By Don Koza, PE, Principal Engineer and Shuang Ma, PE , Boiler Technical Specialist, Bechtel Power Corp. Specialist, Bechtel Power Corp.
Editor’s Note: This article is based on a paper given at POWER-GEN International in Orlando in December 2010. The paper was recognized as one of the best presented at the 2010 conference. This continues our occasional series of publishing the best papers presented at POWER-GEN International.
In the U.S. today, electricity from coal fired plants is hindered due to environmental issues especially CO2 emissions. Biomass, in its various forms, including clean wood waste, and agriculture crop residue is considered CO2 neutral in most jurisdictions and are acceptable as an alternative fuel by many state Renewable Energy Portfolio Standards.
This article discusses various options for biomass combustion, such as stoker/grate-fired boilers, suspension-fired boilers, fluidized bed boilers, including co-firing, identifying characteristics, applications and performance. This article also addresses issues and challenges in combustion technologies related to biomass fuel flexibility, fluctuation in properties and seasonal supply variability, integration of material handling system, wood pelletizing and emission control systems as well as operational constraints. Finally, the article will present examples from an EPC (engineering, procurement and construction) contractor perspective of how to implement innovative strategies that overcome technical challenges, reduce emissions and improve efficiency while achieving low capital and operating costs.
As demand for electricity continues to grow, developers of new power plants and owners of existing plants are increasingly considering firing and co-firing biomass as an acceptable alternative to coal. In many ways, firing biomass, however, can be more difficult than firing coal and requires careful due diligence. Sorting through the options of firing technology, compatible steam cycle conditions and metallurgy, as well as selection of appropriate material handling and air quality control systems best suited to fire the chosen biomass as fuel is easier when working with experienced major equipment suppliers and EPS contractors.
The term “biomass” refers to materials derived from growing or recently grown plant matter and can be generally classified using the following categories:
- Wood residues (forestry, pulp and paper)
- Agricultural residues (bagasse, stover, rice hulls)
- Dedicated energy crops (sawgrass, bamboo, eucalyptus)
- Process wastes (furniture manufacturing, construction and demolition).
These materials, grown using energy from sunlight, are usually considered sustainable when replanted to replenish the supply, although this replenishment may take a few decades when it comes to trees. Properly firing biomass as a replacement for coal not only reduces regulated emissions as well as CO2 emissions, but can be lower in cost and potentially decreases the amount of waste that must be landfilled. Unlike some other renewable sources of electric power, biomass firing can be available even when the wind doesn’t blow and the sun doesn’t shine.
Biomass does not store well and some types begin to badly decay within a matter of a few weeks. Agricultural waste material tends to be only seasonally available while forest harvesting products and waste (non-value trees, tree tops, and branches) are available year around. If a steady, reliable source of biomass is not readily available, a power plant may be forced to utilize “opportunity fuels.” Properties of such fuels may vary widely. Agricultural waste material may contain constituents from fertilizer that may be corrosive or cause fouling and slagging in the boiler. Construction and demolition wastes can contain contaminants that increase regulated and toxic emissions. It is critical the boiler designer understand the fuels that will be fired in the boiler for appropriate design.
Heating value of raw biomass is typically half that of the bituminous coal. This means more pounds of biomass must be fired to achieve the same heat input. Biomass has higher moisture which reduces boiler efficiency, again requiring more pounds of biomass to be fired. Biomass bulk density can be as little as 1/10 that of coal per unit heating value, thus requiring more storage space.
The moisture content of biomass is usually greater than 20 percent and can contain as much as 60 percent. Such high moisture biomass is allowed to dry or dewater before shipment to a power plant. Bamboo and other crops, for example, will lose 38 percent percent of their weight during a 15-day drying period standing in the field, dropping the overall moisture level to about 35 percent.
On a dry basis, biomass fuels have more volatiles and a greater hydrogen:carbon (H:C) ratio, making them more reactive than coals. This means biomass can be fired efficiently if sufficiently dry, however extra caution is necessary to avoid spontaneous combustion during handling and storage. Cellulose breaks down above 451 F, allowing the gases to burn and leaving behind char. Biomass char has more oxygen compared with coal and is more porous and reactive.
Unless from fertilized crops, most biomass has significantly lower nitrogen content than coal, which means the uncontrolled NOX emission levels tend to be lower than from coal. In general, biomass is low in inherent ash; however, when harvesting wood or other crops, “incidental ash” is often picked up: sand from dragging timber, dirt from roots and so on. Also, soil or coastal locations may cause plants to pick up alkalis, chlorine and so on that may cause corrosion in the boiler. Chlorine can be picked up from salt in the soil or by floating logs in salt water or growing crops in brackish water. Some biomass naturally has very high chlorine content (1 percent or more), particularly new, green growth. Where steam temperatures are high, chlorine concentration should be limited to 0.5 percent or even 0.1 percent by weight.
Biomass fuel ash is more alkaline which reduces ash fusion temperature which leads to superheater (radiant and convection surface) fouling and slagging. Biomass fuel can be high in chlorine, but is typically low in sulfur. Sulfur tends to moderate the affect of chlorine and a sulfur:chlorine ratio greater than 2.0 is generally desired. The combination of high chlorine, alkalis and some sulfur forms a low melting (often molten phase), highly corrosive eutectic that can reduce the life of superheaters to just a few years.
It is imperative that a laboratory analysis be obtained for every representative fuel source to account for local environmental and soil conditions rather than simply relying on a textbook analysis to identify constituents that may be detrimental to the boiler and may limit the amount that can be safely fired or co-fired. Biomass fuels are generally characterized by “proximate” and “ultimate” analyses per ASTM-E870.
Biomass Combustion Technologies
In the power generation industry, the most common biomass combustion technologies fall into three categories: stoker/grate firing, fluidized bed combustion (FBC)—including circulating fluidized bed (CFB) and bubbling fluidized bed (BFB) boilers—and suspension firing or pulverized fuel (PF) firing.
Stoker/Grate Firing: Grate-type boilers are likely the oldest commercial combustion technology still in use today. There are several types which have been enhanced through the years and are capable of firing biomass. In fact, grate-type boilers are among the most popular combustion technology for small to medium sized biomass-fired boilers and are available up to 150 MWe. Smaller, lower-cost bottom-supported units in the 15 to 25 MWe range are more common. Grate boilers are suitable for many types of fuels: coal, wood fuels, waste fuels, peat and even straw.
One common problem related to grate firing is melting of the biomass ash on the grate. Combustion temperatures may reach 1,300 to 1,400 C (2,400 to 2,600 F). Ash melting problems have been reduced or eliminated by using water-cooled grates and reducing combustion air preheat temperatures.
Firing or co-firing of biomass with coal, oil or gas in small power plants is relatively safe where the steam temperature is less than 400 C (750 F) and the risk of high temperature corrosion is reduced. Where final steam temperatures are higher, finishing superheater surface is installed at the top of the furnace as platens where the slag will drop off periodically.
Fluidized Bed Technology: Fluidized bed technology is the most flexible for firing a wide range of fuels and fuels that are variable, including biomass.
Adequate heat transfer surface is provided to maintain bed temperature in the range of 815 to 925 C (1,500 to 1,700 F), within prime temperature range of sorbents to react with bed contaminants and this is at the lower end of the potential ash softening and contaminant agglomeration temperature range.
More than 90 percent of the bed is inert material (sand or fuel ash) and the rest is fuel and sorbent. This balance changes with fuel quality and moisture. The large thermal flywheel effect of the inerts minimizes combustion disturbances and undesired swings of bed temperature. In some cases, special bed materials and additives can be used in order to avoid bed agglomeration.
Kaolin clay has been used to counteract alkalis and mitigating agglomeration in fluid bed boilers firing biomass. Kaolin minerals are alumino-silicates. Other minerals in the kaolin group are kaolinite, halloysite, dickite and nacrite. Even materials such as bauxite have been used because it contains significant “alumino-silicate impurities” that are available to react with alkalis.
With high moisture fuels, a support fuel may be required. It is best to co-fire with perhaps 10 to 20 percent of another solid fuel, such as coal that can contribute less-reactive ash. Although this may be best for good operation of the boiler, it may not be acceptable to some permitting agencies.
The choice between BFB and CFB technology depends mostly on boiler size and choice of fuels. Bubbling fluidized bed (BFB) boilers have been favored when firing 100 percent biomass or similar low-grade fuels containing highly volatiles that tend to burn intensely higher in the combustor/furnace, providing more on radiant heat transfer in this zone than conductive as with a CFB boiler. The bubbling bed is maintained in the temperature range of 760 to 815 C (1,400 to 1,500 F). Such units have been installed up to 100 MWe, but tend to be in the 10 to 50 MWe range, consistent with the amount of fuel that can be cost-effectively gathered within a given area. BFBs are typically non-reheat and operate at main steam temperatures at 500 C (932 F) or lower to reduce slagging. Where main steam temperatures are higher, they are typically arranged as platens at the top of the combustor/furnace as with a stoker/grate boiler.
Circulating fluidized bed (CFB) boilers technology is generally applied to larger capacity units and more broad range of fuels, with the largest CFB to date at around 460 MWe. One of the largest CFB firing 100 percent biomass is 190 MWe and is under construction.
A CFB can be configured with high temperature heat transfer surface (superheat and reheat) in the cyclone ash return system, thus picking up high temperatures from the returning bed material without being exposed to corrosive flue gases. Thus, higher cycle conditions can be achieved with a CFB boiler, making the overall power plant more efficient and opening up the range of commercially available steam turbines.
Suspension/Pulverized Fuel Combustion: In suspension fired boilers the pulverized fuel into fine particles burn while suspended in air as opposed to on a grate or in a fluidized bed. A disadvantage of this system is the energy consumption and complexity of the pulverizer system. The main advantage is that it provides the highest combustion efficiency.
Biomass co-firing can contribute anywhere from 5 to 20 percent of the total heat input needed in a pulverized fuel boiler without having to upgrade the metallurgy, depending on how “clean” the biomass is. Typically, the boiler can handle moisture range from 10 percent to 30 percent.
High steam temperature increases the risk of high temperature corrosion when exposed to the corrosive flue gas. Some studies indicate that with steam temperatures above 565 C (1,050 F), the lifetime of superheaters is unacceptably low, although problems start to occur at even lower temperatures. In Denmark, Tech-wise has conducted a number of biomass co-firing experiments and demonstrations, for example at the Studstrup power station. In Studstrup, straw was co-fired up to 20 percent of the energy basis. Corrosion increased, but the result would have been approximately the same if medium-corrosive coal had been used. Slagging increased when the proportion of straw was increased.
Biomass co-firing is the simultaneous combustion of biomass and fossil fuels and it is one of the most attractive and easily implemented biomass technologies. It can be deployed in nearly all types of coal-fired boilers, including pulverized coal boilers, stokers and fluidized beds. Because stoker boilers are designed to fire fairly large fuel particles on traveling or vibrating grates, they are the most suitable boiler type for co-firing at significant biomass input levels.
By taking advantage of existing infrastructure, biomass co-firing could serve as a key component in any Renewable Portfolio Standard (RPS) and carbon regulation regime. It is a fuel-diversification strategy that has been practiced for decades in the wood products industries and more recently in utility-scale boilers.
There are basically three options for co-firing: direct, indirect and parallel co-firing. Direct co-firing is combustion of biomass together with fossil fuel in a single combustion chamber. Indirect co-firing means combustion of fossil fuel with gasified biomass fuel, and parallel combustion requires at least two boilers as biomass is burned in one and fossil fuel in another.
Direct co-firing is a straightforward and low-cost option and therefore usually the first choice of plant operators. The preferred approach of co-firing biomass in a PC boiler is to feed the biomass into a dedicated mill so it can be dried at around 100 C (200 F) while the coal is dried at around 275 C (525 F). Biomass is very reactive and burns hot so the top row of burners is normally selected to apply that heat to the superheater. Chlorine concentration of co-fired fuel should be less than 0.5 percent by weight or even 0.1 percent by weight, depending on the amount of biomass being co-fired.
An application of direct co-firing is the world’s largest co-firing project at the Drax Power Station in the United Kingdom. The 4,000 MWe power station is producing up to 10 percent, or 400 MWe, from biomass co-firing. This has the potential to save over 2.5 million million tons of CO2 each year.
Indirect Co-firing: Indirect co-firing entails the gasification or pyrolysis of the biomass and then injecting the gaseous fuel produced into the furnace of the boiler. Gasification technology is commercially available and there are many different types of gasification systems, atmospheric fluidized bed gasification being one of the most cited in recent literature. In other plant configurations, the flue gas from a biomass pre-combustion chamber is vented to the furnace, where combustion is completed. This option requires much new equipment and a possibly complicated connection to the furnace and control systems.
On the plus side, it does not contaminate the ash used for resale and avoids other unpleasant side effects such as scaling and fouling on the furnace tubes. It can effectively control emissions because heavy metals and up to 90 to 99 percent of the chlorine is removed before the product gas is combusted in the boiler. The Lahti gasifier replaces 15 percent of the fossil fuel fired in the main boiler and significantly reduces SO2, NOX and CO2 emissions.
Parallel Co-firing: Parallel co-firing involves constructing a completely separate biomass-fired boiler and then cross-connecting the two steam supplies into a common header. This approach is straightforward in application but does require a large investment in duplicating much of the furnace-side equipment and fuel-handling systems.
Avedøre power station in Denmark is one of the world’s most energy-efficient combined heat and power plants. Avedøre 2 is divided into three modules: an ultra supercritical boiler plant, a gas turbine plant and a biomass plant.
Typically, biomass fuel supplies should cost at least 20 percent less, on a thermal basis, than coal supplies before a co-firing project can be economically attractive. Payback periods are typically between one and eight years, and annual cost savings could range from $60,000 to $110,000 for an average-size industrial boiler. As a rule, boilers producing less than 35,000 pounds per hour (lb/hr) of steam are too small for co-firing to be economically attractive.
One primary driver for firing biomass is CO2 reduction where it is considered a greenhouse-gas neutral fuel. Firing biomass also reduces other emission such as NOX and SO2.
Stoker/grate units are usually outfitted with multiclones to capture and reinject large ash particles rich in unburned carbon. Because of the risk of sparkler carryover when firing biomass, most installations use a electrostatic precipitators (ESP) for flyash collection. BFBs tend to use an ESP for the same reasons. Because of the integral cyclones and greater amount of bed ash that leaves as flyash, CFBs achieve better carbon burnout and produce flyash with lower loss of ignition and can, therefore, use more efficient baghouses with very little risk of damaging the bags from glowing flyash.
Sorbent may not need to be added to the bed of a BFB or CFB when firing 100 percent biomass due to its low sulfur content, but lime may need to be injected into the flue gas to capture other acid gases. A baghouse provides greater residence time for sorbent to react when it forms part of the filter cake on the bags.
Modern boilers utilize staged combustion and lower combustion temperatures for lower inherent NOX production. NOX can be reduced further by use of selective catalytic reduction (SCR) with injection of a sorbent such as ammonia, as well as selective non-catalytic reduction (SNCR) utilizing only injection of the sorbent into the flue gas without the use of a catalyst. The SNCR system that is typically used on a CFB injects ammonia into the flue gas in a constant temperature zone of around 800 to 900 C (1,500 to 1,700 F) for roughly 60 percent NOX capture. In a PC boiler firing coal, the SCR catalyst is placed in a flue gas temperature zone of 315 to 430 C (600 to 800 F) for best sorbent (ammonia) reaction; this coincides with the position between the economizer and the air heater.
A catalyst in this location is not always suitable for biomass firing due to flue gas constituents such as sodium, potassium, lead or arsenic contained in the biomass ash that can poison the catalyst and dramatically shorten its life. Locating the SCR downstream of the particulate control equipment will solve the poisoning problem but the flue gas temperature is too low for good reaction. Various techniques have been devised for utilizing “low temperature catalyst,” but experience to date indicates they result in varying degrees of higher costs as well as lower plant efficiency.
Fuel Handling and Supply
The handling and flow properties of biomass fuels are usually poor because of particle size variation and high fiber and oversized particle content. Additionally, the bulk is adherent, corrosive and even abrasive. The weak flow properties imply high internal and external friction. Of course there are exceptions such as pelletized fuels made from dry raw material. Biomass also has a tendency to decay, causing foul odors; therefore, storage duration is limited and seasonal variations in supply cannot be overcome.
Chipped wood tend to be more easily handled than mulch-like material or long stringy bark or bio-crops (switchgrass, bagasse and so on). Large quantities of fine, sawdust-like material should also be avoided because it is prone to plugging chutes and hoppers. Some co-firing facilities have found it more convenient and cost-effective to have biomass processed by a third-party fuel supplier. Basically, the handling and conveying system should be designed according to the specific fuel properties. Usually several fuel types have to be fed into the boiler. Sometimes the same feed system can be utilized; however fuels of very different handling characteristics should not be blended as this will likely lead to pluggage.
High shear strength, irregular shape and low energy density of biomass fuels have lead to the design of receiving pits and pre-screens that are as open and as steep as possible, enabling sufficient unloading for the boiler capacity. Usually different fuel fractions will be blended during transportation and in the receiving station. There are very few separate units for mixing. In large plants, fuels are blended sufficiently also in handling and conveying, especially in the loading and unloading of silos. Manual fuel sampling is common where many fuel types are fired. Biomass may pick up rock and other debris when being harvested. It is recommended the fuel be screened during receiving and stockout.
Where biomass is stored in an enclosed structure for long periods of time, significant off gassing of CO, CO2 and CH4 will occur and will need to be vented for personnel protection and fire prevention.
Fuel storage for stoker/grate units is usually just a 15-minute hopper. Large utility-sized pulverized fuel units require much longer storage silos that may dictate the fuel must be free flowing, such as with wood pellets. Fluid bed boilers usually have gravity feed or screw feed of shredded or chipped biomass fuel. These silos should not be so large as to compact the fuel and may even be diverging. Fuel can be tested for bridging and flowability characteristics to determine a suitable silo shape. It is recommended they have a live bottom reclaim such as screw conveyors. These usually feed onto a gravimetric belt conveyor for metering, and can be distributed to the boiler feed points by chain conveyors. One quick tool used to help solve feed or pluggage problems is a cause and effect diagram to help reach a workable solution for the specific difficulties that need to be overcome.
Dust Hazard Considerations: Biomass can be very dusty when dry. This dust can be an explosion hazard every bit as bad as Powder River Basin (PRB) coal, if not worse. If water spray is used for dust control, it will raise the temperature of the stored biomass and may lead to spontaneous combustion.
Materials are generally tested in accordance with ASTM E 1226, “Standard Test Method for Pressure and Rate of Pressure Rise for Combustible Dusts” to establish their Kst and Pmax values. These values are critical in determining vent area requirements in accordance with NFPA 68, “Standard on Explosion Protection by Deflagration Venting” (2007 Edition).
The services a specialty explosion testing company are typically used for include testing the Deflagration Index, Maximum unvented deflagration pressure and other important design factors such as dust cloud ignition temperature, layered dust ignition temperature, minimum explosive concentration (MEC) or minimum ignition energy.
Buildings containing dust hazards require explosion control in accordance with International Building Code (IBC) criterion. Explosion control for buildings is typically provided through explosion venting. The IBC does not specify an exempt limit for combustible dust; hence any accumulated dust is considered hazardous unless justified otherwise. For comparison, former codes and standards specified the exempt limit for dust as 1 lb/1,000 ft3 of enclosure volume. Dust from agricultural products, such as cellulosic materials, can produce explosion properties equal to or greater than PRB coal. Hence, equipment or buildings designed for use with bituminous coal hazards may not be suitable for service with agricultural products without modification or engineering evaluation.
Control, fire and occupational safety are based on a modern distributed control system. A lot of research has been done to study fuel safety properties. Experience has shown that the most critical parts of the process are the receiving, screening, crushing and feeding line near the boiler. The use of modern monitoring, cameras utilizing broader wavelengths, detection and preventive technology has been significantly increased.
Biomass Project Experience
Bechtel is actively involved in pursuing biomass projects of all types. One project currently in development will utilize process steam as well as hot flue gas for an adjacent wood pelletizing facility. Such combined heat and power (CHP) or co-generation applications increase the overall efficiency of a power plant. The pelletizing facility will utilize clean-burning “round wood” (debarked tree trunks) for making bagged pellets for residential use. The bark and tree slashings from nearby hardwood harvesting operations are used as fuel for the electric generating power plant.
There is interest in firing biomass not only in the North America, but also in Europe, Australia, Africa and Asia. Developers are finding that firing or co-firing biomass can be very competitive with conventionally fueled power plants and even with federally subsidized renewable power projects, such as solar and wind.
One of the larger, more interesting units designed to co-fire biomass is the steam generator at the Northampton Generating Plant. The unit is a single reheat CFB boiler designed to burn a blend of waste anthracite coal (culm) and silt (minus 100 mesh washery fines). A 2,400 psig (165 barg), 1,000 F (538 C), 1,000 F (538 C) condensing turbine is designed to supply up to 80,000 pph (36,287 kg/hr) of export steam to a neighboring paper reprocessing facility.
The anthracite culm is received as 2-inch (50 mm) top size and is crushed to ¼-inch (6 mm) top size. Received fuels can be conveyed to the power block day silo or stocked out for storage under cover. Other opportunity fuels that are or have been co-fired are shredded wood, dewatered paper reprocessing sludge, petroleum coke, and shredded scrap tires. The scrap tires are to be received already chopped to 1-inch (25 mm) top size with the wire bead already removed. Likewise, the shredded wood is received at 1-inch (25 mm) top size. One reclaim hopper was originally installed in addition to the truck receiving hopper to facilitate reclaim and blending, allowing high calorific fuels to be blended with low calorific fuels to keep the overall fuel higher heating value within an acceptable range. An additional reclaim hopper was later added by the power plant owner to allow blending of several opportunity fuels simultaneously. The fuel is then conveyed to a single 1,500 ton (1,360 tonne) fuel silo with four outlets that supply fuel to the boiler. The silo is lined with an ultra-high molecular weight (UHMW) polyethylene liner for good flowability.
A second example is the Red Hills Generating Plant, completed in 2002, located in north-central Mississippi. Two lignite-fired CFB boilers generate steam at 2,625 psig (165 barg), 1,055 F (566 C), 1,005 F (538 C) for a single steam turbine.
The Red Hills Generating Plant was configured as an “Eco Park” where wood chips and other logging and paper processing waste materials could be readily co-fired up to 5 percent of the boiler fuel heat input by adding a separate biomass handling system. An area was reserved for receiving and reclaiming prepared and sized biomass. A routing was reserved for the addition of conveyors where the biomass could be conveyed to the discharge end of the lignite feeders, where it would be fed to the CFB through the existing feed points.
The average biomass plant has a capacity of about 20 MW, mainly depending on fuel gathering capability. A few plants are substantially larger and can sustain operations due to dedicated fuel supply.
Options for biomass utilization in power plants includes stoker fired, bubbling or circulating fluidized-bed or pulverized fuel technologies.
Another option is to co-fire biomass fuels with stokers, BFB, CFB or PF, which could reduce the environmental impacts that would otherwise be presented by disposal of these materials. Clearly, maximizing the use of biomass fuels in boilers can be viewed as a win-win scenario for owners as well as the environment and the communities in which we live. Co-firing biomass fuels with coal in a large CFB boiler allows the unit to be sized and designed for utility service, with better economy of scale and better steam cycle efficiency. Biomass fuel can be co-fired in moderation (10 to 15 percent) to reduce fuel cost without detrimental effects on a PF boiler. When the biomass fuel is not available due to seasonal or other reasons, the unit can still meet power demand by firing 100 percent coal.
An important ingredient for a successful plant is early involvement of an experienced EPC contractor in selecting major plant equipment. In the major equipment and technology evaluation and procurement process, Bechtel remains technology neutral but proactive in identifying the best available technology meeting owner requirements.More Power Engineering Issue Articles
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