The Effects of Salt Precipitation During CO2 Injection into Deep Saline Aquifer and Remediation Techniques

The by-products of combustion from the utilisation of fossil fuels for energy generation are a source of greenhouse gas emissions, mainly Carbon dioxide (CO2). This has been attributed to climate change because of global warming. Carbon capture and storage (CCS) technology has the potential to reduce anthropogenic greenhouse gas emissions by capturing CO2 from emissions sources and stored in underground formations such as depleted oil and gas reservoirs or deep saline formations. Deep saline aquifers for disposal of greenhouse gases are attracting much attention as a result of their large storage capacity. The problem encountered during CO2 trapping in the saline aquifer is the vaporisation of water along with the dissolution of CO2. This vaporisation cause salt precipitation which eventually reduces porosity and impairs the permeability of the reservoir thereby impeding the storage capacity and efficiency of the technology. Salt precipitation during CO2 storage in deep saline aquifers can have severe consequences during carbon capture and storage operations in terms of CO2 injectivity.This work investigates and assesses, experimentally, the effects of the presence of salt precipitation on the CO2 injectivity, the factors that influence them on selected core samples by core flooding experiments, and remediation of salt precipitation during CO2 injection. The investigation also covered the determination of optimum range of deep saline aquifers for CO2 storage, and the effects of different brine-saturated sandstones during CO2 sequestration in deep saline aquifers. In this investigation, three (3) different sandstone core samples (Bentheimer, Salt Wash North, and Grey Berea) with different petrophysical properties were used for the study. This is carried out in three different phases for a good presentation.• Phase I of this study involved brine preparation and measurement of brine properties such as brine salinity, viscosity, and density. The brine solutions were prepared from different salts (NaCl, CaCl2, KCl, MgCl2), which represent the salt composition of a typical deep saline aquifer. The core samples were saturated with different brine salinities (5, 10, 15, 20, 25, wt.% Salt) and testing was conducted using the three selected core samples.• Phase II entailed the cleaning and characterisation of the core samples by experimental core analyses to determine the petrophysical properties: porosity and permeability. Helium Porosimetry and saturation methods were used for porosity determination. Core flooding was used to determine the permeability of the core samples. The core flooding process was conducted at a simulated reservoir pressure of 1500 psig, the temperature of 45 °C, with injection rates of 3.0 ml/min respectively. Interfacial tension (IFT) measurements between the CO2 and various brine salinities as used in the core flooding were also conducted in this phase. Remediation scenarios of opening the pore spaces of the core samples were carried out using the same core flooding rig and the precipitated core samples were flooded with remediation fluids (low salinity brine and seawater) under the same reservoir conditions. The petrophysical properties (Porosity, Permeability) of the core samples were measured before core flooding, after core flooding and remediation test respectively.• In phase III of the study, SEM Image analyses were conducted on the core samples before core flooding, after core flooding, and remediation test respectively. This was achieved by using the FEI Quanta FEG 250 FEG high-resolution Scanning Electron Microscope (SEM) interfaced to EDAX Energy Dispersive X-ray Analysis (EDX).xivResults from Bentheimer, Salt Wash North, and Grey Berea core samples indicated a reduction in porosity, permeability impairment, as well as salt precipitation. It was also found that, at 10 to 20 wt.% brine concentrations in both monovalent and divalent brine, a substantial volume of CO2 is sequestered, which indicates the optimum concentration ranges for storage purposes. The salting-out effect was greater in divalent salt, MgCl2 and CaCl2 as compared to monovalent salt (NaCl and KCl). Porosity decreased by 0.5% to 7% while permeability was decreased by up to 50% in all the tested scenarios. CO2 solubility was evaluated in a pressure decay test, which in turn affects injectivity. 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. Injection of remediation fluids during remediation tests effectively opened the pore spaces and pore throats of the core samples and thereby increasing the core sample's porosity in the range of 14.0% to 28.5% and 2.2% to 12.9% after using low salinity brine and seawater remediation fluids respectively. Permeability also increases in the range of 40.6% to 68.4% and 7.4% to 17.2% after using low salinity brine and seawater remediation fluids respectively. These findings provide remediation strategies useful in dissolving precipitated salt as well as decreasing the salinity of the near-well brine which causes precipitation.The SEM images of the core samples after the flooding showed that salt precipitation not only plugged the pore spaces of the core matrix but also showed significant precipitation around the rock grains thereby showing an aggregation of the salts. This clearly proved that the reduction in the capacity of the rock is associated with salt precipitation in the pore spaces as well as the pore throats. Thus, insight gained in this study could be useful in designing a better mitigation technique, CO2 injectivity scenarios, as well as an operating condition for CO2 sequestration in deep saline aquifers