Development of An Operations and Maintenance Cost Model To Identify Cost of Energy Savings For Low Wind Speed Turbines
Development of An Operations and Maintenance Cost Model To Identify Cost of Energy Savings For Low Wind Speed Turbines
Development of An Operations and Maintenance Cost Model To Identify Cost of Energy Savings For Low Wind Speed Turbines
Development of an Operations and Maintenance Cost Model to Identify Cost of Energy Savings for Low Wind Speed Turbines
July 20, 2004 June 30, 2008
R. Poore and C. Walford
Global Energy Concepts, LLC Seattle, Washington
Subcontract Report
NREL/SR-500-40581 January 2008
Development of an Operations and Maintenance Cost Model to Identify Cost of Energy Savings for Low Wind Speed Turbines
July 20, 2004 June 30, 2008
R. Poore and C. Walford
Global Energy Concepts, LLC Seattle, Washington NREL Technical Monitor: A. Laxson
Prepared under Subcontract No YAM-4-33200-07
Subcontract Report
NREL/SR-500-40581 January 2008
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Table of Contents
1. 2. 3. 4. 5. Introduction ............................................................................................................................1 Scope ........................................................................................................................................3 Background .............................................................................................................................5 Source Data .............................................................................................................................6 Approach .................................................................................................................................7 5.1 Model Assumptions...........................................................................................................9 5.2 Facility Costs...................................................................................................................10 5.2.1 Operations and Administration ................................................................................10 5.2.2 Site Maintenance......................................................................................................10 5.2.3 Equipment and Supplies ..........................................................................................11 5.3 Turbine Costs ..................................................................................................................11 5.3.1 Labor ........................................................................................................................11 5.3.2 Parts..........................................................................................................................14 5.3.3 Consumables ............................................................................................................16 5.3.4 Failure Rates ............................................................................................................17 5.3.5 Time to Repair .........................................................................................................19 5.3.6 Cranes ......................................................................................................................20 6. 7. Results....................................................................................................................................24 Reducing O&M Costs ..........................................................................................................32 7.1 7.2 7.3 7.4 7.5 8. Assign Tasks to Outside Services ...................................................................................32 Condition Monitoring......................................................................................................32 After-Market Components ..............................................................................................32 Innovative Rigging and Tooling .....................................................................................32 Record Keeping...............................................................................................................33
Conclusions............................................................................................................................34
Appendix A Using the O&M Cost Estimator Spreadsheet Appendix B Part Quantities and Costs Appendix C Failure Rate Assumptions Appendix D Model Results
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List of Figures
Figure 1. Database Architecture ..................................................................................................... 7 Figure 2. O&M Costs on a per Turbine Basis ................................................................................ 9 Figure 3. Number of Turbines per Technician.............................................................................. 12 Figure 4. Annual Service Hours per Turbine................................................................................ 13 Figure 5. Representative Gearbox Weight.................................................................................... 21 Figure 6. Representative Generator Weight.................................................................................. 22 Figure 7. Crane Costs by Tonnage................................................................................................ 22 Figure 8. Cost per Turbine ($), 20-Year Project Life ................................................................... 24 Figure 9. O&M Costs per Turbine, 5-Year Averages................................................................... 25 Figure 10. Annual Turbine O&M Costs ....................................................................................... 26 Figure 11. Crane Costs.................................................................................................................. 26 Figure 12. Parts Costs over 20 years, by System .......................................................................... 27 Figure 13. Failure Distribution over 20 years, Major Parts .......................................................... 27 Figure 14. Average Cost per kW, 60 MW Project........................................................................ 28 Figure 15. Average Cost per kWh, 60 MW Project...................................................................... 29 Figure 16. Annual Project Cost..................................................................................................... 29 Figure 17. Annual Failures of 2.5 MW Major Components, 60 MW Project Size ...................... 30 Figure 18. Estimated O&M Costs for 2.5 MW Turbines on 80-m v. 100-m Towers................... 30 Figure 19. Effect of Internal Crane on O&M Costs...................................................................... 31
List of Tables
Table 1. Typical Turbine Rating/Tower Combinations.................................................................. 8 Table 2. Cost Contributor Categories ............................................................................................. 9 Table 3. Manpower Levels by Number of Turbines..................................................................... 10 Table 4. Representative Yearly Site Maintenance Expenditures.................................................. 11 Table 5. Representative Yearly Expenditures for Equipment and Supplies................................. 11 Table 6. Labor Hours per Turbine per Technician by Year.......................................................... 13 Table 7. Annual Labor Rates ........................................................................................................ 14 Table 8. Parts Categories by System............................................................................................. 15 Table 9. Per-Turbine Annual Consumable Cost Estimates, $ ...................................................... 17 Table 10. Estimates of Failure Rate Mean Life ............................................................................ 18 Table 11. Assumed Repair Time (Manhours)............................................................................... 20 Table 12. Gearbox & Main Bearing R&R Crane Assumptions.................................................... 23 Table 13. Blade and Pitch Bearing R&R Crane Assumptions...................................................... 23 Table 14. Generator R&R Crane Assumptions............................................................................. 23
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1. Introduction
Global Energy Concepts, LLC (GEC) has developed an operations and maintenance (O&M) cost model for estimating O&M costs for commercial wind turbine generator (WTG) facilities. This model was developed under contract with the National Renewable Energy Laboratory (NREL). The overall objective of this model was to support the Low Wind Speed Turbine project goal of identifying ways to reduce the cost of energy for wind projects in low wind speed areas. The model considers the typical costs associated with ongoing operations, including scheduled maintenance, unscheduled repairs, site management, and support personnel, of a facility that comprises any number of conventional wind turbines. Data from a variety of wind power projects that represent different turbine types, turbine ages, and geographic locations have been used to develop the assumptions. Since the operating record for turbines larger than 1 megawatt (MW) is limited to only 25% of the expected 20-year life, the model is necessarily speculative with respect to costs in the last 75% of project life. There are no series-production turbines in the 2 MW and larger range in North America, so estimates for such machines use extrapolated data. Nevertheless, the model is expected to be a useful tool for understanding the relative influences of the factors that drive O&M costs. The model was created in an Excel workbook and will run on any PC with Microsoft Office. A brief user guide to the application is included in Appendix A. As delivered, the model includes a range of generic turbine sizes, with representative costs for parts and projected parts replacement rates, and default assumptions about staffing levels, labor rates, crane costs, etc. The user is only required to select the turbine rated power, pitch system type, rotor speed control type, and number of turbines for an as-is estimate of costs for a hypothetical project. However, the model is flexible. The user can change basic assumptions about the number of employees, labor rates, component costs, and crane rental rates. The model is predictive rather than prescriptive. It projects costs, but does not directly identify methods for reducing the cost of energy. A key feature of the model is that it allows relative impact of the various O&M cost contributors to be evaluated on a common basis; this facility has not been available up to now. An example is the cost associated with maintaining an electric blade pitch system versus the cost for a more conventional hydraulic pitch system. Also, in the course of developing the assumptions for the model, GEC had the opportunity to observe different strategies for efficiently operating wind power facilities and to solicit recommendations and comments from experienced operators. These recommendations are included in Section 7 of this report. The model produces estimates of O&M costs based on averages of past performance of equipment that is not always representative of current or future wind turbines. Significant changes have occurred in wind turbine technology over the past decade, in both scale and configuration. The megawatt-scale, pitch-regulated, variable-speed turbines that are common today have a relatively short track record. Most are still under warranty, so the reliability data for even this short time period are generally not available to the public. The component failures that do occur with newer machines often reflect a design that is not fully refined, and therefore may
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not be an accurate predictor of future reliability. The model does not reflect premature or serial failures, but rather uses failure rates that are appropriate for mature industrial equipment that has been field tested and proven. Another variable that has an uncertain effect on wind turbine reliability is the condition of the site. The wind regime, as characterized by mean wind speed or turbulence intensity, certainly affects the turbine load spectrum, but the effect of increased loading on the reliability of components has not been considered in this study. Other site conditions, such as extreme temperatures and blown dust, will affect turbine operation and may prematurely degrade components such as fluid lines, wiring insulation, and electronics. The model does not reflect these effects. Finally, not all turbine equipment is identical. The model assumes that all the turbines are equal in quality; that is, they are mature, proven designs, manufactured and installed with appropriate quality assurance measures, and supported by a competent service group. Still, variability between manufacturers, models, and even between individual turbines, is inevitable. These factors (limited performance data of short duration, different site conditions, and variability of equipment quality) present challenges to developing a universally applicable estimating tool. To the extent possible, the model is based on quantifiable data, but some values are based on engineering judgment, as noted in the text. As discussed in Section 6, the model projections have been benchmarked with actual performance for selected projects. However, neither GEC nor NREL can guarantee that the results of the model will accurately reflect any individual project at any given time.
2. Scope
The O&M cost model that is presented here is applicable to conventional, three-bladed WTGs installed on tubular towers. This configuration is the de facto standard for current machines and represents the bulk of machines installed in North America in the last decade. In general these machines include full-span-pitch blades, a planetary/helical gearbox, and an induction generator. Although direct-drive machines represent a 15% world market share, there are few in North America at this time. GEC has no access to the performance data for those machines. However, the model can be configured to accommodate a direct drive if the cost and performance data are available to the user. The generic turbines defined in the model include versions with either electric or hydraulic pitch systems and with either constant or variable rotor speed. No attempt has been made to estimate the costs associated with two- versus three-rotor blades, or with some of the recent innovative features such as permanent magnet generators. However, as stated previously, the model is flexible and has the capability to include any turbine configuration. The scope of this study and of the model is also restricted as follows:
Catastrophic events such as hurricanes, tornados, and lightning have not been considered. This is not to say that these events are not significant; lightning in particular has caused blade damage at numerous sites and will continue to be a risk as projects are installed in lightning-prone areas such as the Plains states. Retrofit work to remedy obvious design or manufacturing defects has not been included in the data that support the model. Components often fail during the first few years of a project, but we should not assume that these failures are representative of the reliability of that type of component. To do so would bias the failure distribution toward the anomalies rather than toward the norm. In some cases, the decision to exclude certain data is straightforward (e.g., where a serial failure has been declared). In other cases, the data point is an obvious outlier in the data set. These are discussed case by case as relevant. Repowering work (decommissioning equipment before the end of its useful life to install modern, usually higher powered equipment) has not been considered as part of the failure data. GEC has avoided data for projects where the motivation to maintain the equipment in optimal working condition has been damped by the prospect of decommissioning in the near future. Shipping and warehousing costs for parts are not included as line items. Given the variability and uncertainty of parts costs, and the number of options for warehousing spares, we may reasonably assume that shipping costs are included in the parts costs. Insurance costs were not included in the study; however, the model can be modified to include a placeholder. Balance-of-plant and substation maintenance costs were not specifically studied, but can be included with site maintenance costs at the users discretion.
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Offshore turbines are specifically excluded from this study. The O&M costs for an offshore installation are uniquely driven by accessibility for service and repair and are not consistent with land-based costs. However, the model can easily be modified to include aspects that are peculiar to offshore projects, such as access intervals and repair times. Land-lease costs, interconnect fees, and royalties are not considered to be O&M costs.
3. Background
O&M costs have long been an uncertain but significant component of the cost of energy from wind power facilities. Much of the current understanding of O&M costs is based on limited knowledge of short-term operating expenses from wind farms, many of which use older turbines that are not representative of current designs, and where the wind farm is much smaller than those being installed in the United States today. This information is combined with estimates about the long-term reliability and replacement costs of major turbine components. Because of the inexact nature of the input data, the O&M cost estimates that result from these analyses are imprecise; however, generally accepted approximations range from about $0.005 to $0.01/kilowatt-hour (kWh) for wind energy facilities in the United States. At low wind sites, where O&M per-turbine costs may remain fixed despite lower energy output, these costs may tend toward the high end of this range. Even higher costs may be incurred for smaller projects or where significant turbine repairs are necessary. Considering the goal of the Low Wind Speed Turbine project to reduce the cost of energy to $0.03/kWh at Class 4 wind sites, minimization of O&M costs should be a significant concern. The model, and the data contained within this report, will provide some insight into the various factors that affect turbine O&M costs.
4. Source Data
Data for this project have come from a variety of sources, including manufacturer publications, published case studies, expenditures and service logs from operating wind farms, and conversations and interviews with project managers and technicians. The quality and quantity of the available data can best be described as spotty. In some cases general estimates of overall maintenance costs for specific projects for periods of one or two years were available; in other cases detailed information on actual expenditures for a variety of turbines (but only for a snapshot of their operating life) was provided. As expected, the data are not in a consistent format, and are broken down into a surprising variety of categories for parts, labor, and downtime. Most importantly, there are no complete and consistent data for any project over the entire useful life of the turbines. Without exception, the older turbines (those reaching the end of their useful life) are smaller and simpler versions of the machines installed in the last five years. This distribution is consistent with the trend toward growth both in size and sophistication of wind turbines over the past 20 years. Following is a summary of the available data sources for this study:
Service logs from operating wind energy projects, which cover turbines that are smaller than 150 kW to nominally 2 MW, covering periods from one to six years. Parts consumption lists for operating projects, some of which include prices. Overall O&M summaries for current projects, including actual expenditures and projections. Spare parts price lists from manufacturers and receipts from actual projects. Interviews with operators and technicians about maintenance strategies, time to repair components, and time required for servicing. Manufacturer estimates of useful life and replacement rates for components. GECs general experience and collective knowledge from evaluating and monitoring a variety of wind projects over the past 19 years. Published studies that are specific to wind project O&M costs and reliability of industrial equipment in general.
Since many of the data used in the study are from private sources and are considered proprietary, GEC has made a conscious effort to avoid reference to specific project sites or equipment manufacturers. Most of the data presented here have been averaged, and where possible normalized, to avoid distinguishing any particular entry. References in the public domain, however, are acknowledged where appropriate.
5. Approach
This cost model is loosely based on previous efforts by GEC to estimate O&M costs for specific projects that comprise specific turbines. The general approach, carried through to this project, is to identify the cost contributors and assemble them into a structure that extrapolates those costs over the operating life of the project. The model assumes a project life of 20 years. Certainly some projects have passed the 20-year mark, and some have been curtailed early by repowering with new equipment. However, 20 years is a common assumption for financing purposes and is representative of the design life for most commercial turbines. Figure 1 shows the overall structure of the model. The database includes representative values for turbine and site service and repair parts, normalized to turbine size, height, and number. The required user inputs are in two broad categories: (1) characteristics related to the wind farm, such as number of turbines, assumed site capacity factor and expected sell price per kilowatt-hour; and (2) turbine characteristics, such as rated capacity, hub height, type of power conversion (fixed or variable speed) and pitch system.
Life-cycle Estimator
By default, the model creates a generic wind turbine as a proxy for commercial turbines. The reasons for this are partly practical: historical data for many of the turbines are limited and the cost data are generally proprietary. More importantly, a generic turbine allows extrapolation, on a common basis, from small to large sizes. This in turn allows the user to evaluate the relative benefits and disadvantages of using fewer large machines versus more small machines for a particular project.
The default turbine proposed in the model is based on the conventional three-bladed, pitchregulated, upwind, tubular tower machine. The model offers selection sizes of 750 kW to 2.5 MW, with hub heights of 60 to 85 meters (m); this range brackets the current offerings in North America. Height is important in that it drives the cost of the crane used for repairs. Table 1 presents some common tower heights for the range of turbine ratings covered in the model. Other combinations of turbine rating and tower height are viable, and depend largely on the wind class at a specific site. In some cases higher towers may be proposed for the turbines rated 2.0 MW and higher. Unfortunately the number of cranes in North America that are capable of lifting the nacelle components to heights above 85 m is limited, and the cost for this type of lift is difficult to estimate.
Table 1. Typical Turbine Rating/Tower Combinations
Size 750 kW 1.0 MW 1.5 MW 2.0 MW 2.5 MW Tower (m) 60 65 80 80 85 Configurations Hydraulic/electric pitch Hydraulic/electric pitch Hydraulic/electric pitch Hydraulic/electric pitch Hydraulic/electric pitch Variable/constant speed Variable/constant speed Variable speed only Variable speed only Variable speed only
In addition to turbine sizes, options are included for turbine type, pitch actuation system, and rotor speed control. Since hydraulically and electrically actuated systems are currently used on commercial equipment, the model includes both versions for any size range. Even though variable-speed operation is currently limited to only one manufacturer, this option is available for all sizes under the assumption that variable speed will be offered by more manufacturers as the patents expire or licensing agreements are put in place. Based on the input assumptions, the model uses scaling laws to populate the various cost contributors for the wind farm, based on the normalized data in the database. These costs are assigned to several categories (see Table 2). All these default assumptions are displayed, and the user can change any of them at will. This feature allows the user to refine the analysis to more accurately reflect conditions at a certain site, or even to add cost components that may be unique to a particular turbine. It also allows the user to evaluate the effect of different project configurations or operating strategies on O&M costs. For example, a 30-MW project that consists of 50, 600-kW turbines can be compared with one that consists of 10, 3-MW turbines.
Maintenance costs associated with options such as extreme weather operation, condition monitoring equipment, and service elevators are not included in the generic configurations. These can be added to the model as line items at the users discretion. 5.1 Model Assumptions The O&M costs have been segregated into the broad categories of facility and turbine costs to develop the assumptions used in the model. This breakdown is summarized as follows: Facility Costs Operations and administration Site maintenance Equipment and supplies Turbine Costs Labor Parts Consumables
In general, the facility costs will remain constant over the life of the project; the turbine costs will escalate as the equipment ages and components reach the end of their useful life. The final result is approximated in Figure 2.
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All costs for the entire period are presented in constant 2004 U.S. dollars (inflation in costs and labor rates is not considered). The next sections define the items in each category and discuss how the cost assumptions were reached.
5.2 Facility Costs Facility costs are linked to the size of the facility and are assumed to remain constant over the life of the project. This implies that the infrastructure is maintained in good condition for the projects life and that no improvements or expansions are made. The model assumes that the project has a minimum of 18 turbines and a maximum of 100 turbines; this is on the high end of most installed projects. The following sections describe the assumptions that are used to create example wind power projects and the method used to derive these assumptions. 5.2.1 Operations and Administration This category includes tasks associated with scheduling turbine crews, ordering and receiving parts for inventory, monitoring turbines status and performance, scheduling outside services for site maintenance, coordinating with the interconnect provider for outages and curtailments, and generating status and production reports. Since the most time-consuming activities are linked to the number of turbines, the model assumes that the manpower required for this activity depends only on the number of installed turbines, as opposed to the size of the turbine or the total capacity. For a small facility with fewer than 20 WTGs, these tasks are commonly assumed by a working manager who also covers some of the turbine maintenance activities. As the number of turbines increases to more than 20, a dedicated manager is commonly assigned. For facilities with more than 40 turbines, the model assumes an administrative assistant will be required, and an additional support person is assumed for more than 60 turbines. These assumptions are summarized in Table 3.
Table 3. Manpower Levels by Number of Turbines
Project Size Manager Support staff <20 WTGs 0.5 2140 WTGs 1 4060 WTGs 1 1 60100 WTGs 1 2
5.2.2 Site Maintenance Tasks that are not directly related to the turbine fall into this category. These include road maintenance, fence repair and brush clearing, maintenance building upkeep, meteorological equipment maintenance, and supervisory control and data acquisition (SCADA) system maintenance. Some activities may not be applicable to a specific site; others, such as snow removal, are applicable only to certain locations. The model assumes that these tasks are contracted to outside services, although depending on workload they may be assigned to turbine maintenance staff. Table 4 presents representative yearly expenditures.
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5.2.3 Equipment and Supplies Vehicles, tools, personal protection equipment, and supplies are collected in this category. General practice, for safety as well as practical reasons, is to dispatch two-person crews for any turbine maintenance work other than resetting faults. One vehicle and tool set are required per crew. Basic maintenance tools, special tools such as fixtures and rigging for removing large components, or remote terminals for communicating with the turbine controller for troubleshooting purposes, are provided with the initial turbine supply; replacements are included annually. Miscellaneous supplies are estimated for offices (paper, copier, utilities) and shops (fuel, personal protective equipment, rags, cleaners). Table 5 presents representative yearly expenditures.
Table 5. Representative Yearly Expenditures for Equipment and Supplies
Project Size Vehicles Tools Shop supplies Office supplies <20 WTGs $12,000/crew $8000/crew $2500/crew $7000 2140 WTGs $12,000/crew $8000/crew $2500/crew $9000 4060 WTGs $12,000/crew $8000/crew $2500/crew $11000 6080 WTGs $12,000/crew $8000/crew $2500/crew $13000 80100 WTGs $12,000/crew $8000/crew $2500/crew $15000
5.3 Turbine Costs Turbine costs are linked to size and configuration, and generally escalate over time as the machines age and parts wear out. As discussed in the following sections, labor costs and replacement parts costs are linked to turbine size and age; consumables are linked only to turbine size. 5.3.1 Labor This category includes all staff who are dedicated to routine turbine maintenance, which includes regular turbine servicing, resets, troubleshooting, and minor repairs. Labor for major repairs, including any tasks that require a crane or more than a one hour of work for two technicians, is additionally included in the parts replacement cost. A survey of a variety of sites indicates that the number of turbines that one technician can cover depends only slightly on the size of the machine. Figure 3 shows the number of turbines per
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technician for 10 representative sites, for turbines in the range of 500 to 2000 kW. The average number of turbines per technician is 16 and 12 for the smaller and larger machines, respectively, but the scatter within any group is very high. For these projects, which range from 20 to more than 100 MW installed capacity, there is no consistent trend between project size and number of technicians.
# WTG / tech
25.0 # WTG / technician 20.0 15.0 10.0 5.0 0.0 0 500 1000 Turbine size (kW) 1500 2000
Several factors, including the tasks associated with regular servicing, the number of fault resets required, and the number and severity of repairs required, influence the time required to maintain a machine. Discussions with operators indicate that regular biannual service for modern turbines requires 2040 hours; the wide range is associated with pitch-regulated machines. Time for repair and fault resets, excluding retrofit activities, is approximately equivalent to service hours. This ratio of service to repair hours is reasonably consistent with older projects. As expected, the available data indicate that the total service hours per turbine, for similar size machines in the range of 500 to 1000 kW rated power, increases with turbine age and then levels off. Figure 4 shows the total annual service hours per turbine for four projects with similar size machines. The newer machines are slightly larger than the older machines, which suggests that their labor costs may level out at a higher cost as they age.
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Figure 4, shows the estimated hours required for turbine maintenance. Table 6 lists these assumptions for turbines. The labor hours assumed for maintaining higher rated turbines reflects the additional time required for turbine access and increased maintenance points. A reasonable number of hours that a full-time employee can effectively devote to maintenance work is 1800 per year; this accounts for 80 hours of vacation and sick leave, and 10% time devoted to administrative activities such as site meetings and safety training. The default crew sizes in the model are calculated by dividing the number of available hours per technician by the required hours per turbine. These estimates agree reasonably well with the data points for the first 10 years presented in Figure 3.
Table 6. Labor Hours per Turbine per Technician by Year
Period (Years) 750 kW to <1 MW >1 MW to 2.5 MW 15 100 200 610 150 250 1115 200 300 1620 250 350
These relationships are used as the default values in the model to estimate turbine maintenance hours given the turbine size and the number of turbines assigned to the project. Even though technicians are routinely dispatched in two-person crews for practical and safety reasons, in some cases odd numbers are used in the analyses. This extra person can be considered to account for turnover, training, and relief time for other employees. The model assumes the hourly rates for site staff that are shown in Table 7. These are representative of rates at operating projects. Technician rates will usually vary by skill level and experience, and often a crew will consist of a senior-level technician paired with a junior-level technician; these are average values for such a crew. Local rates can vary by 25% depending on the labor market in the area.
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5.3.2 Parts This category includes all replacement parts for the turbines, exclusive of consumables. The parts that are considered candidates for replacement, including mechanical, electrical, and hydraulic components, are those that wear or deteriorate during normal use. Mechanical parts that experience any form of friction, contact, or flexure (e.g., bearings, seals, gears, diaphragms, brake and yaw pads) are all candidates, although (as discussed in Section 5.3.4), the failure rate can vary dramatically depending on the design life and duty cycle. Fatigue of mechanical and structural components is explicitly omitted from the model, which assumes that the load-carrying components are designed with adequate design life for the imposed loads and duty cycle. For example, gearboxes are included in mechanical wear items, but the main shaft and bedplate are excluded. By the same reasoning, blades are assumed to structurally survive for the design life of the turbine, although the model assumes that minor blade repairs or refinishing to compensate for damage or wear will be required. Hydraulic parts include pumps, valves and hoses, cylinders, and calipers. There are two distinct failure modes for these components, which have different failure distributions. In general, hoses will deteriorate over time regardless of use, and thus will have a calendar replacement schedule. The other components will wear based on use, and thus will have a replacement distribution based on operating hours. Electrical components such as contactors and circuit breakers that include contacts and moving parts are candidates for wear; main power cables are assumed to last for the life of the machine. Solid-state components such as control boards, power converter regulator boards, and soft-start trigger boards are included as they exhibit thermal deterioration over time. Motors and generators are included as the bearings wear mechanically and the windings fatigue thermally and mechanically with use. The parts are segregated into the categories shown in Table 8. For each category, the major cost items are included and minor cost items are placed into a miscellaneous category.
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As discussed earlier, an effort has been made to standardize the turbines to allow comparison on a common basis for different size machines. The components included in the generic configuration represent the current state of the art for modern turbines currently being supplied, although specifics will vary in the type of components included. These assumptions are described below for each component category.
Rotor: The rotor is three-bladed with independent pitch for each blade. The pitch bearings are rolling-element type, and are periodically lubricated with grease. The pitch mechanism is one of two types: (1) hydraulic pitch systems, which include a pitch cylinder, proportional valve, crank arm mechanism, accumulator, and displacement transducer for each blade. The pump and position controller are common to all three mechanisms; and (2) electric pitch systems, which include a motor with position encoder, gear reducer, electronic drive, and backup battery bank for each blade. The position controller is common for all three mechanisms. Control and Monitoring: The control and monitoring system consists of a main controller in the turbine base, a remote controller in the nacelle, and another in the hub. The base unit contains a user interface and display. Control sensors include wind measurement instruments, rotor speed control, and power/grid monitoring transducers; sensors specific to monitoring component condition (e.g., PT100s for the generator) are included in that component category. Drive Train: The drive train consists of a main shaft supported by two main bearings, coupled to the gearbox with a hydraulic shrink coupling. A composite tube with flexure connections is used to couple the gearbox to the generator. Electrical Power and Grid: The turbine switchgear consists of a main breaker/disconnect, a line contactor for the generator power, and smaller contactors and circuit breakers for ancillary systems and power factor correction capacitors. A soft-starter is included for connecting to the grid for constant-speed machines. Gearbox: The gearbox is a combination planetary/helical unit with an integral lubrication system and fluid cooler system. The gearbox is suspended from the bedplate with elastomeric bushings.
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Generator: The generator is single-speed, induction type. The variable-speed machine includes a wound rotor and slip-rings. Cooling is provided by an integral forced-air system. Brake: The brake is a caliper-type located on the gearbox high-speed shaft. A dedicated hydraulic system provides pressure for the calipers. The brake is used only for parking, as the primary rotor brake is the blade pitch system. Yaw System: The yaw bearing is a sliding-bearing type with spring-applied calipers for stabilization. The surfaces are periodically lubricated with grease. The yaw drives are electric-motor driven with a multiple-reduction gearbox. The number and size of the yaw drives increase with turbine size. Miscellaneous: An overall category for miscellaneous parts that includes a value for parts not identified specifically elsewhere, such as hardware (brackets, pins, fasteners), small hydraulics (hoses, valves), and small electrics (contactors, lights, switches, connectors).
Parts costs for each of the five generic turbine sizes were estimated from machine cost data. In some cases these data have been drawn from manufacturers price lists; in other cases they have come from actual receipts. The former data set is subject to an indeterminate markup; the latter is more limited in scope. All major wear parts are covered; minor parts are not included in the miscellaneous category. Those with a useful life approaching 20 years may be missing, but the impact of these omissions will be included in the margin of error for the major high-cost components. Although small parts will likely be replaced in their entirety as they fail, larger components will likely be rebuilt. This is especially true of the high-priced components like the gearbox and generator, but applies as well to contactors, yaw drives, and power converters. Estimated replacement costs used in the model are based on rebuild cost where appropriate. The parts quantities and costs for the five generic turbines used in the model, along with the relations used to develop these costs, are included in Appendix B. 5.3.3 Consumables Parts and supplies that are required for scheduled service, as opposed to repairs, are considered consumable. This category includes lubricants, filters, and cooling fluids. Parts such as brake pads and generator bushes, which are replaced indeterminately, are included in the parts category. Annual turbine services generally include filter elements and greasing of the main bearing, yaw bearing and gear, pitch bearings, and generator bearings. Gear oil is mineral, as opposed to synthetic, and, according to common practice, should be replaced every three years. The model assumes an offline gear oil filter system and annual oil sampling. Hydraulic fluid will be replenished as required; this is generally a minor expenditure. Table 9 lists these per-turbine consumable estimates for each generic turbine size in the model. Grease quantity is assumed to be scaled proportionally to turbine rated power. Consistent with the current gearbox design guidelines, gear oil quantity scales with turbine rated power at approximately 0.15 liters (L)/kW. Gear oil filter costs are assumed to increase linearly with
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gearbox oil quantity. Hydraulic filters are assumed to be constant with turbine size. Electricity for turbine ancillary equipment (heaters, lights, winch) is estimated at 2 kW/MW at $.05/kWh.
Table 9. Per-Turbine Annual Consumable Cost Estimates, $
Turbine Size Gear oil filter, ea Hydraulic filter, ea Offline filter, ea Hydraulic oil, @$40/L Gear oil, @ 3.70/L Yaw gear grease @15/tube Bearing grease @ $10/tube Oil testing, ea Electricity 750 kW 100 100 100 20 140 60 45 120 657 1 MW 133 100 100 20 187 80 60 120 876 1.5 MW 200 100 100 20 279 120 90 120 1314 2.0 MW 267 100 100 20 371 160 120 120 1752 2.5 MW 333 100 100 20 464 200 150 120 2190
5.3.4 Failure Rates The model estimates parts use by applying two types of failure rates to selected components, or categories of components. The first type of failure event is random, and is represented by a constant failure rate. The model assumes by default that 5% of the blades, main, yaw and pitch bearings, generators, and yaw drives will fail over the 20-year life of the project because of uncontrollable circumstances such as lightning strikes, manufacturer defects, operational errors, or servicing omissions and errors. Additionally, a miscellaneous category includes minor mechanical, hydraulic, and electrical parts such as fasteners, fittings, and switches, which are assumed to fail randomly throughout the project life. The second type of failure event is wear out or deterioration, and is a two-parameter Weibull distribution. This distribution is commonly used in reliability studies as it allows for variation of the scale as well as the shape of the failure distribution. Weibull distributions are intended to describe failure rates for a given population of like components. Generally the most reliable data are obtained from exercising the components in actual or simulated conditions that are consistent over time. In an actual application, however, the parts that fail are replaced, so that the population eventually becomes a combination of components with varying periods of operation. At some point in time past the characteristic life, the instantaneous failure rate will oscillate about, and finally approach, a constant value. The failure rates in the model are based on historical data from operating sites as well as published failure rates for similar components in similar applications. As discussed previously, the available data are sparse and incomplete. Although in some cases GEC has data for periods covering 20 years, these data are for different models and machine sizes throughout this time span. There are no reliable data for any one type of machine for a complete life cycle. Also, the meaning of failure is not always clear, as parts are sometimes replaced when they start to fail, and at other times when they have completely stopped functioning. For some part types (e.g., a
17
control module), failure is definitive, but in other cases (e.g., a gearbox) a wide range of acceptable operating conditions may span significant periods of time. Table 10 summarizes the failure rates, in terms of mean time between failures (MTBF), assumed in the model default turbines, along with representative failure rates from three other sources. MTBF, also referred to as mean life, is the period of time in which half a given population of like components is expected to fail. MTBF is a common metric used in reliability studies. It is related to the Weibull characteristic life by the following relation:
MeanLife = CharcteristicLife (ln 2) 1
A Vachon, W.A. Modeling the Reliability and Maintenance Costs of Wind Turbines Using Weibull Analysis. Windpower 96 Conference Proceedings. B Barringer Associates, Inc. Weibull Database. www.barringer1.com/wdbase.htm. C Assume 5% random failure rate for 20-year project life. D Assume 100% require refurbishment over 20-year project life.
The discrepancies in Table 10 for any one component can be partially explained by the uncertainty of the sources. The data presented by Vachon are limited to one particular era of wind turbines that had operated for 14 years at the time of the study, with missing data for a
18
portion of the early years. Vachon also assumed a constant shape parameter of 3.5, which represents a symmetrical distribution. This is not consistent with the shape parameters in the Weibull database, which are generally less than 2. The data set for the Weibull database includes a wide variety of component types and operating conditions, and is not necessarily representative of the purpose-designed components in a commercial wind turbine. Appendix C discusses the failure rate assumptions used in the model for selected components, along with GECs rationale for selecting the Weibull parameters. 5.3.5 Time to Repair The values used in the model for time to repair or replace a component are based on discussions with operators and technicians and estimates provided by several manufacturers. In some cases GEC did attempt to verify these estimates with service logs, but the lack of consistency in the recording and presentation of the logs allowed for only a rough check. The model only includes time for repair of major components; that is, those that require rigging of some sort and a repair time of more than two hours. Repair time for all other components is assumed to be covered by the general service hours allocated in Section 5.3.1. The model assumes that where required, replacement parts are readily available and that no significant transport or wait time is required. This is consistent with most large facilities that have a stock of spares, including gearbox and generator, but this may not be a valid assumption for smaller facilities that use a central manufacturers depot for parts. Table 11 lists the assumed repair times in man-hours. These include shop preparation time.
19
750 kW 30 6 50 8 4 4 6 4 100 12 70 4 4 16 10 8 4 4 6 4 4 4 8 8 8 4 8 6
1 MW 30 10 50 8 4 4 6 4 110 12 80 4 4 18 10 8 4 4 6 4 4 4 8 8 8 4 8 10
1.5 MW 40 12 60 8 4 4 6 4 120 12 90 4 4 20 10 8 4 4 6 4 4 4 8 8 8 4 8 12
5.3.6 Cranes The model assumes that the wind energy facility rents a crane for any major replacement, and that the replacements will occur on a per-unit basis. That is, the advantages of multiple replacements with one crane rental will not be realized (or required) for a site that follows the failure assumption proposed in the model. Crane rental costs are driven by crane capacity and mobilization time. Discussions with crane rental companies confirm the conclusions from previous studies: the crane capacity required for removal and replacement (R&R) of the two large components (gearbox and generator) is driven by height, not weight. Two common crane typesconventional crawler cranes and truckmounted cranesare appropriate for wind turbine component replacements. Cost for the former is driven by mobilization, as the crane and boom are shipped in pieces and require 10 to 20
20
truckloads, depending on height. Hydraulic truck-mounted cranes use a telescopic boom and require only one to three additional loads for counterweights, and are significantly cheaper to mobilize, but generally cost more per hour. Conventional cranes are sometimes available in a truck-mounted version, but still require multiple loads for the lattice boom and jibs. For both cranes types, the height and reach are maximized by adding boom extensions (fixed jib or luffing jib) to obtain the required reach over the nacelle structure. As height and reach increase, additional counterweight must be attached to the crane body. The lift capacity decreases with height and reach. Fortunately, the weights of major turbine components are relatively small compared to crane tonnage, so that in most cases a given crane can be maximized for height. Figure 5 and Figure 6 show representative weights for gearboxes and generators for current model wind turbines.
20 18 16 14 Weight (mt) 12 10 8 6 4 2 0 0 500 1000 1500 Rated Power (kW) 2000 2500 3000 y = 0.0072x - 0.2467 2 R = 0.8134
21
10.0 9.0 8.0 7.0 Weight (mt) 6.0 5.0 4.0 3.0 2.0 1.0 0.0 0 500 1000 1500 2000 2500 3000 Rated Power (kW) y = 0.0031x + 1.3789 R = 0.6208
2
In general, the candidate cranes for wind turbine work are limited to discrete sizes, and not all of these are readily available near the turbine site. Figure 7 shows example costs for cranes used for R&R of a gearbox at projects in a variety of locations, along with estimates for similar work provided by crane leasing companies. The lower tonnage equipment is truck-mounted hydraulic equipment and the higher tonnage is conventional crawler type.
100000 90000 80000 Cost per Crane Event ($) 70000 60000 50000 40000 30000 20000 10000 0 0 100 200 300 400 500 600 700
Tonnage (mt)
22
Table 12 through Table 14 list appropriate cranes for the five generic turbine sizes proposed in the model, along with representative costs for one day of R&R work and in/out mobilization. These are the default values in the model. The associated costs, which are based on experience with operating projects, include a second assembly crane, fuel, insurance, operator, and rigger for a lattice-type crawler crane. Mobilization cost assumes one day of travel each way from the rental depot. For the larger turbines, it is becoming more common to offer a nacelle-mounted crane for removal of the generator. This option is available on several large commercial machines, but there is little evidence the internal option is being purchased. Thus, the model currently assumes no internal crane to remove and replace the generator or other components for 2- and 2.5-MW models. Crane costs can be added or removed in the entry sheet, thus simulating an internal or external crane. An example of this is shown at the end of Section 6.
Table 12. Gearbox and Main Bearing R&R Crane Assumptions
Turbine size Tower height Gearbox weight Crane size Crane type R&R cost 750 kW 60 m 5.5 mt 200 ton Truck-mounted hydraulic $10,000 1.0 MW 65 m 7 mt 240 ton Truck-mounted hydraulic $25,000 1.5 MW 70 m 10 mt 400 ton Conventional crawler $50,000 2.0 MW 80 m 16 mt 400 ton Conventional crawler $70,000 2.5 MW 85 m 18 mt 650 ton Conventional crawler $90,000
* Griffin, Dayton A. WindPACT Turbine Design Scaling Studies Technical Area 1 Composite Blades for 80- to 120-Meter Rotor, March 21, 2000 March 15, 2001. National Renewable Energy Laboratory. NREL/SR-500-29492, April 2001.
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6. Results
The model provides results in a variety of forms, including cost tables for each major category on a project, per-turbine, and per-kilowatt-hour basis. Tables also list the cost assumptions for all turbine parts and the total number of parts used in the 20-year project life. Copies of complete results from each model run are included in Appendix D. The results show total costs associated with scheduled maintenance, unscheduled maintenance, and levelized replacement costs (LRC). The last category is commonly used to estimate reserves that will be required for major component overhauls or replacements. The failure rate and cost estimates provided by the model could be used to inform the process for establishing the required monetary reserves to cover LRC. Also, the model does not account for lost revenue caused by turbine downtime for repair or service, as this is usually accounted for in the project availability assumptions. Figure 8 presents graphical results of executing the model with the five generic turbine sizes. The chart shows estimated costs on a per turbine basis. The configuration for each size is consistent with most currently available commercial turbines. The project size in each case is 60 MW and the calculations assume a capacity factor of 35%.
Turbine Cost Comparison Study
Annual Average over 20 years, 60 MW Project Size (includes levelized replacement costs)
60,000
50,000
40,000
30,000
20,000
10,000
0 Parts Replacement (Hardware, Addt'l Labor, Crane) Consumables Salaried Labor Wage-based Labor Site Maintenance Equipment Total
Category 1000 kW, const. spd, hydraulic, 65-m tower 2000 kW, variable speed, electric pitch, 80-m tower
750 kW, const. spd, hydraulic, 60-m tower 1500 kW, var. speed, electric 80-m tower 2500 kW, variable speed, electric pitch, 80-m tower
24
The O&M cost estimates for the five turbine sizes demonstrate that the major contributor to overall O&M costs over the project life is parts replacement, followed by labor. Figure 9 shows that in the first 5 years, parts costs are estimated to be 30% of the total cost, and by the end of the project life, they exceed 65% of the total cost. Additionally, if the 20-year average of $37,000 per turbine were used to gauge warranty costs for contract negotiations, rather than the average for years 15 of $19,000, valuable reserve funds could easily be forfeited to the warranty service provider.
Average O&M Cost per Turbine 1500 kW, variable speed, electric pitch, 80-m hub height, 60 MW Project Size
Includes levelized replacement costs 60000 Average Cost ($/turbine) 50000 40000 30000 20000 10000 0 Equipment Site Maintenance Wage-based Labor Salaried Labor Consumables Parts Replacement (Hardware, Addt'l Labor, Crane) Average yr 1-5 600 353 3791 5231 2348 6333 Average yr 6-10 600 353 4633 5231 2348 18588 Avg yr 11-15 600 353 5897 5231 2348 29695 Avg yr 16-20 600 353 6739 5231 2348 36154
Period
Looking at the 1500 -W turbine size in the study, parts costs are dominated by the failure of large parts that require the use of a crane (see Figure 10 and Figure 11).
25
60000
50000
40000 $ / turbine / yr
30000
20000
10000
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Project Age (yr) Parts Replacement (Hardware, Addt'l Labor, Crane) Salaried Labor Site Maintenance Total Consumables Wage-based Labor Equipment
59%
38%
The bumpiness is an artifact of the high-cost infrequent events, and will be accentuated as the number of turbines in the project decreases. An indication of where the high costs are occurring can be found in Figure 12, which shows that the gearbox (including lubrication) and rotor systems are the largest cost drivers.
26
Yaw System 3%
Rotor 21%
A closer examination shows the failure distribution for some major components in each system (see Figure 13). An increase in major failures is noticeable around year 7 when the first gearbox failures are assumed to occur, and later in year 10 when coincident gearbox and structural blade failures are projected.
Cumulative failures or replacements by year (major components)
Repair or Total Failures Replacements over 20 yrs / in 20 yrs per initial qty parts Project in fleet (%) 3 72 1 4% 100% 4%
System
Rotor Drivetrain
Component
Blade--struct. repair Blade--nonstruct. repair Main bearing
1 0 6 0
2 0 6 0
3 0 6 0
4 1 6 0
5 0 6 0
6 0 6 0
7 1 6 0
8 0 6 0
9 10 11 12 13 14 15 16 17 18 19 20 0 6 0 1 6 1 0 6 0 0 6 0 0 6 0 1 6 0 0 6 0 0 6 0 1 6 0 0 6 0 0 6 0 1 6 1
Parts in Project 72 72 24
Gearbox and Lube Gearbox--gear & brgs Gearbox--brgs, all Gearbox--high speed only Generator and Cooling Generator--rot. & brgs Generator--brgs only Power electronics Total
0 0 0 0 0 0 6
0 0 0 0 0 1 7
0 0 0 0 0 1 7
0 0 0 0 0 1 8
0 0 0 0 1 2 9
0 0 0
0 1 1
0 0 0
0 1 1
1 1 1
0 2 2
0 2 2
0 1 1
0 3 3
0 2 2
0 3 3
0 2 2
0 3 3
0 3 3
1 2 2
24 24 24 24 48 24
1 15 15 1 43 26
0 0 0 0 1 0 0 0 0 0 0 0 0 0 1 1 2 2 3 4 4 6 5 6 7 6 7 7 6 5 1 2 2 3 3 3 2 4 3 3 3 3 3 3 3 8 13 10 14 19 17 18 17 22 20 21 21 22 21 22
Although the timing and frequency of these events will vary from site to site, their occurrence will have a major impact on site resources. Projects usually maintain budget reserves for just this contingency, and may rely on additional short-term labor resources. A trend in O&M costs as turbine size increases can be demonstrated with two additional common metrics that are used to evaluate project and turbine performance. Higher rated turbines
27
are projected to cost less per kilowatt irrespective of age. This effect is demonstrated in Figure 14, which shows three turbine sizes of identical architecture (variable speed, electric pitch, 80-m towers).
Average Project Cost, 60 MW Variable Speed, Electric Pitch, 80-m Hub Height 40.0 35.0 Cost per Turbine ($ / kW) 30.0 25.0 20.0 15.0 10.0 5.0 0.0 Average yr 1-5 Average yr 6-10 Avg yr 11-15 Year 1500 2000 2500 Avg yr 16-20 20 yr Avg
Finally, Figure 15 shows the per kilowatt-hour change in cost. The trends for this metric parallel the trends shown above. This must be so, because a constant capacity factor of 35% has been used in all the models. Figure 16 is an annual look at the data in Figure 15. Along with Figure 17, it shows that the high O&M cost for 2500 kW turbines in years 1620 was caused by a compounding of failures in year 16.
28
0.010
0.006
0.004
0.002
0.000 Average yr 1-5 Average yr 6-10 Avg yr 11-15 Year 1500 2000 2500 Avg yr 16-20 20 yr Avg
2500
1500
1000
500
29
System
Rotor Drivetrain
Component
Blade--struct. repair Blade--nonstruct. repair Main bearing
1 0 3 0
2 0 4 0
3 0 3 0
4 0 4 0
5 0 4 0
6 1 3 0
7 0 4 0
8 0 3 0
9 10 11 12 13 14 15 16 17 18 19 20 0 4 0 0 4 0 0 3 0 1 4 0 0 3 0 0 4 0 0 4 0 0 3 0 1 4 1 0 3 0 0 4 0 0 4 0
Parts in Project 72 72 24
Gearbox and Lube Gearbox--gear & brgs Gearbox--brgs, all Gearbox--high speed only Generator and Cooling Generator--rot. & brgs Generator--brgs only Power electronics Total
0 0 0 0 0 0 3
0 0 0 0 0 0 4
0 0 0 0 0 1 4
0 0 0 0 0 1 5
0 0 0 0 0 1 5
0 0 0 0 1 1 6
0 0 0 0 1 1 6
0 1 1 0 2 1 8
0 0 0
0 1 1
0 1 1
0 1 1
0 1 1
0 1 1
0 1 1
0 2 2
1 2 2
0 1 1
0 2 2
0 1 1
24 24 24 24 48 24
1 15 15 1 43 26
0 0 1 3 1 2 6 11
0 0 0 0 0 0 1 0 0 0 2 3 4 3 4 4 4 4 3 4 1 2 1 2 2 2 2 1 2 2 8 12 10 11 12 13 18 10 13 12
Figure 17. Annual failures of 2.5 MW major components, 60-MW project size
A change in architecture such as hub height can affect the O&M costs, so the model is useful for making project development decisions in conjunction with other estimates of project performance, such as hub-height power production. Figure 18 shows the effect of increasing the tower size from 80 to 100 m.
Average Project Cost (2.5 MW turbines, 60 MW Project Size, no internal crane) 35.0 30.0 25.0 Cost ($ / kW) 20.0 15.0 10.0 5.0 0.0 Average yr 1-5 Average yr 6-10 Avg yr 11-15 Tow er Height 80m 100m Avg yr 16-20 20 yr Avg
Figure 18. Estimated O&M costs for 2.5-MW Turbines on 80-m versus 100-m towers
Other studies, such as whether O&M cost savings can be achieved by using an internal crane, can be performed. In Figure 19, the comparison shows savings of more than $2 million if an internal crane can lift blades and generators. The developer may be able to decide whether to use the internal crane based on expected use and the additional cost of an internal crane.
30
Annual Project Cost Internal v. Conventional Crane, Blade and Generator Repair (2.5 MW turbines, 60 MW Project Size )
30,000 25,000 20,000 ($000) 15,000 10,000 5,000 0 100m, no internal crane 100m, internal crane
31
32
already available on some options. Alternate rigging and winching to remove blades, generators, and gearboxes could reduce both the cost and the risk to the project. 7.5 Recordkeeping Extracting useful data from the available record was seriously limited by the inconsistency of the recording methods. The service logs and parts costs data were usually stored separately, which complicated the process of correlating costs with failure events. Projects would be well served by establishing a common recordkeeping system that allows failure events and associated costs to be easily extracted.
33
8. Conclusions
GEC has developed a tool for estimating O&M costs for wind energy projects. This model includes all the major cost contributors and is based on historical operating data from a variety of operating wind energy projects. The model was created in an Excel spreadsheet with a simple user interface and includes a range of generic turbines as examples. The model estimates O&M costs over the 20-year life of the project, and allows the user to modify the project and turbine specifics. This tool should prove useful to project developers, owners, and operators in their evaluation of turbine and project options.
34
Appendix A
2.0
3.0
default data if you change parameters in Tables 1 and 2 by clicking the Use Default macro buttons associated with each table in Tables 3 through 7. If you plan to use values other than default values, you should configure the wind farm and turbine tables first, refresh with defaults second, and then enter the custom values; otherwise, you will have default values from a prior configuration. A quick check with the default values to the right of each field will confirm whether you have updated your configuration with the Reset Default macro. Some user notes appear on the User Entry worksheet that are reminders. You may add notes. 3.1 Table 1. Wind Farm Operations Enter appropriate values for your study. Capacity factor is used for determining the turbine operating costs per kWh (typically a range of 0.25 to 0.40 is used, depending on average site conditions expected for the 20year period). Energy sales price is currently used in the gross annual revenue calculation found in the Results Tables worksheet. The gross revenue is used merely as a relative reference to the O&M costs. Net revenue will not only be a function of O&M costs, but other costs not determined in the spreadsheet, such as land lease, insurance, taxes, etc. 3.2 Table 2. Wind Turbine Characteristics Enter or select from the drop-down list appropriate values for your study. Turbine rated power choices available are 7502500 kW in increments of 50 kW. Default data from the Facility Costs worksheet is based on either 750, 1000, 1500, 2000, or 2500, whichever your value is closest to. Power conversion choices are constant speed or variable speed. Default parts associated with each type of system are assigned quantities appropriate to the system. Parts not associated with each system will appear on the default parts list, but will have quantities of 0. Pitch control choices available are hydraulic, electric, or fixed. All pitchable systems are assumed to be full span. Default parts associated with each type of system are assigned quantities appropriate to three-bladed turbines. Parts not associated with each system will appear on the default parts list, but will have quantities of 0. Hub height is based on default values typical in the industry for each rating of turbine. Ultimately, tower height affects crane costs. If you are performing a comparison of O&M costs associated with various tower heights but do not have available crane cost data, you may manually enter the default value associated with each crane type or height found in the Facility Costs worksheet. 3.3 Table 3. Staffing Levels and Costs Rates for manager, technician, and administrative assistant may be adjusted, as well as the burden, which accounts for additional costs above a negotiated salary or wage such as Social Security, medical, and retirement benefits. Administrator costs are annual salary values; technicians are hourly wages. To calculate hourly wages from an annual salary, divide the annual salary by 2080, which is a standard man-year.
A-2
3.4 Table 4. Annual Turbine Consumables Default values are annual costs on a per turbine basis, and are driven by calendar rather than operating time. They are assumed to remain constant for 20 years using constant 2004 costs as a reference for default data. Additional cells are provided for additional consumable items and costs. 3.5 Table 5. Crane Cost (+Mobilization) Costs are driven to a large extent by mobilization, so you should obtain accurate data for the site. All parts replacements that require a crane assume the event is singular, rather than serial, and require a deployment for each failure except blade nonstructural repairs in the default parts list: all three blades are assumed to be repaired simultaneously with one mobilization. Additional cells are provided for additional crane costs that are associated with a specific component. If you select "TRUE" for any parts that require a crane in the parts list, the component name and crane data need to be added to the crane costs table. To ensure correct lookup of the crane cost, you should use the "Update Table 5" macro button at the top of the column, and then enter the appropriate crane cost to Table 5 adjacent to any components without values to update the component title in the user cell. 3.6 Table 6. Site Equipment, Supplies, and Maintenance You can supply your own values; however, site equipment and maintenance costs are small relative to the overall O&M costs. Additional cells are provided for additional items. 3.7 Table 7. Turbine Parts List Default values are based on field data. However, specific user data will provide more accurate results. If you choose to input different values, enter them in the user cells. Entering user values will override the default. To reset everything in the list to the default values, select the default macro button at the top of the table. A word of caution: You should copy the user values to a comparison study as a backup. If the user values are accidentally overwritten, the backup values can be reloaded. You may select Constant or Weibull failure distributions. Many of the default data are based on Weibull Database failure distributions and correlated to available data. However, some failure rates of major components tend to be constant (and random), and are more accurately modeled with a constant failure rate. Operational experience will provide the best guidance. You can study the effects of reduced part mean life by adjusting the Weibull alpha or beta parameters and looking at the adjacent mean life calculation. The Miscellaneous parts category in the default parts list is used to account for all the remaining smaller components of the turbine. Ideally, each has a unique failure distribution. In reality, the overall effects of parts listed in this category are expected to be minor in relation to the other parts. As operators become more familiar with the characteristics of their parts, those with high failure rates may be added to the list as separate parts to investigate the cost effect on overall O&M.
A-3
4.0
Viewing and Saving Results Initial results are best viewed by using the Results Tables tab. Each table and chart represents a different way of looking at the data. To provide some comparison studies, you may save the results to the Comparison Studies worksheet by selecting the appropriate capture macro. Up to three studies can be compared at one time. You should capture the initial study with all three macro buttons, so as not to have a study captured from prior use of the spreadsheet. This is useful to evaluate the sensitivity of a serial part failure, or adjusted cost, such as a labor rate increase. You should use the Saved As to save the file with an appropriate filename to protect a specific analysis. Problem Notification and Enhancement Requests We appreciate of any feedback you can provide. Your participation is very important, and can greatly improve the quality of the cost model for the entire user community. Please e-mail any problems or requests for enhancement to the following address: droberts@globalenergyconcepts.com or gec@globalenergyconcepts.com attention: Task Code N12 Project Administrator subject: Enhancement request or Problem notification
5.0
A-4
B-1
Part Identification
System Rotor Component Blade--struct. repair Blade--nonstruct. repair Pitch cylinder & linkage Pitch bearing Pump & Hydraulics Pitch position xdcr Pitch motor Pitch gear Pitch drive Main bearing High-speed coupling Gearbox--gear & brgs Gearbox--brgs, all Gearbox--high speed only Lube pumps Generator and Cooling Generator--rot. & brgs Generator--brgs only Power electronics Motor, generator coolant fan Contactor, generator Brakes & Hydraulics Brake caliper Brake Pads Accumulator Hydraulic pump Hydraulic valve Yaw System Yaw gear (drive+motor) Yaw caliper Yaw sliding pads Yaw bearing Control board, Top Control board, Main Control Module 750 24,500 2,450 1,470 6,200 3,780 1,000 2,000 1,015 2,100 4,500 2,045 65,030 37,160 18,580 1,000 16,800 1,650 18,000 257 830 1,170 200 800 1,200 120 4,683 250 400 2,850 2,350 2,900 580 1000 33,750 3,375 1,590 9,700 3,780 1,000 2,667 1,353 2,800 7,100 2,727 92,470 52,840 26,420 1,100 28,840 2,200 18,000 257 1,430 1,230 200 1,400 1,200 120 6,244 250 400 4,102 3,150 3,950 790
$ / Event
Rating 1500 52,956 6,581 2,087 17,834 3,931 1,076 4,076 2,143 4,276 15,668 4,318 153,601 88,501 43,854 1,476 53,228 3,489 18,151 332 2,696 1,483 200 3,076 1,276 158 4,834 401 551 9,121 4,700 6,000 1,200 2000 71,406 8,426 2,395 24,834 3,931 1,076 5,409 2,896 5,676 23,457 5,681 217,910 125,330 62,400 1,676 77,276 4,589 18,151 332 3,896 1,613 200 5,176 1,276 158 6,395 401 551 12,320 6,300 8,100 1,620 2500 90,095 10,503 2,702 32,023 3,931 1,076 6,742 3,610 7,076 32,635 7,045 286,118 164,468 82,007 1,976 101,324 5,689 18,151 332 5,086 1,743 200 7,776 1,276 158 7,956 401 551 15,918 7,850 10,200 2,040 Repair Description Structural fiber repair, replace with spare during repair Cosmetic skin repair; drop rotor and repair 3 at a time Rebuild seals and servo Replace Replace components only Replace Replace Rebuild, bearing replacement, refinish gears Replace IGBTs, repair driver board Replace Replace Rebuild, bearing replacement, refinish gears Rebuild, bearing replacement Rebuild HS side, bearing replacement Replace Rebuild rotor windings, replace bearings Replace bearings Replace IGBTs, repair driver board Replace Replace Replace seals Replace Replace Replace Replace Rebuild, bearing replacement, refinish gears Replace seals Replace Replace Swapout with spare, repair board Swapout with spare, repair board Replace
34,317 4,509 1,779 10,645 3,931 1,076 2,742 1,467 2,876 9,179 2,954 93,982 54,352 26,722 1,176 29,180 2,389 18,151 332 1,506 1,343 200 1,476 1,276 158 6,395 401 551 6,181 3,150 3,950 790
Drivetrain
Control System
Sensor, static Sensor, dynamic Main Contactor Main Circuit Breaker Soft starter Miscellaneous Parts
Replace Replace Swapout with spare, rebuild Swapout with spare, rebuild Swapout with spare, rebuild Replace
B-2
This appendix discusses the failure rate assumptions used in the model for selected components, along with GECs rationale for selecting the Weibull parameters.
Gearbox
Determining the failure rates for a gearbox is complicated by the number of premature failures that have occurred with various newer wind turbines. The reasons for these failures are varied and are the subject of much controversy, but indications are that they are attributable to either manufacturing quality lapses or inappropriate design decisions. GEC does not believe that it is reasonable to project these very short lives into the future, and concludes that these problems will be, and in many cases have been, resolved. Figure A-1 shows gearbox failures for a variety of turbines of sizes at different sites. In all cases, the year of failure is an average of a two or more year period. The trend line is a Weibull distribution through the seven non-premature failures, with a characteristic life of 27 years and a shape factor of 3.5. For comparison purposes, Vachon estimated a life of 12 to 20 years, but this estimate was based on pre-1999 machines. Industry characteristic life estimates for gears in general range from 12 to more than 100 years, with a typical value of 28 years.
Gearbox Failure Rate
Failures/yr/turbine
0.1 0.08 0.06 0.04 0.02 0 0 5 10 15 20
Age (yr)
trend "Normal" Failures Premature Failures
C-1
Generator
Determining the failure rates for a generator is analogous to the difficulty with gearboxes; recently installed machines have exhibited a number of early failures, in two distinct modes. The first is winding failure, which may be the result of inadequate insulation systems or inappropriate winding design. The other failure mode is early bearing fatigue, which may be attributable to inappropriate fits or poor lubrication. GEC believes these problems are localized and in many cases have been rectified with design or manufacturing improvements, and that a mean life of 25 years with a shape factor of 3.5 is reasonable, as indicated with the trend line (see Figure A-2). This value is slightly less than the typical industry-wide mean life of 38 years for a motor, but is reasonable considering that the duty cycle and operating environment for a wind turbine generator are more severe than for a typical process motor.
Generator Failure Rate
Failures/yr/turbine
0.120 0.100 0.080 0.060 0.040 0.020 0.000 0 5 10 15 20
Age (yr)
"Normal" Failures Premature Failures trend
The data available for yaw drive replacements are limited to the past 12 years. Before 1993, the turbines GEC evaluated used hydraulic yaw motors, whereas more modern machines use electric motor coupled to multistage reducers. The failure rate trend line presented in Figure A-3 uses a characteristic life of 12 years with a shape factor of 3.5. These values ignore the outlier point shown in the figure, which was assumed to be a serial replacement. The duty cycle on yaw drives may have increased since the introduction of sliding-pad type yaw bearings as opposed to the earlier low-friction ball bearings.
C-2
Age (yr)
Yaw Gear (Reduction Unit) Premature Gear Failure Yaw Motor trend
Minimal data were available for pitch cylinder failures, and it is not clear in which instances the cylinder was damaged irreparably. Figure A-4 shows a trend line for a characteristic life of 18 years with a shape factor of 2. However, GEC opted to use the vendor-proposed mean life of 10 years (Eta = 12, Beta =2). These values assume that seals will wear faster with the newer turbines than with the older styles because of the generally higher pitch activity demanded of modern pitch systems. The model assumes that the cylinder rod and body will last for the life of the turbine, but that the associated pitch servo valve will be replaced along with the seals.
Pitch Cylinder Failure Rate
0.1
Failures/yr/turbine
Age (yr)
Pitch Cylinder trend
C-3
Contactors
The duty cycle for the contactors in a wind turbine varies widely depending on the device it is driving and the site conditions. Machines that come on and off line frequently, or with highly variable wind direction, will have a higher duty cycle and can expect contactors to wear faster. Airborne dust and contaminants can cause electromechanical equipment to degrade early. Based on the data in Figure A-5, GEC assumed a characteristic life of 20 years for all contactors. This is a higher value than is commonly encountered in other industries, but may be the result of a generally lower duty cycle. The generic turbines presented with the model assume that the turbines are fitted with well-sealed and filtered enclosures. Small contactors (e.g., for capacitor switching or pumps) are assumed to be replaced; main and bypass contactors are rebuilt.
Contactor Failure Rate
0.10
Failures/yr/turbine
Age (yr)
>50 Amp <50 Amp trend
All modern turbines use modular industrial-grade solid-state controllers that are hardened for use in vibration environments. Failure of these components is usually due to either thermal degradation or transient voltage surges. Figure A-6 presents data for several types of controller boards, both interface modules and central processors. The assumed trend line has a characteristic life of 15 years and a shape factor of 2. The model assumes that major components such as control processors are repairable, but interface modules are not.
C-4
Failures/yr/turbine
Age (yr)
Control Board trend
The useful life for all turbine sensors varies widely. As might be expected, thermal sensors, which have no moving parts, appear to last much longer than anemometers. Figure A-7 shows failure rates for all sensors, along with an assumed trend line with a characteristic life of 12 years and a shape factor of 2.
Sensor Failure Rate
0.100 0.080 0.060 0.040 0.020 0.000 0 5 10 15 20 25
Failures/yr/turbine
Age (yr)
Sensor trend
C-5
D-1
Burden (%) 35 35 35 35
years 1-5 1 2 1 3
# of Staff 6-10 1 2 2 4
11-15 1 2 2 6
16-20 1 2 3 7
Staffing Costs ($/Year) years 1-5 6-10 114,750 114,750 94,500 94,500 50,544 101,088 101,088 134,784 360,882 445,122
Total
1,322
D-2
Repair/Replacement Costs
qty per turbine 3 3 3 3 1 3 0 0 0 Addt'l Labor to Repair / Replace (hr) 29 59 7 49 8 4 4 5 4
System Rotor
Component Blade--struct. repair Blade--nonstruct. repair Pitch cylinder & linkage Pitch bearing Pump & Hydraulics Pitch position xdcr Pitch motor Pitch gear Pitch drive
Alpha
Beta
Cost 24500 2450 1470 6200 3780 1000 2000 1015 2100
10
3.5
9.0
Crane? TRUE TRUE FALSE TRUE FALSE FALSE FALSE FALSE FALSE
Drivetrain
5 25 3.5 22.5
1 1
4500 2045
101 12
TRUE FALSE
80 80
Gearbox--gear & brgs Constant Rate Gearbox--brgs, all Weibull Curve Gearbox--high speed only Weibull Curve Lube pumps Weibull Curve Cooling Fan, Gearbox Coo Weibull Curve
1 1 1 3 1
71 71 13 4 4
80 80 80 240 80
Generator--rot. & brgs Constant Rate Generator--brgs only Weibull Curve Power electronics Weibull Curve Motor, generator coolant faWeibull Curve Contactor, generator Weibull Curve
1 2 0 1 3
16 10 8 4 4
80 160 80 240
Weibull Curve Constant Rate Weibull Curve Weibull Curve Weibull Curve
10 10 6 12 12
2 2 4 1 3
6 0 4 4 2
Yaw System
Yaw gear (drive+motor) Yaw caliper Yaw sliding pads Yaw bearing
12 10 10
2 2 4 1
8 8 8 101
Control System
Control board, Top Control board, Main Control Module Sensor, static Sensor, dynamic
Weibull Curve Weibull Curve Weibull Curve Weibull Curve Weibull Curve
15 15 15 14 12
1 1 4 7 4
0 0 0 0 0
20 30 30
1 1 0
4 4 8
80 80
Miscellaneous Parts
Constant Rate
47400
FALSE
80
D-3
750 kW Results
Entry Values Turbine Rated Power (kW) Pitch Systmem Rotor Speed Control Turbine Quantity Total Project Power (MW) Project Capacity Factor 750 Hydraulic Constant Speed 80 60 0.35 Project Parts Cost Breakdown Parts Crane 9,879,414 3,036,500 Gross Project Income / yr $10,117,800 Gross Turbine Income / yr $126,473 Annual Production (MW-hr) $183,960
Total Project O&M Cost ($000) Year Parts Replacement (Hardware, Consumables Salaried Labor Wage-based Labor Site Maintenance Equipment Total O&M $ /Turbine Year Parts Replacement (Hardware, Consumables Salaried Labor Wage-based Labor Site Maintenance Equipment Total O&M $ /kW Year Parts Replacement (Hardware, Consumables Salaried Labor Wage-based Labor Site Maintenance Equipment Total O&M $ /kWh Year Parts Replacement (Hardware, Consumables Salaried Labor Wage-based Labor Site Maintenance Equipment Total 1 0.001 0.001 0.001 0.001 0.000 0.000 0.003 2 0.001 0.001 0.001 0.001 0.000 0.000 0.004 3 0.001 0.001 0.001 0.001 0.000 0.000 0.004 4 0.002 0.001 0.001 0.001 0.000 0.000 0.004 5 0.003 0.001 0.001 0.001 0.000 0.000 0.005 6 0.002 0.001 0.001 0.001 0.000 0.000 0.006 7 0.003 0.001 0.001 0.001 0.000 0.000 0.006 8 0.003 0.001 0.001 0.001 0.000 0.000 0.006 9 0.004 0.001 0.001 0.001 0.000 0.000 0.007 10 0.005 0.001 0.001 0.001 0.000 0.000 0.008 11 0.004 0.001 0.001 0.002 0.000 0.000 0.008 12 0.005 0.001 0.001 0.002 0.000 0.000 0.009 13 0.004 0.001 0.001 0.002 0.000 0.000 0.008 14 0.006 0.001 0.001 0.002 0.000 0.000 0.009 15 0.006 0.001 0.001 0.002 0.000 0.000 0.009 16 0.005 0.001 0.001 0.002 0.000 0.000 0.009 17 0.006 0.001 0.001 0.002 0.000 0.000 0.010 18 0.005 0.001 0.001 0.002 0.000 0.000 0.009 19 0.006 0.001 0.001 0.002 0.000 0.000 0.010 Average Average Avg yr 11- Avg yr 16yr 6-10 15 20 20 yr Avg 20 yr 1-5 0.00 0.00 0.00 0.01 0.00 0.006 0.001 0.00 0.00 0.00 0.00 0.00 0.001 0.00 0.00 0.00 0.00 0.00 0.002 0.00 0.00 0.00 0.00 0.00 0.000 0.00 0.00 0.00 0.00 0.00 0.000 0.010 0.00 0.00 0.00 0.01 0.00 0.01 0.00 0.01 0.00 0.01 1 1.8 1.8 3.5 2.5 0.2 0.4 10.2 2 3.1 1.8 3.5 2.5 0.2 0.4 11.6 3 3.4 1.8 3.5 2.5 0.2 0.4 11.9 4 5.0 1.8 3.5 2.5 0.2 0.4 13.4 5 8.1 1.8 3.5 2.5 0.2 0.4 16.6 6 7.5 1.8 3.5 3.9 0.2 0.4 17.3 7 9.1 1.8 3.5 3.9 0.2 0.4 18.9 8 9.0 1.8 3.5 3.9 0.2 0.4 18.8 9 11.7 1.8 3.5 3.9 0.2 0.4 21.5 10 14.4 1.8 3.5 3.9 0.2 0.4 24.2 11 13.1 1.8 3.5 5.1 0.2 0.4 24.0 12 15.5 1.8 3.5 5.1 0.2 0.4 26.5 13 13.5 1.8 3.5 5.1 0.2 0.4 24.4 14 16.9 1.8 3.5 5.1 0.2 0.4 27.8 15 17.6 1.8 3.5 5.1 0.2 0.4 28.6 16 16.4 1.8 3.5 6.5 0.2 0.4 28.7 17 18.3 1.8 3.5 6.5 0.2 0.4 30.7 18 16.3 1.8 3.5 6.5 0.2 0.4 28.7 19 18.4 1.8 3.5 6.5 0.2 0.4 30.8 Average Average Avg yr 11- Avg yr 16yr 6-10 15 20 20 yr Avg 20 yr 1-5 4.3 10.3 15.3 17.6 11.90 18.7 1.8 1.8 1.8 1.8 1.76 1.8 3.5 3.5 3.5 3.5 3.49 3.5 2.5 3.9 5.1 6.5 4.49 6.5 0.2 0.2 0.2 0.2 0.24 0.2 0.4 0.4 0.4 0.4 0.40 0.4 12.7 20.1 26.3 30.0 22.27 31.1 1 106 106 209 152 14 24 611 2 188 106 209 152 14 24 693 3 207 106 209 152 14 24 711 4 297 106 209 152 14 24 802 5 489 106 209 152 14 24 994 6 451 106 209 236 14 24 1040 7 544 106 209 236 14 24 1133 8 541 106 209 236 14 24 1130 9 700 106 209 236 14 24 1289 10 863 106 209 236 14 24 1452 11 786 106 209 303 14 24 1442 12 932 106 209 303 14 24 1588 13 809 106 209 303 14 24 1466 14 1013 106 209 303 14 24 1669 15 1058 106 209 303 14 24 1714 16 982 106 209 388 14 24 1723 17 1099 106 209 388 14 24 1839 18 979 106 209 388 14 24 1720 19 1107 106 209 388 14 24 1847 Average Average Avg yr 11- Avg yr 16- 20 yr yr 6-10 15 20 Total 20 yr 1-5 257 620 919 1058 14275 1125 106 106 106 106 2116 106 209 209 209 209 4185 209 152 236 303 388 5391 388 14 14 14 14 282 14 24 24 24 24 480 24 762 1209 1576 1799 26729 1865
yr 6-10 15 20 20 yr Avg 20 yr 1-5 3218 7748 11493 13228 8922 14060 1322 1322 1322 1322 1322 1322 2616 2616 2616 2616 2616 2616 1895 2948 3791 4844 3370 4844 176 176 176 176 176 176 300 300 300 300 300 300 9528 15110 19698 22486 16706 23318
D-4
2000 1800 1600 $ / turbine / yr 1400 $ x 1000 / yr 1200 1000 800 600 400 200 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Project Age (yr) Parts Replacement (Hardware, Addt'l Labor, Crane) Salaried Labor Site Maintenance Total Consumables Wage-based Labor Equipment
25000
20000
15000
10000
5000
Parts Replacement (Hardware, Addt'l Labor, Crane) Salaried Labor Site Maintenance Total
35 30 25 $ / kWh 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 $ / kW 20 15 10 5 0 Project Age (yr) Parts Replacement (Hardware, Addt'l Labor, Crane) Salaried Labor Site Maintenance Total Consumables Wage-based Labor Equipment
0.012 0.010 0.008 0.006 0.004 0.002 0.000 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Project Age (yr) Parts Replacement (Hardware, Addt'l Labor, Crane) Salaried Labor Site Maintenance Total Consumables Wage-based Labor Equipment
D-5
Burden (%) 35 35 35 35
years 1-5 1 2 1 2
# of Staff 6-10 1 2 1 4
11-15 1 2 2 4
16-20 1 2 2 6
Staffing Costs ($/Year) years 1-5 6-10 114,750 114,750 94,500 94,500 50,544 67,392 327,186 50,544 134,784 394,578
Total
1,681
D-6
Repair/Replacement Costs
qty per turbine 3 3 3 3 1 3 0 0 0 Addt'l Labor to Repair / Replace (hr) 32 62 9 52 8 4 4 6 4
System Rotor
Component Blade--struct. repair Blade--nonstruct. repair Pitch cylinder & linkage Pitch bearing Pump & Hydraulics Pitch position xdcr Pitch motor Pitch gear Pitch drive
Alpha
Beta
Cost 33750 3375 1590 9700 3780 1000 2667 1353 2800
10
3.5
9.0
Crane? TRUE TRUE FALSE TRUE FALSE FALSE FALSE FALSE FALSE
Drivetrain
5 25 3.5 22.5
1 1
7100 2727
107 12
TRUE FALSE
60 60
Gearbox--gear & brgs Constant Rate Gearbox--brgs, all Weibull Curve Gearbox--high speed only Weibull Curve Lube pumps Weibull Curve Cooling Fan, Gearbox Coo Weibull Curve
1 1 1 3 2
77 77 18 4 4
60 60 60 180 120
Generator--rot. & brgs Constant Rate Generator--brgs only Weibull Curve Power electronics Weibull Curve Motor, generator coolant faWeibull Curve Contactor, generator Weibull Curve
1 2 0 2 3
18 10 8 4 4
Weibull Curve Constant Rate Weibull Curve Weibull Curve Weibull Curve
10 10 6 12 12
2 2 4 1 3
6 0 4 4 2
Yaw System
Yaw gear (drive+motor) Yaw caliper Yaw sliding pads Yaw bearing
12 10 10
2 2 4 1
8 8 8 107
Control System
Control board, Top Control board, Main Control Module Sensor, static Sensor, dynamic
Weibull Curve Weibull Curve Weibull Curve Weibull Curve Weibull Curve
15 15 15 14 12
1 1 4 11 4
0 0 0 0 0
20 30 30
1 1 0
4 4 8
60 60
Miscellaneous Parts
Constant Rate
63210
FALSE
60
D-7
1000 kW Results
Entry Values Turbine Rated Power (kW) Pitch Systmem Rotor Speed Control Turbine Quantity Total Project Power (MW) Project Capacity Factor 1000 Hydraulic Constant Speed 60 60 0.35 Project Parts Cost Breakdown Parts 9,716,424 Crane 4,006,200 Gross Project Income / yr $10,117,800 Gross Turbine Income / yr $168,630 Annual Production (MW-hr) $183,960
Total Project O&M Cost ($000) Year Parts Replacement (Hardware, Consumables Salaried Labor Wage-based Labor Site Maintenance Equipment Total O&M $ /Turbine Year Parts Replacement (Hardware, Consumables Salaried Labor Wage-based Labor Site Maintenance Equipment Total O&M $ /kW Year Parts Replacement (Hardware, Consumables Salaried Labor Wage-based Labor Site Maintenance Equipment Total O&M $ /kWh Year Parts Replacement (Hardware, Consumables Salaried Labor Wage-based Labor Site Maintenance Equipment Total 1 0.001 0.001 0.001 0.001 0.000 0.000 0.003 2 0.001 0.001 0.001 0.001 0.000 0.000 0.003 3 0.001 0.001 0.001 0.001 0.000 0.000 0.004 4 0.001 0.001 0.001 0.001 0.000 0.000 0.004 5 0.002 0.001 0.001 0.001 0.000 0.000 0.004 6 0.003 0.001 0.001 0.001 0.000 0.000 0.006 7 0.004 0.001 0.001 0.001 0.000 0.000 0.006 8 0.003 0.001 0.001 0.001 0.000 0.000 0.006 9 0.004 0.001 0.001 0.001 0.000 0.000 0.007 10 0.004 0.001 0.001 0.001 0.000 0.000 0.006 11 0.004 0.001 0.001 0.001 0.000 0.000 0.007 12 0.005 0.001 0.001 0.001 0.000 0.000 0.009 13 0.005 0.001 0.001 0.001 0.000 0.000 0.008 14 0.007 0.001 0.001 0.001 0.000 0.000 0.010 15 0.006 0.001 0.001 0.001 0.000 0.000 0.009 16 0.005 0.001 0.001 0.002 0.000 0.000 0.009 17 0.006 0.001 0.001 0.002 0.000 0.000 0.009 18 0.006 0.001 0.001 0.002 0.000 0.000 0.010 19 0.006 0.001 0.001 0.002 0.000 0.000 0.009 1 1.7 1.7 3.5 2.0 0.2 0.4 9.5 2 2.5 1.7 3.5 2.0 0.2 0.4 10.3 3 4.1 1.7 3.5 2.0 0.2 0.4 11.9 4 4.6 1.7 3.5 2.0 0.2 0.4 12.4 5 6.0 1.7 3.5 2.0 0.2 0.4 13.8 6 8.3 1.7 3.5 3.1 0.2 0.4 17.2 7 10.7 1.7 3.5 3.1 0.2 0.4 19.6 8 9.7 1.7 3.5 3.1 0.2 0.4 18.6 9 12.9 1.7 3.5 3.1 0.2 0.4 21.8 10 10.9 1.7 3.5 3.1 0.2 0.4 19.8 11 13.0 1.7 3.5 3.9 0.2 0.4 22.7 12 16.5 1.7 3.5 3.9 0.2 0.4 26.2 13 15.8 1.7 3.5 3.9 0.2 0.4 25.6 14 19.9 1.7 3.5 3.9 0.2 0.4 29.7 15 18.0 1.7 3.5 3.9 0.2 0.4 27.7 16 16.8 1.7 3.5 5.1 0.2 0.4 27.6 17 18.1 1.7 3.5 5.1 0.2 0.4 28.9 18 19.0 1.7 3.5 5.1 0.2 0.4 29.8 19 17.9 1.7 3.5 5.1 0.2 0.4 28.8 Average Average Avg yr 11- Avg yr 16yr 6-10 15 20 20 yr Avg 20 yr 1-5 3.8 10.5 16.6 18.8 12.43 22.1 1.7 1.7 1.7 1.7 1.68 1.7 3.5 3.5 3.5 3.5 3.49 3.5 2.0 3.1 3.9 5.1 3.51 5.1 0.2 0.2 0.2 0.2 0.24 0.2 0.4 0.4 0.4 0.4 0.40 0.4 11.6 19.4 26.4 29.6 21.74 33.0 Average Average Avg yr 11- Avg yr 16yr 6-10 15 20 20 yr Avg 20 yr 1-5 0.00 0.00 0.01 0.01 0.00 0.007 0.001 0.00 0.00 0.00 0.00 0.00 0.001 0.00 0.00 0.00 0.00 0.00 0.002 0.00 0.00 0.00 0.00 0.00 0.000 0.000 0.011 0.00 0.00 0.00 0.00 0.00 0.01 0.00 0.00 0.01 0.00 0.00 0.01 0.00 0.00 0.01 1 1732 1681 3488 1966 235 400 9501 2 2493 1681 3488 1966 235 400 10263 3 4133 1681 3488 1966 235 400 11902 4 4589 1681 3488 1966 235 400 12358 5 6001 1681 3488 1966 235 400 13770 6 8313 1681 3488 3089 235 400 17205 7 10746 1681 3488 3089 235 400 19638 8 9664 1681 3488 3089 235 400 18556 9 12887 1681 3488 3089 235 400 21779 10 10917 1681 3488 3089 235 400 19809 11 12963 1681 3488 3931 235 400 22698 12 16457 1681 3488 3931 235 400 26192 13 15845 1681 3488 3931 235 400 25580 14 19934 1681 3488 3931 235 400 29668 15 18005 1681 3488 3931 235 400 27740 16 16787 1681 3488 5054 235 400 27645 17 18078 1681 3488 5054 235 400 28936 18 18982 1681 3488 5054 235 400 29840 19 17906 1681 3488 5054 235 400 28764 1 104 101 209 118 14 24 570 2 150 101 209 118 14 24 616 3 248 101 209 118 14 24 714 4 275 101 209 118 14 24 742 5 360 101 209 118 14 24 826 6 499 101 209 185 14 24 1032 7 645 101 209 185 14 24 1178 8 580 101 209 185 14 24 1113 9 773 101 209 185 14 24 1307 10 655 101 209 185 14 24 1189 11 778 101 209 236 14 24 1362 12 987 101 209 236 14 24 1571 13 951 101 209 236 14 24 1535 14 1196 101 209 236 14 24 1780 15 1080 101 209 236 14 24 1664 16 1007 101 209 303 14 24 1659 17 1085 101 209 303 14 24 1736 18 1139 101 209 303 14 24 1790 19 1074 101 209 303 14 24 1726 Average Average Avg yr 11- Avg yr 16- 20 yr yr 6-10 15 20 Total 20 yr 1-5 227 630 998 1126 14912 1326 101 101 101 101 2017 101 209 209 209 209 4185 209 118 185 236 303 4212 303 14 14 14 14 282 14 24 24 24 24 480 24 694 1164 1583 1778 26088 1978
Average Average Avg yr 11- Avg yr 16yr 6-10 15 20 20 yr Avg 20 yr 1-5 3790 10505 16641 18771 12427 22101 1681 1681 1681 1681 1681 1681 3488 3488 3488 3488 3488 3488 1966 3089 3931 5054 3510 5054 235 235 235 235 235 235 400 400 400 400 400 400 11559 19398 26376 29629 21740 32959
D-8
2500 2000 $ / turbine 1500 1000 500 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Project Age (yr) Parts Replacement (Hardware, Addt'l Labor, Crane) Salaried Labor Site Maintenance Total Consumables Wage-based Labor Equipment
35000 30000 25000 20000 15000 10000 5000 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Project Age (yr) Parts Replacement (Hardware, Addt'l Labor, Crane) Salaried Labor Site Maintenance Total Consumables Wage-based Labor Equipment
$ x 1000
0.012 0.010 0.008 0.006 0.004 0.002 0.000 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Project Age (yr) Parts Replacement (Hardware, Addt'l Labor, Crane) Salaried Labor Site Maintenance Total Consumables Wage-based Labor Equipment
Parts Replacement (Hardware, Addt'l Labor, Crane) Salaried Labor Site Maintenance Total
D-9
Notes: Description:
Burden (%) 35 35 35 35
years 1-5 1 2 1 3
# of Staff 6-10 1 2 1 4
11-15 1 2 2 4
16-20 1 2 2 5
Staffing Costs ($/Year) years 1-5 6-10 114,750 114,750 94,500 94,500 50,544 101,088 360,882 50,544 134,784 394,578
Total
2,348
D-10
Repair/Replacement Costs
qty per turbine 3 3 0 3 0 0 3 3 3 Addt'l Labor to Repair / Replace (hr) 37 69 11 57 8 4 4 8 4
System Rotor
Component Blade--struct. repair Blade--nonstruct. repair Pitch cylinder & linkage Pitch bearing Pump & Hydraulics Pitch position xdcr Pitch motor Pitch gear Pitch drive
Alpha
Beta
Cost 52200 5220 1860 16700 3780 1000 4000 2030 4200
10
3.5
9.0
Crane? TRUE TRUE FALSE TRUE FALSE FALSE FALSE FALSE FALSE
Drivetrain
5 25 3.5 22.5
1 1
13400 4091
121 12
TRUE FALSE
40 40
Gearbox--gear & brgs Constant Rate Gearbox--brgs, all Weibull Curve Gearbox--high speed only Weibull Curve Lube pumps Weibull Curve Cooling Fan, Gearbox Coo Weibull Curve
1 1 1 3 2
91 91 27 4 4
40 40 40 120 80
Generator--rot. & brgs Constant Rate Generator--brgs only Weibull Curve Power electronics Weibull Curve Motor, generator coolant faWeibull Curve Contactor, generator Weibull Curve
1 2 1 2 3
20 10 8 4 4
40 80 40 80 120
Weibull Curve Constant Rate Weibull Curve Weibull Curve Weibull Curve
10 10 6 12 12
3 2 1 1 4
6 0 4 4 2
120 80 40 40 160
Yaw System
Yaw gear (drive+motor) Yaw caliper Yaw sliding pads Yaw bearing
12 10 10
4 4 8 1
8 8 8 121
Control System
Control board, Top Control board, Main Control Module Sensor, static Sensor, dynamic
Weibull Curve Weibull Curve Weibull Curve Weibull Curve Weibull Curve
15 15 15 14 12
1 1 2 17 2
0 0 0 0 0
40 40 80 680 80
20 30 30
1 1 0
4 4 8
40 40
Miscellaneous Parts
Constant Rate
94810
FALSE
40
D-11
1500 kW Results
Entry Values Turbine Rated Power (kW) Pitch Systmem Rotor Speed Control Turbine Quantity Total Project Power (MW) Project Capacity Factor 1500 Electric Variable Speed 40 60 0.35 Project Parts Cost Breakdown Parts 10,421,675 Crane 6,575,400 Additional Labor 518531 Total 17,515,606 Gross Project Income / yr $10,117,800 Gross Turbine Income / yr $252,945 Annual Production (MW-hr) $183,960
Total Project O&M Cost ($000) Year Parts Replacement (Hardware, Consumables Salaried Labor Wage-based Labor Site Maintenance Equipment Total O&M $ /Turbine Year Parts Replacement (Hardware, Consumables Salaried Labor Wage-based Labor Site Maintenance Equipment Total O&M $ /kW Year Parts Replacement (Hardware, Consumables Salaried Labor Wage-based Labor Site Maintenance Equipment Total O&M $ /kWh Year Parts Replacement (Hardware, Consumables Salaried Labor Wage-based Labor Site Maintenance Equipment Total 1 0.001 0.001 0.001 0.001 0.000 0.000 0.003 2 0.001 0.001 0.001 0.001 0.000 0.000 0.004 3 0.001 0.001 0.001 0.001 0.000 0.000 0.004 4 0.002 0.001 0.001 0.001 0.000 0.000 0.005 5 0.002 0.001 0.001 0.001 0.000 0.000 0.005 6 0.002 0.001 0.001 0.001 0.000 0.000 0.005 7 0.004 0.001 0.001 0.001 0.000 0.000 0.007 8 0.003 0.001 0.001 0.001 0.000 0.000 0.005 9 0.004 0.001 0.001 0.001 0.000 0.000 0.007 10 0.007 0.001 0.001 0.001 0.000 0.000 0.010 11 0.006 0.001 0.001 0.001 0.000 0.000 0.009 12 0.006 0.001 0.001 0.001 0.000 0.000 0.009 13 0.005 0.001 0.001 0.001 0.000 0.000 0.008 14 0.008 0.001 0.001 0.001 0.000 0.000 0.011 15 0.007 0.001 0.001 0.001 0.000 0.000 0.010 16 0.008 0.001 0.001 0.001 0.000 0.000 0.011 17 0.007 0.001 0.001 0.001 0.000 0.000 0.010 18 0.008 0.001 0.001 0.001 0.000 0.000 0.011 19 0.008 0.001 0.001 0.001 0.000 0.000 0.011 1 2.2 1.6 3.5 2.5 0.2 0.4 10.5 2 3.3 1.6 3.5 2.5 0.2 0.4 11.5 3 3.9 1.6 3.5 2.5 0.2 0.4 12.1 4 5.6 1.6 3.5 2.5 0.2 0.4 13.8 5 6.0 1.6 3.5 2.5 0.2 0.4 14.3 6 6.1 1.6 3.5 3.1 0.2 0.4 14.8 7 12.8 1.6 3.5 3.1 0.2 0.4 21.5 8 7.9 1.6 3.5 3.1 0.2 0.4 16.7 9 13.3 1.6 3.5 3.1 0.2 0.4 22.1 10 21.9 1.6 3.5 3.1 0.2 0.4 30.7 11 18.5 1.6 3.5 3.9 0.2 0.4 28.1 12 19.2 1.6 3.5 3.9 0.2 0.4 28.8 13 15.7 1.6 3.5 3.9 0.2 0.4 25.3 14 25.1 1.6 3.5 3.9 0.2 0.4 34.8 15 20.5 1.6 3.5 3.9 0.2 0.4 30.1 16 23.8 1.6 3.5 4.5 0.2 0.4 33.9 17 21.5 1.6 3.5 4.5 0.2 0.4 31.7 18 24.7 1.6 3.5 4.5 0.2 0.4 34.9 19 23.8 1.6 3.5 4.5 0.2 0.4 34.0 Average Average Avg yr 11- Avg yr 16yr 6-10 15 20 20 yr Avg 20 yr 1-5 4.2 12.4 19.8 24.1 15.13 26.7 1.6 1.6 1.6 1.6 1.57 1.6 3.5 3.5 3.5 3.5 3.49 3.5 2.5 3.1 3.9 4.5 3.51 4.5 0.2 0.2 0.2 0.2 0.24 0.2 0.4 0.4 0.4 0.4 0.40 0.4 12.4 21.2 29.4 34.3 24.33 36.9 Average Average Avg yr 11- Avg yr 16yr 6-10 15 20 20 yr Avg 20 yr 1-5 0.00 0.00 0.01 0.01 0.00 0.009 0.001 0.00 0.00 0.00 0.00 0.00 0.001 0.00 0.00 0.00 0.00 0.00 0.001 0.00 0.00 0.00 0.00 0.00 0.000 0.000 0.012 0.00 0.00 0.00 0.00 0.00 0.01 0.00 0.00 0.01 0.00 0.00 0.01 0.00 0.00 0.01 1 3360 2348 5231 3791 353 600 15683 2 4922 2348 5231 3791 353 600 17245 3 5878 2348 5231 3791 353 600 18200 4 8443 2348 5231 3791 353 600 20766 5 9065 2348 5231 3791 353 600 21387 6 9081 2348 5231 4633 353 600 22246 7 19135 2348 5231 4633 353 600 32300 8 11880 2348 5231 4633 353 600 25045 9 19969 2348 5231 4633 353 600 33134 10 32875 2348 5231 4633 353 600 46040 11 27721 2348 5231 5897 353 600 42150 12 28781 2348 5231 5897 353 600 43210 13 23540 2348 5231 5897 353 600 37968 14 37700 2348 5231 5897 353 600 52129 15 30735 2348 5231 5897 353 600 45164 16 35646 2348 5231 6739 353 600 50917 17 32309 2348 5231 6739 353 600 47580 18 37060 2348 5231 6739 353 600 52331 19 35730 2348 5231 6739 353 600 51001 1 134 94 209 152 14 24 627 2 197 94 209 152 14 24 690 3 235 94 209 152 14 24 728 4 338 94 209 152 14 24 831 5 363 94 209 152 14 24 855 6 363 94 209 185 14 24 890 7 765 94 209 185 14 24 1292 8 475 94 209 185 14 24 1002 9 799 94 209 185 14 24 1325 10 1315 94 209 185 14 24 1842 11 1109 94 209 236 14 24 1686 12 1151 94 209 236 14 24 1728 13 942 94 209 236 14 24 1519 14 1508 94 209 236 14 24 2085 15 1229 94 209 236 14 24 1807 16 1426 94 209 270 14 24 2037 17 1292 94 209 270 14 24 1903 18 1482 94 209 270 14 24 2093 19 1429 94 209 270 14 24 2040 Average Average Avg yr 11- Avg yr 16- 20 yr yr 6-10 15 20 Total 20 yr 1-5 253 744 1188 1446 18154 1601 94 94 94 94 1879 94 209 209 209 209 209 4185 152 185 236 270 4212 270 14 14 14 14 282 14 24 24 24 24 480 24 746 1270 1765 2057 29192 2212
Average Average Avg yr 11- Avg yr 16yr 6-10 15 20 20 yr Avg 20 yr 1-5 6333 18588 29695 36154 22693 40027 2348 2348 2348 2348 2348 2348 5231 5231 5231 5231 5231 5231 3791 4633 5897 6739 5265 6739 353 353 353 353 353 353 600 600 600 600 600 600 18656 31753 44124 51426 36490 55299
D-12
2500
60000 50000
2000 $ x 1000 / yr $ / turbine / yr 40000 30000 20000 10000 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Project Age (yr)
1500
1000
500
0 Project Age (yr) Parts Replacement (Hardware, Addt'l Labor, Crane) Salaried Labor Site Maintenance Total Consumables Wage-based Labor Equipment
Parts Replacement (Hardware, Addt'l Labor, Crane) Salaried Labor Site Maintenance Total
0.014 0.012 0.010 0.008 0.006 0.004 0.002 0.000 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Project Age (yr)
Parts Replacement (Hardware, Addt'l Labor, Crane) Salaried Labor Site Maintenance Total
Parts Replacement (Hardware, Addt'l Labor, Crane) Salaried Labor Site Maintenance Total
D-13
Notes: Description:
Burden (%) 35 35 35 35
years 1-5 1 2 1 2
# of Staff 6-10 1 2 1 3
11-15 1 2 1 4
16-20 1 2 2 4
Staffing Costs ($/Year) years 1-5 6-10 114,750 114,750 94,500 94,500 50,544 67,392 327,186 50,544 101,088 360,882
Total
3,015
D-14
Repair/Replacement Costs
Addt'l Labor to Repair / Replace (hr) 43 76 14 63 8 4 4 10 4
System Rotor
Component Blade--struct. repair Blade--nonstruct. repair Pitch cylinder & linkage Pitch bearing Pump & Hydraulics Pitch position xdcr Pitch motor Pitch gear Pitch drive
Alpha
Beta
10
3.5
9.0
Cost 70650 7065 2130 23700 3780 1000 5333 2707 5600
Crane? TRUE TRUE FALSE TRUE FALSE FALSE FALSE FALSE FALSE
Parts in Project 90 90 90
90 90 90
Drivetrain
5 25 3.5 22.5
1 1
21000 5455
134 12
TRUE FALSE
30 30
Constant Rate Gearbox--gear & brgs Gearbox--brgs, all Weibull Curve Gearbox--high speed only Weibull Curve Lube pumps Weibull Curve Cooling Fan, Gearbox Coo Weibull Curve
1 1 1 3 3
104 104 37 4 4
30 30 30 90 90
Constant Rate Generator--rot. & brgs Generator--brgs only Weibull Curve Power electronics Weibull Curve Motor, generator coolant faWeibull Curve Contactor, generator Weibull Curve
1 2 1 3 3
22 10 8 4 4
30 60 30 90 90
Weibull Curve Constant Rate Weibull Curve Weibull Curve Weibull Curve
10 10 6 12 12
4 4 1 1 5
6 0 4 4 2
Yaw System
Yaw gear (drive+motor) Yaw caliper Yaw sliding pads Yaw bearing
12 10 10
4 4 8 1
8 8 8 134
Control System
Control board, Top Control board, Main Control Module Sensor, static Sensor, dynamic
Weibull Curve Weibull Curve Weibull Curve Weibull Curve Weibull Curve
15 15 15 14 12
1 1 2 25 2
0 0 0 0 0
30 30 60 750 60
20 30 30
1 1 0
4 4 8
30 30
Miscellaneous Parts
Constant Rate
126410
FALSE
30
D-15
2000 kW Results
Entry Values Turbine Rated Power (kW) Pitch Systmem Rotor Speed Control Turbine Quantity Total Project Power (MW) Project Capacity Factor 2000 Electric Variable Speed 30 60 0.35 Project Parts Cost Breakdown Parts 10,607,932 Crane 6,012,450 Additional Labor 426883 Total 17,047,265 Gross Project Income / yr $10,117,800 Gross Turbine Income / yr $337,260 Annual Production (MW-hr) $183,960
Total Project O&M Cost ($000) Year Parts Replacement (Hardware, Consumables Salaried Labor Wage-based Labor Site Maintenance Equipment Total O&M $ /Turbine Year Parts Replacement (Hardware, Consumables Salaried Labor Wage-based Labor Site Maintenance Equipment Total O&M $ /kW Year Parts Replacement (Hardware, Consumables Salaried Labor Wage-based Labor Site Maintenance Equipment Total O&M $ /kWh Year Parts Replacement (Hardware, Consumables Salaried Labor Wage-based Labor Site Maintenance Equipment Total 1 0.001 0.000 0.001 0.001 0.000 0.000 0.003 2 0.001 0.000 0.001 0.001 0.000 0.000 0.003 3 0.001 0.000 0.001 0.001 0.000 0.000 0.004 4 0.002 0.000 0.001 0.001 0.000 0.000 0.004 5 0.002 0.000 0.001 0.001 0.000 0.000 0.005 6 0.002 0.000 0.001 0.001 0.000 0.000 0.005 7 0.004 0.000 0.001 0.001 0.000 0.000 0.007 8 0.003 0.000 0.001 0.001 0.000 0.000 0.005 9 0.005 0.000 0.001 0.001 0.000 0.000 0.008 10 0.005 0.000 0.001 0.001 0.000 0.000 0.007 11 0.005 0.000 0.001 0.001 0.000 0.000 0.008 12 0.005 0.000 0.001 0.001 0.000 0.000 0.008 13 0.005 0.000 0.001 0.001 0.000 0.000 0.008 14 0.011 0.000 0.001 0.001 0.000 0.000 0.014 15 0.007 0.000 0.001 0.001 0.000 0.000 0.010 16 0.006 0.000 0.001 0.001 0.000 0.000 0.009 17 0.007 0.000 0.001 0.001 0.000 0.000 0.010 18 0.008 0.000 0.001 0.001 0.000 0.000 0.011 19 0.007 0.000 0.001 0.001 0.000 0.000 0.010 1 1.8 1.5 3.5 2.0 0.2 0.4 9.4 2 3.0 1.5 3.5 2.0 0.2 0.4 10.6 3 3.6 1.5 3.5 2.0 0.2 0.4 11.2 4 4.7 1.5 3.5 2.0 0.2 0.4 12.3 5 7.3 1.5 3.5 2.0 0.2 0.4 14.9 6 6.8 1.5 3.5 2.5 0.2 0.4 14.9 7 12.0 1.5 3.5 2.5 0.2 0.4 20.1 8 8.4 1.5 3.5 2.5 0.2 0.4 16.5 9 15.3 1.5 3.5 2.5 0.2 0.4 23.5 10 14.8 1.5 3.5 2.5 0.2 0.4 22.9 11 14.9 1.5 3.5 3.1 0.2 0.4 23.6 12 16.2 1.5 3.5 3.1 0.2 0.4 24.9 13 16.2 1.5 3.5 3.1 0.2 0.4 24.9 14 32.8 1.5 3.5 3.1 0.2 0.4 41.5 15 21.1 1.5 3.5 3.1 0.2 0.4 29.8 16 17.3 1.5 3.5 3.9 0.2 0.4 26.9 17 22.1 1.5 3.5 3.9 0.2 0.4 31.7 18 24.6 1.5 3.5 3.9 0.2 0.4 34.1 19 22.0 1.5 3.5 3.9 0.2 0.4 31.6 Average Average Avg yr 11- Avg yr 16yr 6-10 15 20 20 yr Avg 20 yr 1-5 4.1 11.4 20.2 21.5 14.32 21.6 1.5 1.5 1.5 1.5 1.51 1.5 3.5 3.5 3.5 3.5 3.49 3.5 2.0 2.5 3.1 3.9 2.88 3.9 0.2 0.2 0.2 0.2 0.24 0.2 0.4 0.4 0.4 0.4 0.40 0.4 11.7 19.6 28.9 31.1 22.83 31.2 Average Average Avg yr 11- Avg yr 16yr 6-10 15 20 20 yr Avg 20 yr 1-5 0.00 0.00 0.01 0.01 0.00 0.007 0.000 0.00 0.00 0.00 0.00 0.00 0.001 0.00 0.00 0.00 0.00 0.00 0.001 0.00 0.00 0.00 0.00 0.00 0.000 0.000 0.010 0.00 0.00 0.00 0.00 0.00 0.01 0.00 0.00 0.01 0.00 0.00 0.01 0.00 0.00 0.01 1 3667 3015 6975 3931 470 800 18858 2 5923 3015 6975 3931 470 800 21114 3 7228 3015 6975 3931 470 800 22419 4 9341 3015 6975 3931 470 800 24532 5 14655 3015 6975 3931 470 800 29846 6 13547 3015 6975 5054 470 800 29862 7 23910 3015 6975 5054 470 800 40224 8 16714 3015 6975 5054 470 800 33029 9 30664 3015 6975 5054 470 800 46979 10 29520 3015 6975 5054 470 800 45835 11 29748 3015 6975 6178 470 800 47186 12 32303 3015 6975 6178 470 800 49741 13 32425 3015 6975 6178 470 800 49863 14 65597 3015 6975 6178 470 800 83035 15 42223 3015 6975 6178 470 800 59661 16 34639 3015 6975 7862 470 800 53762 17 44211 3015 6975 7862 470 800 63334 18 49152 3015 6975 7862 470 800 68275 19 44062 3015 6975 7862 470 800 63184 1 110 90 209 118 14 24 566 2 178 90 209 118 14 24 633 3 217 90 209 118 14 24 673 4 280 90 209 118 14 24 736 5 440 90 209 118 14 24 895 6 406 90 209 152 14 24 896 7 717 90 209 152 14 24 1207 8 501 90 209 152 14 24 991 9 920 90 209 152 14 24 1409 10 886 90 209 152 14 24 1375 11 892 90 209 185 14 24 1416 12 969 90 209 185 14 24 1492 13 973 90 209 185 14 24 1496 14 1968 90 209 185 14 24 2491 15 1267 90 209 185 14 24 1790 16 1039 90 209 236 14 24 1613 17 1326 90 209 236 14 24 1900 18 1475 90 209 236 14 24 2048 19 1322 90 209 236 14 24 1896 Average Average Avg yr 11- Avg yr 16- 20 yr yr 6-10 15 20 Total 20 yr 1-5 245 686 1214 1292 17183 1297 90 90 90 90 1809 90 209 209 209 209 4185 209 118 152 185 236 3454 236 14 14 14 14 282 14 24 24 24 24 480 24 701 1176 1737 1865 27393 1870
Average Average Avg yr 11- Avg yr 16yr 6-10 15 20 20 yr Avg 20 yr 1-5 8163 22871 40459 43058 28638 43224 3015 3015 3015 3015 3015 3015 6975 6975 6975 6975 6975 6975 3931 5054 6178 7862 5756 7862 470 470 470 470 470 470 800 800 800 800 800 800 23354 39186 57897 62180 45654 62346
D-16
3000 2500 $ / turbine / yr 2000 $ x 1000 / yr 1500 1000 500 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Project Age (yr) Parts Replacement (Hardware, Addt'l Labor, Crane) Salaried Labor Site Maintenance Total Consumables Wage-based Labor Equipment
90000 80000 70000 60000 50000 40000 30000 20000 10000 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Project Age (yr)
Parts Replacement (Hardware, Addt'l Labor, Crane) Salaried Labor Site Maintenance Total
0.016 0.014 0.012 0.010 0.008 0.006 0.004 0.002 0.000 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Project Age (yr)
Parts Replacement (Hardware, Addt'l Labor, Crane) Salaried Labor Site Maintenance Total
Parts Replacement (Hardware, Addt'l Labor, Crane) Salaried Labor Site Maintenance Total
D-17
Burden (%) 35 35 35 35
years 1-5 1 2 1 2
# of Staff 6-10 1 2 1 2
11-15 1 2 1 3
16-20 1 2 1 4
Staffing Costs ($/Year) years 1-5 6-10 11-15 114,750 114,750 114,750 94,500 94,500 94,500 50,544 50,544 50,544 67,392 67,392 101,088 327,186 327,186 360,882
Total
3,683
3,683
D-18
Repair/Replacement Costs
Addt'l Labor to Repair / Replace (hr) 49 82 17 69 8 4 4 11 4
System Rotor
Component Blade--struct. repair Blade--nonstruct. repair Pitch cylinder & linkage Pitch bearing Pump & Hydraulics Pitch position xdcr Pitch motor Pitch gear Pitch drive
Alpha
Beta
10 12 12 15 12 15
Cost 89150 8915 2400 30700 3780 1000 6667 3383 7000
Crane? TRUE TRUE FALSE TRUE FALSE FALSE FALSE FALSE FALSE
MTTR (days) 3 3 0 3 0 0 3 3 3
Drivetrain
5 25 3.5 22.5
1 1
29800 6818
147 12
TRUE FALSE
1 1
Gearbox--gear & brgs Constant Rate Gearbox--brgs, all Weibull Curve Gearbox--high speed only Weibull Curve Lube pumps Weibull Curve Cooling Fan, Gearbox Coo Weibull Curve
1 1 1 3 3
117 117 46 4 4
1 1 1 3 1
Generator--rot. & brgs Constant Rate Generator--brgs only Weibull Curve Power electronics Weibull Curve Motor, generator coolant faWeibull Curve Contactor, generator Weibull Curve
1 2 1 3 3
24 10 8 4 4
1 2 1 1 3
Weibull Curve Constant Rate Weibull Curve Weibull Curve Weibull Curve
10 10 6 12 12
4 4 1 1 5
6 0 4 4 2
2 2 1 1 3
Yaw System
Yaw gear (drive+motor) Yaw caliper Yaw sliding pads Yaw bearing
12 10 10
4 4 8 1
8 8 8 147
2 2 4 1
Control System
Control board, Top Control board, Main Control Module Sensor, static Sensor, dynamic
Weibull Curve Weibull Curve Weibull Curve Weibull Curve Weibull Curve
15 15 15 14 12
1 1 2 25 2
0 0 0 0 0
1 1 4 7 4
20 30 30
1 1 0
4 4 8
1 1 0
Miscellaneous Parts
Constant Rate
158010
FALSE
D-19
2500 kW Results
Entry Values Turbine Rated Power (kW) Pitch Systmem Rotor Speed Control Turbine Quantity Total Project Power (MW) Project Capacity Factor 2500 Electric Variable Speed 24 60 0.35 Project Parts Cost Breakdown Parts 10,569,218 Crane 5,893,350 Additional Labor 360004 Total 16,822,571 Gross Project Income / yr ######## Gross Turbine Income / yr Annual Production (MW-hr) $421,575 183,960
Total Project $000 /year Year Parts Replacement (Hardware, Consumables Salaried Labor Wage-based Labor Site Maintenance Equipment Total $ /Turbine /year Year Parts Replacement (Hardware, Consumables Salaried Labor Wage-based Labor Site Maintenance Equipment Total $ /kW/ year Year Parts Replacement (Hardware, Consumables Salaried Labor Wage-based Labor Site Maintenance Equipment Total $ /kW-hr Year Parts Replacement (Hardware, Consumables Salaried Labor Wage-based Labor Site Maintenance Equipment Total
20 Average yAverage yAvg yr 11-Avg yr 161089 214 649 1052 1474 88 88 88 88 88 209 209 209 209 209 185 118 118 152 185 14 14 14 14 14 24 24 24 24 24 1610 667 1103 1539 1995
20 Average yAverage yAvg yr 11-Avg yr 1645368 8905 27045 43817 61403 3683 3683 3683 3683 3683 8719 8719 8719 8719 8719 7722 4914 4914 6318 7722 588 588 588 588 588 1000 1000 1000 1000 1000 67079 27808 45948 64124 83113
20 Average yAverage yAvg yr 11-Avg yr 1618.1 3.6 10.8 17.5 24.6 1.5 1.5 1.5 1.5 1.5 3.5 3.5 3.5 3.5 3.5 3.1 2.0 2.0 2.5 3.1 0.2 0.2 0.2 0.2 0.2 0.4 0.4 0.4 0.4 0.4 26.8 11.1 18.4 25.6 33.2
20 Average yAverage yAvg yr 11-Avg yr 160.0059 0.0012 0.0035 0.0057 0.0080 0.0005 0.0005 0.0005 0.0005 0.0005 0.0011 0.0011 0.0011 0.0011 0.0011 0.0010 0.0006 0.0006 0.0008 0.0010 0.0001 0.0001 0.0001 0.0001 0.0001 0.0001 0.0001 0.0001 0.0001 0.0001 0.0088 0.0036 0.0060 0.0084 0.0108
D-20
2000 1800 1600 1400 $ x 1000 / yr 1200 1000 800 600 400 200 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Project Age (yr) Parts Replacement (Hardware, Addt'l Labor, Crane) Consumables Salaried Labor Wage-based Labor Site Maintenance Equipment Total $ / turbine / yr
140000 120000 100000 80000 60000 40000 20000 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Project Age (yr) Parts Replacement (Hardware, Addt'l Labor, Crane) Salaried Labor Site Maintenance Total Consumables Wage-based Labor Equipment
50 45 40 35 30 $ / kW 25 20 15 10 5 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Project Age (yr) Parts Replacement (Hardware, Addt'l Labor, Crane) Salaried Labor Site Maintenance Total Consumables Wage-based Labor Equipment
0.018 0.016 0.014 0.012 $ / kW 0.010 0.008 0.006 0.004 0.002 0.000 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Project Age (yr) Parts Replacement (Hardware, Addt'l Labor, Crane) Salaried Labor Site Maintenance Total Consumables Wage-based Labor Equipment
D-21
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PLEASE DO NOT RETURN YOUR FORM TO THE ABOVE ORGANIZATION. 1. REPORT DATE (DD-MM-YYYY) 2. REPORT TYPE
3.
January 2008
4. TITLE AND SUBTITLE
Subcontract report
7/20/04 - 6/30/08
5a. CONTRACT NUMBER
Development of an Operations and Maintenance Cost Model to Identify Cost of Energy Savings for Low Wind Speed Turbines: July 20, 2004 June 30, 2008
DE-AC36-99-GO10337
5b. GRANT NUMBER
6.
AUTHOR(S)
NREL/SR-500-40581
5e. TASK NUMBER
WER6.0301
5f. WORK UNIT NUMBER
7.
8.
YAM-4-33200-07
10. SPONSOR/MONITOR'S ACRONYM(S)
NREL
11. SPONSORING/MONITORING AGENCY REPORT NUMBER
NREL/SR-500-40581 National Technical Information Service U.S. Department of Commerce 5285 Port Royal Road Springfield, VA 22161
13. SUPPLEMENTARY NOTES
The report describes the operatons and maintenance cost model developed by Global Energy Concepts under contract to NREL to estimate the O&M costs for commercial wind turbine generator facilities.
Unclassified
Unclassified
Unclassified
UL
19b. TELEPHONE NUMBER (Include area code) Standard Form 298 (Rev. 8/98)
Prescribed by ANSI Std. Z39.18
F1146-E(09/2007)