Experimental Study on the Interplay between Different Brine Types/Concentrations and CO2 Injectivity for Effective CO2 Storage in Deep Saline Aquifers

Salt precipitation during CO2 storage in deep saline aquifers can have severe consequences on injectivity during carbon storage. Extensive studies have been carried out on CO2 solubility with individual or mixed salt solutions; however, to the best of the authors’ knowledge, there is no substantial study to consider pressure decay rate as a function of CO2 solubility in brine, and the range of brine concentration for effective CO2 storage. This study presents an experimental core flooding of the Bentheimer sandstone sample under simulated reservoir conditions to examine the effect of four different types of brine at a various ranges of salt concentration (5 to 25 wt.%) on CO2 storage. Results indicate that porosity and permeability reduction, as well as salt precipitation, is higher in divalent brines. It is also found that, at 10 to 20 wt.% brine concentrations in both monovalent and divalent brines, a substantial volume of CO2 is sequestered, which indicates the optimum concentration ranges for storage purposes. Hence, the magnitude of CO2 injectivity impairment depends on both the concentration and type of salt species. The findings from this study are directly relevant to CO2 sequestration in deep saline aquifers as well as screening criteria for carbon storage with enhanced gas and oil recovery processes.

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

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.

Modeling the Combined Effect of Salt Precipitation and Fines Migration on CO2 Injectivity Changes in Sandstone Formation

Carbon dioxide, CO2 emissions have risen precipitously over the last century, wreaking havoc on the atmosphere. Carbon Capture and Sequestration (CCS) techniques are being used to inject as much CO2 as possible and meet emission reduction targets with the fewest number of wells possible for economic reasons. However, CO2 injectivity is being reduced in sandstone formations due to significant CO2-brine-rock interactions in the form of salt precipitation and fines migration. The purpose of this project is to develop a regression model using linear regression and neural networks to correlate the combined effect of fines migration and salt precipitation on CO2 injectivity as a function of injection flow rates, brine salinities, particle sizes, and particle concentrations. Statistical analysis demonstrates that the neural network model has a reliable fit of 0.9882 in R Square and could be used to accurately predict the permeability changes expected during CO2 injection in sandstones.