Modelling the Effect of Water Vaporisation and Halite Precipitation on Reservoir Properties During CO2 Subsurface Storage

The feasibility of any CCS project may be put at risk of failure when supercritical and dry CO2 is injected into highly saline systems. Fluid flow characteristics near the injection point, such as porosity, permeability, and well injectivity, may be severely and negatively impacted due to salt clogging. Water vaporization of formation brine into the injected CO2 stream induces formation dry-out, increased salt concentration, supersaturation and salt deposition. This study demonstrates the impact of solids precipitation on reservoir properties by performing parametric sensitivity analyses.

Calculations were made using a reactive transport compositional reservoir simulation software to account for brine evaporation, capillary pressure re-imbibition and gravity segregation.1D and 2D radial models with fine space discretization near-well blocks were used to achieve good resolution and limit discretization errors. Changes in the values of critical parameters such as injection flow rate, brine salinity, reservoir temperature, and capillary pressure were inputted to test their impact on salt precipitation.

The results show increased halite deposition near-well by reducing an initial injection flow rate (76,200m3/day) by a factor of 2 and 4. In contrast, halite deposition decreased by increasing the flow rate by the same factors. For lower injection rates, the Kozeny-Carman porosity-permeability relationship used in the model showed that a 90% loss of porosity (initial porosity 0.2) resulted in a 99% reduction in permeability of the 100mD rock. In comparison, for higher rates, a 21% loss in porosity resulted in a 43.5% reduction in permeability. The explanation is that at lower injection rates, the counter capillary forces in a backflow dominate the viscous forces bringing salty water to the near well bore, thereby increasing aqueous phase salinity and promoting substantial salt precipitation. Our model also shows that increasing aqueous salinity (2M to 6M) increases salt deposition and the radius of the dry-out zone. Furthermore, increasing reservoir temperature (100C to 160C) increases the size of the dry-out zone because CO2 density and viscosity decrease, which means that the gas becomes more mobile, occupies a larger volume, and is displaced further away from the well. Capillary pressure effects were captured in this model, which, if ignored, can lead to a substantial underestimation in the amount of salt precipitated.

The observations from this study make for practical learning by which the theory and concepts underlying salt precipitation may be better understood.