Hydraulic fracturing with leakoff in a dual porosity medium

Hydraulic fracturing is a key method in the stimulation of shale gas reservoirs. Shale gas formations often contain natural fractures which are fluid-pressure sensitive and dilate in response to the inflation of the fracture, increasing fluid loss and slowing down and prematurely arresting fracture propagation. Models typically assume 1-D single-porosity/permeability leakoff perpendicular to the hydraulic fracture. However, the leakoff process in naturally fractured formation is considerably more complex. We present a hydraulic fracturing model based on the PKN-formalism which accommodates the leakoff into a dual porosity medium. Proppant transport is accommodated by introducing empirical constitutive equations to determine the proppant distribution during the hydraulic fracturing treatment assuming that only the major hydraulic fractures remain propped. The model is solved numerically and is validated against known asymptotic solutions. It is shown that the model is capable of providing a rapid estimation of the morphology of hydraulic fractures in naturally fractured formations and the corresponding proppant distribution. The simulation results illustrate that the leakoff into a dual porosity medium, where fracture permeability is a strong function of applied fluid pressure, results in a reduced length of the propagating fracture due to the fugitive fluid leakoff from the fracture into the surrounding formation and that this in turn results in a reduced maximum width during the treatment. This observation is important as this significantly influences the ability to infuse fracture-maintaining proppants into the accessed reservoir at desired large distances from the injection wellbore due to the earlier screen-out and may compromise the ultimate efficiency of the final hydraulic fracture in relation to gas recovery.