The good news for Canadians hoping to use forest biomass for heat is that proven technology is readily available at just about any scale, from wood-burning stoves to the largest commercial plant. The fibre supply and boiler still need to be carefully matched, and supply logistics analyzed in detail, but you shouldn’t have to gamble with your capital investment.
|Largely because of Canadian staffing regulations, small-scale co-gen plants like this 4.1 MW system at Vaagen Bros. Lumber in Washington State are the exception here rather than the rule. The norm is for plants of 10 MW and beyond.|
A grate furnace includes a conveyor to feed the biomass on a controlled basis to a combustion chamber where a grate holds the fuel being burned. There are several different types of grates, including fixed or stationary, moving or stepping, and vibrating grates, but the basic premise is the same: The biomass is moved along the combustion “bed” so that by the time it exits the furnace the biomass has all been burnt and nothing but ash remains.
This proven approach generally allows for a 60 to 80% thermal efficiency and has several benefits:
• It allows a wide range of project sizes, from below 1 MW (th) to 250 MW (th). In fact the largest biomass plant in North America is a grate furnace: EPCOR Power’s 66 MWe generating station in Williams Lake, BC. In contrast, the 1.1 MW CHP system at Taylor Lumber featured in the last issue of Canadian Biomass is also a grate furnace.
• Relatively low capital cost. These are likely the lowest cost among the industrial or commercial furnaces, and thus will be seen at some of the smaller installations like greenhouses or sawmills, where capital cost is a major factor.
• Low dust loading, as they run with a low quantity of air (blowing air into the system for combustion creates dust).
• Widespread availability from commercial suppliers, including several in Canada.
Still, the design is not without drawbacks. Depending on the application, grate furnaces:
• Can result in poor mixing of the fuel, especially when co-firing (i.e. sludge in pulp mills, coal in other applications).
• Can experience problems with high moisture levels. This technology can accept some variation in fuel, but it should generally be 40% MC or less. It should also be over 5% MC, so that some systems do not burn too hot, possibly overheating and damaging the grate material. Ash can also melt if the fuel burns too hot, becoming attached to the grates, jamming them up.
• Can have problems with rocks and metal pieces, which drop in and jam up the moving grates.
• Can have higher emissions at lower loads: When you have a very low fire during low demand, the mixing efficiency is lower and you’ll get smoking. Greenhouses can get around this to some extent by using large hot water storage tanks, heating the water in the night, and then using it during the day to heat the greenhouses while the furnace is shut down rather than left idling.
|Since moisture content dramatically effects boiler efficiency, as well as haul costs, buying dry biomass, or paying for energy content may be worth looking into.|
Operators also need to buy a unit designed for the fuel you’re going to burn – coal burns differently than wood, which burns differently than agricultural residues. If you do want to burn a wide range of fuel types and quality, and have the scale to justify a larger investment, you may consider a fluidized bed.
This system’s forte is dealing with two or three different fuel sources at once. Consider the current and future fuel sources carefully when choosing a technology. If your supply may change, if you require mixed supplies to meet your volume demands at times, or if you may be forced to accept varying qualities of fuels in a sellers’ market, consider that fluidized beds are very efficient with mixed fuel supplies.
Fluidized beds are typically cylinders (or square units at the larger scales) that are filled with sand to a small portion of their height (three feet of a 20-ft high cylinder like those used at CanmetENERGY’s Ottawa labs). The bottom is perforated with holes slightly smaller than the sand (so you don’t lose your sand of course), through which air is blown upward at just the right velocity to suspend the sand much like the numbered balls in a lottery draw. When various fuel types are added, they are thus mixed very well during combustion.
Aside from the ability to mix fuels, fluidized beds handle wet fuels better. Since the moving sand particles are all pre-heated to about 800 degrees, their motion through the incoming fuel will serve to mix, heat, and effectively combust even wet fuels like sludge. In comparison, wet fuel added to a grate furnace will typically sit there as a lump. That same bucket of sludge in a fluidized bed will be mixed and treated to a much higher heat transfer rate.
The technology also offers good NOx reduction and a very high efficiency, typically between 75 and 85% thermal efficiency. But there are tradeoffs, such as:
- Fluidized beds are very expensive compared to grate furnaces of the same capacity.
- They are not widely available at smaller scales, and are not yet cost efficient below 10 MW (th). Not coincidently, the largest biomass plant in the world, Alholmens Kraft’s 550 MW (th) plant in Finland, is a fluidized bed burning a mix of biomass, peat and coal.
- Higher power consumption to keep it running, as you will need a compressor to blow the air through the sand.
- Some sizing of the fuel is required.
- More training required than a grate furnace.
Yet even though direct combustion technologies like the above are proven, there are still some inherent challenges to using biomass. For starters, biomass other than special cases such as planer mill residues is typically wet. Biomass also contains less energy by weight than almost any other type of fuel currently used. This in turn creates significant challenges for transport, storage, handling, and more. Even when bone dry, wood typically has half the energy content of coal by weight and one third that of natural gas. On top of that, wood’s fuel density is very low compared to coal (although higher than straw).
Combine half the energy content with five or six times the bulk and up to 60% MC in fresh biomass, and you’re moving a lot of air and water with your energy. As a result, cost effective haul distances for fresh biomass will likely be well shy of 200 km, limiting the size of plant that can be built in any one location. Storage and handling systems will also need to be larger than those for conventional fuels. Here are some factors to consider:
- Do what you can to get dry biomass or dry it prior to combustion. Boiler efficiency falls dramatically as moisture content increases, from say over 80% at bone dry to under 60% at over 55% MC. You’re also paying to haul that water, so it may be well worth paying more for drier supplies. Consider sampling loads and paying on a bone dry content, since it’s what you pay per gigajoule that really counts.
- Carefully consider the transport, handling, drying, and comminution stages during your initial biomass planning stages. Effective logistics are the hallmark of successful bioenergy projects; inefficient transport and handling systems can kill even the best plant designs fed with the cheapest fuels.
- Consider densification closer to the biomass source as an option if you need larger volumes, and thus a larger draw area for your biomass. Pelletizing is an option, as it will convert raw biomass that is awkward to handle and ranges from 50 to 300 kg/m3 and up to 50% MC into a uniform feed stock at 600 to 650 kg/m3 and less than 10% MC.
- Consider the cost of that “cheaper” fuel. If you opt for demolition waste with contaminants such as pieces of drywall or use locally available agricultural residues, realize you will be dealing with more ash. Whitewood is typically less than 0.5% ash by weight, while bark is 2 to 3%, some straws are up in the 5 to 10% ash, and manure can reach 30 to 40% ash. Some of that ash may have a lot of potassium, and so will melt at a much lower temperature, causing clinkering and fouling (plugging) problems. In biomass, as in most things, you usually get what you pay for.
There is no shortage of cost effective biomass-based power generation options for the Canadian entrepreneur, but how successful you’ll be may well depend on the scale of your operation. At 10 MWe or above, operators have many proven options to choose from.
|Raw biomass is a non-uniform, often wet material that is hard to store and handle. Pellets offer a possible, more uniform and predictable fuel source.|
There are several prototype systems being tested both here and in Europe for small scale power generation that could get around the high-pressure issue, such as low temperature/ alternate fluid cycles, Organic Rankine Cycle, Brayton Cycle, Stirling engines and more. Yet to date none of these options provides power at an affordable price once capital costs per kW are considered. Research is ongoing.
If straight combustion options are commercially available, choices get much more limited as we move to other biomass options like gasification and pyrolysis. These two options vary the amount of air allowed into the system during conversion. Gasification uses partial air exposure (one third the air needed for combustion) to convert biomass to fuel gases (CO + H2, or carbon monoxide and hydrogen) that can be burned in engines for small scale power generation and/or further refined into fuels and chemicals. The technology is available to create this “syngas” efficiently today, but more work needs to be done to further clean it at a commercial scale so that it can be used in conventional diesel generators. As a result, gasification is a very active research field. For now, those doing it, such as in Europe, are generating power at an uncompetitive 20 cents per kilowatt hour or more.
The next step is exponentially harder – cleaning the gas even beyond the purity required for an engine so that this syngas can be converted to a liquid fuel. If you take the carbon monoxide and hydrogen from the gasifier and put it into a reactor with a catalyst, you can make liquid fuels like ethanol or diesel, etc. There is a lot of interest in this, but this level of cleanliness is a long way from where we are now on the commercial scale. Current commercial operations are burning the gas right away for heat, which does not require advanced cleaning.
Pyrolysis for its part is the process of making organic liquid fuel called “bio-oil” and/or charcoal by exposing biomass to temperatures in excess of 350 degrees Celsius in the complete absence of oxygen. It effectively increases fuel density to beyond the 1,200 kg/m3 range, or double the density of wood pellets, making transport and handling more efficient. But it is important to remember that this is not oil, but rather a mixture of chemicals that includes aldehydes, ketones, esters and specialty chemicals. As far as burning this directly as a fuel, it requires special handling as it is corrosive, demands modified burner nozzles, and tends to polymerize, or turn to a solid at high heat.
There is significant potential in this black liquid, from fuel upgrading to perhaps pharmaceutical or consumer chemicals, but a lot of work remains to be done to extract those chemicals on a commercial scale. Other issues to be resolved include heat transfer and scale-up for the fast pyrolysis oil plants (not an issue for the charcoal slow pyrolysis technologies). Few fast pyrolysis plants (bio-oil) seem to be able to run above 100 tpd, which is very small by conventional fuel standards.
At the end of the day, for a ground-ready commercial project, you can look at straight combustion for heat at any scale or co-gen or power generation for the most part at scales approaching 10 MWe. The rest of these emerging technologies are still very much in the development or pre-commercial stage, and would fall into the old “buyer beware” category.