Tight gas and shale oil play an important role in energy security and in meeting an increasing energy demand. Hydraulic fracturing is a widely used technology for recovering these resources. The design and evaluation of hydraulic fracture operation is critical for efficient production from tight gas and shale plays. The efficiency of fracturing jobs depends on the interaction between hydraulic (induced) and naturally occurring discrete fractures. In this work, a coupled reservoir-fracture flow model is described which accounts for varying reservoir geometries and complexities including non-planar fractures. Different flow models such as Darcy flow and Reynold's lubrication equation for fractures and reservoir, respectively are utilized to capture flow physics accurately. Furthermore, the geomechanics effects have been included by considering a multiphase Biot's model. An accurate modeling of solid deformations necessitates a better estimation of fluid pressure inside the fracture. The fractures and reservoir are modeled explicitly allowing accurate representation of contrasting physical descriptions associated with each of the two. The approach presented here is in contrast with existing averaging approaches such as dual and discrete-dual porosity models where the effects of fractures are averaged out. A fracture connected to an injection well shows significant width variations as compared to natural fractures where these changes are negligible. The capillary pressure contrast between the fracture and the reservoir is accounted for by utilizing different capillary pressure curves for the two features. Additionally, a quantitative assessment of hydraulic fracturing jobs relies upon accurate predictions of fracture growth during slick water injection for single and multistage fracturing scenarios. It is also important to consistently model the underlying physical processes from hydraulic fracturing to long-term production. A recently introduced thermodynamically consistent phase-field approach for pressurized fractures in porous medium is utilized which captures several characteristic features of crack propagation such as joining, branching and non-planar propagation in heterogeneous porous media. The phase-field approach captures both the fracture-width evolution and the fracture-length propagation. In this work, the phase-field fracture propagation model is briefly discussed followed by a technique for coupling this to a fractured poroelastic reservoir simulator. We also present a general compositional formulation using multipoint flux mixed finite element (MFMFE) method on general hexahedral grids with a future prospect of treating energized fractures. The mixed finite element framework allows for local mass conservation, accurate flux approximation and a more general treatment of boundary conditions. The multipoint flux inherent in MFMFE scheme allows the usage of a full permeability tensor. An accurate treatment of diffusive/dispersive fluxes owing to additional velocity degrees of freedom is also presented. The applications areas of interest include gas flooding, CO₂ sequestration, contaminant removal and groundwater remediation. / text

Well logs and formation testers are routinely used for detection and quantification of hydrocarbon reserves. Overbalanced drilling causes invasion of mud filtrate into permeable rocks, hence radial displacement of in-situ saturating fluids away from the wellbore. The spatial distribution of fluids in the near-wellbore region remains affected by a multitude of petrophysical and fluid factors originating from the process of mud-filtrate invasion. Consequently, depending on the type of drilling mud (e.g. water- and oil-base muds) and the influence of mud filtrate, well logs and formation-tester measurements are sensitive to a combination of in-situ (original) fluids and mud filtrate in addition to petrophysical properties of the invaded formations. This behavior can often impair the reliable assessment of hydrocarbon saturation and formation storage/mobility. The effect of mud-filtrate invasion on well logs and formation-tester measurements acquired in vertical wells has been extensively documented in the past. Much work is still needed to understand and quantify the influence of mud-filtrate invasion on well logs acquired in horizontal and deviated wells, where the spatial distribution of fluids in the near-wellbore region is not axial-symmetric in general, and can be appreciably affected by gravity segregation, permeability anisotropy, capillary pressure, and flow barriers. This dissertation develops a general algorithm to simulate the process of mud-filtrate invasion in vertical and deviated wells for drilling conditions that involve water- and oil-base mud. The algorithm is formulated in cylindrical coordinates to take advantage of the geometrical embedding imposed by the wellbore in the spatial distribution of fluids within invaded formations. In addition, the algorithm reproduces the formation of mudcake due to invasion in permeable formations and allows the simulation of pressure and fractional flow-rate measurements acquired with dual-packer and point-probe formation testers after the onset of invasion. An equation-of-state (EOS) formulation is invoked to simulate invasion with both water- and oil-base muds into rock formations saturated with water, oil, gas, or stable combinations of the three fluids. The algorithm also allows the simulation of physical dispersion, fluid miscibility, and wettability alteration. Discretized fluid flow equations are solved with an implicit pressure and explicit concentration (IMPEC) scheme. Thermodynamic equilibrium and mass balance, together with volume constraint equations govern the time-space evolution of molar and fluid-phase concentrations. Calculations of pressure-volume-temperature (PVT) properties of the hydrocarbon phase are performed with Peng-Robinson's equation of state. A full-tensor permeability formulation is implemented with mass balance equations to accurately model fluid flow behavior in horizontal and deviated wells. The simulator is rigorously and successfully verified with both analytical solutions and commercial simulators. Numerical simulations performed over a wide range of fluid and petrophysical conditions confirm the strong influence that well deviation angle can have on the spatial distribution of fluid saturation resulting from invasion, especially in the vicinity of flow barriers. Analysis on the effect of physical dispersion on the radial distribution of salt concentration shows that electrical resistivity logs could be greatly affected by salt dispersivity when the invading fluid has lower salinity than in-situ water. The effect of emulsifiers and oil-wetting agents present in oil-base mud was studied to quantify wettability alteration and changes in residual water saturation. It was found that wettability alteration releases a fraction of otherwise irreducible water during invasion and this causes electrical resistivity logs to exhibit an abnormal trend from shallow- to deep-sensing apparent resistivity. Simulation of formation-tester measurements acquired in deviated wells indicates that (i) invasion increases the pressure drop during both drawdown and buildup regimes, (ii) bed-boundary effects increase as the wellbore deviation angle increases, and (iii) a probe facing upward around the perimeter of the wellbore achieves the fastest fluid clean-up when the density of invading fluid is larger than that of in-situ fluid. / text