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The success of foam to reduce CO 2 mobility in CO 2 enhanced oil recovery and CO 2 storage operations depends on foam stability in the reservoir. Foams are thermodynamically unstable, and factors such as surfactant adsorption, the presence of oil, and harsh reservoir conditions can cause the foam to destabilize. Pore-level foam coarsening and anti-coarsening mechanisms are not, however, fully understood and characterized at reservoir pressure. Using lab-on-a-chip technology, we probe dense (liquid) phase CO 2 foam stability and the impact of Ostwald ripening at 100 bars using dynamic pore-scale observations. Three types of pore-level coarsening were observed: (1) large bubbles growing at the expense of small bubbles, at high aqueous phase saturations, unrestricted by the grains; (2) large bubbles growing at the expense of small bubbles, at low aqueous phase saturation, restricted by the grains; and (3) equilibration of plateau borders. Type 3 coarsening led to stable CO 2 foam states eight times faster than type 2 and ten times faster than type 1. Anti-coarsening where CO 2 diffused from a large bubble to a small bubble was also observed. The experimental results also compared stabilities of CO 2 foam generated with hybrid nanoparticle–surfactant solution to CO 2 foam stabilized by only surfactant or nanoparticles. Doubling the surfactant concentration from 2500 to 5000 ppm and adding 1500 ppm of nanoparticles to the 2500 ppm surfactant-based solution resulted in stronger foam, which resisted Ostwald ripening. Dynamic pore-scale observations of dense phase CO 2 foam revealed gas diffusion from small, high-curvature bubbles to large, low-curvature bubbles and that the overall curvature of the bubbles decreased with time. Overall, this study provides in situ quantification of CO 2 foam strength and stability dynamics at high-pressure conditions. Article Highlights A comprehensive laboratory investigation of CO 2 foam stability and the impact of Ostwald ripening. Pore-level foam coarsening and anti-coarsening mechanisms insights.

Integrating renewable energy requires robust, large-scale storage solutions to balance intermittent supply. Underground hydrogen storage (UHS) in geological formations, such as salt caverns, depleted hydrocarbon reservoirs, or aquifers, offers a promising way to store large volumes of energy for seasonal periods. This review focuses on the biological aspects of UHS, examining the biogeochemical interactions between H2, reservoir minerals, and key hydrogenotrophic microorganisms such as sulfate-reducing bacteria, methanogens, acetogens, and iron-reducing bacteria within the gas–liquid–rock–microorganism system. These microbial groups use H2 as an electron donor, triggering biogeochemical reactions that can affect storage efficiency through gas loss and mineral dissolution–precipitation cycles. This review discusses their metabolic pathways and the geochemical interactions driven by microbial byproducts such as H2S, CH4, acetate, and Fe2+ and considers biofilm formation by microbial consortia, which can further change the petrophysical reservoir properties. In addition, the review maps 76 ongoing European projects focused on UHS, showing 71% target salt caverns, 22% depleted hydrocarbon reservoirs, and 7% aquifers, with emphasis on potential biogeochemical interactions. It also identifies key knowledge gaps, including the lack of in situ kinetic data, limited field-scale monitoring of microbial activity, and insufficient understanding of mineral–microbe interactions that may affect gas purity. Finally, the review highlights the need to study microbial adaptation over time and the influence of mineralogy on tolerance thresholds. By analyzing these processes across different geological settings and integrating findings from European research initiatives, this work evaluates the impact of microbial and geochemical factors on the safety, efficiency, and long-term performance of UHS.

Understanding porous media flow is inherently a multi-scale challenge, where at the core lies the aggregation of pore-level processes to a continuum, or Darcy-scale, description. This challenge is directly mirrored in image processing, where pore-scale grains and interfaces may be clearly visible in the image, yet continuous Darcy-scale parameters may be what are desirable to quantify. Classical image processing is poorly adapted to this setting, as most techniques do not explicitly utilize the fact that the image contains explicit physical processes. Here, we extend classical image processing concepts to what we define as “physical images” of porous materials and processes within them. This is realized through the development of a new open-source image analysis toolbox specifically adapted to time-series of images of porous materials.

This technical note describes the FluidFlower concept, a new laboratory infrastructure for geological carbon storage research. The highly controlled and adjustable system produces a strikingly visual physical ground truth of studied processes for model validation, comparison and forecasting, including detailed physical studies of the behavior and storage mechanisms of carbon dioxide and its derivative forms in relevant geological settings for subsurface carbon storage. The design, instrumentation, structural aspects and methodology are described. Furthermore, we share engineering insights into construction, operation, fluid considerations and fluid resetting in the porous media. The new infrastructure enables researchers to study variability between repeated CO 2 injections, making the FluidFlower concept a suitable tool for sensitivity studies on a range of determining carbon storage parameters in varying geological formations.

The ability of foam to reduce CO 2 mobility in CO 2 sequestration and CO 2 enhanced oil recovery processes relies on maintaining foam stability in the reservoir. Foams can destabilize in the presence of oil due to mechanisms impacting individual lamellae. Few attempts have been made to measure the stability of CO 2 foams in the presence of oil in a realistic pore network at reservoir pressure. Utilizing lab-on-a-chip technology, the pore-level stability of dense-phase CO 2 foam in the presence of a miscible and an immiscible oil was investigated. A secondary objective was to determine the impact of increasing surfactant concentration and nanoparticles on foam stability. In the absence of oil, all surfactant-based foaming solutions generated fine-textured and strong foam that was less stable both when increasing surfactant concentrations and when adding nanoparticles. Ostwald ripening was the primary destabilization mechanism both in the absence of oil and in the presence of immiscible oil. Moreover, foam was less stable in the presence of miscible oil, compared to immiscible oil, where the primary destabilization mechanism was lamellae rupture. Overall, direct pore-scale observations of dense-phase CO 2 foam in realistic pore network revealed foam destabilization mechanisms at high-pressure conditions. Highlights Pore-scale observations of dense-phase CO 2 foam in realistic pore network revealed foam destabilization mechanisms at high-pressure conditions. A comprehensive laboratory investigation of CO2 foam stability in the presence of oil at high pressure.

Accumulation of microbial biomass and its influence on porous media flow were investigated under saturated flow conditions. Microfluidic experiments were performed with model organisms, and their accumulation was observed in the pore space and on the sub-pore scale. Time-lapse optical imaging revealed different modes of biomass accumulation through primary colonization, secondary growth, and filtration events, showing the formation of preferential flow pathways in the flooding domain as result of the increasing interstitial velocity. Navier–Stokes–Brinkmann flow simulations were performed on the segmented images—a digital-twin approach—considering locally accumulated biomass as impermeable or permeable based on optical biomass density. By comparing simulation results and the experimental responses, it was shown that accumulated biomass can be considered as a permeable medium. The average intra-biomass permeability was determined to be 500 ± 200 mD, which is more than a factor of 10 larger than previously assumed in modeling studies. These findings have substantial consequences: (1) a remaining interstitial permeability, as a result of the observed channel formation and the intra-biomass permeability, and (2) a potential advective nutrient supply, which can be considered more efficient than a purely diffusive supply. The second point may lead to higher metabolic activity and substrate conversion rates which is of particular interest for geobiotechnological applications.

The accuracy and robustness of numerical models of geologic CO 2 sequestration are almost never quantified with respect to direct observations that provide a ground truth. Here, we conduct CO 2 injection experiments in meter-scale, quasi-2D tanks with porous media representing stratigraphic sections of the subsurface, and compare them to numerical simulations of those experiments. We evaluate (1) the value of prior knowledge of the system, expressed in terms of ex situ measurements of the tank sands’ multiphase flow properties (local data), with respect to simulation accuracy; and (2) the forecasting capability of history-matched numerical models, when applied to different settings. We match three versions of a numerical simulation model—each with access to an increasing level of local data—to a CO 2 injection experiment in Tank 1 ( 89.7 × 47 × 1.05  cm). Matching is based on a quantitative comparison of CO 2 migration at different times from timelapse image analysis. Next, use the matched models to make a forecast of a different injection scenario in Tank 1 and, finally, a different injection scenario in Tank 2 ( 2.86 × 1.3 × 0.019  m), which represents an altogether different stratigraphic section. The simulation model can qualitatively match the observed free-phase and dissolved CO 2 plume migration and convective mixing. Quantitatively, simulations are accurate during the injection phase, but their concordance decreases with time. Using local data reduces the time required to history match, although the forecasting capability of matched models is similar. The sand–water– CO 2 ( g ) system is very sensitive to effective permeability and capillary pressure changes; where heterogeneous structures are present, accurate deterministic estimates of CO 2 migration are difficult to obtain.

Nanoparticles have gained attention for increasing the stability of surfactant-based foams during CO2 foam-enhanced oil recovery (EOR) and CO2 storage. However, the behavior and displacement mechanisms of hybrid nanoparticle–surfactant foam formulations at reservoir conditions are not well understood. This work presents a pore- to core-scale characterization of hybrid nanoparticle–surfactant foaming solutions for CO2 EOR and the associated CO2 storage. The primary objective was to identify the dominant foam generation mechanisms and determine the role of nanoparticles for stabilizing CO2 foam and reducing CO2 mobility. In addition, we shed light on the influence of oil on foam generation and stability. We present pore- and core-scale experimental results, in the absence and presence of oil, comparing the hybrid foaming solution to foam stabilized by only surfactants or nanoparticles. Snap-off was identified as the primary foam generation mechanism in high-pressure micromodels with secondary foam generation by leave behind. During continuous CO2 injection, gas channels developed through the foam and the texture coarsened. In the absence of oil, including nanoparticles in the surfactant-laden foaming solutions did not result in a more stable foam or clearly affect the apparent viscosity of the foam. Foaming solutions containing only nanoparticles generated little to no foam, highlighting the dominance of surfactant as the main foam generator. In addition, foam generation and strength were not sensitive to nanoparticle concentration when used together with the selected surfactant. In experiments with oil at miscible conditions, foam was readily generated using all the tested foaming solutions. Core-scale foam-apparent viscosities with oil were nearly three times as high as experiments without oil present due to the development of stable oil/water emulsions and their combined effect with foam for reducing CO2 mobility

We present a framework for integrated experiments and simulations of tracer transport in heterogeneous porous media using digital twin technology. The physical asset in our setup is a meter-scale FluidFlower rig. The digital twin consists of a traditional physics-based forward simulation tool and a correction technique which compensates for mismatches between simulation results and observations. The latter augments the range of the physics-based simulation and allows us to bridge the gap between simulation and experiments in a quantitative sense. We describe the setup of the physical and digital twin, including data transfer protocols using cloud technology. The accuracy of the digital twin is demonstrated on a case with artificially high diffusion that must be compensated by the correction approach, as well as by simulations in geologically complex media. The digital twin is then applied to control tracer transport by manipulating fluid injection and production in the experimental rig, thereby enabling two-way coupling between the physical and digital twins.