Simulation and comparison of Sulfinol solvent performance with Amine solvents in removing sulfur compounds and acid gases from natural sour gas

Ghanbarabadi, Hassan; Khoshandam, Behnam

doi:10.1016/j.jngse.2014.12.024

Cited by 61 publications

(26 citation statements)

References 9 publications

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“…Therefore, this paper focuses on removing these contaminants from the feed [1]. The process of using chemical or physical solvents to remove these gases from the raw gas feed is referred to as natural gas sweetening, and its key focus is to meet the sales gas specification [1,11].…”

Section: Introductionmentioning

confidence: 99%

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Sulfolane and di-iso-propanol lean amine blend operating temperature and pressure effect to natural gas sweetening using process simulation

2020

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Blending physical and chemical solvents has shown to be promising for removing hydrogen sulfide, carbon dioxide and mercaptan from natural gas effectively. Studies show that using sulfolane and methyl di-ethylene amine blend yields better performance than traditional methods. However, the Shell process depicts that blending sulfolane with di-isopropanol amine significantly minimizes the problem associated with amine re-circulation efficiency observed with the application of sulfolane and methyl di-ethylene amine. This study aimed at investigating the effect of temperature and pressure to the acid gas removal performance of sulfolane and di-iso-propanol lean solvent using Aspen HYSYS software. In addition, the determination of optimum blend ratio was considered. The acid gas composition of the natural gas stream was 16.9%. This is a hypothetical data used to mimic a relatively high acid gas content in a typical raw natural gas feed. During the process simulation, the lean solvent temperature and pressure were varied between 5 and 210 °C, and 20 and 250 bar, respectively, while maintaining the reactant flow rate at 819.5 kg/h. Findings informs that the optimum blend formulation obtained was 15% water, 15% sulfolane and 70% di-iso-propanol amine at operating temperature and pressure of 50 °C and 45.5 bar, respectively. At the end of the process, the acid gas composition reduced from 16.9 to 0.26%, with an increase in the methane composition by 16.12%. This was as a result of the reduction in the vapor point of the lean solvent, which significantly contributed to enhancing the contact time and efficiency between the gas feed and lean solvent. Hence, the sales gas specification for natural gas was met at lower operating temperature and pressure below 10 °C and 25 bar, respectively.

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Section: Introductionmentioning

confidence: 99%

“…Ghanbarabadi and Khoshandam [11] used sulfolane and MDEA blend in Ilam gas refinery for natural gas processing, to meet sales gas specifications. It was found that 30-40% mercaptan along with hydrogen sulphide and carbondioxide, requiring less than 25% regeneration energy, compared to using MDEA as a standalone solvent.…”

Section: Introductionmentioning

confidence: 99%

Sulfolane and di-iso-propanol lean amine blend operating temperature and pressure effect to natural gas sweetening using process simulation

2020

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“…These chemicals provide necessary water solubility and alkalinity for absorbing acid gases impurities by their Hydroxyl and Amino groups, respectively [1]. Although primary and secondary amines have more alkalinity and reactivity compared to tertiary amines [3], in terms of energy saving, stability and solvent losses, tertiary amines are more desirable [4]. Tertiary amines like MDEA are able to selectively absorb H 2 S and do not directly react with CO2 [1].…”

Section: Introductionmentioning

confidence: 99%

Revamping of an acid gas absorption unit: An industrial case study

Kheirinik

Rahmanian

Farsi

et al. 2018

Journal of Natural Gas Science and Engineering

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This work evaluates the efficiency of the aqueous mixture of Methyl Diethanolamine (MDEA) and Diethanolamine (DEA) at various mass concentrations to remove CO 2 and H 2 S from natural gas in an industrial sweetening unit in Fajr Jam Gas Refining Company located in the south of Iran and gives recommendations for modifying the process. The sweetening unit includes absorber and desorption towers, flash drum, lean and rich amine exchanger, kettle type reboiler and a reflux drum. The considered process is simulated by Promax simulator (version 3.2) taking into account operational constraints and sustainability of the environment. The validity of simulation has been evaluated by comparison between simulation results and the plant data. The main objective of this work is the modification of natural gas sweetening unit to achieve lower energy consumption. Thus, the effect of amine circulating rate and MDEA to DEA ratio on steam consumption in the regeneration tower, CO 2 and H 2 S concentration in the treated gas, and the acid gas loadings have been investigated. Therefore, substitution of DEA solvent in the unit with the aqueous mixture of DEA and MDEA is proposed. In the examined cases, the mass concentration of MDEA and DEA lies between 15-45 wt % and 0-30 wt%, respectively, with the reference cases having MDEA 0 wt.% and DEA 31.6 wt.%. The results show that in the proposed cases of alternative mixtures including cases 1 (MDEA15 wt% and DEA 30 wt%), 2 (MDEA 20 wt% and DEA 25 wt%), and 3 (MDEA 25 wt% and DEA 20 wt%) the amount of reduction in amine circulation rate are between 11.1%v/v and 19.4%v/v compared to the original amine circulation rate. Likewise, steam consumption decreases between 24.4 %wt/wt and 27 %wt/wt. Influence of anti-foam injection for the different cases were also studied and it was found that anti-foam with the concentration of 5000 ppmv is more suitable for the optimum operation and is a more cost effective.

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“…H 2 S, CO 2 , mercaptans, etc.) to the required standards for storage and transportation (Karimkhani and Khorrami, 2009;Ghanbari and Khoshandam, 2014). The vapor pressure of the processed condensate must meet a range within which light components don't evolve as a separate gas phase in pipelines or storage tanks.…”

Section: Introductionmentioning

confidence: 99%

Toward an intelligent approach for H 2 S content and vapor pressure of sour condensate of south pars natural gas processing plant

Kazerooni

Adib

Sabet

et al. 2016

Journal of Natural Gas Science and Engineering

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Simulation and comparison of Sulfinol solvent performance with Amine solvents in removing sulfur compounds and acid gases from natural sour gas

Cited by 61 publications

References 9 publications

Sulfolane and di-iso-propanol lean amine blend operating temperature and pressure effect to natural gas sweetening using process simulation

Sulfolane and di-iso-propanol lean amine blend operating temperature and pressure effect to natural gas sweetening using process simulation

Revamping of an acid gas absorption unit: An industrial case study

Toward an intelligent approach for H 2 S content and vapor pressure of sour condensate of south pars natural gas processing plant

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