Fracturing and fracture reorientation in unconsolidated sands and sandstones

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Zhai, Zongyu

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Data clearly show that fracturing in poorly-consolidated rocks is not adequately represented by traditional models for brittle, linear-elastic rocks. Unconsolidated sands do not exhibit brittle- elastic behavior. In addition, sands have very low tensile and shear strengths. A model is presented for the propagation of “fractures” in unconsolidated sands. The model departs radically from current models in that brittle fracture mechanics is not used. Instead the propagation of pore pressure is computed and the porosity and permeability of the sand is specified as a function of the effective stress. This results in the creation of an anisotropic zone of increased porosity and permeability along the plane of maximum in-situ stress. This region of enhanced porosity and permeability defines a “fracture” in unconsolidated sands. The physics of creation and propagation of this oriented, high permeability zone, is modeled for the first time. It is shown that in-situ stress anisotropy plays a very important role in determining the dimensions of this fracture zone. In addition, the permeability anisotropy generated due to the stress anisotropy in the sand is the critical driving force behind the creation of the oriented fracture. The injection or production of large volumes of fluid into or from a reservoir can result in significant changes to the in-situ stress distributions. Field evidence of this has been provided in the past in water-flooded reservoirs. A poro-elastic model is presented to show how the extent of fracture reorientation can be estimated under different conditions of fluid injection and production. It is shown that the principal horizontal stresses are altered by pore pressure gradients. The extent of fracture reorientation is a function of the in-situ stresses, the mechanical properties of the rock and the pore pressure gradients. In reservoirs where the pore pressure gradients are complex due to multiple injection and production wells, fracture reorientation is sensitive to the net pore-pressure gradients. Fractures tend to reorient themselves away from injection wells and towards production wells, if the pressure gradients are comparable to the in-situ stress contrast.