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Biomass Equipment Options for Steam and Power

The potential to use biomass as a low-cost fuel that reduces carbon footprint is growing. The equipment options for firing biomass to replace fossil fuel in plant operations are equally vast.
By Arnie Iwanick
Most types of organic material can be burned for steam and power. In the final analysis, the choice of feedstock comes down to a matter of economics. Technology is currently available and new innovations are remarkable. Various types of wood waste have been burned in the forest products and pulp and paper industry for decades, if not centuries.

Some locations are using agricultural wastes and products such as rice straw, rice hulls, corn stover, distillers grains, animal bedding waste, manure, and bagasse as boiler fuel.

Although applications exist to convert biomass to biofuels and chemicals, the intent of this discussion is to convert biomass for steam and power. Biomass can be burned directly in a boiler, or a gasifier can be utilized to produce syngas that can be used for a substitute fuel.

Fuel Handling
A robust material handling feed system is required to ensure the efficient operation of any of the combustion devices. Biomass is one of the more difficult materials to handle, and
is especially obedient to Newton's first and third laws: "Every object in a state of uniform motion tends to remain in that state of motion unless an external force is applied to it."

This means there are multiple external forces that prevent biomass from staying in motion. "For every action there is an equal and opposite reaction," which means that once in
place, biomass tends to stay in place.

Biomass presents a variety of interesting challenges and takes special handling. Wood chips or wood waste materials tend to hang-up and bridge. After the bridge forms, biomass is difficult to move. Compaction makes the material stronger and must be avoided to ensure uninterrupted operation. As a part of a good boiler or gasifier operation, getting fuel to the plant reliability is key. The following is an example illustrating methods of handling biomass material.


Figure 1. Fuel storage silo with traveling screw
SOURCE: Harris group inc.


It is important to employ good fuel feed and conditioning systems. There should be enough "take away" capacity in order that fuel handling systems do not jam and plug. Materials must be screened adequately to remove sticks, oversize material, stones and tramp metal. Non-magnetic materials need to be detected to prevent damage to downstream systems.

Equipment must be accessible for lubrication, inspection and maintenance programs. Appropriate cleanouts should be designed where systems might plug. Storage vessels should be designed to prevent bridging. Bins may be tapered slightly outward to avoid compaction and help prevent bridging. Also, the outlet screw discharge rotates around the bin to ensure uniform flow through the bin and first-in/first-out operation.

Screw conveyor design is critical in handling biomass. Material handling is significantly different for biomass versus coal, gravel and ash applications. Biomass will compress, compact and gain strength in compression. Screws are tapered to improve flow characteristics.

Boilers, Gasifiers
Stoker-fed units, bubbling fluidized bed boilers, circulating fluidized bed boilers and gasifiers are available for burning various biofuels. Let's review their operating characteristics to understand which applications are most appropriate for biomass.

Stoker-fed units were one of the first technologies to fire biomass. Still used today, they are reliable and efficient and can use a variety of fuels, including wood waste, municipal solid waste, and agricultural materials such as corn stover, straw and animal waste. The stoker can also handle sludge and combination fuels, including coal and tire-derived fuel.

Improvements have been made with computer fluid dynamic modeling, improved overfire air systems, deep bed burning and emission controls. Older units have had small inefficient overfire air systems, which can result in lower efficiency, low steaming rates, poor carbon burnout, and high carbon monoxide, oxides of nitrogen (NOx) and particulate emissions. All boiler manufacturers and other suppliers now have improved combustion air systems to mitigate these issues.

Stokers can burn many types of fuels individually or in combination. Some operate similar to a gasifier with a deep bed of fuel on the grate. The bed can be burned in a low oxygen environment with undergrate air. Overfire air completes the combustion higher in the furnace. The advantage is a reserve of fuel in the boiler, ready to pick up an increase in steam demand. A rapid decrease in steam demand is attained by reducing undergrate air and fuel under controlled conditions.


Figure 2. Nexterra's gasifier
SOURCE: NEXTERRA


Stoker boilers are capable of handling many fuels. Their advantage is lower capital cost for clean biofuels with no sulfur. With sulfur-bearing fuels, a sulfur dioxide scrubber would be required.

These are used extensively in forest products, pulp and paper, and in power plant applications. The boilers have application in small- to large-sized industrial applications for firing many types of biomass and solid fuels.

Bubbling fluidized bed boilers are applicable for specific fuels, such as agricultural wastes and for combinations such as wood waste and paper mill sludge. Well-designed systems have low carbon monoxide and NOx emissions. Medium-size applications range between 100,000 to 250,000 pounds per hour of steam generation for bottom supported units and large applications to 700,000 pounds per hour for top supported units. The bubbling bed of sand provides a heat sink which allows the boiler to handle various types of fuels and somewhat variable moisture contents.

At a paper mill in Wauna, Ore., Georgia-Pacific operates and maintains a bubbling fluidized bed boiler owned by a local public utility district for power generation. The boiler, installed in 1995, produces 120,000 pounds per hour of steam from wood waste and paper mill sludge. The boiler has an excellent reliability and supplies steam to a steam turbine generator and the paper mill on a continuous basis.

The unit has ammonia and flue gas recirculation for NOx control, limestone for sulfur dioxide control, and baghouses for particulates. The baghouses also remove some sulfur dioxide.

A circulating fluidized bed boiler works well with multiple fuels and mixed fuels. As it relates to alternate fuels and moisture content, this type of boiler is quite forgiving. Typically, the boilers are not used for biomass, but biomass can be considered in combination with fuels such as coal. In general, the boilers would be used for large industrial applications and utility boilers with steaming rates of 250,000 to 1,500,000 pounds per hour.


Figure 3. Gasifier/ oxidizer biomass cogeneration plant
SOURCE: NEXTERRA


The capital cost is reduced for back-end emission control equipment because sulfur dioxide control can be accomplished with lime within the circulating flue gas. The unit has low emissions for NOx due to lower firing temperatures.

Gasification is an old technology used with coal to form producer gas, mainly carbon monoxide, and is now back in favor and considered "new" technology. There have been many improvements to this technology, which can be adapted to allow biomass to replace fossil fuels.

A gasifier is a piece of equipment that burns organic fuel in an oxygen-starved environment. This produces carbon monoxide, hydrogen and methane, and small amounts of other organic products. The carbon monoxide, hydrogen and methane are the main components that are subsequently oxidized as fuel to produce heat.

Carbon reacts with water to form carbon monoxide, carbon dioxide and hydrogen at elevated temperatures.

Shown in Figure 2 is a gasifier by Nexterra, which produces syngas. The syngas temperature is controlled between 700 and 900 degrees Fahrenheit with 25 percent moisture fuel.

Temperature is affected by moisture content of the fuel and controlled by varying the amount of flue gas recirculation and oxygen to the gasifier.

Gasifiers clearly have some advantages. The gasification process operates at low firing temperatures, which results in less slagging in the gasifier furnace. The ash is light and feels similar to ash in a fireplace. The syngas is clean and also fires at a low temperature due to its low British thermal unit content. This also results in less slagging in the superheater and generation banks of the downstream boiler.

This type of gasifier is good for single fuel applications. It produces lower NOx due to low furnace temperatures. The oxidizer burns the syngas and other organics and provides low carbon monoxide and particulate emissions. Small units are available for low steam production rates in the range of 20,000 to 200,000 pounds per hour. Multiple gasifiers are used to attain the higher production rates.

An example installation is shown in Figure 3. The gasifier is designed to produce 60,000 pounds per hour of steam and 1.4 megawatts of electricity. Three gasifiers supply a single oxidizer. A waste heat recovery boiler produces 600 pounds per square inch, 740 degree Fahrenheit steam. The steam turbine generator exhausts to the 110 pounds per square inch steam system to heat the university campus. Capital cost of the facility, installed in 2007, was $20 million and reduces the campus annual energy costs by $2 million. In addition, it generates approximately $600,000 per year of electrical energy.


Figure 4. PulseEnhanced Heat Exchanger for bubbling bed steam reformer
photo: HARRIS GROUP INC.


Other gasifiers can produce a syngas of higher Btu quality by not using air in the gasifier. For instance, a bubbling bed steam reformer can produce a higher Btu syngas with superheated steam converting the biomass to carbon monoxide and hydrogen. The reaction is endothermic.

Shown in Figure 4, pulse combustion heaters (PulseEnhanced Heat Exchangers) burn a portion of the syngas to provide indirect heat to a bubbling bed of alumina oxide and biomass. Excess syngas would be available for steam and power generation or other uses.

Combustion Controls
Proper combustion controls are required for efficient operation of all boilers and gasifiers. Good oxygen control is necessary for safety, proper combustion and efficiency. Fuel-to-oxygen (or air) ratio is measured and controlled. Flue gas oxygen levels are measured and used for trim control. Programmed controls may be installed for startups, shutdowns and special transitions to avoid hazardous explosive conditions. Improved efficiency can be attained utilizing carbon monoxide controls and good overfire air distribution systems.

Overfire air systems are often designed using computer fluidized dynamics design.

Contaminants, Emissions
Contaminants such as potassium, sodium, chlorides, silica and phosphorus can create havoc in a boiler without proper design and chemistry. Variation in fuel type, fuel quality, season and moisture will create operational issues.

Sodium, potassium and phosphorus can cause slagging due to the reduction in the ash melting point. Chlorides from salts or plastics can cause corrosion, slagging and hydrogen chloride emissions. Silica may cause slagging and erosion. Sulfur produces sulfur dioxide emissions, sulfur trioxide emissions and cold end corrosion.

It is recommended to analyze the fuel ash for low fusion point and mix fuels or add materials such as lime to mitigate sticky ash. Sootblowers in specific boiler areas may be required to keep heat transfer surfaces clean. Where possible, contaminants should be removed from the fuel.

How are emissions kept under control for sulfur oxides, NOx, carbon monoxide, volatile organic compounds, particulates and possibly other emissions?

Sulfur dioxide can be reduced internally with lime addition in fluidized bed boilers and circulating fluidized bed boilers. Otherwise backend equipment is needed using lime in a wet scrubber, or a spray dryer absorber with a baghouse.


Figure 5. Carbon monoxide emissions
SOURCE: HARRIS GROUP INC.


NOx can be reduced with overfire air controls, selective catalytic reduction, selective non-catalytic reduction and overfire air controls. Thermal NOx can be reduced with lower firing temperatures and with flue gas recirculation. Ammonia or urea is used to convert the NOx to nitrogen.

Carbon monoxide and volatile organic hydrocarbons are reduced with good combustion controls and good design with computerized fluid dynamic modeling. Minimal air leakage with proper seals is helpful in reducing emissions and improving thermal efficiency. Combustion air systems must be controlled to ensure that the air is added in the proper ratios to the various injection points.

Note in Figures 5 and 6 that the fluidized bed boilers have lower carbon monoxide emissions due in part to better mixing and lower NOx emissions due to lower firing temperatures and low excess oxygen.

Particulate emissions are typically controlled with a baghouse or an electrostatic precipitator.

Operating Costs
One of the goals is to reduce fossil fuel use in our steam and power plants. Biomass-fueled boilers or gasifiers can be used to replace fuel oil or natural gas as one method to accomplish this goal. For a 100,000 pound per hour steam boiler, operating costs can be reduced by more than 50 percent depending on the cost of fuel.

One option would be to use a gasifier to produce syngas or producer gas, which could be burned in a retrofitted existing boiler. An example of such a plant is Chippewa Valley Ethanol Corp. in Benson, Minn. The gas is burned through a multifuel Coen burner on a conventional power boiler.

Burning biofuels can be accomplished economically and can help reduce our dependency on fossil fuels. For a 100,000 pound per hour boiler, natural gas at $8/MMBtu would have an annual fuel cost of $8.2 million. Biofuel costs could be half compared to natural gas.

At the same time, should we consider power generation?

Extraction power from a steam turbine generator could be produced at less than 2 cents per kilowatt hour. Based on a cost of a steam turbine generator at $1,000 per kilowatt and a fuel cost of $50 per bone dry ton, a 5-megawatt generator could provide additional revenue of $2.3 million with a payback on capital of less than 2.5 years.

Condensing power is more expensive to produce due to the lower efficiency for condensing power generation but also for the higher cost of fuel. The fuel to the plant would be delivered from a greater distance for incremental power generation. Fuel for power might cost 4 to 6 cents per kilowatt hour and would most likely not be economical.



Figure 6. NOx emissions
SOURCE: HARRIS GROUP INC.



Figure 7. Capital cost for a biomass-fueled boiler
SOURCE: HARRIS GROUP INC.


Capital Costs
Compared to natural gas, capital costs are higher for handling solid fuels and producing steam and power. The equipment is larger and more complex. More emission control equipment is also needed. The question becomes one of obtaining an acceptable return on investment with proper design of the equipment, a reasonable cost for biomass, and acceptable revenues for steam and power.

For a greenfield plant, such as at University of South Carolina project shown in Figure 3, the simple payback could be five to eight years on the $20 million investment, which isn't suitable for an industrial facility. Grants from the U.S. DOE, utilities and other programs would be needed to make the facility viable. The objective here would be to look for utilities that require green power for increased revenues. Industrial facilities may have some infrastructure in place whereby the plant could modify existing equipment. Options may include cogeneration for increased efficiency, or adding extraction power tied into the plant process. In addition, thermal efficiency of existing industrial processes can be improved to reduce operating costs. Improved thermal efficiency can also be gained by reducing moisture in the fuel and reusing waste heat where possible.

Shown in Figure 7 is a breakdown for the capital cost of a biomass-fired boiler for steam and power.

The capital cost for a greenfield steam and power plant is high and may not be justifiable.

As a result, existing infrastructure should be utilized wherever possible. Since the boiler is the largest capital cost, one should evaluate modifying an existing boiler to accept syngas to replace natural gas or fuel oil. Other considerations include utilizing existing precipitators, existing solid material or fuel handling facilities, or existing steam turbine generators.

Can the facility produce other value-added products from the syngas such as biofuels, ethanol or chemical products? If any parts of the existing infrastructure are not fully utilized, a gasifier can help supplement fuel systems and reduce energy costs.

Financing your combined heat and power (CHP) project independently may be difficult. Review third-party financing either from a private developer or a utility that wants "green power" development. The payback on CHP projects is more than five years and requires special financing.

Most biofuel plants cannot justify a greenfield steam and power plant on their own, unless there are other mitigating circumstances. For instance, a plant can burn sludge to reduce high landfill costs. Alternately, a plant could obtain tipping fees to burn sludge, biomass or municipal solid waste. If a utility needs to purchase green power as mandated by the state, such as Washington, Oregon and others, the utility may pay for a significant portion of the power plant. Grant money also may be available for new technology development.

Plant Experience
Fuel plugging and feeding issues can impact newly designed plants. Design of the fuel system by an experienced supplier.can mitigate this risk.

Stoker-type boilers have many years of operating experience. Older boilers have room for improvement with better combustion control systems and overfire air systems. Reliability still remains excellent for most units.

Circulating fluidized bed boilers are usually very large and are seldom used for biomass fueled applications.

Bubbling fluidized bed boilers have a history of high reliability with satisfactory emissions. Items to be careful of include tube erosion from excessive velocity and turbulence, and sintering. Sintering can occur from high firing temperatures or low melting point eutectics due to sodium, potassium, chlorides, phosphorus or other non-process elements. Upset conditions and induction draft fan limitations can occur due to low temperatures, high moisture fuels and low heating value fuels. Be watchful of corrosion or erosion issues due to boiler configuration and plant design, resulting from unusual flue gas and combustion air distribution in tubular air heaters.

Gasifiers are becoming more popular for certain applications. Refractory design is important and appears to be holding up well. The ash from the gasifier is light and fluffy, similar to that in a home fireplace. Observations show it is not sintering in downstream equipment. Long-term reliability and availability issues are yet to be determined but short-term operation is looking promising. Longer term operating experience will confirm the reliability of these processes.

Conclusions
For firing biomass, good systems are available for many applications. From small to large units, almost any type of organic material, in one form or in combination, can be handled. Some fuels and combinations of fuel may need special treatment.

The economic solution is key to making the project successful. Boilers of different types make sense for medium to large projects while biomass gasifiers are making an impact in the small to medium size project range.

The cost of biomass fuel has a major impact on the return of investment. Fuel collection, delivery and storage at minimum costs are needed to make the large capital investment of the projects worthwhile.

Power generation can improve the project's return on investment. Cogeneration, where possible, produces power and exhausts the steam to a plant process. This may be a more economical solution compared to condensing power. Integration into an existing facility, grants from U.S. DOE or utilities, green power credits, and carbon credits all can make a project more feasible.

Arnie Iwanick is a senior process engineer with Harris Group Inc. Reach him at arnie.iwanick@harrisgroup.com.
 

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