Over the last decade, awareness of the need to control damaging emissions has been reflected in the appearance of new legislation and control measures imposed upon industry. These emissions limits were designed to clamp down on pollutants such as SO₂ and NO_X, but when plants started to install control technology such as selective catalytic reduction (SCR) systems and scrubbers to tackle the problem, another worrying issue became apparent.

Where does blue plume come from?

Visible blue plume emissions have been an unforeseen side effect of the increase in wet scrubber additions to power plants (to reduce the emissions of SO₂), coupled with the addition of SCR units (for NO_X removal), which also add SO3 into the flue gas as a result of the SO₂ oxidation in the vanadia-based catalyst bed of the SCR. An increased level of SO₃ in the flue gas results from the combustion of fuel containing these additives, a problem which is even more prevalent in RFO-fired boilers due to the reactions between vanadium oxides, oxygen and SO₂.^[1] The inflated level of SO₃ present combines with H₂O to form H₂SO₄ gas. As the flue gas passes through the scrubber, the acid forms a mist that is not removed by the scrubber and so increases the opacity level of the plume. The mist consists of sub-micron droplets, which reflect light and create the appearance of an unsightly blue plume. In most cases, the fine H₂SO₄ aerosol particles appear opaque when concentrations exceed 10 to 20 ppm.^[1] Plume opacity is a concern for many plants as it publicly projects an image of pollution and disregard for environmental regulations despite the actual level of SO₃ being emitted. Where high-sulfur coals are used, blue plume is more likely to occur. What is more, H₂SO₄and SO₃ emissions are required to be reported under the 1998 EPA regulation and are often classified as the same pollutant.

How can acid dewpoint monitoring help?

Enlarge this picture The screen capture image above was taken from a Lancom 200 ADT sensor from Land Instruments.

At every step of the flue gas treatment process, acid dewpoint measurement can provide clarity. Using acid dewpoint temperature (ADT), along with established relationships between the ADT and the concentration of SO₃ to find the level of SO₃ in the flue gas, gives an indication of the free SO₃ present in the gas stream as H₂SO₄ vapor. This value, taken prior to the wet scrubber, would be a direct indication of how opaque the Blue Plume problem will be and whether any modifications to operating conditions have had the desired effect. Alternative wet chemistry methods for calculating SO₃ levels can yield overstated readings because it will also measure the H₂SO₄ adsorbed by the flyash. It is also a very laborious and time-consuming method.

A support system for SCRs and ESPs

Measuring ADT can assist with the use of other emissions reduction technologies by providing a constant SO₃ monitoring system. It can be effectively utilized alongside SCR units to ensure that an excess amount of SO₃ is not being produced as a result of the catalyst, while simultaneously allowing plants to cut down the high costs involved in using too much of the expensive SO₂-reducing fuel additives.

Flue gas ADT measurement also can be helpful in assuring that electrostatic precipitators are functioning at optimum efficiency. SO₃ is injected into the gas flow to reduce the resistance of the flyash and increase the electrostatic precipitator’s (ESP's) ability to collect the particles effectively, yet if the ash becomes saturated with an excess of damaging SO₃, this excess is then released into the environment in the exit gas and may contribute to the formation of a blue plume. The SO₃ slip in the ESP can be monitored using sulfuric ADT measurements to ensure that the correct amount of SO₃ is being added during this process, an aid that will both optimize ash collection in the ESP and prevent damaging and regulated emissions of SO₃.

Optimum flue gas temperature

Lowering flue gas temperatures along the gas path can have a significant effect on optimizing boiler efficiency and reducing maintenance costs. ADT measurements can provide a guide to an optimum flue gas temperature, a temperature at which no acid will condense but neither is heat energy needlessly lost. Saving unnecessary costs is an area where this measurement comes into its own, but the reduction of expense is not the only reason an optimum temperature should be identified. Higher temperatures working in combination with catalysts cause a higher reaction rate and more SO₃ to be produced, so from an emissions monitoring perspective, controlling lower temperatures is critical.