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Steps to Ensure Effective Substation Grounding (photo by Peak Power Engineering, Inc.)

Continued from previous article: Steps to Ensure Effective Substation Grounding (1)

Ensuring Proper Grounding

In previous technical article (part 1) was explained first five steps that will ensure a reliable, safe and trouble-free substation grounding system. Here we will explain the last six steps:

Size conductors for anticipated faults (previous part 1)
Use the right connections (previous part 1)
Ground rod selection (previous part 1)
Soil preparation (previous part 1)
Attention to step and touch potentials (previous part 1)
Grounding using building foundations
Grounding the substation fence
Special attention to operating points
Surge arrestors must be grounded properly
Grounding of cable trays
Temporary grounding of normally energized parts

6. Grounding Using Building Foundations

The concrete operation to Building control foundation

Concrete foundations below ground level provide an excellent means of obtaining a low-resistance ground electrode system. Since concrete has a resistivity of about 30 Ωm at 20 °C, a rod embedded within a concrete encasement gives a very low electrode resistance compared to most rods buried in the ground directly.

Since buildings are usually constructed using steel-reinforced concrete, it is possible to use the reinforcement rod as the conductor of the electrode by ensuring that an electrical connection can be established with the main rebar of each foundation.

The size of the rebar as well as the bonding between the bars of different concrete members must be done so as to ensure that ground fault currents can be handled without excessive heating.

Such heating may cause weakening and eventual failure of the concrete member itself. Alternatively, copper rods embedded within concrete can also be used.

The use of ‘Ufer’ grounds (named after the person who was instrumental in the development of this type of grounding practice) has significantly increased in recent years. Ufer grounds utilize the concrete foundation of a structure plus building steel as a grounding electrode.

Even if the anchor bolts are not directly connected to the reinforcing bars (rebar), their close proximity and the conductive nature of concrete will provide an electrical path.

There are a couple of issues to be considered while planning for grounding using the foundations as electrodes. A high fault current (lightning surge or heavy ground fault) can cause moisture in the concrete to evaporate suddenly to steam.

This steam, whose volume is about 1800 times of its original volume when existing as liquid, produces forces that may crack or otherwise damage the concrete. The other factor has to do with ground leakage currents. The presence of even a small amount of DC current will cause corrosion of the rebar. Because corroded steel swells to about twice its original volume, it can cause extremely large forces within the concrete.

Although AC leakage will not cause corrosion, the earth will rectify a small percentage of the AC to DC. In situations where the anchor bolts are not bonded to the rebar, concrete can disintegrate in the current path.

Damage to concrete can be minimized either by limiting the duration of fault current flow (by suitable sensitive and fast acting protective devices) or by providing a metallic path from the rebar through the concrete to an external electrode.

That external electrode must be sized and connected to protect the concrete’s integrity. Proper design of Ufer grounds provides for connections between all steel members in the foundation and one or more metallic paths to an external ground rod or main ground grid.

Excellent joining products are available in the market, which are especially designed for joining rebars throughout the construction. By proper joining of the rebars, exceptionally good performance can be achieved.

An extremely low resistance path to earth for lightning and earth fault currents is ensured as the mass of the building keeps the foundation in good contact with the soil.

Go to Grounding Steps ↑

7. Grounding the Substation Fence

The second most common substation hazard is lack of grounding (photo from IAEI Magazine)

Metallic fences of substations should be considered just as other substation structures.

The reason for this is that the overhead HV lines entering or leaving a substation may snap and fall on the fence. Unless the fence is integrated with the rest of the substation grounding system, a dangerous situation may develop. Persons or livestock in contact with the fence may receive dangerous electric shocks.

Utilities vary in their fence-grounding specifications, with most specifying that each gate post and corner post, plus every second or third line post, be grounded. All gates should be bonded to the gate posts using flexible jumpers. All gate posts should be interconnected. In the gate swing area, an equipotential wire mesh safety mat can further reduce hazards from step and touch potentials when opening or closing the gate.

It is recommended that the fence ground should be tied into the main ground grid, as it will reduce both grid resistance and grid voltage rise. Internal and perimeter gradients must be kept within safe limits because the fence is also atfull potential rise.

This can be accomplished by extending the mesh with a buried perimeter conductor that is about 1 m outside the fence and bonding the fence and the conductor together at close intervals (so that a person or grazing animal touching the fence will stand on the equipotential surface so created).

Go to Grounding Steps ↑

8. Special Attention to Operating Points

To protect the operator in case of a fault, it should be ensured that he is not subjected to high touch or step potentials when a fault happens in the equipment he is operating.

This calls for use of a safety mesh close to these operating points on which the operator will stand and operate the equipment.

There are four types of safety mats.

1. A steel grate or plate on supporting insulators. This works only if the operator can be kept completely isolated on the grate. Therefore, insulators must be kept clean.

Any vegetation in the vicinity should be cut or eliminated completely (this approach is similar to the insulating rubber mats placed in front of most indoor electrical equipment). Safety is ensured by increasing the resistance of current path, so that the current flowing through the operator’s body into the ground does not exceed safe values.

2. A steel grate on the surface, permanently attached to the grounded structure. This arrangement has the operator standing directly on the grate.

3. Bare conductor buried (in a coil or zig-zag pattern) under the handle area and bonded to the grounded structure.

4. Prefabricated equipotential wire mesh safety mat buried under the handle area and bonded to the grounded structure. This is likely to be the least expensive choice.

In all but the first arrangement, both the switch operating handle and the personnel safety grate (or mat) should be exothermically weldedto structural steel, thus ensuring nearly zero voltage drop.

Go to Grounding Steps ↑

9. Surge Arrestors Must be Grounded Properly!

When there is a surge in the electrical system (by indirect lightning strikes or due to switching) surge arrestors placed near all critical equipment divert surge energy to ground and protect the equipment from being subjected to the surges.

Usually, surges involve a very fast rise time during which the current changes from zero to extremely high values of several kiloamperes. It is therefore necessary that the conducting path from the grounding terminal of the surge arrestor to the earth must have minimum impedance.

Even a small amount of self-inductance offered by a grounding conductor will mean very high impedance because of the steep wavefront of the surge and very high voltages from appearing in the grounding system (albeit briefly). To dissipate the surge current with minimum voltage drop, each surge arrestor ground lead should have a short direct path to earth and should be free of sharp bends (bends act like a coil and increase the inductance).

Often surge arrestors are mounted directly on the tank of transformers, close to the HV terminal bushings. In these cases, the transformer tanks and related structures act as the grounding path.

It must be ensured that multiple and secure paths to ground are available (this includes making effective connections).

Whenever there is any question about the adequacy of these paths, it is recommended to use a separate copper conductor between the arrestor and the ground terminal (or main grounding grid). Since steel structures (due to their multiple members) have lower impedance than a single copper conductor, the grounding conductors should preferably be interconnected to the structure near the arrestor.

Go to Grounding Steps ↑

10. Grounding of Cable Trays

Overhead cable trays and ladder racks grounded

Overhead cable trays and ladder racks are jumpered and grounded with AWG #2 bare copper. These conductors, along with the cable bus that collects ground leads from individual cabinets, are connected to the nearest wall-mounted collector bar.

The NEC vide Art. 318 specifies the requirements for cable trays and their use in reducing the induced voltages during a ground fault. All metallic tray sections must be bonded together with proper conducting interconnections. The mechanical splice plates by themselves may not provide an adequate and a reliable ground path for fault currents.

Therefore, the bonding jumpers (either the welded type used on steel trays or the lug type) must be placed across each spliced tray joint.

If a metallic tray comes with a continuous grounding conductor, the conductor can be bonded inside or outside the tray.

When cable tray covers are used, they should be bonded to the tray with a flexible conductor. The trays should also be bonded to the building steel (usually at every other column).

Go to Grounding Steps ↑

11. Temporary Grounding of Normally Energized Parts

Temporary grounding of normally energized parts with ground rod and earth wire clamp

When personnel work on high-voltage electric structures or equipment, any conductive bodies should be grounded as a measure of safety.

This is done so that in the event of the circuit becoming live due to inadvertent switching, the safety of personnel (in contact with the parts, which would become live) is ensured.

The usual grounding method is to attach a flexible insulated copper cable with a ground clamp or lug on each end. These flexible jumpers require periodic inspection and maintenance. For cable connections to clamps, welded terminations (either a welded plain stud or a threaded silicon bronze stud welded to the conductor end) will provide a secure, permanent connection.

The clamp or lug is solidly connected to ground, then the other clamp is attached to the cable being grounded.

Go to Grounding Steps ↑

Resource: Practical Grounding, Bonding, Shielding and Surge Protection – G. Vijayaraghavan; Mark Brown; Malcolm Barnes
(Get this book at Amazon)

Arrangements of LV Utility Distribution Networks (photo credit to abbmvit.blogspot.com)

Introduction

In European countries the standard 3-phase 4-wire distribution voltage level is 230/400 V. Many countries are currently converting their LV systems to the latest IEC standard of 230/400 V nominal (IEC 60038).

Medium to large-sized towns and cities have underground cable distribution systems.

MV/LV distribution substations, mutually spaced at approximately 500-600 metres, are typically equipped with:

A 3-or 4-way MV switchboard, often made up of incoming and outgoing load-break switches forming part of a ring main, and one or two MV circuit-breakers or combined fuse/ load-break switches for the transformer circuits
One or two 1,000 kVA MV/LV transformers
One or two (coupled) 6-or 8-way LV 3-phase 4-wire distribution fuse boards, or moulded-case circuit-breaker boards, control and protect outgoing 4-core distribution cables, generally referred to as “distributors”

The output from a transformer is connected to the LV busbars via a load-break switch, or simply through isolating links. In densely-loaded areas, a standard size of distributor is laid to form a network, with (generally) one cable along each pavement and 4-way link boxes located in manholes at street corners, where two cables cross.

Recent trends are towards weather-proof cabinets above ground level, either against a wall, or where possible, flush-mounted in the wall. Links are inserted in such a way that distributors form radial circuits from the substation with open-ended branches (see Fig. C3).

Where a link box unites a distributor from one substation with that from a neighbouring substation, the phase links are omitted or replaced by fuses, but the neutral link remains in place.

Fig. C3 : Showing one of several ways in which a LV distribution network may be arranged for radial branched-distributor operation, by removing (phase) links

This arrangement provides a very flexible system in which a complete substation can be taken out of service, while the area normally supplied from it is fed from link boxes of the surrounding substations.

Moreover, short lengths of distributor (between two link boxes) can be isolated for fault-location and repair. Where the load density requires it, the substations are more closely spaced, and transformers up to 1,500 kVA are sometimes necessary.

Other forms of urban LV network, based on free-standing LV distribution pillars, placed above ground at strategic points in the network, are widely used in areas of lower load density. This scheme exploits the principle of tapered radial distributors in which the distribution cable conductor size is reduced as the number of consumers downstream diminish with distance from the substation.

In this scheme a number of large-sectioned LV radial feeders from the distribution board in the substation supply the busbars of a distribution pillar, from which smaller distributors supply consumers immediately surrounding the pillar.

Distribution in market towns, villages and rural areas generally has, for many years, been based on bare copper conductors supported on wooden, concrete or steel poles, and supplied from pole-mounted or ground-mounted transformers.

In recent years, LV insulated conductors, twisted to form a two-core or 4-core self supporting cable for overhead use, have been developed, and are considered to be safer and visually more acceptable than bare copper lines. This is particularly so when the conductors are fixed to walls (e.g. under-eaves wiring) where they are hardly noticeable.

Improved methods using insulated twisted conductors to form a pole mounted aerial cable are now standard practice in many countriesAs a matter of interest, similar principles have been applied at higher voltages, and self supporting “bundled” insulated conductors for MV overhead installations are now available for operation at 24 kV. Where more than one substation supplies a village, arrangements are made at poles on which the LV lines from different substations meet, to interconnect corresponding phases.

North and Central American practice differs fundamentally from that in Europe, in that LV networks are practically nonexistent, and 3-phase supplies to premises in residential areas are rare.

The distribution is effectively carried out at medium voltage in a way, which again differs from standard European practices.

The MV system is, in fact, a 3-phase 4-wire system from which single-phase distribution networks (phase and neutral conductors) supply numerous single-phase transformers, the secondary windings of which are centre-tapped to produce 120/240 V single-phase 3-wire supplies.

In Europe, each utility-supply distribution substation is able to supply at LV an area corresponding to a radius of approximately 300 metres from the substation. North and Central American systems of distribution consist of a MV network from which numerous (small) MV/LV transformers each supply one or several consumers, by direct service cable (or line) from the transformer location

The central conductors provide the LV neutrals, which, together with the MV neutral conductors, are solidly earthed at intervals along their lengths. Each MV/LV transformer normally supplies one or several premises directly from the transformer position by radial service cable(s) or by overhead line(s).

Many other systems exist in these countries, but the one described appears to be the most common. Figure C4 (in next part…) shows the main features of the two systems.

Will be continued…

Resource: Electrical Installation Guide 2009 – Schneider Electric

Arrangements of LV Utility Distribution Networks (photo by Steve Ives @ Flickr: Street in Haddington, Philadelphia, PA, US)

Continued from the previous part: Arrangements of LV Utility Distribution Networks (1)

The consumer-service connection

In the past, an underground cable service or the wall-mounted insulated conductors from an overhead line service, invariably terminated inside the consumer’s premises, where the cable-end sealing box, the utility fuses (inaccessible to the consumer) and meters were installed.

A more recent trend is (as far as possible) to locate these service components in a weatherproof housing outside the building.

Fig. C4: Widely-used American and European-type systems

Note: At primary voltages greater than 72.5 kV in bulk-supply substations, it is common practice in some European countries to use an earthed-star primary winding and a delta secondary winding. The neutral point on the secondaryside is then provided by a zigzag earthing reactor,the star point of which is connected to earth through a resistor.

Frequently, the earthing reactor has a secondary winding to provide LV3-phase supplies for the substation. It is then referred to as an “earthing transformer”.

A MCCB - moulded case circuit breaker which incorporates a sensitive residual-current earth-fault protective feature is mandatory at the origin of any LV installation forming part of a TT earthing system.

The utility/consumer interface is often at the outgoing terminals of the meter(s) or, in some cases, at the outgoing terminals of the installation main circuit-breaker (depending on local practices) to which connection is made by utility staff, following a satisfactory test and inspection of the installation.

A typical arrangement is shown in Figure C5.

Fig. C5: Typical service arrangement for TT-earthed systems

A further reason for this MCCB is that the consumer cannot exceed his (contractual) declared maximum load, since the overload trip setting, which is sealed by the supply authority, will cut off supply above the declared value. Closing and tripping of the MCCB is freely available to the consumer, so that if the MCCB is inadvertently tripped on overload, or due to an appliance fault, supplies can be quickly restored following correction of the anomaly.

In view of the inconvenience to both the meter reader and consumer, the location of meters is nowadays generally outside the premises, either:

In a free-standing pillar-type housing as shown in Figures C6 and C7
In a space inside a building, but with cable termination and supply authority’s fuses located in a flush-mounted weatherproof cabinet accessible from the public way, as shown in Figure C8
For private residential consumers, the equipment shown in the cabinet in.

Fig. C6 : Typical rural-type installation

In this kind of installation it is often necessary to place the main installation circuit-breaker some distance from the point of utilization, e.g. saw-mills, pumping stations, etc.

Fig. C7: Semi-urban installations (shopping precincts, etc.)

The main installation CB is located in the consumer’s premises in cases where it is set to trip if the declared kVA load demand is exceeded.

Fig. C8: Town centre installations

The service cable terminates in a flushmounted wall cabinet which contains the isolating fuse links, accessible from the public way. This method is preferred for esthetic reasons, when the consumer can provide a suitable metering and main-switch location.

Fig. C9: Typical LV service arrangement for residential consumers

Figure C5 is installed in a weatherproof cabinet mounted vertically on a metal frame in the front garden, or flush mounted in the boundary wall, and accessible to authorized personnel from the pavement.

Figure C9 shows the general arrangement, in which removable fuse links provide the means of isolation.

In the field of electronic metering, techniques have developed which make their use attractive by utilities either for electricity metering and for billing purposes, the liberalisation of the electricity market having increased the needs for more data collection to be returned from the meters.

For example electronic metering can also help utilities to understand their customers’ consumption profiles.

In the same way, they will be useful for more and more power line communication and radio-frequency applications as well.

In this area, prepayment systems are also more and more employed when economically justified. They are based on the fact that for instance consumers having made their payment at vending stations, generate tokens to pass the information concerning this payment on to the meters. For these systems the key issues are security and inter-operability which seem to have been addressed successfully now.

The attractiveness of these systems is due to the fact they not only replace the meters but also the billing systems, the reading of meters and the administration of the revenue collection.

Resource: Electrical Installation Guide 2009 – Schneider Electric

Testing and Commissioning of Substation DC System (on photo: The battery assembly rated at 108V 200AH, 55 Tungstone Plante Cells all fitted with Aquagen catalytic recombination fillers, which effectively reduce topping up to less than once a year.- by prepair.co.uk)

Objective

Power substation DC system consists of battery charger and battery. This is to verify the condition of battery and battery charger and commissioning of them.

Test Instruments Required

Following instruments will be used for testing:

Multimeter. (Learn how to use it)
Battery loading unit (Torkel-720 (Programma Make) or equivalent.
The Torkel-720is capable of providing a constant current load to the battery under test.
Torkel 720 Battery Load Capacity Tester Front View

Commissionig Test Procedure

1. Battery Charger

Visual Inspection: The battery charger cleanliness to be verified. Proper cable termination of incoming AC cable and the outgoing DC cable and the cable connection between battery and charger to be ensured. A stable incoming AC supply to the battery charger is also to be ensured.
Voltage levels in the Float charge mode and the Boost charge mode to be set according to specifications using potentiometer provided.
Battery low voltage, Mains ‘Off”, charger ‘Off’ etc., conditions are simulated and checked for proper alarm / indication. Thus functional correctness of the battery charger is ensued.
Charger put in Commissioning mode for duration specified only one time during initial commissioning of the batteries. (By means of enabling switch.)
Battery charger put in fast charging boost mode and battery set boost charged for the duration specified by the battery manufacturer.
After the boost charging duration, the battery charger is to be put in float charging (trickle charge) mode for continuous operation.
Some chargers automatically switch to float charge mode after the charging current reduces below a certain value.
Voltage and current values are recorded during the boost charging and float-charging mode.

NiCad Batteries being charged

This test establishes the correct operation of the battery charger within the specified voltage and current levels in various operational modes.

Calculate size of battery bank and inverter – Get MS Excel Spreadsheet!

2. Battery Unit

Mandatory Condition: The battery set should have been properly charged as per the commissioning instructions of the battery manufacturer for the duration specified.
Visual Inspection: Cleanliness of battery is checked and the electrolyte level checked as specified on the individual cells. The tightness of cell connections on individual terminals should be ensured.
The load current, minimum voltage of battery system, ampere-hour, duration etc., is preset in the test equipment using the keypad.
For (e.g.) a 58 AH battery set, 5 Hr. duration specification 11.6 A and 5 Hr. duration are set. Minimum voltage setting is = No. of cells x end cell voltage of cells as per manufacturer specification.
It is to be ensured that the set value of the current and duration is within the discharge capacity of the type of cell used. Also the total power to be dissipated in the load unit should be within the power rating of the battery load kit.
Individual cell voltages to be recorded before the start of the test.
Battery charger to be switched off/load MCB in charger to be switched off.
Loading of the battery to be started at the specified current value.
Individual cell voltages of the battery set are to be recorded every half an hour.
It is to be ensured that all the cell voltages are above the end-cell voltage specified by the manufacturer.
If any of the cell voltages falls below the threshold level specified by the manufacturer, this cell number is to be noted and the cell needs to be replaced.
Test set automatically stops loading after set duration (or) when minimum voltage reached for the battery set.
Test to be continued until the battery delivers the total AH capacity it is designed for.
Value of AH and individual cell voltages to be recorded every half an hour.

Acceptance Limits

This test establishes the AH capacity of battery set at required voltage.

The acceptance limit for the test is to ensure the battery set is capable of supplying the required current at specified DC voltage without breakdown for the required duration.

Resource: Procedures for Testing and Commissioning of Electrical Equipment – Schnedeider Electric

Substations and Distribution Substations Overview (Photo by Ipco Group)

Introduction

High voltage substations are interconnection points within the power transmission and distribution systems between regions and countries.

Different applications of substations lead to high voltage substations with and without power transformers:

Step up from a generator voltage level to a high voltage system (MV/HV)
- Power plants (in load centers)
- Renewable power plants (e.g., windfarms)
Transform voltage levels within the high voltage system (HV/HV)
Step down to medium voltage level of a distribution system (HV/MV)
Interconnection in the same voltage level

Scope

High voltage substations comprise not only the high voltage equipment which is relevant for the functionality in the power supply system.

High voltage substations are planned and constructed comprising high voltage switchgear, medium voltage switchgear, major components such as high voltage equipment and transformers, as well as all ancillary equipment such as auxiliaries, control systems, protective equipment and so on, on a turnkey basis or even as general contractor.

The installations supplied worldwide range from basic substations with a single busbar to interconnection substations with multiple busbars, or a breaker–and–half arrangement for rated voltages up to 800 kV, rated currents up to 8,000A.

A and short circuit currents up to 100 kA.

Circuit configuration

High Voltage Substation

High voltage substations are points in the power system where power can be pooled from generating sources, distributed and transformed, and delivered to the load points.

Substations are interconnected with each other, so that the power system becomes a meshed network.
This increases the reliability of the power supply system by providing alternate paths for flow of power to take care of any contingency, so that power delivery to the loads is maintained and the generators do not face any outage.

The high voltage substation is critical component in the power system, and the reliability of the power system depends upon the substation. Therefore, the circuit configuration of the high voltage substation has to be selected carefully.

Busbars are the part of the substation where all the power is concentrated from the incoming feeders, and distributed to the outgoing feeders. That means that the reliability of any high voltage substation depends on the reliability of the busbars present in the power system.

An outage of any busbar can have dramatic effects on the power system.

An outage of a busbar leads to the outage of the transmission lines connected to it.

As a result, the power flow shifts to the surviving healthy lines that are now carrying more power than they are capable of. This leads to tripping of these lines, and the cascading effect goes on until there is a blackout or similar situation.

The importance of busbar reliability should be kept in mind when taking a look at the different busbar systems that are prevalent.

Protective measures

The protective measures can be categorized as personal protection and functional protection of the substations.

Personal protection

Protective measures against direct contact, i.e., through appropriate covering, obstruction, through sufficient clearance appropriate positioned protective devices, and minimum height
Protective measures against indirect touching by means of relevant earthing measures in accordance with IEC 61936/DIN VDE 0101 or other required standards
Protective measures during work on equipment, i.e., installation must be planned so that the specifications of DIN EN 50110 (VDE 0105) (e.g., five safety rules) are observed.

Functional protection

Protective measures during operation, e.g., use of switchgear interlocking equipment
Protective measures against voltage surges and lightning strikes
Protective measures against fire, water and, if applicable, noise

Stresses

Electrical stresses, e.g., rated current, short circuit current, adequate creepage distances and clearances
Mechanical stresses (normal stressing), e.g., weight, static and dynamic loads, ice, wind
Mechanical stresses (exceptional stresses), e.g., weight and constant loads in simultaneous combination with maximum switching forces or short circuit forces, etc.
Special stresses, e.g., caused by installation altitudes of more than 1,000 m above sea level, or by earthquakes

Arrangement and modules

High Voltage Substation Elements (photo from Idec Group)

Arrangement

The system is off the enclosed 1-phase or 3-phase type.

The assembly consists of completely separate pressurized sections, and is thus designed to minimize any danger to the operating staff and risk of damage to adjacent sections, even if there should be trouble with the equipment.

Rupture diaphragms are provided to prevent the enclosures from bursting discs in an uncontrolled manner. Suitable deflectors provide protection for the operating personnel.

For maximum operating reliability, internal relief devises are not installed, because these would affect adjacent compartments.

The modular design, complete segregation, arc-proof bushing and plug-in connections allow speedy removal and replacement of any section with only minimal effects on the remaining pressurized switchgear.

Busbars

All busbars of the enclosed 3-phase or the 1-phase type are connected with plug from the one bay to the next.

Circuit breakers

ABB - High voltage dead-tank circuit breaker 362 kV, max. 63 kA 362PMI

The circuit breakers operate according to the dynamic self-compression principle. The number of interrupting units per phase depends on the circuit breaker’s performance. The arcing chambers and the circuit breaker contacts are freely accessibly.

The circuit breaker is suitable for out-of-phase switching and designed to minimize overvoltages. The specified arc interruption performance has to be consistent across the entire operating range, from line-charging currents to full short circuit currents.

The circuit breaker is designed to withstand at least 10 operations (depending on the voltage levels) at full short circuit rating.

Opening the circuit breaker for service or maintenance is not necessary. The maximum tolerance for phase displacement is 3ms, that is, the time between the first and the last pole’s opening or closing.

A standard station battery that is required for control and tripping may also be used for recharging the operating mechanism.

The drive and the energy storage system are provided by a stored energy spring mechanism that holds sufficient energy for all standard IEC close-open duty cycles.

The control system provides alarms signals and internal interlocks but inhibits tripping or closing of the circuit breaker when the energy capacity in the energy storage system is insufficient or the SF6 density within the circuit breaker drops below the minimum permissible level.

Disconnectors

Transmission line disconnect switch (photo by Efrem Oshinsky @ Flickr)

All disconectors (isolators) are of the single-break type.

DC motor operation (110, 125, 220 or 250 V) which is fully suited to remote operation, and a manual emergency operating mechanism are provided. Each motor operating mechanism is self-contained and equipped with auxiliary switches in addition to the mechanical indicators.

The bearings are lubricated for life.

Earthing switches

High voltage outdoor earthing switch (126kV, 252kV) - Chint Electric Co.,Ltd.

Work-in progress earthing switches are generally provided on either side of the circuit breaker. Additional earthing switches may be used to earth busbar sections or other groups of the assembly.

DC motor operation (110, 125, 220 or 250 V) that is fully suited for remote operation and a manual emergency operating mechanism are provided. Each motor operating mechanism is self-contained and equipped with auxiliary position switches in addition to the mechanical indicators. The bearings are lubricated for life. Make proof high-speed earthing switches are generally installed at the cable and overhead line terminals.

They are equipped with a rapid closing mechanism to provide short circuit making capacity.

Instrument transformers

SF6 gas insulated high-voltage current transformer (72.5 - 800 KV) - Trench Group

Current transformers (CTs) are of the dry type design. Epoxy resin is not used for insulation purposes. Voltage transformers are of the inductive type, with ratings up to 200 VA.

Cable terminations

1-phase or 3-phase, SF6 gas insulated, metal enclosed cable end housing are provided. The cable manufacturer has to supply the stress cone and suitable sealings to prevent oil or gas from leaking into the SF6 switchgear.

The cable end housing is suitable for oil type, gas-pressure type cables with plastic insulation (PE, PVC, etc.).

Additionally, devices for safety isolating a feeder cable and connecting a high voltage test cable to the switchgear or cable will be provided.

Overhead line terminations

The terminations for connecting overhead lines come complete with SF6-to-air bushings but without line clamps.

Control and monitoring

As a standard, an electromechanical or solid-state interlocking control board is supplied for each switchgear bay. This fault-tolerant interlocking system prevents all operating malfunctions.

Mimic diagrams and position indicators provide the operating personnel with clear operating instructions. Provisions for remote control are included. Gas compartments are constantly monitored by density monitors that provide alarm and blocking signals via contacts.

To be continued…

References:

- SIEMENS Substations Guide
- Andreas Goutis, ‘Electrical drawing, Part 1’

High Voltage Substations Overview (part 2)

Continued from first part: High Voltage Substations Overview (part 1)

Distribution Substations

Transformers are used for the transformation of high and medium voltage to low voltage, flanked by specific protective devices and control systems, which constitute the low voltage distribution substations.

A distribution substation, is characterized by the apparent power of the transformer and whether it is aerial, terrestrial or underground.

The indoor substations (terrestrial or underground), are manufactured in specific areas to ensure waterproofing and adequate ventilation. Among the equipment of high and low voltage, special protective grids (cells) shall be inserted and the transformer is protected by a special cover.

The arrival and departure of electric lines may be:

Aerial (with bare conductors) or
Underground (with reinforced cables)

A distribution substation, usually includes: disconnect switches, circuit breakers, lightning arresters, provisions limiting the short circuit current, monitoring, measuring and recording instruments (power, current and potential transformers), SCADA etc.

The following example refers to a terrestrial distribution station:

1. Floor plan and incision of a terrestrial distribution substation

Floor plan of a terrestrial distribution substation

Incision of a terrestrial distribution substation

2. Single line schematic arrangement

Single line schematic arrangement of power substation

3. Analytical (three-pole) schematic diagram

Analytical (three-pole) schematic diagram of distributive power substation

High Voltage Substation At Rockville Indiana (VIDEO)

Cant see this video? Click here to watch it on Youtube.

References:

- SIEMENS Substations Guide
- Andreas Goutis, ‘Electrical drawing, Part 1’

Things you should know about MV GIS (Medium Voltage Gas Insulated Switchgear) - photo by ormazabal.com

Content

Introduction to GIS (Gas Insulated Switchgear)

Medium voltage (5-38 kV) gas insulated switchgear (GIS) differs greatly from the medium voltage AIS – Air insulated switchgear commonly used in North America Instead of using air and solid insulation materials, GIS switchgear has the vacuum interrupter and bare bus conductors in a sealed housing filled with an insulating gas.

1. Environmental Concerns

The insulating gas used in MV GIS switchgear, sulfur hexaﬂuoride (SF6), is a highly potent greenhouse gas with a global warming potential 23,900 times greater than CO2. SF6 also has an atmospheric life of 3,200 years, so it will contribute to global warming for a very long time.

One pound of SF₆ has the global warming equivalent of 11 tons of CO₂.

(Source: EPA website www.epa.gov/electricpower-sf6)

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2. Safety Concerns

In its normal state, SF6 gas is:

Colorless,
Odorless,
Non-flammable, and
Non-toxic to humans.

However, under high temperature conditions (> 350 degrees F), SF6 decomposes into products that are toxic and corrosive. Decomposition by-products can occur when SF6 is exposed to spark discharges, partial discharges, switching arcs and failure arcing.

These byproducts, in the form of gases or powders, can cause the following conditions in humans:

irritation to the eyes, nose, and throat,
pulmonary edema and
other lung damage, skin and eye burns, nasal congestion, bronchitis;
powders may cause rashes.

(Source: EPA website www.epa.gov/electricpower-sf6)

ANSI certiﬁcation results in equipment that meets rigorous U.S. operating requirements. GIS equipment is not tested to these standards, and deﬁnitely is not tested to IEEE guide for testing metal-enclosed switchgear for internal arcing faults. IEC 62271-200 – Metal enclosed MV switchgear, accepts internal arc tests to be performed with air instead of SF6, for environmental reasons.

However, it should be noted that the test results may differ if the tests were done with SF6.

When a dielectric failure occurs in a GIS, the arc generally will not be extinguished by the SF6, and could lead to internal pressure build up and cause holes in metal walls due to concentrated buming of the arc. GIS manufacturers just state that the GIS equipment is “inherently” arc resistant, but in reality an arc can very well live within the GIS.

Also it is well known that all SF6 containments leak, therefore, the chances of having an issue with GIS is more prevalent than ever having an arc issue within non arc resistant switchgear.

Utilizing other solutions, such as designs that use complete single pole solid insulation, partial discharge sensors for insulation diagnostics, and remote racking for safety, the non arc resistant solution easily exceeds the safety of GIS.

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3. Special Handling Procedures

Due to the safety concems, special handling procedures are recommended for heavily arced SF6 including the use of personal protective equipment (PPE – i.e., respiratory device, protective clothing such as rubber gloves, footwear, goggles) for removal/handling of solid SF6 byproducts.

Contaminated SF6 gas must either be filtered on-site using special mobile equipment or removed for off-site filtering or destruction using trained personnel.

(Source: EPA website www.epagovlelectricpower-sf6)

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4. Installation Concerns

The most signiﬁcant installation issues involve the need for proper alignment. The foundation must be level and in a single plane to allow for proper assembly of the shipping sections. The foundation height can only vary by 1 mm per meter, with a maximum deviation of 2 mm over the full length of the assembly.

After installation of the GIS shipping groups, equipment must be sealed and SF6 is filled at site.

To maintain dielectric withstand levels, special cable termination is required in GIS. The design also limits number of cables/phase that can be installed in a given circuit.

Another issue is power cable connections are not accessible without disassembling the switchgear.

(Source: IEEE Transaction on Industry Applications, Vol. 40. No. 5, September! October 2004 and Eaton experience.)

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5. Operation and Maintenance Concerns

Because SF6 gas provides insulation of internal components, draw out circuit breaker designs are not possible. Most local codes require that the design of equipment incorporate a means to visually verify the isolating function of disconnect devices.

In the GIS switchgear, this requires a means to visually verify the position of the three-position switch. To meet this requirement, some manufacturers install miniature video cameras, and associated lighting, both mounted external to the SF6 gas enclosure.

The video leads are brought to the front panel of the switchgear, and a monitoring device is provided to view the position of the switch.

Cant see this video? Click here to watch it on Youtube.

(Source: IEEE Transaction on Industry Applications, Vol. 40, No. 5, September I October 2004)

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6. End of Life and Recycling Concerns

Used SF6 gas must be recovered by trained professionals, then stored and transported in US Department of Transportation (DOT) approved cylinders for the final recycle process. DOT regulations require equipment containing SF6 gas at pressures greater than 25 psig at 68° F to be certiﬁed to transport compressed gas.

DOT regulations require cylinders of SF6 gas with a gross weight greater than 220 lbs. It must include a shipping paper. Recyclers equipped to handle metals exposed to SF6 gas should process the remaining metal parts of the switchgear.

(Source: EPRI Guidelines for Safe Handling of SF6, DOT CFR 49 Chapter l Subchapter C)

GIS differs greatly from traditional MV Metal Clad switchgear widely used in North America. A view of one pole of a typical unit of GIS switchgear is shown in Figure 1.

Figure 1 - Typical circuit breaker unit in GIS - Gas insulated Switchgear

1 – Cast aluminium housing
2 – Main bus bars with sliding supports
3 – Three-position selector switch
4 – Gas tight bushing
5 – Vacuum interrupter
6 – Toroidal current transformer
7 – Capacitive voltage transformer
8 – Shock-proof (safe-to-touch) cable termination (not shown)

As in air insulated Metal Clad switchgear, vacuum circuit breakers are used for interruption.

MV GIS switchgear differs from high-voltage GIS switchgear in that the SF6 gas is used for its insulating properties, not for interruption.

Conventional MC switchgear relies on a combination of air and solid insulating materials, but GIS switchgear uses bare bus conductors on insulating supports, immersed in insulating gas.

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Conclusion

Due to the environmental concerns, installing medium-voltage GIS switchgear is not consistent with the Sustainability Principles and Greenhouse Gas reduction goals of many leading edge corporations and institutions.

The safety and special handling concems could raise issues with internal Environmental Health and Safety policies.

Finally, the installation, operation and maintenance and end of life/recycling concerns associated with medium voltage GIS switchgear can raise the total cost of ownership and may not be the best value solution.

Alternative solutions include AIS – air insulated switchgear and solid insulated switchgear designs that avoid the use of SF6 gas and can offer a lower total cost of ownership over the complete life cycle of your medium voltage equipment.

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Resource: EATON CORPORATION (http://www.eaton.com/ecm/groups/public/@pub/@electrical/documents/content/pu02200003e.pdf)

Defining Size and Location of Capacitor in Electrical System (1)

Content

Type of Capacitor Bank as per Its Application:

Type of Capacitor as per Construction

Selecting Size of Capacitor Bank

Selection of Capacitor as per Non Liner Load

Configuration of Capacitor:

Effect of series and Parallel Connection of capacitor:

Type of Capacitor Bank as per Its Application

1. Fixed type capacitor banks

The reactive power supplied by the fixed capacitor bank is constant irrespective of any variations in the power factor and the load of the receivers. These capacitor banks are switched on either manually (circuit breaker / switch) or semi automatically by a remote-controlled contactor.

This arrangement uses one or more capacitor to provide a constant level of compensation.

These capacitors are applied at the terminals of inductive loads (mainly motors), at bus bars.

Disadvantages:

Manual ON/OFF operation.
Not meet the require kvar under varying loads.
Penalty by electricity authority.
Power factor also varies as a function of the load requirements so it is difficult to maintain a consistent power factor by use of Fixed Compensation i.e. fixed capacitors.
Fixed Capacitor may provide leading power factor under light load conditions, Due to this result in overvoltages, saturation of transformers, mal-operation of diesel generating sets, penalties by electric supply authorities.

Application:

Where the load factor is reasonably constant.
Electrical installations with constant load operating 24 hours a day
Reactive compensation of transformers.
Individual compensation of motors.
Where the kvar rating of the capacitors is less than, or equal to 15% of the supply transformer rating, a fixed value of compensation is appropriate.
Size of Fixed Capacitor bank Qc ≤ 15% kVA transformer

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2. Automatic type capacitor banks

The reactive power supplied by the capacitor bank can be adjusted according to variations in the power factor and the load of the receivers.

These capacitor banks are made up of a combination of capacitor steps (step = capacitor + contactor) connected in parallel. Switching on and off of all or part of the capacitor bank is controlled by an integrated power factor controller.

The equipment is applied at points in an installation where the active-power or reactive power variations are relatively large, for example:

At the bus bars of a main distribution switch-board,
At the terminals of a heavily-loaded feeder cable.

Where the kvar rating of the capacitors is less than, or equal to 15% of the supply transformer rating, a fixed value of compensation is appropriate.

Above the 15% level, it is advisable to install an automatically-controlled bank of capacitors.

Control is usually provided by contactors. For compensation of highly fluctuating loads, fast and highly repetitive connection of capacitors is necessary, and static switches must be used.

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Types of APFC – Automatic Power Factor Correction

Automatic Power Factor correction equipment is divided into three major categories:

Standard = Capacitor + Fuse + Contactor + Controller
De tuned = Capacitor + De tuning Reactor + Fuse + Contactor + Controller
Filtered = Capacitor + Filter Reactor + Fuse + Contactor + Controller.

Advantages:

Consistently high power factor under fluctuating loads.
Prevention of leading power factor.
Eliminate power factor penalty.
Lower energy consumption by reducing losses.
Continuously sense and monitor load.
Automatically switch on/off relevant capacitors steps for consistent power factor.
Ensures easy user interface.
Automatically variation, without manual intervention, the compensation to suit the load requirements.

Application:

Variable load electrical installations.
Compensation of main LV distribution boards or major outgoing lines.
Above the 15% level, it is advisable to install an automatically-controlled bank of capacitors.
Size of Automatic Capacitor bank Qc > 15% kVA transformer.

Method	Advantages	Disadvantages
Individual capacitors	Most technically efficient, most flexible	Higher installation & maintenance cost
Fixed bank	Most economical, fewer installations	Less flexible, requires switches and/or circuit breakers
Automatic bank	Best for variable loads, prevents over voltages, low installation cost	Higher equipment cost
Combination	Most practical for larger numbers of motors	Least flexible

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Type of Capacitor as per Construction

1. Standard duty Capacitor

Construction: Rectangular and Cylindrical (Resin filled / Resin coated-Dry)

Application:

Steady inductive load.
Non linear up to 10%.
For Agriculture duty.

2. Heavy-duty

Construction: Rectangular and Cylindrical (Resin filled / Resin coated-Dry/oil/gas)

Application:

Suitable for fluctuating load.
Non linear up to 20%.
Suitable for APFC Panel.
Harmonic filtering

3. LT Capacitor

Application:

Suitable for fluctuating load.
Non linear up to 20%.
Suitable for APFC Panel & Harmonic filter application.

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Selecting Size of Capacitor Bank

The size of the inductive load is large enough to select the minimum size of capacitors that is practical.

For HT capacitors the minimum ratings that are practical are as follows:

System Voltage	Minimum rating of capacitor bank
3.3 KV , 6.6KV	75 Kvar
11 KV	200 Kvar
22 KV	400 Kvar
33 KV	600 Kvar

Unit sizes lower than above is not practical and economical to manufacture.

When capacitors are connected directly across motors it must be ensured that the rated current of the capacitor bank should not exceed 90% of the no-load current of the motor to avoid self-excitation of the motor and also over compensation.

Precaution must be taken to ensure the live parts of the equipment to be compensated should not be handled for 10 minutes (in case of HT equipment) after disconnection of supply.

Crane motors or like, where the motors can be rotated by mechanical load and motors with electrical braking systems, should never be compensated by capacitors directly across motor terminals.

For direct compensation across transformers the capacitor rating should not exceed 90 % of the no-load KVA of the motor.

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Selection of Capacitor as per Non Liner Load

For power Factor correction it is need to first decide which type of capacitor is used.

Selection of Capacitor is depending upon many factor i.e. operating life, Number of Operation, Peak Inrush current withstand capacity.

For selection of Capacitor we have to calculate Total Non-Liner Load like: UPS, Rectifier, Arc/Induction Furnace, AC/DC Drives, Computer, CFL Blubs, and CNC Machines.

Calculation of Non liner Load, Example: Transformer Rating 1MVA,Non Liner Load 100KVA
% of non Liner Load = (Non Liner Load/Transformer Capacity) x100 = (100/1000) x100=10%.
According to Non Linear Load Select Capacitor as per Following Table.

% Non Liner Load	Type of Capacitor
<=10%	Standard Duty
Up to 15%	Heavy Duty
Up to 20%	Super Heavy Duty
Up to 25%	Capacitor +Reactor (Detuned)
Above 30%

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Configuration of Capacitor

Power factor correction capacitor banks can be configured in the following ways:

Delta connected Bank.
Star-Solidly Grounded Bank.
Star-Ungrounded Bank.

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1. Star-Solidly Grounded

Initial cost of the bank may be lower since the neutral does not have to be insulated from ground.
Capacitor switch recovery voltages are reduced
High inrush currents may occur in the station ground system.
The grounded-Star arrangement provides a low-impedance fault path which may require revision to the existing system ground protection scheme.
Typically not applied to ungrounded systems. When applied to resistance-grounded systems, difficulty in coordination between capacitor fuses and upstream ground protection relays (consider coordination of 40 A fuses with a 400 A grounded system).
Application: Typical for smaller installations (since auxiliary equipment is not required)

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2. Star-Ungrounded

Industrial and commercial capacitor banks are normally connected ungrounded Star, with paralleled units to make up the total kvar.

It is recommended that a minimum of 4 paralleled units to be applied to limit the over voltage on the remaining units when one is removed from the circuit.

If only one unit is needed to make the total kvar, the units in the other phases will not be overloaded if it fails.

In industrial or commercial power systems the capacitors are not grounded for a variety of reasons. Industrial systems are often resistance grounded. A grounded Star connection on the capacitor bank would provide a path for zero sequence currents and the possibility of a false operation of ground fault relays.

Also, the protective relay scheme would be sensitive to system line-to-ground voltage Unbalance, which could also result in false relay tripping.

Application: In Industrial and Commercial.

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3. Delta-connected Banks

Delta-connected banks are generally used only at distributions voltages and are configured with a Single series group of capacitors rated at line-to-line voltage. With only one series group of units no overvoltage occurs across the remaining capacitor units from the isolation of a faulted capacitor unit.

Therefore, unbalance detection is not required for protection and they are not treated further in this paper.

Application: In Distribution System.

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Effect of series and Parallel Connection of capacitor

Parallel Connection

This is the most popular method of connection. The capacitor is connected in parallel to the unit. The voltage rating of the capacitor is usually the same as or a little higher than the system voltage.

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Series Connection

This method of connection is not much common. Even though the voltage regulation is much high in this method,

It has many disadvantages.

One is that because of the series connection, in a short circuit condition the capacitor should be able to withstand the high current. The other is that due to the series connection due to the inductivity of the line there can be a resonance occurring at a certain capacitive value.

This will lead to very low impedance and may cause very high currents to flow through the lines.

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Active Fire Protection Measures in Substation (photo by Marcus Wong via Flickr)

Fire Detection

Active fire protection measures are automatic fire protection measures that warn occupants of the existence of fire, and extinguish or control the fire. These measures are designed to automatically extinguish or control a fire at its earliest stage, without risking life or sacrificing property and personels.

The benefits of these systems have been universally identified and accepted by building and insurance authorities. Insurance companies have found significant reduction in losses when automatic suppression systems have been installed.

An automatic suppression system consists of:

Extinguishing agent supply,
Control valves,
Delivery system, and
Fire detection and control equipment.

The agent supply may be virtually unlimited (such as with a city water supply for a sprinkler system) or of limited quantity (such as with water tank supply for a sprinkler system).

Typical examples of agent control valves are deluge valves, sprinkler valves, and Halon control valves.

The agent delivery systems are a configuration of piping, nozzles, or generators that apply the agent in a suitable form and quantity to the hazard area (e.g., sprinkler piping and heads).

Fire detection and control equipment may be either mechanical or electrical in operation.

These systems may incorporate a fire detection means such as sprinkler heads or they use a separate fire and detection system as part of their operation. These detection systems detect a fire condition, signal its occurrence, and activate the system.

Deluge valve

Active systems include wet, dry and pre-action sprinklers, deluge systems, foam systems, and gaseous systems. Detailed descriptions of each of these systems, code references and recommendations on application are covered in IEEE 979.

Fire Fighting Test – Sulaibiya Z Substation (VIDEO)

Cant see this video? Click here to watch it on Youtube.

Resource: Substation Engineering Design – L. Grigsby

How to Determine Correct Number of Earthing Electrodes (Strips, Plates and Pipes) - part 1

Introduction

Number of Earthing Electrode and Earthing Resistance depends on the resistivity of soil and time for fault current to pass through (1 sec or 3 sec). If we divide the area for earthing required by the area of one earth plate gives the number of earth pits required.

There is no general rule to calculate the exact number of earth pits and size of earthing strip, but discharging of leakage current is certainly dependent on the cross section area of the material so for any equipment the earth strip size is calculated on the current to be carried by that strip.

First the leakage current to be carried is calculated and then size of the strip is determined.

For most of the electrical equipment like transformer, diesel generator set etc., the general concept is to have 4 number of earth pits. 2 no’s for body earthing with 2 separate strips with the pits shorted and 2 nos for Neutral with 2 separate strips with the pits shorted.

The Size of Neutral Earthing Strip should be capable to carry neutral current of that equipment.
The Size of Body Earthing should be capable to carry half of neutral Current.

For example for 100kVA transformer, the full load current is around 140A.

The strip connected should be capable to carry at least 70A (neutral current) which means a strip of GI 25x3mm should be enough to carry the current and for body a strip of 25×3 will do the needful. Normally we consider the strip size that is generally used as standards.

However a strip with lesser size which can carry a current of 35A can be used for body earthing. The reason for using 2 earth pits for each body and neutral and then shorting them is to serve as back up. If one strip gets corroded and cuts the continuity is broken and the other leakage current flows through the other run thery by completing the circuit.

Similarly for panels the no of pits should be 2 nos. The size can be decided on the main incomer circuit breaker.

For example if main incomer to breaker is 400A, then body earthing for panel can have a strip size of 25×6 mm which can easily carry 100A.

Number of earth pits is decided by considering the total fault current to be dissipated to the ground in case of fault and the current that can be dissipated by each earth pit. Normally the density of current for GI strip can be roughly 200 amps per square cam. Based on the length and dia of the pipe used the number of earthing pits can be finalized.

1. Calculate numbers of pipe earthing

A. Earthing resistance and number of rods for isolated earth pit
(without buried earthing strip)

The earth resistance of single rod or pipe electrode is calculated as per BS 7430:

R=ρ/2×3.14xL (loge (8xL/d)-1)

Where:

ρ = Resistivity of soil (Ω meter),
L = Length of electrode (meter),
D = Diameter of electrode (meter)

Example:

Calculate isolated earthing rod resistance. The earthing rod is 4 meter long and having 12.2mm diameter, soil resistivity 500 Ω meter.

R=500/ (2×3.14×4) x (Loge (8×4/0.0125)-1) =156.19 Ω.

The earth resistance of single rod or pipe electrode is calculated as per IS 3040:

R=100xρ/2×3.14xL (loge(4xL/d))

Where:

ρ = Resistivity of soil (Ω meter),
L = Length of electrode (cm),
D = Diameter of electrode (cm)

Example:

Calculate number of CI earthing pipe of 100mm diameter, 3 meter length. System has fault current 50KA for 1 sec and soil resistivity is 72.44 Ω-Meters.

Current Density At The Surface of Earth Electrode (As per IS 3043):

Max. allowable current density I = 7.57×1000/(√ρxt) A/m2
Max. allowable current density = 7.57×1000/(√72.44X1) = 889.419 A/m2
Surface area of one 100mm dia. 3 meter Pipe = 2 x 3.14 x r x L = 2 x 3.14 x 0.05 x3 = 0.942 m2
Max. current dissipated by one Earthing Pipe = Current Density x Surface area of electrode
Max. current dissipated by one earthing pipe = 889.419x 0.942 = 837.83 A say 838 Amps
Number of earthing pipe required = Fault Current / Max.current dissipated by one earthing pipe.
Number of earthing pipe required = 50000/838 = 59.66 Say 60 No’s.
Total number of earthing pipe required = 60 No’s.
Resistance of earthing pipe (isolated) R = 100xρ/2×3.14xLx(loge (4XL/d))
Resistance of earthing pipe (isolated) R = 100×72.44 /2×3.14x300x(loge (4X300/10)) = 7.99 Ω/Pipe
Overall resistance of 60 no of earthing pipe = 7.99/60 = 0.133 Ω.

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B. Earthing resistance and number of rods for isolated earth pit
(with buried earthing strip)

Resistance of earth strip (R) As per IS 3043:

R=ρ/2×3.14xLx (loge (2xLxL/wt))

Example:

Calculate GI strip having width of 12mm , length of 2200 meter buried in ground at depth of 200mm, soil resistivity is 72.44 Ω-meter.

Resistance of earth strip(Re) = 72.44/2×3.14x2200x(loge (2x2200x2200/.2x.012)) = 0.050 Ω
From above calculation overall resistance of 60 no of earthing pipes (Rp) = 0.133 Ω.
And it connected to bury earthing strip. Here net earthing resistance = (RpxRe)/(Rp+Re)
Net eatrthing resistance = (0.133×0.05)/(0.133+0.05) = 0.036 Ω

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C. Total earthing resistance and number of electrode for group
(parallel)

In cases where a single electrode is not sufficient to provide the desired earth resistance, more than one electrode shall be used. The separation of the electrodes shall be about 4 m. The combined resistance of parallel electrodes is a complex function of several factors, such as the number and configuration of electrode the array.

The total resistance of group of electrodes in different configurations as per BS 7430:

Ra=R (1+λa/n) where a=ρ/2X3.14xRxS

Where:

S = Distance between adjustment rod (meter),
λ = Factor given in table below,
n = Number of electrodes,
ρ = Resistivity of soil (Ω meter),
R = Resistance of single rod in isolation (Ω)

Factors for parallel electrodes in line (BS 7430)
Number of electrodes (n)	Factor (λ)
2	1.0
3	1.66
4	2.15
5	2.54
6	2.87
7	3.15
8	3.39
9	3.61
10	3.8

For electrodes equally spaced around a hollow square, e.g. around the perimeter of a building, the equations given above are used with a value of λ taken from following table.

For three rods placed in an equilateral triangle, or in an L formation, a value of λ = 1.66 may be assumed.

Factors for electrodes in a hollow square (BS 7430)
Number of electrodes (n)	Factor (λ)
2	2.71
3	4.51
4	5.48
5	6.13
6	6.63
7	7.03
8	7.36
9	7.65
10	7.9
12	8.3
14	8.6
16	8.9
18	9.2
20	9.4

For Hollow square total number of electrodes (N) = (4n-1).

The rule of thumb is that rods in parallel should be spaced at least twice their length to utilize the full benefit of the additional rods. If the separation of the electrodes is much larger than their lengths and only a few electrodes are in parallel, then the resultant earth resistance can be calculated using the ordinary equation for resistances in parallel.

In practice, the effective earth resistance will usually be higher than calculation.

Typically, a 4 spike array may provide an improvement 2.5 to 3 times. An 8 spike array will typically give an improvement of maybe 5 to 6 times.

The Resistance of Original Earthing Rod will be lowered by Total of 40% for Second Rod, 60% for third Rod,66% for forth rod.

Example:

Calculate Total Earthing Rod Resistance of 200 Number arranges in Parallel having 4 Meter Space of each and if it connects in Hollow Square arrangement. The Earthing Rod is 4 Meter Long and having 12.2mm Diameter, Soil Resistivity 500 Ω.

First Calculate Single Earthing Rod Resistance:

R = 500/ (2×3.14×4) x (Loge (8×4/0.0125)-1) =136.23 Ω.

Now calculate total resistance of earthing rod of 200 number in parallel condition:

a = 500/(2×3.14x136x4) =0.146
Ra (Parallel in Line) =136.23x (1+10×0.146/200) = 1.67 Ω.

If earthing rod is connected in Hollow square than rod in each side of square is 200 = (4n-1) so n = 49 No.

Ra (in hollow square) =136.23x (1+9.4×0.146/200) = 1.61 Ω.

Originally published at – Electrical Notes - Calculate Numbers of Plate/Pipe/Strip Earthings (Part-1)

Installation of vertical electrodes of earthing

Continued from first part:
How to Determine Correct Number of Earthing Electrodes (Strips, Plates and Pipes) – part 1

2. Calculate Number of Plate Earthing

The Earth Resistance of Single Plate electrode is calculated as per IS 3040:

R=ρ/A√(3.14/A)

Where:

ρ = Resistivity of Soil (Ω Meter),
A = Area of both side of Plate (m2),

Example: Calculate Number of CI Earthing Plate of 600×600 mm, System has Fault current 65KA for 1 Sec and Soil Resistivity is 100 Ω-Meters.

Current Density At The Surface of Earth Electrode (As per IS 3043):

Max. Allowable Current Density I = 7.57×1000/(√ρxt) A/m2
Max. Allowable Current Density = 7.57×1000/(√100X1)=757 A/m2
Surface area of both side of single 600×600 mm Plate= 2 x lxw=2 x 0.06×0.06 = 0.72 m2
Max. current dissipated by one Earthing Plate = Current Density x Surface area of electrode
Max. current dissipated by one Earthing Plate =757×0.72= 545.04 Amps
Resistance of Earthing Plate (Isolated)(R)=ρ/A√(3.14/A)
Resistance of Earthing Plate (Isolated)(R)=100/0.72x√(3.14/.072)=290.14 Ω
Number of Earthing Plate required =Fault Current / Max.current dissipated by one Earthing Pipe.
Number of Earthing Plate required= 65000/545.04 =119 No’s.
Total Number of Earthing Plate required = 119 No’s.
Overall resistance of 119 No of Earthing Plate=290.14/119=2.438 Ω.

3. Calculating Resistance of Bared Earthing Strip

1) Calculation for earth resistance of buried Strip (As per IEEE)

The Earth Resistance of Single Strip of Rod buried in ground is:

R=ρ/Px3.14xL (loge (2xLxL/Wxh)+Q)

Where:

ρ = Resistivity of Soil (Ω Meter),
h = Depth of Electrode (Meter),
w = Width of Strip or Diameter of Conductor (Meter)
L = Length of Strip or Conductor (Meter)
P and Q are Koefficients

2) Calculation for earth resistance of buried Strip (As per IS 3043)

The Earth Resistance of Single Strip of Rod buried in ground is:

R=100xρ/2×3.14xL (loge (2xLxL/Wxt))

Where:

ρ = Resistivity of Soil (Ω Meter),
L = Length of Strip or Conductor (cm)
w = Width of Strip or Diameter of Conductor (cm)
t = Depth of burial (cm)

Example: Calculate Earthing Resistance of Earthing strip/wire of 36mm Diameter, 262 meter long buried at 500mm depth in ground, soil Resistivity is 65 Ω Meter.

Here:

R = Resistance of earth rod in W.
r = Resistivity of soil(Ω Meter) = 65 Ω Meter
l = length of the rod (cm) = 262m = 26200 cm
d = internal diameter of rod(cm) = 36mm = 3.6cm
h = Depth of the buried strip/rod (cm)= 500mm = 50cm

Resistance of Earthing Strip/Conductor (R)=ρ/2×3.14xL (loge (2xLxL/Wt))
Resistance of Earthing Strip/Conductor (R)=65/2×3.14x26200xln(2x26200x26200/3.6×50)
Resistance of Earthing Strip/Conductor (R)== 1.7 Ω

4. Calculate Min. Cross Section area of Earthing Conductor

Cross Section Area of Earthing Conductor As per IS 3043

(A) =(If x√t) / K

Where:

t = Fault current Time (Second).
K = Material Constant.

Example: Calculate Cross Section Area of GI Earthing Conductor for System has 50KA Fault Current for 1 second. Corrosion will be 1.0 % Per Year and No of Year for Replacement is 20 Years.

Cross Section Area of Earthing Conductor (A) =(If x√t) / K

Here:

If = 50000 Amp
T = 1 Second
K = 80 (Material Constant, For GI=80, copper K=205, Aluminium K=126).

Cross Section Area of Earthing Conductor (A) = (50000×1)/80
Cross Section Area of GI Earthing Conductor (A) = 625 Sq.mm
Allowance for Corrosion = 1.0 % Per Year & Number of Year before replacement say = 20 Years
Total allowance = 20 x 1.0% = 20%
Safety factor = 1.5
Required Earthing Conductor size = Cross sectional area x Total allowance x Safety factor
Required Earthing Conductor size = 1125 Sq.mm say 1200 Sq.mm
Hence, Considered 1Nox12x100 mm GI Strip or 2Nox6 x 100 mm GI Strips

Thumb Rule for Calculate Number of Earthing Rod

The approximate earth resistance of the Rod/Pipe electrodes can be calculated by:

Earth Resistance of the Rod/Pipe electrodes:

R= K x ρ/L

Where:

ρ = Resistivity of earth in Ohm-Meter
L = Length of the electrode in Meter.
d = Diameter of the electrode in Meter.
K = 0.75 if 25< L/d < 100.
K = 1 if 100 < L/d < 600
K = 1.2 o/L if 600 < L/d < 300

Number of Electrode if find out by Equation of R(d) = (1.5/N) x R

Where:

R(d) = Desired earth resistance
R = Resistance of single electrode
N = No. of electrodes installed in parallel at a distance of 3 to 4 Meter interval.

Example: Calculate Earthing Pipe Resistance and Number of Electrode for getting Earthing Resistance of 1 Ω ,Soil Resistivity of ρ=40, Length=2.5 Meter, Diameter of Pipe = 38 mm.

Here:

L/d = 2.5/0.038=65.78 so K = 0.75

The Earth Resistance of the Pipe electrodes R= K x ρ/L = 0.75×65.78 = 12 Ω
One electrode the earth resistance is 12 Ω.
To get Earth resistance of 1 Ω the total Number of electrodes required = (1.5×12)/1 = 18 No

Calculating Resistance & Number of Earthing Rod

Reference: As per EHV Transmission Line Reference Book page: 290 and Electrical Transmission & Distribution Reference Book Westinghouse Electric Corporation, Section-I Page: 570-590.

Earthing Resistance of Single Rods:

R = ρx[ln (2L/a)-1]/(2×3.14xL)

Earthing Resistance of Parallel Rods:

R = ρx[ln (2L/A]/ (2×3.14xL)

Where:

L = length of rod in ground Meter,
a = radius of rod Meter
ρ = ground resistivity, ohm-Meter
A = √(axS)
S = Rod separation Meter

Earthing rod arrangements

Factor affects on Ground resistance

The NEC code requires a minimum ground electrode length of 2.5 meters (8.0 feet) to be in contact with the soil. But, there are some factor that affect the ground resistance of a ground system:

Length / Depth of the ground electrode: double the length, reduce ground resistance by up to 40%.
Diameter of the ground electrode: double the diameter, lower ground resistance by only 10%.
Number of ground electrodes: for increased effectiveness, space additional electrodes at least equal to the depth of the ground electrodes.
Ground system design: single ground rod to ground plate.

The GI earthing conductor sizes for various equipment

No	Equipment	Earth strip size
1	HT switchgear, structures, cable trays & fence, rails, gate and steel column	55 X 6 mm (GI)
2	Lighting Arrestor	25 X 3 mm (Copper)
3	PLC Panel	25 X 3 mm (Copper)
4	DG & Transformer Neutral	50X6 mm (Copper)
5	Transformer Body	50×6 mm (GI)
6	Control & Relay Panel	25 X 6 mm (GI)
7	Lighting Panel & Local Panel	25 X 6 mm (GI)
8	Distribution Board	25 X 6 mm (GI)
9	Motor up to 5.5 kw	4 mm2 (GI)
10	Motor 5.5 kw to 55 kw	25 X 6 mm (GI)
11	Motor 22 kw to 55 kw	40 X 6 mm (GI)
12	Motor Above 55 kw	55 X 6 mm (GI)

Selection of Earthing System:

Installations/Isc Capacity	IR Value Required	Soil Type/Resistivity	Earth System
House hold earthing/3kA	8 ohm	Normal Soil/ up to 50 ohm-meter	Single Electrode
		Sandy Soil/ between 50 to 2000 ohm-meter	Single Electrode
		Rocky Soil/ More than 2000 ohm-meter	Multiple Electrodes
Commercial premises,Office / 5kA	2 ohm	Normal Soil/ up to 50 ohm-meter	Single Electrode
		Sandy Soil/ between 50 to 2000 ohm-meter	Multiple Electrodes
		Rocky Soil/ More than 2000 ohm-meter	Multiple Electrodes
Transformers, substation earthing, LT line equipment/ 15kA	less than 1 ohm	Normal Soil/ up to 50 ohm-meter	Single Electrode
		Sandy Soil/ between 50 to 2000 ohm-meter	Multiple Electrodes
		Rocky Soil/ More than 2000 ohm-meter	Multiple Electrodes
LA, High current Equipment./ 50kA	less than 1 ohm	Normal Soil/ up to 50 ohm-meter	Single Electrode
		Sandy Soil/ between 50 to 2000 ohm-meter	Multiple Electrodes
		Rocky Soil/ More than 2000 ohm-meter	Multiple Electrodes
PRS, UTS, RTUs, Data processing centre etc./5KA	less than 0.5 ohm	Normal Soil/ up to 50 ohm-meter	Single Electrode
		Sandy Soil/ between 50 to 2000 ohm-meter	Multiple Electrodes
		Rocky Soil/ More than 2000 ohm-meter	Multiple Electrodes

Size of Earthing Conductor

Ref IS 3043 and Handbook on BS 7671: The Lee Wiring Regulations by Trevor E. Marks.

Size of Earthing Conductor
Area of Phase Conductor S (mm2)	Area of Earthing conductor (mm2) When It is Same Material as Phase Conductor	Area of Earthing conductor (mm2) When It is Not Same Material as Phase Conductor
S < 16 mm2	S	SX(k1/k2)
16 mm2<S< 35 mm2	16 mm2	16X(k1/k2)
S > 35 mm2	S/2	SX(k1/2k2)
K1 is value of Phase conductor,k2 is value of earthing conductor
Value of K for GI=80, Alu=126,Cu=205 for 1 Sec

Standard earthing strip/plate/pipe/wire weight

GI Earthing Strip:

Size (mm2)	Weight
20 x 3	500 gm Per meter
25 x 3	600 gm Per meter
25 x 6	1/200 Kg Per meter
32 x 6	1/600 Kg Per meter
40 x 6	2 Kg Per meter
50 x 6	2/400 Kg Per meter
65 x 10	5/200 Kg Per meter
75 x 12	7/200 Kg Per meter

GI Earthing Plate

Plate	Weight
600 x 600 x 3 mm	10 Kg App.
600 x 600 x 4 mm	12 Kg App.
600 x 600 x 5 mm	15 Kg App.
600 x 600 x 6 mm	18 Kg App.
600 x 600 x 12 mm	36 Kg App.
1200 x 1200 x 6 mm	70 Kg App.
1200 x 1200 x 12 mm	140 Kg App.

GI Earthing Pipe

Pipe	Weight
3 meter Long BISE	5 Kg App.
3 meter r Long BISE	9 Kg App.
4.5 meter (15′ Long BISE)	5 Kg App.
4.5 meter (15′ Long BISE)	9 Kg App.
4.5 meter (15′ Long BISE)	14 Kg App

GI Earthing Wire

Plate	Weight
6 Swg	5 meter in 1 Kg
8 Swg	9 meter in 1 Kg

Requirements and Functions of Substation Automation (photo by psi-incontrol.com)

Introduction

Substation automation is the cutting edge technology in electrical engineering. It means having an intelligent, interactive power distribution network including :

Increased performance and reliability of electrical protection.
Advanced disturbance and event recording capabilities, aiding in detailed electrical fault analysis.
Display of real time substation information in a control center.
Remote switching and advanced supervisory control.
Increased integrity and safety of the electrical power network including advanced interlocking functions.
Advanced automation functions like intelligent load-shedding.

Requirements

The general requirements for selecting an automation system while designing a new substation are:

The system should be adaptable to any vendor’s hardware.
It should incorporate distributed architecture to minimize wiring.
It should be flexible and easily set up by the user.
The substation unit should include a computer to store data and pre-process information.

Functioning

Bus voltages and frequencies, line loading, transformer loading, power factor, real and reactive power flow, temperature, etc. are the basic variables related with substation control and instrumentation. The various supervision, control and protection functions are performed in the substation control room.

The relays, protection and control panels are installed in the controlled room. These panels along with PC aids in automatic operation of various circuit breakers, tap changers, autoreclosers, sectionalizing switches and other devices during faults and abnormal conditions.

Thus, primary control in substation is of two categories:

Normal routine operation by operator’s command with the aid of analog and digital control system.
Automatic operation by action of protective relays , control systems and PC.

The automated substation functioning can be treated as integration of two subsystems, as discussed below :

(a) Control System

The task of control system in a substation includes data collection, scanning, event reporting and recording; voltage control, power control, frequency control, other automatic and semiautomatic controls etc.

The various switching actions like auto reclosing of line circuit breakers, operation of sectionalizing switches, on-load tap changers are performed by remote command from control room. The other sequential operations like load transfer from one bus to another, load shedding etc. are also taken care by control center.

(b) Protective System

The task of protective system includes sensing abnormal condition, annunciation of abnormal condition, alarm, automatic tripping, back-up protection, protective signaling.

The above two systems work in close co-operation with each other. Most of the above functions i.e. automatic switching sequences, sequential event recording, compiling of energy and other reports, etc. are integrated in software in the substation computer. This software is of modular design, which facilitates addition of new functions.

The communication between circuit breakers, autoreclosers and sectionalizing switches in the primary and secondary distribution circuits located in the field and the PC in distribution substation control room is through radio telecontrol or fibre optic channel or power line carrier channel as is feasible.

Reference: Chapter 42, Distribution Automation // Unknown

Power Substation that converts electricity from 66kV down to 11kV (photo by Marcus Wong via Flickr)

Importance Of Community Acceptance

Community acceptance generally encompasses the planning, design, and construction phases of a substation as well as the in-service operation of the substation. It takes into account those issues that could influence a community’s willingness to accept building a substation at a specific site.

New substations or expansions of existing facilities often require extensive review for community acceptance.

Government bodies typically require a variety of permits before construction may begin.

For community acceptance, several considerations should be satisfactorily addressed, including the following:

Noise
Site preparations
Aesthetics
Fire protection
Potable water and sewage
Hazardous materials
Electric and magnetic fields
Safety and security

What does IEEE Standard 1127–1998 say?

The noise level at which transformers become an annoyance is not necessarily dependent upon the level of the transformer noise but may depend upon the differential between ambient and added noise.

If the transformer can be heard, it can be an annoyance. Information from the noise profile study may be used for a presentation to obtain community acceptance.

Noise attenuation with distance is logarithmic, and even where large buffer zones exist, the noise levels from larger transformers can exceed 25–30 dBA at 300 m or more. In quiet rural areas, and some suburban areas, low night time ambient sound levels of 30 dBA or less are possible.

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

The higher background ambient noise levels resulting from high traffic volume, business and industrial activity and the normal household activities such as children playing, dogs barking, lawn mowing, etc., will be missing during the evening and night time hours.

On warm summer nights, nearby residents can find the transformer noise level to be annoying (for sleeping with open windows, sitting outside, etc.).

As a result, sound levels well below the ones imposed by governmental regulations may have to be considered to lessen complaints.

Objections to substation noise levels below those set by governmental regulations can also occur in urban areas. However, the benefit resulting from higher ambient background levels of 35–45 dBA or more (night time) can be offset by the closer proximity of nearby residents (in some cases less that 30 m).

Community acceptance of noise levels may not always have a technical basis. Residents who are annoyed simply by the presence of the substation may find perceived excessive noise levels to be a tangible factor upon which to base a complaint.

References:

Electric Power Engineering Handbook by Leonard L. Grigsby (Get it from Amazon)
IEEE Standard 1127–1998

What's Really Important When You're Designing The Low Voltage Switchgear?

Requirements on the Switchgear

Here what’s important when you’re designing the low voltage switchgear:

1. Device Application in the Supply Circuit

The system infeed is the most “sensitive” circuit in the entire power distribution. A failure here would result in the entire network and therefore the building or production being without power. This worst-case scenario must be considered during the planning.

Redundant system supplies and selective protection setting are important preconditions for a safe network configuration. The selection of the correct protective devices is therefore of elementary importance in order to create these preconditions.

Some of the key dimensioning data is addressed in the following:

1.1 Rated current

3WL11 air circuit breaker optimized for use in power distribution boards and wind turbines

The feeder circuit-breaker in the Low-voltage main distribution (LVMD) must be dimensioned for the maximum load of the transformer/generator. When using ventilated transformers, the higher operating current of up to 1.5 x I_N of the transformer must be taken into account.

Go back to Index ↑

2. Short-circuit strength

The short-circuit strength of the feeder circuit-breaker is determined by (n–1) x I_{k max} of the transformer or transformers (n = number of transformers).

This means that the maximum shortcircuit current that occurs at the installation position must be known in order to specify the appropriate short-circuit strength of the protective device (I_cu).

Circuit breaker nameplate

2.1 Utilization category

When dimensioning a selective network, time grading of the protective devices is essential. When using time grading up to 500 ms, the selected circuit-breaker must be able to carry the short-circuit current that occurs for the set time. Close to the transformer, the currents are very high.

This current carrying capacity is specified by the I_cw value (rated short-time withstand current) of the circuit-breaker. This means the contact system must be able to carry the maximum short-circuit current, i.e. the energy contained therein, until the circuit-breaker is tripped.

This requirement is satisfied by circuit-breakers of utilization category B (e.g. air circuit-breakers, ACB). Current-limiting circuit breakers (molded-case circuit breakers, MCCB) trip during the current rise. They can therefore be constructed more compactly.

Go back to Index ↑

3. The Release (Trip Unit)

For a selective network design, the release (trip unit) of the feeder circuit-breaker must have an LSI (electronic trip unit) characteristic.

LSI (electronic protection unit)

It must be possible to deactivate the instantaneous release (I).

Depending on the curve characteristic of the upstream and downstream protective devices, the characteristics of the feeder circuit breaker in the overload range (L) and also in the time-lag short circuit range (S) should be optionally switchable (I⁴t or I²t characteristic curve).

This facilitates the adaptation of upstream and downstream devices.

3.1 Internal accessories

Depending on the respective control, not only shunt releases (previously: f releases), but also undervoltage releases are required.

3.2 Communication

Information about the current operating states, maintenance, error messages and analyses, etc. is being increasingly required, especially from the very sensitive supply circuits. Flexibility may be required with regard to a later upgrade or retrofit to the desired type of data transmission.

Go back to Index ↑

4. Device Application in Supply Circuits (Coupling)

If the coupling (connection of Network 1 to Network 2) is operated open, the circuit-breaker (tie breaker) only has the function of an isolator or main switch. A protective function (release) is not absolutely necessary.

The following considerations apply to closed operation:

4.1 Rated current

Must be dimensioned for the maximum possible operating current (load compensation). The simultaneity factor can be assumed to be 0.9.

4.2 Short-circuit strength

The short-circuit strength of the feeder circuit-breaker is determined by the sum of the short-circuit components that flow through the coupling. This depends on the configuration of the component busbars and their supply.

4.3 Utilization category

As for the system supply, utilization category B is also required for the current carrying capacity (I_cw value).

4.4 Release

Partial shutdown with the couplings must be taken into consideration for the supply reliability. As the coupling and the feeder circuit-breakers have the same current components when a fault occurs, similar to the parallel operation of two transformers, the LSI characteristic is required.

The special “Zone Selective Interlocking (ZSI)” function should be used for larger networks and/or protection settings that are difficult to determine.

Go back to Index ↑

5. Device Application in the Distribution Circuit

The distribution circuit receives power from the higher level (supply circuit) and feeds it to the next distribution level (final circuit).

Depending on the country, local practices, etc., circuit-breakers and fuses can be used for system protection.

The specifications for the circuit dimensioning must be fulfilled. The ACB has advantages if full selectivity is required. However for cost reasons, the ACB is only frequently used in the distribution circuit as of a rated current of 630 A or 800 A. As the ACB is not a current-limiting device, it differs greatly from other protective devices such as MCCB, MCB and fuses.

As no clear recommendations can otherwise be given, Table 1 shows the major differences and limits of the respective protective devices.

Go back to Index ↑

6. Device Application in the Final Circuit

The final circuit receives power from the distribution circuit and supplies it to the consumer (e.g. motor, lamp, non-stationary load (power outlet), etc.). The protective device must satisfy the requirements of the consumer to be protected by it.

Note: All protection settings, comparison of characteristic curves, etc. always start with the load. This means that no protective devices are required with adjustable time grading in the final circuit.

Go back to Index ↑

Table 1 – Overview of the protective devices

Table 1 - Overview of the protective devices

*) with ETU: No limitation / with TMTU: depends on cable length

Go back to Index ↑

Reference: Siemens Energy Sector – Power Engineering Guide Edition 7.0

An Overview Of Grounding System (Ungrounded) (On photo: installed ground clamp. The 2" x 0.022" copper strip is treated with a copper based anti oxidation grease and then clamped to the clean copper plated 8' ground rod - by beevo.com )

Topics:

Underground Neutral Or Undergrounded System

Before 1950 power system were often without neutral grounding. Such system had repeated arcing grounds, insulation failure and difficult earth fault protection.

Every phase has inherent distributed capacitance with respect to earth. If earth fault occurs on phase B, the distributed capacitance discharges through the fault. The capacitance again gets charged and gets discharged. Because of this sever voltage oscillation is reached in healthy phases.

These voltage oscillation causes stress on insulation of connected equipment.

Figure 1 - Ungrounded neutral or ungrounded system

Ic2 = jCwv2
Ic3 = jCwv3
Ic = jCwv2 + jCwv3
Ic = jCw(v2 + v3) // Equation-01

Now by drawing the phaser diagram as shown below wecan write:

VN + V2 = v2 // Equation-02
VN + V3 = v3 // Equation-03

Substituting equation -02 and equation-03 in equation-01:

Ic = jCw(VN + V2 + VN + V3)
Ic = jCw(2VN + V2 + V3) // Equation-04

Figure 2 - Ungrounded neutral or ungrounded system

Voltage phasers V3 can be resolved in the direction of V_N and in direction perpendicular to V_N as V3Cosθ and V3Sinθ.

Similarly voltage phaser V2 can be resolved as V2Cosθand – V2Sinθ

Hence:
V2 + V3 = V3Cosθ + V3Sinθ + V2Cosθ – V2Sinθ // Equation-05
V3 = V2
V3Cosθ + V2Cosθ = V_N

Substituting in equation-05 we get:

V2 + V3 = VN = V1 (Since V1 is shorted to ground soVN = V1) // Equation-06

Substituting equation-06 in equation- 04 we get:

Ic = jCw(2VN + VN)

Total capacitive charging and discharging current of healthy phase is:

Ic = j3CwV1

For ungrounded system:

If = IC2 + IC3 = IC = j3CwV1 // Equation-07

As seen from equation -07, in unearthed system ground fault current is totally dependent on capacitive current returning via the network phase-earth capacitances. This is the reason for sever voltage stress in healthy phases of ungrounded system.

Since there is no return path available for fault current in ungrounded system so detection of earth fault current is difficult. This is other disadvantage of ungrounded system.

Go back to Topics ↑

Advantages of Ungrounded System

There are some advantages of ungrounded system:

Ungrounded system has negligible earth fault current
Some continuous process or system and essential auxiliaries where single phase to ground fault should not trip the system.

Go back to Topics ↑

Disadvantages of Ungrounded System

However below listed disadvantages of ungrounded system are more adverse than advantages:

Unearthed system experience repeated arcing grounds.
Insulation failure occurs during single phase to ground faults.
Earth fault protection for unearthed system is difficult.
Voltage due to lightning surges do not find path to earth.

In order to overcome the above mentioned technical and operation issues the concept of system grounding was introduced. System grounding is connecting the neutral of system to earth.

At every voltage level neutral of transformer is considered as neutral of system.

System grounding is of two types:

Effective grounding: Effective grounding is also called solid grounding that is without resistance or reactance. In this case co-efficient of earthing ismore than 80%
Non effective grounding: When neutral to earth connection is made through resistance or reactance than the system is said to be non-effectively grounded. In this case coefficient of earthing is greater than 80%

Go back to Topics ↑

Coefficient of earthing and earth fault factor

Coefficient of earthing is the ratio which is measured during single phase to ground fault:

Ce = Highest phase to ground voltage of healthy phase / Phase to phase voltage

In a system without neutral earth (refer Figure 1), phase to earth voltage phase-1 and phase-2 rises to 3times phase to phase voltage Vrms during single phase to earth fault on phase 3. In a neutral earthed system the voltage ofhealthy phase rises to Ce times Vrms.

Therefore value of Ce:

For non-effectively earthed system Ce = 1
For effectively earthed system Ce < 0.8. Hence surge arrester rated voltage is > 0.8 V rms

Surge voltage kV instantaneous is taken as 2.5 times of critical flashover voltage (CFOV) of line insulation. Thus discharge current is given as:

I = (2.5(CFOV) –Residual voltage of arrester) / Surge impedance of line

Earth fault factor is a ratio calculated at selected point of the power system for a given system. Earth fault factor = V1/V2

V1 = Highest RMS phase to phase voltage of healthy phases (phase 2 and 3 refer to Figure 1) during earth faulton pahse-1
V2 = RMS value of phase to earth voltage at same location with fault on faulty phases removed

Go back to Topics ↑

References:

Industrial electrical network design guide By Schneider electric
Switchgear protection & power system By Sunil S Rao, Khanna publications
EARTHING: Your questions answered By Geoff Cronshaw
IEEE Recommended Practice for Electric Power Distribution for Industrial Plants

An Overview Of Grounded Grounding System (on photo: Grounded solar panel by J.E.M. Solar; jemsolar.com)

Continued from technical article: An Overview Of Grounding System (Ungrounded)

Topics covered

Solidly grounded system

Figure 3 - Solidly grounded system

Let us assume that R phase (Phase-3 in figure-3) is shorted to ground than:

If = Current through shorted path (Fault current)
In = Current through neutral to earth connection
Icy = Capacitive current returning via the network Phase-2 (Y phase)-earth capacitances
IcB = Capacitive current returning via the network Phase-1 (B phase)-earth capacitances

We can write:

If = In + IcY + IcB + Ir // Equation-08

Where Ir = Current returning via network insulation resistance which is always negligible

In case of LV, system voltage available between phase and earth is 415/1.732 = 240V. Resistance of earth plate, grounding connections etc… is of the order of 1.5 Ohms so the earth current is limited to approximately 240/1.5 =160 Amperes. This is not very high magnitude hence any intentional impedance is not required in neutral to earth connection.

As per equation -08 for If one can see that if IcY and IcB is negligible than If = In which is the case in LV system. At 415V level capacitive ground currents are not significant hence we can write:

If = In for solidly earthed LV system // Equation-09

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Top

Resistance grounded system

Figure 4 - Resistance grounded system

In case of MV system (3.3kV onwards to 33kV) voltage between phase and earth is high. Also capacitive charging current is not large enough to compensate the same, so earth fault current is likely to be excessive.

Hence resistance is connected between neutral to ground connection. Current through neutral is limited to 100-400 Amperes.

Restricting the earth fault current / current through neutral

Although all the component of power system at MV level are rated at full MV system fault level, for instance:

Winding of transformer,
Cables,
Bus ducts,
Rotating machine winding, etc.

Than what is getting protected by restricting the earth fault current/current through neutral?

The neutral of transformer or generator are grounded through impedance, the principal element of which is resistance. This method is used when the earth fault current would be too large if not restricted (e.g.) MV Generators. Here, a resistor is connected intentionally between the neutral and earth. This is to limit the earth fault current.

Go back to Index ↑

The reasons to limit the earth fault current

The reasons to limit the earth fault current are:

1. In rotating electrical machines like motors and generators, if the earth fault current is high, as in the case of solid earthing, the core damage would be high. To limit the damage to the core, machine manufacturers allow only a limited ground fault current.

This is given in the form of a core damage curve.

2. A typical value would be 25A-100A for 1 second. This value is used as a guide in selecting NGR and setting stator earth fault relays in generator protection.

3. Winding damage in rotating electrical machines is not of serious concern (Though windings are rated for full fault level). The repairs to winding damages can be done by the local re-winder. But, in case of core damage, repairs cannot be carried out at site. The machine has to be sent back to the manufacturer’s works for repairs thus resultingin prolonged periods of loss of production.

Since rotating electrical machines are not present in voltage levels from 22kV onwards, these systems are usually solidly grounded.

4. X0/X1 ratio of the system also decides type of neutral earthing. If the corresponding X0/X1 ratio falls under that predefined range. It is a choice between to weather to deal with higher voltage or higher current while under short circuit. Effectively earthed lowers the over voltage limit of the healthy phases while another phase is short circuited to earth. But the ground fault current is very high.

That means system will need a high capacity breaker but insulation system has to be moderate BIL rating.

But as the neutral to earth impedance increases ground fault current reduces but doing so the over voltage factor will rise even up to 1.73 times! So requires a breaker with low current capacity but a HIGH BIL for all insulation system.

Let us assume that R phase (Phase-1 in figure-4) is shorted to ground than:

If = Current through shorted path (Fault current)
In = Current through neutral to earth connection
Icy = Capacitive current returning via the network Phase-2 (Y phase)-earth capacitances
IcB = Capacitive current returning via the network Phase-3 (B phase)-earth capacitances

Repeating equation-8 we can write:

If = In + IcY + IcB + Ir

Neglecting Ir and substituting the following:

In = -V1/Rn (Negative sign indicates that capacitive charging & discharging current are in phase opposition to current through neutral)

IcY + IcB = Total capacitive charging and discharging current of healthy phase = j3CwV1 from equation-07

Phasor diagram representation will be:

Figure 5 - Phasor Diagram

So finally after substitution of In and IcY + IcB expression for ground fault current in MV system would be:

If = -V1/Rn + j3CwV1 // Equation -10

Magnitude of ground fault current will be:

|If| = |V1|√(I/Rn)2+ 9C2w2

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Top

System earthing at EHV level

In case of HV system (above 33kV) Capacitive ground current is large enough to neutralize the earth fault currents hence no resistance is required in neutral to earth connection.

Solid grounding is universally adopted for following reasons:

1. As we already understood that it is a choice between weather to deal with higher voltage or higher current while under short circuit. At EHV level if we opt for higher voltage than due to higher costof insulation at EHV selection of higher voltage will not be a viable idea.

It is better to opt for higher current by selecting solid grounding.

2. Rotating machines are not present at EHV system so there is no use of limiting the ground fault current as we do in MV system. Even if rotating machines are present because of higher voltage capacitive ground current is also large enough to neutralize the earth fault current.

Go back to Index ↑

References:

Industrial electrical network design guide By Schneider electric
Switchgear protection & power system By Sunil S Rao, Khanna publications
EARTHING: Your questions answered By Geoff Cronshaw
IEEE Recommended Practice for Electric Power Distribution for Industrial Plants

Natural Ventilation Of Power Substation (on photo: Alara-Lukagro transformer doors, type AL-D/T - in compliance with the performance requirements and directives of various power companies)

Thermal Effects In Substation

The operation of a system of natural ventilation is as a result of a decrease in air density as its temperature is raised due to the heat gain from various sources.

This decrease in air density causes a pressure differential which provides the energy to drive the natural ventilation system.

Because the pressure differential developed is relatively small, ventilation louvers and grilles, etc, need to be of a design that offers little resistance to air flow.

To harness the thermal effects and maximise the performance of a natural ventilation system the air inlet openings should be located at low level and the exhaust openings should be as high as possible.

Any ventilation ducts shall have a large cross sectional area and a minimum number of bends to minimise losses. Long horizontal runs of exhaust duct shall be avoided. Due to a natural ventilation system’s sensitivity to the direction of the prevailing wind, the location of ventilation openings on the external face of a building shall be carefully selected to minimise any negative effect.

The benefit of wind effects can be maximised by positioning ventilation openings on adjacent or opposite sides of the building, the inlet on the windward side and the exhaust on the leeward side.

Doors with fixed ventilation lovre (photo by Austral Monsoon Building Products - AMBP)

Reference: Ausgrid NS200 - Major Substations Ventilation Design Standard

Dry-Type Transformer Installation and Ventilation Requirements (On photo dry-type transformer placed and connected)

Installation

Dry-type transformers should be installed over foundations that are properly leveled and capable to withstand their weight.

When a transformer is fitted with wheels, make sure the equipment will be equally supported on its base points in order to assure its stability and to prevent any deformation.

When installing the transformer, the following factors should be carefully taken in account:

1. There should be a minimum spacing of 0,5 m between one transformer and another, and between the transformer and any adjacent wall in order to facilitate the access for inspection and ventilation, depending, however, on the project dimensions and the voltages;

2. The room where the transformer will be installed should be well ventilated as to assure proper natural ventilation, since this is an essential parameter for a proper performance of a dry transformer.

In this regard, it is important that the air inlets are located at the front part of the transformer near the bottom and the air outlets are located at the back part of the transformer, with near the top openings large enough to allow for a circulation of approx. 2,5 cubic meters of air per minute/kW of loss. (See the example calculation below).

Proper ventilation in the transformer room will grant the expected useful life and stable operation either on continuous regime or under momentary overloads.

Figure 1 - Natural transformer ventilation

As normally the natural ventilation is not sufficient, fans can be installed to increase the air flow i n the room according to Figure 2 or, preferably, adopt the refrigeration o f the room where the transformer will operate .

Danger! If the transformer room is going to be air conditioned, make sure the conditioned air will not be directly blown on the transformer, otherwise water condensation can be built on it and can result in the transformer’ s burning.

Figure 2 - Forced transformer Room Ventilation

To calculate the approximate size of the openings or the airflow necessary in the room the following expressions cab be used, considering a difference of 15ºC between the inlet air and the outlet air.

Approximate size of the openings or the airflow

where:

P_t = total transformer losses sinked at 115°C [kW]
S = lower opening surface [m²]
S’ = upper opening surface [m²]
H = distance measured between the middle of the height of the transformer and the middle of the upper opening for air outlet [m]
V = cooling air volume[m³/min]

Example: Installation of two 2.000 kVA dry-type transformers

Typical total losses PT for 2 MVA dry-type transformer at 115ºC = 27kW
Distance H between the middle of the transformer height and the middle of the air upper outlet opening: 1,5m

Calculated area

From the calculated area we know that the installation of forced ventilation in the room will be necessary.

The minimum flow of the fans will be:

Minimum flow of the fans

This example does not consider the presence of a protection cabinet, wich would be put in questi on in the case of a proper room for the transformer installation.

Warning! If the transformer is fitted with protective cubicle, do not replace that Box with another because its ventilation might not be enough for a proper operation of the equipment.

Reference: Instruction Manual For Dry-type Transformers – WEG

What's that hissing, cracking, buzzing noise? (on photo: Corona discharge on insulator string of a 500 kV transmission line)

Corona or Partial Discharge with Buzzing Noise

Corona can be visible in the form of light, typically a purple glow, as corona generally consists of micro arcs.

Darkening the environment can help to visualize the corona. We once attached a camera (set to a long exposure time) to a viewing window in a vacuum chamber to confirm that corona was indeed occurring, and thereby confirming our suspicions.

You can often hear corona hissing or cracking. Thus, stethoscopes or ultrasonic detectors (assuming you can place them in a safe location) can be used to find corona.

In addition, you can sometimes smell the presence of ozone that was produced by the corona. (Who said you don’t use all your senses when troubleshooting?)

The corona discharges in insulation systems result in voltage transients. These pulses are superimposed on the applied voltage and may be detected, which is precisely what corona detection equipment looks for. In its most basic form, the following diagram is a corona (or partial discharge) measuring system.

Partial discharge activity on sharp metal edge (photo by partial-discharge-academy.com)

When corona occurs it creates ozone (detrimental to the human lungs, eyes, etc.), ultraviolet light, nitric acid, electromagnetic emissions and sound.

Ozone is a strong odorous gas that deteriorates rubber-based insulation.

If moisture or high humidity conditions exist nitric acids can also be formed that attacks copper and other metals. The electromagnetic emission can be heard as interference on AM radios and the corona sound can be heard by the human ear and be ultrasonic scanning devices.

Damaged electrical cable due to the partial discharge (photo by JIM CAHILL at emersonprocessxperts.com)

One important point to consider is that unlike infrared that detects heating due to current flow, corona indicates voltage problems and can be present without current flow. High potential in the electrical field is the major dictating factor for its presence.

Corona activity is at its strongest on the positive (+) and negative (-) peaks of the 60Hz cycle.

The effects of corona are cumulative and permanent, and failure can occur without warning.

Corona causes:

Light
Ultraviolet radiation
Sound (hissing, or cracking as caused by explosive gas expansions)
Ozone
Nitric and various other acids
Salts, sometimes seen as white powder deposits
Other chemicals, depending on the insulator material
Mechanical erosion of surfaces by ion bombardment
Heat (although generally very little, and primarily in the insulator)
Carbon deposits, thereby creating a path for severe arcing

How Corona works?

Focussing on corona discharge and surface discharge, i.e. electrical gas discharges occurring in ambient atmosphere, ionisation phenomena are initiated in the high electrical field region respectively resulting from the conductor geometry (wire, point, sharp edge) or from a triple point (metallic conductor / insulation material /gas).

According to the conductor geometry, applied voltage amplitude and polarity, ionisation phenomena will be confined in the vicinity of the high field region or will propagate in gas from this region as transient successive ionisation waves (streamer regime with current pulses associated with the development of filamentary discharges).

In any case, electron in elastic collisions will also lead to gas molecules dissociation and excitation resulting in chemical active species formation and light emission; elastic collision between ions and neutral molecules will result in local gas heating.

Surface partial discharge effect (photo by http://natlfield.com/)

Light, gaseous chemical reactants and heating are consequently evidence of gas discharges.

References:

Corona and Tracking Conditions in Metal-clad Switchgear Case Studies By James Brady, Level-III Certified Thermographer
CHARACTERIZATIONOFMEDIUM VOLTAGE EQUIPMENT AGEING BY MONITORING OF PARTIAL DISCHARGES CHEMICAL AND ACOUSTICAL EMISSION E.Odic*, E.Jouseau**, G. Vivien**, C-S.Maroni**

Network structure example

Network structure:

Example network above consists of:

MV consumer substation;
Two MV ratings: 20 kV and 6 kV;
The main MV switchboard fed at 20 kV can be backed up by a set of four generators. It feeds:

An MV 20 kV network in a loop system comprising three secondary switchboards MV4, MV5 and MV6;
Two 20 kV/6kV transformers in a single line supply system;

The MV main switchboard is made up two bus sections fed at 6 kV by two sources with coupler;
It feeds three MV secondary switchboards and two 6 kV/LV transformers in a single line supply system;
the secondary switchboard MV2 is fed by two sources with coupler and is made up of two bus sections. It feeds two 6 kV motors and two 6 kV/LV transformers in a single line supply system;
the secondary switchboards MV1 and MV3 are fed by a single source. Each feeds a 6 kV/LV transformer and a 6 kV motor;
the main low voltage switchboard MLVS1 can be backed up by a generator;
the main low voltage switchboard MLVS2 is fed by two sources with coupler;
the main low voltage switchboard MLVS3 is fed by a single source;
the motor control centers 1 and 3 are fed by a single source; the motor control center 2 is fed by 2 sources with no coupler.

Reference: Protection of Electrical Networks - Christophe Prévé

Ensuring Proper Grounding

6. Grounding Using Building Foundations

7. Grounding the Substation Fence

8. Special Attention to Operating Points

9. Surge Arrestors Must be Grounded Properly!

10. Grounding of Cable Trays

11. Temporary Grounding of Normally Energized Parts

Introduction

The consumer-service connection

Objective

Test Instruments Required

Commissionig Test Procedure

1. Battery Charger

2. Battery Unit

Acceptance Limits

Introduction

Scope

Circuit configuration

Protective measures

Personal protection

Functional protection

Stresses

Arrangement and modules

Arrangement

Busbars

Circuit breakers

Disconnectors

Earthing switches

Instrument transformers

Cable terminations

Overhead line terminations

Control and monitoring

References:

Distribution Substations

1. Floor plan and incision of a terrestrial distribution substation

2. Single line schematic arrangement

3. Analytical (three-pole) schematic diagram

High Voltage Substation At Rockville Indiana (VIDEO)

Content

Introduction to GIS (Gas Insulated Switchgear)

1. Environmental Concerns

2. Safety Concerns

3. Special Handling Procedures

4. Installation Concerns

5. Operation and Maintenance Concerns

6. End of Life and Recycling Concerns

Conclusion

Content

Type of Capacitor Bank as per Its Application

1. Fixed type capacitor banks

Disadvantages:

Application:

2. Automatic type capacitor banks

Types of APFC – Automatic Power Factor Correction

Advantages:

Application:

Type of Capacitor as per Construction

1. Standard duty Capacitor

2. Heavy-duty

3. LT Capacitor

Selecting Size of Capacitor Bank

Selection of Capacitor as per Non Liner Load

Configuration of Capacitor

1. Star-Solidly Grounded

2. Star-Ungrounded

3. Delta-connected Banks

Effect of series and Parallel Connection of capacitor

Parallel Connection

Series Connection

Fire Detection

Fire Fighting Test – Sulaibiya Z Substation (VIDEO)

Introduction

1. Calculate numbers of pipe earthing

A. Earthing resistance and number of rods for isolated earth pit (without buried earthing strip)

Example:

Example:

B. Earthing resistance and number of rods for isolated earth pit (with buried earthing strip)

Example:

C. Total earthing resistance and number of electrode for group (parallel)

Example:

A. Earthing resistance and number of rods for isolated earth pit
(without buried earthing strip)

B. Earthing resistance and number of rods for isolated earth pit
(with buried earthing strip)

C. Total earthing resistance and number of electrode for group
(parallel)