The oil and gas industry has long recognized the inadequacy of existing theories to predict the behavior and outcome of some hydraulic fracturing treatments. Data sets compiled over the last two decades are incompatible with the conventional picture of a single planar hydraulic fracture. These data sets include field studies, laboratory studies and theoretical models. Several field and laboratory observations show very complex fracture paths, multisegmented fractures, branching, asymmetry and the presence of multiple fractures. The purpose of this study is to investigate the pressure behavior of systems containing near wellbore and far field multiple vertical fractures. This objective is achieved by using two analytical models. These newly developed models are used to explore pressure behavior and to generate type curves using the pressure derivative concept. The first new analytical model considers a composite reservoir with the inner zone containing an arbitrary number of dendritic multiple hydraulic fractures and the outer zone showing natural fractures. Transient pressure, derivative and flow regimes of the fractured system are investigated using this model. This study also uses a numerical model to calibrate and validate the analytical model. Pressure transient behavior of multiple fractures is modeled using a full field model (FFM) with a detailed Cartesian local grid refinement (LGR) around the fractures. The model was calibrated and validated using the case of two wing fractures at 180o. Simulations of the two types of multiple fractures, dendritic and parallel, validate some results of the analytical solutions. The TDS technique is also used to analyze the linear and pseudo-radial flow regimes in order to find fracture length, angle between fractures, fracture conductivity and several conventional reservoir parameters, e.g. permeability, wellbore storage and skin. Multiple fractures create more surface area in direct communication with the wellbore. As a consequence, a greater volume of fluid can be produced from the wellbore per unit time. While fracture treatments continue to be designed using the best tools and techniques available, geometry estimates from fracture models have been difficult to verify. Pressure transient analysis is one of the fracture diagnostic techniques available to fill this knowledge gap, improving our understanding of hydraulic fracture behavior. It is an excellent calibration tool because it lets us evaluate the effective length of the fracture, and determine the appropriate length to use in history matching. Also, regardless of the application, identifying and understanding fracture complexities can lead to improved treatment designs, better completion strategies, and the potential for significant economic rewards through improved well performance and/or reduced completion cost.