Existing techniques for the interpretation of real-time fracturing data assumes that fracture propagation is a continuous power function of time, and that fractures propagate smoothly over time. This assumption implies that the formation is homogeneous. However, this assumption is not always accurate, as heterogeneities such as natural fractures exist, especially in shale. The presence of natural fractures is a vital factor in the productivity of shale oil and gas formations. When a hydraulic fracture intercepts a natural fracture, we believe one of two situations may take place depending on stress field, net pressure, orientation and the type of natural fracture: • The hydraulic fracture may cross the natural fracture and essentially continue to propagate, thus a smooth fracture propagation would be reflected in the real-time pressure data. • The natural fracture may dilate, allowing the fracturing fluid to enter the natural fracture. In this case, the propagation of the hydraulic fracture will cease in favor of the dilation of the natural fracture. Once the natural fracture is sufficiently dilated, the hydraulic fracture will resume propagation from the tip of the natural fracture(s). This paper presents a new real-time analysis technique of fracture propagation data that accounts for this intermittent hydraulic propagation in shale formations. This technique is an expansion of the existing technique originally developed by Nolte and Smith (1981). A few examples from shale formations are also presented, in which a horizontal well was fractured using a multi-stage fracturing technique. The analyzed data clearly shows the opening and dilation of the natural fractures. The ability to interpret fracturing pressure data as the treatment is progressing enhances the operator’s ability to modify the fracture design in response to real-time events to help avoid problems or to enhance success. When fracturing shale formations, it would be advantageous to be able to enhance far-field complexity by modifying the proppant schedule or injection rate at the right moment. The developed fracturing pressure data interpretation may also be linked to fracture design modeling and/or microseismic interpretation during the fracturing treatment or in a post-treatment evaluation process. This connection would yield interpretation advantages over the current practice. The Nolte-Smith technique for analyzing fracturing pressure data depends on the coupling of the power law for fracture propagation and fluid pressure and, through dimensional analysis, develops four possible scenarios describing the various modes of fracture behavior. Although this technique is very valuable and has a quantitative element to it, it still has a strong dependence on the judgment of the operator. A problem is often caught too late in time to take corrective measures except to terminate the treatment. Additionally, the response time is further delayed due to the logarithmic nature of the plotting technique. Two main fracturing models have been developed in the industry—one by Perkins and Kern (1961) and another by Kristianovich and Zheltov (1955). The two models have been modified by several authors such as Nordgen (1972), Daneshy (1978), Geertsma and De Klerk (1969), Haimson and Fairhurst (1967), and others. Both the real-time analysis technique by Nolte-Smith (1981) and the new technique rely on the model developed by Perkins and Kern (1961), as modified by Nordgen. According to the Perkins-Kern model, the fracturing pressure at the wellbore is a power function of time as shown in equation 1.