By Patricia Irwin, PE, Consulting Editor
At a powerplant, a great deal of attention is given to the generators, turbines, and everything else needed to generate electricity. The substation often gets overlooked because it is outside the plant and requires a very different set of skills to maintain and understand. But it is on the critical path from generation to profit and must be considered an integral part of any successful power production operation. This article reviews six key steps to a better understanding of substation maintenance requirements.
Step One: Determine what must be maintained, how important it is, and how difficult it is to keep in top condition. Then, plan accordingly. While everything between the point of generation and the point of sale is on the critical path, some devices (conductors, poles) are less likely to fail than others. Plus, some devices—such as common breakers—are easier to repair or replace than others, because parts are readily available, repairs are quick and easy to make, replacement units are available, and/or can be installed relatively quickly. Still other devices, like large transformers, take a long time to repair or replace. Transmission and distribution companies focus significant attention on them and use a number of triggers to schedule maintenance.
Long replacement lead times, high first cost, and the need for high reliability dictate that power transformers be maintained in accordance with good utility practice. This includes attention to industry standards and to manufacturers’ recommendations. Maintenance includes inspections, testing, and corrective tasks. While there are manufacturer-recommended and typical utility maintenance frequencies for these tasks, the frequency for activities—such as oil testing and visual inspections—may need to be increased in response to specific situations—such as an indication of a deteriorating condition that cannot be immediately addressed.
A widely used summary reference on substation O&M activities based on the experience of PJM and its participating companies is readily available and worthwhile reading. Generating plants also need to carefully maintain their transformers and should consider having spare units on hand or preferred access to them. It’s important to recognize that spares also require maintenance.
Step Two: Recognize maintenance for what it is. “Maintenance basically is the management of deterioration,” says Tony McGrail, solutions director for asset management and monitoring technology at Doble Engineering Co. Everything in the substation eventually will reach the end of its useful life and will be replaced or fail. Asset management, maintenance, and monitoring help manage that inevitable process, but keep in mind that not everything can be managed with complete foresight. There will always be surprises.
“Someone at the plant should understand why the maintenance needs to be done, what it is correcting, and also understand what is not being addressed. For example, the cellulose insulation in transformers and bushings can’t be maintained. It slowly degrades over time,” explains McGrail.
Step Three: Appreciate that a good maintenance plan can reduce unplanned outages, but failures cannot be completely eliminated. For any device, if there is a sufficiently large population in service for a long enough time, trends will be identified. Certain devices (by manufacturer, series, age, operating conditions, etc) have known failure modes. If you know what they are, you can watch for potential problems.
To begin, it is essential to understand failure modes.
- The first type: A device slowly deteriorates, giving the operators plenty of warning. At some point, the operators decide to replace the device because its performance is no longer acceptable or the risk of failure is too great.
- The second type: Without much (or any) warning, monitors detect an imminent failure, the device is de-energized, and it must be replaced.
- The third type: A device fails without warning.
Good maintenance plans and monitoring can help with the first two failure modes. Knowing what equipment is in the substation yard and its typical failure modes can help with all three. This is why knowledge and experience are important.
Step Four: Recognize there is little sense in gathering information if you do not know what it means and how the data impact maintenance. Equipment diagnostic tools and tests can be used in evaluating the need for maintenance (sidebar). Examples include dielectric testing and analysis, breaker timing, thermography scans, and acoustic monitoring. The facility owner’s plan should be clear as to the application, as appropriate, of these diagnostic tools. Pass/fail ranges and testing intervals should be well documented.
“When it comes to failure modes, someone should know what the symptoms of failure are and how likely you are to detect those by monitoring or testing. Someone also should know when it makes sense to bring maintenance forward or defer maintenance based on monitoring/test information. You need to understand the risks associated with that decision,” cautions McGrail.
From the deckplates
One 2 × 1 F-class combined-cycle plant recently visited by the editors invested in a dissolved-gas monitor for its transformers to help detect impending fault conditions and prevent lengthy forced outages. DGA, or dissolved gas analysis, is considered the single most powerful tool for transformer fault detection and asset management.
The eight-gas (H2, CO, CO2, O2, methane, ethane, ethylene, acetylene) online DGA monitoring unit from Kelman Ltd installed relies on advanced photo-acoustic technology to measure all significant fault gases, plus moisture in oil, without need for carrier or calibration gas. Data from the gas analysis go to the plant DCS and are stored in PI on a 1-sec basis.
The plant also installed Doble Engineering Co’s online intelligent diagnostic device (IDD) to continually monitor bushings and current transformers (CTs). The system detects abnormalities in the insulation system and, when appropriate, issues alerts—both locally and remotely. This keeps asset managers informed about the status of their bushings and provides the lead time necessary to determine appropriate corrective action, if necessary.
When IDD identifies abnormal bushing behavior it analyzes leakage current and assesses the condition of the insulation system. More specifically, IDD calculates the absolute and rate-of-change of power/dissipation factor and capacitance of the problem bushing, enabling it to determine problem severity. Advanced signal processing and field-proven algorithms are designed to eliminate noise effects and other environmental conditions conducive to incorrect diagnosis and inappropriate corrective action.
Step Five: Asset management and ROI are critical variables in the maintenance equation. “My view of substations, philosophically and strategically, is the less you spend the better, but you have to balance the risk,” opines McGrail. If you can do less maintenance, fine. But, you need to know what the consequences are and ensure that the maintenance you are doing is valid, valuable, and provides a return on investment,” he continues. However, finding the balance can be challenging. Maintenance strategies vary from “periodic” (maintain a device on schedule, whether it needs it or not) to “risk-based” (run a device to failure if it makes financial sense).
When deciding what should trigger maintenance, there are many things to consider. One is operating conditions. Heavily loaded and/or frequently operated devices (like breakers) may be at higher risk of failure. Frequent plant cycling may put additional stress on transformers. Frequency of operation also should be factored into the determination of maintenance periodicity. Trending of equipment performance versus maintenance should be used to re-evaluate maintenance intervals.
Proper monitoring is particularly important. If you know likely failure modes, you can choose monitoring methods that should alert to maintenance or repairs prior to failure. But there are limitations, as McGrail points out. “Monitoring will only catch those things that can be identified by the parameters that you are measuring. For example, a certain type of bushing has two known failure modes. One is generally thought to be caused by a manufacturing defect and can be detected prior to failure by an increase in the leakage current and changes in power factor.
“The second mode is related to transients on the system and the close proximity of the bushing’s connection lead to the tank. During normal operations, there is possibly a small internal discharge to the tank, but a large transient spike can cause a flashover. Unless you can detect the internal discharges during normal operations—very difficult because they are so small—you can’t predict that failure mode. It becomes obvious only when a flashover occurs.”
Age is another thing to consider. The emblematic bathtub curve indicates that some failures in new devices can be expected to occur because of manufacturing/material defects. Failures then level off until age takes its toll. Older devices can be more likely to fail, especially when stressed.
“For example, studies have found that two-thirds of transformer failures occur because of external causes. Admittedly, those events are difficult to predict and prevent, but if the transformer is weakened by age and the deterioration of its cellulose insulation, it is more likely that the external cause will successfully destroy the unit,” explains McGrail.
Step Six: Risk management. Powerplant personnel can study all the substation data available, but in the end, someone or a small team decides what should be done and when. Statistics help you make a decision, but they are not a decision in themselves.
McGrail points out, “There is a difference between probability and uncertainty. For the owner of a plant, it is important to increase real knowledge about that particular substation and make a decision based on more certain information to work out failure probabilities. It might mean performing more maintenance, or less. It will probably lead to more inspections, more monitoring, and more training. Hiring outside vendors to operate and maintain the substation, might be the best option, but someone at the plant still needs to know enough to review their work.” CCJ