The natural gas dehydration is an important operation in the gas processing and conditioning industry. The standard method for natural gas dehydration is absorption of water using triethylene glycol (TEG). TEG is used in about 95% of the glycol dehydration units for natural gas streams. Glycol dehydration units conventionally consist of a contactor, and a regenerator. An alternate approach for the enhancement of stripping column performance is the use of stripping agent. In this approach a volatile hydrocarbon liquid is added into the glycol regeneration system instead of stripping gas. Reduction of TEG loss and its regeneration is one of the most important processes in gas refinery industry because it is an expensive chemical component.
Most dehydration systems use triethylene glycol (TEG) as the absorbent fluid to remove water from natural gas. As TEG absorbs water, it also absorbs methane, other volatile organic compounds (VOCs), and hazardous air pollutants (HAPs) such as benzene, toluene, ethylbenzene and xylenes (BTEXs). As TEG is regenerated through heating in a reboiler, absorbed methane, VOCs, and HAPs are vented to the atmosphere with the water, wet gas is contacted counter-currently with the glycol which absorbs the water vapor.
The dry gas is piped for further processing or for transmission to a sales pipeline. The rich glycol is fed to a reboiler for regeneration; heating the solution to 200 C will remove enough water to re-concentrate the glycol to 98.5% w/w or better. For processes requiring gas with very low water dew points, or if the wet gas is relatively warm, stripping gas will most likely be needed to aid the regeneration process. For maximum stripping, this gas is normally injected into a short column at the bottom of the reboiler. However, the gas may also be introduced directly into the reboiler.
Natural gas containing high quantities of H2S and CO2 is considered toxic. If H2S and CO2 volumes are appreciable, this lowers the heating value of the sales gas. Thus, sour gas or acid gas must be treated to remove these toxic components. The processes used for removal of acid gas are referred to as sour gas sweetening, amine gas sweetening, gas conditioning or gas treatment.
If water is present in the natural gas along with acid gas components, the combination can be highly corrosive. Therefore, some processes require that the water be removed from the natural gas (dehydration) prior to any other downstream gas treatment. Buyers and transporters of natural gas often establish product specifications for the sales gas. Specifications for sales gas often limit H2S to less than 4ppm and CO2 to less than 3 or 4 mole percent.
Gas sweetening is achieved by contacting the primary gas stream with a solvent solution, usually amine. Alkanolamines are the most widely used solvents for removal of acid gas components. There are several commercial amines available including triethanolamine (TEA), diethanolamine (DEA), monoethanolamine (MEA), diglycolamine (DGA) and methyldiethanolamine (MDEA).
Many of the gas sweetening processes are similar. For a general process description, the term MDEA, or more generally, amine can be used. MDEA is a tertiary amine which can be regenerated and can be used to selectively remove H2S and slip CO2. Slip CO2 is the CO2 that passes through the process along with the treated gas. In this process, MDEA contacts and absorbs the acidic gases. The lean aqueous amine concentration, generally in the range of 40 to 50% by weight, flows counter current to the gas stream in an Absorber/Contactor column.