Fluid front tracking is important in two-phase/component fluid flow in porous media with different heterogeneities, especially in the improved recovery of oil. Three different flow patterns of stable, viscous fingering, and capillary fingering exist based on the fluids’ viscosity and capillary number (CA). In addition, fluid front and sweep efficiency are affected by the heterogeneity of the porous medium. In the current study, the heterogeneous porous media are: (1) normal fault zone or cross-bedding with heterogeneity in permeability, and (2) a fracture or discontinuity between two porous media consisting of two homogeneous layers with very low and high permeabilities, in which immiscible water flooding is performed for sweep efficiency and streamlines tracking purposes. By considering the experimental glass micromodel and the simulation results of discontinuity, a crack is the main fluid flow path. After the breakthrough, fluid inclines to penetrate the fine and coarse grains around the crack. Moreover, an increase in flow rate from 1 and 200 (ml/h) in both the experimental and simulation models causes a reduction in the sweep efficiency from 14% to 7.3% and 15.6% to 10% by the moment of breakthrough, respectively. In the fault zone, the sweep efficiency and the streamline of the injected fluid showed a dependency on the interface incident angle, and the layers’ permeability. The presented glass micromodel and Lattice Boltzmann Method were consistent with fluid dynamics, and both of them were suitable for a precise evaluation of sweep efficiency and visualization of preferential pathway of fluid flow through cross-bedding and discontinuity for enhanced oil recovery purposes.
The study of fluid front in porous media in enhanced oil recovery is important. The purpose of this study is to simulate water flooding, and investigate the factors affecting the fluid front across a microfracture and simple porous media using Shan-Chen type of the Lattice Boltzmann Method (LBM). Various factors, including velocity and dynamic viscosity that define the capillary number and wettability are considered. Independently, the increase in velocity and dynamic viscosity ratio results in viscous fingering and its narrowness. Increasing the wettability of the displacing fluid decreases viscous fingering, and as a result, it makes the fluid move in piston form. The lowest sweep efficiency occurs when the displacing fluid has a neutral wettability. Simulation results show the strength and accuracy of Shan-Chen type of LBM in fluid front tracking in porous media in pore scale.
Fundamental understanding of capillary rise dynamics and precise evaluation of imbibition processes should be considered in many natural and industrial phenomena. The assumptions considered to solve the capillary rise motion usually neglect specific forces which limit the reliability of the derived solutions. In the present study, the dominant forces and regimes involved in the initial moments of the capillary rise imbibition process in a tube were investigated analytically, experimentally, and numerically. Analytical solutions available in the literature were discussed, and then, their validity was verified by comparing them to the experimental observations and numerical results. Comparing the capillary rise behavior at the initial stages revealed significant differences between the theoretical models and the numerical lattice Boltzmann method. This behavior is attributed to simplifying assumptions and ignoring the entrance effect, dynamic contact angle, and the inertial term in the theoretical model. By removing these assumptions in numerical formulations, closer results to the experimental records were observed. In the present study, for the first time, capillary rise dynamics were divided into five steps: (1) transition regime with h~t2; (2) purely inertial (stage one) with h~t; (3) viscous-inertial or crossover (stage two) with h~log10(t); (4) purely viscous (stage three) with h~t1/2; and (5) gravitational-viscous with a constant h. It was known that stage one was purely dominated by the inertial forces, then the influence of viscosity increased (viscous-inertial flow), and finally, the effect of inertia faded and the flow became purely viscous and approached the Lucas-Washburn law.
Quadrant geometry with permeability and wettability contrast occurs in different events, such as faults, wellbore damage, and perforation zones. In these events, understanding the dynamics of immiscible fluid displacement is vital for enhanced oil recovery. Fluid flow studies showed that viscous fingering occurs due to viscous instabilities that depend on the mobility of fluids and capillary forces. Besides, the porous domain heterogeneity is also effective on the formation of fingering. So, the purpose of the current research is to numerically investigate the effect of heterogeneity in wettability and permeability, and flow properties in Saffmann-Taylor instabilities. Numerical simulations with different flow rates in the permeability contrast model illustrated the nodal crossflow, growth of viscous fingering in the nodal part, and bypass flow in the second zone. In the wettability contrast model, a capillary fingering pattern is observed and fluid patches are isolated because of capillary force and the end effects are trapped within the quadrant. Moreover, the consequences of wettability on apparent wettability that alters the fluid-front pattern and displacement efficiency are shown.
Fractured reservoirs have always been of interest to many researchers because of their complexities and importance in the oil industry. The purpose of the current study is to model the fractured reservoir based on geomechanical restoration. Our target is the Arab Formation reservoir which is composed of seven limestone and dolomite layers, separated by thin anhydrite evaporate rock. First of all, in addition to the intensity, the dip, and the azimuth of the fractures, the magnitude and the direction of the stresses are determined using wireline data e.g. photoelectric absorption factor (PEF), sonic density, neutron porosity, a dipole shear sonic imager (DSI), a formation micro imager (FMI), and a modular formation dynamics tester (MDT). Then, the seismic data are interpreted and the appropriate seismic attributes are selected. One of our extracted attributes was the ant tracking attribute which is used for identifying large-scale fractures. Using this data, fractures and faults can be identified in the areas away from wells in different scales. Subsequently, the initial model of the reservoir is reconstructed. After that, the stress field and the distribution of fractures are obtained using the relationship between the stresses, the strains, and the elastic properties of the existing rocks. The model is finely approved using the azimuth and the intensity of fractures in the test well. Our findings showed that the discrete fracture network (DFN) model using geomechanical restoration was positively correlated with real reservoir conditions. Also, the spatial distribution of fractures was improved in comparison to the deterministic-stochastic DFN.
Shear wave velocity is one of the essential parameters for describing hydrocarbon reservoirs that have several applications in petrophysical, geophysical, and geomechanical studies. Shear wave velocity usually does not exist in all wells, especially in old oil fields. In the current study, two equations of Carroll and Castagna have been modified, and linear and nonlinear multi-regressions were used to estimate shear wave velocity in an oil reservoir in southwestern Iran. Initially, compressional wave velocity and porosity were determined as the most effective wire-line logs on shear wave velocity by comparing their correlations. Then, two equations of Carroll and Castagna were modified. In addition, new equations based on porosity and compressional wave velocity for estimating the shear wave velocity were obtained. Shear wave velocity was estimated by new exponential equations in the wells of the current oil field with excellent goodness of fit by determination coefficients of 0.80 in the whole well, 0.72 in the Ghar-Shale-1, and 0.78 in Ghar-Shale-3 in X-07 well.
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