Abstract

Measurement of relative permeability in the laboratory and/or its prediction from models has become an increasingly important subject in reservoir modelling, as reservoir simulation has become the standard method for more accurate forecasting of production and ultimate recovery. However, as is often the case, when the history match in a reservoir simulator is unsatisfactory, the parameter which is most likely to be adjusted is the relative permeability. With developments in measurement and interpretation techniques it is now possible to obtain reliable relative permeability curves.

This paper examines current developments in relative permeability measurements from laboratory coreflood experiments, including developments in data reduction and the interpretation of results. It is apparent that classical analytical techniques, such as the Johnson, Bossler and Nauman (JBN) method, cannot describe the majority of unsteady-state displacements, yet are often inconsiderately applied. Valid relative permeability data is only possible if the analytical or numerical model allows for capillarity, viscous instability, wettability and permeability heterogeneity, and can be tuned by carefully measured pressure, flow, and saturation data, and, if possible, non-invasive saturation monitoring.

The use of upscaling techniques to bridge the gap between reservoir simulation models and geological scale models poses a great challenge on relative permeability measurements and predictions, at small scale (laminar) levels and for different rock facies.

Introduction

Relative permeability is used to describe multiphase flow in a porous medium. Such data are important input to many reservoir engineering calculations, providing a basic description of the way in which the phases will move in the reservoir. Definition of the flow process can have a significant effect on the predicted hydrocarbon production rate and duration, and is important in calculating the volume of recoverable hydrocarbon reserves.

Although ways to determine relative permeability from measurements made in the field have been proposed, they are fraught with problems and have never been regularly used. The most common method for determining relative permeability has been laboratory special core analysis. Laboratory measurement of representative relative permeability data on a reservoir core-fluid system is a complex task. The experiments are costly and time consuming. Accuracy is limited to the specific core samples and is bounded by narrow saturation limits. A fundamental theoretical approach to modelling multiphase fluid flow in porous rocks is prevented by the complex nature of the problem. Major difficulties arise in mathematically describing flow through a porous system where the lengths, diameters and connectivity of channels are largely unquantifiable, and the complex nature of the hydrocarbon fluids which range from heavy oils to gas condensates with complex thermodynamic behaviours.

The extension of Darcy's law to multiple phase flow is, in fact, a heuristic procedure suggested by the analogy with single phase flow. It does not provide an understanding of the physics of multiple phase flow. However, as the law has been substantiated by experiments, it must be assumed that it is at least partly correct and a physical understanding of it has to be sought.

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