Low to ultra-low permeability tight oil reservoirs have recently become a significant source of hydrocarbon supply in North America. Production and pressure transient analysis of tight oil reservoirs is one of the most difficult problems facing a reservoir researcher because of the extreme complexity inherent in tight formations, such as producing from multiple layers with effective permeability that is often enhanced by hydraulic fracturing. Unfortunately, limited productivity and unfavorable economics often prevent expenditures of money and time to collect the dynamic data needed for a comprehensive reservoir study. Horizontal well completion along with multi-stage hydraulic fracturing techniques has enabled economic production from these kinds of reservoirs. To produce oil and gas commercially from tight formations, naturally completed (open-holed) or cased horizontal wells with multi-stage hydraulic fractures are the most popular implementation for completion. The use of a combination of the multifractured horizontal wells is expected to create a complex sequence of flow regimes (Chen and Raghavan, 1997; Clarkson and Pederson, 2010). The proper analysis and identification of presence of flow regimes and sequence of emerging flow regimes are essential for obtaining efficient information about hydraulic fracturing optimization and the tight formation characterization.

This thesis provides a detailed discussion of diagnostic plots of pressure and its corresponding derivative responses for hydraulically fractured horizontal wells in a sizable naturally fractured and homogeneous (single-porosity) formation and providestype-curving matching performance among different existing empirical rate-time relations and compared with simulation results based on the targeted Bakken and Viking Formation in Western Saskatchewan. We consider a naturally-completed (open-hole) and cased horizontal well with either single longitudinal or multiple transverse hydraulic fractures which are normal in the horizontal wellbore, and which might be surrounded by an area with natural fracture system which is simulated by dual-porosity idealization. The discussion is based on pressure-transient performances and characteristics of production data generated by employing a commercial reservoir simulator, CMG IMEX, a 3D finite difference reservoir simulation package which is widely and popularly accepted by petroleum industry. Pressure transient features are discussed and compared. As noted by many findings, it is shown that fully-filled and regional natural fractures would display various pressure transient characteristics and, hence, considerably affects well production performance. In addition, these conductive, interconnected natural fractures dominate the pressure transient performances of horizontal wells in tight formations even with the presence of hydraulic fractures. Additionally, the simulation runs also indicate that if the reservoir is naturally fractured to some extent, hydraulic fracturing stimulation might not improve productivity significantly, unless a large amount of hydraulic fractures and infinite conductivities can be achieved. To demonstrate the feasibility and applicability of simulation models, there is a representative contrast between the simulated pressure transient responses and the corresponding analytical results from the widely-accepted well test model, Kappa. The comparison discussion would be based on the matching performances of a horizontal well with transverse fractures in a homogeneous reservoir. Field case studies are also provided for type-curve fitting and predicting EUR estimation.