Understanding low-temperature corrosion in recovery boilers: risk of sulphuric acid dew point corrosion?

A1 Originalartikel i en vetenskaplig tidskrift (referentgranskad)


Interna författare/redaktörer


Publikationens författare: Emil Vainio, Tor Laurén, Nikolai DeMartini, Anders Brink, Mikko Hupa
Publiceringsår: 2014
Tidskrift: J-For: the Journal of Science and Technology for Forest Products and Processes
Volym: 4
Nummer: 6
Artikelns första sida, sidnummer: 14
Artikelns sista sida, sidnummer: 22
eISSN: 1927-632X


Abstrakt

Nowadays, interest in recovering more energy from flue gases is high. One of the fears when lowering the flue gas temperature is the sulphuric acid dew point. Low-temperature corrosion seen in recovery boilers is often assumed to be caused by sulphuric acid condensation, and therefore the flue gas temperature is kept safely above any acid dew point. However, very little information is available about the presence of H2SO4(g) or about the risk of low-temperature corrosion due to sulphuric acid condensation in recovery boilers. In this work, the risk of sulphuric acid-induced corrosion due to H2SO4(g) condensation was studied both in a modern Kraft recovery boiler and in a sulphite recovery boiler. Measurements were conducted after the electrostatic precipitator (ESP) in the Kraft recovery boiler and between the ESP and the scrubber in the sulphite recovery boiler. In addition, the risk of sulphuric acid-induced corrosion during heavy fuel oil combustion in a Kraft recovery boiler was studied. The following measurements were performed: measurements of H2SO4(g) with a novel salt tube method, dew point measurements with a commercial instrument, and measurements of corrosion rates at various material temperatures with an air-cooled short-term corrosion probe. These measurements in the Kraft recovery boiler showed that no SO2 or H2SO4(g) was present in the flue gases and that therefore no sulphuric acid dew point existed. In the sulphite boiler, the SO2 concentration was higher than 1000 ppmv, but the H2SO4(g) concentration was below 1 ppmv. This implies that any SO3/H2SO4 formed was captured in the fly ash. No acid dew point was detected in the flue gases. However, a water dew point elevation of 15°C was measured in the sulphite recovery boiler. This can be explained by the hygroscopic nature of the fly ash components, such as sodium sulphate and especially bisulphate. Short-term corrosion probe tests showed no corrosion due to an acid dew point. Significant corrosion was observed when the ring temperature was set below the water dew point in the Kraft recovery boiler. Corrosion was observed in the sulphite recovery boiler just above the pure water dew point, which could have been due to the presence of hygroscopic salts. This work has shown that the boilers under study did not suffer from lowtemperature corrosion due to condensation of sulphuric acid. Nowadays, interest in recovering more energy from flue gases is high. One of the fears when lowering the flue gas temperature is the sulphuric acid dew point. Low-temperature corrosion seen in recovery boilers is often assumed to be caused by sulphuric acid condensation, and therefore the flue gas temperature is kept safely above any acid dew point. However, very little information is available about the presence of H2SO4(g) or about the risk of low-temperature corrosion due to sulphuric acid condensation in recovery boilers. In this work, the risk of sulphuric acid-induced corrosion due to H2SO4(g) condensation was studied both in a modern Kraft recovery boiler and in a sulphite recovery boiler. Measurements were conducted after the electrostatic precipitator (ESP) in the Kraft recovery boiler and between the ESP and the scrubber in the sulphite recovery boiler. In addition, the risk of sulphuric acid-induced corrosion during heavy fuel oil combustion in a Kraft recovery boiler was studied. The following measurements were performed: measurements of H2SO4(g) with a novel salt tube method, dew point measurements with a commercial instrument, and measurements of corrosion rates at various material temperatures with an air-cooled short-term corrosion probe. These measurements in the Kraft recovery boiler showed that no SO2 or H2SO4(g) was present in the flue gases and that therefore no sulphuric acid dew point existed. In the sulphite boiler, the SO2 concentration was higher than 1000 ppmv, but the H2SO4(g) concentration was below 1 ppmv. This implies that any SO3/H2SO4 formed was captured in the fly ash. No acid dew point was detected in the flue gases. However, a water dew point elevation of 15°C was measured in the sulphite recovery boiler. This can be explained by the hygroscopic nature of the fly ash components, such as sodium sulphate and especially bisulphate. Short-term corrosion probe tests showed no corrosion due to an acid dew point. Significant corrosion was observed when the ring temperature was set below the water dew point in the Kraft recovery boiler. Corrosion was observed in the sulphite recovery boiler just above the pure water dew point, which could have been due to the presence of hygroscopic salts. This work has shown that the boilers under study did not suffer from lowtemperature corrosion due to condensation of sulphuric acid.

Senast uppdaterad 2019-13-11 vid 04:31