Abstract

A simple approach for matrix block size evaluation in dual porosity reservoirs using a unified derivative type curve is illustrated with the aid of simulated and field examples under different wellbore conditions.

The effect of wellbore storage on dual porosity characteristics is discussed. The relalionship for maximum wellbore storage conditions for obtaining undisturbed values of the dual porosity system parameters (ωand λ) are presented. It is shown that under certain wellbore storage conditions the true values of ωand λ cannot be obtained. .

The unified derivative type curve approach is used to evaluate matrix block sizes in two Iranian naturally fracture reservoirs. The results are compared with other available sources of matrix block size for these reservoirs. .

Introduction

A naturally fractured formation is generally represented by a tight matrix rock fragmented by a spatial fracture network as a result of tectonic activities. The matrix store most of the fluid in the reservoir and is often of low porosity and permeability whereas the fractures have a low storage capacity and high permeability.

The fractures vary considerably in pattern, size and geometry. In addition to this complexity, sealed and displaced fractures deposition of minerals such as calcite and anhydride, dolomitization, dissolution of the matrix and the formation of cavities and vugs introduce considerable difficulties into the description of the internal structure of such reservoirs.

This is why idealized models such as cubical, cylindrical and strata have been used over the past 3 decades in analytical and numerical models to predict the future behavior and to estimate ultimate recoveries, The accuracy of the model in predicting reservoir performance depends on how close the model corresponds to the reservoir.

The analytical models are based on the concept of double porosity systems which was rust introduced by Barenblatt et all. The first complete solution for a well of finite radius producing at a constant flow rate was published by Warren and Root2. They showed that under pseudosteady state matrix to fracture fluid transfer the pressure behavior at the production well was controlled by two characteristic parameters only, viz. ωand λ. They also showed that the plot of the wellbore pressure versus logarithmic of time reveals two parallel straight lines. The unsteady-state flow from matrix to fractures was first studied by Kazemi3 in a numerical radial model assuming horizontal slabs separated by fractures. He concluded that Warren and Root's model was valid in reservoirs with uniform fracture distribution and with large contrast between matrix and fracture flow capacities. Later de Swaan4 presented analytical unsteady state solutions and Najurieta5 further advanced de Swaan's theory by presenting approximate line source solutions for strata and spherical models. Streltsova6 and Serra et al7 independently, by using de Swaan's model, reached the conclusion that the transition period yielded a straight line with a slope equal to one half the slope of the early and late parallel straight lines for small values of ω. The concept of skin on the surface of matrix was presented by Moench8 who showed that the interporosity skin provides theoretical justification for the pseudosteady stale flow approximation.

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