تويت
The construction of nuclear power plant capacity in the United States has been suspended for over a decade. Current construction activities in the nuclear power arena include completing delayed nuclear units and converting existing or partially completed units to fossil fuels. The costs associated with delays and the reengineering required to adapt units to new fuels and thermodynamic cycles is not indicative of the cost associated with committing new nuclear units today. A new generation of smaller light-water reactor nuclear power plants is currently in the design stage. Costs associated with these units, including siting, licensing, and fuel cycle, remain unclear, as they are precommercial. The earliest units will not be offered until the late 1990s. However, they are the basis for nuclear capacity in this section as they are the most likely nuclear units to become commercial in the future. They utilize preengineered designs to reduce construction and licensing time.
In general, light-water reactor nuclear plants require considerably higher investments than do fossil-fueled plants, reflecting the need for leakproof reactor pressure containment structures, radiation shielding, and a host of reactor plant safety-related devices and redundant equipment. Also, light-water reactor plants operate at lower initial steam conditions than do fossil-fueled plants and, because of their poorer turbine cycle efficiency, require larger steam flows and increased equipment sizes at added investment.
Both light-water reactor plants and conventional fossil plants evidence declining unit cost with increasing size. The economy of scale has been demonstrated most strikingly in the nuclear field where orders for units at the 1,200-MW size level had predominated. The utilization of large-size units has been made possible by the interconnection of utility transmission and distribution systems, many of which have grown to levels capable of absorbing large individual units without assuming economic penalties for the reserve equipment required to assure service continuity in the event of unscheduled outages.
Combustion Turbine/Combined-Cycle Plants
Packaged combined-cycle plants are offered by a number of vendors in the 100- to 600-MW size range. These plants consist of multiple installations of combustion gas turbines arranged to exhaust to waste-heat steam generators which may be equipped for supplementary firing of fuel. Steam produced is supplied to a conventional nonreheat steam turbine cycle. Advantages of combined cycles are lower unit investment costs, efficient thermal performance, increased flexibility (which allows independent operation of the gas-turbine portion of the plant), shorter installation schedules, reduced cooling-water requirements, and the reduction in sulfur oxide and particulate emissions characteristic of gaseous fuels.
Hydroelectric Plants
Hydroelectric generation offers unique advantages. Fuel, a heavy contributor to thermal plant operating costs, is eliminated. Also, hydro facilities last longer than do other plant types; thus they carry lower depreciation rates. They have lower maintenance and operating expenses, eliminate air and thermal discharges, and because of their relatively simple design, exhibit attractive availability and forced-outage rates. Quick-start capability and rapid response to load change ideally suit hydro turbines to spinning reserve and frequencycontrol assignments.
The constructed cost of a hydroelectric station is strongly site dependent. Overall costs fluctuate significantly with variations in dam costs, intake and discharge system requirements, pondage required to firm up capacity, and with the cost of relocating facilities within the areas inundated by the impoundments. For a given investment in structures, available head and flow quantity may vary considerably, resulting in a wide range of outputs and unit investment costs. Installed plant costs reported by the Department of Energy for hydro plants include a $398-per-kilowatt investment for the 140-MW Keowee Plant in South Carolina, completed by Duke Power Company in 1971. The Northfield Mountain Plant of Western Massachusetts Electric Company, completed in 1973, carries an investment cost of $145/kW owing to a high gross head and smaller pondage volume. Cost prediction for future hydroelectric construction is difficult, particularly in view of the decreasing availability of economical sites and restrictions imposed by concern for the ecological and social consequences of disrupting the natural flow patterns of rivers and streams.
Pumped-Storage Plants
Pumped-storage plants involve a special application of hydroelectric generation, allowing the use of off-peak energy supplied at incremental charges by low-operating-cost thermal stations to elevate and store water for the daily generation of energy during peak-load hours. Pumped hydro projects must justify the inefficiencies of storage pumping and hydroelectric reconversion of off-peak thermal plant energy by investment cost savings over competing peaking plants. Installation of a pumped hydro station calls for a suitable high head site which minimizes required water storage and upper and lower reservoir areas and an available makeup source to supply the evaporative losses of the closed hydraulic loop. Despite the added complications of installing both pumping and generating units, or of utilizing reversible motor-generator pump-turbines, costs for pumped hydro stations generally fall below those for conventional hydroelectric stations. Lower installed costs are the result of elimination of dams, extensive pondage, and the siting need for appreciable natural water flow. The Department of Energy reports a 1991 installed cost of $937/kW for the Duke Power Company’s 1,065-MW Bad Creek Project. The 1985 Virginia Electric Power Company’s Bath County 2101-MW plant carries an investment charge of $803/kW. Differences in gross head, impoundment, and siting make plant cost comparisons difficult.
Geothermal Plants
Geothermal generation utilizes the earth’s heat by extracting it from steam or hot water found within the earth’s crust. Prevalent in geological formations underlying the western United States and the Gulf of Mexico, geothermal energy is predominantly unexploited, but it is receiving increased attention in view of escalating demands on limited worldwide fossil-fuel supplies. Because natural geothermal heat supplants fuel, the atmospheric release of combustion products is eliminated. Nevertheless, noxious gases and chemical residues, usually contained in geothermal steam and hot water, must be treated when geothemral resources are tapped. There is a current lack of significant cost data covering geothermal plants. The major commercial U.S. facility, the Geysers Plant in northern California, began in 1960 as a phased expansion. It uses dry steam at 600°F (316°C). Because boiler and associated fuel-handling facilities are eliminated, investment in these generating plants is considerably less than the cost of comparable fossil-fueled units. However, overall investment chargeable to geothermal facilities includes significant exploration and drilling costs which are site dependent and cannot be accurately predicted without extensive geophysical investigation.
Environmental Considerations
Environmental protection has become a dominant factor in the siting and design of new power generating stations. Both stack emissions to the atmosphere and thermal discharges to natural water courses must be significantly reduced in order to meet increasingly stringent environmental criteria. In many cases older plants are being required to reduce emission levels to achieve legislated ambient air-quality standards and to control thermal discharges by the use of closed cooling systems to prevent aquatic thermal pollution.
Control of air pollution in fossil-fueled power plants includes the reduction of particulates, sulfur oxides, and nitrogen oxides in flue gas emissions. Particulate collection can be achieved by electrostatic precipitators, baghouse filters, or as part of stack gas scrubbing. Stack gas scrubbing is required for all new coal-fired power plants, regardless of sulfur content of the fuel. Fossil-fueled power plants are believed to be a major contributor to acid rain.
Scrubbers reduce sulfur oxide emissions by contacting flue gas with a sorbate composed of metal (usually sodium, magnesium, or calcium) hydroxides in solution which act as bases to produce sulfate and sulfite precipitates when they contact sulfur oxides in the flue gas. Wet scrubbers contact flue gas with a sorbate in solution. Dry scrubbers evaporate sorbate solution into the gas stream.
Fossil-fueled power plants are required to burn low-sulfur fuels. Restrictions on the use of oil in new power plants and its high cost have virtually eliminated new central station steam power plants designed to utilize oil. Control of nitrogen oxides NOx is attained primarily through modifications to flame propagation and the combustion processes. The 1990 amendments to the federal Clean Air Act and proposed restrictions in the new amendment to the federal Water Pollution Act of 1972 (Clean Water Act) will have cost implications that have not been fully documented. Under the influence of the nitrous oxide (NOx ) emission limitations proposed for Phase I and Phase II of the 1990 amendments to the Clean Air Act, steam generator designs will change to incorporate some form of low-NOx burners, overfire air dampers, catalyst injection, flue gas recirculation to the burners, and other modifications to meet these new federal standards. New combustion turbine designs are also being developed to meet these new NOx emission regulations. In order to avoid plant discharges of waste heat to the aquatic environment, evaporative-type closed-cooling cycles are employed in lieu of once-through cooling system designs. Closed-loop cooling systems in current use employ evaporative cooling towers or cooling ponds. Use of these systems entail investment penalties consisting of net increases in equipment and facilities cost, and penalties incurred by losses in peak capability due to the lower plant efficiency associated with evaporative cooling systems. More advanced closed-cooling-loop designs anticipate the use of dry and wet-dry cooling towers. These represent possible alternates to conventional evaporative systems where makeup water is in short supply or where visible vapor plumes or ice formed by vapor discharge present hazards. The penalties for dry-tower cooling are significantly higher than those for conventional evaporative designs. Large, more costly water-to-air heat-transfer surfaces are required, and characteristically higher condensing temperatures result in higher turbine backpressure, severely restricting plant capability. Although no large-size dry towers are currently in operation in the United States, estimates indicate incremental investment cost penalties for conventional fossil-fueled plants in the range of $150 to $200 per kilowatt for mechanical-draft dry cooling towers and of $300 to $400 per kilowatt for natural draft, dry cooling designs. Similarly equipped nuclear plants bear dry tower investment cost penalties approximately 40 percent higher than the above. Wet-dry towers show promise for practical application, combining the advantages of both wet and dry tower designs. Wet-dry towers incur added investment penalties for closed heat-transfer surface only to the extent necessary to eliminate visible plume and/or to reduce makeup requirements. Investment cost penalties for wet-dry towers fall between those for wet towers and dry towers.
