Page 376 - Enhanced Oil Recovery in Shale and Tight Reservoirs

348 Enhanced Oil Recovery in Shale and Tight Reservoirs

Figure 12.7 Changes of the overall water saturation inside the core (blue [black in print
version] discrete data points) and the pressure drop across the core (black curve) during
flow back (Liang et al., 2017a).

cannot flow back. This capillary imbibition mechanism is supported by
many authors (e.g., Settari et al., 2002; Cheng, 2012; Dehghanpour et al.,
2012; Pagels et al., 2012; Dehghanpour et al., 2013). In Liang et al.’s
(2017a) flow back experiment, pentane was injected from the other end
of the core to try to displace injected water out. A typical set of experimental
data are shown in Fig. 12.7. When the constant flow rate was low, the over-
all water saturation did not decrease, but the pressure difference between the
two ends of the core decreased, indicating that water imbibed into the core
from the inlet side by capillary pressure so that the water blocking was miti-
gated. In the flow system, deionized water and pentane were used. The
late-time plateau of the pressure drop indicated that the further water redis-
tribution by capillary force did not improve the pentane permeability in the
matrix. In other words, the formation damage or water block could be per-
manent if flow rate is low or no remediating chemical is used.
When 20% methanol is added in the fracturing water, the interfacial ten-
sion (IFT) between water and pentane decreased from 50 to 23 mN/m.
Because of this IFT reduction, the capillary force was lower, resulting in