Many people believe that in strongly wetted systems, the relative permeability of the wetting phase is usually a function of its own saturation, which means that it is not a function of saturation history. Anderson reported that the wetting phase relative permeability is very similar for both two and three- phase in strongly wetted systems at a specific wetting phase saturation. This implies that the wetting phase distribution in two-phase is very much similar to the one in three-phase systems. Therefore the hysteresis between the drainage and imbibition of the wetting phase is very small. In three-phase systems, many people assumed that gas is almost always a nonwetting phase.
There were other experiments, which show that there was hysteresis for the wetting phase in both water wet system and oil wet system. It is possible that for the cases where hysteresis was seen in the relative permeability of the wetting phase, the medium was not strongly wet. In general, the majority of the results show that there is little or no relative permeability hysteresis in the wetting phase.
Most of the results that show significant hysteresis in the wetting phase relative permeability were obtained from unsteady state methods. Craig and others believe that there are problems with the unsteady state relative permeability measurement in strongly wetting systems1.
As mentioned before, for the nonwetting phase in a strongly wet medium, many people agree that its relative permeability is a function of its saturation only, thus there is no hysteresis. However, there was significant hysteresis seen for the relative permeability of the intermediate wetting phase.
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Methods of Relative Permeability Measurements
Honarpour and Mahmood provide a detailed assessment of the steady state and unsteady methods of measuring relative permeability5. They believe that steady state provides the most reliable relative permeability data. In this method, two or three fluids are injected simultaneously at a constant rate or pressure drop. The system is then allowed to reach equilibrium. At this point, the saturations, flow rates, and pressure gradients are measured. Darcy’s law is then used to calculate the effective permeability of each phase. The injection rate or pressure drop is then changed and the cycle is repeated again until enough points are collected to plot the relative permeability curve. This method is very time consuming, because equilibrium at each flow rate may take several hours to days to achieve. Unsteady state is the quickest method of obtaining relative permeability. In this method, the in-situ fluids are displaced at a constant rate with the effluent volumes being monitored continuously. Equilibrium is not achieved, so the entire set of relative permeability curves can be obtained in a few hours. However, there are many difficulties associated with this method, such as capillary end effects, viscous fingering and channeling in heterogeneous medium, which cannot be properly accounted for. Capillary end effect is a phenomenon in which the saturation is high at the inlet or outlet of the core. To minimize the boundary effect, the fluids can be flowed through the core at high rates to make the capillary forces insignificant compared to the viscous forces due to the flow of fluids. The fluid dispersion in the porous media increases with the flow rate, thus minimizing the boundary effect at the input end6. However, the use of high flow rate can aggregate viscous fingering problems. Also, in this method viscous oils are usually used to prolong the period of two-phase production (at flow breakthrough, no more information on relative permeability can be obtained). Again, this will further enhance the viscous fingering problem.
Craig and other researchers recommend that the unsteady state method not be used with strongly water wet cores. They believe that the combination of high velocities and high viscosities will cause a strongly water wet medium to behave as an oil wet system during waterflood. During a waterflood, the injected water will move rapidly through the larger pores, bypassing a large number of pores that are filled with viscous oil, causing early breakthrough. Usually, in waterflooding of an oil wet system, it was seen that breakthrough recovery is low and additional oil can still be recovered. Thus, the performance of a waterflood with viscous oil is very similar to a waterflood of an oil wet system. Also, in comparison with the steady state relative permeability of two-phase, the calculated unsteady state relative permeabilities measured on the same core appear to be more oil wet.
During the process of core cleaning and handling, the wettability of the core can be altered, which can significantly affect the relative permeability. The cleaned core is usually more water wet than the actual native state wettability, thus the most accurate relative permeability measurements are obtained on native state core when the core’s wettability is reserved. When these cores are not available, restored state core could be used. The process of core wettability restoration must be handle with care since any error can be resulted in significant wettability alteration.
There are other problems associated with obtaining data from core. Heaviside et al. said that the core sample might not truly represent the reservoir because the core samples are only a small fraction of the
140 reservoir, and may therefore be statistically unrepresentative7. Also, the sample may not be in the same state or have the same properties as when it was in the undisturbed reservoir. When the core plug is brought up to the surface, the light ends hydrocarbon can be liberated, causing the oil to be more heavy7. Some components can be deposited on the pore surface, making the rock more oil wet.