Infrared thermography, ultrasonic noise analysis, partial discharge detection, dissolved gas analysis, vibration analysis - all are very high tech and necessary to determine the health of a transformer fleet. Although high tech is needed, it must be coupled with a good dose of common sense. To determine the condition of each critical transformer on a system, a process must be adopted to provide enough data and information to make a decision to repair, replace, or continue to trend a detected condition.
Consider what a transformer is willing to tell you and what you have to do to listen. A transformer makes noise in the sonic range and ultrasonic ranges. Common sense tells us to listen to both ranges to learn what a healthy transformer sounds like and what a transformer in failure mode sounds like.
A transformer also gives off heat during operation. Common sense tells us to learn the difference between a normal heat signature and one that is in failure. Insulation failure is the number one cause of transformer failure. Common sense also tells us that testing the insulation system while the transformer is at full voltage will give an early warning of impending failure.
This article provides guidance in setting up a common sense program that provides utilities with a complete health report and condition assessment of critical oil filled power transformers. The testing described in this article is performed on energized, fully loaded transformers. No clearance or blocking is needed to accomplish these tasks. All tests described are completely nonintrusive.
The objectives of this article are to answer many common questions and be a resource to those seeking to better determine the condition of oil filled power transformers, generators, lighting arresters and other equipment. Furthermore, readers are encouraged to make this a learning experience. If you only bring away one point of value, consider that a win. Mediocrity is not acceptable! The technology available today is exactly what is needed to provide an environment of excellence.
Do You Think Waiting Until a Disaster Strikes Is the Time to React?
French philosopher and writer Voltaire is credited with the quote, “Common sense is not so common.”
Whether common sense just doesn’t make sense, there is a lack of it in your organization or whatever reason fits your needs, the outcome will be the same - the avoidance of the issue. The catastrophic failure and fire in Figure 1 actually happened; it was not staged for this article. And it will happen again! The cost for a failure like this one could easily exceed $100 million.
Figure 1: Failure led to this catastrophic fire.The aging of the electrical infrastructure in North America is a critical problem that each one of us faces. There is no way to get around this fact. As aging transformers continue to fail, a new level of awareness of the magnitude of the situation becomes very clear.
Many transformers fail unnecessarily. Proper care and condition assessment of these valuable assets is needed now more than ever. With the average age of a transformer fleet over 40 years and a new transformer fleet having a higher than expected failure rate, a proactive approach to predictive maintenance (PdM) is needed. Large power transformers are not off-the-shelf items and must be ordered one to two years in advance. Many are not being manufactured in the U.S. or Canada, so the repair and replacement schedule is critical in most cases. These facts make knowledge of transformer condition of utmost importance.
The crucial nature, fragility, age and long lead time for major components and the interconnection of the grid’s electrical system demand that the best maintenance approaches possible be applied to help ensure reliability. Adding smart metering to a stupid infrastructure does nothing except make money for the meter company.
Transformer Lifecycle and Risk Management
Determining the health of a transformer is a process that can mean the difference between a transformer’s long life and an early death. Certain random failures can occur anytime and with little or no warning, but as a transformer ages, there will be measurable warning signs that foretell the cause(s) of impending failure. The insurance industry states that insulation failure is the number one cause of transformer failure. So how do we determine insulation quality while these transformers remain in service?
Add These Inspections to What You Are Doing Now!
A typical good inspection program, which most utilities are doing, includes the following:
• Dissolved Gas Analysis,
• Offline Electrical Testing.
An enhanced program includes three other components. Adding these to an existing program will greatly reduce the unexpected failure rate:
• Partial Discharge Monitoring and Analysis. (portable and online);
• Vibration Analysis (determine core and coil assembly tightness);
• Sound Level Measurements (precursor to looseness);
• Grading Method (transformer ranking tool);
• Template Building (tier assignment done here).
Unexpected Failures Are Unacceptable
Very rarely will a failure occur without first revealing some small change that is detectable utilizing one or more technologies. A complete transformer condition assessment (TCA) combines data from various technologies to provide insight and an understanding of often subtle, pre-failure signs. In addition, a complete TCA provides an accurate as possible gauge of the health of the transformer’s subsystems, including pumps and cooling system, on-load tap changer (OLTC), no-load tap changer (NLTC), and lightning and surge arresters.
Partial discharge (PD) is unwanted electrical activity. PD is similar to corona activity and occurs at high-voltage sine wave peaks. Most low-level PD activity is load dependent. As the load increases, the voltage decreases. When the voltage decreases, the PD will decrease or disappear completely and then return when the voltage returns to full value.
Up to 80 percent of all oil filled power transformers exhibit some PD. Low-level PD activity sometimes continues for the entire life of a transformer. When insulation breakdown from PD gets to a point where it threatens the life of a transformer, a decision must be made as to whether or not to remove the transformer from service.
Because PD is present in so many transformers, knowing the present condition is critical. Without systematic TCA, there is insufficient information available to confidently decide when to take appropriate action. In a quest to determine unwanted activity, data can be gathered at a moment in time, either as a snapshot or continuously over 24 hours or more like making a movie. Movies generally tell a more complete story.
By adding the previous steps to a TCA process, major failures will be averted. Significant money will be saved and a major safety feature will be built into every visit to the high-voltage transformer yard.
Detecting Acoustic and Electrical Problems on Energized Equipment
The following PD test is used to determine the severity of an electrical fault using the burst interval of the PD pattern captured by the high-frequency current transducer. Then, if the source of the fault is located in an area where its sound reaches the tank wall, acoustic sensors triangulate the exact spot of the fault. Fault sound reaches the tank wall about 90 percent of the time. About 10 percent of faults are deep within the core and coil assembly, so the sound cannot be detected externally. In these cases, at least fault severity and the fact that the fault will require some work deep within the windings are determined.
Acoustic tests have been used for many years to detect and locate partial discharges in power transformers, but the addition of high frequency current transducers (HFCTs) installed on the case ground of the subject transformer make the process complete. It is more difficult to determine if a problem in an oil filled transformer is related to mechanical or electrical malfunction by using acoustic sensors alone. Partial discharge testing using both acoustic sensors and HFCTs makes the determination easy and increases the protection factor for these utility industry assets.
Figure 2 shows acoustic and electrical activity obtained simultaneously. The top portion of the screenshot shows recorded acoustic sensor data, while the bottom shows electrical data from the HFCT. The software user can use the computer cursor to determine the time difference between each burst or burst interval. In this example, the spacing of both the acoustic emission (AE) and HFCT sensors is 16 milliseconds. This indicates that the activity takes place at the voltage peak of each cycle.
Figure 2: Screenshot showing classic partial discharge in an energized power transformer
Asset managers need to know what to do and when to do it to be able to avoid impending failure. The ability to trend the deterioration process aids the asset manager in deciding when to take action.
Figure 3 shows acoustic and electrical data measured for amplitude and duration. This is easily trended by comparing subsequent test results under similar conditions. The top window in the screenshot shows the AE bursts with sensor #2 (red) being closest to the source. The bottom window shows the electrical burst captured from the case ground lead using the HFCT.
The signature captured by the HFCT in the bottom portion indicates a severe case of PD. The spacing between the end of one burst and the beginning of the next burst - called burst interval - is getting dangerously close to two milliseconds, which indicates a failure is imminent. Burst interval is critical information in determining the severity of PD.
Figure 3: Interval between bursts measured to determine severity of partial discharge
Lightning Arrester Testing (Energized at Full Voltage)
The two screenshots in Figure 4 indicate internal arcing in a 500 kV lightning arrester. For these screenshots, an HFCT was located on the arrester ground lead above the strike counter. Multiple data captures on this lightning arrester were all different. No PD was detected by the tests, only arcing.
Normally, lightning arresters have no activity; if this arcing problem was not detected and corrected early, the fault would likely have resulted in a catastrophic failure. This arrester was consequently removed from service, tested offline and disassembled. Offline testing was done at 10 kV and did not find the problem. Teardown found evidence of moisture ingress.
Figure 4: Screenshots of lightning arrester arcing at full voltage
Vibration Analysis of Transformer Main Tank
Vibration analysis is advantageous because it is noninvasive and done online while the transformer is under load. In order for a transformer to withstand through faults or switching surges that include heavy load conditions, the core and windings must be securely blocked and clamped to prevent movement, shifting, or distortion. Clamping pressure must be maintained to prevent core and winding looseness. Deterioration of the pressboard due to moisture or heat may cause shrinkage and looseness. Trending vibration and sound level data is critical to gauge the health of a transformer.
Acquiring Vibration Data
An accelerometer attached to a magnetic base is used to collect vibration signals. This data is stored in a vibration instrument, then downloaded to a computer for analysis with standard vibration software. Eight data points are taken on each transformer and vibration sampling results are commonly displayed graphically as waterfall plots, such as those shown in Figures 5 and 6. Starting on the high-voltage side, arbitrarily named side #1, and moving counterclockwise, data is acquired from two points on each side or wall of the transformer. The exact data point locations are determined by the size and configuration of the transformer, either core form or shell form. It is crucial that the data is gathered by experienced personnel and taken at the correct locations for each type of transformer.
The ideal spectrum of a steady-state vibration signal from a healthy, tight transformer will contain frequencies that indicate a normal signature. First and foremost, 120 Hz pressure waves are detected. These pressure waves are two times 60 Hz line frequency, in that each 60 Hz shift from positive to negative creates a 120 Hz pressure wave that travels through the core, blocking and oil to the transformer wall. Harmonics of 120 Hz also will be detected. It is the combination of data and the shifting of energy that indicates whether a unit is tight or loose.
Analyzing Vibration Data
Recognizing symptoms of core or blocking looseness is imperative in diagnosing transformer condition. Original methods of transformer vibration analysis only considered amplitude. This was based on severity criteria measured in inches per second. Subsequent research has shown that frequency shifts point toward core and winding looseness, regardless of amplitude.
Case Study 1: Normal Shell Form Transformer Waterfall Plot
The transformer used in this case study is a fully loaded 456 MVA generator step-up (GSU).
Figure 5: Normal waterfall plot of vibration analysis of tight GSU transformer
Notice that the dominate frequency is 120 Hz. The spikes to the far left are at 120 Hz even though they appear to be at 100 Hz. That is due to the angle of the waterfall plot. Note that there is very little energy shift to the higher frequencies (240, 360 or 480) indicating that this is a tight transformer. Testing in this manor takes only about 5 minutes and is done fully loaded.
Case Study 2: Loose Core Form Transformer
The vibration data in this case study is from a very small core form transformer. The load at the time of the test is unknown, but average load is 80 to 120 amperes.
Figure 6: Waterfall plot indicating looseness in this small core form transformer
Notice that 120 Hz has dissipated and the energy in the spectrum has shifted to the right to 240 Hz. Average sound level sampled during this test was 81 decibels (dB), a level that is eight to 12 dB higher than similar units at the same load.
The Ranking Tool
Historic data and up-to-date data are entered into a spreadsheet. Built-in formulas evaluate the condition and generate a number and letter grade for each transformer. This tool aids in risk management and with repair and replacement decisions of transformers. The tool also ranks the transformer fleet and shows the highest score achievable when all issues are repaired.
Figure 7: Ranking tool
Adding these test methods to what you are currently doing and combining data from all available technologies greatly improves your success of lifecycle management.
The realities are:
The risk of a failure is real; managing that risk is a full-time job.
Aging electrical equipment may fail.
These failures will cost time and money.
A small investment in the latest technology will pay for itself quickly.
A quality PdM program controls costs and prevents unexpected failures.
Doing nothing is not an option!
A special thank you to Dave Hanson, President of TJ/H2b, where I have been honored for many years presenting at various TechCon Conferences. TJ/H2b provided critical editing work and gave permission to use this article in Uptime magazine.
Jon L. Giesecke is President and CEO of JLG Associates, LLC, a company he founded in 2006. Jon is one of the world’s leading experts in combining technologies used in the in-service inspection of high-voltage oil filled power transformers and substation diagnostics. He has been training personnel worldwide in these methods for over 20 years with great success.