By Amin Almasi, Rotating Machine Consultant

The analytical and testing baseline information is necessary for comparing a power generation machine's previous and present conditions when a malfunction occurs. It can also be used after the problem is fixed to verify the validity of the correction. Most of the baseline data and operational requirements as well as a comprehensive prediction profile of power generation machine should be provided by the machine manufacturer. It is important that users control processes and tests to make sure correct and complete data are provided. Also, a suitable monitoring system – particularly details of required sensors and recommendation of sensor locations – should be included as a part of the design for all rotating machines.

While fulfilling the main function of the rotating machines in power plants, such as gas turbines, steam turbines, engines, and generators, the rotors are usually most prone to mechanical vibrations and are the principal source of vibration. Most malfunctions originate from direct transfer of rotor rotational energy into vibrational energy of various modes. The lateral modes of the rotor are of the highest concern. Rotor vibrations are eventually transmitted to pedestals, casing and foundation. It is evident that measuring vibrations "at the source" becomes vital for correct evaluation of the machine health. That is why the generally accepted practice is to utilize two non-contacting displacement transducers installed in orthogonal XY configuration on or near each radial bearing to measure lateral vibrations and static centerline position of the rotor relative to the mounting fixture.

Vibration measurement on pedestal or casing by using velocity pickups or accelerometers provides indirect information about the vibration source. These casing vibration readings depend on the mechanical transmissibility of elements between the source and transducers. Transducers that measure vibration of casing are useful to identify certain malfunctions and problems. But these transducers are not able to measure shaft centerline position, do not indicate the direction of shaft orbiting, do not provide information on the rotor mode shape and their sensitivity is relatively poor, particularly in low frequency range. Casing vibration measurements are generally recommended as complementary sources of dynamic data, in addition of rotor vibration sensors.

In addition to XY radial transducers, it is extremely useful, and usually mandatory, to install two axially oriented non-contacting proximity transducers in many power generating trains. These probes are used to monitor and alert about machine thrust problems and are often tied to automatic trip when a dangerous condition exists.

Another important transducer is a phase angle reference transducer (the key-phasor transducer). It is used to monitor rotating speed and phase of rotor (synchronous) response as well as phases of other vibration components. The key-phasor ties the rotor vibration data to its rotational motion. The information provided is extremely valuable for condition monitoring and diagnosing various machine malfunctions. The absolute phase on a vibration signal is measured as a phase "lag" from the start of a blank key-phasor dot to the first positive peak of the signal. The key-phasor signal serves, also, for the evaluation of vibration-to-rotation frequency ratio.

Vibration-related parameters are commonly measured on power generating machines under steady-state (online) and transient (startup and shutdown) conditions are as following:

1. Overall magnitude of vibration for indicating presence and severity of a problem. It is just an indication of dynamic behavior and sometimes used for acceptance or rejection of non-critical, relatively small, simple, low-horsepower trains for shop test, site performance test, etc.

2. Frequencies of vibration components for insight into the root causes of the malfunction.

3. Time-base waveforms and orbital paths of rotor lateral motion (also rotor orbital and its direction) for insight into the nature of the malfunction. The orbits are especially significant source of vibrational information. They represent magnified snapshots of the rotor actual motion. Shaft centerline position is important for insight into the radial load status and into the specific location of the rotor with respect to the stationary components of the machine.

4. Amplitudes and phase angles of dynamic motion components of the rotor (vibration amplitude vs. speed and phase angle vs. speed). The phase angle is one of the most important parameters for power generation machine malfunction identification (particularly phase angles of vibration components with synchronous frequency, twice rotating frequency, etc).

Looseness in stationary and rotating parts

Looseness between the rotor supporting pedestal, casing and foundation (for example, loose foundation bolt) is a common malfunction in rotating machines of power plants. The unbalanced force carried by the rotor may occasionally exceed the gravity force or other forces applied to the machine. This causes a periodic lifting of the pedestal, resulting in system stiffness softening, its cyclic variability and impacting. As a result, the rotor may exhibit changes in the synchronous responses, and an appearance of fractional sub-synchronous vibrations (1/2, 1/3, etc) in some rotating speed ranges. Simplified models which simulate the loose pedestal malfunction can be obtained considering periodic softening of the system. Simplified models are usually formulated in direction of looseness and containing simplified dynamic parameters of foundation and rotor.

Together with local impacting effect included in the more formal analysis, even simple models generate synchronous and sub-synchronous fractional frequency analytical responses (1/2, 1/3, 1/4, etc). The diagnosis of the pedestal looseness (particularly foundation bolt looseness) is based on the appearance of 1/2 and usually 1/3 vibrations as well as visual inspection of the bearing/pedestal/foundation fastenings.

Looseness in rotating elements such as disks or thrust collars mounted on rotating shafts (or bearings un-tightened in bearing pedestals, etc.) represent another type of power plant rotating machine malfunction. A disconnected disk or a thrust collar may still rotate, but at a different speed than that of the rotating shaft – it may also displace axially. A loose bearing may start rotating or may suddenly stop. The clearances, friction conditions between the shaft and the loose part, and the tangential external force applied to the loose part, such as external fluid dynamic drag, play important roles in the rotor-dynamic response.

While perturbing the normal operation of power generating machine, this type of looseness-related dynamic phenomena can, however, be relatively easy to identify and eventually corrected. It causes very characteristic modifications of rotor normal operational responses. A loose rotating part usually carries an unbalance which changes the balance state of power generating machine. This results in a modification of the synchronous vibrations (1x) and also appearance of the loose part unbalance-related forced vibration components. Simplified models can be presented for this phenomenon using simplified dynamic parameters of rotor and loose rotating parts. Usually an axial displacement of the loose part is not included in simplified models. The loose part rotating frequency is usually function of the shaft/loose part clearance, surface friction and the tangential drag coefficient provided by the fluid environment. Depending on a particular machine, the latter can drive the loose part at higher frequency than rotor rotating frequency (e.g., a loose turbine disk) or slow down the loose part (lower frequency than rotor rotating frequency). In both situations, friction and fluid drag act in opposite directions. At steady-state conditions, the friction and fluid drag may balance each other, and loose part rotating frequency becomes constant. If loose part speed does not differ very much from the rotor rotating speed, the resulting vibrations exhibit the characteristic pattern of beat. Most often, however, the looseness of a rotating part leads to transient conditions. The loose-part-related vibrations have most often a sub-synchronous frequency tending to the rotating frequency of the rotor. These vibrations look somewhat similar to fluid whirl/whip vibrations, and may sometimes be confused with the latter.

Worn or Problematic Bearing

The designs of hydrodynamic bearings and rolling element bearings used in various rotating machines in power plants include a small bearing clearance which is appropriate for normal operation of the rotor. Poorly lubricated bearing or worn journal bearing surfaces inevitably lead to an increase of the rotor/bearing clearance. The increased looseness in the bearing, often referred to as "dead band," causes a reduction of the system stiffness, and may result in a specific array of dynamic phenomena experienced by the rotating shaft. Excessive bearing clearance and occasional loss of the shaft/bearing contact during operation, cause variable stiffness of the rotor/bearing system, thus provide nonlinear conditions for unbalance-related excitation, which may lead to rotor instability.

The physical phenomena occurring in the oversized or worn bearing/rotor system – namely, variable stiffness, impacting, friction, etc. – are similar to the dynamic phenomena during the rotor-to-stator rubbing. The similarity is, however, of the "mirror image" type. In rubbing, the system becomes periodically stiffer during a cycle of vibration, which leads to an increase of the average stiffness. In the oversized or worn bearing/rotor system, the average stiffness decreases. The rubbing occurrences are described as "normal-tight" situations. The oversized or worn bearing leads to the "normal-loose" description. In both situations, two other physical phenomena, namely friction and impacting, are involved. Their involvement and strength differ, however, in specific cases.

The simplified mathematical model simulating the oversized or worn bearing malfunction is similar to rotor rubbing simplified models. But parameters are different. The model produces rotor unbalance-related responses with synchronous and sub-synchronous fractional frequencies as well as self-excited vibrations occurring with first critical frequency. The perturbation equations around the rotor static equilibrium position yield anisotropic characteristics for the vertical/horizontal stiffnesses and tangential components. The latter adequately reflect the anisotropic nature of the rotor/loose bearing system, and eventually generate differences in vertical and horizontal modes.

The diagnosis of the oversized or worn bearing malfunction, and distinguish it from the rubbing, should be based on the rotor centerline position, synchronous vibration (lx) data, frequency spectrum and especially the orbit analysis. While exhibiting similar spectra, the journal or bearing contact is usually maintained during a longer fraction of the vibration period when the rotor or stator rubbing contact occurs, thus the orbits are substantially different from the rub case. While maintaining the contact, the journal slides on the bearing surface (part of the orbit follows the bearing clearance circle). During rubbing there is high rotor lateral excursion from the rubbing spot and therefore, more impacting and unsteady transient motion occurs. Within an oversized or worn bearing, the journal remains close to the bearing surface, even when the contact is broken. The consecutive contacts do not produce high power impacts. There are much less transient components and higher harmonics in the vibration spectrum, as compared to the rub cases.

Cracked Rotor

Cracked shafts represent a severe malfunction in power generating trains and should always be considered as a potential event that could result in serious catastrophic failure. A shaft crack causes two major results: a stiffness reduction resulting in rotor anisotropy and a shift of the elasticity axis (the rotor bows), which affects the balance state.

In order to obtain a simple model of a rotor with the cracked shaft, usually, unbalanced rotor model/formulation is used as base. The formula is transferred to rotating coordinate at assumed crack location (coordinate rotating with rotor speed). Various parameters and coefficients are involved in formula based on theoretical and semi-empirical relations for crack-related gaping, unilateral stiffness-reducing effect, rotor elasticity, axis shift, etc. Then the equation is re-transformed to the previously used stationary coordinates. It is easier to solve cracked-rotor dynamic formulation in rotating coordination and then transfer solution to stationary coordinate. This formulation has periodically variable stiffness with frequency two times of rotor rotating frequency (since cracked rotor simply presents two events at each rotation). In another way of reasoning, the radial load is applied to a rotor with two times of periodically variable stiffness. The result is an appearance of the forced vibration with frequency equal by two times of rotating frequency. It has additional unbalance-like excitation with 270 phase lag. Since the latter interferes with the rotor residual unbalance, the synchronous responses of a cracked rotor will differ from the original ones, especially at the low frequency range.

The crack-related stiffness is different in two orthogonal directions of the rotor cross-section (modeled through the crack-related gaping coefficient). It actually causes an appearance of a tangential force acting in the direction of rotation (another mechanism of transferring rotating energy into lateral vibrations). This tangential force opposes damping, thus results in the decrease of the system-effective damping. The simplified models predict that if crack-related gaping coefficient reaches four times of synchronous damping factor, then the effective damping is nullified. Such value of crack-related gaping coefficient can practically never be achieved before a total destruction of the rotating machine. A gradual decrease of the effective damping can, however, easily be noticed earlier in rotating speed and two times of rotating speed (1x and 2x) vibration amplitude increases.

The early diagnosis of shaft crack is based mainly on changes in 1x and 2x vibration vectors. These data can be monitored at steady-state, as well as during transient startup/shutdown conditions. The latter data is especially meaningful, as the vibration changes are particularly significant in the 1x and 2x lateral mode resonant ranges of rotating speeds. Deviation of 1x and 2x vibration vectors from their acceptance regions (established based on normal operating condition including radial load information) provides alarming and early warning of a cracked rotor. The rotor centerline position and slow-roll data give additional information about the rotor bow situation. Observation of the orbits is also very helpful in diagnosing the shaft crack. A high 2x vibration component causes an appearance of an internal loop on the orbit (2x orbit is forward). The crack-related weakening of the rotor in a constant speed operation may be diagnosed by analyzing the 1x and 2x vector trend data. A shift in the natural frequency can be detected when at a constant rotating speed, at certain moment of time, the 1x or 2x vectors exhibit resonant features.

The case study is described for mid-size 14 MW, 3,600 rpm electrical generator. Recorded main vibration amplitude components (peak-to-peak) are 58 micron at 1/3x, 61 micron at 1/2x, 40 micron at 1x, 26 micron at 1.5x, 20 micron at 1x and 16 micron at 2x. The 1/2 and 1/3 sub-synchronous vibrations, plus rich spectrum of higher harmonics (2x and 3x) are presented. This response shows loose pedestal connection. Careful site inspection shows loose foundation bolts and grout/foundation damages. Generator foundation is repaired. Train is re-grouted.

Bridging the Gaps in Containment Systems

By Ed Sullivan, freelance writer

The modern design and construction of containment structures – both primary and secondary – are designed and constructed to be foolproof, ensuring safety to the workers, the public and environment. Yet, as safe as they may be, the eventual failure of containment system coatings and linings result in maintenance or rebuilding that is time-consuming and expensive, and may even require exorbitant downtime.

There are many choices of products that are designed to protect against leaking or spilling of the aqueous materials contained in sumps, trenches, concrete dikes and tanks with concrete bottoms. Yet many of the most frequently used products - polyurea, polyurethane, polysulfide, silicone and epoxy - offer only limited protection, and will fail due to exposure to UV light, weather, chemicals, abrasion and cracks in concrete or expansion and control joints.

Failures in primary containment structures, such as clarifiers, can result in extensive downtime. Many clarifiers are constructed of metal walls but have concrete bottoms, sometimes reinforced with grout to provide an extra seal if the concrete should crack from thermal expansion and contraction or other stresses. Yet, in the majority of cases, when the concrete moves or cracks, the grout cracks, causing leakage into the secondary enclosure and need for a cleanup. It also means the primary enclosure must be shut down and repaired.

While secondary containment dikes are required to enclose leaks and spills for three days, damage to the lining is likely from the spill of most chemicals resulting compromising the dike's integrity, resulting in costly and time-consuming maintenance and downtime. UV rays and weather cause concrete to move and crack, also, and just plain degrade most polymers, causing the same problems.

There is a solution to the combined threats of UV, weather, chemical and expansion-contraction problems, an engineered elastomeric lining system that can be applied to primary and secondary containment structures ranging from wastewater facilities to protecting livestock ponds from chemical infiltration. The engineered elastomeric lining is noteworthy for its long service life, ability to "bridge" joints and cracks in concrete, imperviousness to UV light and harsh chemicals, and ease of installation.

The Elasti-Liner system from KCC is a line of engineered elastomeric lining products that is applied by brush or roller to concrete substrates and directly over expansion and control joints.

The elastomeric bridge

"In the past, we used 100 percent epoxy coatings on our secondary containment structures," said Brian Peroni, corrosion control specialist at Florida Power & Light. "Epoxy might work well enough for some primary containment applications, but for concrete structures, it's inadequate. In concrete structures live cracks will occur, and because epoxies are a rigid coating, they tend to crack right along with the concrete. As a result, you have continual maintenance to seal those cracks as they occur."

Peroni described FP&L's typical secondary containment as basically a concrete dike consisting of a wall and base around the facility's primary tanks. Those tanks contain a variety of liquids, ranging from very harsh, low pH chemicals, such as 98 percent sulfuric acid, to very caustic solutions with a pH as high as 10-12. Tanks located in Florida are subjected to a lot of sunlight, which contributes to the cracking of concrete dikes.

The clarifiers at power plants are another example of containment structures where cracking can be a serious problem. These primary containment vessels are often designed with metal sidewalls resting on a concrete base. In an attempt to prevent leaks when the concrete base cracked, the concrete is often reinforced with grout. However, when the concrete moves or cracks, the grout seal also can fracture.

To overcome the problems of leaks resulting from cracked concrete in primary and secondary containment structures, Peroni used Elasti-Liner elastomeric liner.

"The product has great crack bridging properties," he explained. "That's why it is so effective for us. We don't have to worry about cracks in the concrete and we don't have a lot of maintenance. We simply put it on and forget about it."

The inside story

"I would say that this Elasti-Liner product line is the only truly monolithic containment liner available," said Art Rak, president of Ultimate Corrosion Control.

Rak cited the 1994 installation of the elastomeric formula as a lining of a large, 4-ft. containment dike for an 18,000-square-foot tank farm holding highly-corrosive phosphoric acid in Chicago Heights, Ill. "The lining still looks and works great after 17 years," he said.

Rak said this elastomeric product line is great at bridging cracks up to one-eigth inch because of the way it is engineered. The polymers are cross-linked and act like coiled springs that expand and also contract as concrete moves.

"The elastomeric liner exceeds the tensile strength of concrete," he said. "If you deliberately tried to pull the liner off the concrete, you would have to exceed 500 PSI in pulling strength. So, this elastomeric-based lining is so well bonded to concrete no matter what the concrete does."

Because you can apply Elasti-Liner over expansion and control joints in concrete structures, installation time and costs are saved.

Is Your Wind Turbine Step-Up Transformer the Weak Link in the Wind Energy Supply Chain?

By Tom Steeber, Vice President of Marketing and Sales, Pacific Crest Transformers

Converting wind energy to electrical power is the fastest growing segment of the United States' energy sector. Bolstered by available federal stimulus dollars, there has been a virtual modern-day "land-rush" to develop wind farms.

In the words of one industry leader, "If there is a site that has a viable wind profile, access to network connections and access for delivery of materials, and we don't develop it, someone else will."

This headlong rush to install more wind turbines has outstripped the usual developmental learning curve, in which new technologies mature by a process of trial and error, resulting in defining equipment that is suited for the job at hand.

In this 21st century land rush to cash-in on wind energy, developers are often trading low initial costs for higher total costs of ownership to be shouldered later by the wind farm owners and operators. Nowhere is this more evident than with wind turbine generator (WTG) step-up transformers.

Historically, the WTG transformer function has been handled by conventional, off-the-shelf distribution transformers. However, the relatively large numbers of recent failures have convinced many that WTG transformer designs must be substantially more robust.

In some cases, site operators are keeping a quantity of spare transformers at their wind farms so they have spares on hand for the frequent outages caused by using standard distribution transformers where they simply do not belong.

The key WTG step-up transformer design issues that wind farm owners and developers should pay attention to include transformer loading, harmonics and non-sinusoidal loads, transformer sizing and voltage variation and special requirements to withstand faults.

The role of the WTG step-up transformers is critical and its design must be carefully and thoughtfully analyzed and reevaluated. We need to move from equipment purchasing decisions based on lowest initial cost to solutions that will provide the best choice in terms of total cost of ownership, network stability, less down time and lost revenue from high maintenance issues. New transformer technology specially designed for the wind farm market should be considered carefully when making purchasing decisions.

Transformer Loading

Wind turbines are highly dependent upon local wind and other climatic conditions, and their yearly average load factors can be as low as 35 percent. Most utilities in the past anticipated that operational loading would be about 50 percent. The relatively light loading of the WTG transformer introduces two unique and functionally significant problems that must be incorporated into WTG design.

The first issue is that the wind farm transformers' relatively low average load factors skew purchasing decisions and make older economic models inaccurate. When lightly loaded or idle, the core losses become a more significant economic factor while the coil or winding losses become less significant.

Previous purchasing decisions included an estimate of the transformer's amount of idle time. The overall evaluation looks at how much of the time the transformer is sitting idle and how much it will be running, and compares the ratio of these two. Those looking to apply this mode to wind farms must be much more cognizant of idle time; the typically used price evaluation formula does not apply to this scenario.

For example, National Electrical Manufacturers Association (NEMA) TP 1-2002 (Guide for Determining Energy Efficiency for Distribution Transformers) and DOE efficiencies are not modeled for the operational scenario where average loading is near 30 to 35 percent. Wind farm developers should be extremely cautious about applying these standards when calculating the total cost of ownership for WTG transformers.

The second problem is that the WTG transformer is subjected to frequent thermal cycling as a function of varying turbine loads. This causes repeated thermal stress on the winding, clamping structure, seals and gaskets. The situation is analogous to breaking a wire by bending it back and forth until it breaks. The metal fatigue, heat and stress weaken the wire and cause it to break; the same is true of electrical connections that have to withstand repeated thermal cycling, stress and varying loads.

Repeated thermal cycling causes nitrogen gas to be absorbed into the hot oil and then released as the oil cools, forming bubbles within the oil which can migrate into the insulation and windings to create hot spots and partial discharges which can damage insulation. The thermal cycling can also cause accelerated aging of internal and external electrical connections.

Harmonics and Non-Sinusoidal Loads

WTG transformers are switched with solid state controls to limit the inrush currents. While potentially aiding in the initial energization, these same electronic controls contribute damaging harmonic voltages that, when coupled with the non-sinusoidal wave forms from the turbines, cannot be ignored from a heating point of view.

Normal voltage is alternating at 60 cycles per second. If the transformer operates at other voltages, the voltage peaks will not line up and you will not get the amplification you would achieve when frequencies line up. The transformer tries to pass the voltage it sees through the circuit and causes extra loading. All the electronics used today send spikes on the line and each time a frequency disturbance goes back to the transformer, the transformer must be able to handle the higher loading it sees.

When a rectifier/chopper system (the electronic controller used in wind turbines) is used, the WTG transformer must be designed for harmonics similar to rectifier transformers. These are "dirty" from a harmonics point of view, meaning they may contain high frequencies that the wind farm owner does not want to pass onto the utility power's grid, because it will affect other equipment.

If this happens, it can result in a protective equipment fault, causing transmission grid equipment to protect itself against faults by shutting down. The WTG must be able to take the additional loading into consideration and provide electrostatic shields to prevent the transfer of harmonic frequencies between the primary and secondary windings. It must be able to handle the energy and not transmit it to the grid.

Transformer Sizing and Voltage Variation

Because of the high up-front costs, no over-voltage capacity is designed in to a WTG transformer to overcome the frequent voltage fluctuations inherent with wind turbines. WTG transformers are usually designed so the transformer voltage exactly matches the wind turbine's output voltage. There is a one-to-one correspondence between transformer and turbine, and each turbine produces a fixed amount of energy, so future growth is a known fact.

At the same time, the generator output current is monitored at millisecond intervals and the operational limits allow up to 5 percent over-current for 10 seconds before the generator is taken off the system. Since the WTG transformer is designed to match the generator output with no overload sizing, its design must be uniquely robust to function without the extra capacity.

Requirement to Withstand Fault Currents

Typically, conventional distribution transformers, power transformers and other types of step-up transformers will 'drop out' when subjected to a fault. Once the fault has cleared, the distribution transformer is brought back on-line. To maintain network stability, wind turbine generators are not allowed to disconnect from the system when there are network disturbances, except within certain guidelines developed for generating plants. They must be able to stay on the line through the fault and must be mechanically, electrically and thermally able to handle the fault. This is called "fault ride-through."

The length of time the generator is required to stay on line can vary. During this time, the generator will continue to deliver an abnormally low voltage to the WTG transformer. For example, during faults, the transformer may be required to carry as low as 15 percent rated voltage for a few cycles and then ramp back up to full volts just a few seconds after fault clearing. The WTG transformer must be ruggedly designed so it can withstand full short circuit current during the initial few cycles when the maximum mechanical forces are exerted upon the WTG transformer windings.

Checklist of WTG Step-Up Transformer Must Haves

The role of WTG transformers in today's wind generation scheme is unique; its design must be equally unique and robust. Don't trade long term reliability and lower total cost of ownership for low initial cost. Make sure you consider these specific factors to ensure that your wind turbine step-up transformer is a strong link in the chain.

The WTG step up transformer should have enough cooling to handle thermal events. Since heat travels layer to layer, minimize the distances to cool it most efficiently.

Brace the WTG mechanically to withstand events.

Axial forces, which drive the transformer windings to telescope and come apart, are best maintained with coiled end blocking.

Radial force, which make transformer windings expand outwardly, escaping each other as the electro magnetic field becomes polarized and pushes the winding apart, are best maintained with round or circular shaped coils so the forces can spread forces evenly at 360 degrees.

Minimize core losses due to down time. But proactively consider cost and construction tradeoffs associated with decreasing core losses.

When purchasing a WTG step-up transformer, make sure you factor in how reliability affects the total cost of ownership. Wind farm turbines are unique because they are ganged together and dependent upon each other. For example, say one transformer fails, with a loss of revenue of about $1,000 per day. It may take two or even three days to replace the transformer, and in the meantime, the faulty generator may take down 10 to 14 other generators, not allowing them to produce. So that loss of $1,000 of revenue could turn into $30,000 in lost revenue, plus the cost of another transformer, construction labor and crane expenses.

New WTG Transformers Fit the Bill

Pacific Crest Transformers, a leader in the design and construction of liquid-filled distribution transformers, has developed a wind turbine generator step-up transformer specially designed for reliability, given the factors discussed above. It features an innovative design that includes round coils, a cruciform, mitered core with heavy-duty clamping and a proprietary pressure plate design, as well as a premium no-load tap changer.

The PCT design features circular windings with coolant flow ducts throughout the coils, which spread the radial and axial forces evenly over their circumference, eliminating hot spots that lead to premature breakdown and ultimately to transformer failure. Coil end blocking with heavy duty 3 gauge steel bracing and proprietary pressure plates contains the axial forces exerted during a fault condition. These forces can cause telescoping of the coils, shortening transformer life.

The WTSU has a unique cooling system, effectively shortening the path that heat generated within the core and coils must take to reach the cooling fluid. It also features a tap changer with silver-plated contacts, for long-life and reliable operation.