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.

A Novel Method To Assess Stimulation of Sandstone Cores Damaged by Fines Migration

Summary Sandstone stimulation remains challenging because of formation heterogeneity and the sensitivity of clay minerals to acids such as hydrochloric acid (HCl) and mud acid [HCL/hydrofluoric acid (HF)]. Fines migration complicates the well-stimulation process and reduces formation productivity. Multiple field studies show that some stimulation methods can result in permanent damage to the rock matrix near the wellbore because of fines migration. This study aims to locate, quantify, and describe the damage resulting from fines migration after the stimulation of sandstone formations, and examine the composition of clay content in the formation and its effects on the stimulation process and subsequent fines migration. This work evaluates the fines-migration damage during well stimulation in Bandera, Gray Berea, and Kentucky Sandstones. Fines migration was induced by injecting deionized water between brine stages to trigger the mobilization of the clay minerals in sample cores. HCl, formic acid (HCOOH), and HF stimulation stages were then injected after the fines-migration induction. The new formation-damage-evaluation method proposed in this work uses computed-tomography (CT) scanning and nuclear-magnetic-resonance (NMR) measurements before and after the fines-migration induction and experimental stimulation. The CT and NMR data were then combined and processed to generate a 3D representation of the pore structure throughout the core samples, which yields insight on how the clay composition affects the stimulation process and changes the pore system. The developed technique exhibited an excellent ability to visualize the pore-size distribution and the changes in the pore structure after the fines-migration damage and the acid treatment. The mapping of the pore-size distribution using CT and its comparison with the rock mineralogy of Bandera, Gray Berea, and Kentucky Sandstones successfully predicted the changes in the pore structure of these formations upon induction of fines-migration damage using deionized water. These changes in pore structure prevailed as a controlling variable of the acidizing process. The stimulation of the damaged cores at 150 and 250°F resulted in aluminosilicate deposition toward the core outlet. These deposits are attributed to the acid leaching of aluminum (Al) and iron (Fe) ions from the aluminosilicate structures. The higher temperature resulted in the deposition of aluminosilicates closer to the injection point. However, an enhancement in permeability was noticed in all of the sampled formations, which was because of the propagation of narrow channels between heavily deformed pore structures. This work adds to the understanding of sandstone-stimulation technology and contributes a new process to assess the effects of acid stimulation on fines-migration damage. The high level of resolution in visualizing the changes in the pore structure facilitates the optimization of treatments to reduce costs while improving production from clay-rich sandstone formations. This technique offers further potential as a formation-evaluation tool for real-time assessment of a variety of formation-damage mechanisms, such as fracturing fluids and water blockage.