Hydroprocessing

Corrosion in hydroprocessing units is typically associated with localized damage caused by hydrogen (e.g., high-temperature hydrogen attack, wet H₂S damage, high-temperature H2/H2S corrosion, etc.) or polythionic acid attack. As a result, the effectiveness of traditional corrosion monitoring techniques (both intrusive and non-intrusive), which are better suited for detecting uniform corrosion, is often questioned

Corrosion Monitoring Hydroprocessing (hydrotreating/hydrocracking)

Corrosion monitoring in hydroprocessing units (such as hydrotreating and hydrocracking) is relatively uncommon. The core processes, hydrogenation and/or cracking, occur in a water-free environment at elevated temperatures, making typical uniform electrochemical corrosion unlikely. Corrosion generally takes place in the cooling-separation section of the unit and is often driven by the presence of alkaline sour water (ammonium bisulfide solution).

Common areas of corrosion include the reactor effluent air-cooler (REAC), sour water lines from cold separators, product strippers/stabilizers and fractionation. Even so, corrosion monitoring is not always recommended by process licensors, as proper design and material selection effectively mitigate the risks of elevated corrosiveness. When the concentrations of sulfur, nitrogen, and oxygenates in the hydroprocessing feed exceed the original design conditions, whether due to bio-feed co-processing or the use of high-sulfur side-cuts, corrosion can intensify and demanding stricter monitoring.

Feed preheat section

Typically, the metallurgy used in the feed pre-heat section—such as alloyed steels like 5Cr-0.5Mo or 9Cr-1Mo in high-temperature areas—provides sufficient corrosion protection. The generally low rate of corrosion in these sections often makes on-line corrosion monitoring economically impractical.

However, when the feed contains elevated sulfur levels, the process environment can become more aggressive, accelerating the sulfidation process. In these instances, on-line monitoring may become a reliable and cost-effective solution. Given the pressure and temperature conditions, the preferred monitoring method is Ultrasonic Thickness (UT) Monitoring with multiple sensors installed in the hottest pipeline sections (typically after the furnace).

Reactor Section

The hydrotreating or hydrocracking reactor is usually constructed from alloyed steels (1.25Cr, 2.25Cr etc.), with internal cladding made of 300-series austenitic stainless steels (e.g., 347). In this material configuration, uniform corrosion is unlikely, giving way to localized hydrogen-driven cracking phenomena and/or high-temperature damage caused by metallurgical changes (e.g., temper embrittlement). To assess the impact of hydrogen and the likelihood of hydrogen embrittlement, hydrogen flux probes (typically welded to the shell) are sometimes utilized. However, this form of monitoring is rare, as interpreting hydrogen flux data is not a straightforward process.

Reactor Effluent Coolers (REAC)

Ammonium bisulfide is a primary corrosion driver in effluent coolers and downstream equipment (separators). Proper mechanical design of the REAC (balanced piping at the inlet and outlet) and carefully selected operating conditions (such as avoiding high concentrations of NH4HS, reducing cyanide, and implementing efficient water washing, etc.) are, in most cases, sufficient to mitigate corrosion of carbon steel. Exceeding the design conditions, such as increasing H₂S partial pressure (H₂S pp) and NH₃ partial pressure (NH₃ pp) at the reactor’s outlet due to processing feed with elevated sulfur and nitrogen content, will increase the concentration of ammonium bisulfide. This will require a higher wash water rate, and the resulting excessive turbulence will accelerate sour water corrosion.

Intrusive corrosion monitoring is occasionally used, utilizing modern LPR (Linear Polarization Resistance) technologies with the capability to compensate for FeS electrode depolarization by determining the system-specific Stern-Geary constant (B). Probes are typically placed at the common outlet of the REAC system (refer to Figure 1, Location A).

Since most corrosion damage downstream of the REAC occurs in areas with elevated turbulence (high wall shear stress), UT (ultrasonic testing) systems with multiple sensors may also provide a good view in corrosion projections. However, the installation of UT sensors should be preceded by thorough flow modeling to identify areas with the highest wall shear stress and the potential for the highest corrosion rates. The most typical locations are shown in Figure 1 at points B and B’.

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Product stripping and fractionation

After sour water separation, the hydrocarbon stream is generally considered non-corrosive. However, depending on the specific process configuration, if an additional product stabilizer/stripper is used, elevated corrosion may occur in the overhead (OVHD) section of the product stripper. Consequently, though rare, corrosion probes may be installed at the inlet and outlet of the stripper’s OVHD condensers. Electrical resistance probes are the preferred choice, as the very low water content (if any) makes LPR systems non-functional.

In the main fractionator section, general corrosion driven by electrochemical reactions is unlikely, so corrosion monitoring is typically not implemented in this process area.

Summary

A comprehensive summary of corrosion monitoring practices for Hydroprocessing is presented in Table 1. This table outlines typical locations for monitoring, and the recommended monitoring techniques for each unit.

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