NETA Handbook Series I%2c Transformers Vol 2-PDF

Transformer Handbook Volume 2

Published by InterNational Electrical Testing Association

Published by InterNational Electrical Testing Association

Transformer Handbook Volume 2

Published by InterNational Electrical Testing Association Portage, Michigan

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Transformer Handbook Volume 2

Table of Contents Power Transformer Design, Construction and Field Assembly .....................................1 Kerwin J. Boser, A.Sc.T.

Power Factor Testing Dry-Type Transformers ..............................................................5 Jim White

Cooling Classes of Transformers .............................................................................10 Ron Widup

Basic Power Factor Testing ......................................................................................12 Keith Hill

Transformer Frequency Response Analysis: An Introduction .....................................21

Tony McGrail

Transformers: Responding to the Baby Boom ...........................................................25 John van Kooy

Transformer Turn Ratio Testing ..............................................................................27 Jeff Jowett

Large Power Transformer Condition Assessment and Life Extension ..........................30 Richard K. Ladroga, P.E.

The Role of Test Voltage and Current Levels in Transformer Condition Assessment — Is There a Better Way? ...........................................................................................34 Alex Rojas

Transformer Testing — Are You Missing the Test Point? .............................................41 Rick Youngblood

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Transformer Handbook Volume 2

Table of Contents (continued) Partial Discharge Testing of Transformers ...............................................................48 Don A. Genutis

Transformer Monitoring, Communications, Control, and Diagnostics ........................51 Claude Kane and Alexander Golubev

NOTICE AND DISCLAIMER NETA Technical Papers and Articles are published by the InterNational Electrical Testing Association. Opinions, views, and conclusions expressed in articles herein are those of the authors and not necessarily those of NETA. Publication herein does not constitute or imply any endorsement of any opinion, product, or service by NETA, its directors, officers, members, employees, or agents (hereinafter “NETA”). All technical data in this publication reflects the experience of individuals using specific tools, products equipment, and components under specific conditions and circumstances which may or may not be fully reported and over which NETA has neither exercised nor reserved control. Such data has not been independently tested or otherwise verified by NETA. NETA makes no endorsement, representation, or warranty as to any opinion, product, or service referenced in this publication. NETA expressly disclaims any and all liability to any consumer, purchaser, or any other person using any product or service referenced herein for any injuries or damages of any kind whatsoever, including, but not limited to, any consequential, special incidental, direct, or indirect damages. NETA further disclaims any and all warranties, express or implied including, but not limited to, any implied warranty or merchantability or any implied warranty of fitness for a particular purpose. Please Note: All biographies of authors and presenters contained herein are reflective of the professional standing of these individuals at the time the articles were originally published. Titles, companies, and other factors may have changed since the original publication date. Copyright © 2009 by InterNational Electrical Testing Association, all rights reserved. No part of this publication may be reproduced in any form or by any means, electronic or mechanical, without permission in writing from the publisher.

Transformer Handbook — Volume 2

Power Transformer Design, Construction and Field Assembly T

o erTes 2 nnual Te n al onferen e Ker in oser, A c agna Electric Cor oration

Power transformers are the heart of every electrical transmission and distribution system. The concept was first conceived and developed in the late 1800’s by Faraday, Maxwell, and Tesla, and put into common practice by the likes of Edison and Westinghouse. Since then, the basic concept of the transformer has remained the same for over 100 years, however, design and construction techniques have continually improved to increase both the overall efficiency and cost effectiveness of manufactured units. This paper will examine the basics of transformer design, construction and field installation focusing on details to ensure longevity of an installed unit. In general, power transformers refer to liquid filled units and are loosely divided into 3 size categories, small power — under 10 MVA, medium power — 10 to 50 MVA, and large power above 50 MVA. These are not official categories as recognized by ANSI/CSA/IEEE, but are more often ranges referred to by consultants and manufacturers when specifying or building transformers. For example, a transformer manufacturer that builds units in the size range of 10 to 300 MVA will often have one plant facility that builds up to 50 MVA and then another plant that only builds units above 50 MVA and they will refer to these plants as their medium and large power assembly manufacturing facilities respectively.

Insulation Preservation Systems A transformers life expectancy is based on a number of factors, the most important of which is the quality of it’s insulation system over time. The oil used in power transformers is particularly susceptible to moisture and it’s insulating value is seriously reduced when even small amounts of water are present. In addition to this, the oil’s insulating quality and performance as a cooling medium, can be reduced by oxidization as well. It is therefore, extremely important that the design of the transformer be such that it impedes the

contact of the insulation system to the outside atmosphere, which contains both moisture and oxygen. Since the oil in the transformer will expand and contract with temperature and load, a number of systems have been developed to help preserve the overall insulation quality of the transformer. These designs include open style, sealed tank, conservator style, and automatic gas pressure. Open style design refers to a tank design that is free breathing and vented to the atmosphere. In this style, there is an air or gas space in the main tank above the oil level. The insulating oil, inside the tank, expands and contracts with load and temperature, thus ultimately breathing in and venting to the outside atmosphere. This is an older style design normally used only in smaller size ranges. The benefits of this type was an initial lower cost base, but at the same time this is the least effective method of protecting the transformers insulating system. In the sealed tank design, the core/coils and oil are completely enclosed in the main tank with no ventilation to the atmosphere. The gas space above the oil is normally 10 to 15 % of the volume of oil at 25° C and is made up of either dry air or nitrogen. This prevents any outside atmosphere from contact with the oil. This style offers better protection against the ingression of moisture and other contaminants that can have a negative effect on the integrity of the transformers insulation system. Units of this style are often used in small to medium size designs with their top MVA size really being limited by the physical shipping height requirements of the main tank due to the fact that a gas headspace had to be incorporated above the oil. One draw back of this style is if a weld, flange or gasket develops a leak in the gas head space above the oil, this can lead to direct exchange with the outside atmosphere which is not good for the oil. Overall this style offers a cost effective advantage with good insulation protection.

Transformer Handbook — Volume 2 The conservator or expansion type design has the main tank completely filled with oil and a smaller expansion tank positioned above the main tank, with about 5 to 10 % the volume of the main. As the oil expands and contracts with temperature and load, the atmosphere moves in and out through a uni directional moisture removing breather. Only a small surface area of the oil in the expansion tank has exposure to the atmosphere and the expansion tank is designed in such a way so that if moisture should get in, it remains trapped in the expansion tank and cannot be exposed to the paper/wood insulation and clamping system of the core and coils. This is the most cost effective design in higher MVA units and also offers the easiest versatility in shipping because the main tank is totally immersed in oil with no top head space. Newer designs can also incorporate an air bag in the expansion tank which virtually eliminates any oil contact with the outside atmosphere. The gas regulation design is very similar to the sealed tank design with the exception that the air space above the oil is kept at a positive pressure at all times by a gas regulation system. With this style, as long as the gas bottle and regulation system is intact, a positive pressure is automatically maintained on the tank, allowing no atmosphere to oil contact. This system is quite reliable, however, it does come with a higher initial price tag and maintenance cost factor.

Nameplates and Ratings The nameplate on a transformer contains an assortment of information about the unit itself. It is full of acronyms and abbreviations that refer to the style, type, rating, voltage class and construction details of that particular transformer. There are different standards world wide which govern the design criteria for power transformers, the standard(s) that a particular unit is designed to will be labeled on the nameplate. While all these standards have their similarity, they are all unique in their own way and as such, use different acronyms or abbreviations for particular terms. The following table refers to various transformer ratings and cooling methods. This illustrates how the various regulatory bodies use slightly different designations to refer to the different ratings.

COOLING METHODS

C.S.A. A.N.S.I. B.E.S.A. RISE DESIGNATION DESIGNATION DESIGNATION

Oil Immersed, Natural Circulation, Self-Cooled

ONAN

OA

ON

55/65

Oil Immersed, Natural Circulation, Water-Cooled

ONWF

OW

OW

55/65

Oil Immersed, Natural Circulation Forced-Air Cooled

ONAF

OA/FA

OB

55/65

Oil Immersed, Forced Oil, Water Cooled

OFWF

FOW

OFA

55/65

Oil Immersed, Forced Oil, ForcedAir Cooled

OFAF

OA/FA/FOA

ORB

55/65

Oil Immersed Natural Circulation, Forced Air Cooled, Second Stage of Forced Air Cooling

ONAF/ONAF

OA/FA/FA

Table 1 — Transformer Ratings and Cooling Methods

Transformers all have an MVA rating which is defined as the rated output that the transformer can deliver continuously or for a specified time at rated secondary voltage and frequency without exceeding it’s specified temperature rise limitations. This rating is sometimes referred to as the OA or ONAN rating. The rated output of the transformer may be increased with the addition of cooling stages. These cooling stages can be in the form of forced air, forced oil, water cooled, or any combination of these. The following table lists the various types of cooling stages and their associated loading capacities above the base OA or ONAN rating. TYPE OF COOLING

LOADING CAPACITY

ONAN

100%

ONAN/ONAF

100/133%

ONAN/ONAF/ONAF

100/133/167%

ONAN/ONAF/OFAF

100/133/167%

ONWF

125%

OFWF

167%

Table 2 — Transformer Cooling Stages and Loading Capacity

Transformer Handbook — Volume 2 Transformer Construction Transformer design/construction can be divided into three categories, the tank, the core and the windings. The design of each of these components depends on a number of factors and together with the other accessories, they form the basis for the finished product. The tank is made of high quality shot blasted steel with horizontal or vertical re-enforcing stiffeners for added mechanical strength to withstand operating and filling pressures. It is then coated inside and out to prevent the spread of corrosion. The base design may be a skid style or flat style depending on installation requirements. The magnetic core consists of thin silicone steel sheets stacked into piles until the desired cross section is achieved to meet the magnetic circuit design. Once this operation is complete, these steel sheets on the laminations are strapped together, generally with epoxy fiberglass bands. These bands have a high tensile strength and are capable of withstanding hotspot temperatures up to 130° C. The whole core assembly is then clamped, stood up vertically and ready for the windings to be installed. The transformer windings are either copper or aluminum and use insulating materials which perform both mechanical and electrical functions. The insulated wire or strap is wound onto a cylinder core on a special winding machine. The LV winding is normally wound on the inside and the HV on the outside, this is to minimize the insulation required from the live winding to the grounded core. Once the windings are complete, they are tested, dried, sized and placed on the core assembly. An insulating tube and spacers are placed over each core leg before the winding is lowered into place. This provides electrical and mechanical strength as well as ensures the winding is as close to the axial center of the core leg as possible. After all three windings are in place, the top core steel is inserted and the entire core and coil assembly is clamped into place. The unit will then be sent to the oven or autoclave for an initial dryout before installation and fitting in the tank.

Transformer Accessories Other accessories such as bushings, radiators, protective devices, gauges, tap changers, etc. are all installed on the transformer in the factory after it has been through its initial dryout process and fitted into the tank. After these accessories have all been installed, the transformer will have a final vacuum dryout and first oil filling at the factory. Once this first filling is complete, the unit will move to the test bay where factory testing takes place to CSA/ANSI standards. These tests are designed to verify the mechanical strength and electrical integrity of the transformer and guarantee the losses that the manufacture has designed against. Once the unit has passed factory tests, it is dressed down for shipment to a customers site. This involves removing the oil and backfilling the unit with a dry gas (air or nitrogen) to

minimize the possibility of moisture ingression. All accessories that can not be left on for shipping such as bushings, radiators, conservator etc. are removed and packed to be sent to site for the field installation.

Field Assembly and Oil Filling When a power transformer leaves the factory, it is shipped by a combination of either heavy haul trucks, rail and/or seaway vessel to site. There are generally three separate shipments made, the main tank c/w core and coils, the accessories that have been removed and packaged, and the insulating oil. The core and coils are the most critical part of the shipment and are normally monitored continuously from the plant to the final site via one or more three axis accelerometers (impact recorders). These devices are designed to measure sudden movement or “jarring” in any direction that the transformer many experience during its shipment. This sudden movement, if excessive, could have a negative affect on the bracing of the core and coils. Once the unit gets to site, a receiving inspection is done on the unit which generally consists of a visual inspection, examination of the impact records and a test of the core ground insulation and shipping gas. These inspections and tests are completed before the unit is cut loose from the shipping deck and give an indication of the received condition of the transformer. If there is any indication of movement or air leaks during shipment, normally an internal inspection is performed on the main tank, core and coils, before the unit is offloaded to get a first hand look at any potential shifting problems during transportation. If all tests are good, the unit is offloaded and the assembly process can begin. Once the transformer is situated on it’s pad, all the accessories that were removed for shipment are reinstalled. This process is carried out in such a way as to minimize the introduction of moisture, atmosphere or foreign contaminants of any form into the main tank. Dry breathing air with a moisture content of less than 0.5 % is fed into the transformer at all times. It is best to try and complete the work when weather conditions are dry since the number one enemy of the insulation system is water, every attempt is made to keep moisture out. Caution is taken to try and never open up more than one accessory cover or entry hole at one time to prevent cross ventilation of the outside air. In some cases, it is necessary to make a confined space entry into the tank to either remove shipping blocks, make bushing connections inside the tank, or to perform a final internal inspection. Extra caution needs to be taken to ensure nothing is moved or bent inside the tank and that nothing is left or dropped in the tank when this work is being carried out. Even the smallest piece of foreign contaminant introduced, such as metal filing, etc., could have drastic effects on the longevity of the transformer.

Transformer Handbook — Volume 2 After the assembly is completed, the unit is closed up and a pressure check is done to ensure that all flanges, welds, valves, etc. are sealed. A dew point test may be done on the unit at this point to give an indication of the relative humidity or general moisture content of the air and insulation system. At this point, the final dryout of the unit begins by lowering the pressure with high capacity vacuum pumps to a level below the partial vapor pressure of water. This in effect, boils off any surface moisture that has been introduced during the assembly and acts to further dry the paper/wood insulation and bracing system in the transformer. Once the prescribed amount of vacuum has been achieved and held, the oil filling begins. The oil is heated and processed through separate vacuum chamber and filter system into the transformer tank, while holding vacuum on the transformer tank at the same time. This is the most critical part of the procedure and must be monitored very closely. Oil processing speed, temperature, and vacuum all needed to be monitored and kept within specific values to ensure that process meets all manufacturing specifications. Loss of vacuum at any time on the main tank during this process, is call for a complete shutdown and restart of the whole field dryout process. The entire procedure is run continuously until the transformer is filled with oil to the desired full level. At this point the transformer is ready to be final field tested and commissioned for startup.

Summary Transformer design and manufacturing techniques have remained similar for many years. Over time, improvements have been made in materials, design programs and testing techniques to allow for lighter and more efficient units to be produced. The number one enemy of the transformers insulation system is water. Proper procedures and handling for field installation has proven to be very critical in reducing moisture content and maximizing the life span of an installed unit. Kerwin Boser is an Electrical Engineering Technologist with 15 years experience in Power Transformer, design, assembly and field/plant testing. Kerwin spent 6 years with Schneider Electric in a Project Management role specializing in Power Transformer field assembly, vacuum filling, and testing. He has spent the past 8 years with Magna Electric Corporation and has worked on Power Transformer projects all over the world. He is currently the VP of Marketing and Corporate Projects for Magna based out of their Saskatoon office.

5

Transformer Handbook — Volume 2

Power Factor Testing Dry-Type Transformers T

o erTes 2 nnual Te n al onferen e i hite her co Industries, Inc

Introduction Many customers are unsure of the value of power factor testing when it is performed on a dry-type transformer. In many cases, an insulation resistance test or Polarization Index (PI) can be effective in determining insulation quality, especially on units that are less than 167kVA (single-phase) or 500kVA (three-phase). The additional costs associated with testing these smaller units are difficult to justify. However, larger dry-type transformers, especially ones that provide critical power, should be given a power factor test to ensure continued serviceability.

Types of Dry-Type Transformers Ventilated Constructed so that ambient air can circulate through the core and windings to cool them.

Non-Ventilated Constructed so that no additional cooling is created by ambient air circulation.

Class of Materials Dry-type transformers can be constructed of Class B (1300C), C (2200C), or H (1800C) materials, which can be a combination of mica, fiberglass, asbestos, wood or other similar materials. Smaller transformers may be epoxy-encapsulated to provide mechanical strength, whereas some larger units may be encapsulated to prevent moisture intrusion into the insulation.

Figure 1 — Ventilated Dry-Type Transformer Courtesy Square-D Company

Power Factor Test Voltages Corona can be a problem when testing dry-type transformers, so it is recommended that a power factor test be conducted at a lower voltage (something below the corona inception point), and then at the normal test voltage. If the low-voltage result is satisfactory, then the test can proceed at the normal test voltage. If the power factor increases with an increase in voltage, corona is indicated. Running the lower-voltage test first will reduce the possibility of corona damage from occurring. Doble Engineering recommends the test voltages in Table 1.



Transformer Handbook — Volume 2

A transformer’s power factor versus voltage characteristics can be helpful in troubleshooting a suspect unit. Increase the voltage in several steps and record the percent power factor on graph paper. A characteristic that is flat indicates no appreciable ionization. Power factor tip up indicates the presence of voids or ionization within insulation. If the tip up occurs below the operating voltage, this could spell trouble in the near future. If a tip down is measured, it could indicate a missing core ground or surface moisture. Increasing the voltage could eliminate the tip down by drying the surface out. Curve 1 shows the possible test results from running such a test. Doble Engineering states that test voltages up to 125% of the operating voltage can usually be applied to conduct this test.

Although temperature can affect the power factors of dry-type transformers, there are too many different types of insulation to assemble a standard temperature correction chart. At this time Doble believes that temperature may not be a significant factor in dry-type transformers. Since the major insulation component is air, the temperature characteristic curve should be fairly flat. At the Fall meeting, there were a number of companies who stated that temperature did affect the power factor, but not in a uniform way from transformer to transformer. This just reinforces the difficulty in developing a standardized temperature correction chart for dry-type transformers. In the case of epoxy-encapsulated transformers, Doble believes that the characteristic should be fairly flat also. As with all tested devices, if the test results are questionable at high temperatures, allow the unit to cool and retest when its temperature is closer to 200C.

Test Results Analysis The best possible evaluation of power factor test results is by comparing them to the base line results of the specific unit. Base line tests are performed when the unit is first installed using the same (or similar) field test equipment under the same conditions that the tests will be performed in the future. Some times there are no base line results available, so the results can be compared to like units tested under similar conditions or with the factory test results, if available. Some manufacturers do not perform a power factor test as a standard test, but will do it if it is requested.

Capacitance Capacitance should be recorded whenever a power factor test is performed. If the capacitance changes, it would indicate deterioration of the insulation or possibly winding movement.

Curve 1 Power Factor vs. Voltage Characteristic Curve Courtesy Doble Engineering

Curve #1 – Flat characteristics Curve #2 – Power factor tip up

Curve #3 – Power factor tip down Curve #4 – Combining curves #2 and #3

Delta and Ungrounded-Wye Windings Transformer Winding Rating Test Voltage (kV) (kV) 10kV Test Set 2.5kV Test Set Above 14.4 2 and 10 2.5 12 to 14.4 2, *, and 10 2.5 5.04 to 8.72 2 and 5 2.5 2.4 to 4.8 2.0 2.0 Below 2.4 1.0 1.0

*Operating Line-to-Ground Voltage

Grounded-Wye Windings

(The Operating Voltage Dictates That The Following Test Voltages Can Be Used)

2.4 and Above Below 2.4

2.0 1.0

Table 1 — Power Factor Test Voltages Courtesy Doble Engineering®

2.0 1.0

Ventilated Dry-Type (Power and Distribution) CHL CL CH

2.0% 4.0% 3.0%

84% of reported units 75% of reported units 85% of reported units

In tabulating these results, Doble excluded “high contributors”. A transformer was considered to be a high contributor if its results caused the average to be increased significantly. All results are for service-aged transformers. Epoxy-Encapsulated Type (Power) CHL CL CH

1.0% 2.0% 3.0%

96% of reported units 90% of reported units not reported

The above encapsulated type transformer recommendations are for power transformers. Doble does not have enough data to allow recommending maximum values for epoxy-encapsulated distribution transformers. They commented that 83% of the reported distribution transformers were from one manufacturer and had CL power factors of nearly 8%.

Transformer Handbook — Volume 2 Winding Temperature Indicators Test results may be affected by RTD’s imbedded in the winding (winding temperature indicators). If the CHL results are higher than anticipated or are negative, the ground lead from the RTD should be disconnected and the unit retested.

CHL CHL

2.0% 5.0%

Measures CHL

CHL

NETA Recommendations NETA standard MTS-01 recommends the following maximum values for dry-type transformers:

LV

HV

CH

Power transformers (over 500kVA three-phase) Distribution transformers (less than 500kVA three-phase)

A transformer is considered to be a power transformer if it is above 500kVA for a three-phase unit or 167kVA for a single-phase unit. If it has windings above 600 volts, it could be considered a power transformer, also. NETA does not specify values for CH or CL due to the variety of materials and the wide range of test values for them.

Connections Standard test connections are used for power factor testing dry-type transformers; CHL, CL, and CH. Figures 2 through 4 illustrate these connections:

LV

HV

Measures C +C HL H

CHL

CH

Figure 2 — Grounded Specimen Test

Measures C

H

LV

HV CHL

CH

Figure 3 — Guarded Specimen Test

Figure 4 — Ungrounded Specimen Test

Shermco’s Experience Shermco has the opportunity to test and evaluate dozens of these transformers each month. In polling the field service technicians, I have summarized our experience concerning dry-type transformers. We encounter three primary types of transformers: NOMEX Mica Epoxy cast coil The majority of the units tested are the NOMEX insulated type. The Mica insulated ventilated transformers are approximately 6% of the total. With the NOMEX insulated transformers, we typically see less than 5% power factor, with most units testing between 2 to 3%. Mica insulated transformers can have considerably higher power factors, especially if they have been in a high humidity area and de-energized. We have seen initial power factors of up to 20% in this situation. Drying the transformer using heaters can reduce this to 5% or less. Epoxy cast coil transformers generally test well, with most being in line with the Doble recommendations. Potential problems can be caused by dirt buildup in between the high and low winding at the insulating blocks separating the windings from the frame bottom. The power factor often can be reduced by 50% simply by a thorough cleaning at this point. Another problem we have seen is that the leads going from the transformer to the line-side of the switch are often twisted to the extent that they have inadequate clearance between cables. This can cause higher than expected readings, and can cause problems when performing an excitation test (getting the leads mixed up). Some smaller transformers (and fewer larger ones) may have an electrostatic shield between the high and low windings. On transformers with this shield, the CHL test cannot be performed, as the shield is grounded. The tests are limited to performing the Ch and CL tests. This shield also has caused us problems when performing a TTR test using some digital ratiometers, but not when an analog TTR is used.

Transformer Handbook — Volume 2 Although not related to power factor testing, many of the dry-type transformers we test show a second core ground, even when brand new. This unintentional ground is often between the laminations and frame and can be very difficult to locate. The second core ground will cause circulating currents to appear with the core, which can cause the unit to run at a higher temperature. This is not an issue with lightly loaded transformers, but if it is heavily loaded, can cause overheating and loss of life. If the second core ground can be located, the core ground strap can be relocated to be on the same side as the unintentional core ground and reduce its effects. The capillary tubes used for RTD’s can also be a problem with dry-type transformers. They are often held in place by a nylon cable tie. If it is a high-temperature cable tie, there usually is no problem. However, in at least five cases we have encountered transformer failures due to this tube falling onto the winding and causing a short. There have been many more cases where the cable tie was clearly close to failure. Our practice is to replace all cable ties with clamps, eliminating the problem. Lastly, a good number of transformers have been found with the shipping bolts still in place and secured. This causes high noise and vibration in the unit. We have found that leaving the bolts in place, but loosening them eliminates the noise and vibration while protecting the core from shifting if it ever needs to be relocated.

Solid-Porcelain and Epoxy Bushings Doble recommends power factor testing solid porcelain and epoxy bushings rated above 5kV by the hot-collar method. For low-voltage bushings, or bushings with three petticoats or less, it is recommended that the collar be placed below the top petticoat. Bushings with more petticoats should have the collar placed below the top petticoat and then another test run with the collar one petticoat above

the flange. When performing a hot-collar test, be certain to keep the high-voltage probe at a 900 angle to the bushing and seat the collar as closely to the surface as possible. Figure 5 shows the hot-collar test connection. Capacitance should be ± 10% of the average of all bushings of the same type. A fluctuating watts/milliwatts reading indicates a crack in the petticoat. Watts-loss readings above 0.10 watts using the 10kV test set or 6.0 mW using the 2.5kV test set should be investigated as to their cause. This value is quoted by Doble for both solid porcelain and epoxy bushings. In reviewing Doble’s Knowledgebase on their web site, the following notes on epoxy bushings came up: Westinghouse Type: EJ

KV Range: 15 kV S/N Range: Age:

High Power Factor The Westinghouse type EJ bushing has a specially formulated epoxy flange cast around the porcelain body. The inside surface of the porcelain and the outside surface below the bottom skirt have a conducting coating. The outer conducting coat is grounded by means of a small wire cast into the epoxy flange and terminated at a washer at one of the mounting holes. Due to the design of the conducting coating, the bushings have inherently high power factors. These bushings are installed in low voltage windings on medium power transformers. Tests on the transformer windings are not possible without isolating the small grounding washer. The effects of these bushings can only be properly minimized by guarding the bushing flanges at the grounding washer. It is not sufficient to allow the bushing to “float” as directed by Westinghouse. Several clients reported problems due to fractured epoxy flanges on these bushings. Mechanical failure of the epoxy at the flange occurred at a torque value of 10 ft-lbs. According to Westinghouse, these bushings have been removed from production and the old RJ bushings have been reinstituted (recorded 1971).

References 38AIC71, Fall Committee Meeting, pg. 11-33 and 11-37 Westinghouse Type: ES KV Range: S/N Range: Figure 5 — Hot Collar Test Connection Courtesy Doble Engineering

Age: 1941 - 1976

Transformer Handbook — Volume 2 PCB Content PCB contents of up to 20% by weight are believed to be contained in the compound fill/plastic in older Westinghouse bushings such as the Type ES. Production years were 1941-1963 for transformer applications and 1941 – 1976 for breaker applications.

References 57AIC90, Fall Committee Meeting, pg. 11-2.28 Square D Type:

Epoxy

KV Range: S/N Range: Age:

High Power Factor The Square D Cycloaliphatic Epoxy bushings are known to have high power factors due to absorbing moisture. The power factor value is lower if a Silane Surfactant is used on the filler material. Square D power factor limits for bushings with Silane Surfactant coating is 5%, with a rate of 0.5% increase per year. Without the Silane Surfactant coating, it is 15%, with a rate of increase of 1.25% per year. Doble Engineering states that bushings designed for outdoor use must be impervious to moisture. However, there have been conditions of tracking, voids and carbonized cracks, which may result in corona and power factor increases in cast-epoxy equipment that may or may not be directly related to moisture absorption.

References 51AIC84, The Dependence of the Power Factor of Cycloaliphatic Epoxy on its Moisture Content, by F. S. Brugner, pg. 4-401 51AIC84, Discussion, by A. L. Rickley, pg. 4-401A

Summary Power factor testing is recommended on large (over 500kVA) transformers to ensure insulation integrity. Although there are general recommendations, there have not been an adequate number of test results on a broad sampling to verify the effects of temperature on insulation or to provide definitive values for smaller encapsulated type units. Most of these smaller units are probably adequately tested using megohmmeters and performing PI and/or insulation resistance tests.

For larger units, the power factor test can provide good insulation grading and help detect any deficiencies, which may affect reliability. The value of the test increases as the size and criticality of the transformer increases. Jim White is the Director of Training for Shermco Industries, Inc., a NETA Accredited Company and is nationally recognized for technical skills and safety training in the electrical power systems industry. Jim is a NETA Certified Level IV Technician, and serves as the alternation NETA representative of the NFPA 70E Committee and is the NETA representative on the newly-formed IEEE/NFPA Arc Flash Hazard Work Group (RPTC). Additionally he serves as the secretary for the 2006 IEEE Electrical Safety Work Shop, is an authorized OSHA Outreach instructor, the Vice Chair of the Doble Transformer Field Processing Subcommittee and a member of the Asset Maintenance Management Committee and Circuit Breaker Committee. Jim is an associate IEEE member and Inspector member of the International Association of Electrical Inspectors (IAEI).

Transformer Handbook — Volume 2

Cooling Classes of Transformers T

orld

rn 2

b on idu her co Industries

As a point of clarification, the cooling classes of transformers have changed in recent years and are explained in the following information. The IEEE transformer cooling designations were changed to become consistent with the IEC (IEC 60076-2: 1998). The new classifications are detailed in IEEE C57.12.00-2000. The new cooling designations have four-letter descriptions that indicate specific criteria relative to 1) the type of oil, 2) how the oil is internally circulated, 3) what is used to cool the oil, and 4) how the oil is externally cooled. As an example:

The type of oil

What is used to cool the oil

ONAN How the oil is internally circulated

How the oil is externally cooled

The cooling class is identified by the following methodology:

First Letter Internal Cooling Medium in Contact with the Windings

K L

Circulation Mechanism for Internal Cooling Medium Letter Definition N Natural convection flow through cooling equipment and in windings F Forced circulation through cooling equipment (i.e., coolant pumps) and natural convection flow in windings (also called nondirected flow) D Forced circulation through cooling equipment, directed from the cooling equipment into at least the main windings

Third Letter External Cooling Medium

Figure 1 — Cooling Designations

Letter O

Second Letter

Definition Mineral oil or synthetic insulating liquid with fire point ≤ 300°C Insulating liquid with fire point > 300°C Insulating liquid with no measurable fire point

Letter A W

Definition Air Water

Fourth Letter Circulation Mechanism for External Cooling Medium Letter N F

Definition Natural convection Forced circulation [fans (air cooling) or pumps (water cooling)]

Comparison of past transformer cooling designations versus present-day transformer cooling designations is detailed in the following table:

Transformer Handbook — Volume 2 Present Designations

Previous Designations

ONAF

FA

ONAN

ONAN/ONAF/ONAF ONAN/ONAF/OFAF ONAN/ODAF

ONAN/ODAF/ODAF OFAF

OFWF ODAF

ODWF

OA

OA/FA/FA

OA/FA/FOA OA/FOA

OA/FOA/FOA FOA

FOW FOA

FOW

Figure 2 — Comparison Table, Past/Present Designations

For more detailed information on transformer cooling class designations, see IEEE Standard C57.12.00-2000, “IEEE Standard General Requirements for Liquid-Immersed Distribution, Power, and Regulating Transformers.” Ron A. Widup, Executive Vice President/General Manager of Shermco Industries, Inc., has over 20 years of experience in the low-, medium-, and high-voltage switchgear and substation market. He is a principal member of NFPA technical committee 70E (Electrical Safety Requirements for Employee Workplaces) and a member of NEC Code Panel 11. He is past president of NETA and currently a member of the Board of Directors and Standards Review Council. He is certified as a NETA Level IV Senior Test Technician.

How Do You ensure Safety and Reliability? Hire a NETA Accredited Company! NETA has been connecting designers, specifiers, architects and users of electrical power equipment and systems with independent, third-party electrical testing companies since 1972. NETA Accredited Companies test the complete system in accordance with industry codes and standards to provide accurate test reports you can count on every time.

For a complete listing of NETA Accredited Companies turn to page 120 or visit www.netaworld.org.

For more information on NETA or our ANSI/NETA Standards give us a call at 888-300-NETA (6382)

Transformer Handbook — Volume 2

Basic Power Factor Testing T

o erTes 2 nnual Te n al onferen e Keith ill Doble Engineering Co

Power Factor testing is one of the most common tests performed by testing personnel in the field to evaluate the insulation of electrical apparatus. Power Factor testing has been in use for almost 75 years and has proven to be very effective in identifying problems with almost any type of electrical equipment regardless of its operating voltage or type insulation. Today this test is recognized as one of the single most effective methods for locating defective insulation. Power Factor testing can be applied to liquid, gas or dry type insulating systems. Over the years, Power Factor test equipment and technology has changed, but the basic Power Factor concept is still the same - the measurement of the angle between the voltage and total charging current. Test equipment that has a dc voltage output has often been used for testing electrical apparatus. When performing a dc test, such as a “megger”, the weakest point of the insulation system is stressed. In an AC Power Factor test, the overall insulation system is measured which results in the “average” of the insulation systems

Advantages of AC versus DC Testing • The ac test has a common denominator in the form of a ratio (% Power Factor), which is independent of the amount of insulation.

• A layer of “good” insulation in series with a “bad” insulation does not hinder the ac test, since it merely requires a capacitance coupling. • The ac test provides a direct measure of dielectric loss and capacitance, both of which are useful in the diagnosis of the deterioration of many forms of insulation. • The dc measurement depends on the length of time the voltage is applied (PI).

an

Limitations of the Power Factor Tests • The ability to detect localized defects decreases as the inherently normal dielectric-loss and capacitance of the systems increases.

• Defects, which are voltage dependent, may not be detected if the initiation voltage of the defect is greater than the test voltage.

Basic Power Factor Theory When performing Power Factor testing, several components, such as Power Factor, Current, Watts-Loss and Capacitance are measured and calculated by the test equipment. All of the measured components are essential in evaluating the condition of the apparatus being tested. Per cent Power Factor has often been the only criteria used by test personnel and engineers in assessing the condition of equipment, such as a transformers and bushings. In this paper, an attempt will be made to demonstrate the importance of each measured component and how the understanding of each component will help in determining possible problems. The introduction of computers and automated test equipment used in Power Factor testing has not decreased the importance of the test technician. Personnel performing the test must use the proper test procedures and connections if the tests are to provide valid data. Testing personnel must still interpret the test results and identify problems if they exist. Power Factor is often thought of as the efficiency of a power system in terms of real and reactive power. For this paper, Power Factor is used to define the condition of the insulation system. Power Factor is calculated by dividing the watts loss by the total charging current with the cosine of the measured angle being the Power Factor of the insulation.

CORE FORM TRANSFORMER

Single phase or one phase of a three phase transformer shown

CH - High Voltage Winding to ground

High

CL - Low Voltage Winding to ground CH

CHL

CL

High Voltage Winding Low Voltage Winding

Low

CHL - Insulation

Core Ground

between the High and Low Voltage Windings to ground

Tank Cut Away Plan View

Tank Ground

Transformer Handbook — Volume 2 In the following example, the circuit consists of 4 capacitors in series. The total capacitance is 1.25 pF with an average Power Factor of 0.5%.

Average Power Factor =

.5 + .5 + 0 + .5 = 1.5 ——————— —— 4 4

Total capacitance = 1 = 1 + 1 + 1 = 3 — — — — — 5 5 5 5 CT 1 = — CT

3 — 5

CT = 5 — 3

Average Power Factor = .5 + .5 + .5 + .5 = 2.0 ——————— —— 4 4

= .5 %

Total capacitance = 1 = 1 + 1 + 1 + 1 = — — — — — 5 5 5 5 CT 1 = — CT

4 — 5

CT = 5 — 4

4 — 5

= (CT) x 4 = 5 =

1.25 pF

In the following circuit, the Power Factor for Cl has increased from 0.5% to 2.5%. The total capacitance remains the same at 1.25 pF. This represents a change due to contamination or deterioration.

Average Power Factor = 2.5 + .5 + .5 + .5 = 4.0 ——————— —— 4 4 Total capacitance is still 1.25 pF

= .5 %

= (CT) x 3 = 5 =

1.667 pF

The above example indicates how a physical change will result in a change in capacitance without a change in Power Factor. If test personnel do not compare all measured components a problem may be overlooked.

Test Modes The combination of test modes will allow for testing various components of the insulation system. There are three standard test modes for Power Factor testing: GST - Ground, GST - Guard and the UST - Ungrounded Specimen Test. When GST tests are performed, ground current is always measured. In the UST mode, ground current is never measured. GST Ground - Grounded Specimen Test -Ground Current is measure on ground lead and any leads that are in the ground mode. In this circuit CA, CB and Cc are measured since both Low Voltage (LV) leads are grounded.

= 1.0 %

In the following example, the total capacitance has changed since the C3 capacitor has physically been shorted. The averaged Power Factor of the circuit has not been affected. GST Guard - Grounded Specimen Test - Guard Ground current is measured, but any component that is guarded will by-pass the metering circuit. In this circuit, CB and Cc are measured, while CA is guarded. Guarding of the LV lead can be red, blue or both red and blue.

5

Transformer Handbook — Volume 2 Bushings

UST - Ungrounded Specimen Test - No ground current is measured. In this circuit, CA is measured, while CB and Cc are grounded. In this test CB and Cc shunt the meter since no ground current is measured is measured in the UST mode.

In the above circuit, the red or blue leads can be grounded or guarded in different combinations. Any ground current on the ground lead will always by-pass the meter. The red or blue LV lead can be grounded; dependent on which component you wish to measure. Note that no ground current is measured. As shown in the above circuits, the heavy “bare copper” ground attached to the test set should be connected directly to the apparatus being tested and not to another grounded location in the sub. From the circuits, it is also determined that the “bare copper” ground is a current carrying conductor and is part of the measuring circuit. Connection of the ground to the apparatus being tested should be attached to a clean and well-grounded surface of the apparatus. Apparatus that is not grounded will result in erroneous Power Factor readings, which can cause the reading to be negative.

Busings are an important part of electrical apparatus and should be tested and visually inspected for damage or abnormal conditions that may lead to their failure. A busing may be one of two types – condenser or non-condenser. A condenser bushing can either be oil-impregnated paper or resin bound paper insulation. A non-condenser bushing may be solid, alternate layers of solid and liquid or gas filled. A condenser bushing usually consists of porcelain, paper and oil or compound. Bushings may be composed of other materials, but for this paper the bushings will be considered to be condenser oil filled. When performing a bushing test on a transformer, all primary bushings should be shorted together to prevent negative watts reading due to coupling capacitance through the unshorted windings of the transformer. The same holds true for the secondary bushings. Only the tap cover on the bushing being tested should be removed. Removal of tap covers on bushing not being tested can result in bushing problems. In a condenser bushing, the Power Factor and capacitance are often stamped on the nameplate of the bushing. This information, given as Cl and C2, should be referenced when performing tests on the bushings. If the bushing has a tap, both the Cl and C2 tests should be performed even if no data is stamped for the C2 insulation. The Cl is in reference to the main core insulation of the bushing, while the C2 is the insulation between the test tap/potential tap and ground. Rated voltage of the bushing will determine the test voltage when performing a test on the tap. Bushings rated 69 kV and below are considered to have a test tap, with a maximum test voltage on the tap of 500 volts (except for the Ohio Brass type L bushing which is 250 volts). Bushings rated above 69 kV are considered to have a potential tap, with a maximum test voltage on the tap of 2000 volts. Higher voltages may be applied to the tap if approved by the bushing manufacturer. Consult the instructions for the bushing if using any voltages other than mentioned. As mentioned, the Cl is the main core insulation of the bushing. This main core is often referred as the condenser as a “capacitor” is formed when the “paper” is wrapped around the center conductor of the bushing. When tested, remembering capacitor theory, shorted condenser layers will result in a higher than nameplate capacitance for Cl. The type material used to clean the surface of the bushings must be carefully considered. Some solvents and cleaners evaporate so fast that condensation can occur on the surface of the porcelain when the relative humidity is high. Relative humidity over 70% can often affect results. Applying heat with a heat gun or hair dryer will help in the elimination of surface contamination due to moisture.

 Main Insulation / Cl test connection:

Test Includes: Main Cl Core Insulation

The C2 is often overlooked when performing a test on a bushing. If no values are given for the C2, it is often thought that testing the C2 should not be performed. The C2 should always be a part of any standard bushing test program, since problems can be identified by the C2 test that the C1 test will not reveal. Insulation tested during C2 include: tap insulator, core insulation between tapped layer and bushing ground sleeve, portion of liquid or compound filler and portion of the weathershed (petticoat) near flange. Tap-Insulation / C2 test connection: Test Includes: Tap Insulation Core Insulation between tapped layer and Bushing Ground Sleeve Portion of Liquid or Compound Filler

Transformer Handbook — Volume 2 Transformers Transformers are the most common type of electrical equipment that is Power Factor tested. Power Factor tests are the most comprehensive tests for insulation assessment. Power Factor tests are performed to detect moisture/contamination, carbonization and mechanical failure. Power Factor tests performed on a transformer are to include, but not limited to, overall, bushing, oil and excitation. Overall tests measure CH, CHl and CL insulations. Bushing tests should include Cl, C2 and Hot Collar. A Power Factor test should be performed on a sample of the oil to determine contamination/deterioration. At 10 kV, new oil should have a Power Factor less that 0.05%, while used oil should have a Power Factor less than 0.5%. The temperature of the oil sample should be taken after the tests are complete and the proper correction factor should be used to calculate the Power Factor. Excitation tests are performed to identify manufacturing defects, shorts, grounds, winding faults, open circuits and Load Tap Changer problems. Proper connection and preparation of the transformer can prevent testing problems. All external connections should be disconnected from the transformer. Any components that are still attached to the transformer terminals will be included in the tests. This includes disconnecting any Ho or Xo bushing from ground. Externally connected equipment or bus can greatly influence the tests. The transformer tank must be grounded. The ground lead from the Power Factor test set must be connected to a ground on the transformer being tested. Transformer should not be tested that are under vacuum, have a top oil temperature below zero degrees centigrade or that may contain explosive gasses. Safety must be considered when performing Power Factor testing. Company and OSHA safety procedures should be strictly followed to prevent injury or death. After disconnecting all external bus or cables, including Xo and or Ho, the primary bushings should be shorted together and all secondary bushings should be shorted to the other secondary bushings. After properly preparing the transformer, testing can be performed.

Portion of weathershed near Flange

Careful consideration should be given to both the Power Factor and capacitance of the bushing. A change in 10% for capacitance is cause for concern and should be investigated. If the measured Power Factor is greater than twice the nameplate, the bushing should be investigated. Exceeding these limits often include replacement of the bushing. Power Factor and capacitance should be referenced to prior tests of the bushing.

Improper shorting of the primary and secondary bushings is one of the most common mistakes when performing Power Factor testing of a 2-winding transformer.

Transformer Handbook — Volume 2 Testing of the primary winding consists of three overall tests for the primary and three overall tests for the secondary. Tests 4 and 8 are calculated tests results. They are as follows: Test

1

2 3 4 5 6 7 8

Test Connections ENG

HIGH HIGH

GND

LOW

HIGH

GAR LOW

Insulation Measured UST

LOW

Calculated UST - Test 1 minus Test 2 Tests 3 and 4 should be equal LOW LOW LOW

HIGH

HIGH

HIGH

Calculated UST - Test 5 minus Test 6 Tests 7 and 8 should be equal Tests 3, 4, 7 and 8 should be the same

CH + CHL CH

CHL

CL + CHL CL

CHL

Transformer insulations measured are the CH, CHL and CL. The following diagram illustrated the insulation system of a two winding transformer.

Using the above information will help in determining problems when higher than normal readings are obtained. If only the CH is high, you would look at the High Voltage bushings structural insulating members, and DETC insulation. If only the CL is high, you would look at the Low Voltage bushings, winding insulation, structural insulating members and LTC. If only the CHl is high you would look at the winding insulation barriers. If the CH, CL and CHL were high you would look at the oil since it is common to all three insulating systems. Transformer Limit Guidelines

Rating 0-500kVA >500kVA

Type Distribution Power

New 1.0% 0.5%

Used 2.0% 1.0%

When analyzing Power Factor test results for a two winding power transformer test personnel should consider: • New oil power transformers should have a percent Power Factor of around 0.25% to0.30%. Any value over 0.5% is considered deteriorated.

• A change in capacitance or current could indicate a shifted winding / deformed coil or core. 5% or more is cause for concern and should be investigated. • A negative CHl indicates contamination on the surface of the windings or a bad connection on the interwinding shield.

• If all tests, CH, Cl and CHl are poor, the generalized condition may be pointing to the oil or general contamination, such as moisture. The oil should be tested.

• If only the CL is high, you would look at the Low Voltage bushings, winding insulation, structural insulating members, and LTC. • If only the CH is high, you would look at the High Voltage bushings, structural insulating members, and DETC insulation. • If only the CHl is high, you would look at the winding insulation barriers. The CH is the insulation between the High Voltage winding, conductors and the ground tank and core The CH includes the High Voltage bushings, winding insulation, structural insulating members, De-Energized Tap Changer (DETC) insulation, and insulating fluid. The CL is the insulation between the Low Voltage windings, conductors and the grounded tank and core. The CL includes the Low Voltage bushings, winding insulation, structural insulating members, Load Tap changer (LTC) and insulating fluid. The CHL is the insulation between the High and Low Voltage windings. The CHL includes the winding insulation barriers and the insulating fluid

As mentioned earlier in this paper, Power Factor is sensitive to temperature. Power Factor readings should be corrected to 20 degree centigrade using a temperature correction chart provided by the manufacturer of the Power Factor test equipment. High Watts Loss on bushings can sometimes be attributed to high humidity. Steps must be taken to avoid errors in test methods and connections.

Transformer Handbook — Volume 2 Case Study 1 Note the high Power Factor for all tests Tests performed October 30, 2001 Test#

KV

mA

W

1

2.5

12 920

3.605

4.911

1.268

2.58

2.5

8.018

2.338

8.09

2.337

1

18.710

10.700

5.620

3.282

3.07

1

8.018

2.336

2.91

2.33

8.010

2.338

2.92

PF Meas

2 3

2.5

4 5 6 7

1

8

PF Meas

PF Corr

CF

Cap

Insulation Measured

0.80

3426

CH+CHL

0.80

1302

CH

2.92

2.06

2.34

0.80

2125

CHL

2.92

2.34

0.80

2124

CHL

0.80

4963

CL + CHL

0.80

2838

0.80

2125

CHL

2.34

0.80

2125

CHL

PF COIT

CF

Cap

Insulation Measured

0.90

3134

CH+CHL

2.46

CL

Tests performed November 17, 2001 Test#

KV

mA

W

1

2.5

11.810

0.327

2

2.5

4.552

0.143

0.31

0.28

0.90

1207

CH

3

2.5

7.271

0.182

0.25

0.23

0.90

1928

CHL

7 258

0.184

0.25

0.23

0.90

1927

CHL

0.90

4521

CL + CHL

4 5

1

17.040

0.541

6

1

9 777

0.356

0.36

0.32

0.90

2593

CL

7

1

7 271

0.179

0.25

0.23

0.90

1928

CHL

7.263

0.185

0.25

0.23

0.90

1928

CHL

8

Tests after transformer return from repair shop. Transformer windings were baked and new oil installed.

Transformer Handbook — Volume 2 Case Study 2 Note the negative Watts and Power Factor in the following tests As Found tests performed by testing company # 1. Test#

kV

mA

W

1

2

11.760

0.600

2

2

3.040

0.955

3

2

4

PF Meas

PF Corr

CF

Cap

Insulation Measured

0.71

3121

CH+CHL

0.71

805.90 2315

CH

CHL

3.14

2.23 -0.3

0.71

-0.3

0.71

2315.1

CHL

0.71

4041

CL + CHL

8.729

-0.350

-0.40

8.720

-0.355

-0.41

5

1

15.230

1.634

6

1

6.514

1.952

3.00

2.13

0.71

1727

CL

7

1

8.729

-0.330

-0.38

-0.3

0.71

2315

CHL

8.716

-0.318

-0.36

-0.3

0.71

2314

CHL

8

Tests performed by testing company # 2, with transformer tank properly grounded. Test#

kV

mA

W

1

10

11.820

0.314

2

10

3.206

0.111

0.35

3

10

8.616

0.205

8.614

0.203

4

PF Meas

PF Corr

CF

Cap

Insulation Measured

0.80

3135

CH+CHL

0.28

0.80

850.40

CH

0.24

0.19

0.80

2285

CHL

0.24

0.19

0.80

2284.6

CHL

0.80

4109

CL + CHL

5

1

15.490

0.335 0.123

0.18

0.14

0.80

1823

7

1

8.616

0.191

0.22

0.18

0.80

2285

CHL

8.616

0.212

0.25

0.20

0.80

2286

CHL

6 8

1

6.874

CL

Transformer Handbook — Volume 2 As one can see, the test technician or engineer is a critical part of the test procedure. Testing personnel must be able to safely prepare the equipment for testing. They must be able to interpret and analyze the results, even if the software has provided a rating. Sometimes the software may be incorrect. The tester must also be able to “troubleshoot” and locate the problems with the apparatus being tested and in some cases make the necessary repairs.

References Doble Engineering Company. (1997). Bushing Field-Test Guide. Watertown, Massachusetts. Doble Engineering Company. (2000, January). M4000 Insulation Analyzer User Guide. Watertown, Massachusetts. Keith Hill received an electrical degree from the University of Houston. He has eighteen years experience as Electrical Supervisor – Engineering Services at Lyondell-CITGO Refining. He was with Doble Engineering for three years as client service engineer in the region covering Texas, Arkansas, Oklahoma, and Louisiana.

Transformer Handbook — Volume 2

Transformer Frequency Response Analysis: An Introduction T

orld

rn 2

b on cGrail Doble Engineering

Introduction Frequency response analysis (FRA) is a well-understood technique in electrical testing. It is the ratio of an input voltage or current to an output voltage or current. Since the pioneering work of Dick and Erven at Ontario Hydro in the late 1970s, FRA has been applied to power transformers to investigate mechanical integrity. Experience has shown how to make measurements successfully in the field and how to interpret results. This article shows some typical results and how utilities are gaining benefit from what is, in fact, a simple test.

Frequency Response Analysis — FRA and SFRA A standard definition of frequency response analysis (FRA) is the ratio of a steady sinusoidal output from a test object subject to a steady sinusoidal input. Sweeping through the frequency range of interest gives rise to the S in SFRA to distinguish it from impulse methods where the response is estimated rather than measured. Figure 1 shows a simple two-coil arrangement subject to winding movement. The before and after SFRA traces are different, as shown in Figure 2. The peaks and valleys of the traces are called resonances and correspond to combinations of capacitance and inductance within the coils. A change in resonance must be linked to a physical change in inductance or capacitance. Hence, we can deduce there has been a mechanical change in the windings. But how do we use SFRA results in practice? The following examples are from real transformers. It is not always necessary to have reference results, although this is the ideal situation. Comparison with sister units or between phases is also possible. Phase-by-phase analysis is more complex and less reliable as windings are often asymmetrical through design and construction.

Figure 1 — Coil Movement

Practical Results — Axial Collapse of Winding Axial collapse is also known as telescoping, where one winding shifts relative to the other like an expandable telescope. In this case a transformer tripped out on a fault pressure relay during a storm and three days after a previous dissolved gas analysis (DGA) test. The DGA showed a rise in acetylene from zero parts per million to 84 parts

Transformer Handbook — Volume 2

Figure 2 — Change in SFRA

Figure 3 — LV Results for Partial Axial Collapse

Figure 4 — Results for a Good Phase (left) and Bad Phase (right)

per million, indicating a major arc within the transformer. Other dissolved gases supported this diagnosis. Electrical testing included power factor, capacitance, winding resistance, excitation, and turns ratio. All gave acceptable results. SFRA, however, gave an indication of a partial collapse on one winding. The high voltage results gave no significant indication of a problem while the low voltage results were suspect, as shown in Figure 3. Clearly, in Figure 3, the X3-X0 results (in red) show a shift to the right at a number of resonant frequencies. Natural asymmetry of the windings was ruled out as the high voltage results were acceptable and very similar. This result was similar to a case where another transformer had suffered a close-in fault, and subsequent SFRA traces revealed shifts to the right for just one phase. This would provide a reference set of results. Figure 4 shows SFRA results taken in 1994 and 2001. The good phases are very repeatable and indicate no significant problem. The bad phase shows clear and consistent shifts of resonances to higher frequencies.

Note that all results are between 300 kilohertz and one megahertz. A tear down of the transformer showed the damage in the B-phase, as shown in Figure 5, where the blocking can be seen to have collapsed under the winding.

Practical Results — Hoop Buckling of Winding Hoop buckling, or winding compressive failure, is a common cause of deformation in transformers. The winding is bent but not broken. There are cases of transformers with severe hoop buckling remaining in service for several years. They have elevated DGA levels but otherwise perform almost normally. The problem lies with their reduced ability to withstand further faults and the increased likelihood of catastrophic failure while in service. Figure 6 shows hoop buckling on one phase of a mobile transformer, as found during an inspection.

Transformer Handbook — Volume 2

Figure 6 — Hoop Buckling in Winding

Figure 7 — Effect of Hoop Buckling on SFRA Results

Figure 5 — Damage

The SFRA response for this transformer showed a clear shift to lower frequencies for that phase, as shown in Figure 7. Previous results were available for a sister unit that showed the variation was not due to design or construction. The diagnosis was made before the inspection, and the transformer returned to service during a peak load period with advice that it would be more likely to fail if it saw another nearby fault. The bad phase was rewound some months later when the picture in Figure 6 was taken.

Practical Results — No Change One of the strengths of SFRA is in the power of a null result. When using a good repeatable test system, a null result, which shows no variation in the traces, is very strong evidence that the windings have not moved or deformed.

Figure 8 — Five SFRA Results Showing No Significant Variation

Transformer Handbook — Volume 2 Figure 8 shows five results for one phase of a generator step up (GSU) transformer taken over the course of eight years from July 1994 to July 2002. Clearly there has been no change in response, and the transformer is in unchanged condition. Small variations at low frequency relate to the state of core magnetization when the transformer was switched out of service, but it is clear that the main resonances have not changed.

Interpretation Experience has shown that the simplest form of interpretation of SFRA traces is with respect to a baseline. However, it is unlikely that we will ever get a baseline for all transformers on the electric supply network. Consequently, interpretation strategies which involve sister units or short circuit results are used. The least reliable method is phaseby-phase analysis, due to asymmetries brought in through construction and, for example, end mounted tap-changers. Automated approaches have been tried, but these produce both false positive results and false negative results. Simple difference analysis and correlation are sometimes useful as indicators but tend to show where the engineer should investigate the original traces (see McGrail and Sweetser). Doble Engineering is involved in the forefront of research into automated analyses that bring together differences, correlation, and manufacturer-specific experiences.

Key Features of SFRA in the Field Practical experience has shown that SFRA measurements are simple to make, and a consistent measurement may be made in the field up to two megahertz (see McGrail and Lapworth). Above that frequency the value of the measurement is greatly limited by the variability of the test equipment and set up, especially with impulse systems, where it has been found that small movements in the leads will show great variation in responses (see Vandermaar). The value in SFRA is the repeatability of results. Experience over many years has shown that a sweep system is the only way to extract that value from the results. The null result showing no movement in Figure 8 would be lost if the measurement were not repeatable to within +/- one dB. However, SFRA is only one tool and should be used in conjunction with other electrical and diagnostic tests to paint a complete picture of transformer health. To investigate further, please visit the Doble website (www.doble.com) where further information may be found and examples and case studies are given.

References 1. Horowitz, P., The Art of Electronics, Cambridge University Press, Boston, 1989.

2. Heathcote, M.,The J & P Transformer Handbook, Newnes, London, 1998.

3. McGrail, T. and Lapworth, J., “Transformer Winding Movement Detection,” proceeding of the 1999 Doble Client Conference, Boston, MA.

4. McGrail, T. and Sweetser, C., “Substation Diagnostics with SFRA,” proceedings of the 9th EPRI Substation Diagnostics Conference, New Orleans, LA, March, 2004.

5. Vandermaar, J., and Wang, M., “Key Factors Affecting FRA Measurements,” IEEE Electrical Insulation Magazine, v. 20, n. 5, September/October, 2004.

For the last two years, Tony McGrail has been the M5100 SFRA Product Series Manager with the Doble Engineering Company, based in Watertown, Massachusetts, USA. Prior to this, Tony was a transformer engineer with the National Grid Company in the UK. He is a Chartered Engineer in the UK, holding a Ph.D. in Electrical Engineering and a Masters in Instrumentation.

5

Transformer Handbook — Volume 2

Transformers: Responding to the Baby Boom T

orld

van Koo

n er 2

2

b ohn van Koo rans or er Consulting ervices, Inc

In our Transformer Consulting Services business, we often draw an analogy between transformers and the human condition. Transformers, like people, have a relatively long life span. Longevity is related to genetics (quality of manufacture), work environment, maintenance and the unpredictable negative occurrences that impact our lives. Just like human population trends, the transformer population has also seen peaks and valleys in installation responding to the ebb and flow of energy needs. The following chart tracks the sales of transformers approximately 20 MVA and above, from a major transformer manufacturer and is typical of the North American market as a whole.

North American Market – Power Transformer Purchases

The discussion of how long a transformer will last is an open discussion, but if we draw a line in the sand and say life expectancy is 35 to 40 years, then it is apparent that we have a substantial “aging population” whose replacement must be prepared for. Estimated %, by Age, of Transformer Base in North America (based on data from preceeding graph) 70.0% 60.0% 50.0% 40.0% 30.0% 20.0% 10.0% 0.0%

65.1% 51.5% 36.3% 20.0%

40 or older

35 or older

30 or older

25 or older

87

90 19

19

84

78

75

81

19

19

19

72

19

69

63

66

19

19

19

19

60 19

57

19

19

54

Factors Affecting Longevity

We can see a generally high buying trend from the late 1950’s to the late 1960’s (with some dramatic valleys). There was a general slowing but still significant output during the 1970’s followed by a peak in the early 1980’s. From the mid 1980’s to the mid 1990’s there was a dramatic decline in need. Since the mid 1990’s there has been a steady increase in demand from the North American markets.

Genetics (Original Equipment Manufacturer) Although this is a sensitive subject for obvious reasons, there have always been “low cost” suppliers and “brand name” suppliers. Even though all transformers should be built to a consensus Standard (ANSI/IEEE, IEC), there is significant leeway to allow manufacturers to find varying cost alternatives in design and material. Even within a “brand name” supplier’s history, there will be glitches (after all, transformers are made by people). Also, all suppliers are subject to the almost inevitable increase in risk factors as transformer size (MVA) and voltage class have grown over the years. This article deals primarily with mature transformers, but even today it is important to ask suppliers for performance history of their design.



Transformer Handbook — Volume 2

Application (What a Transformer Does for a Living) Transformers are applied in many situations under varying conditions. A utility will employ power transformers in generation and transmission roles. Transformers connected to generators will typically be operated at or near full load continuously. If there is a reduction in demand, the transformer may drop to zero load and then may be required to go to full load very quickly. Transmission transformers are typically applied in pairs with each transformer carrying about half full load (this is changing of course). The transmission load will vary with time of day, season and with increased or decreased general load conditions. Transformers used by industry have many applications, too many to cover in this article, but they are generally worked harder than in a utility application. In addition to potential stressful applications they are also subjected to difficult environments of temperature and contamination that can have a negative impact on life span. Transformers, unlike people, age significantly slower if they are not loaded to capacity. Age is measured not only in years of service but is also moderated by the load carried.

Unusual Occurrences This category of stress would include lightning strikes, short circuits, temporary excessive overloading and mechanical damage. This data may be hard to track but can be significant, as the impact tends to be cumulative. An older transformer may fail because of a single (the last straw) lightning strike or short circuit, but in reality the insulation system has been stressed and weakened over time by a succession of events. Maintenance and Testing My point in the context of this paper is that maintenance and testing methods and their cycles should be based on the importance of the equipment to the system or process, the application, and the relative age of the equipment. I would suggest a different monitoring approach for a 5-year- old, 30 MVA transmission transformer as opposed to a 300 MVA, 25-year-old generator transformer or a 15 MVA, 35-year-old industrial application transformer.

Failure Rate

Representation of Failure Curve for Typical Transformer Population

Years of Service, Installation to End of Life

When looking at the field test results, which would include power factor, insulation resistance, oil sample results, including dissolved gas in oil and furan analysis, we should not expect comparable results for the transformer examples given above. It is generally believed that “bathtub” curve shown above is representative of transformer failure trends. In the first few years, the high failure rate is due to design and application failures, followed by a period of a low, stable failure rates for the majority of the equipment life. Approaching end of life, the failure rate ramps upwards.

Moral of the Story There is a large installed base of transformers built in the late 1950’s and 1960’s that are aging, some gracefully, some not. This equipment forms the core of many utility and industrial systems. This older equipment should have increased surveillance as they approach end of life. When reviewing field test records it is always best to compare results from similar transformers. This is not always possible with a small sample of installed equipment. Efforts should be made to assemble and share maintenance test data to allow comparison and hopefully spot negative trends in segments of the transformer population. Transformer users and maintainers must assess their older transformers installed during the construction boom periods to ensure that these transformers do not end their lives with a BOOM! John van Kooy has over 25 years of experience in transformer design, manufacturing, operation and field test result analysis and included management positions with Westinghouse and ABB in transformer design and engineering. John is currently the owner and technical principal of van Kooy Transformer Consulting Services, Inc.

Transformer Handbook Volume 2

Published by InterNational Electrical Testing Association

Published by InterNational Electrical Testing Association

Transformer Handbook — Volume 2

Transformer Turn Ratio Testing T

orld

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2

b e o ett egger

In their basic conception, transformers are simple devices. Two coils of insulated wire are wound in close proximity on an iron core. Also referred to as “windings,” one is connected to a power source, such as the utility or a generator, and is designated the “primary”. The other provides power, “transformed” in some manner, to the load, and is designated the “secondary.” Energy transfer from one to the other is through magnetic induction. The more “turns” there are to the winding, the more impedance it offers, and hence the higher the voltage that is generated across it, but at the cost of current. If the secondary has more turns than the primary, voltage is increased relative to the primary while current is less. This is called a “step up” transformer. Conversely, fewer windings in the secondary create a “step down” transformer of lower voltage, but higher current. Offering “no moving parts”, as an old advertising ploy used to proclaim, such a device can, and does, run for years and years. But no device is perfect, and transformers can, and do, break down, sometimes cataclysmically. Such failures can produce fires causing enormous damage, even to millions of dollars. An important diagnostic method of testing transformers to detect impending breakdown is called turns ratio testing. A direct relationship exists between the number of turns and the voltage ratio of the primary to the secondary, and is expressed by: Vp = Np — — Vs Ns where Vp = primary voltage, Vs = secondary voltage, Np = number of primary turns, and Ns = number of secondary turns. Additional standard notation is to indicate the highvoltage winding with “H”, and the terminations accordingly as H1 and H2. The low-voltage winding is commonly notated “X”, with the terminations designated X1 and X2. The

source voltage can be connected to either set of terminals, depending on whether the transformer is “step up” or “step down.” As a simple example, if the transformer had 480 turns on the high-voltage side and 240 on the low, and a 480 V source connected to “H,” the output would be 240 V, and the transformer a “step down.” If the input were 100 A, the output would be 200. The high-voltage winding would, in this case, be the primary. But if the same source was connected to the X side, the transformer would now output 960 V but only 50 A for 200A from the source, and the low-voltage winding would be the primary. In the first case, turns ratio would be expressed as 2:1, and in the second, 1:2. H1 LEAD

H2 LEAD

X1 LEAD H1

X1

H2

X2

X2 LEAD

TRANSFORMER Figure 1 — Setup for testing single-phase transformer

This fundamental relationship is the basis for one of the most effective methods of testing, evaluating, and maintaining transformers in working condition. The method is called turns ratio testing. In service, the insulation around windings can become damaged or deteriorated, from an array of causes including spikes, surges, contamination, faults, shipping damage, and others. Insulation damage can result in shorts between turns, effectively reducing the number of turns and altering turns ratio to some value deviating from nameplate rating. It is this change in turns ratio that is measured and utilized as an electrical maintenance tool. The extent of deviation from nameplate ratio is a direct indication of

Transformer Handbook — Volume 2 X1 LEAD H1 LEAD

SERIES WINDING

H1 “RAISE” DIRECTION H1 LEAD

SOURCE

X2

L

H2

S R

X1

L

H2 LEAD

X3

X1 LEAD

Remove Ground Connection X2 LEAD

LOAD SHUNT WINDING

H2 LEAD X2 LEAD

SL COMMON

Figure 2 — Setup for testing single-phase, type A (straight design) step voltage regulator

winding deterioration. A transformer will tolerate a limited amount of such deterioration, but it’s a blueprint for ultimate failure. Accordingly, the ANSI Standard C57.12 specifies that turns ratio be no more than 0.5% from rating. Direct measurement of output voltage might seem a ready solution, but doesn’t work in practice. Live voltage measurement is difficult and potentially dangerous, and cannot be performed with the accuracy and sensitivity necessary to make an exacting calculation of turns ratio. Furthermore, any such crudely determined ratio error could be produced by disturbances to the source voltage, rather than deterioration of turns. Voltage measurement is the key to turn ratio calculation, but it must be performed by a dedicated turns ratio tester designed with requisite performance characteristics and sensitivity. A turns ratio tester is essentially a reference transformer modified to be balanced against a load (the transformer under test), measure the balanced voltages to high accuracy, and calculate the resultant ratio. The voltage ratio at “no load” (balanced) condition is for practical purposes the turns ratio. In order to conform to the above-mentioned standard, the tester should be able to measure voltage to 0.1% accuracy, which is hardly attainable with a common voltmeter across live output! Turns ratio testing is performed on de-energized transformers, with the tester providing the test current. The reference transformer and test transformer are connected in parallel, excited, and balanced so that there is zero circulating current, without burden on either transformer. A major source of measurement error is primary impedance drop from magnetizing current. This can be minimized by excitation at a fraction of rated voltage. The tester should be able to measure “no load” voltage ratio with little excitation voltage. Testers typically operate at around 8 V, and may have multiple test voltages down to a fraction of a volt. A sophisticated tester will limit excitation current to some appropriate level (an example being 100 mA), then

Figure 3 — Setup for testing X1 - X3 winding of distribution transformer

autorange to lower test voltages to prevent exceeding the limit. For the higher demands of three-phase transformers, test voltages up to 100 V are available. Precise measurement is further implemented by various design techniques, including applying excitation voltage to the low side, and by a reference transformer with an alloy core of high permeability and an exciting winding of low resistance. By exciting the low voltage winding, required excitation power, exciting losses, and voltage drop in the winding are low, facilitating high measurement accuracy. Older models, many still in use today, employed magnetic operation through a vibrating reed. As it vibrates, the reed contacts the poles of a double-pole, double-throw switch, rectifying the signal to dc. The operator balances a series of windings on the reference transformer until no current flows. At this point, there is no deflection of the null detector, and turns ratio is read by the settings of the decade dials. Reeds have sensitivity issues on both ends of the scale, thereby circumscribing their use. If the operation was stepdown, by applying excitation to the high-voltage winding, the resultant voltage might be too low to accurately measure. An amplifier would be required in order to cover a practical range. The reverse configuration, exciting the low voltage winding, enables the tester to be smaller, lighter, and easier for field use. Later designs substitute a synchronous rectifier for the vibrating reed. Turns ratios of 0.001 to 130 are typical, but the higher ratios of large transformers could not be tested by this basic technique. Other techniques, employing line voltage and capacitor banks, were used, but these methods were potentially dangerous and destructive. High voltage transformers could be “cascaded” through a series of step-downs, but this required tedious hand calculations, and suffered loss of accuracy. The heightened sensitivity of microprocessor technology now enables transformers of all ratios to be measured directly, with ranges to values of 45,000. Low-end ranges to 0.001 facilitate measurements in conformance with the ANSI accuracy requirement mentioned above. With this degree of sensitivity, low test voltages can be applied to the high voltage winding, with the commensurately lower output voltages accurately measurable. This reversal of configuration eliminates the problem of dangerous voltages generated by the earlier step-up configuration.

Transformer Handbook — Volume 2 H2 LEAD

H1 LEAD

POLARITY DOT

X1

With recent improvements in technology, the benefits of turns ratio testing may now be applied to all transformers, even of the highest ratios, with convenient, portable testers affording light weight, enhanced safety, and maximum accuracy.

X2

X2 LEAD

BUS OR USE HEAVY GAUGE LEAD WIRE CT X1 LEAD

Figure 4 — Setup for testing unmounted current transformer

Success of the operation depends as much on the operator’s knowledge and available information on the transformer’s wiring diagram as it does on the capabilities of the tester. Figs. 1-3 show typical setups, for a singlephase transformer, a voltage regulator, and a distribution transformer, respectively. Current transformers (CTs) present a particular challenge. CTs are used to measure the current in a phase. One of their main uses is at the transfer of ownership of electricity. Toroidal CTs in this application have windings along the entire circumference of the core. Most CTs have ratios less than 1000:1. Frequently, they are used in a “cascading mode”; that is, the current in the main is too high to measure accurately with only one CT. A winding of the first CT will pass through the core of the second CT. The output of the second CT is sufficiently low to be measured directly. The ratios of both cascading CTs need to be measured accurately in order to determine the actual current in the main. Low voltage testers are ideally suited for this application because they avoid saturating the core. To measure, one of the X leads makes a complete loop through the toroid to contact the other X lead. If the opening is not large enough, a wire can be substituted, making one full loop, with the X leads connected across the ends (Fig. 4). The H leads are connected to the output terminals of the CT, and the measurement taken. Low-voltage testers are requisite because the low winding resistance of CTs would cause the core to saturate at higher test voltages. Two corollary functions frequently performed are excitation current measurement and phase displacement (polarity). Excitation current is the current the tester applies through one winding in order to generate voltage across the other. Its measurement helps detect shorted turns or unequal number of turns connected in parallel, and provides information about the condition of the core. Unwanted circulating currents, unintentional grounds, or incipient short circuits can affect the exciting current. Identification of normal (in phase) and reverse polarity determines proper connection within a power network.

Jeff R. Jowett is Senior Applications Engineer for Megger in Valley Forge, PA, serving the manufacturing lines of Biddle®, Megger®, and Multi-Amp® for electrical test and measurement instrumentation. He holds a BS in Biology and Chemistry from Ursinus College. He was employed for 22 years with James G. Biddle Co. which became Biddle Instruments and is now Megger.

Transformer Handbook — Volume 2

Large Power Transformer Condition Assessment and Life Extension T

orld

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2

b ichard K Ladroga, P E Doble Engineered trategies

The conceptual model of deregulation of the United States electric utility industry was never fully completed before numerous states adopted some type of privatized format and began unsteady implementation. The consequences of this exercise in experimentation (with arguably the most critical infrastructure of modern times) are numerous. One such example of significant consequence is the overall health of the general population of large power transformers (LPTs) in the United States. LPTs are now subject to adverse conditions due to advanced aging, decreases in routine testing and maintenance activities, reduction of capital for repair and replacement, increased loading, and lack of technical expertise due to early retirements and corporate mergers, all spawned by a deregulated business environment. Compounding this blend of market drivers is the unsettling fact that the vast majority of US based LPT manufacturing concerns (100 MVA and up) have departed the industry, leaving owners of this equipment faced with the challenging task of venturing outside the borders of the US to purchase new units. The lack of domestic based manufacturing creates a number of related issues, including long distance travel, shipping, communication difficulties, and a local technical expertise resource drain. LPTs (10 MVA and up for the purpose of this article) support the backbone of the electric grid system. There are approximately 150,000 transformers rated 10 MVA or greater presently installed in the United States. It has been estimated that the vast majority of the installed large power transformer capacity in the US averages approximately 30 years of age or older. As the US fleet ages, asset owners begin to run out of options and ultimately all are faced with the same basic choices. The owners of LPT assets

are faced with an oftentimes onerous decision: replace an aging unit with a new unit, oftentimes from an offshore manufacturer, or continue using the existing unit with the “hope” that it keeps on cranking out the megawatts. With new units costing anywhere in a range from several hundred thousand dollars to multimillion dollars, it is imperative that this critical decision is made with the best data and information available. Fortunately today’s asset and risk managers have a varied array of tools at their disposal to help gather critical information necessary to make informed decisions. The methods presented in this article provide the reader with a blueprint to successfully determine the overall health and condition of LPTs. These methods consist of oil and electrical diagnostic testing, visual inspections, historical data trending, design review, and operations/loading/ maintenance/repair review.

Oil Diagnostics Perhaps the simplest and least costly method of quickly assessing the general health of a LPT is to take a sample of the insulating oil. Oil sampling of a transformer is analogous to taking a blood sample from a human. Many different parameters and conditions can be assessed from an oil sample. To a trained eye, oil diagnostics provide a solid method to gain a significant amount of insight into the current state of health of a unit. One major advantage of oil testing is that the sample can easily be taken while the unit is on-line, eliminating the need for an outage. The most commonly performed oil tests are listed below:

Transformer Handbook — Volume 2 TABLE 1 Most Recommended Tests for In-Service Transformers Test Description

ASTM Method

Neutralization Number (Acidity)

D 974

Dielectric Breakdown Dielectric Breakdown Interfacial Tension Color Water Content Specific Gravity

Visual Examination Power Factor Dissolved Gases in Oil

D 877 D 1816

D 971 D 1500 D 1533B D 1298 D 1524 D 924 D 3612

Sometimes more information is required, or perhaps a problem is suspected and additional tests are needed to help pinpoint the issue. There are a number of additional ASTM tests available for oil diagnostics. Some of the more routine additional tests are often performed in such cases and are listed below:

TABLE 2 Additional Tests for In-Service Transformers Corrosive Sulfur Furanic Compounds in Oil Inhibitor Content

Metal-in-Oil Analysis Dissolved Metals Particulate metals (Copper, Lead, Zinc, Iron)

D 1275 D 5837 D 2668

Dissolved Gas-in-Oil Analysis Dissolved gas-in-oil analysis (DGA) is the most commonly requested oil diagnostic test performed on transformer oil. All LPTs contain insulating materials that break down due to excessive thermal or electrical stress, forming gaseous by-products. These by-products are indicative of the type of activity present within the transformer, such as an incipient-fault condition. The DGA can also shed light on the materials involved and the severity of the condition. DGA is a powerful tool for detecting incipient-fault conditions and for investigations after failures have occurred. Additionally, dissolved gases are detectable in low concentrations, which oftentimes allows for early intervention before failure occurs and allows for planned strategies as opposed to unplanned catastrophes. Typical gases generated from mineral oil/cellulose (paper and pressboard) insulated transformers include hydrogen, methane, ethane, ethylene, acetylene, carbon monoxide, and carbon dioxide.

The composition of gases generated provides information about the type of incipient-fault condition present. For example, four general categories of fault conditions have been described and characterized by Key Gases in Table 3.

TABLE 3 Categories of Key Gases and General Fault Conditions KEY GASES Methane, ethane, ethylene, and small amounts of acetylene

GENERAL FAULT CONDITION Thermal condition involving the oil

Hydrogen, methane, and small amounts of acetylene and ethane

Partial discharge

Hydrogen, acetylene, and ethylene

Sustained arcing

Carbon monoxide and carbon dioxide

Thermal condition involving the paper

A single sample will provide a snapshot of the transformer at a moment in the unit’s history. However, the best use of oil diagnostics is to trend the recent data with all other test data taken over the life of the transformer. Trending the data illustrates changes in the transformer that may go undetected in a single test. An example of an adversely trending condition in a LPT is shown in Table 4. In this example, several key gas concentrations have increased significantly, a direct result of a serious problem located within the unit.

Electrical Diagnostics There are a number of highly effective electrical diagnostic tests available to help determine the existing health and overall condition of a LPT. A list of the most commonly performed tests is presented below followed by a brief outline of the purpose of each test:

Winding Power Factor — This test measures the power loss through the insulating system caused by insulation deterioration, contamination, and mechanical deformation. Abnormally high or low values of power factor, dielectric loss, capacitance, or leakage current indicate a failure of the insulation system. Bushing Power Factor — This test also measures power loss through the insulating system of the bushing. Many transformers have been saved from certain failure over the years through the detection of imminent bushing failure through use of the power-factor test. Leakage Reactance — This test is useful in detecting winding movement or core and coil displacement in LPTs. Transformer Turns Ratio — The TTR test is used primarily as an acceptance test, but can also be useful after an event to determine if the windings are short circuited.

Transformer Handbook — Volume 2 TABLE 4 Typical Example of a Large Power Transformer Gassing History (High Temperature Incipient Fault) Sampling Dates GAS

12/23/01

6/21/02

12/12/02

3/20/03

6/19/03

9/17/03

12/18/03

12/24/03

Hydrogen

0

1

0

4

17

79

170

298

Oxygen

30200

33700

30100

37200

31600

30700

30000

35300

Nitrogen

65300

67300

69000

86600

74400

65700

67900

61500

Methane

3

7

6

9

11

34

57

87

Carbon Monoxide

25

21

92

74

76

73

92

113

Ethane

0

0

2

5

11

36

44

69

Carbon Dioxide

2600

1990

2900

3100

2950

2470

3760

5830

Ethylene

1

3

20

34

95

160

211

334

Acetylene

0

0

0

1

3

5

23

33

DC Winding Resistance — This test is used to identify a change in dc winding resistance resulting from shorted turns, defective joints, or bad contacts.

Core Excitation Current — This test measures the current required to excite the transformer core. High values of excitation current are generally indicative of shorted turns or core damage in the transformer.

Core Ground — This test is used to identify inadvertent core grounds which cause unwanted circulating currents to flow, often leading to overheating situations. This test can only be performed in the field if the core ground is accessible.

(Sweep) Frequency Response Analysis (SFRA) — This test is very successful in identifying core and coil anomalies such as shipping or short-circuit mechanical damage. This complex test essentially injects a signal into the coil and measures the output response at varying frequencies. Numerical analysis and fast Fourier transforms (FFTs) are used to transfer the numerical analysis into a graphical image for visual analysis. In short, the output response (signature) of the coil is like a fingerprint. If some event like a short circuit or bump causes a shift in the core and coil assembly, the graphical traces will not line up properly, indicating a problem.

Additional Tests

Figure 1 — Three Phase HV Winding

Some additional tests that can provide useful information for overall transformer health include power-factor tip-up testing, partial-discharge analysis, vibration analysis, and thermography.

Transformer Design — Family Review All transformers have similar designs, but differences do exist between models and manufacturers. A typical assessment should include an evaluation of the unit ratings (nameplate), tank design, core/coil design, load tap-hanger (LTC)/de-energized tap-changer (DETC) design, oil thermal expansion design, bushing design, arrester design, and known common mode failure mechanisms.

Visual Inspection

Figure 2 — Three Phase HV Winding – Shorted Turns

A thorough external visual inspection is recommended as a complement to the diagnostic testing. Items such as gaskets, pumps, fans, coolers, LTC compartments, control cabinets, piping and conduit, bushings, arresters, conductor connections, grounding, tank condition, oil containment, gauge observation, pressure relief valves, and virtually anything else attached, connected to, or mounted on the transformer should be inspected and addressed.

Transformer Handbook — Volume 2 Maintenance Record Review The maintenance history of the unit should be reviewed to help determine its condition. Issues such as oil leaks, oil processing/degassing, fan repairs/replacement, pump repairs/replacement, LTC work, or any other maintenance of the unit since it was originally placed in service should be considered in the assessment.

Operating Record Review The operations and loading history should be reviewed to determine if the unit was ever exposed to overcurrent or overexcitation events, short circuits, through faults, harmonic distortions, operational limitations, grid disturbances, lightning strikes, transient phenomena or any other detrimental conditions. The loading history can be used to establish benchmark data for a thermal analysis of the unit in an effort to determine loss of life.

Summary Large power transformers are very valuable assets. The life of these assets can be extended for long periods of time through the use of advanced diagnostics as described throughout this article. As a result, the life expectancy of LPTs has risen significantly over previous assumptions. There are a number of transformers remaining in service in the United States that are 60, 70, and even 80 years old, and they are still going strong!

References 1. Ladroga, R. K., Switchyard Transformers Overlooked in Power Quality Equation, Power Engineering Magazine, October 2003

2. Ladroga, R. K., Griffin, P. J., McGrail, A. J., Heuston, G. A., McKenney, P. M. Advanced Diagnostics Support Critical Decision Making, Proceedings of the SeventySecond Annual International Conference of Doble Clients, 2005, Transformer Session TX-2

3. Griffin, P.J. Criteria for the Interpretation of Data for Dissolved Gases in Oil from Transformers (A Review), Special Technical Publication 998, ASTM, Philadelphia, PA, 1998, pp. 89-107. 4. Clark, F. M. Insulating Materials for Design and Engineering Practice, John Wiley and Sons, Inc., New York-London, 1962.

5. Griffin, P.J., Lewand, L.R. Transformer Case Studies, Proceedings of the Sixty-Sixth Annual International Conference of Doble Clients, 1999, Sec. 5-7 6. Griffin, P.J., Lewand, L.R., The Effective Use Of Laboratory Analysis Of Insulating Oils As A Maintenance Tool, Proceedings of the 2000 International Conference of Doble Clients - Sec 5-8

7. Horning, M., Kelly, J., Myers, S., Stebbins, R. ,Transformer Maintenance Guide, Third Edition, Transformer Maintenance Institute, S.D. Myers, 2004 8. Heathcote, M. J., J & P Transformer Book, Twelfth Edition, Newnes, Oxford, Woburn 1998

Richard K. Ladroga, P.E., is the Manager of Business Development for Doble Engineered Strategies, concentrating on electrical power apparatus testing, condition assessment, and forensics. He earned the B.S. in Electrical Engineering (Power Systems) with Distinction from Worcester Polytechnic Institute. He has authored a number of publications. He has served as Chairman of the IEEE Power Engineering Society Education and Seminar Committees in Boston and presently serves as Vice-Chairman of the Insulating Fluids Subcommittee of the IEEE Power Engineering Society Transformer Committee. He is also a Board Certified Diplomat of the National Academy of Forensic Engineers.

Transformer Handbook — Volume 2

The Role of Test Voltage and Current Levels in Transformer Condition Assessment — Is There a Better Way? T

o erTes 2 nnual Te n al onferen e Alex o as egger

Abstract Condition assessment of transformer core-coil assembly, at the factory or in the field, includes three fundamental tests: insulation power factor (tan delta), transformer turns ratio and winding resistance. Although these tests can be performed with decades-old technology, users have voiced their need for safer, faster, and more portable test devices. This need calls for a review of what makes older test equipment operate at higher voltages and currents. The geometric and material properties examined when performing such tests is discussed. Why the need for higher test voltages when measuring insulation power factor: is it interference mitigation or true material condition assessment? Further, a discussion on the role of applied voltage and current is given as it relates to core saturation when performing winding resistance tests. Modern high-power electronics and microprocessor controllers offer alternative methods for packaging test instruments while maintaining accuracy, and improving safety, speed and convenience. The importance of observing reliability guides and standards in product design is acknowledged.

Introduction Demand for methods and instrumentation to determine the condition of insulating components, assembled into power apparatus, came with the vast expansion of electrical power systems during the first half of the twentieth century. Insulation failures prompted the industry to develop and implement maintenance programs. The electrical industry was on a steep learning curve and system voltage such as 110 kV were considered very high at that time [1]. As it is today, early testing methods and instruments were meant to assess the condition of the insulation system at time of testing. Further efforts were made to predict the service life

of equipment based on collected data. However, electricity was a relatively new field at that time and long term deterioration of insulation was less well understood. Chronologically, dc insulation test instruments were employed first. Then and now, test sets measured insulation resistance in MEGOHMS and were/are typically conducted at higher voltage levels on equipment that was designed to operate at higher potentials. One marked difference versus subsequent ac test methods is that voltage stress is distributed distinctively. When applying a dc voltage across the terminals of the equipment under evaluation gradients developing within its assembly are distributed according to the localized insulation resistance. Conversely, when utilizing ac, gradients are distributed according to another material/geometric property - namely capacitance. The second method, an ac test, was typically referred to as the measurement of “Capacitance and Power Factor” (C&PF) in North America and as “Capacitance and Dissipation Factor” (C&DF) in Europe. To this date, specialists argue about the value of each test, dc vs. ac, which provides more information, and which is more useful in forecasting the life of electrical insulation [1]. At factory, fully assembled transformers are tested for compliance to previously determined performance levels. Most end-users refer to domestic or internationally accepted standards/guides (i.e. ANSI, IEC, NMX, etc.) to communicate their specific factory test requirements and performance levels. In defining tests for medium/large power transformers, many users make exceptions to standard test levels and procedures in order to fit their custom design requirements. Once in the field, acceptance tests are performed prior to putting the power transformer into service. These are principally done to determine if damage in shipping has occurred and to confirm proper reassembly of some components taken out for shipping. Another very valuable product

5

Transformer Handbook — Volume 2 of initial field testing is that base line results will provide the best yardstick for determining the transformer’s future condition. Further, this initial assessment is being conducted under field conditions and using similar test equipment that will be utilized in subsequent testing. Numerous field test protocols are observed today in determining the condition of the material and geometry in the transformer dielectric and conductive (electrode) components. Test programs include all or part of the following: winding and bushing power factor, leakage reactance, winding turns ratio, winding resistance, core excitation current, core loss and excitation power factor, core ground, Sweep Frequency Response Analysis, and more. Three of the above tests are fundamental and common to most protocols and have been chosen to illustrate the role of test voltage and current levels in transformer condition assessment: winding power factor, winding turns ratio, winding resistance.

Winding Power Factor C&PF testing of electrical insulation has been embraced by many in the insulation field as it provides information on the dielectric constant of the insulating materials as well as the dielectric losses. The dielectric constant is an intrinsic material property that influences the capacitance between two electrodes at different potential. In turn, the capacitance influences the voltage gradient distribution within assembly components. Uneven concentration of high voltage gradients in the insulation, typically measured in kV/mm, contributes to increased dielectric power loss where the gradient is higher. In turn, higher power loss heats the insulation. Localized hot spots may develop which start deteriorating the insulation that would eventually lead to dielectric failure. For example, one of the byproducts of insulation decomposition is water. As water content in the insulation increases, so does its power loss (Watts). The detection and removal of moisture from equipment is very important, as the presence of moisture causes the insulation to deteriorate faster. As a transformer with a 2.5% moisture content ages ten times faster than the transformer at 0.25% moisture, it is imperative to detect and rectify such a situation [1]. In practical terms, a C&PF test instrument sees a two winding transformer as if it were a three terminal capacitor illustrated in figure 1. The “H” electrode represents all HV conducting components (three windings tied together in three-phase equipment). Likewise, the “L” electrode represents all LV conducting components. The transformer tank, typically grounded, is represented by the electrode “G”.

Figure 1 — Transformer Without Tertiary Windings

In the simplest terms, power factor expresses the ratio of values obtained from applying ac voltage across any capacitor equivalent component illustrated above: Power Factor =

Watts absorbed in insulation Applied Voltage x Charging Current

(1)

Therefore, it is not surprising that early instrument configurations for conducting this test were made up of a set of the following components: wattmeter, voltmeter and ammeter. The power factor definition in equation (1) applies equally in power delivery to electric loads, as it does to insulation systems. However, optimum operating points are at opposite positions. When designing/operating power delivery systems, we strive for maintaining the PF closest to unity. Whereas, when designing/operating insulation systems we target a number closest to zero. Figure 2 helps visualize the current vector which develops from applying the above described test voltage V. The current taken by an ideal capacitor (no losses, Ir = 0) is purely capacitive, thus leading the voltage by 90° ( = 90°). In practice, no insulation is perfect but has a certain amount of loss, and the total current I leads the voltage by a phase angle ( < 90°). Some find it more convenient to use the dielectric-loss angle , where = (90° - ). For low power factor insulation Ic and I are approximately the same magnitude since the loss component Ir is very small. Basic trigonometry yields the following relationships: Power Factor = cos

= Ir I

(2)

and the dissipation factor is defined as: Dissipation Factor = tan =

Ir Ic

(3)



Transformer Handbook — Volume 2

Figure 2 — Test Current Components

Power factor is particularly recommended for detecting moisture and other loss-producing contaminants in transformer windings and bushings. Some argue that the power-factor test is more revealing than the dc insulationresistance test when there is a high-loss dielectric in series (as in a transformer winding surrounded by oil), and is less influenced by surface leakage components. Other users have reported cases where high-power-factor readings indicated moisture in the windings, while the oil dielectric tests were up to standard [2]. Realizing the benefits of C&PF testing, field test instrumentation and techniques operating at lower voltages were devised. Early on, a test voltage of 2.5 kV was used. The selection of such test voltage was justified by two criteria:

It was sufficiently high to provide an acceptable signal-to-noise ratio in (then) typical field applications. The typical insulation to be tested was an oil-paper assembly.

Oil-paper insulation systems exhibit flat capacitance and loss curve with respect to test voltage. Thus, measurements at voltages lower than rated could be readily used to represent the insulation characteristics at rated voltage [1]. Dry-type insulation, however, exhibits an increase in power factor values within 2.5 kV and 10 kV. Motors, generators or smaller transformers with dry assemblies have been typically tested at several voltages in order to determine the tip-up for the insulation. Such tip-up may be at 100%, 50% and 25% of the phase-to-phase voltage, or 100%, 50% and 25% of rated phase voltage. As the electric power transmission and distribution industry evolved it increased system operating voltages to transmit more power. Operators managed to keep line losses as low as possible by keeping line currents at acceptable levels, while transmitting larger amounts of power at higher voltages. This new field test environment brought on a new challenge to test instrumentation manufacturers: immunity to electrostatic interference. Consequently, the 2.5 kV test level was increased to 10 kV in order to provide an acceptable signal-to-noise ratio. Some went even further to device

test sequences where 10kV is applied at frequencies other than the fundamental 60 or 50 Hz. One of these methods initially applies test voltage at lower than power frequency; to overcome the frequency bias, a second test is performed at higher than power frequency. The test result is the average of both. Still another approach uses a modulated test voltage, avoiding the power frequency by producing test voltage with two frequency components - one above and another below the power frequency. From the above description, it is evident that current and future test instruments can benefit from power electronics that would readily and reliably control the magnitudes of their test voltage, current, and frequency. Along with the rapid evolution of digital signal processors (DSP) the power industry has seen an evolution in high power switching devices that these DSP devices would control. High-power semiconductors have evolved from early thyristors, to gate turn off thyristors (GTOs), gate commutated turn off thyristors (GCTs), and more recently high/low voltage insulated gate bipolar transistors (IGBTs) [3]. Recent industry trends show a preference for Insulated Gate Bipolar Transistors (IGBT) which is a maturing technology widely used in the following applications [4]: Industrial/Commercial: Uninterruptible Power Supplies (UPS), motor drives for steel mills, pumps, blowers, etc.

Traction: Electric locomotives, subways, light vehicles, etc. Electric power transmission/distribution networks: flexible ac transmission systems (FACTS); static VAR compensators (SVC), variable speed pumped storage, etc.

In many of the above applications a digital signal processor commands an IGBT set to synthesize or modulate a voltage waveform to operate in four quadrants as shown in figure 3.

Figure 3 — IGBT Four Quadrant Operation

Transformer Handbook — Volume 2 Figure 4 depicts a commercially available transistor rated at a blocking voltage of 6.5 kV. Its approximate dimensions for length, width and depth are as follows: 7.5 x 5.5 x 1.5 inches.

The benchmark used for comparison of test values is the nominal or nameplate voltage ratio. It is defined as the line-line voltage of the primary winding to the line-line voltage of the secondary winding at no-load. Since the noload voltage ratio is directly proportional to the turns ratio, the following relationship holds true.

where:

Figure 4 — Commercially Available 6.5kV IGBT (Source: ABB Sales Brochure)

The above illustrated flexibility for adapting to a varying range of reactive loads offers an immediate opportunity for improving power factor test set packaging. Namely, handling the reactive power demand posed by test specimens with larger capacitance values (i.e. large generators). Today’s leading power factor test instrument suppliers require the use of a large “resonating inductor” when test specimens exceed certain capacitance value. A future IGBT power supply, supported by moderately sized inductors, would adapt readily to a wide range of test specimen capacitances. High-voltage IGBT semiconductor technology has matured and been embraced by most in the electric power network industry and many in the traction business. Single unit commercially available voltage classes include 3.3 kV, 4.5 kV and 6.5 kV components. Such offering provides test instrument power electronics designers with new alternatives to package high-voltage power supplies. Potential savings in assembly weight, size and cost are very real. From a test signal measurement circuitry perspective, the industry would benefit from novel approaches to filter-out interference. Traditional tools of harmonic analysis are generally based on Fast Fourier Transforms (FFT) which assume that only harmonics are present and the periodicity intervals are fixed. However, periodicity intervals in the presence of interharmonics are variable and very long [5]. New signal analysis methods are being proposed to take this characteristic into account.

Transformer Turns Ratio One other fundamental test procedure, at the factory or in the field, is the transformer turns ratio test. It is meant to detect: turn-to-turn winding contact (or short) due to damage to paper/enamel covered structures during assembly, open turns or connections, correct polarity of windings, improper routing and connection of leads, etc. The assembly of de-energized tap changers (DETC) and load tap changers (LTC) involves complex arrays of lead connections. Final turns-ratio testing of all tap combinations would ensure proper operation.

Turns Ratio = Np ≈ Vp Ns Vs

(4)

Vp = Primary Voltage Vs = Secondary Voltage Np = Number of Primary Turns Vs = Number of Secondary Turns

The slight difference between the ratios is caused mainly by the voltage drop in the winding that results from the magnetizing current flowing through the same. This voltage drop varies largely due to test voltage and test frequency. For most power and distribution transformers this difference is less than 0.1% or 0.001. Considering the above relationships, early and contemporary turns-ratio test sets have been designed with the principle illustrated in figure 5. The test transformer’s winding terminals H1 and H2 are connected in a series opposing configuration through a null detector to a variable turns winding of a reference transformer. This transformer is located inside the test instrument and has known turns ratio. Terminals X1 and X2 are connected to the fixed-turn winding of the reference transformer; while both linked to the same excitation source. The voltage ratio of both transformers is equal when the variable winding is adjusted so that no current flows in the null detector.

Figure 5 — Traditional TTR Instrument Configuration

A major cause of measurement error is the test specimen’s primary resistance drop from excessive magnetizing current. Limiting the instrument’s test voltage to a fraction of the specimen’s winding rated voltage will mitigate this condition. Test instruments have operated at low voltages (i.e. 2, 5, 8 volts) typically excite the transformers from the LV winding. Alternatively, test voltages of 80 and 100 volts have been employed to excite the HV winding of larger three-phase power transformers.

Transformer Handbook — Volume 2 Today’s electronic-based instrument models will limit excitation current to a few hundred milliamps for the first iteration, stop if limit is exceeded, auto range to a lower voltage, and iterate again. The typical principle of operation is to sense and measure the specimen’s primary and secondary winding voltages from where a turns-ratio is calculated and displayed. In figure 6 the test excitation voltage is applied through the H winding lead select circuitry. The same voltage is applied to the reference conditioning circuitry. The test voltage output is captured through the X lead. The TTR’s measurement circuitry is isolated from the specimen by the range and reference conditioning stages. The reference and range A/D converters translate analog signals to digital equivalent for interfacing with the microprocessor. All steps in the TTR’s operation are managed by the microprocessor. These include: providing sequence of operation, gathering and calculating test results, interfacing with the display, printer port, and control circuitry. Proper control sequence of virtually all the above described components is provided by their central interface: the control stage.

Figure 7 — Wheatstone Bridge Configuration

The measurement of the unknown, RX, is made in terms of three known resistors: RA, RB and RS which is adjusted for zero current in the null detector circuit. Once the bridge is balanced, the unknown RX is obtained from the following relationship:

where:

RX = RA * RS RB

(5)

RX = Unknown resistance RA, RB = Ratio resistors RS = Variable resistor

Accuracy in measurement of low resistance specimens became a challenge. The effects of lead and contact resistance needed to be taken into account. Thus, test instruments evolved to acquire the Kelvin bridge configuration. Figure 8 illustrates how the basic Kelvin bridge configuration differs from the Wheatstone bridge by two ratio arms. Figure 6 — Microprocessor-Based TTR Instrument Configuration

Winding Resistance While the turns ratio test will give a quantitative indication of proper routing and connection of leads, it will not tell us the quality of such conducting paths. At factory and in the field the winding resistance test is used to qualify the ability of various electrode paths to conduct current at or near design levels. This test is intended to detect high resistance conditions at any metal-to-metal interface in the assembly: tap changer connections, bushing connection, winding connections, etc. In addition, at the factory, winding resistance measurements are used to calculate the I2R component of conductor losses, and to calculate the winding temperature at the end of a heat run. Like the TTR tests, traditional test instrument configurations have employed a null detector in a bridge circuit principle. Figure 7 illustrates the basic circuit configuration of a Wheatstone Bridge.

Figure 8 — Kelvin Bridge Configuration

Transformer Handbook — Volume 2 When the Kelvin bridge is balanced, the specimen’s resistance is calculated from the following relationships: If then, where:

RA = Ra RB Rib

(6)

RX = RS * RA RB

(7)

RX = Unknown resistance RA, RB = Ratio resistors Ra, Rib = Ratio arms RS = Variable resistor RY = Yoke (link) Resistance

The traditional instrument configuration employed small adjustable resistors to balance the lead effect between the bridge terminals and the voltage terminals of the resistors. Another instrument configuration provided a high-resistance shunt around the a or b arm until A/B = a/b with the yoke removed. Winding inductance poses a sobering challenge to obtaining stable readings when testing transformers. For simplicity, let’s consider a two-winding transformer. The voltage components of the winding under test can best be expressed as follows:

where:

V = i*R + L * di dt

(8)

V = Test voltage across transformer winding I = Test current thru transformer winding R = Transformer winding resistance L = Transformer winding inductance di = changing value of current dt

Saturating the core would bring the winding inductance closest to zero thus allowing current stabilization for proper measurement. The necessary amount of volt-seconds [VS] must be applied to the core for saturation; since it is a measure proportional to the core flux. The rated voltage of the winding under test dictates the required amount of volt-seconds. For example, a winding rated at 110 kV @ 50 Hz would require the application of approximately 600 [V-S] in order to saturate the core [6]. Variations from this calculated amount would depend on any residual magnetism in the core and the polarity of the applied current. The actual volt-seconds required for saturation may vary from about 150 to about 1000 [V-S]. This analysis suggests that a carefully controlled test voltage magnitude is needed to speed-up the magnetization process. An instrument will take 5 to 30 seconds to saturate the above discussed transformer when providing an output of approximately 30 volts [6]. A microprocessor controlled instrument would optimize the amount [V] and time [S] of the applied test voltage to increase the speed of producing a stable reading.

Last and most important is discharging safely from core the energy stored during the test sequence. A consciously designed instrument would benefit from digital signal processors to automatically provide a path to remove the stored energy and display a signal to indicate that it is safe to proceed with the removal of the test leads.

XIII. Design Reliability Considerations A structured approach to equipment reliability has traditionally been employed by the Military, Space and Aerospace industries. At significant cost, these businesses have long had to mitigate the risk of implementing failure-susceptible designs. They have devised, documented and matured certain guidelines and practices to minimize poor reliability. Other industries have not consolidated their approach to product reliability but are starting to model practices after already established philosophies. In the electric power industry, the increased usage of electronic apparatus has prompted end-users to consider the effect of incorporating these complex assemblies in the reliability of the complete network. Notable examples are the power quality industry and the voltage/current sensor business in the USA and Canada. For example, an increasing number of end users are referring to military guidelines to assess the reliability of Uninterrupted Power Supply equipment (MIL-HDBK -217). The objective of this section is to review aspects, applicable to our industry, of an established reliability program. The underlying message conveyed here is that reliability must be planned into the product at the onset of any design program. The reliability framework highlighted below is based upon military standards, handbooks and specifications. This non-civilian application should not cause us to ignore its validity to the power industry - including test instrumentation. So what are the main standards and specifications used by reliability engineers in the military and related industries? The following is a list of the notable standards and handbooks adopted by the Reliability Engineering discipline [7]: MIL-STD-785 - Reliability Program for Systems and Equipment Development and Production. This standard provides guidelines, in the form of tasks, which need to be completed as part of an overall reliability program. Its premise is that if reliability is planned and incorporated into a design the reliability of the final product will be inherent. MIL-HDBK - 217 - Reliability Prediction of Electronic Equipment. The handbook details two methodologies for reliability estimates: the parts count method and the parts stress analysis method. Full details on how these methodologies are applied to product designs are described in the standard. MIL-HDBK-2164 - Environmental Stress Screening for Electronic Equipment. The handbook provides a technique for identifying latent defects in production systems.

Transformer Handbook — Volume 2 MIL-HDBK-470 - Designing and Developing Maintainable Products and Systems. The handbook describes, in a similar vein to MIL-STD-785, how maintainability can be planned into a product with all the benefits that ensue.

Reliability is obviously critical to product performance but it is not the only critical parameter. Availability is another parameter that is crucial to a product’s performance. It is a measure of the ease with which the fault can be identified, the faulty component replaced, and the system pronounced fully functional. A product designed with high availability in mind will minimize its downtime and optimize its availability. The initial conceptual design and architecture of any product must determine the maintenance philosophy and strategy. The best design (from a maintenance standpoint) is a modular one. Each module can then have some form of failure notification and be easily removed and replaced with a fully functional spare. Therefore, the issue of maintainability is complex since it encompasses module design, alarm notification together with failure identification, failure propagation, ease of module removal, spares policy and interchangeability.

Summary and Conclusions A historical review of the characteristics of applied test voltage and currents leads us to realize that they have not necessarily been implemented to accommodate for testing a given material or geometric property in the transformer. In some instances, the current state of art in instrument technology has taken precedence. A closer look at the material and geometric properties examined when performing such tests uncovers that a measured amount of applied test energy is the best method for optimizing performance. Yes, there is a better way: modern high-power electronics driven by microprocessor controllers offer promising methods for packaging test instruments while maintaining accuracy, and improving safety, speed and convenience. The reliability of the instrument is inherent if it is planned and incorporated into its design; by observing guides and standards, at the onset of its development program.

References [1] Oleh Iwanusiw, “Capacitance and Power Factor testing of Electrical Insulation”, Application Note, August 2005.

[2] US Bureau of Reclamation, “Testing Solid Insulation of Electrical Equipment”, Volume 3-1, 2000

[3] Katsumi Satoh and Masanori Yamamoto, “The Present State of the Art in High-Power Semiconductor Devices”, Proceedings of the IEEE, Vol. 89, No. 6, June 2001. [4] Sibylle Dieckerhoff, Steffen Bernet, ”Power LossOriented Evaluation of High Voltage IGBTs and

Multilevel Converters in Transformerless Traction Applications”, IEEE Transactions on Power Electronics, pp. 1328-1336, Vol. 20, No. 6, November 2005

[5] Z. Leonowicz, T. Lobos, and Jacek Rezmer, “Advanced Spectrum Estimation Methods for Signal Analysis in Power Electronics,” IEEE Transaction on Industrial Electronics, pp. 514–519, Vol. 50, No. 3, June 2003 [6] Oleh Iwanusiw, “Measuring Transformer Winding Resistance”, Application Note, May 2001.

[7] Gary Nicholson, “Reliability Considerations: Optical Sensors for the Control and Measurement of Power”, Proceedings of the IEEE Transmission & Distribution Conference. 2001. Mr. Rojas is a Senior Applications Engineer at Megger. He supports internal and external customers in the use of test instrumentation for condition assessment of substation and distribution equipment. He joined Megger in 2004 from Beacon Power Corporation where he was Applications Engineering Group Leader contributing in the development and application of power quality solutions for the utility and distributed generation markets. From 1996 until 2001 he was an R&D consulting engineer at ABB’s US technology center in Raleigh, North Carolina. At ABB he led projects ranging from applied research through design and manufacturing implementation of new power distribution equipment. His projects included long-term R&D assignments in Europe and product launches throughout South/Central America. Prior to this role, he served five years as design engineer at an ABB transformer design and manufacturing facility which later became Waukesha Electric Systems. In Waukesha he was responsible for the electrical, electromechanical, and thermal design; as well as test program definition of oil-filled power transformers. Mr. Rojas has an MSEE with highest honors from Michigan Technological University (thesis topic: Dielectric Breakdown in Board/Oil Interfaces), and a BSEE from The Ohio State University. Mr. Rojas is a member of NETA and IEEE.

Transformer Handbook — Volume 2

Transformer Testing — Are You Missing the Test Point? T

orld

rn 2

b ic oungblood A erican Electrical esting Co

It is common knowledge that transformer cost comprises anywhere from 40-60 percent of the price of a substation. The cost has spiraled out of control, up 40 percent from last year. These price increases have dried up the inventory of the used market and new transformers are averaging 50-56 weeks from order to arrival. All rewind shops are swamped, and their time lines are growing as well. Unfortunately, the majority of the U.S. transformer population is also at the end of the baby boom era and requires special care and testing if they are to continue to serve until the market can catch up. In some of the more progressive industries and utilities, transformer testing is nothing more than a walk around to look for leaks, nitrogen and oil levels, LTC count, and the temperature recorded by the hot spot and top oil gages. Some company maintenance and test personnel have implemented DGA testing but many still have no clue of its value.

failure producing indicators on the outside. To truly test a transformer 100 percent, all of the failure modes must be known and tested for on a regular basis. All failure modes can be classified into one of the three following categories: mechanical, electrical and dielectric. Each of these categories should be further divided into internal and external testing. The last two divisions are what separate mediocre from the complete testing programs.

External Failure Modes Mechanical failures are typically broken into LTC drive systems and cooling. It is imperative the LTC make a full tap change at a speed where internal arcing damage is minimized. Items such as weak motor starting capacitors (Figures 1 and 2) and low source voltage will cause the motor to labor, pull abnormally high currents, and eventually burn up if not protected by a safety of some sort. Motor voltage should not drop more than 10 percent during tap change from 1 L to 1 R. Low voltage means high current and overheating. Bad source wiring or corroded connections to the LTC can also be a culprit of low voltage.

Figure 1 — Motor mounted capacitor

The companies that do regularly test transformers are many times still guilty of only testing what is inside the tank and totally overlook many of the obvious other transformer

Figure 2 — Externally mounted capacitor

Transformer Handbook — Volume 2

Figure 3 — Rusty chains on a Federal Pacific TC-525

Stiff rusty chains (Figure 3), weak drive springs, dry gear boxes and poor shaft alignment all contribute to tap changer and transformer failure and have nothing to do with the internal workings of LTC or windings. Many transformer failures can be attributed to the failure of the dynamic braking system that stops the LTC on tap rather than partially on tap as can be seen below in Figure 4.

Dry “All Thread” 33 cam switch activators and rusty bearings cause timing errors, out of sequence stepping or failure in the end of stroke limit switches.

Figure 5 — ONAN naturally cooled through oil

Cooling Figure 4 — Contact failure due to faulty drive mechanism

True maintenance of these items does not mean spraying them with WD-40 or any other solvent based penetrant. The only correct solution is to disassemble, clean, and repack the bearing or gear box with compatible grease and replace defective parts. My recently departed good friend and colleague, Butch Zimmerman, coined the phrase of using the solvent approach to repair as “maintenance man in a can.”

Cooling is essential for long transformer life. Most transformers are designed for 55°C or 65°C rise. Using newer insulations such as Nomex®, temperatures of 95°C and higher can be achieved. These temperatures can only be maintained if the transformer operating conditions do not exceed the design limitations. Unfortunately, in today’s operating environment, most end users are pushing loads well past nameplate design limitations resulting in increased winding temperatures. These temperatures are primarily due to increased losses such as I2R. Increased heating plays a major effect on the

Transformer Handbook — Volume 2

Figure 6 — ONAF cooling provided by fans used to supplement convection cooling (no external fans) using natural oil convection (bottom mount up draft)

Figure 7 — ONAF cooling provide by fans used to increase cooling using natural oil convection. (side mount)

Figure 8

Figure 9

degradation of insulation quality and drastically diminishes its life expectancy. Here the standard 10°C rule of thumb still applies for insulation half life. Transformers are either self cooled through natural oil convection and rated ONAN (Figure 5) or fan cooled and rated ONAF Figures 6 and 7. In most extreme cases, forced oil or forced oil over water cooling with a rating of OFAF or OFWF (Figure 11) are used. In each case, it is extremely important that proper temperature transfer takes place. The design of the transformer relies on a specific heat transfer between the windings, oil and the radiator or cooler for heat extraction. Any increase in heat generation or any heat transfer reduction results in higher winding temperatures and shorter insulation life. Additionally, the dielectric fluid is degraded and will be covered in a later section. Figure 10

Transformer Handbook — Volume 2

Figure 12 — Stages of thrust washer wear new/failed Figure 11

Bottom mount fans blow air across the total length of the cooler or radiator but have higher motor failure due to water entrance around the shaft seal. The use of totally enclosed, nonvented motors with high quality shaft seals do, however, increase motor life. Inspection of these motors should be made monthly. Side-mounted fans have a longer life expectancy but tend to blow only across the section of the cooler or radiator where placed. Side-mounted fans are also very susceptible to prevalent wind direction which can help or defeat the air movement across the heat transfer surface. Open frame motors are not recommended in any case due to higher failure rates caused by environmental considerations. Typically one fan failure does not cause serious problems but does result in an overall temperature increase for the transformer especially if it is overloaded as can be seen in infrared Figure 8. Fans typically fail in batches. They are manufactured at the same time and operate in the same environment. Observation of one failure should be an indicator that others may be ready to fail as well leaving the transformer in danger of over temperature. Figure 9 shows loss of cooling in some radiators due to concrete pad settling tilting the transformer. This can, in some cases, be corrected by increasing the oil level in the main tank to a level permitting oil flow through the radiators. Care should be taken to not overfill and create a problem due to oil expansion that takes place during overheating. In Figure 10 all of the oil valves to the radiators are higher than the oil which prevents oil circulation. Low oil level can be a result of leaks or failure to be adequately filled when last serviced. One last issue causing the same consequence happens if the upper butterfly valves to the radiators are turned off during maintenance and not turned back on which prevents oil flow. A simple thermography test will reveal this life-robbing problem.

Figure 13 — Ball bearing failure leading to transformer failure

Forced oil pumping systems FOA/ FOW (Figure11) provide for high flow rates through radiators and the transformer providing maximum heat transfer. Pump flow rate is hard to measure and typically uses a small vane gage located in the piping indicating pump ON or OFF activity. Flow indicators are not always accurate. Many times during maintenance a gage is found to be stuck and does not truly indicate flow. A simple test can be performed by turning the pump off and looking at the indicators to determine if they read correctly. Pumps, themselves create their own set of failure modes in a transformer. Built to tight tolerances, they do not tolerate loose bearings or bushings. As they age, bearings, bushings or thrust washers wear and can cause impeller drag on the pump housings (Figures 12 and 13). This causes large deposits of metal filings to be deposited in the transformer windings and eventually causes insulation failure as they vibrate at operating frequency and wear in. Ultrasonic inspection for bearing wear is an excellent test and can be performed at anytime as long as the pump is running as shown in Figure 14.

5

Transformer Handbook — Volume 2

Be sure to check on the integrity of the plug and cable, a known trouble area as seen in Figure 17.

Figure 14 — Ultrasonic inspection of oil pump bearings

Figure 16 — Standard winding temperature gage made by “Orto”

Electrical Testing Electrical testing is normally thought of as tests such as TTR, insulation resistance, core ground and power factor. All are tests internal to the tank! External testing is just as important to maintain transformer health and prevent unwanted failures. As previously discussed, transformer temperature is extremely important. Most end users take for granted the Hot Spot and Top Oil gages to be accurate and their alarms functional. Regular calibration of these indicators should be performed and many can be done without removing the transformer from service.

Figure 17 — Temperature gage pug and cord

Figure 18 — Liquid level gage Figure 15 - Jofra Hot Well Probe Calibrator

The use of a temperature well calibrator, as seen in Figure 15, in combination with a continuity tester can determine set and trip points also determine if the microswitches used to sound alarms or trip the transformer actually work and trigger at the temperatures desired. Switch activation may mean the difference in tripping the transformer off safely or transformer failure (Figure16).

Oil level gages (Figure 18) can become stuck in one position after many years without movement. Most are magnetically coupled through the tank wall and can fail without notice. Oil leaks and multiple oil samples can all lead to low oil levels. Care should be taken to insure these gages work properly and if connected to alarms or trip circuits, provide the correct outputs. Magnetically coupled gages can be removed without the loss of oil and can be tested using a continuity check by rotating the gage to indicate low oil level.



Figure 19 — Top connection overheating

Transformer Handbook — Volume 2

Figure 21 — Test tap overheating

Overheating of the test tap as seen in Figure 21 can be caused by a poor connection in the grounding cap. Partial discharge or an open circuit can lead to bushing and transformer failure. Identified through thermography, this test can be performed at anytime while the unit is energized and can provide the important data to determine if a forced outage needs to occur to correct failure-causing problems.

Dielectric Maintenance

Figure 20 -Internal overheating due to overload

Bushings Bushing integrity is paramount. Bushings should be tested during transformer outages as per NETA specifications. Other tests such as thermography can be performed during normal operating periods providing valuable information as to transformer health. High resistance on top connection to a bushing (Figure 19) can cause conductor failure and/or internal bushing pressurization and ultimately bushing failure. Complete overheating (Figure 20) occurs due to high resistance internal to the bushing or in many cases today, overloading of the bushing beyond design limits.

Oil and insulation maintenance is paramount to transformer life expectancy. Paper insulation is designed to be pliable and give with fault current winding distortion. The addition of heat damages paper insulation irreversibly. Paper becomes brittle and no longer gives with winding distortion. Once the pliability of the paper is lost, the insulation will begin to crack under fault conditions providing a path for turn-to-turn shorts and eventual winding and transformer failure. Oil is designed to provide cooling and insulating strength. Addition of water and oxygen decreases dielectric strength and begins acid formation. Loss of dielectric strength leads to partial discharge or flash over and again insulation failure. Dielectric testing is required to determine both insulating oil and paper health. Typical oil tests are dissolved gas analysis, dielectric breakdown, power factor, acidity, IFT, color, and Karl Fisher. Other tests such as degree of polymerization and furnanic compounds can be useful in determining the condition and remaining life of the insulation and should be done frequently as the transformer ages or in cases of overloaded or overheated units. All can be done with the transformer in service.

Transformer Handbook — Volume 2 Conclusions Transformer testing whether internal or external is paramount in providing the maximum life expectancy of our equipment whether new or one from our aging fleet. Only if all possible failure modes are addressed can we be certain to provide our customers with a level of certainty that we have done everything possible to insure the integrity of their transformers. Nothing worse can happen to a test technician than a call form a customer asking why their transformer failed only to find out an omitted test could have caught the problem and prevented the failure. It is the difference between a mediocre and an excellent testing program. Are you missing the test point? Rick Youngblood graduated from Indiana State University in 1973 after leaving active duty in the Air Force. Rick joined Cinergy Corporation in 1982 then known as Public Service of Indiana. Rick was promoted to Project Engineer after receiving his BSEE from Purdue University in 1985. In 1987 Rick became the Manager of Technical Services in their Northern Division. Rick was responsible for implementing Cinergy’s CMM System and creation of its Predictive and Preventive Maintenance Programs. In 2000 Rick was promoted to Supervising Engineer for Substation Services where he remained until taking early retirement in 2004. Rick joined American Electrical Testing Company in August of 2004 as Regional Manager heading up the Midwest office located in Indiana. Rick holds a Level III NETA test technician certification.

Transformer Handbook — Volume 2

Partial Discharge Testing of Transformers T

orld

n er 2

2

b Don A Genutis Grou C

Consistent with the theme of this issue’s NETA World, our column will focus on no-outage testing of transformers. Specifically, we shall explore partial discharge (PD) testing of both dry-type and fluid-filled transformers.

Dry-Type Transformers The methods that we will discuss for testing dry-type transformers also apply to cast-coil transformers. These types of transformers are primarily used for medium- and low-voltage indoor applications, but this column only addresses medium-voltage transformers as low-voltage insulation does not typically discharge since the voltage levels used are not great enough to create discharges according to Paschen’s law. Dry-type transformers are typically housed in ventilated enclosures. These vents provide an opportunity to obtain data used to evaluate the condition of the transformer. If an airborne discharge or corona occurs on the surface of the insulation, this sparking activity will radiate high frequency pulses that adhere to the inside of the grounded transformer enclosure and will propagate along the inside surface through

Figure 1 — Dry-Type Transformer

the vent openings and finally to the outside of the enclosure via the “skin effect.” These signals can then can be detected and analyzed by placing a magnetically-coupled capacitive sensor on the transformer enclosure as shown as sensor A in Figures 1 and 2. Alternate sensor arrangements consist of placing split-core, high-frequency current transformers (HFCT) on the shield of the transformer’s primary cables as shown as sensor C and the point where the low voltage neutral is grounded as shown by sensor B. Typically, the signals are then recorded by specialized instruments and then analyzed for the presence of damaging PD. Except for rotating apparatus, insulation systems cannot tolerate PD activity and nonfluid transformers are no exception. Although some types of discharge, such as corona from a conductor in free air, can be benign, it is always best to strive to obtain a PD-free system. Therefore, any presence of PD activity should be considered dangerous and, at a minimum, should be closely monitored. Under some circumstances, it may be desirable to obtain an outage on the transformer and to conduct service and supplementary off-line tests if PD is detected. Sometimes, cleaning the

Figure 2 — Insulation Model for Dry-Type Transformer

Transformer Handbook — Volume 2 transformer thoroughly will eliminate or reduce the PD levels, and close visual inspections can often locate an external trouble spot that is easily repaired in the field. Performing a tip-up test can often provide additional insulation condition information, and PD testing can be performed simultaneously in order to obtain the corona onset voltage. Additional equipment such as the corona camera or the ultrasonic detector can help pinpoint the problem. By integrating annual PD testing into a facility’s no-outage inspection program, insulation failures can be minimized or eliminated completely.

Fluid-Filled Transformers The typical fluid-filled transformer insulation system is not too dissimilar from that of the dry-type transformer. PD activity in oil-filled transformers is just as dangerous and perhaps even more dangerous than PD activity in drytype transformers. Unlike dry-type transformers, discharges in oil-filled transformers are contained within the sealed transformer tank, and the associated PD byproducts caused by the sparking activity under oil are also contained within the sealed tank. PD activity generates hydrogen and regular dissolved gas analysis (DGA) sampling and testing can ensure that PD activity is not occurring as long as hydrogen is not present. It is the PD’s generation of combustible hydrogen gas that presents additional dangers besides the obvious detrimental effects on the insulation, as possible ignition could cause catastrophic failure to the transformer and possible residual damage to adjacent equipment. Presently, nearly all large high-voltage transformers are filled with mineral oil and this oil offers superior dielectric strength and cooling characteristics in comparison to drytype transformers. As the primary voltage levels of the transformer increases, much greater care must be taken in regards to the suppression of electrical stresses and the associated prevention of corona. Through various mechanisms, transformer failure related to corona or PD will generate hydrogen. After hydrogen has been detected, the next step usually involves estimating the location of the PD activity in order to determine the likelihood of conducting successful field repairs. One of most successful methods for PD location involves placing one or more magnetically-coupled acoustic sensors at various points on the outside wall of the transformer. Possible locations can then be determined by triangulation or by performing simple calculations. In order to approximate the internal PD source location, success has been made by placing an HFCT on the transformers ground to detect the electrical PD pulses. These signals are used to start a timer or trigger an oscilloscope, and the acoustic emission sensor signal is used to stop the timer. Years of research has accurately determined that sound propagates through oil in

a steel tank at a certain rate of speed, and the time difference between the electric signal and the acoustic signal is used to calculate the PD source location. Additional detailed information regarding these methods can be found in IEEE Standard C57.127-2007, Guide for the Detection and Location of Acoustic Emissions from Partial Discharges in Oil-Immersed Power Transformers and Reactors. Figure 3 illustrates a plot of PD signal origination that was performed on a transformer in the field. One of the key findings of this survey was that all PD signals were occurring from the top of the transformer, which led to the assumption that inspection and possible corrective actions could be conducted from the top inspection plates. This particular transformer was manufactured with the core suspended from the top plate and subsequent internal inspection revealed tracking occurring from the insulating tube surrounding the core bolts which was easily repaired.

Figure 3

Monitors Certain types of insulation failures can occur fairly rapidly, and regular testing programs may not be able to spot this type of failure quickly enough to save the transformer. Additionally, many transformers may be so critical to the facility that continuous monitoring of the insulation condition is desirable. This is especially true of generating station step-up transformers where replacement costs are in the tens of millions of dollars and replacement units can take six months to obtain. Several different types of monitors are available, but those that continuously monitor the transformer fluid for hydrogen seem to be the most popular because of their reliability and relatively low cost. As discussed earlier, hydrogen is generated by partial discharge activity in oil, and hydrogen is also generated by other failure modes including arcing which generates acetylene but also generates hydrogen. Moisture (H2O) in oil also contains hydrogen, so the health of the transformer can be determined by monitoring hydrogen levels accurately. Other types of popular monitors include the bushing tandelta comparison device that acts like a constant power-factor or tan-delta test of the bushings. On large transformers, bushing failures often destroy the associated transformer

5 winding. As bushings deteriorate they usually do not cause a DGA problem. In order to prevent this mode of failure, a connector is placed in each bushing power-factor tap. The signals from this tap are then connected to a comparator circuit which monitors any changes in the bushing’s insulation system. These taps can also provide a convenient point to conduct periodic or continuous partial discharge tests.

Conclusions In order the ensure transformer reliability and prevent failures, the following no-outage tests should be performed. 1. Medium-voltage, dry-type transformers should be tested annually for partial discharge activity using capacitive sensors connected to the outside of the enclosure. An ultrasonic detector or corona camera may be useful in pinpointing the problem. An off-line, tip-up test is useful to determine the PD severity. 2. Medium-voltage, fluid-filled transformers should be tested annually for DGA and other fluid characteristics.

3. High-voltage, fluid-filled transformers should be tested annually for DGA and other fluid characteristics at a minimum. Consideration should be given to monitor critical transformers continuously for hydrogen-in-oil and for bushing tan delta. Mr. Genutis received his BSEE from Carnegie Mellon University, has been a NETA Certified Technician for 15 years, and is a Certified Corona Technician. Don’s technical training and education is complemented by nearly twenty-five years of practical field and laboratory electrical testing experience. He is presently serving as Vice President of the Group CBS Eastern U.S. Operations and acts as Technical Manager for their subsidiary, Circuit Breaker Sales & Service located in Central Florida.

Transformer Handbook — Volume 2

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Transformer Handbook — Volume 2

Transformer Monitoring, Communications,Control,andDiagnostics T

o erTes 2 nnual Te n al onferen e Presenter Claude Kane Co-Author Alexander Golubev Electrical Diagnostic Innovations, LLC

Introduction The time to failure on transformers is relatively unknown. The use of on-line comprehensive transformer monitoring has become a very useful and cost effective way to help identify problems early. By identifying problems early, they can be fixed before they escalate into a complete failure. This paper will provide an overview as to technologies available for the monitoring of Large Power Transformers.

Protecting Your Transformer Asset

To determine what should be included in an on-line monitoring system, transformer customers often use the failure history of their transformer fleet as a guideline. The data shown below, was obtained from Doble Engineering Company’s review of transformer failures from 1993-19983. We have added text blocks to illustrate what types of online monitoring products/technologies could be employed to address each of these failure modes.

Transformer Failure Data and Available On-line Monitoring Opportunities Transformer monitoring systems can be designed to economically monitor most of the transformer failure modes shown above. With a properly designed system, detection rates of at least 60% are easily achievable. In addition to deciding what to monitor, one also need to decide how to monitor their equipment. The traditional approach was to install function specific products to perform a wide variety of discrete monitoring functions:

Utility Failure Data

While failures can be unpredictable, one thing is for certain; all transformers left in service will eventually fail.

Comprehensive Transformer Monitoring (Transformer Management Systems) Transformer monitoring in its most basic form has been around for many years. Historically, facilities used alarm contacts from the various gauges on the transformer and this was considered to be the “monitoring system”. As technology has advanced, there is now a vast array of monitoring tools and technologies available to provide better information which will give earlier indication of problems.

• Temperature Monitoring

• Cooling system monitoring • LTC Monitoring • D

Monitoring

• Moisture in oil Monitoring • Bushing Monitoring

• Partial Discharge Monitoring

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Transformer Handbook — Volume 2 Fiber Optics -Direct Winding Hot Spot Measurements

Temperature Monitoring Historically, temperature monitoring of transformers was performed using top oil temperature measurements combined with estimated winding hot spot measurements. Since hot spot measurements could not be performed directly, they were simulated using a top oil temperature sensor with a heater to simulate the temperature rise of the winding hot spot over the top oil temperature. Current from a bushing CT passed through the heater raising the measured temperature. A variable resistor or another calibrating device was then used to “tune” the simulated winding hot spot to match the expected hot spot from the design calculations. Unfortunately, the accuracy of the capillary thermometer drifts over time and it is not uncommon to find errors in hot spot temperature measurements of 5-10°C using this method.4 In addition, the winding hot spot gauge is tuned based on an assumed ambient temperature. The LTC is also assumed to be operating on the lossiest tap position with all stages of transformer cooling turned on and operating properly. If any of these conditions change, the accuracy of this “reading” will be affected. While many people may consider an error of 5-10°C negligible, for every 6°C increase in winding temperature, the insulation loss of life doubles. Hence, these “negligible” errors can result in loss of life calculations which are in error by more than 100%.

Calculated Winding Hot Spot Temperatures Transformer management systems and many electronic temperature monitors more accurately predict winding hot spot temperatures by calculating the winding hot spot temperatures. The improved accuracy of a calculated temperature vs. simulated begins with the temperature sensor. Simulated winding hot spot gauges used bulb type thermometers to measure the temperature. TMS’s and ETM’s utilize RTD’s which offer improved accuracy. Advanced systems then use the transformers design information to more accurately calculate the winding hot spot temperature improving the accuracy of the “measurement” over the operating range of the transformer.

The third and arguably, the best method of determining the winding hot spot is to directly measure it using fiber optic probes. Fiber optic technology continues to advance with improved sensors and cables offering better reliability, flexibility and strength at a more economical price. Advancements have also been made in the methods used to position and secure the fiber optic probe in the winding spacer to prevent the sensors from becoming dislodged. For direct winding temperature measurement, sensors are installed in the spacer at the expected hottest spot location as determined by analysis of the eddy loss distribution, the oil flow distribution and the heat transfer characteristics of the transformer windings. Typically redundant sensors are placed at the expected hottest-spot location with additional sensors placed in the vicinity of where the higher temperatures are expected. The improved loading information that can be gained by direct measurement of hot spot temperatures makes the installation of fiber optic probes very common in new GSU applications and other critical transformers. Using fiber optic probes to verify the thermal model in the first of several thermal duplicates or new transformer designs is also becoming more popular.

Dynamic Transformer Rating Transformer ratings (or maximum allowable loading) are governed by thermal conditions and based on a simple model. Energizing a transformer, results in losses in the core and windings which become hot, causing the oil temperatures to rise. Increased loading increases the losses and hence the temperature. The highest temperature in the winding must not exceed the allowable design limit. These ratings however, are based upon defined values for ambient temperature, wind speed and direction and other factors that influence the winding hot spot temperature. When more accurate winding hot spot information is combined with real time ambient temperature, knowledge of the transformer condition and cooling system health, a more accurate real time transformer rating or dynamic rating can be calculated.7 The dynamic rating of a transformer is the maximum possible load that can be served without exceeding the predefined thermal rating limits of the transformer. Experience has shown that transformers may typically be loaded 10-20% higher than their “static” or design rating when real time information is available on the factors that affect this rating. (Note -Some transformer designs may have other loading limitations due to bushings, LTCs, etc which may limit the maximum transformer rating). Knowing a transformer’s real thermal limit or dynamic rating at any point in time allows system operators to load transformers with greater confidence. This information becomes especially critical during system contingencies.

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Transformer Handbook — Volume 2 Cooling System Monitoring and Control Traditional cooling controls turned fans and pumps on and off automatically at the respective temperature set points of the top oil and winding hot spot gauges. While electronic temperature monitors (ETM) and transformer management systems (TMS) perform basic cooling control in a similar fashion, they also offer several other benefits to improve transformer life expectancies.

Smart Cooling Control Most ETM and TMS systems available on the market today offer some form of smart cooling control. Basic systems typically watch for increases in system loading and turn on cooling when the system loading reaches a certain percentage of the transformer nameplate. More advanced systems predict where the top oil and winding temperatures are headed (based on present temperatures, loading and tap position). If the predicted temperatures exceed the traditional temperature set points, the cooling is turned on immediately. By turning the cooling system on early, it is possible to pre-cool the transformer and avoid excessive insulation aging and will reserve more overload capacity for later in the day.

mand has been issued, if it has access to the monitoring information, it can verify that the command issued, was successfully completed. This self monitoring function, which is available in a combined monitoring and control system, can greatly improve the overall reliability of a tap changer and the control system.

Gas-In-Oil Monitors The monitoring of dissolved gases in transformer oil is probably the most well known of all forms of condition monitoring for substation equipment. Every modern facility in the world employs some form of dissolved gas analysis on its transformer fleet. The wealth of information that can be provided by gas in oil analysis make it the single most important element in any transformer maintenance program. As shown in the Doble failure data, winding related failures have been the single largest source of transformer failures. Gas in oil monitoring has been the most common method used to detect failures of this type. Since transformer failures can occur rapidly, on-line gas monitoring is included in most transformer monitoring systems. While there are a wide variety of on-line gas monitors to chose from today, repeatability is the most important factor that should be evaluated when considering gas in oil monitoring equipment. Although on-line gas monitors in theory should eliminate the need for periodic oil samples to be sent to the laboratory, periodic DGA samples are still generally recommended to verify the accuracy of the on-line monitoring system. Portable DGA analyzers can also be very useful in verifying the accuracy of the on-line instruments. Gas-in-oil monitors are available in two types, key gas monitors and multi-gas monitors.

Key Gas Monitors Smart Cooling Control

Other Features include:

Key gas monitors operate on the principle that there are certain key gases that are present to some degree in all transformer faults.

Fail Safe Cooling Control Automatic Self test

Automatic Duty Cycling

LTC Monitoring and Control Due to the number of moving parts, tap changer operation can be one of the more important functions to monitor on a transformer. Historically, the majority of the focus on an LTC has been placed on the high voltage components, i.e. the tap changer contacts and insulating oil. While the importance of monitoring the high voltage components cannot be underestimated, on-line condition monitoring for an LTC needs to start with the tap changer controls and drive mechanism. Combining monitoring and control into a single device allows the control system to monitor itself. When combined, control functions are no longer performed blindly and monitoring is no longer a passive activity. Since the control system is aware of when a com-

Relative Quantities of Dissolved Fault Gases Generated by Incipient Faults

By monitoring for these key gases, early warning of incipient transformer failures can be provided. Following an alert from a key gas monitor, a complete dissolved gas analysis can be performed to verify the alarm and to more accurately identify the source of the problem.

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Transformer Handbook — Volume 2

Most of the key gas monitors available on the market today utilize gas permeable membranes to extract the gases from the oil. While some key gas monitors analyze only hydrogen, other monitors analyze hydrogen combined with smaller concentrations of other key gases.

Multi-Gas Monitors A complete dissolved gas history on a transformer is undoubtedly one of the most important diagnostic tools for evaluating transformer health. The presence of an on-line multi-gas monitor greatly improves the ability to trend DGA gases vs. periodic sampling. In addition to the frequency of sampling, many on-line systems also offer the ability to capture temperature and pressure information which further improves the accuracy of the measurements. While every asset manager recognizes the benefit of having more frequent dissolved gas test results, few are able to justify the cost of this equipment on every transformer. As a result, on-line multi-gas monitors have historically been reserved for only the most critical units or known gassing transformers.

Bushing Monitoring In most transformer failure studies, bushing failures are one of the more predominant failure modes. Moisture ingress, oil deterioration, paper aging and overheating all lead to degradation of bushing insulation. As the dielectric insulation breaks down, partial discharges occur further damaging the bushing insulation through treeing or puncturing of the paper layers. These changes in the quality of the bushing insulation frequently result in changes in the bushing power factor and capacitance readings which are easily measured on line in bushings fitted with test (potential) taps. The effectiveness of periodic bushing power factor and capacitance measurements at accurately identifying bushing degradation has been documented in Doble papers and other industry conferences over the past few decades. While most people recognize the effect temperature has on these readings, the affect increased voltage stress has on the ability to detect potential problems is not as well known. The following figure shows power factor measurements performed on a known defective bushing at various temperatures and voltages. As shown below, performing these measurements on-line at transformer operating voltages and temperatures can greatly improve the ability to detect potential problems early.

Temperature and Voltage Dependency of Power Factor Readings

The most common method of on-line bushing monitoring is the sum current method. For a set of three similar bushings, the sum of the bushing currents is normally very close to zero or may be brought to zero with balancing modules. Changes in the power factor or capacitance of any one bushing, results in a corresponding change in current and can be measured by the following equation:

where ∆I is the change in the current through the insulation, caused by the appearance of a defect, I0 is the current through insulation prior to this defect (more correctly, at the time of the monitoring system commissioning), Δ tan δ reflects a change in power factor of the main bushing part related to the capacitance C1, and ∆C is a change in this capacitance over its initial value C0. Based on experience, a change in leakage current of about 1-2% is considered a sign of deterioration. Changes of 3-5% are a more serious situation with changes above 6-8% being considered an impending catastrophic bushing failure. If changes occur simultaneously in two or three bushings in the set, the sum current value will be a vector sum of all changes.14 Safety should be of utmost concern when considering a bushing monitoring system. In addition to providing over-voltage (surge withstand) protection, bushing sensors should also provide open circuit protection to limit the voltage which may be present should the sheath of the sensor cable become ungrounded. Some monitoring systems also provide fail safe protection which grounds the capacitance tap should the primary protection modes fail.

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Transformer Handbook — Volume 2 Partial Discharge Partial discharge occurs when the local electrical field exceeds the dielectric strength of the insulating material resulting in an electrical discharge which partially penetrates or bridges the insulation between electrical components or conductors. Partial discharges may occur due to: Temporary over-voltage conditions or transients Insulation degradation due to aging, moisture, contamination or loss of insulating fluid Areas of high dielectric stress due to flaws or defects introduced during the manufacturing process or field repairs. The primary causes of PD in transformers are: • Partial discharge activity • Stray flux

• Bad contacts/floating potentials • Voids in solid insulation

• Creeping/tracking discharges in cellulose insulation

external sources of noise such as weather related activity can be difficult. Electrical monitoring is more typical for permanently installed on-line monitoring systems but can be hampered by external electrical noise such as corona. This noise can be mitigated through the use of special noise sensors and filtering techniques. The two methods should be considered to be complimentary and not mutually exclusive. Since some level of PD is normal in any transformer, the best way to monitor PD is through a continuous online monitor. Continuous monitoring allows the ability to track partial discharge activity and correlate its occurrence with load and temperature. PD activity may be dependent on load, temperature, LTC position or other conditions. By correlating the PD activity with operating data, loading guidelines may be instituted to limit PD activity to reduce or eliminate insulation breakdown. Implementing loading guidelines may be more tolerable than rewinding transformers when the source of the PD is deep with the transformer windings.

Leakage Reactance Leakage reactance measurements can provide important information on the overall health of transformer windings. While most IED’s and on-line sensors monitor the transformers “electrical” health, on-line leakage reactance measurements will provide the opportunity to monitor the “mechanical” health of the transformer. Leakage reactance measurements are generally performed during offline testing to monitor for deformation of the transformer windings.

The presence of H2 in a DGA sample without the presence of other gases has historically been considered an indicator of partial discharge activity in transformers. Unfortunately, not all partial discharge activity results in hydrogen generation. The location and severity of the partial discharge affects whether or not detectable hydrogen gas will be generated. Often times, any hydrogen generated from partial discharge activity deep within layers of paper insulation will remain trapped during the early stages of PD. As the problem progresses, the frequency and size of the partial discharges increases until the problem becomes readily apparent in DGA samples. Many partial discharge problems are also self sustaining. Once the PD starts, carbon may be produced which further increases tracking and PD activity. Partial discharge activity can be monitored using electrical or acoustical methods. Acoustical methods can be very useful in identifying the location of the PD activity using triangulation methods when the defect is in the outer part of the winding such as bad contacts in a no load tap changer or a bushing connection. Defects deeper in the winding can not be found using this method. Unfortunately, eliminating

Many facilities today have reliability goals for the duration of outages experienced by customers. To meet these goals, system operators frequently re-close circuit breakers as part of their sectionalizing efforts to restore service to as many customers as possible following system faults. This practice greatly increases the number of through faults a transformer will experience over the course of its lifetime. Methods to monitor leakage reactance using on-line tools are under development. On-line leakage reactance measurements will provide an important tool to measure the affect these reliability goals have on the health of substation transformers.

5 Conclusions The time to failure for transformers can be unpredictable. Fortunately, most transformers will provide an identifiable sign of an impending failure in the days or weeks prior to the failure. On-line monitoring offers the best opportunity to prevent these failures by identifying transformer problems early. While there are a wide variety of monitoring devices available in the marketplace today, the data provided by these discrete sensors and IED’s can be greatly enhanced when correlated with loading, temperatures and other critical information. Comprehensive transformer management systems offer the best opportunity to capture and consolidate these signals to provide asset managers the timely, accurate and meaningful information they require to prevent failures by identifying transformer problems early. Claude Kane has over 35 years of experience in the installation and maintenance practices for power distribution, transmission, and generation equipment. He started with Westinghouse in 1972 as a field service engineer in Kansas City and has held a number of technical and management positions throughout his career. His last 10 years have been spent developing technological products and emerging markets for predictive diagnostic and prognostic equipment. He is currently one of the principal owners of Electrical Diagnostic Innovations, Inc. based in Minneapolis.

Transformer Handbook — Volume 2

NETA Accredited Companies The following is a listing of all NETA Accredited Companies as of August 2011. Please visit the NETA website at www.netaworld.org for the most current list. A&F Electrical Testing., Inc...................................................................................Kevin Chilton Advanced Testing Systems ............................................................................Patrick MacCarthy American Electrical Testing Co., Inc. ......................................................................Scott Blizard Apparatus Testing and Engineering ....................................................................... James Lawler Applied Engineering Concepts .................................................................... Michel Castonguay Burlington Electrical Testing Company, Inc. ........................................................... Walter Cleary C.E. Testing, Inc. ........................................................................................... Mark Chapman CE Power Solutions of Wisconsin, LLC............................................................. James VanHandel DYMAX Holdings, Inc. ....................................................................................... Gene Philipp Eastern High Voltage ....................................................................................... Joseph Wilson ELECT, P.C. .................................................................................................Barry W. Tyndall Electric Power Systems, Inc. .................................................................................. Steve Reed Electrical and Electronic Controls ..................................................................... Michael Hughes Electrical Energy Experts, Inc............................................................................... William Styer Electrical Equipment Upgrading, Inc. .......................................................................Kevin Miller Electrical Maintenance & Testing, Inc........................................................................ Brian Borst Electrical Reliability Services ..................................................................................Lee Bigham Electrical Testing, Inc. ................................................................................. Steve C. Dodd Sr. Elemco Services, Inc. ...................................................................................... Robert J. White Hampton Tedder Technical Services ....................................................................... Matt Tedder Harford Electrical Testing Co., Inc. ................................................................... Vincent Biondino High Energy Electrical Testing, Inc..................................................................... James P. Ratshin High Voltage Maintenance Corp. ........................................................................... Eric Nation HMT, Inc. .........................................................................................................John Pertgen Industrial Electric Testing, Inc. ........................................................................ Gary Benzenberg Industrial Electronics Group ................................................................................. Butch E. Teal Industrial Tests, Inc. .............................................................................................. Greg Poole Infra-Red Building and Power Service ............................................................ Thomas McDonald M&L Power Systems, Inc. .................................................................................. Darshan Arora Magna Electric Corporation ................................................................................... Kerry Heid Magna IV Engineering – Edmonton ...................................................................Jereme Wentzell Magna IV Engineering (BC), Ltd. ........................................................................ Cameron Hite

Setting the Standard

MET Electrical Testing, LLC .......................................................................... William McKenzie National Field Services...................................................................................... Eric Beckman Nationwide Electrical Testing, Inc. ...............................................................Shashikant B. Bagle North Central Electric, Inc. ...............................................................................Robert Messina Northern Electrical Testing, Inc. .......................................................................... Lyle Detterman Orbis Engineering Field Service, Ltd. ....................................................................... Lorne Gara Pacific Power Testing, Inc. ...................................................................................Steve Emmert Phasor Engineering ........................................................................................... Rafael Castro Potomac Testing, Inc. ........................................................................................... Ken Bassett Power & Generation Testing, Inc.......................................................................... Mose Ramieh Power Engineering Services, Inc. ..................................................................... Miles R. Engelke POWER PLUS Engineering, Inc. ...................................................................Salvatore Mancuso Power Products & Solutions, Inc. ........................................................................ Ralph Patterson Power Services, LLC ........................................................................................ Gerald Bydash Power Solutions Group, Ltd ...........................................................................Barry Willoughby Power Systems Testing Co. ............................................................................... David Huffman Power Test, Inc. ..............................................................................................Richard Walker POWER Testing and Energization, Inc. ............................................................... Chris Zavadlov Powertech Services, Inc. ................................................................................... Jean A. Brown Precision Testing Group .................................................................................... Glenn Stuckey PRIT Service, Inc. ........................................................................................ Roderic Hageman Reuter & Hanney, Inc....................................................................................... Michael Reuter REV Engineering, LTD ................................................................................ Roland Davidson IV Scott Testing, Inc................................................................................................Russ Sorbello Shermco Industries ............................................................................................... Ron Widup Sigma Six Solutions, Inc. ....................................................................................... John White Southern New England Electrical Testing, LLC ................................................. David Asplund, Sr. Southwest Energy Systems, LLC .......................................................................Robert Sheppard Taurus Power & Controls, Inc. ............................................................................... Rob Bulfinch Three-C Electrical Co., Inc.................................................................................James Cialdea Tidal Power Services, LLC ....................................................................................Monty Janak Tony Demaria Electric, Inc. ............................................................................ Anthony Demaria Trace Electrical Services & Testing, LLC ...................................................................Joseph Vasta Utilities Instrumentation Service, Inc. ........................................................................Gary Walls Utility Service Corporation.................................................................................. Alan Peterson Western Electrical Services ......................................................................................Dan Hook

Setting the Standard

About NETA NETA (InterNational Electrical Testing Association) is an association of leading electrical testing companies; visionaries, committed to advancing the industry’s standards for power system installation and maintenance to ensure the highest level of reliability and safety. NETA is an accredited standards developer for the American National Standards Institute (ANSI) and defines the standards by which electrical equipment is deemed safe and reliable. NETA is also the leading source of specifications, procedures, testing, and requirements, not only for commissioning new equipment but for testing the reliability and performance of existing equipment.

QUALIFICATIONS OF THE TESTING ORGANIZATION An independent overview is the only method of determining the long-term usage of electrical apparatus and its suitability for the intended purpose. NETA Accredited Companies best support the interest of the owner, as the objectivity and competency of the testing firm is as important as the competency of the individual technician. NETA Accredited Companies are part of an independent, third-party electrical testing association dedicated to setting world standards in electrical maintenance and acceptance testing.

Hiring a NETA Accredited Company assures the customer that: • The NETA Technician has broad-based knowledge — this person is trained to inspect, test, maintain, and calibrate all types of electrical equipment in all types of industries. • NETA Technicians meet stringent educational and experience requirements in accordance with ANSI/NETA Standard for Certification of Electrical Testing Technicians, (ANSI/NETA ETT). • A registered Professional Engineer will review all engineering reports. • All tests will be performed objectively, according to NETA specifications, using calibrated instruments traceable to the National Institute of Science and Technology (NIST). • The firm is a well-established, full-service electrical testing business.

CERTIFICATION NETA Certified Technicians conduct the tests that ensure that electrical power equipment meets the ANSI/NETA standards’ stringent specifications. Certification of competency is particularly important in the electrical testing industry. Inherent in the determination of the equipment’s serviceability is the prerequisite that individuals performing the tests be capable of conducting the tests in a safe manner and with complete knowledge of the hazards involved. They must also evaluate the test data and make an informed judgment on the continued serviceability, deterioration, or nonserviceability of the specific equipment. NETA, a nationally-recognized certification agency, provides recognition of four levels of competency within the electrical testing industry in accordance with ANSI/NETA Standard for Certification of Electrical Testing Technicians, (ANSI/NETA ETT).

Setting the Standard