Introduction

Chapter - 1

INTRODUCTIONA 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 (1998)

The total installed capacity : 89,166.87MW

Thermal power

:55,969.48MW = 62.76%

Hydro

:21,891.08MW = 24.55%

Nuclear

:2,225.00MW = 2.49%

Diesel, wind & gas : 9,081.31MW = 10.18%

100%

Installed power generation capacity, however does not give a correct indication of the quantum of the reliable generation capacity (utilization factor). As the thermal power units are periodically required to be close down (called planned outages) for mandatory repair, inspection & overhauling. Consequently the availability of TPP is reduced to about 60% even under the best condition of operation & management. (The ratio of reliable capacity / installed capacity is called utilization factor). In India the average utilization factor is about 46% .So as such there exists a room for improving the availability. This would probably off set the gap in present demand & supply more economically.

The forced shut down of a boiler due to failure of components severely affects the progress through non-availability of power which is the basic need for growth in national economy. Some of the outages are due to tube failures in pressure parts most of which can be minimized by proper care and preventive steps of its causes.

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% or more of the above (1).

3. Outages due to boiler tube leakage are 75% or more of the above (2).

About The Process

Boiler is a composed of number of tubes. It covers the following heating zones.

1. Water Walls

2. Super-Heaters

3. Re- Heaters

4. Economiser

Water Walls

Almost all-modern power boilers are equipped with water walls. In large boilers water walls completely occur in the interior surface of the furnace providing practically complete elimination of exposed refractory surface. Water walls serve as means of heating and evaporating the feed water supplied to the boiler from economiser. Water walls usually consist of large number of vertical tubes arranged tangentially or approximately. They are connected at the top and bottom of headers. These tubes receive water from the boiler drum by means of down comers connected between drum and water wall lower header. In boiler the water walls absorb approximately 50% of heat released by combustion of fuel in the furnace. Heat so absorbed is used in evaporation of all or a relatively large percentage of water supplied to the boiler. The mixture of steam and water is discharged from top of water wall tubes into the upper wall header and then passes through riser tubes to the steam drum.

Types of water walls

a) Tangent tube construction

b) Membrane wall construction

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 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.

Water Walls

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. 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.

Types of SH & RH

These heating surfaces can be classified into convection and radiant type according to heat transfer process.

Even though the surfaces get heat by both radiation and convection, the ratio between them varies according to the location and temperature of flue gases at that location. The Reheater and SH placed above furnace which can view the flame is called Radiant type .The other surfaces are called as convection type. Radiant surfaces are located at high temperature region.They are widely pitched to reduce the velocity of gas and bridging the surface by the ash . They are arranged inline with least longitudinal pitch. They are called platen SH. The SH and RH can be arranged either horizontally or allowed to hung vertically. The vertical arrangements are simpler in supporting and allows for expansion . This arrangement is pendent type. Horizontal SH needs supporting of tubes at multi points to avoid sagging . Expansion movement should also be permitted with advantage of draining.

The SH which is placed at lower flue gas temperature region is called as Low Temperature Super heater (LTSH). The SH & RH can also arranged as ceiling or wall and they are termed as ceiling superheater or wall SH etc. accordingly.

Arrangements of SH and RH

Generally the heating surface can be arranged in line or staggered. Staggered arrangement requires fewer surfaces for the same duty but draft loss will be more. Also on load cleaning of surfaces, will not be effective. Hence In line or staggered arrangement is selected based on fuel fouling characteristic, operating cost of draft loss and cost of tube material used at location.

The surface can be designed to place in such way that the flow direction of flue gas and steam is in line parallel or opposite. Counter flow arrangement has advantages of minimum surface area requirement but the metal temperature at the leaving section is high compared to parallel flow. Counter flow arrangement is used in most cases except in final section where the metal temperature limitations call for parallel flow.

Economiser

The function of an economiser in a steam-generating unit is to absorb heat from the flue gases & add this as sensible heat to the feed water before the water enters the evaporative circuit of the boiler.

Earlier the economisers were introduced mainly to recover the heat available in flue gas that leaves the boiler. Provision of this additional heating surface increased the efficiency of steam generation, thus saving in fuel consumption. So the name economiser was christened. In the modern boiler (used for power generation) feed water heaters are used to increased the efficiency of the unit & feed water temperature. So the relative size of economiser is less than earlier unit. This is a good proposition as the heat available in boiler exit flue gas can be economically recovered using air heater, which is essential, for pulverized fuel fired boiler.

Location & Arrangements

It is usual to locate economiser ahead of Air Heaters & following the primary SH or RH in the gas stream. Hence it will generally be contained in the same casing as the primary SH or RH tubes.

Counter flow arrangement is normally selected so that heating surface requirement is kept minimum for the same temperature drop in the flue gas. Economiser coils are designed for horizontal placement, which facilitate draining of the coil & favours the arrangement in the second pass of boiler. Water flow is from bottom to top so that any steam formed during heat transfer can move along with water & prevent the lock up steam, which will cause overheating, & failure of economizer tube.

Types of construction of economiser Tube

1) Plain Tube

Plain tube economisers have several banks of tubes with either in- line or staggered type formation.

2) Welded fin- tube

Large no. of variations in this type was available in earlier days. Cast Iron shrouds were shrunk on mild steel tubes for use as economiser in stoker fired boiler. This type had good resistance against gas side corrosion but was heavy in weight. Modern boiler uses only plain or fin welded design as gas side corrosion is not faced due to high feed water temperature.

Materials Used for Boiler Tubes

Metallic iron is rarely found in nature. The principle ores of iron are heamatite (Fe2O3), magnetite (Fe3O4), limonite (2Fe2O3 3H2O) & siderite (FeCo3). The first step in the production of iron & steel is reduction of the ore with coke & limestone in blast furnace to produce an impure form of iron called pig iron. Pig iron is then remelted in a cupola furnace to produce cast iron. C.I. are alloys of iron & carbon containing approximately 2% to 4.5% carbons. Steels like cast iron , are alloys of iron and carbon containing upto 2%. Carbon . Steel is cast in an initially malleable mass. Steel production consists of removal of slag of excessive amount of carbon silicon & manganese, & impurities such as sulphur & phosphorus by chemical reactions. This is followed by addition of controlled quantities of carbon, silicon, manganese & aluminium to produce required composition. Other alloying elements are added in case of alloy steels.

Steels in the molten state can contain in solution relatively large quantities of gases, particularly oxygen & hydrogen. The solubility diminishes with falling temperature & gases released during cooling may be entrapped in the solidifying steel, giving rise to extensive porosity. All cast ingots contains a small proportion of cavities but these have little significance & are welded up by a pressure welding process during rolling or forging. It is necessary to remove most of the gases whilst the steel is still molten.

Effects of Alloying

The effects of alloying elements are numerous. a list of a few of the more important effects is given below.

1) To alter the transformation temperatures and time.

2) To modify the room temperature & Elevated temperature strength of given structures by

a) Stiffening the crystals.

b) Introducing complex precipitates, which tend to harden the steel.

3) To modify the type of oxide film formed on the surface of the steel & there by affects its corrosion resistance.

Alloying elements can be broadly classified into two groupsa) Austenite Stabilizers: Which have the effects of extending the temperature range over which austenite is formed. Such elements are carbon, manganese, nickel, copper & cobalt.

b) Ferrite Stabilizers: Which have the effect of extending the temperature range over which alpha & delta ferrite are formed. This consequently reduces temperature range over which austentile is formed. Such elements are Silicon Chromium, Molybdenum, Tungsten, and Titanium & Niobium.

Some of these elements for example chromium, molybdenum & vanadium also form carbides, which replace or modify the iron carbide in the structure.

Additions of the austenite stablising elements reduce temperature at which the austenite to ferrite change occurs and will consequently facilitate the formation of martensite with slower rates of cooling that are necessary with plain carbon steels. This also means that for a given cooling rate, larger cross- sections can be fully hardened uniformly throughout their section.

A) ChromiumChromium, although in itself a ferrite & carbide former, has a side effect of making the structural changes very sluggish. This suppresses the austenite to ferrite change in heat treatment easily . It is therefore extensively used in steels to be hardened & tempered. A further important property of chromium particularly marked when present in quantities above about 5% is to improve resistance to corrosion & oxidation.

Resistance to corrosion & oxidation of steel depends on the film of oxide formed on its surface . In carbon & many low alloy steels, this oxide film offers little or no resistance to atmospheric corrosion. At elevated temperature i.e. upto 575 degree C these steels have good resistance to oxidation in air or flue gases but above this, the rate of oxidation increase rapidly. The presence of chromium, however, in excesses of about 5% promotes the formation of a more protective oxide film . Although 5% is insufficient to obtain useful resistance to atmospheric & aqueous corrosion, it is enough to improve the oxidation resistance up to about 600(c. Further increasing the chromium content produces a more resistant oxide film & at 13% satisfactory resistance to mild corrosion media such as wet steam is achieved. Application of this type of steel is steam turbine blades, propeller & pump shafts, impellers & water turbine runners. Increasing the chromium content above 13% produces improved resistance to more corrosive media & at 28% chromium, satisfactory oxidation resistance at 1100 degree C can be obtained.

B) Nickel

In order to be able to utilize the good corrosion resisting properties of these high chromium steels and at the same time attain satisfactory engineering properties, it is necessary to re-establish the austentite region. This can be done by adding nickel. With an 18% chromium steel the addition of about 2% of nickel does this and produces a steel which can be hardened and tempered. This is the well known S80 steel (En 57) which is widely used for pump shafts in the marine field.

Maintaining a chromium level of 18%, the addition of increasing amounts of nickel extends the re- established austentite region until at 8% nickel the temperature of the change from austenite to ferrite is suppressed below room temperature and the structure at room temperature consists of grains of austenite. These steels are termed austenite and include the well-known 18/8 stainless steel.

Since the austenite-ferrite change, on which hardening and tempering are dependent, is suppressed below room temperature, these austentite steels are similar to the high chromium ferritic steels in that they cannot be hardened by normal heat treatment. They are different from the ferritic high chromium steels in that they are extremely ductile, and ideally suited for deep pressings and similar applications. In addition, since they are austenitic, they are non- magnetic and they have a high coefficient of thermal expansion and a low thermal conductivity.

Although these steels are not hardenable and have relatively low tensile strength at room temperature, they do have good elevated temperature tensile properties which, when combined with their good corrosion resistance suit them to application demanding this combination. These include superheater tubing and steam piping where the metal temperatures are in excess of 550(C, gas turbine components, and numerous types of pressure vessels employed in the chemical and allied industries.

C) Carbon

Carbon is not generally regarded as an alloying element because steel would not be steel without carbon. Nevertheless, it is appropriate in a discussion of alloying elements to note the specific effects of carbon on the properties of steel.

In general, an increase in carbon content produces higher ultimate strength and hardness but lowers ductility and toughness of steel alloys. The curves in figure indicate the general effect of carbon on the mechanical properties of hot rolled carbon steel.

Carbon also increases air hardening tendencies and weld hardness, especially in the presence of chromium in low alloy steel for high temperature applications. The carbon content is usually restricted to a maximum of about 0.15% in order to assure optimum ductility for welding, expanding, and bending operations. To minimize intergranular corrosion caused by carbide precipitation, the carbon content of austenitic (18-8 type) alloys is limited in commercial specification to a maximum of 0.08%, or even less, i.e. 0.03% in the extremely low- carbon grades used in certain corrosion- resistant applications.

In plain carbon steels in the normalised condition, the resistance to creep at temperature below 440(C appears to increase with carbon content upto 0.4% carbon. At higher temperature there is but little variation of creep properties with carbon content.

An increase in carbon content lessens the thermal and electrical conductivities of steel and increases its hardness on quenching.

C) Silicon

Silicon contributes greatly to the production of sound steel because of its deoxidizing and degasifying properties. When added in amounts up to 2.5%, the ultimate strength of the steel is increased without loss in ductility. Silicon in excess of 2.5% causes brittleness, and amounts higher than 5% make the steel nonmalleable.

Resistance to oxidation and surface stability of steel is increased by the addition of silicon. These desirable effects partially compensate for the tendency of silicon to lower the creep properties of steel. Silicon increases the electrical resistivity of steel and decreases hysteresis losses. Silicon steels are, therefore, widely used in electrical apparatus.

E) Manganese

Manganese is an excellent deoxidizer and sulfur neutralizer, and improves the mechanical properties of steel, notably the ratio of yield strength to tensile strength at normal temperatures. As an alloying element, manganese serves as an inexpensive means of preventing red shortness (brittleness, now more commonly known as hot shortness). It improves rolling properties, hardenability, and resistance to wear. However, manganese increases the crack sensitivity of weldments particularly with steels of higher carbon content.

Unlike silicon, manganese benefits the creep properties of steel. It does not appear to have any specific influence on the resistance to oxidation or corrosion of steel.

F) Titanium and Columbium (Niobium)

These are potent carbide-forming elements. Titanium is also a good deoxidizer and denitrider. These elements are most effective in the chromium-nickel austenitic alloys (18-8 type) where they react more readily with carbon than does chromium. This allows the chromium to remain in solid solution and in the concentrations necessary to maintain the stainlessness (corrosion resistance) of the steel.

Titanium and columbium (or columbium plus tantalum) are sometimes used to reduce air- hardening tendencies and to increase resistance to oxidation in steel containing upto 14% Cr. These elements seem to have a beneficial effect on the long time high temperature properties of chromium- nickel stainless steels. Both columbium and titanium have been used in some of the super alloys to improve high- temperature properties.

Chapter - 2

BOILER TUBE FAILURE MECHANISMS

Identification1) 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.

Superheaters 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

(Fig. 2.3).

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) High Temperature Creep (Stress Rupture)A small fracture may be associated with a blister, while a large fracture could have a thick-edged, "fish mouth", longitudinal crack. The area around the fracture may have an alligator hide appearance, with significant oxide scale penetration. The root causes for high temperature, longer term failure such as these are the following

High heat flux into a section of the boiler that could have used a higher grade of steel

Excessive hot gas flow through an area that is plugged

Excessive heat absorption from an adjacent lug, or other welded attachment

Partial pluggage from blockage or internal scale

3) 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.

4. Caustic Corrosion (Water-side Corrosion) (Fig. 2.4a)

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.

5. Hydrogen Damage (Water-side Corrosion)

Hydrogen damage is a serious and costly type of water side corrosion that affects generating tubes in sub critical boilers operating above 124.11 bar or 1800 psig. Lower pressure units can also experience hydrogen damage, but it becomes more uncommon as the operating pressure is reduced.

Hydrogen damage will occur whenever acidic conditions exist in the boiler

Clean tubes are far less susceptible to hydrogen damage than heavily deposited tubes. Certain types of adherent and nonporous deposits appear to promote localized hydrogen attack more readily.

The failures remove a chunk of tube, almost like a window that has been placed in the tube. The failure has a thick edge fracture that removes the heavy deposit that lead to the failure. The failure's root cause is

(Fig. 2.5)

Boiler water chemistry that has turned acidic, rather than its normally caustic level. Hydrogen damage will not occur under alkaline conditions.

In-leakage of condenser water which tends to be acidic

Contamination from a chemical cleaning procedure

Higher heat flux which helps to form the deposit in the first place. Note that if the deposit is not there to begin with, the excursion to low pH by itself will not cause hydrogen damage.

The dirtier the boiler water, the sooner failures could occur.

Hydrogen damage seldom causes any significant wastage of the tube wall, making it difficult to detect using ultrasonic devices. Sometimes hardened dense oxide plugs of magnetite dispersed with copper form directly over hydrogen damaged areas.

6. Pitting Localised corrosion (Water-side corrosion)(Fig.2.6)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.

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

7. Stress Corrosion Cracking (Water-side Corrosion) (Fig. 2.7)

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 boiler steam drum carry over

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

8. Low temperature corrosion (Fire side) (Fig. 2.8)

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.

9. Water wall corrosion (Fire side) (Fig. 2.9)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 zone of combustion where there is too little oxygen

High level of chloride or sulfides in the fuel being burned

10. Vibration Fatigue (Fig. 2.10)

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

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

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

11. Thermal Fatigue (Fig. 2.11)

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

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

Rapid change in the feed water temperatures to the economiser, i.e. maloperation of the pre-boiler system

12. Corrosion Fatigue (Fig. 2.12)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,

There is residual stress left over from fabrication

Internal pits from dissolved oxygen or acidic corrosion from the pre-boiler circuit aggravate the cracking process in the water cooled tubes.

External corrosion in steam cooled units aggravates the cyclic flexing where the tube enters the header.

13. Maintenance Cleaning Damage (Quality Control) (Fig. 2.13)When accumulations need to be removed with force, it is possible that tubes will be gouged, or dented. This point of stress will be a weak link that eventually gives way. Some of the most common causes are

Hammering on a tube or its supporting lug

Chiseling at fused material

Poking and vacuuming ash/dust/debris out of tight spaces

Aqua-blasting

14. Chemical Excursion Damage (Quality Control) (Fig. 2.14)Initially, the damage will appear as a general pitting of the tubes' internal surface, but in time the chemical contamination will act on the most sensitive locations and result in such mechanisms as hydrogen damage, stress corrosion cracking, caustic corrosion, corrosion fatigue, etc. The causes are

Mal operation or mechanical malfunctions of the pre-boiler water treatment system.

Insufficient neutralization of boiler wash chemicals prior to returning a unit to service.

15. Material Defects (Quality Control) (Fig. 2.15)

When the wrong material is installed, the result can be a stress rupture, and if the defect is a flaw, the failure may appear as a fatigue failure. In either case, the cause is -

Poor QA on the part of the manufacturer

Material fabrication

Storage

Installation

16. Welding Defects (Quality Control) (Fig. 2.16)

If the defect is most notable on the inside, it can become a failure from the internal scale build-up, and resultant corrosion, or corrosion fatigue failure. If the defect is with the integrity of the weld itself, the failures often appear as a brittle failure, where stress is concentrated in a small area. Causes again relate to quality control

The procedure

Weld material used

Preparation of the tube ends before the first pass

17. Steam/Condensate Erosion

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

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

Insufficient documentation to justify the economics of not waiting to bring the unit off-line to attend to the tube failure.

18. Exfoliation (Fig. 2.17)

The above list of 17 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 superheater, 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

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.

Difference in the coefficient in expansion between the internal magnetite layer and the tube metal, resulting in spalling of scale when the unit cycles

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

Chapter 3

METALLURGICAL FAILURE INVESTIGATIONS OF

BOILER TUBES IN THERMAL POWER PLANTS

INTRODUCTION

Although failures/leakages may occur in a relatively low percentage of the total boiler tubes used in a power plant, they may cause a critical breakdown resulting in forced shutdown of generation. Failures are of extreme importance to plant operators, maintenance Engineers, fabricators and suppliers alike. People learn by mistakes and hence a correct diagnostic analysis of failure help in their future prevention.

All of the types of failures that may occur and all of the conditions that promote them are too numerous to list. However, in a broad generalization one may say that the following factors may cause service failures :

i) Deficiencies in design lay out, manufacture and erection of the equipment;

ii) Poor material quality and deficiencies in fabrication;

iii) Incorrect material selection;

iv) Deficiencies in operating conditions;

v) Deficiencies in maintenance.

Often a combination of the above factors may be responsible for failures.

A failure investigation and subsequent analysis should determine the primary cause of failure, and based on the determination, corrective action should be initiated that will prevent similar failures.

Stages of an analysis

Although the sequence is subject to variation depending on the nature of specific boiler tube failures, the principal stages that comprise the investigation and analysis of a failure are as follows:i) Collection of background data and history

ii) Visual or preliminary examination of the damaged/failed tube

iii) Non-destructive inspection

iv) Selection of specimens from the tubes :

a) For microscopic examination and analysis (fracture surface, secondary cracks and other surface phenomena);

b) For mechanical testing including hardness and tensile testing

c) Chemical Assessing (bulk, local surface corrosion products, deposits or coatings, etc.);

v) Analysis of the evidence, formulation of conclusions and drafting the report.

SPECIFIC CASE STUDIES

Case I: Failures Involving Tube Ruptures

Sudden rupture of a tube in a steam generator is a serious failure, because the steam generator must be shut down immediately to avoid -

(a) Erosion and steam-cut on adjacent tubes by escaping steam;

(b) Overheating of other tubes banks because of a loss of boiler circulation;

(c) Damage to other components in the system resulting from loss of working fluid.

Such sudden ruptures can be caused by overheating.

a) Economiser Intermediate Box Drain Tube

The economiser intermediate box drain tube in the power plant had suffered a rupture along the longitudinal axis of the tube (Fig. 1). The length of the ruptured portion was approximately 330 mm. The tube had opened out in the manner of a 'thick-lip' rupture. There was a tightly adhering 'black-scale' on the outer surface of the tube. Boiler quality carbon steel, conforming to the specification B.S. 3602-1962 grade Hot Finished Seamless 27, was used as the material of construction for the economiser tube.

Metrological measurement of the tube had established considerable amount of 'thinning and bulging" out of the wall of the subject tube.

Microstructural examination of the specimen selected judiciously from the extreme edge of the rupture covering the external surface revealed "inter crystalline penetration of oxide scales (oxide-rooting) to an appreciable depth from the external surface of the tube (Fig. 2).

It also exhibited considerable decarborization of the material, Microstructure in and around the rupture area of the tube represented globular carbides indicating "spherodization" of the carbide constitute of pearlite within and at the boundary of the ferrite grains (Fig. 3). Further, the microstructure away from the ruptured zone illustrated a ferrite-pearlite structure which is normal of this type of steel (Fig. 4).

In the present case, the economiser tube was placed horizontally. Sometimes "Steam Blanket" preferentially might be formed inside the tube wall. This in turn, might have deteriorated the heat transfer characteristics of the subject tube material, and caused localized 'over heating'.

The tube had failed as a result of prolonged localized overheating. Due to 'overheating' and consequential 'oxidation' and spheroidization the material could not withstand the working stress, and failure occurred. This type of failure can be minimized by improving upon the tube layout design. The economiser tube may be changed into a vertical position instead of horizontal as in the present case to avoid possible formation of steam-blanket in the pipe wall.

b) Secondary Superheater Tube

The boiler in the power plant used pulverized coal as fuel. For the construction of superheater tubes, boiler quality steel (specification B.S. 3059/12) was used. The tube had ruptured characteristically with a 'fish mouth' type which was about 39 cms. long and 8 mm wide at its maximum. The rupture had extended along the length of the tube and was accompanied by noticeable localize dwelling (Fig. 5). The characteristic features of the rupture indicated that the rupture had taken place after localized 'ballooning' of the tube wall. There were no seals either on the outside or inside surface of the tube. Further, variation in wall thickness in the zone rupture was noticed.

Microscopic examination of the specimens taken from the vicinity of rupture showed coalescence of fine particles of alloy carbides in the matrix of ferrite (Fig. 6), while normal microstructures consisting of fine dispersion of alloy carbide particles in a matrix of ferrite at the areas away from the ruptured zone (Fig. 7).

This evidence clearly indicates that the effected area has been continuously heated below the lower critical temperature (A1) of the steel for a prolonged period in a much localized area of the material. Due to 'spheroidization', the material strength in the affected region could not cope-up with the operating stress at the elevated temperature for long duration. Thus the tube material was subjected to slow and progressive plastic deformation under the influence of operating stress and temperature, which resulted in the weakening of the tube, and its eventual rupture.

To minimize the occurrences of such failures, proper temperature monitoring systems by installing built-in thermocouples on the tube walls should be incorporated.

Case II 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 A 335 (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. The roundness error on the inside diameter of the round region of the cracked tube was in the order of 0.60 mm. This is represented graphically in Fig.11.

Development of ribs on the bore surface of the tube during tube production might have a contributory effect towards the failure of this nature during services. In addition to above causes, leakages/ruptures of boiler tubes in the power plants can occur due to (a) embrittlement arising out of hydrogen damage, (b) water side corrosion by feed water, (d) fire side corrosion resulting from combustion of fossil fuel, (d) abrasives erosion of superheater tubes results from impact by particles of fly ash entrained in the flue gases, (e) stress corrosion cracking of the tubes where feed or condensate can collect.

Remarks

The foregoing illustrations have discussed many causes related to failure. Many failures in steam systems involve more than one failures process the so called multiple mode failures. Certainly many types of failures were not discussed and no attempt could be made to illustrate all the types of failures possible. The causes that promote failures can indeed be many and complex and attempt has been made to illustrate and discuss some of the more common failures and the related causes.

Usually the most spectacular or dramatic failures are carefully studied while little emphasis is placed on the common failures. Many analyses of plant or operational failures usually add upto high separational costs due to time loss resulting from make-shift maintenance or repairs in order to continue operation. Thus metallurgical analysis of such failures is all the more important.

Chapter - 4

SOME CAUSES OF BOILER TUBE FAILURE WHEN SEEN

THROUGH A POWER STATION CHEMIST'S EYE

INTRODUCTION

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

i) Dissolved O2 pitting

ii) Stress corrosion

iii) Ductile corrosion

iv) H2 embrittlement etc.

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

a) Feed System

b) Drum

c) Steam and Condensate

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.

ParticularsBoiler Pressure 60 kg/cm2 and underBoiler Pressure from 60 kg/cm2 and above

PHCond.HSilicaPHCond.HSilica

Make up7.00.5NilNil7.00.5NilNil

Feed8.8 9.0Upto 4.0NilNil8.9 9.0Upto 2.5NilNil

Drum9.5 9.9Upto 100Nil*9.3 9.5Upto 25Nil*

Steam8.8 9.0Upto 4.0Nil0.028.9 9.0Upto 2.5Nil0.02

Condensate8.5-8.7Upto4.0NilNil8.5 8.7Upto 2.5NilNil

Scale : Cond. : 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.

No.Type of DosingChemical DosedPlace of DosingUltimate Effect

1.VolatileAmmonia

Morpholine

Cyclohexyl amineFeed System at the suction of feed pump

To increase pH

2.VolatileHydrazine hydrate inhibited or treated hydrazineFeed System at the suction of feed pump

&

In condensers at the suction of Extraction pumpTo scavange oxygen

&

To increase pH

3.Non-volatileTri-sodium Phosphate

Sodium HydroxideDrumTo increase pH to maintain residual phosphate.

4.Non-volatileSodium Hydroxide &

Sodium-di hydrogen

Phosphate, Hexameta

PhosphateDrumTo decrease pH, to maintain residual phosphate

When dosed properly, the required parameters can be obtained and conditioning becomes proper, resulting in 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.

ChemicalPossible ImpuritiesEffect or Dosing

AmmoniaHardness, SilicaVery slow increase in pH

Rapid increase in conductivity.

Injection of silica in System/

PhosphateFree Sodium Hydroxide and chlorideUnstable pH condition

Increase in conductivity

Foaming action in drum,

Free sodium hydroxide in Steam

All above conditions lead to tube failure,

Effect of Excess Dosing

ChemicalNormal ReactionEffectRemarks on effect

AmmoniaSimple addition

NH4OH + H2O NH4OH H2O

High pH & Conductivity

(Dilution)Caustic corrosion

Hydrazine N2H4 + O2 = N2 + 2H2O

2N2H4 = N2 + H2 + 2NH32N2H4 +H2O = 2NH4OH + N2Oxygen Scavenging

Hydrogen in steam

Ammonia formationNone

Stress corrosion

None

PhosphateNa3PO4 + H2O = NaOH + NaH2PO4High pH & ConductivityCaustic attack carry over foaming causing starvation

When we analyse 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

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.

OTHER FACTORS LEADING TO TUBE FAILURE

The main amongst this is unnecessary increase in dissolved oxygen level. Dissolved oxygen, tends to create hydroxyl ions with the available electrons.

O2 + 2H2O + 4= 4 (OH)

And each hydroxyl ions so form, tends to stabilize with positively charged metal ions aiding to corrosion/deposit,

M(Metal) = M+ + e

M+ + (OH) = M(OH)

The metal hydroxide which is relatively less soluble has a tendency of forming a deposit, resulting improper heat transfer and failure of tubes.

Dissolved carbon dioxide present in water/steam forms H2CO3 commonly known as carbonic acid, this then forms metal carbonates and ultimately forms metal hydroxide. The effect of CO2 on iron (Fe) is as under

CO2 + H2O = H2CO32Fe + 2H2CO3 = 2Fe CO3 + 2H22FeCO3 + 5H2O + O = 2Fe (OH)3 + 2H2CO3as H2CO3 is double in volume the process multiplies leading to further corrosion.

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.

Deposition problems can be avoided if

1. Hydraulic test water, superheater fill water, and desuperheater spray water are free of solids. It is preferable to use DM water for these operations.

2. Drum internal and drum water level controls are maintained in good working order.

3. Silica concentration in the boiler water is held within acceptable limits.

The iron oxide coating in the internal surfaces of boiler tubes is to be maintained. This oxide (magnetite Fe3O4) is normal product that forms on steel exposed to boiler water. It protects the surface from corrosion. The magnetite coating is damaged most often by boiler water salt that becomes corrosive when concentrated. Graph 1 show the relative corrosion rate of carbon steel as acid and alkaline concentrations varies in the boiler water.

In the pH range from low acid to low-alkaline concentrations the oxides on boiler tubes are fully protective. When the pH is excessively high or low, the protective oxide is consumed by the corrosive action of the acid or alkaline salts in the water. Corrosion rates under these conditions accelerate with increasing concentration. Thus the primary purpose of a boiler water treatment program is to maintain a low concentration of potentially corrosive salts, so that the oxide coating remains intact.

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.

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 non-destructive 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 concentration of hydroxide salts such as sodium hydroxide in the boiler water is too high. Ultrasonic tube-wall thickness checks can detect tubes with metal loss. Proper boiler water treatment can minimize further corrosion.

MINIMISING CORROSIVE ATTACK

Corrosion concentrations of salts generally exist at tube surfaces only when these inter-related 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.

CAUSES OF HIGH AND LOW pH

The primary cause of acidic and caustic boiler water condition is condenser leakage. Raw cooling water that leaks into the condenser essentially ends up in the boiler water. The water source determines whether the in-leakage is either acid producing or caustic producing. Fresh water from lakes and rivers, for example, usually provides dissolved solids that hydrolyze in the boiler water environment to form a caustic, such as Sodium Hydroxide. By contrast, sea water and water from Re circulating cooling water systems, with cooling towers contain dissolved solids that hydrolyze to form acidic compounds.

Strict tolerance levels on condenser leakage should be established for all high pressure boilers. Set a limit of 0.5 ppm for short periods only. Shut down the steam generator immediately if the plant's surface condenser leakage produces more than 2 ppm of dissolved solids in the feed water.

Another potential source of acidic and caustic contaminants is the make up demineralizer, where regenerate chemicals such as sulphuric acid and caustic soda may inadvertently enter the feed water system. Chemicals incorrectly applied during boiler water treatment also can be corrosive. For example, Sodium hydroxide is used in conjunction with sodium-phosphate compound to treat boiler water. Corrosion can occur if the sodium hydroxide and sodium phosphate are not added to the water in the proper proportion.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.

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, with a corresponding pH as shown in the Graph 2.

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. Graph 3 & 4 show that with only 15oF difference between the bulk fluid and tube wall temperatures, sodium hydroxide might concentrate dramatically at the tube surface. 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 is 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.

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.

4. 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 recycles line, permits removal of both erosion products and oxygen from the feed water during steam-generator start-up operations.

Importance of Water Analysis

A comprehensive water analysis program should be maintained to assure that feed water and boiler water chemistry are held within prescribed limits, and conduct water tests as per programmed schedule, for pH, oxygen, silica, copper and total iron, and total solids.

The gas side corrosion occurs in oil fired boilers. High temperature corrosion occurs due to the presence in oil of sodium and vanadium, the oxides of which form flux with the protective oxide of the material, thereby causing further attack on the material by the gas. This can be prevented by using low vanadium content oil or by employing certain additives like MgO powder in the oil. The MgO powder can be sprayed through a separate nozzle into the furnace or magnesium wires can be burnt in the furnace. Low temperature or dew point corrosion occurs in oil fired boilers in the air heaters or economizers if the flue gas temperature approaches the dew point temperature. Sulphur in the oil transforms to SO3 in the furnace and then to sulphuric acid with the water vapour in the flue gas at low temperatures and causes corrosion. Low temperature corrosion can be avoided by controlling the inlet temperature of the feed water to the economizer, or counter flow existing in economizer with respect to gas is made as reversed or parallel flow of water, which gets higher temperature at low temperature gas end and helps preventing low temperature corrosion.

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.

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.

Boiler manufacturers help limit solids carry over by paying considerable attention to the design of drum components. To avoid solids contamination from operational point of view three factors are of particular importance.

1.The need for high quality Hydrostatic Test WaterWater used for hydrostatic tests will be evaporated from non-drainable sections during the next firing period, and the solids or salts in the water will concentrate. Hence, water added to the superheater or reheater should be of condensate quality and dosed with hydrazine (200 ppm) and ammonia to produce a pH of 10.

2.The need for High Quality De-superheating spray waterAny solids in the spray water will adhere to superheater surfaces or be carried through the unit in the steam and be deposited in the turbine. Since the source of spray water is the boiler feed water system, feed water should be treated only with volatile chemicals for pH control. All solid chemicals used for treatment must be introduced into the system down stream of where the spray water is removed.

In the event condenser leakage causes the total amount of dissolved solids in the hot well to exceed 500 ppb, increase the rate of blow down and discontinue the use of spray water. Use other means for controlling steam temperature including load reduction until the condenser is repaired and the total solids level in the hot well is below 500 ppb.

3. The third and most important operating factor is to keep solids contained in the boiler feed water from entering the superheater. Steam drum internals reduce the mechanical carry over of moisture content upto 0.1%. Vapors carry over is completely selective since it depends on the solubility or volatility of a specific constituent in the steam. Except silica vaporous carry over of solids dissolved in the boiler water is negligible below an operating pressure of 2600 psig assuming that the concentration of solids are within recommended limits. The volatility of silica is much higher than that of other solids and it increases exponentially with boiler pressure.

In conclusion, you can avoid many potential operating problems by continuously monitoring steam quality. Increase in solids level even if within prescribed limits, may provide an early indication of some carryover abnormality.

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

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 first hand 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.

Data Required for InvestigationThe 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

c) Composition of the flue gas

d) Amount of excess combustion air

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

f) Normal power output and fluctuation in steam demand

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

-o0o-

Repair GuidelinesIntroductionAll 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.

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 (Fig. 1).

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".

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.

3. Repair of Tube BlistersInternal 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.

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 in the these deposits before making the final weld to the tubes.

Chapter 5Causes of Tube Failure

1. Overheating.

2. Erosion.

3. Corrosion.

4. Material Defects.

5. Manufacturing Defects.

Overheating

Overheating can be localised, extensive, prolonged or of a short duration. Metallographic analysis indicates the approximate temp. to which the tube was subjected before failure occured. Observation of the grain growth & microstructure of the failed tube material also indicates if the overheating was of a prolonged or short duration.

Waterwall tube failure results in a burst with a fish mouth opening. Occasionally cracks will also appear up to length of 2 Mts. on either side of the burst.

This may lead the power station authorities to apprehend that the tube is of the CRW type. Bursting occurs due to excessive reactive force cause by change of state from water to steam. In case of SH tube failure takes the form of a narrow opening with multiple stallite cracks.

The reasons for overheating of water wall or SH tubes are,

1. Chocking with foreign material.

2. Starvation due to,

a) Improper circulation.

b) Insufficient flow

3. Flame impingement

4. Secondary burning of fuel.

5. Other causes.

Choking with foreign materials

Foreign materials like mill scales, weld slag, sand, electrodes bits, rust products, chips, small tools, nuts etc. Which collect at the bends or weld joints where the internal cross section is restricted will cause choking of tubes. These materials enter the tube during various stages of manufacture, shipping and / or erection. Choking of tube with foreign materials will impede the flow fully or partially & cause overheating.

Precautions can be taken to mitigate tube choking at various stages of manufacture, shipping, storage & erection. By using TIG root welding for all SH coils at shop & site, the problem of choking can be minimised by eliminating the construction at the weld joints due to excessive weld penetration to check the blocking of tube with foreign material an instrument called contract flow meter (developed by CE research lab UK, & manufactured by Land Pyrometers LTD, UK) can be used. This meter can be used during the commissioning of new boiler to ensure that there is not blockage of & in the case of operating boiler, it can be used during overheating.

Starvation due to improper circulation:-

Insufficient circulation in the water walls may lead to departure from onset of nucleate boiling & may lead to overheating. Which in turn will result in tube failures. Where the failure are traced to improper circulation, the same can be improved in the region of water wall by providing additional downcorners / spider tubes to the existing downcomers.

Starvation due to insufficient flow:-

Starvation can occurs in SH tubes due to an insufficient flow resulting in overheating. This is generally observed in the binder tubes of the platen SH. These binder coils have a number of bends & are longer in length than the other coils in the platen. The flow through these binder coils is, therefore, inadequate. The prolong overheating in such tubes results in creep failure.

Such failures can be avoided by replacing the long binder tubes with shorter tubes, which in turn increases internal flow, & prevents overheating.

Overheating can also be avoided by allowing cooler steam through the wrapper tubes of platen to better cooling of the tube materials.

The materials of the bottom portion of the outermost coils of platen can also be replaced by stainless steel to enhance their life since the bottom most portion faces direct radiation from the furnace.

Flame Impingement

Water wall failures occurs mostly near the burners. This is due to the flame impingement from burners, which get distorted in service. To avoid such failures new burner nozzles such as honeycomb types, which resist distortion, are now used.

Additional peep holes can also be provided for better monitoring of the flame & observation of the burner tip.

Arrangements could be made to supply mellowing air to bring down air temperature wherever necessary so that the combustion front can be kept away from the burner nozzles.

Secondary burning of fuel:-

In certain cases oil from the oil gun may flash on to the tubes & then burning takes place which results in overheating the tubes. Even in coal fired boilers, the unburnt fuel particles may catch fire at the top of the furnace or in the second pass causing secondary combustion, explosion, or overheating of the tubes. This can be avoided by proper control of the atomisation of oil, coal particle size & the firing rate.

Excessive air

Excess air plays an important role in the heat absorption pattern of various zones of the boiler. Too much of excess air leads to cooler furnace & higher heat absorption rates in convective paths. Too little of excess air leads to higher furnance temperature resulting in higher radiation, heat absorption & slagging problems.

In oil fired boilers too much of excess air is favourable to the formation of SO3 due to the increased availability of O2 thereby promoting a higher rate of low temp. corrosion. To avoid such failure O2 content in flue gases should be measured periodically during operation & adjustments made to achieve design values as closely as possible. Further, to avoid overheating the flue gas temperature in different zones should be closely monitored & kept within the design limits.

Internal DepositsInferior quality of feed water leads to internal deposits of salts & silica in the water wall tube. This internal deposit will cause overheating of water wall tubes leading to failure. To avoid this, the feed water of boiler water quality should be maintained within the allowable limits as per the international standards.

The carryover of salts by steam can cause deposits in the tubes with consequent overheating & failure. To avoid this, the salts, content in the drum water should be maintained as per the standard operation with high water levels in drum could lead to carryover of water drops & dissolved solids leading to internal tube deposits in SH tubes. These deposits hinder heat transfer & lead to increase in metal temperature & consequent tube failure. Hence it is necessary to restrict the drum WATER LEVEL TO THE prescribed limits under all operating conditions.

Other causes

Mal-operation can sometimes leads to overheating & results in tube failure. When high-pressure heaters are out of service, the convection SH O/L temperature can shoot up leading to overheating of tubes. This can be avoided by suitable control of the excess air & the boiler load. During hot restart if the flow of auxiliary steam from the drum tap off point is high it will result in a reduced flow through the SH which in turn will lead to overheating.

EROSION

Erosion is a second major cause of tube failure. The tube wall thickness gets reduced due to erosion & when the thickness is not sufficient to withstand the operating pressure and temperature of the tube, the tube will fail.

Erosion of SH & economiser tube may be due to following reasons

i) Flue gas erosion.

ii) Erosion due to steam or water.

Flue gas Erosion

The rate of erosion is proportional to the cube of velocity. The ash content of the Indian coals is of more abrasive in nature containing high silica & alumina. Due to the above, if the velocity of the flue gas at narrow gaps between coils & walls & SH coils and ash hoppers below them is high, then erosion may occurs in these zones. Therefore the boiler have to be designed with 15m/s velocities as for as possible.

A typical ash analysis data is given below :

Silica -- 55.5 to 56.5%

Alumina -- 27.3 to 27.9%

Unburnt carbon -- 4.4 to 6.2%

FeO

-- 5.3 to 6.7%

Lime

-- 1.37 to 2.16%

Sulphates

-- 0.5 to 0.68%

The flue gas erosion in the horizontal SH & economiser can be prevented by providing baffles. The flue gas erosion in the bands of the convection SH in the horizontal pass can be prevented by increasing the height of refractory lining of the ash hoppers in front of the coils.

Erosion due to steam or water

Whenever there is a tube failure the water or steam from the faulty tube escapes in the form of a high velocity jet & when it impinges on the adjacent tube they get eroded. If the boiler is not shutdown immediately after detection of the failure & allowed operating for a protected period the damage due to steam or water erosion will be considerable.

Additionally, sometimes leakage from the soot blowers or wall blowers causes erosion of water wall, SH or economiser tubes. In some boiler, vertical bar type soot blowers have caused tube failures in the horizontal SH & RH & to overcome this the sort blowers should be moved from the ceiling to the sidewalls.

Corrosion

This can be mainly grouped into two types

1) External corrosion due to depositing of chemicals.

2) Internal corrosion taking place inside the tube due to impurities in steam and water.

1) External corrosion due to depositing of chemicals carried by ash.

On review of ash analysis detailed under flue errosion, it can be seen that ash consists of sulfate up to 0.5 to 0.681. This type of corrosion results mainly from the deposits of ash on tube surface. The deposits may be classified either as slagging or fouling.

Slagging

This is the deposition of molten or partially fused particles of fuel constituents (non-combustible) on furnace tube surface. Though it is usually is associated on furnace tube surface, slagging can also occurs in screen tube and in the super heater when molten ash carried over into these solutions and is exposed to excessively high gas temperature.

Fouling

Fouling on other hand is the condensation of combustible constituents such as sodium sulphate on fly ash particles and on boiler tube in area of the unit where temperature are such that the constituents are remain in the liquid state. The combustibles, fly ash, and flue gas react chemically to form the deposit.

Phosphate deposit

This is