The secure storage of carbon dioxide (CO₂) in deep saline aquifers relies on efficient injection, distribution, and trapping within reservoir rocks. Residual trapping, where disconnected CO₂ clusters are immobilised by capillary forces, is considered one of the most reliable long-term storage mechanisms, but its effectiveness depends on sweep efficiency and pore accessibility. This study used Otway sandstone cores from the CRC-8 well to compare conventional supercritical CO₂ injection (CI) with microbubble (MB) injection under reservoir conditions. NMR T₁–T₂ mapping, T₂ distribution analysis, saturation profiling, and SCAL measurements were applied to assess fluid displacement, sweep efficiency, breakthrough timing, and storage capacity.

Results showed that MBs invaded both meso- and micropores more effectively than CI, displacing brine from regions unswept during conventional injection. After drainage, CO₂ saturation reached 39.4% for MBs compared to 23.1% for CI. Following imbibition, residual trapping was 22.5% for MBs versus 16% for CI. Pc–Sw curves indicated lower capillary pressures under MB injection, confirming easier CO₂ entry into smaller pores and a more uniform sweep. Moreover, MB injection delayed breakthrough and produced more uniform saturation profiles, reducing preferential flow through high-permeability zones.

Overall, MB injection provided superior pore-scale control, enabling deeper invasion, broader sweep, and enhanced capillary trapping. By increasing storage capacity and improving conformance in previously inaccessible pores, MB injection demonstrates strong potential as a safer and more reliable approach for large-scale geological CO₂ sequestration.

Keywords: CO₂ sequestration, microbubbles, breakthrough time, sweep efficiency, storage capacity, NMR.

Anthropogenic carbon dioxide (CO₂) emissions are widely recognized as a principal driver of global climate change, contributing to rising atmospheric temperatures and increasing environmental instability. Among various mitigation strategies, carbon capture and storage (CCS) has emerged as a vital approach to reducing emissions by injecting captured CO₂ into deep geological formations such as saline aquifers. However, maintaining injectivity during CO₂ storage remains a key challenge, particularly in sandstone formations with high clay content. Two major mechanisms responsible for injectivity decline are fines migration and salt precipitation. Fines migration involves the detachment and transport of clay minerals (e.g., kaolinite) from pore walls under the influence of viscous and capillary forces. The mobilized particles tend to accumulate at pore throats, leading to permeability reduction and impaired CO₂ injectivity.

This study investigates the potential of a commercial silica-based nanoparticles (NPs) to mitigate fines migration and enhance formation stability during CO₂ injection. A series of core flooding experiments were conducted using high-clay-content sandstone samples to evaluate the effect of nanoparticle treatment on fines stabilization. Results show that, in the absence of nanoparticles, fines migration led to at least 1.5-fold reduction in permeability. In contrast, cores pre-treated with silica nanoparticles exhibited stable permeability throughout the CO₂ injection process, indicating effective fines stabilization by NPs. Effluent analyses further confirmed a high concentration of detached particles in the untreated case, while negligible fines production was observed in the nanoparticle-treated samples.

These findings suggest that nanoparticle pre-treatment can effectively mitigate fines migration during CO₂ storage in saline aquifers, enhancing formation stability and maintaining injectivity. The outcomes of this research provide valuable insights for improving the efficiency and reliability of geological CO₂ storage operations.

Joule–Thomson (JT) cooling of injected CO₂ can significantly impair well injectivity through hydrate formation, salt precipitation, and viscosity increases. These risks impose operational constraints on injection rates during CO₂ storage projects. This study develops and analyses three analytical models that describe temperature evolution during CO₂ injection into porous media under different heat exchange regimes with surrounding formations. The models account for (i) steady-state heat exchange governed by Newton’s law, (ii) non-steady-state heat exchange initiated by the CO₂ front, and (iii) non-steady-state heat exchange initiated by the thermal front. Exact solutions were derived and validated against a quasi-two-dimensional benchmark solution.

The developed models capture temperature propagation for different reservoir boundary conditions, allowing for pressure–temperature trajectories to be mapped onto the CO₂–water phase diagram. This framework enables direct assessment of hydrate formation by evaluating which sections of the injection zone will enter the hydrate stability zone of the phase diagram. Results indicate that higher injection rates intensify JT cooling, giving rise to a maximum safe injection rate that avoids hydrate formation. Adjusting CO₂ injection temperature and rate can significantly alter the P-T trajectory of each well, either preventing hydrate formation entirely or ensuring that any hydrates form only at a sufficient distance from the injection well to avoid injectivity impairment.

The analytical framework provides practical guidance for assessing injection strategies under various geological conditions. By linking injection rate, temperature, and reservoir thermal architecture, the models allow operators to minimise hydrate-induced formation damage and permeability decline. The approach also offers a rapid and transparent method for selecting appropriate heat exchange models, reducing reliance on computer simulations. Application to the Sleipner and Gorgon CO₂ storage projects demonstrates practical relevance for field-scale CCS, supporting reliable and cost-effective planning of large-scale CO₂ storage.