Page 221 - Enhanced Oil Recovery in Shale and Tight Reservoirs

204 Enhanced Oil Recovery in Shale and Tight Reservoirs

8.11 Cooling effect of injected water
When cold water is injected into a shale reservoir, the increase in pore
pressure results in the decrease in effective stress, and the decrease in the reser-
voir temperature leads to the contract of matrix leading to the decrease in
effective stress as well. Such technique is called thermal stimulation applied
in geothermal reservoirs. Siratovich et al. (2011) conducted experiments to
verify that temperature-induced stress can create fractures in a volcanic

rock sample. A typical example was to submerge a sample of 300e650 F

into a 68 F water bath. New fractures were created. Numerical studies also
confirm that temperature-induced stress can form new fractures. Cold water
injection in a hot fractured rock induces thermal contraction and creates
tension near the main fracture. If the induced stress exceeds the rock strength,
secondary fractures can propagate from the main fractures (likely perpendic-
ular to the main fracture) in the matrix (Ghassemi, 2012). Groisman and
Kaplan (1994) studied the formation of fractures during desiccation. During
the process, the samples lost water and contracted, creating tension and form-
ing fractures. This process has some similarity to the cooling effect.
Fakcharoenphol et al. (2013) used a 5-spot pattern model to simulate the
cooling effect. We may use their result to explain the mechanisms.
Fig. 8.27A shows the stress profiles plotted as the Mohr circle including the
failure envelope with a 100 psi cohesion and a fraction angle of 30 degree
for healed natural fractures. On the plot, the maximum stress reduction is
near the injector where the maximum temperature occurs. The intersection
of the stress profile with the failure envelope shows a possible reactivation of
healed natural fractures. Fig. 8.27B compares the pore pressure-induced stress

Figure 8.27 (A) Simulated effective stress profiles at the initial condition, 200 and 300 ft
from the injector, (B) temperature- and pore pressure-induced stress profiles at 200 ft
from the injector, after 1 years of injection (Fakcharoenphol et al., 2013).