Thanks to Control Loop Foundation!!!
Thanks to Control Loop Foundation!!!
One common application of cascade control combined with feed forward control is in level control systems for boiler steam drums.
The control strategies now used in modern industrial boiler systems had their beginnings on shipboard steam propulsion boilers. When boilers operated at low pressure, it was reasonably inexpensive to make the steam drum large. In a large drum, liquid level moves relatively slowly in response to disturbances (it has a long time constant). Therefore, manual or automatic adjustment of the feedwater valve in response to liquid level variations was an effective control strategy.
But as boiler operating pressures have increased over the years, the cost of building and installing large steam drums forced the reduction of the drum size for a given steam production capacity.
The consequence of smaller drum size is an attendant reduction in process time constants, or the speed with which important process variables can change. Smaller time constants mean upsets must be addressed more quickly, and this has led to the development of increasingly sophisticated control strategies.
3 Element Strategy
As shown below (click for large view), most boilers of medium to high pressure today use a “3-element” boiler control strategy. The term “3-element control” refers to the number of process variables (PVs) that are measured to effect control of the boiler feedwater control valve. These measured PVs are:
▪ liquid level in the boiler drum,
▪ flow of feedwater to the boiler drum, and
▪ flow of steam leaving the boiler drum.
Maintaining liquid level in the boiler steam drum is the highest priority. It is critical that the liquid level remain low enough to guarantee that there is adequate disengaging volume above the liquid, and high enough to assure that there is water present in every steam generating tube in the boiler. These requirements typically result in a narrow range in which the liquid level must be maintained.
The feedwater used to maintain liquid level in industrial boilers often comes from multiple sources and is brought up to steam drum pressure by pumps operating in parallel. With multiple sources and multiple pumps, the supply pressure of the feedwater will change over time. Every time supply pressure changes, the flow rate through the valve, even if it remains fixed in position, is immediately affected.
So, for example, if the boiler drum liquid level is low, the level controller will call for an increase in feedwater flow. But consider that if at this moment, the feedwater supply pressure were to drop. The level controller could be opening the valve, yet the falling supply pressure could actually cause a decreased flow through the valve and into the drum.
Thus, it is not enough for the level controller to directly open or close the valve. Rather, it must decide whether it needs more or less feed flow to the boiler drum. The level controller transmits its target flow as a set point to a flow controller. The flow controller then decides how much to open or close the valve as supply pressure swings to meet the set point target.
This is a “2-element” (boiler liquid level to feedwater flow rate) cascade control strategy. By placing this feedwater flow rate in a fast flow control loop, the flow controller will immediately sense any variations in the supply conditions which produce a change in feedwater flow. The flow controller will adjust the boiler feedwater valve position to restore the flow to its set point before the boiler drum liquid level is even affected. The level controller is the primary controller (sometimes referred to as the master controller) in this cascade, adjusting the set point of the flow controller, which is the secondary controller (sometimes identified as the slave controller).
The third element in a “3-element control” system is the flow of steam leaving the steam drum. The variation in demand from the steam header is the most common disturbance to the boiler level control system in an industrial steam system.
By measuring the steam flow, the magnitude of demand changes can be used as a feed forward signal to the level control system. The feed forward signal can be added into the output of the level controller to adjust the flow control loop set point, or can be added into the output of the flow control loop to directly manipulate the boiler feedwater control valve. The majority of boiler level control systems add the feed forward signal into the level controller output to the secondary (feedwater flow) controller set point. This approach eliminates the need for characterizing the feed forward signal to match the control valve characteristic.
Actual boiler level control schemes do not feed the steam flow signal forward directly. Instead, the difference between the outlet steam flow and the inlet water flow is calculated. The difference value is directly added to the set point signal to the feedwater flow controller. Therefore, if the steam flow out of the boiler is suddenly increased by the start up of a turbine, for example, the set point to the feedwater flow controller is increased by exactly the amount of the measured steam flow increase.
Simple material balance considerations suggest that if the two flow meters are exactly accurate, the flow change produced by the flow control loop will make up exactly enough water to maintain the level without producing a significant upset to the level control loop. Similarly, a sudden drop in steam demand caused by the trip of a significant turbine load will produce an exactly matching drop in feedwater flow to the steam drum without producing any significant disturbance to the boiler steam drum level control.
Of course, there are losses from the boiler that are not measured by the steam production meter. The most common of these are boiler blow down and steam vents (including relief valves) ahead of the steam production meter. In addition, boiler operating conditions that alter the total volume of water in the boiler cannot be corrected by the feed forward control strategy. For example, forced circulation boilers may have steam generating sections that are placed out of service or in service intermittently. The level controller itself must correct for these unmeasured disturbances using the normal feedback control algorithm.
Notes on Firing Control Systems
In general, firing control is accomplished with a Plant Master that monitors the pressure of the main steam header and modulates the firing rate (and hence, the steam production rate) of one or more boilers delivering steam to the steam header. The firing demand signal is sent to all boilers in parallel, but each boiler is provided with a Boiler Master to allow the Plant Master demand signal to be overridden or biased. When the signal is overridden, the steam production rate of the boiler is set manually by the operator, and the boiler is said to be base-loaded. Most boilers on a given header must be allowed to be driven by the Plant Master to maintain pressure control. Boilers that have the Boiler Master set in automatic mode (passing the steam demand from the Plant Master to the boiler firing control system) are said to be swing boilers as opposed to base-loaded boilers.
The presence of heat recovery steam boilers on a steam header raises new control issues because the steam production rate is primarily controlled by the horsepower demand placed on the gas turbine providing the heat to the boiler. If the heat recovery boiler operates at a pressure above the header pressure, a separate pressure control system can be used to blow off excess steam from the heat recovery boiler when production is above the steam header demand. Note that for maximum efficiency, most heat recovery boilers are fitted with duct burners to provide additional heat to the boiler. The duct burner is controlled with a Boiler Master like any other swing boiler. As long as there are other large swing boilers connected to the steam header, the other fired boilers can reduce firing as required when output increases from the heat recovery boiler.
Source: Allen D. Houtz
The drum level must be controlled to the limits specified by the boiler manufacturer. If the drum level does not stay within these limits, there may be water carryover. If the level exceeds the limits, boiler water carryover into the superheater or the turbine may cause damage resulting in extensive maintenance costs or outages of either the turbine or the boiler. If the level is low, overheating of the water wall tubes may cause tube ruptures and serious accidents, resulting in expensive repairs, downtime, and injury or death to personnel. A rupture or crack most commonly occurs where the tubes connect to the drum. Damage may be a result of numerous or repeated low drum level conditions where the water level is below the tube entry into the drum.
Some companies have had cracked or damaged water tubes as a result of time delayed trips or operators having a trip bypass button. When the drum level gets too low, the boiler must have a boiler trip interlock to prevent damage to the tubes and cracks in the tubes where they connect to the boiler drum. The water tubes may crack or break where they connect to the drum, or the tubes may rupture resulting in an explosion. The water tube damage may also result in water leakage and create problems with the drum level control. The water leakage will affect the drum level because not all the water going into the drum is producing steam.
Poor level control also has an effect on drum pressure control. The feedwater going into the drum is not as hot as the water in the drum. Adding feedwater too fast will result in a cooling effect in the boiler drum reducing drum pressure and causing boiler level shrinkage. This can be demonstrated by pouring tap water into a pan of boiling water.
Shrink and swell
Shrink and swell must be considered in determining the control strategy of a boiler. During a rapid increase in load, a severe increase in level may occur. Shrink and swell is a result of pressure changes in the drum changing water density. The water in the drum contains steam bubbles similar to when water is boiled in our homes. During a rapid increase in load, a severe rise in level may occur because of an increase in volume of the bubbles. This increased volume is the result of a drop in steam pressure from the load increase and the increase in steam generation from the greater firing rate to match the load increase (i.e., bubbles expand). If the level in the drum is too high at this time, it may result in water carryover into the superheater or the turbine. The firing rate cycle can result in drum pressure cycles. The drum pressure cycles will cause a change in drum level.
The firing rate change has an effect on drum level, but the most significant cause of shrink and swell is rapid changes in drum pressure expanding or shrinking the steam bubbles due to load changes. When there is a decrease in demand, the drum pressure increases and the firing rate changes, thus reducing the volume of the bubbles (i.e., bubbles get smaller). A sudden loss in load could result in high drum pressure causing shrinkage severe enough to trip the boiler on low level. A boiler trip at high firing rates creates a furnace implosion. If the implosion is severe enough, the boiler walls will be damaged due to high vacuum in the furnace.
Typically, for redundancy, there are three different methods used to measure drum level. In the “Boiler drums/level measurement” example, the bull’s eye technology is a direct reading level measurement. The differential pressure transmitter represents the level control measurement, and the probe type sensor is a common method for level alarms and low and high level shutdown. Note the connections in the second illustration are not realistic.
The chamber with the probes is for drum level alarms and boiler trips. The longest probe is the common one. The one above it is low water trip. The one above that is the low water alarm. The short probe can be a high level alarm or a boiler trip. The length of the probes is determined by the boiler manufacturer. My experience is the low water shutdown probe is 1½ to 2½ inches above the water tube boiler connections.
The basic indication of the drum water level is commonly shown in a sight gage glass (bull’s eye) connected to the boiler drum. The American Society of Mechanical Engineers requires a direct reading of the drum level. Due to the configuration of the boiler, and the distance the boiler drum is from the operator, a line-of-sight indication may not be practical. The gage glass image can be projected with a periscope arrangement of mirrors. There are a number of methods for drum level measurement. Other methods are a closed circuit television and the use of fiber optics.
The sight glass reading is affected by the temperature/density of the water in the sight glass. The water in the sight glass is cooler than the water in the boiler drum.
Drum level measurement
The “Drum level connections” image is an example of the arrangement of a differential drum level measuring transmitter. The differential transmitter output signal increases as the differential pressure decreases. (Note the differential pressure connections. The connections may need to be reversed or calibrated so increasing level will go from 0 to 100%.) The differential pressure range will vary between 10 and 30 inches, depending on the size of the boiler drum, with a zero suppression of several inches. On the high pressure side of the measuring device, the effective pressure equals boiler drum pressure plus the weight of a water column at ambient temperature having a length equal to the distance between the two drum pressure connections. On the low pressure side, the effective pressure equals boiler drum pressure, plus the weight of a column of saturated steam having a length from the upper drum pressure connection to the water level, and the weight of a column of water at saturation temperature having a length from the water level to the lower drum pressure connection.
On high pressure boilers, a condensate pot is connected on the top water leg to keep the leg full of condensate. If the condensate level varies in the top connected leg, the drum level measurement will not be accurate. On low pressure boilers, a condensate pot may not be required. The “Drum level connections” image is an example of the correct method of installing a differential pressure transmitter. The correct installation allows the sediment to remain in the blowdown line without getting into the transmitter.
Problems with drum level measurement can be a result of improper installation of the sensing legs from the boiler drum to the transmitter. It is critical that lines be sloped at least a half inch per foot from the boiler drum to the transmitter. If not properly sloped, air pockets may form in the lines creating improper drum level measurement.
When a differential pressure transmitter is used to measure drum level and the instruments used are sensitive to density variation, density compensation techniques must be employed. A mass steam flow and water flow signal is required for two and three element control systems. (For more information, refer to ANSI/ISA-77.42.01-1999 (R2006) – Fossil Fuel Power Plant Feedwater Control System – Drum Type.)
Observe the error due to density in the “Uncompensated drum level measurement error” chart. The top boiler connection to the transmitter will be filled with condensate. As the drum level increases, the two signals become equal, thus reading zero level when the drum level is at 100% (“Sight glass drum level indication” image). By reversing the connections at the transmitter, the drum level signal is reversed. The reading may also be corrected with transmitter calibration.
The drum level control indicator scale for a 30-inch span, the distance between the upper and lower drum connections, would be -15 to +15 inches with zero as the controller set point. On higher pressure boilers, typically above 1000 psi, a considerable error in level measurement at other than the operating pressures exist when a differential pressure is used to measure level due to water density changes in the drum.
SOURCE: Boiler Control Systems Engineering, 2nd Edition, by Jerry Gilman, http://www.isa.org/boilereng.