You are here: Home News Megger Application News Electrical Tester March 2010 from Megger
Electrical Tester March 2010 from Megger Print
Published by Megger
March 2010
The industry's recognised information tool
ELECTRICAL
TESTER
In this issue
What's in a name?
Dielectric frequency response and temperature dependence of dissipation factor
A view from Serbia
Cable fault location can be challenging!
What's in a name?
Nick Hilditch
Group Marketing Services Manager
For well over a century, the Megger name has been synonymous with quality, reliability and accuracy in portable electrical test equipment. But where did that famous name come from? It's a fascinating story.
Back in 1888, electric lighting was rapidly growing in popularity and Sidney Evershed was working for Goolden & Trotter, a company with a department that specialised in domestic electrical installations. To verify the safety of those installations, the company needed a reliable and convenient method of testing insulation. However, at that time, insulation resistance could only be measured in a laboratory, and the measurements were carried out at low voltages, typically around 2 V.
Evershed knew from his researches that testing at such low voltages gave unsatisfactory results, and that to ensure the safety of an installation, it was essential to test the insulation at its working voltage or higher. He also knew that the laboratory techniques for measuring insulation resistance were totally unsuitable for use on site.
His response was to develop the world's first direct-reading ohmmeter, which comprised a small permanent magnet suspended at the centre of, and controlled by, two coils at right angles to each other. One coil was connected directly to the voltage source energising the ohmmeter, the other was connected to the same voltage source via the insulation under test. This arrangement meant that the results obtained were independent of the voltage. Evershed energised his ohmmeter with a hand-cranked generator, similar to the type in use at the time for ringing telephones. The instrument proved to be so successful that Evershed patented it. Goolden & Trotter started to manufacture and market it in 1889.
In 1895, Sidney Evershed and Ernest Vignoles, another Goolden & Trotter director, purchased the instrument department from that company and set it up as Evershed & Vignoles Limited.
The insulation testers made by Evershed & Vignoles were given the name Megger, and on May 25, 1903, the company registered the word Megger as trademark number 254820 in
Sidney Evershed Ernest Vignoles
the UK. It has since been registered in almost every country of the world.
The exact date the word Megger was first used is not known, but it is believed it was devised by Ernest Vignoles. Some sources suggest that it is a contraction of the words MEGohm and metER, with the addition of an extra G, while others suggest that the original words were MEGohm and testER. Either way, the result is one of the best-known and most respected trademarks in the electrical industry worldwide.
Over the years, the Megger name has become so well known that instead of saying that they're going to carry out an insulation test on a item of equipment, many engineers and technicians will simply say that they're going to Megger the item. Nevertheless, Megger is still a registered trademark, and great care is taken to protect it.
That's not quite the whole of the Megger story. After several changes of ownership, Evershed and Vignoles eventually joined forces with AVO Limited, the company that developed the world's first multimeter, to form Megger Instruments. In 1991, Megger Instruments came together with Biddle and Multi-Amp in the USA to form the organisation then known as AVO. More recently acquired PowerDB, Programma and Pax.
Today, the whole organisation is known as Megger with development and manufacturing facilities in the US, the UK and Sweden. In the next edition of Electrical Tester, we will explain how James Biddle fits the picture.
Dielectric frequency response and temperature dependence of
dissipation factor
Matz Öhlén
Director - Transformer Test Systems
Peter Werelius
Applications and Product Specialist
This is a shortened version of a paper that won the coveted and prestigious Award for the most outstanding paper presented at TechCon Asia Pacific 2009.
Introduction
With an aging power component population, today's electrical utilities face a tough challenge as failures and consequent repair and revenue loss may inflict major costs. Transformers have become one of the most mission critical components in the electrical grid. The importance of reliable diagnostic methods drives the world's leading experts to evaluate new technologies that improve reliability and optimise the use of the power network.
The condition of the insulation is an essential aspect in the operational reliability of power transformers, generators, cables and other high voltage equipment. Transformers with high moisture content cannot sustain high load without risk; bushings and cables with high dissipation factor at high temperature can explode due to “thermal runaway”.
It is also important to identify “good” units in the aging population of equipment. Adding just a few operating years to the expected endof-life means substantial cost savings.
Traditional Dissipation Factor Measurements
The most common insulation diagnostic test is measuring capacitance and dissipation/power factor at 50/60 Hz. Most tests are done at 10 kV and operating temperature but there are also tests with variable voltage (tip-up) as well as tests where power factor versus temperature is measured. Analysis is based on (historical) statistics and comparing factory values. Since insulation properties depend on temperature, compensation is needed for measurements not performed at 20 °C. IEEE 62-1995 details typical power factor values for transformers and bushings, but these values are approximate guidelines only.
IEEE 62-1995 states; “The power factors recorded for routine overall tests on older apparatus provide information regarding the general condition of the ground and interwinding insulation of transformers and reactors. They also provide a valuable index of dryness, and are helpful in detecting undesirable operating conditions and failure hazards resulting from moisture, carbonisation of insulation, defective bushings, contamination of oil by dissolved materials or conducting particles, improperly grounded or ungrounded cores, etc. While the power factors for older transformers should also be <0.5% (20 ºC), power factors between 0.5% and 1.0% (20 ºC) may be acceptable; however, power factors >1.0% (20 ºC) should be investigated.”
Dielectric Frequency Response Measurements
The first field instrument for DFR/FDS measurements of transformers, bushings and cables was introduced 1995. Since then, the technology has been extensively evaluated and several international reports have identified dielectric response as the preferred method for measuring moisture content in power transformers. In DFR tests, capacitance and dissipation/power factor are measured. The measurement principle and setup are basically the same as for traditional 50/60 Hz testing but insulation properties are measured at frequencies ranging from mHz to kHz, rather than at line frequency. The results are normally presented as capacitance and/or tan delta/ power factor versus frequency. Measurement setup is shown in Fig 1, and typical results in Fig 2.
Figure 1 – DFR/FDS test set up
Figure 2 – DFR/FDS power factor measurements on four transformers
Moisture Assessment
The ability of DFR to measure dissipation factor as function of frequency is a powerful tool for diagnostic testing. Moisture assessment is one example.
High moisture level in transformers is a serious issue since it limits the maximum loading capacity (IEEE Std C57.91-1995) and it accelerates the aging process. Accurate knowledge of the moisture content in the transformer is needed to make decisions about corrective actions, replacement/scrapping or relocation to a different site with reduced loading.
The method of using DFR for determining moisture content in the oil-paper insulation inside an oil-immersed power transformer has been described in detail in several papers and is only briefly summarized here.
The dissipation factor plotted against frequency shows a typical S-shaped curve. With increasing temperature the curve shifts towards higher frequencies. Moisture influences mainly the low and the high frequency areas.
The middle section of the curve with the steep gradient reflects oil conductivity. Fig 3 shows how these parameters influence the master curve.
Figure 3 – Parameters that affect dissipation factor at various frequencies
Using DFR for moisture determination relies on comparing the transformer’s dielectric response to a modelled dielectric response (master curve). A matching algorithm rearranges the modelled dielectric response and delivers a new master curve that reflects the measured transformer. The moisture content along with the oil conductivity for the master curve is presented. Only the insulation temperature (top oil or winding temperature) needs to be entered as a fixed parameter.
Figure 4 – MODS analysis for two transformers
Figure 4 shows the results for two different transformers. They have the same 0.7% dissipation factor at 50/60 Hz, characterized by IEEE 62-1995 as a warning status calling for investigation. The investigation is done by moisture analysis using MODS. This reveals that the two transformers are very different and that they need different maintenance measures.
Transformer 1 has good oil but needs drying. Transformer 2 has low moisture but needs oil change or regeneration.
Bushing Diagnostics
Aging/deterioration of high-voltage bushings is a growing problem and various methods have been suggested and tried for detecting bushing problems before they turn into catastrophic failures. This includes on-line monitoring as well as offline diagnostic measurements.
Traditional 50/60 Hz dissipation/power factor testing may give an indication of aging/high moisture content, especially if performed at various temperatures. Dissipation factor values at lower temperatures are similar from very low to moderate moisture contents; significant differences are not seen until around 50 °C.
Increased dissipation factor at higher temperatures is a good indicator of bushing problems. Catastrophic bushing failures (explosions) are often caused thermal runaway, when a high dissipation factor at higher temperatures result in an increased heating of the bushing which in turn increases the losses causing additional heating which increases the losses even further until the bushing explodes.
DFR measurements and analysis together with modelling of the insulation system includes also temperature dependence. A new methodology (patent pending) is to perform DFR measurements and convert the results to dissipation factor at 50/60 Hz as a function of temperature.
This technique has major advantages in measurement simplicity. Instead of time-consuming heating/cooling of the bushing and taking measurements at various temperatures, one DFR measurement is performed and the results are converted to 50/60 Hz tan delta values as a function of temperature. In Figure 5 shows the results in comparison with the classical results presented by Blodget in 1962.
Figure 5 – Power factor at 60 Hz as a function of temperature for oil-paper insulation with various moisture contents
Applying this technique to real-world DFR measurements on bushings gives the results shown in Fig 1, where two bushings – “OK” and “bad” – are compared with manufacturer's values. The “bad” bushing is estimated to have about 4% moisture and should be considered “at risk”.
Individual Temperature Compensation
Temperature correction tables like those in IEEE/C57.12.90 give average values assuming average conditions and are not correct for an individual transformer or bushing. Utilities have noticed this and try to avoid temperature correction by recommending that measurements are performed over a narrow temperature range.
Figure 6 – Bushing dissipation factor as a function of temperature. Measured and converted data compared with published data.
Figure 7 – Standard temperature correction compared with individual temperature correction for samples of GE Type U bushings
With DFR and the technique for converting data to temperature dependence, it is possible to do accurate, individual temperature compensation (patent pending). For a good component, the temperature dependence is small. When the component ages or deteriorates, the temperature correction becomes much larger, i.e. the temperature correction is a function of aging.
Bushings
Manufacturer's data is only valid for as-new bushings. As soon as the bushing starts to deterioration, temperature dependence increases. Bad bushings have a large temperature correction.
Transformers
Individual temperature correction for transformers is more complex than that for single material components like bushings. The oil-paper insulation activation energy constant W2 in Arrhenius’ law, κ = κ0exp(-W2/kT) with activation energy Wa and Boltzmann constant k, is typically 0.9-1 eV, while for transformer oil W2 is typically around 0.4-0.5. Individual temperature correction for transformers of various age is shown in Figure 8.
Figure 8 – Temperature corrections for transformers in various conditions
Conclusions
Dielectric Frequency Response (DFR/FDS) measurement is a technique for general insulation testing and diagnostics. In comparison with standard 50/60 Hz dissipation factor measurements, DFR measurements have the following advantages:
Capability of performing individual temperature correction of measured 50/60 Hz dissipation/ power factor
Capability of estimating the moisture content of oil-immersed cellulose insulation in power transformers and bushings
Capability of estimating dissipation/power factor at operating temperature in order to assess risk of thermal runaway catastrophic failure
Capability of investigating increased dissipation factor in power components
Insulation properties are very important for determining the condition of power system components, and knowing the condition of these component helps to avoid potential catastrophic failure. Identifying good units and deciding upon correct maintenance in transformers and other power systems approaching end-of-life can save significant money due to postponed investment costs.
The full version of the paper, which includes additional figures and tables as well as comprehensive references, can be viewed at www.megger.com
A view from Serbia
Ivana Zivanovic
Ivana holds a BSc E E from the faculty of electrical engineering in Belgrade, Serbia, where she wrote her thesis on EMC testing. She has worked for nine years for Tectra AG, a Swiss-based company that represents leading manufacturers of test and measuring equipment for use by power utilities, refineries and other areas of industry.
It's the fastest growing economy in the Balkans, it's the power transmission hub of the region and it’s preparing for membership of the EU – clearly Serbia is a country worth watching. That's why we asked Ivana Zivanovic, Managing Director of Tectra, a leading supplier of test and measurement equipment in the Central European market, to provide us with an up-to-the-minute country briefing.
Overview
The Republic of Serbia is located in southeast Europe and covers the central part of the Balkans. On a purchasing power parity (PPP) basis, it had a GDP of almost $79 billion in 2008, when its economy was growing by 8.7% per annum. Serbia's principal trading partner is the EU.
Despite its dynamic economy, the current business situation in Serbia is far from ideal as the country is in a transitional period with most of the state-owned companies going through a phase of privatisation and modernisation. As a result, the number of small and mid-sized companies is increasing at the expense of large, state-owned organisations. These changes are causing considerable disruption at the present time and, in the short term at least, they will undoubtedly continue to do so. The new smaller companies are, however, helping the country to move away from the difficult economic times it experienced in the 1990s.
In addition to the electrical power industry, the country has two refineries, one in Pancevo and one in Novi Sad, both of which have recently been purchased by Gazprom Neft of Russia. Serbia is also active in the manufacture of food and beverages, and it has significant chemical and petrochemical industries. In the automobile sector, the Zastava company in Kragujevac has recently made an agreement to manufacture vehicles for the local market under a licence from Fiat.
In the area of standards for the electrical sector, Serbia has its own national standards that are based on IEC guidelines.
Power transmission
When Serbia was an integral part of the former Yugoslavia,
a 400 kV transmission net-work in the form of a ring was built. This now plays a key role in linking the power system of the former Yugoslav territories – Slovenia, Croatia, Bosnia, Montenegro and FYR Macedonia as well as Serbia – all of which are now separate states. More recently, Serbia has built another 400 kV ring. This connects to Bulgaria and Romania at Serbia's eastern border, and also provides links to Western Europe via Slovenia and Croatia, to Central Europe via Hungary and to Greece via FYR Macedonia.
These networks make Serbia the power transmission hub for the region, and its transmission systems play a key role in ensuring the stability and flexibility of the supply system for much of Europe.
Power generation
Serbia has the largest power generating capacity and the largest transmission network of all the countries in the Balkan region. More than 60% of the power generated in Serbia comes from conventional thermal plants of which 90% burn coal, the remaining 10% natural gas. The largest thermal plant – designated Nikola Tesla, after one of Serbia's most famous electrical engineers – is currently being upgraded to provide an additional 600 MW capacity. There are also plans for a completely new thermal plant with a capacity of 600 MW.
The balance of Serbia's power, almost 40%, comes from hydroelectric plants, the largest of which, Djerdap I and Djerdap II, are on the border with Romania. A new hydroelectric plant, on the border between Serbia and Bosnia, is planned. Serbia has no nuclear power plants.
Power transmission and distribution
Transmission in Serbia takes place at 400 kV, 220 kV and 110 kV. The power lines themselves and the substations are operated by a company within the power utility. The country has adequate transmission capacity but a modernisation programme, which started several years ago, is underway with the principal objective of providing automatic control.
Residential services
Power is supplied to residences at 380/220 V. All maintenance of the low voltage network, up to and including the customer's meter, is the responsibility of the local power distribution company.
The environment
For many years, environmental protection was not a high priority in Serbia but, the democratic changes made since 2001 and the country's ambitions to join the EU mean that much more attention is now given to ecological issues. One important consequence is that many power stations and industrial plants are now being fitted with filters and emission monitoring systems.
The future
Without doubt, the trend that has already been mentioned for large formerly state-owned organisations to be split up into smaller companies under private management will continue. Considering the power utilities specifically, maintenance sectors are being separated out, and the plan is that, in the future, these will be independent organisations. This should mean that they will be better equipped with modern test equipment and that, because of competition in the free market, the service they provide should improve.
Cable fault location can be challenging!
Sureshchandra Narayana
Regional Sales Engineer
Sureshchandra Narayana found locating a fault on a power cable at one of the naval base facilities in India to be more than usually challenging!
When it comes to locating power cable faults, many options are available including, for example, time domain reflectometry, arc reflection, surge impulse current and voltage decay. Some of these techniques are better suited to high resistance faults, and some to low resistance. There are some faults, however, like the one described here, that seem to defy location by any of these methods!
The fault in question was on a 900 m long 11 kV XLPE cable buried at a depth of about 0.8 m. As is normal practice, our first step was to carry out an insulation test, which confirmed that there was indeed fault on the R phase.
The resistance of the fault was around 22 kΩ, which immediately suggested that locating it using high voltage techniques was unlikely to be successful, as these work best with high resistance faults. This was confirmed when we attempted to apply a high voltage to the cable, and the instrument's kilovolt meter failed to move from zero.
Our next step was to connect a time domain reflectometer (TDR) to the faulty core. The trace on the TDR screen clearly showed the end of the cable at a distance of 945 metres and closer inspection revealed a small almost sinusoidal kink in the trace at a distance of 288 metres, which looked very much like a cable joint. When we checked with the site engineers, they confirmed that there was indeed a joint at around 300 metres. But where was the fault?
Although we knew that the fault would not stand high voltages, we decided to try using the arc reflection method with as low a voltage as possible, as this was almost our last option. We chose a surge voltage of 2 kV, but the resulting trace revealed nothing. Hoping that this simply meant that the arcing wasn't sufficiently stable at that voltage to capture a useful trace, we repeated the test with higher voltages, but still without success.
Next we tried the surge impulse current method, but applying different voltages and capturing multiple traces didn't help in any way to pre-locate the fault. We considered walking along the cable with an acoustic pick up while applying surges to the cable (thumping), but obstructions
along the route of the cable made this almost impossible. We really did need some way of locating that fault!
Next we decided to go back to the TDR and to observe the trace more closely while using different gains and pulse widths, in the hope of gaining some clues. However, the trace remained unchanged, giving us absolutely no useful information. At this point, almost in desperation, we connected the TDR to one of the cable’s good cores. There was a small difference in the shape of the trace around the joint at 288 m!
This looked interesting, so we tried the second healthy core. The traces for both healthy cores matched around the area of the cable joint, but the trace from the faulty core didn't! Since this was the only point where we could see anything at all suspicious, we started thumping the cable and checked the joint location with an acoustic pick up. Within ten minutes, we’d found the fault.
The lesson to be learned from this experience is that phase comparison using a TDR is a very powerful tool for locating cable faults without the need to apply a high voltage to the cable. We should probably have tried it sooner – it's a simple straightforward technique that, as this example shows, can work when all other methods have failed.
< Prev   Next >