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As an effective approach to evaluate shale gas production, macroscale numerical simulations have been conducted; however, multiscale storage space and complex gas–water two-phase transport mechanisms are not systematically considered. To deal with this, a rigorous cross-scale gas–water two-phase transport simulation method that considers the pore, core, and field scale is proposed herein. First, to investigate the fluid storage state in different pore types during the gas–water two-phase transport process, a shale pore network gas–water transport simulation is conducted. Subsequently, a core-scale model that considers the distribution of organic matter is constructed, and the gas–water two-phase transport behaviors are upscaled from the pore to the core by incorporating nanomicroscale effects. Next, a shale gas–water two-phase macroscale numerical simulation is implemented based on the core-scale simulation results. Multiple interacting continua are used to describe the shale matrix and microfractures, whereas the embedded discrete fracture method is employed to represent hydraulic fractures. Finally, the manner by which nanomicroscale effects, stress sensitivity, and SRV area affect the production of shale gas reservoirs is discussed comprehensively. This study provides a practical method to estimate shale gas production by rigorously considering gas–water nanomicroscale effects to reduce uncertainties during productivity evaluation. [ABSTRACT FROM AUTHOR]

This paper presents an integrated study from fracture propagation modeling to gas flow modeling and a correlation analysis to explore the key controlling factors of intensive volume fracturing. The fracture propagation model takes into account the interaction between hydraulic fracture and natural fracture by means of the displacement discontinuity method (DDM) and the Picard iterative method. The shale gas flow considers multiple transport mechanisms, and the flow in the fracture network is handled by the embedded discrete fracture model (EDFM). A series of numerical simulations are conducted to analyze the effects of the cluster number, stage spacing, stress difference coefficient, and natural fracture distribution on the stimulated fracture area, fractal dimension, and cumulative gas production, and their correlation coefficients are obtained. The results show that the most influential factors to the stimulated fracture area are the stress difference ratio, stage spacing, and natural fracture density, while those to the cumulative gas production are the stress difference ratio, natural fracture density, and cluster number. This indicates that the stress condition dominates the gas production, and employing intensive volume fracturing (by properly increasing the cluster number) is beneficial for improving the final cumulative gas production. [ABSTRACT FROM AUTHOR]

Geologic storage of CO 2 in shale formation not only enhances natural gas recovery, but also sequestrates CO 2 effectively. According to this technology, a multi-continuum quadruple porosity binary component gas model is developed to investigate carbon dioxide storage capacity and CO 2 enhanced shale gas recovery, which is based on multiple flow mechanisms, including dissolution, adsorption/desorption, viscous flow, diffusion, slip flow and stress sensitivity of hydraulic fractures. This fully coupled model is divided into quadruple media, including organic matters, organic pore system, matrix system and natural fracture system. The matrix-fracture transfer flow is simulated by modified multiple interacting continua (MINC) method. Embedded discreate fracture model (EDFM) is introduced to describe the gas flow in hydraulic fractures and the transfer flow between hydraulic fractures and natural fractures. Finite difference method (FDM) and quasi-Newton iterative method are applied to solve this model. The reliability and practicability of this model is validated by matching the production history of a fractured horizontal well in shale gas reservoir. The effects of relevant parameters on production curves are analyzed, including adsorption parameters, dissolution parameters, well production pressure, injection pressure, volumetric fraction of kerogen and injection opportunity. The result shows that the model in this work is reliable and practicable, and the model presented here can be used to investigate the injectivity of CO 2 and CO 2 enhanced shale gas recovery. • Developing a multi-continuum quadruple porosity binary component gas model. • Considering multiple flow mechanisms for binary component gas. • Solving this model by finite difference method and quasi-Newton iterative method. • Estimating CO 2 storage capacity and CO 2 enhanced shale gas recovery. • Simulating fracture-matrix transfer flow by modified multiple interacting continua method. [ABSTRACT FROM AUTHOR]

The composite shale gas reservoir consists of an inner and an outer region. Inner region is stimulated reservoir volume (SRV) and contains shale matrix and natural fractures. Outer region represents un-stimulated reservoir volume (USRV) and contains shale matrix only. The interface boundary between SRV and USRV is often arbitrarily shaped rather than the regular, which can be derived from micro-seismic events of shale gas reservoirs with multiple fractured horizontal well (MFHW) Considering arbitrary interface boundary between SRV and USRV and outer boundary, a composite model is presented for MFHW in composite shale gas reservoirs, which based on multiple mechanisms, including adsorption/desorption, viscous flow, diffusive flow and stress sensitivity of natural fractures. Boundary element method (BEM) is introduced to solve the pressure response of MFHW in composite shale gas reservoirs. The accuracy of this model is validated by comparing its pressure response solution with the result derived from an analytical and a numerical method, respectively. According to pressure performance analysis of MFHW in composite shale gas reservoirs, eight flow regimes are identified: the early linear flow, the early radial flow, the second linear flow, the second radial flow, inter-porosity flow from shale matrix to natural fractures, the transition flow, diffusive flow and the third radial flow. The effects of relevant parameters on pressure response are analyzed, including mobility ratio, storability ratio, inter-porosity coefficient, diffusion coefficient, adsorption index and the shape of interface boundary. The result shows that BEM can be perfectly used to analyze the pressure performance of MFHW of composite shale gas reservoirs with arbitrary shaped interface boundary and outer boundary; the presented model can be used to interpret pressure data more accurately for shale gas reservoirs and provide more accurate dynamic parameters which are important for efficient reservoir development. [ABSTRACT FROM AUTHOR]