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This paper investigates the reduction in gas mobility during the EOR (enhanced oil recovery) process of gas injection due to the presence of foam, thereby increasing sweep efficiency. The presented work is focused on developing a systematic approach to tune the CO2 foam parameters based on two separate core flooding experiments, the former conducted at variable foam qualities while the latter at a fixed foam quality. The paper discusses the experimental data required for the modeling of mobility control using CO2-foam for a high temperature, high salinity layered carbonate reservoir. An empirical foam model is used for parametric matching of laboratory data, and foam parameters are calculated and tuned. The key objective of the model is not only to match the measured apparent foam viscosity for varying foam qualities but also be able to capture the pressure drop measured for various experimental runs. The tuned foam model can be applied to field scale and design the injection strategy to maximize the oil recovery.

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Augmented by the recent activities in unconventional reservoirs, it can be easily said that hydraulic fracturing has become a pivotal component for the successful development of unconventional reservoirs. This novel study deals with the investigation of fracture propagation behavior in shale gas reservoirs under varying controllable and non-controllable parameters. In addition to the analysis of propagation behavior, their interaction in the presence of natural fractures are reviewed and quantified. It is highly challenging to quantify and address the distinct contributions of an element due to the level of heterogeneity that is present in reservoirs. In-situ stress has been reported to be such a dominant contributor to the fracture propagation behavior as they are imperative to assess the extent and the direction of fractures. An enhanced dynamic simulation was conducted to investigate fracture propagation behavior in shale gas reservoirs under varying parameters which were categorized as controllable and non-controllable with respect to the fracture design, treatment and drilling process. After an extensive assessment, a set of natural fractures were introduced to the system and the system behavior was further analysed. The constructed model is verified with traditional and published models to validate the generated results. It is illustrated that even modest variations of the associated principal stresses between the target zones and the bounding zones can severely limit hydraulic fractures. Further simulation runs under varying fluid conditions and its associated properties revealed similar observations. With the introduction of natural fractures, it is demonstrated that the distribution of the natural fracture network plays a critical role in the cumulative gas production along with its description. Additional investigation illustrates and verifies that fracture width assists in better performance as compared to fracture length for the defined conditions. Fracture placement along with its orientation and proppant properties are also considered to further examine the associated response on productivity. This novel investigative approach will create a paradigm for future studies that will assist in a simplified prediction of fracture propagation behavior, its associated drilling parameters and anticipated response. In addition, an extensive investigation for the quantification of changes with respect to the variation in prime contributors is presented, which assists in the validation of modern best practices approach.

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