Important: AMPP System Update February 27 - March 11 – Limited Access to AMPP Digital Services. Act Now to Avoid Disruptions! - Learn More
In recent years, unexpected failure caused by sulfidation corrosion have increased presumably because many refineries diversify the crude oils to process them. Crude oils contain corrosive species such as sulfides, nitrides, chlorides, organic acids and chemical additives. In these corrosive species, sulfides in the fluids cause sulfidation corrosion operating at temperature above approximately 260 °C1.
A new prediction tool was developed for sulfidation corrosion applied in crude units. The corrosion rate of sulfidation is predicted using the total sulfur concentration and temperature by the modified McConomy curves. However, the corrosion behavior in crudes even with the same total sulfur concentration is sometimes different. This is because the corrosion rate might be affected by reactive sulfur compounds in particular crudes. This study was conducted to enhance prediction technique using a new factor replaced with the total sulfur concentration. For the target crude oils, diesel, heavy gas oil and residue fractions were distilled using a 15-stage distillation apparatus. The corrosion rates by immersion tests with each fraction were not correlated with the total sulfur and mercaptan concentrations. Then, “S factor” is proposed as a new concept to evaluate the sulfidation corrosion rate. The coefficients are determined for the total sulfur and mercaptan concentrations in distillates, and the S factor is defined as an addition of each term. As a result, the corrosion rates have a good correlation with the S factor. As well as the total sulfur and mercaptan concentrations, the S factor is installed as a prediction factor of the sulfidation corrosion of crudes.
The corrosivity of four mercaptans and selected crude oil fractions were measured in lab tests. Conclusion: Mercaptan corrosion can contribute significantly to the total sulfur related corrosion in the temperature range 235–300°C, which agrees with observations of elevated temperature corrosion in refinery distillation equipment.
We are unable to complete this action. Please try again at a later time.
If this error continues to occur, please contact AMPP Customer Support for assistance.
Error Message:
Please login to use Standards Credits*
* AMPP Members receive Standards Credits in order to redeem eligible Standards and Reports in the Store
You are not a Member.
AMPP Members enjoy many benefits, including Standards Credits which can be used to redeem eligible Standards and Reports in the Store.
You can visit the Membership Page to learn about the benefits of membership.
You have previously purchased this item.
Go to Downloadable Products in your AMPP Store profile to find this item.
You do not have sufficient Standards Credits to claim this item.
Click on 'ADD TO CART' to purchase this item.
Your Standards Credit(s)
1
Remaining Credits
0
Please review your transaction.
Click on 'REDEEM' to use your Standards Credits to claim this item.
You have successfully redeemed:
Go to Downloadable Products in your AMPP Store Profile to find and download this item.
High temperature sulfidation is one of the oldest damage mechanisms in the refining process such as crude distillation unit, vacuum distillation unit and hydroprocessing unit. Since corrosion proceeds to general corrosion and occurs in a high temperature environment, it is a type of corrosion that can lead to a large fire explosion when a leak occurs.
There are three known types of high temperature sulfidation present in the refining industry. Two of them have industry recognized methodologies for damage prediction, and they both manifest as general thinning morphologies. They are known as H2-free sulfidation and H2/H2S corrosion. The third type, although recognized as H2-free, low-sulfur corrosion, does not have an accepted chemical theory or a prediction tool, and it manifests as a localized thinning morphology. This third type of sulfidation is much less common and occurs in units and process conditions where little-to-no H2S would be expected to be present. This paper discusses the operating conditions in two known damage cases presented here and provides a viable chemical theory that could lead to the observed damage profile. In addition, an approach to mitigation of this attack is discussed.