• US firm buys Bradford switchgear manufacturer

    US firm buys Bradford switchgear manufacturer

    Texas-based Powell Industries has bought Bradford-based Switchgear and Instrumentation in a deal with former parent company, Yorkshire’s NG Bailey Organisation.

    Powell will gain improved market share and opportunities from this, especially in Europe and the Middle East. The new parent company has pledged continued support and investment for the Bradford site.

    For over 40 years, S&I has provided products and electrical and advanced system design for offshore and other industries, including pharmaceutical, mining, utilities and building services. Annual turnover tops £30m and the company employs over 300 at its Bradford facility, which includes NG Bailey Manufacturing.

    Powell Industries is a Nasdaq-quoted company with annual sales of $225m. It specialises in electrical equipment for heavy-specification users in process industries.

    Steve Ward, who joined S&I as operations director a year ago, will take over as managing director. Ward said of the purchase: “This is a very good strategic fit, with both companies operating in similar markets and with complementary product ranges and services. Combining our efforts will strengthen our future market drive, particularly as our new parent company has an impressive track record in both research and development and capital investment.”

  • Switchgear & substations – GIS solution leads to shrinking substations

    Switchgear & substations – GIS solution leads to shrinking substations

    Think of a primary substation and you’ll probably envisage a vast outdoor compound with massive transformers connected to overhead powerlines and bank after bank of circuit breakers and disconnectors. This is not always the case says Stephen Trotter, ABB’s director of power systems projects for the UK

    Traditional substations have provided excellent service over many years, and many are still being constructed today. However, when it comes to planning substations in urban areas there is an ever increasing demand from utility customers to minimise the space required, not just because of the cost and availability of land, but also to reduce their visual impact on the local environment. New high voltage technology offers the ideal solution in the form of gas insulated switchgear (GIS) which enables substations to be ‘shrunk’ into about 20 per cent of the space required by a traditional design, and housed indoors or even buried underground.

    GIS advantages
    Until the 1970s, air insulated switchgear (AIS) was the type most commonly in use for substations. AIS requires large distances between earth and phase conductors and therefore a good deal of space. This means that for higher voltages – typically above 36kV - this type of installation is only feasible outdoors.
    The situation changed when SF6 (sulphur hexafluoride) became available as an insulating medium in switchgear enclosures in order to reduce phase to earth distances. The advantages of GIS compared to AIS are as follows:
    • Less space requirements, especially in congested city areas, saving on land costs and civil works
    • Low visibility buildings can be designed to blend in with local surroundings
    • Less sensitivity to pollution, as well as salt, sand or even large amounts of snow
    • Increased availability and reduced maintenance costs
    • Higher personnel safety due to enclosed high voltage equipment and insignificant electromagnetic (EM) fields.
    A direct comparison of the component investment for identical switchgear configurations will suggest that the GIS variant is more costly than the AIS solution. However, this does not necessarily show the true story. The capability to install a GIS substation within a significantly smaller site – typically up to 80 per cent smaller - enables it to be located close to the load centres, providing a far more efficient network structure at both the HV (high voltage) and MV (medium voltage) levels. As a result, both the investment and operating costs are reduced.
    Sites large enough for new AIS substations are seldom available, and when they are their cost is usually extremely high. But it is not just the smaller size of the site that can make GIS the lower-cost option: GIS is also the more economic alternative when expanding or replacing existing substations. An inner city site that has been used previously for an AIS installation could be sold or rented out and the income used to finance the new substation. The compact nature of GIS enables an HV transformer substation to be fully integrated in an existing building, which may only have to be increased in height or have a basement added.

    Port Ham shrinks from view
    Central Networks’ £12 million replacement Port Ham switching station, which has recently been constructed by an ABB and Balfour Beatty consortium on the banks of the River Severn, near Gloucester, provides an ideal example of the advantages of the GIS approach.
    Port Ham is a grid supply point. It takes electricity at 132kV from the National Grid substation, a few miles away at Walham, and feeds it into the Central Networks distribution network. Through a network of primary and secondary substations, this network feeds over 240,000 customers in Gloucestershire, Herefordshire and much of south and east Worcestershire.
    The original outdoor station, built in the early 1950s, had experienced above average load growth, to a peak load of 672MVA. The AIS equipment had reached the end of its useful life, so in 2002 Central Networks decided to completely rebuild the facility to ensure continued reliability of supply, as well as providing scope for further load growth.
    Initially, the project was tendered in the expectation that the AIS would be replaced on a like-for-like basis. However, in consultation with the ABB and Balfour Beatty consortium, Central Networks decided building a new indoor GIS switching station would offer a number of important advantages, at around the same overall cost. A key benefit was that ABB’s state of the art compact ELK-04 (GIS) switchgear solution could be condensed into just one-fifth of the space used by the existing station. Port Ham is in an important nature conservation area. So the smaller switchgear allowed Central Networks to meet planning concerns by housing the station in a low-profile building designed to blend in with the local environment.
    In addition to saving space, GIS also offered two further advantages. Firstly, circuit downtime could be reduced, as the new GIS circuits were constructed with the existing units still in service. Downtime was limited to the rerouting of the network connections. This was a crucial factor, because of the critical position of Port Ham in the supply network. Secondly, the GIS was constructed outside the existing live compound, considerably reducing health and safety risks to personnel working on site.
    One of the major project challenges was the soft ground – on the flood plain of the River Severn – which required major foundation work before construction could begin. In just over 10 days some 120 cast concrete piles were driven down 15 metres to the bedrock. The building itself has been raised on stilts to ensure that the switchgear is at least one metre above the predicted level of the once in 100 years flood level.
    The new indoor switching station comprises 20 bays of GIS switchgear: 12 feeder circuits; four National Grid incomers; two bus couplers; and two bus sections. The size of the investment and the strategic importance of Port Ham made it a flagship project for Central Networks.

    NEDL’s Norton substation
    A similar approach was adopted when NEDL needed to replace its 132kV substation at Norton, near Stockton on Tees, that interconnects the National Grid and NEDL’s distribution network.
    The new indoor GIS substation, completed in 2005, occupies just one sixth of the space of the old AIS substation. It is rated at 540MVA, and features 20 bays of switchgear (four of which have been transferred to National Grid) with four incoming circuits fed by Supergrid transformers and 14 outgoing circuits, two of which feed local grid transformers.

    Going underground
    The GIS switchgear concept has been taken to its logical conclusion in ABB’s Barbana 132kV/20kV transformer substation in the centre of Orense, Spain. The 132kV switchyard, comprising two cable feeder bays and one transformer bay, has been constructed entirely underground and concealed beneath a park. This design requires forced cooling, which inevitably entails unwanted fan noise. But damping features or low-noise fans can be expensive. Instead a waterfall has been created. This acts as a heat exchanger to dissipate the heat created by the transformer while the sound of the falling water also drowns out the noise from the fans.

  • Switchgear and substations – Meeting the system demands of the future

    The Government projects the UK will go significantly beyond its commitment under the Kyoto Protocol and reduce its greenhouse gas emissions by almost 20 per cent below 1990 levels by 2010. With such emphasis being placed on renewable energy sources the energy industry needs to look ahead in order to identify what the effects of the system changes will be, as a consequence of the changing power sources. Masoud Bazargan at Areva T&D explains the importance of suppliers within the industry working with their clients’ systems departments.

    In order to work more effectively, suppliers and users need to make sure transmission equipment is designed to incorporate current and future system requirements taking into account the changes in generating methodology needed to support the rigorous climate change programme the UK is undertaking.
    Transmission and distribution plants have always been subject to continuous research and development in order to maximise reliability, safety, and wherever possible reduce capital and operating costs for the network operator. There are a large number of areas where development has provided benefits. Examples for transmission switchgear, have been the move from hydraulic to spring operated mechanisms; reduced energy mechanisms; more sophisticated interruptive technology; design improvements, modelling technology, arc physics; compact solutions; hybrid GIS solutions; end of life disposal; environmental considerations; reduced power to weight ratio; less site assembly times and lower volumes (i.e. space-saving).
    However, one key area where development effort is being focused has been driven by more pressing external forces. Indeed, concerns about damage to the ozone layer and associated climatic effects caused by carbon emissions has accelerated the decline in the popularity of traditional fossil fuels and in turn driven the ascent of renewable energy sources. Generally this shift which has been welcomed, despite some opposition concerning local issues, is set to have wide ranging impact on transmission and distribution networks. Fundamental differences associated with renewable energy include fluctuating outputs and often remote geographical location of suitable power sources. Existing networks were designed for ‘traditional’ fossil fuel based generation in centralised locations and the change in generation mode and location to embedded generation from renewable sources in remote locations will inevitably impact on the specification for switchgear and other equipment.
    In order to provide products that will fulfil the needs of network operators today and in the future, it is important to ensure that equipment is designed in line with the DNO’s development strategy. In order to achieve this, Areva T&D has developed close working links with system designers, using partnerships wherever possible in order to ensure that product design and development is aligned to the needs of the market, especially as what was an extremely stable market is about to go through one of the biggest changes since its inception. For these partnerships to succeed, they need to be a two way process with transfer of information of value, to and from both parties. The fact that continuity of specification ensures that substation components from different suppliers are in some cases very similar, makes this type of value add extremely important.
    One of the most effective and favoured forms of renewable energy is wind-power. However due to public objections and land availability constraints, we are looking more and more to utilise the renewable energy available in the marine environment through construction of offshore wind farms. By its very nature, the offshore wind farm creates huge challenges for the transmission and distribution sector. The challenge facing the industry is not only to capture and convert the natural energies of the wind and the ocean but also how to transmit this power to the shore considering the difficult environment. These considerations can range from ecological impacts on the environment, e.g. effects on marine life and by the environment, such as marine growth on the installation, through to shipping lanes, oil and gas pipelines, geological and seabed consideration, access, weather condition, foundation, corrosion and cost.
    One proven way of addressing the transmission issue is to connect the wind farm turbines via an inter array network of cables which link at offshore transformer substations located within the wind farm. Electricity from all the individual wind turbines is collected and the voltage stepped up to 132kV to make it more easily transported to shore via high voltage cables reducing the power losses.
    The concept of an offshore substation, close to the turbines, does help resolve transmission issues, however, it also introduces problems of a different kind as the module will need to resist highly aggressive marine conditions, alien to its land-based cousins. Seawater induced corrosion can be minimised by locating the module out of the splash zone, around 10m above the high water mark, but a specialised external paint finish should be utilised to protect the structure and reduce the need for maintenance. The location of equipment types within the substation and its surface profile can also influence corrosion rates and must be carefully planned. Mechanical elements such as diesel generators must also be protected from water and salt ingress and suitable arrangements made for the substation to be self sustaining for say seven days in case of power loss. The transformer itself should also be reviewed in terms of layout, corrosion resistance and long term maintenance with particular reference to radiators, tank, fan and pump. Ventilation also needs to be considered, employing special filters to prevent salt ingress that could cause contamination and corrosion. In addition, handles and all other external fittings need to be re-specified for a marine environment to prevent corrosion.
    Another consideration for offshore substations is the mounting arrangements and weight distribution. While a traditional land based substation will usually be mounted on a reinforced concrete plinth, an offshore module may be mounted on a large diameter steel monopile. The very nature of the support structure dictates that loadings must be minimised by managing the centre of gravity to the module and ensuring even weight distribution. Consideration must also be given to both dynamic and static loading in temporary as well as service conditions. Finally but no less importantly, the installation, commissioning, and any subsequent maintenance will have to be carried out in an alien, hostile environment far from overland access.
    These changes are fundamental enough to require a paradigm shift in mind-set and an evolution of the current skill set. But we believe the whole industry will rise to the challenge and ensure that energy can be generated from renewable sources and distributed to where it is needed, consistently, cleanly, efficiently and safely ensuring that we all play our part in providing the electricity we need while combating global warming.

  • Switchgear & substations - Model railway project

    Bernard Johnson, programme controller for the ABB Mowlem Southern Region Power Supply Upgrade (SRPU) team, explains how detailed planning, coordination, collabora-tive working and an uncompromising approach to health and safety helped make the project so successful that in the end nobody noticed it!

    In 2003, Network Rail embarked on its three-year Southern Region Power Upgrade (SRPU) programme to support the introduction of 2000 new, more comfortable carriages. Thanks to features such as central door locking, CCTV and air conditioning, the Bombardier Class 375/376 Electrostar and Siemens Class 450 Desiros trains draw around 23 per cent more power than the old rolling stock from the 750V traction power supply system – the reason for the upgrade.
    With 3,196 miles of track, Southern Region is the UK’s largest private operator of an electrical distribution system. And the upgrade is believed to be the largest DC project of its type undertaken anywhere in the world.
    Kent region
    ABB in consortium with Mowlem Railways was one of four regional contractors appointed initially by Network Rail, and the consortium was awarded the Kent region – extending from Ramsgate on the coast through to Cannon Street substation in central London. Between 2003 and 2006 the consortium carried out around £80 million of project work including the construction or upgrading of 27 substations and 17 feeders and installing around 100 panels of ABB ZX1.2 gas insulated MV switchgear and 25km of 33kV cable.
    Working on one of the world’s busiest rail networks presented a whole raft of challenges and constraints as all site deliveries, possessions and outages had to be planned down to the finest detail. This was especially important because, while the SRPU project was vital for Network Rail’s future plans, its over-riding need was of course to keep the trains running on a day to day basis, so potential disruption and delays had to be kept to an absolute minimum.
    It was clear that communication and coordination at all stages, from definition, through design, tender for the individual work packages to execution, would be the key to the success of this project. So it was decided to take the unusual step of co-locating the consortium team alongside the client team in Network Rail’s project office in central London. This ensured that right from there start there was no ‘us and them’, but rather a partnership that enabled problems to be solved before they became issues.
    Management of ‘possessions’ – the windows of opportunity when access was available to work on individual sites – was a core element handled by specific team members. This was particularly challenging as six months is a normal period of notice for a possession, while on some of the busiest routes access was only available at Christmas, so they had to be planned 12 months ahead. Added to this, Network Rail’s operational requirements sometimes meant that planned possessions had to be cancelled at the last moment, calling for the team to think on its feet to reorganize work programmes to maintain the overall project momentum.
    Much of the site work was carried out at night and weekends. The team also became particularly adept at ‘piggybacking’ on access to sites that had already been granted to Network Rail’s own team for routine track maintenance. Of course, with two different teams on site working with different objectives, careful planning was needed to ensure there was no clash of priorities.
    Hand in hand with the planning of possessions, the delivery of equipment to the sites was planned with military precision. A great deal of effort went into making this a ‘non-rail’ project where possible, using road access rather than rail to deliver equipment, although there were a number of ‘rail-locked’ sites with no road access. On some sites, the limited access called for specialized rail-mounted cranes to manoeuvre heavy equipment into position. Again this required long-term planning as there are only three such cranes in the UK.
    In order to keep on-site work and costs down, the project made substantial use of containerized substations, which were fitted out off site. They are housed in robust, long-lasting, stainless steel enclosures that should last for 40 years.
    Health and safety
    An uncompromising approach to creating a safe working environment was paramount throughout the project, with the emphasis on minimizing potential risk to site operatives. This was reflected in a remarkable safety record. All work on the infrastructure was undertaken with the Rimini plan system, which is used to make sure the safest system of work is used when ‘on the line’. In addition a safety coach was kitted out, known affectionately as ‘Thunderbird 3’. This was despatched to the various sites to show videos and provide information and handouts about the specific safety issues that the working gangs might encounter on that site.
    Innovative team approach
    Mid-way through the project a substantial work package was started for the north Kent ring of substations. Because of the way the substations in the ring are linked together it was not possible to take two out of service at the same time without disrupting the network. So an innovative approach was adopted by constituting a separate, dedicated planning team with representatives from all interested parties. The team was led by Network Rail, and as well as the consortium it also included the Scada team, the network controller, the outage planner and representatives from the team working on the inner London region of the SRPU, since our work could also impinge on their area. By meeting on a weekly basis the 12-strong planning team ensured that the north Kent ring work package proceeded without a hitch.
    ZX1.2 switchgear
    For the SRPU project ABB used its ZX1.2 range of metal-clad gas-insulated medium voltage switchgear which has technical acceptance from ENA (the Energy Networks Association) and Network Rail for use at 33kV for ratings up to 31.5kA and 2000A.
    ABB designed the ZX1.2 with a modular, plug in approach to meet the specific needs of electricity distribution network owners and operators by providing compact, flexible substation configurations that offer reliable and cost efficient switchgear solutions for single busbar applications. Key design features include laser welded stainless steel enclosures, compact modular construction and the introduction of plug-in technology which facilitates simple, controlled connections of busbar, cable, test bushings and voltage transformer, without the need for ‘on site’ gas handling equipment.
    All maintenance-free live components, such as switching devices and busbars, are contained under SF6 in gas-tight enclosures, which eliminate the effects of ageing processes and environmental influences to ensure maximum operator availability and a long service life. The ZX1.2 design also offers easy cable access at the rear with generous provision for conventional control and protection devices, dedicated cable test sockets and full mechanical interlocking between the disconnector/earthing selector and the circuit breaker
    Underneath the arches
    The innovative side of the consortium really came to the fore in constructing a new substation in Vauxhall. Space is at a premium in this part of London and it was difficult to see where it could be placed. The consortium hit on the idea of utilising two dilapidated arches of a railway bridge to create a smart new indoor substation. As well as special cladding to make the substation watertight, ventilation and fire detection systems were installed to ensure the complete safety of the enclosed transformer.
    The success of the SRPU project was not just down to procedures. A key aspect was the excellent people working as a team across the board - civils, engineering, project management and installation and commissioning staff, supported along the way by administration and specialist safety and possession staff.
    At the peak in January 2005, there were around 140 ABB Mowlem project staff, along with many other installation, civils, cable pulling contractors and site staff.
    The final verdict
    By November 2005 all the new trains were in service, with not one train introduction delayed due to a lack of power, and Network Rail’s view on the overall Southern Region Power Upgrade project was – “the project so successful that in the end nobody noticed it!”

  • Switchgear & substations - MV switchgear can be Green

    The transmission and distribution business has seen a significant shift in technology over the last quarter century with the decline in oil and air insulated switchgear in favour of the newer vacuum and sulphur hexafluoride (SF6) technologies says Philip Dingle, utility segment manager at Eaton.

    SF6 is unchallenged for transmission voltages but for distribution systems from 3kV to 38kV vacuum circuit-breakers have become the dominant technology (See Fig. 1)
    However, vacuum interrupters are frequently used in gas insulated switchgear (GIS), which uses the greenhouse gas SF6 as an insulant. Despite worldwide concern over the environmental effects of SF6, manufacturers continue to promote the GIS concept for ring main units and packaged substations in the face of technically sound solid-insulated alternatives.
    In terms of size and cost there is little to choose between the two circuit interruption technologies at distribution voltages. At one time solid insulation tended to be more bulky than gas but advances in technology have overcome this objection. Both vacuum and SF6 offer good load switching and short-circuit protection capabilities but vacuum interruption excels under the more onerous short-circuit duties and offers long life under frequent switching duty.
    Vacuum interruption
    The first vacuum interruptors were introduced 40 years ago and, since then, have proved remarkably reliable. Modern units retain their vacuum for at least 20 years, thereby exceeding the mechanical life of the circuit-breakers of which they form a part. Operation is maintenance-free, eliminating the need for regular inspection and costly leak monitoring equipment.
    Performance is excellent over a wide range of applications including transformer secondary protection, short-line fault switching, capacitor and motor switching. The rated a.c. power frequency withstand voltage is typically two to four times normal operating voltage and lightning impulse withstand voltage voltage is four to 12 times operating voltage.
    Vacuum interruptors are environmentally benign. They do not contain greenhouse gases, or present a health risk due to decomposition products caused by arcing. No special measures are needed to protect the environment from the results of leakage or at the end of life. The constituent materials can be recovered safely and recycled.
    Solid insulation
    Historically, one of the reasons for using SF6 gas insulation with vacuum insulators was size – solid insulation resulted in much larger units. This is no longer the case. The use of modern potting compounds such as polyurethane and epoxy to encase the vacuum interruptor, together with a contoured profile similar to the sheds used on overhead line insulators, has made it possible to increase the basic insulation level (BIL) of the vacuum interruptor to the same order as GIS.
    Solid insulation means there are no greenhouse gases involved and there is no need for special gas monitoring systems and other precautions to protect personnel from the risk of leakage. The switchgear can be installed inside buildings with confidence there is no danger of a build-up of heavier-than-air gas.
    Anybody who has been involved with the disposal problems created by the past use of asbestos, polychlorinated biphenyls (PCBs) or chlorofluorocarbons (CFCs) should take warning. The current use of SF6 gas in switchgear could be creating a similar legacy for industry and utilities in twenty or thirty years’ time. The very fact literature on SF6 technology devotes so much space to defending its environmental reputation should be enough to sound warning bells.
    SF6 and global warming
    Sulphur hexafluoride does not occur in nature. At normal temperatures it is a stable, inert gas – harmless to people and animals. However, it is heavier than air so precautions are necessary to avoid the possibility of high concentrations in confined spaces.
    The principal concern is that SF6 is a potent greenhouse gas (See Table 1). The United Nations Framework Convention on Climate Change in Kyoto in December 1997 identified a basket of six major greenhouse gases:
    • Carbon dioxide (CO2)
    • Nitrous oxide (N2O)
    • Methane (CH4)
    • Chlorinated fluorocarbons (CFCs)
    • Hydrated fluorcarbons (HFCs)
    • Sulphur Hexafluoride (SF6)
    The signatories agreed to restrict emissions of these gases to specified amounts and, furthermore, to reduce overall emissions by at least 5.2% below 1990 levels in the commitment period 2008 to 2012.
    The European Climate Change Programme has set out proposals to enable the European Community to meet its Kyoto Protocol targets for fluorinated greenhouse gases, including SF6. The quantities of these gases are measured in equivalent tonnes of carbon dioxide. At 1995 it estimated the total emissions of SF6 gas as 65.2 tonnes, of which electrical switchgear contributed five tonnes.
    While the concentration of SF6 may be low compared with some other greenhouse gases, SF6 has a global warming potential (GWP) 23,000 times that of CO2 and an atmospheric lifetime estimated at up to 3200 years compared with 50-200 years for CO2. The continuous build-up of SF6 in the environment therefore represents a serious long-term threat.
    Furthermore, recent research has revealed a new, highly active greenhouse gas, SF5CF3 that is thought to be a product of the breakdown of SF6. Although it occurs in relatively small concentrations, its contribution per molecule to the greenhouse effect is much greater than any previously known greenhouse gas.
    A report by the Department for Environment, Food and Rural Affairs (Defra) gives 1995 emissions of greenhouse gases in the UK, expressed in equivalent tonnes of CO2 as shown in Table 2. It estimated that total use of SF6 over the previous decade had remained roughly constant at 160 tonnes, equivalent to 1,200,000 tonnes of CO2 per year. Four main uses for SF6 were identified:-
    • Electrical installations
    • Electronics
    • Magnesium smelting
    • Training shoes
    In switchgear, leakage may occur at the mechanical and electrical seals and even within the pressure monitoring equipment itself. Consequently, regular monitoring is necessary and procedures should be in place to ensure that monitoring takes place regularly but also that appropriate steps are taken if it reveals evidence of leakage.
    Serious concerns also centre on the disposal of the SF6 at the end of its useful life. SF6 is manufactured in industrialised countries under carefully-monitored conditions. It is used in enclosed conditions with every effort taken to minimise the risk of leakage. But SF6 switchgear is being sold and installed worldwide. What guarantees are there for responsible disposal in 20-30 years’ time?
    The United Kingdom is committed to reducing emissions by 12.5% from 1990 levels by 2008-2012. Other countries have already taken steps to deal with problems created by the use of SF6 in switchgear including Denmark where its use as an insulating medium in new circuit-breakers was prohibited from January 1 2002.
    In Germany the following steps have been taken:
    • Manufacturers guarantee a minimum leakage rate of approximately 0.5% a year
    • All gas-filled enclosures are continuously monitored to detect leaks
    • Used SF6 is either purified and reused in a closed system or re-use directly
    • SF6 manufacturers guarantee to take back used gas for re-use or disposal by environmentally compatible means.
    • All personnel handling SF6 receive regular information and training
    • Only properly qualified staff carry out maintenance work
    • SF6 producers keep records of quantities produced and equipment manufacturers and users keep records of gas consumption and inventories.
    SF6 under operating and fault conditions
    While it is stable at room temperature, SF6 breaks down into toxic substances on combustion, at high temperature, or when subjected to arcing. In the event of a major short-circuit that the system cannot handle, SF6 gas and these toxic products of combustion will be released into the atmosphere. Even under normal operating conditions, whenever an arc is suppressed, there will be toxic residues within the enclosure. This calls for special precautions when dismantling at the end of life.
    At temperatures above 300°C SF6 starts to decompose, forming free sulphur and fluor ions which combine with hydrogen and oxygen ions in the air to form a number of dangerous products including hydrogen fluoride (HF) an extremely corrosive fuming liquid, thionyl fluoride (SOF2) a very stable and poisonous gas, and sulphur tetrafluoride (SF4) a poisonous gas that combines with water to form HF and SOF2. Among these latter effects, SF4 reacts with moisture in the eye to form hydrogen fluoride, which has a strong etching effect on the cornea. HF also impairs the lungs. A number of other toxic substances are also produced.
    During arc interruption, these same decomposition products are produced and, in addition, metal fluorides, mostly in the form of dust. Special measures are necessary when handling this dust. Only skilled and well-trained personnel should carry out maintenance and other work. Protective clothing should be worn, including tight-fitting gloves, goggles and masks to prevent skin contact. Special measures are also necessary to ensure that dust does not come into contact with the surrounding environment. The problems of decommissioning at the end of life are comparable with those associated with PCBs in transformers.
    If an internal fault should occur in gas insulated switchgear, the enclosure may burn through or the arcing energy may cause a rise in the temperature and pressure in the enclosure leading to bursting of the enclosure or opening of a pressure relief valve. As a result of any of these events, the surrounding environment will be filled rapidly with the toxic and aggressive products of decomposition. This could present a major risk with GIS substations or ring main units situated on street corners or in commercial or industrial buildings.
    At high voltage there is little choice today but to use SF6 switchgear for circuit interruption and steps can be taken to minimise the risk of decomposition products presenting a danger to the public. Furthermore the number of installations is relatively low so utilities can support the small number of trained personnel needed to handle high voltage SF6 products.
    At medium voltage, the large number of products in service make it impractical to maintain the staffing levels needed to look after equipment. The availability of compact vacuum interrupters which generally offer superior electrical characteristics, together with compact solid insulation techniques, make it practically, economically and environmentally preferable to use solid-insulated vacuum switchgear.

    For further information on the consequences of using SF6 gas see www.greenswitching.com

  • FKI Switchgear celebrates Channel Tunnel link completion

    FKI Switchgear celebrates Channel Tunnel link completion

    The opening of a prestigious rail link between London’s St Pancras International and the Channel Tunnel this month also marked the completion of a major contract for a world leader in the design, manufacture and instillation of electrical switchgear products.

    FKI Switchgear has supplied nearly 200 of its Hawkvac 15 panels to the multi-billion pound project that has been completed in two stages.

    The first phase, a 43 km stretch from the Channel Tunnel to Waterloo Station in London, opened in 2003 and involved the installation of 20 panels to meet a requirement for cost effective withdrawable switchgear solutions.

    The extension of the high-speed rail link to St Pancras via East London has required the installation of a further 176 panels at a cost of more than £2.5 million over four years.

    Explained Steve Dymond, Sales and Marketing Director at FKI Switchgear: “In recent years we have supplied switchgear to a number of high profile rail projects across the globe.

    “The Hawkvac 15 panels installed on the Channel Tunnel link benefit from a metalclad, multi-compartment housing, that allows authorised work in safe areas whilst preventing access to live equipment.

    “The medium voltage, indoor metalclad vacuum switchgear also provides a relatively inexpensive solution for rail projects such as this.

    “When the first train arrives at St Pancras on November 14 we will feel extremely proud to have played such an important role in the completion of such a prestigious project,” he added.

    Once the whole line is fully operational, London to Paris journey times will be cut to around two and quarter hours, with Brussels possible in under two hours.

    FKI Switchgear is part of the FKI Group and has manufacturing facilities in the UK, Australia and the United States.

  • Switchgear & Substations - Intelligent substation protection proves its worth

    Currently, there are well over 4,000 substation automation systems installed worldwide, providing positive proof that power utilities now accept these systems and understand their benefits.However, since until quite recently there was no overall standard for the serial communications in substation automation, the majority of these systems are based on proprietary standards. This meant each system was limited to using components from a single supplier, or complex and costly protocol conversions had to be applied. Andy Osiecki, substation automation manager at ABB reports

    There is a natural desire for the power utilities to want to safeguard their investment in substation automation equipment. This has resulted in a growing demand for flexible, future-proof systems able to cope with changing requirements, philosophies and technologies. In the early years of this decade, the industry responded by developing and releasing a new standard, IEC 61850 Communication Networks and Systems in Substations which is the first and only global standard that considers all the communication needs within substations.
    The main goal of IEC 61850 is interoperability. This is the ability for IEDs (Intelligent Electronic Devices) from one or a number of different manufacturers to exchange information and to use it for their own functions.

    Furthermore, the standard allows a free allocation of these functions and accepts any system philosophy, from a distributed architecture (such as decentralised substation automation) to a centralised configuration (such as Remote Terminal Unit (RTU) based).
    The standard is also future-oriented, taking into consideration developments in communication technology move faster than developments in the functionality of substation automation, protection and control equipment. In addition, the standard provides for ease of system engineering and maintenance.
    New IEC 61850 compliant products
    As well as its role in drawing up the standard, ABB has developed a new common range of products that fully embrace IEC 61850, rather than simply upgrading older platforms. In creating this new 670 Series of protection, control and monitoring IED we adopted an evolutionary path that builds on our many decades of protection experience. The protection and control algorithms, as well as parts of the hardware platform, have been carried over from the 500 Series - with over 40,000 units installed world-wide.

    Currently, the 670 Series covers the following applications:
    - Line distance protection 
    - Line differential protection 
    - Transformer protection 
    - Bay control 
    - Bus and breaker failure protection 
    - Generator protection
    Each IED is delivered ready-to-use, pre-configured and type-tested for different types of application. This makes them easy to use, from selection to operation and maintenance. There are also three or four different option packages available for each product, enabling them to be easily adapted to meet specific customer requirements.

    The existing series of transmission and distribution products can also be used in 61850 data buses with corresponding protocol converters. This ensures seamless upgrades to the new standard as far as connectivity is concerned.

    In addition, we have released a number of other products that comply with IEC 61850, including: REB 500 busbar protection V7.3; PCM 600 tool for  the 670 Series; MicroSCADA Pro substation and network control products.

    Verified IEC 61850 conformance
    ABB has established a System Verification Centre (SVC) in Baden, Germany to verify the correct implementation of IEC 61850 throughout its portfolio. This is the only vendor test centre in the world with official qualification by UCA International, an independent user organisation for IEC 61850.

    Each and every product, system component, application and tool is tested in a real-life system environment to prove its appropriate working and performance - functionally and interactively. Certain products have also been certified by independent agencies such as KEMA.

    Successful trial of  RED670 with National Grid
    As part of our planned implementation of IEC 61850 compliant IEDs in the UK market, in 2007 we carried out a nine-month site trial with National Grid in which the GPS- based RED670 line differential protection IED was installed on 400kV substation circuits in North Wales. The extended trial enabled ABB to demonstrate the RED670's capabilities in a realistic ‘in-service' environment, without exposing the power system to undue risk.
    The RED670 is designed for protection, monitoring and control of overhead lines and cables with up to five line terminals. Its phase segregated line differential protection enables reliable single/two/three pole tripping and auto-reclosing with synchronising and synchro-check. In addition, the RED670 is capable of handling transformer feeders and generator and transformer blocks.

    We had of course carried out extensive laboratory testing with the RED670. But as far as the customer is concerned there is nothing like real-life experience to show how a system behaves when subjected to the electrical noise and RFI found at a working site. This trial enabled us to install devices in a three-ended 400kV substation circuit between Trawsfyndd, Legacy and Deeside. They were connected alongside the existing protection systems where they were subjected to same working environment and fed the same live input data. The only difference from a fully live installation was that the RED670 devices didn't perform any actual tripping. Instead, we monitored their outputs to check that they were analysing the data correctly and making the right decisions.

    As well as mimicking the behaviour of the existing site protection systems, the devices were subjected periodically to additional tests to monitor their stability under abnormal conditions. This involved planned route switching of the communications channels and simulation of the loss of the GPS signal, both individually and simultaneously. There were also times when the devices were subjected to unplanned communications interference, they performed appropriately under these circumstances and then even better when the problem was resolved.

    Lightning strike
    The devices performed very well under what were relatively normal operating conditions. Ideally, we wanted to see how they would behave under exceptional conditions, such as a primary circuit fault. But of course that is a condition you can't create as a test on an operational network where you can't risk interrupting the supply to customers. However, near the end of the test programme there was a lightning strike that created a transient primary fault on the overhead line close to Trawsfyndd. This kind of event makes a lot of different things happen very quickly on a network, especially a large, sudden increase in current.  We were very pleased to report that the RED670 responded well, providing exactly the right switching response.

    The test programme was coordinated by the ABB office in Stone, Staffordshire. We enjoyed a very high level of team work and cooperation from both National Grid's asset policy team and the substations communications network provider, Cable & Wireless. 

    National Grid imposes exacting requirements on any equipment connected to its network to ensure that it can always maintain the highest level of customer availability. Now the RED670 has complete this onerous test programme we are utilising the device as part of ABB's bay solution for substation protection and automation systems based on National Grid's standardised NICAP (National scheme for Integrated Control And Protection) engineering philosophy and specification. It is featuring on our current 275kV substation project at Stalybridge, as well as new NICAP projects at Greystones, Ratcliffe-on-Soar, Willington and Wilton.

  • Switchgear - Older high voltage switchgear: managing the risk

    Authorised persons looking after electrical installations invariably have a high level of competence but many may not be aware of the risks involved in managing older switchgear. Fortunately, says Marcus Charter, Power Consultant at Schneider Electric, once this shortcoming is recognised, it can readily be addressed by having robust management processes and training programmes

    Let's not mince words - working with electrical switchgear always involves risks. Large amounts of energy are continuously available when the switchgear is in use and, under fault conditions, even more energy is likely to be released. In the unfortunate instance an operator is exposed to this energy they are likely to be maimed for life or even killed.
    It is essential, therefore, not only that the equipment should be suitable for duty in hand when it is first installed, but that it should continue to be suitable for this duty as it ages. Make no mistake, should a switchgear assembly fail to contain the energy present, whether under normal or fault conditions, it is likely to fail catastrophically.

    These significant risks associated with switchgear can, however, be controlled to a reduced level if that switchgear is well managed - which involves regular inspection, testing, maintenance, increased user familiarity and documentation - and correctly operated. The responsibility for ensuring that these issues are properly addressed falls to Authorised Persons who will have received appropriate training and be appointed through a lengthy assessment process by there organisation.

    Sufficiently assessed and trained authorised persons will be well aware of the hazards posed by modern switchgear. They are also likely to be comfortable that modern equipment will operate safely, putting their faith in the modern technologies and techniques used to enhance safety, and also being reassured by knowing that the equipment is relatively new and has, therefore, suffered little wear or degradation since leaving the factory.
    But what about older switchgear, especially if it is oil filled? The small but noticeable amount of rust on the chassis, the mildew in the termination box gasket - do these reflect the condition of the contacts, the operating mechanism, the fault containment and the arc dissipating components inside?

    Is the operator risking their life when they operate the switch? How do they know whether to operate the switch or not? Is their decision based on guesswork, complacency or faith?
    It must be none of these things. The basis for the decision has to be full confidence in an established properly managed switchgear system, which ensures that the equipment is correctly maintained, taking into account its age, type and dielectric type, and that any restriction notices have been appraised and appropriate action taken.
    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 with the operating the switchgear.
    - 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 that 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. In particular, as the equipment ages, more intrusive inspections are required.
    s Anti-reflex handles - these must be fitted to ensure that the equipment can only be operated fully in one direction (open or close), before the handle is re-oriented to allow operation in the other direction.

    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
    s 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.

    Record keeping is, of course, not the only requirement. It must be complemented by continued training of persons authorised to operate switchgear (authorised persons). Care must be taken, however, in selecting the training provider - it is important to choose an organisation that has in-depth knowledge and experience of the special issues involved with older switchgear, rather than an organisation that can only provide training relating to modern technology.

    Naturally, the dangers of older switchgear that were mentioned earlier must also be directly addressed. This means, for example, that equipment with dependent manual operating mechanisms or which lacks anti-reflex handles must be immediately taken out of service and removed from site.

    Taking these measures will help to maximise the safety and reliability of older equipment. In contrast, if the special needs of older switchgear are not properly considered, and if it is operated without due regard for its internal condition, or when it is outside its recommended life cycle, the consequences could be catastrophic.

    It is always essential to remember the operator's life is in their own hands when they operate switchgear. No assumptions should be made, therefore, and no pressure should be applied to operators to force them to carry out switching operations unwillingly.
    Operators should always be confident, because of a well-structured management programme, the switchgear is in a suitable condition to be switched safely. Implementing a switchgear management programme is not difficult, but it is often useful to seek advice and guidance from an expert in the field.

    Hopefully this article has demonstrated health and safety issues, far from being a subject for trivialisation, are an essential concern for everyone whose work involves electrical switchgear. Tackling these issues has many benefits. Reduction of hazards is the most important of these, but well-trained personnel and an effective equipment management regime will also result in reduced downtime and increased security of supply.  Investing in health and safety, therefore, is a very sound business proposition.

  • Switchgear technology - Withdrawable switchgear – the Return

    The popularity of withdrawable switchgear declined considerably in the UK during the last ten years, but has recently been making a comeback. However, its rise in popularity has raised concerns about compliance with new IEC regulations. Steve Goldspink, Siemens Transmission and Distribution, outlines the new regulations and tells the untold story of the return of withdrawable switchgear to the UK market

    For the last decade, the UK switchgear industry has focused on fixed pattern switchgear. This being despite the fact its alternative - withdrawable switchgear - has a reputation for being, where required, much easier and safer to repair and maintain; particularly in process orientated environments where power outages can be extremely costly. In recent times however, withdrawable switchgear has made a comeback as the industry has begun to rediscover, understand and appreciate its benefits.

    This new switchgear, now available, is not vastly different technology but changes in technical requirements of users based on operational safety, service continuity and maintenance needs have driven subtle change.
    In order to keep abreast with these changes, the International Electrotechnical Commission (IEC), a leading global organisation that prepares and publishes international standards for all electrical and electronic related technologies, has developed a new standard for medium voltage switchgear - IEC 62271-200.
    IEC 62271-200 is a standard for AC metal-enclosed switchgear and control gear for rated voltages above 1 kV and up to and including 52kV. There are a number of differences between the previous and new standard. Contrary to its predecessor, IEC62271-200 no longer classifies switchgear according to design features but on the basis of functional characteristics. It demands a detailed description of the characteristics concerning the aspects of service continuity, maintainability and safety classifications, which are all of prime importance to the user.
    Introduced in 2003, it is a legal requirement for all switchgear built after 1 February 2007 to satisfy this standard. IEC 62271-200 supersedes the previous standard for medium voltage switchgear - IEC 60298 and aims to remove some of the ambiguities in this standard by means of classifying switchgear.
    An increasing concern of mine, however, is a number of medium voltage switchgear manufacturers in the power transmission and distribution industry may be deterred from putting their equipment through the appropriate testing procedures to ensure it meets this standard, due to the significant investment required in doing so. Whilst accurate statistics are almost impossible to source, it is almost certainly the case that some switchgear being sold new into the UK market has not been tested to the new standards, and is therefore unlikely to be fully compliant with the new standard. In short, the ultimate benefit of the new IEC 62271-200 standard is to provide improved classifications regarding the levels of operator safety, service continuity and maintainability - features that should not be overlooked.

    The new switchgear utilises well established, high availability maintenance-free vacuum circuit breaker technology, with operating cycles far exceeding the normal number, meaning frequent access to the circuit-breaker is no longer an ongoing concern for the switchgear operators. Additionally, the vacuum arc-quenching principle in modern switchgear is technologically superior to other arc-quenching principles currently employed within the industry.

    Furthermore, in line with the latest requirements of the new standard, to ensure maximum operational and functional safety, the circuit breaker and earth switches are fully type tested inside the appropriate switchgear panel and not as a standalone device to ensure all functional influences are taken into account.

    One particular area where safety is of critical importance is internal arc tested equipment, an issue which is gaining widespread awareness across the world due to operator safety concerns. An internal arc is a high resistance arc fault within the switchgear enclosure due to disruptive discharges between phases or phase to earth. Internal arcs can be created by a variety of causes including insulation failures, functional faults of devices and even negligence during routine operation and maintenance. The result however can be catastrophic, in that the arc reacts explosively with the surrounding atmosphere, causing a rapid increase in temperature and pressure which, if uncontrolled, can be extremely hazardous to people in the immediate area.

    With the old IEC standard, much room was left for different ways of carrying out the test and interpreting the results. Although still an optional test in IEC 62271-200, the new standard gives clear guidance on how to perform the internal arcing test and defines the acceptance criteria. More specifically, test conditions are defined and are no longer subject to agreement between the equipment manufacturer and the test laboratory. Ultimately, internal arc classification is only granted if all criteria are met.

    In addition, when an internal arc classification is selected, all five internal arc criteria must be fulfilled without exception. Firstly, covers and doors on the switchgear must remain closed, with limited deformations accepted. Secondly, no fragmentation of enclosure must occur, with zero projection of small parts above 60g in weight. There must also be no holes in the accessible sides of the switchgear up to a height of two metres and the horizontal and vertical indicators used in testing must not ignite due to the effect of hot gases. Finally, the enclosure must remain connected to its earthing connections at all times.

    The key now must be for manufacturers of switchgear equipment to take their responsibilities seriously and ensure all new switchgear being produced goes through the appropriate testing where required, and is re-classified in line with the new IEC standard.
    This is even more important given there is a general skills shortage facing the industry. We are now in a situation where more and more purchasers of switchgear equipment are either outsourcing their operations because of a lack of skilled engineers, or being forced to employ a smaller team of engineers to carry out the work. Both of these factors make health and safety even more important in order to protect those engineers operating and maintaining switchgear equipment.

    My advice to end-users is to demand the switchgear they are purchasing meets the latest testing criteria and all switchgear used has been classified in accordance with IEC 62271-200. This is the only way that users of switchgear in industrial applications can have the peace of mind of being able to select products which utilise the latest developments in technology, safety, service continuity and reliability.

    Withdrawable switchgear is making a welcome return to the UK market with process industries benefiting from easier maintenance and repair, which in turn can result in much reduced downtime. However, any move to withdrawable switchgear should only be contemplated when maximum operator safety can be guaranteed. In effect this means selecting equipment type-tested according to IEC 62271-200.

  • Switchgear & Substations - Condition measurement pays dividends

    More than 50 senior figures from the electricity industry gathered at London's Royal Automobile Club on 5 February 2009, for NetWork 2009 - the first ever international DNO strategy conference. Top of their agenda was how the ability to measure the condition of live assets is making the management of network assets more efficient, at lower cost. Neil Davies from EA Technology Instruments investigates

    The inaugural NetWork 2009 event in February was an extremely valuable opportunity for UK DNOs to share knowledge on the key strategic management issues facing network operators and learn from the examples  of two of the world's most reliable and efficient networks - SP Powergrid of Singapore and China Light and Power (CLP) of Hong Kong.
    The pressures are common to every operator across the world: how can they manage an ageing asset base so that it will deliver greater network reliability, power quality and safety, while reducing costs to consumers? At the same time, how can they make a watertight business case for investment in maintaining, upgrading and replacing assets to stakeholders, including industry regulators?

    The answer to these questions is being found in two developments which are inextricably linked: new techniques for accurately measuring the condition of live assets, plus new methodologies for managing assets more effectively, based on their actual condition.
    Let's look at what has been achieved in Hong Kong and Singapore, where condition based asset management has become the driver for remarkable improvements in both reliability and cost efficiency:

    SP Powergrid, Singapore
    SP Powergrid's network includes nearly 10,000 substations, 40,000 switchgear sets, 14,000 transformers and 30,000km of cable. Since incorporating condition monitoring into its systems, it has dramatically improved an already excellent performance. The System Average Interruption Duration Index (SAIDI) has averaged less than 1 minute per year over the last three years.
    NB: The blip in 2004/5 was caused by a third party supply issue outside SP Powergrid's control.

    SP Powergrid estimates over the last eight financial years, condition monitoring has enabled it to avert 450 network failure incidents, with a net financial saving of US$29m. In addition to improving customer service, it has been able to pass cost savings on to them.

    CLP  Hong  Kong
    The China Light and Power network in Hong Kong includes nearly 13,000 substations and 22,000km of overhead lines and underground cables, serving 2.26 million customers.
    As a result of focusing over the last 10 years on condition based maintenance, to predict faults and improve reliability , it has reduced its SAIDI figures from more than 40 to 2.68 minutes lost per year

    Demand from customers has continue to grow, but in the last two years, greater operating efficiencies have enabled CLP to reduce tariffs.

    The UK Business Case
    Taken as a whole, the UK electricity network is relatively efficient. But an in-depth analysis by EA Technology Consulting of preventable, condition-related failures, shows there is considerable scope for improvement:
    Using condition monitoring as a failure prevention tool is a valuable technique, but is only part of a much wider move towards condition based asset management techniques.

    Using Condition Data
    The ability to collect data on the condition of live assets is transforming the industry's approach to asset management itself: from one based on time-scheduled maintenance and replacement, to one based on a detailed understanding of the condition of the asset base. It also provides accurate intelligence for investment programmes.
    Maximising the value of  data is essentially carried out at two levels:

    Asset condition registers
    Expert analysis and interpretation of PD activity readings gives a clear indication of the condition of assets, including accurate predictions of when they are likely to fail. In EA Technology's case, this is based on a unique database, built up over more than 30 years, which shows how tens of thousands of asset types have deteriorated over time.
    This approach enables operators to develop registers of assets, in which each asset is accorded a ‘health index' showing its present condition, its predicted date of failure and/or its remaining service life.

    Condition Based Risk Management (CBRM)
    CBRM is a comprehensive new methodology, which takes condition based asset management to a higher level, enabling managers to take more intelligent decisions on revenue and capital spending. It also reduces the cost of network operation, while improving their efficiency and reliability.

    The effectiveness of CBRM derives from factoring together probability (derived from the asset condition) and consequences of asset failure, to determine risk in terms of financial cost.
    In addition to managing the health of assets, CBRM provides the answers to the key questions:

    - If an asset costing £XX fails, what will be the consequential loss to the business? 
    - If an asset is refurbished or replaced at a cost of £YY, what will be the benefit to the business?
    - Therefore, where should we prioritise our spending?

    EA Technology's experience shows that partial discharge (PD) activity is a factor in around 85% of disruptive substation failures. It has thus become increasingly clear the ability to detect and measure PD is key to assessing the health of assets. PD activity provides clear evidence that an asset is deteriorating in a way that is likely to lead to failure.  The process of deterioration can propagate and develop, until the insulation is unable to withstand the electrical stress, leading to flashover.

    Partial discharges emit energy, in the form of effects which can be detected, located, measured and monitored:
    - Electromagnetic emissions, in the form of radio waves, light and heat.
    - Acoustic emissions, in the audible and ultrasonic ranges.
    - Ozone and nitrous oxide gases.
    The most effective techniques for detecting and measuring PD activity in live assets are based on quantifying:

    Transient earth voltages (TEVs)
    The importance of TEV effects (discharges of radio energy associated with PD activity) was first identified by EA Technology in the 1970s. Measuring TEV emissions is the most effective way to assess internal PD activity in metalclad MV switchgear.

    Ultrasonic emissions
    PD activity creates emissions in both the audible and ultrasonic ranges. The latter is by far the most valuable for early detection and measurement.  Measuring ultrasonic emissions is the most effective way to assess PD activity where there is an air passage e.g. vents or door in the casing of an asset.

    UHF emissions
    PD activity can also be measured in the UHF range, and is particularly useful in monitoring EHV assets.

    The latest PD instruments typically use a combination of ultrasonic and TEV sensor technologies, characterised by the EA Technology UltraTEV range. These include:

    - Handheld dual sensor instruments which provide an instant indication of critical levels of PD activity, ideal for ‘first pass' PD surveys and safety checks. Traffic light warning levels are precisely calibrated using a database of known patterns of asset deterioration.
    - More sophisticated handhelds, which provide audible and numerical readings of ultrasonic and TEV activity.
    - PD location instruments which pinpoint and quantify the source of PD activity.
    - PD monitoring instruments, which measure, record and analyse PD activity over time.
    - PD alarm systems, which give immediate warning of critical PD activity in groups of assets or whole networks.
    - Specialist PD monitoring systems for strategically important assets, including Gas Insulated Switchgear (GIS).

    Other Asset Classes
    Condition based management is by no means confined to assets which present faults in the form of PD activity.

    The same principle is equally effective, using a range of condition measurement techniques, to all types of electricity network assets including substations and cables. It can apply to the complete asset, such as an overhead line, as well as to the component parts, such as the overhead conductors, poles, towers and footings.

    The ability to assess the condition of live assets is changing the way assets are managed on many levels: as a technique for preventing faults from developing into failures, as a means of moving from time-based to condition-based maintenance, as a way of quantifying risk and as the basis for justifying and prioritising investment.

    But the ultimate rationale for condition measurement is that it pays for itself, many times over.

    This article includes material from presentations made at NetWork 2009, the first international distribution network strategy conference, held in London in February 2009. The full presentations are available from www.networkconference.co.uk, where readers can also register their interest in  NetWork 2010.
    For further information please email This email address is being protected from spambots. You need JavaScript enabled to view it.

  • Switchgear - Testing times for fixed circuit breaker panels

    ABB's UniGear ZS1 range was launched in 2004, claimed to be the world's first ‘one  size fits all' platform for primary MV (medium voltage) air-insulated switchgear (AIS) in the 12 to 24 kV range. Since then, we have seen a significant change in the UK market. Now, instead of the traditional withdrawable circuit breaker panel, a growing number of customers are  calling for the simplicity, lower cost and smaller installation footprint offered by a fixed circuit breaker panel. Malcolm Cork of ABB outlines the testing programme behind the company's new fixed circuit breaker panel

    ABB's response was the launch, in 2008, of the new UniGear 500 R fitted with the Vmax/F vacuum circuit breaker. It is just 500 mm wide - a significant space saving compared with the standard 650 mm panel, especially in typical applications of banks of 10 or more panels. It is ideally suited for various market segments requiring containerized solutions. Before it could be brought to market it had to undergo a rigorous type testing programme to ensure compliance with the relevant specifications. In particular we had to meet the Energy Networks Association Technical Specification ENATS 41-36 which covers distribution switchgear up to 36kV for the utilities. This brings together IEC 60694, IEC 62271-200 and 62271-100 with enhancements, clarifications and additional testing to meet the requirements of UK DNOs (Distribution Network Operators).

    IEC standard

    The starting point for the test programme was IEC 62271-200, High voltage switchgear and controlgear - Part 200: AC metal-enclosed switchgear and controlgear for rated voltages above 1 kV and up to and including 52 kV. Issued in November 2003, this international standard was a further development of the previous standard IEC 60298 of 1990. A key aim of the new standard was to focus more on functional characteristics than on design and construction. From February 2007, all new metal-enclosed switchgear must comply with IEC 62271-200 while pre-existing switchgear can continue in operation to IEC 60298.
    The new standard sets a number of new requirements: Firming up of test conditions for the switching devices (making and breaking capacity);Changed sequence for dielectric testing; Introduction of new partition classes; Introduction of internal arc classified (IAC) qualifications

    Test programme
    ÏThe type test programme simulated situations which occur very rarely in real-life. For example, a short-circuit at the maximum current level for which the installation has been designed is rather unrealistic because of the presence of current-limiting components (such as the cables) and because the power available is normally lower than the rated one.

    Short-time and peak withstand current
    This test showed that the main power and the earthing circuits can resist the stresses caused by the passage of the short-circuit current without any damage.

    Temperature rise
    The temperature rise test was carried out at the rated current value of the switchgear unit and shows that the temperature does not become excessive inside of it. During the test, both the switchgear and the apparatus it might be fitted with was checked (circuit-breakers, contactors and switch-disconnectors).

    These tests checked the switchgear has sufficient capability to withstand the lightning impulse and the power frequency voltage. The power frequency withstand voltage test is carried out as a type test, but is also routine on every switchgear unit manufactured.

    Apparatus making and breaking capacity
    All the apparatus (circuit-breakers, contactors and switch-disconnectors) was subjected to the rated current and short-circuit current breaking tests. Furthermore, they were also subjected to the opening and closing of capacitive and inductive loads, capacitor banks and cable lines.

    Earthing switch making capacity
    The earthing switch of the UniGear 500 R can be closed under short-circuit. In actual fact, the earthing switch is normally interlocked to avoid being operated on circuits which are still live. However, should this happen for any one of several reasons, safety of the personnel operating the installation would be fully safeguarded.

    Mechanical operations
    The mechanical life tests on all the operating parts highlight the reliability of the apparatus. General experience shows mechanical faults are one of the most common causes of a fault in an installation. The switchgear and apparatus it contains have been tested by carrying out a high number of operations - higher than those which are normally carried out in installations in service. Moreover, the switchgear components are part of a quality programme and are regularly sampled from the production lines and subjected to mechanical life tests to verify that the quality is identical to that of the components subjected to the type tests.

    When developing any type of electrical equipment, personnel safety must take first place. So the equipment should be designed and tested to withstand an internal arc due to a short-circuit current of the same level as the maximum short-time withstand level.

    The tests showed the metal housing is able to protect personnel working near the switchgear in the case of a fault which evolves as far as striking an internal arc.
    An internal arc is among the most unlikely of faults, although it can theoretically be caused by various factors, such as:
    - Insulation defects due to deterioration of the components such as caused by environmental conditions and pollution.
    - Overvoltages of atmospheric origin or generated by operation of a component.
    - Incorrect operations due to not following procedures or inadequate training.
    - Breakage or tampering of the safety interlocks.
    - Overheating of the contact area, due to the presence of corrosive agents or when the
    connections are not sufficiently tightened.
    - Entry of small animals in the switchgear.
    - Material left behind inside the switchgear during maintenance operations.
    Careful design can significantly reduce the possibility of these incidents but not all of them can be eliminated completely.
    The energy produced by the internal arc causes the following phenomena:
    - Increase in the internal pressure.
    - Increase in temperature.
    - Visual and acoustic effects.
    - Mechanical stresses on the switchgear structure.
    - Melting, decomposition and evaporation of materials.

    Unless suitably controlled, these can have very serious consequences for the operators, such as physical harm (due to the shock wave, flying parts and the doors opening) and burns (due to emission of hot gases).

    The tests checked the compartment doors remain closed and that no components are ejected from the switchgear even when subjected to very high pressures, and that no flames or incandescent gases escaped, thereby ensuring the physical integrity of the personnel operating near the switchgear. It also checked that no holes were produced in the external freely accessible parts of the housing and finally, that all the connections to the earthing circuit remained intact, guaranteeing the safety of personnel who may access the switchgear after the fault.

    Typical areas where the international standards are enhanced by the ENA Technical Specifications relate to operational procedures, interlocking and consequently operator health and safety. ENA specifications also consider quality procedures, low voltage controls and auxiliary component requirements.

    A good example of where ENA specifications have impacted on design is in how the exhaust gases are relieved. The standard UniGear 500 R is internal arc classified IAC AFLR up to 25kA x 1 second according to the IEC 62271-200 Annex A, with exhaust gas relief through the top via the main gas duct channel. The ENATS 41-36 version is classified IAC AFL up to 25kA x 1 second but with exhaust gas relief from the rear.

    ENA approval lasts for three years, but it is very much a dynamic process that enables manufacturers to receive direct feedback of field experience.. For example, there have recently been reports of arc tracking occurring on fuse clips on equipment that is now over 30 years old. So we are looking at new designs to prevent this.

    Following ENA approval, the equipment has already been installed in a number of applications that require a compact, space-saving, low-maintenance solution such as data centres and wind farms. The fixed circuit breaker can be replaced in less than 90 minutes. But there are some installations that will require the higher level of availability and ease of maintenance made possible by a withdrawable circuit breaker, especially on crucial  circuits. The advantage of the UniGear 500 is it coordinates with the complete UniGear ZS1 portfolio. This makes it possible to specify on the same busbar, a UniGear ZS1 with withdrawable incomer, a fixed circuit breaker outgoing and additional starter switchgear.

  • Switchgear - Environment first with SF6

    The new Fluorinated Greenhouse Gases Regulations 2009 impose specific conditions on operators of high voltage (HV) switchgear assets containing SF6 gas. EA Technology senior consultant Gary Eastwood explains why the new regs are important

    The good news about sulphur hexafluoride (SF6) is that it is an exceptionally effective electrical insulator that is widely used to ensure the safe and reliable performance of modern HV switchgear around the world. The bad news is that, for a given mass of gas released into the atmosphere, it has the highest potential to contribute to global warming of any other fluorinated greenhouse gas so far evaluated.

    Let's start by examining the global warming potential issue, because that is the driver behind the new regulations, which have come into force across the European Union (EU) and will no doubt influence legislation globally.
    SF6 molecule
    Pure SF6 is a colourless, odourless, non-toxic gas made up of a single sulphur atom, bonded with six fluorine atoms. Under normal conditions it is extremely resistant to reaction with other substances, making it chemically inert: and it is over five times heavier than air. However, if it is allowed to escape to atmosphere, its potential effect on global warming, measured over a 100 year time period, is approximately 22,000 times greater than the equivalent amount of carbon dioxide (CO2). In other words, releasing a single kilo of SF6 gas has the same effect as 22 tonnes of CO2.

    The advantages of using SF6 in HV switchgear are considerable, not least because the gas is non-flammable, non-corrosive to internal switchgear components and its thermal properties make it an exceptional arc suppressant: even when SF6 is momentarily broken down during arcing, it largely re-combines back into its original state. In its pure form, it is non-toxic and does not pose a hazard to human health providing switchrooms and storage locations are well ventilated. This combination of properties has enabled designers to develop HV switchgear which is smaller and requires less frequent intrusive maintenance than equivalent types that use air or oil for arc extinguishing and insulation.

    The electricity industry is a major user of SF6, accounting for approximately 4,000 tonnes of production each year. Not surprisingly, the European Commission initially considered an outright ban on the use of SF6 in new switchgear, but subsequently stepped back from this position, particularly in the light of voluntary actions already being taken by SF6 producers, switchgear manufacturers and utilities to minimise emissions of the gas. Instead, they have decided to impose new regulations (Regulation EC No. 842/2006) that require SF6 gas, or mixtures of the gas, in high voltage switchgear to be recovered by trained and certificated personnel. This applies to maintenance activities as well as final disposal. Every EU member state is obliged to adopt these regulations. Hence the UK's Fluorinated Greenhouse Gases Regulations 2009.

    The new regulations certainly provide for member states to impose fines for non-compliance, but in practice the industry itself is expected to ensure the requirements are being implemented. Minimising the release of SF6 is important in the context of individual companies' environmental and corporate responsibilities: but it is also a challenge collectively for the industry. If SF6 emissions from electrical equipment are seen as not being controlled through compliance with the regulations, then there is a real danger of more regulation or possible restrictions on its use in high voltage equipment, at greater cost and inconvenience to the industry. Compliance is therefore not only the right thing to do environmentally: it is in our own best interests.

    Specific provisions relating to handling of SF6 in HV switchgear are laid out in the new UK regulations. These stipulate that anyone who recovers the gas from HV switchgear must have enrolled on an appropriate training course by 3 July 2009, for the purposes of gaining certification in the regulations.

    Subsequent to that, personnel will only be allowed to recover the gas if they have passed an assessment, and been issued with a certificate of competence, by an approved evaluation and certification body. It is worth noting operators of HV switchgear are also responsible for ensuring that anyone who carries out gas recovery on their equipment, including contractors' personnel, is suitably qualified and certificated.

    Because EA Technology has been running SF6 training courses for several years, it has been relatively straightforward for us to tailor them to meet the specific requirements of the new regulations. We have also been designated as an evaluation and certification body in the UK by the Department for Environment, Food and Rural Affairs (DEFRA) and certification issued by us is valid in all EU member states.

    Our two day course comprises one day on the theory and generic practices for handling and testing SF6, using a range of equipment typically used by the industry: the skills and knowledge gained are intended to be readily transferable to other types of switchgear and SF6 handling equipment. Training includes the correct selection and use of Personal Protection Equipment (PPE) for working in open compartments which may contain small quantities of SF6  decomposition products, produced by arcing or abnormal electrical discharges.

    On the second day, delegates are assessed and issued with a certificate of competency and a personal ID competency card. Both are valid for four years and are recognised across the EU. Each course is limited to 16 people, split into groups of eight, so tuition and assessment are on a personal level. Each stage of the assessment is fully documented using pre-prepared question papers and checklists. Delegates are issued with digital copies of all course presentations and materials on a memory stick: this also includes our practical guide for storage, transport, handling, testing and disposal of SF6.

    We also offer single day courses, without the assessment and certification elements, for managers and supervisors who are responsible for developing SF6 policies and monitoring compliance by staff and contractors: and we provide refresher courses for people who already have SF6 handling experience but need to get up to speed on the latest developments.

    In our view, the requirement for training and certification should be seen as a positive step towards minimising emissions of SF6 when carrying out maintenance activities and final disposal of HV switchgear, rather than an additional regulatory burden. Given that restrictions have been placed on the use of SF6 in other industries and the fact EU member states are required to report annual emissions of fluorinated greenhouse gases, it is truly in the best interests of the electricity industry that operators of HV switchgear should take the steps necessary to achieve compliance with the new regulations and build on the voluntary actions already taken to date.

    Details on SF6 training courses, assessments and certification are available from Jackie Clarke or Vanessa Revell at This email address is being protected from spambots. You need JavaScript enabled to view it.  or call 0151 347 2323.

  • Switchgear - HV switchgear – there is a green alternative

    High voltage switchgear is one of the few applications where the use of SF6 gas is still  permitted under Greenhouse Gas Regulations. This is based on the premise that there is no viable alternative. However, in the range 1-52kV there is a perfectly viable option in the form of vacuum switchgear with solid dielectric insulation. Vacuum switchgear is similar in size and technically equivalent, if not superior, to SF6 switchgear. It is being used increasingly by utilities in Europe for medium voltage (1-52kV) applications explain W Porte and GC Schoonenberg from Eaton, in the first instalment of this two-part article

    The notion there is no viable alternative to SF6 switchgear for high voltage applications, which is exploited by the producers of SF6 and manufacturers of SF6 switchgear, can be attributed in part to the different methods of classifying voltage levels. IEC terminology identifies two voltage bands - low voltage for applications up to 1,000V a.c. and high voltage for anything greater than 1,000V. However the term medium voltage is widely used for distribution voltages in the range 1kV-52kV. Thus it is perceived by some that SF6 is the only option for systems greater than 1kV when, in reality, vacuum switchgear is a ‘green' option up to 52kV.

    F-gas Regulations
    The Fluorinated Greenhouse Gas Regulations 2009, which came into force in March, impose strict legal requirements upon personnel and companies in five industry sectors which use fluorinated greenhouse gases (F gases).  These gases include the fluorocarbons (CFCs and HFCs) as well as sulphur hexafluoride (SF6).   High voltage switchgear is one of the five industry sectors along with refrigeration and air conditioning, fire protection systems and certain types of solvent.

    The Regulations and steps that can be taken to train personnel in the recovery of SF6 gas, or mixtures of the gas, during maintenance or at end of life were described by Gary Eastwood in the August issue of Electrical Review.

    Concerned utilities are turning increasingly to vacuum technology for medium voltage applications. Northern Ireland Electricity became the first United Kingdom utility to order Eaton's Xiria vacuum ring main units in 2007, as part of its framework contract for secondary power distribution, and last year EDF Energy placed a three-year framework contract with Eaton to supply 11kV double-busbar switchgear incorporating its Innovac vacuum circuit-breakers. The first 60 units were supplied to EDF Energy for a major substation in Stratford, East London.

    In the Netherlands, the government is supporting a Green Switching initiative involving  four utilities, the SenterNovem (a Dutch agency of the Ministry of Economic Affairs for the promotion of sustainability and innovation)  and Eaton. This group is working to increase awareness of the issues surrounding non-carbon greenhouse gases and to promote the development of alternative technologies. It believes that there should be tighter controls over the use of SF6 with a ban on its use up to 52kV. A position paper and other documentation are available on www.greenswitching.com.

    In the USA, the Environmental Protection Agency (EPA) is promoting a voluntary SF6 emission reduction programme in which 80 utilities are participating. Between 2000 and 2006, emissions by these utilities fell from 15.1% to 6.5%.    Meanwhile, the Leadership in Energy and Environmental Design (LEED) system for rating green buildings, developed by the US Green Building Council, is being adopted in many parts of the world as a way to quantify and compare sustainability. Use of vacuum switchgear with solid dielectric will help achieve the objectives of the LEED standards.

    SF6 switchgear
    Approximately 8,000 tonnes of SF6 are produced annually, of which 80% is used in electrical switchgear. It is used for two functions - circuit interruption and insulation.

    For circuit interruption SF6 offers excellent arc quenching and heat transfer properties. It has a high chemical stability and a fast dielectric recovery time with self-healing properties under electrical discharge conditions. Under normal operating conditions it is non-flammable and non-explosive, making it an excellent alternative to oil-filled switchgear, which has largely disappeared as a technology over the last thirty years.

    As an insulating medium, SF6 has an electrical breakdown strength approximately three times that of air at atmospheric pressure. This means by filling a circuit-breaker enclosure with SF6 gas the line-to-line and line-to-earth distances can be reduced, making for compact equipment. This is the principal reason why SF6 gas has been used so extensively as an insulation medium in gas insulated switchgear (GIS) even where vacuum technology is used for circuit interruption.

    However, SF6 is one the of six most potent greenhouse gases identified by the Intergovernmental Panel on Climate Change (IPCC) and consequently included in the Kyoto list of substances whose use and emission should be minimised. Although far less common than carbon dioxide, it has a global warming potential (GWP) listed as 23,900. This means one tonne of SF6 has the same greenhouse effect as 23,900 tonnes of CO2. At present its contribution to global warming is only 0.01% but, unlike other greenhouse gases, it is largely immune to chemical and photolytic degradation so its effects are cumulative. Annual rate of increase in the atmosphere is said to be 8% and lifetime in the atmosphere is estimated as 3,200 years (CO2 is 50-200 years).

    Under the F-gas Regulations of 2006, the use of SF6 was prohibited for most applications including sports shoes, tennis balls, car tyres and double glazing. However, its continued use for HV switchgear is permitted on the basis that there is no viable alternative. Nevertheless, the Regulations imposed strict requirements for the manufacture, use, maintenance and disposal of SF6 switchgear, including special requirements for the training and certification of personnel. These requirements were strengthened by the 2009 Regulations.

    The extent of leakage of SF6 into the atmosphere is not known, but emissions of 6-13% per annum have been estimated. Under the F-gas Regulations all larger systems containing SF6 should be inspected regularly and emissions should be prevented as far as possible during maintenance. Some authorities insist on continuous monitoring of all gas-filled enclosures to detect leaks.

    SF6 also poses a number of health risks. For example, although it is non-toxic and chemically and thermally stable under normal conditions, it can break down into highly toxic substances such as HF, SOF2, SF4 and S2F10 when exposed to arcing, partial discharges or incineration. Under normal operating conditions these are generally recombined after a discharge is cleared but some toxic residue may remain in the housing. If there is a catastrophic failure, these products could be released into the atmosphere, exposing the public to risk. Consequently, SF6 switchgear should not be used in residential areas, commercial buildings, shopping malls, railway stations, hospitals, educational campuses or underground installations.

    Asphyxiation is another risk. SF6 is a colourless, odourless gas which is about five times the density of air. Consequently locations should be well-ventilated and gas analysing equipment may be needed to alert staff to any risk from leakage.

    End-of-life disposal is an important consideration. Measures must be in place to recover the SF6 gas and personnel need to be protected against risks from harmful by-products. The presence of these by-products restricts the ability of the materials to be recycled.

    It should also be borne in mind while these products are manufactured under controlled conditions in industrialised countries, they are being sold worldwide, including countries where controls embodied in the F-Gas Regulations and similar legislation are not enforced. End-of-life disposal becomes even more uncertain in these countries. The risks are exacerbated when used equipment containing SF6 gas is exported as waste to third-world countries where it may be dismantled by unqualified personnel.

    The second part of this feature will appear in the November issue of Electrical Review

  • Switchgear - HV switchgear – there is a green alternative - part 2

    High voltage switchgear is one of the few applications where the use of SF6 gas is still permitted under Greenhouse Gas Regulations. This is based on the premise there is no viable alternative. However, in the range 1-52kV there is a perfectly viable option in the form of vacuum switchgear with solid dielectric insulation. Vacuum switchgear is similar in size and technically equivalent, if not superior, to SF6 switchgear. It is being used increasingly by utilities in Europe for medium voltage (1-52kV) applications say W Porte and GC Schoonenberg from Eaton, in the second instalment of this two-part article 
    *the first part of this article can be found at

    Vacuum interruption is a proven technology, introduced more than 40 years ago. Arc interruption takes place in a vacuum ‘bottle'. Vacuum interrupters do not require costly leakage monitoring equipment. Electrical performance is comparable and, at times, better than SF6 switchgear. While capital cost is slightly higher, total life-cycle cost is lower due to the lower maintenance costs. All materials can be recycled at end of life.

    Continuous development has seen the size of a 15kV vacuum interrupter bottle come down from180mm diameter in 1967 to 50mm today. Meanwhile modern sealing techniques ensure that units retain their vacuum for more than 25 years. On the rare occasions when leaks do occur, they normally manifest themselves early in life; so rigorous production testing helps identify such leaks before units reach the field. Any leaks are, of course, completely harmless to the environment.

    Vacuum circuit-breakers are suitable for a wide range of medium voltage switching applications including transformer secondary protection, capacitor switching and motor switching. They are used by utilities for ring main units and MV switchboards in the range 3kV to 36kV.  They are suitable for current ratings from 100A to more than 4,000A and fault levels from 6kA to 63kA.

    Apart from compact size, vacuum circuit-breakers offer excellent electrical performance. They will normally withstand a rated a.c. power frequency withstand voltage (an overvoltage due to power system switching operations) of 2-4 times normal operating voltage. Rated lightning impulse withstand is 4-12 times normal operating voltage. However, in normal service the breaker contacts are closed so lightning overvoltages are mostly seen by the line-to-earth or line-to-line insulation; in the rare event of a lightning impulse appearing across the open contacts of the vacuum interrupter, the current will be quickly broken. Under similar conditions an SF6 puffer-type circuit-breaker, air circuit-breaker or minimum oil circuit-breaker would probably explode.

    An interesting characteristic of the vacuum circuit-breaker is self-conditioning of the contacts. Rough spots that can occur on the contact surfaces are smoothed out by the discharge when the contacts are opened on-load.

    Vacuum interrupters offer exceptional performance under load switching conditions, far exceeding the mechanical life of any circuit-breakers and reclosers of which they form a part. Consequently they are used in railway switching applications where electrical and mechanical life in excess of 250,000 operations is required. They are also suited to motor switching duties in excess of one million operations, arc furnace switching and capacitor switching. Contact resistance remains low throughout life because contact erosion only occurs at the cathode and eroded material is deposited uniformly on the anode; the contacts act randomly as cathode and anode so the effect is evened out. In SF6 circuit-breakers, contact resistance increases during life.

    Vacuum interrupters are constructed from materials that can be recovered and recycled at the end of life. They do not contain greenhouse gases; nor do they present potential health hazards due to the products of decomposition. No special precautions are necessary to protect the environment from the results of leaks or during disposal.

    The compact size of modern vacuum insulator bottles means special measures are necessary to improve insulation levels. A 150mm ceramic length will only have a basic insulation level (BIL) of 125kV in air. For this reason insulators may be immersed in a dielectric medium such as oil or SF6 gas to raise the BIL to 170kV. Oil is being phased out because of the fire risk, so SF6 insulation is favoured by many manufacturers.

    However, an alternative approach is to enclose the vacuum interrupter in a potting compound such as polyurethane or epoxy. In some cases an epoxy insulator with a contoured profile, similar to the ‘sheds' used on overhead line insulators, is used to increase creep distances. This is especially valuable when the equipment is used in industrial environments involving heavy atmospheric pollution or condensation. In some cases the entire interrupter and associated busbar are enclosed in solid insulation.

    Modern vacuum switchgear with solid dielectric insulation is comparable in size to the SF6 gas insulated equivalent. The circuit-breaker assembly can operate in a normal enclosure with no special sealing or gas filling, and there is no need for costly monitoring equipment. Maintenance is negligible and life can be expected to be 30 years or more.

    Total cost of ownership
    While the unit cost for gas insulated switchgear is lower than for the solid insulated switchgear described above, total cost of ownership is much higher for the GIS equipment.  The specialist nature of the pressure checks needed by GIS equipment means that trained personnel with specialist equipment will have to carry out the work. One estimate has put the annual cost of this maintenance as 9% of the equipment value per year. This does not include any other safety and insurance costs.

    Disposal costs for GIS equipment at end of life are difficult to quantify. Recycling of parts and by-products is not practicable and dismantling, transport and disposal costs will be high.  In contrast the solid-insulated equipment is fully compliant with ISO 14001, covering environmental management systems and standards. All parts are capable of being recycled.

    There is no justification - environmentally, technically or financially - for using SF6 gas-insulated switchgear for circuit-breakers and ring main units up to 52kV. In fact vacuum interrupters up to 145kV are now in service. However, solid insulation has yet to catch up with this.

  • Switchgear technology - Hybrid substation switchgear provides the best of both worlds

    Stephen Trotter, division head of ABB Power Systems UK, explains how hybrid switchgear  modules that combine the virtues of AIS and GIS technology can offer greater flexibility for substation design

    The term ‘hybrid' refers to the combination of both conventional air insulated switchgear (AIS) and the newer metal-clad gas insulated (GIS) switchgear. This hybrid solution, as found in ABB's Pass MO design - rated up to 170 kV, uses existing, tried and trusted GIS components together with a conventional and extremely reliable AIS bus to connect the various hybrid modules. All the necessary substation switchgear bay functions, including a circuit breaker, one or more combined disconnector/earthing switches, bushings for connection to single or double busbar systems and a current transformer are integrated in one compact module, eliminating the need for separate pieces of equipment for each function.

    Hybrid advantages
    The advantages of the hybrid switchgear design include:
    - AIS busbar: The AIS busbar is relatively inexpensive while offering proven reliability.
    - All live contacts in SF6: Experience has shown AIS disconnector switch contacts require relatively high levels of maintenance, while experience with GIS is exactly the opposite. The use of SF6 technology makes the hybrid switchgear virtually maintenance free, this combines with a high level of reliability to ensure a lower global life cycle cost.
    - Fewer switching elements: Use of GIS technology allows rationalisation of switching elements.
    - Factory pre-assembled and tested: The hybrid modules are fully pre-assembled and tested in the factory. This ensures a higher quality of finished bay than if it is assembled under site conditions, minimises installation time on site - typically two days per bay, reduces the possibility of delay due to adverse site conditions and there is less need for skilled resources on site.
    - Monitoring and on-line diagnostics: The integrated nature of the plant facilitates the use of electronic monitoring and on-line remote diagnostics.
    - Substation modularisation: A modular approach to substation design offers cost and time savings during the design and construction phases. The use of standardized components reduces the number of possible variations and hence the risk of design errors. More predictable costs also offers a higher level of confidence in the project estimation process.
    - Space saving and reduced civil works: The hybrid design can save up to 70% of the space normally required for a conventional AIS substation, while also reducing the need for civil works such as foundations, steelwork and cable trenching operations
    - Combined disconnector/earthing switch: Pass MO is equipped with a combined disconnector/earthing switch. The mechanism has a minimal number of mechanical components and is intrinsically reliable and maintenance-free.
    - Circuit breaker: The Pass MO circuit breaker is a single pressure interrupter that operates by means of the well known selfblast principle. The energy for interrupting currents is partly supplied by the arc itself, this reduces the energy the operating mechanism needs to provide by around 50% compared with a conventional puffer type circuit breaker.
    - Versatility: The Pass MO range offers a series of modules for HV substations including: single bus bar (SBB); double bus bar (DBB); double circuit breaker (DCB). It can also be installed as a high voltage bay on a mobile truck for use in emergencies or if work has to be carried out on existing HV bays.
    - Transportation: The Pass MO fits into a standard truck container and does not require any packaging. No special arrangements are needed for shipping and transportation, and once on site just a simple 30° rotation of the outer poles is needed for the final layout.

    Tight fit for Breamish Street substation
    Well over 2,000 Pass MO bays have been installed worldwide. Following its approval by the ENA (Energy Networks Association) one of the first UK projects to feature the range was CE Electrics UK's new 66/11 kV Breamish Street substation on a brownfield, urban site in Newcastle-upon-Tyne.

    The new primary substation is helping CE Electric UK to deliver an additional 18 MVA of firm capacity to meet the growing demand for additional power, and need for load transfer, created by the significant urban redevelopment programmes on the north bank of the River Tyne. The restricted space available presented a particular technical challenge, since the Breamish Street site is not only compact in size, it is also hemmed in on all four sides by a hotel, a pharmacy, a residents association and the 18th century St Ann's church.

    The space-saving capability of the design has been utilised to construct a new substation comprising two 66/11 kV 15/30 MVA CER transformers, a 66 kV in/out unit and a 13 panel 11 kV switchboard. A 66 kV feeder unit has also been installed at Fossway, the closest CE Electric UK substation.

    Providing vital construction space at Reading
    Hybrid switchgear has also provided an innovative interim solution for the new Scottish and Southern Energy (SSE) 132 kV indoor GIS substation at Reading, currently under construction by an ABB and Balfour Beatty consortium. The site presented a particular challenge as it was already completely full with time expired AIS switchgear that needed to remain in service until the circuits could be transferred to the new substation.

    At first, it appeared the only possibility would be to extend the site onto the local, heavily wooded, green space to offer the additional room needed for the construction of the new indoor GIS building. However, extending the site would have involved considerable planning time and expense and significant project delays.

    An innovative alternative was found by using ABB switchgear as a temporary measure to provide additional space to enable the new GIS building to be built within the existing site footprint. Firstly, ABB dismantled the generator circuit breakers that used to serve the old North Earley power station, which was demolished some years ago. This freed up just enough space to install the Pass MO modules to take over the operation of the AIS circuits at the far end of the site. This enabled the old AIS switchgear to be dismantled to make room for the new GIS substation. After all the circuits have been transferred to the new substation the Pass MO modules will be removed.


  • Designed and built to automate switchgear

    LINAK’s iSwitch has been purposely designed and built to automate switchgear and is a complete turnkey solution.

    Advantages of the iSwitch began by listening to markets issues and their requirements and providing a solution, to name a few LINAK / iSwitch offers…
    -      Easy to install
    -      Manually operated without removing the iSwitch
    -      LINAK offers a complete solution
    -      Cost advantages (reduced instillation times / reliable feedback state etc)

    To summarise we have created and developed a modern approach to Network Automation offering a fit for purpose range of equipment that enables transparency in terms of local manual operation. We offer a competent solution which has been adopted and formally approved with UK and European based DNO’s.

    Tel: 0121 544 2211


  • New low-voltage switchgear

    Rittal has significantly expanded the flexibility and modularity of Ri4Power. Combining Ri4Power low-voltage switchgear with designs 1 and 2-4 to form a single system technology, Ri4Power Form 1-4, allows switchgear manufacturers to fabricate every known form of internal subdivision from one single set of modules.

    Switchgear manufacturers now have access to three busbar systems for the different performance categories of one single low-voltage switchgear system. RiLine60, as a compact busbar system with component and connection adaptors, offers a solution for up to 1600 A for power distribution at the lower distribution level. Maxi-PLS provides a compact busbar system of 1000-4000 A that cuts installation time and Flat-PLS is a rugged busbar system for currents up to 5500 A, based on flat copper bars, meeting maximum requirements with its high short-circuit resistance.

    01709 704000
  • Feature switchgear - Checking switchgear is a really safe bet

    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.

  • Feature switchgear - Sf6 – Yesterday’s technology

    In the 1970s when SF6 (sulphur hexafluoride) was first used in MV switchgear, it seemed to be an almost ideal insulating and switching medium. Since then, the environmental and other hazards associated with SF6 have become increasingly apparent, leading to a shift towards alternative types of switchgear that eliminate its use with no cost or performance penalty. This means, says Alan Birks of Eaton’s Electrical Sector, that SF6 is now yesterday’s technology

    When the search was on in the 1960s to find a viable alternative to the potentially flammable, always messy and sometimes carcinogenic oils used in the MV switchgear of the era, SF6 must have seemed like a godsend. It combines excellent electrical properties with chemical stability and low toxicity. It’s non-flammable and  low in cost. Unsurprisingly, these very desirable characteristics lead to its widespread and enthusiastic adoption in MV switchgear.

    Unfortunately the picture was not quite as rosy as it at first appeared. In particular, as concerns about the environment and, in particular, global warming started to grow, it became all too clear that SF6 had significant potential for causing environmental damage.

    Global warming is the consequence of the greenhouse effect and this is usually associated with elevated levels of CO2 (carbon dioxide) in the atmosphere, which trap more of the sun’s heat. CO2 is not, however, the only culprit; there are many gases that are much more potent in trapping heat than CO2 and, unfortunately SF6 is one of them. In fact, SF6 is currently listed by the International Panel on Climate Change (IPCC) as the most potent greenhouse gas, with a global warming potential 23,900 times that of CO2. That’s not all – SF6 has an atmospheric lifetime of up to 3,200 years, so gas released today will affect the climate for a very long time.

    Clearly the release of SF6 into the atmosphere – which is virtually impossible to avoid when the gas is used, no matter how carefully it is handled – is highly undesirable. As a result, SF6 is on the Kyoto list of substances, the use and emission of which must be minimised. In fact, SF6 is now banned in most of applications, but it is still permitted in medium-voltage (up to 52 kV) and high-voltage (above 52 kV) switchgear. As a consequence 80% of the SF6 produced in the world today is destined for electrical applications.

    It can be confidently expected legislation will ultimately be introduced controlling the use of SF6 in switchgear. Some measures are already in place, including the voluntary programme of the Environmental Protection Agency in the USA and the F-gas regulations that were introduced in Europe in 2007. These legislative changes are already increasing the cost of maintaining switchgear that uses SF6 as well as starting to make its end-of-life disposal expensive and difficult.

    It is worth mentioning poor environmental characteristics are not the only shortcoming of SF6 – its use also gives rise to potential health and safety issues. While SF6 itself is usually considered to be harmless in normal concentrations, the derivatives that are inevitably formed by the arcs created during switching operations are another matter entirely.

    These by-products, which include HF, SOF2, SF4 and S2F10, are toxic. Granted they are produced in relatively small quantities during the normal operation of the switchgear, but they are likely to be present when switchgear is dismantled for maintenance or at the end of its life. Further, should a fault occur that causes an explosion in the switchgear, these toxic by-products are released into the surrounding area.

    We have established there is a strong case for avoiding the use of SF6 switchgear for new installations. Not only is it harmful to the environment, it is also likely to have a high lifetime cost, as the inevitable legislative changes make the maintenance and disposal of equipment that uses SF6 more and more expensive. But are there practical alternatives?

    In answering this question, it’s necessary to distinguish between HV and MV switchgear. When it comes to HV switchgear that operates above 52 kV, there are, at present, few viable alternatives to SF6 in its switching role. However, development is proceeding rapidly in this field and this situation can be expected to change in the not too distant future.

    However, for switchgear operating at below 52 kV, it’s a completely different story. Practical and affordable alternatives are readily available that make the use of SF6 completely unnecessary. The best of this new generation of SF6-free MV switchgear is based on vacuum interrupter technology used in conjunction with solid insulation.

    In addition to their almost negligible environmental impact, vacuum interrupters have many other characteristics to recommend them. Because of the way arcs behave in a vacuum – they constantly move from point to point on the electrodes rather than establishing themselves at a single location, and they are always extinguished at the first current zero – contact erosion in vacuum switching elements is almost non-existent. This has two important consequences. The first is that the switching elements require no maintenance, and the second is that they have very long working lives. The latest types are, for example, certified for 30,000 operating cycles.

    Modern vacuum interrupters are ideally complemented by solid insulation produced using cast epoxy resin technology. This approach allows the parts to be shaped specifically for the best possible insulation performance, with components such as busbars and vacuum interrupters integrated directly into the mouldings.

    The use of solid insulation also allows excellent control over electric fields in the switchgear. With conventional shapes for the primary components like busbars and other conductors in MV switchgear, the electric field is distributed in a manner that is far from uniform. This means there are areas with high field concentrations and, in these areas, there is risk of partial breakthrough. This can trigger avalanches leading to flashovers.

    With solid insulation, however, engineers with experience of breakthrough phenomena and field-steering techniques can arrange for the components and insulation used in the switchgear to be shaped in such a way that flashovers are eliminated entirely, while still achieving a very compact design.

    While the risk of internal arcs is very small with solid-insulated switchgear, it is impossible to say, as with any kind of switchgear, that there is no risk at all. However, solid-insulated switchgear has the additional important benefit that careful design can ensure that, if an internal arc event does occur, its environmental impact is minimised. This can be achieved by adopting single-pole construction, which means that the only conceivable type of internal fault is a single-phase short circuit, rather than a potentially more damaging phase-to-phase short circuit.

    In the best examples of solid-insulated switchgear, the impact of internal arc events is reduced still further by arc absorbers. These guide the gasses and smoke produced by the arc out of the panel and they also have a large absorbing surface that breaks up and filters the gases, greatly reducing their potential for causing damage and injury.

    Further benefits of solid-insulated switchgear over its SF6 counterpart include elimination of the costly and inconvenient routine pressure checks that are always needed with SF6 equipment; and low end-of-life disposal costs. In fact, the newest types of solid-insulated switchgear have been designed specifically to make re-cycling of the components used in them straightforward and inexpensive.

    It is now clear there is an alternative to SF6 switchgear in MV applications that not only eliminates the need to use this environmentally unfriendly gas, but also offers very significant benefits in its own right. Solid-insulated switchgear is safe, compact and very cost-effective, especially when lifecycle costs are considered. It offers dependable performance, it needs minimal maintenance and it has a very long service life. What possible reason can there be, therefore, for the continued use of MV SF6 switchgear?

    In truth, there is no reason. Specifiers and users of MV equipment would be well advised, therefore, to avoid SF6 equipment for all new installations. In addition, end users may wish to consider the benefits of replacing their existing SF6 equipment sooner rather than later, before the regulatory regime relating to greenhouse gasses tightens still further and pushes the costs associated with dismantling and disposing of such equipment sky high.

    A final thought for those who may be tempted to ignore this call to action – your option to do that may not last much longer! The use of SF6 in MV electrical equipment is still tolerated only because it is currently considered a special case, where there are no reasonable alternatives available. As we’ve seen, that’s no longer true, and it’s not hard to predict the relevant regulations will soon be changed to reflect this development.

    In short, SF6 is yesterday’s technology; it’s served its purpose but now it’s obsolete. SF6 offers no technical or financial benefits – in fact quite the opposite – so let’s confine SF6 MV switchgear to the one place where it still belongs. And that, of course, is a museum!

  • Switchgear technology - Guidance on the application of BS EN 61439-2

    Standards such as BS EN 61439-2, while ultimately beneficial to electrical designers and industry overall, can sometimes be confusing to the uninitiated. Here Andy Evans technical executive at Gambica, reports on the Controlgear Group Technical Committee’s (CGTC) view on how the standard applies to those distribution boards known as ‘panel boards’

    Concerns have been raised as to whether the casing around a switching contact mechanism can constitute a Form 4 enclosure as defined in Annex NA of BS EN 61439-2 and thus achieve a particular standard of separation between functional units.

    Panel boards are a type of distribution board, commonly consisting of a number of outgoing moulded case circuit breakers (MCCBs) or fuse switches, connected to a common busbar which in turn is fed from a single incoming MCCB. The outgoing connection can come from the MCCB device itself or onto a set of outgoing terminals associated with each outgoer. The arrangements made for the outgoing connections are many and various and have a big influence on the final Form of Separation.

    The starting point for switchgear design is the assumption the equipment must be safe to use for anyone who will have access to it during its lifecycle. This includes the fitters, engineers, maintenance personnel and machine operators as well as other people who shouldn’t touch the equipment but conceivably could, such as passers-by.

    Annex NA to BS EN 61439-2 defines the performance criteria for an assembly to Form 4 as follows:

    Main Criteria
    Separation of busbars from functional units and separation of all functional units from one another, including the terminals for external conductors, which are an integral part of the functional unit.

    Sub Criteria, Form 4a (Types 1-3)
    Terminals for external conductors (are) in the same compartment as associated functional unit.

    Sub Criteria, Form 4b (Types 4 – 7)
    Terminals for external conductors (are) NOT in the same compartment as associated functional unit, but in individual separate, enclosed, protective spaces or compartments.
    In order to apply these definitions, one has to answer the question, ‘What constitutes a functional unit and how is the necessary separation, as defined in the criteria above, created?’

    The answer to this question is also provided in BS EN 61439-2, where a functional unit is defined as “A part of an assembly comprising all the electrical and mechanical elements that contribute to the fulfilment of the same function”.

    Although alternative interpretations are sometimes given, BS EN 61439-2 actually states that the integral housing of a device, for example a moulded case circuit breaker, is sufficient to satisfy the separation requirements as follows: 
    8.101 Internal separation of PSC-ASSEMBLIES (power switchgear and controlgear assemblies)

    Typical arrangements of internal separation by barriers or partitions are described in Table 104 and are classified as forms (for examples, see Annex AA).

    The form of separation and higher degrees of protection shall be the subject of an agreement between assembly manufacturer and user.

    PSC-assemblies can be divided to attain one or more of the following conditions between functional units, separate compartments or enclosed protected spaces:
    - protection against contact with hazardous parts. The degree of protection shall be at least IP XXB;
    - protection against the passage of solid foreign bodies. The degree of protection shall be at least IP 2X.

    Note: The degree of protection IP 2X covers the degree of protection IP XXB.
    Separation may be achieved by means of partitions or barriers (metallic or non-metallic), insulation of live parts or the integral housing of a device e.g. a moulded case circuit breaker.
    It should be noted the Form of Separation is one of the design aspects that is ‘subject to agreement between manufacturer and user’.

    So, to satisfy the main criteria for Form 4, one alternative is to merely use an MCCB which by definition has a moulded case enclosing the electrical and mechanical parts necessary for it to fulfil its function. In this case, the terminal compartment may also physically form one of the constructional elements of the MCCB device.

    To effect this arrangement, a means of shrouding the terminals and connected cable glands to ensure a minimum of IPXXB is necessary. Form 4 Type 5 indicates this may be done by use of insulated coverings. Forms 4 Type 6 and Type 7 require the separation via metallic or non-metallic rigid barriers or partitions.

    So, again, a suitably designed MCCB device can satisfy both the main criteria, for Form 4 and the sub-criteria for Form 4b, and depending on the materials used to form the termination chamber, can provide Form 4 Type 5 or 6 arrangements.

    One key issue to note is neutral (N) conductors, as they contribute to the fulfilment of the same function, form part of a particular functional unit and, in respect of Forms of Separation, must be treated as part of the functional unit. To this end, each outgoing way must have its own individual N connection, usually alongside the phase connections, and not be connected at a common N bar or terminal. 

    For four pole functional units, this is not normally an issue but in the case of a TP&N system, it’s a little more complicated. It is usual for a triple pole MCCB, for example, to have a separable neutral link mounted immediately adjacent to the MCCB to allow connection of all external cables in the same protected space, assuming adequate shrouding of all four terminals. For this arrangement to remain within the definitions of a functional unit and separation, multiple components should be logically arranged without gaps  so that they are readily seen as being within one space.

    A common N termination point arrangement cannot be deemed to be Form 4 as there is no separation of the terminals for external N connections for each functional unit in this case.

    There is no distinction in BS EN 61439-2 between a Form 4 declaration where MCCB enclosures are used to define separation of functional units in a single enclosure compartment and that employing MCCB devices mounted in separate compartments of a multi-compartment PSC- assembly. Both can be declared Form 4 separation and both meet the performance requirements for separation. However, separation is not the only criterion to be considered. Regardless of the form of separation employed or how it is achieved, all assemblies must meet all the other safety and performance criteria laid down in the standard, for example; short- circuit including emissions from devices, temperature rise, and protection against electric shock.

    BS EN 61439-2 gives only typical arrangements of internal separation; fundamentally the objectives of the separation and how it is achieved is a matter for agreement between the customer and the manufacturer. As a result, the customer should give careful consideration to the needs of his application, for example maintenance requirements.

    Gambica is the trade association for instrumentation, control, automation and laboratory technology in the UK. It has a membership of over 200 companies including major multinationals in the sector and a significant number of smaller and medium sized companies.

    It covers the following five principal sectors of the
    - Industrial automation products and systems  
    - Process measurement and control equipment and systems
    - Environmental analysis and monitoring equipment
    - Laboratory Technology
    - Test and measurement equipment for electrical and electronic industries

    Permission to reproduce extracts from BS EN 61439-2 is granted by BSI.  British Standards can be obtained in PDF or hard copy formats from the BSI online shop: www.bsigroup.com/Shop.

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