Before discussion of advanced, biomass combustion systems, it is in order to consider electric power generation with biomass fuels because several advanced technologies are being used or are planned for this application. A typical utility boiler consists of a furnace, where heat is transferred to enclosed water-cooled tubes, and a convection section, where more heat is transferred to the water tubes. Steam superheating can occur, and various economizers and recupera­tors may be installed. The steam is produced at rates of about 100 to 4500 t/ h and converted to electric power in high-speed steam turbine generators, which range in capacity from about 20 to 1300 MW. In the United States, a very high percentage of electric power generation by utilities is by turbine — generator systems in which steam is expanded in variations of the Rankine cycle (Miller and Allen, 1985). This cycle, originally developed with steam engines, closely approximates the Carnot cycle when used with low-pressure steam. As pressures increase to obtain higher saturated steam temperatures, the Rankine cycle does not improve as much as the Carnot cycle because the low-temperature heat being added to bring the condensate back to boiler saturation temperature becomes a major portion of the total heat content of the saturated steam. But with regenerative feedwater heating and reheating the steam after it has been partially expanded through the turbine, Rankine efficiencies can approach Carnot efficiencies. Overall thermal efficiencies for power production usually range from about 28 to 34%. Some plants have been reported to operate at up to 40% overall efficiencies. The thermal energy in terms of fuel consumption needed to generate 1000 kWh of electricity is assumed in most U. S. tabulations in non-SI units to be about 1.8 bbl of crude oil, 0.47 ton of coal, 0.6 ton of dry biomass, or 10,000 ft3 of natural gas. This is equivalent to thermal energy consumption of about 11 MJ/kWh (10,400 Btu/kWh). Fossil-fueled steam-electric plants typically use about 10.5 to 12.7 MJ (10,000 to 12,000 Btu) of fuel input per kilowatt-hour gen­erated.

At full load, one of the largest single-boiler, stoker grate, wood-fueled, electric utility plants—a central station power plant in Burlington, Vermont that generates 50 MW of net production—consumes dry equivalent wood at a rate of 925 t/day (Tewksbury, 1987). Net electrical production was re­ported to be 280,137,900 kWh for a total green wood fuel consumption of 394,612.9 tonne (435,060.7 ton) at 50 wt % moisture over a 1-year period. At an average energy density of 18.6 GJ/t (16.0 million Btu/ton) for dry wood, this corresponds to thermal energy consumption of 13.10 MJ/kWh (12,424 Btu/kWh) generated and a thermal efficiency of 27.5%. The opportuni­ties for fuel savings in conventional electric power generation facilities are obvious. Note that at 100% resistance heating efficiencies, 1.0 kWh is equiva­lent to 3.60 MJ (3412 Btu) of thermal energy independent of the generating process.

Modem fossil-fired plants typically have capacities from 300 to 900 MW; 600 MW is the approximate average for U. S. utilities (Miller and Allen, 1985). Some plants have been built with capacities of 1300 MW. Steam conditions have effectively been standardized at 16,500 kPa and initial temperatures of 538°C with reheat to 538°C. Some plants utilize supercritical pressures of approximately 24,100 kPa, mostly with steam temperatures at 538°C/538°C. Some plants also utilize double-reheat and steam temperatures up to 565°C. A few advanced plants were designed to operate with steam pressures up to 34,500 kPa and steam temperatures up to 650°C. The net heat rate and the labor cost and investment per kilowatt-hour decrease with increasing plant size, so larger plants are desirable.

Biomass-fired boilers are typically limited to steam production rates up to 227 to 273 t/h (250 to 300 ton/h) according to some analysts because of fuel availability, fuel cost considerations, and materials handling difficulties associated with low-density fuels (Tillman, 1985). This restriction in turn limits the maximum economical pressure to about 10,300 kPa compared to coal-fired units, which range from 16,500 to 24,100 kPa, increases the steam rate requirement, and limits the number of feedwater heaters to 1 to 4, com­pared to the 8 feedwater heaters commonly associated with fossil-fired units. The characteristics of biomass power plants shown in Table 7.4 illustrate how these limitations can affect the technology. Biomass-fired cogeneration power plants usually have capacities in the range 5 to 25 MW, whereas condensing power plants have capacities up to 60 MW. Cogeneration is the simultaneous conversion of thermal energy into electrical energy and some other form of

energy. For example, steam produced in a boiler drives a steam turbine to generate electric power, and the waste heat is recovered and used for heat or process steam production. The overall thermal efficiency is higher because of the recovery of additional, useful energy. From a practical standpoint, the availability of fuel at a sustainable, competitive price is probably the most important factor that determines plant size.

The 50-MW plant in Burlington, Vermont, was limited in capacity by the wood fuel available within the area circumscribed by a radius of 80 km (50 mi.) from the plant. This is considered by most energy specialists to be the maximum distance that wood fuel can be obtained and economically transported to the plant by truck or rail. For captive sources of biomass fuels, the capacity can be larger. One example is the 60-MW, wood waste-fueled power plant located in Williams Lake, British Columbia (Baker, 1995). This plant is located in the center of a major lumber industry region that has five large sawmills located within 5 km of each other. The mills produce more than 540,000 green tonnes of bark, sawdust, and other wood waste products per year.

Efficiency improvements in the conversion of thermal energy to electric power are a direct route to increasing power plant capacity. Several techniques have been developed that offer large improvements in efficiency. Among them is the combined cycle configuration. In one configuration of a combined cycle plant, a combustion turbine drives a generator and the hot exhaust is fed to a heat recovery steam generator. The steam from this unit drives a steam turbine generator and the exhaust is used to provide process steam or is condensed and returned to the heat recovery steam generator. There are many variations of this design. Integrated gasification-combined cycle (IGCC) con­figurations for coal-fired systems are an example. IGCC systems are also appli­cable to biomass feedstocks and will be discussed in Chapter 9. The systems can be designed to operate at an overall energy conversion efficiency consider­ably larger than the sum of the efficiencies of separate systems that convert the same total quantity of fuel to electric power. Some projections indicate that overall thermal efficiencies as high as 70% might be possible.

Another approach to increasing power plant efficiencies is to use a nonther­mal conversion method for power production, such as fuel cells. Fuel cells rely on electrochemical conversion of the chemical energy in the fuel to electric power. In the cogeneration mode, these systems have been reported to be operable at overall efficiencies as high as 85% (Schora, 1991). Large-scale power plants based on fuel cells have not been developed yet and are not expected to be available for generating central station power until well into the twenty-first century.

The U. S. Department of Energy has developed a strategic plan that delineates how electric power generation from biomass can be significantly increased in

the U. S.A. (U. S. Dept, of Energy, 1996). The U. S. biomass power industry in the mid-1990s represented an investment base of $15 billion and supported about 66,000 jobs. DOE’s projections indicated the potential for biomass power to grow to an industry of 30,000 MW employing 150,000 persons in mainly rural areas and producing 150 to 200 billion kWh by the year 2020. This would require 127 million tonnes of dry biomass fuel annually according to DOE’s estimates, which is equivalent on a gross energy content basis to about 2.36 EJ/year and the annual gross generation of about 223 billion kWh at 85% availability and 33% overall thermal efficiency. If the required fuels were all dedicated biomass energy crops, 80,940 km2 (8.1 million ha) of growth area would be required at a conservative yield of 15.7 dry t/ha-year. Various strate­gies have been proposed to achieve the 30,000-MW target, including the cofiring of biomass fuels and coals as a bridging strategy. For example, the cofiring of wood wastes in coal-fired utility boilers has the potential to reduce fuel costs, support local economic development, and address environmental concerns (с/. Tillman et ah, 1995).

The most realistic approach to attainment of 30,000 MW of on-line biomass power in the United States within the next few decades is to develop large — scale, integrated biomass production-conversion systems that operate at high overall thermal and net energy production efficiencies (Chapter 14). This is perhaps the only practical approach, although efficiency improvements in power generation via advanced combined-cycle schemes and high-efficiency, nonthermal generation with fuel cells will help reduce the amounts of dedicated energy crops needed. Energy crop yields and costs are most certainly primary factors in achieving the 30,000-MW target.

A contrasting viewpoint is that large-scale, biomass-fueled power generation systems are unlikely to be economically competitive with natural gas or coal — fired generation, but that they can fill important niche markets, especially via distributed generation (Whittier, Haase, and Badger, 1996). Distributed generation is defined as any modular technology that is sited throughout a utility’s service area—interconnected to the distribution or subtransmission system—to lower the cost of service. They typically have capacities less than 50 MW. Distributed generation is claimed to provide multiple benefits to utilities and end users, including lower capital costs and reduced financial risk compared to those of the larger generation systems; deferral of upgrades to substations; provision of power in increments that match projected demand patterns; and various forms of grid support. Other advantages are that the logistics of sustaining operations are simplified and most of the biomass conver­sion technologies qualify as distributed generation candidates.

Assessments of commercial biomass power technologies indicate that oppor­tunities exist, particularly for niche market applications, when the business conditions are right. Federal legislation can have a large impact on these opportunities. For example, the U. S. Public Utilities Regulatory Policies Act of 1978 (PURPA, PL 95-617) created a utility market for independent, nonutility power producers by requiring public utilities to purchase power from them at the so-called avoided cost, or the utility’s cost of purchasing or generating the power itself. Many small power producers and cogenerators took advantage of this arrangement by generating power for on-site use and selling the surplus to the local utility. One technology that fared quite well under PURPA, when Standard Offer contracts in California allowed independent power producers to lock in payments that started at $0.08 to $0.09/kWh, is bubbling, fluid-bed combustion. It was a key technology that allowed plants to achieve favorable economics in a changing regulatory and fuel price environment. The flexibility of 3 such plants (net capacities of 10,10, and 25 MW), for example, permitted them to accept a very wide range of biomass fuels and to meet California’s strict emissions requirements using ammonia injection and limestone additive for NOx and SOx control over a 7-year operating history (Ferris, 1996). When scheduled shutdowns and reduced loads were required by the utility that purchased the power, the advanced designs of these plants made it possible for them to be operated as peaking units after the utility offered payments up to $0.06/kWh under curtailment contracts.