Summary
One difficulty in fracture upscaling for field-scale dual-porosity reservoir
simulation is the determination of equivalent gridblock fracture permeability,
which depends on the type of boundary conditions imposed on the
discrete-fracture-network (DFN) simulation. Actually, classical upscaling
procedures usually are based on linearly varying pressure boundary conditions,
which cannot capture the near-well flow behavior. As a result, the well
productivity calculated by a dual-porosity flow simulator can be very different
from that calculated on a DFN model.
This paper proposes a near-well fracture-upscaling procedure based on the
geological DFN model to improve the accuracy of well productivity in
fractured-reservoir simulators. This procedure enables us to represent the
actual flow through the fractures and the exchanges between matrix and
fractures in the well vicinity. On the basis of the computed near-well flow
pattern, equivalent fracture transmissibilities as well as numerical well
indices are determined and assigned to the gridblocks of the dual-porosity
reservoir simulator. The reliability and necessity of using the near-well
upscaling procedure are demonstrated by examples.
Introduction
Advanced characterization methodologies are now able to provide realistic
models of geological fracture networks (Cacas et al. 2001). In addition,
production logging and transient well tests can be simulated with DFN models to
validate the geological fracture-network geometry and calibrate the hydraulic
properties of fractures (Sarda et al. 2002). However, because of computational
limitations, the complex geological DFN model cannot be used straightforwardly
to simulate a multiphase-flow production scenario at field scale (Bourbiaux et
al. 2002). For such simulations, a dual-porosity reservoir simulator is
typically used. The dual-porosity reservoir model, using large gridblocks to
discretize the whole reservoir, is a conceptual representation of the actual
geology of the fractured medium. The flow properties of the fracture network
are then homogenized on gridblocks through upscaling procedures.
The upscaling of fracture properties is the problem of translating the
geological and hydraulic description of fracture networks into
reservoir-simulation parameters. The dual-porosity model requires the
determination of equivalent fracture permeability and equivalent matrix-block
dimensions or shape factors (Bourbiaux et al. 1997; Sarda et al. 1997). This
paper discusses methodologies for upscaling the permeability of a fracture
network, especially in the vicinity of the well.
Upscaling of fracture permeability has been studied extensively. The
commonly used method is numerical, based on flow simulation on a model of the
actual fracture network with specific boundary conditions to compute an
equivalent gridblock permeability (Sarda et al. 1997). Other methods were also
developed; for example, Oda (1985) proposed an analytical equation to calculate
the fracture-permeability tensor, and Lough et al. (1997) presented an approach
using the boundary-element method, which integrates the contribution of matrix
in the equivalent permeability of the fractured medium. When using a numerical
approach to determine the equivalent permeability of a fracture network, the
upscaled result depends on the type of boundary conditions imposed in the flow
simulation. Actually, classical upscaling procedures are usually based on flow
simulation in a parallelepipedic model with linear-type pressure boundary
conditions, which cannot capture the near-well flow behavior. As a result, the
well productivity calculated by a dual-porosity flow simulator can be very
different from that calculated on a near-wellbore DFN model.
© 2006. Society of Petroleum Engineers
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History
- Original manuscript received:
7 December 2004
- Revised manuscript received:
19 June 2006
- Manuscript approved:
31 July 2006
- Version of record:
20 October 2006
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