Page 357 - Enhanced Oil Recovery in Shale and Tight Reservoirs

330 Enhanced Oil Recovery in Shale and Tight Reservoirs

Table 11.10 Effect of pressure gradient by changing matrix permeability and
injected water viscosity in surfactant only flooding.
Injected water (dp/dl) f , (dp/dl) fm ,
Matrix permeability, mD viscosity, cP psi/ft psi/ft RF, fraction
0.0003 1 0.132 1.920 0.0132
100 1 0.145 0.000 0.766
100 10 0.675 0.048 0.999
0.1 1 0.146 0.384 0.060
0.1 10 1.284 0.048 0.056

recovery factor is significant. This verifies Parra et al.’s experimental obser-
vation and our simulation models as well. To check whether oil recovery
factor in tight oil reservoirs could be increased by increasing pressure
gradient, two additional models are run. In these models, the matrix perme-
ability is 0.1 mD, and the water viscosity is increased from 1 to 10 cP. The
results are presented in Table 11.10 as well. Although the pressure gradient is
increased from 0.146 to 1.284 psi/ft when the water viscosity is increased
from 1 to 10 cP, the oil recovery factor is almost unchanged.
For comparison, the microemulsion phase pressure gradient (dp/dl) fm
from the fracture block (6 4 2) to the matrix block (6 3 2) at the middle
of injection process (4.4 days) for each case is also presented in Table 11.10.
These data show that for the base shale model with the matrix permeability
of 0.0003 mD, the pressure gradient from the fracture block to the matrix
block is 1.920 psi/ft (negative!), indicating that the microemulsion phase
in the fracture cannot enter the matrix. When the matrix permeability is
100 mD, the pressure gradient from the fracture block to the matrix block
is zero for the injected water viscosity of 1 cP, and 0.048 psi/ft (close to
zero) for the injected water viscosity of 10 cP. Compared with the pressure
gradient for the 0.0003 mD case, these pressure gradients (absolute value) are
much smaller. For the tight model with the matrix permeability of 0.1 mD
and the injected water viscosity of 1 cP, the (dp/dl) fm is 0.384 psi/ft, while
the pressure gradient in the fracture (dp/dl) f is þ0.146 psi/ft. The fluid in the
fracture block cannot enter the matrix block. For the tight model with the
injected water viscosity of 10 cP, although the (dp/dl) fm is equal to 0.048
psi/ft (close to zero), the (dp/dl) f is þ1.284 psi/ft (very high). Thus the
injected surfactant solution channels through the fracture.
From the above discussion, we can see that increasing pressure gradient
in a chemical flooding may not be effective in fractured shale or tight
reservoirs.