Page 428 - Enhanced Oil Recovery in Shale and Tight Reservoirs

396 Enhanced Oil Recovery in Shale and Tight Reservoirs

may help to remove such blockage. However, several factors need to be
considered: fine migration, fracture closure, etc. Water blockage is more
severe near the fracture face. To effectively remove this blockage, early
flow back should be practiced. Here it means that if you plan to perform
flow back, early flow back is preferred, because as time elapses, the water
may enter deep into the formation and then it will be more difficult to
flow back. You may argue that this deep dissipation may mitigate the water
blockage. This issue has been discussed earlier.

12.9.3 CO 2 injection
CO 2 dissolves in trapped water and reduces the gas-water interfacial tension.
Then the energized water will more easily flow out.

12.9.4 Solvent injection
Injection of a mutual solvent like methanol experienced success in gas res-
ervoirs. Heavier alcohols like isopropanol, butanol (Sharma and Sheng,
2017) are preferred for oil reservoirs.

12.9.5 Use of surfactants
Fig. 12.54 compares the water saturation profiles during flow back. In the
experiments, pentane was injected to displace the invaded water from the
other end of the core. For the left column, the invaded fluid was water
only. For the right column, different types of microemulsions were formed
in situ during invasion. First, during water invasion, the saturation in the
invaded zone was flat which represented the front saturation, For surfactant
solutions, the water saturation near the fracture face (end of core) was high
and declined to the front water saturation. Water blocking near the fracture
face will be more effective. The water saturations in this figure show that
water blocking will be more severe initially when surfactants are added.
In Fig. 12.55, the left column shows the average water saturations in the
corresponding cores presented in the earlier figure. Initially, the water
saturations with surfactants were higher than those without surfactants.
But during the flow back, the water saturations with surfactants quickly
declined to levels lower than those without surfactants. Among all three sur-
factant cases, the type-I microemulsion triggered the most flow back. Note
that the type II had a lower viscosity because the pentane oil viscosity was
about 0.24 cP that was lower than water viscosity, so that it is easier for
the type II solution fingered through the water phase, being less effective