Modelling the Impact of Injection Rate and Heterogeneity on the Extent and Location of Halite Precipitation During CO2 Storage in Saline Aquifers: A Field Case Example

Abstract Reservoir injectivity and storage efficiency may decline during CO2 injection in a heterogeneous saline formation with variable reservoir quality due to the salting-out effect. Rock heterogeneity affects salt precipitation patterns and distributions and causes changes in flow characteristics. Consequently, a risk assessment of injectivity loss due to halite precipitation in the near-well formation is required. This study investigates the influence of heterogeneity and injection rate on the extent and location of halite precipitation. Numerical simulations were performed using a reactive transport compositional model which accounted for brine evaporation, halite precipitation, capillary pressure re-imbibition, and gravity segregation. 2D radial models were developed to identify near-well injection effects and calculate the extent of the dry-out zone, porosity and injectivity changes. The phase behaviour is modelled using a Peng-Robinson equation-of-state to evaluate the evaporation of the aqueous phase and water solubility in the gas phase. Henry’s Law accounted for CO2 solubility in the aqueous phase. The Kozeny-Carman porosity-permeability relationship was used as the permeability-reduction in the model. Dry CO2 was injected at a constant rate of 0.9 Mtpa for 2 years into an aquifer with a salinity of 330 g/L. The well was completed in a formation 100 m thick with five heterogeneous scenarios viz. alternating high-perm and low-perm, bimodal high-perm to low-perm, bimodal low-perm to high-perm, coarsening-up and fining-up sequences. The results show that at high injection rates, viscous forces displace brine from the well such that there is insignificant formation damage due to halite precipitation, regardless of the degree of heterogeneity. However, at low CO2 injection, the injection rate and heterogeneity have a role to play. While the injection rate governs the interplay between viscous and gravity forces, causing dry-out to occur in the near-well formation, heterogeneity governs the location of salt precipitation and where exactly the blockage occurs. At low injection, gravity and capillary forces dominate, resulting in brine influx into the bottom layers, which supply salty water, and when this evaporates, there is a total blockage of these layers. Furthermore, the injectivity index at high injection rate depends on the ability to efficiently sweep brine from the well; at low injection, it depends on the formation damage of the high-perm and low-perm layers. This paper presents a methodology for evaluating the risk of halite precipitation during CO2 injection in heterogeneous saline aquifers. The understanding from this work is important for CCS projects where the CO2 injection rate may be low for prolonged periods or intermittently stopped.