Acid Dew Point of Flue Gas
Computes the temperature at which sulphuric acid starts to condense on the cold surfaces of a boiler, using the Verhoff and Banchero correlation: the reciprocal of the absolute dew point temperature is a combination of the logarithms of the partial pressures of water vapour and sulphur trioxide in the flue gas, plus the product of those two logarithms. The result is the thermal floor of the design — keeping the stack, the economiser and the air preheater above it is what prevents the acid corrosion that eats steel in a few weeks, and it is why heavy fuel oil boilers throw away up the stack heat they could otherwise recover. SO₃ is what rules here, not humidity, and the reason is the range each one spans: water vapour barely leaves the 5% to 15% band in a flue gas, which accounts for 11 °C end to end, while SO₃ varies by orders of magnitude with the sulphur in the fuel — going from 1 to 10 ppm alone raises the dew point by almost 22 °C. The Verhoff and Banchero correlation was adopted, with partial pressures in millimetres of mercury at atmospheric pressure, as it is the one most used in boiler design, in its original form with the interaction term between the two logarithms; the later Okkes correlation returns 1 to 8 °C lower for the same composition, so treat the value as a reference and not as an exact limit. Enter the water vapour content and the SO₃ content of the flue gas.
Result
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Acid Dew Point: The Thermal Floor of the Stack
Every boiler burning a fuel that carries sulphur lives with the same trade-off. Dropping the flue gas exit temperature buys efficiency, roughly one percentage point for every 20 °C recovered, yet below a certain level the sulphuric acid formed in combustion condenses on cold metal and starts eating the economiser, the air preheater and the stack lining. A tube holed within months, or a Ljungström basket falling apart, almost always traces back to one thing: somebody picked an exit temperature without knowing where the acid dew point sat.
The Verhoff and Banchero correlation links the reciprocal of the absolute dew point to the logarithms of the partial pressures: 1000/T = 2.276 − 0.0294·ln(pH2O) − 0.0858·ln(pSO3) + 0.0062·ln(pH2O·pSO3), with T in kelvin and pressures in millimetres of mercury. The calculator handles the conversion from composition at 1 atm: each 1% of water vapour is worth 7.6 mmHg, each ppm of SO₃ worth 0.00076 mmHg. Natural gas leaves 15 to 18% water and almost no SO₃; heavy fuel oil, 8 to 12% and 5 to 30 ppm. SO₃ rules the outcome: moving from 5 to 20 ppm lifts the dew point 16.8 °C, while water going from 5% to 20% buys only 4.9 °C.
The correlation returns an equilibrium temperature, never a condensation rate or a corrosion rate — just below the dew point the attack is still slow, and the worst wastage usually shows up 20 to 40 °C lower, where condensate is plentiful and still concentrated. What has to stay above the value is the metal wall, always colder than the gas, and the 10 to 20 °C margin belongs to that wall. The most common field slip is typing the SO₂ reading into the SO₃ field: the 500 ppm of SO₂ typical of an oil-fired boiler returns 170.8 °C against the 116.9 °C of the defaults, and the design then throws away recoverable heat over one wrong field.
Frequently asked questions
The defaults give 116.9 °C. What exit temperature should I design for?
I have no SO₃ measurement. How do I estimate the content?
Why does changing the water vapour barely move the answer?
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