Hydraulic fracturing of a naturally-fractured reservoir is a challenge for industry, as fractures can have complex growth patterns when propagating in systems of natural fractures in the reservoir. Fracture propagation near a natural fracture (NF) considering interaction between a hydraulic fracture (HF) and a pre-existing NF, has been investigated comprehensively using a two dimensional Displacement Discontinuity Method (DDM) Model in this thesis. The rock is first considered as an elastic impermeable medium (with no leakoff), and then the effects of pore pressure change as a result of leakoff of fracturing fluid are considered. A uniform pressure fluid model and a Newtonian fluid flow model are used to calculate the fluid flow, fluid pressure and width distribution along the fracture. Joint elements are implemented to describe different NF contact modes (stick, slip, and open mode). The structural criterion is used for predicting the direction and mode of fracture propagation. The numerical model was used to first examine the mechanical response of the NF to predict potential reactivation of the NF and the resultant probable location for fracture re-initiation. Results demonstrate that: 1) Before the HF reaches a NF, the possibility of fracture re-initiation across the NF and with an offset is enhanced when the NF has weaker interfaces; 2) During the stage of fluid infiltration along the NF, a maximum tensile stress peak can be generated at the end of the opening zone along the NF ahead of the fluid front; 3) Poroelastic effects, arising from fluid diffusion into the rock deformation can induce closure and compressive stress at the center of the NF ahead of the HF tip before HF arrival. Upon coalescence when fluid flows along the NF, the poroelastic effects tend to reduce the value of the HF aperture and this decreases the tension peak and the possibility of fracture re-initiation with time. Next, HF trajectories near a NF were examined prior to coalesce with the NF using different joint, rock and fluid properties. Our analysis shows that: 1) Hydraulic fracture trajectories near a NF may bend and deviate from the direction of the maximum horizontal stress when using a joint model that includes initial joint deformation; 2) Hydraulic fractures propagating with higher injection rate or fracturing fluid of higher viscosity propagate longer distance when turning to the direction of maximum horizontal stress; 3) Fracture trajectories are less dependent on injection rate or fluid viscosity when using a joint model that includes initial joint deformation; whereas, they are more dominated by injection rate and fluid viscosity when using a joint model that excludes initial joint deformation.

Frac-pack design is still done on conventional hydraulic fracturing models that employ linear elastic fracture mechanics. However it has become evident that the traditional models of fracture growth are not applicable to soft rocks/unconsolidated formations due to elastoplastic material behavior and strong coupling between flow and stress model. Conventional hydraulic fracture models do not explain the very high net fracturing pressures reported in field and experiments and predict smaller fracture widths than expected. The key observations from past experimental work are that the fracture propagation in poorly consolidated sands is a strong function of fluid rheology and leak off and is accompanied by large inelastic deformation and shear failure leading to higher net fracturing pressures. In this thesis a numerical model is formulated to better understand the mechanisms governing fracture propagation in poorly consolidated sands under different conditions. The key issues to be accounted for are the low shear strength of soft rocks/unconsolidated sands making them susceptible to shear failure and the high permeabilities and subsequently high leakoff in these formations causing substantial pore pressure changes in the near wellbore region. The pore pressure changes cause poroelastic stress changes resulting in a strong fluid/solid coupling. Also, the formation of internal and external filtercakes due to plugging by particles present in the injected fluids can have a major impact on the failure mechanism and observed fracturing pressures. In the presented model the fracture propagation mechanism is different from the linear elastic fracture mechanics approach. Elastoplastic material behavior and poroelastic stress effects are accounted for. Shear failure takes place at the tip due to fluid invasion and pore pressure increase. Subsequently the tip may fail in tension and the fracture propagates. The model also accounts for reduction in porosity and permeability due to plugging by particles in the injected fluids. The key influence of pore pressure gradients, fluid leakoff and the elastic and strength properties of rock on the failure mechanisms in sands have been demonstrated and found to be consistent with experimental observations. / text