The understanding of rock characteristic and fluid flow behavior at the near-wellbore region is an important topic. Triaxial experiment setup can help to investigate these properties. In this research, a new triaxial experimental setup has been developed where the higher scale of the parameters such as higher reservoir pressure, and comparatively larger core sample can be used. High permeable synthetic porous samples are prepared to validate the device. The new triaxial experimental setup is validated with water as a base fluid. In the validation test, real samples and synthetic samples are used. First, flow in convergent direction is studied which represents as production at the in-situ condition. Then, the flow in divergent direction is examined that may represent the injection of fluid to enhance the hydrocarbon production. The near-wellbore flow phenomena are studied with real and synthetic samples. The results indicate that using this triaxial setup pressure drop and pressure buildup test can be explained. The new scientific setup is able to reduce the scale-up gap between laboratory data and field data to get actual reservoir flow phenomena.
Formation damage in petroleum reservoirs is a combination of many complicated phenomena. The formation damage reduces the productivity index significantly. The damage mechanisms may occur from the stage of drilling process to tertiary oil recovery stage. This study investigates the formation damage of petroleum wells due to shooting in well completion. The study is conducted with numerical and experimental investigations. The experimental set is a prototype. Two techniques are considered for numerical simulations: one is ANSYS-CFX and other one is a computational methodology which is based on weighted residual collocation method. Single phase and two-phase flows in porous media have been taken into consideration to explore the productivity index, which is affected by formation damage. Therefore, a better understanding of damage mechanisms for various reservoir conditions can lead to optimize oil recovery rate.
The multiphase flow mechanism in miscible displacement through porous media is an important topic in various applications, such as petroleum engineering, low Reynolds number suspension flows, dusty gas dynamics, and fluidized beds. To simulate such flows, volume averaging spatial operators are considered to incorporate pressure drag and skin friction experienced by a porous medium. In this work, a streamline-based Lagrangian methodology is extended for an efficient numerical approach to handle dispersion and diffusion of solvent saturation during a miscible flow. Overall pressure drag on the diffusion and dispersion of solvent saturation is investigated. Numerical results show excellent agreement with the results obtained from asymptotic analysis. The present numerical simulations indicate that the nonlinear effects due to skin friction and pressure drag cannot be accurately captured by Darcy's method if the contribution of the skin friction dominates over that of the pressure drag. Moreover, mass conservation law is investigated, which is an important feature for enhanced oil recovery, and the results help to guide a good agreement with theory. This investigation examines how the flow regime may be optimized for enhanced oil recovery methods.
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