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Academic literature on the topic 'Hydrocarbon-bearing'

Author: Grafiati

Published: 4 June 2021

Last updated: 3 February 2022

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Journal articles on the topic "Hydrocarbon-bearing"

Zemanek, Joe. "Low-Resistivity Hydrocarbon-Bearing Sand Reservoirs." SPE Formation Evaluation 4, no. 04 (December 1, 1989): 515–21. http://dx.doi.org/10.2118/15713-pa.

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Harrison, R. K. "Hydrocarbon-bearing nodules from Heysham, Lancashire." Geological Journal 7, no. 1 (April 30, 2007): 101–10. http://dx.doi.org/10.1002/gj.3350070106.

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Wen, Bo, and Kung K. Wang. "Solution-phase synthesis of bowl- and basket-shaped fullerene fragments via benzannulated enyne–allenes." Pure and Applied Chemistry 84, no. 4 (January 26, 2012): 893–905. http://dx.doi.org/10.1351/pac-con-11-09-03.

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Benzannulated enyne-allenes bearing an aryl substituent at both the alkynyl and allenyl termini are excellent precursors of 5-aryl-11H-benzo[b]fluorenyl derivatives having the carbon frameworks of fullerene fragments. The mildness of the reaction conditions and the availability of several synthetic methods for benzannulated enyne-allenes allow the design of new synthetic pathways leading to bowl- and basket-shaped fullerene fragments. Specifically, a bowl-shaped C28H18 hydrocarbon bearing a 27-carbon framework of C60 and a basket-shaped C56H40 hydrocarbon bearing a 54-carbon framework of C60 were synthesized. The interior 30-carbon core of the C56H40 hydrocarbon can be regarded as a partially hydrogenated [5,5]circulene, a C30H12 semibuckminsterfullerene. In addition, a basket-shaped C56H38 hydrocarbon was also constructed to serve as a precursor toward an end-cap template for (6,6) carbon nanotubes.

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Worthington, Paul F. "Quality-assured evaluation of freshwater-bearing hydrocarbon reservoirs." Journal of Petroleum Science and Engineering 78, no. 2 (August 2011): 542–51. http://dx.doi.org/10.1016/j.petrol.2011.06.008.

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He, Faqi, Ying Rao, Weihong Wang, and Yanghua Wang. "Prediction of hydrocarbon reservoirs within coal-bearing formations." Journal of Geophysics and Engineering 17, no. 3 (February 25, 2020): 484–92. http://dx.doi.org/10.1093/jge/gxaa007.

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Abstract This paper presents a case study on the prediction of hydrocarbon reservoirs within coal-bearing formations of the Upper Palaeozoic. The target reservoirs are low-permeability low-pressure tight-sandstone reservoirs in the Daniudi Gas Field, Ordos Basin, China. The prime difficulty in reservoir prediction is caused by the interbedding coal seams within the formations, which generate low-frequency strong-amplitude reflections in seismic profiles. To tackle this difficulty, first, we undertook a careful analysis regarding the stratigraphy and lithology of these coal-bearing formations within the study area. Then, we conducted a geostatistical inversion using 3D seismic data and obtained reservoir parameters including seismic impedance, gamma ray, porosity and density. Finally, we carried out a reservoir prediction in the coal-bearing formations, based on the reservoir parameters obtained from geostatistical inversion and combined with petrophysical analysis results. The prediction result is accurately matched with the actual gas-test data for the targeted four segments of the coal-bearing formations.

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Jiang, Zaixing, Hongjie Duan, Chao Liang, Jing Wu, Wenzhao Zhang, and Jianguo Zhang. "Classification of hydrocarbon-bearing fine-grained sedimentary rocks." Journal of Earth Science 28, no. 6 (December 2017): 693–976. http://dx.doi.org/10.1007/s12583-016-0920-0.

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Gryadunova, E. N., R. N. Polyakov, and N. V. Tokmakov. "Photometric Method of Diagnosis of Bearing Units Operating with Hydrocarbon Mixtures." Solid State Phenomena 284 (October 2018): 1342–48. http://dx.doi.org/10.4028/www.scientific.net/ssp.284.1342.

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The article is devoted to the diagnosis of bearing units working with hydrocarbon mixtures. The diagnostic is based on the photometric method. This method allows you to determine the internal damage to the bearing unit at the stage of the appearance of the microcrack. The photometric method is based on changing the color of the indicator fabric. As the indicator substance, a bromine solution was used which had a dark brown color. If there is a leak, the hydrocarbon reacts with bromine molecules and a bright spot appears on the tape. Indicator fabric is applied to the bearing unit during assembling.The material of the article contains a model of the physicochemical process, which is the basis of the photometric method. Various stages of leakage of hydrocarbon mixtures through microcracks were studied. The results of the experimental studies are consistent with the theoretical propositions. The proposed diagnostic method can be used as a method for non-destructive testing of bearing units.

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Cao, Tong, and Shao Bin Guo. "Application of Absorption and Attenuation Analysis Based on Pre-Stack Seismic Data: Su-77 Block Gas Field Example." Advanced Materials Research 772 (September 2013): 771–75. http://dx.doi.org/10.4028/www.scientific.net/amr.772.771.

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Most hydrocarbon absorption attenuation studies are based on poststack seismic data processing but, because of multiple stacks at full angle, poststack data will lose some lithology and hydrocarbon-bearing capacity information. To overcome this disadvantage, a prestack angle-domain absorption attenuation analysis technique can be performed for seismic data stacked at various angles to obtain angle-domain-dependent absorption profiles. The absorption anomaly reflects the gas-bearing reservoir and also decreases as the angle increases. Actual data from the Sulige gas field, Ordos Basin, have been processed, and the hydrocarbon predictions match very well with actual drilling results, validating the method's effectiveness.

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Xiao, Jun, Bei Zhu, and Ji Hua Liao. "Hydrocarbon Detection Techniques on Subtle Reservoir Exploration in Qiongdongnan Basin." Advanced Materials Research 356-360 (October 2011): 3028–32. http://dx.doi.org/10.4028/www.scientific.net/amr.356-360.3028.

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Subtle reservoir is an important area of hydrocarbon exploration in Qiongdongnan basin. The reservoir hydrocarbon-bearing potential is one of the cores of this research, and the geophysical technology is the main research tool. In this paper, AVO, AVD, DR and seismic attenuation gradient techniques are carried out to evaluate the hydrocarbon-bearing ability. Taking the JY area of eastern Qiongdongnan basin as a case study, the results show that the characteristics of gas-bearing reservoir in JY area are the 3rd AVO anomaly, high AVD and DR, and low attenuation gradient. Furthermore, multi-information fusion technique is used to qualify the gas resource scale and provide decision-making advice for the future exploration. It shows that the seismic anomaly sand body of the first member of Sanya Formation in JY area has large gas resource potential and good exploration prospect.

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Akulov, Nikolay I., and Varvara V. Akulova. "Pyrolysis of Technogenic-Redeposited Coal-Bearing Rocks of Spoil Heaps." Geosciences 10, no. 4 (March 28, 2020): 122. http://dx.doi.org/10.3390/geosciences10040122.

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The paper presents the results of a study of epigenetic changes in technogenic-redeposited coal-bearing rocks of Irkutsk and Kuznetsk coal basin spoil heaps (Russia). Hydrocarbon products formed under high-temperature and low-temperature pyrolysis of coal-bearing rocks were studied by using a chromatography-mass spectrometer GCMS-QP2010NC Plus (made by Shimadzu Company). The average temperature of low-temperature natural pyrolysis does not exceed 120 °C, and its average speed is approximately 2 m/year. In this case, three pyrolysis zones gradually built metamorphic rock mass (from bottom to top) are clearly established: heating (focal) activated and enriched. The average temperature of high-temperature pyrolysis reaches 850 °C, and its average speed is approximately 20 m/year. Unlike low-temperature pyrolysis, high-temperature pyrolysis is accompanied by the presence of two major zones (from bottom to top): pyrogenic (focal) and enriched (coke). The chemical composition of the enriched pyrolysis zone was studied in detail. It has been established that hydrocarbon compounds in samples of the pyrolysis zone are presented by six classes: asphaltic-resinous substances; polycyclic aromatic hydrocarbons, heterocyclic compounds, organic sulphur compounds; pyrolytic hydrocarbon and heavy hydrocarbon residue. Quantitative content of hydrocarbon compounds in the analyzed samples varies from 0.35% to 41.88%.

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Dissertations / Theses on the topic "Hydrocarbon-bearing"

Kowal, David Anazario. "Comparison of thermal maturation indicators within hydrocarbon bearing sedimentary rock." Kansas State University, 2015. http://hdl.handle.net/2097/20599.

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Master of Science
Geology
Matthew W. Totten
The thermal maturity of hydrocarbon-rich source rocks can be estimated by several different methods. These methods focus on a specific geochemical or mineralogical aspect contained within the rock. Because each method has limitations, it is advisable to use several methods to better determine thermal maturation. This report summarizes two common methods used to determine thermal maturity, vitrinite reflectance and illitization. Vitrinite reflectance and illitization have both been shown to be effected by similar temperatures that are within the hydrocarbon generation window. In some previous studies these two methods give different levels of maturation when looked at in tandem. Formations such as the Woodford Shale of Oklahoma are made up almost completely of illite in the clay fraction, even at low levels of vitrinite reflectance. These are also without a clear source of potassium, which is often the limiting factor in the process of illitization. Totten et al. (2013) suggest that in place of potassium feldspars, which are a common source of K⁺ for illite (but lacking in the Woodford) that the needed K⁺ was provided by the organic material that was being altered under the same temperatures of the clay minerals. The Woodford contains large amounts of organic matter, This would be consistent with promoting illitization at lower thermal maturities than organic-poor shales.

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Golding, Martyn Lee. "Biostratigraphy and sedimentology of Triassic hydrocarbon-bearing rocks in northeastern British Columbia." Thesis, University of British Columbia, 2014. http://hdl.handle.net/2429/46325.

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The Triassic Montney and Doig formations in the subsurface of northeastern British Columbia are important hydrocarbon reserves for the province. However the age and tectonic setting of these formations, and their outcrop equivalents (Grayling, Toad and Liard formations), are poorly constrained. The collection of conodont and detrital zircon samples from outcrop sections, and from core taken from subsurface hydrocarbon wells, has allowed the biostratigraphy of these formations to be improved, and the tectonic setting to be inferred. The study of new conodont samples, together with re-examination of existing collections, has led to the recognition of more than thirty new species and morphotypes within the Anisian (Middle Triassic) of British Columbia. These new taxa have in turn allowed the recognition of 11 new faunal assemblages that further refine the conodont biostratigraphic scale for the Anisian of British Columbia. Conodont biostratigraphy of the Montney and Doig formations in the subsurface has allowed correlation of these formations with those of surface sections, and also for the first time provided an age for the boundary between them. The boundary is recognised to be diachronous, and it is oldest in the centre of the study area. The basal Doig Formation is condensed, and shows most condensation at the edges of the study area. Both observations imply the presence of palaeo-highs to the west as well as to the east during the Triassic. This conclusion is supported by detrital zircon geochronology, which demonstrates the presence of sediment derived from the Arctic and from the pericratonic Yukon-Tanana terrane in the Triassic rocks of northeastern British Columbia. Previous hypotheses of Permo-Triassic accretion of this terrane onto the North American margin (the Klondike Orogeny) are supported by this study, and the Triassic sediments of northeastern British Columbia are interpreted to have been deposited in the foreland basin of this orogeny.???

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Vanneste, Heleen L. A. E. "Seepage of hydrocarbon bearing fluids at the Carlos Ribeiro and Darwin mud volcanoes (Gulf of Cadiz)." Thesis, University of Southampton, 2010. https://eprints.soton.ac.uk/207995/.

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Submarine mud volcanism is an important pathway for transfer of deep-sourced fluids enriched in hydrocarbons and other elements into the ocean. Mud volcanoes (MVs) occur in abundance on all oceanic plate margins, so fluxes of methane (CH4) and other chemical constituents from mud volcanism are likely to be significant for the oceanic budgets of some elements. Here, I present a detailed study of the spatial and temporal variation in fluid and chemical fluxes and mud flow activity at the Carlos Ribeiro and the Darwin MVs in the Gulf of Cadiz. Analyses of the chemical composition of pore fluids, sediments and authigenic carbonates are combined with a 1-D transport-reaction pore fluid model. Pore fluids from both MVs contain high concentrations of hydrocarbons (up to 16 mM), while pore fluids from Carlos Ribeiro MV (CRMV) are also enriched in lithium (Li+) and boron (B) but depleted in chloride relative to seawater. Oxygen, hydrogen and strontium isotope data suggest that the pore fluids are derived from depth and are affected by the transformation of smectite to illite. This process also produces pore fluids that are depleted in chloride and potassium, while B and Li+ appear to be leached from the sediments during this transformation process. The CRMV is the most active of the two MVs: fluid flow velocities are as high as 4 cm yr−1 at the eye of the MV but rapidly decrease to 0.4 cm yr−1 at the periphery. The associated fluxes of B, Li+ and CH4 are 7-301, 0.5-6 and 0-806 mmol m−2 yr−1, respectively. Fluid flow velocities at the Darwin MV are lower, ῀0.09 cm yr−1, and show little spatial variation: seepage activity appears to be controlled by the distribution of slabs of authigenic carbonate that are found on the seafloor at the summit of the MV. Results of radiocarbon dating of the hemipelagic sediments covering the CRMV suggest that there has been recent mudflow activity at the eye of the MV, and frequent mud expulsions over the past ῀1000 Cal yrs BP. The distribution of barite fronts at the margin of the MV and within the mudflow to the SE of the summit suggests that fluid advection has ceased over the past 340 Cal yrs, but degassing of these mudflows is ongoing and is potentially an important source of CH4. Geochemical and petrographic analyses of carbonates from the Darwin MV suggest that the MV formed in stages, with periods of intense fluid flow alternating with phases of mud extrusion and tectonic uplift. The results of this study demonstrate that fluid (and chemical) fluxes from MVs vary over relatively small time and space scales and that mud volcanism may contribute significantly to the oceanic inventories of Li+ and B. Moreover, anaerobic oxidation of methane appears to be an important control on methane emissions into the overlying water column, and a better understanding of this process is urgently required to properly quantify the impact of mud volcanism on the global oceanic methane budget.

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Popielski, Andrew Christopher. "Rock classification from conventional well logs in hydrocarbon-bearing shale." Thesis, 2011. http://hdl.handle.net/2152/ETD-UT-2011-12-4418.

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This thesis introduces a rock typing method for application in shale gas reservoirs using conventional well logs and core data. Shale gas reservoirs are known to be highly heterogeneous and often require new or modified petrophysical techniques for accurate reservoir evaluation. In the past, petrophysical description of shale gas reservoirs with well logs has been focused to quantifying rock composition and organic-matter concentration. These solutions often require many assumptions and ad-hoc correlations where the interpretation becomes a core matching exercise. Scale effects on measurements are typically neglected in core matching. Rock typing in shale gas provides an alternative description by segmenting the reservoir into petrophysically-similar groups with k-means cluster analysis which can then be used for ranking and detailed analysis of depth zones favorable for production. A synthetic example illustrates the rock typing method for an idealized sequence of beds penetrated by a vertical well. Results and analysis from the synthetic example show that rock types from inverted log properties correctly identify the most organic-rich model types better than rock types detected from well logs in thin beds. Also, estimated kerogen concentration is shown to be most reliable in an under-determined problem. Field cases in the Barnett and Haynesville shale gas plays show the importance of core data for supplementing well logs and identifying correlations for desirable reservoir properties (kerogen/TOC concentration, gas saturation, and porosity). Qualitative rock classes are formed and verified using inverted estimates of kerogen concentration as a rock-quality metric. Inverted log properties identify 40% more of a high-kerogen rock type over well-log based rock types in the Barnett formation. A case in the Haynesville formation suggests the possibility of identifying depositional environments as a result of rock attributes that produce distinct groupings from k-means cluster analysis with well logs. Core data and inversion results indicate homogeneity in the Haynesville formation case. However, the distributions of rock types show a 50% occurrence between two rock types over 90 ft vertical-extent of reservoir. Rock types suggest vertical distributions that exhibit similar rock attributes with characteristic properties (porosity, organic concentration and maturity, and gas saturation). This method does not directly quantify reservoir parameters and would not serve the purpose of quantifying gas-in-place. Rock typing in shale gas with conventional well logs forms qualitative rock classes which can be used to calculate net-to-gross, validate conventional interpretation methods, perform well-to-well correlations, and establish facies distributions for integrated reservoir modeling in hydrocarbon-bearing shale.
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Shabro, Vahid. "Pore-scale numerical modeling of petrophysical properties with applications to hydrocarbon-bearing organic shale." 2013. http://hdl.handle.net/2152/22902.

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The main objective of this dissertation is to quantify petrophysical properties of conventional and unconventional reservoirs using a mechanistic approach. Unconventional transport mechanisms are described from the pore to the reservoir scale to examine their effects on macroscopic petrophysical properties in hydrocarbon-bearing organic shale. Petrophysical properties at the pore level are quantified with a new finite-difference method. A geometrical approximation is invoked to describe the interstitial space of grid-based images of porous media. Subsequently, a generalized Laplace equation is derived and solved numerically to calculate fluid pressure and velocity distributions in the interstitial space. The resulting macroscopic permeability values are within 6% of results obtained with the Lattice-Boltzmann method after performing grid refinements. The finite-difference method is on average six times faster than the Lattice-Boltzmann method. In the next step, slip flow and Knudsen diffusion are added to the pore-scale method to take into account unconventional flow mechanisms in hydrocarbon-bearing shale. The effect of these mechanisms is appraised with a pore-scale image of Eagle Ford shale as well as with several grain packs. It is shown that neglecting slip flow in samples with pore-throat sizes in the nanometer range could result in errors as high as 2000% when estimating permeability in unconventional reservoirs. A new fluid percolation model is proposed for hydrocarbon-bearing shale. Electrical conductivity is quantified in the presence of kerogen, clay, hydrocarbon, water, and the Stern-diffuse layer in grain packs as well as in the Eagle Ford shale pore-scale image. The pore-scale model enables a critical study of the [delta]LogR evaluation method commonly used with gas-bearing shale to assess kerogen concentration. A parallel conductor model is introduced based on Archie's equation for water conductivity in pores and a parallel conductive path for the Stern-diffuse layer. Additionally, a non-destructive core analysis method is proposed for estimating input parameters of the parallel conductor model in shale formations. A modified reservoir model of single-phase, compressible fluid is also developed to take into account the following unconventional transport mechanisms: (a) slip flow and Knudsen diffusion enhancement in apparent permeability, (b) Langmuir desorption as a source of gas generation at kerogen surfaces, and (c) the diffusion mechanism in kerogen as a gas supply to adsorbed layers. The model includes an iterative verification method of surface mass balance to ensure real-time desorption-adsorption equilibrium with gas production. Gas desorption from kerogen surfaces and gas diffusion in kerogen are the main mechanisms responsible for higher-than-expected production velocities commonly observed in shale-gas reservoirs. Slip flow and Knudsen diffusion marginally enhance production rates by increasing permeability during production.
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Montaut, Antoine Marc Marie. "Detection and quantification of rock physics properties for improved hydraulic fracturing in hydrocarbon-bearing shales." 2012. http://hdl.handle.net/2152/20020.

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Horizontal drilling and hydraulic stimulation make hydrocarbon production from organic-rich shales economically viable. Identification of suitable zones to drill a horizontal well and to initiate or contain hydraulic fractures requires detection and quantification of many factors, including elastic mechanical properties. Elastic behavior of rocks is affected by rock composition and fabric, pore pressure, confining stress, and other factors. Rock fabric refers to the arrangement of the rock’s solid and fluid constituents. The objective of this thesis is to quantify rock fabric properties of hydrocarbon-bearing shales affecting elastic properties, including load-bearing matrix, anisotropic cracks, and shape of rock components. Once rock fabric is validated with sonic logs, results can be used to identify suitable zones to drill a horizontal well, initiate hydraulic stimulation, and contain fracture propagation. We develop a method to estimate elastic properties based on rock composition. The differential effective medium (DEM) theory is invoked to model rock elastic properties with a load-bearing component in which remaining minerals and pores are added as spheres or ellipsoids. The method can be combined with the self-consistent approximation (SCA) to construct a load-bearing matrix made of two solid phases. Anisotropic inclusions are added via Hudson’s model. Subsequently, Gassmann’s theory is invoked to saturate the rock with fluids and determine low-frequency elastic properties for comparison to sonic logs. Rock fabric properties remain constant in a vertically homogeneous formation. In vertically heterogeneous strata, the depth interval of interest is divided into rock types, based on rock solid composition, and each rock type is associated with a specific fabric. Quantification of rock fabric properties is a non-unique process, and one should take into account as much petrophysical and geological information as possible to ensure physically viable results. Our simulation and interpretation method is implemented in two wells in both the Haynesville and Barnett shales. Averages of relative errors between estimated velocities and sonic logs are less than 4% in the four wells. Simulations in the Haynesville shale are isotropic, and therefore indicate that rock fabric may not be the main cause of mechanical anisotropy in cases where such behavior is inferred from field data. Rock fabric properties are constant with depth in both wells. Consequently, identification of suitable zones to drill a horizontal well or to contain fracture propagation is not based on rock fabric; it is deduced from Young’s modulus. Simulated Poisson’s ratio is shown to be more sensitive to errors in velocities than Young’s modulus and is therefore not used in the interpretation. Favorable depth intervals for gas production exhibit sizeable volumes of gas and organic content. In the Barnett shale, the two wells exhibit different rock fabrics. Such a behavior indicates that the formation is laterally heterogeneous. Rock physics models should therefore be extrapolated from one well to another with caution. Simulations assume anisotropic elastic behavior and suggest the presence of compliant horizontal pores in one case. Natural vertical fractures are observed on electric image logs in the remaining case and are modeled with Hudson’s theory. This behavior suggests that rock fabric causes mechanical anisotropy in the formation. Heterogeneity of the Barnett shale rock fabric is inferred from the necessary use of rock typing to adequately reproduce sonic logs in both wells. Intervals with large porosity and high gas saturation identify suitable zones to perform hydraulic stimulation. Among such zones, rock types that exhibit stiff load-bearing matrices (comprising mostly calcite, for example) indicate suitable depths to drill horizontal wells or to contain hydraulic fractures. Intervals with dense layering of different rock types are unsuitable for fracture propagation and should be avoided during hydraulic-fracturing operations.
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Marouby, Philippe Matthieu. "Estimation of elastic properties of hydrocarbon-bearing shale by combining effective-medium calculations, conventional well logs, and dispersion processing of sonic waveforms." Thesis, 2011. http://hdl.handle.net/2152/ETD-UT-2011-12-4390.

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Identification of favorable production zones in hydrocarbon-bearing shale often requires the quantification of in-situ mechanical properties. These properties are also necessary for the optimal design of hydro-fracturing operations. Rock elastic properties are affected by volumetric concentrations of mineral constituents, porosity, fluid saturations, and total organic carbon (TOC). Rapid depth variations of rock properties often encountered in shale gas formations make conventional petrophysical interpretation methods inadequate to estimate volumetric concentration of mineral constituents. We introduce a new method to assess elastic properties of organic shale based on the combined quantitative interpretation of sonic, nuclear, and resistivity logs. In-situ elastic properties of organic shale are estimated by (a) improving the assessment of volumetric concentrations of mineral constituents, (b) implementing reliable rock physics models and mixing laws for organic shale, and (c) numerically reproducing wideband frequency dispersions of Stoneley and flexural waves. An example of the application of the method is described in the Haynesville shale gas formation. Estimates of mineral concentrations, porosity, and fluid saturations are in agreement with available laboratory core measurements and X-Ray Diffraction (XRD) data. Calculated layer-by-layer P- and S-wave velocities differ by less than 15% from measured velocities thus confirming the reliability of the method. Finally, based on the new interpretation method developed in this thesis, correlations are found between mineral concentrations, TOC, porosity, and rock elastic properties, which can be used in the selection of optimal production zones.
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"Synthesis of amphiphilic hydrocarbon dendrons bearing surface hydroxyl groups and dimerization study of their ureidopyrimidinone derivatives." 2008. http://library.cuhk.edu.hk/record=b5896843.

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Choi, Lai Sheung.
Thesis (M.Phil.)--Chinese University of Hong Kong, 2008.
Includes bibliographical references (leaves 111-115).
Abstracts in English and Chinese.
Contents --- p.i
Acknowledgements --- p.iv
Abstract --- p.v
Abbreviations --- p.viii
Chapter Chapter 1 - --- Introduction to Dendrimer
Chapter 1.1 --- Definition --- p.1
Chapter 1.2 --- Synthetic Routes --- p.2
Chapter 1.2.1 --- Divergent Growth --- p.2
Chapter 1.2.2 --- Convergent Growth --- p.3
Chapter 1.3 --- Applications --- p.4
Chapter 1.4 --- Examples of Dendrimers --- p.6
Chapter 1.4.1 --- Hydrocarbon Dendritic Species --- p.6
Chapter 1.4.2 --- Aliphatic Polyether Dendritic Species --- p.8
Chapter Chapter 2 - --- Synthesis of Novel Amphiphilic Hydrocarbon Dendrons
Chapter 2.1 --- Background - Hydrocarbon Dendrons (HCDs) --- p.11
Chapter 2.2 --- Modification and Design of Synthetic Scheme --- p.13
Chapter 2.3 --- Syntheses --- p.14
Chapter 2.3.1 --- Convergent Synthesis --- p.14
Chapter 2.3.2 --- Divergent Synthesis --- p.19
Chapter 2.4 --- Characterizations --- p.22
Chapter 2.4.1 --- 1H NMR Spectroscopy --- p.22
Chapter 2.4.2 --- 13C NMR Spectroscopy --- p.25
Chapter 2.4.3 --- Mass Spectrometry --- p.27
Chapter 2.4.4 --- Gel Permeation Chromatography (GPC) --- p.29
Chapter 2.4.5 --- Thin Layer Chromatography (TLC) --- p.31
Chapter 2.4.6 --- Solubility --- p.31
Chapter 2.5 --- Conclusions and Future Prospects --- p.33
Chapter Chapter 3 - --- Hydrogen Bonding in Supramolecular Chemistry
Chapter 3.1 --- Background ´ؤ Supramolecular Chemistry --- p.35
Chapter 3.1.1 --- Multiple Hydrogen Bondings --- p.37
Chapter 3.1.2 --- Applications --- p.39
Chapter 3.2 --- 2-Ureido-4[lH]-Pyrimidinone (UPy) --- p.40
Chapter 3.2.1 --- Tautomerization and Dimerization Equilibria --- p.40
Chapter 3.2.2 --- Examples of Dendronized UPy Dimers --- p.44
Chapter 3.3 --- Effects of Substituents on the Dimerization Behavior of UPy --- p.46
Chapter 3.4 --- Dimerization Studies on Our New UPy-Dendrons --- p.50
Chapter Chapter 4 - --- "Synthesis, Characterizations and Dimerization Properties of Dendronized UPy Dimers"
Chapter 4.1 --- Synthesis --- p.51
Chapter 4.2 --- Characterizations --- p.51
Chapter 4.2.1 --- 1H NMR Spectroscopy --- p.51
Chapter 4.2.1.1 --- Dimerization Behavior of Protected UPy Series (94-97) in CDC13 at 25 °C --- p.52
Chapter 4.2.1.2 --- Temperature-Dependent Behavior of Protected UPy Series (94´ؤ97) in CDC13 --- p.59
Chapter 4.2.1.3 --- Tautomeric Behavior of Protected UPy Series in (94-97) in Other Solvents --- p.60
Chapter 4.2.1.4 --- Characterization of Deprotected UPy Series (98-101) in DMSO-d6 --- p.60
Chapter 4.2.1.5 --- Dimerization Behavior of Deprotected UPy Series (98-101) in THF-d8 and Other Solvents --- p.63
Chapter 4.2.1.6 --- Temperature-Dependent Behavior of Deprotected UPy Series (98´ؤ101) in THF-d8 --- p.67
Chapter 4.2.1.7 --- Dimerization Constants of Both Protected and Deprotected UPy Series in DMSO-d6/CDCl3 Mixtures at 25 °C --- p.68
Chapter 4.2.2 --- 13C NMR Spectroscopy --- p.71
Chapter 4.2.3 --- Mass Spectrometry --- p.71
Chapter 4.2.4 --- Gel Permeation Chromatography (GPC) --- p.73
Chapter 4.2.5 --- Vapour Pressure Osmometry (VPO) --- p.74
Chapter 4.2.6 --- Infrared Spectroscopy --- p.75
Chapter 4.2.7 --- Polarity and Solubility --- p.76
Chapter 4.3 --- Conclusions --- p.77
Chapter Chapter 5 - --- Conclusions --- p.79
Chapter Chapter 6 - --- Experimantal Procedures
Chapter 6.1 --- General Information --- p.81
Chapter 6.2 --- Experimantal Procedures --- p.82
References --- p.111
Appendix 1 - Calculations of lower-limits of Kdim* in CDCI3 --- p.A-1
Appendix 2 - Calculations of Kdim* in systems where both dimer(s) and 6[1H] monomer coexist --- p.A-4
Appendix 3 - List of Spectra --- p.A-5

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Adiguna, Haryanto. "Comparative study for the interpretation of mineral concentrations, total porosity, and TOC in hydrocarbon-bearing shale from conventional well logs." 2012. http://hdl.handle.net/2152/20053.

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The estimation of porosity, water saturation, kerogen concentration, and mineral composition is an integral part of unconventional shale reservoir formation evaluation. Porosity, water saturation, and kerogen content determine the amount of hydrocarbon-in-place while mineral composition affects hydro-fracture generation and propagation. Effective hydraulic fracturing is a basic requirement for economically viable flow of gas in very-low permeability shales. Brittle shales are favorable for initiation and propagation of hydraulic fracture because they require marginal or no plastic deformation. By contrast, ductile shales tend to oppose fracture propagation and can heal hydraulic fractures. Silica and carbonate-rich shales often exhibit brittle behavior while clay-rich shales tend to be ductile. Many operating companies have turned their attention to neutron capture gamma-ray spectroscopy (NCS) logs for assessing in-situ mineral composition. The NCS tool converts the energy spectrum of neutron-induced captured gamma-rays into relative elemental yields and subsequently transforms them to dry-weight elemental fractions. However, NCS logs are not usually included in a well-logging suite due to cost, tool availability, and borehole conditions. Conventional well logs are typically acquired as a minimum logging program because they provide geologists and petrophysicists with the basic elements for tops identification, stratigraphic correlation, and net-pay determination. Most petrophysical interpretation techniques commonly used to quantify mineral composition from conventional well logs are based on the assumption that lithology is dominated by one or two minerals. In organic shale formations, these techniques are ineffective because all well logs are affected by large variations of mineralogy and pore structure. Even though it is difficult to separate the contribution from each mineral and fluid component on well logs using conventional interpretation methods, well logs still bear essential petrophysical properties that can be estimated using an inversion method. This thesis introduces an inversion-based workflow to estimate mineral and fluid concentrations of shale gas formations using conventional well logs. The workflow starts with the construction and calibration of a mineral model based on core analysis of crushed samples and X-Ray Diffraction (XRD). We implement a mineral grouping approach that reduces the number of unknowns to be estimated by the inversion without loss of accuracy in the representation of the main minerals. The second step examines various methods that can provide good initial values for the inversion. For example, a reliable prediction of kerogen concentration can be obtained using the ΔlogR method (Passey et al., 1990) as well as an empirical correlation with gamma-ray or uranium logs. After the mineral model is constructed and a set of initial values are established, nonlinear joint inversion estimates mineral and fluid concentrations from conventional well logs. An iterative refinement of the mineral model can be necessary depending on formation complexity and data quality. The final step of the workflow is to perform rock classification to identify favorable production zones. These zones are selected based on their hydrocarbon potential inferred from inverted petrophysical properties. Two synthetic examples with known mineral compositions and petrophysical properties are described to illustrate the application of inversion. The impact of shoulder-bed effects on inverted properties is examined for the two inversion modes: depth-by-depth and layer-by-layer. This thesis also documents several case studies from Haynesville and Barnett shales where the proposed workflow was successfully implemented and is in good agreement with core measurements and NCS logs. The field examples confirm the accuracy and reliability of nonlinear inversion to estimate porosity, water saturation, kerogen concentration, and mineral composition.
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Alkan, Engin 1979. "Exploring hydrocarbon-bearing shale formations with multi-component seismic technology and evaluating direct shear modes produced by vertical-force sources." 2012. http://hdl.handle.net/2152/19575.

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It is essential to understand natural fracture systems embedded in shale-gas reservoirs and the stress fields that influence how induced fractures form in targeted shale units. Multicomponent seismic technology and elastic seismic stratigraphy allow geologic formations to be better images through analysis of different S-wave modes as well as the P-wave mode. Significant amounts of energy produced by P-wave sources radiate through the Earth as downgoing SV-wave energy. A vertical-force source is an effective source for direct SV radiation and provides a pure shear-wave mode (SV-SV) that should reveal crucial information about geologic surfaces located in anisotropic media. SV-SV shear wave modes should carry important information about petrophysical characteristics of hydrocarbon systems that cannot be obtained using other elastic-wave modes. Regardless of the difficulties of extracting good-quality SV-SV signal, direct shear waves as well as direct P and converted S energy should be accounted for in 3C seismic studies. Acquisition of full-azimuth seismic data and sampling data at small intervals over long offsets are required for detailed anisotropy analysis. If 3C3D data can be acquired with improved signal-to-noise ratio, more uniform illumination of targets, increased lateral resolution, more accurate amplitude attributes, and better multiple attenuation, such data will have strong interest by the industry. The objectives of this research are: (1) determine the feasibility of extracting direct SV-SV common-mid-point sections from 3-C seismic surveys, (2) improve the exploration for stratigraphic traps by developing systematic relationship between petrophysical properties and combinations of P and S wave modes, (3) create compelling examples illustrating how hydrocarbon-bearing reservoirs in low-permeable rocks (particularly anisotropic shale formations) can be better characterized using different S-wave modes (P-SV, SV-SV) in addition to the conventional P-P modes, and (4) analyze P and S radiation patterns produced by a variety of seismic sources. The research done in this study has contributed to understanding the physics involved in direct-S radiation from vertical-force source stations. A U.S. Patent issued to the Board of Regents of the University of Texas System now protects the intellectual property the Exploration Geophysics Laboratory has developed related to S-wave generation by vertical-force sources. The University’s Office of Technology Commercialization is actively engaged in commercializing this new S-wave reflection seismic technology on behalf of the Board of Regents.
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Books on the topic "Hydrocarbon-bearing"

Morton, Robert A. Depositional history, facies analysis, and production characteristics of hydrocarbon-bearing sediments, offshore Texas. Austin, Tex: Bureau of Economic Geology, University of Texas at Austin, 1985.

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Valin, Zenon C. Molecular and isotopic analyses of the hydrocarbon gases within gas hydrate-bearing rock units of the Prudhoe Bay-Kuparuk River area in northern Alaska. [Menlo Park, CA.]: U.S. Geological Survey, 1992.

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Molecular and isotopic analyses of the hydrocarbon gases within gas hydrate-bearing rock units of the Prudhoe Bay-Kuparuk River area in northern Alaska. [Menlo Park, CA.]: U.S. Geological Survey, 1992.

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S, Collett T., and United States. Dept. of Energy, eds. Molecular and isotopic analyses of the hydrocarbon gases within gas hydrate-bearing rock units of the Prudhoe Bay-Kuparuk River area in northern Alaska. [Menlo Park, CA.]: U.S. Geological Survey, 1992.

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Book chapters on the topic "Hydrocarbon-bearing"

Parnell, John, and Alistair McCready. "Paragenesis of gold- and hydrocarbon-bearing fluids in gold deposits." In Organic Matter and Mineralisation: Thermal Alteration, Hydrocarbon Generation and Role in Metallogenesis, 38–52. Dordrecht: Springer Netherlands, 2000. http://dx.doi.org/10.1007/978-94-015-9474-5_3.

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Djunin, V. I., and A. V. Korzun. "Fluidodynamics in Hydrocarbon-Bearing Formations of the Northern Pechora Petroliferous Basin." In Hydrogeodynamics of Oil and Gas Basins, 187–238. Dordrecht: Springer Netherlands, 2009. http://dx.doi.org/10.1007/978-90-481-2847-1_8.

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Cao, L. "Fungal Communities of Methane Clathrate-Bearing Deep Sea Sediments." In Handbook of Hydrocarbon and Lipid Microbiology, 2225–30. Berlin, Heidelberg: Springer Berlin Heidelberg, 2010. http://dx.doi.org/10.1007/978-3-540-77587-4_161.

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Falkner, A., and C. Fielding. "Quantitative Facies Analysis of Coal-Bearing Sequences in the Bowen Basin, Australia: Applications to Reservoir Description." In The Geological Modelling of Hydrocarbon Reservoirs and Outcrop Analogues, 81–97. Oxford, UK: Blackwell Publishing Ltd., 2009. http://dx.doi.org/10.1002/9781444303957.ch4.

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Mastalerz, M., R. M. Bustin, A. J. Sinclair, B. A. Stankiewicz, and M. L. Thomson. "Implications of hydrocarbons in gold-bearing epithermal systems: Selected examples from the Canadian Cordillera." In Organic Matter and Mineralisation: Thermal Alteration, Hydrocarbon Generation and Role in Metallogenesis, 359–77. Dordrecht: Springer Netherlands, 2000. http://dx.doi.org/10.1007/978-94-015-9474-5_17.

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"hydrocarbon-bearing." In Dictionary Geotechnical Engineering/Wörterbuch GeoTechnik, 700. Berlin, Heidelberg: Springer Berlin Heidelberg, 2014. http://dx.doi.org/10.1007/978-3-642-41714-6_81892.

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Morton, R. A., L. A. Jirik, and R. Q. Foote. "FACIES ANALYSIS OF HYDROCARBON-BEARING SEDIMENTS, OFFSHORE TEXAS." In Habitat of Oil and Gas in the Gulf Coast. SEPM Society for Sedimentary Geology, 1985. http://dx.doi.org/10.5724/gcs.85.04.0061.

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Eyles, N., A. B. França, G. Gonzalez Bonorino, C. H. Eyles, and O. López Paulsen. "Hydrocarbon-Bearing Late Paleozoic Glaciated Basins of Southern and Central South America." In Petroleum Basins of South America. American Association of Petroleum Geologists, 1995. http://dx.doi.org/10.1306/m62593c7.

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Krzywiec, P., T. M. Peryt, H. Kiersnowski, P. Pomianowski, G. Czapowski, and K. Kwolek. "Permo-Triassic Evaporites of the Polish Basin and Their Bearing on the Tectonic Evolution and Hydrocarbon System, an Overview." In Permo-Triassic Salt Provinces of Europe, North Africa and the Atlantic Margins, 243–61. Elsevier, 2017. http://dx.doi.org/10.1016/b978-0-12-809417-4.00012-4.

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Conference papers on the topic "Hydrocarbon-bearing"

Worthington, Paul Francis. "Quality-Assured Evaluation Of Freshwater-Bearing Hydrocarbon Reservoirs." In SPE Asia Pacific Oil and Gas Conference and Exhibition. Society of Petroleum Engineers, 2010. http://dx.doi.org/10.2118/133898-ms.

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P. Sibiriakov, B. "Prediction of stresses in hydrocarbon bearing structures using seismics." In 58th EAEG Meeting. Netherlands: EAGE Publications BV, 1996. http://dx.doi.org/10.3997/2214-4609.201408893.

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Burtman, Vladimir, Masashi Endo, Michael S. Zhdanov, and Thomas Ingeman‐Nielsen. "High‐frequency induced polarization measurements of hydrocarbon‐bearing rocks." In SEG Technical Program Expanded Abstracts 2011. Society of Exploration Geophysicists, 2011. http://dx.doi.org/10.1190/1.3628168.

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Popielski, Andrew C., Zoya Heidari, and Carlos Torres-Verdin. "Rock Classification from Conventional Well Logs in Hydrocarbon-Bearing Shale." In SPE Annual Technical Conference and Exhibition. Society of Petroleum Engineers, 2012. http://dx.doi.org/10.2118/159255-ms.

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Rasmussen, R., O. V. Vejbæk, S. A. Petersen, L. Klinkby, and P. Japsen. "Modelling of Seismic Response from Hydrocarbon Bearing North Sea Chalk." In 67th EAGE Conference & Exhibition. European Association of Geoscientists & Engineers, 2005. http://dx.doi.org/10.3997/2214-4609-pdb.1.p601.

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Latief, Fourier Dzar Eljabbar, and Tedy Muslim Haq. "Digital characterization and preliminary computer modeling of hydrocarbon bearing sandstone." In 4TH INTERNATIONAL CONFERENCE ON MATHEMATICS AND NATURAL SCIENCES (ICMNS 2012): Science for Health, Food and Sustainable Energy. AIP Publishing LLC, 2014. http://dx.doi.org/10.1063/1.4868762.

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Burtman, V., M. Endo, T. Ingeman-Nielsen, and M. S. Zhdanov. "Spectral Induced Polarization Measurements of Hydrocarbon-bearing Rocks and Fluids." In Saint Petersburg 2012. Netherlands: EAGE Publications BV, 2012. http://dx.doi.org/10.3997/2214-4609.20143667.

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Moosavi, N., and M. Bagheri. "Modeling Hydrocarbon Bearing Reservoirs Using Fuzzy SVR and Electrofacies Analysis." In NSG2021 27th European Meeting of Environmental and Engineering Geophysics. European Association of Geoscientists & Engineers, 2021. http://dx.doi.org/10.3997/2214-4609.202120145.

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Ray, Amit Kumar, Ritesh Kumar Sharma*, and Satinder Chopra. "Hydrocarbon-bearing dolomite reservoir characterization: A case study from eastern Canada." In SEG Technical Program Expanded Abstracts 2014. Society of Exploration Geophysicists, 2014. http://dx.doi.org/10.1190/segam2014-0240.1.

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Kallesten, E. I., U. Zimmermann, M. V. Madland, and M. W. Minde. "Petrological, Mineralogical and Geochemical Constraints on Hydrocarbon Bearing North Sea Reservoir Chalk." In IOR 2017 - 19th European Symposium on Improved Oil Recovery. Netherlands: EAGE Publications BV, 2017. http://dx.doi.org/10.3997/2214-4609.201700300.

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Reports on the topic "Hydrocarbon-bearing"

Jennie Ridgley. ANALYSIS OF OIL-BEARING CRETACEOUS SANDSTONE HYDROCARBON RESERVOIRS, EXCLUSIVE OF THE DAKOTA SANDSTONE, ON THE JICARILLA APACHE INDIAN RESERVATION, NEW MEXICO. Office of Scientific and Technical Information (OSTI), May 2000. http://dx.doi.org/10.2172/834191.

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Ridgley, Jennie, and Robyn Wright Dunbar. Analysis of oil-bearing Cretaceous sandstone hydrocarbon reservoirs, exclusive of the Dakota Sandstone, on the Jicarilla Apache Indian Reservation, New Mexico. Office of Scientific and Technical Information (OSTI), June 2000. http://dx.doi.org/10.2172/756282.

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Thermal maturity of hydrocarbon-bearing formations in southwestern Wyoming and northwestern Colorado. US Geological Survey, 1987. http://dx.doi.org/10.3133/i1831.

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