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2
Testing of
Power Transformers
1. Verification of voltage Ratio and vector
Group or phase displacement and polarity.
3
1. Turn Ratio Measurement
1.1 Purpose of measurement
The no‐load voltage ratio between two windings of a transformer is called turn ratio. The aim of measurement is; confirming the no‐load voltage ratio given in the customer order Specifications, determining the conditions of both the windings and the connections and examining the problems (if any). The measurements are made at all tap positions and all phases.1.2 Turn Ratio Measurement
Bridge method
Measurement of turn ratio is based on, applying a phase voltage to one of the windings using a bridge (equipment) and measuring the ratio of the induced voltage at the bridge. The measurements are repeated in all phases and at all tap positions, sequentially. During measurement, only turn ratio between the winding couples which have the same magnetic flux can be measured, which means the turn ratio between the winding couples which have the parallel vectors in the vector diagram can be measured.
Theoretical turn ratio = HV winding voltage / LV winding voltage
The theoretical no‐load turn ratio of the transformer is adjusted on the equipment by an adjustable transformer; it is changed until a balance occurs on the % error indicator. The value read on this error indicator shows the deviation of the transformer from real turn ratio as %. (Measured turn ratio) ‐ (Designed turn ratio) % Deviation = * 100 (Designed turn ratio) The % deviation of the turn ratios should be ≤ 0.5 %.
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1.2 Determining the Vector Group
Depending on the type of the transformer, the input and output windings of a multi‐phase transformer are connected either as star ( Y ) or delta( D ) or zigzag( Z ). The phase angle between the high voltage and the low voltage windings varies between 0⁰ and 360⁰.
Representing as vectors, the HV winding is represented as 12 (0) hour and the other windings of the connection group are represented by other numbers of the clock in reference to the real or virtual point. For example, in Dyn 11 connection group the HV winding is delta and the LV winding is star and there is a phase difference of 330⁰ (11x30⁰) between two windings. While the HV end shows 12 (0), the LV end shows 11 o’clock (after 330⁰). Determining the connection group is valid only in three phase transformers. The high voltage winding is shown first (as reference) and the other windings follow it. If the vector directions of the connection are correct, the bridge can be balanced. Also, checking the connection group or polarity is possible by using a voltmeter. Direct current or alternating current can be used for this check. The connections about the alternating current method are detailed in standards. An example of this method is shown on a vector diagram below. Fig: ‐ Connection group representation and measuring The order of the measurements: 1) ‐ 3 phase voltage is applied to ABC phases 2) ‐ voltage between phases (e.g. AC) is measured 3) ‐ A short circuit is made between C and n 4) ‐ voltage between B and B’ is measured 5) ‐ voltage between A and c’ is measured
As seen from the vector diagram, in order to be Dyn 11 group, A.c’ > AB > B.b’ correlation has to realized. Taking the other phases as reference for starting, same principles can be used and also for determining the other connection groups, same principles will be helpful.
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6
1.3 Polarity test
1.3.1 Polarity test using voltmeters
Single‐phase transformers
For single‐phase transformers the polarity can be either additive or subtractive. The low voltage winding is connected in series with the high voltage winding, either in phase or in opposite phase. For additive determination of polarity, if the phase displacement is correct, see figure 1.3.1. Figure 1.3.1: Connection for additive polarity test And for subtractive determination of polarity, see figure 1.3.2 Figure 1.3.2: Connection for subtractive polarity test. Polyphase Transformers. The vector group must be checked for three‐phase transformers. This is done by connecting a terminal from the low voltage side to a terminal on the high voltage side, see figure 1.3.3. When a three‐phase supply is connected to the high voltage winding, potential differences appear between the open terminals and are used to determine the vector group. Figure 1.3.3: Polarity test and connection test on three‐phase transformer Using one voltmeter
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1.3.2 Polarity check using DC current.
This method establishes the polarity of single and three‐phase transformers by briefly switching on a DC current source at the high voltage winding, see figure 1.3.4. The polarity is shown on a polarized voltmeter connected to the low voltage side. Figure 1.3.4: Basic analog ratio bridge circuit
8
Testing of
Power Transformers
2. Winding Resistance
Measurement.
9
2. Winding Resistance Measurement.
2.1 Purpose of the test
Winding resistance serves a number of important functions like: • Providing a base value to establish load loss. • Providing a basis for an indirect method to establish winding temperature and Temperature rise within a winding. • Inclusion as part of an in‐house quality assurance program, like verifying electric continuity within a winding.2.2 General.
Winding resistance is always defined as the DC‐resistance (active or actual resistance) of a winding in Ohms [Ω].
Temperature dependence
It should be noted that the resistivity of the conductor material in a winding – copper or aluminum – is strongly dependent on temperature. For temperatures within the normal operating range of a transformer the following relationship between resistance and temperature is sufficiently accurate:
C+Ø
2R
2= R
1C+Ø
1 Where: R1 = resistance at temperature Ø2 R2 = resistance at temperature Ø1 Ø = temperature in °C C = constant which is a function of material type IEC [1] specifies: C = 235 for copper = 225 for aluminumPrinciple and methods for resistance measurement:‐
There are basically two different methods for resistance measurement: namely, the so‐called “voltmeter‐ ammeter method” and the bridge method.“Voltmeter‐ammeter Method”
The measurement is carried out using DC current. Simultaneous readings of current and voltage are taken. The resistance is calculated from the readings in accordance with Ohm’s Law. This measurement may be performed using conventional analog (rarely used nowadays) or digital meters; however, today digital devices such as Data Acquisition Systems (DAS) with direct resistance display are being used more and more.Measurement with voltmeter and ammeter
The measuring circuit is shown in figure 2.1. Resistance RX is calculated according to Ohm’s Law:R
X=U/I
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The advantage of this method is the simplicity of the test‐circuit. On the other hand, this method is rather inaccurate and requires simultaneous reading of the two instruments.
“Resistance measurement using a Kelvin (Thomson) Bridge”
This measurement is based on the comparison of two voltage drops: namely, the voltage drop across the unknown winding resistance RX, compared to a voltage drop across a known resistance RN (standard resistor), figure 2.2.
DC‐current is made to flow through RX and RN and the corresponding voltage drops are measured and compared.
The bridge is balanced by varying the two resistors Rdec and RV, which have relatively high resistance values. A balanced condition is indicated when the galvanometer deflection is zero, at which time the following relationship holds:
R
decR
X= R
NR
v The influence of contact resistances and the connection cable resistances (even of the connection between RX and RN) can be neglected. Figure 2.1: Voltmeter ‐ ammeter method measuring circuit Figure 2.2: Kelvin (Thomson) Bridge method11
Value of the DC‐current of measurement
Maximum value: To avoid an inadmissible winding temperature rise during the measurement, the DC‐current should be limited to a maximum 10% of the rated current of the corresponding winding. Minimum value: The lower limit of the DC‐current is given by the following considerations: The measuring circuit for all resistance measuring methods consists of a DC‐source and a transformer winding fixed around an iron core as represented by the following equivalent circuit, Winding inductance is strongly dependent on current and displays the following characteristic for transformers, see figure 3.4. As the measuring circuit time‐constant is given by the relation L/R, the current‐time characteristic differs quite significantly when switching on the DC‐source, depending on the measuring current value (magnetizing current).
Therefore, the DC measuring current should be at least 1.2 times higher than the crest value of the magnetizing current to be sure to saturate the iron core Figure 3.3: Equivalent circuit of a Figure 3.4: Inductance of transformer winding Winding as a function of the current.
12
Testing of
Power Transformers
3. Magnetic Balance and
Magnetising Current
Measurement.
13
Magnetic Balance Test on 3‐phase Transformers
This test is conducted only in three‐phase transformers to check the imbalance in the magnetic circuit. In this test, no winding terminal should be grounded; otherwise results would be erratic and confusing. The test shall be performed before winding resistance measurement. The test voltage shall be limited to maximum power supply voltage available at site.Evaluation Criteria
The voltage induced in the center phase is generally 50% to 90% of the applied voltage on the outer phases. However, when the center phase is excited then the voltage induced in the outer phases is generally 30 to 70% of the applied voltage.Zero voltage or very negligible voltage with higher excitation current induced in the other two windings should be investigated. The voltage induced in different phases of transformer in respect to neutral terminals given in the table below.
Left side phase Central phase Right side phase
AN BN CN Voltage applied at left side phase 230 V 180 V 50 V Voltage applied at central phase 115 V 230 V 115 V Voltage applied at right side phase 50 V 180 V 230 V
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EXCITING/ MAGNETISING CURRENT MEASUREMENT
This test should be done before DC measurements of winding resistance to reduce the effect of residual magnetism. Magnetising current readings may be effected by residual magnetism in the core. Therefore, transformer under test may be demagnetised before commencement of magnetizing current test. Three‐phase transformers are tested by applying Single‐phase 10 kV voltage to one phase (HV terminals) and keeping other winding open circuited and measuring the current at normal, minimum and max. tap positions. Keep the tap position in normal position and keep HV and LV terminals open. Apply 1phase 10kV supply on IV terminals. Measure phase to phase voltage between the IV terminals and current on each of the IV terminals. The set of reading for current measurement in each of the tap position should be equal. Unequal currents shall indicate possible short circuits in winding. Results between similar single‐phase units should not vary more than 10 % .The test values on the outside legs should be within 15 % of each other, and values for the centre leg should not be more than either outside for a three‐phase transformers. Results compared to previous tests made under the same conditions should not vary more than 25%. If the measured exciting current value is 50 times higher than the value measured during precommissioning checks, then there is likelihood of a fault in the winding which needs further analysis. The identical results confirm no damage due to transportation. The availability of test data of normal condition and faulty condition results help us to analyze the problem in future.
Measurement of Magnetization Current at Low Voltage
For 3‐phase transformers, the test shall be conducted either with 415 V, 3‐phase (neutral grounded) or 230 V, 1 phase (preferred). For single phase transformers, the test shall be conducted with 230 V.
This test is performed to locate defect in magnetic core structure, shifting of windings, failures in turn insulation or problem in tap changers.
The acceptance criteria for the results of exciting current measurement should be based on the comparison with the previous site test results or factory test results. The general pattern is two similar high readings on the outer phases and one lower reading on the center phase, in case of three phase transformers. An agreement to within 25% of the measured exciting current with the previous test is usually considered satisfactory. If the measured exciting current value is 50% higher than the value measured during pre‐ commissioning checks, then the winding needs further analysis.
15
Testing of
Power Transformers
4. MEASUREMENT OF SHORT
CIRCUIT IMPEDANCE
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MEASUREMENT OF SHORT CIRCUIT IMPEDANCE
This test is used to detect winding movement that usually occurs due to heavy fault current or mechanical damage during transportation or installation since dispatch fro the factory.
Ensure the isolation of Transformer from High Voltage & Low voltage side with physical inspection of open condition of the concerned isolators/disconnectors. In case tertiary is also connected, ensure the isolation of the same prior to commencement of testing
The measurement is performed in single phase mode. This test is performed for the combination of two winding. The one of the winding is short circuited and voltage is applied to other winding. The voltage and current reading are noted.
The test shall be conducted with variac of 0‐280 V, 10 A, precision RMS voltmeter and ammeter. The conductors used for short‐circuiting one of the transformer windings should have low impedance (less than 1m‐ohm) and short length. The contacts should be clean and tight. The acceptable criteria should be the measured impedance voltage having agreement to within 3 percent of impedance specified in rating and diagram nameplate of the transformer. Variation in impedance voltage of more than 3% should be considered significant and further investigated. The formula for calculating the percentage impedance with current and frequency correction is:
Where:
V
test= Test voltage
V
rated=Rated voltage
I
test= Test current
I
rated= Rated current
f
t= Test frequency
f
r= Rated frequency
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Testing of
Power Transformers
5. Measurement of dissipation
factor (tanδ) of the insulation
system capacitances.
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Measurement of dissipation factor (tanδ) of the insulation system capacitances
The purpose of the measurement
The insulation power‐factor test, similar to the insulation resistance test, allows certain conclusions to be drawn concerning the condition of the transformer insulation. The significance of the power factor figure is still a matter of opinion. Experience has shown, however, that the power‐factor is helpful in assessing the probable condition of the insulation when good judgment is used.
General
IEC defines the power factor as the ratio between the absorbed active power to the absolute value of the reactive power. This corresponds to tanδ. IEEE [51], on the other hand defines the insulation power‐factor as the ratio of the power dissipated in the insulation in watts, to the product of the effective voltage and current in volt‐amperes (corresponding to the apparent power) when tested using a sinusoidal voltage. Insulation power‐factor is usually expressed in percent [51].
Measurement of power‐factor values in the factory is useful for comparison with field power‐factor measurements and assessing the probable condition of the insulation. It has not been feasible to establish standard power‐factor values for the following reasons: • There is little or no relationship between power‐factor and the ability of the Transformer to withstand the prescribed dielectric tests. • The variation of power‐factor with temperature is substantial and erratic. • The various liquids and insulation materials used in transformers result in Large variations in insulation power factors [51].
The measuring circuit / the measuring procedure [51]
Measurement using a bridge
The method is based on comparing the capacitance CX (transformer under test) with a well‐known capacitance CN (standard capacitor).Conventional Schering‐Bridge
Figure shows the measuring circuit for the insulation power‐factor measurement of a two‐winding transformer using a conventional Schering‐bridge.Instrumentation
The Schering‐Bridge test circuit consists of three main parts: • The unknown capacitance CX, which represents the transformer under test whose power‐factor (or tanδ) and capacitance are to be measured. • The standard capacitor CN, which must be a HV capacitor with very low dielectric losses. Normally its capacitance is between 100 pF and 10 nF. • The Schering‐Bridge casing contains resistors R3, R4 and r, adjustable capacitor C4 and galvanometer G. In order to reduce the influence of external disturbances, coaxial cables must be used for the connection between CX (the transformer under test) to the bridge and also between standard capacitance CN and the bridge.19
Figure: Measuring circuit for the measurement of power factor and winding Capacitances.When the bridge is balanced, the unknown capacitance CX and tanδ can be calculated using the following equations: In most bridges the following resistance values are used for R4, to simplify the calculation: 100/π, 1000/π or 10000/π etc. in ohms. For a 50 Hz measurement, with R4 = 1000/π and C4 in nF, the insulation power factor tanδ will be:
20
A modern tanδ bridge with current comparator and microprocessor
This bridge uses basically the same measuring principle as described above. Figure 18.1 b shows the measuring circuit for dissipation factor and capacitance measurement with a modern tan _ measuring bridge with incorporated microprocessor.
The currents are balanced in a comparator (more‐winding differential transformer) and quadrature current is injected to balance the losses.
For the unknown capacitance Cx, the standard capacitor CN and the connections between transformer and bridge are the same as mentioned above for the conventional Schering Bridge.
MEASURING METHODS:
CAPACITANCE AND TAN δ MEASUREMENT OF BUSHINGS
C & Tan δ measurement of bushings shall be done at 10kV with fully automatic test kit so as to have reliable test result. • For 3‐Ph auto‐transformer, short together all 400kV, 220kV and Neutral (isolated from earth) Bushings. Also short all 33kV Bushings and earth the same. Measurement of C1 Capacitance and Tanδ: Connect the crocodile clip of the HV cable to the top terminal of the shorted HV/IV bushings. Unscrew the test tap cover, Insert a pin in the hole of the central test tap stud by pressing the surrounding contact plug in case of 245 kV OIP Bushing and remove the earthing strip from the flange by unscrewing the screw (holding earth strip to the flange body) in case of 420 kV OIP Bushing. Connect the LV cable to the test tap (strip/central stud) of the bushing under test to the C & TAN δ KIT through a screened cable and earth the flange body. Repeat the test for all Bushings by changing only LV lead connection of the kit to test tap of the Bushing which is to be tested. Measurement of C2 Capacitance and Tanδ : HV lead to be connected to the test tap of the bushing under test (if required additional crocodile type clip may be used) and LV of the kit to be connected to the ground. HV of the bushing is to be connected to the Guard terminal of the test kit. Test to be carried out in GSTg mode at 1.0kV. • For measurement of 33kV Bushing Tan Delta, earth HV/IV Bushings (already shorted). Apply HV lead of the Test kit to shorted 33kV Bushings and connect LV lead of the test kit to Test tap of the Bushing under test.• Measurements shall be made at similar conditions as that of a previous measurement. The oil‐paper insulation combination of bushings exhibit fairly constant tan delta over a wide range of operating temperature. Hence, effort is to be made for testing at temperature near to previous test and Correction factor need not be applied. • Do not test a bushing (new or spare) while it is in its wood shipping crate, or while it is lying on wood. Wood is not as good an insulator as porcelain and will cause the readings to be inaccurate. Keep the test results as a baseline record to compare with future tests.
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• It is to be ensured that C& Tan δ measurement of bushings and testing of turrets carried out before installation. This will prevent installation of bushings having C& Tan δ values beyond permissible limits. • It is to be ensured that Test Tap points are earthed immediately after carrying out the measurements for that particular Bushing and earthing of test tap to be ensured by carrying out continuity test.
CAPACITANCE AND TAN δ MEASUREMENT OF WINDINGS
The combination for C & tanδ measurement of winding is same as that of measurement of IR value. The summery of probable combination is given below: Auto‐Transformer (Two winding) Test Mode Shunt Reactor
Test Mode 3 winding Transformer
Test Mode
HV + IV to LV UST V HV to E GST HV to LV1 UST
HV + IV to E GSTg HV to LV2 UST
LV to E GSTg LV1 to LV2 UST
HV to Ground GSTg LV1 to Ground GSTg LV2 to Ground GSTg Table: Combination for C & tanδ measurement of winding for various Transformers/ Shunt Reactor.
• Ensure that test specimen is isolated from other equipments. Removal of Jumpers from Bushings is Pre‐ Requisite for C & Tan δ Measurement of Windings. • For ICTs (Auto‐Transformers): Shorting of all three phase Bushings (400kV&220kV) and neutral to be done. In case of single phase, 400kV, 220kV and neutral Bushings to be shorted Capacitance and Tan δ measurement of windings should be done in following combinations: Test No. Winding Combination Test
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1. HV‐IV/LV UST CHL HV lead of test kit to
HV/IV bushings of transformer LV lead of test kit to LV bushing of transformer 2. HV‐IV/ LV+G GST CHL +CHG ‐do‐ 3. HV‐IV / LV with Guard GSTg C HG ‐ do‐ LV to be Guarded 4 HV‐IV/LV UST CHL LV lead of test kit to HV/IV bushings of
transformer HV lead of test kit to LV bushing of transformer 5 LV/ HV‐IV +G GST CHL+CLGLG ‐do‐ 6. LV/ HV‐IV with Guard GSTg C LG ‐do‐ HV to be Guarded Table :.Winding combination for C & tan δ measurement for auto transformer. • Measurement inter‐check can be done by calculating C1= C2‐C3 & C4= C5‐ C6 & DF1=C2DF2‐C3DF3 / C2‐C3= C4DF4‐C5DF5 / C4‐C5 Where C stands for capacitance and DF for dissipation factor or tan δ and attached suffix (1…6) denotes the sr. no. of test in above table. • For Reactors: All 400kV and neutral Bushings to be shorted. HV of the test kit to be connected to shorted Bushings and LV of the test kit to be connected to Earth connection. Measure the Capacitance and tan Delta in GST mode. Neutral connection with earth/ NGR to be isolated before the test.
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Testing of
Power Transformers
6. Measurement
Insulation Resistance
.
24
Measurement of insulation resistance
Insulation resistance tests ‐ Megger tests ‐ are performed to determine the insulation resistance from individual windings to earth or between individual windings. Knowledge of the insulation resistance is of value when evaluating the condition of the transformer insulation.
Insulation resistance is commonly measured in megohms, (MΩ).
It should be stated, that variations in insulation resistance can be caused by numerous factors including: design, temperature, dryness, and cleanliness of parts, especially of bushings. When insulation resistance falls below specified value, it can often be brought back to the required value by cleaning and drying. Insulation resistance varies with the applied voltage. Any measurement comparisons should always be carried out at the same voltage. Figure: Principal measuring circuit for the insulation resistance measurement IEEE Std. C57.12.00 [50] also specifies the insulation resistance measurement between core and earth. It shall be measured after complete assembly of the transformer at a level of at least 0.5 Kv DC for a duration of 1 minute. The test is conducted with the help of mega‐ohmmeter. IR is proportional to the leakage current through/over the insulation after capacitive charging and absorption currents become negligible on application of DC voltage. Insulation resistance shall be measured after the intervals of 15 sec, 60 sec and 600 sec. The polarization index (PI) is defined as the ratio of IR values measured at the intervals of 600 and 60 seconds respectively. Whereas, the dielectric absorption is the ratio of IR values measured after 60 sec and 15 sec. IR is normally measured at 5 kV DC or lower test voltage, but the test voltage should not exceed half the rated power‐frequency test voltage of transformer windings.
Polarization index (PI) is useful parameters for logistic interpretation of IR test results. This ratio is independent of temperature and gives more reliable data for large power transformers. A PI of more than 1.3 and dielectric absorption factor of more than 1.25 are considered satisfactory for a transformer when the results of other low voltage tests are found in order. PI of less than 1 calls for immediate corrective action. For bushings, an IR value of above 10000 M‐ohms is considered satisfactory.
The IR value of transformer is dependent on various factors such as configuration of winding insulation structures, transformer oil, atmosphere condition etc. therefore, present trend is to monitor oil characteristics
25
for judging the condition of dryness of the transformer and not to rely solely on absolute values of IR. It may be note that no national/international standards specify minimum insulation resistance values of transformers. The value of IR may be very low under heavy fog or humid conditions. During IR measurement, we must ensure following conditions: • Transformer is disconnected from other associated equipment • Bushings are cleaned and free of moisture • Transformer tank and core are properly grounded • Both ends of winding under test are short‐circuited.
Measuring Methods:‐
IR measurements shall be taken between the windings collectively (i.e. with all the Windings being connected together) and the earthed tank (earth) and between each winding and the tank, the rest of the windings being earthed. Before taking measurements the neutral should be disconnected from earth. Following table gives combinations of IR measurements for auto‐transformer, three ‐winding transformer & Shunt Reactor. For Auto‐transformer For 3 winding transformer For Shunt Reactor
HV + IV to LV HV + IV to LV HV to E
HV + IV to E HV + LV to IV
LV to E HV + IV +LV to E
Where HV‐High voltage, IV‐Intermediate voltage, LV‐Low voltage/Tertiary voltage windings, E‐ Earth
Unless otherwise recommended by the manufacturer the following IR values as a thumb rule may be considered as the minimum satisfactory values at 30°C (one minute measurements) at the time of commissioning.
Insulation resistance varies inversely with temperature and is generally corrected to a standard temperature (usually 20 °C) using table (Source: BHEL instruction Manual) as given below.
26
PI= R10 / R1 (dimensionless), Where PI is Polarisation Index and R is resistance The following are guidelines for evaluating transformer insulation using polarization index values: A PI of more than 1.25 and DAI of more than 1.3 are generally considered satisfactory for a transformer when the results of other low voltage tests are found in order. PI less than 1 calls for immediate corrective action. For bushings, an IR value of above 10,000 MΩ is considered satisfactory.27
Testing of
Power Transformers
7. CHECK LIST FOR ENERGISATION
OF TRANSFORMER.
28
CHECK LIST FOR ENERGISATION OF TRANSFORMER/ REACTOR
PRELIMINARY CHECKS
1. Release air at the high points, like oil communicating bushings, buchholz petcock, tank cover and the cooling devices including headers, radiators, pumps, expansion joints etc. of the transformer. Air release should be resorted from low points to high points. 2. Check the whole assembly for tightness and rectify where necessary. 3. Check the general appearance and retouch the paint work if need be. 4. Check that the valves are in the correct position: • Tank: valves closed and blanked • Cooling circuit: valves open • Conservator connection: valves open • By‐pass: valves open or closed as the case may be. • On‐load tap changer: valves open 5. Check that the silica gel in the breather is blue and that there is oil in the breather cup (oil seal) 6. Check that CC‐CL‐G are shorted7. Check the oil level in the main conservator and the conservator of on‐load tap changer, bushing caps, flanges, turrets, expansion bellows as per manufacturer’s recommendation. Level should correspond to 35º C mark on oil level gauges for BHEL transformers 8. Check the bushings: • Oil level (bushings fitted with sight‐glasses) • Adjustment of spark‐gaps /arcing horn –gaps, if provided • Conformity of connection to the lines (no tensile stress on the terminal heads) • Bushing CT secondary terminals must be shorted and earthed, if not in use. • Neutral bushing effectively earthed 9. Check the on‐load tap changer: • Conformity of the positions between the tap changer control cubicle and the tap Changer head • Adjustment of the tap‐changer control cubicle coupling • Electric and mechanical limit switches and protective relays • Step by step operation‐ local and remote electrical operation as well as manual Operation and parallel operation, if any • Signaling of positions 10. Check the quality of the oil: • Draw off a sample from the bottom of the tank • Carry out DGA and oil parameters test (i.e. BDV, Moisture content, resistivity & tan δ at 90°C and IFT )
29
before energisation. 11. Check the oil of OLTC chamber, if not good, drain and fill with filtered oil upto desired level. 12 Check that equalising link between OLTC tank and Main tank is removed 13 Extraneous materials like tools, earthing rods, pieces of clothes, waste etc. should be removed before energisation.CHECKING OF AUXILIARY AND PROTECTIVE CIRCUITS
1. Check temperature indicator readings and their calibrations2. Check the setting and working of the mercury switches of winding and oil temperature indicators and presence of oil in the thermometer pockets • Follow the same procedure for the thermal replicas 3. Check the direction of installation of buchholtz relay. 4. Check the operation of the buchholz relay and the surge protective relay of the tap‐changer : • Alarm and tripping • Protections and signals interlocked with these relays 5. Check the insulation of the auxiliary circuits in relation to the ground by 2 kV megger for 1 min. 6. Check the earthing of the tank and auxiliaries like cooler banks at two places. 7. Measure the supply voltages of the auxiliary circuits 8. Check the cooling system : • Check the direction of installation of oil pumps • Check the direction of rotation of the pumps and fans • Check the working of the oil flow indicators • Check the setting of the thermal overload relays • Go through the starting up sequences, control and adjust, if necessary, the relay time delays 9. Check that there is efficient protection on the electric circuit supplying the accessories and tightness of all electrical connections 10. Check the heating and lighting in the cubicles
11. Check the differential protection, over‐current protection, restricted earth fault protection, over‐fluxing protection etc. are in service and settings are as per CC/Engg recommendations. After the inspection / tests are completed, the transformer may be energised from the incoming side on NO LOAD. The initial magnetising current at the time of switching will be very high, depending upon the particular moment in the cycle. The transformer should always be soaked for few hours under constant care i.e. keep it energised for twelve hours. Excessive vibrations of radiator parts etc. should be located and corrected. The transformer hum should be observed for any abnormality. After that it may be checked for gas collection. Should the gas prove to be inflammable, try to detect the cause which may probably be an internal fault? If the breaker trips on
30
differential /REF, buchholz or any other protective device, the cause must be investigated thoroughly before re‐energizing the transformer/ reactor. After successful charging, performance of transformer / rector should be checked under loading; OTI/WTI readings should be monitored for 24 hours and ensured that they are as per loading.DGA samples may be sent as per Standard practice (after 24 hrs of energisation, one week, 15 days, one month and three months after charging, thereafter as per normal frequency of 6 months). Loading data may be forwarded to CC/OS and manufacturer (if requested by them).
31
Testing of
Power Transformers
8. PRE‐COMMISSIONING CHECKS
/TESTS FOR TRANSFORMERS.
32
PRE‐COMMISSIONING CHECKS /TESTS FOR TRANSFORMERS & REACTORS
Once oil filling is completed, various pre‐commissioning checks/ tests are performed to ensure the healthiness of the Transformer/ Reactor prior to its energisation. Various electrical tests to be performed and their significance are given below. Sr. No.Name of Test / Check point
Purpose of test/ check
3.1 Core insulation tests To check the insulation between Core (CC&CL) and Ground 3.2 Operational Checks
on protection System
Operational Checks on cooler bank (pumps & Fans), Breathers (silica gel or drycol), MOG, temperature gauges (WTI/OTI), gas actuated relays (Buchholz, PRD, SPR etc.) and simulation test of protection system
3.3 Insulation Resistance(IR) measurement
Test reveals the condition of insulation (i.e. degree of dryness of paper insulation), presence of any foreign contaminants in oil and also any gross defect inside the transformer (e.g. Failure to remove the temporary transportation bracket on the live portion of tap‐ changer part)
3.4 Capacitance and Tanδ measurement of bushings
Measurement of C1 & C2 Capacitance and Tanä in UST mode. Changes in the normal capacitance of an insulator indicate abnormal conditions such as the presence of moisture layer,short ‐ circuits or open circuits in the capacitance network.
3.5 Capacitance and Tan δ measurement of windings
Dissipation factor/Loss factor and capacitance measurement of winding is carried out to ascertain the general condition of the ground and inter‐winding insulation
3.6 Turns ratio (Voltage ratio) measurement
To determine the turns ratio of transformers to identify any abnormality in tap changers/ shorted or open turns etc
3.7 Vector Group & Polarity
To determine the phase relationship and polarity of transformers 3.8 Winding resistance
measurement
To check for any abnormalities due to loose connections, broken strands and high contact resistance in tap changers
3.9 Magnetic Balance test
This test is conducted only in three phase transformers to check the imbalance in the magnetic circuit
33
3.10 Floating Neutral point measurement
This test is conducted to ascertain possibility of short circuit in a winding.
3.11 Measurement of Short Circuit Impedance
This test is used to detect winding movement that usually occurs due to heavy fault current or mechanical damage during transportation or installation since dispatch from the factory.
3.12 Exciting/Magnetising current
measurement
To locate defect in magnetic core structure, shifting of windings, failures in turn to turn insulation or problems in tap changers. These conditions change the effective reluctance of the magnetic circuit thus affecting the current required to establish flux in the core.
3.13 Vibration
measurement of Oil‐ immersed Reactor
To measure the vibrations of core /coil assembly in the tank of the reactor. Movement of the core‐coil assembly and shielding structure caused by the time–varying magnetic forces results in vibration of the tank and ancilliary quipment. These vibrations have detrimental effects such as excessive stress on the core‐coil assembly
3.14 Operational check on OLTCs
To ensure smooth & trouble free operation of OLTC during operation.
3.15 Stability of
Differential, REF of Transformer/ Reactor
This test is performed to check the proper operation of Differential & REF protection of Transformer & Reactor by simulating actual conditions. Any problem in CT connection, wrong cabling, relay setting can be detected by this test.
3.16 Tests/ Checks on Bushing Current Transformers (BCTs)
To ascertain the healthiness of bushing current transformer at the time of erection
3.17 Frequency Response Analysis (FRA) measurement
To assess the mechanical integrity of the transformer. Transformers while experiencing severity of short circuit current looses its mechanical property by way of deformation of the winding or core. During pre‐commissioning this test is required to ascertain that Transformer active part has not suffered any severe impact/ jerk during transportation.
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3.18 Dissolved Gas Analysis (DGA) of oil sample
Oil sample for DGA to be drawn from transformer main tank before commissioning for having a base data and after 24 hrs. of charging subsequently to ensure no fault gas developed after first charging. DGA analysis helps the user to identify the reason for gas formation & materials involved and indicate urgency of corrective action to be taken 3.19 Thermovision Infra‐ red scanning (IR thermography)
A thermo vision Camera determines the temperature distribution on the surface of the tank as well as in the vicinity of the Jumper connection to the bushing. The information obtained is useful in predicting the temperature profile within the inner surface of tank and is likely to provide approximate details of heating mechanism. Thermovision scanning of transformer to be done at least after 24 hrs. of loading and repeated after one week.
1.0 TRANSFORMER AND REACTOR
1.1 Following points to be checked After Receipt of transformer /
reactor at Site:
1.1.1 N2 pressure and Dew point to be checked after receipt of transformer at Site. It should be within permissible band (as per graph provided by manufacturer & given below in Fig‐1)
1.1.2 The data of impact recorder shall be analyzed jointly in association with the
manufacturer. In case the impact recorder indicates some serious shocks during shipment, further course of action for internal inspection, if necessary shall be taken jointly. Impact Recorder should be detached from the Transformer/ Reactor preferably when the main unit has been placed on its foundation. 1.1.3 Oil Samples shall be taken from oil drums/ tanker received at site and sent to our Lab (CIOTL / IOTL) for oil parameter testing. The copy of test certificate of routine testing at oil refinery should be available at site for comparison of test results. 1.1.4 Unpacking and Inspection of Accessories to be carried out taking all precautions so that the tools used for opening do not cause damage to the contents. Fragile instruments like oil level gauge, temperature indicators, etc. are to be inspected for breakage or other damages. Any damaged or missing components should be reported to equipment manufacturer, so that the same can be investigated or shortage made up as per the terms/ conditions of the contract.
1.1.5 Core Insulation Test shall be carried out to check insulation between Core (CC&CL) and Ground. (Not applicable for Air Core Reactors)
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1.1.6 After receiving the accessories at site same should be inspected and kept ready for immediate erection: • If erection work can not start immediately due to some reasons, then accessories should be repacked into their own crates properly and packing list should be retained. • All packings should be kept above ground by suitable supports so as to allow free air flow underneath. The storage space area should be such that it is accessible for inspection; water does not collect on or around the area and handling/transport would be easy. Proper drainage arrangement in storage areas to be ensured so that in no situation, any component get submerged in water due to rain, flooding etc.. Immediately after the receipt of main unit and also the accessories, same should be inspected and if found satisfactory, the unit should be erected completely and filled with dry transformer oil as per the instruction. • It is preferable to store the main unit on its own location/foundation. If the foundation is not likely to be ready for more than three (3) months, then suitable action plan has to be taken from the manufacturer regarding proper storage of the Main Unit. • If the transformer/ Reactor is to be stored up to three (3) months after arrival at site, it can be stored with N2 filled condition. N2 pressure to be monitored on daily basis so that chances of exposure of active part atmosphere are avoided. In case of drop in pressure, dew point of N2 has to be measured to check the dryness of the Transformer/ Reactor.36
• In case of storage of transformer in oil‐filled condition, the oil filled in the unit should be tested for BDV and moisture contents once in every three months. The oil sample should be taken from bottom valve. If BDV is less and moisture contents are more than as given for service condition then oil should be filtered.
1.1.7 During erection, the exposure of active part of transformers should be minimized. Further either dry air generator should be running all the time or dry air cylinders may be used to minimize ingress of moisture. The transformer should be sealed off after working hours. It is practical to apply a slight overpressure overnight with dry air or N2 inside – less than 300 mbar (30 kPa or 0.3 atmospheres). Next day the pressure is checked and suspected leaks may be detected with leak detection instruments , with soap water or with plastic bags tightened around valves (being inflated by leaking air) For oil filled units whenever oil is drained out below the inspection covers, job will be treated as exposed. Other exposure activities are as below: 1) Bushing erections 2) Jumper connections of Bushings 4) Fixing bushing turrets on cover 5) Fixing bushing turrets on side 6) Core insulation checking 7) Buchholz relay pipe work fixing on cover. 8) Gas release pipes/equaliser pipe fixing. 9) Entering inside the tank for connections/inspection etc. For oil filled units depending upon the level up to which the oil is drained decides the exposure time. All such exposure time should be recorded in a log sheet to decide the oil processing (drying) and oil filling of transformer. For transformers with a gas pressure of 2.5‐ 3 PSI, the acceptable limits of dew point shall be as under:
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TABLE ‐ Variation of Dew Point of N2 Gas Filled in Transformer Tank w.r.t Temperature.38
Parameters of Transformer Oil
The oil sample from the transformer tank, after filling in tank before commissioning should meet the following specifications as per IS: 1866 – 2000 (latest Revision) given in table below:
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Testing of
Power Transformers
9. Partial Discharge Measurements.
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Partial Discharge Measurements
9.1 Purpose of measurement
A partial discharge measurement (PD‐measurement) is a nondestructive tool used to establish the condition of a transformer insulation system. The goal of partial discharge measurement is to certify that no harmful PD‐ sources exist. A PD‐measurement makes it possible to detect and localize areas within the transformer which are exposed to elevated dielectric stresses, i.e. stresses which in the long run can be harmful to safe transformer operation. Partial discharge measurements are explicitly specified in standards or in customer specifications. They are to be carried out in conjunction with dielectric tests in high voltage laboratories using AC‐voltage in the power frequency range. For HVDC transformers PD measurements are also carried out on dielectric tests with DC‐voltages For on‐site PD measurements (for example on repaired transformers) other types of PD‐free excitation may also be carried out [221]. Partial discharge measurement should generally be the last dielectric test conducted on the transformer.
9.2 General
Partial discharge is a partial voltage breakdown within a series of insulating elements between two electrodes of different potential, (capacitances C’2 and C’3, see figure 9.1). During a typical PD measurement, the magnitude of the detectable value of partial discharge activity is recorded as a function of the applied voltage. A partial discharge can be interpreted as the rapid movement of an electric charge from one position to another. For very fast changes, or during the first instant after charge movement, the individual insulation links in a series of connected links between two line terminals can be regarded as a number of series connected capacitors. BU = bushing HV = high voltage NT = neutral terminal C1, 2, 3 = active part of transformer (including oil) C1 = weak region Ct = test object capacitance (C’2 and C’3) Figure 1 : Schematic representation of a part of the transformer insulation.41
If the two line terminals are connected together via an external capacitor Ck, see figure 9.2, the charge movements within the series‐connected insulation links (capacitances C’2 and C’3, see figure 9.1) will also be reflected in the charge of external capacitor Ck. The charge movements can be detected as circulating current impulses i(t) in the parallel‐connected capacitors Ck and Ct, see figure 9.2. Ct = test object capacitance Ck = coupling capacitor G = voltage source i (t) = PD current pulses i~k,~t = displacement currents Z = voltage source connectors Q = transferred charge Ut = voltage at parallel‐connected capacitors Zm = measuring impedance Figure 9.2: Equivalent circuit for PD measurement.
Two requirements must be fulfilled to initiate a partial discharge (i.e. electric breakdown) within the weak region of an extended insulating system: • Local electric field stress E in the weak region must be greater than the inception electric field of the PD Source. • Free electrons must be available to initiate the electric breakdown, see clause A 9.1. Excessive stress in the weak region can result from design flaws, contamination or deviation from permissible tolerances in the manufacturing process, insulating material flaws, etc. Another possibility is hidden damage to the insulation caused by preceding tests.
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9.3 Principle of PD measurement
All PD measuring methods are based on the detection of PD current impulses i(t) circulating in the parallel‐ connected capacitors Ck (coupling capacitor) and Ct (test object capacitance) via measuring impedance Zm. The basic equivalent circuit for PD measurements is presented in figure 9.2 [212].The measuring impedance Zm can either be connected in series with coupling capacitor Ck or with the test object capacitance Ct.
As discussed in section 9.3 “General”, PD current impulses are generated by charge transfers between parallel‐ connected capacitor Ck (coupling capacitor) and Ct (test object capacitance).
Present IEC and IEEE Standards have both established rules for measuring and evaluating electric signals caused by partial discharges together with specifications on permissible magnitude.
The IEC approach to the processing of the recorded electric signal is different from the IEEE approach. IEC transforms the signal to an apparent electric charge generally measured in picocoulombs (pC), while IEEE transforms the signal to a Radio Interference Voltage RIV, generally measured in micro volts (μV). The use of the RIV‐method for PD‐signal detection will be abandoned, although the IEEE standard has not yet been officially approved. The detection of apparent charge in pC is the preferred method now in use in IEEE Std. C57.113 [56]. For the detection of apparent charge the integration of the PD‐current impulses i(t) is required. Integration of the PD current impulses can be performed either in the time domain (digital oscilloscope) or in the frequency domain (band‐pass filter). Most PD systems available on the market perform a “quasi integration” of the PD current impulses in the frequency domain using a “wide‐band” or “narrow‐band” filter, see clause A 9.2. Note: For short duration currents (ns‐range) the test voltage source is practically decoupled from the PD measuring circuit (parallel connection of Ck and Ct) by the inductive impedance Z (step‐up transformer connections). For the HV‐components without any bushing an external coupling capacitor Ck must be connected in parallel with the test object Ct, see figure 9.3.