March 2012

Precision alignment is the process of making the two shafts co-linear under normal operating conditions. Properly aligned shafts are able to spin freely and not induce other unwanted forces to the system. These unwanted forces will damage and/or destroy bearings, seals, and couplings, and eventually the gearbox or generator. Precision alignment is recommended by most wind turbine manufacturers for optimal operation and reliability. Generator efficiency can also be affected by misalignment (angular and offset). The following questions—and answers—will help you to enhance the productivity and longevity of your turbine.

What needs to be aligned in a wind turbine?
The shafts of the gearbox and generator need to be aligned. The output bearing of the gearbox and the input bearing of the generator are most likely to suffer damage from misalignment.

When should I perform an alignment in a wind turbine?
An alignment should be performed upon commissioning. The nacelle has traveled a long way, probably by truck, so there is no guarantee that the factory alignment is still good. Anytime a gearbox or generator is replaced, an alignment should be performed. Because of the movement of the tower and other dynamic forces, a best practice is to re-check the alignment six months after the initial install and a minimum of every year after. Consult your turbine’s maintenance manual for recommendations.

What safety precautions are needed for wind turbine alignment?
Safety should be the very first consideration up tower. Check with the turbine manufacturer for specific safety requirements, but generally the brake should be engaged, dead bolts locked, blades pitched at 9:00, and the nacelle up against the wind. Alignment should not be tried in wind speeds ~over 8 m/s.

Does tower movement affect alignment measurements?
All movement can affect the laser measurements. Wind turbines present unique challenges because the gearbox and generator will not always move the same way at the same time. Use a laser measurement system that will allow you to increase the number of readings taken during the recording of each measurement. Five seconds per recording will provide more than enough data for accuracy.

I can only measure at the 6:00 position, not the 12:00 position—what now?
The 12:00 position can be replaced by the 6:00 position in the measurement process using a traditional 9:00-12:00-3:00 measurement method. When this is the case, the vertical movements will be accurate, but opposite (i.e. high will be low, and low will be high). Measuring units (laser/detector) that incorporate inclinometers will usually compensate for the different position automatically, providing accurate readings in the correct direction. Figure 1

What are the main differences between the three measurement method and limited (40° or 60°) measurement?
Many laser systems employ inclinometers for limited turn or sweep measurement. The inclinometers tell the system where the measuring units are in space so it can make the correct calculations based on the measurement position. Inclinometers will be affected by any movement in the nacelle. This movement can be seen on screen and will affect the measurement. Measurement filters (see question two) will help compensate for this movement. The three measurement method is accomplished by making three static measurements at 9:00, 12:00, and 3:00 when viewing the generator from the rear. This procedure will turn off the inclinometers reducing the effect. The measuring units will still “see” any generator/gearbox movement, but the inclinometers won’t add to the effect. The measurement filter can be used to minimize the effect.

Where should the measuring units be positioned during generator movement?
The most accurate readings when moving the generator will be achieved when the measuring units are in the same plane as the movement. When moving the gearbox horizontally, the measuring units should be in the 3:00 position. When moving vertically, the measuring units should be in the 12:00 position. If, for example, you are in the 2:00 position when moving horizontally, you will induce error into the readings and, thus, once you are within tolerance, you should re-measure and move again.

What if the brake is in the way at 9:00 and/or 6:00?
In many wind turbines access to 9:00 and 3:00 (and sometimes 12:00) may be prohibited by the brake calipers when using the traditional chain and bracket mounting fixtures. Magnetic fixtures can be used with mounting rods to position the measuring units inside the brake calipers on the brake disc. Care should be taken to ensure that the laser references the centerline of the shaft. The measuring units on either side need to be placed so as to reference their corresponding centerlines.

Should I align with the coupling in or out?
When performing an alignment with the coupling in, you will need to disengage the brake to rotate the shafts. All health and safety standards must be followed in this case. Without the coupling you can use the flange or shaft end to mount the units and turn without disengaging the brake. Figure 2

How do I decide on alignment tolerances?
Generally, alignment tolerances are determined by the RPM speed of the machine. The speed of the shaft is determined by the gearbox. Depending on the wind available, this speed can vary. The tolerances should be set for the highest allowable speed of the gearbox.

What is dynamic offset and why is it important?
Dynamic offset is caused by the movement of either machine under normal operating conditions. This movement can be caused when temperatures are different from one side of the system to the other. This is called thermal growth. Dynamic offset is caused in a wind turbine when the brake is released and the hub starts to turn. The weight of the system may cause the gearbox to shift upwards (in the vertical direction). When this happens, the shafts of the gearbox and generator are no longer in alignment.

How can I calculate dynamic offset in a wind turbine?
That should be a part of the turbine manufacturer’s specification. They know how much the turbine/gearbox will rise or move depending on dynamic forces in different situations. When using a laser alignment tool, make sure it includes a program for Thermal Growth (Dynamic) Compensation.

What is soft foot, and why is it important?
Soft foot is the condition where the machine stands on three feet instead of four. This of course means that the machine is standing unstable on the foundation. Soft foot must be corrected before alignment. A machine with a soft foot condition will continue to move during alignment, making a good job virtually impossible. Because of the generator and gearbox mounting base tolerances, soft foot may not be applicable in generator alignment. Should you find that alignment is extraordinarily difficult, check for soft foot as the culprit. Figure 3

What other tools will I need?
A good supply of clean shims, feeler gauges to help measure soft foot, micrometers can be used to measure the shim pack, a wire brush is used or cleaning foundations and shims. A good plan and a good tool kit will help prevent the need to go back down tower. When performing an alignment without the coupling, you will need a distance gauge to measure the distance between the flanges. Because many manufacturers are using a carbon fiber coupling that has a tight specification, the axial distance is critical when you align and move the generator.

What should I be concerned about with documentation?
Electronic documentation is the first quality check to ensure that techs have been trained properly and understand how to do alignments that are with in tolerance, ensuring good alignments every time. Good documentation will also help make subsequent jobs go more quickly and easily. O&M companies should be able to provide their customer with a document that shows what was done, who did it and that it was done properly and to tolerance. Documentation should be digital, recordable, and electronically storable. The document should include the final offset and angular misalignment for both the horizontal and vertical direction. Documentation should include the operator and the time and date the alignment performed. The documentation system should also have the ability to record and store any problems or obstacles noted by the technician for future reference. The document should be made available to the technician prior to performing a new alignment. 

As the North American wind energy market matures and turbines reach the end of their warranty period, condition-based maintenance (CBM) is generating a great deal of buzz. No matter where a turbine is found, or how long it’s been in operation, keeping your finger on the pulse of its internal workings will enhance productivity and increase active service life. Let’s begin with a general discussion of CBM techniques before turning to whether or not you’re a good candidate, and what you can expect as a return on your investment (ROI).

Existing Options
There are a number of commercial condition monitoring (CM) systems that provide diagnostic capabilities for wind turbine gearboxes. While useful for asset management and logistic support, the current products are deficient in two major areas. First, their ability to define a level of damage is immature (e.g., how bad is bad). Second, these systems have limited ability to predict when a component will go bad (e.g., the damage threshold).

The ability to define a damage threshold is complicated by the metric, or condition indicators (CI), used to identify component health. For all but shaft order 1 vibration—the vibration associated with 1 x the rotation rate of a shaft, which has a physical meaning—there are rarely defined limits. For example, there is no physical limit for gear CIs such as residual kurtosis, or any other CI. In general, when a CI value is “large” (e.g., residual kurtosis greater than 8) it is assumed that the gear is bad.

Additionally, for many components there is no single CI that works for all failure modes, making it difficult to compare relative failure across components. For bearings there are condition indicators for the inner race, outer race, and roller element. For gears, which have at least six different failure modes, there are numerous CIs that work for some failure modes, but not all. While side band modulation can detect a gear misalignment, it is ineffective for a soft tooth. Similarly, residual RMS (root mean square) work well for gear tooth pitting, but is not effective for an eccentric gear.

Learning from Aerospace
One technique that has been successfully used in aerospace CM systems is the Health Indicator (HI). The HI fuses “n” number of CIs into a single, common indicator of health. For example, the HI can range from 0 to 1, where:

• A nominal component is 0 to 0.5;
• A serviceable component ranges from 0.5 to 0.75;
• A component out of limit ranges from 0.75 to 1, and;
• A component with an HI greater than 1 indicates continued operation would result in collateral damage to other components in the gearbox.

The HI can be designed to have a constant false alarm rate. This is initially set by sampling nominal component data, then using statistical techniques to model the data, account for CI correlation and, ultimately, ensure that a when the HI is greater than 1 it is appropriate to do maintenance. This methodology is useful because, instead of asking the question “when is the component bad,” it asks the question “when is the component not good?” It enables operators to see when components are going bad and take proactive steps to avoid more costly damage.

The Value of Prognostics
The HI concept facilitates prognostics by enabling maintenance when a component is no longer good. Using the HI, the remaining useful life (RUL) of the component is then simply the estimated time until when the HI is 1. The operator knows that when the HI is 1, it is necessary to do maintenance (because the component is “not good”).

The prognostic is also dependent on a fault model. Damage of rotating equipment comes from fatigue, which is a function of torque. It’s no surprise that a wind turbine will fail sooner when operating under high loads (e.g., large torques). Paris’s Law relates the rate of change of damage (e.g., crack length) to cyclic loading. In most cases the parameters needed for Paris’s Law are calculated in the lab. NRG Systems has developed a patent-pending methodology to estimate the unknown parameters by reconstructing them from a state observer. Instead of crack length a surrogate for damage, the HI, is used. By integrating Paris’s Law it is possible to estimate the cycles, or time, remaining until the HI is 1. Figure 1

As a result, this prognostic (or measure of RUL) provides valuable information to operators about when components might go bad and under what conditions. This allows for real-time decision making, such as curtailment under high winds to extend the life of a component. Conversely, the RUL can be used to perform opportunistic maintenance. For example, if a maintenance crew were onsite to tend to more costly damage, they could do well-informed preventative maintenance during the same maintenance event, saving time and money down the road.

While these systems aren’t there quite yet, there’s much we could learn from other industries to continually lower the cost of operations and maintenance and strengthen the competitiveness of wind.

Considering ROI
Now that we understand the basics of CBM practices and technologies for wind turbines, what is the actual value? Why should you as an owner or operator of wind farms want to spend money on it? The answer is because there is a lot of evidence to suggest that condition-based maintenance can significantly lower operational costs. The question is how to quantify these cost savings.

NREL’s Gearbox Reliability Study, among other things, is striving to validate the performance of condition monitoring technologies. Sandia Laboratories has a similar technology program, focused on improving wind turbine performance and reliability to reduce the cost of energy. While NREL’s emphasis has been on the gearbox, Sandia has focused on monitoring blade structural loads. Both groups are helping to quantify the performance of CBM practices.

CBM Savings
But how are operational costs reduced? Condition monitoring does not change the design of the turbine, but it can give operators insight into the material condition of the monitored components. This insight can influence maintenance practices and logistics. For example, CBM can give early warning for an imminent generator or gearbox bearing failure. Replacement prior to failure can allow for an uptower repair ($50K) versus a downtower repair where the generator or gearbox must be dropped onsite, repaired, and reinstalled (new gearbox = $250K plus Crane Rental = $150K).

Or CBM can be used to conduct maintenance opportunistically. If the operator needs to bring the crane out for a downtower repair, knowing the condition of all the turbines in a wind farm would allow the operator to perform maintenance on any other questionable turbines at the same time. This could save the operator from bringing the crane out again for another downtower event. Additionally, there is the opportunity cost savings of being able to operate the turbine and generate revenue, instead of having a tower offline waiting for a crane. Figure 2

Workshop Examples
At a recent AWEA Project Performance & Reliability Workshop, a number of CBM cost-saving metrics were quoted. GE Wind Services announced plans to provide extended 10-year warranties, based in part on installing condition-based maintenance equipment on their 14,000+ fielded 1.5MW machines. This may be due to the reported 10-30 percent reduction in maintenance costs associated with monitored machines.

Other examples of reduction in maintenance costs were presented by Roland Kewitsch of Schenck USA. He gave the first example I have seen of what I would call “active preservation.” Based on their condition monitoring system, they found a gearbox in the process of failing. By curtailing production on this machine in high wind conditions, they were able to extend the life of the gearbox by eight months. This facilitated maintenance during the summer, when production is lower and impacts on revenue are less.

Is CBM for You?
The decision to install CBM is based on a positive return on investment. While most operators agree that CBM greatly reduces operational costs, many existing projects simply have not budgeted the $20K or so per turbine cost to buy and install a system. I would say that as CBM systems mature:

• Operators will learn how to use a CBM system better and the tangible return on investment will increase;
• Insurers and owners will insist on, or provide financial incentives to, install CBM systems prior to commissioning;
• The cost of a CBM system will drop, making the initial investment more attractive.

All of which suggests that there will be many more condition-based maintenance systems installed in the future. As Jean-Marie Robin of 01 dB-Metravib stated, “You simply wouldn’t not monitor a 1.5MW industrial machine when the incremental cost of changing a gearbox on a wind turbine can equal a year’s profits.” I would agree. 

The wind energy market has grown dramatically in recent years, with generating capacity in Germany alone increasing from about 1000MW in 2000 to more than 27,000MW in 2010 [1]. This growth has been accompanied by the use of ever-larger rotor blades [2]. The powers given in Figure 1 are not average power values but rather indicate the maximum size of the wind turbines.

Figure 2 shows the structure of modern rotor blades. A distinction is made between non-structural and structural bonded joints, with the majority of rotor blade manufacturers using rotor blade designs with a structurally bonded joint between the blade shells with integrated spar caps and the shear web, resulting in an “I-beam section.”

The second design variant has no structural load carrying bond lines. An integral manufactured composite structure takes the loads and the bond line has only to transfer the aerodynamical loads in this structure. The mechanical requirements for an adhesive joint in the “I-beam” construction tend to be higher, as failure of the bonded joint would have a significant effect upon the structural integrity of the blade.

Methods for Testing Components
Rotor blades typically require certification in accordance with the current IEC standard 61400 and related regulations; e.g. Germanischer Lloyd [3]. The certification is based on static and dynamic material tests, and a full-scale static blade test. Actual stresses in the bond-line—due to stress concentrations and manufacturing variability, for example—are not directly measured in the full-scale blade test. Without a direct measurement, a large safety factor is assumed to minimize risks in the structural bondlines. For example, Germanischer Lloyd (GL) [3] allows maximum shear loads of 7 N/ mm2 for static loads, yet typical adhesives attain shear strengths of 40 N/mm2 to 50 N/mm2. Over 1,000,000 cycles of simulated dynamic fatigue loading, GL specifies a shear stress below 1N/mm2.

Rotor blade manufacturers, material suppliers, and European research organizations have recognized that there is room between these two extremes for enhancing our understanding of materials and structures. This would allow the reliability of rotor blades to be increased, further optimization of blade designs, and/or reductions in material use. Figure 4 compares the advantages and disadvantages of the test scales shown in Figure 3. The ability to determine SN- lines for structures and study the effect of production faults, material variations, and design adaptations have enormous potential for improving the reliability of bonded joints for rotor blades.

Even though rotor blades are amongst the largest integral fiber composite components that are produced, there are distinct regions of the structure and design that have close similarity. These are, for example: a) rotor blade end section; b) leading edge; c) flange-web design (ply drops in the flanges, flange-web bonded joints); d) sandwich structures, and; e) blade connections (the only blade components currently tested in component tests).

Besides these regions of rotor blades, some of which have to bear very high loads, there are geometrically complex areas of the blade root that are often subject to relatively small loads (Figure 5). Due to the load bearing function of the flange-web joint and the instances of failure and damage observed in operation, this region was chosen in a project between Henkel AG & Co. KgaA, Fraunhofer IWES, as well as in the UpWind project.

Stresses on Bonded Joints
As part of the OPTIMAT project, T. Philippidis published a report [5] about the loads on a 35 m rotor blade and determined the loads using an experimentally validated FE model. Using this model it is possible to estimate the stresses on the bonded blade joint. For a flange-web joint width between 100 mm and 250 mm a shear stress between 0.825 N/mm2 and 0.33 N/mm2 is calculated for the blade radius 5 m. The corresponding axial strain is 0.25 percent. Axial stress thus dominates the load on a bonded joint (Figure 6).

Based on these loads, Henkel and Fraunhofer IWES together developed a representative test specimen whose structure is in principle similar to a rotor blade (Figure 6) and induces comparable mechanical stress in the adhesive. One of the test specimen geometries was also used in the EU funded UpWind project [3] because this gave a more realistic state of stress in the adhesive than with the UpWind design used in the project (for example, see [4]).

GEC and UpWind Beams
The Henkel GEC beam and Henkel UpWind beam shown in Figure 7 have a similar geometric cross-section to a classic I-section, as used today in common blade designs. The beams are supported and loaded by steel bolts that are press fitted and bonded into the beams. In order for the beam loads to be borne by the bolts, these regions are reinforced. The calculated loads on the Henkel UpWind beam are shown in Figure 8. To take account of any differences in blade design and to guarantee conservative results a “safety factor” of two was chosen on the shear stress. A similar load condition was attained in the Henkel GEC beam by varying the flange width.

Macroplast UK 1340 and Macroplast UK 1351 polyurethane structural adhesives were used for the Henkel GEC (Figure 7, left) and Henkel UpWind beams. The two Henkel products do not have glass fillers, and are claimed to offer substantial production time saving due to faster cure. Macroplast UK 1351 is a faster-curing system used for bonding components, smaller blades, and repairs. Macroplast UK 1340 has longer open time and higher sag resistance for utility scale blade bonding. In addition, Momentive Epikote Resin MGS Paste 135 G3 glass-filled epoxy adhesive was used as a benchmark reference system for the Henkel UpWind beams [4].

FE Beam Simulation
The measurement of local strain using the beam model is possible with the help of strain gauges or optical methods. Spatially resolved analysis of the load on the adhesive was carried out using computer simulation (Figure 9).

Special modeling tools are then used to simulate the mechanical behavior of fiber composite materials. These are able to effectively show the anisotropic behavior of the individual layers. Material parameters for the laminates are available as validated empirical values or measured values. Such values have been published by Sayer et al. [7]. The mechanical characterization of a structural adhesive requires stress-strain curves determined with pure tensile and shear loads.

The pure load condition for tensile is achieved in accordance with EN ISO 527-2. The pure load condition for shear is achieved using hollow cylinders under torsional loads (DIN EN 14869-1). In combination with suitable experimental boundary conditions, a model can be developed to determine stress and strain in a three-dimensional subcomponent model. The result is an economic assessment tool for the evaluation of different adhesives and bond-line geometries.

Cyclic Tests
In total, six cyclic progressive tests were performed using the Henkel Macroplast UK1340 adhesive: three on the Henkel GEC beam, and three on the Henkel UpWind beam. A further test was carried out using Macroplast UK1351 adhesive. Figure 10 (the maximum axial stress in the adhesive is plotted) shows that the Wöhler exponent κ lies in the region of the standard value of Germanischer Lloyd [3] for a unidirectional laminate.

Figure 11 shows the test results for the Henkel UpWind beam and the Momentive adhesive from the UpWind project (the maximum axial stress in the adhesive is once again plotted here). The Wöhler exponent κ is higher; however the ultimate strength is lower. Differences in the mixing and dispensing process (laboratory methods versus industrial machine mixing) complicate a conclusion about the relative performance of the tested adhesives. Different beam variations were tested with the Momentive adhesive. For example different joint widths were considered and also a thin biaxial stitched glass fabric (840 g/m2) was laminated across the bonded joint. This leads to a slight reduction in the shear stress in the bonded joint (ca. 25 percent for linear calculation).

Significant stress changes in the bonded joint are therefore not expected. On changing the shear stress in the adhesive by varying the width of the bonded joint there were only small changes in the service life (76 percent and 145 percent of the shear stress of the reference shear stress). By laminating over the open part of the bonded joint there was a clear increase in the service life, although the influence on the shear loading of the bond line was comparable to the width increase.
Both the Henkel adhesives and also the Momentive adhesive showed a similar failure behavior (performance should not be compared due to differences in mixing and dispersing technology). First of all cracks formed in the bonded joint, induced by the high axial stress.

These grew across the entire height of the bonded joint and ended at the flange and web laminate. Cracks spread from there to the interface between the laminate and adhesive and led to failure of the structure (Figure 12). It was observed that the density of the axial cracks in the Momentive adhesive was higher than in the Henkel Macroplast adhesive. This could be attributed to normal variations seen in the mixing process.

Summary
Component tests are a worthwhile addition to tests on material and full scale rotor blades level that are currently widely used in the wind power industry. The Henkel UpWind beam design leads to stresses in the adhesive of the flange-web joint that is similar to that in rotor blades. The failure behavior of the adhesives was similar. A pure shear stress, under the tested conditions, had no noteworthy effect on the service lives of the test specimens. Cover laminate for the bonded joint led to a significant increase in the service life. As subcomponent beam tests could play a leading role in the future development of adhesives for wind turbines, the objective is now to establish this economic method to assess the performance of adhesives as a standard test for the wind power industry.  

References:
1) C. Enders; Wind Energy use in Germany; DEWI Magazin, 31th of December 2010
2) J. P. Molly, Zukunft der Windenergie weltweit DEWI GmbH, Erneuerbare Großprojekte Wind und Wasser, Stif- tung Energie & Klimaschutz Baden- Württemberg, 29th of April 2009, Stuttgart (Germany)
3) Germanischer Lloyd, Richtlinien für die Zertifizierung von Windenergieanlagen, edition 2003
4) UpWind-Project; www.upwind.eu; 2011
5) E. Stammes, F. Sayer: UpWind WP3 beam test comparison all partners; UpWind-Document
6) T. P. Philippidis: Quantification of Complex Stress State Effect on Blade Design; Optimat-Blade Report: OB_ TG2_R032_ rev. 000; www.kc-wmc.nl; August 2010
7) F. Sayer et al.; Development of a new Test Methodology for Adhesive Joints in the Wind Industry; EWEC 2010 in Warsaw

Acknowledgement
The participation of Fraunhofer IWES in the EU UpWind project was made possible by the HookUp2Wind research project, which was funded by the BMU (Federal Ministry for the Environment, Nature Conservation and Nuclear safety).

Geotechnical surveys physically sample or test the seabed characteristics so developers can ensure the optimal placement of offshore wind farm turbine, substation, and cabling infrastructure. By the time a project requires geotechnical data it has already traversed several stages, including desktop, baseline, environmental, marine mammal observation, hydrographic, and geophysical studies, so stakeholders have significant investments tied up in their leaseholds. As the tasks that comprise geotechnical studies represent the largest single investment in the site characterization process, they require extensive experience in marine operations and equipment, particularly as projects move from the shallow-water regions that comprise the bulk of offshore farms around the world to increasingly deeper waters.

Though marine wind projects in North America are moving forward, the United States still doesn’t have a production turbine in the water and has yet to institute a federal Renewable Energy Standard (RES) or the long-term production tax credits that will encourage the level of investment needed to drive the sector. On the regulatory front, BOEM and other agency regulations are works in progress, but agencies have stated their intentions to collaborate and use existing multidiscipline data to streamline permitting guidelines where applicable. When these financial and regulatory issues are eventually addressed, the U.S. will need to play catch-up.

The good news is that U.S. developers can turn to offshore geotechnical work in Europe and elsewhere to inform their own wind energy efforts. To speed the tempo needed to stay competitive on an international scale and reap the economic and environmental benefits that offshore wind promises, North American contractors can incorporate the hard-won lessons learned collecting geotechnical data for overseas offshore wind projects, as well as from oil and gas projects worldwide. The offshore O&G industry has spent decades incrementally improving geotechnical techniques to develop optimum specifications and equipment, which have been further tested and modified over the last several years for offshore wind installations off Europe. Though the vast majority of wind projects has thus far been in shallower waters, deepwater O&G specs and continuing lessons from overseas wind farm work can serve as very valuable tools for projects progressing off the East Coast, in the Great Lakes, and in the Gulf of Mexico.

These synergies were a key driver behind United Kingdom-based Gardline Ltd.’s acquisition of New Jersey-based Alpine Ocean Seismic Survey in 2009. Working in the offshore wind sector for more than a decade, Gardline has completed more than 140 renewables projects and is currently involved with five of the U.K.’s nine Round Three efforts. Alpine, working alongside Gardline Geosciences, adds the complex geotechnical piece to its existing portfolio of marine services to offer one-stop, turnkey data collection solutions for North America’s burgeoning offshore wind sector, giving the company access to the kind of equipment and experience needed to tackle geotechnical work in nearshore, transitional depths, and deepwater projects. With expertise gained from more than 50 years in marine projects, Alpine brings localized knowledge of the U.S. market and regulations, long-standing associations with state and federal agencies, and relationships with other domestic contractors that simplify project coordination.

Geophysical Informs Geotechnical
The efficiency and quality of a geotechnical campaign is closely tied to the success of the geophysical data collection operation that precedes it. The high-resolution geophysical (HRG) studies that acoustically map seabed features—seafloor topography, bathymetry, stratigraphy, archaeological elements, hazards, and other characteristics—enable the design of a geotechnical study that targets locations that will yield the most representative physical samples and in-situ measurements needed to determine the viability of proposed infrastructure sites. Geotechnical studies examine soil structure and other attributes that, combined with geophysical findings, create the geological model needed to establish engineering parameters for turbine foundations, substations, cable burial trenches, and other infrastructure.

According to estimates, geophysical, geological, and geotechnical studies comprise on average more than three quarters of the total cost of site characterization investigations. With comprehensive geophysical data gathered and analyzed, geotechnical contractors can—where regulations allow—reduce the number of points that have to be physically sampled or drilled, thereby trimming the cost and time of their effort. Further, with a single experienced marine contractor handling both disciplines, developers can alleviate concerns that a geotechnical outfit working independently of the geophysical provider will perform unnecessary work. Beyond getting a geotechnical design that best complements the geophysical data collected, stakeholders also ensure they get smooth transitions between survey phases, accountability, and a single point of coordination, keeping costs and timelines more reasonable than those sometimes seen when multiple contractors are involved (Figure 1).

In the U.K., for example, offshore wind farm regulations allow contractors to rely more on less-costly geophysical surveys to target optimum—rather than overly redundant—test sites for their geotechnical studies. U.K. guidelines regulating geotechnical designs are geology- and consultant-dependent, an approach that can streamline the extensive amount of work required. Based on their geophysical data analysis, for example, North Sea contractors can reduce the number of conventional soil boring samples they take by relying more heavily on seabed cone penetration testing (CPT), which can be less expensive and provide better coverage than conventional drilling. As agencies elsewhere see satisfactory outcomes from an approach that gives more credence to comprehensive geophysical campaigns, they’re more likely to consolidate their own regulations to more efficiently get critical infrastructure in the water and operational.

In the U.S., BOEM guidelines currently require CPT and soil borings for each turbine foundation pile and substation. However, as projects progress around the world, geosciences contractors may be able to leverage successful outcomes from overseas efforts to work with BOEM to ease regulations as agencies have in the U.K. With such evidence, BOEM may deem its blanket regulations for this kind of activity to be excessive, and allow U.S. contractors to leverage vetted geophysical data to reduce the number of locations where they must supplement CPT with standard soil borings. In the mid-Atlantic region of the East Coast’s Outer Continental Shelf (OCS), for example, the geology generally isn’t highly varied, which can obviate the need to conduct conventional borings in every location, reducing survey time, costs, and permitting cycles.

Equipment Selection Suits the Project
The equipment used for a marine geotechnical campaign depends on water depths and ground conditions, as well as the region’s regulatory requirements, making ready access to a depth and breadth of tools that span a wide range of project types a key differentiator. Geotechnical specialists should be capable of deploying the following technologies:

Cone penetration testing (CPT) units: CPTs are versatile devices used for in-situ soil tests, typically the first step in a geotechnical campaign. CPTs capture data continuously or at specified depths on such geotechnical parameters as soil density, shear strength, and consolidation rates. During penetration, the forces on the cone and the unit’s friction sleeve and pore pressure transducers are measured and transmitted to topside data-logging software. For work in North American waters, contractors should be able to choose from a number of units designed for specific applications and penetration depths, ranging from lightweight mini-CPTs (with penetration up to 10m) to such equipment as Wheeldrive ROSON units (with penetrations up to 40m), Neptune 3000 and 5000 units (10m and 20m, respectively), and wireline CPTs, which enable downhole tests to be performed and guarantee CPT data to the final depth of the borehole.

CPTs provide more accurate, calibrated, and fully traceable in-situ information on the geotechnical properties of the soil than standard penetration tests (SPTs), which are more commonly used for land projects and involve counting how many blows (blow counts) of a standardized weight it takes the drill string to penetrate a set distance. Data captured through CPTs can be analyzed onboard in realtime, unlike physical samples that require offshore or onshore laboratory testing.

Seabed samplers: For seabed sampling for such infrastructure studies as cable route surveys, geotechnical contractors utilize a range of samplers. A provider should have at its disposal:

• High-power and specialty vibrocorers;
• Hydraulic clamshell grabs for bulk samples;
• Box corers for minimal impact sampling of surface soils.

Heave compensation drill rigs: For deeper-water wind farm projects, geotechnical data acquisition requires the use of heave compensated drilling rigs. These systems provide three-meter heave compensation, allowing drilling to continue undisturbed in rougher marine conditions where waves that lift the drilling vessel likewise raise a stationary drill, potentially ruining the sample or damaging the rig. They can be permanently installed on dedicated drill vessels, and are also available in containerized packages so they can be used on third-party vessels, where ideally, they are operated through a moon pool, or if necessary, through side-mount installation.

For offshore renewables projects, heave compensation rigs should be capable of drilling in water depths up to 1,000 meters, enabling them to be deployed for drilling, sampling, and downhole CPT efforts for a range of wind farm sites. These systems can also perform downhole geophysics studies—performed in completed boreholes to calculate additional important attributes related to depth—and can incorporate onboard data and analysis capabilities. For leaseholds in deeper waters, developers should consider contractors with these rigs in their arsenal, ensuring the extensive experience required to deploy them for various applications.

Vessel Versatility
As the majority of the wind farm work in the North Sea and in U.S. waters to date has been nearshore, geotechnical contractors have relied to a great extent on smaller niche and jack-up vessels, often opting to mount land-based truck-mounted rigs for drilling purposes. Under the right conditions and supervision, this combination is effective and cost-efficient, but it is limited in application.

On the vessel side, jack-ups revealed their limitations for wind farm geotechnical site investigations in early North Sea efforts. Testing for wind turbine sites naturally means working in windy areas, and unlike specialized vessels, stationary platforms aren’t optimized to handle the resulting marine conditions. Further, research teams with stationary jack-ups can only test in the area within range of the vessel before mobilizing to a new location, a more arduous process with jack-ups than in moving a dynamic positioning (DP) or anchored vessel. This remobilization process doesn’t easily accommodate the need to work in the tight timeframes when weather conditions are suitable, a leading factor dictating offshore data collection. In addition, smaller jack-ups don’t have adequate living accommodations, so personnel must be continually transported from ship to shore and back.

On the equipment side of the equation, there are also HSE (health, safety, and environment) issues to consider when using land-based drilling equipment on jack-ups. Relatively few drilling operators whose expertise is in land-based projects have the experience required to conduct drilling safely, effectively, and efficiently offshore. Further, the effectiveness of this vessel/drill rig combination is limited to shallower waters under calm conditions. For projects farther offshore, contractors must rely on marine options designed for harsher conditions, both for effective operations and safety reasons. Expertise in these challenging environments is important as projects progress in the Northeast, where most of the geotechnical drilling to date has been on inland waterways rather than offshore, where conditions are far less predictable.

In deeper waters, a heave compensated rig is the superior drill choice. The point where contractors should consider moving to this kind of rig is when water depths reach 60 to 70 feet. Some jack-ups, especially those available on the East Coast of the U.S., aren’t large enough to perform safely or adequately beyond these depths. Although larger jack-ups working in the Gulf of Mexico can operate in deeper waters, the costs of mobilization from the Gulf to the Northeast, coupled with the higher costs of leasing a bigger vessel, make it more effective and equally economical to use heave compensation equipment on a properly configured drill ship.

Though the bulk of U.S. offshore wind development to date has largely been in water depths ranging from less than 60 to around 160 feet, it’s just a matter of time before efforts move to deeper areas. If developers are planning a small test turbine array in shallow water, heave compensated equipment isn’t necessary, but if they’re intending to place hundreds of turbines in deeper waters, it’s much more effective to choose a heave compensated system mounted on a dedicated DP vessel to take advantage of strong seakeeping performance, onboard real-time data analysis capabilities, dry and wet laboratories for sample processing, and accommodations for extended periods at sea.

Depending on project parameters, heave compensated drilling rigs can be permanently mounted on specialized vessels or temporarily installed on multi-role vessels and barges. In the U.S. it’s important for both project suitability and local stakeholder interests—given the strong business emphasis on using local providers—that companies have geotechnical equipment that can be mounted on third-party barges and other vessels to employ local companies as part of a project.

When developers contract with a geotechnical services provider whose expertise is in offshore operations, they ensure they get personnel with experience sampling and drilling in a dynamic marine environment, who understand the risks, safety requirements, and specific data attributes needed to design and conduct acquisition efforts. With this approach, even if the project is far-reaching and calls for using land-based equipment on jack-ups nearshore and marine-optimized technologies and DP vessels in deeper water, the marine contractor can coordinate the entire operation and ensure quality control throughout the project. The geotechnical campaign is consequently much more likely to be completed successfully without encountering the kinds of problems that can bring a project to a costly and damaging halt. 

Wind energy is one of the world’s fastest-growing sources of energy. According to a 2011 report provided by the World Wind Energy Association, China, the United States, Germany, Spain, and India were the top five wind power markets by total capacity in 2010. When it comes to producing wind turbine components as efficiently and inexpensively as some of these countries, however, the United States tends to lag behind. Why is that, and what can be done?

Embracing Efficiency
Europe, for example, is capable of producing wind turbine components at much more affordable levels than the United States. The Europeans follow the mindset that they will invest in the right equipment to make these components as quickly and cost effectively as possible. In fact, they use large, high-powered machines to achieve fast metal removal rates and shorter cycle times.

The United States has not been able to mimic Europe’s efficient machining practices because not enough incentive funding exists for wind turbine manufacturers to want to move forward in improving their processes. For example, the oil and gas industry receives higher tax incentives than wind power. Furthermore, wind power manufacturers must renew their federal subsidies on an annual basis, making it difficult for them to gauge how stable the wind industry is going to be from one year to the next. Figure 1

The current reality in the United States is that several wind turbine manufacturers have evolved from automotive-type companies who are continuing to utilize their existing machine tool equipment to produce turbine components. These machines are older, slower, and less powerful than what Europe is using to machine their parts. To put it in perspective, Europeans can produce a wind turbine rotor hub in four to five hours, whereas it takes a U.S. manufacturer eight or more hours. All the while, OEMs are putting a lot of pressure on American manufacturers to reduce manufacturing costs.

Materials Matter
On a brighter note, some U.S. manufacturers are contemplating the use of lighter, stronger materials such as carbon fiber, compacted graphite iron (CGI), aluminum, and titanium alloy to lower the cost of industrial wind turbines. After all, the heavier the wind turbine, the more costly it is to produce, transport, and install.

The larger OEMs, in particular, are actively looking into materials with improved strength-to-weight ratio for wind turbines out on the ocean. Offshore turbines tend to be a lot larger than those on land, and installation is a lot more difficult and expensive. Therefore, being able to reduce their weight is a big deal. Should this become a successful trend, more manufacturers of land wind turbines will be apt to follow suit.

Consider the land-based 5MW wind turbine of today, which weighs more than 1.1 million pounds, with the nacelle, rotor hub, and blades accounting for most of the weight. If manufacturers started making these three main wind turbine components out of lighter material, they could probably cut the weight of the 5MW in half. As a result, the tower portion—which typically weighs several hundred tons—can undergo a considerable weight reduction because it would only have to support approximately 551,000 pounds instead of over a million. Furthermore, the wind turbine’s foundation could also see a decrease in size.

Today, wind turbine blades are typically made of fiberglass and assembled by hand. If manufacturers transitioned over to carbon fiber materials and invested in a CNC process, the weight of the blades would decrease by about 70 percent and their strength and consistency levels would improve overall. However, carbon fiber costs more: a fact that deserves attention when looking at the overall savings of building a complete wind turbine. It’s also important to note that manufacturers can’t reduce the size of the blades to save money because the area of the blades that “catches” the wind must remain the same size.

Rotor hubs are currently made of ductile cast iron. However, a better alternative exists with compacted graphite iron because of its improved strength-to-weight ratio. It features mechanical and physical properties between those of ductile and gray irons. CGI’s graphite particles are short and thick, resulting in stronger adhesion between the graphite and iron for greater tensile strength. Such properties make CGI more resilient to mechanical and chemical fatigue and are highly favored in applications ranging from high-speed rail train disc brakes to engine blocks. And because of its benefits, several wind turbine manufacturers are starting to have rotor hub test pieces made out of CGI.

Attractive Alloys
Aluminum is another material the wind turbine industry is considering for manufacturing rotor hubs because it is approximately ⅓ the weight of steel and provides corrosion resistance. Titanium alloy is another choice that offers excellent strength-to-weight ratio, but it comes at a higher price. Therefore, when looking to reduce rotor hub weight through CGI, aluminum or titanium alloy, manufacturers need to evaluate which material will offer the best overall weight, strength and price ratio for their operations. Figure 2

Although manufacturers can reduce the actual size of the rotor hub to eliminate weight, the hub still has to be able to withstand strong wind forces and successfully transfer the torque to the mainshaft/gearbox or generator on a direct drive system. Therefore, choosing a lighter, stronger material to produce the rotor hub is more likely the best option in terms of weight reduction.
When looking to reduce the weight of ancillary wind turbine components such as bearings, the bearing house, shaft, and gearbox, manufacturers need to go through the same weight, strength, and price ration routine to see what material is going to reap the best benefits for their businesses.

Beyond the wind turbine itself, when manufacturers reduce the weight of turbine components, they are also lessening their manufacturing efforts. For example, the size of the equipment they use—from machines to forklifts—doesn’t have to be as large to accommodate such hefty parts.

Cutting Edges
There are, however, some challenges when transitioning over to some of the lighter, stronger materials. For example, if a shop is currently machining rotor hubs made of ductile cast iron and wants to start using aluminum, the shop would need to update its tooling, reprogram its parts for different cutting techniques, and adjust its speeds and feeds for the tooling. Another challenge is the hazardous dust that comes with machining carbon fiber materials. Shops would need to have special equipment to keep the carbon fiber particles from contaminating the air.

But for those wind component manufacturers ready to start a weight-loss trend, Seco has extensive experience in working with carbon fiber, compacted graphite iron, aluminum, and titanium alloy. After all, the company’s cutting tools have long played a role in machining these weight-reducing materials within the aerospace and power generation markets.

Such cutting tools include Seco’s Turbo square shoulder mill. Available in four different insert sizes, the Turbo offers improved tool life and precision by optimizing cutting properties that reduce heat generation and cutting forces. Another ideal milling solution is the company’s Double Octomill™ that features 16 cutting edges and provides excellent cost effectiveness. It handles roughing and finishing by accurately positioning its inserts inside the cutter body pockets using high-speed steel location pins that offer easy and secure indexing. The Double Octomill also provides extremely fast metal removal rates and can greatly reduce cycle times when machining a wind turbine component.

Additionally, some of Seco’s cutting geometries are free cutting, which is important because they increase stability in long-reach applications, which are common in wind turbine component manufacturing.

Steady Systems
When tackling long-reach applications, Seco’s patented Steadyline™ vibration dampening system, made of high tensile steel, improves the dynamic rigidity of milling assemblies. In a typical long overhang milling operation, the Steadyline provides increased tool life as well as performs twice as fast as a classic system. Steadyline shell mill holders are available in a wide range of types and sizes, including cylindrical, conically strengthened, HSK, Seco-Capto, DIN, BT, and CAT.

Other relevant Seco tools for the wind power industry include a complete range of drilling, reaming, and boring tools such as Feedmax™ solid carbide drills and Perfomax® indexable insert drills, X-fix™ large diameter, multi-tooth reamers, and the Graflex® boring bar system of various lengths and diameters. In fact, with its wide variety of holemaking tools Seco offers the widest boring range on the market, covering the entire 0.12” to 84.843” diameter range with complete precision.

While Seco can optimize most machining operations with its comprehensive tooling portfolio, the company can also provide turbine manufacturers with custom tooling solutions that maximize their unique wind power operations.

Production Partner
For those just getting started in the wind turbine component industry, Seco offers a Component Engineering Tooling (CET) program that takes a comprehensive approach to process design and improvement that ensures the best possible operational results. As part of the program, the CET team—which consists of expert engineers—conducts technology evaluations to ensure a company’s manufacturing process incorporates the most suitable equipment. Functional testing can also take place inside one of Seco labs to prove out a machining solution prior to implementation. The Seco team then executes an integration plan of the selected equipment, including technical support and training, implementation of the system, run-off tests, and documentation of potential savings. Several wind customers have taken advantage of this program and managed to save time and money before any parts hit the manufacturing floor.

Current wind turbine component manufacturers looking to improve their productivity and profitability via their existing operations are encouraged to take advantage of Seco’s Productivity and Cost Analysis (PCA), which represents a total evaluation of a manufacturing process using Seco’s unique software program. The PCA begins with Seco working closely with a manufacturer’s employees to understand and benchmark the company’s current efforts. The software program allows Seco to verify and gain a baseline of any type of component. In fact, the software goes step-by-step with each tool and process as a way to put together a “snapshot” of an entire manufacturing process.

Seco then draws upon the expertise of its global resources to identify, investigate and prove out recommendations for reducing costs, increasing throughput and maximizing efficiency. Typical results from a fully executed PCA include cost reductions of up to 30 percent and productivity increases of up to 40 percent. Manufacturers can also tailor a PCA to meet a specific need, from assessing a single machining application to evaluating workflow throughout the company’s entire facility.

Summary
Wind is among the most affordable renewable energy resource on the planet. However, in order to cost-effectively cultivate more wind farms in the United States, a trend toward using more efficient equipment and weight-reducing materials in the development of wind turbine components must first occur. Manufacturers should know they are not alone in such a movement, however, because Seco is ready to help them pave the way with its optimized machining solutions.