| description abstract | Lower Silurian Longmaxi and Upper Ordovician Wufeng shales are gas-producing formations. These formations have ultralow porosity and permeability in the southeastern Sichuan Basin and have normal formation pressures with pressure coefficients of less than 1.2. Hydraulic fracturing has been proven as the best development strategy to produce gas. But choosing hydraulic fracture treatment parameters becomes challenging due to strong reservoir heterogeneity, significant horizontal stress contrast and high in situ stress in this region. We employed the pseudo-three-dimensional (P3D) model to study fracturing fluid types, injection rates, and proppant sizes to optimize the fracturing design of these shale formations. First, this model was solved in the simulator by the finite element method (FEM) to obtain the fracture height, length, and width. Then the results were validated by 3D Tip dominated model, and the perkins-kern-nordgren (PKN) and khristianovic-geertsma-deklerk (KGD) analytical models, which are popular and most used in designing hydraulic fractures. It was found that as the volumetric injection rate and gel loading in the fracturing fluid rise, so do the generated fracture length and width. Furthermore, the formations’ stress contrast affected the shape of the fracture, the interval with lower stress had a wider fracture compared to the interval with higher stress. Also, the higher stress in the layers above and below the shale formations contained the fracture height, which favored the growth of fracture in the shale formations. Lastly, it is suggested that a fluid with gel loading of 60 ppgt, proppant with 12/20 mesh size and an injection rate of 6.36 m3/min be used in these shale formations with normal reservoir pressure. These parameters’ combinations created the most extended propped fracture length of 264.8 m, and the average width was 1.06 cm. | |
