Corrosion is one of the main causes of reduced reliability in steam generating systems. It is estimated that problems due to boiler system corrosion cost industry billions of dollars per year.
Many corrosion problems occur in the hottest areas of the boiler-the water wall, screen, and superheater tubes. Other common problem areas include deaerators, feedwater heaters, and economizers.
Methods of corrosion control vary depending upon the type of corrosion encountered. The most common causes of corrosion are dissolved gases (primarily oxygen and carbon dioxide), under-deposit attack, low pH, and attack of areas weakened by mechanical stress, leading to stress and fatigue cracking.
These conditions may be controlled through the following procedures:
Most industrial boiler and feedwater systems are constructed of carbon steel. Many have copper alloy and/or stainless steel feedwater heaters and condensers. Some have stainless steel superheater elements.
Proper treatment of boiler feedwater effectively protects against corrosion of feedwater heaters, economizers, and deaerators. The ASME Consensus for Industrial Boilers (see Chapter 13) specifies maximum levels of contaminants for corrosion and deposition control in boiler systems.
The consensus is that feedwater oxygen, iron, and copper content should be very low (e.g., less than 7 ppb oxygen, 20 ppb iron, and 15 ppb copper for a 900 psig boiler) and that pH should be maintained between 8.5 and 9.5 for system corrosion protection.
In order to minimize boiler system corrosion, an understanding of the operational requirements for all critical system components is necessary.
Feedwater Heaters
Boiler feedwater heaters are designed to improve boiler efficiency by extracting heat from streams such as boiler water blowdown and turbine extraction or excess exhaust steam. Feedwater heaters are generally classified as low-pressure (ahead of the deaerator), high-pressure (after the deaerator), or deaerating heaters.
Regardless of feedwater heater design, the major problems are similar for all types. The primary problems are corrosion, due to oxygen and improper pH, and erosion from the tube side or the shell side. Due to the temperature increase across the heater, incoming metal oxides are deposited in the heater and then released during changes in steam load and chemical balances. Stress cracking of welded components can also be a problem. Erosion is common in the shell side, due to high-velocity steam impingement on tubes and baffles.
Corrosion can be minimized through proper design (to minimize erosion), periodic cleaning, control of oxygen, proper pH control, and the use of high-quality feedwater (to promote passivation of metal surfaces).
Deaerators
Deaerators are used to heat feedwater and reduce oxygen and other dissolved gases to acceptable levels. Corrosion fatigue at or near welds is a major problem in deaerators. Most corrosion fatigue cracking has been reported to be the result of mechanical factors, such as manufacturing procedures, poor welds, and lack of stress-relieved welds. Operational problems such as water/steam hammer can also be a factor.
Effective corrosion control requires the following practices:
Other forms of corrosive attack in deaerators include stress corrosion cracking of the stainless steel tray chamber, inlet spray valve spring cracking, corrosion of vent condensers due to oxygen pitting, and erosion of the impingement baffles near the steam inlet connection.
Economizers
Economizer corrosion control involves procedures similar to those employed for protecting feedwater heaters.
Economizers help to improve boiler efficiency by extracting heat from flue gases discharged from the fireside of a boiler. Economizers can be classified as nonsteaming or steaming. In a steaming economizer, 5-20% of the incoming feedwater becomes steam. Steaming economizers are particularly sensitive to deposition from feedwater contaminants and resultant under-deposit corrosion. Erosion at tube bends is also a problem in steaming economizers.
Oxygen pitting, caused by the presence of oxygen and temperature increase, is a major problem in economizers; therefore, it is necessary to maintain essentially oxygen-free water in these units. The inlet is subject to severe pitting, because it is often the first area after the deaerator to be exposed to increased heat. Whenever possible, tubes in this area should be inspected closely for evidence of corrosion.
Economizer heat transfer surfaces are subject to corrosion product buildup and deposition of incoming metal oxides. These deposits can slough off during operational load and chemical changes.
Corrosion can also occur on the gas side of the economizer due to contaminants in the flue gas, forming low-pH compounds. Generally, economizers are arranged for downward flow of gas and upward flow of water. Tubes that form the heating surface may be smooth or provided with extended surfaces.
Superheaters
Superheater corrosion problems are caused by a number of mechanical and chemical conditions. One major problem is the oxidation of superheater metal due to high gas temperatures, usually occurring during transition periods, such as start-up and shutdown. Deposits due to carryover can contribute to the problem. Resulting failures usually occur in the bottom loops-the hottest areas of the superheater tubes.
Oxygen pitting, particularly in the pendant loop area, is another major corrosion problem in superheaters. It is caused when water is exposed to oxygen during downtime. Close temperature control helps to minimize this problem. In addition, a nitrogen blanket and chemical oxygen scavenger can be used to maintain oxygen-free conditions during downtime.
Low-Pressure Steam and Hot Water Heating Systems
Hot water boilers heat and circulate water at approximately 200°F. Steam heating boilers are used to generate steam at low pressures, such as 15 psig. Generally, these two basic heating systems are treated as closed systems, because makeup requirements are usually very low.
High-temperature hot water boilers operate at pressures of up to 500 psig, although the usual range is 35-350 psig. System pressure must be maintained above the saturation pressure of the heated water to maintain a liquid state. The most common way to do this is to pressurize the system with nitrogen. Normally, the makeup is of good quality (e.g., deionized or sodium zeolite softened water). Chemical treatment consists of sodium sulfite (to scavenge the oxygen), pH adjustment, and a synthetic polymer dispersant to control possible iron deposition.
The major problem in low-pressure heating systems is corrosion caused by dissolved oxygen and low pH. These systems are usually treated with an inhibitor (such as molybdate or nitrite) or with an oxygen scavenger (such as sodium sulfite), along with a synthetic polymer for deposit control. Sufficient treatment must be fed to water added to make up for system losses, which usually occur as a result of circulating pump leakage. Generally, 200-400 ppm P-alkalinity is maintained in the water for effective control of pH. Inhibitor requirements vary depending on the system.
Electric boilers are also used for heating. There are two basic types of electric boilers: resistance and electrode. Resistance boilers generate heat by means of a coiled heating element. High-quality makeup water is necessary, and sodium sulfite is usually added to remove all traces of dissolved oxygen. Synthetic polymers have been used for deposit control. Due to the high heat transfer rate at the resistance coil, a treatment that precipitates hardness should not be used.
Electrode boilers operate at high or low voltage and may employ submerged or water-jet electrodes. High-purity makeup water is required. Depending on the type of system, sodium sulfite is normally used for oxygen control and pH adjustment. Some systems are designed with copper alloys, so chemical addition must be of the correct type, and pH control must be in the range suitable for copper protection.
Corrosion control techniques vary according to the type of corrosion encountered. Major methods of corrosion control include maintenance of the proper pH, control of oxygen, control of deposits, and reduction of stresses through design and operational practices.
Galvanic Corrosion
Galvanic corrosion occurs when a metal or alloy is electrically coupled to a different metal or alloy.
The most common type of galvanic corrosion in a boiler system is caused by the contact of dissimilar metals, such as iron and copper. These differential cells can also be formed when deposits are present. Galvanic corrosion can occur at welds due to stresses in heat-affected zones or the use of different alloys in the welds. Anything that results in a difference in electrical potential at discrete surface locations can cause a galvanic reaction. Causes include:
A general illustration of a corrosion cell for iron in the presence of oxygen is shown in Figure 11-1. Pitting of boiler tube banks has been encountered due to metallic copper deposits. Such deposits may form during acid cleaning procedures if the procedures do not completely compensate for the amount of copper oxides in the deposits or if a copper removal step is not included. Dissolved copper may be plated out on freshly cleaned surfaces, establishing anodic corrosion areas and forming pits, which are very similar to oxygen pits in form and appearance. This process is illustrated by the following reactions involving hydrochloric acid as the cleaning solvent.
Magnetite is dissolved and yields an acid solution containing both ferrous (Fe²+) and ferric (Fe³+) chlorides (ferric chlorides are very corrosive to steel and copper)
| Fe3O4 | + | 8HCl | ® | FeCl2 | + | 2FeCl3 | + | 4H2O |
| magnetite | hydrochloric acid | ferrous chloride | ferric chloride | water |
Metallic or elemental copper in boiler deposits is dissolved in the hydrochloric acid solution by the following reaction:
| FeCl3 | + | Cu | ® | CuCl | + | FeCl2 |
| ferric chloride | copper | cuprous chloride | ferrous chloride |
Once cuprous chloride is in solution, it is immediately redeposited as metallic copper on the steel surface according to the following reaction:
| 2CuCl | + | Fe | ® | FeCl2 | + | 2Cu0 |
| cuprous chloride | iron | ferrous chloride | copper oxide |
Thus, hydrochloric acid cleaning can cause galvanic corrosion unless the copper is prevented from plating on the steel surface. A complexing agent is added to prevent the copper from redepositing. The following chemical reaction results:
| FeCl3 | + | Cu | + | Complexing Agent | ® | FeCl2 | + | CuCl |
| ferric chloride | copper | ferrous chloride | cuprous chloride complex |
This can take place as a separate step or during acid cleaning. Both iron and the copper are removed from the boiler, and the boiler surfaces can then be passivated.
In most cases, the copper is localized in certain tube banks and causes random pitting. When deposits contain large quantities of copper oxide or metallic copper, special precautions are required to prevent the plating out of copper during cleaning operations.
Caustic Corrosion
Concentration of caustic (NaOH) can occur either as a result of steam blanketing (which allows salts to concentrate on boiler metal surfaces) or by localized boiling beneath porous deposits on tube surfaces.
Caustic corrosion (gouging) occurs when caustic is concentrated and dissolves the protective magnetite (Fe3O4 ) layer. Iron, in contact with the boiler water, forms magnetite and the protective layer is continuously restored. However, as long as a high caustic concentration exists, the magnetite is constantly dissolved, causing a loss of base metal and eventual failure (see Figure 11-2).
Steam blanketing is a condition that occurs when a steam layer forms between the boiler water and the tube wall. Under this condition, insufficient water reaches the tube surface for efficient heat transfer. The water that does reach the overheated boiler wall is rapidly vaporized, leaving behind a concentrated caustic solution, which is corrosive.
Porous metal oxide deposits also permit the development of high boiler water concentrations. Water flows into the deposit and heat applied to the tube causes the water to evaporate, leaving a very concentrated solution. Again, corrosion may occur.
Caustic attack creates irregular patterns, often referred to as gouges. Deposition may or may not be found in the affected area.
Boiler feedwater systems using demineralized or evaporated makeup or pure condensate may be protected from caustic attack through coordinated phosphate/pH control. Phosphate buffers the boiler water, reducing the chance of large pH changes due to the development of high caustic concentrations. Excess caustic combines with disodium phosphate and forms trisodium phosphate. Sufficient disodium phosphate must be available to combine with all of the free caustic in order to form trisodium phosphate.
Disodium phosphate neutralizes caustic by the following reaction:
| Na2HPO4 | + | NaOH | ® | Na3PO4 | + | H2O |
| disodium phosphate | sodium hydroxide | trisodium phosphate | water |
This results in the prevention of caustic buildup beneath deposits or within a crevice where leakage is occurring. Caustic corrosion (and caustic embrittlement, discussed later) does not occur, because high caustic concentrations do not develop (see Figure 11-3).
Figure 11-4 shows the phosphate/pH relationship recommended to control boiler corrosion. Different forms of phosphate consume or add caustic as the phosphate shifts to the proper form. For example, addition of monosodium phosphate consumes caustic as it reacts with caustic to form disodium phosphate in the boiler water according to the following reaction:
| NaH2PO4 | + | NaOH | ® | Na2HPO4 | + | H2O |
| monosodium phosphate | sodium hydroxide | disodium phosphate | water |
Conversely, addition of trisodium phosphate adds caustic, increasing boiler water pH:
| Na3PO4 | + | H2O | ® | Na2HPO4 | + | NaOH |
| trisodium phosphate | water | disodium phosphate | sodium hydroxide |
Control is achieved through feed of the proper type of phosphate to either raise or lower the pH while maintaining the proper phosphate level. Increasing blowdown lowers both phosphate and pH. Therefore, various combinations and feed rates of phosphate, blowdown adjustment, and caustic addition are used to maintain proper phosphate/pH levels.
Elevated temperatures at the boiler tube wall or deposits can result in some precipitation of phosphate. This effect, termed "phosphate hideout," usually occurs when loads increase. When the load is reduced, phosphate reappears.
Clean boiler water surfaces reduce potential concentration sites for caustic. Deposit control treatment programs, such as those based on chelants and synthetic polymers, can help provide clean surfaces.
Where steam blanketing is occurring, corrosion can take place even without the presence of caustic, due to the steam/magnetite reaction and the dissolution of magnetite. In such cases, operational changes or design modifications may be necessary to eliminate the cause of the problem.
Acidic Corrosion
Low makeup or feedwater pH can cause serious acid attack on metal surfaces in the preboiler and boiler system. Even if the original makeup or feedwater pH is not low, feedwater can become acidic from contamination of the system. Common causes include the following:
Acid corrosion can also be caused by chemical cleaning operations. Overheating of the cleaning solution can cause breakdown of the inhibitor used, excessive exposure of metal to cleaning agent, and high cleaning agent concentration. Failure to neutralize acid solvents completely before start-up has also caused problems.
In a boiler and feedwater system, acidic attack can take the form of general thinning, or it can be localized at areas of high stress such as drum baffles, "U" bolts, acorn nuts, and tube ends.
Hydrogen Embrittlement
Hydrogen embrittlement is rarely encountered in industrial plants. The problem usually occurs only in units operating at or above 1,500 psi.
Hydrogen embrittlement of mild steel boiler tubing occurs in high-pressure boilers when atomic hydrogen forms at the boiler tube surface as a result of corrosion. Hydrogen permeates the tube metal, where it can react with iron carbides to form methane gas, or with other hydrogen atoms to form hydrogen gas. These gases evolve predominantly along grain boundaries of the metal. The resulting increase in pressure leads to metal failure.
The initial surface corrosion that produces hydrogen usually occurs beneath a hard, dense scale. Acidic contamination or localized low-pH excursions are normally required to generate atomic hydrogen. In high-purity systems, raw water in-leakage (e.g., condenser leakage) lowers boiler water pH when magnesium hydroxide precipitates, resulting in corrosion, formation of atomic hydrogen, and initiation of hydrogen attack.
Coordinated phosphate/pH control can be used to minimize the decrease in boiler water pH that results from condenser leakage. Maintenance of clean surfaces and the use of proper procedures for acid cleaning also reduce the potential for hydrogen attack.
Oxygen Attack
Without proper mechanical and chemical deaeration, oxygen in the feedwater will enter the boiler. Much is flashed off with the steam; the remainder can attack boiler metal. The point of attack varies with boiler design and feedwater distribution. Pitting is frequently visible in the feedwater distribution holes, at the steam drum waterline, and in downcomer tubes.
Oxygen is highly corrosive when present in hot water. Even small concentrations can cause serious problems. Because pits can penetrate deep into the metal, oxygen corrosion can result in rapid failure of feedwater lines, economizers, boiler tubes, and condensate lines. Additionally, iron oxide generated by the corrosion can produce iron deposits in the boiler.
Oxygen corrosion may be highly localized or may cover an extensive area. It is identified by well defined pits or a very pockmarked surface. The pits vary in shape, but are characterized by sharp edges at the surface. Active oxygen pits are distinguished by a reddish brown oxide cap (tubercle). Removal of this cap exposes black iron oxide within the pit (see Figure 11-5).
Oxygen attack is an electrochemical process that can be described by the following reactions: Anode:
| ½O2 + H2O + 2e ¯ ® 2OH ¯ |
The influence of temperature is particularly important in feedwater heaters and economizers. A temperature rise provides enough additional energy to accelerate reactions at the metal surfaces, resulting in rapid and severe corrosion.
At 60°F and atmospheric pressure, the solubility of oxygen in water is approximately 8 ppm. Efficient mechanical deaeration reduces dissolved oxygen to 7 ppb or less. For complete protection from oxygen corrosion, a chemical scavenger is required following mechanical deaeration.
Major sources of oxygen in an operating system include poor deaerator operation, in-leakage of air on the suction side of pumps, the breathing action of receiving tanks, and leakage of undeaerated water used for pump seals.
The acceptable dissolved oxygen level for any system depends on many factors, such as feedwater temperature, pH, flow rate, dissolved solids content, and the metallurgy and physical condition of the system. Based on experience in thousands of systems, 3-10 ppb of feedwater oxygen is not significantly damaging to economizers. This is reflected in industry guidelines.
the ASME consensus is less than 7 ppb (ASME recommends chemical scavenging to "essentially zero" ppb)
TAPPI engineering guidelines are less than 7 ppb EPRI fossil plant guidelines are less than 5 ppb dissolved oxygen
Many corrosion problems are the result of mechanical and operational problems. The following practices help to minimize these corrosion problems:
Where boiler tubes fail as a result of caustic embrittlement, circumferential cracking can be seen. In other components, cracks follow the lines of greatest stress. A microscopic examination of a properly prepared section of embrittled metal shows a characteristic pattern, with cracking progressing along defined paths or grain boundaries in the crystal structure of the metal (see Figure 11-6). The cracks do not penetrate the crystals themselves, but travel between them; therefore, the term "intercrystalline cracking" is used.
Good engineering practice dictates that the boiler water be evaluated for embrittling characteristics. An embrittlement detector (described in Chapter 14) is used for this purpose.
If a boiler water possesses embrittling characteristics, steps must be taken to prevent attack of the boiler metal. Sodium nitrate is a standard treatment for inhibiting embrittlement in lower-pressure boiler systems. The inhibition of embrittlement requires a definite ratio of nitrate to the caustic alkalinity present in the boiler water. In higher-pressure boiler systems, where demineralized makeup water is used, embrittling characteristics in boiler water can be prevented by the use of coordinated phosphate/pH treatment control, described previously under "Caustic Corrosion." This method prevents high concentrations of free sodium hydroxide from forming in the boiler, eliminating embrittling tendencies.
Caustic Embrittlement
Caustic embrittlement (caustic stress corrosion cracking), or intercrystalline cracking, has long been recognized as a serious form of boiler metal failure. Because chemical attack of the metal is normally undetectable, failure occurs suddenly-often with catastrophic results.
For caustic embrittlement to occur, three conditions must exist:
Where boiler tubes fail as a result of caustic embrittlement, circumferential cracking can be seen. In other components, cracks follow the lines of greatest stress. A microscopic examination of a properly prepared section of embrittled metal shows a characteristic pattern, with cracking progressing along defined paths or grain boundaries in the crystal structure of the metal (see Figure 11-6). The cracks do not penetrate the crystals themselves, but travel between them; therefore, the term "intercrystalline cracking" is used.
Good engineering practice dictates that the boiler water be evaluated for embrittling characteristics. An embrittlement detector (described in Chapter 14) is used for this purpose.
If a boiler water possesses embrittling characteristics, steps must be taken to prevent attack of the boiler metal. Sodium nitrate is a standard treatment for inhibiting embrittlement in lower-pressure boiler systems. The inhibition of embrittlement requires a definite ratio of nitrate to the caustic alkalinity present in the boiler water. In higher-pressure boiler systems, where demineralized makeup water is used, embrittling characteristics in boiler water can be prevented by the use of coordinated phosphate/pH treatment control, described previously under "Caustic Corrosion." This method prevents high concentrations of free sodium hydroxide from forming in the boiler, eliminating embrittling tendencies.
Fatigue Cracking
Fatigue cracking (due to repeated cyclic stress) can lead to metal failure. The metal failure occurs at the point of the highest concentration of cyclic stress. Examples of this type of failure include cracks in boiler components at support brackets or rolled in tubes when a boiler undergoes thermal fatigue due to repeated start-ups and shutdowns.
Thermal fatigue occurs in horizontal tube runs as a result of steam blanketing and in water wall tubes due to frequent, prolonged lower header blowdown.
Corrosion fatigue failure results from cyclic stressing of a metal in a corrosive environment. This condition causes more rapid failure than that caused by either cyclic stressing or corrosion alone. In boilers, corrosion fatigue cracking can result from continued breakdown of the protective magnetite film due to cyclic stress.
Corrosion fatigue cracking occurs in deaerators near the welds and heat-affected zones. Proper operation, close monitoring, and detailed out-of-service inspections (in accordance with published recommendations) minimize problems in deaerators.
Steam Side Burning
Steam side burning is a chemical reaction between steam and the tube metal. It is caused by excessive heat input or poor circulation, resulting in insufficient flow to cool the tubes. Under such conditions, an insulating superheated steam film develops. Once the tube metal temperature has reached 750°F in boiler tubes or 950-1000°F in superheater tubes (assuming low alloy steel construction), the rate of oxidation increases dramatically; this oxidation occurs repeatedly and consumes the base metal. The problem is most frequently encountered in superheaters and in horizontal generating tubes heated from the top.
Erosion
Erosion usually occurs due to excessive velocities. Where two-phase flow (steam and water) exists, failures due to erosion are caused by the impact of the fluid against a surface. Equipment vulnerable to erosion includes turbine blades, low-pressure steam piping, and heat exchangers that are subjected to wet steam. Feedwater and condensate piping subjected to high-velocity water flow are also susceptible to this type of attack. Damage normally occurs where flow changes direction.
Iron and copper surfaces are subject to corrosion, resulting in the formation of metal oxides. This condition can be controlled through careful selection of metals and maintenance of proper operating conditions.
Iron Oxide Formation
Iron oxides present in operating boilers can be classified into two major types. The first and most important is the 0.0002-0.0007 in. (0.2-0.7 mil) thick magnetite formed by the reaction of iron and water in an oxygen-free environment. This magnetite forms a protective barrier against further corrosion.
Magnetite forms on boiler system metal surfaces from the following overall reaction:
| 3Fe | + | 4H2O | ® | Fe3O4 | + | 4H2 |
| iron | water | magnetite | hydrogen |
The magnetite, which provides a protective barrier against further corrosion, consists of two layers. The inner layer is relatively thick, compact, and continuous. The outer layer is thinner, porous, and loose in structure. Both of these layers continue to grow due to water diffusion (through the porous outer layer) and lattice diffusion (through the inner layer). As long as the magnetite layers are left undisturbed, their growth rate rapidly diminishes.
The second type of iron oxide in a boiler is the corrosion products, which may enter the boiler system with the feedwater. These are frequently termed "migratory" oxides, because they are not usually generated in the boiler. The oxides form an outer layer over the metal surface. This layer is very porous and easily penetrated by water and ionic species.
Iron can enter the boiler as soluble ferrous ions and insoluble ferrous and ferric hydroxides or oxides. Oxygen-free, alkaline boiler water converts iron to magnetite, Fe3O4. Migratory magnetite deposits on the protective layer and is normally gray to black in color.
Copper Oxide Formation
A truly passive oxide film does not form on copper or its alloys. In water, the predominant copper corrosion product is cuprous oxide (Cu2O). A typical corrosion reaction follows:
| 8Cu | + | O2 | + | 2H2O | ® | 4Cu2O | + | 2H2 |
| copper | oxygen | water | cuprous oxide | hydrogen |
As shown in Figure 11-7, the oxide that develops on the copper surfaces is comprised of two layers. The inner layer is very thin, adherent, nonporous, and comprised mostly of cupric oxide (CuO). The outer layer is thick, adherent, porous and comprised mainly of cuprous oxide (Cu2O). The outer layer is formed by breakup of the inner layer. At a certain thickness of the outer layer, an equilibrium exists at which the oxide continually forms and is released into the water.
Maintenance of the proper pH, elimination of oxygen, and application of metal-conditioning agents can minimize the amount of copper alloy corrosion.
Metal Passivation
The establishment of protective metal oxide lay-ers through the use of reducing agents (such as hydrazine, hydroquinone, and other oxygen scavengers) is known as metal passivation or metal conditioning. Although "metal passivation" refers to the direct reaction of the compound with the metal oxide and "metal conditioning" more broadly refers to the promotion of a protective surface, the two terms are frequently used interchangeably.
The reaction of hydrazine and hydroquinone, which leads to the passivation of iron-based metals, proceeds according to the following reactions:
| N2H4 | + | 6Fe2O3 | ® | 4Fe3O4 | + | 2H2O | + | N2 |
| hydrazine | hematite | magnetite | water | nitrogen |
| C6H4(OH)2 | + | 3Fe2O3 | ® | 2Fe3O4 | + | C6H4O2 | + | H2O |
| hydroquinone | hematite | magnetite | benzoquinone | water |
Similar reactions occur with copper-based metals:
| N2H4 | + | 4CuO | ® | 2Cu2O | + | 2H2O | + | N2 |
| hydrazine | cupric oxide | cuprous oxide | water | nitrogen |
| C6H6O2 | + | 2CuO | ® | Cu2O | + | C6H4O2 | + | H2O |
| hydroquinone | cupric oxide | cuprous oxide | benzoquinone | water |
Magnetite and cuprous oxide form protective films on the metal surface. Because these oxides are formed under reducing conditions, removal of the dissolved oxygen from boiler feedwater and condensate promotes their formation. The effective application of oxygen scavengers indirectly leads to passivated metal surfaces and less metal oxide transport to the boiler whether or not the scavenger reacts directly with the metal surface.
Protection of steel in a boiler system depends on temperature, pH, and oxygen content. Generally, higher temperatures, high or low pH levels, and higher oxygen concentrations increase steel corrosion rates.
Mechanical and operational factors, such as velocities, metal stresses, and severity of service can strongly influence corrosion rates. Systems vary in corrosion tendencies and should be evaluated individually.
Copper and Copper Alloys Many factors influence the corrosion rate of copper alloys:
The impact of each of these factors varies depending on characteristics of each system. Temperature dependence results from faster reaction times and greater solubility of copper oxides at elevated temperatures. Maximum temperatures specified for various alloys range from 200 to 300°F.
Methods of minimizing copper and copper alloy corrosion include:
pH Control
Maintenance of proper pH throughout the boiler feedwater, boiler, and condensate systems is essential for corrosion control. Most low-pressure boiler system operators monitor boiler water alkalinity because it correlates very closely with pH, while most feedwater, condensate, and high-pressure boiler water requires direct monitoring of pH. Control of pH is important for the following reasons:
The pH or alkalinity level maintained in a boiler system depends on many factors, such as sys-tem pressure, system metals, feedwater quality, and type of chemical treatment applied.
The corrosion rate of carbon steel at feedwater temperatures approaches a minimum value in the pH range of 9.2-9.6 (see Figure 11-9). It is important to monitor the feedwater system for corrosion by means of iron and copper testing. For systems with sodium zeolite or hot lime softened makeup, pH adjustment may not be necessary. In systems that use deionized water makeup, small amounts of caustic soda or neutralizing amines, such as morpholine and cyclohexylamine, can be used.
In the boiler, either high or low pH increases the corrosion rates of mild steel(see Figure 11-10). The pH or alkalinity that is maintained depends on the pressure, makeup water characteristics, chemical treatment, and other factors specific to the system.
The best pH for protection of copper alloys is somewhat lower than the optimum level for carbon steel. For systems that contain both metals, the condensate and feedwater pH is often maintained between 8.8 and 9.2 for corrosion protection of both metals. The optimum pH varies from system to system and depends on many factors, including the alloy used (see Figure 11-11).
To elevate pH, neutralizing amines should be used instead of ammonia, which (especially in the presence of oxygen) accelerates copper alloy corrosion rates. Also, amines form protective films on copper oxide surfaces that inhibit corrosion.
Oxygen Control
Chemical Oxygen Scavengers. The oxygen scavengers most commonly used in boiler systems are sodium sulfite, sodium bisulfite, hydrazine, catalyzed versions of the sulfites and hydrazine, and organic oxygen scavengers, such as hydroquinone and ascorbate.
It is of critical importance to select and properly use the best chemical oxygen scavenger for a given system. Major factors that determine the best oxygen scavenger for a particular application include reaction speed, residence time in the system, operating temperature and pressure, and feedwater pH. Interferences with the scavenger/oxygen reaction, decomposition products, and reactions with metals in the system are also important factors. Other contributing factors include the use of feedwater for attemperation, the presence of economizers in the system, and the end use of the steam. Chemical oxygen scavengers should be fed to allow ample time for the scavenger/oxygen reaction to occur. The deaerator storage system and the feedwater storage tank are commonly used feed points.
In boilers operating below 1,000 psig, sodium sulfite and a concentrated liquid solution of catalyzed sodium bisulfite are the most commonly used materials for chemical deaeration due to low cost and ease of handling and testing. The oxygen scavenging property of sodium sulfite is illustrated by the following reaction:
| 2Na2SO3 | + | O2 | ® | 2Na2SO4 |
| sodium sulfite | oxygen | sodium sulfate |
Theoretically, 7.88 ppm of chemically pure sodium sulfite is required to remove 1.0 ppm of dissolved oxygen. However, due to the use of technical grades of sodium sulfite, combined with handling and blowdown losses during normal plant operation, approximately 10 lb of sodium sulfite per pound of oxygen is usually required. The concentration of excess sulfite maintained in the feedwater or boiler water also affects the sulfite requirement.
Sodium sulfite must be fed continuously for maximum oxygen removal. Usually, the most suitable point of application is the drop leg between the deaerator and the storage compartment. Where hot process softeners are followed by hot zeolite units, an additional feed is recommended at the filter effluent of the hot process units (prior to the zeolite softeners) to protect the ion exchange resin and softener shells.
As with any oxygen scavenging reaction, many factors affect the speed of the sulfite-oxygen reaction. These factors include temperature, pH, initial concentration of oxygen scavenger, initial concentration of dissolved oxygen, and catalytic or inhibiting effects. The most important factor is temperature. As temperature increases, reaction time decreases; in general, every 18°F increase in temperature doubles reaction speed. At temperatures of 212°F and above, the reaction is rapid. Overfeed of sodium sulfite also increases reaction rate. The reaction proceeds most rapidly at pH values in the range of 8.5-10.0.
Certain materials catalyze the oxygen-sulfite reaction. The most effective catalysts are the heavy metal cations with valences of two or more. Iron, copper, cobalt, nickel, and manganese are among the more effective catalysts.
Figure 11-12 compares the removal of oxygen using commercial sodium sulfite and a catalyzed sodium sulfite. After 25 seconds of contact, catalyzed sodium sulfite removed the oxygen completely. Uncatalyzed sodium sulfite removed less than 50% of the oxygen in this same time period. In a boiler feedwater system, this could result in severe corrosive attack.
The following operational conditions necessitate the use of catalyzed sodium sulfite:
High feedwater sulfite residuals and pH values above 8.5 should be maintained in the feedwater to help protect the economizer from oxygen attack.
Some natural waters contain materials that can inhibit the oxygen/sulfite reaction. For example, trace organic materials in a surface supply used for makeup water can reduce speed of scavenger/oxygen reaction time. The same problem can occur where contaminated condensate is used as a portion of the boiler feedwater. The organic materials complex metals (natural or formulated catalysts) and prevent them from increasing the rate of reaction.
Sodium sulfite must be fed where it will not contaminate feedwater to be used for attemporation or desuperheating. This prevents the addition of solids to the steam.
At operating pressures of 1,000 psig and higher, hydrazine or organic oxygen scavengers are normally used in place of sulfite. In these applications, the increased dissolved solids contributed by sodium sulfate (the product of the sodium sulfite-oxygen reaction) can become a significant problem. Also, sulfite decomposes in high-pressure boilers to form sulfur dioxide (SO2) and hydrogen sulfide (H2S). Both of these gases can cause corrosion in the return condensate system and have been reported to contribute to stress corrosion cracking in turbines. Hydrazine has been used for years as an oxygen scavenger in high-pressure systems and other systems in which sulfite materials cannot be used. Hydrazine is a reducing agent that removes dissolved oxygen by the following reaction:
| N2H4 | + | O2 | ® | 2H2O | + | N2 |
| hydrazine | oxygen | water | nitrogen |
Because the products of this reaction are water and nitrogen, the reaction adds no solids to the boiler water. The decomposition products of hydrazine are ammonia and nitrogen. Decomposition begins at approximately 400°F and is rapid at 600°F. The alkaline ammonia does not attack steel. However, if enough ammonia and oxygen are present together, copper alloy corrosion increases. Close control of the hydrazine feed rate can limit the concentration of ammonia in the steam and minimize the danger of attack on copper-bearing alloys. The ammonia also neutralizes carbon dioxide and reduces the return line corrosion caused by carbon dioxide.
Hydrazine is a toxic material and must be handled with extreme care. Because the material is a suspected carcinogen, federally published guidelines must be followed for handling and reporting. Because pure hydrazine has a low flash point, a 35% solution with a flash point of greater than 200°F is usually used. Theoretically, 1.0 ppm of hydrazine is required to react with 1.0 ppm of dissolved oxygen. However, in practice 1.5-2.0 parts of hydrazine are required per part of oxygen.
The factors that influence the reaction time of sodium sulfite also apply to other oxygen scavengers. Figure 11-13 shows rate of reaction as a function of temperature and hydrazine concentration. The reaction is also dependent upon pH (the optimum pH range is 9.0-10.0).
In addition to its reaction with oxygen, hydrazine can also aid in the formation of magnetite and cuprous oxide (a more protective form of copper oxide), as shown in the following reactions:
| N2H4 | + | 6Fe2O3 | ® | 4Fe3O4 | + | N2 | + | 2H2O |
| hydrazine | hematite | magnetite | nitrogen | water |
| N2H4 | + | 4CuO | ® | 2Cu2O | + | N2 | + | 2H2O |
| hydrazine | cupric oxide | cuprous oxide | nitrogen | water |
Because hydrazine and organic scavengers add no solids to the steam, feedwater containing these materials is generally satisfactory for use as attemperating or desuperheating water.
The major limiting factors of hydrazine use are its slow reaction time (particularly at low temperatures), ammonia formation, effects on copper-bearing alloys, and handling problems.
Organic Oxygen Scavengers. Several organic compounds are used to remove dissolved oxygen from boiler feedwater and condensate. Among the most commonly used compounds are hydroquinone and ascorbate. These materials are less toxic than hydrazine and can be handled more safely. As with other oxygen scavengers, temperature, pH, initial dissolved oxygen concentration, catalytic effects, and scavenger concentration affect the rate of reaction with dissolved oxygen. When fed to the feedwater in excess of oxygen demand or when fed directly to the condensate, some organic oxygen scavengers carry forward to protect steam and condensate systems.
Hydroquinone is unique in its ability to react quickly with dissolved oxygen, even at ambient temperature. As a result of this property, in ad-dition to its effectiveness in operating systems, hydroquinone is particularly effective for use in boiler storage and during system start-ups and shutdowns. It is also used widely in condensate systems.
Hydroquinone reacts with dissolved oxygen as shown in the following reactions:
| C6H4(OH)2 | + | O2 | ® | C6H4O2 | + | H2O |
| hydroquinone | oxygen | benzoquinone | water |
Benzoquinone reacts further with oxygen to form polyquinones:
| C6H4O2 | + | O2 | ® | polyquinones |
| benzoquinone | oxygen |
These reactions are not reversible under the alkaline conditions found in boiler feedwater and condensate systems. In fact, further oxidation and thermal degradation (in higher-pressure systems) leads to the final product of carbon dioxide. Intermediate products are low molecular weight organic compounds, such as acetates.
Oxygen Level Monitoring. Oxygen monitoring provides the most effective means of controlling oxygen scavenger feed rates. Usually, a slight excess of scavenger is fed. Feedwater and boiler water residuals provide an indication of excess scavenger feed and verify chemical treatment feed rates. It is also necessary to test for iron and copper oxides in order to assess the effectiveness of the treatment program. Proper precautions must be taken in sampling for metal oxides to ensure representative samples.
Due to volatility and decomposition, measurement of boiler residuals is not a reliable means of control. The amount of chemical fed should be recorded and compared with oxygen levels in the feedwater to provide a check on the control of dissolved oxygen in the system. With sodium sulfite, a drop in the chemical residual in the boiler water or a need to increase chemical feed may indicate a problem. Measures must be taken to determine the cause so that the problem can be corrected.
Sulfite residual limits are a function of boiler operating pressure. For most low- and medium-pressure systems, sulfite residuals should be in excess of 20 ppm. Hydrazine control is usually based on a feedwater excess of 0.05-0.1 ppm. For different organic scavengers, residuals and tests vary.
Effective corrosion control monitoring is essential to ensure boiler reliability. A well planned monitoring program should include the following:
Monitoring Techniques
Appropriate monitoring techniques vary with different systems. Testing should be performed at least once per shift. Testing frequency may have to be increased for some systems where control is difficult, or during periods of more variable operating conditions. All monitoring data, whether spot sampling or continuous, should be recorded.
Boiler feedwater hardness, iron, copper, oxygen, and pH should be measured. Both iron and copper, as well as oxygen, can be measured on a daily basis. It is recommended that, when possible, a continuous oxygen meter be installed in the feedwater system to detect oxygen intrusions. Iron and copper, in particular, should be measured with care due to possible problems of sample contamination.
If a continuous oxygen meter is not installed, periodic testing with spot sampling ampoules should be used to evaluate deaerator performance and potential for oxygen contamination from pump seal water and other sources.
For the boiler water, the following tests should be performed:
Sampling
It is critical to obtain representative samples in order to monitor conditions in the boiler feedwater system properly. Sample lines, continuously flowing at the proper velocity and volume, are required. Generally, a velocity of 5-6 ft/sec and a flow of 800-1000 mL/min are satisfactory. The use of long sample lines should be avoided. Iron and copper sampling should be approached with extreme care because of the difficulty of obtaining representative samples and properly interpreting results. Trends, rather than individual samples, should be used to assess results. Copper sampling requires special precautions, such as acidification of the stream. Composite sampling, rather than spot sampling, can also be a valuable tool to determine average concentrations in a system.
Oxygen sampling should be performed as close to the line as possible, because long residence time in sampling lines can allow the oxygen scavenger to further react and reduce oxygen readings. Also, if in-leakage occurs, falsely high data may be obtained. Sampling for oxygen should also be done at both the effluent of the deaerator and effluent of the boiler feedwater pump, to verify that oxygen ingress is not occurring.
Results and Action Required
All inspections of equipment should be thorough and well documented.
Conditions noted must be compared to data from previous inspections. Analytical results and procedures must be evaluated to ensure that quality standards are maintained and that steps are taken for continual improvement. Cause-and-effect diagrams (see Figure 11-14) can be used either to verify that all potential causes of problems are reviewed, or to troubleshoot a particular corrosion-related problem.
Oxygen corrosion in boiler feedwater systems can occur during start-up and shutdown and while the boiler system is on standby or in storage, if proper procedures are not followed. Systems must be stored properly to prevent corrosion damage, which can occur in a matter of hours in the absence of proper lay-up procedures. Both the water/steam side and the fireside are subject to downtime corrosion and must be protected.
Off-line boiler corrosion is usually caused by oxygen in-leakage. Low pH causes further corrosion. Low pH can result when oxygen reacts with iron to form hydroferric acid. This corrosion product, an acidic form of iron, forms at water-air interfaces.
Corrosion also occurs in boiler feedwater and condensate systems. Corrosion products generated both in the preboiler section and the boiler may deposit on critical heat transfer surfaces of the boiler during operation and increase the potential for localized corrosion or overheating.
The degree and speed of surface corrosion depend on the condition of the metal. If a boiler contains a light surface coating of boiler sludge, surfaces are less likely to be attacked because they are not fully exposed to oxygen-laden water. Experience has indicated that with the improved cleanliness of internal boiler surfaces, more attention must be given to protection from oxygen attack during storage. Boilers that are idle even for short time periods (e.g., weekends) are susceptible to attack.
Boilers that use undeaerated water during start-up and during their removal from service can be severely damaged. The damage takes the form of oxygen pitting scattered at random over the metal surfaces. Damage due to these practices may not be noticed for many years after installation of the unit.
The choice of storage methods depends on the length of downtime expected and the boiler complexity. If the boiler is to be out of service for a month or more, dry storage may be preferable. Wet storage is usually suitable for shorter down-time periods or if the unit may be required to go on-line quickly. Large boilers with complex circuits are difficult to dry, so they should be stored by one of the wet storage methods.
Dry Storage
For dry storage, the boiler is drained, cleaned, and dried completely. All horizontal and non-drainable boiler and superheater tubes must be blown dry with compressed gas. Particular care should be taken to purge water from long horizontal tubes, especially if they have bowed slightly.
Heat is applied to optimize drying. After drying, the unit is closed to minimize air circulation. Heaters should be installed as needed to maintain the temperature of all surfaces above the dew point.
Immediately after surfaces are dried, one of the three following desiccants is spread on water-tight wood or corrosion-resistant trays:
The trays are placed in each drum of a water tube boiler, or on the top flues of a fire-tube unit. All manholes, handholes, vents, and connections are blanked and tightly closed. The boiler should be opened every month for inspection of the desiccant. If necessary, the desiccant should be renewed.
Wet Storage
For wet storage, the unit is inspected, cleaned if necessary, and filled to the normal water level with deaerated feedwater.
Sodium sulfite, hydrazine, hydroquinone, or another scavenger is added to control dissolved oxygen, according to the following requirements:
No matter which treatment is used, pH or alkalinity adjustment to minimum levels is required.
After chemical addition, with vents open, heat is applied to boil the water for approximately 1 hr. The boiler must be checked for proper concentration of chemicals, and adjustments made as soon as possible.
If the boiler is equipped with a nondrainable superheater, the superheater is filled with high-quality condensate or demineralized water and treated with a volatile oxygen scavenger and pH control agent. The normal method of filling nondrainable superheaters is by back-filling and discharging into the boiler. After the superheater is filled, the boiler should be filled completely with deaerated feedwater. Morpholine, cyclohexylamine, or similar amines are used to maintain the proper pH.
If the superheater is drainable or if the boiler does not have a superheater, the boiler is allowed to cool slightly after firing. Then, before a vacuum is created, the unit is filled completely with deaerated feedwater.
A surge tank (such as a 55-gal drum) containing a solution of treatment chemicals or a nitrogen tank at 5 psig pressure is connected to the steam drum vent to compensate for volumetric changes due to temperature variations.
The drain between the nonreturn valve and main steam stop valve is left open wide. All other drains and vents are closed tightly.
The boiler water should be tested weekly with treatment added as necessary to maintain treatment levels. When chemicals are added, they should be mixed by one of the following methods:
If the steaming method is used, the boiler should subsequently be filled completely, in keeping with the above recommendations.
Although no other treatment is required, standard levels of the chemical treatment used when the boiler is operating can be present.
Boilers can be protected with nitrogen or another inert gas. A slightly positive nitrogen (or other inert gas) pressure should be maintained after the boiler has been filled to the operating level with deaerated feedwater.
Storage of Feedwater Heaters and Deaerators
The tube side of a feedwater heater is treated in the same way the boiler is treated during storage. The shell side can be steam blanketed or flooded with treated condensate.
All steel systems can use the same chemical concentrations recommended for wet storage. Copper alloy systems can be treated with half the amount of oxygen scavenger, with pH controlled to 9.5.
Deaerators are usually steam or nitrogen blanketed; however, they can be flooded with a lay-up solution as recommended for wet lay-up of boilers. If the wet method is used, the deaerator should be pressurized with 5 psig of nitrogen to prevent oxygen ingress.
Cascading Blowdown
For effective yet simple boiler storage, clean, warm, continuous blowdown can be distributed into a convenient bottom connection on an idle boiler. Excess water is allowed to overflow to an appropriate disposal site through open vents. This method decreases the potential for oxygen ingress and ensures that properly treated water enters the boiler. This method should not be used for boilers equipped with nondrainable superheaters.
Cold Weather Storage
In cold weather, precautions must be taken to prevent freezing. Auxiliary heat, light firing of the boiler, cascade lay-up, or dry storage may be employed to prevent freezing problems. Sometimes, a 50/50 water and ethylene glycol mixture is used for freeze protection. However, this method requires that the boiler be drained, flushed, and filled with fresh feedwater prior to start-up.
Disposal of Lay-up Solutions
The disposal of lay-up chemicals must be in compliance with applicable federal, state, and local regulations.
Fireside Storage
When boilers are removed from the line for extended periods of time, fireside areas must also be protected against corrosion.
Fireside deposits, particularly in the convection, economizer, and air heater sections, are hygroscopic in nature. When metal surface temperatures drop below the dew point, condensation occurs, and if acidic hygroscopic deposits are present, corrosion can result.
The fireside areas (particularly the convection, economizer, and air heater sections) should be cleaned prior to storage.
High-pressure alkaline water is an effective means of cleaning the fireside areas. Before alkaline water is used for this purpose, a rinse should be made with fresh water of neutral pH to prevent the formation of hydroxide gels in the deposits (these deposits can be very difficult to remove).
Following chemical cleaning with a water solution, the fireside should be dried by warm air or a small fire. If the boiler is to be completely closed up, silica gel or lime can be used to absorb any water of condensation. As an alternative, metal surfaces can be sprayed or wiped with a light oil.
If the fireside is to be left open, the metal sur-faces must be maintained above the dew point by circulation of warm air.
Learn more about Veolia's boiler water treatment and how it can help avoid boiler system corrosion.