Geology Reference
In-Depth Information
Filtrate densities are usually about 0.75
0.8 g/cc. To
calculate the fluid modulus of OBM filtrate, a mix of
diesel (~35 API) with no dissolved gas and water
usually works well.
Saturation interpretations may come from a
resistivity log suite interpretation or a petrophysical
'
-
3
ρ
0
2.5
2
. For example, rules of thumb com-
monly used for invaded zone saturation are as
follows.
For water-based mud:
rule of thumb
'
1.5
ρ
fl
1
0.5
S
w
0
:
2
S
xo
¼ð
S
w
+2
Þ=
3orS
xo
¼
ð
Dewan, 1983
Þ:
ð
8
:
44
Þ
0
0
20
40
60
100
80
For oil-based mud:
Core porosity (%)
¼
<
:
S
xo
S
w
ifSw
0
5, otherwise
Figure 8.53
Graphic illustration of fluid density determination
using density log and core porosity measurements.
S
xo
¼
0
:
5
ð
F
:
Whitehead, personal communication
Þ:
Þ
Another approach is to establish an invaded zone
saturation based on the estimated fluid density and
assumptions about end member fluids. In wells
where there are multiple fluid zones and limited
variations in reservoir lithology, comparison of
results from the different zones may lead to a refine-
ment of the fluid densities that are appropriate for
each zone. Relating saturation in the invaded zone to
fluid density is straightforward, but the calculation
of the fluid modulus is less clear-cut. Besides the
definition of the end member fluid properties a key
question is what mixing rule should be applied.
A starting point is to assume that fluid mixing is
homogeneous and that Reuss
ð
8
:
45
Making corrections for invasion to the density log
is straightforward:
Þ
¼ ρ
b
ϕ
:ρ
flx
ϕ
:ρ
flv
,
ρ
b corr
ð
8
:
43
Þ
ð
where
ρ
b(corr)
¼
corrected bulk density,
ρ
b
¼
original
bulk density,
ϕ
¼
porosity,
ρ
flx
¼
invaded zone fluid
density,
Correcting the sonic log for invasion, however, is
more complex, requiring Gassmann fluid substitu-
tion. Not only is the effective fluid density required
but also the effective fluid modulus. The calculation
of these properties involves:
ρ
flv
¼
virgin zone fluid density
calculation of filtrate elastic parameters,
equation applies.
However, it is possible that in the invaded pore space
the saturations are not homogeneous, owing to vari-
able permeability.
The argument for using mixing schemes other
than the Reuss average in the invaded zone comes
from laboratory results. Studies by Domenico (
1977
),
Knight and Nolen Hoeksema (
1990
) and Knight et al.
(
1998
) showed that the velocity vs saturation relation-
ship changes depending on the distribution of gas and
brine in the pore space (
Fig. 8.54
). Where the pore
scale saturations were uniform the velocity was fairly
constant except for a dramatic drop associated with a
small amount of gas. On the other hand, a more
gradual decrease in velocity with increasing gas con-
tent was observed when the pore scale saturations
were heterogenous or
'
estimation of the invaded zone saturation,
determination of end member fluid parameters,
choice of a fluid modulus mixing scheme.
Filtrate properties depend on the nature of the drilling
mud. Where the saline component of the water-based
mud (WBM) filtrate is sodium chloride (NaCl) the
equations of Batzle and Wang (
1992
) may be used to
calculate fluid density and modulus. Note that the
filtrate density of potassium chloride (KCl) muds is
likely to be slightly lower than that of NaCl muds
owing to the lower molecular weight of potassium
(J. Garnham, personal communication). Typical
density values for water-based mud filtrate are around
1 g/cc but can be higher depending on salinity and
mud additives. With regard to oil-based muds
(OBM), typically up to 50% of OBM filtrate is water
with the rest being refined oils and other additives.
. Given the variations
in pore space permeability it
'
patchy
'
189
is conceivable that
