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Keywords: Salt precipitation, Porous media, Permeability reduction, X-ray tomography
Salt crystallization is a well-known issue during subsurface gas injection and production operations, particularly in the context of CO₂ storage in saline aquifers, where salt precipitation can significantly impair permeability and injectivity. Experimental studies have reported permeability reductions ranging from 10% to 83% [1], emphasizing the severity of pore clogging by salt. Most laboratory investigations rely on conventional drying at reservoir temperature, which often induces localized salt crystallization near sample boundaries, leading to heterogeneous salt distributions that hamper the derivation of representative permeability–salt fraction volume relationships at the representative elementary volume (REV) scale. However, several studies indicate that under certain subsurface conditions, such as high injection flow rates, salt precipitation may occur more uniformly within the pore space [2], motivating experimental approaches capable of reproducing homogeneous salt distributions.
In this study, we propose an experimental protocol designed to promote homogeneous salt precipitation within porous media and to directly quantify its impact on permeability. The protocol consists of repeated cycles of imbibition with a saturated KCl solution followed by controlled vacuum drying, leading to progressive in-pore salt accumulation. Experiments are conducted on both artificial porous media (VitraPOR cylinders, 6 mm in diameter, with pore sizes of 40–100 µm and 100–160 µm) and natural sandstones (Bentheimer and Vosges). After every two cycles, X-ray tomography and mass measurements are performed to quantify salt distribution and accumulation, while permeability is measured using a Hassler cell.
X-ray tomography confirms that vacuum drying enables a spatially homogeneous salt distribution throughout the pore network, with salt preferentially accumulating in the same pore regions across cycles. Permeability measurements reveal contrasted behaviours between artificial and natural porous media. For example, in model samples such as VitraPOR Por01, permeability decreases progressively and reproducibly with salt accumulation. For model samples with different pore size classes, the permeability decline follows an exponential trend and shows good agreement with the Verma–Pruess model, consistent with homogeneous salt crystallization at the pore scale. In contrast, for natural sandstone such as Bentheimer, permeability remains initially stable over the first cycles before undergoing a sharp drop despite a homogeneous salt distribution observed by X-ray tomography. After this abrupt transition, permeability stabilizes, while the permeability–porosity relationship becomes increasingly scattered and deviates from classical theoretical models, highlighting the dominant role of intrinsic microstructural heterogeneity in natural rocks.
These results demonstrate that homogeneous salt precipitation enables a direct experimental quantification of permeability loss as a function of salt accumulation at the REV scale in model porous media, while also revealing the limitations of analytical permeability models when applied to natural sandstones. The proposed experimental framework provides a valuable dataset for validating and refining permeability–porosity relationships used in reactive transport and subsurface flow models.
| References | [1] N. Muller, R. Qi, E. Mackie, K. Pruess, and M. J. Blunt, CO₂ injection impairment due to halite precipitation, Energy Procedia, 1(1), 3507–3514 (2009). [2] L. Sun et al., Salt precipitation and pore structure changes during CO₂ injection into porous media, J. Clean. Prod., 505, 145446 (2025). |
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| Country | France |
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