Office Hrs: Today 8:00am to 4:30pm EST
2681 Coral Ridge Rd. Brooks, KY 40109
Monday - Friday08:00 - 20:00
Saturday09:00 - 18:00
Sunday09:00 - 18:00
High Temperature Oil Ash Corrosion
High temperature oil ash corrosion is caused by the formation of low melting point compounds produced during combustion of fuel oil. Low-melting species form at superheater and reheater operating temperatures. Vanadium, sodium, and sulfur (V2O5-Na2O or V2O5-Na2SO4) are the primary culprits that form troublesome surface liquids that cause corrosion. The melting points of these compounds range from 1000oF and 1550oF depending on composition. The oil ash corrosion mechanism is similar to coal ash corrosion: a low melting point liquid forms and it dissolves the protective iron oxides.
High temperature oil ash corrosion produces wall thinning that eventually results in stress rupture of the steel. The greatest metal loss occurs under the molten ash deposit. Flat spots may be produced at the interface between the deposit and the exposed tube. Fractures are longitudinal and the outside surface may have an alligator hide texture.
Oil ash corrosion is caused by the formation of complex sodium-vanadium compounds in a molten ash deposit on the tube surface. The amount of vanadium in the oil varies according to the source of the oil, while most sodium chloride in residual oils comes from contamination by seawater during ocean transport. The greatest wastage occurs when the sodium oxide to vanadium oxide ratio is about 1:5 and the tube metal temperature is high enough to allow molten ash to form. The root cause of oil ash corrosion can be verified by determining the corrosiveness of the oil ash and by monitoring the tube metal temperature under the ash deposit. Field testing with controlled temperature corrosion probes or ash deposition probes has been performed to determine the corrosiveness of the ash deposit.
Ultrasonic (UT) wall thickness measurements and tube metal temperature measurements are taken to establish the corrosion rate extent and to calculate the effect of the corrosion on the service life of the tube steel. This is taken at the area of greatest metal loss.
Corrective actions depend on the severity of the corrosion problem. An estimate of tube remaining service life should be performed on a non-failed tube sample. Several short term actions involve using thicker tubes, shielding the tubes, or coating with a thermal sprayed corrosion-resistant material. Long term actions include replacing the tubes with a higher grade alloy or surface treated tube steel. Maintaining oxidizing conditions inside the furnace potentially eliminates the formation of porous iron sulfide scales instead of protective iron oxides. Inaccurate burner angles may result in localized reducing conditions. Therefore, burners should be adjusted per design to have the correct stoichiometric mixture. Weld overlays of more corrosion resistant alloys like Alloys 625 and 622 have been proven to be a long term solution for fireside corrosion. The superior corrosion resistance of these superalloys in both oxidizing and reducing environments containing mixtures of acids has been attributed to the formation of Cr-rich oxides (Cr2O3).