Fractures are important in improving tight sandstone pore connectivity and fluid flow capacity. However, the contribution of fractures to pore connectivity and fluid flow capability cannot be quantified using current methods. The objective of this study was to develop a method to quantitatively characterize reservoir improvement as a result of fractures. This method was proposed based on the experimental results of 37 core samples recovered from the Upper Triassic Chang 8 tight sandstone in the Jiyuan area of the Ordos Basin, China. The morphological features of the porosity spectra, the mercury injection capillary pressure curves, and the pore-throat radius distributions were analyzed. Accordingly, a method was proposed to construct pseudocapillary pressure (P-c) curves from the porosity spectra to characterize the pore structure of fractured reservoirs and to establish corresponding models based on the classified power function method. In addition, a model was developed to predict fracture formation permeability based on the Swanson parameter. The proposed method and models were applied in field applications, and the estimated results agreed well with the core and drill-stem testing data. Fractured formations contained good pore structure, high permeability, and oil production rata. The relative errors between the model-predicted pore structure evaluation parameters, permeability from P-c curves, and core-derived results are all within +/- 30.0%. With the integrated study of reservoir pore structure with permeability, the effective Upper Triassic Chang 8 fractured tight sandstone reservoirs with development potential were successfully identified.