Geological carbon storage is a key strategy for mitigating anthropogenic emissions. Long-term storage security depends on three main trapping mechanisms:

• Capillary trapping – immobilization of CO₂ in pore spaces

• Solubility trapping – dissolution of CO₂ into formation brine

• Mineral trapping – precipitation of stable carbonate minerals

While previous research has examined temperature, salinity, or wettability individually, their combined effects—especially under different wettability states controlled by hysteresis—have not been systematically quantified. This study addresses that gap using reactive transport modeling in carbonate-rich formations.

Simulations at 50–90 °C show that:

• In mixed-wet systems, mineralization increases from ~4.4 × 10⁶ to ~1.3 × 10⁷ mol of CO₂.

• Dissolution trapping exceeds 30% at higher temperatures.

• Capillary trapping declines with increasing temperature.

In contrast, water-wet systems exhibit stronger initial capillary trapping, but reduced sustained CO₂–rock interaction compared to mixed-wet conditions.

Implication: Mixed-wet reservoirs may promote greater long-term mineralization due to enhanced interfacial contact and geochemical interaction.

At 90 °C, increasing brine salinity up to 210,000 ppm NaCl:

• Reduces CO₂ solubility (salting-out effect)

• Shifts trapping dominance from dissolution (~36%) to capillary (~82%)

• Constrains plume migration laterally in water-wet systems

This demonstrates that salinity is a mechanism-specific control parameter that can fundamentally alter plume behavior and storage partitioning.

Geochemical reactions involving calcite, kaolinite, and anorthite were modeled using transition state theory. Results show:

• Calcite precipitation declines by ~22% with increasing temperature and ~14% with increasing salinity.

• Kaolinite precipitation can triple under certain conditions.

• Anorthite dissolution varies from −25% to +90% depending on wettability.

Over a 60-year simulation period, porosity and permeability increased modestly (~0.36% and ~1.22%), suggesting limited adverse impact on reservoir integrity.

Reactive transport simulations were performed using CMG-GEM, integrating:

• Heterogeneous carbonate mineralogy derived from laboratory data

• Temperature scenarios: 50 °C, 70 °C, 90 °C

• Salinity scenarios: 70,000–210,000 ppm NaCl

• Wettability states represented by hysteresis values (0.35 for water-wet; 0.20 for mixed-wet)

The modeling framework couples multiphase flow with geochemical reactions, linking aqueous ion evolution to mineral precipitation, pH variation, and reservoir property changes.

This study provides:

• A quantitative evaluation of how wettability-dependent hysteresis affects CO₂ phase distribution

• A mechanistic link between geochemistry and multiphase flow

• A framework for screening injection strategies under varying geothermal and salinity conditions

The findings clarify that optimal CO₂ storage performance depends on the coupled behavior of interfacial physics and geochemical reactions, rather than on isolated reservoir parameters.

Carbonate saline aquifers are widespread across Central Asia, the Middle East, North America, and Europe. By improving predictive understanding of storage mechanisms, this research supports:

• More reliable site screening

• Enhanced long-term storage security

• Reduced uncertainty in CCS project design

The study contributes to the scientific foundation needed to scale industrial carbon capture and storage (CCS) under complex reservoir conditions.

• Reza Khoramian – School of Mining and Geosciences, Nazarbayev University

• Miras Issakhov – Kazakh-British Technical University

• Peyman Pourafshary – Nazarbayev University

• Saule Aidarova – Kazakh-British Technical University

• Altynay Sharipova – Satbayev University