Untitled NORME INTERNATIONALE CEI IEC INTERNATIONAL STANDARD 60076 7 Première édition First edition 2005 12 Transformateurs de puissance – Partie 7 Guide de charge pour transformateurs immergés dans l[.]
Introduction
The normal life expectancy serves as a conventional benchmark for continuous operation at the specified design ambient temperature and assigned operating conditions Applying a load that exceeds the nameplate rating and/or operating at a higher ambient temperature than the design temperature introduces a degree of risk and accelerates aging This is the focus of the current section.
CEI 60076 d'identifier de tels risques et d'indiquer comment, dans certaines limites, les transformateurs peuvent être chargés au-delà des caractéristiques de la plaque signalétique
Buyers can mitigate these risks by clearly specifying the maximum load conditions, while suppliers can address these conditions in their design process.
Symbol Meaning Units θ h Hot-spot temperature °C θ ma Monthly average temperature °C θ ma-max Monthly average temperature of the hottest month, according to
IEC 60076-2:1993 °C θ o Top-oil temperature (in the tank) at the load considered °C θ ya Yearly average temperature, according to IEC 60076-2:1993 °C τ o Average oil time constant min τ W Winding time constant min
∆θ br Bottom oil (in tank) temperature rise at rated load (no-load losses + load losses)
∆θ h Hot-spot-to-top-oil (in tank) gradient at the load considered K
∆θ hi Hot-spot-to-top-oil (in tank) gradient at start K
∆θ hr Hot-spot-to-top-oil (in tank) gradient at rated current K
∆θ o Top-oil (in tank) temperature rise at the load considered K
∆θ oi Top-oil (in tank) temperature rise at start K
∆θ om Average oil (in tank) temperature rise at the load considered K
∆θ omr Average oil (in tank) temperature rise at rated load (no-load losses + load losses)
∆θ or Top-oil (in tank) temperature rise in steady state at rated losses (no-load losses + load losses)
∆θ' or Corrected top-oil temperature rise (in tank) due to enclosure K
∆(∆θ or ) Extra top-oil temperature rise (in tank) due to enclosure K
5 Effect of loading beyond nameplate rating
Normal life expectancy serves as a standard reference for continuous operation under specified ambient temperatures and rated conditions Exceeding the nameplate rating or operating in higher ambient temperatures increases the risk of accelerated aging This section of IEC 60076 aims to identify these risks and provide guidance on safely loading transformers beyond their nameplate ratings To mitigate these risks, it is essential for the purchaser to specify maximum loading conditions, which the supplier should consider during transformer design.
Conséquences générales
Operating a transformer beyond its nameplate ratings can lead to several critical issues Firstly, the temperatures of the windings, supports, connections, insulation, and oil can rise to unacceptable levels Secondly, the magnetic induction of the leakage flux outside the magnetic circuit increases, resulting in higher heating due to eddy currents in the metal parts affected by the leakage flux Additionally, temperature variations can alter the humidity levels and gas content in the insulation and oil Lastly, components such as bushings, tap changers, cable terminations, and current transformers experience increased stress, which diminishes their design and application margins.
La combinaison du flux principal et du flux de fuite accru restreint les possibilités de fonctionnement du circuit magnétique en surexcitation [1], [2], [3] 1
For column-type transformers that facilitate energy transfer from the outer winding (typically high voltage) to the inner winding (usually low voltage), the maximum magnetic induction occurs in the end caps This induction is a result of the combination of the main flux and the leakage flux within the magnetic circuit.
Tests indicate that the magnetic flux is less than or equal to the flux generated by the same voltage applied to the open terminals of the transformer's outer winding In a loaded transformer, the magnetic flux in the wound columns of the magnetic circuit is determined by the voltage at the terminals of the inner winding and is nearly equal to the flux produced by the same voltage when unloaded.
For column-type transformers with energy transfer from the inner winding, the maximum magnetic induction occurs in the wound columns of the magnetic circuit This value is slightly higher than that observed for the same voltage applied under no-load conditions The induction in the end caps is then determined by the voltage across the outer winding.
It is essential to monitor the voltages on both sides of the transformer under load conditions that exceed the nameplate specifications As long as the voltages supplying a transformer remain below the limits specified in Article 4 of IEC 60076-1, no excitation restrictions are necessary during operation beyond the nameplate characteristics However, when higher excitations occur to maintain voltage during emergency conditions, it is crucial that the magnetic circuit's induction values do not exceed levels where the flux is no longer confined within it (for cold-rolled grain-oriented sheets, saturation effects begin to manifest above 1.9 T) Excessive stray flux can unpredictably raise temperatures on the magnetic circuit's surface and in nearby metallic components, such as the winding clamping system or even within the windings, due to high-frequency components in the stray flux, potentially jeopardizing the transformer Generally, the short overload times imposed by the windings are brief enough to prevent overheating of the magnetic circuit during overexcitation, as the core's high thermal time constant mitigates this phenomenon.
Consequently, there is a risk of premature failure associated with increased currents and temperatures This risk can be immediate in the short term or may arise from the cumulative effects of thermal aging of the transformer's insulation over many years.
Effets et risques d'un régime de charge de secours de courte durée
A short-duration increased load can lead to a service condition with a higher risk of failure Temporary overloads may cause hotspots in conductors, potentially resulting in a temporary reduction of dielectric strength However, accepting this condition for a brief period may be preferable to experiencing a power loss Such overloads are rare and should be quickly reduced or the transformer disconnected to prevent failure The allowable duration of this load is shorter than the thermal time constant of the transformer and depends on the operating temperature prior to the load increase, typically lasting less than half an hour.
1 Les chiffres entre crochets renvoient à la bibliographie
Loading a transformer beyond its nameplate rating can lead to several serious consequences Firstly, the temperatures of the windings, cleats, leads, insulation, and oil may rise to unacceptable levels Additionally, increased leakage flux density outside the core can result in extra eddy-current heating in metallic components affected by this flux Furthermore, temperature fluctuations can alter the moisture and gas content in both the insulation and oil Lastly, components such as bushings, tap-changers, cable-end connections, and current transformers will experience heightened stress, potentially exceeding their design and application limits.
The combination of the main flux and increased leakage flux imposes restrictions on possible core overexcitation [1], [2], [3] 1
For loaded core-type transformers, energy flows from the outer high voltage (HV) winding to the inner low voltage (LV) winding The maximum magnetic flux density in the core, resulting from the combination of the main flux and leakage flux, is observed in the yokes.
Tests show that the magnetic flux in a loaded transformer is less than or equal to the flux produced by the same applied voltage at the outer winding's terminals under no-load conditions The flux in the core legs of the transformer is primarily influenced by the voltage at the inner winding's terminals and is nearly equal to the flux generated by the same voltage when the transformer is under no-load.
In core-type transformers, the maximum flux density occurs in the core legs when energy flows from the inner winding, and this value is only marginally greater than the flux density observed under no-load conditions at the same applied voltage Meanwhile, the flux density in the yokes is influenced by the voltage applied to the outer winding.
Monitoring the voltages on both sides of a loaded transformer is crucial when operating beyond its nameplate rating As long as the voltages on the energized side remain within the limits specified in IEC 60076-1, Clause 4, no excitation restrictions are necessary However, if higher excitations are required to maintain voltage during emergency conditions, it is essential to ensure that the magnetic flux densities in the core do not exceed critical levels, particularly above 1.9 T for cold-rolled grain-oriented steel, to prevent core flux straying Stray fluxes can lead to dangerously high temperatures in the core and nearby metallic components, posing a risk to the transformer Fortunately, the short overload durations allowed by the windings are typically brief enough to prevent core overheating due to overexcitation, thanks to the core's long thermal time constant.
Increased currents and temperatures can lead to a risk of premature failure in transformers, which may arise either immediately or from the long-term cumulative effects of thermal aging on the insulation over several years.
5.3 Effects and hazards of short-time emergency loading
Short-term increased loading can elevate the risk of failure in service conditions Emergency overloading may cause conductor hot-spots to reach levels that temporarily reduce dielectric strength While accepting this condition briefly may be preferable to losing supply, such loading should be rare and must be quickly mitigated or the transformer disconnected to prevent failure The allowable duration for this increased load is typically less than half an hour and is influenced by the operating temperature prior to the overload, remaining shorter than the thermal time constant of the transformer.
1 Numbers in square brackets refer to the bibliography
The primary risk for short-duration failures is the reduction of dielectric strength caused by the potential presence of gas bubbles in areas of high electrical stress, such as windings and connections These bubbles are likely to form when the hot spot temperature exceeds 140 °C in a transformer with approximately 2% moisture content in the winding insulation This critical temperature decreases as moisture concentration increases Additionally, gas bubbles can develop on the surfaces of massive metallic parts heated by leakage currents or may be produced by oil supersaturation However, such bubbles typically form in regions with low dielectric stress and must migrate to areas with higher stress before a significant reduction in dielectric strength occurs.
Bare metal parts, excluding windings, that are not in direct thermal contact with cellulosic insulation but are in contact with non-cellulosic insulation (such as aramid paper or fiberglass) and oil in the transformer can quickly reach high temperatures It is crucial to avoid exceeding a temperature of 180 °C Temporary degradation of mechanical properties at elevated temperatures may reduce short-circuit withstand capability Pressure buildup in penetrations can lead to failure due to oil leakage, and gas may also form in capacitor penetrations if the temperature of the insulators exceeds approximately 140 °C Additionally, oil expansion can cause overflow in the conservator, and interrupting excessively high currents in the tap changer can be hazardous.
Limitations on maximum hot spot temperatures in windings, the magnetic circuit, and structural components are based on short-term risk considerations.
Short-term risks typically diminish once the load is reduced to a normal level; however, it is essential that these risks are clearly identified and accepted by all stakeholders, including planners, asset holders, and operators.
Effets du chargement d'urgence de longue durée
The occurrence of this condition is not typical and is considered rare, yet it can persist for weeks or even months, leading to significant aging a) The mechanical properties of conductor insulation deteriorate more rapidly at elevated temperatures, potentially reducing the effective lifespan of the transformer, especially during short circuits or transport events b) Other insulation components, particularly those supporting the axial pressure of the winding block, may also experience accelerated aging at higher temperatures c) The contact resistance of tap changers can increase under high currents and temperatures, with extreme cases risking thermal runaway d) Additionally, the joints of the transformer may become more brittle at elevated temperatures.
Les règles de calcul pour une vitesse de vieillissement relative et la consommation de durée de vie en pourcentage sont fondées sur des considérations de risques à long terme
The primary risk associated with short-term failures is the decrease in dielectric strength, which can result from the presence of gas bubbles in areas of high electrical stress, such as the windings and leads These gas bubbles are more likely to form when the hot-spot temperature surpasses a critical threshold.
A critical temperature of 140 °C is observed for transformers with a winding insulation moisture content of approximately 2% This temperature decreases as moisture concentration increases Additionally, gas bubbles may form in oil or solid insulation due to heating from leakage flux or oil super-saturation However, these bubbles typically arise in areas of low electric stress and must move to regions with higher stress before they significantly impact dielectric strength.
Bare metallic parts in transformers, excluding windings, can experience rapid temperature increases when in contact with non-cellulosic insulation and oil, with a critical limit of 180 °C Elevated temperatures may temporarily weaken mechanical properties, potentially compromising short-circuit strength Additionally, pressure build-up in bushings can lead to oil leakage failures, while gassing in condenser-type bushings may occur if insulation temperatures exceed 140 °C Furthermore, oil expansion can result in overflow from the conservator, and excessive currents in the tap-changer pose significant hazards.
The limitations on the maximum hot-spot temperatures in windings, core and structural parts are based on considerations of short-term risks (see Clause 7)
Short-term risks typically diminish once the load is returned to a normal level; however, it is essential for all stakeholders, including planners, asset owners, and operators, to clearly identify and acknowledge these risks.
5.4 Effects of long-time emergency loading
This abnormal operating condition, though rare, can persist for weeks or months, leading to significant ageing of transformer components Higher temperatures accelerate the deterioration of conductor insulation, potentially reducing the transformer's effective lifespan, especially during system short circuits or transportation Additionally, insulation parts that bear the axial pressure of the winding block may experience increased ageing rates under elevated temperatures The contact resistance of tap-changers can rise with higher currents and temperatures, risking thermal runaway in severe cases Furthermore, gasket materials within the transformer may become brittle due to elevated temperatures.
The calculation rules for the relative ageing rate and per cent loss of life are based on considerations of long-term risks
Taille du transformateur
La sensibilité des transformateurs à des conditions de charges supérieures aux caractéristiques de la plaque signalétique dépend généralement de leur taille À mesure que la taille augmente, la tendance est que:
• les forces de court-circuit augmentent;
• la masse de l'isolation, qui est soumise à des contraintes électriques élevées, est augmentée;
• il est plus difficile de déterminer les températures de point-chaud
A large transformer may be more susceptible to load conditions exceeding its nameplate ratings compared to a smaller device Additionally, the impact of a transformer failure is more severe for larger units than for smaller ones.
To apply a reasonable degree of risk for expected services, this section of IEC 60076 outlines three categories: a) Distribution transformers, where only the hot spot temperatures in the windings and thermal degradation are considered; b) Medium power transformers, which require attention to variations in cooling modes; and c) High power transformers, where the effects of stray flux are significant and the consequences of failure are severe.
Papier d'isolation à performances thermiques améliorées ou non
An improved thermal performance insulation paper aims to neutralize the acid production caused by hydrolysis (thermal degradation) of the material throughout the transformer's lifespan Hydrolysis is significantly more active at high temperatures, and research findings indicate that thermally enhanced insulation papers retain a much higher percentage of their tensile and burst strength compared to untreated papers exposed to elevated temperatures.
[4], [5] Les mêmes références présentent également l’évolution en fonction du temps du DP d’un papier thermiquement et non thermiquement amélioré exposé à une température de
The sensitivity of transformers to loading beyond nameplate rating usually depends on their size As the size increases, the tendency is that:
• the leakage flux density increases;
• the short-circuit forces increase;
• the mass of insulation, which is subjected to a high electric stress, is increased;
• the hot-spot temperatures are more difficult to determine
Larger transformers are more susceptible to exceeding their nameplate ratings, making them more vulnerable to overloads Additionally, the impact of a transformer failure is significantly greater in larger units compared to smaller ones.
IEC 60076 outlines three categories for assessing risk in transformer duties: a) Distribution transformers focus on hot-spot temperatures in the windings and thermal deterioration; b) Medium power transformers account for variations in cooling modes; c) Large power transformers consider the significant effects of stray leakage flux and the severe consequences of failure.
5.6 Non-thermally and thermally upgraded insulation paper
Thermally upgrading insulation paper aims to mitigate acid production from hydrolysis during a transformer's lifespan, particularly at high temperatures Research indicates that thermally upgraded insulation papers maintain significantly greater tensile and bursting strength compared to untreated papers under elevated temperatures Additionally, studies demonstrate the degradation of degree of polymerization (DP) over time for both thermally and non-thermally upgraded papers exposed to 150 °C.
DP Degré de polymérisation t Temps (h)
Valeurs pour le papier thermiquement amélioré Valeurs pour le papier non thermiquement amélioré
Figure 1 – Vieillissement accéléré en tube scellé dans de l’huile minérale à 150°C
Une autre référence [6] illustre l'influence de la température et de la teneur en humidité, comme le montre le Tableau 1
Tableau 1 – Durée de vie du papier sous diverses conditions
Type de Papier/température de vieillissement
Sec et exempte d'air avec de l’air et 2 % d’humidité
La différence illustrée dans le comportement de vieillissement thermique a été prise en considération dans les normes industrielles comme suit
• La vitesse de vieillissement relatif V = 1,0 correspond à une température de 98 °C pour le papier non thermiquement amélioré, et à 110 °C pour le papier thermiquement amélioré
The results presented in Figure 1 and Table 1 are not intended for use in aging calculations or lifespan estimates They are included solely to demonstrate the differing aging behaviors between thermally enhanced and non-thermally enhanced insulation paper.
DP Degree of polymerization t Time (h)
Values for thermally upgraded paper Values for non-thermally upgraded paper
Figure 1 – Sealed tube accelerated ageing in mineral oil at 150 C
Another reference [6] illustrates the influence of temperature and moisture content, as shown in Table 1
Table 1 – Life of paper under various conditions
Dry and free from air
The illustrated difference in thermal ageing behaviour has been taken into account in industrial standards as follows
• The relative ageing rate V = 1,0 corresponds to a temperature of 98 °C for non-thermally upgraded paper and to 110 °C for thermally upgraded paper
The data presented in Figure 1 and Table 1 should not be utilized for aging calculations or life estimations Instead, they serve to illustrate the distinct aging behavior observed between non-thermally and thermally upgraded insulation paper.
6 Vitesse de vieillissement relatif et durée de vie de l’isolation du transformateur
Généralités
There is no simple, universal criterion to measure the remaining lifespan of a transformer However, establishing such a criterion is beneficial for transformer users Therefore, it is essential to focus on the aging process and the condition of the transformer's insulation.
Vitesse de vieillissement relatif
Although the aging or deterioration of insulation is influenced by time, temperature, humidity, oxygen, and acids, the model presented in this section of IEC 60076 relies solely on the temperature of the insulation as the controlling parameter.
Since temperature distribution is not uniform, the section operating at high temperatures will generally experience the most significant deterioration Consequently, the aging rate is related to the temperature of the hot spot in the windings In this context, the relative aging rate \( V \) is defined by equation (2) for non-thermally enhanced paper and by equation (3) for thermally enhanced paper.
V (3) ó θ h est la température du point-chaud en °C
Les équations (2) et (3) impliquent que V est très sensible à la température du point-chaud comme cela peut se voir dans le Tableau 2
Tableau 2 – Vitesse de vieillissement relatif due à la température du point-chaud θ h °C
6 Relative ageing rate and transformer insulation life
Determining a singular end-of-life criterion for assessing a transformer's remaining lifespan is complex Nonetheless, establishing such a criterion is beneficial for transformer users Therefore, it is essential to concentrate on the aging process and the condition of transformer insulation.
The ageing of insulation is influenced by various factors such as temperature, moisture, oxygen, and acid content However, the model outlined in IEC 60076 focuses solely on insulation temperature as the primary factor affecting deterioration.
The non-uniform temperature distribution leads to the highest temperature areas experiencing the most significant deterioration Consequently, the ageing rate is associated with the winding hot-spot temperature The relative ageing rate \( V \) is defined by equation (2) for non-thermally upgraded paper and by equation (3) for thermally upgraded paper.
V (3) where θ h is the hot-spot temperature in °C
Equations (2) and (3) imply that V is very sensitive to the hot-spot temperature as can be seen in Table 2
Table 2 – Relative ageing rates due to hot-spot temperature h °C
Calcul de perte de la vie
La consommation de durée de vie L sur une certaine période de temps est égale à:
V n est la vitesse de vieillissement relatif pendant l'intervalle n, conformément à l'équation
(2) ou (3); t n est le n ième intervalle de temps; n est le numéro de chaque intervalle de temps;
N est le nombre total d'intervalles pendant la période considérée.
Durée de vie de l'isolation
La référence [7] suggère quatre critères différents de fin de vie différents, c'est-à-dire quatre durées de vie différentes pour le papier thermiquement amélioré, indiquées au Tableau 3
Tableau 3 – Durée de vie normale d'un système d'isolation à performance thermique améliorée exempte d'oxygène et bien sec à la température de référence de 110 °C
Base Durée de vie normale des isolants
Heures Années Résistance à la traction de l’isolation retenue pour 50 % de sa valeur initiale 65 000 7,42
Résistance à la traction de l’isolation retenue pour 25 % de sa valeur initiale 135 000 15,41
Degré de polymérisation de l'isolation correspondant à une valeur de 200 150 000 17,12
Interprétation des données d’essai sur la durée de vie fonctionnelle des transformateurs de distribution
The lifespans indicated in Table 3 are provided for reference only, as most power transformers operate well below full load for the majority of their actual lifespan A hot-spot temperature of a specific value is crucial for their performance.
A temperature decrease of 6 °C compared to the assigned values results in a halving of the designated lifespan, leading to the actual lifespan of transformer insulation being significantly extended, for instance, up to 180,000 hours.
For GSU transformers connected to base load generators and other transformers supplying constant loads or operating at relatively stable ambient temperatures, the actual lifespan requires special consideration.
Limitations de courant et de température
When operating under load conditions that exceed the specifications on the nameplate, it is essential to adhere to all individual limits outlined in Table 4 and to consider the specific limitations provided in sections 7.2 to 7.4.
The loss of life L over a certain period of time is equal to
V n is the relative ageing rate during interval n, according to equation (2) or (3); t n is the nth time interval; n is the number of each time interval;
N is the total number of intervals during the period considered
Reference [7] suggests four different end-of-life criteria, i.e four different lifetimes for thermally upgraded paper as shown in Table 3
Table 3 – Normal insulation life of a well-dried, oxygen-free thermally upgraded insulation system at the reference temperature of 110 C
50 % retained tensile strength of insulation 65 000 7,42
25 % retained tensile strength of insulation 135 000 15,41
200 retained degree of polymerization in insulation 150 000 17,12 Interpretation of distribution transformer functional life test data 180 000 20,55
The lifetimes listed in Table 3 serve as a reference, as power transformers typically operate significantly below full load for most of their lifespan A hot-spot temperature just 6 °C below the rated values can reduce the rated loss of life by half, leading to an actual insulation lifetime that can reach up to 180,000 hours.
NOTE For GSU transformers connected to base load generators and other transformers supplying constant load or operating at relatively constant ambient temperatures, the actual lifetime needs special consideration
When operating with loads exceeding the nameplate rating, it is crucial to ensure that none of the individual limits outlined in Table 4 are surpassed, while also considering the specific restrictions detailed in sections 7.2 to 7.4.
Tableau 4 – Limites de courant et de température applicables aux charges au-delà des caractéristiques de la plaque signalétique
Type de charge Transformateurs de distribution (voir Note)
Transformateurs de moyenne puissance (voir Note)
Transformateurs de grande puissance (voir Note) Régime de charge cyclique normal
Température de point-chaud d'enroulement et des parties métalliques en contact avec les matériaux isolants cellulosiques (°C)
Température de point-chaud des autres pièces métalliques (en contact avec l’huile, les papiers en aramide, les matériaux en fibre de verre) (°C)
Régime de charge de secours de longue durée
Température de point-chaud d'enroulement et des parties métalliques en contact avec les matériaux isolants cellulosiques (°C)
Température de point-chaud des autres pièces métalliques (en contact avec l’huile, les papiers en aramide, les matériaux en fibre de verre) (°C)
Régime de charge de secours de courte durée
Température de point-chaud d'enroulement et des parties métalliques en contact avec les matériaux isolants cellulosiques (°C)
Température de point-chaud des autres pièces métalliques (en contact avec l’huile, les papiers en aramide, les matériaux en fibre de verre) (°C)
Température de l’huile supérieure (°C) Voir 7.2.1 115 115
The temperature and current limits are not intended to be valid simultaneously The current may be restricted to a value lower than specified to comply with temperature limitation requirements Conversely, the temperature can be capped at a value below the indicated level to meet current limitation standards.
Limitations spécifiques pour les transformateurs de distribution
7.2.1 Limitations de courant et de température
It is essential to adhere to the limits specified in Table 4 regarding charging current, hot spot temperature, top oil temperature, and the temperature of metallic parts other than windings and connections For short-term emergency conditions, no limits are set for the top oil temperature or hot spot temperature, as it is generally impossible to control the duration of these emergency regimes in distribution transformers It is important to note that when the hot spot temperature exceeds 140 °C, gas bubbles may form, potentially compromising the dielectric strength of the transformer.
Table 4 – Current and temperature limits applicable to loading beyond nameplate rating
Types of loading Distribution transformers (see Note)
Medium power transformers (see Note)
Large power transformers (see Note) Normal cyclic loading
Winding hot-spot temperature and metallic parts in contact with cellulosic insulation material (°C)
Other metallic hot-spot temperature (in contact with oil, aramid paper, glass fibre materials) (°C)
Winding hot-spot temperature and metallic parts in contact with cellulosic insulation material (°C)
Other metallic hot-spot temperature (in contact with oil, aramid paper, glass-fibre materials) (°C)
Winding hot-spot temperature and metallic parts in contact with cellulosic insulation material (°C)
Other metallic hot-spot temperature (in contact with oil, aramid paper, glass fibre materials) (°C)
The temperature and current limits should not be considered valid at the same time; the current may be restricted to a lower value to comply with temperature limitations, while the temperature may also be reduced to adhere to current limitations.
7.2 Specific limitations for distribution transformers
It is crucial to adhere to the limits on load current, hot-spot temperature, top-oil temperature, and the temperature of metallic parts, as outlined in Table 4 During short-time emergency loading for distribution transformers, no specific limits are established for top-oil and hot-spot temperatures due to the impracticality of controlling the duration of such loading However, it is important to recognize that exceeding a hot-spot temperature of 140 °C can lead to the formation of gas bubbles, which may compromise the dielectric strength of the transformer.
In addition to the windings, other components of the transformer, such as the bushings, cable terminal connections, tap-changing devices, and connections, can restrict operation if the load current exceeds 1.5 times the rated value.
La dilatation et la pression d'huile peuvent également imposer des restrictions
When transformers are used indoors, it is necessary to adjust the assigned oil temperature at the upper part to account for the enclosure Ideally, this additional heating should be determined through testing (refer to section 8.3.2).
Wind, sunlight, and rainfall can impact the loading capacity of distribution transformers, but due to their unpredictable nature, it is impossible to account for these factors in advance.
Limitations spécifiques pour les transformateurs de moyenne puissance
7.3.1 Limitations de courant et de température
It is essential to adhere to the limits specified in Table 4 regarding charging current, hot spot temperature, top oil temperature, and the temperature of metallic parts other than windings and connections Additionally, it is important to note that if the hot spot temperature exceeds 140 °C, gas bubbles may form, potentially compromising the dielectric strength of the transformer (refer to section 5.3).
7.3.2 Accessoires, matériels associés et autres considérations
In addition to the windings, other components of the transformer, such as the bushings, cable terminal connections, tap-changing devices, and connections, can restrict operation if the load current exceeds 1.5 times the rated value.
Dilation and oil pressure can also impose restrictions, while attention may also be paid to associated equipment such as cables, circuit breakers, and current transformers, which can impact overall performance and efficiency.
7.3.3 Exigences relatives à la tenue au court-circuit
During or shortly after operating under a load exceeding the specifications on the nameplate, transformers may not meet the thermal withstand requirements for short-circuit conditions as outlined in IEC 60076-5, which are based on a short-circuit duration of 2 seconds However, in most cases, the duration of short-circuit currents in service is less than 2 seconds.
Sauf s’il existe d'autres limitations pour le réglage de tension à flux variable (voir la
CEI 60076-4) il convient que la tension appliquée ne dépasse pas 1,05 fois la tension assignée (prise principale) ou la tension de prise (autres prises) sur aucun enroulement du transformateur
In addition to the windings, components like bushings, cable-end connections, tap-changing devices, and leads can limit transformer operation when the load exceeds 1.5 times the rated current Furthermore, oil expansion and pressure may also create operational restrictions.
When using transformers indoors, it is essential to adjust the rated top-oil temperature rise to account for the enclosure Ideally, this additional temperature rise should be established through testing.
Wind, sunshine and rain may affect the loading capacity of distribution transformers, but their unpredictable nature makes it impracticable to take these factors into account
7.3 Specific limitations for medium-power transformers
The load current, hot-spot temperature, top-oil temperature, and temperatures of metallic parts, excluding windings and leads, must remain within the limits specified in Table 4 It is crucial to recognize that if the hot-spot temperature surpasses 140 °C, gas bubbles may form, potentially compromising the transformer's dielectric strength (refer to section 5.3).
7.3.2 Accessory, associated equipment and other considerations
In addition to the windings, components like bushings, cable-end connections, tap-changing devices, and leads can limit transformer operation when the load exceeds 1.5 times the rated current Oil expansion and pressure may also create operational constraints Furthermore, it is essential to consider related equipment, including cables, circuit breakers, and current transformers, when assessing performance.
Transformers operating at loads exceeding their nameplate ratings may fail to meet the thermal short-circuit requirements outlined in IEC 60076-5, which are based on a 2-second short-circuit duration However, it is important to note that the actual duration of short-circuit currents in service is typically shorter than 2 seconds.
The applied voltage to any transformer winding should not exceed 1.05 times the rated voltage for the principal tapping or the tapping voltage for other tappings, unless specific limitations for variable flux voltage variations are established, as outlined in IEC 60076-4.
Limitations spécifiques pour les transformateurs de grande puissance
For high-power transformers, additional limitations primarily related to leakage flux must be considered Therefore, it is advisable to specify the required load capacity for specific applications at the time of the tender and order.
En ce qui concerne la détérioration thermique de l'isolation, la même méthode de calcul s’applique à tous les transformateurs
Given the current state of knowledge, it is advisable to take a more conservative and specific approach for larger units compared to smaller ones, considering the critical importance of their reliability in light of the consequences of a failure, along with the factors outlined below.
The combination of leakage flux and main flux in the cores or windings of the magnetic circuit makes large transformers more susceptible to overexcitation compared to smaller transformers, especially under load conditions exceeding the nameplate ratings Additionally, the increase in leakage flux can lead to extra heating due to eddy currents in other metallic components.
The degradation of mechanical properties in insulation, influenced by temperature and time, can lead to significant wear from thermal expansion This issue is particularly critical for large transformers compared to smaller ones.
The hot spot temperatures outside the windings cannot be determined from a standard heating test Even if such a test at rated current shows no anomalies, conclusions cannot be drawn for higher currents, as this extrapolation may not have been considered during the design phase.
Calculating the hot spot temperature rise for currents exceeding the assigned value, based on the results of a heating test at the assigned current, may be less reliable for larger units compared to smaller ones.
7.4.2 Limitations de courant et de température
It is essential to adhere to the limits specified in Table 4 regarding charging current, hot spot temperature, top oil temperature, and the temperature of metallic parts other than windings and connections that are in contact with solid insulation Additionally, it is important to note that if the hot spot temperature exceeds 140 °C, gas bubbles may form, potentially compromising the dielectric strength of the transformer (refer to section 5.3).
7.4.3 Accessoires, matériels associés et autres considérations
7.4.4 Exigences relatives à la tenue au court-circuit
7.4 Specific limitations for large power transformers
When dealing with large power transformers, it is crucial to consider additional limitations related to leakage flux Therefore, it is recommended to specify the required loading capability for specific applications during the inquiry or ordering process.
As far as thermal deterioration of insulation is concerned, the same calculation method applies to all transformers
Given the significant consequences of failure, it is crucial to prioritize the high reliability of large units, warranting a more conservative and individualized approach compared to smaller units.
Large transformers are more susceptible to overexcitation compared to smaller ones due to the interaction of leakage flux and main flux in their limbs or yokes, particularly when operating above their nameplate rating Additionally, increased leakage flux can lead to heightened eddy-current heating in other metallic components.
The degradation of insulation's mechanical properties, influenced by temperature and time, can lead to significant wear from thermal expansion, particularly in large transformers compared to their smaller counterparts.
Hot-spot temperatures outside the windings cannot be determined through a standard temperature-rise test Even if the test shows no issues at rated current, it does not provide insights for higher currents, as this extrapolation may not have been considered during the design phase.
Calculating the winding hot-spot temperature rise at currents exceeding the rated levels can be less reliable for larger units compared to smaller ones, particularly when based on temperature-rise test results conducted at rated current.
The load current, hot-spot temperature, top-oil temperature, and temperatures of metallic parts in contact with solid insulating material must remain within the limits specified in Table 4 It is crucial to monitor these temperatures, as exceeding a hot-spot temperature of 140 °C can lead to the formation of gas bubbles, potentially compromising the dielectric strength of the transformer.
7.4.3 Accessory, equipment and other considerations
Echauffement du point-chaud en régime permanent
To be precise, the hot spot temperature refers to the temperature of the adjacent oil, which is assumed to be the upper oil temperature within the winding Measurements indicate that the upper oil temperature inside a winding can be up to 15 K higher than the mixed oil temperature at the top inside the tank, depending on the cooling conditions.
For most transformers in operation, the precise temperature of the oil within a winding is not accurately known Conversely, for many of these units, the temperature of the oil at the top of the tank is well-documented, either through measurement or calculation.
Les règles de calcul dans la présente partie de la CEI 60076 sont basées comme suit:
• ∆θ or , l'échauffement de l'huile à la partie supérieure de la cuve par rapport à la température ambiante et pour les pertes assignées [K];
• ∆θ hr , l'échauffement du point-chaud au-dessus de la température de l'huile supérieure dans la cuve et au courant assigné [K]
Le paramètre ∆θ hr peut être défini soit par mesure directe pendant un essai d’échauffement, soit par une méthode de calcul validée par des mesures directes
8.1.2 Calcul de l'échauffement du point-chaud à partir des données de l’essai normal d’échauffement
A thermal diagram, as illustrated in Figure 2, is hypothesized to simplify a more complex distribution The assumptions for this simplification include: a) the oil temperature in the tank increases linearly from the bottom to the top, regardless of the cooling method; b) as a first approximation, the heating of the conductor along the height of the winding is assumed to increase linearly, parallel to the oil heating, with a constant difference (g r) between the two lines; c) the hot spot temperature is higher than the conductor temperature at the top of the winding, as described in section 8.1.2b), to account for losses, local oil flow differences, and potential additional insulation on the conductor To address these nonlinearities, the temperature difference between the hot spot and the oil at the top of the tank is defined as H × g r, or ∆θ hr = H × g r.
In many instances, it has been observed that the temperature of the oil exiting the tank is higher than that of the oil in the oil pocket In such cases, it is advisable to use the temperature of the oil leaving the tank for load management.
8.1 Hot-spot temperature rise in steady state
For precise accuracy, the hot-spot temperature must be related to the adjacent oil temperature, which is typically the top-oil temperature within the winding Studies indicate that this top-oil temperature can be as much as 15 K higher than the mixed top-oil temperature found in the tank, depending on the cooling conditions.
The top-oil temperature within transformer windings is often uncertain, while the temperature at the top of the tank is typically well-documented through measurement or calculation.
The calculation rules in this part of IEC 60076 are based on the following:
• ∆θ or , the top-oil temperature rise in the tank above ambient temperature at rated losses [K];
• ∆θ hr , the hot-spot temperature rise above top-oil temperature in the tank at rated current [K]
The parameter ∆θ hr can be defined either by direct measurement during a heat-run test or by a calculation method validated by direct measurements
8.1.2 Calculation of hot-spot temperature rise from normal heat-run test data
A thermal diagram simplifies a more complex temperature distribution, as illustrated in Figure 2 It is assumed that the oil temperature in the tank increases linearly from the bottom to the top, regardless of the cooling method Additionally, the temperature rise of the conductor along the winding is approximated to increase linearly, parallel to the oil temperature, with a constant difference, denoted as \( g_r \), representing the average temperature rise by resistance compared to the average oil temperature Furthermore, the hot-spot temperature rise exceeds that of the conductor at the top of the winding due to factors such as increased stray losses, variations in local oil flows, and potential additional insulation on the conductor To account for these non-linearities, the temperature difference between the hot-spot and the top oil in the tank is defined as \( \Delta \theta_{hr} = H \times g_r \).
In many instances, the temperature of the oil at the tank outlet is found to be higher than that of the oil in the oil pocket Therefore, for loading purposes, it is essential to use the temperature of the tank outlet oil.
The oil temperature at the upper section is determined by averaging the temperature of the oil exiting the tank and the temperature of the oil pocket within the tank.
B Température de l'huile de mélange dans la cuve au sommet de l'enroulement (souvent supposée être la même température que A)
C Température de l’huile au niveau moyen de la cuve
D Température d'huile au bas de l'enroulement
E Niveau inférieur de la cuve g r Gradient de température entre l’enroulement moyen et l’huile moyenne (dans la cuve) au courant assigné
Q Température moyenne de l'enroulement déterminée par une mesure de résistance
Axe Y Positions relatives point mesuré; point calculé
A Top-oil temperature derived as the average of the tank outlet oil temperature and the tank oil pocket temperature
B Mixed oil temperature in the tank at the top of the winding (often assumed to be the same temperature as A)
C Temperature of the average oil in the tank
D Oil temperature at the bottom of the winding
E Bottom of the tank g r Average winding to average oil (in tank) temperature gradient at rated current
Q Average winding temperature determined by resistance measurement
Y-axis Relative positions measured point; calculated point
8.1.3 Mesure directe de l’échauffement du point chaud
La mesure directe avec des sondes à fibres optiques existe depuis le milieu des années 80, et a depuis été appliquée sur des transformateurs choisis
Experiments have indicated that temperature gradients exceeding 10 K can occur at different locations on the top of a standard transformer winding Therefore, relying on one to three sensors may not accurately identify the true hot spot A balance must be struck between the need for a sufficient number of sensors to locate the optimal position and the additional costs and efforts associated with fiber optic sensors It is advisable to install sensors in each winding where direct hot spot measurements are required.
Typically, the conductors near the top of the winding experience the maximum leakage field and the highest surrounding oil temperature, leading to the assumption that the upper conductors are the hottest However, measurements have indicated that the hottest point may actually shift to the lower conductors Therefore, it is advisable to distribute sensors across the first few conductors, as viewed from the top of a winding The manufacturer should determine the sensor locations through separate loss and thermal calculations.
Temperature variations at the top of a winding are illustrated in Figures 3 and 4 The installation of fiber optic sensors was carried out in a 400 MVA ONAF-cooled transformer The displayed values represent steady-state conditions at the conclusion of a 15-hour overload test The temperatures of 107 K and 115 K were recorded as the hot spot temperatures of the respective windings The oil temperature at the top at the end of the test was 79 K, resulting in a temperature rise of ∆θ hr = 28 K for the winding.
120 kilovolts et ∆θ hr = 36 K pour l'enroulement de 410 kilovolts
Figure 3 – Echauffement local au-dessus de la température de l'air dans un enroulement de 120 kV avec un facteur de charge de 1,6
8.1.3 Direct measurement of hot-spot temperature rise
Direct measurement with fibre optic probes became available in the middle of the 1980s and has been practised ever since on selected transformers
Experience indicates that temperature gradients exceeding 10 K can occur at various locations on a standard transformer winding Consequently, relying on just one to three sensors may not accurately identify the true hot-spot A balance must be struck between the need for multiple probes to pinpoint the optimal location and the increased costs and efforts associated with fiber optic sensors It is advisable to install sensors in each winding where direct hot-spot measurements are essential.
Typically, the conductors at the top of the winding are thought to experience the highest leakage field and surrounding oil temperature, suggesting they contain the hottest spot However, measurements indicate that the hottest spot may actually be located in lower conductors Consequently, it is advisable to distribute sensors among the first few conductors from the top of the winding The manufacturer should determine the sensor locations based on specific loss and thermal calculations.
Examples of the temperature variations in the top of a winding are shown in Figures 3 and 4
[8] The installation of fibre optic probes was made in a 400 MVA, ONAF-cooled transformer The values shown are the steady-state values at the end of a 15 h overload test The values
The hot-spot temperature rises for the windings were recorded at 107 K and 115 K, respectively At the conclusion of the test, the top-oil temperature rise was measured at 79 K, with a temperature rise of 28 K for the 120 kV winding and 36 K for the 410 kV winding.
Figure 3 – Local temperature rises above air temperature in a 120 kV winding at a load factor of 1,6
Figure 4 – Echauffement local au-dessus de la température de l'air dans un enroulement de 410 kV avec un facteur de charge de 1,6
Températures de l'huile à la partie supérieure et température du point-chaud
This paragraph presents two alternative methods for describing the hot spot temperature over time, considering variable load current and ambient temperature a) The solution of exponential equations, suitable for step function-type load variations This approach is particularly effective for determining thermal transfer parameters through testing, especially by manufacturers [12], and it yields accurate results in specific cases.
• Chacun des paliers de charge croissante est suivi d'un palier de charge décroissante ou vice versa
In the case of N successive load levels (N ≥ 2), each of the first (N – 1) levels must be sufficiently long for the temperature gradient ∆θ h at the hot spot relative to the oil at the top to reach a steady state This condition also applies to N successive load levels with decreasing loads (N ≥ 2) Additionally, the solution of differential equations is suitable for a load factor K that varies arbitrarily over time and for a variable ambient temperature θ a This method is particularly applicable for online monitoring, especially since there are no restrictions on the load profile.
For ON and OF cooling, the change in oil viscosity counteracts the ohmic resistance variation of the conductors The cooling effect from the viscosity change is more significant than the thermal effect from resistance changes, as reflected by the winding exponent of 1.3 in Table 5 In contrast, for OD cooling, the impact of oil viscosity on heating is minimal, necessitating consideration of the ohmic resistance variation An approximate correction term for the hot spot heating in OD mode is given by 0.15 × (∆θ_h – ∆θ_hr).
An example of a step function load variation, where each increasing load plateau is followed by a decreasing load plateau, is illustrated in Figure 8 (details of the example are provided in Appendix B).
8.2 Top-oil and hot-spot temperatures at varying ambient temperature and load conditions 8.2.1 General
This subclause presents two alternative methods for describing hot-spot temperature as a function of time, considering varying load current and ambient temperature The first method involves exponential equations, which are ideal for load variations modeled as a step function This approach is particularly effective for determining heat transfer parameters through testing, especially for manufacturers, and produces accurate results in specific scenarios.
• Each of the increasing load steps is followed by a decreasing load step or vice versa
For N successive increasing or decreasing load steps (N ≥ 2), each of the first (N – 1) steps must be sufficiently long to allow the hot-spot-to-top-oil gradient, ∆θ h, to reach a steady state Additionally, the solution of difference equations is effective for varying load factors K and ambient temperatures θ a, making this method particularly suitable for online monitoring, as it imposes no restrictions on the load profile.
In ON and OF cooling, the change in oil viscosity effectively counteracts the variations in ohmic resistance of the conductors, with the cooling effect of viscosity being more significant than the heating effect of resistance This relationship is reflected in the winding exponent of 1.3 presented in Table 5 Conversely, in OD cooling, the impact of oil viscosity on temperature increases is minimal, necessitating consideration of the variations in ohmic resistance An approximate correction term is required to account for the hot-spot temperature rise.
An example of load variation represented by a step function is illustrated in Figure 8, where each increment in load is succeeded by a decrement Detailed information about this example can be found in Annex B.
Légende θ h Température du point-chaud d’enroulement θ o Température de l'huile supérieure en cuve
K1 est de 1,0 K2 est de 0,6 K3 est de 1,5 K4 est de 0,3 K5 est de 2,1
Figure 8 – Réponses en température aux variations en échelons du courant de charge
The temperature at the hot spot is determined by the sum of the ambient temperature, the heating of the oil at the top of the tank, and the temperature difference between the hot spot and the oil at the tank's surface.
L’augmentation de la température jusqu'à un niveau correspondant à un facteur de charge de
De même, la diminution de la température jusqu'à un niveau correspondant à un facteur de charge de K est donnée par:
L'exposant de l’huile au sommet x et l'exposant d'enroulement y sont donnés dans le tableau 5
Key θ h Winding hot-spot temperature θ o Top-oil temperature in tank
K1 is 1,0 K2 is 0,6 K3 is 1,5 K4 is 0,3 K5 is 2,1
Figure 8 – Temperature responses to step changes in the load current
The hot-spot temperature is determined by adding the ambient temperature to the top-oil temperature rise in the tank, along with the temperature difference between the hot-spot and the top-oil within the tank.
The temperature increase to a level corresponding to a load factor of K is given by:
Correspondingly, temperature decrease to a level corresponding to a load factor of K, is given by:
The top-oil exponent x and the winding exponent y are given in Table 5 [14]
La fonction f 1 (t) décrit l'augmentation relative de l'échauffement de l’huile au sommet selon l’unité de sa valeur en régime établi:
1 t 1 e t k k f = − − × (7) ó k 11 est une constante donnée dans le tableau 5; τ 0 est la constante de temps de l’huile moyen (min)
The function \( f_2(t) \) represents the relative increase in the hot spot gradient compared to the oil at the peak, normalized to its steady-state value It models the delay in the oil circulation's adjustment in speed to match the increased load level.
The constants \( k_{11} \), \( k_{21} \), \( k_{22} \), and the time constants \( \tau_w \) and \( \tau_0 \) are specific to the transformer and can be determined during a prolonged heating test within the "no-load losses + load losses" period, provided that the losses and corresponding cooling conditions, such as AN or AF, remain unchanged until equilibrium is reached It is essential to start the heating test when the transformer is approximately at ambient temperature Notably, \( k_{21} \), \( k_{22} \), and \( \tau_w \) can only be defined if the transformer is equipped with fiber optic sensors If \( \tau_0 \) and \( \tau_w \) are not defined during the prolonged heating test, they can be calculated (see Appendix A) In the absence of specific transformer values, the values from Table 5 are recommended, with the corresponding graphs presented in Figure 9.
If the current and cooling conditions do not remain stable long enough during the heating process to project the tangent to the initial heating curve, the time constants cannot be determined from the heating test conducted according to IEC standards.
The graphs of \( f_2(t) \) observed for distribution transformers resemble Graph 7 in Figure 9, indicating that distribution transformers do not exhibit a significant "overshoot" at the hot spot This behavior contrasts with power transformers that experience an increasing load current step.
La fonction f 3 (t) décrit la diminution relative du gradient de la température d’huile au sommet par rapport à la température ambiante selon l’unité de la décroissante totale
The function f 1 (t) describes the relative increase of the top-oil temperature rise according to the unit of the steady-state value:
1 t 1 e t k 11 k 0 f = − − × (7) where k 11 is a constant given in Table 5; τ 0 is the average oil-time constant (min)
The function \$f_2(t)\$ represents the relative increase in the hot-spot-to-top-oil gradient based on the steady-state value It illustrates the time required for oil circulation to adjust its speed in response to the heightened load level.