This paper present a comprehensive review of different processes available and suitable for removal of CO2 from natural gas to meet LNG production specifications and explore the capability of Aspen HYSYS 8.6 process simulator to predict the CO2 removal process operating conditions range at which hydrocarbon and chemical (amine solvent) loss can be minimized. Removal of CO2 from natural gas is currently a global issue. Apart from meeting the customer‟s contract specifications and for successful liquefaction process in liquefied natural gas (LNG) plants, it is also a measure for reducing global CO2 emission. The simulation program developed in this research work has been used to modify the physical, thermodynamics and transport properties of the gas streams and process units so as to improve process efficiency and environmental performance. It was observed that as the concentration of amine increases, the percentage mole concentration of CO2 in the sweet gas decreases. This is attributed to the increase in amine solvent capacity with increase in concentration of amine in the solution. Also the mole percent of CO2 in the sweet gas increased with contactor (absorber) operating temperature and decreased with increase in pressure, while the hydrocarbon (C1) coabsorbed with the CO2 in the solvent increased with pressure and decrease with increase in temperature. The simulated results showed that for a given partial pressure of CO2 in the feed gas the amine loading increased with increasing amine wt% in the solution: with 25 wt%, 30 wt% and 35 wt% DEA, the loading [molCO2/molDEA] ranged from 0.6067 – 0.6369, 0.5316 – 0.5529 and 0.4638 – 0.4832 respectively.