FPE Models TC-525/546 Spring Drive Tear Down, Maintenance & Repair

In this white paper, we will discuss tear down, maintenance and repair of the FPE TC Series spring drive mechanisms. We stock many of the components that will be discussed and for those who might be interested, we offer full tear down and overhaul services for each of the FPE TC Series spring drive mechanisms. As a part of the discussion, a comparison of the models that were produced will be offered and the key differences in the models will be highlighted and described. The information we provide will help to ensure you properly identify your model and are positioned to recognize and procure any replacement components that you ultimately need as a result of your inspection. Key activities that should be completed, including major items that should be inspected and maintained, will be listed and discussed. Helpful tips to aid in tear down and inspection will also be shared.

Two major variations of the FPE TC spring drive mechanisms were manufactured. Much of the design and “componentry” of each variant were similar, but they were not identical. The first variant model numbers are TC-525 and TC23-2. The second variant model numbers are TC-546, TC15 and TC23-1. Referring to the series of figures below (labeled Figure 1), the main differences between the model variants are labeled and described.

Figure 1

Figure 1 above depicts a top view of each variant in which three main differences in the two models are circled in red and numbered. Below is the description of each of the numbered differences:

  1. Drive spring barrel assembly for the TC-525 has a 1″ diameter shaft, while the same shaft on the TC-546 has a 3/4″ diameter.
  2. Dimensions and materials of the vertical drive shaft, worm gear and worm gear support structure are different.
  3. Dimensions and materials of the lock plate and first shaft assembly are different.
Figure 2

Figure 2 above provides a left side look at both variants, resulting in another view of two of the three main differences in the models. The differences are circled in red and numbered. Below is the description of each of the numbered differences:

  1. Dimensions and materials of the vertical drive shaft, worm gear and worm gear support structure are different.
  2. Dimensions and materials of the lock plate and first shaft assembly are different.


The next few figures depict examples of the “typical” wear conditions that can be found during the tear down and inspection of the FPE TC Series spring drive mechanisms. Descriptions of the specific wear conditions are presented in Figures 3 through 7, including visual identifiers which help illustrate the worn condition and aid in pinpointing locations of key components that should be inspected.

Figure 3: Wear Patterns on Key Components

Figure 3 above shows the locations and types of wear that can occur on the spring barrel mount and support plate holes. Typical wear on the spring drive crank and the cross head bearing is also depicted.

Figure 4: Inspection Points on Main Spring Drive Barrel Assembly

Figure 4 above provides visualizations of each of the major inspection points on the main spring drive barrel assembly. Brief descriptions of the individual items are included for reference.

Figure 5 below shows the locations and types of wear that can occur on the Geneva wheels and scroll cam. Excessive wear and separation of the laminated plates on both Geneva wheels are shown. NOTE: The scroll cam depicted in the picture has excessive wear.

Figure 5: Wear Patterns on Geneva Wheels and Scroll Cam

Figure 6 below shows the locations and types of wear that can occur on the vertical shaft. Pay special attention to worn or broken teeth on the worm gears. Also, inspect the area where the shaft seals contact the shaft to ensure that grooves have not worn into the shaft.

Figure 6: Wear Patterns on Vertical Shaft

Ensure the vertical shaft is straight and verify condition of the oil seals. Refer to Figure 7 below for detailed information on the two types of vertical shaft oil seal assemblies that were used.

Figure 7

Figure 7 above contains schematics of the two oil seal assembly configurations for the FPE TC Series spring drive mechanisms. When inspecting your FPE TC spring drive mechanism, this is a component that should always be inspected in detail and care should be taken to verify the condition of the oil seal assembly. For the TC-546, the replacement part number is 4000-682. For the TC-525, the replacement part number is 4000-731.


If you plan to self-perform tear down, maintenance and repair of your FPE TC Series spring drive mechanism, several key activities should be completed to ensure high quality results. Those key activities are presented in the bulleted list below for a TC-546 spring drive. The list is accompanied by Figure 8 which includes an exploded view of a TC-546 spring drive mechanism. Figure 8 is meant to provide a visual aid to assist in pinpointing and understanding each of the key activities that need to be performed. Key activities include:

  • Always replace all bearings (bearing kit, part number 4000-079K)
  • Replace the oil seal assembly
  • If the 3rd shaft assembly needs replacement, upgrade to the solid Geneva gear design offered by Waukesha® Components (third shaft assembly, part number 4000-641)
  • If the 2nd shaft assembly needs to be replaced, replace with the original Geneva gear design offered by Waukesha® Components (second shaft assembly, part number 4000-626)
  • Replace any gears that have broken teeth or exhibit excessive mechanical wear
  • Always fully disassemble and fully inspect the main spring drive barrel assembly (main spring drive barrel assembly for TC-546, part number 4000-371)
  • Replace all locking hardware, i.e. lock washers, nyloc nuts, locking tabs and spring pins
Figure 8: Exploded View of FPE TC-546 Spring Drive Mechanism

Finally, when planning to self-perform a comprehensive tear down, maintenance and/or repair of your FPE TC Series spring drive mechanism, always remember to complete the following activities before removing any parts of the assembly:

  • Ensure the mechanism is in neutral position
  • Match mark all mating gears with metal marker
  • Remove all locking spring pins, securing support plates to the mechanism base plate
  • Mark current location of all corners of support plates on the base plate for future reference

To learn more about all components available for the Federal Pacific line of LTCs, contact a member of our sales team at 1-800-338-5526. Also, don’t forget about our library of easy-to-navigate, 3D catalogs designed to help you quickly identify and locate hard-to-find components for LTCs and oil circuit breakers. The library also contains several of the Waukesha® Components’ line of Transformer Health Products®.

Maintaining Healthy Transformers and LTCs


For transformers and LTCs to operate at their optimum level, transformer oil, a key part of the insulation system, must remain free of impurities that will lower its ability to function properly and efficiently. Three key impurities contribute significantly to the aging rate of a transformer: heat, oxygen and moisture. At least one, the moisture level, has a solution.

Every non-conservator equipped free breathing transformer/LTC has a headspace above the transformer oil level that is filled with a gaseous mixture. This headspace exists to allow for expansion and/or contraction of the oil volume due to load or environmental heating and cooling. During the heating cycle, the head space contracts, causing the transformer/LTC to exhale the differential volume of gas to the atmosphere. During the cooling cycle, the headspace expands, causing the transformer/LTC to inhale the differential volume from the atmosphere.

This air transfer without the use of a silica gel breather would contain the ambient level of moisture. This level could swing from 10% (Mojave Desert on a sunny day) to 99% during a foggy or rainy day anywhere in the USA. Why should we care? Because moisture in transformer oil affects the dielectric breakdown strength of oil, the temperature at which water vapor bubbles are formed, and the aging rate of the insulation materials (oil and paper), all of which could lead to a transformer failure.

What about transformers with conservators, are they not immune to moisture since the oil is protected from contact with ambient air by the rubber bladder? Yes and No. The bladder, when intact, does protect oil from ambient air. Degradation/Service aging of the bladder material over time can impair the life of the bladder. In addition, since no easy way exists to inspect the bladder without actually opening the conservator tank, a rupture can occur and go unnoticed. In this case, the oil has the same exposure to ambient air and moisture as a free-breathing transformer without a conservator tank.

Therefore, what type of silica gel breather should be used? What are the pros and cons of each system?

A static, “dumb” silica gel breather has a relatively low upfront cost. However, it has a finite capacity to absorb moisture, and, therefore, its life is difficult to predict due to the multiple variables involved with the weather and equipment loading. This type of breather requires frequent visual monitoring since the unit lacks any type of self-monitoring. Once the capacity of the unit has been reached, silica gel must be replaced with new or recycled dry silica gel to avoid moist air from entering the equipment.

A properly designed auto regenerating dehydrating breather has more upfront expense but eliminates the need for frequent monitoring and replacement. These breathers are self-monitoring with the capability of remote reporting and will function for many years with only minor annual inspections.

In conclusion, protecting the oil in a transformer or LTC from moisture contamination is readily accomplished with minimal attention by using an automatic regenerating dehydrating silica gel breather, such as the Waukesha® Dual Column Breather.

Art Martin
Senior Product Engineer – Service & Components Division


The latest generation Waukesha® Auto Regenerating Dehydrating Breather System (Dual Column Breather is designed to remove moisture from the air entering transformer, LTC and conservator tanks as well as other sealed tanks. Regeneration is accomplished using Positive Temperature Coefficient (PTC) solid state heaters located in the central column and controlled by an adjustable timer and humidity sensor to provide automatic recharging of the silica gel desiccant, eliminating the need for manual intervention. The humidity sensor constantly monitors air from the in-service column and will force a column shift if the air stream humidity reaches the trigger point, regardless of the timer setting. The use of dual columns ensures that the unit does not have to wait for a “quiet time,” i.e. when the transformer in not inhaling, in order to regenerate. That enables the breather to have a fresh silica gel column continuously available for service. By adjusting the silica gel column regeneration cycle time, the system may be configured for various tank (air volumes) of 100 to 40,000 gallons or more.

Column “A” in Service

Column “B” in Service

During normal operation, air enters the breather through slots in the upper housing and passes through the desiccant to the center of the assembly. The center tube contains several holes along the entire length, forcing airflow to disperse through the maximum surface area of desiccant. Airflow then travels through the center tube, along a path—depending on the column in service—to the isolation solenoid and humidity sensor and eventually through the top port to the conditioned airspace.

During regeneration, a temperature regulating PTC heater element within the center tube of the column being regenerated, is energized to heat the desiccant to a specified temperature. Any moisture present in the desiccant is driven outward to the cooler borosilicate glass globe where it turns into condensate. The condensate runs to the bottom of the breather assembly where it is discharged through the water drain filter. In the arctic version, heat is automatically transferred to the drain to prevent freezing down to –50°C. During regeneration, the solenoid valve, located at the top of the breather assembly, isolates the column being regenerated while allowing the conditioned airspace to breathe through the column that is in-service. Once regeneration of the out-of-service column is complete (3 hours plus 30 minute cool down), the column is placed in stand-by mode. At the end of the in-service column cycle or if a column switch is triggered by the humidity sensor, the exhausted column is placed in regeneration mode and the stand-by column is placed in-service, ensuring a continuous supply of dry air to the conditioned airspace.

The Dual Column Breather system is shipped as a single integrated assembly and includes installed silica gel and accessories needed for mounting. The breather is constructed with a machined, anodized aluminum top, bottom and cast controls housing. Other components include heating elements, heat conductive fins, screen, condenser media and a filter vent system. Customer electrical and signal wiring is via conduit connections on the bottom of the control housing. The outer tube is optically clear borosilicate high strength glass. Sealed super bright LED lamps on the control cover provide clear visual indication of breather status, even in sunlight.

The Dual Column Breather systems feature an integrated PCB microcontroller that constantly monitors the condition of airflow through the breather. User adjustable, time-based controls regenerate the desiccant regardless of condition. Humidity sensing capability automatically overrides and regenerates the desiccant, if needed, between the set timer frequencies. Due to the dual column design, column regeneration is independent of the breathing status of the conditioned airspace.

The Dual Column Breather system is designed to be vertically mounted by means of four mounting tabs. Due to the dual column design, the mounting pattern is significantly different from our previous single column designs. An adapter plate is available from the previous mount pattern to that of the Dual Column Breather. An adapter kit is also available to accommodate the transition from previous cabled design to the conduit connections of the Dual Column Breather. The recommended connection to the conditioned space should be accomplished using standard flex hose and hose barbs (included), copper tubing, hard non-ferrous pipe or DIN 42562-5 flanged fitting.

In order to ensure that the Dual Column Breather system performs with exceptional reliability, it has been rigorously tested to IEC, EN, MIL and Prolec GE Waukesha internal standards. Five beta units are currently in service at diverse U.S. locations.

This new system features specifications designed to allow for ease of installation and operation:

  • Wide range of input voltage tolerance, 100–240 VAC, 50–60 Hz
  • Both time based and humidity based silica gel regeneration control
  • Local system status SuperBrite LEDs for visibility is bright sun
  • Remote monitoring of major system functions

Intelligent controls continuously monitor the status of the Dual Column Breather systems’ major components. The component’s status is reported via a combination of local LED signals and, for major faults, via an alarm relay, which may be monitored remotely. These include:

  • Normal Operation (Green LED)
  • Fast Mode operation (Flashing Green LED)
  • Regeneration in Progress (Yellow LED)
  • Humidity Sensor out of range (Blinking Yellow)
  • Regeneration Heater Fault (Blinking Red LED & Remote alarm)
  • Solenoid Fault (Red LED & Remote alarm)
  • Power Failure (No LEDs Lit & Remote alarm)

The Dual Column Auto Regenerating Dehydrating Breather requires minimal annual maintenance:

  • Check bottom drains for restrictions such as dust or other contaminants
  • Visually check the silica gel for contamination, particularly transformer oil, which will show up as a dark or blackened color (transformer oil contaminated silica gel must be replaced)
  • Clean the glass tube(s), if required
    • Use glass cleaner or soap and water as solvents may degrade the rubber seals

Regulating Heat in the Control Cabinet

Appropriate Use and Application of Control Cabinet Heaters

Proper use of heaters in cabinets can improve reliability, efficiency and operational life of electrical equipment by preventing condensation inside the cabinet, thereby eliminating component and metal surface corrosion. However, the effects of too much heat and/or heat concentrated in one area of the cabinet can cause more harm than good. For anti-condensation purposes, the appropriate amount of heat needed should be based on the calculated power required (watts) to warm the enclosure to a temperature difference of 5 – 7 degrees Celsius above outside ambient temperature.

Two types of heater technology are typically available for control cabinet applications: strip heaters and self-regulating Positive Temperature Coefficient (PTC) heaters. Strip heaters have been around longer, are based on a fixed resistance element and therefore operate at a fixed wattage output. This type of heater requires a thermostat to turn the heater on below a set temperature and off above the set temperature to control the enclosure temperature. Typically, strip heaters only provide radiant heat which result in extreme temperature gradients with the heat concentrated on equipment closest to the heater, while condensation can still form in areas furthest away from the heater. Excessive localized heating caused by strip heaters may result in the unintentional thermal overload operation of protective devices, such as circuit breakers, deterioration of cable insulation, and warping / melting of plastic components such as wire ducts. Terminal blocks and wiring closest to strip heaters are exposed to high temperatures, possibly causing thermal damage. When wire insulation is damaged, risk of faults increases as does the risk of equipment failure, both of which can negatively affect personnel safety.

During cold weather, when a significant amount of heat is required to reach the thermostat setting, or in applications of continuous year-round use, a traditional strip heater is likely to drive the temperature of the area around the heater well above desirable levels. This can result in uneven heat distribution in the cabinet with areas measuring much colder temperatures further away from the strip heater.

PTC heaters, on the other hand, utilize a variable resistance element that changes resistance in response to changes in air temperature. As the air temperature decreases, the resistance of the heater element decreases allowing more current to flow through the heater, which leads the effective watts in heat to increase. Likewise, as the air temperature increases, the resistance of the heater element increases, allowing less current to flow through the heater, which leads the effective watts in heat to decrease. PTC heaters are available with fans for circulating the air in the enclosure to produce a more even distribution of heat throughout the enclosure. Due to the variable resistance element, PTC heaters do not require a thermostat to control operation, but thermostats can be used in special applications where ambient temperatures can exceed 40C and supplemental heat in an enclosure is not required or to increase power output when temperatures are lower than desired.

Below in the Max Temperature chart is a comparison between a strip (non-PTC) heater and a PTC heater, both without thermostats that can limit their power output. Depending on the ambient temperature, PTC heaters stabilize slightly above that ambient temperature, while strip heaters continue outputting as much heat as possible.

To Select a Heater

  1. Calculate the power (watts) needed for your particular enclosure size. For estimation of enclosure heat needed (based upon natural convection air moving less than 5 m/s), use this equation:Joules/Second = Watts = h x A x TWhere h = overall heat transfer coefficient W/(m^2K) – The value of h is difficult to calculate and is different for virtually every application; however, for rectangular outdoor enclosures with small amounts of venting and mounted to a vertical support, the typical value is between 5 and 10. Using 10 will represent a “worst case” scenario in a windier environment.A = Exposed surface area of enclosure (m^2)T = Temperature difference desired (K) – For anti-condensation purposes, typical value is equal to 5.A higher value may be used for particularly humid applications. EXAMPLE: A 3.5 foot wide, 4 foot tall and 1 foot deep cabinet mounted to a flat wall would have exposed surfaces equaling 29 ft^2 or 2.7 m^2. Watts = h x A x T = 10 x 2.7 x 5 = 135
  2. Draw a corresponding horizontal line on the selection chart (see Water vs. Heater Inlet Temperature chart below) based upon wattage calculated in Step 1 above.
  3. Determine the highest ambient temperature condition for the enclosure application and draw a corresponding vertical line at the bottom of the chart.EXAMPLE: The same cabinet in the example above is in a location where the higher air temperatures often reach 45°C. The vertical line should be drawn at 45°C and intersect with the 135 watt horizontal line in Step 2.
  4. Select the closest heater that intersects above and to the right of the drawn intersecting lines.EXAMPLE: The 200 watt heater would be selected for this application. NOTE – If high temperature operation would have been 65°C or higher, the 300 watt heater would have been appropriate for the application.

Measures can be taken to prevent issues like high cabinet temperatures, so remember your options: Properly calculate and select the number of heaters and the type of technology you need in the cabinet, use heaters with fans to evenly distribute heat and consider adding thermostats to your heaters instead of selecting continuous use heaters to prevent overheating your cabinets.

Transformer Life Extension

Performing transformer life extensions (TLEs) is the practice of improving and upgrading an asset, returning it to near new status. TLEs provide a strategic fleet management option to overcome issues with budget, availability, site constraints and/or grid priorities. Current supply chain constraints and longer lead times magnify these issues, making TLEs a viable option for more asset managers.

As defined here, TLEs are done to upgrade and improve critical systems to add useful life to the asset. In contrast, a transformer rewind would be considered a full transformer rebuild. A rebuild is normally considered when a catastrophic event happens in the main tank and the unique nature of the asset requires a like-for-like replacement of the unit. Rebuilt units also serve as a viable alternative on the secondary market.

A TLE is an option when the main tank elements (core and coil) are in excellent shape, and the peripheral elements are contributing to the asset’s limitations. For example, an ideal transformer for a TLE would have DGA and electrical tests on the main transformer tank which indicate a healthy unit, but its arcing-in-oil load tap changer (LTC) is a potential failure point. In this instance, the main tank is healthy and could provide several years of additional service to the utility; however, the LTC’s condition may force a premature retirement of the asset.

Each utility will have its own process for evaluating assets and determining which assets are TLE candidates, but the four main considerations are as follows:

  • Unique designs and location constraints
  • Health of the candidate units
  • Asset classification
  • Fleet status and availability of new units

When the design of the existing unit or substation does not allow for a change in footprint, a TLE may be the only option. For these assets, TLEs can help overcome physical constraints. In urban areas where transformers can be located inside structures, replacing a transformer can pose significant challenges.
New designs can change the height, width, or length dimensions, changes that may not conform to existing codes. If the main tank is viable, a TLE will allow the asset to be upgraded in place. Managing the TLE within the existing footprint can eliminate the need for a new substation project.

The health of the main tank is the primary driver when considering a TLE. You should evaluate trend data as well as point-in-time reports to determine the viability of the unit. Both DGA and routine electrical tests should be evaluated. Additional data can also help evaluate the health of the unit, including fault history, PD monitoring data, surge counts, historical load profile, etc. Once the data analysis is complete and the unit is determined to be a candidate, a visual inspection should be performed to determine if any internal issues exist.  The decision to perform a TLE is subjective, and each utility will have a threshold for the minimum acceptable condition to move forward.

Two Primary Considerations:  Accounting Treatment and Economic Viability
Each utility will have a lower and upper bound for TLEs. The lower bound may be driven by accounting and asset management rules that prescribe the minimum requirements for capitalization of the project. These requirements can be expressed in terms of dollars vs. asset value or in terms of the number of systems addressed. Accounting principles must be considered as well as regulatory requirements and PUC rate case requirements when establishing parameters to evaluate capital reinvestment in an existing unit.

The upper bound is the crossover point where investment in the existing asset no longer makes financial sense. With any capital project, there will be a cost/benefit calculation. Generally, the viability of the TLE diminishes as the value of the upgrades approaches the value of a new asset. Certain assets will not warrant a TLE. The cost of updating an older asset compared to the cost of a new asset and the ability to establish a longer depreciation schedule on the new asset will naturally drive a decision for the new asset.

Situations exist where the status of the utility fleet, spares, and upcoming expansion projects will influence the TLE decision. When the available budget or number of assets becomes finite and the current assets outstrip available resources, extending the life of existing assets can overcome the shortfall. This can be a temporary strategy to minimize the impact of point-in-time conditions, or it can augment a new unit strategy. TLEs allow utilities to manage expansion, non-viable unit replacement, and service levels to customers.

Once assets are evaluated and identified for TLE, scope of work elements are identified. Each utility will have its own process for evaluating the elements to include in a TLE, but here are six considerations:

  • Load tap changer: upgrade or retrofit
  • Electrical controls: wiring, terminal blocks, gauges, fuses, relays, breakers, and heaters
  • Electrical load handling: bushings, arresters, and leads
  • Fluid cooling and breathing: radiators, fans, pumps, coolers, conservator, and breathers
  • Monitoring and controls systems: alarms, protection, and asset monitoring
  • External tank upgrades: painting, crack repair, and leak mitigation

LTC Updates
One of the weakest systems on a transformer is the LTC. The LTC is a common—and often catastrophic—failure point. Arcing-in-oil units require periodic inspection and maintenance to ensure proper operation, and older vacuum systems do not benefit from the design improvements realized over the last 50 years. Moving from either of these systems to newer technology can extend the life of the transformer and minimize ongoing maintenance costs. Retrofitting the LTC with a new vacuum unit is a significant upgrade to the transformer. However, the ability to upgrade to new vacuum technology depends on the design of the transformer. Each unit must be evaluated and inspected to verify the unit qualifies for an LTC retrofit. Once validated, a complete set of engineering drawings is produced to include the new vacuum LTC. The LTC retrofit is a significant project that can take 30+ weeks from identification to commissioning; however, the total transformer outage time to perform the upgrade is typically only two to three weeks, including LTC throat wall retrofits.

Transformers that utilize outdated, maintenance intensive vacuum tap changers also benefit from upgrades that take place during transformer life extensions. First generation vacuum systems may require more frequent maintenance or adjustment to perform properly. Current generation LTCs improved the reliability of the systems, but older units may require upgrade or replacement to overcome limitations of the earlier designs.

Controls Upgrades
Electrical controls within the transformer are frequently upgraded during the life extension process. Gauges that monitor performance of the unit’s temperature, pressure, tap position, and fluid level are replaced with modern equivalents that have outputs for external monitoring. Control cabinets on field-aged transformers normally have multiple modifications performed by field crews that sometimes render the original control drawings inaccurate. The life extension process involves a reengineering effort that can include replacement of control cabinet wiring as well as components within the control cabinet of an outdated design that are no longer produced, such as fuses and terminals.

Heaters in the control cabinet along with relays and breakers used for auxiliary power handling are frequent sources of unplanned maintenance for field personnel during inspections on aged assets. The TLE investment offers replacement of these 20 to 50-year-old electrical items. Replacing the auxiliary control devices also provides the opportunity to decrease auxiliary voltage from 480V to 240V to accommodate modern safety practices that require arc flash protective equipment for 480V environments.

Electrical Load Handling
Bushings can also be upgraded as part of the TLE process. Due to their flammability, oil-impregnated paper (OIP) bushings can cause significant damage to other components, the main transformer, and even other systems in the substation. Upgrades to resin-impregnated paper (RIP) bushings can provide lower partial discharge, zero headspace, better physical characteristics, and are non-flammable while also offering lower external current leakage and reduced risk of flashover in contaminated coastal environments. Utility design parameters and preferences will influence adoption of this technology; however, a retrofit with RIP bushings can provide an upgrade to the transformer.

External arresters used for lightning and over voltage protection are normally replaced during the TLE upgrades. Aged porcelain-insulated arresters are frequently upgraded to new polymer sheathed designs that offer better performance in industrial and coastal environments. System conditions normally evolve during a transformer’s life cycle, which could provide an opportunity to optimize the arrester’s maximum continuous operating voltage, fault magnitude, and energy ratings for current requirements. Lower temperature operation along with replacement of the bolted electrical connections will reduce arrester maintenance and call-out visits in the future.

Improved Cooling Performance
Upgrades to the cooling system offer multiple benefits to the life of the transformer. Both fans and pumps are rotating assemblies and performance can degrade or fail over time. Upgrading to new fluid handling equipment will help restore the cooling capabilities originally designed into the transformer. In addition to ensuring all components are working, upgrading to modern, higher CFM, lower amp draw, sealed bearing fans—or even adding fans to the system—will help maintain operating temperatures in the main tank. Pump performance is also critical to maintaining the appropriate cooling.

Radiators used in transformer construction evolved from tube-based designs to more efficient plate-based coolers. Radiator performance increases from header pipe design, cooler efficiency, and cleanliness might add years to the life of a field-aged transformer. Modern radiators are more durable with longer lifespans, and most are zinc-coated to further extend life. Radiators will be replaced as part of a scheduled TLE.

Replacement of the conservator bladder, the Buchholz relay, and sudden pressure relay will restore the transformer’s oil handling and fluid-based protection systems. Leaks in the rubber conservator bladder increase moisture contamination within the transformer’s main tank and cause premature degradation of
in-tank insulation. Breathers are often upgraded to self-drying models to reduce O&M costs associated with replacing desiccant. If the transformer is nitrogen blanketed rather than a conservator design, replacement of the cylinder regulator and cylinder itself will be evaluated along with the potential addition of a nitrogen generator system.

The addition of real-time monitoring equipment as part of a TLE upgrade provides the transformer owner the opportunity to reduce maintenance visits. Gas-in-oil monitoring, partial discharge, remote temperature outputs, and bushing monitoring are useful additions to consider when performing a proactive life extension. Trending data that can be accessed remotely helps identify issues early before a critical failure occurs.

External Considerations
Aged transformers frequently suffer from fluid leaks and external tank degradation, such as rusting and welding cracks. The re-gasketing of fluid handling equipment on the transformer during a TLE might also include an external inspection that results in a recommendation to paint the outside of the transformer’s main tank. In salt air contaminated environments, paint deterioration is a frequent maintenance item that can be greatly improved with a deep cleaning and full “top to bottom” recoating. Failed welds and joints can be repaired on-site to decrease future maintenance visits and third-party contractor expenditures.

With a proactive and calculated approach to TLEs, a utility can improve the overall quality of its fleet. TLEs can provide reductions in forced outages, unit failures and maintenance. They can also improve quality of service, maximize spend, and allow for greater flexibility when dealing with spares and expansion. Transformer life extensions are another tool to ensure the reliability of the grid and high service levels while adding years to the life of the assets.

After the life extension, you could have:

  • Solid main tank (tested and inspected prior to project)
  • Modern load tap changer (a weak link in transformers with arcing-in-oil or early vacuum LTCs)
  • New controls and information devices
  • Improved electrical load handling (potentially safer and more reliable than existing equipment)
  • Better cooling performance
  • Upgrades to real time monitoring, and
  • Refreshed externals

Waukesha® UZD® LTC Upgrades and Enhancements

Since its introduction, the Waukesha® UZD® has developed a track record as a trusted and reliable high speed resistance bridging load tap changer (LTC). Today there are more than 6,500 units in service. Over the years, several design modifications have been introduced that have enhanced operation and improved reliability of the Waukesha® UZD® LTC. This Tech Tip will highlight the most significant design upgrades and enhancements that have been made over the years. Detailed information on the purpose and impact of each will be illuminated. We will also provide access to other key technical resources that you can use to better understand the operation and maintenance needs of your Waukesha® UZD® LTC.

The UZD is a three-phase, fully insulated, externally mounted load tap changer designed to be applied to liquid-filled power transformers. It is a 33-position switch designed for plus/minus operation by use of a reversing change-over selector switch. The UZD is rated to carry a maximum through current of 600 amps at a nominal system operating voltage of 34.5 kV.

The main tank of the UZD LTC is comprised of two compartments. The first is an oil-filled switching compartment with a 100 gallon oil capacity. This oil-filled compartment houses the tap selector and the reversing change-over selector switch. The second compartment of the main tank is air-filled and is home to the spring drive mechanism. The spring drive mechanism is connected via driveshaft to the motor drive mechanism which is located in a separate ancillary enclosure called a BUE. The BUE provides mechanical power to the spring drive mechanism and houses electrical control, signaling and protection equipment.

In the following sections, the modifications that will be addressed have been grouped together in subsections based upon their physical location. The subsections represented below are the switching compartment, spring drive compartment and BUE motor drive enclosure. This grouping aids in pinpointing the physical location of each modification and can be utilized for top level planning of inspection and maintenance activities.


The vast majority of modifications developed over the years are applicable to components that are located in the switching compartment. Figure 2 below is a graphic depiction of one of the three identical cast epoxy phase moldings with assembled contacts located in the switching compartment. Each of the sub-assemblies in which modifications have been developed are identified below by call out arrows with labeled item numbers.

Figure 2: UZD Cast Epoxy Phase Molding with Assembled Contacts

Item 1 in Figure 2 above is the moving selector switch assembly. Figure 3 below shows a detailed view of the moving selector switch assembly and an individual view of a contact roller sub-assembly.

Figure 3: Moving Selector Switch Assembly

Our first example of components that have been modified are circled in red above. In order to increase contact pressures, the leaf spring count of each of the sub-assemblies was increased from two to three. Additionally, the design of the pins that secure the rollers was changed from hollow to solid to increase rigidity and reliability. An edge radius was also added to the rollers to reduce wear and a nib was added to the collar to improve alignment in the sub-assembly. These modifications are offered as part of a kit under part number 1030-027K-OEM.

Figure 4 below is an enlarged view of the area of the phase molding that includes the complete reversing change-over selector switch assembly.

Figure 4: Reversing Change-Over Selector Switch Assembly

Figure 5 below is an exploded view of Items 1 and 2 depicted in Figure 4 above. Item 1 is the reversing stationary contact which has seen two modifications to enhance performance. First, the mounting hole was offset to improve alignment between the moving and fixed contact. This change was made in 1991. In 1994, the finish of the contact surface was changed to a 32 micro-inch polish. If your unit is older, you might want to consider changing the reversing stationary contact to the new style which includes both enhancements. The associated part number is 1030-384P.

Item 2 is the reversing moving contact sub-assembly. In 1997, several design changes were incorporated into this sub-assembly to improve performance. The number of contact points and the spring pressures were increased. The springs were moved outside of the current path. A self-aligning feature was built into the main current path and a backup shunt was added. Item 2 is available under part number 1030-371P.

Figure 5: Reversing Switch Moving and Stationary Contacts

Figure 6 below is an exploded view of the main slip contact sub-assembly. This sub-assembly is applied in both the selector and reversing switches. The location of the slip contact sub-assemblies in the fully assembled phase molding are indicated by the circled areas in the figure on the left. The contact tube labeled below as Item 3 has been improved by changing to a machined copper material with thicker tube wall and an integrated shoulder. The original design utilized a steel washer. The changes improved reliability of the sub-assembly and reduced the operating current density. The applicable part number for the improved contact tube is 1030-065P. Item 4 below depicts the slip contacts. In 1992, the design was modified to increase contact surface area. The revised design is available under part number 1030-025K.

Figure 6: Main Slip Contact (Bowtie)

Rounding out the upgrades available for the switching compartment are those that were initially introduced to enhance unit reliability by improving oil quality. In 1988, the original flat door gasket, part number 2011486, was replaced with an “O” ring gasket to achieve better sealing and longer service life. The “O” ring gasket is carried under part number 2007012. For units produced before mid-year 1995, there is a universal entrance tube kit available. This kit allows the customer to add a UZD oil filter without having to drill holes and weld joints in the field. The part number for this kit is 1030-014K. Finally, the 2nd generation auto-recharging dehydrating breather (ARDB2) is recommended. When properly installed, the ARDB2, part number ARDB2-0000, keeps the LTC oil dry and does not require maintenance personnel to periodically change-out the silica gel.


The spring drive compartment is situated adjacent to the selector compartment and is not oil filled. The spring drive allows the tap changer to be operated manually while energized and carrying load. Once charged and activated the stored energy in the spring drive mechanism results in high speed operation and minimum arcing time. The design of the spring drive mechanism ensures that each tap change is consistent and unaffected by voltage interruptions or manual hand cranking speed. Figure 7 below depicts the fully assembled spring drive mechanism as it is mounted in the spring drive compartment.

Figure 7: Spring Drive Mechanism

Figure 7: Spring Drive Mechanism

A magnified view of Item 1 in Figure 7 at right is presented in Figure 8 below. There have been two enhancements made to the brake roller assembly of the UZD. The first is listed as Item 2 below. The nylon brake roller was changed from the original nylon material which was white in color to a new nylon material that is black in color. A lubricated bronze insert was also added to the new black nylon roller to improve wear characteristics. The brake rollers can be purchased individually under part number 1030-043K or they also come installed as part of the full assembly as depicted in Figure 8 below, available under part number 1030-042K. Item 3 in Figure 8 are the brake pads. Originally, the brake pads were secured to the shoes via rivets. In the new design, the pads are glued to the shoe to improve resistance to corrosion in the connected area.

Figure 8: Brake Roller Assembly


The BUE motor drive enclosure shown in Figure 9 below includes the drive motor that charges the spring battery in the spring drive compartment which operates the LTC. The BUE motor drive enclosure is located at a convenient height and includes the operation counter and position indicator for the LTC. The BUE motor drive enclosure is readily accessible at ground level for inspections and maintenance.

Figure 9: BUE Motor Drive Enclosure

Figure 10 below is a graphic of the a BUE motor drive without the enclosure. There have been three notable enhancements made to the BUE motor drive. The location of each of the enhancements has been indicated in Figure 10 below.

Figure 10: BUE Motor Drive

The motor drive limit switch labeled as Item 1 above was changed in 2010. Of note is the fact that the old and new switches are not interchangeable. Item 2 above is the limit switch gear. In 2005, the gear material was changed from nylon to brass. This change was made to improve reliability of the gear assembly. The gear and associated accessories are available as a kit under part number 1030-1741K.

The most significant change made to the BUE is the drive motor itself. The original ASEA drive motor was changed to a Bodine motor in 1991. At the time this change was made, the motor mount assembly was modified to accommodate the taller American Solenoid limit switches. These switches are blue in color. The drive motor and associated mounting hardware as shown in Figure 11 below are offered as a kit under part number 1030-031K.

Figure 11: Bodine Motor Replacement Kit

As the OEM for the UZD load tap changer, we have developed several resources designed to assist our customers in understanding, operating and maintaining the UZD. Specifically, we offer the following UZD resources for download from our website:
• UZD 3D Catalog
• UZD Maintenance Manual
• UZD Technical Manual
• UZD Brochure

We welcome calls from customers seeking technical support on the UZD. If you need assistance, we will gladly work with you to support your needs on the UZD.

To learn more about all components available from the Waukesha® Components, contact a member of our sales team at 1-800-338-5526. Also, don’t forget about our library of easy-to-navigate, 3D catalogs designed to help you quickly identify and locate hard-to-find components for LTCs and oil circuit breakers. While a link is included above to the UZD catalog, the library also contains catalogs for most other major legacy LTCs and several of the Waukesha® Components’ line of Transformer Health Products®.

Westinghouse UTT Upgrade Series: Part 3 of 3

Upgrading your UTT, UTT-A or UTT-A70 to the UTT-B and RMT-1 Style Transfer Switches

In this white paper, we will discuss possible upgrades for the transfer switch assembly on the Westinghouse UTT Series load tap changer (LTC). These upgrades address areas of the transfer switch that are prone to failure due to overheating and carbon buildup and are applicable to the UTT, UTT-A, UTT-A70 and UTT-B models. Form, fit, and function of these upgrades are of the highest quality available.

Each phase of a 3-phase UTT LTC contains two transfer switch assemblies. Figure 1 below contains 3-D models of individual phase panels for each of the different UTT Series LTC models. Red arrows indicate areas where overheating and coking typically occur. These arrows also help visually identify areas where differences exist in the individual model designs. Additionally, the area of the phase panel that includes the transfer switches has been identified in a red rectangle.

Figure 2 below depicts the transfer switch portion of a UTT phase panel. The stationary and moving contact portion of the transfer switch assemblies are circled for ease of identification. You will note that two transfer switch contact assemblies are included for each phase, one on either side of each phase panel.  When standing in front of the open inspection door, the front transfer contact assembly on each phase is readily visible on the right hand side of each phase panel and can be easily inspected. The second transfer contact assembly for each phase is more difficult to inspect, as it is in the back of the compartment and is most often obscured from sight by the leads. In order to complete a thorough inspection, care must be taken to inspect all six transfer switch contact assemblies.

By upgrading the transfer switch contact assemblies of the UTT, UTT-A and UTT-A70 to the UTT-B design, the risk of overheating and carbon buildup in the stationary contact areas is fundamentally reduced. Figure 3 below depicts the transfer switch stationary contact assembly of a UTT. While slight differences exist between the UTT, UTT-A and UTT-A70 designs, the UTT design is sufficient to represent all three for the purpose of illustrating the improvements incorporated into the UTT-B design. Figure 4 shows the improved transfer switch stationary contact assembly of the UTT-B. The transfer switch stationary contact assembly design utilized in the UTT-B is the same design that was applied in the RMT-1. When comparing the two transfer switch stationary contact assemblies presented in Figures 3 and 4 below, the following design enhancements are readily evident:

  • Cross sectional area of the stationary contact fingers is significantly larger in the
  • UTT-B design, thereby resulting in a sizable increase in current carrying capability
  • Stationary contact plates of the UTT-B design are substantially larger, yielding more surface area immersed in oil; as a result, the amount of heat dissipated in the oil is much greater in the UTT-B design
  • A braided copper jumper has been incorporated into the UTT-B design, allowing the primary flow of current to be from the finger contact into the plate thus bypassing the static spring-loaded joint of the finger contact

Westinghouse UTT Upgrade Series: Part 2 of 3

Upgrading your UTT, UTT-A or UTT-A70 to the UTT-B Style Selector Switch

In this installment, we will discuss upgrades for the selector switch assembly of your Westinghouse UTT Series load tap changer (LTC). These upgrades address areas of the selector switch that are prone to failure due to overheating and carbon buildup and are applicable to the UTT, UTT-A and UTT-A70 models.

Each phase of a 3-phase LTC contains a selector switch. Below are 3-D models of individual phase panels for each of the different UTT Series LTC models. Red arrows indicate areas where overheating and coking typically occur. These arrows also help visually identify areas where there are differences in the designs of the individual models.

Figures 1 and 2 below depict the flip side of the moving contact arm assembly in which the contacts are clearly visible. Arrows indicate areas of the moving contact arm assembly where overheating and carbon buildup are most likely to occur. Figure 1 depicts the UTT model and Figure 2 depicts the UTT-A/UTT-A70 models.

By upgrading the moving contact assembly of the UTT, UTT-A, UTT-A70 to the UTT-B design, the risk of overheating and carbon buildup in the contact areas is fundamentally reduced. Figure 3 below depicts the contact arm assembly of a UTT-B with the contacts exposed. The upgrade to the UTT-B design reduces the number of contact fingers from four (4) to two (2) and the number of non-wiping fingers from four (4) to zero (0).

In addition to the upgraded contact configuration, the collector rings on the UTT-B design are offered in an improved “split” design for phases A and B. Figure 4 below indicates the position of the collector rings. The split design allows for worn collector rings on phases A and B to be replaced in the field without untanking the LTC.

Form, fit and function are exactly the same between the different designs, but the selector switch upgrades presented above offer the following benefits:

  • 50% reduction in spring-loaded contact fingers, reducing risk of overheating and coking
  • Elimination of all non-wiping spring-loaded contacts, reducing risk of overheating and coking
  • Significant reduction in time required for collector ring replacement without untanking the unit

Each upgrade kit from Waukesha® Components comes with detailed instructions for installing the upgraded designs. We also offer standard and customized component kit cases. These cases offer the following unique set of benefits:

  • Parts are easier to pull from inventory and issue to the maintenance jobs
  • All key parts are included for easy and safe transport to the work location
  • No need for field personnel to keep lists of components consumed during maintenance
  • Cases provide a better means of protection and storage for the components
  • Quick and easy to replenish after completion of field maintenance

Our 30-year history of providing replacement parts for the majority of OEM LTCs has allowed us to develop the capability to confidently engineer, manufacture and support a myriad of design-enhanced replacement parts. You can be confident that the Waukesha® Components version of the UTT-B style selector switch components will match the performance of the OEM part at a fraction of the cost.

Similar upgrades are available for the UTT, UTT-A and UTT-A70 transfer switches. These other upgrades will be covered in detail in the third installment of this three-part Tech Tip series.

To learn more about all upgrades available for the UTT Series LTC contact a member of our sales team at 1-800-338-5526. Also, don’t forget about our library of easy-to-navigate, 3D catalogs designed to help you quickly identify and locate hard-to-find components for LTCs and oil circuit breakers, while also including one for the Waukesha® Components’ line of Transformer Health Products®.

​Westinghouse UTT Upgrade Series: Part 1 of 3

Upgrading to the RMT-1 Style Reversing Switch

Did you know that many affordable upgrades are available for your Westinghouse UTT Series load tap changer (LTC) that can be installed during your next maintenance rotation? These upgrades are designed to extend maintenance intervals while improving reliability of the unit. This is the first in a three-part series intended to introduce you to upgrades currently available for the Westinghouse UTT series. This installment will focus on upgrading to the RMT-1 style reversing switch.

Upgrading to the RMT-1 style reversing switch is highly recommended since the RMT-1 style is a self-aligning design that offers a higher current (amps) capacity than any other UTT design. Table 1 below contains a summary of the designations and ratings of Westinghouse UTT LTCs:

To quickly identify what type of tap changer model you have, use the following guidelines:

  • UTT: Two windows into cam switch compartment front and side; position indicator from “ON POS” indication side
  • UTT-A: One window through swinging door; position indicator front “ON-POS” indication, open door
  • UTT-A70: One window through swinging door; side position indicator tilted down 30 degrees, “ON-POS” indication can only be seen when the cam switch compartment door is open
  • UTT-B: No window through swinging door; side position indicator tilted down 30 degrees, “ON-POS” indication can only be seen when the cam switch compartment door is open
  • RMT-1: No window through swinging door; side position indicator boss round

Below are 3-D models of phase panels for each of the different UTT Series LTC models. Red arrows indicate areas where overheating and coking typically occur. These arrows also help visually identify differences between the UTT models.

Below is a different view of the moving selector switches for the UTT-A/A70 and UTT. Red arrows again point out common areas most affected by overheating and coking.

Now that we have shown the different model types with their amperage ratings and how to identify them, we will describe the benefits of upgrading your standard reversing switch to the RMT-1 style.

The purpose of the reversing switch is to select raise or lower connection of a tapped winding section. Each phase will contain a reversing switch on a 3-phase LTC. The figures below show a side-by-side comparison of the standard reversing switch designs and the RMT-1.

Form, fit and function are exactly the same between the different designs, but the RMT-1 offers the following benefits:

  • Offers increased current rating of 1320 amps vs 1000 amps
  • Operates at lower temperatures for a given load current
  • Self-aligns for better mechanical operation and smoother transition when
    passing through neutral
  • Moving contact utilizes six pair of contact fingers with high spring pressure vs two pair for the UTT-B model and four pair for the UTT/UTT-A/UTT-A70 models, allowing more current paths with oil between them for better thermal performance
  • Eliminates static, spring-loaded mating contact surfaces and replaces with moving contact surfaces that help ensure contact filming and heating are less likely to occur

Each upgrade kit from Waukesha® Components comes with detailed instructions for installing the upgraded designs. Our 30-year history of providing replacement parts for the majority of OEM LTCs allowed us to develop the capability to confidently engineer, manufacture and support a myriad of design-enhanced replacement parts. You can be confident that the Waukesha® Components version of the RMT-1 style reversing switch will match the performance of the OEM part at a fraction of the cost.

Similar upgrades are available for the UTT, UTT-A and UTT-A70 selector and transfer switches. These other upgrades will be covered in detail in the second and third installments of this three-part Tech Tip series.

To learn more about all upgrades available for the UTT Series LTC, contact a member of our sales team at 1-800-338-5526. Also, don’t forget about our library of easy-to-navigate, 3D catalogs designed to help you quickly identify and locate hard-to-find components for LTCs and oil circuit breakers, while also including one for the Waukesha® Components’ line of Transformer Health Products®.

Why Oil Analysis is Important to the Health of Your Load Tap Changer

Maintaining your load tap changer fleet is crucial to the continuous, safe operation of your transformers. Over time, contacts and other moving parts can start to show wear from repeated use or become damaged from intense heating inside the LTC. Many countermeasures exist for preventing LTC malfunction and critical failure, evolving over the years as the industry continues to study the effects of tap changer operations in oil.

Time-based maintenance, while oftentimes effective for routinely inspecting and maintaining all parts in good condition, can become expensive quickly, especially with large LTC fleets. Draining oil, opening the unit(s) and inspecting for wear or damage adds time and money that can be avoided with other, more sophisticated diagnostic tools.

Dissolved Gas Analysis, or DGA, analyzes the gasses captured within the oil, such as hydrogen, methane, ethane, ethylene and acetylene, to form a good diagnostic tool for the LTC. Prior to 1995, LTC DGA was considered of no value. Even today, dissolved gas and oil quality analysis are not widely used on a regular basis to assess and troubleshoot LTCs. Annual oil sampling for DGA coupled with online oil filtration systems can extend major maintenance intervals to 10+ years. As temperature inside the LTC increases, the amount of combustible gasses created via arcing and heating are dissolved into the oil, increasing over time. By studying the rise and fall of these gasses, detection of low, moderate and severe heating conditions are found without the cost of opening the unit for visual inspection. Severe heating conditions can lead to a critical fault and malfunction of the tap changer.

The type of fault can be indicated by the dominant gas in the LTC, based on an increasing fault temperature that differs for each combustible gas. The ratios of each gas indicate the presence of heating, coking and arcing. While no industry accepted standards exist, we can analyze these gasses over time to form an idea of what is happening inside the tank.

One ratio to consider is ethylene over acetylene for arcing-in-oil type LTCs (both resistive and reactive) to predict when inspection of the load tap changer should occur. Because certain gasses appear more frequently as the fault temperature increases, we can detect low, moderate and severe heating conditions over time based on how much more ethylene is present compared to acetylene. These ratios are independent to the number of operations in the tap changer and also resistant to changes due to loss of gasses to the atmosphere. For vacuum-type LTCs, tracking the total combustible gas count over time can give some indication as to when the unit should be inspected.

Another ratio that can be considered is the Stenestam Ratio, which looks at the sum of methane, ethane and ethylene compared to acetylene.

Important to note that for each ratio calculation, a minimum count of gasses needs to exist before the ratio is effective. With small counts of gas, the ratio can vary wildly up and down the spectrum and have misleading results.

The Duval triangle is another great tool for trending heating and arcing gasses for LTCs. By plotting the gasses on the triangle, units moving from the “N” region (normal operation condition) to a fault condition can be detected. Coupled with infrared scans while in service, units headed towards failure can be reasonably confirmed.

Five zones of abnormal operation or faults are identified in the Triangle for LTCs of the oil type:
T3 = severe thermal fault with heavy coking of contacts (T > 700°C);
T2 = severe thermal fault with coking of contacts (300°C < T < 700°C);
X3 = fault T3 or T2 in progress, with light coking or increased electrical resistance of contacts;
D1 = abnormal discharges of low energy D1;
X1 = abnormal discharges of low energy D1, or thermal fault in progress;
N = Normal Operation

Note: Minimum gas levels should be >10ppm to apply this analysis method

While industry guides exist for analyzing DGA results, model-specific industry accepted limits are NOT available today. Generating such guidelines requires a significant number of LTCs and samples to form sound statistical results. Gas generation rates can vary due to model, design vintage, breathing type, frequency of operation and even maintenance practices across a fleet.

With all the discussion above, DGA is only half of the LTC condition assessment equation. Oil quality analysis is equally important for determining the health of your tap changer. Measuring key parameters such as inter-facial tension (IFT), acidity and water content, these tests provide an oil quality index and relative saturation that can be utilized as an additional indicator for chemical changes in the oil. Fluid quality index – (Acidity x 1000) / IFT – coupled with comparing the N2/O2 ratio in oil on free breathing units can detect the onset of sludge formation and contact filming before coking and contact damage occurs.

As moisture and oxygen in the oil increase, the heat from loading acts as an accelerant to oil oxidation and sludge formation. This contact sludge, or film, adds resistance to the contact which, in turn, increases heating even further. As this resistance rises, the rate of heating and sludge increases as well, leading to “thermal runaway” and formation of coke.

Oil chemistry affects can be mitigated. Monitor oil quality and DGA annually and trend results. Determine oil quality index – (Acidity x 1000) / IFT – and replace oil when quality index is greater than 18 during maintenance. Use online oil filtration on arcing-in-oil reactive and resistive-type LTCs. On units flagged by oil analysis, use infrared in conjunction with oil testing data to verify temperature differences between the LTC and main tank.


For an example of how both DGA results and oil quality data can be utilized as tools for LTC assessment, let’s take a look at the data from this UZD:

The ethylene over acetylene ratio of 0.11 is “normal” according to the accepted guidelines, but the fluid quality index of 22 triggered an inspection of the tap changer (should be below 18 under normal operation). If DGA results alone were used, this unit likely would not have been flagged for inspection, as it appears to be in the normal operation range when plotted on the Duval Triangle.


Upon opening the unit, one can clearly see that this was a good catch, as film was beginning to form on many components of the LTC. Thermal runaway/coking may have unexpectedly occurred before the next maintenance cycle.

Using traditional DGA alongside oil quality data, Waukesha® Components has formulated a patented algorithm to analyze your fleet data and create a prioritized listing of units most in need of maintenance before significant damage occurs. With a large population of load tap changers and enough statistical data points, Waukesha® Components can provide a FREE fleet consultation, giving a detailed, targeted approach to maintenance greatly exceeding industry standard DGA analysis guidelines.