Jiang Hanqiao

Numerical simulation study of shale gas reservoir with stress-dependent fracture conductivity using multiscale discrete fracture network model

ABSTRACT The exploitation of shale gas has increasingly become the focus of worldwide energy industry. Due to the existence of natural/hydraulic fractures, most of the shale gas reservoirs exhibit high degree of heterogeneity and complexity which leads to the stress-dependent fracture conductivity of shale gas reservoir. Discrete fracture network (DFN) model is adopted in this research since the conventional continuum model cannot meet the numerical simulation requirements of fractured shale gas reservoir. A series of experiments about the fracture properties stress-dependent have been conducted on some shale core samples, the stress-dependent fracture conductivity correlation is selected and incorporated into the mathematical model to characterize the reduction of fracture conductivity potential with the reservoir pressure drop. The DFN model is applied to a shale gas reservoir with fracture network to study the effect of the stress-dependent fracture conductivity on the shale gas well performance. The results show that the effect of fracture conductivity reduction with pressure drop on the shale gas well performance depends on both the initial fracture conductivity and matrix permeability. The complex interactions between the fracture and matrix permeability should be considered when select the appropriate size of proppants for fracturing.

Pressure transient analysis of arbitrarily shaped fractured reservoirs

Reservoir boundary shape has a great influence on the transient pressure response of oil wells located in arbitrarily shaped reservoirs. Conventional analytical methods can only be used to calculate transient pressure response in regularly shaped reservoirs. Under the assumption that permeability varies exponentially with pressure drop, a mathematical model for well test interpretation of arbitrarily shaped deformable reservoirs was established. By using the regular perturbation method and the boundary element method, the model could be solved. The pressure behavior of wells with wellbore storage and skin effects was obtained by using the Duhamel principle. The type curves were plotted and analyzed by considering the effects of permeability modulus, arbitrary shape and impermeable region.

Evaluation and selection of numerical simulation methods for shale gas reservoirs

The complex fracture network brings great challenge to the numerical simulation of shale gas reservoirs. Based on the discrete fracture model (DFM), micro scale model and field scale model are established to investigate the influence of fracture types on the reservoir performance when the correspondence of matrix permeability and fracture aperture is different. Results show that: because the magnitude of shale gas reservoir matrix permeability is (10−8–10−4)×10−3μm2 and the SRV is a prerequisite for shale gas production, hydraulic fractures play an important role in the shale gas production while the contribution of natural fractures in and out the SRV is relatively small. Therefore, considering the computational complexity and precision, natural fractures can be characterized by matrix-natural fracture apparent permeability model and continuum model while the hydraulic fracture can be characterized by the discrete fracture network (DFN) with less computational grids and high efficient.

Shale gas apparent permeability model couplingthe transport mechanisms in matrix and natural fractures

Shale gas reservoirs exist micropores, nanopores and natural fractures. The mode of gas occurrence and the transports mechanisms vary with the change of type pores. In this paper, a new shale gas apparent permeability model coupling the gas transport mechanisms in matrix pores and natural fractures is presented on the basis of the quantitative characterization of the natural fractures. The model is derived based on the permeability tandem-parallel model and considers the gas slippage effect, diffusion effect in nanopores and the flow characteristics in natural fractures. Sichuan Basin Niutitang group shale sample with natural fractures are used to verify the theoretical model. The results show that the analytical solution of the apparent permeability model not only can match the measured value in lab, but also accurately describes the flow features of interaction in matrix pores and natural fractures in the core internal. In short, the natural fractures quantitative characterization of shale gas reservoirs and the apparent permeability model considering the flow characteristics in the micropores, nanopores and natural fractures not only provides a new approach to the modeling of complex fractures network, but also further promotes the shale gas reservoirs discrete fracture network model numerical simulation for the industrial application.