Browse
Submit Data
Databases
API
Help

Dataset Information

0 Views

0 Connections

0 Citations

0 Reanalyses

0 Downloads

Omics score: 0

Pore-Scale Simulation and Sensitivity Analysis of Apparent Gas Permeability in Shale Matrix.

ABSTRACT: Extremely low permeability due to nano-scale pores is a distinctive feature of gas transport in a shale matrix. The permeability of shale depends on pore pressure, porosity, pore throat size and gas type. The pore network model is a practical way to explain the macro flow behavior of porous media from a microscopic point of view. In this research, gas flow in a shale matrix is simulated using a previously developed three-dimensional pore network model that includes typical bimodal pore size distribution, anisotropy and low connectivity of the pore structure in shale. The apparent gas permeability of shale matrix was calculated under different reservoir pressures corresponding to different gas exploitation stages. Results indicate that gas permeability is strongly related to reservoir gas pressure, and hence the apparent permeability is not a unique value during the shale gas exploitation, and simulations suggested that a constant permeability for continuum-scale simulation is not accurate. Hence, the reservoir pressures of different shale gas exploitations should be considered. In addition, a sensitivity analysis was also performed to determine the contributions to apparent permeability of a shale matrix from petro-physical properties of shale such as pore throat size and porosity. Finally, the impact of connectivity of nano-scale pores on shale gas flux was analyzed. These results would provide an insight into understanding nano/micro scale flows of shale gas in the shale matrix.

SUBMITTER: Zhang P

PROVIDER: S-EPMC5459163 | biostudies-other | 2017 Jan

REPOSITORIES: biostudies-other

ACCESS DATA

Json Xml

Similar Datasets

Multiparameter Analysis of Gas Transport Phenomena in Shale Gas Reservoirs: Apparent Permeability Characterization.

Project description:The large amount of nanoscale pores in shale results in the inability to apply Darcy's law. Moreover, the gas adsorption of shale increases the complexity of pore size characterization and thus decreases the accuracy of flow regime estimation. In this study, an apparent permeability model, which describes the adsorptive gas flow behavior in shale by considering the effects of gas adsorption, stress dependence, and non-Darcy flow, is proposed. The pore size distribution, methane adsorption capacity, pore compressibility, and matrix permeability of the Barnett and Eagle Ford shales are measured in the laboratory to determine the critical parameters of gas transport phenomena. The slip coefficients, tortuosity, and surface diffusivity are predicted via the regression analysis of the permeability data. The results indicate that the apparent permeability model, which considers second-order gas slippage, Knudsen diffusion, and surface diffusion, could describe the gas flow behavior in the transition flow regime for nanoporous shale. Second-order gas slippage and surface diffusion play key roles in the gas flow in nanopores for Knudsen numbers ranging from 0.18 to 0.5. Therefore, the gas adsorption and non-Darcy flow effects, which involve gas slippage, Knudsen diffusion, and surface diffusion, are indispensable parameters of the permeability model for shale.

| S-EPMC5805773 | biostudies-literature

Micro/Nano-pore Network Analysis of Gas Flow in Shale Matrix.

Project description:The gas flow in shale matrix is of great research interests for optimized shale gas extraction. The gas flow in the nano-scale pore may fall in flow regimes such as viscous flow, slip flow and Knudsen diffusion. A 3-dimensional nano-scale pore network model was developed to simulate dynamic gas flow, and to describe the transient properties of flow regimes. The proposed pore network model accounts for the various size distributions and low connectivity of shale pores. The pore size, pore throat size and coordination number obey normal distribution, and the average values can be obtained from shale reservoir data. The gas flow regimes were simulated using an extracted pore network backbone. The numerical results show that apparent permeability is strongly dependent on pore pressure in the reservoir and pore throat size, which is overestimated by low-pressure laboratory tests. With the decrease of reservoir pressure, viscous flow is weakening, then slip flow and Knudsen diffusion are gradually becoming dominant flow regimes. The fingering phenomenon can be predicted by micro/nano-pore network for gas flow, which provides an effective way to capture heterogeneity of shale gas reservoir.

| S-EPMC4642512 | biostudies-other

Laboratory simulation of shale gas produced water

Project description:Laboratory simulation of shale gas produced water Raw sequence reads

| PRJNA819831 | ENA

A Coupled Model for Upscaling Water Flow in a Shale Matrix System from Pore Scale to Representative Elementary Area Scale.

Project description:Understanding water transport in pore structures is essential for studying the impact of water leakage on oil and gas development in shale reservoirs. Previous apparent liquid permeability models have focused on describing the flow mechanism and paid less attention to the quantification of multiscale porous media within real samples and the convenience of numerically calculating multiscale flow-solid coupling. This study presents a multicomponent, multiscale pore spatial model by combining a representative elementary area (REA)-scale shale matrix grid model and fractal conical micropipe bundle model, facilitating quantification of the complex pore space in shale. The well-researched water-transport behavior in nanopores was then increased to describe REA-scale shale. The results show that the fractal conical micropipe model is more suitable for describing the heterogeneous pore structures of shale components than the fractal capillary bundle model. Wettability and fluid viscosity are key factors affecting the permeability enhancement of organic matter (OM) and inorganic matter (IOM), respectively. The degree of influence of OM heterogeneity on the total permeability of REA-scale shale depends on the total organic carbon content and permeability contrast between OM and IOM. Finally, an empirical model describing the macroscopic apparent liquid permeability of shale matrices was established that could quantify the effects of scale and porosity and permeability heterogeneity on permeability in shale matrices. The findings of this study can help us to better understand pore systems and fluid flow phenomena in shale matrices.

| S-EPMC10851231 | biostudies-literature

Lattice Boltzmann simulation of shale gas transport in organic nano-pores.

Project description:Permeability is a key parameter for investigating the flow ability of sedimentary rocks. The conventional model for calculating permeability is derived from Darcy's law, which is valid only for continuum flow in porous rocks. We discussed the feasibility of simulating methane transport characteristics in the organic nano-pores of shale through the Lattice Boltzmann method (LBM). As a first attempt, the effects of high Knudsen number and the associated slip flow are considered, whereas the effect of adsorption in the capillary tube is left for future work. Simulation results show that at small Knudsen number, LBM results agree well with Poiseuille's law, and flow rate (flow capacity) is proportional to the square of the pore scale. At higher Knudsen numbers, the relaxation time needs to be corrected. In addition, velocity increases as the slip effect causes non negligible velocities on the pore wall, thereby enhancing the flow rate inside the pore, i.e., the permeability. Therefore, the LBM simulation of gas flow characteristics in organic nano-pores provides an effective way of evaluating the permeability of gas-bearing shale.

| S-EPMC4007072 | biostudies-other

Nanoscale simulation of shale transport properties using the lattice Boltzmann method: permeability and diffusivity.

Project description:Porous structures of shales are reconstructed using the markov chain monte carlo (MCMC) method based on scanning electron microscopy (SEM) images of shale samples from Sichuan Basin, China. Characterization analysis of the reconstructed shales is performed, including porosity, pore size distribution, specific surface area and pore connectivity. The lattice Boltzmann method (LBM) is adopted to simulate fluid flow and Knudsen diffusion within the reconstructed shales. Simulation results reveal that the tortuosity of the shales is much higher than that commonly employed in the Bruggeman equation, and such high tortuosity leads to extremely low intrinsic permeability. Correction of the intrinsic permeability is performed based on the dusty gas model (DGM) by considering the contribution of Knudsen diffusion to the total flow flux, resulting in apparent permeability. The correction factor over a range of Knudsen number and pressure is estimated and compared with empirical correlations in the literature. For the wide pressure range investigated, the correction factor is always greater than 1, indicating Knudsen diffusion always plays a role on shale gas transport mechanisms in the reconstructed shales. Specifically, we found that most of the values of correction factor fall in the slip and transition regime, with no Darcy flow regime observed.

| S-EPMC4308705 | biostudies-literature

Shale Gas Nanofluid in the Curved Carbon Nanotube: A Molecular Dynamics Simulation Study.

Project description:Curved nanochannels are prevalent in porous and tortuous materials, with shale matrices being a noteworthy example. The tortuosity of shale matrices significantly influences the behavior of shale gas, holding crucial implications for gas recovery engineering. In this study, we employ molecular dynamics simulation (MD) to investigate the impact of curvature and radius in tortuous nanochannel formed by a curved single-walled carbon nanotube (SWCNT) on the adsorption and transport properties of methane gas fluid. Our findings reveal that the inner half surface of the SWCNT, characterized by negative curvature, exhibits enhanced methane adsorption. Methane in straighter and narrower channels displays higher flow velocities, while wider channels exhibit higher flow flux. The nonzero flow velocity alters adsorption strength, causing the outer half to surpass the inner half. Tangent and vertical velocities of the flow are heterogeneously distributed in the channel, with the outer half having higher tangent velocities. Additionally, a vertical velocity pulse near the entrance induces turbulent vortex flow, slowing down the tangent flow velocity. This research contributes to a deeper understanding of shale gas properties in matrices with bent and curved channels, offering insights into nanofluids in carbon nanotubes and porous media featuring curved nanochannels.

| S-EPMC11256318 | biostudies-literature

shale gas metagenome

Project description:Microbial community in hydraulic fracturing fluids from deep hydrocarbon-rich shale

| PRJDB7857 | ENA

shale gas metagenome

Project description:Shale gas microbial communities from Fort St. John, British Columbia, Canada - PROGRESS HHA metagenome

| PRJNA620677 | ENA

shale gas metagenome

Project description:Shale gas microbial communities from Fort St. John, British Columbia, Canada - PROGRESS PAD metagenome

| PRJNA620678 | ENA