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