David Da-Teh Huang

Capillary end effects in coreflood calculations

Abstract Capillary end effects in coreflood experiments, in some cases, can significantly influence the computation of end-point relative permeabilities and final saturation levels. Because capillary end effects arise from capillarity, these corrections for relative permeability and saturation can be quantified if the capillary pressure curve is known a priori. Based on Darcys law and the relative permeability–capillary pressure relationships, we present in this paper how these corrections can be done in corefloods if the in situ saturation profile is unavailable. Under the same principle, if the in situ saturation profile of the capillary end is available, it is therefore possible to simultaneously predict both relative permeability and capillary pressure using pressure data. Such a method of prediction is presented in the paper and experimentally verified. In a reservoir-conditioned oilflood using a carbonate core sample, we obtained the capillary end information through in situ microwave monitoring, and the relative permeability and capillary pressure were predicted based on the theory. The predictions were compared with separate capillary pressure (mercury injection, porous-plate, and centrifuge) and relative permeability (steady-state) measurements. The predictions and experiments agree well with one another.

The impact of wettability and core-scale heterogeneities on relative permeability

Abstract The objectives of this work were to evaluate the effects of several key parameters (e.g., wettability, saturation history and measurement methods) on the water-oil relative permeability in a mixed-wet reservoir rock. Relative permeability was first measured at its initial wettability along with its hysteresis. Wettability was altered and its impact on relative permeability was assessed. Steady-state and unsteady-state methods were compared. The relative permeabilities of the composite core were compared to those of individual plugs. A CT scanner was used to characterize the core heterogeneity and to monitor three-dimensional in situ fluid distributions during steady state and unsteady state experiments. Numerical simulation was conducted with separately characterized lithologies to describe the flow mechanism in mixed-wet porous media. Results show that an increase in oil-wettability increases the water relative permeability and decreases the oil relative permeability. A decrease of initial water saturation produces an increase in relative permeability hysteresis. Three-dimensional in situ saturations help characterize regions of different lithology and flow mechanisms. The low flow rate unsteady-state experiment can be modelled by the steady-state relative permeabilities if the heterogeneities and the capillary pressures of the composite core are considered.