While mechanical gauges have been reliable tools for temperature monitoring for decades, their limitations are becoming more pronounced as industries demand higher accuracy, better data integration, and more sophisticated transformer monitoring capabilities.
For many years the limit for normal apparatus loading was based on the maximum nameplate rating or an arbitrarily set value, called “the red line.”
This nameplate red line typically provides important information such as the transformer’s rated power (in kVA or MVA), rated voltage, current, frequency, and the allowable temperature rise, among other specifications.
The nameplate will indicate the maximum allowable temperature rise above ambient temperature, often in terms of “oil temperature rise” and “winding temperature rise.” The “red line” here refers to the upper limit of temperature that should not be exceeded to avoid thermal degradation of the transformer’s insulation and other critical components.
While the nameplate red line provides a critical baseline for transformer monitoring systems and their operation, it can be inaccurate when used as the sole reference point in monitoring – showing us again why asset management relies on the continued evolution of accurate measurement tools. Factors such as ambient temperature variations, aging, past operational history, and real-time operating conditions all contribute to the need for more dynamic and context-aware monitoring systems.
Typically, line ratings are based on conservative assumptions about worst case, long-term air temperature and other weather conditions that can lead to underutilization of the transmission grid.
Advanced monitoring technologies that track real-time data can complement the nameplate values to electronically update line ratings, offering a more accurate and reliable approach to transformer management.
Limitations to Mechanical Devices
Mechanical gauges are sufficiently rugged to be used for protection purposes but only if the recommended maintenance and/or calibration verification is carried out every 4 to 5 years — which is not a guarantee. There are occasions when this regular maintenance is not carried out for extended periods of time, or never carried out at all, either through oversight or a lack of knowledge.
These devices are also prone to mechanical damage of the small-bore tubing or spiral wound Bourdon tube within the measuring device. Additionally, internal component oxidation may lead to increased mechanical friction or seizing up entirely, further reducing the accuracy, all without any malfunction being signaled to the operator.
Mechanical gauges are often fixed in place and cannot be easily moved or reconfigured for different measurement points without significant effort, and single-point measurement means they generally measure temperature at only one point, while many modern applications require multi-point or distributed sensing.
Additionally, mechanical gauges do not have built-in capabilities for data logging. This absence makes it challenging to perform historical analysis or trend monitoring without additional equipment. Integrating mechanical gauges with modern data analytics platforms and IoT systems is also cumbersome, limiting their use in advanced predictive maintenance and monitoring setups.
Mechanical gauges generally do not support remote monitoring or integration with digital systems, a limitation that makes it difficult to collect and analyze data from multiple points in a centralized manner.
Mechanical gauges also typically feature analog displays, which can be harder to read precisely compared to digital displays. Small increments might be difficult to discern, leading to less accurate readings. Different operators might interpret the readings slightly differently, leading to variability in data recording.
Any of the above may result in an inaccurate simulation of the top oil and winding hotspot temperature, which can lead to inefficient cooling and tripping control.
The Advantages of Online Monitoring
When it comes to electrical grid monitoring, there are a number of advantages to using online continuous monitoring systems, including sustaining electrical apparatus operation and uptime, allowing field assets to communicate to networks via substation control rooms, and ensuring reliable operations and increased asset life.
The cost of deploying such systems is non-recurrent, totally flexible and extremely competitive with fiber optic or wireless systems.
Condition based monitoring also helps reduce maintenance costs and outages, particularly with top oil and winding hot spot temperature, while real-time monitoring enables load optimization as utilities operators can take transformers to their operating limits without compromising life expectancy or reliability.
Top Oil Temperature Detection
Monitoring top oil temperature is essential, as it provides an overall measure of the thermal condition of the transformer. Real-time temperature monitoring helps in assessing whether the cooling system (often consisting of oil and cooling radiators or fans) is functioning correctly. If the top oil temperature rises beyond acceptable limits, it indicates that the transformer is experiencing higher than normal loading conditions, or that there is an issue with the cooling system.
Additionally, during periods of high electrical demand, transformers can become overloaded. Continuous monitoring of the top oil temperature allows operators to detect when the transformer is being subjected to overload conditions. By taking corrective actions, such as load shedding or adjusting cooling mechanisms, operators can prevent thermal runaway and subsequent transformer failure.
Additionally, during periods of high electrical demand, transformers can become overloaded. Continuous monitoring of the top oil temperature allows operators to detect when the transformer is being subjected to overload conditions. By taking corrective actions, such as load shedding or adjusting cooling mechanisms, operators can prevent thermal runaway and subsequent transformer failure.
Continuous Winding Hot Spot Temperature Monitoring
The winding hot spot temperature is even more critical than the top oil temperature, as the lifespan of a transformer’s insulation is inversely related to the winding hot spot temperature. As the temperature rises, the insulation deteriorates more rapidly. This degradation reduces the dielectric strength of the insulation, increasing the risk of electrical failure. By monitoring the winding hot spot temperature, operators can ensure that the transformer is operating within safe thermal limits, thereby prolonging the life of the insulation and, consequently, the transformer itself.
By monitoring this temperature, operators can detect the onset of potentially catastrophic conditions, such as hot spot heating or thermal instability, long before they lead to transformer failure. This early warning capability is crucial for maintaining system reliability.
Continuous monitoring allows for real-time adjustments to the load, ensuring that the transformer is not subjected to excessive thermal stress. This is particularly important in scenarios where transformers are operated close to their maximum capacity, as even slight overloads can cause significant temperature increases.
Easier Temperature Monitoring Solutions
For the reasons listed above, asset managers are moving toward simpler and easier temperature monitoring solutions, and Dynamic Ratings offers both the B100 and Fiber Optic options. The B100 ETM makes the job more efficient by reducing installation and maintenance, while the Fiber Optic Temperature Module is attached to a fiber optic cable, providing direct winding temperature measurement.
The B100 Increases Efficiency
Using the B100 ETM will significantly reduce installation and maintenance requirements. Manufacturers of traditional WTIs recommend calibration verification at regular intervals, and with the DR-B100 the sensors are continuously checked, and the system has a failsafe watch-dog function to ensure proper operation of all components.
The further benefit of the B100 ETM is its capability to be connected to SCADA and communicate its data and alarms to the operating and maintenance staff – even over the existing substation cabling (which eliminates the need to lay fiber optic cables). That possibility is non-extant with traditional OTI and WTI devices.
The B100 is:
- Easy to install, no software is needed
- Easy to read, the LCD display can be seen from up to 60 feet and also can be read in bright sunlight or at night.
- Easy to configure either remotely or on site
- Easy to maintain
Fiber Optic Module Options
Fiber optic temperature modules provide direct winding temperature measurement on critical transformer applications, including large auto-transformers, generator transformers, mobile transformers or critical installation transformers. Modules are available for use with either ceramic phosphorescent tipped probes (Luxtron) or GaAs probes (FISO or other GaAs probes).
The SE-604 Fiber Optic Module for Use with Lumasense Patented Fluoroptic® Technology
The SE-604 Fiber Optic Hotspot Module has a temperature sensitive phosphorescent sensor attached to the fiber optic cable. Pulses of light transmitted down the fiber cause the sensor to fluoresce. The digital signal processing (DSP) based electronics detect and calculate the decay time of this fluorescence after each pulse. The decay time correlates with the temperature of the sensor, providing the basis for accurate temperature measurement.
These modules can be bundled with the E3 or C50 Transformer Monitors, allowing an automatic comparison of the real-time measured temperatures to the advanced analytics calculations, providing the ultimate in accuracy.
Real-time Online Monitoring Provides Better Readings
Implementing real-time online monitoring of power transformers and circuit breakers provides situational awareness of electrical assets operating closer to their capacity without compromising safety or reliability.
Online monitoring also fully optimizes real-time substation asset condition or operating modes, and assists operators in making intelligent decisions about load management based on actual circumstances.
Additionally, online monitoring allows for the forecasting of operating conditions used to facilitate condition-based maintenance (CBM) programs or agency reporting (such as environmental reporting of SF6 release), while also collecting operational and accumulated loss of life data.
The benefits of online monitoring allow operators to make intelligent decisions on how to optimize the load on such important substation assets follows the adoption of load management technology for power equipment such as oil-filled transformers and oil or gas-filled circuit breakers, providing communications with external networks and enabling the system to be integrated in the transformer control system resulting in minimal incremental cost to implement.
Today’s sophisticated monitoring solutions continuously calculate the maximum safeload capability of the assets and display (locally or via embedded web servers) and communicate with other systems and SCADA.
Critically, this additional information gathered on the asset greatly offsets this cost. The size or criticality of the unit is no longer the deciding factor for on-line monitoring as the cost of deployment is minimal and the tangible benefits related to monitoring far out-weigh the cost.
If you’d like to learn more about how our asset performance management software and measurement tools can help you improve utility reporting accuracy, contact us today to learn more or to sign up for one of our informative user group meetings and to stay up to date on the current nuances of the utility power management zeitgeist.
Author: Tyler Willis, Dynamic Ratings