Browsing by Subject "Multiphase flow in porous media"

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Oil relative permeability reduction caused by fracturing fluid invasion in low-permeability rocks
(2020-12-03) Luo, Xiao, Ph. D.; DiCarlo, David Anthony, 1969-; Nguyen, Quoc P.; Mohanty, Kishore; Daigle, Hugh; Jones, Raymond
The reduction of oil relative permeability is one important type of formation damage, and it commonly occurs during drilling and fracturing in low-permeability formations. Conceptually, the invaded fluid enters the rock, lowers the oil saturation and reduces oil flow during production. For water-based fracturing fluids, this reduction in oil permeability is also known as a water block. For fracturing gas and foam, the infiltration of the gas may also cause a permeability reduction for oil flow. In this study, coreflood experiments and CT scans are used to measure the effect of fluid invasion on oil permeability. The results show that the fluid block is often transient. The oil permeability reduction gradually diminishes and the fluid block clears over time. This study shows that the important physics for clearing of the invaded fluids are dissolution and imbibition. For dissolution, the invaded fluid dissolves/partitions into the oil, and clears as a chemical component with oil production. For imbibition, the invaded fluid clears by spontaneous imbibition to the deeper part of the reservoir. Because of the different underlying physics, the two processes scale differently with rock and fluid properties. For dissolution, I proposed a new method to solve the hyperbolic conservation equation for compositional displacements. The predicted dissolution time is a good match with the experiments with gas invasion. For imbibition, the clearing time can be found from the plateau duration in the coreflood experiments. A simple scaling formula is derived to estimate this clearing time, and the results match well with both experiments and simulations. For both of the clearing processes, the volume of the fluid invasion has a significant impact to the clearing time. I conducted fluid leak-off experiments that use water, gas, and combination (foam proxy) on oil-saturated cores to measure and determine the dependencies on fluid type. The results show that water leak-off can be well described by the leak-off coefficient, but it may not work for gas leak-off as its leak-off volume is measured to be linear or super-linear with time. The fluid invasion is permeability dependent, and an overall clearing time(s) are derived for water and gas block by incorporating the volume of fluid leak-off. From the calculations that use field values, water block clears faster with decreasing permeability, and gas block clears faster with increasing permeability. This suggests that at low-permeability, it can take longer to clear the invaded gas, and water-based fracturing fluids may be optimal in minimizing the oil permeability reduction
The application of microfluidics in the study of multiphase flow and transport in porous media of improved hydrocarbon recovery methods
(2021-07-11) Du, Yujing; Balhoff, Matthew T.; Pope, Gary A; Mohanty, Kishore K; Prodanovic, Masa; Werth, Charles J
Fundamental investigation of the underlying physics in multiphase flow and transport phenomena in porous media is crucial for many engineering processes, including environmental remediation, geological sequestration, and improved hydrocarbon recovery. Microfluidics are widely used to provide direct, in-time visualization of multiphase flow behavior at the pore-scale and sometimes extend to the representative elementary volumes (REV) scale. Qualitative and quantitative analysis are obtained from microfluidic experiments and are used for mechanisms interpretations. In this work, microfluidics and micromodels are designed to explore fundamental mechanisms in several enhanced/improved oil recovery processes by performing systematic experiments. First, a study of the low salinity effects in improved oil recovery by microfluidics experiments is presented which explains a type of low-salinity effect with delayed oil recovery and without the presence of clay. Experiments were performed from single-pore microfluidics to a REV scale reservoir-on-a-chip model. A time-dependent, oil-water interaction controlled by diffusion was proposed based on the pore-scale observations. Second, the time-dependent behaviors and the role of surfactant during the low salinity waterflood is further investigated by systematic experiments in a 2.5D, inch-long micromodel using mineral oils with different surfactant concentrations and water with different salinities. It is found that the low salinity effects are significant when the surfactant concentration is sufficiently high. The surfactant also dominates the time-dependent behaviors, where higher surfactant concentration leads to shorter delay time. Third, three inch-long “reservoir-on-a-chip” micromodels were utilized to probe the impacts of the microfracture connectivity on the displacement efficiency and sweep patterns when the mobility ratio is unfavorable and the displacement is unstable. It was observed the presence of microfractures do not necessarily improve the displacement efficiency, but the microfracture connectivity, capillary number and wettability altogether impact on the displacement patterns and the ultimate recovery. Last, the role of viscoelasticity’s effects in reducing residual oil saturation is investigated by performing microfluidic experiments in foot-long (30 cm), heterogeneous glass micromodels (“coreflood-on-a-chip”). Significant redistribution and reconnection of residual ganglia occur due to viscoelasticity induced instabilities during high-viscoelasticity polymer floods, which results in residual ganglia remobilization that ultimately reduces residual saturation