Page 431 - Enhanced Oil Recovery in Shale and Tight Reservoirs

Fracturing fluid flow back 399

that a type II microemulsion is oil external and should be able to be well dis-
placed by oil.
The right column of Fig. 12.55 compares the pressure drop for DI-water
and three types of microemulsions. For the type I, the pressure drop was
lower than that for DI-water, indicating the surfactant solution improved
the matrix permeability. For the type II, the pressure drop was lower in
the early time, but higher in the late time. For the type III, the pressure
drop continued declining but was higher than that for DI-water later for a
long time. These data show that the type I was most effective in improving
the matrix permeability, followed by the type II, and the worst is the type III.
Overall, laboratory experiments have shown that surfactants regained
more hydrocarbon permeability than fracturing water (Ahmadi et al.,
2011; Rostami and Nasr-El-Din, 2014; Sayed et al., 2018; Dong et al.,
2019).

12.9.6 Injection of dry gas
In principle, dry gas may be injected to vaporize liquid so that liquid phase
trapping may be mitigated. Care may be taken if the trapped brine is
concentrated with soluble ions. As the brine desiccates, the soluble ions
may be precipitated and plug the pores, especially where divalent concentra-
tions are high (Bennion et al., 1999).
This technique is proposed in gas condensate reservoirs in a huff-n-puff
process (Meng et al., 2015a,b). This technique also has the mechanism of
repressurization. However, it has not been reported in shale and tight reser-
voirs to remove water blockage, probably due to economic concern and
effectiveness.

12.9.7 Formation heating

Formation heating was proposed by Jamaluddin et al. (1995) to remove
water-based phase traps and water reactive clay-induced damage in gas res-
ervoirs. Hot gas is injected through the tubing. A zone of 2 m high and

1.5e2 m in the radial depth is treated. Temperatures over 500 C lead to su-
percritical extraction of trapped water and thermal decomposition and
desensitization of reactive clays.
Roychaudhuri et al. (2014) conducted forced imbibition experiments of
60 ppm surfactant solution into shale gas cores. The cores were saturated
with gas and confined by 2500 psi. Then the surfactant solution was injected
at one end with the other end closed. They found the imbibition rate of the