Speaker
Description
Injection of CO₂ into saline aquifers can induce capillary-driven drying of residual brine in the near-wellbore region, leading to salt precipitation and a potential reduction in injectivity. This phenomenon represents a key operational risk for geological CO₂ storage, particularly under conditions where drying and precipitation processes are strongly coupled to local flow behaviour. Previous experimental and numerical studies have demonstrated that CO₂ injection rate plays an important role in controlling whether salt precipitation becomes spatially localised or more uniformly distributed within the pore space [1–7]. Despite these advances, for realistic storage formations the injection rate at which precipitation behaviour transitions between different spatial regimes remains poorly understood. Moreover, it is still unclear how such rate-dependent transitions should be incorporated into porosity–permeability relationships commonly used in reservoir-scale simulations of injectivity evolution.
In this study, we examine the existence of a threshold CO₂ injection rate governing salt precipitation behaviour in a representative UK sandstone storage formation. The investigation is based on CO₂ coreflooding experiments conducted under controlled conditions. These experiments are complemented by high-resolution three-dimensional micro-CT imaging, enabling direct pore-scale characterisation of salt precipitation patterns formed under different flow regimes. This combined experimental approach allows precipitation behaviour to be assessed in a physically realistic pore structure representative of saline aquifer storage sites.
To bridge pore-scale observations with larger-scale modelling needs, pore-scale modelling is employed to evaluate flow behaviour and to establish a porosity–permeability evolution framework associated with salt precipitation during CO₂ injection. Rather than focusing on specific quantitative outcomes, the emphasis is placed on developing a generalised modelling approach that captures rate-dependent effects while remaining suitable for upscaling to reservoir-relevant conditions.
The integrated experimental and numerical framework in the present work provides a systematic basis for identifying transitions in precipitation behaviour associated with changes in injection rate and for formulating porosity–permeability relationships applicable to CO₂ storage scenarios. The outcomes of this work are intended to support injectivity modelling and inform injection strategy design in saline aquifers, particularly in the near-wellbore region where salt precipitation may influence operational performance. More broadly, the study highlights the importance of explicitly accounting for flow-rate-dependent processes when representing coupled pore-scale and reservoir-scale behaviour during geological CO₂ storage.
| References | [1] Ott, H., de Kloe, K., Marcelis, F., & Makurat, A. (2011). Injection of supercritical CO2 in brine saturated sandstone: pattern formation during salt precipitation. Energy Procedia, 4, 4425-4432. [2] Ott, H., de Kloe, K., Van Bakel, M., Vos, F., Van Pelt, A., Legerstee, P., ... & Makurat, A. (2012). Core-flood experiment for transport of reactive fluids in rocks. Review of Scientific Instruments, 83(8). [3] Ott, H., Snippe, J., De Kloe, K., Husain, H., & Abri, A. (2013). Salt precipitation due to sc-gas injection: Single versus multi-porosity rocks. Energy Procedia, 37, 3319-3330. [4] Roels, S. M., Ott, H., & Zitha, P. L. (2014). μ-CT analysis and numerical simulation of drying effects of CO2 injection into brine-saturated porous media. International Journal of Greenhouse Gas Control, 27, 146-154. [5] Ott, H., Roels, S. M., & De Kloe, K. (2015). Salt precipitation due to supercritical gas injection: I. Capillary-driven flow in unimodal sandstone. International Journal of Greenhouse Gas Control, 43, 247-255. [6] Ji, T., Haghi, A. H., Jiang, P., Chalaturnyk, R., & Xu, R. (2025). Capillary‐Driven transport and precipitation of salt in heterogeneous structures during carbon sequestration. Geophysical Research Letters, 52(13), e2024GL114388. [7] Chen, X. S., Hu, R., Zhou, C. X., Xiao, Y., Yang, Z., & Chen, Y. F. (2024). Capillary‐driven backflow during salt precipitation in a rough fracture. Water Resources Research, 60(3), e2023WR035451. |
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| Country | United Kingdom |
| Student Awards | I would like to submit this presentation into the Earth Energy Science (EES) and Capillarity Student Poster Awards. |
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