Objective and Method  High CO₂ injectivity in reservoirs is essential for high-quality sites of CO₂ geological storage (CGS). Salt precipitation in the vicinity of injection wells due to brine dissolution in CO₂ emerges as a critical factor impairing CO₂ injectivity. To explore the differences in the mechanisms behind salt precipitation and damage degree across various reservoirs, this study conducted salt precipitation simulation experiments on sandstone samples with distinct pore structures using a high-temperature and high-pressure fluid displacement system. By combining methods such as cast thin section observations, scanning electron microscopy and resulting spectra, micro-X-ray fluorescence (micro-XRF) spectroscopy, mercury injection capillary pressure (MICP), nuclear magnetic resonance (NMR), and relative permeability tests, this study aims to clarify the mechanisms underlying the impacts of initial reservoir pore structures on the crystal characteristics and distribution patterns of salt precipitation.

Results and Conclusions  Salt precipitation in high-porosity, high-permeability porous reservoirs was characterized by a low number of small salt crystals dominated by dispersed single crystals, with a maximum salt precipitation content of merely about 0.2%. Decreases in the pore throat size, sorting, and connectivity corresponded to increases in the number and size of salt crystals, as well as the salt aggregate content. Accordingly, the maximum salt precipitation content reached up to approximately 4.7%. As the reservoir pore structures shifted from homogeneous large pore throats to heterogeneous small pore throats, the distribution patterns of salt precipitation evolved through three stages: a homogeneous distribution pattern of weak salt precipitation primarily induced by brine dissolution, a heterogeneous distribution pattern characterized by local strong salt precipitation mainly due to capillary brine reflux, and a homogeneous distribution pattern of strong salt precipitation under the joint control of capillary brine reflux and salt solute diffusion. Intensified salt precipitation significantly increased the damage to the pore structures and CO₂ injectivity of reservoirs in the vicinity of injection wells. The porosity-permeability damage rate increased from about 1% in reservoirs with large pore throats to 26% and 38% in reservoirs with small pore throats. Reservoirs with varying initial pore structures exhibited different developmental patterns of salt precipitation and varying injectivity impairment risks. The results of this study will provide a theoretical basis for mitigating damage to reservoirs during CO₂ geological storage in saline aquifers, thereby facilitating the efficient deployment of CO₂ geological storage.