Biomass is big in the UK. The 4,000-MW Drax Power Station recently completed a retrofit that allows it to blend biomass with coal using the existing emergency coal reclaim hopper. Together, the 100-MW blending and the new 400-MW direct injection system provide 500 MW of biomass generating capacity.
This photo shows the handling and storage area of the biomass cofiring system during construction. The facility uses wood pellets that are delivered by rail. Bottom dump rail cars are unloaded, and the pellets are stored in four silos. The wood pellets are reclaimed and conveyed to a fuel feed bin and then pneumatically conveyed and injected into the combustor. Courtesy: Energy Associates
Designing Fuel Systems for Large Biomass Plants.
The European Union (EU) has set firm goals for renewable energy consumption, and all member states are expected to supply 20% of their energy requirements by 2020 from sustainable forms of energy. Those renewable options include wind, landfill gas, and biomass; solar, geothermal, and wave power are also expected to contribute small amounts.
Because of the EU’s renewable energy requirements, some European coal-fired plants have implemented or are developing programs that will add biomass to their fuel mix. In the United Kingdom (UK), what appears to be the largest cofiring project was recently brought online by Drax Power. Its 4,000-MW coal-fired Drax Power Station in Selby, North Yorkshire, is the largest coal-fired station in the UK and provides enough power to meet 7% of the UK’s electricity needs. (See “Drax Offers Model for Cofiring Biomass,” July 2010.) Drax Power began experimenting with a system that blends biomass with coal, using the existing emergency coal reclaim hopper. Based upon the success of this project, Drax Power recently completed an £80 million ($150 million) direct biomass injection system. Together, the 100-MW blending and the 400-MW direct injection systems provide 500 MW of biomass generating capacity
Compared with other solid fuel–fired plants, the systems and components required for handling and processing biomass appear quite familiar, but important fuel differences must be considered. A successful biomass plant design must provide flexibility for handling the expected wide range of biomass fuel properties and characteristics.
Power plant owners and developers have multiple ways to include biomass as a fuel in their fleets. Cofiring—adding biomass generation to existing coal-fired plants—is a relatively inexpensive option. For large units, the simplest approach is to cofire biomass with coal. (For an example, see “OPG Charts Move from Coal to Biomass,” April 2010 in POWER’ s online archives at http://www.powermag.com.) Biomass can also be added to a plant that has smaller, older, inefficient coal-fired units: One or more old units can be replaced by a modern, efficient boiler that is designed to best utilize solid fuels, including biomass. Greenfield plants are a third option, but they take more time to bring online and obviously involve additional siting complexities.
Whichever option a plant owner chooses, designing a plant, or its retrofit, with the special characteristics of biomass in mind is critical for successful use of the various forms of this renewable fuel. Those characteristics affecting plant design are the focus of this article.
Cofiring in a Utility Boiler
Many utilities have a fleet of existing multi-unit coal-fired power plants. The easiest way to add biomass to the fleet is to adapt those existing plants to burn biomass. Although doing so requires plant additions and modifications, compared with starting from scratch, modification for cofiring is a relatively low-cost option. This can be practical when the amount of biomass available is relatively modest. Approximately 4% to 5% biomass can be blended with the reclaimed coal, especially if the unit has spare mill capacity. At increased percentages of biomass, direct firing is advantageous. In fact, boiler capacity can actually be improved by biomass cofiring when unit generation is limited due to wet coal.
Beginning in 1996, the Electric Power Research Institute and the U.S. Department of Energy (DOE) began a biomass cofiring research program that continues today. Demonstration projects were conducted at several pulverized coal (PC) and cyclone plants. The program tested biomass cofiring with heat input rates up to 10%. The amount of biomass that was cofired varied with the method of biomass feeding; it was either blended directly using the coal reclaim system or separately injected directly into the furnace.
Normally, adding biomass to the fuel matrix decreases boiler efficiency. This decrease in efficiency is a function of the biomass characteristics and unit design parameters. The dominant reasons for this decrease are the fuel’s higher moisture content and the hydrogen/carbon atomic ratios in biomass, as compared with those of coal. The latent heat of vaporization for moisture, and the pyrolysis of oxygen and hydrogen components of biomass into moisture, have been shown to reduce boiler efficiency by 2% at the 20% cofiring level on a mass basis.
Air emissions are also affected by cofiring biomass. Biomass cofiring typically reduces SOx and NOx emissions due to the biomass fuel’s lower nitrogen and sulfur content when compared with coal. The lower ash content in biomass can reduce particulate emissions, but the resistivity of biomass fly ash may be a factor in plants using an electrostatic precipitator.
With cofiring, the risks of adding biomass to a generation fleet are reduced in comparison with other technologies. When cofiring biomass, the availability of biomass itself is not a critical issue. Biomass can be used when supplies are plentiful and economics are advantageous, but the plant can easily return to firing 100% coal when biomass supplies are low or conditions are otherwise unfavorable.
So if costs and risks are relatively low, why aren’t hundreds of utility plants cofiring biomass? The answer, at least in part, is that cofiring with biomass is more expensive than using just coal, for three reasons:
* Biomass handling and firing systems must be added to the plant.
* On a $/million Btu basis, biomass fuel is typically more expensive than coal.
* The higher moisture content of biomass will result in a higher heat rate for the unit, thereby increasing the amount of fuel that must be consumed.
From PEI Magazine
No comments:
Post a Comment