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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.

Carbon capture and subsequent storage (CCS) is identified as a necessity to achieve climate commitments. Permanent storage of carbon dioxide (CO2) in subsurface saline aquifers or depleted oil and gas reservoirs is feasible, but large-scale implementation of such storage has so far been slow. Although sandstone formations are currently most viable for CO2 sequestration, carbonates play an important role in widespread implementation of CCS; both due to the world-wide abundancy of saline aquifers in carbonate formations, and as candidates for CO2-EOR with combined storage. Acidification of formation brine during CO2 injection cause carbonate dissolution and development of reactive flow patterns. Using calcite-functionalization of micromodels we experimentally investigate fundamental pore-scale reactive transport dynamics relevant for carbonate CO2 storage security. Calcite-functionalized, two-dimensional and siliconbased, pore scale micromodels were used. Calcite precipitation was microbially induced from the bacteria Sporosarcina pasteurii and calcite grains were formed in-situ. This paper details an improved procedure for achieving controlled calcite precipitation in the pore space and characterizes the precipitation/mineralization process. The experimental setup featured a temperature-controlled micromodel holder attached to an automatic scanning stage. A high-resolution microscope enabled full-model (22x27 mm) image capture at resolution of 1.1 µm/pixel within 82 seconds. An in-house developed image-analysis python script was used to quantify porosity alterations due to calcite precipitation. The calcite-functionalized micromodels were found to replicate natural carbonate pore geometry and chemistry, and thus may be used to quantify calcite dissolution and reactive flow at the pore-scale.

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.

Positron emission tomography (PET) is routinely used for medical imaging; a current surge in published geoscientific research utilizing this modality also infer increasing interest for in-situ PET imaging in core analysis. Excellent signal to noise ratio coupled with high temporal and spatial resolution suggest that PET might become the new method-of-choice for core analysis. Obstacles related to production, transfer and handling of radioactive fluids and gases must, however, be dealt with for PET to become a widely used core scale imaging technique. This paper describes an ongoing, true multidisciplinary collaboration, where pre-clinical PET imaging facilities are routinely used in core analysis to investigate dynamic fluid flow at high pressure conditions. We detail challenges and opportunities related to porous media research in established pre-clinical laboratory facilities designed for small-animal imaging, and demonstrate the significant potential of PET imaging in core scale analysis in a context related to long-term porous media carbon storage. Explicit imaging of several fluid phases is possible by PET imaging using a range of readily available radiotracers. Relevant radiotracers to carbon storage in porous media are e.g. the carbon radioisotope 11 C and water-soluble tracer 18 F. These are both short-lived tracers (20 - 110 min) and must be used in high doses of radiation, which present challenges related to safe transfer and handling. Although there are several obstacles to conduct advanced core analysis in hospital imaging facilities (some of which are detailed in this paper), significant advantages include trained personnel on-site to operate a local cyclotron, procedures in place to ensure safe and efficient transfer of short-lived radiopharmaceuticals from the cyclotron, and advanced image analysis capabilities available. Cyclotrons are widely available worldwide (currently more than 1200 operating cyclotrons), often located in close proximity to medical and pre-clinical imaging facilities and academic institutions. Similar collaborations may therefore also be possible elsewhere, reducing the need for allocated geophysical PET-scanners and lowering the threshold for routinely using PET imaging in core analysis.

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.