Characterization of Reservoir Flow Properties using Pore-scale Experiments and Simulations
10th October 2018, Wednesday, 04:00‐04:30 pm (25+5 mins), ChE Seminar hall
Water-flooding of oil reservoirs is the most popular secondary oil recovery process. It accounts for 25 to 30 % of the total oil recovery. In this process, pressurized water is injected from the injection well into the oil reservoir and oil is recovered from the production well. Upstream oil industry use reservoir-scale simulations to predict oil production. These simulations require several reservoir properties, (e.g., porosity and permeability) fluid properties (e.g., viscosity and interfacial tension) and interaction flow properties (e.g., relative permeability) as input parameters to predict oil recovery. Relative permeability is a function of pore-scale properties like rock structure, wettability, and local saturation.
Relative permeability data is conventionally generated from core flooding experiments of very small rock core samples. The reservoir rocks are generally layered (heterogeneous) in nature because of sediment deposition over several decades. However, due to the significantly small core sizes (~ 25 mm) considered in core flooding experiments, the heterogeneous structure of reservoir rock is ignored in the conventional experiments. For accurate prediction of oil recovery, it is necessary to determine the effect of heterogeneity on oil-water relative permeability. Therefore, the objectives of the present work are (i) to investigate the effect of heterogeneity on the dynamics of local saturation and thus on relative permeability and (ii) to study the effects of wettability and interfacial tension on relative permeability of heterogeneous porous medium.
A physical model of the layered porous medium is created using different size of glass beads. This physical model is used to visualize the two-phase flow phenomenon using a high- resolution camera at pore-scale. To study the above phenomenon in detail, a heterogeneous 2D micro-pillar geometry is simulated using Volume of Fluid (VOF) model. The dynamics of ocal saturation is qualitatively similar in glass bead pack and the micro-pillar structure. However, the micro-pillar structure quantitatively differs from the glass bead pack as the pore structure in the third dimension is neglected. A digital pack of spherical particles is created using a Rigid Body Simulation. The pore structure of this digital pack is used to study the flow dynamics using the VOF simulations.
In the present work, we experimentally and numerically show that at a low capillary number, a capillary regime is developed i.e. the wetting fluid front leads in the least permeable layer, while at a high capillary number the wetting fluid front leads in the highest permeability layer. In that case, the least permeable layer is found to draw fluid from the high permeability layer due to capillary suction. The detailed study of the dynamics of local saturation and the pore-scale pressure data generated by VOF simulations will be useful to determine the macroscopic relative permeability by appropriate upscaling.