Abstract

A naturally fractured reservoir consists of two distinct regions, each one with its own porosity and permeability.

Data obtained from core analysis such as permeability, porosity, relative permeability curves and capillary pressures are representative of only the matrix (or primary porosity) system. Consequently, these data should not be used in material balances or numerical simulators without proper corrections to account for the presence of fractures.

Furthermore, as reservoir pressure declines, there is a reduction in porosity and permeability due to closing of the fractures. This effect produces a continuous change in the relative perm abilities of the composite system.

This paper presents techniques to generate relative permeability curves for a double-porosity system at initial and subsequent reservoir pressures. The techniques are based on integrated studies of core, log and well testing data, and net overburden pressures.

Introduction

In many cases, data obtained from core analysis such as permeability, porosity, relative permeability characteristics and capillary pressure curves are used in the evaluation of naturally fractured reservoirs without accounting properly for the presence of fractures.

The data obtained from cores apply in nearly all cases to the matrix (primary porosity) system only. Consequently, the use or these data without proper corrections can lead to serious errors when forecasting performance of naturally fractured reservoirs.

Experience indicates that the gas-oil ratio increases faster in fractured than in non-fractured reservoirs. This occurs because the critical gas saturation within the fracture network is very small and in many cases approaches zero. Furthermore this occurs because the relative permeability curve to gas in the fractured reservoir is steeper than in the non-fractured reservoir.

An example 1 of a significant increase in gas-oil ratio below the bubble point is provided by the Driver field (Spraberry Sand) of Texas (Fig. 1). Note that the GOR has increased to about 12,000 scf/STB when the oil recovery was less than 7 percent. An important increase over the initial gas in solution had been already noticed at recoveries as low as 3 and 4 percent.

To avoid potential economic fiascos due to optimistic forecasts of naturally fractured reservoirs, it is necessary to work with relative permeability curves representative of the composite system.

In some cases composite relative permeability curves which remain constant over the life of the reservoir have been used.2,3 In other situations, constant sets of relative permeabilities for each fractures and matrix have been utilized.4

It appears, however, that in some reservoirs there is a tendency for the fractures to close as the reservoir is depleted because of an increase in the net overburden pressure. In these cases there is a continuous change in the relative permeability curves.

This paper presents methods to generate such relative permeability curves. The techniques are based on integrated studies of core, log and well testing data, and net overburden pressures. These techniques are not claimed to be perfect, however, they are giving encouraging results.

THEORETICAL AND EXPERIMENTAL BACKGROUND

Experience indicates that, in some cases, a fracture system can be represented by a bundle of tubes.5

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