The Cruciality of Combustion Technology

Proper selection of combustion technology is critical to biomass power. An expert reviews current options, along with pros and cons.
By Brandon Bell | August 22, 2012

With increasing pressure from the U.S. EPA to reduce emissions from fossil fuel-fired power plants, and states requiring an increasing amount of renewable capacity, biomass power generation has evolved into a more viable power option. According to U.S. Energy Information Administration’s Annual Report released in November 2011, a total of 147 new biomass sources are expected to be built between 2011 and 2013.  Planned generating capacity additions for wood and other biomass sources are predicted to reach 377 MW by 2013, compared to 290 MW from coal and 224 MW from hydroelectric.

With these increases in biomass capacity, proper selection of combustion technology is critical for plant performance and economics.

Stoker Boilers

One of the oldest forms of combustion technology available, stoker firing has proven to be reliable and rugged under a wide range of fuels and operating conditions. In a stoker boiler, fuel is introduced onto a grate where the combustion process occurs. This grate and the fuel feed system are the defining factors of a stoker boiler, with many variations being designed over the years. From fixed hearths to traveling grates and now vibrating grates and mass feed to spreader stokers, each type has been developed to accommodate a multitude of fuels. Stoker-fired boilers typically benefit from low auxiliary power requirements and compared to other combustion technologies, generally exhibit reduced capital expenditure costs. A major drawback to the stoker boiler, however, is an unfavorable emission profile. Due to the design of a stoker, they have an inherent problem of generating high amounts of carbon monoxide (CO) and nitrogen oxides (NOX).

Fluid Bed Combustors

Another popular combustion technology for biomass power generation is a fluid bed combustor. In a fluid bed combustor, an inert medium such as sand, commonly referred to as the bed, is heated to a temperature greater than the combustion temperature of the biomass fuel. Underneath the bed, high pressure combustion air is introduced at a rate that reduces the contact forces between particles created by gravity. As more combustion air is introduced and higher velocities are achieved, drag forces on the particles will counteract gravity. At this point, the particles are suspended in an upward stream, the bed increases in height, and due to the non-uniform formations, the bed exhibits liquid-like properties, or fluidization.

There are two popular types of fluid bed combustors used for biomass combustion. The first is referred to as a Bubbling Fluidized Bed boiler. In a BFB boiler, the velocity and volume of air in the bed increases to the point of bubble formation below the bed. With the bed of the boiler fluidized and the bubble formations approaching the surface, the appearance of a liquid boiling is observed. Air velocities are controlled such that suspended particles retain fluid-like properties without leaving the bed.

The second style of fluid bed combustors is referred to as a circulating fluidized bed boiler. In a CFB boiler, the air velocities and volume are increased to even greater velocities than that of a BFB boiler to promote solid elutriation from the bed. To recover solids lost from elutriation, the gas stream passes through a solids separation device after leaving the furnace. The collected solids are returned to the bed for reuse in the combustion process.  This elutriation and return process gives the appearance of a constant stream of particles circulating in the boiler.

A major benefit to a fluid bed combustor is the ability to precisely control the bed temperature to inhibit the formation of thermal NOX.  High turbulence also reduces the formation of carbon monoxide.  A fluid bed combustor may also utilize a bed medium such as limestone in order to reduce sulfur dioxide emissions. The bed is typically drained on a continuous basis to remove bed ash and foreign material in order to optimize performance. Fluid bed combustors are also able to burn a wide range of fuels for the combustion process, however, all of these benefits are at the expense of higher auxiliary loads and capital cost.

Suspension Boilers

More than 40 percent of the electricity generated in the U.S. comes from the combustion of coal.  By far, the most common coal combustion technique used by utilities is suspension firing. As states mandate more renewable energy sources, existing coal boiler operators are modifying their equipment to handle mixtures of biomass and coal. In suspension firing, fuel is ground to the consistency of flour. This finely-sized material is conveyed pneumatically to a set of burners located in the furnace walls of the boiler, and once the fuel is introduced into the furnace, the combustion process takes place where solid particles are passing through the high temperature region, or flame basket.
Cofiring biomass in an existing coal unit can be attractive as the modification and capital costs associated may be relatively modest.  In most coal boilers, emission control systems are typically already in place to clean up pollutants generated in the combustion process. Some drawbacks to utilizing suspension firing of biomass are the limited range of fuels suitable for this application, and potential for unit de-rating.  Additionally, fuel constituents—particularly chlorine—can accelerate boiler tube corrosion and promote slag formation.


Gasification has been used for producing synthetic natural gas, or syngas, since the 1800s. In biomass gasification, an organic solid feedstock is heated in a sub-stoichiometric environment to convert the solid feedstock into a combustible gas. This combustible gas is then burned either in a boiler to generate steam or in a reciprocating engine or combustion turbine. The primary advantage of gasification is the ability to achieve higher temperatures and thus greater thermal efficiency than direct combustion of the biomass feedstock.


In an anaerobic digester, biomass is converted from a solid waste to a usable gas that is then used to produce power. Typically this process occurs in three steps. The first is the hydrolysis of biomass into usable molecules such as sugar. Next, the decomposed matter converts into various organic acids, which are then converted into a methane gas. This methane gas is captured and combusted in a boiler to generate steam and produce power. A drawback to this process is its sensitivity to lower temperatures, and a key benefit to a digester is that almost any biological material may be used to produce the methane gas. The feedstock’s digestibility, however, will determine the amount of gas yielded.

Combustion technology selection depends on biomass fuel type, availability and selection, desired facility performance envelope, and underlying project economics. For upcoming biomass power projects, selection will be critical for maximizing return while maintaining a low emission profile. As environmental regulations evolve for fossil fuel power generation and utilities are mandated to increase their renewables portfolio, biomass power generation will use existing combustion technologies while continuing to develop new methods to convert biomass into electricity.

Author: Brandon Bell
Principle Mechanical Engineer, KBR Power & Industrial


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