A model is developed for petrophysical evaluation of naturally fractured reservoirs where dip of fractures ranges between zero and 90, and where fracture tortuosity is greater than 1.0. This results in an intrinsic porosity exponent of fractures (m(f)) that is larger than 1.0. The finding has direct application in the evaluation of fractured reservoirs and tight gas sands, where fracture dip can be determined, for example, from image logs. In the past, a fracture-matrix system has been represented by a dual-porosity model which can be simulated as a series-resistance network or with the use of effective medium theory. For many cases both approaches provide similar results. The model developed in this study leads to the observation that including fracture dip and tortuosity in the petrophysical analysis can generate significant changes in the dual-porosity exponent (m) of the composite system of matrix and fractures. It is concluded that not taking fracture dip and tortuosity into consideration can lead to significant errors in the calculation of water saturation. The use of the model is illustrated with examples.