Hello!! power plant engineers. The failure of
industrial boiler has been a prominent feature in fossil fuel power plants. The
contribution of one or several factors appears to be responsible for failures,
eliminating in the partial or complete shutdown of the plant resulting in heavy
losses in industrial production and disruption to civil amenities. The use of
inferior tube materials, use of high sulphur or/and vanadium containing fuels,
exceeding the design limit of temperature and pressure during operation, poor maintenance
and ageing are some of the factors which have a detrimental effect on the
performance of materials of construction. The failure of boiler tubes appeared
in the form of bending, bulging, Wearing or rupture, decarburization,
carburization causing leakage of the tubes. The failure can be caused by one or
more modes such as overheating, Stress Corrosion Cracking, hydrogen embrittlement, creep, flame
impingement, sulphide attack, weld attack, dew point attack, hot corrosion, etc.
Failure of boiler
water side components during operation may not only be costly from an
operations and personnel perspective, but potential legal costs may well
outstrip the actual physical costs. It is incumbent upon the system designer,
the builder, the operators and the chemical treatment supplier to ensure that
the systems will operate reliably. When this happens, a full assessment of the
failure mechanisms is required to preclude further failures due to the same
factors. Several failure modes are addressed in this article, which hopefully
will give the boiler engineers a better understanding of failure analysis and
failure mitigation.
Tube failures are classified as in-service failures in
boilers. These failures can be grouped under five major causes:
- Stress rupture
- Water side corrosion
- Fatigue
- Erosion
- Fire side corrosion (also called as High temperature
Corrosion)
1. STRESS
RUPTURE
1.1 OVERHEATING:
Tube failures occur due to the ‘Overheating’
and the ‘Plastic Flow’ conditions associated with restricted flow of water in
side of the particular tube facing failure.
Such failures are generally of two
types:
A) Short term Overheating
B) Long term Overheating
Careful
examination of the failed tube section reveals whether the failure is on
account of rapid acceleration in the tube wall temperature or it is on account
of a long term gradual build up/ accumulation of the cause of failure.
A) Short Term Over-Heating:
Short term overheating failures frequently exhibits a
thin- lipped longitudinal rupture, accompanied by noticeable tube bulging,
which creates the large fish-mouth appearance as shown in fig. Virtually all
types of tubes, which carry water or steam and are exposed to high operating
temperatures, are susceptible to these types of failure. The more violent
ruptures occur at tube metal operating temperature well above the ASME oxidation limits of the material and typically
above the eutectoid transformation temperature
7270 C. Peak metal operating temperatures above the can be
estimated by the amount of bainite or martensite mixed with ferrite
in the metal micro-structure at the failure origin. When conditions causing a
rapid metal temperature elevation at local spot occur, a violent rupture
results. The ‘Plastic – Flow’ phenomena of ‘Carbon Steel’ materials at
temperatures between: 700 0C – 800 0C is the cause of such
occurrences.
Interruption/ Restriction, in the
water circulation by some blockage in tube leads to such failures, as the tube
metal gets exposed to direct flames in such cases. Short term failures can be
caused by low water level partial or complete plugging of tubes, rapid start
up, excessive load swings and excessive heat input.
B) Long Term Over-Heating:
‘Long Term’ conditions finally lead to a tube leak;
wrinkled or bulged external surfaces are observed in such cases. Such
appearance is caused by long term ‘Creep
Failure’ causing by repetitive scale formation, which leads to
‘Overheating’, thus ‘Swelling’ the surface, forming a Bulge or Blister,
visually observable minor fissures, etc. on external surfaces. Long term
failures mainly occurs in super heaters, reheaters and water walls as a result
of gradual accumulation of deposits or scale, partially restricted steam or
water flow, excessive heat input from burners or undesired channelising of fireside gases. Horizontal or
inclined tubes subjected to steam blanketing are also prone to long term
failures. Tube metal operating temperatures above 4540 C, or
slightly above the oxidation limits of tube steels, can lead to blistering,
tube bulging or thick lipped creep rupture failures.
It
is recommended that the quality of the ‘Boiler Feed Water’ for boilers
operating at 21 Kg/ cm2 (g) should be as per the
annexure ‘A’ attached herewith. It is also recommended that the ‘Blow down
Time’ & duration should be observed as per the annexure ‘B’ attached
herewith. Blow Down must also be conducted on regular basis (When Boiler is in
Low Steaming Stage) from side wall, rear & front wall headers; so that
sludge accumulation
in these headers may be avoided; which otherwise would rise in furnace tubes
creating conditions for circulation restrictions/ blockage, thus overheating at
local spots.
At times, foreign matters get
left behind during the erection. Such happenings may be avoided by carefully
examining tubes/ headers after fitting the same by a suitable method, such as,
ball test/ by passing water & observing flow at the other end (where
possible). Anyhow, these precautions should be taken before the firing of the
Boiler.
ANNEXURE ‘A’
Sr.
|
Feed Water
|
|
|
1
|
Hardness, Max. (as
Ca CO3) mg/L
|
:
|
10
|
2
|
pH at 25 0C
|
:
|
8.8
to 9.2
|
3
|
Oxygen, Max. mg/L
|
:
|
0.01
|
4
|
Total Iron mg/L
|
:
|
0.100
|
5
|
Copper, Max. mg/L
|
:
|
0.05
|
6
|
Total Dissolved
Solids, Max. mg/L
|
:
|
200
|
Sr.
|
Boiler
Water
|
|
|
1
|
pH
at 25 0C
|
:
|
9.8 to 10.8
|
2
|
Phosphate
Residual (as PO4) mg/L
|
:
|
20 to 40 (If Added)
|
3
|
Total
Dissolved Solids, Max. (T.D.S.) mg/L
|
:
|
3500
|
4
|
Conductivity at 25 0C, Max. Microsiemens/ cm
|
:
|
7000
|
5
|
Total
Alkalinity mg/L
|
:
|
700
|
1.2 DISSIMILAR METAL
WELDS:
Designers of boiler Super heater/Reheater pendents
incorporate the favorable mechanical properties of stainless steel within these
sections of the boiler that combine high heat and high gas flows. However, due
to the high material costs, these sections are ultimately welded to more common
low alloy steels. This resulting dissimilar metal welds (DMW’s) have a tendency
to suffer service related deteriorations (cracking) over time. Cracking of
dissimilar metal welds is typically attributed to three primary factors.
The most significant factor is the difference between the
thermal coefficient of expansion of ferrite, representing the low-alloy steel
tubing, and austenite, representing the stainless steel weld deposit and
tubing. This difference results in a significant temperature-induced stress at
the weld interface.
The second factor contributing to the degradation of
this type of weld is carbon diffusion from the ferrite to the austenite. This
diffusion occurs slightly during welding and more extensively during subsequent
use in high temperature service. It leaves a band of carbon depleted low-alloy
steel immediately adjacent to the weld interface. This band of low-alloy steel
has a much lower resistance to creep than average, and as a result has a
greater propensity for failure by creep.
The third factor affecting the integrity of this
type of weld is a difference in oxidation resistance between low alloy and
stainless steels. This difference results in an oxide wedge forming along the
outside and inside diameters of the component in question at the interface
between these two materials. These wedges will continue to grow as a result of
the difference in the oxidation resistance of the two materials. The oxide
wedges reduce the available cross sectional thickness of the component, and
thus, its load bearing capacity.
2. WATER SIDE
CORROSION
2.1 HYDROGEN DAMAGE
Hydrogen damage occurs in boilers operating usually
above 70 kg/cm2 and under heavy deposits or other areas where
corrosion releases atomic hydrogen. Concentrated sodium hydroxide beneath the
deposits removes the protective magnetite film by the following reactions:
4 NaOH + Fe3O4 → 2 NaFeO2 + Na2FeO2 + 2H2O
Concentrated sodium hydroxide can
then react with freshly exposed base metal to yield sodium ferroate and atomic
hydrogen
Fe + 2NaOH → Na2FeO2 + 2H
Upsets in phosphate treatment
programs or residual acids from chemical cleanings can also cause hydrogen
damage, especially if the acids remain trapped beneath the deposits. These
failures are typically characterised as thick lipped, brittle type ruptures.
Sometimes thick walled “windows” can be completely blown out of the tube wall.
2.2 CAUSTIC GOUGING:
Sodium hydroxide (NaOH) is used
extensively in boiler water treatment to maintain the optimum hydroxyl ion
concentration range to form a protective magnetite film on steel surfaces and to
help from non adherent sludge when hardness enters the boiler water. However,
excessive sodium hydroxide can destroy the protective film and corrode the base
metal as shown in equations. NaOH can concentrate during departure from
nucleate boiling (DNB), film boiling or steam blanketing conditions.Concentration also occurs when normal boiler water
evaporates beneath deposits leaving behind the caustic at the metal surface.
The effect of tube metal gouging beneath deposits.
Caustic gouging can also occur due to
evaporation along a water line without significant accumulation of deposit as
shown in fig in theses case, solubilized sodium ferroite is removed from the
base tube metal, but then hydrolyzes and precipitates elsewhere in the boiler
as magnetite when the concentrated water is diluted by normal boiler water.
2.3 OXYGEN ATTACK:
The presence of dissolved oxygen in boiler water
causes the cathode of any corrosion cell to depolarize, thereby sustaining the
corrosion process. Formation of reddish brown hermatite (Fe2O3)
or “rust” deposits or tubercles accomplished by hemispherical pitting is the
most familiar form of oxygen attack.
Dissolved oxygen is also a significant component
in ammonia corrosion of copper alloys, stress concentration cracking austenitic
stainless steels and Chelan corrosion. Oxygen pitting occurs with the presence
of excessive oxygen in boiler water. It can occur during operation as a result
of in leakage of air at pumps, or failure in operation of pre-boiler water
treatment equipment. This also may occur during extended out-of-service
periods, such as outages and storage, if proper procedures are not followed in
lay-up. Non-drainable locations of boiler circuits, such as super heater loops,
sagging horizontal super heater and repeater tubes, and supply lines, are
especially susceptible. More generalized oxidation of tubes during idle periods
is sometimes referred to as out-of-service corrosion. Wetted surfaces are
subject to oxidation as the water reacts with the iron to form iron oxide. When
corrosive ash is present, moisture on tube surfaces from condensation or water
washing can react with elements in the ash to form acids that lead to a much
more aggressive attack on metal surfaces.
2.4 Stress Corrosion Cracking (SCC):
Stress Corrosion Cracking
(SCC) is a cracking process that requires the simultaneous action of a
corrodent and sustained tensile stress. In relation to boilers this problem was
formerly called caustic embrittlement. Stress corrosion cracking is often
confused with corrosion fatigue and has been observed in both the steam and mud
drums of boilers. If there is seepage between the tube and drum it is possible
for the concentration of NaOH to increase dramatically in this area.
Metallurgically, the drum under load is in tensile loading and with a high
localised caustic concentration, the ideal environment is produced for SCC.
Although the incidence of SCC was found to be low it is known that there were
several major problems in 70bar petrochemical boilers. To prevent SCC in the
best way is to prevent the concentration of corrosion compounds either
mechanically or chemically through appropriate maintenance and water treatment
respectively.
3.
FATIGUE
As
fatigue is such an important feature and the various mechanisms are quite
distinct, it has been split into the three most common types, namely Thermal,
Corrosion and Mechanical Fatigue. From experience it is known that thermal and
corrosion fatigue are common occurrences, particularly with fire-tube boilers.
3.1 THERMAL
FATIGUE
Thermal fatigue is defined
as fracture resulting from the presence of temperature gradients that vary with
time in such a manner as to produce cyclic stresses in the structure. Thermal
fatigue occurs when metal is subjected to a number of rapid heating and cooling
cycles causing large differences in thermal expansion between the structural
members. Depending on the magnitude of the thermal shock involved, failure can
occur with less than ten cycles. The material in question is normally in a condition
of high restraint. Biaxial or triaxial stresses are induced in the affected
surface producing micro cracks on the surface of the material. Once initiated
then crack will continue to propagate with each cycle. In fire tube boilers the
most common cause is internal scale, which prevents sufficient heat transfer
and hence adequate cooling. Over-firing, incorrect burner settings and too many
on/off cycles are amongst common causes resulting in cracking. In water tube
boilers thermal fatigue can occur when there is frequent wetting of a hot
surface such as is caused by an ill placed and leaking valve dripping
internally into a hot steam line. Such failure of a steam line could have very
serious consequences. Thermal fatigue cracks can be similar to corrosion
fatigue and the two are often confused. Thermal fatigue can only be eliminated
by removing the offending thermal cycling. Thermal fatigue damage typically
exhibits numerous and crazing.
This
damage results from cyclic and excessive temperature gradients can
accomplished by mechanical constrains. Excessive temperature can add to
internal strain to initiate or enhance the cracking process. Once initiated,
freshly exposed metal within the cracks can undergo oxidation. Creating a wedge
effect at the crack tip, since the oxide occupies a greater volume than a base
metal .Thermal fatigue can occur in water walls or other areas subjected to DNB
or rapidly fluctuating flows. Low amplitude vibrations of entire super heaters
can lead to thermal fatigue
Corrosion fatigue is
defined as cracking produced under the combined action of fluctuating stress and
a corrosive environment at lower stress levels or frequencies than would be
required in the absence of a corrosive environment. Corrosion fatigue in
boilers is extremely dangerous and is the subject of many treatises. It
requires the interaction of cyclic loading, corrosive environment and a high
residual stress field. Several failures have resulted in considerable loss of
life. As with thermal fatigue it manifests itself in quite different forms in
fire-tube and water-tube boilers. A weld undercut, corrosion pit or other
defect, usually at the toe of the weld, could cause the high stress. The joint
area is usually in high restraint. The first phase of the initiation is the
cracking of the protective oxide layer by the cyclic loading. This permits
fresh attack by the corrosive medium on the bare metal and the formation of
micro cracks. The exposed metal at the root of the crack is oxidized and then
cracks at the next cycle so propagating the failure. Cracks are distinctively
wedge shaped and transgranular particularly in the early stages. Most of the
water tube boilers that were found to exhibit corrosion fatigue were in the
higher Pressure range. The appearance of these defects is typical of corrosion
fatigue but there may also have been a contribution from caustic embrittlement,
also known as stress corrosion cracking (SCC).
3.3 Mechanical
fatigue:
Mechanical fatigue can be
defined as fracture under fluctuating mechanical stresses having a maximum
value less than the ultimate tensile strength of the material.
Mechanical
fatigue is what most people imagine when the word 'fatigue' is mentioned.
Several instances in water tube boilers have been encountered where cracking
has occurred in the tube to manifold weld of drainable super heaters. This was
due to the vibration from inadequately supported elements. This is an
often-neglected part of boiler maintenance. Other failures, again from
vibration, have been due to defective tube-to-tube welds a result of
manufacturing defects.
3.4 Flow assisted corrosion:
Flow assisted corrosion
(FAC) is the localized thinning of a component related to the dissolution of
the protective oxide film and the underlying base metal. The mechanisms
involved in FAC are very complex due to the effect of many variables, which
influences its occurrence. In utility operations FAC is typically seen in
single or two phase water flowing in carbon steel piping. The more common
locations where FAC is detected are:
- ·
Low pressure system blends in evaporators,
risers and economizer
- ·
Feed water cycle (due to more volatile
chemistry and lower pH)
There are essentially seven variables
which affect FAC: with those to
- ·
Temperature
- ·
pH
- ·
Oxygen concentration
- ·
Mass flow rate
- ·
Geometry
- ·
Quality of fluid (single or two phase)
- ·
Materials of construction
4. EROSION
4.1
Fly Ash Erosion:
In most countries, fly ash erosion (FAE) is the most serious or
second cause of availability loss for fossil plants. Historically the approach
has been to arbitrarily position solid shields and baffles or apply a variety
of coatings in ‘areas’ where FAE was occurring. It was recognized in an earlier
study that the use of these palliative repair techniques was the main cause of
repeat failures due to fly ash erosion. They simply redirected the high
velocity flow onto an adjacent tube area.
The rate and extent of erosive processes are affected by particle
velocity, angle of impact, particle composition and shape, and erosive
resistance of the tube surface including composition and temperature
variations. Particle velocity is the most important parameter as the rate of
erosive loss is proportional to the velocity raised to an exponent that ranges
between two and four. Particle velocity is driven by the local flow velocity at
any particular boiler location. The optimum long term solutions are based on
identifying and reducing the highest velocity locations. It is important to
note that local velocities, not bulk velocities across a section of the boiler
are those of interest. As a rule of thumb, maximum design bulk velocities are
on the order of 50 ft/sec or less. It has been observed that local velocities in
excess of 100 ft/sec are required to cause fly ash erosion failures in 10,000
to 50,000 hours. The primary tool to combat FAE is flow modification in
conjunction with a cold air velocity test before and after modification. A
comprehensive EPRI Guideline has been published since the last conference,
which provides a stepby- step procedure. This overall approach is shown in
Figure Where units have been evaluated
by the cold air velocity technique (CAVT) to determine local velocity profiles,
maximum local velocities of two or more times the nominal velocity have typically
found, and these peak velocities usually correspond to the locations of know
tube erosion damage.
The use of CAVT to identify regions of excessive
velocity, followed by the installation of diffusion and distribution screens,
should provide utilities with the most permanent solution to the problem. However,
the technique has not been adopted by sufficient utilities, which explains why
FAE is still the second most important failure mechanism.
5. FIRE SIDE CORROSION
Corrosion on the fire side of boiler tubes is caused by
moisture condensing from the atmosphere during periods of shutdown, or from
flue gas condensation during operation. This type of corrosion is especially
troublesome in boiler installations near bodies of water, or where the
atmosphere is otherwise humid. Fire side corrosion is accelerated by the use of
high sulfur fuels. Sulfur gases may condense on tube surfaces during operation;
depending upon the kind of fuel, its sulfur content and the methods of firing.
Accumulations of soot on the tubes should be periodically removed. Soot
attracts moisture; and air, moisture and steel together result in attack of the
tubes. Cleaning may be daily, weekly or monthly, depending on the fuel used and
the method of firing.
Some hot water boilers
-- for example, those in greenhouses -- may operate at water temperatures of
140oF to 150oF. Under such conditions, the condensing gases from coal or oil
firing form sulfurous acid which attacks the tubes and results in a more
uniform type of corrosion. If the percentage of sulfur in the fuel is high,
this situation is worse. Even in the absence of sulfur compounds, corrosion may
occur during shutdown periods because of high humidity in the air. When
shutting down the boiler under such conditions, the fire side tube surfaces
should be brushed and flushed to remove the winter's accumulation of soot and
other products of combustion. This should be followed by blowing air through to
dry out these surfaces. A light coat of oil should be applied for further
protection. Also, in extremely humid locations,
the stack should be disconnected, or at least the damper should be closed, and
a tray of unslaked lime placed in the ash pit to keep the fire side dry. This
lime must be renewed whenever it becomes mushy, so the drying effectiveness
will not be lost. Many samples of scale removed from fire side surfaces have
been found to be acid when mixed with water. The presence of this acid may
cause the tube metal to eat away to eventual failure. Often, boiler rooms are
in damp cellars, some with water on the floor constantly. During the summer
months, in particular, humid air tends to build up in basements, causing
clothes and leather to mildew from the dampness. Similarly, humid air may have
ready access to the fire side of boiler tubes in basement installations if the
tubes are not properly protected.
Even with gas firing of hot
water boilers, serious fire side attack can take place. Some installations
employ outdoor-indoor thermometers to control system water temperatures as
outdoor temperatures fluctuate. Low water temperatures can result in condensation
of moisture from the flue gas and lead to serious corrosion of the tubes. High
water temperatures reduce the probability of attack.
Some horizontal tube boilers suffer from a mechanism called
"necking" and "grooving."
This shows up as a circumferential groove around the
outside of the tube where it enters the tube sheet. It usually occurs at the
beginning of the first pass, which is the hottest end of the tubes. In all
cases, there is some corrosion in evidence in other areas, but it concentrates
at the ends because of strains from two sources. When tubes are rolled in, some
unavoidable expansion takes place back of the tube sheet. Secondly, when a
boiler heats up, the metal in the tubes expands and lengthens. Consequently,
strains are set up at the ends, which are fixed in the tube sheets. Sometimes
these expansions are so severe that the tubes loosen in the sheets. Scale
forming at the tube ends tends to flake off, exposing fresh steel to further
attack. This problem can be reduced by more gradual firing, more gradual
changes in temperature, and maintaining the boiler water free of oxygen and
under proper control.
From above discussion we come to conclusion that for minimizing such type of
failures use some safety precautions as stated in operation & maintanance
manual. Don't forgot to share experiences and views.
