[James_H._Harlow]_Electric_Power_Transformer_Engin(BookSee.org)

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considerably; furthermore, each material interface further attenuates the propagated signal. Therefore, acoustic signals can only be detected within a limited distance from the source. Consequently, the sensitivity for PD inside transformer windings, for example, may be quite low. In typical applications, many acoustic sensors are carefully distributed around the tested equipment (Eleftherion, 1995; Bengtsson et al., 1997). Though not disturbed by the electric network, external influences in the form of rain or wind and non-PD vibration sources, like loose parts and cooling fans, will generate acoustic signals that interfere with the PD detection. One way to decrease the external influence is to use acoustic waveguides (Harrold, 1983) that detect signals from inside the transformer tank. This solution is typically only considered for permanent monitoring of important transformers. As an alternative, phase-position analysis can be used to reject these disturbances (Bengtsson et al., 1997). A transformer generates disturbing acoustic signals in the form of core noise, which can extend up to the 50 to 100-kHz region. To diminish this disturbance, acoustic sensors with sensitivity in the 150-kHz range are usually employed (Eleftherion, 1995). Such sensors may, however, have less sensitivity to PD signals as well (Bengtsson et al., 1997). The properties of these signals are such that it is relatively easy to distinguish them from PD signals; thus, their main effect is to limit sensitivity. Regarding the electric multisensor systems discussed here, there are a few descriptions of combined electric and acoustic PD monitoring systems for transformers in the literature (Wang et al., 1997). Rather elaborate software must be employed to utilize the potential sensitivity of these systems. If both the acoustic and the electric parts are designed with the considerations above in mind and an effective software constructed, systems like this will become effective yet costly. 3.13.3.1.4 Oil Temperatures Overheating or overloading can cause transformer failures. Continuous measurement of the top-oil temperature is an important factor in maximizing the service life. Top-oil temperature, ambient temperature, load (current), fan/pump operations, and direct readings of winding temperatures (if available) can be combined in algorithms to determine hottest-spot temperature and manage the overall temperature conditions of the transformer. 3.13.3.1.5 Winding Temperatures There is a direct correlation between winding temperature and normally expected service life of a transformer. The hottest-spot temperature of the winding is one of a number of limiting factors for the load capability of transformers. Insulation materials lose their mechanical strength with prolonged exposure to excessive heat. This can result in tearing and displacement of the paper and dielectric breakdown, resulting in premature failures. Conventional winding temperature measurements are not typically direct; the hot spot is indirectly calculated from oil temperature and load current measurements using a widely recommended and described test method (Domun, 1994; Duval and Lamarre, 1977; Feser et al., 1993; Fox, 1983; IEEE, 1995). Fiber-optic temperature sensors can be installed in the winding only when the transformer is manufactured, rebuilt, or refurbished. Two sensor types are available: optical fibers that measure the temperature at one point, and distributed optical fibers that measure the temperature along the length of the winding. Since a distributed fiber-optic temperature sensor is capable of measuring the temperature along the fiber as a function of distance, it can replace a large number of discrete sensors and allow a real-time measurement of the temperature distribution. 3.13.3.1.6 Load Current and Voltage Maximum loading of transformers is restricted by the temperature to which the transformer and its accessories can be exposed without excessive loss of life. Continuous on-line monitoring of current and voltage coupled with temperature measurements can provide a means to gauge thermal performance. Load current and voltage monitoring can also automatically track the loading peaks of the transformer, increase the accuracy of simulated computer load-flow programs, provide individual load profiles to assist in distribution-system planning, and aid in dynamically loading the transformer. FIGURE 3.13.2 Power-factor graphical representation. 3.13.3.1.7 Insulation Power Factor The dielectric loss in any insulation system is the power dissipated by the insulation when an ac voltage is applied. All electrical insulation has a measurable quantity of dielectric loss, regardless of condition. Good insulation usually has a very low loss. Normal aging of an insulating material causes the dielectric loss to increase. Contamination of insulation by moisture or chemical substances can cause losses to be higher than normal. Physical damage from electrical stress or other outside forces also affects the level of losses. When an ac voltage is applied to insulation, the leakage current flowing through the insulation has two components, one resistive and the other capacitive. This is depicted in Figure 3.13.2. The power factor is a dimensionless ratio of the resistive current (I R ) to total current (I T ) flowing through the insulation and is given by the cosine of the angle depicted in Figure 3.13.2. The dissipation factor, also known as tan delta, is a dimensionless ratio of the resistive current to the reactive current flowing through the insulation and is the tangent of the angle in Figure 3.13.2. By convention, these factors are usually expressed in percent. Due to the fact that theta is expected to be large, usually approaching 90 degrees, and delta is commensurately small, the power factor and dissipation factor are often considered to be essentially equal. 3.13.3.1.8 Pump/Fan Operation The most frequent failure mode of the cooling system is the failure of pumps and fans. The objective of continuous on-line analysis of pumps and fans is to determine if they are on when they are supposed to be on and are off when they are supposed to be off. This is accomplished by measuring the currents drawn by pumps and fans and correlating them with the measurement of the temperature that controls the cooling system. This can also be accomplished by measuring pump/fan current and top-oil temperature. Mode of operation is verified based on current level. Normal operational modes indicate rotation of fan blades and correct rotation of pump impeller. Abnormal operational modes are usually the result of improper control wiring to those devices. Pump failures due to malfunctioning bearings could be a source of metallic particles, and such particles could be a potential dielectric hazard. Sensors that detect bearing wear are available. The ultrasonic sensors are embedded in the pump bearings and measure the bearing length, thus determining whether metal loss is occurring. Furthermore, continuous on-line analysis should take into account that: • The temperature that controls the cooling system can differ from the temperature measured by the diagnostic system. • The initial monitoring parameters are set for the cooling stages based on the original transformer design. Any modifications to the cooling sequences or upgrades must be noted, since this will change the monitoring system output. • The sensitivity of the diagnostic system is influenced by the number of motors that are measured by each current sensor. © 2004 by CRC Press LLC © 2004 by CRC Press LLC
3.13.3.2 Instrument Transformers The techniques available to monitor instrument transformers on-line can be focused on fewer possible degradation mechanisms than those for monitoring power transformers. However, the mechanisms by which instrument transformers fail are among the most difficult to detect on-line and are not easy to simulate or accelerate in the laboratory. 3.13.3.2.1 Failure Mechanisms Associated with Instrument Transformers While the failure rates of instrument transformers around the world are generally low, the large numbers of installed instrument transformers has led to the development of a database of failures and failure statistics. One problem associated with compiling a database of failures of porcelain-housed instrument transformers is that such failures are often catastrophic, leaving little evidence to determine the cause of the fault. Nevertheless, the following mechanisms have been observed and identified as probable causes of failure. 3.13.3.2.1.1 Moisture Ingress — Moisture ingress is commonly identified as a cause of failure of instrument transformers. The ingress of moisture into the instrument transformer can occur through loss of integrity of a mechanical seal, e.g., gaskets. The moisture penetrates the oil and oil/paper insulation (which increases the losses in the insulating materials) and failure then follows. This would appear to be a particular problem if the moisture penetrates to certain high-stress regions within the instrument transformer. The increase in the dielectric losses will be detected as a change in the power factor of the material and will also appear as increased moisture levels in oil quality tests. 3.13.3.2.1.2 Partial Discharge — The insulation of instrument transformers may have voids within it. Such voids will undergo partial discharge if subjected to a high enough electric field. Such discharges may produce aggressive chemical by-products, which then enlarge the size of the void, causing an increase in the energy of the discharge within the void. Eventually, these small partial discharges can degrade individual insulation layers, resulting in the short-circuiting of stress grading layers. Such a developing fault can be detected in two ways. One is the observance of a change in the capacitance of the device (through the shorting of one stress grading layer), and which may reflect as a change in tan delta. The second is an increase in the partial discharge levels (in pC) associated with the failing item. 3.13.3.2.1.3 Overvoltages — Overvoltages produced by induced lightning surges are also a failure mechanism, particularly where thunderstorms occurred in the vicinity of the failure. More recently, the observance of fast rise-time transients (T rise 100 s) in substations during disconnect switch operations has led to concerns that these transients may cause damage to the insulation of instrument transformers. There is significant speculation that instrument transformers do not perform well when exposed to a number of disconnect switch operations in quick succession. These disconnector-generated fast transients will remain a suspected cause of failure until more is understood about the stress distribution within the instrument transformer under these conditions. Switching overvoltages are an additional source of overstressing that may lead to insulation failure. 3.13.3.2.1.4 Through-Faults — In order to prevent failures due to the mechanisms outlined above, experience seems to indicate that slower-forming faults are probably detectable and preventable, while fast-forming faults due to damage caused by lightning strikes will be difficult to detect quickly enough to prevent consequential failure of the transformer. Another possible mechanism may relate to mechanical damage to the insulation after a current transformer (CT) has been subjected to fault current through its primary winding. After current transformer failures, it is often observed in retrospect that one to two weeks prior to the failure the CT had been subjected to a through-fault. Again, it is difficult to state that damage is caused to the CT under these conditions, and additional information would be required before this mechanism can be considered a probable cause of failure. 3.13.3.2.2 Instrument Transformer On-Line Monitoring Methods On-line techniques for the measurement of relative tan delta and relative capacitance (by comparing individual units against a larger population of similar units) have been installed by a number of utilities, with reports of some success in identifying suspect units. On-line partial-discharge measurement techniques may provide important additional information as to the condition of the insulation within the instrument transformer, but research and development work is still under way in order to address issues related to noise rejection vs. required sensitivity and on-site calibration. Other possible future developments may include on-line dissolved-gas analyzers that will be able to detect all gases associated with the partial-discharge degradation of oil/paper insulation. The following subsections review applicable methods for on-line monitoring of instrument transformers. 3.13.3.2.2.1 Relative Tan Delta and Relative Capacitance Measurements — Off-line partial discharge and tan delta monitoring are well-established techniques. These can be supplemented by taking small samples of mineral oil from the instrument transformer for DGA. The development of on-line monitoring techniques is ongoing, but significant progress has been made, particularly with respect to on-line tan delta and capacitance measurements. Laboratory-type tan delta and capacitance measurements usually require a standard low-loss capacitor at the voltage rating of the equipment under test, such that a sensitive bridge technique can be used to determine the capacitance and the tan delta (also know as the insulation power factor) of the insulation. This is not practical for on-line measurements. This problem is overcome by relying on relative measurements, in which the insulation of one instrument transformer is compared with the insulation of the other instrument transformers that are installed in the same substation. By comparing sufficient numbers of instrument transformers with other similar units, changes in one unit (not explained as normal statistical fluctuations due to changes in loading and ambient temperatures) can be identified. There are two commercially available units that monitor tan delta on-line. In the first, the ground current from each of the three single-phase instrument transformers is detected. This is done by isolating the base of the instrument transformer from its base except at one connection point, which then forms the only current path to ground. This current can then be measured using a suitable sensor. The current consists of two components: a capacitive component (the capacitance of a typical CT to earth being on the order of 0.5 to 1 F) and a resistive component dependent upon the insulation loss factor or tan delta of the insulation within the instrument transformer. If each of the three instrument transformers is in similar condition and of similar design, then the phasor sum of the three-phase currents to earth is essentially zero. Any resistive component of current to earth causes slight phase and magnitude shifts in these currents. If all three units on each phase have a low tan delta, then changes in one unit with respect to the other two can be readily detected. As the insulation deteriorates, and possibly as a grading layer is shorted out, a change in the capacitance of the unit will be reflected as a change in the capacitive current to earth. As the measurements are made with respect to other similar units, such measurements are referred to as relative tan delta and relative capacitance change measurements. Figure 3.13.3 shows this arrangement schematically. Another technique involves comparing each instrument transformer with a number of different units, possibly on the same busbar or on each of three phases. The capacitive and resistive current flows to earth are monitored, and the results for each instrument transformer can then be compared with those values measured on other units. Relative changes in tan delta and capacitance can then be determined, and an alarm is raised if these exceed norms established from software algorithms. These two techniques are currently in service and have achieved success in detecting instrument transformers behaving in a manner that is markedly different from other similar units. Both measurement tools are trending instruments by detecting changes of certain parameters for a large sample of units over a period of time. Consequently, they can identify an individual unit or units performing outside the parameter variations seen for other units. 3.13.3.2.2.2 On-Line Gas Analysis — The fuel-cell sensor-membrane technology that has been applied widely to power transformers with circulating oil can be applied to instrument transformers. However, in instrument transformers, the oil is confined, and this confinement can affect sensor operation. © 2004 by CRC Press LLC © 2004 by CRC Press LLC
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ELECTRIC POWER TRANSFORMER ENGINEER
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I wish to recognize the interest of
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Contents 1 Theory and Principles Ch
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1.3 Equivalent Circuit of an Iron-C
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designer starts to make a design fo
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• Transient voltages generated du
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the transformer’s bushings and, m
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% regulation = [(V NL - V FL )/V FL
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In core-form transformers, the wind
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FIGURE 2.1.14 Layer windings (singl
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the transformer design, which may b
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consumer’s service circuit is a d
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FIGURE 2.2.3 Single-phase transform
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is installed so that the tank never
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above which persons might be burned
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FIGURE 2.2.16 Two-bushing subway. (
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carbon steel or the very expensive
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FIGURE 2.2.31 Radial-style dead fro
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FIGURE 2.2.36 Complete transformer
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voltage in each winding simultaneou
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mounted transformers can have arres
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V S + V S I V L Z=R+jX a) V L V S V
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Z = jX (2.3.19) 0.7 Then the curren
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X1 L* X1 S =X1 L X2 L* X3 L* a) S L
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150 V(%) 100 50 0 -50 40 80 T(s) 12
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2.3.8.1.2 Series Connection • The
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A six-pulse single-way transformer
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The degree of coupling also influen
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where I h = current for the hth har
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In the case of liquid-filled transf
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FIGURE 2.4.21 A 36-pulse system mad
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Vacuum-pressure encaps ulated — T
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FIGURE 2.6.1 Typical wiring and sin
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a) H1 b) Ip X2 FLUX H2 LEAKAGE FLUX
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and for CTs is TCF = RCF - (PA/2600
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RCF x Bx Bt RCF t - RCF 0 co
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2000 1000 5% Vex BANDWITH FROM NOMI
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This may be more useful when operat
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also some uncertainty in repeatabil
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FIGURE 2.6.25 Standard two-element
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2.7 Step-Voltage Regulators Craig A
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Source Bypass Switch Source Bypass
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2.7.4 Theory A step-voltage regulat
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FIGURE 2.7.22 Equalizer winding inc
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TABLE 2.7.4 Increase in Ampere Load
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References IEEE, Standard Requireme
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300% FIGURE 2.8.4 Schematic of a co
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TABLE 2.8.1 Typical Sizing Workshee
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Input with Interruption Ferro Outpu
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FIGURE 2.8.20A Performance of a rid
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• Input frequency or frequency ra
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References 1. Sola/Hevi-Duty Corp.,
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FIGURE 2.9.5 Typical phase-reactor
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FIGURE 2.9.10 Two generator arrange
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• Overloading of lines • Increa
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FIGURE 2.9.23 34-kV, 25-MVAR (per p
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V 90 ( X X ) s T (2.9.10a) where,
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Therefore, Line reactive losses = (
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ate of rise of transient-recovery v
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the LLCR is provided in IEEE Std. C
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aluminum shielding, i.e., an oil-im
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Leo J. Savio ADAPT Corporation Ted
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3.1.2.2.2 Heat Dissipation A second
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FIGURE 3.2.1 Solid-type bushing. ma
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1.6 cm. This means that most of the
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where HS = steady-state bushing ho
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the conductivity of the water-solub
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of 178 ohm-m, and a test duration o
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2. Easley, J.K. and Stockum, F.R.,
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FIGURE 3.3.5 Reactance-type LTC, in
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FIGURE 3.3.10 LTC with delta connec
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3.3.5 Selection of Load Tap Changer
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FIGURE 3.3.19 Effect of the leakage
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References Goosen, P.V. , Transform
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If i 1 is the full-load current rat
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TABLE 3.4.1 Loading Recommendations
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3.5.4 Three-Phase Transformer Conne
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FIGURE 3.5.4 Interconnected star-gr
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3.6.1.1 Standards ANSI standards fo
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ANSI standards. LTC control setting
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FIGURE 3.6.7 Discharging the capaci
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FIGURE 3.6.10 Standard switching-im
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voltage of the excited winding, rea
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FIGURE 3.6.18 Current, voltage, and
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TABLE 3.6.3 Transformer Short-Circu
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FIGURE 3.7.3 Control for voltage re
Page 173 and 174: FIGURE 3.7.6A Feeder with power-fac
Page 175 and 176: 3. Circulating current (current bal
Page 177 and 178: FIGURE 3.7.10 Control block diagram
Page 179 and 180: Primary Current (Amps) 60 40 20 0 -
Page 181 and 182: current transformer having two prim
Page 183 and 184: 87R1 87BL1 (A) Independent Harmonic
Page 185 and 186: Winding 1 Secondary Currents Data A
Page 187 and 188: Y Y 20 18 3 rd Harmonic CTR1=40 CTR
Page 189 and 190: 230 kV 3 180 MVA 138 kV 5 CTR1 = 2
Page 191 and 192: 29. Concordia, C. and Rothe, F.S.,
Page 193 and 194: FIGURE 3.9.1 Measurement of pressur
Page 195 and 196: H 2m 1. Vertical Forced Air 2. Prin
Page 197 and 198: Gade, S., Sound Intensity Instrumen
Page 199 and 200: nected. This steady-state voltage d
Page 201 and 202: where [A] = state matrix [B] = inpu
Page 203 and 204: where C = capacitance between the t
Page 205 and 206: L ijo = N i N j ijo (3.10.31) 1.4
Page 207 and 208: % VOLTAGE % VOLTAGE 100 BIL 90 50 3
Page 209 and 210: 29. Degeneff, R.C., Reducing Storag
Page 211 and 212: All connections should be cleaned a
Page 213 and 214: 6. Costs to set up and use a mobile
Page 215 and 216: Records of relay operation must be
Page 217 and 218: • Has heating occurred as the res
Page 219 and 220: a reference value) of the currents
Page 221 and 222: The next data-processing step is to
Page 223: temperature. As the transformer coo
Page 227 and 228: FIGURE 3.13.5 Analysis of bushing s
Page 229 and 230: temperature. Under abnormal conditi
Page 231 and 232: 3.14.1.2 Accredited Standards Commi
Page 233 and 234: FIGURE 3.14.4 IEC technical-committ
Page 235 and 236: TABLE 3.14.2 Relevant Documents for
Page 241: TABLE 3.14.13 Relevant Documents fo
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