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Implementation of a Condition Based Assessment Program for Load Tap Changers atSacramento Municipal Utility District

Gary Hoffman, Advanced Power TechnologiesGarry Sparks, Sacramento Municipal Utility District

Abstract

The cost and lead time to replace power transformers has become increasingly expensive andlengthy in recent years. With an ever aging population of power transformers on the powersystem, there is a need to consider methodologies which allow users to have better information onthe condition of these units. Many of this aging fleet have Load Tap Changers (LTC) wherecondition based assessment (CBA) is important in preventing unplanned outages and unscheduledasset replacement. Up to now, the primary solution for users is to periodically inspect thetransformer, including the LTC, using thermal imaging and oil sampling for the purpose ofperforming Dissolved Gas Analysis (DGA). When heating and combustible gases are observed inthe LTC, it is difficult to determine if the problem is just beginning or close to causing a failure ofthe LTC. Hot metal gases can be present, albeit at lower concentrations, even at the early onset ofa problem. This makes it difficult to know if the outage must be taken immediately, or if theoutage can be scheduled at a more convenient time.

In “2005” Sacramento Municipal Utility District (SMUD) embarked on a program to implement aWorld-class condition based assessment program of their Power Transformers. This programadded all new technologies available to assist the individual responsible for TransformerMaintenance in making informed decisions. One of the newer technologies is the LTCTemperature Differential Equipment. This equipment has been installed on all FPE andSiemanTLH21 tap changers. The equipment data is downloaded every 3 months and thenevaluated for any change. Also used in the overall transformer program is DGA analysis of theload tap changer and the main tank, Ultra Sonic Testing, Vibration Testing and Sweep FrequencyAnalysis. The transformers are also checked yearly with an infrared (IR) camera.

The success of the LTC temperature Differential equipment has been outstanding. SMUD hasidentified 6 transformers that would have probably had a LTC failure and the worse case outcomeof any/all of these could have been a complete transformer failure. These finds were between theDGA and IR testing. The monitoring rate for these cases had been set to 1 hour.

The greatest find with this tool is that it is so sensitive that individual taps that are heating can beidentified well before that LTC is in trouble. SMUD reviewed the DGA and had the unit IR againand neither test indicated that a problem was present yet.

This paper will address the methodology used to provide the necessary data to make importantdecisions regarding the condition of SMUD’s LTC’s. It will also discuss the models implementedto interpret the data along with success and lessons learned during the implementation of theprogram.

Introduction

In a transformer equipped with a properly operating energized LTC, the load-tap-changingcompartment, or LTC tank containing the tap selection switches surrounded by insulating fluid,generates little to no heat. Since very little heat is generated within the load-tap-changingcompartment, heat generated within the main tank dominates the heating of the load-tap-changing

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compartment. This main tank heating can be caused from I2R losses in the winding and leads, oreddy currents and stray flux. Within the LTC tank, increased contact resistance, looseconnections or a mechanism malfunction can cause abnormal heating. The heating can evolveover a long period of time or can evolve quickly. Both problems can lead to failure of thetransformer, which could require rebuilding or replacement.

Traditionally, periodic infrared imaging of the LTC tank and the main tank along with DissolvedGas Analysis of the LTC tank oil has been the primary methods used to find a problem within theload-tap-changing compartment. While infrared and DGA are important maintenance strategies,sometimes problems begin evolving shortly after infrared imagery and DGA inspection. In thefirst case, problems can be missed leading to failure prior to the next inspection, or if done toosoon, the problem may not be visible once the tank is drained and opened for inspection.

Therefore, a strategy of continuous monitoring of the main tank and LTC tank together providesan ability to know exactly when a problem begins within the LTC. This will help better planmaintenance and avert a failure to very important piece of equipment within the substation andyour system.

Measurement Methodologies

There are many methods to measure the insulating fluid’s temperature in both the main and LTCtank. These include:

Thermocouples Resistive Temperature Detector (RTD) Thermistors Semiconductor Devices

Thermocouples while accurate and stable have not found widespread use in liquid filledtransformers due to cable interface issues. The resistance of Thermistors has a very broaddynamic range requiring high precision analog to digital converters. Also because of the broaddynamic range it is difficult to manage the measurement without introducing self heating that in-turn affects measurement accuracy. In addition, these devices have memory which furtherdegrades measurement accuracy. Regarding semiconductor measurement devices, these have notfound favor due to the fact that ground potential rises could damage the very device used tomeasure temperature.

Of these methods, the RTD is the primary method used to electronically monitor the temperatureof both the main and LTC tanks. In this case two separate RTD’s are used, one in the main tankmeasuring top oil and the second measuring the temperature within the LTC tank.

There are numerous RTD materials available including Platinum, Nickel, Copper, and alloys ofNickel and Iron also known as BALCO elements. All have resistance characteristics that arerelatively stable and repeatable over their temperature range. The Table 1 summarizes thenominal resistance, resistance change per degree Celsius and the relative cost. The nominalresistance of all elements is at 0° C except BALCO which is at 23° C.

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RTD NominalResistance in

Ohms

Change inResistanceOhms/°C

Cost

Copper 10 0.39 Low

Nickel 120 ~ 0.7 Low

Platinum 100 0.385 Low

Platinum 1000 3.85 High

BALCO 1000 ~ 4.5 Low

Table 1

While most manufacturers can make an accurate RTD from these materials, the real issue comesdown to the instrument’s measurement accuracy over time and the likelihood of periodiccalibration. Therefore, the user should be satisfied that the manufacture of the device used tomeasure the resistance understands the drift characteristics of their measurement circuits to knowwhether the instrument they are considering will require frequent calibration over the life of theinstallation.

The next issue relates to the tank temperature measurements and probe construction. As a rule isit always best to monitor the main and LTC tanks with the same type of probe. For example onnew transformers or re-built, when possible, the user should ask the transformer manufacturer orre-builder to install a thermometer well into the load-tap-changing compartment. However, forretrofit onto an existing transformer it may not be practical to install a thermometer well. In thiscase, the user is left with two options: Use a surface mount probe for the LTC tank and use athermometer well probe on the main tank (which can also be used to calculate windingtemperature and control cooling). The second option is to use two probes of the same design forboth the main and LTC tanks. This includes using two thermometer well probes or two surfacemount probes of the same design. Users have reported successful detection of an impendingfailure in the LTC tank through use of a top oil probe installed in the thermometer well in themain tank and a magnetic mount surface probe on the LTC tank. [1]

If a surface mount probe is required, the user has a choice between using a probe adhered by anadhesive or a magnetic mount design. Regardless of the type, there are three factors that shouldbe considered:

Choose a surface mount probe that is compatible with the maximum tank temperature.

Choose a surface mounted probe that is not affected by direct exposure to sunlight.

Choose a surface mount probe where the accuracy does not degrade with increasing tanktemperature.

Whenever a surface mount probe is used it is recommended that suitable thermal grease be usedbetween the measurement element surface and the tank wall. Figure 1 illustrates the surfacewhere thermal grease should be applied on a magnetic mount probe.

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Figure 1

In addition, if using a magnetic surface mount probe, a bead of RTV should be placed around theperimeter of the probe. This should be done for two reasons: First, moisture will get behind theprobe and reduce the magnetic force. Second, transformers tend to bang and vibrate and theprobe may move from its required position on the tank. Figure 2 illustrates the application ofRTV.

Figure 2

One final note is with regard to transformer size. Larger size transformers have proportionallylarger LTC tanks. A good rule of thumb is to use two LTC tank probes on transformers 80 MVAand larger. These probes should be installed on opposite ends of the tank.

RTV Seal

Tank Wall

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Probe Placement Strategies

One important aspect to reliably detect a heating problem in the LTC tank is through correctplacement of the temperature probes in or on the main and LTC tanks. We will cover first theapplication of temperature probes on a new transformer.

On a new transformer, the thermometer well to accept the probe on the main tank should be thelevel where the top oil probe will be installed. The placement on the thermometer well LTC tankshould be at level from the minimum oil level of the LTC tank to no lower than the middle of thetank. Figure 3 illustrates the probe placement where two magnetic surface mount probes are used.

Figure 3On retrofit applications as mentioned previously, it is ideal to use two probes of the same type.That is, either two thermometer well probes or two magnetic probes. However, in many casesusing two magnetic probes is not practical, as it may be desirable to use an ElectronicTemperature Monitor (ETM) that can monitor winding temperature and control cooling. In thiscase it should be noted that although a magnetic surface mount probe can be used for top oil, thetank surface is normally three to five degrees Celsius cooler than the actual oil temperature.

Another common retrofit scenario is that the user may want to replace a faulty top oilthermometer with an ETM, and at the same time, gain the additional benefits of monitoring theLTC tank differential temperature.

The placement of the main and LTC tank probes in a retrofit application is similar to that for anew transformer. If a magnetic probe is used on the main tank, it must be at the same elevation asthe existing thermometer well to measure top oil, but at least 26.4 cm (12 in) from the heated wellif the transformer is so equipped and not disabled. For the LTC tank, the magnetic surface mountprobe should be mounted on the side of the tank at an elevation not above the minimum oil levelbut not below the center of the tank. When possible a non-contact infrared thermometer should beemployed to check for the optimal probe placement on the LTC tank. Figure 4 illustrates anapplication of a thermometer well probe in the main tank and magnetic surface mount probe onthe LTC tank. [1]

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Figure 4

As a final note on probe placement, proper probe selection should be considered before probeplacement. For example, probes that are not immune from the affects of sunlight should beavoided as it will dictate that the magnetic probe be mounted away from direct sunlight exposure.This is not always possible or practical.

Detection Methodologies

Once a system is installed there are several ways that data can be collected and managed. Someusers may wish to convey the data from the measurement device on the transformer to a centralmaintenance data collection and notification system. Some customers with limited ability to getthis data back will need to rely on local data collection or data logging and alarm generation.Since the Case Study of this paper will deal with using remote monitoring, this section willdiscuss an alternative strategy of using pre-programmed set-points to alert Dispatch through analarm that there is a thermal problem within the LTC tank.

There are two possible heating events that can occur within the LTC tank. The first are problemsthat evolve slowly over time. One such problem is coking, or carbonization of the contacts. Overtime this carbonization will build to a point where the I2R losses are so high that the metal melts.The second are quickly evolving problems which cause the temperature to rapidly increase withinthe LTC tank. This rapid temperature will cause sudden pressure increases and generation ofcombustible gases at a very high rate.

Figure 5 illustrates the detection methodology for slowly evolving problems. Normally the maintank or top oil temperature is greater than the LTC tank temperature, as the LTC tank is thermallydriven from the main tank. However, during a sunny morning when the load on the transformer islower, the LTC tank may exceed the main tank temperature by as much as 10 to 15 degreesCelsius. This occurs because the LTC tank is dimensionally smaller than the main tank and willheat up more quickly when the transformer is lightly loaded. The solution as shown in Figure 5 isto employ a time delay that requires the difference temperature between the LTC and main tankto stay above a set-point of 5° C for at least four hours in colder climates and six to eight hours in

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warmer climates. Essentially, we wait to make sure that the main tank temperature comes intoequilibrium with the LTC tank temperature. If the monitoring system has local data logging, theuser can either retrieve the information remotely or travel to the station to gather the logged datafor review.

Figure 5

Since not all abnormal heating problems evolve slowly, there is a need for an algorithm to detectquickly evolving problems. This method must distinguish between a true rapid temperatureincrease within the LTC tank and a breeze which causes a temperature drop, but the temperaturerebounds once the breeze ceases. One method to do this is shown in Figure 6.

Temperature

Time

LTC Set Point

LTC DIFF Pickup

LTC Tank Temperature

Top Oil Temperature

LTC Tank Temp - Top Oil Temp

LTC DIFF Drop Out

LTC Pickup Timer

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Figure 6

The algorithm watches the LTC differential temperature increase over a set period of time. If thetemperature rises 20° C in 20 minutes it is likely that there is a serious problem within the LTCtank that requires immediate attention.

The two methods together allow the user to detect most problems developing in the LTC tank. [2]

Recently new methodologies have been developed that further the goal of CBA of Load TapChangers. One such method is to track LTC differential temperature versus tap position. [3] Thiscapability gives the user ability to know where the problem is occurring and thus allowsadditional degrees of freedom to operate their system more intelligently.

Case Study

This case study is on a FPE TC-25 Load Tap Changer. The tap changer is monitored on a 30 minsample rate. This rate was chosen due to the tap changer past history. The data is downloadedevery three months and the data is then reviewed by a maintenance engineer.

The sample of results of the LTC Temperature Monitor (Figure 7) shown below was taken inMarch of this year. The red line is the top oil temperature. The blue line is the temperature deltabetween top oil and the LTC tank oil. The second sample (Figure 8) was taken in June of thisyear. Note that the temperature delta in March was around 10-11 degrees at its highest point. InJune the temperature delta was 15 degrees.

Temperature

Time

LTCDIFF Rate of Rise Set Point

LTC Tank Temperature

Top Oil Temperature

LTCDIFF

UNITTRIPSOFF

RATE

RISE

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Figure 7

Figure 8

Figure 9 is a photo of the contact and the coking that was taking place, note that this washappening only on one phase.

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Figure 9

Figures 10 and 11 reflect the digital photo and the IR image that was added to the analysis of thetap changer.

Figure 10

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Figure 11

The transformer was taken out of service and repaired.

Why did this happen?

Poor Manufacturing

Miss Aligned Contacts

Movable Contacts Pressure Not Correct

Conclusions

Continuous monitoring of both the main tank and LTC tank temperature has been proven toprovide the necessary early warning of a problem developing within the LTC tank. Since thisprogram has been implemented at SMUD they have not had a Load Tap Changer failure.

References

[1] C.T. Emoto, R. Tamayo, G.R. Hoffman: “Implementation of a Predictive MaintenanceSystem”, Transmission and Distribution Conference and Exhibition, 2005/2006 IEEEPES

[2] G.R. Hoffman: “Sensing load tap changer (LTC) conditions”, U.S. Patent 7,323,852

[3] G.R. Hoffman, T.C. Tennille: “Apparatus and method for monitoring tap positions ofload tap changer”, U.S. Patent 7,417,411