Transformer dissolved gas monitoring has long been accepted as a critical part of a utility's asset management strategy. But industry experience has shown the traditional method of periodic manual sampling and laboratory analysis cannot be counted on to catch events that propagate in short time periods.
With this understanding, remote automated dissolved gas analysis (DGA) technologies were developed and are now commonly available. These systems can transmit data to remote monitoring stations at near-real-time rates and have been proven to be an effective preventive maintenance strategy component. But, as the number of transformers being monitored increases exponentially, how do utilities avoid being overwhelmed by the flow of monitoring data?
Pepco Holdings Inc. (PHI) is in the process of installing on-line DGA monitors on critical transformers. The key is to be smart about exactly which indicators are monitored and what alerts are passed on to engineering and maintenance personnel. Approximately three years ago, PHI surveyed the market for dissolved gas monitors and selected the eight-gas Serveron TM8 on-line transformer monitors supplied by BPL Global. Serveron was chosen because of its reputation for providing monitors that have detected potential transformer failures for other utilities. PHI has installed between 50 and 60 units, and plans to have close to 100 on-line by the end of 2012, representing about 75% to 85% of the utility's larger transformers. Ultimately, the utility plans to monitor all of its critical transformers.
PHI has set up the monitors to communicate on its secure power delivery data network (PDDN). The PDDN has been designed to comply with the North American Electric Reliability Corp. (NERC) cyber security standards, ensuring that access to the raw information coming from the monitors is tightly controlled. PHI also wanted the analysis of the data to be available to essential personnel over the utility's regular corporate network, which is not necessarily subject to the same critical infrastructure protection (CIP) rules set by NERC.
Besides the need to provide easy and secure access to a wide array of corporate users, PHI wanted its asset monitoring system to prioritize the most critical information and simplify the display of that information for users, while still allowing easy and intuitive access to more detailed raw data needed for diagnostic purposes. After surveying available monitoring tools in the industry, PHI decided to develop its own asset monitoring and management (AMM) system.
What AMM Does
To automate the process of analyzing the information from remote monitoring, PHI partnered with BPL Global's Serveron division to develop an AMM system. A key component of PHI's AMM system is the Serveron TM View Enterprise software application. This application, which runs on PHI's servers and workstations, collects data from the remote monitors and transfers it to locations within and outside of the secure PDDN. It also provides a graphical interface that identifies and displays alarm conditions recorded by the DGA monitors and other sensors across the utility's network.
The TM View Enterprise solution is comprised of both a server component and a client component. The server component polls the PHI substations on the PDDN and automatically sends the monitored information through a system of switches, routers and firewalls to a centralized and secure database located on the corporate network. The data is transferred from the secure PDDN to the corporate network in a manner compliant with NERC CIP security standards, satisfying a key objective of the project. A graphical user interface (GUI) on the server side allows users to view data and configure the system. The server software on the PDDN also alerts PHI's engineering and maintenance staff by e-mail of conditions needing immediate attention.
The TM View Enterprise Client software, which runs on the corporate network, accesses information from the centralized database, making it available to corporate users through its own GUI. The client GUI is similar to the server GUI, with the primary exception that it is a view-only application and does not allow for system configuration. System changes can be made only from within the secure PDDN network.
The monitoring system is designed to be hardware independent, so different asset monitoring systems and devices with multiple communication protocols can be supported in the future. Besides monitoring transformer dissolved gas and temperature parameters, the system is being set up to monitor other devices such as load-tap changers, breakers and batteries. To make the most productive use of time for PHI's engineering and maintenance staff, they focus on the most urgent monitoring information. This requires that intelligence be built into the monitoring software.
AMM Relies on Key Indicators
Since more immediate problems in a transformer are normally indicated by a jump or change in levels of dissolved gases or oil moisture, the AMM system looks at these indicators and their rates of change. Monitors use gas chromatography techniques to isolate levels of eight fault gases — oxygen, hydrogen, methane, carbon monoxide, carbon dioxide, ethylene, ethane and acetylene — and correlate this data, plus oil temperature and ambient temperature, with transformer load. Some gases are more critical than others as indicators of developing catastrophic events. For example, methane, ethylene and acetylene are three key critical gases that may not only indicate failure development, but also predict what could be going wrong, thereby suggesting a path to rectify the problem.
The AMM system looks at overall levels of all dissolved gases (besides the three critical ones), but these are viewed as longer-term issues used more for trending purposes than diagnosing immediate issues.
To facilitate an analysis of the three key gases, the AMM relies on the Duval triangle, which is built into the TM View Enterprise software. The Duval triangle has been adopted by International Electrotechnical Commission (IEC) 60599-1999 and remains today one of the most valuable tools for making sense of changes in levels of dissolved gas in transformers. The Duval method plots concentrations of methane, ethylene and acetylene, expressed as percentages of the total on a triangular chart subdivided into fault zones. The chart can distinguish problems due to overheating from those due to electrical discharge or those involving both thermal overheating and electrical discharge.
The setting of the gassing and rate-of-change limits for each individual transformer is what drives the software. Limits are carefully selected for each PHI transformer based on inputs such as voltage, size, rating, manufacturer, load, criticality, previous gassing history and footprint. Once the appropriate limits are set, the software notifies users when a limit has been exceeded and data needs to be evaluated.
PHI has been running the transformer monitoring software for close to a year. So far, it has been able to detect several maintenance conditions and closely monitor other abnormal situations with ease. Remote monitoring has enabled PHI to make more accurate diagnoses to proceed with proactive repair decisions to maximize the life of its assets or make timely plans to replace the equipment before experiencing a catastrophic failure.
AMM in Action
An example of an abnormal situation PHI is closely monitoring is at an autotransformer in one of its Delaware substations. This transformer has had several core grounds over the years that have resulted in excessive thermal overheating and arcing within the transformer. After several attempts by maintenance personnel to remove the core grounds and prevent further internal damage and degradation to the transformer, the AMM system and diagnostic software continually notified PHI that repairs were not successful. Given the condition and ability to closely monitor the active situation with this transformer, PHI was able to make a timely decision to replace and, in the meantime, is able to nurse the transformer until it can be proactively replaced. Had PHI not caught the recurring condition in time, the transformer probably would have failed before it could have been replaced.
With the AMM system in place, and given the ability to remotely monitor PHI's transformers, the utility's engineers and maintenance personnel can now come in to their offices every morning and see at a glance how the system is operating. If personnel are not in the office, they can still access the information using a secure VPN connection. The information also is used by management to get a broad view of how the electric system is performing.
The AMM system has resulted in making PHI's maintenance staff more productive and has certainly improved the utility's sense of awareness of the health of its transformer fleet. As previously mentioned, PHI is now working to apply these tools to assets other than transformers, such as load-tap changers, breakers and batteries.
Carl S. Kapes (firstname.lastname@example.org) is the senior supervising engineer over maintenance strategy and failure analysis teams within Pepco Holding's asset management department. Kapes helped develop the reliability-centered maintenance program at Pepco, and helped develop and run the equipment condition assessment program, which is used to make repair or replace decisions on T&D assets. Kapes holds a BSEE degree from Villanova University and a Juris Doctor degree from Widener University School of Law.
Finding the Data in AMM's Monitoring Screens
There are four levels of monitoring screens in the asset monitoring and management (AMM) system of Pepco Holdings Inc.
The top-level screen shows the four regional utilities that are part of PHI. Each of the four regions has three circular indicating lights. The first light on the left indicates whether a gassing caution or alarm warning exists within the region. If this light is green, there are no gassing alarms within the region. If this light is yellow, there is a gassing caution limit that has been exceeded within the region. If the light is red, there is a gassing alarm limit that has been exceeded within the region.
Gassing limits can be based on dissolved gassing rate of change or overall dissolved gassing levels on a per-gas basis. The middle light is for reporting monitor service issues only. If the light is green, there are no monitor service issues within the region. If the light is blue, there is a service issue within that region.
The third light, on the far right, indicates the age of the current data. If the light is green, data within the region is less than 12 hours old. If the light is yellow, data is between 12 and 24 hours old. If the light is red, data is older than 24 hours. PHI sets its monitors to gather data at least every 8 hours, if not more frequently. If data is older than 24 hours, it usually needs to be investigated as there may be a power or communications issue with the monitoring device.
After picking the region — in PHI's case, this would be New Castle, Bay, Atlantic or Central — the user can further drill down to the substation level to narrow down where an issue may be within the selected region.
The bottom-most level of the drill down provides specific monitored information. The screen level, shown above, indicates which parameter is in a caution or alarm state and also indicates what the limits are when the user rolls the mouse over the parameter. Information in the screen shown on the left also indicates if service is required.
Once a problem has been identified by the system, further analysis can be conducted by using special diagnostic software tools built into the software. Serveron's TM View Enterprise software application provides detailed monitoring status information for each individual transformer. The user can work through screens and see other information such as overall gassing trends , the Duval analytical tool, caution and alarm limits, rate-of-change limits, sampling frequencies and even monitor calibration data.
BPL Global www.bplglobal.net
International Electrotechnical Commission www.iec.ch