In this work, a new type of flooding system, "worm-like micelles", in enhanced heavy oil recovery (EOR) has been introduced. Application of these types of surfactants, because of their intriguing and surprising behaviour, is attractive for EOR studies. Fundamental understanding of the sweep efficiencies as well as displacement mechanisms of this flooding system in heterogeneous systems especially for heavy oils remains a topic of debate in the literature. Worm-like micellar surfactant solutions are made up of highly flexible cylindrical aggregates. Such micellar solutions display high surface activity and high viscoelasticity, making them attractive in practical applications for EOR. In this study, worm-like micellar solutions were used for flooding experiments in micromodels, initially saturated with heavy crude oil. The fractured micromodels with different fracture geometrical properties, different orientation angles and length, were used in the tests under oil-wet condition. During experiments, high quality pictures of injection processes were recorded. Oil recoveries as a function of injected pore volumes and microscopic mechanisms during displacements were investigated from precise analyses of the provided pictures. It was observed that three mechanisms govern the EOR process during worm-like micellar solution flooding: ultra-low interfacial tension, high viscosity of the injecting fluid and in situ formation of macro-emulsion. Considering these mechanisms, worm-like micellar surfactants solutions are potentially good choices for EOR in heterogeneous systems such as fractured reservoirs. This study illustrates that the application of worm-like micelles for heavy oil recovery in heterogeneous systems can reduce the risks involved with heterogeneity on flooding performance in such reservoirs.

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Horizontal wells with multiple fractures are becoming more prevalent in the Industry. They can especially beneficial in gas condensate reservoirs to minimize the pressure drop in order to reduce liquid drop-out and reduce the severe loss of well productivity and therefore lower gas recovery. Reliable evaluations of stimulation performance are required for field development planning. As such, pressure transients are often used, and can be successful, to observe and define the various impacting factors of stimulation, such as fracture length, conductivity, orientation, etc.This project investigates the modeling and interpretation of pressure transient responses of multiple hydraulic fractured horizontal wells in gas condensate reservoirs using a numerical reservoir model with a focus on the existence of different mobility zone due to condensate dropout. Derivative shapes expected from hydraulic fractured horizontal well-test data are obtained using a 3D fully compositional model in gas condensate reservoirs below the dew point under various conditions. The numerical model is validated using an analytical solution and applied to a simple reservoir model. Complex reservoirs are then simulated and pressure transient response signatures are obtained. Sensitivity studies of important reservoir, well and fracture properties are performed and a result of each case is presented.It was found that condensate dropout near the wellbore yields a well-test composite behavior; similar to what is found in hydraulically fractured vertical wells, but superimposed on a horizontal well behavior, which makes it much more complex. Furthermore a higher gas production will be achieved in a horizontal well with optimum number of fractures, fractures conductivity and fracture half length which may depend on formation and hydrocarbon characteristics.

This work presents a laboratory phase behavior study of Sodium Stearate/brine/oil system. The quantitative and qualitative observation of the phase behavior of the microemulsion in a three phase brine/oil/emulsion system is reported (Winsor III). The experiments were designed to investigate the stability, interfacial tension (IFT), and viscosity of the emulsion phase in a wide range of temperature (25-60 °C), water-to-oil ratio (0.2 to 5), salinity (10 to 200,000 ppm), and surfactant concentration. The range of parameters was selected as what typically occur during a chemical enhanced oil recovery (EOR) process. The effect of pH variations was also studied by changing that of the system from 1 to 11, using different acid and alkalines. As the pH increases, the stability of the emulsion phase increases as well as the emulsion phase thickness. The viscosity of the emulsion phase was also monitored qualitatively for different temperatures. Moreover, using longer chain alkanes confirms the capability of the surfactant for chemical EOR process.