Imagine that instead of changing a car's oil every 3000 miles, drops of the oil could be tested to determine when it needed to be changed. This might never be done for cars because the testing is more expensive than just changing the oil. But when it comes to electrical high-voltage substations, it is too expensive not to engage in the predictive and diagnostic maintenance (PdM) that PECO, an electric and natural gas utility subsidiary of Exelon Corp., is using to proactively manage transmission and substation maintenance.

PECO's approach to maintenance drives greater productivity, avoids equipment failures and outages, provides costs savings and supports the utility's environmental goals of preventing oil spills and greenhouse-gas leaks. Work plans directly link the work of maintenance technicians, engineers and planners to the utility's strategies. This approach adds up to operational excellence, which is the ultimate objective.

The Right Maintenance Programs

The alternative to PdM is time-based maintenance, which is much more labor intensive, ineffective at identifying problems that develop between scheduled inspections and not as cost effective.

For utilities, PdM has moved far beyond simply looking at the dipstick, to continue the car analogy. Predictive maintenance technology has drastically changed over the last few years. Substation technicians are using oil sampling, infrared thermography, visual inspections, acoustical monitoring, SF6 gas detection cameras and other practices to proactively manage maintenance to ensure system reliability. Comprehensive data collection and analyses is critical. Technicians collect and evaluate more than 50,000 data points every month.

With predictive maintenance, as it relates to general equipment in the substation and the need to maintain it, data is collected on equipment. The data is then turned into information to identify issues. The issues are taken care of before any components break down. As a result, equipment is maintained before it fails. This approach reduces maintenance costs significantly.

Fixing larger problems requires taking a substation off-line, taking a piece of equipment out of service and rerouting power, or placing operations into contingencies. A transformer may cost several million dollars and take months for a utility to replace. A lot of money and resources are saved if a failure is prevented. Downtime for a power plant due to an outage at its substation can be incredibly costly, too.

In addition to eliminating equipment breakdowns, quickly repairing oil leaks and reducing greenhouse-gas leaks at substations are high priorities. The goal is zero preventable spills while handling the insulating oil, and there are aggressive targets for emission reductions from breaker SF6 releases. Inspectors identify and prioritize leaks, and they are proactively fixed.

Currently, PECO has approximately 15 technicians who perform substation inspections, off-line diagnostics and dissolved gas analysis (DGA) oil sampling on transformers and circuit breakers. They also use infrared thermography to check for heat and cold in the wrong places. Systems often do not have to be taken out of service to be inspected and maintained, saving time and money and — most of all — increasing equipment availability.

Avoiding Failure Outages Saves Millions

As Pennsylvania's largest utility, PECO's system spans southeastern Pennsylvania and serves 1.6 million customers with its 29,000 miles (46,671 km) of distribution and transmission lines. Its 452 substations range from the large power substations connected to generation to small-unit substations that feed residential neighborhoods.

PECO's transmission and substation group maintains approximately 1200 power transformers on the system. They range in age from new to more than 80 years old. The Schuylkill Station in south Philadelphia was constructed in 1926 while General Electric founder and renowned inventor Thomas Edison was still working. But rather than showing an aging fleet, the Schuylkill operation demonstrates the effectiveness of PECO's maintenance program.

Oil analysis is a long-term program that can be more predictive than many other methods. PECO's program is roughly 10 years old. Engineers and technicians keep components and substations humming along while collecting more than 16,000 data points a month from oil sampling alone and roughly 36,000 data points from the Cascade database of equipment records. Cascade is a utility maintenance management system from Digital Inspections, a KEMA company. All told, about 5500 fluid qualities and approximately 4000 DGA samples are taken each year on 1800 pieces of PECO equipment. Oil sampling is done at more than 300 locations, and the infrared camera is used on the largest 138 facilities. The thermography checks heating and cooling on transformers.

Replacing oil in a car is cheap, so it does not make sense to test it. But transformers are expensive pieces of equipment, so PECO relies on the data to tell when it is time to fix the equipment. This PdM approach has proven successful. Over the past decade, PECO's substation transformer failure rate has dropped 50%; its failure rate consistently ranks among the lowest in the industry. Annual savings are estimated at more than US$30 million.

One of the secrets to the success of this plan is to actually insert inspections into technicians' weekly work schedules. The inspections are listed right along with other duties and work tasks as well as training and days off. The technicians take a sample and deliver it to the chemical lab. The sample results are entered into Cascade and analyzed. An alert is sent to the engineers, who write follow-up work orders to handle the situation.

Although this sounds like pretty mundane stuff, in reality, the analysis is actually anything but mundane. Studying the gases dissolved in oil is similar to analyzing a blood sample taken from a medical patient. A syringe of oil is withdrawn and analyzed using a gas chromatograph. Just like a blood test reveals good and bad cholesterol and triglyceride levels to show the health of a patient, the existence of certain gases, including methane, ethane, ethylene and acetylene, may indicate problems such as a partial discharge, overheating or arcing. Just like the optimum blood pressure and cholesterol levels are different for people of different ages and gender, various gas levels can be calculated for various equipment. Other gases such as carbon dioxide may be a sign of overheated insulation. Results are tracked and trends noted in order to identify problems, perform maintenance and maintain system health.

Finding Hot Spots

Meanwhile, the PdM team members also use infrared cameras to reveal excessive heating of various components that could indicate emerging problems. Infrared monitoring and analysis can be extremely effective for spotting both mechanical and electrical failures. Using a thermography camera, equipment may be safely and fully scanned from a distance. Older technology used sniffers or probes that only allowed a portion of the equipment to be checked, which meant leaks went unnoticed.

During a test last year at transformer No. 17 at the Bryn Mawr substation in suburban Philadelphia, thermography revealed low oil levels that, although not an immediate problem, made technicians aware they needed to address the low levels within the next month to prevent any problems. The regular inspections find failing lightning arresters, high-side bushings and cable failures, too. Some examples of catches PECO has found as a result of inspections are as follows:

  • A 169°C (336°F) hot spot that indicated a substation disconnect phase hinge end was overheating

  • A substation oil circuit breaker with a B-phase tank overheating

  • A 125°C (257°F) transformer hot spot

  • A 185°C (365°F) hot spot on a small-unit substation transformer

  • A 125°C hot spot on a 4-kV cutout box on a pole.

All these incipient failures were caught before costly equipment failures. Using thermography also identified low oil levels in a transformer whose gauge read normal.

Part of the program's overall effectiveness lies in having the same person conducting the entire battery of tests. Substations are inspected every five weeks and samples are taken on a timely basis. The same technician takes oil samples and scans the yard with the infrared camera, looking for hot spots among the connections. If one is hotter than another, it is flagged and reported to engineering to make sure the issue is handled.

A high temperature may indicate a connection is not adequate to carry current. Eventually, it will heat up and melt metal, causing a failure. Breaker connections also must be examined. If any of the phases are out of sync or hotter than another, this indicates an issue. Thermography may even indicate whether a transformer radiator is getting adequate oil flow.

After using a vendor periodically, PECO purchased the thermography camera in 2009 to detect SF6 gas leaks, making even more progress in reducing emissions. It is a red flag when gas must be added to a SF6 breaker. When that happens twice, a course of action needs to be put in place. A technician is sent out with the gas-detection camera to identity the problem and schedule the fix on a priority basis.

Owning the camera allows PECO to proactively manage these greenhouse-gas emissions. The camera offers substantial cost savings and improved environmental protection because it finds leaks from equipment more successfully than previous methods. PECO is well ahead of the reduction targets for greenhouse-gas emissions. Along with its sister utility, Commonwealth Edison, PECO is participating in an industry-wide initiative.

Best in Class

PECO staff are proud the predictive maintenance program has been recognized as best in class. Staff have been asked to demonstrate the processes to other utilities, and the approach has been shared at industry conferences. Just as the SF6 camera has improved testing, there is a constant search for the next new way to test equipment better, new technologies and process improvements that will improve overall maintenance effectiveness. The searching includes participation in industry committees and even looking at acceptable gas levels from oil test results.

Finally, there is another secret to this success: The chemical lab works directly for PECO and has the same manager as the inspector and analyst, so they all fall under the same umbrella. Combined with infrared scanning and other diagnostic testing, this gives a true picture of substation health. The entire process works quite well. Overall, this results in a consistently low rate of bus outages and transformer failures — not to mention more than $30 million in annual cost savings.


Drew Reindel (andrew.reindel@peco-energy.com) has worked for PECO/Exelon for 24 years. The majority of his time has been spent in substation project engineering, operations and maintenance. He has been involved in the development of the maintenance program and the CASCADE system at Exelon since 2001. Reindel is currently manager of transmission and substations' equipment and maintenance engineering department.

Harry Steger (harry.steger@peco-energy.com) started work in PECO Energy's construction division in 1967. During the intervening 27 years, he progressed in responsibility to become electrical construction supervisor. In 1995, he became a maintenance supervisor, then in 2007, manager of Substation & Services, Transmission and Substations.

Companies mentioned in this article:

Commonwealth Edison www.comed.com

Digital Inspections digitalinspections.com

Exelon www.exeloncorp.com

KEMA www.kema.com

PECO www.peco.com