Understanding Corrosion in Water Pipelines: A Guide for Pipeline Designers


4 Important Corrosion Sources in Natural Gas Dehydration Process Plants

By Chikezie Nwaoha
Published: August 31, 2017 | Last updated: January 31, 2022
Key Takeaways

The occurrence of corrosion during gas dehydration can be blamed on several issues, such as the water content in the feed gas stream, oxygen ingress (air ingress), impurities in the gas stream, and high temperature for glycol regeneration.

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Gas dehydration is a key unit operation in the natural gas processing chain because it involves the reduction of water vapor in the gas stream with the aim of decreasing the water condensation temperature, also known as the water dew point temperature. This is done to meet sales specifications or to meet the requirements for the gas liquefaction process. Gas dehydration is achieved by applying solid desiccants (activated alumina, molecular sieves, silica gel) or liquid desiccants (glycols). The glycol process is more efficient compared to the solid desiccants because of the high affinity and physical absorption capability. Commonly used glycols include monoethylene glycol (MEG), diethylene glycol (DEG) and triethylene glycol (TEG), with TEG being most common because the operating cost is lower and it can be regenerated easily.


Overview of the Natural Gas Dehydration Process

Figure 1 shows a typical process configuration of a natural gas dehydration unit that uses glycol. The water-saturated gas (e.g., high pressure natural gas) exiting the acid gas removal unit enters the glycol absorber where it counter currently contacts with the water-lean glycol solution. The glycol solution physically absorbs the water vapor and leaves the absorber bottom.


The 4 Important Corrosion Sources in Natural Gas Dehydration Process Plants

Figure 1. Typical process configuration of a gas dehydration process plant using a glycol solution.

The pressure of the glycol solution is lowered in the flash drum to remove any possible hydrocarbons that were co-absorbed in the absorber. The pressure drop also helps to keep the glycol solution pressure equal to the stripper pressure of about 2 bar (200 kPa). The cross-exchanger is where the rich glycol solution absorbs heat from the hot lean glycol solution, which facilitates water desorption in the stripper. The reboiler provides the necessary heat for stripping the absorbed water vapor to produce high purity glycol (≥ 98.5 wt.%) to be recycled to the absorber.


Vaporized glycol is recovered by the stripper overhead condenser and refluxed back into the stripper to reduce glycol losses.

Dehydration of natural gas is particularly important in the gas liquefaction chain where water will freeze at 0°C (32°F) because natural gas liquefaction occurs at about -160°C (-256°F). The dehydration unit is usually situated downstream from the amine unit where acid gases (CO2, H2S, etc.) are removed. Wherever the gas dehydration unit is located, the main aim is to reduce the amount of water vapor in the gas stream to avoid and reduce accompanying issues, especially corrosion. However, the occurrence of corrosion during gas dehydration can be blamed on several issues, such as the water content in the feed gas stream, oxygen ingress (air ingress), impurities in the gas stream, and high temperature for glycol regeneration. (Related reading: Corrosion in Carbon Capture Processing Plants.)


Water Content in the Feed Gas Stream

The presence of water in feed gas streams will most likely lead to the formation of hydrates. Hydrates are a solid-like crystalline compound that is formed when hydrocarbons become trapped or caged in the molecular cavities of free water. Being solids, these hydrates will not only plug the pipeline transportation network, heat exchangers and booster compressors, but will lead to erosion corrosion. In the presence of a high velocity gas stream, these gas hydrates will erode the outer protective layer of the plant's infrastructure construction materials, and in the worst case will erode the construction material itself. (To learn more about erosion corrosion, see Erosion Corrosion: Coatings and Other Preventive Measures.) These eroded materials in the presence of the high velocity gas stream can also accelerate existing erosion corrosion. Erosion corrosion can also be triggered by the presence of eroded materials in the high velocity glycol solution. If this is left uncontrolled and unattended, it will eventually lead to leakage and possible oxygen ingress. Oxygen ingress will aggravate any existing erosion corrosion. Upstream coolers and separators should be installed to reduce the potential of hydrate formation due to free water.

Oxygen Ingress

There are several possible sources of oxygen ingress into a gas dehydration processing plant, including holes in gas lines, the failure of moving parts in gas compressors and glycol pumps, and empty space in process vessels and the glycol storage tanks. Regardless of the source, once oxygen finds its way into the gas dehydration unit it readily oxidizes the glycol solution to form organic acids that are very corrosive. These organic acids will reduce the pH of the glycol solution. As a precautionary technique, the glycol pH is regularly checked during plant operations as this can be an early indication of possible glycol oxidation. All moving parts of gas compressors and glycol pumps should be well-fitted to avoid possible oxygen intrusion. In addition, an inert gas blanket should be used to envelope the empty space in glycol storage tanks. In cases where oxygen ingress is very difficult to prevent, oxidation inhibitors should be injected into the glycol.

Gas Stream Impurities

Impurities in the gas stream are another source of corrosion in gas dehydration plants. In the scenario were the gas dehydration unit is located downstream of the acid gas removal unit, residual CO2 and H2S in the gas stream will become a potential source of corrosion. The natural gas exiting the acid gas removal unit is usually water-saturated, especially when an aqueous amine solution is used for the process. Therefore, in the right conditions (temperature and pressure) residual CO2 will interact with the water to form carbonic acid according to the equation:

CO2 + H2O —> H2CO3

Carbonic acid will not only increase the corrosion rate of the process equipment but will also reduce the efficiency of the glycol solution (pH reduction).

Then again, the residual CO2 and H2S in the feed gas will be co-absorbed by the glycol solution, leading to acidic glycol (a pH reduction). The formation of acidic compounds also occurs in the glycol solution where water and acid gases exit the process.

Therefore, it is important to note that corrosion reduction in gas dehydration plants also depend on the efficiency of the acid gas removal process unit.

Thermal Degradation of Glycol

The thermal degradation of any chemical solvent occurs when the operating temperature exceeds its thermal decomposition temperature. In most cases, the products formed due to thermal degradation are acidic compounds that will reduce the pH of the chemical solvent, hence accelerating the corrosion rate. This is also the case for glycols used for gas dehydration. In gas dehydration, thermal degradation is most prevalent around the reboiler section (see Figure 1) where temperature is highest (about 200°C, 390°F). For glycols used in gas dehydration, their thermal decomposition temperature increases in the order:

monoethylene glycol (MEG) < diethylene glycol (DEG) < triethylene glycol (TEG)

This is another reason why TEG is more frequently used for gas dehydration because it is stable and can withstand high stripping temperatures. However, as a rule of thumb stripping temperatures should be much higher than the decomposition temperature of the glycol.


It can be seen that the efficiency of the acid gas removal unit plays an integral role in reducing corrosion rates in gas dehydration process systems. Hence, there is a need to maintain a very low acid gas content in the water-saturated feed gas entering the dehydration process plant. If left unchecked for a prolonged operating time, corrosion of the process equipment will become inevitable due to acid formation. Acid compounds are also formed when very high temperatures are used in the reboiler section (thermal degradation) and when oxygen ingress oxidizes the glycol solution.

Considering that there are occasional upsets during process plant operation, a combination of mitigation strategies should be put in place to prevent and minimize corrosion. This can be in the form of applying oxidation inhibitors and using construction materials that are resistant to acidic compounds. In order to contain capital costs, this material can be used at areas that are susceptible to such corrosion. Alternatively, a protective layer (e.g., a stainless steel lining) can be used on inexpensive carbon steel to prevent direct contact between the carbon steel and the possible corrosive fluid.

Frequently checking the glycol solution's pH also serves as a predictive approach towards determining the presence of acidic compounds. This will help in early identification and troubleshooting of corrosion in gas dehydration process plants. By itself, the glycol pH is not sufficient enough to provide details of the acidic compounds; hence analytical methods should be used for special investigations.

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Written by Chikezie Nwaoha | Researcher, Clean Energy Technologies Research Institute (CETRI), University of Regina

Chikezie Nwaoha

Chikezie Nwaoha, Ph.D. is a Process Engineer with more than 7 years’ research and development experience in carbon capture and utilization from large industrial sources, gas separation, clean energy technologies and process simulation and optimization.

He has published over 10 research articles in international peer review journals and presented papers at international conferences. In 2012, Mr. Nwaoha co-edited the book titled ‘Process Plant Equipment: Operation, Control and Reliability’ which was published by John Wiley and Sons, USA. This was followed by the book titled ‘Corrosion and Materials in the Oil and Gas Industries’ which was published in 2013 by CRC Press (Taylor and Francis Group), USA. He is also a co-author of the books ‘Dictionary of Industrial Terms’ and ‘Dictionary of Oil, Gas and Petrochemical Processing’ which were both published in 2013 by Scrivener Publishing, USA and CRC Press (Taylor and Francis Group), USA respectively. These book projects had over 70 contributors working in all parts of the world – USA, Canada, England, Scotland, Italy, Serbia, Norway, Turkey, Portugal, Nigeria, Egypt, China, Japan, Bangladesh, Malaysia, Jordan, Oman, Singapore, Iraq, Iran, United Arab Emirates, Australia, Brazil and India.

Mr. Nwaoha is engineer–in–training (EIT) with Association of Professional Engineers & Geoscientists of Saskatchewan (APEGS). He is also a member of Pulp and Paper Technical Association of Canada (PAPTAC), Gas Processing Association of Canada (GPAC) and Professional Writers Association of Canada (PWAC).

The statement made herein is solely the responsibility of the author.

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