Conquering Co-Combustion

While cofiring woody biomass with coal is more common on a testing scale than commercial, most issues related to co-combustion within the boiler can be alleviated with proper fuel sizing and blending.
By Lisa Gibson | August 23, 2011

With so few U.S. coal utilities cofiring woody biomass, the practice must be fraught with combustion-related problems, right? Not so. Fortunately, the co-combustion aspect itself, for most boilers, is surprisingly free of any detrimental issues that can’t be mitigated through proper material sizing and feedstock blending. That, however, requires a timely and often expensive trial-and-error process.

“Everyone wants to [cofire], but nobody wants to spend a lot of money,” says Bill Stirgwolt, manager of biomass engineering for boiler designer and manufacturer The Babcock & Wilcox Power Generation Group Inc.  Paper mills have for years, and in some cases decades, successfully fired bark with pulverized coal, he adds. “To do that, the boiler is designed with a grate and the course fuel is fed into the lower part of the furnace and burnt on a grate, and above it would be pulverized coal burners.”
But paper mills aren’t necessarily as concerned with efficiency as much as they are with generating steam for internal plant consumption. “The challenge is when you try to make it look like, or fire like, a pulverized coal,” he says. “Those folks are asking, ‘How can I get as much energy without compromising the combustion process or taking a hit on efficiency?’”

Cofiring is a simple-enough process, but Stirgwolt cautions, “If you want to cofire biomass, you can’t put blinders on.” 

Size and Blend Solution

“You have to get the fuel sized properly, and that’s not easy to do,” Stirgwolt says. “If you can make the particle size small, the biomass burns readily. If it’s not small, then you’re going to have combustion issues.”

The main problem with a biomass fuel that’s too big is the unburned carbon. The residence time for a pulverized coal furnace is short and does not provide for ample burning of larger biomass, Stirgwolt says. Under ideal circumstances, biomass devolatilizes and the fixed carbon burns out. “If you don’t have enough time for the fixed carbon to burn out, it will carry over to the convection pass, the air heaters or particulate capture device.” When hot, unburned carbon or char from oversized fuel enters an air heater precipitator or baghouse, it leaves disconcertingly high probabilities of fire, needing only a small leak that provides a source of air, Stirgwolt cautions. “If you want to fire biomass in a burner, it all comes down to size reduction.”

Perhaps just as important as fuel particle sizing is fuel blending. Without uniform size and quality, biomass material can cause bridging and plugging in the combustion process, specifically ground woody biomass, according to Gregg Coffin, superintendent of the University of Missouri in Columbia power plant. Such materials tend to create flow blockages, he adds. 

The university has four coal-fired stoker boilers that cofire up to a 15 percent blend of woody biomass. Coffin says problems have arisen mainly in biomass fuel procurement and blending, with little difficulty on the combustion end. “A good, clean wood chip product was sized very well to blend with our coal,” he says. “They burn well. We didn’t have any combustion issues, environmental issues or operational issues.”

The process for settling into the proper fuel size and blend for a specific boiler is, unfortunately, trial and error, both Coffin and Stirgwolt agree. One of the first problems the University of Missouri encountered was the lower density of woody biomass in comparison with coal. The plant uses a batch-style scale to measure the fuel—both coal and biomass—going into the furnace, he explains. “It is designed to know when it’s full by weight. So as soon as you start introducing a significant amount of wood chips at a much lower density and larger volume, they would overfill.” All that was required to fix the problem, however, was an adjustment to the scales and fuel feed.

So far, the best results for the university have come with a feedstock of mill residue from wood products manufacturing facilities, delivered in well-sized and uniform quality chips. The 66-megawatt combined-heat-and-power plant produces about 60 percent of the campus’s electricity needs and 100 percent of its steam requirements. With more than 14 million square feet of facilities including a research hospital, a Department of Veterans Affairs hospital and a veterinary hospital, that’s no small feat.

The school is replacing the plant’s aging fuel handling system, as well as a coal-fired boiler, and is taking that opportunity to install a 100 percent biomass boiler and associated fuel system, Coffin says. The bubbling fluidized bed boiler will burn primarily wood chips, initially about 90 percent coming from mill residue and 10 percent from tree tops and branches. The system will also use agricultural residues such as corncobs and some energy crops including switchgrass and miscanthus.

“With the new coal system and new biomass system, we’ll have a much better way to meter-blend the wood chips with coal for cofiring in the existing plant, as well as a nice conveyor system for the new boiler,” Coffin says.

 Coffin’s advice for conquering that trial-and-error headache is to first identify the fuel source and size for the furnace, and then start slowly with small blends, incrementally increasing until the first challenges arise. “Then you either correct those challenges or you back off to where you find where the appropriate blend ratio is for your plant.”

Moisture and Ash

The proper fuel blend can also mitigate issues related to moisture content in the combustion process. Too much moisture in the wood can cause clumping, especially in pulverized coal burners, according to Tom Kimmerer, senior scientist at Moore Ventures LLC. To avoid that, he explains, pulverized coal boiler operators have three options: mixing wood and coal before pulverization, which is generally not a good idea; mixing after pulverization; or injecting the wood into a separate burner from the coal, which could be the best option. “These boilers have more than one burner,” Kimmerer says. “You can open up a port when you do the retrofitting that allows you to feed wood in separately from the coal and that appears to be the most effective way in a pulverized coal boiler.” The best long-term solution, he adds, is using torrefied wood, as it becomes coal-like and hydrophobic, but the material still comes at a high price and finding a large enough supply to conduct adequate testing could present a challenge.

Moisture content is simpler to deal with in fluidized bed boilers than pulverized coal boilers, as fluidized bed boilers are not as susceptible to problems caused by clumping. Still, Stirgwolt says moisture is only an issue when cofiring large amounts of biomass.

“Moisture content can be a problem, but it really has to do with the fact that a lot of biomass material has more moisture than coal,” says Michael Goerndt, postdoctoral fellow in the University of Missouri’s Department of Forestry. The extent of the disruption moisture content causes depends heavily on, of course, how the material is stored, but also the type of material. Pellets, he says, have lower moisture content than chips, although it is harder to break pellets down smaller than their individual constituents.

But even with the use of wood chips, Coffin says the university hasn’t experienced the moisture problems it had anticipated, although the chips’ lower Btu value in comparison with coal’s, warranted some system adjustments. “You have to recognize that and adjust your air flow as well as understand the impact to your steam capacity,” he says.

Ash content in cofiring also proved to be a nonissue for the school, but it has a tendency to wreak havoc on heat transfer surface maintenance and cleaning, in some instances. “There are certain types of biomass that may want to slag, so it would create a drippy fouling in the furnace itself that can be difficult to clean,” Stirgwolt says, adding that additional cleaning devices in the furnace might be needed. In cooler regions of the boiler, dry ash could also deposit on the heat transfer surface requiring additional soot-blowing equipment or an increase in blowing frequency. No large difference exists between ash content of wood and that of coal, and, in fact, coal probably has more, Stirgwolt says. The trick is the nature of the ash once it’s fired. “Does it make a more difficult-to-clean combustion product?” 

Pondering Potential

Despite the easily mitigated boiler issues that may arise with the co-combustion of wood and coal, the potential for cofiring is enormous and hinges on several significant factors, Goerndt says. Infrastructure for biomass transportation is crucial and is one factor working in the University of Missouri’s favor. Goerndt also lists coal availability and price, as well as woody biomass resource availability. Electricity demand makes the list too, but is only marginally significant.

Not surprisingly, the implementation of state renewable portfolio standards is a major factor Goerndt and his colleagues are studying. The university’s School of Natural Resources has conducted a cofiring potential study for 20 states in the Northern region of the U.S., finding that 19 of those 20 had renewable standards as of 2010, giving them higher potential for cofiring. “It was a significant enough variable that we made a pretty fine point about it in our report,” he said, adding that the report is not yet released. “It means renewable portfolio standards are having a significant correlation with cofiring.”

Despite all the clear potential, woody biomass and coal cofiring remain primarily relegated to testing, and Stirgwolt attributes that to a lack of mandates and renewable energy credits. “Over the past two to three years, we’ve had a tremendous amount of inquiries about ‘How can I fire biomass in my existing pulverized coal-fired utility boiler?’” Stirgwolt says. “The key here is that a lot of people are investigating biomass cofiring with the thought that they were going to have to do something for renewable energy credits, but they’ve never moved forward with any of the studies.”

Goerndt and Coffin attribute the lack of a solid U.S. cofiring sector to cost, while Coffin also adds availability. “In our case, we were able to secure our biomass at a comparable price to coal,” Coffin says.

While Goerndt’s reasoning specifies biomass transportation costs, the university sees an advantage in no longer transporting coal from out of state. “Being a state-supported public university, it’s always in our best interest when we can spend our funds within the state,” Coffin emphasizes. “By using biomass in lieu of coal, we transferred a portion of our fuel budget from out-of-state coal expense to in-state biomass expense. That’s regional economic development.” As the university expands its use of biomass over the next few years, it will make a significant impact on the number of jobs in the region and reinvestment of those dollars back into Missouri.

Whatever the reason for minimal biomass/coal cofiring action in the U.S., it doesn’t seem to stem from boiler issues in the combustion process, as they can be easily tackled. “I’ve talked to a lot of people who are interested in cofiring and the first thing I tell them is after you identify your source and try to determine your sizing, your challenge is to figure out how best to get it blended [to avoid conveyance and boiler problems],” Coffin says.
Author: Lisa Gibson
Associate Editor Biomass Power & Thermal
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