The separation of carbon dioxide (CO₂) and hydrogen sulfide (H₂S) from sour natural gas is an important step in gas processing and emission control. This study applies a rate-based Aspen Plus simulation to examine solvent-based CO₂/H₂S removal under conditions representative of the Shurtan Gas Chemical Complex in Uzbekistan. Monoethanolamine (MEA) and methyldiethanolamine (MDEA) are evaluated as reference solvents with respect to separation performance and energy demand. The rate-based modeling framework accounts for reaction kinetics and mass transfer effects in the absorber–regenerator system. Simulation results indicate that both solvents achieve high acid gas removal efficiencies. From an engineering perspective, the results provide practical guidance for solvent selection and energy optimization in existing acid gas removal units, supporting pilot-scale deployment under industrial operating conditions. Sensitivity analysis suggests that increasing gas throughput beyond 30 t/h leads to a gradual reduction in CO₂ capture efficiency, primarily due to mass transfer limitations. From a techno-economic perspective, the lower energy demand of the MDEA-based system may imply reduced operating costs. The captured CO₂ stream reaches a purity of around 99.5%, which is compatible with downstream soda ash production. Overall, the results provide a screening-level assessment supporting further detailed evaluation.

Natural gas streams extracted from production wells often contain undesirable components such as water vapor, gas condensate, and solid particulates. These impurities reduce fuel quality and damage downstream equipment through corrosion, fouling, and foaming. This study presents the development and field-scale evaluation of a high-performance gas–liquid separator designed for the deep decontamination of natural gas. The proposed separator incorporates 30 suspended baffles arranged in three rows and an anti-foaming mesh to enhance phase separation and prevent liquid re-entrainment. Field experiments were conducted at the Somontepa gas field in Uzbekistan. Compared to the baseline industrial unit, the upgraded separator reduced gas condensate from 16.58 g/m³ to 0.725 g/m³, water from 4.84 g/m³ to 0.10 g/m³, and solid impurities from 1.20 g/m³ to 0.0058 g/m³. The foam height was lowered from 96.4 mm to 10.2 mm, and the average bubble diameter was reduced by over 60%. The design maintained low pressure drops and demonstrated stable operation under varying flow rates. Fractional analysis confirmed the quality of a recovered condensate suitable for downstream utilization. The proposed configuration offers substantial improvements in gas purification performance and economic efficiency. These results support the application of this separator design for high-contaminant natural gas streams in industrial gas processing facilities.

The separation and purification of carbon dioxide (CO₂) from sour gas streams is critical for emission reduction and industrial reuse. This study presents a chemical absorption-based process simulation of CO₂ (carbon dioxide) and H₂S (hydrogen sulfide) separation using Aspen Plus V12.0, focusing on solvent-based treatment using an aqueous monoethanolamine (MEA) system selected based on industrial applicability and regeneration performance. The process was modeled for two gas streams originating from the Shurtan Gas Chemical Complex: a raw feed stream containing 3.42% CO₂ and 0.09% H₂S, and a treated dry gas containing 2.1% CO₂. The goal was to achieve high-purity CO₂ recovery (≥99.5%) with flow rates of 30 t/h and 20 t/h, respectively. Rate-based modeling was employed to simulate mass transfer and chemical kinetics in the absorber and regenerator columns. The simulation results indicated that at optimal solvent flow and absorber temperature (40–45 °C), over 98.6% CO₂ and 99.9% H₂S removal could be achieved. The specific energy requirement for solvent regeneration was estimated at 2.3 GJ per ton of CO₂, aligning with industrial efficiency benchmarks. The purified CO₂ is intended for use in the production of sodium carbonate (Na₂CO₃) at the Dehkanabad Potash Plant, which converts 20 t/h of CO₂ into 296,000 tons/year of calcined soda with 77% process efficiency. This approach enhances gas resource utilization while reducing atmospheric emissions. The model serves as a techno-economically viable foundation for scaling up CO₂ capture and utilization (CCU) in the Uzbek chemical industry.