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. 2024 Jun 7;9(24):25704-25714.
doi: 10.1021/acsomega.3c09100. eCollection 2024 Jun 18.

Removal of Carbon Dioxide and Hydrogen Sulfide from Natural Gas Using a Hybrid Solvent of Monoethanolamine and N-Methyl 2-Pyrrolidone

Abid Salam Farooqi  1   2 , Raihan Mahirah Ramli  1   2 , Serene Sow Mun Lock  1   3 , Ahmad Salam Farooqi  4 , Muhammad Zubair Shahid  4 , Syed Muhammad Wajahat Ul Hasnain  1   3 , Noor E Hira  1   3 , Bawadi Abdullah  1   3
Affiliations

Removal of Carbon Dioxide and Hydrogen Sulfide from Natural Gas Using a Hybrid Solvent of Monoethanolamine and N-Methyl 2-Pyrrolidone

Abid Salam Farooqi et al. ACS Omega. .

Abstract

The main goal of traditional methods for sweetening natural gas (NG) is to remove hydrogen sulfide (H2S) and significantly lower carbon dioxide (CO2). However, when NG processes are integrated into the carbon capture and storage (CCS) framework, there is potential for synergy between these two technologies. A steady-state model utilizing a hybrid solvent consisting of N-methyl-2-pyrrolidone (NMP) and monoethanolamine (MEA) has been developed to successfully anticipate the CO2 and H2S capture process from NG. The model was tested against important variables affecting process performance. This article specifically explores the impact of operational parameters such as lean amine temperature, absorber pressure, and amine flow rate on the concentrations of CO2 and H2S in the sweet gas and reboiler duty. The result shows that hybrid solvents (MEA + NMP) perform better in removing acid gases and reducing reboiler duty than conventional chemical solvent MEA. The primary purpose is to meet product requirements while consuming the least energy possible, which is in line with any process plant's efficiency goals.

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Conflict of interest statement

The authors declare no competing financial interest.

Figures

Figure 1
Figure 1
Process flow diagram of the acid gas removal unit.
Figure 2
Figure 2
Major units energy requirement in an acid gas capture plant.
Figure 3
Figure 3
Effect of lean amine temperature on acid gases and reboiler duty (a) of the CO2 content in sweet gas (b) of the H2S content in sweet gas.
Figure 4
Figure 4
Effect of regenerator inlet temperature on acid gases and reboiler duty (a) CO2 content in sweet gas (b) H2S content in sweet gas.
Figure 5
Figure 5
Effect of amine flow rate (a) CO2 content in sweet gas (b) H2S content in sweet gas (c) Reboiler duty.
Figure 6
Figure 6
Effect of absorber pressure on acid gases and reboiler duty (a) CO2 content in sweet gas and (b) H2S content in sweet gas.
Figure 7
Figure 7
Effect of feed gas temperature on acid gases and reboiler duty (a) CO2 content in sweet gas and (b) H2S content in sweet gas.
Figure 8
Figure 8
Effect of reboiler temperature on acid gases and reboiler duty (a) CO2 content in sweet gas (b) H2S content in sweet gas.
Figure 9
Figure 9
Variation in reboiler pressure with a change in reboiler temperature.
Figure 10
Figure 10
Effect of reboiler pressure on acid gases and reboiler duty (a) CO2 content in sweet gas and (b) H2S content in sweet gas.
See this image and copyright information in PMC

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