical properties of oil bearing rocks have not been well understood. In this paper, we employ percolation concepts to investigate the effect of wettability on the electrical conductivity of a reservoir formation. A three-dimensional simple cubic network is used to represent an ideal reservoir formation...

  6. Phenomenology of tremor-like signals observed over hydrocarbon reservoirs

    NARCIS (Netherlands)

    Dangel, S.; Schaepman, M.E.; Stoll, E.P.; Carniel, R.; Barzandji, O.; Rode, E.D.; Singer, J.M.

    2003-01-01

    We have observed narrow-band, low-frequency (1.5-4 Hz, amplitude 0.01-10 mum/s) tremor signals on the surface over hydrocarbon reservoirs (oil, gas and water multiphase fluid systems in porous media) at currently 15 sites worldwide. These 'hydrocarbon tremors' possess remarkably similar spectral and

  7. On the water saturation calculation in hydrocarbon sandstone reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Stalheim, Stein Ottar

    2002-07-01

    The main goal of this work was to identify the most important uncertainty sources in water saturation calculation and examine the possibility for developing new S{sub w} - equations or possibility to develop methods to remove weaknesses and uncertainties in existing S{sub w} - equations. Due to the need for industrial applicability of the equations we aimed for results with the following properties: The accuracy in S{sub w} should increase compared with existing S{sub w} - equations. The equations should be simple to use in petrophysical evaluations. The equations should be based on conventional logs and use as few as possible input parameters. The equations should be numerical stable. This thesis includes an uncertainty and sensitivity analysis of the most common S{sub w} equations. The results are addressed in chapter 3 and were intended to find the most important uncertainty sources in water saturation calculation. To increase the knowledge of the relationship between R{sub t} and S{sub w} in hydrocarbon sandstone reservoirs and to understand how the pore geometry affects the conductivity (n and m) of the rock a theoretical study was done. It was also an aim to examine the possibility for developing new S{sub w} - equations (or investigation an effective medium model) valid inhydrocarbon sandstone reservoirs. The results are presented in paper 1. A new equation for water saturation calculation in clean sandstone oil reservoirs is addressed in paper 2. A recommendation for best practice of water saturation calculation in non water wet formation is addressed in paper 3. Finally a new equation for water saturation calculation in thinly interbedded sandstone/mudstone reservoirs is presented in paper 4. The papers are titled: 1) Is the saturation exponent n a constant. 2) A New Model for Calculating Water Saturation In 3) Influence of wettability on water saturation modeling. 4) Water Saturation Calculations in Thinly Interbedded Sandstone/mudstone Reservoirs. A

  8. Data Compression of Hydrocarbon Reservoir Simulation Grids

    KAUST Repository

    Chavez, Gustavo Ivan

    2015-05-28

    A dense volumetric grid coming from an oil/gas reservoir simulation output is translated into a compact representation that supports desired features such as interactive visualization, geometric continuity, color mapping and quad representation. A set of four control curves per layer results from processing the grid data, and a complete set of these 3-dimensional surfaces represents the complete volume data and can map reservoir properties of interest to analysts. The processing results yield a representation of reservoir simulation results which has reduced data storage requirements and permits quick performance interaction between reservoir analysts and the simulation data. The degree of reservoir grid compression can be selected according to the quality required, by adjusting for different thresholds, such as approximation error and level of detail. The processions results are of potential benefit in applications such as interactive rendering, data compression, and in-situ visualization of large-scale oil/gas reservoir simulations.

  9. Data Compression of Hydrocarbon Reservoir Simulation Grids

    KAUST Repository

    Chavez, Gustavo Ivan; Harbi, Badr M.

    2015-01-01

    A dense volumetric grid coming from an oil/gas reservoir simulation output is translated into a compact representation that supports desired features such as interactive visualization, geometric continuity, color mapping and quad representation. A

  10. Petrophysics and hydrocarbon potential of Paleozoic rocks in Kuwait

    Science.gov (United States)

    Abdullah, Fowzia; Shaaban, Fouad; Khalaf, Fikry; Bahaman, Fatma; Akbar, Bibi; Al-Khamiss, Awatif

    2017-10-01

    Well logs from nine deep exploratory and development wells in Kuwaiti oil fields have been used to study petrophysical characteristics and their effect on the reservoir quality of the subsurface Paleozoic Khuff and Unayzah formations. Petrophysical log data have been calibrated with core analysis available at some intervals. The study indicates a complex lithological facies of the Khuff Formation that is composed mainly of dolomite and anhydrite interbeds with dispersed argillaceous materials and few limestone intercalations. This facies greatly lowered the formation matrix porosity and permeability index. The porosity is fully saturated with water, which is reflected by the low resistivity logs responses, except at some intervals where few hydrocarbon shows are recorded. The impermeable anhydrites, massive (low-permeability) carbonate rock and shale at the lower part of the formation combine to form intraformational seals for the clastic reservoirs of the underlying Unayzah Formation. By contrast, the log interpretation revealed clastic lithological nature of the Unayzah Formation with cycles of conglomerate, sandstone, siltstone, mudstone and shales. The recorded argillaceous materials are mainly of disseminated habit, which control, for some extent, the matrix porosity, that ranges from 2% to 15% with water saturation ranges from 65% to 100%. Cementation, dissolution, compaction and clay mineral authigenesis are the most significant diagenetic processes affecting the reservoir quality. Calibration with the available core analysis at some intervals of the formation indicates that the siliciclastic sequence is a fluvial with more than one climatic cycle changes from humid, semi-arid to arid condition and displays the impact of both physical and chemical diagenesis. In general, the study revealed that the Unyazah Formation has a better reservoir quality than the Khuff Formation and possible gas bearing zones.

  11. Hydrocarbon accumulation in deep fluid modified carbonate rock in the Tarim Basin

    Institute of Scientific and Technical Information of China (English)

    2007-01-01

    The activities of deep fluid are regionalized in the Tarim Basin. By analyzing the REE in core samples and crude oil, carbon isotope of carbon dioxide and inclusion temperature measurement in the west of the Tazhong Uplift in the western Tarim Basin, all the evidence confirms the existence of deep fluid. The deep fluid below the basin floor moved up into the basin through discordogenic fauit and volcanicity to cause corrosion and metaaomatosis of carbonate rock by exchange of matter and energy. The pore structure and permeability of the carbonate reservoirs were improved, making the carbonate reservoirs an excellent type of deeply buried modification. The fluorite ore belts discovered along the large fault and the volcanic area in the west of the Tazhong Uplift are the outcome of deep fluid action. Such carbonate reservoirs are the main type of reservoirs in the Tazhong 45 oilfield. The carbonate reservoirs in well YM 7 are improved obviously by thermal fluid dolomitization. The origin and territory of deep fluid are associated with the discordogenic fault and volcanicity in the basin. The discordogenic fault and volcanic area may be the pointer of looking for the deep fluid modified reservoirs. The primary characteristics of hydrocarbon accumulation in deep fluid reconstructed carbonate rock are summarized as accumulation near the large fault and volcano passage, late-period hydrocarbon accumulation after volcanic activity, and subtle trap reservoirs controlled by lithology.

  12. Seismic Response of Deep Hydrocarbon Bearing Reservoirs: examples from Oso Field and implications for Future Opportunities

    International Nuclear Information System (INIS)

    Oluwasusi, A. B.; Hussey, V.; Goulding, F. J.

    2002-01-01

    The Oso Field (OML 70) produces approximately 100 TBD of condensate from Miocene age shelfal sand reservoirs at approximately 10,000 feet below sea level. The field was discovered in 1967 while testing a deeply buried fault closure. Reservoirs are normally pressured, exceed 1 Darcy in permeability and range from 50 to 600 feet in thickness.There are seismic amplitudes associated with the shallower reservoirs on the existing conventional 3D dataset; however there are no anomalies associated with the deeper, condensate accumulations.The paper explores the physical rock and fluid properties associated with the Oso reservoirs and the resulting seismic responses. Modelled results have been calibrated with the actual seismic signatures for the water and hydrocarbon bearing zones. Results indicate that the deeper reservoirs exhibit a classic Class II AVG seismic response and that the use of longer offset and angle stack data can help predict the occurrence of these types of reservoirs. Examples of similar accumulations will be shared.Mobil Producing Nigeria is conducting a full reprocessing effort of the existing 3D dataset over the Joint Venture acreage with a goal of identifying and exploiting additional accumulations with Class II AVG seismic response. Preliminary results of the reprocessing over known accumulations will be presented

  13. X-ray microtomography application in pore space reservoir rock.

    Science.gov (United States)

    Oliveira, M F S; Lima, I; Borghi, L; Lopes, R T

    2012-07-01

    Characterization of porosity in carbonate rocks is important in the oil and gas industry since a major hydrocarbons field is formed by this lithology and they have a complex media porous. In this context, this research presents a study of the pore space in limestones rocks by x-ray microtomography. Total porosity, type of porosity and pore size distribution were evaluated from 3D high resolution images. Results show that carbonate rocks has a complex pore space system with different pores types at the same facies. Copyright © 2011 Elsevier Ltd. All rights reserved.

  14. Reservoir rock permeability prediction using support vector regression in an Iranian oil field

    International Nuclear Information System (INIS)

    Saffarzadeh, Sadegh; Shadizadeh, Seyed Reza

    2012-01-01

    Reservoir permeability is a critical parameter for the evaluation of hydrocarbon reservoirs. It is often measured in the laboratory from reservoir core samples or evaluated from well test data. The prediction of reservoir rock permeability utilizing well log data is important because the core analysis and well test data are usually only available from a few wells in a field and have high coring and laboratory analysis costs. Since most wells are logged, the common practice is to estimate permeability from logs using correlation equations developed from limited core data; however, these correlation formulae are not universally applicable. Recently, support vector machines (SVMs) have been proposed as a new intelligence technique for both regression and classification tasks. The theory has a strong mathematical foundation for dependence estimation and predictive learning from finite data sets. The ultimate test for any technique that bears the claim of permeability prediction from well log data is the accurate and verifiable prediction of permeability for wells where only the well log data are available. The main goal of this paper is to develop the SVM method to obtain reservoir rock permeability based on well log data. (paper)

  15. Depleted Hydrocarbon Reservoirs Present a Safe and Practical Burial Solution for Graphite Waste

    International Nuclear Information System (INIS)

    Rahmani, L.

    2016-01-01

    A solution for graphite waste is proposed that combines reliance on thick impermeable host rock that is needed to confine the long-life radioactivity content of most irradiated graphite with low capitalistic and operational unit volume costs that are required to render this bulky waste form manageable. The solution, uniquely applicable to irradiated graphite due to its low dose rates, moderate mechanical strength and light density, consists in three steps: first, graphite is fine-crushed under water; second, it is made in an aqueous suspension; third, the suspension is injected into a deep, disused hydrocarbon reservoir. Each of these steps only involves well mastered techniques. Regulatory changes that may allow this solution to be added to the gamut of available waste routes, geochemical issues, availability of depleted reservoirs and cost projections are presented. (author)

  16. Hydrocarbon potential of Ordovician and Silurian rocks. Siljan Region (Sweden)

    Energy Technology Data Exchange (ETDEWEB)

    Berner, U. [Bundesanstalt fuer Geowissenschaften und Rohstoffe (BGR), Hannover (Germany); Lehnert, O. [Erlangen-Nuernberg Univ., Erlangen (Germany); Meinhold, G. [Goettingen Univ. (Germany)

    2013-08-01

    Hydrocarbon exploration in the vicinity of Europe's largest impact structure (Siljan, Central Sweden) focused for years on abiogenic concepts and largely neglected state of the art knowledge on hydrocarbon generation via thermal decomposition of organic matter. In our study we use sedimentary rocks obtained from three drill sites (Mora001, Stumsnaes 1 and Solberga 1) within the ring structure around the central uplift to investigate the hydrocarbon potential of Ordovician and Silurian strata of the region and also for comparison with the shale oil and gas potential of age equivalent rocks of the Baltic Sea. Elemental analyses provided information on concentrations of carbonate and organic carbon, total sulfur as well as on the composition of major and minor elements of the sediments. The data has been used to evaluate the depositional environment and possible diagenetic alterations of the organic matter. RockEval pyrolysis and solvent hydrocarbon extraction gave insight into the hydrocarbon generation potential and the type and thermal maturity of the sediments. From the geochemistry data of the studied wells it is obvious that changes of depositional environments (lacustrine - marine) have occurred during Ordovician and Silurian times. Although, the quality of the organic matter has been influenced in marine and brackish environments through sulfate reduction, we observe for a number of marine and lacustrine sediments a good to excellent preservation of the biological precursors which qualify the sediments as hydrocarbon source rocks (Type II kerogens). Lacustrine source rocks show a higher remaining hydrocarbon potential (up to {proportional_to}550 mg HC per g C{sub org}) than those of marine or brackish environments. Our investigations indicate that the thermal maturity of organic matter of the drill sites has reached the initial stage of oil generation. However, at Mora001 some of the sediments were stained with oil indicating that hydrocarbons have

  17. Rock slopes and reservoirs - lessons learned

    International Nuclear Information System (INIS)

    Moore, D.P.

    1999-01-01

    Lessons learned about slope stability in the course of four decades of monitoring, and in some cases stabilizing, slopes along British Columbia's hydroelectric reservoirs are discussed. The lessons are illustrated by short case histories of some of the more important slopes such as Little Chief Slide, Dutchman's Ridge, Downie Slide, Checkerboard Creek and Wahleach. Information derived from the monitoring and other investigations are compared with early interpretations of geology and slope performance. The comparison serves as an indicator of progress in slope stability determination and as a measure of the value of accumulated experience in terms of the potential consequences to safety and cost savings over the long life-span of hydroelectric projects.14 refs., 2 tabs., 15 figs

  18. Improved characterization of reservoir behavior by integration of reservoir performances data and rock type distributions

    Energy Technology Data Exchange (ETDEWEB)

    Davies, D.K.; Vessell, R.K. [David K. Davies & Associates, Kingwood, TX (United States); Doublet, L.E. [Texas A& M Univ., College Station, TX (United States)] [and others

    1997-08-01

    An integrated geological/petrophysical and reservoir engineering study was performed for a large, mature waterflood project (>250 wells, {approximately}80% water cut) at the North Robertson (Clear Fork) Unit, Gaines County, Texas. The primary goal of the study was to develop an integrated reservoir description for {open_quotes}targeted{close_quotes} (economic) 10-acre (4-hectare) infill drilling and future recovery operations in a low permeability, carbonate (dolomite) reservoir. Integration of the results from geological/petrophysical studies and reservoir performance analyses provide a rapid and effective method for developing a comprehensive reservoir description. This reservoir description can be used for reservoir flow simulation, performance prediction, infill targeting, waterflood management, and for optimizing well developments (patterns, completions, and stimulations). The following analyses were performed as part of this study: (1) Geological/petrophysical analyses: (core and well log data) - {open_quotes}Rock typing{close_quotes} based on qualitative and quantitative visualization of pore-scale features. Reservoir layering based on {open_quotes}rock typing {close_quotes} and hydraulic flow units. Development of a {open_quotes}core-log{close_quotes} model to estimate permeability using porosity and other properties derived from well logs. The core-log model is based on {open_quotes}rock types.{close_quotes} (2) Engineering analyses: (production and injection history, well tests) Material balance decline type curve analyses to estimate total reservoir volume, formation flow characteristics (flow capacity, skin factor, and fracture half-length), and indications of well/boundary interference. Estimated ultimate recovery analyses to yield movable oil (or injectable water) volumes, as well as indications of well and boundary interference.

  19. Prediction of Hydrocarbon Reservoirs Permeability Using Support Vector Machine

    Directory of Open Access Journals (Sweden)

    R. Gholami

    2012-01-01

    Full Text Available Permeability is a key parameter associated with the characterization of any hydrocarbon reservoir. In fact, it is not possible to have accurate solutions to many petroleum engineering problems without having accurate permeability value. The conventional methods for permeability determination are core analysis and well test techniques. These methods are very expensive and time consuming. Therefore, attempts have usually been carried out to use artificial neural network for identification of the relationship between the well log data and core permeability. In this way, recent works on artificial intelligence techniques have led to introduce a robust machine learning methodology called support vector machine. This paper aims to utilize the SVM for predicting the permeability of three gas wells in the Southern Pars field. Obtained results of SVM showed that the correlation coefficient between core and predicted permeability is 0.97 for testing dataset. Comparing the result of SVM with that of a general regression neural network (GRNN revealed that the SVM approach is faster and more accurate than the GRNN in prediction of hydrocarbon reservoirs permeability.

  20. Well log and seismic data analysis for complex pore-structure carbonate reservoir using 3D rock physics templates

    Science.gov (United States)

    Li, Hongbing; Zhang, Jiajia

    2018-04-01

    The pore structure in heterogeneous carbonate rock is usually very complex. This complex pore system makes the relationship between the velocity and porosity of the rock highly scattered, so that for the classical two-dimensional rock physics template (2D RPT) it is not enough to accurately describe the quantitative relationship between the rock elastic parameters of this kind of reservoir and its porosity and water saturation. Therefore it is possible to attribute the effect of pore type to that of the porosity or water saturation, and leads to great deviations when applying such a 2D RPT to predict the porosity and water saturation in seismic reservoir prediction and hydrocarbon detection. This paper first presents a method to establish a new three-dimensional rock physics template (3D RPT) by integrating the Gassmann equations and the porous rock physics model, and use it to characterize the quantitative relation between rock elastic properties and the reservoir parameters including the pore aspect ratio, porosity and water saturation, and to predict these parameters from the known elastic properties. The test results on the real logging and seismic inversion data show that the 3D RPT can accurately describe the variations of elastic properties with the porosity, water saturation and pore-structure parameters, and effectively improve the accuracy of reservoir parameters prediction.

  1. Climate modeling - a tool for the assessment of the paleodistribution of source and reservoir rocks

    Energy Technology Data Exchange (ETDEWEB)

    Roscher, M.; Schneider, J.W. [Technische Univ. Bergakademie Freiberg (Germany). Inst. fuer Geologie; Berner, U. [Bundesanstalt fuer Geowissenschaften und Rohstoffe, Hannover (Germany). Referat Organische Geochemie/Kohlenwasserstoff-Forschung

    2008-10-23

    In an on-going project of BGR and TU Bergakademie Freiberg, numeric paleo-climate modeling is used as a tool for the assessment of the paleo-distribution of organic rich deposits as well as of reservoir rocks. This modeling approach is based on new ideas concerning the formation of the Pangea supercontinent. The new plate tectonic concept is supported by paleo- magnetic data as it fits the 95% confidence interval of published data. Six Permocarboniferous time slices (340, 320, 300, 290, 270, 255 Ma) were chosen within a first paleo-climate modeling approach as they represent the most important changes of the Late Paleozoic climate development. The digital maps have a resolution of 2.8 x 2.8 (T42), suitable for high-resolution climate modeling, using the PLASIM model. CO{sub 2} concentrations of the paleo-atmosphere and paleo-insolation values have been estimated by published methods. For the purpose of validation, quantitative model output, had to be transformed into qualitative parameters in order to be able to compare digital data with qualitative data of geologic indicators. The model output of surface temperatures and precipitation was therefore converted into climate zones. The reconstructed occurrences of geological indicators like aeolian sands, evaporites, reefs, coals, oil source rocks, tillites, phosphorites and cherts were then compared to the computed paleo-climate zones. Examples of the Permian Pangea show a very good agreement between model results and geological indicators. From the modeling approach we are able to identify climatic processes which lead to the deposition of hydrocarbon source and reservoir rocks. The regional assessment of such atmospheric processes may be used for the identification of the paleo-distribution of organic rich deposits or rock types suitable to form hydrocarbon reservoirs. (orig.)

  2. DEPLETED HYDROCARBON RESERVOIRS AND CO2 INJECTION WELLS –CO2 LEAKAGE ASSESSMENT

    Directory of Open Access Journals (Sweden)

    Nediljka Gaurina-Međimurec

    2017-03-01

    Full Text Available Migration risk assessment of the injected CO2 is one of the fi rst and indispensable steps in determining locations for the implementation of projects for carbon dioxide permanent disposal in depleted hydrocarbon reservoirs. Within the phase of potential storage characterization and assessment, it is necessary to conduct a quantitative risk assessment, based on dynamic reservoir models that predict the behaviour of the injected CO2, which requires good knowledge of the reservoir conditions. A preliminary risk assessment proposed in this paper can be used to identify risks of CO2 leakage from the injection zone and through wells by quantifying hazard probability (likelihood and severity, in order to establish a risk-mitigation plan and to engage prevention programs. Here, the proposed risk assessment for the injection well is based on a quantitative risk matrix. The proposed assessment for the injection zone is based on methodology used to determine a reservoir probability in exploration and development of oil and gas (Probability of Success, abbr. POS, and modifi ed by taking into account hazards that may lead to CO2 leakage through the cap rock in the atmosphere or groundwater. Such an assessment can eliminate locations that do not meet the basic criteria in regard to short-term and long-term safety and the integrity of the site

  3. Rock Physics of Reservoir Rocks with Varying Pore Water Saturation and Pore Water Salinity

    DEFF Research Database (Denmark)

    Katika, Konstantina

    experiments, the rock is subjected to high external stresses that resemble the reservoir stresses; 2) the fluid distribution within the pore space changes during the flow through experiments and wettability alterations may occur; 3) different ions, present in the salt water injected in the core, interact......Advanced waterflooding (injection of water with selective ions in reservoirs) is a method of enhanced oil recovery (EOR) that has attracted the interest of oil and gas companies that exploit the Danish oil and gas reservoirs. This method has been applied successfully in oil reservoirs...... and in the Smart Water project performed in a laboratory scale in order to evaluate the EOR processes in selected core plugs. A major step towards this evaluation is to identify the composition of the injected water that leads to increased oil recovery in reservoirs and to define changes in the petrophysical...

  4. Porosity, permeability and 3D fracture network characterisation of dolomite reservoir rock samples.

    Science.gov (United States)

    Voorn, Maarten; Exner, Ulrike; Barnhoorn, Auke; Baud, Patrick; Reuschlé, Thierry

    2015-03-01

    With fractured rocks making up an important part of hydrocarbon reservoirs worldwide, detailed analysis of fractures and fracture networks is essential. However, common analyses on drill core and plug samples taken from such reservoirs (including hand specimen analysis, thin section analysis and laboratory porosity and permeability determination) however suffer from various problems, such as having a limited resolution, providing only 2D and no internal structure information, being destructive on the samples and/or not being representative for full fracture networks. In this paper, we therefore explore the use of an additional method - non-destructive 3D X-ray micro-Computed Tomography (μCT) - to obtain more information on such fractured samples. Seven plug-sized samples were selected from narrowly fractured rocks of the Hauptdolomit formation, taken from wellbores in the Vienna basin, Austria. These samples span a range of different fault rocks in a fault zone interpretation, from damage zone to fault core. We process the 3D μCT data in this study by a Hessian-based fracture filtering routine and can successfully extract porosity, fracture aperture, fracture density and fracture orientations - in bulk as well as locally. Additionally, thin sections made from selected plug samples provide 2D information with a much higher detail than the μCT data. Finally, gas- and water permeability measurements under confining pressure provide an important link (at least in order of magnitude) towards more realistic reservoir conditions. This study shows that 3D μCT can be applied efficiently on plug-sized samples of naturally fractured rocks, and that although there are limitations, several important parameters can be extracted. μCT can therefore be a useful addition to studies on such reservoir rocks, and provide valuable input for modelling and simulations. Also permeability experiments under confining pressure provide important additional insights. Combining these and

  5. Caprock Integrity during Hydrocarbon Production and CO2 Injection in the Goldeneye Reservoir

    Science.gov (United States)

    Salimzadeh, Saeed; Paluszny, Adriana; Zimmerman, Robert

    2016-04-01

    Carbon Capture and Storage (CCS) is a key technology for addressing climate change and maintaining security of energy supplies, while potentially offering important economic benefits. UK offshore, depleted hydrocarbon reservoirs have the potential capacity to store significant quantities of carbon dioxide, produced during power generation from fossil fuels. The Goldeneye depleted gas condensate field, located offshore in the UK North Sea at a depth of ~ 2600 m, is a candidate for the storage of at least 10 million tons of CO2. In this research, a fully coupled, full-scale model (50×20×8 km), based on the Goldeneye reservoir, is built and used for hydro-carbon production and CO2 injection simulations. The model accounts for fluid flow, heat transfer, and deformation of the fractured reservoir. Flow through fractures is defined as two-dimensional laminar flow within the three-dimensional poroelastic medium. The local thermal non-equilibrium between injected CO2 and host reservoir has been considered with convective (conduction and advection) heat transfer. The numerical model has been developed using standard finite element method with Galerkin spatial discretisation, and finite difference temporal discretisation. The geomechanical model has been implemented into the object-oriented Imperial College Geomechanics Toolkit, in close interaction with the Complex Systems Modelling Platform (CSMP), and validated with several benchmark examples. Fifteen major faults are mapped from the Goldeneye field into the model. Modal stress intensity factors, for the three modes of fracture opening during hydrocarbon production and CO2 injection phases, are computed at the tips of the faults by computing the I-Integral over a virtual disk. Contact stresses -normal and shear- on the fault surfaces are iteratively computed using a gap-based augmented Lagrangian-Uzawa method. Results show fault activation during the production phase that may affect the fault's hydraulic conductivity

  6. Study on the enhancement of hydrocarbon recovery by characterization of the reservoir

    Energy Technology Data Exchange (ETDEWEB)

    Kwak, Young Hoon; Son, Jin Dam; Oh, Jae Ho [Korea Institute of Geology Mining and Materials, Taejon (Korea)] [and others

    1998-12-01

    Three year project is being carried out on the enhancement of hydrocarbon recovery by the reservoir characterization. This report describes the results of the second year's work. This project deals with characterization of fluids, bitumen ad rock matrix in the reservoir. New equipment and analytical solutions for naturally fractured reservoir were also included in this study. Main purpose of the reservoir geochemistry is to understand the origin of fluids (gas, petroleum and water) and distribution of the bitumens within the reservoir and to use them not only for exploration but development of the petroleum. For the theme of reservoir geochemistry, methods and principles of the reservoir gas and bitumen characterization, which is applicable to the petroleum development, are studied. and case study was carried out on the gas, water and bitumen samples in the reservoir taken form Haenam area and Ulleung Basin offshore Korea. Gases taken form the two different wells indicate the different origin. Formation water analyses show the absence of barrier within the tested interval. With the sidewall core samples from a well offshore Korea, the analysis using polarizing microscope, scanning electron microscope with EDX and cathodoluminoscope was performed for the study on sandstone diagenesis. The I/S changes were examined on the cuttings samples from a well, offshore Korea to estimate burial temperature. Oxygen stable isotope is used to study geothermal history in sedimentary basin. Study in the field is rare in Korea and basic data are urgently needed especially in continental basins to determine the value of formation water. In the test analyses, three samples from marine basins indicate final temperature from 55 deg.C to 83 deg.C and one marine sample indicate the initial temperature of 36 deg.C. One sample from continental basin represented the final temperature from 53 and 80 deg.C. These temperatures will be corrected because these values were based on assumed

  7. The hydrocarbon accumulations mapping in crystalline rocks by mobile geophysical methods

    Science.gov (United States)

    Nesterenko, A.

    2013-05-01

    Sedimentary-migration origin theory of hydrocarbons dominates nowadays. However, a significant amount of hydrocarbon deposits were discovered in the crystalline rocks, which corroborates the theory of non-organic origin of hydrocarbons. During the solving of problems of oil and gas exploration in crystalline rocks and arrays so-called "direct" methods can be used. These methods include geoelectric methods of forming short-pulsed electromagnetic field (FSPEF) and vertical electric-resonance sounding (VERS) (FSPEF-VERS express-technology). Use of remote Earth sounding (RES) methods is also actual. These mobile technologies are extensively used during the exploration of hydrocarbon accumulations in crystalline rocks, including those within the Ukrainian crystalline shield. The results of explorations Four anomalous geoelectric zones of "gas condensate reservoir" type were quickly revealed as a result of reconnaissance prospecting works (Fig. 1). DTA "Obukhovychi". Anomaly was traced over a distance of 4 km. Approximate area is 12.0 km2. DTA"Korolevskaya". Preliminary established size of anomalous zone is 10.0 km2. The anomalous polarized layers of gas and gas-condensate type were determined. DTA "Olizarovskaya". Approximate size of anomaly is about 56.0 km2. This anomaly is the largest and the most intense. DTA "Druzhba". Preliminary estimated size of anomaly is 16.0 km2. Conclusions Long experience of a successful application of non-classical geoelectric methods for the solving of variety of practical tasks allow one to state their contribution to the development of a new paradigm of geophysical researches. Simultaneous usage of the remote sensing data processing and interpretation method and FSPEF and VERS technologies can essentially optimize and speed up geophysical work. References 1. S.P. Levashov. Detection and mapping of anomalies of "hydrocarbon deposit" type in the fault zones of crystalline arrays by geoelectric methods. / S.P. Levashov, N.A. Yakymchuk, I

  8. A hybrid waveguide cell for the dielectric properties of reservoir rocks

    International Nuclear Information System (INIS)

    Siggins, A F; Gunning, J; Josh, M

    2011-01-01

    A hybrid waveguide cell is described for broad-band measurements of the dielectric properties of hydrocarbon reservoir rocks. The cell is designed to operate in the radio frequency range of 1 MHz to 1 GHz. The waveguide consists of 50 Ω coaxial lines feeding into a central cylindrical section which contains the sample under test. The central portion of the waveguide acts as a circular waveguide and can accept solid core plugs of 38 mm diameter and lengths from 2 to 150 mm. The central section can also be used as a conventional coaxial waveguide when a central electrode with spring-loaded end collets is installed. In the latter mode the test samples are required to be in the form of hollow cylinders. An additional feature of the cell is that the central section is designed to telescope over a limited range of 1–2 mm with the application of an axial load. Effective pressures up to 35 MPa can be applied to the sample under the condition of uniaxial strain. The theoretical basis of the hybrid waveguide cell is discussed together with calibration results. Two reservoir rocks, a Donnybrook sandstone and a kaolin rich clay, are then tested in the cell, both as hollow cylinders in coaxial mode and in the form of solid core plugs. The complex dielectric properties of the two materials over the bandwidth of 1 MHz to 1 GHz are compared with the results of the two testing methods

  9. Acoustic and mechanical response of reservoir rocks under variable saturation and effective pressure.

    Science.gov (United States)

    Ravazzoli, C L; Santos, J E; Carcione, J M

    2003-04-01

    We investigate the acoustic and mechanical properties of a reservoir sandstone saturated by two immiscible hydrocarbon fluids, under different saturations and pressure conditions. The modeling of static and dynamic deformation processes in porous rocks saturated by immiscible fluids depends on many parameters such as, for instance, porosity, permeability, pore fluid, fluid saturation, fluid pressures, capillary pressure, and effective stress. We use a formulation based on an extension of Biot's theory, which allows us to compute the coefficients of the stress-strain relations and the equations of motion in terms of the properties of the single phases at the in situ conditions. The dry-rock moduli are obtained from laboratory measurements for variable confining pressures. We obtain the bulk compressibilities, the effective pressure, and the ultrasonic phase velocities and quality factors for different saturations and pore-fluid pressures ranging from normal to abnormally high values. The objective is to relate the seismic and ultrasonic velocity and attenuation to the microstructural properties and pressure conditions of the reservoir. The problem has an application in the field of seismic exploration for predicting pore-fluid pressures and saturation regimes.

  10. A hybrid waveguide cell for the dielectric properties of reservoir rocks

    Science.gov (United States)

    Siggins, A. F.; Gunning, J.; Josh, M.

    2011-02-01

    A hybrid waveguide cell is described for broad-band measurements of the dielectric properties of hydrocarbon reservoir rocks. The cell is designed to operate in the radio frequency range of 1 MHz to 1 GHz. The waveguide consists of 50 Ω coaxial lines feeding into a central cylindrical section which contains the sample under test. The central portion of the waveguide acts as a circular waveguide and can accept solid core plugs of 38 mm diameter and lengths from 2 to 150 mm. The central section can also be used as a conventional coaxial waveguide when a central electrode with spring-loaded end collets is installed. In the latter mode the test samples are required to be in the form of hollow cylinders. An additional feature of the cell is that the central section is designed to telescope over a limited range of 1-2 mm with the application of an axial load. Effective pressures up to 35 MPa can be applied to the sample under the condition of uniaxial strain. The theoretical basis of the hybrid waveguide cell is discussed together with calibration results. Two reservoir rocks, a Donnybrook sandstone and a kaolin rich clay, are then tested in the cell, both as hollow cylinders in coaxial mode and in the form of solid core plugs. The complex dielectric properties of the two materials over the bandwidth of 1 MHz to 1 GHz are compared with the results of the two testing methods.

  11. Low permeability Neogene lithofacies in Northern Croatia as potential unconventional hydrocarbon reservoirs

    Science.gov (United States)

    Malvić, Tomislav; Sučić, Antonija; Cvetković, Marko; Resanović, Filip; Velić, Josipa

    2014-06-01

    We present two examples of describing low permeability Neogene clastic lithofacies to outline unconventional hydrocarbon lithofacies. Both examples were selected from the Drava Depression, the largest macrostructure of the Pannonian Basin System located in Croatia. The first example is the Beničanci Field, the largest Croatian hydrocarbon reservoir discovered in Badenian coarse-grained clastics that consists mostly of breccia. The definition of low permeability lithofacies is related to the margins of the existing reservoir, where the reservoir lithology changed into a transitional one, which is mainly depicted by the marlitic sandstones. However, calculation of the POS (probability of success of new hydrocarbons) shows critical geological categories where probabilities are lower than those in the viable reservoir with proven reserves. Potential new hydrocarbon volumes are located in the structural margins, along the oil-water contact, with a POS of 9.375%. These potential reserves in those areas can be classified as probable. A second example was the Cremušina Structure, where a hydrocarbon reservoir was not proven, but where the entire structure has been transferred onto regional migration pathways. The Lower Pontian lithology is described from well logs as fine-grained sandstones with large sections of silty or marly clastics. As a result, the average porosity is low for conventional reservoir classification (10.57%). However, it is still an interesting case for consideration as a potentially unconventional reservoir, such as the "tight" sandstones.

  12. Advanced Gas Hydrate Reservoir Modeling Using Rock Physics

    Energy Technology Data Exchange (ETDEWEB)

    McConnell, Daniel

    2017-12-30

    Prospecting for high saturation gas hydrate deposits can be greatly aided with improved approaches to seismic interpretation and especially if sets of seismic attributes can be shown as diagnostic or direct hydrocarbon indicators for high saturation gas hydrates in sands that would be of most interest for gas hydrate production.

    A large 3D seismic data set in the deep water Eastern Gulf of Mexico was screened for gas hydrates using a set of techniques and seismic signatures that were developed and proven in the Central deepwater Gulf of Mexico in the DOE Gulf of Mexico Joint Industry Project JIP Leg II in 2009 and recently confirmed with coring in 2017.

    A large gas hydrate deposit is interpreted in the data where gas has migrated from one of the few deep seated faults plumbing the Jurassic hydrocarbon source into the gas hydrate stability zone. The gas hydrate deposit lies within a flat-lying within Pliocene Mississippi Fan channel that was deposited outboard in a deep abyssal environment. The uniform architecture of the channel aided the evaluation of a set of seismic attributes that relate to attenuation and thin-bed energy that could be diagnostic of gas hydrates. Frequency attributes derived from spectral decomposition also proved to be direct hydrocarbon indicators by pseudo-thickness that could be only be reconciled by substituting gas hydrate in the pore space. The study emphasizes that gas hydrate exploration and reservoir characterization benefits from a seismic thin bed approach.

  13. Reservoir petrophysics and hydrocarbon occurrences of the Bahariya Formation, Alamein-Yidma fields, Western Desert of Egypt

    Energy Technology Data Exchange (ETDEWEB)

    Abdel-Aziz Younes, Mohamed [Alexandria Univ. (Egypt). Geology Dept.

    2012-12-15

    The Bahariya Formation of Cenomanian age is considered to be one of the main oil and gas accumulations in most of the fields of the Western Desert basins. The lithostratigraphic succession of the Bahariya Formation is classified into two main sand units (Unit I and Unit III) separated by shalesiltstone (Unit II). The sandstone of unit-I and III is characterized by being highly enriched in shale content especially glauconite in all wells of the Alamein Field, that has an obvious negative effect on the porosity and oil saturation, where the glauconite increases the grain density of sandstone reservoirs from 2.65 g/cm{sup 3} up to 2.71 g/cm{sup 3}. The well logging data and petrophysical characteristics conducted on Alamein well-28 involving analysis of 30 core samples, were used to evaluate the reservoir characterization and hydrocarbon potentialities. The petrophysical parameters indicate that the primary porosity values are between 8.7 and 29.1%. Decreasing porosity is related to the increase of shale content from 9 to 13%, which occurs as a dispersed habitat. The water saturation changes from 43 to 80%, while the hydrocarbon saturation ranges from 12.1 to 37%. Promising hydrocarbon accumulations are displayed by the sandstone of unit-III due to increased hydrocarbon saturation and effective porosity, thus reflecting the high quality reservoir of this unit. The irreducible and movable hydrocarbon distribution shows a general increase at the eastern and western flanks of the faulted anticline in the Alamein-Yidma fields. The biomarker characteristics and stable carbonisotopic composition of the Bahariya crude oils recovered from the Alamein Field show no obvious variations among them. These oils are paraffinic, containing little branched or cyclic materials waxy n-alkanes(C{sub 25}-C{sub 31}) and characterized by high API gravity, low sulfur content, oleanane index < 2% and moderately high pristane/phytaneratio > 1 and CPI > 1 and the canonical variable parameter is

  14. Oxygen isotope geochemistry of The Geysers reservoir rocks, California

    Energy Technology Data Exchange (ETDEWEB)

    Gunderson, Richard P.; Moore, Joseph N.

    1994-01-20

    Whole-rock oxygen isotopic compositions of Late Mesozoic graywacke, the dominant host rock at The Geysers, record evidence of a large liquid-dominated hydrothermal system that extended beyond the limits of the present steam reservoir. The graywackes show vertical and lateral isotopic variations that resulted from gradients in temperature, permeability, and fluid composition during this early liquid-dominated system. All of these effects are interpreted to have resulted from the emplacement of the granitic "felsite" intrusion 1-2 million years ago. The {delta}{sup 18}O values of the graywacke are strongly zoned around a northwest-southeast trending low located near the center of and similar in shape to the present steam system. Vertical isotopic gradients show a close relationship to the felsite intrusion. The {delta}{sup 18}O values of the graywacke decrease from approximately 15 per mil near the surface to 4-7 per mil 300 to 600 m above the intrusive contact. The {delta}{sup 18}O values then increase downward to 8-10 per mil at the felsite contact, thereafter remaining nearly constant within the intrusion itself. The large downward decrease in {delta}{sup 18}O values are interpreted to be controlled by variations in temperature during the intrusive event, ranging from 150{degree}C near the surface to about 425{degree}C near the intrusive contact. The upswing in {delta}{sup 18}O values near the intrusive contact appears to have been caused by lower rock permeability and/or heavier fluid isotopic composition there. Lateral variations in the isotopic distributions suggests that the effects of temperature were further modified by variations in rock permeability and/or fluid-isotopic composition. Time-integrated water:rock ratios are thought to have been highest within the central isotopic low where the greatest isotopic depletions are observed. We suggest that this region of the field was an area of high permeability within the main upflow zone of the liquid

  15. Characterization of nanometer-scale porosity in reservoir carbonate rock by focused ion beam-scanning electron microscopy.

    Science.gov (United States)

    Bera, Bijoyendra; Gunda, Naga Siva Kumar; Mitra, Sushanta K; Vick, Douglas

    2012-02-01

    Sedimentary carbonate rocks are one of the principal porous structures in natural reservoirs of hydrocarbons such as crude oil and natural gas. Efficient hydrocarbon recovery requires an understanding of the carbonate pore structure, but the nature of sedimentary carbonate rock formation and the toughness of the material make proper analysis difficult. In this study, a novel preparation method was used on a dolomitic carbonate sample, and selected regions were then serially sectioned and imaged by focused ion beam-scanning electron microscopy. The resulting series of images were used to construct detailed three-dimensional representations of the microscopic pore spaces and analyze them quantitatively. We show for the first time the presence of nanometer-scale pores (50-300 nm) inside the solid dolomite matrix. We also show the degree of connectivity of these pores with micron-scale pores (2-5 μm) that were observed to further link with bulk pores outside the matrix.

  16. Hydrocarbon Reservoir Identification in Volcanic Zone by using Magnetotelluric and Geochemistry Information

    Science.gov (United States)

    Firda, S. I.; Permadi, A. N.; Supriyanto; Suwardi, B. N.

    2018-03-01

    The resistivity of Magnetotelluric (MT) data show the resistivity mapping in the volcanic reservoir zone and the geochemistry information for confirm the reservoir and source rock formation. In this research, we used 132 data points divided with two line at exploration area. We used several steps to make the resistivity mapping. There are time series correction, crosspower correction, then inversion of Magnetotelluric (MT) data. Line-2 and line-3 show anomaly geological condition with Gabon fault. The geology structure from the resistivity mapping show the fault and the geological formation with the geological rock data mapping distribution. The geochemistry information show the maturity of source rock formation. According to core sample analysis information, we get the visual porosity for reservoir rock formation in several geological structure. Based on that, we make the geological modelling where the potential reservoir and the source rock around our interest area.

  17. MULTIDISCIPLINARY IMAGING OF ROCK PROPERTIES IN CARBONATE RESERVOIRS FOR FLOW-UNIT TARGETING

    Energy Technology Data Exchange (ETDEWEB)

    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.

  18. Development of a segmentation method for analysis of Campos basin typical reservoir rocks

    Energy Technology Data Exchange (ETDEWEB)

    Rego, Eneida Arendt; Bueno, Andre Duarte [Universidade Estadual do Norte Fluminense Darcy Ribeiro (UENF), Macae, RJ (Brazil). Lab. de Engenharia e Exploracao de Petroleo (LENEP)]. E-mails: eneida@lenep.uenf.br; bueno@lenep.uenf.br

    2008-07-01

    This paper represents a master thesis proposal in Exploration and Reservoir Engineering that have the objective to development a specific segmentation method for digital images of reservoir rocks, which produce better results than the global methods available in the bibliography for the determination of rocks physical properties as porosity and permeability. (author)

  19. Hydrocarbon accumulation characteristics and enrichment laws of multi-layered reservoirs in the Sichuan Basin

    Directory of Open Access Journals (Sweden)

    Guang Yang

    2017-03-01

    Full Text Available The Sichuan Basin represents the earliest area where natural gas is explored, developed and comprehensively utilized in China. After over 50 years of oil and gas exploration, oil and gas reservoirs have been discovered in 24 gas-dominant layers in this basin. For the purpose of predicting natural gas exploration direction and target of each layer in the Sichuan Basin, the sedimentary characteristics of marine and continental strata in this basin were summarized and the forms of multi-cycled tectonic movement and their controlling effect on sedimentation, diagenesis and hydrocarbon accumulation were analyzed. Based on the analysis, the following characteristics were identified. First, the Sichuan Basin has experienced the transformation from marine sedimentation to continental sedimentation since the Sinian with the former being dominant. Second, multiple source–reservoir assemblages are formed based on multi-rhythmed deposition, and multi-layered reservoir hydrocarbon accumulation characteristics are vertically presented. And third, multi-cycled tectonic movement appears in many forms and has a significant controlling effect on sedimentation, diagenesis and hydrocarbon accumulation. Then, oil and gas reservoir characteristics and enrichment laws were investigated. It is indicated that the Sichuan Basin is characterized by coexistence of conventional and unconventional oil and gas reservoirs, multi-layered reservoir hydrocarbon supply, multiple reservoir types, multiple trap types, multi-staged hydrocarbon accumulation and multiple hydrocarbon accumulation models. Besides, its natural gas enrichment is affected by hydrocarbon source intensity, large paleo-uplift, favorable sedimentary facies belt, sedimentary–structural discontinuity plane and structural fracture development. Finally, the natural gas exploration and research targets of each layer in the Sichuan Basin were predicted according to the basic petroleum geologic conditions

  20. The Controls of Pore-Throat Structure on Fluid Performance in Tight Clastic Rock Reservoir: A Case from the Upper Triassic of Chang 7 Member, Ordos Basin, China

    Directory of Open Access Journals (Sweden)

    Yunlong Zhang

    2018-01-01

    Full Text Available The characteristics of porosity and permeability in tight clastic rock reservoir have significant difference from those in conventional reservoir. The increased exploitation of tight gas and oil requests further understanding of fluid performance in the nanoscale pore-throat network of the tight reservoir. Typical tight sandstone and siltstone samples from Ordos Basin were investigated, and rate-controlled mercury injection capillary pressure (RMICP and nuclear magnetic resonance (NMR were employed in this paper, combined with helium porosity and air permeability data, to analyze the impact of pore-throat structure on the storage and seepage capacity of these tight oil reservoirs, revealing the control factors of economic petroleum production. The researches indicate that, in the tight clastic rock reservoir, largest throat is the key control on the permeability and potentially dominates the movable water saturation in the reservoir. The storage capacity of the reservoir consists of effective throat and pore space. Although it has a relatively steady and significant proportion that resulted from the throats, its variation is still dominated by the effective pores. A combination parameter (ε that was established to be as an integrated characteristic of pore-throat structure shows effectively prediction of physical capability for hydrocarbon resource of the tight clastic rock reservoir.

  1. Reservoir Space Evolution of Volcanic Rocks in Deep Songliao Basin, China

    Science.gov (United States)

    Zheng, M.; Wu, X.; Zheng, M.; HU, J.; Wang, S.

    2015-12-01

    Recent years, large amount of natural gas has been discovered in volcanic rock of Lower Crataceous of Songliao basin. Volcanic reservoirs have become one of the important target reservoir types of eastern basin of China. In order to study the volcanic reservoirs, we need to know the main factors controlling the reservoir space. By careful obsercation on volcanic drilling core, casting thin sections and statistical analysis of petrophysical properties of volcanic reservoir in Songliao basin, it can be suggested that the igneous rock reservoir in Yingcheng formation of Lower Crataceous is composed of different rock types, such ad rohylite, rohylitic crystal tuff, autoclastic brecciation lava and so on. There are different reservoirs storage space in in various lithological igneous rocks, but they are mainly composed of primary stoma, secondary solution pores and fractures.The evolution of storage space can be divided into 3 stage: the pramary reservoir space,exogenic leaching process and burial diagenesis.During the evolution process, the reservoir space is effected by secondary minerals, tectonic movement and volcanic hydrothermal solution. The pore of volcanic reservoirs can be partially filled by secondary minerals, but also may be dissoluted by other chemical volcanic hydrothermal solution. Therefore, the favorable places for better-quality volcanic reservoirs are the near-crater facies of vocanic apparatus and dissolution zones on the high position of paleo-structures.

  2. Anomalous dispersion due to hydrocarbons: The secret of reservoir geophysics?

    Science.gov (United States)

    Brown, R.L.

    2009-01-01

    When P- and S-waves travel through porous sandstone saturated with hydrocarbons, a bit of magic happens to make the velocities of these waves more frequency-dependent (dispersive) than when the formation is saturated with brine. This article explores the utility of the anomalous dispersion in finding more oil and gas, as well as giving a possible explanation about the effect of hydrocarbons upon the capillary forces in the formation. ?? 2009 Society of Exploration Geophysicists.

  3. A study of light hydrocarbons (C{sub 4}-C{sub 1}3) in source rocks and petroleum fluid

    Energy Technology Data Exchange (ETDEWEB)

    Odden, Wenche

    2000-07-01

    This thesis consists of an introduction and five included papers. Of these, four papers are published in international journals and the fifth was submitted for review in April 2000. Emphasis has been placed on both naturally and artificially generated light hydrocarbons in petroleum fluids and their proposed source rocks as well as direct application of light hydrocarbons to oil/source rock correlations. Collectively, these papers describe a strategy for interpreting the source of the light hydrocarbons in original oils and condensates as well as the source of the asphaltene fractions from the reservoir fluids. The influence of maturity on light hydrocarbon composition has also been evaluated. The papers include (1) compositional data on the light hydrocarbons from thermal extracts and kerogen pyrolysates of sediment samples, (2) light hydrocarbon data of oils and condensates as well as the pyrolysis products of the asphaltenes from these fluids, (3) assessment of compositional alteration effects, such as selective losses of light hydrocarbons due to evaporation, thermal maturity, phase fractionation and biodegradation, (4) comparison of naturally and artificially generated light hydrocarbons, and (5) compound-specific carbon isotope analysis of the whole range of hydrocarbons of all sample types. (author)

  4. Microstructural characterization of reservoir rocks by X-ray microtomography

    International Nuclear Information System (INIS)

    Fernandes, Jaquiel Salvi; Appoloni, Carlos Roberto

    2007-01-01

    The evaluation of microstructural parameters from reservoir rocks is of great importance for petroleum industries. This work presents measurements of total porosity and pore size distribution of a sandstone sample from Tumblagooda geological formation, extracted from the Kalbari National Park in Australia. X-ray microtomography technique was used for determining porosity and pore size distribution. Other techniques, such as mercury intrusion porosimetry and Archimedes method have also been applied for those determinations but since they are regarded destructive techniques, samples cannot usually be used for further analyses. X-ray microtomography, besides allowing future analyses of a sample already evaluated, also provides tridimensional images of the sample. The experimental configuration included a SkysCan 1172 from CENPES-PETROBRAS, Rio de Janeiro, Brazil. The spatial resolution of this equipment is 2.9 μm. Images have been reconstructed using NRecon software and analysed with the IMAGO software developed by the Laboratory of Porous Materials and Thermophysical Properties of the Department of Mechanical Engineering / Federal University of Santa Catarina, Florianopolis, Brazil

  5. Trace element characterisation of Cretaceous Orange Basin hydrocarbon source rocks

    International Nuclear Information System (INIS)

    Akinlua, A.; Adekola, S.A.; Swakamisa, O.; Fadipe, O.A.; Akinyemi, S.A.

    2010-01-01

    Research highlights: → Vanadium and nickel contents indicate that the rock samples from the Orange Basin have marine organic matter input. → The organic matter of the Orange Basin source rocks were deposited in reducing conditions. → Despite the similarities in the organic matter source input and depositional environment of the samples from the two well, cross plots of Co/Ni versus V/Ni and Mo/Ni versus Co/Ni were able to reveal their subtle differences. → Cluster analysis classified the samples into three groups based on subtle differences in their .thermal maturity. - Abstract: Trace elements in the kerogen fraction of hydrocarbon source rock samples from two wells obtained from the Cretaceous units of the Orange Basin, South Africa were determined using X-ray fluorescence spectrometry, in order to determine their distribution and geochemical significances. The concentrations of the elements (As, Ce, Co, Cu, Fe, Mo, Ni, Pb and V) determined ranged from 0.64 to 47,300 ppm for the samples analysed. The total organic carbon (TOC) values indicate that the samples are organic rich but did not show any trend with the distribution of the trace metals except Ce, Mo and Pb. Dendrogram cluster analysis discriminated the samples into three groups on the basis of their level of thermal maturity. Thermal maturity has a significant effect on the distribution of the trace metals. Cobalt/Ni and V/Ni ratios and cross plots of the absolute values of V and Ni indicate that the samples had significant marine organic matter input. The V and Ni contents and V/(V + Ni) ratio indicate that the organic matter of the source rocks had been deposited in reducing conditions. Despite the similarities in the organic matter source input and depositional environment of the organic matter of the samples from the two well, cross plots of Co/Ni versus V/Ni and Mo/Ni versus Co/Ni were able to reveal subtle differences. Cluster analysis of the samples was also able to reveal the subtle

  6. Polycyclic aromatic hydrocarbons in soils around Guanting Reservoir, Beijing, China

    NARCIS (Netherlands)

    Jiao, W.T.; Lu, Y.L.; Wang, T.Y.; Li, J.; Han, Jingyi; Wang, G.; Hu, W.Y.

    2009-01-01

    The concentrations of 16 polycyclic aromatic hydrocarbons ( 16PAHs) were measured by gas chromatography equipped with a mass spectrometry detector (GC-MS) in 56 topsoil samples around Guanting Reservior (GTR), which is an important water source for Beijing. Low to medium levels of PAH contamination

  7. Geometrical and hydrogeological impact on the behaviour of deep-seated rock slides during reservoir impoundment

    Science.gov (United States)

    Lechner, Heidrun; Zangerl, Christian

    2015-04-01

    Given that there are still uncertainties regarding the deformation and failure mechanisms of deep-seated rock slides this study concentrates on key factors that influence the behaviour of rock slides in the surrounding of reservoirs. The focus is placed on the slope geometry, hydrogeology and kinematics. Based on numerous generic rock slide models the impacts of the (i) rock slide geometry, (ii) reservoir impoundment and level fluctuations, (iii) seepage and buoyancy forces and (iv) hydraulic conductivity of the rock slide mass and the basal shear zone are examined using limit equilibrium approaches. The geometry of many deep-seated rock slides in metamorphic rocks is often influenced by geological structures, e.g. fault zones, joints, foliation, bedding planes and others. With downslope displacement the rock slide undergoes a change in shape. Several observed rock slides in an advanced stage show a convex, bulge-like topography at the foot of the slope and a concave topography in the middle to upper part. Especially, the situation of the slope toe plays an important role for stability. A potentially critical situation can result from a partially submerged flat slope toe because the uplift due to water pressure destabilizes the rock slide. Furthermore, it is essential if the basal shear zone daylights at the foot of the slope or encounters alluvial or glacial deposits at the bottom of the valley, the latter having a buttressing effect. In this study generic rock slide models with a shear zone outcropping at the slope toe are established and systematically analysed using limit equilibrium calculations. Two different kinematic types are modelled: (i) a translational or planar and (ii) a rotational movement behaviour. Questions concerning the impact of buoyancy and pore pressure forces that develop during first time impoundment are of key interest. Given that an adverse effect on the rock slide stability is expected due to reservoir impoundment the extent of

  8. Digital Rock Physics Aplications: Visualisation Complex Pore and Porosity-Permeability Estimations of the Porous Sandstone Reservoir

    Science.gov (United States)

    Handoyo; Fatkhan; Del, Fourier

    2018-03-01

    Reservoir rock containing oil and gas generally has high porosity and permeability. High porosity is expected to accommodate hydrocarbon fluid in large quantities and high permeability is associated with the rock’s ability to let hydrocarbon fluid flow optimally. Porosity and permeability measurement of a rock sample is usually performed in the laboratory. We estimate the porosity and permeability of sandstones digitally by using digital images from μCT-Scan. Advantages of the method are non-destructive and can be applied for small rock pieces also easily to construct the model. The porosity values are calculated by comparing the digital image of the pore volume to the total volume of the sandstones; while the permeability values are calculated using the Lattice Boltzmann calculations utilizing the nature of the law of conservation of mass and conservation of momentum of a particle. To determine variations of the porosity and permeability, the main sandstone samples with a dimension of 300 × 300 × 300 pixels are made into eight sub-cubes with a size of 150 × 150 × 150 pixels. Results of digital image modeling fluid flow velocity are visualized as normal velocity (streamline). Variations in value sandstone porosity vary between 0.30 to 0.38 and permeability variations in the range of 4000 mD to 6200 mD. The results of calculations show that the sandstone sample in this research is highly porous and permeable. The method combined with rock physics can be powerful tools for determining rock properties from small rock fragments.

  9. Fission track analysis and evolution of mesozoic-paleozoic hydrocarbon resource-rocks headed in Northern Jiangsu-South Yellow sea basin

    International Nuclear Information System (INIS)

    Xu Hong; Cai Qianzhong; Sun Heqing; Guo Zhenxuan; Yan Guijing; Dai Jing; Liu Dongying

    2008-01-01

    Fission track data of different geologic epoches from Binhai salient, Yancheng sag, Haian sag, Baiju sag, Gaoyou sag, Hongze sag and Jinhu sag of northern Jiangsu basin and seismic data from Laoshan uplift in South Yellow Sea basin and evolution of Paleozoic hydrocarbon resource-rocks headed in the Northern Jiangsu-South Yellow Sea basin were studied. Results indicate that Binhai salient uplifted in 38-15 Ma, forming 'structure uplifting model', Paleozoic hydrocarbon resource-rocks have the appearance of 'different layers but identical mature, different layers but identical temperature' with Laoshan uplift. All sags have the characters of 'long time heating model', and sedimentations in Cenozoic were exploited by 2 km. Mesozoic-Paleozoic hydrocarbon resource- rocks of Laoshan uplift get ahead of 10 km. Structure evolution was compared with Binhai salient. According to the modeling results of secondary hydrocarbon generation, Mesozoic-Paleozoic hydrocarbon resource-rocks of Laoshan uplift have the good reservoir potentiality and probably become an important new window for sea oil and gas exploration. (authors)

  10. The impact of pressure-dependent interfacial tension and buoyancy forces upon pressure depletion in virgin hydrocarbon reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    McDougall, S.R.; Mackay, E.J. [Heriot-Watt University, Edinburgh (United Kingdom). Dept. of Petroleum Engineering

    1998-07-01

    This paper describes a combined experimental and theoretical study of the microscopic pore-scale physics characterizing gas and liquid production from hydrocarbon reservoirs during pressure depletion. The primary focus of the study was to examine the complex interactions between interfacial tension and buoyancy forces during gas evolution within a porous medium containing oil, water and gas. A specialized 2-dimensional glass micromodel, capable of operating at pressure in excess of 35 MPa was used to visualize the physical mechanisms governing such microscopic processes. In addition, a 3-dimensional, 3-phase numerical pore-scale simulator was developed that can be used to examine gas evolution over a range of different lengthscales and for a wide range of fluid and rock properties. The model incorporates all of the important physics observed in associated laboratory micromodel experiments, including: embryonic nucleation, supersaturation effects, multiphase diffusion, bubble growth-migration-fragmentation, and three-phase spreading coefficients. The precise pore-scale mechanisms governing gas evolution were found to be far more subtle than earlier models would suggest because of the large variation of gas/oil interfacial tension with pressure. This has a profound effect upon the migration of gas structures during depletion and, in models pertaining to reservoir rock, the process of gas migration is consequently much slower than previously thought. This is the first time that such a phenomena has been modelled at the pore-scale and the implications for production forecasting are thought to be significant. (author)

  11. ADVANCED CHARACTERIZATION OF FRACTURED RESERVOIRS IN CARBONATE ROCKS: THE MICHIGAN BASIN

    Energy Technology Data Exchange (ETDEWEB)

    James R. Wood; William B. Harrison

    2002-12-01

    The purpose of the study was to collect and analyze existing data on the Michigan Basin for fracture patterns on scales ranging form thin section to basin. The data acquisition phase has been successfully concluded with the compilation of several large digital databases containing nearly all the existing information on formation tops, lithology and hydrocarbon production over the entire Michigan Basin. These databases represent the cumulative result of over 80 years of drilling and exploration. Plotting and examination of these data show that contrary to most depictions, the Michigan Basin is in fact extensively faulted and fractured, particularly in the central portion of the basin. This is in contrast to most of the existing work on the Michigan Basin, which tends to show relatively simple structure with few or minor faults. It also appears that these fractures and faults control the Paleozoic sediment deposition, the subsequent hydrocarbon traps and very likely the regional dolomitization patterns. Recent work has revealed that a detailed fracture pattern exists in the interior of the Central Michigan Basin, which is related to the mid-continent gravity high. The inference is that early Precambrian, ({approx}1 Ga) rifting events presumed by many to account for the gravity anomaly subsequently controlled Paleozoic sedimentation and later hydrocarbon accumulation. There is a systematic relationship between the faults and a number of gas and oil reservoirs: major hydrocarbon accumulations consistently occur in small anticlines on the upthrown side of the faults. The main tools used in this study to map the fault/fracture patterns are detailed, close-interval (CI = 10 feet) contouring of the formation top picks accompanied by a new way of visualizing the data using a special color spectrum to bring out the third dimension. In addition, recent improvements in visualization and contouring software were instrumental in the study. Dolomitization is common in the

  12. Mineral Dissolution and Precipitation due to Carbon Dioxide-Water-Rock Interactions: The Significance of Accessory Minerals in Carbonate Reservoirs (Invited)

    Science.gov (United States)

    Kaszuba, J. P.; Marcon, V.; Chopping, C.

    2013-12-01

    Accessory minerals in carbonate reservoirs, and in the caprocks that seal these reservoirs, can provide insight into multiphase fluid (CO2 + H2O)-rock interactions and the behavior of CO2 that resides in these water-rock systems. Our program integrates field data, hydrothermal experiments, and geochemical modeling to evaluate CO2-water-rock reactions and processes in a variety of carbonate reservoirs in the Rocky Mountain region of the US. These studies provide insights into a wide range of geologic environments, including natural CO2 reservoirs, geologic carbon sequestration, engineered geothermal systems, enhanced oil and gas recovery, and unconventional hydrocarbon resources. One suite of experiments evaluates the Madison Limestone on the Moxa Arch, Southwest Wyoming, a sulfur-rich natural CO2 reservoir. Mineral textures and geochemical features developed in the experiments suggest that carbonate minerals which constitute the natural reservoir will initially dissolve in response to emplacement of CO2. Euhedral, bladed anhydrite concomitantly precipitates in response to injected CO2. Analogous anhydrite is observed in drill core, suggesting that secondary anhydrite in the natural reservoir may be related to emplacement of CO2 into the Madison Limestone. Carbonate minerals ultimately re-precipitate, and anhydrite dissolves, as the rock buffers the acidity and reasserts geochemical control. Another suite of experiments emulates injection of CO2 for enhanced oil recovery in the Desert Creek Limestone (Paradox Formation), Paradox Basin, Southeast Utah. Euhedral iron oxyhydroxides (hematite) precipitate at pH 4.5 to 5 and low Eh (approximately -0.1 V) as a consequence of water-rock reaction. Injection of CO2 decreases pH to approximately 3.5 and increases Eh by approximately 0.1 V, yielding secondary mineralization of euhedral pyrite instead of iron oxyhydroxides. Carbonate minerals also dissolve and ultimately re-precipitate, as determined by experiments in the

  13. Geochemical Interaction of Middle Bakken Reservoir Rock and CO2 during CO2-Based Fracturing

    Science.gov (United States)

    Nicot, J. P.; Lu, J.; Mickler, P. J.; Ribeiro, L. H.; Darvari, R.

    2015-12-01

    This study was conducted to investigate the effects of geochemical interactions when CO2 is used to create the fractures necessary to produce hydrocarbons from low-permeability Middle Bakken sandstone. The primary objectives are to: (1) identify and understand the geochemical reactions related to CO2-based fracturing, and (2) assess potential changes of reservoir property. Three autoclave experiments were conducted at reservoir conditions exposing middle Bakken core fragments to supercritical CO2 (sc-CO2) only and to CO2-saturated synthetic brine. Ion-milled core samples were examined before and after the reaction experiments using scanning electron microscope, which enabled us to image the reaction surface in extreme details and unambiguously identify mineral dissolution and precipitation. The most significant changes in the reacted rock samples exposed to the CO2-saturated brine is dissolution of the carbonate minerals, particularly calcite which displays severely corrosion. Dolomite grains were corroded to a lesser degree. Quartz and feldspars remained intact and some pyrite framboids underwent slight dissolution. Additionally, small amount of calcite precipitation took place as indicated by numerous small calcite crystals formed at the reaction surface and in the pores. The aqueous solution composition changes confirm these petrographic observations with increase in Ca and Mg and associated minor elements and very slight increase in Fe and sulfate. When exposed to sc-CO2 only, changes observed include etching of calcite grain surface and precipitation of salt crystals (halite and anhydrite) due to evaporation of residual pore water into the sc-CO2 phase. Dolomite and feldspars remained intact and pyrite grains were slightly altered. Mercury intrusion capillary pressure tests on reacted and unreacted samples shows an increase in porosity when an aqueous phase is present but no overall porosity change caused by sc-CO2. It also suggests an increase in permeability

  14. New Hydrocarbon Degradation Pathways in the Microbial Metagenome from Brazilian Petroleum Reservoirs

    Science.gov (United States)

    Sierra-García, Isabel Natalia; Correa Alvarez, Javier; Pantaroto de Vasconcellos, Suzan; Pereira de Souza, Anete; dos Santos Neto, Eugenio Vaz; de Oliveira, Valéria Maia

    2014-01-01

    Current knowledge of the microbial diversity and metabolic pathways involved in hydrocarbon degradation in petroleum reservoirs is still limited, mostly due to the difficulty in recovering the complex community from such an extreme environment. Metagenomics is a valuable tool to investigate the genetic and functional diversity of previously uncultured microorganisms in natural environments. Using a function-driven metagenomic approach, we investigated the metabolic abilities of microbial communities in oil reservoirs. Here, we describe novel functional metabolic pathways involved in the biodegradation of aromatic compounds in a metagenomic library obtained from an oil reservoir. Although many of the deduced proteins shared homology with known enzymes of different well-described aerobic and anaerobic catabolic pathways, the metagenomic fragments did not contain the complete clusters known to be involved in hydrocarbon degradation. Instead, the metagenomic fragments comprised genes belonging to different pathways, showing novel gene arrangements. These results reinforce the potential of the metagenomic approach for the identification and elucidation of new genes and pathways in poorly studied environments and contribute to a broader perspective on the hydrocarbon degradation processes in petroleum reservoirs. PMID:24587220

  15. Microbial conversion of higher hydrocarbons to methane in oil and coal reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Kruger, Martin; Beckmaann, Sabrina; Siegert, Michael; Grundger, Friederike; Richnow, Hans [Geomicrobiology Group, Federal Institute for Geosciences and Natural Resources (Germany)

    2011-07-01

    In recent years, oil production has increased enormously but almost half of the oil now remaining is heavy/biodegraded and cannot be put into production. There is therefore a need for new technology and for diversification of energy sources. This paper discusses the microbial conversion of higher hydrocarbons to methane in oil and coal reservoirs. The objective of the study is to identify microbial and geochemical controls on methanogenesis in reservoirs. A graph shows the utilization of methane for various purposes in Germany from 1998 to 2007. A degradation process to convert coal to methane is shown using a flow chart. The process for converting oil to methane is also given. Controlling factors include elements such as Fe, nitrogen and sulfur. Atmospheric temperature and reservoir pressure and temperature also play an important role. From the study it can be concluded that isotopes of methane provide exploration tools for reservoir selection and alkanes and aromatic compounds provide enrichment cultures.

  16. Xenon NMR measurements of permeability and tortuosity in reservoir rocks.

    Science.gov (United States)

    Wang, Ruopeng; Pavlin, Tina; Rosen, Matthew Scott; Mair, Ross William; Cory, David G; Walsworth, Ronald Lee

    2005-02-01

    In this work we present measurements of permeability, effective porosity and tortuosity on a variety of rock samples using NMR/MRI of thermal and laser-polarized gas. Permeability and effective porosity are measured simultaneously using MRI to monitor the inflow of laser-polarized xenon into the rock core. Tortuosity is determined from measurements of the time-dependent diffusion coefficient using thermal xenon in sealed samples. The initial results from a limited number of rocks indicate inverse correlations between tortuosity and both effective porosity and permeability. Further studies to widen the number of types of rocks studied may eventually aid in explaining the poorly understood connection between permeability and tortuosity of rock cores.

  17. Use of ``rock-typing`` to characterize carbonate reservoir heterogeneity. Final report

    Energy Technology Data Exchange (ETDEWEB)

    Ikwuakor, K.C.

    1994-03-01

    The objective of the project was to apply techniques of ``rock-typing`` and quantitative formation evaluation to borehole measurements in order to identify reservoir and non-reservoir rock-types and their properties within the ``C`` zone of the Ordovician Red River carbonates in the northeast Montana and northwest North Dakota areas of the Williston Basin. Rock-typing discriminates rock units according to their pore-size distribution. Formation evaluation estimates porosities and pore fluid saturation. Rock-types were discriminated using crossplots involving three rock-typing criteria: (1) linear relationship between bulk density and porosity, (2) linear relationship between acoustic interval transit-time and porosity, and (3) linear relationship between acoustic interval transit-time and bulk density. Each rock-type was quantitatively characterized by the slopes and intercepts established for different crossplots involving the above variables, as well as porosities and fluid saturations associated with the rock-types. All the existing production was confirmed through quantitative formation evaluation. Highly porous dolomites and anhydritic dolomites contribute most of the production, and constitute the best reservoir rock-types. The results of this study can be applied in field development and in-fill drilling. Potential targets would be areas of porosity pinchouts and those areas where highly porous zones are downdip from non-porous and tight dolomites. Such areas are abundant. In order to model reservoirs for enhanced oil recovery (EOR) operations, a more localized (e.g. field scale) study, expanded to involve other rock-typing criteria, is necessary.

  18. Mercury-free PVT apparatus for thermophysical property analyses of hydrocarbon reservoir fluids

    Energy Technology Data Exchange (ETDEWEB)

    Lansangan, R.M.; Lievois, J.S.

    1992-08-31

    Typical reservoir fluid analyses of complex, multicomponent hydrocarbon mixtures include the volumetric properties, isothermal compressibility, thermal expansivity, equilibrium ratios, saturation pressure, viscosities, etc. These parameters are collectively referred to as PVT properties, an acronym for the primary state variables; pressure, volume, and temperature. The reservoir engineer incorporates this information together with the porous media description in performing material balance calculations. These calculations lead to the determination (estimation) of the initial hydrocarbon in-place, the future reservoir performance, the optimal production scheme, and the ultimate hydrocarbon recovery. About four years ago, Ruska Instrument Corporation embarked on a project to develop an apparatus designed to measure PVT properties that operates free of mercury. The result of this endeavor is the 2370 Hg-Free PVT system which has been in the market for the last three years. The 2370 has evolved from the prototype unit to its present configuration which is described briefly in this report. The 2370 system, although developed as a system-engineered apparatus based on existing technology, has not been exempt from this burden-of-proof Namely, the performance of the apparatus under routine test conditions with real reservoir fluids. This report summarizes the results of the performance and applications testing of the 2370 Hg-Free PVT system. Density measurements were conducted on a pure fluid. The results were compared against literature values and the prediction of an equation of state. Routine reservoir fluid analyses were conducted with a black oil and a retrograde condensate gas mixtures. Limited comparison of the results were performed based on the same tests performed on a conventional mercury-based PVT apparatus. The results of these tests are included in this report.

  19. Petrophysics Features of the Hydrocarbon Reservoirs in the Precambrian Crystalline Basement

    Science.gov (United States)

    Plotnikova, Irina

    2014-05-01

    A prerequisite for determining the distribution patterns of reservoir zones on the section of crystalline basement (CB) is the solution of a number of problems connected with the study of the nature and structure of empty spaces of reservoirs with crystalline basement (CB) and the impact of petrological, and tectonic factors and the intensity of the secondary transformation of rocks. We decided to choose the Novoelhovskaya well # 20009 as an object of our research because of the following factors. Firstly, the depth of the drilling of the Precambrian crystalline rocks was 4077 m ( advance heading - 5881 m) and it is a maximum for the Volga-Urals region. Secondly, petrographic cut of the well is made on core and waste water, and the latter was sampled regularly and studied macroscopically. Thirdly, a wide range of geophysical studies were performed for this well, which allowed to identify promising areas of collector with high probability. Fourth, along with geological and technical studies that were carried out continuously (including washing and bore hole redressing periods), the studies of the gaseous component of deep samples of clay wash were also carried out, which indirectly helped us estimate reservoir properties and fluid saturation permeable zones. As a result of comprehensive analysis of the stone material and the results of the geophysical studies we could confidently distinguish 5 with strata different composition and structure in the cut of the well. The dominating role in each of them is performed by rocks belonging to one of the structural-material complexes of Archean, and local variations in composition and properties are caused by later processes of granitization on different stages and high temperature diaphthoresis imposed on them. Total capacity of reservoir zones identified according to geophysical studies reached 1034.2 m, which corresponds to 25.8% of the total capacity of 5 rock masses. However, the distribution of reservoirs within the cut

  20. A Rock Physics Feasibility Study of the Geothermal Gassum Reservoir, Copenhagen Area, Denmark

    DEFF Research Database (Denmark)

    Bredesen, Kenneth; Dalgaard, Esben Borch; Mathiesen, Anders

    The subsurface of Denmark stores significant amounts of renewable geothermal energy which may contribute to domestic heating for centuries. However, establishing a successful geothermal plant with robust production capacity require reservoirs with sufficient high porosity and permeability. Modern...... quantitative seismic interpretation is a good approach to de-risk prospects and gain reservoir insight, but is so far not widely used for geothermal applications. In this study we perform a rock physics feasibility study as a pre-step towards quantitative seismic interpretation of geothermal reservoirs......, primarily in areas around Copenhagen. The results argue that it may be possible to use AVO and seismic inversion data to distinguish geothermal sandstone reservoirs from surrounding shales and to estimate porosity and permeability. Moreover, this study may represent new possibilities for future rock physics...

  1. Radar Mapping of Fractures and Fluids in Hydrocarbon Reservoirs

    Science.gov (United States)

    Stolarczyk, L. G.; Wattley, G. G.; Caffey, T. W.

    2001-05-01

    A stepped-frequency radar has been developed for mapping of fractures and fluids within 20 meters of the wellbore. The operating range has been achieved by using a radiating magnetic dipole operating in the low- and medium-frequency bands. Jim Wait has shown that the electromagnetic (EM) wave impedance in an electrically conductive media is largely imaginary, enabling energy to be stored in the near field instead of dissipated, as in the case for an electric dipole. This fact, combined with the low attenuation rate of a low-frequency band EM wave, enables radiation to penetrate deeply into the geology surrounding the wellbore. The radiation pattern features a vertical electric field for optimum electric current induction into vertical fractures. Current is also induced in sedimentary rock creating secondary waves that propagate back to the wellbore. The radiation pattern is electrically driven in azimuth around the wellbore. The receiving antenna is located in the null field of the radiating antenna so that the primary wave is below the thermal noise of the receiver input. By stepping the frequency through the low- and medium-frequency bands, the depth of investigation is varied, and enables electrical conductivity profiling away from the wellbore. Interpretation software has been developed for reconstructive imaging in dipping sedimentary layers. Because electrical conductivity can be related to oil/water saturation, both fractures and fluids can be mapped. Modeling suggests that swarms of fractures can be imaged and fluid type determined. This information will be useful in smart fracking and sealing. Conductivity tomography images will indicate bed dip, oil/water saturation, and map fluids. This paper will provide an overview of the technology development program.

  2. Marine controlled source electromagnetic (mCSEM) detects hydrocarbon reservoirs in the Santos Basin - Brazil

    Energy Technology Data Exchange (ETDEWEB)

    Buonora, Marco Polo Pereira; Rodrigues, Luiz Felipe [PETROBRAS, Rio de Janeiro, RJ (Brazil); Zerilli, Andrea; Labruzzo, Tiziano [WesternGeco, Houston, TX (United States)

    2008-07-01

    In recent years marine Controlled Source Electromagnetic (mCSEM) has driven the attention of an increasing number of operators due to its sensitivity to map resistive structures, such as hydrocarbon reservoirs beneath the ocean floor and successful case histories have been reported. The Santos basin mCSEM survey was performed as part of a technical co-operation project between PETROBRAS and Schlumberger to assess the integration of selected deep reading electromagnetic technologies into the full cycle of oil field exploration and development. The survey design was based on an in-depth sensitivity study, built on known reservoirs parameters, such as thickness, lateral extent, overburden and resistivities derived from seismic and well data. In this context, the mCSEM data were acquired to calibrate the technology over the area's known reservoirs, quantify the resistivity anomalies associated with those reservoirs, with the expectation that new prospective locations could be found. We show that the mCSEM response of the known reservoirs yields signatures that can be clearly imaged and accurately quantified and there are evident correlations between the mCSEM anomalies and the reservoirs. (author)

  3. Upscaling of permeability heterogeneities in reservoir rocks; an integrated approach

    NARCIS (Netherlands)

    Mikes, D.

    2002-01-01

    This thesis presents a hierarchical and geologically constrained deterministic approach to incorporate small-scale heterogeneities into reservoir flow simulators. We use a hierarchical structure to encompass all scales from laminae to an entire depositional system. For the geological models under

  4. Consideration of clay in rocks in discriminating carbonate reservoirs in Eastern Turkmenia

    International Nuclear Information System (INIS)

    Ehjvazov, A.M.

    1975-01-01

    A method is described for calculating the clayiness of rocks in discrimination of carbonate reservoirs of eastern Turkmenia. Carbonate deposits in eastern Turkmenia contain significant amounts of clayey material, which interferes with the collector properties of the rocks. However, in many cases the clayey limestones, when sampled, give industrial supplies of gas. Analysis of gamma-logging data with calculation of the results of sampling for layers of different porosities, as determined from the results of neutron gamma logging, showed a definite correlation between the reservoir properties of carbonate layers and the values of ΔIsub(γ) of two different gamma-logging parameters, calculated by the single ''reference'' horizon method

  5. Permeability Estimation of Rock Reservoir Based on PCA and Elman Neural Networks

    Science.gov (United States)

    Shi, Ying; Jian, Shaoyong

    2018-03-01

    an intelligent method which based on fuzzy neural networks with PCA algorithm, is proposed to estimate the permeability of rock reservoir. First, the dimensionality reduction process is utilized for these parameters by principal component analysis method. Further, the mapping relationship between rock slice characteristic parameters and permeability had been found through fuzzy neural networks. The estimation validity and reliability for this method were tested with practical data from Yan’an region in Ordos Basin. The result showed that the average relative errors of permeability estimation for this method is 6.25%, and this method had the better convergence speed and more accuracy than other. Therefore, by using the cheap rock slice related information, the permeability of rock reservoir can be estimated efficiently and accurately, and it is of high reliability, practicability and application prospect.

  6. Sedimentary environments and hydrocarbon potential of cretaceous rocks of indus basin, Pakistan

    International Nuclear Information System (INIS)

    Sheikh, S.A.; Naseem, S.

    1999-01-01

    Cretaceous rocks of Indus Basin of Pakistan are dominated by clastics with subordinate limestone towards the top. These rocks represent shelf facies and were deposited in deltaic to reducing marine conditions at variable depths. Indications of a silled basin with restricted circulation are also present. Cretaceous fine clastics/carbonates have good source and reservoir qualities. Variable geothermal gradients in different parts of basin have placed these rocks at different maturity levels; i.e. from oil to condensate and to gas. The potential of these rocks has been proved by several oil and gas discoveries particularly in the Central and Southern provinces of Indus Basin. (author)

  7. Microwave-assisted nonionic surfactant extraction of aliphatic hydrocarbons from petroleum source rock

    Energy Technology Data Exchange (ETDEWEB)

    Akinlua, A., E-mail: geochemresearch@yahoo.com [Fossil Fuels and Environmental Geochemistry Group, Department of Chemistry, Obafemi Awolowo University, Ile-Ife (Nigeria); Jochmann, M.A.; Laaks, J.; Ewert, A.; Schmidt, T.C. [Instrumental Analytical Chemistry, University Duisburg-Essen, Universitaetsstr, 5, 45141 Essen (Germany)

    2011-04-08

    The extraction of aliphatic hydrocarbons from petroleum source rock using nonionic surfactants with the assistance of microwave was investigated and the conditions for maximum yield were determined. The results showed that the extraction temperatures and kinetic rates have significant effects on extraction yields of aliphatic hydrocarbons. The optimum temperature for microwave-assisted nonionic surfactant extraction of aliphatic hydrocarbons from petroleum source rock was 105 deg. C. The optimum extraction time for the aliphatic hydrocarbons was at 50 min. Concentration of the nonionic surfactant solution and irradiation power had significant effect on the yields of aliphatic hydrocarbons. The yields of the analytes were much higher using microwave assisted nonionic surfactant extraction than with Soxhlet extraction. The recoveries of the n-alkanes and acyclic isoprenoid hydrocarbons for GC-MS analysis from the extractant nonionic surfactant solution by in-tube extraction (ITEX 2) with a TENAX TA adsorbent were found to be efficient. The results show that microwave-assisted nonionic surfactant extraction (MANSE) is a good and efficient green analytical preparatory technique for geochemical evaluation of petroleum source rock.

  8. Microwave-assisted nonionic surfactant extraction of aliphatic hydrocarbons from petroleum source rock

    International Nuclear Information System (INIS)

    Akinlua, A.; Jochmann, M.A.; Laaks, J.; Ewert, A.; Schmidt, T.C.

    2011-01-01

    The extraction of aliphatic hydrocarbons from petroleum source rock using nonionic surfactants with the assistance of microwave was investigated and the conditions for maximum yield were determined. The results showed that the extraction temperatures and kinetic rates have significant effects on extraction yields of aliphatic hydrocarbons. The optimum temperature for microwave-assisted nonionic surfactant extraction of aliphatic hydrocarbons from petroleum source rock was 105 deg. C. The optimum extraction time for the aliphatic hydrocarbons was at 50 min. Concentration of the nonionic surfactant solution and irradiation power had significant effect on the yields of aliphatic hydrocarbons. The yields of the analytes were much higher using microwave assisted nonionic surfactant extraction than with Soxhlet extraction. The recoveries of the n-alkanes and acyclic isoprenoid hydrocarbons for GC-MS analysis from the extractant nonionic surfactant solution by in-tube extraction (ITEX 2) with a TENAX TA adsorbent were found to be efficient. The results show that microwave-assisted nonionic surfactant extraction (MANSE) is a good and efficient green analytical preparatory technique for geochemical evaluation of petroleum source rock.

  9. Advances and applications of rock physics for hydrocarbon exploration; Avances y aplicaciones en fisica de rocas para exploracion de hidrocarburos

    Energy Technology Data Exchange (ETDEWEB)

    Vargas-Meleza, L.; Valle-Molina, C. [Instituto Mexicano del Petroleo (Mexico)]. E-mails: lvargasm@imp.mx; cvallem@imp.mx

    2012-10-15

    Integration of the geological and geophysical information with different scale and features is the key point to establish relationships between petrophysical and elastic characteristics of the rocks in the reservoir. It is very important to present the fundamentals and current methodologies of the rock physics analyses applied to hydrocarbons exploration among engineers and Mexican students. This work represents an effort to capacitate personnel of oil exploration through the revision of the subjects of rock physics. The main aim is to show updated improvements and applications of rock physics into seismology for exploration. Most of the methodologies presented in this document are related to the study the physical and geological mechanisms that impact on the elastic properties of the rock reservoirs based on rock specimens characterization and geophysical borehole information. Predictions of the rock properties (lithology, porosity, fluid in the voids) can be performed using 3D seismic data that shall be properly calibrated with experimental measurements in rock cores and seismic well log data. [Spanish] Se discuten los fundamentos de fisica de rocas y las implicaciones analiticas para interpretacion sismica de yacimientos. Se considera conveniente difundir, entre los ingenieros y estudiantes mexicanos, los fundamentos y metodologias actuales sobre el analisis de la fisica de rocas en exploracion de hidrocarburos. Este trabajo representa un esfuerzo de capacitacion profesional en exploracion petrolera en el que se difunde la relevancia de la fisica de rocas. El interes principal es exponer los avances tecnologicos y aplicaciones actuales sobre fisica de rocas en el campo de sismologia de exploracion. La mayoria de las metodologias estudia los mecanismos fisicos y geologicos que controlan las propiedades elasticas de los yacimientos de hidrocarburos, a partir de nucleos de roca y registros geofisicos de pozo. Este conocimiento se usa para predecir propiedades de la

  10. Rock-physics and seismic-inversion based reservoir characterization of the Haynesville Shale

    International Nuclear Information System (INIS)

    Jiang, Meijuan; Spikes, Kyle T

    2016-01-01

    Seismic reservoir characterization of unconventional gas shales is challenging due to their heterogeneity and anisotropy. Rock properties of unconventional gas shales such as porosity, pore-shape distribution, and composition are important for interpreting seismic data amplitude variations in order to locate optimal drilling locations. The presented seismic reservoir characterization procedure applied a grid-search algorithm to estimate the composition, pore-shape distribution, and porosity at the seismic scale from the seismically inverted impedances and a rock-physics model, using the Haynesville Shale as a case study. All the proposed rock properties affected the seismic velocities, and the combined effects of these rock properties on the seismic amplitude were investigated simultaneously. The P- and S-impedances correlated negatively with porosity, and the V _P/V _S correlated positively with clay fraction and negatively with the pore-shape distribution and quartz fraction. The reliability of these estimated rock properties at the seismic scale was verified through comparisons between two sets of elastic properties: one coming from inverted impedances, which were obtained from simultaneous inversion of prestack seismic data, and one derived from these estimated rock properties. The differences between the two sets of elastic properties were less than a few percent, verifying the feasibility of the presented seismic reservoir characterization. (paper)

  11. The coupling of dynamics and permeability in the hydrocarbon accumulation period controls the oil-bearing potential of low permeability reservoirs: a case study of the low permeability turbidite reservoirs in the middle part of the third member of Shahejie Formation in Dongying Sag

    DEFF Research Database (Denmark)

    Yang, Tian; Cao, Ying-Chang; Wang, Yan-Zhong

    2016-01-01

    The relationships between permeability and dynamics in hydrocarbon accumulation determine oilbearing potential (the potential oil charge) of low permeability reservoirs. The evolution of porosity and permeability of low permeability turbidite reservoirs of the middle part of the third member...... facies A and diagenetic facies B do not develop accumulation conditions with low accumulation dynamics in the late accumulation period for very low permeability. At more than 3000 m burial depth, a larger proportion of turbidite reservoirs are oil charged due to the proximity to the source rock. Also...

  12. The potentiality of hydrocarbon generation of the Jurassic source rocks in Salam-3x well,

    Directory of Open Access Journals (Sweden)

    Mohamed M. El Nady

    2016-03-01

    Full Text Available The present work deals with the identification of the potential and generating capability of oil generation in the Jurassic source rocks in the Salam-3x well. This depending on the organo-geochemical analyses of cutting samples representative of Masajid, Khatatba and Ras Qattara formations, as well as, representative extract samples of the Khatatba and Ras Qattara formations. The geochemical analysis suggested the potential source intervals within the encountered rock units as follows: Masajid Formation bears mature source rocks and have poor to fair generating capability for generating gas (type III kerogen. Khatatba Formation bears mature source rock, and has poor to good generating capability for both oil and gas. Ras Qattara Formation constituting mature source rock has good to very good generating capability for both oil and gas. The burial history modeling shows that the Masajid Formation lies within oil and gas windows; Khatatba and Ras Qattara formations lie within the gas window. From the biomarker characteristics of source rocks it appears that the extract is genetically related as the majority of them were derived from marine organic matters sources (mainly algae deposited under reducing environment and take the direction of increasing maturity and far away from the direction of biodegradation. Therefore, Masajid Formation is considered as effective source rocks for generating hydrocarbons, while Khatatba and Ras Qattara formations are the main source rocks for hydrocarbon accumulations in the Salam-3x well.

  13. The Pore-scale modeling of multiphase flows in reservoir rocks using the lattice Boltzmann method

    Science.gov (United States)

    Mu, Y.; Baldwin, C. H.; Toelke, J.; Grader, A.

    2011-12-01

    Digital rock physics (DRP) is a new technology to compute the physical and fluid flow properties of reservoir rocks. In this approach, pore scale images of the porous rock are obtained and processed to create highly accurate 3D digital rock sample, and then the rock properties are evaluated by advanced numerical methods at the pore scale. Ingrain's DRP technology is a breakthrough for oil and gas companies that need large volumes of accurate results faster than the current special core analysis (SCAL) laboratories can normally deliver. In this work, we compute the multiphase fluid flow properties of 3D digital rocks using D3Q19 immiscible LBM with two relaxation times (TRT). For efficient implementation on GPU, we improved and reformulated color-gradient model proposed by Gunstensen and Rothmann. Furthermore, we only use one-lattice with the sparse data structure: only allocate memory for pore nodes on GPU. We achieved more than 100 million fluid lattice updates per second (MFLUPS) for two-phase LBM on single Fermi-GPU and high parallel efficiency on Multi-GPUs. We present and discuss our simulation results of important two-phase fluid flow properties, such as capillary pressure and relative permeabilities. We also investigate the effects of resolution and wettability on multiphase flows. Comparison of direct measurement results with the LBM-based simulations shows practical ability of DRP to predict two-phase flow properties of reservoir rock.

  14. Wettability of Oil-Producing Reservoir Rocks as Determined from X-ray Photoelectron Spectroscopy

    Science.gov (United States)

    Toledo; Araujo; Leon

    1996-11-10

    Wettability has a dominant effect in oil recovery by waterflooding and in many other processes of industrial and environmental interest. Recently, the suggestion has been made that surface science analytical techniques (SSAT) could be used to rapidly determine the wettability of reservoir materials. Here, we bring the capability of X-ray photoelectron spectroscopy (XPS) to bear on the wettability evaluation of producing reservoir rocks. For a suite of freshly exposed fracture surfaces of rocks we investigate the relationship between wettability and surface composition as determined from XPS. The classical wettability index as measured with the Amott-Harvey test is used here as an indicator of the wettability of natural sandstones. The XPS spectra of oil-wet surfaces of rocks reveal the existence of organic carbon and also of an "organic" silicon species, of the kind Si-CH relevant to silanes, having a well-defined binding energy which differs from that of the Si-O species of mineral grains. We provide quantifiable evidence that chemisorbed organic material on the pore surfaces defines the oil-wetting character of various reservoir sandstones studied here which on a mineralogic basis are expected to be water-wet. This view is supported by a strong correlation between C content of pore surfaces and rock wettability. The results also suggest a correlation between organic silicon content on the pore surfaces and rock hydrophobicity.

  15. Hydrocarbon source rock potential evaluation of the Late Paleocene ...

    Indian Academy of Sciences (India)

    63

    research is available on its source rock potential evaluation at Nammal Gorge Section in the Salt. Range, Potwar Basin .... methods of Tucker (2003) and Assaad (2008) have been followed. A total of fifteen ..... Business Media. Baker D M, Lillie ...

  16. Calculation of Interfacial Tensions of Hydrocarbon-water Systems under Reservoir Conditions

    DEFF Research Database (Denmark)

    Zuo, You-Xiang; Stenby, Erling Halfdan

    1998-01-01

    Assuming that the number densities of each component in a mixture are linearly distributed across the interface between the coexisting vapor-liquid or liquid-liquid phases, we developed in this research work a linear-gradient-theory (LGT) model for computing the interfacial tension of hydrocarbon......-brine systems. The new model was tested on a number of hydrocarbon-water/brine mixtures and two crude oil-water systems under reservoir conditions. The results show good agreement between the predicted and the experimental interfacial tension data.......Assuming that the number densities of each component in a mixture are linearly distributed across the interface between the coexisting vapor-liquid or liquid-liquid phases, we developed in this research work a linear-gradient-theory (LGT) model for computing the interfacial tension of hydrocarbon-water...... mixtures on the basis of the SRK equation of state. With this model, it is unnecessary to solve the time-consuming density-profile equations of the gradient-theory model. In addition, a correlation was developed for representing the effect of electrolytes on the interfacial tension of hydrocarbon...

  17. Ephemeral-fluvial sediments as potential hydrocarbon reservoirs. Vol. 1: Sedimentology

    Energy Technology Data Exchange (ETDEWEB)

    Taylor, K.S.

    1994-12-31

    Although reservoirs formed from ephemeral-fluvial sandstones have previously been considered relatively simple, unresolved problems of sandbody correlation and production anomalies demonstrate the need for improved understanding of their internal complexity. Outcropping ephemeral-fluvial systems have been studied in order to determine the main features and processes occurring in sand-rich ephemeral systems and to identify which features will be of importance in a hydrocarbon reservoir. The Lower Jurassic Upper Moenave and Kayenta Formations of south-eastern Utah and northern Arizona comprise series of stacked, sand-dominated sheet-like palaeochannels suggestive of low sinuosity, braided systems. Low subsidence rates and rapid lateral migration rates enabled channels to significantly modify their widths during high discharge. (author)

  18. Total porosity of carbonate reservoir rocks by X-ray microtomography in two different spatial resolutions

    International Nuclear Information System (INIS)

    Nagata, Rodrigo; Appoloni, Carlos R.; Marques, Leonardo C.; Fernandes, Celso P.

    2011-01-01

    Carbonate reservoir rocks contain more than 50% of world's petroleum. To know carbonate rocks' structural properties is quite important to petroleum extraction. One of their main structural properties is the total porosity, which shows the rock's capacity to stock petroleum. In recent years, the X-ray microtomography had been used to analyze the structural parameters of reservoir rocks. Such nondestructive technique generates images of the samples' internal structure, allowing the evaluation of its properties. The spatial resolution is a measurement parameter that indicates the smallest structure size observable in a sample. It is possible to measure one sample using two or more different spatial resolutions in order to evaluate the samples' pore scale. In this work, two samples of the same sort of carbonate rock were measured, and in each measurement a different spatial resolution (17 μm and 7 μm) was applied. The obtained results showed that with the better resolution it was possible to measure 8% more pores than with the poorer resolution. Such difference provides us with good expectations about such approach to study the pore scale of carbonate rocks. (author)

  19. Rock Mass Classification of Karstic Terrain in the Reservoir Slopes of Tekeze Hydropower Project

    Science.gov (United States)

    Hailemariam Gugsa, Trufat; Schneider, Jean Friedrich

    2010-05-01

    Hydropower reservoirs in deep gorges usually experience slope failures and mass movements. History also showed that some of these projects suffered severe landslides, which left lots of victims and enormous economic loss. Thus, it became vital to make substantial slope stability studies in such reservoirs to ensure safe project development. This study also presents a regional scale instability assessment of the Tekeze Hydropower reservoir slopes. Tekeze hydropower project is a newly constructed double arch dam that completed in August 2009. It is developed on Tekeze River, tributary of Blue Nile River that runs across the northern highlands of Ethiopia. It cuts a savage gorge 2000m deep, the deepest canyon in Africa. The dam is the highest dam in Ethiopia at 188m, 10 m higher than China's Three Gorges Dam. It is being developed by Chinese company at a cost of US350M. The reservoir is designed at 1140 m elevation, as retention level to store more than 9000 million m3 volume of water that covers an area of 150 km2, mainly in channel filling form. In this study, generation of digital elevation model from ASTER satellite imagery and surface field investigation is initially considered for further image processing and terrain parameters' analyses. Digitally processed multi spectral ASTER ortho-images drape over the DEM are used to have different three dimensional perspective views in interpreting lithological, structural and geomorphological features, which are later verified by field mapping. Terrain slopes are also delineated from the relief scene. A GIS database is ultimately developed to facilitate the delineation of geotechnical units for slope rock mass classification. Accordingly, 83 geotechnical units are delineated and, within them, 240 measurement points are established to quantify in-situ geotechnical parameters. Due to geotechnical uncertainties, four classification systems; namely geomorphic rock mass strength classification (RMS), slope mass rating (SMR

  20. MULTI-ATTRIBUTE SEISMIC/ROCK PHYSICS APPROACH TO CHARACTERIZING FRACTURED RESERVOIRS

    Energy Technology Data Exchange (ETDEWEB)

    Gary Mavko

    2000-10-01

    This project consists of three key interrelated Phases, each focusing on the central issue of imaging and quantifying fractured reservoirs, through improved integration of the principles of rock physics, geology, and seismic wave propagation. This report summarizes the results of Phase I of the project. The key to successful development of low permeability reservoirs lies in reliably characterizing fractures. Fractures play a crucial role in controlling almost all of the fluid transport in tight reservoirs. Current seismic methods to characterize fractures depend on various anisotropic wave propagation signatures that can arise from aligned fractures. We are pursuing an integrated study that relates to high-resolution seismic images of natural fractures to the rock parameters that control the storage and mobility of fluids. Our goal is to go beyond the current state-of-the art to develop and demonstrate next generation methodologies for detecting and quantitatively characterizing fracture zones using seismic measurements. Our study incorporates 3 key elements: (1) Theoretical rock physics studies of the anisotropic viscoelastic signatures of fractured rocks, including up scaling analysis and rock-fluid interactions to define the factors relating fractures in the lab and in the field. (2) Modeling of optimal seismic attributes, including offset and azimuth dependence of travel time, amplitude, impedance and spectral signatures of anisotropic fractured rocks. We will quantify the information content of combinations of seismic attributes, and the impact of multi-attribute analyses in reducing uncertainty in fracture interpretations. (3) Integration and interpretation of seismic, well log, and laboratory data, incorporating field geologic fracture characterization and the theoretical results of items 1 and 2 above. The focal point for this project is the demonstration of these methodologies in the Marathon Oil Company Yates Field in West Texas.

  1. Application of magnetic techniques to lateral hydrocarbon migration - Lower Tertiary reservoir systems, UK North Sea

    Science.gov (United States)

    Badejo, S. A.; Muxworthy, A. R.; Fraser, A.

    2017-12-01

    Pyrolysis experiments show that magnetic minerals can be produced inorganically during oil formation in the `oil-kitchen'. Here we try to identify a magnetic proxy that can be used to trace hydrocarbon migration pathways by determining the morphology, abundance, mineralogy and size of the magnetic minerals present in reservoirs. We address this by examining the Tay formation in the Western Central Graben in the North Sea. The Tertiary sandstones are undeformed and laterally continuous in the form of an east-west trending channel, facilitating long distance updip migration of oil and gas to the west. We have collected 179 samples from 20 oil-stained wells and 15 samples from three dry wells from the British Geological Survey Core Repository. Samples were selected based on geological observations (water-wet sandstone, oil-stained sandstone, siltstones and shale). The magnetic properties of the samples were determined using room-temperature measurements on a Vibrating Sample Magnetometer (VSM), low-temperature (0-300K) measurements on a Magnetic Property Measurement System (MPMS) and high-temperature (300-973K) measurements on a Kappabridge susceptibility meter. We identified magnetite, pyrrhotite, pyrite and siderite in the samples. An increasing presence of ferrimagnetic iron sulphides is noticed along the known hydrocarbon migration pathway. Our initial results suggest mineralogy coupled with changes in grain size are possible proxies for hydrocarbon migration.

  2. Pore Characterization of Shale Rock and Shale Interaction with Fluids at Reservoir Pressure-Temperature Conditions Using Small-Angle Neutron Scattering

    Science.gov (United States)

    Ding, M.; Hjelm, R.; Watkins, E.; Xu, H.; Pawar, R.

    2015-12-01

    Oil/gas produced from unconventional reservoirs has become strategically important for the US domestic energy independence. In unconventional realm, hydrocarbons are generated and stored in nanopores media ranging from a few to hundreds of nanometers. Fundamental knowledge of coupled thermo-hydro-mechanical-chemical (THMC) processes that control fluid flow and propagation within nano-pore confinement is critical for maximizing unconventional oil/gas production. The size and confinement of the nanometer pores creates many complex rock-fluid interface interactions. It is imperative to promote innovative experimental studies to decipher physical and chemical processes at the nanopore scale that govern hydrocarbon generation and mass transport of hydrocarbon mixtures in tight shale and other low permeability formations at reservoir pressure-temperature conditions. We have carried out laboratory investigations exploring quantitative relationship between pore characteristics of the Wolfcamp shale from Western Texas and the shale interaction with fluids at reservoir P-T conditions using small-angle neutron scattering (SANS). We have performed SANS measurements of the shale rock in single fluid (e.g., H2O and D2O) and multifluid (CH4/(30% H2O+70% D2O)) systems at various pressures up to 20000 psi and temperature up to 150 oF. Figure 1 shows our SANS data at different pressures with H2O as the pressure medium. Our data analysis using IRENA software suggests that the principal changes of pore volume in the shale occurred on smaller than 50 nm pores and pressure at 5000 psi (Figure 2). Our results also suggest that with increasing P, more water flows into pores; with decreasing P, water is retained in the pores.

  3. Organic tissues, graphite, and hydrocarbons in host rocks of the Rum Jungle Uranium Field, northern Australia

    Science.gov (United States)

    Foster, C.B.; Robbins, E.I.; Bone, Y.

    1990-01-01

    The Rum Jungle Uranium field consists of at least six early Proterozoic deposits that have been mined either for uranium and/or the associated base and precious metals. Organic matter in the host rocks of the Whites Formation and Coomalie Dolomite is now predominantly graphite, consistent with the metamorphic history of these rocks. For nine samples, the mean total organic carbon content is high (3.9 wt%) and ranged from 0.33 to 10.44 wt%. Palynological extracts from the host rocks include black, filamentous, stellate (Eoastrion-like), and spherical morphotypes, which are typical of early Proterozoic microbiota. The colour, abundance, and shapes of these morphotypes reflect the thermal history, organic richness, and probable lacustrine biofacies of the host rocks. Routine analysis of rock thin sections and of palynological residues shows that mineral grains in some of the host rocks are coated with graphitized organic matter. The grain coating is presumed to result from ultimate thermal degradation of a petroleum phase that existed prior to metamorphism. Hydrocarbons are, however, still present in fluid inclusions within carbonates of the Coomalie Dolomite and lower Whites Formation. The fluid inclusions fluoresce dull orange in blue-light excitation and their hydrocarbon content is confirmed by gas chromatography of whole-rock extracts. Preliminary analysis of the oil suggests that it is migrated, and because it has escaped graphitization through metamorphism it is probably not of early Proterozoic age. The presence of live oil is consistent with fluid inclusion data that suggest subsequent, low-temperature brine migration through the rocks. The present observations support earlier suggestions that organic matter in the host formations trapped uranium to form protore. Subsequent fluid migrations probably brought additional uranium and other metals to these formations, and the organic matter provided a reducing environment for entrapment. ?? 1990.

  4. Study of different factors affecting the electrical properties of natural gas reservoir rocks based on digital cores

    International Nuclear Information System (INIS)

    Jiang, Liming; Sun, Jianmeng; Wang, Haitao; Liu, Xuefeng

    2011-01-01

    The effects of the wettability and solubility of natural gas in formation water on the electrical properties of natural gas reservoir rocks are studied using the finite element method based on digital cores. The results show that the resistivity index of gas-wet reservoir rocks is significantly higher than that of water-wet reservoir rocks in the entire range of water saturation. The difference between them increases with decreasing water saturation. The resistivity index of natural gas reservoir rocks decreases with increasing additional conduction of water film. The solubility of natural gas in formation water has a dramatic effect on the electrical properties of reservoir rocks. The resistivity index of reservoir rocks increases as the solubility of natural gas increases. The effect of the solubility of natural gas on the resistivity index is very obvious under conditions of low water saturation, and it becomes weaker with increasing water saturation. Therefore, the reservoir wettability and the solubility of natural gas in formation water should be considered in defining the saturation exponent

  5. Influence of heat exchange of reservoir with rocks on hot gas injection via a single well

    Science.gov (United States)

    Nikolaev, Vladimir E.; Ivanov, Gavril I.

    2017-11-01

    In the computational experiment the influence of heat exchange through top and bottom of the gas-bearing reservoir on the dynamics of temperature and pressure fields during hot gas injection via a single well is investigated. The experiment was carried out within the framework of modified mathematical model of non-isothermal real gas filtration, obtained from the energy and mass conservation laws and the Darcy law. The physical and caloric equations of state together with the Newton-Riemann law of heat exchange of gas reservoir with surrounding rocks, are used as closing relations. It is shown that the influence of the heat exchange with environment on temperature field of the gas-bearing reservoir is localized in a narrow zone near its top and bottom, though the size of this zone is increased with time.

  6. Time-Lapse Seismic Monitoring and Performance Assessment of CO2 Sequestration in Hydrocarbon Reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Datta-Gupta, Akhil [Texas Engineering Experiment Station, College Station, TX (United States)

    2017-06-15

    Carbon dioxide sequestration remains an important and challenging research topic as a potentially viable approach for mitigating the effects of greenhouse gases on global warming (e.g., Chu and Majumdar, 2012; Bryant, 2007; Orr, 2004; Hepple and Benson, 2005; Bachu, 2003; Grimston et al., 2001). While CO2 can be sequestered in oceanic or terrestrial biomass, the most mature and effective technology currently available is sequestration in geologic formations, especially in known hydrocarbon reservoirs (Barrufet et al., 2010; Hepple and Benson, 2005). However, challenges in the design and implementation of sequestration projects remain, especially over long time scales. One problem is that the tendency for gravity override caused by the low density and viscosity of CO2. In the presence of subsurface heterogeneity, fractures and faults, there is a significant risk of CO2 leakage from the sequestration site into overlying rock compared to other liquid wastes (Hesse and Woods, 2010; Ennis-King and Patterson, 2002; Tsang et al., 2002). Furthermore, the CO2 will likely interact chemically with the rock in which it is stored, so that understanding and predicting its transport behavior during sequestration can be complex and difficult (Mandalaparty et al., 2011; Pruess et al., 2003). Leakage of CO2 can lead to such problems as acidification of ground water and killing of plant life, in addition to contamination of the atmosphere (Ha-Duong, 2003; Gasda et al., 2004). The development of adequate policies and regulatory systems to govern sequestration therefore requires improved characterization of the media in which CO2 is stored and the development of advanced methods for detecting and monitoring its flow and transport in the subsurface (Bachu, 2003).

  7. The elusive Hadean enriched reservoir revealed by 142Nd deficits in Isua Archaean rocks.

    Science.gov (United States)

    Rizo, Hanika; Boyet, Maud; Blichert-Toft, Janne; O'Neil, Jonathan; Rosing, Minik T; Paquette, Jean-Louis

    2012-11-01

    The first indisputable evidence for very early differentiation of the silicate Earth came from the extinct (146)Sm-(142)Nd chronometer. (142)Nd excesses measured in 3.7-billion-year (Gyr)-old rocks from Isua (southwest Greenland) relative to modern terrestrial samples imply their derivation from a depleted mantle formed in the Hadean eon (about 4,570-4,000 Gyr ago). As dictated by mass balance, the differentiation event responsible for the formation of the Isua early-depleted reservoir must also have formed a complementary enriched component. However, considerable efforts to find early-enriched mantle components in Isua have so far been unsuccessful. Here we show that the signature of the Hadean enriched reservoir, complementary to the depleted reservoir in Isua, is recorded in 3.4-Gyr-old mafic dykes intruding into the Early Archaean rocks. Five out of seven dykes carry (142)Nd deficits compared to the terrestrial Nd standard, with three samples yielding resolvable deficits down to -10.6 parts per million. The enriched component that we report here could have been a mantle reservoir that differentiated owing to the crystallization of a magma ocean, or could represent a mafic proto-crust that separated from the mantle more than 4.47 Gyr ago. Our results testify to the existence of an enriched component in the Hadean, and may suggest that the southwest Greenland mantle preserved early-formed heterogeneities until at least 3.4 Gyr ago.

  8. Lithofacies Architecturing and Hydrocarbon Reservoir Potential of Lumshiwal Formation: Surghar Range, Trans-Indus Ranges, North Pakistan

    Directory of Open Access Journals (Sweden)

    Iftikhar Alam

    2015-12-01

    directed Paleo-current system prevailed during deposition of Lumshiwal Formation. Diagenetic and tectonically induced fractures make the formation exceedingly porous and permeable as suitable reservoir horizon for the accumulation of hydrocarbon in the Trans-Indus ranges. The same formation has already been proven as potential reservoir horizon for hydrocarbon in the Kohat Plateau of northwest Pakistan. Secondly, the formation is dominantly comprised of silica/quartz sandstone (quartzarenite which can be used as silica sand, one of the essential raw materials for glass industries. The formation is also comprised of local coal seams which can be mined for production of coal in the region.

  9. A Multi-physics Approach to Understanding Low Porosity Soils and Reservoir Rocks

    Science.gov (United States)

    Prasad, M.; Mapeli, C.; Livo, K.; Hasanov, A.; Schindler, M.; Ou, L.

    2017-12-01

    We present recent results on our multiphysics approach to rock physics. Thus, we evaluate geophysical measurements by simultaneously measuring petrophysical properties or imaging strains. In this paper, we present simultaneously measured acoustic and electrical anisotropy data as functions of pressure. Similarly, we present strains and strain localization images simultaneously acquired with acoustic measurements as well as NMR T2 relaxations on pressurized fluids as well as rocks saturated with these pressurized fluids. Such multiphysics experiments allow us to constrain and assign appropriate causative mechanisms to development rock physics models. They also allow us to decouple various effects, for example, fluid versus pressure, on geophysical measurements. We show applications towards reservoir characterization as well as CO2 sequestration applications.

  10. On the CO2 Wettability of Reservoir Rocks: Addressing Conflicting Information

    Science.gov (United States)

    Garing, C.; Wang, S.; Tokunaga, T. K.; Wan, J.; Benson, S. M.

    2017-12-01

    Conventional wisdom is that siliclastic rocks are strongly water wet for the CO2-brine system, leading to high irreducible water saturation, moderate residual gas trapping and implying that tight rocks provide efficient seals for buoyant CO2. If the wetting properties become intermediate or CO2 wet, the conclusions regarding CO2 flow and trapping could be very different. Addressing the CO2 wettability of seal and reservoir rocks is therefore essential to predict CO2 storage in geologic formation. Although a substantial amount of work has been dedicated to the topic, contact angle data show a large variability and experiments on plates, micromodels and cores report conflicting results regarding the influence of supercritical CO2 (scCO2) exposure on wetting properties: whereas some experimental studies suggest dewetting upon reaction with scCO2, some others observe no wettability alteration under reservoir scCO2 conditions. After reviewing evidences for and against wettability changes associated with scCO2, we discuss potential causes for differences in experimental results. They include the presence of organic matter and impact of sample treatment, the type of media (non consolidated versus real rock), experimental time and exposure to scCO2, and difference in measurement system (porous plate versus stationary fluid method). In order to address these points, new scCO2/brine drainage-imbibition experiments were conducted on a same Berea sandstone rock core, first untreated, then fired and finally exposed to scCO2 for three weeks, using the stationary fluid method. The results are compared to similar experiments performed on quartz sands, untreated and then baked, using the porous plate method. In addition, a comparative experiment using the same Idaho gray sandstone rock core was performed with both the porous plate and the stationary fluid methods to investigate possible method-dependent results.

  11. An improved method for predicting brittleness of rocks via well logs in tight oil reservoirs

    Science.gov (United States)

    Wang, Zhenlin; Sun, Ting; Feng, Cheng; Wang, Wei; Han, Chuang

    2018-06-01

    There can be no industrial oil production in tight oil reservoirs until fracturing is undertaken. Under such conditions, the brittleness of the rocks is a very important factor. However, it has so far been difficult to predict. In this paper, the selected study area is the tight oil reservoirs in Lucaogou formation, Permian, Jimusaer sag, Junggar basin. According to the transformation of dynamic and static rock mechanics parameters and the correction of confining pressure, an improved method is proposed for quantitatively predicting the brittleness of rocks via well logs in tight oil reservoirs. First, 19 typical tight oil core samples are selected in the study area. Their static Young’s modulus, static Poisson’s ratio and petrophysical parameters are measured. In addition, the static brittleness indices of four other tight oil cores are measured under different confining pressure conditions. Second, the dynamic Young’s modulus, Poisson’s ratio and brittleness index are calculated using the compressional and shear wave velocity. With combination of the measured and calculated results, the transformation model of dynamic and static brittleness index is built based on the influence of porosity and clay content. The comparison of the predicted brittleness indices and measured results shows that the model has high accuracy. Third, on the basis of the experimental data under different confining pressure conditions, the amplifying factor of brittleness index is proposed to correct for the influence of confining pressure on the brittleness index. Finally, the above improved models are applied to formation evaluation via well logs. Compared with the results before correction, the results of the improved models agree better with the experimental data, which indicates that the improved models have better application effects. The brittleness index prediction method of tight oil reservoirs is improved in this research. It is of great importance in the optimization of

  12. Lacustrine Environment Reservoir Properties on Sandstone Minerals and Hydrocarbon Content: A Case Study on Doba Basin, Southern Chad

    Science.gov (United States)

    Sumery, N. F. Mohd; Lo, S. Z.; Salim, A. M. A.

    2017-10-01

    The contribution of lacustrine environment as the hydrocarbon reservoir has been widely known. However, despite its growing importance, the lacustrine petroleum geology has received far less attention than marine due to its sedimentological complexity. This study therefore aims in developing an understanding of the unique aspects of lacustrine reservoirs which eventually impacts the future exploration decisions. Hydrocarbon production in Doba Basin, particularly the northern boundary, for instance, has not yet succeeded due to the unawareness of its depositional environment. The drilling results show that the problems were due to the: radioactive sand and waxy oil/formation damage, which all are related to the lacustrine depositional environment. Detailed study of geological and petrophysical integration on wireline logs and petrographic thin sections analysis of this environment helps in distinguishing reservoir and non-reservoir areas and determining the possible mechanism causing the failed DST results. The interpretations show that the correlation of all types> of logs and rho matrix analysis are capable in identifying sand and shale bed despite of the radioactive sand present. The failure of DST results were due to the presence of arkose in sand and waxy oil in reservoir bed. This had been confirmed by the petrographic thin section analysis where the arkose has mineral twinning effect indicate feldspar and waxy oil showing bright colour under fluorescent light. Understanding these special lacustrine environment characteristics and features will lead to a better interpretation of hydrocarbon prospectivity for future exploration.

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

    Science.gov (United States)

    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.

  14. Geologic and petrophysic analysis of a travertine block as hydrocarbon reservoir analogue

    International Nuclear Information System (INIS)

    Basso, Mateus; Kuroda, Michelle Chaves; Vidal, Alexandre Campane

    2017-01-01

    Microbialitic limestones are gaining space in petroleum geology due to the existence of many reservoirs composed of these lithologies in the pre-salt producing fields. Travertine, calcareous tufa and stromatolites figure among the rocks proposed as analogous for the microbialitic rocks. This work conduces the study of geological, petrophysical and geophysical parameters of a travertine block measuring 1,60 x 1,60 x 2,70 m, weighing 21,2 tons and available in the Centro de Estudo do Petroleo (CEPETRO) at the Universidade Estadual de Campinas. The Italian block, named T-block, corresponds to the representative elementary volume of its original formation and allows the study in an intermediate scale between the hand sample and the outcrop scale. Permeability tests and gamma ray spectrometry measurements were conducted and the porosity was calculated by image analysis. Models were generated from the obtained data and then associated with descriptive geology of the block. A reduction in permeability, porosity and concentration of elements potassium (K), uranium (U) and thorium (Th) was recorded, following a gradient towards the top of the T-block accompanying the reduction in the degree of development of the rock fabric. (author)

  15. Optimizing and Quantifying CO2 Storage Resource in Saline Formations and Hydrocarbon Reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Bosshart, Nicholas W. [Univ. of North Dakota, Grand Folks, ND (United States). Energy & Environmental Research Center; Ayash, Scott C. [Univ. of North Dakota, Grand Folks, ND (United States). Energy & Environmental Research Center; Azzolina, Nicholas A. [Univ. of North Dakota, Grand Folks, ND (United States). Energy & Environmental Research Center; Peck, Wesley D. [Univ. of North Dakota, Grand Folks, ND (United States). Energy & Environmental Research Center; Gorecki, Charles D. [Univ. of North Dakota, Grand Folks, ND (United States). Energy & Environmental Research Center; Ge, Jun [Univ. of North Dakota, Grand Folks, ND (United States). Energy & Environmental Research Center; Jiang, Tao [Univ. of North Dakota, Grand Folks, ND (United States). Energy & Environmental Research Center; Burton-Kelly, Matthew E. [Univ. of North Dakota, Grand Folks, ND (United States). Energy & Environmental Research Center; Anderson, Parker W. [Univ. of North Dakota, Grand Folks, ND (United States). Energy & Environmental Research Center; Dotzenrod, Neil W. [Univ. of North Dakota, Grand Folks, ND (United States). Energy & Environmental Research Center; Gorz, Andrew J. [Univ. of North Dakota, Grand Folks, ND (United States). Energy & Environmental Research Center

    2017-06-30

    In an effort to reduce carbon dioxide (CO2) emissions from large stationary sources, carbon capture and storage (CCS) is being investigated as one approach. This work assesses CO2 storage resource estimation methods for deep saline formations (DSFs) and hydrocarbon reservoirs undergoing CO2 enhanced oil recovery (EOR). Project activities were conducted using geologic modeling and simulation to investigate CO2 storage efficiency. CO2 storage rates and efficiencies in DSFs classified by interpreted depositional environment were evaluated at the regional scale over a 100-year time frame. A focus was placed on developing results applicable to future widespread commercial-scale CO2 storage operations in which an array of injection wells may be used to optimize storage in saline formations. The results of this work suggest future investigations of prospective storage resource in closed or semiclosed formations need not have a detailed understanding of the depositional environment of the reservoir to generate meaningful estimates. However, the results of this work also illustrate the relative importance of depositional environment, formation depth, structural geometry, and boundary conditions on the rate of CO2 storage in these types of systems. CO2 EOR occupies an important place in the realm of geologic storage of CO2, as it is likely to be the primary means of geologic CO2 storage during the early stages of commercial implementation, given the lack of a national policy and the viability of the current business case. This work estimates CO2 storage efficiency factors using a unique industry database of CO2 EOR sites and 18 different reservoir simulation models capturing fluvial clastic and shallow shelf carbonate depositional environments for reservoir depths of 1219 and 2438 meters (4000 and 8000 feet) and 7.6-, 20-, and 64-meter (25-, 66

  16. Characteristics of waterflooding of oil pools with clay-containing reservoir rocks

    Energy Technology Data Exchange (ETDEWEB)

    Zheltov, Yu V; Stupochenko, V E; Khavkin, A Ya; Martos, V N

    1981-01-01

    When planning the development of oil fields with reservoir pressure maintenance by the injection of water or activated solutions (surfactants, alkali, etc.), it is necessary to take into account the consequences of phenomena related to clay swelling. For this purpose, it is necessary to measure on a core the parameters characterizing the change and hysteresis of the filtration and storage properties of the reservoir rocks. Swelling of the clay component of the rock along with reducing these properties in the sweep zone can promote an increase of the efficiency of displacing oil by water. Theoretical investigations showed that the maximum displacement efficiency in homogeneous clay-containing rocks does not depend on the time of starting stimulation by demineralized waters. The efficiency from changing the mineralization of the stimulating agent increases with increase of viscosity of the oil. Under certain physical and geologic conditions, a purposeful change of the filtration and storage properties by increasing or decreasing clay swelling can increase the efficiency of developing the field and can increase oil recovery.

  17. Sedimentary facies and lithologic characters as main factors controlling hydrocarbon accumulations and their critical conditions

    Directory of Open Access Journals (Sweden)

    Jun-Qing Chen

    2015-10-01

    Full Text Available Taking more than 1000 clastic hydrocarbon reservoirs of Bohai Bay Basin, Tarim Basin and Junggar Basin, China as examples, the paper has studied the main controlling factors of hydrocarbon reservoirs and their critical conditions to reveal the hydrocarbon distribution and to optimize the search for favorable targets. The results indicated that the various sedimentary facies and lithologic characters control the critical conditions of hydrocarbon accumulations, which shows that hydrocarbon is distributed mainly in sedimentary facies formed under conditions of a long-lived and relatively strong hydrodynamic environment; 95% of the hydrocarbon reservoirs and reserves in the three basins is distributed in siltstones, fine sandstones, lithified gravels and pebble-bearing sandstones; moreover, the probability of discovering conventional hydrocarbon reservoirs decreases with the grain size of the clastic rock. The main reason is that the low relative porosity and permeability of fine-grained reservoirs lead to small differences in capillary force compared with surrounding rocks small and insufficiency of dynamic force for hydrocarbon accumulation; the critical condition for hydrocarbon entering reservoir is that the interfacial potential in the surrounding rock (Φn must be more than twice of that in the reservoir (Φs; the probability of hydrocarbon reservoirs distribution decreases in cases where the hydrodynamic force is too high or too low and when the rocks have too coarse or too fine grains.

  18. Geological rock property and production problems of the underground gas storage reservoir of Ketzin

    Energy Technology Data Exchange (ETDEWEB)

    Lange, W

    1966-01-01

    The purpose of the program of operation for an industrial injection of gas is briefly reviewed. It is emphasized that the works constitute the final stage of exploration. The decisive economic and extractive aspects are given. Final remarks deal with the methods of floor consolidation and tightness control. In the interest of the perspective exploration of the reservoir it is concluded and must be realized as an operating principle that the main problem, after determining the probable reservoir structure, consists in determining step-by-step (by combined theoretical, technical and economic parameters) the surface equipment needed from the geological and rock property factors, which were determined by suitable methods (hydro-exploration, gas injection). The technique and time-table of the geological exploration, and the design and construction of the installations will depend on the solution of the main problem. At the beginning, partial capacities will be sufficient for the surface installation. (12 refs.)

  19. Ground deformation at collapse calderas: influence of host rock lithology and reservoir multiplicity

    Energy Technology Data Exchange (ETDEWEB)

    Geyer, A; Gottsmann, J [Department of Earth Sciences, University of Bristol, Wills Memorial Building, Queen' s Road, BS8 1RJ, Bristol (United Kingdom)], E-mail: A.GeverTraver@bristol.ac.uk

    2008-10-01

    A variety of source mechanisms have been proposed to account for observed caldera deformation. Here we present a systematic set of new results from numerical forward modelling using a Finite Element Method. which provides a link between measured ground deformation and the inaccessible deformation source. We simulate surface displacements due to pressure changes in a shallow oblate reservoir overlain by host rock with variable mechanical properties. We find that the amplitude and wavelength of resultant ground deformation is dependent on the distribution of mechanically stiff and soft lithologies and their relative distribution above a reservoir. In addition, we note an influence of layering on the critical ratio of horizontal over vertical displacements, a criterion employed to discriminate between different finite source geometries.

  20. Integrating sequence stratigraphy and rock-physics to interpret seismic amplitudes and predict reservoir quality

    Science.gov (United States)

    Dutta, Tanima

    This dissertation focuses on the link between seismic amplitudes and reservoir properties. Prediction of reservoir properties, such as sorting, sand/shale ratio, and cement-volume from seismic amplitudes improves by integrating knowledge from multiple disciplines. The key contribution of this dissertation is to improve the prediction of reservoir properties by integrating sequence stratigraphy and rock physics. Sequence stratigraphy has been successfully used for qualitative interpretation of seismic amplitudes to predict reservoir properties. Rock physics modeling allows quantitative interpretation of seismic amplitudes. However, often there is uncertainty about selecting geologically appropriate rock physics model and its input parameters, away from the wells. In the present dissertation, we exploit the predictive power of sequence stratigraphy to extract the spatial trends of sedimentological parameters that control seismic amplitudes. These spatial trends of sedimentological parameters can serve as valuable constraints in rock physics modeling, especially away from the wells. Consequently, rock physics modeling, integrated with the trends from sequence stratigraphy, become useful for interpreting observed seismic amplitudes away from the wells in terms of underlying sedimentological parameters. We illustrate this methodology using a comprehensive dataset from channelized turbidite systems, deposited in minibasin settings in the offshore Equatorial Guinea, West Africa. First, we present a practical recipe for using closed-form expressions of effective medium models to predict seismic velocities in unconsolidated sandstones. We use an effective medium model that combines perfectly rough and smooth grains (the extended Walton model), and use that model to derive coordination number, porosity, and pressure relations for P and S wave velocities from experimental data. Our recipe provides reasonable fits to other experimental and borehole data, and specifically

  1. Diffusion and spatially resolved NMR in Berea and Venezuelan oil reservoir rocks.

    Science.gov (United States)

    Murgich, J; Corti, M; Pavesi, L; Voltini, F

    1992-01-01

    Conventional and spatially resolved proton NMR and relaxation measurements are used in order to study the molecular motions and the equilibrium and nonequilibrium diffusion of oils in Berea sandstone and Venezuelan reservoir rocks. In the water-saturated Berea a single line with T*2 congruent to 150 microseconds is observed, while the relaxation recovery is multiexponential. In an oil reservoir rock (Ful 13) a single narrow line is present while a distribution of relaxation rates is evidenced from the recovery plots. On the contrary, in the Ful 7 sample (extracted at a deeper depth in a different zone) two NMR components are present, with 3.5 and 30 KHz linewidths, and the recovery plot exhibits biexponential law. No echo signal could be reconstructed in the oil reservoir rocks. These findings can be related to the effects in the micropores, where motions at very low frequency can occur in a thin layer. From a comparison of the diffusion constant in water-saturated Berea, D congruent to 5*10(-6) cm2/sec, with the ones in model systems, the average size of the pores is estimated around 40 A. The density profiles at the equilibrium show uniform distribution of oils or of water, and the relaxation rates appear independent from the selected slice. The nonequilibrium diffusion was studied as a function of time in a Berea cylinder with z axis along H0, starting from a thin layer of oil at the base, and detecting the spin density profiles d(z,t) with slice-selection techniques. Simultaneously, the values of T1's were measured locally, and the distribution of the relaxation rates was observed to be present in any slice.(ABSTRACT TRUNCATED AT 250 WORDS)

  2. Evaluation on occluded hydrocarbon in deep–ultra deep ancient source rocks and its cracked gas resources

    Directory of Open Access Journals (Sweden)

    Jian Li

    2015-12-01

    Full Text Available Oil-cracked gas, as the main type of high-over mature marine natural gas in China, is mainly derived from occluded hydrocarbon. So it is significant to carry out quantitative study on occluded hydrocarbon. In this paper, the occluded hydrocarbon volume of the main basins in China was calculated depending on their types, abundances and evolution stages by means of the forward method (experimental simulation and the inversion method (geologic profile dissection. And then, occluded hydrocarbon evolution models were established for five types of source rocks (sapropelic, sapropelic prone hybrid, humic prone hybrid, humic and coal. It is shown that the hydrocarbon expulsion efficiency of sapropelic and sapropelic prone hybrid excellent source rocks is lower than 30% at the low-maturity stage, 30%–60% at the principal oil generation stage, and 50%–80% at the high-maturity stage, which are all about 10% higher than that of humic prone hybrid and humic source rocks at the corresponding stages. The resource distribution and cracked gas expulsion of occluded hydrocarbon since the high-maturity stage of marine source rocks in the Sichuan Basin were preliminarily calculated on the basis of the evolution models. The cracked gas expulsion is 230.4 × 1012 m3 at the high evolution stage of occluded hydrocarbon of the Lower Cambrian Qiongzhusi Fm in this basin, and 12.3 × 1012 m3 from the source rocks of Sinian Doushantuo Fm, indicating good potential for natural gas resources. It is indicated that the favorable areas of occluded hydrocarbon cracked gas in the Qiongzhusi Fm source rocks in the Sichuan Basin include Gaoshiti–Moxi, Ziyang and Weiyuan, covering a favorable area of 4.3 × 104 km2.

  3. Inverse Problems in Geosciences: Modelling the Rock Properties of an Oil Reservoir

    DEFF Research Database (Denmark)

    Lange, Katrine

    . We have developed and implemented the Frequency Matching method that uses the closed form expression of the a priori probability density function to formulate an inverse problem and compute the maximum a posteriori solution to it. Other methods for computing models that simultaneously fit data...... of the subsurface of the reservoirs. Hence the focus of this work has been on acquiring models of spatial parameters describing rock properties of the subsurface using geostatistical a priori knowledge and available geophysical data. Such models are solutions to often severely under-determined, inverse problems...

  4. Organic maturation levels, thermal history and hydrocarbon source rock potential of the Namurian rocks of the Clare Basin, Ireland

    Energy Technology Data Exchange (ETDEWEB)

    Goodhue, Robbie; Clayton, Geoffrey [Trinity Coll., Dept. of Geology, Dublin (Ireland)

    1999-11-01

    Vitrinite reflectance data from two inland cored boreholes confirm high maturation levels throughout the onshore part of the Irish Clare Basin and suggest erosion of 2 to 4 km of late Carboniferous cover and elevated palaeogeothermal gradients in the Carboniferous section. The observed maturation gradients are fully consistent with the published hypothesis of a late Carboniferous/Permian 'superplume' beneath Pangaea but local vertical reversals in gradients also suggest a complex thermal regime probably involving advective heating. The uppermost Visean--lower Namurian Clare Shale is laterally extensive and up to 300 m thick. Although this unit is post-mature, TOC values of up to 15% suggest that it could have considerable hydrocarbon source rock potential in any less mature offshore parts of the basin. (Author)

  5. Pre-drilling prediction techniques on the high-temperature high-pressure hydrocarbon reservoirs offshore Hainan Island, China

    Science.gov (United States)

    Zhang, Hanyu; Liu, Huaishan; Wu, Shiguo; Sun, Jin; Yang, Chaoqun; Xie, Yangbing; Chen, Chuanxu; Gao, Jinwei; Wang, Jiliang

    2018-02-01

    Decreasing the risks and geohazards associated with drilling engineering in high-temperature high-pressure (HTHP) geologic settings begins with the implementation of pre-drilling prediction techniques (PPTs). To improve the accuracy of geopressure prediction in HTHP hydrocarbon reservoirs offshore Hainan Island, we made a comprehensive summary of current PPTs to identify existing problems and challenges by analyzing the global distribution of HTHP hydrocarbon reservoirs, the research status of PPTs, and the geologic setting and its HTHP formation mechanism. Our research results indicate that the HTHP formation mechanism in the study area is caused by multiple factors, including rapid loading, diapir intrusions, hydrocarbon generation, and the thermal expansion of pore fluids. Due to this multi-factor interaction, a cloud of HTHP hydrocarbon reservoirs has developed in the Ying-Qiong Basin, but only traditional PPTs have been implemented, based on the assumption of conditions that do not conform to the actual geologic environment, e.g., Bellotti's law and Eaton's law. In this paper, we focus on these issues, identify some challenges and solutions, and call for further PPT research to address the drawbacks of previous works and meet the challenges associated with the deepwater technology gap. In this way, we hope to contribute to the improved accuracy of geopressure prediction prior to drilling and provide support for future HTHP drilling offshore Hainan Island.

  6. Reservoir simulation with the cubic plus (cross-) association equation of state for water, CO2, hydrocarbons, and tracers

    Science.gov (United States)

    Moortgat, Joachim

    2018-04-01

    This work presents an efficient reservoir simulation framework for multicomponent, multiphase, compressible flow, based on the cubic-plus-association (CPA) equation of state (EOS). CPA is an accurate EOS for mixtures that contain non-polar hydrocarbons, self-associating polar water, and cross-associating molecules like methane, ethane, unsaturated hydrocarbons, CO2, and H2S. While CPA is accurate, its mathematical formulation is highly non-linear, resulting in excessive computational costs that have made the EOS unfeasible for large scale reservoir simulations. This work presents algorithms that overcome these bottlenecks and achieve an efficiency comparable to the much simpler cubic EOS approach. The main applications that require such accurate phase behavior modeling are 1) the study of methane leakage from high-pressure production wells and its potential impact on groundwater resources, 2) modeling of geological CO2 sequestration in brine aquifers when one is interested in more than the CO2 and H2O components, e.g. methane, other light hydrocarbons, and various tracers, and 3) enhanced oil recovery by CO2 injection in reservoirs that have previously been waterflooded or contain connate water. We present numerical examples of all those scenarios, extensive validation of the CPA EOS with experimental data, and analyses of the efficiency of our proposed numerical schemes. The accuracy, efficiency, and robustness of the presented phase split computations pave the way to more widespread adoption of CPA in reservoir simulators.

  7. A chemical and thermodynamic model of oil generation in hydrocarbon source rocks

    Science.gov (United States)

    Helgeson, Harold C.; Richard, Laurent; McKenzie, William F.; Norton, Denis L.; Schmitt, Alexandra

    2009-02-01

    Thermodynamic calculations and Gibbs free energy minimization computer experiments strongly support the hypothesis that kerogen maturation and oil generation are inevitable consequences of oxidation/reduction disproportionation reactions caused by prograde metamorphism of hydrocarbon source rocks with increasing depth of burial.These experiments indicate that oxygen and hydrogen are conserved in the process.Accordingly, if water is stable and present in the source rock at temperatures ≳25 but ≲100 °C along a typical US Gulf Coast geotherm, immature (reduced) kerogen with a given atomic hydrogen to carbon ratio (H/C) melts incongruently with increasing temperature and depth of burial to produce a metastable equilibrium phase assemblage consisting of naphthenic/biomarker-rich crude oil, a type-II/III kerogen with an atomic hydrogen/carbon ratio (H/C) of ˜1, and water. Hence, this incongruent melting process promotes diagenetic reaction of detritus in the source rock to form authigenic mineral assemblages.However, in the water-absent region of the system CHO (which is extensive), any water initially present or subsequently entering the source rock is consumed by reaction with the most mature kerogen with the lowest H/C it encounters to form CO 2 gas and a new kerogen with higher H/C and O/C, both of which are in metastable equilibrium with one another.This hydrolytic disproportionation process progressively increases both the concentration of the solute in the aqueous phase, and the oil generation potential of the source rock; i.e., the new kerogen can then produce more crude oil.Petroleum is generated with increasing temperature and depth of burial of hydrocarbon source rocks in which water is not stable in the system CHO by a series of irreversible disproportionation reactions in which kerogens with higher (H/C)s melt incongruently to produce metastable equilibrium assemblages consisting of crude oil, CO 2 gas, and a more mature (oxidized) kerogen with a lower

  8. Bathymetric maps and water-quality profiles of Table Rock and North Saluda Reservoirs, Greenville County, South Carolina

    Science.gov (United States)

    Clark, Jimmy M.; Journey, Celeste A.; Nagle, Doug D.; Lanier, Timothy H.

    2014-01-01

    Lakes and reservoirs are the water-supply source for many communities. As such, water-resource managers that oversee these water supplies require monitoring of the quantity and quality of the resource. Monitoring information can be used to assess the basic conditions within the reservoir and to establish a reliable estimate of storage capacity. In April and May 2013, a global navigation satellite system receiver and fathometer were used to collect bathymetric data, and an autonomous underwater vehicle was used to collect water-quality and bathymetric data at Table Rock Reservoir and North Saluda Reservoir in Greenville County, South Carolina. These bathymetric data were used to create a bathymetric contour map and stage-area and stage-volume relation tables for each reservoir. Additionally, statistical summaries of the water-quality data were used to provide a general description of water-quality conditions in the reservoirs.

  9. Development of a X-ray micro-tomograph and its application to reservoir rocks characterization

    International Nuclear Information System (INIS)

    Ferreira de Paiva, R.

    1995-10-01

    We describe the construction and application to studies in three dimensions of a laboratory micro-tomograph for the characterisation of heterogeneous solids at the scale of a few microns. The system is based on an electron microprobe and a two dimensional X-ray detector. The use of a low beam divergence for image acquisition allows use of simple and rapid reconstruction software whilst retaining reasonable acquisition times. Spatial resolutions of better than 3 microns in radiography and 10 microns in tomography are obtained. The applications of microtomography in the petroleum industry are illustrated by the study of fibre orientation in polymer composites, of the distribution of minerals and pore space in reservoir rocks, and of the interaction of salt water with a model porous medium. A correction for X-ray beam hardening is described and used to obtain improved discrimination of the phases present in the sample. In the case of a North Sea reservoir rock we show the possibility to distinguish quartz, feldspar and in certain zone kaolinite. The representativeness of the tomographic reconstruction is demonstrated by comparing the surface of the reconstructed specimen with corresponding images obtained in scanning electron microscopy. (author). 58 refs., 10 tabs., 71 photos

  10. Structural analysis of porous rock reservoirs subjected to conditions of compressed air energy storage

    Energy Technology Data Exchange (ETDEWEB)

    Friley, J.R.

    1980-01-01

    Investigations are described which were performed to assess the structural behavior of porous rock compressed air energy storage (CAES) reservoirs subjected to loading conditions of temperature and pressure felt to be typical of such an operation. Analyses performed addressed not only the nominal or mean reservoir response but also the cyclic response due to charge/discharge operation. The analyses were carried out by assuming various geometrical and material related parameters of a generic site. The objective of this study was to determine the gross response of a generic porous reservoir. The site geometry for this study assumed a cylindrical model 122 m in dia and 57 m high including thicknesses for the cap, porous, and base rock formations. The central portion of the porous zone was assumed to be at a depth of 518 m and at an initial temperature of 20/sup 0/C. Cyclic loading conditions of compressed air consisted of pressure values in the range of 4.5 to 5.2 MPa and temperature values between 143 and 204/sup 0/C.Various modes of structural behavior were studied. These response modes were analyzed using loading conditions of temperature and pressure (in the porous zone) corresponding to various operational states during the first year of simulated site operation. The results of the structural analyses performed indicate that the most severely stressed region will likely be in the wellbore vicinity and hence highly dependent on the length of and placement technique utilized in the well production length. Analyses to address this specific areas are currently being pursued.

  11. Validating predictions of evolving porosity and permeability in carbonate reservoir rocks exposed to CO2-brine

    Science.gov (United States)

    Smith, M. M.; Hao, Y.; Carroll, S.

    2017-12-01

    Improving our ability to better forecast the extent and impact of changes in porosity and permeability due to CO2-brine-carbonate reservoir interactions should lower uncertainty in long-term geologic CO2 storage capacity estimates. We have developed a continuum-scale reactive transport model that simulates spatial and temporal changes to porosity, permeability, mineralogy, and fluid composition within carbonate rocks exposed to CO2 and brine at storage reservoir conditions. The model relies on two primary parameters to simulate brine-CO2-carbonate mineral reaction: kinetic rate constant(s), kmineral, for carbonate dissolution; and an exponential parameter, n, relating porosity change to resulting permeability. Experimental data collected from fifteen core-flooding experiments conducted on samples from the Weyburn (Saskatchewan, Canada) and Arbuckle (Kansas, USA) carbonate reservoirs were used to calibrate the reactive-transport model and constrain the useful range of k and n values. Here we present the results of our current efforts to validate this model and the use of these parameter values, by comparing predictions of extent and location of dissolution and the evolution of fluid permeability against our results from new core-flood experiments conducted on samples from the Duperow Formation (Montana, USA). Agreement between model predictions and experimental data increase our confidence that these parameter ranges need not be considered site-specific but may be applied (within reason) at various locations and reservoirs. This work was performed under the auspices of the U.S. Department of Energy by Lawrence Livermore National Laboratory under Contract DE-AC52-07NA27344.

  12. International Workshop on Hot Dry Rock. Creation and evaluation of geothermal reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    NONE

    1988-11-04

    At the above-named event which met on November 4 and 5, 1988, a number of essays were presented concerning the fracture system, exploration, evaluation, geophysical measurement application, etc., as developed in the U.S., France, Sweden, Italy, Japan, England, etc. Novel technologies are necessary for a breakthrough in HDR (hot dry rock) exploitation. In the designing of an HDR system, the orientation and dimensions of a fracture to be hydraulically produced have to be appropriately predicted, for which knowledge of rock physical properties and geological structures and the technology of simulating them will be useful. Drilling and geophysical probing of rock mass are some means for fracture observation. Seismometer-aided mapping by AE (acoustic emission) observation is performed while hydraulic fracturing is under way. Upon completion of an HDR circulation system, evaluation of the reservoir by experiment or theory becomes necessary. The heat exchanging area and deposition are estimated using the geochemical data, temperature fall, etc., of the liquid in circulation. If fracture impedance or water loss is out of the designed level, the fracture needs improvement. (NEDO)

  13. A sedimentological approach to refining reservoir architecture in a mature hydrocarbon province: the Brent Province, UK North Sea

    Energy Technology Data Exchange (ETDEWEB)

    Hampson, G.J.; Sixsmith, P.J.; Johnson, H.D. [Imperial College, London (United Kingdom). Dept. of Earth Science and Engineering

    2004-04-01

    Improved reservoir characterisation in the mature Brent Province of the North Sea, aimed at maximising both in-field and near-field hydrocarbon potential, requires a clearer understanding of sub-seismic stratigraphy and facies distributions. In this context, we present a regional, high-resolution sequence stratigraphic framework for the Brent Group, UK North Sea based on extensive sedimentological re-interpretation of core and wireline-log data, combined with palynostratigraphy and published literature. This framework is used to place individual reservoirs in an appropriate regional context, thus resulting in the identification of subtle sedimentological and tectono-stratigraphic features of reservoir architecture that have been previously overlooked. We emphasise the following insights gained from our regional, high-resolution sequence stratigraphic synthesis: (1) improved definition of temporal and spatial trends in deposition both within and between individual reservoirs, (2) development of regionally consistent, predictive sedimentological models for two enigmatic reservoir intervals (the Broom and Tarbert Formations), and (3) recognition of subtle local tectono-stratigraphic controls on reservoir architecture, and their links to the regional, Middle Jurassic structural evolution of the northern North Sea. We discuss the potential applications of these insights to the identification of additional exploration potential and to improved ultimate recovery. (author)

  14. Isotopic and geochemical tools to assess the feasibility of methanogenesis as a way to enhance hydrocarbon recovery in oil reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Jimenez, N.; Morris, B.E.L.; Richnow, H.H. [Helmholtz-Zentrum fuer Umweltforschung (UFZ), Leipzig (Germany). Abt. Isotopenbiogeochemie; Cai, M.; Yao, Jun [Helmholtz-Zentrum fuer Umweltforschung (UFZ), Leipzig (Germany). Abt. Isotopenbiogeochemie; University of Sicence and Technology, Beijing (China). School of Civil and Environment Engineering; Straaten, N.; Krueger, M. [Bundesanstalt fuer Geowissenschaften und Rohstoffe (BGR), Hannover (Germany). Fachbereich Geochemie

    2013-08-01

    In situ biotransformation of oil to methane was investigated in a thermophilic reservoir in Dagang, China using isotopic analyzes, chemical fingerprinting and molecular and biological methods. Our first results, which were already published, demonstrated that anaerobic oil degradation concomitant with methane production was occurring. The reservoir was highly methanogenic and the oil exhibited varying degrees of degradation between different parts of the reservoir, although it was mainly highly weathered, and nearly devoid of nalkanes, alkylbenzenes, alkyltoluenes, and light PAHs. In addition, the isotopic data from reservoir oil, water and gas was used to elucidate the origin of the methane. The average {delta}{sup 13}C for methane was around -47 permille and CO{sub 2} was highly enriched in {sup 13}C. The bulk isotopic discrimination ({Delta}{delta}{sup 13}C) between methane and CO{sub 2} was between 32 and 65 permille, in accordance with previously reported results for methane formation during hydrocarbon degradation. Subsequent microcosm experiments revealed that autochthonous microbiota are capable of degrading oil under methanogenic conditions and of producing methane and/or CO{sub 2} from {sup 13}C-labelled n-hexadecane, 2-methylnaphthalene or toluene ({delta}{sup 13}C values up to 550 permille). These results demonstrate that methanogenesis is linked to aliphatic and aromatic hydrocarbon degradation. Further experiments will elucidate the activation mechanisms for the different compounds. (orig.)

  15. Factors controlling leaching of polycyclic aromatic hydrocarbons from petroleum source rock using nonionic surfactant

    Energy Technology Data Exchange (ETDEWEB)

    Akinlua, Akinsehinwa [Obafemi Awolowo Univ., Ile-Ife (Nigeria). Fossil Fuels and Environmental Geochemistry Group; Jochmann, Maik A.; Qian, Yuan; Schmidt, Torsten C. [Duisburg-Essen Univ., Essen (Germany). Instrumental Analytical Chemistry; Sulkowski, Martin [Duisburg-Essen Univ., Essen (Germany). Inst. of Environmental Analytical Chemistry

    2012-03-15

    The extraction of polycyclic aromatic hydrocarbons (PAHs) from petroleum source rock by nonionic surfactants with the assistance of microwave irradiation was investigated and the conditions for maximum yield were determined. The results showed that the extraction temperatures and type of surfactant have significant effects on extraction yields of PAHs. Factors such as surfactant concentration, irradiation power, sample/solvent ratio and mixing surfactants (i.e., mixture of surfactant at specific ratio) also influence the extraction efficiencies for these compounds. The optimum temperature for microwave-assisted nonionic surfactant extraction of PAHs from petroleum source rock was 120 C and the best suited surfactant was Brij 35. The new method showed extraction efficiencies comparable to those afforded by the Soxhlet extraction method, but a reduction of the extraction times and environmentally friendliness of the new nonionic surfactant extraction system are clear advantages. The results also show that microwave-assisted nonionic surfactant extraction is a good and efficient green analytical preparatory technique for geochemical evaluation of petroleum source rock. (orig.)

  16. Hydrocarbon Source Rock Potential of the Sinamar Formation, Muara Bungo, Jambi

    Directory of Open Access Journals (Sweden)

    Moh. Heri Hermiyanto Zajuli

    2014-07-01

    Full Text Available DOI: 10.17014/ijog.v1i1.175The Oligocene Sinamar Formation consists of shale, claystone, mudstone, sandstone, conglomeratic sandstone, and intercalation of coal seams. The objective of study was to identify the hydrocarbon source rock potential of the Sinamar Formation based on geochemichal characteristics. The analyses were focused on fine sediments of the Sinamar Formation comprising shale, claystone, and mudstone. Primary data collected from the Sinamar Formation well and outcrops were analyzed according to TOC, pyrolisis analysis, and gas chromatography - mass spectometry of normal alkanes that include isoprenoids and sterane. The TOC value indicates a very well category. Based on TOC versus Pyrolysis Yields (PY diagram, the shales of Sinamar Formation are included into oil prone source rock potential with good to excellent categories. Fine sediments of the Sinamar Formation tend to produce oil and gas originated from kerogen types I and III. The shales tend to generate oil than claystone and mudstone and therefore they are included into a potential source rock

  17. Organic geochemical characterization of potential hydrocarbon source rocks in the upper Benue Trough

    International Nuclear Information System (INIS)

    Obaje, N. G.; Pearson, M. J.; Suh, C. E.; Dada, S. S.

    1999-01-01

    The Upper Benue Trough of Nigeria is the northeastern most portion of the Benue rift structure that extends from the northern limit of the Niger Delta in the south to the southern limit of the Chad basin int he northeast. this portion of the trough is made up of two arms: the Gongola Arm and the Yola Arm. Stratigraphic sequence in the Gongola Arm comprises the continental Albian Bima Sandstone, the transitional Cenomanian Yolde Formation and the marine Turonian - Santonian Gongila, Pindiga, and Fika Formations. Overlying these are the continental Campane - Maastrichtian Gombe Sandstone and the Tertiary Kerri - Kerri Formation. In the Yola Arm, the Turonian - Santonian sequence is replaced by the equally marine Dukul, Jessu, Sekuliye Formations, Numanha Shale, and the Lamja Sandstone. Organic geochemical studies have been carried on outcrop sample form the Gongila, Pindiga, Dukul Formations, the Fika shale and the shaly units of the Gombe Sandstone, with the aim of assessing their source rock potential. Gas Chromatography (GC), Gas Chromatography - Mass Spectrometry (C - MS), and Rock Eval Pyrolysis were the major organic geochemical tools employed. Biomaker hydrocarbon signatures obtained from the GC - MS and the Rock Eval Pyrolysis results indicate that all he formations studied, except the Dukul formation, are immature and are all lean in organic matter

  18. Characterization of coal-derived hydrocarbons and source-rock potential of coal beds, San Juan Basin, New Mexico and Colorado, U.S.A.

    Science.gov (United States)

    Rice, D.D.; Clayton, J.L.; Pawlewicz, M.J.

    1989-01-01

    Coal beds are considered to be a major source of nonassociated gas in the Rocky Mountain basins of the United States. In the San Juan basin of northwestern New Mexico and southwestern Colorado, significant quantities of natural gas are being produced from coal beds of the Upper Cretaceous Fruitland Formation and from adjacent sandstone reservoirs. Analysis of gas samples from the various gas-producing intervals provided a means of determining their origin and of evaluating coal beds as source rocks. The rank of coal beds in the Fruitland Formation in the central part of the San Juan basin, where major gas production occurs, increases to the northeast and ranges from high-volatile B bituminous coal to medium-volatile bituminous coal (Rm values range from 0.70 to 1.45%). On the basis of chemical, isotopic and coal-rank data, the gases are interpreted to be thermogenic. Gases from the coal beds show little isotopic variation (??13C1 values range -43.6 to -40.5 ppt), are chemically dry (C1/C1-5 values are > 0.99), and contain significant amounts of CO2 (as much as 6%). These gases are interpreted to have resulted from devolatilization of the humic-type bituminous coal that is composed mainly of vitrinite. The primary products of this process are CH4, CO2 and H2O. The coal-generated, methane-rich gas is usually contained in the coal beds of the Fruitland Formation, and has not been expelled and has not migrated into the adjacent sandstone reservoirs. In addition, the coal-bed reservoirs produce a distinctive bicarbonate-type connate water and have higher reservoir pressures than adjacent sandstones. The combination of these factors indicates that coal beds are a closed reservoir system created by the gases, waters, and associated pressures in the micropore coal structure. In contrast, gases produced from overlying sandstones in the Fruitland Formation and underlying Pictured Cliffs Sandstone have a wider range of isotopic values (??13C1 values range from -43.5 to -38

  19. Evaluation of Management of Water Release for Painted Rocks Reservoir, Bitterroot River, Montana, 1984 Annual Report.

    Energy Technology Data Exchange (ETDEWEB)

    Lere, Mark E. (Montana Department of Fish, Wildlife and Parks, Missoula, MT)

    1984-11-01

    Baseline fisheries and habitat data were gathered during 1983 and 1984 to evaluate the effectiveness of supplemental water releases from Painted Rocks Reservoir in improving the fisheries resource in the Bitterroot River. Discharge relationships among main stem gaging stations varied annually and seasonally. Flow relationships in the river were dependent upon rainfall events and the timing and duration of the irrigation season. Daily discharge monitored during the summers of 1983 and 1984 was greater than median values derived at the U.S.G.S. station near Darby. Supplemental water released from Painted Rocks Reservoir totaled 14,476 acre feet in 1983 and 13,958 acre feet in 1984. Approximately 63% of a 5.66 m{sup 3}/sec test release of supplemental water conducted during April, 1984 was lost to irrigation withdrawals and natural phenomena before passing Bell Crossing. A similar loss occurred during a 5.66 m{sup 3}/sec test release conducted in August, 1984. Daily maximum temperature monitored during 1984 in the Bitterroot River averaged 11.0, 12.5, 13.9 and 13.6 C at the Darby, Hamilton, Bell and McClay stations, respectively. Chemical parameters measured in the Bitterroot River were favorable to aquatic life. Population estimates conducted in the Fall, 1983 indicated densities of I+ and older rainbow trout (Salmo gairdneri) were significantly greater in a control section than in a dewatered section (p < 0.20). Numbers of I+ and older brown trout (Salmo trutta) were not significantly different between the control and dewatered sections (p > 0.20). Population and biomass estimates for trout in the control section were 631/km and 154.4 kg/km. In the dewatered section, population and biomass estimates for trout were 253/km and 122.8 kg/km. The growth increments of back-calculated length for rainbow trout averaged 75.6 mm in the control section and 66.9mm in the dewatered section. The growth increments of back-calculated length for brown trout averaged 79.5 mm in the

  20. Experimental simulation of the geological storage of CO2: particular study of the interfaces between well cement, cap-rock and reservoir rock

    International Nuclear Information System (INIS)

    Jobard, Emmanuel

    2013-01-01

    The geological storage of the CO 2 is envisaged to mitigate the anthropogenic greenhouse gas emissions in the short term. CO 2 is trapped from big emitters and is directly injected into a reservoir rock (mainly in deep salty aquifers, depleted hydrocarbon oil fields or unexploited charcoal lodes) located at more than 800 m deep. In the framework of the CO 2 storage, it is crucial to ensure the integrity of the solicited materials in order to guarantee the permanent confinement of the sequestrated fluids. Using experimental simulation the purpose of this work is to study the mechanisms which could be responsible for the system destabilization and could lead CO 2 leakage from the injection well. The experimental simulations are performed under pressure and temperature conditions of the geological storage (100 bar and from 80 to 100 deg. C). The first experimental model, called COTAGES (for 'Colonne Thermoregulee A Grains pour Gaz a Effet de Serre') allows studying the effects of the thermal destabilisation caused by the injection of a fluid at 25 deg. C in a hotter reservoir (submitted to the geothermal gradient). This device composed of an aqueous saline solution (4 g.L -1 of NaCl), crushed rock (Lavoux limestone or Callovo-Oxfordian argillite) and gas (N 2 or CO 2 ) allows demonstrating an important matter transfer from the cold area (30 deg. C) toward the hot area (100 deg. C). The observed dissolution/precipitation phenomena leading to changes of the petro-physical rocks properties occur in presence of N 2 or CO 2 but are significantly amplified by the presence of CO 2 . Concerning the experiments carried out with Lavoux limestone, the dissolution in the cold zone causes a raise of porosity of about 2% (initial porosity of 8%) due to the formation of about 500 pores/mm 2 with a size ranging between 10 and 100 μm 2 . The precipitation in the hot zone forms a micro-calcite fringe on the external part of the grains and fills the intergrain porosity

  1. Compound-specific radiocarbon analysis of polycyclic aromatic hydrocarbons (PAHs) in sediments from an urban reservoir

    International Nuclear Information System (INIS)

    Kanke, Hirohide; Uchida, Masao; Okuda, Tomoaki; Yoneda, Minoru; Takada, Hideshige; Shibata, Yasuyuki; Morita, Masatoshi

    2004-01-01

    A quantitative apportionment of polycyclic aromatic hydrocarbons (PAHs) derived from fossil fuel combustion ( 14 C-free) and biomass burning (contemporary 14 C) was carried out using a recently developed compound-specific radiocarbon analysis (CSRA) method for a sediment core from an urban reservoir located in the central Tokyo metropolitan area, Japan. The 14 C abundance of PAHs in the sediments was measured by accelerator mass spectrometry (AMS) after extraction and purification by three types of column chromatography, by high performance liquid chromatography (HPLC), and, subsequently, by a preparative capillary gas chromatography (PCGC) system. This method yielded a sufficient quantity of pure compounds and allowed a high degree of confidence in the determination of 14 C. The fraction modern values (f M ) of individual PAHs (phenanthrene, alkylphenanthrenes, fluoranthene, pyrene and benz[a]anthracene) in the sediments ranged from 0.06 to 0.21. These results suggest that sedimentary PAHs (those compounds mentioned above) were derived mostly from fossil fuel combustion. Three sectioned-downcore profiles (∼40 cm) of the 14 C abundance in phenanthrene and alkylphenanthrenes showed a decreasing trend with depth, that was anti-correlated with the trend of ΣPAHs concentration. The f M values of phenanthrene were also larger than those of alkylphenanthrenes in each section of the core. This result indicates that phenanthrene received a greater contribution from biomass burning than alkylphenanthrenes throughout the core. This finding highlights the method used here as an useful approach to elucidate the source and origin of PAHs in the environment

  2. Subcontinuum mass transport of hydrocarbons in nanoporous media and long-time kinetics of recovery from unconventional reservoirs

    Science.gov (United States)

    Bocquet, Lyderic

    2015-11-01

    In this talk I will discuss the transport of hydrocarbons across nanoporous media and analyze how this transport impacts at larger scales the long-time kinetics of hydrocarbon recovery from unconventional reservoirs (the so-called shale gas). First I will establish, using molecular simulation and statistical mechanics, that the continuum description - the so-called Darcy law - fails to predict transport within a nanoscale organic matrix. The non-Darcy behavior arises from the strong adsorption of the alkanes in the nanoporous material and the breakdown of hydrodynamics at the nanoscale, which contradicts the assumption of viscous flow. Despite this complexity, all permeances collapse on a master curve with an unexpected dependence on alkane length, which can be described theoretically by a scaling law for the permeance. Then I will show that alkane recovery from such nanoporous reservoirs is dynamically retarded due to interfacial effects occuring at the material's interface. This occurs especially in the hydraulic fracking situation in which water is used to open fractures to reach the hydrocarbon reservoirs. Despite the pressure gradient used to trigger desorption, the alkanes remain trapped for long times until water desorbs from the external surface. The free energy barrier can be predicted in terms of an effective contact angle on the composite nanoporous surface. Using a statistical description of the alkane recovery, I will then demonstrate that this retarded dynamics leads to an overall slow - algebraic - decay of the hydrocarbon flux. Such a behavior is consistent with algebraic decays of shale gas flux from various wells reported in the literature. This work was performed in collaboration with B. Coasne, K. Falk, T. Lee, R. Pellenq and F. Ulm, at the UMI CNRS-MIT, Massachusetts Institute of Technology, Cambridge, USA.

  3. Gas-water-rock interactions induced by reservoir exploitation, CO2 sequestration, and other geological storage

    International Nuclear Information System (INIS)

    Lecourtier, J.

    2005-01-01

    Here is given a summary of the opening address of the IFP International Workshop: 'gas-water-rock interactions induced by reservoir exploitation, CO 2 sequestration, and other geological storage' (18-20 November 2003). 'This broad topic is of major interest to the exploitation of geological sites since gas-water-mineral interactions determine the physicochemical characteristics of these sites, the strategies to adopt to protect the environment, and finally, the operational costs. Modelling the phenomena is a prerequisite for the engineering of a geological storage, either for disposal efficiency or for risk assessment and environmental protection. During the various sessions, several papers focus on the great achievements that have been made in the last ten years in understanding and modelling the coupled reaction and transport processes occurring in geological systems, from borehole to reservoir scale. Remaining challenges such as the coupling of mechanical processes of deformation with chemical reactions, or the influence of microbiological environments on mineral reactions will also be discussed. A large part of the conference programme will address the problem of mitigating CO 2 emissions, one of the most important issues that our society must solve in the coming years. From both a technical and an economic point of view, CO 2 geological sequestration is the most realistic solution proposed by the experts today. The results of ongoing pilot operations conducted in Europe and in the United States are strongly encouraging, but geological storage will be developed on a large scale in the future only if it becomes possible to predict the long term behaviour of stored CO 2 underground. In order to reach this objective, numerous issues must be solved: - thermodynamics of CO 2 in brines; - mechanisms of CO 2 trapping inside the host rock; - geochemical modelling of CO 2 behaviour in various types of geological formations; - compatibility of CO 2 with oil-well cements

  4. The potential for hydrocarbon biodegradation and production of extracellular polymeric substances by aerobic bacteria isolated from a Brazilian petroleum reservoir.

    Science.gov (United States)

    Vasconcellos, S P; Dellagnezze, B M; Wieland, A; Klock, J-H; Santos Neto, E V; Marsaioli, A J; Oliveira, V M; Michaelis, W

    2011-06-01

    Extracellular polymeric substances (EPS) can contribute to the cellular degradation of hydrocarbons and have a huge potential for application in biotechnological processes, such as bioremediation and microbial enhanced oil recovery (MEOR). Four bacterial strains from a Brazilian petroleum reservoir were investigated for EPS production, emulsification ability and biodegradation activity when hydrocarbons were supplied as substrates for microbial growth. Two strains of Bacillus species had the highest EPS production when phenanthrene and n-octadecane were offered as carbon sources, either individually or in a mixture. While Pseudomonas sp. and Dietzia sp., the other two evaluated strains, had the highest hydrocarbon biodegradation indices, EPS production was not detected. Low EPS production may not necessarily be indicative of an absence of emulsifier activity, as indicated by the results of a surface tension reduction assay and emulsification indices for the strain of Dietzia sp. The combined results gathered in this work suggest that a microbial consortium consisting of bacteria with interdependent metabolisms could thrive in petroleum reservoirs, thus overcoming the limitations imposed on each individual species by the harsh conditions found in such environments.

  5. Petrophysical and Mineralogical Research on the Influence of CO2 Injection on Mesozoic Reservoir and Cap-rocks from the Polish Lowlands

    International Nuclear Information System (INIS)

    Tarkowski, R.; Wdowin, M.

    2011-01-01

    Special equipment, simulating formation conditions, was designed to study interactions between injected CO 2 , rocks and brines. The investigations were carried out on samples collected from reservoir and cap-rocks of the Pagorki (Cretaceous deposits) and Brzesc Kujawski (Jurassic deposits) boreholes. Mineralogical and petrographic investigations were carried out on the samples before and after the experiment to determine changes occurring as a result of the processes. The investigations proved that these rocks show good quality reservoir and sealing properties. The experiment did not significantly worsen the reservoir properties of the rocks. (authors)

  6. Molecular isotopic characterisation of hydrocarbon biomarkers in Palaeocene-Eocene evaporitic, lacustrine source rocks from the Jianghan Basin, China

    NARCIS (Netherlands)

    Sinninghe Damsté, J.S.; Grice, Kliti; Schouten, S.; Peters, Kenneth E.

    1998-01-01

    Immature organic matter in lacustrine source rocks from the Jianghan Basin, eastern China, was studied for distributions and stable carbon isotopic compositions (13C) of hydrocarbon biomarkers. All of the bitumens contain isorenieratane (13C ca. −17 ) indicating the presence of Chlorobiaceae, and

  7. Rational Rock Physics for Improved Velocity Prediction and Reservoir Properties Estimation for Granite Wash (Tight Sands in Anadarko Basin, Texas

    Directory of Open Access Journals (Sweden)

    Muhammad Z. A. Durrani

    2014-01-01

    Full Text Available Due to the complex nature, deriving elastic properties from seismic data for the prolific Granite Wash reservoir (Pennsylvanian age in the western Anadarko Basin Wheeler County (Texas is quite a challenge. In this paper, we used rock physics tool to describe the diagenesis and accurate estimation of seismic velocities of P and S waves in Granite Wash reservoir. Hertz-Mindlin and Cementation (Dvorkin’s theories are applied to analyze the nature of the reservoir rocks (uncemented and cemented. In the implementation of rock physics diagnostics, three classical rock physics (empirical relations, Kuster-Toksöz, and Berryman models are comparatively analyzed for velocity prediction taking into account the pore shape geometry. An empirical (VP-VS relationship is also generated calibrated with core data for shear wave velocity prediction. Finally, we discussed the advantages of each rock physics model in detail. In addition, cross-plots of unconventional attributes help us in the clear separation of anomalous zone and lithologic properties of sand and shale facies over conventional attributes.

  8. Drag reduction in reservoir rock surface: Hydrophobic modification by SiO{sub 2} nanofluids

    Energy Technology Data Exchange (ETDEWEB)

    Yan, Yong-Li, E-mail: yylhill@163.com [College of Chemistry & Chemical Engineering, Xi’an Shiyou University, Xi’an 710065 (China); Cui, Ming-Yue; Jiang, Wei-Dong; He, An-Le; Liang, Chong [Langfang Branch of Research Institute of Petroleum Exploration & Development, Langfang 065007 (China)

    2017-02-28

    Graphical abstract: The micro-nanoscale hierarchical structures at the sandstone core surface are constructed by adsorption of the modified silica nanoparticles, which leads to the effect of drag reduction to improve the low injection rate in ultra-low permeability reservoirs. - Highlights: • A micro-nanoscale hierarchical structure is formed at the reservoir rock surface. • An inversion has happened from hydrophilic into hydrophobic modified by nanofluids. • The effect of drag reduction to improve the low injection rate is realized. • The mechanism of drag reduction induced from the modified core surface was unclosed. - Abstract: Based on the adsorption behavior of modified silica nanoparticles in the sandstone core surface, the hydrophobic surface was constructed, which consists of micro-nanoscale hierarchical structure. This modified core surface presents a property of drag reduction and meets the challenge of high injection pressure and low injection rate in low or ultra-low permeability reservoir. The modification effects on the surface of silica nanoparticles and reservoir cores, mainly concerning hydrophobicity and fine structure, were determined by measurements of contact angle and scanning electron microscopy. Experimental results indicate that after successful modification, the contact angle of silica nanoparticles varies from 19.5° to 141.7°, exhibiting remarkable hydrophobic properties. These modified hydrophobic silica nanoparticles display a good adsorption behavior at the core surface to form micro-nanobinary structure. As for the wettability of these modified core surfaces, a reversal has happened from hydrophilic into hydrophobic and its contact angle increases from 59.1° to 105.9°. The core displacement experiments show that the relative permeability for water has significantly increased by an average of 40.3% via core surface modification, with the effects of reducing injection pressure and improving injection performance of water

  9. Drag reduction in reservoir rock surface: Hydrophobic modification by SiO_2 nanofluids

    International Nuclear Information System (INIS)

    Yan, Yong-Li; Cui, Ming-Yue; Jiang, Wei-Dong; He, An-Le; Liang, Chong

    2017-01-01

    Graphical abstract: The micro-nanoscale hierarchical structures at the sandstone core surface are constructed by adsorption of the modified silica nanoparticles, which leads to the effect of drag reduction to improve the low injection rate in ultra-low permeability reservoirs. - Highlights: • A micro-nanoscale hierarchical structure is formed at the reservoir rock surface. • An inversion has happened from hydrophilic into hydrophobic modified by nanofluids. • The effect of drag reduction to improve the low injection rate is realized. • The mechanism of drag reduction induced from the modified core surface was unclosed. - Abstract: Based on the adsorption behavior of modified silica nanoparticles in the sandstone core surface, the hydrophobic surface was constructed, which consists of micro-nanoscale hierarchical structure. This modified core surface presents a property of drag reduction and meets the challenge of high injection pressure and low injection rate in low or ultra-low permeability reservoir. The modification effects on the surface of silica nanoparticles and reservoir cores, mainly concerning hydrophobicity and fine structure, were determined by measurements of contact angle and scanning electron microscopy. Experimental results indicate that after successful modification, the contact angle of silica nanoparticles varies from 19.5° to 141.7°, exhibiting remarkable hydrophobic properties. These modified hydrophobic silica nanoparticles display a good adsorption behavior at the core surface to form micro-nanobinary structure. As for the wettability of these modified core surfaces, a reversal has happened from hydrophilic into hydrophobic and its contact angle increases from 59.1° to 105.9°. The core displacement experiments show that the relative permeability for water has significantly increased by an average of 40.3% via core surface modification, with the effects of reducing injection pressure and improving injection performance of water

  10. Multi-Attribute Seismic/Rock Physics Approach to Characterizing Fractured Reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Gary Mavko

    2004-11-30

    Most current seismic methods to seismically characterize fractures in tight reservoirs depend on a few anisotropic wave propagation signatures that can arise from aligned fractures. While seismic anisotropy can be a powerful fracture diagnostic, a number of situations can lessen its usefulness or introduce interpretation ambiguities. Fortunately, laboratory and theoretical work in rock physics indicates that a much broader spectrum of fracture seismic signatures can occur, including a decrease in P- and S-wave velocities, a change in Poisson's ratio, an increase in velocity dispersion and wave attenuation, as well as well as indirect images of structural features that can control fracture occurrence. The goal of this project was to demonstrate a practical interpretation and integration strategy for detecting and characterizing natural fractures in rocks. The approach was to exploit as many sources of information as possible, and to use the principles of rock physics as the link among seismic, geologic, and log data. Since no single seismic attribute is a reliable fracture indicator in all situations, the focus was to develop a quantitative scheme for integrating the diverse sources of information. The integrated study incorporated three key elements: The first element was establishing prior constraints on fracture occurrence, based on laboratory data, previous field observations, and geologic patterns of fracturing. The geologic aspects include analysis of the stratigraphic, structural, and tectonic environments of the field sites. Field observations and geomechanical analysis indicates that fractures tend to occur in the more brittle facies, for example, in tight sands and carbonates. In contrast, strain in shale is more likely to be accommodated by ductile flow. Hence, prior knowledge of bed thickness and facies architecture, calibrated to outcrops, are powerful constraints on the interpreted fracture distribution. Another important constraint is that

  11. Rock-Eval 6 Applications in Hydrocarbon Exploration, Production, and Soil Contamination Studies Les applications de Rock-Eval 6 dans l'exploration et la production des hydrocarbures, et dans les études de contamination des sols

    Directory of Open Access Journals (Sweden)

    Lafargue E.

    2006-12-01

    Full Text Available Successful petroleum exploration relies on detailed analysis of the petroleum system in a given area. Identification of potential source rocks, their maturity and kinetic parameters, and their regional distribution are best accomplished by rapid screening of rock samples (cores and/or cuttings using the Rock-Eval apparatus. The technique has been routinely used for about fifteen years and has become a standard tool for hydrocarbon exploration. This paper describes how the new functions of the latest version of Rock-Eval (Rock-Eval 6 have expanded applications of the method in petroleum geoscience. Examples of new applications are illustrated for source rock characterization, reservoir geochemistry, and environmental studies, including quantification. Le succès d'une exploration pétrolière repose sur l'analyse détaillée du système pétrolier dans une zone donnée. L'identification des roches mères potentielles, la détermination de leur maturité, de leurs paramètres cinétiques et de leur répartition sont réalisées au mieux à partir d'examens rapides d'échantillons de roches (carottes ou déblais au moyen de la pyrolyse Rock-Eval. Cette technique a été utilisée en routine pendant une quinzaine d'années et elle est devenue un outil standard pour l'exploration des hydrocarbures. Cet article décrit comment les nouvelles fonctionnalités de la dernière version de l'appareil Rock-Eval (Rock-Eval 6 ont permis une expansion des applications de la méthode en géosciences pétrolières. Des exemples d'applications nouvelles sont illustrés dans les domaines de la caractérisation des roches mères, de la géochimie de réservoir et des études environnementales incluant la quantification et la description des hydrocarbures dans des sols contaminés.

  12. Reservoir attributes of a hydrocarbon-prone sandstone complex: case of the Pab Formation (Late Cretaceous) of Southwest Pakistan

    DEFF Research Database (Denmark)

    Umar, Muhammad; Khan, Abdul Salam; Kelling, Gilbert

    2016-01-01

    Links between the architectural elements of major sand bodies and reservoir attributes have been explored in a field study of the hydrocarbon-yielding Late Cretaceous Pab Formation of southwest Pakistan. The lithofacies and facies associations represented in the Pab Formation are the main...... determinants of its reservoir properties. Thus, thick, vertically connected and laterally continuous sand packets have moderate-to-high mean porosities (10–13 %) in fluviodeltaic, shoreface, shelf delta, submarine channel, and fan-lobe facies associations while deeper shelf and basin floor sand bodies yield...... significantly lower porosities (4–6 %). Overall, in the Pab arenites, porosity values increase with increasing grain size and better sorting. The varying sand-shale ratios encountered in different sectors of the Pab outcrop are also petrophysically important: Sequences displaying high ratios yield higher bulk...

  13. Application of probabilistic facies prediction and estimation of rock physics parameters in a carbonate reservoir from Iran

    International Nuclear Information System (INIS)

    Karimpouli, Sadegh; Hassani, Hossein; Nabi-Bidhendi, Majid; Khoshdel, Hossein; Malehmir, Alireza

    2013-01-01

    In this study, a carbonate field from Iran was studied. Estimation of rock properties such as porosity and permeability is much more challenging in carbonate rocks than sandstone rocks because of their strong heterogeneity. The frame flexibility factor (γ) is a rock physics parameter which is related not only to pore structure variation but also to solid/pore connectivity and rock texture in carbonate reservoirs. We used porosity, frame flexibility factor and bulk modulus of fluid as the proper parameters to study this gas carbonate reservoir. According to rock physics parameters, three facies were defined: favourable and unfavourable facies and then a transition facies located between these two end members. To capture both the inversion solution and associated uncertainty, a complete implementation of the Bayesian inversion of the facies from pre-stack seismic data was applied to well data and validated with data from another well. Finally, this method was applied on a 2D seismic section and, in addition to inversion of petrophysical parameters, the high probability distribution of favorable facies was also obtained. (paper)

  14. Tectonic controls on preservation of Middle Triassic Halfway reservoir facies, Peejay Field, northeastern British Columbia: a new hydrocarbon exploration model

    Energy Technology Data Exchange (ETDEWEB)

    Caplan, M. L. [British Columbia Univ., Vancouver, BC (Canada). Dept. of Geological Sciences; Moslow, T. F. [Calgary Univ., AB (Canada). Dept. of Geology and Geophysics

    1997-12-01

    The Peejay Field in northeastern British Columbia was chosen as the site of a detailed study to establish the paleogeography, geological history and genesis of reservoir facies of Middle Triassic strata. A total of 132 cores and well logs from 345 wells were examined to establish the depositional model, to identify the origin of all reservoir facies and to construct an exploration model to improve the prediction of reservoir facies. Results show that the Middle Triassic Halfway Formation of northeastern British Columbia is comprised of at least four west-southwest prograding paleoshorelines. The Lithofacies Succession One quartz-arenites paleoshore faces have less porosity and permeability and are laterally discontinuous. For these reasons shoreface facies have minimal reservoir quality. The tidal inlet fill successions were found to have the greatest observed porosity, permeability and lateral continuity in the Peejay Field. The geometry and orientation of these tidal inlet fill deposits are controlled by tectonic processes. It was suggested that the success of hydrocarbon exploration in this structurally complex area of northeastern British Columbia and west-central Alberta depends on further stratigraphic and sedimentological examination of Middle Triassic strata on a regional scale to obtain a complete understanding of the geological history of the area. 39 refs., 13 refs.

  15. Experimental reactivity with CO2 of clayey cap-rock and carbonate reservoir of the Paris basin

    International Nuclear Information System (INIS)

    Hubert, G.

    2009-01-01

    The constant increase in the quantity of carbon dioxide in the atmosphere is regarded as being the principal cause of the current global warming. The geological sequestration of CO 2 seems to be an ideal solution to reduce the increase of greenhouse gases (of which CO 2 ) in the atmosphere but only if the reservoir's cap-rock keep its integrity for several hundreds or thousands of years. Batch experimental simulations were conducted to observe the reactivity of a cap-rock made of clay and a carbonate reservoir with CO 2 at 80 C and 150 C for a pressure of 150 bar with an equilibrated water. The analytical protocol established allowed to compare the rocks before and after experimentations finding a very low reactivity, focusing on aluminium in phyllosilicates. Textural analysis shows that CO 2 does not affect the properties of adsorption and the specific surface. The study of carbonate reservoir by confocal microscopy has revealed phenomena of dissolution-precipitation which have no significant impact on chemistry and structure of the reservoir. The numerical simulations carried out on mineral reference as calcium montmorillonite or clinochlore show a significant reaction in the presence of CO 2 not achieved experimentally, probably due to lacunas in the thermodynamic databases or the kinetics of reactions. The simulations on Bure show no reaction on the major minerals confirming the results with batch experiments. (author)

  16. Hydraulic characterization of aquifers, reservoir rocks, and soils: A history of ideas

    Science.gov (United States)

    Narasimhan, T. N.

    1998-01-01

    Estimation of the hydraulic properties of aquifers, petroleum reservoir rocks, and soil systems is a fundamental task in many branches of Earth sciences and engineering. The transient diffusion equation proposed by Fourier early in the 19th century for heat conduction in solids constitutes the basis for inverting hydraulic test data collected in the field to estimate the two basic parameters of interest, namely, hydraulic conductivity and hydraulic capacitance. Combining developments in fluid mechanics, heat conduction, and potential theory, the civil engineers of the 19th century, such as Darcy, Dupuit, and Forchheimer, solved many useful problems of steady state seepage of water. Interest soon shifted towards the understanding of the transient flow process. The turn of the century saw Buckingham establish the role of capillary potential in governing moisture movement in partially water-saturated soils. The 1920s saw remarkable developments in several branches of the Earth sciences; Terzaghi's analysis of deformation of watersaturated earth materials, the invention of the tensiometer by Willard Gardner, Meinzer's work on the compressibility of elastic aquifers, and the study of the mechanics of oil and gas reservoirs by Muskat and others. In the 1930s these led to a systematic analysis of pressure transients from aquifers and petroleum reservoirs through the work of Theis and Hurst. The response of a subsurface flow system to a hydraulic perturbation is governed by its geometric attributes as well as its material properties. In inverting field data to estimate hydraulic parameters, one makes the fundamental assumption that the flow geometry is known a priori. This approach has generally served us well in matters relating to resource development primarily concerned with forecasting fluid pressure declines. Over the past two decades, Earth scientists have become increasingly concerned with environmental contamination problems. The resolution of these problems

  17. Evaluation of Microstructural Parameters of Reservoir Rocks of the Guarani Aquifer by Analysis of Images Obtained by X- Ray Microtomography

    Science.gov (United States)

    Fernandes, J. S.; Lima, F. A.; Vieira, S. F.; Reis, P. J.; Appoloni, C. R.

    2015-07-01

    Microstructural parameters evaluation of porous materials, such as, rocks reservoir (water, petroleum, gas...), it is of great importance for several knowledge areas. In this context, the X-ray microtomography (μ-CT) has been showing a technical one quite useful for the analysis of such rocks (sandstone, limestone and carbonate), object of great interest of the petroleum and water industries, because it facilitates the characterization of important parameters, among them, porosity, permeability, grains or pore size distribution. The X-ray microtomography is a non-destructive method, that besides already facilitating the reuse of the samples analyzed, it also supplies images 2-D and 3-D of the sample. In this work samples of reservoir rock of the Guarani aquifer will be analyzed, given by the company of perforation of wells artesian Blue Water, in the municipal district of Videira, Santa Catarina, Brazil. The acquisition of the microtomographys data of the reservoir rocks was accomplished in a Skyscan 1172 μ-CT scanner, installed in Applied Nuclear Physics Laboratory (LFNA) in the State University of Londrina (UEL), Paraná, Brazil. In this context, this work presents the microstructural characterization of reservoir rock sample of the Guarani aquifer, analyzed for two space resolutions, 2.8 μm and 4.8 μm, where determined average porosity was 28.5% and 21.9%, respectively. Besides, we also determined the pore size distribution for both resolutions. Two 3-D images were generated of this sample, one for each space resolution, in which it is possible to visualize the internal structure of the same ones.

  18. Evaluation of Microstructural Parameters of Reservoir Rocks of the Guarani Aquifer by Analysis of Images Obtained by X- Ray Microtomography

    International Nuclear Information System (INIS)

    Fernandes, J S; Lima, F A; Vieira, S F; Reis, P J; Appoloni, C R

    2015-01-01

    Microstructural parameters evaluation of porous materials, such as, rocks reservoir (water, petroleum, gas...), it is of great importance for several knowledge areas. In this context, the X-ray microtomography (μ-CT) has been showing a technical one quite useful for the analysis of such rocks (sandstone, limestone and carbonate), object of great interest of the petroleum and water industries, because it facilitates the characterization of important parameters, among them, porosity, permeability, grains or pore size distribution. The X-ray microtomography is a non-destructive method, that besides already facilitating the reuse of the samples analyzed, it also supplies images 2-D and 3-D of the sample. In this work samples of reservoir rock of the Guarani aquifer will be analyzed, given by the company of perforation of wells artesian Blue Water, in the municipal district of Videira, Santa Catarina, Brazil. The acquisition of the microtomographys data of the reservoir rocks was accomplished in a Skyscan 1172 μ-CT scanner, installed in Applied Nuclear Physics Laboratory (LFNA) in the State University of Londrina (UEL), Paraná, Brazil. In this context, this work presents the microstructural characterization of reservoir rock sample of the Guarani aquifer, analyzed for two space resolutions, 2.8 μm and 4.8 μm, where determined average porosity was 28.5% and 21.9%, respectively. Besides, we also determined the pore size distribution for both resolutions. Two 3-D images were generated of this sample, one for each space resolution, in which it is possible to visualize the internal structure of the same ones. (paper)

  19. An Integrated Rock Typing Approach for Unraveling the Reservoir Heterogeneity of Tight Sands in the Whicher Range Field of Perth Basin, Western Australia

    DEFF Research Database (Denmark)

    Ilkhchi, Rahim Kadkhodaie; Rezaee, Reza; Harami, Reza Moussavi

    2014-01-01

    Tight gas sands in Whicher Range Field of Perth Basin show large heterogeneity in reservoir characteristics and production behavior related to depositional and diagenetic features. Diagenetic events (compaction and cementation) have severely affected the pore system. In order to investigate...... the petrophysical characteristics, reservoir sandstone facies were correlated with core porosity and permeability and their equivalent well log responses to describe hydraulic flow units and electrofacies, respectively. Thus, very tight, tight, and sub-tight sands were differentiated. To reveal the relationship...... between pore system properties and depositional and diagenetic characteristics in each sand type, reservoir rock types were extracted. The identified reservoir rock types are in fact a reflection of internal reservoir heterogeneity related to pore system properties. All reservoir rock types...

  20. 3D Seismic Reflection Amplitude and Instantaneous Frequency Attributes in Mapping Thin Hydrocarbon Reservoir Lithofacies: Morrison NE Field and Morrison Field, Clark County, KS

    Science.gov (United States)

    Raef, Abdelmoneam; Totten, Matthew; Vohs, Andrew; Linares, Aria

    2017-12-01

    Thin hydrocarbon reservoir facies pose resolution challenges and waveform-signature opportunities in seismic reservoir characterization and prospect identification. In this study, we present a case study, where instantaneous frequency variation in response to a thin hydrocarbon pay zone is analyzed and integrated with other independent information to explain drilling results and optimize future drilling decisions. In Morrison NE Field, some wells with poor economics have resulted from well-placement incognizant of reservoir heterogeneities. The study area in Clark County, Kanas, USA, has been covered by a surface 3D seismic reflection survey in 2010. The target horizon is the Viola limestone, which continues to produce from 7 of the 12 wells drilled within the survey area. Seismic attributes extraction and analyses were conducted with emphasis on instantaneous attributes and amplitude anomalies to better understand and predict reservoir heterogeneities and their control on hydrocarbon entrapment settings. We have identified a higher instantaneous frequency, lower amplitude seismic facies that is in good agreement with distinct lithofacies that exhibit better (higher porosity) reservoir properties, as inferred from well-log analysis and petrographic inspection of well cuttings. This study presents a pre-drilling, data-driven approach of identifying sub-resolution reservoir seismic facies in a carbonate formation. This workflow will assist in placing new development wells in other locations within the area. Our low amplitude high instantaneous frequency seismic reservoir facies have been corroborated by findings based on well logs, petrographic analysis data, and drilling results.

  1. Structural characterization and numerical simulations of flow properties of standard and reservoir carbonate rocks using micro-tomography

    Science.gov (United States)

    Islam, Amina; Chevalier, Sylvie; Sassi, Mohamed

    2018-04-01

    With advances in imaging techniques and computational power, Digital Rock Physics (DRP) is becoming an increasingly popular tool to characterize reservoir samples and determine their internal structure and flow properties. In this work, we present the details for imaging, segmentation, as well as numerical simulation of single-phase flow through a standard homogenous Silurian dolomite core plug sample as well as a heterogeneous sample from a carbonate reservoir. We develop a procedure that integrates experimental results into the segmentation step to calibrate the porosity. We also look into using two different numerical tools for the simulation; namely Avizo Fire Xlab Hydro that solves the Stokes' equations via the finite volume method and Palabos that solves the same equations using the Lattice Boltzmann Method. Representative Elementary Volume (REV) and isotropy studies are conducted on the two samples and we show how DRP can be a useful tool to characterize rock properties that are time consuming and costly to obtain experimentally.

  2. The genetic source and timing of hydrocarbon formation in gas hydrate reservoirs in Green Canyon, Block GC955

    Science.gov (United States)

    Moore, M. T.; Darrah, T.; Cook, A.; Sawyer, D.; Phillips, S.; Whyte, C. J.; Lary, B. A.

    2017-12-01

    Although large volumes of gas hydrates are known to exist along continental slopes and below permafrost, their role in the energy sector and the global carbon cycle remains uncertain. Investigations regarding the genetic source(s) (i.e., biogenic, thermogenic, mixed sources of hydrocarbon gases), the location of hydrocarbon generation, (whether hydrocarbons formed within the current reservoir formations or underwent migration), rates of clathrate formation, and the timing of natural gas formation/accumulation within clathrates are vital to evaluate economic potential and enhance our understanding of geologic processes. Previous studies addressed some of these questions through analysis of conventional hydrocarbon molecular (C1/C2+) and stable isotopic (e.g., δ13C-CH4, δ2H-CH4, δ13C-CO2) composition of gases, water chemistry and isotopes (e.g., major and trace elements, δ2H-H2O, δ18O-H2O), and dissolved inorganic carbon (δ13C-DIC) of natural gas hydrate systems to determine proportions of biogenic and thermogenic gas. However, the effects from contributions of mixing, transport/migration, methanogenesis, and oxidation in the subsurface can complicate the first-order application of these techniques. Because the original noble gas composition of a fluid is preserved independent of microbial activity, chemical reactions, or changes in oxygen fugacity, the integration of noble gas data can provide both a geochemical fingerprint for sources of fluids and an additional insight as to the uncertainty between effects of mixing versus post-genetic modification. Here, we integrate inert noble gases (He, Ne, Ar, and associated isotopes) with these conventional approaches to better constrain the source of gas hydrate formation and the residence time of fluids (porewaters and natural gases) using radiogenic 4He ingrowth techniques in cores from two boreholes collected as part of the University of Texas led UT-GOM2-01 drilling project. Pressurized cores were extracted from

  3. Application of Rock-Eval pyrolysis to the detection of hydrocarbon property in sandstone-type uranium deposits

    International Nuclear Information System (INIS)

    Sun Ye; Li Ziying; Guo Qingyin; Xiao Xinjian

    2006-01-01

    Rock-Eval pyrolysis is introduced into the research of uranium geology by means of oil-gas geochemical evaluation. Hydrocarbon (oil-gas) components in DS sandstone-type uranium deposit are detected quantitatively. Through analyzing the oil-gas bearing categories of the uranium-bearing sandstones, the internal relationships between the uranium deposit and the oil-gas are revealed. Rock-Eval pyrolysis is an effective method to study the interaction between inorganic and organic matters, and should be extended to the study of sandstone-type uranium deposits. (authors)

  4. Study on the enhancement of hydrocarbon recovery by characterization of the reservoir

    Energy Technology Data Exchange (ETDEWEB)

    Jeong, Tae-Jin; Kwak, Young-Hoon; Huh, Dae-Gee [Korea Institute of Geology Mining and Materials, Taejon (KR)] (and others)

    1999-12-01

    The reservoir geochemistry is to understand the origin of these heterogeneities and distributions of the bitumens within the reservoir and to use them not only for exploration but for the development of the petroleums. Methods and principles of the reservoir geochemistry, which are applicable to the petroleum exploration and development, are reviewed in the study. In addition, a case study was carried out on the gas, condensate, water and bitumen samples in the reservoir, taken from the Haenam, Pohang areas and the Ulleung Basin offshore Korea. Mineral geothermometers were studied to estimate the thermal history in sedimentary basins and successfully applied to the Korean onshore and offshore basins. The opal silica-to-quartz transformation was investigated in the Pohang basin as a geothermometer. In Korean basins, the smectite-to-illite changes indicate that smectite and illite can act as the geothermometer to estimate the thermal history of the basins. The albitization reaction was also considered as a temperature indicator. Naturally fractured reservoir is an important source of oil and gas throughout the world. The properties of matrix and fracture are the key parameters in predicting the performances of naturally fractured reservoirs. A new laboratory equipment has been designed and constructed by pressure pulse method to determine the properties, which are (1) the porosity of matrix, (2) the permeability of matrix, (3) the effective width of the fractures, and the permeability of the fractures. (author). 97 refs.

  5. Structural and petrophysical characterization: from outcrop rock analogue to reservoir model of deep geothermal prospect in Eastern France

    Science.gov (United States)

    Bertrand, Lionel; Géraud, Yves; Diraison, Marc; Damy, Pierre-Clément

    2017-04-01

    The Scientific Interest Group (GIS) GEODENERGIES with the REFLET project aims to develop a geological and reservoir model for fault zones that are the main targets for deep geothermal prospects in the West European Rift system. In this project, several areas are studied with an integrated methodology combining field studies, boreholes and geophysical data acquisition and 3D modelling. In this study, we present the results of reservoir rock analogues characterization of one of these prospects in the Valence Graben (Eastern France). The approach used is a structural and petrophysical characterization of the rocks outcropping at the shoulders of the rift in order to model the buried targeted fault zone. The reservoir rocks are composed of fractured granites, gneiss and schists of the Hercynian basement of the graben. The matrix porosity, permeability, P-waves velocities and thermal conductivities have been characterized on hand samples coming from fault zones at the outcrop. Furthermore, fault organization has been mapped with the aim to identify the characteristic fault orientation, spacing and width. The fractures statistics like the orientation, density, and length have been identified in the damaged zones and unfaulted blocks regarding the regional fault pattern. All theses data have been included in a reservoir model with a double porosity model. The field study shows that the fault pattern in the outcrop area can be classified in different fault orders, with first order scale, larger faults distribution controls the first order structural and lithological organization. Between theses faults, the first order blocks are divided in second and third order faults, smaller structures, with characteristic spacing and width. Third order fault zones in granitic rocks show a significant porosity development in the fault cores until 25 % in the most locally altered material, as the damaged zones develop mostly fractures permeabilities. In the gneiss and schists units, the

  6. Reservoir evaluation of thin-bedded turbidites and hydrocarbon pore thickness estimation for an accurate quantification of resource

    Science.gov (United States)

    Omoniyi, Bayonle; Stow, Dorrik

    2016-04-01

    One of the major challenges in the assessment of and production from turbidite reservoirs is to take full account of thin and medium-bedded turbidites (succession, they can go unnoticed by conventional analysis and so negatively impact on reserve estimation, particularly in fields producing from prolific thick-bedded turbidite reservoirs. Field development plans often take little note of such thin beds, which are therefore bypassed by mainstream production. In fact, the trapped and bypassed fluids can be vital where maximising field value and optimising production are key business drivers. We have studied in detail, a succession of thin-bedded turbidites associated with thicker-bedded reservoir facies in the North Brae Field, UKCS, using a combination of conventional logs and cores to assess the significance of thin-bedded turbidites in computing hydrocarbon pore thickness (HPT). This quantity, being an indirect measure of thickness, is critical for an accurate estimation of original-oil-in-place (OOIP). By using a combination of conventional and unconventional logging analysis techniques, we obtain three different results for the reservoir intervals studied. These results include estimated net sand thickness, average sand thickness, and their distribution trend within a 3D structural grid. The net sand thickness varies from 205 to 380 ft, and HPT ranges from 21.53 to 39.90 ft. We observe that an integrated approach (neutron-density cross plots conditioned to cores) to HPT quantification reduces the associated uncertainties significantly, resulting in estimation of 96% of actual HPT. Further work will focus on assessing the 3D dynamic connectivity of the low-pay sands with the surrounding thick-bedded turbidite facies.

  7. The validity of generic trends on multiple scales in rock-physical and rock-mechanical properties of the Whitby Mudstone, United Kingdom

    NARCIS (Netherlands)

    Douma, L.A.N.R.; Primarini, M.I.W.; Houben, M.E.; Barnhoorn, A.

    Finding generic trends in mechanical and physical rock properties will help to make predictions of the rock-mechanical behaviour of shales. Understanding the rock-mechanical behaviour of shales is important for the successful development of unconventional hydrocarbon reservoirs. This paper presents

  8. ISS Assessment of the Influence of Nonpore Surface in the XPS Analysis of Oil-Producing Reservoir Rocks

    Science.gov (United States)

    Leon; Toledo; Araujo

    1997-08-15

    The application of X-ray photoelectron spectroscopy (XPS) to oil-producing reservoir rocks is new and has shown that pore surface concentrations can be related to rock wettability. In the preparation of fresh fractures of rocks, however, some nonpore surface corresponding to the connection regions in the rocks is created and exposed to XPS. To assess the potential influence of this nonpore surface in the XPS analysis of rocks here we use ion scattering spectroscopy (ISS), which has a resolution comparable to the size of the pores, higher than that of XPS, with an ion gun of He+ at maximum focus. Sample charging effects are partially eliminated with a flood gun of low energy electrons. All the ISS signals are identified by means of a formula which corrects any residual charging on the samples. Three rock samples are analyzed by XPS and ISS. The almost unchanged ISS spectra obtained at different points of a given sample suggest that the nonpore surface created in the fracture process is negligibly small, indicating that XPS data, from a larger surface spot, represents the composition of true pore surfaces. The significant changes observed in ISS spectra from different samples indicate that ISS is sample specific. Copyright 1997Academic Press

  9. Insights on fluid-rock interaction evolution during deformation from fracture network geochemistry at reservoir-scale

    Science.gov (United States)

    Beaudoin, Nicolas; Koehn, Daniel; Lacombe, Olivier; Bellahsen, Nicolas; Emmanuel, Laurent

    2015-04-01

    Fluid migration and fluid-rock interactions during deformation is a challenging problematic to picture. Numerous interplays, as between porosity-permeability creation and clogging, or evolution of the mechanical properties of rock, are key features when it comes to monitor reservoir evolution, or to better understand seismic cycle n the shallow crust. These phenomenoms are especially important in foreland basins, where various fluids can invade strata and efficiently react with limestones, altering their physical properties. Stable isotopes (O, C, Sr) measurements and fluid inclusion microthermometry of faults cement and veins cement lead to efficient reconstruction of the origin, temperature and migration pathways for fluids (i.e. fluid system) that precipitated during joints opening or faults activation. Such a toolbox can be used on a diffuse fracture network that testifies the local and/or regional deformation history experienced by the rock at reservoir-scale. This contribution underlines the advantages and limits of geochemical studies of diffuse fracture network at reservoir-scale by presenting results of fluid system reconstruction during deformation in folded structures from various thrust-belts, tectonic context and deformation history. We compare reconstructions of fluid-rock interaction evolution during post-deposition, post-burial growth of basement-involved folds in the Sevier-Laramide American Rocky Mountains foreland, a reconstruction of fluid-rock interaction evolution during syn-depostion shallow detachment folding in the Southern Pyrenean foreland, and a preliminary reconstruction of fluid-rock interactions in a post-deposition, post-burial development of a detachment fold in the Appenines. Beyond regional specification for the nature of fluids, a common behavior appears during deformation as in every fold, curvature-related joints (related either to folding or to foreland flexure) connected vertically the pre-existing stratified fluid system

  10. Maximization of wave motion within a hydrocarbon reservoir for wave-based enhanced oil recovery

    KAUST Repository

    Jeong, C.

    2015-05-01

    © 2015 Elsevier B.V. We discuss a systematic methodology for investigating the feasibility of mobilizing oil droplets trapped within the pore space of a target reservoir region by optimally directing wave energy to the region of interest. The motivation stems from field and laboratory observations, which have provided sufficient evidence suggesting that wave-based reservoir stimulation could lead to economically viable oil recovery.Using controlled active surface wave sources, we first describe the mathematical framework necessary for identifying optimal wave source signals that can maximize a desired motion metric (kinetic energy, particle acceleration, etc.) at the target region of interest. We use the apparatus of partial-differential-equation (PDE)-constrained optimization to formulate the associated inverse-source problem, and deploy state-of-the-art numerical wave simulation tools to resolve numerically the associated discrete inverse problem.Numerical experiments with a synthetic subsurface model featuring a shallow reservoir show that the optimizer converges to wave source signals capable of maximizing the motion within the reservoir. The spectra of the wave sources are dominated by the amplification frequencies of the formation. We also show that wave energy could be focused within the target reservoir area, while simultaneously minimizing the disturbance to neighboring formations - a concept that can also be exploited in fracking operations.Lastly, we compare the results of our numerical experiments conducted at the reservoir scale, with results obtained from semi-analytical studies at the granular level, to conclude that, in the case of shallow targets, the optimized wave sources are likely to mobilize trapped oil droplets, and thus enhance oil recovery.

  11. Geochemical characteristics of natural gas in the hydrocarbon accumulation history, and its difference among gas reservoirs in the Upper Triassic formation of Sichuan Basin, China

    Directory of Open Access Journals (Sweden)

    Peng Wang

    2016-08-01

    Full Text Available The analysis of hydrocarbon generation, trap formation, inclusion homogenization temperature, authigenic illite dating, and ESR dating were used to understand the history of hydrocarbon accumulation and its difference among gas reservoirs in the Upper Triassic formation of Sichuan Basin. The results show the hydrocarbon accumulation mainly occurred during the Jurassic and Cretaceous periods; they could also be classified into three stages: (1 early hydrocarbon generation accumulation stage, (2 mass hydrocarbon generation accumulation stage before the Himalayan Epoch, (3 and parts of hydrocarbon adjustment and re-accumulation during Himalayan Epoch. The second stage is more important than the other two. The Hydrocarbon accumulation histories are obviously dissimilar in different regions. In western Sichuan Basin, the gas accumulation began at the deposition period of member 5 of Xujiahe Formation, and mass accumulation occurred during the early Middle Jurassic up to the end of the Late Cretaceous. In central Sichuan Basin, the accumulation began at the early Late Jurassic, and the mass accumulation occurred from the middle Early Cretaceous till the end of the Late Cretaceous. In southern Sichuan Basin, the accumulation began at the middle Late Jurassic, and the mass accumulation occurred from the middle of the Late Cretaceous to the end of the Later Cretaceous. The accumulation history of the western Sichuan Basin is the earliest, and the southern Sichuan Basin is the latest. This paper will help to understand the accumulation process, accumulation mechanism, and gas reservoir distribution of the Triassic gas reservoirs in the Sichuan Basin better. Meanwhile, it is found that the authigenic illite in the Upper Triassic formation of Sichuan Basin origin of deep-burial and its dating is a record of the later accumulation. This suggests that the illite dating needs to fully consider illite origin; otherwise the dating results may not accurately

  12. Neoproterozoic rift basins and their control on the development of hydrocarbon source rocks in the Tarim Basin, NW China

    Science.gov (United States)

    Zhu, Guang-You; Ren, Rong; Chen, Fei-Ran; Li, Ting-Ting; Chen, Yong-Quan

    2017-12-01

    The Proterozoic is demonstrated to be an important period for global petroleum systems. Few exploration breakthroughs, however, have been obtained on the system in the Tarim Basin, NW China. Outcrop, drilling, and seismic data are integrated in this paper to focus on the Neoproterozoic rift basins and related hydrocarbon source rocks in the Tarim Basin. The basin consists of Cryogenian to Ediacaran rifts showing a distribution of N-S differentiation. Compared to the Cryogenian basins, those of the Ediacaran are characterized by deposits in small thickness and wide distribution. Thus, the rifts have a typical dual structure, namely the Cryogenian rifting and Ediacaran depression phases that reveal distinct structural and sedimentary characteristics. The Cryogenian rifting basins are dominated by a series of grabens or half grabens, which have a wedge-shaped rapid filling structure. The basins evolved into Ediacaran depression when the rifting and magmatic activities diminished, and extensive overlapping sedimentation occurred. The distributions of the source rocks are controlled by the Neoproterozoic rifts as follows. The present outcrops lie mostly at the margins of the Cryogenian rifting basins where the rapid deposition dominates and the argillaceous rocks have low total organic carbon (TOC) contents; however, the source rocks with high TOC contents should develop in the center of the basins. The Ediacaran source rocks formed in deep water environment of the stable depressions evolving from the previous rifting basins, and are thus more widespread in the Tarim Basin. The confirmation of the Cryogenian to Ediacaran source rocks would open up a new field for the deep hydrocarbon exploration in the Tarim Basin.

  13. Aryl hydrocarbon receptor (AhR) inducers and estrogen receptor (ER) activities in surface sediments of Three Gorges Reservoir, China evaluated with in vitro cell bioassays

    NARCIS (Netherlands)

    Wang, J.; Bovee, T.F.H.; Bi, Y.; Bernhöft, S.; Schramm, K.W.

    2014-01-01

    Two types of biological tests were employed for monitoring the toxicological profile of sediment cores in the Three Gorges Reservoir (TGR), China. In the present study, sediments collected in June 2010 from TGR were analyzed for estrogen receptor (ER)- and aryl hydrocarbon receptor (AhR)-mediated

  14. Qualitative and quantitative changes in detrital reservoir rocks caused by CO2-brine-rock interactions during first injection phases (Utrillas sandstones, northern Spain)

    Science.gov (United States)

    Berrezueta, E.; Ordóñez-Casado, B.; Quintana, L.

    2016-01-01

    The aim of this article is to describe and interpret qualitative and quantitative changes at rock matrix scale of lower-upper Cretaceous sandstones exposed to supercritical (SC) CO2 and brine. The effects of experimental injection of CO2-rich brine during the first injection phases were studied at rock matrix scale, in a potential deep sedimentary reservoir in northern Spain (Utrillas unit, at the base of the Cenozoic Duero Basin).Experimental CO2-rich brine was exposed to sandstone in a reactor chamber under realistic conditions of deep saline formations (P ≈ 7.8 MPa, T ≈ 38 °C and 24 h exposure time). After the experiment, exposed and non-exposed equivalent sample sets were compared with the aim of assessing possible changes due to the effect of the CO2-rich brine exposure. Optical microscopy (OpM) and scanning electron microscopy (SEM) aided by optical image analysis (OIA) were used to compare the rock samples and get qualitative and quantitative information about mineralogy, texture and pore network distribution. Complementary chemical analyses were performed to refine the mineralogical information and to obtain whole rock geochemical data. Brine composition was also analyzed before and after the experiment.The petrographic study of contiguous sandstone samples (more external area of sample blocks) before and after CO2-rich brine injection indicates an evolution of the pore network (porosity increase ≈ 2 %). It is probable that these measured pore changes could be due to intergranular quartz matrix detachment and partial removal from the rock sample, considering them as the early features produced by the CO2-rich brine. Nevertheless, the whole rock and brine chemical analyses after interaction with CO2-rich brine do not present important changes in the mineralogical and chemical configuration of the rock with respect to initial conditions, ruling out relevant precipitation or dissolution at these early stages to rock-block scale. These results

  15. Combining water-rock interaction experiments with reaction path and reactive transport modelling to predict reservoir rock evolution in an enhanced geothermal system

    Science.gov (United States)

    Kuesters, Tim; Mueller, Thomas; Renner, Joerg

    2016-04-01

    Reliably predicting the evolution of mechanical and chemical properties of reservoir rocks is crucial for efficient exploitation of enhanced geothermal systems (EGS). For example, dissolution and precipitation of individual rock forming minerals often result in significant volume changes, affecting the hydraulic rock properties and chemical composition of fluid and solid phases. Reactive transport models are typically used to evaluate and predict the effect of the internal feedback of these processes. However, a quantitative evaluation of chemo-mechanical interaction in polycrystalline environments is elusive due to poorly constrained kinetic data of complex mineral reactions. In addition, experimentally derived reaction rates are generally faster than reaction rates determined from natural systems, likely a consequence of the experimental design: a) determining the rate of a single process only, e.g. the dissolution of a mineral, and b) using powdered sample materials and thus providing an unrealistically high reaction surface and at the same time eliminating the restrictions on element transport faced in-situ for fairly dense rocks. In reality, multiple reactions are coupled during the alteration of a polymineralic rocks in the presence of a fluid and the rate determining process of the overall reactions is often difficult to identify. We present results of bulk rock-water interaction experiments quantifying alteration reactions between pure water and a granodiorite sample. The rock sample was chosen for its homogenous texture, small and uniform grain size (˜0.5 mm in diameter), and absence of pre-existing alteration features. The primary minerals are plagioclase (plg - 58 vol.%), quartz (qtz - 21 vol.%), K-feldspar (Kfs - 17 vol.%), biotite (bio - 3 vol.%) and white mica (wm - 1 vol.%). Three sets of batch experiments were conducted at 200 ° C to evaluate the effect of reactive surface area and different fluid path ways using (I) powders of the bulk rock with

  16. The effect of rock electrical parameters on the calculation of reservoir saturation

    International Nuclear Information System (INIS)

    Li, Xiongyan; Qin, Ruibao; Liu, Chuncheng; Mao, Zhiqiang

    2013-01-01

    The error in calculating a reservoir saturation caused by the error in the cementation exponent, m, and the saturation exponent, n, should be analysed. In addition, the influence of m and n on the reservoir saturation should be discussed. Based on the Archie formula, the effect of variables m and n on the reservoir saturation is analysed, while the formula for the error in calculating the reservoir saturation, caused by the error in m and n, is deduced, and the main factors affecting the error in reservoir saturation are illustrated. According to the physical meaning of m and n, it can be interpreted that they are two independent parameters, i.e., there is no connection between m and n. When m and n have the same error, the impact of the variables on the calculation of the reservoir saturation should be compared. Therefore, when the errors of m and n are respectively equal to 0.2, 0.4 and 0.6, the distribution range of the errors in calculating the reservoir saturation is analysed. However, in most cases, the error of m and n is about 0.2. When the error of m is 0.2, the error in calculating the reservoir saturation ranges from 0% to 35%. Meanwhile, when the error in n is 0.2, the error in calculating the reservoir saturation is almost always below 5%. On the basis of loose sandstone, medium sandstone, tight sandstone, conglomerate, tuff, breccia, basalt, andesite, dacite and rhyolite, this paper first analyses the distribution range and change amplitude of m and n. Second, the impact of m and n on the calculation of reservoir saturation is elaborated upon. With regard to each lithology, the distribution range and change amplitude of m are greater than those of n. Therefore, compared with n, the effect of m on the reservoir saturation is stronger. The influence of m and n on the reservoir saturation is determined, and the error in calculating the reservoir saturation caused by the error of m and n is calculated. This is theoretically and practically significant for

  17. Geophysical and transport properties of reservoir rocks. Final report for task 4: Measurements and analysis of seismic properties

    Energy Technology Data Exchange (ETDEWEB)

    Cook, N.G.W.

    1993-05-01

    The principal objective of research on the seismic properties of reservoir rocks is to develop a basic understanding of the effects of rock microstructure and its contained pore fluids on seismic velocities and attenuation. Ultimately, this knowledge would be used to extract reservoir properties information such as the porosity, permeability, clay content, fluid saturation, and fluid type from borehole, cross-borehole, and surface seismic measurements to improve the planning and control of oil and gas recovery. This thesis presents laboratory ultrasonic measurements for three granular materials and attempts to relate the microstructural properties and the properties of the pore fluids to P- and S-wave velocities and attenuation. These experimental results show that artificial porous materials with sintered grains and a sandstone with partially cemented grains exhibit complexities in P- and S-wave attenuation that cannot be adequately explained by existing micromechanical theories. It is likely that some of the complexity observed in the seismic attenuation is controlled by details of the rock microstructure, such as the grain contact area and grain shape, and by the arrangement of the grain packing. To examine these effects, a numerical method was developed for analyzing wave propagation in a grain packing. The method is based on a dynamic boundary integral equation and incorporates generalized stiffness boundary conditions between individual grains to account for viscous losses and grain contact scattering.

  18. Rock music : a living legend of simulation modelling solves a reservoir problem by playing a different tune

    Energy Technology Data Exchange (ETDEWEB)

    Cope, G.

    2008-07-15

    Tight sand gas plays are low permeability reservoirs that have contributed an output of 5.7 trillion cubic feet of natural gas per year in the United States alone. Anadarko Petroleum Corporation has significant production from thousands of wells in Texas, Colorado, Wyoming and Utah. Hydraulic fracturing is the key to successful tight sand production. Production engineers use modelling software to calculate a well stimulation program in which large volumes of water are forced under high pressure in the reservoir, fracturing the rock and creating high permeability conduits for the natural gas to escape. Reservoir engineering researchers at the University of Calgary, led by world expert Tony Settari, have improved traditional software modelling of petroleum reservoirs by combining fracture analysis with geomechanical processes. This expertise has been a valuable asset to Anadarko, as the dynamic aspect can have a significant effect on the reservoir as it is being drilled. The challenges facing reservoir simulation is the high computing time needed for analyzing fluid production based on permeability, porosity, gas and fluid properties along with geomechanical analysis. Another challenge has been acquiring high quality field data. Using Anadarko's field data, the University of Calgary researchers found that water fracturing creates vertical primary fractures, and in some cases secondary fractures which enhance permeability. However, secondary fracturing is not permanent in all wells. The newly coupled geomechanical model makes it possible to model fracture growth more accurately. The Society of Petroleum Engineers recently awarded Settari with an award for distinguished achievement in improving the technique and practice of finding and producing petroleum. 1 fig.

  19. Pore facies analysis: incorporation of rock properties into pore geometry based classes in a Permo-Triassic carbonate reservoir in the Persian Gulf

    International Nuclear Information System (INIS)

    Rahimpour-Bonab, H; Aliakbardoust, E

    2014-01-01

    Pore facies analysis is a useful method for the classification of reservoir rocks according to pore geometry characteristics. The importance of this method is related to the dependence of the dynamic behaviour of the reservoir rock on the pore geometry. In this study, pore facies analysis was performed by the quantification and classification of the mercury injection capillary pressure (MICP) curves applying the multi-resolution graph-based clustering (MRGC) method. Each pore facies includes a limited variety of rock samples with different depositional fabrics and diagenetic histories, which are representative of one type of pore geometry. The present pore geometry is the result of the interaction between the primary rock fabric and its diagenetic overprint. Thus the variations in petrographic properties can be correlated with the pore geometry characteristics. Accordingly, the controlling parameters in the pore geometry characteristics were revealed by detailed petrographic analysis in each pore facies. The reservoir rock samples were then classified using the determined petrographic properties which control the pore system quality. This method is proposed for the classification of reservoir rocks in complicated carbonate reservoirs, in order to reduce the incompatibility of traditional facies analysis with pore system characteristics. The method is applicable where enough capillary pressure data is not available. (papers)

  20. Improve The Efficiency Of The Study Of Complex Reservoirs And Hydrocarbon Deposits - East Baghdad Field

    Directory of Open Access Journals (Sweden)

    Sudad H. Al-Obaidi

    2015-08-01

    Full Text Available Practical value of this work consists in increasing the efficiency of exploration for oil and gas fields in Eastern Baghdad by optimizing and reducing the complex of well logging coring sampling and well testing of the formation beds and computerizing the data of interpretation to ensure the required accuracy and reliability of the determination of petrophysical parameters that will clarify and increase proven reserves of hydrocarbon fields in Eastern Baghdad. In order to calculate the most accurate water saturation values for each interval of Zubair formation a specific modified form of Archie equation corresponding to this formation was developed.

  1. Evaluation of Management of Water Releases for Painted Rocks Reservoir, Bitterroot River, Montana, 1983-1986, Final Report.

    Energy Technology Data Exchange (ETDEWEB)

    Spoon, Ronald L. (Montana Department of Fish, Wildlife and Parks, Missoula, MT)

    1987-06-01

    This study was initiated in July, 1983 to develop a water management plan for the release of water purchased from Painted Rocks Reservoir. Releases were designed to provide optimum benefits to the Bitterroot River fishery. Fisheries, habitat, and stream flow information was gathered to evaluate the effectiveness of these supplemental releases in improving trout populations in the Bitterroot River. The study was part of the Northwest Power Planning Council's Fish and Wildlife Program and was funded by the Bonneville Power Administration. This report presents data collected from 1983 through 1986.

  2. Hydrocarbons

    Energy Technology Data Exchange (ETDEWEB)

    1927-02-22

    Coal tar, mineral oils, bitumens, coal extraction products, hydrogenation products of coal, oil schists can be atomized and heated with steam to decompose pyrogenetically and form gases rich in olefins which may be heated with or without pressure and with or without catalysts to produce liquid hydrocarbons of low boiling point, some of which may be aromatic. The apparatus should be lined with copper, silica, or ferrosilicon to prevent contact of the bases with iron which causes deposition of soot. Catalysts used may be metal oxides, silica, graphite, active charcoal, mica, pumice, porcelain, barium carbonate, copper, silver, gold, chromium, boron, or their compounds. At temperatures from 300 to 400/sup 0/C, olefins are produced. At higher temperatures, naphthenes and benzene hydrocarbons are produced.

  3. A Geochemical Model of Fluids and Mineral Interactions for Deep Hydrocarbon Reservoirs

    Directory of Open Access Journals (Sweden)

    Jun Li

    2017-01-01

    Full Text Available A mutual solubility model for CO2-CH4-brine systems is constructed in this work as a fundamental research for applications of deep hydrocarbon exploration and production. The model is validated to be accurate for wide ranges of temperature (0–250°C, pressure (1–1500 bar, and salinity (NaCl molality from 0 to more than 6 mole/KgW. Combining this model with PHREEQC functionalities, CO2-CH4-brine-carbonate-sulfate equilibrium is calculated. From the calculations, we conclude that, for CO2-CH4-brine-carbonate systems, at deeper positions, magnesium is more likely to be dissolved in aqueous phase and calcite can be more stable than dolomite and, for CO2-CH4-brine-sulfate systems, with a presence of CH4, sulfate ions are likely to be reduced to S2− and H2S in gas phase could be released after S2− saturated in the solution. The hydrocarbon “souring” process could be reproduced from geochemical calculations in this work.

  4. Fracture network growth for prediction of fracture characteristics and connectivity in tight reservoir rocks

    NARCIS (Netherlands)

    Barnhoorn, A.; Cox, S.F.

    2012-01-01

    Fracturing experiments on very low-porosity dolomite rocks shows a difference in growth of fracture networks by stress-driven fracturing and fluid-driven fracturing. Stress-driven fracture growth, in the absence of fluid pressure, initially forms fractures randomly throughout the rocks followed by

  5. Characterization of phosphorus leaching from phosphate waste rock in the Xiangxi River watershed, Three Gorges Reservoir, China.

    Science.gov (United States)

    Jiang, Li-Guo; Liang, Bing; Xue, Qiang; Yin, Cheng-Wei

    2016-05-01

    Phosphate mining waste rocks dumped in the Xiangxi River (XXR) bay, which is the largest backwater zone of the Three Gorges Reservoir (TGR), are treated as Type I industry solid wastes by the Chinese government. To evaluate the potential pollution risk of phosphorus leaching from phosphate waste rocks, the phosphorus leaching behaviors of six phosphate waste rock samples with different weathering degrees under both neutral and acidic conditions were investigated using a series of column leaching experiments, following the Method 1314 standard of the US EPA. The results indicate that the phosphorus release mechanism is solubility-controlled. Phosphorus release from waste rocks increases as pH decreases. The phosphorus leaching concentration and cumulative phosphorus released in acidic leaching conditions were found to be one order of magnitude greater than that in neutral leaching conditions. In addition, the phosphorus was released faster during the period when environmental pH turned from weak alkalinity to slight acidity, with this accelerated release period appearing when L/S was in the range of 0.5-2.0 mL/g. In both neutral and acidic conditions, the average values of Total Phosphorus (TP), including orthophosphates, polyphosphates and organic phosphate, leaching concentration exceed the availability by regulatory (0.5 mg/L) in the whole L/S range, suggesting that the phosphate waste rocks stacked within the XXR watershed should be considered as Type II industry solid wastes. Therefore, the phosphate waste rocks deposited within the study area should be considered as phosphorus point pollution sources, which could threaten the adjacent surface-water environment. Copyright © 2016 Elsevier Ltd. All rights reserved.

  6. APPLICATION OF WELL LOG ANALYSIS IN ASSESSMENT OF PETROPHYSICAL PARAMETERS AND RESERVOIR CHARACTERIZATION OF WELLS IN THE “OTH” FIELD, ANAMBRA BASIN, SOUTHERN NIGERIA

    Directory of Open Access Journals (Sweden)

    Eugene URORO

    2014-12-01

    Full Text Available Over the past years, the Anambra basin one of Nigeria’s inland basins has recorded significant level of hydrocarbon exploration activities. The basin has been confirmed by several authors from source rock analyses to have the potential for generating hydrocarbon. For the hydrocarbon to be exploited, it is imperative to have a thorough understanding of the reservoir. Computer-assisted log analyses were employed to effectively evaluate the petrophysical parameters such as the shale volume (Vsh, total porosity (TP, effective porosity (EP, water saturation (Sw, and hydrocarbon saturation (Sh. Cross-plots of the petrophysical parameters versus depth were illustrated. Five hydrocarbon bearing reservoirs were delineated in well 1, four in well 2. The reservoirs in well 3 do not contain hydrocarbon. The estimated reservoir porosity varies from 10% to 21% while their permeability values range from 20md to 1400md. The porosity and permeability values suggest that reservoirs are good enough to store and also permit free flow of fluid. The volume of shale (0.05% to 0.35% analysis reveals that the reservoirs range from shaly sand to slightly shaly sand to clean sand reservoir. On the basis of petrophysics data, the reservoirs are interpreted a good quality reservoir rocks which has been confirmed with high effective porosity range between 20% and high hydrocarbon saturation exceeding 55% water saturation in well 1 and well 2. Water saturation 3 is nearly 100% although the reservoir properties are good.  

  7. A land-use and water-quality history of White Rock Lake Reservoir, Dallas, Texas, based on paleolimnological analyses

    Science.gov (United States)

    Platt, Bradbury J.; Van Metre, P.C.

    1997-01-01

    White Rock Lake reservoir in Dallas, Texas contains a 150-cm sediment record of silty clay that documents land-use changes since its construction in 1912. Pollen analysis corroborates historical evidence that between 1912 and 1950 the watershed was primarily agricultural. Land disturbance by plowing coupled with strong and variable spring precipitation caused large amounts of sediment to enter the lake during this period. Diatoms were not preserved at this time probably because of low productivity compared to diatom dissolution by warm, alkaline water prior to burial in the sediments. After 1956, the watershed became progressively urbanized. Erosion decreased, land stabilized, and pollen of riparian trees increased as the lake water became somewhat less turbid. By 1986 the sediment record indicates that diatom productivity had increased beyond rates of diatom destruction. Neither increased nutrients nor reduced pesticides can account for increased diatom productivity, but grain size studies imply that before 1986 diatoms were light limited by high levels of turbidity. This study documents how reservoirs may relate to land-use practices and how watershed management could extend reservoir life and improve water quality.

  8. The role of nitrogen and sulphur bearing compounds in the wettability of oil reservoir rocks: an approach with nuclear microanalysis and other related surface techniques

    International Nuclear Information System (INIS)

    Mercier, F.; Toulhoat, N.; Potocek, V.; Trocellier, P.

    1999-01-01

    Oil recovery is strongly influenced by the wettability of the reservoir rock. Some constituents of the crude oil (polar compounds and heavy fractions such as asphaltenes with heteroatoms) are believed to react with the reservoir rock and to condition the local wettability. Therefore, it is important to obtain as much knowledge as possible about the characteristics of the organic matter/mineral interactions. This study is devoted to the description at the microscopic scale of the distribution of some heavy fractions of crude oil (asphaltenes) and nitrogen molecules (pyridine and pyrrole) on model minerals of sandstone reservoir rocks such as silica and clays. Nuclear microanalysis, X-Ray Photoelectron Spectroscopy and other related microscopic imaging techniques allow to study the distribution and thickness of the organic films. The respective influences of the nature of the mineral substrate and the organic matter are studied. The important role played by the nitrogen compounds in the adsorption of organic matter is emphasized

  9. Wind monitoring of the Saylorville and Red Rock Reservoir Bridges with remote, cellular-based notifications.

    Science.gov (United States)

    2012-05-01

    Following a high wind event on January 24, 2006, at least five people claimed to have seen or felt the superstructure of the Saylorville Reservoir Bridge in central Iowa moving both vertically and laterally. Since that time, the Iowa Department of Tr...

  10. Potential petrophysical and chemical property alterations in a compressed air energy storage porous rock reservoir

    Energy Technology Data Exchange (ETDEWEB)

    Stottlemyre, J.A.; Erikson, R.L.; Smith, R.P.

    1979-10-01

    Successful commercialization of Compressed Air Energy Storage (CAES) systems depends on long-term stability of the underground reservoirs subjected to somewhat unique operating conditions. Specifically, these conditions include elevated and time varying temperatures, effective stresses, and air humidities. To minimize the requirements for premium fuels, it may be desirable to retain the thermal energy of compression. Porous media, e.g., sandstone, may hold promise as elevated temperature reservoirs. In this study, a reservoir composed of clean quartz sandstone and injection air temperatures of 300 to 575/sup 0/K are assumed. Numerical modeling is used to estimate temperature, stress, and humidity conditions within this reference porous media reservoir. A discussion on relative importance to CAES of several potential porous media damage mechanisms is presented. In this context, damage is defined as a reduction in intrinsic permeability (measure of air transport capability), a decrease in effective porosity (measure of storage capability), or an increase in elastic and/or inelastic deformation of the porous material. The potential damage mechanisms presented include: (1) disaggregation, (2) particulate plugging, (3) boundary layer viscosity anomalies, (4) inelastic microstructural consolidation, (5) clay swelling and dispersion, (6) hydrothermal mineral alteration, (7) oxidation reactions, and (8) well casing corrosion. These mechanisms are placed in perspective with respect to anticipated CAES conditions and mechanisms suggested are: (1) of academic interest only, (2) readily identified and controlled via engineering, or (3) potential problem areas requiring additional investigation.

  11. Water exposure assessment of aryl hydrocarbon receptor agonists in Three Gorges Reservoir, China using SPMD-based virtual organisms.

    Science.gov (United States)

    Wang, Jingxian; Bernhöft, Silke; Pfister, Gerd; Schramm, Karl-Werner

    2014-10-15

    SPMD-based virtual organisms (VOs) were deployed at five to eight sites in the Three Gorges Reservoir (TGR), China for five periods in 2008, 2009 and 2011. The water exposure of aryl hydrocarbon receptor (AhR) agonists was assessed by the VOs. The chosen bioassay response for the extracts of the VOs, the induction of 7-ethoxyresorufin-O-deethylase (EROD) was assayed using a rat hepatoma cell line (H4IIE). The results show that the extracts from the VOs could induce AhR activity significantly, whereas the chemically derived 2,3,7,8-tetrachlorodibenzo-p-dioxin (TCDD) equivalent (TEQcal) accounted for water level reached a maximum of 175 m. Although the aqueous concentration of AhR agonists of 0.8-4.8 pg TCDDL(-1) in TGR was not alarming, the tendency of accumulating high concentration of AhR agonists in VO lipid and existence of possible synergism or antagonism in the water may exhibit a potential hazard to local biota being exposed to AhR agonists. Copyright © 2014 Elsevier B.V. All rights reserved.

  12. Time-lapse cased hole reservoir evaluation based on the dual-detector neutron lifetime log: the CHES II approach

    International Nuclear Information System (INIS)

    DeVries, M.R.; Fertl, W.

    1977-01-01

    A newly developed cased hole analysis technique provides detailed information on (1) reservoir rock properties, such as porosity, shaliness, and formation permeability, (2) reservoir fluid saturation, (3) distinction of oil and gas pays, (4) state of reservoir depletion, such as cumulative hydrocarbon-feet at present time and cumulative hydrocarbon-feet already depleted (e.g., the sum of both values then giving the cumulative hydrocarbon-feet originally present), and (5) monitoring of hydrocarbon/water and gas/oil contacts behind pipe. The basic well log data required for this type of analysis include the Dual-Detector Neutron Lifetime Log, run in casing at any particular time in the life of a reservoir, and the initial open-hole resistivity log. In addition, porosity information from open-hole porosity log(s) or core data is necessary. Field examples from several areas are presented and discussed in the light of formation reservoir and hydrocarbon production characteristics

  13. Lattice Boltzmann Simulations of Fluid Flow in Continental Carbonate Reservoir Rocks and in Upscaled Rock Models Generated with Multiple-Point Geostatistics

    Directory of Open Access Journals (Sweden)

    J. Soete

    2017-01-01

    Full Text Available Microcomputed tomography (μCT and Lattice Boltzmann Method (LBM simulations were applied to continental carbonates to quantify fluid flow. Fluid flow characteristics in these complex carbonates with multiscale pore networks are unique and the applied method allows studying their heterogeneity and anisotropy. 3D pore network models were introduced to single-phase flow simulations in Palabos, a software tool for particle-based modelling of classic computational fluid dynamics. In addition, permeability simulations were also performed on rock models generated with multiple-point geostatistics (MPS. This allowed assessing the applicability of MPS in upscaling high-resolution porosity patterns into large rock models that exceed the volume limitations of the μCT. Porosity and tortuosity control fluid flow in these porous media. Micro- and mesopores influence flow properties at larger scales in continental carbonates. Upscaling with MPS is therefore necessary to overcome volume-resolution problems of CT scanning equipment. The presented LBM-MPS workflow is applicable to other lithologies, comprising different pore types, shapes, and pore networks altogether. The lack of straightforward porosity-permeability relationships in complex carbonates highlights the necessity for a 3D approach. 3D fluid flow studies provide the best understanding of flow through porous media, which is of crucial importance in reservoir modelling.

  14. 4D seismic reservoir characterization, integrated with geo-mechanical modelling

    NARCIS (Netherlands)

    Angelov, P.V.

    2009-01-01

    Hydrocarbon production induces time-lapse changes in the seismic attributes (travel time and amplitude) both at the level of the producing reservoir and in the surrounding rock. The detected time-lapse changes in the seismic are induced from the changes in the petrophysical properties of the rock,

  15. The role of fluid migration system in hydrocarbon accumulation in Maichen Sag, Beibuwan Basin

    Science.gov (United States)

    Liu, Hongyu; Yang, Jinxiu; Wu, Feng; Chen, Wei; Liu, Qianqian

    2018-02-01

    Fluid migration system is of great significance for hydrocarbon accumulation, including the primary migration and secondary migration. In this paper, the fluid migration system is analysed in Maichen Sag using seismic, well logging and core data. Results show that many factors control the hydrocarbon migration process, including hydrocarbon generation and expulsion period from source rocks, microfractures developed in the source rocks, the connected permeable sand bodies, the vertical faults cutting into/through the source rocks and related fault activity period. The spatial and temporal combination of these factors formed an effective network for hydrocarbon expulsion and accumulation, leading to the hydrocarbon reservoir distribution at present. Generally, a better understanding of the hydrocarbon migration system can explain the present status of hydrocarbon distribution, and help select future target zones for oil and gas exploration.

  16. Quantification of pore size distribution in reservoir rocks using MRI logging: A case study of South Pars Gas Field.

    Science.gov (United States)

    Ghojogh, Jalal Neshat; Esmaili, Mohammad; Noruzi-Masir, Behrooz; Bakhshi, Puyan

    2017-12-01

    Pore size distribution (PSD) is an important factor for controlling fluid transport through porous media. The study of PSD can be applicable in areas such as hydrocarbon storage, contaminant transport, prediction of multiphase flow, and analysis of the formation damage by mud infiltration. Nitrogen adsorption, centrifugation method, mercury injection, and X-ray computed tomography are commonly used to measure the distribution of pores. A core sample is occasionally not available because of the unconsolidated nature of reservoirs, high cost of coring operation, and program limitations. Magnetic resonance imaging logging (MRIL) is a proper logging technique that allows the direct measurement of the relaxation time of protons in pore fluids and correlating T 2 distribution to PSD using proper mathematical equations. It is nondestructive and fast and does not require core samples. In this paper, 8 core samples collected from the Dalan reservoir in South Pars Gas Field were studied by processing MRIL data and comparing them by PSD determined in the laboratory. By using the MRIL method, variation in PSD corresponding to the depth for the entire logged interval was determined. Moreover, a detailed mineralogical composition of the reservoir samples related to T 2 distribution was obtained. A good correlation between MRIL and mercury injection data was observed. High degree of similarity was also observed between T 2 distribution and PSD (R 2 = 0.85 to 0.91). Based on the findings from the MRIL method, the obtained values for clay bond water varied between 1E-6 and 1E-3µm, a range that is comprehended from an extra peak on the PSD curve. The frequent pore radius was determined to be 1µm. Copyright © 2017 Elsevier Ltd. All rights reserved.

  17. Feasibility of a data-constrained prediction of hydrocarbon reservoir sandstone microstructures

    International Nuclear Information System (INIS)

    Yang, Y S; Gureyev, T E; Tulloh, A; Clennell, M B; Pervukhina, M

    2010-01-01

    Microstructures are critical for defining material characteristics such as permeability, mechanical, electrical and other physical properties. However, the available techniques for determining compositional microstructures through segmentation of x-ray computed tomography (CT) images are inadequate when there are finer structures than the CT spatial resolution, i.e. when there is more than one material in each voxel. This is the case for CT imaging of geomaterials characterized with submicron porosity and clay coating that control petrophysical properties of rock. This note outlines our data-constrained modelling (DCM) approach for prediction of compositional microstructures, and our investigation of the feasibility of determining sandstone microstructures using multiple CT data sets with different x-ray beam energies. In the DCM approach, each voxel is assumed to contain a mixture of multiple materials, optionally including voids. Our preliminary comparisons using model samples indicate that the DCM-predicted compositional microstructure is consistent with the known original microstructure under low noise conditions. The approach is quite generic and is applicable to predictions of microstructure of various materials. (technical design note)

  18. Hydrodynamic thickness of petroleum oil adsorbed layers in the pores of reservoir rocks.

    Science.gov (United States)

    Alkafeef, Saad F; Algharaib, Meshal K; Alajmi, Abdullah F

    2006-06-01

    The hydrodynamic thickness delta of adsorbed petroleum (crude) oil layers into the pores of sandstone rocks, through which the liquid flows, has been studied by Poiseuille's flow law and the evolution of (electrical) streaming current. The adsorption of petroleum oil is accompanied by a numerical reduction in the (negative) surface potential of the pore walls, eventually stabilizing at a small positive potential, attributed to the oil macromolecules themselves. After increasing to around 30% of the pore radius, the adsorbed layer thickness delta stopped growing either with time or with concentrations of asphaltene in the flowing liquid. The adsorption thickness is confirmed with the blockage value of the rock pores' area determined by the combination of streaming current and streaming potential measurements. This behavior is attributed to the effect on the disjoining pressure across the adsorbed layer, as described by Derjaguin and Churaev, of which the polymolecular adsorption films lose their stability long before their thickness has approached the radius of the rock pore.

  19. Mercury-free PVT apparatus for thermophysical property analyses of hydrocarbon reservoir fluids. Final report, August 16, 1990--July 31, 1992

    Energy Technology Data Exchange (ETDEWEB)

    Lansangan, R.M.; Lievois, J.S.

    1992-08-31

    Typical reservoir fluid analyses of complex, multicomponent hydrocarbon mixtures include the volumetric properties, isothermal compressibility, thermal expansivity, equilibrium ratios, saturation pressure, viscosities, etc. These parameters are collectively referred to as PVT properties, an acronym for the primary state variables; pressure, volume, and temperature. The reservoir engineer incorporates this information together with the porous media description in performing material balance calculations. These calculations lead to the determination (estimation) of the initial hydrocarbon in-place, the future reservoir performance, the optimal production scheme, and the ultimate hydrocarbon recovery. About four years ago, Ruska Instrument Corporation embarked on a project to develop an apparatus designed to measure PVT properties that operates free of mercury. The result of this endeavor is the 2370 Hg-Free PVT system which has been in the market for the last three years. The 2370 has evolved from the prototype unit to its present configuration which is described briefly in this report. The 2370 system, although developed as a system-engineered apparatus based on existing technology, has not been exempt from this burden-of-proof Namely, the performance of the apparatus under routine test conditions with real reservoir fluids. This report summarizes the results of the performance and applications testing of the 2370 Hg-Free PVT system. Density measurements were conducted on a pure fluid. The results were compared against literature values and the prediction of an equation of state. Routine reservoir fluid analyses were conducted with a black oil and a retrograde condensate gas mixtures. Limited comparison of the results were performed based on the same tests performed on a conventional mercury-based PVT apparatus. The results of these tests are included in this report.

  20. Reactivity of hydrocarbons in response to injection of a CO2/O2 mixture under depleted reservoir conditions: experimental and numerical modeling

    International Nuclear Information System (INIS)

    Pacini-Petitjean, Claire

    2015-01-01

    The geological storage of CO 2 (CO 2 Capture-Storage - CCS) and the Enhanced Oil Recovery (EOR) by CO 2 injection into petroleum reservoirs could limit CO 2 atmospheric accumulation. However, CO 2 can be associated with oxygen. To predict the hydrocarbon evolution under these conditions involves the study of oxidation mechanisms. Oxidation experiment and kinetic detailed modeling were carried out with pure compounds. The comparison between experimental and modeling results led to the construction of a hydrocarbon oxidation kinetic model and emphasized the parameters leading to auto ignition. The good agreement between our experiments and modeling are promising for the development of a tool predicting the critical temperature leading to auto-ignition and the evolution of hydrocarbon composition, to estimate the stability of a petroleum system in CO 2 injection context. (author) [fr

  1. Regional assessments of the hydrocarbon generation potential of selected North American proterozoic rock sequences. Progress report, September 1989--April 1990

    Energy Technology Data Exchange (ETDEWEB)

    Engel, M.H.; Elmore, R.D.

    1990-04-01

    Our primary research objectives for the first year of this grant are nearing completion. This includes comprehensive sedimentologic/organic geochemical studies of two depositionally distinct, unmetamorphosed units, the Nonesuch Formation ({approximately}1.1 Ga lacustrine rift deposit) and the Dripping Spring Quartzite ({approximately}1.3 Ga marine shelf deposit). As discussed in this progress report, an attempt has been made to (1) identify source rocks by quantification and characterization of constituent organic matter, (2) recognize depositional/diagenetic/catagenetic factors that may have influenced source rock quality and (3) evaluate the possibility of previous or current hydrocarbon generation and migration. Organic petrology and geochemical analyses suggest important differences between kerogens in the Michigan (MI) and Wisconsin (WI) Nonesuch Formation study areas. When considered within a geographic/stratigraphic framework, the Nonesuch Formation in the MI study area exhibits superior source rock potential. It is suggested that sedimentary organic matter in the WI area was subject to more extensive microbial alteration during early diagenesis. It is also possible that thermal maturity levels were slightly to moderately higher in WI than MI. Petrologic evidence for migrated bitumens and the stable isotope composition of late vein carbonates suggest, furthermore, that oil generation and migration may have actually been more extensive in the WI study area.

  2. Reconstruction of burial history, temperature, source rock maturity and hydrocarbon generation in the northwestern Dutch offshore

    NARCIS (Netherlands)

    Abdul Fattah, R.; Verweij, J.M.; Witmans, N.; Veen, J.H. ten

    2012-01-01

    3D basin modelling is used to investigate the history of maturation and hydrocarbon generation on the main platforms in the northwestern part of the offshore area of the Netherlands. The study area covers the Cleaverbank and Elbow Spit Platforms. Recently compiled maps and data are used to build the

  3. Hydrogeologic controls on induced seismicity in crystalline basement rocks due to fluid injection into basal reservoirs.

    Science.gov (United States)

    Zhang, Yipeng; Person, Mark; Rupp, John; Ellett, Kevin; Celia, Michael A; Gable, Carl W; Bowen, Brenda; Evans, James; Bandilla, Karl; Mozley, Peter; Dewers, Thomas; Elliot, Thomas

    2013-01-01

    A series of Mb 3.8-5.5 induced seismic events in the midcontinent region, United States, resulted from injection of fluid either into a basal sedimentary reservoir with no underlying confining unit or directly into the underlying crystalline basement complex. The earthquakes probably occurred along faults that were likely critically stressed within the crystalline basement. These faults were located at a considerable distance (up to 10 km) from the injection wells and head increases at the hypocenters were likely relatively small (∼70-150 m). We present a suite of simulations that use a simple hydrogeologic-geomechanical model to assess what hydrogeologic conditions promote or deter induced seismic events within the crystalline basement across the midcontinent. The presence of a confining unit beneath the injection reservoir horizon had the single largest effect in preventing induced seismicity within the underlying crystalline basement. For a crystalline basement having a permeability of 2 × 10(-17)  m(2) and specific storage coefficient of 10(-7) /m, injection at a rate of 5455 m(3) /d into the basal aquifer with no underlying basal seal over 10 years resulted in probable brittle failure to depths of about 0.6 km below the injection reservoir. Including a permeable (kz  = 10(-13)  m(2) ) Precambrian normal fault, located 20 m from the injection well, increased the depth of the failure region below the reservoir to 3 km. For a large permeability contrast between a Precambrian thrust fault (10(-12)  m(2) ) and the surrounding crystalline basement (10(-18)  m(2) ), the failure region can extend laterally 10 km away from the injection well. © 2013, National Ground Water Association.

  4. Compositional controls on early diagenetic pathways in fine-grained sedimentary rocks: Implications for predicting unconventional reservoir attributes of mudstones

    Science.gov (United States)

    Keller, Margaret A.; Macquaker, Joe H.S.; Taylor, Kevin G.; Polya, David

    2014-01-01

    Diagenesis significantly impacts mudstone lithofacies. Processes operating to control diagenetic pathways in mudstones are poorly known compared to analogous processes occurring in other sedimentary rocks. Selected organic-carbon-rich mudstones, from the Kimmeridge Clay and Monterey Formations, have been investigated to determine how varying starting compositions influence diagenesis.The sampled Kimmeridge Clay Formation mudstones are organized into thin homogenous beds, composed mainly of siliciclastic detritus, with some constituents derived from water-column production (e.g., coccoliths, S-depleted type-II kerogen, as much as 52.6% total organic carbon [TOC]) and others from diagenesis (e.g., pyrite, carbonate, and kaolinite). The sampled Monterey Formation mudstones are organized into thin beds that exhibit pelleted wavy lamination, and are predominantly composed of production-derived components including diatoms, coccoliths, and foraminifera, in addition to type-IIS kerogen (as much as 16.5% TOC), and apatite and silica cements.During early burial of the studied Kimmeridge Clay Formation mudstones, the availability of detrital Fe(III) and reactive clay minerals caused carbonate- and silicate-buffering reactions to operate effectively and the pore waters to be Fe(II) rich. These conditions led to pyrite, iron-poor carbonates, and kaolinite cements precipitating, preserved organic carbon being S-depleted, and sweet hydrocarbons being generated. In contrast, during the diagenesis of the sampled Monterey Formation mudstones, sulfide oxidation, coupled with opal dissolution and the reduced availability of both Fe(III) and reactive siliciclastic detritus, meant that the pore waters were poorly buffered and locally acidic. These conditions resulted in local carbonate dissolution, apatite and silica cements precipitation, natural kerogen sulfurization, and sour hydrocarbons generation.Differences in mud composition at deposition significantly influence subsequent

  5. Combined rock-physical modelling and seismic inversion techniques for characterisation of stacked sandstone reservoir

    NARCIS (Netherlands)

    Justiniano, A.; Jaya, Y.; Diephuis, G.; Veenhof, R.; Pringle, T.

    2015-01-01

    The objective of the study is to characterise the Triassic massive stacked sandstone deposits of the Main Buntsandstein Subgroup at Block Q16 located in the West Netherlands Basin. The characterisation was carried out through combining rock-physics modelling and seismic inversion techniques. The

  6. Phase I (Year 1) Summary of Research--Establishing the Relationship between Fracture-Related Dolomite and Primary Rock Fabric on the Distribution of Reservoirs in the Michigan Basin

    Energy Technology Data Exchange (ETDEWEB)

    G. Michael Grammer

    2005-11-09

    This topical report covers the first 12 months of the subject 3-year grant, evaluating the relationship between fracture-related dolomite and dolomite constrained by primary rock fabric in the 3 most prolific reservoir intervals in the Michigan Basin (Ordovician Trenton-Black River Formations; Silurian Niagara Group; and the Devonian Dundee Formation). Phase I tasks, including Developing a Reservoir Catalog for selected dolomite reservoirs in the Michigan Basin, Characterization of Dolomite Reservoirs in Representative Fields and Technology Transfer have all been initiated and progress is consistent with our original scheduling. The development of a reservoir catalog for the 3 subject formations in the Michigan Basin has been a primary focus of our efforts during Phase I. As part of this effort, we currently have scanned some 13,000 wireline logs, and compiled in excess of 940 key references and 275 reprints that cover reservoir aspects of the 3 intervals in the Michigan Basin. A summary evaluation of the data in these publications is currently ongoing, with the Silurian Niagara Group being handled as a first priority. In addition, full production and reservoir parameter data bases obtained from available data sources have been developed for the 3 intervals in Excel and Microsoft Access data bases. We currently have an excess of 25 million cells of data for wells in the Basin. All Task 2 objectives are on time and on target for Phase I per our original proposal. Our mapping efforts to date, which have focused in large part on the Devonian Dundee Formation, have important implications for both new exploration plays and improved enhanced recovery methods in the Dundee ''play'' in Michigan--i.e. the interpreted fracture-related dolomitization control on the distribution of hydrocarbon reservoirs. In an exploration context, high-resolution structure mapping using quality-controlled well data should provide leads to convergence zones of fault

  7. How the rock fabrics can control the physical properties - A contribution to the understanding of carbonate reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Duerrast, H.; Siegesmund, S. [Goettingen Univ. (Germany)

    1998-12-31

    The correlation between microfabrics and physical properties will be illustrated in detail on three dolomitic carbonate reservoir rocks with different porosity. For this study core segments from the Zechstein Ca2-layer (Permian) of the Northwest German Basin were kindly provided by the Preussag Energie GmbH, Lingen. The mineral composition was determined by using the X-ray diffraction method. Petrographic and detailed investigation of the microfabrics, including the distribution and orientation of the cracks were done macroscopally (core segments) and microscopally with the optical microscope and the Scanning Electron Microscope (thin sections in three orthogonally to each other oriented directions). Different kinds of petrophysical measurements were carried out, e.g. porosity, permeability, electrical conductivity, seismic velocities. (orig.)

  8. Invasion of geothermal fluids into hydrocarbon reservoirs; La invasion de fluidos geotermicos en yacimientos de hidrocarburos

    Energy Technology Data Exchange (ETDEWEB)

    Suarez Arriaga, Mario Cesar [Universidad Michoacana, Facultad de Ciencias, Morelia, Michoacan (Mexico)]. E-mail: msuarez@umich.mx

    2009-01-15

    Oil reservoirs beneath the coast of the Gulf of Mexico contain geothermal brine at 150 degrees Celsius and produce a mixture of hot brine and oil. Water from an aquifer 6000 m deep flows vertically through conductive faults. These nonisothermal conditions affect the effective saturations and the relative permeability of the immiscible phases. Dynamic viscosities of oil and water diminish, affecting the displacement of both fluids. Studied wells produce from the oil-saturated zone above the aquifer, yet the total volume of produced water can equal or exceed the volume of oil. The presence of water is a severe problem. We produced an original numerical model able to predict the critical production when the wells start to be invaded by geothermal brine. The model has a single equation in partial derivatives, of a parabolic and nonlineal type, which is a function of water saturation, three-dimension space and time. A gas phase can be included in the model. This equation is a generalization of the classic isothermal result of Buckley-Leverett, in a single dimension. The model is solved numerically by using the Finite Element method on a nonstructured network. The historic effect of water invasion observed in some critical cases is reproduced. After production with both phases stable, a sudden brine invasion can occur with a sharp reduction of the oil volume produced. The immediate objective is to optimize the production so the well will be able to produce a stable water-oil mix where oil always prevails. [Spanish] Se reportan reservorios de aceite situados en la costa del Golfo de Mexico que son invadidos por salmuera geotermica con una temperatura de 150 grados centigrados, produciendo una mezcla variable de agua caliente y aceite. El agua de un acuifero, a 6000 metros de profundidad, fluye verticalmente por fallas conductivas. Estas condiciones no isotermicas afectan las saturaciones efectivas y las permeabilidades relativas de las fases inmiscibles. Las viscosidades

  9. Modelling of water-gas-rock geo-chemical interactions. Application to mineral diagenesis in geological reservoirs

    International Nuclear Information System (INIS)

    Bildstein, Olivier

    1998-01-01

    Mineral diagenesis in tanks results from interactions between minerals, water, and possibly gases, over geological periods of time. The associated phenomena may have a crucial importance for reservoir characterization because of their impact on petrophysical properties. The objective of this research thesis is thus to develop a model which integrates geochemical functions necessary to simulate diagenetic reactions, and which is numerically efficient enough to perform the coupling with a transport model. After a recall of thermodynamic and kinetic backgrounds, the author discusses how the nature of available analytic and experimental data influenced choices made for the formalization of physical-chemical phenomena and for behaviour laws to be considered. Numerical and computational aspects are presented in the second part. The model is validated by using simple examples. The different possible steps during the kinetic competition between two mineral are highlighted, as well the competition between mineral reaction kinetics and water flow rate across the rock. Redox reactions are also considered. In the third part, the author reports the application of new model functions, and highlights the contribution of the modelling to the understanding of some complex geochemical phenomena and to the prediction of reservoir quality. The model is applied to several diagenetic transformations: cementation of dolomitic limestone by anhydride, illite precipitation, and thermal reduction of sulphates [fr

  10. Jurassic and Cretaceous clays of the northern and central North Sea hydrocarbon reservoirs reviewed

    Energy Technology Data Exchange (ETDEWEB)

    Wilkinson, M.; Haszeldine, R.S.; Fallick, A.E.

    2006-03-15

    illite occurs almost ubiquitously within the clastic sediments of the North Sea. An early pore-lining phase has been interpreted as both infiltrated clastic clay, and as an early diagenetic phase. Early clays may have been quite smectite-rich illites, or even discrete smectites. Later, fibrous illite is undoubtedly neoformed, and can degrade reservoir quality significantly. Both within sandstones and shales, there is an apparent increase in the K content deeper than 4 km of burial, which could be due to dilution of the early smectite-rich phase by new growth illite, or to the progressive illitization of existing I-S. Much of the 'illite' that has been dated by the K-Ar method may therefore actually be I-S. The factors that control the formation of fibrous illite are only poorly known, though temperature must play a role. Illite growth has been proposed for almost the entire range of diagenetic temperatures (e.g. 15-20{sup o}C, Brent Group; 35-40{sup o}C, Oxfordian Sand, Inner Moray Firth; 50-90{sup o}C, Brae formation; 100-110{sup o}C, Brent Group; 130-140{sup o}C, Haltenbanken). It seems unlikely that there is a threshold temperature below which illite growth is impossible (or too slow to be significant), though this is a recurring hypothesis in the literature. Instead, illite growth seems to be an event, commonly triggered by oil emplacement or another change in the physiochemical conditions within the sandstone, such as an episode of overpressure release. Hence fibrous illite can grow at any temperature encountered during diagenesis. Although there is an extensive dataset of K-Ar ages of authigenic illites from the Jurassic of the North Sea, there is no consensus as to whether the data are meaningful, or whether the purified illite samples prepared for analysis are so contaminated with detrital phases as to render the age data meaningless. At present it is unclear about how to resolve this problem, though there is some indication that chemical micro

  11. Tests of US rock salt for long-term stability of CAES reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Gehle, R.M.; Thoms, R.L.

    1986-01-01

    This is a report on laboratory tests to assess the effects of compressed air energy storage (CAES) on rock salt within the US. The project included a conventional laboratory test phase, with triaxial test machines, and a bench-scale test phase performed in salt mines in southern Louisiana. Limited numerical modeling also was performed to serve as a guide in selecting test layouts and for interpreting test data.

  12. Factors affecting storage of compressed air in porous-rock reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Allen, R.D.; Doherty, T.J.; Erikson, R.L.; Wiles, L.E.

    1983-05-01

    This report documents a review and evaluation of the geotechnical aspects of porous medium (aquifer) storage. These aspects include geologic, petrologic, geophysical, hydrologic, and geochemical characteristics of porous rock masses and their interactions with compressed air energy storage (CAES) operations. The primary objective is to present criteria categories for the design and stability of CAES in porous media (aquifers). The document will also describe analytical, laboratory, and field-scale investigations that have been conducted.

  13. Element mobilization and immobilization from carbonate rocks between CO 2 storage reservoirs and the overlying aquifers during a potential CO 2 leakage

    Energy Technology Data Exchange (ETDEWEB)

    Lawter, Amanda R.; Qafoku, Nikolla P.; Asmussen, R. Matthew; Kukkadapu, Ravi K.; Qafoku, Odeta; Bacon, Diana H.; Brown, Christopher F.

    2018-04-01

    Despite the numerous studies on changes within the reservoir following CO2 injection and the effects of CO2 release into overlying aquifers, little or no literature is available on the effect of CO2 release on rock between the storage reservoirs and subsurface. To address this knowledge gap, relevant rock materials, temperatures and pressures were used to study mineralogical and elemental changes in this intermediate zone. After rocks reacted with CO2, liquid analysis showed an increase of major elements (e.g., Ca, and Mg) and variable concentrations of potential contaminants (e.g., Sr and Ba); lower concentrations were observed in N2 controls. In experiments with As/Cd and/or organic spikes, representing potential contaminants in the CO2 plume originating in the storage reservoir, most or all of these contaminants were removed from the aqueous phase. SEM and Mössbauer spectroscopy results showed the formation of new minerals and Fe oxides in some CO2-reacted samples, indicating potential for contaminant removal through mineral incorporation or adsorption onto Fe oxides. These experiments show the interactions between the CO2-laden plume and the rock between storage reservoirs and overlying aquifers have the potential to affect the level of risk to overlying groundwater, and should be considered during site selection and risk evaluation.

  14. The Baltic Basin: structure, properties of reservoir rocks, and capacity for geological storage of CO2

    Directory of Open Access Journals (Sweden)

    Vaher, Rein

    2009-12-01

    Full Text Available Baltic countries are located in the limits of the Baltic sedimentary basin, a 700 km long and 500 km wide synclinal structure. The axis of the syneclise plunges to the southwest. In Poland the Precambrian basement occurs at a depth of 5 km. The Baltic Basin includes the Neoproterozoic Ediacaran (Vendian at the base and all Phanerozoic systems. Two aquifers, the lower Devonian and Cambrian reservoirs, meet the basic requirements for CO2 storage. The porosity and permeability of sandstone decrease with depth. The average porosity of Cambrian sandstone at depths of 80–800, 800–1800, and 1800–2300 m is 18.6, 14.2, and 5.5%, respectively. The average permeability is, respectively, 311, 251, and 12 mD. Devonian sandstone has an average porosity of 26% and permeability in the range of 0.5–2 D. Prospective Cambrian structural traps occur only in Latvia. The 16 largest ones have CO2 storage capacity in the range of 2–74 Mt, with total capacity exceeding 400 Mt. The structural trapping is not an option for Lithuania as the uplifts there are too small. Another option is utilization of CO2 for enhanced oil recovery (EOR. The estimated total EOR net volume of CO2 (part of CO2 remaining in the formation in Lithuania is 5.6 Mt. Solubility and mineral trapping are a long-term option. The calculated total solubility trapping capacity of the Cambrian reservoir is as high as 11 Gt of CO2 within the area of the supercritical state of carbon dioxide.

  15. SEISMIC ATTENUATION FOR RESERVOIR CHARACTERIZATION

    Energy Technology Data Exchange (ETDEWEB)

    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. The Eocene Rusayl Formation, Oman, carbonaceous rocks in calcareous shelf sediments: Environment of deposition, alteration and hydrocarbon potential

    Energy Technology Data Exchange (ETDEWEB)

    Dill, H.G.; Wehner, H.; Kus, J. [Federal Institute for Geosciences and Natural Resources, P.O. Box 510163, D-30631 Hannover (Germany); Botz, R. [University Kiel, Geological-Paleontological Department, Olshausenstrasse 40-60, D-24118 Kiel (Germany); Berner, Z.; Stueben, D. [Technical University Karlsruhe, Institute for Mineralogy and Geochemistry, Fritz-Haber-Weg 2, D-76131 Karlsruhe (Germany); Al-Sayigh, A. [Sultan Qaboos University, Geological Dept. PO Box 36, Al-Khod (Oman)

    2007-10-01

    incursions make up a greater deal of the sedimentary record than mangrove swamps. Terra rossa paleosols mark the end of accumulation of organic material (OM) and herald supratidal conditions at the passage of Rusayl Formation into the overlying Seeb Formation. In the subtidal-supratidal cycles of lithofacies unit VIII the terra rossa horizons are thining upwards and become gradually substituted for by deep-water middle ramp sediments of lithofacies unit IX. Framboidal pyrite, (ferroan) dolomite with very little siderite are indicative of an early diagenetic alteration stage I under rather moderate temperatures of formation. During a subsequent stage II, an increase in the temperature of alteration was partly induced by burial and a high heat flow from the underlying Semail Ophiolite. Type-III kerogen originating from higher plants and, in addition, some marine biota gave rise to the generation of small amounts of soluble organic matter during this stage of diagenesis. The average reflectance of humic particles marks the beginning of the oil window and the production index reveals the existence of free hydrocarbons. Further uplift of the Eocene strata and oxidation during stage IIII caused veins of satin spar to form from organic sulfur and pyrite in the carbonaceous material. Lowering of the pH value of the pore fluid led to the precipitation of jarosite and a set of hydrated aluminum sulfates dependant upon the cations present in the wall rocks. AMD minerals (= acid mine drainage) are not very widespread in this carbonaceous series intercalated among calcareous rocks owing to the buffering effect of carbonate minerals. These carbonate-hosted carbonaceous rocks are below an economic level as far as the mining of coal is concerned, but deserves particular attention as source rocks for hydrocarbons in the Middle East, provided a higher stage of maturity is reached. (author)

  17. Final Report: Development of a Chemical Model to Predict the Interactions between Supercritical CO2, Fluid and Rock in EGS Reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    McPherson, Brian J. [University of Utah; Pan, Feng [University of Utah

    2014-09-24

    This report summarizes development of a coupled-process reservoir model for simulating enhanced geothermal systems (EGS) that utilize supercritical carbon dioxide as a working fluid. Specifically, the project team developed an advanced chemical kinetic model for evaluating important processes in EGS reservoirs, such as mineral precipitation and dissolution at elevated temperature and pressure, and for evaluating potential impacts on EGS surface facilities by related chemical processes. We assembled a new database for better-calibrated simulation of water/brine/ rock/CO2 interactions in EGS reservoirs. This database utilizes existing kinetic and other chemical data, and we updated those data to reflect corrections for elevated temperature and pressure conditions of EGS reservoirs.

  18. From axiomatics of quantum probability to modelling geological uncertainty and management of intelligent hydrocarbon reservoirs with the theory of open quantum systems

    Science.gov (United States)

    Lozada Aguilar, Miguel Ángel; Khrennikov, Andrei; Oleschko, Klaudia

    2018-04-01

    As was recently shown by the authors, quantum probability theory can be used for the modelling of the process of decision-making (e.g. probabilistic risk analysis) for macroscopic geophysical structures such as hydrocarbon reservoirs. This approach can be considered as a geophysical realization of Hilbert's programme on axiomatization of statistical models in physics (the famous sixth Hilbert problem). In this conceptual paper, we continue development of this approach to decision-making under uncertainty which is generated by complexity, variability, heterogeneity, anisotropy, as well as the restrictions to accessibility of subsurface structures. The belief state of a geological expert about the potential of exploring a hydrocarbon reservoir is continuously updated by outputs of measurements, and selection of mathematical models and scales of numerical simulation. These outputs can be treated as signals from the information environment E. The dynamics of the belief state can be modelled with the aid of the theory of open quantum systems: a quantum state (representing uncertainty in beliefs) is dynamically modified through coupling with E; stabilization to a steady state determines a decision strategy. In this paper, the process of decision-making about hydrocarbon reservoirs (e.g. `explore or not?'; `open new well or not?'; `contaminated by water or not?'; `double or triple porosity medium?') is modelled by using the Gorini-Kossakowski-Sudarshan-Lindblad equation. In our model, this equation describes the evolution of experts' predictions about a geophysical structure. We proceed with the information approach to quantum theory and the subjective interpretation of quantum probabilities (due to quantum Bayesianism). This article is part of the theme issue `Hilbert's sixth problem'.

  19. From axiomatics of quantum probability to modelling geological uncertainty and management of intelligent hydrocarbon reservoirs with the theory of open quantum systems.

    Science.gov (United States)

    Lozada Aguilar, Miguel Ángel; Khrennikov, Andrei; Oleschko, Klaudia

    2018-04-28

    As was recently shown by the authors, quantum probability theory can be used for the modelling of the process of decision-making (e.g. probabilistic risk analysis) for macroscopic geophysical structures such as hydrocarbon reservoirs. This approach can be considered as a geophysical realization of Hilbert's programme on axiomatization of statistical models in physics (the famous sixth Hilbert problem). In this conceptual paper , we continue development of this approach to decision-making under uncertainty which is generated by complexity, variability, heterogeneity, anisotropy, as well as the restrictions to accessibility of subsurface structures. The belief state of a geological expert about the potential of exploring a hydrocarbon reservoir is continuously updated by outputs of measurements, and selection of mathematical models and scales of numerical simulation. These outputs can be treated as signals from the information environment E The dynamics of the belief state can be modelled with the aid of the theory of open quantum systems: a quantum state (representing uncertainty in beliefs) is dynamically modified through coupling with E ; stabilization to a steady state determines a decision strategy. In this paper, the process of decision-making about hydrocarbon reservoirs (e.g. 'explore or not?'; 'open new well or not?'; 'contaminated by water or not?'; 'double or triple porosity medium?') is modelled by using the Gorini-Kossakowski-Sudarshan-Lindblad equation. In our model, this equation describes the evolution of experts' predictions about a geophysical structure. We proceed with the information approach to quantum theory and the subjective interpretation of quantum probabilities (due to quantum Bayesianism).This article is part of the theme issue 'Hilbert's sixth problem'. © 2018 The Author(s).

  20. Mobility Effect on Poroelastic Seismic Signatures in Partially Saturated Rocks With Applications in Time-Lapse Monitoring of a Heavy Oil Reservoir

    Science.gov (United States)

    Zhao, Luanxiao; Yuan, Hemin; Yang, Jingkang; Han, De-hua; Geng, Jianhua; Zhou, Rui; Li, Hui; Yao, Qiuliang

    2017-11-01

    Conventional seismic analysis in partially saturated rocks normally lays emphasis on estimating pore fluid content and saturation, typically ignoring the effect of mobility, which decides the ability of fluids moving in the porous rocks. Deformation resulting from a seismic wave in heterogeneous partially saturated media can cause pore fluid pressure relaxation at mesoscopic scale, thereby making the fluid mobility inherently associated with poroelastic reflectivity. For two typical gas-brine reservoir models, with the given rock and fluid properties, the numerical analysis suggests that variations of patchy fluid saturation, fluid compressibility contrast, and acoustic stiffness of rock frame collectively affect the seismic reflection dependence on mobility. In particular, the realistic compressibility contrast of fluid patches in shallow and deep reservoir environments plays an important role in determining the reflection sensitivity to mobility. We also use a time-lapse seismic data set from a Steam-Assisted Gravity Drainage producing heavy oil reservoir to demonstrate that mobility change coupled with patchy saturation possibly leads to seismic spectral energy shifting from the baseline to monitor line. Our workflow starts from performing seismic spectral analysis on the targeted reflectivity interface. Then, on the basis of mesoscopic fluid pressure diffusion between patches of steam and heavy oil, poroelastic reflectivity modeling is conducted to understand the shift of the central frequency toward low frequencies after the steam injection. The presented results open the possibility of monitoring mobility change of a partially saturated geological formation from dissipation-related seismic attributes.

  1. Burial history, thermal history and hydrocarbon generation modelling of the Jurassic source rocks in the basement of the Polish Carpathian Foredeep and Outer Carpathians (SE Poland)

    Science.gov (United States)

    Kosakowski, Paweł; Wróbel, Magdalena

    2012-08-01

    Burial history, thermal maturity, and timing of hydrocarbon generation were modelled for the Jurassic source rocks in the basement of the Carpathian Foredeep and marginal part of the Outer Carpathians. The area of investigation was bounded to the west by Kraków, to the east by Rzeszów. The modelling was carried out in profiles of wells: Będzienica 2, Dębica 10K, Góra Ropczycka 1K, Goleszów 5, Nawsie 1, Pławowice E1 and Pilzno 40. The organic matter, containing gas-prone Type III kerogen with an admixture of Type II kerogen, is immature or at most, early mature to 0.7 % in the vitrinite reflectance scale. The highest thermal maturity is recorded in the south-eastern part of the study area, where the Jurassic strata are buried deeper. The thermal modelling showed that the obtained organic matter maturity in the initial phase of the "oil window" is connected with the stage of the Carpathian overthrusting. The numerical modelling indicated that the onset of hydrocarbon generation from the Middle Jurassic source rocks was also connected with the Carpathian thrust belt. The peak of hydrocarbon generation took place in the orogenic stage of the overthrusting. The amount of generated hydrocarbons is generally small, which is a consequence of the low maturity and low transformation degree of kerogen. The generated hydrocarbons were not expelled from their source rock. An analysis of maturity distribution and transformation degree of the Jurassic organic matter shows that the best conditions for hydrocarbon generation occurred most probably in areas deeply buried under the Outer Carpathians. It is most probable that the "generation kitchen" should be searched for there.

  2. Application of conditional simulation of heterogeneous rock properties to seismic scattering and attenuation analysis in gas hydrate reservoirs

    Science.gov (United States)

    Huang, Jun-Wei; Bellefleur, Gilles; Milkereit, Bernd

    2012-02-01

    We present a conditional simulation algorithm to parameterize three-dimensional heterogeneities and construct heterogeneous petrophysical reservoir models. The models match the data at borehole locations, simulate heterogeneities at the same resolution as borehole logging data elsewhere in the model space, and simultaneously honor the correlations among multiple rock properties. The model provides a heterogeneous environment in which a variety of geophysical experiments can be simulated. This includes the estimation of petrophysical properties and the study of geophysical response to the heterogeneities. As an example, we model the elastic properties of a gas hydrate accumulation located at Mallik, Northwest Territories, Canada. The modeled properties include compressional and shear-wave velocities that primarily depend on the saturation of hydrate in the pore space of the subsurface lithologies. We introduce the conditional heterogeneous petrophysical models into a finite difference modeling program to study seismic scattering and attenuation due to multi-scale heterogeneity. Similarities between resonance scattering analysis of synthetic and field Vertical Seismic Profile data reveal heterogeneity with a horizontal-scale of approximately 50 m in the shallow part of the gas hydrate interval. A cross-borehole numerical experiment demonstrates that apparent seismic energy loss can occur in a pure elastic medium without any intrinsic attenuation of hydrate-bearing sediments. This apparent attenuation is largely attributed to attenuative leaky mode propagation of seismic waves through large-scale gas hydrate occurrence as well as scattering from patchy distribution of gas hydrate.

  3. Rock-fluid chemical interactions at reservoir conditions: The influence of brine chemistry and extent of reaction

    Science.gov (United States)

    Anabaraonye, B. U.; Crawshaw, J.; Trusler, J. P. M.

    2016-12-01

    Following carbon dioxide injection in deep saline aquifers, CO2 dissolves in the formation brines forming acidic solutions that can subsequently react with host reservoir minerals, altering both porosity and permeability. The direction and rates of these reactions are influenced by several factors including properties that are associated with the brine system. Consequently, understanding and quantifying the impacts of the chemical and physical properties of the reacting fluids on overall reaction kinetics is fundamental to predicting the fate of the injected CO2. In this work, we present a comprehensive experimental study of the kinetics of carbonate-mineral dissolution in different brine systems including sodium chloride, sodium sulphate and sodium bicarbonate of varying ionic strengths. The impacts of the brine chemistry on rock-fluid chemical reactions at different extent of reactions are also investigated. Using a rotating disk technique, we have investigated the chemical interactions between the CO2-saturated brines and carbonate minerals at conditions of pressure (up to 10 MPa) and temperature (up to 373 K) pertinent to carbon storage. The changes in surface textures due to dissolution reaction were studied by means of optical microscopy and vertical scanning interferometry. Experimental results are compared to previously derived models.

  4. An integrated rock magnetic and EPR study in soil samples from a hydrocarbon prospective area

    Science.gov (United States)

    González, F.; Aldana, M.; Costanzo-Álvarez, V.; Díaz, M.; Romero, I.

    Magnetic susceptibility (MS) and organic matter free radical concentration (OMFRC) determined by electron paramagnetic resonance, have been measured in soil samples (≈1.5 m depth) from an oil prospective area located at the southern flank of the Venezuelan Andean Range. S-ratios close to 1, as well as high temperature susceptibility analyses, reveal magnetite as the chief magnetic phase in most of these samples. Ethane concentrations, MS and OMFRC normalized data have been plotted against the relative position of 22 sampling sites sequentially arranged from north to south. Although there is not a linear correlation between MS and OMFRC data, these two profiles seem to vary in like fashion. A MS and OMFRC southern anomaly coincides with the zone of highest ethane concentration that overlies a “Cretaceous kitchen”. OMFRC highs could be linked to the degradation or alteration of organic matter, the possible result of hydrocarbon gas leakage, whose surface expression is the stressed fern observed by remote sensing studies previously performed in the area. Ethane anomalies are associated to this seepage that also produces changes in the magnetic mineralogies detected as MS positive anomalies.

  5. Mineralogical controls on porosity and water chemistry during O_2-SO_2-CO_2 reaction of CO_2 storage reservoir and cap-rock core

    International Nuclear Information System (INIS)

    Pearce, Julie K.; Golab, Alexandra; Dawson, Grant K.W.; Knuefing, Lydia; Goodwin, Carley; Golding, Suzanne D.

    2016-01-01

    Reservoir and cap-rock core samples with variable lithology's representative of siliciclastic reservoirs used for CO_2 storage have been characterized and reacted at reservoir conditions with an impure CO_2 stream and low salinity brine. Cores from a target CO_2 storage site in Queensland, Australia were tested. Mineralogical controls on the resulting changes to porosity and water chemistry have been identified. The tested siliciclastic reservoir core samples can be grouped generally into three responses to impure CO_2-brine reaction, dependent on mineralogy. The mineralogically clean quartzose reservoir cores had high porosities, with negligible change after reaction, in resolvable porosity or mineralogy, calculated using X-ray micro computed tomography and QEMSCAN. However, strong brine acidification and a high concentration of dissolved sulphate were generated in experiments owing to minimal mineral buffering. Also, the movement of kaolin has the potential to block pore throats and reduce permeability. The reaction of the impure CO_2-brine with calcite-cemented cap-rock core samples caused the largest porosity changes after reaction through calcite dissolution; to the extent that one sample developed a connection of open pores that extended into the core sub-plug. This has the potential to both favor injectivity but also affect CO_2 migration. The dissolution of calcite caused the buffering of acidity resulting in no significant observable silicate dissolution. Clay-rich cap-rock core samples with minor amounts of carbonate minerals had only small changes after reaction. Created porosity appeared mainly disconnected. Changes were instead associated with decreases in density from Fe-leaching of chlorite or dissolution of minor amounts of carbonates and plagioclase. The interbedded sandstone and shale core also developed increased porosity parallel to bedding through dissolution of carbonates and reactive silicates in the sandy layers. Tight interbedded cap-rocks

  6. Origin and evolution of formation water at the Jujo-Tecominoacan oil reservoir, Gulf of Mexico. Part 1: Chemical evolution and water-rock interaction

    Energy Technology Data Exchange (ETDEWEB)

    Birkle, Peter, E-mail: birkle@iie.org.mx [Instituto de Investigaciones Electricas (IIE), Gerencia de Geotermia, Av. Reforma 113, Cuernavaca, Morelos 62490 (Mexico); Garcia, Bernardo Martinez; Milland Padron, Carlos M. [PEMEX Exploracion y Produccion, Region Sur, Activo Integral Bellota-Jujo, Diseno de Explotacion, Cardenas, Tabasco (Mexico)

    2009-04-15

    The origin and evolution of formation water from Upper Jurassic to Upper Cretaceous mudstone-packstone-dolomite host rocks at the Jujo-Tecominoacan oil reservoir, located onshore in SE-Mexico at a depth from 5200 to 6200 m.b.s.l., have been investigated, using detailed water geochemistry from 12 producer wells and six closed wells, and related host rock mineralogy. Saline waters of Cl-Na type with total dissolved solids from 10 to 23 g/L are chemically distinct from hypersaline Cl-Ca-Na and Cl-Na-Ca type waters with TDS between 181 and 385 g/L. Bromine/Cl and Br/Na ratios suggest the subaerial evaporation of seawater beyond halite precipitation to explain the extreme hypersaline components, while less saline samples were formed by mixing of high salinity end members with surface-derived, low salinity water components. The dissolution of evaporites from adjacent salt domes has little impact on present formation water composition. Geochemical simulations with Harvie-M{phi}ller-Weare and PHRQPITZ thermodynamic data sets suggest secondary fluid enrichment in Ca, HCO{sub 3} and Sr by water-rock interaction. The volumetric mass balance between Ca enrichment and Mg depletion confirms dolomitization as the major alteration process. Potassium/Cl ratios below evaporation trajectory are attributed to minor precipitation of K feldspar and illitization without evidence for albitization at the Jujo-Tecominoacan reservoir. The abundance of secondary dolomite, illite and pyrite in drilling cores from reservoir host rock reconfirms the observed water-rock exchange processes. Sulfate concentrations are controlled by anhydrite solubility as indicated by positive SI-values, although anhydrite deposition is limited throughout the lithological reservoir column. The chemical variety of produced water at the Jujo-Tecominoacan oil field is related to a sequence of primary and secondary processes, including infiltration of evaporated seawater and original meteoric fluids, the subsequent

  7. Origin and evolution of formation water at the Jujo-Tecominoacan oil reservoir, Gulf of Mexico. Part 1: Chemical evolution and water-rock interaction

    International Nuclear Information System (INIS)

    Birkle, Peter; Garcia, Bernardo Martinez; Milland Padron, Carlos M.

    2009-01-01

    The origin and evolution of formation water from Upper Jurassic to Upper Cretaceous mudstone-packstone-dolomite host rocks at the Jujo-Tecominoacan oil reservoir, located onshore in SE-Mexico at a depth from 5200 to 6200 m.b.s.l., have been investigated, using detailed water geochemistry from 12 producer wells and six closed wells, and related host rock mineralogy. Saline waters of Cl-Na type with total dissolved solids from 10 to 23 g/L are chemically distinct from hypersaline Cl-Ca-Na and Cl-Na-Ca type waters with TDS between 181 and 385 g/L. Bromine/Cl and Br/Na ratios suggest the subaerial evaporation of seawater beyond halite precipitation to explain the extreme hypersaline components, while less saline samples were formed by mixing of high salinity end members with surface-derived, low salinity water components. The dissolution of evaporites from adjacent salt domes has little impact on present formation water composition. Geochemical simulations with Harvie-Mφller-Weare and PHRQPITZ thermodynamic data sets suggest secondary fluid enrichment in Ca, HCO 3 and Sr by water-rock interaction. The volumetric mass balance between Ca enrichment and Mg depletion confirms dolomitization as the major alteration process. Potassium/Cl ratios below evaporation trajectory are attributed to minor precipitation of K feldspar and illitization without evidence for albitization at the Jujo-Tecominoacan reservoir. The abundance of secondary dolomite, illite and pyrite in drilling cores from reservoir host rock reconfirms the observed water-rock exchange processes. Sulfate concentrations are controlled by anhydrite solubility as indicated by positive SI-values, although anhydrite deposition is limited throughout the lithological reservoir column. The chemical variety of produced water at the Jujo-Tecominoacan oil field is related to a sequence of primary and secondary processes, including infiltration of evaporated seawater and original meteoric fluids, the subsequent mixing of

  8. Integrated 3D Reservoir/Fault Property Modelling Aided Well Planning and Improved Hydrocarbon Recovery in a Niger Delta Field

    International Nuclear Information System (INIS)

    Onyeagoro, U. O.; Ebong, U. E.; Nworie, E. A.

    2002-01-01

    The large and varied portfolio of assets managed by oil companies requires quick decision-making and the deployment of best in class technologies in asset management. Timely decision making and the application of the best technologies in reservoir management are however sometimes in conflict due to large time requirements of the latter.Optimizing the location of development wells is critical to account for variable fluid contact movements and pressure interference effects between wells, which can be significant because of the high permeability (Darcy range) of Niger Delta reservoirs. With relatively high drilling costs, the optimization of well locations necessitates a good realistic static and dynamic 3D reservoir description, especially in the recovery of remaining oil and oil rim type of reservoirs.A detailed 3D reservoir model with fault properties was constructed for a Niger delta producing field. This involved the integration of high quality 3D seismic, core, petrophysics, reservoir engineering, production and structural geology data to construct a realistic 3D reservoir/fault property model for the field. The key parameters considered during the construction of the internal architecture of the model were the vertical and horizontal reservoir heterogeneities-this controls the fluid flow within the reservoir. In the production realm, the fault thickness and fault permeabilities are factors that control the impedance of fluid flow across the fault-fault transmissibility. These key internal and external reservoir/structural variables were explicitly modeled in a 3D modeling software to produce different realizations and manage the uncertainties.The resulting 3D reservoir/fault property model was upscaled for simulation purpose such that grid blocks along the fault planes have realistic transmissibility multipliers of 0 to 1 attached to them. The model was also used in the well planner to optimize the positioning of a high angle deviated well that penetrated

  9. Understanding the fracture role on hydrocarbon accumulation and distribution using seismic data: A case study on a carbonate reservoir from Iran

    Science.gov (United States)

    Karimpouli, Sadegh; Hassani, Hossein; Malehmir, Alireza; Nabi-Bidhendi, Majid; Khoshdel, Hossein

    2013-09-01

    The South Pars, the largest gas field in the world, is located in the Persian Gulf. Structurally, the field is part of the Qatar-South Pars arch which is a regional anticline considered as a basement-cored structure with long lasting passive folding induced by salt withdrawal. The gas-bearing reservoir belongs to Kangan and Dalan formations dominated by carbonate rocks. The fracture role is still unknown in gas accumulation and distribution in this reservoir. In this paper, the Scattering Index (SI) and the semblance methods based on scattered waves and diffraction signal studies, respectively, were used to delineate the fracture locations. To find the relation between fractures and gas distribution, desired facies containing the gas, were defined and predicted using a method based on Bayesian facies estimation. The analysis and combination of these results suggest that preference of fractures and/or fractured zones are negligible (about 1% of the total volume studied in this paper) and, therefore, it is hard to conceive that they play an important role in this reservoir. Moreover, fractures have no considerable role in gas distribution (less than 30%). It can be concluded from this study that sedimentary processes such as digenetic, primary porosities and secondary porosities are responsible for the gas accumulation and distribution in this reservoir.

  10. Types and characteristics of carbonate reservoirs and their implication on hydrocarbon exploration: A case study from the eastern Tarim Basin, NW China

    Directory of Open Access Journals (Sweden)

    Shiwei Huang

    2017-02-01

    Full Text Available Carbonate rocks are deposited in the Ordovician, Cambrian, and Sinian of eastern Tarim Basin with a cumulative maximum thickness exceeding 2000 m. They are the main carriers of oil and gas, and a great deal of natural gas has been found there in the past five years. Based on lithofacies and reservoir differences, natural gas exploration domains of eastern Tarim Basin can be classified into five types: Ordovician platform limestone; Ordovician platform dolomite; Cambrian platform margin mound shoal; Cambrian slope gravity flow deposits, and; Sinian dolomite. Carbonate reservoir characteristics of all the types were synthetically analyzed through observation on drilling core and thin sections, porosity and permeability measurement, and logging data of over 10 drilling wells. We find distribution of part of good fracture and cave reservoir in carbonate platform limestone of Ordovician. In the Ordovician, platform facies dolomite is better than limestone, and in the Cambrian, platform margin mound shoal dolomite has large stacking thickness. Good quality and significantly thick carbonate gravity deposit flow can be found in the Cambrian slope, and effective reservoir has also been found in Sinian dolomite. Commercial gas has been found in the limestone and dolomite of Ordovician in Shunnan and Gucheng areas. Exploration experiences from these two areas are instructive, enabling a deeper understanding of this scene.

  11. The Role of the Nuclear Science and Technology in Hydrocarbon

    International Nuclear Information System (INIS)

    Eko Budi Lelono; Isnawati

    2007-01-01

    The development of the nuclear science and technology influences the method of hydrocarbon exploration as shown by the use of radioactive isotope to determine the absolute age of the rock. Traditionally, the age determination relies on the occurrence of index fossil, both micro and macro forms, to define the relative age of the rock. The absolute age is basically defined based on the calculation of the decay of the selected radioactive mineral. By referring to its absolute age, the rock (source rock or reservoir) can be precisely put in the certain stratigraphic level. On the other hand, the nuclear technology - so called NMR (Nuclear Magnetic Resonance) - is applied in the well exploration survey to measure the porosity and the permeability of the rock for predicting the existence of hydrocarbon. From the sedimentology view point, the nuclear technology is used in x ray diffraction (XRD) laboratory to identify mineral in the reservoir rock. In addition, it is also applied in scanning electron microscope (sem) laboratory for estimating the porosity of reservoir. These kinds of information are required by the exploration experts to create reservoir management. (author)

  12. The role of mineral heterogeneity on the hydrogeochemical response of two fractured reservoir rocks in contact with dissolved CO2

    Science.gov (United States)

    Garcia Rios, Maria; Luquot, Linda; Soler, Josep M.; Cama, Jordi

    2017-04-01

    In this study we compare the hydrogeochemical response of two fractured reservoir rocks (limestone composed of 100 wt.% calcite and sandstone composed of 66 wt.% calcite, 28 wt.% quartz and 6 wt.% microcline) in contact with CO2-rich sulfate solutions. Flow-through percolation experiments were performed using artificially fractured limestone and sandstone cores and injecting a CO2-rich sulfate solution under a constant volumetric flow rate (from 0.2 to 60 mL/h) at P = 150 bar and T = 60 °C. Measurements of the pressure difference between the inlet and the outlet of the samples and of the aqueous chemistry enabled the determination of fracture permeability changes and net reaction rates. Additionally, X-ray computed microtomography (XCMT) was used to characterize and localized changes in fracture volume induced by dissolution and precipitation reactions. In all reacted cores an increase in fracture permeability and in fracture volume was always produced even when gypsum precipitation happened. The presence of inert silicate grains in sandstone samples favored the occurrence of largely distributed dissolution structures in contrast to localized dissolution in limestone samples. This phenomenon promoted greater dissolution and smaller precipitation in sandstone than in limestone experiments. As a result, in sandstone reservoirs, the larger increase in fracture volume as well as the more extended distribution of the created volume would favor the CO2 storage capacity. The different distribution of created volume between limestone and sandstone experiments led to a different variation in fracture permeability. The progressive stepped permeability increase for sandstone would be preferred to the sharp permeability increase for limestone to minimize risks related to CO2 injection, favor capillary trapping and reduce energetic storage costs. 2D reactive transport simulations that reproduce the variation in aqueous chemistry and the fracture geometry (dissolution pattern

  13. Unlocking the hydrocarbon potential of the eastern Black Sea basin. Prospectivity of middle Miocene submarine fan reservoirs by seismic sequence stratigraphy

    International Nuclear Information System (INIS)

    Gundogan, Coskun; Galip, Ozbek; Ali, Demirer

    2002-01-01

    Full text : The objective of this paper is to present present depositional characteristics and hydrocarbon prospectivity of the middle Miocene submarine basin floor fan deposits from the exploration stand point of view by using seismic data available in the offshore eastern Black Sea basin. This basin is a Tertiary trough formed as a continuation of the Mesozoic oceanic basin. The hydrocarbon potential of the basin is believed to be high in the Tertiary section because of the existence of the elements necessary for generation, migration and entrapment of hydrocarbon. A sequence stratigraphic study has been carried out by using 2-d seismic data in the Turkish portion of the eastern Black Sea basin. The objective of the study was to determine periods of major clastic sediment influxes which might lead to identify good reservoir intervals and their spatial distribution in this basin. All basic seismic sequence stratigraphic interpretation techniques and seismic facies analysis were used to identify times of these sand rich deposition periods. Sequence stratigraphy and seismic facies analysis indicate that the basinal areas of the middle Miocene sequences were dominated mainly by submarine fan complexes introduced in the lowstand stages and pelagic sediments deposited during the transgressive and highstand stages. It was proposed that Turkish portion of this basin which is one of the best frontier exploration area with its high potential left in the world, is glimpsing to those looking for good future exploration opportunities.

  14. Deep reservoir and barrier rock units in Bavaria. An overview; Tiefliegende Speicher- und Barrieregesteinskomplexe in Bayern. Ein Ueberblick

    Energy Technology Data Exchange (ETDEWEB)

    Diepolder, Gerold W.; Schulz, Uta [Bayerisches Landesamt fuer Umweltschutz, Muenchen (Germany). Geologischer Dienst

    2011-07-01

    In order to meet the challenges of sustainable development the capture and sequestration of CO{sub 2} (CCS) is generally accepted as one option for the mitigation of climate change. Within the scope of the project ''Information system on geological storage options in Germany'' 23 potential reservoir and barrier rock suites of the deeper subsurface in Bavaria have been re-evaluated based on existing data and reports. Focused on the feasibility of CO{sub 2}-sequestration only areas at a depth of more than 800 m have been investigated in two major basins: the deeper parts of the Franconian Basin and the Molasse Basin. Due to the heterogeneous distribution of borehole data with large areas completely lacking information and, in many cases, insufficient lithological characterisations many formations are described rather cursory. Mapping of the spatial distribution is confined to four examples from the project's deliverables showing typical and complex situations. Contour maps of strate as well as isopach maps produced within the project's scope are mentioned. A reasonable regionalisation of porosity and permeability data was not feasible. Competing subsurface uses strongly restricting the utilisation of CO{sub 2}-sequestration are summarised. Owing to insufficient data available all statements made and summary maps depicted in this report are rather vague even at the 1: 1m. overview scale. Thus, an appraisal of the effective suitability of particular areas for geological storage of CO{sub 2} requires additional investigations in detail considering all structural features and the reach of impact of competing subsurface rights. (orig.)

  15. The presence of hydrocarbons in southeast Norway

    DEFF Research Database (Denmark)

    Hanken, Niels Martin; Hansen, Malene Dolberg; Kresten Nielsen, Jesper

    Hydrocarbons, mostly found as solid pyrobitumen, are known from more than 30 localities in southeast Norway. They occur as inclusions in a wide range of "reservoir rocks" spanning from Permo-Carboniferous breccias to veins (vein quartz and calcite veins) in Precambrian granites, gneisses and amph......Hydrocarbons, mostly found as solid pyrobitumen, are known from more than 30 localities in southeast Norway. They occur as inclusions in a wide range of "reservoir rocks" spanning from Permo-Carboniferous breccias to veins (vein quartz and calcite veins) in Precambrian granites, gneisses......, indicating that Alum Shale was the most important source rock. Petrographic investigations combined with stable isotope analyses (d13C and d18O) of the cement containing pyrobitumen indicate two phases of hydrocarbon migration. The first phase probably took place in Upper Silurian to Lower Devonian time......, when the Alum Shale entered the oil window. These hydrocarbons are mostly found as pyrobitumen in primary voids and calcite cemented veins in Cambro-Silurian sedimentary deposits. The second phase is probably of Late Carboniferous/Permian age and was due to the increased heat flow during the formation...

  16. Petroleum geological features and exploration prospect of deep marine carbonate rocks in China onshore: A further discussion

    Directory of Open Access Journals (Sweden)

    Zhao Wenzhi

    2014-10-01

    Full Text Available Deep marine carbonate rocks have become one of the key targets of onshore oil and gas exploration and development for reserves replacement in China. Further geological researches of such rocks may practically facilitate the sustainable, steady and smooth development of the petroleum industry in the country. Therefore, through a deep investigation into the fundamental geological conditions of deep marine carbonate reservoirs, we found higher-than-expected resource potential therein, which may uncover large oil or gas fields. The findings were reflected in four aspects. Firstly, there are two kinds of hydrocarbon kitchens which were respectively formed by conventional source rocks and liquid hydrocarbons cracking that were detained in source rocks, and both of them can provide large-scale hydrocarbons. Secondly, as controlled by the bedding and interstratal karstification, as well as the burial and hydrothermal dolomitization, effective carbonate reservoirs may be extensively developed in the deep and ultra-deep strata. Thirdly, under the coupling action of progressive burial and annealing heating, some marine source rocks could form hydrocarbon accumulations spanning important tectonic phases, and large quantity of liquid hydrocarbons could be kept in late stage, contributing to rich oil and gas in such deep marine strata. Fourthly, large-scale uplifts were formed by the stacking of multi-episodic tectonism and oil and gas could be accumulated in three modes (i.e., stratoid large-area reservoir-forming mode of karst reservoirs in the slope area of uplift, back-flow type large-area reservoir-forming mode of buried hill weathered crust karst reservoirs, and wide-range reservoir-forming mode of reef-shoal reservoirs; groups of stratigraphic and lithologic traps were widely developed in the areas of periclinal structures of paleohighs and continental margins. In conclusion, deep marine carbonate strata in China onshore contain the conditions for

  17. Evolution of the Petrophysical and Mineralogical Properties of Two Reservoir Rocks Under Thermodynamic Conditions Relevant for CO2 Geological Storage at 3 km Depth

    International Nuclear Information System (INIS)

    Rimmel, G.; Barlet-Gouedard, V.; Renard, F.

    2010-01-01

    Injection of carbon dioxide (CO 2 ) underground, for long-term geological storage purposes, is considered as an economically viable option to reduce greenhouse gas emissions in the atmosphere. The chemical interactions between supercritical CO 2 and the potential reservoir rock need to be thoroughly investigated under thermodynamic conditions relevant for geological storage. In the present study, 40 samples of Lavoux limestone and Adamswiller sandstone, both collected from reservoir rocks in the Paris basin, were experimentally exposed to CO 2 in laboratory autoclaves specially built to simulate CO 2 -storage-reservoir conditions. The two types of rock were exposed to wet supercritical CO 2 and CO 2 -saturated water for one month, at 28 MPa and 90 C, corresponding to conditions for a burial depth approximating 3 km. The changes in mineralogy and micro-texture of the samples were measured using X-ray diffraction analyses, Raman spectroscopy, scanning-electron microscopy, and energy-dispersion spectroscopy microanalysis. The petrophysical properties were monitored by measuring the weight, density, mechanical properties, permeability, global porosity, and local porosity gradients through the samples. Both rocks maintained their mechanical and mineralogical properties after CO 2 exposure despite an increase of porosity and permeability. Microscopic zones of calcite dissolution observed in the limestone are more likely to be responsible for such increase. In the sandstone, an alteration of the petro-fabric is assumed to have occurred due to clay minerals reacting with CO 2 . All samples of Lavoux limestone and Adamswiller sandstone showed a measurable alteration when immersed either in wet supercritical CO 2 or in CO 2 -saturated water. These batch experiments were performed using distilled water and thus simulate more severe conditions than using formation water (brine). (authors)

  18. Microbial diversity in methanogenic hydrocarbon-degrading enrichment cultures isolated from a water-flooded oil reservoir (Dagang oil field, China)

    Science.gov (United States)

    Jiménez, Núria; Cai, Minmin; Straaten, Nontje; Yao, Jun; Richnow, Hans H.; Krüger, Martin

    2015-04-01

    Microbial transformation of oil to methane is one of the main degradation processes taking place in oil reservoirs, and it has important consequences as it negatively affects the quality and economic value of the oil. Nevertheless, methane could constitute a recovery method of carbon from exhausted reservoirs. Previous studies combining geochemical and isotopic analysis with molecular methods showed evidence for in situ methanogenic oil degradation in the Dagang oil field, China (Jiménez et al., 2012). However, the main key microbial players and the underlying mechanisms are still relatively unknown. In order to better characterize these processes and identify the main microorganisms involved, laboratory biodegradation experiments under methanogenic conditions were performed. Microcosms were inoculated with production and injection waters from the reservoir, and oil or 13C-labelled single hydrocarbons (e.g. n-hexadecane or 2-methylnaphthalene) were added as sole substrates. Indigenous microbiota were able to extensively degrade oil within months, depleting most of the n-alkanes in 200 days, and producing methane at a rate of 76 ± 6 µmol day-1 g-1 oil added. They could also produce heavy methane from 13C-labeled 2-methylnaphthalene, suggesting that further methanogenesis may occur from the aromatic and polyaromatic fractions of Dagang reservoir fluids. Microbial communities from oil and 2-methyl-naphthalene enrichment cultures were slightly different. Although, in both cases Deltaproteobacteria, mainly belonging to Syntrophobacterales (e.g. Syntrophobacter, Smithella or Syntrophus) and Clostridia, mostly Clostridiales, were among the most represented taxa, Gammaproteobacteria could be only identified in oil-degrading cultures. The proportion of Chloroflexi, exclusively belonging to Anaerolineales (e.g. Leptolinea, Bellilinea) was considerably higher in 2-methyl-naphthalene degrading cultures. Archaeal communities consisted almost exclusively of representatives of

  19. Petrophysical examination of CO₂-brine-rock interactions-results of the first stage of long-term experiments in the potential Zaosie Anticline reservoir (central Poland) for CO₂ storage.

    Science.gov (United States)

    Tarkowski, Radosław; Wdowin, Magdalena; Manecki, Maciej

    2015-01-01

    The objective of the study was determination of experiment-induced alterations and changes in the properties of reservoir rocks and sealing rocks sampled from potential reservoir for CO₂. In the experiment, rocks submerged in brine in specially constructed reactors were subjected to CO₂ pressure of 6 MPa for 20 months at room temperature. Samples of Lower Jurassic reservoir rocks and sealing rocks (sandstones, claystones, and mudstones) from the Zaosie Anticline (central Poland) were analysed for their petrophysical properties (specific surface area, porosity, pore size and distribution) before and after the experiment. Comparison of the ionic composition the brines before and after the experiment demonstrated an increase in total dissolved solids as well as the concentration of sulphates and calcium ions. This indicates partial dissolution of the rock matrix and the cements. As a result of the reaction, the properties of reservoir rocks did not changed significantly and should not affect the process of CO₂ storage. In the case of the sealing rocks, however, the porosity, the framework density, as well as the average capillary and threshold diameter increased. Also, the pore distribution in the pore space changed in favour of larger pores. The reasons for these changes could not be explained by petrographic characteristics and should be thoroughly investigated.

  20. Geologic and petrophysic analysis of a travertine block as hydrocarbon reservoir analogue; Analise geologica e petrofisica de um bloco de travertino como analogo de reservatorio de hidrocarbonetos

    Energy Technology Data Exchange (ETDEWEB)

    Basso, Mateus; Kuroda, Michelle Chaves; Vidal, Alexandre Campane, E-mail: mbstraik@gmail.com, E-mail: ckuroda@ige.unicamp.br, E-mail: vidal@ige.unicamp.br [Universidade Estadual de Campinas (CEPETRO/UNICAMP), SP (Brazil). Centro de Estudos do Petroleo

    2017-04-15

    Microbialitic limestones are gaining space in petroleum geology due to the existence of many reservoirs composed of these lithologies in the pre-salt producing fields. Travertine, calcareous tufa and stromatolites figure among the rocks proposed as analogous for the microbialitic rocks. This work conduces the study of geological, petrophysical and geophysical parameters of a travertine block measuring 1,60 x 1,60 x 2,70 m, weighing 21,2 tons and available in the Centro de Estudo do Petroleo (CEPETRO) at the Universidade Estadual de Campinas. The Italian block, named T-block, corresponds to the representative elementary volume of its original formation and allows the study in an intermediate scale between the hand sample and the outcrop scale. Permeability tests and gamma ray spectrometry measurements were conducted and the porosity was calculated by image analysis. Models were generated from the obtained data and then associated with descriptive geology of the block. A reduction in permeability, porosity and concentration of elements potassium (K), uranium (U) and thorium (Th) was recorded, following a gradient towards the top of the T-block accompanying the reduction in the degree of development of the rock fabric. (author)

  1. Investigating the effects of rock porosity and permeability on the performance of nitrogen injection into a southern Iranian oil reservoirs through neural network

    Science.gov (United States)

    Gheshmi, M. S.; Fatahiyan, S. M.; Khanesary, N. T.; Sia, C. W.; Momeni, M. S.

    2018-03-01

    In this work, a comprehensive model for Nitrogen injection into an oil reservoir (southern Iranian oil fields) was developed and used to investigate the effects of rock porosity and permeability on the oil production rate and the reservoir pressure decline. The model was simulated and developed by using ECLIPSE300 software, which involved two scenarios as porosity change and permeability changes in the horizontal direction. We found that the maximum pressure loss occurs at a porosity value of 0.07, which later on, goes to pressure buildup due to reservoir saturation with the gas. Also we found that minimum pressure loss is encountered at porosity 0.46. Increases in both pressure and permeability in the horizontal direction result in corresponding increase in the production rate, and the pressure drop speeds up at the beginning of production as it increases. However, afterwards, this pressure drop results in an increase in pressure because of reservoir saturation. Besides, we determined the regression values, R, for the correlation between pressure and total production, as well as for the correlation between permeability and the total production, using neural network discipline.

  2. An Effective Reservoir Parameter for Seismic Characterization of Organic Shale Reservoir

    Science.gov (United States)

    Zhao, Luanxiao; Qin, Xuan; Zhang, Jinqiang; Liu, Xiwu; Han, De-hua; Geng, Jianhua; Xiong, Yineng

    2017-12-01

    Sweet spots identification for unconventional shale reservoirs involves detection of organic-rich zones with abundant porosity. However, commonly used elastic attributes, such as P- and S-impedances, often show poor correlations with porosity and organic matter content separately and thus make the seismic characterization of sweet spots challenging. Based on an extensive analysis of worldwide laboratory database of core measurements, we find that P- and S-impedances exhibit much improved linear correlations with the sum of volume fraction of organic matter and porosity than the single parameter of organic matter volume fraction or porosity. Importantly, from the geological perspective, porosity in conjunction with organic matter content is also directly indicative of the total hydrocarbon content of shale resources plays. Consequently, we propose an effective reservoir parameter (ERP), the sum of volume fraction of organic matter and porosity, to bridge the gap between hydrocarbon accumulation and seismic measurements in organic shale reservoirs. ERP acts as the first-order factor in controlling the elastic properties as well as characterizing the hydrocarbon storage capacity of organic shale reservoirs. We also use rock physics modeling to demonstrate why there exists an improved linear correlation between elastic impedances and ERP. A case study in a shale gas reservoir illustrates that seismic-derived ERP can be effectively used to characterize the total gas content in place, which is also confirmed by the production well.

  3. Development of a X-ray micro-tomograph and its application to reservoir rocks characterization; Developpement d`un microtomographe X et application a la caracterisation des roches reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Ferreira de Paiva, R.

    1995-10-01

    We describe the construction and application to studies in three dimensions of a laboratory micro-tomograph for the characterisation of heterogeneous solids at the scale of a few microns. The system is based on an electron microprobe and a two dimensional X-ray detector. The use of a low beam divergence for image acquisition allows use of simple and rapid reconstruction software whilst retaining reasonable acquisition times. Spatial resolutions of better than 3 microns in radiography and 10 microns in tomography are obtained. The applications of microtomography in the petroleum industry are illustrated by the study of fibre orientation in polymer composites, of the distribution of minerals and pore space in reservoir rocks, and of the interaction of salt water with a model porous medium. A correction for X-ray beam hardening is described and used to obtain improved discrimination of the phases present in the sample. In the case of a North Sea reservoir rock we show the possibility to distinguish quartz, feldspar and in certain zone kaolinite. The representativeness of the tomographic reconstruction is demonstrated by comparing the surface of the reconstructed specimen with corresponding images obtained in scanning electron microscopy. (author). 58 refs., 10 tabs., 71 photos.

  4. Quantifying Fracture Heterogeneity in Different Domains of Folded Carbonate Rocks to Improve Fractured Reservoir Analog Fluid Flow Models

    NARCIS (Netherlands)

    Bisdom, K.; Bertotti, G.; Gauthier, B.D.M.; Hardebol, N.J.

    2013-01-01

    Fluid flow in carbonate reservoirs is largely controlled by multiscale fracture networks. Significant variations of fracture network porosity and permeability are caused by the 3D heterogeneity of the fracture network characteristics, such as intensity, orientation and size. Characterizing fracture

  5. Wind monitoring of the Saylorville and Red Rock Reservoir Bridges with remote, cellular-based notifications : tech transfer summary.

    Science.gov (United States)

    2012-05-01

    Following high winds on January 24, 2006, at least five people claimed to have seen or felt the superstructure of the Saylorville Reservoir Bridge in central Iowa moving both vertically and laterally. Since that time, the Iowa Department of Transport...

  6. Timing of Hydrocarbon Fluid Emplacement in Sandstone Reservoirs in Neogene in Huizhou Sag, Southern China Sea, by Authigenic Illite 40Ar- 39Ar Laser Stepwise Heating

    Science.gov (United States)

    Hesheng, Shi; Junzhang, Zhu; Huaning, Qiu; yu, Shu; Jianyao, Wu; Zulie, Long

    Timing of oil or gas emplacements is a new subject in isotopic geochronology and petroleum geology. Hamilton et al. expounded the principle of the illite K-Ar age: Illite is often the last or one of the latest mineral cements to form prior to hydrocarbon accumulation. Since the displacement of formation water by hydrocarbons will cause silicate diagenesis to cease, K-Ar ages for illite will constrain the timing of this event, and also constrain the maximum age of formation of the trap structure. In this study, the possibility of authigenic illites 40Ar- 39Ar dating has been investigated. The illite samples were separated from the Tertiary sandstones in three rich oil reservoir belts within the Huizhou sag by cleaning, fracturing by cycled cooling-heating, soxhlet-extraction with solvents of benzene and methanol and separating with centrifugal machine. If oil is present in the separated samples, ionized organic fragments with m/e ratios of 36 to 40 covering the argon isotopes will be yielded by the ion source of a mass spectrometer, resulting in wrong argon isotopic analyses and wrong 40Ar- 39Ar ages. The preliminary experiments of illite by heating did show the presence of ionized organic fragments with m/e ratios of 36 to 44. In order to clean up the organic gases completely and obtain reliable analysis results, a special purification apparatus has been established by Qiu et al. and proved valid by the sequent illite analyses. All the illite samples by 40Ar- 39Ar IR-laser stepwise heating yield stair-up age spectra in lower laser steps and plateaux in higher laser steps. The youngest apparent ages corresponding to the beginning steps are reasonable to be interpreted for the hydrocarbon accumulation ages. The weighted mean ages of the illites from the Zhuhai and Zhujiang Formations are (12.1 ± 1.1) Ma and (9.9 ± 1.2) Ma, respectively. Therefore, the critical emplacement of petroleum accumulation in Zhujiang Formation in Huizhou sag took place in ca 10 Ma. Late

  7. Two-phase flow visualization under reservoir conditions for highly heterogeneous conglomerate rock: A core-scale study for geologic carbon storage.

    Science.gov (United States)

    Kim, Kue-Young; Oh, Junho; Han, Weon Shik; Park, Kwon Gyu; Shinn, Young Jae; Park, Eungyu

    2018-03-20

    Geologic storage of carbon dioxide (CO 2 ) is considered a viable strategy for significantly reducing anthropogenic CO 2 emissions into the atmosphere; however, understanding the flow mechanisms in various geological formations is essential for safe storage using this technique. This study presents, for the first time, a two-phase (CO 2 and brine) flow visualization under reservoir conditions (10 MPa, 50 °C) for a highly heterogeneous conglomerate core obtained from a real CO 2 storage site. Rock heterogeneity and the porosity variation characteristics were evaluated using X-ray computed tomography (CT). Multiphase flow tests with an in-situ imaging technology revealed three distinct CO 2 saturation distributions (from homogeneous to non-uniform) dependent on compositional complexity. Dense discontinuity networks within clasts provided well-connected pathways for CO 2 flow, potentially helping to reduce overpressure. Two flow tests, one under capillary-dominated conditions and the other in a transition regime between the capillary and viscous limits, indicated that greater injection rates (potential causes of reservoir overpressure) could be significantly reduced without substantially altering the total stored CO 2 mass. Finally, the capillary storage capacity of the reservoir was calculated. Capacity ranged between 0.5 and 4.5%, depending on the initial CO 2 saturation.

  8. Applying a probabilistic seismic-petrophysical inversion and two different rock-physics models for reservoir characterization in offshore Nile Delta

    Science.gov (United States)

    Aleardi, Mattia

    2018-01-01

    We apply a two-step probabilistic seismic-petrophysical inversion for the characterization of a clastic, gas-saturated, reservoir located in offshore Nile Delta. In particular, we discuss and compare the results obtained when two different rock-physics models (RPMs) are employed in the inversion. The first RPM is an empirical, linear model directly derived from the available well log data by means of an optimization procedure. The second RPM is a theoretical, non-linear model based on the Hertz-Mindlin contact theory. The first step of the inversion procedure is a Bayesian linearized amplitude versus angle (AVA) inversion in which the elastic properties, and the associated uncertainties, are inferred from pre-stack seismic data. The estimated elastic properties constitute the input to the second step that is a probabilistic petrophysical inversion in which we account for the noise contaminating the recorded seismic data and the uncertainties affecting both the derived rock-physics models and the estimated elastic parameters. In particular, a Gaussian mixture a-priori distribution is used to properly take into account the facies-dependent behavior of petrophysical properties, related to the different fluid and rock properties of the different litho-fluid classes. In the synthetic and in the field data tests, the very minor differences between the results obtained by employing the two RPMs, and the good match between the estimated properties and well log information, confirm the applicability of the inversion approach and the suitability of the two different RPMs for reservoir characterization in the investigated area.

  9. ANALYSIS OF OIL-BEARING CRETACEOUS SANDSTONE HYDROCARBON RESERVOIRS, EXCLUSIVE OF THE DAKOTA SANDSTONE, ON THE JICARILLA APACHE INDIAN RESERVATION, NEW MEXICO

    International Nuclear Information System (INIS)

    Jennie Ridgley

    2000-01-01

    A goal of the Mesaverde project was to better define the depositional system of the Mesaverde in hopes that it would provide insight to new or by-passed targets for oil exploration. The new, detailed studies of the Mesaverde give us a better understanding of the lateral variability in depositional environments and facies. Recognition of this lateral variability and establishment of the criteria for separating deltaic, strandplain-barrier, and estuarine deposits from each other permit development of better hydrocarbon exploration models, because the sandstone geometry differs in each depositional system. Although these insights will provide better exploration models for gas exploration, it does not appear that they will be instrumental in finding more oil. Oil in the Mesaverde Group is produced from isolated fields on the Chaco slope; only a few wells define each field. Production is from sandstone beds in the upper part of the Point Lookout Sandstone or from individual fluvial channel sandstones in the Menefee. Stratigraphic traps rather than structural traps are more important. Source of the oil in the Menefee and Point Lookout may be from interbedded organic-rich mudstones or coals rather than from the Lewis Shale. The Lewis Shale appears to contain more type III organic matter and, hence, should produce mainly gas. Outcrop studies have not documented oil staining that might point to past oil migration through the sandstones of the Mesaverde. The lack of oil production may be related to the following: (1) lack of abundant organic matter of the type I or II variety in the Lewis Shale needed to produce oil, (2) ineffective migration pathways due to discontinuities in sandstone reservoir geometries, (3) cementation or early formation of gas prior to oil generation that reduced effective permeabilities and served as barriers to updip migration of oil, or (4) erosion of oilbearing reservoirs from the southern part of the basin. Any new production should mimic that of

  10. Hydrocarbon migration and accumulation in the Upper Cretaceous Qingshankou Formation, Changling Sag, southern Songliao Basin: Insights from integrated analyses of fluid inclusion, oil source correlation and basin modelling

    Science.gov (United States)

    Dong, Tian; He, Sheng; Wang, Dexi; Hou, Yuguang

    2014-08-01

    The Upper Cretaceous Qingshankou Formation acts as both the source and reservoir sequence in the Changling Sag, situated in the southern end of the Songliao Basin, northeast China. An integrated approach involving determination of hydrocarbon charging history, oil source correlation and hydrocarbon generation dynamic modeling was used to investigate hydrocarbon migration processes and further predict the favorable targets of hydrocarbon accumulations in the Qingshankou Formation. The hydrocarbon generation and charge history was investigated using fluid inclusion analysis, in combination with stratigraphic burial and thermal modeling. The source rocks began to generate hydrocarbons at around 82 Ma and the hydrocarbon charge event occurred from approximately 78 Ma to the end of Cretaceous (65.5 Ma) when a large tectonic uplift took place. Correlation of stable carbon isotopes of oils and extracts of source rocks indicates that oil was generated mainly from the first member of Qingshankou Formation (K2qn1), suggesting that hydrocarbon may have migrated vertically. Three dimensional (3D) petroleum system modeling was used to evaluate the processes of secondary hydrocarbon migration in the Qingshankou Formation since the latest Cretaceous. During the Late Cretaceous, hydrocarbon, mainly originated from the Qianan depression, migrated laterally to adjacent structural highs. Subsequent tectonic inversion, defined as the late Yanshan Orogeny, significantly changed hydrocarbon migration patterns, probably causing redistribution of primary hydrocarbon reservoirs. In the Tertiary, the Heidimiao depression was buried much deeper than the Qianan depression and became the main source kitchen. Hydrocarbon migration was primarily controlled by fluid potential and generally migrated from relatively high potential areas to low potential areas. Structural highs and lithologic transitions are potential traps for current oil and gas exploration. Finally, several preferred hydrocarbon

  11. Condensation Mechanism of Hydrocarbon Field Formation.

    Science.gov (United States)

    Batalin, Oleg; Vafina, Nailya

    2017-08-31

    Petroleum geology explains how hydrocarbon fluids are generated, but there is a lack of understanding regarding how oil is expelled from source rocks and migrates to a reservoir. To clarify the process, the multi-layer Urengoy field in Western Siberia was investigated. Based on this example, we have identified an alternative mechanism of hydrocarbon field formation, in which oil and gas accumulations result from the phase separation of an upward hydrocarbon flow. There is evidence that the flow is generated by the gases released by secondary kerogen destruction. This study demonstrates that oil components are carried by the gas flow and that when the flow reaches a low-pressure zone, it condenses into a liquid with real oil properties. The transportation of oil components in the gas flow provides a natural explanation for the unresolved issues of petroleum geology concerning the migration process. The condensation mechanism can be considered as the main process of oil field formation.

  12. Modeling brine-rock interactions in an enhanced geothermal systemdeep fractured reservoir at Soultz-Sous-Forets (France): a joint approachusing two geochemical codes: frachem and toughreact

    Energy Technology Data Exchange (ETDEWEB)

    Andre, Laurent; Spycher, Nicolas; Xu, Tianfu; Vuataz,Francois-D.; Pruess, Karsten.

    2006-12-31

    The modeling of coupled thermal, hydrological, and chemical (THC) processes in geothermal systems is complicated by reservoir conditions such as high temperatures, elevated pressures and sometimes the high salinity of the formation fluid. Coupled THC models have been developed and applied to the study of enhanced geothermal systems (EGS) to forecast the long-term evolution of reservoir properties and to determine how fluid circulation within a fractured reservoir can modify its rock properties. In this study, two simulators, FRACHEM and TOUGHREACT, specifically developed to investigate EGS, were applied to model the same geothermal reservoir and to forecast reservoir evolution using their respective thermodynamic and kinetic input data. First, we report the specifics of each of these two codes regarding the calculation of activity coefficients, equilibrium constants and mineral reaction rates. Comparisons of simulation results are then made for a Soultz-type geothermal fluid (ionic strength {approx}1.8 molal), with a recent (unreleased) version of TOUGHREACT using either an extended Debye-Hueckel or Pitzer model for calculating activity coefficients, and FRACHEM using the Pitzer model as well. Despite somewhat different calculation approaches and methodologies, we observe a reasonably good agreement for most of the investigated factors. Differences in the calculation schemes typically produce less difference in model outputs than differences in input thermodynamic and kinetic data, with model results being particularly sensitive to differences in ion-interaction parameters for activity coefficient models. Differences in input thermodynamic equilibrium constants, activity coefficients, and kinetics data yield differences in calculated pH and in predicted mineral precipitation behavior and reservoir-porosity evolution. When numerically cooling a Soultz-type geothermal fluid from 200 C (initially equilibrated with calcite at pH 4.9) to 20 C and suppressing mineral

  13. Production Characteristics and Reservoir Quality at the Ivanić Oil Field (Croatia) Predicted by Machine Learning System

    OpenAIRE

    Hernitz, Zvonimir; Đureković, Miro; Crnički, Josip

    1996-01-01

    At the Ivanić oil field, hydrocarbons are accumulated in fine tomedium grained litharenits of the Ivanić-Grad Formation (Iva-sandstones member) of Upper Miocene age. Reservoir rocks are dividedinlo eight depositional (production) units (i1- i8). Deposits of eachunit are characterized by their own reservoir quality parameters(porosity, horizontal permeability, net pay ... ). Production characteristicsof 30 wells have been studied by a simple slatistical method. Twomajor production well ca...

  14. Establishing the Relationship between Fracture-Related Dolomite and Primary Rock Fabric on the Distribution of Reservoirs in the Michigan Basin

    Energy Technology Data Exchange (ETDEWEB)

    G. Michael Grammer

    2006-09-30

    This topical report covers the year 2 of the subject 3-year grant, evaluating the relationship between fracture-related dolomite and dolomite constrained by primary rock fabric in the 3 most prolific reservoir intervals in the Michigan Basin (Ordovician Trenton-Black River Formations; Silurian Niagara Group; and the Devonian Dundee Formation). The characterization of select dolomite reservoirs has been the major focus of our efforts in Phase II/Year 2. Fields have been prioritized based upon the availability of rock data for interpretation of depositional environments, fracture density and distribution as well as thin section, geochemical, and petrophysical analyses. Structural mapping and log analysis in the Dundee (Devonian) and Trenton/Black River (Ordovician) suggest a close spatial relationship among gross dolomite distribution and regional-scale, wrench fault related NW-SE and NE-SW structural trends. A high temperature origin for much of the dolomite in the 3 studied intervals (based upon initial fluid inclusion homogenization temperatures and stable isotopic analyses,) coupled with persistent association of this dolomite in reservoirs coincident with wrench fault-related features, is strong evidence for these reservoirs being influenced by hydrothermal dolomitization. For the Niagaran (Silurian), a comprehensive high resolution sequence stratigraphic framework has been developed for a pinnacle reef in the northern reef trend where we had 100% core coverage throughout the reef section. Major findings to date are that facies types, when analyzed at a detailed level, have direct links to reservoir porosity and permeability in these dolomites. This pattern is consistent with our original hypothesis of primary facies control on dolomitization and resulting reservoir quality at some level. The identification of distinct and predictable vertical stacking patterns within a hierarchical sequence and cycle framework provides a high degree of confidence at this point

  15. Physical simulation of gas reservoir formation in the Liwan 3-1 deep-water gas field in the Baiyun sag, Pearl River Mouth Basin

    Directory of Open Access Journals (Sweden)

    Gang Gao

    2015-01-01

    Full Text Available To figure out the process and controlling factors of gas reservoir formation in deep-waters, based on an analysis of geological features, source of natural gas and process of reservoir formation in the Liwan 3-1 gas field, physical simulation experiment of the gas reservoir formation process has been performed, consequently, pattern and features of gas reservoir formation in the Baiyun sag has been found out. The results of the experiment show that: ① the formation of the Liwan 3-1 faulted anticline gas field is closely related to the longstanding active large faults, where natural gas is composed of a high proportion of hydrocarbons, a small amount of non-hydrocarbons, and the wet gas generated during highly mature stage shows obvious vertical migration signs; ② liquid hydrocarbons associated with natural gas there are derived from source rock of the Enping & Zhuhai Formation, whereas natural gas comes mainly from source rock of the Enping Formation, and source rock of the Wenchang Formation made a little contribution during the early Eocene period as well; ③ although there was gas migration and accumulation, yet most of the natural gas mainly scattered and dispersed due to the stronger activity of faults in the early period; later as fault activity gradually weakened, gas started to accumulate into reservoirs in the Baiyun sag; ④ there is stronger vertical migration of oil and gas than lateral migration, and the places where fault links effective source rocks with reservoirs are most likely for gas accumulation; ⑤ effective temporal-spatial coupling of source-fault-reservoir in late stage is the key to gas reservoir formation in the Baiyun sag; ⑥ the nearer the distance from a trap to a large-scale fault and hydrocarbon source kitchen, the more likely gas may accumulate in the trap in late stage, therefore gas accumulation efficiency is much lower for the traps which are far away from large-scale faults and hydrocarbon source

  16. Uranium-thorium series radionuclides in brines and reservoir rocks from two deep geothermal boreholes in the Salton Sea Geothermal Field, southeastern California

    Science.gov (United States)

    Zukin, Jeffrey G.; Hammond, Douglas E.; Teh-Lung, Ku; Elders, Wilfred A.

    1987-10-01

    minutes, indicating the potential for rapid removal of reactive isotopes fom brines. The brine is greatly enriched in 226Ra (2-3 dpm/g, about 10 4-10 5 times that of its parent 230Th), while reservoir rocks are about 10% deficient in 226Ra relative to 230Th. Material balance calculations for 2 226Ra and 18O suggest that brines reside in the reservoir for 10 2-10 3 years, that the SSGF formed 10,000-40,000 years B.P., and that porosity cannot be more than 20%.

  17. Method for inverting reflection trace data from 3-D and 4-D seismic surveys and identifying subsurface fluid and pathways in and among hydrocarbon reservoirs based on impedance models

    Science.gov (United States)

    He, W.; Anderson, R.N.

    1998-08-25

    A method is disclosed for inverting 3-D seismic reflection data obtained from seismic surveys to derive impedance models for a subsurface region, and for inversion of multiple 3-D seismic surveys (i.e., 4-D seismic surveys) of the same subsurface volume, separated in time to allow for dynamic fluid migration, such that small scale structure and regions of fluid and dynamic fluid flow within the subsurface volume being studied can be identified. The method allows for the mapping and quantification of available hydrocarbons within a reservoir and is thus useful for hydrocarbon prospecting and reservoir management. An iterative seismic inversion scheme constrained by actual well log data which uses a time/depth dependent seismic source function is employed to derive impedance models from 3-D and 4-D seismic datasets. The impedance values can be region grown to better isolate the low impedance hydrocarbon bearing regions. Impedance data derived from multiple 3-D seismic surveys of the same volume can be compared to identify regions of dynamic evolution and bypassed pay. Effective Oil Saturation or net oil thickness can also be derived from the impedance data and used for quantitative assessment of prospective drilling targets and reservoir management. 20 figs.

  18. Evaluation of the efficiency of injection of polyacrylamide in different reservoir-rock samples; Avaliacao da eficiencia de injecao de poliacrilamida em diferentes amostras de rocha-reservatorio

    Energy Technology Data Exchange (ETDEWEB)

    Marcelino, Cleuton P.; Valentim, Adriano C.M.; Medeiros, Ana Catarina R. de; Girao, Joaquim H.S.; Barcia, Rosangela B. [Universidade Federal do Rio Grande do Norte (UFRN), Natal, RN (Brazil)

    2004-07-01

    Water soluble polymers have been used extensively in the petroleum recovery, due to their ability in increasing the viscosity of the injection water and to reduce water/oil mobility ratio and the water relative permeability in the reservoir. This reduction acts favorably as a secondary effect, and it reestablishes part of the pressure in the reservoir after the flow of the polymer, causing a correction of the injection profile in the wells through the restructuring of the resident fluids in the porous media. Nevertheless, some parameters influence the improve of this mechanism, such as petrophysics properties, chemical composition of the rock, adsorption, resistance factor and the residual resistance factor. Many paper in the area of polymers applied to the enhanced petroleum recovery indicate a high efficiency in the injection of different partially hydrolysed polyacrylamides, in different concentrations, or even in different injection conditions, as: temperature, flow, among others. In this work it was evaluated the behavior and efficiency of partially hydrolysed polyacrylamide flooding on outcrop cores from Botucatu, Rio Bonito, Clashach and Assu, using core flow tests and computer simulations. (author)

  19. Field demonstration of an active reservoir pressure management through fluid injection and displaced fluid extractions at the Rock Springs Uplift, a priority geologic CO2 storage site for Wyoming

    Energy Technology Data Exchange (ETDEWEB)

    Jiao, Zunsheng [Univ. of Wyoming, Laramie, WY (United States)

    2017-04-05

    This report provides the results from the project entitled Field Demonstration of Reservoir Pressure Management through Fluid Injection and Displaced Fluid Extraction at the Rock Springs Uplift, a Priority Geologic CO2 Storage Site for Wyoming (DE-FE0026159 for both original performance period (September 1, 2015 to August 31, 2016) and no-cost extension (September 1, 2016 to January 6, 2017)).

  20. Experimental investigation of geochemical and mineralogical effects of CO2 sequestration on flow characteristics of reservoir rock in deep saline aquifers

    Science.gov (United States)

    Rathnaweera, T. D.; Ranjith, P. G.; Perera, M. S. A.

    2016-01-01

    Interactions between injected CO2, brine, and rock during CO2 sequestration in deep saline aquifers alter their natural hydro-mechanical properties, affecting the safety, and efficiency of the sequestration process. This study aims to identify such interaction-induced mineralogical changes in aquifers, and in particular their impact on the reservoir rock’s flow characteristics. Sandstone samples were first exposed for 1.5 years to a mixture of brine and super-critical CO2 (scCO2), then tested to determine their altered geochemical and mineralogical properties. Changes caused uniquely by CO2 were identified by comparison with samples exposed over a similar period to either plain brine or brine saturated with N2. The results show that long-term reaction with CO2 causes a significant pH drop in the saline pore fluid, clearly due to carbonic acid (as dissolved CO2) in the brine. Free H+ ions released into the pore fluid alter the mineralogical structure of the rock formation, through the dissolution of minerals such as calcite, siderite, barite, and quartz. Long-term CO2 injection also creates a significant CO2 drying-out effect and crystals of salt (NaCl) precipitate in the system, further changing the pore structure. Such mineralogical alterations significantly affect the saline aquifer’s permeability, with important practical consequences for the sequestration process. PMID:26785912

  1. Study on Relation between Hydrodynamic Feature Size of HPAM and Pore Size of Reservoir Rock in Daqing Oilfield

    Directory of Open Access Journals (Sweden)

    Qing Fang

    2015-01-01

    Full Text Available The flow mechanism of the injected fluid was studied by the constant pressure core displacement experiments in the paper. It is assumed under condition of the constant pressure gradient in deep formation based on the characteristic of pressure gradient distribution between the injection and production wells and the mobility of different polymer systems in deep reservoir. Moreover, the flow rate of steady stream was quantitatively analyzed and the critical flow pressure gradient of different injection parameters polymer solutions in different permeability cores was measured. The result showed that polymer hydrodynamic feature size increases with the increasing molecular weight. If the concentration of polymer solutions overlaps beyond critical concentration, then molecular chains entanglement will be occur and cause the augment of its hydrodynamic feature size. The polymer hydrodynamic feature size decreased as the salinity of the dilution water increased. When the median radius of the core pore and throat was 5–10 times of the polymer system hydrodynamic feature size, the polymer solution had a better compatibility with the microscopic pore structure of the reservoir. The estimation of polymer solutions mobility in the porous media can be used to guide the polymer displacement plan and select the optimum injection parameters.

  2. Geologic framework for the assessment of undiscovered oil and gas resources in sandstone reservoirs of the Upper Jurassic-Lower Cretaceous Cotton Valley Group, U.S. Gulf of Mexico region

    Science.gov (United States)

    Eoff, Jennifer D.; Dubiel, Russell F.; Pearson, Ofori N.; Whidden, Katherine J.

    2015-01-01

    The U.S. Geological Survey (USGS) is assessing the undiscovered oil and gas resources in sandstone reservoirs of the Upper Jurassic–Lower Cretaceous Cotton Valley Group in onshore areas and State waters of the U.S. Gulf of Mexico region. The assessment is based on geologic elements of a total petroleum system. Four assessment units (AUs) are defined based on characterization of hydrocarbon source and reservoir rocks, seals, traps, and the geohistory of the hydrocarbon products. Strata in each AU share similar stratigraphic, structural, and hydrocarbon-charge histories.

  3. 3D seismic modeling in geothermal reservoirs with a distribution of steam patch sizes, permeabilities and saturations, including ductility of the rock frame

    Science.gov (United States)

    Carcione, José M.; Poletto, Flavio; Farina, Biancamaria; Bellezza, Cinzia

    2018-06-01

    Seismic propagation in the upper part of the crust, where geothermal reservoirs are located, shows generally strong velocity dispersion and attenuation due to varying permeability and saturation conditions and is affected by the brittleness and/or ductility of the rocks, including zones of partial melting. From the elastic-plastic aspect, the seismic properties (seismic velocity, quality factor and density) depend on effective pressure and temperature. We describe the related effects with a Burgers mechanical element for the shear modulus of the dry-rock frame. The Arrhenius equation combined to the octahedral stress criterion define the Burgers viscosity responsible of the brittle-ductile behaviour. The effects of permeability, partial saturation, varying porosity and mineral composition on the seismic properties is described by a generalization of the White mesoscopic-loss model to the case of a distribution of heterogeneities of those properties. White model involves the wave-induced fluid flow attenuation mechanism, by which seismic waves propagating through small-scale heterogeneities, induce pressure gradients between regions of dissimilar properties, where part of the energy of the fast P-wave is converted to slow P (Biot)-wave. We consider a range of variations of the radius and size of the patches and thin layers whose probability density function is defined by different distributions. The White models used here are that of spherical patches (for partial saturation) and thin layers (for permeability heterogeneities). The complex bulk modulus of the composite medium is obtained with the Voigt-Reuss-Hill average. Effective pressure effects are taken into account by using exponential functions. We then solve the 3D equation of motion in the space-time domain, by approximating the White complex bulk modulus with that of a set of Zener elements connected in series. The Burgers and generalized Zener models allows us to solve the equations with a direct grid

  4. Lower Cretaceous Source Rock and its Implication for the Gulf of Guinea Petroleum System

    International Nuclear Information System (INIS)

    Frost, B.R.; Griffith, R.C.

    2002-01-01

    Current petroleum system models for the Gulf of Guinea propose Tertiary-age deltaic organic material as the principal source for the hydrocarbons found there. Although previous workers recognized numerous difficulties and inconsistencies, no alternative model has been resented to adequately explain the complete petroleum system. We propose that the principal source rock for the Gulf of Guinea system occurs in upper lower Cretaceous-age shales at the rift-drift transition. Tertiary loading and the consequent maturation of this lower Cretaceous source rock can explain the controls on tap formation, reservoir distribution and hydrocarbon types found in the Gulf of Guinea

  5. Scientific results from the deepened Lopra-1 borehole, Faroe Islands: Hydrocarbon gases in Palaeogene volcanic rocks from the Lopra-1/1A well, Faroe Islands

    Directory of Open Access Journals (Sweden)

    Laier, Troels

    2006-07-01

    Full Text Available Hydrocarbon gases were monitored in the drilling fluid during deepening of the Lopra-1 well from 2178–3565 m, in which thermogenic, methane-rich gases had been found previously. The mud gas concentration, up to 105 ppm of methane, was generally higher in the hyaloclastite sequence, 2470 m – terminal depth (TD, than in the overlying lavas of the lower basalt formation. The highest concentrations of mud gas in the lower basalt formation were associated with the more porous tuffaceous zones, whereas no simple relationship could be established between measured mud gas concentrations and porosity of the hyaloclastic rocks, which showed less marked porosity variations than the lavas.Chemical (C2+ 104 ppm. No particularly gas-rich zones were indicated, however, by the mud gas, nor was any significant change in lithology noted for this interval. It is possible that the technique of turbo-drilling, that had been attempted over a short interval, 2657–2675 m prior to collection of the high-level methane samples, may have caused enhanced degassingdue to the very fine cuttings produced. Chemical and isotopic composition of headspace gas and mud gas indicated the same type of gas throughout the well, although headspace methane tended to bemore enriched with respect to the 13C isotope.The origin of the Lopra-1 gas is discussed in the light of recent information obtained from source rock studies of central East Greenland and the Faroe–Shetland Basin.

  6. A direct method for determining complete positive and negative capillary pressure curves for reservoir rock using the centrifuge

    Energy Technology Data Exchange (ETDEWEB)

    Spinler, E.A.; Baldwin, B.A. [Phillips Petroleum Co., Bartlesville, OK (United States)

    1997-08-01

    A method is being developed for direct experimental determination of capillary pressure curves from saturation distributions produced during centrifuging fluids in a rock plug. A free water level is positioned along the length of the plugs to enable simultaneous determination of both positive and negative capillary pressures. Octadecane as the oil phase is solidified by temperature reduction while centrifuging to prevent fluid redistribution upon removal from the centrifuge. The water saturation is then measured via magnetic resonance imaging. The saturation profile within the plug and the calculation of pressures for each point of the saturation profile allows for a complete capillary pressure curve to be determined from one experiment. Centrifuging under oil with a free water level into a 100 percent water saturated plug results in the development of a primary drainage capillary pressure curve. Centrifuging similarly at an initial water saturation in the plug results in the development of an imbibition capillary pressure curve. Examples of these measurements are presented for Berea sandstone and chalk rocks.

  7. Characterization of a hot dry rock reservoir at Acoculco geothermal zone, Pue.; Caracterizacion de un yacimiento de roca seca caliente en la zona geotermica de Acoculco, Pue.

    Energy Technology Data Exchange (ETDEWEB)

    Lorenzo Pulido, Cecilia; Flores Armenta, Magaly Ramirez Silva, German [Comision Federal de Electricidad, Gerencia de Proyectos Geotermoelectricos, Morelia, Michoacan (Mexico)]. E-mail: cecilia-lorenzo@cfe.gob.mx

    2011-01-15

    Hot dry rock (HDR) geothermal resources, also called enhanced (or engineered) geothermal systems (EGS), have been researched for a long time. The HDR concept is simple. Most of the reservoirs are found at depths of around 5000 m and comprised of impermeable rocks at temperatures between 150 degrees Celsius and 300 degrees Celsius -lacking fluid. Rock temperature is a main economic criterion, since to generate electric energy initial temperatures above 200 degrees Celsius are required. To develop a HDR system, two wells are drilled. Cold water is introduced in one well and hot water is obtained from the other well by passing the water through the hot rock. Since June 2008, a 1.5 MWe power plant has been operating in France, part of the Soultz-sous-Foret project financed by the European Deep Geothermal Energy Programme. To characterize the HDR reservoir multi-disciplinary information was gathered regarding: (1) the heat source origin, (2) qualitative information on temperature and transfer mechanisms of natural heat, (3) natural faults and fractures, (4) local stresses, and (5) the basement rock. The information was applied to a geothermal zone in Acoculco, Pue.. The zone was explored by the Exploration Department with wells EAC-1 and EAC-2, defining the presence of a high temperature reservoir (from 220 degrees Celsius to more than 250 degrees Celsius ). The zone presents the following features: (1) heat source origin: volcano-tectonic, (2) temperature logs show values of 263.8 degrees Celsius and 307.3 degrees Celsius at depths of 1900 m and 2000 m, respectively, (3) the exploration wells are located in a graben-like structure, and the core and cutting samples show evidences of natural faults and fractures partially or completely sealed by hydrothermal minerals such as epidote, quartz and pyrite, (4) stress analyses indicate the local NW-SE and E-W systems are the main systems in the geothermal zone, and (5) the basement rock is composed of limestones with contact

  8. Fracture Analysis of basement rock: A case example of the Eastern Part of the Peninsular Malaysia

    International Nuclear Information System (INIS)

    Shamsuddin, A; Ghosh, D

    2015-01-01

    In general, reservoir rocks can be defined into carbonates, tight elastics and basement rocks. Basement rocks came to be highlighted as their characteristics are quite complicated and remained as a significant challenge in exploration and production area. Motivation of this research is to solve the problem in some area in the Malay Basin which consist fractured basement reservoirs. Thus, in order to increase understanding about their characteristic, a study was conducted in the Eastern part of the Peninsular Malaysia. The study includes the main rock types that resemble the offshore rocks and analysis on the factors that give some effect on fracture characteristic that influence fracture systems and fracture networks. This study will allow better fracture prediction which will be beneficial for future hydrocarbon prediction in this region

  9. Determination of Pore Pressure from Sonic Log: a Case Study on One of Iran Carbonate Reservoir Rocks

    Directory of Open Access Journals (Sweden)

    Morteza Azadpour

    2015-07-01

    Full Text Available Pore pressureis defined as the pressure of the fluid inside the pore space of the formation, which is also known as the formation pressure. When the pore pressure is higher than hydrostatic pressure, it is referred to as overpressure. Knowledge of this pressure is essential for cost-effective drilling, safe well planning, and efficient reservoir modeling. The main objective of this study is to estimate the formation pore pressure as a reliable mud weight pressure using well log data at one of oil fields in the south of Iran. To obtain this goal, the formation pore pressure is estimated from well logging data by applying Eaton’s prediction method with some modifications. In this way, sonic transient time trend line is separated by lithology changes and recalibrated by Weakley’s approach. The created sonic transient time is used to create an overlay pore pressure based on Eaton’s method and is led to pore pressure determination. The results are compared with the pore pressure estimated from commonly used methods such as Eaton’s and Bowers’s methods. The determined pore pressure from Weakley’s approach shows some improvements in comparison with Eaton’s method. However, the results of Bowers’s method, in comparison with the other two methods, show relatively better agreement with the mud weight pressure values.

  10. Wettability Alteration of Sandstone and Carbonate Rocks by Using ZnO Nanoparticles in Heavy Oil Reservoirs

    Directory of Open Access Journals (Sweden)

    Masoumeh Tajmiri

    2015-10-01

    Full Text Available Efforts to enhance oil recovery through wettability alteration by nanoparticles have been attracted in recent years. However, many basic questions have been ambiguous up until now. Nanoparticles penetrate into pore volume of porous media, stick on the core surface, and by creating homogeneous water-wet area, cause to alter wettability. This work introduces the new concept of adding ZnO nanoparticles by an experimental work on wettability alteration and oil recovery through spontaneous imbibition mechanism. Laboratory tests were conducted in two experimental steps on four cylindrical core samples (three sandstones and one carbonate taken from a real Iranian heavy oil reservoir in Amott cell. In the first step, the core samples were saturated by crude oil. Next, the core samples were flooded with nanoparticles and saturated by crude oil for about two weeks. Then, the core samples were immersed in distilled water and the amount of recovery was monitored during 30 days for both steps. The experimental results showed that oil recovery for three sandstone cores changed from 20.74, 4.3, and 3.5% of original oil in place (OOIP in the absence of nanoparticles to 36.2, 17.57, and 20.68% of OOIP when nanoparticles were added respectively. Moreover, for the carbonate core, the recovery changed from zero to 8.89% of OOIP by adding nanoparticles. By the investigation of relative permeability curves, it was found that by adding ZnO nanoparticles, the crossover-point of curves shifted to the right for both sandstone and carbonate cores, which meant wettability was altered to water- wet. This study, for the first time, illustrated the remarkable role of ZnO nanoparticles in wettability alteration toward more water-wet for both sandstone and carbonate cores and enhancing oil recovery.

  11. Investigating Multiphase Flow Phenomena in Fine-Grained Reservoir Rocks: Insights from Using Ethane Permeability Measurements over a Range of Pore Pressures

    Directory of Open Access Journals (Sweden)

    Eric Aidan Letham

    2018-01-01

    Full Text Available The ability to quantify effective permeability at the various fluid saturations and stress states experienced during production from shale oil and shale gas reservoirs is required for efficient exploitation of the resources, but to date experimental challenges prevent measurement of the effective permeability of these materials over a range of fluid saturations. To work towards overcoming these challenges, we measured effective permeability of a suite of gas shales to gaseous ethane over a range of pore pressures up to the saturated vapour pressure. Liquid/semiliquid ethane saturation increases due to adsorption and capillary condensation with increasing pore pressure resulting in decreasing effective permeability to ethane gas. By how much effective permeability to ethane gas decreases with adsorption and capillary condensation depends on the pore size distribution of each sample and the stress state that effective permeability is measured at. Effective permeability decreases more at higher stress states because the pores are smaller at higher stress states. The largest effective permeability drops occur in samples with dominant pore sizes in the mesopore range. These pores are completely blocked due to capillary condensation at pore pressures near the saturated vapour pressure of ethane. Blockage of these pores cuts off the main fluid flow pathways in the rock, thereby drastically decreasing effective permeability to ethane gas.

  12. Isotope shifting capacity of rock

    International Nuclear Information System (INIS)

    Blattner, P.; Department of Scientific and Industrial Research, Lower Hutt

    1980-01-01

    Any oxygen isotope shifted rock volume exactly defines a past throughput of water. An expression is derived that relates the throughput of an open system to the isotope shift of reservoir rock and present-day output. The small isotope shift of Ngawha reservoir rock and the small, high delta oxygen-18 output are best accounted for by a magmatic water source

  13. Hydro-mechanically coupled finite-element analysis of the stability of a fractured-rock slope using the equivalent continuum approach: a case study of planned reservoir banks in Blaubeuren, Germany

    Science.gov (United States)

    Song, Jie; Dong, Mei; Koltuk, Serdar; Hu, Hui; Zhang, Luqing; Azzam, Rafig

    2017-12-01

    Construction works associated with the building of reservoirs in mountain areas can damage the stability of adjacent valley slopes. Seepage processes caused by the filling and drawdown operations of reservoirs also affect the stability of the reservoir banks over time. The presented study investigates the stability of a fractured-rock slope subjected to seepage forces in the lower basin of a planned pumped-storage hydropower (PSH) plant in Blaubeuren, Germany. The investigation uses a hydro-mechanically coupled finite-element analyses. For this purpose, an equivalent continuum model is developed by using a representative elementary volume (REV) approach. To determine the minimum required REV size, a large number of discrete fracture networks are generated using Monte Carlo simulations. These analyses give a REV size of 28 × 28 m, which is sufficient to represent the equivalent hydraulic and mechanical properties of the investigated fractured-rock mass. The hydro-mechanically coupled analyses performed using this REV size show that the reservoir operations in the examined PSH plant have negligible effect on the adjacent valley slope.

  14. Hydro-mechanically coupled finite-element analysis of the stability of a fractured-rock slope using the equivalent continuum approach: a case study of planned reservoir banks in Blaubeuren, Germany

    Science.gov (United States)

    Song, Jie; Dong, Mei; Koltuk, Serdar; Hu, Hui; Zhang, Luqing; Azzam, Rafig

    2018-05-01

    Construction works associated with the building of reservoirs in mountain areas can damage the stability of adjacent valley slopes. Seepage processes caused by the filling and drawdown operations of reservoirs also affect the stability of the reservoir banks over time. The presented study investigates the stability of a fractured-rock slope subjected to seepage forces in the lower basin of a planned pumped-storage hydropower (PSH) plant in Blaubeuren, Germany. The investigation uses a hydro-mechanically coupled finite-element analyses. For this purpose, an equivalent continuum model is developed by using a representative elementary volume (REV) approach. To determine the minimum required REV size, a large number of discrete fracture networks are generated using Monte Carlo simulations. These analyses give a REV size of 28 × 28 m, which is sufficient to represent the equivalent hydraulic and mechanical properties of the investigated fractured-rock mass. The hydro-mechanically coupled analyses performed using this REV size show that the reservoir operations in the examined PSH plant have negligible effect on the adjacent valley slope.

  15. Hydrocarbons in mother rock in France. Initial report and complementary report (further to the law of the 13 July 2011 creating the national commission for orientation, follow-up and assessment of techniques of exploration and exploitation of liquid and gaseous hydrocarbons)

    International Nuclear Information System (INIS)

    Leteurtrois, Jean-Pierre; Durville, Jean-Louis; Pillet, Didier; Gazeau, Jean-Claude; Bellec, Gilles; Catoire, Serge

    2012-02-01

    These reports aimed at studying the opportunities of development of mother-rock hydrocarbons as well as the associated economic opportunities and geopolitical challenges, exploitation techniques (efficiency, capacity of the French industry, impacts, costs, perspectives), their social and environmental challenges (notably with respect to such a development in France), and legal, regulatory and tax framework. These issues are addressed in the first report whereas the complementary report gives an overview of the evolution of the energy context, of hydrocarbon resources and technologies, of the main actors in the world, and of experiments in France

  16. Petroleum systems and hydrocarbon accumulation models in the Santos Basin, SP, Brazil; Sistemas petroliferos e modelos de acumulacao de hidrocarbonetos na Bacia de Santos

    Energy Technology Data Exchange (ETDEWEB)

    Chang, Hung Kiang; Assine, Mario Luis; Correa, Fernando Santos; Tinen, Julio Setsuo [Universidade Estadual Paulista (UNESP), Rio Claro, SP (Brazil). Lab. de Estudos de Bacias]. E-mails: chang@rc.unesp.br; assine@rc.unesp.br; fscorrea@rc.unesp.br; jstinen@rc.unesp.br; Vidal, Alexandre Campane; Koike, Luzia [Universidade Estadual de Campinas (UNICAMP), Campinas, SP (Brazil). Centro de Estudos de Petroleo]. E-mails: vidal@ige.unicamp.br; luzia@iqm.unicamp.br

    2008-07-01

    The Santos Basin was formed by rifting process during Mesozoic Afro-American separation. Sediment accumulation initiated with fluvial-lacustrine deposits, passing to evaporitic stage until reaching marginal basin stages. The analysis of hydrocarbon potential of Santos Basin identified two petroleum systems: Guaratiba-Guaruja and Itajai-Acu-Ilhabela. The Guaratiba Formation is less known in the Santos Basin because of small number of wells that have penetrated the rift section. By comparison with Campos Basin, hydrocarbons are of saline lacustrine origin deposited in Aptian age. Analogous to Campos Basin the major source rock is of saline-lacustrine origin, which has been confirmed from geochemical analyses of oil samples recovered from the various fields. These analyses also identified marine source rock contribution, indicating the Itajai-Acu source rock went through oil-window, particularly in structural lows generated by halokynesis. Models of hydrocarbon accumulation consider Guaratiba Formacao as the major source rock for shallow carbonate reservoirs of Guaruja Formacao and for late Albian to Miocene turbidites, as well as siliciclastic and carbonate reservoirs of the rift phase. Migration occurs along salt window and through carrier-beds. The seal rock is composed of shales and limestones intercalated with reservoir facies of the post-rift section and by thick evaporites overlying rift section, especially in the deeper water. In the shallow portion, shale inter-tongued with reservoir rocks is the main seal rock. The hydrocarbon generation and expulsion in the central-north portion of the basin is caused by overburden of a thick Senonian section. Traps can be structural (rollovers and turtle), stratigraphic (pinch-outs) and mixed origins (pinch-outs of turbidites against salt domes). (author)

  17. Acoustic Impedance Inversion To Identify Oligo-Miocene Carbonate Facies As Reservoir At Kangean Offshore Area

    Science.gov (United States)

    Zuli Purnama, Arif; Ariyani Machmud, Pritta; Eka Nurcahya, Budi; Yusro, Miftahul; Gunawan, Agung; Rahmadi, Dicky

    2018-03-01

    Model based inversion was applied to inversion process of 2D seismic data in Kangean Offshore Area. Integration acoustic impedance from wells and seismic data was expected showing physical property, facies separation and reservoir quality of carbonate rock, particularly in Kangean Offshore Area. Quantitative and qualitative analysis has been conducted on the inversion results to characterize the carbonate reservoir part of Kujung and correlate it to depositional facies type. Main target exploration in Kangean Offshore Area is Kujung Formation (Oligo-Miocene Carbonate). The type of reservoir in this area generate from reef growing on the platform. Carbonate rock is a reservoir which has various type and scale of porosity. Facies determination is required to to predict reservoir quality, because each facies has its own porosity value. Acoustic impedance is used to identify and characterize Kujung carbonate facies, also could be used to predict the distribution of porosity. Low acoustic impedance correlated with packstone facies that has acoustic impedance value below 7400 gr/cc*m/s. In other situation, high acoustic impedance characterized by wackestone facies above 7400 gr/cc*m/s. The interpretation result indicated that Kujung carbonate rock dominated by packstone facies in the upper part of build-up and it has ideal porosity for hydrocarbon reservoir.

  18. A Methodology to Integrate Magnetic Resonance and Acoustic Measurements for Reservoir Characterization

    Energy Technology Data Exchange (ETDEWEB)

    Parra, Jorge O.; Hackert, Chris L.; Collier, Hughbert A.; Bennett, Michael

    2002-01-29

    The objective of this project was to develop an advanced imaging method, including pore scale imaging, to integrate NMR techniques and acoustic measurements to improve predictability of the pay zone in hydrocarbon reservoirs. This is accomplished by extracting the fluid property parameters using NMR laboratory measurements and the elastic parameters of the rock matrix from acoustic measurements to create poroelastic models of different parts of the reservoir. Laboratory measurement techniques and core imaging are being linked with a balanced petrographical analysis of the core and theoretical model.

  19. Diagenetic Evolution and Reservoir Quality of Sandstones in the North Alpine Foreland Basin: A Microscale Approach.

    Science.gov (United States)

    Gross, Doris; Grundtner, Marie-Louise; Misch, David; Riedl, Martin; Sachsenhofer, Reinhard F; Scheucher, Lorenz

    2015-10-01

    Siliciclastic reservoir rocks of the North Alpine Foreland Basin were studied focusing on investigations of pore fillings. Conventional oil and gas production requires certain thresholds of porosity and permeability. These parameters are controlled by the size and shape of grains and diagenetic processes like compaction, dissolution, and precipitation of mineral phases. In an attempt to estimate the impact of these factors, conventional microscopy, high resolution scanning electron microscopy, and wavelength dispersive element mapping were applied. Rock types were established accordingly, considering Poro/Perm data. Reservoir properties in shallow marine Cenomanian sandstones are mainly controlled by the degree of diagenetic calcite precipitation, Turonian rocks are characterized by reduced permeability, even for weakly cemented layers, due to higher matrix content as a result of lower depositional energy. Eocene subarkoses tend to be coarse-grained with minor matrix content as a result of their fluvio-deltaic and coastal deposition. Reservoir quality is therefore controlled by diagenetic clay and minor calcite cementation.Although Eocene rocks are often matrix free, occasionally a clay mineral matrix may be present and influence cementation of pores during early diagenesis. Oligo-/Miocene deep marine rocks exhibit excellent quality in cases when early cement is dissolved and not replaced by secondary calcite, mainly bound to the gas-water contact within hydrocarbon reservoirs.

  20. Methods to evaluate some reservoir characterization by means of the geophysical data in the strata of limestone and marl

    Directory of Open Access Journals (Sweden)

    V. M. Seidov

    2017-12-01

    Full Text Available As we know, the main goal of interpreting the materials of well logging, including the allocation of collectors and assessment of their saturation, are successfully achieved when the process of interpretation has a strong methodological support. This means, that it is justified by the necessary interpretational models and effective instructional techniques are used. They are based on structural and petrophysical models of reservoirs of the section investigated. The problem of studying the marl rocks with the help of the geophysical methods is not worked out properly. Many years of experience of studying limestone and marl rocks has made it possible to justify the optimal method of data interpretation of geophysical research wells in carbonate sections, which was represented by limestone and marl formations. A new method was developed to study marl rocks. It includes the following main studies: detection of reservoirs in the carbonate section according to the materials of geophysical studies of wells; determination of the geophysical parameters of each reservoir; assessment of the quality of well logging curves; introduction of amendments; selection of reference layers; the calculation of the relative double differencing parameters; the involvement of core data; identifying the lithological rock composition; the rationale for structural models of reservoirs; the definition of the block and of the total porosity; determination of argillaceous carbonate rocks; determination of the coefficient of water saturation of formations based on the type of the collector; setting a critical value for effective porosity, etc. This method was applied in the Eocene deposits of the Interfluve of the Kura and Iori, which is a promising object of hydrocarbons in Azerbaijan. The following conclusions have been made: this methodology successfully solves the problem of petrophysical characteristics of marl rocks; bad connection is observed between some of the

  1. Integrating geologic and engineering data into 3-D reservoir models: an example from norman wells field, NWT, Canada

    International Nuclear Information System (INIS)

    Yose, L.A.

    2004-01-01

    A case study of the Norman Wells field will be presented to highlight the work-flow and data integration steps associated with characterization and modeling of a complex hydrocarbon reservoir. Norman Wells is a Devonian-age carbonate bank ('reef') located in the Northwest Territories of Canada, 60 kilometers south of the Arctic Circle. The reservoir reaches a maximum thickness of 130 meters in the reef interior and thins toward the basin due to depositional pinch outs. Norman Wells is an oil reservoir and is currently under a 5-spot water injection scheme for enhanced oil recovery (EOR). EOR strategies require a detailed understanding of how reservoir flow units, flow barriers and flow baffles are distributed to optimize hydrocarbon sweep and recovery and to minimize water handling. Reservoir models are routinely used by industry to characterize the 3-D distribution of reservoir architecture (stratigraphic layers, depositional facies, faults) and rock properties (porosity. permeability). Reservoir models are validated by matching historical performance data (e.g., reservoir pressures, well production or injection rates). Geologic models are adjusted until they produce a history match, and model adjustments are focused on inputs that have the greatest geologic uncertainty. Flow simulation models are then used to optimize field development strategies and to forecast field performance under different development scenarios. (author)

  2. Preliminary Geospatial Analysis of Arctic Ocean Hydrocarbon Resources

    Energy Technology Data Exchange (ETDEWEB)

    Long, Philip E.; Wurstner, Signe K.; Sullivan, E. C.; Schaef, Herbert T.; Bradley, Donald J.

    2008-10-01

    Ice coverage of the Arctic Ocean is predicted to become thinner and to cover less area with time. The combination of more ice-free waters for exploration and navigation, along with increasing demand for hydrocarbons and improvements in technologies for the discovery and exploitation of new hydrocarbon resources have focused attention on the hydrocarbon potential of the Arctic Basin and its margins. The purpose of this document is to 1) summarize results of a review of published hydrocarbon resources in the Arctic, including both conventional oil and gas and methane hydrates and 2) develop a set of digital maps of the hydrocarbon potential of the Arctic Ocean. These maps can be combined with predictions of ice-free areas to enable estimates of the likely regions and sequence of hydrocarbon production development in the Arctic. In this report, conventional oil and gas resources are explicitly linked with potential gas hydrate resources. This has not been attempted previously and is particularly powerful as the likelihood of gas production from marine gas hydrates increases. Available or planned infrastructure, such as pipelines, combined with the geospatial distribution of hydrocarbons is a very strong determinant of the temporal-spatial development of Arctic hydrocarbon resources. Significant unknowns decrease the certainty of predictions for development of hydrocarbon resources. These include: 1) Areas in the Russian Arctic that are poorly mapped, 2) Disputed ownership: primarily the Lomonosov Ridge, 3) Lack of detailed information on gas hydrate distribution, and 4) Technical risk associated with the ability to extract methane gas from gas hydrates. Logistics may control areas of exploration more than hydrocarbon potential. Accessibility, established ownership, and leasing of exploration blocks may trump quality of source rock, reservoir, and size of target. With this in mind, the main areas that are likely to be explored first are the Bering Strait and Chukchi

  3. Quantification of oil recovery efficiency, CO 2 storage potential, and fluid-rock interactions by CWI in heterogeneous sandstone oil reservoirs

    DEFF Research Database (Denmark)

    Seyyedi, Mojtaba; Sohrabi, Mehran; Sisson, Adam

    2017-01-01

    Significant interest exists in improving recovery from oil reservoirs while addressing concerns about increasing CO2 concentrations in the atmosphere. The combination of Enhanced Oil Recovery (EOR) and safe geologic storage of CO2 in oil reservoirs is appealing and can be achieved by carbonated (CO...... for oil recovery and CO2 storage potential on heterogeneous cores. Since not all the oil reservoirs are homogenous, understanding the potential of CWI as an integrated EOR and CO2 storage scenario in heterogeneous oil reservoirs is essential....

  4. Exploration and reservoir characterization; Technology Target Areas; TTA2 - Exploration and reservoir characterisation

    Energy Technology Data Exchange (ETDEWEB)

    2008-07-01

    In future, research within exploration and reservoir characterization will play an even more important role for Norway since resources are decreasing and new challenges like deep sea, harsh environment and last but not least environmental issues have to be considered. There are two major fields which have to be addressed within exploration and reservoir characterization: First, replacement of reserves by new discoveries and ultimate field recoveries in mature basins at the Norwegian Continental shelf, e.g. at the Halten Terrace has to be addressed. A wealth of data exists in the more mature areas. Interdisciplinary integration is a key feature of reservoir characterization, where available data and specialist knowledge need to be combined into a consistent reservoir description. A systematic approach for handling both uncertainties in data sources and uncertainties in basic models is needed. Fast simulation techniques are necessary to generate models spanning the event space, covering both underground based and model-based uncertainties. Second, exploration in frontier areas like the Barents Sea region and the deeper Voering Basin has to be addressed. The scarcity of wells in these frontier areas leads to uncertainties in the geological understanding. Basin- and depositional modelling are essential for predicting where source rocks and reservoir rocks are deposited, and if, when and which hydrocarbons are generated and trapped. Predictive models and improved process understanding is therefore crucial to meet these issues. Especially the challenges related to the salt deposits e.g. sub-salt/sub-basalt reservoir definitions in the Nordkapp Basin demands up-front research and technology developments. TTA2 stresses the need to focus on the development of new talents. We also see a strong need to push cooperation as far as possible in the present competitive environment. Projects that may require a substantial financial commitment have been identified. The following

  5. Asphalt features and gas accumulation mechanism of Sinian reservoirs in the Tongwan Palaeo-uplift, Sichuan Basin

    Directory of Open Access Journals (Sweden)

    Wei Li

    2015-10-01

    Full Text Available Breakthroughs have been made in natural gas exploration in Sinian reservoirs in the Tongwan Palaeo-uplift, Sichuan Basin, recently. However, there are disputes with regard to the genetic mechanisms of natural gas reservoirs. The development law of asphalts in the Sinian reservoirs may play an extremely important role in the study of the relationships between palaeo oil and gas reservoirs. Accordingly, researches were conducted on the features and development patterns of asphalts in the Sinian reservoirs in this area. The following research results were obtained. (1 Asphalts in the Sinian reservoirs were developed after the important hydrothermal event in the Sichuan Basin, namely the well-known Emei Taphrogeny in the mid-late Permian Period. (2 Distribution of asphalts is related to palaeo oil reservoirs under the control of palaeo-structures of Indosinian-Yanshanian Period, when the palaeo-structures contained high content of asphalts in the high positions of the palaeo-uplift. (3 Large-scale oil and gas accumulations in the Sinian reservoirs occurred in the Indosinian-Yanshanian Period to generate the Leshan-Ziyang and Gaoshiti-Moxi-Guang'an palaeo oil reservoirs. Cracking of crude oil in the major parts of these palaeo oil reservoirs controlled the development of the present natural gas reservoirs. (4 The development of asphalts in the Sinian reservoirs indicates that hydrocarbons in the Dengying Formation originated from Cambrian source rocks and natural gas accumulated in the Sinian reservoirs are products of late-stage cracking of the Sinian reservoirs. (5 The Sinian palaeo-structures of Indosinian-Yanshanian Period in the Sichuan Basin are favorable regions for the development of the Sinian reservoirs, where discoveries and exploration practices will play an important role in the era of Sinian natural gas development in China.

  6. An insight into the mechanism and evolution of shale reservoir characteristics with over-high maturity

    Directory of Open Access Journals (Sweden)

    Xinjing Li

    2016-10-01

    Full Text Available Over-high maturity is one of the most vital characteristics of marine organic-rich shale reservoirs from the Lower Paleozoic in the south part of China. The organic matter (OM in shale gas reservoirs almost went through the entire thermal evolution. During this wide span, a great amount of hydrocarbon was available and numerous pores were observed within the OM including kerogen and solid bitumen/pyrobitumen. These nanopores in solid bitumen/pyrobitumen can be identified using SEM. The imaging can be dissected and understood better based on the sequence of diagenesis and hydrocarbon charge with the shape of OM and pores. In terms of the maturity process showed by the various typical cases, the main effects of the relationship between the reservoir porosity and organic carbon abundance are interpreted as follows: the change and mechanism of reservoirs properties due to thermal evolution are explored, such as gas carbon isotope from partial to complete rollover zone, wettability alteration from water-wet to oil-wet and then water-wet pore surface again, electrical resistivity reversal from the increasing to decreasing stage, and nonlinearity fluctuation of rock elasticity anisotropy. These indicate a possible evolution pathway for shale gas reservoirs from the Lower Paleozoic in the southern China, as well as the general transformation processes between different shale reservoirs in thermal stages.

  7. An interpretation of core and wireline logs for the Petrophysical evaluation of Upper Shallow Marine sandstone reservoirs of the Bredasdorp Basin, offshore South Africa

    Science.gov (United States)

    Magoba, Moses; Opuwari, Mimonitu

    2017-04-01

    This paper embodies a study carried out to assess the Petrophysical evaluation of upper shallow marine sandstone reservoir of 10 selected wells in the Bredasdorp basin, offshore, South Africa. The studied wells were selected randomly across the upper shallow marine formation with the purpose of conducting a regional study to assess the difference in reservoir properties across the formation. The data sets used in this study were geophysical wireline logs, Conventional core analysis and geological well completion report. The physical rock properties, for example, lithology, fluid type, and hydrocarbon bearing zone were qualitatively characterized while different parameters such as volume of clay, porosity, permeability, water saturation ,hydrocarbon saturation, storage and flow capacity were quantitatively estimated. The quantitative results were calibrated with the core data. The upper shallow marine reservoirs were penetrated at different depth ranging from shallow depth of about 2442m to 3715m. The average volume of clay, average effective porosity, average water saturation, hydrocarbon saturation and permeability range from 8.6%- 43%, 9%- 16%, 12%- 68% , 32%- 87.8% and 0.093mD -151.8mD respectively. The estimated rock properties indicate a good reservoir quality. Storage and flow capacity results presented a fair to good distribution of hydrocarbon flow.

  8. Advances in carbonate exploration and reservoir analysis

    Science.gov (United States)

    Garland, J.; Neilson, J.; Laubach, S.E.; Whidden, Katherine J.

    2012-01-01

    The development of innovative techniques and concepts, and the emergence of new plays in carbonate rocks are creating a resurgence of oil and gas discoveries worldwide. The maturity of a basin and the application of exploration concepts have a fundamental influence on exploration strategies. Exploration success often occurs in underexplored basins by applying existing established geological concepts. This approach is commonly undertaken when new basins ‘open up’ owing to previous political upheavals. The strategy of using new techniques in a proven mature area is particularly appropriate when dealing with unconventional resources (heavy oil, bitumen, stranded gas), while the application of new play concepts (such as lacustrine carbonates) to new areas (i.e. ultra-deep South Atlantic basins) epitomizes frontier exploration. Many low-matrix-porosity hydrocarbon reservoirs are productive because permeability is controlled by fractures and faults. Understanding basic fracture properties is critical in reducing geological risk and therefore reducing well costs and increasing well recovery. The advent of resource plays in carbonate rocks, and the long-standing recognition of naturally fractured carbonate reservoirs means that new fracture and fault analysis and prediction techniques and concepts are essential.

  9. An innovative technique for estimating water saturation from capillary pressure in clastic reservoirs

    Science.gov (United States)

    Adeoti, Lukumon; Ayolabi, Elijah Adebowale; James, Logan

    2017-11-01

    A major drawback of old resistivity tools is the poor vertical resolution and estimation of hydrocarbon when applying water saturation (Sw) from historical resistivity method. In this study, we have provided an alternative method called saturation height function to estimate hydrocarbon in some clastic reservoirs in the Niger Delta. The saturation height function was derived from pseudo capillary pressure curves generated using modern wells with complete log data. Our method was based on the determination of rock type from log derived porosity-permeability relationship, supported by volume of shale for its classification into different zones. Leverette-J functions were derived for each rock type. Our results show good correlation between Sw from resistivity based method and Sw from pseudo capillary pressure curves in wells with modern log data. The resistivity based model overestimates Sw in some wells while Sw from the pseudo capillary pressure curves validates and predicts more accurate Sw. In addition, the result of Sw from pseudo capillary pressure curves replaces that of resistivity based model in a well where the resistivity equipment failed. The plot of hydrocarbon pore volume (HCPV) from J-function against HCPV from Archie shows that wells with high HCPV have high sand qualities and vice versa. This was further used to predict the geometry of stratigraphic units. The model presented here freshly addresses the gap in the estimation of Sw and is applicable to reservoirs of similar rock type in other frontier basins worldwide.

  10. Source rock

    Directory of Open Access Journals (Sweden)

    Abubakr F. Makky

    2014-03-01

    Full Text Available West Beni Suef Concession is located at the western part of Beni Suef Basin which is a relatively under-explored basin and lies about 150 km south of Cairo. The major goal of this study is to evaluate the source rock by using different techniques as Rock-Eval pyrolysis, Vitrinite reflectance (%Ro, and well log data of some Cretaceous sequences including Abu Roash (E, F and G members, Kharita and Betty formations. The BasinMod 1D program is used in this study to construct the burial history and calculate the levels of thermal maturity of the Fayoum-1X well based on calibration of measured %Ro and Tmax against calculated %Ro model. The calculated Total Organic Carbon (TOC content from well log data compared with the measured TOC from the Rock-Eval pyrolysis in Fayoum-1X well is shown to match against the shale source rock but gives high values against the limestone source rock. For that, a new model is derived from well log data to calculate accurately the TOC content against the limestone source rock in the study area. The organic matter existing in Abu Roash (F member is fair to excellent and capable of generating a significant amount of hydrocarbons (oil prone produced from (mixed type I/II kerogen. The generation potential of kerogen in Abu Roash (E and G members and Betty formations is ranging from poor to fair, and generating hydrocarbons of oil and gas prone (mixed type II/III kerogen. Eventually, kerogen (type III of Kharita Formation has poor to very good generation potential and mainly produces gas. Thermal maturation of the measured %Ro, calculated %Ro model, Tmax and Production index (PI indicates that Abu Roash (F member exciting in the onset of oil generation, whereas Abu Roash (E and G members, Kharita and Betty formations entered the peak of oil generation.

  11. Underground disposal of tanks containing liquid and inflammable hydrocarbons; Mise sous talus ou sous terre des reservoirs contenant des hydrocarbures liquides inflammables

    Energy Technology Data Exchange (ETDEWEB)

    Kukuczka, P.; Giovannini, B.; Caumont, M.; Varin, F

    2001-09-15

    The protection from thermal and mechanical stresses, of hazardous products tanks, by earth covering, is often used since many years in France and in many countries of Europe. In the case of hydrocarbons tanks, only small capacity tanks are covering. The aim of this report is to evaluate the feasibility of this technique for big capacity tanks as refinery tanks. It details the different typologies of tanks containing inflammable liquids and the associated systems, examines if the covering technique presents some special difficulties and precises the specifications needed for the new tanks being covering. (A.L.B.)

  12. Summary of Research through Phase II/Year 2 of Initially Approved 3 Phase/3 Year Project - Establishing the Relationship between Fracture-Related Dolomite and Primary Rock Fabric on the Distribution of Reservoirs in the Michigan Basin

    Energy Technology Data Exchange (ETDEWEB)

    G. Grammer

    2007-09-30

    This final scientific/technical report covers the first 2 years (Phases I and II of an originally planned 3 Year/3 Phase program). The project was focused on evaluating the relationship between fracture-related dolomite and dolomite constrained by primary rock fabric in the 3 most prolific reservoir intervals in the Michigan Basin. The characterization of select dolomite reservoirs was the major focus of our efforts in Phases I and II of the project. Structural mapping and log analysis in the Dundee (Devonian) and Trenton/Black River (Ordovician) suggest a close spatial relationship among gross dolomite distribution and regional-scale, wrench fault-related NW-SE and NE-SW structural trends. A high temperature origin for much of the dolomite in these 2 studied intervals (based upon fluid inclusion homogenization temperatures and stable isotopic analyses,) coupled with persistent association of this dolomite in reservoirs coincident with wrench fault-related features, is strong evidence for these reservoirs being influenced by hydrothermal dolomitization. In the Niagaran (Silurian), there is a general trend of increasing dolomitization shelfward, with limestone predominant in more basinward positions. A major finding is that facies types, when analyzed at a detailed level, are directly related to reservoir porosity and permeability in these dolomites which increases the predictability of reservoir quality in these units. This pattern is consistent with our original hypothesis of primary facies control on dolomitization and resulting reservoir quality at some level. The identification of distinct and predictable vertical stacking patterns within a hierarchical sequence and cycle framework provides a high degree of confidence at this point that the results should be exportable throughout the basin. Much of the data synthesis and modeling for the project was scheduled to be part of Year 3/Phase III, but the discontinuation of funding after Year 2 precluded those efforts

  13. RECENT ADVANCES IN NATURALLY FRACTURED RESERVOIR MODELING

    OpenAIRE

    ORDOÑEZ, A; PEÑUELA, G; IDROBO, E. A; MEDINA, C. E

    2001-01-01

    Large amounts of oil reserves are contained in naturally fractured reservoirs. Most of these hydrocarbon volumes have been left behind because of the poor knowledge and/or description methodology of those reservoirs. This lack of knowledge has lead to the nonexistence of good quantitative models for this complicated type of reservoirs. The complexity of naturally fractured reservoirs causes the need for integration of all existing information at all scales (drilling, well logging, seismic, we...

  14. Consideration of the reservoir by the temperature history at the Hijiori HDR (hot dry rock) wells; Hijiori koon gantai no kokukosei ni okeru ondo rireki wo mochiita choryuso no kosatsu

    Energy Technology Data Exchange (ETDEWEB)

    Takahashi, W; Shinohara, N; Osato, K; Takasugi, S [GERD Geothermal Energy Research and Development Co. Ltd., Tokyo (Japan)

    1997-10-22

    Hot dry rock (HDR) power generation has been promoted by NEDO since 1984 at Hijiori, Okura village, Mogami-gun, Yamagata Prefecture. Hydraulic fracture tests and circulation tests have been conducted using four wells named as SKG-2, HDR-1, HDR-2 and HDR-3. Based on these test results, flow models of Hijiori shallow and deep reservoirs have been proposed. Conventional circulation tests have been analyzed only using temperature profile data. In this paper, circulation tests are analyzed by numerical simulation, to discuss individual characteristics of the shallow and deep reservoirs. Injection flow, production flow and circulation days were inputted as past circulation test data, to discuss the characteristics of geological layers, especially the permeability data, by which the features of temperature profiles in each well can be explained. As a result, it was found that the extension of permeable zone affecting the temperature in the SKG-2 well equivalent to the shallow reservoir was larger than that in the HDR-1 well. It was also found that there was a large difference in the permeability between the HDR-2a and HDR-3 wells. 5 refs., 8 figs., 2 tabs.

  15. Digital Core Modelling for Clastic Oil and Gas Reservoir

    Science.gov (United States)

    Belozerov, I.; Berezovsky, V.; Gubaydullin, M.; Yur’ev, A.

    2018-05-01

    "Digital core" is a multi-purpose tool for solving a variety of tasks in the field of geological exploration and production of hydrocarbons at various stages, designed to improve the accuracy of geological study of subsurface resources, the efficiency of reproduction and use of mineral resources, as well as applying the results obtained in production practice. The actuality of the development of the "Digital core" software is that even a partial replacement of natural laboratory experiments with mathematical modelling can be used in the operative calculation of reserves in exploratory drilling, as well as in the absence of core material from wells. Or impossibility of its research by existing laboratory methods (weakly cemented, loose, etc. rocks). 3D-reconstruction of the core microstructure can be considered as a cheap and least time-consuming method for obtaining petrophysical information about the main filtration-capacitive properties and fluid motion in reservoir rocks.

  16. Micro- and macro-scale petrophysical characterization of potential reservoir units from the Northern Israel

    Science.gov (United States)

    Haruzi, Peleg; Halisch, Matthias; Katsman, Regina; Waldmann, Nicolas

    2016-04-01

    Lower Cretaceous sandstone serves as hydrocarbon reservoir in some places over the world, and potentially in Hatira formation in the Golan Heights, northern Israel. The purpose of the current research is to characterize the petrophysical properties of these sandstone units. The study is carried out by two alternative methods: using conventional macroscopic lab measurements, and using CT-scanning, image processing and subsequent fluid mechanics simulations at a microscale, followed by upscaling to the conventional macroscopic rock parameters (porosity and permeability). Comparison between the upscaled and measured in the lab properties will be conducted. The best way to upscale the microscopic rock characteristics will be analyzed based the models suggested in the literature. Proper characterization of the potential reservoir will provide necessary analytical parameters for the future experimenting and modeling of the macroscopic fluid flow behavior in the Lower Cretaceous sandstone.

  17. Uranium-thorium series radionuclides in brines and reservoir rocks from two deep geothermal boreholes in the Salton Sea geothermal field, southeastern California

    International Nuclear Information System (INIS)

    Zukin, J.G.; Hammond, D.E.; Ku, Tehlung; Elders, W.A.

    1987-01-01

    Naturally occurring U and Th series radionuclides have been analyzed in high temperature brines (∼ 300 degree C, 25 wt% dissolved solids) and associated rocks from two deep geothermal wells located on the northeastern margin of the Salton Sea Geothermal Field (SSGF). These data are part of a study of the SSGF as a natural analog of possible radionuclide behavior near a nuclear waste repository constructed in salt beds, and permit evaluation of some characteristics of water-rock interaction in the SSGF

  18. Characterization of the Qishn sandstone reservoir, Masila Basin-Yemen, using an integrated petrophysical and seismic structural approach

    Science.gov (United States)

    Lashin, Aref; Marta, Ebrahim Bin; Khamis, Mohamed

    2016-03-01

    This study presents an integrated petrophysical and seismic structural analysis that is carried out to evaluate the reservoir properties of Qishn sandstone as well as the entrapment style of the hydrocarbons at Sharyoof field, Sayun-Masila Basin that is located at the east central of Yemen. The reservoir rocks are dominated by clean porous and permeable sandstones zones usually intercalated with some clay stone interbeds. As identified from well logs, Qishn sandstone is classified into subunits (S1A, S1B, S1C and S2) with different reservoir characteristics and hydrocarbon potentiality. A number of qualitative and quantitative well logging analyses are used to characterize the different subunits of the Qishn reservoir and identify its hydrocarbon potentiality. Dia-porosity, M-N, Pickett, Buckles plots, petrophysical analogs and lateral distribution maps are used in the analysis. Shale volume, lithology, porosity, and fluid saturation are among the most important deduced parameters. The analysis revealed that S1A and S1C are the main hydrocarbon-bearing units. More specifically, S1A unit is the best, as it attains the most prolific hydrocarbon saturations (oil saturation "SH″ up to 65) and reservoir characteristics. An average petrophysical ranges of 4-21%, 16-23%, 11-19%, 0-65%, are detected for S1A unit, regarding shale volume, total and effective porosity, and hydrocarbon saturation, respectively. Meanwhile, S1B unit exhibits less reservoir characteristics (Vsh>30%, ϕEff<15% and SH< 15%). The lateral distribution maps revealed that most of the hydrocarbons (for S1A and S1C units) are indicated at the middle of the study area as NE-SW oriented closures. The analysis and interpretation of seismic data had clarified that the structure of study area is represented by a big middle horst bounded by a group of step-like normal faults at the extreme boundaries (faulted anticlinal-structure). In conclusion, the entrapment of the encountered hydrocarbon at Sharyoof oil

  19. Fracture corridors as seal-bypass systems in siliciclastic reservoir-cap rock successions: Field-based insights from the Jurassic Entrada Formation (SE Utah, USA)

    NARCIS (Netherlands)

    Ogata, Kei; Senger, Kim; Braathen, Alvar; Tveranger, Jan

    2014-01-01

    Closely spaced, sub-parallel fracture networks contained within localized tabular zones that are fracture corridors may compromise top seal integrity and form pathways for vertical fluid flow between reservoirs at different stratigraphic levels. This geometry is exemplified by fracture corridors

  20. Geochemical modeling of water-gas-rock interactions. Application to mineral diagenesis in geologic reservoirs; Modelisation geochimique des interactions eau-gaz-roche. Application a la diagenese minerale dans les reservoirs geologiques

    Energy Technology Data Exchange (ETDEWEB)

    Bildstein, O

    1998-03-13

    The Ph.D. report describes a conceptual and numerical model for simulating gas-water-rock interaction during mineral diagenesis of sediments. The main specific features of this model are the following: applicable to open systems, half-implicit resolution numerical method, feedback on the texture evolution (grain model), existence of a gas phase, oxido-reduction phenomena. (author) 217 refs.

  1. Accumulation conditions and enrichment patterns of natural gas in the Lower Cambrian Longwangmiao Fm reservoirs of the Leshan-Longnǚsi Palaeohigh, Sichuan Basin

    Directory of Open Access Journals (Sweden)

    Xu Chunchun

    2014-10-01

    Full Text Available As several major new gas discoveries have been made recently in the Lower Cambrian Longwangmiao Fm reservoirs in the Leshan-Longnǚsi Palaeohigh of the Sichuan Basin, a super-huge gas reservoir group with multiple gas pay zones vertically and cluster reservoirs laterally is unfolding in the east segment of the palaeohigh. Study shows that the large-scale enrichment and accumulation of natural gas benefits from the good reservoir-forming conditions, including: (1 multiple sets of source rocks vertically, among which, the high-quality Lower Paleozoic source rocks are widespread, and have a hydrocarbon kitchen at the structural high of the Palaeohigh, providing favorable conditions for gas accumulation near the source; (2 three sets of good-quality reservoirs, namely, the porous-vuggy dolomite reservoirs of mound-shoal facies in the 2nd and 4th members of the Sinian Dengying Fm as well as the porous dolomite reservoirs of arene-shoal facies in the Lower Cambrian Longwangmiao Fm, are thick and wide in distribution; (3 structural, lithological and compound traps developed in the setting of large nose-like uplift provide favorable space for hydrocarbon accumulation. It is concluded that the inheritance development of the Palaeohigh and its favorable timing configuration with source rock evolution are critical factors for the extensive enrichment of gas in the Lower Cambrian Longwangmiao Fm reservoirs. The structural high of the Palaeohigh is the favorable area for gas accumulation. The inherited structural, stratigraphic and lithological traps are the favorable sites for gas enrichment. The areas where present structures and ancient structures overlap are the sweet-spots of gas accumulation.

  2. ANALYSIS OF OIL-BEARING CRETACEOUS SANDSTONE HYDROCARBON RESERVOIRS, EXCLUSIVE OF THE DAKOTA SANDSTONE, ON THE JICARILLA APACHE INDIAN RESERVATION, NEW MEXICO

    International Nuclear Information System (INIS)

    Jennie Ridgley

    2000-01-01

    An additional 450 wells were added to the structural database; there are now 2550 wells in the database with corrected tops on the Juana Lopez, base of the Bridge Creek Limestone, and datum. This completes the structural data base compilation. Fifteen oil and five gas fields from the Mancos-ElVado interval were evaluated with respect to the newly defined sequence stratigraphic model for this interval. The five gas fields are located away from the structural margins of the deep part of the San Juan Basin. All the fields have characteristics of basin-centered gas and can be considered as continuous gas accumulations as recently defined by the U.S. Geological Survey. Oil production occurs in thinly interbedded sandstone and shale or in discrete sandstone bodies. Production is both from transgressive and regressive strata as redefined in this study. Oil production is both stratigraphically and structurally controlled with production occurring along the Chaco slope or in steeply west-dipping rocks along the east margin of the basin. The ElVado Sandstone of subsurface usage is redefined to encompass a narrower interval; it appears to be more time correlative with the Dalton Sandstone. Thus, it was deposited as part of a regressive sequence, in contrast to the underlying rock units which were deposited during transgression

  3. Elastic Rock Heterogeneity Controls Brittle Rock Failure during Hydraulic Fracturing

    Science.gov (United States)

    Langenbruch, C.; Shapiro, S. A.

    2014-12-01

    For interpretation and inversion of microseismic data it is important to understand, which properties of the reservoir rock control the occurrence probability of brittle rock failure and associated seismicity during hydraulic stimulation. This is especially important, when inverting for key properties like permeability and fracture conductivity. Although it became accepted that seismic events are triggered by fluid flow and the resulting perturbation of the stress field in the reservoir rock, the magnitude of stress perturbations, capable of triggering failure in rocks, can be highly variable. The controlling physical mechanism of this variability is still under discussion. We compare the occurrence of microseismic events at the Cotton Valley gas field to elastic rock heterogeneity, obtained from measurements along the treatment wells. The heterogeneity is characterized by scale invariant fluctuations of elastic properties. We observe that the elastic heterogeneity of the rock formation controls the occurrence of brittle failure. In particular, we find that the density of events is increasing with the Brittleness Index (BI) of the rock, which is defined as a combination of Young's modulus and Poisson's ratio. We evaluate the physical meaning of the BI. By applying geomechanical investigations we characterize the influence of fluctuating elastic properties in rocks on the probability of brittle rock failure. Our analysis is based on the computation of stress fluctuations caused by elastic heterogeneity of rocks. We find that elastic rock heterogeneity causes stress fluctuations of significant magnitude. Moreover, the stress changes necessary to open and reactivate fractures in rocks are strongly related to fluctuations of elastic moduli. Our analysis gives a physical explanation to the observed relation between elastic heterogeneity of the rock formation and the occurrence of brittle failure during hydraulic reservoir stimulations. A crucial factor for understanding

  4. New Insight into the Kinetics of Deep Liquid Hydrocarbon Cracking and Its Significance

    Directory of Open Access Journals (Sweden)

    Wenzhi Zhao

    2017-01-01

    Full Text Available The deep marine natural gas accumulations in China are mainly derived from the cracking of liquid hydrocarbons with different occurrence states. Besides accumulated oil in reservoir, the dispersed liquid hydrocarbon in and outside source also is important source for cracking gas generation or relayed gas generation in deep formations. In this study, nonisothermal gold tube pyrolysis and numerical calculations as well as geochemical analysis were conducted to ascertain the expulsion efficiency of source rocks and the kinetics for oil cracking. By determination of light liquid hydrocarbons and numerical calculations, it is concluded that the residual bitumen or hydrocarbons within source rocks can occupy about 50 wt.% of total oil generated at oil generation peak. This implies that considerable amounts of natural gas can be derived from residual hydrocarbon cracking and contribute significantly to the accumulation of shale gas. Based on pyrolysis experiments and kinetic calculations, we established a model for the cracking of oil and its different components. In addition, a quantitative gas generation model was also established to address the contribution of the cracking of residual oil and expulsed oil for natural gas accumulations in deep formations. These models may provide us with guidance for gas resource evaluation and future gas exploration in deep formations.

  5. Organic geochemistry and petrology of oil source rocks, Carpathian Overthrust region, southeastern Poland - Implications for petroleum generation

    Science.gov (United States)

    Kruge, M.A.; Mastalerz, Maria; Solecki, A.; Stankiewicz, B.A.

    1996-01-01

    The organic mailer rich Oligocene Menilite black shales and mudstones are widely distributed in the Carpathian Overthrust region of southeastern Poland and have excellent hydrocarbon generation potential, according to TOC, Rock-Eval, and petrographic data. Extractable organic matter was characterized by an equable distribution of steranes by carbon number, by varying amounts of 28,30-dinor-hopane, 18??(H)-oleanane and by a distinctive group of C24 ring-A degraded triterpanes. The Menilite samples ranged in maturity from pre-generative to mid-oil window levels, with the most mature in the southeastern portion of the study area. Carpathian petroleum samples from Campanian Oligocene sandstone reservoirs were similar in biomarker composition to the Menilite rock extracts. Similarities in aliphatic and aromatic hydrocarbon distributions between petroleum asphaltene and source rock pyrolyzates provided further evidence genetically linking Menilite kerogens with Carpathian oils.

  6. The role of reservoir characterization in the reservoir management process (as reflected in the Department of Energy`s reservoir management demonstration program)

    Energy Technology Data Exchange (ETDEWEB)

    Fowler, M.L. [BDM-Petroleum Technologies, Bartlesville, OK (United States); Young, M.A.; Madden, M.P. [BDM-Oklahoma, Bartlesville, OK (United States)] [and others

    1997-08-01

    Optimum reservoir recovery and profitability result from guidance of reservoir practices provided by an effective reservoir management plan. Success in developing the best, most appropriate reservoir management plan requires knowledge and consideration of (1) the reservoir system including rocks, and rock-fluid interactions (i.e., a characterization of the reservoir) as well as wellbores and associated equipment and surface facilities; (2) the technologies available to describe, analyze, and exploit the reservoir; and (3) the business environment under which the plan will be developed and implemented. Reservoir characterization is the essential to gain needed knowledge of the reservoir for reservoir management plan building. Reservoir characterization efforts can be appropriately scaled by considering the reservoir management context under which the plan is being built. Reservoir management plans de-optimize with time as technology and the business environment change or as new reservoir information indicates the reservoir characterization models on which the current plan is based are inadequate. BDM-Oklahoma and the Department of Energy have implemented a program of reservoir management demonstrations to encourage operators with limited resources and experience to learn, implement, and disperse sound reservoir management techniques through cooperative research and development projects whose objectives are to develop reservoir management plans. In each of the three projects currently underway, careful attention to reservoir management context assures a reservoir characterization approach that is sufficient, but not in excess of what is necessary, to devise and implement an effective reservoir management plan.

  7. Coupled Nd-142, Nd-143 and Hf-176 Isotopic Data from 3.6-3.9 Ga Rocks: New Constraints on the Timing of Early Terrestrial Chemical Reservoirs

    Science.gov (United States)

    Bennett, Vickie C.; Brandon, alan D.; Hiess, Joe; Nutman, Allen P.

    2007-01-01

    Increasingly precise data from a range of isotopic decay schemes, including now extinct parent isotopes, from samples of the Earth, Mars, Moon and meteorites are rapidly revising our views of early planetary differentiation. Recognising Nd-142 isotopic variations in terrestrial rocks (which can only arise from events occurring during the lifetime of now extinct Sm-146 [t(sub 1/2)=103 myr]) has been an on-going quest starting with Harper and Jacobsen. The significance of Nd-142 variations is that they unequivocally reflect early silicate differentiation processes operating in the first 500 myr of Earth history, the key time period between accretion and the beginning of the rock record. The recent establishment of the existence of Nd-142 variations in ancient Earth materials has opened a new range of questions including, how widespread is the evidence of early differentiation, how do Nd-142 compositions vary with time, rock type and geographic setting, and, combined with other types of isotopic and geochemical data, what can Nd-142 isotopic variations reveal about the timing and mechanisms of early terrestrial differentiation? To explore these questions we are determining high precision Nd-142, Nd-143 and Hf-176 isotopic compositions from the oldest well preserved (3.63- 3.87 Ga), rock suites from the extensive early Archean terranes of southwest Greenland and western Australia.

  8. Petroacoustic Modelling of Heterolithic Sandstone Reservoirs: A Novel Approach to Gassmann Modelling Incorporating Sedimentological Constraints and NMR Porosity data

    Science.gov (United States)

    Matthews, S.; Lovell, M.; Davies, S. J.; Pritchard, T.; Sirju, C.; Abdelkarim, A.

    2012-12-01

    Heterolithic or 'shaly' sandstone reservoirs constitute a significant proportion of hydrocarbon resources. Petroacoustic models (a combination of petrophysics and rock physics) enhance the ability to extract reservoir properties from seismic data, providing a connection between seismic and fine-scale rock properties. By incorporating sedimentological observations these models can be better constrained and improved. Petroacoustic modelling is complicated by the unpredictable effects of clay minerals and clay-sized particles on geophysical properties. Such effects are responsible for erroneous results when models developed for "clean" reservoirs - such as Gassmann's equation (Gassmann, 1951) - are applied to heterolithic sandstone reservoirs. Gassmann's equation is arguably the most popular petroacoustic modelling technique in the hydrocarbon industry and is used to model elastic effects of changing reservoir fluid saturations. Successful implementation of Gassmann's equation requires well-constrained drained rock frame properties, which in heterolithic sandstones are heavily influenced by reservoir sedimentology, particularly clay distribution. The prevalent approach to categorising clay distribution is based on the Thomas - Stieber model (Thomas & Stieber, 1975), this approach is inconsistent with current understanding of 'shaly sand' sedimentology and omits properties such as sorting and grain size. The novel approach presented here demonstrates that characterising reservoir sedimentology constitutes an important modelling phase. As well as incorporating sedimentological constraints, this novel approach also aims to improve drained frame moduli estimates through more careful consideration of Gassmann's model assumptions and limitations. A key assumption of Gassmann's equation is a pore space in total communication with movable fluids. This assumption is often violated by conventional applications in heterolithic sandstone reservoirs where effective porosity, which

  9. Aromatic hydrocarbons

    International Nuclear Information System (INIS)

    Roder, M.

    1985-01-01

    Papers dealing with radiolysis of aromatic hydrocarbons of different composition (from benzene to terphenyls and hydrocarbons with condensed rings) as well as their mixtures (with alkanes, alkenes, other aromatic hydrocarbons) are reviewed. High radiation stability of aromatic hydrocarbons in condensed phases associated with peculiarities of molecular structure of compounds is underlined. Mechanisms of radiolytic processes, vaues of product yields are considered

  10. A reconnaissance view of tungsten reservoirs in some crustal and mantle rocks: Implications for interpreting W isotopic compositions and crust-mantle W cycling

    Science.gov (United States)

    Liu, Jingao; Pearson, D. Graham; Chacko, Thomas; Luo, Yan

    2018-02-01

    High-precision measurements of W isotopic ratios have enabled increased exploration of early Earth processes. However, when applying W isotopic data to understand the geological processes, it is critical to recognize the potential mobility of W and hence evaluate whether measured W contents and isotopic compositions reflect the primary petrogenetic processes or instead are influenced by the effects of secondary inputs/mobility. Furthermore, if we are to better understand how W is partitioned between different minerals during melting and metasomatic processes it is important to document the likely sinks for W during these processes. In addition, an understanding of the main hosts for W in the crust and mantle is critically important to constrain how W is cycled and stored in the crust-mantle geochemical cycle. As a first step to investigate these issues, we have carried out in situ concentration measurements of W and other HFSEs in mineral phases within a broad spectrum of crustal and mantle rocks, along with whole-rock concentration measurements. Mass balance shows that for tonalitic gneiss and amphibolite, the major rock-forming minerals can adequately account for the bulk W budget, and for the pristine ultramafic rocks, olivine and orthopyroxene are the major controlling phases for W whereas for metasomatized ultramafic rocks, significant W is hosted in Ti-bearing trace phases (e.g., rutile, lindsleyite) along grain boundaries or is inferred to reside in cryptic W-bearing trace phases. Formation or decomposition of these phases during secondary processes could cause fractionation of W from other HFSEs, and also dramatically modify bulk W concentrations in rocks. For rocks that experienced subsequent W enrichment/alteration, their W isotopic compositions may not necessarily represent their mantle sources, but could reflect later inputs. The relatively small suite of rocks analyzed here serves as a reconnaissance study but allows some preliminary speculations on

  11. Composite microstructural anisotropies in reservoir rocks: consequences on elastic properties and relation with deformation; Anisotropies microstructurales composites dans les roches reservoir: consequences sur les proprietes elastiques et relation a la deformation

    Energy Technology Data Exchange (ETDEWEB)

    Louis, L.

    2003-10-15

    From diagenesis to tectonic stress induced deformation, rock microstructures always present some anisotropy associated with a preferential orientation, shape or spatial arrangement of its constituents. Considering the consequences anisotropy has on directional transport properties and compliance, as the geological history it carries, this approach has received a particular attention in numerous works. In this work, the microstructural features of various sedimentary rocks were investigated through direct observations and laboratory measurements in naturally deformed and undeformed blocks, samples being considered as effective media. All investigated samples were found to be anisotropic with respect to the physical properties we measured (i.e. ultrasonic P-wave velocity, magnetic susceptibility, electrical conductivity). Considering that P-wave velocities can be described by a second order tensor, we applied to the velocity data the same inversion procedure as the one routinely used in magnetic studies, which provided an efficient tool to estimate and compare these 3D anisotropies with respect to the original sample geographical position. In each case, we tried to identify as thoroughly as possible the microstructural source of the observed anisotropies, first by the mean of existing models, then through direct observations (optic and electronic microscopy). Depending on the rock investigated, anisotropy was found to be controlled by pore shape, intergranular contact distribution, preferentially oriented microcracks interacting with compaction pattern or pressure solution cleavages interacting with each other. The net result of this work is that P-wave velocity anisotropy can express the interaction between different microstructural features as well as their evolution during deformation. (author)

  12. Geomechanical production optimization in faulted and fractured reservoirs

    NARCIS (Netherlands)

    Heege, J.H. ter; Pizzocolo, F.; Osinga, S.; Veer, E.F. van der

    2016-01-01

    Faults and fractures in hydrocarbon reservoirs are key to some major production issues including (1) varying productivity of different well sections due to intersection of preferential flow paths with the wellbore, (2) varying hydrocarbon column heights in different reservoir compartments due to

  13. Reservoir resistivity characterization incorporating flow dynamics

    KAUST Repository

    Arango, Santiago; Sun, Shuyu; Hoteit, Ibrahim; Katterbauer, Klemens

    2016-01-01

    Systems and methods for reservoir resistivity characterization are provided, in various aspects, an integrated framework for the estimation of Archie's parameters for a strongly heterogeneous reservoir utilizing the dynamics of the reservoir are provided. The framework can encompass a Bayesian estimation/inversion method for estimating the reservoir parameters, integrating production and time lapse formation conductivity data to achieve a better understanding of the subsurface rock conductivity properties and hence improve water saturation imaging.

  14. Reservoir resistivity characterization incorporating flow dynamics

    KAUST Repository

    Arango, Santiago

    2016-04-07

    Systems and methods for reservoir resistivity characterization are provided, in various aspects, an integrated framework for the estimation of Archie\\'s parameters for a strongly heterogeneous reservoir utilizing the dynamics of the reservoir are provided. The framework can encompass a Bayesian estimation/inversion method for estimating the reservoir parameters, integrating production and time lapse formation conductivity data to achieve a better understanding of the subsurface rock conductivity properties and hence improve water saturation imaging.

  15. Reservoir quality of intrabasalt volcaniclastic units onshore Faroe Islands, North Atlantic Igneous Province, northeast Atlantic

    DEFF Research Database (Denmark)

    Ólavsdóttir, Jana; Andersen, Morten Sparre; Boldreel, Lars Ole

    2015-01-01

    The Paleocene and Eocene strata in the western part of the FaroeShetland Basin contain abundant volcanic and volcaniclastic rocks. Recently, hydrocarbon discoveries have been made in reservoirs of siliciclastic origin in intra- and post-volcanic strata in the central Faroe-Shetland Basin that show....... Onshore samples are used as Faroese offshore volcaniclastic intervals are represented by a few confidential samples where the stratigraphic level is uncertain. The onshore samples have been taken from 29 geotechnical (made related to tunnel building, etc.) and 2 scientific (made related to research of the geology...

  16. A numerical study of stress/strain response to oil development in reservoir rocks-a case study in Xingshugang area of Daqing Anticline

    International Nuclear Information System (INIS)

    Li Zian; Ma Teng; Yi Jin; Zhu Jiangjian; Lin Ge; Zhang Lu; Zhu Yan; Sun Yaliang; Zhu Jun

    2010-01-01

    Formation pressure and the underground stress field will be disturbed by high pressure injection and production activities during oilfield development. Such disturbance will induce the deformation of formation rock, sometimes causing formation to slip. As a result, production wells and/or injection wells will encounter sanding, casing deformation, or even casing shear problems. This article introduced a simulation study on formation pressure and the underground stress field variation during injection and production activities in the Xingshugang area of the Daqing Anticline, Songliao Basin, China. The relationships of injection pressure to formation pressure, underground stress field variation, and strain variation were investigated in this paper.

  17. Visualisation des propriétés capillaires des roches réservoir Visualizing the Capillary Properties of Reservoir Rocks

    Directory of Open Access Journals (Sweden)

    Zinszner B.

    2006-11-01

    Full Text Available Cet article décrit des expériences de drainage par centrifugation et d'imbibition par ascension capillaire réalisées avec des résines époxy colorées. Après polymérisation, l'observation des lames minces permet de localiser les fluides mouillants et non mouillants. Après avoir décrit les modes opératoires en insistant sur l'analyse des paramètres expérimentaux, on donne des exemples d'applications à la géologie de réservoir. Deux points sont développés : les études de perméabilités et les modèles de réservoir qui permettent d'étudier la répartition du fluide mouillant et des fractions déplaçables ou piégées du fluide non mouillant. This article describes drainage experiments by centrifuge method and imbibition by capillary rise performed with colored epoxy resins. After polymerization, analysis of thin sections serves to situate the wetting and nonwetting fluids. After describing the operating methods with em-phasis on the analysis of experimental parameters, the article gives examples of applications to reservoir geology. The following two points are developed : (i permeability investigations and (ii reservoir modelswhich can be used to analyze the distribution of the wetting fluid and the movable or trapped fractions of the nonwetting fluid

  18. Hydrogeochemical modelling of fluid–rock interactions triggered by seawater injection into oil reservoirs: Case study Miller field (UK North Sea)

    International Nuclear Information System (INIS)

    Fu, Yunjiao; Berk, Wolfgang van; Schulz, Hans-Martin

    2012-01-01

    A hydrogeochemical model is presented and applied to quantitatively elucidate interdependent reactions among minerals and formation water–seawater mixtures at elevated levels of CO 2 partial pressure. These hydrogeochemical reactions (including scale formation) occur within reservoir aquifers and wells and are driven by seawater injection. The model relies on chemical equilibrium thermodynamics and reproduces the compositional development of the produced water (formation water–seawater mixtures) of the Miller field, UK North Sea. This composition of the produced water deviates from its calculated composition, which could result solely from mixing of both the end members (formation water and seawater). This indicates the effect of hydrogeochemical reactions leading to the formation and/or the dissolution of mineral phases. A fairly good match between the modelled and measured chemical composition of produced water indicates that hydrogeochemical interactions achieve near-equilibrium conditions within the residence time of formation water–seawater mixtures at reservoir conditions. Hence the model enables identification of minerals (including scale minerals), to quantitatively reproduce and to predict their dissolution and/or formation. The modelling results indicate that admixing of seawater into formation water triggers the precipitation of Sr–Barite solid solution, CaSO 4 phases and dolomite. In contrast, calcite and microcrystalline quartz are dissolved along the seawater flow path from the injection well towards the production well. Depending on the fraction of seawater admixed, interdependent reactions induce profound modifications to the aquifer mineral phase assemblage. At low levels of seawater admixture, Ba–Sr sulfate solid solution is precipitated and coupled to concurrent dissolution of calcite and microcrystalline quartz. Massive dissolution of calcite and the formation of CaSO 4 phases and dolomite are triggered by intense seawater admixture

  19. APPLICATION OF INTEGRATED RESERVOIR MANAGEMENT AND RESERVOIR CHARACTERIZATION

    Energy Technology Data Exchange (ETDEWEB)

    Jack Bergeron; Tom Blasingame; Louis Doublet; Mohan Kelkar; George Freeman; Jeff Callard; David Moore; David Davies; Richard Vessell; Brian Pregger; Bill Dixon; Bryce Bezant

    2000-03-01

    Reservoir performance and characterization are vital parameters during the development phase of a project. Infill drilling of wells on a uniform spacing, without regard to characterization does not optimize development because it fails to account for the complex nature of reservoir heterogeneities present in many low permeability reservoirs, especially carbonate reservoirs. These reservoirs are typically characterized by: (1) large, discontinuous pay intervals; (2) vertical and lateral changes in reservoir properties; (3) low reservoir energy; (4) high residual oil saturation; and (5) low recovery efficiency. The operational problems they encounter in these types of reservoirs include: (1) poor or inadequate completions and stimulations; (2) early water breakthrough; (3) poor reservoir sweep efficiency in contacting oil throughout the reservoir as well as in the nearby well regions; (4) channeling of injected fluids due to preferential fracturing caused by excessive injection rates; and (5) limited data availability and poor data quality. Infill drilling operations only need target areas of the reservoir which will be economically successful. If the most productive areas of a reservoir can be accurately identified by combining the results of geological, petrophysical, reservoir performance, and pressure transient analyses, then this ''integrated'' approach can be used to optimize reservoir performance during secondary and tertiary recovery operations without resorting to ''blanket'' infill drilling methods. New and emerging technologies such as geostatistical modeling, rock typing, and rigorous decline type curve analysis can be used to quantify reservoir quality and the degree of interwell communication. These results can then be used to develop a 3-D simulation model for prediction of infill locations. The application of reservoir surveillance techniques to identify additional reservoir ''pay'' zones

  20. INTEGRATED OUTCROP AND SUBSURFACE STUDIES OF THE INTERWELL ENVIRONMENT OF CARBONATE RESERVOIRS: CLEAR FORK (LEONARDIAN-AGE) RESERVOIRS, WEST TEXAS AND NEW MEXICO

    Energy Technology Data Exchange (ETDEWEB)

    F. Jerry Lucia

    2002-01-31

    This is the final report of the project ''Integrated Outcrop and Subsurface Studies of the Interwell Environment of Carbonate Reservoirs: Clear Fork (Leonardian-Age) Reservoirs, West Texas and New Mexico'', Department of Energy contract no. DE-AC26-98BC15105 and is the third in a series of similar projects funded jointly by the U.S. Department of Energy and The University of Texas at Austin, Bureau of Economic Geology, Reservoir Characterization Research Laboratory for Carbonates. All three projects focus on the integration of outcrop and subsurface data for the purpose of developing improved methods for modeling petrophysical properties in the interwell environment. The first project, funded by contract no. DE-AC22-89BC14470, was a study of San Andres outcrops in the Algerita Escarpment, Guadalupe Mountains, Texas and New Mexico, and the Seminole San Andres reservoir, Permian Basin. This study established the basic concepts for constructing a reservoir model using sequence-stratigraphic principles and rock-fabric, petrophysical relationships. The second project, funded by contract no. DE-AC22-93BC14895, was a study of Grayburg outcrops in the Brokeoff Mountains, New Mexico, and the South Cowden Grayburg reservoir, Permian Basin. This study developed a sequence-stratigraphic succession for the Grayburg and improved methods for locating remaining hydrocarbons in carbonate ramp reservoirs. The current study is of the Clear Fork Group in Apache Canyon, Sierra Diablo Mountains, West Texas, and the South Wasson Clear Fork reservoir, Permian Basin. The focus was on scales of heterogeneity, imaging high- and low-permeability layers, and the impact of fractures on reservoir performance. In this study (1) the Clear Fork cycle stratigraphy is defined, (2) important scales of petrophysical variability are confirmed, (3) a unique rock-fabric, petrophysical relationship is defined, (4) a porosity method for correlating high-frequency cycles and defining rock

  1. Extraction of hydrocarbons from high-maturity Marcellus Shale using supercritical carbon dioxide

    Science.gov (United States)

    Jarboe, Palma B.; Philip A. Candela,; Wenlu Zhu,; Alan J. Kaufman,

    2015-01-01

    Shale is now commonly exploited as a hydrocarbon resource. Due to the high degree of geochemical and petrophysical heterogeneity both between shale reservoirs and within a single reservoir, there is a growing need to find more efficient methods of extracting petroleum compounds (crude oil, natural gas, bitumen) from potential source rocks. In this study, supercritical carbon dioxide (CO2) was used to extract n-aliphatic hydrocarbons from ground samples of Marcellus shale. Samples were collected from vertically drilled wells in central and western Pennsylvania, USA, with total organic carbon (TOC) content ranging from 1.5 to 6.2 wt %. Extraction temperature and pressure conditions (80 °C and 21.7 MPa, respectively) were chosen to represent approximate in situ reservoir conditions at sample depth (1920−2280 m). Hydrocarbon yield was evaluated as a function of sample matrix particle size (sieve size) over the following size ranges: 1000−500 μm, 250−125 μm, and 63−25 μm. Several methods of shale characterization including Rock-Eval II pyrolysis, organic petrography, Brunauer−Emmett−Teller surface area, and X-ray diffraction analyses were also performed to better understand potential controls on extraction yields. Despite high sample thermal maturity, results show that supercritical CO2 can liberate diesel-range (n-C11 through n-C21) n-aliphatic hydrocarbons. The total quantity of extracted, resolvable n-aliphatic hydrocarbons ranges from approximately 0.3 to 12 mg of hydrocarbon per gram of TOC. Sieve size does have an effect on extraction yield, with highest recovery from the 250−125 μm size fraction. However, the significance of this effect is limited, likely due to the low size ranges of the extracted shale particles. Additional trends in hydrocarbon yield are observed among all samples, regardless of sieve size: 1) yield increases as a function of specific surface area (r2 = 0.78); and 2) both yield and surface area increase with increasing

  2. Reservoir management

    International Nuclear Information System (INIS)

    Satter, A.; Varnon, J.E.; Hoang, M.T.

    1992-01-01

    A reservoir's life begins with exploration leading to discovery followed by delineation of the reservoir, development of the field, production by primary, secondary and tertiary means, and finally to abandonment. Sound reservoir management is the key to maximizing economic operation of the reservoir throughout its entire life. Technological advances and rapidly increasing computer power are providing tools to better manage reservoirs and are increasing the gap between good and neural reservoir management. The modern reservoir management process involves goal setting, planning, implementing, monitoring, evaluating, and revising plans. Setting a reservoir management strategy requires knowledge of the reservoir, availability of technology, and knowledge of the business, political, and environmental climate. Formulating a comprehensive management plan involves depletion and development strategies, data acquisition and analyses, geological and numerical model studies, production and reserves forecasts, facilities requirements, economic optimization, and management approval. This paper provides management, engineers, geologists, geophysicists, and field operations staff with a better understanding of the practical approach to reservoir management using a multidisciplinary, integrated team approach

  3. Reservoir management

    International Nuclear Information System (INIS)

    Satter, A.; Varnon, J.E.; Hoang, M.T.

    1992-01-01

    A reservoir's life begins with exploration leading to discovery followed by delineation of the reservoir, development of the field, production by primary, secondary and tertiary means, and finally to abandonment. Sound reservoir management is the key to maximizing economic operation of the reservoir throughout its entire life. Technological advances and rapidly increasing computer power are providing tools to better manage reservoirs and are increasing the gap between good and neutral reservoir management. The modern reservoir management process involves goal setting, planning, implementing, monitoring, evaluating, and revising plans. Setting a reservoir management strategy requires knowledge of the reservoir, availability of technology, and knowledge of the business, political, and environmental climate. Formulating a comprehensive management plan involves depletion and development strategies, data acquisition and analyses, geological and numerical model studies, production and reserves forecasts, facilities requirements, economic optimization, and management approval. This paper provides management, engineers geologists, geophysicists, and field operations staff with a better understanding of the practical approach to reservoir management using a multidisciplinary, integrated team approach

  4. Hydrocarbon assessment summary report of Buffalo Lake area of interest

    Energy Technology Data Exchange (ETDEWEB)

    Lemieux, Y. [Northwest Territories Geoscience Office, Yellowknife, NT (Canada)

    2007-07-01

    The Northwest Territories (NWT) Protected Areas Strategy (PAS) is a process to identify the known cultural, ecological and economic values of areas in the NWT. This report presented a hydrocarbon resource potential assessment of Buffalo Lake area of interest located in the Great Slave Plain region. It covers an area greater than 2100 square km. The region is almost entirely covered by a thick mantle of glacial deposits. It is underlain by a southwest-dipping, relatively undisturbed succession dominated by Paleozoic carbonate rocks and Cretaceous clastic rocks. Six exploration wells have been drilled within, or near the outer limit of Buffalo Lake area of interest. Suitable source and reservoir rocks are present within Buffalo Lake area of interest, but the potential of significant petroleum discoveries is likely very low. Most of the prospective intervals are either shallow or exposed at surface. Other exploration risks, such as discontinuous distribution and isolation from source rocks, are also anticipated for some of the plays. 17 refs., 2 tabs., 6 figs.

  5. Estimating fault stability and sustainable fluid pressures for underground storage of CO2 in porous rock

    International Nuclear Information System (INIS)

    Streit, J.E.; Hillis, R.R.

    2004-01-01

    Geomechanical modelling of fault stability is an integral part of Australia's GEODISC research program to ensure the safe storage of carbon dioxide in subsurface reservoirs. Storage of CO 2 in deep saline formations or depleted hydrocarbon reservoirs requires estimates of sustainable fluid pressures that will not induce fracturing or create fault permeability that could lead to CO 2 escape. Analyses of fault stability require the determination of fault orientations, ambient pore fluid pressures and in situ stresses in a potential storage site. The calculation of effective stresses that act on faults and reservoir rocks lead then to estimates of fault slip tendency and fluid pressures sustainable during CO 2 storage. These parameters can be visualized on 3D images of fault surfaces or in 2D projections. Faults that are unfavourably oriented for reactivation can be identified from failure plots. In depleted oil and gas fields, modelling of fault and rock stability needs to incorporate changes of the pre-production stresses that were induced by hydrocarbon production and associated pore pressure depletion. Such induced stress changes influence the maximum sustainable formation pressures and CO 2 storage volumes. Hence, determination of in situ stresses and modelling of fault stability are essential prerequisites for the safe engineering of subsurface CO 2 injection and the modelling of storage capacity. (author)

  6. Engineering and Design: Characterization and Measurement of Discontinuities in Rock Slopes

    National Research Council Canada - National Science Library

    1983-01-01

    This ETL provides guidance for characterizing and measuring rock discontinuities on natural slopes or slopes constructed in rock above reservoirs, darn abutments, or other types of constructed slopes...

  7. Computerized X-ray Microtomography Observations and Fluid Flow Measurements of the Effect of Effective Stress on Fractured Reservoir Seal Shale

    Science.gov (United States)

    Welch, N.; Crawshaw, J.; Boek, E.

    2014-12-01

    The successful storage of carbon dioxide in geologic formations requires an in-depth understanding of all reservoir characteristics and morphologies. An intact and substantial seal formation above a storage reservoir is required for a significant portion of the initial sealing mechanisms believed to occur during carbon dioxide storage operations. Shales are a common seal formation rock types found above numerous hydrocarbon reservoirs, as well as potential saline aquifer storage locations. Shales commonly have very low permeability, however they also have the tendency to be quite fissile, and the formation of fractures within these seals can have a significant detrimental effect on the sealing potential of a reservoir and amount to large areas of high permeability and low capillary pressures compared to the surrounding intact rock. Fractured shales also have an increased current interest due to the increasing development of shale gas reservoirs using hydraulic fracturing techniques. This work shows the observed changes that occur within fractured pieces of reservoir seal shale samples, along with quarry analogues, using an in-situ micro-CT fluid flow imaging apparatus with a Hassler type core holder. Changes within the preferential flow path under different stress regimes as well as physical changes to the fracture geometry are reported. Lattice Boltzmann flow simulations were then performed on the extracted flow paths and compared to experiment permeability measurements. The preferential flow path of carbon dioxide through the fracture network is also observed and compared to the results two-phase Lattice Boltzmann fluid flow simulations.

  8. Reservoir engineering and hydrogeology

    International Nuclear Information System (INIS)

    Anon.

    1983-01-01

    Summaries are included which show advances in the following areas: fractured porous media, flow in single fractures or networks of fractures, hydrothermal flow, hydromechanical effects, hydrochemical processes, unsaturated-saturated systems, and multiphase multicomponent flows. The main thrust of these efforts is to understand the movement of mass and energy through rocks. This has involved treating fracture rock masses in which the flow phenomena within both the fractures and the matrix must be investigated. Studies also address the complex coupling between aspects of thermal, hydraulic, and mechanical processes associated with a nuclear waste repository in a fractured rock medium. In all these projects, both numerical modeling and simulation, as well as field studies, were employed. In the theoretical area, a basic understanding of multiphase flow, nonisothermal unsaturated behavior, and new numerical methods have been developed. The field work has involved reservoir testing, data analysis, and case histories at a number of geothermal projects

  9. Tectonic control in source rock maturation and oil migration in Trinidad

    Energy Technology Data Exchange (ETDEWEB)

    Persad, K.M.; Talukdar, S.C.; Dow, W.G. (DGSI, The Woodlands, TX (United States))

    1993-02-01

    Oil accumulation in Trinidad were sourced by the Upper Cretaceous calcareous shales deposited along the Cretaceous passive margin of northern South America. Maturation of these source rocks, oil generation, migration and re-migration occurred in a foreland basin setting that resulted from interaction between Caribbean and South American plates during Late Oligocene to recent times. During Middle Miocene-Recent times, the foreland basin experienced strong compressional events, which controlled generation, migration, and accumulation of oil in Trinidad. A series of mature source rock kitchens formed in Late Miocene-Recent times in the Southern and Colombus Basins to the east-southeast of the Central Range Thrust. This thrust and associated fratured developed around 12 m.y.b.p. and served as vertical migration paths for the oil generated in Late Miocene time. This oil migrated into submarine fans deposited in the foreland basin axis and older reservoirs deformed into structural traps. Further generation and migration of oil, and re-migration of earlier oil took place during Pliocene-Holocene times, when later thrusting and wrench faulting served as vertical migration paths. Extremely high sedimentation rates in Pliocene-Pleistocene time, concurrent with active faulting, was responsible for very rapid generation of oil and gas. Vertically migrating gas often mixed with earlier migrated oil in overlying reservoirs. This caused depletion of oil in light hydrocarbons with accompanied fractionation among hydrocarbon types resulting in heavier oil in lower reservoirs, enrichment of light hydrocarbons and accumulation of gas-condensates in upper reservoirs. This process led to an oil-gravity stratification within about 10,000 ft of section.

  10. Chalk as a reservoir

    DEFF Research Database (Denmark)

    Fabricius, Ida Lykke

    , and the best reservoir properties are typically found in mudstone intervals. Chalk mudstones vary a lot though. The best mudstones are purely calcitic, well sorted and may have been redeposited by traction currents. Other mudstones are rich in very fine grained silica, which takes up pore space and thus...... basin, so stylolite formation in the chalk is controlled by effective burial stress. The stylolites are zones of calcite dissolution and probably are the source of calcite for porefilling cementation which is typical in water zone chalk and also affect the reservoirs to different extent. The relatively...... have hardly any stylolites and can have porosity above 40% or even 50% and thus also have relatively high permeability. Such intervals have the problem though, that increasing effective stress caused by hydrocarbon production results in mechanical compaction and overall subsidence. Most other chalk...

  11. Identification of igneous rocks in a superimposed basin through integrated interpretation dominantly based on magnetic data

    Science.gov (United States)

    LI, S.

    2017-12-01

    Identification of igneous rocks in the basin environment is of great significance to the exploration for hydrocarbon reservoirs hosted in igneous rocks. Magnetic methods are often used to alleviate the difficulties faced by seismic imaging in basins with thick cover and complicated superimposed structures. We present a case study on identification of igneous rocks in a superimposed basin through integrated interpretation based on magnetic and other geophysical data sets. The study area is located in the deepest depression with sedimentary cover of 14,000 m in Huanghua basin, which is a Cenozoic basin superimposed on a residual pre-Cenozoic basin above the North China craton. Cenozoic and Mesozoic igneous rocks that are dominantly intermediate-basic volcanic and intrusive rocks are widespread at depth in the basin. Drilling and seismic data reveal some volcanic units and intrusive rocks in Cenozoic stratum at depths of about 4,000 m. The question remains to identify the lateral extent of igneous rocks in large depth and adjacent areas. In order to tackle the difficulties for interpretation of magnetic data arisen from weak magnetic anomaly and remanent magnetization of igneous rocks buried deep in the superimposed basin, we use the preferential continuation approach to extract the anomaly and magnetic amplitude inversion to image the 3D magnetic units. The resultant distribution of effective susceptibility not only correlates well with the locations of Cenozoic igneous rocks known previously through drilling and seismic imaging, but also identifies the larger scale distribution of Mesozoic igneous rocks at greater depth in the west of the basin. The integrated interpretation results dominantly based on magnetic data shows that the above strategy is effective for identification of igneous rocks deep buried in the superimposed basin. Keywords: Identification of igneous rocks; Superimposed basin; Magnetic data

  12. NMR characterization of hydrocarbon adsorption on calcite surfaces: A first principles study

    Energy Technology Data Exchange (ETDEWEB)

    Bevilaqua, Rochele C. A.; Miranda, Caetano R. [Centro de Ciências Naturais e Humanas, Universidade Federal do ABC, UFABC, Santo André, SP (Brazil); Rigo, Vagner A. [Centro de Ciências Naturais e Humanas, Universidade Federal do ABC, UFABC, Santo André, SP (Brazil); Universidade Tecnológica Federal do Paraná, UTFPR, Cornélio Procópio, PR (Brazil); Veríssimo-Alves, Marcos [Centro de Ciências Naturais e Humanas, Universidade Federal do ABC, UFABC, Santo André, SP (Brazil); Departamento de Física, ICEx, Universidade Federal Fluminense, UFF, Volta Redonda, RJ (Brazil)

    2014-11-28

    The electronic and coordination environment of minerals surfaces, as calcite, are very difficult to characterize experimentally. This is mainly due to the fact that there are relatively few spectroscopic techniques able to detect Ca{sup 2+}. Since calcite is a major constituent of sedimentary rocks in oil reservoir, a more detailed characterization of the interaction between hydrocarbon molecules and mineral surfaces is highly desirable. Here we perform a first principles study on the adsorption of hydrocarbon molecules on calcite surface (CaCO{sub 3} (101{sup ¯}4)). The simulations were based on Density Functional Theory with Solid State Nuclear Magnetic Resonance (SS-NMR) calculations. The Gauge-Including Projector Augmented Wave method was used to compute mainly SS-NMR parameters for {sup 43}Ca, {sup 13}C, and {sup 17}O in calcite surface. It was possible to assign the peaks in the theoretical NMR spectra for all structures studied. Besides showing different chemical shifts for atoms located on different environments (bulk and surface) for calcite, the results also display changes on the chemical shift, mainly for Ca sites, when the hydrocarbon molecules are present. Even though the interaction of the benzene molecule with the calcite surface is weak, there is a clearly distinguishable displacement of the signal of the Ca sites over which the hydrocarbon molecule is located. A similar effect is also observed for hexane adsorption. Through NMR spectroscopy, we show that aromatic and alkane hydrocarbon molecules adsorbed on carbonate surfaces can be differentiated.

  13. Petrofacies analysis - the petrophysical tool for geologic/engineering reservoir characterization

    Energy Technology Data Exchange (ETDEWEB)

    Watney, W.L.; Guy, W.J.; Gerlach, P.M. [Kansas Geological Survey, Lawrence, KS (United States)] [and others

    1997-08-01

    Petrofacies analysis is defined as the characterization and classification of pore types and fluid saturations as revealed by petrophysical measures of a reservoir. The word {open_quotes}petrofacies{close_quotes} makes an explicit link between petroleum engineers concerns with pore characteristics as arbiters of production performance, and the facies paradigm of geologists as a methodology for genetic understanding and prediction. In petrofacies analysis, the porosity and resistivity axes of the classical Pickett plot are used to map water saturation, bulk volume water, and estimated permeability, as well as capillary pressure information, where it is available. When data points are connected in order of depth within a reservoir, the characteristic patterns reflect reservoir rock character and its interplay with the hydrocarbon column. A third variable can be presented at each point on the crossplot by assigning a color scale that is based on other well logs, often gamma ray or photoelectric effect, or other derived variables. Contrasts between reservoir pore types and fluid saturations will be reflected in changing patterns on the crossplot and can help discriminate and characterize reservoir heterogeneity. Many hundreds of analyses of well logs facilitated by spreadsheet and object-oriented programming have provided the means to distinguish patterns typical of certain complex pore types for sandstones and carbonate reservoirs, occurrences of irreducible water saturation, and presence of transition zones. The result has been an improved means to evaluate potential production such as bypassed pay behind pipe and in old exploration holes, or to assess zonation and continuity of the reservoir. Petrofacies analysis is applied in this example to distinguishing flow units including discrimination of pore type as assessment of reservoir conformance and continuity. The analysis is facilitated through the use of color cross sections and cluster analysis.

  14. Petroleum Characterisation and Reservoir Dynamics - The Froey Field and the Rind Discovery, Norwegian Continental Shelf

    Energy Technology Data Exchange (ETDEWEB)

    Bhullar, Abid G.

    1999-07-01

    The objective of this thesis is to apply the fundamental principles of petroleum geochemistry integrated with petroleum/reservoir engineering and geological concepts to the dynamics and characterisation of petroleum reservoirs. The study is based on 600 core samples and 9 DST oils from 11 wells in the Froey Field and the Rind Discovery. The work is presented in five papers. Paper 1 is a detailed characterisation of the reservoirs using a petroleum geochemical approach. Paper 2 describes the application of a single reservoir geochemical screening technique to exploration, appraisal and production geology and reservoir/petroleum engineering. Paper 3 compares the Iatroscan TLC-FID screening technique and the extraction efficiency of micro-extraction used in this work with the well-established Rock-Eval geochemical screening method and with the Soxtec extraction method. Paper 4 refines the migration and filling models of Paper 1, and Paper 5 presents a comparison of models of petroleum generation, migration and accumulation based on geochemical data with 1D burial history, a ''pseudo well'' based on actual well data and regional seismic analysis representing the hydrocarbon generative basin conditions.

  15. Technology for Increasing Geothermal Energy Productivity. Computer Models to Characterize the Chemical Interactions of Geothermal Fluids and Injectates with Reservoir Rocks, Wells, Surface Equipment

    International Nuclear Information System (INIS)

    Nancy Moller Weare

    2006-01-01

    This final report describes the results of a research program we carried out over a five-year (3/1999-9/2004) period with funding from a Department of Energy geothermal FDP grant (DE-FG07-99ID13745) and from other agencies. The goal of research projects in this program were to develop modeling technologies that can increase the understanding of geothermal reservoir chemistry and chemistry-related energy production processes. The ability of computer models to handle many chemical variables and complex interactions makes them an essential tool for building a fundamental understanding of a wide variety of complex geothermal resource and production chemistry. With careful choice of methodology and parameterization, research objectives were to show that chemical models can correctly simulate behavior for the ranges of fluid compositions, formation minerals, temperature and pressure associated with present and near future geothermal systems as well as for the very high PT chemistry of deep resources that is intractable with traditional experimental methods. Our research results successfully met these objectives. We demonstrated that advances in physical chemistry theory can be used to accurately describe the thermodynamics of solid-liquid-gas systems via their free energies for wide ranges of composition (X), temperature and pressure. Eight articles on this work were published in peer-reviewed journals and in conference proceedings. Four are in preparation. Our work has been presented at many workshops and conferences. We also considerably improved our interactive web site (geotherm.ucsd.edu), which was in preliminary form prior to the grant. This site, which includes several model codes treating different XPT conditions, is an effective means to transfer our technologies and is used by the geothermal community and other researchers worldwide. Our models have wide application to many energy related and other important problems (e.g., scaling prediction in petroleum

  16. Technology for Increasing Geothermal Energy Productivity. Computer Models to Characterize the Chemical Interactions of Goethermal Fluids and Injectates with Reservoir Rocks, Wells, Surface Equiptment

    Energy Technology Data Exchange (ETDEWEB)

    Nancy Moller Weare

    2006-07-25

    This final report describes the results of a research program we carried out over a five-year (3/1999-9/2004) period with funding from a Department of Energy geothermal FDP grant (DE-FG07-99ID13745) and from other agencies. The goal of research projects in this program were to develop modeling technologies that can increase the understanding of geothermal reservoir chemistry and chemistry-related energy production processes. The ability of computer models to handle many chemical variables and complex interactions makes them an essential tool for building a fundamental understanding of a wide variety of complex geothermal resource and production chemistry. With careful choice of methodology and parameterization, research objectives were to show that chemical models can correctly simulate behavior for the ranges of fluid compositions, formation minerals, temperature and pressure associated with present and near future geothermal systems as well as for the very high PT chemistry of deep resources that is intractable with traditional experimental methods. Our research results successfully met these objectives. We demonstrated that advances in physical chemistry theory can be used to accurately describe the thermodynamics of solid-liquid-gas systems via their free energies for wide ranges of composition (X), temperature and pressure. Eight articles on this work were published in peer-reviewed journals and in conference proceedings. Four are in preparation. Our work has been presented at many workshops and conferences. We also considerably improved our interactive web site (geotherm.ucsd.edu), which was in preliminary form prior to the grant. This site, which includes several model codes treating different XPT conditions, is an effective means to transfer our technologies and is used by the geothermal community and other researchers worldwide. Our models have wide application to many energy related and other important problems (e.g., scaling prediction in petroleum

  17. Using Multi-Disciplinary Data to Compile a Hydrocarbon Budget for GC600, a Natural Seep in the Gulf of Mexico

    Science.gov (United States)

    MacDonald, I. R.; Johansen, C.; Marty, E.; Natter, M.; Silva, M.; Hill, J. C.; Viso, R. F.; Lobodin, V.; Diercks, A. R.; Woolsey, M.; Macelloni, L.; Shedd, W. W.; Joye, S. B.; Abrams, M.

    2016-12-01

    Fluid exchange between the deep subsurface and the overlying ocean and atmosphere occurs at hydrocarbon seeps along continental margins. Seeps are key features that alter the seafloor morphology and geochemically affect the sediments that support chemosynthetic communities. However, the dynamics and discharge rates of hydrocarbons at cold seeps remain largely unconstrained. Here we merge complementary geochemical (oil fingerprinting), geophysical (seismic, subbottom, backscatter, multibeam) and video/imaging (Video Time Lapse Camera, DSV ALVIN video) data sets to constrain pathways and magnitudes of hydrocarbon fluxes from the source rock to the seafloor at a well-studied, prolific seep site in the Northern Gulf of Mexico (GC600). Oil fingerprinting showed compositional similarities for samples from the following collections: the reservoir, an active vent, and the sea-surface. This was consistent with reservoir structures and pathways identified in seismic data. Video data, which showed the spatial distribution of seep indicators such as bacteria mats, or hydrate outcrops at the sediment interface, were combined with known hydrocarbon fluxes from the literature and used to quantify the total hydrocarbon fluxes in the seep domain. Using a systems approach, we combined data sets and published values at various scales and resolutions to compile a preliminary hydrocarbon budget for the GC600 seep site. Total estimated in-flow of hydrocarbons was 2.07 x 109 mol/yr. The combined total of out-flow and sequestration amounted to 7.56 x 106 mol/yr leaving a potential excess (in-flow - out-flow) of 2.06 x 109 mol/yr. Thus quantification of the potential out-flow from the seep domains based on observable processes does not equilibrate with the theoretical inputs from the reservoir. Processes that might balance this budget include accumulation of gas hydrate and sediment free-gas, as well as greater efficiency of biological sinks.

  18. Total petroleum systems and geologic assessment of undiscovered oil and gas resources in the San Juan Basin Province, exclusive of Paleozoic rocks, New Mexico and Colorado

    Science.gov (United States)

    ,

    2013-01-01

    In 2002, the U.S. Geological Survey (USGS) estimated undiscovered oil and gas resources that have the potential for additions to reserves in the San Juan Basin Province, New Mexico and Colorado. Paleozoic rocks were not appraised. The last oil and gas assessment for the province was in 1995. There are several important differences between the 1995 and 2002 assessments. The area assessed is smaller than that in the 1995 assessment. This assessment of undiscovered hydrocarbon resources in the San Juan Basin Province also used a slightly different approach in the assessment, and hence a number of the plays defined in the 1995 assessment are addressed differently in this report. After 1995, the USGS has applied a total petroleum system (TPS) concept to oil and gas basin assessments. The TPS approach incorporates knowledge of the source rocks, reservoir rocks, migration pathways, and time of generation and expulsion of hydrocarbons; thus the assessments are geologically based. Each TPS is subdivided into one or more assessment units, usually defined by a unique set of reservoir rocks, but which have in common the same source rock. Four TPSs and 14 assessment units were geologically evaluated, and for 13 units, the undiscovered oil and gas resources were quantitatively assessed.

  19. Hydrocarbon Migration from the Micro to Macro Scale in the Gulf of Mexico

    Science.gov (United States)

    Johansen, C.; Marty, E.; Silva, M.; Natter, M.; Shedd, W. W.; Hill, J. C.; Viso, R. F.; Lobodin, V.; Krajewski, L.; Abrams, M.; MacDonald, I. R.

    2016-02-01

    In the Northern Gulf of Mexico (GoM) at GC600, ECOGIG has been investigating the processes involved in hydrocarbon migration from deep reservoirs to sea surface. We studied two individual vents, Birthday Candles (BC) and Mega-Plume (MP), which are separated by 1km on a salt supported ridge trending from NW-SE. Seismic data depicts two faults, also separated by 1km, feeding into the surface gas hydrate region. BC and MP comprise the range between oily, mixed, and gaseous-type vents. In both cases bubbles are observed escaping from gas hydrate out crops at the sea floor and supporting chemosynthetic communities. Fluid flow is indicated by features on the sea floor such as hydrate mounds, authigenic carbonates, brine pools, mud volcanoes, and biology. We propose a model to describe the upward flow of hydrocarbons from three vertical scales, each dominated by different factors: 1) macro (capillary failure in overlying cap rocks causing reservoir leakage), 2) meso (buoyancy driven fault migration), and 3) micro (hydrate formation and chemosynthetic activity). At the macro scale we use high reflectivity in seismic data and sediment pore throat radii to determine the formation of fractures in leaky reservoirs. Once oil and gas leave the reservoir through fractures in the cap rock they migrate in separate phases. At the meso scale we use seismic data to locate faults and salt diapirs that form conduits for buoyant hydrocarbons follow. This connects the path to the micro scale where we used video data to observe bubble release from individual vents for extended periods of time (3h-26d), and developed an image processing program to quantify bubble release rates. At mixed vents gaseous bubbles are observed escaping hydrate outcrops with a coating of oil varying in thickness. Bubble oil and gas ratios are estimated using average bubble size and release rates. The relative vent age can be described by carbonate hard ground cover, biological activity, and hydrate mound formation

  20. Amplitude various angles (AVA) phenomena in thin layer reservoir: Case study of various reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Nurhandoko, Bagus Endar B., E-mail: bagusnur@bdg.centrin.net.id, E-mail: bagusnur@rock-fluid.com [Wave Inversion and Subsurface Fluid Imaging Research Laboratory (WISFIR), Basic Science Center A 4" t" hfloor, Physics Dept., FMIPA, Institut Teknologi Bandung (Indonesia); Rock Fluid Imaging Lab., Bandung (Indonesia); Susilowati, E-mail: bagusnur@bdg.centrin.net.id, E-mail: bagusnur@rock-fluid.com [Rock Fluid Imaging Lab., Bandung (Indonesia)

    2015-04-16

    Amplitude various offset is widely used in petroleum exploration as well as in petroleum development field. Generally, phenomenon of amplitude in various angles assumes reservoir’s layer is quite thick. It also means that the wave is assumed as a very high frequency. But, in natural condition, the seismic wave is band limited and has quite low frequency. Therefore, topic about amplitude various angles in thin layer reservoir as well as low frequency assumption is important to be considered. Thin layer reservoir means the thickness of reservoir is about or less than quarter of wavelength. In this paper, I studied about the reflection phenomena in elastic wave which considering interference from thin layer reservoir and transmission wave. I applied Zoeppritz equation for modeling reflected wave of top reservoir, reflected wave of bottom reservoir, and also transmission elastic wave of reservoir. Results show that the phenomena of AVA in thin layer reservoir are frequency dependent. Thin layer reservoir causes interference between reflected wave of top reservoir and reflected wave of bottom reservoir. These phenomena are frequently neglected, however, in real practices. Even though, the impact of inattention in interference phenomena caused by thin layer in AVA may cause inaccurate reservoir characterization. The relation between classes of AVA reservoir and reservoir’s character are different when effect of ones in thin reservoir and ones in thick reservoir are compared. In this paper, I present some AVA phenomena including its cross plot in various thin reservoir types based on some rock physics data of Indonesia.

  1. Amplitude various angles (AVA) phenomena in thin layer reservoir: Case study of various reservoirs

    International Nuclear Information System (INIS)

    thfloor, Physics Dept., FMIPA, Institut Teknologi Bandung (Indonesia); Rock Fluid Imaging Lab., Bandung (Indonesia))" data-affiliation=" (Wave Inversion and Subsurface Fluid Imaging Research Laboratory (WISFIR), Basic Science Center A 4thfloor, Physics Dept., FMIPA, Institut Teknologi Bandung (Indonesia); Rock Fluid Imaging Lab., Bandung (Indonesia))" >Nurhandoko, Bagus Endar B.; Susilowati

    2015-01-01

    Amplitude various offset is widely used in petroleum exploration as well as in petroleum development field. Generally, phenomenon of amplitude in various angles assumes reservoir’s layer is quite thick. It also means that the wave is assumed as a very high frequency. But, in natural condition, the seismic wave is band limited and has quite low frequency. Therefore, topic about amplitude various angles in thin layer reservoir as well as low frequency assumption is important to be considered. Thin layer reservoir means the thickness of reservoir is about or less than quarter of wavelength. In this paper, I studied about the reflection phenomena in elastic wave which considering interference from thin layer reservoir and transmission wave. I applied Zoeppritz equation for modeling reflected wave of top reservoir, reflected wave of bottom reservoir, and also transmission elastic wave of reservoir. Results show that the phenomena of AVA in thin layer reservoir are frequency dependent. Thin layer reservoir causes interference between reflected wave of top reservoir and reflected wave of bottom reservoir. These phenomena are frequently neglected, however, in real practices. Even though, the impact of inattention in interference phenomena caused by thin layer in AVA may cause inaccurate reservoir characterization. The relation between classes of AVA reservoir and reservoir’s character are different when effect of ones in thin reservoir and ones in thick reservoir are compared. In this paper, I present some AVA phenomena including its cross plot in various thin reservoir types based on some rock physics data of Indonesia

  2. Fluids in crustal deformation: Fluid flow, fluid-rock interactions, rheology, melting and resources

    Science.gov (United States)

    Lacombe, Olivier; Rolland, Yann

    2016-11-01

    Fluids exert a first-order control on the structural, petrological and rheological evolution of the continental crust. Fluids interact with rocks from the earliest stages of sedimentation and diagenesis in basins until these rocks are deformed and/or buried and metamorphosed in orogens, then possibly exhumed. Fluid-rock interactions lead to the evolution of rock physical properties and rock strength. Fractures and faults are preferred pathways for fluids, and in turn physical and chemical interactions between fluid flow and tectonic structures, such as fault zones, strongly influence the mechanical behaviour of the crust at different space and time scales. Fluid (over)pressure is associated with a variety of geological phenomena, such as seismic cycle in various P-T conditions, hydrofracturing (including formation of sub-horizontal, bedding-parallel veins), fault (re)activation or gravitational sliding of rocks, among others. Fluid (over)pressure is a governing factor for the evolution of permeability and porosity of rocks and controls the generation, maturation and migration of economic fluids like hydrocarbons or ore forming hydrothermal fluids, and is therefore a key parameter in reservoir studies and basin modeling. Fluids may also help the crust partially melt, and in turn the resulting melt may dramatically change the rheology of the crust.

  3. A novel viscoelastic surfactant suitable for use in high temperature carbonate reservoirs for diverted acidizing stimulation treatments

    Energy Technology Data Exchange (ETDEWEB)

    Holt, Stuart; Zhou, Jian; Gadberry, Fred [AkzoNobel Surface Chemistry, Forth Worth, TX (United States); Nasr-El-Din, Hisham; Wang, Guanqun [Texas A and M University, College Station, TX (United States). Dept. of Petroleum Engineering

    2012-07-01

    Due to the low permeability of many carbonate hydrocarbon-bearing reservoirs, it is difficult to achieve economic hydrocarbon recovery from a well without secondary stimulation. Bullheading of strong acids, such as HCl is practiced in low temperature reservoirs, but as the bottom hole temperature (BHT) rises, the acid becomes increasingly corrosive, causing facial dissolution and sub-optimal wormhole network development. In the last decade, viscoelastic surfactants (VES) have been added to HCl acid systems to improve the stimulation of HT carbonate reservoirs. The VES form 'living polymers' or worm-like micelles as electrolyte concentration rises in the acid due to reaction with the reservoir. This leads to viscosification of the stimulation fluid. The viscosification slows further acid reaction in the region already contacted by the acid, and forces the acid to take an alternate path into the rock, leading to diversion of the acids further down the well to the harder to access toe or lower permeability zones. Until recently, the maximum BHT that such VES-based diverting systems could be used was up to about 250 deg F/120 deg C. Above that temperature, all viscous properties of the fluid are lost, destroying the mechanism of acid diversion. A recently developed novel viscoelastic surfactant provides nearly 100 deg F/55 deg C extension in the BHT range in which diverted acid treatments can be used. These fluids are able to maintain both viscosity up to about 375 deg F/190 deg C, with the elastic modulus predominating up to 350 deg F/175 deg C. It is the elasticity which is particularly important in acid diversion. These fluids can have their viscosity readily broken by in-situ hydrocarbons, dilution with water or by using a mutual solvent. The broken fluids are readily removed from the near-well bore, leaving the newly created wormhole network to produce the target hydrocarbons. The new VES is significantly more environmentally benign compared with current

  4. Optrode for sensing hydrocarbons

    Science.gov (United States)

    Miller, H.; Milanovich, F.P.; Hirschfeld, T.B.; Miller, F.S.

    1988-09-13

    A two-phase system employing the Fujiwara reaction is provided for the fluorometric detection of halogenated hydrocarbons. A fiber optic is utilized to illuminate a column of pyridine trapped in a capillary tube coaxially attached at one end to the illuminating end of the fiber optic. A strongly alkaline condition necessary for the reaction is maintained by providing a reservoir of alkali in contact with the column of pyridine, the surface of contact being adjacent to the illuminating end of the fiber optic. A semipermeable membrane caps the other end of the capillary tube, the membrane being preferentially permeable to the halogenated hydrocarbon and but preferentially impermeable to water and pyridine. As the halogenated hydrocarbon diffuses through the membrane and into the column of pyridine, fluorescent reaction products are formed. Light propagated by the fiber optic from a light source, excites the fluorescent products. Light from the fluorescence emission is also collected by the same fiber optic and transmitted to a detector. The intensity of the fluorescence gives a measure of the concentration of the halogenated hydrocarbons. 5 figs.

  5. Reservoir characteristics and control factors of Carboniferous volcanic gas reservoirs in the Dixi area of Junggar Basin, China

    Directory of Open Access Journals (Sweden)

    Ji'an Shi

    2017-02-01

    Full Text Available Field outcrop observation, drilling core description, thin-section analysis, SEM analysis, and geochemistry, indicate that Dixi area of Carboniferous volcanic rock gas reservoir belongs to the volcanic rock oil reservoir of the authigenic gas reservoir. The source rocks make contact with volcanic rock reservoir directly or by fault, and having the characteristics of near source accumulation. The volcanic rock reservoir rocks mainly consist of acidic rhyolite and dacite, intermediate andesite, basic basalt and volcanic breccia: (1 Acidic rhyolite and dacite reservoirs are developed in the middle-lower part of the structure, have suffered strong denudation effect, and the secondary pores have formed in the weathering and tectonic burial stages, but primary pores are not developed within the early diagenesis stage. Average porosity is only at 8%, and the maximum porosity is at 13.5%, with oil and gas accumulation showing poor performance. (2 Intermediate andesite and basic basalt reservoirs are mainly distributed near the crater, which resembles the size of and suggests a volcanic eruption. Primary pores are formed in the early diagenetic stage, secondary pores developed in weathering and erosion transformation stage, and secondary fractures formed in the tectonic burial stage. The average porosity is at 9.2%, and the maximum porosity is at 21.9%: it is of the high-quality reservoir types in Dixi area. (3 The volcanic breccia reservoir has the same diagenetic features with sedimentary rocks, but also has the same mineral composition with volcanic rock; rigid components can keep the primary porosity without being affected by compaction during the burial process. At the same time, the brittleness of volcanic breccia reservoir makes it easily fracture under the stress; internal fracture was developmental. Volcanic breccia developed in the structural high part and suffered a long-term leaching effect. The original pore-fracture combination also made

  6. Executive summary--2002 assessment of undiscovered oil and gas resources in the San Juan Basin Province, exclusive of Paleozoic rocks, New Mexico and Colorado: Chapter 1 in Total petroleum systems and geologic assessment of undiscovered oil and gas resources in the San Juan Basin Province, exclusive of Paleozoic rocks, New Mexico and Colorado

    Science.gov (United States)

    ,

    2013-01-01

    In 2002, the U.S. Geological Survey (USGS) estimated undiscovered oil and gas resources that have the potential for additions to reserves in the San Juan Basin Province (5022), New Mexico and Colorado (fig. 1). Paleozoic rocks were not appraised. The last oil and gas assessment for the province was in 1995 (Gautier and others, 1996). There are several important differences between the 1995 and 2002 assessments. The area assessed is smaller than that in the 1995 assessment. This assessment of undiscovered hydrocarbon resources in the San Juan Basin Province also used a slightly different approach in the assessment, and hence a number of the plays defined in the 1995 assessment are addressed differently in this report. After 1995, the USGS has applied a total petroleum system (TPS) concept to oil and gas basin assessments. The TPS approach incorporates knowledge of the source rocks, reservoir rocks, migration pathways, and time of generation and expulsion of hydrocarbons; thus the assessments are geologically based. Each TPS is subdivided into one or more assessment units, usually defined by a unique set of reservoir rocks, but which have in common the same source rock. Four TPSs and 14 assessment units were geologically evaluated, and for 13 units, the undiscovered oil and gas resources were quantitatively assessed.

  7. Hydrocarbon potential assessment of Ngimbang formation, Rihen field of Northeast Java Basin

    Science.gov (United States)

    Pandito, R. H.; Haris, A.; Zainal, R. M.; Riyanto, A.

    2017-07-01

    The assessment of Ngimbang formation at Rihen field of Northeast Java Basin has been conducted to identify the hydrocarbon potential by analyzing the response of passive seismic on the proven reservoir zone and proposing a tectonic evolution model. In the case of petroleum exploration in Northeast Java basin, the Ngimbang formation cannot be simply overemphasized. East Java Basin has been well known as one of the mature basins producing hydrocarbons in Indonesia. This basin was stratigraphically composed of several formations from the old to the young i.e., the basement, Ngimbang, Kujung, Tuban, Ngerayong, Wonocolo, Kawengan and Lidah formation. All of these formations have proven to become hydrocarbon producer. The Ngrayong formation, which is geologically dominated by channels, has become a production formation. The Kujung formation that has been known with the reef build up has produced more than 102 million barrel of oil. The Ngimbang formation so far has not been comprehensively assessed in term its role as a source rock and a reservoir. In 2013, one exploratory well has been drilled at Ngimbang formation and shown a gas discovery, which is indicated on Drill Stem Test (DST) reading for more than 22 MMSCFD of gas. This discovery opens new prospect in exploring the Ngimbang formation.

  8. Diagenesis and reservoir quality of the Lower Cretaceous Quantou Formation tight sandstones in the southern Songliao Basin, China

    Science.gov (United States)

    Xi, Kelai; Cao, Yingchang; Jahren, Jens; Zhu, Rukai; Bjørlykke, Knut; Haile, Beyene Girma; Zheng, Lijing; Hellevang, Helge

    2015-12-01

    later than the tight rock formation (with the porosity close to 10%). However, thicker sandstone bodies (more than 2 m) constitute potential hydrocarbon reservoirs.

  9. Petroleum hydrocarbons

    International Nuclear Information System (INIS)

    Farrington, J.W.; Teal, J.M.; Parker, P.L.

    1976-01-01

    Methods for analysis of petroleum hydrocarbons in marine samples are presented. Types of hydrocarbons present and their origins are discussed. Principles and methods of analysis are outlined. Infrared spectrometry, uv spectrometry, gas chromatography, mass spectroscopy, and carbon 14 measurements are described

  10. The Role of the Rock on Hydraulic Fracturing of Tight Shales

    Science.gov (United States)

    Suarez-Rivera, R.; Green, S.; Stanchits, S.; Yang, Y.

    2011-12-01

    Successful economic production of oil and gas from nano-darcy-range permeability, tight shale reservoirs, is achieved via massive hydraulic fracturing. This is so despite their limited hydrocarbon in place, on per unit rock volume basis. As a reference, consider a typical average porosity of 6% and an average hydrocarbon saturation of 50% to 75%. The importance of tight shales results from their large areal extent and vertical thickness. For example, the areal extent of the Anwar field in Saudi Arabia of 3230 square miles (and 300 ft thick), while the Marcellus shale alone is over 100,000 square miles (and 70 to 150 ft thick). The low permeability of the rock matrix, the predominantly mineralized rock fabric, and the high capillary forces to both brines and hydrocarbons, restrict the mobility of pore fluids in these reservoirs. Thus, one anticipates that fluids do not move very far within tight shales. Successful production, therefore results from maximizing the surface area of contact with the reservoir by massive hydraulic fracturing from horizontal bore holes. This was the conceptual breakthrough of the previous decade and the one that triggered the emergence of gas shales, and recently oily shales, as important economic sources of energy. It is now understood that the process can be made substantially more efficient, more sustainable, and more cost effective by understanding the rock. This will be the breakthrough of this decade. Microseismic monitoring, mass balance calculations, and laboratory experiments of hydraulic fracturing on tight shales indicate the development of fracture complexity and fracture propagation that can not be explained in detail in this layered heterogeneous media. It is now clear that in tight shales the large-scale formation fabric is responsible for fracture complexity. For example, the presence and pervasiveness of mineralized fractures, bed interfaces, lithologic contacts, and other types of discontinuities, and their orientation

  11. Evaluation of hydrocarbon potential

    International Nuclear Information System (INIS)

    Cashman, P.H.; Trexler, J.H. Jr.

    1992-01-01

    Task 8 is responsible for assessing the hydrocarbon potential of the Yucca Mountain vincinity. Our main focus is source rock stratigraphy in the NTS area in southern Nevada. (In addition, Trexler continues to work on a parallel study of source rock stratigraphy in the oil-producing region of east central Nevada, but this work is not funded by Task 8.) As a supplement to the stratigraphic studies, we are studying the geometry and kinematics of deformation at NTS, particularly as these pertain to reconstructing Paleozoic stratigraphy and to predicting the nature of the Late Paleozoic rocks under Yucca Mountain. Our stratigraphic studies continue to support the interpretation that rocks mapped as the open-quotes Eleana Formationclose quotes are in fact parts of two different Mississippian units. We have made significant progress in determining the basin histories of both units. These place important constraints on regional paleogeographic and tectonic reconstructions. In addition to continued work on the Eleana, we plan to look at the overlying Tippipah Limestone. Preliminary TOC and maturation data indicate that this may be another potential source rock

  12. Characterizing gas shaly sandstone reservoirs using the magnetic resonance technology in the Anaco area, East Venezuela

    Energy Technology Data Exchange (ETDEWEB)

    Fam, Maged; August, Howard [Halliburton, Houston, TX (United States); Zambrano, Carlos; Rivero, Fidel [PDVSA Gas (Venezuela)

    2008-07-01

    With demand for natural gas on the rise every day, accounting for and booking every cubic foot of gas is becoming very important to operators exploiting natural gas reservoirs. The initial estimates of gas reserves are usually established through the use of petrophysical parameters normally based on wireline and/or LWD logs. Conventional logs, such as gamma ray, density, neutron, resistivity and sonic, are traditionally used to calculate these parameters. Sometimes, however, the use of such conventional logs may not be enough to provide a high degree of accuracy in determining these petrophysical parameters, which are critical to reserve estimates. Insufficient accuracy can be due to high complexities in the rock properties and/or a formation fluid distribution within the reservoir layers that is very difficult to characterize with conventional logs alone. The high degree of heterogeneity in the shaly sandstone rock properties of the Anaco area, East Venezuela, can be characterized by clean, high porosity, high permeability sands to very shaly, highly laminated, and low porosity rock. This wide variation in the reservoir properties may pose difficulties in identifying gas bearing zones which may affect the final gas reserves estimates in the area. The application of the magnetic resonance imaging (MRI) logging technology in the area, combined with the application of its latest acquisition and interpretation methods, has proven to be very adequate in detecting and quantifying gas zones as well as providing more realistic petrophysical parameters for better reserve estimates. This article demonstrates the effectiveness of applying the MRI logging technology to obtain improved petrophysical parameters that will help better characterize the shaly-sands of Anaco area gas reservoirs. This article also demonstrates the value of MRI in determining fluid types, including distinguishing between bound water and free water, as well as differentiating between gas and liquid

  13. Solid as a rock

    International Nuclear Information System (INIS)

    Pincus, H.J.

    1984-01-01

    Recent technologic developments have required a more comprehensive approach to the behavior of rock mass or rock substance plus discontinuities than was adequate previously. This work considers the inherent problems in such operations as the storage of hot or cold fluids in caverns and aquifers, underground storage of nuclear waste, underground recovery of heat from hydrocarbon fuels, tertiary recovery of oil by thermal methods, rapid excavation of large openings at shallow to great depths and in hostile environments, and retrofitting of large structures built on or in rock. The standardization of methods for determining rock properties is essential to all of the activities described, for use not only in design and construction but also in site selection and post-construction monitoring. Development of such standards is seen as a multidisciplinary effort

  14. Design Techniques and Reservoir Simulation

    Directory of Open Access Journals (Sweden)

    Ahad Fereidooni

    2012-11-01

    Full Text Available Enhanced oil recovery using nitrogen injection is a commonly applied method for pressure maintenance in conventional reservoirs. Numerical simulations can be practiced for the prediction of a reservoir performance in the course of injection process; however, a detailed simulation might take up enormous computer processing time. In such cases, a simple statistical model may be a good approach to the preliminary prediction of the process without any application of numerical simulation. In the current work, seven rock/fluid reservoir properties are considered as screening parameters and those parameters having the most considerable effect on the process are determined using the combination of experimental design techniques and reservoir simulations. Therefore, the statistical significance of the main effects and interactions of screening parameters are analyzed utilizing statistical inference approaches. Finally, the influential parameters are employed to create a simple statistical model which allows the preliminary prediction of nitrogen injection in terms of a recovery factor without resorting to numerical simulations.

  15. Coupled Modeling of Flow, Transport, and Deformation during Hydrodynamically Unstable Displacement in Fractured Rocks

    Science.gov (United States)

    Jha, B.; Juanes, R.

    2015-12-01

    Coupled processes of flow, transport, and deformation are important during production of hydrocarbons from oil and gas reservoirs. Effective design and implementation of enhanced recovery techniques such as miscible gas flooding and hydraulic fracturing requires modeling and simulation of these coupled proceses in geologic porous media. We develop a computational framework to model the coupled processes of flow, transport, and deformation in heterogeneous fractured rock. We show that the hydrocarbon recovery efficiency during unstable displacement of a more viscous oil with a less viscous fluid in a fractured medium depends on the mechanical state of the medium, which evolves due to permeability alteration within and around fractures. We show that fully accounting for the coupling between the physical processes results in estimates of the recovery efficiency in agreement with observations in field and lab experiments.

  16. Multi Data Reservoir History Matching using the Ensemble Kalman Filter

    KAUST Repository

    Katterbauer, Klemens

    2015-01-01

    Reservoir history matching is becoming increasingly important with the growing demand for higher quality formation characterization and forecasting and the increased complexity and expenses for modern hydrocarbon exploration projects. History

  17. Understanding the True Stimulated Reservoir Volume in Shale Reservoirs

    KAUST Repository

    Hussain, Maaruf

    2017-06-06

    Successful exploitation of shale reservoirs largely depends on the effectiveness of hydraulic fracturing stimulation program. Favorable results have been attributed to intersection and reactivation of pre-existing fractures by hydraulically-induced fractures that connect the wellbore to a larger fracture surface area within the reservoir rock volume. Thus, accurate estimation of the stimulated reservoir volume (SRV) becomes critical for the reservoir performance simulation and production analysis. Micro-seismic events (MS) have been commonly used as a proxy to map out the SRV geometry, which could be erroneous because not all MS events are related to hydraulic fracture propagation. The case studies discussed here utilized a fully 3-D simulation approach to estimate the SRV. The simulation approach presented in this paper takes into account the real-time changes in the reservoir\\'s geomechanics as a function of fluid pressures. It is consisted of four separate coupled modules: geomechanics, hydrodynamics, a geomechanical joint model for interfacial resolution, and an adaptive re-meshing. Reservoir stress condition, rock mechanical properties, and injected fluid pressure dictate how fracture elements could open or slide. Critical stress intensity factor was used as a fracture criterion governing the generation of new fractures or propagation of existing fractures and their directions. Our simulations were run on a Cray XC-40 HPC system. The studies outcomes proved the approach of using MS data as a proxy for SRV to be significantly flawed. Many of the observed stimulated natural fractures are stress related and very few that are closer to the injection field are connected. The situation is worsened in a highly laminated shale reservoir as the hydraulic fracture propagation is significantly hampered. High contrast in the in-situ stresses related strike-slip developed thereby shortens the extent of SRV. However, far field nature fractures that were not connected to

  18. Deep-water northern Gulf of Mexico hydrocarbon plays

    International Nuclear Information System (INIS)

    Peterson, R.H.; Cooke, D.W.

    1995-01-01

    The geologic setting in the deep-water (depths greater than 1,500 feet) Gulf of Mexico is very favorable for the existence of large, commercial hydrocarbon accumulations. These areas have active salt tectonics that create abundant traps, underlying mature Mesozoic source rocks that can be observed expelling oil and gas to the ocean surface, and good quality reservoirs provided by turbidite sand deposits. Despite the limited amount of drilling in the deep-water Gulf of Mexico, 11 deep-water accumulations have been discovered which, when developed, will rank in the top 100 largest fields in the Gulf of Mexico. Proved field discoveries (those with announced development plans) have added over 1 billion barrels of oil equivalent to Gulf of Mexico reserves, and unproved field discoveries may add to additional billion barrels of oil equivalent. The Minerals Management Service, United States Department of the Interior, has completed a gulf-wide review of over 1,086 oil and gas fields and placed every pay sand in each field into a hydrocarbon play (plays are defined by chronostratigraphy, lithostratigraph, structure, and production). Seven productive hydrocarbon plays were identified in the deep-water northern Gulf of Mexico. Regional maps illustrate the productive limits of each play. In addition, field data, dry holes, and wells with sub-economic pay were added to define the facies and structural limits for each play. Areas for exploration potential are identified for each hydrocarbon play. A type field for each play is chosen to demonstrate the play's characteristics

  19. H2-rich and Hydrocarbon Gas Recovered in a Deep Precambrian Well in Northeastern Kansas

    International Nuclear Information System (INIS)

    Newell, K. David; Doveton, John H.; Merriam, Daniel F.; Lollar, Barbara Sherwood; Waggoner, William M.; Magnuson, L. Michael

    2007-01-01

    abiogenic hydrocarbon gases from Precambrian Shield sites in Canada, Finland, and South Africa. Compositional and isotopic signatures for gas from the no. 1 Wilson well are consistent with a predominantly thermogenic origin, with possible mixing with a component of microbial gas. Given the geologic history of uplift and rifting this region, and the major fracture systems present in the basement, this hydrocarbon gas likely migrated from source rocks and reservoirs in the overlying Paleozoic sediments and is not evidence for abiogenic hydrocarbons generated in situ in the Precambrian basement

  20. Reservoir heterogeneity in carboniferous sandstone of the Black Warrior basin. Final report

    Energy Technology Data Exchange (ETDEWEB)

    Kugler, R.L.; Pashin, J.C.; Carroll, R.E.; Irvin, G.D.; Moore, H.E.

    1994-06-01

    Although oil production in the Black Warrior basin of Alabama is declining, additional oil may be produced through improved recovery strategies, such as waterflooding, chemical injection, strategic well placement, and infill drilling. High-quality characterization of reservoirs in the Black Warrior basin is necessary to utilize advanced technology to recover additional oil and to avoid premature abandonment of fields. This report documents controls on the distribution and producibility of oil from heterogeneous Carboniferous reservoirs in the Black Warrior basin of Alabama. The first part of the report summarizes the structural and depositional evolution of the Black Warrior basin and establishes the geochemical characteristics of hydrocarbon source rocks and oil in the basin. This second part characterizes facies heterogeneity and petrologic and petrophysical properties of Carter and Millerella sandstone reservoirs. This is followed by a summary of oil production in the Black Warrior basin and an evaluation of seven improved-recovery projects in Alabama. In the final part, controls on the producibility of oil from sandstone reservoirs are discussed in terms of a scale-dependent heterogeneity classification.

  1. A multiscale fixed stress split iterative scheme for coupled flow and poromechanics in deep subsurface reservoirs

    Science.gov (United States)

    Dana, Saumik; Ganis, Benjamin; Wheeler, Mary F.

    2018-01-01

    In coupled flow and poromechanics phenomena representing hydrocarbon production or CO2 sequestration in deep subsurface reservoirs, the spatial domain in which fluid flow occurs is usually much smaller than the spatial domain over which significant deformation occurs. The typical approach is to either impose an overburden pressure directly on the reservoir thus treating it as a coupled problem domain or to model flow on a huge domain with zero permeability cells to mimic the no flow boundary condition on the interface of the reservoir and the surrounding rock. The former approach precludes a study of land subsidence or uplift and further does not mimic the true effect of the overburden on stress sensitive reservoirs whereas the latter approach has huge computational costs. In order to address these challenges, we augment the fixed-stress split iterative scheme with upscaling and downscaling operators to enable modeling flow and mechanics on overlapping nonmatching hexahedral grids. Flow is solved on a finer mesh using a multipoint flux mixed finite element method and mechanics is solved on a coarse mesh using a conforming Galerkin method. The multiscale operators are constructed using a procedure that involves singular value decompositions, a surface intersections algorithm and Delaunay triangulations. We numerically demonstrate the convergence of the augmented scheme using the classical Mandel's problem solution.

  2. Reservoir heterogeneity in Carboniferous sandstone of the Black Warrior basin. Final report

    Energy Technology Data Exchange (ETDEWEB)

    Kugler, R.L.; Pashin, J.C.; Carroll, R.E.; Irvin, G.D.; Moore, H.E.

    1994-04-01

    Although oil production in the Black Warrior basin of Alabama is declining, additional oil may be produced through improved recovery strategies, such as waterflooding, chemical injection, strategic well placement, and infill drilling. High-quality characterization of reservoirs in the Black Warrior basin is necessary to utilize advanced technology to recover additional oil and to avoid premature abandonment of fields. This report documents controls on the distribution and producibility of oil from heterogeneous Carboniferous reservoirs in the Black Warrior basin of Alabama. The first part of the report summarizes the structural and depositional evolution of the Black Warrior basin and establishes the geochemical characteristics of hydrocarbon source rocks and oil in the basin. This second part characterizes facies heterogeneity and petrologic and petrophysical properties of Carter and Millerella sandstone reservoirs. This is followed by a summary of oil production in the Black Warrior basin and an evaluation of seven improved-recovery projects in Alabama. In the final part, controls on the producibility of oil from sandstone reservoirs are discussed in terms of a scale-dependent heterogeneity classification.

  3. Cretaceous rocks of the Western Interior basin

    International Nuclear Information System (INIS)

    Molenaar, C.M.; Rice, D.D.

    1988-01-01

    The Cretaceous rocks of the conterminous United States are discussed in this chapter. Depositional facies and lithology are reviewed along with economic resources. The economic resources include coal, hydrocarbons, and uranium

  4. Geochemical characteristics of crude oil from a tight oil reservoir in the Lucaogou Formation, Jimusar Sag, Junggar Basin

    Science.gov (United States)

    Cao, Z.

    2015-12-01

    Jimusar Sag, which lies in the Junggar Basin,is one of the most typical tight oil study areas in China. However, the properties and origin of the crude oil and the geochemical characteristics of the tight oil from the Lucaogou Formation have not yet been studied. In the present study, 23 crude oilsfrom the Lucaogou Formation were collected for analysis, such as physical properties, bulk composition, saturated hydrocarbon gas chromatography-mass spectrometry (GC-MS), and the calculation of various biomarker parameters. In addition,source rock evaluation and porosity permeability analysis were applied to the mudstones and siltstones. Biomarkers of suitable source rocks (TOC>1, S1+S2>6mg/g, 0.7%hydrocarbon generation history of the Lucaogou source rock, 1D basin modeling was performed. The oil-filling history was also defined by means of basin modeling and microthermometry. The results indicated the presence of low maturity to mature crude oils originating from the burial of terrigenous organic matter beneath a saline lake in the source rocks of mainly type II1kerogen. In addition, a higher proportion of bacteria and algae was shown to contribute to the formation of crude oil in the lower section when compared with the upper section of the Lucaogou Formation. Oil-source correlations demonstrated that not all mudstones within the Lucaogou Formation contributed to oil accumulation.Crude oil from the upper and lower sections originated from thin-bedded mudstones interbedded within sweet spot sand bodies. A good coincidence of filling history and hydrocarbon generation history indicated that the Lucaogou reservoir is a typical in situ reservoir. The mudstones over or beneath the sweet spot bodies consisted of natural caprocks and prevented the vertical movement of oil by capillary forces. Despite being thicker, the thick-bedded mudstone between the upper and lower sweet spots had no obvious contribution to

  5. Task 8: Evaluation of hydrocarbon potential

    International Nuclear Information System (INIS)

    Cashman, P.H.; Trexler, J.H. Jr.

    1994-01-01

    Our studies focus on the stratigraphy of Late Devonian to early Pennsylvanian rocks at the NTS, because these are the best potential hydrocarbon source rocks in the vicinity of Yucca Mountain. In the last year, our stratigraphic studies have broadened to include the regional context for both the Chainman and the Eleana formations. New age data based on biostratigraphy constrain the age ranges of both Chainman and Eleana; accurate and reliable ages are essential for regional correlation and for regional paleogeographic reconstructions. Source rock analyses throughout the Chainman establish whether these rocks contained adequate organic material to generate hydrocarbons. Maturation analyses of samples from the Chainman determine whether the temperature history has been suitable for the generation of liquid hydrocarbons. Structural studies are aimed at defining the deformation histories and present position of the different packages of Devonian - Pennsylvanian rocks. This report summarizes new results of our structural, stratigraphic and hydrocarbon source rock potential studies at the Nevada Test Site and vicinity. Stratigraphy is considered first, with the Chainman Shale and Eleana Formation discussed separately. New biostratigraphic results are included in this section. New results from our structural studies are summarized next, followed by source rock and maturation analyses of the Chainman Shale. Directions for future work are included where appropriate

  6. Analysis of real-time reservoir monitoring : reservoirs, strategies, & modeling.

    Energy Technology Data Exchange (ETDEWEB)

    Mani, Seethambal S.; van Bloemen Waanders, Bart Gustaaf; Cooper, Scott Patrick; Jakaboski, Blake Elaine; Normann, Randy Allen; Jennings, Jim (University of Texas at Austin, Austin, TX); Gilbert, Bob (University of Texas at Austin, Austin, TX); Lake, Larry W. (University of Texas at Austin, Austin, TX); Weiss, Chester Joseph; Lorenz, John Clay; Elbring, Gregory Jay; Wheeler, Mary Fanett (University of Texas at Austin, Austin, TX); Thomas, Sunil G. (University of Texas at Austin, Austin, TX); Rightley, Michael J.; Rodriguez, Adolfo (University of Texas at Austin, Austin, TX); Klie, Hector (University of Texas at Austin, Austin, TX); Banchs, Rafael (University of Texas at Austin, Austin, TX); Nunez, Emilio J. (University of Texas at Austin, Austin, TX); Jablonowski, Chris (University of Texas at Austin, Austin, TX)

    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

  7. Research of hard-to-recovery and unconventional oil-bearing formations according to the principle «in-situ reservoir fabric»

    Directory of Open Access Journals (Sweden)

    А. Д. Алексеев

    2017-12-01

    Full Text Available Currently in Russia and the world due to the depletion of old highly productive deposits, the role of hard-to-recover and unconventional hydrocarbons is increasing. Thanks to scientific and technical progress, it became possible to involve in the development very low permeable reservoirs and even synthesize oil and gas in-situ. Today, wells serve not only for the production of hydrocarbons, but also are important elements of stimulation technology, through which the technogenic effect on the formation is carried out in order to intensify inflows. In this context, the reservoir itself can be considered as a raw material for the application of stimulation technologies, and the set of wells through which it is technologically affected is a plant or a fabric whose intermediate product is the stimulated zone of the formation and the final product is reservoir hydrocarbons. Well-established methods for studying hydrocarbon deposits are limited to the definition of standard geological parameters, which are commonly used for reserves calculations (net pay, porosity, permeability, oil and gas saturation coefficient, area, but they are clearly insufficient to characterize the development possibilities using modern stimulation technologies. To study objects that are promising for the production of hydrocarbons, it is necessary to develop fundamentally new approaches that make it possible to assess the availability of resources depending on the technologies used, and to improve the methods for forecasting and evaluating the properties of the stimulated zone of the formation. «In-situ reservoir fabric» is a collective term that combines a combination of technologies, research and methodological approaches aimed at creating and evaluating a stimulated zone of the formation by applying modern methods of technogenic impact on objects containing hard-to-recover and «unconventional» hydrocarbons in order to intensify inflows from them hydrocarbons. In 2015

  8. Geology and oil and gas assessment of the Mancos-Menefee Composite Total Petroleum System: Chapter 4 in Total petroleum systems and geologic assessment of undiscovered oil and gas resources in the San Juan Basin Province, exclusive of Paleozoic rocks, New Mexico and Colorado

    Science.gov (United States)

    Ridgley, J.L.; Condon, S.M.; Hatch, J.R.

    2013-01-01

    The Mancos-Menefee Composite Total Petroleum System (TPS) includes all genetically related hydrocarbons generated from organic-rich shales in the Cretaceous Mancos Shale and from carbonaceous shale, coal beds, and humate in the Cretaceous Menefee Formation of the Mesaverde Group. The system is called a composite total petroleum system because the exact source of the hydrocarbons in some of the reservoirs is not known. Reservoir rocks that contain hydrocarbons generated in Mancos and Menefee source beds are found in the Cretaceous Dakota Sandstone, at the base of the composite TPS, through the lower part of the Cliff House Sandstone of the Mesaverde Group, at the top. Source rocks in both the Mancos Shale and Menefee Formation entered the oil generation window in the late Eocene and continued to generate oil or gas into the late Miocene. Near the end of the Miocene in the San Juan Basin, subsidence ceased, hydrocarbon generation ceased, and the basin was uplifted and differentially eroded. Reservoirs are now underpressured.

  9. Real rock-microfluidic flow cell: A test bed for real-time in situ analysis of flow, transport, and reaction in a subsurface reactive transport environment.

    Science.gov (United States)

    Singh, Rajveer; Sivaguru, Mayandi; Fried, Glenn A; Fouke, Bruce W; Sanford, Robert A; Carrera, Martin; Werth, Charles J

    2017-09-01

    Physical, chemical, and biological interactions between groundwater and sedimentary rock directly control the fundamental subsurface properties such as porosity, permeability, and flow. This is true for a variety of subsurface scenarios, ranging from shallow groundwater aquifers to deeply buried hydrocarbon reservoirs. Microfluidic flow cells are now commonly being used to study these processes at the pore scale in simplified pore structures meant to mimic subsurface reservoirs. However, these micromodels are typically fabricated from glass, silicon, or polydimethylsiloxane (PDMS), and are therefore incapable of replicating the geochemical reactivity and complex three-dimensional pore networks present in subsurface lithologies. To address these limitations, we developed a new microfluidic experimental test bed, herein called the Real Rock-Microfluidic Flow Cell (RR-MFC). A porous 500μm-thick real rock sample of the Clair Group sandstone from a subsurface hydrocarbon reservoir of the North Sea was prepared and mounted inside a PDMS microfluidic channel, creating a dynamic flow-through experimental platform for real-time tracking of subsurface reactive transport. Transmitted and reflected microscopy, cathodoluminescence microscopy, Raman spectroscopy, and confocal laser microscopy techniques were used to (1) determine the mineralogy, geochemistry, and pore networks within the sandstone inserted in the RR-MFC, (2) analyze non-reactive tracer breakthrough in two- and (depth-limited) three-dimensions, and (3) characterize multiphase flow. The RR-MFC is the first microfluidic experimental platform that allows direct visualization of flow and transport in the pore space of a real subsurface reservoir rock sample, and holds potential to advance our understandings of reactive transport and other subsurface processes relevant to pollutant transport and cleanup in groundwater, as well as energy recovery. Copyright © 2017 Elsevier B.V. All rights reserved.

  10. Analysis of structural heterogeneities on drilled cores: a reservoir modeling oriented methodology; Analyse des heterogeneites structurales sur carottes: une methodologie axee vers la modelisation des reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Cortes, P.; Petit, J.P. [Montpellier-2 Univ., Lab. de Geophysique, Tectonique et Sedimentologie, UMR CNRS 5573, 34 (France); Guy, L. [ELF Aquitaine Production, 64 - Pau (France); Thiry-Bastien, Ph. [Lyon-1 Univ., 69 (France)

    1999-07-01

    The characterization of structural heterogeneities of reservoirs is of prime importance for hydrocarbons recovery. A methodology is presented which allows to compare the dynamic behaviour of fractured reservoirs and the observation of microstructures on drilled cores or surface reservoir analogues. (J.S.)

  11. An-integrated seismic approach to de-risk hydrocarbon accumulation for Pliocene deep marine slope channels, offshore West Nile Delta, Egypt

    Science.gov (United States)

    Othman, Adel A. A.; Bakr, Ali; Maher, Ali

    2017-12-01

    The Nile Delta basin is a hydrocarbon rich province that has hydrocarbon accumulations generated from biogenic and thermogenic source rocks and trapped in a clastic channel reservoirs ranging in age from Pliocene to Early Cretaceous. Currently, the offshore Nile Delta is the most active exploration and development province in Egypt. The main challenge of the studied area is that we have only one well in a channel system exceeds fifteen km length, where seismic reservoir characterization is used to de-risk development scenarios for the field by discriminating between gas sand, water sand and shale. Extracting the gas-charged geobody from the seismic data is magnificent input for 3D reservoir static modelling. Seismic data, being non-stationary in nature, have varying frequency content in time. Spectral decomposition analysis unravels the seismic signal into its initial constituent frequencies. Frequency decomposition of a seismic signal aims to characterize the time-dependent frequency response of subsurface rocks and reservoirs for imaging and mapping of bed thickness, geologic discontinuities and channel connectivity. Inversion feasibility study using crossplot between P-wave impedance (Ip) and S-wave impedance (Is) which derived from well logs (P-wave velocity, S-wave velocity and density) is applied to investigate which inversion type would be sufficient enough to discriminate between gas sand, water sand and shale. Integration between spectral analysis, inversion results and Ip vs. Is crossplot cutoffs help to generate 3D lithofacies cubes, which used to extract gas sand and water sand geobodies, which is extremely wonderful for constructing facies depositional static model in area with unknown facies distribution and sand connectivity. Therefore de-risking hydrocarbon accumulation and GIIP estimation for the field became more confident for drilling new development wells.

  12. Hydrocarbons in mother rock in France. Initial report and complementary report (further to the law of the 13 July 2011 creating the national commission for orientation, follow-up and assessment of techniques of exploration and exploitation of liquid and gaseous hydrocarbons); Les hydrocarbures de roche-mere en France. Rapport initial et Rapport complementaire (suite a la loi du 13 juillet 2011 creant la Commission nationale d'orientation, de suivi et d'evaluation des techniques d'exploration et d'exploitation des hydrocarbures liquides et gazeux)

    Energy Technology Data Exchange (ETDEWEB)

    Leteurtrois, Jean-Pierre; Durville, Jean-Louis; Pillet, Didier; Gazeau, Jean-Claude; Bellec, Gilles; Catoire, Serge

    2012-02-15

    These reports aimed at studying the opportunities of development of mother-rock hydrocarbons as well as the associated economic opportunities and geopolitical challenges, exploitation techniques (efficiency, capacity of the French industry, impacts, costs, perspectives), their social and environmental challenges (notably with respect to such a development in France), and legal, regulatory and tax framework. These issues are addressed in the first report whereas the complementary report gives an overview of the evolution of the energy context, of hydrocarbon resources and technologies, of the main actors in the world, and of experiments in France

  13. Detailed north-south cross section showing environments of deposition, organic richness, and thermal maturities of lower Tertiary rocks in the Uinta Basin, Utah

    Science.gov (United States)

    Johnson, Ronald C.

    2014-01-01

    , and North Horn Formations since 1970. Datum for the cross section is sea level so that hydrocarbon source rocks and reservoir rocks could be integrated into the structural framework of the basin.

  14. Surface analogue outcrops of deep fractured basement reservoirs in extensional geological settings. Examples within active rift system (Uganda) and proximal passive margin (Morocco).

    Science.gov (United States)

    Walter, Bastien; Géraud, Yves; Diraison, Marc

    2014-05-01

    The important role of extensive brittle faults and related structures in the development of reservoirs has already been demonstrated, notably in initially low-porosity rocks such as basement rocks. Large varieties of deep-seated resources (e.g. water, hydrocarbons, geothermal energy) are recognized in fractured basement reservoirs. Brittle faults and fracture networks can develop sufficient volumes to allow storage and transfer of large amounts of fluids. Development of hydraulic model with dual-porosity implies the structural and petrophysical characterization of the basement. Drain porosity is located within the larger fault zones, which are the main fluid transfer channels. The storage porosity corresponds both to the matrix porosity and to the volume produced by the different fractures networks (e.g. tectonic, primary), which affect the whole reservoir rocks. Multi-scale genetic and geometric relationships between these deformation features support different orders of structural domains in a reservoir, from several tens of kilometers to few tens of meters. In subsurface, 3D seismic data in basement can be sufficient to characterize the largest first order of structural domains and bounding fault zones (thickness, main orientation, internal architecture, …). However, lower order structural blocks and fracture networks are harder to define. The only available data are 1D borehole electric imaging and are used to characterize the lowest order. Analog outcrop studies of basement rocks fill up this resolution gap and help the understanding of brittle deformation, definition of reservoir geometries and acquirement of reservoir properties. These geological outcrop studies give information about structural blocks of second and third order, getting close to the field scale. This allows to understand relationships between brittle structures geometry and factors controlling their development, such as the structural inheritance or the lithology (e.g. schistosity, primary

  15. Understanding and Mitigating Reservoir Compaction: an Experimental Study on Sand Aggregates

    Science.gov (United States)

    Schimmel, M.; Hangx, S.; Spiers, C. J.

    2016-12-01

    Fossil fuels continue to provide a source for energy, fuels for transport and chemicals for everyday items. However, adverse effects of decades of hydrocarbons production are increasingly impacting society and the environment. Production-driven reduction in reservoir pore pressure leads to a poro-elastic response of the reservoir, and in many occasions to time-dependent compaction (creep) of the reservoir. In turn, reservoir compaction may lead to surface subsidence and could potentially result in induced (micro)seismicity. To predict and mitigate the impact of fluid extraction, we need to understand production-driven reservoir compaction in highly porous siliciclastic rocks and explore potential mitigation strategies, for example, by using compaction-inhibiting injection fluids. As a first step, we investigate the effect of chemical environment on the compaction behaviour of sand aggregates, comparable to poorly consolidated, highly porous sandstones. The sand samples consist of loose aggregates of Beaujean quartz sand, sieved into a grainsize fraction of 180-212 µm. Uniaxial compaction experiments are performed at an axial stress of 35 MPa and temperature of 80°C, mimicking conditions of reservoirs buried at three kilometres depth. The chemical environment during creep is either vacuum-dry or CO2-dry, or fluid-saturated, with fluids consisting of distilled water, acid solution (CO2-saturated water), alkaline solution (pH 9), aluminium solution (pH 3) and solution with surfactants (i.e., AMP). Preliminary results show that compaction of quartz sand aggregates is promoted in a wet environment compared to a dry environment. It is inferred that deformation is controlled by subcritical crack growth when dry and stress corrosion cracking when wet, both resulting in grain failure and subsequent grain rearrangement. Fluids inhibiting these processes, have the potential to inhibit aggregate compaction.

  16. Dynamics of hydrocarbon vents: Focus on primary porosity

    Science.gov (United States)

    Johansen, C.; Shedd, W.; Abichou, T.; Pineda-Garcia, O.; Silva, M.; MacDonald, I. R.

    2012-12-01

    This study investigated the dynamics of hydrocarbon release by monitoring activity of a single vent at a 1215m deep site in the Gulf of Mexico (GC600). An autonomous camera, deployed by the submersible ALVIN, was programmed to capture a close-up image every 4 seconds for approximately 3.5 hours. The images provided the ability to study the gas hydrate outcrop site (that measured 5.2x16.3cm3) in an undisturbed state. The outcrop included an array of 38 tube-like vents through which dark brown oil bubbles are released at a rate ranging from 8 bubbles per minute to 0 bubbles per minute. The average release of bubbles from all the separate vents was 59.5 bubbles per minute, equating the total volume released to 106.38cm per minute. The rate of bubble release decreased toward the end of the observation interval, which coincided approximately with the tidal minimum. Ice worms (Hesiocaeca methanicola, Desbruyères & Toulmond, 1998) were abundant at the vent site. The image sequence showed the ice-worms actively moving in and out of burrows in the mound. It has been speculated that Hesiocaeca methanicola contribute to gas hydrate decomposition by creating burrows and depressions in the gas hydrate matrix (Fisher et al, 2000). Ice worm burrows could generate pathways for the passage of oil and gas through the gas hydrate mound. Gas hydrates commonly occur along active and/or passive continental margins (Kennicutt et al, 1988a). The release of oil and gas at this particular hydrocarbon seep site is along a passive continental margin, and controlled primarily by active salt tectonics as opposed to the movement of continental tectonic plates (Salvador, 1987). We propose a descriptive model governing the release of gas and oil from deep sub-bottom reservoirs at depths of 3000-5000m (MacDonald, 1998), through consolidated and unconsolidated sediments, and finally through gas hydrate deposits at the sea floor. The oil and gas escape from the source rock and/or reservoir through

  17. Reservoir Characterization using geostatistical and numerical modeling in GIS with noble gas geochemistry

    Science.gov (United States)

    Vasquez, D. A.; Swift, J. N.; Tan, S.; Darrah, T. H.

    2013-12-01

    The integration of precise geochemical analyses with quantitative engineering modeling into an interactive GIS system allows for a sophisticated and efficient method of reservoir engineering and characterization. Geographic Information Systems (GIS) is utilized as an advanced technique for oil field reservoir analysis by combining field engineering and geological/geochemical spatial datasets with the available systematic modeling and mapping methods to integrate the information into a spatially correlated first-hand approach in defining surface and subsurface characteristics. Three key methods of analysis include: 1) Geostatistical modeling to create a static and volumetric 3-dimensional representation of the geological body, 2) Numerical modeling to develop a dynamic and interactive 2-dimensional model of fluid flow across the reservoir and 3) Noble gas geochemistry to further define the physical conditions, components and history of the geologic system. Results thus far include using engineering algorithms for interpolating electrical well log properties across the field (spontaneous potential, resistivity) yielding a highly accurate and high-resolution 3D model of rock properties. Results so far also include using numerical finite difference methods (crank-nicholson) to solve for equations describing the distribution of pressure across field yielding a 2D simulation model of fluid flow across reservoir. Ongoing noble gas geochemistry results will also include determination of the source, thermal maturity and the extent/style of fluid migration (connectivity, continuity and directionality). Future work will include developing an inverse engineering algorithm to model for permeability, porosity and water saturation.This combination of new and efficient technological and analytical capabilities is geared to provide a better understanding of the field geology and hydrocarbon dynamics system with applications to determine the presence of hydrocarbon pay zones (or

  18. Hydrocarbon potential of Altiplano and northern Subandean, Bolivia

    Energy Technology Data Exchange (ETDEWEB)

    Edman, J.D.; Kirkpatrick, J.R.; Lindsey, D.D.; Lowell, J.D.; Cirbian, M.; Lopez, M.

    1989-03-01

    Seismic, stratigraphic, structural, and geochemical data from the Altiplano, northern Subandean, and northern plains of Bolivia were interpreted in order to evaluate the exploration potential of each province. Identification of three possible source rock intervals, primarily the Devonian and secondarily the Permian and Cretaceous, was used as the basis for recognizing active hydrocarbon systems. For those areas containing source intervals, their analysis revealed that possible reservoir and seal units range in age from Paleozoic to Tertiary; the majority of structures, however, are Eocene or younger. With these general concepts in mind, traps were identified in all three sedimentary provinces. In the northern Altiplano, the most prospective area is along the eastern margin near a southwest and west-vergent thrust belt where hanging-wall anticlines and a warped Eocene-Oligocene(.) unconformity surface form the most likely potential traps. In the central and southern Altiplano, both thrust-related and wrench-related structures present possible exploration targets. In the northern Subandean and Beni plains north of the Isiboro-Chapare area, traps can be classified into two broad groups. First, there are a wide variety of structural traps within the northern Subandean thrust belt, the most attractive of which are footwall structures that have been shielded from surface flushing by hanging-wall strata. Second, in the plains just northeast of the thrust belt, hydrocarbons sourced from the remnant Paleozoic basin may have migrated onto the Isarsama and Madidi highs.

  19. Methane clumped isotopes in the Songliao Basin (China): New insights into abiotic vs. biotic hydrocarbon formation

    Science.gov (United States)

    Shuai, Yanhua; Etiope, Giuseppe; Zhang, Shuichang; Douglas, Peter M. J.; Huang, Ling; Eiler, John M.

    2018-01-01

    Abiotic hydrocarbon gas, typically generated in serpentinized ultramafic rocks and crystalline shields, has important implications for the deep biosphere, petroleum systems, the carbon cycle and astrobiology. Distinguishing abiotic gas (produced by chemical reactions like Sabatier synthesis) from biotic gas (produced from degradation of organic matter or microbial activity) is sometimes challenging because their isotopic and molecular composition may overlap. Abiotic gas has been recognized in numerous locations on the Earth, although there are no confirmed instances where it is the dominant source of commercially valuable quantities in reservoir rocks. The deep hydrocarbon reservoirs of the Xujiaweizi Depression in the Songliao Basin (China) have been considered to host significant amounts of abiotic methane. Here we report methane clumped-isotope values (Δ18) and the isotopic composition of C1-C3 alkanes, CO2 and helium of five gas samples collected from those Xujiaweizi deep reservoirs. Some geochemical features of these samples resemble previously suggested identifiers of abiotic gas (13C-enriched CH4; decrease in 13C/12C ratio with increasing carbon number for the C1-C4 alkanes; abundant, apparently non-biogenic CO2; and mantle-derived helium). However, combining these constraints with new measurements of the clumped-isotope composition of methane and careful consideration of the geological context, suggests that the Xujiaweizi depression gas is dominantly, if not exclusively, thermogenic and derived from over-mature source rocks, i.e., from catagenesis of buried organic matter at high temperatures. Methane formation temperatures suggested by clumped-isotopes (167-213 °C) are lower than magmatic gas generation processes and consistent with the maturity of local source rocks. Also, there are no geological conditions (e.g., serpentinized ultramafic rocks) that may lead to high production of H2 and thus abiotic production of CH4 via CO2 reduction. We propose

  20. Bazhen Fm matured reservoir evaluation (West Siberia, Russia)

    Science.gov (United States)

    Parnachev, S.; Skripkin, A.; Baranov, V.; Zakharov, S.

    2015-02-01

    The depletion of the traditional sources of hydrocarbons leads to the situation when the biggest players of the oil and gas production market turn to unconventional reserves. Commercial shale oil and gas production levels in the USA have largely determined world prospects for oil and gas industry development. Russia takes one of the leading place in the world in terms of shale oil resources. The main source rock of the West Siberia, the biggest oil and gas basin in Russia under development, the Bazhen Fm and its stratigraphic and lithologic analogs, is located in the territory of over 1,000,000 square kilometers. Provided it has similar key properties (organic carbon content, porosity, permeability) with the deposits of the Bakken Fm and Green River Fm, USA, it is still extremely poorly described with laboratory methods. We have performed the laboratory analysis of core samples from a well drilled in Bazhen Fm deposits with matured organic matter (Tmax>435 °C). It was demonstrated the applicability of the improved steady-state gas flow method to evaluate the permeability of nanopermeable rocks. The role of natural fracturing in forming voids was determided that allows regarding potential Bazhen Fm reservoirs as systems with dual porosity and dual permeability.

  1. Bazhen Fm matured reservoir evaluation (West Siberia, Russia)

    International Nuclear Information System (INIS)

    Parnachev, S; Skripkin, A; Baranov, V; Zakharov, S

    2015-01-01

    The depletion of the traditional sources of hydrocarbons leads to the situation when the biggest players of the oil and gas production market turn to unconventional reserves. Commercial shale oil and gas production levels in the USA have largely determined world prospects for oil and gas industry development. Russia takes one of the leading place in the world in terms of shale oil resources. The main source rock of the West Siberia, the biggest oil and gas basin in Russia under development, the Bazhen Fm and its stratigraphic and lithologic analogs, is located in the territory of over 1,000,000 square kilometers. Provided it has similar key properties (organic carbon content, porosity, permeability) with the deposits of the Bakken Fm and Green River Fm, USA, it is still extremely poorly described with laboratory methods. We have performed the laboratory analysis of core samples from a well drilled in Bazhen Fm deposits with matured organic matter (T max >435 °C). It was demonstrated the applicability of the improved steady-state gas flow method to evaluate the permeability of nanopermeable rocks. The role of natural fracturing in forming voids was determided that allows regarding potential Bazhen Fm reservoirs as systems with dual porosity and dual permeability

  2. Purifying hydrocarbons

    Energy Technology Data Exchange (ETDEWEB)

    Demoulins, H D; Garner, F H

    1923-02-07

    Hydrocarbon distillates, including natural gases and vapors produced by cracking hydrocarbon oils, are desulfurized etc. by treating the vapor with an aqueous alkaline solution of an oxidizing agent. The hydrocarbons may be previously purified by sulfuric acid. In examples aqueous solutions of sodium or calcium hydrochlorite containing 1.5 to 5.0 grams per liter of available chlorine and sufficient alkali to give an excess of 0.1 percent in the spent reagent are preheated to the temperature of the vapor, and either sprayed or atomized into the vapors near the outlet of the dephlegmator or fractionating tower, or passed in countercurrent to the vapors through one or a series of scrubbers.

  3. Reducing Uncertainties in Hydrocarbon Prediction through Application of Elastic Domain

    Science.gov (United States)

    Shamsuddin, S. Z.; Hermana, M.; Ghosh, D. P.; Salim, A. M. A.

    2017-10-01

    The application of lithology and fluid indicators has helped the geophysicists to discriminate reservoirs to non-reservoirs from a field. This analysis is conducted to select the most suitable lithology and fluid indicator for the Malaysian basins that could lead to better eliminate pitfalls of amplitude. This paper uses different rock physics analysis such as elastic impedance, Lambda-Mu-Rho, and SQp-SQs attribute. Litho-elastic impedance log is generated by correlating the gamma ray log with extended elastic impedance log. The same application is used for fluid-elastic impedance by correlation of EEI log with water saturation or resistivity. The work is done on several well logging data collected from different fields in Malay basin and its neighbouring basin. There's an excellent separation between hydrocarbon sand and background shale for Well-1 from different cross-plot analysis. Meanwhile, the Well-2 shows good separation in LMR plot. The similar method is done on the Well-3 shows fair separation of silty sand and gas sand using SQp-SQs attribute which can be correlated with well log. Based on the point distribution histogram plot, different lithology and fluid can be separated clearly. Simultaneous seismic inversion results in acoustic impedance, Vp/Vs, SQp, and SQs volumes. There are many attributes available in the industry used to separate the lithology and fluid, however some of the methods are not suitable for the application to the basins in Malaysia.

  4. Multiple intersecting cohesive discontinuities in 3D reservoir geomechanics

    OpenAIRE

    Das, K. C.; Sandha, S.S.; Carol, Ignacio; Vargas, P.E.; Gonzalez, Nubia Aurora; Rodrigues, E.; Segura Segarra, José María; Lakshmikantha, Ramasesha Mookanahallipatna; Mello,, U.

    2013-01-01

    Reservoir Geomechanics is playing an increasingly important role in developing and producing hydrocarbon reserves. One of the main challenges in reservoir modeling is accurate and efficient simulation of arbitrary intersecting faults. In this paper, we propose a new formulation to model multiple intersecting cohesive discontinuities (faults) in reservoirs using the XFEM framework. This formulation involves construction of enrichment functions and computation of stiffness sub-matrices for bulk...

  5. Reservoir Identification: Parameter Characterization or Feature Classification

    Science.gov (United States)

    Cao, J.

    2017-12-01

    The ultimate goal of oil and gas exploration is to find the oil or gas reservoirs with industrial mining value. Therefore, the core task of modern oil and gas exploration is to identify oil or gas reservoirs on the seismic profiles. Traditionally, the reservoir is identify by seismic inversion of a series of physical parameters such as porosity, saturation, permeability, formation pressure, and so on. Due to the heterogeneity of the geological medium, the approximation of the inversion model and the incompleteness and noisy of the data, the inversion results are highly uncertain and must be calibrated or corrected with well data. In areas where there are few wells or no well, reservoir identification based on seismic inversion is high-risk. Reservoir identification is essentially a classification issue. In the identification process, the underground rocks are divided into reservoirs with industrial mining value and host rocks with non-industrial mining value. In addition to the traditional physical parameters classification, the classification may be achieved using one or a few comprehensive features. By introducing the concept of seismic-print, we have developed a new reservoir identification method based on seismic-print analysis. Furthermore, we explore the possibility to use deep leaning to discover the seismic-print characteristics of oil and gas reservoirs. Preliminary experiments have shown that the deep learning of seismic data could distinguish gas reservoirs from host rocks. The combination of both seismic-print analysis and seismic deep learning is expected to be a more robust reservoir identification method. The work was supported by NSFC under grant No. 41430323 and No. U1562219, and the National Key Research and Development Program under Grant No. 2016YFC0601

  6. Rock fragmentation

    Energy Technology Data Exchange (ETDEWEB)

    Brown, W.S.; Green, S.J.; Hakala, W.W.; Hustrulid, W.A.; Maurer, W.C. (eds.)

    1976-01-01

    Experts in rock mechanics, mining, excavation, drilling, tunneling and use of underground space met to discuss the relative merits of a wide variety of rock fragmentation schemes. Information is presented on novel rock fracturing techniques; tunneling using electron beams, thermocorer, electric spark drills, water jets, and diamond drills; and rock fracturing research needs for mining and underground construction. (LCL)

  7. Determinação das formas de nitrogênio e nitrogênio total em rochas-reservatório de petróleo por destilação com arraste de vapor e método do indofenol Determination of nitrogen forms and total nitrogen in petroleum reservoir rocks by steam distillation and the indophenol method

    Directory of Open Access Journals (Sweden)

    Lílian Irene Dias da Silva

    2006-02-01

    Full Text Available Several extraction procedures are described for the determination of exchangeable and fixed ammonium, nitrate + nitrite, total exchangeable nitrogen and total nitrogen in certified reference soils and petroleum reservoir rock samples by steam distillation and indophenol method. After improvement of the original distillation system, an increase in worker safety, a reduction in time consumption, a decrease of 73% in blank value and an analysis without ammonia loss, which could possibly occur, were achieved. The precision (RSD < 8%, n = 3 and the detection limit (9 mg kg-1 NH4+-N are better than those of published procedures.

  8. Sedimentary tectonic evolution and reservoir-forming conditions of the Dazhou–Kaijiang paleo-uplift, Sichuan Basin

    Directory of Open Access Journals (Sweden)

    Yueming Yang

    2016-12-01

    Full Text Available Great breakthrough recently achieved in the Sinian–Lower Paleozoic gas exploration in the Leshan–Longnüsi paleo-uplift, Sichuan Basin, has also made a common view reached, i.e., large-scale paleo-uplifts will be the most potential gas exploration target in the deep strata of this basin. Apart from the above-mentioned one, the other huge paleo-uplifts are all considered to be the ones formed in the post-Caledonian period, the impact of which, however, has rarely ever been discussed on the Sinian–Lower Paleozoic oil and gas reservoir formation. In view of this, based on outcrops, drilling and geophysical data, we analyzed the Sinian–Lower Paleozoic tectonic setting and sedimentary background in the East Sichuan Basin, studied the distribution rules of reservoirs and source rocks under the control of paleo-uplifts, and finally discussed, on the basis of structural evolution analysis, the conditions for the formation of Sinian–Lower Paleozoic gas reservoirs in this study area. The following findings were achieved. (1 The Dazhou–Kaijiang inherited uplift in NE Sichuan Basin which was developed before the Middle Cambrian controlled a large area of Sinian and Cambrian beach-facies development. (2 Beach-facies reservoirs were developed in the upper part of the paleo-uplift, while in the peripheral depression belts thick source rocks were developed like the Upper Sinian Doushantuo Fm and Lower Cambrian Qiongzhusi Fm, so there is a good source–reservoir assemblage. (3 Since the Permian epoch, the Dazhou–Kaijiang paleo-uplift had gradually become elevated from the slope zone, where the Permian oil generation peak occurred in the slope or lower and gentle uplift belts, while the Triassic gas generation peak occurred in the higher uplift belts, both with a favorable condition for hydrocarbon accumulation. (4 The lower structural layers, including the Lower Cambrian and its underlying strata, in the East Sichuan Basin, are now equipped with a

  9. Multilevel techniques for Reservoir Simulation

    DEFF Research Database (Denmark)

    Christensen, Max la Cour

    The subject of this thesis is the development, application and study of novel multilevel methods for the acceleration and improvement of reservoir simulation techniques. The motivation for addressing this topic is a need for more accurate predictions of porous media flow and the ability to carry...... Full Approximation Scheme) • Variational (Galerkin) upscaling • Linear solvers and preconditioners First, a nonlinear multigrid scheme in the form of the Full Approximation Scheme (FAS) is implemented and studied for a 3D three-phase compressible rock/fluids immiscible reservoir simulator...... is extended to include a hybrid strategy, where FAS is combined with Newton’s method to construct a multilevel nonlinear preconditioner. This method demonstrates high efficiency and robustness. Second, an improved IMPES formulated reservoir simulator is implemented using a novel variational upscaling approach...

  10. Understanding creep in sandstone reservoirs - theoretical deformation mechanism maps for pressure solution in granular materials

    Science.gov (United States)

    Hangx, Suzanne; Spiers, Christopher

    2014-05-01

    Subsurface exploitation of the Earth's natural resources removes the natural system from its chemical and physical equilibrium. As such, groundwater extraction and hydrocarbon production from subsurface reservoirs frequently causes surface subsidence and induces (micro)seismicity. These effects are not only a problem in onshore (e.g. Groningen, the Netherlands) and offshore hydrocarbon fields (e.g. Ekofisk, Norway), but also in urban areas with extensive groundwater pumping (e.g. Venice, Italy). It is known that fluid extraction inevitably leads to (poro)elastic compaction of reservoirs, hence subsidence and occasional fault reactivation, and causes significant technical, economic and ecological impact. However, such effects often exceed what is expected from purely elastic reservoir behaviour and may continue long after exploitation has ceased. This is most likely due to time-dependent compaction, or 'creep deformation', of such reservoirs, driven by the reduction in pore fluid pressure compared with the rock overburden. Given the societal and ecological impact of surface subsidence, as well as the current interest in developing geothermal energy and unconventional gas resources in densely populated areas, there is much need for obtaining better quantitative understanding of creep in sediments to improve the predictability of the impact of geo-energy and groundwater production. The key problem in developing a reliable, quantitative description of the creep behaviour of sediments, such as sands and sandstones, is that the operative deformation mechanisms are poorly known and poorly quantified. While grain-scale brittle fracturing plus intergranular sliding play an important role in the early stages of compaction, these time-independent, brittle-frictional processes give way to compaction creep on longer time-scales. Thermally-activated mass transfer processes, like pressure solution, can cause creep via dissolution of material at stressed grain contacts, grain

  11. An Analytical Model for Assessing Stability of Pre-Existing Faults in Caprock Caused by Fluid Injection and Extraction in a Reservoir

    Science.gov (United States)

    Wang, Lei; Bai, Bing; Li, Xiaochun; Liu, Mingze; Wu, Haiqing; Hu, Shaobin

    2016-07-01

    Induced seismicity and fault reactivation associated with fluid injection and depletion were reported in hydrocarbon, geothermal, and waste fluid injection fields worldwide. Here, we establish an analytical model to assess fault reactivation surrounding a reservoir during fluid injection and extraction that considers the stress concentrations at the fault tips and the effects of fault length. In this model, induced stress analysis in a full-space under the plane strain condition is implemented based on Eshelby's theory of inclusions in terms of a homogeneous, isotropic, and poroelastic medium. The stress intensity factor concept in linear elastic fracture mechanics is adopted as an instability criterion for pre-existing faults in surrounding rocks. To characterize the fault reactivation caused by fluid injection and extraction, we define a new index, the "fault reactivation factor" η, which can be interpreted as an index of fault stability in response to fluid pressure changes per unit within a reservoir resulting from injection or extraction. The critical fluid pressure change within a reservoir is also determined by the superposition principle using the in situ stress surrounding a fault. Our parameter sensitivity analyses show that the fault reactivation tendency is strongly sensitive to fault location, fault length, fault dip angle, and Poisson's ratio of the surrounding rock. Our case study demonstrates that the proposed model focuses on the mechanical behavior of the whole fault, unlike the conventional methodologies. The proposed method can be applied to engineering cases related to injection and depletion within a reservoir owing to its efficient computational codes implementation.

  12. Rupture Dynamics and Scaling Behavior of Hydraulically Stimulated Micro-Earthquakes in a Shale Reservoir

    Science.gov (United States)

    Viegas, G. F.; Urbancic, T.; Baig, A. M.

    2014-12-01

    In hydraulic fracturing completion programs fluids are injected under pressure into fractured rock formations to open escape pathways for trapped hydrocarbons along pre-existing and newly generated fractures. To characterize the failure process, we estimate static and dynamic source and rupture parameters, such as dynamic and static stress drop, radiated energy, seismic efficiency, failure modes, failure plane orientations and dimensions, and rupture velocity to investigate the rupture dynamics and scaling relations of micro-earthquakes induced during a hydraulic fracturing shale completion program in NE British Columbia, Canada. The relationships between the different parameters combined with the in-situ stress field and rock properties provide valuable information on the rupture process giving insights into the generation and development of the fracture network. Approximately 30,000 micro-earthquakes were recorded using three multi-sensor arrays of high frequency geophones temporarily placed close to the treatment area at reservoir depth (~2km). On average the events have low radiated energy, low dynamic stress and low seismic efficiency, consistent with the obtained slow rupture velocities. Events fail in overshoot mode (slip weakening failure model), with fluids lubricating faults and decreasing friction resistance. Events occurring in deeper formations tend to have faster rupture velocities and are more efficient in radiating energy. Variations in rupture velocity tend to correlate with variation in depth, fault azimuth and elapsed time, reflecting a dominance of the local stress field over other factors. Several regions with different characteristic failure modes are identifiable based on coherent stress drop, seismic efficiency, rupture velocities and fracture orientations. Variations of source parameters with rock rheology and hydro-fracture fluids are also observed. Our results suggest that the spatial and temporal distribution of events with similar

  13. Methane in the Northern West Siberian Basin. Generation, dynamics of the reservoirs and exchange with the atmosphere

    International Nuclear Information System (INIS)

    Cramer, B.

    1997-07-01

    Based on compositional data and isotope geochemistry natural gas in northern West Siberia can be divided into three groups. These are: natural gas in Jurassic rocks, natural gas in Neocomian rocks and natural gas from the Aptian to Cenomanian Pokur Formation. Natural gas in Jurassic rocks was generated thermogenically from rocks of the Jurassic Tyumen Formation. Natural gas in Neocomian rocks is also of thermogenic origin, possibly being generated from the organic matter of Lower Cretaceous sediments. The largest accumulation of natural gas occurs in sandstone reservoirs in the Pokur Formation. This gas can be described as a mixture between thermogenic gas from deeper strata and isotopically light almost pure methane. 98.6% of this gas consists of methane with an unusual isotope signature of -51.2 permille. It is not possible to explain the existence of this methane with established concepts of gas generation. A new model was developed to examine the possibility of a thermogenic origin of the isotopically light methane in early mature rocks of the Pokur Formation. Based on pyrolysis experiments and reaction kinetic calculations the model enables the simulation of stable carbon isotope ratios of hydrocarbon components in natural gas. The temperature dependent kinetic isotope fractionation is defined by a difference in the activation energies of 12 C-and 13 C-methane generation. The application of the new method to two coaly sandstones of the Pokur Formation results in a good correspondence between modelled carbon isotope ratios of δ 13 C values of methane in the reservoirs. The mass of methane thermogenically generated within the Pokur Formation under the gas field structures, however, is not sufficient to explain the mass of accumulated methane. (orig./SR) [de

  14. Purifying hydrocarbons

    Energy Technology Data Exchange (ETDEWEB)

    Dunstan, A E

    1918-06-03

    Ligroin, kerosene, and other distillates from petroleum and shale oil, are purified by treatment with a solution of a hypochlorite containing an excess of alkali. The hydrocarbon may be poured into brine, the mixture stirred, and an electric current passed through. Heat may be applied.

  15. Reservoir characterization of the Smackover Formation in southwest Alabama

    Energy Technology Data Exchange (ETDEWEB)

    Kopaska-Merkel, D.C.; Hall, D.R.; Mann, S.D.; Tew, B.H.

    1993-02-01

    The Upper Jurassic Smackover Formation is found in an arcuate belt in the subsurface from south Texas to panhandle Florida. The Smackover is the most prolific hydrocarbon-producing formation in Alabama and is an important hydrocarbon reservoir from Florida to Texas. In this report Smackover hydrocarbon reservoirs in southwest Alabama are described. Also, the nine enhanced- and improved-recovery projects that have been undertaken in the Smackover of Alabama are evaluated. The report concludes with recommendations about potential future enhanced- and improved-recovery projects in Smackover reservoirs in Alabama and an estimate of the potential volume of liquid hydrocarbons recoverable by enhanced- and improved-recovery methods from the Smackover of Alabama.

  16. The Importance of Water-Hydrocarbon Phase Equilibria During Reservoir Production and Drilling Operations Nouveaux défis liés à la présence d'équilibres eau-hydrocarbures lors des opérations de production et de forage

    Directory of Open Access Journals (Sweden)

    Zhou H.

    2006-12-01

    Full Text Available The inevitable presence of water in high pressure-high temperature reservoirs leads to a number of new challenges for petroleum engineers. A brief state of the art on water-hydrocarbon phase equilibria is presented. It appears that large amounts of water may be present in the hydrocarbon phase (up to 10% molar, and non negligible amounts of gas can dissolve in water. Based on experimental data, a large number of models have been developed. However, concerning the limitations of the data, caution is expressed about the correctness of some models. Recent studies have proven the usefulness of Henry's constants to predict hydrocarbon solubilities in water. The new challenges that are raised by this problem are discussed based on a number of recent publications. The water present in the hydrocarbon may lead to salt deposits downwell, and it must be taken into account in order to estimate the amount of gas in place. It can also result in modifications of the saturation pressure. Due to the presence of water, additional treatment is needed for pipe transport. On the other hand, the large amount of hydrocarbons dissolved in the water phase may result in a modification of the hydrocarbon composition, especially when reservoir pressure becomes very low. The increased toxicity of the water, containing either H2S or aromatics, can become a real burden for gas reservoirs in contact with aquifers or when disposing of production water. During drilling, large amounts of dissolved gas can become very hazardous, increasing the risk of eruption. A particular attention must be paid to acid gas injection in reservoirs, as the true effect of the injected gas may not be straightforward to predict. In conclusion, in light of the industrial importance of this information, some general guidelines are provided concerning additional data to be gathered and ideas for improving current models. La présence inévitable d'eau dans les réservoirs à hautes pression et temp

  17. Seismic reservoir characterization: how can multicomponent data help?

    International Nuclear Information System (INIS)

    Li, Xiang-Yang; Zhang, Yong-Gang

    2011-01-01

    This paper discusses the concepts of multicomponent seismology and how it can be applied to characterize hydrocarbon reservoirs, illustrated using a 3D three-component real-data example from southwest China. Hydrocarbon reservoirs formed from subtle lithological changes, such as stratigraphic traps, may be delineated from changes in P- and S-wave velocities and impedances, whilst hydrocarbon reservoirs containing aligned fractures are anisotropic. Examination of the resultant split shear waves can give us a better definition of their internal structures. Furthermore, frequency-dependent variations in seismic attributes derived from multicomponent data can provide us with vital information about fluid type and distribution. Current practice and various examples have demonstrated the undoubted potential of multicomponent seismic in reservoir characterization. Despite all this, there are still substantial challenges ahead. In particular, the improvement and interpretation of converted-wave imaging are major hurdles that need to be overcome before multicomponent seismic becomes a mainstream technology

  18. Seismic reservoir characterization: how can multicomponent data help?

    Science.gov (United States)

    Li, Xiang-Yang; Zhang, Yong-Gang

    2011-06-01

    This paper discusses the concepts of multicomponent seismology and how it can be applied to characterize hydrocarbon reservoirs, illustrated using a 3D three-component real-data example from southwest China. Hydrocarbon reservoirs formed from subtle lithological changes, such as stratigraphic traps, may be delineated from changes in P- and S-wave velocities and impedances, whilst hydrocarbon reservoirs containing aligned fractures are anisotropic. Examination of the resultant split shear waves can give us a better definition of their internal structures. Furthermore, frequency-dependent variations in seismic attributes derived from multicomponent data can provide us with vital information about fluid type and distribution. Current practice and various examples have demonstrated the undoubted potential of multicomponent seismic in reservoir characterization. Despite all this, there are still substantial challenges ahead. In particular, the improvement and interpretation of converted-wave imaging are major hurdles that need to be overcome before multicomponent seismic becomes a mainstream technology.

  19. The origin of high hydrocarbon groundwater in shallow Triassic aquifer in Northwest Guizhou, China.

    Science.gov (United States)

    Liu, Shan; Qi, Shihua; Luo, Zhaohui; Liu, Fangzhi; Ding, Yang; Huang, Huanfang; Chen, Zhihua; Cheng, Shenggao

    2018-02-01

    Original high hydrocarbon groundwater represents a kind of groundwater in which hydrocarbon concentration exceeds 0.05 mg/L. The original high hydrocarbon will significantly reduce the environment capacity of hydrocarbon and lead environmental problems. For the past 5 years, we have carried out for a long-term monitoring of groundwater in shallow Triassic aquifer in Northwest Guizhou, China. We found the concentration of petroleum hydrocarbon was always above 0.05 mg/L. The low-level anthropogenic contamination cannot produce high hydrocarbon groundwater in the area. By using hydrocarbon potential, geochemistry and biomarker characteristic in rocks and shallow groundwater, we carried out a comprehensive study in Dalongjing (DLJ) groundwater system to determine the hydrocarbon source. We found a simplex hydrogeology setting, high-level water-rock-hydrocarbon interaction and obviously original hydrocarbon groundwater in DLJ system. The concentration of petroleum hydrocarbon in shallow aquifer was found to increase with the strong water-rock interaction. Higher hydrocarbon potential was found in the upper of Guanling formation (T 2 g 3 ) and upper of Yongningzhen formation (T 1 yn 4 ). Heavily saturated carbon was observed from shallow groundwater, which presented similar distribution to those from rocks, especially from the deeper groundwater. These results indicated that the high concentrations of original hydrocarbon in groundwater could be due to the hydrocarbon release from corrosion and extraction out of strata over time.

  20. Simulation of Anisotropic Rock Damage for Geologic Fracturing

    Science.gov (United States)

    Busetti, S.; Xu, H.; Arson, C. F.

    2014-12-01

    A continuum damage model for differential stress-induced anisotropic crack formation and stiffness degradation is used to study geologic fracturing in rocks. The finite element-based model solves for deformation in the quasi-linear elastic domain and determines the six component damage tensor at each deformation increment. The model permits an isotropic or anisotropic intact or pre-damaged reference state, and the elasticity tensor evolves depending on the stress path. The damage variable, similar to Oda's fabric tensor, grows when the surface energy dissipated by three-dimensional opened cracks exceeds a threshold defined at the appropriate scale of the representative elementary volume (REV). At the laboratory or wellbore scale (1000m) scales the damaged REV reflects early natural fracturing (background or tectonic fracturing) or shear strain localization (fault process zone, fault-tip damage, etc.). The numerical model was recently benchmarked against triaxial stress-strain data from laboratory rock mechanics tests. However, the utility of the model to predict geologic fabric such as natural fracturing in hydrocarbon reservoirs was not fully explored. To test the ability of the model to predict geological fracturing, finite element simulations (Abaqus) of common geologic scenarios with known fracture patterns (borehole pressurization, folding, faulting) are simulated and the modeled damage tensor is compared against physical fracture observations. Simulated damage anisotropy is similar to that derived using fractured rock-mass upscaling techniques for pre-determined fracture patterns. This suggests that if model parameters are constrained with local data (e.g., lab, wellbore, or reservoir domain), forward modeling could be used to predict mechanical fabric at the relevant REV scale. This reference fabric also can be used as the starting material property to pre-condition subsequent deformation or fluid flow. Continuing efforts are to expand the present damage

  1. Heavy oil reservoir evaluation : performing an injection test using DST tools in the marine region of Mexico

    Energy Technology Data Exchange (ETDEWEB)

    Loaiza, J.; Ruiz, P. [Halliburton, Mexico City (Mexico); Barrera, D.; Gutierrez, F. [Pemex, Mexico City (Mexico)

    2010-07-01

    This paper described an injection test conducted to evaluate heavy oil reserves in an offshore area of Mexico. The drill-stem testing (DST) evaluation used a fluid injection technique in order to eliminate the need for artificial lift and coiled tubing. A pressure transient analysis method was used to determine the static pressure of the reservoir, effective hydrocarbon permeability, and formation damage. Boundary effects were also characterized. The total volume of the fluid injection was determined by analyzing various reservoir parameters. The timing of the shut-in procedure was determined by characterizing rock characteristics and fluids within the reservoir. The mobility and diffusivity relationships between the zones with the injection fluids and reservoir fluids were used to defined sweep fluids. A productivity analysis was used to predict various production scenarios. DST tools were then used to conduct a pressure-production assessment. Case histories were used to demonstrate the method. The studies showed that the method provides a cost-effective means of providing high quality data for productivity analyses. 4 refs., 2 tabs., 15 figs.

  2. Geological Characterisation of Depleted Oil and Gas Reservoirs for ...

    African Journals Online (AJOL)

    Dr Tse

    The reservoir formation consists of multilayered alternating beds of sandstone and shale cap rocks ... In the oil sector, Nigeria is one of the highest emitters ... Industrial emission and flaring .... integration of the 3D seismic data and wireline logs.

  3. Prediction of total organic carbon content in shale reservoir based on a new integrated hybrid neural network and conventional well logging curves

    Science.gov (United States)

    Zhu, Linqi; Zhang, Chong; Zhang, Chaomo; Wei, Yang; Zhou, Xueqing; Cheng, Yuan; Huang, Yuyang; Zhang, Le

    2018-06-01

    There is increasing interest in shale gas reservoirs due to their abundant reserves. As a key evaluation criterion, the total organic carbon content (TOC) of the reservoirs can reflect its hydrocarbon generation potential. The existing TOC calculation model is not very accurate and there is still the possibility for improvement. In this paper, an integrated hybrid neural network (IHNN) model is proposed for predicting the TOC. This is based on the fact that the TOC information on the low TOC reservoir, where the TOC is easy to evaluate, comes from a prediction problem, which is the inherent problem of the existing algorithm. By comparing the prediction models established in 132 rock samples in the shale gas reservoir within the Jiaoshiba area, it can be seen that the accuracy of the proposed IHNN model is much higher than that of the other prediction models. The mean square error of the samples, which were not joined to the established models, was reduced from 0.586 to 0.442. The results show that TOC prediction is easier after logging prediction has been improved. Furthermore, this paper puts forward the next research direction of the prediction model. The IHNN algorithm can help evaluate the TOC of a shale gas reservoir.

  4. Rock Art

    Science.gov (United States)

    Henn, Cynthia A.

    2004-01-01

    There are many interpretations for the symbols that are seen in rock art, but no decoding key has ever been discovered. This article describes one classroom's experiences with a lesson on rock art--making their rock art and developing their own personal symbols. This lesson allowed for creativity, while giving an opportunity for integration…

  5. Origin of late pleistocene formation water in Mexican oil reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Birkle, P. [Instituto de Investigaciones Electricas, Cuernavaca (Mexico)

    2004-07-01

    . For wellhead samples, a 20 liter-sampling-reagent was previously filled with N{sub 2}-gas for the collection and phase separation of the pressurized gas-water-crude oil mixture. No differences in {sup 14}C-concentrations were detected applying, both, conventional and AMS-techniques. In contradiction to the expected 'fossil age' of reservoir water as part of a stagnant hydraulic system, measured {sup 14}C-concentrations between 0.89 pmC and 31.86 pmC indicate a late Pleistocene-early Holocene, regional event for the infiltration of surface water into the reservoir. The variety in water mineralization from meteoric (TDS{sub max} = 0.5 g/l) to hyper-saline composition (TDS{sub max} = 338 g/l) is not caused by halite dissolution from adjacent salt domes, as shown by elevated Br/Cl ratios. In contrary, the linear correlation between {sup 18}O and Cl values reflect varying mixing proportions of two components - meteoric water and evaporated seawater. Instead of water/rock-interaction, evaporation of seawater at the surface prior to infiltration represents the principal process for fluid enrichment in {sup 18}O and chlorine, with maximum values of 17.2 %o and 228 g/l, respectively. The young residence time of formation water in Mexican oil reservoirs implies following: - The common assumption of 'hydraulically-frozen' reservoirs is not correct, as main descending fluid migration occurred during glacial period. Probably, major infiltration processes are related to periods with climatic changes and increased humidity - as observed for the adjacent Yucatan region in SE-Mexico during early-mid Holocene (6,000 yr BP) (Metcalfe et al. 2000) - with the probable transgression of Mexican Gulf seawater into the recent Mexican coastal plain. - The common hypothesis of hydrocarbon maturation within Jurassic organic-rich layers, and its subsequent expulsion and migration into Cretaceous/Tertiary sedimentary units must be expanded by a last-step-process: As glacial

  6. FRACTURED PETROLEUM RESERVOIRS

    Energy Technology Data Exchange (ETDEWEB)

    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

  7. Reservoir Modeling Combining Geostatistics with Markov Chain Monte Carlo Inversion

    DEFF Research Database (Denmark)

    Zunino, Andrea; Lange, Katrine; Melnikova, Yulia

    2014-01-01

    We present a study on the inversion of seismic reflection data generated from a synthetic reservoir model. Our aim is to invert directly for rock facies and porosity of the target reservoir zone. We solve this inverse problem using a Markov chain Monte Carlo (McMC) method to handle the nonlinear...

  8. Cracking hydrocarbons

    Energy Technology Data Exchange (ETDEWEB)

    Forwood, G F; Lane, M; Taplay, J G

    1921-10-07

    In cracking and hydrogenating hydrocarbon oils by passing their vapors together with steam over heated carbon derived from shale, wood, peat or other vegetable or animal matter, the gases from the condenser are freed from sulfuretted hydrogen, and preferably also from carbon dioxide, and passed together with oil vapors and steam through the retort. Carbon dioxide may be removed by passage through slaked lime, and sulfuretted hydrogen by means of hydrated oxide of iron. Vapors from high-boiling oils and those from low-boiling oils are passed alternately through the retort, so that carbon deposited from the high-boiling oils is used up during treatment of low-boiling oils.

  9. Distilling hydrocarbons

    Energy Technology Data Exchange (ETDEWEB)

    Bataafsche, N V; de Brey, J H.C.

    1918-10-30

    Hydrocarbons containing a very volatile constituent and less volatile constituents, such as casing-head gases, still gases from the distillation of crude petroleum and bituminous shale are separated into their constituents by rectification under pressure; a pressure of 20 atmospheres and limiting temperatures of 150/sup 0/C and 40/sup 0/C are mentioned as suitable. The mixture may be subjected to a preliminary treatment consisting in heating to a temperature below the maximum rectification temperature at a pressure greater than that proposed to be used in the rectification.

  10. The Time-Dependency of Deformation in Porous Carbonate Rocks

    Science.gov (United States)

    Kibikas, W. M.; Lisabeth, H. P.; Zhu, W.

    2016-12-01

    Porous carbonate rocks are natural reservoirs for freshwater and hydrocarbons. More recently, due to their potential for geothermal energy generation as well as carbon sequestration, there are renewed interests in better understanding of the deformation behavior of carbonate rocks. We conducted a series of deformation experiments to investigate the effects of strain rate and pore fluid chemistry on rock strength and transport properties of porous limestones. Indiana limestone samples with initial porosity of 16% are deformed at 25 °C under effective pressures of 10, 30, and 50 MPa. Under nominally dry conditions, the limestone samples are deformed under 3 different strain rates, 1.5 x 10-4 s-1, 1.5 x 10-5 s-1 and 1.5 x 10-6 s-1 respectively. The experimental results indicate that the mechanical behavior is both rate- and pressure-dependent. At low confining pressures, post-yielding deformation changes from predominantly strain softening to strain hardening as strain rate decreases. At high confining pressures, while all samples exhibit shear-enhanced compaction, decreasing strain rate leads to an increase in compaction. Slower strain rates enhance compaction at all confining pressure conditions. The rate-dependence of deformation behaviors of porous carbonate rocks at dry conditions indicates there is a strong visco-elastic coupling for the degradation of elastic modulus with increasing plastic deformation. In fluid saturated samples, inelastic strain of limestone is partitioned among low temperature plasticity, cataclasis and solution transport. Comparison of inelastic behaviors of samples deformed with distilled water and CO2-saturated aqueous solution as pore fluids provide experimental constraints on the relative activities of the various mechanisms. Detailed microstructural analysis is conducted to take into account the links between stress, microstructure and the inelastic behavior and failure mechanisms.

  11. Fourteenth workshop geothermal reservoir engineering: Proceedings

    Energy Technology Data Exchange (ETDEWEB)

    Ramey, H.J. Jr.; Kruger, P.; Horne, R.N.; Miller, F.G.; Brigham, W.E.; Cook, J.W.

    1989-01-01

    The Fourteenth Workshop on Geothermal Reservoir Engineering was held at Stanford University on January 24--26, 1989. Major areas of discussion include: (1) well testing; (2) various field results; (3) geoscience; (4) geochemistry; (5) reinjection; (6) hot dry rock; and (7) numerical modelling. For these workshop proceedings, individual papers are processed separately for the Energy Data Base.

  12. Fourteenth workshop geothermal reservoir engineering: Proceedings

    Energy Technology Data Exchange (ETDEWEB)

    Ramey, H.J. Jr.; Kruger, P.; Horne, R.N.; Miller, F.G.; Brigham, W.E.; Cook, J.W.

    1989-12-31

    The Fourteenth Workshop on Geothermal Reservoir Engineering was held at Stanford University on January 24--26, 1989. Major areas of discussion include: (1) well testing; (2) various field results; (3) geoscience; (4) geochemistry; (5) reinjection; (6) hot dry rock; and (7) numerical modelling. For these workshop proceedings, individual papers are processed separately for the Energy Data Base.

  13. Mathematical modelling on transport of petroleum hydrocarbons

    Indian Academy of Sciences (India)

    A brief theory has been included on the composition and transport of petroleum hydrocarbons following an onshore oil spill in order to demonstrate the level of complexity associated with the LNAPL dissolution mass transfer even in a classical porous medium. However, such studies in saturated fractured rocks are highly ...

  14. 'Escher' Rock

    Science.gov (United States)

    2004-01-01

    [figure removed for brevity, see original site] Chemical Changes in 'Endurance' Rocks [figure removed for brevity, see original site] Figure 1 This false-color image taken by NASA's Mars Exploration Rover Opportunity shows a rock dubbed 'Escher' on the southwestern slopes of 'Endurance Crater.' Scientists believe the rock's fractures, which divide the surface into polygons, may have been formed by one of several processes. They may have been caused by the impact that created Endurance Crater, or they might have arisen when water leftover from the rock's formation dried up. A third possibility is that much later, after the rock was formed, and after the crater was created, the rock became wet once again, then dried up and developed cracks. Opportunity has spent the last 14 sols investigating Escher, specifically the target dubbed 'Kirchner,' and other similar rocks with its scientific instruments. This image was taken on sol 208 (Aug. 24, 2004) by the rover's panoramic camera, using the 750-, 530- and 430-nanometer filters. The graph above shows that rocks located deeper into 'Endurance Crater' are chemically altered to a greater degree than rocks located higher up. This chemical alteration is believed to result from exposure to water. Specifically, the graph compares ratios of chemicals between the deep rock dubbed 'Escher,' and the more shallow rock called 'Virginia,' before (red and blue lines) and after (green line) the Mars Exploration Rover Opportunity drilled into the rocks. As the red and blue lines indicate, Escher's levels of chlorine relative to Virginia's went up, and sulfur down, before the rover dug a hole into the rocks. This implies that the surface of Escher has been chemically altered to a greater extent than the surface of Virginia. Scientists are still investigating the role water played in influencing this trend. These data were taken by the rover's alpha particle X-ray spectrometer.

  15. Estimation of reservoir fluid volumes through 4-D seismic analysis on Gullfaks

    Energy Technology Data Exchange (ETDEWEB)

    Veire, H.S.; Reymond, S.B.; Signer, C.; Tenneboe, P.O.; Soenneland, L.; Schlumberger, Geco-Prakla

    1998-12-31

    4-D seismic has the potential to monitor hydrocarbon movement in reservoirs during production, and could thereby supplement the predictions of reservoir parameters offered by the reservoir simulator. However 4-D seismic is often more band limited than the vertical resolution required in the reservoir model. As a consequence the seismic data holds a composite response from reservoir parameter changes during production so that the inversion becomes non-unique. A procedure where data from the reservoir model are integrated with seismic data will be presented. The potential of such a procedure is demonstrated through a case study from a recent 4-D survey over the Gullfaks field. 2 figs.

  16. Paragenetic evolution of reservoir facies, Middle Triassic Halfway Formation, PeeJay Field, northeastern British Columbia: controls on reservoir quality

    Energy Technology Data Exchange (ETDEWEB)

    Caplan, M. L. [Alberta Univ., Dept. of Earth and Atmospheric Sciences, Edmonton, AB (Canada); Moslow, T. F. [Ulster Petroleum Ltd., Calgary, AB (Canada)

    1998-09-01

    Because of the obvious importance of reservoir quality to reservoir performance, diagenetic controls on reservoir quality of Middle Triassic reservoir facies are investigated by comparing two reservoir lithofacies. The implications of porosity structure on the efficiency of primary and secondary hydrocarbon recovery are also assessed. Halfway reservoir facies are composed of bioclastic grainstones (lithofacies G) and litharenites/sublitharenites (lithofacies H), both of which are interpreted as tidal inlet fills. Although paragenetic evolution was similar for the two reservoir facies, subtle differences in reservoir quality are discernible. These are controlled by sedimentary structures, porosity type, grain constituents, and degree of cementation. Reservoir quality in lithofacies G is a function of connectivity of the pore network. In lithofacies H, secondary granular porosity creates a more homogeneous interconnected pore system, wide pore throats and low aspect ratios. The high porosity and low permeability values of the bioclastic grainstones are suspected to cause inefficient flushing of hydrocarbons during waterflooding. However, it is suggested that recovery may be enhanced by induced hydraulic fracturing and acidization of lower permeability calcareous cemented zones. 52 refs., 15 figs.

  17. Continuous distillation of oil-bearing rocks

    Energy Technology Data Exchange (ETDEWEB)

    1923-11-14

    A continuous process of distilling petroleum-bearing, asphaltic, or bituminous rocks to free bitumen is characterized by vaporizing hydrocarbons solid, pasty, or liquid from petroleum-containing asphaltic or bituminous rocks to free bitumen without ever reaching the temperatures at which they can produce decomposition, the necessary heat being furnished by combustion of part of the hydrocarbons of the treated rocks. A furnace for carrying out the process of claim 1 is characterized by consisting of a cavity lined inside with reflector, of variable section and with a throat at the upper part for charging the material to be treated and means for blowing the lower part of the furnace with the air necessary for combustion and inert gas for regulating the combustion and removal of the hydrocarbons.

  18. A feasibility study on the expected seismic AVA signatures of deep fractured geothermal reservoirs in an intrusive basement

    International Nuclear Information System (INIS)

    Aleardi, Mattia; Mazzotti, Alfredo

    2014-01-01

    The deep geothermal reservoirs in the Larderello-Travale field (southern Tuscany) are found in intensively fractured portions of intrusive/metamorphic rocks. Therefore, the geothermal exploration has been in search of possible fracture signatures that could be retrieved from the analysis of geophysical data. In the present work we assess the feasibility of finding seismic markers in the pre-stack domain which may pinpoint fractured levels. Thanks to the availability of data from boreholes that ENEL GreenPower drilled in the deep intrusive basement of this geothermal field, we derived the expected amplitude versus angle (AVA) responses of the vapour reservoirs found in some intensely, but very localized, fractured volumes within the massive rocks. The information we have available limit us to build 1D elastic and isotropic models only and thus anisotropy effects related to the presence of fractures cannot be properly modelled. We analysed the velocities and the density logs pertaining to three wells which reached five deep fractured zones in the basement. The AVA response of the fractured intervals is modelled downscaling the log data to seismic scale and comparing the analytical AVA response (computed with the Aki and Richards approximation) and the AVA extracted from a synthetic common mid point (calculated making use of a reflectivity algorithm). The results show that the amplitude of the reflections from the fractured level is characterized by negative values at vertical incidence and by decreasing absolute amplitudes with the increase of the source to receiver offset. This contrasts with many observations from hydrocarbon exploration in clastic reservoirs where gas-sand reflections often exhibit negative amplitudes at short offsets but increasing absolute amplitudes for increasing source to receiver offsets. Thereby, some common AVA attributes considered in silicoclastic lithologies would lead to erroneous fracture localization. For this reason we propose a

  19. Hydrocarbon oils

    Energy Technology Data Exchange (ETDEWEB)

    Foorwood, G F; Taplay, J G

    1916-12-12

    Hydrocarbon oils are hydrogenated, cracked, or treated for the removal of sulfur by bringing their vapors mixed with steam at temperatures between 450 and 600/sup 0/C into contact with a form of carbon that is capable of decomposing steam with the production of nascent hydrogen at those temperatures. The forms of carbon used include lamp-black, soot, charcoals derived from wood, cellulose, and lignite, and carbons obtained by carbonizing oil residues and other organic bodies at temperatures below 600/sup 0/C. The process is applied to the treatment of coal oil, shale oil, petroleum, and lignite oil. In examples, kerosene is cracked at 570/sup 0/C, cracked spirit is hydrogenated at 500/sup 0/C, and shale spirit is desulfurized at 530/sup 0/C. The products are led to a condenser and thence to a scrubber, where they are washed with creosote oil. After desulfurization, the products are washed with dilute caustic soda to remove sulfurretted hydrogen.

  20. Hydrocarbon exploration

    Energy Technology Data Exchange (ETDEWEB)

    Lerche, I. (South Carolina Univ., Columbia, SC (United States). Dept. of Geological Sciences)

    1993-01-01

    This special issue of the journal examines various aspects of the on-going search for hydrocarbons, ranging from frontier basins where little data are available, to more mature areas where considerable data are available. The incentives underlying the search for oil are roughly: the social, economic and industrial needs of a nation; the incentive of a corporation to be profitable; and the personal incentives of individuals in the oil industry and governments, which range from financial wealth to power and which are as diverse as the individuals who are involved. From a geopolitical perspective, the needs, requirements, goals, strategies, and philosophies of nations, and groups of nations, also impact on the oil exploration game. Strategies that have been employed have ranged from boycott to austerity and rationing, to physical intervention, to global ''flooding'' with oil by over-production. (author)

  1. Multi-data reservoir history matching for enhanced reservoir forecasting and uncertainty quantification

    KAUST Repository

    Katterbauer, Klemens

    2015-04-01

    Reservoir simulations and history matching are critical for fine-tuning reservoir production strategies, improving understanding of the subsurface formation, and forecasting remaining reserves. Production data have long been incorporated for adjusting reservoir parameters. However, the sparse spatial sampling of this data set has posed a significant challenge for efficiently reducing uncertainty of reservoir parameters. Seismic, electromagnetic, gravity and InSAR techniques have found widespread applications in enhancing exploration for oil and gas and monitoring reservoirs. These data have however been interpreted and analyzed mostly separately, rarely exploiting the synergy effects that could result from combining them. We present a multi-data ensemble Kalman filter-based history matching framework for the simultaneous incorporation of various reservoir data such as seismic, electromagnetics, gravimetry and InSAR for best possible characterization of the reservoir formation. We apply an ensemble-based sensitivity method to evaluate the impact of each observation on the estimated reservoir parameters. Numerical experiments for different test cases demonstrate considerable matching enhancements when integrating all data sets in the history matching process. Results from the sensitivity analysis further suggest that electromagnetic data exhibit the strongest impact on the matching enhancements due to their strong differentiation between water fronts and hydrocarbons in the test cases.

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

    Science.gov (United States)

    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

  3. Modeling Tools for Drilling, Reservoir Navigation, and Formation Evaluation

    Directory of Open Access Journals (Sweden)

    Sushant Dutta

    2012-06-01

    Full Text Available The oil and gas industry routinely uses borehole tools for measuring or logging rock and fluid properties of geologic formations to locate hydrocarbons and maximize their production. Pore fluids in formations of interest are usually hydrocarbons or water. Resistivity logging is based on the fact that oil and gas have a substantially higher resistivity than water. The first resistivity log was acquired in 1927, and resistivity logging is still the foremost measurement used for drilling and evaluation. However, the acquisition and interpretation of resistivity logging data has grown in complexity over the years. Resistivity logging tools operate in a wide range of frequencies (from DC to GHz and encounter extremely high (several orders of magnitude conductivity contrast between the metal mandrel of the tool and the geologic formation. Typical challenges include arbitrary angles of tool inclination, full tensor electric and magnetic field measurements, and interpretation of complicated anisotropic formation properties. These challenges combine to form some of the most intractable computational electromagnetic problems in the world. Reliable, fast, and convenient numerical modeling of logging tool responses is critical for tool design, sensor optimization, virtual prototyping, and log data inversion. This spectrum of applications necessitates both depth and breadth of modeling software—from blazing fast one-dimensional (1-D modeling codes to advanced threedimensional (3-D modeling software, and from in-house developed codes to commercial modeling packages. In this paper, with the help of several examples, we demonstrate our approach for using different modeling software to address different drilling and evaluation applications. In one example, fast 1-D modeling provides proactive geosteering information from a deep-reading azimuthal propagation resistivity measurement. In the second example, a 3-D model with multiple vertical resistive fractures

  4. Coupling a fluid flow simulation with a geomechanical model of a fractured reservoir

    OpenAIRE

    Segura Segarra, José María; Paz, C.M.; de Bayser, M.; Zhang, J.; Bryant, P.W.; Gonzalez, Nubia Aurora; Rodrigues, E.; Vargas, P.E.; Carol, Ignacio; Lakshmikantha, Ramasesha Mookanahallipatna; Das, K. C.; Sandha, S.S.; Cerqueira, R.; Mello,, U.

    2013-01-01

    Improving the reliability of integrated reservoir development planning and addressing subsidence, fault reactivation and other environmental impacts, requires increasingly sophisticated geomechanical models, especially in the case of fractured reservoirs where fracture deformation is strongly coupled with its permeability change. Reservoir simulation has historically treated any geomechanical effects by means of a rock compressibility term/table, which can be improved by simulating the actual...

  5. Geologic assessment of undiscovered oil and gas resources—Lower Cretaceous Albian to Upper Cretaceous Cenomanian carbonate rocks of the Fredericksburg and Washita Groups, United States Gulf of Mexico Coastal Plain and State Waters

    Science.gov (United States)

    Swanson, Sharon M.; Enomoto, Catherine B.; Dennen, Kristin O.; Valentine, Brett J.; Cahan, Steven M.

    2017-02-10

    In 2010, the U.S. Geological Survey (USGS) assessed Lower Cretaceous Albian to Upper Cretaceous Cenomanian carbonate rocks of the Fredericksburg and Washita Groups and their equivalent units for technically recoverable, undiscovered hydrocarbon resources underlying onshore lands and State Waters of the Gulf Coast region of the United States. This assessment was based on a geologic model that incorporates the Upper Jurassic-Cretaceous-Tertiary Composite Total Petroleum System (TPS) of the Gulf of Mexico basin; the TPS was defined previously by the USGS assessment team in the assessment of undiscovered hydrocarbon resources in Tertiary strata of the Gulf Coast region in 2007. One conventional assessment unit (AU), which extends from south Texas to the Florida panhandle, was defined: the Fredericksburg-Buda Carbonate Platform-Reef Gas and Oil AU. The assessed stratigraphic interval includes the Edwards Limestone of the Fredericksburg Group and the Georgetown and Buda Limestones of the Washita Group. The following factors were evaluated to define the AU and estimate oil and gas resources: potential source rocks, hydrocarbon migration, reservoir porosity and permeability, traps and seals, structural features, paleoenvironments (back-reef lagoon, reef, and fore-reef environments), and the potential for water washing of hydrocarbons near outcrop areas.In Texas and Louisiana, the downdip boundary of the AU was defined as a line that extends 10 miles downdip of the Lower Cretaceous shelf margin to include potential reef-talus hydrocarbon reservoirs. In Mississippi, Alabama, and the panhandle area of Florida, where the Lower Cretaceous shelf margin extends offshore, the downdip boundary was defined by the offshore boundary of State Waters. Updip boundaries of the AU were drawn based on the updip extent of carbonate rocks within the assessed interval, the presence of basin-margin fault zones, and the presence of producing wells. Other factors evaluated were the middle

  6. Integrated Modeling and Carbonate Reservoir Analysis, Upper Jurassic Smackover Formation, Fishpond Field, Southwest Alabama

    Science.gov (United States)

    Owen, Alexander Emory

    This field case study focuses on Upper Jurassic (Oxfordian) Smackover hydrocarbon reservoir characterization, modeling and evaluation at Fishpond Field, Escambia County, Alabama, eastern Gulf Coastal Plain of North America. The field is located in the Conecuh Embayment area, south of the Little Cedar Creek Field in Conecuh County and east of Appleton Field in Escambia County. In the Conecuh Embayment, Smackover microbial buildups commonly developed on Paleozoic basement paleohighs in an inner to middle carbonate ramp setting. The microbial and associated facies identified in Fishpond Field are: (F-1) peloidal wackestone, (F-2) peloidal packstone, (F-3) peloidal grainstone, (F-4) peloidal grainstone/packstone, (F-5) microbially-influenced wackestone, (F-6) microbially-influenced packstone, (F-7) microbial boundstone, (F-8) oolitic grainstone, (F-9) shale, and (F-10) dolomitized wackestone/packstone. The Smackover section consists of an alternation of carbonate facies, including F-1 through F-8. The repetitive vertical trend in facies indicates variations in depositional conditions in the area as a result of changes in water depth, energy conditions, salinity, and/or water chemistry due to temporal variations or changes in relative sea level. Accommodation for sediment accumulation also was produced by a change in base level due to differential movement of basement rocks as a result of faulting and/or subsidence due to burial compaction and extension. These changes in base level contributed to the development of a microbial buildup that ranges between 130-165 ft in thickness. The Fishpond Field carbonate reservoir includes a lower microbial buildup interval, a middle grainstone/packstone interval and an upper microbial buildup interval. The Fishpond Field has sedimentary and petroleum system characteristics similar to the neighboring Appleton and Little Cedar Creek Fields, but also has distinct differences from these Smackover fields. The characteristics of the

  7. Frequency–amplitude range of hydrocarbon microtremors and a discussion on their source

    International Nuclear Information System (INIS)

    Gerivani, H; Hafezi Moghaddas, N; Ghafoori, M; Lashkaripour, G R; Haghshenas, E

    2012-01-01

    Recently, some studies have suggested using ambient noise as a tool for hydrocarbon reservoir investigation. This new passive seismic technique, named HyMas, is based on the positive energy anomaly in data spectra between 1 to 6 Hz for microtremor measurements over reservoirs, which are called hydrocarbon microtremors. Despite the acceptable results obtained by the HyMas technique, there are many unknowns, especially concerning the source and generation mechanism of hydrocarbon microtremors and the relations between reservoir characteristics and the attributes of hydrocarbon microtremors. In this study we tried to find the relations between reservoir characteristics, including fluid content and depth, for 12 sites around the world with hydrocarbon microtremor attributes, including peak amplitude and frequency. Based on the power spectral density curves of these 12 reservoirs, a frequency–amplitude range is also proposed as a criterion for separating hydrocarbon microtremors from local noise not related to reservoirs. Finally, the source of the hydrocarbon microtremors is discussed and tidal displacement is suggested as a probable agent for the generation of these anomalies. (paper)

  8. Smart Waterflooding in Carbonate Reservoirs

    DEFF Research Database (Denmark)

    Zahid, Adeel

    brine solutions regarding phase behavior and viscosity measurements. This difference is attributed to the difference in composition of the different crude oils. More experiments are carried out in order to understand mechanisms of the crude oil viscosity reduction and emulsion formation. We observed...... with and without aging. The total oil recovery, recovery rate and interaction mechanisms of ions with rock were studied for different injected fluids under different temperatures and wettability conditions. Experimental results demonstrate that the oil recovery mechanism under high salinity seawater flooding...... phase could be the possible reasons for the observed increase in oil recovery with sulfate ions at high temperature in chalk reservoirs, besides the mechanism of the rock wettability alteration. * Crude oil/brine interaction study suggests that viscosity reduction for crude oil in contact with brine...

  9. Unsaturated medium hydrocarbons pollution evaluation

    International Nuclear Information System (INIS)

    Di Luise, G.

    1991-01-01

    When the so called porous unsaturated medium, that's the vertical subsoil section between both the ground and water-table level, is interested by a hydrocarbons spill, the problem to evaluate the pollution becomes difficult: considering, essentially, the natural coexistence in it of two fluids, air and water, and the interactions between them. This paper reports that the problems tend to increase when a third fluid, the pollutant, immiscible with water, is introduced into the medium: a three-phases flow, which presents several analogies with the flow conditions present in an oil-reservoir, will be established. In such a situation, it would be very useful to handle the matter by the commonly used parameters in the oil reservoirs studies such as: residual saturation, relative permeability, phases mobility, to derive a first semiquantitative estimation of the pollution. The subsoil pollution form hydrocarbons agents is one of the worldwide more diffused causes of contamination: such events are generally referable to two main effects: accidental (oil pipeline breakdowns, e.g.), and continuous (underground tanks breaks, industrial plants leakages, e.g.)

  10. Constructing reservoir-scale 3D geomechanical FE-models. A refined workflow for model generation and calculation

    Energy Technology Data Exchange (ETDEWEB)

    Fischer, K.; Henk, A. [Technische Univ. Darmstadt (Germany). Inst. fuer Angewandte Geowissenschaften

    2013-08-01

    The tectonic stress field strongly affects the optimal exploitation of conventional and unconventional hydrocarbon reservoirs. Amongst others, wellbore stability, orientation of hydraulically induced fractures and - particularly in fractured reservoirs - permeability anisotropies depend on the magnitudes and orientations of the recent stresses. Geomechanical reservoir models can provide unique insights into the tectonic stress field revealing the local perturbations resulting from faults and lithological changes. In order to provide robust predictions, such numerical models are based on the finite element (FE) method and account for the complexities of real reservoirs with respect to subsurface geometry, inhomogeneous material distribution and nonlinear rock mechanical behavior. We present a refined workflow for geomechanical reservoir modeling which allows for an easier set-up of the model geometry, high resolution submodels and faster calculation times due to element savings in the load frame. Transferring the reservoir geometry from the geological subsurface model, e.g., a Petrel {sup registered} project, to the FE model represents a special challenge as the faults are discontinuities in the numerical model and no direct interface exists between the two software packages used. Point clouds displaying faults and lithostratigraphic horizons can be used for geometry transfer but this labor-intensive approach is not feasible for complex field-scale models with numerous faults. Instead, so-called Coon's patches based on horizon lines, i.e. the intersection lines between horizons and faults, are well suited to re-generate the various surfaces in the FE software while maintaining their topology. High-resolution submodels of individual fault blocks can be incorporated into the field-scale model. This allows to consider both a locally refined mechanical stratigraphy and the impact of the large-scale fault pattern. A pressure load on top of the model represents the

  11. Recreating Rocks

    DEFF Research Database (Denmark)

    Posth, Nicole R

    2008-01-01

    Nicole Posth and colleagues spent a month touring South African rock formations in their quest to understand the origin of ancient iron and silicate layers.......Nicole Posth and colleagues spent a month touring South African rock formations in their quest to understand the origin of ancient iron and silicate layers....

  12. Hot dry rock heat mining

    International Nuclear Information System (INIS)

    Duchane, D.V.

    1992-01-01

    Geothermal energy utilizing fluids from natural sources is currently exploited on a commercial scale at sites around the world. A much greater geothermal resource exists, however, in the form of hot rock at depth which is essentially dry. This hot dry rock (HDR) resource is found almost everywhere, but the depth at which usefully high temperatures are reached varies from place to place. The technology to mine the thermal energy from HDR has been under development for a number of years. Using techniques adapted from the petroleum industry, water is pumped at high pressure down an injection well to a region of usefully hot rock. The pressure forces open natural joints to form a reservoir consisting of a small amount of water dispensed in a large volume of hot rock. This reservoir is tapped by second well located at some distance from the first, and the heated water is brought to the surface where its thermal energy is extracted. The same water is then recirculated to mine more heat. Economic studies have indicated that it may be possible to produce electricity at competitive prices today in regions where hot rock is found relatively close to the surface

  13. Multi Data Reservoir History Matching using the Ensemble Kalman Filter

    KAUST Repository

    Katterbauer, Klemens

    2015-05-01

    Reservoir history matching is becoming increasingly important with the growing demand for higher quality formation characterization and forecasting and the increased complexity and expenses for modern hydrocarbon exploration projects. History matching has long been dominated by adjusting reservoir parameters based solely on well data whose spatial sparse sampling has been a challenge for characterizing the flow properties in areas away from the wells. Geophysical data are widely collected nowadays for reservoir monitoring purposes, but has not yet been fully integrated into history matching and forecasting fluid flow. In this thesis, I present a pioneering approach towards incorporating different time-lapse geophysical data together for enhancing reservoir history matching and uncertainty quantification. The thesis provides several approaches to efficiently integrate multiple geophysical data, analyze the sensitivity of the history matches to observation noise, and examine the framework’s performance in several settings, such as the Norne field in Norway. The results demonstrate the significant improvements in reservoir forecasting and characterization and the synergy effects encountered between the different geophysical data. In particular, the joint use of electromagnetic and seismic data improves the accuracy of forecasting fluid properties, and the usage of electromagnetic data has led to considerably better estimates of hydrocarbon fluid components. For volatile oil and gas reservoirs the joint integration of gravimetric and InSAR data has shown to be beneficial in detecting the influx of water and thereby improving the recovery rate. Summarizing, this thesis makes an important contribution towards integrated reservoir management and multiphysics integration for reservoir history matching.

  14. Importance of water Influx and waterflooding in Gas condensate reservoir

    OpenAIRE

    Ali, Faizan

    2014-01-01

    The possibility of losing valuable liquid and lower gas well deliverability have made gas condensate reservoirs very important and extra emphasizes are made to optimize hydrocarbon recovery from a gas condensate reservoir. Methods like methanol treatments, wettability alteration and hydraulic fracturing are done to restore the well deliverability by removing or by passing the condensate blockage region. The above mentioned methods are applied in the near wellbore region and only improve the w...

  15. Discovery and basic characteristics of high-quality source rocks found in the Yuertusi Formation of the Cambrian in Tarim Basin, China

    Directory of Open Access Journals (Sweden)

    Guangyou Zhu

    2016-02-01

    Full Text Available The Upper Paleozoic strata of the Tarim Basin have abundant resources of marine oil and gas. In the Tahe area, Halahatang area, and Tazhong area of the basin, many large-scale oilfields have been found. These oilfields have a confirmed oil and gas reserves worth more than 2.5 billion tons and have completed the annual output of more than 14 million tons of marine oil and gas equivalent. The belief that the only main hydrocarbon source rocks are of the Cambrian or Ordovician is still controversial. Chemists have made significant progress and have effectively lead the oil and gas exploration in Tarim Basin. Due to the complexity of the basin and the limitation of samples, the research work, and fine contrast is restricted. In this article, we investigated the Cambrian strata outcrop of Tarim Basin in detail. By analyzing a lot of outcrops, high-quality hydrocarbon source rocks of Yuertusi Formation have been found in more than 10 outcrop points in Aksu region. The source rocks' lithology is black shale with total organic carbon (TOC content that ranges between 2% and 16%. Total organic carbon (TOC of the black shale layer could be as much as 4%–16%, especially in the outcrops of the Yutixi and Shiairike. This by far is the best marine hydrocarbon source rock that was found in China. The source rocks were distributed consistently in the Aksu region, the thickness of which is about 10–15 m. It was formed in a sedimentary environment of a middle gentle slope to a low gentle slope. Organic matter enrichment is controlled by the upwelling currents. The thick strata of dolostone that developed in the Xiaoerblak Formation are considered to be good reservoirs of the beach and microbial reef in the upper strata of Yuertusi Formation. No hydrocarbon source rocks have been found in the outcrop of Xiaoerblak Formation. The thick strata of gyprock and mudstone development are a set of satisfactory cap layer in the Lower Cambrian. This hydrocarbon

  16. Smart waterflooding in carbonate reservoirs

    Energy Technology Data Exchange (ETDEWEB)

    Zahid, A.

    2012-02-15

    During the last decade, smart waterflooding has been developed into an emerging EOR technology both for carbonate and sandstone reservoirs that does not require toxic or expensive chemicals. Although it is widely accepted that different salinity brines may increase the oil recovery for carbonate reservoirs, understanding of the mechanism of this increase is still developing. To understand this smart waterflooding process, an extensive research has been carried out covering a broad range of disciplines within surface chemistry, thermodynamics of crude oil and brine, as well as their behavior in porous media. The main conclusion of most previous studies was that it is the rock wettability alteration towards more water wetting condition that helps improving the oil recovery. In the first step of this project, we focused on verifying this conclusion. Coreflooding experiments were carried out using Stevens Klint outcrop chalk core plugs with brines without sulfate, as well as brines containing sulfate in different concentrations. The effects of temperature, injection rate, crude oil composition and different sulfate concentrations on the total oil recovery and the recovery rate were investigated. Experimental results clearly indicate improvement of the oil recovery without wettability alteration. At the second step of this project, we studied crude oil/brine interactions under different temperatures, pressures and salinity conditions in order to understand mechanisms behind the high salinity waterflooding. Our results show, in particular that sulfate ions may help decreasing the crude oil viscosity or formation of, seemingly, an emulsion phase between sulfate-enriched brine and oil at high temperature and pressure. Experimental results indicate that crude oils interact differently with the same brine solutions regarding phase behavior and viscosity measurements. This difference is attributed to the difference in composition of the different crude oils. More experiments

  17. Characterization of fracture reservoirs using static and dynamic data: From sonic and 3D seismic to permeability distribution. Annual report, March 1, 1996--February 28, 1997

    Energy Technology Data Exchange (ETDEWEB)

    Parra, J.O.; Collier, H.A.; Owen, T.E. [and others

    1997-06-01

    In low porosity, low permeability zones, natural fractures are the primary source of permeability which affect both production and injection of fluids. The open fractures do not contribute much to porosity, but they provide an increased drainage network to any porosity. They also may connect the borehole to remote zones of better reservoir characteristics. An important approach to characterizing the fracture orientation and fracture permeability of reservoir formations is one based on the effects of such conditions on the propagation of acoustic and seismic waves in the rock. The project is a study directed toward the evaluation of acoustic logging and 3D-seismic measurement techniques as well as fluid flow and transport methods for mapping permeability anisotropy and other petrophysical parameters for the understanding of the reservoir fracture systems and associated fluid dynamics. The principal application of these measurement techniques and methods is to identify and investigate the propagation characteristics of acoustic and seismic waves in the Twin Creek hydrocarbon reservoir owned by Union Pacific Resources (UPR) and to characterize the fracture permeability distribution using production data. This site is located in the overthrust area of Utah and Wyoming. UPR drilled six horizontal wells, and presently UPR has two rigs running with many established drill hole locations. In addition, there are numerous vertical wells that exist in the area as well as 3D seismic surveys. Each horizontal well contains full FMS logs and MWD logs, gamma logs, etc.

  18. Anomalies of natural gas compositions and carbon isotope ratios caused by gas diffusion - A case from the Donghe Sandstone reservoir in the Hadexun Oilfield, Tarim Basin, northwest China

    Science.gov (United States)

    Wang, Yangyang; Chen, Jianfa; Pang, Xiongqi; Zhang, Baoshou; Wang, Yifan; He, Liwen; Chen, Zeya; Zhang, Guoqiang

    2018-05-01

    Natural gases in the Carboniferous Donghe Sandstone reservoir within the Block HD4 of the Hadexun Oilfield, Tarim Basin are characterized by abnormally low total hydrocarbon gas contents ( δ13C ethane (C2) gas has never been reported previously in the Tarim Basin and such large variations in δ13C have rarely been observed in other basins globally. Based on a comprehensive analysis of gas geochemical data and the geological setting of the Carboniferous reservoirs in the Hadexun Oilfield, we reveal that the anomalies of the gas compositions and carbon isotope ratios in the Donghe Sandstone reservoir are caused by gas diffusion through the poorly-sealed caprock rather than by pathways such as gas mixing, microorganism degradation, different kerogen types or thermal maturity degrees of source rocks. The documentation of an in-reservoir gas diffusion during the post entrapment process as a major cause for gas geochemical anomalies may offer important insight into exploring natural gas resources in deeply buried sedimentary basins.

  19. Integrated Analysis Seismic Inversion and Rockphysics for Determining Secondary Porosity Distribution of Carbonate Reservoir at “FR” Field

    Science.gov (United States)

    Rosid, M. S.; Augusta, F. F.; Haidar, M. W.

    2018-05-01

    In general, carbonate secondary pore structure is very complex due to the significant diagenesis process. Therefore, the determination of carbonate secondary pore types is an important factor which is related to study of production. This paper mainly deals not only to figure out the secondary pores types, but also to predict the distribution of the secondary pore types of carbonate reservoir. We apply Differential Effective Medium (DEM) for analyzing pore types of carbonate rocks. The input parameter of DEM inclusion model is fraction of porosity and the output parameters are bulk moduli and shear moduli as a function of porosity, which is used as input parameter for creating Vp and Vs modelling. We also apply seismic post-stack inversion technique that is used to map the pore type distribution from 3D seismic data. Afterward, we create porosity cube which is better to use geostatistical method due to the complexity of carbonate reservoir. Thus, the results of this study might show the secondary porosity distribution of carbonate reservoir at “FR” field. In this case, North – Northwest of study area are dominated by interparticle pores and crack pores. Hence, that area has highest permeability that hydrocarbon can be more accumulated.

  20. Compressible fluid flow through rocks of variable permeability

    International Nuclear Information System (INIS)

    Lin, W.

    1977-01-01

    The effectiveness of course-grained igneous rocks as shelters for burying radioactive waste can be assessed by determining the rock permeabilities at their in situ pressures and stresses. Analytical and numerical methods were used to solve differential equations of one-dimensional fluid flow through rocks with permeabilities from 10 4 to 1 nD. In these calculations, upstream and downstream reservoir volumes of 5, 50, and 500 cm 3 were used. The optimal size combinations of the two reservoirs were determined for measurements of permeability, stress, strain, acoustic velocity, and electrical conductivity on low-porosity, coarse-grained igneous rocks

  1. Evaluating the utility of hydrocarbons for Re-Os geochronology : establishing the timing of processes in petroleum ore systems

    Energy Technology Data Exchange (ETDEWEB)

    Selby, D.; Creaser, R.A. [Alberta Univ., Edmonton, AB (Canada). Dept. of Earth and Atmospheric Sciences

    2005-07-01

    Oil from 6 Alberta oil sands deposits were analyzed with a rhenium-osmium (Re-Os) isotope chronometer, an emerging tool for determining valuable age information on the timing of petroleum generation and migration. The tool uses molybdenite and other sulphide minerals to establish the timing and duration of mineralization. However, establishing the timing events of petroleum systems can be problematic because viable sulphides for the Re-Os chronometer are often not available. Therefore, the known presence of Re and Os associated with organic matter in black shale, a common source of hydrocarbons, may suggest that bitumen and petroleum common to petroleum systems may be utilised for Re-Os geochronology. This study evaluated the potential of the Re-Os isotopic system for geochronology and as an isotopic tracer for hydrocarbon systems. The evaluation was based on Re-Os isotopic analyses of bitumen and oil sands. Hydrocarbons formed from migrated oil in both Alberta oil sand deposits and a Paleozoic Mississippi Valley-type lead-zinc deposit contain significant Re and Os contents with high {sup 187}Re/{sup 188}Os and radiogenic {sup 187}Os/{sup 188}Os ratios suitable for geochronology. The oil from the 6 Alberta oil sand deposits yields Re-Os analyses with very high Re/{sup 188}Os ratios, and radiogenic Os isotopic compositions. Regression of the Re-Os data yields a date of 116 {+-} 27 Ma. This date plausibly represents the period of in situ radiogenic growth of {sup 187}Os following hydrocarbon migration and reservoir filling. Therefore, directly dating these processes, and this formation age corresponds with recent burial history models for parts of the Western Canada Sedimentary Basin. The very high initial {sup 187}Os/{sup 188}Os for this regression requires rocks much older than Cretaceous for the hydrocarbon source.

  2. Art Rocks with Rock Art!

    Science.gov (United States)

    Bickett, Marianne

    2011-01-01

    This article discusses rock art which was the very first "art." Rock art, such as the images created on the stone surfaces of the caves of Lascaux and Altimira, is the true origin of the canvas, paintbrush, and painting media. For there, within caverns deep in the earth, the first artists mixed animal fat, urine, and saliva with powdered minerals…

  3. HYDROCARBONS RESERVES IN VENEZUELA

    Energy Technology Data Exchange (ETDEWEB)

    Gonzalez Cruz, D.J.

    2007-07-01

    Venezuela is an important player in the energy world, because of its hydrocarbons reserves. The process for calculating oil and associated gas reserves is described bearing in mind that 90% of the gas reserves of Venezuela are associated to oil. Likewise, an analysis is made of the oil reserves figures from 1975 to 2003. Reference is also made to inconsistencies found by international experts and the explanations offer