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(Cosentino 2001 ), in which it is the ratio of
permeability, k, to viscosity,
net-to-gross method and a more general total prop-
erty modelling approach.
, that defines the
flow potential (the mobility ratio). For example,
the following cut-offs are equivalent:
3.5.2 The Net-to-Gross Method
01 md
1 md
5 cp
05 cp
From a geological perspective, the ideal case of a
reservoir containing clean (high porosity) sand-
stone set in a background of homogeneous
mudstones or shale does not occur in reality.
However, for certain cases the pure sand/shale
assumption is an acceptable approximation and
gives us a useful working model. When using
this N/G ratio approach it is important that we
define net sand on a geological basis making
clear and explicit simplifications. For example,
the following statements capture some of the
assumptions typically made:
￿ We assume the fluvial channel facies is 100 %
sand (but the facies can contain significant
thin shale layers).
￿ If the net-sand volume fraction in the model
grid is within 2 % of the continuous-log net-
sand volume fraction, then this is considered
as an acceptable error and ignored.
￿ The estuarine bar facies is given a constant sand
volume fraction of 60 % in the model, but in
reality it varies between about 40 and 70 %.
￿ Tightly-cemented sandstones are included
with the mudstone volume fraction and are
collectively and loosely referred to as “shale”.
Having made the geological assumptions
clear and explicit, it is important to then proceed
to an open discussion (between geologists,
petrophysicists, reservoir engineers and the eco-
nomic decision makers) in order to agree the
definition of net reservoir cut-off criteria. For
example, a typical decision might be:
￿ We assume that net reservoir is defined in the
well-log data by: IF (Gamma
Worthington and Cosentino ( 2005 ) argue that
the most consistent way to handle cut-offs is to
cross plot porosity versus the k/
ratio to decide
on an appropriate and consistent set of cut off
criteria (Fig. 3.29 ). The cut-off criterion (k/
) c is
arbitrary but based on a reservoir engineering
decision concerning the flow rate that is eco-
nomic for the chosen production well concept
and the design life of the oil field. It may be the
case that later on in the field life the appropriate
) c criterion is revised (to lower values) on
account of advances in oil recovery technology
and introduction of enhanced oil
Because of these difficulties with terminology
and the underlying arbitrary nature of the cut-off
assumptions, the key guideline for good reservoir
model design is to:
Use net-to-gross and cut-off criteria in a consistent
way between geological reservoir descriptions,
petrophysical interpretations and reservoir flow
In the following discussion, we consider two end
members of a range of possible approaches - the
Log(k/ m)
(k/ m) c
0.05 OR Perm
0.1 mD) THEN
N/G reservoir )
￿ After averaging, reservoir modelling and
upscaling, the simulation model N/G reservoir
may differ from average well-data N/G reservoir
by a few percent and will be adjusted to
ensure a match.
Hidden within the discussion above is the
problem of upscaling. That is, the N/G estimate
f c
Fig. 3.29 Cross plot of porosity, ø, versus the k/
ratio to
define a consistent set of cut-off criteria,
c and k c
(Redrawn from Ringrose 2008 ,
2008, Society of Petro-
leum Engineers Inc., reproduced with permission of SPE.
Further reproduction prohibited without permission)
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