Boiler tube failures due to Improper commissioning

CASE STUDIES OF BOILER FAILURES DUE TO IMPROPER COMMISSIONING
PROCEDURE
K.K.Parthiban- Venus Energy Audit System / Sri Devi engg consultancy & agency / Sri Devi Boiler
Equipment & spares
Introduction
There have been many unpublished cases of improper commissioning of power boilers which have
led to tube failures. The boilers may have been commissioned without proper stage inspection, precommissioning
& commissioning protocols. We share our experience with case studies on waterwall
failures, roof tube failures, SH tube failures and main steam header failures. The failures could have
been avoided by proper field inspection.
CASE STUDY 1-WATERWALL TUBE BURST IN A CFBC BOILER
The first CFBC boiler in this plant was commissioned in October 2009. The power plant had been in
operation for a total period of 326 hrs. Within this period, there had been 34 stoppages. Out of these
stoppages, three were due to waterwall tube bursts experienced in the LH & RH side wall panels
towards rear. The tube failures locations were at 200 - 400 mm below the refractory lining near
furnace outlet. The burst tubes showed the sudden overheating. The tubes have burst due to sudden
loss of circulation / departure from nucleate boiling or steam blanketing. The failed tubes did not
exhibit long term overheating. See photo 1 to 4.
The boiler was under shut down at the time of visit. As requested, the steam drum was opened and
offered for inspection. The boiler drum exhibited presence of high corrosion products in boiler water.
See the photos 5 & 6.
Boiler water & condensate chemistry problem
The steam drum was seen with low pH / high PH corrosion and there was no magnetite layer
formation of internal surface. There was no distinct water to steam interface seen in the drum. The
steam purifying driers also showed the reddish appearance, confirming foaming due to presence of
corrosion products in boiler water.
It was learnt that during the entire operating period, the best silica level in condensate was only 0.07
ppm. The condensate was always seen with high silica levels. See table below:
Table 1: conductivity & silica levels in return condensate
Period of operation 18/9-21/9 25/9 -28/9 1/10 - 5/10 15/10 – 19/10 2/ 11 to 4 /11
Conductivity µs/cm 25.5 to 8.3 8.8 to 10.5 4.2 to 6.1 5.2 to 6.9 9.7 to 11.4
Silica ppm 0.31 to 0.42 1.67 to 0.3 0.13 to 0.41 0.07 to 0.25 0.25 to 0.35
There had been very high blow down rate done to limit the silica in boiler water. Under this
circumstance, the phosphate dosing had been raised. But simultaneously, high blow down was
maintained. This should have led to pH variations in boiler water. It was confirmed that the blow
down water was reddish. However the boiler water phosphate and pH were high, confirming that the
boiler water was alkaline. This could have been due to presence of foaming or due to drum internal
arrangement. Free OH alkalinity (2P-M alkalinity) was seen in the boiler water in the earlier period

of operations. Though the boiler water chemistry seemed OK, the boiler internal surface did not say
so. A wipe off shows the drum surface was red. There was no grey surface at water space or steam
space. The following were the boiler water analysis data.
Table 2: pH & silica values in boiler water
The pH values
The PO 4 values
9.15,9.9,9.9,9.5,9.56,9.64,9.65 22.4,8.15,10.4,4.6,10.4,3.8,5.5,7.9,9.8,4.5
Drum internal arrangement
There is a possibility of chemical stirring effect by the feed water distributor pipe. See photograph 11
& 12. It is the normal practice to locate the chemical pipe in such way that the feed water carries the
phosphate chemical to the downcomers. In steam drum internal layout, the blow down pipe should
be arranged in such a way that the high TDS return water is taken out without mixing any fresh water
/ chemical. In the drum internal arrangement, the holes in feed distributor were located at 30 deg
upward to horizontal. The two distribution pipes could stir up the chemical and cause a sampling
error. It was advised to rotate the feed distributor pipe, so that the water ejects downwards. The
chemical pipe could be connected to feed distributor pipe close to inlet point in the drum. This will
help in proper mixing of chemical with feed water. Or else the chemical dosing pipe should be laid
below the feed distributor pipe.
Proper pre-commissioning care for start up of the unit
Air cooled condenser has large heating surface as compared to boiler. Air cooled condensers are not
chemically cleaned during pre-commissioning. It generates corrosion product during every start up.
The first steam that enters the ACC is generally of low pH and it leads to some corrosion. The
corrosion product due to oxygen exposures also would come in to the condensate. The contaminated
condensate chokes up the strainers at CEP inlet. Also the BFP strainers will be choked as the mesh
opening is lesser than that of the CEP. It was reported that the strainers got choked with reddish fine
particles. This can increase the conductivity and silica depending on the condition of internal surface
of the ACC tubes. This had forced the high blow down rate from the boiler. The rate of blow down
had been as high as 7.7 to 9.52 %. It was confirmed that colloidal silica was not there in the feed
water. Hence the source of contamination could be from ACC. When the phosphate requirement was
calculated, there was a mismatch. For high pressure steam cycles with ACC, condensate filtration
and polishing system is a must.
Frequent tripping & ACC being offline
There had been as high as 34 trippings of the power plant. During these trippings, the ACC went
offline. Every time the ACC was exposed to air, it would corrode. When the condensate was taken
without treatment it had contaminated the boiler water with suspended & dissolved impurities. This
made the boiler water dirty causing choking the bottom drains. The high blow down requirements
and boiler drain valve choking confirmed this. The hot box of the boiler led to choking of the drain /
bottom supply pipes as the corroded iron particles begin to separate out of water.
Physical arrangement of downcomers & riser
The distributing pipes are tapped off from the main downcomers and connected to all four walls. See

figure 7 & 8. The failures had been in the last ten tubes at the ESP side on both left & right side
panels. The distributing pipes to this section of the boiler are taken from the bottom most point of the
main downcomer. The front & rear waterwall panels (226 tubes) are fed by 18 distributing pipes. The
left & right side waterwall panels (170 tubes) are fed by 14 distributing pipes. The rear waterwall
tubes have lot of bends as compared to the side waterwall panels. When there is undersized
downcomers, the failures will be experienced at all water wall tubes and the worst affected will be
the rear waterwall panel tubes. Since the tubes of left & right side waterwall panels have failed, the
problem was simply related to starvation only. Looking into symmetry of the boiler about the centre,
it was clear that water flowing was disrupted when there was stoppage and restart. On stoppage of
boiler / load reduction / on filling, the corrosion products tend to accumulate at bottom most pipes
only. This can retard the flow rate to the extreme tubes of the LHS & RHS panel tubes.
TSP consumption
The TSP consumption should have been 18 to 23 kg instead of 5 kg as per log sheet. Usually the
chemical consumption will be more from the estimated value due to low purity levels.
Accumulation of dirt in low heat flux tubes
As such the corner tubes can have less circulation as there will be less heat pick up. Dirt build up /
concentration is usually more in such tubes. This can cause overheating failures as the cooling may
be retarded.
Failure to do low pressure blow down during commissioning
During commissioning of the new boiler, low pressure blow downs are done with fire off. This helps
in attaining good water chemistry in a short time. Moreover when there is a mechanism of dirt
generation in the boiler or even after the tube replacement job, the boiler calls for a low pressure
blow down. It was learnt that this was not done.
Storage post hydrotest stage

It was learnt that the water used for hydrotest was left inside the boiler for a long duration. This was
not proper. During long outages, the boiler needs preservation against corrosion. The water should be
completely removed and hot air should be admitted in the boiler. Simple alternate method is to place
a tray full of silica gel / lime inside the drum. This will have to be followed at TG exhaust &
condensate storage tank also so that the ACC will be dry. Failure to preserve the boiler & ACC will
accumulate dirt inside the boiler and lead to plugging of evaporative circuits. Hot air circulation
arrangement is a fool proof method for offline corrosion protection of ACC.
Hand hole pipe & drain at main downcomer
The boiler was found to have no hand hole pipe system in downcomer. Hand hole pipes help to clean
the system, after the alkali boil out in a better manner. In this boiler, the main downcomers act as
dirt trap. In some boilers the bottom ring headers collect the dirt. It is safer this way. The drain pipe
of 50 nb was directly fitted to end plate. Further the drain valve is of 25 nb and is of globe type. See
photo 10. It is difficult to de-choke this valve even by tapping. The valves got choked often. This
confirmed the presence of sufficient amount of corrosion products. The drain arrangement needs to
be modified. See the better arrangement in photo 9.
Globe or gate type valves for drains
It was advised to provide 40 nb / 50 nb drain valves of gate type. Gate type valves help in easy
removal of blockages. When the boiler is restarted after the repair work or annual overhauling, the
water should be flushed out from the boiler by keeping the drain valve open. Low pressure blow
down is suggested as the boiler pressure is raised during a start up.
Piping system after the drain valves
The drain piping from the main downcomer is connected to blow down tank. Unfortunately the drain
piping is with a U loop. As long as the boiler is under pressure, the water may flow to tank. When the
pressure is less, the last run of dirty water will trap in this U loop. It is a good engineering practice to
slope the drain lines towards the final outlet point. An alternate direct drain to trench was
recommended.
A Quick check on circulation velocity
This boiler has two main downcomers of 350 nb, feeding the water for the four side waterwall
panels. The designer at site informed that the CR ratio is 6.7. This will have a velocity of 3.2 m/s in
main downcomers. The distributing pipes are of 125 nb pipes. The water velocity in these pipes is
2.1 m/s. The steam water mixture velocity in risers will be 3.95 m/s. There is no undersizing of
downcomers or risers.
Modifications carried out by OEM
It was learnt that the boiler of same design was running at another place. This confirmed that the
failures were due to causes outlined above. The modifications carried out by OEM were seen to be
out of anxiety. Connecting additional supply tubes & relief tubes from header ends was not required.
Conclusion
The lack of provisions for proper cleaning during pre-commissioning & operational cleaning and

ACC debris ingress had led to the multiple tube failures. The startup procedure shall include low
pressure bottom drain valve operations –with fire off condition. It was advised to drain off the ACC
condensate until the condensate met the requirements.
CASE STUDY 2: IMPORTANCE OF PROPER COMMISSIONING OF STEAM PIPE
SPRING HANGERS & SUPPORTS
There are several pipelines that connect various equipments in a power plant. These pipes are to be
supported properly at regular intervals. Invariably, the pipelines are hot and hence there is thermal
movement of piping in service. In order to take care of the movement and at the same time to offer
proper support, a combination of rigid hanger, rigid support, roller support, guided supports, limit
stops are provided. There is another important support system called spring supports. Spring supports
are essential to take care of the movement and at the same time offer a support without straining the
pipe / or the connected equipment. Boiler feed pump and turbine flanges are important connections
that are not to be loaded beyond the allowable forces. Also there will be thermal movements to be
taken care of. Spring supports can be variable spring support, variable spring hanger, constant load
hanger & constant load support.
Equipment such as Turbine generator, Final SH header, Steam drum, main steam header, LP heater,
HP heater, Condenser, Condensate pump, BFP are somewhat fixed to some locations. These
equipments yet have thermal expansion at the connecting ends to piping.
The pipes have their self weight and imposed loads due to valves. Certain reaction loads due to
opening/ closing of control valves and safety valves also act on the piping. Pipes are insulated and
thus have additional loads.
Pipelines are to be supported at regular intervals to prevent sagging. Pipes can be supported by pipe
racks or hung or base supported from boiler supporting structure or building. The routing of pipes is
done from aesthetic sense, accessibility for valves, instruments, and head room clearance and to
make use of nearby structure.
Pipelines are subjected to thermal expansion. If the piping is not designed for flexibility, we may
have strained flanges, weld joints, strained bends, and strained branches. Ultimately pipe would
rupture if the piping is not designed with flexibility. We often see break down of piping, header due
to improper piping design and improper construction of steam pipelines.
Pipeline failures are due to,
1) Layout changes executed by construction engineers either due to interferences or by their own
decisions.
2) Improper commissioning of pipe support due to lack of knowledge.
3) Inadequate rigidity of the base support.
4) Failure to remove the temporary anchoring done for construction purpose.
5) Failure to locate the support with a shift based on expected thermal movement as per stress
analysis report.

Recently we had come across a case of a main steam header crack which occurred within few
months of commissioning of a power plant. See photograph 15. The cause was identified as nonremoval
of temporary anchors of steam piping. But the construction manager showed an attitude of
disagreement to the finding. He went ahead to say that their designer had verified that the header
should not fail for this reason. It appeared that the magnitude of thermal forces is not verified by
calculation by the designer. The inspection made by the design engineer was not complete. The case
study is presented below:
This is the case study of a 2 x 25 MW power plant. The main steam parameters are 105 kg/cm 2 g and
545 deg C. The newly commissioned 2 x 115 TPH boilers and two steam turbines are linked by the
main steam header placed on the roof of control room. The steam pipelines from boilers are of 250
nb OD x 32 thk. The steam piping to TG is also 250 nb pipe with 32 thk. The main steam header is
of 400 nb dia & 44.45 thk. The main steam boiler is of 6.5 m long. It is anchored at one end allowed
to expand in opposite direction. The header and pipeline arrangements are shown in figure 1. The
customer had arranged for all the piping system drawings. The entire pipeline from boiler to header
and header to turbine was checked for the correctness of spring hangers, spring supports, guides &
rigid supports. While all the supports are found at the right places, certain additional temporary
supports were seen inside the insulation. After the insulation was removed, the pipelines were seen to
be locked at locations shown in the drawing. See photographs 13 & 14.
The unit had several start / stops since there were teething troubles with the various equipments.
There were totally about 20 stoppages. It was concluded that the large cyclic forces must have led to
the failure. This led to the crack of pipe close to the weldments. Generally a weldment is stronger
that the parent metal due to extra thick reinforcement at weld. In addition, the heat affected zone is
likely to have some minute hair line cracks. The cracks grow, if sufficient force is made available.
Cycling forces accelerate the growth of the crack.
Reasoning by forces / bending moment / stress analysis
To support the argument, the thermal forces were estimated. It could be seen from the calculations,
the order of the forces were simply too high.
The header is considered as a simply supported pipe with various loads acting on it. It has its own
weight along with insulation. The bending stresses can be estimated for this case separately.
Part of the weight of connecting pipes & valves will be acting on the header. Depending on the
location of the support in the pipe, the bending stresses can be calculated.
When the connecting pipes are restricted by locks, the restricted thermal expansion of pipe
develops thermal stresses. The stresses transfer as forces on to the header. The forces are found to
be of very high order. The order of the forces can be seen below.
The above three stresses are added to the longitudinal stresses developed by internal pressure.
The calculations proved that the failure was bound to occur at the location where the failure had
taken place.
Estimation of Thermal forces on header by the restricted piping,
Thermal Co-efficient For P22 Material α = 14.35x10 -6 mm / mm / °C

Young’s modulus For P22 Material E = 1.4342 x 10 4 kg/mm 2
Operating temperature T = 535°C
Thermal Stress (On complete restraint) = α*T*E
= 14.35x 10 -6 * 535*1.434x10 4
Thermal stress = 110.1 kg/mm 2
Assuming the pipe is flexible to absorb the thermal expansion to an extent of 90%, the actual stress
can be taken as 10% of the above.
Therefore, Stress in the piping = 110.1* 10%
σ = 11.01 kg/mm 2
Converting stresses into forces:
Stress σ = F/A
Force at R (from boiler 1)
= σ A
= 11.01 * π (273²-209²)/4
= 266750 kg
Force at S (to boiler 3) = 11.01* π (219²-163²)/4
= 185000 kg
Force at T (to TG3) = 11.01* π (273²-209²)/4
= 266750 kg
The forces act as bending moments on the header. Stresses due to bending moment add to the
longitudinal stress developed due to internal pressure. It is found that allowable stresses have
exceeded the value specified by the code.
Related case studies
In another installation, photographs 16 to 25 were taken. In photographs 16 & 17, we can see here
how the inadequate structural support has yielded to load. The variable spring support close to these
supports has got loaded heavily and it is no more a spring support. These developments which show
up during commissioning have to be brought to the designer’s notice to avoid major catastrophe in
steam piping. These photographs are not covering all the wrong installations at the plant. In general
such mistakes are seen in several plants.
Recommendations for a proper piping support installation & commissioning
1. Hanger and supports are to be used only for the intended purpose. It is not to be used for
scaffolding purpose.
2. The pipe routing is not to be altered by erection engineer. If done, it should be after the revision
of stress analysis and load calculations.
3. The location of pipe support is not to be changed by the erector. If done, it should be after the
revision in stress analysis and load calculations.
4. Spring supports and assemblies should not be used for earthing.

5. Temporary supports used for piping should be removed finally after the complete insulation work
also. Finally the insulation should be completed in left over area too.
6. All spring supports are to be unlocked.
7. After hydro test, if the springs do not return to cold position, they have to be adjusted to match
the pointer returns to cold position.
8. At the first heating of the piping, the spring supports are to be monitored till the piping reaches
its rated duty condition.
9. After the construction activities are completed, piping engineer should “walk through” with the
drawings and spring support data sheet to ensure that the hangers and supports have been erected
correctly unlocked and that no temporary support is preventing the free movement of piping.
10. Sliding supports should be properly designed and erected. The piping is placed centrally to the
support in cold condition by many of us. Many times we can see the pipe is about to slip off from
the support.
11. It is vital that no pipe line fouls with the structure, cable trays, walk ways etc, hand rails, which
can cause serious damage and accident when thermal expansions start occurring.
Final word
It is a great set back if the pipeline fails in service. The steam force in the pipe can cause damages to
unpredictable levels to power plant and the staff. It was to the luck of the plant that the damage was
minimal when the header failed. There are so many plants, where piping supports are not
commissioned by the engineers. For the reader’s information only, some photographs are attached
with this article.
CASE STUDY 3: ROOF TUBE FAILURES IN A 250 TPH PULVERISED FUEL FIRED
BOILER
There are three identical boilers at this plant. Shortly after commissioning, only one unit suffered repeated
roof tube failures. The customer had been repairing the roof tubes for four or five times until the matter
became critical when the other two units were on annual shut down. The plant was under great pressure and
the management had put the foot down to resolve the matter. The boilers were of Chinese make and hence
proper support was not available from the manufacturer on time and hence I had the chance to diagnose the
problem. The failure was from the steam cooled roof panel.
The failed tube
The failed tube was seen with swelling on furnace side. On inside the whitish deposits were seen. See photo
26 & 27. Then I concluded there was mechanical carryover. I enquired with O&M team whether the steam
drum was opened any time in the past after the failures. No one nodded yes. I prayed for a chance to see the
drum inside. To my luck the boiler had to be shut for the turbine related problem. Meanwhile I had gone
through the drum internal drawings. I could see that there is a possibility of cyclone coming off its position as
the fit up design was not proper. See the photo 28 & 29 enclosed.

Soon after the drum was opened the cause of the failure was identified. Three cyclone separators had come off
from the position. See photo no 30 & 31. I advised that the cyclone should be wedged and welded so that it
would not come off its position.
Lessons for the plant personnel
There are three identical boilers and the problem was encountered only in one unit. Thus the failure can be
related to installation defect. The loss could have been prevented by proper inspection during construction. It
must be remembered that cost of damage is phenomenal compared to expenses incurred for a construction
audit. Incidentally the unit had wall tube failures which were related to improper buckstays fitment.

Photo 1 : Burst tubes inside waterwall panels. The sudden bulge seen is a case of starvation.
Photo 2: The swelling of tubes seen nearby failed area as well. Weldment being stronger, the
swelling is seen only above and below the weld joints.

Photo 3: The waterwall is seen distorted. This implies that the entire waterwall was starving for
water.
Photo 4: A close look of failed tube.

Photo 5: The drum internal showing the pH deviations. There can be iron loading from ACC
during pre-commissioning. Usually if the corrosion products are transported from the pre-boiler
circuit, the dirt appears dark brown but the boiler surface will show grey surface. If the corrosion
products are generated within the boiler circuit, then the surface will be reddish.
Photo 6: The screen drier showing the foaming inside the drum due to loose hydrated iron oxide
Fe 2 O 3 in boiler water. The magnetite layer is not seen even in steam space. This is an indication of
deviation of boiler water pH.

Photo 7: The present downcomer arrangement. The bottom most supply pipes feed the extreme
WW tubes in the LHS & RHS. If this is choked then the tubes may starve.
Photo 8: Even the front & rear waterwall tubes are fed by the bottom most supply pipes. But the
connection is at middle. The remaining supply pipes would ensure supply.

Photo 9: Good engineering practice by another boiler maker. The main downcomer has a hand hole
& a drain valve taken above the end cover. In this arrangement commissioning debris can be
cleared easily.
Photo 10: The main downcomer is not provided with a dirt trap / hand hole plate. The drain size is
small. It was informed that the drain was choked during boiler operation. On every hot box up, the
floating dirt would settle at this header end cap.

Photo 11: The feed water distributor is arranged in such a way that the water outlet holes are facing
30 deg up to horizontal. This arrangement can stir up the phosphate and lead to high phosphate in
blow down. Then the boiler water chemistry will be different from what the sample indicates. It
was advised to direct the holes downwards. Though the boiler water pH and PO 4 were OK as per
report, the drum internal surface indicated low pH. The chemical dosing line has to be connected to
feed distributor itself.
Photo 12: Arrangement of feed distributor with holes facing upwards. See the color of drum.

Figure 1: The drawing shows the piping arrangements connected to the main steam header. The
drawing shows the location of temporary anchoring. The pipelines & headers are meant for carrying
steam at a pressure of 100 kg/cm 2 & at 540 deg C.
Photo 13: The steam piping from header to old
TG is seen locked up. The insulation was
removed to identify the temporary anchoring.
Photo 14: The steam piping from boiler no 2 to
header is seen locked up. The insulation was
removed to identify the temporary anchoring.

Photo 15: The header crack can be seen here very close to the weldment.
Photo 17: In the main steam piping, this is the
status of the next support. The rigid hanger
support base is not rigid enough.
Photo 16: This is a mistake by a designer that a
base support for hanger is not rigid enough. This
is from another installation.
Photo 18: We can see that the spring support next
to the above two supports has got overloaded.

Photo 19: A constant load hanger is seen with an
improvised lock at a recently commissioned
installation.
Photo 20: A spring support waiting to be loaded in
the operating power plant.
Photo 21: A pipe is seen with temporary support
though the permanent support is installed nearby.
Photo 22: Pipe support partially commissioned by
the commissioning team.
Photo 23: A rigid hanger in the boiler feed piping
designed for 125 kg/cm 2 is seen fallen due to poor
welding at support.
Photo 24: Steam piping to TG is seen buried in
the building wall. This is a common mistake seen.
Photo 25: Due to burying the steam line inside the
TG wall, the pipe support gets lifted off it is base.

Photo 26: This is the inside surface of the failed tube. The tube indicates the phosphate carryover.
Silica carryover does not affect the roof tube. It can affect the turbine blades only. This can be
purely due to defective drum internal.
Photo 27: This is another tube from the same boiler, which failed by swelling. The external surface
proved mechanical carryover.

Photo 28: The cyclone is not fully bolted type. This can lead to passing of steam- water mixture
from the flange and cause mechanical carryover.
Photo 29: The cyclone is fitted with a wedge. This can get loosened over a period and lead to
mechanical carryover.

Photo 30 & 31: The drum internal of boiler is in open condition. Many cyclones were seen in fallen
down. This had resulted in direct water carryover (mechanical) to the superheater. Over a period
the carryover must have been there. When the PO 4 levels were haphazard and crossed the
permissible limits, the carryover of phosphate leads to overheating failure.