Influence of Capillarity on Relative Permeability in Fractional Flows

Abstract

The effect of capillary pressure on multiphase flow is described by the capillary pressure gradient term in the fractional flow equation. This term is typically neglected during core-flooding experiments, as it is not easily accessible. However, the capillary pressure is not constant during core flooding owing to a capillary pressure discontinuity at the core outlet. By imaging spatial fluid distributions under two-phase steady-state flow, we determine in situ phase saturations and capillary pressures from interfacial curvature measurements along an entire core, thus achieving the assessment of the capillary pressure gradient and its influence on multiphase flow. We demonstrate how the pore-scale capillary pressure gradient affects multiphase flow and, in turn, the core-scale relative permeability measurements. Further, an alternative approach to determining relative permeability from a single fractional flow experiment is proposed. The approach provides a range of relative permeabilities for a single fractional flow experiment and does not require capillary-end correction, as the formulation directly accounts for the effect of capillary pressure on the flow.

In‐Situ Capillary Pressure and Its Interrelationships With Flow Characteristics During Steady‐State Three‐Phase Flow in Water‐Wet Berea Sandstone

“…However, this correction does not acknowledge the mutual interactions between the different phases or in other words that the reduction in the relative permeability of the less wetting phase may imply an increase in that of the more wetting one. Therefore, in the second correction approach (Correction (II)), which is extension of that discussed by (Lin et al, 2018;Zou et al, 2020) to three-phase flow, the fractional flow equations can be solved simultaneously as follows. Based on the flow rates of the co-injected fluids, we can define the following fractional flows and total flow rates for each pair of fluids:…”

A New Method for Calculating the Relative Permeability Curve of Polymer Flooding Based on the Viscosity Variation Law of Polymer Transporting in Porous Media

“…Relative permeability curves can describe the seepage state of multiphase fluid in porous media and play important roles in many aspects, such as history matching and the design of oil field development schemes. Studies on oil-water relative permeability [11][12][13][14][15][16][17][18][19][20][21][22] and oil-gas relative permeability [23][24][25][26][27] were carried out in recent years. For the acquisition of oil-water relative permeability curves, except that a few studies used some parameters to predict [16][17][18], most of them were measured by experiments [19][20][21][22].…”

Characterization of Two-Phase Flow from Pore-Scale Imaging Using Fractal Geometry under Water-Wet and Mixed-Wet Conditions

“…The results for the Euler characteristic indicate a decrease of non-wetting phase relative permeability with wettability altered from water-wet to mixed-wet on the same rock. Moreover, a pore-by-pore basis on pore and throat fluid occupancy [16,17], fluid/fluid interfacial areas [18], curvatures [19,20], and contact angles [21,22] have been conducted on high-resolution imaging under water-wet and mixed-wet conditions and adopted to explain the pore-scale physics that control the measured macroscopic relative permeability under various wettability conditions [23]. Overall, using a combination of flow experimentation and imaging provide insight into the effects of the configuration of the pore space and the fluids in it on transport.…”