The presence of corrosive sulfur in mineral oil has been a concern since its use as an insulating medium for transformers. Test methods to detect potentially corrosive sulfur have been developed and included in oil product specifications since the early 1900s. Recent failures of large power transformers and reactors which have been attributed to the presence of corrosive sulfur in the insulating oil has lead to a revision of these test methods and the addition of other test methods. This paper will review test methodology from a historical perspective and present the current developments in test methods both in the US and internationally.

Authors: Thomas A. Prevost, Weidmann Diagnostic Solutions — Dec 19, 2007

Due to the economical value to producers and users, coal-fired electricity represents the prime choice of electrical energy today. The aging of these plants have heightened awareness of the owners to properly evaluate, maintain and improve the reliability and performance of the infrastructure of these large coal-fired facilities. Many of these Transformer Rectifiers have provided 20 to 30 years of reliable, hassle-free performance. During the past 5 years, though, this performance has begun to wane. This paper will address the Transformer Rectifiers, and will cover the following: transformer rectifier basics; configuration; inspection and maintenance (actual case studies); insulating fluid interpretation; insulating fluid standards; testing.

Authors: Marty Watson, CE Power Solutions — Dec 13, 2007

This presentation reviews one utility’s practices regarding the testing of new transformers and transformers in service for the presence of corrosive sulfur.

Authors: Donald W. Platts, PPL Electric Utilities — Dec 13, 2007

This paper will describe the process; including triggering mechanisms, troubleshooting tasks, analyzing of results, and historical reviews, applied when one of the most critical transformers in our system was replaced with our operational spare under controlled conditions in order to prevent an unexpected failure of the unit. The paper demonstrates how several contributing factors; including increasing operating voltages and numerous thru-faults, resulted in the decision to replace the suspect unit. The findings of the internal inspection confirming the decision to remove the unit from service will also be discussed.

Authors: John Stead, AltaLink Management Ltd. — Dec 13, 2007

Since the adoption of Condition-Based Maintenance throughout the T&D business, a variety of tests and diagnostic methods are now in use to determine the condition of expensive assets such as power transformers. Once “condition” is assessed, a rigorous method of scoring or metrics must be selected. Ranking such as Good, Satisfactory and Poor can work in the broadest sense but numerical methods are better used for additional analysis and calculation of such consideration as residual life or risk of failure. This paper discusses the logical extension of applying condition assessment metrics to such things as remaining life and likelihood of failure for the purpose of examining the owner’s risk or risk-cost resulting from impact of failure. Risk elements such as total replacement cost, consequences such as loss of use and the cost of collateral damage such as environmental and safety impacts are discussed. Risk mitigation and ways of avoiding some failure modes are addressed, along with typical values used in dealing with subjects such as risk calculation methods for supporting pro-active transformer replacement strategies are provided in this topical paper.

Authors: David Woodcock, Weidmann Diagnostic Solutions — Dec 6, 2007

A new technology is presented which makes it possible to dry high voltage transformers in the field with the advanced vapour phase drying technology. The transformer is dried in its own tank. Residual moisture levels can be reached similar to those in new transformers. The cost intensive transport of the transformer to a repair workshop is no longer applicable.

Authors: Dr.-Ing. Stefan Zabeschek, Dipl.Ing. Helmut Strzala, Hedrich Vacuum Systems, Germany — Dec 6, 2007

Most of the current test methods for the evaluation of insulation systems for liquid-filled transformers are based on test methods designed around cellulosic papers and boards in conjunction with mineral oil. With the introduction of many new materials, both solid and liquid, a new test procedure using a dual-temperature model has been developed to evaluate a variety of combinations of these materials. This paper will present an update of the work performed using the new test procedure to evaluate the classic insulation system of mineral oil and non-upgraded kraft paper, along with a discussion of aging experiments using a variety of solid and liquid combinations.

Authors: Roger Wicks, Brian Glenn, Rick Marek – DuPont; Tom Prevost – Weidmann Diagnostic Solutions — Dec 6, 2007

Recently, the old issue of corrosive sulfur gained renewed interest as several organizations reported failures worldwide that claimed to be caused by it. This presentation will show there are more factors to consider and offers suggestions as to what users and manufacturers can/should do about it.

Authors: H. Jin Sim, Waukesha Electric Systems — Dec 13, 2007

Dissolved gas data from thousands of normally operating and faulted mineral oil transformers, collected and analyzed over the course of decades, form the empirical basis of a means to help assess the condition of a particular transformer. The IEEE, IEC, and U.S. Bureau of Reclamation publish guides to aid in interpreting dissolved gas data for fault diagnosis. Because of their similar gas generation and absorption properties, dissolved gases in natural ester (vegetable oil) can be interpreted in much the same way as for gases in mineral oil. Case histories illustrating the many similarities and few exceptions are discussed.

Authors: Peter Stenborg and John Luksich, Cooper Power Systems — Dec 6, 2007

Recent international findings are indicating that presence of potentially corrosive sulphur compounds in the mineral insulating oil, in special circumstances, may lead to copper deposition in the transformer insulation and consequently transformer failure. On the other hand sulphur compounds also greatly contribute to oxidation stability of the oil. In any case to avoid copper dissolution and subsequent deposition, the use of a metal passivator is recommended. This paper reports investigations on the effectiveness and stability of a passivator in mineral insulating oil.

Authors: Prof. Bruce Pahlavanpour and Kjell Sundkvist, Nynas Naphthenics Ltd., UK — Dec 5, 2007

As the age of the transformer fleet continues to increase it is becoming more important to accurately predict the remaining life of a power transformer. The condition of the solid insulation, particularly at the hot spot, is considered a primary factor in determining the remaining life of a transformer. It is not possible to obtain insulation samples from the hot spot of a transformer in service. If however, the utility has a similar transformer that which will be removed from service a detailed post-mortem investigation of the insulation age can be performed. A post-mortem investigation includes a detailed sample procedure in which paper and pressboard samples are removed from strategic locations within and around transformer windings that are subsequently tested for Degree of Polymerization (DP). This investigation will yield an aging map of the insulation structure. This information, together with knowledge of the loading and operation history of similar transformers on the system is a valuable tool for the condition assessment of transformers in service.

Authors: Thomas A. Prevost, Weidmann Diagnostic Solutions; Hans Peter Gasser, Christoph Krause, Weidmann Electrical Technology AG — Dec 5, 2007

The presentation summarizes the results of an analytical study conducted by Siemens Power Transmission & Distribution, Inc., Power Technologies International (Siemens PTI) to determine the relative contribution of individual power transformers to the overall reliability of the utility network. This work is part of the Network Planning and Improvement Asset Risk Management Analysis currently being performed for a utility in Texas. Network reliability, in this case, is measured in terms of the ability of the power system to maintain continuity of supply to loads. Results from this reliability analysis are combined with the results of the transformers actual technical condition assessment to provide an overall picture of the transformers’ vulnerability to failures and the significance of their failures on the overall performance of the power system. The network reliability calculations are conducted in four steps. The result of the study showed a significant switch of importance of individual transformers, on comparing the two distinct phases of the ranking process. It also provided the utility with actionable information particularly regarding the most critical units.

Authors: Luiz Cheim, Siemens PT&D — Dec 5, 2007

Initially industry reaction to the concept of applying DGA as a diagnostic tool for load tap changers, LTCs, was not positively received. Successful application of DGA has overcome any skeptical evaluation of the method. Progress has been made in the last few years to the point that most utilities are currently using or seriously considering this tool. DGA for power transformers developed in a similar fashion as to LTC-DGA. Laboratory procedures are identical for power transformers and LTCs. Data interpretation is, however, dramatically different. Improvements in data interpretation are an ongoing process. Utilities and IEEE are all making progress on the DGA data interpretation. This presentation will discuss the advantages of DGA as a diagnostic tool for LTCs and current interpretation concepts.

Authors: Fredi Jakob, Ph.D., Karl Jakob, P.E., Weidmann Diagnostic Solutions — Dec 5, 2007

Utilities rely on the equations in the IEEE Loading Guide, C57.91, for several reasons: to calculate loading capabilities for planning studies, and contingency operation; to calculate the expected temperatures in a transformer when analyzing an unusual loading event; many rely on monitoring equipment installed on the transformer. In most cases the temperature algorithm used by the monitor manufacturer follows these same equations. Equations in the Loading Guide and LTC Winding Connections will be discussed, with examples that demonstrate that it is crucial to understand both the construction of the unit and the specific details of the temperatures and the location of the hot spot. The paper demonstrates how users would typically use the data from a test report, and the differences that would be produced by that process compared to the design data provided. The paper also demonstrates how the CT currents used by standard temperature monitoring devices will often produce different temperatures from the data provided in the tables.

Authors: Donald W. Platts, PPL Electric Utilities — Dec 5, 2007

As of this writing, the technology advances for the condition assessment of large oil filled transformers has reached a point where it is unacceptable to experience an unexpected failure. This presentation will cover the full process of level two condition assessment (L2CA) and will include: Partial Discharge Detection, Infrared Thermography, Vibration Analysis, Dissolved Gas Analysis, and how each of these technologies relates to one another.

Authors: Jon Giesecke, JLG Associates, LLC — Dec 5, 2007

Cooling control of power transformers is traditionally provided by a winding temperature indicator (WTI) that is based on a measurement of the top-oil temperature and a simulation of the winding hottest spot temperature. This method has some drawbacks and utilities are now considering the application of fiber optic temperature sensors for this critical function. Assessing the winding temperature from the measured top oil temperature can lead to significant errors depending on the cooling mode and the shape of load profile. This situation is reflected in the current revision of the IEEE Loading Guide. The industry consensus leans toward a method based on the bottom oil temperature and a proper representation of the temperature evolution in the cooling duct. The various hot spot temperature calculation methods are reviewed for the actual case of a 240MVA transformer where the fiber optic sensors have been selected for the control of the cooling banks. It is shown that in case of rapid load change, the method used by classic WTI can indicates a lower temperature by more than 10°C even if they are properly adjusted for the steady state conditions. It appears that with the dependability of modern fiber optic sensors the long-term application of transformer cooling can be better achieved with this more accurate monitoring device.

Authors: Jean-Noel Bérubé, Neoptix, Inc.; Jacques Aubin, Consultant: Bruce L. Broweleit, GCPUD — Dec 5, 2007