Large amounts of hydrocarbon reserves are trapped in fractured reservoirs where fluid flux is far more rapid along fractures than through the porous matrix, even though the volume of the pore space may be a hundred times greater than the volume of the fractures. These are considered extremely challenging in terms of accurate recovery prediction because of their complexity and heterogeneity. Conventional reservoir simulators are generally not suited to naturally fractured reservoirs’ production history simulation, especially when production processes are associated with large pressure and temperature changes that lead to large redistribution of effective stresses, causing natural fracture aperture alterations. In this case, all the effective processes, i.e. hydraulic, thermal and geomechanical, should be considered simultaneously to explain and evaluate the behavior of stress-sensitive reservoirs over the production period. This is called thermo-hydro-mechanical (THM) coupling. In this study, a fully coupled thermo-hydro-mechanical approach is developed to simulate the physical behavior of fractures in a plane strain thermo-poroelastic medium. A hybrid numerical method, which implements both the finite difference method (FDM) and the displacement discontinuity method (DDM), is established to study the pressure, temperature, deformation and stress variations of fractures and surrounding rocks during production processes. This method is straightforward and can be implemented in conventional reservoir simulators to update fracture conductivity as it uses the same grid block as the reservoir grids and requires only discretization of fractures. The hybrid model is then verified with couple of analytical solutions for the fracture aperture variation under different conditions. This model is implemented for some examples to present the behavior of fracture network as well as its surrounding rock under thermal injection and production. The results of this work clearly show the importance of rate, aspect ratio (i.e. geometry) and the coupling effects among fracture flow rate and aperture changes arising from coupled stress, pressure and temperature changes. The outcomes of this approach can be used to study the behavior of hydraulic injection for induced fracturing and promoting of shearing such as hydraulic fracturing of shale gas or shale oil reservoirs as well as massive waste disposal in the porous carbonate rocks. Furthermore, implementation of this technique should be able to lead to a better understanding of induced seismicity in injection projects of all kinds, whether it is for waste water disposal, or for the extraction of geothermal energy.

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.

[pt] Todos os reservatórios de petróleo apresentam algum grau de fraturamento. Muitas vezes, a presença de fraturas afeta de forma significativa o fluxo dos fluidos nele contidos, seja por incrementarem a permeabilidade do meio, criando caminhos preferenciais de escoamento, seja por imporem algum tipo de barreira ao fluxo. Quando submetidos à injeção de água, reservatórios naturalmente fraturados podem apresentar graves problemas de produção prematura de água e baixíssimas eficiências de varrido. Os estudos realizados neste trabalho procuraram contribuir para o melhor entendimento dos processos de recuperação envolvidos na produção de reservatórios fraturados, bem como o impacto de cada um dos principais parâmetros que condicionam o fluxo no meio poroso fraturado. Foi realizada, ainda, uma análise de possíveis estratégias de drenagem para esse tipo de reservatório. Por fim, foram realizadas simulações para estudar possíveis ganhos da injeção de emulsão de óleo em água, como método de recuperação, em comparação com a injeção de água. / [en] All oil reservoirs have some degree of fracturing. Often, the presence of fractures affects significantly the flow of the fluids contained in the reservoir, increasing the permeability and creating preferential flow paths or by imposing some barrier to the flow. When subjected to waterflooding, naturally fractured reservoirs may have serious problems like early production of water or very low swept efficiencies. The analyses conducted in this study contemplated the understanding of recovery processes involved in the production of fractured reservoirs and the impact of each of the main parameters that influence the flow in fractured porous media. Also, an analysis of possible draining strategies for this type of reservoir was performed. Finally, simulations were performed to study the possible gains of emulsion injection, as a recovery method, compared with water injection.

As easy target reservoirs are depleted around the world, the need for intelligent enhanced oil recovery (EOR) methods increases. The first part of this work is focused on modeling aspects of novel chemical EOR methods for naturally fractured reservoirs (NFR) involving wettability modification towards more water wet conditions. The wettability of preferentially oil wet carbonates can be modified to more water wet conditions using alkali and/or surfactant solutions. This helps the oil production by increasing the rate of spontaneous imbibition of water from fractures into the matrix. This novel method cannot be successfully implemented in the field unless all of the mechanisms involved in this process are fully understood. A wettability alteration model is developed and implemented in the chemical flooding simulator, UTCHEM. A combination of laboratory experimental results and modeling is then used to understand the mechanisms involved in this process and their relative importance. The second part of this work is focused on modeling surfactant/polymer floods using a fully implicit scheme. A fully implicit chemical flooding module with comprehensive oil/brine/surfactant phase behavior is developed and implemented in general purpose adaptive simulator, GPAS. GPAS is a fully implicit, parallel EOS compositional reservoir simulator developed at The University of Texas at Austin. The developed chemical flooding module is then validated against UTCHEM. / text

The primary objective of this study is to improve understanding of the mechanics of hydraulic fracturing in naturally-fractured reservoirs. The study focuses on enhancing the interpretation of hydraulic fracture-induced microseismic data using an S-wave Gaussian-beam method and numerical modeling techniques for interpretation. The S-wave Gaussian-beam method was comprehensively calibrated by synthetic and real data sets with different recording networks, and this showed the potential to retrieve additional microseismic data from hydraulic fracturing with linear receiver arrays. This approach could enhance current practice because a large number of induced events in these environments have very strong S-waves with P-wave amplitudes similar, or less than, background noise levels. The numerical study using the distinct element methods PFC2D and PFC3D was used to validate the understanding of the hydraulic fracturing mechanisms induced in laboratory and field fluid treatments in naturally-fractured reservoirs. This was achieved through direct comparison with the results of the geometry of hydraulic fractures and seismic source information (locations, magnitudes, and mechanisms) from both laboratory experiments and field observations. A suite of numerical models with fully-dynamic and hydro-mechanical coupling has been used to examine in detail the interaction between natural and induced fractures with the variations of the differential stresses and the orientations of the pre-fractures, and the relationship between the fluid front, the fracture tip, and the induced seismicity. The numerical results qualitatively agreed with the laboratory and field observations of the geometry of hydraulic fractures, confirmed the possible mechanics of new fracture development and their interactions with natural fractures, and illustrated the possible relationship between the fluid front and the fracture tip. The validated model could therefore help track the potential extent of induced fracturing in naturally-fractured reservoirs and the extent to which it can be detected by a microseismic monitoring array in order to assess the effectiveness of a hydraulic fracturing project.

The primary objective of this study is to improve understanding of the mechanics of hydraulic fracturing in naturally-fractured reservoirs. The study focuses on enhancing the interpretation of hydraulic fracture-induced microseismic data using an S-wave Gaussian-beam method and numerical modeling techniques for interpretation. The S-wave Gaussian-beam method was comprehensively calibrated by synthetic and real data sets with different recording networks, and this showed the potential to retrieve additional microseismic data from hydraulic fracturing with linear receiver arrays. This approach could enhance current practice because a large number of induced events in these environments have very strong S-waves with P-wave amplitudes similar, or less than, background noise levels. The numerical study using the distinct element methods PFC2D and PFC3D was used to validate the understanding of the hydraulic fracturing mechanisms induced in laboratory and field fluid treatments in naturally-fractured reservoirs. This was achieved through direct comparison with the results of the geometry of hydraulic fractures and seismic source information (locations, magnitudes, and mechanisms) from both laboratory experiments and field observations. A suite of numerical models with fully-dynamic and hydro-mechanical coupling has been used to examine in detail the interaction between natural and induced fractures with the variations of the differential stresses and the orientations of the pre-fractures, and the relationship between the fluid front, the fracture tip, and the induced seismicity. The numerical results qualitatively agreed with the laboratory and field observations of the geometry of hydraulic fractures, confirmed the possible mechanics of new fracture development and their interactions with natural fractures, and illustrated the possible relationship between the fluid front and the fracture tip. The validated model could therefore help track the potential extent of induced fracturing in naturally-fractured reservoirs and the extent to which it can be detected by a microseismic monitoring array in order to assess the effectiveness of a hydraulic fracturing project.

Pour effectuer des simulations d'écoulement diphasique dans les réservoirs fracturés, l'usage des modèles DFM entraîne des temps de calculs exorbitants. L'une des solutions envisageables est le recours aux modèles double milieu. Ces modèles nécessitent la détermination des dimensions du bloc équivalent et la mise à l'échelle des paramètres d'écoulement monophasique et diphasique. Concernant les paramètres d'écoulement monophasique, des méthodes de mise à l'échelle existantes ont déjà fait leur preuve. En contrepartie la mise à l'échelle des paramètres d'écoulement diphasique reste un sujet ouvert nécessitant l'identification de la nature des forces (capillaires, gravitaires ou visqueuses) contrôlant l'écoulement dans le réservoir. Dans le cadre de cette thèse, les formulations mathématiques et les modèles numériques liées à la simulation de type DFM et double milieu ont été explorés. Une étude bibliographique portant sur les méthodes existantes de mise à l'échelle a été développée. Une nouvelle méthode de détermination des dimensions du bloc équivalent (méthode OBS) a été mise en place. Une analyse dimensionnelle servant à identifier la nature des échanges matrice-fractures (capillaire ou visqueuses) lors d'un écoulement diphasique eau-huile, sans gravité, a été mise en place. Le nombre capillaire dérivé a été testé. Enfin, une méthodologie de mise l'échelle des paramètres équivalents double milieu a été mise en place. Cette méthodologie traite le cas d'un écoulement diphasique dans les réservoirs fracturés ayant un milieu matriciel hétérogène dans un contexte d'échanges matrice-fractures dominés par les effets visqueux. / In order to carry-out two phase flow simulations within naturally fractured reservoirs, using DFM models results in huge computational costs. Using dual medium models is one of the available alternative solutions. These models require identifying the equivalent bloc dimensions and upscaling single phase and two phase flow parameters. Available upcaling methods related to single phase parameters reached maturity. Otherwise, upscaling two phase flow parameters is still an open research topic requiring identifying the type of the forces controlling flow in the fractured reservoir (gravity, capillary forces, and viscous forces). During this PhD work, mathematical and numerical models related to DFM and dual medium simulations were explored. A study of the state of the art related to upscaling methods was done. A new and original method allowing determining the dual medium equivalent bloc dimensions (OBS method) was settled down. A dimensional analysis aiming at identifying the type of the forces controlling matrix-fracture exchanges (capillarity, viscous forces) in a water-oil two phase flow within naturally fractured reservoirs without gravity was settled down. The derived capillary number was tested. Finally, an equivalent two phase flow parameters upscaling workflow was also settled down. This workflow treats the particular case of a two phase flow in naturally fractured reservoirs with an heterogeneous matrix medium in a context of matrix-fracture exchanges ruled by viscous forces.

Les réservoirs non-conventionnels présentent un milieu fracturé à multi-échelles, y compris des fractures stimulées et des fractures naturelles, augmentant l'hétérogénéité et la complexité de la simulation de réservoir. Ce travail propose un modèle unique et simple tout en tenant compte des paramètres clés d'un réservoir, tels que l'orientation des fractures, l'anisotropie et la faible perméabilité du réservoir. L'échange matrice-fracture n'est pas correctement modélisé en utilisation les modèles Discrete Fracture Model (DFM) standards en raison de la très faible perméabilité. Dans ce travail nous proposons l'extension de la méthode MINC (Multiple interagissant Continua) aux modèles DFM afin d'améliorer l'échange matrice-fracture. Notre DFM basé sur la méthode MINC, est un modèle triple porosité où les fractures de très grandes conductivités sont explicitement discrétisées et le reste est homogénéisé. Autrement aux modèles standards et afin d'améliorer l'échange de flux entre la matrice et la fracture, une maille matrice est subdivisé selon une fonction de proximité en tenant compte de la distribution des fractures. Notamment, notre approche est particulièrement utile pour les simulations multiphasique avec un changement de phase dans l'échange matrice/fracture, qui ne peut pas être simulé avec une approche standard. Enfin, nous avons appliqué notre approche pour un cas DFN synthétique dans un réservoir de gaz à condensat et un réservoir tight-oil. Un bon accord a été observé en comparant nos résultats à des solutions de référence obtenues avec des maillages très fins. / Unconventional low permeability reservoirs present a multi-scale fractured media, including stimulated fractures and natural fractures of various sizes, increasing the heterogeneity and the complexity of the reservoir simulation. This work proposes a methodology to address this challenge, taking into account reservoir key parameters such as fractures locations, orientation, anisotropy and low permeability matrix in a unique model as simple as possible. Using standard Discrete Fracture Models (DFMs), the matrix-fracture interaction is not properly handled due to the large grid cells and very low matrix permeability. In this work, we extended the MINC (Multiple INteracting Continua) method to the DFM in order to improve the matrix-fracture flow exchange. Our DFM based on a MINC proximity function is computed by taking into account all discrete fractures, within a triple-porosity model where the propped fractures are explicitly discretized and other fractures are homogenized. In order to improve the flow exchange between the matrix and fracture media, the matrix grid cell is subdivided according to the MINC proximity function based on the distance to all discrete fractures, by using randomly sampled points. Our approach is particularly useful for multi-phase flow simulations in matrix-fracture interaction with phase change, which cannot be handled by a standard approach. Finally, we applied our technique to synthetic DFM case in a retrograde gas and a tight-oil reservoirs. A good agreement is observed by comparing our results to a reference solution where very fine grid cells were used.

La plupart des méthodes pour la modélisation des réservoirs fracturés reposent sur le modèle de Warren et Root (1963). Mais ce modèle reste limité par : l'hypothèse d'un volume élémentaire représentatif, l'évaluation des transferts matrice-fractures, l’idéalisation du système fracturé, l'emploi de conditions aux limites locales. La méthode développée répond à ces quatre points. Un réseau de fractures et une grille de matrice sont discrétisés conjointement, puis un changement d'échelle est réalisé. Un ensemble de nœuds représentatifs est sélectionné, et un système simplifié équivalent est construit par décimation des autres nœuds en assurant la conservation des pressions et des débits sans imposer de conditions aux limites. Enfin le nombre de connexions est réduit et les transmissibilités restantes sont calculées par une procédure d'optimisation. Ces systèmes simplifiés ont été résolus plus rapidement lors de simulations d’écoulement tout en reproduisant le comportement du modèle fin / Most methods for modeling fractured reservoirs rely on the model of Warren and Root (1963). But this model is limited by: the assumption of a representative elementary volume, the evaluation of matrix-fracture transfers, the idealization of the fractured system, the use of local boundary conditions. The developed method overcomes these four points. A fracture network and a matrix grid are jointly discretized, then an upscaling is carried out. A set of representative nodes is selected, and an equivalent simplified system is built by decimating the other nodes while ensuring the preservation of pressure and flow rate and without imposing any boundary conditions. Finally the number of connexions is reduced and the remaining transmissibilities are evaluated by an optimization procedure. These simplified systems have been solved more quickly by the flow simulator while reproducing the fine model behavior

[pt] A presença de fraturas naturais em reservatórios de petróleo pode gerar grandes impactos no deslocamento de fluidos em seu interior. Os maiores problemas estão na irregularidade da área varrida pelo fluido injetado, por exemplo, a água, e a antecipação dos breakthroughs, ou seja, a chegada precoce da água aos poços produtores. De modo a analisar o efeito promovido pela presença de fraturas no meio, foram simulados os dois modelos de simulação de fluxo em reservatórios fraturados: o modelo de dupla-porosidade (DP) e o modelo de dupla-porosidade e dupla-permeabilidade (DPDK), bem como outros dois modelos derivados do modelo DP, o modelo de Subdomínios (SD) e o modelo MINC (Multiple Interacting Continua). Também foram realizadas análises paramétricas para compreender o impacto de propriedades, como as permeabilidades tanto da matriz quanto da fratura e o espaçamento das fraturas, no comportamento do fluxo em reservatórios fraturados. A presença de corredores de fraturas (fracture swarms) foi, igualmente, avaliada, assim como seu efeito associado à presença de camadas de altíssima permeabilidade (super-K). Por fim, foi simulado um modelo mais complexo, denominado GTEP, o qual foi construído a partir de uma seção aplicada à simulação de um reservatório carbonático gigante do Oriente Médio, com o intuito de exemplificar a irregularidade da área varrida em reservatórios naturalmente fraturados. / [en] The presence of natural fractures in oil reservoirs can generate major impacts on the fluid displacement inside them. The greatest problems are irregularity in the area swept by the injected fluid, e.g. water, and breakthroughs anticipation, or early arrival of water to the producing wells. In order to analyze the effect of the presence of fractures in the medium, two flow models of fractured reservoirs were constructed: the dual-porosity model (DP) and the dual-porosity and dual permeability model (DPDK), as well as two other models derived from the DP model, Subdomains model (SD) and MINC model (Multiple Interacting Continua). Parametric analyzes were also conducted to comprehend the impact of properties, such as the matrix permeability, the fracture permeability and the fracture spacing, on the flow behavior in fractured reservoirs. The presence of fracture corridors (fracture swarms) was also evaluated in three models, as well as its effect associated with the presence of layers of high permeability, denoted super-K. Finally, a more complex model, called GTEP Field, was simulated, which was constructed from a section applied to the simulation of a giant carbonate reservoir in the Middle East, in order to illustrate the irregularity of the swept area in natural fractured reservoirs.