Fifteen years ago a common belief was that dissolved gas analysis, DGA, was not applicable to oil circuit breakers, OCB’s or load tap changers, LTC’s. This assumption was based on the idea that the gases produced during normal operation of an OCB or LTC would be more significant than gases produced by a fault process such as contact overheating.

The new deregulated electric utility environment is driving Transmission and Distribution companies to find ways to improve their competitive position. Maximizing return on investment (ROI) is often a key financial driver when formulating a profitable T D operation and maintenance strategy. This strategy requires that utility operations and maintenance find ways to leverage the most out of existing transformers.

Investment in the development of electric generation, transmission and distribution was booming throughout the mid-1960s to early 1980s period. The installation of power transformers followed this trend. This peak development period was followed by a sharp decline in capital spending, which on average has continued in decline for the past 20 years. At the same time demand for electrical energy, or load growth, has slowly but steadily increased. This has resulted in the typical power transformer on the U.S. domestic grid being highly loaded with an average age of 35 years. Electrical equipment of this age is generally considered to be approaching the end of its useful life. Electric utility companies, driven by their customers’ needs, have a low tolerance for failures and hence risk-cost has become a very real cost of doing business.

Power transformer windings are designed to withstand high axial forces which result from short circuit events. To withstand these forces, the winding assembly is clamped to a predetermined pre-load pressure during manufacture. This paper discusses the important relationship between changes in moisture level versus clamping pressure for new transformers. It further relates laboratory investigations of changes in clamping pre-load versus changes in operating temperature, moisture and the insulation aging effect.

Fluids, either gases or liquids, that are used as dielectrics in electrical equipment must possess certain basic properties. The selected fluid must provide thermal conductivity in order to dissipate heat generated within the equipment. It must have excellent insulating properties and must be able to quench arcs. Additional desirable physical and chemical properties that are important include low viscosity, chemical stability and low toxicity. Sulfur hexafluoride, SF6, is a unique gas that meets all of the stated requirements.

Mineral oil based dielectric fluids have been used more extensively than other dielectric fluids in electrical equipment because of their wide availability, low cost and excellent physical and electrical properties. Their only shortcoming is their relatively low flash and fire points. Polychlorinated bi-phenyls, PCB’s, known generically as Askarels, were developed as alternative dielectric fluids. PCB’s have excellent dielectric properties and they are far less flammable than mineral oils. Government agencies, at one time, mandated the use of PCB’s whenever there was a safety concern related to fluid flammability. Unfortunately PCB’s turned out to be an environmentally hazardous material. Federal regulations subsequently mandated elimination of PCB’s. This regulation lead to a search for replacement dielectric fluids that are not as flammable as mineral oil. Two major types of fluids were developed.

New rules in the deregulated electric utility business require Transmission and Distribution companies to find ways to improve their competitive position. Maximizing return on investment (ROI) is often a key financial driver when formulating a profitable operating T D strategy. Increased equipment utilization, deferred capital expenditure and reduced maintenance expense are all a part of the guidelines for today’s T D asset strategists and managers. Although tighter operating budgets and reduced spending are nothing new to utility engineers and planners, today’s increased need to leverage more out of existing equipment must be achieved with an aged asset base.

Fluids, liquids or gases, that are used in electrical equipment serve three essential purposes. These fluids must provide adequate insulation, efficiently transfer heat from the source to the atmosphere and quench arcs that may develop in the equipment. To meet these requirements the selected fluid must consist of non-polar molecules that are chemically stable. Viscosity, specific heat and thermal conductivity are properties that must also be considered when evaluating the ability of the fluid to conduct heat.

During the B.D. era, before deregulation, run to failure, time based and operation count based maintenance methods were widely employed. These methods were effective in maintaining the power delivery system but were labor intensive and not cost effective. Time based and operation count based maintenance methods could not identify units that developed problems between scheduled inspections. Units were often inspected on a time basis and no problems were identified.

During the past forty years, dissolved gas analysis DGA, has become universally accepted as the premier diagnostic tool for location of incipient faults in transformers. Extension of DGA to other oil filled equipment were proposed and debated during the past decade. The consensus opinion was that gases developed during the switching operation would “cover up” any gases due to equipment problems. Table 1 shows the gas producing processes that occur in oil filled electrical apparatus. The gases that are produced by these various processes are listed in Table II. Recognition of these differences between normal and abnormal gassing conditions paved the way to diagnostic evaluation of load tap changers LTC’s, and oil filled circuit breakers, OCB’s.