ABSTRACT Many process conditions in refinery amine units are known to promote accelerated corrosion. Monitoring corrosion in these units typically is limited to the traditional means- coupons, linear polarization probes, electrical resistance probes and so forth. Amine analyses are useful but not entirely without shortcomings when applied to corrosion monitoring. Computer modeling has evolved to become a useful tool in identifying potentially corrosive environments in localized areas within the unit. In this paper, a computer model is developed using data from a refinery system using MDEA to remove hydrogen sulfide from a process stream also containing carbon dioxide. Rules for reducing corrosion developed in-house or in literature are applied to anticipate corrosion.
INTRODUCTION The development of process simulation software that can estimate the composition, chemical and physical parameters of process streams in refinery amine unit service is not new. These types of programs have been used to identify operating variables and equipment for several decades. This paper illustrates some of the uses of process simulation software in predicting corrosive environments in amine units.
Amine solutions are used to remove hydrogen sulfide (H2S) and mercaptans from refinery process streams by adsorption. Carbon dioxide (CO2) and many other acid specie are also absorbed by the amine solution from the process stream.
Still other acid specie are reported to form in the amine solution from compounds in the feed stream such as carbon monoxide, oxygen and hydrogen cyanide.
The weakest of these acids, hydrogen sulfide and carbon dioxide, are removed from the amine solution by steam stripping. The steam stripping is not complete so residual hydrogen sulfide and carbon dioxide remains in the lean amine solution.
Many of these acids are not removed by steam stripping and are called Heat Stable Salts (HSS) or, unless otherwise neutralized, Heat Stable Amine Salts (HSAS). The accumulation of HSAS in the amine solution has been documented and generally agreed to as increasing corrosion activity. Heat Stable Amine Salts can be removed from the solution (called reclaiming) or neutralized insitu.
Amine solutions used in refinery service
The amine solvent is selected to meet specific processing needs with the most common being (mono) ethanolamine (MEA), diethanolamine (DEA), methyldiethanolamine (MDEA) and Diglycolamine (DGA). Each amine solvent has distinct advantages and disadvantages.
One of the most important parameters in selecting an amine solution is "selectivity" for H2S over other acid gases. Of the amines listed here, MDEA is the only amine with significant selectivity in commercial applications. This selectivity reduces the amount of carbon dioxide absorbed by the solution allowing for higher capacity or lower energy usage. H2S selectivity also reduces the amount of CO2 in the acid gas feed stream to the sulfur plant. H2S selectivity increases as MDEA concentration is reduced.
Mercaptan removal is important for many petrochemical feed stocks. DGA is reported to provide the best mercaptan removal.
All of the amines have some solubility in hydrocarbon streams such as liquefied petroleum gas or LPG. Literature 3 indicates that at the maximum recommended concentrations, DEA has the lowest LPG solubility. Amine losses resulting from solubility in LPG increase with amine solution concentration. The literature source indicates that MDEA solubility in LPG increases from about 135 ppm to 300 ppm as MDEA concentration increases from 35 to 50-wt%.
In refinery service, all amine solutions that accumulate HSAS require reclaimin