Orientador: Alexandre Campane Vidal / Dissertação (mestrado) - Universidade Estadual de Campinas, Faculdade de Engenharia Mecanica e Instituto de Geociencias / Made available in DSpace on 2018-08-12T08:28:49Z (GMT). No. of bitstreams: 1 Lima_LuizMauricioSilvade_M.pdf: 4795138 bytes, checksum: 429f15da9df616f78f3feee5b40ebb38 (MD5) Previous issue date: 2007 / Resumo: A caracterização de reservatórios e de fundamental importância para a implantação de uma estratégia de produção de um campo petrolífero. Os modelos geológicos permitem o entendimento da gênese do reservatório em estudo com a possibilidade de realizar uma distribuição espacial e qualitativa das principais heterogeneidades. Esta analise envolve quantidade enorme de variáveis devido à complexidade do problema gerando um grande numero de cenários prováveis. Para o modelo geológico da área, fundamentada na analise de dez perfis elétricos e radioativos, foi possível a determinação de intercalações de camadas, definição das fácies e a definição da porosidade e permeabilidade dos arenitos. Devido a presença de pacotes mais espessos e contínuos de arenitos na direção SW-NE, portanto com maior razão areia/folhelho, infere-se esta como a direção preferencial de aporte dos sedimentos. A analise geoestatistica foi realizada para as principais variáveis referentes à caracterização de reservatórios. Esta analise definiu a direção SW-NE como a direção preferencial de aporte dos sedimentos e forneceu uma estimativa de volume de óleo in cento. Devido a elevada incerteza na estimativa desse volume, foi realizada a simulação estocástica levando em consideração as variáveis topo e base do reservatório, distribuição de arenitos e porosidade. Os resultados da simulação estocástica demonstram a variação dos volumes de óleo in situ. / Abstract: The reservoir characterization model is of fundamental importance for the planning of a strategy production petroleum field. The geological models allow the understanding of the reservoir's spacial and qualitative distribution of its principal heterogeneity. This analysis involves enormous amount of variables due to the complexity of the problem, which generates a great number of probable scenarios. For the geological model of the area the interpretation is based on the analysis of ten electrical and radioactive logs, with which it is possible to determine the intercalations layers and the definition of the porosity and permeability of the sandstones. The presence of thicker and continuous packages of sandstones in the NE-SW direction, with its high net to gross ratio, is probable due to the existence of a preferential direction of the sediment sources. The geostatistical analysis was carried out for the principle variables regarding the characterization of the reservoir. This analysis defined the direction SW-NE as the preferential direction of the sediments sources and in situ oil volume estimate. Due to the raised uncertainty in the estimate of this volume, a stochastical was carried out with the consideration of; top and base variables of the reservoir, distribution of sandstones and porosity. The results of the stocastical simulations show the variation of the volume in situ of oil. / Mestrado / Reservatórios e Gestão / Mestre em Ciências e Engenharia de Petróleo

“History matching” (model calibration, parameter identification) is an established method for determination of representative reservoir properties such as permeability, porosity, relative permeability and fault transmissibility from a measured production history; however the uniqueness of selected model is always a challenge in a successful history matching. Up to now, the uniqueness of history matching results in practice can be assessed only after individual and technical experience and/or by repeating history matching with different reservoir models (different sets of parameters as the starting guess). The present study has been used the stochastical theory of Kullback & Leibler (K-L) and its further development by Akaike (AIC) for the first time to solve the uniqueness problem in reservoir engineering. In addition - based on the AIC principle and the principle of parsimony - a penalty term for OF has been empirically formulated regarding geoscientific and technical considerations. Finally a new formulation (Penalized Objective Function, POF) has been developed for model selection in reservoir history matching and has been tested successfully in a North German gas field. / „History Matching“ (Modell-Kalibrierung, Parameter Identifikation) ist eine bewährte Methode zur Bestimmung repräsentativer Reservoireigenschaften, wie Permeabilität, Porosität, relative Permeabilitätsfunktionen und Störungs-Transmissibilitäten aus einer gemessenen Produktionsgeschichte (history). Bis heute kann die Eindeutigkeit der identifizierten Parameter in der Praxis nicht konstruktiv nachgewiesen werden. Die Resultate eines History-Match können nur nach individueller Erfahrung und/oder durch vielmalige History-Match-Versuche mit verschiedenen Reservoirmodellen (verschiedenen Parametersätzen als Startposition) auf ihre Eindeutigkeit bewertet werden. Die vorliegende Studie hat die im Reservoir Engineering erstmals eingesetzte stochastische Theorie von Kullback & Leibler (K-L) und ihre Weiterentwicklung nach Akaike (AIC) als Basis für die Bewertung des Eindeutigkeitsproblems genutzt. Schließlich wurde das AIC-Prinzip als empirischer Strafterm aus geowissenschaftlichen und technischen Überlegungen formuliert. Der neu formulierte Strafterm (Penalized Objective Function, POF) wurde für das History Matching eines norddeutschen Erdgasfeldes erfolgreich getestet.

[pt] Na área de exploração e produção de petróleo são alocados grandes investimentos para conseguir diminuir os riscos associados à baixos níveis de produção, que podem ser minimizados mediante a acertada caracterização do reservatório de petróleo. Uma valiosa fonte de informação pode ser extraída de dados sísmicos 3D, obtidos do campo em estudo. O custo econômico de aquisição de esta base de dados para o reservatório completo é relativamente baixo, se comparado com uma amostragem direta por meio de perfurações de poços. Embora, a relação entre os dados sísmicos e as propriedades de reservatório seja considerada ambígua, esta deve ser integrada com informação confiável, como aquela obtida mediante perfilagem de poços. Fazendo uso dos abundantes dados sísmicos e das escassas, mas, precisas medições em perfurações existentes, foi desenvolvido neste trabalho um sistema baseado no algoritmo de Programação Genética (PG) para caracterizar geologicamente um reservatório de petróleo. PG é uma técnica de computação evolucionária capaz de estimar relações não lineares entre um conjunto de entrada e de saída, mediante uma expressão simbólica explícita. Para extrair informação adicional nos registros sísmicos são calculados atributos sísmicos, que facilitam a identificação de características estratigráficas ou estruturais do subsolo representadas indiretamente pela sísmica. Adicionalmente, é utilizado o método de inversão sísmica para o cálculo da impedância acústica, que é uma variável auxiliar derivada de sísmica calibrada com perfis de poço. Os atributos sísmicos junto com a impedância acústica servirão para a estimação de propriedades geológicas. Esta metodologia de trabalho foi testada em um reservatório real de grande complexidade geológica. Por meio de PG, foi representada satisfatoriamente a relação entre dados derivados da sísmica e a porosidade do campo, demostrando assim que PG é uma alternativa viável para a caracterização geológica de reservatórios. Posteriormente, foi realizada uma clusterização do campo baseada em características geofísicas que permitiram a construção de estimadores por PG especializados para cada zona. / [en] In the field of oil exploration and production a great deal of investment is allocated in reducing the risks associated to low production levels that can be minimized through an accurate oil reservoir characterization. A valuable source of information can be extracted from 3D seismic data, obtained from the studied reservoir. The economic cost of the acquisition of this data base for the whole reservoir is relatively low, if compared to the direct sampling method of well drilling. Being that the relationship between seismic data and reservoir properties is considered ambiguous, it must be integrated with reliable information, such as that obtained by well logging. Making use of abundant seismic data and scarce, yet accurate, measurements from the existing drillings, it was developed in this study a system based in the algorithm of Genetic Programming (GP), to geologically characterize an oil reservoir. GP is an evolutionary computational technique capable of estimating the non-linear relationships between input and output parameter, through an explicit symbolic expression. In order to extract additional information from seismic records, seismic attributes are calculated, which facilitate tasks of identifying stratigraphic and structural characteristics of the subsurface, represented indirectly by seismic data. Moreover, a seismic inversion method is used to estimate the acoustic impedance, an auxiliary variable derived from seismic data calibrated by well logs. The seismic attributes along with the acoustic impedance will be used to estimate geological properties. This workflow was tested on a real reservoir, thus presenting geological complexity. Through GP, the relationship between seismic derived data and the field porosity was represented satisfactorily, demonstrating that GP is a viable alternative for geologic reservoir characterization. Afterwards, the reservoir was divided in clusters according to geophysical properties, this allowed the construction of GP based estimators for each zone.

[pt] Simulação de reservatórios de óleo e gás é uma demanda comum em engenharia de petróleo e pesquisas relacionadas, que pode requerer um elevado custo computacional de tempo e processamento ao resolver um problema matemático. Além disso, alguns métodos de caracterização de reservatórios necessitam múltiplas iterações, resultando em muitas simulações para obter um resultado. Também podemos citar os métodos baseados em conjunto, tais como o ensemble Kalman filter, o EnKF, e o Ensemble Smoother With Multiple Data Assimilation,o ES-MDA, que requerem muitas simulações. Em contrapartida, o uso de aprendizado de máquina cresceu bastante na indústria de energia. Isto pode melhorar a acurácia de predição, otimizar estratégias e outros. Visando reduzir as complexidades de simulação de reservatórios, este trabalho investiga o uso de aprendizado de máquina como uma alternativa a simuladores convencionais. O modelo Random Forest Regressor é testado para reproduzir respostas de pressão em um reservatório multi-região radial composto. Uma solução analítica é utilizada para gerar o conjunto de treino e teste para o modelo. A partir de experimentação e análise, este trabalho tem o objetivo de suplementar a utilização de aprendizado de máquina na indústria de energia. / [en] Oil and gas reservoir simulation is a common demand in petroleum engineering, and research, which may have a high computational cost, solving a mathematical numeric problem, or high computational time. Moreover, several reservoir characterization methods require multiple iterations, resulting in many simulations to obtain a reasonable characterization. It is also possible to mention ensemble-based methods, such as the ensemble Kalman filter, EnKF, and the Ensemble Smoother With Multiple Data Assimilation, ES-MDA, which demand lots of simulation runs to provide the output result. As a result, reservoir simulation might be a complex subject to deal with when working with reservoir characterization. The use of machine learning has been increasing in the energy industry. It can improve the accuracy of reservoir predictions, optimize production strategies, and many other applications. The complexity and uncertainty of reservoir models pose significant challenges to traditional modeling approaches, making machine learning an attractive solution. Aiming to reduce reservoir simulation’s complexities, this work investigates using a machine-learning model as an alternative to conventional simulators. The Random Forest regressor model is experimented with to reproduce pressure response solutions for multi-region radial composite reservoirs. An analytical approach is employed to create the training dataset in the following procedure: the permeability is sorted using a specific distribution, and the output is generated using the analytical solution. Through experimentation and analysis, this work aims to advance our understanding of using machine learning in reservoir simulation for the energy industry.

[pt] O ensemble smoother with multiple data assimilation (ES-MDA) se tornou um poderoso estimador de parâmetros. A principal ideia do ES-MDA é assimilar os mesmos dados com a matriz de covariância dos erros dos dados inflada. Na implementação original do ES-MDA, os fatores de inflação e o número de assimilações são escolhidos a priori. O único requisito é que a soma dos inversos de tais fatores seja igual a um. Naturalmente, escolhendo-os iguais ao número de assimilações cumpre este requerimento. Contudo, estudos recentes mostraram uma relação entre a equação de atualização do ES-MDA com a solução para o problema inverso regularizado. Consequentemente, tais elementos agem como os parâmetros de regularização em cada assimilação. Assim, estudos propuseram técnicas para gerar tais fatores baseadas no princípio da discrepância. Embora estes estudos tenham propostos técnicas, um procedimento ótimo para gerar os fatores de inflação continua um problema em aberto. Mais ainda, tais estudos divergem em qual método de regularização é sufiente para produzir os melhores resultados para o ES-MDA. Portanto, nesta tese é abordado o problema de gerar os fatores de inflação para o ESMDA e suas influências na performance do método. Apresentamos uma análise numérica do impacto de tais fatores nos parâmetros principais do ES-MDA: o tamanho do conjunto, o número de assimilações e o vetor de atualização dos parâmetros. Com a conclusão desta análise, nós propomos uma nova técnica para gerar os fatores de inflação para o ES-MDA baseada em um método de regularização para algorítmos do tipo Levenberg-Marquardt. Investigando os resultados de um problema de inundação de um reservatório 2D, o novo método obtém melhor estimativa tanto para os parâmetros do modelo tanto quanto para os dados observados. / [en] The ensemble smoother with multiple data assimilation (ES-MDA) gained much attention as a powerful parameter estimation method. The main idea of the ES-MDA is to assimilate the same data multiple times with an inflated data error covariance matrix. In the original ES-MDA implementation, these inflation factors, such as the number of assimilations, are selected a priori. The only requirement is that the sum of the inflation factors inverses must be equal to one. Therefore, selecting them equal to the number of assimilations is a straightforward choice. Nevertheless, recent studies have shown a relationship between the ES-MDA update equation and the solution to a regularized inverse problem. Hence, the inflation factors play the role of the regularization parameter at each ES-MDA assimilation step. As a result, they have also suggested new procedures to generate these elements based on the discrepancy principle. Although several studies proposed efficient techniques to generate the ES-MDA inflation factors, an optimal procedure to generate them remains an open problem. Moreover, the studies diverge on which regularization scheme is sufficient to provide the best ES-MDA outcomes. Therefore, in this work, we address the problem of generating the ES-MDA inflation factors and their influence on the method s performance. We present a numerical analysis of the influence of such factors on the main parameters of the ES-MDA, such as the ensemble size, the number of assimilations, and the ES-MDA vector of model parameters update. With the conclusions presented in the aforementioned analysis, we propose a new procedure to generate ES-MDA inflation factors based on a regularizing scheme for Levenberg-Marquardt algorithms. It is shown through a synthetic two-dimensional waterflooding problem that the new method achieves better model parameters and data match compared to the other ES-MDA implementations available in the literature.

Geologic sequestration of anthropogenic carbon dioxide (CO2) greenhouse gas emissions is an engineering solution that potentially reduces CO2 emissions released into the atmosphere thereby limiting their effect on climate change. This study focuses on Woodside field as a potential storage and sequestration site for CO2 emissions. The Woodside field is positioned on a doubly plunging, asymmetrical anticline on the northeast flank of the San Rafael Swell. Particular focus will be placed on the Permian White Rim Sandstone, Black Box Dolomite and Black Dragon Member of the Triassic Moenkopi Formation as the reservoir/seal system to store and sequester CO2 at Woodside field. The White Rim Sandstone, the primary target reservoir, is divided into three stratigraphic intervals based on facies analysis: a lower sand sheet facies (about 60 ft or 18 m), a thick middle eolian sandstone facies (about 390 ft or 119 m), and an upper marine reworked facies (about 70 ft or 21 m). Porosity and permeability analyses from the outcrop indicate good reservoir quality in the eolian sandstone and reworked facies. Porosity in the White Rim Sandstone ranges from 7.6 to 24.1% and permeability reaches up to 2.1 D. The maximum combined thickness of the three facies is 525 ft (160 m) at Woodside field providing a significant volume of porous and permeable rock in which to store CO2. The Black Box Dolomite is the secondary potential reservoir for CO2 storage at Woodside field and has a gross thickness up to 76 ft (23 m). The Black Box Dolomite is divided into four lithofacies: a basal nodular dolomudstone (8.2 -15 ft or 3.5-4.5 m), a dolowackestone (25-37 ft or 7.5-11 m), a dolomitic sandstone (0-8.2 ft or 0-2.5 m), and an upper sandy dolowackestone (0-16 ft or 0-4.9 m). Porosity and permeability analyses indicate reservoir potential in the dolowackestone, dolomitic sandstone, and sandy dolowackestone lithofacies. Porosity in the Black Box Dolomite ranges from 6.6 to 29.2% and permeability reaches up to 358 mD. The nodular dolomudstone lithofacies has relatively poor reservoir quality with porosity up to 9.4% and permeability up to 0.182 mD. This lithofacies could act as a baffle or barrier to fluid communication between the White Rim Sandstone and Black Box Dolomite. The Black Dragon Member of the Triassic Moenkopi Formation will serve as the seal rock for the relatively buoyant CO2 stored in the underlying formations. The Black Dragon Member is comprised of four lithofacies: a chert pebble conglomerate; an interbedded sandstone, siltstone, and shale; a trough cross-stratified sandstone, and an oolitic and algal limestone. The Black Dragon Member has a maximum thickness of 280 ft (85 m) at Woodside field. Mudstone beds contain from 0.16 to 0.47% porosity. QEMSCAN analysis indicates several minerals within shale beds that may react with a CO2-rich brine including calcite (18.73 to 23.43%), dolomite (7.56 to 7.89%), alkali feldspar (4.12 to 4.43 %), glauconite (0.04 to 0.05%), and plagioclase (0.03 to 0.04%). Silty mudstones comprise 75% of this member at Black Dragon Canyon. Volumetric estimates for Woodside field were calculated based on the 10th, 50th, and 90th percent probabilities (P10, P50, and P90). The White Rim Sandstone is the primary target reservoir and has capacity to hold 2.2, 8.8, or 23.7 million metric tonnes (P10, P50, and P90 respectively) of CO2 within the structural closure of Woodside field. The Black Box Dolomite may hold 0.5, 1.8, or 4.5 million metric tonnes, respectively of additional CO2 within the structural closure of Woodside field. These two formations combined have the capacity to store up to 28.3 million metric tonnes (P90) of CO2.

Sur l’île de Majorque (Espagne), l’exploitation en continue de la nappe aquifère a favoriséla formation d’un biseau salé et l’épuisement de la ressource en eau potable. En 2002, un projet nommé ALIANCE, financé par l’Union européenne, a été lancé pour permettre une meilleure caractérisation des réservoirs. L’objectif est de concevoir un plan de gestion durable des ressources en eau dans les zones côtières aquifères sujets aux problèmes d’intrusion d’eau salée. Dans cet optique, un site expérimental près de la ville de Campos (Majorque) a été créé, avec la mise en place de plusieurs puits au sein d’un milieu karstique carbonaté. Des études pétrophysiques sur des échantillons ont été réalisées ainsi que différentes prospections géophysiques dans la zone saturée (tomographie puits à puits). Ce type d’études est utile pour déterminer certaines propriétés réservoirs telles que la porosité, mais sont limitées à la zone saturée au voisinage des puits. Ainsi, une étude sismique 3D haute résolution a été réalisée pour localiser les principaux réflecteurs, leurs répartitions sur la zone et imager les hétérogénéités du réservoir dans la zone non saturée. L’acquisition et le traitement de données sismiques lors de prospection de subsurface est une tâche difficile en raison de plusieurs facteurs, notamment logistique et technique. Cependant, cette acquisition 3D haute résolution a été optimisée pour imager une structure peu profonde, à savoir une centaine de mètres. Différentes stratégies de traitement de données ont été appliquées pour éliminer de manière efficace le bruit sur les données, et une technique de calcul de correction statique, basée sur l’inversion des temps de premières arrivées, a été mise au point. Différents attributs sismiques ont été extraits et utilisés pour la caratérisation du réservoir. La propagation des ondes sismiques est limitée par la nature des roches carbonatées et la création d’ondes de Rayleigh. Un obstacle majeur rencontré lors du traitement des données sismiques a été la présence d’ondes de Rayleigh de fortes amplitudes, d’une part due à l’utilisation d’une source en surface et d’autre part en raison des hétérogénéités de petite tailles. Un "mute" de ces ondes de surface a été réalisé avant d’imager la structure profonde. De multiples problèmes d’interférences sont également dus aux nombreuses hétérogénéités, à l’atténuation rapide du contenu hautes-fréquences des signaux et au contraste d’impédance avec les couches sous-jacentes. L’interprétation finale nous amène à observer que le réflecteur principal est très irrégulier sur une zone d’étude de petite taille à l’échelle d’un réservoir. L’analyse de différents attributs sismiques révèle clairement des structures et hétérogénéités typiques des systèmes karstiques. / Continuous water extraction and intrusion of salt water in the coastal aquifer of the islandof Mallorca (Spain) is depleting the fresh water aquifers. In 2002 a project named ALIANCE,funded by European Union, was initiated for better reservoir characterization and to devisethe sustainable management plan of the water resources in coastal aquifers suffering from salt water intrusion. For this purpose an experimental site near the Campos town on the island of Mallorca (Spain) was developed. Several wells on the site were drilled and cored. Extensive studies are carried out to characterize the reservoir by studying the well cores. Different geophysical tomographic studies are also carried out for these drilled wells in the saturated zone. Laboratory study of cores, petrophysical studies and several tomographic studies were helpful to construct the reservoir porosity system and other reservoir properties. But these all studies are restricted to saturated zone and in the vicinity of the wells. High resolution 3D seismic survey is carried out on this site to locate the different characteristic reflectors, their spatial presence over the area and reservoir heterogeneity in the unsaturated zone. Seismic data acquisition and processing for the shallow surveys is a difficult task due to number of factors including logistic and technical. Nonetheless high resolution 3D seismic survey is acquired with optimized parameters to image the required zone. Different data processing strategies are applied to get a noise free high resolution image. A technique for static correction calculation based on the delay time inversion is developed.Energy penetration in the subsurface was hampered due to carbonate rock nature and forced generation of Rayleigh waves. The processing of the seismic data was difficult due to overwhelming high amplitude Rayleigh waves that are generated partly due to use of the surface source and partly due to the small scale heterogeneities. Rayleigh wave muting is performed to obtain the meaningful image. Due to heterogeneities, attenuation of high frequency content of the signals and impedance contrast of the underlying layers result in interference. Different seismic attributes are extracted and used for reservoir characterization. From the interpretation of data it is evident that even for this small area the shape of the main reflector varies considerably in the area. Seismic attributes reveal karsts and other structural heterogeneities in the area.

In South Central Cut Bank Sand Unit (SCCBSU) of Cut Bank field, primary production and waterflood projects have resulted in recovery of only 29 % of the original oil in place from heterogeneous, fluvial sandstone deposits. Using highresolution sequence stratigraphy and geostatistical analysis, I developed a geologic model that may improve the ultimate recovery of oil from this field. In this study, I assessed sequence stratigraphic concepts for continental settings and extended the techniques to analyze low-accommodation alluvial systems of the Cut Bank and Sunburst members of the lower Kootenai formation (Cretaceous) in Cut Bank field. Identification and delineation of five sequences and their bounding surfaces led to a better understanding of the reservoir distribution and variability. Recognition of stacking patterns allowed for the prediction of reservoir rock quality. Within each systems tract, the best quality reservoir rocks are strongly concentrated in the lowstand systems tract. Erosional events associated with falling baselevel resulted in stacked, communicated (multistory) reservoirs. The lowermost Cut Bank sandstone has the highest reservoir quality and is a braided stream parasequence. Average net-to-gross ratio value (0.6) is greater than in other reservoir intervals. Little additional stratigraphically untapped oil is expected in the lowermost Cut Bank sandstone. Over most of the SCCBSU, the Sunburst and the upper Cut Bank strata are valley-fill complexes with interfluves that may laterally compartmentalize reservoir sands. Basal Sunburst sand (Sunburst 1, average net-to-gross ratio ~0.3) has better reservoir quality than other Sunburst or upper Cut Bank sands, but its reservoir quality is significantly less than that of lower Cut Bank sand. Geostatistical analysis provided equiprobable representations of the heterogeneity of reservoirs. Simulated reservoir geometries resulted in an improved description of reservoir distribution and connectivity, as well as occurrences of flow barriers. The models resulting from this study can be used to improve reservoir management and well placement and to predict reservoir performance in Cut Bank field. The technical approaches and tools from this study can be used to improve descriptions of other oil and gas reservoirs in similar depositional systems.

Quantifying the influence of pressure on the effective elastic rock properties is important for applications in rock physics and reservoir characterization. Here I investigate the relationship between effective pressure and seismic velocities by performing inversion on the laboratory-measured data from a suite of clastic, carbonate and igneous rocks, using different analytic and discrete inversion schemes. I explore the utility of a physical model that models a natural fracture as supported by asperities of varying heights, when an effective pressure deforms the tallest asperities, bringing the shorter ones into contact while increasing the overall fracture stiffness. Thus, the model is known as the ?asperity-deformation? (ADM) or ?bed-of-nails? (BNM) model. Existing analytic solutions include one that assumes the host rock is infinitely more rigid than the fractures, and one that takes the host-rock compliance into account. Inversion results indicate that although both solutions can fit the data to within first-order approximation, some systematic misfits exist as a result of using the rigid-host solution, whereas compliant-host inversion returns smaller and random misfits, yet out-of-range parameter estimates. These problems indicate the effects of nonlinear elastic deformation whose degree varies from rock to rock. Consequently, I extend the model to allow for the pressure dependence of the host rock, thereby physically interpreting the nonlinear behaviors of deformation. Furthermore, I apply a discrete grid-search inversion scheme that generalizes the distribution of asperity heights, thus accurately reproduces velocity profiles, significantly improves the fit and helps to visualize the distribution of asperities. I compare the analytic and numerical asperity-deformation models with the existing physical model of elliptical ?pennyshape? cracks with a pore-aspect-ratio (PAR) spectrum in terms of physical meaning and data-fitting ability. The comparison results provide a link and demonstrate the consistency between the use of the two physical models, making a better understanding of the microstructure as well as the contact mechanism and physical behaviors of rocks under pressure. ADM-based solutions, therefore, have the potential to facilitate modeling and interpretation of applications such as time-lapse seismic investigations of fractured reservoirs.

Made available in DSpace on 2015-03-13T17:08:38Z (GMT). No. of bitstreams: 1 FilipeSL_DISSERT.pdf: 18861623 bytes, checksum: dec06565f69ab3657111750b25f78441 (MD5) Previous issue date: 2013-06-27 / The Camorim Oilfield, discovered in 1970 in the shallow water domain of the Sergipe Sub-basin, produces hydrocarbons from the Carm?polis Member of the Muribeca Formation, the main reservoir interval, interpreted as siliciclastics deposited in an alluvial-fluvial-deltaic context during a late rifting phase of Neoaptian age, in the Sergipe-Alagoas Basin. The structural setting of the field defines different production blocks, being associated to the evolution of the Atalaia High during the rift stage and subsequent reactivations, encompassing NE-SW trending major normal faults and NWEW trending secondary faults. The complexity of this field is related to the strong facies variation due to the interaction between continental and coastal depositional environments, coupled with strata juxtaposition along fault blocks. This study aims to geologically characterize its reservoirs, to provide new insights to well drilling locations in order to increase the recovery factor of the field. Facies analysis based on drill cores and geophysical logs and the 3D interpretation of a seismic volume, provide a high resolution stratigraphic analysis approach to be applied in this geodynamic transitional context between the rift and drift evolutionary stages of the basin. The objective was to define spatial and time relations between production zones and the preferential directions of fluid flow, using isochore maps that represent the external geometry of the deposits and facies distribution maps to characterize the internal heterogeneities of these intervals, identified in a 4th order stratigraphic zoning. This work methodology, integrated in a 3D geological modelling process, will help to optimize well drilling and hydrocarbons production. This methodology may be applied in other reservoirs in tectonic and depositional contexts similar to the one observed at Camorim, for example, the oil fields in the Aracaju High, Sergipe Sub-basin, which together represent the largest volume of oil in place in onshore Brazilian basins / O Campo de Camorim, descoberto em 1970 na por??o de ?guas rasas da Subbacia de Sergipe, produz hidrocarbonetos do Membro Carm?polis/Forma??o Muribeca, principal intervalo reservat?rio, interpretado como silicicl?sticos depositados em um contexto al?vio-fl?vio-deltaico na fase tardia do rifteamento da Bacia Sergipe-Alagoas, Neoaptiano. O arcabou?o estrutural, que subdivide o campo em blocos produtores, est? associado ? evolu??o do Alto de Atalaia durante a fase rifte e reativa??es posteriores, apresentando falhas normais principais de dire??o NE-SW e falhas secund?rias de dire??es NW-SE e E-W. A complexidade do campo est? ligada ? intensa varia??o faciol?gica, resultante da intera??o entre os ambientes deposicionais continentais e costeiros, e a justaposi??o dos estratos associada ? evolu??o estrutural. Este trabalho tem como objetivo a caracteriza??o geol?gica dos reservat?rios para dar subs?dios ?s novas perfura??es de po?os destinados a aumentar o fator de recupera??o do campo. Deste modo, a partir da an?lise faciol?gica realizada em testemunhos e perfis geof?sicos, em conjunto com a interpreta??o do volume s?smico 3D, prop?e-se uma metodologia que se baseia na an?lise estratigr?fica de alta resolu??o, aplicada em um contexto geodin?mico transicional entre os est?gios rifte e drifte de evolu??o da bacia, capaz de determinar as rela??es espaciais e temporais das zonas produtoras e as dire??es preferenciais do fluxo de fluidos, empregando para este fim, mapas de is?coras que representam a geometria externa, e mapas de distribui??o de f?cies para as heterogeneidades internas destes intervalos identificados em um zoneamento estratigr?fico de 4? ordem. Esta metodologia de trabalho, integrada em um processo de modelagem geol?gica 3D, vai ser utilizada para estabelecer a geometria da malha de po?os injetores/produtores do intervalo de interesse e pode ser aplicada em outros reservat?rios cujo contexto tect?nico-deposicional seja semelhante ao observado em Camorim, caso dos campos localizados no Alto de Aracaju, Sub-bacia de Sergipe, que juntos comp?em o maior volume de ?leo in place na por??o terrestre das bacias brasileiras