Is It Futile to Measure Relative Permeability For Heavy Oil Reservoirs?
Authors: Maini B. 
Published: March 2010

The importance of relative permeability curves in calculations of reservoir performance can hardly be overstated. Both oilwater and oil-gas two-phase relative permeability functions are crucial parts of the input data for heavy oil reservoir simulation studies of primary depletion and thermal recovery processes. The simulation results are often very sensitive to small changes in the relative permeability curves. Therefore, substantial effort and resources are spent in obtaining laboratory measurements of relative permeability. However, as is often the case, when the history match is unsatisfactory, the parameter that is most likely to be adjusted is the relative permeability. Is it, then, futile to measure relative permeability in heavy oil systems?

This paper attempts to answer this question by examining the theoretical and experimental problems in applying conventional relative permeability concepts and methods to heavy oil systems. The experimental difficulties can start in the very first step of obtaining a representative core sample. The core damage occurring in coring and core handling operations can have significant effect on the measured relative permeability.

A brief review of how heavy oil/water (or heavy oil/gas) relative permeability of unconsolidated sand formations is measured in the laboratory, is presented with focus on possible sources of errors. The role of viscous fingering in relative permeability measurements and the conditions under which the laboratory measurements fail to represent the field behaviour are discussed.

It is shown that the laws governing simultaneous flow of heavy oil and water (or heavy oil and gas) through porous media have not yet been clearly formulated. The flow description based on the relative permeability concept, although not as convenient and powerful as it is in the conventional oil systems, is still the best available alternative.

Introduction

The concept of relative permeability stems from the empirical extension of Darcy's law to two-phase (or multi-phase) flow in porous media. Relative permeability, by definition, is the ratio of the effective permeability of a porous medium for a given fluid and a base value of permeability, which is often the absolute permeability of the medium. Thus the relative permeability is a measure of the fractional loss of conductivity for a given fluid due to the presence of other immiscible fluids in the porous medium. The two-phase relative permeabilities are assumed to depend on saturation, saturation history, wettability and pore structure but not on fluid viscosities, densities or flow rates. Bear(1) examined the experimental and theoretical evidence supporting this concept and concluded that it was a good approximation for all practical purposes. This conclusion is also supported by the extensive, and generally successful, application of this flow model in reservoir engineering calculations. Numerical simulation of reservoir processes requires relative permeability curves among other data. These curves are generally estimated from laboratory experiments involving two-phase flow in small samples of the reservoir rock. In view of the heterogeneous nature of petroleum reservoirs, the application of the experimental data measured on a small sample of the rock to represent the fluid flow behaviour of the reservoir represents a leap of faith.