Water Wall Tubes’ High Temperature Corrosion Root Cause Investigation: A 300 MW Level Boiler Case

Abstract

High temperature corrosion poses a great threat to boiler water wall safe operation. To investigate the corrosion root cause, a 300 MW level boiler water wall high temperature H2S corrosion case was reported. The typical hydrogen sulfide H2S corrosion feature was large amounts of sulfur which could be found in the cut down sample tube corrosion layer, with a thickness of 482 μm. In addition, huge amounts of lead (Pb) could be found in the corrosion layer, which resulted from the lead sulfide (PbS) deposition when the high temperature flue gas condensed at the water wall tubes. Meanwhile, the sulfur in the corrosion layer was closely related to the H2S concentration in the water wall ambience. The related ambience test showed that the H2S could achieve up to 1000 ppm when the boiler was in operation, far larger than the suggested reference value of 100 ppm. Hence, the overlarge H2S concentration was a vital factor for the tube corrosion. To further investigate the reason why the H2S was kept in such high concentration in the boiler long term operation, and the reasons for the over-high sulfur content in the coal and the over-large diameter of the imaginary circle of primary air (DICPA), two factors were obtained. The peak sulfur content reached 2.5% and the suggested sulfur content was below 1%. The DICPA was so large (1580 mm) that the pulverized coal easily scoured the water wall tubes, which would boost the thinning process of the tubes. To relieve the high temperature corrosion, improve the coal qualities, decrease the DICPA, adjust the operation diameter and adopt a coating technology four measures were suggested.