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1
Wong, Wing-yee. "Permeability studies in rock fractures." View the Table of Contents & Abstract, 2002. http://sunzi.lib.hku.hk/hkuto/record/B30109334.
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2
Wong, Wing-yee, and 黃詠儀. "Permeability studies in rock fractures." Thesis, The University of Hong Kong (Pokfulam, Hong Kong), 2002. http://hub.hku.hk/bib/B43895013.
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Schmitt, Mayka. "Pore structure characterization of low permeability rocks." reponame:Repositório Institucional da UFSC, 2014. https://repositorio.ufsc.br/xmlui/handle/123456789/128792.
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Tese (doutorado) - Universidade Federal de Santa Catarina, Centro Tecnológico, Programa de Pós-Graduação em Ciência e Engenharia de Materiais, Florianópolis, 2014.<br>Made available in DSpace on 2015-02-05T20:21:04Z (GMT). No. of bitstreams: 1
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Previous issue date: 2014<br>Hoje as pesquisas em rochas de baixa permeabilidade (grande tendência no mundo e em breve na indústria petrolífera brasileira) se voltam à escala de poros seja para investigação petrofísica, morfológica, de distribuição de tamanhos de grãos ou poros ou escoamento de fluidos, prática descrita pelos valores de permeabilidade. A avaliação destas propriedades por sua vez, é essencial ao desenvolvimento e exploração de reservas de hidrocarbonetos. No entanto, a determinação de parâmetros do sistema poroso nessas rochas, arenitos de baixa permeabilidade (TGS) e rochas selantes (SR), continua a ser um grande desafio devido à extrema variabilidade de ambientes deposicionais e complexa microestrutura composta por argilas e tamanhos de poros de submícrons a ångströms. Nesta tese empregou-se um conjunto de técnicas experimentais para a caracterização da estrutura porosa de TGS e SR. De tal modo, o trabalho foi dividido em dois tópicos principais: (i) Caracterização do sistema poroso e propriedades petrofísicas em TGS utilizando-se as técnicas de permeabilidade por decaimento de pulso (PDP), NMR de baixo campo, adsorção gasosa N2 (N2GA), porosimetria por intrusão Hg (MICP), nano- e microtomografia de raios X (res. <0,7 µm); (ii) Estudo por espectrometria fotoacústica (PAS) em SR de distintos campos geológicos para a determinação de porosidade e difusividade térmica (TD), de forma a estimular a exploração segura de gás e óleo, o armazenamento de CO2, bem como a caracterização de folhelhos. Para SR os valores de TD variaram entre 0,0167 e 0,0930 (cm2/s) e a porosidade entre 1,42 e 9%; para TGS a caracterização 3D da estrutura porosa forneceu valores de tortuosidade e fator de forma entre 2,19-5,47 e 3,2-8,5. As distribuições de tamanho de poros mostraram-se bimodais nos ensaios MICP, trimodais na multiescala 3D e tetramodais na NMR, enquanto a porosidade pela combinação N2GA e MICP variou entre 1,94 e 11,96% e a permeabilidade PDP de 0,036 a 0,00066 mD. Alguns dos parâmetros microestruturais obtidos em TGS foram correlacionados na estimativa de permeabilidade utilizando-se modelos como Carman-Kozeny (Dullien, 1992) e Coates (1999). O conjunto de técnicas e metodologias aplicado nesta tese mostrou ser ferramenta imprescindível na caracterização de rochas de baixa permeabilidade, uma vez que permitem integrar atributos da rede de poros que influenciam nas macro-propriedades das rochas analisadas.<br><br>Abstract : Nowadays, significant research effort in low-permeability rocks (a wide tendency elsewhere and soon in the Brazilian petroleum industry) has been focused on pore-scale petrophysics, morphologies and distributions, as well as fluid flow circulation described by the values of permeability. The evaluation of these properties in turn is essential for the assessment and exploitation of hydrocarbon reserves; however, determining pore system parameters in such rocks as tight gas sandstones (TGS) and seal rocks (SR) remains challenging because of the extreme variability in depositional environments resulting in complex pore structures comprised by clays and length scales from sub-microns to Angstroms. In this work we applied a set of techniques to characterize submicron-pore structures in TGS and SR. Therefore it was divided into two main topics of interest: (i) Characterization of petrophysical properties and pore systems in very low permeability TGS using Pulse-Decay Permeability (PDP), Low Field Nuclear Magnetic Resonance (LFNMR), Nitrogen Gas Adsorption (N2GA), Mercury Intrusion Capillary Pressure (MICP) and Multi-scale 3D X-ray Nano- and MicroCT (down to 0.7 µm resolution) techniques; (ii) Study of Photoacoustic Spectrometry (PAS) for determining thermal diffusivity (TD) and porosity in three seal rocks originating from dissimilar fields as a key issue for safe exploration, storage purposes (CO2 sequestration) and developments in shale characterization. The values obtained for TD were between 0.01667 and 0.09298 (cm2/s) while porosity ranged from 1.42 to 9%. For the analyzed TGS the 3D pore-structure characterization lead to pore tortuosity and shape factors ranges of 2.19-5.47 and 3.2-8.5, respectively, and pore size distributions tended to be bimodal for MICP, trimodal for 3D multi-scale and tetramodal for LFNMR measurements. The porosity values ranged from 1.94 to 11.96% obtained by the combination of N2GA and MICP techniques and permeability from 0.036 to 0.00066 mD by PDP technique. The measured pore-structure parameters were also used to predict empirical permeability in TGS (using e.g. Carman-Kozeny (Dullien, 1992) and Coates (1999) models). The set of applied methods has shown to be a useful tool for the unconventional reservoir characterization since it allows obtaining pore morphological and quantitative parameters which account for the permeability values.
4
Astakhov, Dmitriy Konstantinovich. "Permeability evolution as a result of fluid-rock interaction." Diss., Georgia Institute of Technology, 2000. http://hdl.handle.net/1853/21693.
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5
Bernabé, Yves. "Permeability and pore structure of rocks under pressure." Thesis, Massachusetts Institute of Technology, 1985. http://hdl.handle.net/1721.1/57818.
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Thesis (Ph. D.)--Massachusetts Institute of Technology, Dept. of Earth, Atmospheric, and Planetary Sciences, 1986.<br>Microfiche copy available in Archives and Science<br>Includes bibliographies.<br>by Yves Bernabe.<br>Ph.D.
6
Jozefowicz, R. R. "The post-failure stress-permeability behaviour of coal measure rocks." Thesis, University of Nottingham, 1997. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.339717.
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Hyun, Yunjung. "Multiscale anaylses of permeability in porous and fractured media." Diss., The University of Arizona, 2002. http://etd.library.arizona.edu/etd/GetFileServlet?file=file:///data1/pdf/etd/azu_e9791_2002_321_sip1_w.pdf&type=application/pdf.
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8
Schaffer, Andrew 1952. "PERMEABILITY TESTING AND GROUTING OF FRACTURED ROCK." Thesis, The University of Arizona, 1985. http://hdl.handle.net/10150/275420.
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Pereira, Janaina Luiza Lobato. "Permeability prediction from well log data using multiple regression analysis." Morgantown, W. Va. : [West Virginia University Libraries], 2004. https://etd.wvu.edu/etd/controller.jsp?moduleName=documentdata&jsp%5FetdId=3368.
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Thesis (M.S.)--West Virginia University, 2004.<br>Title from document title page. Document formatted into pages; contains xiii, 82 p. : ill. (some col.), maps. Vita. Includes abstract. Includes bibliographical references (p. 41).
10
AZEVEDO, FLAVIO DA SILVA. "EXPERIMENTAL STUDY OF THE STRESS INFLUENCE ON PERMEABILITY OF PRODUCING OIL ROCKS." PONTIFÍCIA UNIVERSIDADE CATÓLICA DO RIO DE JANEIRO, 2005. http://www.maxwell.vrac.puc-rio.br/Busca_etds.php?strSecao=resultado&nrSeq=6697@1.
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COORDENAÇÃO DE APERFEIÇOAMENTO DO PESSOAL DE ENSINO SUPERIOR<br>Reservatórios de hidrocarbonetos são sistemas dinâmicos que
estão
constantemente mudando durante a história da produção
(depleção). A produção
de fluidos, a partir de reservas de hidrocarbonetos, reduz
a poro-pressão do
reservatório, podendo levar à compactação das rochas devido
ao aumento das
tensões efetivas. Por outro lado, a injeção de água em um
reservatório pode
aumentar a poro-pressão e, com isso, diminuir a tensão
efetiva. O conhecimento
de mudanças de tensão e poro-pressão é essencial para uma
boa gestão do
reservatório, porque a alteração da tensão in situ durante
a produção pode ter um
impacto significante na performance do reservatório,
variando a permeabilidade
da rocha. O objetivo da atual pesquisa é estudar
experimentalmente a variação, a
anisotropia e a histerese de permeabilidade de rochas
produtoras de petróleo
(arenitos) sob variação dos estados de tensão hidrostático
e triaxial verdadeiro.
Para realização dos ensaios foi utilizado um novo
equipamento triaxial verdadeiro,
que aplica de forma independente as três tensões principais
em corpos de prova
cúbicos, atingindo, desta maneira, um estado de tensão mais
realista para o estudo
das propriedades relevantes das rochas. Os resultados dos
ensaios apresentaram
evidências que estimativas de produção e de reserva de
hidrocarbonetos podem
ser significativamente melhoradas, quando a permeabilidade
é considerada uma
variável dinâmica. A permeabilidade dos arenitos Berea, Rio
Bonito e Botucatú se
mostrou altamente influenciada, tanto pelo estado de tensão
hidrostático quanto
pelo triaxial verdadeiro. Contudo, o estado hidrostático
apresentou maior
influência na permeabilidade.<br>Hydrocarbons reservoirs are dynamic systems that constantly
changes
during depletion. The production of fluids from a reservoir
often reduces pore
pressure such that there is an increase in its effective
stresses. This may cause
compaction which, in turn, may impact matrix permeability.
On the other hand,
during water injection on reservoirs, the pore pressure
increases and effective
stress decreases. An understanding of these changes is of
fundamental importance
to performance predictions and management of the stress-
sensitive reservoirs. The
main objectives of this work is to experimentally
investigate the stress dependence
of rock producing oil permeability, its anisotropy and
hysteresis under hydrostatic
and true triaxial stress conditions. In the present
investigation a new true triaxial
equipment, one that is able to apply the three principal
boundary stresses
independently using cubic samples was utilized. This
equipment can apply a
realistic stress state to the rock samples for measuring of
the relevant properties
under stress states that mimic the in situ condition. The
experimental results have
produced evidence that hydrocarbon production and reserve
estimates may
significantly improve when permeability is considered as a
dynamic variable.
Permeability in all three formations (Berea, Rio Bonito and
Botucatú sandstones)
was shown to be strongly stress-dependent both under a
hydrostatic stress state
and under a true triaxial stress state. Nevertheless, the
effect of stress states on
permeability has clearly shown that permeability reduction
under true triaxial
stresses was less than that under hydrostatic stresses.
11
Nunn, Jacob. "Investigations of Partial Gas Saturation on Diffusion in Low-permeability Sedimentary Rocks." Thesis, Université d'Ottawa / University of Ottawa, 2018. http://hdl.handle.net/10393/38396.
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The effect of partially saturated conditions on aqueous diffusion was investigated on the Upper Ordovician Queenston Formation shale from the Michigan Basin of southwest Ontario, Canada. Effective diffusion coefficients (De) were determined for iodide tracer on duplicate cm-scale samples from a core segment. Partially saturated conditions were created with a new gas-ingrowth method that takes advantage of the variability of N2 solubility with pressure. The method is designed to create partially saturated pores, quantify the level of partial gas/brine saturation within the tracer-accessible pore space, and measure De under fully porewater-saturated and partially gas-saturated conditions for the same sample. X-ray radiography is used with an iodide tracer for quantifying the degree of partial saturation and measuring De. The saturated De values range from 2.8 x 10-12 to 3.1 x 10-12 m2/s. Following generation of a gas phase in the pores (average gas saturations of 4 to 6.7 %), De values decrease by 20 to 22 % relative to the porewater-saturated condition, indicating that the tortuosity factor (ratio of constrictivity to tortuosity) is sensitive to saturation. Suggesting that a small volume of the pore fraction is responsible for majority of the transport. The gas-ingrowth method was successful for generating partial gas saturation, but the distribution of the gas phase is non-uniform, with relatively high gas saturations near boundaries and lower saturations in the interior of the samples.
12
Fabbri, Heber Agnelo Antonel. "Modeling the effects of natural fractures on the permeability of reservoir rocks /." Bauru, 2019. http://hdl.handle.net/11449/190698.
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Orientador: Osvaldo Luís Manzoli<br>Abstract: This work presents a numerical method based on Discrete Fracture Model (DFM) and the Finite Element Method (FEM), where the fractures are approximated by a reduced model. The flow along and across the fracture is described by a simplified set of equations considering both conductive fractures and barriers. The coupled hydromechanical model is composed of a linear poroelastic Biot medium and a nonlinear model based on damage mechanics for the fractures, which captures the nonlinear normal deformation and shear dilation according to the Barton-Bandis model. Both flow and geomechanical models are approximated using the finite element model. Fractures are explicitly represented by three-node standard finite elements with high aspect ratio (i.e. ratio between the largest and the smallest element dimensions) and appropriate constitutive laws. These interface high aspect ratio elements represent a regularization method which continuously approximate the discontinuous pressure and displacement fields on a narrow material band around the fracture. The complete mathematical formulation is presented together with the algorithm suggested for its numerical implementation. The efficiency of the proposed method is demonstrated through numerical examples, as well as the effects of fractures in the hydraulic properties of porous rocks and its dependency of the stress state.<br>Resumo: Este trabalho apresenta um método numérico baseado no Modelo de Fratura Discreta (MFD) e no Método dos Elementos Finitos (MEF), onde as fraturas são aproximadas por um modelo reduzido. O fluxo ao longo e através da fratura é descrito por um conjunto simplificado de equações, considerando tanto fraturas condutoras quanto barreiras. O modelo hidromecânico acoplado é composto por um meio poroelástico linear e um modelo não linear para fraturas, baseado na mecânica do dano e que captura a deformação normal não linear e a dilatância ao cisalhamento de acordo com o modelo de Barton-Bandis. Os modelos de fluxo e geomecânico são aproximados usando o método dos elementos finitos. As fraturas são explicitamente representadas por elementos finitos triangulares de três nós com elevada razão de aspecto (isto é, a razão entre a maior e a menor dimensão do elemento) e leis constitutivas apropriadas. Esses elementos de elevada razão de aspecto representam um método de regularização que aproxima de forma contínua os campos de pressão e deslocamento descontínuos em uma estreita faixa material ao redor da fratura. A formulação matemática completa é apresentada juntamente com o algoritmo sugerido para sua implementação numérica. A eficiência do método proposto é demonstrada através de exemplos numéricos, bem como os efeitos de fraturas nas propriedades hidráulicas de rochas porosas e sua dependência do estado de tensão.<br>Mestre
13
Depner, Joseph Scott. "Estimation of the three-dimensional anisotropic spatial covariance of log permeability using single-hole and cross-hole packer test data from fractured granites." Thesis, The University of Arizona, 1985. http://etd.library.arizona.edu/etd/GetFileServlet?file=file:///data1/pdf/etd/azu_e9791_1985_407_sip1_w.pdf&type=application/pdf.
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Ryan, Thomas Michael 1963. "A laboratory assessment of flow characteristics and permeability of fractures in rock." Thesis, The University of Arizona, 1987. http://hdl.handle.net/10150/276629.
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Intact and fractured rock samples were studied in the laboratory in order to understand more fully the mechanism of closure of fractures subjected to high confining stresses and the resultant effect on specimen permeability. Confining stresses applied to the specimens ranged from 3.0 to 20.0 MPa, and the closure of fractures was observed by monitoring the change in the hydraulic conductivity of the specimens. Test results suggest that some resealing may occur due to crushing and realignment of mineral grains along a fracture surface. The closure of fractures is dependent upon the strength of the rock mass, the physical nature of the fracture, and the fluid pressure present in the fracture. Fracture closure is highly time dependent, and a number of nonlinear pressure flow relationships have been identified. These deviations are thought to represent two fundamentally different processes, the most important of which are turbulence in the flow and fracture expansion.
15
Cant, Joseph Liam. "Matrix Permeability of Reservoir Rocks, Ngatamariki Geothermal Field, Taupo Volcanic Zone, New Zealand." Thesis, University of Canterbury. Geology, 2015. http://hdl.handle.net/10092/10567.
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Sixteen percent of New Zealand’s power comes from geothermal sources which are primarily located within the Taupo Volcanic Zone (TVZ). The TVZ hosts twenty three geothermal fields, seven of which are currently utilised for power generation. Ngatamariki Geothermal Field is the latest geothermal power generation site in New Zealand, located approximately 15 km north of Taupo. This was the location of interest in this project, with testing performed on a range of materials to ascertain the physical properties and microstructure of reservoir rocks. The effect of burial diagenesis on the physical properties was also investigated.
Samples of reservoir rocks were taken from the Tahorakuri Formation and Ngatamariki Intrusive Complex from a range of wells and depths (1354-3284 mbgl). The samples were divided into four broad lithologies: volcaniclastic lithic tuff, primary tuff, welded ignimbrite and tonalite. From the supplied samples twenty one small cylinders (~40-50mm x 20-25mm) were prepared and subjected to the following analyses: dual weight porosity, triple weight porosity, dry density, ultrasonic velocity (saturated and dry) and permeability (over a range of confining pressures). Thin sections impregnated with an epoxy fluorescent dye were created from offcuts of each cylinder and were analysed using polarised light microscopy and quantitative fluorescent light microstructural microscopy.
The variety of physical testing allowed characterisation of the physical properties of reservoir rocks within the Ngatamariki Geothermal Field. Special attention was given to the petrological and mineralogical fabrics and their relation to porosity and matrix permeability. It was found that the pore structures (microfractures or vesicles) had a large influence on the physical properties. Microfractured samples were associated with low porosity and permeability, while the vesicular samples were associated with high porosity and permeability. The microfractured samples showed progressively lower permeability with increased confining pressure whereas samples with a vesicular microstructure showed little response to increased confining pressure.
An overall trend of decreasing porosity and permeability with increasing density and sonic velocity was observed with depth, however large fluctuations with depth indicate this trend may be uncertain. The large variations correlate with changes in lithology suggest that the lithology is the primary control of the physical properties with burial diagenesis being a subsidiary factor.
This project has established a relationship between the microstructure and permeability, with vesicular samples showing high permeability and little response increased confining pressure. The effects of burial diagenesis on the physical properties are subsidiary to the observed variations in lithology. The implications of these results suggest deep drilling in the Tahorakuri Formation may reveal unexploited porosity and permeability at depth.
16
Phillips, Matthew David. "The effect of pore structure on gas and liquid permeability in crystalline rocks." Thesis, University of London, 2001. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.252227.
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Riera, Alexis J. "Predicting permeability and flow capacity distribution with back-propagation artificial neural networks." Morgantown, W. Va. : [West Virginia University Libraries], 2000. http://etd.wvu.edu/templates/showETD.cfm?recnum=1309.
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Thesis (M.S.)--West Virginia University, 2000.<br>Title from document title page. Document formatted into pages; contains xii, 86 p. : ill. (some col.), maps. Includes abstract. Includes bibliographical references (p. 61-63).
18
Nines, Shawn D. "Predicting a detailed permeability profile from minipermeameter measurements and well log data." Morgantown, W. Va. : [West Virginia University Libraries], 2000. http://etd.wvu.edu/templates/showETD.cfm?recnum=1690.
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Thesis (M.S.)--West Virginia University, 2000.<br>Title from document title page. Document formatted into pages; contains ix, 111 p. : ill. (some col.), map. Includes abstract. Includes bibliographical references (p. 110-111).
19
Bashir, Abdulaadem A. "An experimental investigation of some capillary pressure-relative permeability correlations for sandstone reservoir rocks." Thesis, Robert Gordon University, 2000. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.310346.
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Keaney, Gemma Maria Jacinta. "Experimental study of the evolution of permeability in rocks under simulated crustal stress conditions." Thesis, University College London (University of London), 2000. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.392134.
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Farough, Aida. "An experimental study on characterization of physical properties of ultramafic rocks and controls on evolution of fracture permeability during serpentinization at hydrothermal conditions." Diss., Virginia Tech, 2015. http://hdl.handle.net/10919/76669.
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Serpentinization is a complex set of hydration reactions, where olivine and pyroxene are replaced by serpentine, magnetite, brucite, talc and carbonate minerals. Serpentinization reactions alter chemical, mechanical, magnetic, seismic, and hydraulic properties of the crust. To understand the complicated nature of serpentinization and the linkages between physical and chemical changes during the reactions, I performed flow-through laboratory experiments on cylindrically cored samples of ultramafic rocks.
Each core had a well-mated through-going tensile fracture, to investigate evolution of fracture permeability during serpentinization. The samples were tested in a triaxial loading machine at an effective pressure of 30 MPa, and temperature of 260°C, simulating a depth of 2 km under hydrostatic conditions. Fracture permeability decreased by one to two orders of magnitude during the 200 to 340 hour experiments. Electron microprobe and SEM data indicated the formation of needle-shaped crystals of serpentine composition along the walls of the fracture, and chemical analyses of sampled pore fluids were consistent with dissolution of ferro-magnesian minerals. The rate of transformation of olivine to serpentine in a tensile fracture is calculated using the data on evolution of fracture permeability assuming the fracture permeability could be represented by parallel plates. Assuming the dissolution and precipitation reactions occur simultaneously; the rate of transformation at the beginning of the experiments was ~ 10-8-10-9 (mol/m2s) and decreased monotonically by about an order of magnitude towards the end of the experiment. Results show that dissolution and precipitation is the main mechanism contributing to the reduction in fracture aperture. The experimental results suggest that the fracture network in long-lived hydrothermal circulation systems may be sealed rapidly as a result of mineral precipitation, and generation of new permeability resulting from a combination of tectonic and crystallization-induced stresses may be required to maintain fluid circulation.
Another set of flow through experiments were performed on intact samples of ultramafic rocks at room temperature and effective pressures of 10, 20 and 30 MPa to estimate the pressure dependency of intact permeability. Porosity and density measurements were also performed with the purpose of characterizing these properties of ultramafic rocks.
The pressure dependency of the coefficient of matrix permeability of the ultramafic rock samples fell in the range of 0.05-0.14 MPa-1. Using porosity and permeability measurements, the ratio of interconnected porosity to total porosity was estimated to be small and the permeability of the samples was dominantly controlled by microcracks. Using the density and porosity measurements, the degree of alteration of samples was estimated. Samples with high density and pressure dependent permeability had a smaller degree of alteration than those with lower density and pressure dependency.<br>Ph. D.
22
Ehab, Moustafa Kamel Karim. "Image-based modelling of complex heterogeneous microstructures: Application to deformation-induced permeability alterations in rocks." Doctoral thesis, Universite Libre de Bruxelles, 2021. http://hdl.handle.net/2013/ULB-DIPOT:oai:dipot.ulb.ac.be:2013/320653.
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The permeability of rocks has a critical influence on their fluid transport response in critical geo-environmental applications, such as pollutant transport or underground storage of hazardous nuclear waste. In such processes, the materials microstructure may be altered as a result of various stimuli, thereby impacting the fluid transfer properties. Stress or strain state modifications are one of the main causes for such evolutions. To numerically address this concern, an integrated and automated numerical tool was developed and illustrated on subsets of microCT scans of a Vosges sandstone (i) to explore the links between the pore space properties and the corresponding macroscopic transfer properties, with (ii) an incorporation of the microstructural alterations associated with stress state variations by using a realistic image-based representation of the microstructural morphology. The ductile mechanical deformation behavior under high confining pressures at the scale of the microstructure, inducing pore closures by local plastifications, was modelled using finite elements simulations with a non-linear elastoplastic law, allowing to take into account the redistribution of local stresses. These simulations require robust discretization tools to capture the complex geometry of the porous network and the corresponding solid boundaries of the heterogeneous microstructural geometries. To achieve this, an integrated approach for the conformal discretization of complex implicit geometries based on signed distance fields was developed, producing high quality meshes from both imaging techniques and computational RVE generation methodologies. This conforming discretization approach was compared with an incompatible mode-based framework using a non conforming approach. This comparison highlighted the complementarity of both methods, the former capturing the effect of more detailed geometrical features, while the latter is more flexible as it allows using the same (non conforming) mesh for potentially variable geometries.The evolution of permeability was evaluated at different confining pressure levels using the Lattice-Bolzmann method. This uncoupled solid-fluid interaction made it possible to study the combined influence on the permeability, porosity and the pores size distribution of the pore space morphology and the solid skeleton constitutive law parameters during loading and unloading conditions. The results highlight the need to consider elastoplastic laws and heterogeneities in the rock model to simulate the ductile behavior of rocks at high confining pressures leading to significant permeability alterations under loading, and irreversible alterations under loading/unloading cycles induced by progressive pore closures.The proposed methodology is designed to be flexible thanks to the interfacing with 'classical' discretization approaches and can be easily readapted to other contexts given the block approach.<br>Doctorat en Sciences de l'ingénieur et technologie<br>info:eu-repo/semantics/nonPublished
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Saurabh, Suman. "GEOMECHANICAL STATE OF ROCKS WITH DEPLETION IN UNCONVENTIONAL COALBED METHANE RESERVOIRS." OpenSIUC, 2020. https://opensiuc.lib.siu.edu/dissertations/1826.
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AN ABSTRACT OF THE DISSERTATION OFSUMAN SAURABH, for the Doctor of Philosophy degree in Engineering Science, presented on August 30, 2019, at Southern Illinois University Carbondale.TITLE: GEOMECHANICAL STATE OF ROCKS WITH DEPLETION IN UNCONVENTIONAL COALBED METHANE RESERVOIRSMAJOR PROFESSOR: Dr. Satya HarpalaniOne of the major reservoir types in the class of unconventional reservoirs is coalbed methane. Researchers have treated these reservoirs as isotropic when modeling stress and permeability, that is, mechanical properties in all directions are same. Furthermore, coal is a highly sorptive and stress- sensitive rock. The focus of this dissertation is to characterize the geomechanical aspects of these reservoirs, strain, stresses, effective stress and, using the information, establish the dynamic flow/permeability behavior with continued depletion. Several aspects of the study presented in this dissertation can be easily extended to shale gas reservoirs. The study started with mechanical characterization and measurement of anisotropy using experimental and modeling work, and evaluation of how the sorptive nature of coal can affect the anisotropy. An attempt was also made to characterize the variation in anisotropy with depletion. The results revealed that the coals tested were orthotropic in nature, but could be approximated as transversely isotropic, that is, the mechanical properties were isotropic in the horizontal plane, but significantly different in vertical direction. Mechanical characterization of coal was followed by flow modeling. Stress data was used to characterize the changes in permeability with depletion. This was achieved by plotting stress path followed by coal during depletion. The model developed was used to successfully predict the permeability variation in coal with depletion for elastic deformations. As expected, the developed model failed to predict the permeability variation resulting from inelastic deformation given that it was based on elastic constitutive equations. Hence, the next logical step was to develop a generalized permeability model, which would be valid for both elastic and inelastic deformations. Investigation of the causes of coal failure due to anisotropic stress redistribution during depletion was also carried out as a part of this study. It was found that highly sorptive rocks experience severe loss in horizontal stresses with depletion and, if their mechanical strength is not adequate to support the anisotropic stress redistribution, rock failure can result. In order to develop a generalized permeability model based on stress data, stress paths for three different coal types were established and the corresponding changes in permeability were studied. Stress path plotted in an octahedral mean stress versus octahedral shear stress plane provided a signal for changes in the permeability for both elastic as well as inelastic deformations. This signal was used to develop a mechanistic model for permeability modeling, based on stress redistribution in rocks during depletion. The model was able to successfully predict the permeability variation for all three coal types. Finally, since coal is highly stress- sensitive, changes in effective stresses were found to be the dictating factor for deformations, changes in permeability and possible failure with depletion. Hence, the next step was to develop an effective stress law for sorptive and transversely isotropic rocks. For development of an effective stress law for stress sensitive, transversely isotropic rocks, previously established constitutive equations were used to formulate a new analytical model. The model was then used to study changes in the variation of Biot’s coefficient of these rocks. It was found that Biot’s coefficient, typically less than one, can take values larger than one for these rocks, and their values also change with depletion. The study provides a methodology which can be used to estimate the Biot’s coefficient of any rock. As a final step, preliminary work was carried out on the problem of under-performing coal reservoirs in the San Juan basin, where coal is extremely tight with very low permeability. An extension of the work presented in this dissertation is to use the geomechanical characterization techniques to unlock these reservoirs and improve their performance. The experimental data collected during this preliminary study is included in the last chapter of the dissertation.
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Nejedlik, John. "Petrographic image analysis as a tool to quantify porosity and cement distribution." Title page, contents and abstract only, 2001. http://web4.library.adelaide.edu.au/theses/09SM/09smn417.pdf.
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Includes bibliographical references (leaves 153-157). Petrographic image analysis proved particularly useful in determining the parameters for statistical analysis for the simple mineralogies displayed in the samples from the Hutton Sandstone. Concentrates on establishing techniques for statistical study of data collected by PIA to subdivide the framework grains from the porosity or cement.
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Bächle, Gregor T. [Verfasser], and Thomas [Akademischer Betreuer] Aigner. "Effects of pore structure on velocity and permeability in carbonate rocks / Gregor T. Bächle ; Betreuer: Thomas Aigner." Tübingen : Universitätsbibliothek Tübingen, 2012. http://d-nb.info/116269999X/34.
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Benson, Philip Michael. "Experimental study of void space, permeability and elastic anisotropy in crustal rocks under ambient and hydrostatic pressure." Thesis, University College London (University of London), 2004. http://discovery.ucl.ac.uk/1446540/.
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Anisotropy in the physical and transport properties of crustal rocks is a key influence on crustal evolution and energy resource management. Data from deep seismic soundings, borehole logging and laboratory measurement all show that the physical properties of the earth are anisotropic. Such anisotropy generally results from the superposition of fabric development during diagenesis and/or petrogenesis, and the application of anisotropic tectonic stresses. This leads to an aligned crack and pore fabric in crustal rocks that, in turn, leads to seismic velocity anisotropy and permeability anisotropy. This thesis describes an experimental study which aims to investigate the relationships between pressure, pore fabric geometry and seismic and permeability anisotropy under hydrostatic pressures from room pressure to ~4km depth equivalence within the Earth's crust. Firstly, pore fabric analyses of three representative crustal rock types is presented. These rock types represent a range of crack and pore fabrics. The average void space shape and orientation is determined 3-D using the methods of anisotropy of magnetic susceptibility and velocity anisotropy. Scanning electron microscopy and fluorescent-dye crack imaging techniques further aid in the void space characterisation. Secondly, the development and application of an apparatus capable of contemporaneously measuring elastic wave velocity, porosity and permeability at effective pressures of up to 100 MPa is described. Results are analysed in terms of applied effective pressure and the rock pore fabric type and orientation. Finally, the laboratory data are used to test models that attempt to predict geophysical parameters such as permeability and elastic wave velocity from microstructural attributes. This multi-facetted analysis allows a number of conclusions to be drawn, expanding the state-of-the-art in how the pore fabric microstructure of crustal rock is represented by the methods of elastic wave velocity and porosity, with reference to the hydrostatic confining pressure and hence the burial conditions of the rock.
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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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Busch, Andreas [Verfasser], H. [Akademischer Betreuer] Stanjek, C. J. [Akademischer Betreuer] Spiers, and D. [Akademischer Betreuer] Elsworth. "Gas retention and transport processes in low permeability rocks / Andreas Busch ; H. Stanjek, C. J. Spiers, D. Elsworth." Aachen : Universitätsbibliothek der RWTH Aachen, 2015. http://d-nb.info/1126040592/34.
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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 - MSc<br>This 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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Ecevitoglu, Berkan G. "Velocity and Q from reflection seismic data." Diss., Virginia Polytechnic Institute and State University, 1987. http://hdl.handle.net/10919/77793.
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This study has resulted in the discovery of an exact method for the theoretical formulation of the effects of intrinsic damping where the attenuation coefficient, a(v), is an arbitrary function of the frequency, v. Absorption-dispersion pairs are computed using numerical Hilbert transformation; approximate analytical expressions that require the selection of arbitrary constants and cutoff frequencies are no longer necessary. For constant Q, the dispersive body wave velocity, p(v), is found to be
p(v) = (p(v<sub>N</sub>)/(1+(1/2Q H(-v)/v))
where H denotes numerical Hilbert transformation, p(v) is the phase velocity at the frequency v, and p(v<sub>N</sub>) is the phase velocity at Nyquist. From (1) it is possible to estimate Q in the time domain by measuring the amount of increase, ΔW, of the wavelet breadth after a traveltime,
Q=(2Δ𝛕)/(𝝅ΔW)
The inverse problem, i.e., the determination of Q and velocity is also investigated using singular value decomposition (SVD). The sparse matrices encountered in the acquisition of conventional reflection seismology data result in a system of linear equations of the form AX = B, with A the design matrix, X the solution vector, and B the data vector. The system of normal equations is AᵀAX = AᵀB where the least-squares estimate of X = X = V(1/S)UᵀB and the SVD of A is A = USVᵀ. A technique to improve the sparsity pattern prior to decomposition is described.
From an application of equation (2) using reference reflections from shallower reflectors, crystalline rocks in South Carolina over the depth interval from about 5 km to 10 km yield values of Qin the range Q = 250 - 300.
Non-standard recording geometries ( "Q-spreads") and vibroseis recording procedures are suggested to minimize matrix sparseness and increase the usable frequency bandwidth between zero and Nyquist. The direct detection of body wave dispersion by conventional vibroseis techniques may be useful to distinguish between those crustal volumes that are potentially seismogenic and those that are not. Such differences may be due to variations in fracture density and therefore water content in the crust.<br>Ph. D.
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Chen, Tao Verfasser], Christoph [Akademischer Betreuer] [Clauser, Olaf [Akademischer Betreuer] Kolditz, and Gabriele [Akademischer Betreuer] Marquart. "Upscaling permeability for fractured porous rocks and modeling anisotropic flow and heat transport / Tao Chen ; Christoph Clauser, Olaf Kolditz, Gabriele Marquart." Aachen : Universitätsbibliothek der RWTH Aachen, 2017. http://d-nb.info/1180733703/34.
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Chen, Tao [Verfasser], Christoph [Akademischer Betreuer] Clauser, Olaf [Akademischer Betreuer] Kolditz, and Gabriele [Akademischer Betreuer] Marquart. "Upscaling permeability for fractured porous rocks and modeling anisotropic flow and heat transport / Tao Chen ; Christoph Clauser, Olaf Kolditz, Gabriele Marquart." Aachen : Universitätsbibliothek der RWTH Aachen, 2017. http://d-nb.info/1180733703/34.
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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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Gaunt, H. E. "Experimental study of permeability under simulated volcanic conditions on lava dome rocks from Mount St. Helens : constraints on degassing and eruption style." Thesis, University College London (University of London), 2014. http://discovery.ucl.ac.uk/1426442/.
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The research presented in this thesis integrates field observations and sampling, data from controlled laboratory experiments with a radially-symmetric fluid flux model to investigate permeability controls on degassing processes operating during lava dome eruptions at silicic volcanoes. Laboratory permeability measurements were made on samples collected systematically across the marginal shear zone of a lava spine at Mount Saint Helens (MSH), Washington, USA, from the 2004-08 eruption, at room temperature and confining pressures up to 85 MPa. Permeability experiments were also performed on samples of massive dacite from the spine core at a range of temperatures up to 900°C and a confining pressure of 10 MPa. A simplified radially-symmetric fluid flux model was developed which incorporated the observed structure of the conduit at Mount Saint Helens and the measured permeability profile to show the effects of the permeability on the magnitude and direction of fluid flow. Permeability was found to be essentially isotropic in the conduit interior but highly anisotropic in the marginal shear zone rocks. Vertical permeability in the marginal rocks is increased by two orders of magnitude, through the formation of an aligned shear fracture network. Ultracataclasite shear bands in the fault core also decreased the horizontal permeability by two orders of magnitude. Permeability was also seen to decrease by around four orders of magnitude as temperature was increased to 900°C. In contrast to previous work that assumed significant lateral transport of gases, modeled fluid flow using the experimentally determined permeability data shows that the vertical volatile volumetric flow rate will be orders of magnitude greater than the horizontal rate into the wall rock; more than 90% of volatile flow would have been partitioned vertically within the conduit-margin fault zone, consistent with the location of gas and ash venting during the eruption. Changes in permeability with temperature indicate that magma rising in the conduit becomes progressively more permeable to gas escape during ascent and crystallisation. When applied to gas sealing processes, the intrusion of molten lava under a solidified plug and the associated heating may cause the permeability of the overlying rock to decrease sufficiently that gas escape is inhibited, allowing for the build up of pressure and potentially an explosive eruption.
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Domínguez, Lucía García 1988. "Efeito da vazão nas curvas de permeabilidade relativa em regime transiente." [s.n.], 2015. http://repositorio.unicamp.br/jspui/handle/REPOSIP/265757.
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Orientador: Rosângela Barros Zanoni Lopes Moreno<br>Dissertação (mestrado) - Universidade Estadual de Campinas, Faculdade de Engenharia Mecânica e Instituto de Geociências<br>Made available in DSpace on 2018-08-28T12:56:20Z (GMT). No. of bitstreams: 1
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Previous issue date: 2015<br>Resumo: A capacidade de armazenamento de hidrocarbonetos no reservatório depende do tipo de rocha e da estrutura dos poros. Uma das propriedades rocha-fluido mais estudadas é a permeabilidade relativa, ou seja, a medida da resistência ao escoamento que um fluido apresenta na presença de outro. A permeabilidade relativa é essencial para a avaliação dos processos de recuperação de hidrocarbonetos e previsão do escoamento multifásico de fluidos através do reservatório. A permeabilidade relativa depende de outros parâmetros que têm sido estudados por especialistas durante os últimos anos, como saturação dos fluidos, molhabilidade, tensão interfacial, estrutura porosa, temperatura, heterogeneidades e vazão de deslocamento. Em relação ao efeito da vazão de deslocamento na permeabilidade relativa, muitas pesquisas têm sido realizadas sem conseguir um acordo. Por tanto, a principal motivação deste estudo é a falta de conformidade na literatura. O foco do trabalho é encontrar se existe dependência da permeabilidade relativa com a vazão e avaliar este efeito em óleos de diferentes viscosidades. Foram realizados quinze testes de deslocamento em regime transiente a temperatura e vazão constantes. Os experimentos de laboratório foram executados com três plugues, cortados a partir de uma amostra única de rocha carbonática e saturados com três óleos de viscosidades diferentes, respetivamente. Foram utilizadas três vazões diferentes para cada amostra, que correspondem aos valores mínimo, máximo e intermediário de acordo o critério de dos Santos et al (1997) que visa balancear as forças viscosas, capilares e gravitacionais. Estas vazões foram variadas começando pela maior e diminuindo até a menor e posteriormente revertendo o ciclo, para observar se a sequência seguida influencia nos resultados. A análise dos resultados foi realizada mediante o método de Johnson-Bossler-Naumann para calcular as permeabilidades relativas ao óleo e à água. Sob as condições dos testes realizados, observou-se que as saturações e permeabilidades dos pontos terminais bem como as curvas de permeabilidade relativa, dependem da vazão. Além disso, pode-se observar que as variações foram diferentes dependendo da viscosidade do óleo utilizado. Deste modo, o óleo de menor viscosidade sempre se comportou de modo contrário ao de maior viscosidade e a mistura dos outros dois teve um comportamento intermediário. Este comportamento tem sido atribuído, nos óleos mais viscosos, a um aumento no ângulo de contato e consequente diminuição do número capilar em resposta à vazão mais elevada. Já nos óleos menos viscosos, a vazão não altera significativamente o ângulo de contato e, portanto, o número capilar aumenta com a vazão. Estas diferenças na variação do número capilar, dependendo do óleo utilizado, podem gerar as tendências diferentes nos resultados e explicar o desacordo na literatura<br>Abstract: The storability of hydrocarbons in the reservoir is dependent upon the rock formation and the pore structures. One of the main important rock-fluid property is the relative permeability, a measure of the flow resistance of one fluid in the presence of another one into the rock. Relative permeability depends on other parameters which have been studied by researchers during the years like fluid properties and saturation, wettability, interfacial tension, porous structure, temperature, heterogeneity and flow rate. Many researchers have focused on flow rate influence in relative permeability curves without obtaining agreement. Therefore, the main motivation for this study is the lack of conformity in the literature. The focus of the work is to find whether there is dependence of relative permeability with the flow and evaluate this effect in oils of different viscosities. Fifteen transient displacement tests were performed at constant temperature and flow rate. The laboratory experiments were performed with three plugs, cut from a single sample of carbonate rock and saturated with three fluids of different viscosities, respectively. Three different flow rates were used for each sample, corresponding to the minimum, maximum and intermediate according to dos Santos et al criterion (1997) which aims to balance the viscous, capillary and gravitational forces. These flow rates were varied starting with the largest and decreasing to the smallest, and subsequently reversing the cycle, to see if the next sequence influences the results. Experimental results were analyzed using JBN method (Johnson-Bossler-Naumann) to calculate oil and water relative permeability curves. Under the studied circumstances, it was observed that the end point saturations and permeabilities and the relative permeability curves depend on the flow rate. Moreover, variations were different depending on the viscosity of the oil used. Thus, the lower viscosity oil will always behave in a contrary manner to the higher viscosity and the mixture of the other two had an intermediate performance. This behavior has been attributed, for more viscous oils, to an increment in contact angle and thus diminution in the capillary number in response to the higher flow. Nevertheless in lower viscous oils, the flow rate does not alter significantly the contact angle and thus the capillary number increases with flow rate. These differences in the variation of the capillary number depending on the oil used may generate the differences on the results trends and explain the disagreement in the literature<br>Mestrado<br>Reservatórios e Gestão<br>Mestra em Ciências e Engenharia de Petróleo
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Souza, André Alves de. "Estudo de propriedades petrofísicas de rochas sedimentares por Ressonância Magnética Nuclear." Universidade de São Paulo, 2012. http://www.teses.usp.br/teses/disponiveis/88/88131/tde-26072012-161426/.
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A Ressonância Magnética Nuclear (RMN) é uma das técnicas mais versáteis de investigação científica experimental, com destaque para o estudo da dinâmica, estrutura e conformação de materiais. Em particular, sua utilização na ciência do petróleo é uma de suas primeiras aplicações rotineiras. Metodologias desenvolvidas especificamente para atender esta comunidade científica mostraram-se desde cedo muito úteis, sendo o estudo da interação rocha/fluido uma de suas vertentes mais bem sucedidas. Desde então, importantes propriedades petrofísicas de reservatórios de óleo e gás têm sido determinadas e entendidas, tanto em laboratório quanto in-situ, nas próprias formações geológicas que armazenam esses fluidos. Entre estas propriedades, a permeabilidade, porosidade e molhabilidade de um reservatório figuram dentre as mais importantes informações estimadas. Com essa finalidade, a determinação e correlação dos possíveis efeitos que a interação rocha/fluido pode causar nos fenômenos de relaxação magnética e difusão molecular, tais como influência da susceptibilidade magnética e geometria do espaço poroso, foram estudados em onze rochas sedimentares retiradas de afloramentos, que possuem propriedades petrofísicas similares àquelas apresentadas por rochas reservatório de petróleo. Os resultados mostraram que os tipos de interação rocha/fluido, detectáveis pelos experimentos de RMN, são por sua vez influenciados pelas características geométricas e estruturais do meio poroso, sendo possível obter essas informações pelos resultados de RMN. Assim, este trabalho teve como objetivo principal estudar e estabelecer essas correlações, afim de se obter informações petrofísicas com maior acurácia e abrangência. Em particular, o estudo da razão T1/T2, que é a razão entre os tempos de relaxação longitudinal e transversal, típicos parâmetros envolvidos numa medida de RMN, mostrou ser um parâmetro útil no estabelecimento destas correlações. Ainda, diferentes metodologias para se medir estes e outros parâmetros de RMN foram estudadas e propostas, cuja interpretação conjunta mostrou ser fundamental para o entendimento dessas correlações. A permeabilidade das rochas, importante parâmetro que define as propriedades de transporte de fluidos dentro da matriz porosa, foi estimada aplicando-se essas metodologias propostas, mostrando excelentes resultados. Através do uso da técnica de RMN em estado-estacionário, esses resultados podem ser estendidos para a escala de well-logging, fato que aumenta consideravelmente a importância desses resultados. Uma vez consolidadas as medidas in-situ, as metodologias propostas deverão auxiliar a indústria de exploração e produção de petróleo a otimizar seus métodos e estratégias de produção, reduzindo seus custos e aumentando a vida útil de seus reservatórios.<br>The Nuclear Magnetic Resonance (NMR) technique is one of the most versatile techniques for scientific research, specially for the study of dynamics, structure and conformational of materials. In particular, its application in oil science is one of its first routine applications. Methodologies developed specifically to match this scientific community proved to be very useful, and the study of rock/fluid interactions is one of its most successful cases. Since then, important petrophysical properties of oil and gas reservoirs have been determined and understood both in the laboratory and inside the geological formations that store those fluids. Among these properties, the permeability, porosity and wettability of a reservoir formation are the most important information to be estimated. For this purpose, the determination and correlation of possible rock/fluid interaction effects that cause alterations on magnetic relaxation phenomena and molecular diffusion, such as the influence of the magnetic susceptibility and geometry of the porous space, were studied in eleven sedimentary rock cores taken from outcrops, since they have the same petrophysical properties presented by oil reservoir rocks. The results obtained confirmed that the types of rock/fluid interactions, detectable by the NMR experiments, are for instance influenced by the porous media geometry and structure, being possible so to obtain such information using those NMR results. Thus, the main goal of this work was the study and establishment of these correlations, in order to obtain petrophysical information with greater accuracy and comprehensiveness. In particular, the study of the T1/T2 ratio, which is the ratio of longitudinal and transverse relaxation times, common parameters strongly involved in a typical NMR measurement, was found to be useful in establishing those correlations. Moreover, different methodologies to measure this and other NMR parameters were studied and proposed, whose joint interpretation proved to be fundamental for the success of these correlations. The permeability of the rocks, an important parameter that controls the fluid transport properties inside the porous matrix, was estimated using the proposed methodologies, showing excellent results. Appling the steady-state NMR technique, those results could be extended to the well-logging scale, which could improve considerably the importance of that results. Once confirmed in measurements in-situ, the proposed methodologies will be able to help the production and exploration industry to optimize their production methods and strategies, thereby reducing production costs and increasing the reservoir lifetimes.
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Meier, Silke [Verfasser], Sonja L. [Akademischer Betreuer] [Gutachter] Philipp, and Martin [Gutachter] Sauter. "Fault zones in potential geothermal reservoir rocks in the Upper Rhine Graben: Characteristics, permeability implications, and numerical stress field models / Silke Meier. Betreuer: Sonja L. Philipp. Gutachter: Sonja L. Philipp ; Martin Sauter." Göttingen : Niedersächsische Staats- und Universitätsbibliothek Göttingen, 2016. http://d-nb.info/1109046375/34.
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Boulton, Carolyn Jeanne. "Experimental Investigation of Gouges and Cataclasites, Alpine Fault, New Zealand." Thesis, University of Canterbury. Geological Sciences, 2013. http://hdl.handle.net/10092/8917.
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The upper 8-12 km of the Alpine Fault, South Island, New Zealand, accommodates relative Australia-Pacific plate boundary motion through coseismic slip accompanying large-magnitude earthquakes. Earthquakes occur due to frictional instabilities on faults, and their nucleation, propagation, and arrest is governed by tectonic forces and fault zone properties. A multi-disciplinary dataset is presented on the lithological, microstructural, mineralogical, geochemical, hydrological, and frictional properties of Alpine Fault rocks collected from natural fault exposures and from Deep Fault Drilling Project (DFDP-1) drillcore. Results quantify and describe the physical and chemical processes that affect seismicity and slip accommodation.
Oblique dextral motion on the central Alpine Fault in the last 5-8 Myr has exhumed garnet-oligoclase facies mylonitic fault rocks from depths of up to 35 km. During the last phase of exhumation, brittle deformation of these mylonites, accompanied by fluid infiltration, has resulted in complex mineralogical and lithological variations in the fault rocks. Petrophysical, geochemical, and lithological data reveal that the fault comprises a central alteration zone of protocataclasites, foliated and nonfoliated cataclasites, and fault gouges bounded by a damage zone containing fractured ultramylonites and mylonites. Mineralogical results suggest that at least two stages of chemical alteration have occurred. At, or near, the brittle-to-ductile transition (c. >320 °C), metasomatic alteration reactions resulted in plagioclase and feldspar replacement by muscovite and sausserite, and biotite (phlogopite), hornblende (actinolite) and/or epidote replacement by chlorite (clinochlore). At lower temperatures (c. >120°C), primary minerals were altered to kaolinite, smectite and pyrite, or kaolinite, smectite, Fe-hydroxide (goethite) and carbonate, depending on redox conditions. Ultramylonites, nonfoliated and foliated cataclasites, and gouges in the hanging wall and footwall contain the high-temperature phyllosilicates chlorite and white mica (muscovite/illite). Brown principal slip zone (PSZ) gouges contain the low-temperature phyllosilicates kaolinite and smecite, and goethite and carbonate cements.
The frictional and hydrological properties of saturated intact samples of central Alpine Fault surface-outcrop gouges and cataclasites were investigated in room temperature experiments conducted at 30-33 MPa effective normal stress (σn') using a double-direct shear configuration and controlled pore fluid pressure in a triaxial pressure vessel. Surface-outcrop samples from Gaunt Creek, location of DFDP-1, displayed, with increasing distance (up to 50 cm) from the contact with footwall fluvioglacial gravels: (1) an increase in fault normal permeability (k = 7.45 x 10⁻²⁰ m² to k = 1.15 x 10⁻¹⁶ m²), (2) a transition from frictionally weak (μ=0.44) fault gouge to frictionally strong (μ=0.50’0.55) cataclasite, (3) a change in friction rate dependence (a–b) from solely velocity strengthening to velocity strengthening and weakening, and (4) an increase in the rate of frictional healing. The frictional and hydrological properties of saturated intact samples of southern Alpine Fault surface-outcrop gouges were also investigated in room temperature double-direct shear experiments conducted at σn'= 6-31 MPa. Three complete cross-sections logged from outcrops of the southern Alpine Fault at Martyr River, McKenzie Creek, and Hokuri Creek show that dextral-normal slip is localized to a single 1-12 m-thick fault core comprising impermeable (k=10⁻²⁰ to 10⁻²² m²), frictionally weak (μ=0.12 – 0.37), velocity-strengthening, illite-chlorite and trioctahedral smectite (saponite)-chlorite-lizardite fault gouges. In low velocity room temperature experiments, Alpine Fault gouges tested have behaviours associated with aseismic creep.
In a triaxial compression apparatus, the frictional properties of PSZ gouge samples recovered from DFDP-1 drillcore at 90 and 128 m depths were tested at temperatures up to T=350°C and effective normal stresses up to σn'=156 MPa to constrain the fault's strength and stability under conditions representative of the seismogenic crust. The chlorite/white mica-bearing DFDP-1A blue gouge is frictionally strong (μ=0.61–0.76) across a range of experimental conditions (T=70–350°C, σn'=31.2–156 MPa) and undergoes a stability transition from velocity strengthening to velocity weakening as T increases past 210°C, σn'=31.2–156 MPa. The coefficient of friction of smecite-bearing DFDP-1B brown gouge increases from μ=0.49 to μ=0.74 with increasing temperature and pressure (T=70–210°C, σn'=31.2–93.6 MPa) and it undergoes a transition from velocity strengthening to velocity weakening as T increases past 140°C, σn'=62.4 MPa. In low velocity hydrothermal experiments, Alpine Fault gouges have behaviours associated with potentially unstable, seismic slip at temperatures ≥140°C, depending on mineralogy.
High-velocity (v=1 m/s), low normal stress (σn=1 MPa) friction experiments conducted on a rotary shear apparatus showed that the peak coefficient of friction (μp) of Alpine Fault cataclasites and fault gouges was consistently high (mean μp=0.69±0.06) in room-dry experiments. Variations in fault rock mineralogy and permeability were more apparent in experiments conducted with pore fluid, wherein the peak coefficient of friction of the cataclasites (mean μp=0.64±0.04) was higher than the fault gouges (mean μp=0.24±0.16). All fault rocks exhibited very low steady state coefficients of friction (μss) (room-dry mean μss=0.18±0.04; saturated mean μss=0.10±0.04). Three high-velocity experiments conducted on saturated smectite-bearing principal slip zone (PSZ) fault gouges had the lowest peak friction coefficients (μp=0.13-0.18), lowest steady state friction coefficients (μss=0.02-0.10), and lowest breakdown work values (WB=0.07-0.11 MJ/m²) of all the experiments performed.
Lower strength (μ < c. 0.62) velocity-strengthening fault rocks comprising a realistically heterogeneous fault plane represent barrier(s) to rupture propagation. A wide range of gouges and cataclasites exhibited very low steady state friction coefficients in high-velocity friction experiments. However, earthquake rupture nucleation in frictionally strong (μ ≥ c. 0.62), velocity-weakening material provides the acceleration necessary to overcome the low-velocity rupture propagation barrier(s) posed by velocity-strengthening gouges and cataclasites. Mohr-Coulomb theory stipulates that sufficient shear stress must be resolved on the Alpine Fault, or pore fluid pressure must be sufficiently high, for earthquakes to nucleate in strong, unstable fault materials. A three-dimensional stress analysis was conducted using the average orientation of the central and southern Alpine Fault, the experimentally determined coefficient of friction of velocity-weakening DFDP-1A blue gouge, and the seismologically determined stress tensor and stress shape ratio(s). Results reveal that for a coefficient of friction of μ ≥ c. 0.62, the Alpine Fault is unfavourably oriented to severely misoriented for frictional slip.
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Nguyen, Van hung. "Compaction des roches réservoirs peu ou non consolidées : Impacts sur les propriétés de transport." Thesis, Cergy-Pontoise, 2012. http://www.theses.fr/2012CERG0660.
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Au cours de la production d'hydrocarbures, l'extraction de fluides fait décroître la pression de pore dans les réservoirs (« depletion »). Ceci induit un changement du champ de contraintes qui résulte en une augmentation des contraintes effectives appliquées sur le réservoir. Les mesures in situ montrent que les variations de contraintes peuvent être décrites par un paramètre appelé chemin de chargement (stress path), défini comme le rapport entre la variation de contrainte effective horizontale et la variation de contrainte effective verticale par rapport aux conditions initiales dans le réservoir. La compaction induite par la production d'hydrocarbures peut avoir de graves conséquences dans le cas de roches faiblement consolidées car elle induit des variations des propriétés pétrophysiques des roches in situ, notamment de la perméabilité, un des paramètres les plus importants pour estimer la performance d'un réservoir mais aussi un des plus difficiles à mesurer. Pour compliquer encore les choses, la perméabilité est souvent anisotrope dans les réservoirs avec de forts contrastes entre la perméabilité horizontale kh et la perméabilité verticale kv.L'objectif de cette étude est de comprendre l'influence des chemins de chargement sur le comportement mécanique et les évolutions couplées de perméabilité pour un sable quartzeux (Sable de la Durance, DS) et un grès faiblement consolidé (grès d'Otter Sherwood, OSS, qui constitue la roche réservoir du champ pétrolier de Wytch Farm en Angleterre). Nos résultats montrent que le grès peu consolidé présente un comportement mécanique similaire à celui de roches consolidées. Au contraire, le sable présente un comportement différent, avec une transition plus graduelle entre les régimes de déformation qui nécessite d'utiliser un critère basé sur l'évolution du rayon de courbure des courbes contraintes-déformations pour déterminer les contraintes limites : cette méthode a été validée par une étude d'analyse des émissions acoustiques pour caractériser l'endommagement. Les domaines de déformation élastique et plastique ont été bien définis et les contraintes limites ont été comparées aux prédictions du modèle Cam-Clay modifié et du modèle d'enveloppe limite normalisée. Les perméabilités horizontale et verticale ont été mesurées sous contraintes. Pour analyser l'influence des effets de bord dans les essais mécaniques, les perméabilités mesurées soit classiquement sur toute la longueur de l'échantillon, soit entre deux points intermédiaires ont été comparées. Pour l'écoulement horizontal, les facteurs géométriques et facteurs d'anisotropie ont été déterminés par des simulations numériques en éléments finis afin de pouvoir déterminer les vraies valeurs de perméabilité horizontale. L'évolution de la perméabilité suit l'évolution de la déformation des matériaux et est contrôlée aussi bien par la déformation volumique que par la déformation en cisaillement. A partir de nos mesures il est possible de séparer l'effet de la pression moyenne de l'effet de la contrainte déviatorique sur l'évolution de la perméabilité en construisant des cartes d'isoperméabilités dans l'espace des contraintes. Enfin une modélisation élasto-plastique a été réalisée pour prédire le comportement hydro-mécanique du grès faiblement consolidé. L'approche utilisée permet de prédire de manière satisfaisante l'évolution de la perméabilité avec les contraintes, à partir d'une loi exponentielle fonction de la déformation effective. Au contraire, pour le sable de la Durance le lien entre l'évolution de la perméabilité et la déformation est loin d'être évidente, notamment aux faibles contraintes où la réduction de perméabilité est très rapide. Pour mieux comprendre ces évolutions de perméabilité, une analyse de l'endommagement a été réalisée par des mesures sur échantillons et en utilisant des techniques d'imagerie à plusieurs échelles<br>During hydrocarbon production, the extraction of fluid induces a decrease of pore pressure called depletion. This depletion causes a change in the stress field that results in an increased stress on the rock by enhancement of the effective stress in the reservoir. In situ measurements show that the stress variations can be described by the so-called stress path parameter, defined as the ratio of the change in effective horizontal stress by the change in effective overburden stress from initial reservoir conditions. This production induced compaction can have severe consequences in the case of poorly consolidated reservoirs. Compaction induces variations of petrophysical properties of in situ rocks and particularly permeability variations, one of the most important parameters controlling reservoir performance. Yet it is one of the most difficult property to measure. To complicate matters further, permeability anisotropy is often found in reservoirs. Therefore the horizontal permeability kh, may be different from the vertical permeability kv.The aim of this study is to understand the influence of stress paths on the mechanical behavior and coupled permeability evolutions of a Quartz sand (Durance Sand, DS) and a weakly consolidated sandstone (Otter Sherwood Sandtone, OSS which is the reservoir rock of the Wytch Farm oil field, UK). We found that the weakly consolidated rock presents a mechanical behavior similar to that of consolidated rocks. However, the sand shows a different behavior, with a gradual transition regime which requires the use of a curvature criterion to peak yield stresses on the stress-strain evolution plot; this criterion has been validated on the basis of Acoustic Emission analysis. The elastic and plastic deformation regimes are well identified and the determined yield stresses are fitted using the modified Cam-Clay and Elliptic Cap models for all observed onsets of plastic yielding. Both vertical and horizontal permeability have been measured during loading. To analyze the influence of end effects during loading in the triaxial cell, permeabilities measured over the mid-section and over the total core length were compared. For the horizontal flow, the geometrical and anisotropy factors were determined using Finite Element simulations in order to calculate the correct horizontal permeability. Permeability evolution follows closely the material deformation and is controlled by both volumetric and shear strains. It is possible to infer the effect of the mean pressure and/or the deviatoric stress on the permeability evolution by building isopermeability maps in the stress space. Finally, an application of elasto-plastic modeling to predict the hydromechanical behavior of the weakly consolidated rock is presented. This approach allows a satisfying prediction of the permeability evolution with stresses, using an exponential function of an effective strain. Reversely for DS, the link between strain and permeability is not obvious as permeability reduction is pronounced at early stage of loading. To understand these permeability evolutions, a damage analysis has been performed using core analysis measurements and multi-scale imaging
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Melani, Leandro Hartleben 1988. "Caracterização petrofísica de reservatório carbonático." [s.n.], 2015. http://repositorio.unicamp.br/jspui/handle/REPOSIP/265810.
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Orientador: Alexandre Campane Vidal<br>Dissertação (mestrado) - Universidade Estadual de Campinas, Faculdade de Engenharia Mecânic e Instituto de Geociências<br>Made available in DSpace on 2018-08-27T08:43:25Z (GMT). No. of bitstreams: 1
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Previous issue date: 2015<br>Resumo: A análise petrofísica é essencial para caracterização de reservatórios de hidrocarboneto, fornecendo parâmetros para avaliação do potencial econômico do campo. Este estudo foi realizado em um reservatório carbonático fraturado da Formação Quissamã, Bacia de Campos, composto predominantemente por calcarenitos e calcirruditos da Formação Quissamã, o qual foi denominado de Campo B. Este reservatório é essencialmente microporoso, com porosidade média a alta (15-30%) e, em geral, apresenta baixa permeabilidade de matriz (0,1-10 mD). As relações petrofísicas podem ser bastante complexas em reservatórios carbonáticos, em função da maior heterogeneidade na distribuição de fácies e porosidade nestas rochas. O grau de complexidade torna-se ainda mais elevado para o caso de reservatórios fraturados. Foi desenvolvido neste estudo um fluxo de trabalho para caracterização petrofísica da matriz deste reservatório carbonático, através da utilização de dados de perfis elétricos e de plugues. O objetivo do trabalho foi identificar possíveis comportamentos de fluxo distintos e definir regiões do campo com provável contribuição de fluxo intergranular. Para isto, é indispensável entender a relação entre os controles geológicos e o comportamento dinâmico do reservatório. A partir da análise das propriedades petrofísicas da matriz foram reconhecidas duas regiões do reservatório com comportamentos de fluxo distintos, diretamente influenciados pela heterogeneidade do sistema poroso. Na área sul foi constatado baixíssima permeabilidade de matriz, decorrente do amplo predomínio de microporosidade, que confere esta característica de fluxo às rochas. Na área norte foram observados os melhores índices de permeabilidade de matriz para o campo, associados à contribuição de fluxo intergranular, devido à preservação de porções significativas de macroporosidade original. As altas taxas de produtividade registradas nos dados de produção para poços da região sul indicam a presença de fraturas. O sistema de fraturas tem pequeno impacto sobre a porosidade total deste reservatório, porém tem grande contribuição para o regime de fluxo, desempenhando um importante papel na produção comercial do campo. Foi investigado também o impacto associado aos parâmetros de Archie - coeficientes de cimentação (m) e saturação (n) - no cálculo de saturação de água (Sw) para este reservatório carbonático fraturado. Para investigar este impacto foram gerados e comparados quatro cenários de Sw baseados em valores de m e n distintos. Foram realizadas três análises principais: (I) valores de Sw e espessura porosa com óleo (HPhiSo) foram comparados para cada cenário. Os resultados mostraram considerável variação nos valores obtidos para ambos os parâmetros (Sw - HPhiSo). (II) Análise baseada nos valores de corte e Net Pay. Foi observado que os valores de corte devem ser redefinidos de acordo com a variação da curva de saturação de água, para que seja mantida a mesma espessura de Net Pay em um dado reservatório. (III) Análise da influência dos valores de corte individual e global na variação de espessura de Net Pay foi avaliada para todos os poços para o cenário C2. Variações pequenas indicam que um valor de corte global é válido para este campo. Os resultados do estudo mostram que valores imprecisos dos parâmetros de Archie podem conduzir a erros na avaliação de reservas<br>Abstract: Petrophysical analysis plays a vital role in reservoirs characterization, providing parameters to assess the economic potential of the field. This study was performed in a fractured carbonate reservoir of Quissamã Formation, Campos Basin, mostly composed of calcarenites and calcirudites of Quissamã Formation, which it was named Field B. This reservoir is essentially microporous, characterized by medium to high porosity (15-25%) and, in general, low matrix permeability (0.1-10 mD). The petrophysical relationships can be considerably complex in carbonate reservoirs, due to the greater heterogeneity in facies and porosity distribution of these rocks. The complexity became even higher in particular case of fractured reservoirs. It was developed in this paper a general workflow for petrophysical characterization of this Albian carbonate reservoir, using well log data and plugs samples. The goals of this paper were to identify different flow behaviors and to define areas of the field with possible intergranular flow contribution. It is extremely important therefore to understand the relationship between the geological controls and the dynamic behavior of the reservoir. The petrophysical analysis of matrix properties enabled to recognize two reservoir zones with distinct flow behaviors, directly influenced by the porous system heterogeneity. In the southern area it was found very low matrix permeability, due to the large occurrence of microporosity. In the northern area it were found the best matrix permeability values of B Field, related to the contribution of intergranular flow due to the original macroporosity preservation. The high initial production rates obtained from production data of wells located in the southern portion indicate the presence of fractures. The fracture system has a small impact on the percentage of total reservoir porosity, but it has a large contribution to the flow domain, playing an important role in the commercial production of the field. It was also investigated the impact associated with Archie?s parameters - Cementation Factor (m) and Saturation Exponent (n) - in the determination of water saturation (Sw) in this fractured carbonate reservoir. To investigate this impact, four Sw scenarios were generated by applying different m and n values and compared with one another. Three main analyses were performed according to m and n variations: (I) the average values of Sw and Hydrocarbon Pore Volume Height (HPhiSo) were compared for each scenario. The results showed a considerable variation in the average values for both. (II) The second analysis was based on the cut-off and Net Pay values. The results showed that cut-off values must be changed according to the variation given by a water saturation curve, whatever the Sw scenario, in order to keep the same Net Pay values. (III) The differences between global and individual cut-offs on Net Pay thickness were analyzed for all wells for the scenario C2. Insignificant variations indicate that a global cut-off value is acceptable for this field. The results show that inaccurate values of Archie?s parameters can lead to gross errors in reserves evaluation<br>Mestrado<br>Reservatórios e Gestão<br>Mestre em Ciências e Engenharia de Petróleo
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Stormont, John Charles. "Gas permeability changes in rock salt during deformation." Diss., The University of Arizona, 1990. http://hdl.handle.net/10150/185159.
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A laboratory, field and numerical study of the changes in gas permeability which rock salt experiences during deformation is given. The laboratory tests involves gas permeability and porosity measurements coincident with hydrostatic and triaxial quasi-static, stress-rate controlled compression tests. The permeability and porosity of the as-received samples decrease significantly as a result of hydrostatic loading. These changes are largely irreversible, and are believed to "heal" or return the rock to a condition comparable to its undisturbed state. Deviatoric loading induces a dramatic change in pore structure. The permeability can increase more than 5 orders of magnitude over the initial (healed) state as the samples are loaded. The gas permeability changes are consistent with flow paths initially developing along the grain boundaries and then along axial secondary tensile cracks. The results from two sets of in situ gas permeability measurements from the underground workings of the WIPP Facility are given. The results consistently indicate that there is no measurable gas permeability prior to disturbing the rock by excavation. In the immediate vicinity of an excavation, the gas permeability can be 5 orders of magnitude greater than the undisturbed permeability. A numerical procedure to predict the in situ permeability is developed based on the results of the laboratory tests. The stress and strain fields surrounding excavations in rock salt, predicted with an elastoplastic model, are used in a model of gas permeability based on the equivalent channel model. The zone of the gas permeable rock is predicted well, but the magnitude of the gas permeability is underpredicted very near excavations. The gas permeability which develops in situ is principally a result of flow along dilated grain boundaries.
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Ben, Ohoud Mohsine. "Etude comparative de l'organisation des materiaux argileux en termes de dimensions fractales." Orléans, 1988. http://www.theses.fr/1988ORLE2002.
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Caracterisation structurale et texturale des materiaux argileux selon une nouvelle approche reposant sur l'idee que l'organisation des elements de la texture a une echelle donnee se retrouve adaptes a chaque echelle. Formalisation de cette approche dans le cadre de la theorie des fractals. On montre aue kaolinite, argiles fibreuses et illite relevent d'une description triviale, basee sur un assemblage tridimensionnel desordonne, alors que les montmorillonites sont des materiaux a texture fractale. On analyse les correlations entre dimensions fractales de surface et de porosite des montmorillonitesm deshydratees et les proprietes des suspensions (permeabilite, retention en eaum rheologie)
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Jim, Nilsson. "Fracture characterization in magmatic rock, a case study of the Sosa-dyke (Neuquén Basin, Argentina)." Thesis, Uppsala universitet, Institutionen för geovetenskaper, 2020. http://urn.kb.se/resolve?urn=urn:nbn:se:uu:diva-411548.
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There are many examples worldwide were fossil magmatic intrusions influence the local water and energy supply. Due to that intrusions can act as a conductor and a reservoir, but also as a barrier for fluids and gases in the ground. The decisive feature between conductor or barrier in an intrusion is its fracture network. Hence it is of paramount importance to characterize an intrusion’s fracture network and thus its permeability. However, other than through boreholes magmatic intrusions are rather inaccessible and very little is known about their influence on aquifers and reservoir rocks in the underground. It is therefore important to increase the knowledge of magmatic intrusion by investigate the intrusions that are accessible for us at ground surface. In this study, photos from a case study about the Sosa dyke have been used to map and characterizes the fractures of the Sosa dyke, which is an accessible vertical magmatic intrusion and a part of the Chachahuén volcano complex in the southwestern parts of Argentina. The photos that were used are taken with an UAV (unmanned aerial vehicle), and to analyze the photos, map the fractures and produce the results, software as Agisoft Metashape, MOVE™ and MATLAB with the toolbox FracPaQ was used. The intrusion has two distinct fracture sets, one that is perpendicular to the intrusion margins and one that stretches parallel with the intrusion. The connectivity of the fractures is low, and since the permeability of the fractures largely depends on the connectivity, it is also low. The fracture set that is perpendicular to the intrusion margin is what’s called cooling fractures, which is created as the magma in the intrusion cools. This causes the magma to contract and break, forming fractures perpendicular to the inward migrating solidification front. The fracture set that is parallel with the intrusion is caused by minerals in the magma flow being affected by friction from the intrusion margins. This causes the minerals in the magma to elongate in the direction of flow along the sides of the dyke, creating foliation, enabling fractures to propagate along. These fracture sets are poorly connected which concludes that the mapped area of the Sosa-dyke has a low permeability.<br>I hela världen finns det många exempel där stelnade magmatiska intrusioner påverka ett områdes vatten och energiförsörjning, på grund av att intrusioner kan agera som ledare och reservoarer men också som barriärer för vätskor och gaser in marken. Den avgörande faktorn mellan ledare och barriärer i en intrusion är dess spricknätverk. Därför är det viktigt att kartlägga och karakterisera en intrusions spricknätverk och därmed också få en uppfattning om dess permeabilitet. Magmatiska intrusioner är förutom genom borrhål ofta svåråtkomliga, det finns därför väldigt lite information om hur de påverkar akviferer och reservoarer i marken. Det är därför viktigt att öka kunskapen om magmatiska intrusioner genom att undersöka intrusionerna som är tillgängliga vid markytan. I denna studie har bilder från en fallstudie om Sosa Intrusionen använts för att kartera och karakterisera sprickor i Sosa intrusionen. Det är en vertikal magmatisk intrusion som är synlig på markytan, och en del av Chachahuén vulkan komplexet i sydvästra Argentina. Bilderna som användes är tagna med en UAV( unmanned aerial vehicle), och för att analysera bilderna, kartera sprickorna och producera resultaten, användes programmen Agisoft Metashape, MOVE™ och MATLAB med FracPaQ verktyget. Intrusionen har två distinkta sprickgrupper, en som är vinkelrät mot intrusionens kanter och en som går parallellt med kanterna. Konnektivitet mellan sprickorna är låg och eftersom permeabiliteten påverkas av konnektiviteten är den också låg. Sprickgruppen som är vinkelrätt mot intrusionskanten är så kallade kylningssprickor och bildas nät magman i intrusionen svalnar. Det leder till att magman kontraherar och spricker, och bildar sprickor som går inåt mot stelningsgränsen och därmed vinkelrätt mot intrusionskanten. Sprickgruppen som går parallellt med intrusionen bildas av att mineral i magmaströmmen påverkas av friktion från intrusionskanterna. Det gör att mineralen lägger sig och sträcks ut i samma riktning som magmaflödet, vilket när magman stelnar bildar svaghetszoner som sprickor kan fortplanta sig i. Dessa sprickgrupper har låg konnektivitet vilket gör att slutsatsen blir att det karterade området av Sosa intrusionen har låg permeabilitet.
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Hsia, Tain-Yen. "Perforation cleanup as a function of rock permeability and underbalance." Thesis, Massachusetts Institute of Technology, 1991. http://hdl.handle.net/1721.1/110873.
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Hosa, Aleksandra Maria. "Modelling porosity and permeability in early cemented carbonates." Thesis, University of Edinburgh, 2016. http://hdl.handle.net/1842/16181.
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Cabonate-hosted hydrocarbon reservoirs will play an increasingly important role in the energy supply, as 60% of the world's remaining hydrocarbon resources are trapped within carbonate rocks. The properties of carbonates are controlled by deposition and diagenesis, which includes calcite cementation that begins immediately after deposition and may have a strong impact on subsequent diagenetic pathways. This thesis aims to understand the impact of early calcite cementation on reservoir properties through object-based modelling and Lattice Boltzmann ow simulation to obtain permeability. A Bayesian inference framework is also developed to quantify the ability of Lattice Boltzmann method to predict the permeability of porous media. Modelling focuses on the impact of carbonate grain type on properties of early cemented grainstones and on the examination of the theoretical changes to the morphology of the pore space. For that purpose process-based models of early cementation are developed in both 2D (Calcite2D) and 3D (Calcite3D, which also includes modelling of deposition). Both models assume the existence of two grain types: polycrystalline and monocrystalline, and two early calcite cement types specific to these grain types: isopachous and syntaxial, respectively. Of the many possible crystal forms that syntaxial cement can take, this thesis focuses on two common rhombohedral forms: a blocky form 01¯12 and an elongated form 40¯41. The results of the 2D and 3D modelling demonstrate the effect of competition of growing grains for the available pore space: the more monocrystalline grains present in the sample, the stronger this competition becomes and the lesser the impact of each individual grain on the resulting early calcite cement volume and porosity. The synthetic samples with syntaxial cements grown of the more elongated crystal form 40¯41 have lower porosity for the same monocrystalline grains content than synthetic samples grown following more blocky crystal form 01¯12. Moreover, permeability at a constant porosity is reduced for synthetic samples with the form 40¯41. Additionally, synthetic samples with form 40¯41 exhibit greater variability in the results as this rhombohedral form is more elongated and has the potential for producing a greater volume of cement. The results of the 2D study suggest that for samples at constant porosity the higher the proportion of monocrystalline grains are in the sample, the higher the permeability. The 3D study suggests that for samples with crystal form 01¯12 at constant porosity the permeability becomes lower as the proportion of monocrystalline grains increase, but this impact is relatively minor. In the case of samples with crystal form 40¯41 the results are inconclusive. This dependence of permeability on monocrystalline grains is weaker than in the 2D study, which is most probably a result of the bias of flow simulation in the 2D as well as of the treatment of the porous medium before the cement growth model is applied. The range of the permeability results in the 2D modelling may be artificially overly wide, which could lead to the dependence of permeability on sediment type being exaggerated. Poroperm results of the 2D modelling (10-8000mD) are in reasonable agreement with the data reported for grainstones in literature (0.1-5000mD) as well as for the plug data of the samples used in modelling (porosity 22 - 27%, permeability 200 - 3000mD), however permeability results at any given porosity have a wide range due to the bias inherent to the 2D flow modelling. Poroperm results in the 3D modelling (10 - 30, 000mD) exhibit permeabilities above the range of that reported in the literature or the plug data, but the reason for that is that the initial synthetic sediment deposit has very high permeability (58, 900mD). However, the trend in poroperm closely resembles those reported in carbonate rocks. As the modelling depends heavily on the use of Lattice Boltzmann method (flow simulation to obtain permeability results), a Bayesian inference framework is presented to quantify the predictive power of Lattice Boltzmann models. This calibration methodology is presented on the example of Fontainebleau sandstone. The framework enables a systematic parameter estimation of Lattice Boltzmann model parameters (in the scope of this work, the relaxation parameter τ ), for the currently used calibrations of Lattice Boltzmann based on Hagen-Poiseuille law. Our prediction of permeability using the Hagen-Poiseuille calibration suggests that this method for calibration is not optimal and in fact leads to substantial discrepancies with experimental measurements, especially for highly porous complex media such as carbonates. We proceed to recalibrate the Lattice Boltzmann model using permeability data from porous media, which results in a substantially different value of the optimal τ parameter than those used previously (0.654 here compared to 0.9). We augment our model introducing porosity-dependence, where we find that the optimal value for τ decreases for samples of higher porosity. In this new semi-empirical model one first identifies the porosity of the given medium, and on that basis chooses an appropriate Lattice Boltzmann relaxation parameter. These two approaches result in permeability predictions much closer to the experimental permeability data, with the porosity-dependent case being the better of the two. Validation of this calibration method with independent samples of the same rock type yields permeability predictions that fall close to the experimental data, and again the porosity-dependent model provides better results. We thus conclude that our calibration model is a powerful tool for accurate prediction of complex porous media permeability.
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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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Ogata, Sho. "Development of Coupled Thermal-Hydraulic-Mechanical-Chemical Models for Predicting Rock Permeability Change." Doctoral thesis, Kyoto University, 2019. http://hdl.handle.net/2433/244532.
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京都大学<br>0048<br>新制・課程博士<br>博士(工学)<br>甲第22051号<br>工博第4632号<br>新制||工||1722(附属図書館)<br>京都大学大学院工学研究科都市社会工学専攻<br>(主査)教授 岸田 潔, 教授 木村 亮, 教授 小池 克明<br>学位規則第4条第1項該当<br>Doctor of Philosophy (Engineering)<br>Kyoto University<br>DFAM
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Carnaffan, Paul Carleton University Dissertation Engineering Civil and Environmental. "An experimental technique for determining the permeability of rock, concrete and cement grout." Ottawa, 1994.
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Hart, Megan Leanore. "Membrane properties of intact rock cores of Burlington Limestone, Jefferson Dolomite, Darrington Phyllite, and low permeability concrete." Diss., Rolla, Mo. : Missouri University of Science and Technology, 2009. http://scholarsmine.mst.edu/thesis/pdf/Hart_09007dcc80699aec.pdf.
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Thesis (Ph. D.)--Missouri University of Science and Technology, 2009.<br>Vita. The entire thesis text is included in file. Title from title screen of thesis/dissertation PDF file (viewed August 21, 2009) Includes bibliographical references.
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Hwang, Bohyun. "Water-Rock Interaction in the Coso Geothermal System." The Ohio State University, 2014. http://rave.ohiolink.edu/etdc/view?acc_num=osu1417724456.
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