By Brad Buecker, Contributing Editor
During combustion in a boiler, the primary pollutants nitrogen oxides (NOX), sulfur oxides (SOX) and mercury tend to form predominant species, but with trace to significant concentrations of alternate compounds. Both the major and minor species have a critical impact on the selection of control methods and how the control equipment performs in operation.
Nitrogen oxides are formed by lightning and by coal combustion in utility boilers.
Basic chemistry tells us that very high temperatures will cause elemental nitrogen (N2) and oxygen (O2) to react to produce nitrogen oxides. For example, lightning from a thunderstorm produces such oxides, which in turn enter the soil where they become nitrogen sources for plant fertilization. However, what is often not realized is that of the NOX produced in a coal-fired utility boiler (or other coal furnaces, for that matter) generally only 25 percent comes from nitrogen and oxygen reacting in the combustion air. The other three-quarters come from nitrogen in the fuel, which, as the coal particles decompose and combust, reacts with oxygen.
The type of furnace greatly influences this latter mechanism. Cyclone boilers, where the pebble-sized coal particles take longer to decompose, generally produce NOX in quantities exceeding 1.0 lb/MMBtu, while pulverized coal units may only produce half that amount, or less. So from just a boiler design standpoint, the type of boiler has a large impact on the amount of NOX to be removed.
The other major factor is the speciation of NOX. Typically, 90 percent or so of the initial product is nitrogen moNOXide (NO), with most of the remainder consisting of nitrogen dioxide (NO2). While NO2 is partially soluble in water (and even more so with further oxidation to N2O5), nitrogen monoxide is not. This eliminates wet scrubbing as a method for NO removal and has led to development of other techniques for NOX reduction. One of the earliest was the use of overfire air, where initial combustion with a slightly lean air mixture allows a significant portion of the coal’s nitrogen atoms to self-react to produce N2. Final combustion is achieved with additional air injection above the main flame front. This nitrogen chemistry is by far the most thermodynamically stable reaction, as the triple bond between nitrogen atoms in N2 is very strong. New developments in overfire air technology are further improving NOX reduction capabilities. Suffice it to say that the process alone can often reduce NOX concentrations to well below 0.20 lb/MMBtu.
For additional NOX reductions, selective non-catalytic reduction (SNCR) and selective catalytic reduction (SCR) are the choices, with the latter able to reduce NOX concentrations to 0.10 lb/MMBtu or lower. In both mechanisms, ammonia (NH3) or urea (N2H4CO) is injected into the flue gas stream to react with NOX. The equations below are representative of the process.
4NO + 4NH3 + O2 ➔ 4N2 + 6H2O
2NO2 + 4NH3 +O2 ➔ 3N2 + 6H2O
By the far the most prominent sulfur species that arises from combustion is sulfur dioxide (SO2). It is this compound that is removed in scrubbers. However, small amounts of sulfur trioxide (SO3) also form in the furnace and a small percentage of additional SO3 may form due to sulfur dioxide oxidation in SCR catalyst beds. It is well known that sulfur trioxide, when added in controlled amounts to flue gas, will lower the resistivity of sub-bituminous fly ash such as that generated from Powder River Basin (PRB) coals. But excess SO3 induces a blue plume in stack emissions and, perhaps more importantly, reacts with atmospheric moisture to produce sulfuric acid (H2SO4) aerosols.
Oxidized mercury is very soluble and will come out in wet scrubbing solutions, but elemental mercury is not.
Somewhat surprisingly, although SO3 reacts with atmospheric moisture, the compound passes through wet scrubbers relatively untouched. Regardless, the difficulties with SO3 have led to a number of techniques to prevent its formation or discharge from the stack. These include development of SCR catalysts that minimize SO2 to SO3 oxidation and alkaline chemical injection to neutralize the SO3 prior to removal in a scrubber.
The speciation of mercury as it escapes from the coal during and after combustion is interesting and is dependent upon the coal’s chlorine content. In the absence of chlorine, mercury tends to emerge in its elemental form, Hg0. Chlorine oxidizes mercury to primarily Hg+2. This has major effects on how mercury is removed from the gas. Oxidized mercury is very soluble and will come out in wet scrubbing solutions, but elemental mercury is not. So, for utilities burning Eastern bituminous coals, wet scrubbing is a potential solution for removing most of the mercury from the flue gas. Oxidized mercury will also adsorb onto carbonaceous materials, either unburned carbon in the flue gas or artificially injected activated carbon. A point to note about mercury removal in wet scrubbers is that some may be re-emitted by the scrubbing solution. When sulfur dioxide is transferred from the gas phase to the liquid phase (and as it first reacts with the alkaline reagent, either limestone or lime), the anionic product formed is sulfite (SO3-2). Sulfite is easily oxidized by air in the flue gas or by forced air injection, but it can also be oxidized by mercury, which in turn reverts to its elementaland insolublestate.
For PRB coals, which have much less chlorine than their bituminous counterparts, elemental mercury is usually the majority species. While some elemental mercury will adsorb to carbon-based material, the process is much more effective if the mercury can be oxidized. Thus, much testing is underway to oxidize mercury by injection of chloride or bromide salts either into the flue gas or onto the coal before it is combusted.
A factor that negatively influences mercury adsorption by carbonaceous materials is injection of SO3 for enhanced electrostatic precipitator (ESP) performance. PRB coal combustion produces a high resistivity ash, which a small amount of sulfur trioxide reduces. However, the SO3 also adsorbs to carbon, thus reducing its effectiveness in capturing mercury. This is a difficulty that is still being investigated.
A Different Speciation
A final issue that has been well known for years but remains of concern at utilities that burn several varieties of coal is sodium. Many of the inorganic materials in coal are complex silicon-based structures in which various metals (including sodium, aluminum, potassium and others) are bound together. But sodium can also exist in a salt form, such as chloride. When the coal is combusted this “free” sodium volatilizes, but then begins to condense within an approximate temperature range of 1,300 F to 1,500 F. These temperatures, of course, exist in the boiler backpass. There, the condensing sodium acts as a glue to collect fly ash, which builds up on superheater and reheater tubes.
A problem can arise at utilities where the fuels manager has authority to buy a wide variety of coals on the spot market depending on the lowest price. Even though the fuel may all come from the same geographical region, the coal quality between minesand sometimes even within a seam, particularly with regard to impuritiesmay be quite different. In some cases, rapid and severe fouling of the backpass results, with aggravating (or worse) consequences. In at leastsome of these cases, increased volatile sodium content in the coal undoubtedly is to blame.
Author: Brad Buecker is a contributing editor. He can be reached at [email protected].