Turbine Doctors Revive a ‘Dead’ Vestas
September 14, 2011 by Windpower Engineering
Filed under Maintenance, Maintenance & operations
It took two engineers from Availon North America a matter of hours to repair and bring on-line a Vestas V27 225-kW wind turbine that belongs to the Story County Medical Center in Nevada, Iowa. The turbine was commissioned at the end of 1994 but stopped working in April 2011 when the power supply for the PLC controller died. The part, one called “inactive”, is still available but difficult to find and expensive. Replacing the failed part with a not-yet-found version was the only solution offered by the service provider. Due to the high cost and the long lead time, the clinic decided to just leave the turbine unrepaired until another solution could be found.
Andrew Engle, mechanic product support engineer for Availon, checks a couple more items in the nacelle of the once ailing Vestas V27 that is sited on the grounds of the Story Country Medical Center. Assisting in the project but not shown is Weston Smith, an Electrical Product Support Engineer.
So the turbine sat idle until its project coordinator, Jim Miller, learned of Availon North America’s experience servicing wind turbines. Within 24 hours of agreeing to service the turbine, Availon technicians had the unit back on-line. How did they do it? Availon says their engineers, who frequently service Vestas turbines, recognized that the company’s more recent V80 uses a similar power supply with just a few more features. The crew installed the readily available supply and gave permission for the turbine to return to productive work.
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Better Bearings for Wind Turbine Reliability
July 21, 2011 by Windpower Engineering
Filed under Bearings, Mechanical Components, Turbine Design, Webinars
Learn how to properly maintain your wind turbine bearings
Replacing failed bearings in wind-power equipment is no easy task. But after 20 years of concentrated effort, bearing manufacturers have devised designs that carry loads that fluctuate with wind gusts and work well in electric fields around generators. Viewers of this Webcast will hear presenters discuss the problems with bearing that shorten their life and more importantly, how their recent designs improve wind-turbine reliability.
Detecting Ice on Wind-turbine Blades
July 21, 2011 by Windpower Engineering
Filed under Condition Monitoring, Editorial, Maintenance
Nick Harper
Applications Manager
Blade Sensing Systems
Moog Inc.
www.Moog.com
Cold weather presents special problems for wind turbines. Inside the nacelle, low-viscosity lubricants keep the gearbox turning and enclosure seals to keep moisture and ice off electronic components. But outside the nacelle, things are different. Ice easily forms on turbine blades possibly adding hundreds of kilograms, which degrades performance and shortens working life. About 65% of wind turbines in North America are in areas where icing is possible and likely. Also because wind farms are often in remote locations, shutdowns are occasionally necessary when icing conditions are present. Then, turbines require a visual inspection before a restart.
The problem with ice on a working turbine is that it can be thrown, and when not, it causes additional drive-train loads often in excess of design loads. For this reason, many turbines are shut down when ice buildup threatens and restarts come only after an inspection confirms the ice is gone. This is a difficult practice in remote locations or at night.
Ice on turbine blades is fairly obvious when the unit is clearly visible. But at night or in remote locations, the question of ice on blades becomes a matter of conjecture. Weather conditions right for ice is one indicator, but there are better ways to detect it and protect turbines.
Traditional ice detection uses meteorological equipment but this does not detect ice on blades. It simply measures conditions for icing, so it does not give operators enough warning or time to take action – such as shutting down the turbine to prevent damage.
Detecting ice
A recent solution to the problem of blade icing includes ice-detection sensors and controls. The unit is part of a rotor monitoring concept, called RMS, for wind turbines. It lets operators monitor wind-turbine performance to detect ice on blades and avoid damage. RMS uses optical strain sensors mounted inside at the root of each blade. They work optically so the sensors are immune to lightning and electromagnetic induction effects.
The ice detection system provides information for the operator to shut down the turbine when ice loads exceed the specs or present a danger of throwing ice. The system also detects when ice has been shed.
The ice-detection system works two ways. The left of Signals from ice shows the system working under normal operation conditions. The monitoring system measures the bending moment of the blade as it rotates, generating a sinusoidal wave pattern. As ice builds on the blade, the amplitude changes. When the trace goes above a predetermined threshold, the monitoring system shuts the turbine down.
The right side of Signals from ice shows a static signal trace. At this time, the turbine is closed down but not stopped. The rotor is still turning slowly while the system is working in the frequency domain. It is relying on the low wind speed, about 3 m/s, to excite the natural frequency of the blade. This natural frequency changes as ice builds on the blade and changes its mass.
The photos and traces show how ice looks to a technician and the detection system.
The buildup of ice correlates with stored data. The right of Reading the graph tracks a period from October to December. At the test site, there was no ice buildup for the first 70 days. At about day 72, moderate ice was verified. On day 78, a significant amount of ice was noted. After that, there is a reduction in mass to the point where it was safe to restart the turbine.
Now consider two turbines, A and B, on the same wind farm. The red and blue traces show strong correlation. Notice the apparent noise signal level indicating about a 100 to 150 kg addition to one blade. This is significantly reduced by providing blade pitch information.
The ellipses identify two severe ice events detected by the system and confirmed by inspection. Without ice, mass values should be zero. In this case, both turbines have inherent noise of 100 to 150 kg because pitch angle feeds were not provided. Overall system accuracy is maximized by supplying a pitch and angle feed from the turbine controls, along with blade mass and center of gravity.
Experience shows that to increase the overall accuracy of the ice detection system, blade pitch position from the turbine’s control system is combined with the optical data.
So if we can take blade-pitch information on the turbine, we can reduce the noise level. Even without it, we can clearly see that both turbines correlate well with each other – they are both icing at about the same rate. At 40 days, turbine A had ice for about half the time of turbine B. This tells that the operator was able to start Turbine A before B by two days. This, of course, improves the revenue for that particular machine.
When the RMS is functioning on a working turbine, it can generate the blue traces. When signal top a predefined threshold, the controls halt the turbine, but the RMS continues to track ice build up through the frequency domain, the red plots.
Data in Time domain and frequency analysis presents a comparison between a turbine rotating (blue trace) and one stopped (red data). Notice that the turbine on Day 2 is working without ice, but slowing over a period of 1 to 1.5 days. The blue curve is going up indicating ice build up on the blade.
At some point, the selected threshold is exceeded and the turbines will be stopped. The red information indicates that Turbine A is halted, but the system still provides useful data. The mass still increases on the blade, up for two more days, but then the data becomes flat again. After about day six, it reverts to zero. So the system works when the turbine is operating, but it is just as useful when it is not.
A closer look
The rotor monitor includes several components. First, there are four independent sensors at the root of each blade. These are installed at four positions corresponding to the leading edge, trailing edge, pressure surface, and suction surface. The sensors that connect to the interrogator unit, are rugged, well protected, and will last the life of the blade. The interrogator unit (OEM1030), mounts in the hub of the turbine. It can also mount in the root of the blade, but anywhere in the rotating part of the turbine would do.
There are several ways to transmit data out of the hub. One is a GRPS modem, which lets operators send data to the U.K. for analysis. Another way is to send the data by slip ring into the nacelle where it could be connected to the SCADA system for direct control of the turbine. So as the ice builds to a certain level, the SCADA can call for a shutdown and restart when the ice clears.
The RMS from Moog includes four optical strain gages in each blade, an interrogator unit in the hub, and at least one of two ways for transmitting signals across the turning hub.
The other main feature of the system is part of the RMS. Using the same system and additional software supplied by Moog, the system can interrogate the data and deduce information associated with blade damage and rotor imbalance. This can reduce the unit’s overall payback period.
Ice detection can be implemented on any wind turbine. It has been globally installed in many and we have not yet received word of any sensor failure. From experience, the system annually provides about $15,000 in additional revenue. In September 2009, GL certified the system.
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Wind Turbine Reliability – The Importance of Highly Reliable Pitch Control and Blade Sensing Systems
July 20, 2011 by Windpower Engineering
Filed under Condition Monitoring, Construction, Maintenance, Maintenance & operations, Towers, Uncategorized, Webinars, Wind Safety
Increase Turbine Reliability
In this 40 minute webinar, learn how two common hazards can hamper a wind turbine’s production. Wind-turbine owners and operators may experience a significant reduction of generated power, reducing overall turbine efficiency, if they don’t take into account:
- Blade Icing
- Failed Slip Rings Issues
- Increased Reliability
In this free webinar, we explore how Moog Blade Sensing Ice Detection Systems can monitor the load of each blade, providing real-time data indicating presence and level of ice build-up. We also examine key challenges with transmitting power and data signals from the nacelle through slip rings to the pitch-control system. Costly downtime can be eliminated by using fiber-brush technology and rugged mechanical components in the slip ring. Moog representatives show how they designed a slip ring that addresses these requirements for reliability and maintainability and thereby reduces a wind turbine’s overall operating cost.
Wind Wakes May Spill Their Secrets
July 19, 2011 by Windpower Engineering
Filed under Weather forecasting, Wind Watch
Wind turbine wakes produce invisible ripples that can affect the atmosphere and influence downstream units. Recent computer research into turbine spacing indicates about 15 rotor diameters are sufficient to dissipate wake effects and maintain the output of downwind machines. Because more detail is needed, researchers have launched a study to make the ripples visible to observe their affect on the atmosphere.
Julie Lundquist, assistant professor in the atmospheric and oceanic sciences department at University of Colorado Boulder along with researchers from the National Oceanic and Atmospheric Administration (NOAA), the National Renewable Energy Laboratory (NREL), and Lawrence Livermore National Laboratory (LLNL), are conducting the study–Turbine Wake and Inflow Case–to improve energy production at wind farms across the country.
The National Wind Technology Center with several turbines near Boulder, provided equipment of the study. (The data collection phase completed recently and the analysis has begun.) The collected meteorological data included a range of atmospheric stability conditions, including wind speed, wind direction, and streamwise variance profiles.
The ultimate laboratory shows turbine wake extending back many rotor lengths. But air flow and patterns between the turbines and above them remain unknown.
The data will help validate wind-flow models developed at Livermore and elsewhere. “The study is part of a larger suite of observations and model-development efforts under way at LLNL to help hit aggressive state and national targets for renewable energy deployment,” says LLNL’s Jeff Mirocha. “This field campaign dovetails with ongoing observational studies at our Site 300 that focused on understanding complex wind patterns occurring in hilly, coastally influenced locations, which is similar to much of California’s wind resource.”
Today’s massive wind turbines reach into a complicated part of the atmosphere, Lundquist expalins. “If we can understand how gusts and rapid changes in wind direction affect turbine operations and how turbine wakes behave, we can improve design standards, increase efficiency, and reduce the cost of energy.”
LLNL has also been working on numerical weather models to predict power generated by wind. Researchers at the Lab are looking at prediction time frames ranging from an hour to days.
Analysts will examine turbulence and other wake effects in a broad wedge of air up to 4.3 miles long and 3,280 feet high. The team used a lidar (laser detection and ranging) unit for a detailed look at the atmosphere in front of and behind one of the large turbines on the NREL site – a 2.3 megawatt unit with a rotor that reaches up to 492 ft. A goal is to capture the effects of ramp up and ramp down events, when winds suddenly gust or die down, and what happens downstream when winds quickly shift direction.
“The wake effect has been modeled in wind tunnel studies and numerical models,” says Mirocha, “but the atmosphere is different. It’s more variable and complicated.”
The output from a lidar unit tracks time versus altitude, while the color scale indicates wind speeds.
Researchers used Windcube’s lidar and a Second Wind sonic detection and ranging system to measure wind and turbulence. NREL also installed two meteorological towers, each 442 ft high, to measure air temperature, wind, and turbulence. Data analysis will take several months.
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What types of metals are used in wind turbines?
May 19, 2011 by Windpower Engineering
Filed under Materials, Wind Basics
The most used metal in a wind turbine is steel in the tower and other components. But a few more recent material ideas deserve mention. For instance, one solution to the climbing cost of all copper wire is in copper-clad steel. It is said to be reliable, cost effective, and can provide the wind industry with a smarter alternative to copper-based grounding systems. The financial crisis has altered the trajectory of wind-farm projects by tightening developers’ budgets with a need to control costs, an increasing priority even as the industry expands.
Until recently, copper has been the predominant material in wire and cable used to grounding of electrical systems. But the cost of copper fluctuates substantially. This is bad news for wind- farm developers, and electrical and construction contractors who are under increasing pressure to control costs.
One solution to the problem is in new materials, such as copper-clad steel. It is said to be reliable, cost effective, and can provide the wind industry with a smarter alternative to copper-based grounding systems. The financial crisis has altered the trajectory of wind-farm projects by tightening developers’ budgets with a need to control costs, an increasing priority even as the industry expands.
Given the cost sensitivity of any wind-farm project, the idea of burying a precious metal (copper) underground makes little economic sense when less expensive, alternatives are readily available. Copper-clad steel has been around for decades and is a practical option to consider in grounding applications. It offers an alternative to copper by combining the strength of steel with the conductivity of copper through a cladding that delivers comparable performance.
Trends in wind power electrical components
May 17, 2011 by Windpower Engineering
Filed under Electrical Systems, Turbine Design
Wind turbines have been maintenance nightmares for many operators over the past few years. This is to be expected when the rush to install wind turbines has avoided the usual developmental learning curve, on which new technologies mature by trial and error. Instead, many turbine designs have, until very recently, been taken from other industries with little to no modification. The gearbox was designed for railroad use, bearings were taken from a number of different industries that didn’t expose their components to such extremes. Electrical components are no different, except that they may be slightly behind the curve. Thankfully, manufacturers have noticed the high failure rates and started to do something about it.
Transformers
Historically, transformers wind farms have been conventional, off-the-shelf distribution units. But, after a relatively large number of failures, transformer manufacturers have changed their strategy and begun designing wind-farm specific transformers. Key characteristics of the new models include alterations to transformer loading, harmonics and non-sinusoidal loads, voltage variations, transformer sizing, and special requirements to handle faults. According to Tom Steeber with Pacific Crest Transformers, “A transformer designed specifically for a particular application will hold up dependably, while standard off-the-shelf transformers may fail if not designed with the needs of an application in mind.”
Transformer operating costs are also an issue the industry is addressing. ABB’s Transformer Design Specialist Doug Getson puts it into perspective, “Transformer losses are measured at load and no-load,” he says. “Even when they aren’t working hard, transformers are consuming power often priced from $2 to $8 per Watt over a 20-year equipment life. A 0.5 to1% boost does not sound like much but consider the many transformers on a wind farm and you suddenly see the operator could be losing a significant sum.”
Utilities often consider a transformer’s total cost of ownership as the unit’s price tag plus the cost of operation. So even though more efficient transformers cost more up front, over a 20-year life a typical high-efficiency transformer can save about $11,000. Now multiply that by the number of turbines on the farm and there’s substantial savings.
Other Electronics
Other electronic adaptations have resulted in similar lackluster performances, and have subsequently been through a redesign as well. For example, Eaton Corp. has designed a 38-kV vacuum circuit breaker specifically to handle the fluctuations inherent in wind systems. This design offers added capabilities such as capacitor switching duty, transformer secondary fault protection, and high operating endurance.
Similarly, Pfannenberg USA has designed thermal management systems to help keep electronic products within a desired temperature. The DTS 3000 series cooling units offer high ambient temperature performance designed with internal airflow paths that support natural convection and eliminate hot spots within turbine control panels. Pfannenberg is also currently developing and testing 48-V units for special high-frequency vibration applications.
A 3-MW drivetrain all in one package
April 7, 2011 by Windpower Engineering
Filed under Couplings, Electrical Systems, Mechanical Components, Turbine Design, Wind Power Generators, Wind Turbine Gearboxes
A recent wind-turbine drive combines a two-stage gearbox, coupling, and permanent-magnet generator into one compact package. One design goal for the HybridDrive from manufacturer Winergy (winergy-ag.com) is to reduce drivetrain size. A direct connection between gearbox and generator allows shortening the drivetrain by about 35% and nearly eleminating alignment tasks. The company says it demonstrates a peak efficiency of over 94%.
The direct connection between gearbox and generator allows a drivetrain 35% shorter than a similarly sized conventional unit.
Its compact dimensions present several advantages when designing a wind turbine. For instance, when the HybridDrive replaces existing machinery, it is possible to use the reclaimed space for the converter and transformer instead of mounting those in the tower. Relocating transformers to the nacelle reduces low-voltage cable losses, which further improves efficiency. Depending on design, tower costs can be reduced due to the lower nacelle weight. Transportation costs also drop because of the smaller nacelle.
Another plus is that the PM generator uses only 20% of the rare-earth materials used in similarly sized direct-drive units. Dependence on a particular and costly raw material, often neodymium, is considerably lower making long term costs easier to calculate.
The drivetrain is available with just one or a dual-bearing rotor shaft. Winergy adds that engineers can order the drive with either journal or conventional roller bearings for the planetary gears.
Despite its compact size, the drive is sufficiently modular to allow for disassembly and replacing parts when necessary. For instance, a service crane in the nacelle can lift individual drive modules. So if major service becomes necessary, there will be no need for a crane callout, which considerably reduces service costs. Furthermore, says Winergy, reliability and quality of the drive is optimized because a single supplier is responsible for the design and quality assurance of the drivetrain.
The first design of the drive has an output of 3 MW and is intended for use in offshore turbines. The developer says the concept is easily increased to the 6 to 7 MW range.
Mountain top turbine includes a viewing deck
March 3, 2011 by Windpower Engineering
Filed under Construction, Towers, Turbine Design, Wind Power Projects
The Eye of the Wind, a 1.5-MW turbine, sits on Grouse Mountain near Vancouver. It is the first turbine to feature a viewing deck. Workers begin to build the Eye of the Wind on its mountaintop location at 4,039 ft above the Vancouver.
Not many tourists would be willing or able to climb a 60-m ladder just to pop the top hatch of a turbine nacelle for a stunning view. Thanks to an unusual turbine variation built on Grouse Mountain near Vancouver, BC, they won’t have to. The turbine, The Eye of the Wind, includes an elevator and viewing deck or pod open to the public. It is the first in the world.
Finnish escalator manufacturer Kone Inc., designed the lift for the turbine. The company called in its marine department to assist because of seismic requirements, limited space inside the tower, and a continuously swaying structure.
A few construction and logistical challenges included the size of many components and the unusual mountaintop location. For instance, the pod sits 1,231 m (4,039 feet) above the city. The structure’s hexagon foundation measures 2-m high, 8-m wide. The concrete base uses anchors imbedded deep into bedrock, some as deep as 15 m. The most complex task was transporting the three, 37.3-m long blades which came by freighter from Europe to nearby docks. For their final leg, a large Air Crane helicopter lifted the blades to the peak.
Workers begin to build the Eye of the Wind on its mountaintop location at 4,039 ft above the Vancouver.
The wind turbine tower was manufactured in Washington State in three sections. Each is close to 20-m long and made from structural steel weighing up to 45,454 kg/section. Tower sections were transported on low-bed trailers along expressways and city roads, and finally at a walking pace up Grouse Mountain’s winding 13 km back road.
The viewPOD, designed and manufactured in France, was transported by freighter to the east coast of Canada and by train to Vancouver. This steel-and-glass capsule was assembled on the ground before being lifted into place.
To prepare for construction, a crane was brought to the project site in 17 separate truck loads. It was assembled on the site over three days. This crane can lift 300 tons with its 90-m boom.
A helicopter carried the 37.3-m turbine blades to the construction site.
Turbine assembly took another three days. Each component was lifted by the crane and bolted into place. The three tower sections were lifted first, followed by the viewPOD, the wind turbine machine carrier, then the generator, and the blades. The blades were pre-assembled to the hub and lifted as one unit. The months following saw installation of the elevator inside the tower and completion of the electrical components.
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Finding and fixing drivetrain problems
March 1, 2011 by Windpower Engineering
Filed under Drives, Featured Wind Power Articles, Maintenance & operations
Ashley Crowther, VP Engineering, Wind Romax U.S.
A case study shows how condition-monitoring data and engineering analysis can identify the root cause of trouble in wind-turbine drivetrains, and then give design teams information to solve the problems.
Maintaining profitability is one of the biggest challenges facing offshore wind-farm operators and owners. Innovative technology and logistics mean reliability issues and traditional reactive-maintenance practises lessen viability of equipment mounted offshore.
To meet these challenges, wind-farm owners and operators are turning to “asset management” companies along with operations-and-maintenance (O&M) suppliers to reduce the cost of running the turbine fleet. As with any fledgling industry, offshore wind is bound to suffer from teething problems. Drivetrain failures are responsible for a significant amount of turbine downtime, particularly in the gearbox and main bearings.
Why repairs fail
There are 
many reasons these major components suffer. Most of their performance shortcomings stem from extreme weather conditions, manufacturing errors, and sometimes fundamental design flaws. Surface fixes, such as bearing or gearbox replacements, often prove to be short-term fixes and fail to find a root cause. Superficial repairs lead to repeat failures and additional cost.
The tech records a few maintenance figures in a nacelle. The size of the gearbox shows that almost any repair to it will require heavy-duty labor.
Mitigating such risk requires an in-depth understanding of the complex drivetrain system and environmental interactions, something which only experienced wind-energy providers and technical experts can provide. Drivetrain assessments, component-life predictions, and end-of-warranty inspections form part of an O&M program that can reduce cost and increase reliability.
A good example of how these services can improve turbine reliability and safeguard future wind farm profitability is a recent project conducted by colleagues at an offshore wind farm. The project set out to identify the cause of an unusual number of identical failures in the turbine fleet. The operator also wanted to understand the nature of the vibration characteristics uncovered by their condition-monitoring data, and whether those signatures were indicative of a wider reliability issue.
A failure distribution analysis found that 80% of the particular failures were due to bearings, and nearly 10% due to gears. The bearing-failure ratio was much higher than other farms in the fleet, especially for the high-speed shaft bearing which was a problem for the turbines in that series. The engineering analysis team had to establish the root cause of the high-speed shaft bearing failure.
An assessment of vibration data showed that the high-speed gear mesh’s 3rd harmonic and oil pump’s 6th harmonic had high amplitudes near the machine’s rated speed and power.
When the machine speed decreased, these vibration amplitudes reduced markedly, but the high-speed gear mesh 4th harmonic grew in magnitude. Field data showed that at rated speed and power the two vibration sources (high-speed gear mesh and oil pump) where contributing 40% of the RMS vibration level of the gearbox. Assessing data from other turbines in the fleet showed the vibration issue in all gearboxes of the same make and pointed to a serial design problem.
To carry the investigation further, the team built a simulation model of the gearbox in RomaxWIND software to predict the structural vibration response from the gear transmission error and its multiple harmonics. The software is a simulation tool with capability to model an entire gearbox (gears, carriers, bearings, lubricant, and housing) and predict dynamic behaviour under particular operating conditions –certain torques and speeds. It is applied to wind farm, drivetrain-issues in combination with practical engineering design and field work.
LEFT: A gearbox simulation showed several modes that will be excited near 1,600 rpm. The image shows one example, a bending mode of the high-speed shaft. The model can be used for gear-tooth microgeometry optimization, one way to reduce the vibration level. CENTER: Data for the charts came from a different wind farm than the one in the case history. The top pie charts shows turbines there have trouble about 59% of the time because of gearbox failure, and those most often because of bearings, and that most bearing failures occur on the high-speed shaft. RIGHT: A wind turbine gear box has been modeled in Romax Wind, modeling and simulation software for wind turbine drive trains and pitch and yaw systems. A transparent housing shows two planetary stages and their arrangements.The high-speed output shaft appears to the lower left with the output torque designated as a red ring.
The vibration spectra plots vibration amplitude versus frequency for two shaft speeds. At 1,698 rpm on the output shaft, the oil pump’s 6th harmonic and the high-speed shaft’s 3rd harmonic dominate. Dropping the shaft speed to 1,296 rpm also drops amplitudes of the two components while the 4th harmonic on the high speed shaft dominates. This indicates something amiss with the high-speed shaft.
The software’s dynamic analysis demonstrated that subsystem resonance at rated condition was the likely cause. The Waterfall graph shows a predicted housing response for the first three harmonics of the high-speed gear mesh. The resonant behavior of the system with the 3rd harmonic from 1,600 to 2,000 rpm is also evident. Correlating to the vibration characteristics from field data helps then to use the model to understand the source. In this case, many local structural modes are excited by the HS gear and oil pump higher harmonics. The illustration Bending Mode shows an example bending mode that will respond to the excitation.
The analysis uncovered several issues contributing to the poor bearing reliability, one of which is a serial issue of resonance of gear excitation frequencies with the structure. By simulation and field work, the analysis team demonstrated that the gearbox had not been designed for good vibration characteristics at operating torque and speeds. In addition, the technical team was able to explain how design improvements could overcome these issues.
For a gearbox retrofit, it is not practical to change the structure and shift the resonances. Hence, practical engineering solutions include investigating the surface waviness of the oil-pump gear from manufacturing processes to ensure it is not related to the 6th harmonic, changing the number of gear teeth on the pump, or improving the microgeometry design.
For the high-speed gear, a good avenue for improvement would be microgeometry optimization to reduce source excitation; the third harmonic of the gear transmission error. Microgeometry optimization could include parameters such as tip relief, root relief, and involute crowning and would need to be engineered so modifications do not reduce gear durability.
By redesigning the component, the turbines would be able to run more effectively. Of course, gearbox rebuilds must be kept within design and cost constraints and they certainly should not go back to the field with the same problems.
Understanding flaws
The analysis team showed that by understanding faults and the ability to predict the lifespan of components through simulation, wind-farm operators can greatly improve their knowledge and ability to schedule maintenance for their fleet of wind turbines. Much of Romax’s field engineering focuses on this issue because a reasonable bottom line for the fleet depends on improving reliability and controlling costs.
A proactive approach to turbine fleet management can have a significant impact on the running costs and fleet uptime. The ability to feedback potential design issues through the manufacturing cycle also significantly aids in the design of new machines and helps ensure the next generation of turbines is installed without the problems of the past.
Housing response to high speed gear vibration: High-speed shaft speeds plot on the X axis (rated speed is approximately 1,600 rpm for this shaft). Vibration amplitude plots on the Z axis, from the gearbox housing near the high-speed shaft. And response frequency plots on the Y axis. It’s the frequency of the actual vibration of each harmonic at a certain shaft speed (X axis speed). As the gearbox speeds up, vibration at the 3rd harmonic grows to a resonance near 1,600 rpm and then falls away again as the machine runs faster. The high-speed gear is the largest contributor to vibration.
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