Summary
The geological complexity of fractured reservoirs requires the use of
simplified models for flow simulation. This is often addressed in practice by
using flow modeling procedures based on the dual-porosity, dual-permeability
concept. However, in most existing approaches, there is not a systematic and
quantitative link between the underlying geological model [in this case, a
discrete fracture model (DFM)] and the parameters appearing in the flow
model.
In this work, a systematic upscaling procedure is presented to construct a
dual-porosity, dual-permeability model from detailed discrete fracture
characterizations. The technique, referred to as a multiple subregion (MSR)
model, represents an extension of an earlier method that did not account for
gravitational effects. The subregions (or subgrid) are constructed for each
coarse block using the iso-pressure curves obtained from local pressure
solutions of a discrete fracture model over the block. The subregions thus
account for the fracture distribution and can represent accurately the
matrix-matrix and matrix-fracture transfer. The matrix subregions are connected
to matrices in vertically adjacent blocks (as in a dual-permeability model) to
capture phase segregation caused by gravity. Two-block problems are solved to
provide fracture-fracture flow effects. All connections in the coarse-scale
model are characterized in terms of upscaled transmissibilities, and the
resulting coarse model can be used with any connectivity-based reservoir
simulator.
The method is applied to simulate 2D and 3D fracture models, with viscous,
gravitational, and capillary pressure effects, and is shown to provide results
in close agreement with the underlying DFM. Speedups of approximately a factor
of 120 are observed for a complex 3D example.
Introduction
The accurate simulation of fractured reservoirs remains a significant
challenge. Although improvements in many technical areas are required to enable
reliable predictions, there is a clear need for procedures that provide
accurate and efficient flow models from highly resolved geological
characterizations. These geological descriptions are often in the form of
discrete fracture representations, which are generally too detailed for direct
use in reservoir simulation.
Dual-porosity modeling is the standard simulation technique for flow
prediction of fractured reservoirs. This model was first proposed by Barenblatt
and Zheltov (1960) and introduced to the petroleum industry by Warren and Root
(1963). The key aspect of this approach is to separate the flow through the
fractures from the flow inside the matrix. The reservoir model is represented
by two overlapping continua—one continuum to represent the fracture network,
where the main flow occurs, and another continuum to represent the matrix,
which acts as a source for the fracture continuum. The interaction between
these two continua is modeled through a transfer function, also called the
shape factor. Though very useful, the model is quite simple in that the
geological and flow complexity is reduced to a single parameter, the shape
factor. This parameter is in general different for each gridblock depending on
the underlying geology and the type of flow.
© 2008. Society of Petroleum Engineers
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History
- Original manuscript received:
28 June 2006
- Meeting paper published:
24 September 2006
- Revised manuscript received:
19 June 2007
- Manuscript approved:
24 June 2007
- Version of record:
20 March 2008
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