When, how to improve energy efficiency through boiler tuning

Industrial plant engineers can achieve proper fuel, steam and air flow to improve energy efficiency through boiler tuning activities

By Tom Marsh January 30, 2024
Courtesy: Novaspect


Learning Objectives

  • Learn how to best optimize oxygen for efficiency and coordinate fuel and air tuning.
  • Understand boiler control final elements such as dampers and variable frequency drives, and how they work together in a modern boiler.
  • Review the effect of feedwater temperature on drum level control.


Boiler insights

  • Boiler tuning can be used to optimize operation and thermal efficiency in industrial steam systems.
  • Boiler tuning includes combustion setup (curve setting), optimized flue gas oxygen control, boiler loop tuning coordination and drum level control best practices.

Modern boiler control applications are inherently challenging. Trying to maximize combustion efficiency while adhering to the boiler manufacturer’s recommendations, along with NFPA and ASME codes and simultaneously satisfying emissions permit requirements via the U.S. Environmental Protection Agency, is practically a study in diametrically opposed methodologies.

Still, the most common way to carry heat through a plant is with steam, making it an integral aspect for plant manufacturing operations. So it is left to the boiler tuner to pull a rabbit out of a hat each year when the boiler gets it scheduled tuning. Let’s dive into some ways to approach the different issues commonly encountered with newer boiler/burner applications during scheduled tuning.

Figure 1: Air damper output curves without variable frequency drive. Courtesy: Novaspect

Figure 1: Air damper output curves without variable frequency drive. Courtesy: Novaspect

Air flow control/characterization

Gone are the simple days where a damper with a single speed fan controls air flow. Today’s modern boiler systems can have a variety of different air flow control devices and drives installed, including:

  • Fresh air damper: The first damper before the fan and flue gas recirculation (FGR) duct that regulates the amount of fresh air entering the process.

  • Fan inlet and outlet dampers: The dampers after the FGR combines before the windbox to help control airflow.

  • Boiler outlet damper: Often referred to as the stack damper, it properly directs water vapor and combustion gases out of the system.

  • FGR damper: Controls the recirculation of flue gases to lower nitrogen oxides (NOx) emissions.

  • Motor variable frequency drives (VFD): Motor speed controllers that automatically lower the motor speed when operating at lower loads to save energy.

Figure 2: Air damper output curves with variable frequency drive. Courtesy: Novaspect

Figure 2: Air damper output curves with variable frequency drive. Courtesy: Novaspect

Here are the steps of a normal air flow control tuning strategy:

  1. Use the boiler outlet damper to control the pressure, either just ahead of it in the boiler outlet or in the furnace. This pressure is the critical driver of flow through the FGR ducts making it critical for good NOx control.

  2. Position the FGR according to a curve based on the fuel flow. There are times when FGR flow is measured, then the curve gives the setpoint for the FGR flow controller.

  3. Then, group the other dampers and fan speed together, each with its own characterization curves to control air flow.

The critical tuning step for this is configuring the characterization of all the various air flow controlling dampers (usually three dampers and a motor speed). The best way to accomplish this is with the boiler offline while just running the fan. This gives the person tuning a chance to adjust each curve by simultaneously monitoring the air flow while stepping up the output of the flow controller in 5% or 10% increments.

Any proportional-integral-derivative control requires linearity to work throughout the control range and this is particularly critical in a boiler that will operate flows through the whole control range. With a VFD, the cost savings can come from opening the air dampers first and then ramping up the fan speed, but keeping the fan running as slow as possible.

Be aware: turning the fan too slow can lead to pulsations caused by the fan blades passing the fan scroll. Usually, 25-30 Hertz works as a minimum, but some boilers may require 40 Hertz or higher as a minimum. It really is a function of how the fan is designed, but pulsations in the outlet duct expansion joints will be an indicator the fan speed is too slow.

O2 control and boiler efficiency

Controlling the oxygen (O2) close to the setpoint is an essential element that leads to efficiency and cost savings, and the trick is getting the fuel and air controllers to operate in conjunction with each other. However, it is not as simple as characterizing the outputs and giving both loops the same gain and reset.

The key really lies in the different dynamics of the two flow controllers. Fuel flows, whether liquid or gas, tend to be very close to the controlling valve so they can operate rather quickly. Air flow ducts are sized for low velocities and pressure drop to prevent buying a bigger fan than necessary. So, the feedback dynamics between the two loops can be quite different.

Ensuring that the closed loop response time between the air and fuel controllers match is critical to the efficient tuning of the boiler. This can be done with boiler master step changes and calculating the response time back to setpoint in a trend for each controller. Or a more advanced tuning scheme can be used that predicts closed loop response time like some auto tuners or the lambda tuning method. Either way, when a step change is made in load, the fuel and air should arrive at the new setpoint at the same time and the O2 should stay right on the setpoint curve as the transition takes place.

The largest loss in the sum of losses method of efficiency calculation is the dry flue gas loss (the heat that is going up the stack). As the air comes in at an ambient temperature it is heated up several hundred degrees and goes up the stack, carrying the unburned oxygen and 78% nitrogen with it.

Determining the normal operating range of the boiler and improving O2 at that point could lead to significant savings. A general rule of thumb is that for every 1% you save in flue gas O2 will save you 0.5% in efficiency. The savings can be significantly greater when going from 5%-4% O2, than from 3%-2% O2.

Depending on how good the O2 control is and how your air and fuel flow controllers are characterized and tuned, the result may not be lowering the O2 throughout the entire control range as that may adversely affect carbon monoxide or NOx at high loads. Many plants operate multiple boilers at a 40%-60% load range with the hopes that if one trips the others can make up for the load loss, but this is typically below the O2 design point from the manufacturer’s O2 curve. If testing and tuning can be done in the normal 40%-60% operating range, a 1% or even 2% O2 reduction is possible. The key to this is better air and fuel flow control allowing the O2 to always stay on setpoint.

One final warning for taking O2 readings: It is critical to close off the O2 calibration port during normal operation because any leaks in the calibration lines or from the valves on the calibration tanks can cause erroneous readings, which can be dangerous. It is always important to ensure that O2 calibration lines have no leaks and that all valves are closed when a boiler is operating.

Figure 3: Oxygen (O2) curve adjustments to maximize efficiency. Courtesy: Novaspect

Figure 3: Oxygen (O2) curve adjustments to maximize efficiency. Courtesy: Novaspect

Drum level control in boilers

Effective drum level control is critical to the safe operation of the boiler and the widely recommended three-element drum level control has been the standard for decades. Controlling the water/vapor interface can be fickle and is often fraught with challenges.

However, another common problem has surfaced in recent years with the deaerator temperature. The deaerator is the tank that mixes feedwater with steam before it goes to the boiler to remove the noncondensable gases. The deaerator’s ability to heat the water is essential for drum level control. Recent trends like flue gas condensable heaters and dumping trap discharge directly to the deaerator has caused plants to operate the deaerator at a lower pressure.

Historically, the deaerator operated at 15 psig with the feedwater temperature at 250°F, but now many are operating at 5 psig and are lucky to get feedwater to 225°F. The issue involves the feedwater initiated shrink/swell affect, where the drum level is going down, so you raise the feedwater flow, but the cold feedwater comes in and collapses the steam bubbles, which results in a decrease in level. This is a classic inverse acting loop where the effect gets drastically worse when the feedwater temperature is lowered.

There are some shrink/swell compensator circuits that can be added to the three-element drum level control and derivative can be used for offsetting some of the lag in the loop, but lower feedwater temperatures make this less effective. Boilers can change load just as fast as drum level will let it and by doing things that compromise drum level control (like using lower deaerator pressure), which only impede the ability to safely react to load changes.

Boiler header pressure control

Plants will often have a pressure controller per boiler and the operator will assign each of them different setpoints so that one ramps up to full first and then the second one comes off minimum and starts to control pressure. This works, but by controlling all the load swings with one boiler, it increases the chances of that boiler tripping. It is better to have a coordinated plant master that sends the demand to each boiler and allows all boilers to operate together to control swings.

Like a three-element drum level control, the coordinated plant master is a common standard that should be easy to implement for any control system. Even with boilers that have their own standalone control system, they will have a “remove” mode to accept a signal from a remote source, which can be a good upgrade as it only takes a few input/output per boiler to configure this control.

An important fact to consider about plant master and drum level is that they often interfere with each other because they are both integrating processes with similar time constraints — i.e., one will start to swing and then the other will as well, especially if the integral times are too tight. Like with air and fuel, the best way to combat this is to use a tuning method to determine their close loop response time. This can help you gain some separation from the interference through separating response time.

Figure 4: Determining lag time from the process variable measurement (e.g., pressure, temperature, flow, pH, speed, etc.) change in direction. Courtesy: Novaspect

Figure 4: Determining lag time from the process variable measurement (e.g., pressure, temperature, flow, pH, speed, etc.) change in direction. Courtesy: Novaspect

Another approach is to use a little derivative on the plant master. Many times, this will break that interaction and stabilize the entire process. To pick the derivative time, use a manual bump test to make the pressure first go down and then go back up. From the trend, take the difference from the time when the pressure starts to change its upward direction and the time when it has completely leveled out in the new direction. This should be the lag time and it is first order. If you divide that time by four, it should give you a good derivative time (shown as tau, or time, in Figure 4).

Achieving proper boiler system control and optimal thermal efficiency through tried and tested tuning methods requires a delicate balance between science and art amid myriad constraints facing industrial manufacturing plants.

Author Bio: Tom Marsh is an Application Engineer at Novaspect.