Tulsa, Oklahoma, USA — With the heightened renewable energy focus, many pulverized coal steam generator owners are asking how to convert their existing asset to biomass firing. While a simple question in premise, the answer is multi-faceted with a number of important factors dictating the equipment required and boiler performance implications. Fuel quantity and characteristics, environmental emissions and the existing equipment all influence the retooling.
Biomass is a general term for a wide range of fuels with an equally broad range of physical characteristics that can affect combustion technology and boiler equipment. Stipulated emission requirements need to be considered, as both the uncontrolled and controlled levels can influence boiler design and post-combustion equipment considerations. Existing boiler and auxiliary equipment have to be evaluated for performance, operating and maintenance considerations associated with the different physical characteristics and flue gas properties associated with the fuel switch.
Stoker, bubbling fluid bed (BFB), and circulating fluid bed (CFB) boilers are proven biomass firing technologies. With the increased demand for renewable energy, power plants are evaluating existing pulverized coal, oil or gas fired boilers to determine biomass-firing capability. A viable biomass conversion strategy is to retrofit to one of the core mass firing technologies listed above typically by adding a stoker or BFB bottom to an existing unit. In most cases, it’s not practical to retrofit an existing unit to CFB technology.
An alternative approach is to suspension-fire biomass. Co-firing is a suspension-firing technology that uses a dual fuel burner and finely prepared biomass. A dual fuel burner can fire biomass simultaneously with a main fuel (for example, pulverized coal) and share the same flame front. Co-combustion is the suspension-firing of finely prepared biomass and a main fuel simultaneously but through separate and fuel specific dedicated burners.
Partial-suspension firing is yet another combustion technique that makes use of raw, coarser biomass without a burner and involves the introduction of biomass through furnace ports or similar wall openings. With partial-suspension firing there will be less in-flight combustion and the remaining unburned char will fall to the furnace bottom. To burn out the char, the furnace hopper can be equipped with a dump grate. This last technique requires continual use of a support fuel.
Defining fuel characteristics and firing strategy is a crucial first step in a boiler conversion project. In order to determine the availability and certainty of fuel supply, one should consider whether the biomass be burned continuously, seasonally, occasionally, at a constant or variable rate or in some combination of these scenarios.
Biomass can be generally defined as anything that has recently been derived directly or indirectly from the photosynthesis process. While this definition can include animal wastes, this article focuses on wood product and/or grass product. Woody biomass includes whole tree wood chips, shrubs, bushes or other wood waste. Grassy biomass includes various grasses, straw and other thin vegetable matter. Grasses tend to be less dense than woody biomass, have lower energy per unit volume and can have challenging ash properties.
Biomass may be harvested raw (virgin), sized and delivered. Raw or harvested biomass material itself is less expensive than prepared biomass, but requires significant investment in on-site fuel handling and processing equipment. Raw biomass material may contain more than 50 percent moisture and be non-homogenous; that is, strands rather than particles. Grassy biomass is normally field dried to less than 15 percent moisture and then sheltered from rain.
An alternative to raw biomass is to align with a fuel supplier who processes the biomass into a prepared product. Prepared biomass can take the form of pellets, briquettes or a fuel dried and sized to specification. Biomass torrefaction, a process of low-temperature pyrolysis that improves fuel quality, is gaining industry interest due to the physical properties approaching those of coal. Dry prepared pelletized fuel also is much more suitable than raw biomass for co-milling and minimizes material handling equipment. A plant site assessment and an economic evaluation will help with fuel sourcing, preparation, material handling and delivery to the combustion equipment.
Fuel preparation requirements are driven by the combustion process, primarily residence time. Residence time is necessary for completion of combustion of gaseous products and char burnout. Mass firing technologies, such as stoker and BFB fired boilers, have long furnace residence times and can accommodate larger, as delivered (4-inch to 6-inch minus) fuel particles. Existing pulverized coal (PC) fired utility boilers have shorter residence times. Co-firing or co-combusting biomass requires a fine particle size (1/16-inch minus, or grass less than 2 inches in length). Because oversized biomass will not completely combust, the goal is to make as-fired fuel size as small as economically possible. Incomplete combustion reduces boiler efficiency and leads to higher fuel feed rates and increases in unburned combustibles (UBC) in the furnace and downstream ash collection hoppers. UBC in the ash may increase the potential for hopper, economizer, air heater, precipitator and/or baghouse fires, as well as ash disposal issues.
Once fuel has been determined, gaseous emissions should be considered. Evaluate uncontrolled emissions first and then consider post-combustion options. Match the combustion technology selection with air quality control systems (AQCS) to achieve the most cost-effective arrangement. NOX and CO are two emissions species that are combustion technology-dependent. Therefore, evaluate combustion and NOX control technologies simultaneously. The total evaluated project cost may not be obvious at the onset and the most cost effective arrangement may mean evaluation of multiple combustion/AQCS technologies scenarios.
One hundred percent virgin biomass firing lends itself to a stoker or BFB retrofit. Modern stoker units for biomass firing are normally water/air-cooled vibrating grates (see Figure 1, above) depending on the fuel moisture content. Wood firing on a grate is similar to that used for spreader-stoker coal firing. The wood is fed over the fuel bed and distributed uniformly across the grate area. Fine particles ignite and burn in suspension; the coarser fuel particles fall to the grate and combust on a thin, fast burning bed. Fuel is evenly distributed across the active grate area and combustion air is uniformly distributed through the grate. A portion of the total combustion air is admitted through ports above the grate as over-fire air (OFA).
A typical BFB furnace (see Figure 2, below) consists of a horizontal air distributor with an array of bubble caps. This provides the fluidizing air to the lower furnace bed material. The bubble caps are closely spaced so that airflow is distributed uniformly over the furnace plan area. The lower furnace is filled with sand or other noncombustible material such as crushed limestone or bed material from prior operation. Airflow is forced upward through the material and the bed expands. A high number of bubble caps and bed pressure drop promotes uniform airflow.
A BFB combustor has fluidizing air bubble caps and pipes mounted on widely spaced distribution ducts. Stationary bed material fills the hoppers and furnace bottom up to the level of the bubble caps, above which air fluidizes the bed material. The open spacing is effective in removing larger rocks and debris from the active bed area as bed material moves down through hoppers. This design is particularly attractive in biomass and waste fuel applications containing noncombustible debris.
The typical operating temperature range of a bubbling bed is 1,350 F to 1,650 F. Fuel moisture, ash analysis and alkali content affect combustion and ultimately stoichiometry controls bed temperature. Even at these low combustion temperatures, high convective and radiative heat transfer from the bed material to the fuel particles is sufficient to evaporate moisture, heat the ash and combust the remaining fuel without significantly changing the bulk bed temperature.
The retrofit of a stoker or BFB to an existing PC fired unit has its advantages. Fuel sizing requirements are more generous. Fuel handling is simpler and the unit can have up to 100 percent biomass firing capability. Further, both the stoker and BFB are independently bottom supported meaning new loads are not being added to existing steel. The limiting retrofit parameter is typically flue gas velocities or furnace residence time. Firing biomass, especially high moisture biomass can have gas weights 30 to 50 percent greater than coal. Convection pass velocities increase proportionally. With elevated gas velocities, the concern becomes erosion from particulate carryover and fouling potential. With 60 ft/sec convection pass velocities, a 30 percent steam flow derate can be expected.
There are many issues to consider when firing PC and biomass. Biomass inherently has a lower heating value, higher volatiles, higher moisture and lower ash content than coal. The moisture content delays ignition, lowers flame temperatures and lowers boiler efficiency. The lower biomass heating value means a higher fuel feed rate (material handling) to meet heat input requirements. Volatiles make biomass more reactive than coal; that is, they have twice the volatile matter, one-third to one-fourth of the fixed carbon and highly reactive char.
Some biomass combustion strategies may involve the existing coal pulverizers. In this article, the term co-milling refers to feeding coal and biomass to the mills, grinding the fuels simultaneously and then pneumatically conveying the pulverized blend to the burner(s). Co-combustion also can be applied with existing pulverizers, with one or more mills dedicated to biomass and the others to coal. The mills can be altered as necessary to improve biomass performance.
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Unprepared biomass, that is wood chips (or their equivalent) with minimal on-site preparation using existing pulverizers, inherently limits biomass firing capabilities. Generally, the biomass should be fed through all mills due to increased mill pressure drop and re-circulating load. Another fuel sizing option is to provide on-site biomass preparation. This requires substantial capital equipment (shredders, hammer mills and so on) and separate biomass and coal material handling systems. Prepared woody biomass can either be fed directly to dedicated burners or to separate axial nozzles in a dual fuel biomass/PC burner. Both grassy and woody biomass are pneumatically transported to the burners with a transport velocity greater than 3,000 fpm with an air/solids mass ratio of around 1.0.
When co-firing biomass and coal at low input rates (around 2 to 3 percent of fuel heat input) there are fewer concerns to boiler performance as coal dominates. But biomass co-milling, at even low input rates, can lower coal fineness and thus raise UBC. As biomass input increases, expect an overall reduction in heat input and boiler load due to lower heat content and reduced grindability. The primary air (PA) to solids loading will tend to increase resulting in a lower density, higher velocity fuel stream to the burners. Flame stability and turndown without igniters will become more difficult. Finally, increased unburned combustibles and boiler efficiency loss should be expected.
From a combustion equipment standpoint, biomass can be supplied to dedicated biomass burners and co-combusted in the furnace. Equipment layout, retrofit modifications and capital expense may result in firing limitations and/or compromise. The question arises as to which burners are best for biomass firing. A middle burner elevation provides better upsweep and reduces drop out, while interior burners (from the sidewalls) are better for burnout and flame stability. Unfortunately, concentrating biomass in these areas will raise overall furnace air/fuel balance issues. In addition, arranging burners in such a configuration can be an integration challenge on an existing unit.
When suspension-firing biomass, don’t exceed the rated burner input (coal plus biomass). If the strategy is to inject biomass into coal lines downstream of the pulverizer, high biomass inputs increase burner nozzle velocity and destabilize the flame. Pulverizer primary air can be reduced (within limits) to lower the nozzle velocity and achieve higher biomass inputs, but a reduction in coal throughput and possibly boiler load may result. Even with adjusted primary air-to-coal ratios, flame stability can suffer with higher moisture biomass.
If the strategy is to fire biomass through modified burners with dedicated biomass nozzles, low inputs are easily achievable. Small biomass nozzles can be retrofit into existing burners. Higher biomass inputs will require new burners and perhaps wall openings. The goals are to create a burner that can co-fire biomass and pulverized coal, fire pulverized coal alone when necessary, and fire either fuel or both with state-of-the-art NOX performance.
Partial suspension firing has less stringent biomass sizing requirements (less than 3/8″ x 3/8″ x 3/8″) and can be fired at rates up to 50 percent of boiler heat input. Partial suspension firing requires an auxiliary fuel (PC, oil or gas) and the furnace must have provisions for char burnout. Typically this would be a dump grate. Since partial suspension firing is a less sophicated technology, certain issues can arise. Should the biomass be extremely dry or fine the unit may exhibit significant carryover. Also, gaseous emissions may be more difficult to control.
Biomass co-firing or co-combustion may change the furnace and convection pass absorption characteristics based on biomass characteristics and firing rate. Firing biomass at rates greater than 5 to 10 percent total heat input requires a thorough review of all boiler components due to increased flue gas weight and volume. A detailed evaluation should be performed to determine how the existing convection pass (superheater, reheater and economizer), air heaters and fans are affected and what modifications may be needed.
Air Quality Control Systems
Regulatory agencies are pushing for tighter emissions targets. Emissions challenges arise when firing biomass due to the inherent variable nature of the fuel. Biomass particle sizing, variable moisture and intermittent/variable biomass input are transient phenomena that have to be addressed. Achieving NOX emissions equivalent to or lower than PC capability, reducing SO2, minimizing CO through proper air/fuel balance and minimizing unburned carbon through proper fuel sizing are often priorities to consider when choosing air quality control systems.
Biomass firing may require the control of carbon monoxide (CO), volatile organic compounds (VOCs), NOX and at times sulfur dioxide (SO2) and hydrochloric acid (HCl). CO and VOCs are controlled by good combustion. Stoichiometry controls NOX: a staged combustion air system provides approximately 15 to 25 percent NOX reduction.
Historically, post-combustion NOX control on biomass boilers (if required) was achieved with selective non-catalytic reduction (SNCR) technology. The SNCR process involves injecting ammonia or urea in a 1,600 F to 1,900 F gas temperature window to reduce uncontrolled NOX while producing water vapor and nitrogen. There are practical SNCR-based NOX reduction limits. Mixing of the reagent and reactant and residence time (in the 1,600 to 1,900F temperature window) are integral to the reaction process and critical for obtaining good reductions and reasonable ammonia slip.
SCR technology can achieve higher NOX reduction with lower ammonia slip values than SNCR systems. The conventional “high dust” SCR typical to PC units involves injecting ammonia in a 600F to 750F temperature window upstream of a catalyst surface. Again, the ammonia reacts with the NOX to produce water vapor and nitrogen. SCR catalyst manufacturers have deactivation concerns due to biomass flyash poisoning and unburned carbon carryover. To mitigate this concern, an alternative arrangement may be to place the SCR downstream of a particulate collection device. With the “low dust” arrangement, process temperatures and flue gas constituents such as SO2 also will need to be considered.
Woody biomass has low sulfur content, and inherent wood ash alkalis provide some SO2 and HCl emissions reduction. But some biomass can have relatively high sulfur and chlorine contents. In this case, SO2 control, if necessary, can be accomplished with reagent injection. Excess SO2 reagent reduces HCl emissions. HCl is preferentially removed over SO2 given the correct temperature window.
Either a baghouse or an electrostatic precipitator typically controls the particulate matter leaving the boiler system. The use of a baghouse, in lieu of a precipitator, enhances SO2 removal and other acid gases such as HCI due to the intimate gas-to-solids contact created within the filter cake.
The firing of biomass, whether alone or in combination with PC, may be a viable and attractive means for the existing boiler fleet to produce renewable energy. Each potential project has to be examined closely from a number of perspectives; it is not a simple matter of switching fuel. The project must consider biomass fuel availability, transportation logistics, fuel yard handling, and fuel variability sizing. Combustion technology considerations include adaptability to existing assets, fuel sizing requirements and uncontrolled emissions. The existing boiler and auxiliary equipment must be examined for much different thermal operating conditions. Finally, gaseous emissions must be evaluated opposite permits to determine AQCS equipment requirements. Only with a close evaluation of all these parameters will a practical and cost effective solution result.
Philip McKenzie is business development manager of biomass projects for Babcock & Wilcox Power Generation Group (B&W) Service Projects Division. He has 14 years’ experience in boiler design, field engineering services and project management. He is a member of AIChE. Mr. McKenzie earned a Bachelor of Science and Masters of Science in Engineering from the University of New Brunswick.
William Stirgwolt has 30 years experience with Babcock & Wilcox and manages the B&W Service Company Biomass & Waste to Energy Engineering group. He is a Professional Engineer and holds B.S. and M.S. degrees in Mechanical Engineering from the University of Akron.