A study was carried out to determine the geomechanical effects of polymer flooding in an unconsolidated sand reservoir. The work involved laboratory-scale polymer injections in unconsolidated sand blocks to identify the injectivity mechanisms, numerical analyses for fracture prediction, and geomechanical modeling of the formation to examine the potential of shear failure and containment loss during flooding.

Laboratory tests under polyaxial conditions indicate that near-wellbore fracturing and permeability increase in unconsolidated sands occurs at net injection pressures limited to 2.0 MPa. These findings were applied to fracture modeling. Geomechanical modeling suggests large-scale shear failure in the sand and in the bounding shale during polymer flooding. These are expected to affect both the fracture containment and the vertical-hole integrity. Finally, fracture predictions underscore the importance of the geomechanical considerations on determining the fracture dimensions and containment. Sensitivity analyses also point to the significance of bounding several key parameters for fracture prediction. These include sand-shale stress contrast, fluid quality and TSS content, fluid rheology and effective viscosity in the formation, and the filtercake properties in the presence of polymer.

This paper is intended to provide a geomechanical perspective on the generally complex problem of polymer flooding in unconsolidated formations containing viscous oil. The work also offers some insights into the critical issues that must be examined in such situations to avoid catastrophic failures, and highlights the existing technological gaps in the current predictive capabilities.


Some of the unconsolidated sand formations both onshore and offshore contain high viscosity oil and might be considered for polymer flooding to improve recovery. Flooding in unconsolidated sand could lead to "fracture" propagation. Although such formations typically have high permeability in the order of several Darcies, the minute quantities of impurity and solids present in the injection fluid can plug the sand face over time and lead to fracturing, if the injection rate is to be maintained [1]. Even in the absence of any fines and solids contaminants in the fluid, the high in-situ oil viscosity and low polymer mobility could instigate fracture propagation if the injection rate is sufficiently large.

The principal concerns about fracturing during flooding pertain to length control and vertical containment. The fracture length must be limited to avoid interception with the production wells. Moreover, the fracture half-length must be typically less than one-third of the distance between the injector and producer to obtain good areal sweep and to ensure that fracture growth will not be detrimental to the pattern sweep, regardless of the principal horizontal stress orientation in the reservoir. For unconsolidated sands, there are currently no theoretically sound techniques to predict the fracture geometry and whether or not a fracture would be contained within the reservoir. Since the stress contrast between the sands and shales in unconsolidated formations is typically small, determination of containment requires a better understanding of the propagation mechanisms at the interface.

This content is only available via PDF.
You can access this article if you purchase or spend a download.