InterPore2026

Modeling Salt Precipitation under Short Intermittent CO₂ Injection: Role of Salinity, Capillarity and Injection Rate on Injectivity

22 May 2026, 10:20

1h 30m

Poster Presentation (MS16) Complex fluid and Fluid-Solid-Thermal coupled process in porous media: Modeling and Experiment Poster

Speaker

Alfredo Perez-Perez (CHLOE (Adera))

Description

Geological storage of CO₂ in deep saline aquifers is a widely recognized strategy for mitigating atmospheric CO₂ emissions. When dry CO₂ is injected, water vaporizes into the CO₂ stream, increasing brine salinity. Once the solubility limit is exceeded, halite precipitates -primarily near the wellbore-reducing porosity and permeability, which can impair injectivity and compromise storage efficiency.
In previous work (Perez-Perez and Berthelot, 2025), we investigated the interplay between injection rate, water vaporization, and capillary backflow on halite precipitation during continuous CO₂ injection. High-resolution thermal-compositional simulations revealed that low injection rates enhance capillary-driven brine backflow, promoting salt accumulation and significant permeability reduction near the wellbore. Conversely, higher injection rates limit brine supply and reduce salt deposition. Gravity effects further induce non-uniform salt distribution, concentrating injectivity loss in specific well sections.
Previous studies (Ogundipe and Mackay, 2024; Khosravi et al., 2024; Landa-Marbán et al., 2024) have examined intermittent CO₂ injection, a scenario particularly relevant for CCS projects facing fluctuating CO₂ supply or operational constraints. These works emphasize the importance of high-resolution, multi-physics modeling and tailored injection strategies to mitigate formation damage and maintain injectivity under such conditions. Building on this, our recent study (Perez-Perez and Berthelot, 2025) investigated halite precipitation during short intermittent injection (weekly basis) in a North Sea aquifer (salinity: 49 g/L), accounting for spontaneous imbibition during shut-in periods. Simulation results revealed that capillary forces govern brine re-wetting of dry-out zones, which in turn influences salt dissolution and re-precipitation during intermittent CO₂ injection. Furthermore, the analysis indicated an overall injectivity loss of approximately 6% after one year of short intermittent cycles with a yearly target rate of 1MTPA and low salinity.
In this work, we extend the analysis to short intermittent injection scenarios across salinities ranging from 50 to 300 g/L. Each intermittent cycle consisted of a 7-day injection period at an average rate of 1 MTPA over one year. Injectivity indices were computed and compared against corresponding cases without salt precipitation, as well as continuous injection scenarios.
Results indicate that normalized injectivity loss becomes significant at salinities above 150 g/L and strongly correlates with injection rate. Below 150 g/L, short intermittent and continuous injection exhibit similar impairment. At a concentration of 300 g/L, continuous injection produced a markedly higher impairment (90%) relative to intermittent injection with extended shut-in (73%). This difference arises because continuous injection maintains a lower rate, whereas intermittent injection -with extended shut-in- results in a higher average rate.
To assess precipitation risk under varying salinity and injection velocities, we applied a dimensionless Capillary number (Ca). At high Ca, salt deposition is limited to the brine’s initial salt content, whereas at very low Ca, capillary forces dominate, causing solid saturation to increase and permeability ratio (k/ko) to decrease near the wellbore. Figure 1 illustrates these trends. A similar curve for the injectivity index vs Ca will be presented. This approach provides a practical framework for predicting injectivity impairment and optimizing injection strategies under varying reservoir conditions, offering valuable guidance for CCS project design and operational planning.