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 decompo- sition 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 neutrali- sation 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 H 2 S 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, particu - larly in their application as H 2 S scavengers. However, even without tramp amines, some units are at risk from salt for- mation 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. • Stronger base salt control additives can lessen the cor- rosion impact of unavoidable salts but may not achieve desired corrosion control targets.
• Last, operational methods can be used to alter environ- ments to non-salting conditions, but operating outside of the optimal range comes with significant penalties to profitability. However, it may be better than the cost of an unplanned shutdown. Ultimately, these strategies come with costs, but the Topguard program can help understand how much improve- ment can be realised from each, thus helping to optimise the mitigation costs and avoid more costly equipment failure. Identifying threats Before salt corrosion can be addressed, there must be an understanding of how salts form under the range of oper- ating conditions. Since different salts form under different conditions, the first step is identifying which salts are pos - sible in the system. Each salt-forming contaminant must be identified and quantified to assess the salt risk. For most crude overheads, a simple titration method is adequate for identifying the chlorides present in the over- head system. However, the titration method will react to all halides present and may not indicate the presence of bro- mide in the overhead water draw. Periodic elemental analy- ses such as X-ray fluorescence should be used to check for bromide breakthrough into the overhead system. The only proven method to speciate and quantify amines is via liquid ion chromatography (IC). Other attempted methods to date have failed to show consistent reliability across the wide variability of crude overhead water com- positions. The program’s field amine measurement service uses IC-based technology to accurately isolate and quantify ammonia and the two most common tramp amines, MEA and methylamine (MA), without interference with common neutralising amines. Less frequent tramp amines, diethan- olamine (DEA) and methyldiethanolamine (MDEA), are also measurable in most cases. Quantifying threats To allow for prompt evaluation and response to any changes in corrosion risk as unit conditions vary, the benefits of sim - ulation technology are available on demand from the pro- gram’s corrosion risk monitor (CRM). Immediate on-site corrosion-control answers for any issues that arise are also provided. Critical parameters are tracked, including salt for- mation, water dew point, water wash requirements, and vapour velocities. The corrosion risk monitor includes a technique designed to predict the conditions under which salt deposition will occur and define operating strategies that eliminate the harmful deposition. The CRM program determines the equilibrium between a salt and its vapour reactants. As a first step, the CRM program utilises process simulation technology to perform rigorous heat and material balances. The material balance depends heavily on state-of-the-art analytical capabilities to determine the quantities of trace contaminants that comprise the salt-forming reactants. Once the quantity of the various salt reactants is defined, the CRM system carries out thermodynamic calculations to determine the equilibrium salt formation temperature, which depends on the system pressure and on the concentration
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PTQ Q2 2025
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