Bubbling Fluidized Bed or Stoker Which is the Right Choice for Your Renewable Energy Project?

Transcription

1 Technical Paper Bubbling Fluidized Bed or Stoker Which is the Right Choice for Your Renewable Energy Project? J.P. DeFusco, P.A. McKenzie and M.D. Fick Barberton, Ohio, U.S.A. Presented to: CIBO Fluid Bed Combustion XX Conference May 21-23, 2007 Lexington, Kentucky, U.S.A. BR-1802

2 Bubbling Fluidized Bed or Stoker Which is the Right Choice for Your Renewable Energy Project? J.P. DeFusco, P.A. McKenzie and M.D. Fick Barberton, Ohio, U.S.A. Presented to: CIBO Fluid Bed Combustion XX Conference May 21-23, 2007 Lexington, Kentucky, U.S.A. Abstract Current market conditions are providing multiple economic and environmental drivers to promote the use of renewable fuels including: A Federal renewable energy tax credit; State mandated Renewable Portfolio Standards (RPS) programs; Voluntary green up programs; Displacement of higher cost fossil fuels; and Biomass based power as CO 2 neutral. A viable renewable fuel in many parts of the country is wood-based biomass. There are many ways to drive useful energy out of biomass fuels. In regard to power production and or combined heat and power applications, a proven method is to convert the chemical energy in the biomass to thermal energy via gasification or combustion. This energy is transferred to a working fluid such as steam, which in turn drives a turbine generator, and/or provides heat to an industrial process. This paper will explore two different technologies available to convert the energy in wood biomass to do useful work in a power plant application. Both options involve the use of a steam generator. The fuel in both cases is identical it is assumed to be whole tree chips and primarily the low value attributes of the tree, which would be the tree tops, trimmings and bark. It is assumed that the high value section of the tree will be further refined to make lumber, furniture, or other higher quality, valued-added products, and not utilized for power production. For the purpose of this analysis, we assumed a constant fuel moisture content. Also, we did not consider any non-biomass fuels such as tire derived fuel (TDF), coal, or petcoke; the later two would normally drive the technology toward Circulating Fluidized Bed (CFB). For outputs of between 15 and 100 MW e and the conditions we have outlined, there are two conventional, commercially available technologies that could be considered Bubbling Fluidized Bed (BFB) technology and Stoker technology. While the boiler systems and designs are similar, there are distinct differences. This paper will explore the differences BR-1802 between these technologies in the areas of technical features, capital cost and Operating and Maintenance (O&M) costs. The results of this evaluation can be utilized to pick the appropriate technology for a specific project, given the same or similar design conditions. Review of stoker technology Stoker technology has been around for more than one hundred years, and was the means by which most of the early solid-fuel boilers were fired. These early generation boilers were stoked by an operator or fireman shoveling fuel in by hand. Ash was later removed by manually raking the grate. Modern stoker units for wood firing are normally mechanical rotating grates or water/air-cooled vibrating grates depending on the fuel moisture content. Fuel is typically introduced into the boiler through multiple fuel chutes. Air is supplied under the grate as well as above via an overfire air (OFA) system. Depending on the fuel moisture content, the combustion air is pre-heated to 350 to 650F. The combustion zone temperature is typically neither measured nor controlled and can range from 2200 to over 3000F. Due to high shaft velocities in the lower furnace and the throwing of fuel onto the grate for proper distribution with the stoker combustion process, a modern stoker unit will have unburned fuel carried over and out of the furnace. This carryover occurs by virtue of entrainment of unburned wood particles in the flue gas moving up through the furnace shaft. The unburned combustible loss leaving the boiler can be as high as 4 to 6% on a fuel efficiency basis. If not recovered, this unburned fuel results in efficiency losses, which increases the required fuel consumption and equipment costs. In order to recover what would have been a loss, stoker-fired boilers typically include carbon re-injection systems that recycle the

3 carbon-rich boiler ash back into the furnace. Sand classifiers are also typically required to separate out the high abrasive silica content of the flyash before re-injection into the furnace. These re-injection systems are high maintenance items and have been shut down at many plants. A mechanical dust collector is also typically installed to prevent any heavy particle carryover from reaching the precipitator. Concerns over unburned carbon carryover, and the potential fire hazard that can result, usually dictate that a precipitator be used for particulate control in stoker applications. The precipitator is used instead of a baghouse, due to concerns about hot carryover particles possibly igniting the bags. Review of fluid bed technology The term fluidized bed is derived from the process that takes place in the lower part of the boiler. The lower furnace or bed of a BFB boiler is charged with an inert medium such as sand, which is initially brought up to temperature by using auxiliary fuel. Once at temperature, the auxiliary fuel is shut off and biomass is introduced into the unit. The high pressure air introduced under the bed fluidizes the sand/bed, i.e., it takes on characteristics similar to a fluid. This is distinctly different from a stoker because the bed creates a large mass of hot material that is able to absorb fluctuations in fuel conditions with little to no change in performance. Another distinct difference is that the BFB bed temperature is both measured and controlled to an optimum temperature of approximately 1500F. Bed temperature is typically controlled by staging (adding or removing) air to the bed, fuel feed adjustments and/or the use of flue gas recirculation (FGR). Maintaining a nearly constant bed temperature minimizes boiler upset conditions due to fuel variations (moisture, ash, heating value, etc.) providing near steady-state conditions for boiler performance and emissions. The lower furnace combustion process is characterized by operating in sub-stoichiometric condition, i.e., at significantly less than the total air needed to complete combustion. It is not unusual to operate at 35% of theoretical air. This has the effect of gasifying the fuel. The gasified fuel is then fully combusted with overfire air introduced above the bed. This process is sometimes described as close-coupled gasification, because the gasification process and heat transfer apparatus are close coupled to each other. This differs from a synthetic gas process where the gas product may be fired in an engine or gas turbine located downstream from the gasifier. Close-coupled gasification is more common in biomass applications due to the high volatile matter content of biomass fuels and problems associated with the tar byproducts. Like the stoker, fuel is typically introduced into the BFB through fuel chutes on one or more of the walls. Because less under-bed air is used compared to a stoker, velocities in the bed are lower. Mechanical attrition of the fuel due to the bed fluidization, coupled with the lower bed velocities, minimizes the potential for any significant large-particle unburned carryover from the BFB. The unburned combustible loss leaving the boiler is less than 1% on a fuel efficiency basis. Because there is little to no carryover, BFB systems do not usually have carbon re-injection systems since there are no cinders to capture and re-inject. This also eliminates the need for mechanical dust collectors (MDC) downstream of the boiler. Without the concern for large particle carryover from a BFB, a baghouse is the technology of choice for particulate removal as compared to a precipitator for the stoker application. Uncontrolled emissions Due to the improved combustion process previously described for a BFB, the uncontrolled (upstream of any post combustion air quality control systems) NO x, CO and VOC emissions for a BFB are typically 10 to 25% less for a given biomass fuel than for a stoker. The BFB emissions are also less susceptible to variations in fuel properties that are inherent with any biomass plant. Under normal steady state operating conditions, both the BFB and stoker can be operated reliably within permitted emission limits. However, normal day-today operations in a typical plant are anything but steady state. Fuel variability is a fact of life, even when a conscious effort is made in the fuel yard to keep the fuel homogeneous. The large mass of bed material in the BFB creates a flywheel effect, which is better suited to minimize spikes in emissions due to any changes in fuel characteristics. Conversely, the relatively low fuel inventory on a grate will typically be much more susceptible to an upset and potential emissions spikes, under changing fuel conditions. The fuel ash distribution is different between a BFB and a stoker. The typical distribution in a stoker is approximately 35% bottom ash / 65% flyash; in a BFB almost all the fuel ash becomes flyash. This shift does not usually affect the size of the particulate control devices since that equipment is typically sized based upon flue gas flow, but should still be a consideration for the particulate control system and its associated ash handling system. Post-combustion emissions considerations Regulatory agencies continue to push the envelope regarding emissions. Currently, best available control technology (BACT) for post-combustion NO x control would normally be considered Selective Non-Catalytic Reduction (SNCR) for biomass fuels. The SNCR process involves injecting ammonia in a 1600 to 1900F temperature window in the furnace to react with the NO x to produce water vapor and nitrogen. Today, there are increasingly more stringent requirements for NO x, SO 2 and air toxins, even on projects firing clean wood fuels. Higher NO x reduction along with a lower ammonia slip can be achieved with Selective Catalytic Reduction (SCR) as compared to SNCR. The SCR process involves injecting ammonia in a 600 to 750F temperature window upstream of a catalyst surface to react with the NO x to produce water vapor and nitrogen. The SCR process achieves higher NO x 2

4 reduction rates along with lower ammonia consumption and slip values, as compared to an SNCR. While there is limited SCR experience in this country on wood-fired boilers, there is a growing experience base in Europe. The SCR catalyst manufacturers remain concerned about exposing catalyst to unburned carbon carryover coming from a typical stoker unit. Conversely, the growing experience in Europe supports the use of a conventional SCR located behind a BFB when burning clean wood that will result in a catalyst life that would be acceptable to most operating companies. As previously discussed, the particulate matter (PM 10 ) leaving the stack is controlled by either a baghouse for a BFB or an MDC and electrostatic precipitator for the stoker. Another benefit of the BFB, which utilizes a baghouse in lieu of a precipitator, includes the additional removal of SO 2 and other acid gases such as HCl from the flue gas. The bags of the baghouse serve as a good gas-to-solids contact device. Alkalis inherent to the wood ash contribute as a reagent to provide reduction of SO 2 and HCl emissions. System design and layout B&W recently engineered a 400,000 lb/hr steam capacity boiler island configured as both a BFB and as a water-cooled vibrating grate. The boiler design basis was identical. The project terminal points were consistent between the two technologies and the scope differences resided in the description outlined below. In general, equipment sizing and layout are comparable between a steam generator configured with a BFB combustor and that with a water-cooled vibrating grate. Flow schematics of the BFB and stoker configurations considered are depicted in Figures 1 and 2 respectively. For the size considered in this paper, furnace dimensions were approximately the same. For larger steam capacity units configured with stoker combustors, the furnace plan area is dictated by the ability to adequately distribute the fuel on the grate. Typically the fuel delivery is arranged on the front wall and is thrown towards the rear of the unit. With air-swept spouts the practical throw distance is limited to approximately 26 ft and larger furnace configurations must be achieved by the less economical approach of widening the furnace. BFBs, on the other hand, have the ability of adding fuel from any wall as well as multiple wall feed configurations. This flexibility allows BFBs to maintain an economical furnace aspect ratio through a very large capacity range. The boilers have similarly configured convection passes and back-end heat traps. The superheater and generating banks are arranged similarly and have approximately the same heat transfer surface. Due to higher combustion air temperature requirements the stoker arrangement has more tubular air heater surface. Consequently, the BFB is arranged with a larger economizer. In general, convection pass surface is designed for lower flue gas velocities in the BFB. Tubular air heaters on the BFB are designed for gas-over-tube construction. Auxiliary equipment including fuel feed, feedwater, desuperheat, boiler cleaning, boiler trim, flyash removal, and stack are basically the same for both configurations. The BFB requires auxiliary fuel to attain solid fuel ignition temperature. This is accomplished by firing either fuel oil or natural gas in dedicated start-up burners. The stoker, while not always practical, can be started from a cold condition without the use of auxiliary fuel. Most BFBs are equipped with a dedicated sand addition and reclaim system. Proper bed inventory and sizing are main- Fig. 1 Flow schematic for a bubbling fluidized-bed boiler configuration. 3

5 Fig. 2 Flow schematic for a stoker-fired boiler configuration. tained via the bed sand drain system. Stokers are equipped with bottom ash systems to collect the unburned and tramp material from the grate. Capital cost comparison For the 400,000 lb/hr capacity boiler island, within the accuracy level of our budget estimate, we found the capital cost of the two systems to be essentially the same, with the BFB system being slightly less than the stoker system. The project terminal points were consistent between the two configurations, and as such scope differences resided in the combustion and auxiliary equipment as outlined above. While the absolute costs can be subject to differences in the steel market, labor, etc., the relative cost comparison for a snapshot in time is insignificant. Comments on operating cost differences The BFB technology requires high pressure air in order to fluidize the bed. This creates an additional parasitic load burden on the forced draft fans when compared to the undergrate air to the stoker. That being said, the flyash reinjection system required for a stoker is an area of high maintenance as well as an additional blower operating cost. Also, the stoker convection pass, tubular air heater and mechanical dust collector have higher gas-side pressure drop, which increases the parasitic load required for the induced draft fan. Due to the fuel mixing and controlled combustion process inherent to the fluidized bed, on a day-in day-out basis, BFBs tend to operate at lower excess air levels. This coupled with lower loss on ignition (LOI) results in higher boiler efficiency, correspondingly less fuel is consumed, and there are power savings associated with the lower gas weights. In regard to the backend equipment, there is a significant electrical usage associated with an electrostatic precipitator (ESP) compared to a baghouse, though a baghouse normally has more gas-side pressure drop. Sand usage and make-up is a process stream unique to the BFB. Bed drain rates, sand attrition and elutriation from the bed are fuel dependent. The bed inventory initial charge and make-up are typically commercially insignificant process streams, but if sand usage becomes high there are manmade substitutes which can decrease the make-up quantity required. When all these factors are combined, the electrical load to the ESP and decreased fuel costs from higher boiler efficiency can offset the higher fan power requirements of the BFB and our analysis shows that the BFB has lower overall operating cost than the stoker. Conclusion There may be compelling reasons beyond those noted here for choosing one technology over another, but for the design basis as specified in this paper, which amounts to a typical woody-biomass fuel, we would conclude that weighing all factors including total capital cost of the boiler island, total system O&M, and environmental concerns, Bubbling Fluidized Bed Technology was evaluated as the preferred technology. There certainly may be other situations such as the case of a very dry fuel where a stoker unit may be preferable, but for the above case, which is based upon a typical woody-biomass fuel, BFB was evaluated as the preferred technology choice.

6 Copyright 2007 by All rights reserved. No part of this work may be published, translated or reproduced in any form or by any means, or incorporated into any information retrievalsystem, without the written permission of the copyright holder. Permission requests should be addressed to: Market Communications,, P.O. Box 351, Barberton, Ohio, U.S.A Disclaimer Although the information presented in this work is believed to be reliable, this work is published with the understanding that and the authors are supplying general information and are not attempting to render or provide engineering or professional services. Neither nor any of its employees make any warranty, guarantee, or representation, whether expressed or implied, with respect to the accuracy, completeness or usefulness of any information, product, process or apparatus discussed in this work; and neither nor any of its employees shall be liable for any losses or damages with respect to or resulting from the use of, or the inability to use, any information, product, process or apparatus discussed in this work.