CHAPTER-1

INTRODUCTION In the modern increasing competitive environment, an efficient operating criterion for

pulverized coal fired furnace is vital for the future of thermal power station. Thermal power plants

contribute about 70% to all India installed capacity of electric power generating stations. In

worldwide energy sector, total 37% of electricity is produced by combusting coal.

A countrys production of electricity is a basic indicator of its size & level of developments.

Although a few countries export electric power, mostly generation is for domestic consumption.

In 1983 the first electric supply undertaking was established in India by a company, which

constructed a small generating station in the city of Surat in Gujrat. This was perhaps one of the

earliest electric supply companies anywhere in the world. This undertaking got as far as lighting

the main streets of the city by arc lamps, but unfortunately in the next year disastrous floods of the

river Tapi submerged its generating plant. In the year 1896 an undertaking started operation at

Calcutta. Thus the beginning of electric supply industry in India was mainly due

to private company effort.

According to reports (31-11-2014)

The total installed capacity : 2,55,012.78MW

Thermal power : 1,77,741.89MW = 69.69%

Hydro : 40,798.76MW = 15.99%

Nuclear : 4780MW = 1.87%

Renewable Energy Sources : 31,692.14MW = 12.42%

100%

In the thermal power station, the boiler performance is a backbone for power production.

With ever increasing demand for electricity, it is very necessary for the power plants to generate

electricity without forced outages. The power plants are facing the problem of boiler tube leakage

and it is more critical when they are running on full load. It becomes one of the critical reasons

1

among numerous reasons of the energy crisis. Utilities have been fighting boiler tube failure since

long. The tube failures cost crores of rupees lost, as it causes loss in generation. Boiler tubes have

limited life and can fail due to various failure mechanisms. Tube failures are classified as in-service

failure in boilers. These failures can be grouped under six major causes. Stress rupture, fatigue,

corrosion, erosion, material failure and welding defects.

The actual cost of repairing failed tubes is less than the cost of generation loss due to

outage, so it becomes imperative to repair & bring the unit quickly into service. Also, it is equally

important to identify the cause of failure so as to take corrective action and preventive measures

so that the failure does not recur. Tube failure is most significant causes of bringing down the plant

availability in utility fossil-fired boilers. Shutdown of a 200MW unit on account of tube failure

will cause a loss of several lakhs rupees, even when the shutdown is only for three days. Further,

during outage of boiler, if the secondary damages due to the tube failure is not detected additional

failure during start up or afterwards can occur, thus prolonging shutdown & increasing the

generation loss.

1. Forced / unplanned / planned outages in power plant amount to 15%.

2. Forced / unplanned / planned outages resulting out of boiler are 60%

3. Outages due to boiler tube leakage are 75%

2

BOILER PRESSURE PARTS

ECONOMISER

Economisers are provided in the boilers to improve the efficiency of the boiler by extracting

the heat from flue gases and add it as either sensible heat alone or sensible heat and latent heat to the

feed water enters the evaporating surface of the boiler. The economiser in the present day power

boilers have tubes made of low carbon steel with tube outside diameters ranging from 38 mm to 52

mm with spacing about 90 to 140 mm, Both horizontally and vertically.

3

LOCATION AND ARRANGEMENT

Location of economiser will vary with the overall design of the boiler. It is usual to locate

the economiser ahead of air heaters and following the primary super heater of reheater in the

convective pass of the gas stream. In some cases where very low exit gas temperature and high air

temperatures are desired it may be necessary to divide the economiser and the air heater and place

the cooler section of the economiser between the air heater sections.

WATER WALL TUBES

Any boiler needs primarily an evaporating surface for the conversion of water into steam. In

the early periods of boiler development the evaporating surfaces are formed by placing many coils

of tubes or tube banks across the flow path of the hot gases from the furnace and circulating water

through these tubes. With the need for increase in steaming capacity of boilers and to minimise the

furnace heat losses by radiation, in modern boilers the evaporating surface is made of water walls,

which form the major part, if no all, of the furnace enclosure. Usually carbon steel especially low

carbon steel is used for the water wall tubes as the tube metal temperature normally will be within

4000C. However some prefer to use % molybdenum steel also for water wall tubes to have better

stress value.

MEMBRANE WALL

In this type the tubes are welded together by means of flat metal strips approximately 12 mm

wide. This type of construction enables furnace wall tube panels to be prefabricated in a factory and

facilitate the erection of the wall at site. With membrane wall construction the furnace walls are

airtight. The membrane walls will be insulated at the non-firing side by mineral wool blankets and

covered by metal lagging called skin casing.

SUPER- HEATERS:

SH are meant to raise the steam temperature above the saturation temperature by absorbing

heat from flue gas. By increasing the temperature of the medium (steam) the useful energy that can

be recovered increases thus efficiency of the cycle is improved. So in modern Boilers SH are widely

used to increase a cycle efficiency economically. The maximum temperature to which steam can be

heated is dictated by the metallurgy & economy in initial cost and maintenance cost. Present trend

is to limit the steam temperature value to 540oC both in SH as well as reheater. SH also eliminates

the formation of condensate during transporting of steam in pipelines and inside the early stages of

turbines, which is harmful to the turbine blades and pipelines.

4

REHEATER:

RH is used to raise the temperature of cold steam from which, part of the energy has been

extracted in H.P.T. This is another method of increasing the cycle efficiency. The efficiency

increases with number of stages of reheating. Reheating requires additional equipment (i.e.) heating

surface, boiler turbine connecting piping, safety equipment like safety valve, NRV, isolating valve,

steam temperature regulating equipment , instruments etc. Because of these additional investment,

complexity in operation and reduced availability of such system offsets the gain in efficiency of the

system gets minimised. Hence single RH can be economically applied only for capacity above 100

MW & two RH for capacity above 500MW. The limit is also dictated by the predicted fuel price

over the period of operation.

5

CHAPTER-2

BOILER TUBE METALLURGY

Boiler pressure parts subjected to high pressure and temperature call for following properties:

High Temperature Strength

Allowable stress is a good representation of the high temperature strength characteristics

of heat resistant steels, and is often determined by creep rupture strength under actual operating

conditions. In order to improve the reliability of high temperature components, it is therefore

necessary to ascertain creep rupture strength up to 100 000 h (the basis for fixing allowable stress),

or to make an accurate estimate of this, and to fully appreciate the relationship between the changes

in creep rupture strength and structures over long periods of time. Both high temperature strength

and economy must be considered in the selection of materials. In general, higher cost materials

have greater high temperature strength.

High Temperature Corrosion

High temperature corrosion is a major factor affecting the life of superheater tubes, and the

corrosion rate increases as the temperature goes up. In general, increasing the chromium content

makes materials more corrosion resistant, and corrosion resistance goes up dramatically when

the chromium content exceeds 20%.

Coal is one of the main fuels for power plants. The corrosion caused by coal ash is quite different

from that caused by other fuels, as it is highly dependent on the amount of SO2 in flue gas and on

the amount of Na2SO4 and K2SO4 in the ash. When large quantities of these substances are

present, Na3Fe (SO4)3, K3Fe (SO4)3 and other basic iron sulfates form on the surface of the tube,

giving rise to severe corrosion. Ash is carried upwards with the flue gas, and corrosion occurs

where it accumulates on tube surfaces. It is most severe on surfaces at an angle of 45 to the upward

flow of flue gas.

As the corrosion resistance of boiler tube materials is greatly affected by the amount of SO2 in

flue gas and the amount of Na2SO4 and K2SO4 in the ash, it is also necessary to evaluate different

types of coal, particularly in terms of sulfur content. Corrosion has been controlled by using a

mixture of various types of coal to reduce the sulfur content to less than 2%. The need to reduce

the S content to control air pollution has also helped to reduce corrosion caused by coal combustion

6

products, and this latter issue is almost unheard of in modern coal-fired boilers. High temperature

corrosion due to coal ash is strongly associated with the chemical composition of the ash, as coal

contains different types of compounds which accelerate or inhibit corrosion. It is important to

know the chemical composition of the ash for evaluation of corrosion resistance of alloys to be

investigated.

Steam Oxidation

Problems due to steam oxidation include

a) Creep rupture resulting from overheating caused by tube plugging, which is due in turn to

exfoliation and buildup of formed scale

b) solid-particle erosion of turbine components caused by exfoliated scale.

Examination of scale from austenitic steels shows that the outer layer of scale, Fe3O4, is very

likely to exfoliate, whereas the inner layer is a tightly formed spinal oxide composed primarily of

Cr and Ni which never exfoliates from the tube surface. In scale which has grown beyond a certain

thickness, the outer layer exfoliates due to the difference in thermal expansion between the tube

material and the scale during start and stop of the boiler. Various studies have been conducted with

the aim of preventing this, and it is now known that increasing the Cr content in excess of about

20% is effective in inhibiting growth of steam oxide scale. Treatment of the inner surface of the

tube such as chrome plating and chromizing is also useful. Meanwhile, as a protective measure

employed for practical purposes, fine-grained TP347HFG steels or TP321H with a fine-grained

inside surface are used, taking advantage of the fact that the finer the grain size of stainless steel,

the smaller the scale formation. Steel tubes with shot-blasted internal surfaces are also used, given

the fact that the cold-worked layer tends to inhibit scale formation.

Thermal Fatigue

According to the failure experiences thermal fatigue and creep fatigue caused substantial

damage to the header, main steam pipes and valves, which were mainly made of austenitic TP316

steel because of the high steam pressure and temperature. The low thermal conductivity of this

steel was one reason for the damage, because large thermal stresses soon arose when the plant

started and stopped, even given base load operation. For this reason, and because of frequent start

and stop operation of recent power plants, ferritic steels must be employed even in temperature

ranges where austenitic steels were formerly used.

7

Materials used for boiler pressure parts and their properties are as shown in table

SECTION MATERIAL SPECIFICATION

ECONOMISER CARBON STEEL Gr 210 Gr A1

SA 210 Gr C

WATER WALL

SMOOTH

CARBONSTEEL SA 210 Gr C

RIFLED CARBON

STEEL SA 210 Gr C

STUDDED TUBES

SUPER/RE

HEATER

SA 209 T1

CARBON STEEL

and SA 213 T11

ALLOY STEEL SA 213 T22

SA 213 T91

SA 213 TP 347H

Mechanical Properties

ASME/ASTM

Material

Specification

Tensile

Strength

Yield

Strength Min Elongation

(2 in./50mm),%

ksi MPa ksi MPa

SA-210 Gr.

A1 60 415 37 255 30

SA-210 Gr. C 70 485 40 275 30

8

CHAPTER - 3

BOILER TUBE FAILURE MECHANISMS

IDENTIFICATION:

1. Short term Overheating (Stress Rupture):

For a specific tube material, there is a maximum allowable stress at a particular

temperature. If the tube metal temperature increases beyond this point, creep will occur

and the tube will eventually fail by stress rupture.

Super heaters and reheaters can experience interruptions and/or reductions in steam flow

that can increase tube metal temperatures that lead to stress rupture failures.

With ferritic steel, a "fish mouth" or longitudinal rupture, with a thin edge fracture

is most likely. With other tube materials, still other appearances are possible. The causes

for this type of failure are the following

Abnormal coolant flow from a blockage in the tube

Blockage due to debris in the tube

Blockage due to scale in the tube

Blockage due to condensate in the tube following an incomplete boil out Excessive

combustion gas temperatures

High temperatures from over-firing during start-up.

2. Dissimilar Metal Welds (Stress Rupture):

The weld failures will normally have one side of the weld that responds to a magnet, while

the other does not. The weld crack will be circumferential at the weld, over on the side that

responds to the magnet; the ferritic side. The cause of failure relate the stress of the two

metals expanding differently and the following

Stress from internal steam pressure

Stress from the vertical weight on the weld

Stress from the constraints of how the tube is supported or attached

Internal thermal gradients, which add up to the total stress. The higher the value, the sooner

the weld fails.

9

3. Caustic Corrosion (Water-side Corrosion):

There are two types of caustic corrosion: caustic embrittlement and caustic

gouging. Caustic embrittlement is an intergranular attack along grain boundaries leading to sudden

failures. Caustic gouging is a general eating away of the protective magnetite film until the tube

wall is thinned to failure. Caustic embrittlement is relatively uncommon in comparison to caustic

gouging. Caustic embrittlement is characterized by intergranular cracking with very little metal

loss. It normally occurs in stressed and restricted areas where boiler water containing caustic soda

can reach high concentration levels (100,000 to 200,000 ppm NaOH). The most common

occurrence of caustic embrittlement is on tubes that the rolled into boiler drums. If leakage occurs

around the rolled-in tube, the escaping steam leaves the tube-drum interface highly concentrated

with soluble boiler water salts. If caustic is present, then the potential for caustic embrittlement

exists. Three conditions are necessary for caustic embrittlement: high metal stress, concentrating

mechanism and free caustic.

There is no question that more boilers suffer from caustic gouging. This water side

corrosion literally eats away the protective magnetite film along boiler tubing.

Caustic corrosion can cause either a pinhole leak or what looks more like a small, bulged,

thin edge rupture. The tube fails when the tube is so thin that it cannot take the internal pressure

any longer. There is often a thick deposit on the inside of the tube, but the leak could purge much

of the deposit. These failures are usually found where the heat flux is greatest and are the result of

the following

Condenser leaks Deposits of caustic contaminants from the feed water system Upsets in

the boiler water chemistry.

The two conditions necessary for caustic gouging are: a concentrating mechanism must be

initiated and free caustic must be present in the boiler water. Dirty tubes are far more susceptible

to caustic gouging because the deposits trap and concentrate the boiler water. Proper adjustment

of boiler water chemistry is required to prevent caustic gouging

4. Pitting Localized corrosion (Water-side corrosion):

Water containing dissolved oxygen is highly corrosive to many metals: therefore

everything must be done to minimize the introduction of oxygenated water into the boiler and pre-

boiler systems. Oxygen corrosion can dramatically affect various components in operating and

non-operating boilers. Much of the suspended crux that enters an operating boiler is the direct

result of oxygen attack of components in the pre-boiler system.

10

Localized pitting is found where oxygen is allowed to come in contact with the inside of

the tubes, which is just about anywhere. It appears as a steep edged crater with red iron oxide

surrounding the pit. The tube surface near the pit may show little or no attack. Sometimes there is

a series of smaller pits. The typical cause starts with High levels of oxygen in the feed water, i.e.

poor deaeration at start-up filling of condensate in low point, such as bends, when the steam cools

Outages where air gets inside the assembly from adjacent repairs, or vents being left open as the

steam condenses

5. Stress Corrosion Cracking (Water-side Corrosion):

These thick-edged fractures can be either circumferential or longitudinal,

depending on how the stress is oriented. Typically the chemical attack is on the inside of the tube

and works its way out through the growing crack. Far less commonly, the chemical attack exists

on the outside (fire side) and works its way inward. The root cause is the coupling of more than

one factor working on the same location.

Contaminants can come from contamination in the desuperheater

spray. External contaminants come from acidic components to the fuel. Additionally there

must be a stress possibly from a bend in the tube Weld attachments from initial assembly

or possibly from cyclic unit operation.

6. Low temperature corrosion (Fire side):

External surfaces of furnace tubes that are exposed to a moist environment containing flue

gases can experience acid corrosion. Certain acidic salts (ferrous sulfate for example) can

hydrolyze in moist environment to produce low pH conditions that will attack carbon steel.

Sulfur trioxide (SO3), present in the cooler flue gas areas, can react with water vapour to

produce sulfuric acid. If the temperature is below the dew point, sulfuric acid condenses along

metal surfaces and corrodes the metal. Water washing can also produce acid attack.

A gouged exterior and a thin ductile failure characterize this form of failure. When the

pressure becomes too great, the pressure inside blows out a hole. The root cause for low

temperature failures are

The presence of sulfur in the oil, which has an opportunity to condense on the

last rows of economiser tubes

The condensing of sulfur and ash when the exit gas temperature is low.

11

7. Water wall corrosion (Fire side):

Fire side water wall corrosion covers a broad array of corrosive forces from the intense

combustion process. A broad, general thinning occurs with the surface of the tube having fairly

deep longitudinal and lateral gouges or cracks. The thin wall ductile rupture will go length wise

down the tube. The surface of the tube will typically have a hard dark slag deposit. The causes are

a) A zone of combustion where there is too little oxygen

b) High level of chloride or sulfides in the fuel being burned

8. Vibration Fatigue:

In locations where boiler tubes are welded to support lugs, a thick edge failure can form at the

toe of the weld. This fracture is circumferential, running at right angles to the weld. The root cause

is

a) The vibration of the tube, caused by the steady flow of exhaust gases

c) Along with a lug location that induces a rigid point that will concentrate the force into a short distance.

9. Thermal Fatigue:

The flexing action of thermal fatigue produces multiple surface cracks, laterally across the

tube which results in a thick edge fracture. The fatigue is caused by

a) Sudden cooling of the tube metal, either from within or externally

b) Rapid change in the feed water temperatures to the economiser, i.e. maloperation of the

pre-boiler system

10. Corrosion Fatigue:

Like the previous fatigue mechanism, cyclic stresses produce a series of parallel surface

cracks, however this time the corrosive environment adds to the deterioration by forcing an oxide

wedge into the cracks, further leveraging the fracture. The thick edge fracture will be coated with

an oxide layer. Pits can often be found on the inside surface of the cracks. The causes have two

key ingredients, corrosion and stress

There is either induced stress from the way the tube connects to another pressure part or,

there is induced stress from the way the tube is tied to a structural support,

12

There is residual stress left over from fabrication

a) Internal pits from dissolved oxygen or acidic corrosion from the pre-boiler circuit

aggravate the cracking process in the water cooled tubes.

b) External corrosion in steam cooled units aggravates the cyclic flexing where the tube

enters the header.

11. Steam/Condensate Erosion

a) When a failure is allowed to continue for several hours or days, the result can amount to

more time and energy needed to make repairs. The root cause is

b) Decision making in how quickly a unit is brought off-line once a failure is found

c) Insufficient documentation to justify the economics of not waiting to bring the unit off-

line to attend to the tube failure.

12. Exfoliation:

The above list of 12 failure mechanism does not necessarily include all possible failure

modes, and some tubing problems do not necessarily reduce availability by virtue of a tube failure,

as in the example shown below. The spalling of the indigenous oxide on super heater, reheater

tubes and steam piping is referred to as exfoliation. With exfoliation, the tube wastage is from the

inside out, and the damaged component is in the turbine's internals. The root cause is not known,

however, consider the following

a) Bottling-up of stream in the tube when the unit trips, resulting in forced migration of

steam into the black oxide scale layer within the tube.

b) Difference in the coefficient in expansion between the internal magnetite layer and the

tube metal, resulting in spalling of scale when the unit cycles

c) Quenching of the tube internals when the unit is in a start-up mode.

13

CHAPTER - 4

CAUSES OF BOILER TUBE FAILURE THROUGH WATER

CHEMISTRY

In power plant operation a Chemist is intimately mixed up with tube failures. It may be due

to faulty water conditioning or improper operation. In general, every tube failure may be due to

any of the following three reasons:

a) Material failure

b) Mal - operation

c) Improper water conditioning

In case of material failure, blame goes to the manufacturer, for mal-operation and improper

water conditioning it is human error. In the present chapter, based on experience, it has been tried

to show how improper water conditioning can cause tube failures.

NEED FOR WATER CONDITIONING:

1. The main need is to protect the internals from corrosion which cause ultimate failure. There

are several types of corrosion possible, like

1. Dissolved O2 pitting

2. Stress corrosion

3. Ductile corrosion

4. H2 embrittlement etc.

There are three zones, where same water is conditioned differently. They are

a. Feed System

b. Drum

c. Steam and Condensate

14

Various parameters are laid by the boiler manufacturers, time to time, depending upon the

metallurgy of the surfaces through which water/steam flows. These parameters vary depending

upon the pressure of boiler and temperature of the Steam Cycle. In the table below, effective

parameters are shown.

Particulars

Boiler Pressure 60 kg/cm2 and

under

Boiler Pressure from 60 kg/cm2 and

above

PH Cond. H Silica PH Cond. H Silica

Make up 7.0 0.5 Nil Nil 7.0 0.5 Nil Nil

Feed 8.8 9.0 Upto 4.0 Nil Nil 8.9 9.0 Upto 2.5 Nil Nil

Drum 9.5 9.9 Upto 100 Nil * 9.3 9.5 Upto 25 Nil *

Steam 8.8 9.0 Upto 4.0 Nil 0.02 8.9 9.0 Upto 2.5 Nil 0.02

Condensate 8.5-8.7 Upto4.0 Nil Nil 8.5 8.7 Upto 2.5 Nil Nil

Scale: Conductivity in Micromhos, Silica in ppm, silica, hardness in ppm CaCO3. * As per

pressure silica curve

The change of pH 7.0 in make-up to 9.5 in drum is maintained by dosing suitable

chemicals at different places of the water cycle. The parameters are designed to suit the internals

of the system, so that a corrosion free surface is maintained. The dosings are mainly of two types

volatile and non-volatile.

Sr. Type of Chemical Dosed Place of Dosing Ultimate Effect

No. Dosing

1. Volatile Ammonia Feed System at the To increase pH

Morpholine suction of feed pump

Cyclohexyl amine

2. Volatile Hydrazine hydrate Feed System at the To scavange oxygen

inhibited or treated suction of feed pump &

Hydrazine & To increase pH

15

In condensers at the

suction of Extraction

Pump

3. Non- Tri-sodium Phosphate Drum To increase pH to

volatile Sodium Hydroxide maintain residual

Phosphate.

4. Non- Sodium Hydroxide & Drum

To decrease pH, to

When dosed properly, the required parameters can be obtained and conditioning becomes

proper, resulting a trouble free service.

MAIN CAUSE OF TUBE FAILURES EVEN AFTER PROPER DOSING:

There can be two types of main causes of failures. These are

a) Improper Chemicals

b) Excess or incorrect amount of dosing

Improper chemicals not only deviate main aim of water conditioning it raise complication

also, the effect of improper chemical dosings are summerised as under with particular reference

to the probable impurities.

Chemical Possible Impurities Effect or Dosing

Ammonia Hardness, Silica Very slow increase in pH

Rapid increase in conductivity.

Injection of silica in System/

Phosphate Free Sodium Hydroxide and chloride Unstable pH condition

16

Increase in conductivity

Foaming action in drum,

Free sodium hydroxide in Steam

All above conditions lead to tube failure,

Effect of Excess Dosing

Chemical Normal Reaction Effect Remarks on effect

Ammonia Simple addition High pH & Caustic corrosion

NH4OH + H2O NH4OH H2O Conductivity

Hydrazine

Hydrate N2H4 + O2 = N2 + 2H2O Oxygen Scavenging None

2N2H4 = N2 + H2 + 2NH3 Hydrogen in steam Stress corrosion

2N2H4 +H2O = 2NH4OH + N2 Ammonia formation None

Phosphate Na3PO4 + H2O = NaOH + High pH & Caustic attack carry

NaH2PO4 Conductivity over foaming causing

Starvation

When we analyze the remarks on last column following points are raised on tube failure:

a) Caustic attack

b) Hydrogen attack

Caustic Attack

Although the pH of the media is high and safe for most of the tubes, yet excess of it may

cause soap-bubble effect at a particular point leading to carryover and or volatile caustic carryover

from drum and improper distribution of heat flux at any point due to the same.

The caustic attack due to sodium hydroxide is very much deteriorating than due to

ammonia. Whereas, excess of ammonia may give raise to a possible formation of nitric acid as :

NH3 + 202 = HNO3 + H2O

17

The possibility is very less due to the presence of excess hydrazine hydrate, which takes

care of any oxygen available in the system.

The caustic attack due to the presence of excess sodium hydroxide is very much harmful

due to the phenomenon known as steam blanketing, resulting static or slow moving slug of steam

generation causing rupture in the tube due to irregular heat transfer.

Hydrogen Attack

This is very serious, sometimes we find unnecessary increase in hydrogen level in steam,

this leads to corrosion as per per-oxide theory.

The H2 released combines immediately with free O2 to from hydrogen per-oxide (H2O2).

This reacts with Fe(OH)2 and forms Fe(OH)3.

2Fe(OH)2 + H2O2 = 2Fe(OH)3

But hydrogen aid polarization which reduces electro-chemical reaction.

WATER WALL CORROSION:

Control of the water and/or steam environment inside economiser, boiler, superheater and reheater

tubes is a pre-requisite for trouble free performance of a fossil-fired steam generator. When water

and steam chemistry are not maintained within limits recommended by the boiler manufacturer or

a qualified consultant, corrosion damage may occur in water walls and economiser tubes.

Water wall corrosion problems generally can be avoided in boiler if

1. Recommended water treatment controls are followed; 2. Corrosion products formed in the feed water system are kept within specified limits; 3. Feed water oxygen concentration is properly controlled and 4. Precautions are taken during chemical cleaning operations to prevent metal attack. LOW-pH DAMAGE:

Corrosion failure occurs when acid or alkaline salts are concentrated. Hydrogen induced

brittle fracture occurs beneath a relatively dense deposit and is most likely to occur when boiler

water pH is too low. Though some metal loss may be caused by corrosion mechanisms, the steam

generator tube usually fractures long before it has corroded to the point at which tensile failure

would occur.

18

Some of the hydrogen produced in the corrosion reaction diffuses into the tube metal where

it combines with carbon in the steel. Methane is formed and it exerts internal pressures within the

steel, causing grain-boundary fissuring. Brittle fracture occurs along the partially separated

boundaries. In many cases an entire section is blown out of the damaged tube. Restoration of proper

boiler water treatment may not be sufficient to prevent further hydrogen attack, unless the dense

corrosion product deposits are removed. Even repeated chemical cleanings sometimes will not

remove them. Arbitrary replacement of tubes, in the general areas where metal attack exists,

becomes necessary. Generally, hydrogen damage is difficult to detect using nondestructive means.

Ultrasonic thickness checks may pinpoint some damaged areas, but positive identification of all

failure prone tube is not possible.

HIGH-pH DAMAGE:

Ductile failures caused by a gouging type of corrosion usually occur when the concentrtion

of hydroxide salts such as sodium hydroxide in the boiler water is too high. Ultrsonic tube-wall

thickness checks can detect tubes with metal loss. Proper boiler water treament can minimize

further corrosion.

MINIMISING CORROSIVE ATTACK:

Corrosion concentrations of salts generally exist at tube surfaces only when these

iterrelated conditions are present.

a) An acidic or alkaline producing environment prevails.

b) The boiler operates outside of the established boiler water treatment recommendations,

allowing abnormal acidic or alkaline conditions to persist.

c) A means of concentrating the acidic or alkaline salts exists.

WATER TREATMENT CONTROLS:

To protect steam generator tubes against corrosion two widely used boiler water treatments

are available, however, even in the event of moderate contamination. They are volatile and

coordinated phosphate/pH control.

19

Briefly, volatile treatment uses a volatile neutralizing amine, such as ammonia, to maintain

a pH that will not disrupt the magnetite coating on the boiler tubes. It does not contribute additional

dissolved solids to the boiler water. Thus, it minimizes the amount of solids that can be carried

into the superheater by the steam. But it does not give any protection against contaminants, such

as salts carried into the boiler by condenser cooling water.

Phosphate treatment in drum type units maintains pH in the proper alkaline range to protect

the magnetite film and it reacts with salt contaminants to prevent the formation of free caustic or

acidic compounds. Coordinated phosphate/pH control is maintained by using a combination of di-

sodium phosphate and tri-sodium phosphate or sodium hydroxide to give a residual phosphate

concentration of upto 10 ppm.

If the phosphate and pH control points are below the curve no potentially damaging free

caustic is produced. The concentrating mechanism most often responsible for corrosion damage

involves internal deposits. As heat is transferred through the tube wall to the water/steam mixture

in the tube, a temperature gradient is established. That is, the temperature of the internal surface

of the tube is slightly higher than that of the bulk fluid. When boiler water evaporates, dissolved

solids such as sodium hydroxide, concentrate in the thin film between the tube wall and the bulk

fluid. When porous internal deposits are formed in areas of high heat absorption, it is possible to

produce very high stable concentrations, because the deposit acts as a diffusion barrier.

This concentration mechanism explains why corrosion damage normally occurs on the tube

internal surface facing the fire and tends to be most severe in the highest heat absorbing area.

Pre-boiler corrosion occurs when oxygen and pH values deviate from established limits.

Oxygen control is, perhaps more critical than pH-especially during start-up, shut-down, and idle

periods. Low pressure feed water heaters and related extraction piping often are under negative

pressure during low load operation. Thus any leaking valves, pumps, flanges, etc. provide a path

for air into the system. Idle units may even become saturated with oxygen if proper precautions

are not exercised. Oxygen concentration in feed water should be maintained at less than about 5

ppb during unit operation to minimise the formation of pre-boiler corrosion products. The

following are few of the ways to minimise oxygen infiltration during idle and start up periods and

to reduce the transport of corrosion products to the boiler.

20

1. The boiler and as much of the pre-boiler system as possible should be blanketed with steam

or nitrogen when the unit is out of service. If a long outage is contemplated, fill the boiler and

feed water system to the greatest extent possible with the corrosion inhibitor. Excellent results

have been obtained with solutions containing 200 ppm of hydrazine and 10 ppm of ammonia

for lay-up period of more than one year. For pre-boiler systems containing copper alloys,

reduce the dosage to 50 ppm of hydrazine and 0.5 ppm of ammonia to avoid copper attack by

ammonia.

2. Make sure an adequate supply of steam is available to the deaerator during unit start-up so

that oxygen can be purged from the feed water. If no adequate auxiliary steam source is

available, peg the deaerator with steam from the boiler drum until turbine extraction steam is

available.

3. Introduce aerated storage water into the feed water system only through the dearerating

section of the condenser, if all deaeration is accomplished there.

Connect aerated storage water into the feed water system only through the dearerating

section of the condenser, or through the aerator.

5. Consider a partial flow condensate polisher for cycling units. Its use together with that of the

pre-boiler systems recycle line, permits removal of both erosion products and oxygen from

the feed water during steam-generator start-up operations.

Minimizing Pitting of Boiler Tubes:

Excessive dissolved oxygen in the boiler water and excessive temperature during chemical

cleaning, can cause severe local attack pitting. Crevices, like those formed by backing rings, or

minor variations in metallurgical structure, may act to promote localized corrosion. Normal, but

higher than the average peak stress also can contribute to preferential pitting. Pitting attack of

various types can affect the internal surfaces of all tubes. The pitting attack usually is quite shallow

and does not adversely affect the tube integrity, but occasionally it may be locally severe and even

penetrate the tube wall. Crack like interconnected pitting is a common form of attack, too.

Penetrations of this type can develop into corrosion fatigue cracks, but it is not unusual for them

to propagate through the wall as a result of corrosion alone. Most leaks associated with corrosion

pitting are like to occur at or near weld or attachments.

21

Prevention:

Pitting caused by dissolved oxygen can be prevented by maintaining feed water oxygen

level within the 5 ppm limit while attack by chemical cleaning solvents can be eliminated by

carefully following the cleaning procedures. During shut-down periods, it is necessary to protect

all internal surfaces, wet lay up, together with a positive nitrogen pressure cap of about 3 5 psig,

will protect metal surfaces from corrosion. Some of the pitting attack may have been caused by

the presence of oxygen and moisture during shut down periods. Those that do occur usually can

be attributed to improper wet lay up, or to the introduction of contaminants into the heat transfer

sections.

Avoiding Steam side Deposition:

A more common problem affecting the internal surfaces of steam side components, such

as the superheater and reheater, deposits. They can cause overheating failures by insulating the

tube from the cooling effect of the steam. Such failures usually occur as creep blisters at the low

spot in pendant surfaces. But deposits also have caused failures on vertical tubes. Occasionally,

they partially or totally block steam flow in a particular circuit. Solids carried by the steam into

the turbine also can be damaging.

Failures Due to Manufacturing Defects Raw Material Defect:

Either mix up of material or raw material defect also accounts to tube failures. Due to mix

up of material of different specification than designed one comes to the service and failure occurs.

And raw material defect comes in the rolling of tubes itself and a lap or eccentricity formed thus

causes tube failures at elevated temperatures.

Material defect due to defective rolling of tubes is shown in figures below:

Eccentric Rolling Defects Lap Formed Tube

22

Sufficient care during rolling of tubes and correct material selection can avoid failures due

to such defects.

Procedures for failure investigations and collection of failed sample:

The causes for failures are evaluated by removing carefully the failed material (e.g. tube)

along with deposits if present. It is preferable to pack them with polythene wrappers and box, such

that no corrosion and mechanical damage occur during transit. If the deposits are loose, water side

and fire side deposits are collected in separate polythene bags with rigid tags. The flame cut region

should be at least 200 mm away from the region of failure since heat produced during flame cutting

will change the microstructure, if the cut region is close to failed region. For comparison, it is

preferable to have a good portion (about 300 mm) of the tube (along with deposits if it is present)

which is considerably away from failed region. The samples of materials which failed due to brittle

fracture should be taken out (if it possible) and the fractured facets should be protected by using

rust preventive coatings. In some cases in site micro-examination is carried out when the specimen

could not be removed. This technique is also used for fracture investigations. In certain cases it

becomes essential for the metallurgist or chemist to visit the site and have firsthand information

regarding the location and overall nature of failed tubes or any other components. He has to watch

the performance under the existing condition at site. This will help in the interpretation of complex

failures.

Procedures for Metallurgical Investigations:

The tools and techniques for failure investigations are chosen as to suit the individual

requirements. Generally the following procedures are followed:

a) Dimension and thickness measurement at important locations comparison with the original or good material.

b) Standard mechanical tests; usually tensile, drift flattening, hardness etc. c) Spectral and chemical analysis of deposits, water, fuel, ash etc. d) Investigations with microscope for evaluating the nature of failures special corrosion tests

for stainless steel components. e) Advanced techniques; Electron microscopy for detailed information on fine structures and

creep damages, x-ray diffraction for the analyzing of ash, deposits, scales etc., creep testing and burst testing for the determination of residual creep life etc. are used for complex case histories.

23

Data Required for Investigation:

The log book is to be referred at site for one or more of the following information which

will be required for effective investigation of failed components.

a) Operating pressure and temperature of the pressure parts close to failed region location of

the failed tube, data of failure etc.

b) Composition of the fuel gas

c) Amount of excess combustion air

d) Analysis of feed water and steam condensate type and amount of contaminants in make-up

water

e) Normal power output and fluctuation in steam demand

f) Frequency and method of cleaning water side and fire side surfaces of tubes.

REPAIR GUIDELINES:

Introduction

All plant personnel should bear in mind the legal formalities involved in the repair

of boiler pressure parts. The responsible parties, before making repairs or alterations of a pressure

part, must notify the legally responsible inspection agency and obtain approval before starting the

work. The responsible inspection agency may be the boiler insurance carrier or state or municipal

inspection agency. In some cases, it may be a federal agency. The responsible parties must follow

this procedure even though a pressure part fails during the manufacturer's warranty period. The

boiler manufacturer may recommend a repair procedure, but it must be approved by the responsible

inspection agency. Generally, the manufacturer's recommendation will be accepted, but the

inspection agency still has the legal responsibility for approval.

24

Welding Repair or Low Carbon Steel Tubes:

Cut out a damaged tube at least 50 mm (2') on each side of the defective area. The

minimum replacement tube length should be not less than 152 mm (6'). Do not use backing rings

to weld any heat-absorbing tubes carrying water or a mixture of steam and water. Without a

backing ring, make the first pass of the weld using gas tungsten arc or oxyacetylene. The weld

passes may be completed by either process, or by shielding metal arc. If access is difficult, use

window welds for repair work. The first pass of a window weld must be made by gas tungsten arc

of oxyacetylene.

Fit-up of the weld joints is important. Although it is difficult to obtain accurate cuts

on furnace tubes, it is important to get the existing tube ends squared and correctly chamfered and

to cut the replacement tube to the correct length. Use a tube-end scarfing tool when possible. Allow

for shrink in welding. Remember that the weld metal and parent metal are melted in the welding

process and the molten metal shrinks as it solidifies.

A butt weld in a tube will shorten the total length about 1.6 mm (1/16"). Use a clamp or guide lug to hold one end of the replacement tube in alignment while the

first weld is made. Do not tack weld both ends of the replacement tube, particularly if the existing tubes are

rigidly supported. As a general rule, first complete the weld at the lower end of the replacement tube. Do not start welding the upper end of the replacement tube until both the replacement and

existing tubes have cooled to ambient temperature.

Alloy Tube Repairs:

If a damaged alloy tube must be replaced, it is always preferable to weld the replacement

tube to an existing tube end of the same alloy and the same wall thickness. Before removing the

damaged tube, check the manufacturer's unit material diagram and locate shop welds used to join

the damaged length to tubes of different material or different wall thickness. If at all possible, make

the cuts to remove the damaged tube at least 152 mm (6") from the shop weld, thus leaving a "Safe

end".

25

If necessary to cut out a shop weld joining tubes of different material and/or wall thickness,

pay special attention since all qualified but-welding procedures require the two tube ends to have

the same internal diameter (ID) as the weld root.

In some cases, the thicker wall tube may be bored to match the ID of the thinner wall tube

But the thicker wall tube may be bored only if the strength of the tube, after reducing the wall

thickness, is at least equal to the strength of the thinner wall tube at the same operating temperature.

A ferritic alloy tube must not be bored to match a thinner wall austenitic alloy tube.

The only satisfactory method is to use a connector of austenitic alloy tube having the same

wall thickness as the ferritic alloy tube.

One end of the connector is bored to match the wall thickness of the existing austenitic

alloy tube.

Shrinkage in welding alloy tubes is similar to that for carbon steel tubes. Allowance must

be made for expansion from preheating which will close the root gap slightly.

For shielded metal arc welding with a backing ring, it is essential that the root gap opening

be sufficient to assure full penetration and fusion with the backing ring during the first pass.

For gas tungsten arc welding, a zero root gap opening is permitted. There must

be no pressure exerted between the two tubes.

It is advisable to allow enough clearance to avoid actual contact at the root gap opening

after the two tubes are preheated.

Repair of Tube Blisters:

Internal deposits cause blisters on the furnace wall or boiler tubes.

Generally, they occur in boilers operated with a high percentage of make-up feed water.

A blister forms because an internal deposit increases tube metal temperature until metal

creep occurs.

As the heated area swells, the internal deposit cracks off and the tube metal temperature

returns to normal.

26

The process may be repeated several times before the blister ruptures.

Commonly, a large number of tubes are blistered and not noticed until one of the blisters

cracks open. To avoid a massive tube replacement job, particularly where replacement tubes are

not immediately available, work the blisters down to the original tube radius.

Follow these general guidelines:

Remove the damaged tube, then carefully cut away enough of the bar or fin to allow

chamfering the tube end for welding around the sides of the replacement tube joint

After the tube welds are completed, weld the bar or fin to the replacement tube.

If the gas between bar or fin is too great for easy bridging, insert a low carbon steel

welding rod for a fin is too great for easy bridging, insert a low carbon steel welding

rod for a filler.

The spaces in the bars or fins, at the tube joints, are built up with deposited weld metal.

Be sure no cracks exist before making the final weld to the tubes.

27

CHAPTER-5

CASE STUDIES

CASE - 1: Flame Impingement of Water Wall Tubes

During unit reliability operation flame impingement test was conducted on water wall tubes

for a few hours and it was found that flame touched the rear wall of the furnace. It was decided by

the Plant management to send some tubes for investigating the effect of flame impingement on

water wall tubes.

Physical Inspection

Out of the 6 tubes provided for analysis, 3 tubes were from flame impingement area, 2

tubes and from non-flame impingement area and one tube was unused tube for comparison

purposes. The tubes were in services at variable boiler load conditions. All the tubes were electrical

resistance welded seam (ERWS), however, the location of the seam was not visible by naked eye.

The position of the seam in the tube was located by grinding, polishing and deep etching of the

tube. The original thickness of the tube was 6.2 mm and the material composition corresponded to

SA 178C. Steam side (internal surface) of the tubes contains very thin adherent dark grey colored

scales. The results of analysis steam side scales indicate high concentrations of Cu (19-28%) and

Ni (6 to 11%) along with Zn, P, Ca and Al in significant concentrations. There is much higher

concentration of Cu and Ni in steam side scales in tubes from flame impingement zone. All these

compounds are contaminated with magnetite scales.

28

Microstructural Studies

The microstructures of the cross-sections of unused, non-flame impingement zone and

flame impingement zone tubes were studied. The microstructures of the cross-sections of all the

tubes were observed at the seam area. In general, the microstructures of the seam areas show

contour shaped structures in which contours in opposite directions can be seen along a vertical

axis. Some typical microstructures are discussed below:

(i) Unused Tube: Contour type with well-defined central line structure is pearlitic-ferritic type with

no decarburization layer.

(ii) Non-Flame Impingement Zone Tube: Diffused line along the opposite Contours with no

decarburization.

(iii) Flame Impingement Zone Tubes: There are following cases:

(a) When the seam is not facing flame directly, there is a contour structure but no Evidence of

decarburization.

(b) When the seam is directly facing the flame, refinement of the grains along the vertical axis can

be seen with a well-defined decarburized layer. This tube appears to be most affected by flame

impingement. In all the tubes, there is reduction in wall thickness (5 to 8%) after operation.

Conclusions

1. No decarburization was found in the unused tube and non-impingement zone tubes. However,

in flame impingement zone tubes, a well-defined decarburized layer is present in area between the

opposite contours.

2. A clear decarburization layer is probably only when the seam of the boiler tube is directly facing

the flames.

29

CASE 2: Economizer Tube Failure

Tripping of boiler occurred as a result of economizer tubes failure. A huge rupture was

noticed as revealed by nearly fish-mouthed full opening. Figure 1 shows back view of the ruptured

area of the economizer tube. Figure 11 shows thinning of the cross-section of the tube. The total

length of the tube was 145 cm and the length of ruptured portion was 0.28 cm due to rupture, the

tube reduced its original thickness by 0.25 to 2.00 mm. Figure 1. Photograph showing economizer

tube in as received condition Figure 2. Photograph showing back view of the ruptured area of

economizer tube and greenish deposits SEM and EDX Studies shows EDX profile of the external

(fire side) deposits. The profile shows the presence of S, V and Mg in substantial concentration.

The source of S and V appears to be the heavy oil (fuel) which is usually rich in these elements.

Na, Ni, Fe and C are present in very small concentrations.

Figure 1. Photograph showing economizer tube in as received condition

Figure 2. Photograph showing back view of the ruptured area of economizer tube

30

Discussion

In the present scenario, the visual examination and the metallographic studies show that

there is nominal corrosion attack at the inner (steam) side of the economizer tube. This is further

confirmed by low value of scale thickness and scale density (20.0 m near rupture) obtained from

experiments. The corrosion activity in the economizer tube appears to be concentrated at the fire

side where huge deposits of corrosion products rich in sulfur and significantly rich in vanadium

were found. The inner surface around the ruptured areas is free from scales or corrosion products

therefore, the possibility of overheating is ruled out. It appears that the failure of economizer tube

is a case of H2SO4 dew-point in which there is condensation of acid on the outer surface of the

tube causing severe corrosion. In consequence, this resulted in the thinning of the metal to a state

where it could not bear the inside pressure of feed water and eventually got ruptured. A reduction

in wall thickness of the tubes, located inside the furnace support the initiation of corrosion from

fire side as a result of acid condensation. Furthermore, the external deposits on the tube helped in

lowering down the tube metal temperature and thus favoring acid condensation over the deposits.

Conclusions

1. No significant corrosion activity or abnormal scaling was observed at the inner side of the boiler

tube.

2. The relatively low temperature of feed water caused the lowering of the tube metal temperature

and promoted the condensation of H2SO4.

3. The thinning and rupture of the economizer tubes are the results of H2SO4 dew-point corrosion.

Recommendations

1. An increase in the economizer feed inlet temperature will help in reducing the severity of cold

end corrosion.

2. Sulfur content should be reduced to minimum which can be helpful in combating the acid dew-

point corrosion.

3. A powerful and efficient soot blowing system can reduce the possibility of acid dew-point

corrosion effectively.

31

CASE - 3:

Creep Failure of Boiler Reheater Tubes in a Power Plant

The boilers were commissioned about 24 years ago and had been in operation for more than

150,000 hrs. Following were the salient features of the boiler tubes:

Tube material: Medium carbon steel SA 192

Nature of the tube: Seamless

Outer diameter: 57.15 mm

Nominal thickness: 3.4 mm

Working pressure: 345 psig

Metallography

Photograph of the reheater tubes as shown in (Fig 3) in received condition. External surface

appeared reddish brown.

Figure 3. Photograph of the reheater tubes as in received condition

Steam Side Scales

The steam side scales contain dark grey magnetite. The inner surface is covered with small and

big pits with hematite stringers (Fig 4).

32

Figure 4. Photograph of the splitted reheater tube showing steam side

magnified view

Microstructural Studies

The microstructures of the boiler tubes were studied by observing the structures of cross-sections

through a photo metallurgical microscope. The main observations were as follows:

(i) Cross-section of boiler steam side: Ferritic-pearlitic structure, there is dispersion of carbides

and accumulation at grain boundaries.

(ii) Cross-section of boiler fire side: Carbides are dispersed in ferrite matrix and precipitated at the

grain boundaries.

(iii) Cross-section of boiler steam side: Pearlitic structure. Dispersion of carbides in the matrix,

precipitation of carbide at the grain boundaries and spheroidization of carbides. Presence of voids

is also indicated.

(iv) Cross-section of boiler fire side: Pearlitic structure. Huge dispersion of carbides,

spheroidization and accumulation of carbide at the grain boundaries.

33

Discussion

Microstructural studies reveal the following features:

(i) Structure is ferritic-pearlitic

(ii) Dispersion of carbides in the ferritic matrix

(iii) Accumulation of carbides at the grain boundaries

(iv) Spheropidization of carbides

(v) Presence of voids in some cases

The afore-mentioned observations provide strong evidence for a creep induced failure of type II

which appeared to be dominant during current operation of the boiler. No cracking or leakage was

found in the tube which indicates that stage III creep has not yet reached, so tubes can be used for

some more time.

Scale density and scale thickness values of the boiler tubes are high but still they can be operated

without cleaning.

Conclusion

The results of metallographic studies point out the involvement of creep type II behavior in

reheater tubes from boiler.

Recommendation

As the reheater tubes from boiler unit appear to be under deterioration due to the influence

of creep type II behavior. Therefore, the replacement of the tubes shall be required in near future.

A better tube material like a low alloy steel shall be a better choice at the operating boiler

temperature above 500 C.

34

CASE - 4: Failure of High Temperature Superheater Tube of Boiler

The boiler had been in operation for more than 15 years. It was found that superheater

tube had failed at 2 locations. The failed portions were from the same pendant.

The first portion of the failure was found at the bottom of the first loop near the

upstream side of the first bend.

The second portion of the failure was found at the bottom portion of the third loop

upstream of the weld point. This portion of the tube consisting of outlet and

inlet tubes were sent for investigation. The pipe sheared at the bottom

portion. From the photograph, it is observed that the failure of the tube occurred by

rupture at the bottom portion of the third loop upstream side of the weld joint (Fig. 5)

Figure 5. Inlet and outlet portions of the ruptured tube at the bottom of the 3rd

loop upstream of boiler, HTSH Pendent As received condition

35

SEM Studies

The inner section of the ruptured tube outlet and inlet are marked 1 to 5 indicating

different locations. (Fig. 6).

Figure 6. Inner section of ruptured super heater tube (HTSH Pendent)

The fractography of the tube sample at locations 1 and 3 was carried out by SEM. Whilst

at location 1 (expanded portion) there are clear indications of intergranular cracking originated

from the outside surface, the cracks at location 3 (protruded portion) are intergranular as well as

trans granular. The cracks at location 5 (inlet of tube) are trans granular. All cracks showed

multiple direction of propagation which are typically arising out of stresses in the scales and the

metal at high temperature.

Quantification of the Scales

The quantification of scale densities carried out near fracture surface of the tubes, as

determined by acid dissolution technique was found to be 483 and 219 mg/cm2 for super heater

inlet and outlet tubes (both third loop), respectively. The scale densities seem to exceed the limits

for chemical cleaning of the boiler tubes.

Discussion

The presence of thick scale deposition in the fractured boiler tubes would result in

overheating leading to fracture under operating pressure-temperature conditions. The presence of

Trans and intergranular fracture in SEM further proves the consequences of thick scale deposition

over team side.

36

Conclusions

(i) Optical and SEM studies and quantification of the scale densities indicate the

cause of superheater tube is overheating.

(ii) Overheating of the tube at the bottom of 3rd loop near the upstream side is due to

heavy scale deposition.

Recommendations

(i) In view of abnormal deposition of scales at various locations of superheater

tubes, chemical cleaning of all high temperature superheater tubes be carried out

to avoid failure in future.

(ii) Periodic evaluation of superheater tubes for its scale density and tube life should

be planned in every maintenance schedule.

37

Case 5 Poor material Quality and Deficiency in Fabrication

The present case documents an interesting analysis of failure of secondary superheater tube

in a power plant due to poor material quality and processing defects.

The material used for the secondary superheater tube conforms to ASTM A335 (Grade P5)

Boiler quality steel. The damaged tube had a crack of about 53 cms long, and had extended along

the length of the tube. There were no seals either on the outside or inside surface of the tube. No

swelling was observed in the cracked zone.

Further, on dissection of the tube longitudinally, typical crack on the bore surface was

noticed .The bore surface of the tube was also found to be uneven and noticeable ribs (alternate

elevation and depression on the tube wall) were detected. It was also evident that longitudinal and

discontinuous crack propagated along one of the pronounced ribs. There was no evidence of

corrosion or fitting on the bore of tube.

Microstructural analysis of the samples selected from the vicinity of crack and away from

it revealed almost identical structures, i.e. fine dispersion of alloy carbides particles in a matrix of

ferrite (Fig. 10). This illustrated that the tube was not overheated as the microstructure was quite

agreeable to this class of material as developed in commercial production of the tubes.

To substantiate the case of failure, metrological measurements in regard to the well thickness at

different locations of the tube in the vicinity of crack and at its sound portion as well as the

roundness error on the inside diameter at the sound portion were done. The observations showed

heterogeneity in measured values.

38

CHAPTER-6

CONCLUSION

It is observed from the various failures at various power stations. Research Institute

suggests them to follow the following practices during operation to avoid frequent failure of boiler

tubes & thus prevents the frequency of outages.

1. Proper operation of boiler within the permissible limits of various parameters.

2. Shrouding, shielding the areas, which are prone to erosion & proper inspection of tube elements

during overhaul, may help to reduce the outages.

3. Particular care for operation of oil guns, proper distribution of secondary air and total airflow

& proper soot blower operation may help to reduce outages.

4. Soot blowers operation, proper care to be taken from retraction or leaky poppet valve to avoid

erosion of nearby tubes may help to reduce tube failure considerably. Wall soot blowers should

be properly aligned for hot operation of the blower considering the expansion of furnace &

structure.

5. Sudden variation of loads & abnormal operation beyond permissible limits should be avoided.

6. Proper purging of boiler should be carried out during startup & after every shutdowns.

7. Feed water quality should be maintained within permissible limit.

8. Startup fuel atomization should be checked for its proper operation.

39

CHAPTER-7

REFERENCES

1. Carbon Steel handbook

2. L&T manuals

3. BHEL manuals

4. IOSR Journal of Mechanical and Civil Engineering (IOSR-JMCE)

5. NLC manuals

40