May 1, 2009

Boiler-Tuning Basics, Part IITim Leopold, ABB Inc.

Boilers have enormous thermal mass and are relatively slow to react. Turbines are

nimble and quickly answer an operator’s command. Coordinating an entire plant

requires an intimate knowledge of both systems and selecting the right logic tools to

bring them together.

The front end, in the jargon of the power plant controls engineer, consists of the boiler

master and turbine master. As explained in Part I of this two-part series, the operator’s

window into the control system is referred to as a station or master, and it provides the

operator interface for a given control loop. Access to that loop is typically from a switch

or hand station located on the control panel in older plants or, more commonly, the

operator’s keyboard in plants fortunate enough to be equipped with digital controls.

The best case is when both the turbine and boiler masters are in the distributed control

system (DCS). But this is not always the case. We often find that only the boiler controls

have been upgraded. In such cases it is important that the DCS be able to interface with

the existing turbine controls if you want to take advantage of the DCS’s full abilities.

Options for tuning the entire plant are limited with a DCS that includes the boiler master

but lacks a communications link with the turbine controls.

Boiler Control OptionsBoiler tuning is something of a balancing act. Feedwater enters the boiler through a

series of low- and high-pressure steam heaters into the drum. The water then journeys

through the water walls of the furnace and absorbs heat until steam is formed in the

main steam drum.

This steam then enters the main steam line and passes through a series of

superheaters and desuperheaters until it finally ends up at the turbine governor and/or

stop valves. The boiler controls the turbine throttle pressure by modulating the boiler-

firing rate. This means that the amount of fuel and air that is going into the furnace is

increased or decreased depending on whether the turbine requires more or less steam

pressure.

There are four usual modes of operation in the world of drum boilers: base mode, boiler-

following mode, turbine-following mode, and coordinated control (Table 1). Each of

these operating modes is described in the following paragraphs.

Table 1.    Options for plant boiler control. Source: Tim Leopold

In general, the boiler master will be either in auto or manual control mode. The turbine is

another matter. Turbine controls generally have a number of stand-alone loops — such

as megawatt, pressure, valve position, or speed — which are control loops that do not

respond to the DCS turbine master. If the turbine controls are not looking at the front

end, then as far as the front end is concerned, the turbine is in manual control. For our

purposes, "auto" under the turbine master heading in Table 1 means the front end is

controlling the turbine governor valves.

Base Mode. In this mode, there is no automatic response to changes in main steam or

throttle pressure or megawatt setpoint by the front-end controllers. An operator’s steady

hand is required to make the final boiler control adjustments. The turbine might be in

one of its own stand-alone loops, but the turbine master has no control of the plant.

Many plants operate in this or a similar mode prior to upgrading their turbine controls to

a DCS.

Boiler-Following Mode. In this mode of operation, the boiler master is in automatic and

the turbine is not. This is an automatic control loop, controlling steam pressure.

Depending on the boiler, it can be well controlled. Generally, this is the loosest of the

three typical automatic front-end modes of operation (Figure 1).

1.    Loaded questions. A typical boiler-following response following a setpoint change.

Source: Tim Leopold

This is one of those loops that uses the dreaded derivative gain. The proportional gain

is normally pretty high, the integral action slow, and the derivative is absolutely a must.

The real keys to tuning the front end are a few simple concepts. For example, don’t add

to an upset; that is, don’t have any of your gains disproportionately high. We use the

derivative because we are trying to anticipate the steam pressure deviation.

The feedforward signal is an important part of this control loop and is often referred to

as target steam flow. Target steam flow is the measured steam flow multiplied by the

ratio of throttle pressure setpoint to throttle pressure. Typically, there is a function

generator designed such that 0% to 100% of the input signal is proportional to a 0% to

100 % output signal. The nicely dynamic nature of the ratio helps the boiler master

move in the right direction. Additional "kickers" may also be available. One option is a

throttle pressure setpoint kicker that adds a little to the feedforward signal if the setpoint

is changed. The derivative action of the controller also acts as a kicker.

Turbine-Following Mode. In many ways, this is my favorite plant operating mode,

because it is the easiest to tune. It also offers a good strong safety net to operators in

times of crisis. In turbine-following mode the boiler master is in manual and the turbine

master is in automatic mode. The turbine master controls throttle pressure by

modulating the turbine governor valves. Megawatts are then produced in the generator

and pushed to the grid as a function of the boiler load.

Compared to the slow and sometimes lumbering response of the boiler, turbine

response is usually fast and agile. Proportional gains are usually moderately large, and

the integral action can be quite fast. Although adaptive tuning is possible, there usually

isn’t the need for this; many units use only one value for the proportional and/or the

integral gain. Also, the need for a feedforward is minimal. The turbine governor valves

operate as one large pressure control valve that can easily control throttle pressure

when the control loops are well-tuned.

Turbine-following mode is also a favorite among operators. If the plant is in coordinated

mode, and the unit starts to go out of control for almost any reason, operators simply

have to put the boiler master into manual. Immediately, the controls will automatically

default to turbine-following mode. The valves open or close, as necessary to control the

main steam pressure. Meanwhile, because the firing rate has steadied, the boiler

controls will soon settle out.

Figure 2 plots the data taken during start-up of a 320-MW power plant. At the lower left

corner you can see where the valve transfer occurred. The valve transfer is a process in

which the turbine, upon start-up, transfers control from the stop valve to the governor

valve. There are actually two sets of valves in the main steam line before the turbine:

the main stop valve and the governor valves. The next interesting point on this figure is

the area that I call the "disturbing delta." There was a long period, during this load ramp,

when the difference (delta), between the throttle pressure and the throttle pressure

setpoint was virtually constant (the purple and green lines at the first vertical white

dotted line). When we expect the controls to act one way, and they do not, it’s time to

investigate.

2.    Under control. Taming a control loop that switched out the integral control on a

load ramp. Source: Tim Leopold

During a change in unit load demand, in coordinated control, it is common practice to

decrease the integral action of the boiler master controller to zero until the load ramp is

finished. This strategy was used in all of the turbine and boiler master controller modes.

This is a case where more is definitely not better; there was a touch of feedforward,

based on boiler demand, substantial proportional gain, and no integral gain when I

looked at the logic. Tuned as it was, the error signal between throttle pressure and

throttle pressure setpoint will never go away.

I tried to tune out the error without success. Although the error decreased, as shown in

Figure 2, we soon discovered that the tuning was not robust under all operating

conditions. We then downloaded the necessary logic modifications (the second white

vertical dotted line), causing the unit to drop out of turbine-following and into base load

mode, and then back again. When the logic modifications were made, from that point on

(the third white vertical dotted line) you can see good control of the throttle pressure.

This is how a well-tuned turbine-following mode should operate.

Coordinated Control ModeCoordinated front-end control was developed in the late 1970s and early 1980s to

answer a long-standing controls problem. For many years, the turbine master controlled

megawatt production and the boiler master controlled boiler pressure, and the two never

spoke to one another. To this day there are plants that continue to operate with no

coordination between the boiler and turbine masters.

For example, if we are in boiler-following mode, the boiler master is controlling pressure,

and if the turbine master uses the local megawatt control loop, we have what I refer to

as an "anti-coordinated" mode. If the megawatts increase, the turbine valves must close

down. When the valves close, the throttle pressure rises. When the pressure rises, the

boiler master must decrease. When the boiler decreases, the megawatts drop and the

turbine valves must open up, dropping pressure, raising the boiler demand, increasing

megawatts, closing the valves... and around we go again, and will hopelessly oscillate

this way forever.

Enter boiler-turbine coordinated control, where the boiler master and turbine master are

used in tandem to control both megawatt production and throttle pressure. In

coordinated mode the boiler master looks mostly at the throttle pressure error and just a

tiny bit of megawatt error. The turbine, on the other hand looks mostly at the megawatt

error with some throttle pressure error. The expert tuning the controls must then decide

how much of each to use. The rule of thumb, as passed on to me by Al Shultz, PhD, is

10 parts throttle pressure error to 1 part megawatt error for the boiler master; for the

turbine it’s 10 parts megawatt error to 4 parts throttle pressure error.

If there is no coordination between the boiler and turbine controls, they will fight each

other to the death. The boiler really cannot do much more than control throttle pressure,

and even then it is slow because of its massive thermal capacitance.

The turbine valves are much faster and are capable of controlling both megawatts and

pressure. The valves tap into the boiler’s thermal capacitance when the plant’s load

changes. These ratios focus the turbine controls on megawatt production with the

megawatt setpoint and throttle pressure are near the setpoint. When deviations occur,

the throttle pressure error becomes more important and slows the turbine down, moving

it in the opposite direction that a pure megawatt controller would demand. Amazingly,

for all boilers (drum or once-through, coal- or gas- or oil-fired) this rule of thumb will give

you a good solid starting point to begin tuning the front-end coordinated mode controls.

Next comes the tuning of the controllers. In general, the turbine master is the easier of

the two components to tune, so that is the one to attack first. The gains will be less

aggressive than were used for the turbine-following mode, but it is good practice to have

the turbine master control the megawatts as tightly as possible at first. If that response

is too much for the boiler to handle, the tuning can be loosened up later. Note that this

will only be proportional and integral tuning with no derivative action.

The key to tuning the boiler master is balancing the proportional, integral, and derivative

action of the controller so that the pressure is maintained with good control, moves

toward the setpoint in a timely manner, and correctly anticipates the movement of the

error signal. In general, the proportional gain will be fairly large, the integral action slow,

and the derivative gain in the controller should be relatively small.

Finally, the controls that make up the coordinated front end may use some feedforward

and the various kickers that are part of it. The feedforward signals to both the turbine

and the boiler master controllers, in coordinated mode, is a function of unit load

demand.

Tuning for Unit ResponseUnit load demand is the high- and low-limited and rate-limited version of the unit master

demand. The operator enters in his target megawatt load into the DCS. There are high

and low limits on what the operator can enter that are determined by the operator, the

boiler and turbine suppliers, and good practice. A unit load increase rate limit is also

available to the operator. Typical values used by the industry are 1% or 2% per minute

unit load rate of change. I have tuned boilers that can go up to 5% a minute, but nobody

really uses that value because of the wear and tear on the equipment. I normally expect

to see a rate limit of about 1 MW/minute for a 100-MW unit or 8 MW/minute for an 800-

MW unit.

The feedforward to the turbine will usually be a very weak function of unit load demand,

when used. This is because the turbine is quite capable of doing its part in this

coordinated control dance — it can respond much faster than the boiler. The

feedforward to the coordinated boiler master controller is quite different. The important

aspect of feedforward is the slope of the line. This is determined by the function of unit

load as well as the rate of change of the unit load demand chosen by the operator. This

feedforward helps the boiler master keep up with the increase or decrease in load to

maintain the throttle pressure at setpoint.

However, a simple feedforward addition is almost never sufficient for a robust

coordinated control system. Remember that the boiler is a reservoir of energy trapped

by the turbine governor valves as the load demand changes. However, it’s not an

infinite reservoir, and the main steam pressure tends to sag or balloon as the unit

increases and decreases load. That is why kicker circuits are included in the controls.

The first kicker is based on the feedforward (that is a function of unit load demand), and

it should be a derivative kick that can be tuned to minimize the pressure sag on a load

change. Remember, the closer the throttle pressure can stay to the setpoint, whatever it

is, the easier it is for the turbine to provide megawatts and the less swing will occur

when the load change is finished. Some boilers are well behaved and very responsive,

so this kick is minimal. Some boilers are not well behaved, and their kickers can be

pretty substantial. There can be other kickers, possibly based on the throttle pressure or

the throttle pressure setpoint kicker, as described for the boiler-following mode.

Practical Controls MagicThe tuning process can’t be rushed and does take some time to get right. Here is an

example. Recently, I walked into the control room of an 800-MW unit just as the

operators made a load change. As you can see, the response of the unit left something

to be desired (Figure 3).

3.    Unresponsive. A load change on this 800-MW unit showed poor response and

controls in need of a good tuning. Source: Tim Leopold

By the third day, the coordinated controls were responding well after I slightly decreased

the integral and proportional gain and increased the derivative action of the controller by

about 25%. I also modified the feedforward signal slightly. Figure 4 illustrates the unit

response to a 353-MW load increase test. About halfway through, the operator was

unable to start an induced-draft (ID) fan, so he changed to base mode and then to

boiler-following mode. When the ID fan was finally started, he returned to coordinated

control mode. As you can see in Figure 4, a request was received by the front end to

increase load just after the operator decided to raise his throttle pressure. This well-

tuned boiler sailed through each test with rock-solid performance.

4.    New lease on life. The same 800-MW unit as in Figure 3 showed much better

response to a load change after tuning the proportional and integral gain and increasing

the derivative action of the controller by 25%. Source: Tim Leopold

Runbacks and RundownsThe final phase of tuning is runback testing. Turbine following is a nice safe place to

retreat to when the operator has the time to take action. However, what happens when

there is no time to react?

For these situations two control strategies are used: runbacks and rundowns. A runback

is an action taken on a loss of a major piece of equipment. Typical runbacks include

coal feeders, boiler feed pumps, or any plant fan — induced draft, forced draft (FD), or

primary air.

A rundown is a reaction to a large process error that does not go away, such as a major

boiler tube rupture. In this incident, the feedwater pumps pick up the increased

feedwater demand or the feedwater valve goes completely open, but the drum level

keeps dropping. Eventually, the plant must initiate a rundown or reduction in steam

generation rather than trip the boiler. Typical rundowns are associated with air flow,

furnace pressure, fuel flow, feedwater flow, or drum level.

Rundowns are seldom tested, on purpose, and that’s not because they are overlooked.

Rather, the logic decides if the boiler or the turbine can or should respond. If the fuel

master is in auto and looking at the boiler master for its output, then the boiler is

capable of responding, and there is no need for the turbine to respond. If the turbine is

not looking at the front-end controls for its output and the fuel master is not in auto, then

the only device that can respond is the turbine, and so it does. This last scenario has a

very high potential for tripping the unit.

Usually, the fuel master will be in auto. The boiler demand is then reduced by the

rundown logic from where it was to some value that allows the error that is driving the

rundown to fall below some preset limit. If the error does not go down, the rundown will

continue to reduce boiler load to a set minimum value.

The first runback logic that I ever came into contact with was very severe. On a loss of

equipment, the boiler controls would attempt to stay in coordinated mode. The unit load

demand would run down, at some preset, fast, rate. This would decrease the boiler

demand and the demand to the turbine governor valves. That worked all right for some

boilers, but the rate that was necessary for the boiler to get to a safe operating load was

very fast. The difficulty is that the turbine governor valve would close down at the same

rate. When these valves close, the main steam pressure must climb and may eventually

lift the boiler pressure safety relief valves. This is very hard on the drum level and your

ears, and often results in a master fuel trip. Granted, it was a trip from a lower boiler

load, rather than if we had otherwise simply tripped the boiler, but it was a trip

nonetheless.

As a result, what I like to call a kinder, gentler runback was developed. Some call it the

turbine-following runback, where the boiler switches to manual on the loss of a piece of

equipment. If you are in coordinated mode, the boiler should go to manual control and

turbine-following mode for the steam turbine. At this time, the runback logic reduces the

boiler demand to a predetermined level at a preset rate. In the meantime, the turbine is

free to control the main steam pressure. The megawatt load is then gently reduced, and

the plant experiences a soft landing. Turbine-following is the best mode to select in an

emergency.

A further goal of a runback is to recover automatically so the operators can figure out

what happened to the equipment and fix it while the unit is still online and avoid a

master fuel trip.

The data shown in Figure 5 were collected during an actual runback test on a 95-MW

plant that operated with three pulverizers. The runback occurred when an ID fan was

tripped, which had the effect of tripping one of the FD fans. The runback of the boiler

was set to a point that was below the three-mill minimum load for safe and stable

operation. As a result, automatic mill tripping on a runback was developed.

5.    Avoiding unit trips. A runback test is necessary when any changes are made to

boiler gas pass, fans, or mills. In this test of a 95-MW unit, the runback occurred when

an ID fan was tripped. Source: Tim Leopold

You can see the boiler demand dropping, and the fuel flow percentage dropping even

further as one of the three mills is shut down by the runback logic. The pulverizer

master (coal master demand) picks up momentarily as the mill is stopped, then ramps

back down, eventually getting the fuel percentage down to the boiler demand.

Automatic mill tripping is generally a good idea, especially on larger units with a lot of

mill capacity. Also, notice how the turbine pushes the throttle pressure back to the

setpoint. Drum level also dropped slightly before it recovered. The entire runback

occurred in just over two minutes. Figure 6 is a longer view of the entire episode.

6.    Many moving parts. The same runback test (Figure 5) of a 95-MW unit but with a

longer time-span is illustrated. Here you can see the pulverizer master ramping back

and the lowering of the turbine operating pressure setpoint. Source: Tim Leopold

In this test, as is true for most of the tests I have run over the years, the fan and fuel

runbacks are easily handled by the turbine-following runback logic. However, the boiler

feedwater pump runback can be another matter. The turbine valves are relatively slow

to respond and tend to suck steam from the drum. Though some boilers are able to

survive this without tripping on low drum level, many can not.

As a result, new logic was developed. I like to call this special type of runback the

separated runback. On the loss of a boiler feed pump, the boiler master goes to manual,

coal mills are tripped, and the boiler demand is driven to minimum. The turbine master

remains in auto to stay in turbine-following mode. At this point, we add a special high-

limit override enabled during this runback that overrides the turbine-following controller

and marches the governor valves to a predetermined position. The rate at which the

valves are closed is variable and depends on the throttle pressure. Higher pressures

tend to depress the drum level, which we do not want, and really high pressures lift

safeties, which started us on this runback logic journey in the first place.

If you plan to test your runback logic, it’s a good idea to elevate the drum level a few

inches before your test. At this same 95-MW plant, we tested the boiler feedwater pump

runback using separated runback logic from 75% load with the drum level rundown

initiated when the runback was complete. Figure 7 data illustrate this successful test

from the feedwater perspective. Notice the action of the feedwater control valve. The

drum level dropped about 6.5 inches. The low drum level trip was set at 7.7 inches. That

was successful, but a little too close for comfort.

7.    Different perspective. The same runback test (see Figure 5) of a 95-MW unit but

from the perspective of the feedwater system. Note the drum level response. Source:

Tim Leopold

When Enough Is EnoughOne of the big challenges faced by a boiler and turbine controls tuner is to know when

to stop. It’s a job that has no defined stopping point, and there are always ways to

further improve performance.

So how do we know when boiler tuning is finished? Typically, I call it quits when the

operators are satisfied and, based on my experience, the plant is as good as other units

I’ve worked on over the years. Or, in the words of Supreme Court Justice Potter

Stewart, "I know it when I see it."

—Tim Leopold (tim.leopold@hotmail.com) is a field service engineer with ABB and has

more than 20 years’ experience tuning controls on power plants around the world. His

book, You Can Tune a Boiler But You Can’t Tuna Fish, is available through

amazon.com.