Page Content. This is achieved through a controlled injection of water into the superheated steam. A secondary attemperator called final stage is often placed after the inter stage temperature transmitter in order to prevent thermal damages to the steam turbine during start-up. The final stage attemperator ensures that the steam temperature upstream the turbine does not rise too fast. The DAM-B is a high performing ring style attemperator with a welded flow profiling liner for superior evaporation and performance. It complies with all existing standards and is always pressure tested on both the steam side as well as the water side.

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Steam temperature is one of the most challenging control loops in a power plant boiler because it is highly nonlinear and has a long dead time and time lag. Adding to the challenge, steam temperature is affected by boiler load, rate of change of boiler load, air flow rate, the combination of burners in service, and the amount of soot on the boiler tubes. After separation from the boiler water in the drum, the steam is superheated to improve the thermal efficiency of the boiler-turbine unit.

Modern boilers raise the steam temperature to around F C , which approaches the creep slow deformation point of the steel making up the superheater tubing. Steam temperatures above this level, even for brief periods of time, can shorten the usable life of the boiler. Keeping steam temperature constant is also important for minimizing thermal stresses on the boiler and turbine.

Steam temperature is normally controlled by spraying water into the steam between the first and second-stage superheater to cool it down.

Water injection is done in a device called an attemperator or desuperheater. The spray water comes from either an intermediate stage of the boiler feedwater pump for reheater spray or from the pump discharge for superheater spray. Other methods of steam temperature control include flue gas recirculation, flue gas bypass, and tilting the angle at which the burners fire into the furnace.

This discussion will focus on steam temperature control through attemperation. The designs discussed here will apply to the reheater and superheater, but only the superheater will be mentioned for simplicity. The simplest method for controlling steam temperature is by measuring the steam temperature at the point it exits the boiler, and changing the spray water valve position to correct deviations from the steam temperature set point Figure 1.

This control loop should be tuned for the fastest possible response without overshoot, but even then the loop will respond relatively slowly due to the long dead time and time lag of the superheater. Because of the slow response of the main steam temperature control loop, improved disturbance rejection can be achieved by implementing a secondary inner control loop at the desuperheater. This loop measures the desuperheater outlet temperature and manipulates the control valve position to match the desuperheater outlet temperature to its set point coming from the main steam temperature controller Figure 2.

This arrangement is called cascade control. The spray water comes from upstream of the feedwater control valves, and changes in feedwater control valve position will cause changes in spray water pressure, and therefore disturb the spray water flow rate. The desuperheater outlet temperature control loop will provide a gradual recovery when this happens. If the spray water flow rate to the attemperator is measured, a flow control loop can be implemented as a tertiary inner loop to provide very fast disturbance rejection.

However, in many cases spray water flow rate is not measured at the individual attemperators and this flow loop cannot be implemented.

The process dead time of the superheater increases with a decrease in boiler load because of the slower rate of steam flow at lower loads. This will have a negative impact on the stability of the main steam temperature control loop unless gain scheduling is implemented.

Step tests need to be done at low, medium, and high boiler loads, and optimal controller settings calculated at each load level. A gain scheduler should be implemented to adjust the controller settings according to unit load. Because of the changing dead time and lag of the superheater, the integral and derivative times must be scheduled in addition to the controller gain.

The gain of the desuperheater outlet temperature loop will be affected greatly by steam flow rate. Changes in steam flow rate will affect the amount of cooling obtained from a given spray water flow rate.

Less cooling will occur at high steam flow rates. In addition, at high loads the pressure differential between the feedwater pump discharge and steam pressure will be lower, reducing the spray flow rate for a given spray valve position assuming the absence of a flow control loop on the desuperheater spray flow. To compensate for these nonlinear behavior, controller gain scheduling should be implemented on the desuperheater outlet temperature loop too.

Similar to tuning the main steam temperature control loop, step tests must be done at low, medium, and high boiler loads to design the gain scheduler. During boiler load ramps in turbine-following mode, the firing rate is changed first, followed by a change in steam flow rate a while later. With the increase in steam flow rate lagging behind fuel flow rate, the additional heat in the furnace can lead to large deviations in steam temperature. To compensate for this, a feedforward control signal from the boiler master to the steam temperature controller can be implemented.

In essence, when boiler load is increasing, the spray water flow rate will be increased to counter the excess heat being transferred to the steam, and vice versa. The feedforward can be calibrated by measuring the extent of steam temperature deviation during load ramps. Stay tuned! Excellent effort. You can touch upon the integral windup problem frequent in STC.

I would like to see you write about the boiler-turbine co-ordinated control. Regards Karthi. Karthi, You bring up a good point. When the desuperheater outlet approaches saturation temperature, the inner loop should be blocked from adding more spray. In actual practice, you cannot permit the desuperheater outlet temperature reach saturation temperature since you have no idea of the quality of the fluid other that it could be all saturated liquid, all saturated vapor or some mixture of the two states.

Unfortunately, turbines and superheater tubes do not like water. The spray flow must be limited to a temperature above saturation temperature for the pressure, typically 20 degrees F. In the few cases where it is necessary to spray to saturation, a simple temperature based limit cannot be used. It is is very informative detail.

Imran, From the information you gave me it is not possible to tell exactly what the problem is. Are your measurements and controller outputs ranged exactly the same as they were before the retrofit? I didnt get the cascade control theory basics…. Output of PID is limited to 0 to corresponding to 4 to 20 mA for control valve. Please provide me more detailss…. Some controllers e. Honeywell Experion do the scaling for you automatically.

Yet other systems e. Emerson Ovation require you to place a scaling block between the two controllers. So how can we generate the feed forward signal logic from the fuel flow or boiler master demand to compensate this deviation? Can you give the that logic which can implemented to reduce this problem? Ravi, there are several designs for this feedforward of which some seem to work better than others depending on the particular situation, boiler design, fuel type, etc.

Some use fuel flow, or its rate of change, some use air flow, or its rate of change. Others use a combination of steam and fuel flow that alters spray flow based on the relative difference between fuel and steam flows. It is an excellent source of technical information on boiler controls. This is slightly off topic but still relevant question for Control engineers at a time when Advanced process control schemes are becoming more prevalent.

Is the use of a Model predictive controller to provide set-points to the spray control valves for steam temperature control a cost effective approach? On the flip side, the power industry is the forerunner with utilizing complex DCS-based control strategies.

The power industry lacks the skills to implement and maintain APC, and the cost benefits are just not there in many cases except perhaps for environmental controls. I read the article and found it to give an objective assessment on APC in power plants. Hi, I read your article impressively. In the plant where I worked, the main and re-heat steam temperature control loop is cascade without feedforward demand. At first, the main and re-heat steam temperatures swinged and it affected MW and steam pressure.

To avoid that, we applied charecteristic curve o. A characterizer can be used very effectively in feedforward control where the relationship between the disturbance and the required compensating control action is nonlinear. It sounds like this is what your boss did, even though the design might have been different from normal. If there is a strong relationship between e. However, you will likely also require some degree of feedback control to compensate for other variables such as different burners in use, boiler sooting, etc.

Firstly, I cannot thank you enough for this incredibly educational and useful website. With regards to the main steam temperature to desuperheater outlet temperature cascade arrangement, is the inner loop here typically many times faster than the master loop? Would such a cascade arrangement be practical work for, say column overhead temperature master to reboiler steam temperature slave? So even a ratio may make cascade control desirable. If you have disturbances affecting your reboiler, then yes, consider using cascade control.

Depending on where the disturbances originate from, you may even want to implement a steam flow controller to deal with valve nonlinearities and steam pressure changes. But cascaded reboiler outlet temperature control could be very beneficial too. Again, it depends where your disturbances or nonlinearities show up first. Jacques, Thank you for article, curious to know how I can implement gain scheduling in Yokogawa.

Because I presume that there is no tailor made block same like of Honeywell. Moreover, how can I represent integrated gain scheduling feedback loop in the form of controller bolock diagram.

Ritesh: Modern PID control blocks allow you to expose the tuning settings to be connected to external signals. See your Yokogawa user guide for how to do it. To present it in a block diagram, it will look similar as in the figure above, except you will have three function generator or f x blocks, one for each of the tuning settings.

Name required. Mail will not be published required. Steam Temperature Control September 8, Figure 1. Simple Steam Temperature Control. Figure 2. Cascaded Steam Temperature Controls. Figure 3.


​​​​​​​DAM-B: Steam Attemperator

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