Two recent headlines caught my attention. The first one is from June 29, 2019: “Fire breaks out in transformer at Providence power plant.” The report indicated that thick, black smoke caused a major traffic jam on Interstates 95 and 195 through the Rhode Island city. Firefighters worked at the scene for more than seven hours. News reports indicate that the transformer contained 5,000 gallons of mineral oil. The incident, which didn’t result in an outage, only involved the transformer and did not affect buildings or other equipment. Workers on-site were able to shift the load to other equipment.
The next incident took place two weeks later in New York. A transformer in an underground utility vault exploded, which led to a widespread outage that affected the west side of Manhattan, including Times Square. Several Broadway shows canceled their evening performances. Reports indicated that several thousand customers were affected. Several subway lines also were affected. None of the reports indicated what the oil capacity was.
I am not making any judgments about what happened, but both incidents prove that sometimes things go wrong. Neither of these incidents involved a transformer that would have been covered by the National Electrical Code. Transformer problems have occurred on both sides of the service point, which is the dividing line between the utility and the customer.
Both installations would have been governed by Section 15 of the National Electrical Safety Code. NFPA 850, Recommended Practice for Fire Protection for Electric Generating Plants and High Voltage Direct Current Converter Stations, includes fire-protection guidelines, which may have applied to the installation at the generating plant.
The NEC’s requirements for transformers are found in Article 450. They include electrical-protection requirements and some other installation requirements for separation, fire protection and construction, all of which will depend on a number of considerations.
The overcurrent protection requirements are found in two tables in Section 450.3. It is important to note the requirements for the transformers over 1,000 volt (V) comes first in 450.3(A), followed by the requirements for transformers of 1,000V. (Usually, the lower-voltage equipment is dealt with first in the NEC.) The overcurrent-protection requirements apply to dry-types and liquid-insulated transformers. Some literature recommends more elaborate transformer protection schemes involving protective relays to provide a higher level of protection.
Decisions on higher levels of protection are typically made based on such factors as how important the transformer is, the impact on industrial processes, how long it would take to obtain a replacement, and how likely a problem is.
The installation requirements for transformers, either dry-type or liquid-insulated, differ depending on whether the unit is installed indoors or outdoors. Dry-type transformers can have some simpler installation requirements. Outdoors, the requirements of 450.22 are fairly easy to meet. Indoors, if they are 112½ kilovolt-amperes (kVA) or less, they require adequate spacing to combustible material (at least 12 inches) or they must be completely enclosed. If completely enclosed, ventilation openings are permitted. If they are larger than 112½ kVA, a transformer room of fire-resistant construction (minimum of one-hour fire rating) may be required. There are some exceptions for transformers of Class 155 and higher insulation systems. If the transformer is over 35 kV, the transformer must be installed in a vault complying with Part III of Article 450.
Liquid-insulated transformers usually have higher ratings because the liquid insulation, commonly mineral oil, helps to dissipate heat. On larger units, fan cooling may also be provided to increase the rating. However, liquid insulation can have its challenges.
Mineral oil is combustible. In normal operation, it will be well below its flash point. However, the oil can burn and fault conditions can result in dissolved gas in the oil. Installing an oil-insulated transformer outdoors is more complicated than a dry-type because buildings, fire escapes and door and window openings must be safeguarded against fires originating in the transformer. Additional safeguards are listed in 450.27. If installed indoors, Section 450.26 requires a vault, constructed in accordance with Part III of Article 450. There are six very limited exceptions to this rule.
The potential hazards of oil-insulated transformers have long been recognized. From 1929 through 1979, the solution was Askarel insulation. Askarel is a polychlorinated biphenyl (PCB) with excellent insulation and fire characteristics, generally considered to be a nonflammable fluid. It was marketed under a variety of brand names by different vendors including Pyranol, Inerteen, Saf-T-Kuhl and No-Flamol, among others. The Toxic Substances Control Act (TSCA) of 1976 banned the production of Askarel with an effective date in 1979. TSCA identified PCBs as a human carcinogen and an environmental pollutant that did not break down easily in the environment. Its continued usage and disposal were severely restricted.
The EPA set a lower limit of concentration of 500 ppm to be considered a PCB transformer. Typical Askarel had a much higher concentration. The problem was that many years ago, some non-Askarel transformers that were filled with mineral oil were cross contaminated when the mineral oil-filled transformers were serviced and the oil was stored in a tank that had previously contained Askarel. Maintenance procedures improved over time to reduce the likelihood of cross contamination.
Fire incidents can result in direct property damage as well as a major public relations problem. One notable incident involving a PCB transformer was a fire in a utility vault outside of a New York State Office Building in Binghamton. One product of combustion was dioxin. The vault was near a ventilation opening that allowed dioxin-laden smoke to enter and spread through the building.
After the initial cleanup effort, dioxin was noted to be present throughout. The cleanup efforts continued for 13 years and numerous tests were conducted over time that continued to show unacceptable levels of dioxin pollution. The effort cost $53 million, more than the original cost of the building. This incident involved a utility transformer but could just as easily have involved a premises-owned transformer.
Less flammable fluids
Recognizing that the age of Askarel was coming to an end, the electrical industry worked to develop a replacement with similar electrical and fire resistance characteristics. High fire-point fluids—also referred to as nonpropagating liquids—were introduced in the 1978 NEC. These fluids have an ignition temperature of at least 300°C. It the 1981 Code, these fluids were called less-flammable fluids. These fluids were required to be listed, which also meant that the installation requirement of the listing would kick in. These requirements would include factors, such as overcurrent protection, tank strength, liquid spill containment and distance to combustibles.
A key to minimizing problems in an electrical installation is to establish an electrical preventive maintenance program (EPM). A key document is NFPA 70B: Recommended Practice for Electrical Equipment Maintenance. NFPA 70B defines EPM as:
“A managed program of inspecting, testing, analyzing and servicing electrical systems and equipment with the purpose of maintaining safe operations and production by reducing or eliminating system interruptions and equipment breakdowns.”
Electrical equipment will deteriorate over time. A maintenance program can keep equipment in service by repairing or replacing parts that are most likely to fail.
As noted in NFPA 70B, “Electrical equipment deterioration is normal, and equipment failure is inevitable. However, equipment failure can be delayed through appropriate EPM. As soon as new equipment is installed, a process of normal deterioration begins. Unchecked, the deterioration process can cause malfunction or an electrical failure. Deterioration can be accelerated by factors such as a hostile environment, overload, or severe duty cycle. An effective EPM program identifies and recognizes these factors and provides measures for coping with them.”
In addition to normal deterioration, other potential causes of equipment degradation can be detected and corrected through EPM. Among these are load changes or additions, circuit alterations, improperly set or improperly selected protective devices and changing voltage conditions. EPM also lets the maintenance personnel know when equipment is approaching the failure point so that it can be taken out of service before catastrophic failure occurs.
Tests that should be part of any EPM
Acceptance tests provide baseline information that the equipment meets the purchasing spec. Tests are usually performed at the factory, but on-site tests ensure that the equipment was not damaged during shipping.
Routine maintenance tests are performed at regular intervals over the service life of the equipment. These tests normally are performed concurrently with preventive maintenance on the equipment.
What’s appropriate for transformers?
Like all major electrical equipment, maintenance of transformers is critical. Transformers are often viewed as a large piece of electrical equipment with no moving parts. NFPA 70B lists a number of test methods for transformers. Electrical tests include power factor, insulation resistance, turns ratio, excitation current, core insulation, winding resistance and dielectric breakdown.
Transformer oil can have quite a story to tell. Some of the more critical tests involve oil analysis. Among these are dielectric breakdown, acidity, color, interfacial tension and dissolved gas in oil analysis. If the transformer is experiencing arcing or overheating, combustible gases—acetylene, ethane, ethylene—may tell the story, which will lead to learning the cause.
I am not making judgments about any of the three incidents cited. Following the Code-mandated installation rules is critical. However, maintaining equipment and preventing failures is key to keeping a business running and staying out of the headlines.
About The Author
EARLEY, P.E., is an electrical engineer. Retired from the National Fire Protection Association, he was secretary of the National Electrical Code Committee for 30 years and is president of Alumni Code Consulting Group.