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Fractal characteristic has been considered as the essential parameter to determine transport properties of porous media. Fluid flow in the real porous media is more influenced by the narrow throat system than the relatively large pore system. In this work, the concept of throat fractal dimension is proposed and applied to predict permeability in porous media. First, pore system and throat system of six sandstone rock samples and three carbonate rock samples are divided from the pore network models extracted from rock CT images. Then, fractal dimensions based on the total pore space, pore system and throat system are calculated, respectively, based on the three-dimensional (3D) box-counting method. Three groups of permeabilities are estimated, respectively, using the fractal theory based on the pore space fractal parameter, pore system fractal parameter and the proposed throat system fractal parameter. The results indicate that permeabilities estimated by the proposed throat system fractal parameter are closer to the accurate permeabilities of rock samples compared with that estimated by the pore space fractal parameter and pore system fractal parameter. Our study results reveal that throat fractal dimension should be used to accurately predict fluid transport properties in porous media. [ABSTRACT FROM AUTHOR]

Gas flows in the forms of multiple transport mechanisms in shale nanoporous media with complex pore structure and different pore types. Laboratory pressure pulse decay technique is often applied to measure gas permeability but the current gas permeability interpretation model is mostly based on the homogeneous macro scale model while the influence of pore structure on real gas transport is neglected. In this study, a novel pore structure based real gas transport model is proposed to determine gas permeability in nanoporous shale combining laboratory pressure pulse decay technique with pore network simulation. The laboratory pressure pulse decay process is simulated in a virtual system based on the similarity principle which contains upstream vessel, downstream vessel, and core sample. The core sample is constructed by a series of connected pore networks and the sizes of pores and throats in each location of the pore network are randomly assigned according to laboratory measured pore size distribution. Gas transport mechanisms inside the core sample consider viscous flow, Knudsen diffusion, surface diffusion and real gas effect. At each time step, the upstream vessel pressure decreases and the downstream vessel pressure increases until the upstream vessel pressure and downstream vessel pressure become equal. The simulated pressure drop versus time curve is obtained and is applied to fit the laboratory measured pressure drop data by repeating core sample construction and pressure pulse decay process. The proposed model is applied to measure gas permeability of Sichuan basin, Longmaxi formation shale core sample. The results indicate that the predicted value based on the proposed model matches well with the experimental measured pressure drop data. The proposed model is used to study the influences of test gas type and pore size on gas permeability. When the average organic pore radius is less than 20 nm, helium tested permeability overestimates at least 40% of the methane permeability. [ABSTRACT FROM AUTHOR]

Owning to their differences in surface properties and pore geometry, pores of predominant submicron sizes in organic and inorganic matter of gas shale incur different gas flow and transport behaviours. Those differences can manifest at sample scales differently depending on the spatial distributions of shale organic and inorganic matter, and the pore-size distributions in these types of matter. Therefore, understanding the impacts of variable configurations of them on the gas flow is essential to guide progressive subsampling in multiscale shale characterisation that is required for modelling shale gas flow at the first place. This article reports a pore-scale numerical investigation into the impacts of combinations of three end-member spatial arrangements of the organic matter and two contrasting sets of organic and inorganic pore-size distributions at variable organic fractions on gas flow using pore-network modelling. A unified pore-network flow model for shale gas that captures a comprehensive set of gas flow and transport mechanisms is developed in this work to calculate the effective gas apparent permeability at reservoir conditions. In terms of the mean permeability at each selected organic fraction, the largest differences are found to appear at a high fraction above 25% across all the arrangements, and the upper bound can reach more than two orders of magnitude greater than the lower bound. The results suggest that subsampling ought to focus on subdomains where organic fractions are high, organic and inorganic pores differ in size, and distinct flow-enhancing or baffling arrangements of organic matter are present. [ABSTRACT FROM AUTHOR]

• Shale permeability upscaling is proposed considering multiple transport mechanisms. • A REV size is determined as 420 μm with experimental data of Sichuan basin. • Bulk gas in inorganic matter contributes roughly 70% to core-scale permeability. • Water film effect can be neglected at mean pore size larger than 40 nm. This paper presents a new upscaling method to derive the core-scale apparent gas permeability from an improved pore-scale permeability model and experimental data, with more rigorous incorporation of varying gas storage/transport mechanisms in nano/micro pores. First, in use of SEM images of a gas-rich shale field example in Sichuan Basin from our lab, pore network models of inorganic-matter (IOM) and organic-matter (OM) are characterized by using a digital-core technique. Next, an improved pore-scale real gas apparent permeability is modeled rigorously for both IOM/OM, respectively, with 1) bulk gas transport, gas adsorption, surface diffusion, pore-size confined phase behavior, and stress-dependent rock properties and 2) an additional reduction in inorganic pore sizes by water film adhered on pore surfaces. Core-scale permeability is then derived by assembling the permeabilities of stochastically distributed IOM/OM patches with different pore network models properties using the Monte Carlo sampling method. The new core-scale permeability model is validated by pulse-decay permeability experiment. Moreover, the representative elementary volume (REV) size is determined by analyzing the relative standard deviation of apparent gas permeability in cases with different sample sizes. The contributions of different gas transport mechanisms are discussed, and the impacts of stress-dependence for several field examples (i.e., Sichuan, Pierre and Barnett Basins) and water film with varying relative humidity (RH) on core-scale apparent permeability are analyzed. This work provides an effective approach to determine the core-scale shale permeability by directly using pore-scale experimental data, which is a common challenge in the unconventional resources. [ABSTRACT FROM AUTHOR]

Water flooding is the most widely used method to enhance oil recovery. Simulating the influence of particle content on fluid flow in water flooding process can provide instructive significance for oilfield development. In this paper, a pore network model was established to simulate the transport process of particles in injected water and fallen particles from the reservoir. It was used to study the influence of particle blockage, deposition and migration on the clogged throats and changes of oil-water relative permeability curves. In the model, four parameters were set, fallen particle diameter, injected particle diameter, fallen particle number and injected particle number. Other parameters were fixed and only a variable was changed to explore the changeable rule of relative permeability curves. It can be generally noted that fallen particle changes have great influence on the relative permeability curves of oil phase and injected particle changes mainly affect the relative permeability curves of water phase. It is of great significance for oilfield development to study the influence of particle transportation on fluid seepage processes. • A pore network model containing particles was established. • A transport process of injected particles and fallen particles from the reservoir during water flooding was simulated. • The influence of particle blockage, deposition and migration on the clogged throats and oil-water relative permeability curves was studied. [ABSTRACT FROM AUTHOR]

This study proposed an advection-diffusion-mechanical deformation integral model to predict coal matrix methane permeability combining digital rock physics with laboratory measurements. The coal matrix pore network was first extracted from the segmented 3D digital coal image. Organic pore-controlled methane transport pathways and mineral-associated pore methane transport pathways were identified from the coal matrix pore network. Advection and Knudsen diffusion processes were considered for methane transport in the mineral associate pores and bulk methane transport in organic pores. To determine the adsorbed methane surface diffusion ability in organic pores, laboratory adsorption and desorption experiments were conducted to determine the desorption curve and critical desorption pressure. Pore shrinkage was considered for organic pores and mineral-associated pores whereas sorption-induced volumetric strain was also modeled for the organic pore system. The coal matrix methane permeability was calculated over a wide range of production pressures and the influences of reservoir and methane transport properties on coal matrix methane permeability were analyzed in detail. Results revealed that gas slippage and initial formation pressure dominate the coal matrix methane permeability more than other influencing factors. Coal matrix methane permeability was underestimated by at least 40% by using Darcy flow to describe methane flow in the coal matrix and the influence of organic matter bulk modulus variation on coal matrix methane permeability can be neglected at initial formation pressures less than 10 MPa. • An advection-diffusion-deformation coal matrix methane permeability model is proposed. • Pore size change caused by stress and sorption-induced volume are modeled. • Methane transport mechanisms in different pore types are considered. • Influences of geochemical properties on coal matrix methane permeability are studied. [ABSTRACT FROM AUTHOR]

Digital core simulation technology, as an emerging numerical simulation method, has gradually come to play a significant role in the study of petrophysical properties. By using this numerical simulation method, the influence of micro factors on seepage properties of reservoir rock is taken into consideration, making up the shortcomings of the traditional physical experiment. Three-dimensional core images are reconstructed by a computed tomography scanning technique. Different sizes of the sub-region were simulated by three methods including the direct computation of Navier-Stokes equations, the simulation of the pore network model, and the lattice Boltzmann method. The permeability computed by each simulation was compared. After comparison between these three methods, the results of the direct computation method based on Navier-Stokes equations were found to be higher than the other two methods. The pore network model simulation has an obvious advantage on the computation speed and the simulation area. The lattice Boltzmann method shows the low efficiency due to the time-consuming process. At last, the permeability calculated by the three methods is matched by the Kozeny-Carman equation. A more accurate formula can be obtained by a series of numerical simulations, which can be applied to marco-scale simulation. [ABSTRACT FROM AUTHOR]