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Pereira, Leonardo Azevedo Guerra Raposo. "Seismic attributes in hydrocarbon reservoirs characterization." Master's thesis, Universidade de Aveiro, 2009. http://hdl.handle.net/10773/2735.
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Mestrado em Engenharia GeológicaNo presente trabalho apresentam-se as vantagens da utilização de atributos sísmicos na interpretação de dados de sísmica de reflexão 3D e na identificação e caracterização de reservatórios de hidrocarbonetos. O trabalho prático necessário para a elaboração desta tese foi realizado durante um estágio de quatro meses na empresa de serviços para a indústria petrolífera, Schlumberger, em Paris, utilizando o software de interpretação sísmica e de modelação de reservatórios de hidrocarbonetos, Petrel 2008.1. Os atributos sísmicos podem ser considerados formas alternativas de visualizar os dados de sísmica de reflexão, que normalmente são representados em amplitude. A sua utilização facilita o processo de interpretação sísmica, uma vez que permite aumentar a razão sinal-ruído, detectar descontinuidades, reforçar a continuidade dos reflectores sísmicos e evidenciar indicadores directos de hidrocarbonetos nos dados sísmicos originais. Os atributos sísmicos podem ainda ser usados para treinar processos de auto-aprendizagem utilizados em redes neuronais na predição da distribuição de facies numa área em estudo. De uma forma geral, a utilização de atributos sísmicos facilita a correlação entre os dados provenientes do método sísmico, dados de poços e a geologia da área em estudo. Neste trabalho foi utilizado um bloco migrado de sísmica de reflexão 3D, com aproximadamente 6000 km2, adquirido no deep-offshore da costa Oeste Africana. Para além de um teste individual dos atributos sísmicos disponíveis no Petrel 2008.1, esta tese incluí uma avaliação preliminar do potencial em hidrocarbonetos de um sistema de canais amalgamados identificado na área em estudo. A sua identificação, interpretação e caracterização foi possível com o recurso a atributos sísmicos que evidenciam a presença de falhas, ou outras descontinuidades, e de atributos sísmicos sensíveis a pequenas variações na litologia e à presença de fluídos nos poros das formações litológicas. ABSTRACT: In this work the advantages related to the use of seismic attributes in the interpretation of 3D seismic data and in the characterization of hydrocarbon reservoirs are discussed. A four months internship at Schlumberger, in Paris, using the Petrel 2008.1 “seismic-to-simulation” software provided the necessary data to perform the work described in this thesis. Seismic attributes are different ways to look at the original seismic data, which normally is displayed in amplitudes. Using seismic attributes during the seismic interpretation process allow a significant improvement in the signal-to-noise ratio, the automatic detection of discontinuities, the enhancement of seismic reflectors continuity and the enhancement of direct hydrocarbon indicators. In the self-learning process for neural networks, seismic attributes can be used as training data to predict facies distribution in the study area. Generally, seismic attributes provide a better correlation between the data provided by the seismic reflection method, well log data and the geology of the study area. In this work, a 3D migrated seismic cube was used, with an approximate area of 6000km2, acquired in the deep-water of West Africa. Besides an individual test of each attribute available in Petrel 2008.1, this thesis also includes a preliminary evaluation of the oil and gas potential of a system of stacked channels identified within the study area. The identification, interpretation and characterization of this potential hydrocarbon reservoir was possible using seismic attributes to enhance faults and other discontinuities, and by using seismic attributes sensitive to subtle lithological variations and the presence of fluids in the pore spaces of the lithological formations.
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Taylor, Katherine Sarah. "Ephemeral-fluvial sediments as potential hydrocarbon reservoirs." Thesis, University of Aberdeen, 1994. http://digitool.abdn.ac.uk:80/webclient/DeliveryManager?pid=123206.
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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. Ephemeral flows occur in direct response to precipitation, receiving little or no water from springs or other long-continued sources. They consequently predominate in dryland regions where precipitation is high in intensity, short lived and of limited areal extent. Resulting flow is high energy, relatively shallow and also restricted in duration and areal coverage. High transmission losses, abundant loose material and sparse vegetation result in highly concentrated flows which dissipate rapidly, causing a downstream decrease in flow discharge. Sediments deposited from these flows include parallel laminated sands, massive sands, scour-fill sands, transitional lower to upper flow regime dunes, and commonly contain numerous erosional discontinuities, scattered mudclasts, rapid grain size changes and deformational features. Large quantities of rainfall falling over longer periods produces steady flows dominated by well sorted, lower flow regime bedforms which have moderately well developed fining-up sequences. High intensity rainfall falling for shorter periods produces unsteady flows which are characterised by more poorly sorted, upper flow regime bedforms and an absence of fining-up sequences. 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 complex series of stacked, sand-dominated sheet-like palaeochannels suggestive of low sinuosity, braided systems.
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Seth, Siddhartha. "Increase in surface energy by drainage of sandstone and carbonate." Laramie, Wyo. : University of Wyoming, 2006. http://proquest.umi.com/pqdweb?did=1221730011&sid=4&Fmt=2&clientId=18949&RQT=309&VName=PQD.
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Owens, John. "Using object-oriented databases to model hydrocarbon reservoirs." Thesis, University of Aberdeen, 1995. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.262174.
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Hydrocarbon reservoir modelling plays a central role in the exploration and production of reservoirs. This thesis describes significant improvements in the way that data and knowledge about reservoir modelling is used in comparison with other attempts at such modelling. This thesis describes the development of a flexible reservoir modelling environment which allows users to apply their own knowledge in order to influence the modelling process. The modelling environment allows users to explore their own 'What if ...' hypotheses. A Smalltalk/V functional data model has been used as a front end to an object-oriented database (P/FDM). A technique called transparent object migration has been developed which allows objects from P/FDM to be reconstructed in the Smalltalk/V functional data model. The thesis describes how users can configure their own stochastic modelling algorithms. Common stages in stochastic modelling algorithms have been isolated and a number of alternatives developed for each stage. This has been implemented in an object-oriented architecture which allows users to configure their own algorithms from the re-usable parts supplied. A graphical probability distribution function editor has been developed. This provides a graphical representation of a probability distribution function which can be easily modified by the user, without the user having to provide a quantitative description of the changes that are required. By using this technique as part of a feedback loop, the user can develop reservoir models which they have more belief in.
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Fang, Chao. "Pore-scale Interfacial and Transport Phenomena in Hydrocarbon Reservoirs." Diss., Virginia Tech, 2019. http://hdl.handle.net/10919/89911.
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Exploring unconventional hydrocarbon reservoirs and enhancing the recovery of hydrocarbon from conventional reservoirs are necessary for meeting the society's ever-increasing energy demand and requires a thorough understanding of the multiphase interfacial and transport phenomena in these reservoirs. This dissertation performs pore-scale studies of interfacial thermodynamics and multiphase hydrodynamics in shale reservoirs and conventional oil-brine-rock (OBR) systems.
In shale gas reservoirs, the imbibition of water through surface hydration into gas-filled mica pores was found to follow the diffusive scaling law, but with an effective diffusivity much larger than the self-diffusivity of water molecules. The invasion of gas into water-filled pores with width down to 2nm occurs at a critical invasion pressure similar to that predicted by the classical capillary theories if effects of disjoining pressure and diffusiveness of water-gas interfaces are considered. The invasion of oil droplets into water-filled pores can face a free energy barrier if the pressure difference along pore is small. The computed free energy profiles are quantitatively captured by continuum theories if capillary and disjoining pressure effects are considered. Small droplets can invade a pore through thermal activation even if an energy barrier exists for its invasion.
In conventional oil reservoirs, low-salinity waterflooding is an enhanced oil recovery method that relies on the modification of thin brine films in OBR systems by salinity change. A systematic study of the structure, disjoining pressure, and dynamic properties of these thin brine films was performed. As brine films are squeezed down to sub-nanometer scale, the structure of water-rock and water-oil interfaces changes marginally, but that of the electrical double layers in the films changes greatly. The disjoining pressure in the film and its response to salinity change follow the trend predicted by the DLVO theory, although the hydration and double layer forces are not simple additive as commonly assumed. A notable slip between the brine film and the oil phase can occur.
The role of thin liquid films in multiphase transport in hydrocarbon reservoirs revealed here helps lay foundation for manipulating and leveraging these films to enhance hydrocarbon production and to minimize environmental damage during such extraction.Doctor of Philosophy
Meeting the ever-increasing energy demand requires efficient extraction of hydrocarbons from unconventional reservoirs and enhanced recovery from conventional reservoirs, which necessitate a thorough understanding of the interfacial and transport phenomena involved in the extraction process. Abundant water is found in both conventional oil reservoirs and emerging hydrocarbon reservoirs such as shales. The interfacial behavior and transport of water and hydrocarbon in these systems can largely affect the oil and gas recovery process, but are not well understood, especially at pore scale. To fill in the knowledge gap on these important problems, this dissertation focuses on the pore-scale multiphase interfacial and transport phenomena in hydrocarbon reservoirs. In shales, water is found to imbibe into strongly hydrophilic nanopores even though the pore is filled with highly pressurized methane. Methane gas can invade into water-filled nanopores if its pressure exceeds a threshold value, and the thin residual water films on the pore walls significantly affect the threshold pressure. Oil droplet can invade pores narrower than their diameter, and the energy cost for their invasion can only be computed accurately if the surface forces in the thin film formed between the droplet and pore surface are considered. In conventional reservoirs, thin brine films between oil droplet and rock greatly affect the wettability of oil droplets on the rock surface and thus the effectiveness of low-salinity waterflooding. In brine films with sub-nanometer thickness, the ion distribution differs from that near isolated rock surfaces but the structure of water-brine/rock interfaces is similar to their unconfined counterparts. The disjoining pressure in thin brine films and its response to the salinity change follow the trend predicted by classical theories, but new features are also found. A notable slip between the brine film and the oil phase can occur, which can facilitate the recovery of oil from reservoirs.
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Obidi, Onochie. "Timescales for the development of thermodynamic equilibrium in hydrocarbon reservoirs." Thesis, Imperial College London, 2014. http://hdl.handle.net/10044/1/24880.
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The full understanding of the initial state of petroleum reservoirs and the fluxes that lead to compositional variations have become of huge interest to the petroleum industry. The compositional variation of reservoir fluid has great commercial impact on reservoir management and field development as it affects the value of the hydrocarbon in place, what recovery mechanisms applied and the treatment process of the extracted fluid if necessary. Lateral and vertical variation in hydrocarbon density and composition between wells are observed in many oil reservoirs under appraisal. These gradations may be due to changes in reservoir filling over geological time, in which case the variations are not in an equilibrium state, or alternatively due to an equilibrium between chemical, thermal and gravity potentials. The mixing of non-equilibrium compositional distributions is affected by Darcy flows (if there is a resulting pressure gradient), gravitational overturning (if there is a density difference) and molecular diffusion. The diffusion flux may also be affected by gravitational and thermal effects. Previous work has focused primarily on convective mixing and simple models of mixing via molecular diffusion. This work focuses on the rate of mixing via molecular diffusion, including the effects of pressure and thermal diffusion, which are modelled using the thermodynamics of irreversible processes for a single phase system. The interaction of diffusional mixing and gravitational overturning is also examined. The timescales to attain steady state are analyzed as well as the resulting compositional profiles. The developed model has been validated using simple transient analytical solution proposed by Carslaw and Jaeger (1959) for the molecular diffusion flux and Gardner et al. (1962) for the natural convection process. The diffusive fluxes in our model are also validated by steady state analytical solutions for species segregating in a thermo-gravitational column. The developed model was used to analyze the experimental results obtained for two ternary mixtures of methane, n-pentane and 1-methylnapthalene; and methane, n-pentane and undecane by Ratulowski et al. (2003). Although 1-methylnapthalene and undecane have similar molar masses, the system containing 1-methylnapthalene resulted in a bigger grading (difference in mole fraction at the top and bottom of the system) than the latter. This analysis demonstrates the impact of real mixture modelling (as opposed to the case when an ideal fluid is assumed) on the segregation-mixing process. Finally, we show how the knowledge of the timescales for observed compositional variations to reach equilibrium can be used to estimate the time since a reservoir filled. The Madison formation in the LaBarge field in Wyoming, U.S.A was studied. This is an unusual gas reservoir, as non-hydrocarbons make up about 80% of the total gas composition, with methane constituting the remainder. The methane composition varies significantly, 22% at the crest of the formation to 5% near the GWC. There are several hypotheses in the literature behind the unusual gas composition and distribution in this formation (De Bruin, 2001; Stilwell, 1989; Huang et al., 2007). We use the fluid mixing model to test the various hypotheses. The results reveal that the geothermal gradient in this field is not sufficient to make the thermal diffusion and thermal convection process in this reservoir override the effect of the molecular diffusion. We conclude that the reservoir is not yet in compositional equilibrium as molecular diffusion will completely homogenize the composition variation in this field. We propose that the currently observe composition profile is as result of the formation being enriched with CO2 at approximately 3 million years ago. This timescale is contemporaneous with the volcanic activity proposed by De Bruin (2001) and Stilwell (1989).
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Coffey, Melody Roy. "Microbially Mediated Porosity Enhancement in Carbonate Reservoirs: Experiments with samples from the Salem, Sligo, and Smackover Formations." MSSTATE, 2004. http://sun.library.msstate.edu/ETD-db/theses/available/etd-10122004-105856/.
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This study used petrographic thin sections, scanning electron microscopy, and confocal laser microscopy to document microbially mediated dissolution of carbonate reservoir rocks. The samples studied came from three carbonate units that are hydrocarbon reservoirs; the Salem, Sligo, and Smackover formations. These samples were inoculated with bacteria, and then treated with nutrient solutions followed by ethanol to promote generation of acetic acid by bacteria. Dissolution occurred in calcite-dominated rocks and in dolomitized rocks. Noticeable changes first occurred after nine weeks of ethanol treatment and significant change only occurred after twelve weeks of ethanol treatment. The size of the vuggy pores created increased from 1 µm or less to over 5 µm, and rarely over 10 µm, in length.
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Calleja, Glecy School of Biological Earth & Environmental Sciences UNSW. "Influence of mineralogy on petrophysical properties of petroleum reservoir beds." Awarded by:University of New South Wales. School of Biological, Earth and Environmental Sciences, 2005. http://handle.unsw.edu.au/1959.4/22423.
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Key petrophysical properties of reservoir sequences are determined by their individual mineral compositions, and are routinely evaluated through the analysis of cores and geophysical well logs. However, mineralogical studies are seldom incorporated in reservoir assessment. The objectives of the study were to investigate the influence of mineralogy on petrophysical properties of petroleum reservoir beds and the application of mineralogical studies in reservoir evaluation. Mineralogical analyses were performed on core samples from the Plover Formation, the principal reservoir sequence in the Northwest Shelf area of Australia, intersected in two separate wells in the Laminaria petroleum field. The techniques used included X-ray powder and oriented-aggregate analysis, optical microscopy and whole rock geochemistry. Quantification of each mineral phase based on whole-rock powder data was performed using the Rietveld-based Siroquant technique. Results from the Siroquant assay were used as an indicator of mineralogy for the individual samples and were compared with core plug and geophysical log data. X-ray micro-tomography analysis of selected samples was also performed. The reservoir sequences in both wells were sand-dominated, consisted mostly of quartz, clay mineral matrix and cement of silica, pyrite or calcite. The abundance of clay minerals increased in the shale and shaly sandstone intervals. Comparison of mineralogical and core plug analyses of samples from the same depths showed that the down-hole variations in porosity, permeability, grain density and radioactivity were accompanied by changes in mineralogy. Higher proportion of clay minerals in shales was indicated by higher gamma log signals. The gamma log may be taken as an indicator of shaliness only in intervals where kaolinite is proportional to the quantity of illitic clays. Sonic log and neutron log porosity values are comparable with core plug porosity data in sandstone intervals. However, clay minerals increase the sonic log response, thereby increasing porosity in shaly intervals. Clay minerals tend to decrease the neutron log response causing higher porosity indication in shales, similar to that expected in sandstones. Routine density log analysis underestimated porosity values because of the contribution of dense minerals to the bulk density of the formation. Use of laboratory determined grain and fluid densities resulted in improved density log porosity compared to core porosity. X-ray tomography analysis revealed an overall positive correlation between mineralogy and porosity data. Routine geophysical log evaluation revealed inconsistent results when compared to core analysis data because of the influence of minerals on various logs. It is essential that mineralogical studies be included in reservoir assessment. X-ray tomography may provide an alternative approach in evaluating porosity and mineralogy.
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Berhanu, Solomon Assefa. "Seismic and petrophysical properties of carbonate reservoir rocks." Thesis, University of Reading, 1994. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.262633.
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Devine, Carol A. "16S ribosomal DNA analysis of microbial populations associated with hydrocarbon reservoirs." Thesis, University of Aberdeen, 2000. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.312360.
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The sulphate-reducing bacteria (SRB) are a diverse group of organisms which use sulphate as a terminal electron acceptor and produce the highly toxic gas, hydrogen sulphide. The deleterious effects of this include hydrocarbon reservoir souring, formation damage and microbial corrosion. The SRB are of major economic importance to the oil industry. However, knowledge of the microbial ecology of the deep subsurface remains limited. The aim of this project was to investigate whether organisms are indigenous to the hydrocarbon formation and/or are introduced during drilling operations. A range of molecular techniques such as 16S rDNA sequence analysis, probing with labelled oligonucleotides, and denaturing gradient gel electrophoresis (DGGE) were employed to investigate the microbial diversity in oil field samples. A wide range of bacterial 16S rDNA sequences were identified using these molecular methods. An analysis of drilling mud samples revealed a diverse range of bacterial 16S rDNA sequences confirming that bacteria, including SRB, can be introduced to the reservoir during drilling operations. A number of bacterial 16S rDNA sequences were recovered from a geological core sample taken from a depth of 9,770 feet. The microbial diversity was remarkable in such a high temperature, high pressure environment. This lends credence to the theory that certain bacteria may be indigenous to the subsurface environment. Scanning electron micrographs of core which had been incubated in growth medium indicated the presence of 'nannobacteria'. These tiny coccoids, with a diameter of only 0.1 μm are far smaller than the generally accepted minimum size for cellular life forms. The nannobacteria grew in regular colony shaped structures and were seen only in sections taken from inside the rock. This study indicates that hydrocarbon reservoirs provide an environment in which bacteria, if introduced during drill operations, may become established. However, the subsurface also contains complex indigenous microbial populations that demonstrate considerable species diversity and may include unrecognised life forms.
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Fonseca, Rojas Mirla Josefina. "Phase behaviour modelling of water-hydrocarbon in high temperature petroleum reservoirs." Thesis, Heriot-Watt University, 2006. http://hdl.handle.net/10399/2152.
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Development of high pressure-high temperature (RPHT) reservoirs is increasingly being pursued world wide to exploit hydrocarbon from deep formation. Due to their extreme conditions (can be up to 2000e and 16000 psia), composition of RPHT fluids can be considerably different from that of conventional reservoirs, particularly the concentration of heavy hydrocarbons in the vapour phase can be quite high. Also, at high temperature the amount of water dissolved in the reservoir hydrocarbon phase could be significant and should be taken into account in detennining the phase and volumetric properties of the fluids. In this study, a model based on equations of state (BOS) was developed to predict phase behaviour of RPHT fluids in the presence of water. The conventional mixing rule was modified by adding a non-random element in the attractive term of EOS. This modification was required to describe the interaction between non-polar (hydrocarbon) and polar (water) compounds. The developed phase behaviour model with the added term to the conventional mixing rules was evaluated for predicting the phase behaviour of hydrocarbon mixtures in presence of water. The conventional (random) interaction parameters (kij) and the non-random interaction parameter of the asymmetric term (lpi) for water-hydrocarbons were determined by matching the solubility data of hydrocarbon-water binary systems in vapour-liquid equilibrium for light and in liquid-liquid equilibrium for intermediate and heavy hydrocarbons. A method based on the Krichevsky-Kasarnovsky equation was developed to correct the effect of pressure on fugacity of the solute in the liquid phase in liquid-liquid equilibrium. The determined binary interaction parameters (BIP) were generalised by correlating them with critical properties and the molecular weight of hydrocarbons. The reliability of the model was evaluated against measured data, not used in its development, over a wide range of pressure and temperature and compared with those of leading models reported in the literature. The model could reliably predict the presence of free water phase and the effect of pressure on the liquid water phase at high temperatures. It also reliably predicted the effect of water on saturation pressure of tested synthetic reservoir fluids. However, it failed to accurately reproduce the effect of addition of water on the volumetric behaviour of the liquid hydrocarbon phase.
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Besong, Donald Ojong. "Time-scales for the development of thermodynamic equilibrium in hydrocarbon reservoirs." Thesis, Imperial College London, 2009. http://hdl.handle.net/10044/1/5848.
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This project investigates the time-scales for hydrocarbon components in an isothermal oil reservoir column to reach thermodynamic equilibrium under the competing influences of molecular diffusion and gravitational segregation by gravity diffusion. The influence of non ideal behaviour on the equilibrium compositional profile, as well as on the equilibrium time for some examples of binary and ternary hydrocarbon mixtures is also investigated. When the variation of hydrocarbon composition within a field cannot be described by standard steady-state models of gravity-diffusion equilibrium, it is usually assumed to be caused by some degree of hindrance to the connectivity of the oil volume, a situation known as reservoir compartmentalization. However, order of magnitude estimates of the time taken for thermodynamic equilibrium to be established by diffusion are similar to the ages of many hydrocarbon reservoirs (between 1 million and 100 million years). Thus it is possible that compositional variations within a reservoir may be simply due to there having been insufficient time from reservoir filling for diffusion to equilibrate compositions. It is important to determine the time-scales for vertical compositional gradients to be established in order to assess whether compositional profiles that are not in thermodynamic equilibrium are indicative of barriers to flow within the reservoir or simply that the reservoir fluids have not yet had time to establish a steady-state distribution. A macroscopic, numerical model of the thermodynamic behaviour of the reservoir fluids has been used for this investigation. The model has been validated against simple transient analytic solutions for molecular diffusion, as well as steady-state solutions for molecular/gravity diffusion in binary mixtures. It was found that a uniform mixture of methane and undecane will segregate over a vertical distance of 300m in a few hundred thousand years and that this timescale can be affected by non-ideal mixing and the relative proportions of the two components. Equilibrium time was found to be a function of the competing influences of molecular diffusion and gravitational segregation. We also use our model to investigate laboratory observations of compositional grading in ternary mixtures of methane, n-pentane and 1-methylnapthalene reported by Ratulowski et al. (2003) and why their numerical simulation produced an unexpectedly smaller separation when methylnaphthalene was replaced by n-undecane, although methylnaphthalene and undecane have almost the same molar weight. Our study also provides insight into the relative importance of density, molecular diffusion, initial composition and realmixture modelling (as opposed to ideal mixture assumptions) on compositional grading in a fluid more representative of a real crude oil.
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Tran, Nam Hong Petroleum Engineering Faculty of Engineering UNSW. "Characterisation and modelling of naturally fractured reservoirs." Awarded by:University of New South Wales. Petroleum Engineering, 2004. http://handle.unsw.edu.au/1959.4/20559.
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Naturally fractured reservoirs are generally extremely complex. The aim of characterisation and modelling of such reservoirs is to construct numerical models of rock and fractures, preparing input data for reliable stimulation and fluid flow simulation analyses. This requires the knowledge of different fracture heterogeneities and their correlations at well locations and inter-well regions. This study addresses the issues of how to integrate different information from various field data sources and construct comprehensive discrete fracture networks for naturally fractured reservoir. The methodology combines several mathematical and artificial intelligent techniques, which include statistics, geostatistics, fuzzy neural network, stochastic simulation and simulated annealing global optimisation. The study has contributed to knowledge in characterisation and modelling of naturally fractured reservoirs in several ways. It has developed: .An effective and data-dependant fracture characterisation procedure. It examines all the conventional reservoir data sources and their roles towards characterisation of different fracture properties. The procedure has the advantage of being both comprehensive and flexible. It is able to integrate all multi-scaled and diverse fracture information from the different data sources. .An improved hybrid stochastic generation algorithm for modelling discrete fracture networks. The stochastic simulation is able to utilise both discrete and continuum fracture information. It could simulate not only complicated distributions for fracture properties (e.g. multimodal circular statistics and non-parametric distributions) but also their correlations. In addition, with the incorporation of artificial fuzzy neural simulation, discrete multifractal geometry of fracture size and fracture density distribution map could be evaluated and modelled. Compared to most of the previous fracture modelling approach, this model is more flexible and comprehensive. .An improved conditional global optimisation model for modelling discrete fracture networks. The hybrid model takes full advantages of the advanced fracture characterisation using geostatistical and fuzzy neural analyses. Discrete fractures are treated individually and yet continuum information could be modelled. Compared to the stochastic simulation approach, this model produces more representative fracture networks. Compared to the conventional optimisation programs, this model is more versatile and contains superior objective function.
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Caruana, Albert. "Immiscible flow behaviour within heterogeneous porous media." Thesis, University of London, 1997. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.285232.
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Robinson, Julian M. "Prediction of fracturing in reservoirs from an analysis of curvature of folded surfaces." Thesis, Cardiff University, 1997. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.364063.
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Taggart, Samantha. "Quantifying the impact of geological heterogeneity on hydrocarbon recovery in marginal aeolian reservoirs." Thesis, Imperial College London, 2009. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.504905.
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Muia, George. "The ''Turkana Grits'' : Potential Hydrocarbon Reservoirs of the Northern and Central Kenya Basins." Thesis, Rennes 1, 2015. http://www.theses.fr/2015REN1S069/document.
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Plus des deux tiers des champs pétroliers mondiaux se trouvent dans deux principaux environnements tectoniques : les marges continentales passives et les rifts continentaux. Dans le bassin de Lockichar dans le rift kenyan, plus de 600 millions de barils d'huile extractible ont été découverts. Les roches réservoirs principales dans ce bassin sont les grès de Lokone qui appartiennent à une famille plus large de grès appelés les ‘Turkana Grits', grès arkosiques en sandwich entre le socle métamorphique et les roches volcaniques du Miocène Moyen. La quantité des hydrocarbures dans les grès réservoirs de Lokone ont ainsi motivé la présente étude des ‘Turkana Grits' pour en préciser les caractéristiques en tant que réservoir potentiel d'hydrocarbures. Trois formations sédimentaires, c'est-à-dire, la Formation Kimwarer, la Formation Kamego et le grès de Loriu, qui n'ont jamais été complètement caractérisées du point de vue chronostratigraphique et sédimentologique ont été étudiées à travers des relevés détaillés. Plus de 170 échantillons ont été récoltés pour déterminer leur contenu en fraction détritique et authigène, les zones principales de cimentation des différents affleurements et, à partir d'une analyse des lithofaciès, les environnements de dépôts. Les échantillons de roches volcaniques et intrusives ont également été caractérisés et utilisés pour des datations avec la méthode 39Ar-40Ar. Trois environnements de dépôt superposés ont été déterminés pour la Formation Kimwarer : un chenal fluviatile distal, un cône d alluvial et une plaine d'inondation. L'étude diagénétique montre des changements de ciments à hématite dominante à la base, calcite dominante dans les zones intermédiaires et retour à l'hématite dominante au sommet de la formation. Les épisodes de cimentation opèrent pendant la diagénèse précoce à tardive, à basse température (<80°C), et en condition de compaction mécanique significative. Un âge minimum des dépôts d'environ 18 Ma (Miocène précoce-Burdigalien) a également été établi pour cette formation. La Formation Kamego évolue d'un environnement fluviatile à celui d'une plaine d'inondation et est principalement cimentée par de l'hématite. De la calcite est présente uniquement dans les premiers 5 m. Une coulée de lave peu épaisse interstratifiée dans les sédiments les plus jeunes de la Formation Kamego a livré un âge minimum des dépôts d'environ 20 Ma pour l'essentiel des sédiments. Le grès de Loriu est une formation principalement composée de dépôts de chenal fluviatile. Les principaux ciments sont la calcite, l'hématite et la kaolinite. Un filon intrusif suggère que l'âge minimum des dépôts est d'environ 18.5 Ma. L'analyse de réservoir finale sur les 'Turkana Grits' montre que la compaction et la cimentation sont les agents dominants de la réduction de porosité, et que les ‘Turkana Grits' sont généralement de médiocre à modérément bonnes unités réservoirs. Les grès de Lokone ont des porosités en sub-surface qui s'échelonnent entre 10 et 20 % et des perméabilités aussi élevées que 3 Darcy (Africa Oil Corporation, 2011). A partir des analyses pétrographiques, la Formation Kimwarer a été classée comme ayant la seconde place en tant que réservoir potentiel d'hydrocarbures avec des porosités aussi élevées que 20 % sur certains segments du log stratigraphique étudié. La Formation Kamego a également un bon potentiel mais n'est pas aussi bien classée à cause de la fraction importante de matériel volcanique qu'elle renferme et de la capacité de ce matériel à s'altérer au cours de la diagénèse. Les porosités sont basses dans les grès de Loriu, en conséquence cette formation n'est classée que cinquième parmi les Turkana Grits, réservoir potentiel d'hydrocarburesOver two thirds of the world’s giant oilfields are found in two principle tectonic regimes; continental passive margins and continental rifts. The preferential formation of hydrocarbons in rifts is attributed to the proximal juxtaposition of high grade, lacustrine source rock units with medium to high grade reservoir rocks - a consequence of both faulting and sedimentation in the resulting accommodation space, which in many cases may locally modify the prevailing climatic conditions. In one of such basins, the Lokichar Basin in the Kenyan Rift, over 600 million barrels of recoverable oil have been discovered. The principle reservoir unit in this basin is the Lokone Sandstone that belongs to a larger family of sandstones called the ‘Turkana Grits’, arkosic sandstones that are sandwiched between metamorphic basement and mid-Miocene volcanics. The hydrocarbon proclivity of the Lokone Sandstones as reservoir units motivated further study of the ‘Turkana Grits’, as potential hydrocarbon reservoirs. In this work, three sedimentary formations, i.e. Kimwarer Formation, Kamego Formation and Loriu Sandstones, which have not been previously fully characterized from chronostratigraphic and sedimentological point of views were studied through detailed logging. Over 170 samples were collected to determine, detrital and authigenic components, the main cementation zones in the different outcrops, and, from lithofacies analysis, the depositional environments. Volcanic and intrusive samples were also characterized and used for 39Ar-40Ar dating. Three superposed depositional environments were determined for the Kimwarer Formation, a distal fluvial channel, an alluvial fan and a floodplain depositional environment. The diagenetic study shows cements change from dominant hematite at the base to calcite within the middle zones and back to hematite towards the top of the Formation. These cementation episodes occur during early and relatively late diagenesis in low temperature conditions (<80 °C), under significant mechanical compaction. A minimum deposition age at ca. 18 Ma (Early Miocene – Burdigalian) has also been set for the Kimwarer Formation. The Kamego Formation evolves from fluvial to floodplain depositional environments and is dominantly cemented by hematite. Calcite cement is only noted in the lowermost 5m. A thin lava flow interbedded with the topmost sediments of the Kamego Formation gave a minimum deposition age of ca. 20 Ma for most of the sediments. The Loriu Sandstone is composed predominantly of fluvial channel deposits. The main cements are calcite, hematite and kaolinite clays. A cross-cutting dyke suggests a minimum deposition age of ca. 18.5Ma. A final reservoir analysis of the Turkana Grits shows that while compaction and cementation are dominant agents of porosity reduction, the Turkana Grits are generally poor to moderately good reservoir units. The Lokone Sanstone has been proven to have sub-surface porosities ranging between 10 - 20% and permeabilities as high as 3 darcies (Africa Oil Corporation, 2011). For petrographic analyses, the Kimwarer Formation has been ranked as having the second best reservoir potential with porosities as high as 20% in some sections of its studied stratigraphy. The Kamego Formation also has good potential but is not as highly ranked owing to the huge component of volcanic material that have a greater propensity to diagenetic alteration. No good porosities were noted for the Loriu Sandstone and hence this formation has been ranked 5th amongst the Turkana Grits
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Lowden, Ben D. "A methodology for the quantification of outcrop permeability heterogeneities through probe permeametry." Thesis, Imperial College London, 1993. http://hdl.handle.net/10044/1/7588.
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Zhang, Hongjie. "Spectral decomposition of outcrop-based synthetic seismic data, applied to reservoir prediction in deep-water settings." Thesis, University of Aberdeen, 2014. http://digitool.abdn.ac.uk:80/webclient/DeliveryManager?pid=215575.
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Dalrymple, Mark. "Sedimentological evolution of the Statfjord Formation fluvial hydrocarbon reservoirs of the northern North Sea." Thesis, University of Aberdeen, 1997. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.302647.
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The sedimentological evolution of the Statfjord Formation of the Viking Graben at the Triassic - Jurassic transition is detailed by integration of studies of mineral assemblages, isotope age data, sedimentological core analysis, palaeosol / mineralogical wireline analysis and regional correlation of subsurface wireline information, combined with theories on basin evolution in continental settings. The aim of this study is to enhance the description of, and correlation within, hydrocarbon reservoirs developed within intra-continental alluvial sediments which have been deposited in areas above the knickpoints of coastline attached incised valleys, where there is a paucity of biostratigraphical information. Sedimentological analysis of core, wireline suites and production data, allow a stratigraphic framework to be erected which can delineate reservoir flow units. In the absence of palynological datums, chronostratigraphic correlation is done by heavy mineral and geochemical analysis, distinguishing between individual flow units allowing a more genetic correlation between related sands to be made. These analytical studies also point the stratigrapher to a more accurate regional geomorphic interpretation of the core by defining units which have the same provenance, thus allowing comparison of differing sedimentological criteria within single fluvial or floodplain units. At a smaller scale, a short outcrop study of the Castisent Formation of the Spanish Pyrenees was done to illustrate the intra-alluvial sheet sand complexity present in subsurface hydrocarbon reservoirs of alluvial origin. Using data mainly from the Brent Field, Statfjord Field and Snorre Field a model for the regional evolution of the Statfjord Formation is developed. Regional correlation of the reservoir units within the Statfjord Formation, using the methods discussed above, demonstrates basic geomorphic principles which are specifically concerned with the regional development of aggradational and erosive alluvial suites in settings inland from coastal areas.
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Teimoori, Sangani Ahmad Petroleum Engineering Faculty of Engineering UNSW. "Calculation of the effective permeability and simulation of fluid flow in naturally fractured reservoirs." Awarded by:University of New South Wales. School of Petroleum Engineering, 2005. http://handle.unsw.edu.au/1959.4/22408.
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This thesis is aimed to calculate the effective permeability tensor and to simulate the fluid flow in naturally fractured reservoirs. This requires an understanding of the mechanisms of fluid flow in naturally fractured reservoirs and the detailed properties of individual fractures and matrix porous media. This study has been carried out to address the issues and difficulties faced by previous methods; to establish possible answers to minimise the difficulties; and hence, to improve the efficiency of reservoir simulation through the use of properties of individual fractures. The methodology used in this study combines several mathematical and numerical techniques like the boundary element method, periodic boundary conditions, and the control volume mixed finite element method. This study has contributed to knowledge in the calculation of the effective permeability and simulation of fluid flow in naturally fractured reservoirs through the development of two algorithms. The first algorithm calculates the effective permeability tensor by use of properties of arbitrary oriented fractures (location, size and orientation). It includes all multi-scaled fractures and considers the appropriate method of analysis for each type of fracture (short, medium and long). In this study a characterisation module which provides the detail information for individual fractures is incorporated. The effective permeability algorithm accounts for fluid flows in the matrix, between the matrix and the fracture and disconnected fractures on effective permeability. It also accounts for the properties of individual fractures in calculation of the effective permeability tensor. The second algorithm simulates flow of single-phase fluid in naturally fractured reservoirs by use of the effective permeability tensor. This algorithm takes full advantage of the control volume discretisation technique and the mixed finite element method in calculation of pressure and fluid flow velocity in each grid block. It accounts for the continuity of flux between the neighbouring blocks and has the advantage of calculation of fluid velocity and pressure, directly from a system of first order equations (Darcy???s law and conservation of mass???s law). The application of the effective permeability tensor in the second algorithm allows us the simulation of fluid flow in naturally fractured reservoirs with large number of multi-scale fractures. The fluid pressure and velocity distributions obtained from this study are important and can considered for further studies in hydraulic fracturing and production optimization of NFRs.
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Etienam, Clement. "Structural and shape reconstruction using inverse problems and machine learning techniques with application to hydrocarbon reservoirs." Thesis, University of Manchester, 2019. https://www.research.manchester.ac.uk/portal/en/theses/structural-and-shape-reconstruction-using-inverse-problems-and-machine-learning-techniques-with-application-to-hydrocarbon-reservoirs(e21f1030-64e7-4267-b708-b7f0165a5f53).html.
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This thesis introduces novel ideas in subsurface reservoir model calibration known as History Matching in the reservoir engineering community. The target of history matching is to mimic historical pressure and production data from the producing wells with the output from the reservoir simulator for the sole purpose of reducing uncertainty from such models and improving confidence in production forecast. Ensemble based methods such as the Ensemble Kalman Filter (EnKF) and Ensemble Smoother with Multiple Data Assimilation (ES-MDA) as been proposed for history matching in literature. EnKF/ES-MDA is a Monte Carlo ensemble nature filter where the representation of the covariance is located at the mean of the ensemble of the distribution instead of the uncertain true model. In EnKF/ES-MDA calculation of the gradients is not required, and the mean of the ensemble of the realisations provides the best estimates with the ensemble on its own estimating the probability density. However, because of the inherent assumptions of linearity and Gaussianity of petrophysical properties distribution, EnKF/ES-MDA does not provide an acceptable history-match and characterisation of uncertainty when tasked with calibrating reservoir models with channel like structures. One of the novel methods introduced in this thesis combines a successive parameter and shape reconstruction using level set functions (EnKF/ES-MDA-level set) where the spatial permeability fields' indicator functions are transformed into signed distances. These signed distances functions (better suited to the Gaussian requirement of EnKF/ES-MDA) are then updated during the EnKF/ES-MDA inversion. The method outperforms standard EnKF/ES-MDA in retaining geological realism of channels during and after history matching and also yielded lower Root-Mean-Square function (RMS) as compared to the standard EnKF/ES-MDA. To improve on the petrophysical reconstruction attained with the EnKF/ES-MDA-level set technique, a novel parametrisation incorporating an unsupervised machine learning method for the recovery of the permeability and porosity field is developed. The permeability and porosity fields are posed as a sparse field recovery problem and a novel SELE (Sparsity-Ensemble optimization-Level-set Ensemble optimisation) approach is proposed for the history matching. In SELE some realisations are learned using the K-means clustering Singular Value Decomposition (K-SVD) to generate an overcomplete codebook or dictionary. This dictionary is combined with Orthogonal Matching Pursuit (OMP) to ease the ill-posed nature of the production data inversion, converting our permeability/porosity field into a sparse domain. SELE enforces prior structural information on the model during the history matching and reduces the computational complexity of the Kalman gain matrix, leading to faster attainment of the minimum of the cost function value. From the results shown in the thesis; SELE outperforms conventional EnKF/ES-MDA in matching the historical production data, evident in the lower RMS value and a high geological realism/similarity to the true reservoir model.
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Rogers, Anna Louise. "Poroelastic modeling of groundwater and hydrocarbon reservoirs : investigating the effects of fluid extraction on fault stability." Thesis, Massachusetts Institute of Technology, 2017. http://hdl.handle.net/1721.1/113792.
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Thesis: S.M. in Geophysics, Massachusetts Institute of Technology, Department of Earth, Atmospheric, and Planetary Sciences, 2017.Cataloged from PDF version of thesis.
Includes bibliographical references (pages 91-93).
The possibility of human-triggered earthquakes is critical to understand for hazard mitigation. This project was developed to better understand the stability of faults in areas with high amounts of fluid extraction, and was applied to both a groundwater and hydrocarbon basin. The theory of poroelasticity was used to calculate the stress changes resulting from fluid flow. Then, the resulting fault stability was evaluated with the the Coulomb Failure Function ([Delta]CFF). A COMSOL and MATLAB workflow was used to derive the results. Two applications were completed. The primary research focused on the extraction from a groundwater aquifer in Lorca, Spain, in relation to the M, 5.1, 2011 earthquake. A smaller project was completed for the production of an oil well in Wheeler Ridge, California, in relation to the Mw 7.7, 1952 earthquake. In Lorca, it was found that extraction from a local aquifer promoted failure on an antithetic fault to the major Alhama de Murcia Fault. Specifically, while the left-lateral portion of the slip was stabilized, the reverse component of the slip was promoted (depth -5 km). Published InSAR and focal mechanism results support a rupture plane aligned with the antithetic fault. The final stress change was ~0.03 MPa which is small but not negligible compared to the expected total stress drop (~2 MPa). In California, the production from Well 85-29 was of interest. It was found that oil extraction promoted failure on the White Wolf Fault. There was a region adjacent to but below the reservoir that tended toward destabilization after the production. However, there was a notably small stress change (~0.5 kPA). This project lends to some important conclusions, and demonstrates that the poroelastic deformation of an aquifer or reservoir can result in distinct zones of stabilization and destabilization on pre-existing faults.
by Anna Louise Rogers.
S.M. in Geophysics
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Parker, Irfaan. "Petrophysical evaluation of sandstone reservoirs of the Central Bredasdorp Basin, Block 9, offshore South Africa." Thesis, University of the Western Cape, 2014. http://hdl.handle.net/11394/4661.
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>Magister Scientiae - MScThis contribution engages in the evaluation of offshore sandstone reservoirs of the Central Bredasdorp basin, Block 9, South Africa using primarily petrophysical procedures. Four wells were selected for the basis of this study (F-AH1, F-AH2, F-AH4, and F-AR2) and were drilled in two known gas fields namely F-AH and F-AR. The primary objective of this thesis was to evaluate the potential of identified Cretaceous sandstone reservoirs through the use and comparison of conventional core, special core analysis, wire-line log and production data. A total of 30 sandstone reservoirs were identified using primarily gamma-ray log baselines coupled with neutron-density crossovers. Eleven lithofacies were recognised from core samples. The pore reduction factor was calculated, and corrected for overburden conditions. Observing core porosity distribution for all wells, well F-AH4 displayed the highest recorded porosity, whereas well F-AH1 measured the lowest recorded porosity. Low porosity values have been attributed to mud and silt lamination influence as well as calcite overgrowths. The core permeability distribution over all the studied wells ranged between 0.001 mD and 2767 mD. Oil, water, and gas, were recorded within cored sections of the wells. Average oil saturations of 3 %, 1.1 %, and 0.2 % were discovered in wells F-AH1, F-AH2, and F-AH4. Wells F-AH1 to F-AR2 each had average gas saturations of 61 %, 57 %, 27 %, and 56 % respectively; average core water saturations of 36 %, 42 %, 27 %, and 44 % were recorded per well.
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Dinske, Carsten [Verfasser]. "Interpretation of fluid-induced seismicity at geothermal and hydrocarbon reservoirs of Basel and Cotton Valley / Carsten Dinske." Berlin : Freie Universität Berlin, 2011. http://d-nb.info/1025510666/34.
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Gilliland, Ellen. "An Assessment of Hypocenter Errors Associated with the Seismic Monitoring of Induced Hydro-fracturing in Hydrocarbon Reservoirs." Thesis, Virginia Tech, 2009. http://hdl.handle.net/10919/45325.
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Expanding the standard, single-well recording geometry used to monitor seismicity during hydro-fracture treatments could provide more accurate hypocenter locations and seismic velocities, improving general reservoir characterization. However, for the real, two-well data set obtained for this project, only S-wave picks were available, and testing resulted in anomalous hypocenter location behavior. This study uses a hypocenter location algorithm and both real and synthetic data sets to investigate how the accuracy of the velocity model, starting hypocenter location, recording geometry, and arrival-time picking error affect final hypocenter locations.
Hypocenter locations improved using a velocity model that closely matched the observed sonic log rather than a smoothed version of this model. The starting hypocenter location did not affect the final location solution if both starting and final locations were between the wells. Two solutions were possible when the true solution was not directly between the wells. Adding realistic random picking errors to synthetic data closely modeled the dispersed hypocenter error pattern observed in the real data results. Adding data from a third well to synthetic tests dramatically reduced location error and removed horizontal geometric bias observed in the two-well case.
Seismic event data recorded during hydro-fracture treatments could potentially be used for three-dimensional joint hypocenter-velocity tomography. This would require observation wells close enough to earthquakes to record P- and S-wave arrivals or wells at orientations sufficient to properly triangulate hypocenter locations. Simulating results with synthetic tests before drilling could optimize survey design to collect data more effectively and make analysis more useful.Master of Science
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Campbell, Stuart Alexander. "The Ecca type section (Permian, South Africa) : an outcrop analogue study of conventional and unconventional hydrocarbon reservoirs." Thesis, Rhodes University, 2015. http://hdl.handle.net/10962/d1018199.
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The Karoo Basin of South Africa holds an estimated 906 billion to 11 trillion cubic meters of unconventional shale gas within the shales of the Whitehill and Collingham formations of the Ecca Group. Evaluation of this potential resource has been limited due to the lack of exploration and a scarcity of existing drill core data. In order to circumnavigate this problem this study was undertaken to evaluate the potential target horizons exposed in outcrops along the southern portion of the Karoo Basin, north of Grahamstown in the Eastern Cape Province. Detailed field logging was done on the exposed Whitehill and Collingham formations as well as a possible conventional sandstone (turbidite) reservoir, the Ripon Formation, along road cuttings of the Ecca Pass. Palaeocurrent data, jointing directions and fossil material were also documented. Samples were analysed for mineralogy, porosity, permeability, and total organic carbon content (TOC). The extensively weathered black shales of the Whitehill Formation contain a maximum TOC value of 0.9% and the Collingham Formation shales contain a maximum TOC value of 0.6%. The organic lithic arkose sandstones of the Ripon Formation are classified as ‘tight rock’ with an average porosity of 1% and an average permeability of 0.05 mD. The Whitehill Formation in the southern portion of the Karoo Basin has experienced organic matter loss due to low grade metamorphism as well as burial to extreme depths, thus reducing shale gas potential. The Ripon Formation is an unsuitable conventional reservoir along the southern basin boundary due to extensive cementation and filling of pore spaces.
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Ronan, Leah L. "An NMR investigation of pore size and paramagnetic effects in synthetic sandstones /." Connect to this title, 2006. http://theses.library.uwa.edu.au/adt-WU2007.0198.
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Olajide, Oluseyi. "The petrophysical analysis and evaluation of hydrocarbon potential of sandstone units in the Bredasdorp Central Basin." Thesis, University of the Western Cape, 2005. http://etd.uwc.ac.za/index.php?module=etd&action=viewtitle&id=gen8Srv25Nme4_9559_1181561577.
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This research was aimed at employing the broad use of petrophysical analysis and reservoir modelling techniques to explore the petroleum resources in the sandstone units of deep marine play in the Bredasdorp Basin.
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Schalkwyk, Hugh Je-Marco. "Assessment controls on reservoir performance and the affects of granulation seam mechanics in the Bredasdorp Basin, South Africa." Thesis, University of the Western Cape, 2006. http://etd.uwc.ac.za/index.php?module=etd&action=viewtitle&id=gen8Srv25Nme4_3459_1183461991.
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The Bredasdorp Basin is one of the largest hydrocarbon producing blocks within Southern Africa. The E-M field is situated approximate 50 km west from the FA platform and was brought into commission due to the potential hydrocarbons it may hold. If this field is brought up to full producing capability it will extend the lifespan of the refining station in Mosselbay, situated on the south coast of South Africa, by approximately 8 to 10 years. An unexpected pressure drop within the E-M field caused the suite not to perform optimally and thus further analysis was imminent to assess and alleviate the predicament. The first step within the project was to determine what might have cause the pressure drop and thus we had to go back to cores drilled by Soekor now known as Petroleum South Africa, in the early 1980&rsquo
s.
Analyses of the cores exposed a high presence of granulation seams. The granulation seams were mainly subjected within sand units within the cores. This was caused by rolling of sand grains over one another rearranging themselves due to pressure exerted through compaction and faulting, creating seal like fractures within the sand. These fractures caused these sand units to compartmentalize and prohibit flow from one on block to the next. With advance inquiry it was discovered that there was a shale unit situated within the reservoir dividing the reservoir into two main compartments. At this point it was determined to use Petrel which is windows based software for 3D visualization with a user interface based on the Windows Microsoft standards. This is easy as well as user friendly software thus the choice to go with it. The software uses shared earth modeling tool bringing about reservoir disciplines trough common data modelling. This is one of the best modelling applications in the available and it was for this reason that it was chosen to apply within the given aspects of the project A lack of data was available to model the granulation seams but with the data acquired during the core analyses it was possible to model the shale unit and factor in the influences of the granulation seams to asses the extent of compartmentalization. The core revealed a thick shale layer dividing the reservoir within two sections which was not previously noted. This shale layer act as a buffer/barrier restricting flow from the bottom to the top halve of the reservoir. This layer is thickest at the crest of the 10km²
domal closure and thins toward the confines of the E-M suite. Small incisions, visible within the 3 dimensional models could serve as a guide for possible re-entry points for future drilling. These incisions which were formed through Lowstand and Highstand systems tracts with the rise and fall of the sea level. The Bredasdorp Basin consists mainly of tilting half graben structures that formed through rifting with the break-up of Gondwanaland. The model also revealed that these faults segregate the reservoir further creating bigger compartments. The reservoir is highly compartmentalized which will explain the pressure loss within the E-M suite. The production well was drilled within one of these compartments and when the confining pressure was relieved the pressure dropped and the production decrease. As recommendation, additional wells are required to appraise the E-M structure and determine to what extent the granulation seems has affected fluid flow as well as the degree of sedimentation that could impede fluid flow. There are areas still containing untapped resources thus the recommendation for extra wells.
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Do, Thi Thuy Linh. "Controls on the development and distribution of lateral and terminal splays in modern and ancient fluvial systems : examples from the Parapeti River, Bolivia and the Miocene Ebro Basin, Spain." Thesis, University of Aberdeen, 2016. http://digitool.abdn.ac.uk:80/webclient/DeliveryManager?pid=230525.
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The vertical and lateral aggradation of terminal and crevasse splay deposits in continental environments can form extensive fine-grained, sheet-like sandstone bodies which may form an important but often overlooked component of subsurface hydrocarbon reservoirs. This study examines splay deposits on the modern day Distributive Fluvial System (DFS), of the Parapeti River, Bolivia, using remote sensing techniques and geographic information system (ArcGIS) to characterise both lateral and terminal modern splay systems. Overall emphasis is given to the spatial and temporal relationship between sedimentary facies at the distal part of the Parapeti DFS over the past 42 years. A sedimentary facies evolution model is created to account for the development of the distal part of the Parapeti DFS. A number of splay deposits have formed and developed during this period and the Parapeti channel has prograded ~17 km basinward by short-term deposition in one location, followed by either repeated local avulsion or coeval downstream progradation of the terminal channel and associated splays. Rock record examples from the Miocene aged Huesca DFS in the Ebro Basin, Spain were studied in order to compare dimensional data as well as understand the relationship between splays and associated channel bodies. The study area is characterized by thin sandstone sheets (0.05-2.6 m thick; 100s m wide) interbedded with mudstones and siltstones interpreted to represent a terminal splay complex based on the distribution of facies, architectural elements and paleocurrent data. There is a strong resemblance between the model developed for the Parapeti DFS and the splay complexes recorded in the Miocene Huesca DFS. Sedimentary models are proposed in which terminal splay formation through avulsions is considered to be the dominant process in the distal parts of both systems. Avulsions control sediment distribution, resulting in stacking of splay deposits to form extensive sandstone sheets. However, it is suggested that different types of avulsion successions (i.e. progressive or abrupt) recognized by previous workers, may not be distinguishable in the rock record as they can produce a similar stratigraphic signature.
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Ball, Nathaniel H. Atchley Stacy C. "Depositional and diagenetic controls on reservoir quality and their petrophysical predictors within the Upper Cretaceous (Cenomanian) Doe Creek Member of the Kaskapau Formation at Valhalla Field, Northwest Alberta." Waco, Tex. : Baylor University, 2009. http://hdl.handle.net/2104/5296.
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Lippmann, Robert [Verfasser], Reinhard [Gutachter] Gaupp, and Rolando di [Gutachter] Primio. "Diagenesis in Rotliegend, Triassic and Jurassic clastic hydrocarbon reservoirs of the Central Graben, North Sea / Robert Lippmann ; Gutachter: Reinhard Gaupp, Rolando di Primio." Jena : Friedrich-Schiller-Universität Jena, 2012. http://d-nb.info/1177653435/34.
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Nfor, Nformi Emmanuel. "Sequence stratigraphic characterisation of petroleum reservoirs in Block 11b/12b of the Southern Outeniqua Basin." University of the Western Cape, 2011. http://hdl.handle.net/11394/2924.
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Magister Scientiae - MScThe main purpose of this study was to identify and characterize the various sand prone depositional facies in the deepwater Southern Outeniqua Basin which generally tend to form during lowstand (marine regression) conditions producing progradational facies. It made use of sequence stratigraphy and turbidite facies models to predict the probable location of deepwater reservoirs in the undrilled Southern Outeniqua Basin using data from basin margin Pletmos Basin and the deepwater Southern Outeniqua Basin. Basin margin depositional packages were correlated in time and space with deepwater packages. It was an attempt at bridging the gap between process-related studies of sedimentary rocks and the more traditional economic geology f commercial deposits of petroleum using prevailing state-of-the-art in basin analysis. It enabled the most realistic reconstructions of genetic stratigraphy and offered the greatest application in exploration. Sequence stratigraphic analysis and interpretation of seismics, well logs, cores and biostratigraphic data was carried out providing a chronostratigraphic framework of the study area within which seismic facies analysis done. Nine (9) seismic lines that span the shallow/basin margin Pletmos basin into the undrilled deepwater Southern Outeniqua basin were analysed and interpreted and the relevant seismic geometries were captured. Four (4) turbidite depositional elements were identified from the seismic lines: channel, overbank deposits, haotic deposits and basin plain (basin floor fan) deposits. These were identified from the relevant seismic geometries (geometric attributes) observed on the 2D seismic lines. Thinning attributes, unconformity attributes and seismic facies attributes were observed from the seismic lines. This was preceded by basic structural analyses and interpretation of the seismic lines. according to the structural analysis and interpretation, deposition trended NW-SE and NNW-SSE as we go deepwater into the Southern Outeniqua basin. Well logs from six (6) of the interpreted wells indicated depositional channel fill as well as basin floor fans. This was identified in well Ga-V1 and Ga-S1 respectively. A bell and crescent shape gamma ray log signature was observed in well Ga-V1 indicating a fining up sequence as the channel was abandoned while an isolated massive mound-shape gamma ray log signature was observed in Ga-S1 indicating basin plain well-sorted sands. Core analyses and interpretation from two southern-most wells revealed three (3) facies which were derived based on Walker‘s 1978, turbidite facies. The observed facies were: sandstone, sand/shale and shale facies. Sequence stratigraphic characterisation of petroleum reservoirs in block 11b/12b of the Southern Outeniqua Basin. Cores of well Ga-V1 displayed fine-grained alternations of thin sandstone beds and shales belonging to the thin-bedded turbidite facies. This is typical of levees of the upper fan channel but could easily be confused with similar facies on the basin plain. According to Walker, 1978 such facies form under conditions of active fan progradation. Ga-S1 cores displayed not only classic turbidite facies where there was alternating sand and shale sections but showed thick uninterrupted sections of clean sands. This is typical of basin plain deposits. Only one well had biostratigraphic data though being very limited in content. This data revealed particular depth sections and stratigraphic sections as having medium to fast depositional rates. Such rates are characteristic of turbidite deposition from turbidity currents. This study as well as a complementary study by Carvajal et al., 2009 revealed that the Southern Outeniqua basin is a sand-prone basin with many progradational sequences in which tectonics and sediment supply rate have been significant factors (amongst others such as sea level change) in the formation of these deepwater sequences. In conclusion, the Southern Outeniqua basin was hereby seen as having a viable and unexplored petroleum system existing in this sand prone untested world class.
South Africa
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Benvenutti, Carlos Felipe [UNESP]. "Estudo da porção offshore da bacia do Benin e o seu potencial no armazenamento de hidrocarbonetos, margem equatorial africana." Universidade Estadual Paulista (UNESP), 2012. http://hdl.handle.net/11449/92925.
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benvenutti_cf_me_rcla.pdf: 5702564 bytes, checksum: 3468aeafad128f8380c10b5ae674509f (MD5)A presente pesquisa conta com uma área de estudo de 7.737 km2 na porção ojJshore da Bacia do Benin, localizada na Província do Golfo da Guiné, Margem Equatorial Africana, onde a lâmina da água varia de 100 a mais de 3.200 m, cobrindo basicamente o talude. Dados ísmicos 3D e 2D foram disponibilizados pela Compagnie Béninoise des Hydrocarbures(CBH SARL) para interpretação dos mesmos com o objetivo de caracterizar o arcabouço estrutural e estratigráfico da região, assim como avaliar o potencial do armazenamento de hidrocarboneto. Foi necessário o mapeamento dos horizontes sísmicos, a elaboração de mapas de contorno estrutural, de atributos sísmicos e de isópacas. A Bacia do Benin encontra-se entre as zonas de fratura de Romanche e Chain, correlata à Bacia do Ceará na Margem Equatorial Brasileira. Sua evolução tectono-sedimentar está condicionada à ruptura do Gondwana no Cretáceo Inferior, predominando estruturas da fase rifte relacionadas à distensão e transcorrência, a influência da transpressão é muito significativa no Cretáceo Superior. Destaca-se também uma tectônica gravitacional marcada por falhamentos dos níveis estratigráficos cenozóicos. A coluna sedimentar é representada por uma seção rifte continental limitada pela discordância do Meso-Albiano e outra pós-rifte marinha, do Albiano Superior ao Recente; sendo esta subdividida pela discordância do Oligoceno relacionada a uma queda eustática. A sedimentação está controlada pelo strends NE-SW e ENE-WSW, incluindo os canais submarinos. Os principais altos estruturais desta região já foram perfurados sem sucesso comercial, porém o potencial de acumulação de hidrocarbonetos é promissor, pelo menos dois grandes canais foram identificados no estudo em uma região cuja profundidade do fundo do mar é cerca de 2.200 m. Oportunidades...
The present research has a study area of 7.737 km2 located in the offshore portion of Benin Basin in the Gulf of Guinea Province, African Equatorial Margin. The water depth ranges from 100 to more than 3.200 m, basically covering the slope. The Compagnie Béninoise des Hydrocarbures (CBH SARL) provided 3D and 2D seismic data in order to interpret and characterize the stratigraphic and structural frarnework, as well as to evaluate the petroleum exploration potential. To achieve the desired results, it was performed seismic horizons mapping, elaboration of structural outline, isopach and seismic attribute maps. Benin Basin is limited by Romanche and Chain fracture zones and is correlated to Ceará Basin in Brazilian Equatorial Margin. Its tectono-stratigraphic evolution was conditioned by the Gondwana break-up in the Lower Cretaceous and shows rift structures related to extension trike-slip tectonics. The transpression influence is very significant in the Upper Cretaceous. It is also highlighted a gravitational tectonic marked by normal faults in the Cenozoic level. The sedimentary package is represented by a continental rift section limited by a Mid-Albian unconformity and other marine post-rift sequence from Upper Albian to Recent; the last one can still be divided by the Oligocene unconformity. The sedimentation is controlled by NE-SW and ENE- WSW trends, including submarine channels in the Upper Cretaceous. The main structural traps weredrilled in the study area without commercial success. At least two great channels were identified in a region where the water depth is around 2.200 m. Roll-overs and minor channels opportunities in Paleogene and Neogene should also be considered. The pre-rift sequences of the study area are poorly recognized, the absence of well information in this interval and the low resolution of seismic data... (Complete abstract click electronic access below)
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Sarzalejo, de Bauduhin Sabrina 1955. "Integration of borehole and seismic data to unravel complex stratigraphy : case studies from the Mannville Group, western Canada." Thesis, McGill University, 2009. http://digitool.Library.McGill.CA:80/R/?func=dbin-jump-full&object_id=115696.
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Understanding the stratigraphic architecture of geologically complex reservoirs, such as the heavy oil deposits of Western Canada, is essential to achieve an efficient hydrocarbon recovery. Borehole and 3-D seismic data were integrated to define the stratigraphic architecture and generate 3-dimensional geological models of the Mannville Group in Saskatchewan. The Mannville is a stratigraphically complex unit formed of fluvial to marine deposits. Two areas in west-central and southern Saskatchewan were examined in this study. In west-central Saskatchewan, the area corresponds to a stratigraphically controlled heavy oil reservoir with production from the undifferentiated Dina-Cummings Members of the Lower Cretaceous Mannville Group. The southern area, although non-prospective for hydrocarbons, shares many similarities with time-equivalent strata in areas of heavy oil production. Seismic sequence stratigraphic principles together with log signatures permitted the subdivision of the Mannville into different packages. An initial geological model was generated integrating seismic and well-log data Multiattribute analysis and neural networks were used to generate a pseudo-lithology or gamma-ray volume. The incorporation of borehole core data to the model and the subsequent integration with the lithological prediction were crucial to capture the distribution of reservoir and non-reservoir deposits in the study area. The ability to visualize the 3-D seismic data in a variety of ways, including arbitrary lines and stratal or horizon slicing techniques helped the definition of stratigraphic features such as channels and scroll bars that affect fluid flow in hydrocarbon producing areas. Small-scale heterogeneities in the reservoir were not resolved due to the resolution of the seismic data. Although not undertaken in this study, the resulting stratigraphic framework could be used to help construct a static reservoir model. Because of the small size of the 3-D seismic surveys, horizontal slices through the data volume generally imaged only small portions of the paleogeomorphologic features thought to be present in this area. As such, it was only through the integration of datasets that the geological models were established.
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Benvenutti, Carlos Felipe. "Estudo da porção offshore da bacia do Benin e o seu potencial no armazenamento de hidrocarbonetos, margem equatorial africana /." Rio Claro : [s.n.], 2012. http://hdl.handle.net/11449/92925.
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Resumo: A presente pesquisa conta com uma área de estudo de 7.737 km2 na porção ojJshore da Bacia do Benin, localizada na Província do Golfo da Guiné, Margem Equatorial Africana, onde a lâmina da água varia de 100 a mais de 3.200 m, cobrindo basicamente o talude. Dados ísmicos 3D e 2D foram disponibilizados pela Compagnie Béninoise des Hydrocarbures(CBH SARL) para interpretação dos mesmos com o objetivo de caracterizar o arcabouço estrutural e estratigráfico da região, assim como avaliar o potencial do armazenamento de hidrocarboneto. Foi necessário o mapeamento dos horizontes sísmicos, a elaboração de mapas de contorno estrutural, de atributos sísmicos e de isópacas. A Bacia do Benin encontra-se entre as zonas de fratura de Romanche e Chain, correlata à Bacia do Ceará na Margem Equatorial Brasileira. Sua evolução tectono-sedimentar está condicionada à ruptura do Gondwana no Cretáceo Inferior, predominando estruturas da fase rifte relacionadas à distensão e transcorrência, a influência da transpressão é muito significativa no Cretáceo Superior. Destaca-se também uma tectônica gravitacional marcada por falhamentos dos níveis estratigráficos cenozóicos. A coluna sedimentar é representada por uma seção rifte continental limitada pela discordância do Meso-Albiano e outra pós-rifte marinha, do Albiano Superior ao Recente; sendo esta subdividida pela discordância do Oligoceno relacionada a uma queda eustática. A sedimentação está controlada pelo strends NE-SW e ENE-WSW, incluindo os canais submarinos. Os principais altos estruturais desta região já foram perfurados sem sucesso comercial, porém o potencial de acumulação de hidrocarbonetos é promissor, pelo menos dois grandes canais foram identificados no estudo em uma região cuja profundidade do fundo do mar é cerca de 2.200 m. Oportunidades... (Resumo completo, clicar acesso eletrônico abaixo)Abstract: The present research has a study area of 7.737 km2 located in the offshore portion of Benin Basin in the Gulf of Guinea Province, African Equatorial Margin. The water depth ranges from 100 to more than 3.200 m, basically covering the slope. The Compagnie Béninoise des Hydrocarbures (CBH SARL) provided 3D and 2D seismic data in order to interpret and characterize the stratigraphic and structural frarnework, as well as to evaluate the petroleum exploration potential. To achieve the desired results, it was performed seismic horizons mapping, elaboration of structural outline, isopach and seismic attribute maps. Benin Basin is limited by Romanche and Chain fracture zones and is correlated to Ceará Basin in Brazilian Equatorial Margin. Its tectono-stratigraphic evolution was conditioned by the Gondwana break-up in the Lower Cretaceous and shows rift structures related to extension trike-slip tectonics. The transpression influence is very significant in the Upper Cretaceous. It is also highlighted a gravitational tectonic marked by normal faults in the Cenozoic level. The sedimentary package is represented by a continental rift section limited by a Mid-Albian unconformity and other marine post-rift sequence from Upper Albian to Recent; the last one can still be divided by the Oligocene unconformity. The sedimentation is controlled by NE-SW and ENE- WSW trends, including submarine channels in the Upper Cretaceous. The main structural traps weredrilled in the study area without commercial success. At least two great channels were identified in a region where the water depth is around 2.200 m. Roll-overs and minor channels opportunities in Paleogene and Neogene should also be considered. The pre-rift sequences of the study area are poorly recognized, the absence of well information in this interval and the low resolution of seismic data... (Complete abstract click electronic access below)
Orientador: Nelson Angeli
Coorientador: Maria Gabriela C. Vincetelli
Banca: George Luiz Luvizotto
Banca: Adilson Viana Soares Júnior
Mestre
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Lasisi, Ayodele Oluwatoyin. "Pore pressure prediction and direct hydrocarbon indicator: insight from the southern pletmos basin, offshore South Africa." Thesis, University of the Western Cape, 2014. http://hdl.handle.net/11394/4255.
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>Magister Scientiae - MScAn accurate prediction of pore pressure is an essential in reducing the risk involved in a well or field life cycle. This has formed an integral part of routine work for exploration, development and exploitation team in the oil and gas industries. Several factors such as sediment compaction, overburden, lithology characteristic, hydrocarbon pressure and capillary entry pressure contribute significantly to the cause of overpressure. Hence, understanding the dynamics associated with the above factors will certainly reduce the risk involved in drilling and production. This study examined three deep water drilled wells GA-W1, GA-N1, and GA-AA1 of lower cretaceous Hauterivian to early Aptian age between 112 to 117.5 (MA) Southern Pletmos sub-basin, Bredasdorp basin offshore South Africa. The study aimed to determine the pore pressure prediction of the reservoir formation of the wells. Eaton’s resistivity and Sonic method are adopted using depth dependent normal compaction trendline (NCT) has been carried out for this study. The variation of the overburden gradient (OBG), the Effective stress, Fracture gradient (FG), Fracture pressure (FP), Pore pressure gradient (PPG) and the predicted pore pressure (PPP) have been studied for the selected wells. The overburden changes slightly as follow: 2.09g/cm3, 2.23g/cm3 and 2.24g/cm3 across the selected intervals depth of wells. The predicted pore pressure calculated for the intervals depth of selected wells GA-W1, GA-N1 and GA-AA1 also varies slightly down the depths as follow: 3,405 psi, 4,110 psi, 5,062 psi respectively. The overpressure zone and normal pressure zone were encountered in well GA-W1, while a normal pressure zone was experienced in both well GA-N1 and GA-AA1. In addition, the direct hydrocarbon indicator (DHI) was carried out by method of post-stack amplitude analysis seismic reflectors surface which was used to determine the hydrocarbon prospect zone of the wells from the seismic section. It majorly indicate the zones of thick hydrocarbon sand from the amplitude extraction grid map horizon reflectors at 13AT1 & 8AT1 and 8AT1 & 1AT1 of the well GA-W1, GA-N1 and GA-AA1 respectively. These are suggested to be the hydrocarbon prospect locations (wet-gas to Oil prone source) on the seismic section with fault trending along the horizons. No bright spot, flat spot and dim spot was observed except for some related pitfalls anomalies
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Ronan, Leah L. "An NMR investigation of pore size and paramagnetic effects in synthetic sandstones." University of Western Australia. School of Oil and Gas Engineering, 2007. http://theses.library.uwa.edu.au/adt-WU2007.0198.
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[Truncated abstract] This thesis describes the development of synthetic rock samples, representative of core samples from hydrocarbon reservoirs. The basic process consists of screening and sorting silica particles into discrete grain sizes, and then binding them together using a proprietary process known as CIPS, (Calcite In-situ Precipitation System). In the bonding process, the porosity of the system is substantially preserved, and the technique allows the manufacture of synthetic core samples with a tailor-made permeability. The produced samples were extensively characterised using a variety of analytic techniques to determine their porosity, permeability and pore size distribution. These analyses were a necessary pre-cursor to a major part of this thesis: the characterisation of the pore space by nuclear magnetic resonance (NMR) techniques. The synthetic core samples, covering a 7 times factor in grain sizes were examined using NMR, and this data formed the comparative basis for the NMR studies that followed. Two fundamental NMR questions were posed and answered in this thesis: 1. What is the effect of paramagnetic ions in the rock matrix on the NMR response? In pursuit of this question the CIPS process was extended to include co-precipitation of paramagnetic ions. A key feature is that the ions were deposited in predictable amounts at known sites (on the wall of the pore space). ... The NMR response in these double cores was then measured and examined to provide an answer to the question posed at the beginning of this paragraph. The significance of this work is that the physically distinct cores are a cylindrical analogue of adjoining sedimentary strata. By answering the question posed above, the thesis gives an indication of the vertical porosity resolution ultimately possible in an NMR logging tool. At present this ranges from 9” to 24” in the most favourable circumstances. This work suggests that the NMR signal carries porosity information at a much higher resolution, and that advanced numerical analysis of the NMR signature could realise the potential of greater stratigraphic resolution in NMR logging In addition to the research outlined above, the application of the CIPS technique to produce analogues of reservoir rocks, pioneered in this thesis, has stimulated similar research to be undertaken at other institutions, including the fabrication of synthetic reservoir cores containing clay particles (at CSIRO - the Commonwealth Scientific and Industrial Research Organisation) and a large scale application, formation of meter size blocks of CIPS bonded material, with separate strata, for laboratory studies of seismic waves (at Curtin University)
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Choi, Jong-Won. "Geomechanics of subsurface sand production and gas storage." Diss., Georgia Institute of Technology, 2011. http://hdl.handle.net/1853/39493.
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Improving methods of hydrocarbon production and developing new techniques for the creation of natural gas storage facilities are critically important for the petroleum industry. This dissertation focuses on two key topics: (1) mechanisms of sand production from petroleum reservoirs and (2) mechanical characterization of caverns created in carbonate rock formations for natural gas storage. Sand production is the migration of solid particles together with the hydrocarbons when extracted from petroleum reservoirs. It usually occurs from wells in sandstone formations that fail in response to stress changes caused by hydrocarbon withdrawal. Sand production is generally undesirable since it causes a variety of problems ranging from significant safety risks during high-rate gas production, to the erosion of downhole equipment and surface facilities. It is widely accepted that a better understanding of the mechanics of poorly-consolidated formations is required to manage sand production; which, in turn, enables the cost effective production of gas and oil resources. In this work, a series of large-scale laboratory experiments was conducted in fully saturated, cohesionless sand layers to model the behavior of a petroleum reservoir near a wellbore. We directly observed several key characteristics of the sand production phenomenon including the formations of a stable cavity around the wellbore and a sub-radial flow channel at the upper surface of the tested layer. The flow channel is a first-order feature that appears to be a major part of the sand production mechanism. The channel cross section is orders of magnitude larger than the particle size, and once formed, the channel becomes the dominant conduit for fluid flow and particle transport. The flow channel developed in all of our experiments, and in all experiments, sand production continued from the developing channel after the cavity around the borehole stabilized. Our laboratory results constitute a well constrained data set that can be used to test and calibrate numerical models employed by the petroleum industry for predicting the sand production phenomenon. Although important for practical applications, real field cases are typically much less constrained. We used scaling considerations to develop a simple analytical model, constrained by our experimental results. We also simulated the behavior of a sand layer around a wellbore using two- and three-dimensional discrete element methods. It appears that the main sand production features observed in the laboratory experiments, can indeed be reproduced by means of discrete element modeling. Numerical results indicate that the cavity surface of repose is a key factor in the sand production mechanism. In particular, the sand particles on this surface are not significantly constrained. This lack of confinement reduces the flow velocity required to remove a particle, by many orders of magnitude. Also, the mechanism of channel development in the upper fraction of the sample can be attributed to subsidence of the formation due to lateral extension when an unconstrained cavity slope appears near the wellbore. This is substantiated by the erosion process and continued production of particles from the flow channel. The notion of the existence of this surface channel has the potential to scale up to natural reservoirs and can give insights into real-world sand production issues. It indicates a mechanism explaining why the production of particles does not cease in many petroleum reservoirs. Although the radial character of the fluid flow eventually stops sand production from the cavity near the wellbore, the production of particles still may continue from the propagating surface (interface) flow channel. The second topic of the thesis addresses factors affecting the geometry and, hence, the mechanical stability of caverns excavated in carbonate rock formations for natural gas storage. Storage facilities are required to store gas when supply exceeds demand during the winter months. In many places (such as New England or the Great Lakes region) where no salt domes are available to create gas storage caverns, it is possible to create cavities in limestone employing the acid injection method. In this method, carbonate rock is dissolved, while CO₂ and calcium chloride brine appear as products of the carbonate dissolution reactions. Driven by the density difference, CO₂ rises towards the ceiling whereas the brine sinks to the bottom of the cavern. A zone of mixed CO₂ , acid, and brine forms near the source of acid injection, whereas the brine sinks to the bottom of the cavern. Characterization of the cavern shape is required to understand stress changes during the cavity excavation, which can destabilize the cavern. It is also important to determine the location of the mixture-brine interface to select the place of acid injection. In this work, we propose to characterize the geometry of the cavern and the location of the mixture-brine interface by generating pressure waves in a pipe extending into the cavern, and measuring the reflected waves at various locations in another adjacent pipe. Conventional governing equations describe fluid transients in pipes loaded only by internal pressure (such as in the water hammer effect). To model the pressure wave propagation for realistic geometries, we derived new governing equations for pressure transients in pipes subjected to changes in both internal and external (confining) pressures. This is important because the internal pressure (used in the measurement) is changing in response to the perturbation of the external pressure when the pipe is contained in the cavern filled with fluids. If the pressure in the cavern is perturbed, the perturbation creates an internal pressure wave in the submerged pipe that has a signature of the cavern geometry. We showed that the classic equations are included in our formulation as a particular case, but they have limited validity for some practically important combinations of the controlling parameters. We linearized the governing equations and formulated appropriate boundary and initial conditions. Using a finite element method, we solved the obtained boundary value problem for a system of pipes and a cavern filled with various characteristic fluids such as aqueous acid, calcium chloride brine, and supercritical CO₂ . We found that the pressure waves of moderate amplitudes would create measurable pressure pulses in the submerged pipe. Furthermore, we determined the wavelengths required for resolving the cavern diameter from the pressure history. Our results suggest that the pressure transients technique can indeed be used for characterizing the geometry of gas storage caverns and locations of fluid interfaces in the acid injection method.
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Karpfinger, Florian. "Modelling borehole wave signatures in elastic and poroelastic media with spectral method." Thesis, Curtin University, 2009. http://hdl.handle.net/20.500.11937/2447.
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Borehole sonic measurements are an important tool to characterize formation and completion properties of hydrocarbon or water reservoirs. Such measurements can provide direct information about rock physical parameters such as permeability or elastic moduli. These properties are obtained from guided waves propagating along boreholes. The so called tube wave or Stoneley wave is a symmetric mode which compresses the fluid column leading to a piston like motion. If the medium around the borehole wall is permeable, the radial expansion of the fluid column will result in fluid flow across the borehole wall. This results in a sensitivity of the tube wave signature to the permeability of the surrounding formation which manifests itself in a characteristic dispersion and attenuation of the tube wave. Information about the permeability of the surrounding formation provides essential knowledge for reservoir characterization.In addition to the traditional method of using tube wave signatures for formation permeability estimations, the same approach may be used for production monitoring. In sand reservoirs a complicated borehole completion is installed during the production phase for the purpose of controlling sand production. In such a setup highly permeable layers such as a sand screen or a gravel pack are used to prevent sand production.The problem with such completions is that they are very expensive to install and susceptible to plugging or corrosion. No permanent surveillance tool exists to date which allows diagnosis of problems in sand-screened deepwater completions. However, the recently proposed Real-Time Completion Monitoring (RTCM) uses the signature of tube waves to identify permeability changes: the increase of the tube wave velocity can indicate a decrease of permeability and vice versa. Therefore, RTCM has potential to identify problems in sand-screened deepwater completions.In order to understand the acoustic response of such deepwater completions, the dispersion and attenuation of tube waves in this complicated setup needs to be studied. To this end I have developed a modelling algorithm based on a spectral method. The developed algorithm computes the dispersion and attenuation of borehole modes propagating in a cylindrically layered structure with an arbitrary number of fluid, elastic and poroelastic layers. The numerical algorithm discretizes the medium along the radial axis using Chebyshev interpolation points derived from Chebyshev polynomials. The differential operators are discretized using spectral differentiation matrices. Thus, for any number of layers, the corresponding equations can be expressed as a generalized algebraic eigenvalue problem. For a given frequency, the eigenvalues correspond to the wavenumbers of different modes. The eigenvectors, computed along with the eigenvalues, correspond to the displacement potentials. They can be used to obtain the variation of displacement and stress components along the radius of the structure.In this thesis the spectral method was first developed for structures with an arbitrary number of fluid and elastic layers. Subsequently, the algorithm was extended for poroelasticity. The results produced by the modelling program are benchmarked against analytical solutions. Such analytical solutions are known for elastic and poroelastic cylinders as well as fluid filled tubes. The tube wave dispersion in a fluid-filled borehole surrounded by an elastic or poroelastic formation obtained with the spectral method was compared to the analytical low-frequency solution.I obtained the dispersion of the two tube waves propagating in a four layer completion model: fluid – permeable sand-screen – fluid – elastic casing. Varying the permeability of the sand-screen layer allowed me to account for the effect of fluid flow across this layer. Being able to obtain the acoustic response can help to identify broken fluid communication which increases the tube wave velocity. A corroded sand-screen has an extremely attenuated tube wave signature.Furthermore, I have implemented the more complex model of a borehole surrounded by an altered zone in the algorithm. Due to drilling damage the altered zone is an area of reduced permeability. In order to account for the effect of the altered zone on the tube wave signature, up to ten layers were used with stepwise increase of permeability from the borehole towards the formation. Overall, the spectral method proved to be a valuable algorithm to model wave propagation in cylindrical structures.Using borehole modes to evaluate the physical properties of the formation or completions is an important application. However, in borehole seismic modelling, such as crosshole or VSP, it is also important to account for the effect of boreholes and the associated modes. Since the borehole radius is a thousand times smaller then the investigated volume it would require a prohibitively small grid size to explicitly model the borehole. However, it is possible to effectively represent a borehole as a superposition of point sources. This mimics the presence of borehole modes. In order to implement this technique for poroelasticity, it is necessary to model source signatures in poroelastic media. To this end I have analyzed the radiation characteristics and moment tensor solutions for various source types. Together with the spectral method these point source representations can be used to model the effect of boreholes. This will pave the way for more efficient poroelastic seismic modelling in various fluid-filled boreholes and completions.
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Bilsland, Mark Christopher. "An integrated approach to hydrocarbon reservoir characterisation." Thesis, Imperial College London, 1989. http://hdl.handle.net/10044/1/6900.
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In this thesis a method of characterisation of reservoir properties has been achieved by integration of petrophysical, geological and reservoir engineering data, at a variety of scales. This approach to characterisation was developed using the Magnus oil field in the United Kingdom Northern North Sea as an example. The Magnus Sandstone is a coarse clastic submarine fan system within the Upper Jurassic Kimmeridge Clay Formation. The data used in this study was obtained from three main sources : reservoir geology, wireline log data and petrophysical core analysis. Techniques used in this reservoir interpretation included X-ray diffraction of the clay fraction, both secondary and back-scattered scanning electron microscopy, interactive log interpretation, and application of quality control rules for core derived petrophysical data. Using the example of the Magnus oil field, this research has shown that:- Secondary porosity generation by isolated grain solution is common across the Magnus Field. This results in high porosities being preserved, with no significant increase in permeability. Isolated occurrences of the leaching of poikilotopic carbonate cement results in the enhancement of both porosity and permeability. Illitic clay matrix is present throughout the Magnus reservoirsandstones. In the oil leg, detrital illitic clay masses are preserved, whilst in the aquifer these are recrystallised to form characteristically wispy authigenic illite-smectite. This is manifested in the significantly reduced permeability observed in the aquifer. Permeability character is controlled by saturating fluid type. Log derived porosity functions specific to zones of different fluid saturations are used to generate permeability algorithms. Reconciliation of well test derived Kh and Kh derived from the log based algorithms provides an enhanced understanding of effective permeability for application to reservoir simulation scale modelling. The well test Kh values although only 1.5 times lower in the oil zone are up to 35 orders of magnitude lower in the water saturated material, confirming the observed distribution of the authigenic illite-smectite material. By making a thorough integration of routine core analysis data, log derived data and sedimentological data, a basis for the effective design of relevant special core analysis tests using preserved core material can be derived. This work has shown that the integration of reservoir data requires the establishment of a model which recognises the constraints bounding each data set, and which reconciles the extreme variation of the investigative scale of the data from microns in the scanning electron microscope, to millions of cubic metres in well tests.
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Verde, Leandro Costa Lima 1979. "Avaliação da diversidade filogenética e funcional da microbiota envolvida na biodegradação de hidrocarbonetos em amostras de petróleo de reservatórios brasileiros = Evaluation of the phylogenetic and functional diversity of the microbiota involved in hydrocarbon biodegradation in petroleum samples from Brazilian reservoirs." [s.n.], 2014. http://repositorio.unicamp.br/jspui/handle/REPOSIP/317327.
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Orientador: Valéria Maia MerzelTese (doutorado) - Universidade Estadual de Campinas, Instituto de Biologia
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Resumo: O processo de biodegradação do petróleo em reservatórios pode resultar em mudanças na composição e propriedades físico-químicas de óleos brutos e gases naturais, as quais levam à diminuição do teor de hidrocarbonetos saturados, produzindo óleos mais pesados e com baixo valor econômico. O uso combinado de técnicas dependentes e independentes de cultivo pode nos permitir um melhor entendimento acerca da comunidade de micro-organismos que habita os reservatórios de petróleo, incluindo aqueles responsáveis por esta biodegradação. O conhecimento sobre a composição microbiana, suas funções e interações com outros micro-organismos e com o ambiente pode levar à definição de estratégias de monitoramento e/ou controle da biodegradação em reservatórios. Este estudo teve como finalidade avaliar a diversidade de micro-organismos e genes envolvidos na degradação de hidrocarbonetos presentes em amostras de petróleo provenientes de dois poços terrestres da Bacia Potiguar (RN), identificados como GMR75 (poço biodegradado) e PTS1 (poço não-biodegradado), através da construção de bibliotecas de genes catabólicos (alcano monooxigenases - alk, dioxigenases que hidroxilam anéis aromáticos ¿ ARHDs e 6-oxocyclohex-1-ene-1-carbonyl-CoA hidroxilase - bamA) e sequenciamento em larga escala de metagenoma e metatranscriptoma de enriquecimentos microbianos aeróbios. Os resultados obervados mostraram uma distribuição diferencial dos genes catabólicos entre os reservatórios, sendo o óleo biodegradado mais diverso para os genes alk e bamA. As sequências foram semelhantes aos genes alkB dos gêneros Geobacillus, Acinetobacter e Streptomyces, aos genes ARHD dos gêneros Pseudomonas e Burkholderia, e aos genes bamA do gênero Syntrophus. A análise quantitativa dos genes catabólicos de degradação de hidrocarbonetos presentes e expressos nos enriquecimentos microbianos em diferentes etapas da biodegradação do óleo, através de PCR Tempo Real, demonstrou maior atividade do gene que codifica a enzima dioxigenase nas comunidades microbianas enriquecidas, e os resultados obtidos pela técnica de microarray sugeriram a existência de novas sequências dos genes alk e ARHD provindas do reservatório de petróleo. As análises das sequências obtidas a partir do metagenoma e metatranscriptoma mostraram que a comunidade bacteriana recuperada no enriquecimento aeróbio é bastante diversa, com predominância do Filo Actinobacteria, seguido de Proteobacteria. As sequências com maior abundância e níveis de expressão foram relacionadas aos genes que codificam as proteínas ligase CoA de ácido graxo de cadeia longa, envolvida na degradação de compostos aromáticos; descarboxilase, envolvida com o ciclo do glioxilato, e o fator sigma da RNA polimerase, envolvida com a regulação da resposta ao estresse oxidativo, sugerindo uma adaptação da comunidade microbiana às condições do enriquecimento e um processo inicial de biodegradação dos hidrocarbonetos. Os resultados obtidos neste trabalho fornecem dados inéditos sobre a diversidade de genes catabólicos e de membros da comunidade microbiana potencialmente envolvidos com a degradação do óleo em reservatórios de petróleo
Abstract: The process of oil biodegradation in reservoirs may result in changes in the composition and physico-chemical properties of crude oils and natural gases, which lead to the decrease of the content of saturated hydrocarbons, producing heavy oils and with low economic value. The combined use of both dependent and independet cultivation techniques may allow us to better understand the microbial community inhabiting oil reservoirs, including those microorganisms responsible for oil degradation. The knowledge about the microorganisms, ther functions and interactions with other microorganisms and the environment may lead to the definition of monitoring and/or control strategies of biodegradation in oil reservoirs. This study aimed at evaluating the diversity of microorganisms and genes involved in the degradation of hydrocarbons present in oil samples from two onshore reservoirs at Potiguar Basin (RN), identified as GMR75 (biodegraded) and PTS1 (non- biodegraded), through the construction of catabolic gene libraries (alkane monooxygenases - alk, aromatic ring hydroxylating dioxygenases ¿ ARHD and 6-oxocyclohex-1-ene-1-carbonyl-CoA hydroxylase - bamA) and highthroughput sequencing of metagenome and metatranscriptome from aerobic microbial enrichments. Results observed showed a differential distribution of catabolic genes between the reservoirs, being the biodegraded oil more diverse for the alk and bamA genes. The sequences were similar to alkB genes from Geobacillus, Acinetobacter and Streptomyces genera, to the ARHD genes from Pseudomonas and Burkholderia genera, and to the bamA genes from Syntrophus genus. Quantitative analysis of the hydrocarbon degradation genes present and expressed in the microbial enrichments during the different phases of oil biodegradation by Real-Time PCR showed that there was a higher activity of dioxygenase enzymes in the enriched microbial communities and results from microarray assays suggested the existence of new alk and ARHD gene sequences originated from the oil reservoir. Metagenomic and metatranscriptomic analyses showed a highly diverse bacterial community, dominated by the Phylum Actinobacteria, followed by Proteobacteria. The most abundant and active sequences were affiliated to the Long-chain-fatty-acid-CoA ligase protein, involved in the degradation of aromatic compounds; decarboxylase, which is involved with the glyoxylate cycle, and RNA polymerase sigma factor, which is involved in regulating the oxidative stress response, suggesting an adaptation of the microbial community to the enrichment conditions and an initial process of biodegradation of hydrocarbon compounds. The results obtained in this work bring innovative data on the diversity of catabolic genes and microbial community members potentially involved with oil degradation in petroleum reservoirs
Doutorado
Genetica de Microorganismos
Doutor em Genetica e Biologia Molecular
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Xia, Changyou. "Geological risk and reservoir quality in hydrocarbon exploration." Thesis, University of Edinburgh, 2018. http://hdl.handle.net/1842/33159.
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In the next 20 years, the global demand for oil is forecast to grow by 0.7% every year, and the demand for natural gas will increase by 1.6% annually. But as we continue to produce oil and gas, the resources of our current oilfields are depleting. To meet the rising global energy demand, it is essential that we can keep discovering more petroleum resources in the future. The primary aim of this PhD project is to deepen our understanding of hydrocarbon reservoirs and enhance our ability to explore. The first project looked at the geological risks in hydrocarbon exploration. It reviewed and statistically analysed the data of 382 unsuccessful boreholes in the UK offshore area. The results suggest that the most significant risk for an exploration well is encountering a thin or absent target reservoir. This risk happened to 27 ± 4% of the past unsuccessful wells. The following most common risks are low-porosity reservoirs (22 ± 4% of all cases) and the lack of a closed trap (23 ± 4%). The probability of a target reservoir having a leaky caprock is 5 ± 2%. The study has calculated the probability of occurrence of all the geological risks in exploration, and this risk data can be applied to predict the potential geological risks in future exploration. One challenge in developing saline aquifers as CO2 storage reservoirs is the lack of subsurface data, unless a well has been drilled. Drawing on the experience of hydrocarbon exploration, a potential CO2 storage site identified on seismic profiles will be subject to many uncertainties, such as thin or low-porosity reservoirs, leaky seals, which are analogue to the geological risks of an undrilled hydrocarbon prospect. Since the workflow of locating CO2 storage reservoirs is similar to the exploration for hydrocarbon reservoirs, the risk data of hydrocarbon exploration wells can be applied to infer the geological risks of the exploration wells for CO2 storage reservoirs. Based on this assumption, the study of Chapter 3 estimated that the probability of a borehole encountering a reservoir suitable for CO2 storage is c. 41-57% (90% confidence interval). For reservoirs with stratigraphic traps within the UKCS, the probability of success is slightly lower, at 39 ± 10% (90% confidence). Chapter 4 studies the porosity and diagenetic process of the Middle Jurassic Pentland Formation in the North Sea. The analysis data come from 21 wells that drilled and cored the Pentland Formation. Petrographic data suggest the content of detrital illite is the most important factor affecting the porosity of the Pentland Sandstone - the porosities of the sandstones with more than 15% of illite (determined by point-count) are invariably low (< 10%). Quartz cement grows at an average rate of 2.3 %/km below the depth of 2km, and it is the main porosity occluding phase in the deep Pentland Sandstone. Petrographic data shows the clean, fine-grained sandstones contain the highest amount of quartz cement. Only 1-2 % of K-feldspar seems to have dissolved in the deep Pentland Sandstone (> 2 km), and petrographic data suggest that K-feldspar dissolution does not have any substantial influence on the sandstone porosity. There is no geochemical evidence for mass transfer between the sandstones and shales of the Pentland Formation. Chapter 5 investigates the high porosity of the Pentland Sandstone in the Kessog Field, Central North Sea. The upper part of the Kessog reservoir displays an anomalously high porosity (c. 25 %, helium porosity) that is 10 % higher than the porosity of other Pentland sandstones at the same depth (c. 15 %, 4.1 - 4.4 km). Petrographic data show these high porosities are predominantly primary porosity. The effects of sedimentary facies, grain coats, secondary porosity and overpressure on the formation of the high porosity are considered to be negligible in this case. Early hydrocarbon emplacement is the only explanation for the high porosity. In addition to less quartz cement, the high-porosity sandstones also contain more K-feldspar and less kaolin than the medium-porosity sandstones of the same field. This indicates that early hydrocarbon emplacement has also inhibited the replacement of K-feldspar. The last chapter studies the potential mass transfer of silica, aluminium, potassium, iron, magenesium and calcium at sandstone-shale contacts. The study samples include 18 groups of sandstones and shales that were collected from five oilfields in the North Sea. The interval space between the samples of each group varies from centimetres to meters. The research aim is to find evidence of mass transfer by studying the samples' variation of mineralogy and chemistry as a function of the distance to the nearest sandstone-shale contact. The sandstones are mostly turbidite sandstones, and the shales are Kimmeridge Clay shales. Petrographic, mineralogical and chemical data do not provide firm evidence for mass transfer within any group of the samples. The result indicates that the scale of mobility of silica, aluminium, potassium, iron, magenesium and calcium in the subsurface may be below the scale of detection of the study method, i.e. < 5 cm.
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Hernandez, Ramos Juan Carlos. "Sensitivity of reservoir simulations to uncertainties in viscosity." Thesis, Imperial College London, 2001. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.369224.
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McInally, Alan T. "The reservoir sedimentology of ephemeral fluvial distributary systems." Thesis, Royal Holloway, University of London, 1996. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.287122.
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Man, Hing Nung. "Pore scale modelling of petrophysical characteristics of hydrocarbon reservoir rocks." Thesis, Imperial College London, 2001. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.271230.
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Al, Ramadhan Abdullah Ali S. "Reservoir imaging using induced microseismicity." Thesis, Curtin University, 2010. http://hdl.handle.net/20.500.11937/1963.
Full textAbstract:
Production activities within a hydrocarbon reservoir, such as extracting oil or injecting fluid, result in changes in stress which consequently cause micro-earthquakes. The induced micro-seismic events are small earthquakes producing high frequency waves which can be used to give a hi-resolution image of the hydrocarbon reservoir. However, induced micro-seismic events are usually too small in magnitude to be detected on the surface due to seismic wave attenuation through the overburden rocks. In addition, we lack information about their hypocentres and origin times. Besides, because the ray-path depends on the slowness model, the relationship between the arrival time and the slowness is nonlinear. Therefore, it is important to deploy many sensors well positioned within the hydrocarbon reservoir in order to make use of such induced micro-seismic events for monitoring, characterizing and/or imaging of the hydrocarbon reservoir.The current practice uses a fixed slowness model to obtain the origin times and hypocentres of induced micro-seismic events within a hydrocarbon reservoir. This, on the one hand, assumes that the velocity model is not changing, which may introduce errors into the hypocentres and origin times. It also ignores the information carried by the waves through the inactive zone. This, on the other hand, cannot replace the conventional 4D seismic time-lapse monitoring method to monitor the dynamic changes within a carbonate hydrocarbon reservoir.In this thesis, I present an iterative two-stage integrated framework to incorporate arrival times in order to address the problem. First, to estimate the hypocentre and origin time for each micro-seismic event, I have developed and implemented a systematic grid search algorithm to obtain the global minimiser of a nonlinear and multimodal objective function. The algorithm can also be applied to SWD (seismic while drilling) data to locate the drilling bit. Second, to reconstruct an improved velocity model, I have developed and implemented a two-phase algorithm to initially construct an objective function with its gradient for all the micro-seismic events and then apply the variable metric method to optimise the objective function. The algorithm can also be applied to VSP (vertical seismic profiling) data to construct the velocity model. The procedure is iterated until an acceptable match between observed data and computed synthetics is achieved. There are two main reasons for such a choice. First is the fact that both the position coordinates and origin time are unique for each particular micro-seismic event, whereas the slowness is common to all sources. Second is that we start with a good velocity model resulting from the prior information within a hydrocarbon reservoir and this can lead to a very accurate source positions coordinates and origin times. The framework can be used for either P-wave or S-wave.The methodology could lead to enhanced understanding and hence efficient management of the hydrocarbon reservoir. This in turn would enhance the understanding of fluid movements resulting in improved petroleum recovery from the reservoir.
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Mercedes, Martín Ramón. "Estudio de carbonatos microbiales en afloramiento como análogos de la caracterización y modelización de reservorios de hidrocarburos." Doctoral thesis, Universitat de Barcelona, 2013. http://hdl.handle.net/10803/132602.
Full textAbstract:
El registro sedimentario de la facies Muschelkalk superior (Triásico medio) de la Cuenca Catalana constituye un importante pulso transgresivo ladiniense en el NE de Iberia. Las curvas de subsidencia calculadas muestran dos etapas de subsidencia total rápida/desacelerada, constituyendo dos pulsos discretos rift-postrift durante el periodo Triásico. El segundo pulso (Muschelkalk superior-Fm. Imon (Rhaetiense) está caracterizado por una rápida subsidencia sinrift durante el Muschelkalk superior, la cual controló el desarrollo de los estromatolitos y trombolitos (biostromos y mud-mounds).
El registro del Muschelkalk superior está organizado en dos secuencias transgresivo-regresivas (T-R) formadas por dos rampas carbonatadas de bloques fracturados, dominadas por microbios y donde la acomodación estuvo controlada principalmente por fallas extensionales. Una caída del nivel del mar de al menos 50 m. tuvo lugar al final del Ladiniense inferior, dejando la plataforma subaéreamente expuesta. Como resultado, un importante carst con significativas incisiones erosivas y brechas de colapso se formó en posiciones de rampa interna y media. La discordancia subaérea resultante limita la secuencia T-R1 y 2. La Secuencia T-R1 se corresponde con una rampa carbonatada de bloques fracturados dominada por microbialitos y bajíos oolíticos. La Secuencia T-R2 representa una rampa carbonatada de bloques fracturados dominada por lagoons y bajíos.
Diversos tipos de microbialitos (estromatolitos s.s., estromatolitos oolítico-peloidales y trombolitos) están ampliamente representados en las porciones de rampa interna y media. Los microbialitos exhiben una porosidad relacionada con el medio de depósito, la cual está actualmente ocluida por cementos de calcita esparítica y cementos de cuarzo. Los tipos más comunes de porosidad antigua son de tipo interlaminar (fenestral), vacuolar (vuggy) y móldica (disolución de granos y reemplazamiento de evaporitas).
Los microbialitos estudiados registran una presencia concomitante durante el Ladiniense inferior (Fassanian), así como una yuxtaposición de las facies microbianas (estromatolitos s.s., estromatolitos oolítico-peloidales y trombolitos) durante el Ladiniense superior (Longobardian). A pesar de la participación de procesos microbianos en su acreción, varios factores extrínsecos (como la salinidad, energía del agua, tipo de sustrato y condiciones oceanográficas anómalas) fueron clave en el crecimiento de esos microbialitos.
Las rampas carbonatadas estudiadas pueden ser utilizadas como análogos de reservorios de hidrocarburos en microbialitos. Concretamente, en áreas deposicionales altamente subsidentes, que presentan una gran diversidad de depósitos microbianos formados en condiciones marinas abiertas a restringidas y con una gran variedad de porosidad antigua.The Upper Muschelkalk sedimentary record of the Triassic Catalan Basin (Catalan Ranges) constitutes a major transgressive pulse of northeastern Iberia during the Ladinian. Calculated subsidence curves display two stages of rapid/decelerated total subsidence, constituting two discrete rift/post-rift pulses in the large Triassic rifting period. The second pulse (Late Muschelkalk- Imon Formation (Rhaetian) is characterized by a rapid syn-rift subsidence during the Late Muschelkalk, which controls the development of the stromatolites and thrombolites (biostromes and mud-mounds). The Upper Muschelkalk sedimentary record is arranged in two transgressive-regressive (T-R) sequences formed by two fault-block microbial-dominated carbonate ramps where accommodation was mainly controlled by extensional faults. A sea-level fall of at least 50 metres occurred at the end of the Early Ladinian leaving the platform subaerially exposed. As a result, a prominent karst with significant erosional incisions and profuse collapse breccia fillings was formed in the inner and middle ramp settings. The resultant subaerial unconformity bounds T-R sequences 1 and 2. T-R sequence 1 corresponds to a fault-block carbonate ramp system dominated by microbialites and oolitic shoals. T-R sequence 2 represents a fault-block carbonate ramp system mainly characterised by lagoons and shoals. The diverse types of microbialites (stromatolites, ooidal-peloidal stromatolites and thrombolites) are widely represented in the inner and middle ramp settings. Microbialites exhibit a fabric-selective ancient porosity which is currently occluded by coarse calcite and quartz cements. The most common types of ancient porosity are interlaminar, vuggy and mouldic (grain dissolution and evaporite replacement). The studied microbialites recorded a concomitant occurrence during the Lower Ladinian (Fassanian), and juxtaposition of microbial facies (stromatolites, ooidal-peloidal stromatolites) during the Upper Ladinian (Longobardian). Despite the involvement of microbial processes in their accretion, a number of extrinsic factors such as salinity, water energy, sediment supply, type of substratum, and widespread and anomalous oceanographic conditions were instrumental in the growth of these microbialites. The studied carbonate ramps can be used as an analogue for ancient microbialite reservoirs in rapidly subsiding depositional areas, with a high diversity of microbial deposits formed in restricted to open marine conditions, with a wide array of ancient porosity and a well-known sequence stratigraphic context.
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Al-Siyabi, Zaid Khamis Sarbookh. "The contact angle, interfacial tension and viscosity of reservoir fluids : experimental data and modelling." Thesis, Heriot-Watt University, 2000. http://hdl.handle.net/10399/1198.
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