Retrofitting Boilers for the Future

By Dan Wallace

Old boiler systems with outdated, inefficient equipment are the norm for our industry. This is because boiler technology is largely stable, and boilers are reliable pieces of equipment that can last decades. They are also expensive. This means that boilers are only infrequently replaced, and boiler replacement is often the only time that upgrading the rest of the system (burners, pumps, control systems) comes up for discussion.

However, the world is rapidly changing. Electrical costs continue to climb, petroleum and natural gas prices increase, and regulations on emissions continue to tighten. Many outdated boiler systems are, or soon will be, prohibitively expensive to run and out of compliance with state and federal regulations.

We will examine components of the boiler system that can be replaced without having to replace the boiler itself. In particular, we will present boiler retrofits that can increase efficiency and prepare the system for the future.

Upgrade to Parallel Positioning or Fully Metered System

When we evaluate burner systems for upgrade potential, one of the first things we look at is whether the system is using some sort of jackshaft linkage or single point positioning. This antiquated technology is surprisingly common, and presents a relatively straightforward and inexpensive retrofit opportunity. But there are some things to look for and keep in mind.

Fuel and air must enter the burner at specific ratios and rates, and the ratios vary with desired firing rates. This is because more excess air is required at low firing rates than at high firing rates. So fuel and airflow (and potentially other aspects of the system, such as recirculated flue gas) must be coupled in a way that is sensitive to the firing rate.

Jackshaft linkages solve this problem in a straightforward mechanical way. A single actuator controls the output of the system and is changed depending on the firing. This actuator is attached to a jackshaft, which is in turn attached to the fuel and air fan valves via linkage arms. Fuel and air flow ratios can then be configured at different firing rates by adjusting the length and angle of the linkage arms. As more and more components are tied into the jackshaft, the setup can become very complex and expensive.

There are two problems with these systems: configuration and maintenance. Correlating linkage arm length/angle to desired outputs is an extremely complex and manual task. A service manual may list specs for some common output parameters, but fine tuning things requires a highly skilled operator. And because adjusting one part of the system can potentially affect all others, the process is error prone and can take a long time. Because of these constraints, it is very common to set these systems for one scenario and then not update them — even when it’s known that under current conditions, a different configuration may be more efficient.

Additionally, because the components are made of metal and connected by bolts, the system drifts from the desired configuration over time. Bolts loosen, introducing slippage (or hysteresis) into the system. Hysteresis means inefficiency as incorrect amounts of fuel or air flow into the burner. It also can mean that the system is not operating within the desired specifications — this can be problematic for facilities operating under stringent emissions regulations.

Because of these two problems, burners using jackshaft linkages are generally not operating anywhere close to maximal efficiency. These systems are using far more fuel or electricity — and producing more emissions — than the burner requires for the given firing rate. Jackshaft linkages are one of the first things that should be replaced in facilities looking to retrofit for the future. What’s the alternative? Either a parallel positioning system or a fully metered system.

In a parallel positioning system, each burner component has its own actuator valve that is wired into a central control computer. The obvious benefit here is that configuration is straightforward — punch in the desired parameters into a computer interface — and there is no slippage to speak of. Burners can reliably operate at specified conditions, representing large efficiency gains.

O2 Trim & VFDs

One of the biggest sources of error in a combustion control system is variation in ambient temperature and humidity. The oxygen content of air changes with temperature and humidity. Recall that in a jackshaft linkage system, each firing rate is configured to deliver a particular volume or mass of air to the furnace. The upshot is that this may or may not be the optimal amount of oxygen, depending on temperature/humidity. To account for this, traditional systems must add large quantities of extra air to cover the full range of temperatures/humidities in which the burner operates. Because extra air means higher operating costs — by sending wasted heat out the stack — this is a big downside.

Parallel positioning helps by making it easy to add an O2 trim system. This means that O2 sensors can be added to monitor oxygen content in the furnace in real time. This feedback can then be used to change the fan actuator to correct the air flow. Good O2 trim on a parallel positioning system can significantly reduce the amount of excess air required. When paired with a good variable frequency fan drive (VFD), electrical costs can be drastically reduced — in some cases by as much as 85 percent.

Tradeoffs

The combination of easier configuration, reduced hysteresis, and O2 trim with VFDs adds up to greatly reduced operating costs and greatly improved operating precision. The cost of switching to a parallel positioning system can vary from $5,000 to $20,000+. Part of the decision for this retrofit will be balancing operating cost savings against this upfront investment. In the context of retrofitting for the future, consider tightening regulations and ever-increasing electrical expenses. From this perspective, anything that improves efficiency and reduces electrical consumption is a win.

When replacing outdated jackshaft linkage systems, the option of fully metered control systems offers an additional level of precision over parallel positioning systems. However, they are also much more costly and complicated to install. While a deep dive into fully metered systems is beyond the scope of this article, a good rule of thumb is that parallel positioning systems are the best choice for boilers up to 600 BHP. Beyond that, the advantages of a fully metered system start to outweigh the additional cost. A good design and engineering firm will be able to discuss the tradeoffs of a particular application.

NOx Emissions Control: Striking the Balance

Nitrogen oxides (NOx), and in particular nitrogen dioxide (NO2), are a harmful byproduct of combustion. They are one of the primary constituents of “smog” and are known to cause serious damage to human health once above a certain concentration. For this reason, they have been a big focus for federal and state regulatory agencies, especially since the 1990s. Stricter NOx standards began at the federal level through the EPA under the clean air act. Since then, there has been a steady trend of state and municipal agencies enacting stricter regulations on NOx emissions than formally required by the EPA.

“The elephant in the room is that moving to ultra-low NOx emissions inherently means lower combustion efficiency…”

There are many sources of NOx emissions. The most significant is heavy-duty trucks, and much of the NOx regulations focus on these emissions. But industrial boilers are another significant source, and most states regulate NOx emissions from these too, especially where heavy-duty trucks already meet stringent requirements but further air quality improvements are required. California has led the charge here, with many areas of the state now requiring that burner emissions have NOx concentrations of only 9 parts per million (ppm). Meanwhile, some areas, like New York City, don’t place any NOx emissions requirements on boilers. Many states fall in between, with more moderate NOx requirements between 20-30 ppm. Tracking these regulations starting in the 1990, the tightening trend is clear.

There are three primary ways a boiler can form NOx: prompt formation, thermal formation, and fuel formation. Prompt NOx contributes only negligibly to combustion emissions, so thermal and fuel NOx are the primary target. Thermal NOx is formed during combustion, and is a reaction between the oxygen required for combustion and the nitrogen that is present in the air. Fuel NOx is the result of nitrogen present in the fuel source that is freed during combustion. This is negligible in the case of natural gas, but can represent up to 50%-80% of the total NOx produced when burning coal or oil (which, by the way, is a great reason to upgrade older coal or fuel oil systems to natural gas).

We can expect NOx standards to become stricter over time, so retrofitting a boiler for the future should take this into account. The most straightforward strategy is to opt for an ultra-low NOx burner, capable of achieving ~9ppm NOx emissions (generally agreed to be the lowest practical level). These have been on the market for a number of years now, primarily to serve facilities in California and other areas with very stringent NOx regulations.

Since thermal NOx is highly dependent on combustion temperature and oxygen presence, reducing temperature and the presence of excess oxygen are the best ways to control it. Ultra-low NOx burners generally achieve this by either flue gas recirculation or a lean premix of fuel and air. Flue gas recirculators (FGR) use fans to recirculate exhaust back into the combustion chamber. Because flue gas is both cooler and has significantly reduced oxygen concentrations, this can dramatically reduce the concentration of NOx in emissions. Lean premix burners, on the other hand, premix the fuel and air at a very low (“lean”) ratio of fuel to air. This produces a very uniform, low flame temperature.

There are tradeoffs to both systems. FGR systems are typically more efficient than lean premix systems. A typical FGR burner operates at 2-3% O2, while a typical lean premix burner operates at 8-10% O2. This can translate to a boiler efficiency difference of 3-4% O2. Additionally, FGR burners can achieve excellent turndown rates. The flipside, though, is that these burners incur substantial electrical costs, because they have to power large flue gas fans. This can be a problem where electrical costs are high, or where a facility also has strict carbon commitments (using electricity creates a carbon debt).

Lean premix systems avoid these electrical costs, at the cost of some O2 efficiency. An additional benefit is that the underlying physics here is very well-understood, making predictable configuration fairly easy. One of the major downsides of lean premix systems is that their combustion heads are typically made of a fragile, metal mesh that is prone to clogging. Additionally, they generally use air filters that require frequent changing. This not only increases maintenance costs, but means that efficiency gradually decreases over time. Yet another negative is that these systems generally have poor turndown of around only 3:1.

The good news for facilities that can’t use FGR is that new lean premix systems are coming onto the market that address some of these problems. Look for lean premix burners that use solid metal heads and don’t require air filters. The best and most recent entrants to the market can achieve high turndown rates of 6- 9:1.

Switching to an ultra-low NOx burner will require other modifications to the system — many of these considerations are well-covered in a previous issue of Power Engineering. The elephant in the room is that moving to ultra-low NOx emissions inherently means lower combustion efficiency, and so higher operating costs (in addition to the electrical overhead of an FGR system). Remember, if we’re burning at a low temperature, we’re not using our fuel as efficiently as possible, and so more fuel is required to produce the same amount of heat.

When we talk about future proofing, we’re talking about being prepared for future NOx requirements that could be around 9ppm. But we also know that these requirements are typically enacted gradually. Switching to operating at 9 ppm NOx now for regulations that might not come into effect for 5 or 10 years means incurring a lot of unnecessary operating costs in the meantime. At the same time, many old burners need to be replaced — and if you’re going to replace one, shouldn’t you replace it with an ultra-low NOx model so that you’re not facing another replacement in a few years when regulations change?

The way out of this conundrum is the latest breed of low-NOx burners that offer configurable NOx emissions concentrations. These now exist in both FGR and lean premix forms. In the case of the FGR configurable burners, the amount of flue gas that gets recirculated is programmable over a wide range, and down to the lowest theoretically possible levels. In the case of the lean premix configurable burners, that fuel-to-air ratio is configurable, from super lean to very rich. These configurable systems are the best option for areas that don’t yet face the strictest NOx standards. By switching to one of these burners, NOx emissions can be set to exactly meet current NOx regulations, while maximizing efficiency. When and if these standards change in the future, the burner can be simply reconfigured to meet the new requirements.

Retrofitting for Biofuel: The New Frontier of Liquid Wood

Along with a trend towards lower NOx emissions, there is a trend toward lower carbon footprints and the use of renewable biofuels. Until recently, the only viable option for boilers was solid-mass biofuels — in particular, wood pellets or chips.

The wood for these fuels can be sustainably sourced from tree farms, and replanting the trees used to produce the fuel can mostly offset the carbon emitted from burning them. What has limited their widespread adoption, however, are the significant costs of switching to such a system. An entirely new boiler is generally required to enable burning solid chunks of fuel as opposed to burning liquid or gas. The solid biomass fuel will need to be burned over a grate or in a fluidized bed boiler, which is significantly different from a standard firetube or watertube boiler. Additionally, burning solid biomass produces much more ash, and the burner has to be equipped so that this can be regularly removed from the boiler. All of this means that switching to solid biomass fuels can easily exceed $20M in upfront investment. That type of investment is generally only made sense for institutions with very strict carbon or renewable commitments (for example, universities which adopted strict carbon commitments under the American College & University Presidents’ Climate Commitment).

However, it is now possible to retrofit for biofuel because liquid wood, (renewable fuel oil or bio-oil) has become viable for use in existing gas or oil boilers for the first time. Liquid wood is produced by heating wood in the absence of oxygen, in excess of 500º Celsius. Because there is no oxygen, the wood does not combust: it first becomes charcoal, and then further decomposes into gas and liquid. When heated above 700º C, pyrolysis occurs very quickly and the yield will be around 60% bio-oil, 20% char, and 20% “syngas.”

From the perspective of the boiler, this bio-oil is essentially the same as traditional fuel oils or natural gas. Burning the liquid wood efficiently and reliably however, is rather subtle: the liquid is highly corrosive, thermally unstable, and will easily polymerize if exposed to air. Accordingly, it requires tight temperature and pressure tolerances from the burner, along with pumps, piping, and storage tanks that are very corrosion resistant. The difficulty of engineering the burner and pump system, along with the lack of a reliable, cost-competitive source of liquid wood has–until recently–prevented the use of this bio-oil in boiler applications.

Though liquid wood has long been available on the market, commercially viable burners that can handle burning it have just arrived. These burners are compatible with a wide range of existing boilers, and represent a highly future-proof choice for retrofitting an existing boiler. The cost of such a retrofit is generally around 90 percent less than the wholesale replacement of a boiler for a solid biomass solution. It’s effective too: a college in Maine that recently made the switch reduced their carbon footprint by 83 percent in just one year.

This is new technology, and its applicability will depend on a facility’s prioritization of carbon footprint and sustainability and their ability to obtain liquid wood, which is now becoming increasingly available.

A Cleaner Future with Your Existing Boiler

When looking to retrofit for the future without having to replace your entire boiler system, one of the most inexpensive, and widely applicable retrofits is replacing jackshaft linkage with a modern parallel positioning system. Switching to a low-NOx burner with configurable NOx emissions prepares your system for tightening NOx regulations without incurring an unnecessary efficiency hit in the meantime. For the truly forward-looking, switching to bio-oil with a compatible burner and pump system can dramatically reduce your facility’s carbon footprint.

A good boiler can last many decades and because boiler technology is fairly mature, replacing one typically only makes sense when the boiler is at the end of its life. The technology surrounding the boiler, however, has changed radically over the last 10 years. In addition, emissions and efficiency requirements will continue to tighten for the foreseeable future. There has never been a better time to retrofit your existing boiler with these modern, forward-looking components. By future-proofing your boiler in this way, you can ensure that it remains in operation for its full lifespan — and significantly reduce operational costs in the process.

Author:

Dan Wallace is Vice President of Research & Development at Preferred Utilities Manufacturing Corp.