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Published by Megger
March 2009 |
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| The industry's recognised information tool |
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ELECTRICAL
TESTER |
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In this issue |
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Meeting the transformer challenge |
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When moisture means trouble! |
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Testing considerations for 61850 |
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Meeting the transformer challenge |
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| Dr Peter Werelius |
| Application & Project Management |
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| With an aging power transformer population, today’s power utilities face a tough challenge in trying to minimise the loss of revenue and repair costs associated with transformer failures. In fact transformers have become one of the most mission critical components in the power transmission network. |
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| The key to reducing the heavy losses associated with unforeseen transformer failures is reliable monitoring and diagnostic testing. However, traditional methods of transformer testing are usually inconvenient and time consuming, as well as being prone to delivering inconclusive results. |
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| To address these issues, dielectric frequency response (DFR) testing for transformers, which is also sometimes known as frequency domain spectrometry was developed. This test method has been used in laboratories for many years, but only recently with the introduction of the Megger IDAX range of test sets has it become a practical proposition in the field. |
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| DFR testing involves injecting test signals at discrete frequency steps between 1 kHz and 1 MHz into the transformer and plotting the response at each frequency. The resulting profile represents the properties of the insulating material in the transformer and can be subjected to further analysis to provide detailed and accurate information. |
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| One of the most important applications is determination of the moisture content in transformer insulation, as moisture in the insulation significantly accelerates the ageing process and can also cause bubbles between the windings, leading to catastrophic failure. DFR testing is an important aid in helping transformer users to avoid these problems, since it involves only a single test that can be completed in just a few minutes. |
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| The Megger IDAX-300 |
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| An important benefit is that the test can be carried out at any temperature. This is a sharp contrast to conventional methods of moisture assessment that rely on testing oil samples, since the water migrates between the transformer’s solid insulation and the oil as the temperature changes. |
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| For accurate results, therefore, the oil sample must be taken at a relatively high temperature when the transformer is in equilibrium. Unfortunately, this is a rare state in transformers and, in consequence, moisture assessments performed on basis of oil samples are often unreliable. |
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| The full benefits of FRA testing are provided by Megger’s latest IDAX test set, the IDAX300, which is smaller, lighter and faster to use than its predecessors. Designed for use with an external PC for measurement control and data analysis, the IDAX300 can complete a transformer moisture assessment in just eighteen minutes. |
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| The IDAX300 complements the existing IDAX206, which is an ideal option for users that prefer a standalone instrument. |
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| In addition to transformer moisture assessments, IDAX instruments can also be used measuring and analysing dielectric losses in bushings, cables, motors and similar components, making them a versatile aid for routine maintenance and faultfinding in power networks of all types and sizes. |
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When moisture means trouble! |
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| Adrian Parker |
| Applications Engineer |
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| Megger KF Lab and KF875 oil test sets |
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| Moisture in insulating oil not only reduces the efficiency of the oil as an insulator but may also indicate the degradation of solid insulation in transformers and switchgear, since water is a by-product of the breakdown of this type of insulation. The ability to accurately measure the moisture content of oil is, therefore, highly desirable. |
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| One of the most convenient and dependable solutions is the use of Karl Fischer coulometric titrimetry. This is the recognised industry standard method for determining moisture content, and the standard against which other instruments are calibrated. |
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| The Karl Fischer method is very sensitive, which is important as most insulating oils can be expected to have a moisture content in the low mg/Kg (parts per million) range. The method can however be used over a much wider range should this prove necessary. |
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| Modern test sets based on the Karl Fischer method, such as those in Megger’s KF range, are straightforward in operation, allowing them to be used easily by non-laboratory personnel, and they can provide accurate results in under a minute. |
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| With integral batteries and rugged construction, KF test sets have been specifically designed to be as suitable for use on site as in the workshop and laboratory. This is an important benefit, as on-site testing eliminates the contamination risks and other problems associated with storing and transporting samples, as well as giving on-the-spot results, thus allowing equipment with defective oil to be taken out of service without delay. |
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Testing considerations for 61850 |
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| Rene Aguilar |
| Application Engineer |
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| What is IEC 61850? IEC 61850 is the new international communication standard for substations. The main goal of 61850 is to obtain interoperability between different protective devices from different vendors. IEC 61850 has many benefits and one of these is replacing the traditional copper wiring with Ethernet/Fiber cables. This means no more binary inputs and outputs for control and protection functions. The traditional method of tripping a breaker via a contact will be replaced by a GOOSE (Generic Object Oriented Substation Events) messages sent via Ethernet or fiber optic cables. One of the major challenges currently facing 61850 is defining testing procedures. How is a 61850 device supposed to be tested? What is required in order to test these devices? |
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| Traditional testing methods can still be used to test 61850 devices. Voltage and current signals must be applied to the device in order for it to trip. The difference is in the way the tripping signal is monitored. Traditionally the user would connect a test lead from a binary input of the test set to a binary output of the protective device. When the protective device would trip the output would close and this would cause the input on the test set to activate and stop either test injections or a timer. With 61850 devices, a physical output is no longer monitored by the test set. The test set will have to be able to detect and pick up a GOOSE message. Once the correct GOOSE message is detected the test set must either stop injections and/or stop the timer. |
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| Challenges facing the testing of 61850 are the lack of knowledge many technicians have of the standard, and also understanding the functionality and implementation of a test system used in testing these devices. In order to know what GOOSE messages to monitor, the user has to be aware of the basic language of 61850. For example, SCL (Substation Configuration Language) files contain all the information of how the substation is configured but most importantly what GOOSE messages are available. |
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| Modern test systems must be able to receive and send GOOSE messages via the substation LAN. This would require the test system to be able to interrogate the network, acquire the right GOOSE message, and stop injections or timer in less than 2 milliseconds. This time is only achieved by the proper algorithm implementation in the test system. Also the test system would have to be able to read SCL files and map inputs to the various GOOSE messages available in the SCL file. If an SCL file is not available then the test system would have to be able to interrogate the network, and display all available GOOSE messages on the network, to allow the user to be able to map these messages to binary inputs on the test system. |
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| For example, a user needing to test a reclosing scheme using 61850 would perform the following. First, he would connect the test system to the network to determine what GOOSE messages are available. This can also be done via an SCL file. After all GOOSE messages of interest are found, these would be “mapped” internally to the binary inputs and outputs of the test system (similar to connecting the binary inputs and outputs of the relay using test leads to the binary inputs of the test system). The test values would be injected and the relay would trip sending a trip message to the network via GOOSE. |
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| Figure 1: Test Connections Used for Testing 61850 Devices |
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| At this time the test system must detect the message and record the trip time. After a few cycles of delay used to simulate breaker opening the test system will send a GOOSE message to the network simulating a breaker opening (52A) condition. The relay receives the message and initiates reclosing. Once the reclosing time expires; the relay will send another GOOSE message to reclose the breaker. At this time the test system acquires the message and sends another GOOSE message simulating breaker closing. This continues until the last reclosing cycle is performed by the relay. This is how a typical 61850 device would be tested. |
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| This might seem like a thing of the future. However, this standard is being used world-wide today, with hundreds of substations already in service. There are a number of substations in the US implementing 61850. However, some details were left out of the initial release of the IEC 61850 standard. There are groups currently working on defining these gaps in the testing of 61850 devices. One push is towards using a test bit, which is currently an optional setting (not in all IEC 61850 compatible relays). The user would set a test bit and the substation devices would know that the messages being sent by that device are not true events but a test GOOSE. |
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| Another topic is the use of Process Bus. Process Bus is defined by IEC 61850 Part 9-2. Process Bus is the digitalisation of all analog signals in the substation. This is achieved by connecting all current transformers, potential transformers and control cables to Merging Units. These units convert the analogue signals to binary signals and send the information via the Process Bus to all the devices that “subscribe” for that information. This is quite new and many manufacturers have not implemented this yet. As one can see IEC 61850 will be evolving as time passes. |
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| Suppliers of test equipment like Megger have to test not only new products, but also existing products that they intend to continue selling, to ensure that they meet the new standard. In order to do this, it is likely to that those suppliers will need to purchase additional equipment to extend the scope of their test installations up to 2.7 GHz. |
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| Although the suppliers will undoubtedly do all they can to absorb these additional costs, it is almost inevitable that a proportion will be passed on to their customers. In summary, therefore, the changes to the EMC test regime arguably mean that customers will get a better product, but almost certainly at a higher price. |
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