Results

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.

Abstract

Production from shale gas reservoirs depends greatly on the efficiency of hydraulic fracturing treatments. The cumulated experience in the industry has led to several best practices in treatment design, which have improved productivity of these reservoirs. However, further advancement of treatment design requires a deeper understanding of the complex physics involved in both hydraulic fracturing and production, such as stress shadow, proppant placement and treatment interaction with pre-existing natural fractures.

This paper sheds light on the non-linear physics involved in the production of shale gas reservoirs by improving the understanding of the complex relation between gas production, the reservoir properties, and several treatment design parameters. A fracturing-to-production simulation workflow integrating the Unconventional Fracture Model (Weng et al., 2011), with the Unconventional Production Model (Cohen et al., 2012) is presented. By applying this workflow to a realistic reservoir, we did an extensive parametric study to investigate the relation between production and treatment design parameters such as fracturing fluid viscosity, proppant size, proppant concentration, proppant injection order, treatment volume, pumping rate, pad size and hybrid treatment. The paper also evaluates the influence of unconventional reservoir properties - such as permeability, horizontal stress, horizontal stress anisotropy, horizontal stress orientation, Poisson's ratio and Young‘s modulus - on production. Since this paper focuses on fluid and proppant selection, our methodology was to run 28 simulations to cover the 2D parametric space of proppant size and fracturing fluid viscosity for all of these parameters. More than fourteen hundred simulations were run in this parametric study and the results provide guidelines for optimized treatment design.

This paper illustrates how this unique workflow can identifies the optimum fluid and proppant selection that gives the maximum production for a given reservoir and completion. In addition, the parametric study shows how these optimums evolve as a function of reservoir and treatment parameters. The results validate several best practices in treatment design for shale. For example, combination of different sizes of proppant optimizes production by maximizing initial production and slowing down production decline. Simulations also confirm the best practice of injecting the smallest proppant first. The study explains why slickwater treatments should be injected at maximum pumping rate and preferably with 40/70 mesh sand. It also illustrates why reservoirs with high Young's modulus (such as the Barnett shale) can be stimulated effectively with slickwater. Another key finding is that the optimum fluid viscosity increases with treatment volume.