Transformer iron core temperature on-line monitoring system

Abstract

The invention relates to the technical field of transformer monitoring, in particular to a transformer iron core temperature online monitoring system. According to the method, the radial temperature rise gradient between lamination layers is calculated according to the temperatures of the corresponding temperature measurement points inside and outside the iron core lamination, and the coupling degree of the temperature and the current is calculated by combining the temperature change rate of the inner layer temperature measurement point and the current change rate of the iron core grounding lead, so that the radial temperature distribution inside the iron core lamination is quantitatively represented; and the early symptom of local overheating is effectively captured, and the problem that local abnormal temperature rise in the iron core is difficult to accurately recognize due to the fact that only surface or single-point temperature measurement is depended on is solved.

Description

Technical Field

[0001] This invention relates to the field of transformer monitoring technology, specifically to an online monitoring system for transformer core temperature. Background Technology

[0002] Transformers are core equipment in power systems, and the core is one of the core components of a transformer. During long-term operation, localized multi-point grounding faults may occur due to insulation aging, manufacturing defects, or external factors, forming circulating currents between the core laminations. These circulating currents generate additional Joule heat, causing localized overheating of the core. Localized overheating of the core can lead to accelerated aging of the transformer insulation, oil deterioration, and even serious failures. Therefore, online monitoring and early warning of transformer core temperature are crucial.

[0003] Existing technologies, such as Chinese invention patent publication number CN117470406B, disclose an alarm system for transformer winding temperature and core temperature. This system calculates a transformer warning coefficient and issues an alarm by integrating power data, environmental data, insulation layer data, and historical operating data, thereby achieving overheating prediction.

[0004] However, analysis revealed the following shortcomings of the existing technologies: 1. Temperature data mainly relies on surface or single-point temperature measurement of the core or winding, failing to quantitatively analyze and characterize the radial temperature distribution inside the core laminations, thus making it difficult to effectively capture early characteristics of local overheating; 2. There is a lack of coupled analysis of core temperature changes and grounding current changes, resulting in an inability to effectively distinguish between temperature rises caused by actual grounding faults and temperature rises caused by other reasons, leading to weak alarm targeting. Summary of the Invention

[0005] The purpose of this invention is to overcome the shortcomings of the prior art and to solve the problems that the existing technology fails to quantitatively analyze and characterize the radial temperature distribution inside the iron core lamination, resulting in insufficient early identification capability of local overheating; and lacks coupling analysis of iron core temperature change and grounding current change, resulting in difficulty in distinguishing fault types and weak alarm targeting.

[0006] The technical solution adopted by this invention to solve its technical problem is: an online monitoring system for transformer core temperature, comprising: a state characterization module, used to calculate the radial temperature rise gradient between lamination layers based on the temperatures of corresponding temperature measuring points inside and outside the core laminations; and to calculate the coupling degree of temperature and current based on the temperature change rate of the inner layer temperature measuring points and the change rate of the core grounding lead current.

[0007] The heat dissipation quantification module is used to calculate the oil temperature difference at the upper yoke temperature measuring point based on the temperature at the upper yoke temperature measuring point and the oil temperature at the top layer of the transformer.

[0008] The primary diagnostic module generates a first-class alarm when both the radial temperature gradient and coupling degree exceed their respective historical baseline values; and generates a second-class alarm when the oil temperature difference exceeds its historical baseline value.

[0009] The composite verification module is used to respond to a type of alarm and analyze the grounding lead current to obtain a specific harmonic content. When the specific harmonic content exceeds its historical baseline value, a type of verification signal is output. In response to a type of alarm, when the cooling oil pump current and the oil temperature difference change in opposite directions over multiple consecutive cycles, a type of verification signal is output.

[0010] The maintenance triggering module is used to trigger the corresponding maintenance control process based on a type I or type II verification signal.

[0011] Compared with the prior art, the present invention has the following beneficial effects: 1. The present invention calculates the radial temperature rise gradient between lamination layers based on the temperature of corresponding temperature measurement points inside and outside the iron core lamination, and calculates the coupling degree of temperature and current by combining the temperature change rate of the inner layer temperature measurement point with the current change rate of the iron core grounding lead, thereby quantitatively characterizing the radial temperature distribution inside the iron core lamination and effectively capturing early signs of local overheating, solving the problem that it is difficult to accurately identify local abnormal temperature rise inside the iron core due to relying only on surface or single-point temperature measurement.

[0012] 2. This invention generates an alarm when both the radial temperature rise gradient and the coupling degree exceed their respective historical baseline values. The composite verification module then analyzes the specific harmonic content in the grounding lead current for verification, thereby realizing the coupled analysis of core temperature change and grounding current change. This effectively distinguishes between temperature rise caused by actual grounding fault and temperature rise caused by other reasons, improving the pertinence and accuracy of the alarm.

[0013] 3. For radial temperature rise gradient, coupling degree and oil temperature difference, the present invention takes the median of the corresponding stable data set as the historical base value; for specific harmonic content, since its normal value distribution has a right skewed characteristic, the upper quartile of the corresponding stable data set is taken as the historical base value; thus reducing the dependence on fixed thresholds and the interference of environmental and load fluctuations. Attached Figure Description

[0014] To more clearly illustrate the technical solutions of the embodiments of the present invention, the accompanying drawings used in the description of the embodiments will be briefly introduced below. Obviously, the drawings described below are only some embodiments of the present invention. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0015] Figure 1 This is a schematic diagram of the system module connections of the present invention.

[0016] Figure 2This is a schematic diagram of the process for calculating the radial temperature rise gradient according to the present invention.

[0017] Figure 3 This is a schematic diagram of the process for identifying intermediate temperature measurement points according to the present invention.

[0018] Figure 4 This is a schematic diagram illustrating the process of determining historical baseline values ​​in this invention. Detailed Implementation

[0019] Various exemplary embodiments of the present invention will now be described in detail with reference to the accompanying drawings. It should be noted that, unless otherwise specifically stated, the relative arrangement, numerical expressions, and values ​​of the components and steps set forth in these embodiments do not limit the scope of the invention. Furthermore, it should be understood that, for ease of description, the dimensions of the various parts shown in the drawings are not drawn to actual scale.

[0020] The following description of at least one exemplary embodiment is merely illustrative and is in no way intended to limit the invention or its application or use. Techniques, methods, and apparatus known to those skilled in the art may not be discussed in detail, but where appropriate, such techniques, methods, and apparatus should be considered part of the specification.

[0021] In all examples shown and discussed herein, any specific values ​​should be interpreted as merely exemplary and not as limitations. Therefore, other examples of exemplary embodiments may have different values.

[0022] Unless otherwise defined, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this invention pertains.

[0023] The following description, in conjunction with the accompanying drawings, details the specific scheme of the online monitoring system for transformer core temperature provided by this invention.

[0024] Please see Figure 1 The diagram illustrates the module connection of an online transformer core temperature monitoring system provided by the present invention, which specifically includes: a status characterization module, a heat dissipation quantification module, a primary diagnostic module, a composite verification module, and a maintenance triggering module.

[0025] The outputs of the status characterization module and the heat dissipation quantization module are connected to the primary diagnostic module, the output of the primary diagnostic module is connected to the composite verification module, and the output of the composite verification module is connected to the maintenance trigger module.

[0026] The state characterization module is used to obtain the radial temperature rise gradient between the stacked layers and the coupling degree between temperature and current.

[0027] Considering that localized overheating of the iron core can alter its normal radial heat flow distribution, when an internal heat source appears, the inner layer temperature will rise abnormally, leading to a sharp increase in the radial temperature gradient.

[0028] Therefore, the radial temperature rise gradient is obtained based on the temperature of the corresponding temperature measurement points inside and outside the iron core laminations. This avoids the fact that the absolute temperature values ​​of the inner or outer layers alone are easily affected by factors such as ambient temperature and load fluctuations, making it difficult to accurately reflect local anomalies.

[0029] Among them, the temperatures of the corresponding temperature measuring points located on the inner and outer layers of the iron core laminations along the same radial path, i.e. the temperatures of the corresponding temperature measuring points inside and outside the iron core laminations, can be collected in real time by fiber optic temperature sensors or surface-mounted thermocouples embedded between the iron core laminations.

[0030] It is also considered that multi-point grounding faults in the iron core will not only cause local overheating, but also form circulating current in the grounding circuit, resulting in an abnormal increase in the current of the iron core grounding lead. Under this fault, the temperature and current usually change synchronously.

[0031] Therefore, based on the temperature change rate of the inner layer temperature measurement point and the current change rate of the iron core grounding lead, the coupling degree of temperature and current can be obtained, thereby effectively distinguishing the temperature rise caused by a real grounding fault from the temperature rise caused by other reasons.

[0032] Please see Figure 2 and Figure 3 In specific implementation, the calculation process of radial temperature gradient is as follows: First, on the straight line connecting the inner layer temperature measurement point and the outer layer temperature measurement point, the intermediate temperature measurement point located between the inner layer temperature measurement point and the outer layer temperature measurement point is identified, thereby refining the analysis of radial temperature distribution.

[0033] To eliminate the impact of the deviation between the actual installation position of the temperature measuring point and the design coordinates on the calculation of the radial temperature gradient, this invention adopts a method that combines directional consistency and positional centering to dynamically identify intermediate temperature measuring points, ensuring that the selected temperature measuring points are located on the actual radial heat conduction path, and making the subsequent primary diagnosis based on the radial temperature rise gradient more accurate.

[0034] The process of identifying intermediate temperature measurement points is as follows: the straight line connecting the inner and outer temperature measurement points is used as the reference radial path, which represents the ideal radial heat flow direction.

[0035] Next, to eliminate temperature measurement points that significantly deviate from the reference radial path and narrow down the candidate range, the physical structure of the core laminations was obtained through the core design drawings and as-built data of the temperature measurement points. This included the spatial geometric arrangement of the core laminations and the topological relationship formed by the actual installation coordinates of all pre-embedded or mounted temperature measurement points. Based on this, the vertical distance from each temperature measurement point to the reference radial path was calculated. All temperature measurement points within the preset tolerance range of the reference radial path were then selected, and these selected temperature measurement points were used as the candidate point set.

[0036] In this invention, the preset tolerance range can be exemplarily set at 10 mm. If the core manufacturing process is precise and the lamination clamping force is large, it can be reduced to 5 mm to ensure that an effective intermediate temperature measurement point can be captured. If it is to be compatible with cores of different models and sizes, it can be appropriately increased to 15 mm.

[0037] After obtaining the candidate point set, it is further determined whether the candidate point set is empty. If it is empty, it means that there are no temperature measurement points within the preset tolerance range of the reference radial path. In this case, the overall average gradient between the inner layer temperature measurement point and the outer layer temperature measurement point is directly calculated as the radial temperature rise gradient.

[0038] If the candidate point set is not empty, then the candidate point with the direction closest to the radial direction is further selected from the candidate point set. Specifically, based on the unit vector of the line direction connecting each candidate point in the candidate point set to the inner layer temperature measurement point, the angle between the line direction and the reference radial path is calculated by vector dot product, and the candidate point with the smallest angle is selected as the first candidate point.

[0039] Meanwhile, based on the direction of the line connecting each candidate point in the candidate point set to the outer temperature measurement point, the second candidate point is obtained in the same way.

[0040] If the first candidate point is the same as the second candidate point, then it is used as the intermediate temperature measurement point; otherwise, calculate the absolute value of the difference between the two straight-line distances (i.e., Euclidean distances) from the first candidate point to the inner temperature measurement point and from the first candidate point to the outer temperature measurement point; similarly, calculate the absolute value of the difference between the two straight-line distances corresponding to the second candidate point.

[0041] Based on the consideration that the ideal midpoint should be located approximately at the midpoint between the inner and outer points, and the difference in distance from it to the two ends should be minimized, the candidate point corresponding to the smaller absolute value is selected as the midpoint temperature measurement point.

[0042] After determining the intermediate temperature measurement point, the straight-line distance and temperature difference between the inner temperature measurement point and the intermediate temperature measurement point are calculated based on the same time. The temperature difference is divided by the straight-line distance to obtain the first temperature gradient. Similarly, the second temperature gradient between the corresponding intermediate temperature measurement point and the outer temperature measurement point is obtained.

[0043] At the same time, the temperature difference between the inner layer temperature measurement point and the corresponding outer layer temperature measurement point of the core lamination at the same moment is calculated as the instantaneous temperature difference between the layers.

[0044] Then, calculate the sum of the straight-line distances from the inner layer temperature measurement point to the middle temperature measurement point and from the middle temperature measurement point to the outer layer temperature measurement point; compare the instantaneous temperature difference between the layers with the sum of the straight-line distances to obtain the overall average gradient.

[0045] If the first and second temperature gradients have the same sign, it indicates that the temperature changes from the inner layer to the middle and from the middle to the outer layer are in the same direction, such as both showing an increasing or decreasing trend. Therefore, the one with the larger absolute value is taken as the radial temperature gradient, with the unit being degrees Celsius per millimeter.

[0046] If the first and second temperature gradients have different signs, it indicates that the temperature change has changed in the middle. At this time, the segmented temperature gradients may cancel each other out and cannot truly reflect the overall heat flow direction. Therefore, the overall average gradient is taken as the radial temperature rise gradient.

[0047] The calculation process for the coupling degree between temperature and current is as follows: First, the temperature of the inner layer temperature measurement point and the current of the iron core grounding lead are obtained for 20 consecutive sampling periods. The current can be obtained from the output of the through-type current transformer installed on the iron core grounding lead.

[0048] Then, based on the temperature of the inner layer temperature measuring point in each sampling period and the previous adjacent sampling period, the temperature change rate of the inner layer temperature measuring point is calculated; similarly, the current change rate of the iron core grounding lead is obtained.

[0049] Next, under the same time reference, a trend synergy analysis was performed on the temperature change rate series and the current change rate series to obtain the coupling degree. Specifically, it was determined whether there were at least two adjacent sampling periods in which the numerical signs of the temperature change rate and the current change rate were the same within 20 consecutive sampling periods.

[0050] If it does not exist, it means that the temperature change and the current change lack a consistent directional correlation within 20 consecutive sampling periods. Therefore, it is determined that there is no effective electrothermal coupling relationship at present, and the coupling degree is set to zero.

[0051] If such a correlation exists, it implies a consistent directional correlation. Therefore, among all sampling periods where the temperature and current change rates have the same sign, sampling periods where both the temperature and current change rates are non-zero are selected, forming a set of non-zero coherent periods.

[0052] When the set of non-zero cooperative periods is empty, it indicates that the current cooperative trend may be caused by measurement noise near zero and is insufficient to reflect the true physical correlation; therefore, the coupling degree is set to zero.

[0053] When the set of non-zero coordinated periods is not empty, the product of the absolute value of the temperature change rate and the absolute value of the current change rate for each sampling period is calculated, and the arithmetic mean of all products is taken as the coupling degree, which reflects the degree of coordination between temperature and current changes; the coupling degree is a dimensionless coefficient.

[0054] It should be noted that the number of continuous sampling periods used in this invention is not fixed and can be adjusted according to the application scenario. For example, if the transformer is in a peak-shaving power station with rapidly changing load, the number of continuous sampling periods can be reduced to 10 for faster response; if it is in a base-load power station with stable operation, the number of continuous sampling periods can be increased to 30.

[0055] The heat dissipation quantification module is used to calculate the oil temperature difference at the upper yoke temperature measuring point based on the temperature at the upper yoke temperature measuring point and the oil temperature at the top layer of the transformer.

[0056] Considering that the upper yoke of the iron core is a key part for heat dissipation from the iron core into the oil, its temperature is affected by both the internal heating of the iron core and the cooling effect of the external oil. The top oil temperature reflects the overall outlet temperature of the cooling system and is the ultimate manifestation of the cooling effect.

[0057] Therefore, the temperature difference between the temperature at the yoke measuring point on the iron core and the oil temperature at the top layer of the transformer can directly reflect the heat dissipation efficiency of the iron core.

[0058] The specific calculation process is as follows: calculate the difference between the temperature of the yoke temperature measuring point on the iron core and the oil temperature of the top layer of the transformer in the current sampling period, and use it as the current oil temperature difference value.

[0059] At the same time, the difference between the temperature of the yoke temperature measuring point on the iron core and the oil temperature of the top layer of the transformer in the previous adjacent sampling period is calculated as the historical oil temperature difference value.

[0060] Then, the larger of the current oil temperature difference and the historical oil temperature difference is taken as the oil temperature difference value of the upper yoke temperature measuring point, and the unit of the oil temperature difference value is degrees Celsius.

[0061] The primary diagnostic module generates a first-class alarm when both the radial temperature gradient and coupling degree exceed their respective historical baseline values; and generates a second-class alarm when the oil temperature difference exceeds its historical baseline value.

[0062] Specifically, a radial temperature rise gradient exceeding its historical baseline indicates an abnormal radial temperature difference within the core, potentially indicating localized overheating. Simultaneously, a coupling degree exceeding its historical baseline suggests a strong correlation between this temperature rise and changes in the grounding current.

[0063] If both the radial temperature gradient and coupling degree exceed their respective historical baseline values, it indicates that the fault may originate from an electrical-side anomaly, such as a local short circuit or insulation degradation leading to a surge in losses and triggering a significant thermal effect; at this time, a type of alarm is generated.

[0064] One type of alarm mainly includes: alarm type identifier, such as electrothermal coupling anomaly; trigger time; current radial temperature rise gradient and coupling degree that triggered the alarm, as well as their respective historical base values.

[0065] When the oil temperature difference exceeds its historical baseline, it indicates that the heat dissipation efficiency of the yoke part of the iron core to the transformer oil has decreased, and the thermal resistance has increased. This may be caused by a variety of reasons, such as the performance degradation of the cooling oil pump, oil circuit blockage, radiator fouling, oil aging, etc.; at this time, a Class II alarm is generated.

[0066] Type II alarms mainly include: alarm type identifier, such as abnormal heat dissipation; trigger time; current oil temperature difference that triggered the alarm and its historical baseline value.

[0067] Both Class I and Class II alarms can be displayed through the system's human-machine interface, output through the audible and visual alarm, or uploaded through the remote communication interface.

[0068] To prevent false alarms from the initial diagnosis, the system introduces a composite verification module. After the initial diagnosis, the composite verification module performs composite verification on Class I alarms and Class II alarms respectively.

[0069] Specifically, after responding to a type of alarm, the grounding lead current is analyzed and processed. This is because type of alarms points to electrothermal coupling problems, and the harmonic components of the grounding current are typical electrical characteristics for diagnosing faults in the core magnetic circuit and loop, which can be used to verify type of alarms.

[0070] The specific verification process is as follows: First, the current signal of the iron core grounding lead within a preset time period is extracted. Then, a Fast Fourier Transform is applied to the acquired current signal to convert it to the frequency domain; the Fast Fourier Transform is an existing technology and will not be described in detail here.

[0071] When a transformer core experiences localized overheating, magnetic circuit saturation, or a short-circuit turn, the nonlinearity of the magnetization curve will generate significant odd harmonics in the grounding current, especially the third and fifth harmonics. An increase in the content of these two harmonics is a typical sign of a fault.

[0072] Therefore, from the obtained spectrum, the spectral amplitudes corresponding to 3 times the fundamental frequency (e.g., 150Hz) and 5 times the fundamental frequency (e.g., 250Hz) are read and defined as the third harmonic amplitude and the fifth harmonic amplitude, respectively. At the same time, the amplitude of the fundamental frequency (50Hz) is also obtained.

[0073] Then, the ratios of the third and fifth harmonic amplitudes to the fundamental frequency amplitude are calculated to obtain the third and fifth harmonic content. The units for both the third and fifth harmonic content are percentages.

[0074] If the third or fifth harmonic content exceeds its corresponding historical baseline value, it indicates that the frequency domain composition of the grounding current has changed abnormally, indicating that the grounding current harmonics are abnormal, which means that a certain type of alarm is credible, and therefore a certain type of verification signal is output; otherwise, no certain type of verification signal is output.

[0075] Without outputting a verification signal, the system can maintain an alarm state, but mark it as requiring further confirmation or prompt operators to verify it using other methods.

[0076] The preset duration mentioned above can be exemplarily set to 2 seconds in this invention; this duration, for a 50Hz power frequency, includes 100 cycles, which is sufficient for accurate harmonic analysis. If the electromagnetic interference on site is strong and a higher frequency resolution is required to distinguish adjacent harmonics, it can be extended to 5 seconds; if the system requires extremely fast verification response speed, it can be shortened to 1 second.

[0077] To ensure the accuracy of the aforementioned Fast Fourier Transform, the current signal sampling frequency configured by the system is no less than 2kHz. Accordingly, with preset durations of 1 second, 2 seconds, or 5 seconds, no less than 2000, 4000, and 10000 sampling points are obtained, respectively.

[0078] Upon responding to a Type II alarm, it is necessary to analyze and process the difference between the cooling oil pump current and the oil temperature. This is because Type II alarms indicate abnormal heat dissipation, and the cooling oil pump is the main component responsible for active heat dissipation. Analyzing the relationship between the pump's operating current (which reflects its mechanical load and electrical power input) and the oil temperature difference (which characterizes the heat dissipation effect) can help determine whether the fault originates from the cooling oil pump itself, the oil circuit, or the radiator.

[0079] The specific verification process is as follows: The current of the cooling oil pump and the corresponding oil temperature difference in multiple (e.g., 5) consecutive sampling periods can be obtained through the current sensor on the power circuit of the cooling oil pump motor. The difference between the cooling oil pump current and the oil temperature difference in each sampling period and the previous adjacent sampling period is calculated respectively.

[0080] If, within multiple consecutive sampling periods, for each sampling period, the sign of the difference in cooling oil pump current is positive (value increases) and the sign of the difference in oil temperature is negative (value decreases); or the sign of the difference in cooling oil pump current is negative and the sign of the difference in oil temperature is positive, then it is determined that the two changes in opposite directions within multiple consecutive sampling periods. Otherwise, it is determined that the two changes in opposite directions are not continuously opposite.

[0081] If the direction of change of the cooling oil pump current is opposite to the direction of change of the oil temperature difference in multiple consecutive sampling periods, it indicates that the change in the working state of the cooling oil pump can effectively affect and improve the heat dissipation effect. At this time, a Type II verification signal is output, which means that the observed abnormal oil temperature difference is likely just a transient response of the system or caused by the normal adjustment of the oil pump; otherwise, no Type II verification signal is output.

[0082] If no Type II verification signal is output, it indicates that there may be a blockage or inefficiency in the oil circuit or the radiator itself. The system can then provide targeted maintenance suggestions, such as checking the opening of the oil circuit valves or cleaning the radiator fins.

[0083] Please see Figure 4 In a preferred embodiment of the present invention, the historical baseline values ​​of radial temperature rise gradient, coupling degree, oil temperature difference and specific harmonic content are determined in the following manner.

[0084] Specifically, for radial temperature rise gradient, coupling degree, oil temperature difference and specific harmonic content, the following operations are performed respectively: First, extract data from the transformer during a period of continuous and stable operation without planned shutdown, external short circuit impact, load rate fluctuation not exceeding ±20% of the rated value, maintenance operation, and alarm occurrence, such as time series data within 30 or 90 days, to ensure that the final historical baseline value can effectively reflect the recent operating status of the transformer.

[0085] Next, the time-series data can be divided into multiple data segments of equal length based on the total data duration; for example, if the total duration is 30 days, it can be divided into 30 segments by day, or into 60 segments by 12 hours. Then, for each data segment, it is divided into two consecutive sub-segments in chronological order.

[0086] Then, the difference between the maximum and minimum values ​​of the data points in the data segment is calculated as the overall fluctuation value. The average value of the data points in each of the two sub-segments is then calculated, and the absolute value of the difference between the two average values ​​is used as the sub-segment offset.

[0087] If the sub-segment offset is less than the overall fluctuation value, it means that the data segment is in a relatively stable random fluctuation state. Therefore, the data segment is determined to be a stable data segment, and the original data points within all stable data segments are collected to form a stable data set.

[0088] If the sub-segment offset is greater than or equal to the overall fluctuation value, the data segment is determined to be an unstable data segment, and the original data points contained therein are not included in the stable data set.

[0089] Specifically, for radial temperature rise gradient, coupling degree, and oil temperature difference, the median of the corresponding stable data set is taken as the historical base value to reduce the impact of outliers.

[0090] For a specific harmonic content, since its normal value distribution has a right-skewed characteristic, in order to avoid over-responding to normal fluctuations and reduce false alarms, the upper quartile of the corresponding stable data set is taken as the historical base value.

[0091] The maintenance triggering module is used to trigger the corresponding maintenance control process based on a type I verification signal or a type II verification signal.

[0092] Specifically, when a verification signal is received, it indicates that the system has confirmed the presence of electrothermal coupling abnormality and grounding current harmonic abnormality, pointing to the possibility of local overheating or grounding fault in the iron core.

[0093] At this time, the maintenance trigger module executes a type of maintenance control process, including but not limited to: prompting operators to prioritize checking for faults such as multi-point grounding of the iron core, insulation deterioration, or partial short circuit; and automatically pushing the fault time, current radial temperature rise gradient, coupling degree, and specific harmonic content to the operation and maintenance management system.

[0094] Upon receiving a Type II verification signal, it indicates that the system has confirmed an abnormal heat dissipation, and that the abnormality is directly related to changes in the operating status of the cooling oil pump.

[0095] At this time, the maintenance trigger module executes a second type of maintenance control process, including but not limited to: prompting operators to check the working status of the cooling oil pump, the unobstructedness of the oil circuit and the cleanliness of the radiator; and automatically recording the changing trend of the cooling oil pump current and oil temperature difference over multiple consecutive sampling cycles.

[0096] All maintenance control processes can be displayed through a human-machine interface and can be synchronized to the upper-level monitoring platform via a remote communication interface.

[0097] As a preferred embodiment of the present invention, the maintenance triggering module can also be configured to only record and prompt the alarm when no verification signal is received but the primary diagnostic module has generated an alarm, without triggering the maintenance control process, so as to reduce the risk of erroneous operation.

[0098] The above embodiments can be implemented, in whole or in part, by software, hardware, firmware, or any other combination thereof. When implemented using software, the above embodiments can be implemented, in whole or in part, in the form of a computer program product.

[0099] Those skilled in the art will recognize that the modules and algorithm steps of the various examples described in conjunction with the embodiments disclosed herein can be implemented in electronic hardware, or a combination of computer software and electronic hardware. Whether these functions are implemented in hardware or software depends on the specific application and design constraints of the technical solution. Those skilled in the art can use different methods to implement the described functions for each specific application, but such implementations should not be considered beyond the scope of this invention.

[0100] In addition, the functional modules in the various embodiments of the present invention can be integrated into one processing module, or each module can exist physically separately, or two or more modules can be integrated into one module.

[0101] The above description is merely a specific embodiment of the present invention, but the scope of protection of the present invention is not limited thereto. Any variations or substitutions that can be easily conceived by those skilled in the art within the technical scope disclosed in the present invention should be included within the scope of protection of the present invention. Therefore, the scope of protection of the present invention should be determined by the scope of the claims.

[0102] Finally, the above description is only a preferred embodiment of the present invention and is not intended to limit the present invention. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the present invention should be included within the protection scope of the present invention.

Claims

1. A transformer core temperature online monitoring system, characterized in that, include: The state characterization module is used to calculate the radial temperature rise gradient between lamination layers based on the temperatures of corresponding temperature measurement points inside and outside the iron core laminations. The coupling degree between temperature and current is calculated based on the temperature change rate of the inner layer temperature measuring point and the current change rate of the iron core grounding lead. The heat dissipation quantification module is used to calculate the oil temperature difference at the upper yoke temperature measuring point based on the temperature at the upper yoke temperature measuring point and the oil temperature at the top layer of the transformer. The primary diagnostic module generates a first-class alarm when both the radial temperature gradient and coupling degree exceed their respective historical baseline values; and generates a second-class alarm when the oil temperature difference exceeds its historical baseline value. The composite verification module is used to respond to a type of alarm and analyze the grounding lead current to obtain a specific harmonic content. When the specific harmonic content exceeds its historical base value, a type of verification signal is output. In response to a type of alarm, when the cooling oil pump current and the oil temperature difference change in opposite directions over multiple consecutive cycles, a type of verification signal is output. The maintenance triggering module is used to trigger the corresponding maintenance control process based on a type I or type II verification signal.

2. The online monitoring system for transformer core temperature according to claim 1, characterized in that, The calculation process for the radial temperature rise gradient is as follows: On the straight line connecting the inner and outer temperature measurement points, identify the intermediate temperature measurement point located between the inner and outer temperature measurement points; Based on the same moment, the first temperature gradient is determined according to the straight-line distance and temperature difference between the inner temperature measuring point and the middle temperature measuring point; similarly, the second temperature gradient between the corresponding middle temperature measuring point and the outer temperature measuring point is obtained. Calculate the temperature difference between the inner layer temperature measurement point and the corresponding outer layer temperature measurement point of the core lamination at the same moment, and use it as the instantaneous temperature difference between the layers; Calculate the sum of the straight-line distances from the inner layer temperature measuring point to the middle temperature measuring point, and from the middle temperature measuring point to the outer layer temperature measuring point; compare the instantaneous temperature difference between layers with the sum of the straight-line distances to obtain the overall average gradient; A radial temperature rise gradient is generated based on the first temperature gradient, the second temperature gradient, and the overall average gradient.

3. The online monitoring system for transformer core temperature according to claim 2, characterized in that, Based on the first temperature gradient, the second temperature gradient, and the overall average gradient, a radial temperature rise gradient is generated, specifically as follows: If the first and second temperature gradients have the same sign, the one with the larger absolute value is taken as the radial temperature rise gradient; otherwise, the overall average gradient is taken as the radial temperature rise gradient.

4. The online monitoring system for transformer core temperature according to claim 3, characterized in that, The process for identifying the intermediate temperature measurement point is as follows: The straight line connecting the inner and outer temperature measurement points is used as the reference radial path. Based on the physical structure of the iron core laminations, all temperature measurement points within the preset tolerance range of the reference radial path are obtained as a candidate point set. Based on the direction of the line connecting each candidate point in the candidate point set to the inner temperature measurement point, the candidate point with the smallest angle between the line direction and the reference radial path is selected as the first candidate point. Based on the direction of the line connecting each candidate point in the candidate point set to the outer temperature measurement point, the second candidate point is obtained in the same way. If the first candidate point is the same as the second candidate point, then it shall be used as the intermediate temperature measurement point; Otherwise, calculate the absolute value of the difference between the two straight-line distances from the first candidate point to the inner temperature measurement point and from the first candidate point to the outer temperature measurement point; Similarly, calculate the absolute value of the difference between the two straight-line distances corresponding to the second candidate point, and take the candidate point corresponding to the smaller absolute value as the intermediate temperature measurement point.

5. The online monitoring system for transformer core temperature according to claim 1, characterized in that, The calculation process for the coupling degree is as follows: The temperature of the inner layer temperature measurement point and the current of the iron core grounding lead are obtained for multiple consecutive sampling periods. The temperature change rate of the inner layer temperature measuring point is calculated based on the temperature in each sampling period and the previous adjacent sampling period; similarly, the current change rate of the iron core grounding lead is obtained. Under the same time reference, trend synergy analysis is performed on the temperature change rate series and the current change rate series, and the coupling degree is obtained based on the trend synergy analysis results.

6. The online monitoring system for transformer core temperature according to claim 5, characterized in that, The trend synergy analysis process is as follows: Determine whether, within multiple consecutive sampling periods, at least two adjacent sampling periods have the same numerical sign for both the rate of temperature change and the rate of current change. If not, then it is determined that the temperature change rate sequence and the current change rate sequence have no coordinated trend, and the coupling degree is set to zero; If so, then among all sampling periods with the same numerical sign, select the sampling periods where both the rate of temperature change and the rate of current change are not zero, and form a set of non-zero cooperative periods. When the set of non-zero cooperative periods is empty, the coupling degree is set to zero; when the set of non-zero cooperative periods is not empty, the product of the absolute value of the temperature change rate and the absolute value of the current change rate of each sampling period is calculated, and the arithmetic mean of all products is taken as the coupling degree.

7. The online monitoring system for transformer core temperature according to claim 1, characterized in that, The calculation process for the oil temperature difference is as follows: Calculate the difference between the temperature at the yoke temperature measuring point on the iron core and the oil temperature at the top layer of the transformer during the current sampling period, and use it as the current oil temperature difference value; Calculate the difference between the temperature at the yoke temperature measurement point on the iron core and the oil temperature at the top layer of the transformer in the previous adjacent sampling period, and use it as the historical oil temperature difference value; The larger of the current oil temperature difference and the historical oil temperature difference is taken as the oil temperature difference at the upper yoke temperature measuring point.

8. The online monitoring system for transformer core temperature according to claim 1, characterized in that, The process by which the composite verification module responds to a type of alarm is as follows: After responding to a type of alarm, the current signal of the iron core grounding lead within a preset time period is extracted and the spectrum analysis is performed to obtain the amplitude of the third harmonic and the amplitude of the fifth harmonic. The ratios of the third harmonic amplitude, the fifth harmonic amplitude, and the fundamental frequency amplitude are calculated to obtain the third harmonic content and the fifth harmonic content. If the third harmonic content or the fifth harmonic content exceeds its corresponding historical baseline value, a verification signal of type I is output; otherwise, no verification signal of type I is output.

9. The online monitoring system for transformer core temperature according to claim 1, characterized in that, The process by which the composite verification module responds to Type II alarms is as follows: After responding to a Class II alarm, the cooling oil pump current and the corresponding oil temperature difference are obtained in multiple consecutive sampling cycles; Calculate the difference between the cooling oil pump current and the oil temperature difference between each sampling period and the previous adjacent sampling period; If the difference in cooling oil pump current is positive and the difference in oil temperature is negative, or if the difference in cooling oil pump current is negative and the difference in oil temperature is positive, then the two changes are determined to be in opposite directions. When the direction of change of the cooling oil pump current and the direction of change of the oil temperature difference are opposite in multiple consecutive sampling periods, a type II verification signal is output; otherwise, no type II verification signal is output.

10. The online monitoring system for transformer core temperature according to claim 1, characterized in that, The process for determining the historical baseline value is as follows: For radial temperature rise gradient, coupling degree, oil temperature difference, and specific harmonic content, perform the following operations respectively: The time series data is divided into multiple data segments of equal length; then each data segment is evenly divided into two consecutive sub-segments. Calculate the difference between the maximum and minimum values ​​of data points in a data segment, and use this as the overall fluctuation value; Calculate the average value of the data points in the two sub-segments respectively, and then calculate the absolute value of the difference between the two average values ​​as the sub-segment offset; If the sub-segment offset is less than the overall fluctuation value, the data segment is determined to be a stable data segment; the original data points in all stable data segments are collected to form a stable data set; Specifically, for radial temperature rise gradient, coupling degree and oil temperature difference, the median of the corresponding stable data set is taken as the historical base value; for specific harmonic content, the upper quartile of the corresponding stable data set is taken as the historical base value.

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