Advances in Water Resources最新文献

This paper discusses axi-symmetric flow during CO₂ injection into a non-adiabatic reservoir accounting for Joule-Thomson cooling and steady-state heat exchange between the reservoir and the adjacent layers by Newton's law. An exact solution for this 1D problem is derived and a new method for model validation by comparison with quasi 2D analytical heat-conductivity solution is developed. The temperature profile obtained by the analytical solution shows a temperature decrease to a minimum value, followed by a sharp increase to initial reservoir temperature on the temperature front. The temperature distribution head of the front is determined by the initial reservoir temperature, while the solution behind the front is determined by the temperature of injected CO₂. The analytical model exhibits stabilisation of the temperature profile and the cooled zone. The explicit formula for temperature distributions allows determining the maximum injection rate that avoids hydrate formation.

An areal-averaged form of classical Shallow-Water-Equations is developed in conjunction with Finite-Volume-Method for capturing sub-grid bed variation. The averaging mechanism treats sub-grid obstacles through depth-dependent-area-averaged porosity at the macroscopic level. This porosity assumes a binary distribution (0,1) for a resolution fine enough to treat bed-variation separately, resulting in convergence of the developed framework to classical form. An attempt has been made to incorporate the unresolved fine-scale flow-information (e.g., micro-scale and cross-scale interaction components) in terms of the macroscopic variables through a non-linear closure model. An augmented approximated Riemann solver incorporates varying source–sink terms within interfacial fluxes along with discontinuous porosity and bed variation. The model is applied to three test-cases ranging from wave-interaction with trapezoidal porous block to dam-break flows through obstacle(s) with varying grid configurations. The coarse-scale formulation, along with closure, produces a reasonably accurate solution with minimal computational overhead.

This article explores the possibility to assess the flow and transport properties of loosely consolidated rock material—something that is very hard or impossible to achieve in the laboratory due to fragility of cores. We present two cases of weakly consolidated and unconsolidated rocks. We provide a solution based on pore-scale simulations and stochastic reconstructions using scanning electron (SEM) and grain optical microscopy images as input data. The hybrid reconstruction approach is based on 3D grain shape construction out of 2D optical images, packing of grains to match the target porosity measured from SEM imaging, and addition of clay and other cementing phases with the help of phase-recovery method. Note that standard digital rock protocol based on X-ray microtomography did not work for considered samples due to fine-grained particle size distribution (insufficient resolution of X-ray microtomography). After creation of 3D digital replicas of rock samples based on their SEM and optical microscopy images, we applied pore-scale modeling to obtain permeability and two-phase flow properties. Simulated permeability of 259 mD for the first sample was in surprisingly good agreement with laboratory measurements of 248 mD. For the second sample permeabilities deviated by an order of magnitude. After additional studies it was found that the mesh attached to the sample during measurements affected the results. After pore-scale simulations of the grain packing with the mesh we were able to achieve very good agreement with the experiment, confirming that the lab was basically exploring the properties of the mesh clogged with unconsolidated rock material. Thus, pore-scale hybrid rock structure reconstruction technique combined with pore-scale simulations was able to correct inaccurate laboratory assessment and obtain flow properties for unconsolidated rock sample. We believe the developed hybrid reconstruction technique to be robust enough to serve as a basis of the industrial technology for petrophysical studies of weakly and unconsolidated core material.

As a result of complex pore-throat geometry and precursor corner flow, the snap-off of the non-wetting phase occurs during the spontaneous imbibition (SI) of wetting phase. However, accurate modeling of such pore-scale flow behavior remains a big challenge, and its influencing factors remain unclear. In this study, an improved pseudopotential lattice Boltzmann method (LBM) is used to analyze the snap-off behavior during the SI process in three-dimensional (3D) pore-throat models with rough surfaces. The influence of the pore-to-throat size ratio (λ), contact angles (θ), and Ohnesorge number (Oh) on the occurrence of the snap-off are investigated and based on which a 3D phase diagram is established. The snap-off is more likely to occur with the increase in λ and Oh and decrease in θ, respectively. Only when the λ is ≥2 and the θ is <13°, the snap-off may occur. With the increase in θ from 0° to 13°, the snap-off is suppressed due to the relatively small advancing difference between the corner flow and the bulk meniscus. Volume fraction of the entrapped gas bubble in the pore increases with the increase in λ and Oh and the decrease in θ. The time when snap-off occurred increases with the increase in λ and θ, and decrease in Oh. These results are fundamental for investigating snap-off phenomena in real 3D pore space and guide how to avoid or facilitate the occurrence of snap-off and to control the degree of snap-off.

Low-permeability sedimentary formations, such as tight sandstones, exhibit fluid flow and transport phenomena distinct from those in conventional porous systems due to the dominance of micro- to nanometer-sized pores and variable amounts of boundary slip. The widely used traditional no-slip boundary condition often fails to accurately describe fluid behavior in these formations. A knowledge gap exists in understanding how liquid slip influences fluid dynamics in complex, heterogeneous sedimentary structures, as previous studies have primarily focused on simplified, homogeneous pore geometries. In this study, we investigated the impact of boundary slip on low-Reynolds number fluid dynamics within synthetically designed two-dimensional graded and random pore networks with varying pore-size distributions to account for heterogeneity. Our results showed that velocity variance increased with increasing heterogeneity, following a power-law relationship. The power-law exponents decreased with boundary slip, quantifying how boundary slip mitigated the impact of heterogeneity on velocity variance. We developed a theoretical model to predict asymptotic flow enhancement and derived constitutive relations to estimate the coefficient C and maximum flow enhancement (ΔE) based on the pore-to-grain size ratio and porosity. Energy dissipation increased with both heterogeneity and boundary slip, which we identified as the primary mechanism contributing to asymptotic flow enhancement. This relationship was illustrated by a 1:1 linear correlation between maximum energy dissipation and maximum flow enhancement, regardless of heterogeneity, indicating that energy dissipation due to boundary slip entirely controls the emerging fluid dynamics. The presented theoretical model and constitutive equations offer practical applications for optimizing fluid dynamics in heterogeneous formations.

High-resolution three-dimensional X-ray microscopy can be used to image the pore space of materials. Machine learning algorithms can generate a statistical ensemble of representative images of arbitrary sizes for rock characterization, modeling, and analysis. However, current methods struggle to capture features at different spatial scales observed in many complex rocks which have a wide range of pore size. We use the Improved Pyramid Wasserstein Generative Adversarial Network (IPWGAN) to automatically reproduce multi-scale features in segmented three-dimensional images of porous materials, enabling the reliable generation of large-scale representations of complex porous media. A Laplacian pyramid generator is introduced, which creates pore-space features across a hierarchy of spatial scales. Feature statistics mixing regularization enhances the discriminator’s ability to distinguish between real and generated images by mixing their feature statistics, thereby indirectly enhancing the generator’s ability to capture and reproduce multi-scale pore-space features, leading to increased diversity and realism in the generated images. The method has been tested on five sandstone and carbonate samples. The generated images, which can be of any size – including cm-scale ten-billion-cell images – demonstrate the power of the approach. These images have two-point correlation functions, porosity, permeability, Euler characteristic, curvature, and specific surface area closer to those of the training datasets than existing machine learning techniques. The generated images accurately capture geometric and flow properties, demonstrating a considerable improvement over previously published studies using generative adversarial networks. For instance, the mean relative error in the calculated absolute permeability between the Berea sandstone images generated by IPWGAN and the corresponding real rock images can be reduced by 79%. The work allows representative models of a wide range of porous media to be generated, offering potential benefits in carbon dioxide sequestration, underground hydrogen storage, and enhanced oil recovery.

The simplified view of two-phase flow, such as oil and gas, in a fracture is often assumed to occur in a stratified behavior. However, recent studies and production practices have revealed that two-phase flow in fractures exhibits diverse flow patterns. This paper investigates the control of the fracture aperture, fluids viscosity, and wettability on two-phase flow in a 2D cross section of a 3D Berea fracture. Lattice Boltzmann Method (LBM) simulations are used to model the impact of these properties on relative permeability curves. Notably, in strongly wet fractures, two distinct permeability regimes emerge. High aperture values exhibit behavior resembling parallel planes, while low aperture values lead to a linear decrease in permeability due to fluid interactions between fracture surfaces. Conversely, anomalous behavior of the relative permeability curves is identified in weakly wet fractures within specific aperture ranges. This behavior is associated with the occurrence of specific flow patterns within the fracture. Results also emphasize that changes in viscosity ratio do not affect the presence or the saturation range of the anomalous behavior but do influence its intensity for each fluid. Comparisons with Poiseuille profile equations reveal the limited impact of the fracture roughness. These findings enhance our understanding of the interactions between aperture, viscosity, and wettability and how they control the shape of the relative permeability curves. These curves are pivotal parameters for the continuum scale modeling (reservoir models) in oil and gas application, for instance.

Fluid production from fractured rock masses readily induces fracture flow velocities of meters per second. Yet, most discrete fracture flow models treat flow as laminar creeping flow or account for inertia effects only by single-fracture constitutive relationships.

This numeric simulation study investigates water flow patterns and spatial velocity variations in a natural fracture network with mm-wide open fractures, studying the transition from laminar creeping to turbulent flow. After verification with a fracture intersection model, a Reynolds-time-averaged Navier Stokes solver serves to analyse flow regimes and velocity distribution. Our results show that for fracture flow velocities greater than $\sim$1-cm/s, fluid inertia begins to markedly alter flow patterns and the overall velocity distribution in the network. The pressure-gradient-flow relationship therefore becomes non-linear long before the flow in straight fractures enters the weak inertia regime. This prominence of inertia effects highlights the need to improve fracture network flow models.

Richards equation is often used to represent two-phase fluid flow in an unsaturated porous medium when one phase is much heavier and more viscous than the other. However, it cannot describe the fully saturated flow for some capillary functions without specialized treatment due to degeneracy in the capillary pressure term. Mathematically, gravity-dominated variably saturated flows are interesting because their governing partial differential equation switches from hyperbolic in the unsaturated region to elliptic in the saturated region. Moreover, the presence of wetting fronts introduces strong spatial gradients often leading to numerical instability. In this work, we develop a robust, multidimensional mathematical model and implement a well-known efficient and conservative numerical method for such variably saturated flow in the limit of negligible capillary forces. The elliptic problem in saturated regions is integrated efficiently into our framework by solving a reduced system corresponding only to the saturated cells using fixed head boundary conditions in the unsaturated cells. In summary, this coupled hyperbolic–elliptic PDE framework provides an efficient, physics-based extension of the hyperbolic Richards equation to simulate fully saturated regions. Finally, we provide a suite of easy-to-implement yet challenging benchmark test problems involving saturated flows in one and two dimensions. These simple problems, accompanied by their corresponding analytical solutions, can prove to be pivotal for the code verification, model validation (V&V) and performance comparison of simulators for variably saturated flow. Our numerical solutions show an excellent comparison with the analytical results for the proposed problems. The last test problem on two-dimensional infiltration in a stratified, heterogeneous soil shows the formation and evolution of multiple disconnected saturated regions.

In aged levees, toe (blanket) drains get clogged with time due to seepage-induced suffusion and translocation of fine soil fractions from the upstream to the downstream part of the embankment. These particles deposit on the top of the drain (usually, Terzhagi's graded gravel) as a cake. Also, high hydraulic gradients in the vicinity of the drain move the fine particles into the body of the coarse filter material such that “internal colmation” takes place. In this paper 2-D seepage to a clogged drain is studied experimentally, analytically and numerically. In a sandbox, we illustrate the difference in the position of a phreatic surface and the seepage flow rate between an equipotential toe drain and a clogged one. In the analytical solution, a potential flow model is used and the Neumann (Kirkham-Brock) boundary condition on the clogged drain surface (horizontal segment) is imposed. A circular triangle is mapped conformally onto a reference half-plane, where Hilbert's boundary value problem for a holomorphic function is solved. For a given size of the levee, clogging causes a significant rise of the phreatic surface, although the seepage flow rate drops. In HYDRUS2-D simulations, a FEM-meshed Richards’ equation for a saturated-unsaturated 2-D flow is used for solving in a composite polygon, which mimics a vertical cross-section of a rectangular levee and a clogged-colmated blanket drain. Numerical results are in rough agreement with the analytical model.