Boiler water problems generally fall into two classes: deposit-related and corrosion-related. Because the two often interact, it is very common to find a boiler experiencing both simultaneously. There are many instances where deposits cause corrosion and corrosion causes deposits. It is important to avoid both problems.
Deposit-Related Problems
Boiler Scale
One of the most common deposit problems is boiler scale. This happens when calcium, magnesium and silica, common in most water supplies, react with tube metal found in boilers to form a hard scale on the interior of the boiler tubes, reducing heat transfer and lowering the boiler’s efficiency. If allowed to accumulate, boiler scale can eventually cause the tubes to overheat and rupture. Scaling is one of the leading causes of boiler tube failures. Scale is equivalent to having a thin film of insulation between the furnace
gases and boiler water. It can drop a boiler’s efficiency by as much as 10-12%. Scale forms as the solubilities of the scaleforming salts in water decreases and the temperature and concentrations of the salts increases. When feedwater is elevated to boiler water temperature, the solubility of the scaleforming salts is decreased, and solid scale begins to form on the boiler systems. See Table 2-1. Removing calcium and magnesium or other deposit-forming materials from the feedwater before they enter the boiler system is the best way to prevent scaling. Small amounts of hardness (calcium plus magnesium) can be effectively treated in the boiler and related system components by using boiler water treatment products such as chelates, polymers, and/or phosphates. Scale formation also occurs in economizers, feedwater pumps and related service lines. It also forms in low-pressure boilers where no pre-treatment or poorly maintained treatment chemicals, boiler water treatment products or pretreatment chemicals such as sodium zeolite are used. It is not normally found in boiler systems where demineralization is used or in high pressure, high purity systems.
Large amounts of hardness that cannot be successfully treated using boiler water treatment products must be treated by some other process.
Silica Scale
Silica scale is another kind of scale that affects boilers, much in the same manner as calcium and magnesium scale. Silica is found in most water supplies and it is not as easily removed as calcium and magnesium. Silica can form several types of deposits, such as amorphous silica and magnesium silicate. Amorphous silica appears on boiler surfaces as a smooth, glass-like deposit that is very difficult to remove. A hydrofluoric acid-based cleaner is used to clean such affected surfaces. Magnesium silicate has a rough-textured tan to off-white appearance, and, while easier to remove than amorphous silica, is still difficult to remove. Silica scale is found primarily in lower pressure systems where the pretreatment system uses sodium zeolite for softening and is not designed for silica removal. Silica-based deposits can also be found in high pressure systems where silica leakage through the anion unit(s) has occurred. Deposits form more readily as silica levels increase and hydrate alkalinities decrease. Silica deposits have high insulating properties which limit heat transfer and thus boiler efficiency and may also cause the failure. Silica can also distill from the boiler as silicic acid. Any silica carryover can promote deposits on steam turbine blades. Silica carryover at pressures about 600 psig (40 bar), becomes more serious as pressure increases.
Silica control can be done through pretreatment and proper boiler blowdown, and in low pressure boilers by maintaining at least a 3:1 ratio of hydrate alkalinity to silica in the boiler water.
Effects of Boiler Scale
The chemical structure of the scale, it’s porosity and the design and operational method of the boiler all influence the amount of heat lost. For example, 1/8-inch (3mm) of scale can cause a 2.0-3.0% loss in fire-tube boilers and water tube boilers. A second but more serious effect from scale is the overheating of boiler tube metal, causing eventual tube failure. In modern boilers with high heat-transfer rates, even extremely thin layers of scale will cause a serious elevation in the temperature of tube material. This is dramatically shown in Figure 2-1. A third serious effect of scale formation is localized corrosion. Boilers with high heat transfer rates above 75,000 Btu/sqft/hr Effective Projected Radiant Surface (EPRS) are subject to localized corrosion, a situation where the deposits are actually causing the corrosion. This is a good example of the interaction between deposit-related and corrosion-related boiler water problems. Secondary corrosion is particularly present in systems with iron oxide deposits. The net effect is that the stack gas temperature may increase as the boiler absorbs less heat from the furnace gases, leading to increased pollution and more fuel consumption through inefficient operation.
Iron Deposits
Iron oxide is another compound which will accumulate on boiler surfaces. Iron enters the boiler in the feed-water or it can form in the boiler from corrosion. Iron oxides can be present in both soft and hard-scale deposits. Both types are frequently found at the same location, with the hard deposit existing as a layer next to the boiler tube and the soft layer on top of it. Iron oxides are porous deposits, which will allow boiler water to seep through and “flash” to steam, leaving behind the dissolved solids. These dissolved solids in the boiler water, such as caustic and chelates, can concentrate in these localized areas to thousand of parts per million even though the water contains the normally recommended levels of these compounds. These excessive concentrations can result in rapid and severe
metal dissolution and tube failure. See Figure 2-2.
Minimizing Iron Deposit-Related Problems
The most obvious and effective way to minimize iron-related problems is to keep as much iron out of the boiler as possible. The supply water should be subject to pretreatment techniques such as filtration, clarification, etc. Likewise, if steam condensate is returned to the boiler, action should be taken to minimize the corrosivity of the condensate through proper chemical treatment. Water treatment chemicals such as chelates, polymers and phosphates (residual with and without polymer) can minimize iron deposits. Other areas that should receive attention include hot and cold lime softeners, filters, sodium zeolite softeners, and water-cooled packing glands on feedwater pumps because they can contribute iron to the system. These system components must be operating properly before chemical treatment can be effectively applied.
Corrosion-Related Problems
Oxygen Attack
Dissolved oxygen interacts with boiler component surfaces, forming “pits” on the metal surface. These pits may eventually grow large enough to penetrate the metal, forcing a boiler shutdown. Oxygen present in boiler feedwater becomes very aggressive when heated, causing corrosive damage to preheaters and economizers. Oxygen which enters the boiler itself can also cause further damage to steam drums, mud drums, boiler tubes and headers. Damage can also occur to condensers and condensate piping from oxygen still present in the steam. Controlling the oxygen content in the feedwater is done through deaeration and chemical treatment. Deaerators in steam generating systems use steam to strip oxygen from the feedwater. A properly designed and maintained deaerator can effectively remove almost all the oxygen from the feedwater, typically to < 15ug/lppb (parts per billion) without the need to add an additional oxygen scavenger. The final traces of oxygen can be removed from the feedwater with an oxygen scavenger.
The most common scavenger is sodium sulfite, although other organic materials also work well. Some of these materials also form a protective oxide on large preheater and economizer surfaces. Scavengers cannot effectively substitute for the function of the deaerator; if the oxygen content of the feedwater is greater than 50ug/1 (ppb) then oxygen corrosion can occur even when oxygen scavengers are used. Two of the most common causes of corrosion are the presence of carbon dioxide and oxygen in the condensate. Carbon dioxide will form carbolic acid and reduce the pH of the condensate and cause acid attack while oxygen can directly attack metal. The source of carbon dioxide in condensate is usually carbonate found in boiler water carried over in the steam. Boilers using softened water are more prone to this than those using demineralized water. The presence of oxygen in condensate can be caused by poorly operating deaerators, leakage of air into vacuum condensers, leakage of cooling water and other factors. Treatment of condensate is done with neutralizing amines. Carbon dioxide reacts with water to form carbonic acid, a highly corrosive material that can attack equipment. It cannot be emphasized strongly enough that the deaerator is the one piece of equipment in the water treatment process that should receive careful maintenance attention.
Caustic Attack
Caustic attack on boilers can take two forms: caustic gouging or caustic cracking, also called caustic embrittlement. Caustic gouging causes deep elliptical depressions in metal boiler surfaces, which occur in areas of high heat flux or under heavy porous deposits, such as iron oxide deposits. This is another clear case of an interrelated deposit and corrosion problem. Underneath these deposits, boiler water can concentrate to the point where high caustic concentration accumulates, causing a localized corrosion. This very rapid action can take place and even cause a failure within a few days or even a few hours. Careful control of boiler water chemistry can prevent caustic gouging; if the “free hydroxide alkalinity” is set too high or uncontrolled, then caustic gouging may result. Prevention of porous deposit formation (such as iron oxide) eliminates a place for caustic gouging to occur. Caustic cracking is a form of stress corrosion cracking that happens when a high concentration of caustic is present at a heated and stressed steel surface. These cracks can occur quickly and cannot be readily seen, sometimes causing a violent failure. All parts of the boiler are subject to this type of corrosion, including boiler tubes, headers, steam drums, mud drums, bolts, etc. Avoiding heated, stressed surfaces in boilers is not feasible, so care should be taken to prevent high concentrations of caustic from forming. However, maintaining an excessive “free hydroxide alkalinity” while using caustic to regenerate anion exchange resins and control the pH of the boiler water can cause high caustic concentrations.
Acid Attack
A third corrosion-related problem is caused when the boiler water pH drops below about 8.5. Known as acid attack, the effect exhibits rough pitted surfaces, with some of the pits being quite deep. Again, the presence of iron oxide deposits on boiler surfaces can encourage this kind of corrosion. A low boilerwater pH is usually caused by contamination of the boiler feedwater, from sources such as hydrochloric or sulfuric acid from leaks in demineralizers and condenser leaks of cooling tower water. Contamination can also occur from process leaks of acid or acid-forming materials into the return condensate system. Boiler feedwater pH should be continuously monitored.
