Power transformers are critical to the electric power system. And utilities are now focusing on reliability-centered maintenance of their assets for extended life and maximum return on investment. A large proportion of power transformers have attained their designed service life. The deterioration of a transformer's internal components results in the production of combustible gases that dissolve in the transformer's oil. Because of this, utilities have long incorporated transformer oil testing into their asset management programs.
Asset managers have learned from experience that just checking for fault gases a couple of times a year by performing laboratory oil analyses is not always sufficient to detect problematic conditions that may develop quickly over a period of days or hours. In response to this issue, utilities have begun installing monitoring systems that perform remote dissolved gas analysis (DGA) on a near-real-time basis and transmit results to central monitoring stations.
Though remote dissolved gas analyzers have been available for more than a decade, utilities primarily have chosen to equip only the transformers generally viewed as aging problem transformers with remote monitors. This is easy to understand because the total project cost of adding a remote monitor to a transformer can run in the neighborhood of US$55,000 per unit, so the investment is significant.
While making this investment may be viewed by some utilities as easier to justify for problem transformers, there are reasons that can justify the broader use of monitoring systems. One reason is to validate the effectiveness of maintenance programs on transformers of any age. Viewed in comparison to the cost of replacing a transformer, remote monitoring is an affordable expense. Asset managers know if a large transformer should fail, the replacement cost of the transformer could be in the ballpark of $3 million to $4 million, with as much as a two-year lead time for obtaining a new unit, in addition to lost revenue from domestic and exporting power markets.
Some utilities are considering the value of on-line DGA as part of their maintenance programs, and there is often a debate within utilities regarding whether remote monitoring devices are valuable on transformers that are not nearing the end of their life cycle. At BC Hydro, an incident with a transformer that was not nearing the end of its life cycle shows the value of monitoring other units, as well.
Monitoring Uncovers an Issue
Four generator transformers are installed at BC Hydro's Seven Mile Generating Station. The 225-MVA T1, T2 and T3 transformers were installed in 1978, and the 233-MVA T4 transformer was installed in 2003. All four transformers were equipped with gas detector relays and, when T4 was commissioned, BC Hydro installed a hydrogen monitor after an internal problem was detected during the initial energization.
In December 2004, T1 began gassing, indicated by a gas relay alarm, so BC Hydro maintenance staff moved the hydrogen monitor from T4 to T1 to gather more data on the failure. Further testing revealed there was an internal short circuit between the core and the frame (that is, C2 to F1 short) due to failed insulation or contamination. The engineers installed a resistor in the C2-F1 grounding circuit to minimize the circulating current and minimize the gassing issue.
In January 2011, T2 had a gas relay alarm determined to be the result of an internal high-voltage bushing failure.
These two events motivated BC Hydro management to examine the other transformers at the station. The utility decided to install eight-gas fault monitors on each of the transformers at the generating station since these two failures had not been detected by traditional oil testing methods.
BC Hydro chose eight-gas monitors for both technical and commercial reasons; measuring the levels of all eight fault gases typically provides a more definitive picture of what is going wrong inside a problem transformer than can be determined by monitoring a single gas such as hydrogen. The gas chromatography system contained in the monitors, which employs a fully automatic National Institute of Standards and Technology (NIST)-certified calibration capability, has been tested and refined over the product's history. Utilities around the world are basing their transformer asset maintenance strategies around them.
The on-line DGA monitors were installed on T2 and T3 in July 2011, and the T1 and T4 transformers in October 2011. Immediately after the T1 and T4 monitors were installed, they produced gas level alarms, which is not unusual for new monitors during the first 48 hours of operation (while alarm threshold settings are established and fine-tuned).
On Oct. 13, two days after the monitors were installed, the T1 alarm was still present while the T4 alarm had cleared. The on-line DGA reading showed elevated levels of CH4 (methane), C2H6 (ethane), H2 (hydrogen) and total dissolved combustible gas in the oil. BC Hydro maintenance personnel took T1 out of service and rushed oil syringe samples from all of the transformers to the lab. They also contacted the DGA monitor vendor's service staff, who verified the T1 monitor was working properly. On Oct. 14, BC Hydro received notification from the lab verifying the elevated fault gas levels that had been indicated by the eight-gas on-line monitor.
BC Hydro maintenance personnel isolated the T1 transformer for more testing. During the electrical tests, they were suspicious of the ground resistor because they saw gas levels similar to those seen in 2004. The engineers determined that, when the maintenance people reattached the core/frame grounding cover after the latest round of maintenance tests in September 2011, the wiring had become pinched, shorting the resistor out of the circuit and causing the same condition that had occurred in 2004.
The wiring problem was fixed and T1 was put back in service. The transformer was observed by the on-line DGA monitor to verify gas levels remained constant and there were no other problems. New gas level alarm settings were implemented since the levels were now above the normal “high” limits and plans were initiated to degasify the T1 oil during a scheduled maintenance outage in 2012.
On the morning of Nov. 18, the T1 monitor alarm went off again, with one gas level above the new setpoint. The transformer was closely monitored, and within 6 hours, five total gas levels had set off alarms, so the transformer was taken out of service immediately. A series of electrical tests were performed on the transformer and another short circuit was found inside the transformer, this time between the second half of the core and frame (that is, C1 to F1 short).
A second resistor was installed in the C1-F1 grounding circuit, and the transformer was energized for an 8-hour test to confirm the gassing had stopped. During this energization test, the monitor was used to provide hourly gas samples to determine whether to continue or abort the test. T1 successfully passed the energization test with no further gassing.
Coincidently, or perhaps not, an earthquake occurred at 5 a.m. on Nov. 18 in northern Washington, about 200 km (124 miles) southwest of the Seven Mile Generating Station. The 4.6-magnitude earthquake was felt by personnel living in the area, although it is unknown whether or not the earthquake initiated the second core-to-frame short.
A series of lab tests also were conducted on the T1 oil and, because of contamination concerns, BC Hydro decided to replace the oil before returning the transformer to service to ensure the long-term reliability of the transformer. During the oiling work, an internal inspection of T1 was conducted but did not identify the root cause of the short. On Dec. 14, T1 was returned to service with the two grounding resistors installed.
By using on-line monitors connected to a local area network, subject-matter experts were able to review gas levels in real time, helping them to make better technical and operational decisions about the transformer's performance. During the T1 energization test, this provided an added personnel safety benefit of being able to barricade the transformer area while accessing all information from the office.
Effective Asset Management Tool
With results such as those seen at the Seven Mile Generating Station, BC Hydro is proving that on-line DGA is a good investment. As an effective early-warning device, it gives maintenance managers comfort in the integrity of their assets. The monitors can show when maintenance is required and confirm maintenance performed was effective.
BC Hydro's experience also shows that monitoring systems can help to extend the life of problem transformers, by enabling them to be run at decreased load until they are replaced or a permanent repair is made. Without the ability to do continuous monitoring (if only laboratory oil analysis is available), the best practice may be to take the transformer out of service if there are operational or personnel safety concerns.
BC Hydro is considering a plan to specify every new transformer it buys be installed with an on-line monitor. The utility also is considering an engineering standard to determine when old transformers with gassing concerns need to have on-line monitoring installed to ensure the safe and reliable operation of the transformer. Maintenance managers feel this makes sense, comparing the cost of the transformer with the cost of the monitor.
Jamie Beauchamp (Jamie.Beauchamp@bchydro.com) has been working for BC Hydro since earning a bachelor's of engineering from the University of Victoria in 1993. He has primarily worked as a field engineer and is presently the senior electrical maintenance engineer for Lower Columbia Generation region. His primary focus is on maintenance and reliability of hydroelectric generating station equipment.
Muhammad Arshad (Muhammad.Arshad@bchydro.com) works at BC Hydro Canada, Generation Engineering as a division manager (electrical and P&C design). His primarily research interests are condition monitoring, diagnostics and remnant life estimation of power transformers and generators. He holds a Ph.D. degree in electrical power engineering in 2006 and is a senior member of the IEEE.
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