Experimental study of CO2 injectivity impairment in sandstone due to salt precipitation and fines migration

Abstract

Re-injection of carbon dioxide (CO2) in deep saline formation is a promising approach to allow high CO2 gas fields to be developed in the Southeast Asia region. However, the solubility between CO2 and formation water could cause injectivity problems such as salt precipitation and fines migration. Although both mechanisms have been widely investigated individually, the coupled effect of both mechanisms has not been studied experimentally. This research work aims to quantify CO2 injectivity alteration induced by both mechanisms through core-flooding experiments. The quantification injectivity impairment induced by both mechanisms were achieved by varying parameters such as brine salinity (6000–100,000 ppm) and size of fine particles (0–0.015 µm) while keeping other parameters constant, flow rate (2 cm3/min), fines concentration (0.3 wt%) and salt type (Sodium chloride). The core-flooding experiments were carried out on quartz-rich sister sandstone cores under a two-step sequence. In order to simulate the actual sequestration process while also controlling the amount and sizes of fines, mono-dispersed silicon dioxide in CO2-saturated brine was first injected prior to supercritical CO2 (scCO2) injection. The CO2 injectivity alteration was calculated using the ratio between the permeability change and the initial permeability. Results showed that there is a direct correlation between salinity and severity of injectivity alteration due to salt precipitation. CO2 injectivity impairment increased from 6 to 26.7% when the salinity of brine was raised from 6000 to 100,000 ppm. The findings also suggest that fines migration during CO2 injection would escalate the injectivity impairment. The addition of 0.3 wt% of 0.005 µm fine particles in the CO2-saturated brine augmented the injectivity alteration by 1% to 10%, increasing with salt concentration. Furthermore, at similar fines concentration and brine salinity, larger fines size of 0.015 µm in the pore fluid further induced up to three-fold injectivity alteration compared to the damage induced by salt precipitation. At high brine salinity, injectivity reduction was highest as more precipitated salts reduced the pore spaces, increasing the jamming ratio. Therefore, more particles were blocked and plugged at the slimmer pore throats. The findings are the first experimental work conducted to validate theoretical modelling results reported on the combined effect of salt precipitation and fines mobilisation on CO2 injectivity. These pioneering results could improve understanding of CO2 injectivity impairment in deep saline reservoirs and serve as a foundation to develop a more robust numerical study in field scale.

Review on Experimental Investigation into Formation Damage during Geologic Carbon Sequestration: Advances and Outlook

“…They have shown that the CO 2 –brine–rock interaction can happen in both zones of water and gas because, during the reaction, water can evaporate to the steam phase, while CO 2 reacts with the brine water, resulting in carbonic acid. Similarly, the study revealed that the CO 2 –brine–rock interaction leads to formation damage because the reaction of the rock mineral may dissolute and form free particles that can be transported and fill the pore spaces along the pass of fluid flow, leading to a severe reduction of permeability. , .…”

“…According to Sbai and Azaroual, several mechanisms have contributed to the formation damage, such as active mineral precipitation and trapped particles, causing blocking/plugging and bridging processes, particularly in porous environments. Also, clogging of the suspended particles at the pore throats during an unprecedented flow rate of CO 2 storage could result in restriction of production and a loss in permeability surrounding the injector zone. , Research by Mohamed and Nasr-El-Din showed the reduction of CO 2 injectivity in carbonate rock as a result of the formation damage resulting from the precipitation of carbonate minerals and sulfate scales. Usually, sodium sulfate in brine water causes formation damage as a result of the precipitation of calcium sulfate .…”

“…Additionally, it should be noted that the permeability trend in the saline formation is more severely affected by formation damage during CO 2 injection, in which the permeability was observed to drop more than in other samples. The permeability drop is due to the chemical processes that led to the formation damage from salt precipitation and active mineral dissolution. , …”

“…Numerous studies have reported that injecting CO 2 into geological formations can disrupt the geochemical equilibrium through dissolution and precipitation processes, which affect the reservoir mineral phases. ,− However, it has been mentioned that, by having a small number of secondary minerals present in the formation after CO 2 injection, considerable changes in permeability and porosity can be seen through precipitation. , Similarly, Shao et al reported that the permeability could decrease when the precipitation size is nearly equal to the size of the pore throats in the porous system of the formation …”

Advances in Carbon Dioxide Storage Projects: Assessment and Perspectives

“…Numerous researchers have discussed CO 2 storage in geological formations with various theories, and simulation models. − They outlined that CCS is a safe technology to meet the climate targets as stated by IPCC, organizations, research, and different governments. In addition to the many advantages of CCS, this technique faces many difficulties, such as high operational costs (as described by Moghanloo et al and Fawad and Mondol), proper handling to prevent compromise with wellbore integrity, public acceptance by some countries, and environmental concerns.…”