Summary
In conventional reservoir simulations, gridblock permeabilities are
frequently assigned values larger than those observed in core measurements to
obtain reasonable history matches. Even then, accuracy with regard to some
aspects of the performance such as water or gas cuts, breakthrough times, and
sweep efficiencies may be inadequate. In some cases, this could be caused by
the presence of substantial flow through natural fractures unaccounted for in
the simulation. In this paper, we present a numerical investigation into the
effects of coupled fracture-matrix fluid flow on equivalent permeability.
A fracture-mechanics-based crack-growth simulator, rather than a purely
stochastic method, was used to generate fracture networks with realistic
clustering, spacing, and fracture lengths dependent on Young’s modulus, the
subcritical crack index, the bed thickness, and the tectonic strain. Coupled
fracture-matrix fluid-flow simulations of the resulting fracture patterns were
performed with a finite-difference simulator to obtain equivalent
permeabilities that can be used in a coarse-scale flow simulation. The effects
of diagenetic cements completely filling smaller aperture fractures and
partially filling larger aperture fractures were also studied.
Fractures were represented in finite-difference simulations both explicitly
as grid cells and implicitly using nonneighbor connections (NNCs) between grid
cells. The results indicate that even though fracture permeability is highly
sensitive to fracture aperture, the computed equivalent permeabilities are more
sensitive to fracture patterns and connectivity.
Introduction
High-permeability fracture networks in a matrix system can create
high-conductivity channels for the flow of fluids through a reservoir,
producing larger flow rates and, therefore, larger apparent permeabilities. The
presence of fractures can also cause early breakthrough of the displacing fluid
and lead to poorer sweep efficiencies in displacement processes. A better
understanding of reservoir performance in such cases may be obtained by
including the details of the fluid flow in fractures in a coupled
fracture-matrix reservoir flow model.
It is very difficult to directly measure interwell fracture-network geometry
in sufficient detail to model its effect on reservoir behavior. Thus, most
modeling approaches have been statistical, using data from outcrop and wellbore
observations to determine distributions of fracture attributes such as fracture
length, spacing, and aperture to randomly populate a field. In this paper, we
use a mechanistic approach to generate the fracture patterns. Attributes of the
fracture network depend on the applied boundary conditions and material
properties.
© 2005. Society of Petroleum Engineers
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History
- Original manuscript received:
21 April 2004
- Revised manuscript received:
18 May 2005
- Manuscript approved:
31 May 2005
- Version of record:
15 August 2005
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