Ethylene glycol elimination in amine loop for more efficient gas conditioning

Hajilary and Rezakazemi Chemistry Central Journal (2018) 12:120 https://doi.org/10.1186/s13065-018-0493-3 RESEARCH ARTICLE Chemistry Central Journal Open Access Ethylene glycol elimination in amine loop for more efficient gas conditioning Nasibeh Hajilary1* and Mashallah Rezakazemi2 Abstract The gas sweetening unit of phase 2 and 3 in South Pars Gas Field (Asalouyeh, Iran) was first simulated to investigate the effect of mono ethylene glycol (MEG) in the amine loop. MEG is commonly injected into the system to avoid hydrate formation while a few amounts of MEG is usually transferred to amine gas sweetening plant. This paper aims to address the points where MEG has negative effects on gas sweetening process and what the practical ways to reduce its effect are. The results showed that in the presence of 25% of MEG in amine loop, H 2S absorption from the sour gas was increased from 1.09 to 3.78 ppm. Also, the reboiler temperature of the regenerator (from 129 to 135 °C), amine degradation and required steam and consequently corrosion (1.10 to 17.20 mpy) were increased. The energy consumption and the amount of amine make-up increase with increasing MEG loading in amine loop. In addition, due to increasing benzene, toluene, ethylbenzene and xylene (BTEX) and heavy hydrocarbon solubility in amine solution, foaming problems were observed. Furthermore, side effects of MEG presence in sulfur recovery unit (SRU) such as more transferring BTEX to SRU and catalyst deactivation were also investigated. The use of total and/or partial fresh MDEA, install insulation and coating on the area with the high potential of corrosion, optimization of operational parameters and reduction of MEG from the source were carried out to solve the problem. The simulated results were in good agreement with industrial findings. From the simulation, it was found that the problem issued by MEG has less effect when MEG concentration in lean amine loop was kept less than 15% (as such observed in the industrial plant). Furthermore, the allowable limit, source and effects of each contaminant in amine gas sweetening were illustrated. Keywords: CO2 and H2S absorptions, Mono ethylene glycol, Amine gas sweetening, Corrosion, Foaming Introduction Natural gas is produced from wells with a range of impurities and contaminants such as sulfur dioxide (SO2), hydrogen sulfide (H2S) and carbon dioxide (CO2) [1–4]. These contaminants should be removed from the natural gas to meet typical specifications for use as commercial fuel or feedstock for natural gas hydrate, liquefied natural gas (LNG) plants, gas turbines, industrial and domestic use [5–8]. Removal of these contaminants is required from point of safety, environmental requirements, corrosion control, product specification, decreasing costs, and *Correspondence: ; 1 Department of Chemical Engineering, Faculty of Engineering, Golestan University, Gorgan, Iran Full list of author information is available at the end of the article prevention of catalysts poisoning in downstream facilities [9]. Many methods have been employed to remove acidic components (primarily H 2S and CO2) from hydrocarbon streams including adsorption, absorption [10, 11], membrane [12–16], hybrid system and etc. [17–20]. From these methods, the amine absorption attracts increasing attention due to higher H 2S and CO2 removal and environmental compliance. An amine gas treating plant is commonly faced with two major problems: corrosion and instability of operation [6]. Furthermore, the purity of amine has a considerable effect on the efficiency of the gas sweetening unit. In most amine based sour gas treating process, the conventional alkanol amines such as monoethanolamine (MEA), diethanolamine (DEA), methyl diethanolamine (MDEA), disopropanolamine (DIPA), and © The Author(s) 2018. This article is distributed under the terms of the Creative Commons Attribution 4.0 International License (http://creativecommons.org/licenses/by/4.0/), which permits unrestricted use, distribution, and reproduction in any medium, provided you give appropriate credit to the original author(s) and the source, provide a link to the Creative Commons license, and indicate if changes were made. The Creative Commons Public Domain Dedication waiver (http://creativecommons.org/ publicdomain/zero/1.0/) applies to the data made available in this article, unless otherwise stated. Hajilary and Rezakazemi Chemistry Central Journal (2018) 12:120 diglycolamine (DGA) is used to separate H 2S and C O2 from natural gas [19, 21]. MDEA is commonly used in industrial plants because it has some advantages over other alkanol amines such as high selectivity to the H 2S, high equilibrium loading capacity (1 mol C O2 per 1 mol amine) and less heat of reaction with C O2, and lower energy consumption in regeneration section. Mono ethylene glycol (MEG) is commonly injected into the system from two different points (wellhead and gas receiving facilities) as corrosion and hydrate inhibitor especially during winter time when the potential of condensation corrosion and hydrate formation are high. In phases 2 and 3 through the gas path, MEG is injected at sea line, before HIPPS valve, and after the High-pressure separator drum. A few amounts of MEG is usually transferred to the amine gas sweetening plant. The MEG concentration gradually increases in amine gas sweetening plant even to more than 25%. A large build-up of injection chemicals can eventually lead to fouling and can cause changes in solution physical properties, such as viscosity and mass transfer. South Pars is a giant gas reservoir shared with Qatar with more than 20 phases. The phases 2 and 3 of South Pars gas refinery has been planted to treat the produced gas through four gas treating trains and stabilize the accompanied condensate from the gas reservoir. Nowadays, about 2500 million standard cubic feet per day (MMSCFD) of gas is fed to this plant. In phases 2 and 3, the untreated gas is transferred via two 30″ pipelines to onshore facilities for treatment. MEG is transferred by means of two 4″ piggy back lines to the wellhead for hydrate prevention and low dosage hydrate inhibitor (LDHI) is being used as a backup. The main purpose of the current study is to find where MEG has negative effects on gas sweetening process and what the practical ways to reduce its effect are. The effects of MEG injection on amine gas sweetening and sulfur recovery unit (SRU) units were also studied. Since the presence of MEG was not predicted in the design of gas sweetening unit, it seems the phases 2 and 3 was the first gas plants to deal with this problem. Other gas refineries in South Pars Gas Field which used MEG as a hydrate inhibitor are gradually encountering this problem. Furthermore, a certain value was not found in the literature for the maximum allowable of MEG content in amine loop. To overcome the problems issued by MEG in amine loop, four different methods including: (1) cha (...truncated)