By Daniel Mahr, P.E.
Energy Associates, P.C.
Montville, NJ, USA
WHY BIOMASS?
The power industry is confronting challenges with seemingly conflicting goals. Large, solid-fuel power plants provide the reliability and flexibility utilities require for baseload, cycling, and on-demand situations. They provide the economy of scale needed to minimize the cost of production. Consumers, including industry, rely on affordable, dependable electrical energy. It’s an important part of our economy and our daily lifestyle. Reducing emission levels and conserving our finite resources are key components for achieving a sustainable environment.
Historically, biomass powered society’s early development, and its ability to power our needs today is being reassessed, as a means to recycle carbon emissions. Biomass is a resource that can be substituted for coal, in varying degrees for existing pulverized coal (PC) plants. New, large power plants are being designed to utilize biomass as the primary fuel, most notably in circulating fluidized bed combustion (CFB) boilers.
Biomass is available now. New products and sources are being developed, as the market unfolds.
While biomass-fired plants have been a part of the scene for some time, they have typically been relatively small, 25 to 50 MW, and often address specialized, local conditions. Biomass units on the scale of 300 MW and larger present a number of different and important challenges. The plant’s ability to effectively utilize biomass fuel products is more important for this technology scale-up.
Biomass fuel procurement decisions have a greater impact on a solid-fuel power plant’s design and its fuel processing, handling, and storage features. Compared to other solid-fuel-fired plants, some components will appear quite familiar, but there are important differences. Other system components and processes will be completely foreign. A successful design must consider the fuel first and provide the flexibility needed to handle the range of properties and characteristics that will be experienced. A number of examples and lessons learned from smaller biomass plants provide some of the guidance needed for scaling up to 300 MW and larger biomass units.
CO-FIRING IN A PC BOILER
One of the options that can most easily be implemented by utilities with coal-fired units is to adapt their existing plants. While it requires plant additions and modifications, compared to starting from scratch, it’s a relatively low-cost methodology to add biomass to the plant fleet.
Beginning in 1996, the Electric Power Research Institute and the U.S. Department of Energy began a biomass co-firing research program. Demonstration projects were conducted at several pulverized coal and cyclone plants. The program added biomass co-firing with heat input rates up to 10%. The amount of biomass that was co-fired varied with the method of biomass feeding, either blending it directly using the coal reclaim system or separately injecting it into the combustor.
Directly blending biomass with coal can be practical when the amount of biomass is relatively modest (4 to 5%), especially if the plant has spare mill capacity. At higher levels, direct firing is advantageous. If wet coal is adversely limiting boiler capacity, boiler capacity can be improved with biomass co-firing.
Normally, co-firing with biomass does decrease boiler efficiency. The impact is a function of fuel characteristics and unit parameters. The dominant reasons for the decrease in boiler efficiency are the higher moisture content and hydrogen/carbon atomic ratios in biomass, in comparison to coal. The latent heat of vaporization for moisture and the pyrolysis of oxygen and hydrogen components of biomass into moisture have been shown to reduce boiler efficiency by 2% at the 20% co-firing level on a mass basis.
Air emissions are affected by biomass co-firing. Biomass co-firing typically reduces SOx and NOx emissions. This is due to the lower nitrogen and sulfur content of biomass in comparison to coal. The lower ash content in biomass can reduce particulate emissions, but the resistivity of biomass fly ash may be a factor to examine for an electrostatic precipitator (ESP).
One of the advantages of co-firing biomass is that the availability of biomass itself is not a critical issue. Biomass can be used when supplies are plentiful and economics are advantageous. The plant can easily return to 100% coal firing when supplies are low or conditions are otherwise unfavorable.
Co-firing with biomass can be more expensive than just using coal for three reasons:
1. Biomass handling and firing systems must be added to the plant, a capital cost financial component.
2. The cost of biomass fuel is typically higher than the cost of coal.
3. The higher moisture content of biomass will result in a higher heat rate for the unit; more fuel will be required.
As a result, monetary incentives are necessary to make biomass co-firing an economic choice.
The European Union expects all member states to supply 20% of their energy requirements by 2020 from sustainable forms of energy. These include wind, landfill gas, and biomass—with small amounts from solar, geothermal, and wave power.
In the United Kingdom, perhaps the largest co-firing project has recently been installed by Drax Power at its 4,000 MW, coal-fired Drax Power Station, located in Selby, North Yorkshire. This is the largest coal-fired station in the U.K. and provides enough power to meet 7% of the U.K.’s electricity needs. Drax Power began experimenting with a system that blends biomass with coal, using the existing emergency coal reclaim hopper. Based upon the success of this project, Drax Power recently completed an £80 million ($150 million) direct biomass injection system. Together, the 100 MW blending and the 400 MW direct inject provide 500 MW of biomass generating capacity. Figure No. 1 views the handling and storage area of the biomass co-firing system during construction.
An important aspect of Drax Power’s project is the U.K. government’s long-term subsidies for biomass. The uncertainty of the level of the current subsidy has dozens of companies delaying their further investment in biomass. The amount and duration of the subsidy will affect how much biomass is co-fired at the Drax Power Station.
CO-FIRING IN A CFB BOILER
One of the attributes of circulating fluidized bed combustion technology is its ability to utilize a variety of solid fuels. Very often, a CFB boiler will be using a high-ash, high-sulfur fuel. The relatively low combustion temperatures, reduced fuel preparation requirements, and inherent control of emissions within the boiler itself make it well suited to low-quality coal and alternative solid-fuel products.
The low-ash and low-sulfur characteristics of biomass fuel make it a convenient fuel foil for low-quality coal. It nicely “offsets” the high-ash, high-sulfur components of low-quality coal.
ENEL’s Sulcis plant in Sardinia, Italy, currently has two units, a 240 MWe pulverized coal boiler, which has a FGD system, and a new 350 MWe, Alstom Power fluidized bed boiler. The fluidized bed boiler was retrofitted to the plant and two 240 MWe pulverized coal-fired boilers were removed.
The plant now uses a blend of South African, Colombian, and Sardinian coals. The Sardinian coal is from a local mine/preparation plant. It has moderate ash content, relatively high sulfur levels, and high moisture content.
While the CFB boiler was designed for coal, ENEL added a biomass system. Figure No. 2 views Sulcis’s biomass handling, processing, and yard storage area. Wood chips are received by truck from local sources. They are stockpiled outdoors and reclaimed by payloaders. Wood chips are screened and stored in the yard and boiler bins. A completely independent biomass handling and feed system was constructed. The biomass is fed to the boiler via two of the three cyclone sealpots at the back wall of the furnace. Biomass is a maximum of 15% of the fuel input by heating value.
The world’s largest fluidized bed boiler is the 460 MW, once-through supercritical unit at the Lagisza plant. It began commercial operation in June 2009, replacing two of the seven existing units. The fluidized bed unit is designed to co-fire up to 10% biomass by weight. The biomass feeding equipment was considered in the design, so it could be added at a later date.
The Shaw Group is currently constructing the $1.8 billion, 585 MWe, Virginia City Hybrid Energy Center near St. Paul, Va., for Dominion Virginia Power. The plant will have two Foster Wheeler CFB boilers that will utilize waste coal, “gob,” and use up to 20 percent biomass. Construction began on June 30, 2008, and passed the halfway point in December 2009. Figure No. 3 is an artist’s rendering of the plant.
DIRECT FIRING IN A CFB BOILER
Technology developments for the direct firing of biomass benefited from the Public Utility Regulatory Policies Act (PURPA) that was passed as part of the National Energy Act in 1978. It promoted the conservation of energy, efficient use of facilities and resources, and equitable rates for customers. It encouraged a greater use of renewable energy by creating an expanded market by adding non-utility producers.
A variety of boiler designs were used under PURPA’s regulations including bubbling fluidized bed, circulating fluidized bed, fixed grate stokers, sloping grate, traveling grate stokers, and water-cooled vibrating grates. These technologies typically are all available up to a 50 MWe capacity for a single unit. As unit size ramps up, the circulating fluidized bed boiler becomes the technology of choice. Like pulverized coal technology, CFB technology scales up more easily for coal/biomass than stokers or grates. Major boiler manufacturers like Foster Wheeler, Alstom Power, and Metso Power are offering 300 MWe units for biomass and looking to the next larger size generation.
For new generation capacity, there are good reasons to consider a CFB boiler. This technology is proven and has been used since the 1980s. There are numerous plants that utilize agricultural, forest, mill, and urban biomass products. With forethought for boiler and plant design, a variety of solid fuels can be used according to availability, market, regulatory, or other circumstance.
Drax Power has been investigating the addition of three 300 MWe biomass-fired plants in the U.K. One would be located adjacent to its existing 4,000 MWe coal-fired plant and another in the Port of Immingham. Sites for the third plant are being evaluated. A variety of biomass products are being investigated including wood chips, wood pellets, miscanthus briquettes, straw pellets, bagasse briquettes, and logs. Much of the fuel will be initially imported while indigenous sources are developed.
The current uncertainty of sufficient long-term subsidies in the U.K. for biomass, however, has these three plants and dozens of companies slowing or delaying their investment in biomass.
UTILIZATION ATTRIBUTES
Fuel properties and characteristics are important to boiler design and operation. Different boilers have unique design and fuel requirements, i.e. what’s injected into a pulverized coal-fired (PC) boiler is an inappropriate fuel product for a stoker boiler. Heating value, percent volatiles, total ash and moisture content, ash constituents, and particle size are all key parameters considered by the boiler designer.
There are a wide number of choices in selecting the component materials that are generically known as “biomass.” Some biomass products have unique utilization issues. Wheat straw, for instance, has very high levels of chlorine and its ash chemistry is dominated by silica from the phytolith inorganic structures with significant potassium present. The chemical fraction behavior of biomass materials is quite different from that of typical coals.
For co-firing applications, the properties of biomass, coal, and possibly other solid fuels can be blended as a designer fuel. The objective is to best meet boiler, combustion, emission, and economic requirements.
CFB boilers are different from other combustion technologies. They have relatively low combustion temperatures and long combustion residence time, and the injection of limestone into the furnace makes the CFB technology unique in its ability to utilize a wide range of fuels while controlling emissions. In a CFB boiler, fuel is generally combusted in a bed or matrix of material that is expanded at a pressure and velocity that are:
1. above the particle’s saltation velocity but
2. below the particle’s transport velocity,
to sustain fuel particles in the fluidized state. The particles’ mass, volume, and shape are important to the efficiency of the process.
As a practical matter, the fuel feed to a CFB boiler will cover a range of particle sizes, from sand-size grains to small lumps. For any given fluidizing velocity, the smaller particles will transport much easier than larger particles, but they will also fully combust more quickly. CFB boilers use cyclones to separate the smallest (fly ash) particles from larger particles that may be only partially combusted. The larger particles are discharged to the bottom of the cyclone’s sealpot or loop-seal and reintroduced to the combustion bed. The combustion gases and fly ash are discharged through the top of the cyclone to the superheater and economizer. The design and operation of the cyclones themselves are dependent upon particle size and flue gas velocity.
Particle size curves have been developed by boiler manufacturers to identify fuel requirements. These curves are dependent upon the particle’s fluidizing and combustion characteristics. Particle mass, size, shape, and volatile content are key parameters for the curve. Some boiler manufacturers impose distinct fuel requirements to meet contract performance guarantees and warranties, depending upon the design fuel and contract terms.
Controlling fuel quality and cost by processing and blending biomass products on-site is a standard industry practice. Biomass handling systems typically include screens and hogs. Not all biomass products are completely suitable and the amount of some, like straw or miscanthus pellets, may be limited due to their chlorine and potassium content, which are deposition and corrosion concerns. When different, less-suitable products are used, accurate control of the blending process is important for combustion.
For a pulverized coal-fired boiler, it is well known that for coal to be combusted much like a gaseous fuel, it must be pulverized to a fineness where 70% typically passes a 200 mesh size. Combustion residence time is counted in seconds. The co-firing of biomass fuel in a PC boiler imposes similar requirements, although the particles are larger, perhaps crushed by an air-swept hammermill to less than 1/4 inch.
The requirements for a biomass-fired stoker boiler is seen in Figure No. 4, as published in Steam, Its Generation and Use, 40th Edition, page 15-8, by Babcock & Wilcox. B&W adds a note of caution that this distribution is rarely achieved, a processing problem.
Figure No. 5 illustrates the acceptable size range of biomass, as used by one CFB boiler manufacturer. The curve conforms to Austrian standard No. M 7133, “Chipped wood for energetic purposes—Requirements and test specifications”.
Figure No. 6 illustrates the fuel sizing curve used by one boiler manufacturer for coal. With a top size of perhaps 3/8 inch, it is very different from the curves for biomass that have a top size of something more like 4 to 6 inches. Figure No. 6 is considered to be conservative for commercial commitments and drawn for a low-volatile coal. For coals that are relatively high in volatiles, the upper curve might be adjusted by the user at the plant, so that larger particles could be used.
Comparing the curves in Figures No. 4, 5, and 6, it can be seen that Figure No. 5 has a much wider, forgiving range (distance between the upper and lower curves and slopes of the two curves themselves) of particle sizes. This has a lot to do with the high volatile levels and low specific gravity of biomass products. Both parameters are important for combustion and fluidization. Fluidization parameters are not an issue for a stoker boiler and the higher specific gravity and lower volatility of coal make their combustion characteristics different for these applications and technologies.
Some boiler manufacturers do not define particle sizing per se, only the maximum and minimum sizes and maximum percent within the size distribution. In one case for wood chips, the maximum size is 30 x 30 x 5 mm and the minimum size, those particles smaller than 3.15 mm, is limited to 10% of the fuel matrix. Both the minimum and maximum values are more restrictive than Figure No. 5, i.e. fewer fines and a smaller top size are allowed. This makes the sizing issue more important than what would be supposed by Figure No.5. This can be a key consideration in matching fuel processing techniques to boiler requirements.
As seen, controlling particle size and fuel quality to meet contract terms and boiler guarantees are important issues during the plant design and development stage of a project. Typically the boiler manufacturer is not responsible for supplying the fuel nor does he furnish the fuel preparation system. It can be an issue of contention for the parties to the contract—fuel supplier, fuel handling system designer/vendor, EPC contractor, boiler supplier, owner, and engineer.
HANDLING ATTRIBUTES
One of the limitations of biomass products such as wood chips is the relatively low, volumetric heating value or energy density. This is a property that is not normally of concern for other solid fuels. Both the lower mass heating value in MJ/kg (Btu/lb.) and low bulk density in kg/m3 (lb./ft.3) conspire to significantly reduce its volumetric heating value. As a result, many more railcars, much larger stockpiles, and wider belt conveyors are necessary to deliver and store the energy equivalent of other solid fuels. Wood chips require six times the volume as bituminous coal on a MJ/m3 (Btu/ft.3) basis.
Fuel degradation and spontaneous combustion are more important concerns for biomass fuel products. This is a moisture-dependent issue.
Dry biomass can be stored for long periods. Farmers store their grain harvests in silos to protect it for markets. Their hay was once stored in barns as the winter diet for horses, cows, and other farm animals. The grains discovered in Egyptian pyramids survived for thousands of years. So dry biomass can be stored for long time periods.
At moisture levels between 20 and 60 percent, degradation and spontaneous combustion become a concern. There is a high-temperature process due to oxidation of the cellulosic materials and a low-temperature process involving the growth and respiration of microorganisms, such as aerobic mold-fungi and bacteria. Biological heating, under the influence of water content or air humidity can increase product temperature to a sufficiently high value to trigger oxidation of the cellulose material to initiate a fire.
Above a 60 percent moisture level, wet biomass does not pose a spontaneous combustion problem. As any camper can attest, it’s hard to start or sustain a campfire with wet wood. At high moisture levels, too much energy is needed to increase the water temperature to 100 oC (212 oF) and then evaporate it. This high energy demand drops the temperature of the biomass below the level needed to sustain combustion. Biomass will, however, continue to degrade due to biological heating.
The large surface area of particles like wood chips and their irregular shape that traps small air pockets provide a near-ideal environment for the breakdown of fibers, increasing surface temperatures, and the potential for spontaneous combustion. Smaller chip sizes increase surface area and the probability of biological heating.
Wood chips, chopped straw, and other agricultural products have poor flow characteristics. During storage in stockpiles and bins, they compress in volume and particles can become entwined, matted, gaining strength as a mass, rather than behaving as unique individual particles. Instead of having a sloping angle of repose, the sides of a partially reclaim stockpile can be vertical. Storage bins are often designed with negative wall angles; the bins have walls that diverge. The bins are wider at the bottom than they are at the top, which is very different from the hoppers typically used for storing coal or other solid bulk products. Chute angles and the choice of liner materials should consider these poor flow properties.
Different biomass products can be blended for availability, economic, combustion, and other reasons. Tests have found that the blends of different biomass products can result in poorer flow conditions than if any product is used alone. Particle size, shape, and compressibility have a lot to do with this phenomenon.
PRE-TREATMENT
A biomass pre-treatment industry is developing to address some of the following issues:
1. The wide variety of biomass products often does not match with the narrow fuel specifications for the boiler.
2. To lower the relatively high costs of transportation, handling, and storage.
3. To reduce plant investment, maintenance, and labor costs by using a homogenous, consistent fuel for the combustion process.
Pellets are formed in a process that dries, mills, conditions with binders, extrudes, and then cools the product. A variety of biomass feedstocks can be used including bagasse, corn cobs and screenings, peanut shells, sawdust, switchgrass, and wheat middlings. The process grinds oversized material and compacts the fine biomass feedstock into a homogenous, high-energy-density fuel. The pellets are cylindrical shapes, with dimensions of 6-8 mm diameter and 15-25 mm length. Pellets are a convenient biomass product for co-firing in a coal-fired plant.
The properties and quality of biomass pellets can vary widely. While pellets from different manufacturers may appear to be similar, fuel properties are inherited from the parent or source feedstock material and quality is dependent upon the manufacturing process. While pellets manufactured from sawdust might be directly suitable as a fuel, pellets manufactured from switchgrass might be limited to no more than 10% of the blended biomass fuel because of their high alkali, chlorine, and silicon content, which can increase erosion and corrosion problems. Likewise, some manufacturers may use a binder such as starch while other processes will depend upon the biomass’s cellulosic lignin, which with heat and moisture acts as a binder to form a dense pellet. The amount of handling and exposure can also affect the quality of the delivered product. Receiving a shipment of wood pellets that has degraded into mostly sawdust can be very disconcerting when you are expecting a cargo of free flowing, hard, clean, relatively dust-free pellets.
Biomass briquettes have much in common with pellets. The primary difference is that briquettes are larger than pellets. They may be 30 to 100 mm (1–4 inches) in diameter. They can be a composite product formed from a blend of biomass and coal.
The properties of biomass can be improved through a thermo-chemical process known as torrefaction. Biomass is heated at a temperature of 200-300 oC (390-570 oF), in a reducing environment, typically for an hour. During this time, the biomass partially decomposes giving off volatiles. The remaining product or char alters material properties as follows:
1. increased energy density,
2. improved hydrophobic nature,
3. improved grindability,
4. increased uniformity, and
5, improved durability.
Torrefaction can help to mitigate certain constraints related to co-firing of biomass with coal, such as size reduction of biomass (which is problematic for untreated biomass due to its fibrous structure), storage (dry matter losses, fungi growth), or feeding. A unique advantage is that different types of feedstocks can be used and the torrefaction process will produce a uniform product. It reduces some of the quality control issues that might otherwise be encountered with biomass products.
Torrefied biomass can be further processed into pellets, which improves physical properties. Torrefied pellets can be stored in outdoor stockpiles and handled much like coal. They have perhaps half of the energy density of coal, which is a big improvement in comparison to untreated biomass products. The ability to handle and store torrefied biomass much like coal can significantly reduce the capital cost for an existing coal-fired plant to get into the “biomass business” with a co-firing project. Integro Earthfuels in the U.S. and Topell B.V. in the Netherlands are two companies that are moving from the pilot stage to their first commercial biomass torrefaction and pelletizing plants.
LESSONS LEARNED
In a non-regulated, competitive market environment, plants are less inclined to share information that could be valuable to a competitor. Both the good and bad experiences are of value to those seeking a path that avoids the pitfalls.
The National Renewable Energy Laboratory of the U.S. Department of Energy examined the experience of twenty biomass plants in 2000. They identified several key issues that impacted these plants: fuel cost, location, fuel handling, reliability and dependability, partnerships, and subsidies.
Fuel cost was the highest priority at most plants. Since there is normally a direct correlation between fuel cost and fuel quality, fuel quality trade-offs played an important role in plant design and operation.
The location affects a biomass power plant in a couple of ways. First, there can be local circumstances that become permit and community requirements. These can increase operating cost due to the need to curb traffic, to restrict operations that are noise and odor sources, and to pay high tax or labor rates. Second, the distance to biomass resources is important because the typically low energy value of biomass in comparison to coal, oil, and gas can quickly raise fuel cost as the transport distance increases.
Most plants in the NREL survey experienced a significant learning curve. They spent a lot of time and money the first couple of years solving problems such as fuel stockpile heating and odors, excessive equipment wear, handling hang-ups and bottlenecks, tramp metal problems, and wide fluctuations in fuel moisture content. A plant must meet environmental standards operating with variable conditions and without excessively corroding heat transfer surfaces or slagging boilers beyond the point of prudent operation.
Many biomass plants significantly changed fuels over the years. This is not an unusual case for the utility industry. Many PC boilers, which were originally designed to use bituminous coal, switched to low-sulfur PRB coal and, perhaps once fitted with scrubbers, have now switched to a high-sulfur Illinois coal.
For biomass, the differences can be significant and designing for fuel flexibility is a good strategy. The Colmac plant found it economical to modify its permit to allow the use of petroleum coke. At times, waste fossil fuels can be more economical than biomass products and the properties of one can offset those of another.
Plants with the best long-term operating records placed a high priority on plant reliability and dependability. This must be stressed during both plant design and operation. Staying atop of maintenance programs and maintaining a clean, neat workplace are essential elements for long-term reliability.
For those plants with close ties to a limited number of customers and/or suppliers, the relationship or partnership with these firms is important. For instance, a sawmill may provide the fuel as a primary supplier and be a consumer of the generated power. The mill and power plant have a mutual interest in the success of one another. In instances where the interest of the partners diverges, both parties suffer.
Many of these plants were constructed with the aid of PURPA’s regulations or state regulations where the legislature obligates utilities to either generate or purchase power at rates that are higher than what is otherwise available from other sources, i.e. a coal or nuclear power plant. Subsidy programs, however, do not last and competition will affect the long-term financial future of the plant.
WHY NOT BIOMASS?
The conflicting goals confronting the power industry make a sustainable, dependable fuel like biomass a candidate option to consider. It allows large, existing solid-fuel power plants to diversify their fuel base by co-firing biomass with coal or other solid fuels. Because existing plants can be employed and biomass can be a secondary fuel, it is an opportune technology that allows utilities to test the technology and build a network of suppliers in a relatively low-cost and low-risk program.
Consumers and industry rely on affordable, dependable electrical energy. Reducing emission levels and conserving our finite resources are key components for achieving a sustainable environment. Utilities build plant fleets to handle baseload, cycling, and peak demands. For a variety of reasons, there is no one technology that best meets all operating conditions. Biomass is a fuel that can deliver on many counts now and new pre-treatment technologies are at hand to make it a fuel that is more familiar, convenient, and economical. For utilities that are planning new power plants, biomass is a strategic fuel for expanding the plant fleet and one to add to the checklist of options.
This paper is from the Proceedings of ASME 2010 Power Conference, POWER2010, held July 13-15 in Chicago.
REFERENCES
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Hotta, Arto, “Features and Operation Performance of Lagisza 460MWe CFB Boiler”, 20th International Conference On Fluidized Bed Combustion, May 18, 2009.
Lord Jenkin of Roding, “The U.K.’s Energy Future”, Transmission & Distribution World, January 2010.
Maciejewska, Anna et. al., Co-Firing of Biomass with Coal: Constraints and Role of Biomass Pre-Treatment, DG JRC Institute for Energy, 2006.
Mahr, Daniel et. al., “Biomass plant relies on variety of local fuels”, Power, April 1992.
Paul, Dilo et.al., “Drivers for Biomass Co-Firing in the U.S. Economics of Legislation”, 26th Coal Utilization & Fuel Systems, March 5-8, 2001.
Plasynski, Sean I. et. al., “Biomass Cofiring In Full-Sized Coal-Fired Boilers”, 24th Coal Utilization & Fuel Systems, March 8-11, 1999.
Virginia City Hybrid Energy Center Newsletter, Volume 5, October 2009.
Webster, Ben, “Drax suspends plan to replace coal with greener fuel”, TIMESOnline, Feb., 19, 2010.
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