CONDENSER

Why Vacuum in Condenser?

In order reduce the back pressure, below the atmospheric pressure, for increasing work done and efficiency, the steam from the turbine has to be exhausted in a closed vessel, where it will be conveyed by the cooling water. Condensation of steam in a closed vessel enables expansion of steam to a lower back pressure, and hence temperature. This result was expected because one kg of steam at 0.1 bar occupies 19.9m3 volume, where as after condensation it will occupy 0.001016 m3 of volume. These has enormous striptease, (19.9/0.001016=9,500 times approximately), accomplishes two important practical results.

CONDENSER: A closed vessel in which steam is condensed by abstracting the heat and where the pressure is maintained below atmospheric pressure is known as a condenser. The condenser plant must be capable of producing and maintaining a high vacuum with the quantity of cooling water available and should be designed to operate for the prolonged periods with out trouble.

A desirable feature of good condensing plant is:

1. Minimum quantity of circulating water.

2. Minimum Cooling surface area per KW capacity.

3. Minimum auxiliary power.

4. Maximum steam condensed per m2 of surface area.Advantages of CONDENSER:

1. The condensate steam from the condenser can be used as feed water for boiler.

Using the condensate as feed for boiler the cost of power generation as the condensate is supplied at higher temperature to the boiler

2. It lowers the cost of supply of cleaning and treating of working fluid as is readily available for further use without treatment.3. It increases the efficiency of the cycle by allowing the plant to operate on largest possible temperature difference between source and sink.4. The efficiency of the plant increases as the enthalpy drop increases by increasing the vacuum of the condenser.

The specific steam consumption of the plant also decreases as the available enthalpy drop or work developed per kg of steam increases with the decrease in back pressure by using condenser.5. It is far easier to pump a liquid than a steam.6. The deposition of salt in the boiler is prevented with the use of condensate instead of using the feed water from outer source which contains salt.

7. The use of condenser in steam power plant reduces the overall cost of generation by increasing the thermal efficiency of the power plant.Disadvantages of' the condenser:

1. The capital cost is more.

2. The maintenance cost and running cost of this condenser is high.

3. It is bulky and requires more space.

The difference between saturation temperature corresponding to condenser vacuum and temperature of condensate in hot well is called condensate depression.

The pressure drop from inlet to exit of condenser is called steam exhaust resistance of a condenser. The partial pressure of air at the bottom of the condenser cannot be neglected.

As the air-steam mixture moves through the condenser and the steam is condensed, its temperature decreases owing to decreasing partial pressure of saturated steam.

This is due to increase in relative content of air in the mixture. The pressure also decreases due to resistance to flow of steam.

EFFECT OF AIR LEAKAGE1. It increase in the condenser pressure or back pressure of the turbine with the effect that there is less heat drop and low thermal efficiency of the plant (reduces work done per kg of steam).2. The pressure of air lowers the partial pressure of steam and its corresponding temperature which means steam will condense at lower temperature and that will require greater amount of cooling water.

{The latent heat of steam increases at low pressure. Therefore, more quantity of water is required to condense one kg of steam as the quantity of latent heat removed is more}. There is a greater possibility of under-cooling the condensate with the reduction in partial pressure of steam due to the presence of air. This phenomenon reduces the overall efficiency of the power producing plant.

3. The heat transfer rates are greatly reduced due to the presence of air because air offers high resistance to heat flow. This further necessitates the more quantity of cooling water to maintain the heat transfer rates. Otherwise, it reduces the condensation rate and further increases the back pressure of the prime mover.

Sources of AIR leakage:

1.The air leaks through the joints, pickings and glands into the condenser where the pressure is below the atmospheric pressure. The amount of air leakage through these sources depends upon the quantity of workmanship.

2.The feed water contains air in dissolved condition. The dissolved air gets liberated when the steam is formed and it is carried with the steam into the condenser.

Preventive measures:

The air from the condenser is removed with the help of air pumps. The primary function of the air pump is to maintain the vacuum in the condenser which corresponds to the exhaust steam temperature by removing the air. Another function of the pump is to remove the condensate coming out from the bottom of the condenser.

An air pump which removes both air and condensate together is called wet air-pump while the air pump which removes only the moist air is known as Dry air-pump.

The type of air-pumps which are commonly used are:

1. steam ejectors (generally dry)

2. Rotary type (generally dry)

3. Reciprocating type (dry or wet)

TYPES OF CONDENSERS: The two main types of condensers are:

1. Jet condensers.

2. Surface condensers.

In jet condensers, the exhaust steam and cooling water are mixed with each other and the heat transfer from steam to water is by direct conduction.

In surface condensers, the exhaust steam and cooling water do not mix with each other, the water being circulated through a nest of tubes and the exhaust steam flows across the tubes, the heat transfer being by convection. A much lower exhaust pressure can be attained in surface condensers as compared to jet type and also the condensate is usefully recovered, whereas, in jet condensers, the condensate escapes with the cooling water. Therefore, for large power plants, jet condensers are not practical. Also, the supply of cooling water has to be reasonably pure.

1. Classification of Jet Condensers

The jet condensers may be further classified:

1. Parallel Flow Type: Here the steam and cooling water enter at the top of the condenser and flow downwards in parallel. The coldest water is thus in contact with hot steam and, therefore, it is less efficient.

2. Counter Flow Type: Here, the steam flows upwards through the condenser, meeting the cooling water which flows downwards from the top. The air is removed at the top and the condensate and water, separately, at the bottom. In this type, since the hottest steam is in contact with the hottest cooling water, it is thermodynamically the most efficient, because heat transfer approximates towards reversibility. Also, the cooling of air is most effective and this will reduce the capacity of the air suction pump. The counter flow type is of two designs:

(a) Low Level Jet Condenser: Here, Figure 1, the supply of cold cooling water is drawn into the condenser shell, by the vacuum created by the air pump. The water is sprayed downward in the shell into the up flowing steam. The condensed steam and cooling water flowing downward are discharged into the hot well.

(b) High Level Jet Condenser: This is also known as far barometric jet condenser, Figure 2. If the bottom of the condenser is not less than, say, 10.5 m above the level of the water in collection tank (hot well), condensate extraction pump is not needed and the condenser is self discharging. But a pump is needed to inject the cooling water into the condenser shell, from the cooling pond.

3. Ejector Condenser: In this condenser, Figure 3, the cooling water enters the condenser at the top from 4.5 to 6 metre and flows downward through a number of co-axial guide cones in a tube. As the water rushes across the gaps between the central parts of nozzles (cones), it drags in the exhaust steam and air. The steam gets condensed in contact with cooling water and the air is carried forward with the water. This condenser thus acts as a pump as well as a condenser.

2. Classification of Surface Condensers

Since in this type of condenser the cooling water and the exhaust steam do not mix with each other, the condensate is directly available as an ideal boiler feed. Due to this factor, if a sufficient amount of cooling water is available and the initial cost of the condenser is not of prime consideration, surface condenser is preferred to other types of condensers. The usual construction of the source condenser is that there is a cast iron or steel shell fitted with a tube plate at each end. A great number of tubes extend between these end plates to form the cooling surface. Surface condensers can be classified depending upon whether the water flows through the tubes or steam flows through the tubes. The usual flow pattern is that water flows through the tubes and the steam is circulated around the tubes as the outside of the tubes is not contaminated by the clean steam. The steam enters the condenser through an opening in the top of the shell. The steam after being condensed leaves the condenser through a hole at the bottom of the shell, Figure 4. The condensers may be single pass or two pass. In single pass condenser, the cooling water flows in one direction only through all the tubes and in the two pass tube (Figure 4), the water flows inone direction through part of the tubes and returns through the remaining of the tubes.

Surface condensers are also classified as parallel flow, counter flow or cross flow depending upon the direction of flow of the condensate relative to the tubes. They can be further classified as: down flow type, central flow type and inverted flow type. In the down flow type, Fig. 4, the steam enters at the top of the condenser and flows downwards over the tubes (through which cooling water flows) as the extraction pump is at the bottom. The cooling water flows in one direction through the lower half of the tube nest and returns in the reverse direction through the upper half of the tube nest. The air associated with the steam is also extracted from the bottom of condenser where the temperature is lowest, so that the work of the air pump is reduced. To keep the velocity of

steam across the tubes, approximately uniform, the cross-section of the condenser is gradually reduced in width towards the bottom. Also, the tubes are generally placed close together in the lower part. In the central flow type, Figure 5, the suction pipe of the air pump is located at the centre of the tube nest. The condensate then leaves at the bottom where the condensate extraction pump is placed. In this type, the steam comes into close contact with the whole periphery of the tubes. In the inverted type, the air suction pump is at the top. The steam flows upwards and then the condensate returns to the bottom of the condenser by flowing near the outer surface. The condensate pump is at the bottom of the condenser.

ADVANTAGES AND DISADVANTAGES OF A SURFACE CONDENSER

The various advantages of a surface condenser are as follows:

1. The condensate can be used as boiler feed water.

2. Cooling water of even poor quality can be used because the cooling water does not come in direct contact with steam.

3. High vacuum (about 73.5 cm of Hg) can be obtained in the surface condenser. This increases the thermal efficiency of the plant.

The various disadvantages of' the surface condenser are as follows:

1. The capital cost is more.

2. The maintenance cost and running cost of this condenser is high.

3. It is bulky and requires more space.

REQUIREMENTS OF A MODERN SURFACE CONDENSER

The requirements of ideal surface condenser used for power plants are as follows:

1. The steam entering the condenser should be evenly distributed over the whole cooling surface

of the condenser vessel with minimum pressure loss.

2. The amount of cooling water being circulated in the condenser should be so regulated that the

temperature of cooling water leaving the condenser is equivalent to saturation temperature of

steam corresponding to steam pressure in the condenser.

This will help in preventing under cooling of condensate.

3. The deposition of dirt on the outer surface of tubes should be prevented.

Passing the cooling water through the tubes and allowing the steam to flow over the tubes achieve this.

4. There should be no air leakage into the condenser because presence of air destroys the vacuum in the condenser and thus reduces the work obtained per kg of steam. If there is leakage of air into the condenser air extraction pump should be used to remove air as rapidly as possible.

2.3. Evaporative Condenser

In this condenser Figure 6, the steam flows through a set of gilled piping which is bent backwards and forwards and placed in a vertical place. Cooling water is sprayed from the top over the pipes. As it drips from one pipe to the other, it forms a thin film over the pipes. Air blowing across the pipes (by natural or mechanical means) rapidly evaporates the water film resulting in condensing of the steam flowing through the pipes. This condenser is very suitable when water is expensive or a small quantity of pure water is available.

7. DALTON'S LAW OF PARTIAL PRESSURES

According to Dalton's law of partial pressures the pressure exerted by a mixture of two gases or a gas and a vapour is equal to the sum of the pressures which each fluid would exert if occupying the same space alone. Or the final pressure of the mixture is equal to the sum of the partial pressure of each constituent. This means that each constituent of the mixture behaves as if it occupied the space alone and is independent of the presence of theother constituent. Mass of air in a mixture of steam and air can be calculated if the temperature and pressure of the mixture are known, as under:

1. obtain partial pressure (p.p) of steam ps from steam tables, the pressure of steam corresponding to the temperature of the mixture.

2. Then, from, p (pressure of mixture) = p.p of air (pa) + ps

pa p ps

3. mass of air, ma

pa v Rma T

Main functions of condenser

1. To condense the steam exhausted from turbine.

2. To maintain vacuum so that heat drop utilized in turbine is maximum.

3. To maintain condensate temperature to saturation level so that dissolved gases are liberated.

4. To form convenient point for introducing makes up water to the cycle.

5. To prevent under cooling of condensate so that thermal losses are minimized.

6. To facilitate extraction of air and other gases.

CONDENSER TUBE CLEANING

Regardless of the tube material, the most effective way to ensure that tubes achieve their full life expectancy is to keep them clean. Each time the tube deposits, sedimentation, bio fouling and obstructions are removed, the tube surfaces are returned almost to bare metal, providing the tube itself with a new life cycle, the protective oxide coatings quickly rebuilding themselves to re-passivate the cleaned tube.

1. The majority of cleaning procedures are performed off-line, the most frequently chosen and fastest method being mechanical cleaning.

Among other off-line methods is the use of very high-pressure water but, since the jet can only be moved along the tube slowly, the time taken to clean a condenser can become extended. Great care must be taken to avoid damaging any tube sheet or tube coatings which may be present; otherwise the successful removal of fouling deposits may become associated with new tube leaks or increased tube sheet corrosion, only observable after the unit has been brought back on-line.

2. Chemicals are also used for the off-line cleaning of condenser tubes. Several mildly acidic products are available and will remove more deposit than most other methods; but it is expensive, takes longer for the operation to be completed and the subsequent disposal of the chemicals, an environmental hazard, creates its own set of problems. It has also been found quite frequently that some residual material still needs to be removed by mechanical cleaning methods.

3. Very few on-line methods are available to clean condenser tubes but the best known is the Taprogge system, which uses recirculated sponge rubber balls as the cleaning vehicle. These systems often operate for only a part of each day and, rather than maintaining absolutely clean tube surfaces, tend to merely limit the degree of tube fouling. Unfortunately, although the tubes may become cleaner if abrasive balls are used, tube wear can now become a problem.

Mussalli et al(8) showed some uncertainty concerning sponge ball distribution and therefore, how many of the tubes actually become cleaned on line. It is also not uncommon to find that numerous sponge balls have become stuck in condenser tubes and these appear among the material removed during mechanical cleaning operations. For these reasons, the tubes of condensers equipped with these on-line systems still have to be cleaned periodically off-line, especially if loss of generation capacity is of serious concern.

2.1 Mechanical cleaning of condenser tubes Off-line mechanical cleaning is especially useful where fouling problems exist and are too severe to be handled by any of the other methods. Obviously, the tool selected has to be the most appropriate for removing a particular type of deposit. Moulded plastic cleaners (pigs) are quite popular for some light silt applications. Brushes can also be used to remove these soft deposits as well as some microbiological deposits. Brushes are also useful for cleaning tubes with enhanced surfaces (e.g. spirally indented or finned); or those tubes with thin wall metal inserts or epoxy type coatings. With harder types of deposit, metal cleaners of various designs have been developed, often with a particular deposit in mind. Mechanical condenser tube cleaners were first introduced in 1923 and subsequent patents granted over the years to the both the Griffin brothers and to the Saxon family have improved on the original design. Figures 1.0(a) and 1.0(b) show some ofthe current versions of this cleaner, which consist of several U-shaped tempered steel strips arranged to form pairs of spring-loaded blades.

These strips are mounted on a spindle and placed at 90 degrees rotation to one another. Mounted at one end of the spindle is a serrated rubber or plastic disk that allows a jet of water to propel the cleaners through a tube with greater hydraulic efficiency. The water is directed to the tube being cleaned by a hand-held triggered device (also known as a gun), the water being delivered by a pump operating at only 300 psig (2.07 MPa). Since the pump is usually mounted on a wheeled base plate, the system can be conveniently moved from unit to unit within a plant or even moved to another plant.

A water pressure of 300 psig (2.07 MPa) is very effective for propelling the cleaning tools through the tubes, preventing their exit velocity from rising above a safe level. Some other cleaning systems use air or a mixture of air and water as the propelling fluid; but the expansion of the air as the cleaner exits the tube can convert the cleaner into a projectile and place the technicians at risk.

Another advantage of using water as the cleaner propellant is that the material removed can be collected in a plastic container for later drying, then weighing to establish the deposit density (g/m2) and followed in many cases by X-ray fluorescent analysis of the deposit cake.

Most metal cleaners are designed to have a controlled spring-loaded cutting edge: but, if effective deposit removal is to be the result, the dimensions of the cutting surfaces have to be closely matched to the internal diameter of the tube being cleaned, not only to improve the peripheral surface contact but also to ensure that the appropriate spring tension will be applied as the cleaner is propelled through the tube. The effective life of cleaners designed in this way can be as high as 10 tube passes.

However, since such cleaners can behave as stiff springs, loading the cleaners into the tubes was sometimes rather tedious. To speed up this operation, while also providing the blades with more circumferential coverage of the tube surface, the cleaner shown in Figure 1.0(c) was developed. This design not only reduced the cleaning time for 1000 tubes but, due to the increased contact surface provided by the greater number of blades, it was found to be more efficient in removing tenacious deposits such as those consisting of various forms of manganese. A later development involved a tool for removing hard calcite deposits, which were found to be difficult to remove even by acid cleaning. This is shown in Figure 1.0(d), and consists of a teflon body on which are mounted a number of rotary cutters, similar to those used for cutting glass. These are placed at different angles around the body, which is fitted with a plastic disk similar to those used to propel other cleaners through tubes. Used on condenser tubes that had accumulated a large quantity of very hard deposits, Stiesma et al(9) described how cleaners of this type removed 80 tons (72.48 tonnes) of calcite material from this condenser. It has now become a standard tool whenever hard and brittle deposits are encountered.

The experience gained from using these techniques has allowed the time to clean to be forecasted with confidence and cleaning to be performed to schedule. For instance, a normal crew can clean between 5,000 and 7,000 tubes during a 12-hour shift. Clearly, this number can rise with an increase in crew size, limited only by there being adequate space in the waterbox(es) for the crew to work effectively

The concern is occasionally expressed that mechanical cleaners can possibly cause damage to tube surfaces. With cleaners that have been properly designed and carefully manufactured, such damage is extremely rare. Indeed, Hovland et al(10) conducted controlled tests by passing such cleaners repeatedly through 30 feet long, 90-10 CuNi tubes. It was found that, after 100 passes of these cleaners, the wall thickness became reduced by only between 0.0005 and 0.0009 inches (12.5 and 22.86). If a 50% reduction in wall thickness is the critical parameter, extrapolating this series of tests would be equivalent to 2800 passes of a cleaner per tube, or 1000 years of condenser cleaning!

Clearly, all off-line cleaning methods sometimes need assistance where the deposits have been allowed to build up and even become hard. In such cases, it may still be necessary to acid clean, followed by cleaning with mechanical cleaners or high-pressure water to remove any remaining debris.

2.2 Developing an appropriate cleaning procedure The selected cleaning procedure should remove the particular deposits that are present as completely as possible, while also causing the unit to be out of service for the minimum amount of time. Some other major considerations in the selection process are as follows:

2.2.1 Removal of obstructions Many tube-cleaning methods are ineffective when there are obstructions within tubes, or various forms of macro fouling are present and, clearly, those cleaning methods should be avoided. Attention has already been drawn to the shell-fish, which constitute macrofouling, including Asiatic clams and zebra mussels. The selected tube cleaner must have the body and strength to remove such obstructions. The cleaning method must also be able to remove the byssal material that shell-fish use to attach themselves to the tube walls.

There are certain types of other debris which can become obstructions, among them being cooling tower fill, waste construction material, sponge rubber balls, rocks, sticks, twigs, seaweed and fresh water pollutants, any or all of which can become lodged in the tubes and have to be removed. Meanwhile, experience has shown that, if appropriate procedures are followed, properly designed cleaners should not become stuck inside tubes, unless the tube has been deformed. 2.2.2 Removal of corrosion products With condensers equipped with copper alloy tubing, copper deposits grow continuously and the thick oxide coating or corrosion product can grow to the point where it will seriously impede heat transfer. Not only will the performance of the condenser be degraded but such deposits will also increase the potential for tube failure. When a thick outer layer of porous copper oxide is allowed to develop, it disrupts the protective inner cuprous oxide film, exposing the base metal to attack and causing under-deposit pitting to develop. Such destructive copper oxide accumulations together with any other deposits must be removed regularly.

2.2.3 Surface roughness Rough tube surfaces, as are created by the accumulation of fouling deposits, are associated with increased friction coefficients while the reduced cooling water flow rates allow deposits to accumulate faster. It has also been found that rough tube surfaces tend to pit more easily than smooth surfaces. Thus smooth tube surfaces, which result from cleaning, can improve condenser performance through:

Improved heat transfer capacity and a lower water temperature rise across the condenser, reducng the heat lost to the environment

Increase in both flow volume and water velocity, often resulting in reduced pumping power

Increased time required between cleanings, by reducing rate of re-deposition of fouling material on the tube surfaces.

Reduced pitting from turbulence and gas bubble implosion

3. IN-LEAKAGE DETECTION METHODS The EPRI Condenser In-Leakage Guideline(6) discusses in great detail the sources of both water and air in-leakage and their consequences, together with methods for their location and correction. The techniques have evolved from earlier methods (e.g. use of foam and plastic wrap), to the current techniques that involve the use of tracer gases, principally helium and sulfur hexafluoride (SF6), both of which are non-toxic. Most of the innovations were stimulated by the need to locate small circulating water in-leaks but, eventually, the same techniques became used for the location of air in-leaks as well.

3.1 Water in-leaks The condenser is supposed to form a barrier between the cooling water - which flows between the water boxes through the condenser tubes - and the shell side of the condenser, in which the exhaust vapour is collected as condensate. However, even small circulating water leaks will quickly find their way into the condensate, contaminating it with undesirable dissolved solids which tend to cause corrosion in the feed water heaters, boilers or steam generators. On-line conductivity or salinity instruments are used to indicate the presence of a leak and steps should be taken to rectify the problem as soon as possible. Unfortunately, this usually means taking the unit out of service, the associated loss of revenue depending on the length of the outage. Thus the time taken to locate and correct the problem can be economically significant. This time can be reduced significantly if the water box associated with the leak can be identified while the unit is still on-line.

Among the leak detection methods commonly employed in the past were smoke generators, foam or plastic wrap applied to the tube sheet, ultrasonic, tube pressure testing and membrane type rubber stoppers. These earlier techniques also left some uncertainty as to whether the leak was confined to only one tube; so that adjacent tubes were often plugged as well (often unnecessarily) as a form of insurance plugging. All these methods require that the shell side of the condenser be under vacuum, provided either by the air removal system or, if the water box is divided, by continuing to run the unit at low load, taking each water box out of service in turn and checking it for leaks.

The development of the helium tracer gas technique in 1978 not only reduced the time required to locate a leak; it also eliminated much of the former uncertainty whether the actual source of the leak had been found. However, the lowest detectible concentration of helium is one part per million above the background level, and helium was often unable to detect small water in-leaks. Thus a tracer gas with greater sensitivity was sought and, in 1982, a tracer gas leak detection technique using SF6 was developed. It was found that SF6 in concentrations as low as one part per 10 billion (0.1ppb) can be detected, so that small leaks could now be located and with confidence.

PLENUMTRACER GASINJECTIONAIR HORNINLET WATERBOXOUTLET WATERBOXCONDENSER TUBE BUNDLETECHNCIANCONTROLLINGCONDENSEROFF-GASEXHAUST TOATMOSPHEREGASANALYZERSAMPLECONDITION-INGSAMPLINGPUMPSTRIPCHARTRECORDERSECONDTECHNICIANSTATIONIN WATERBOXAIR REMOVALSYSTEM

Figure 2 - General setup for tube water leak test This method is illustrated in Figure 2, in which a tracer gas monitor is connected to the off-gas stream leaving the air removal system. A technician is stationed at the monitor to observe the shape of the trace on the strip chart recorder (See Figure 3.0), a typical response time being 30-45 seconds. Another technician is stationed in the water box and dispenses the tracer. The two technicians communicate through two-way sound-powered radios, chosen to avoid RF interference with other equipment.

Once the waterbox is open and the tubesheet exposed, a series of plenums is placed over a section of the tubesheet, each sized to cover an ever-smaller group of tubes. The technician in the waterbox injects the tracer gas into the plenum using a portable dispenser. The vacuum within the condenser allows the tracer gas to pass through any leaks that may be present and eventually appear in the off-gas stream leaving the air removal system. The technician watching the tracer gas detector monitor warns the other technician when the presence of the gas is observed. A smaller plenum is then used, and so on. By using this rigorous process of elimination, the problem tube can be rapidly identified.

As a guide to tracer gas selection, if the water in-leakage is less than 50 gallons per day (189.2 l/day), SF6 is the preferred tracer gas; otherwise, either gas may be used. Similarly, if the unit is operating at more than 20% of full load, either gas may be used. If the leak is so bad that the unit cannot be brought on-line, then the use of helium would be the standard procedure.

TIMERESPONSEBASE LINECLEAROUT TIMERATE OF RESPONSEMAGNITUDE OFREPONSERESPONSEGASRELEASERESPONSETIMEINITIAL

Figure 3 Chart Recording of a typical leak response Sulfur Hexafluoride can also be used on-line to identify the waterbox, even tube bundle, in which the leaking tube is located. The SF6 is injected periodically into the circulating water before each waterbox while the unit is still on-line, and a permanently installed analyzer and monitor is used to identify the waterbox associated with the leak This reduces the time required to locate and repair the leaking tube, once the associated waterbox has been opened.

3.2 Air in-leakage Condensers are designed to perform correctly with the unavoidable and low level of air in-leakage which is always present(7). However, greater air in-leakage than this low normal value will increase the concentration of non-condensibles in the shell side of the condenser and cause the thermal resistance to heat transfer to increase. An increase in backpressure and unit heat rate will result. The in-leakage may even rise to the point where the backpressure approaches its operating limit, forcing a reduction in load. Another effect of high air in-leakage is often an increase in the concentration of dissolved oxygen in the condensate, a

concentration that will tend to increase with lower condensate temperatures. The consequences are increased corrosion of feedheaters, boilers and steam generators and/or an increase in the consumption of water treatment chemicals. All these consequences have a negative impact on unit profitability.

Using tracer gas techniques, the source of most air in-leaks can be located with the unit still on-line. Once again, a tracer gas monitor is installed in the off-gas line from the air removal system and the technician handling the tracer gas dispenser roams around the unit in a methodical manner until the technician at the monitor observes a response. The leak detection survey starts at the turbine deck level and proceeds from top to bottom of the unit, one deck at a time. Care must be taken when dispensing the tracer gas that only one potential source is sprayed at a time, otherwise the ability to associate a response with a particular source may become impaired.

CONDENSATE POLISHING UNIT

Introduction

The Condensate Polishing Unit removes 'crud' - corrosion products consisting mostly of oxide of iron, copper or nickel, dissolved solids - mostly consisting of sodium, chloride and silica and carbon dioxide. Condensate polishing units are typically installed for super thermal power station with the main objective of improving the boiler water quality. The benefits of condensate polishing is quicker start up and as a result full load conditions are reached early giving economic benefits. Orderly shut down is possible in the case of condenser tube leak conditions.

Process Description

The condensate polishers are located in the turbine hall and the exhausted resins are hydro pneumatically transferred to the water treatment plant areas where they are regenerated and transferred back to the polisher.

It is normal to operate the polisher initially in the hydrogen cycle in which the cation resin is in hydrogen form and the anion resin is in the hydroxide form. The process typically takes around 7 -8 days after which the cation resin gets converted into ammonium form and the polisher is then operated in the ammonia cycle. Experience has shown that the hydrogen cycle operation is almost always problem free and produces condensate of the required quality. Boiler drum sodium, chloride and silica increases within 2 - 3 days of operation of the polisher in ammonium cycle.

Separation of ion exchange resin in a mixed bed is done by backwashing the unit with water when cation resin settles at the bottom and the light anion resin is at the top. However, the process almost always results in presence of a small percentage of cation resins in the anion portion and vise versa - a phenomenon called cross contamination. On regeneration of the anion resin with alkali, the cation resin presents in the anion portion gets converted into sodium form and simillarly, the anion resin present in the cation portion gets converted into chloride form.

Fig-1 shows the location of the condensate polisher in the boiler turbine circuit.

Benefits

Improvement in the quality of condensate and "cycle" clean up.

Reduced blow down and make up requirements

Improvement in boiler water quality for drum type boilers

Quick start up and as a result, full load conditions are reached early giving economics benefits.

Orderly shutdown possible in case of condenser tube leak conditions.

Improvement in quality of steam which results in enhanced turbine life.

Appplications

Condensate polishing units are typically used in nuclear (pressurised water reactor ) and fossil power plants.

What is DEAERATION?

DEAERATION is the process of removing dissolved corrosive gases(O2 & CO2) from water. This process is also called degasification.

Why are these gases corrosive?

Dissolved oxygen acts as a depolarizer and contributes to the corrosion of metal.

O2 +4e + 2H2O ( 4OH_Write about DEAERATOR

Priciples of deaeration

1.DALTONS LAW OF PARTIAL PRESSURE :

2 Henry Law of Solubility : The solubility of any gas in a liquid is directly proportional to the partial pressure of the gas above the liquid surface. Solubility of a gas in a liquid decreases with increase in temperature of liquid.

OPERATION : Deaerator operates in two stages.

In the first stage, the water is heated to within 2 4 0 C of steam saturation temperature and virtually all of the oxygen and free carbon dioxide are removed. This is accomplished by spraying the water through self adjusting spray valves which are designed to produce a uniform spray film under all conditions of load and consequently a constant temperature and uniform gas removal is obtained at this point.

In particular, dissolved oxygen in boiler feed waters will cause serious corrosion damage in steam systems by attaching to the walls of metal piping and other metallic equipment and forming oxides (rust). It also combines with any dissolved carbon dioxide to form carbonic acid that causes further corrosion. Most deaerators are designed to remove oxygen down to levels of 7 ppb by weight (0.0005 cm/L) or less.

In the second stage the preheated water mixes with fresh steam. This stage distributor or several assemblies of trays. Water is in intimate contact with fresh gas free steam. Very little steam is condensed here as the water is already heated near to saturation level in first stage. Uncondensed steam carries small quantity of gases to the first stage.

In the first stage most of the steam is condensed and the remaining gases passed through the vent where the non-condensable gases flow to the atmosphere. A very small amount of steam is also discharged to the atmosphere which assures that the Deaerator is adequately vented at all times.

The water which leaves the second stage falls to the storage tank where it is stored for use. At this time the water is completely deaerate and is heated to the steam saturation temperature corresponding to the pressure within the vessel.

Functions of Deaerator:

1. To remove dissolved non condensable gases

2. To heat feed water.

3. To mix water and steam in controlled manner.

4. Protects boiler components from corrosion by removing gases.

5. Acts as storage vessel for BFPs.

Elevation of the deaerator gives the required net positive suction head for the BFPs.

Caution: Do not fill the Deaerator with steam and then start the water filling. This will create noise and vibration, which can damage the internals of the Deaerator. All Deaerators are protected against damage by one or more safety devices. These devices are designed to discharge in the event that some operating conditions cause the Deaerator to exceed the standard operating levels.

De-aeration can be done by mechanical de-aeration, by chemical de-aeration or by both together.Mechanical de-aeration:

Removal of oxygen and carbon dioxide can be accomplished by heating the boiler feed water. They operate at the boiling point of water at the pressure in the de-aerator. They can be of vacuum or pressure type.

The vacuum type of de-aerator operates below atmospheric pressure, at about 82oC, can reduce the oxygen content in water to less than 0.02 mg/litre. Vacuum pumps or steam ejectors are required to maintain the vacuum.

The pressure-type de-aerators operate by allowing steam into the feed water and maintaining temperature of 105oC. The steam raises the water temperature causing the release of O2 and CO2 gases that are then vented from the system.This type can reduce the oxygen content to 0.005 mg/litre.

Steam is preferred for de-aeration because steam is free from O2 and CO2, and steam is readily available & economical

Chemical de-aeration:

While the most efficient mechanical deaerators reduce oxygen to very low levels (0.005 mg/litre), even trace amounts of oxygen may cause corrosion damage to a system. So removal of hat traces of oxygen with a chemical oxygen scavenger such as sodium sulfite or hydrazine is needed.Deaerator

A deaerator is a device that is widely used for the removal of oxygen and other dissolved gases from the feedwater to steam-generating boilers. In particular, dissolved oxygen in boiler feedwaters will cause serious corrosion damage in steam systems by attaching to the walls of metal piping and other metallic equipment and forming oxides (rust). Dissolved carbon dioxide combines with water to form carbonic acid that causes further corrosion. Most deaerators are designed to remove oxygen down to levels of 7 ppb by weight (0.005cm/L) or less as well as essentially eliminating carbon dioxide.[1]

HYPERLINK "http://en.wikipedia.org/wiki/Deaerator" \l "cite_note-Spirax-1" [2]

HYPERLINK "http://en.wikipedia.org/wiki/Deaerator" \l "cite_note-2" [3]There are two basic types of deaerators, the tray-type and the spray-type:[2]

HYPERLINK "http://en.wikipedia.org/wiki/Deaerator" \l "cite_note-3" [4]

HYPERLINK "http://en.wikipedia.org/wiki/Deaerator" \l "cite_note-4" [5]

HYPERLINK "http://en.wikipedia.org/wiki/Deaerator" \l "cite_note-5" [6]

HYPERLINK "http://en.wikipedia.org/wiki/Deaerator" \l "cite_note-6" [7] The tray-type (also called the cascade-type) includes a vertical domed deaeration section mounted on top of a horizontal cylindrical vessel which serves as the deaerated boiler feedwater storage tank.

The spray-type consists only of a horizontal (or vertical) cylindrical vessel which serves as both the deaeration section and the boiler feedwater storage tank.

Contents

1 Types of deaerators

1.1 Tray-type deaerator 1.2 Spray-type deaerator 2 Deaeration steam 3 Oxygen scavengers 4 See also 5 References 6 External links

Types of deaeratorsThere are many different horizontal and vertical deaerators available from a number of manufacturers, and the actual construction details will vary from one manufacturer to another. Figures 1 and 2 are representative schematic diagrams that depict each of the two major types of deaerators.

Tray-type deaerator

Figure 1: A schematic diagram of a typical tray-type deaerator.

The typical horizontal tray-type deaerator in Figure 1 has a vertical domed deaeration section mounted above a horizontal boiler feedwater storage vessel. Boiler feedwater enters the vertical deaeration section above the perforated trays and flows downward through the perforations. Low-pressure deaeration steam enters below the perforated trays and flows upward through the perforations. Some designs use various types of packing material, rather than perforated trays, to provide good contact and mixing between the steam and the boiler feed water.

The steam strips the dissolved gas from the boiler feedwater and exits via the vent at the top of the domed section. Some designs may include a vent condenser to trap and recover any water entrained in the vented gas. The vent line usually includes a valve and just enough steam is allowed to escape with the vented gases to provide a small and visible telltale plume of steam.

The deaerated water flows down into the horizontal storage vessel from where it is pumped to the steam generating boiler system. Low-pressure heating steam, which enters the horizontal vessel through a sparger pipe in the bottom of the vessel, is provided to keep the stored boiler feedwater warm. External insulation of the vessel is typically provided to minimize heat loss.

Spray-type deaerator

Figure 2: A schematic diagram of a typical spray-type deaerator.

As shown in Figure 2, the typical spray-type deaerator is a horizontal vessel which has a preheating section (E) and a deaeration section (F). The two sections are separated by a baffle(C). Low-pressure steam enters the vessel through a sparger in the bottom of the vessel.

The boiler feedwater is sprayed into section (E) where it is preheated by the rising steam from the sparger. The purpose of the feedwater spray nozzle (A) and the preheat section is to heat the boiler feedwater to its saturation temperature to facilitate stripping out the dissolved gases in the following deaeration section.

The preheated feedwater then flows into the dearation section (F), where it is deaerated by the steam rising from the sparger system. The gases stripped out of the water exit via the vent at the top of the vessel. Again, some designs may include a vent condenser to trap and recover any water entrained in the vented gas. Also again, the vent line usually includes a valve and just enough steam is allowed to escape with the vented gases to provide a small and visible telltale plume of steam.

The deaerated boiler feedwater is pumped from the bottom of the vessel to the steam generating boiler system.

Deaeration steamThe deaerators in the steam generating systems of most thermal power plants use low pressure steam obtained from an extraction point in their steam turbine system. However, the steam generators in many large industrial facilities such as petroleum refineries may use whatever low-pressure steam is available.

Oxygen scavengersOxygen scavenging chemicals are very often added to the deaerated boiler feedwater to remove any last traces of oxygen that were not removed by the deaerator. The most commonly used oxygen scavenger is sodium sulfite (Na2SO3). It is very effective and rapidly reacts with traces of oxygen to form sodium sulfate (Na2SO4) which is non-scaling. Another widely used oxygen scavenger is hydrazine (N2H4).

Other scavengers include 1,3-diaminourea (also known as carbohydrazide), diethylhydroxylamine (DEHA), nitriloacetic acid (NTA), ethylenediaminetetraacetic acid (EDTA), and hydroquinone.

Deaeration in boilers

In order to meet industrial standards for both oxygen content and the allowable metal oxide levels in feed water, nearly complete oxygen removal is required. This can be accomplished only by efficient mechanical deaeration supplemented by a properly controlled oxygen scavenger.

Deaeration is driven by the following principles: the solubility of any gas in a liquid is directly proportional to the partial pressure of the gas at the liquid surface, decreases with increasing liquid temperature; efficiency of removal is increased when the liquid and gas are thoroughly mixed.

Deaeration can be performed using a physical medium such as deaerating heaters or vacuum deaerators or a chemical medium such as oxygen scavengers (polishing treatment) or catalytic resins. Membrane contractors are increasingly being used. Carbon dioxide is often removed using a physical medium.

The purpose of a deaerator is to reduce dissolved gases, particularly oxygen, to a low level and improve plant thermal efficiency by raising the water temperature. In addition, they provide feed water storage and proper suction conditions for boiler feed water pumps.

Pressure deaerators can be classified under two major categories: tray type and spray type.

The tray type desecrating heaters consist of a shell, spray nozzles to distribute and spray the water, a direct contact vent condenser, tray stacks and protective interchamber walls. The chamber is constructed in low carbon steel, but more corrosion-resistant stainless steels are used for the spray nozzles and the other parts.

Incoming water is sprayed into steam atmosphere, where it is heated up to a few degrees to the saturation temperature of the steam. Most of the non-condensable gases (principally oxygen and free carbon dioxide) are released to the steam as the water is sprayed into the unit. Seals prevent the recontamination of tray stack water by gases from the spray section. Water falls from tray to tray, breaking into fine droplets of film, which intimately contact the incoming steam.

The steam heats the water to the steam saturation temperature and removes the very last traces of oxygen. Deaerated water falls to the storage space below, where a steam blanket protects it from recontamination. It is usually stored in a separate tank.

The steam enters the deaerators through ports in the tray compartment, flows down through the tray stack parallel to the water flow. A very small amount of steam condenses in this section as the water temperature rises to the saturation temperature of the steam. The rest of the steam scrubs the cascading water. Before leaving the tray compartment, the steam flows upward between the shell and the interchamber walls to the spray section. Most of the steam is condensed and becomes part of the deaerated water. A small portion of the steam, which contains the non-condensable gas released from the water, is vented to the atmosphere. It is essential that sufficient venting is provided at all times or deaeration will be incomplete. Steam flow through the tray stack may be cross-flow, counter-current, or co-current to the water.

The spray type deaerating heaters consist of a shell, spring-loaded inlet spray valves, a direct contact vent condenser section and a steam scrubber for final dearetion; the shell and steam may be low carbon steel, the spray valves and the direct contact vent condenser section are in stainless steel. The incoming water is sprayed into a steam atmosphere and heated up to a few degrees to the saturation temperature of the steam. Most of the non-condensable gases are released to the steam, and the heated water falls to water seals and drains to the lowest section of the steam scrubber. The water is scrubbed by a large volume of steam and heated to the saturation temperature prevailing at that point. As the water-steam mixture rises in the scrubber, the deaerated water is a few degrees above the saturation temperature, due to a slight pressure loss. In this way a small amount of flashing is produced, which aids in the release of dissolved gases. The deaerated water overflows from the steam scrubber to the storage section below.

Steam enters the deaerator through a chest on the side and flows to the steam scrubber. After flowing into the scrubber it passes up into the spray heater section to heat the incoming water. Most of the steam condenses in the spray section to become a part of the deaerated water. A small portion of the gases is vented to the atmosphere to remove the non-condensable gases.

Vacuum deaeration is used at temperatures below the atmospheric boiling point to reduce the corrosion rate in water distribution systems. A vacuum is applied to the system to bring the water to its saturation temperature. Spray nozzles break the water into small particles to facilitate gas removal and vent the exhaust gases. Incoming water enters through spray nozzles and falls through a columns packed with Raschig rings to other synthetic packing. In this way, water is reduced to thin films and droplets, which promote the release of dissolved gases. The released gases and water vapor are removed through the vacuum, which is maintained by steam jet eductors or vacuum pumps, depending on the size of the system. Vacuum deaerators remove oxygen less efficiently that pressure units.

Corrosion fatigue at or near welds is a major problem in deaerators. It is the result of mechanical factors, such as manufacturing procedures, poor welds and lack of stress-relieved welds. Operational problems such as water/steam hammer can also be a factor.

Find extra information about boiler feed water and boiler water treatment.Check also our web page about he main problems occurring in boilers: scaling, foaming and priming, and corrosion. For a description of the characteristics of the perfect boiler water click here.

Read more: http://www.lenntech.com/applications/process/boiler/deaeration.htm#ixzz2BahAXDVJWater hammer is a liquid shock wave resulting from the sudden starting or stopping of flow. Generally water hammers can occur in any thermal-hydraulic systems and nuclear power plants as well.

Water hammer (or, more generally, fluid hammer) is a pressure surge or wave caused when a fluid (usually a liquid but sometimes also a gas) in motion is forced to stop or change direction suddenly (momentum change). Water hammer commonly occurs when a valve closes suddenly at an end of a pipeline system, and a pressure wave propagates in the pipe. It's also called hydraulic shock.

This pressure wave can cause major problems, from noise and vibration to pipe collapse. It is possible to reduce the effects of the water hammer pulses with accumulators and other features.

Rough calculations can be made either using the Joukowsky equation,[1] or more accurate ones using the method of characteristics.

Cause and effectIf the pipe is suddenly closed at the outlet (downstream), the mass of water before the closure is still moving forward with some velocity, building up a high pressure and shock waves. In domestic plumbing this is experienced as a loud banging resembling a hammering noise. Water hammer can cause pipelines to break if the pressure is high enough. Air traps or stand pipes (open at the top) are sometimes added as dampers to water systems to provide a cushion to absorb the force of moving water to prevent damage to the system.

In hydroelectric generating stations, the water travelling along the tunnel or pipeline may be prevented from entering a turbine by closing a valve. But if there is, say, 14km of tunnel of say 7.7m diameter, full of water travelling at say 3.75 m/sec[2], that represents a very large amount of kinetic energy that must be arrested. This is frequently achieved by a surge shaft[3] open at the top, into which the water flows. As the water rises up the shaft, converting kinetic energy into potential energy, it decelerates the water in the tunnel. At some HEP stations, what looks like a water tower is actually one of these devices, known in these cases as a surge drum.

In the home, water hammer may occur when a dishwasher, washing machine, or toilet shuts off water flow. The result may be heard as a loud bang, repetitive banging (as the shock wave travels back and forth in the plumbing system), or as some shuddering.

On the other hand, when an upstream valve in a pipe closes, water downstream of the valve attempts to continue flowing, creating a vacuum that may cause the pipe to collapse or implode. This problem can be particularly acute if the pipe is on a downhill slope. To prevent this, air and vacuum relief valves, or air vents, are installed just downstream of the valve to allow air to enter the line and prevent this vacuum from occurring.

Other causes of water hammer are pump failure, and check valve slam (due to sudden deceleration, a check valve may slam shut rapidly, depending on the dynamic characteristic of the check valve and the mass of the water between a check valve and tank).

Expansion joints on a steam line that have been destroyed by steam hammer

Steam distribution systems may also be vulnerable to a situation similar to water hammer, known as steam hammer. In a steam system, water hammer most often occurs when some of the steam condenses into water in a horizontal section of the steam piping. Subsequently, steam picks up the water, forms a "slug" and hurls it at high velocity into a pipe fitting, creating a loud hammering noise and greatly stressing the pipe. This condition is usually caused by a poor condensate drainage strategy.

Where air filled traps are used, these eventually become depleted of their trapped air over a long period of time through absorption into the water. This can be cured by shutting off the supply, opening taps at the highest and lowest locations to drain the system (thereby restoring air to the traps), and then closing the taps and re-opening the supply.

Water hammer during an explosionWhen an explosion happens in an enclosed space, water hammer can cause the walls of the container to deform. However, it can also impart momentum to the enclosure if it is free to move. An underwater explosion in the SL-1 nuclear reactor vessel caused the water to accelerate upwards through 2.5 feet (0.76m) of air before it struck the vessel head at 160 feet per second (49m/s) with a pressure of 10,000 pounds per square inch (69,000kPa). This pressure wave caused the 26,000 pounds (12,000kg) steel vessel to jump 9 feet 1 inch (2.77 m) into the air before it dropped into its prior location.[4]Mitigating measuresWater hammer has caused accidents and fatalities, but usually damage is limited to breakage of pipes or appendages. An engineer should always assess the risk of a pipeline burst. Pipelines transporting hazardous liquids or gases warrant special care in design, construction, and operation.

The following characteristics may reduce or eliminate water hammer:

Reduce the pressure of the water supply to the building by fitting a regulator.

Lower fluid velocities. To keep water hammer low, pipe-sizing charts for some applications recommend flow velocity at or below 5 ft/s (1.5 m/s).

Fit slowly-closing valves. Toilet flush valves are available in a quiet flush type that closes quietly.

High pipeline pressure rating (expensive).

Good pipeline control (start-up and shut-down procedures).

Water towers (used in many drinking water systems) help maintain steady flow rates and trap large pressure fluctuations.

Air vessels work in much the same way as water towers, but are pressurized. They typically have an air cushion above the fluid level in the vessel, which may be regulated or separated by a bladder. Sizes of air vessels may be up to hundreds of cubic meters on large pipelines. They come in many shapes, sizes and configurations. Such vessels often are called accumulators or expansion tanks.

A hydropneumatic device similar in principle to a shock absorber called a 'Water Hammer Arrestor' can be installed between the water pipe and the machine, to absorb the shock and stop the banging.

Air valves often remediate low pressures at high points in the pipeline. Though effective, sometimes large numbers of air valves need be installed. These valves also allow air into the system, which is often unwanted.

Shorter branch pipe lengths.

Shorter lengths of straight pipe, i.e. add elbows, expansion loops. Water hammer is related to the speed of sound in the fluid, and elbows reduce the influences of pressure waves.

Arranging the larger piping in loops that supply shorter smaller run-out pipe branches. With looped piping, lower velocity flows from both sides of a loop can serve a branch.

Flywheel on pump.

Pumping station bypass.

Hydroelectric power plants must be carefully designed and maintained because the water hammer can cause water pipes to fail catastrophically.

Column separationColumn separation is a phenomenon that can occur during a water-hammer event. If the pressure in a pipeline drops rapidly to the vapor pressure of the liquid, the liquid vaporises and a "bubble" of vapor forms in the pipeline. This is most likely to occur at specific locations such as closed ends, high points or knees (changes in pipe slope). When the pressure later increases above the vapor pressure of the liquid, the vapor in the bubble returns to a liquid state, which leaves a vacuum in the space formerly occupied by the vapor. The liquid either side of the vacuum is then accelerated into this space by the pressure difference. The collision of the two columns of liquid, (or of one liquid column if at a closed end,) results in Cavitation and causes a large and nearly instantaneous rise in pressure. This pressure rise can damage hydraulic machinery, individual pipes and supporting structures. Many repetitions of cavity formation and collapse may occur in a single water-hammer event.[10]Simulation softwareMost water hammer software packages use the method of characteristics [7] to solve the differential equations involved. This method works well if the wave speed does not vary in time due to either air or gas entrainment in a pipeline. The Wave Method (WM) is also used in various software packages. WM lets operators analyze large networks efficiently. Many commercial and non commercial packages are available.

Software packages vary in complexity, dependent on the processes modeled. The more sophisticated packages may have any of the following features:

Multiphase flow capabilities

An algorithm for cavitation growth and collapse

Unsteady friction - the pressure waves dampens as turbulence is generated and due to variations in the flow velocity distribution

Varying bulk modulus for higher pressures (water becomes less compressible)

Fluid structure interaction - the pipeline reacts on the varying pressures and causes pressure waves itself

Applications The water hammer principle can be used to create a simple water pump called a hydraulic ram.

Leaks can sometimes be detected using water hammer.

Enclosed air pockets can be detected in pipelines.

Q. What are pigs and pipeline pigging?

A pig is a device inserted into a pipeline which travels freely through it, driven by the product flow to do a specific task within the pipeline. These tasks fall into a number of different areas: (a) Utility pigs which perform a function such as cleaning, separating products in-line or dewatering the line; (b) Inline inspection pigs which are used to provide information on the condition of the pipeline and the extent and location of any problem (such as corrosion for example) and (c) special duty pigs such as plugs for isolating pipelines.

Q. Why is it called pigging?

One theory is that two pipeliners were standing next to a line when a pig went past. As the pig travelled down the line pushing out debris, one of them made the comment that it sounded like a pig squealing. The pig in question consisted of leather sheets stacked together on a steel body. Without doubting the authenticity of the story, it does indicate that these tools have been around for some time. Another theory is that PIG stands for Pipeline Intervention Gadget.

Q. What is the purpose of pigging?

Pipelines represent a considerable investment on behalf of the operators and can often prove strategic to countries and governments. They are generally accepted as being the most efficient method of transporting fluids across distances. In order to protect these valuable investments, maintenance must be done and pigging is one such maintenance tool.

During the construction of the line, pigs can be used to remove debris that accumulates. Testing the pipeline involves hydro-testing and pigs are used to fill the line with water and subsequently to dewater the line after the successful test. During operation, pigs can be used to remove liquid hold-up in the line, clean wax off the pipe wall or apply corrosion inhibitors for example. They can work in conjunction with chemicals to clean pipeline from various build-ups.

Inspection pigs are used to assess the remaining wall thickness and extent of corrosion in the line, thus providing timely information for the operator regarding the safety and operability of the line. Pigs (or more specifically) plugs can be used to isolate the pipeline during a repair.

Q. How is the correct pig selected for a given pipeline?

There are many different pigs available in the market place and many different suppliers (see PPSA membership list). Choosing the correct pig is an involved process but if performed in a methodical way, the right choice can be made. It is important to set the objective and define the task that the pig has to perform. This may be removal of a hard scale in an 8 line for a cleaning pig or the location of corrosion pits in a 24 sour gas line for an inspection pig for example. Operating conditional can sometimes dictate the type of pig that must be considered. For example, an ultrasonic pig requires a liquid couplant around the pig and this may be difficult to achieve in a gas pipeline.

The pipeline layout and features will dictate the geometry of the pig largely. The pig must be long enough to span features such as wyes and tees yet must be short enough to negotiate bends. Changes in internal line diameter will influence the design effort required for the pig. In summary, the correct pig type is chosen for the task but then the pipeline design and operating conditions will affect the actual design of the pig.

Q. What inspection Techniques are there?

The main inspection methods that are used are MFL (Magnetic Flux Leakage) and UT (Ultrasonics). MFL is an inferred method where a strong magnetic flux is induced into the pipeline wall. Sensors then pick up any leakage of this flux and the extent of this leakage indicates a flaw in the pipe wall. For instance, internal material loss in the line will cause flux leakage that will be picked up by the sensors. Defect libraries are built up to distinguish one defect from another.

Ultrasonic inspection is a direct measurement of the thickness of the pipe wall. A transducer emits a pulse of ultrasonic sound that travels at a known speed. The time taken for the echo to return to the sensor is a measurement of the thickness of the pipe wall. The technique needs a liquid through which the pulse can travel. The presence of any gas will affect the output.

Q. What are the differences between offshore and onshore pipelines and their intelligent pigging procedures?

Offshore pipelines are of thicker wall than onshore-sometimes up to 35mm thick.

Offshore pipelines can have greater operating pressures, particularly the deepwater pipelines offshore Angola, Brazil or Gulf of Mexico. Maximum operating pressures onshore can be 100barg but offshore can be 300barg.

Flowrates of products both onshore and offshore are the same dependant upon the type of pipeline or its position with regard to transporting product either between offshore platforms or from platform to shore.

Offshore pipelines tend to be protected by a concrete outer coating and sacrificial anodes fitted to the pipeline every 100 metres so the outside of offshore pipelines tend not to suffer corrosion but may get damaged by sea bed movement or anchors from ships.

Inspection of offshore pipelines tends to look for internal problems.

The most favoured inspection methods are either ultrasonic or magnetic flux inspection.

Ultrasonic can inspect very thick wall pipe but magnetic flux is limited because of how strong the magnets need to be to get enough magnetism in the wall of the pipe to enable good results to be obtained. Sometimes some pipelines can only be inspected using ultrasonic techniques because of the wall thickness.

Generally running pigs in offshore pipelines is very similar to running in onshore lines, after the wall thickness and higher pressures are taken in to consideration.

One very important thing to realise with offshore inspection is that the pig must not get stuck in the pipeline as retrieving it will be much more expensive than from an onshore pipeline.

Q. What is a Plug?

A plug is a specialist pig that can be used to isolate a section of pipeline at pressure while some remedial work is undertaken. For example, a valve can be changed out while the pipeline remains at pressure. This can be done by setting two plugs either side of the valve. Work can then proceed on removing the existing valve and installing the new one. In complex systems, this can allow production to continue while maintenance work proceeds at a platform for example.

The plugs can withstand pressures up to 200 bars typically. The plug works by gripping into the line pipe and then having a separate sealing system. Lower pressure techniques include High Friction pigs, which provide a barrier for depressurised systems.

Q. Is it possible to pig multi-diameter pipelines?

For economic reasons, a number of dual diameter pipelines have been designed and built in recent years. An existing riser or J-tube at a platform may require that there is a difference between the pipeline and the riser diameters. Tying a line into an existing pipeline may result in a change in diameter from one to the next. Dual and Multi-diameter pigs have had to be designed and tested to allow such systems to be pigged.

These include pre-commissioning pigs for dewatering the lines; operational pigs to allow liquid hold-up to be removed from gas lines and inspection pigs to provide information on the line. Typical examples of dual diameter lines include a 10 x 8 line, a 20 x 16 and a multi-diameter line 11 x 12 x 14. The biggest line is the sgard gas export line, which is 28 x 42 in the Norwegian sector of the North Sea. This can be both pigged and inspected.

Q. How often should a pipeline be pigged?

Pigging frequency depends largely on the contents of the pipeline. Some sales gas pipelines for example are normally never pigged. This is since there is little by way of liquid to remove or debris / corrosion products in the line. On the other hand, production oil lines can suffer from wax deposition, which must be managed in order to allow production to continue.

It is difficult to give general guidance on this, as the pigging frequency must be set for each specific pipeline. The general advice would be that a pig is a valuable flow assurance tool and a decision should be reached with the operator on the frequency of pigging based on the flow assurance analysis of the line and in conjunction with the pigging specialists. Likewise, inspection intervals should be based on discussions between integrity management and the pig vendors.

Pigging in the context of pipelines refers to the practice of using pipeline inspection gauges or 'pigs' to perform various maintenance operations on a pipeline. This is done without stopping the flow of the product in the pipeline.

These operations include but are not limited to cleaning and inspecting of the pipeline. This is accomplished by inserting the pig into a 'pig launcher' (or 'launching station') - a funnel shaped Y section in the pipeline. The launcher / launching station is then closed and the pressure-driven flow of the product in the pipeline is used to push it along down the pipe until it reaches the receiving trap the 'pig catcher' (or receiving station).

If the pipeline contains butterfly valves, or reduced port ball valves, the pipeline cannot be pigged. Full port (or full bore) ball valves cause no problems because the inside diameter of the ball is the same as that of the pipe.

Pigging has been used for many years to clean larger diameter pipelines in the oil industry. Today, however, the use of smaller diameter pigging systems is now increasing in many continuous and batch process plants as plant operators search for increased efficiencies and reduced costs.

Pigging can be used for almost any section of the transfer process between, for example, blending, storage or filling systems. Pigging systems are already installed in industries handling products as diverse as lubricating oils, paints, chemicals, toiletries, cosmetics and foodstuffs.

Pigs are used in lube oil or painting blending: they are used to clean the pipes to avoid cross-contamination, and to empty the pipes into the product tanks (or sometimes to send a component back to its tank). Usually pigging is done at the beginning and at the end of each batch, but sometimes it is done in the midst of a batch, e.g. when producing a premix that will be used as an intermediate component.

Pigs are also used in oil and gas pipelines: they are used to clean the pipes but there are also "smart pigs" used to measure things like pipe thickness and corrosion along the pipeline. They usually do not interrupt production, though some product can be lost when the pig is extracted. They can also be used to separate different products in a multiproduct pipeline.

Q. What are pigs and pipeline pigging?

A pig is a device inserted into a pipeline which travels freely through it, driven by the product flow to do a specific task within the pipeline. These tasks fall into a number of different areas: (a) Utility pigs which perform a function such as cleaning, separating products in-line or dewatering the line; (b) Inline inspection pigs which are used to provide information on the condition of the pipeline and the extent and location of any problem (such as corrosion for example) and (c) special duty pigs such as plugs for isolating pipelines.

Q. Why is it called pigging?

One theory is that two pipeliners were standing next to a line when a pig went past. As the pig travelled down the line pushing out debris, one of them made the comment that it sounded like a pig squealing. The pig in question consisted of leather sheets stacked together on a steel body. Without doubting the authenticity of the story, it does indicate that these tools have been around for some time. Another theory is that PIG stands for Pipeline Intervention Gadget.

Q. What is the purpose of pigging?

Pipelines represent a considerable investment on behalf of the operators and can often prove strategic to countries and governments. They are generally accepted as being the most efficient method of transporting fluids across distances. In order to protect these valuable investments, maintenance must be done and pigging is one such maintenance tool.

During the construction of the line, pigs can be used to remove debris that accumulates. Testing the pipeline involves hydro-testing and pigs are used to fill the line with water and subsequently to dewater the line after the successful test. During operation, pigs can be used to remove liquid hold-up in the line, clean wax off the pipe wall or apply corrosion inhibitors for example. They can work in conjunction with chemicals to clean pipeline from various build-ups.

Inspection pigs are used to assess the remaining wall thickness and extent of corrosion in the line, thus providing timely information for the operator regarding the safety and operability of the line. Pigs (or more specifically) plugs can be used to isolate the pipeline during a repair.

Q. How is the correct pig selected for a given pipeline?

There are many different pigs available in the market place and many different suppliers (see PPSA membership list). Choosing the correct pig is an involved process but if performed in a methodical way, the right choice can be made. It is important to set the objective and define the task that the pig has to perform. This may be removal of a hard scale in an 8 line for a cleaning pig or the location of corrosion pits in a 24 sour gas line for an inspection pig for example. Operating conditional can sometimes dictate the type of pig that must be considered. For example, an ultrasonic pig requires a liquid couplant around the pig and this may be difficult to achieve in a gas pipeline.

The pipeline layout and features will dictate the geometry of the pig largely. The pig must be long enough to span features such as wyes and tees yet must be short enough to negotiate bends. Changes in internal line diameter will influence the design effort required for the pig. In summary, the correct pig type is chosen for the task but then the pipeline design and operating conditions will affect the actual design of the pig.

Q. What inspection Techniques are there?

The main inspection methods that are used are MFL (Magnetic Flux Leakage) and UT (Ultrasonics). MFL is an inferred method where a strong magnetic flux is induced into the pipeline wall. Sensors then pick up any leakage of this flux and the extent of this leakage indicates a flaw in the pipe wall. For instance, internal material loss in the line will cause flux leakage that will be picked up by the sensors. Defect libraries are built up to distinguish one defect from another.

Ultrasonic inspection is a direct measurement of the thickness of the pipe wall. A transducer emits a pulse of ultrasonic sound that travels at a known speed. The time taken for the echo to return to the sensor is a measurement of the thickness of the pipe wall. The technique needs a liquid through which the pulse can travel. The presence of any gas will affect the output.

Q. What are the differences between offshore and onshore pipelines and their intelligent pigging procedures?

Offshore pipelines are of thicker wall than onshore-sometimes up to 35mm thick.

Offshore pipelines can have greater operating pressures, particularly the deepwater pipelines offshore Angola, Brazil or Gulf of Mexico. Maximum operating pressures onshore can be 100barg but offshore can be 300barg.

Flowrates of products both onshore and offshore are the same dependant upon the type of pipeline or its position with regard to transporting product either between offshore platforms or from platform to shore.

Offshore pipelines tend to be protected by a concrete outer coating and sacrificial anodes fitted to the pipeline every 100 metres so the outside of offshore pipelines tend not to suffer corrosion but may get damaged by sea bed movement or anchors from ships.

Inspection of offshore pipelines tends to look for internal problems.

The most favoured inspection methods are either ultrasonic or magnetic flux inspection.

Ultrasonic can inspect very thick wall pipe but magnetic flux is limited because of how strong the magnets need to be to get enough magnetism in the wall of the pipe to enable good results to be obtained. Sometimes some pipelines can only be inspected using ultrasonic techniques because of the wall thickness.

Generally running pigs in offshore pipelines is very similar to running in onshore lines, after the wall thickness and higher pressures are taken in to consideration.

One very important thing to realise with offshore inspection is that the pig must not get stuck in the pipeline as retrieving it will be much more expensive than from an onshore pipeline.

Q. What is a Plug?

A plug is a specialist pig that can be used to isolate a section of pipeline at pressure while some remedial work is undertaken. For example, a valve can be changed out while the pipeline remains at pressure. This can be done by setting two plugs either side of the valve. Work can then proceed on removing the existing valve and installing the new one. In complex systems, this can allow production to continue while maintenance work proceeds at a platform for example.

The plugs can withstand pressures up to 200 bars typically. The plug works by gripping into the line pipe and then having a separate sealing system. Lower pressure techniques include High Friction pigs, which provide a barrier for depressurised systems.

Q. Is it possible to pig multi-diameter pipelines?

For economic reasons, a number of dual diameter pipelines have been designed and built in recent years. An existing riser or J-tube at a platform may require that there is a difference between the pipeline and the riser diameters. Tying a line into an existing pipeline may result in a change in diameter from one to the next. Dual and Multi-diameter pigs have had to be designed and tested to allow such systems to be pigged.

These include pre-commissioning pigs for dewatering the lines; operational pigs to allow liquid hold-up to be removed from gas lines and inspection pigs to provide information on the line. Typical examples of dual diameter lines include a 10 x 8 line, a 20 x 16 and a multi-diameter line 11 x 12 x 14. The biggest line is the sgard gas export line, which is 28 x 42 in the Norwegian sector of the North Sea. This can be both pigged and inspected.

Q. How often should a pipeline be pigged?

Pigging frequency depends largely on the contents of the pipeline. Some sales gas pipelines for example are normally never pigged. This is since there is little by way of liquid to remove or debris / corrosion products in the line. On the other hand, production oil lines can suffer from wax deposition, which must be managed in order to allow production to continue.

It is difficult to give general guidance on this, as the pigging frequency must be set for each specific pipeline. The general advice would be that a pig is a valuable flow assurance tool and a decision should be reached with the operator on the frequency of pigging based on the flow assurance analysis of the line and in conjunction with the pigging specialists. Likewise, inspection intervals should be based on discussions between integrity management and the pig vendors.PAGE 42