3.1 Introduction
Numerous components are required for operation besides the actual boiler and the burners. Some of these components are required by law. However, even the parts that are not required by law are essential if the plant is to operate reliably. This book cannot deal with all the details relating to the legal regulations that apply in each case. These are published in regulations and directives (TRD) issued by the EU, TÜV and VGB. Regulations and safety measures for fire tube boilers are set out in DIN EN 12953. Water tube boilers are covered in DIN EN 12952. This chapter covers continuous blowdown valves, bottom blowdown valves, safety valves, water level indicators, feedwater valves and water separators.
3.2 Bottom or Intermittent and continuous blowdown valves
A small proportion of the boiler water is drained off through a valve during continuous and intermittent blowdown processes. It is necessary to differentiate between:
- Continuous blowdown, which aims to ensure that the salt content of the boiler water does not rise too high and
- Bottom or intermittent blowdown required by law, which drains off the boiler as quickly as possible in the event of an emergency.
If required, the device used for the latter process can also be used to remove the sludge collected at the bottom of the boiler.
Bottom or Intermittent blowdown valves
The process of removing the sludge at the bottom of the boiler using a manual blowdown valve is also known as "Bottom Blowdown". The intermittent blowdown valve is fitted at the bottom of the boiler, and is opened for approx. 2 seconds once or twice a day in order to purge the collected sludge from the bottom of the boiler.
A spring-loaded fast-acting drain valve, which is opened using a lever to counteract the spring action, is used to do this. Fig. 3-1.
Fig. 3-1: Intermittent blowdown valve, ARI Type STEVI®BBD 415
On this type of valve, the boiler pressure is behind the plug, thus ensuring that the valve is well sealed. The seat and plug must meet strict requirements. The plug must be shaped in such a way that small particles of boiler scale and other dirt do not become trapped between the plug and the seat. Also, the valve's resting position should be 'closed'
In addition to the manual version, the valve may be operated pneumatically. This allows the intermittent blowdown process to be automated using a timer switch.
Because the release of energy is so great during bottom blowdown, regulations require that systems are in place to ensure that only one boiler is blowndown at one time. This usually means that if a manual system is in use, then only one operating handle is available. If an automated system is used, then the controls should be interlocked to prevent simultaneous operation of the valves.
Continuous (or TDS) blowdown valves
This type of blowdown uses a control valve rather than a spring-loaded valve. The continuous blowdown valve is fitted high on the side of the boiler to avoid dirt being entrained with the blowdown water
On many boiler systems this continuous blowdown is fitted approx. 200 mm below the water surface of the evaporation space. It has been shown that, when the steam boiler is under full load, the highest concentration of salts is at this point. The disadvantage is that the highest salt concentration is at the bottom when the boiler is operating at low load and the blowdown loss is therefore also the greatest.
The simplest continuous blowdown valve is a control valve with a scale indicating the valve opening.
Systems have come on to the market in recent years which use the conductivity measurement to control boiler water continuous blowdown automatically. Refer to Chapter 3.17 Continuous (TDS) and bottom blowdown process.
3.3 Safety valves
The steam pressure in the boiler is controlled automatically. If the steam pressure is too low, more combustion air and fuel are added. If the pressure increases, the supply of fuel and combustion air is reduced. If a fault develops in the pressure control system, or the steam consumption suddenly stops, it is possible that pressure within the boiler can increase. Regulations specify that the pressure in the boiler must never rise more than 10 % above the maximum permissible pressure. For this reason, the safety valve needs to open quickly to vent the excess pressure. The safety valve needs to be sized so that it has sufficient capacity to discharge all the steam without the permissible pressure being exceeded by more than 10 %. If two safety valves are specified, the total seat cross-section must meet these requirements.
Safety valves are safety related components, which are subject to regular checks by an independent authority (e.g. TÜV).
Fig. 3-2: Spring-loaded safety valve, here ARI Type SAFE 902
In a safety valve, the plug (disc) is closed, preventing the steam exiting out to the atmosphere. The spring in the bonnet transfers its force to the plug via the stem. The spring preloading, and hence the valve set pressure, can be varied using the adjusting screw. A lead seal is fitted to the cap to prevent this setting being adjusted by unauthorised persons. The flexibly mounted plug is in contact with the seat. Both the seat and the plug are precision lapped to provide a good seal, and a long service life. As the safety valve is normally closed, the top surface of the seat is covered by a plate to prevent deposits from forming. For high temperature steam applications, an open bonnet prevents the spring from becoming too hot: if a spring becomes too hot it reduces its force and results in a fall in the set pressure. A drain hole is provided to ensure that the body of the valve is clear is condensate which could impair the valve's performance.
3.4 Water level indicators
The correct water level in a steam boiler is an important factor for correct operation. If heat is not transferred to the water in the boiler, the boiler pipes and walls become so overheated that they may suffer heat damage and ultimately, failure.
To comply (with TRD 401 each steam generator), with the exception of the continuous-flow steam generator, must be equipped with at least two devices that allow the water level to be determined from the boiler control room; this is most commonly a gauge glass. A gauge glass can be replaced by:
- Two remote water level display devices or
- A reliable water level control system or a water level limiter which at least shows the water level directly.
With the first system, the boiler operator in charge does not have to be able to see the gauge glass.
Low water level
According to TRD 401 an indicator to show the lowest water level needs to be affixed in close proximity to the water level indicator
- The lowest water level (NW) must be at least 100 mm above the highest point of the steam generator heating flues.
- The lowest water level (NW) is also to be defined as a point where it takes not less than 7 minutes to evaporate the water down to the highest point of the steam generator heating flues. (Sometimes referred to as 'sinking time')
- The lowest point of the water level indicator is 50 mm below NW - in other words, 50 mm above the highest point of the heated surface.
- If the water level drops below this value (no more water in the water level indicator), the burner should switch off automatically. This process is so important for safety that two control circuits that operate independently of each other are required (sensor A and B).
Other regulations not listed here must be complied with, depending on whether the boiler plant is monitored continuously, to a limited extent or not at all.
Fig. 3-3 shows the exact position of a water level monitoring device.
Fig. 3-3: Water level indicator for flame tube and water tube boilers
On a fire tube boiler the highest point of the heated surface is the top of the combustion chamber but on a water tube boiler the highest point is on the top downcomer tube.
Types of water level indicator
Reflex and transparent indicators are probably the most common types of water level indicators in use. A reflex water level indicator (Fig. 3-4) incorporates a thick square piece of glass with prismatic grooves on the water side. The water level indicator is fitted with pipe connections, screwed sockets and sealing rings, which are in turn connected to water level gauge cocks. Above the boiler water level, the glass prisms reflect the surrounding light. Below the boiler water level the liquid fills the prisms causing the glass to be transparent. Reflex water level indicators can be used up to a pressure of 20 bar.
Fig. 3-4: Reflex water level indicator
For steam pressures above 20 bar transparent water level indicators are more common. The steam/water space is between two flat glass plates. The back of the indicator is illuminated (Fig. 3-5). To prevent chemicals in the boiler water from etching the glass, a thin mica plate is fitted inside of the glass. If a leak develops in the water level indicator, a ball closes an orifice
Fig. 3-5: Transparent water level indicator
3.5 Feedwater globe/check valves
Steam boiler plants with a feedwater pump meet the requirements of TRD 401, providing
the following conditions are satisfied:
- If the energy source powering the feedwater pump fails, the emergency stop system on the boiler firing system must be triggered.
- Steam generators must be equipped with an adjustable boiler firing system. If an emergency stop has occurred, the design of the firing system and the steam generator must have enough safeguards to prevent evaporation of the water stored in the combustion chamber and boiler pipes.
- The steam pressure and water feed must be controlled automatically. Proof must be furnished that the controller for the water feed is reliable.
- A reliable low water safety device (water level limiter) must be provided in addition to the water feed control device.
Steam boiler plants with steam generators, which do not meet this demand, must have at least two feed pumps. The capacity of the feed pumps must be equivalent to 1.25 times the 'from & at' rating of all the system's steam generators allowed for operation.
If more than 5 % of boiler water as compared to the 'from & at' rating is continuously removed, the capacity of the feed pumps must exceed this volume by 5 %.
In addition, where at least two feed pumps are used, the following requirements must be observed:
- If the feed pump with the greatest capacity fails, the remaining feed pumps must be able to handle the total capacity.
- Two sources of energy independent of each other must be available. The feed pumps are to be connected to the source of energy so that, if one source of energy fails, the feed pumps that are still operational are able to handle the total required capacity.
It is permissible for both pumps to supply the boiler via one feedwater pipe. If several steam boilers are installed, one back-up pump is sufficient. This means that three feedwater pumps are to be installed for two boilers. Each feedwater pump should be provided with one check valve with a shut-off feature. The purpose of this valve is to prevent the contents of the boiler flowing out into the boiler house if a pipe breaks. In addition, the check valve prevents boiler water from flowing back into the feedwater system should the feedwater pump fail and a pump check valve fail to operate.
There are valves and fittings which combine both functions (shut off and stopping return flow) in a single housing (Screw down non-return or SDNR valve).
Fig. 3-6: Check valve, ARI Type 003
Fig. 3-7:Check valve with shut-off feature, ARI Type FABA®-Plus 046 with loose plug and spring
3.6 Separators
The steam produced in the boiler typically contains between 5 and 10 % water (by mass). This mixture of saturated steam and fine particles of water is generally called wet steam. The water content many be much higher if:
- There is an excessively high level of water in the boiler
- The rate at which steam is drawn from the boiler is too high (overload)
- The TDS concentration in the boiler water is too high.
Wet steam also forms if the steam condenses in a distribution pipe, e.g. as a result of poor or no insulation or if the pipe to the consumer is too long and it does not contain enough drainage points. These last causes given are very simple to eliminate. Chapter 5.0 Pipe Drainage looks at the drainage of steam pipes.
The two most important prerequisites for a "dry" steam pipe are:
- Steam traps in the steam pipe every 50 to 75 m, depending on the insulation.
- Steam traps with drainage points at each rising section of the steam pipe.
Most process equipment is very sensitive to condensate entrained with steam. Water particles striking the wall of a pipe, on a bend, for example, at a speed of 20 m/s (72 km/h) will cause erosion; in the long term this can lead to leakage. Thin walled steam pipes within heat exchangers can develop leaks for the same reason. It is therefore advisable to install a separator upstream of the inlet connection.
Injectors also require dry steam for reliable operation. It is advisable to install a steam separator (steam drier) to protect sensitive equipment from wet steam. Fig. 3-8 shows a cyclone steam separator which operates using centrifugal force. Here, too, the heavier water particles are separated from the steam and flow down the wall towards the steam trap.
Fig. 3-8: Cyclone steam separator
Fig. 3-9 shows a water separator with a mist eliminator (demister). The separator contains a wire mesh pack, which consists of several layers of knitted and corrugated metal wires. This provides a certain density of mesh.
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Fig. 3-9: Water separator with a mist eliminator (demister)
The water particles are trapped and collected by the wires. In contrast to the water particles, steam can very easily find a way through this tightly knitted mesh. The small particles collect at points where the wires of the mesh cross and form small droplets. Above a certain droplet size they fall in the opposite direction to the flow. In spite of the close density of the woven mesh, a free passage of approx. 98 to 99 % remains. The pressure loss is minimal. In order to achieve a dryness of 99.5 %, the speed of the steam in the demister should be between 2.5 and 7.5 m/s.
- If the speed is too low, the water particles do not stick to the wires
- If the speed is too high, the droplets are entrained in the steam
If there is likelihood that water particles will be entrained during steam generation, a separator should be fitted directly at the boiler steam outlet. As a general rule, boiler manufacturer's pre-install cyclone-type separators in water tube boilers.
3.7 Pressure reducing valves
Not all process equipment is designed to work at the operating pressure of a steam boiler. In order to condition the steam pressure upstream of an item of equipment, pressure reducing valves are fitted upstream. Example: Autoclaves, evaporators and also deaerators. In these cases, a pressure reducing valve controls the steam pressure so that the permissible pressure is not exceeded. A safety valve must be fitted downstream of the pressure reducing valve in order to ensure that, if the pressure reducing valve develops a fault, a hazardous situation cannot occur. A steam trapset must always be installed upstream of a pressure reducing valves. Fig. 3-10 shows a pressure reducing system with all associated devices, valves and fittings. Because the steam temperature would damage the diaphragm in the pressure reducing valve, a small vessel is fitted upstream of the control line.
Fig. 3-10: Pressure reducing system, ARI Type PRESys®
Fig. 3-11 shows a directly controlled pressure reducing valve. The spring tension (and therefore the required steam pressure) can be set using an adjusting nut on the stem.
Fig. 3-11: Pressure reducing valve, ARI Type PREDU®
Self-operated pressure reducing valves operate using the pressure of the medium as the motive force. Their purpose is to reduce a high pressure (upstream pressure) to a lower one (downstream pressure). The valve is required to modulate to maintain a specific downstream pressure even in the case of changes in upstream pressure fluctuations, or changes in flowrate. A marginal seat is screwed into the through housing. The plug has a small parabolic shoulder, which ensures the control process is not affected by vibration even at very low flow rates. The pressure reducing valve has two stainless steel bellows. The lower one is used to seal the stem from the outside. The upper one is the balancing bellows, which is used to balance out forces at the plug. To achieve this, the upstream pressure reaches the interior on the outside of the bellows through a bore in the plug. The inner side of the bellows is connected to the downstream pressure side via openings. As the effective area of the bellows is the same size as the area of the seat, the differential pressures are compensated and the influence of fluctuations in upstream pressure is only minimal.
The pressure reducing valve is operated by the diaphragm. The downstream pressure acts on the diaphragm via the buffer unit (water seal pot) and balances against the force of the spring. The pre-tensioning of the spring can be changed by the adjusting mechanism so that both forces are balanced at the desired downstream pressure. If the flowrate of steam changes, the plug is adjusted until balance is achieved again.
The pressure reducing valve in Fig. 3-11 is directly actuated by the steam pressure. Electrically or pneumatically actuated control valves are used almost exclusively for precise pressure control. Pressure is measured using a pressure sensor, which passes a signal to the process controller. This compares the specified value with the actual value and, depending on the control deviation, outputs a signal of 4 - 20 mA to an electro-pneumatic positioner, which changes the position of the control valve.
3.8 Water treatment
Introduction
In spite of the many publications on boiler feedwater treatment, misunderstandings frequently occur.
Water chemistry is a complex subject which requires all the skill of a trained chemist. This chapter is a simple explanation of how and why boiler feedwater is treated in practice. Firstly, we will discuss softening feedwater in low-pressure boiler plants. The aim is to prevent deposits from forming on heated parts of the boiler. Feedwater treatment for highpressure boiler plants will be discussed later.
Generally, boiler feedwater is a mixture of returned condensate and feedwater. Condensate is condensed steam, equivalent to distilled water, and it can generally be used again as feedwater with only a minimal amount of additional treatment. Additional feedwater is required to replace the loss of condensate in the water/steam circuit. This loss of condensate is produced by:
- Steam injection for heating, e.g. for a water tank
- Contaminated condensate, which has been made unusable for further use as a result of contamination by lubricating oil or process chemicals.
- Condensate is not being returned
- Continuous boiler blowdown
- Steam and water leaks
- Water vapour and flash steam into the atmosphere
Sources of feedwater
The main sources of feedwater are:
- Groundwater, such as wells and spring water
- Bodies of surface water such as rivers, lakes or ponds
- Drinking and service water
Natural sources of water cannot automatically be used as feedwater for boiler plants. Most sources of ground and surface water are contaminated by a variety of substances so that, if it is used as feedwater without being treated, it would result in damage being caused to the boiler plant.
Even drinking water processed in water works is not suitable to be used as boiler feedwater. Clearly, feedwater needs to be treated and monitored. Apart from steam boilers, feedwater pipes and condensate pipes must be protected against corrosion.
Water chemistry
In the following section, we will try not to use any more chemical terms than are absolutely necessary. Where possible, we have replaced chemical notations and formulas with the chemical names, adding the formula in brackets, if necessary.
The following chemical compounds occur in water:
| Designation | Chemical formula |
| Calcium hydrocarbonate | Ca(HCO3)2 |
| Magnesium hydrocarbonate | Mg(HCO3)2 |
| Calcium sulphate | CaSO4 |
| Magnesium sulphate | MgSO4 |
| Calcium chloride | CaCl2 |
| Magnesium chloride | MgCl2 |
| Common salt | NaCl |
| Silicic acid | SiO2 |
In summary, one can say that the chemical compounds in water consist of calcium and magnesium coupled with hydrocarbonates (bicarbonates), sulphates and chlorides. In addition to this, there is sodium coupled with chlorides and silicic acid. Calcium and magnesium compounds are hardening constituents. These compounds must first be broken down before the water can be used as feedwater. The molecules of the salts dissolved in the water split up (dissociate) into electrically charged particles called ions. Calcium hydrocarbonate splits into calcium (Ca) and hydrocarbonate (HCO3)2. Magnesium hydrocarbonate dissociates in the same way
Calcium and magnesium hydrocarbonate are difficult to dissolve in water. They represent carbonate hardness (or carbonates of alkaline earths). Once the water is heated, they will be deposited on or in the boiler pipes. The carbon dioxide escapes as a gas and condenses with the steam to form acidic water. The pH value drops sharply and results in the dreaded carbonic acid corrosion in the condensate pipes. Calcium and magnesium compounds containing sulphates and chlorides form the noncarbonated hardness (or non-carbonates of alkaline earths) and remain soluble in water. Only when the concentration in the boiler water has become much too high, e.g. as a result of too little continuous blowdown, can non-carbonates cause scale deposits.
The sum of carbonate harness and non-carbonate hardness produces total hardness (total of alkaline earths).
Requirements for feedwater
It is sufficient for a low-pressure boiler if the carbonate hardness is removed from the water using an ion exchanger (softener). Chloride and sodium are not critical if the concentration is low.
In the case of high-pressure boilers, if possible all impurities should be removed. A complex ion exchanger, a so-called demineralisation plant, is used for this. The rule that applies is the higher the steam pressure, the higher the requirement for water purity. Demands in relation to the composition of boiler feedwater are especially high where steam is used to drive a turbine.
In order to prevent the hardness from dis-associating in the softener in low-pressure systems (which do not always work perfectly), metered chemicals are added to eliminate the residual hardness. In this form, the hardness cannot be deposited in or on the boiler pipes but instead it collects at the bottom as sludge. The sludge is then removed during the bottom blowdown process. Orthophosphates and polyphosphates are then used as residual softening agents. Recently, increasing use has been made of polymers and complex binders for reasons of environmental protection.
If scale is deposited on or in the boiler pipes, it reduces the amount of heat transferred. As the layers of scale become thicker, the wall of the pipe overheats and there is a serious risk that the pipe will burst, Fig. 3-12.
Fig. 3-12: Burst boiler pipe
Fig. 3-13 shows the difference in the temperature characteristic between a clean pipe wall (maximum temperature 380 ºC) and a wall where the thickness of boiler scale is 1 mm (maximum temperature 670 ºC).
Fig. 3-13: How the layer of scale influences the temperature of the pipe wall
The ion exchanger operates according to the principle that magnesium and calcium ions are replaced by less damaging sodium and hydrogen ions. This softens the water and demineralises it.
An ion exchanger is a vessel, also called a filter, which is filled with plastic waterproof granules. These granules are able to exchange their absorbed ions for the ions present in the water. Styrol resins are almost exclusively used for these granules. The sodium or hydrogen ions in the resin are replaced by the magnesium or calcium ions in the water.
All metal (Na+, Ca++) and hydrogen ions (H+) have a positive charge. Acidic residues (Cl- , SO4 --, CO3 --) and hydroxide ions (OH- ) have a negative charge.
Ions with a positive charge are called cations. Ions with a negation charge are anions. In aqueous solutions there are always an equal number of cations and anions. Ion exchangers are divided into two main groups:
- Weakly and strongly acidic cation exchangers
- Weakly and strongly basic anion exchangers
These exchangers soften, partly demineralise and fully demineralise water in systems with one or two filters.
3.9 Softening
Process
A cation filter or cation exchanger (also known as a 'base exchange' softening unit) is commonly used to soften water (replacing calcium and magnesium ions). A resin bed is enriched with sodium ions (made of NaCl) in common salt brine. Upon leaving the unit, all calcium and magnesium ions have been replaced by sodium ions and the water has been softened.
The exchange process only functions up to a certain saturation level. The filter reaches its performance limit when the number of exchanged ions is almost equal to the number of absorbed sodium ions. A full exchange is then no longer possible.
Exceeding the limit allows unwanted ions to escape through the unit; the water remains 'hard' and is no longer suitable as feedwater. Generally, base exchange units comprise two cylinders, one on-line, and the other on re-generation/stand-by.The resin bed is regenerated by back-flushing with a brine solution.The regeneration process takes place in three phases:
Removal from service -> Flushing -> Regeneration -> Washing -> Starting up
The purpose of flushing is to loosen up the exchange material and remove dirty particles.
A 10 % common salt solution is required for regeneration. The regeneration process is the reverse to the softening process. All calcium and magnesium ions absorbed from the resin are exchanged for sodium ions in the brine. The calcium and magnesium ions are discharged into the waste water system with the washing water. The resin granules should remain sufficiently long in contact with the brine in order to regenerate fully. The manufacturers of resins specify a regeneration time and the percentage of brine per m3 of resin. The brine is displaced with water in the last stage of the process. Only then is the filter ready for a new softening process. This procedure is fully automated for the majority of softeners.
| Composition of softened water |
| Sodium hydrogen carbonate | NaHCO3 |
| Sodium sulphate | Na2SO4 |
| Common salt | NaCl |
| Silicic acid | SiO2 |
| Composition of untreated water |
| Calcium hydrogen carbonate | Ca(HCO3)2 |
| Magnesium hydrogen carbonate | Mg(HCO3)2 |
| Calcium sulphate | CaSO4 |
| Magnesium sulphate | MgSO4 |
| Calcium chloride | CaCl2 |
| Magnesium chloride | MgCl2 |
| Common salt | NaCl |
| Silicic acid | SiO2 |
Fig. 3-14: Softening in the cation exchanger
The softening process is shown as a diagram in Fig. 3-14. After the process, all calcium and magnesium ions have been removed from the water and replaced by sodium sulphate, common salt, sodium hydro-carbonate and silicic acid. This mixture still contains hydrocarbonates and can cause carbonic acid corrosion.
Protection against residual hardness
If a fault occurs during the process (concentration of brine too low, time switch defective or cooling water in the condensate), the hardening constituents remain dissolved and can be deposited on or in the pipes.
In order to make the hardening constituents in the steam boiler inert, primarily phosphates (ortho-phosphates, tri-sodium phosphates) are metered so that the hardening constituents are precipitated as sludge on the bottom of the boiler. The concentration of phosphates in the boiler water must be between 25 and 50 mg/l and must be monitored regularly.
If the concentration drops suddenly, this is a sign that a source of hardness has entered somewhere in the system. The cause must be ascertained very quickly and eliminated. Chelates are also used in addition to phosphate metering. However, chelates are difficult to handle and therefore they are metered in combination with phosphates. Here the phosphates act as a tracker. An environmentally friendly agent binds the phosphates, which distribute the hardness in such fine particles that it is not deposited as scale.
3.10 Formation of corrosion
Apart from the care required to supply the boiler with water of the required quality, undesirable gases must be prevented from entering the boiler. The presence of oxygen in the feedwater causes corrosion in the boiler and the rest of the steam system. The presence of carbon dioxide results in acidic corrosion or carbonic acid corrosion in the condensate system. A deaerator removes the oxygen (see Chapter 3.14 Deaerator).
Carbon dioxide is partially removed in the deaerator. The remaining carbon dioxide is neutralised by means of decarbonisation and chemicals.
Carbon dioxide
In water chemistry carbon dioxide comes in free and bound form. Free carbon dioxide (CO2) is absorbed from the air. Bound carbon dioxide comes in the form of hydrocarbonate (-HCO3).
Free carbon dioxide and oxygen are expelled in a deaerator. However, the temperature in the deaerator is too low to split and remove the hydrocarbonate. The hydrocarbonate is taken with the feedwater to the steam boiler. As a result of the high temperature the hydrocarbonate breaks down into carbon dioxide and water. The carbon dioxide enters the steam system. During the condensation process the carbon dioxide dissolves in the condensate. The condensate becomes acidic, with a pH value between 4 and 5. It subsequently causes corrosion in the condensate system, especially if the plant is out of service and condensate remains in the pipes.
Neutralising chemicals in the form of volatile alkaline agents such as ammonia or amines are metered in order to prevent this acidic corrosion. Sometimes amines are also metered in order to apply a protective layer to the inside of the pipes in the condensing part of the system. A disadvantage of the amines that form this protective layer is that they dissolve old layers of corrosion, which in turn clog steam traps and cause additional sludge to form on the bottom of the boiler. It is advisable to be especially cautious!
Decarbonisation is another method of removing hydrocarbonate. Hydrocarbonate is split into carbon dioxide and water by metering acid into the softened water. The carbon dioxide is then expelled in a CO2 sprinkler via air flow. After this treatment the pH value of the acidic water must be increased to a value of approx. 8 by means of chemicals (for example, caustic soda).
Metering caustic soda causes an increase in drain loss.
CO2 sprinkler
Fig. 3-15 shows a CO2 sprinkler. The sprinkler consists of a packed column over a water basin.
Fig. 3-15: CO2 sprinkler
The acidic water evaporates in the upper part and then trickles into a water basin via several layers filled with plastic rings. Air is blown in the opposite direction to the water. This means that air and water come into contact with each other very vigorously. The carbon dioxide is removed down to a figure of less than 10 mg/l by reducing the partial pressure for CO2. Air and CO2 are blown into the atmosphere. Because the water is aggressive (acidic), CO2 sprinklers are generally made of plastic.
3.11 Softening and decarbonisation
To remove the bound carbon dioxide, the untreated water is first passed through an H ion exchanger or H filter during the decarbonisation process in a two-filter process and it is then passed via an Na ion exchanger or Na filter. The H filter is regenerated using hydrochloric acid and the Na filter is regenerated by means of common salt, Fig. 3-16.
Fig. 3-16: Softening and decarbonisation, H and Na filters connected in series
The Ca and Mg ions are exchanged for hydrocarbonates in the H filter. Carbonic acid (H2CO3) is formed as a result. Everything else remains unchanged in the H filter. The Ca and Mg ions from the Ca and Mg chlorides are exchanged for Na ions in the Na filter.
Downstream of the Na filter the water containing the carbonic acid from the H filter is sprayed in a CO2 sprinkler. Air is blown in the opposite direction into the sprinkler from below. The carbonic acid splits into water and carbon dioxide. The carbon dioxide is blown out in the air.
Sometimes CO2 sprinklers are fitted between two filters. As a result of this, a slightly smaller Na filter can be fitted.
Both filters can also be operated in parallel. Here it is important to make sure that partial flows are correctly distributed and water quality is monitored continuously.
3.12 Demineralisation
Softening is not enough for high-pressure steam plants. Although softened water does not leave scale deposits, the high concentration of residual salts and the high steam temperature will cause corrosion. For this reason the feedwater for high pressure plants must be demineralised. Fig. 3-17 shows an example of a demineralisation system.
Fig. 3-17: Demineralisation system
A strongly acidic cation filter regenerated with hydrochloric acid is connected in series to a weak basic anion filter regenerated with a sodium hydroxide solution. The CO2 sprinkler is fitted behind the anion filter. Water from the sprinkler is already almost demineralised. The CO2 sprinkler also reduces the amount of chemicals required for the strongly basic anion exchanger. A strongly basic anion filter is fitted in addition behind the CO2 sprinkler to remove the silicic acid. A mixed bed exchanger is fitted between to act as a "policing filter" to improve the content of residual salts and silicic acid.
It is particularly necessary to remove silicic acid in the case of high-pressure steam, e.g. for turbine systems. Silicic acid is not only deposited on the heated surfaces of the steam boiler but it may also be deposited on turbine blades, thus influencing the efficiency of the turbine.
Fig. 3-18 shows the basic circuits, which are used in different combinations, depending on the properties of the untreated water, the intended use of the demineralised water and the prevailing operating combinations.
Fig. 3-18: Basic circuits of demineralisation systems
3.13 Monitoring make-up, feed and boiler water
Guidelines
A check should be made every day to monitor the quality of the make-up, feed and boiler water. Suppliers of chemicals specify the limit values for the many different characteristics of water in combination with the recommended chemicals.
The following tables provide the recommended values for fire tube boilers up to 20 bar steam pressure for feed and boiler water.
| Boiler water |
| Fire tube boiler up to 20 bar |
| p value | mmol/kg | 9 - 11 |
| Silicic acid | mg/kg | 15 x p value |
| Conductivity measurement | µS/cm | 6000 |
| Phosphates | mg/kg | 30 - 80 |
| Feedwater |
| Flame tube boiler up to 20 bar |
| pH | 7.0 | |
| Hardness | mval/kg | 0.036 |
| Iron | mg/kg | 0.3 |
| Copper | mg/kg | 0.1 |
| Oil | mg/kg | 3.0 |
| Oxygen | mg/kg | 0.1 |
Sample assessment
An example to illustrate water analysis:
| Make-up water | Feedwater deaerated | Boiler water | ||
| Conductivity measurement | µS/cm | 620 | 200 | 4000 |
| pH | 8 | 9.1 | 12.5 | |
| p value | mmol/kg | 0.1 | 24 | |
| m-value | mmol/kg | 1.8 | 0.8 | 28 |
| Chlorides | mg/kg | 20 | 10 | 320 |
| Hardness | mval/kg | <0.007 | <0.007 | |
| Phosphates | mg/kg | 60 | ||
| Sulphites | mg/kg | 90 | ||
This is what an assessment of the analysis looks like:
The hardness is below the recommended value and is in order. The chloride content of the make-up water (20 mg/kg) is a given variable but 10 mg/kg is measured in the deaerator. It can be assumed that the chloride content of the returned condensate is 0 mg/kg.
Consequently, the feedwater contains = 
make-up water.
The chloride content in the boiler is 320 mg/kg.
With regard to the make-up water, the continuous blowdown percentage is therefore 20/320 x 100 % = 6.25 %. With regard to the feedwater, the continuous blowdown percentage is 10/320 x 100 % = 3.125 %.
The continuous blowdown percentage can also be calculated using the m-value or the conductivity. The p-value is above the recommended value of 10 mmol/kg and therefore further continuous blowdown is required. The phosphate and sulphite values are reduced as a result of the increased continuous blowdown process. It is possible that the metering rate for chemicals may have to be increased.
Checking the hardness
The unit for measuring hardness is ºD (German hardness) or mval/kg. It is converted as follows:
1 ºD = 0.357 mval/kg
1 mval/kg = 2.8 ºD
A fast tried and tested method of determining the hardness of water is to put the water in a test tube with a few drops of a standardised soap solution. The solution is then shaken.
- If the head of foam remains, the water is soft.
- If the head of foam disappears or if it does not form at all, the water is hard.
3.14 Deaerator
Introduction
The boiler feedwater should be deaerated before it is supplied to the steam boiler. Feedwater is generally composed of make-up water and returned condensate. The gases contained in condensate are oxygen (O2) and free carbonic acid or carbon dioxide gas (CO2). The gases are removed in a deaerator.
Small steam generators are often not equipped with a deaerator. In this case, the gas contained in the water is removed by adding chemicals. Oxygen in the feedwater causes pitting corrosion in the boiler and on pipes. The higher the steam pressure, the lower the level of oxygen permissible in the feedwater. For boilers with steam pressure of less than 20 bar, the maximum O2 content is 0.03 mg/l. A maximum of 0.02 mg/l is permitted for higher steam pressures. Free carbon dioxide produces acidic condensate and therefore causes acid corrosion in the condensate pipes. This chapter starts with a brief description of how the deaerator works. This will be followed by a section in which the details of the different versions are covered. Finally, some recommendations will be provided for practical situations.
How deaerators work
There are two main principles:
Spray deaerators:
The feedwater is supplied to the deaerator from above via the sprayer.
Cascade deaerator:
The feedwater is sprinkled into the deaeration dome and cascades over a series of trays before falling into the body of the vessel.
For steam, the pressure is typically controlled to around 1.2 bar a. The mixture of make-up water and returned condensate is therefore heated to 105 ºC. This temperature is sufficient to drive out the gases contained in the water (105 ºC is the saturation temperature of steam at 1.2 bar a).
The deaerator operates in accordance with Henry Dalton's law on the absorption of gases. Put simply, the gases are removed from the water because the partial pressure (concentration) of the gases in the fluid is higher than the concentration of gases in the steam.
A prerequisite is that water is sprayed or distributed with the finest possible droplets into a space with saturated steam above the feedwater level. The atomisation should be so fine and the distribution so intensive that the temperature of feedwater is 105 °C before it reaches the level of the water in the vessel. Therefore, in this first stage of deaeration approximately 90 % of the gases contained are expelled with intensive spraying. In the second stage of deaeration steam is fed to the water space of the deaerator via a nozzle.
If pressurised condensate is available, this can also be fed to the deaerator. The flash steam released is used to drive out residual gases.
3.15 Spray deaerators
Design
Fig. 3-19 shows a spray deaerator. The mixture of make-up water and condensate is atomised as a fine spray from above into the steam space via a sprayer (1). The steam is supplied via a manifold (2).
In some large deaerators the manifolds are fitted in a V-type shape and are called screens (5).
Fig. 3-19: Spray deaerators
The feedwater off-take to the feed pump (3) is to be fitted as far as possible away from the water inlet. The residence time of the water in the deaerator should be a minimum of 25 minutes. To prevent water that is not yet fully deaerated from escaping, a baffle plate has been fitted in the deaerator illustrated. This baffle is not fitted in smaller deaerators. The gases are drawn off at the point with the greatest concentration of gas. This is generally directly adjacent to the spray unit (4).
Deaerators are protected inside by a special coating in order to prevent corrosion. The condition of this protective coating should be inspected and repaired, if necessary, during routine inspections of the deaerator.
Sprayer
Fig. 3-20 shows a high-performance sprayer. The sprayer consists of a housing, in which a spring-loaded, perforated piston is suspended. Depending on the sprayer loading, the number of free perforations varies according to the spring pressure. In this way the spraying is almost completely in proportion to the desired capacity. A scale fitted on the spring, outside the deaerator, shows the loading.
Possible clogging of the perforations can be eliminated by cutting off the supply of water for a short time. During this operation the piston is pulled upwards to scrape off the dirt.
Fig. 3-20: High-performance sprayer
Another design for smaller deaerators is shown in Fig. 3-21. As the volume of water increases, the gap opens wider and the spray is not as fine. A disadvantage of this sprayer is the fact that it cannot be adjusted during operation. For this simple sprayer it is advisable to check the mechanical operation when the sprayer is cold each time the deaerator is serviced.
Fig. 3-21: Simple sprayer
Cascade deaerator
Fig. 3-22 shows a cascade deaerator. The cascade is mounted on the deaerator dome. The feedwater and returned condensate are sprinkled into the deaeration space by means of trays fitted above the deaerator vessel.
There the water spreads over the cross section of the deaerator. As the cascades are continuously overflowing, a thin wall of flowing water is formed, which combines to form a considerable water surface area. This process involves making intensive contact with the steam that flows in the opposite direction. As already described for the spray deaerator, the water is at a temperature of 105 ºC when it hits the surface of the water. Part of the steam is routed to the cascade space and the other part is supplied via a nozzle pipe on the base of the feedwater tank. The expelled gases, are taken away and vented.
Fig. 3-22: Cascade deaerator
3.16 Practical information on operation
Flash steam
Finally, in all deaerators the gases released from the water collect in the steam space above the water level. They are then vented to atmosphere using an air vent. Some flash steam should always be discharged in order to completely purge of oxygen and free carbon dioxide from the steam space.
The higher the concentration of gas in the steam, the lower the efficiency with which gas is separated from the water. For this reason, the flash steam should be discharged as close to the water inlet as possible, i.e. at the sprayer or above the cascades.
If the deaerator temperature falls below the saturation temperature of the steam, it is a sign that insufficient flash steam has been released (e.g. below 1.2 bar a / 105 ºC).
A pressure measurement would show the total pressure of gases and steam. However, the partial gas pressure accounts for the majority of the prevailing pressure of 1.2 bar. Consequently, the actual steam pressure is under 1.2 bar and the water temperature is also below 105 °C. For this reason, it is advisable to measure the water temperature as well as the deaerator pressure.
Heat recovery from flash steam
In the case of larger deaerators, it may be economic to use the heat contained in the flash steam for preheating by passing it via a heat exchanger. The benefit gained from the steam must be weighed against the high-cost of materials for heat exchangers (because some constituents of the gas encourage corrosion)
Separation of the pump from non-deaerated water
As already noted, the residence time of the water in the deaerator should be at least 25 minutes. It is necessary to prevent incompletely deaerated water from flowing directly to the suction connection of the pump. In other words, there must be no contact between the incoming non-deaerated water and the feedwater pump.
For both deaerator types - cascade and spray deaerators - the position of the water spray nozzle should be as far as possible from the feedwater pump. Unfortunately, this is not always what happens in practice. Some manufacturers build barriers in the deaerator to force the water to take a longer route through the deaerator.
Mixture temperature resulting from make-up water and returned condensate
Sufficient live steam must be supplied in order to achieve the desired degree of gas separation. This is ensured if the mixture of make-up water and condensate is not greater than 90 °C to 95 °C. This also applies if water and condensate are supplied separately. Condensate supplied under pressure, which flashes in the deaerator, does not need to satisfy this condition.
Safety valve
The majority of deaerators are protected with a safety valve set at 1.4 bar a. Deaerators are subject to mandatory inspections at pressures higher than 1.5 bar a.
On some older deaerators, the overflow/pressure relief station takes the form of a water seal (manometric loop). However, in practice this system has hidden weaknesses. Every time there is a hammer or pulse in the system which exceeds the head pressure of the water column, the water seal empties and steam escapes. The deaerator pressure would then need to be reduced to restore the water seal.
Today safety valves are nearly always used for pressure relief to eliminate this reliability issue.
Correct metering of chemicals
Chemicals are added to scavenge oxygen and regulate the pH value. As already noted, oxygen scavenging chemicals are not added in the deaerator, but instead they have to be added just before (or in) the feedwater pump suction pipe. The chemicals will bind the remaining oxygen at this point and fulfil a role similar to the last safety precaution.
If chemicals were to be added before the deaerator, considerable quantities of chemicals would be consumed and they would be a substitute for the intended purpose of the deaerator but in an inefficient way.
Correct air venting
Good air venting is achieved where the concentration of gases is the highest, i.e. as close to the water inlet as possible. In the case of a spray deaerator, this is immediately adjacent to the sprayer and for a cascade deaerator it is at the highest point of the cascade. An air venting point close to the sprayer is more efficient than if it is distributed on the surface.
A typical example of incorrect air venting design is shown in Fig. 3-23.
Fig. 3-23: Incorrect double venting of the deaerator
The figure shows air venting at two points - a correct air venting point close to the sprayer and an (unnecessary) second one on the other side of the deaerator. Both air venting points are discharged via a shared pipe. An orifice or a control valve can be added in the air venting pipe.
An air venting point close to the sprayer will not function or will not operate properly because the steam pressure close to the sprayer is always slightly lower than the pressure at the right-hand side of the deaerator. As a result of this, only the right-hand side would be vented and not the space with the greatest concentration of gas. If such an arrangement exists, only the air venting point close to the sprayer should be opened. Should it still prove to be necessary to vent the other side as well, this should be done via a separate pipe. Nevertheless, the air venting performance of this separate device would be less effective.
On/off level control
On some deaerators the water level is controlled via an on/off switch for the pump or an OPEN/CLOSED control.
This process involves a large quantity of cold water being supplied to the aerator within a very short time, which means that the steam control system must cope with peak load.
If a tonne of cold water is supplied to the deaerator within ten minutes, the steam boiler needs to produce an additional peak output of 1 t/h in order to maintain the required pressure in the deaerator.
Continuous control of the water level is an advantage in order to avoid these undesirable peak loads. If continuous control is not possible, the quantity of water supplied per switching cycle should be kept to a minimum. One option is to keep the difference between the maximum and minimum signalling level as small as possible. The additional electricity required for the higher switching frequency increases the thermal load on the make-up water pump.
Deaerators with a steam pressure of > 1.2 bar
If there is no opportunity to recover the residual heat from the returned condensate, it is possible for condensate temperature to exceed 105 °C.
The flue gas temperature downstream of the pre-heater rises in line with the increase in the inlet temperature of the water in the feedwater pre-heater. Because flue gas is aggressive, the flue gas temperature should be kept at a temperature that is above the dew point. If the deaerator temperature is 125 ºC, the flue gas temperature downstream of the feedwater pre-heater is approx. 20 ºC higher than if the water inlet temperature is 105 ºC.
If this cannot be achieved because the temperature obtained by mixing the make-up water and the returned condensate is too high, the temperature should be 10 to 15 ºC above the mixed temperature. Here the condensate supplied at a higher pressure is not taken into account.
Deaerators connected in parallel
Where there are two deaerators which are operated in parallel on the water side (the feedwater pumps take water from both deaerators), the steam pressure in the deaerators should be equal. To do this, both deaerators must be connected on the steam side. If the deaerators are only connected via the feedwater pumps, the water level and pressure may fluctuate considerably.
The moment one deaerator is supplied with water, the internal pressure falls. The other deaerator then feeds water into the first deaerator via the suction pipe of the feedwater pumps. The process is then repeated in reverse order.
The coupling pipe between the steam spaces of the two deaerators should be generously proportioned. At 105 ºC the specific volume of the deaerator steam should be 1.4 m3/kg. The diameter is also dependent on the size of the deaerator. If a pipe with DN 100 is used, the flow is only 200 kg/h of deaerator steam at a speed of 10 m/s.
Feedwater cooler
The lower the feedwater temperature when it enters the feedwater pre-heater, the greater its efficiency. The lower limit of the inlet temperature is determined on the basis of the point at which the water vapour in the chimney just fails to condense. For systems fired by natural gas, this point is at 70 ºC.
In general, a feedwater cooler in the feedwater pump suction pipe can ensure that the temperature of the water is lower. Feedwater is cooled down upstream of the pre-heater in this heat exchanger and the make-up water is heated up. Fig. 3-24 shows this layout.
Fig. 3-24: Feedwater cooler
A heat audit should be carried out before such a measure is implemented. Here care should be taken to ensure that the maximum temperature of the mixture of make-up water and returned condensate is 95 °C, as it is supplied to the deaerator.
Cavitation in the feedwater pump
In order to prevent steam from forming in the suction pipe and consequently cavitation occurring in the feedwater pump, the deaerator should be fitted at least four metres above the pump inlet flange. Only then can it be ensured that there is sufficient upstream pressure in the suction pipe to prevent steam from forming in the event of a sudden fall in deaerator pressure.
This may be a helpful explanation. The suction line to the feedwater pump is filled with hot water that has a temperature of 105 ºC. If the pressure in the deaerator falls below 1.2 bar a, the water starts to boil at 105 ºC. This boiling effect also starts in the suction pipe and this causes the pump to fail. The risk of steam forming is particularly great at the point where the diameter of the suction pipe reduces upstream of the pump suction connection.
Vacuum breaker
If the steam boiler is taken out of service, the steam condenses and may create a vacuum in the deaerator. Under certain circumstances this vacuum causes water from the deaerator to draw water into the boiler (via the internal steam pipe). If the water is able to flow back to the steam system, for example, it creates a siphon effect. It is very easy to prevent this siphon effect by drilling a small hole in the internal steam pipe at the level of the steam space.
3.17 Continuous (TDS) and bottom blowdown process
Introduction
Live steam from the boiler is almost pure as a result of the evaporation process. Impurities that come from fresh water and returning condensate during the steam generation process remain in the boiler. The concentration of impurities increases during the evaporation process in the boiler, and the boiler water becomes more concentrated. Small quantities of boiler water are drawn off to examine the concentration in order to keep control of the permissible concentration.
In boiler plants two types of blowdown are common:
- Continuous (TDS) blowdown means that blowdown of boiler water takes place on a continuous basis to regulate the concentration of dissolved substances. The specified value depends on the operating pressure and is generally determined by consulting an expert. In the majority of cases, the pH value and conductivity of the boiler water is controlled manually.
- Bottom blowdown describes the process whereby the boiler water is blown down via a blowdown valve to remove the dirt, rust and silt that has collected at the bottom of the boiler. The sludge is produced by chemical binding of residual hardness with phosphates and other impurities, which are entrained in the condensate. Depending on the quality and colour of the boiler water, boiler water is blown down using one blowdown valve, once or twice per day for about 2 seconds.
If continuous (TDS) blowdown does not take place, the concentration of impurities could increase to the extent that the boiler pipes and walls become corroded. Another symptom of an increased concentration is that the water in the boiler may prime. This means that the water and the steam bubbles do not completely separate. This priming action may be so great that, apart from steam, boiler water may be lost from the boiler.
Theoretically, returning condensate is equivalent to distilled water and is almost pure. In practice, there are many reasons why condensate may be contaminated:
- Boiler water may be entrained with the steam. The most common causes are excessive TDS concentration or the water level is too high. In extreme cases, white stripes (chemical residues) can be seen on valves because contaminated steam has escaped at leakage points.
- In individual cases, the cause can also be a badly designed boiler. A correctly designed boiler produces approx. 95 % dry steam. This means that 5 % boiler water is entrained in the steam and is returned to the boiler with the returning condensate.
- Dregs of cooling water often remain in the pipes, particularly during processes where, for example, pipe coils are used for cooling and heating, and end up in the steam circuit together with the condensate. Some contaminants such as salts and chlorides are also found in fresh water, depending on which purification process is used (softening or demineralisation).
Continuous (TDS) blowdown
There are three options available for controlling the TDS values of boiler water during the continuous blowdown process:
- Manual control
- Automatic control
- Time control
a) Manual control
Depending on the results of the boiler water analysis, a greater or lesser amount of water is blown down via a special type of manual valve. This valve is configured internally to pass the boiler water over a number of stages. A proportion of the hot water flashes at each of the stages; this keeps the flow at a low speed and the valve has a longer service life. The valve stem has a coarse thread pitch. A pointer on the lever and a fixed show a percentage open, and the amount of water drained off can be determined using a nomogram.
b) Automatic control
The manual blowdown valve described above is equipped with an actuator. An electrode is installed in the boiler with where the conductivity of the boiler water is measured. The measured value is compared in the controller with the specified value (Fig. 3-25). If the specified value is exceeded, the continuous blowdown valve opens very slightly. If the figure is below the specified value, the continuous blowdown valve closes accordingly.
Fig. 3-25: Automatic continuous blowdown control
c) Time control
Where time control is used, blowdown no longer takes place continuously but instead it is triggered by a time switch or another signal via a circuit. This method is often used is continuous blowdown, during which the deaerator or the condensate tank is filled with fresh water.
Bottom blowdown
Because intermittent blowdown at the bottom of the boiler only takes place once or twice a day for about 20 seconds, it is not economically efficient to recover the heat contained. In general, the water discharged during the bottom blowdown process is directed to a blowdown tank, the flash steam is discharged and the remaining water of 100 ºC is cooled to 40 °C and discharged into the sewage system.
To prevent excessively hot blowdown water from entering the sewage system and possibly damaging the piping system, the hot water is collected in a tank (Fig. 3-26). The flash steam is then discharged into the atmosphere via a large pipe and the remaining water is cooled down to an acceptable temperature using cooling water.
Fig. 3-26: Continuous and intermittent blowdown water tank
Warning:
If the blowdown process removes too much water and is carried out too often, it has a negative impact on fuel costs and also increases expenditure for water and chemicals.
Recovering heat from blowdown water
Heat contained in the continuous blowdown can be recovered in a heat exchanger. The most common systems us the heat to heat up cold make-up water before it is supplied to the deaerator or the feedwater tank.
Unfortunately, the direct transfer of heat from the continuous blowdown water in the heat exchanger is not free of problems. Because the boiler water flashes after the continuous blowdown valve, the mixed water (flash steam/boiler water) enters the heat exchanger at high speed, which causes erosion at the base of the pipe. Leaks then often occur. This is reflected in the fact that the continuous blowdown water coolers are often out of action in many boiler houses. For this reason it is advisable to route the continuous blowdown water into a flash vessel. The flash steam should be routed into the pipe downstream of the pressure reducing valve, which controls the deaerator.
Heat transfer between the incoming feedwater and the rest of the continuous blowdown water (105 ºC) should take place in a heat exchanger (Fig. 3-27).
Fig. 3-27: Recovering heat from blowdown water
Continuous (TDS) blowdown flash vessel
Blowdown water from the boiler is directed to the flash vessel. The top (steam) connection is connected to the deaerator. This steam connection is 'T'ed into the steam pipe downstream of the deaerator pressure control valve. The blowdown water is drained off to the heat exchanger via a float-type steam trap positioned at a slightly higher point. The residual heat of the blowdown water is transferred to the incoming fresh water in the heat exchanger.
Bearing in mind that the aim is always to keep the heat exchanger filled with water, the discharge is via a swan neck connected at a higher point. A prerequisite for this system working correctly is modulating water level control system for the deaerator.
In order to prevent the blowdown water from entering the deaerator if the floating trap is faulty, the flash vessel should be equipped with a high water level alarm. This alarm signal can, if necessary, intervene in the function of the blowdown controller. When calculating the vessel diameter, the steam should not exceed a speed of 1 m/s. The speed in the discharging steam pipe must be kept at 10 m/s. The minimum diameter of the flash vessel is 250 mm.
Example:
The heat content of the water at 10 bar is 762 MJ/tonne. Bearing in mind that the heat from the blowdown water cannot be reused, the energy lost can be calculated as follows. If the blowdown amount is 4.5 % and the average boiler efficiency rate is 93 %, the figure is as follows:
Energy loss=
=0.0369 GJ/tonne
If the price of heat is €7.50 /GJ, €0.28 /tonne of steam generated are lost.
If average steam production is 50000 tonnes/year, the payback time on the capital employed is about 3 years if the heat in the water drained off is used and the heat of the blowdown water is, for instance, used to heat up fresh water to 40 ºC.
Calculation of the continuous blowdown percentage rate
In practice, there are two methods used as a basis for calculating the continuous blowdown percentage rate:
Method 1: Calculation of the relationship between the chloride content in the feedwater and in the boiler water.
Method 2: Calculation of the relationship between the chloride content in the make-up water and in the boiler water.
The resulting loss in kg is the same for both methods. Only the percentage rates and the starting points are different.
The resulting loss in kg is the same for both methods. Only the percentage rates and the starting points are different.
Definition of the continuous blowdown percentage rate as per method 1:
The formula is:
Continuous blowdown percentage rate = 
Clfw = Chloride content of feedwater
Clbw = Chloride content of boiler water
Example:
Clfw = 9 mg/l
Clbw = 200 mg/l
Continuous blowdown percentage = 
=4.5%
Definition of the continuous blowdown percentage rate as per method 2:
The formula is:
Continuous blowdown percentage rate = 
Clmw = Chloride content of make-up water
Clbw = Chloride content of boiler water
Example:
Clmw = 18 mg/
Clbw = 200 mg/l
Continuous blowdown percentage = 
=9%
It can be deduced from the relationship between Clfw and Clmw or 9 and 18 mg/l, respectively, that the feedwater contains approximately 50 % fresh water in this case. Per tonne of fresh water, 1.09 tonnes of water are supplied and 0.09 tonnes are blown down.
A loss of 0.09 x 0.5 = 0.045 tonne remains per tonne of steam produced.
Since both calculations relate steam production to feedwater, it is possible that small deviations can occur.
Sampling
Samples of boiler and feedwater should always be taken via a sample cooler. If this procedure is not followed, the sample will be defective. The boiler water sample of a 10 bar boiler flashes and therefore loses approximately 16 % of the sample.
A rule of thumb for flashing is this. The saturation temperature at 10 bar is 180 ºC, so flashing is (180 - 100) x 0.2 = 16 %. This means that the concentration of the constituents in the sample is 16 % higher than for a cooled sample. It is also unsafe.
Boiling
Steam bubbles form in the boiler water and, because they have a lower density, they are buoyant. As a result of this, the bubbles rise. The closer the steam bubbles get to the water surface in the boiler, the greater their speed. At the point where the bubbles break the surface, they are moving at such a high speed that water is entrained.
If a good steam separator is fitted in or on the boiler, the entrained water is removed. The separator must be properly drained to avoid water hammer and corrosion.