Microporosity is commonly assumed to be non-connected porosity and not commonly studied in geoengineering industry. However, the presence of micropores plays a key role in connecting macropores and it can contribute significantly to the overall flow performance. In this study, targeted CO₂ storage carbonate fields in Southeast Asia have significant amounts of microporosity ranging from 10 to 60% of the total measured porosity. Microporosity can only be seen in high resolution images. To study the unresolved and the resolved microporosity, Middle Miocene carbonate samples from CO₂ storage candidate fields were scanned using lower resolution micro-computed micro-tomography (micro-CT) and higher resolution synchrotron light source to understand the pore scale structure of the carbonate sample at different length scales. This paper proposes a proof-of-concept upscaling method that integrates multiscale 3D imaging techniques and trendline analysis to establish porosity-permeability relationships with microporosity insight. After image acquisition and processing, the images were divided into smaller sub-volumes. Pore-scale modelling was conducted to predict the permeability using Darcy-Brinkman-Stokes (DBS) model. Then, a nano-scale porosity-permeability transform is generated using natural log trendline fitting based on simulation results. The porosity-permeability transform is further extended to three cases to cover the low case, mid case, and high case of datapoint fittings and is further validated with laboratory measured data. The established porosity-permeability transforms in this study have been applied to compare with petrophysical derived porosity-permeability transforms with better performance (higher R² value) for low permeability datapoint. The multiscale imaging upscaling workflow has integrated machine learning during image segmentation with pore-scale modelling and trendline fitting during the upscaling study. It emphasises the importance of seeing the unseen (unresolved microporous phase) to understand the internal texture and microstructure of a rock sample in order to understand the connectivity of the overall flow performance in a carbonate rock.

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Subsurface porous rocks hold significant hydrogen (H₂) storage potential to support an H₂-based energy future. Understanding H₂ flow and trapping in subsurface rocks is crucial to reliably evaluate their storage efficiency. In this work, we perform cyclic H₂ flow visualization experiments on a layered rock sample with varying pore and throat sizes. During drainage, H₂ follows a path consisting of large pores and throats, through a low permeability rock layer, substantially reducing H₂ storage capacity. Moreover, due to the rock heterogeneity and depending on the experimental flow strategy, imbibition unexpectedly results in higher H₂ saturation compared to drainage. These results emphasize that small-scale rock heterogeneity, which is often unaccounted for in reservoir-scale models, plays a vital role in H₂ displacement and trapping in subsurface porous media, with implications for efficient storage strategies.

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Hypothesis

Underground hydrogen (H2) storage is a potentially viable solution for large-scale cyclic H2 storage; however, the behavior of H2 at subsurface pressure and temperature conditions is poorly known. This work investigates if the pore-scale displacement processes in H2-brine systems in a porous sandstone can be sufficiently well defined to enable effective and economic storage operations. In particular, this study investigates trapping, dissolution, and wettability of H2-brine systems at the pore-scale, at conditions that are realistic for subsurface H2 storage.

Experiments

We have performed in situ X-ray imaging during a flow experiment to investigate pore-scale processes during H2 injection and displacement in a brine saturated Bentheimer sandstone sample at temperature and pressure conditions representative of underground reservoirs. Two injection schemes were followed for imbibition: displacement of H2 with H2-equilibrated brine and with non-H2-equilibrated brine. The results from the two cycles were compared with each other.

Findings

The sandstone was found to be wetting to the brine and non-wetting to H2 after both displacement cycles, with average contact angles of 54° and 53°, for H2-equilibrated and non-H2-equilibrated brine, respectively. We also found a higher recovery of H2 (43.1%) when displaced with non-H2-equilibrated brine compared to that of H2-equilibrated brine (31.6%), indicating potential dissolution of H2 in the unequilibrated, imbibing brine at reservoir conditions. Our results suggest that underground H2 storage may indeed be a suitable strategy for energy storage, but considerable further research is needed to fully comprehend the pore-scale interactions at reservoir conditions.@en