Search

The multiphase flow behavior in shale porous media is known to be affected by multiscale pore size, dual surface wettability, and nanoscale transport mechanisms. However, it has not been fully understood so far. In this study, fractal model of gas–water relative permeabilities (RP) in dual-wettability shale porous media for both injected water spontaneous imbibition and the flow back process are proposed using fractal geometry. The shale pore structure is described as tortuous with different pore sizes and morphologies including slit pore, equilateral triangle, circular pore and square pore. The proportion of each pore morphology can be obtained from SEM/FIB-SEM pore structure characterization results. Injected water spontaneous imbibition after hydraulic fracturing is modeled as the capillary force dominated process and injected water flow back is modeled as a non-wetting gas phase drainage process in inorganic matter. The organic pores are deemed to be not accessible by injected water. The boundary slip of water and free gas flow in the inorganic matrix are considered while both free gas flow and adsorbed gas flow are modeled in organic matter. The proposed gas–water RP fractal model is verified via comparisons with the available experimental data and is discussed in detail. Study results reveal that gas phase RP increases with increasing pore fractal dimensions and tortuosity fractal dimensions, whereas it decreases with increasing Total Organic Carbon (TOC) volumes. Water phase RP decreases with increasing of pore fractal dimensions and tortuosity fractal dimensions, whereas it increases with increasing TOC volumes. [ABSTRACT FROM AUTHOR]

Duo to different transport mechanisms and gas storage in organic and inorganic systems, a new triple-continuum model coupling Discrete Fracture Model (DFM) was established to investigate gas flow in shale gas reservoir. Considering the multi-scale and heterogeneity of shale matrix, fractal theory was used to calculate the apparent permeability of organic and inorganic systems while multiple gas transport mechanisms such as viscous flow, Knudsen diffusion, surface diffusion, gas absorption/desorption effect and real gas effect were incorporated. This coupled mathematical model was solved by Finite Element Method (FEM) and the presented fractal apparent permeability model was validated with the experimental data. The results show that fractal characteristics of shale matrix have great impact on gas reservoir performance. The model without considering the influence of fractal characteristics could lead to underestimate gas production by approximately 17%. Viscous flow is the dominate transport mechanisms of shale gas and Knudsen diffusion has an impact on gas flow when the pressure declines. Surface diffusion should be only considered in organic systems and can be ignored. Then the results of sensitivity analysis show that the characteristic parameters of inorganic matter have a greater impact than those of organic matter and establishing a triple-continuum model with considering comprehensive effect of organic and inorganic matter is necessary. In addition, gas production would decrease as the pore fractal dimension and tortuosity fractal dimension increase, which results from the increasing number of small pores and more tortuous path for gas flow. [ABSTRACT FROM AUTHOR]

Shale gas storage and transport mechanisms are notably different in kerogen systems and inorganic matrix systems. Based on these complex shale gas transport mechanisms, including viscous flow, Knudsen diffusion, surface diffusion and gas adsorption/desorption on the internal kerogen grain surfaces, a kerogen – inorganic matrix – fracture triple-continuum model is established. There are two transfer terms in the triple-continuum model in this paper. The kerogen – inorganic matrix transfer flow is simulated by the Warren-Root pseudo-steady state (PSS) transfer model, while the inorganic matrix – fracture transfer flow is simulated by the Vermeulen transient transfer model. To investigate the impact of the kerogen continuum on shale gas reservoir performance, a comparison between the matrix – fracture dual-continuum model and kerogen – inorganic matrix – fracture triple-continuum model is conducted. The matrix – fracture transfer flow in the dual-continuum model is also simulated by the Vermeulen transient transfer model. In addition, two triple-continuum models with different inorganic matrix – fracture transfer models are compared to investigate the impact of the transfer model. One triple-continuum model uses the Warren-Root PSS transfer model. The other uses the Vermeulen transient transfer model. The mathematical model is solved by the PDE module of COMSOL Multiphysics. A sensitivity analysis of parameters affecting shale gas production, including kerogen pore volume, kerogen permeability, inorganic matrix permeability, fracture permeability and Langmuir parameters, is conducted. The results indicate that dividing the matrix system into a kerogen continuum and inorganic matrix continuum significantly influences shale gas reservoir performance. Not considering the kerogen continuum could lead to an overestimate in cumulative gas production of approximately 8%. The triple-continuum model that uses the Vermeulen transient transfer model yields a higher recovery than that which uses the Warren-Root PSS transfer model. Moreover, natural fractures are the main permeable channels in shale gas reservoirs and play a more important role than the kerogen and inorganic matrix in shale gas recovery. Langmuir pressure and Langmuir volume also have significant effects on the cumulative production of desorbed gas, free gas and total gas, with the effect of Langmuir volume being relatively larger. In conclusion, a triple-continuum model with a transient transfer term should be incorporated into the numerical simulators of shale gas reservoirs to predict shale gas production more accurately. [ABSTRACT FROM AUTHOR]

• A DAGP model is proposed based on shale geostatistical and petrophysical data. • A representative model is constructed by fractal organic matter particles. • DAGP exhibits different patterns, depending on a high or low matrix Young's modulus. • The impact of OM pores development degree on DAGP can be ignored at TOC < 5%. Current shale gas apparent permeability models often fail to integrate morphological properties of multiple storage spaces and various transport mechanisms. To deal with this, we propose a comprehensive model for estimating the dynamic apparent gas permeability (DAGP) during depressurization based on a representative model. First, dual fractal characteristics of organic matter (OM) particles and inorganic matter (IOM)/OM pores along with morphological information of OM particles from scanning electron microscope (SEM) images are considered to establish the representative model conditioned to a total organic carbon (TOC) content. Next, multiple transport mechanisms and a pore size change due to a poromechanical response and desorption-induced volumetric strain are incorporated in the DAGP calculation. Results reveal that the controlling factor of the DAGP comes from pore size shrinkage owing to a poromechanical response to gas transport mechanisms during depressurization at a high Young's modulus, while the DAGP is totally controlled by a poromechanical response at a low Young's modulus. The critical TOC content is determined to be about 5% at which the influence of the degree of OM pore development can be neglected. This work provides a practical method to estimate the DAGP from both geostatistical and petrophysical perspectives, which effectively decreases the uncertainty during productivity prediction in shale gas reservoirs and other unconventional reservoirs. [ABSTRACT FROM AUTHOR]

Because of the complex pore structure and multiple types of gas storage, the traditional Darcy permeability model is not valid for describing shale gas flow. In this paper, an upscaled transport model is established based on homogenization theory to consider multiple transport mechanisms and the heterogeneity of shale samples. This new transport model is employed to successfully explain pressure decay experimental data. The results show that absorbed gas cannot be ignored in pressure decay experiment and the pressure difference decreases rapidly when the absorbed gas is not considered. Then several critical conclusions have been drawn as follows. The permeability anisotropy for stochastic distribution model can be ignored and the effective permeability will be underestimated by double porosity model if surface diffusion dominates gas flow in shale reservoir. In addition, shale gas transport is dominated by Knudsen diffusion when the pore pressure is below 2 MPa and the contribution of surface diffusion increases as the pore pressure increases. The macroscopic effective permeability of the whole domain is dominated by the permeability of the connected phase; meanwhile, it can be influenced by the permeability of the disconnected phase. When the pore pressure is below 3.52 MPa, the effective permeability increases as the organic matter content (TOC) decreases. However, the effective permeability increases as the TOC increases when the pore pressure is above 3.52 MPa, which is different from traditionally believed when the relationship between the TOC and gas absorption capacity of the shale matrix is not considered. The effective permeability particularly increases at a high pore pressure as the Langmuir volume increases. In addition, the effective permeability increases as the Langmuir pressure decreases; however, this becomes apparent when the pore pressure is smaller. • An upscaled transport model is established based on homogenization theory by considering multiple transport mechanisms and heterogeneity of shale gas reservoir. • This new transport model is employed to successfully explain the pressure decay experiment data successfully and the absorption phenomenon is also considered. • The permeability anisotropy for stochastic distribution model can be ignored and the effective permeability will be underestimated by double porosity model if surface diffusion dominates gas flow in shale reservoir. • The macroscopic effective permeability of whole domain is dominated by the permeability of connected phase meanwhile it can be influenced by the permeability of disconnected phase. [ABSTRACT FROM AUTHOR]

• Coupled porous media and free flow model of fluid flow in fractured karst reservoirs. • Analytical expression of connectivity for discrete fracture-cave networks. • Flow channeling dominated by network connectivity. • Permeability scaling with connectivity in a power law for connected systems. Fractured karst reservoirs play a significant role in hydrocarbon reserves and groundwater storage. They often exhibit complex multiscale heterogeneities involving pores, fractures and caves, whose length scales range from microns to tens or hundreds of meters. Thus, the study of fractured karst reservoirs is faced with a significant unresolved challenge in quantitatively characterizing the geometrical connectivity and hydraulic conductivity as well as their interrelationships in such strongly heterogeneous, multicomponent systems. In this paper, we propose an analytical formulation to characterize the connectivity of discrete fracture-cave networks building upon the excluded area concept of the percolation theory. By implementing a state-of-the-art computational model solving coupled Navier-Stokes (free flow) and Darcy (porous media flow) equations, we numerically derive the permeability of a fractured and karstified porous media, such that the relationship between the connectivity and permeability is further explored. The high-fidelity numerical model also permits us to elucidate the process of flow channelization within the fracture-cave network. The results show that the fracture-cave network connectivity correlates to the permeability via a power law scaling for connected systems. Significant flow channeling occurs around the percolation threshold where the flow is dominated by a limited number of preferential pathways. Caves play a crucial role in the flow due to the fact that caves could globally enhance the network connectivity and locally serve as hotspots for high fluid velocity. Finally, a semi-analytical permeability model for fractured karst reservoirs is developed. The results of our research and insights obtained have important implications for understanding the subsurface fluid flow in fractured karst reservoirs. [ABSTRACT FROM AUTHOR]