Hydrogen sulfide solubility in 50 wt% and 70 wt% aqueous methyldiethanolamine at temperatures from 283 to 393 K and total pressures from 500 to 10000 kPa

Eirini Skylogianni,Ingvild Mundal,Diego D.D Pinto,Christophe Coquelet,Hanna K Knuutila

doi:10.1016/j.fluid.2020.112498

Abstract

The hydrogen sulfide (H2S) absorption capacity of a 70 wt% aqueous methyldiethanolamine (MDEA) solution was investigated in a static-analytic apparatus at temperatures of 283, 353 and 393 K and pressures of 2000, 6000 and 10000 kPa in the presence of methane. New experimental data were also produced for a 50.1 wt% aqueous MDEA at 323 K and pressures of 500 and 3000 kPa as part of the apparatus validation procedure. A model based on electrolyte non-random two-liquid (eNRTL) activity coefficient model to describe the liquid phase and Peng-Robinson Equation of State to describe the vapor phase non-idealities was developed for the system H2S-MDEA-H2O, which can potentially be used also for the system in the presence of methane at low pressures. Vapor pressure measurements of pure MDEA were also performed in the range of 405–435 K in an ebulliometer and parameters for the Antoine correlation were proposed.

Highlights

Natural and refinery gas streams usually contain acid gases, carbon dioxide and sulfur compounds, which must be removed in order to ensure trouble-free and safe operations.Typical sulfur compounds are hydrogen sulfide, carbonyl sulfide, mercaptans, with the first one being the most important one as it occurs in the largest concentrations [1].Hydrogen sulfide (H2S) gas content is routinely controlled by absorption into aqueous methyldiethanolamine (MDEA), which can be thermally regenerated and reused.A 50 wt.% MDEA-H2O concentration is considered a benchmark solvent in H2S removal, due to its equilibrium behavior and low corrosion
The experimental vapor-liquid equilibrium data obtained in this work with 50.1 wt.% and 70 wt.% MDEA solution for the system CH4-H2S-MDEA-H2O at various pressures and temperatures are presented in Table 8 and Table 9
The new data are accompanied by the standard uncertainties for total pressure and temperature as well as the combined uncertainties for the partial pressure of hydrogen sulfide, the global and the liquid loading

Summary

Introduction

Natural and refinery gas streams usually contain acid gases, carbon dioxide and sulfur compounds, which must be removed in order to ensure trouble-free and safe operations.Typical sulfur compounds are hydrogen sulfide, carbonyl sulfide, mercaptans, with the first one being the most important one as it occurs in the largest concentrations [1].Hydrogen sulfide (H2S) gas content is routinely controlled by absorption into aqueous methyldiethanolamine (MDEA), which can be thermally regenerated and reused.A 50 wt.% MDEA-H2O concentration is considered a benchmark solvent in H2S removal, due to its equilibrium behavior and low corrosion. Natural and refinery gas streams usually contain acid gases, carbon dioxide and sulfur compounds, which must be removed in order to ensure trouble-free and safe operations. Hydrogen sulfide (H2S) gas content is routinely controlled by absorption into aqueous methyldiethanolamine (MDEA), which can be thermally regenerated and reused. A 50 wt.% MDEA-H2O concentration is considered a benchmark solvent in H2S removal, due to its equilibrium behavior and low corrosion. Aqueous MDEA has been long established in the industry due to among others, the amine’s availability, low cost and energy requirements, resistance to degradation, ability to meet the 4 ppm specification requirement for pipeline gas and to selectively remove H2S over CO2, which often coexist. By regulating the contact time between the solvent and the gas, H2S removal to specification and minimum co-absorption of CO2 can be achieved [2],

Methods

Results

Conclusion