January 2012

Success or failure in construction is largely determined by how well risks are managed. Foundation system selection represents one of the largest risks to any project because of the inherent uncertainty that exists when working in the ground. This risk is never more critical than on wind farm projects where the project “site” covers many square miles and geotechnical conditions may vary drastically from one turbine location to another. For the maximum chance of success on any project, owners, designers and constructors must manage risks carefully by selecting foundation systems that are cost-effective, reliable and also adaptable to variations in geotechnical conditions.

Foundation Options
Foundation system selection needs to consider performance as well as construction cost and schedule. Even the most efficient foundation systems must also have sufficient flexibility to adapt to changes in conditions that may be encountered in the field during construction. Figure 1

The most efficient foundation scenario involves support of a turbine on competent soil at the design foundation bearing elevation. In this instance, a large concrete, inverted “T” foundation is used for turbine support. This approach represents one with the least expense and lowest foundation construction risk. Unfortunately, wind projects are sited in soil conditions that often exhibit insufficient support capacity to meet performance requirements and additional foundation support measures are needed.

One option in wide use involves over-excavation and replacement of poor soils. This approach requires large volumes of soil be excavated and removed at the tower location and the area is backfilled with thin, controlled lifts of high-quality engineered aggregate (similar to roadway construction material) prior to foundation construction. The tower foundations are then designed and constructed as the same inverted “T” foundations as those supported on natural competent soils. While this approach meets performance requirements if constructed properly, the risk of schedule delays and cost overruns remains high because of the potential for encountering high groundwater (requiring dewatering operations), inclement weather or deeper excavation requirements than anticipated to remove unsuitable soils.

Other options, in cases where the poor soils extend too deep for excavation, fall into the “deep” foundation category. Deep foundations are used to bypass thick zones of soft or compressible soils to transfer foundation loads to more competent bearing materials. These include driven piles, drilled piers (caissons), augercast-in-place piles, grout piles, and other forms of rigid inclusions. While these systems provide acceptable performance, tower foundation costs are typically much higher. These designs require thorough analysis to account for the behavior of the pile group under the complex turbine loads. Additionally, costs for deep foundations are often prohibitive because piles need to extend to depths sufficient to develop shaft resistance or bear on hard material (i.e. rock or hard glacial soil). Construction schedule risks exist from uncertainty of installation depths to reach bearing strata, low daily production rates, and difficulty with material delivery to the often-remote sites.

Intermediate Support
For more than a decade, many wind farm project teams have reduced performance and construction risk and saved time and money by considering support solutions beyond the traditional construction approaches. Rammed Aggregate Pier® (RAP) systems designed by Geopier Foundation Company have provided support for structures for over two decades. These Intermediate Foundation® systems have been used extensively on wind projects in the United States, Canada, Mexico and in Europe. Figure 2

The concept involves densifying or reinforcing poor soils through the installation of stiff aggregate piers that uses high frequency vertical ramming energy during construction. Installation of RAP elements is accomplished by either replacement (Geopier® system) or displacement (Impact® or Rampact® systems) construction techniques to depths of up to 45 feet. The replacement system involves drilling a 24-36 inch diameter cavity depending on design requirements; placing thin lifts of aggregate within the cavity and vertically ramming the aggregate using a high-energy patented beveled tamper. The displacement system involves driving a specially designed mandrel and tamper foot into the ground using a strong static crowd force augmented by dynamic vertical impact energy. After driving to design depth, the hollow mandrel serves as a conduit for aggregate placement. Figure 3 Aggregate is placed inside the mandrel and delivered to the tamper head. The mandrel is then raised approximately three feet and then driven back down two feet, forming a one-foot thick compacted lift. Compaction is achieved through static down force and dynamic vertical ramming from the hammer.

During construction of each RAP system the high frequency energy delivered by the hydraulic hammer, combined with the beveled shape of the tamper, not only densifies the aggregate vertically to create a stiff aggregate pier but also forces aggregate laterally, resulting in lateral stress increase in surrounding soil. The lateral stress increase reduces the compressibility of the surrounding soil and promotes positive coupling of the RAP element and the soil to create an improved composite, reinforced soil zone.

The system reinforces poor soils, which improves the bearing pressure of the reinforced zone beneath turbine foundations, controls total and differential settlement (angular distortion) of the foundations and improves the rotational and dynamic stiffness values to achieve the desired turbine performance. The soil reinforcement designs are developed on a project-specific basis depending on site and tower loading conditions to support shallow inverted-T foundations, like those bearing on engineered fill or competent native soils. The use of the intermediate solution eliminates the need for massive over-excavation or deep foundations and also allows for adaptability in construction based on soil conditions encountered at the site. Figure 4

Challenging Sites Demand Flexibility
Recently, engineers with HDR Engineering, Inc. (HDR) were faced with the challenge of designing a large wind farm in Franklin County, Iowa. The project involved the design and construction of 121 wind towers traversing 33,000 acres, or about 51 square miles. The project featured Vestas V82 model turbines, with 80-meter hub heights, capable of generating 1.65MW of power.

Working with the project geotechnical engineers (Terracon), the design team determined that the foundation risks for many sites could be managed cost-effectively by supporting towers on octagonal inverted-T foundations bearing on competent soils or perhaps limited areas of shallow over-excavation. Multiple, different-sized tower designs were prepared to accommodate the different soil conditions and variation in maximum allowable soil bearing pressures from site to site. Figure 5

Typically, when over-excavation depths exceed three or four feet below the foundation, alternative approaches become more cost-effective. Many sites across the 51 square miles encountered these conditions where the shallow foundation option bearing on native soil was inappropriate. HDR and Terracon, working with Geopier engineers, found a solution by using an intermediate RAP approach to provide acceptable performance and keep foundation costs under control while utilizing the existing shallow foundation designs prepared by HDR. The soil conditions requiring reinforcement ranged from soft to stiff clay with occasional silt and sand layers to thick deposits of loose clayey sand, silt and sand. With variable soil conditions and groundwater levels as shallow as three feet at some sites, multiple RAP construction approaches (replacement and displacement) were required. The versatility of the Geopier technologies ultimately resulted in a solution for 37 tower sites.

Once selected, prime contractor RMT, Inc. utilized the RAP system constructed by licensed installer Foundation Service Corporation, Inc. (FSC), of Hudson, Iowa. During detailed design FSC and Geopier identified each site as either a replacement (Geopier approach) or a displacement (Impact) approach. Different RAP design approaches were then developed based on the different soil conditions for each site. The soil reinforcement designs incorporated a grid of RAP elements ranging between 56 and 100 piers per turbine site with piers extending 9-17 feet below the footing to reinforce the poor soils.

Construction of the RAP systems at each site was typically completed within two to four days depending on the installation method and soil conditions encountered. In some instances, unexpected variations in soil conditions resulted in the need to adjust installation methods.  Fortunately, the RAP systems afford the flexibility to modify the construction approach (displacement Impact or replacement Geopier) with rapid changes to the RAP design made in a day or two and no subsequent structural design changes to the foundations. These adjustments allowed the project to continue moving forward to meet schedule goals despite unexpected variations in conditions.

Quality control testing on the project included the performance of full-scale modulus load testing to evaluate the response of the pier under applied stresses. Measurements confirmed the pier stiffness met or exceeded the design requirements when loaded to pier stress levels more than four times the maximum foundation stress.

Summary
Rammed Aggregate Pier systems are now commonly used for foundation support solutions on turbine sites across the Americas and Europe as a means to manage geotechnical risks and provide superior construction and performance. This intermediate foundation approach reinforces a variety of poor soil conditions, allows the use of cost-effective inverted-T foundations and provides flexibility during construction to make construction/design changes based on conditions encountered at specific sites to help maintain schedules. With over 1,000MW of towers supported, Rammed Aggregate Pier systems are fast becoming a preferred foundation support solution to manage geotechnical construction risks and deliver successful time and cost-saving solutions. 

The rotating machinery in a wind turbine has demanding requirements. Consider that designing a wind turbine gearbox is equivalent to designing an automotive gearbox to last for two million miles, with 15 times as many cycles. The machine must be light and thereby flexible, and it is subject to transient loads and overload, idling conditions, and temperature extremes. Service of this long duty cycle machinery must be performed 80-odd meters from the ground.

Fortunately, various offline and online monitoring technologies help to keep an eye on the health of your machinery—vibration, temperature, and lubricant condition, for example. The technology is generally well established yet the application of monitoring is still challenging, and no all-encompassing gadget or approach is going to warn you of every machinery failure. Tuning monitoring equipment, or your approach to problems reoccurring in your wind farm and machinery, is generally a good step to take.

Common Problems
A few examples of common problems the industry is facing today include:
Type 1: Inclusions in gear material, from poor quality control on the raw material manufacturing. The inclusion acts as a stress concentration and can result in tooth fatigue failures, often readily identifiable from visual inspection due to characteristic beach marks radiating out from the crack origin.

Type 2: Gear surface tempering (grinding burn), where the surface temperature of the case hardened gear has not been controlled properly during grinding. This can even lead to re-austenization and re-hardening of the material. Temper grinding burn will reduce the surface hardness and residual stress condition, which will reduce wear resistance. Re-hardening burn will produce a hard, brittle surface layer, and cracks may begin in the tooth surface and result in low life for pitting and fracture.

Type 3: Axial cracking in through hardened bearings, where the bearings are prone to cracking as they have inherent poor toughness and residual tensile stresses due to the heat treatment process (compared to case carburized bearings). They may suffer from hydrogen embrittlement, have superimposed hoop stresses from inner ring raceway fits, and they are often subject to harsh overload conditions in the wind turbine. The cracks may lead to the raceway slipping on the shaft, and potentially a catastrophic failure in the gearbox. Any cracks will also form a nucleation point for surface rolling contact fatigue, where the raceway surfaces will break up due to fatigue spalling.

Type 4: Poor load sharing conditions in double row spherical roller mainshaft bearings, where the downwind raceway of the bearing supports all the thrust loading from the blades, while the upwind raceway becomes unloaded. The operating condition is poor (i.e. the axial to radial load ratio on the downwind race is too high), and the bearing tends to suffer from adhesive wear and micropitting toward the roller ends due to roller skewing under the extreme load conditions. The generated debris then contaminates the grease, causing surface indentations on rollers and raceways, and eventually leading to a runaway surface fatigue failure.

These four examples are machinery problems that, if they happen two or so times in your fleet of 100 turbines, you can reasonably expect them to happen again. A Weibull analysis using the failure records will provide estimates of future failures with a statistical basis and indicate whether the failures are due to infant mortality, aging, or from some random external influence. Getting a grip on how to detect the problem consistently and plan your maintenance and repair in advance, as well as avoiding secondary damage or catastrophic failure, will bring a good payback.

Detecting Defects
Temperature trending is easy to do. Every modern turbine SCADA system records 10-minute temperature data for the gearbox oil and several bearings, mainshaft bearings, generator bearings, and various other locations such as pitch motor temperatures and generator winding temperatures. Temperature can provide a good indication of a problem (see Figure 1), which provides the distribution of temperature each week. The bearing showed a clear trend of overheating; the replacement was scheduled two months out when mean temperatures approached 75°C and the damage was approaching a critical stage (Figure 2).

Yet not all damage is obvious, or the trend slow. For example, if inclusions are present in the gear material the fatigue crack origin is likely to be subsurface, and cracking may propagate along the tooth axially some distance before reaching the surface, at which point a large tooth segment may be quickly liberated. This is a catastrophic failure that requires immediate shut down. Detecting such damage should not be difficult. The RMS (root mean square value of the vibration level) will increase rapidly, and the envelope spectra (a demodulated vibration signal) will show an obvious issue. Figure 3 provides an easy “spot the difference” example.

An axial crack forming in a wind turbine bearing raceway is actually similar to the type of controlled experiment performed in research laboratories, where a raceway or roller has a line defect machined for production of a clear repetitive impulse. The crack will cause a sharp impulse when it passes through the bearing contact zone, exciting the structural system in a similar fashion to a modal test. The impulse will excite natural frequencies of the structure that are detected at the various vibration sensor locations, depending on the transfer function between impulse location and sensor. The natural frequencies become a carrier frequency, and when the envelope analysis technique is applied the signal is demodulated to provide the frequency of the defect. Figure 4 shows the frequency spectra for a bearing that has developed such a crack and the marked change in the frequency spectra.

Defects on inner raceway, outer raceway and rollers occur at different frequencies. For stationary outer raceway, an inner raceway defect is manifested by roller pass frequencies (RPFI) modulated with shaft frequencies (ω_s) as the crack rotates through the contact zone. The outer raceway defect frequency (RPFO) has no modulation for a fixed outer raceway. The roller defect frequency (2RSF) is twice the roller spin frequency as the defect hits the inner and outer raceway once per roller revolution and is modulated by the cage frequency (ω_c). These defect frequencies commonly include higher harmonics. Table 1 provides a summary for a fixed outer raceway.

Avoiding Failure
Many installed condition monitoring systems (CMS) are configured with certain envelope analysis parameters, yet they don’t necessarily band pass the appropriate carrier frequency to detect the crack. Figure 5 illustrates this, with the RMS of a standard envelope (and RMS) from installed CMS compared to an envelope technique customized by Romax to find cracks occurring at this particular wind farm. In this case temperature data also showed no evidence of the crack formation and growth.

Main bearings failing from micropitting and surface fatigue are another challenge. Here the rotational speeds are very slow, and the bearing fault frequencies are falling in the range of 1-5Hz. The machine has speed and load variations within the same frequency range which brings some challenges. When the shaft speed varies the machine frequencies vary with time, which smears the spectrum. In order to compensate for the speed fluctuations, the shaft speed is used to re-sample the vibration signal.

Nonetheless, a combination of techniques allows the detection of the bearing failure, which for this common failure mode can be six to nine months in development from initial damage to a critical state. Figure 6, Figure 7, Figure 8 provide temperature and vibration examples for a group of the turbines (note that the days on the graphs correspond). Here several bearings at the site are failing, yet temperature trends are only clear in one machine, where the damage is severe. A combination of several vibration techniques including customized envelopes and trending fault frequencies as well as certain envelope bands does yield good results. Once a certain level of damage is reached, the bearing defect trends can decrease (Figure 7). This is a sign that the damage has progressed from isolated areas to a large proportion of the raceways and rollers, as was the case when the bearing was inspected at day 0. The customized envelope is providing a much earlier and clearer indication of damage, and the temperature trend only provides a late indication. See Figure 8 for an image of the condition of the main bearing for Turbine A at -128 days, and Figure 9 during teardown inspection by Romax engineers.

Understanding the root causes of failures and not having surprise problems that stop or reduce production at your wind farm reduces O&M costs. When failures occur, perform root cause analysis with experienced inspection engineers, gear and bearing designers/analysts, and metallurgists. Use the turbine data that is available, whether SCADA/vibration or both, and develop approaches that work well for the failures that occurring commonly. Conduct an annual vibration data acquisition and assessment campaign if CMS is not installed and is too costly. Apply reliability statistical methods to predict component lifetimes, and if poor consider re-engineering or other mediation to extend service life.

Conclusion
Romax Technology is a global engineering consultancy providing services to the wind industry. We have designed certified gearboxes for nine different turbine manufacturers and provide services to wind farm owner/operators including machinery inspection, SCADA assessment, vibration analysis, root cause analysis, and problem solving. Romax has U.S. offices in Boulder, Colorado, and Troy, Michigan. 

The winds of change may soon affect wind turbine design. Moog recently conducted a worldwide survey of wind farm operators and wind turbine builders to better understand their needs vis-à-vis blade pitch control. We found that, excluding macroeconomic forces, there are three trends likely to affect the design of wind turbines in the medium term. First, the world will see new wind farms in hard-to-reach areas with harsh weather conditions. Second, wind power will account for a larger part of total electricity supply. And third, there will be an increased focus on improving turbine efficiency, especially in mature markets.

Addressing these issues while maintaining rapid growth will be challenging. Wind turbine builders will need to nurture mutually beneficial relationships with key subsystem suppliers in order to improve performance, while increasing production volume and expanding their geographical scope.

Offshore and Elsewhere
As wind energy grows in importance, new wind farms will increasingly be located in harsh environments that are difficult to reach. Offshore installations present particularly difficult issues. Offshore wind capacity is growing fast, with 13,500MW of new capacity expected to be installed globally between 2010 and 2014 [1]. The current generation of offshore wind turbines face strong wind conditions and waves one meter high or more. Figure 1

As the number of offshore wind farms grows, operators and owners are likely to locate these farms in deeper waters and further from shore. In the United Kingdom, for example, the average maximum depth of water in which wind turbines are located is projected to increase from 15.6 meters for projects commissioned between 2005 and 2009 to 27.1 meters for those commissioned between 2010 and 2014. Similarly, the distance from shore is projected to increase from 9.1 kilometers to 19.8 kilometers [2].

A similar trend will apply to onshore wind farms, with new wind farms increasingly being located in remote locations with harsh climates. China, for example, has declared its intention to create seven wind power bases with a capacity of at least 10GW each by 2020. Two of these are in Eastern and Western Inner Mongolia. Inner Mongolia is bitterly cold, with long winters during which temperatures can drop as low as -23°C. Blizzards are common in winter and there are frequent sand storms during the short summer.

Total Electricity Supply
In its reference scenario, which assumes that there are no major changes in energy policy, the International Energy Agency (IEA) expects wind power as a percentage of total electricity generated globally to increase from 0.9 percent—the share in 2007—to 3.7 percent in 2020, and 4.5 percent in 2030. Under its 450 scenario, which assumes that countries take coordinated action to control greenhouse gas emissions, the share of wind increases to 5.1 percent in 2020 and 9.3 percent in 2030 [3].

The share of wind in Europe will be significantly higher than the world average. The IEA projects the share rising to 14.6 percent in 2030 in its reference scenario and to 20.1 percent in its 450 scenario for the European Union. The shares in Denmark and Spain are likely to be even higher than this (Figure 1).

Increasing Scale
The scale of wind farms is also increasing, with 50+ MW wind farms becoming more common. This is especially true for China, the U.S., and offshore installations. In addition, clustering of wind farms within a region will become more common (e.g., China). The growing scale of wind farms increases their impact at a local level, since they account for a larger share of total electricity production within a region. Wind turbines are also expected to become larger in size. The average wind turbine size increased to 1,599 kW in 2009. It is likely to increase further as operators install larger turbines in new locations and they replace existing wind turbines in Europe with new models.

Repowering of older, smaller wind turbines in mature European markets like Denmark, Spain, and Germany to increase output from high quality sites will accentuate this trend. Survey respondents generally agreed that repowering would gain importance in Europe. “Some wind parks are almost 10 years old, so we will see a lot of them being repowered in the next 10 years,” according to a European wind turbine builder. “This is currently occurring on a small scale in Denmark and Germany.”
 

“In Europe, land is restricted and many plants are aged,” a U.S. turbine manufacturer adds. “Therefore, they will have to be replaced.”

As wind’s share of total power generation rises, operators will require accurate wind power predictions to schedule the operation of other generation resources. This becomes important when wind energy’s share of installed capacity reaches 5 percent, and critical at 10 percent.

Focus on Efficiency
The top 15 wind farm operators accounted for 35 percent of total wind power capacity in 2008, versus 23 percent in 2003 [4]. Utilities will continue to increase their share of wind power capacity since they are cash rich and do not face the financial constraints that developers do.

The growing role of utilities in wind power is leading to a greater focus on efficiency. They are demanding reliable solutions and will focus more on energy efficiency, uptime and O&M cost management. Respondents to our research questions generally agreed that operators were increasing scale in wind power and would demand higher levels of operational efficiency. A representative of a European consulting firm laims that large energy suppliers will become the main operators of wind farms, which means that requirements in terms of quality and efficiency will become more demanding. A European wind turbine builder adds that “The more plants they operate, the more they are forced to address efficiency.”

These trends are likely to change the factors that wind farm operators manage and measure and, therefore, the attributes they look for in the wind turbines they purchase. There was general agreement among survey respondents that reliability was becoming more important in influencing the purchase decisions of operators. Operators want more output and there is a trend toward larger wind turbine systems. However, when breakdown or failure occurs, the larger the system the bigger the loss. In other words, reliability and uptime are extremely important. Or, according to a U.S. manufacturer, “Technical availability is more important, even if the price of the turbine is higher. Our contracts guarantee technical availability and actual performance. If these are not fulfilled, we provide rectification or compensation or both.”

Reliability is seen by survey respondents as especially important for offshore installations, since these can be difficult and expensive to access in the event of a failure. Condition monitoring systems—which usually monitor the gearbox, bearings, and generator—are likely to become more widely adopted in the future for a number of reasons.

First, the growing size of wind turbines exposes operators to greater loss of revenue in the event of failure, as well as the cost of repair. Operators are therefore more willing to invest in monitoring systems so they can detect potential problems early, carry out preventive maintenance, and minimize downtime. “The other important factor is the size of the turbine,” according to the operator of a wind farm in the U.S. “If I have a $2 million machine and the gearbox costs $500,000, then I definitely want to use condition monitoring.”

Second, operators feel that condition monitoring is more essential for offshore installations than for onshore because of poor accessibility and the high cost of maintenance. The growth of offshore wind farms will therefore lead to growth in condition monitoring. The main objective is to keep mean time between failures (MTBF) as low as possible, especially for offshore installations, since maintenance for offshore involves more cost and more risk. Condition monitoring is therefore essential, especially for offshore parks with limited access.

Third, operators see a greater need for conditioning monitoring for wind turbines located in harsh environments. The proportion of wind turbines in such locations is likely to grow over time. As a European wind farm operator explains, “If the turbine is located in a very windy environment, the probability of it breaking down is high, so we would install a condition monitoring system on a windy site.”

Fourth, insurance companies are increasingly requiring condition monitoring systems for offshore turbines and may offer favorable terms for onshore turbines with these. And finally, large utilities are more willing to invest in condition monitoring systems, since they have used these for other forms of power generation and understand the value they provide.

Focus on Pitch Control
Accurate forecasts and the ability to conform to the grid code will grow in importance as the share of wind power in electricity generation increases. Some of these requirements can be met by varying the output from the wind farm, which can be done relatively easily if the wind farm uses pitch-controlled wind turbines. The increasing interest in improving turbine efficiency in mature markets is also likely to stimulate interest in pitch systems, since these can help improve turbine operation through reduced friction, better wind utilization, or both.

The growing size of wind turbines will also increase the importance of pitch systems because of their role in managing loads, which reduces wear on components, minimizes downtime and increases lifetime. Individual pitch control, which dynamically adjusts the pitch of each blade in real time to optimize rotor loading, is also likely to be more widely adopted in the future. Survey respondents expressed strong interest in this new technology. A Japanese wind farm operator says that “More precise response to wind conditions would enhance life-time and revenue of the wind turbine, and is therefore desirable.”

Conclusions
Wind turbine builders will need to cost-effectively address the changing requirements of wind farm operators to remain competitive. The key issues wind turbine builders need to address include:

• Finding a cost-effective response to the need for greater reliability. Pitch control will be a key system that requires more attention;
• Catering to the likely increase in need for condition monitoring;
• Assisting wind farm operators to satisfy increasingly stringent grid code requirements.

Addressing these challenges and satisfying customer expectations is challenging. Wind turbine builders are unlikely to do it alone. Developing mutually beneficial relationships with subsystem suppliers who understand these requirements is a key to success. 

References:
1) World Market Update 2009. BTM Consult, March 2010
2) UK Offshore Wind-Charting the Right Course. BWEA
3) World Energy Outlook 2009. International Energy Agency
4) World Market Update 2009. BTM Consult, March 2010

Condition-based monitoring has been proven to provide significant cost savings in many industrial applications employing rotating equipment, including wind energy. It leads to high availability, low O&M costs, and a lower overall cost of energy. Condition monitoring systems take the surprise elements out of the actual operation by providing a view on what is actually happening inside, especially when it comes to large wind energy converters (WEC) or offshore turbines. By being able to accurately determine parts that are soon going to fail, maintenance can be planned much more effectively.

Eliminating Guesswork
Wind turbine reliability today still causes major financial headaches for turbine owners and operators. O&M costs for a single large onshore turbine have been estimated to be approximately $7/kW/year, whereas these costs are estimated to surge to about $40/kW/year for offshore turbines. In total these costs can represent about 10 percent of the total cost of energy for onshore turbines, and up to 35 percent for offshore turbines.

Failures can affect all of a wind turbine’s subsystems, with varying consequences and costs arising from downtime and repairs. In the case of most failures, damage accumulates slowly during operation. Continuous monitoring allows turbine operators to intervene at an early stage and minimize any further damage or lost availability.

Automated Measurements
Condition monitoring has been used for various rotating machines for years with great success. Only during the past decade, however, has there been a movement to automate this work in order to get regular, accurate vibration measurements that help operators understand whether their wind turbine components are in good condition or whether they are soon going to fail. This has helped operators schedule service in advance, eliminating total failures, keeping downtime to a minimum, and saving unnecessary costs.

Condition monitoring systems today are not able to say that a given component will fail for sure, nor can they prevent a failure. However, once a certain level of vibration is reached then it’s easy to predict when a component will fail. Operators can recognize vibration patterns, for example, when teeth are broken on a gearbox. Although they cannot eliminate the failure of the gearbox, they can proactively reduce the damage that the broken teeth cause to the gearbox and possibly other equipment. They can reduce the operational speed or take other measures to keep the turbine up and producing a lower amount of energy.

Early Warning
Most online condition monitoring systems with fault detection algorithms allow early warning of electrical and mechanical defects to eliminate the risk of complete component failure. Effects on auxiliary equipment can be prevented as well. This allows necessary maintenance activities to be scheduled well in advance, avoiding difficulties with bad weather or the lack of in-stock parts.

Condition monitoring can even show indications of extreme external weather conditions, such as icing or wave-induced tower oscillation in the case of offshore wind turbines. This saves in overall maintenance costs, reduces downtime, and significantly lengthens intervals between maintenance, as well as the overall lifetime of the WEC itself.

Preventing Downtime
The aim of any condition monitoring system is to understand as comprehensively as possible the status of a wind turbine at any given moment. It is not possible to predict the future, but it is possible to prevent many failures in advance with the support of condition monitoring systems.

When operating a wind turbine, three main maintenance strategies are most typical. These include corrective maintenance, scheduled maintenance, and condition-based maintenance. With corrective maintenance no action is taken until something breaks, which can be highly risky. Scheduled maintenance takes a more preventive approach by changing parts that could potentially be worn out. This strategy helps eliminate risks but is very costly, as parts that could still have considerable operational lifetime may be changed too frequently.

Condition-based monitoring using a condition monitoring system is the strategy that finds the optimum point between corrective and scheduled maintenance strategies. By having information from an advanced data mining algorithm that indicates just how bad a given component really is, operators can make a much more informed decision of whether that component can run until the next scheduled maintenance or not.

Integrated Monitoring
Condition monitoring generally works using a series of vibration sensors on the main bearings, gearboxes, generators, and other key components, sending vibration signals to a monitoring station which can be located miles away. The drivetrain monitors measure surface accelerations as an indication if any part is wearing too quickly.

Vibration sensors are the most common tools used to measure the wear and tear on components. For example, these sensors can be used to measure the effect of bearing or gear wear on the drivetrain. AMSC’s wtCMS™ condition monitoring system is unique in that the condition monitoring capabilities are fully integrated within the wind turbine control system. This gives essential information about turbine operation modes directly to the main controller. No additional sensors are required, which results in a reduced total number of components and increased reliability in comparison to similar, non-integrated monitoring systems (Figure 1).

The wtCMS system provides wind park operators with virtually real-time information regarding the condition of selected sub-systems and components. It also features an automatic measurement system with online analysis and alarm generation. Communication all happens to the AMSC wtSCADA™ supervisory control and data acquisition system, which results in accurate vibration trend visualization for onsite and remote users.

The vibration signals alone don’t tell much, but trained operators can pick up on problems by observing trends over several days, weeks, or months, and they can then use the expertise gathered over the years by AMSC to make intelligent decisions about any necessary repair work required.

Ample Automation
Besides being highly integrated, the wtCMS system also offers the highest degree of automation. This set of tools can monitor a large set of data automatically, which is another specific advantage for wind park operators because they can count on AMSC’s years of experience and knowledge database to bring them automatically analyzed data cheaper and more quickly.

AMSC’s wtCMS consists of a core CMS processor module that receives and processes measurement signals. A condition monitoring module enables input for up to nine analog signals from accelerometers, plus three additional channels. It also allows input of additional signals and variables from the main controller.

The wtCMS cabinet contains the heating element, cooling ventilator, and thermostats for environmental control, power supply, and electronics protection. Instrumentation includes general-purpose accelerometers, low frequency accelerometers, and accelerometer connection cables. The entire system operates reliably in an exceptionally wide temperature range from -45°C to +60°C.

Vibration Sources
Sources of vibration are numerous on a WEC. Failures can affect all of the sub-systems, but the downtime and repair costs of the failure rates differ dramatically. For example, the electrical system typically experiences a high rate of failures annually, but is relatively quick to repair. In comparison, the drivetrain does not fail often, but when it does downtime can be considerably long if the replacement components must be manufactured from scratch and shipped then to the wind park site (Figure 2). Other sources of vibration can be the tower oscillations, yaw movement, oil pumps, generator defects, the power converter, or the mechanical feedback coupling from line voltage variations (Figure 3).

Examples of just a few of the signal patterns captured automatically in the integrated wtCMS system indicate shaft unbalance, misalignment, mechanical looseness, damaged gear teeth, or wear in any bearing parts. In total, wtCMS is able to detect more than 30 different signal patterns, and the list is constantly growing.

Data Management
The AMSC wtCMS system offers ease of use for every wind turbine operator. Data can be accessed quickly to make well-informed decisions. All results from the wtCMS are communicated directly to the wtSCADA system (Figure 4). The fully integrated systems allow results visualization and comparison with overall WEC performance. A high degree of advanced automated analysis and intelligent software algorithms minimize the amount of effort needed to reach the right conclusion.

In addition, the advanced data-mining algorithms from AMSC enable accurate analysis and long-term trends. The single user interface for wtSCADA and wtCMS provide easy and automatic evaluation of results from the analysis and visualization. The benefits of an integrated condition monitoring system are clear: an early indication of system damage allows optimal performance, cost efficiency, and the highest reliability from each turbine. The wtCMS can even be configured to monitor specific frequencies of interest for each type of WEC. 

CMS Outlook
Development plans at AMSC are ambitious when it comes to creating the next generation of condition monitoring systems to further enhance the reliability and uptime of wind turbines. AMSC was one of the first companies to offer automated solutions for wind turbines. To date we have delivered more than 650 condition monitoring systems since launching them to the market as part of our portfolio in 2005. Our development plans are to continue to expand our range of monitoring tools for all critical parts of a WEC that are subject to deterioration. This would include the electrical components and blades, for example.

In the future, any kind of sensor could be used as part of the CMS strategy, and not just vibration-based sensor systems. Plans even call for developing a condition monitoring system that is self-contained. This means it could be run by trained personnel, but would not require specialists for the result interpretation. This next generation would use all of the competencies within AMSC to provide a system in an algorithm form that works automatically on all available data.

For example, the converter currently features its own diagnostics system that sends information to the turbine control regarding immediate failures. AMSC plans to use the converter’s diagnostic system to help detect failure as part of the CMS in the future. This would enable the converter to not only diagnose itself, but also all surrounding electrical systems as well. AMSC has the data needed to put this into an algorithm and turn the converter from a reactive component into a proactive one for greater reliability.

Summary
Again, the goal in the future is to continue to minimize the efforts needed from operators through the use of intelligent software algorithms and automated analysis. AMSC’s customers benefit from these continuous software improvements, and we’re now developing additional measurement systems for advanced monitoring that will be integrated into our existing platform. We want to do all we can to make sure wind turbines are reliable, and that they have the lowest possible risk of failure, minimized maintenance costs, and high availability.   

The growth of wind power and its sustainability depends on good return on investment. The goal everywhere is minimizing cost/kWh. Several strategies are emerging to attain this goal:

• Improve turbine efficiency;
• Access better wind conditions (high mean wind speed);
• Improve turbine output;
• Reduce cost of acquisition and construction;
• Reduce cost of maintenance.

Three of these strategies are answered directly by the implementation of greater hub height. All of them are influenced by optimal tower design. Overall, the economics show a shorter payback is obtainable by employing a larger tower.

The Challenges
Significant structural challenges are connected with implementing higher wind towers. Higher towers require more massive and costly foundations. Flexibility of the high tower must be addressed. It is more difficult to achieve the natural frequency required for proper turbine operation. These factors add significantly to the up-front engineering burden during the design stage.

Transportation of larger tower pieces poses a special problem. Most highways have a 4.5-m width limitation, and vehicles handling long sections find it difficult to negotiate the curving roads that commonly serve remote wind farm locations. Construction time for higher towers can be longer, lengthening return on investment by delaying the commencement of revenue bookings.

Design Strategies
Designers are turning to a variety of new technologies to minimize costs connected with detail design, tower components and foundations. One alternative is employing precast concrete. Hybrid precast concrete/steel towers are proving attractive for several reasons. They offer easy transport of manageably sized component pieces, rapid erection, high strength and stiffness, the prospect of reduced maintenance and an attractive lifetime cost. Some designers are using cast-in-place hybrid towers with concrete 60 m high and 8 m diam. at the base. Others are employing prefabricated concrete rings bolted together on-site and post tensioned using external tendons. Some precasters have a continuous taper tower design, where the diameter at ground level approximates that of steel.

With these conventional diameter designs, the challenges of tower frequency and load concentration at the foundation remain. Foundations are necessarily thick, massive, and expensive to construct.

The Atlas CTB
One design has emerged that addresses the challenges with foundation loading, complexity and cost challenges. This is the Tindall Atlas CTB™ Tower Base (Figure 1), a patent pending design featuring a flared precast concrete base section. The Atlas CTB comprises the lower 40m of hybrid tower system that serves as an elevated platform to support conventional steel monotowers 80m to 100m in height to achieve hub heights to 140 meters and designed for wind turbines from 1.5MW to 3MW and up.

The Atlas CTB truncated cone base assembly is composed of 12 or more stave units. The multiple precast concrete staves are erected, assembled and post-tensioned on site. The staves are captured by an outer precast ring system at the tower transition region. This concrete transition ring controls the stave tops and provides an uninterrupted transition from the truncated cone base to circular precast concrete tubular sections that form the upper part of the Atlas CTB and provide the support for the steel tower.

The vertical staves that form the truncated cone base are identical for each assembly (Figure 2); they are of a size that makes them easily transportable in pairs by rail (Figure 3, Figure 4). Most importantly, the modular, multiple stave design affords design simplicity and scalability to accommodate towers of various height and turbine size. With increasing numbers of staves, the base diameter increases to accommodate the loads imposed by greater heights and larger turbines.

Foundation Comparison
The larger footprint and lower foundation pressure characteristic of the wide Atlas CTB Tower Base does away with the massive, costly foundations required by narrow diameter base sections. The 0.75-m to 1-m-thick ring foundation (Figure 5) accommodates loading using 50-60 percent less concrete than other tall tower options.

With no high-mass concrete pours, this contractor friendly ring foundation poses no thermal cracking concerns during curing. The wide load distribution makes the simple ring foundation less sensitive to settlement throughout its service life and provides for improved dynamic performance that is less sensitive to the prevailing soil conditions.

Strength Development
Post-Tensioning. The composite transition region is vertically and circumferentially post-tensioned together, resulting in a bi-axially compressed condition. No tension is present under applied loads. Multiple pairs of tendons are passed down through the transition assembly, the stave beneath, the neighboring stave, then back up to its anchorage point (Figure 6). These looped tendons provide precompression (increased shear capacity) of the grouted stave-to-stave joints. Moreover, additional circumferential tendons are employed at multiple shear key locations situated lower in the conical tower base. Altogether, the combination of tendons gives the Atlas CTB Tower Base outstanding resistance to all anticipated bending, shear and torsional forces.

Strength Benefits. The post-tensioned stave/ring system produces a high tower frequency. The result is a tower with superior dynamic properties, thanks to the post-tensioning process and the natural dampening qualities of precast concrete.

Economic Advantages
The Atlas CTB Tower Base design concept promises significant economic advantages relative to installed cost, schedule compression, extended life cycle and reduced maintenance.
 

Site Work. The onsite construction process is significantly shorter with the Atlas CTB Tower Base design. The structure is composed of factory or site-manufactured pre-cast components. This repetitive, precast manufacturing process reduces field construction work and the concrete tower construction becomes principally erection instead of field construction. No welding and requisite testing are necessary. Apart from the foundation, no concrete forms have to be built. The large amounts of waste typical with construction sites are not generated. Pieces can be placed using standard cranes.

Maintenance Factors. Low maintenance over an anticipated 50-year service life enhances the economic attractiveness of the Atlas CTB Tower Base. There is no periodic tightening required since the primary connections are post-tensioned throughout the structure and at the foundation. The structure needs no painting over its lifetime. Given the rigidity and superior dynamic properties of the Atlas CTB, the service life of the turbine and related components should be extended.

The Atlas CTB Tower Base is designed as an answer to the specific challenges encountered in the need for higher unit power output in the wind farm, with enhanced return on investment and expanding the wind resource footprint by increasing hub heights and creating viable wind development in low wind speed regions. Furthermore, with its selectable number of staves for increased base diameters, the design is scalable to accommodate the loads presented by higher hub heights and the next generation of high-output turbines.