Post on 19-Jan-2016
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.
.