Boiler-Tuning Basics, Part I 03/01/2009 | Tim Leopold

PRINT MODE : OFF

PAGES:

1

2

3

4

5

6

26 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, Ive 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.

javascript:void(0)javascript:void(0)javascript:void(0)javascript:void(0)javascript:void(0)javascript:void(0)javascript:void(0)http://www.powermag.com/

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 Controls

The operators 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 operators 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 Control

Furnace pressure control is a fairly simple loop, but its 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 Trim

Forced 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 O2requirements 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

isnt, 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 Control

Feedwater 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. Thats 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 Control

Superheated 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 boilers 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 Control

It 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 Control

It is an interesting fact that superheater spray adds to the efficiency of a unit but reheater spray flow

decreases the units 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 Cant Tuna Fish is slated for publication in March

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

quickly answer an operators 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 operators 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 operators 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 DCSs 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 Options

Boiler 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.

http://www.powermag.com/'+String.fromCharCode(116,105,109,46,108,101,111,112,111,108,100,64,104,111,116,109,97,105,108,46,99,111,109)+'?%27

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 operators 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).

SIRTRUNGHighlightSIRTRUNGHighlight

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, dont add to an upset; that is, dont 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.

SIRTRUNGHighlightSIRTRUNGHighlightSIRTRUNGHighlight

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 isnt 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, its 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 Mode

Coordinated 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 its 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 boilers thermal capacitance when the plants 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 Response

Unit 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, its 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 Magic

The tuning process cant 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 Rundowns

The 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 thats 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

SIRTRUNGHighlightSIRTRUNGHighlightSIRTRUNGHighlight

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.

SIRTRUNGHighlight

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, its 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 Enough

One of the big challenges faced by a boiler and turbine controls tuner is to know when to stop. Its 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 Ive worked on over the

years. Or, in the words of Supreme Court Justice Potter Stewart, "I know it when I see it."

Boiler-Tuning Basics, Part IWhat Constitutes Good Control?Operator ControlsFurnace Pressure ControlAirflow and Oxygen TrimDrum Level and Feedwater ControlSuperheat Temperature ControlDeaerator Level ControlReheat Temperature ControlBoiler Control OptionsCoordinated Control ModeTuning for Unit ResponsePractical Controls MagicRunbacks and RundownsWhen Enough Is Enough