The Fracturing Behavior in Layered Rocks

Abstract

Hydrocarbon or geothermal reservoir often consists of several rock layers from different lithology. The various lithologies have their own number of mechanical properties and the layering effect introduced the term of mechanical contrast, which represents the ratio of rock strength between adjacent layers. Mechanical contrast and confining pressure highly influence the fracture behavior in the layered rocks.
In this study, fractures in layered rocks are investigated, starting with its geometry and also the stress field contributed to the fracture generation and development. The fracture geometry such as fracture length, average aperture, aperture distribution and orientation are quantified in a two dimension slice image. The study focused on comparing the fracture behavior when (a) the layered rock compositions are the same between samples with increasing confining pressure or (b) the different compositions of layered rocks (different mechanical contrast) between samples in the same confining pressure.
The results show that fracture tends to propagate through layer interface when the mechanical contrast between adjacent layers and the confining pressure are low. The fracture in the weak layer developed at a gentler dip (shear fracture) with higher fracture aperture compared to the ones in the strong layer which almost vertical (tensile fracture). In addition, the shear fracture in the weak layer usually accompanied by the zone of cataclastic flow while the tensile fracture has a more clear pathway for fluid flow.
However, mode I opening/tensile fractures are less likely to affect fluid flow in the reservoir because their aperture is insignificant at depth. While in mode II sliding/shear fractures, only several parts along the fracture that can provide the open space, which depend on the presence of jogs and irregularities on the fracture surfaces.
The results from fracture measurements show that in the weak layer, average aperture and aperture distribution will reduce with the increasing of confining pressure, but increased with the increasing of mechanical contrast. Average fracture aperture and distribution have a significant role in capillary pressure. The higher average aperture will reduce the amount of pressure needed to flow the fluid, while a higher number of aperture standard deviation (aperture distribution) has a contrasting effect. The average aperture has a bigger impact on capillary pressure compare to aperture distribution. Thus, by increasing the confining pressure or decreasing the mechanical contrast, the required pressure for fluid to flow is increasing.
Furthermore, the numerical modeling is performed by imitating the rock mechanical properties and the fracturing conditions from the laboratory experiment. The results show that under compressive stresses, the layered rocks still generate tensile stresses around the interface within the strong layer. The tensile stresses occur because of the stress transfer between adjacent stiff and soft layer with a bonded interface. The presence of tensile stress and the crack-tip stress are responsible for the generation of the tensile fracture in the strong layer for all samples.
The effect of varying the number of confining pressure, Poisson’s ratio and Young’s modulus on the tensile stresses distribution are also performed. The sensitivity study shows that Poisson’s ratio has a more significant impact compared to Young’s modulus on both maximum tensile stress and thickness of tensile region. Higher Poisson’s ratio resulting in higher tensile stresses, while on Young’s modulus it depends on the contrast between adjacent layers rather than the magnitudes.
Understanding the fracture behavior in layered rocks is beneficial for reservoir characterization, as fractures can enhance the permeability and providing vertical connectivity between isolated reservoirs. Accurately interpret 3D natural fracture distribution can help the estimation of the resource and recoverable potential early in field life. It will also contribute to optimizing the well placement and completion design for efficient production planning.