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 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)
Metallic or elemental copper in boiler deposits is dissolved
in the hydrochloric acid solution by the following reaction:
Once cuprous chloride is in solution, it is immediately
redeposited as metallic copper on the steel surface according to the
following reaction:
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:
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:
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:
Conversely, addition of trisodium phosphate adds caustic,
increasing boiler water pH:
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:
Fe ® Fe2+ + 2e¯
Cathode:
Overall:
Fe + ½O2 + H2O ® Fe(OH)2
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:
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:
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:
Similar reactions occur with copper-based metals:
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.
A significant reduction in feedwater oxygen and metal
oxides can occur with proper application of oxygen scavengers (see
Figure 11-8).
Steel and Steel Alloys
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:
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:
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:
and
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:
Benzoquinone reacts further with oxygen to
form polyquinones:
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.
|
Friday, 28 February 2014
PRE BOILER & BOILER CORROSION
Subscribe to:
Posts (Atom)