Page 313 - Enhanced Oil Recovery in Shale and Tight Reservoirs

286 Enhanced Oil Recovery in Shale and Tight Reservoirs

ultralow permeability and porosity, the base sand model is converted to a
19 2
base shale model which has 0.1 porosity and 300 nD (w3 10 m )
horizontal permeability. The maximum pressure increases 412 times
from seven psi for 122 mD permeability and 0.24 porosity to 2887 psi
for 300 nD permeability and 0.1 porosity, scaled according to permeability
0 1
p ffiffiffiffiffiffiffiffiffiffiffiffiffi p ffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffiffi
ðk=fÞ 122e 3=0:24
high
and porosity using @ ffiffiffiffiffiffiffiffiffiffiffiffiffi ¼ p ffiffiffiffiffiffiffiffiffiffiffiffiffiffi A ¼ 412, according to Eq.
p
ðk=fÞ 3e 7=0:1
low
9.11. The imbibition recovery factors (RF) for the base sand model and
the base shale model are shown in Fig. 10.2. One may think the high capil-
lary pressure in the base shale model will quickly drive water in the core to
displace oil out. However, the imbibition oil recovery factor is only 26.8%
by more than 2 million days, indicating a very slow imbibition process. To
find the cause(s), the surfactant phase saturation profile shown in Fig. 10.3
for the 122 mD model is compared with that shown in Fig. 10.4 for the 300
nD model. The saturation profiles are in the middle layer of the models by
20 days of imbibition of a surfactant solution. The surfactant phase satura-
tions in the middle blocks are 0.47 and 0.32 for the 122 mD and 300 nD
models, respectively. That means when the permeability is low, the

Figure 10.2 Effect of permeability and porosity on imbibition oil recovery.