PTQ Q2 2025 Issue

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

B eing the first processing unit in the overall oil refining process, the crude distillation unit (CDU) takes the brunt of the highly variable impurities and contami - nants found in an array of hundreds of crude oils. One type of contaminant, tramp amines, can threaten severe corro - sion 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 pres - ence of the tower stripping steam. HCl from the hydrolysis of sea salts in crude oil is the primary acid, but hydrogen sul - phide (H2S), carbon dioxide (CO2), sulphur oxides, and vola - tile 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 cor - rosion is more challenging to control than acidic water cor - rosion. 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 inhib - itors. 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 magne - sium 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 analy - ses. 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 pres - ent 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 ammo - nium 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

200 225 250 275 325 300 350

NHCl NHBr

175

150

-10

-9

-8

-7

-6

LOG (Partial pressure of ammonia x partial pressure acid ) (psia 2 )

Figure 1 Comparison of the formation temperatures of ammonium chloride and ammonium bromide

PTQ Q2 2025