Viktoriya Yarushina

The macroscopic properties of porous rocks are governed by their complex microstructure and the constitutive behavior of the solid matrix. Traditional effective media models, often based on analytical solutions for isolated cavities or inclusions, are typically limited to linear elastic or viscous rheologies. However, the elastic-plastic response characteristic of rocks is rarely captured by these approaches. Building on our previous work [1], which provided an analytical solution for elastoplastic compaction and revealed how the effective bulk modulus depends on both elastic properties and yield strength, we extend the framework to include shear effects. Our model demonstrates that plastic yielding couples shear and volumetric responses, leading to phenomena such as shear-enhanced compaction and significant deviations from traditional linear predictions.Here, we extend this framework [1] by deriving the effective shear modulus and exploring how plastic yielding jointly controls both bulk and shear responses [2]. We systematically test the limits of the analytical solution against high-resolution numerical models of multiple interacting voids, in both 2D (cylindrical/elliptical voids) and 3D (spherical voids) geometries. Our results show that the elastoplastic analytical solution remains valid for rocks with higher porosities of up to 20%, extending beyond typical dilute-distribution assumptions. For cylindrical voids in the 2D case, the merging of plastic zones leads to a sharp decrease in the effective bulk modulus and the onset of full pore collapse. The analytical solution for the critical pressure at which full pore collapse occurs agrees well with the numerical results. For spherical voids arranged in 3D configurations, plastic zone merging leads to a more gradual reduction in the effective bulk modulus. Furthermore, under the influence of shear stresses, the development of aligned plastic zones leads to stress-induced anisotropy in initially isotropic materials.For numerical homogenization, we employ two complementary approaches: a GPU‑accelerated finite‑difference solver (dynamic relaxation method) and a finite/spectral‑element solver (based on CAE Fidesys [3] computational kernel). To ensure the reliability of the calculated effective moduli, we implement periodic boundary conditions, which we find essential for minimizing spurious boundary effects in both 2D and 3D simulations. The developed numerical tools are capable of handling complex rock microstructures, broadening the potential applications of this modeling approach.MY acknowledges the support by the Russian Science Foundation under grant 24-77-10022. 1. Yarushina, V.M., Podladchikov Y.Y., & Wang L.H. (2020). Model for (de)compaction and porosity waves in porous rocks under shear stresses. Journal of Geophysical Research: Solid Earth, 125(8), e2020JB019683.2. Yakovlev, M.Ya., Yarushina, V.M., Bystrov, I.D., Nikitin, L.S., & Podladchikov, Yu.Yu. (2025). Benchmarking effective moduli in porous elastoplastic materials. International Journal of Mechanical Sciences, 306, 110854.3. https://cae-fidesys.com/

Understanding and quantifying the flow of multiple pore fluid phases is a key component to understanding many natural and engineered reservoir processes. A well-known example is the migration of hydrocarbon phases in sedimentary reservoirs, including natural migration, conventional production, and enhanced hydrocarbon recovery. As Carbon Capture and Storage (CCS) emerged as a potential strategy to combat climate change, understanding multiphase flow processes of supercritical CO2 and the various pore fluids is at the forefront of scientific interest.Our governing equations are based on the conservation of mass and momentum in two immiscible fluid phases. The fluid phases may be compressible or incompressible. We assume the inertial terms to be negligible in both phases and momentum transfer to happen in the Darcy-flow regime. Multiple fluid phase effects are introduced in the mathematical model by saturation-dependent relative permeabilities and fluid viscosities, which uniquely determine the total mobility, relative mobility, and fractional fluid flow curves. Here we consider capillary effects negligible. This results in two independent equations: an elliptic equation for fluid pressure and a hyperbolic equation for saturation.We choose a staggered-grid-based finite-difference discretization. The elliptic fluid pressure equation is solved using pseudo-transient iterations. The hyperbolic saturation equation is solved using a conservative first-order upwind scheme. Multiple coupling and time-stepping options (e.g., explicit/implicit, first order/higher order) are tested against an analytical solution. The numerical scheme can be implemented on GPUs in a straightforward manner using the ParallelStencil.jl package in Julia. We will provide some examples of various reservoir applications, which will also be used as performance benchmarks. Finally, we will discuss the potential of the presented numerical scheme to be implemented in a broader THMC framework.

The CETP-funded DecarbFaroe project advances CO2 mineralization in volcanic geological formations by moving from academic research to low-cost, commercially viable onshore pilot demonstrations, starting with the first kiloton-scale injections on the Faroe Islands. By leveraging the untapped potential of globally abundant mafic rocks for distributed, permanent onshore CO2 storage, the project addresses a critical gap in Carbon Capture and Storage (CCS). This approach tackles the high costs and limited adoption of large-scale saline aquifer CCS while overcoming acceptance and scalability challenges associated with subsurface mineralization.Following extensive site characterization, the project will inject up to 1,000 tons of CO2 (dissolved in water) from a local biogas plant into subsurface basalt, demonstrating carbonate mineralization and permanent storage through geochemical and geophysical monitoring. The project also plans dissemination to similar geological settings, including immediate scale-up efforts in India and Brazil.Beyond technical objectives, DecarbFaroe addresses regulatory, social, and commercial feasibility, aiming for low costs (

Serpentinites are hydrous rocks with a wide pressure-temperature stability range and play a key role in subduction zone dynamics and fluid transfer within the downgoing slab. During subduction, progressive metamorphic reactions transform hydrous mineral assemblages into anhydrous phases. For example, the breakdown of brucite through reactions with antigorite, followed by the terminal breakdown of antigorite to olivine and enstatite, releases aqueous fluids that influence the deep-water cycle and induce major changes in rock density, porosity, permeability, and mechanical strength. Field observations and numerical studies suggest that chemical heterogeneities and variations in fluid composition can localize dehydration reactions and generate fluid pathways. The mechanical-chemical coupling during such fluid pathway generation can be studied with hydro-mechanical-chemical (HMC) numerical models, however, such HMC modelling remains challenging.Here, we present a HMC model that couples poromechanical deformation and Darcy flow with a thermodynamic model for chemically driven serpentinite dehydration. We develop a two-dimensional numerical HMC model using finite-difference discretization and an accelerated pseudo-transient solution method based on an iterative, matrix-free approach. A particular focus is to make the HMC model conservative to guarantee accurate mass conservation during chemical transport. The numerical implementation integrates thermodynamically constrained look-up tables that relate chemical concentrations with solid and fluid densities to simulate the temporal and spatial evolution of reaction-induced density changes.We use a new analytical solution for chemically driven reaction-front propagation to test the numerical model. This analytical solution has been validated with laboratory experiments. Initial applications focus on simplified configurations in which a homogeneous medium with a characteristic chemical composition is infiltrated by a fluid with a different silica content, thereby controlling the initiation and propagation of dehydration reactions. The first numerical experiments investigate how dehydration reaction fronts evolve in response to chemical variations. A primary objective of this contribution is to quantify the fundamental controls of chemical heterogeneity on dehydration dynamics and reaction-front propagation as well as the impact of mechanical deformation on such dehydration.

Helium, like hydrogen, are critical resources essential to the energy transition. Despite different end uses for helium (e.g., coolant for fission and fusion reactors) and hydrogen (e.g., energy – storage, fuel), the two gases share key similarities, while also having some notable differences. It has been established that they have overlapping source mechanisms (e.g., radioactive decay within basement rocks, radiolysis associated with shales, etc.) resulting in the two gases being co-located in a number of exploration wells globally. Likewise, due to a similarity in the kinetic diameters of the molecules although not the reactive nature of them, physical traps that work for hydrogen, should in principle also work for helium. However, transport and trapping of these molecules are affected by a number of competing factors. Therefore, the transport mechanisms and rates at both a basin and pore-scale remain poorly understood.Here we explore the nature of helium and hydrogen transport within porous media utilizing a microfluidic cell, representative of typical upper-crustal siliciclastics found in the subsurface, in combination with time-lapsed geometrical image analysis. At the pore scale, concentration of both elements (i.e. He, H2) within the pore space are dependent on a number of factors, including (1) the number of ejection pulses from a given source migrating through the same pore space, (2) the rate of arrival from the source, and (3) the impact of local hydrological currents on the pore space.The laboratory experiments are combined with numerical modeling of multiphase fluid flow in porous media using a continuum approach. These models allow pore-scale observations from the microfluidic experiments to be upscaled, providing insight into the influence of flow rate, injection cyclicity, and permeability heterogeneity on gas migration and plume stability at the reservoir scale.

Transitioning to low-emission energy systems increasingly relies on subsurface technologies such as carbon capture and storage (CCS), geological hydrogen storage, and the sealing and abandonment of legacy hydrocarbon wells. All these technologies require reliable long-term containment, which depends strongly on the sealing capacity of caprocks. Shales commonly form the primary barrier above storage reservoirs, benefiting from their very low permeability and relatively ductile deformation behavior. During injection, as the pore pressure in the storage reservoir increases and injected fluids start to invade the shale caprock, pressure-driven changes in pore structure and saturation state may directly impact transport pathways, potentially increasing leakage risk. Given the critical role of shale caprocks in preventing CO₂ migration, laboratory core-scale measurements are essential to assess any such changes in caprock properties.This study presents a laboratory experimental program designed to quantify how CO₂ and CO₂–water flow alters shale core plug permeability and pressure response. Cylindrical shale core plugs are assembled in an experimental cell with controlled confinement, and permeability is determined from continuous monitoring of inlet and outlet pressures, differential pressure, and flow rate during constant volumetric injection. In the first set of tests, CO₂ is injected CO₂ is injected through shale core plugs under different confining pressures to evaluate how changes in external loading and flow conditions influence measured permeability and pressure transients. These measurements provide insight into stress-sensitive flow behavior and whether permeability changes are reversible or exhibit hysteresis after pressure cycling.In a second set of experiments, a three-step injection sequence will be performed to mimic saturation-history effects relevant to CO₂ storage. Starting with a water-saturated sample, first CO2 will be injected, followed by water, and then CO2 again. Throughout the sequence, pressure evolution and permeability estimates are tracked to evaluate how switching between injected fluids, and fluid–rock interactions influence transport. The CO₂–water–CO₂ protocol is used to assess whether water introduction modifies flow pathways, and whether the subsequent CO₂ reinjection restores, further reduces, or permanently alters the permeability relative to the initial CO₂ baseline.The resulting dataset links injection history and confining-pressure changes to permeability evolution in shale caprock analogs, providing experimental constraints for evaluating caprock performance in CCS. In addition, the measurements will be used to calibrate numerical models of flow in low-permeability caprock, strengthening model and improving predictive capability for caprock integrity assessment under realistic injection scenarios.

Reactive flow, coupling transport and chemical alteration processes, is a key geological driver, taking place over a wide range of conditions and scales. In addition to natural phenomena (e.g., contact metamorphism; ore formation), many geo-energy technologies are also dependent on, or affected by reactive flow.One well-studied example of reactive flow is the carbonation, alteration, and potential degradation of a typical wellbore cement exposed to a CO2-bearing fluid under reservoir conditions. As CO2 permeates the cement, it reacts with Ca2+ from portlandite and other cement gel phases to form CaCO3, leading to an increase in solid volume, and therefore a decrease in porosity (and permeability). Different experimental methodologies have been applied to better understand the progression of the carbonation front, including static exposure in batch apparatuses, and exposure to forced flow driven by a pressure gradient along the sample axis. However, progression of the carbonation front typically shows a dependence on the square root of time, suggesting that even under high pressure gradients, transport is still controlled by diffusion through the low-permeability matrix, rather than advective flow.Interestingly, cement carbonation is often associated with a sharp reaction front, with large changes in mineral assemblage and fluid composition and pH across a relatively short distance. In this presentation, we take a closer look at the carbonation fronts in a set of cement samples exposed to wet supercritical CO2 and CO2-saturated water, using both batch and forced-flow methodologies. We will combine observations based on laboratory experiments with analytical and numerical modelling to address three closely related aspects of reactive transport. First, by explicitly evaluating the Peclet number, we demonstrate that diffusion dominates over advection under the tested conditions, providing a unified interpretation of batch and flow-through experiments. Second, we distinguish between the true diffusion coefficient of CO₂ in the pore fluid and the effective diffusion coefficient inferred from reaction-front propagation, showing that the latter is an emergent quantity controlled by reaction thermodynamics and concentration contrasts rather than a material property. Third, using a reactive transport model that couples fluid transport, solid-fluid reactions, and porosity evolution, we investigate the conditions under which sharp reaction fronts arise and contrast them with regimes that produce smooth transition zones.

During the offshore petroleum production era, thousands of wells were drilled, many in regions characterized by active natural gas seepage. Observations show gas emissions near plugged and abandoned wells, raising key questions about well integrity and the origin of detected seepage. It remains unclear whether such seepage is induced by compromised wells, would occur naturally in the absence of wells, or reflects contributions from deeper reservoirs versus shallow gas accumulations.In this study, we investigate these questions using fully coupled fluid‑flow and geomechanical modeling. Our simulations incorporate realistic deformation behavior of soft sediments, pressure‑dependent permeability, and two‑phase fluid flow. The study focuses on the Norwegian channel and its western bank in the northern North Sea, which hosts the Heincke and Sentinel natural seep systems. Geological and geophysical data collected during a recent research cruise were integrated into a detailed subsurface model.We simulate natural fluid migration without wells and compare it with scenarios including a hypothetical well-related seep. The results demonstrate that the presence of a well perturbs natural flow pathways, modifies seepage patterns, and alters both the timing and magnitude of seepage. We quantify seepage rates for natural and well‑influenced scenarios and identify zones where migrating fluids are most likely to reach the seafloor. The modeling further reveals that seepage is inherently intermittent, with rates varying over time due to coupled hydro‑mechanical processes.

Lined rock cavern (LRC) offer a promising solution for underground hydrogen storage, which requires high pressure (>200 bar) to ensure economic viability due to hydrogen’s low volumetric density. In LRCs, the liner acts solely as a gas seal, while the rock mass bears the structural load. However, at economically feasible shallow depths (< few hundred meters), the high storage pressure significantly exceeds the low in-situ stress (on the order of 10 bars), creating a critical containment challenge.Achieving safe containment under such a pressure difference requires accurate assessment of the mechanical strength of the rock mass. A criterion often used is to limit the load below the level when plastic deformation occurs. In many cases, however, this criterion still yields safe gas pressure which are below the desired level. Increasing gas pressure above this level means that some degree of plastic deformation will occur in the rock mass. This can take the forms of continuous deformation, jointing, or cracking.Our knowledge from rock deformation experiments and LRC pilot sites indicates that there exists a safe level of inelastic deformation before storage integrity is compromised. However, the critical challenge lies in identifying how such inelastic deformation initiates, evolves, and redistributes under high internal pressure, as well as its implications for long-term cavern stability. Consequently, the mechanical response of the surrounding rock under high internal pressure remains a key uncertainty in stability assessment. Simplified elastic rheological models, which are commonly used in engineering design, may mask irreversible deformation processes in the near-field region of the cavern. In this study, a visco-elastic–viscoplastic (VEVP) model is employed to systematically investigate the mechanical behavior of the surrounding rock under cyclic gas pressurization, with particular focus on the role of rock plasticity. Model predictions are quantitatively compared with those obtained from a purely elastic formulation by varying the rock cohesion parameter. Under baseline conditions, the maximum radial displacement predicted by the VEVP model is 53% higher than that predicted by the elastic model, while the maximum circumferential strain increases by 186%. With the development of plasticity, the spatial distributions of strain and displacement evolve significantly. During the elastic stage, maximum circumferential strain is aligned with the principal stress directions, whereas maximum radial displacement occurs along directions oriented at 45° to the axes. As plastic deformation develops, the dominant deformation zone migrates toward the axial directions where plastic flow becomes most pronounced. Furthermore, plasticity-driven stress redistribution leads to stress relaxation and homogenization of deviatoric stress, accompanied by directional migration of pressure-dominated zones. Finally, the VEVP model elucidates a mechanical mechanism for potential lining–rock debonding caused by modulus mismatch. Upon depressurization, the steel lining undergoes nearly complete elastic rebound, while the surrounding rock retains irreversible plastic deformation, leading to asynchronous recovery and possible interface opening. These findings highlight the necessity of accounting for rock plasticity when assessing the mechanical stability and design of lined rock caverns for underground hydrogen storage.

The presence of liquid petroleum trapped within low-permeability vesicular basalt or mafic intrusions is more than a scientific curiosity, as it also challenges the conventional fluid migration and storage models in porous media. Its presence is significant because it may suggest complex primary magmatic porosity development, low temperature alteration and resulting fluid pathways, nano-scale deformation, or other processes leading to secondary porosity development. Thus the cases offer insights into processes controlling hydrocarbon and fluid flow systems in volcanic areas. In this contribution, we present the study of a Permian dolerite dyke at Tvedestrand in Norway and a vesicular basalt sample from West Greenland, both of which contain liquid oil. The Tvedestrand dyke is emplaced in Precambrian gneiss that was previously overlain by Cambrian black shales. The Greenland basalt is part of the North East Atlantic igneous province, underlain by petroleum-bearing sedimentary strata. Organic geochemistry indicates both oils to be immature, hence suggesting migration through these rocks after emplacement and cooling. We also show ultrahigh-resolution photographs in natural and ultraviolet light to show the distribution of petroleum compounds and image the microstructures controlling fluid migration. The parameters controlling fluid migration in tight crystalline rocks are important to constrain, as these are directly relevant to hydrocarbon exploration in unconventional settings and for hydrogen or carbon storage. We discuss the most likely mechanisms enabling fluid migration in these systems and their broader implications.