Simulation of acid gas removal unit using DIPA+TEA amine solvent

Abstract

Abstract Due to the inexpensive cost of amine solvent, more than 95 % of natural gas (NG) processing plants use an acid gas removal unit that utilizes an aqueous amine solvent to remove sour gas components such as carbon dioxide (CO2) and hydrogen sulfide (H2S). Different technologies are available to capture CO2 from NG. However, chemical absorption is the most reliable and used technology all over the world. However, it is challenging to determine the amine blend’s optimal composition for the effective removal of CO2 and H2S and solvent regeneration. This is mainly due to the difference in reservoir gas compositions, affecting gas removal efficiency and solvent regeneration energies. The present investigation addresses the performance of using a novel solvent blend of diisopropanolamine (DIPA) and Triethanolamine (TEA) to determine the absorption capacity of CO2 & H2S using Aspen HYSYS software. A study on the effects of solubility on CO2 absorption was performed at varying pressure (10-80 bar) and temperature (25°C to 50°C). The percentage of CO2 removal increased from 80% to 98% as the temperature increased from 25°C to 50°C. The results revealed that the concentration of CO2 and H2S in sweet gas decrease with the increase in pressure while the concentration of CO2 and H2S increases with the increase in temperature.