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Hydraulic fracturing creates a fracture network that enhances the hydrocarbon flow from the tight reservoir where the proppant migration determines the conductivity of the propped fracture, and thus, the well productivity. Core observations from the Hydraulic Fracturing Test Site (HFTS) show that hydraulic fractures are denser than initially designed and most of them are not well propped. Understanding the proppant migration in the thin and rough fracture is crucial to the optimization of the pumping scheme in the field. In this work, a transparent rough fracture model is duplicated from a hydraulically fractured outcrop by the epoxy resin with the dimension 300 mm × 300 mm × 300 mm. The settling rate of sands is quantified in this rough fracture model under different mimicked pumping conditions, from which a model is built to help estimate the growth of propped hydraulic fracture under different pumping rates, sand ratios, sand diameters, and fracturing time during field operations. The model corrects the classic Stokes' law for proppant settlement within a narrow and rough fracture. Results indicate that the equilibrium height and migration rate of the sandbank increase with the sand ratio and decrease with the pumping rate. After being compared with results obtained from Fluent simulations, a numerical model is further proposed to predict the growth of a propped fracture in the field scale.

The low-permeability reservoir is mainly featured by small reservoir pore, tight, fine throat, high filtration resistance, and low oil productivity. After several years of working to recover hydrocarbons from these reservoirs effectively, it has been proven that creating complex fracture networks by multi-stage fracturing is one of the most efficient ways to enhance production. However, several factors affect the development of the complex fracture networks, and the in-situ stress is the most significant one. Low in-situ stress anisotropy [1] increases the possibility of creating complex fracture networks with hydraulic fracturing. In order to compensate for the in-situ stress anisotropy, based on the application of a numerical model coupled flow and geomechanics, this research analyzes the variation of in-situ stress and suggests arranging a sequence of horizontal well deployment. In addition, the research predicts the dynamic productivity coupled flow and geomechanics. From the results, this research concludes the dynamic change regularity of in-situ stress and the impact of difference well deployment, which is beneficial to optimize horizontal well deployment and fracturing design [2].

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