Stratigraphic heterogeneity in marine sediments creates localized pore-scale hydraulic bottlenecks that influence fluid flow and drainage behavior; however, the pore-scale mechanisms by which sediment architecture organizes hydraulic resistance remain insufficiently quantified. In this study, we use high-resolution Computational Fluid Dynamics (CFD) simulations with OpenFOAM to investigate pore-scale flow behavior in three idealized sediment configurations representative of common marine stratigraphic architectures: homogeneous, fining-upward, and coarse–fine–coarse (CFC). Analysis of velocity fields, effective flow path length, hydraulic-gradient magnitudes, and strain-rate magnitudes reveals pronounced architecture-dependent differences in the spatial organization of hydraulic resistance despite comparable bulk porosities ( 0.34) and bulk permeabilities within the same order of magnitude, ranging from 2.08 × 10−11 to 7.89 × 10−12 m2. At comparable mean velocities, the stratigraphically heterogeneous configurations exhibit higher hydraulic-gradient and strain-rate magnitudes than the homogeneous configuration. The homogeneous configuration shows comparatively uniform profiles, whereas the fining-upward configuration develops an upward increase in hydraulic-gradient magnitude. CFC concentrates elevated resistance indicators near abrupt interfaces and shows weak coupling between the mean-velocity and hydraulic-gradient profiles. These findings demonstrate that mean flow velocity and bulk permeability do not fully describe internal hydraulic resistance in stratified sediments. Instead, stratigraphic architecture controls where pore-scale hydraulic resistance is concentrated, identifying potential hydraulic bottlenecks with implications for fluid redistribution in layered marine sediments.
The Kozeny–Carman (KC) equation remains the standard closed-form predictor of permeability in porous rocks, yet it systematically under-performs in heterogeneous carbonates where connectivity, rather than porosity alone, governs flow. We extend KC by a Buckingham- Π reduction of {k,τ ,ϕ _eff,Z_avg,S,T̅} to a single dimensionless complexity number Π = τ ^α/[ϕ _eff^β Z_avg^γ (ST̅)^2δ] , closed by k = 1/(c_lit S^2 Π ) . The closure is dimensionally consistent for any exponent values, sign-consistent with the physics of every descriptor, and reduces exactly to KC when α =2 , β =3 , γ =δ =0 . The model hierarchy M0–M4 was fitted on 1 963 sub-volumes extracted from twenty parent micro-CT scans (ten clean clastic sandstone and ten Brazilian pre-salt carbonate volumes), yielding 923 sandstone and 1 040 carbonate sub-volumes, with single-relaxation-time lattice Boltzmann permeability as the reference. The models were selected by the corrected Akaike Information Criterion. The preferred model was M3 (KC pinned at α =2 , β =3 with γ and δ free), with γ̂ = 0.67 and δ̂ = 0.50 , achieving log-space R^2 = 0.986 , log-MAE = 0.24 (typical multiplicative error 1.27× ), and 100% of samples within ± 1 decade of the LBM ground truth. The unconstrained M4 fit returns α̂ = 2.01 and β̂ = 3.00 , empirically confirming the classical squared-tortuosity and cubic porosity scalings to within 1% . The throat-scale exponent δ̂ = 0.50 lies midway between the KC ( δ =0 ) and Katz–Thompson ( δ =1 ) endpoints. Cross-lithology validation under an intercept-refitted protocol was symmetric ( R^2_log≳ 0.95 in either direction), indicating that the four exponents capture lithology-invariant physics rather than within-lithology over-fitting.
Underground hydrogen storage (UHS) in saline aquifers is a potential strategy for long-term storage of energy from intermittent sources, such as wind and solar. Currently, there are limited laboratory studies on the multiphase flow of hydrogen (H2) in brine-saturated porous media featuring in situ imaging of the progression of the H2 phase. Such studies are crucially important to understand H2-brine multiphase flow and the viability and efficiency of UHS. Here, we present time-lapse X-ray computed tomography images of meter-scale rock cores at dimensionless microscopic capillary numbers ( 3× 10^-6< N_Ca < 5× 10^-9 ), Bond numbers ( 20< N_Bo < 70 ), and mobility ratios ( M ≈ 0.016 ) characteristic of the injection and withdrawal of H2 in saline aquifers. Horizontally oriented experiments show the development of viscous fingers at all flow rates. Extremely thin and exceptionally mobile fingers are apparent at large flow rates. The vertically oriented experiments also show the development of viscous fingers at all flow rates, even in the stabilizing presence of gravity. This is contrary to expectation. Potential losses of H2 by disconnection and trapping of the gas phase in the viscous finger may be significant and losses due to fingering need to be taken into account when designing and simulating UHS.
Understanding the Physico-mechanical and transport evolution of basalt at elevated temperatures is crucial for evaluating its suitability for subsurface energy systems, nuclear waste disposal, and carbon dioxide sequestration. In this study, a site-specific, semi-empirical approach is developed for estimating permeability through a framework of bulk porosity, multiscale pore properties, and quantitative crack geometry. Basalt samples were subjected to heating from 25 to 1000 °C, with analyses measuring porosity, Brunauer-Emmett-Teller (BET) surface area, pore volume, pore diameter, and fractal dimensions, complemented by Scanning Electron Microscope (SEM)-based crack metrics. Water Immersion Porosimetry (WIP) showed stable porosity up to 400 °C, rising sharply to 18.7
Viscous fingering develops when a higher mobility fluid displaces a lower mobility fluid in porous media, creating preferential pathways that accelerate breakthrough and reduce sweep efficiency. This instability affects enhanced oil recovery, groundwater remediation, underground gas storage, and geological carbon storage. Predicting its three-dimensional evolution remains difficult because phase mobility, nonlinear pathway interactions, numerical directional bias, and computational cost must be addressed together. Reservoir simulators represent relative permeability, fractional flow, and residual saturation, but often smear individual fingerings. High-resolution miscible and pore-scale methods resolve detailed morphology, yet are not naturally formulated for reservoir-style saturation-dependent mobility or large continuum domains. Multidirectional transport treatments and GPU sparse solvers address numerical limitations, but these capabilities have generally been developed separately. We therefore develop a pressure-based high-resolution 3D CFD framework integrating Corey-type relative permeability, fractional-flow phase partitioning, clipped effective saturation, D3Q27-inspired directional link-velocity weighting, and GPU-based implement solution. The calculations concern homogeneous, viscosity-dominated liquid displacement; capillary pressure, gravity, and Forchheimer inertia are excluded. The framework was assessed against one-dimensional Buckley–Leverett solutions and benchmarked against Habermann’s miscible quarter five-spot experiments for macroscopic mobility-ratio trends. It reproduced saturation-profile classes, the compact-to-dendritic transition, and declining sweep efficiency with increasing mobility ratio. Three-dimensional calculations revealed tubular pathways, bypass, coalescence, and pressure-field shielding. Mesh, realization, and connectivity comparisons showed that directional treatment affects the resolved morphology, while GPU pressure-solver tests demonstrated acceleration. The framework provides a unified computational route from reservoir-relevant mobility closure to quantitative three-dimensional morphology, connectivity-sensitivity assessment, pressure-field interpretation, and accelerated sparse solution for viscosity-dominated porous-media displacement.
