Steam Accumulators

A complete overview of the need for steam storage to meet peak load demands in specific industries, including the design, construction and operation of a steam accumulator, with calculations.

Use the quick links below to take you to the main sections of this tutorial:

The purpose of a steam accumulator is to release steam when the demand is greater than the boiler's ability to supply at that time, and to accept steam when demand is low.

Steam accumulators are sometimes thought of as relics of the 'steam age' with little application in modern industry. The following Sections within this Tutorial will:

  • Illustrate how a steam accumulator can improve the operation of a modern plant.
  • Discuss the factors which make steam accumulators even more necessary now, than in the past.
  • Provide guidance on the sizing and selection of appropriate ancillary equipment.
Arrow Top

Boiler design

Boilers today (September 2002) are significantly smaller than their counterparts of only 30 years ago. This reduction in boiler size has been brought about by users, who demand that boilers be:

  • More efficient in terms of fuel input to steam output.
  • More responsive to changes in demand.
  • Smaller, and so take up less floor space.
  • Cheaper to buy and install.

These targets have been met in part by today's more sophisticated controls/burners which respond faster and more accurately to changes in demand than those of bygone years. However, a boiler's response to changes in demand is also affected by the laws of nature, for example: how much water is to be heated and the heat transfer area available to transfer that heat from the burner flame to the water.

Response times have been improved by physically reducing the external dimensions of the boiler for any given output, and by cramming the insides full of tubes to increase the heat transfer area. This means that the modern boiler holds less water, and the heat transfer area per kg of water is greater. Consider the situation of today:

  • Steam demand from the plant is increased, and the pressure in the boiler falls to the burner control set point.
  • The burner control purges the combustion chamber, and the burner is ignited.
  • The large heat transfer area and the lower mass of water combine to rapidly evaporate the water in the boiler to satisfy the demand for steam.

As covered in Tutorial 3.7, 'Boiler Fittings and Mountings', the energy stored in a boiler is contained in the water which is held at saturation temperature. The greater the amount of water inside a boiler, the greater the amount of stored energy to cope with changes in demand/load.

Table 3.22.1 compares an old Lancashire boiler of the 1950s with a modern packaged boiler. Note that the modern packaged boiler contains only 20% of the water held in a similarly rated Lancashire boiler. It follows from this that the reserve of energy held in the modern packaged boiler is only 20% of the Lancashire boiler. This suggests that the modern packaged boiler cannot cope with peak demands in the way an old Lancashire boiler could.

Also note from Table 3.22.1, that the 'steam release rate' from the surface of the water inside the modern packaged boiler has increased by a factor of 2.7. This means that the steam has only 1/2.7 (40%) of the time available in a Lancashire boiler to separate itself from the water. At times of peak demand this may mean that wet steam is being exported from the modern packaged boiler, and possibly at a lower pressure than that which it was designed to operate - Covered in Tutorial 3.12, Controlling TDS in the Boiler Water.

Water which is carried over with the steam will be dirty (approximately 3 000 ppm TDS), and will contaminate control valves and heat transfer surfaces. It may even block some of the smaller orifices in pressure sensing devices, steam traps and so on.

Table 3.22.1 - Comparison of Lancashire - and modern packaged boilers Table 3.22.1
Comparison of Lancashire
and modern packaged boilers

Note: The information to create Table 3.22.1 was supplied by Thermsave. Imperial units are also shown in the Table to provide an insight into the factors applied in the designing of boilers in the past.

Arrow Top

Peak demands

Steam demands on any process plant are rarely steady, but the size and type of the fluctuations depend on the application and the industry. Peaks may occur once a week or even once a day during start-up.

The biggest problems caused by peak demands are usually associated with batch processing industries:

  • Brewing
  • Textiles
  • Dry-cleaning
  • Canning
  • Lightweight concrete block manufacturers
  • Specialised areas of the steel making industry
  • Rubber industries with large autoclaves

For these processes the peaks may be heavy and long-term, and measured in fractions of an hour.

Alternatively, load cycles can consist of short-term frequent peaks of short duration but very high instantaneous flowrate:

  • Hosiery finishing
  • Rubber
  • Plastic and polystyrene moulding
  • Steam peeling
  • Hospital and industrial sterilisation

Figure 3.22.1, shows that in each case the demands are almost instantaneous and the peaks are well above the average load. The result of a sudden demand on boiler plant is a pressure drop in the boiler, because the boiler and its associated combustion equipment are unable to generate steam at the rate at which it is being drawn off.

Fig. 3.22.1 - Typical steam flow chart for a batch process plant Fig. 3.22.1
Typical steam flow chart for a batch process plant

Peak demands and subsequent pressure drops may have quite serious consequences on factory production.

At worst, the result is a boiler 'lockout', due to the elevation of water level caused by rapid boiling, followed by its collapse. This is seen as a low water level alarm by the level controls.

At best, the steam produced is wet and contaminated. This, coupled with a reduction in pressure, can lead to:

  • Increased process times.
  • A reduction in product quality or even damage or loss of the product.
  • Waterhammer in the steam mains causing distress to pipework and fittings, and possible danger to personnel.

For the boiler plant, peak demands are responsible for:

  • A higher level of maintenance
  • Reduced boiler life
  • Reduced fuel efficiency

This is because the combustion equipment is continually cycling from low to high fire, and even shutting off during periods of very low demand, only to fire again a few minutes later, with all the pre and post-purge chilling effects.

Multiple or oversized boilers may be used in an effort to cope with peak demands (and the subsequent dips in demand) which inevitably result in low efficiencies.

To illustrate this point, it can be assumed that:

  • For an average steam boiler, less than 1% of the losses are due to heat radiated from the boiler shell (for example: 1% of the Maximum Continuous Rating (MCR) of the boiler).
  • If a boiler is then producing 50% of its MCR, the losses due to radiation are 2% relative to its production rate.
  • If a boiler is producing 25% of its MCR the losses are 4% of its production rate.

And so on, until a boiler is simply maintained at a pressure without exporting any steam to the factory. At this point, 1% of its MCR is a 100% loss relative to its steam production rate.

If boiler plant is sized for peak loads, problems arise due to oversizing relative to the average demand. In practice, a boiler may shut off during a period of low demand. If this is then followed by a sudden surge of demand and the boiler is not firing, an alarm situation may arise.

Alarms will ring, the boiler may lockout and steam recovery will be slow and arduous.

In short, peaks are responsible for:

  • Loss of production.
  • Reduced product quality.
  • Increased production times.
  • Poor quality steam from the boiler.
  • Low fuel efficiency.
  • High maintenance costs.
  • Reduced boiler life.
Arrow Top

Load levelling techniques

Modern boilers are very efficient when properly loaded and respond quickly to load increases, provided that the boiler is firing. However, conventional shell boilers are generally unable to meet large peak demands in a satisfactory way and should be protected from large fluctuating loads.

Various methods are used in an attempt to create a stable load pattern to protect the boiler plant from the effects of large fluctuating loads.

Arrow Top

Engineering methods:

  • Pressure maintaining valves (also called surplusing valves) can be used as load shedding devices by isolating non-essential parts of the plant and thereby giving priority to essential plant, a typical arrangement is shown in Figure 3.22.2. The success of this method again depends on the severity of the peaks and the assumption that the boiler is firing when the peak develops.
Fig. 3.22.2 - Surplussing valves used as load shedding devices Fig. 3.22.2
Surplussing valves used as load shedding devices

Surplussing valves can also be fitted directly to the boiler or on the steam main to the factory, as shown in Figure 3.22.3.

The set pressure should be:

  • Less than the 'high fire' control pressure, to prevent any interference of the surplussing control with the burner controls.
  • High enough to maintain the pressure in the boiler at a safe level.

In terms of sizing the surplussing valve, the requirement is for minimum pressure drop. As a general indication, a line size valve should be considered.

Fig. 3.22.3 - Surplussing valve on a boiler main Fig. 3.22.3
Surplussing valve on a boiler main
  • Two-element or three-element water level control. These can be successful as long as the peaks are not violent and the boiler is firing when the peak develops; the boiler must also have sufficient capacity.

    Two-element control uses inputs from the boiler water level controls and the steam flowrate to position the feedwater control valve.

    Three-element control uses the above two elements plus an input from a feedwater flow measuring device to control the incoming feedwater flowrate, rather than just the position of the feedwater control valve. (This third element is only appropriate on boilers which use modulating level control in boiler houses with a feedwater ring main.)

Example 3.22.1

A boiler is rated at 5 000 kg/h 'From and At'

The high/low fire pressure settings are 11.3/12.0 bar g respectively (12.3/13.0 bar a).

The surplussing valve setting is 11.0 bar g (12.0 bar a).

  • Based on a velocity of approximately 25 m/s, a 100 mm steam main would be selected.
  • Kvs of a standard DN100 surplussing control valve is 160 m³/h.
  • Using the following mass flow equation for saturated steam the pressure downstream of the surplussing valve (P2) can be calculated:
Equation 3.21.2 Equation 3.21.2

Where:

s = Steam mass flowrate (kg/h)
Kv = Valve flow coefficient
P1 = Pressure upstream of the control valve (bar a)
P2 = Pressure downstream of the control valve (bar a)

     
     
     

In this example, at low fire, the boiler pressure is given as 12 bar g (13 bar a).

It can be calculated from Equation 3.21.2 that the pressure after the fully open surplussing valve is 11.89 bar g (12.89 bar a).

Consequently, the pressure drop is small (0.11 bar) and would not be significant in normal operation. However, if the pressure should fall to 11.0 bar g, the surplussing valve will start to close in order to maintain upstream pressure.

The proportional band on the controller should be set as narrow as possible without making the valve 'hunt' about the set point.

Both methods of applying pressure-maintaining valves may provide protection to the boiler plant, but they will not overcome the fundamental requirement of more steam for the process.

Arrow Top

Management methods

These include, for example, staggered starts on processes to keep peak loads as low as possible. This method of smoothing out peaks can be beneficial to the boiler plant but may be detrimental and restrictive to production, having much the same effect as the pressure-maintaining valve.

It is, however, impossible to smooth out short-term peaks using only management methods.

In a factory where there are many individual processes imposing such peaks it is possible for this to have a levelling effect on the load, but equally so, it is also possible for the many individual processes to peak simultaneously, with disastrous effects.

If the above methods do not provide the required stability of demand, it may be time to consider a means of storing steam.

Arrow Top

The steam accumulator

The most appropriate means of providing clean dry steam instantaneously, to meet a peak demand is to use a method of storing steam so that it can be 'released' when required. Storing steam as a gas under pressure is not practical due to the enormous storage volume required at normal boiler pressures.

This is best explained in an example:

In the example used later in this Tutorial, a vessel with a volume of 52.4 m³ is used.

  • Charging pressure is 10 bar g (specific volume = 0.177 m³ / kg).
  • Discharge pressure is 5 bar g (specific volume = 0.315 m³ / kg).

Based on these parameters, the resultant energy stored and ready for instant release to the plant is contained in 130 kg of steam. This amounts to only 5.2% of the energy stored and ready for use, compared to a water filled accumulator.

In practice there are two ways of generating steam:

  • By adding heat to boiling water, indirectly via a combustion tube and burner, as in a conventional boiler.
  • By reducing the pressure on water stored at its saturation temperature. This results in an excess of energy in the water, which causes a proportion of the water to change into steam.

    This phenomenon is known as 'flashing', and the equipment used to store the pressurised water is called a steam accumulator. There are, in principle, two types of systems available for steam storage; the pressure-drop accumulator and the constant pressure accumulator. This tutorial only considers the former type.

A steam accumulator is, essentially, an extension of the energy storage capacity of the boiler(s). When steam demand from the plant is low, and the boiler is capable of generating more steam than is required, the surplus steam is injected into a mass of water stored under pressure. Over a period of time the stored water content will increase in temperature and pressure until it finally achieves the saturation temperature for the pressure at which the boiler is operating.

Demand will exceed the capability of the boiler when:

  • A load is applied faster than the boiler's ability to respond - for example, the burner(s) may be extinguished and a purging cycle must be completed before the burner can be safely ignited. This may take up to 5 minutes, and rather than adding heat to the boiler, the purging cycle will actually have a slight cooling effect on the water in the boiler. Add to this the fact that the flashing of the boiler water will cause a drop in water level, and the boiler level control system will automatically compensate for this by bringing feedwater in at, for example, 90°C. This will have a quenching effect on the water already at saturation temperature, and will aggravate the situation.
  • A heavy demand occurs over a longer than normal period.

In either case, the result is a drop in pressure inside the steam accumulator, and as a result of this some of the hot water will flash to steam. The rate at which the water flashes to steam is a function of the storage pressure, and the rate at which steam is required by the system being supplied.

Arrow Top

Charging

The pressure-drop steam accumulator consists of a cylindrical pressure vessel partially filled with water, at a point between 50% and 90% full depending on the application. Steam is charged beneath the surface of the water by a distribution manifold, which is fitted with a series of steam injectors, until the entire water content is at the required pressure and temperature.

It is natural that the water level will rise and fall during charging and discharging.

If the steam accumulator is charged using saturated (or wet) steam, there may be a small gain in water due to the radiation losses from the vessel. Normally, a slightly greater mass of steam is discharged than is admitted.

A steam trap (ball float type) is fitted at the working level and acts as a level-limiter, discharging the small amount of surplus water to the condensate return system.

However, if the steam accumulator were charged using superheated steam, or if the radiation losses are very small, there would be a gradual loss of water due to evaporation, and a feedvalve or pump, under the control of level probes, would be required to make up the deficit.

Arrow Top

Discharging

As a pressure drop occurs in a steam accumulator with the stored water at saturation temperature, flash steam will be generated at the rate demanded by any load above the boiler capacity; consequently the overload condition will be satisfied. When the overload is followed by a demand below the boiler capacity the steam accumulator is charged using surplus steam from the boiler. This charge and discharge cycle explains the name 'steam accumulator' and continually allows the boiler to fire up to its maximum continuous rating.

Arrow Top

The charging / discharging cycle

The accumulator needs to be fully charged at the beginning of its discharge period, for it to operate correctly. To allow this, two main events must be satisfied:

1. Enough time must be available from the end of one overload period to the beginning of the next, to recharge the water stored in the accumulator.

2. The average off-load steam demand must be lower than the boiler capacity (the maximum continuous rating or MCR), such that sufficient surplus boiler capacity is available to recharge the water stored in the accumulator during off-peak times.

Other criteria are also important to ensure the accumulator has enough capacity, and these must be satisfied by the design:

1. Enough water must be stored to provide the required amount of flash steam during the discharge period. This can be satisfied by ensuring the accumulator volume is large enough.

2. Higher steam release rates will produce wet steam. The velocity and flowrate at which the flash steam is released from the water surface must be below a predetermined value. This can be satisfied by ensuring the water surface area is large enough which, in turn, depends on the accumulator size.

3. The evaporation capacity must be sufficient. This depends on the pressure at which the water is stored when fully charged (the boiler pressure) and the minimum pressure at which the accumulator will operate at the end of the discharge period (the accumulator design pressure). The larger the differential between these two pressures, the more flash steam will be produced.

4. The accumulator design pressure must be higher than the downstream distribution pressure. This is necessary to create a pressure differential across the downstream pressure reducing valve (PRV), to allow the required flow from the accumulator to the plant. The closer the accumulator pressure to the distribution pressure, the smaller the accumulator but this also gives a smaller pressure differential across the PRV. This requires a larger PRV; large enough to pass the highest overload demand when the accumulator is at its design pressure (the minimum pressure in the accumulator at the end of the discharging period).

Arrow Top

Sizing a steam accumulator

A steam accumulator in the steam system gives increased storage capacity. Proper design of the steam accumulator ensures that any flowrate can be catered for. There are no theoretical limits to the size of a steam accumulator, but of course practical considerations will impose restrictions.

In practice the steam accumulator volume is based on the storage required to meet a peak demand, with an allowable pressure drop, whilst still supplying clean dry steam at a suitable steam release velocity from the water surface. Example 3.22.2 below, is used to calculate the potential of steam capacity in a horizontal steam accumulator.

Example 3.22.2 Boiler:

Maximum continuous rating=5 000 kg/h
Normal working pressure=10 bar g (hf = 781 kJ/kg, from steam tables)
Burner switching differential=1 bar (0.5 bar either side of 10 bar g)

Plant requirements:

Maximum instantaneous demand=12 000 kg/h
Distribution pressure=5 bar g

Although the maximum instantaneous overload is 12 000 kg/h, the mean value of the overload should be used to size the accumulator.

This prevents unnecessary oversizing of the accumulator. Equally, it is necessary to determine and use the mean 'off-peak' load in the sizing calculation. Off-peak load is any load below the boiler MCR.

Finding the mean value of the overload and off-peak load
There are three possible methods to establish the mean loads for existing boiler plant:

  • To guestimate, based on experience.
  • To interrogate the existing boiler steam output charts to establish the mean loads and the time periods over which they occur.
  • To program a steam meter's computer to integrate the steam load over both the overload and off-peak load periods.

Method 1 could prove to be rather reckless, if an expensive accumulator ended up too small.

However, if the boiler plant is still at the design stage, an educated guess will be the only option. From the designer's knowledge of the installation, it should be possible to give a reasonable estimate of the maximum plant load, the load diversity, and the times over which they occur.

Method 2 is quite easy to expedite, and should give a reasonably accurate result.

Method 3 would provide the most accurate results, and the cost of the steam meter is small relative to the overall cost of an accumulator project.

The following procedure shows how to determine the mean steam loads from an existing chart recording the load pattern. The procedure is built up from Figure 3.22.4, which shows the flow pattern for Example 3.22.2.

Fig. 3.22.4 - Shows the boiler MCR, and allows the mean load periods to be defined Fig. 3.22.4
Shows the boiler MCR, and allows the mean load periods to be defined

From Figure 3.22.4, it can be seen that the off-peak loads have been divided up into the following mean loads and time periods. From this data, the mean surplus load for each off-peak period can be determined.

The mean surplus flow is calculated in the following way:

From the above data, it can be seen that:

  • The boiler maximum continuous rating = 5 000 kg / h
  • The maximum instantaneous overload = 12 000 kg / h
  • The largest mean surplus flow = 2 916 kg / h
  • The largest mean overload = 10 300 kg / h
  • The minimum time between overloads = 95 minutes
  • The distribution pressure = 5 bar g

The accumulator design pressure needs to be chosen, and it is usual to choose a pressure 1 bar higher than the distribution pressure. This gives a reasonable flash steam capacity, without unduly oversizing the downstream PRV.

In this example the distribution pressure is 5 bar g, so the accumulator design pressure can initially be considered at 6 bar g (Note: the water mass is taken at boiler working pressure).

From this information, an accumulator may now be sized.

Steam accumulator:

The potential steam capacity in a steam accumulator can be calculated using Equation 3.22.1:

Equation 3.22.1 Equation 3.22.1

Note that this 2 500 kg of flash steam will be released in the time taken for the pressure to drop. If this has been an hour, the steaming rate is 2 500 kg / h; if it were over 30 minutes, then the steaming rate could be:

If the steam accumulator is connected to a boiler rated at 5 000 kg/h, and supplying an average demand within its capacity, the combined boiler and accumulator outputs could meet peak loads of 20 000 kg/h for 10 minutes. The alternative is an additional combination of boilers capable of generating 20 000 kg/h for 10 minutes with the limitations previously noted.

It is now possible to calculate the size of steam accumulator required for a particular application.

The figures as used in Example 3.22.2 are used below to facilitate checking.

However, steam is only required for 30 minutes every hour, so the steam storage required must be:

The amount of water required to release 2 650 kg of steam is a function of the proportion of flash steam released due to the drop in pressure.

This satifies the criterion of having enough water to produce the required amount of flash steam. It can be seen that the storage capacity of 2 797 kg is greater than the storage required of 2 650 kg of steam.

If the steam accumulator will be charged at 10 bar g by the boiler, and discharged at 6 bar g to the plant, the proportion of flash steam can be calculated as follows:

Equation 2.2.5 Equation 2.2.5

The water content will typically account for only 90% of the volume of the steam accumulator when fully charged:

The vessel capacity is larger at 87.9 m³, so the vessel satisfies this criterion.

Using the vessel dimensions given earlier, the water surface area is approximately 20.53 m² when fully charged, at a volume of 90% of the vessel capacity.

The maximum steaming rate from the accumulator is given as 5 300 kg/h, therefore:

Emperical test work shows that the rate at which dry steam can be released from the surface of water is a function of pressure. A working approximation suggests:

Maximum release rate without steam entrainment (kg/m² h) = 220 x pressure (bar a)

The steam accumulator in Example 3.22.2 is operating at 10 bar g (11 bar a). The maximum release rate without steam entrainment will be:

220 x 11 bar a = 2 420 kg/m² h

This is shown graphically in Figure 3.22.5

The example at 1 071 kg/m² h is well below the maximum value, and dry steam can be expected. Had the steam release rate been too high, different diameters and lengths giving the same vessel volume needed to be considered.

It must be emphasised that this is only an indication, and design details should always be delegated to specialist manufacturers.

Fig. 3.22.5 - Steam release rate without steam entrainment Fig. 3.22.5
Steam release rate without steam entrainment
Arrow Top

Steam accumulator controls and fittings

The following is a review of the equipment required for a steam accumulator installation, together with some guidance on sizing and selection of appropriate equipment.

Using figures from Example 3.22.2:

From these figures it can be deduced that 65 920 kg of water must be heated from saturation temperature at 6 bar g to saturation temperature at 10 bar g in 95 minutes.

Pipework

The pipework between the boiler and the steam accumulator should be sized, as per normal practice, on a steam velocity of 25 to 30 m/s and the maximum output of the boiler.

In the case of Example 3.22.2, this would require a DN100 pipeline from the boiler to the accumulator, to carry the boiler Maximum Continuous Rating (MCR) of 5 000 kg / h @ 10 bar g.

The pipework from the accumulator to the downstream PRV should be sized on the maximum instantaneous overload and a velocity of no more than 20 m / s. This would require a DN250 nominal bore pipe for this example, with an accumulator design pressure of 6 bar g.

Stop valve

A line-size stop valve is required in addition to the boiler crown valve. A suitably rated stop valve, preferably in cast steel, would be appropriate.

Check or non-return valve

A line-size check valve is required to prevent reverse flow of the steam back to the boiler in the event of the boiler being deliberately shut down, or perhaps, the boiler locking-out.

A disc check valve would be an appropriate choice.

Surplussing valve

The surplussing valve is essential to ensure that the rate at which steam is flowing from the boiler to the accumulator is within the capability of the boiler. Example 3.22.1, shows how the valve would be sized.

Pilot operated, self-acting surplussing valves may be used in smaller installations, provided the narrow (and non-adjustable) proportional band is acceptable. A pneumatic controller and control valve is more appropriate to larger installations, and offers the advantage of an adjustable proportional band.

For this application a DN100 pneumatically operated control valve with appropriate operating and shut-off capability, would be selected.

Arrow Top

Steam injection equipment

A properly sized steam inlet pipe must feed to well below the water surface level and into a steam distribution header/manifold system such as shown in Figure 3.22.6.

The steam is injected into the water.

It is important to remember that the injector capacity will reduce as the pressure in the vessel increases, as the differential pressure between the injected steam and the vessel pressure is reduced.

At very low flowrates the steam will tend to issue from the injectors closest to the steam inlet pipe(s).

The design of the inlet pipe(s) and the manifold system, together with the placement of the injectors, must provide even injection of steam throughout the length of the accumulator regardless of actual steam flowrate.

Fig. 3.22.6 - Installation of injectors in a steam accumulator Fig. 3.22.6
Installation of injectors in a steam accumulator

The discharge from the injectors will be very hot water and steam, possibly with some condensing steam bubbles, at very high velocity, promoting turbulence and mixing in the water mass. They should not discharge directly against, or close to, the walls of the vessel. Angled installation may therefore be advisable. Ideally, they should also be angled in different directions to assist with more even distribution.

A nominal arrangement is shown in Figure 3.22.6.

In very long vessels, more regular distribution may be achieved if two or more inlet pipes are used. In such cases, it is very important that the inlet pipes are carefully manifolded together from the supply main.

All the injectors should be installed as low down in the accumulator as possible to ensure the maximum possible liquid head above them. It may also be appropriate to install the injectors at a slight angle to avoid erosion of the vessel.

Fig. 3.22.7 - A high efficiency steam injector Fig. 3.22.7
A high efficiency steam injector

A typical arrangement is shown in Figure 3.22.6.

In very long vessels, more regular distribution may be achieved if two or more inlet pipes are used. In such cases, it is very important that the inlet pipes are carefully manifolded together from the supply main.

All the injectors should be installed as low down in the accumulator as possible to ensure the maximum possible liquid head above them. It may also be appropriate to install the injectors at a slight angle to avoid erosion of the vessel.

Returning to Example 3.22.2:

Boiler pressure (P1) = 10 bar g
Plant pressure (P2) = 5 bar g
ΔP(maximum) = 10 - 5 = 5 bar
Flowrate = Boiler maximum continuous rating (5 000 kg/h on example)

Manufacturers' sizing tables will give the Kvs value of steam injectors (see Table 3.22.2)

Table 3.22.2 - Spirax Sarco steam injector capacity index values Table 3.22.2
Spirax Sarco steam injector capacity index values

Using the data from Table 3.22.2 and referring to Figure 3.22.7, an extract from the saturated steam sizing chart Figure 3.22.8:

  • Draw a line horizontally to the right across from the 'x' axis at 11 bar a (10 bar g) until it intersects the critical pressure drop line, point (A).
  • Draw a line vertically down the chart from point (A) until it intersects the Kvs value of the injector, point (B), (For example Kvs 5.8 for an IM25M injector).
  • Draw a line horizontally to the left, until it intersects the 'y' axis, point (C). The value shown will be the capacity of the injector. (Approximately 760 kg/h for this example).
  • Fig. 3.22.8 - Extract from saturated steam sizing chart Fig. 3.22.8
    Extract from saturated steam sizing chart

The flowrate may also be calculated using Equation 3.21.2:

Equation 3.21.2 Equation 3.21.2

Where:

s= Steam mass flow (kg/h)
Kv= Capacity index of injector
P1= Boiler pressure bar a
= Pressure drop ratio ΔP/P1

Arrow Top

Sizing and quantifying the injectors

The above exercise gives a capacity of 760 kg / h for one injector; but this only relates to the start of the charging period, when the vessel pressure is at its lowest, and the injector capacity is at its highest.

It must be remembered that, as more steam is injected into the vessel, the vessel pressure will rise, effectively reducing the injectors' capacities, until the vessel pressure may eventually equalise with the boiler pressure, and no flow can take place.

Because of this, it is not practical to use the one (highest) flowrate, 760 kg / h in this example.

Instead, it is necessary to find the mean injection rate over the charging period.

This can be done by using Equation 3.21.2 to calculate the flow at different vessel pressures. (The Spirax Sarco Engineering Support Centre has a valve sizing utility, which can be used to calculate the injector capacities easily from the injector Kv values - see http://www.spiraxsarco.com/esc)

In this example, the vessel pressure will vary between 6 bar g and 10 bar g. The greater the number of pressures taken, the greater the accuracy but, in general, taking increments at 10% of the difference between boiler and accumulation pressure will give a reliable mean value. Table 3.22.3 shows the calculations for an IN25 injector (1") with a Kv of 5.8.

Table 3.22.3 - Capacities at various differential pressures for an IN25 injector Table 3.22.3
Capacities at various differential pressures for an IN25 injector

The total flow of 6 076 kg / h is divided by the number of entries. it must be remembered to include the zero entry as well; hence there are eleven entries to consider.

It can be seen that the mean flowrate of 553 kg / h is somewhat less than the maximum capacity of 759 kg / h. If the maximum capacity were used to quantify the number of injectors, then not enough injectors would be chosen.

The number of injectors required can be determined by dividing the steam flow by the amount a single injector can supply.

Fig. 3.22.9 - Saturated steam sizing chart Fig. 3.22.9
Saturated steam sizing chart
Arrow Top

Calculating the time required to recharge the vessel

From the load patterns shown in Figure 3.22.4, it has been shown that the minimum time between charge cycles is 95 minutes. It is now necessary to check that the vessel can be recharged in less time than this.

It has been shown that the quantity of steam used during the discharge period is 2 650 kg.

The mean surplus flow of steam available during the recharging period has been calculated from Figure 3.22.4 as 2 916 kg / h.

The time required for recharging is proportional to the ratio of the mass of steam used during discharge to the rate of surplus steam flowing in the off-peak period:

As the required recharging time is less than the time between the shortest overload cycle of 95 minutes, the balance between the overload time and the recharging time can be satisfied by the accumulator.

Therefore, the accumulator size of 7 metres long by 4 metres diameter provides sufficient capacity for this particular example.

Arrow Top

Pressure gauge

A suitably ranged pressure gauge is required to show the pressure within the steam accumulator.

Ideally it should be marked to show:

  • Minimum pressure (plant steam pressure)
  • Maximum pressure (boiler steam pressure)
  • Vessel maximum working pressure
Arrow Top

Boiler efficiency

A modern steam boiler will generally operate at an efficiency of between 80 and 85%. Some distribution losses will be incurred in the pipework between the boiler and the process plant equipment, but for a system insulated to current standards, this loss should not exceed 5% of the total heat content of the steam. Heat can be recovered from blowdown, flash steam can be used for low pressure applications, and condensate is returned to the boiler feedtank. If an economiser is fitted in the boiler flue, the overall efficiency of a centralised steam plant will be around 87%.

This is lower than the 100% efficiency realised with an electric heating system at the point of use, but the typical running costs for the two systems should be compared. It is clear that the cheapest option is the centralised boiler plant, which can use a lower, interruptible gas tariff rather than the full tariff gas or electricity, essential for a point of use heating system. The overall efficiency of electricity generation at a power station is approximately 30 to 35%, and this is reflected in the unit charges. Components within the steam plant are also highly efficient. For example, steam traps only allow condensate to drain from the plant, retaining valuable steam for the process. Flash steam from the condensate can be utilised for lower pressure processes with the assistance of a flash vessel.The following pages introduce some real life examples of situations in which a steam user had, initially, been poorly advised and/or had access to only poor quality or incomplete information relating to steam plant. In both cases, they almost made decisions which would have been costly and certainly not in the best interests of their organisation. Some identification details have been altered.
Case study: UK West Country hospital considers replacing their steam systemIn one real life situation in the mid 1990's, a hospital in the West of England considered replacing their aged steam system with a high temperature hot water system, using additional gas fired boilers to handle some loads. Although new steam systems are extremely modern and efficient in their design, older, neglected systems are sometimes encountered and this user needed to take a decision either to update or replace the system.The financial allocation to the project was £2.57 million over three years, covering professional fees plus VAT.It was shown, in consultation with the hospital, that only £1.2 million spent over ten years would provide renewal of the steam boilers, pipework and a large number of calorifiers. It was also clear that renewal of the steam system would require a much reduced professional input. In fact, moving to high temperature hot water (HTHW) would cost over £1.2 million more than renewing the steam system.
The reasons the hospital initially gave for replacing the steam system were:

Additional claims in favour of individual gas fired boilers were given as:

Arrow Top

Trace heating

Trace heating is a vital element in the reliable operation of pipelines and storage/process vessels, across a broad range of industries.A steam tracer is a small steam pipe which runs along the outer surface of a (usually) larger process pipe. Heat conductive paste is often used between the tracer and the process pipe. The two pipes are then insulated together. The heat provided from the tracer (by conduction) prevents the contents of the larger process pipe from freezing (anti-frost protection for water lines) or maintains the temperature of the process fluid so that it remains easy to pump. Tracing is commonly found in the oil and petrochemical industries, but also in the food and pharmaceutical sectors, for oils, fats and glucose. Many of these fluids can only be pumped at temperatures well above ambient. In chemical processing, a range of products from acetic acid through to asphalt, sulphur and zinc compounds may only be moved through pipes if maintained at a suitable temperature. For the extensive pipe runs found in much of process industry, steam tracing remains the most popular choice. For very short runs or where no steam supply is available, electrical tracing is often chosen, although hot water is also used for low temperature requirements. The relative benefits of steam and electric tracing are summarised in Table 1.2.5.


Case study: UK oil refinery uses steam tracing for 4 km pipelineIn 1998, a steam trace heating system was installed at one of the UK's largest oil refineries.
BackgroundThe oil company in question is involved in the export of a type of wax product. The wax has many uses, such as insulation in electric cabling, as a resin in corrugated paper and as a coating used to protect fresh fruit. The wax has similar properties to candle wax. To enable it to be transported any distance in the form of a liquid, it needs to be maintained at a certain temperature. The refinery therefore required a pipeline with critical tracing.The project required the installation of a 200 mm diameter product pipeline, which would run from a tank farm to a marine terminal out at sea - a pipeline of some 4 km in length. The project began in April 1997, installation was completed in August 1998, and the first successful export of wax took place a month later. Although the refinery management team was originally committed to an electric trace solution, they were persuaded to look at comparative design proposals and costings for both electric and steam trace options.
The wax applicationThe key parameter for this critical tracing application was to provide tight temperature control of the product at 80°C, but to have the ability to raise the temperature to 90°C for start-up or re-flow conditions. Other critical factors included the fact that the product would solidify at temperatures below 60°C, and spoil if subjected to temperatures above 120°C.Steam was available on site at 9 bar g and 180°C, which immediately presented problems of excessive surface temperatures if conventional schedule 80 carbon steel trace pipework were to be used. This had been proposed by the contractor as a traditional steam trace solution for the oil company. The total tracer tube length required was 11.5 km, meaning that the installation of carbon steel pipework would be very labour intensive, expensive and impractical. With all the joints involved it was not an attractive option. However, today's steam tracing systems are highly advanced technologically. Spirax Sarco and their partner on the project, a specialist tracing firm, were able to propose two parallel runs of insulated copper tracer tube, which effectively put a layer of insulation between the product pipe and the steam tracer. This enabled the use of steam supply at 9 bar g, without the potential for hot spots which could exceed the critical 120°C product limitation. The installation benefit was that as the annealed ductile steam tracer tubing used was available in continuous drum lengths, the proposed 50 m runs would have a limited number of joints, reducing the potential for future leaks from connectors.This provided a reliable, low maintenance solution.After comprehensive energy audit calculations, and the production of schematic installation drawings for costing purposes, together with some careful engineering, the proposal was to use the existing 9 bar g distribution system with 15 mm carbon steel pipework to feed the tracing system, together with strainers and temperature controls. Carbon steel condensate pipework was used together with lightweight tracing traps which minimised the need for substantial fabricated supports. The typical tracer runs would be 50 m of twin isolated copper tracer tubing, installed at the 4 and 8 o'clock positions around the product pipe, held to the product pipeline with stainless steel strap banding at 300 mm intervals. The material and installation costs for steam trace heating were about 30% less than the electric tracing option. In addition, ongoing running costs for the steam system would be a fraction of those for the electrical option. Before the oil company management would commit themselves to a steam tracing system, they not only required an extended product warranty and a plant performance guarantee, but also insisted that a test rig should be built to prove the suitability of the self-acting controlled tracer for such an arduous application. Spirax Sarco were able to assure them of the suitability of the design by referral to an existing installation elsewhere on their plant, where ten self-acting controllers were already installed and successfully working on the trace heating of pump transfer lines. The oil company was then convinced of the benefits of steam tracing the wax product line and went on to install a steam tracing system.Further in-depth surveys of the 4 km pipeline route were undertaken to enable full installation drawings to be produced. The company was also provided with on-site training for personnel on correct practices and installation procedures.

An appropriate valve can now be selected either from the manufacturer's sizing charts or using the saturated steam sizing chart shown in Figure 3.22.9.

For sizes up to DN80, a pilot operated self-acting valve would be suitable, whilst a pneumatically actuated control valve is appropriate on larger sizes.

Arrow Top

Pipework

It is appropriate at this point to check that the pipework between the steam accumulator pressure reducing station and the plant is adequately sized. This pipe should be sized as per normal practice on a steam velocity of 25 to 30 m/s, but using the peak flowrate from the steam accumulator at the plant pressure, in this instance 5 bar g.

A steam accumulator with fittings A steam accumulator with fittings
Arrow Top

Typical arrangements of steam accumulators:

Figure 3.22.11 shows all the steam generated by the boiler plant passing through the steam accumulator. This is the more modern generally preferred arrangement.

Fig. 3.22.11  Steam accumulator adjacent to the boiler Fig. 3.22.11 Steam accumulator adjacent to the boiler

The arrangement shown in Figure 3.22.12 was more commonly used in the past and is still useful when the steam accumulator must be sited some distance from the steam main. However, the check valves should be checked regularly, as a combination of 'sticking' and 'passing' valves can result in steam being charged to the steam accumulator above the steam surface, which brings no benefit.

Fig. 3.22.12 - Steam accumulator remote from the boiler Fig. 3.22.12
Steam accumulator remote from the boiler

Figure 3.22.13 shows an arrangement where steam at boiler pressure is required as well as steam at a lower pressure.

Some process applications cannot tolerate low pressure steam, and steam at boiler pressure may be required at all times (typically for a drying process). If a peak load is caused by the high pressure users, the pressure maintaining valve in Figure 3.22.13 would sense a pressure drop, and modulate towards its seat, thereby reserving high pressure steam for the high pressure users, thus leaving the steam accumulator to supply the low pressure demand during this period. In this way the system supplies a low pressure fluctuating load via the steam accumulator and the maximum possible flowrate for the high pressure load is ensured by the action of the pressure maintaing valve.

Fig. 3.22.13 - Steam required at boiler pressure as well as at lower pressure Fig. 3.22.13
Steam required at boiler pressure as well as at lower pressure

In Figure 3.22.14, the boiler is steaming at its normal design pressure, for example 10 bar, and the steam passes to variable loads which require not more than, for example 5 bar. Pressure reducing valve A is reducing pressure between the boiler header and the distribution main in the plant, responding to the pressure sensed in the 5 bar line.

Fig. 3.22.14 - Alternative standard arrangement Fig. 3.22.14
Alternative standard arrangement

If the steam demand should exceed the capacity of this supply from the boiler, and the pressure in the low pressure main falls below, for example 4.8 bar, valve B will begin to open and supplement the supply. This draws steam from the steam accumulator, and over a sustained period the steam accumulator pressure will fall. Valve B is responding to the downstream pressure in the distribution main, thus acting as a pressure reducing valve also. Its capacity should match the discharge rate permitted for the steam accumulator, and it will be smaller than pressure reducing valve A.

Valve C is a pressure-maintaining valve, responding to the boiler pressure. If the pressure rises because of reduced demand from the plant, pressure-maintaining valve C opens. Steam is then admitted to the steam accumulator that is recharged towards its maximum pressure, a little below boiler pressure. Pressure reducing valve B will be closed at this time because the plant is receiving sufficient steam through the (partially closed) pressure reducing valve A.

Arrow Top

Practical considerations for steam accumulators

Bypasses
In any plant, the engineering manager must endeavour to provide at least a minimum service in the event that the steam accumulator and its associated equipment either requires maintenance or breaks down.

This will include the provision of adequate and safe isolation of the accumulator with valves, and perhaps some means of protecting the boiler from overload if large changes in demand cannot be avoided. The most obvious solution here is a stand-by pressure-maintaining valve.

Fig. 3.22.15 - Accumulator bypass arrangement (valve controls not shown) Fig. 3.22.15
Accumulator bypass arrangement (valve controls not shown)

Effects on the boiler firing rate
The steam accumulator and pressure maintaining valve together protect the boiler from overload conditions and allow the boiler to operate properly up to its design rating. This is important to achieve good efficiencies and at the same time to supply clean, dry, saturated steam. Figures 3.22.16 and 3.22.17 illustrate respectively the firing rate without a steam accumulator and the firing rate with a steam accumulator.

Fig. 3.22.16 - Boiler without a steam accumulator Fig. 3.22.16
Boiler without a steam accumulator
Fig. 3.22.17 - Boiler with a steam accumulator and surplussing regulator Fig. 3.22.17
Boiler with a steam accumulator and surplussing regulator

Steam quality
When correctly designed and operated, steam from a steam accumulator is always clean, and has a dryness fraction quite close to 1. The steam accumulator is designed with a large water surface and sufficient steam space in order to produce high quality steam almost instantaneously during periods of peak demand. In the case of some vertical steam accumulators the steam space is enlarged to compensate for the smaller water surface.

Water
Water in the steam accumulator is steam that has condensed and is therefore clean and pure, with a typical TDS level of 20-100 ppm (compared with a shell boiler TDS of seldom less than 2 000 ppm) which promotes a clean and comparatively stable water surface. Steam accumulators are sometimes used to ensure clean steam is provided where steam is in direct contact with the product; as in hospital and industrial sterilisers, textile finishing and certain applications within the food and drinks industry.

Once the accumulator has been filled with water, and at normal running conditions, water additions and overflow rates are very small indeed.

  • If superheated steam is used, the amount of water to be added would be related to the amount of superheat, but since the specific heat of superheated steam is lower than water, it will have a smaller effect on changes in water level.
  • If saturated steam is used, the increase in water level is simply a function of heat loss from the vessel. With proper insulation, heat loss is minimal, so the increase in water level, and hence overflow through the steam trap (used as a level limiting device) is also minimal.

Steam accumulator designs
The steam accumulators described and illustrated in this Tutorial have been large and of a horizontal configuration. Steam accumulators are always designed and manufactured to suit the application, and vessels of only 1 m diameter are not uncommon. It is also usual for the smaller steam accumulators to be of a vertical configuration (although large vertical steam accumulators exist). Either configuration can maintain the same values of storage and discharge rate, and it may be easier to find space for a vertical unit.

The storage vessel
This is usually the most expensive part of a steam accumulator system, and will be individually designed for each application. It must be designed to hold the water / steam at the temperatures that are required for the plant. For industrial plant this typically means between 5 and 30 bar, although power station units may be rated up to 150 bar.

Typically the ratio of diameter to total length is between 1.4 to 1.6, but this can vary substantially depending on site conditions.

Steam accumulators are generally cylindrical in form with elliptical ends, as this is structurally the most effective shape. They will be manufactured from boiler plate. In Europe the design and construction will comply with the European Pressure Equipment Directive 97/23/EC.

The greater the acceptable pressure differential between the boiler pressure and the plant pressure, the greater the proportion of flash steam, and hence the lower the live steam capacity required.

In addition to the live storage capacity, the vessel must have:

  • Sufficient water in the bottom of the vessel, under minimum conditions, to accommodate and cover the steam injectors.
  • Sufficient clearance above the water under fully charged conditions to give a reasonable surface area for steam release. This is important because the instantaneous steam release velocity alone could be the final criteria if the peak loads are heavy and abrupt.

Justifying the cost of an accumulator
There are several ways in which the capital cost of an accumulator installation can be justified, and they will often pay back in a short period of time. The following points should be considered during an initial analysis.

  • Compare the capital cost of a boiler-only installation to meet the peak demand, with that of a smaller boiler used with an accumulator.
  • Estimate the fuel savings as a result of a smaller boiler operating closer to its maximum output and on a steadier load. In a recent case study, a brewery calculated a 10% fuel saving and a payback period of approximately 18 months.
  • As a result of levelling out the peaks and troughs of steam generation, determine if the unit cost of the fuel will be less. It may then be possible to contract for a lower maximum supply rate.
  • Estimate the financial advantage of reduced maintenance on boiler plant, steam control valves, and the steam using equipment. These benefits will result from a steadier boiler load and better quality steam.
Arrow Top

Conclusion

Steam accumulators are not old fashioned relics from the past. Indeed, far from it. Steam accumulators have been installed throughout modern industry including bio-technology, hospital and industrial sterilisation, product testing rigs, printing and food manufacturing, as well as more traditional industries such as breweries and dyehouses.

Modern boilers have become smaller and there is also an increase in the use of small water-tube boilers, coil boilers and annular boilers, all of which are efficient, but which reduce the thermal capacity of the system, and make it vulnerable to peak load problems.

There are many further applications for steam accumulators. For long term peaks which the boiler plant must ultimately handle, a steam accumulator can be used to store, for example, 5 minutes of the peak flowrate, allowing time for the boiler plant to reach the appropriate output safely. Steam accumulators can also be used with electrode or immersion heater boilers so that steam can be generated off peak, stored, and used during peak times. The possibilities are endless.

In summary, the steam accumulator is an efficient tool, as it may well provide the most cost effective way of supplying steam to a batch process.

Acknowledgement
Spirax Sarco acknowledges the help and information provided by:
Thermsave Engineering (UK) Ltd., Dinnington, South Yorkshire. S25 3QX

Arrow Top

What do I do now?

ukash exchange exchange ukash ukash exchange exchange ukash
ukash bozdurma yksek kur ukash bozdurma ukash bozdurmak istiyorum ukash bozdurma kuru