- Research Article
- Open Access
Ethylene glycol elimination in amine loop for more efficient gas conditioning
© The Author(s) 2018
- Received: 9 July 2018
- Accepted: 15 November 2018
- Published: 23 November 2018
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, H2S 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.
- CO2 and H2S absorptions
- Mono ethylene glycol
- Amine gas sweetening
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 prevention of catalysts poisoning in downstream facilities .
Many methods have been employed to remove acidic components (primarily H2S 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 H2S and CO2 removal and environmental compliance. An amine gas treating plant is commonly faced with two major problems: corrosion and instability of operation . 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 diglycolamine (DGA) is used to separate H2S and CO2 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 H2S, high equilibrium loading capacity (1 mol CO2 per 1 mol amine) and less heat of reaction with CO2, 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) changing operational parameters in the presence of MEG in amine loop; (2) reducing MEG loading in amine loop by total or partial discharging of amine; (3) enhancing resistant to corrosion; (4) developing a strategy to track the source of MEG in amine loop were suggested and investigated.
Characteristics of sour gas feed to the gas sweetening unit (units 101 and 108) of phases 2 and 3 in South Pars Gas Field (Asalouyeh, Iran)
Methyl cyclo pentane
Methyl cyclo hexane
The comparison of the simulation results of the gas sweetening unit with Promax with actual data
Amine flow rate (m3/h)
Inlet to regenerator
Amine temperature (°C)
Top temperature (°C)
Bottom temperature (°C)
Amine inlet to the regenerator reboiler
CO2 loading (mol%)
H2S loading (mol%)
H2S loading mole/mole amine
CO2 loading mole/mole amine
Gas in the absorber top
Amine in the absorber bottom
CO2 loading mole/mole amine
H2S loading mole/mole amine
Chemical properties of MEG
Molecular weight (g/mol)
Normal boiling point (°C)
Ideal liquid density (kg/m3)
Viscosity @ 60 °C (cP)
Flash point (°C)
Regenerator bottom temperature
H2S concentration in sweet gas obtained from the simulation for 1 to 25 wt% MEG content in the amine solution
The simulation results showed that the energy consumption of regenerator reboiler increases from 39,165,295 (Case 1) to 41,274,795 kJ/h (Case 2). In other equipment, the energy consumption was not changed considerably. Totally, the energy consumption in gas sweetening unit increased 5.4% in the case of 25 wt% MEG in lean amine solution while for 1 wt% MEG, the increase was 0.05%.
BTEX and heavy hydrocarbon solubility
Composition of acid gas routed to the SRU with lean amine solution containing 1, 5, 10, 15, 20, and 25 wt% MEG content
Composition (mole%)/MEG (wt%)
Foaming in the amine absorber is a common problem. In an industrial plant, the differential pressure (DP) of the absorber, the flow rate of flash gas (gas exited from the flash drum), and the opening of LV0026 [level valve of the bottom of sweet gas Knock-Out (K.O)] are signs of foaming. Parameters such as sour gas inlet temperature, bottom level of absorber, amine flow rate and temperature, gas flow, antifoam concentration, homogeneity and flow rate, lifetime of filters, total suspended solids (TSS) of amine, and lean amine quality have significant effects on foaming formation.
After removing MEG from lean amine, the opening of LV0026 shows amine carryover and DP of absorber were decreased from 0.3 to 0.2 bar (Fig. 12). These signs showed foaming are reduced in amine loop and the used amine has more TSS in compare to the fresh amine.
MDEA contaminant analysis
The amine analyses results, allowable limit, source, and effects of contaminant
Total amine content (wt%)
Degradation in the presence of oxygen
Can be turned to N-(2-hydroxyethyl) ethylenediamine (HEED)
It is non-corrosive
It promotes thermal degradation of MDEA in presence of oxygen
In the presence of oxygen at a temperature above 82° C
DEA is formed carbamic acid with CO2, this acid can be turned to the n,n,n-tris-(2-hydroxyethyl) ethylenediamine (THEED). THEED corrosion rate is 6 times higher than DEA
Production of corrosion or erosion
Production of stainless steel corrosion
Must be monitored and checked by corrosion coupon
Production of stainless steel corrosion
Must be monitored and checked by corrosion coupon
CO2 (mol CO2/mol MDEA)
CO2 in regenerated amine
Helped to the corrosion with formation of HSAS
Combination of amine, glycol with oxygen
Reaction of amine with oxygen at temperature above 121 °C
For 2000 ppm formate, severe corrosion occurs especially in the top of the regenerator
In make-up water and in feed gas
With amine formed amine chloride
Increases the pitting corrosion
Leads to the corrosion and erosion of stainless steel and total corrosion of carbon steel
Oxygen of make-up water is reacted with H2S
Increases the rate of corrosion
Can be formed Bicine
Reaction of amine with oxygen at temperature above 81 °C
Increases the corrosion
Entering oxygen to the system
Purging the water of reflux drum can reduce it
In the feed gas
H2S + O2 + HCN
Reaction with oxygen in temperature above 82 °C
Causes the corrosion
Water make up
Water make up
Amine thermal and oxygen degradation. Side production of cyanide with water
If ammonium is condensed, it absorbed CO2, formed carbonate ammonium or bio carbonate and block the condenser path
It can absorb H2S and formed biosulphide that it is corrosive
Total solid content (wt%)
Weak in primary separation, corrosion from the filters
TSS must be less than 100 ppm
Average particle size (µm)
The average particle size shall be less than 5 μm to prevent foaming
It absorbed in the carbon filter and covers the cartridge filter
Amino acid (ppm)
MDEA covert to TEA. TEA reacts with oxygen to form bicine
Cyanide + formaldehyde
Severe corrosion especially in reboiler
If bicine is more than 250 ppm, corrosion more than 10 mpy is expected for carbon steel
Can be removed by vacuum distillation and ion exchange
Carbon steel corroded
In the presence of oxidant and acids, MDEA converts to MMEA at high temperature
Can be converted to the DMHEED
Can be made situation with potential for corrosion
Can be removed by vacuum distillation
Temperature more than 121 °C and presence of oxygen
Water washing before absorber can be reduced it
Fitting and metering in wellhead equipment, lines are corroded or amine tank if has not nitrogen as inert gas
In presence of oxygen, MDEA, after a while, converts to the DEA
For less amount of oxygen, oxygen scavenger such as hydrazine, amine hydroxyl can be used
Nitrogen blanketing in amine tank
Oxygen solubility in amine is 2 to 10 ppmv
100 ppmv of oxygen in feed gas can produce high amount of HSS
0.5 to 1.0 wt%
When amine react with acids stronger than H2S and CO2
Increases foaming, viscosity and mass transfer, decreases capacity of acid gas absorption
For ratio less than 19, total acid gas in amine increases relatively because of protection layer of FeS
Dark coffee from corrosion
Dark brown from thermal destroyed
When the amine is brown, after passing of filter paper, the color is changed, the source is corrosion otherwise the source is amine thermal degradation
Nil to 30 s
Hydrocarbon and solid particle
Dropping the bottom temperature of amine regenerator:
In this technique, the temperature and pressure at the top of regenerator must be reduced. The temperature has a positive effect but the pressure has not considerable effect. Moreover, rich amine existed from flash drum is entered to the amine/amine exchanger and then routed to the regenerator. If the efficiency of amine/amine exchanger increases, the temperature of amine fed to the regenerator will be increased and consequently less steam is needed in the reboiler and the bottom temperature of regenerator can be kept in lower temperature. But from the economical point of view, this technique was not possible.
Applying a coating of Ceramium on the bottom of the regenerator and around the nozzles of reboiler.
Applying proper insulation in the corroded area over the vapor line to prevent condensation.
Changing the material of the vapor line of reboiler from carbon steel to stainless steel—grade 316 (SS316).
Using partially refreshment of fresh MDEA (0.5 to 5.0%).
After using fresh amine, the H2S content in both fresh amine and consequently in sweet gas were high, indicating acid assisted regeneration phenomena . To reduce H2S loading in amine solution and better amine regeneration, the temperature of amine regenerator was increased from 98 to 110 °C and the bottom temperature of regenerator was increased according to the temperature at top of the regenerator. It must be emphasized to this point that high bottom temperature can cause amine degradation. To keep regenerator bottom temperature less than 132 °C, the amine flow rate was reduced from 155 to 140 m3/h. Lower amine flow rate increases MDEA residence time in the regeneration section and as a result, H2S loading decreases. Therefore, the top temperature of regenerator was decreased from 110 to 105 °C while the bottom temperature was kept less than 132 °C. Since the fresh amine creates some problems in the amine gas sweetening unit, refreshment was partially carried out in order to keep MEG content less than 10 wt%. With results of this experience, it is suggested a few used-amine is added to the fresh amine after the construction of the amine gas sweetening unit.
Comparing actual and simulated data of MEG wt% in the bottom of 105-D-201
MEG% in lean amine
MEG wt% in bottom of 105-D-201
MEG loading in lean amine after routed to the bottom of 105-D-201 in the condensation unit instead of routing to the amine flash drum
MDEA make-up in gas sweetening unit train #1 to #4
MDEA Make-Up (m3)
In addition, with consideration of operational parameters, this line (bottom of 105-D-X01 routed to the condensation unit) must be checked from the corrosion point of view. Therefore, corrosion coupon was installed in the route. After 6 months, the installed corrosion coupons showed corrosion rate less than 1 mpy (allowable limit of NACE standard RP 0775). Consequently, by applying the proposed operational remedies, the MEG loading in amine loop has kept less than 15 wt% for 3 years.
Introducing 25 wt% MEG in amine loop decreases H2S and CO2 absorption from sour gas.
Introducing 25 wt% MEG, the regenerator bottom temperature was increased from 129 to 135 °C and consequently, energy consumption of the sweetening unit was increased 5.4%.
Because of less CO2 absorption in absorber column, H2S concentration in inlet SRU was increased. Also, the solubility of BTEX and heavy hydrocarbon in amine solution was increased, which leads to transferring BTEX to SRU and finally sooner catalyst deactivation.
Foaming problems were increased.
Severe corrosion was observed in some parts of the regeneration section. Since approximately all the contaminations of amine were in the allowable limit, the reason for the corrosion just can be related to the MEG presence and higher temperature of the regeneration section.
Total and/or partial refreshment of fresh MDEA was used in gas sweetening unit to reduce MEG content. Furthermore, some techniques (install insulation, coating, etc.) in point of prevention of corrosion were carried out in regenerator tower.
Bottom of the inlet K.O drum of the dew pointing unit (105-D-X01) was routed to the stabilization unit instead of routing to the amine flash drum. Hence, the MEG presence in lean amine was kept less than 15 wt% until now.
The value, allowable limit, source and effects of each contaminant and the pros and cons of operational conditions in amine gas sweetening were illustrated.
It is recommended to consider the effects of MEG in amine loop in the design of gas sweetening unit when glycol exists in the offshore.
The work is a product of the intellectual environment of the whole team; and that all members have contributed in various degrees to the analytical methods used, to the research concept, and to the experiment design. Both authors read and approved the final manuscript.
The authors acknowledge the engineering department of Phases 2 and 3 of South Gas Pars.
The authors declare that they have no competing interests.
Availability of data and materials
The datasets generated and/or analyzed during the current study are available from the corresponding author on reasonable request.
Consent for publication
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