Need for Dynamic Transformer Ratings

This article was published in the August 2023 Newsletter of the Global Smart Energy Federation.

In the Dec. 2022 and Jan. 2023 Newsletters, I wrote about the need for defining smart power assets for tomorrow. Here, I examine such a need for power transformers.

Recently, I was invited by India’s Central Board of Irrigation & Power (CBIP) to speak at their National Conference titled “Power Transformer & Reactor Failures” on August 9-10 in New Delhi. This was co-organized with CIGRE India. Many experts shared their views on transformer failures, diagnostic methods and preventive maintenance issues. I spoke on the need for Dynamic Transformer Ratings (DTRs) for reasons outlined below.

It is often mentioned that a good T&D network should be capable of evacuating at least twice the total generation (baseload and RE) connected to it. Higher the intermittent renewable generation, greater the need for a more reliable interconnected network to ensure no curtailment of low-cost clean power. For a country like India, a generation target of 400 GW requires about 800 GW of T&D capacity.

Power transformer failures have a big impact on the network due to their long repair time. Since the 1970s, we have come a long way in better designs, enhanced diagnostics and improved preventive maintenance, all leading to lower transformer failure rates. However, our progress in the past two decades has only been incremental (no major breakthroughs) and climate change restoration may have even slid backwards in (a) managing forced outages (long lead spares) and (b) much needed OEM repair facilities (most overseas now). ?

To complicate matters, two strong trends are here now. First, climate change with rising ambient temperatures (approaching 50°C in Asia and 115°F in Southern USA) and unpredictable wide daily temperature swings (±15°C). Second, a growing variable RE generation (wind/solar) whose intermittent output (particularly in MV grid and behind-the-meter) adding to “net-load” volatility (unless energy storage is widely deployed). Let us examine each of these pieces as it relates to a transformer’s operation:

1.????? Ambient Temperature Standards: In a very simplistic way, most standards define maximum ambient temperatures in two parts, (a) the maximum ambient temperature itself (40°C or 45°C); and (b) the required 24-hour ambient average to be 10°C lower. A 40°C ambient standard requires its 24-hour average to be 30°C. If the actual ambient temperature were to rise to 50°C, then one would need a 24-hour average to be 20°C to comply with the 40°C standard. But such differential rarely occurs, leading to name-plate de-rating of 10-15%.

2.????? Material Stress: Both electrical and thermal stresses cause material failure (insulation, oil, paper, gasket) by excessive temperature rise. Temperature excesses cause localized thermal damage which then becomes a nucleus for further deterioration. For example, paper insulation may need to be limited to 90°C, while oil may need to be limited to 120°C. Copper and steel can tolerate higher temperatures.?

3.????? Capacity Limits: The loading capability of a transformer is directly related to its internal temperature determined by its prior 4-6-hour load and the thermal headroom available hereon. The large mass (thermal inertia) takes more time to cool. Higher ambient makes for slower cooling. Repeated thermal overload can result in loss of useful life of the asset.

4.????? RE and Load Volatility: A high RE penetration (>40%) and its real-time output intermittency will mirror as “net load” volatility for supply transformers. This together with consumer-led daily load actions of ± 25% (lighting, hot-water, air-conditioners, cooking and now EV charging), further exacerbates total load volatility.

To sum up the above, a transformer’s capability to meet a forecasted load is heavily dependent on its (a) current internal temperature; (b) available thermal headroom; (c) forecasted ambient temperature; (d) temperature rise due to forecasted load duration; and (e) load-ramp steepness. This computed temperature-rise should be within the transformer’s thermal headroom under prevailing ambient conditions. Hence, dynamic transformer rating.

Since most transmission line assets in the USA is approaching 90% of its maximum rating, a similar concept is being introduced termed as Ambient Adjusted Ratings (AAR) by FERC Order 881 (a forecasted 10-hour ambient adjusted rating). IEEE 738 corelates the temperature-ampacity relationship. A more advanced method is Dynamic Line Rating (DLR) which measures wind-speed, ambient & conductor temperatures in real-time with load forecast.

Dynamic Transformer Rating (DTR) is better suited to large power transformers (≥ 5 MVA) than simply using Ambient Adjusted Transformer Ratings (AATR). This is due to (a) its large thermal inertia; (b) ambient temperatures swings; (c) long and expensive consequences of failures; and (d) high VRE penetration. It avoids a generic name-plate de-rating. On the other hand, AATR is more useful for smaller distribution transformers (< 5 MVA) not subjected to high RE penetration.

Temperature measurement inside a transformer (core, oil, windings, etc.) is often restricted to just top-oil temperature measurement. This is due to the fact RTDs and thermocouples cannot be placed inside a high voltage/electrical stress environment. This often warrants tradeoffs or compromises such as top oil temperature management (at 120°C max) with winding paper insulation (at 90°C max). In the past, this was possible since the load profile was a slow ramp with enough time to efficiently conduct heat away from the windings by the oil medium. Both of these assumptions are not valid anymore due to changing ambient and high RE penetration.

Today, fiber optic temperature measurement systems overcome several of the challenges described above.? They are thin and can be placed just about anywhere (including winding slots). Since they carry only laser-light, they are not affected by any electrical stress environment and are immune to EMI/EMF. Further, the technology enables digital, synchronized, time-stamped temperature measurements in real-time. Such systems can accommodate large fiber loop lengths (up to 20 km) with a temperature measurement every 1 meter along its length (enabling literally thousands of temperature measurements per measurement cycle). This allows for a good 3-dimensional internal thermal map of the power transformer. This technology has been successfully piloted in Canada/USA in medium voltage power transformers, cables, motors and reactors.

Such 3-dimensional internal thermal mapping can be undertaken on (a) new designs by the OEM as a prototype; (b) on a few transformers across geographies or substation groups or with other assets to create digital twin models; and (c) as a dynamic aid to real-time power transformer operations. Such internal temperature data can be correlated with electrical loads and ambient conditions to create standard operating procedures (SOP) and/or be fed into a SCADA system for real-time network operation.

The question is how many thermal data points and where inside a transformer, would constitute a good set of thermal mapping results. At the least, a representational temperature mapping should include about 25 data points each from (a) the steel core (core temperature); (b) select winding slots to include copper, joints, paper insulation (winding temperature); (c) bottom oil, bulk-oil areas, top-oil and wall-oil (oil temperature gradients); (d) external radiator (OFW cooling) or transformer tank top/sides (ONAN cooling); and (e) ambient air temperature (weather temperature). Thus, a good thermal asset mapping could have about 100 real-time temperature data points in 3-dimensions. Higher MVA or KV Class models and designs could have more data points.

To standardize DTRs, collaborative efforts must begin with utilities, OEMs, Standards bodies (SDOs) and research organizations working together to define the above. At the very least the utility needs (a) a new ambient temperature standard (50°C or 55°C); (b) an AATR operating procedure given rising ambient temperatures; and (c) real-time dynamic operating guidelines for large transformers along the lines of a dynamic transformer rating (DTR) model.

The need for Dynamic Transformer Rating (DTR) is urgent if our older assets must continue to operate in climate change and high RE penetration environment.