Investigation of Corrosion Conditions in Naphtha Hydro treating (NHT) Units: A Data-Based Analysis

Corrosion in Naphtha Hydro treating (NHT) units poses a significant challenge to the long-term reliability and economic performance of petroleum refineries. These units operate under severe conditions—high temperatures, elevated hydrogen pressures, and the presence of corrosive species such as hydrogen sulfide (H₂S), organic acids, and chlorides—which create an aggressive environment for materials of construction. This study investigates the key operational factors that influence corrosion rates in an NHT unit using a six-month dataset from a hypothetical refinery scenario. Data collected includes reactor temperature and pressure, feed sulfur content, amine inhibitor dosage, and field-measured corrosion rates from corrosion coupons installed in critical locations. Statistical analysis revealed strong positive correlations between corrosion rate and both feed sulfur content (r = ۰.۸۱) and reactor temperature (r = ۰.۷۴), while amine inhibitor dosage showed a moderate inverse relationship (r = -۰.۶۶). A multiple linear regression model was developed to predict corrosion rate as a function of these parameters, with an R² value of ۰.۸۳, indicating high predictive accuracy. Corrosion hotspots were identified at the reactor inlet and in the cold zones of heat exchangers, suggesting the need for targeted monitoring and material upgrades in those areas. The study concludes that optimizing feed quality, maintaining appropriate inhibitor dosing, and deploying real-time corrosion monitoring can significantly mitigate corrosion risk. The findings provide a quantitative foundation for corrosion risk assessment in NHT units and offer actionable insights for improving operational safety and asset longevity in hydro processing environments.

Keywords:

Naphtha Hydro treating (NHT) , corrosion rate , Sulfur Content , amine inhibitor , Hydrogen Sulfide (H₂S)