Predictive Modelling of CO2 Injectivity Impairment due to Salt Precipitation and Fines Migration During Sequestration

Abstract

Recent studies indicated that reactive interactions between carbon dioxide (CO2), brine, and rock during CO2 sequestration can cause salt precipitation and fines migration. These mechanisms can severely impair the permeability of sandstone which directly affect the injectivity of supercritical CO2 (scCO2). Previous CO2 injectivity change models are ascribed by porosity change due to salt precipitation without considering the alteration contributed by the migration of particles. Therefore, this paper presents the application of response surface methodology to predict the CO2 injectivity change resulting from the combination of salt precipitation and fines migration. The impacts of independent and combined interactions between CO2, brine, and rock parameters were also evaluated by injecting scCO2 into brine saturated sandstone. The core samples were saturated with NaCl brine with salinity between 6,000 ppm to 100,000 ppm. The 0.1, 0.3, and 0.5 wt.% of different-sized hydrophilic silicon dioxide particles (0.005, 0.015, and 0.060 μm) were added to evaluate the effect of fines migration on CO2 injectivity alteration. The pressure drop profiles were recorded throughout the injection process and the CO2 injectivity alteration was represented by the ratio between the initial and final injectivity. The experimental results showed that brine salinity has a greater individual influence on permeability reduction as compared to the influence of particles (jamming ratio and particle concentration) and scCO2 injection flow rate. Moreover, the presence of both fines migration and salt precipitation during CO2 injection was also found to intensify the permeability reduction by 10%, and reaching up to threefold with increasing brine salinity and particle size. The most significant reductions in permeability were observed at higher brine salinities, as more salts are being precipitated out which, in turn, reduces the available pore spaces and leads to a higher jamming ratio. Thus, more particles were blocked and plugged especially at the slimmer pore throats. Based on comprehensive 45 core flooding experimental data, the newly developed model was able to capture a precise correlation between four input variables (brine salinity, injection flow rate, jamming ratio, and particle concentration) and CO2 injectivity changes. The relationship was also statistically validated with reported data from five case studies.

Well Injectivity during CO2 Geosequestration: A Review of Hydro-Physical, Chemical, and Geomechanical Effects

“…120 Salt precipitation is another cause of fines-induced injectivity impairments through making the pores susceptible to fines entrapment by size exclusion capture in thin pore throats. 82,121,122 Mineral dissolution is also likely to increase the portion of dislodged fines in saline aquifers; however, there are some arguments on how it affects the wellbore injectivity. For instance, Pearce et al 113 showed that at lower pH condition of CO 2 -rich brines, the impacts of fines migration can be either negative or positive.…”

“…Salt precipitation is another cause of fines-induced injectivity impairments through making the pores susceptible to fines entrapment by size exclusion capture in thin pore throats. ,, …”

Assessment of Advanced Remediation Techniques for Enhanced CO2 Injectivity: Laboratory Investigations and Implications for Improved CO2 Flow in Saline Aquifers

“…14 These precipitated salts formed can obstruct the flow of CO 2 within the porous rock matrix, thereby impairing the CO 2 injectivity. 15,16 More so, these salt formations can serve as nucleation sites for further precipitation, 10 creating a cycle of injection obstructions and operational disturbances. In extreme cases, the extensive salt buildup can completely block the injection well, rendering the well inoperable and jeopardizing the entire CCS operation.…”

“…During CO 2 injection in saline aquifers, the dry scCO 2 stream interacts with the resident brine, leading to the evaporation of water. ,, This evaporation process results in the precipitation of salts, a phenomenon referred to as the drying effect . These precipitated salts formed can obstruct the flow of CO 2 within the porous rock matrix, thereby impairing the CO 2 injectivity. , More so, these salt formations can serve as nucleation sites for further precipitation, creating a cycle of injection obstructions and operational disturbances. In extreme cases, the extensive salt buildup can completely block the injection well, rendering the well inoperable and jeopardizing the entire CCS operation.…”