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This paper presents a recent effort to further minimize the threat of corrosion by wet ammonium chloride salt. Includes advances in fundamental understanding salt behavior, predictive mdeling, integration of models with process and operations.
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Variables that influence extent of vaporization of injected wash water & subsequent impact on minimizing the risk of corrosion. Consequences of liquid maldistribution in reactor effluent air coolers (REACs). Selecting between single and multiple injection points.
As governments around the world seek to promote the adoption of lower-carbon fuels, credits are available for fuels which satisfy various low-carbon or renewable fuels standards. In the United States, the most common standards discussed include California’s Low Carbon Fuels Standard1 and the US EPA’s Renewable Fuel Standard2. These standards define the acceptable methods (called pathways) for conversion of renewable feeds into consumer fuel products. In order for a producer to be eligible for credits, one of the acceptable pathways must be used. The most common pathway presently being used or considered by most facilities is hydrotreating.
Hydrocracking and other refinery hydroprocessing units have a common goal to convert organic sulfur compounds to hydrogen sulfide (H2S) that can be removed, thereby producing low-sulfur refinery products. Corrosion and equipment degradation risks range from high-temperature hydrogen attacks (HTHA) to ammonium bisulfide and ammonium chloride corrosion in the downstream heat recovery and fluid separation equipment.This paper provides an overview of corrosion management principles that can be applied to reduce operating risks in new and existing units, focusing equipment susceptible to ammonium bisulfide (NH4HS) and ammonium chloride (NH4Cl) corrosion. Best practices for materials selection, as well as designing for corrosion management through adequate provision of corrosion management related instrumentation and sampling points are covered.
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.
Predicting corrosion rates. Areas of vulnerability in the distillation equipment associated with hydroprocessing units. Corrosion rate and materials data from hydroprocessing units compared to previous data.