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Amine systems in natural gas processing plants and crude oil refineries are prone to various forms of disruption, making them notoriously difficult to maintain in a steady state. Common causes of amine unit upset include: (1) liquid hydrocarbons that enter the amine system with the natural gas stream (2) particulate solids that enter the amine unit with the natural gas stream and/or that form as corrosion products in the process unit itself (3) hydrocarbon-solid combinations that form a shoe-polish like substance that adheres to process equipment, and (4) heat-stable salts that form from the reaction of amine with oxygen and acids. The focus of this discussion is on the impacts of and removal of particulate solids in amine sweetening units with attention to the application of magnetic separation systems.
Particulate contamination in amine systems can be found in natural gas feeds, rich amine and lean amine. It can also be found in related equipment including absorbers, regenerator columns, reboilers, sumps and separators. Mechanical filters are typically applied to remove such contamination on both the rich and lean sides of the system. These filtration systems can be very expensive to operate given the high particle counts and small sizes of the particulates. For example, up to 70% of iron sulfide particulate can be less than 10 microns in size. Increasing the size rating of the mechanical filters to avoid replacement filter costs is often an expedient resolution, although problematic from the standpoint of removing contamination. Historically, very limited alternatives have been available.
Magnetic separation systems have been employed selectively in hydrocarbon processing and pipeline applications for over 10 years. They are now being used more widely in field gathering, gas processing, pipelines, fractionation, refineries, chemical plants, tankage and ship loading terminals. In amine service, when positioned upstream of existing mechanical filtration systems, they have shown to be remarkably effective at capturing both ferrous and non-ferrous particulate contamination to very high efficiency levels down below 0.10 microns. This can significantly reduce conventional filter use, increase amine efficiency; reduce erosion effects on system components and reduce fuel, anti-foaming chemicals and amine replacement costs.
Natural gas processing facilities and crude oil refineries typically employ an amine system process for the removal of acid gasses (H2S and CO2) from natural gas and other light gasses and products. Such processes are closed loop systems that use different varieties of alkanolamines (or amines, such as MEA, DEA, DGA, MDEA, etc) in an absorber column to chemically strip the acid gasses from the incoming gas or product stream. The subsequent rich amine stream is processed through a series of vessels and filters for the purposes of isolating and removing the acid gas stream. This refurbishes the amine for subsequent re-use as lean amine and removes particulate contaminants.
Although considerable effort is devoted to keeping the amine system free of contaminants, almost every plant ends up dealing with four typical forms of these contaminants. These are:
Entrained hydrocarbons that condense out of the natural gas stream in the absorbing tower;
Solids that are introduced with the natural gas stream and corrosion products that develop in the amine system itself;
Combined hydrocarbons and solids that form an adhesive “shoe-polish” compound; and
Heat stable salts that form from the reaction of amine with oxygen and acids stronger than H2S and CO2.
The presence of H2O, along with H2S and CO2, may cause the formation of hydrosulfuric and carbonic acid. These are highly corrosive to the carbon surfaces, as they compromise the piping and vessels in the amine system. This corrosion produces sulfides, oxides, and hydroxides of the alloying elements of the various system components. The byproducts of which are mostly solid phase in nature, with particle sizes ranging from below 1 to over 150 microns.
The presence of even a small amount of liquid hydrocarbons in the contactor can be disruptive; it will change the surface tension of the lean solvent that cascades downward through the trays of the absorber, resulting in foaming...