A New Experimental Method To Determine Interval of Confidence for Capillary Pressure and Relative-Permeability Curves

Abstract

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe saturation profiles are routinely measured during Special Core Analysis (SCAL experiments). Several ways exist to use this information in the inversion procedure of the relative permeability data. To date, the local saturation profiles are either included in a global objective function that is minimized during the inversion process, or smoothed and used as input data in the simulation, which leads to non smoothed simulated pressure drop. None of these methods permit to reproduce the local saturation fluctuations that are measured during coreflooding experiments. Our approach has the advantage to take benefit from these fluctuations to characterize the petrophysical properties for a given rock-type. In this paper, the methodology is first recalled and illustrated on a synthetic case. It is based on upscaling techniques applied in reservoir simulation. Both the stabilized and transient saturation profiles are analyzed to evaluate the local properties. The quality of the history matching is significantly improved. In addition, both kr and Pc-curves are obtained from only one experiment and the variability of these parameters with the heterogeneity is also investigated. This estimated interval of confidence for kr and Pc can be very useful to perform uncertainty studies at the reservoir scale. The Pc-curve interval of confidence determined with this method on a carbonate sample, is in good agreement with the variability observed with several centrifuge experiments performed on sister plugs. Finally an alternative approach derived of the heterogeneous method is proposed, which allows a very quick acquisition of all the information relative to kr and Pc during a multi-rate flow experiments.

Estimation of the Water–Oil Relative Permeability Curve from Radial Displacement Experiments. Part 2: Reasonable Experimental Parameters

“…When using the unsteady-state radial displacement experiments to obtain the water–oil relative permeability curve, to reduce the influence of neglecting capillary pressure data and make the estimated curve precisely reflect the flow characteristic of the water–oil two phase in the porous medium, the core sample, properties of fluids, and displacement history should be similar to those of a real reservoir. − Moreover, displacement conditions, such as injection rate, average permeability, and oil–water viscosity ratio, should also be limited to their rational value domains. It is known that the displacement conditions belong to human factors and cannot be ignored. − These factors can alter the pressure gradient at both ends of the core sample and then affect the degree of relative permeability deviation when the capillary pressure is neglected.…”