Over the life of a transformer, thermal, mechanical, electrical and chemical factors degrade the transformer's insulating oil or materials. This degradation causes transformer fault gases to form and dissolve in the oil or escape into the atmosphere. The concentrations of individual dissolved gases in the oil, as well as the combination of gases present, are primary indicators of the condition of large transformers. Certain gas levels indicate aging, the need for maintenance or potential failure.

To monitor the gas content, transformer engineers periodically take oil samples from the transformer and send them to a lab for dissolved gas analysis (DGA). Analysts use a variety of IEC, ASTM and IEEE approved oil-analysis techniques to predict whether a fault has occurred and, if so, the type of fault. Virtually every analytical lab uses a laboratory gas chromatograph (GC) to analyze transformer oil samples for dissolved gases, which are typically acetylene (C₂H₂), methane (CH₄), ethane (C₂H₆), hydrogen (H₂), oxygen (O₂), ethylene (C₂H₄), carbon monoxide (CO) and carbon dioxide (C0₂).

It is important to monitor trends in the individual gas components. A significant change in the level of any gas may signal impending failure. If the individual gas concentrations are not measured, but instead reliance is placed on combined “total combustible gas” measurements, then some early warning signs might be missed.

Standard sampling periods can be as infrequent as once a year, or more often for a suspected failing transformer. While well documented and defined, the periodic laboratory DGA method, in practice, can be error prone and can miss predicting exact equipment failures. For example, periodic sampling may not detect instantaneous faults that occur and subside within sampling intervals. In addition, it is possible for the properties of oil samples to change during the time between drawing the sample and when the sample reaches the lab. The sampling and analysis process is cost- and labor-intensive. For example, a transformer that requires frequent testing can cost tens of thousands of dollars in maintenance time and lab fees over the course of a year.

A Real Experience

Preferable to periodic oil sampling and testing at a remote laboratory is a means of bringing the lab to the transformer and continually testing the oil. The U.S. Army Corps of Engineers Portland District (USACE, Portland, Oregon, U.S.) has been working with just such an instrumentation facility to monitor its generation step-up unit (GSU) transformer at the Green Peter Dam in southern Oregon. Green Peter is a small hydroelectric powerhouse with two generators and one transformer (a three-phase 1967 General Electric Coreform 115 MVA GSU). Conventional periodic laboratory oil analysis monitored the transformer at the dam. Following a series of tests, maintenance personnel saw the elevated fault gases (hydrogen and acetylene) in the oil, which caused concern about an imminent failure.

To get a real-time view of what was going on inside the transformer, the USACE Green Peter staff installed a TrueGas on-site transformer gas analyzer produced by Serveron Corp. (Hillsboro, Oregon). This online gas chromatograph takes the laboratory to the transformer providing on-the-spot, continuous analysis.

The on-site gas-in-oil analyzer examines the same eight gases as the typical lab. Measurements are made within the closed system of either the nitrogen-blanketed headspace or the transformer oil, therefore eliminating errors induced through sample handling and delays between drawing and analyzing the sample.

A built-in verification gas source, which is traceable to the National Institute of Standards and Technology (NIST) standards, provided online validation of measurement accuracy and documented the system operation. Measurements taken as often as every four hours provide near-continuous data on transformer operation. The analyzer monitors the Green Peter GSU transformer, measuring all eight transformer fault-indicating gases, and storing and analyzing the results to predict transformer faults. To confirm the data from the Serveron instrument, the USACE Green Peter staff continued to use conventional laboratory analyses during a trial period.

At 4 a.m. on June 27, 2001, the on-site monitor discovered a fault event within the transformer, resulting in increases in acetylene from 28.7 ppm to 37.5 ppm by noon, while hydrogen rose from 28.2 ppm to 37.0 ppm. Before the event, nominal acetylene and hydrogen gas levels ranged consistently between 20 ppm and 25 ppm. The jump in the concentration of acetylene versus time indicates high-voltage, high-temperature arcing within the transformer.

When the USACE Green Peter staff saw this real-time information, they immediately shut down the transformer to avoid a complete failure. Four days after the event, the USACE brought the transformer back online with a program of continuous four-hour sampling. However, the transformer is scheduled for replacement. With the close monitoring that the on-site DGA provides, the USACE facility can continue to produce power while awaiting the delivery and commissioning of the new replacement unit.

Advantages of Remote Monitoring

In addition to “bringing the lab to the transformer,” the DGA provided the ability for monitoring remotely continuous test results. Using the instrument's built-in modem, the maintenance engineers responsible for the Green Peter facility track fault gas levels at the dam 24 hours a day, even from their homes. Because the data is remotely accessible, the engineers have the ability to respond faster to problem conditions, while also reducing unneeded visits to the facility during normal conditions. The availability of timely and complete information makes it easier to use trending and analysis techniques to decrease risk of failure.

Today, the Green Peter staff has eliminated the need to use laboratory gas sampling. They keep the transformer online unless they see a problem. Now that the monitoring of the transformer at the Green Peter site has become routine, USACE is able to focus its limited resources where it can be most effective. Periodic online remote analysis has become an important asset management tool for USACE.

Maurice Secrest received the BSEE degree from the University of Washington in Seattle in 1962. His work experience includes extensive experience with the construction of Veterans Administration hospitals and with construction division in the Corps of Engineers. Currently working for the U.S. Army Corps of Engineers Portland District, he is with the Technical Section of Operations Division. Presently, he is a project manager for a team responsible for overseeing the repair, upgrade and replacement of hydropower equipment and related facilities within the Portland District.