March 1, 2009

Boiler-Tuning Basics, Part ITim Leopold

On my first project as a combustion control engineer, I was responsible for loop checks

and for watching the experts tune the system controls. The first loop I tried to tune solo

was the drum level control. At that time the trend-tune program defaulted to a 2-minute

window, and no one bothered to mention to me that the proper time span to tune drum

level control to is 20 to 30 minutes. I also zoomed in on the drum level, which has a

normal range of ±15 inches, though my trend range was ±3 inches. Finally, I did not

know that drum level can be a very "noisy" signal, so the hours I spent trying to tune out

that noise were wasted.

Eventually, I got the bright idea to add a little derivative to the loop control. In the time it

took to program 0.01 as the derivative gain and then immediately remove it, the boiler

tripped. Thus began my career in boiler tuning.

In the 20-plus years since my inauspicious debut, I’ve had the opportunity to

successfully tune hundreds of boilers, new and old, that needed either a control loop

tweak or a complete overhaul.

Many inexperienced engineers and technicians approach boiler tuning with a heavy

hand and little insight into the inner workings of individual control loops, how highly

interconnected they are with other loops in the boiler system, or what change should be

expected from the physical equipment the loops are to control. My purpose in writing

this article is to explore these fundamentals and share my experiences. I trust these

insights will be of value to the power industry and specifically to those who want to tune

boilers for rock-solid stability yet agility when responding to process changes.

What Constitutes Good Control?Every boiler ever built has its own set of peculiarities. Even two boilers built at the same

plant at the same time to the same drawings will have unique quirks and special tuning

issues. I begin with a description of the various boiler and subsystem control loops

before moving to good boiler-tuning practices that are sufficiently robust to

accommodate even minute differences between what should be identical boilers.

From a pure controls perspective, the most important goal is to tune for repeatability of

a value, not the actual value itself. We do not care that there are exactly 352,576.5 pph

of fuel going into the furnace; we only care that, for a given fuel master demand, we get

the same amount every time. There will be process variation, of course, but the goal is

to tune the controls to keep that variation as small as possible and then tune for

accuracy.

Boiler control processes are where I will begin. Additional control functions outside the

furnace will be explored in Part II in a future issue of POWER.

Operator ControlsThe operator’s window into the control system is referred to as a master or as a

hand/auto station, control station, or operator station. The station is the operator

interface to a given control loop and is typically a switch located on the control panel in

older plants or accessible from the operator’s keyboard in those equipped with all-digital

controls. Typically, the control station allows the operator to move between manual and

automatic modes of operation. All of the control loops discussed in this article combine

to form the set of controls that manage the key boiler operating functions.

When a control loop is placed in manual mode, the operator will have direct control of

the output. In automatic mode the output is modulated by the proportional-integral-

derivative (PID) controller. In automatic mode the operator usually has some control

over the set point or operating point of the process, either directly or through the use of

a bias signal. Occasionally, as in primary airflow control, the set point is displayed either

on the controller located on the control panel or on the computer screen graphic display.

Cascade mode is a subset of the automatic mode in which the operator turns over

control of the set point to the master, whose internal logic generates the set point.

Usually, there is some digital logic that requires the station to be interlocked to manual,

as well as control output tracking and set point tracking.

Furnace Pressure ControlFurnace pressure control is a fairly simple loop, but it’s also one that has important

safety implications. The National Fire Protection Association (NFPA) codes, such as

NFPA 85: Boiler and Combustion Systems Hazards Code, are dedicated to fire and

furnace explosion and implosion protection. Before you begin tuning a boiler, you must

read and understand the NFPA codes that apply to your boiler.

Balanced draft boilers use induced draft (ID) fans and/or their inlet dampers to control

boiler furnace pressure. The typical control system has one controller that compares the

difference between the furnace pressure and the furnace pressure set point that uses a

feedforward signal usually based on forced draft (FD) fan master output. The output

from the controller typically is fed through an ID fan master control station. Smaller units

may have a single ID fan, but larger units usually have two or more ID fans. The most I

have seen is eight ID fans for a single unit. In this case, the output from the control loop

or master is distributed to the individual fan control stations.

The NFPA also requires some additional logic for the furnace pressure control loop to

ensure adequate operating safety margins. There should be high and low furnace

pressure logic to block the ID fan from increasing or decreasing speed, as is

appropriate. For example, because this fan sucks flue gas out of the furnace, on a high

furnace pressure signal the fan should be blocked from decreasing speed and on a low

furnace pressure signal it should be blocked from increasing speed. On a very negative

furnace pressure signal, there should be an override that closes the ID inlet damper or

decreases ID fan speed. The settings of these signals are determined by the boiler and

fan supplier during the design of the plant.

Also, on a main fuel trip (MFT) there should be MFT kicker logic. An MFT occurs when

the burner management system detects a dangerous condition and shuts down the

boiler by securing the fuel per NFPA and boiler manufacturer requirements. When fuel

is removed, the flame within the furnace collapses violently, which can cause a lot of

wear and tear on the boiler and related boiler equipment. It also presents the very real

danger of an implosion. The MFT kicker should immediately reduce the control output to

the fan(s) proportional to the load being carried at the time of the MFT and then release

the device back to normal operation.

I am constantly amazed at how well furnace pressure can be controlled, especially

when you consider the amount of fuel and air being injected into a ball of fire many

stories tall and the ferocious and chaotic environment inside a boiler. The fact that a

well-tuned system can maintain furnace pressure to – 0.5 inches H2O is remarkable.

A typical mistake made by boilers tuners is the use of very fast integral action to the

furnace pressure controller. Furnace pressure changes quickly, but not instantaneously,

so consider the size of your furnace and the amount of duct work between the furnace

and the fans as capacitance in the system, because air is compressible. I recommend

restraint when tuning furnace pressure when it comes to adding integral gain.

Interestingly, the feedforward for almost every boiler is on the order of 0% to 100% in,

and 0% to 80% out.

The trends in the following figures show what you should expect to see from your

furnace pressure control. The plant from which these data were taken uses both fan

inlet damper position and fan speed to control furnace pressure. Figure 1 illustrates an

ID fan tuning trend and the reaction of the ID fans and the furnace pressure to a change

in set point.

1.    Blowing hot air. Induced draft fans are used to control furnace pressure and

primary combustion airflow. In this test, induced draft fan and furnace pressure respond

to a step increase in furnace pressure set point. Source: Tim Leopold

Airflow and Oxygen TrimForced draft fans are typically placed in automatic after the ID fan master is placed in

automatic. Usually, the FD fan master is only controlling airflow; however, some boilers

are designed with secondary airflow dampers that control the airflow. In this case the

FD fan will control the secondary air duct pressure to the dampers (Figure 2).

2.    Favorite trend. I typically monitor airflow, O2 content in the flue gas, and furnace

pressure control when I tune airflow. The particular response of those variables was

observed after a 20% load increase in coordinated control mode. Source: Tim Leopold

Air and, consequently, O2 control are critical to the safe and efficient operation of a

boiler. The airflow signal is normally measured in terms of a percentage and is usually

not available in volumetric or mass flow units. The obvious question is, "Percentage of

what?" The answer is the percentage of airflow that is available from a given fan or

system of fans. The actual measured pounds per hour of air does not matter, because

air is free, and the final arbiter of proper airflow is the O2 content in the flue gas (gases

leaving the furnace). Because of variations in coal heat content, air temperature, and

combustion conditions inside a boiler, we ensure proper burning by measuring the

amount of oxygen content in the flue gas, commonly referred to simply as O2.

Pulverized coal has an interesting property: Under certain conditions of heat in a low-

oxygen atmosphere, coal can self-ignite or even explode. Therefore, personnel safety

and equipment protection require boiler operators to maintain excess O2 in the flue gas.

The amount of excess O2 is determined by the load on the plant and the type and

design of boiler. Typically, the load signal used is steam flow. In any coal-fired boiler,

airflow demand is a function of the boiler firing rate or boiler demand (Figure 3). Gas-

and oil-fired boilers have lower O2 requirements at higher loads.

3.    Extra air is a good thing. A typical O2 set point curve for a coal-fired plant is a

function of boiler firing rate or boiler demand. Minimum levels of air are required so that

reducing conditions in the furnace never occur. Source: Tim Leopold

The term cross-limiting refers to the function of fuel flow that limits the decrease in air

demand and the function of airflow that limits the increase in fuel demand. When

decreasing load, the air demand follows its lag function and the fuel demand follows the

boiler demand to ensure that there is always more air than fuel going into a furnace so

explosive conditions never develop inside the furnace. When increasing load, the

opposite is true. This is truly an elegant piece of logic.

The output from the boiler master is the boiler demand. Cross-limited air demand is

developed by choosing the highest of four calculated values: boiler demand function,

the lag of the boiler demand signal, a minimum value (per the boiler manufacturer under

the NFPA codes), and a function of the actual fuel flow. The cross-limited fuel demand

is selected from the least of three signals: boiler demand function, a lag of boiler

demand, and a function of actual airflow. When load is increased, air demand follows

the function of the boiler demand and the fuel demand follows its lag of the boiler

demand.

To develop the air demand for your boiler, hold your O2 trim controller in manual at 50%

output. At a low, medium, and high load, place your FD fan master, or secondary airflow

dampers (if the boiler is so equipped), and your fuel master in manual. Then manipulate

the airflow until you find the amount that satisfies your O2 set point requirement, using

stack opacity as a reality check on the O2 set point. Next, manipulate the airflow

characterization curve as required to allow the air demand to equal or slightly exceed

the fuel flow or boiler demand. Record the airflow required for that fuel flow and then

move on to another fuel flow setting. Three points should be sufficient for a good airflow

curve.

Typically, the airflow measurement is a differential pressure taken in air ductwork and

requires a square root in order to make it linear. Ensure that your signal is also

temperature-compensated. Each boiler should have an airflow characterization curve

that should be a virtual straight line. If it isn’t, I would be concerned about unexplained

"correction factors" or "magic numbers" that should not be necessary.

Next, the characterized airflow is multiplied against a function of the O2 trim controller.

The O2 trim control loop uses the set point curve, discussed above, plus an operator

bias to calculate an O2 set point for various loads. This set point is compared with the O2

content of the flue gas used by the control system. It is best to have several O2

measurements because of striations or variations of temperature and oxygen that are

present across the stack cross-section.

Different plants use different measurement schemes, selecting the average, the

median, or the lowest measurement to control. O2 trim is designed to be a steady state

trim of the airflow. If you, or your tuner, are trying to control airflow with the trim

controller, stop it. The O2 trim controller should be mostly integral action with very little

proportional and no derivative gain. Your time is better spent reworking your air demand

curves or airflow characterization than attempting to tune the airflow using the O2

controls.

The output from the O2 trim control station then goes through a function generator such

that a 0% to 100% input signal equals a 0.8 to 1.2 output signal. This value is then

multiplied against the characterized airflow. This means that the O2 trim controller can

adjust the airflow ±20%. In some extreme cases this amount can be varied, but for most

boilers ±20% is more than sufficient. The final result is a signal referred to as "O2

trimmed airflow." This value is then used by the airflow controller to modulate the ID

fans or dampers.

Because O2 trim control uses a primarily integral-only controller, it does not have the

dynamic capabilities of most controllers. As a result, there are times when the controller

should not be allowed the full range of control. At low loads, typically less than 30% to

35%, output from the O2 trim controller should not be allowed to go below 50% but

should be limited to some minimum setting so that an air-rich atmosphere is always

maintained in the furnace.

Also, when the lag function in the cross-limited air demand is driving air demand, airflow

will lag behind. That is, the air will remain elevated for a period of time as the load, and

the fuel flow, decreases. As a result, oxygen in the flue gas will spike up. If the O2 trim

controller is not limited, the controls would see the O2 go higher than the set point and

start cranking, cranking, cranking down. Then, when the load gets to where the

operators have set it and the fuel flow is no longer decreasing, airflow demand will catch

up with the boiler demand, and the O2 will quickly begin to fall. The controller will see the

O 2 falling and begin to crank up. But because there is very little, or no, proportional

gain, it will take a long time to bring the air back. This can result in an unsafe or, at the

least, a nerve-wracking condition.

The NFPA requires some additional logic for the airflow control loop. There should be

high and low furnace pressure logic to block the airflow from increasing or decreasing,

as is appropriate. Because this fan forces air into the furnace, on high furnace pressure,

the fan should be blocked from increasing speed; on a low furnace pressure signal, it

should be blocked from decreasing.

Also, on an MFT there are NFPA and boiler manufacturer requirements that must be

considered. One important consideration is the need to hold the air in place for a time

after an MFT or if the airflow should drop very low during or just after a trip. The

dampers should go to a full open position shortly after the loss of all FD or ID fans

(providing a natural draft air path). Moreover, in the typical boiler air control system, if

the ID fan is placed in manual, then the FD fan is normally forced to manual. If the FD

fan is in manual, then O2 trim is forced to manual.

Drum Level and Feedwater ControlFeedwater is fed into the drum in a typical subcritical pulverized coal – fired drum boiler

via either a series of valves in parallel with a series of constant-pressure feedwater

pumps or a battery of variable-speed feedwater pumps. If the feedwater level in the

drum goes too high, water can become entrained in the steam going to the turbine and

can cause catastrophic results. If the drum feedwater level goes too low, the drum itself

can become overheated, possibly resulting in catastrophe.

Feedwater (and drum level) control has two modes of automatic operation: single- and

three-element control. The drum level set point for both modes is set by the operator. In

single-element control the difference between the drum level and the drum level set

point provides the error signal that is used by the single-element controller to control the

rate of water entering the drum by modulating the feedwater flow control valve. Three-

element control governs the three variables, or elements, that are used in this control

scheme: drum level, steam flow, and feedwater flow.

Drum level control uses a cascaded controller scheme consisting of an outer and an

inner controller. Steam flow is an indication of the rate at which water is being removed

from the drum. A function of steam flow is used as a feedforward to the outer controller.

The drum level error is then operated on by the outer controller. The output of this

controller is the feedwater flow set point. The difference between this set point and the

feedwater flow is then operated on by the inner controller. The output from this

controller is then used to modulate the feedwater flow control valve.

Three-element control is much more stable and robust than single-element control. The

reason that we use single-element control at all has to do with the nature of the

instrumentation. Typically, feedwater flow, and occasionally steam flow, is developed by

using a flow-measuring device like an orifice plate or a flow nozzle, where flow rate is

proportional to differential pressure. However, a problem occurs at low flow rates (low

boiler load), where differential pressures are not as solidly proportional as we would like

and therefore untrustworthy for boiler control. Consequently, single-element control is

used at low loads.

A well-tuned drum level control can be placed in automatic as soon as a pump is

started. By the time steam flow has passed 25% of the total range, we can consider

steam flow signals to be reliable. That is a good point at which to switch to three-

element control.

There really is not much in the way of manual interlocks or control tracking when it

comes to the drum level loop. If the drum level signal or the feedwater flow valve control

output goes out of range, or no pump is running, this station is normally locked to

manual mode. That’s about it.

Normally, tuning for the single-element controller consists of big proportional and very

small integral gain settings. Tuning for the three-element controller has some additional

requirements. As in any cascaded loop, it is absolutely crucial that the inner controller

be tuned as tightly as time will allow. The inner controller, the feedwater controller in this

case, must have an integral action that is faster than that of the outer, or drum level,

controller (Figure 4). This is true for all cascade loops.

4.    Rapid responder. A typical coal-fire boiler with a properly tuned drum level control

will respond very quickly to a substantial load increase (top) or load decrease (bottom).

The dynamic response of other key variables in boiler drum level control system is also

illustrated. Source: Tim Leopold

You may notice that as the load decreases, the drum level sags downward, and as the

load increases, the drum level is slightly elevated. This means that the steam flow

feedforward is just a tad too strong. A minute adjustment to the feedforward signal can

add stability to the control loop (Figure 5).

5.    Small is big. A small increase in the feedforward signal added more stability to the

drum level controls. Only very small incremental changes in feedforward should be

made when tuning drum level controls. Source: Tim Leopold

Superheat Temperature ControlSuperheated steam temperature control is very straightforward. Normally, steam leaves

the drum and travels through a primary superheater(s) before entering the

desuperheater, where attemperating water is mixed with the steam to modulate its

temperature before it enters the next superheater section. After the steam passes

through that superheater, the outlet temperature is measured.

If the inlet temperature to the superheater is a measured variable, the preferred method

of control is a cascaded loop. In this case the outer controller uses the superheater

outlet temperature as the process variable. The output from the outer controller is the

inlet temperature set point. The output from the inner controller is spray water demand.

If the superheater outlet temperature is the only available measurement, then we are

forced to use a single-element control loop. In either case, it is important that the

controls are equipped with a feedforward signal.

A variety of signals can be used for the superheater temperature control feedforward.

Usually, the boiler demand is a good starting point for the feedforward because this

signal anticipates the measured temperature signals. My experience is that the boiler

demand usually has a well-defined relationship with the superheater temperature.

Other measured variables are available to supply the feedforward signal. Throttle

pressure is usually used in tandem with the throttle pressure set point as an indication

of over- or underfiring of the boiler, but throttle pressure is transient in nature. Airflow

versus fuel flow or steam flow may be used in the same way. The ratio of fuel flow to the

top mill versus the other mills is a good indicator of the changing dynamics in the boiler,

especially if the boiler is large and has many burner levels. In this case it is a good rule

of thumb to think of the top elevations as affecting temperature more than pressure, and

the lower elevations as affecting steam pressure more than temperature. Finally, the

reheater temperature control affects the superheater temperature to a greater or lesser

degree, depending on the type of boiler manufacturer and its method of control.

The feedforward signal development may include both static and dynamic functionality.

The static cases are basically a function of the variable that you are using. Dynamic

feedforward refers to a derivative kick based on the movement of the chosen variable.

For example, the ratio of airflow to steam flow might be used as an indicator of the

boiler’s movement up or down, and the feedforward then can be manipulated

accordingly.

Patience is a virtue when tuning these feedforwards, because steam temperature

processes may have long time constants.

Deaerator Level ControlIt is often possible to use a three- element controller for deaerator level control.

Whereas the drum level controls use drum level, steam flow, and feedwater flow, the

three-element controller for the deaerator uses deaerator level, feedwater flow, and

condensate flow.

It is usually not necessary to provide adaptive tuning for this control loop, but do add it if

possible.

Reheat Temperature ControlIt is an interesting fact that superheater spray adds to the efficiency of a unit but

reheater spray flow decreases the unit’s efficiency. Maximum boiler efficiency is always

the goal, so boiler manufacturers have developed alternative approaches to control

reheat steam temperature.

Babcock & Wilcox uses a gas recirculation fan to move flue gas from the outlet of the

boiler back into the furnace, either directly or through the secondary air wind box. More

recirculation yields higher furnace temperature and, therefore, higher steam

temperatures. Combustion Engineering, now Alstom Power, is famous for its tangential,

tilting burner design that can move the furnace fireball vertically to control steam

temperatures. Foster Wheeler boilers use a superheat/reheat gas bypass damper to

shunt flue gas to the appropriate gas pass ducts to control reheat temperature. Spray

valves are also used in each design, although the reheat temperature set point to the

spray valve controller is usually several degrees higher to keep the reheater spray to a

minimum.

The setup for the reheat temperature spray valve control is the same as that for the

superheat temperature control: two valves (modulating valve and block valve), an

attemperator or desuperheater, and a reheater section. However, reheat steam

temperature control is not normally a cascaded loop. Assuming that the primary method

of control (gas recirculating fan, tilting burners, or bypass damper) is operating, the

sprays are held in reserve. The operator-adjustable set point is used directly by the

primary control mechanism. A sliding bias is added to the set point before it is sent to

the spray controller. Usually, the spray set point is set higher than the primary reheat

temperature control set point before the sprays are enabled, to reduce the reheater

spray flow.

Part II will look at fuel flow control, pulverizer air control, and overall plant control

options such as boiler- and turbine-following modes and plant coordinated control.

--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 slated for publication in March.

.