Analysis of CO2 Injectivity by Change of Pressure, Temperature, and CO2 Phase in Saline Aquifer
Authors: Mardhatillah Mutia Kharunisa , Yusof Muhammad Aslam Md , Rosdi Nadhirah Mohd , Radzali Iswadi B. , Yusof Shahrul Rizzal B. M. , Turkson Joshua Nsiah , Ibrahim Mohamad Arif 
Published: February 2024

Abstract
A "business-as-usual" approach to the increasing anthropogenic CO2 emissions would exacerbate the issues of climate change and global warming, which have devastating impacts. Given this, measures are currently rolled out to mitigate these global challenges. CO2 capture and storage (CCS) has proven to support the realization of a carbon-neutral society by 2050. Saline aquifers, with their porous and permeable properties, have gained prominence as potential storage reservoirs for CO2 sequestration. However, the CO2 injectivity in saline aquifers could be curtailed by challenges such as permeability impairment, which is triggered by the CO2-brine-rock interactions. Permeability impairment (or simply injectivity loss) could be influenced by the thermophysical conditions and injected CO2 characteristics. Moreover, these factors dictate the effectiveness of CO2 storage via the solubility trapping mechanism. The study therefore explored the impact of pressure and temperature variations, and the injected CO2 phase on the CO2 injectivity alteration during CO2 injection in saline aquifers. Coreflooding experiments were conducted on high-quartz Berea sandstone samples using a 30000 ppm (3wt%) NaCl brine. The thermophysical conditions were varied from 900 to 2000 psi for pressure and 27 and 60°C for temperature to evaluate the impact of different CO2 phases (gas, liquid, and supercritical) on injectivity impairment. Additionally, pressure and temperature ranges of 1400 to 4000 psi and 40 to 100°C were selected to investigate their influence on injectivity impairment during CO2 injection into saline aquifers. These thermophysical conditions represent those of warm-shallow, warm-deep, cold-shallow, and cold-deep storage basins. The injection rate was kept constant at 2 mL/min in all experiments to capture near-wellbore fluid flow conditions. The relative injectivity change (RIC) was computed post-CO2 injection to comprehend the extent of injectivity alteration and identify the optimum conditions for CO2 injection in saline aquifers. Subsequently, petrographic, and effluent analyses were employed to corroborate permeability measurements before and after CO2 injection. Experimental findings revealed that the severity of formation damage is temperature-dependent, decreasing up to 80°C, beyond which an increase in potential damage is observed. The key findings from the study underscore the temperature-dependent nature of CO2 solubility saturation, the influence of pressure up to saturation points, and the plateauing effect at higher temperatures. This study contributes essential knowledge to the field, emphasizing the intricate relationship between pressure, temperature, and CO2 injectivity alteration. The findings also provide a robust foundation for the development of a comprehensive predictive model to enhance our ability to optimize CO2 storage and achieve global net-zero targets.