POWER TRANSFORMER AUTOMATIC TAP CHANGER CONTROLS BASIC INFORMATION

How Transformer Tap Changer Control Works?

The tap-changing mechanism is usually motor-driven and can be controlled manually and automatically. In the automatic mode, the output voltage of the transformer is compared to a reference voltage and a raise/lower signal is sent to the tap changer motor when the output voltage falls outside a specified band, called a dead band.

The dead band must not be smaller than the voltage between taps; otherwise, it will ‘‘hunt’’ endlessly and burn up the tap changer. The dead band must not be too wide, however, because the purpose of voltage regulation will be defeated.

Ordinarily, the dead band is set to a voltage between two and three tap increments. With the tap voltage typically around 1% of the nominal secondary voltage, this provides regulation within a 2–3% range.

If two or more transformers with load tap changers are connected in parallel, then it is important that all transformers operate at the same transformer turns ratio; otherwise, excessive circulating KVAR results. The way this is implemented is to have the tap changer on one of the parallel transformers control voltage as the lead tap changer, with the other tap changers as the followers.

Circuitry is installed on the followers to sense the direction of reactive power flow through each transformer. If too much reactive power is flowing from the primary to the secondary, then its secondary taps are lowered.

If too much reactive power is flowing from the secondary to the primary, then secondary taps are raised. Appropriate dead bands are established to prevent the LTCs from hunting and to limit interactions among the tap changer controls.

One such control scheme, called a load-balancing method, is depicted in Figure 6.16 for three transformers with voltage regulators supplying a common load bus.

  FIGURE 6.16 A load-balancing control scheme for three parallel transformers with load tap changers.

If the three transformer impedances equal and if the transformers are set on the proper tap positions, the transformer secondary currents will all be in phase with the load current and there will be no current unbalance.

If one or more transformer is set on the wrong tap, circulating currents will flow in all three transformers. The principle of operation of the load-balancing method is to separate each of the transformer secondary currents into a load current component and a circulating-current component. The transformer secondary currents flow through current transformers, labeled CT 1, CT 2, and CT 3 in Figure 6.16.

The currents at the CT secondaries split into two paths at each of the CT secondary windings. Path 1 (to the right) goes through a set of auxiliary transformers, labeled CT 4, CT 5, and CT 6. The secondaries of the auxiliary CTs are connected in series, forcing the currents in all three primary windings equal one another, each being one-third of the total load current. By default, the unbalance-current components must flow in path 2 to the left.

Each of the circulating-current components (also called unbalanced current components) flows through an inductive reactance element, called a paralleling reactor. The paralleling reactors are labeled jX in Figure 6.16. In general, the unbalance-current components of the three transformers are unequal.

The voltages developed across the paralleling reactors are added to the sensed voltages at the secondary windings of the main transformers, which are used to control the movement of the tap changers.

If transformer 1 is on a higher tap position than transformer 2 or transformer 3, the unbalanced currents flowing through the parallel reactors increase the sensed voltage at transformer 1 and reduce the sensed voltages at transformers 2 and 3.

This causes transformer 1 to lower its taps and transformers 2 and 3 to raise their taps. If transformer 1 is on a lower tap position than transformers 2 and 3, the unbalanced currents flowing through the parallel reactors decrease the sensed voltage at transformer 1 and increase the sensed voltages at transformers 2 and 3. This causes transformer 1 to raise its taps and transformers 2 and 3 to lower their taps.

TRANSFORMER GAS IN OIL ANALYSIS BASIC INFORMATION AND TUTORIALS

Various research organizations, such as Westinghouse Electric Corporation, Analytical Associates, Inc., that did extensive research in the 1970s quickly led to the widespread use of dissolved gas-in-oil analysis as a predictive maintenance tool [4]. There is also an extensive bibliography on this subject found in IEEE Std. C57.104–1991 [5].

The basic theory is straightforward: Transformer dielectric fluids are refined from petroleum and are very complex mixtures containing aromatic, naphthenic, and paraffinic hydrocarbons. At high temperatures, some of these molecules break down into hydrogen plus small hydrocarbon molecules such as, methane, ethane, ethylene, acetylene, propane, and propylene. This process is known as cracking.

The kraft paper materials that are used to insulate transformer windings are made up of cellulose. At high temperatures, cellulose oxidizes to form carbon dioxide (CO2), carbon monoxide (CO) and water (H2O). High concentrations of CO2 and or CO are indications of overheated windings.

All of the breakdown products are gases that dissolve readily in transformer oil in different concentrations, depending on the specific gas and the temperatures that produce them. By taking samples of transformer insulating oil, extracting the dissolved gases and doing a quantitative analysis of the various gases in the samples through gas chromatography, it is possible to infer the temperatures at the sites where these gases were produced.

At temperatures below 150°C, transformer oil starts breaking down into methane (CH4) and ethane (C2H6). At temperatures above 150°C, ethylene (C2H4) begins to be produced in large quantities while the concentration of ethane decreases.

At around 600°C, the ethylene production peaks while the concentration of methane continues to increase. Acetylene (C2H2) production starts at around 600°C and methane concentration peaks at 1000°C. Hydrogen (H2) production is not significant below 700°C and continues to increase along with acetylene at temperatures above 1400°C.

Therefore, the relative concentrations of the key gases change over a wide range of temperature. This is basis for the application of dissolved gas in-oil analysis for predictive and diagnostic use. An approximate formula uses the ratio of C2H4/C2H6 to derive the temperature of oil decomposition between 300°C and 800°C:

T(°C) = 100 C2H4/C2H6 + 150

The so-called Rogers ratio method takes the ratios of several key gases into account to develop a code that is supposed to give an indication of what is causing the evolution of gas. The codes for the four ratio method are given in Table 8.2. A fairly detailed diagnosis of transformer trouble can be derived from various combinations of codes, shown in Table 8.3.

The diagnoses shown above were derived from empirical observation. The problem with the four-ratio Rogers code is that a code generated from the gas concentrations will often not match any of the ‘‘known’’ diagnoses.

So like a rare disease with strange symptoms, many cases of transformer trouble cannot be diagnosed at all using this method. Another method, called the three-ratio method, sometimes works when the four-ratio method does not.

In the three-ratio method, the values of A, B, and C are given in Table 8.4 with the corresponding diagnoses for the various combinations given in Table 8.5. Not only are the ratios of the key gases important, but the total quantity of dissolved gas and the rate of increase are also important factors in making a diagnosis. One of the criteria for making a judgment call is the total combustible gas concentration. The combustible gases include H2, CH4,

C2H4, C2H6, C2H2, which are produced by oil decomposition, and CO, which is produced by cellulose decomposition. Each utility has a different philosophy and a different threshold for concern.

Table 8.6 gives one set of guidelines based on good utility practice that is useful for determining the overall health of a power transformer based on the total concentration of combustible gases.

It is generally accepted that if the rate of combustible gas generation exceeds 100 ppm per day on a continuing basis, or if the presence of C2H2 exceeds 20 ppm, then consideration should be given to taking the transformer out of service to perform additional tests and inspection.

IEEE Std. C57.104-1991 Table 3 also provides a set of actions based on the total dissolved combustible gas (TDCG) concentrations as well as the daily rate of TDCG production.

According to the IEEE Guide, a rate of 30 ppm per day is the threshold for considering removing the transformer from service. Oil samples are taken from the bottom drain valve in a sealed syringe to prevent the dissolved gases from escaping.

The samples are sent to a chemical laboratory where the dissolved gases are extracted from the sample under vacuum and analyzed using a gas chromatograph. The results are reported as ppm dissolved in oil.