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Assessment of Research Needs for Wind Turbine Rotor Materials Technology 1 INTRODUCTION SCOPE AND CONTENT Wind-driven power systems represent a renewable technology that is still in the early stages of its development and maturation. It is a renewable power technology that, during the course of its rapid evolution over the last decade, has accumulated significant, large-scale, utility-connected experience. This experience not only revealed the early design problems, which for the most part have been resolved, but also presented opportunities for further significant improvements in the technology and economics of the wind turbine, the principal component of these renewable power systems. The principal improvements will be associated with increases in wind turbine size, improved knowledge of structural materials, incorporation of improved control hardware and algorithms, utilization of power conversion electronics, and development and integration of short-term energy storage systems. A major area of potential improvement, and the focus of this report, is the need for improved knowledge of materials properties and advanced, economical, high-volume manufacturing processes. This chapter traces the evolution of wind power systems in this country, identifies the principal components of a power-generating wind turbine, presents a simplified description of the relationship between the power in the wind and the power flow through the turbine drive train, and describes the characteristics of the wind environment that impact both the short- and the long-term structural integrity of wind turbines. The remaining chapters of this report explore and further define the need for improved materials properties, manufacturing processes, and control systems. The report closes with major conclusions and recommendations. WIND-DRIVEN POWER PLANTS Large-scale, wind-driven power stations have emerged as one of the most attractive of the recently developed renewable power technologies. These arrays of interconnected wind turbines convert the power carried by the wind into standardized electricity. This electricity is delivered into a conventional grid system for use by utility customers. Shown in the photograph of Figure 1-1 are some of the wind turbines of wind power plant in California. These renewable power systems have evolved rapidly over the last decade. The first sizeable, grid-connected installations began operation in 1981 in California. Their development was facilitated initially by federal and state tax incentives, high energy prices, and a favorable regulatory environment. These factors supported the attraction of the private sector risk capital required for the development and early commercialization of a new, untried, and capital-intensive power generation technology. As the reliability and economics improved, these power systems were able to attract conventional financing similar to that available for other industrial capital equipment. These factors and improvements have resulted in a renewable power technology with major installations in California, Denmark, and Hawaii. For a technology that can be described as being in its infancy, these power systems have achieved a remarkable record of performance. At the close off 1989, the
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Assessment of Research Needs for Wind Turbine Rotor Materials Technology Figure 1-1 Wind power plant in Altamont Pass, California. (Courtesy, U.S. Windpower, Inc.)
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Assessment of Research Needs for Wind Turbine Rotor Materials Technology wind power plants in California represented a power-generating capacity of 1335 MW, equivalent to a medium-size nuclear or coal-fired power plant. During 1989 the wind power systems of California delivered slightly more than 2 billion kWh of electricity. This amount of electrical energy is equal to the annual residential needs of a city the size of San Francisco or Washington, D.C. In Europe, Denmark has been a pioneer in the use of modern wind turbines for electricity generation. The approximately 2500 wind turbines installed throughout Denmark currently supply about 1 percent of the country's annual electrical needs. We note here that approximately half of the wind turbines installed in California during the 1980s were of Danish manufacture. This is relevant to the longer-term impact of this study as it relates to the future viability of U.S. manufacturers. The progress of the last decade was not achieved without difficulty and, at times, controversy. Early structural failures, together with under-capitalization of some wind power plant operators, led to the perception, from some quarters, that the California installations were ''tax farms.'' However, as the systems improved in performance and began to produce large amounts of energy, these accusations were replaced by a growing appreciation of the environmental benefits and advantages offered by this renewable power generation technology. The advantages and benefits include the following: Environmentally Benign: Wind power systems are environmentally benign. There are no gaseous emissions, no particulates, and no radioactive by-products. Rapid Modular Addition of Capacity: Wind power systems can be installed quickly, thus reducing financing costs and providing flexibility in meeting demand growth. Wide Range of Capacities: Wind power systems can range in size from very small systems to power plants of utility scale (i.e., from a few kilowatts to hundreds of megawatts in power-generating capacity). Ease of Integration: Wind power systems are readily integrated into existing utility generation-transmission-distribution systems, using standard utility components and practices. The wind turbine is the only new component. Couse of Land: While land intensive, wind-driven power plants coexist with other uses of the land on which they are situated. The wind turbine and towers, service roads, and electrical equipment typically occupy only 10 percent of the land on which the wind power plant is installed. Previous uses, typically agricultural, can continue with little useful area removed. Use of Indigenous Resources: Wind-driven power plants use indigenous resources for their fuel. Since the fuel is without cost, the user country achieves a degree of energy independence and preserves hard currency assets. This is important not only for developed countries with adequate wind resources but perhaps more so for developing countries. Economically Competitive: The cost of energy (CoE) from wind power plants is competitive now with some conventional energy generation sources. Large-scale systems now being installed deliver energy at costs in the range 7 to 9c/kWh. Under comparable wind resource conditions, third-generation wind turbines (under design now) are expected to deliver energy at costs in the range of 4 to 6c/kWh. These advantages are applicable not only to this country but globally as well. While not a complete solution to environmental concerns, wind power systems do represent an attractive part of the total generation mix. As with most technologies, the advantages of wind power systems must be weighed against the disadvantages and limitations. The disadvantages include their visual impact, noise, potential interference with the reception of television signals, and potential hazard to birds. Visual impact is inescapable, particularly at close distances. The principal sources of noise in wind turbines have been the blades and gearboxes. Early machines were relatively noisy compared with more recent designs. Advances in blade airfoil shape and manufacture have significantly reduced the noise from wind turbine blades. Similarly, attention to the sources of noise in wind turbine gearboxes has resulted in significant reductions. However, with both sources a certain amount of noise is
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Assessment of Research Needs for Wind Turbine Rotor Materials Technology inevitable. At reasonable distances (several rotor diameters), wind turbine noise can be difficult to discern from ambient background and cultural noise sources (e.g., wind noise, automobile traffic). Television interference has not been a problem with recent large installations. This may be due in part to the use of composite materials in the blades and the fact that people typically do not reside in close proximity to wind turbines. There also are limitations to the broader application of the technology. The relative newness of the technology has justifiably required the accumulation of significant operating experience. This limitation is being removed by the favorable technical and economic performance accumulated over the past half decade or more by many existing installations. A fundamental limitation is that the economic generation of electricity is governed by the quality of the wind resource—no wind, no energy; poor wind, some energy but unattractive economics. Wind systems thus have a geographical limitation based on availability of the required resource—wind. Finally, a limitation of current systems is that the electricity generated is time variable, reflecting the variability of the wind. This variability occurs on several time scales. Seasonal and diurnal variations are statistically predictable, such that the generated energy can be factored into the planning of the overall utility generation mix. However, time variations on the order of minutes and tens of minutes (faster than the ramp rates of conventional generation sources) can pose system voltage and frequency stability problems. The utility rule of thumb is that wind systems of current design are limited to the range of 5 to 15 percent of the total generating capacity. For a given utility system, the specific wind penetration limit depends on such technical details as transmission line characteristics, the ratio of real and reactive power, and allowable excursions of voltage and frequency. Thus far, with the large installations in California, system stability has not been a major problem due to the very large utility systems to which the energy is supplied. The fraction of wind generation capacity is less than 10 percent of the total generation on-line. Depending on the time of day and the load profile, the wind systems on the island of Hawaii do approach limitations imposed by system stability arguments. At night, when the load is minimal, the installed wind systems can exceed the range cited above. The system stability limitation represents an upper bound on the amount of current design wind capacity that can be integrated with the balance of the utility generation mix. As such, this limitation is a market limitation having technical origins. There are three approaches, now undergoing research and development, that will mitigate and eventually remove this limitation. New wind turbine system designs form the first of these approaches, one example of which is the variable-speed architecture with power electronic control and interface to the grid. Other less complex examples are provided by innovative, passive, load-relieving rotor designs and by advances in self-regulating airfoils. A second approach that will provide relief from this limitation is improved control of the wind system and integration of control with the conventional generation sources. Finally, the third technique for removing the penetration limitation is the incorporation of energy storage, which will compensate for the time variability of the wind. We are beginning to see all of these techniques employed in smaller integrated power systems. These are systems used in regions where no large regional grid system is available, where the wind power capacity is comparable to the conventional power generation capacity (often provided by diesels), and where the conventional power sources can be turned off, with the load being supplied by the wind system. WHY MATERIALS KNOWLEDGE IS CRITICAL From an engineering perspective, the early structural failures and continuing risks had their genesis in an early lack of understanding of the wind forces acting on these large structures. This included not only the effects of the steady-state component of the incident wind flow field, but
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Assessment of Research Needs for Wind Turbine Rotor Materials Technology more particularly the turbulence component. Research, field measurements, and improved modeling, augmented by operational experience, have greatly increased our understanding of these stochastic forcing functions and the response of the wind turbine. Nevertheless, it is still true that the turbulence structure of the wind contributes the most uncertainty in the design and sizing of the major structural components of a wind turbine. From the perspective of a designer, this uncertainty continues to be due in part to incomplete knowledge of the turbulence and its description and in part to the difficulty of modeling the structural vibrational responses. However, a major contributor is uncertainty about the long-term responses of the wind turbine materials to the turbulent stochastic loadings. The specific long-term responses of interest here are fatigue failures-that is, failures due to the cumulative effects of many millions of flexural cycles of a structural component. Fatigue failures represent the greatest uncertainty with regard to the long-term service lifetime (typically projected to be 20 to 30 years) of the major structural components of a wind turbine. Thus, fatigue failures represent a major uncertainty in the life-cycle CoE. Uncertainty about the properties of materials causes the wind turbine designer either to add more weight (and cost) than is required or to misjudge and inadequately size a component so that failure occurs (usually more costly). To further improve the economics of wind turbine systems and increase their range of use, improved materials properties are required. This is particularly true with regard to the long-term fatigue properties of composite materials. As used thus far in wind turbines, composite materials are combinations of glass, other synthetic fibers, or wood in a resin matrix. With the anticipated increasing use of these and other composite materials, improved knowledge about both their static strength and their fatigue properties becomes critical in order to assure both short-term performance and the long-term life required of these power systems. This knowledge base is particularly critical for composites because of the wide variation in their geometries, constituents, and manufacture. In addition to the need for improved materials knowledge, there is also a need for increased awareness in the wind turbine community (within both the federal and the private sectors) of advanced manufacturing processes. These processes, which may be used in other industries, are required to support not only the more extensive use of composites but also their large-volume, economical manufacture. THE EVOLUTION OF WIND-DRIVEN POWER PLANTS Wind-driven power plants are arrays of interconnected wind turbines used for generating and delivering large amounts of electricity. The electricity typically is delivered to a larger utility generation-transmission-distribution system or grid. These large-scale power plants are often referred to as wind farms or wind parks. The term wind power plant or wind power system will be used here. These renewable energy generation systems have evolved rapidly over the past 10 years. There are now substantial installations in three regions of California, in Hawaii, and in Denmark. Currently, there are about 14,000 wind turbines in California-all installed since 1980. The California installations are situated principally in the Altamont Pass region, about 60 miles east of San Francisco near Livermore; the Tehachapi region, about 100 miles northwest of Los Angeles near Mojave; and the San Gorgonio Pass region, about 100 miles southeast of Los Angeles near Palm Springs. The wind power plants in northern California (about half of the total) deliver their energy to the grid system of the Pacific Gas and Electric Company, while the installations in southern California feed their energy into the Southern California Edison grid system. As illustrated in Figure 1-2, during 1989 the wind power plants in California delivered about 2 billion kWh of electricity. The two graphs of Figure 1-3 illustrate the growth in the rated power-generating capacity of the California wind power plants. The graph units are megawatts. The bar graph shows the capacity added during each year from 1981
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Assessment of Research Needs for Wind Turbine Rotor Materials Technology Figure 1-2 World energy generation by wind power plants during 1989 (units of millions of kWh). (Courtesy, Paul Gipe & Associates.) Figure 1-3 Growth of generating capacity for the California wind power plants. Sources: California Energy Commission (CEC); CEC Performance Reporting Systems (PRS). (Courtesy, Paul Gipe & Associates)
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Assessment of Research Needs for Wind Turbine Rotor Materials Technology through the projection for 1990. The line graph of Figure 1-3 depicts almost the same information but in a cumulative format. This graph shows the cumulative total of the net installed capacity at the end of each year during this 10-year period. There are four features in the data of Figure 1-3 that merit attention: (1) the current total rated capacity, (2) the shape of the year-to-year growth in capacity, (3) a comparison of the capacity installed before and after the end of 1985, and (4) the 1988 decrease in the cumulative total capacity. Discussion of these features will illuminate the reasons behind the rapid evolution and growth of these large-scale renewable power systems. The first thing to notice about the information in Figure 1-3 is the current rated capacity of the wind power plants. For a power generation technology that has evolved over the recent decade, the nearly 1500 MW of installed capacity is substantial. The second aspect of Figure 1-3 that merits comment is the rapid growth of the year-to-year added capacity from 1981 through 1985 and the generally reduced rate of new installations in the succeeding years. This is a manifestation of the mechanisms used to initiate the early, large-scale commercialization of a relatively new and untried power generation technology. These mechanisms included tax incentives at the federal level and at some state levels (including California) and federal legislation requiring regulated utilities to purchase the energy produced by nonregulated or independent power producers (IPPs). The development occurred first in California not only because of the three excellent wind regions, but also because of a favorable legislative and regulatory climate at the state level. The legislative climate resulted in tax credits to California residents who invested in renewable energy generation facilities. The favorable regulatory climate, as represented through the actions of the California Public Utilities Commission and the California Energy Commission, influenced the terms of power purchase contracts negotiated between the regulated utilities and the IPPs. These policies, factors, and influences permitted the attraction of the large amounts of private capital needed to launch a new, capital-intensive industry. The wind power systems of California represent a private capital investment of about $2.5 billion. The incentives and the attendant attractive returns compensated the investors for participation in a risky and relatively untried power generation technology. The tax incentives at the federal level expired at the end of 1985. The California tax incentives were phased out over the 2-year period of 1986 and 1987. While there were some carryovers and grandfathering, for all practical purposes the tax credit era that fostered the early development of wind power technology expired at the end of 1985. The effects can be seen in the post-1985 decrease in the yearly installation rate of new capacity, depicted in the bar graph of Figure 1-3. At this point, we are equipped to appreciate the third feature in the data of Figure 1-3. If one sums in Figure 1-3 the yearly capacity added from 1986 through the projections for 1990, this post-tax-incentive added capacity is about equal to that installed from 1981 through 1985. Aside from any carryovers or phaseouts of special tax incentives, two factors supported continued installations in the years following 1985: (1) the continually improving energy production and overall economic performance of the wind systems and (2) the carry-forward provisions of some of the pre-1985 power purchase contracts. Finally, in Figure 1-3, the 1988 dip in the cumulative capacity on-line (the line graph) reflects the fact that a number of older, first-generation wind turbines were retired. They were replaced, to some extent but not entirely, by the new capacity (59 Mw) installed during 1988. The growth in annual energy production of the California wind power systems is depicted in Figure 1-4. The data in this figure show that energy production has steadily improved from 1981 through the present. Nevertheless, averaged over the fleet, the current average capacity factor is still not up to the realistically achievable potential in the wind regimes of the three California regions. For good sites in any of these regions, a capacity factor of 0.25 is a reasonable performance value. The best of the current machines do achieve this value or higher.
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Assessment of Research Needs for Wind Turbine Rotor Materials Technology Figure 1-4 Growth of annual energy production for California wind power plants. Sources: CEC, CEC PRS. (Courtesy, Paul Gipe & Associates.) The high energy prices in the early part of the 1980s were accompanied by the expectation of still higher prices. This led to the development and approval of negotiated power purchase contracts wherein the energy prices paid were consistent with the prevailing expectations of high, and higher, energy prices. By means of a long-term fixed-price payment provision in certain contracts, the operator of wind power systems surrendered the possibility of receiving near-future higher energy sales prices in return for defined energy prices that were fixed for a long-term period (typically 10 years). This benefited the utility rate payers by putting a cap on energy prices from these sources; it benefited the IPPs by providing revenue certainty over the period of fixed prices. This period of revenue certainty (often coincident with the term of third-party financing) supported the continued (post-1985) attraction of investment capital from the private sector. Now, however, these investments, made in the absence of special tax incentives, took on a different complexion. These factors allowed wind systems to be financed on the basis of their economic performance. Thus, beginning in 1986, large-scale wind power plants began to be financed in the same ways that other industrial capital equipment is financed. These included sale-lease transactions and straight debt, secured by the equipment, with repayment supported by the revenue streams generated by the equipment. THE PRINCIPAL COMPONENT: WIND TURBINES Wind turbines are the principal component of wind farms. They are the only component that is not a standard piece of utility equipment. They represent the major fraction, in the range of 60 to 75 percent, of a wind farm's total installed cost. The CoE associated with currently installed, second-generation wind turbines is in the range of 7 to 9c/kWh. While this is economically competitive in the context of the most attractive power purchase contracts currently in place, and is competitive with some conventional means of energy generation, the full potential of wind power as a large-scale
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Assessment of Research Needs for Wind Turbine Rotor Materials Technology renewable energy source will not be realized until costs can be reduced further. Both the installed capital cost and the continuing maintenance costs need to be reduced. Two paths by which this might occur are improved knowledge of the behavior of materials and the use of advanced manufacturing techniques. Through utilization of these and other improvements, it is believed that the CoE from wind systems can be brought to the range of 4 to 6c/kWh. This range will make wind power systems competitive not only with nuclear but also with new coal-fired installations. At the same time, the performance characteristics will be improved to the extent that wind turbine installations can be economically productive over a broader class of wind regimes and geographical regions. There are two generic types of wind turbines: (1) the horizontal axis wind turbine (HAWT) and (2) the vertical axis wind turbine (VAWT). Although many of the findings and recommendations of this study are applicable to both architectures, the focus here is on the HAWT. This is the type predominantly used in the approximately 20,000 wind turbines now in service throughout the world. Illustrated in Figure 1-5 are the principal elements of a wind turbine. These include (1) the rotor, consisting of the blades and the supporting hub; (2) the drive train, consisting of the low-speed shaft (LSS), the gearbox or transmission, the high-speed shaft (HSS), and the generator; (3) the machine bedplate or supporting frame; (4) the yaw bearing and yaw orientation system; and (5) the tower. In the interest of clarity, the bedplate or frame has been omitted from the drawing of Figure 1-5, as have the tower foundation and most of the tower. Figure 1-5 Wind turbine subsystems.
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Assessment of Research Needs for Wind Turbine Rotor Materials Technology The wind turbine blades are rotating airfoil surfaces that transform power in the wind to mechanical shaft power. As will be discussed later, the blades also provide one means for the control of power flow through the drive train. The wind turbine gearbox is a step-up type, used to convert the low-speed power and torque produced by the rotor to their high-speed equivalents required for operation of the generator. The gearbox matches the different operating speeds of the generator and the rotor. The electrical machine typically used as a generator in wind turbines is the four-pole, squirrel cage induction machine or, more briefly, an induction machine. An induction machine operates within a narrow range of speeds centered about the synchronous speed of the machine. For a four-pole induction machine designed for use on a 60-Hz electrical system, the synchronous speed is 1800 rpm. At speeds below synchronous, the induction machine functions as a motor. At speeds above synchronous, it operates as a generator. The range of operating speeds is defined by the slip range. Typically, the slip range for the four-pole induction machines used in wind turbines is 2 percent of synchronous speed, or about 35 rpm. Used as a generator, this machine begins to develop power at about 1800 rpm and reaches full rated power at about 1835 rpm. The aerodynamic characteristics of the blade airfoils, the rotor diameter, and the range of operating wind speeds determine the optimum rotor speed. For wind turbines having power ratings in the range of 100 to 600 kW, the range of current interest and emphasis, the corresponding rotor speed range would be approximately 35 to 70 rpm. Thus, for an 1800-rpm generator and this range of rotor speeds, the corresponding gearbox ratios would be in the range of 26:1 to 51:1. Typically, such ratios would be implemented by two- or three-stage gearboxes. The wind speeds over which turbines can generate power typically lie in the range of 10 to 50 mph. For the California wind regions, the number of hours per year that the wind speeds lie within this operating range varies from 3000 to 4500. The actual number of operating hours accumulated in any given year depends not only on interannual wind statistics and local siting effects but also on the characteristics of a given wind turbine. For use in a later illustration, we choose the intermediate value of 4000 hours per year. This means that the wind turbine operates often enough to generate power 4000 hours out of the 8760 hours per year, or about 46 percent of the time. Typically, there is a pronounced seasonal variation. In California, for example, about 70 percent of the annual energy is produced during the five summer months, May through September. In most regions there are many hours per year when the wind speeds are less than 10 mph. For these speeds the wind does not carry enough power, with current technology, to overcome the effects of conversion inefficiencies and losses. At the other end of this range, the number of hours during which the wind speeds are greater than 50 mph usually is quite small. Thus, for wind speeds greater than 50 mph, the added revenues generated do not compensate for the costs of the necessary increased structural strength. Finally, it is important to note that the wind turbine structure is required to survive very high (nonoperating) wind speeds. A typical design survival wind speed is 125 mph (56 m/s). As a function of wind speed, the power output of wind turbines may be characterized by four numbers. In this simplified but useful description, three of the numbers specify characteristic wind speeds and one defines the power rating of the wind turbine: vci the cut-in wind speed, defined as the wind speed at which the wind turbine begins to generate useable amounts of electrical power. Typical values are vci = 10 mph = 4.5 m/s. vr the rated wind speed, defined as the lowest wind speed at which the wind turbine reaches the maximum value of its electrical power output. Typical values are vr = 27 mph = 12 m/s.
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Assessment of Research Needs for Wind Turbine Rotor Materials Technology Pr the rated power, defined as the maximum value of the electrical power output. Vco the cut-out wind speed, defined as the wind speed at which the wind turbine reduces its electrical output from the maximum rated power level to zero. Although this usually occurs over a narrow range of wind speeds, for simplicity it is often assumed to occur at the single value vco. Typical values are vco = 50 mph = 22 m/s. These values define the wind turbine power curve, a graph of the electrical power output as a function of wind speed. The general features of a wind turbine power curve are depicted in Figure 1-6. The wind turbine produces no power from zero wind speed through the cut-in value vci. As the wind speed increases further, the power output rises, reaching the rated value Pr at the wind speed vr. As the wind speed increases beyond the value vr, the wind turbine control system (which may be active or passive) endeavors to hold the output power constant at the rated value Pr. This output value is maintained until reaching the cut-out wind speed vco, at which speed the power output is reduced to zero. The power curve of Figure 1-6 is an idealization. It neglects differences in wind turbine control strategies. It accounts for rapid variations in wind speed only in an average sense. However, this representation does indicate the average performance characteristics of a Figure 1-6 Wind turbine power curve.
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Assessment of Research Needs for Wind Turbine Rotor Materials Technology given wind turbine and is useful in predicting its annual energy production. We shall use Figure 1-6 to illustrate simplified equations that describe the conversion wind power to electrical power delivered by the wind turbine. POWER CONVERSION EQUATIONS Illustrated in Figure 1-7 are the principal loads, torques, and moments resulting from an incident wind flow field. The relationship between the power in the wind and the resulting power flow through the drive train can be described by simplified analytic expressions. The simplifying assumption is that the incident wind flow field can be characterized solely by the speed v, which is constant in both time and space. This approach, which invokes conservation of mass plus linear momentum and energy, yields the simplest representation of the wind turbine behavior and response to the wind flow field. This approach, used to derive an upper bound to the performance of a wind turbine (the Betz limit), is derived in de Vries (1979) and Eggleston (1987). As sketched in Figure 1-8, it proceeds from the power associated with the wind flow described by Equation (1) and yields the wind turbine performance relations of Equation (2): Equation (1) shows the dependence of the power in the wind incident upon a rotor of swept area A as a function of the wind speed v. Equation (2) describes the electrical power output of the wind turbine resulting from this flow. These equations are defined in terms of the following parameters: Figure 1-7 Wind flow field and turbine loads.
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Assessment of Research Needs for Wind Turbine Rotor Materials Technology Figure 1-8 Comparison of logarithmic power in the wind with a wind turbine power curve (Pr = 100 kW). A area (m2) swept out by the rotor; v speed (m/s) of the incident wind flow field; ρ mass density (kg/m3 of the air; Pw power (watt) in the wind flow through the rotor of swept area A, where P2 power (watt) in the shaft that carries the rotor, the low-speed shaft; Cp power conversion coefficient (dimensionless) of the rotor, defined as the ratio P2/Pw; efficiency (dimensionless) of the gearbox; efficiency (dimensionless) of the generator; and Pe electrical power output (watt) of the generator, defined as The last portion of Equation (2) highlights the important dependencies. This relationship indicates that the output power as well as the power flowing through the drive train is proportional to the cube of the wind speed, to the area of the rotor, and to the power conversion efficiency of the rotor. Under the idealized assumptions of this model, the maximum value achievable by the rotor power conversion coefficient is 16/27, the Betz limit:
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Assessment of Research Needs for Wind Turbine Rotor Materials Technology For comparison, the better-performing wind turbine rotors achieve maximum power coefficient values in the vicinity of This disparity indicates the deficiencies (e.g., neglect of angular momentum) in the model used to derive the Betz limit and, to a limited extent, the potential for improvement in blade performance. These equations illustrate the major problem in wind turbine design: the control or modulation of the power flow through the wind turbine drive train. This power flow has both a steady-state, quasi-static component and a fluctuating component. For the time being, we continue with the assumption of an incident wind flow field that is constant in both time and space. This allows us to focus on the power control problem. The problem is that the power in the wind flow field increases as v3 since the rotor area is fixed in practically all designs. Thus, over the 10 to 50 mph operating range cited earlier, the incident wind power increases by a factor of 125. Since the wind turbine is designed to deliver electrical power at the value Pr, a more realistic measure of the dynamic range that a wind turbine must accommodate is given by the ratio of the wind speed at cut out to the rated wind speed: Thus, if the wind turbine's rated power is Pr= 500 kW, the cubic dependence of Pw means that the turbine must be able to accommodate at least 3.2 MW of power flow in the wind. To accommodate these power levels directly (in brute force fashion with no control actions) over the typical range of operating wind speeds would place a severe economic penalty on the structural design margins of the rotor, drive train and tower, and foundations. The remedy is to recognize that Cp is not a constant but may be actively or passively controlled. To show this, we rewrite Equation (2) to show the explicit dependence of Cp on the wind speed v: Thus, an upper bound on the power and torque experienced by the drive train is achieved by modulating Cp(v). This is done typically by either active blade pitch control or passive stall control techniques. The relationship between the power in the incident flow field and the wind turbine power output (which is functionally the same as the drive train power levels) is shown in the two graphs of Figure 1-8. These are simply plots of Equations (1) and (5) wherein a function Cp(v) for a nominal 100-kW wind turbine has been used. The curves in this figure illustrate the need for control of power through the drive train. For the example shown in Figure 1-8, the cut-out wind speed is about 50 mph. At this wind speed, the wind turbine must accommodate the power in the wind whose value is more than six times either the shaft power or the electrical power output. As discussed above, the wind turbine blades provide one means for control of power flow through the drive train. Several variations are used to effect this control. The two techniques currently used most widely are (1) pitch control, wherein the entire blade is rotated about the pitch axis so as to change the power extraction characteristics of the blade, and (2) fixed pitch or stall control, wherein the blade is kept at a fixed pitch angle chosen so that the blade becomes increasingly less efficient as the wind speed increases. These are illustrated in Figure 1-9 along with other variations, including partial-span pitch control, wherein only an outboard portion of the blade is rotated about the pitch axis; the use of ailerons; and the use of deployable tip sections to limit overspeeds. Also illustrated is a control technique seldom used thus far in wind turbine airfoils—pumped spoiling or boundary layer control.
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Assessment of Research Needs for Wind Turbine Rotor Materials Technology Figure 1-9 Wind turbine blade control methods. The discussion thus far has dealt with steady state or nonfluctuating loads experienced by the wind turbine structure and components. There is, in addition, a fluctuating component to the wind turbine loads that arises from several sources. These include vertical wind shear, temporal and spatial turbulence, gravity, and interaction of the rotor with the tower. These sources are discussed next in the context of a more realistic description of the wind flow field. THE WIND ENVIRONMENT The discussion thus far of the interaction between a wind turbine and an incident wind flow field has assumed that the wind is constant in both time and space over the area swept out by the wind turbine rotor. This assumption results only in the steady-state component of the loads on the wind turbine structure. Any more realistic description of the wind flow field must also include those characteristics responsible for the fluctuating component of the wind turbine loads. The fluctuating components are induced by both the steady-state as well as the fluctuating components of the wind. This more complete description will reveal the many ways in which real wind fields extract fatigue lifetime from the materials of wind turbine structures. We approach this topic by reflecting on the characteristics of the wind time-series data available to designers of the early wind turbines. As noted previously, many of the early, first-generation wind turbines suffered major structural failures. Typically, these were machines installed during the period 1981 through 1983. These failures can be attributed to several factors. Predominant among them was a lack of understanding of the dynamic range and attack times of the gust structure of the wind flow fields incident upon the wind turbine. At that time the bulk of the wind data available was based on standard meteorological practice. Both the wind speed and the wind direction values represented averages over 10 minutes or more. Further, the measurements were taken at the standard meteorological sensor height of 10 m.
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Assessment of Research Needs for Wind Turbine Rotor Materials Technology There are fundamental disparities between these wind measurement parameters, the resulting descriptors of the wind flow field, and the actual wind flow field incident upon the wind turbines. Thus, it is not surprising, in retrospect, that some aspects of early designs were marginal. First, the relatively efficient rotors of modern wind turbines respond quickly to wind changes, inducing correspondingly rapid loadings. Thus, the rotor and drive train experience torque and other transients that would not be expected from the 10-minute or longer averages of standard meteorological measurements. Second, the center of the wind turbine rotor, the hub, sits not at a 10 m height but more typically at two to three times that height. Because wind speeds increase with height in the earth's boundary layer where wind turbines operate, wind speeds are typically higher at the hub height relative to a 10-m height. This increase of wind speed with height is termed vertical shear. The function often used to model vertical wind shear is given by Equation (6): This function connects the wind speed v(h) at the height h with the wind speed v(h1) at the reference height h1. The power law coefficient usually chosen as representative has the value α = 1/7. From this relationship we see that the wind speed at height h = 20 m can be 1.10 times the value at the standard meteorological sensor height of 10 m. Similarly, at the height h = 30 m, the wind speed may be 1.17 times greater in value. To appreciate the impact of vertical wind shear, consider a rotor of diameter 20 m situated at a hub height of 25 m. Due to vertical wind shear alone, each blade during each revolution will experience a +7 percent (top) and a -8 percent (bottom) variation in wind speed. This maps into a 45 percent variation in the power density (watts/m2) of the incident wind flow field. Thus, we see that even though the vertical wind shear may be time independent, the vertical spatial dependence, when sampled by a rotating blade, induces cyclic loads. Cyclic loads also occur when the blades pass through any stationary wakes or bow waves associated with the tower. These cyclic load components are superimposed on the quasi-static loads associated with the average wind speed and power density. Gravity is of course also time independent, but again the rotating blades experience cyclic bending moments due to gravity. The influence of gravity in fact becomes a major limiting factor as wind turbine rotors become larger. The remainder of the contributors to the cyclic load components are associated with fluctuations in the wind flow field incident upon the wind turbine rotor. These flow fields always have both a time and a spatial dependence over the rotor swept area. While we are unable to treat these fluctuating components adequately in the context of this chapter, the cyclic loads produced by these components are in practice responsible for a significant fraction of the fatigue damage experienced by wind turbine structural components. FATIGUE CYCLE ACCUMULATION We now can form a greatly simplified, lower-bound estimate of the accumulation of fatigue cycles as a function of operating time. The estimate serves to illustrate the very large number of fatigue cycles experienced by a wind turbine rotor and other structural components during the turbine operational lifetime. In a comprehensive treatment, the sources of the cyclic loadings must include the temporal and spatial structures of the wind flow field itself as well as the cyclic events associated with operation of the wind turbine, that is, rotation of the rotor and blades. For the purpose of forming a simple, lower-bound estimate, we ignore the cyclic loading contributions of the wind turbulence structure and pretend that the wind flow field has only a steady-state component that is constant in both space and time over the rotor swept area.
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Assessment of Research Needs for Wind Turbine Rotor Materials Technology In this estimate we thus focus on the effects of gravity, vertical wind shear, and blade-tower interactions. Ignored are the stochastic loadings associated with the actual turbulence structure of the wind flow field, including the passage of the blade through cells of spatial turbulence and the effects of yaw and off-axis operation. Ignored also are the fatigue damage effects of wind turbine stop-start events. Although fewer in number, their loading amplitudes and fatigue life extraction may be quite large. The lower-bound fatigue cycle estimate is thus based only on the deterministic sources of cyclic loads. In fact only one source need be considered, as all are associated with and driven by the rotational speed of the wind turbine rotor. To obtain a simple result, no information about the spectrum of loadings is included. All effects are considered to have the same unspecified loading amplitudes. Not included are the balance of the deterministic sources; the effects induced by the temporal, spatial turbulence of the wind; and any stop-start effects. All of these neglected effects act to increase the rate of accumulation of fatigue cycles. Thus, the estimate is a lower bound on the number of fatigue cycles accumulated over time. With these simplifications, the number of fatigue cycles accumulated as a function of calendar time is given by the function where t is the elapsed calendar time (years) over which cyclic events are accumulated; Hop is the wind turbine operating hours per year (hours/year); ω is the rotational speed (rpm) of the low-speed shaft; k is the number of cyclic events per revolution (cycles/rev); and N is the number of cyclic events accumulated (pure number) during the elapsed calendar time t as a function of the operating hours per year Hop, the low-speed shaft rotational speed ω, and the number of cyclic events per revolution k, where The number of operating hours depends on the wind turbine, its operating strategy, and the wind regime, but typically the value lies in the range of 3000 hr/year to 4500 hr/year. The value Hop = 4000 hr/year is used in Figure 1-10. The range of low-speed shaft rotational speeds considered is 35 to 70 rpm. Wind turbines at the smaller end of the size spectrum typically will operate near the upper end of this range, while larger machines will operate near the lower end. The parameter k, the number of cyclic events per revolution, typically can take on the integer values k = 1, 2, or 3. Given the present simplifications, from the perspective of a blade, this parameter has the value k = 1. Similarly, for the cyclic events experienced by the low-speed shaft, this parameter is equal in value to the number of blades. The value k = 1 is used in Figure 1-10. For the parameters and their units as defined above, the cumulative number of fatigue cycles is given by the numerical expression of Equation (7): This function is illustrated in Figure 1-10 as a function of the elapsed calendar time t. The parameters k and Hop were chosen to have the values k = I and Hop = 4000 hr/year. Curves are given for each of the low-speed shaft rotational speeds of 35 rpm and 70 rpm. This estimate shows that the number of fatigue cycles accumulated reaches 107 very quickly, in about a year's time. The number of fatigue cycles reaches 108 after about 10 years of
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Assessment of Research Needs for Wind Turbine Rotor Materials Technology Figure 1-10 Accumulation of fatigue cycles. operation. By 20 to 30 years of operation (typically the expected lifetime of wind turbines), the cumulative number of fatigue cycles lies in the range of 108 to 109.1 This extreme accumulation of fatigue cycles with such a large amplitude range is unequaled by practically any other mechanical or structural system. Further, economics are a severe constraint for wind turbine systems. Wind turbine systems must operate competitively under an economic ceiling associated with other means of generating power. As a result, the three cost components of wind turbine economics—capital cost, maintenance cost, and overhaul cost—are subject to stringent and demanding requirements. Increased knowledge about the properties of materials can contribute in a major way to the advancement and further utilization of this large-scale, renewable energy source. 1 This analysis shows that fatigue data at 109 cycles are needed. However, the magnitude of the task of performing fatigue tests to 109 cycles should not be underestimated. Test frequencies are limited to around 20 Hz for fiberglass materials, which means a single test to 108 cycles would require about 100 days and 109 cycles would require about 2 years. When difficulties with test equipment failure and power interruption were considered, fatigue testing to 109 cycles is a major undertaking. Although we have called for fatigue test data at 109 cycles in a number of places in this report, this is an idealized requirement. Much guidance on design and materials selection would be provided by test data in the 107 to 108 cycle range.
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Assessment of Research Needs for Wind Turbine Rotor Materials Technology REFERENCES AND BIBLIOGRAPHY California Energy Commission. 1984. Wind Energy: Investing in Our Future. Revised Edition, California Energy Commission, Sacramento, California, March. (See also Rashkin and Ringer below.) California Energy Commission. 1985. Wind Atlas. California Energy Commission, Sacramento, California, April. de Vries, O. 1979. Fluid Dynamic Aspects of Wind Energy Conversion. National Aerospace Laboratory, The Netherlands, sponsored by the NATO Advisory Group for Aerospace Research and Development, AGARD-AG-243, July. (available from the National Technical Information Service as NTIS AD/A076315. ) Eggleston, D. M., and F. S. Stoddard. 1987. Wind Turbine Engineering Design. Van Nostrand Reinhold Company, New York. Electric Power Research Institute. 1986. Proceedings of a Workshop on Prospects and Requirements for Geographic Expansion of Wind Power Usage. EPRI report AP-4794, November. (Results of a conference that examined the potential for use of wind power stations in regions of the United States beyond California. See also Solar Energy Research Institute Wind Atlas entry below. Freris, L. L., ed. 1990. Wind Energy Conversion Systems. Prentice-Hall, Englewood Cliffs, New Jersey. Gipe, P. 1989. Wind Energy Comes of Age in California. Paul Gipe & Associates, Tehachapi, California, May. (A fairly complete, rational summary of the evolution and performance of the large-scale California wind power stations, including comparisons with other countries and potential.) Hohmeyer, O. 1988. Social Costs of Energy Consumption: External Effects of Electricity Generation in the Federal Republic of Germany. Document EUR 11519, Commission of the European Communities, Springer-Verlag, Berlin (English). (Excellent treatise by a staff member of the Fraunhofer Institute of the direct and indirect costs of various classes of energy sources.) Lynette, R., & Associates, Inc. 1985. Wind Power Stations: 1984 Experience Assessment. Interim Report, Research Project RP 1996-2, Electric Power Research Institute, Palo Alto, California, January. (One of a series of reports sponsored by EPRI that tracked the operations and maintenance performance of a large number of California wind power installations.) Office of Technology Assessment, U.S. Congress. 1985. New Electric Power Technologies: Problems and Prospects for the Nineties. OTA, Washington, D.C., February. Pepper, J. 1985. Wind Farm Economics from a Utility's Perspective. Pacific Gas & Electric Company, San Francisco, California, August. (One of a series of examinations and comparisons of wind farm economics by a utility economist. Later publications appear under the name Janis Pepper-Slate, Enertron Consultants, Los Altos, California.) Pollock, C. 1986. Decommissioning: Nuclear Power's Missing Link. WorldWatch Institute, Washington, D.C., April. (One of a series of papers published by the WorldWatch Institute on the environmental impact of various means of power generation.)
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Assessment of Research Needs for Wind Turbine Rotor Materials Technology Rashkin, S. 1988. Results from the Wind Project Performance Reporting System: 1987 Annual Report. California Energy Commission, Sacramento, California, August. (One of a series of quarterly and annual reports that track the energy production performance of the California wind power stations.) Ringer, M. 1984. Relative Cost of Electricity Production. California Energy Commission, Sacramento, California, July. Solar Energy Research Institute. 1987. Wind Energy Resource Atlas of the United States. Solar Technical Information Program, Report DoE/CH 10093-4, SERI, Golden, Colorado, March. (Excellent treatise on the locations and quality of wind resources in the United States suitable for wind power installations.) Solar Energy Research Institute. 1988. Wind Energy Technical Reading List. Solar Technical Information Program, Report SERI/SP-320-3400 DE88001193, SERI, Golden, Colorado, May. (Bibliography containing references to technical reports from the federal wind research program.) Stoddard, F. S. 1990. Wind Turbine Blade Technology: A Decade of Lessons Learned. Presented at the World Renewable Energy Congress, Reading, United Kingdom, September. Sutherland, R. J., and R. H. Drake. 1984. The Future Market for Electric Generating Capacity: A Summary of Findings. Los Alamos National Laboratory, Los Alamos, New Mexico, December. (Among other topics, portrays the component of capital cost attributable to the cost of funds used during construction of a nuclear power station, prior to its becoming a performing, operational asset.) Utility Data Institute. 1988. 1987 Production Costs: Operating Steam-Electric Plants. Utility Data Institute, Washington, D.C., October.
Representative terms from entire chapter: