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Compact design reduces volume by up to 33 percent and lowers environmental impact

ABB's latest generation 420 kV GIS (April 2012)

ABB's latest generation 420 kV GIS (April 2012)

Zurich, Switzerland, April 23, 2012 – ABB, the leading power and automation technology group, announced the launch of its new generation 420kV (kilovolt) Gas Insulated Switchgear (GIS) at the Hannover Fair being held in Germany from 23-27 April 2012. The new design reduces product volume by up to 33 per cent (width x depth x height) compared to its predecessor resulting in a considerably smaller footprint.

The compactness of the unit makes it ideally suited for installations where space is a constraint and also reduces the amount of SF6 insulating gas requirement by as much as 40 percent making it more environmentally friendly. It is also designed to enhance resource efficiency by reducing thermal losses, lowering transportation costs and optimizing investment in infrastructure.

The new GIS can be factory assembled, tested, and shipped as one bay in a container instead of multiple assembly units, saving site installation and commissioning time by up to 40 percent compared with traditional designs. Frontal access to drives, position indicators and service platforms enable easier operation, inspection and maintenance. Standardized modules and connection elements also enable flexibility in terms of configurations and building optimization.

The product features a fast single-interrupter dual motion circuit breaker and has been designed for current ratings up to 5000A (amperes). It is capable of providing protection to power networks with rated short-circuit currents up to 63kA (kilo amperes).

“A compact and more user friendly design, faster on-site commissioning and lower environmental impact are some of the key features of this latest generation of Gas Insulated Switchgear”, said Giandomenico Rivetti, head of ABB’s High Voltage Products business, a part of the company’s Power Products division. “The introduction of this 420kV GIS is part of ABB’s ongoing technology and innovation focus and follows the recent launch of our advanced 245kV and 72.5kV versions.”

In a power system, switchgear is used to control, protect and isolate electrical equipment thereby enhancing the reliability of electrical supply. With GIS technology, key components including contacts and conductors are protected with insulating gas. Compactness, reliability and robustness make this a preferred solution where space is a constraint (e.g. busy cities) or in harsh environmental conditions.

ABB pioneered high-voltage GIS in the mid-1960s and continues to drive technology and innovation, offering a full range product portfolio with voltage levels from 72.5kV to 1,100kV. As a market leader in high-voltage GIS technology, ABB has a global installed base of more than 20,000 bays.

ABB (www.abb.com) is a leader in power and automation technologies that enable utility and industry customers to improve their performance while lowering environmental impact. The ABB Group of companies operates in around 100 countries and employs about 135,000 people.


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Current Switching with High Voltage Air Disconnector

Current Switching with High Voltage Air Disconnector

In the paper are presented results of switching overvoltages investigations, produced by operations of air disconnector rated voltage 220 kV. Measurements of these switching overvoltages are performed in the air-insulated substation HPP Grabovica on River Neretva, which is an important object for operation of electric power system of Bosnia and Herzegovina.

Investigations of operating of air disconnector type Centre-Break were performed in order to determine switching overvoltage levels that can lead to relay tripping in HPP Grabovica. During operations of disconnector (synchronization or disconnecting of generator from network) malfunctions of signalling devices and burning of supply units of protection relays were appeared. Also, results of computer simulations using EMTP-ATP [1] are presented.

I. INTRODUCTION

Switching operation in power stations and substations, highvoltage faults and lightning cause high levels of high frequency overvoltages that can be coupled with low voltage secondary circuits and electronic equipment unless they are suitably protected. The function of high-voltage air-break disconnectors is to provide electrical isolation of one part of the switchgear.

Disconnector’s standards define a negligible current interrupting capability (≤0.5 A) or a voltage between the contacts if it is not significantly changed. These values of currents include the capacitive charging currents of bushing, bus bars, connectors, very short lengths of cables and the current of voltage instrument transformers. Disconnector’s contacts in air-insulated substations (AIS) are moving slowly causing numerous strikes and restrikes between contacts.

When the contacts are closed, the capacitive charging current flowing through the contacts ranges from 0.017×10-3 to 1.1×10-3 A/m for voltage levels 72.5 – 500 kV [2], depending on the rated voltage and length of bus, which is switched.

Strikes and restrikes occur as soon as the dielectric strength of the air between contacts is exceeded by overvoltage. The distance between contacts, the contacts geometry and relative atmospheric condition defines the overvoltage at the instant of strike. Every strike causes high-frequency currents tending to equalize potentials at the contacts. When the current is interrupted, the voltages at the source side and the loading side will oscillate independently. The source side will follow the power frequency while the loading side will remain at the trapped voltage. As soon as the voltage between contacts exceeds the dielectric strength of the air, at that distance the restrike will occur, and so on. Successive strikes occurring during the closing and opening operations of the off-loaded bus by the disconnector are shown in Fig. 1 a and b, respectively.

When closing takes place, the first strike will occur at the maximum value of the source voltage. Its values can be positive or negative. As the time passes a series of successive strikes will keep occurring at reduced amplitude, until the contacts touch. The highest transient overvoltage therefore occurs during the initial pre-arc, Fig.1 a. When the disconnector opening, restrikes occur because of the very small initial clearance between the contacts. At the transient beginning, the intervals between particular strikes are on the order of a millisecond, while just before the last strike; the period can reach about one half of cycle at power frequency, Fig. 1 b.

Fig. 1. The voltage due to the disconnector switching a)	Disconnector closing, b)	Disconnector opening 1-source side voltage, 2- load side voltage

Fig. 1. The voltage due to the disconnector switching a) Disconnector closing, b) Disconnector opening 1-source side voltage, 2- load side voltage

During the switching time of operations of disconnectors at HPP Grabovica up to 500 restrikes were registered. In paper [3] there are up to 5000 restrike registered during switching operation of the disconnector. The maximum value of voltages and maximum value of the wave front increasing will take place at the maximum distance between contacts. For the purpose of the investigation of the insulation strength and induction of electromagnetic interferences (EMI), the most important are the first few strikes during the closing operation or the last few strikes during the opening operation. Each individual strike causes a travelling wave with the basic frequency on the order 0.5 MHz (330 kHz-600 kHz). Very fast transient overvoltage due to the closing operation of the disconnector at the load side of the test circuit is shown in Fig.2.

Fig. 2. Very fast transient overvoltage due to the closing operation Channel 1- source side voltage Channel 2-load side voltage

Fig. 2. Very fast transient overvoltage due to the closing operation Channel 1- source side voltage Channel 2-load side voltage

These high-frequency phenomena are coupled with the secondary circuits as a result of various mechanisms. The strongest interference is exerted by the stray capacities between the high-voltage conductors and the grounding system, followed by the metallic link between the grounding system and the secondary circuits.

High-frequency transient current flowing in the grounding system generates potential differences, every time when a strike occurs between disconnector’s contacts. In large secondary circuits, the potential differences are in the form of longitudinal voltages between the equipment inputs and the equipment enclosures.

Depending on the type of secondary circuits used and the way they are laid, differential voltages may also occur. Such a coupling mechanism has a special effect on the secondary circuits of instrument transformers, and particularly on the connected instruments, since these circuits are always galvanically linked to the grounding system. Another factor, which cannot be discounted, is the linking of these circuits to the primary plant via the internal capacities of the instrument transformers [4].

Interference levels in secondary circuits of air-insulated substations during switching disconnectors depend on following parameters:

  • The transient voltages and currents generated by the switching operation;
  • The voltage level of the substation;
  • The relative position of the source of disturbances and susceptor;
  • The nature of the grounding network;
  • The cable type (shielded or unshielded);
  • The way the shields are grounded.

There are two main modes of coupling secondary circuits with primary circuits [3, 5]:

  1. Electromagnetic or EM coupling, which can be split into three sub-categories; inductive, capacitive and radiative. The most important source of EM coupling is the propagating current and voltage waves on bus bars and power lines during high-voltage switching operations by disconnectors;
  2. Common impedance coupling, as a result of coupling caused by the sharing of a lumped impedance common to both the source and susceptor circuits.

Common mode voltages, i.e., voltages measured between conductors and local ground, represent the main parameter used for assessing equipment immunity. The difficulty of comparing data comes from the fact that different authors performed measurements at different places (some measurements were made at the closest point to the disconnector being operated whereas others made measurements in the vicinity of the auxiliary equipment, i.e. in the relay room). Little information is available about the grounding practice of the neutral conductor in CT or VT circuits, the quality and grounding of the sable shields as well as how the measurements have been performed. Therefore, the measured levels have to be analyzed very carefully before comparison and drawing any conclusions [5]. Results of up to date measured common mode voltages at secondary circuits of CVT, CT and VT are presented in the paper [5]. There are maximum levels of the common mode voltages ranging from 100 Vpeak up to 2.5 kVpeak in the shields of the secondary circuits cables of the CT and VT. Results show that measured values of the common mode voltages at CT/CV secondary circuits, 220 kV ratings, range from Ucm=0.32 kVpeak [6] up to Ucm=0.85 kVpeak [7].

Results shown in paper [3] are for measured common mode voltages from 3-4 kV during switching operation by disconnector in 150 kV switchgear up to 6-10 kV at 400 kV switchgear.

II. RESULTS OF EXPERIMENTAL MEASUREMENTS ON SITE

The last ten years of extensive analysis of disconnector and circuit breakers generated EMI measurements that have confirmed that disconnector operation with off-loaded busbar is the most important and typical source of interference in secondary circuits of substations. Measurements of switching overvoltages generated during disconnector operation in the air insulated substation HPP Grabovica on the river Neretva were performed. HPP Grabovica is an important object for operating of electric power system of Bosnia and Herzegovina. Investigations of operating of air disconnector type Centre-Break were performed in order to determine switching overvoltage levels that can lead to relay tripping in HPP Grabovica [8].

During operations of disconnector (synchronization or disconnecting of generator from network) malfunctions of signalling devices and burning of supply units of protection relays were appeared. Malfunctioning of auxiliary circuits were manifested by tripping relay of differential protection of the generator, phase ’4′- signalization on relay box ‘ZB I‘ and signalling ‘fire’ in 35 kV control panel.

At the same time sparking between primary terminals of the current transformer (CT) was occurred. Malfunctioning of
signalling circuits were lower (not eliminated) with installing shielded cables. Also, independent of switching operation of air insulated disconnectors, during synchronization of generator AG1 on network, it’s happened that one of the pole of 220 kV circuit breaker failures. In this case generator AG1 worked in motor regime. Because of that, HPP Grabovica plans to install circuit breakers on generator’s voltage (10,5 kV) [9].

The field tests were performed at the test circuit at HPP Grabovica, Fig. 3.

Fig. 3. The considered test circuit VT-voltage transformer (220/√3/0.1/√3/0.1/√3 kV), CT-current transformer (200/1/1 A), CVD-capacitive voltage divider, CB-circuit breaker with two interrupting chambers and parallel capacitors (SF6 220 kV, 1600 A), Dc- disconnector (220 kV, 1250 A), MOSA-metal oxide surge arrester (Ur=199,5 kV, 10 kA), PT-power transformer (64 MVA, 242/10,5±5% kV, YD5), AG1- generator 1 (64 MVA, 10,5±5% kV)

Fig. 3. The considered test circuit VT-voltage transformer (220/√3/0.1/√3/0.1/√3 kV), CT-current transformer (200/1/1 A), CVD-capacitive voltage divider, CB-circuit breaker with two interrupting chambers and parallel capacitors (SF6 220 kV, 1600 A), Dc- disconnector (220 kV, 1250 A), MOSA-metal oxide surge arrester (Ur=199,5 kV, 10 kA), PT-power transformer (64 MVA, 242/10,5±5% kV, YD5), AG1- generator 1 (64 MVA, 10,5±5% kV)

The recorded wave shape of the overvoltage at the load side is shown in Fig. 4. The overvoltage factors at busbar, k, were recorded up to 1.16 p.u. with the dominant frequency of considered transient fd equal to 0.536 MHz. Common mode voltages, Ucm, at VT were up to 708 Vpeak, with dominant frequency equal to 1.31 MHz.

Fig. 4. Waveshape of the overvoltage Channel 1-voltage at CVD; ch 1 (2.5 V/div), probe 1x100, ratio 455 Channel 2-voltages at secondary of VT; ch 2 (5 V/div), probe 1x100

Fig. 4. Waveshape of the overvoltage Channel 1-voltage at CVD; ch 1 (2.5 V/div), probe 1x100, ratio 455 Channel 2-voltages at secondary of VT; ch 2 (5 V/div), probe 1x100

III. MODELING OF THE TEST CIRCUIT

Computer simulations were performed on the model of test circuit containing elements drawn in Fig. 5. Overvoltages at busbars were calculated during disconnector closing operations, for the same substation layout on which measurements were carried out.

Fig. 5. Model of the test circuit Arc-4 Ω; stray-200 pF; connection tube Z=370 Ω; CVD-R=300 Ω, C=1 nF; VT-500 pF; CB-2 capacitors, each C≅2 nF, (capacitance of open contacts, each C≅20 pF), Ccb=100 pF; CT-500 pF; MOSA-100 pF; connection wire Z=440 Ω; PT-3.5 nF

Fig. 5. Model of the test circuit Arc-4 Ω; stray-200 pF; connection tube Z=370 Ω; CVD-R=300 Ω, C=1 nF; VT-500 pF; CB-2 capacitors, each C≅2 nF, (capacitance of open contacts, each C≅20 pF), Ccb=100 pF; CT-500 pF; MOSA-100 pF; connection wire Z=440 Ω; PT-3.5 nF

The waveshape of simulated overvoltage surge at load side is given in Fig. 6. The difference between magnitudes of measured and simulated overvoltages is 5 %. The dominant frequency of simulated overvoltage is 0.620 MHz. Comparison between results of measured and calculated overvoltages certified a good agreement of obtained values.

Fig. 6. Waveshape of simulated overvoltage surge

Fig. 6. Waveshape of simulated overvoltage surge

When the Capacitive Voltage Divider (CVD) was excluded, there were higher values of calculated overvoltages (15% higher on amplitude and 6 % on frequency). Capacitive divider due to primary resistor equal to 300 W and primary capacitance equal to 1 nF influences on overvoltage at the same measurement point causing attenuation and damping of transient overvoltrages. In order to reduce EMI in secondary circuits the best way is to reduce sources of interference emission during switching of air insulated disconnector.

One of the ways of reducing is to install disconnecting circuit breakers. Substation disconnectors isolate circuit breakers from rest of the system during maintenance and repair. The maintenance requirements for modern SF6 high voltage circuit breakers are lower than maintenance demands made on disconnectors, which means one of reasons for disconnectors removed. Installing disconnecting circuit breaker there are no needs for switching operation of disconnectors. With disconnecting circuit breakers it is still possible to isolate the line, but low maintenance requirements means it is no longer necessary to isolate the circuit breaker. The disconnecting breaker had to be designed to safety lock in the open position, and to meet all voltage withstanding capabilities and safety requirements of disconnectors.

Another way of reducing sources of interference emission is to install circuit breaker without parallel capacitors to contacts. This suggestion is based on analyses performed on three circuit models:

  1. Model of CB with two breaking chambers and paralel capacitors and VT on netvork side of CB;
  2. Model of CB with two breaking chambers and without paralel capacitors and VT on netvork side of CB
  3. Model of CB with two breaking chambers and without paralel capacitors and VT on generator side of CB

Magnitudes of simulated overvoltages are presented in Table I. Voltages are measured in point of connection of VT, CT and PT.

TABLE I - MAGNITUDES OF SIMULATED OVERVOLTAGES

TABLE I - MAGNITUDES OF SIMULATED OVERVOLTAGES

Overvoltages on generator side of 220 kV CB during switching of disconnectors could be up to 320 V in the case of installing instrument voltage transformer (VT) on generator side of CB without parallel capacitors (near instrument current transformer CT). This case causes installing of circuit breaker at generator’s voltage (10,5 kV) for synchronization of generator to network (better conditions for synchronization). This solution of installing circuit breakers on generator’s voltage resulted from problems have occurred during synchronization of generatror with current 220 kV CB.

IV. CONCLUSION

Switching overvoltages due to disconnector operations have been analysed on the existing 220 kV AIS on HPP Grabovica. Measurements and calculations were conducted on the characteristic points in AIS, in order to determine the level of the EMI.

The result of measurements has shown that high frequency voltages on busbars occur with amplitudes up to 1.16 p.u. (233 kVpeak) and the dominant frequencies up to 0.6 MHz. The difference between magnitudes of measured and calculated overvoltages is 5 % and 15.6 % on frequency. Measured common mode voltages at secondary circuits were from 430 V up to 708 V. CVD influences on overvoltages at the same measurement point on busbars causing attenuation and damping of transient overvoltages.

Comparison of the transient computer simulations with field measurements showed that calculations could be used for
assessment of the transient overvoltages due to disconnector switching. In order to reduce EMI in secondary circuits, it is suggested to install switching modules and disconnecting circuit breakers [10] or to install circuit breakers without parallel capacitors to contacts.

AUTHORS: Salih Carsimamovic, Zijad Bajramovic, Miroslav Ljevak, Meludin Veledar, Nijaz Halilhodzic

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FIGURE 1 – Voltage gradient around a substation under fault condition

FIGURE 1 – Voltage gradient around a substation under fault condition

The purpose of this paper is to report a new test method and make a recommendation to improve the procedures according to the findings.

The test method involves measurement of high voltage substations earth grid impedance, by utilization of a variable frequency current source and frequency selective measurement techniques.

Safety policies require that the values of earth impedances remain within the specified acceptable range and every utility is required to guarantee safe step-and-touch potential levels. It is therefore necessary to carry out periodic testing on substation earthing to monitor the condition of the substation earthing system.

Knowledge of earth grid impedance of high voltage substations is also very important for correct operation of protection schemes and fault clearance. As the condition of grounding components change over time due to corrosion of earth cables, changes in the adjacent infrastructures and so on, it is necessary to measure the impedance of earthing grid periodically to ensure that the values are within expected range.

Knowledge of the overall resistance ZE allows calculation of the total voltage rise of a substation under maximum fault current. Knowledge of the voltage gradient around the substation, especially close to the substation allows calculation of the step-andtouch voltages under worst-case conditions.

Measurement principle

According to international standards such as CENELEC HD637S1 [1] or ANSI IEEE 80-2000 [2], 81-1983 [3] it is recommended to use a current-voltage method otherwise known as fall-of-potential [4].

Generally in a 90° angle (birds-eye view) two electrodes are placed outside the influence of the grounding system under test. One is used to inject the current (current electrode) and one to measure the voltage (voltage electrode). However because the area which is influenced by the grounding system is not so easy to determine, the current electrode is usually placed at a distance of at least 10 times, and up to 15 to 20 times the diameter of the grounding system under test. The voltage electrode then is placed in various distances.

Close to the system under test, large voltage degradation is visible. The further the voltage probe is located from the system under test, the more stable the measured voltages become (FIGURE 2 & 6).

FIGURE 2 – Voltage Degradation

FIGURE 2 – Voltage Degradation

Problems with Conventional Measurement Methods

For small grounding systems like a single tower, it is generally no problem to place the two needed electrodes and low currents generated by battery-operated equipment can generally do the job satisfactorily. However when measuring large substations, the distances are substantial and should be as large as 10 to 20 times the diameter of the substation. In some cases, measurements show peaks and drops until an area free of buildings and buried conductors or pipes is reached. Until then, erroneous results can be obtained.

Voltage drops can be observed when measurement points are set close to objects, like towers of power lines leaving the substation, connected to the grounding system under test. Voltage rises can be observed when for example measurement points are placed over a buried pipe that runs close to the current electrode. Therefore it is often difficult to distinguish between drops, rises and stable results.

To place the current electrode very far away is certainly a good idea, because then at least the influence of the current electrode can be minimized, however here the effort becomes even bigger. The biggest challenge is when the current electrode has to be relocated several times, before a stable measurement can be achieved.

Usage of existing power lines

One method to overcome these measurement problems is to use diesel generators (weighing several tons) to generate currents that have frequencies slightly different from mains frequency and to feed in the currents over existing, de-energized power lines leaving the substation. The grounding system of the remote substation where the power line terminates is used as current electrode (see FIGURE 2 Impedance Measurement).

The amount of current needed for such a test still has to be quite large to overcome mains frequency disturbances and the power requirement is enormous. But with these devices it is possible to measure ground impedances. However, the effort is by far too high to use it as a realistic approach for maintenance measurements.

Combination of the good ideas

FIGURE 3 – Test equipment for line impedance measurement

FIGURE 3 – Test equipment for line impedance measurement

A new approach of Omicron is to combine the principle of simple battery operated equipment based on the variable frequency principle and use the existing power lines and the grounding system of the remote substation as current electrode.

The test set CPC 100 and CP CU1 from OMICRON comprises of a frequency variable amplifier (29 kg), a coupling unit (28 kg) and a protection device (6 kg).

The CPC 100 is a multi-functional, frequency-variable test set for testing various primary equipments. It is capable of generating currents up to 800 A or voltages up to 2000 V, with special software modules to be used for various automated tests on CTs, VTs, power transformers or other primary equipments. With other accessories it can also be used for tangent delta testing on power transformer bushings or windings, with test voltages up to 12 kV.

In the application of ground impedance measurement it is used as frequency variable power generator, measurement tool and analyzer. Due to the variable frequency generation, it is possible to generate signals first under and then above mains frequency. Using digital filter algorithms, the test set will measure only the signal with the frequency that is currently generated and filters out signals at other frequencies. Disturbances due to noise and electrical interference thus no longer influence the result.

FIGURE 4 – Frequency selective measurement

FIGURE 4 – Frequency selective measurement

For safety reasons, the coupling unit CP CU1 is used for galvanic decoupling of the current output and the measurement inputs from the power line. This way, if fault or lightning occur during the test, the operator can be safe from dangerous voltages. For optimum performance there is a range selector switch for the current output, and a built-in voltmeter for a quick check of induced voltages or burden. Test currents of up to 100A can be generated for short cables, and for long lines of up to a few hundred kilometers, currents over 1A are still possible.

The protection device CP GB1 is a tool for easy connection to the overhead line or power cable and existing grounding cables of the substation may be used. In case of unexpected high voltage on the power line due to faults on a parallel system, lightning discharges or transients due to switching operations, the GB1 is capable of discharging short transients or permanently shorting fault currents of up to 30 kA for at least 100 ms. These features will protect the operator in unexpected situations.

The test itself is simple: the combination of CPC 100, CP CU1 and CP GB1 is connected to a de-energized power line (FIGURE 2&5); after removing the near end ground connection, test current with a different frequency than the mains frequency is injected. The voltage test probe then is located at various distances until stable voltage measurements can be observed. At this point the measurement is completed And the results can be stored in the CPC, downloaded to a PC and analyzed in a Microsoft Excel application.

Case study

The test was carried out on 7th October 2004 by confirming outage on Western Power Corporation’s Landsdale Northern Terminal line. Northern Terminal Substation was the remote terminal and the earth grid at Landsdale Substation was measured.

Earth Switches at both substations were closed and portable earths were applied to the lines in preparation for the test.
CPC 100 and CP CU20 (a predecessor of the CP CU1) were connected to the line as per test set up and voltage measurements stake was inserted at different distances from the test point in a different direction from that of the transmission line in order to avoid induction. Measurements were carried out and test files were saved to the CPC 100 memory to be retrieved in the office.

Test was performed at various frequencies (between 30-110 Hz) to suppress the noise and achieve a precise characteristic of the grid impedance under test. Impedances for 50Hz were extrapolated from the test results.

FIGURE 5 – Measurement of Landsdale Local Substation's Earth Grid

FIGURE 5 – Measurement of Landsdale Local Substation's Earth Grid

The mass of the earth is not the only path for feeding the ground current. All metal structures such as pipes tubes, railway lines and Multiple Earthed Neutral (MEN) of distribution systems between the test point and the current auxiliary electrode form the path for the ground current, including the shield wire on the top of the pole.

Test Results

The graph for the impedance measurement was as follows:

FIGURE 6 – Voltage degradation measurement results

The impedance profile of the earthing system was obtained and the stabilization of the impedance at a distance above 100m was obvious.

This data was then used to calculate the earthgrid potential rise during maximum earth fault conditions.

Conclusion

Substation earthing system testing using the conventional method is arduous, time consuming and involves multiple heavy equipment producing end results that are sometimes unreliable due to electrical interference and noise. The conventional method requires high test currents in order to achieve a higher signal-to-noise ratio, therefore heavy equipment and generators are required to produce such currents.

The alternative method using variable frequency technique, achieves the desired outcome with less cost, effort and resources and increases efficiency and accuracy.

AUTHORS
Dean SHARAFI – WESTERN POWER (Australia)
Ulrich KLAPPER  – OMICRON electronics (Australia)

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Connecting wind turbines to the power grid

Connecting wind turbines to the power grid

Precautions to be taken when connecting wind turbines to the power grid: The procedure for connecting wind turbines to an electric distribution network normally consists of 2 steps:

1. First, the HV/LV transformer is energized from the high voltage side,
2. Then, in the right wind conditions and further to wind turbine adjustment tests (initial pole test, pole test sequence, etc.), the turbine is connected to the power grid as follows:

  • The rotation of the wind turbine’s blades triggers the aerogenerator (motorgenerator set), which acts as a generator,
  • The transformer’s LV winding is energized by the wind turbine’s stator (connected by a star or delta connection) and hence provides electrical energy to the HV network.

However, during this 2-step process, the HV/LV transformer must not, in any event whatsoever, be supplied with high and low voltage currents at the same time. In such an event, there would be a risk of energizing the LV voltage side in opposite phase to the HV side.

The result would be an extremely strong current, the intensity of which would be greater than the brief, 3-phase short-circuit current stipulated in the contract (usually 2 seconds).

General diagram of a wind turbine installation

General diagram of a wind turbine installation

As the electrodynamic stress on the windings is proportional to the square of the current intensity (F = K.I2), the transformer can not, in general, withstand the extremely intense stress caused by a current greater than the contractual short-circuit current. This type of stress would automatically lead to significant, unacceptable and irreversible mechanical deformation of the LV and HV windings, and the LV connections: hence it would, in due course, totally destroy the transformer.

On-site transformer failures have occurred, as a result of energizing the LV and HV sides at the same time and failing to comply with the phase sequence of the LV network.

The LV winding was subjected to a current much stronger than the contractual 3-phase short-circuit current and, as a result, the transformer was completely destroyed by huge electrodynamic stress.
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Measures to apply in all circumstances…

Power HV/LV Transformer

Power HV/LV Transformer

Therefore, when connecting a wind turbine transformer to a power grid, it is absolutely essential not to energize the LV and HV sides of the transformer at the same time, which may cause the LV winding to be in opposite phase.

Hence, it is extremely important not to interfere with the various tripping sequences, and to comply with the adjustment specifications for the transformer in question.

If the transformer is energized from both sides and, in addition, the phase sequence of the LV network is not respected, the result will be total transformer failure.
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SOURCE: France Transfo

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Maintenance Of SF6 Gas Circuit Breakers

Maintenance Of SF6 Gas Circuit Breakers

Sulfur Hexafluoride (SF6) is an excellent gaseous dielectric for high voltage power applications. It has been used extensively in high voltage circuit breakers and other switchgears employed by the power industry.

Applications for SF6 include gas insulated transmission lines and’gas insulated power distributions. The combined electrical, physical, chemical and thermal properties offer many advantages when used in power switchgears.
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Some of the outstanding properties of SF6 making it desirable to use in power applications are:

  • High dielectric strength
  • Unique arc-quenching ability
  • Excellent thermal stability
  • Good thermal conductivity

Properties Of SF6 (Sulfur Hexafuoride) Gas

  • Toxicity – SF6 is odorless, colorless, tasteless, and nontoxic in its pure state. It can, however, exclude oxy­gen and cause suffocation. If the normal oxygen content of air is re­duced from 21 percent to less than 13 percent, suffocation can occur without warning. Therefore, circuit breaker tanks should be purged out after opening.
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  • Toxicity of arc products – Toxic decomposition products are formed when SF6 gas is subjected to an elec­tric arc. The decomposition products are metal fluorides and form a white or tan powder. Toxic gases are also formed which have the characteristic odor of rotten eggs. Do not breathe the vapors remaining in a circuit breaker where arcing or corona dis­charges have occurred in the gas. Evacuate the faulted SF6 gas from the circuit breaker and flush with fresh air before working on the circuit breaker.
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  • Physical properties – SF6 is one of the heaviest known gases with a den­sity about five times the density of air under similar conditions. SF6 shows little change in vapor pressure over a wide temperature range and is a soft gas in that it is more compressible dynamically than air. The heat trans­fer coefficient of SF6 is greater than air and its cooling characteristics by convection are about 1.6 times air.
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  • Dielectric strength – SF6 has a di­electric strength about three times that of air at one atmosphere pressure for a given electrode spacing. The dielectric strength increases with increasing pressure; and at three atmospheres, the dielectric strength is roughly equivalent to transformer oil. The heaters for SF6 in circuit breakers are required to keep the gas from liquefying because, as the gas liquifies, the pressure drops, lowering the dielectric strength. The exact dielectric strength, as compared to air, varies with electrical configuration, electrode spacing, and electrode configuration.
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  • Arc quenching – SF6 is approxi­mately 100 times more effective than air in quenching spurious arcing. SF6 also has a high thermal heat capacity that can absorb the energy of the arc without much of a temperature rise.
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  • Electrical arc breakdown – Because of the arc-quenching ability of SF6, corona and arcing in SF6 does not occur until way past the voltage level of onset of corona and arcing in air. SF6 will slowly decompose when ex­posed to continuous corona.

All SF6 breakdown or arc products are toxic. Normal circuit breaker operation produces small quantities of arc products during current interruption which normally recombine to SF6. Arc products which do not recombine, or which combine with any oxygen or moisture present, are normally re­moved by the molecular sieve filter material within the circuit breaker.

Handling Nonfaulted SF6

The procedures for handling nonfaulted SF6 are well covered in manufacturer’s instruction books. These procedures normally consist of removing the SF6 from the circuit breaker, filtering and storing it in a gas cart as a liquid, and transferring it back to the circuit breaker after the circuit breaker maintenance has been performed. No special dress or precautions are required when handling nonfaulted SF6.

Handling Faulted SF6

Toxicity

  • Faulted SF6 gas – Faulted SF6 gas smells like rotten eggs and can cause nausea and minor irritation of the eyes and upper respiratory tract. Normally, faulted SF6 gas is so foul smelling no one can stand exposure long enough at a concentration high enough to cause permanent damage.
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  • Solid arc products - Solid arc products are toxic and are a white or off-white, ashlike powder. Contact with the skin may cause an irritation or possible painful fluoride burn. If solid arc products come in contact with the skin, wash immediately with a large amount of water. If water is not available, vacuum off arc products with a vacuum cleaner.
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Clothing and safety equipment requirements

When handling and re­ moving solid arc products from faulted SF6, the following clothing and safety equipment should be worn:

  • Coveralls – Coveralls must be worn when removing solid arc products. Coveralls are not required after all solid arc products are cleaned up. Disposable coveralls are recommended for use when removing solid arc products; however, regular coveralls can be worn if disposable ones are not available, provided they are washed at the end of each day.
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  • Hoods – Hoods must be worn when removing solid arc products from inside a faulted dead-tank circuit breaker.
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  • Gloves – Gloves must be worn when solid arc products are hah-died. Inexpensive, disposable gloves are recommended. Non-disposable gloves must be washed in water and allowed to drip-dry after use.
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  • Boots – Slip-on boots, non-disposable or plastic disposable, must be worn by employees who enter eternally faulted dead-tank circuit breakers. Slip-on boots are not required after the removal of solid arc products and vacuuming. Nondisposable boots must be washed in water and dried after use.
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  • Safety glasses – Safety glasses are recommended when handling solid arc products if a full face respirator is not worn.
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  • Respirator – A cartridge, dust-type respirator is required when entering an internally faulted dead-tank circuit breaker. The respirator will remove solid arc products from air breathed, but it does not supply oxygen so it must only be used when there is sufficient oxygen to support life. The filter and cartridge should be changed when an odor is sensed through the respirator. The use of respirators is optional for work on circuit breakers whose in­ terrupter units are not large enough for a man to enter and the units are well ventilated.
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    Air-line-type respirators should be used when the cartridge type is ineffective due to providing too short a work time before the cartridge becomes contaminated and an odor is sensed.
    When an air-line respirator is used, a minimum of two working respirators must be available on the job before any employee is allowed to enter the circuit breaker tank.
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Disposal of waste

All materials used in the cleanup operation for large quantities of SF6 arc products shall be placed in a 55­ gal drum and disposed of as hazardous waste.

The following items should be disposed of:

  • All solid arc products
  • All disposable protective clothing
  • All cleaning rags
  • Filters from respirators
  • Molecular sieve from breaker and gas cart
  • Vacuum filter element

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Maintenance Of High Voltage Circuit Breakers

Maintenance Of High Voltage Circuit Breakers

Most manufacturers recommend com­plete inspections, external and internal, at intervals of from 6 to 12 months.

Ex­perience has shown that a considerable expense is involved, some of which may be unnecessary, in adhering to the manufacturer’s recommendations of in­ ternal inspections at 6 to 12 month intervals. With proper external checks, part of the expense, delay, and labor of internal inspections may be avoided without sacrifice of dependability.
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Inspection schedule for new breakers

A temporary schedule of frequent inspections is necessary after the erection of new equipment, the modification or modernization of old equipment, or the replication of old equipment under different condi­ tions.

The temporary schedule is required to Correct internal defects which ordinarily appear in the first year of service and to correlate external check procedures with internal conditions as a basis for more conservative maintenance program thereafter. Assuming that a circuit breaker shows no serious defects at the early complete inspections and no heavy interrupting duty is imposed, the following inspection schedule is recommended:

.6 months after erection.Complete inspection and adjustment
.12 months after .previous inspection.Complete inspection and adjustment
.12 months after .previous inspection.Complete inspection and adjustment
.12 months after .previous inspection.External checks and inspection; if checks are .satisfactory, no internal inspection
.12 months after .previous inspection.Complete inspection and adjustment

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Inspection schedule for existing breakers

The inspection schedule should be based by the interrupting duty imposed on the breaker. It is advisable to make a complete internal inspection after the first severe fault interruption. If internal conditions are satisfactory, progressively more fault interruptions may be allowed before an internal inspection is made. Average experience indicates that up to five fault interruptions are allowable between inspections on 230 kV and above circuit breakers, and up to 10 fault interruptions are allowable on circuit breakers rated under 230 kV.

Normally, no more than 2 years should elapse between external in­ spections or 4 years between internal inspections.

External Inspection Guide

The following items should be included in an external inspection of a high-voltage breaker.

  1. Visually inspect PCB externals and operating mechanism. The tripping latches should be examined with spe­ cial care since small errors in adjustments and clearances and roughness of the latching surfaces may cause the breaker to fail to latch properly or increase the force neces­ sary to trip the breaker to such an extent that electrical tripping will not always be successful, especially if the tripping voltage is low. Excessive “opening” spring pressure can cause excessive friction at the tripping latch and should be avoided. Also, some extra pressure against the tripping latch may be caused by the electro­ magnetic forces due to flow of heavy short-circuit currents through the breaker.
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    Lubrication of the bearing surfaces of the operating mechanism should be made as recommended in the manufacturer’s instruction book, but excessive lubrication should be avoided as oily surfaces collect dust and grit and get stiff in cold weather, resulting in excessive friction.
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  2. Check oil dielectric strength and color for oil breakers. The dielectric strength must be maintained to pre vent internal breakdown under voltage surges and to enable the interrupter to function properly since its action depends upon changing the internal arc path from a fair conductor to a good insulator in the short interval while the current is passing through zero. Manufacturer’s instructions state the lowest allowable dielectric strength for the various circuit break­ ers. It is advisable to maintain the dielectric strength above 20 kV even though some manufacturer’s instructions allow 16 kV.
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    If the oil is carbonized, filtering may remove the suspended particles, but the interrupters, bushings, etc., must be wiped clean. If the dielectric strength is lowered by moisture, an inspection of the fiber and wood parts is advisable and the source of the moisture should be corrected. For these reasons, it is rarely worthwhile to filter the oil in a circuit breaker while it is in service.
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  3. Observe breaker operation under load.
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  4. Operate breaker manually and electrically and observe for malfunc­ tion. The presence of excessive friction in the tripping mechanism and the margin of safety in the tripping function should be determined by making a test of the minimum voltage required to trip the breaker. This can be accomplished by connecting a switch and rheostat in series in the trip-coil circuit at the breaker (across the terminals to the remote control switch) and a voltmeter across the trip coil. Staring with not over 50 percent of rated trip-coil voltage, gradually in­ crease the voltage until the trip-coil plunger picks up and successfully trips the breaker and record the mini­ mum tripping voltage. Most breakers should trip at about 56 percent of rated trip-coil voltage.
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    The trip-coil re­ sistance should be measured and compared with the factor test value to disclose shorted turns.
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    Most modern breakers have trip coils which will overheat or burn out if left energized for more than a short pe­ riod. An auxiliary switch is used in series with the coil to open the circuit as soon as the breaker has closed. The auxiliary switch must be properly adjusted and successfully break the arc without damage to the contacts.
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    Tests should also be made to deter­ mine the minimum voltage which will close the breaker and the closing coil resistance.
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  5. Trip breaker from protective relays.
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  6. Check operating mechanism adjustments. Measurements of the mechanical clearances of the operat­ing mechanism associated with the tank or pole should be made. Appre­ ciable variation between the value found and the setting when erected or after the last maintenance overhaul is erected or after the last maintenance overhaul is usually an indication of mechanical trouble. Temperature and difference of temperature between different parts of the mechanism effect the clearances some. The manufacturers’ recommended tolerances usually allow for these effects.
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  7. Doble test bushings and breaker.
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  8. Measure contact resistance. As long as no foreign material is present, the contact resistance of high-pres- sure, butt-type contacts is practically independent of surface condition. Nevertheless, measurement of the electrical resistance between external bushing terminals of each pole may be regarded as the final “proof of the pudding.” Any abnormal increase in the resistance of this circuit may be an indication of foreign material in contacts, contact loose in support, loose jumper, or loose bushing connection. Any one of these may cause localized heating and deterioration.
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    The amount of heat above normal may be readily calculated from the increase in resistance and the current.Resistance of the main contact cir­ cuits can be most conveniently measured with a portable double bridge (Kelvin) or a “Ducter.” The breaker contacts should not be opened during this test because of possible damage to the test equip­ment.
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    Table 1
    gives maximum contact resistances for typical classes of breakers.
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    .Table 1 | Maximum contact resistances for typical classes of breakers
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  9. Make time-travel or motion-analyzer records. Circuit breaker motion an­ alyzers are portable devices designed to monitor the operation of power circuit breakers which permit mechanical coupling of the motion an­ alyzer to the circuit breaker operating rod. These include high-voltage and extra- high-voltage dead tank and SF6 breakers and low-voltage air and vac­ uum circuit breakers.
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    Motion analyzers can provide graphic records of close or open initiation signals, contact closing or opening time with respect to initiation signals, contact movement and velocity, and contact bounce or rebound. The records obtained not only indicated when mechanical difficulties are present but also help isolate the cause of the difficulties. It is preferable to obtain a motion-analyzer record on a breaker when it is first installed. This will provide a master record which can be filed and used for comparison with future maintenance checks.
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    Tripping and closing voltages should be re­ corded on the master record so subsequent tests can be performed under comparable conditions. Time-travel records are taken on the pole nearest the operating mecha­ nism to avoid the inconsistencies due to linkage vibration and slack in the remote phases..
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Internal Inpection Guide – Lines

An internal inspection should include all items listed for an external inspection, plus the breaker tanks or contact heads should be opened and the contacts nd interrupting parts should be inspected. These guidelines are not intended to be a complete list of breaker maintenance but are intended to provide an idea of the scope of each inspection.
A specific checklist should be developed in the field for each type of inspection for each circuit breaker maintained.
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Typical Internal Breaker Problems

The following difficulties should be looked for during internal breaker inspections:

  • Tendency for keys, bolts (espe- cially fiber), cotter pins, etc, to come loose.
  • Tendency for wood operating rods, supports, or guides to come loose from clamps or mountings.
  • Tendency for carbon or sludge to form and accumulate in interrupter or on bushings.
  • Tendency for interrupter to flash over and rupture static shield or resis­ tor.
  • Tendency for interrupter parts or barriers to burn or erode.
  • Tendency for bushing gaskets to leak moisture into breaker insulating material.

Fortunately, these difficulties are most likely to appear early in the use of a breaker and would be disclosed by the early internal inspections. As unsatis­ factory internal conditions are corrected and after one or two inspections show the internal conditions to be satisfactory, the frequency of internal inspections may safely be decreased.

Influence Of Duty Imposed

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Influence of light duty

Internal inspection of a circuit breaker which has had no interruption duty or switching since the previous inspection will not be particularly beneficial although it will not be a total loss. If the breaker has been energized, but open, erosion in the form or irregular grooves (called tracking) on the inner surface of the interrupter or shields may appear due to electrostatic charging current. This is usually aggravated by a deposit of carbon sludge which has previously been generated by some interrupting operation.
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If the breaker has remained closed and carrying current, evidence of heating of the contacts may be found if the contact surfaces were not clean, have oxidized, or if the contact pressure was improper. Any shrinkage and loosening of wood or fiber parts (due to loss of absorbed moisture into the dry oil) will take place following erection, whether the breaker is operated or not. Mechanical operation, however, will make any loosening more evident. It is worthwhile to deliberately impose several switching operations on the breaker before inspection if possible. If this is impossible, some additional information may be gained by operating the breaker several times after it is deenergized, measuring the contact resistance of each pole initially and after each operation.
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Influence of normal duty

The relative severity of duty imposed by load switching, line dropping, and fault interruptions depends upon the type of circuit breaker involved. In circuit breakers which employ an oil blast generated by the power arc, the interruption of light faults or the interruption of line charging current may cause more deterioration than the interruption of heavy faults within the rating of the breaker because of low oil pressure. In some designs using this basic principle of interruption, distress at light interrupting duty is minimized by multiple breaks, rapid contact travel, and turbulence of the oil caused by movement of the contact and mech­ anism.

In designs employing a mechanically driven piston to supple­ ment the arc-driven oil blast, the performance is more uniform. Still more uniform performance is usually yielded by designs which depend for arc interruption upon an oil blast driven by mechanical means. In the latter types, erosion of the contacts may appear only with heavy interruptions. The mechanical stresses which accompany heavy interruptions are always more severe.

These variations of characteristic performance among various designs must be considered when judging the need for maintenance from the service records and when judging the performance of a breaker from evidence on inspection. Because of these variations, the practice of evaluating each fault interruption as equivalent to 100 no-load operations, employed by some companies, is necessarily very approximate although it may be a useful guide in the absence of any other information.
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Influence of severe duty

Erosion of the contacts and damage from severe mechanical stresses may occur during large fault interruption. The most reliable indication of the stress to which a circuit breaker is subjected during fault interruptions is afforded by automatic oscillograph records. Deterioration of the circuit breaker may be assumed to be proportional to the energy dissipated in the breaker during the interruption.

The energy dissipated is approximately proportional to the current and the duration of arcing; that is, the time from parting of the contacts to interruption of the current. However, the parting of contacts is not always evident on the oscillograms, and it is sometimes necessary to determine this from indicated relay time and the known time for breaker contacts to part. Where automatic oscillograph records are available, they may be as useful in guiding oil circuit breaker maintenance as in showing relay and system performance.

Where automatic oscillographs are not available, a very approximate, but nevertheless useful, indication of fault duty imposed on the circuit breakers may be obtained from relay operation targets and accompanying system conditions. All such data should be tabulated in the circuit breaker maintenance file.
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SOURCE: HYDROELECTRIC RESEARCH AND TECHNICAL SERVICES GROUP

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