This research utilizes imbibition experiments and X-Ray tomography results for modeling fluid flow in naturally fractured reservoirs. Conventional dual porosity simulation requires large number of runs to quantify transfer function parameters for history matching purposes. In this study empirical transfer functions (ETF) are derived from imbibition experiments and this allows reduction in the uncertainness in modeling of transfer of fluids from the matrix to the fracture.

The application of ETF approach is applied in two phases. In the first phase, imbibition experiments are numerically solved using the diffusivity equation. Usually only the oil recovery in imbibition experiments is matched. But with the advent of X-ray CT the spatial variation of the saturation can also be computed. The matching of this variation can lead to accurate reservoir characterization. In the second phase, the imbibition derived empirical transfer functions are used in developing a dual porosity reservoir simulator. The results from this study are compared with published results. The study reveals the impact of uncertainty in the transfer function parameters on the flow performance and reduces the computations to obtain transfer function required for dual porosity simulation.


A major part of the worlds oil reserves are present in naturally fractured reservoirs but because of the complexities involved in characterizing these reservoirs, the production from these reservoirs is very low. Fluid flow simulation in naturally fractured reservoirs (NFRs) using dual porosity was first introduced to the petroleum industry by Warren and Root(1). Dual porosity divides the porous system of any reservoir divided into two parts:

  • Primary Porosity (Matrix): Matrix is the portion of the porous system that is the intergranular and controlled by deposition methods. This media contributes significantly to fluid storage but because of low permeability, its contribution to fluid flow is low.

  • Secondary Porosity (Fracture): Fractures are the portion of the porous system that is caused by fracturing, solution or other post-depositional phenomenon. This media is highly permeable and hence. contribute significantly to the fluid flow but as it is not very porous, their contribution to fluid storage is negligible.

Most of the petroleum reservoirs show dichotomy of porous space but with varying degree of matrix and fracture presence. Most NFRs are highly fractured and consist of a significant amount of secondary porosity.

Dual porosity formulation superimposes the secondary (or fracture) media on the primary (or matrix) media and this superimposition is idealized as primary porosity coupled with the secondary porosity as shown in Fig. 1. Most of the research in terms of naturally fractured reservoirs has been done to model accurately the inter-porosity flow between the matrix and the fracture media. NFRs are characterized by very high initial production and after a very brief period of time they reach a plateau in the production. This plateau is controlled by the inter-porosity flow between the matrix and the fracture. Hence efficient modeling of this phenomenon is necessary for efficient reservoir modeling. Also in the modeling of secondary and tertiary production schemes, the inter-porosity flow plays an important role.

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