Reducing Risk, Increasing Situational and Operational Awareness on Substation Transformers

Presented By:
Brian Sparling

Dynamic Ratings
Tara-lee MacArthur
Energy Queensland
TechCon 2019


Using online monitoring to make intelligent decisions is an area that is quickly finding acceptance with HV asset owners globally. Online monitoring can also be a valuable tool for transformer condition assessment, optimizing utilization and reducing the risk of unexpected failures. Real-time monitoring of equipment and its operating environment will enable system planners and operations personnel to dynamically load transformers to optimum limits, safely and without compromising reliability. 

This paper will present current practices used for monitoring and utility experience related to the operation, events, data, reliability and benefits. 

1) Upgrading Oil Temperature Indicator (OTI) and Winding Temperature Indicator (WTI)  technology developed in the 1940’s with Electric Temperature Monitors (ETM). Adoption of  ETM technology combined with real-time operating information of the transformer and modern communications to enable decision-making as part of any Smart Grid application. At the same time, reducing maintenance costs associated with traditional OTI/WTI, which often seized up, or went out of calibration over time.  

2) The knowledge gained by acquiring the operating behaviour of monitored assets leads to a  deeper understanding of failure modes, never seen before due to the limitations of Time-Based Maintenance and inspections. Case histories will be discussed. 

3) Understanding what to monitor, wherein the network and why, using a business case approach to this investment. A utility perspective on a project in progress will be discussed,  where new Solar Farm projects are being inserted into Distribution Networks that were never designed to accommodate the unique output characteristics of such distributed generation assets. 

4) Focusing attention on those assets that may still have remaining life and are expected to be kept in service for years to come, all be it, with an eye on the assets’ behaviour. 

5) The value of data. Acquisition of data is important for knowing real-time condition or status,  however, processing of the data to acquire information and knowledge is what makes the data valuable.

The objective of the paper is to share knowledge of the activities of other distribution utilities,  how to make use of existing assets and apply technology to improve the understanding of the asset performance. 

Keywords; Situational awareness, reliability, safety, utilization. 


For many decades, it has been a standard practice to install Oil Temperature Indicator (OTI)  and Winding Temperature Indicator (WTI) on new transformers. These devices typically are comprised of a temperature-sensing bulb inserted into a dry well in the top layer of the insulating fluid as shown in Figure 1. In addition to this, the WTI incorporates a heater element to which a sample of the load current carried by the transformer is applied. This current causes the temperature bulb to read the oil temperature plus a temperature increment that is intended to be the same as the winding hottest spot temperature rise above top oil temperature. The fluid in the bulb expands through a capillary tube connected to a dial gauge equipped with switches that can be adjusted to any temperature within the operating range. They are sufficiently rugged to be used for protection purposes if the recommended maintenance and/or calibration verification is carried out every 4 to 5 years. 

The WTI is a critical device on a transformer because it not only controls the cooling system but also provides the transformer with thermal protection. 

A failure of this device or even an incorrect indication may have an important impact on transformer aging and may affect transformer reliability especially if a transformer must be operated under overloading conditions. Utility experience indicates that a significant part of transformer maintenance is devoted to WTIs.  


Conventional winding hot spot gauges use a bulb-type thermometer surrounded by a small heating coil to simulate the temperature rise of the winding hot spot over the top oil (“the gradient”). Current from a bushing CT (in proportion to the load current of the transformer) is passed through the heating coil raising the measured temperature. 

Figure 1 Typical Winding Hot Spot Gauge Diagram
Figure 1 Typical Winding Hot Spot Gauge Diagram

Transformer manufacturers are responsible for calibrating the winding hot spot gauge to read the correct temperature at full load. The concern that the windings of a transformer could overheat without adequate warning or autonomous mitigating actions may be justified if the transformer is equipped with these legacy devices and is subjected to gross overloads as may occur in load-sharing applications. With a winding time constant of typically 6 minutes and a  minimum legacy WTI response time of 29 minutes, the windings would have ample time to rise to potentially hazardous temperatures before cooling can be initiated or load shedding performed. (3) 

If the calculated gradient is accurate, the “tuned” WHS gauge will provide very good readings at full load under steady-state conditions.  

Figure 2 Typical Schematic of a Winding Hot Spot Gauge
Figure 2 Typical Schematic of a Winding Hot Spot Gauge

The following challenges are typically encountered when using analogue winding hot spot  gauges: 

  • The accuracy of the capillary thermometer drifts over time. Periodic calibration of the WHS gauge is required to ensure the gauge continues to provide an accurate reading at full load.  While historically utilities had maintenance tasks to periodically calibrate their gauges, most  utilities eliminated these time-based maintenance tasks many years ago.  
  • The accuracy of the reading at loads greater and less than full load will depend on the  transformer design. The accuracy of the reading during load transitions will depend on the  WHS system design.  
  • The time constant of the gauge may not match the time constant of the winding hot spot. The  time constant of the gauge is determined by the sensor, thermal well design and the amount of  oil circulation near the thermal well (which will dissipate the heat generated by the resistor).  Since the time constant of the gauge is determined by environmental factors in the transformer,  it may not match the time constant measured during the heat run test. 

Due to the problems listed above, it is not uncommon to find errors in hot spot temperature  measurements of 5-10°C (1) or more when using analogue winding hot spot gauges as can be  observed in Figure 3. 

Figure 3 WTI reads 50°C, the OTI reads 65°C, new unit, in service for three months.
Figure 3 WTI reads 50°C, the OTI reads 65°C, new unit, in service for three months.

There are occasions when this regular maintenance is not carried out for extended periods of  time, or never carried out, either through oversight or ignorance of the issue. 

WTIs are prone to mechanical damage of the small-bore tubing or spiral wound Bourdon tube  in the measuring device.  

Moreover, internal component oxidation (because of moisture ingress as seen in Figure 4), may  lead to increased mechanical friction or seizing up entirely, further reducing the accuracy without signaling this malfunction to the operator. It may result in an inaccurate simulation of the winding hotspot temperature which can lead to inefficient cooling and tripping control.

Figure 4 Example ETM, and Vintage WTI, with obvious leakage problems to atmosphere
Figure 4 Example ETM, and Vintage WTI, with obvious leakage problems to atmosphere


With the advent of on-line, real-time monitoring of transformers, the necessary real-time data  and information can be made available via remote access (communication) thereby enabling  decisions regarding loading to be made rapidly. 

Table 1 shows the suggested maximum temperatures given in IEEE C57.91-1995 and IEC  Standards 60354 and 60076-7, for four types of transformer loading. In addition to these criteria,  it is always advisable to calculate the loss of insulation life and make sure it is acceptable for the loads beyond the nameplate. Acceptable limits of loss of insulation life for various loadings are very important in developing a loading policy and thermal model limits to facilitate real-time dynamic loading.  

Table 1 Suggested maximum temperatures
Table 1 Suggested maximum temperatures
NOTE: These loading conditions make one very important assumption: that the solid insulation is DRY. The definition of DRY is a solid insulation system (most importantly the winding conductor insulation) with moisture content of less than 0.5% (weight of water/weight of solid insulation).


The consequences of loading a transformer beyond its nameplate rating are; •

  • The temperature of the windings, cleats, leads, insulation and oil will increase and can reach unacceptable levels. 
  • The leakage flux density outside the core increases causing additional eddy-current heating in metallic parts linked by the leakage flux. 
  • As the temperature changes, the moisture and gas content in the insulation and in the oil,  will change. 
  • Bushings, On-Load Tap Changers (OLTCs), cable-end connections and current transformers will also be exposed to higher stresses, which encroach upon their design and application margins. Therefore, they become at risk from overloading which may result in premature failure.  


5.1 Electronic temperature monitors, ETM 

The use of fully electronic devices such as electronic temperature monitors (ETM) that continuously calculate the winding hottest temperature on up to three windings, from measured values of top oil temperature (via existing PT100 RTD sensors) and load current measurements from the bushing CT’s.  

The computations follow the well-known and established equations found in the loading  Guides of IEEE and IEC, where the WHS is taken as the sum of the top oil temperature, plus an increment proportional to the load level elevated to a power (typically 1.8). With that information, cooling control of up to two stages (typically) of cooling can be programmed and the Thermal Aging Rate of the transformer calculated. All measured and computed data is recorded and stored every minute. 

Using the ETM will significantly reduce installation and maintenance requirements.  Manufacturers of traditional WTIs recommend calibration/verification at regular intervals.  With the ETM 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 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 (no need to lay fibre optic cables). That possibility is non-extant with traditional OTI  and WTI devices.

5.2 The acquisition of data  

Dynamic access to data will be required for the analysis of monitoring data. As an example, the interpretation of actual DGA measurements often requires a trending analysis, for which historic data is needed. As another example, the interpretation of oil temperature at a specific load requires static data on the transformer thermal properties, and dynamic data on the ambient temperature. 

For static data it is recommended to store as much information as is available: it will consume much less storage capacity than dynamic data. For dynamic data it is crucial to decide on beforehand what data is, or might be, relevant for processing or for any form of analysis. This may involve both recent and historic dynamic data. 

Important data attributes involving the data format, data compaction, data security and compatibility with other systems will need to be considered and taken into the overall design of the data repository. Not to forget the quality and timeliness of the data is vital to assess. 


Investment decisions need to align with the utilities or asset owner’s strategic direction. The  table below highlights some of the advantages and disadvantages of condition monitoring from  a utility perspective.


  • Increased visibility of transformer health
    • Assist with operational decisions by providing operators a quick and straightforward way to determine the up-to-date asset condition 
    • Allows personnel to determine appropriate actions and resources to deploy in response to alarms, thereby reducing number of trips to the site, with corresponding reduction in risk of accidents.
  • Potential for increased transformer capacity
  • Prolonging the useful life of assets 
    • Deferral of asset replacement 
    • More viable investment outcomes 
    • Reduce wastage of valuable assets 
  • Increased awareness of the asset condition enabling replacement or refurbishment of assets  to be appropriately timed with the asset conditions.
  • Calculated water content in paper based on measured relative saturation of moisture in  dielectric fluid (increased accuracy)
  • Broader transformer and rating management 
    • Better visibility by network operators into the real-time conditions of plant under normal or  contingency conditions allowing increased switching opportunities
  • Flexibility to add further monitoring in the future 
    • Bushing Monitoring for early detection of incipient faults, early detection of partial  discharge and OLTC monitoring and control
  • Condition Based Maintenance can be performed 
    • Better visibility of when equipment needs maintenance, repairs and eventually  replacement 
    • Avoid outages for unnecessary maintenance


  • Capital Expenditure
  • Reduce the risk of a failure 
    • Monitoring can reveal issues previously not detected
  • Potential rating reduction


Many countries around the world are operating in a deregulated environment, which is driving  Transmission & Distribution (T&D) companies to find ways to improve their competitive  position and increase their return on investment (ROI). It is important for a utility to ensure the electrical network is developing and operating in a manner that is safe, capable of supplying the growing demand during normal and contingency conditions, whilst balancing risks, cost, and customer requirements. 

As mentioned in section 3, there is a risk to overloading a transformer beyond its nameplate.  The nameplate rating of a power transformer (specification rating) is a continuous loading that  a transformer must be capable of supplying without excessively aging the assets insulation systems. While static ratings have been a safe and standard practice, changes in the electricity market and cost pressures are driving the need to extract higher value from existing assets. In some cases, assets are required to be operated beyond their nameplate rating or de-rated based on asset condition. Using online monitoring enables a greater understanding of the asset. The factors exacerbating these risks are shown below, however, favorable weather and asset  condition potentially allows for a dynamic rating be applied over existing static ratings. 

The greatest risks to plant ratings are: 

  • Climatic conditions (high ambient temperatures, calm or no wind) 
  • Peak loading 
  • Load shape 
  • Load duration 
  • Water content in paper (WCP) 

7.1 Provisions in Specifications for New Transformers 

To facilitate the installation of online condition monitoring equipment there are certain  sensors and facilities that can be provided on new transformers. CIGRE Technical Brochure  343 (5) provides guidance for these facilities and sensors for the ease and safety of fitting condition monitoring systems at any point in the transformer’s lifetime and should help to lower the barriers to effective and economic use of these systems. 


What happens when monitoring is applied to previously unmonitored transformers see the four  case studies below.  

8.1 Real Life Scenario – Case 1(2) 

Tim Action / Response
1/7/2010  7:20 AMReceive Emergency Hot Spot Alarm initiated by the monitor at Glade  Station as the Phase ‘A’ Hot Spot ultimately exceeds 143 Degrees C. Note: The transformer did not have a winding hot spot gauge and only top oil prior to transformer monitoring package being installed. The cooling control was done only by the OTI and there was no connection SCADA at this substation.
10:30 AMStation inspection reveals that the Glade #1 transformer (8.4/10.5MVA – 65 OA/FA), has a single cooling fan and not the required minimum of  three fans.
3:00 PM 4 additional fans are added and placed on manual.
1/8/2010  7:10 AMDDC quote to Station Management – “We checked the temperatures  this morning from SCADA and the fans definitely made a difference.  The winding temp is running 20 to 40 degrees C lower than the previous  night with similar temperatures”
Figure 1 Top oil temperature of Glade transformer 1

8.2 Case 2 Defective Bushing Detected 

Online monitoring of other components, such as OIP Bushings, has also provided owners with indication of incipient failure conditions. A case in North America with a 69kV transformer,  where the HV bushings are monitored, alarmed on increasing leakage current measured, and indicated PD inside the Phase ‘B’ bushing that was contributing to the failure condition. The transformer was taken out of service and all bushings were tested. One bushing was found to have a defect and therefore was replaced, avoiding an unexpected potentially catastrophic failure. (4)

Figure 2 Sum of leakage currents trending above HI and HI-HI alarm limits
Figure 3 PD data showed elevated PD levels on B phase bushing

Case 3 – Result from no visibility of thermal conditions 

Consider the case study below, where an aged transformer operating above the nameplate rating failed during high loading and periods of thermal stress.  

Table 3 Combination of high insulating paper moisture, low flashover temperatures, high ambient temperatures and high loading over varying times.

Prior to the failure the transformer was identified with an increased risk due to loading and  excessive moisture. As the WCP increases, the flashover temperature reduces accordingly. The  flashover temperature is the temperature at which formation of water vapour bubbles can result  in flashover leading to transformer failure. In this case, the WCP was 3.95% wt./wt. and  respectively, a flashover temperature around 110°C. Asset owners can apply the calculated  flashover temperature limitation using curves in C57.91-1995 (6) and CIGRE TB 349 (7).

The transformer failed during a peak summer period and required replacement. This could  potentially have been avoided if visibility of the transformer condition was available in real  time and changes to network configuration were available to reduce thermal stress.  

Case 4 On-line monitoring of critical transformers 

Condition monitoring of strategic power transformers will allow for risk management of assets and an increase of analytical data critical for engineering judgment. Not all these transformers are at end of life and require replacement, instead they are critical to the network. 

Table 4 the installation of on-line monitoring for end of life and critical assets to the network.

Currently, there is no visibility of thermal conditions from these assets (above) and the  transformers are running at nameplate rating daily due to solar farm installations. Real-time  data is required to understand the impact of the solar farm connections on these transformers, therefore, condition monitoring equipment capable of the following is to be installed:

  • Measuring of moisture content, electrical load, top oil temperature, ambient air temperature
  • Partial discharge monitoring 
  • Bushing monitoring 
  • Tap-changer monitoring 

The data will be sampled at regular intervals (i.e. 1 minute) and will be stored within at database where it can be analysed further. Online monitoring can reduce the risk of unexpected transformer failure resulting in a transformer replacement. It can also assist in verifying alarms and trips, avoiding the need for crews travelling to a remote site to check temperatures or investigate transformer trips.  


The use of ETM type devices and other online monitoring devices within the electricity network is becoming commonplace and many utilities are already starting to realize the benefits of the modern technologies over the historic equivalents. This allows utilities to perform predictive asset analysis for asset replacement, determine optimal condition-based maintenance, manage the performance and increase reliability of their power network.  Incorporating the use of real-time condition data relating to critical network assets could also result in further benefits to asset owners.


1) William F. Griesacker, Pennsylvania Transformer Technology, Inc. Control Cabinets  and Gauges, Doble Life of a Transformer 2007. 

2) Paul Thomas, et al., “Distribution Substation Transformer Monitoring and Diagnostics  at American Electric Power”, DistribuTECH Conference & Exhibition, March 2010

3) Insulation Life Subcommittee of the IEEE Transformers Committee, “Task Force  Report on Winding Temperature Indicators Experimental Investigation of Response of  Heated-Sensor Simulated Winding Temperature Devices to Large Changes in Signal  Current”, December 2015 

4) Euro TechCon 2015, “A Solution, Proven, to better manage personnel and asset risks  of a bushing failure, given ageing infrastructure” Presentation 

5) CIGRE Technical Brochure 343 Recommendations for Condition Monitoring and  Condition Assessment Facilities for Transformers, April 2008  

6) IEEE Guide C57.91-1995, Guide for Loading Mineral Oil Immersed Transformers

7) CIGRE Technical Brochure 349, Moisture Equilibrium and Migration within  Transformer Insulation Systems

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