Environmental Engineering Reference
In-Depth Information
instance, in most petroleum reservoirs and some tight sands, natural fractures play a
critical role in controlling fluid flow and hence production in recovery processes.
There are major differences between recovery performance of fractured and non-
fractured oil reservoirs. The high contrast of capillarity between the solid matrix and
the fractures is the main cause of these differences. For instance, high rate wells in the
early life of the field is one main characteristic of fractured reservoirs due to the high
effective single-phase permeability of the combined matrix-fracture porous media
(Firoozabadi
2000
). Depending on their matrix/fissure permeabilities and matrix
block sizes, fractured reservoirs can be produced using several recovery processes,
which include primary recovery, gas drive, waterflood, miscible or immiscible gas-
flood, and enhanced oil recovery methods, such as gas injection combined with water
injection, chemical, and thermal methods (Manrique et al.
2007
).
In view of its important applications in the oil industry, several conceptual models
have been developed for describing fluid flow in fractured porous media. Basically,
each method can be distinguished on the basis of the storage and flow capabili-
ties of the porous medium and fracture. The storage characteristics are associated
with porosity, while the flow characteristics are associated with permeability. Out
of the several existing conceptual models, the double-porosity/dual-permeability
concept has been the most widely used approach for modelling fluid flow, heat
transfer, and chemical transport through fractured reservoirs (Lemonnier and Bour-
biaux
2010a
,
b
). In addition, multiple-interacting continua and multi-porosity/multi-
permeability conceptual models have been also developed (Sahimi
1995
). Further
distinctions among the models can be drawn on the basis of the spatial and tem-
poral scales of integration, or averaging, of the flow regime. For instance, scales
of concern in fracture flow include: (a) the very near field, where flow occurs in a
single fracture and porous medium exchange is possible; (b) the near field, where
flow occurs in a fracture porous medium and each fracture is described in detail; (c)
the far field, where flow occurs in two overlapping continua with mass exchanged
through coupling parameters; and (d) the very far field, where fracture flow occurs,
on average, in an equivalent porous medium (Bear and Berkowitz
1987
). However,
state-of-the-art reservoir simulation packages employed in the oil industry often do
not take into account the complex random geometry of real fractured systems that
can vary from one grid-block to another, and sometimes even within a single grid-
block. The are two reasons for this: first, there exists no technology as yet to image
the micro-fractures in-situ, and second, most of the existing software does not use
micro-scale flow equations to calculate the change of flow variables.
6.1 Dual-Continuum Model
In particular, dual-continuum models are based on an idealized flow medium con-
sisting of a primary porosity created by deposition and lithification and a secondary
porosity created by fracturing, jointing, or dissolution. The basis of these models is
the observation that unfractured rocks account for much of the porosity (storage) of
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