The Babcock & Wilcox CompanyBR-1802

Technical Paper

Presented to:

CIBO Fluid Bed Combustion XX Conference 

May 21 - 23, 2007

Lexington, Kentucky, U.S.A.

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

The Babcock & Wilcox Company

Barberton, Ohio, U.S.A.
Bubbling Fluidized Bed or Stoker — Which is the 

Right Choice for Your Renewable Energy Project?

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 CO2 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 MWe 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 

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 

J.P. DeFusco, P.A. McKenzie and M.D. Fick

The Babcock & Wilcox Company

Barberton, Ohio, U.S.A.

Presented to:

CIBO Fluid Bed Combustion XX Conference

May 21 - 23, 2007

Lexington, Kentucky, U.S.A.

BR-1802
The Babcock & Wilcox Company

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) NOx, 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 NOx 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 NOx to produce water vapor and nitrogen. 

Today, there are increasingly more stringent requirements 

for NOx, SO2 and air toxins, even on projects firing clean 

wood fuels.

Higher NOx 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 NOx to produce water 

vapor and nitrogen. The SCR process achieves higher NOx
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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 (PM10) 

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 SO2 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 SO2 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 mainFig. 1 Flow schematic for a bubbling fluidized-bed boiler configuration.
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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.

Fig. 2 Flow schematic for a stoker-fired boiler configuration.
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© Copyright 2007 by The Babcock & Wilcox Company

a McDermott company

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