Characteristic Forced and Spontaneous Imbibition Behavior in Strongly Water-Wet Sandstones Based on Experiments and Simulation

Abstract

Forced and spontaneous imbibition of water is performed to displace oil from strongly water-wet Gray Berea (~130 mD) and Bentheimer (~1900 mD) sandstone core plugs. Two nonpolar oils (n-heptane and Marcol-82) were used as a non-wetting phase, with viscosities between 0.4 and 32 cP and brine (1 M NaCl) for the wetting phase with viscosity 1.1 cP. Recovery was measured for both imbibition modes, and pressure drop was measured during forced imbibition. Five forced imbibition tests were performed using low or high injection rates, using low or high oil viscosity. Seventeen spontaneous imbibition experiments were performed at four different oil viscosities. By varying the oil viscosity, the injection rate and imbibition modes, capillary and advective forces were allowed to dominate, giving trends that could be captured with modeling. Full numerical simulations matched the experimental observations consistently. The findings of this study provide better understanding of pressure and recovery behavior in strongly water-wet systems. A strong positive capillary pressure and a favorable mobility ratio resulting from low water relative permeability were main features explaining the observations. Complete oil recovery was achieved at water breakthrough during forced imbibition for low and high oil viscosity and the recovery curves were identical when plotted against the injected volume. Analytical solutions for forced imbibition indicate that the pressure drop changes linearly with time when capillary pressure is negligible. Positive capillary forces assist water imbibition, reducing the pressure drop needed to inject water, but yielding a jump in pressure drop when the front reaches the outlet. At a high injection rate, capillary forces are repressed and the linear trend between the end points was clearer than at a low rate for the experimental data. Increasing the oil viscosity by a factor of 80 only increased the spontaneous imbibition time scale by five, consistent with low water mobility constraining the imbibition rate. The time scale was predicted to be more sensitive to changes in water viscosity. At a higher oil-to-water mobility ratio, a higher part of the total recovery follows the square root of time. Our findings indicate that piston-like displacement of oil by water is a reasonable approximation for forced and spontaneous imbibition, unless the oil has a much higher viscosity than the water.

Spontaneous Imbibition and an Interface-Electrostatics-Based Model of the Transition Zone Thickness of Hydrocarbon Reservoirs and Their Theoretical Interpretations

“…From Equation (4), the model of surface charge density requires knowledge of the cylindrical parallel pores that forms petroleum reservoirs [62]. Assuming mean values for porosity and permeability, the effective mean value can be calculated based on the definition of Leverette radius as [63]:…”

Early- and Late-Time Prediction of Counter-Current Spontaneous Imbibition, Scaling Analysis and Estimation of the Capillary Diffusion Coefficient

“…The high RF tr is consistent with relatively low or similar oil viscosity compared to water viscosity. Water-wet systems tend to have much lower k rw than k ro (Mungan 1972;Kleppe and Morse 1974;Anderson 1987b;Bourbiaux and Kalaydjian 1990;Andersen et al 2022) so the oil-to-water mobility ratio is high, shifting Λ n to high saturations and RF tr to high values. In the 63.3 cP oil tests, the oil-to-water mobility ratios are lower, and the curves deviate from the linear trend between RF tr = 0.75 and 0.9.…”

Snap-Off during Imbibition in Porous Media: Mechanisms, Influencing Factors, and Impacts

“…In particular, capillary forces induced by surface tension promote the spontaneous movement of the wetting phase within narrow channels, while viscous forces determined by liquid viscosity and flow velocity hinder the flow of the nonwetting phase within pores. Under different types of porous media and fluid conditions, the relative magnitudes of capillary forces and viscous forces vary, thus affecting the efficiency and outcomes of the imbibition process [10,13,14]. This ultimately results in different characteristics of imbibition under various reservoir and rock conditions.…”

“…Specially, capillary forces are altered by adjusting external conditions or medium properties, thereby influencing the progression of imbibition. Spontaneous imbibition [1,4,13] is an outcome that occurs independently of external conditions. In this scenario, imbibition is propelled solely by the interaction of various forces within the medium, without any external interference.…”