34 Questions And Answers To Break the Myth About SF6 Gas In Electrical Equipment

Miracle gas or not?

There are many published discussions and reports on various aspects of  SF6 gas (sulphur hexafluoride) usage in electrical equipment. Most of them are based on facts and researches, but some are not. Let’s try to answer the 34 questions and break the myth about this ‘miracle’ gas.

Note that most of answers are based on CAPIEL (Coordinating Committee for the Associations of Manufacturers of Industrial Electrical Switchgear and Controlgear in the European Union) researches and related IEC standards as well.

1. Where is SF6 used?

The following applications are known. For some of these most probably you haven’t heard of.

• For sound insulation in windows,
• In vehicle tyres,
• For magnesium casting in the automotive industry,
• As insulating and arc extinguishing medium in electric power equipment,
• For manufacturing of semi-conductors,
• In tandem-particle accelerators,
• In electron microscopes,
• As tracer-gas in mining,
• In x-ray material examination equipment,
• As purification and protection gas for aluminium and magnesium casting,
• In sport shoes,
• Medical examinations,
• In military aircraft radar systems and other military applications.

2. Is SF6 a health hazard?

Pure SF6 is physiologically completely harmless for humans and animals. It’s even used in medical diagnostic. Due to its weight it might displace the oxygen in the air, if large quantities are concentrating in deeper and non ventilated places.

3. Is SF6 harmful for the environment?

It has no ecotoxic potential, it does not deplete ozone. Due to its high global warming potential of 22.200 (*) it may contribute to the man made greenhouse-effect, if it is released into the atmosphere. However in electrical switchgear the SF6 gas is always used in gas-tight compartments, greatly minimising leakage. This make the real impact on greenhouse effect negligible.

_{(*) According to the 3rd Assessment Report of UNFCCC. Previous accepted value was 23.900}

4. What is the overall contribution of SF6 used in the electrical equipment to the greenhouse effect?

Less than 0,1 % ( see CAPIEL) and CIGRE). In an Ecofys study the contribution to the greenhouse effect in Europe is estimated to 0.05 % (*).

_{(*) ECOFYS, Sina Wartmann, Dr. Jochen Harnisch, June 2005, “Reductions of SF6 Emissions from High and Medium Voltage Equipment in Europe”}

5. How wide is the use of SF6 in transmission and distribution switchgear applications ?

SF6 insulated switchgear is currently used world-wide. It is estimated that an average of about 80 % of HV equipment manufactured now has an SF6 content.

6. Why is SF6 used in electric power equipment?

Because of its outstanding electrical, physical and chemical properties enabling significant benefits for the electricity supply network:

1. It insulates 2.5 times better than air (N₂),
2. Over 100 times better arc quenching capability than air (N₂), and
3. Better heat dissipation than air;

In addition to this, LCA studies have proven that the use of SF6 technology in the electrical distribution switchgear equipment results in lower overall direct and indirect environmental impacts compared to air-insulated switchyards (*)

_{(*) Solvay Germany, 1999: Urban power supply using SF6 technology, Life cycle assessment on behalf of ABB, PreussenElektra Netz, RWE Energie, Siemens, Solvay Fluor und Derivate}

7. What are the benefits of high and medium voltage SF6-switchgear?

There is a significant number of benefits, as follows:

Local operator safety

1. SF6-insulated switchgear makes a substantial contribution to reduce the accident risk.
2. The total enclosure of all live parts in earthed metal enclosures provides immanent protection against electric shock and minimises the risks associated with human errors
3. The high-grade switchgear remains hermetically sealed for its whole service life.

Very high operational reliability

1. It offers a great operational reliability because inside the enclosed gas compartments the primary conductors have complete protection against all external effects.
2. The minimal use of synthetics reduces the fire load.
3. The SF6 insulation ensures complete freedom from oxidation for the contacts and screwed joints, which means that there is no gradual reduction in the current carrying capacity of the equipment as it ages.
4. There is no reduction in insulation capacity due to external factors.

Important contribution to the security of supply

Total enclosure also means that the equipment is almost completely independent from the environment. SF6 insulated switchgear can also be used under difficult climatic conditions, for example:

1. In humid areas with frequent condensations from temperature changes, and even in places with flooding potential.
2. Where the reliability of the insulation might otherwise suffer from contamination, e.g. dust from industry or agriculture or saline deposits in coastal areas. Gas- insulated switchgear completely eliminates this possibility throughout the whole service life of an installation
3. In contrast to air insulation, whose insulating capacity reduces with increasing altitude, SF6-insulated switchgear retains its full insulating capacity regardless of height above sea level. So larger and more costly special designs, or equipment with higher insulation ratings – and therefore more costly – are avoided

Small space requirement

1. Due to the high dielectric strength of the gas, the switchgear is compact with space requirements minimised.
2. The excellent safety and low space requirement of SF6 switchgear allows it to be sited directly in conurbations and close to load centres, such as city centres, industrial manufacturing plants and commercial areas.
3. Therefore, this fulfils one of the basic essentials of power distribution, namely that substations should be placed as close as possible to load centres in order to keep transmission losses to a minimum, to conserve resources and to minimise costs.
4. Major savings in building, land and transport costs can be achieved throughout the whole process chain.
5. In several cases SF6 switchgear is the only possible solution: for wind power plants (offshore), in caverns, for large generator circuit-breakers, and for extensions of existing installations.
6. This often allows existing buildings use to be extended where switchgear replacement or extension to meet load growth is needed.

Excellent economical and ecological features

1. Distinct economic benefits come from:
   1. The long service life
   2. Minimal maintenance expenditure thanks to maintenance-free, gas-tight enclosures
   3. Reduced costs for land, buildings, transport and commissioning
      
   4. Maximum operational reliability as a prerequisite for the remote control and automation of power networks
2. Ecological and economic benefits arise from:
   
   1. Minimum transmission losses as a result of placing equipment close to load centres.
   2. Reduced primary energy consumption and emissions contribute to economically optimised power supply systems.
   3. And the long service life of SF6 switchgear also contributes to the conservation of resources.
3. Aesthetic and ecological benefits for rural and city landscapes:
   
   1. Because SF6 installations are compact, need minimum maintenance, have extraordinarily high availability and are independent from climatic impacts. They offer not only major ecological and economic advantages but can also be integrated seamlessly in any landscape or architecture of towns, cities or countryside
   2. Reclamation of areas previously taken up by conventional substations.

8. Is there any alternative to SF₆ in switchgear for high and medium voltage?

From the LCA point of view no technically and economically viable alternative exists with an equivalent set of properties described above and the same degree of safety and reliability.

”A combination of extraordinary electrical, physical, chemical and thermal properties makes SF₆ a unique and indispensable material in electric power equipment for which there is no functionally equivalent substitute.” (Quotation from a CIGRE3 Report) (*)

_{(*) CIGRE: International Council on Large Electric Systems}

9. What are the different applications in electrical power equipment using SF6?

These are the most common applications where SF6 is used:

1. GIS (Gas Insulated Switchgear for medium and high voltage),
2. CBs (Circuit Breaker),
3. Power transformers,
4. VT (Voltage Transformer),
5. CT (Current transformer),
6. RMU (Ring Main Unit),
7. Assemblies of HV devices and GIL (Gas insulated lines),
8. Capacitors etc.

10. What is the difference between high-voltage (HV) and medium- voltage (MV) GIS regarding SF6?

Basically there is no difference as both applications use the SF6 in gas-tight compartments with negligible leakage rates. In general the MV (up to 52 kV) use pressures close to atmospheric pressure in sealed pressure systems. Low pressure and small size result in little gas quantities of only some kg. The leakage rate is extremely low, less than 0.1 % per year.

11. What are the main commitments of the voluntary actions/agreements of manufacturers and users concerning SF6 handling?

Both, switchgear manufacturers and users are committed to a continuous improvement in reduction of emission rates as well as monitoring and annual reporting.

12. How is the effectiveness of voluntary actions verified?

The production processes of MV and HV switchgear in Western Europe have been improved so to reduce the specific emission rates of about 2/3 from1995 to 2003. Ecofys (*) determined for the same period an emission reduction of 40 %.

_{(*) ECOFYS, Sina Wartmann, Dr. Jochen Harnisch, June 2005, “Reductions of SF6 Emissions from High and Medium Voltage Equipment in Europe”}

13. What are the user’s obligations for monitoring SF6 data of medium voltage switchgear?

As far as sealed pressure systems (sealed for life) are concerned the users do not normally need to either monitor or report emissions.

Therefore they only have to assure that the disposal and the end of life is carried out by a qualified entity, in accordance with available national rules.

14. How is the proper end-of-life treatment of SF6-switchgear ensured?

Following internationally acknowledged instructions (i.e. according to IEC 601634, CIGRE 2003 SF6 Recycling Guide).

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15. What are the user’s obligations when taking SF6-switchgear out of service?

To make sure that the SF6 is handled by a qualified entity or by qualified personnel according to IEC 61634 subclause 4.3.1. and according to IEC 60480 subclause 10.3.1.

16. How is used SF6-gas treated or disposed?

It is normally re-used after proper filtering. In some special cases disposal of the gas is necessary.

17. In some European countries bans on SF6-switchgear have been proposed. Where are legal bans implemented?

There are no legal bans implemented. In political discussions reduced use of SF6 in some applications was proposed which are not related to the electrical industry.

In the past some proposals of this kind concerning electrical switchgear came up due to insufficient knowledge on how the electrical industry is using SF6. Once this was clarified and the benefits given by this technology were explained, the proposals were withdrawn.

18. Can we use vacuum as insulation medium?

Vacuum technology is already in use for switching purposes in the MV range. In the case of a small volume, a vacuum can be relatively easy maintained, which is essential to assure the performance of the switching device.

19. How can the user supervise the SF6 quality?

The sealed for life MV equipment does not require SF6 quality checks. For other HV equipment Annex B of IEC 60480 describes different methods of analysis applicable for closed pressure systems (on-site and in laboratory).

20. What about ageing process of SF6 gas? Is replenishment of gas needed after approximately 20 years?

It is generally not necessary because the gas quality than is in line with the values given in IEC 60480 Table 2 “Maximum acceptable impurity levels” (applicable for closed pressure systems). For MV sealed for life equipment no replenishment is necessary, because of the unique qualities of SF6 under normal operating conditions no degradation occurs.

21. How much SF6 (quantified in kg) can escape due to “normal” leakage?

This depends on the filling quantity, which depends on the rating and design of the equipment (volume and pressure). For HV switchgear the emission factor ranges from about 0.1% per year to 0,5% (0,5% per year is the maximum acceptable leakage rate according to IEC 62271-203)

For sealed for life MV equipment a range below 0,1 % per year is common. For example, a 3 kg filling quantity (RMU) results in a calculated loss of 3 g per year.

22. How high is the MAC (Maximum allowable working environment concentration) for pure SF6 in the substation and how hazardous is pure SF6?

It is generally recommended that the maximum concentration of SF6 in the working environment should be kept lower than 1000 μl/l (*). This is the value accepted for a full time (8 h/day, 5 day/week) work schedule. This value is not related to toxicity, but an established limit for all non-toxic gases which are not normally present in the atmosphere.

_{(*) TRGS 900, Technische Regeln für Gefahrstoffe}

23. What decomposition products are created in the case of internal arc faults, and in what quantities?

Gaseous and dusty by-products will be generated. See IEC 60480, Table 1 and/or CIGRE Report Electra 1991 (“Handling of SF6 and its decomposition products in GIS”, Table 2 “Rough characterisation of the major decomposition products resulting from different sources”).

The decomposition products depend on the type of equipment and its service history; the quantities depend on energy (voltage, current, time) and the type of the equipment.

24. How hazardous are the decomposition products?

See IEC 61634, Annex C: “Release of SF6 from switchgear and control gear – potential effects on health”.

25. What has to be done after an arc fault in the switchgear?

In such accidental cases caution must be taken. If the encapsulation has been damaged some compounds with toxic characteristics may be present, generated not only from decomposition of SF6 but also from other sources (e.g. burning paintings, vapours of copper, etc) can be present.

Therefore, in all cases, evacuation of the switchgear room is the first measure to be taken irrespective the switchgear contains SF6 or not. See IEC 61634 sub-clause 5.3: “Abnormal release due to internal fault”.

26. Does a (passive or active) ventilation system have to be installed in the switchgear room or cable basement?

Buildings containing SF6-filled indoor equipment should be provided with ventilation; natural ventilation would normally be adequate to prevent the accumulation of SF6 released due to leakage (see IEC 61634, sub-clause 3.4: “Safety of personnel” and IEC 61936-1). Type and extent of required measures depend upon location of the room, the accessibility, and the ratio of gas to room volume.

27. What do I have to do when a GIS installation is damaged?

For example hole drilled in encapsulation or transport damage such as a panel dropped and cast resin broken) and SF6 escapes or when my GIS develops an abnormal leak?

Appropriate corrective action should be to deal with the leakage. If the equipment is in service and the leakage is high, it must be de-energised, in accordance with the organisation’s operational procedures. Loss of gas must be minimised by following the organisation’s procedures and using the services/recommendations of the manufacturer or qualified service organisation as appropriate.

The technical integrity of the equipment will need to be verified after such an occurrence and appropriate corrective actions taken by authorised personnel before refilling of equipment or placing in service.

28. Under which conditions needs SF6 gas in gas-insulated switchgear to be replaced?

Which are the parameters to be checked e.g. (concentration, dew point, decomposition products) and what are the related acceptable limits?

Normally the gas remains until disassembly. During a maintenance operation requiring the evacuation of the gas, it should be analysed. Guidance on how to proceed then is given in IEC 60480.

29. How do I evacuate and fill the system?

See IEC 61634, CIGRE Report 2004 (“Practical SF6 handling instructions”). Please, refer also to the instruction manual of your equipment.

30. How much SF6 gas is in my switchgear? Where do I find this information?

On the nameplate or in the operating manual. For older equipment please ask your manufacturer.

31. Does SF6 have to be disposed of when moist?

No, it is possible to dry the gas; moisture can be reduced to acceptable levels by adsorption; material such as alumina, soda lime, molecular sieves or mixtures thereof are suitable for this purpose (see also IEC 61634, Annex B.3: “Measures for the removal of SF6 decomposition products”). Maximum tolerable moisture levels for re-use can be taken from IEC 60480, Annex A.

32. What do I have to do when I came in contact with decomposed SF6?

See IEC 61634, Annex E: “General safety recommendations, equipment for personal protection and first aid”. Normally only trained and qualified personnel should deal with this and hence be aware of the necessary precautions and actions.

33. What environmental and safety at work aspects have to be taken into account?

See IEC 61634 [8], clause 4: “Handling of used SF6″.

The need to handle used SF6 arises where:

1. Topping up of the SF6 in closed pressure systems is carried out;
2. The gas has to be removed from an enclosure to allow maintenance, repair or exten-sion to be carried out;
3. The gas has been wholly or partially expelled due to an abnormal release;
4. The gas has to be removed at the end of the life of an item of equipment;
5. Samples of the gas must be obtained or the gas pressure measured through tempo-rary connection of measuring apparatus.

Situations 1 and 1 arise mainly with respect to high-voltage equipment and may arise with medium-voltage GIS equipment in particular if it is required to add further equipment to an existing switchboard. They do not arise with equipment using sealed pressure systems.

34. What has to be observed for cleaning of the switchgear room after an internal fault with emission of decomposed gas?

See IEC 61634, sub-clause 5.3/5.3.3:

Abnormal release due to internal fault (Indoor installations”, and national requirements.)

An internal fault occurs when abnormal arcing is initiated inside a switchgear and controlgear enclosure.

In certain types of equipment, particularly metal-enclosed medium-voltage switchboards, air insulation is used for the busbars between cubicles and around cable connections and SF6 is present only within switching chambers. In this case an internal fault could occur within the switchboard but outside the switching chamber, so that no SF6 is released.

An internal fault is a very rare occurrence but cannot be completely disregarded.

Following an internal fault leading to pressure relief or enclosure burn-through, the SF6 and much of any solid decomposition products (powders) will have been expelled from the SF6 enclosure.

References:

• CAPIEL (Coordinating Committee for the Associations of Manufacturers of Industrial Electrical Switchgear and Controlgear in the European Union) – Frequently asked Questions (FAQ) and Answers on SF6
• IEC 61634 High-voltage switchgear and controlgear – Use and handling of sulphur hexafluoride (SF6) in high-voltage switchgear and controlgear
• IEC 60480 Guidelines for the checking and treatment of sulphur hexafluoride (SF6) taken from electrical equipment and specification for its re-use

The Consumer Power Substation With Metering On Medium Voltage Side (photo credit: alanya.tv)

Nominal voltage 1kV – 35kV

A consumer power substation with metering on medium voltage side is an electrical installation connected to a utility supply system at a nominal voltage usually between 1kV – 35kV, which for example may supply a single MV/LV transformer (exceeding generally 1250 kVA), several MV/LV transformers or one or several MV/LV secondary substations.

The single line diagram and the layout of a substation with MV metering depend on the complexity of the installation and the presence of secondary substations.

Functions of the substation with MV metering

1. Connection to the MV network
2. MV/LV Transformers and internal MV distribution
3. Metering
4. Local emergency generators
5. Capacitors
6. LV main switchboard
7. Simplified electrical network diagram

1. Connection to the MV network

Connection to the MV network can be made:

1. By a single service cable or overhead line,
2. By dual parallel feeders via two mechanically interlocked load-break switches
3. Via a ring main unit including two load-break switches.

SM6 medium voltage switchgear, Schneider Electric (photo credit: ezois.ru)

Go back to Index ↑

2. MV/LV Transformers and internal MV distribution

As well as for substation with LV metering, only oil-immersed and dry type cast-resin transformers are allowed with the same rules of installation. When the installation includes several MV/LV transformers and/or secondary MV/ LV substations an internal MV distribution network is required.

Trihal – Dry-type transformer 1600 kVA 10/0,42kV connected to busbar system Canalis KTA 2500A (Schneider Electric)

According to the required level of availability, the MV supplies to the transformers and the secondary substations may be made:

1. By simple radial feeders connected directly to the transformers or to the secondary substations
2. By one or several rings including the secondary MV/LV substations
3. By duplicate feeders supplying the secondary MV/LV substations.

For the two latter solutions the MV switchboard located in each secondary substation includes two load break switch functional units for the connection of the substation to the internal MV distribution and one transformer protection unit, for each transformer installed in the substation. The level of availability can be increased by using two transformers operating in parallel or arranged in dual configuration with an automatic change over system.

Go back to Index ↑

3. Metering

The characteristics and the location of the VT’s and CT’s dedicated to the metering shall comply with the utility requirements.

Medium voltage SM6 metering cubicle GBC (photo credit: schneider-electric.be)

The VT’s and CT’s are generally installed in the MV switchboard. A dedicated functional unit is in most of the cases required for the voltage transformers while the current transformers may be contained in the functional unit housing the circuit breaker ensuring the general protection of the substation.

Go back to Index ↑

4. Local emergency generators

Emergency standby generators are intended to maintain the power supply to the essential loads in the event of failure of the utility power supply. According to the energy needs an installation may contains one or several emergency generators.

The generators can be connected:

At MV level to the MV main substation (see Fig. B34).The generator(s) may be sized either for the supply of the whole installation or for a part only. In this case a load shedding system must be associated to the generator(s).

Figure B34 – Connection of emergency generators at MV level

At LV level on one or several LV switchboards requiring an emergency supply. At each location, the loads requiring an emergency supply may be grouped on a dedicated LV busbar supplied by a local generator (see Fig. B32).

Figure B32 – Emergency generator at LV LevelEmergency generator at LV Level

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5. Capacitors

Capacitors are intended to maintain the power factor of the installation at the contractual value specified by the utility. The capacitor banks can be fixed or adjustable by means of steps.

They can be connected:

• At MV level to the main MV substation
• At LV level on LV switchboards.

Capacitor banks panel (photo credit: schneider-electric.be)

Go back to Index ↑

6. LV main switchboard

Every MV/LV transformer is connected to a main LV switchboard complying with the requirements listed for substation with LV metering.

Main low voltage switchgear, type PRISMA P, Schneider Electric (photo credit: skaaret.as)

Go back to Index ↑

7. Simplified electrical network diagram

Figure B35 – Consumer substation with MV metering

The diagram (Fig. B35) shows:

• The methods of connection of a MV/LV substation to the utility supply:
  • Spur network or single-line service
  • Single line service with provision for future connection to a ring or to dual parallel feeders
  • Dual parallel feeders
  • Loop or ring-main service
• General protection at MV level
• MV metering functions
• Protection of MV circuits
• LV distribution switchboard

Go back to Index ↑

Reference: Electrical Installation Guide 2015 – Schneider Electric (Download)

Inspection, Test and Measurement Procedures for LV and MV (up to 36kV) Switchgears (on photo” Eaton Cutler Hammer Magnum DS Switchgear Inspection, and Transformer Testing)

Importance of checks and maintenance

Installed in clean, well ventilated or air-conditioned locations, switchgear will require little routine maintenance.

Major inspection should be scheduled for power plant shutdowns and concentrate for low voltage switchboards on identifying contact wear, correct operation of interlocks, correct overload settings and fuse sizes, signs of overheating, and undue dirt or corrosion. For MV switchgear similar considerations apply although more extensive checks on protective devices, circuit breaker oil, vacuum bottle contact distances are required as specified by the Manufacturer.

Gas Insulated Switchgear (GIS) shall be maintained in accordance with the manufacturer’s recommendations. Where extensive (intrusive) maintenance is required, the Manufacturer should be involved in the activity.

For older switchgear, a condition assessment should be performed to establish that the equipment remains in a suitable condition for further service.

Partial discharge testing and infrared scanning can be used to obtain data on the performance of the insulation system and the integrity of the switchgear busbars and cable terminations. The frequency of such tests will depend on the duty, age and condition of the switchgear.

Infrared partial discharge testing (photo credit: reliabilityweb.com)

NOTE //

The effectiveness of infra-red scanning depends on the ability to access the current-carrying components under loaded condition. Scanning through metallic enclosures has generally proved ineffective. Removal of enclosures of live equipment may not be possible without compromising electrical safety.

LV switchgear

NOTES:

1. Access to modern, high integrity, insulated/segregated busbar systems may be difficult. In this case other test and measurements as indicated should give sufficient information on the actual condition.
2. CT connected protection relays should be tested by means of secondary injection.
3. Testing of change-over systems of emergency switchboards should coincide with the testing of the emergency generator/system.
4. Type of protection ‘e’. Motor protection devices are selected so that the tripping time from hot when the locked rotor current of the motor is carried, is carried with the motor in the stalled condition, is less than the time tE on the motor nameplate.
5. Internal inspection should be limited to contactor/control equipment installed out of doors in boxes, e.g. MOV control panels.

MV switchgear (up to 36 kV)

NOTES:

1. Access to modern, high integrity, insulated/segregated busbar systems may be difficult. In this case other test and measurements as indicated should give sufficient information on the actual condition.
2. CT connected protection relays should be tested by means of secondary injection.
3. After operation of the circuit breaker/contactor following a short circuit, the proper operation of switching device and its protection shall be tested.
4. Type of protection ‘e’.
   Motor protection devices are selected so that the tripping time from hot when carrying the locked rotor current of the motor is carried, with the motor in the stalled condition, is less than the stated time tE on the motor nameplate.
5. Where used for tariff purposes.

Reference: Field commissioning and maintenance of electrical installations and equipment // DEP 63.10.08.11-Gen.

Ring Main Unit as an important part of Secondary Distribution Substations (on photo: ABB’a 24kV RMU type ‘SafeRing’)

RMU

A Ring Main Unit (RMU) is a totally sealed, gas-insulated compact switchgear unit. The primary switching devices can be either switch disconnectors or fused switch disconnectors or circuit breakers.

Different combinations of these primary switching devices within the unit are commonly used.

An example of distribution network with Ring Main Units (combinations of RMU units by Schneider Electric)

In case a circuit breaker is the switching device, it is also equipped with protective relaying, either with a very basic self-powered type or a more advanced one with communication capabilities.

The rated voltage and current ranges for RMUs typically reach up to 24 kV and 630 A respectively. With many of the manufacturers of RMUs, the basic construction of the unit remains the same for the whole of the voltage range.

The increase in rated voltage is handled by an increase in the insulating gas pressure.

Figure 1 – Single-line representation of a typical RMU configuration

The figure above shows a typical RMU configuration where load disconnectors are the switching devices for the incoming cable feeders and circuit breaker works as the switching device for distribution transformer feeder.

Three-position design // Closing, Opening and Earthing

All of the switching devices are of three-position design, having the possibility to close or open or earth the feeder in question.

All switches can be operated with the included operating handle

Closing

Closing the moving contact assembly is manipulated by means of a fast-acting operating mechanism. Outside these manipulations, no energy is stored. For the circuit breaker and the fuse-switch combination, the opening mechanism is charged in the same movement as the closing of the contacts.

Turn the operating handle clockwise to charge the close/open spring. Then push the green button. (A)

Opening

Opening of the switch is carried out using the same fast-acting mechanism, manipulated in the opposite direction. For the circuit breaker and fuse-switch combination, opening is actuated by:

• A pushbutton
• A fault.

Push the red button (B) to open fuse switch disconnector

Earthing

A specific operating shaft closes and opens the earthing contacts. The hole providing access to the shaft is blocked by a cover which can be opened if the switch or circuit breaker is open, and remains locked when it is closed.

Close earthing switch by turning operating handle clockwise

The figure below shows typical outlook of a three-feeder RMU. In the figure, the combination consists of load disconnectors for the incoming two feeders and a fused load disconnector for the distribution transformer feeder. The incoming and outgoing medium-voltage cables are attached using elbow-type plug-in cable ends.

Figure 2 – Outlook of a typical three-feeder 24 kV RMU unit (ABB’s SafeRing RMU)

Whereas the RMU type of units represents the very compact gas-insulated design for a dedicated purpose, the secondary medium-voltage switchgears represent an air-insulated, quite freely extendable and configurable solution.

References:

• Distribution Automation Handbook // Elements of power distribution systems – ABB
• RM6 Ring main Unit catalogue – Schneider Electric
• MV RMU SafeRing catalogue – ABB

Degradation of Insulation in Switchgear (why you should take it seriously); photo credit: Schneider Electric

Partial Discharge (PD)

Electrical insulation is subjected to electrical and mechanical stress, elevated temperature and temperature variations, and environmental conditions especially for outdoor applications. In addition to normal operating conditions, there are a host of other factors that may trigger accelerated aging or deterioration of insulation.

Both normal and accelerated aging of insulation produce the same phenomenon in common – Partial Discharge (PD).

Partial discharge activity on MV cables insulation (photo credit: eatechnology.com)

PD is a localized electrical discharge that does not completely bridge the electrodes. PD is a leading indicator of an insulation problem. Quickly accelerating PD activity can result in a complete insulation failure.

PD mechanism can be different depending on how and where the sparking occurs:

• Voids and cavities are filled with air in poorly cast current transformers, voltage transformers and epoxy spacers. Since air has lower permittivity than insulation material, an enhanced electric field forces the voids to flashover, causing PD. Energy dissipated during repetitive PD will carbonize and weaken the insulation.
• Contaminants or moisture on the insulation induce the electrical tracking or surface PD. Continuous tracking will grow into a complete surface flashover.
• Corona discharge from sharp edge of a HV conductor is another type of PD. It produces ozone that aggressively attacks insulation and also facilitates flashover during periods of overvoltage.

Features of partial discharge activity, such as intensity, maximum magnitude, pulse rate, long-term trend, are important indications of the insulation’s condition.

Healthy switchgear has very little or no PD activity. If PD activity is significant, it will eventually deteriorate insulation to a complete failure. Higher voltages produce higher intensity partial discharges, thus PD detection in gear with higher voltages (13.8 kV and up) is more critical.

Partial disharge on busbars

Photos above show damages resulting from partial discharge activity. Complete failure of the insulation in these examples can be prevented by partial discharge monitoring.

Usually in insulation, the deterioration process is relatively slow and the problem can be detected, located and fixed. Learn more about maintenance management of switchgear.

What is Partial Discharge? (VIDEO)

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Reference: Predictive Diagnostics for Switchgear – EATON

Sensors as alternative

As an alternative for traditional primary current and voltage measurement techniques, the use of sensor technique is gaining field. This technique is typically applied to current and voltage measurement in medium-voltage metal-enclosed indoor switchgears.

There are many undeniable advantages with sensors when compared to the traditional solutions:

• Non-saturable
• High degree of accuracy
• Personnel safety
• Extensive dynamic range
• Small physical size and weight
• Possibility to combine current and voltage measurement into one physical device with compact dimensions
• Environmental friendliness (less raw material needed)

The above statements are discussed in more detail in the following paragraphs while introducing the sensor techniques and the actual related apparatus. Let’s say a word about each type of sensor and some conclusion at the end:

1. Current sensors
2. Voltage sensors
3. Combined sensors
4. Conclusion and answer on why sensors are not 100% alternative

Current Sensors

The measurement of current is based on the Rogowski coil principle. The Rogowski coil is a toroidal coil without an iron core. The coil is placed around the current-carrying primary conductor. The output from the coil is a voltage signal, proportional to the derivative of the primary current.

The signal is then integrated in the secondary device to produce a signal proportional to the primary current wave form.

The open-circuited traditional current transformer produces dangerous voltages to the secondary side and lead to a serious overloading of the transformer. Since the output from the current sensor is a voltage signal, the open-circuited secondary conditions do not lead to a dangerous situation, neither to human beings nor apparatus.

The transmitted signal is a voltage:

U_out = M · di_p / d_t

For a sinusoidal current under steady state conditions the voltage is:

U_out = M · j · ω · I_p

With traditional current transformers, the ratio of the CT is fixed to one value, or in case of multi-ratio CTs, to several values. These values are chosen according to the specific application needs and load currents.

With a current sensor, the situation is simpler, since one type of sensor covers a range of primary currents and in optimum case the whole installation can be covered with one type only.

To give an idea of the secondary-voltage signal level, one fixed point (ratio) inside the rated current range could be 400 A primary value, typically corresponding to 150 mV secondary signal level.

The problems related to saturating iron core in conventional current transformers can be overcome with the sensor technology. The below figure demonstrates the difference between the secondary-signal performance for both traditional current transformer and current sensor.

Due to the compact size of a current sensor (no iron core), there are better possibilities to integrate the measurement devices inside other constructional parts of a metal-enclosed switchgear.

Go back to Types ↑

Voltage Sensors

The measurement of voltage is based on voltage divider. Two main types are available, namely the capacitive one and the resistive one. The output in both cases is a low-level voltage signal. The output is linear throughout the whole rated measurement range.

The considerations and protection methods against the ferroresonance phenomena, discussed with traditional voltage transformers, are not applicable with voltage sensors.

As with current sensors, also with voltage sensors it is possible to cover certain voltage range with one sensor type. To give an idea of the secondary voltage signal level, one fixed point (ratio) inside the rated voltage range could be 20000/√3V primary value, typically corresponding to 2/√3V secondary-signal level.

Go back to Types ↑

Combined Sensors

The sensor solution being quite compact and space saving, it is possible to combine both current and voltage sensors in one physical device. This device can be part of the switchgear’s mechanical basic construction, having other functions beside the measurement, like being a part of medium-voltage cable termination or busbar support construction.

These features give new possibilities to design switchgear constructions that are built according to specific customer needs and on the other hand they help the standardization work for the bulk type of switchgears.

Go back to Types ↑

Conclusion and comparison

The features of the sensor measurement technique compared to the traditional approach are shortly summarized in the figure below.

It could also be asked why the sensor approach has not totally taken over the traditional approach, at least when it comes to medium-voltage indoor switchgear. This is a very valid question and several answers could be given, depending on the viewpoint of the person answering.

Without going into this discussion any deeper, one valid argument is the limited selection of sensor-connectable secondary devices other than protection relays (IEDs).

Go back to Types ↑

Reference // Distribution Automation Handbook (prototype) – ABB

The post Current and voltage sensors as an alternative to traditional CTs and VTs appeared first on EEP - Electrical Engineering Portal.

Neutral point connection method

First, let’s define the different medium voltage earthing systems and then compare the advantages and disadvantages of each one. Earthing systems in medium voltage can be differentiated according to the neutral point connection method.

The various earthing systems in medium voltage systems are different in the way they operate and each has its advantagesand disadvantages, which we shall now consider.

1. Directly earthed neutral (Direct earthing)
2. Unearthed neutral
3. Resistance earthing
4. Reactance earthing
5. Petersen coil earthing

1. Directly earthed neutral (Direct earthing)

Description: An electrical connection is made between the neutral point and earth.

Operating technique: Compulsory switching on occurrence of the first insulation fault.

Advantages:

• Reduces the risk of overvoltages occurring.
• Authorizes the use of equipment with a normal phase to earth insulating level.

Disadvantages:

• Compulsory tripping upon occurrence of the first fault.
• Very high fault currents leading to maximum damage and disturbance (creation of induced currents in telecommunication networks and auxiliary circuits).
• The risk for personnel is high while the fault lasts; the touch voltages which develop being high.
• Requires the use of differential protection devices so that the fault clearance time is not long. These systems are costly.

Go back to Index ↑

2. Unearthed neutral

Description:

There is no electrical connection between the neutral point and earth, except for measuring or protective devices. A high impedance is inserted between the neutral point and earth.

Operating technique:

No switching on occurrence of the first insulation fault – it is thus compulsory:

• To carry out permanent insulation monitoring;
• To indicate the first insulation fault;
• To locate and clear the first insulation fault;
• To switch upon occurrence of the second insulation fault (double fault).

Advantages:

• Provides continuity of service by only tripping upon occurrence of the second fault, subject to the network capacity not leading to a high earth fault current that would be dangerous for personnel and loads on occurrence of the first fault.

Disadvantages:

The unearthed neutral involves:

• The use of equipment whose phase-to-earth insulation level is at least equal to that of the phase-to-phase level. Indeed, when a permanent phase-earth fault occurs, the voltage of both unaffected phases in relation to earth takes on the value of the phase-to-phase voltage if tripping is not triggered on occurrence of the first fault. Cables, rotating machines, transformers and loads must therefore be chosen with this in mind;
• The risk of high internal overvoltages making it advisable to reinforce the equipment insulation;
• The compulsory insulation monitoring, with visual and audible indication of the first fault if tripping is not triggered until the second fault occurs;
• The presence of maintenance personnel to monitor and locate the first fault during use;
• Some difficulties implementing selective protection devices upon occurrence of the first fault;
• The risk of ferroresonance.

Go back to Index ↑

3. Resistance earthing

Limiting resistance earthing

A resistor is inserted between the neutral point and earth.

Operating technique: Switching upon occurrence of the first fault.

Advantages:

• Limits fault currents (reduced damage and disturbance).
• Dampens overvoltages of internal origin in that the limiting current I_l is twice as high as the capacitive current I_C giving I_l > 2 I_C.
• Does not require the use of equipment, and in particular cables, having a special phase/earth insulation level.
• Allows the use of simple selective protection devices.

Disadvantages: Tripping on the first fault.

Go back to Index ↑

4. Reactance earthing

Limiting reactance earthing

Description: A reactor is inserted between the neutral point and earth.

Operating technique: Switching upon occurrence of the first insulation fault.

Advantages:

• Limits the fault currents (reduced damage and disturbance).
• Allows the implementation of simple selective protection devices if I_L >> I_C.
• The coil, being of low resistance, does not have to dissipate a high heat load.

Disadvantages:

• May cause high overvoltages during earth fault clearance.
• Compulsory tripping upon occurrence of the first fault.

Go back to Index ↑

5. Petersen coil earthing

Description:

A reactor L tuned to the network capacities is inserted between the neutral point and earth so that if an earth fault occurs, the fault current is zero.

I_f = I_L + I_C

Where:

• I_f – fault current
• I_L – current in the neutral earthing reactor
• I_C – current in the phase-earth capacitances

Operating technique: No switching upon occurrence of the first fault.

Advantages:

If the reactance is such that 3 L₀ C₀ ω₀ = 1 is respected, the phase-earth fault current is zero:

• Spontaneous clearance of non-permanent earth faults;
• The installation continues to operate in spite of there being a permanent fault, with tripping necessarily occurring on the second fault;
• The first fault is indicated by the detection of the current flowing through the coil. The coil is dimensioned so that permanent operation is possible.

Disadvantages:

• Difficulties establishing the condition 3 L₀ C₀ ω² = 1 due to uncertain knowledge of the network’s capacity: the result is that throughout the duration of the fault, a residual current circulates in the fault. Care must be taken to make sure this current is not dangerousfor personnel and equipment.
• The risk of overvoltages occurring is high.
• Requires the presence of monitoring personnel.
• Impossible to provide selective protection upon occurrence of the first fault if the coil has been tuned to: 3 L₀ C₀ ω² = 1
  If it is systematically out of tune (3 L₀ C₀ ω² ≠ 1) selective protection upon occurrence of the first fault is complex and costly.
• Risk of ferro-resonance.

Go back to Index ↑

Resource: Protection of Electrical Networks – Christophe Prévé (get this book from Amazon)

The post Medium Voltage Earthing Systems – Arrangements and Comparison appeared first on EEP - Electrical Engineering Portal.

Accessibility and service continuity

Some parts of a switchgear may be made accessible for the user, for various reasons from operation to maintenance, and such an access could impair the overall operation of the switchgear then decreasing the availability. The IEC 62271-200 proposes user-oriented definitions and classifications intended to describe how a given switchgear can be accessed, and what will be the consequences on the installation.

The manufacturer shall state which are the parts of the switchgear which can be accessed, if any, and how safety is ensured.

For that matter, compartments have to be defined, and some of them are going to be said accessible.

Three categories of accessible compartments are proposed:

1. Interlock based access: the interlocking features of the switchboard ensure that the opening is only possible under safe conditions
2. Procedure based access: the access is secured by means of, for instance, a padlock and the operator shall apply proper procedures to ensure a safe access
3. Tool based access: if any tool is needed to open a compartment, the operator shall be aware that no provision is made to ensure a safe opening, and that proper procedures shall be applied. This category is restricted to compartments where no normal operation nor maintenance is specified.

Several categories are defined, according to “the extent to which the switchgear and controlgear are intended to remain operational in case access to a high-voltage compartment is provided”:

• If any other functional unit than the one under intervention has to be switched off, then service is partial only: LSC1
• If at least one set of busbars can remain live, and all other functional units can stay in service, then service is optimal: LSC2
• If within a single functional unit, other(s) compartment(s) than the connection compartment is accessible, then suffix A or B can be used with classification LSC2 to distinguish whether the cables shall be dead or not when accessing this other compartment.

But is there a good reason for requesting access to a given function? That’s a key point.

Switchgear Examples (by Schneider Electric)

Example 1 – Ex Areva WI

Here is a GIS solution with in (D) what is said to be “Base section with cable connection area” (AREVA WI). There is no connection compartment, and the only HV compartments are gas filled.

Example 2 – CGset

Here is a GIS solution (Schneider Electric CGset) with an air insulated connection (and possibly VT) compartment. This compartment is accessible (with tools). The other HV compartments are not accessible. Access to the connection compartment is possible with the busbar(s) live, meaning all other functional units can be kept operating.

The LSC classification applies, and such solution is LSC2.

Example 3 – GMset

Here is a GIS solution (Schneider Electric GMset) with an air insulated connection (and possibly VT) compartment. This compartment is accessible and interlocked with the earthing function.

The circuit breaker can be extracted (tool access compartment), even if that is not considered as normal operation nor normal maintenance. Access to one functional unit within a switchboard does not require any other functional unit to be switched off. Such solution is LSC2A.

Example 4 – GenieEvo

A mixed technology (Schneider Electric GenieEvo) with an air insulated connection compartment, and an air insulated main switching device which can be extracted with the busbar live, thanks to the disconnector. Single line diagram is similar to example 2.

If both the connection compartment and the circuit breaker compartment are accessible, and access to any of them means the cables are first switched off and earthed.

Category is LSC2A.

Example 5 – MCset

A very classic structure of withdrawable air-insulated switchgear (Schneider Electric MCset), with interlock accessible compartments for the connections (and CTs) and the main switching device.

The LSC classification applies, and category is LSC2B.

Example 6 – SM6

A typical secondary distribution switch-disconnector switchgear, with only one interlock accessible compartment for the connection (Schneider Electric SM6).

When accessing one compartment within the switchboard, all other functional units are kept in service. Category is again LSC2. Similar situation occurs with most of the Ring Main Units solutions.

Example 7 – RM6

An unusual functional unit, available in some ranges: the metering unit which provides VTs and CTs on the busbar of an assembly (here a Schneider Electric RM6).

This functional unit is LSC1.

Reference // Medium Voltage technical guide – Schneider Electric (Download guide)

The post MV Metal-Enclosed Switchgear and Loss of Service Continuity (LSC) Categories appeared first on EEP - Electrical Engineering Portal.

Matching the MV circuit breaker to the task

Many years of experience in developing both SF6 and vacuum medium-voltage circuit breakers has yielded up ample evidence that neither of the two technologies is generally better than the other, and especially that they are complementary from the application point of view.

Typical of such special applications is the switching of //

1. Overhead lines and cables
2. Dry-type transformers
3. Small-size motors
4. Capacitors
5. Arc furnaces,
6. Shunt reactors and
7. Railway traction systems.

The need for ‘frequent switching’ or ‘soft switching’ can be an additional element influencing the choice. In such cases, a comprehensive study of the planned installation may be needed to find the best answer.

1. Overhead lines and cables

When applied to the onerous duty of switching and protecting overhead line distribution networks, in which the fault currents are distributed over the whole current range, both technologies provide adequate margins over and above the maximum required by the relevant standards and in normal service practice.

Go back to Special Applications ↑

2. Transformers

Modern vacuum MV circuit breakers as well as SF6 circuit breakers are suitable for switching the magnetizing currents of unloaded transformers with overvoltages lower than 3.0 pu. In special cases, for instance when vacuum circuit-breakers are used for switching dry-type transformers in industrial installations, the use of surge arresters is to be recommended.

Go back to Special Applications ↑

3. Small-Size Motors

When choosing MV circuit breaker for motor-switching duty, attention should be paid to the problems of overvoltages during operation.

The target limit for overvoltages of less than 2.5 pu is obtainable with both technologies. Where vacuum MV circuit breakers are used for switching small motors (starting currents less than 600 A), measures may be necessary to limit overvoltages due to multiple re-ignitions.

However, the probability of this phenomenon arising is low.

Go back to Special Applications ↑

4. Capacitor banks

Both technologies are suitable for restrike-free switching of capacitor banks. When capacitors must be switched back-to-back, reactors may be necessary to limit the inrush currents. The synchronous control of MV circuit breakers is an effective solution to this problem.

SF6 is specifically recommended for applications with rated voltages higher than 27 kV.

Go back to Special Applications ↑

5. Arc furnaces

Arc furnace switching is often characterized by frequent operation at high current values and short intervals. Vacuum circuit breakers are particularly suited to these service conditions.

Go back to Special Applications ↑

6. Shunt reactors

SF6 circuit breakers are suitable for switching with overvoltages generally lower than 2.5 pu. Where vacuum circuit breakers are employed, it may be necessary under certain circumstances to take additional measures to limit overvoltages.

Go back to Special Applications ↑

7. Railway traction

In principle, both interrupting technologies are well suited for this duty. However, in the case of low-frequency applications (eg, 16.67 Hz), vacuum circuit breakers are to be recommended.

Go back to Special Applications ↑

Reference // SF6 or Vacuum MV Circuit Breaker? – Guenter Leonhardt, Mauro Marchi, Giandomenico Rivetti at ABB (Download)

Distribution system protection //

Sectionalizers are (beside overcurrent relays, reclosers and fuses) one of the most used for distribution system protection.

A sectionalizer is a device that automatically isolates faulted sections of a distribution circuit once an upstream breaker or recloser has interrupted the fault current and is usually installed downstream of a recloser.

Sectionalisers count the number of operations of the recloser during fault conditions. After a preselected number of recloser openings, and while the recloser is open, the sectionalizer opens and isolates the faulty section of line. This permits the recloser to close and re-establish supplies to those areas free of faults. If the fault is temporary, the operating mechanism of the sectionalizer is reset.

Sectionalizers are constructed in single- or three-phase arrangements with hydraulic or electronic operating mechanisms.

IMPORTANT // A sectionalizer does not have a current/time operating characteristic and can be used between two protective devices whose operating curves are very close and where an additional step in coordination is not practicable.

Hydraulic operating mechanisms

Sectionalizers with hydraulic operating mechanisms have an operating coil in series with the line. Each time an overcurrent occurs, the coil drives a piston that activates a counting mechanism when the circuit is opened and the current is zero by the displacement of oil across the chambers of the sectionalizer.

After a pre-arranged number of circuit openings, the sectionalizer contacts are opened by means of pre-tensioned springs. This type of sectionalizer can be closed manually.

Electronic operating mechanisms

Sectionalizers with electronic operating mechanisms are more flexible in operation and easier to set. The load current is measured by means of CTs, and the secondary current is fed to a control circuit that counts the number of operations of the recloser or the associated interrupter and then sends a tripping signal to the opening mechanism.

This type of sectionalizer is constructed with manual or motor closing.

Factors to consider //

The following four factors should be considered when (technically) selecting a sectionalizer:

1. System voltage,
2. Maximum load current,
3. Maximum short-circuit level, and
4. Coordination with protection devices installed upstream and downstream.

The nominal voltage and current of a sectionalizer should be equal to or greater than the maximum values of voltage or load at the point of installation.

The short-circuit capacity (momentary rating) of a sectionalizer should be equal to or greater than the fault level at the point of installation. The maximum clearance time of the associated interrupter should not be permitted to exceed the short-circuit rating of the sectionalizer.

Coordination factors that need to be taken into account include the starting current setting and the number of operations of the associated interrupter before opening.

Sectionalizer with surge arrester protection //

References //

• Protection of Electricity Distribution Networks – Juan M. Gers and Edward J. Holmes (Purchase from Amazon)
• ABB AutoLink resettable electronic sectionalizers

MV/LV transformer grounding philosophy //

Let’s discuss in some detail the reasons for the grounding philosophy adopted for pole-mounted MV/LV transformer substations illustrated in Figure 0.

• LV grounding
• MV grounding
• Combined MV/LV grounding
• Separate MV/LV grounding
  • MV electrode
  • LV electrode
• Pole transformer basics (VIDEO)

LV grounding

The purpose of LV system grounding is as follows:

• To maintain the LV neutral potential to as close to earth potential as possible thereby prospective touch voltages in all the grounded metal parts of equipment
• To provide a low-impedance return path for any LV ground faults
• To ensure operation of MV protection in the event of an inter-winding fault (MV and LV) within the transformer.

Go back to Grounding Analysis ↑

MV grounding

The surge arrestors of MV lines are connected to the transformer tank, which in turn is grounded through the MV, ground electrode. This limits the voltage between the tank and the lines to the voltage drop across the arrestors in the event of a surge.

Go back to Grounding Analysis ↑

Combined MV/LV grounding

Though it is theoretically possible to have a combined ground at the transformer for both MV and LV, such a practice may lead to unsafe conditions in the event of an MV to LV fault. Figure 1 shows the reason.

The total impedance for a fault between HV and MV winding (neglecting the line impedance and the leakage impedance of the transformer windings) is the substation ground mat resistance of 10 Ω, the NGR (neutral grounding resistance) value and the MV/LV combined ground electrode resistance assumed as 1 Ω.

This gives a figure of 276 A. This current will cause the potential of 276 V to appear on the transformer tank and through the neutral lead to the enclosures of all equipment connected in the LV system with respect to true earth potential (this is because in TN-C-S type of systems, which we saw in the last chapter, the neutral and equipment ground are one and the same).

This value is unacceptably high. In actual practice, the line and transformer impedances come into play and the value will therefore get restricted to safe values. Use of combined MV and LV grounding is therefore possible only if the ground resistance can be maintained below 1 Ω.

Go back to Grounding Analysis ↑

Separate MV/LV grounding

MV electrode

In view of the difficulty of maintaining a very low combined ground resistance arrived at above, the code allows the use of a separate ground for the LV neutral away from the transformer. The only point of connection between the LV system and the transformer tank is the LV neutral surge arrestor whose grounding lead is connected to the transformer tank (refer Figure 2 below).

The problem with this connection is that a fault within the transformer (MV winding to core fault) resulting in rise of voltage can cause a high enough voltage to ground causing the neutral surge arrestor to fail and communicate the high voltage into the LV system.

Assuming a maximum LV voltage of 5000 V for withstand of neural surge arrestors, the voltage rise across the MV ground electrode resistance should not be greater than this value.

For 11 kV system, a value of 100 Ωis permissible. The limit for the electrode resistance should also consider the ground fault current so that the MV ground fault relay can operate reliably to isolate the fault. A value of 30 Ωis taken as the limit for ground electrode systems for all MV systems. Standard configurations are available in the code for 30 Ω electrodes and can be used in the design.

Go back to Grounding Analysis ↑

LV electrode

The LV electrode resistance should be normally expected to permit sufficient fault currents for detection. Since with the LV line to neutral voltage of 240 V, the resistance limit works out to 2.4 Ωif a ground fault current of 100 A is to be obtained.

However, with the TN-C-S type of system, all equipment enclosures are directly connected to the neutral at the service inlet itself and thus the current flow does not involve the ground path at all.

So, the limit of LV grounding resistance is decided by the criteria of obtaining sufficient fault current when there is an MV to LV fault without involving the tank or core (refer Figure 3).

Assuming an MV earth fault protection setting of 40 A, the ground loop resistance can be arrived at 318 Ω (12 700/40) for 22 kV system. The permissible ground electrode resistance works out to 273 Ω (after taking off the values of NGR (neutral grounding resistance) and substation ground resistance).

If we consider a safety factor of 400%, the maximum value of LV ground resistance can be taken as 68 Ω. The safety factor will ensure that the seasonal changes of soil resistivity will have no adverse effect on protection operation. Standard configurations are available in the code for 70 Ω electrodes and can be used in the design.

Go back to Grounding Analysis ↑

Pole Transformer (VIDEO)

Very basic, points out components and discusses current flow.

Go back to Grounding Analysis ↑

Reference: Practical Grounding, Bonding, Shielding and Surge Protection G. Vijayaraghavan, Mark Brown and Malcolm Barnes (Buy hardcopy from Amazon)

MV switchboard supply solutions //

Medium voltage networks are made up of switchboards and the connections feeding them. Let’s take a look at the eight different supply modes of these medium voltage switchboards. We’ll start with the main power supply solutions of an MV switchboard, regardless of its place in the network.

NOTE // The number of sources and the complexity of the switchboard differ according to the level of power supply security required.

8 most common power supply modes //

1. 1 busbar, 1 supply source
2. 1 busbar with no coupler, 2 supply sources
3. 2 bus sections with coupler, 2 supply sources
4. 1 busbar with no coupler, 3 supply sources
5. 3 bus sections with couplers, 3 supply sources
6. 2 busbars, 2 connections per outgoing feeder, 2 supply sources
7. 2 interconnected double busbars
8. “Duplex” distribution system

I – 1 busbar, 1 supply source

Operation // If the supply source is lost, the busbar is put out of service until the fault is repaired.

Go back to Power Supply Modes ↑

II – 1 busbar with no coupler, 2 supply sources

Operation // One source feeds the busbar, the other provides a back-up supply. If a fault occurs on the busbar (or maintenance is carried out on it), the outgoing feeders are no longer fed.

Go back to Power Supply Modes ↑

III – 2 bus sections with coupler, 2 supply sources

Operation // Each source feeds one bus section. The bus coupler circuit-breaker can be kept closed or open. If one source is lost, the coupler circuit-breaker is closed and the other source feeds both bus sections.

If a fault occurs in a bus section (or maintenance is carried out on it), only one part of the outgoing feeders is no longer fed.

Go back to Power Supply Modes ↑

IV – 1 busbar with no coupler, 3 supply sources

Operation // The power supply is normally provided by two parallel-connected sources. If one of these two sources is lost, the third provides a back-up supply. If a fault occurs on the busbar (or maintenance is carried out on it), the outgoing feeders are no longer fed.

Go back to Power Supply Modes ↑

V – 3 bus sections with couplers, 3 supply sources

Operation // Both bus coupler circuit-breakers can be kept open or closed. Each supply source feeds its own bus section. If one source is lost, the associated coupler circuit-breaker is closed, one source feeds two bus sections and the other feeds one bus section.

If a fault occurs on one bus section (or if maintenance is carried out on it), only one part of the outgoing feeders is no longer fed.

Go back to Power Supply Modes ↑

VI – 2 busbars, 2 connections per outgoing feeder, 2 supply sources

Operation // Each outgoing feeder can be fed by one or other of the busbars, depending on the state of the isolators which are associated with it, and only one isolator per outgoing feeder must be closed.

If one source is lost, the other source takes over the total power supply. If a fault occurs on a busbar (or maintenance is carried out on it), the coupler circuit-breaker is opened and the other busbar feeds all the outgoing feeders.

Go back to Power Supply Modes ↑

VII – 2 interconnected double busbars

Operation // This arrangement is almost identical to the previous one (two busbars, two connections per feeder, two supply sources). The splitting up of the double busbars into two switchboards with coupler (via CB1 and CB2) provides greater operating flexibility.

Each busbar feeds a smaller number of feeders during normal operation.

Go back to Power Supply Modes ↑

VIII – “Duplex” distribution system

Operation // Each source can feed one or other of the busbars via its two drawout circuit-breaker cubicles. For economic reasons, there is only one circuit-breaker for the two drawout cubicles, which are installed alongside one another. It is thus easy to move the circuit-breaker from one cubicle to the other.

Thus, if source 1 is to feed busbar BB2, the circuit-breaker is moved into the other cubicle associated with source 1.

The same principle is used for the outgoing feeders. Thus, there are two drawout cubicles and only one circuit-breaker associated with each outgoing feeder. Each outgoing feeder can be fed by one or other of the busbars depending on where the circuit-breaker is positioned.

If one source is lost, the other source provides the total power supply. If maintenance is carried out on one of the busbars, the coupler circuit-breaker is opened and each circuit-breaker is placed on the busbar in service, so that all the outgoing feeders are fed. If a fault occurs on a busbar, it is put out of service.

Go back to Power Supply Modes ↑

Reference // Protection of Electrical Network – Christophe Prévé

Electrical system on board //

Without going into the details of the management modalities of the electric distribution or of the layout that an electrical system on board may have, it is possible to describe it in short, however giving the possibility to understand its structure and complexity.

In the power plants on board of big ships, or however in the most modern ships, such as for example line cruisers, the generation of electric energy occurs in the power station on board, which, in some cases, can be divided into two parts, one placed astern and the other at the bow.

Medium voltage distribution (see Figure 1 below) starts from the main switchboard which consists of two sections, each of them connected to one gen-set.

These bars are usually connected through a bus-tie which allows the power to be handled according to the specific needs, always with the point of view of keeping, even if reduced, such an efficiency that a good degree of safety and stability is ensured for the ship.

The medium voltage main busbar system or some distribution sub-switchboards deliver power, directly or through control devices (e.g. electronic converters) to:

1. Essential high power loads (e.g. the propellers or the thrusters for transverse motion);
2. Big power motors, for example for air-conditioning or for the typical functions linked to particular vessel typology;
3. Various substations in the service areas intended to supply LV power to all the power loads, small power loads or lights provided for that area.

Therefore, the secondary power supply of the LV switchboards starts from the substations, through MV/ LV transformers. These switchboards often offer the possibility of having redundant supply coming from other MV switchboards supplied in turn by the other half-busbar of the main MV switchboard.

From the LV switchboards a complex distribution network (see Figure 2) is originated and it supplies the different types of LV loads on board, such as the rudder, the winches or the essential auxiliaries of the motor and, moreover, the lightning plant, the entertaining, comfort and performance facilities, as well as the accommodation structures with kitchens and laundries.

The power plant must always guarantee service continuity; therefore, switchboards with two incoming feeders de- riving from other separate switchboards are provided.

In case of fault, putting out of service, as fast as possible, only the load involved or the section affected by the breakdown is important, thus realizing high selectivity for all the loads.

In the previous paragraph, the MV generation voltage values have already been mentioned. Instead, as regards the distribution levels of the LV plant, till some years ago the standard value was 440V.

This has implied some advantages, such as:

• Partial reduction of the fault current values,
• Reduction of the cross sectional areas of the cables and consequently of weights and overall dimensions,
• Reduction of voltage drops and bigger admissible lengths of cables and an increase in the power of the motors which can be directly connected to the primary network and generally of all the loads of the Main Switchboard.

Low voltage final distribution is carried out at lower voltages (400V/230V), obtained through LV/LV transformers. The frequencies most commonly used are 50Hz or 60Hz according to different aspects, such as for example the type of naval construction and the country of origin.

For special loads, or more simply in the military eld, dedicated circuits are required in the presence of 400Hz.

Typically, the direct current has voltage values of 48V, 110V or 125V are maintained for those particular circuits, for example, where devices for battery recharging or for automation auxiliary circuits are provided.

Redundant supply //

As already said, also the lack of supply for the fundamental utilities must be avoided for safety on board. Therefore the distribution system shall provide for the possibility of a redundant supply.

For example dividing the MV main busbar, which closes if needed, so that the power supply to the electric propulsion engines is ensured in order not to jeopardize the ship maneuver-ability, or for LV switchboards to provide the possibility of a double supply deriving from other switchboards, or also through adequate designing of the emergency power station.

Electrical power plants on board are typically in alternating current since they result to guarantee a better management in terms of costs and reliability in comparison with direct current ones.

Will be continued soon…

Reference // Generalities on naval systems and installations on board – ABB

Continued from the first part Power plants on board of big ships – LV/MV ditribution

MV primary distribution network

The MV primary distribution network generally consists in a three-phase system with three conductors without neutral. Such system is usually managed with the neutral of the star point isolated from earth or connected with earth through a resistance or a Petersen coil, thus allowing a reduction in the values of leakage and short-circuit currents. In this way, a first fault with insulation loss does not represent a hazard and allows the system to be maintained in service without the intervention of the protection.

Obviously the fault must be signaled and standard service conditions must be immediately restored so that it can be avoided that the first fault turns into a double fault to earth, which is extremely dangerous in IT systems.

Once, when onboard installations were not very wide and the powers involved quite small, the secondary distribution system consisted in a single-phase network with two insulated conductors or three conductors with the medium point of the transformer connected to earth.

Generally, the secondary distribution network is radially distributed with the possibility of double switchboard supply through two different lines, thus realizing the reserve connection to the load. The choice of using one type or the other depends on the plant conditions and it is carried out either by means of a switch or of interlocked circuit-breakers.

• Radial power distribution
• Compound radial distribution
• Power distribution with ring circuit
• High-Voltage Shore Connection (HVSC)

Radial power distribution

MV main distribution networks have a different structure according to the type of ship and to the installed power. They can be of simple radial type with substations or sub-switchboards.

The simple radial diagram (see Figure 1) includes a main switchboard with a single busbar, from which the output feeders for all the LV power consumers start. This con guration results to be particularly critical since a fault on the main switchboard may jeopardize the reliability of the services on board.

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Compound radial distribution

The compound radial diagram (see Figure 2) is fitter than the previous one for the realization of medium power plants and comprises a main switchboard with one or more main busbars and some sub-switchboards, which provide solely for the power supply delivery from the main switchboard to the distribution switchboards differently placed.

With this configuration there is a remarkable reduction in the number of the circuits derived from the main switchboard and therefore of the devices installed in the switchboard.

Instead, as regards the service continuity of the users derived from different distribution sub-switchboards, a remarkable importance is represented by the correct sizing of the chain of circuit-breakers positioned at the different levels of the distribution system so that it is possible to obtain the tripping of the circuit-breaker affected by the fault only, thus guaranteeing power supply for the other loads and sub-switchboards.

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Power distribution with ring circuit

To ensure power supply continuity, the radial system is often structured with a reserve ring (Figure 3) intended for the supply of the substations having the main line interrupted, or even the whole substation group in case of a serious fault on the semi-busbar of the main switch- board usually supplying them.

In this case, which is to be considered very heavy and hard, only half the generators results to be available and consequently half the energy power installed. The ring shall be sized to provide for the needs of the plant foreseen for this operation situation, which, as it is evident, is of extreme emergency.

The plant on board may be divided into three main parts, represented by:

1. Main plant

The main plant, consisting of the essential services of the ship, such as the propulsion or the circuits intended for priority functions on board, each of them characteristic of the ship typology (e.g. the circuits intended for gas pumping or compression for a gas carrier, or the circuits intend for the control of the devices for load handling on shipping containers).

2. Auxiliary circuits //

The auxiliary circuits which include power production and distribution systems for lightening and auxiliary motive force;

3. Special installations //

The special installations for which a particular technology has been developed:

• Telephone installations,
• Electronics devices for different uses,
• Telegraphs,
• Torquemeters,
• Integrated navigation systems,
• Fire warning devices.

Another main difference concerns the distinction which can be made between essential and non-essential loads, which influence the distribution system which supplies them.

The first ones are those for which supply and proper operation are to be guaranteed also under emergency conditions, since they carry out functions indispensable to the safety of the vessel. Among them, first of all the propulsion system, the control systems of motors, helms and stabilizer paddles, the re-prevention systems, the alarms, the communication and auxiliary systems for navigation, the emergency lightening.

The electrical system, in compliance with the Naval Regisisters’ rules, provide also an emergency electrical station positioned in another area with respect to the power station on board, usually on one of the high decks and however over the waterline. The power station consists of an autonomous LV diesel-generator set (440V or 690V), in the order of some MW.

The diesel engine under consideration shall be able to start also when the main network cannot deliver energy and this is usually obtained by means of a connection to the UPS system. A set of capacitors is present to guarantee energy availability also during the starting time of the emergency generator. Under standard operating conditions, that is in the presence of voltage on the mains, a rectifier shall have the task of delivering to the capacitor banks the energy necessary to keep the maximum charge.

In case of malfunctioning of the main station, an automatic control sequence provides for switching to the emergency switchboard the power delivery of the part of the plant to which the priority loads, which must work also in emergency case, are connected (e.g. emergency lightning, re pumps, steering devices and auxiliary equipment indispensable for the machinery systems, communication and signaling networks and other circuits).

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High-Voltage Shore Connection (HVSC)

Besides, due to environmental constraints, in harbors ships must turn their diesel engines off thus interrupting electric generation. Then they must connect to the on-shore grid, normally to a LV source, or in the most modern solutions to a MV tap made available in the port.

This procedure, defined High-Voltage Shore Connection (HVSC) finds favor with the harbor management authorities worldwide, allows for a reduction in the polluting emissions of ships at berth, improving air quality in the port areas and in the surrounding ones.

HVSC technology (Figure 4) allows power supply directly from the wharf to the vessel to ensure operation of the machinery systems and installations on board (refrigerators, illumination, heating and air-conditioning) and allow the diesel engines normally used to supply electrical generators on board to be turned off.

This operation in parallel, which is necessary for onboard electrical power supply must not cause problems of power quality to the onshore distribution grid.

To give an idea of the environmental impact, a big line cruiser at berth for 10 hours, if using onshore power supply, avoids burning of up to 20 metric tons of fuel, which is equivalent to 60 metric tons of carbon dioxide not emitted into the atmosphere, which is the annual emission of 25 cars.

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Reference // Generalities on naval systems and installations on board – ABB