Power transformers are a critical, capital-intensive asset for the utility industry.  As an asset manager reviewing the life expectancy of a transformer, or a substation operator responsible for determining the loading capabilities of a transformer, you should be concerned with the water content in your transformer.

One of the most important ageing indicators of transformers is the water content in the solid part of the insulation (paper, pressboard).  Accurate diagnostic tools for determining the health of your transformers is critical. The OMICRON DIRANA is a unique and efficient device which determines the water content in the solid insulation.

Moisture entering in to oil-paper insulation can cause three dangerous effects in transformers: it decreases the dielectric withstand strength, accelerates cellulose ageing (de-polymerization) and causes the emission of gas bubbles at high temperatures.

Water in transformers comes from four sources: residual water after drying, water from cellulose and oil ageing, water through leaky seals or repairs, and water due to breathing.  Therefore, even in the case of a non-breathing transformer the moisture can reach a critical level.

The DIRANA measures the dielectric response of solid insulation in equipment. The dielectric response is a unique characteristic of the particular insulation system.  The increased moisture content of the insulation results in a changed dielectric model and, consequently a changed dielectric response.  By measuring the dielectric response of the equipment in a wide frequency range, the moisture content can be assessed and the insulation condition diagnosed.  For the dielectric response, the measurement is performed as a traditional ungrounded specimen test (UST), made from the high voltage winding to the low voltage winding (CHL) in a two winding transformer.  We are most concerned with the CHL test, as this is the measurement which contains the most cellulose insulation material.  The test connections and modes are the same as used in a traditional transformer insulation Tangent Delta (or power fact)test with the difference being that it is performed at a low voltage, up to 200vpp, and the test is performed at frequencies from 1 kHz to 10µHz. 

The unit combines the polarization current measurement (PDC) method in time domain with frequency domain spectroscopy (FDS) and thus significantly reduces the testing time compared to existing techniques.  Essentially, time domain measurements can be accomplished in a short time period but are limited to low frequencies. The extended measurement range of 5 kHz down to 50 µHz, allows the DIRANA to discriminate between the oil, insulation geometry and paper.  The result is independent from the moisture equilibrium.

The patented technique combines the advantages of both principles.  It acquires data in the time domain from 10 µHz to 0.1 Hz and in the frequency domain from 0.1 Hz to 5 kHz.  This reduces the measuring duration by up to 75% compared to exclusive frequency domain measurements.

DIRANA's moisture determination is based on a comparison of the transformer's dielectric response to a modelled dielectric response. A fitted algorithm compares the measured data with the modelled data and calculates the geometry data, the moisture content, as well as the oil conductivity.  The moisture assessment is based on IEC 60422. The software is very easy to use, and the user only needs to enter the oil temperature.

Aged transformer oils often have increased values of conductivity due to acids and other ageing byproducts. This can lead to incorrect water content results. The insulation model in the DIRANA's software compensates for this influence.

Excessive water content can be extremely detrimental to the life expectancy of a transformer. The Dirana provides a simple, non-intrusive method of detecting this moisture and alerting the user of the need to take action to alleviate the problem.


Tel: 01785 251 000

There is no legal requirement to replace aged oil filled switchgear with modern vacuum types. The fact is most switchgear, of any age, if properly maintained is both safe and reliable. oil filled switchgear has been with us a long time and has proven to work well. In which case why does there remain an imperative to upgrade oil filled equipment? There are safety, reliability and cost considerations that belie the above statements, as Tony Harris of the PBSI Group explains

Safety, reliability or cost in any combination provide a real incentive to evaluate existing switchgear in any application. In spite of the fact there is no legal requirement to modernise existing aged installations, the Health and Safety Executive, the British Standards Institute and the Institution of Engineering and Technology have all published documents relating to safety. By the same token, major users of switchgear, such as the UK’s Network Distribution Operators and the power generation industry have also highlighted the need to modernise because of the mission critical nature of their applications. Finally the rising costs of maintenance and the, often, punitive penalties for system failure have added a significant motivation for renewal.

Dealing with safety issues first and foremost, it must be reiterated that dangerous failures of switchgear are rare. Unfortunately, rather like other rare failures, such as aircraft malfunctions, the consequences can be disastrous. Similarly, we only consider within this article, the equipment itself under safe and responsible operation, rather as we would not consider human error to reflect on the fitness for purpose of any other item of equipment.

The HSE makes clear in the introduction to its excellent Electrical Switchgear and Safety – A Concise Guide for Users that: In general, switchgear has a proven record of reliability and performance. Failures are rare but, where they occur, the results may be catastrophic. Tanks may rupture and, with oil-filled switchgear, this can result in burning oil and gas clouds, causing death or serious injury and major damage to plant and buildings in the vicinity. Failures of switchgear can also result in serious financial losses.

Having stated there is no law requiring users to replace aged switchgear, it is a legal requirement to provide management systems to ensure safety and minimise the risks of injury. To comply with this obligation it is clear that switchgear must be inspected, assessed and where necessary overhauled, repaired or replaced.

This having been said, de-skilling and cost reductions in some organisations have left them without the specialised knowledge needed to properly assess the function, potential risks and remedies where equipment is involved.  Switchgear suppliers must therefore provide intelligent and conscientious assistance to users – which does not mean simply selling them some new equipment!

Let's take a look at some of the dangers specifically associated with the use of older switchgear. Among the most important are:
- Lack of knowledge – users may not have enough knowledge to be aware of the potential risks involved
- Overstressing – the switchgear may not be rated to handle present-day full load currents and fault levels
- Modifications – the manufacturer may have issued recommendations for modifications to ensure that the equipment remains safe to operate. It is essential these are implemented
- Dependent manual operating mechanisms – all switchgear currently in use must incorporate operating mechanisms that do not depend on the operator's strength and speed to make and break contacts. Any switchgear that does not meet this requirement is unfit for use
- Lack of proper maintenance – this is usually the result of oversight, but may also be due to limitations imposed by financial controllers in order to minimise shutdowns. It is important that maintenance of older switchgear takes into account the age and peculiarities of the equipment.

Addressing these issues involves implementing an effective switchgear management system. A very good starting point for this is Health and Safety Executive document HSG230 Keeping Switchgear Safe. The guidelines contained in this document define records that need to be kept and keeping these records will ensure that:
- The switchgear is not outside its managed life cycle
- The maintenance cycle and the maintenance work carried out has taken into account the age of the switchgear
- The maintenance has been fully and correctly completed
- A full maintenance history is available
- All restriction notices have been considered and, where necessary, appropriate actions have been implemented
- The Switchgear is known to fall in line with latest requirements, such as independent manual operation, anti-reflex handles
It is worth noting these records not only provide a framework for increasing the reliable and safe operation of the equipment, but also help to meet legal obligations, not least those related to ensuring that employees are protected from harm.

Safety in practice
Increasingly companies have become reluctant to operate older switchgear locally – particularly oil circuit breakers. With this in mind a minerals company recently ordered new vacuum oil replacement breakers, P&B Switchgear’s VOR-M, to replace old MV oil switchgear at its salt mining installation in Cheshire.

Vacuum retrofit breakers have been installed to replace 11kV oil breakers at a major pharmaceutical plant in Speke, Liverpool. This enables remote operation, as opposed to the local, manual, operation of the old switchgear. Not only does this ensure greater safety, but it also means switchgear can be operated without personnel having to don cumbersome arc flash protection clothing.

A major chemical company is also replacing old and obsolete air switchgear with 415V switchgear with modern compact air circuit breakers. During type testing of new retrofit circuit breakers to replace 415V circuit breakers from two well known, but now defunct, UK manufacturers, the original isolating contacts from both designs failed catastrophically under short circuit conditions. The fault level was within the rating of the equipment when supplied many years ago, indicating deterioration in performance of the contacts. Fortunately, P&B Switchgear was able to supply alternative type tested replacement isolating contacts with the circuit breakers to ensure the customer has a safe installation – this might perhaps start to ring warning bells with other switchgear users.

Reliability is key
Because diligently maintained and inspected switchgear of any age can be considered safe, a greater incentive to consider replacement or renewal of existing switchgear is often reliability. Reliability in sectors such as power generation, utilities, oil and chemical industries, transport and so forth is crucial. However, accurately assessing mean time between failures for switchgear is almost impossible. Hence, these industries often regard it as beholden upon themselves to mitigate worst case scenarios, however potentially unlikely. Many operators resort to establishing arbitrary maintenance procedures and time intervals based on their type of switchgear, age of equipment, its location and environment and so on. This usually involves high degrees of guesswork, certain assumptions and, if reliability is of paramount importance, a truncation of the service or inspection intervals. None of which is particularly efficient, but reliability trumps efficiency in such circumstances.

The main reasons for replacing switchgear are usually because the age of the equipment is causing a high level of maintenance, this in turn causing higher costs, lack of availability (reliability) and difficulty in locating obsolete spare parts. Some motives are to remove oil (safety) although some companies have elected to introduce remote operation on older switchgear as a cheaper way to improve safety by removing the need for a local operator. Safety may become a key driver for replacement in the future.

The use of the latest equipment with its inherent monitoring and reporting facilities, increases efficiency and hence reduces costs. However, in older plant, it is the reliability, rather than the automation, of the system that is the highest priority.

Reliability in practice
Most UK coal power stations were fitted with 11kV and 3.3kV air break switchgear when they were built in the 1960s. Over the past decade or so the circuit breakers have needed increased maintenance. That, coupled with the difficulty in obtaining spare parts for obsolete equipment, has led to many of the older breakers being retrofitted with P&B Switchgear vacuum circuit breakers. The overwhelming majority of these power stations have ranges of fully type tested retrofit vacuum breakers on most key circuits to increase reliability of operation. This is manifest in increased time between maintenance and in many cases, to increase the fault level to cater for additional generation being added over time. P&B designs have been type tested to well over 50kA rms, with peak making currents and DC components enhanced far above the original, or indeed, current IEC/BS requirements. Examples of this are at Ratcliffe, Cottam, Ferrybridge, Fiddlers Ferry, West Burton power stations to name a few.

The latest designs of breakers to replace oil types incorporate resin embedded vacuum interrupters and magnetic actuator operating devices for the ultimate in maintenance free, long life operation. This is especially suitable when frequent use is an important requirement, such as in process industries.

Costs are a key driver when assessing assets and running expenses. This is in greater focus even in the power generation sector, where costs have generally been less of a factor – reliability and safety ranking higher. It is understandably difficult to quantify costs and therefore economies in operating switchgear. However, the impact of greater reliability and perhaps just as significantly the ability to monitor and control the installations have made substantial savings that greatly offset the price of renewal of entire switchgear panels or the upgrading of them using the latest relay technologies.

Cost justification in practice
Replacing switchgear is never high on the list of capital requirements unless the previously discussed factors are important. As mentioned earlier there are guides issued by the likes of the HSE which assist users in the selection process of replace, refurbish or retrofit, but the cost of the options is usually a significant factor.

Often a straight forward approach is to simply remove the old switchboard and install a complete new one. This delivers a new installation compliant with the latest standards, but it is not usually the most cost effective option, even when the protection is to be replaced at the same time. Depending on the size and type of substation, replacing the old with new switchgear is likely to result in extra time and costs for building work, further costs and, of course, potential risk in disturbing or replacing cables that result in longer project timescales on site. It also requires a complete shutdown. Since in many cases the switchgear fixed portion is in good enough condition, these issues can be avoided with a circuit breaker retrofit option, even if the decision is to upgrade  to modern protection relays.

Some companies consider the initial cost of a suite of retrofit breakers and argue this amounts to perhaps70% of the price of a new switchboard. However, when one takes into account the additional costs described earlier, the overall installed price for the retrofit option is typically nearer to 50%, with less disruption and reduced downtime. The case for organisations to select reliable partners has become increasingly important.

The UK government is currently looking to smart meters as one of the key initiatives to drive energy efficiency, transforming the country’s consumption of energy by enabling consumers to make informed choices regarding their energy use, lower their bills and reduce carbon emissions. Andy Slater, director at Sensus, explains

Traditionally copper has been the material of choice when it comes to electrical conductors, but in February 2011 its price per tonne broke through the $10,000(US) barrier for the first ever time. And, AS with fuel prices here in the UK, it looks set to continue rising. So what does the spiralling cost of copper mean to the electrical industry? Electrical Review spoke to Steve Marr, the marketing manager of Legrand’s power distribution division, to find out more

For as long as any of us care to remember copper has been the chosen material when it comes to conducting electricity, but in recent years this position has begun to be undermined by the growing acceptance of aluminium as a suitable alternative.

And now, with the soaring cost of copper putting it in real danger of becoming prohibitively expensive, aluminium looks like it could have the opportunity to make its move and become the electrical conductor of choice here in the UK.

But how do the two rate against one another? In the past aluminium tended to be seen as the poor relation to copper, but today it’s very much a high performance product that compares favourably with copper in terms of mechanical strength, heat stability and thermal conductivity.

Nowhere can this transformation be better seen than its performance in two key power distribution product groups – namely busbars and cast resin transformers.

Over the last 50-years, busbar power distribution systems have increased in versatility and sophistication and are now widely regarded as the first-choice solution for power distribution projects in most industrial and commercial applications.

An interesting element of the busbar’s development has been the significant shift away from copper to aluminium solutions – both in terms of manufacture and specification.

The reasons for its surge in popularity are plentiful, but interestingly one of the key ones is cost. On the world’s commodity market aluminium’s value is far more stable than copper, and is not so sensitive to the ‘ebb and flow’ of consumer demand, political uncertainties and other economic and climatic factors. For example, the flooding and cyclone in Australia earlier in the year had a significant impact on the price of copper due to the fact copper mines, such as Mount Isa in Townsville, Queensland, were forced to temporarily shut down. As a result, aluminium can consistently provide significant cost savings.

The benefits of aluminium do though stretch far beyond the simple question of cost. Take for example, conductivity. Although aluminium’s conductivity is only 62% that of coppers, it is 70% lighter - for example our Zucchini 4000A busbar is 62.7kg per metre in aluminium, compared to 101kg per metre in copper. This not only saves money on transportation, but helps to reduce time, effort and, of course, cost during installation. In return for this substantial weight saving the aluminium bar is slightly deeper, but only by an extra 40mm with a total depth of 480mm. What this means is when you compare an aluminium system against a copper-based system of equal size and weight, aluminium is scored twice as conductive as copper

Historically, the key concern specifiers had with aluminium was its susceptibility to oxidisation, which caused significant problems with contact conductivity at the joint. This issue is no longer a concern with any Zucchini busbar system as all our aluminium conductors are electro-tin plated specifically to eliminate this problem.

Moving on, the plus points in aluminium’s favour come thick and fast. For example, unlike ferrous metals, aluminium doesn’t generate sparks when used in combination with other metals, making it ideal for use in potentially flammable or explosive environments.

Also, as aluminium is nonmagnetic it’s ideal for use in applications that need minimum magnetic interference. These include high-voltage applications as well as electronics.
And if that wasn’t enough, aluminium alloys have a mechanical resistance of 60 to 530 Newton/mm², which is more than sufficient, and compares favourably with copper.

When taken as a whole, we feel these benefits mean the advantages of specifying aluminium busbar systems easily outweigh those of copper systems in terms of performance, safety and cost.

Despite all of these advantages, the debate over the best busbar solutions still rages on. So much so that the majority of manufacturers still offer bother copper and aluminium solutions, simply on the basis that there are still consultants and specifiers who will always opt for copper and that there are certain installations where copper is seen by many – often mistakenly – as the best option.

Cast resin transformers
In contrast, the debate when it comes to cast resin transformers is very much done and dusted, with aluminium standing triumphant over its copper foe. In fact, a growing number of manufacturers now only offer aluminium solutions.

The reason for this is simple – the benefits of aluminium far outweigh copper in these systems.

Perhaps most importantly, the coefficient of thermal expansion of aluminium is more similar to the coefficient of the resin than copper. What this means is that when the transformer is loaded the compatibility between the expansion coefficient of aluminium and the resin used for the casting ensures against the potential for possible cracks in the cast resin coils – a guarantee that copper simply can’t deliver.

In addition, because aluminium windings work at a lower current density than copper windings this enables them to have a better short term overload capacity.

The vast difference in the weight of the two materials again comes into play, with aluminium wound cast resin transformers being far lighter than copper wound ones. And finally, the efficiency of aluminium wound products is guaranteed to be the same as the equivalent copper wound version.

What happens next?
As with any industry, the path to significant change in the electrical industry is a slow and arduous one. People with long-held beliefs need to be educated as to the benefits of the newer solution and why it should usurp the traditional one.

In the majority of cases this process alone is unlikely to convince everybody, which is why you see the kind of situation arising that we currently have in the busbar market. This being that despite the fact the overwhelming evidence points towards the advantages of aluminium solutions far outweighing those of copper, there are still enough decision makers within the market who prefer copper to warrant manufacturers producing both solutions.

Of course, there is one factor that can always be relied upon to change people’s mind – money. Yes, aluminium has a host of attributes, in terms of mechanical strength, heat stability and thermal conductivity that put it on a par, if not ahead of copper, but it is the financial aspect that will almost certainly tip the scales in its favour as the conductor of choice here in the UK.

To recap, copper prices are at an all time high. And when you consider the global economy is unlikely to deliver the kind of stability needed to rein these prices in at any stage soon, and add to that the fact the climate is also weighing in with its own natural problems, it seems certain the only way is up for the price of copper. All of which means one thing, the future surely has to be aluminium.

Legrand offers a wide selection of aluminium busbars and cast resin transformers. Its Zucchini MR aluminium busbar range is available in all sizes from 160 to 1,000A, while its SCP busbar range is offered in all sizes up to 5,000A. Both systems feature a large selection of tap-off boxes that allow the supply and protection of a wide range of loads using different devices such as fuses, MCBs and MCCBs. The company also manufactures both products with copper conductors.

In contrast, Legrand’s range of cast resin transformers is manufactured solely with aluminium conductors. The Zucchini EdM range satisfies high power, medium voltage market needs, with bespoke solutions available upto 17,000kVA.

Unfortunately only a few professional specifiers, contractors and traders in the electrical sector know about their responsibilities under the Low Voltage Directive and related CE marking. Dr Jeremy Hodge, chief executive of BASEC explains

Cutting electrical energy use in motor-driven applications through the use of variable- speed drives (VSDs) is a well-proven method, but not everyone is getting the message. ABB takes a systematic approach to energy sustainability that provides proof of just how much can be saved

A major part of sustainable manufacturing is using energy wisely. As energy prices continue to rise, it is becoming increasingly important to make the most efficient use of energy, both as responsible companies that care about the impact on the environment and for the future profitability of the company.

Yet, many companies do not know where their biggest energy use is and have misguided ideas about how best to cut it. A survey of UK manufacturing managers revealed the most common method of reducing the electricity bill was to switch suppliers, yet as all suppliers are increasing their prices, this can only provide a minimal saving. Other managers cited increased compressor efficiency or improved factory heating. The real answer lies in looking objectively at where electricity is used most and assessing how it can be reduced cost- effectively.

The elephant in the room is electric motors when you consider 65% of the total electricity at industrial sites is consumed by electric motors driving pumps, fans and compressors to name but a few.

To make the most of potential new business opportunities in the growing solar panel sector‚ contractors need to understand the technology and the electrical testing associated with PV system installation‚ says Jim Wallace of Seaward Solar

Energy regulator OFGEM recently reported the 2010 year end total of solar power installations reached 45MW. Month by month numbers of domestic PV installations ended the year with over 2‚000 per month during November and December.

This solar microgeneration ‘boom’ reflects the impact of Feed-in Tariffs (FITs) introduced from 1 April 2010 and also the arrival of free installation schemes that enable the property owner to benefit from solar electricity while the installer receives the FIT payments. Any PV installation seeking funding from the FITs initiative must use Microgeneration Certification Scheme (MCS) approved contracting companies. MCS is a quality assurance scheme and approval is therefore a pre-requisite for any company seeking to take advantage of the growing demand for solar panel installation.

Given the obvious synergies‚ it is widely expected grid connected PV systems will quickly become a mainstream electrical contracting industry activity. Alongside MCS accreditation‚ the installation process itself is unlikely to be too difficult for a qualified electrician‚ although there are significant differences from the usual installation wiring technology that they are likely to be working with on a day to day basis.

PV installation overview
The installation of PV systems presents a unique combination of hazards linking the risk of electric shock with the implications of working at height.

PV arrays produce a DC voltage when exposed to sunlight. In the wiring system associated with PV panel installation‚ the DC current generated by the solar array is converted to AC by means of an inverter which then feeds into the AC mains supply of a building.

From the outset, therefore, the designer and installer of a PV system must consider the potential hazards carefully and systematically devise methods to minimise the risks - including mitigating potential hazards present during and after the installation phase. In particular, it is vital the long term performance and electrical safety of the system is not compromised by a poor installation or subsequent poor maintenance.

Much of this comes down to the quality of the installation and the system inspection and testing regime.

PV systems are unusual in that the energy source cannot be switched off. If there is daylight falling on a PV panel it will produce electricity and it is possible for a relatively small array of only a few panels to deliver a lethal shock.

Another important point is PV panels generate DC voltage, which is not always commonly used by electricians in their normal work. In addition‚ because of the current limiting properties of PV cells‚ they are incapable of producing sufficient fault currents to operate over-current protection devices such as fuses. Once established a fault may remain undetected, not only posing a hazard for an extended period but also wasting energy generated by the PV system. Undetected faults may also develop into a fire hazard over time. Special measures must therefore be taken during installation of PV systems to eliminate the risks of dangerous working and latent electrical problems.

These include completing the DC wiring before connection is made to the panels and avoiding working with both positive and negative conductors simultaneously. This will allow the effective isolation of the dc system (via a DC isolating switch and module cable connectors) while the array is installed and the effective isolation of the PV array while the inverter is installed.

Installation standards
The general requirement is that grid connected PV solar systems are tested according to 17th edition electrical wiring regulations but there also additional requirements for PV systems.

Engineering Recommendation G83/1 is the installation commissioning confirmation form for the connection of Small Scale Embedded Generators‚ such as PV arrays‚ of up to 16A per phase with public low voltage distribution networks. Installers are required to complete G83/1 with information on various tests‚ system details and a range of supporting information to satisfy the requirements of the Distribution Network Operator.

Installation of domestic grid connected PV systems falls with the scope of Part P of the Building Regulations and it the responsibility of installer to ensure systems are installed according to the existing BS7671 electrical installation standard – the 17th Edition IEE Wiring Regulations.

However‚ the inspection and testing of DC circuits associated with PV arrays requires special considerations.  The IEE Guidance Note 7 Special Locations provides guidance on Solar photovoltaic (PV) power systems.

‘IEC 62446: 2009 Grid connected PV systems – minimum requirements for system documentation, commissioning tests, and inspection’ specifies the minimum requirements for PV system documentation‚ commissioning tests and inspections.

Building or electrical works in the vicinity of the PV array are also likely and the ownership of a system may also change. The standard recognises that only by the provision of adequate documentation at the outset can the long term performance and safety of the PV system be ensured.

In short the standard sets out measures to ensure:
t The PV panels and electrical supply connections have been wired up correctly
t That the electrical insulation is good
t The protective earth connection is as it should be
t There has been no damage to cables during installation

Under electrical tests the standard sets out specific requirements for:
t Earth continuity of array frame to earth and connection to main earthing terminal
t Polarity of all DC cables
t PV string open circuit voltage test
t PV string short circuit current test
t PV array insulation test  
t Operational test – PV string current
t Functional test
t Irradiance
IEC62446 also requires inverter details to be recorded and MCS requires that installation records are kept.

Testing times
Between them‚ the various installation requirements for PV systems are designed to ensure the electrical safety of the installation and installation personnel - and the verification of performance/power output of the system.

However‚ in what is still a relatively new area for many contractors‚ there remains a lack of understanding of some issues.

For example, many inverters have transformer isolation between the AC and DC side, preventing DC fault currents from being fed into the electrical installation. Transformerless inverters are increasing in popularity due their increased efficiency and reduced cost and physical size.

IEE Guidance Note 7 advises where an electrical installation includes a PV power supply without at least simple separation between the Ac and DC sides, an RCD installed to provide fault protection shall be type B.

However, the guidance also states where the inverter is, by construction, not able to feed DC fault currents into the electrical installation, an RCD of type B is not required. Manufacturers of transformerless inverters commonly provide declarations to this effect - avoiding the need for a type B RCD.

One area of PV installations where there is there is also much debate is that of protective earthing and equipotential zones.  Where the PV array is not Class II, exposed metal parts must be connected to protective earth. When the electrical installation is a Protective Multiple Earthing (PME) system, the recommendation is that the PME is not taken outside the equipotential zone.

In such cases, the recommendation given in the DTI Guide to the installation of PV systems is connection to earth is via an earth spike. However, there is much debate as to whether a PV is inside or outside the equipotential zone. The array itself is mounted on the exterior of the building - however, conductive parts such as fixings or brackets may be accessible from inside the building as they pass through the roof. Also‚ in terms of test instrumentation‚ different PV electrical tests require the use of different testers – typically including an earth continuity and insulation resistance tester‚ a multimeter and DC clampmeter. Using such an array of instruments can be cumbersome and time consuming – considerations which have led to the introduction of a new generation of integrated testers capable of performing all of the tests required by IEC 62446.

Ongoing verification of performance
The installation of PV system by householders is clearly only undertaken after careful consideration of the costs involved and potential return on investment provided by lower energy bills and FIT payments. The verification of system performance and energy output from the panels is therefore particularly important and a major reason why periodic verification and testing of the system can also be very important – as well as being essential to comply with warranty and PV system guarantees. In many cases simple electrical faults or wiring failures can cause a serious inefficiency in the ability of the panel to produce power. This is particularly important for installers working on ‘roof rental’ schemes were installation has been provided free of charge in return for receipt of the FIT payments. In such circumstances proper metering will always give an indication of system performance but effective electrical testing is vital not only to prove the safe installation of a new system but also to verify ongoing functional performance over extended periods.



The use of connectors in wind turbines faces a unique set of challenges explains Kevin Canham of Harting

Working with wind turbines, ambient conditions such as vibration and air humidity are harsher than in some industrial environments. This applies in particular to wind farms sited in offshore waters – an increasingly important location.

As well as needing to be resistant to these environmental influences, it is important prefabricated components can be assembled quickly and without mistakes on-site. One of the requirements is the time taken to assemble these turbines and take them into operation is kept as short as possible.

Application sectors
Fig.1 shows the key areas where high-quality interconnection is required in a wind turbine:
Pitch control: Almost all modern wind turbines use so-called ‘pitch control’ to regulate speed and power output. Here, the angle between the rotor blades and the wind is changed by rotating them around their longitudinal axis. In this application, components in Harting’s flexible Han-Modular‚ connector series can be freely combined, so that users can configure their own connector. An extensive range of modules is available for electric, optical and gaseous signals.

An urgent question facing many manufacturing companies is, ‘How do we provide clean, safe, environmentally-sustainable energy products for Britain, Europe and the world as a whole, during the twenty-first century? - Steve Gallon, UK MD of enclosure manufacturer Fibox, explains its approach

With scientists predicting the world's population will continue to grow for several decades at least. It’s clear the demand for energy is likely to increase even faster, and the proportion supplied by electricity will also grow faster still. - However, this is where opinions depart as to whether the demand for electricity will continue to be served predominantly by extensive grid systems, or whether there will be a strong trend to locally distributed generation.

Either way, it will not prevent the need for more power, especially in urbanised and industrialised areas, and much of that demand will be for a continuous, reliable supply of electricity.

In service high-voltage (HV) substation equipment is exposed to many stresses, from the electrical, mechanical and thermal to the environmental. These stresses can act to accelerate the deterioration of the insulation and the electrical integrity of the HV equipment eventually leading to failure. Partial discharge (PD) is both a symptom and a cause of insulation deterioration, so the detection and measurement of PD phenomena can provide early warning signs of insulation failure.

Critical to this detection is the availability of accurate and cost effective surveillance tools, which, if non-invasive, can provide early recognition and location of possible sites of electrical degradation while components are still in service. Gathering and trending PD activity over time is essential to monitor the rate and severity of degradation. Maintenance can then be planned in an effort to avoid unplanned outages, interruptions and inevitable loss of revenue.

The use of radio frequency interference (RFI) measurement is an efficient, non-invasive surveillance technique to detect and locate partial discharges in individual HV apparatus. This article will look at the benefits of combining the assessment of RFI emissions with the targeted deployment of complementary, non-invasive electromagnetic interference (EMI) detection techniques. Specifically, frequency sweep data and time-resolved traces can be compared with follow up assessments using complementary EMI couplers such as high frequency CTs (HFCT) and transient earth voltage (TEV) couplers. This combination of tests provides an increased level of confidence in the location, identification and assessment of the severity of degradation and is beneficial when dealing with complex HV apparatus.

The detection and measurement of RFI emissions from PD phenomena involves the measurement of complex waveforms varying considerably and often erratically in amplitude and time. RFI signals from such phenomena are considered to be broadband and impulsive in nature with low repetition rates.

Measurements carried out on PD activity within oil-insulated HV equipment demonstrate that the discharges produce current pulses with rise times less than a nanosecond and therefore capable of exciting broadband signals in the VHF (30 to 300MHz) and UHF (300MHz to 3GHz) bands. Other investigations in open-air insulation substations show that signals from PD and flashover occupy a frequency range up to 300MHz.

When PD occurs inside a metal enclosure, such as in a transformer tank, the signal propagates within the structure, suffering frequency attenuation, reflection, etc. Detection of RFI emission relies on the placement of apertures in the tank walls and penetrating conductors to allow the RFI emissions to propagate and radiate externally.

In the following examples, the instrument used (Doble PDS100) has two different detection modes: spectrum analyser and time-resolved mode. Within spectrum analyser there are three separate detection techniques: peak detection, average detection and separated peak and average detection.

Case Study 1
Dissolved Gas Analysis (DGA) carried out on a South African, 275/88/11KV, 250MVA transformer showed signs of a discharge type fault. RFI measurements (using the Doble PDS100) and conducted EMI measurements (using a HFCT) were performed to establish correlation between the measurements. RFI measurements were taken around the periphery of the transformer. The frequency traces (FIGURE 2) exhibit a discrete appearance as pulses are accumulated. Short bursts of pulse accumulation were interspersed with long intervals of no or low energy activity. Triangulation based on signal intensity of the higher frequencies locates the source of propagation in the vicinity of the HV B-phase. Observing the RFI at 900MHz for a period of time in spot frequency mode sees the measured peak amplitude reaching -45dBm at that location. This mode also confirms the burst nature of the pulse sequence.

The conducted EMI was measured using a 300MHz split-core HFCT at the HV neutral connection to earth. The measured conducted EMI is subjected to significant attenuation through the HV neutral connection and requires an extended observation time. In time-resolved mode both the RFI and conducted EMI measurement confirm the measured pulse behaviour. However, the pulsed activity is more easily captured and more of the lower energy pulses are detected.

Partial discharge activity is indicated by both the RFI and EMI techniques. In each, the dynamic behaviour of the activity is characterised by very short burst activity interspersed by intervals of no or low energy activity. The sequence exhibits the characteristics of a floating type discharge. A secondary source of discharge is evident in the time-resolved traces. The results confirm the conclusions drawn from the DGA analysis. This study proves the use of RFI as an assessment tool while the use of an HFCT coupler provides increased sensitivity to internal PD activity, offering an increased level of confidence in the identification and assessment of PD activity.

Case Study 2
At a distribution substation, RFI measurements were undertaken to survey the condition of each of the oil-filled circuit breakers making up a typical 11kV distribution switchboard configuration commonly found in the UK. A high percentage of 11/33kV switchboards have an installed age of over 25 years. They are subjected to various types of duty plus a varied level of maintenance. The trend is to extend the maintenance period for medium-voltage (MV) switchgear, which in turn creates the need for interim non-intrusive condition monitoring techniques to offer confidence in the equipment’s safety and reliability.

A baseline RFI scan was captured in an adjacent room away from the surveyed switchboard. Measurements at the rear of each circuit breaker were captured and compared with the baseline. The observed uplift of frequencies indicated a nearby discharge source, which was eventually triangulated to one particular circuit breaker by comparing the uplift in higher frequencies while moving the receiving antenna along the rear of the switchboard. Further RFI measurements were captured at the front of the switchboard. A comparison of the front and rear RFI measurements shows that the uplift in the lower frequencies was strongest to the front of the unit. These tests were followed by complementary EMI measurements to gather more information. 

RFI Peak Measurements: Front and Rear of Circuit Breaker
Legend: Front, Rear

The HFCT uses inductive coupling to detect PD pulses flowing to earth and is capable of picking up both local PD in the cable end box and also the lower frequency PD pulses coming from down the cable. The results of this method confirmed the observations from the RFI survey, with uplifts of up to approximately 50dB at 75MHz and 40dB at 200MHz. Time-resolved measurements also showed pulse behaviour is similar to those obtained from RFI measurements (FIGURE 6).

Lower Frequency ( circa 50MHz)
Legend: RFI, HFCT, TEV

Mid Frequency (circa 150MHz)
Legend: RFI, HFCT, TEV

Higher Frequency (circa 200MHz)
Legend: RFI, HFCT, TEV

The placement of HFCTs provides a means to trace the likely source of the signals by comparing the uplift in frequencies. The uplift reduces significantly as the location of the HFCT is moved away from the suspect circuit breaker. Repeated measurements on earth straps placed on adjacent circuit breakers indicate the circuit breaker identified is the source of the measured discharge activity.

The most advantageous setup for metal-clad switchgear is to use an HFCT sensor in conjunction with a TEV sensor. Transient Earth Voltage (TEV) measurements work on the principle that if a PD occurs within metal clad switchgear, electromagnetic waves escape through openings in the metal casing. The electromagnetic wave propagates along the outside of the casing generating a transient earth voltage on the metal surface. TEV sensors are “capacitive couplers”, which when placed on the surface of metal cladding can detect TEV pulses as a result of PD internal to the switchgear.

Observed peak TEV measurements on the main circuit breaker tank reach 0dBm at a frequency of 100MHz. Comparative measurements taken with the TEV sensor located on the cable end box show a reduction in uplift of approximately 20dB. The main circuit breaker tank is identified as the likely source of the discharge. Time-resolved measurements show pulse behaviour confirming the results obtained from both RFI and HFCT measurements.
The utility opened up the circuit breaker and found signs of carbon at the cable end in the main tank of the switchgear. Results of this study confirm that deploying frequency spectra measurements and time-resolved patterns from RFI, HFCT and TEV probes can be used to pinpoint PD issues within switchgear. Using TEV sensors in conjunction with RFI surveillance on metal clad switch gear offers an additional capability in confirming and localising the partial discharge source.

RFI monitoring offers, and has proven to be, a routine non-invasive and cost-effective surveillance technique that complements and provides added value to other well established HV asset monitoring techniques such as thermal imaging and DGA analysis. As the practical examples illustrate, measurements logged with an RFI instrument platform specifically designed for substation surveillance can assist in effective discrimination and recognition of the RFI emissions radiated from potential sites of insulation deterioration.

There are great benefits of combining the assessment of RFI emissions with targeted deployment of other complementary non-invasive electromagnetic interference (EMI) detection techniques using the same RFI instrument platform. The deployment of both ‘far field’ and ‘near field’ probes provide a diversity of sensors, which is of particular importance with complex HV apparatus such as transformers where the propagation paths for RFI are less well defined.

This article is based on the paper Substation Surveillance Using RFI and Complementary EMI Detection Techniques, which was recently presented at the 78th International Conference of Doble Clients in Boston, Massachusetts USA. The paper was written by Alan Nesbitt, Brian Stewart and Scott McMeekin of Glasgow Caledonian University and Kjetil Liebech-Lien and Hans Ove Kristiansen of Doble Engineering Company.

Part 2 of this article will appear in the June 2011 issue of Electrical Review.


No denying it. Fukushima has changed the ground rules for the wonderful world of electricity. Forever.

Arcing faults can be quickly detected and cleared using the Falcon Arc Detection System from CEE Relays. Clearing arcing faults more quickly reduces the incident energy of the fault. The incident energy at each busbar and required personal protective equipment (PPE) can be calculated using the Arc Flash Evaluation module of the Power*Tools for Windows (PTW) power system analysis software, helping engineers modify protection settings and the network configuration to reduce the incident energy. Reducing the incident energy reduces the risk to personnel and the expensive downtime due to the damage caused by arcing faults.