Problems involving coupled thermo-poro-chemo-mechanical processes are of great importance in geothermal and petroleum reservoir systems. In particular, economic power production from enhanced geothermal systems, effective water-flooding of petroleum reservoirs, and stimulation of gas shale reservoirs are significantly influenced by coupled processes. During such procedures, stress state in the reservoir is changed due to variation in pore fluid pressure and temperature. This can cause deformation and failure of weak planes of the formation with creation of new fractures, which impacts reservoir response. Incorporation of geomechanical factor into engineering analyses using fully coupled geomechanics-reservoir flow modeling exhibits computational challenges and numerical difficulties. In this study, we develop and apply efficient numerical models to solve 3D injection/extraction geomechanics problems formulated within the framework of thermo-poro-mechanical theory with reactive flow. The models rely on combining Displacement Discontinuity (DD) Boundary Element Method (BEM) and Finite Element Method (FEM) to solve the governing equations of thermo-poro-mechanical processes involving fracture/reservoir matrix. The integration of BEM and FEM is accomplished through direct and iterative procedures. In each case, the numerical algorithms are tested against a series of analytical solutions. 3D study of fluid injection and extraction into the geothermal reservoir illustrates that thermo-poro-mechanical processes change fracture aperture (fracture conductivity) significantly and influence the fluid flow. Simulations that consider joint stiffness heterogeneity show development of non-uniform flow paths within the crack. Undersaturated fluid injection causes large silica mass dissolution and increases fracture aperture while supersaturated fluid causes mineral precipitation and closes fracture aperture. Results show that for common reservoir and injection conditions, the impact of fully developed thermoelastic effect on fracture aperture tend to be greater compare to that of poroelastic effect. Poroelastic study of hydraulic fracturing demonstrates that large pore pressure increase especially during multiple hydraulic fracture creation causes effective tensile stress at the fracture surface and shear failure around the main fracture. Finally, a hybrid BEFEM model is developed to analyze stress redistribution in the overburden and within the reservoir during fluid injection and production. Numerical results show that fluid injection leads to reservoir dilation and induces vertical deformation, particularly near the injection well. However, fluid withdrawal causes reservoir to compact. The Mandel-Cryer effect is also successfully captured in numerical simulations, i.e., pore pressure increase/decrease is non-monotonic with a short time values that are above/below the background pore pressure.

The depletion of conventional oil reservoirs forced companies and consequently researchers to pursue alternatives such as resources that in the past were considered not economically viable, in consequence of the high depth, low porosity and permeability of the play zone. The exploration challenges were overcome mainly by the development of horizontal drilling and hydraulic fracturing. However, the extremely high temperatures and pressures, in association to a complex nanopore structure, in which reservoir fluids are now encountered, instigate further investigation of fluid phase behavior and composition, and challenge conventional macroscale reservoir simulation predictions. Moreover, the unusual high temperatures and pressures have increased the cost as well as the hazardous level for reservoir analyzes by lab experiments. Molecular Dynamics (MD) simulation of reservoirs can be a safe and inexpensive alternative tool to replicate reservoir pore and fluid conditions, as well as to monitor fluid behavior. In this study, a MD simulation of nanoconfinement effect on hydrocarbon fluid phase and compositional behavior in organic shale rocks is presented. Chapter 1 reviews and discusses previous works on MD simulations of geological resources. With the knowledge acquired, a fully atomistic squared graphite pore is proposed and applied to study hydrocarbon fluid phase and compositional behavior in organic shale rocks in Chapter 2. Results demonstrate that nano-confinement increases fluid mass density, which can contribute to phase transition, and heptane composition inside studied pores. The higher fluid density results in an alteration of oil in place (OIP) prediction by reservoir simulations, when nano-confinement effect is not considered. / Master of Science / Petroleum sub products are present in the day to day life of almost any human. The list include gasoline, plastics, perfumes, medications, polyester for clothing. Petroleum is naturally encountered in the void space, known as pores, inside rocks at reservoirs thousands of feet underground. In the past, the pores of oil reservoirs in development were larger and interconnected, which facilitates its extraction and reserve predictions. Most of reservoirs being developed nowadays have pores in the nanoscale and with poor interconnection as well as higher reservoir temperatures and pressure. These "new conditions", instigates further investigation of fluid phase behavior and composition, and challenge macroscale reservoir simulation predictions. In this study, the effect of decrease in pore size, as well as higher temperature and pressure conditions, in fluid behavior and composition is studied. Chapter 1 reviews and discusses previous works on geological resources modeling and simulation. With the knowledge acquired, a fully squared shale pore is proposed and applied to study hydrocarbon fluid phase and compositional behavior in organic shale rocks in Chapter 2. Results demonstrate that pores in the nanoscale region tend to increase fluid mass density, which can contribute to phase transition, and heptane composition inside studied pores. The higher fluid density results in an underestimation of reserves prediction by reservoir simulations, when the change in density is not considered.

Les réservoirs dits « tight gas » sont constitués de grès de faible perméabilité ayant des propriétés petro-physiques susceptibles de nuire à la productivité du gisement. Une importante zone de transition est observée in situ dans laquelle ni l’eau ni le gaz ne sont suffisamment mobiles pour permettre une extraction industrielle : c’est ce que l’on appellera le « permeability jail ». Cette étude vise principalement à caractériser l’influence du chargement mécanique (via l’utilisation de différentes pressions de confinement) et de la nature des roches (roches provenant de différents puits et prélevées à différentes profondeurs) sur les courbes de perméabilité relative au gaz et les caractéristiques poro-mécaniques de ces roches. La porosité accessible à l’eau mesurée est de 2 à 12%. La perméabilité intrinsèque au gaz a mis en évidence de fortes disparités sans lien avec la porosité des échantillons. Une grande sensibilité de la perméabilité relative au confinement a été observée dès l’application de pressions de confinement de 15 à 30 MPa. Deux familles d’échantillons ont ainsi été identifiées. Les échantillons les plus perméables (perméabilité compris entre 100 – 1000 μD), sont peu sensibles au confinement et leur perméabilité relative ne chute qu’à partir de saturations de l’ordre de 50%. Les échantillons les moins perméables apparaissent beaucoup plus sensibles à la fois au confinement et à la saturation.Des méthodes classiquement utilisées dans le domaine pétrolier reposant sur l’interprétation d’essais de porosimétrie par intrusion mercure, ont également été mise en œuvre pour évaluer les perméabilités relatives et les comparer aux mesures expérimentales / So-called tight gas reservoirs are constituted of low permeability sandstones, which petro-physical properties may interfere with proper gas recovery. They have a low absolute permeability (below 0.1 mD under ambient conditions), a porosity lower than 10%, and a strong sensitivity to in situ stresses as compared to conventional reservoirs. Moreover, an important transition zone is observed in situ, where partial water saturation is present, and which may extend over several hundred meters over the free water table. In such zone, where water saturation is on the order of 40-50%, neither gas nor water seems sufficiently mobile for industrial extraction: this is the permeability jail. Our aim is to assess their actual petro-physical properties, namely porosity, gas permeability under varying hydrostatic stress and water saturation level, in relation with sandstone microstructure. Accessible water porosity measured is between 2 to 12%. The intrinsic permeability to gas did not appeared related to the porosity of samples. A high sensitivity of gas permeability to confinement was observed. Two families of samples were identified. The more permeable samples (permeability between 100-1000 μD), are relatively insensitive to confinement and their relative permeability decrease for water saturation higher than 50%. Less permeable samples appear much more sensitive to mechanical loading and saturation.Methods classically used in oil and gas industry based on the interpretation of mercury intrusion porosimetry tests have also been used to evaluate relative permeability and compared with experimental measurements