SHORT-CIRCUIT WITHSTAND OF T&D COMPONENTS R.P.P. SMEETS A.G.A. LATHOUWERS rene.s ren e.smeet meets@k s@kema ema.co .com m and andre. re.lath lathouw ouwers@ ers@kema kema.co .com m KEMA T&D Testing Services The Netherlands
1. SUMMARY
In present day networks for transmission tr ansmission and distribution, the level of maximum short-circuit short-circuit current is rapidly rising, creating increasing electro-dynamical electro-dynamical and thermal stresses. In the present contribution, the authors wish to share their experiences in verification of short-circuit withstand through testing. The following topics will be highlighted: Power transformers: the large experience of transformer transformer short-circuit withstand is discussed. It is the author's experience that 30% of the transformers fail upon first access of the test-site. Test-methods and test results will be presented. Internal arcs: A typical thermal stress related to a fault is the effect of internal arcs in switchgear panels and GIS GIS compartments. compartments. Backgrounds of the test, interpretation, interpretation, result and failure failure modes and and statistics will be presented. Also, the problem is discussed how to deal with SF6 filled metal enclosed switchgear, causing great environmental challenges in internal arc testing. Finally, guidelines will be given on the allowable amount of supply voltage reduction in the performance of these tests. Few other components will be highlighted as well, among others: Busducts: conductors, connecting power plant generators with downstream components components have to to endure extraordinary large short-circuit forces during a fault. Adequate testing can guarantee survival of this crucial connecting component. Disconnectors: Disconnectors Disconnectors need to conduct short-circuit current in closed position. Various experiences from testing, as well as failure modes will be presented. 2. SHORT CIRCUIT CURRENT ASYMMETRY 2.1 Asymmetrical current The wave shape of short-circuit short-circuit current right after its initiation is strongly determined by the X/R ratio of the circuit (part) in which it arises. This quantity is related to dc time constant () and power power factor factor (cos ) in the following following way: =
1
X
2 f R
;
X R
cos = cos arctan
with f the t he power frequency, X circuit reactance and R resistance. The effect of the DC time constant is the appearance of a DC component with a time constant of decay , superimposed on the symmetrical symmetrical AC current, the latter entirely determined by driving voltage and short circuit impedance. As a result, the sum of the two components has an asymmetrical asymmetrical shape, the peak value of which which can be substantially larger larger than without DC component. component. This is illustrated illustrated in fig. 1, where the interruption of a three-phase asymmetrical asymmetrical fault current is shown. The maximum asymmetrical asymmetrical current peak (case of fig. 1) will appear when short-circuit current starts at a zero crossing of the system voltage.
It is this high peak value that causes electro-dynamical stresses to all circuit parts in which the asymmetrical current flows. In addition, there are thermal stresses due to the resistive heating of conductors.
2.0
asymmetrical peak = APF/1.42
R
1.5
R S
1.0 0.5
T 0.0
The asymmetrical current peak factor (APF) is an important quantity in this respect and is defined as follows: APF =
-0.5
S -1.0
iˆ
0
I rms
with î the peak value of asymmetrical current and I RMS the RMS value of the AC current. In table 1, values of APF are tabulated for power frequencies of 60 and 50 Hz and various relevant dc time constants.
10
20
30
40
50
60
70
time (ms)
Fig.1: Asymmetrical three-phase fault current (maximum asymmetry in phase R) and dc component (dashed) for an ungrounded 60 Hz circuit with = 45 ms.
Both thermal and electro-dynamical stress are current, making it necessary to adapt the design of equipment as well as its lay-out in a station to the maximum value of APF. Also, testing of equipment, as described in the various standards should take into account current asymmetry without compromise. 2.2 Tendencies of increasing DC time constant
T
-1.5
proportional to the square of momentary (short-circuit) f req. 50 Hz 60 Hz
(ms)
45
60
90
120
133
X/R APF X/R
14.1 2.55 16.9
18.8 2.61 22.6
28.3 2.68 33.9
37.7 2.72 45.2
41.8 2.73 50.1
APF
2.59
2.65
2.70
2.73
2.74
Table 1
Partly initiated by economical considerations, DC time constants have increased in recent years [1], [2] because of: • the introduction of local energy generation within networks. Herewith, the large values of (sub)transient time constants of the generator become manifest; • tendency to use low-loss transformers (smaller copper losses, leading to a decrease of resistance, thus to higher DC time constants); • installation of power transformers with high short-circuit reactance in order to reduce the number of standard voltage levels in systems at the expense of larger tapping capability to reduce voltage drop (larger short-circuit reactance leading to higher DC time constant); • a move towards the use of transmission lines with larger cross sections and more conductor bundles in order to expand transport capability of existing lines (the transmission lines at UHV levels > 800 kV have DC time constants > 100 ms); • greater use of reactive components for short circuit limitation (e.g. reactors), often used as a solution to postpone the investment of switchgear with higher short-circuit current breaking capability. As a result, asymmetrical peak current has increased accordingly. This has led to the introduction of alternative time constants (besides the traditional = 45 ms) in the relevant IEC standard for circuit breakers (IEC 62271-100): • 120 ms for rated voltages 52 kV, generally for transformer dominated networks • 60 ms for rated voltages from 72,5 kV up to and including 420 kV • 75 ms for rated voltages 550 - 800 kV • 120 ms for rated voltages > 800 kV (proposal for future IEC 62271-100 standard)
In the IEEE standard C37.09, a preferred value of 45 ms is also recognized, but any other value, suggested by the user of the equipment, is acceptable. In the past, a DC time constant of 45 ms was assumed to be adequate in all cases. This is no longer a fact. 3. SHORT CIRCUIT CURRENT STRESSES TO POWER TRANSFORMERS
The effects of short-circuit currents in transmission and distribution networks for electric energy are tremendous, both for the equipment and for the stability of the networks. Since short circuits occur quite often, the short-circuit withstand capability is regarded as belonging to the main characteristics of the equipment installed. Transformers, like series reactors, have the ability to limit the short-circuit currents to values predominantly determined by the transformer's impedance. The control of the forces and stresses exerted by the same short-circuit currents inside the transformer must be an integral part of the design process [3]. With an increase of the short-circuit power during the years, the most severe short-circuit currents will appear when the transformer is aged. These short-circuit currents have to be withstood without impairing the transformer. Short-circuit withstand capability should also cover the ability to withstand several full asymmetrical short-circuit currents in each phase and in each representative tap position without impairing the transformer suitability for normal service.
Fig. 2: Buckling: Collapse of the cylindrical winding shell (photo ABB [5])
One of the methods for purchasers to assess the short-circuit current withstand capability of transformer is to conduct a design review, based on calculation results only. CIGRE issued guidelines on this method [4]. However, serious limitations of this method have been explained [5, 6, 7, 8, 9], as well as the possibilities to achieve a higher degree of reliability with respect to short-circuit withstand capability through full-scale testing in accordance with the international standards [10, 11, 12, 13].
3.1. Short-circuit stresses in the windings By means of all the short-circuit currents calculated for the different network conditions the electrodynamic stresses can in principle be determined. The electro-dynamic forces are proportional to the vector product of the current in a conductor and the magnetic induction at that location. The magnetic induction in and between the coils of a winding is varying in the radial direction as well as in the axial direction of the windings. Also, from the centre towards the ends of the coils, the direction of the magnetic induction is varying from predominantly axial to predominantly radial, influencing in this way the radial and axial stresses. The magnitude of the leakage fluxes is dependent on the currents and current directions in the different coils forming one phase. Such coils are for instance the coils forming one or two LV-windings, the HV-windings, the tapping windings and the compensation windings (when applied). The electro-dynamic forces appear in the radial direction (pushing the inner core inwards and the outer coil outwards) and in the axial direction (with a pulsating compression force). Related to the conducting material the forces can be translated into stresses: radial stresses and tangential stresses of a tensile or compressive nature. The stresses then can be compared with the material's characteristics in order to judge the probability of over-stressing the conductors and its supports. Radial stresses regularly lead to buckling of t he winding (see fig. 2), axial and radial forces have been observed to result in spiraling (see fig. 3) and/or tilting.
The electro-dynamic stresses are varying in time and space. By means of simplifications it is possible to calculate approximately the highest stresses that occur. The simplifications are: disregard of the influence of the other phases on the magnetic fields in a certain winding, calculate the forces and stresses for the current peaks and RMS values only, consider the windings as rigid (i.e. without any flexibility or settling effects), consider the coils as circular symmetrical, etc. The most onerous circumstances can be selected by such calculations and simulations. The transient mechanical behaviour of the windings (natural frequencies, damping, non-linear effects) and the production tolerances (tolerances in materials, processing, assembling, etc.) make it very complicated to exactly simulate the winding's behaviour. At the design stage extra margins are implemented to cover such effects.
3.2. Test practice Two methods of applying the short-circuit are defined in the standards: the pre-set and the post-set short-circuit method: a. Post-set short-circuit (fig. 4 upper). With the post-set method the transformer is energized at one side (the other side is open) and after the Fig. 3: Spiraling: Tangential inrush currents have disappeared the short-circuit is switched in at the shift of the end turns in helicalother side. Before short-circuiting, the source voltage Us appears at the type windings (photo ABB [7]) terminals of the transformer, so that the source voltage has to be limited in relation to the transformer voltage Ut. In the IEEE Standards a maximum source voltage of 110% related to the rated tap voltage of the transformer under test is allowed and in the IEC standards 115%. Because of the very large power needed, this method can in practice only be used by test stations that are fed directly from the power grid. The advantages of post-set testing are: • representative of the real network situation Fig 4: post-set (upper) and pre-set testing • accurate control of peak value of asymmetrical current is easier than in the pre-set situation (see below), especially if the transformer under test is fed through a short-circuit transformer and the make switch is placed upstream at generator voltage. b. Pre-set short-circuit (fig. 4 lower). With the pre-set method one side of the transformer is shortcircuited before the application of the voltage. The source voltage Us may differ to a large extent from the transformer voltage Ut, as long as the required short-circuit current flows. With the pre-set method the short-circuit current is superimposed on the inrush current, but, thanks to the short-circuited LV windings between the core and the energized winding, the inrush current is not comparable with a normal inrush current or the inrush current of the post-set method. Single phase testing methods. Three-phase transformers should preferably be tested three-phase. In case the voltage range is not sufficient or the short-circuit power is not enough, the testing authorities may use single-phase testing instead of three-phase testing. Like with three-phase testing, at each test one phase is subjected to the specified (peak) current value. During later tests the other phases are subjected to the required current. A much more realistic approach is the 1.5 phase method, that (unlike pure single phase methods), takes into account the dynamic interaction between the phase windings. With the 1.5 phase method, the phase under test is connected in series with the other two phases, which are connected in parallel. The currents in the two parallel connected phases are 50% of the specified three-phase value. At the moment of the peak in the phase, tested with 100% current, the current in the other two phases has equal value (1.28 pu) and polarity as would be in a three-phase test. Only half the power (single-phase power) is required from the test station compared to three-phase testing.
3.3 KEMA's experience on short-circuit current withstand 1996 – 2009 Having available 8400 MVA of direct generator-fed short-circuit power (world's largest), KEMA can test transformers up to very high MVA and kV ratings. Thanks to the generators, there is a good match of supply voltage with test-object, as well as sufficient time constant, and availability of power supply, which is not always the case in test stations that are supplied by the grid. An evaluation is made of short-circuit test results in the 14 year period 1996-2009. The tests are performed in accordance with IEC standard or IEEE standards on transformers with power 25 - 440 MVA and voltage 20 500 kV. The population includes single-phase and three-phase transformers, auto-transformers, step-up -, railway-, auxiliary- and threewinding transformers, 16 2/3, 50 and 60 Hz transformers, YD-, DY-transformers and YY autotransformers. The largest transformers tested are 250 MVA single-phase and 440 MVA three phase. In detail, the test-experience is as follows:
40 initially not OK s r e m r o f s n a r t f o r e b m u n
32
initially OK
24 16 8 0 25-50
50-100
100-200
>200
MVA (rated)
Fig.5: Initial failure rate for various ranges of MVA rating
36 s r e m r o f s n a r t f o r e b m u n
32
initially not OK
28
initially OK
24 20 16
During the past 14 years, in total 133 times a 12 test access for a transformer larger than 25 8 MVA (119 transformers from which 14 are 4 re-tested) has been counted: 0 20-100 100-200 200-300 300-400 >400 • 86 Transformers showed no problem at kV (r ated) the test-site. These transformers initially passed the short-circuit test. The final Fig. 6: Initial failure rate for various ranges of kV (primary) rating test-result is not always known because there was not always KEMA involvement in the subsequent routine tests, the inspection and the identification. In four cases, routine testing and/or visual inspection at the manufacturers site revealed an unacceptable problem that was not detected during short-circuit testing and its assessment. In total, 57 transformers were inspected at the manufacturer's site. • 33 Transformers showed a problem due to short-circuit stresses that became immediately apparent at the test site. Mostly, this problem was an unacceptable increase of short-circuit impedance due to the short-circuit stress, but a range of other more evident problems also occurred. • 14 Transformers from the latter group had been re-tested after modification in the factory and did not show a problem at the test site at the re-test. From these results, an initial failure rate is defined as the ratio of test objects that resulted in failure to pass the test at first access (33 transformers) and the total number of transformers (119). Thus, the initial failure rate is 28%. This is in the same order as the experience reported by another major test laboratory, that reports a failure rate of 20-25% out of 20 units > 100 MVA [14]. Other sources [15] state an overall failure rate of 23% for a total of 3934 tests.
In figs. 5 and 6 results are shown, differentiated in both power- and voltage class, not clearly showing a tendency of initial failure dependency on power or voltage. In fig. 7, the testing volumes and failure rates are indicated of tests at KEMA (>= 25 MVA). As can be seen, there is a significant increase in testing need in recent years. The overall tendency of failure rate is slowly decreasing in time, insofar the small population allows such a conclusion. Commonly, the reason of not passing short-circuit tests is because the winding reactance change (usually an increase) is larger than specified in the standards.
18 s r e m r o f s n a r t f o r e b m u n
16
initially not OK
14
initially OK
12 10 8
6 A wide variety of defects are revealed 4 such as: 2 • Axial clamping system: Looseness of 0 96 97 98 99 00 01 02 03 04 05 06 07 08 09 force in axial clamping, of axial year compression force, of axial supporting Fig. 7: Initial failure rate during the past 14 years 1996 - 2009 spacers and of top and bottom insulating blocks; • Windings: Axial shift of windings, buckling, spiraling of windings (helical or layer winding); • Cable leads: Mechanical movement, for instance from tap changer to regulating windings; deformed or broken leads, outward displacement and deformation of exit leads from inner windings; broken exit leads; • Insulation: Crushed and damaged conductor insulation; displacement of vertical oil-duct spacers; dielectric flashover across HV-winding or to the tank; displacement of pressboard insulation; tank current due to damaged conductor insulation; • Bushings: Broken or cracked LV-bushings; • Enclosure: Spraying of oil, exhaust of hot gases, evaporated oil, measurement of current to enclosure.
In the cases (the majority) that the reactance change is within the tolerances set by the standards, it is KEMA's observation that (visual) inspection only rarely (approx. 5% of the cases) still leads to rejection of a certificate. Nevertheless, visual inspection is necessary, because deformations and displacements in supporting structures, clamping systems, insulation materials, winding exit leads, external connections from the coils to the tap-changer and within the on-load tap-changer can not be detected by the reactance measurements only. Defects to the voltage regulation winding, could in several cases by unveiled by careful inspection of the pattern of reactance variations after each short-circuit tests. Later, by visual inspection, such defects came evident [16]. The authors conclude that the reactance variation is a very good tool to assess short-circuit withstand capability right after the short-circuit test. KEMA's experience with the short-circuit reactance measurements is that for power t ransformers a variation of more than 1.0% indicates a large deformation in one or more coils. Also a gradually increasing variation during the short-circuit tests, although in total not more than 0.5% to 1.0%, indicates a progressive movement of winding conductors. Variations of the reactance values between the shortcircuit tests in an unusual way are an indication of large flexibility of the windings. 4 SHORT CIRCUIT WITHSTAND OF METAL ENCLOSED SWITCHGEAR
A fault inside metal enclosed switchgear will lead to an internal arc. Internal faults inside metalenclosed switchgear can occur in a number of locations and will lead to internal arcs. Internal arcs initiate various physical phenomena. The arc energy resulting from an arc in any insulating medium within the enclosure will cause an internal overpressure and local overheating which will result in mechanical and thermal stressing of the equipment. Moreover, the materials involved may produce hot decomposition products, either gaseous or vaporous, which may be
discharged to the outside of the enclosure, and endanger personnel or general public. Relevant tests are defined in the IEC standard IEC 62271-203 [17] (for GIS), IEC 62271-200 [18], 201 [19], and IEEE guide C37.20.7 [20] (for metal/insulation enclosed switchgear). GIS > 52 kV (IEC 62271-203) Evidence of internal arc withstand of enclosure against bursting and burnthrough shall be demonstrated by the manufacturer when required by the user. The IEC standard allows evidence to consist of a test or calculations based on test results performed on a similar arrangement or a combination of both. Procedures and applications are described in [21, 22].
room simulation
indicator
Tests shall be carried out with the normal insulating gas, usually SF6, at rated filling density. The switchgear is considered adequate if no external Fig.8: Indicator racks located at front and lateral side of MV panel for internal arc effect other than the testing operation of pressure relief devices occurs within the specified time and if escaping gases are directed so as to minimize the danger to personnel. In test practice, because equipment of this voltage class is normally SF6 filled, and release of (contaminated) SF6 into the environment may not be acceptable, KEMA has the policy that such tests are performed on GIS (sections) that are contained in a pressure-resistant container of adequate size. Metal/insulation enclosed switchgear 52 kV (IEC 62271-200, -201, IEEE C37.20.7) Internal arc testing of MV metal enclosed switchgear is intended to offer a tested level of protection to persons in the immediate vicinity of switchgear in the event of an internal arc. Effects from internal fault arc, such as overpressure acting on covers, doors, inspection windows etc., as well as the thermal effects of arc(s), arc roots, ejected gas(es) and glowing particles are i ncluded. In contrast to internal arcing in GIS > 52 kV, the relevant IEC standard leaves no possibility to verify internal arc withstand through calculation, even not based on t esting equivalent designs. For this reason, and because of the generally much easier public accessibility of medium voltage installations compared to high-voltage installations, internal arc testing of metal enclosed medium voltage switchgear is very common. 4.1. Standardization status
With the advent of IEC 62271-200 in 2003 a classification (IAC, Internal Arc Classification) is defined, taking into account various possibilities of accessibility of the switchgear: Type A: Accessibility by authorized personnel only; Type B: By general public; Type C: Installation out of reach (pole mounted switchgear); For assessment of the thermal effects of the hot gases, expelled from the installation due to pressure rise from the fault arc, special black cotton cloth indicators (15x15 cm, in a steel frame to avoid
mutual ignition, see fig. 8) are used. The indicators are mounted on a rack (vertically and horizontally) arranged in a checkerboard pattern, covering 40-50% of the area of the accessible switchgear side, or of the 3x3 m2 area below the switchgear in case of pole mounted apparatus. The fabric imitates the clothing of people close to the installation. An important (the most critical) criterion to pass internal arc tests is the absence of ignition of indicators by hot gasses. Ignition by glowing particles, however, is allowed, and in order to make a distinction between the cause of ignition, high-speed video is normally used. However, in many cases, the real reason of ignition (hot gases or particles) can not be identified. Depending on the accessibility type, two degrees of flammability of the cotton indicator cloth are required, expressed in their specific weight (150 g/m2 for type A, 40 g/m2 for type B, C). Indicators have to be located at all accessible vertical sides of the switchgear, for type A at 30 cm distance and for type B at 10 cm distance. In addition, horizontal indicators have to be installed in a prescribed way. In order to represent the flow of expelled hot gases, the room in which the switchgear is to be installed is simulated with a floor, ceiling and two walls perpendicular to each other (see fig. 8). The room simulation does not represent the pressure- and temperature rise in the room, but is intended to represent realistic guidance of exhaust gases directly around the switchgear. Acceptance criteria to qualify the switchgear for an IAC classification are the following: Criterion 1: Doors and covers may not open. Deformations may not touch the indicator racks or walls; Criterion 2: No parts above 60 g may be projected; enclosure must remain intact during arcing; Criterion 3: Arc may not burn through an accessible side lower than 2 m high; Criterion 4: Indicators may not ignite due to the effect of hot gasses; Criterion 5: Connection of enclosure with earthing point remains intact. 4.2. Test result statistics 100% Results of its internal arc not fulfilled fulfilled tests have been analyzed 80% by KEMA. Most recent statistics are based on 91 tests in 2005 and 2006. It 60% is KEMA's experience that in approx. 80% of the 40% tests all criteria have been fulfilled. The most pro20% minent failure mode is related to criterion 4: the 0% absence of ignition of 1 2 3 4 5 total result indicators. In 15% of all criterium as specified in IEC 62271-200 A6 tests, indicators ignited. Fig. 9: KEMA's experience with rate of passing criteria of IEC 62271-200 (population: For comparison, earlier 91 tests in 2005 and 2006) data (2001-2002 when IEC 60298 was in use) are also evaluated (from 137 tests): 32% did not fulfill all criteria; also in that period, in 23% of the tests vertical indicators ignited, and in 11% horizontal ones [23] (IEC 60298 made a distinction between ignition of vertical and horizontal indicators). 4.3. Conditions of current and voltage The applied voltage should be equal to the rated voltage of the switchgear. In case of test-lab limitations, internal arc tests can be performed with lower than the rated voltage. This, however at the following conditions: 1. IEC 62271-200 stipulates that asymmetrical peak value of the short-circuit current should not be lower than 90% of the peak under rated voltage conditions. The internal arc has a reducing effect on the asymmetrical peak at reduced (low) voltages. With an arc voltage taken as 700 V calculations show that a 20 kA internal arc in switchgear with rated voltage between 12 and 36 kV, when tested in circuits with lower voltages (all with 20 kA), may be subjected to a strongly reduced
1
asymmetrical peak. This is quantified in fig. 10. Herein, the horizontal axis shows the fraction of prospective peak factor fraction of rated voltage, used as source 0.95 36 kV voltage, and vertically the resulting fraction of the full asymmetrical peak factor (2.55 in 50 Hz circuits). 24 k V 2. In addition, in circuits with lower voltage, 0.9 there is the risk of premature arc extinction, 17.5 kV which makes the test invalid. 3. AC current must be kept at a constant level 0.85 during the test duration of up to 1 s, and if 12 k V this is not possible, duration of the t est must be extended until the value of idt (taken as 0.8 being proportional to the arc energy assuming a constant arc voltage) equals the testvoltage specified value (within 0 to +10% 0.75 tolerance). This under the provision that t he 0.4 0.5 0.6 0.7 0.8 0.9 1 Fig.10: Reduction of prospective asymmetrical peak first three ac half-cycles are as specified and factor(vert) by arc voltage (700 V) vs test voltage (fraction current shall not be reduced by more than of rated voltage, hor.) for4 rated voltages. Inset: 50% of the specified value at the end of the prospective- and reduced current peak test. Such calculations, however, can only be performed at hindsight, since arc behaviour cannot be predicted, and leads to imprecise representation of stresses. prospective peak actual peak
2.5
2
1.5
1
0.5
0
-0.5
-1
0
0. 005
0. 01
0.015
0.02
0.025
0.03
0.035
0.04
0. 045
0. 05
4.4. Nameplate designation and certification
As a result of an internal arc test, IEC classification based on tests i s denoted in the nameplate as follows: - Classification IAC BFLR ("B" means accessibility type B, "FLR" means the Front, Lateral and Rear sides have been confronted with indicator racks and passed criterion 4 and the other criteria); - Internal arc 12.5 kA 0.5 s (means test have been performed with 12.5 kARMS and 0.5 s duration). KEMA (and other labs belonging to the Short-circuit Testing Liaison) does not issue certificates on internal arc tests only. Reasons for this are the following considerations: - Identification of the relevant parameters in the design verification is not clear. A well-defined system of documentation does not exist yet. Too little is known on what design parameters determine a positive result of a test - The results of tests have been found to depend strongly on arc initiation (method, single vs. three phase, location) and this, in turn, may depend on application - There are questions regarding the reproducibility of test results. 4.5 Internal arc testing in SF6 insulated switchgear
The background of having this on the agenda is the present discussion on banning SF6 as filling gas during internal arc testing of medium voltage SF6 insulated switchgear. In the present standard IEC 62271-200 it is stated (clause A.3.1): "It is permitted to replace SF6 with air at the rated filling conditions (± 10%)". From environmental reasons there is a clear motivation for this, since solid (metal-sulphides and fluorides) as well as gaseous SF6 decomposition products, especially in the presence of humidity (SF4, H2S, SO2, HF, CF4, S2F10, S2OF10) are mostly very poisonous. In addition, test-labs wish to minimize their emission of clean SF6, a greenhouse gas, and certainly polluted SF6. A series of new tests were performed (KEMA USA), purely aimed at comparing the effects of arcing in SF6 with air under identical conditions of current, driving voltage, arc duration, geometry, contact
material etc. Test parameters were: arc current 14.2 ± 0.3 kA, driving voltage 15.5 kV and tank volume 0.53 m3. 4 The following differences arcing volume between (short-circuit) arcing in air and SF6 were reported [24]: 3 ) r a b ( e s i r e r u s s e r p
a. Arc energy (at constant short circuit current). In literature there 2 are quite different statements about the value of SF6 arc voltage compared to that in air at the 1 same pressure: In some exhaust volume experiments a lower voltage was 0 obtained, in others a higher one. 0 500 1000 150 Analyzing these results it seems time (ms) to depend mainly on electrode Fig. 11: Pressure rise in arcing- and exhaust volume for air-filled geometry. If the arc is somehow (blue) and SF 6 filled (red) arcing volume (1 s arc duration). stabilized and/or arc bending is Vertical markers: pressure relief action (diaphragm burst) impeded, SF6 arc voltage is lower than in air. On the contrary, if the arc is allowed to move and bend and especially with strong metal evaporation (e.g. at longer arc duration), the voltage of SF6 arcs is higher. From this it follows that t he arc energy of arcs in air in a worst-case situation should be regarded as being lower than i n SF6. b. Pressure inside the arc compartment . As shown by several authors the maximum pressure in a closed arc compartment is higher if it is filled with air instead of SF6. This can be seen in fig. 11, where it is clear that both rate-of-rise of pressure as well as maximum pressure are higher in the airfilled container. This effect is true even when the arc energy in SF6 is higher than in air. The reason is the larger heat capacity of SF 6, which compensates the higher arc energy. The smaller heat capacity of air leads to a faster pressure rise and an earlier burst of the rupture disc. With a relief opening of the arc compartment the pressure rise is limited. In tendency, the opening will act at a higher pressure in air due to inertia effects. From this it follows that the arc compartment will be stressed in comparable or even more severe way by an arc in air. c. Exhaust of gases via an intermediate compartment. If the overpressure of the arc compartment is directly discharged into the environment (room), the hot gas stream will affect the indicators immediately. However, in general, metal-enclosed switchgear consists of several compartments with only the "arcing" compartment filled with SF6. In this case, hot SF6 first of all will exhaust to a neigh bouring air-filled compartment (intermediate room, e.g. cable compartment, pad mount enclosure) within the switchgear before leaving it e.g. through fissures. In this case the overpressure within the intermediate compartment will be lower if the arc compartment is filled with air instead of SF6 (due to the lower energy content of the heated air). This effect can be seen in fig. 11, where pressure rise in the air-filled exhaust volume reaches a higher value if the arcing volume is filled with SF6.
5 OTHER T&D COMPONENTS
Apart from the cases described above, high current withstand (with or without arc) is verified also for the following cases: a) Surge arresters: the relevant test for t he surge arrester is the short-circuit test (formerly referred to in the IEC standard as "pressure relief test"). Hereby, conditions are created in which an internal short-circuit is forced by suitable pre-conditioning [25]. As shortly as possible after initiation of an (internal) fault arc in the arrester body, pressure rise that might cause explosion must be mitigated by
suitable pressure relief measures. This is explained in fig. 12, showing the expulsion of the high-current arc outside of the arrester by a venting system at both terminals of the device. In case no special venting outlets are built-in, the venting is through the polymer housing. IEC describes that the arrester passes the shortcircuit tests if: • there are no ceramic (ZnO, porcelain) fragments heavier than 10 g expelled outside a defined circumference around the arrester; • the arrester must be able to self extinguish flames within 2 minutes. b) Disconnectors: the relevant issue is that disconnectors have to remain in closed position at full fault current. KEMA has experience up to 80 kA for 245 kV disconnectors.
Fig 12. Operating principle of porcelain and tubular design. Left: Arrester in its healthy state. Middle: Arrester has failed short-circuit, pressure relief plates open and gas begins to be expelled through the venting ducts Right: The two gas streams meet and the internal arc is commutated safely to the outside. This must normally occur before the first peak of current approx. within 5 - 10 ms.
c) Busducts: busducts are the conductors in t he power plants, and may have to endure extreme currents. KEMA has experience with shortcircuit current testing up to 275 kARMS (three phase current) during 0.7 s. Main failure mode are the insulators, that are observed to be very critically stressed.
d) Overhead lines and accessories: KEMA has experience with overhead line testing up to 100 kA, including power arc tests at 100 kA. Power arc tests are tests to verify the integrity of line insulators under the influence of very severe arcing in the immediate vicinity. The challenge of high-current tests in which fault arcs are involved is to supply the arc current at sufficient voltage, i.e. a voltage much higher than the arc voltage. Especially at long arcs (with corresponding high arc voltage, this is a demanding matter. e) Complete substations: In some cases, the critical components of stations (disconnectors, busbars, insulators) are assembled in the laboratory in order to make a representative model of a station. In various instants, the suitability of an upgrade of short-circuit current from 63 to 80 kA has been verified. REFERENCES
[1] CIGRE WG13.04: Specified Time Constants for Testing Asymmetric Current Capability of Switchgear, Electra, 173, 1997, pp.19 - 31 [2] W.M.C. van den Heuvel, A.L.J. Janssen, G.C. Damstra, "Interruption of Short Circuit Currents in MV networks with Extremely Long Time Constant", IEE Proc., vol. 136, Pt. C., No. 2, 1989,115 119 [3] CIGRE WG 12.19: "The Short-Circuit Performance of Power Transformers", CIGRE Technical Brochure 209, August 2002 [4] CIGRE WG 12.22: "Guidelines for Consulting Design Reviews for Transformers 100 MVA and 123 kV and above", CIGRE Technical Brochure 204, August 2002. [5] T. Fogelberg, "Short-Circuit Withstand Capability of Power Transformers", ABB Review 2008 [6] G. Bertagnolli, "Short-circuit Duty of Power Transformers", Book printed on behalf of ABB Trasformatori Legano (Milano), Italy, 3rd ed. 2006. [7] A.J.L.Janssen and L.H. te Paske: "Short-Circuit testing experience with large power transformers", CIGRE SC12 Session 2000, report 12-105. [8] Macor, G. Robert, D. Girardot, J.C. Riboud, T. Ngegueu, J.P. Arthaud, E. Chemin, " The Short-
Circuit Resistance of Transformers: The Feedback in France Based on Tests, Service and Calculation Approaches". CIGRE Conference, paper 12-102, 2000. [9] N.V.C. Sastry, H. Gupta, "Short-Circuit Test on EHV Transformers", 9th Int. Conf. on ShortCircuit Currents in Power Systems, Cracow 2000 [10] IEC standard 60076-5: Power Transformers - Part 5: "Ability to withstand short-circuit", 2000 [11] IEEE Std C57.12.00-1993: "IEEE Standard General Requirements for Liquid-Immersed Distribution, Power, and Regulating Transformers" [12] IEEE Std C57.12.90-1993, Part I: "IEEE Standard Test Code for Liquid-Immersed Distribution Power, and Regulating Transformers" [13] IEEE Std C57.12.90-1993, Part II: "IEEE Guide for Short-Circuit Testing of Distribution and Power Transformers". [14] M. de Nigris, "Checking the Short-Circuit Withstand of Power Transformers: CESI perspective", KEMA Int. Symp. on High Power Testing, Nov. 2004 [15] Mengyun Wang, "1995-1999 Fault Statistics & Analysis All Transformer Type in China", Electrical Equipment 2(1), 2001 [16] R.P.P. Smeets, L.H. te Paske, "Thirteen Years Test Experience with Short-Circuit Withstand Capability of Large Power Transformers", 8th Int. Conf. on Transformers, TrafoTech 2010, Mumbai, India [17] IEC Int. Standard 62271-203: Gas-insulated metal-enclosed switchgear for rated voltages above 52 kV, 2003. [18] IEC Int. Standard 62271-200: AC metal-enclosed switchgear and controlgear for rated voltages above 1 kV and up to and including 52 kV, 2003. [19] IEC Int. Standard 62271-201: AC insulation-enclosed switchgear and controlgear for rated voltages above 1 kV and up to and including 52 kV, 2006. [20] IEEE Standard C37.20.7 IEEE Guide for Testing Medium Voltage Metal-Enclosed Switchgear for Internal Arcing Faults, 2001. [21] N. Giao Trinh, "Risk of Burn-Through - a Quantitative Assessment of the Capability of Gas Insulated Equipment to Withstand Internal Arcs", IEEE Trans. on Pow. Del, vol.7 no.1, 1992 [22] CIGRE WG 23.03, "Pressure Rise in Metal-Enclosed Switchgear of Single Phase Enclosure Type due to Internal Arc. Evaluation of various International Test Results and Study of Calculation Procedure", Electra 93, pp.25-52, 1984. [23] P.P. Leufkens, prepared contribution, Int. Conf. on El. Distr. (CIRED) 2003. [24] R. Smeets, J. Hooijmans, H. Bannink, H. Barts, P. Leufkens, N. Uzelac P. Milovac, D. Kennedy, G.J. Pietsch, K. Anantavanich , "Internal Arcing: Issues Related to Testing and Standardization", CIGRE Conference Aug. 25-29 2008, paper A3-207 [25] R.P.P. Smeets, H. Barts, W.A.van der Linden, L.Stenström, "Modern ZnO Surge Arresters under Short-Circuit Current Stresses: Test Experiences and Critical Review of the IEC Standard", CIGRE Conference 2004
