Apr-2025

Meeting the challenge of tramp amines in crudes

New technologies provide options to refiners for quantifying and mitigating tramp amine corrosion risk.

Joel Lack
Baker Hughes

Article Summary

Being the first processing unit in the overall oil refining process, the crude distillation unit (CDU) takes the brunt of the highly variable impurities and contaminants found in an array of hundreds of crude oils. One type of contaminant, tramp amines, can threaten severe corrosion in the crude distillation tower top, top pumparound, and overhead condensing equipment. There are options for meeting the challenge of identifying tramp amine threats, quantifying their risk, and managing their impact on CDU operation.
While the American Petroleum Institute (API) identifies eight possible damage mechanisms in the crude distillation overhead, two seem to be the most prevalent.¹ The first is acidic water corrosion, or hydrochloric acid (HCl) corrosion. It is caused by volatile acid gases condensing in the presence of the tower stripping steam. HCl from the hydrolysis of sea salts in crude oil is the primary acid, but hydrogen sulphide (H2S), carbon dioxide (CO2), sulphur oxides, and volatile organic acids also contribute. This corrosion mechanism is controlled by pH neutralisation along with the application of inhibitors and is managed well on most units.

The second mechanism is salt corrosion, or ammonium chloride corrosion, but amines can also contribute. This occurs when ammonia or amines are able to react with HCl at temperatures above which water can condense. Salt corrosion is more challenging to control than acidic water corrosion. As such, salt corrosion is the cause of most overhead equipment failures. New technologies that can overcome the barriers to managing salt corrosion in a crude overhead system will be discussed in further detail.
Salt is formed when the reaction of ammonia or amine with HCl becomes thermodynamically spontaneous. The salts formed may be crystalline or molten, but that does not matter much in a crude overhead. These salts are extremely hydrophilic, which means not only are they very soluble in water, but they will also easily absorb moisture from the humid steam stripped overhead vapours.

Now, with an electrolyte present, the salt can ionise. The ammonium or aminium ion that forms is a weak acid, which will disassociate hydrogen ions. These hydrogen ions can oxidise the metal surface, causing corrosion damage. So, technically, salts are a form of acidic corrosion. However, the extremely concentrated phase is difficult to neutralise with conventional chemicals and cannot be mitigated with inhibitors. Therefore, the resulting corrosion can be severe and very localised, often manifesting as pits in the metal.

Sources of salt-forming contaminants
The usual anion in overhead corrosive salts is chloride from HCl. HCl is formed under the high-temperature conditions of the crude furnace from the hydrolysis of non-desalted mineral salts commonly found in crude oils such as magnesium chloride (MgCl2) and calcium chloride (CaCl2).

Bromide salts are also present in crude oil brine water. However, the amount of hydrogen bromide (HBr) typically generated in the furnace does not exceed trace levels in the overhead. On rare occasions, though, levels can be high enough to generate a few ppm in overhead water analyses. Higher bromide levels can be natural, such as in certain crudes from Arkansas in the US, or upstream additives used in deep well production and extending maturing reservoirs. Measurable levels of bromide in the overhead waters present a higher risk for salt formation, as HBr is much more aggressive at forming salts than HCl.

Figure 1 shows the phase equilibrium curves for ammonium chloride (NH4Cl) and ammonium bromide (NH4Br) salts, illustrating the magnitude of this difference. NH4Br will form at about 45°F hotter than an equimolar amount of NH4Cl. Another way to consider this is that 1 ppm of bromide has the same salt-forming tendency as 50 ppm of chloride with ammonia. The salt-forming difference between these two anions varies with different amines, but all show a similarly greater threat with bromide.

Every unit has some ammonia. It is naturally present in crude oil, and some is generated by the thermal decomposition of complex nitrogen-containing compounds in the oil. Additional ammonia can come from desalter wash water, and some units may add ammonia as the acid neutraliser directly to the overhead system.

Most units use an amine neutraliser for better neutralisation properties than ammonia and to reduce the risk of ammonia salt formation by not adding additional ammonia to that naturally present. Unfortunately, the current lowest- cost neutralising amine, monoethanolamine (MEA), is one of the most aggressive salt-forming amines. It is ironic that some operators desiring to save chemical treatment costs usually end up paying to cause corrosion when purchasing MEA-based neutraliser products. Using neutraliser products with amines that are more resistant to salt formation is the easiest way to prevent salts from neutralisers.

Tramp amines are amines that are not added directly to the overhead system but can come from a variety of sources.²
• Neutraliser amines from other refinery units can reach the desalter when process waters are used as a desalter wash source.
• Boiler amines will be present via the stripping steam. Usually, these are low enough in concentration to avoid forming a salt, but some amines, like MEA, can form salts at low concentrations.
• The alkanolamines preferred for acid gas scrubbing are all more aggressive at forming salts at higher temperatures, and they can enter the crude unit via slops processing.
• Tramp amines in the feedstocks come from upstream chemical treatment. The most common are H2S scavengers, which produce amines as a byproduct of the scavenging reaction.
• Some amines are formed from natural nitrogen content in crude oil.
Tramp amines are an increasing issue in refineries, particularly in their application as H2S scavengers. However, even without tramp amines, some units are at risk from salt formation due to ammonia or any neutraliser amine, especially units that operate with lower water dew points. Regardless of the source, salts must be addressed to control corrosion.

Options for mitigating tramp amine salt corrosion
Options for mitigating tramp amine salt corrosion include:
• The first line of defence is the overhead water wash. Except for situations where salts can form at temperatures high enough to affect the tower, an effective water wash can be all that is needed to protect overhead condensers.
• Contaminant reduction of HCl via caustic or tramp amines via desalter acidification can be very effective at preventing salt from forming in the tower, but limitations in maximum removal may not prevent formation before water dew point.