posted on 2024-02-06, 18:15authored byMagda
Ibrahim Youssif, Keerti Vardhan Sharma, Lamia Goual, Mohammad Piri
Foam
flooding in fractured tight oil reservoirs can enhance gas
mobility and conformance control by diverting gas flow from high-permeability
zones (fractures) to low-permeability ones (matrices). Several factors,
including operating conditions, foam generation parameters, fluid
injection schemes, and properties of injected and resident fluids,
affect the fracture–matrix interactions. However, thus far,
the literature provides a limited understanding of the effects of
such factors on the fluid displacement mechanisms between matrices
and fractures in propped fractured rocks under reservoir conditions.
In this study, two different methane foam injection schemes were investigated
for their impact on foamability and oil recovery from propped fractured
oil-wet carbonate cores at 115 °C and 3500 psi: (1) foam-alternating-gas
injection (FAGI-D) and (2) foam-alternating-wet gas-alternating-gas
injection (FAGI-W-D). The aqueous solutions consisted of high-salinity
brine containing two foaming agents: surfactant A (anionic) and surfactant
B (amphoteric). The macro-scale foam flooding tests showed that the
performance of foam in oil-wet porous media was significantly influenced
by the number of cycles, foam slug size, total injection rate, and
gas fraction. Surfactants A and B exhibited different foaming behaviors
irrespective of the foam injection scheme at a fixed concentration
(4000 ppm) and foam quality (85%). For surfactant A, a large foam
slug size (i.e., six pore volumes) and a high injection rate were
necessary to generate foam. In contrast, a lower slug size (i.e.,
three pore volumes) and a lower injection rate were sufficient for
surfactant B. The latter also showed better tolerance toward oil and
produced foam of good strength in oil-wet porous media. Therefore,
the foam generated by surfactant B significantly reduced the gas mobility
and enhanced the fluid displacement from the matrix, leading to higher
oil recovery (20.61%) compared with its counterpart (12.96%). Interestingly,
the performance of both surfactants was improved at a lower foam quality
of 70% and resulted in better foamability, stability, and oil production
from tight matrices. This behavior can be attributed to the high water
content in the foam, which depleted the oil saturation inside the
porous medium more efficiently, leading to increased foamability and
higher foam stability. The results also demonstrated that a higher
total injection rate of 3 cc/min supported the generation of gas bubbles
and caused significant fracture–matrix interactions, diverting
more gas from the fracture to the rock matrix.