Alkanolamine solutions removing acid gases such as CO2 and a : s from natural gas, synthetic gas or light hydrocarbons are often plagued not only by corrosion problems but also by fouling of heat exchange surface area and contact equipment. Corrosion due to amine heat stable salts and CO2 are of particular concern since they are not easily controlled through changes in operating parameters. Operating problems arising from corrosion and fouling can be diminished through addition of a unique additive via continuous injection or by pre-blending with the make-up amine solution. The additive is a multicomponent formulation incorporating metal passivators, neutralizing agents, and reducing agents. There are no detrimental effects and the additive has been successfully used in MEA, DEA, MDEA, high performance amine formulations and physical solvents. The paper discusses some of the corrosion and fouling mechanisms and plant improvements after addition of the additive.
Alkanolamine solutions are often used to remove acid gases such as CO: and H2S from light hydrocarbons or synthetic gases. Alternatively, when acid gas partial pressures are high, a physical solvent such as a methyl ether of a polyethylene glycol may be used. In either case, the acid gases are absorbed into the solution then released by thermal regeneration or by one or more low-pressure adiabatic or isentropic flash stages. Corrosion and fouling in these "treating" systems result from any one of the following: poor initial design, over utilization, contamination by another reactive, more corrosive component than H2S or C02, heavier hydrocarbon contamination, solution degradation, or poor operating practices.
The types of corrosion associated with these systems are well documented in the literature. ~'2 In general the corrosiveness of the system increases with acid gas loadings in the solvent, operating temperature, and solvent linear velocities. Other factors influencing corrosion are solvent pH, solvent concentration, level of heat stable salts or chlorides and solvent degradation products. Experience has shown that in systems operating with relatively low acid gas loadings, amine solution velocities of approximately l rn/sec or less, acceptable amine concentration ranges and low amine degradation or heat stable salts, a corrosion inhibitor is typically not warranted. More specific criteria are listed in Table 1. However in other systems not meeting the low corrosion conditions, it is necessary to inhibit corrosion to allow for safe operation in normally corrosive regimes. In these cases corrosion inhibitors have been used for many years. Examples include alkali metal salts based on chrome, vanadium, or antimony; arsenic; filming amines; and oxygen scavengers or reducing agents.
The filming amines, antimony and arsenic compounds can be classified as anodic or cathodic inhibitors. They adhere to the metal surface to form a barrier against corrosion. The organic film formers are usually based on heavy amines or have acetylenic bonds so as to adhere to metal surfaces. The barrier is often only a few molecular layers thick and not sufficiently tenacious to guard against aggressive corrosion. The organic film formers have worked well in the vapor phase regions of the regenerator overhead and in the cooler areas of the amine unit. They have not been very effective in other areas especially the piping and reboiler where corrosion occurs from the hot acidic anions of the amine heat stable salts or from residual COs. The inhibitors based on arsenic and antimony are now rarely used due to toxicity concerns. The organic film formers can also lead to unit fouling and will be removed by the activated carbon fil
