Protective grounding requirements

Each region implements procedures to ensure the adequacy of the grounds of protection and will periodically review the grounding system in each facility to determine the appropriate size, length, and number (if parallel grounds are required) of grounds protection.
Regions must maintain and periodically update a list of maximum fault currents at each facility or location where Reclamation employees apply protection grounds.
These reviews should be performed every five years1 or earlier if changes in equipment or system conditions require a specific overhaul.
High
Requirements
Earthing of cables and associated cables Earthing the equipment mus

meet the following requirements:

1
Capable of directing the maximum fault current that could occur at the earthed work site if the de-energized line or equipment is energized from any source and during fault resolution hours
Earth or jumper that is sized to conduct the maximum fault current available must be sufficient to safely conduct currents from other hazardous energy sources, including steady-state currents induced by electromagnetic coupling from lines or live equipment nearby.

2
Capable of withstanding the maximum available fault current including shifted DC-current due to waveform asymmetry for high X / R ratio values ​​of fault circuit impedance Refer to Section 5 for cable ampacity information and section 6 for conductor sizing procedure.

3
Capable of withstanding a second activation within 30 cycles of inadvertent first activation.

4
Applied on the job site in such a way that the worker exposure or the body contact voltage does not exceed the values ​​given in paragraph 4.1 as long as the earth cables conduct a fault current. Refer to Section 6 for the procedure to determine operator exposure voltage.

5
Connected directly to the equipment, bus or conductor to be grounded. No impedance or device (circuit-breaker, disconnector, transformer, siphon, etc.) must be authorized in series between the point of connection of the protective earth and the location of the contact by the workers.

grounding requirements
Protective grounding requirements

6
Be easy to apply, meet the requirements of field application conditions, use minimal time and preparation for installation, and cover a wide range of uses. Standardization, where possible, is desirable at each site to minimize the number of sizes and types.

7
Manufactured as an assembly of appropriately sized components (conductor, ferrules, hose clamps) to withstand the thermal and electromechanical stresses imposed when conducting a fault current.

8
Stored and transported properly to prevent damage and maintained in good working order.

9
Equipment and terminal ground switches are not a substitute for reasons of personal protection. However, earth switches can be closed in parallel with protective grounds in order to reduce fault current through the earth cables and lower the exposure voltage of workers on the job site.
The earth cables must be sized for the maximum fault current available, without any reduction in current due to closed earth switches.
Certain types of earthing switches are designed for static earthing of equipment and do not withstand fault currents. Check the characteristics of the earth switch before closing in parallel with the protective earth.

10
Temporary removal of protective grounding system for unauthorized testing of de-energized equipment. Rather, protective grounds should be installed so that de-energized equipment under test is safely isolated from grounded circuits for the duration of the test.

HV lightning surge control methods

introduction
For well-shielded transmission lines, the return condition, near the substation, is of prime importance in determining the location and number of surge arresters needed to coordinate the isolation of the substation against HV lightning surges.

Hubbell’s best transmission protecta-lite line arrester line has been simplified with fewer parts and less risk of parts wear. Several steel components have been replaced with a copper bracelet. The strap makes installation easier and reduces wear points. Vibration and wear are greater on transmission line arresters because they are more exposed to wind and vibration.
The risk of a back flashover can be reduced by keeping tower foot impedances to a minimum, especially near the substation (first five to seven turns ).
The terminal tower is usually bonded to the substation earth mat and has a very low earth impedance ( 1 ohm ).
However, the ” gaping ” procedure on the first three or four turns where the distance between lines is reduced to reduce incoming surges will increase the risk of shutting down in ‘Backflashover.

Location of surge arresters
Considering the system when the transmission line is directly connected to a 420 kV GIS (gas-insulated switchgear), a computer model can be created to take into account the parameters described previously.
A transient study would reveal the level of lightning current needed to cause a backlash.

HV lightning surge
HV lightning surge control

Then according to the number of lines flashing 100 km/year calculated for the transmission line and using the probability curve for the amplitude of the lightning current, a return time for this running current can be evaluated ( Le. 1 to 400 years, 1 to 10 years, etc. ) in, for example, the first mile of the line.
The voltage that then arrives at the substation can be evaluated and compared to the LIWL ( Lightning Impulse Withstand Level ) for the substation equipment.
The open-circuit breaker condition should be investigated here because if the line circuit breaker is open, the overvoltage will “ double ” at the open terminal. Different levels of running current can be simulated at different locations of the tower and the resulting surges from the substation can be evaluated.
If it is considered that the LIWL of the substation will be exceeded or if the margin between the calculated overvoltage levels and the calculated pressure drop level is insufficient to generate an acceptable risk, then HV lightning surge protection must be applied.
The rating of MOA ( Metal Oxide Surgearresters ) will have been evaluated from TOV ( Temporary Surge ), and from the manufacturer’s data, a surge arrester model can be included in the system model. The repetition of the various studies reveals the level of protection of the surge arrester and makes it possible to assess the safety factor for this system configuration.
IEC 60071 recommends a safety factor of 1.25 for equipment at 420 kV (safety factor = LIWL / protection level).
The surge suppressor current calculated for this condition should be the “worst-case” and can therefore be used to estimate the surge arrester-rated discharge current requirement ( 5kA, 10kA, or 20kA ).
( IEC 60091-1 is the international standard for surge arresters [16], and an accompanying guide with detailed information on the use of surge arresters is available.
To fully utilize the MOA Protection Level, the surge arrester should be placed as close as possible to the equipment to be protected.
In the case of the circuit breaker open, this distance can be between 10 and 20 m.
Depending on the rate of rising of the surge voltage, a voltage greater than the residual voltage at the location of the surge arrester will be detected across the open circuit breaker. This should be taken into account when evaluating the overvoltage of the substation.
the overvoltage profile of the SIG (Gas Insulated Switchgear) with the line circuit breaker closed. It shows that additional surge arresters may be needed due to the distances involved in the configuration of the substation.
It follows that surge arresters have a ‘ protection length ‘ which is sensitive to the rate of rising of the incoming surge voltage, which should be taken into account when evaluating the lighting surge on equipment remote from the surge arrester.

Fire-fighting precautions in the power substation

The heat from the failed capacitor bank completely destroyed the main inbound 400-volt distribution board of a large shopping mall and spread the fire around the substation. The radiant heat released by this fire also destroyed the control panel and the emergency generator control panel located directly opposite.
Introduction to fire-fighting protection
Plant layout and building design play a major role in reducing the spread of fire and the effects of explosions.
For example, equipment and buildings should be arranged so that they have vents that rupture instead of allowing an explosion to damage the main fabric. Site supervisors should ensure that these vents are never blocked. In fire prevention, cleanliness and neatness are very important, as is the careful maintenance of tools.
Most fires are caused either by negligence or faulty equipment.
The choice of fire-fighting equipment depends on its suitability for electric fires, but also on the cost and extent of the power supply to the point. The types of portable manuals are as follows: halon gas of various kinds, chemical carbon dioxide foam, and powder.
Use of fixed sprinkler systems for water, carbon dioxide, and halon gas. Halon gas and carbon dioxide can suffocate personnel trapped in the landfill area.
Strict precautions must therefore be taken to lock the equipment in the presence of personnel. There is also the use of sand, blankets, and fire hoses. Fire doors are a very important means of limiting the spread of fire and ventilation systems should also be provided with automatic shutdown if not with automatic dampers in the event of a fire. Fire drills are also important and should not be overlooked on a construction site.
Wiring can also be a cause of serious fires with the risk of significant damage to the installation and danger to personnel. Low Smoke and Smoke Developed (LSF) cables are now available in a variety of forms, most of which will reduce flammability and release less toxic gases when heated.

the DC-Provisions ( UPS Batteries ) are a particularly important and vulnerable part of any facility. They are generally derived from stationary batteries which give off flammable and toxic gases.
Batteries should be in a separate room with an acid-resistant floor, special fixtures, a suitable sink, and an adequate water supply. It is wise to have an acid-resistant drainage system. The room should be well ventilated, but direct sunlight should not be allowed on the cells.

Considerations for fire-fighting safety in substations
The main fire risks and detection difficulties in substations arise from the following factors:
The formation of electric arcs and the formation of static electric charges in equipment.
Overheating of electrical control equipment, switchgear, and wiring.
Once initiated, a fire can spread rapidly due to the presence of large amounts of combustible materials in the form of hydrocarbons contained in wiring and insulation.
The environment in areas of uninterrupted power supply (i.e. the battery room) can become explosive due to the build-up of high concentrations of hydrogen.
Since substations are generally unmanned, early intervention by staff may not be possible in the event of a fire.

Zones Essential advised
Switch/relay room Ceiling √
Cabinet In / On √
Control room Ceiling √
Cabinet In / On √
Empty floor √
Return vent / duct √
Battery room Ceiling √
Return vent / duct √
Cable trench √
The high air movement caused by air conditioning dilutes and disperses the smoke.

Fire-fighting
Fire-fighting precautions in the power substation


Much of the mission-critical equipment is housed Ceiling mounted detectors can take some time to detect fires in cabinets and installation cabinets, especially since cabinet fires are typically long-lasting.
Underground trenches connecting the main areas of the substation are considered hostile environments. The high levels of background pollution present in these areas will affect the proper functioning of conventional detectors and constitute a source of false alarms.

Designed for effective fire protection
Protection zones
Table 1 below shows the operational areas of a substation where protection is required.

Switch/relay room
The switch room accommodates high-density electronic equipment housed in cabinets and automated switches. The equipment in the cabinet performs the main functions of the installation and constitutes the switching interface between the control room and the equipment in the field.
The area can also accommodate a large amount of counting and recording equipment. Due to the high volume of critical electronic equipment, it is essential to detect a fire before compromising the operation of the plant.

Control room
The control room is the main command center of the substation. The entire operation of the site is monitored and controlled from this central location.
A control room can range from a small, unventilated room that is rarely occupied, to a large air-conditioned area containing many staff and electronic equipment ( PCs, control panels/consoles, electrical and electronic switching devices, under-wiring). floor, etc. ).

Battery room
The lead-acid battery room or nickel-cadmium batteries for the uninterruptible power supply (UPS) of the substation.
Battery rooms may consist of a slightly corrosive atmosphere ( sulfuric acid ). It is recommended to use a network of polymer sampling pipes in order to eliminate the risk of corrosion. In addition, it might be necessary to incorporate a Chemical Filter – a special filter designed to absorb corrosive gaseous contaminants.

Cable trench
A cable trench is located under the switch/relay room, control room, and battery room to house the communication, control, and power cables between the substation operating areas, as well as the transport of the energy to external high voltage switching towers.
The most effective way to protect a cable trench is to install a network of sample pipes in the top 10% of the trench.

An overview of the earthing system

Topics covered an earthing system
Firmly grounded system
Resistance Grounded-System
Reason for resistance to earthing
Grounding the system at the EHV level

Firmly grounded system
Suppose Phase R is shorted to ground that:
Si = Current on short-circuited path ( Fault current )
In = Current flowing through the neutral connection to earth
Ice = Capacitive current returned via the Phase-2 network ( Phase Y ) – capacitors
IcB = Capacitive current returned via the Phase-1 network ( Phase B ) – capacitors
We can write:
Si = In + IcY + IcB + Ir 
Where Ir = Current returned by the network insulation resistance which is always negligible
In the event of LV, the system voltage available between phase and earth is 415 / 1.732 = 240V. The resistance of the earth plate, earth connections, etc.… is of the order of 1.5 Ohms so that the earth current is limited to approximately 240 / 1.5 = 160 amps. This magnitude is not very high and no intentional impedance is needed in a neutral connection to the earth.
At 415V the level capacitive earth currents are not significant and therefore we can write:
Si = In for solidly earthed LV system // equation-09

Resistance Grounded System Or Earthing system

In the case of an MV system ( 3.3 kV to 33 kV ), the voltage between phase and earth is high. Also capacitive load current is not large enough to compensate for the same, so the earth fault current may be excessive.
Therefore, the resistor is connected between neutral and earth. The current to neutral is limited to 100-400 amps.

Limitation of earth fault / neutral current
Although all MV level power system components are rated at full MV system fault level, for example:
Transformer winding,
Cables,
Bus ducts,
Machine rotation, etc.
What is protected by limiting the earth fault current / the current through the neutral?
The neutral of the transformer or generator is earthed by the impedance, the main element of which is resistance. This method is used when the earth current is too high if it is not restricted (for example) by MV-generators. Here, a resistor is intentionally connected between neutral and earth. This is to limit the earth fault current.

Reasons to limit the earth current
The reasons for limiting the earth fault current are:
1. In rotating electrical machines like motors and generators, if the earth fault current is high, such as in the case of continuous earthing, the damage to the core would be great. To limit damage to the core, machine manufacturers only allow a limited earth fault current.
This is given in the form of a heart damage curve.

earthing system
electrical-earthing-service


2. A typical value would be 25A-100A for 1 second. This value serves as a guide for selecting NGR and setting stator earth fault relays in generator protection.
3. Damage to windings in rotating electrical machines is not a serious problem (although windings are classified for the full fault level). Winding damage repairs can be done by the local winder. However, in the event of damage to the heart, repairs cannot be made on site. The machine must be returned to the manufacturer for repair, resulting in prolonged production losses.
Since rotating electrical machines are not present at voltage levels above 22 kV, these systems are usually solidly fused.

  1. System X0 / X1 ratio also decides the type of neutral earthing system. If the corresponding X0 / X1 ratio is within this predefined range. It is a choice between weatherproofing to cope with higher voltage or higher current in the case of a short circuit. Effectively earthing reduces the overvoltage limit of healthy phases while another phase is short-circuited to earth. But the earth fault current is very high.
    This means that the system will need a large capacity circuit-breaker, but the isolation system will need to have a moderate BIL rating.
    But as the neutral impedance to the earth increases, the earth faults current decreases, but the surge factor even increases up to 1.73 times! This, therefore, requires a circuit breaker with a low current capacity but a HIGH BIL for any insulation system.
    Suppose Phase R ( Phase 1 in Figure 4 ) is shorted to ground that:
    Si = Current on short-circuited path ( Fault current )
    In = current flowing through the neutral connection to the earth
    Ice = Capacitive current returned via the Phase-2 network ( Phase Y ) – capacitors
    IcB = Capacitive current returned via the Phase-3 network ( Phase B ) – capacitors
    By repeating Equation 8, we can write:
    Si = In + IcY + IcB + Ir
    Ignore Ir and replace it with the following:
    In = -V1 / Rn ( The negative sign indicates that the capacitive charge and discharge current is in phase opposition with the current flowing through neutral )
    IcY + IcB = Total capacitive load and healthy phase discharge current = j3CwV1 from equation-07
    The representation of the phasor diagram will be:

So, finally, after substituting the expression In and IcY + IcB for the earth fault current in the MV system, we obtain:
If = -V1 / Rn + j3CwV1 // equation -10
The magnitude of the earth fault current will be:
| If | = | V1 | √ (I / Rn) 2+ 9C2w2

Grounding the system at the EHV level
In the case of the HV system ( above 33kV ), the capacitive earth current is large enough to neutralize earthing system fault currents, therefore, no resistance is required in the neutral earth connection.
Strong foundations are universally adopted for the following reasons:
1. As we already understood that it is a choice between the weather conditions to deal with higher voltage or higher current in case of a short circuit the EHV level, if we go for a higher voltage than due to the high cost of insulation, selecting a higher voltage will not be a viable idea.
It is better to go for a higher current by choosing a solid ground.
2. The rotating machines are not present in the EHV system. It is therefore not useful to limit the earth fault current as in the MV system. Even though rotating machines are present due to higher voltage, the capacitive earth current is also large enough to neutralize the earth fault current.

What are the main advantages of HVDC transmission over HVAC?

AC as a preferred option
Although the alternating current is the dominant mode for the transmission of electrical energy, in a number of applications the advantages of HVDC technology make it the preferred option over alternating transmission.
Examples include:
Submarine cables where high capacity causes additional AC losses ( eg the 250 km Baltic cable between Sweden and Germany ).
Mass transmission over long distances, point to point, without intermediate socket, for example in remote areas.
Increase the capacity of an existing electrical network in situations where the installation of additional cables is difficult or expensive.
Allowing the transmission of power between unsynchronized AC-distribution systems.
Reduce the profile of cables and pylons for a given power transmission capacity, as the HVDC can carry more power per conductor of a given size
Connect a remote power plant to the distribution network; for example, the bipolar line of the Nelson River in Canada ( IEEE 2005 ).
To stabilize an electrical network mainly without increasing the maximum potential short-circuit current.
Reduce corona loss ( due to higher voltage peaks ) compared to HVAC transmission lines of similar power.
Reduce the cost of the line, because HVDC transmission requires fewer conductors; For example, two for a typical two-pole HVDC line, compared to three for a three-phase HVDC.
HVDC transmission is particularly advantageous in submarine power transmission. Long submarine AC cables have high capacity.

Example (VIDEO)
500 MW HVDC light transmission interconnection
ABB has commissioned a 500 megawatt HVDC Light (VSC) transmission interconnection connecting the Irish and UK Grids, enabling cross-border energy flows and improving grid reliability and security of electricity supply.
The East-West interconnector includes a 262 km high voltage cable link, 186 km of which is submarine.

Therefore, the current required to charge and discharge the capacitance of the cable causes additional power losses when the cable is under AC voltage. while this has minimal effect on DC transmission. In addition, alternating current is lost due to dielectric losses.
In general applications, HVDC can carry more power per conductor than AC, because, for a given power, the constant voltage in a DC line is less than the peak voltage in an AC line.
This voltage determines the thickness of the insulation and the spacing of the conductors. This lowers the cost of HVDC transmission lines compared to alternative transmission and allows transmission line corridors to carry higher power density.

advantages of HVDC
hvdc-transmission-system


An HVDC transmission line would not produce the same type of very low frequency electromagnetic (ELF) field as an equivalent AC line. Although there are concerns about the potential adverse effects of such fields, including the suspicion of increased leukemia rates, the current scientific consensus does not consider the sources of ELF fields and their associated fields to be harmful.
Deployment of HVDC equipment would not completely eliminate electric fields, as there would always be DC electric field gradients between conductors and earth. These fields are not associated with health effects.
Because HVDC allows the transmission of power between unsynchronized AC systems, it can help increase system stability. It does this by preventing cascading outages from spreading from one part of a larger power transmission network to another while allowing the import or export of energy in the event of outages. less important.
This feature has encouraged the wider use of HVDC technology for its stability advantages alone. The energy flow on an HVDC transmission line is defined with the help of converter station control systems. The energy flow does not depend on the mode of operation of the connected power systems.
Thus, unlike HVAC links, intersystem HVDC links can have arbitrarily low transfer capacity, thus eliminating weak tie problems, ”and lines can be designed based on optimal power flows.
Likewise, the difficulties of synchronizing different operational control systems of different power systems are eliminated. Fast-acting emergency control-systems on HVDC transmission lines can further increase the stability and reliability of the power system as a whole. In addition, power flow regulation can be used to dampen oscillations in power systems or in HVAC lines in parallel.
For example, the rapidly growing Indian power system is being built in the form of several interconnected regional power systems with HVDC transmission lines and back-to-back converters with centralized control of these HVDC elements (Koshcheev 2001).
Likewise, in China ± 800 kV HVDC will be the main one. This mode is used to transmit large capacities over very long distances from large hydroelectric and thermal bases. Other applications concern long-distance transmission projects with few power connections along the line (Yinbiao 2005).

Types of surge arresters and auxiliary equipment

Surge arresters were installed at the Kingston substation in 1928.
Almost 100 years ago, sets of electrodes (rod, sphere, or pipe) were used to limit surges on equipment (Sakshaug, 1991). Some of these systems, particularly the broken piping, may still be in service today. However, the voltage thinning characteristic of the gap versus time before surge does not match well with the resistance characteristics versus the front of most insulators; that is, it is difficult to coordinate.
The next evolutionary step was to add a resistive element in series with the gap, in order to limit the following current after a stop discharge operation. Hopefully, the current limiting would allow the stopper to release that current, instead of relying on a circuit-breaker or fuse nearby. At the same time, the voltage of the resistor during discharge should be low enough that no excessive voltage can appear on the protected equipment.
These competing requirements have led to the use of expensive and complicated nonlinear resistive elements, some involving both solid and liquid materials with high float loads.
From around 1930, silicon carbide (SiC) was used for non-linear resistive elements, leading to much better protection characteristics. Since SiC would conduct significant current at rated voltage, it was necessary to provide an ignition gap that prevents conduction at rated voltage. After discharge of the arrester, these spaces must be sealed against the current, otherwise, the arrester will have thermal failure. In the mid-1950s, active vacancies were created for SiC surge arresters.

Surge Arrester
Surge-Arrester


These active lacunae contain auxiliary elements which:
Preionize the sparkover space to achieve better levels of surge protection and
Extend the power arc and move its attachment points for better interrupt performance.
SiC surge arresters have been successfully applied on transmission systems up to 345 kV, but some limitations have arisen with respect to surge protection, energy discharge capability, and decompression capability.
Having both vacancies and silicon SiC blocks, the height of the stopper increased until it reached the point where it was difficult to release the built-up pressure in the event of failure, which limited the discharge value pressure of the shut-off device.
Due to their discharge characteristics vs frequency or time to time, SiC surge arresters have been optimized for lightning. They were less effective for steep edge surges and slow switching surges.
In the mid-1970s, metal oxide arresters were developed into commercial products (Sakshaug et al., 1977). Metal oxide blocks are much more nonlinear than silicon carbide, so they only conduct a few milliamps at rated AC voltage. It eventually became possible to do without empty spaces altogether, although older models made use of them
Metal oxide arresters have several major advantages over previous silicon carbide arresters:
Active deviations are not necessary, which improves reliability
Metal oxide can discharge much more energy per unit volume than silicon carbide
Metal oxide provides better protection than silicon carbide over the surge wavefront range
The decrease in the height of the limiter, caused by the elimination of empty spaces, leads to higher pressure relief rates
Virtually all new applications will use metal oxide arresters. The metal oxide enabled new applications, such as series capacitor protection and overhead line switching surge control, which was not possible with silicon carbide.
However, many silicon carbide arresters are still in use. Some researchers have found high failure rates of the silicon carbide arrester, due to moisture penetration, after several years of service on medium voltage distribution systems. This experience does not necessarily apply to surge arresters in substations. If such problems arise, it would make sense to routinely replace silicon carbide arresters on a system. Otherwise, assuming the initial request is correct, the old silicon carbide arresters could remain in service.

auxiliary equipment
auxiliary equipment


The general use of surge voltage surge arresters. The dotted design (1a) applies to silicon carbide, while the continuous design (1d) applies to the latest generation of metal oxide. A manufacturer used the shunt gap (1b) in the first metal oxide arresters. In steady-state, the two non-linear elements withstand the nominal voltage, thus reducing the current slightly. During a surge discharge, the shunt gap would produce a bypass effect to bypass the smaller section of metal oxide, thereby reducing the discharge voltage and providing slightly better protection Another manufacturer used the gap in series with capacitive dimming (1c) in the first metal oxide arresters. In steady-state,
During a sudden discharge, the gap forms “Immediately” due to capacitive gradation. The latest generations of metal oxides do not need these shortcomings, although it is planned to use them to achieve specific purposes (eg coordination of surge arresters, resistance to temporary overvoltages). The surge protector must be installed on something, such as a transformer tank or a pedestal. It must also be connected to the protected system, usually via wire or cable. We will see later that these connections have important effects on overall protection, especially for strong peaks.
The pedestal and lead, length and location, should be considered part of the overall installation of the surge arrester. On distribution systems, a ground cable disconnector is often used with the surge arrester. If the arrester fails and conducts current stably, the disconnect switch will detonate and disconnect the base of the arrester from the ground. It should happen in about 1 second or faster.
The surge arrester can then remain connected to the system until maintenance personnel has the opportunity to replace it. No circuit breaker or fuse should be used to isolate the faulty surge arrester; if the surge arrester is the only thing that has failed, no customer should lose their electrical service. Of course, the surge arrester does not provide any surge protection during this period with its ground wire disconnected. There would be a clear visual indication that the ground wire has been disconnected; it will be “suspended” below the stopper. Regular visual inspections are necessary to maintain surge protection whenever earthing switches are used.
Many surge-protectors installed in substations or industrial facilities have been fitted with “‘surge meters”. “
These are accessories to be installed in the connection of the earth wire of the surge arrester. Two functions can be provided:
A steady-state current meter calibrated in mA. If this current increases over time, it may indicate thermal damage to the surge arrester. However, the presence of harmonics or external leakage currents would complicate the assessment.
A counter indicates the number of surge current discharges above a certain threshold, which may depend on the frequency or the time before. Even if the count is accurate, it does not mean that the discharge voltage has reached a particular level during these events.
To effectively use surge counters, it is important to follow the readings regularly, beginning with commissioning.

Total losses in power distribution and transmission lines

1.Continuation of the first part: Total losses in power distribution and transmission lines
There are two types of power distribution and transmission lines:
Technical losses ( explained in the previous part )
Non-technical losses ( commercial losses )

  1. Non-technical (commercial losses)
    The non-technical losses are at 16.6% and related to the meter reading, defective meter and meter reading error, billing of customer’s energy consumption, lack of administration, financial constraints, estimate of energy supply. unmetered energy as well as energy theft
    Main reasons for non-technical losses
    How to reduce technical losses?
    How to reduce non-technical losses?

Main reasons for non-technical losses

  1. Theft of power
    Electricity theft is the energy supplied to customers that are not measured by the energy meter for the customer.
    The customer tempers the meter by means of mechanical shaking, placing strong magnets, or disturbing the rotation of the disc with foreign bodies, stopping the meters remotely.

2.measurement inaccuracies
Losses due to measurement inaccuracies are defined as the difference between the amount of energy actually supplied by the meters and the amount recorded by the meters.
All energy meters have some level of error, which requires standards to be set. Measurement Canada, formerly Industry Canada, is responsible for regulating the accuracy of energy meters.
The legal requirements relating to meters are within an accuracy range of + 2.5% and – 3.5%. Old tech counters normally started life with negligible errors, but as their mechanisms got older they slowed down, resulting in under-recording. Modern electronic meters do not under-register with age in this way.
As a result, with the introduction of electronic-meter technology, there should have been a gradual reduction in meter errors. The increase in the replacement rate of mechanical meters is expected to accelerate this process

  1. Unmeasured losses for a very small load
    Unmeasured losses are situations where energy use is estimated instead of being measured with an energy meter. This happens when the loads are very small and the installation of energy meters is economically impractical.
    Examples of this are street lights and cable TV amplifiers.
  2. Unmeasured supply
    One of the main reasons for the loss of business is the unmetered supply of agricultural pumps. In most states, the farm rate is based on the unit horsepower (HP) of the engines. Such power charges are sanctioned with low charge declarations.
    Once the connections are released, consumers increase their connected loads, without obtaining the necessary sanction, for increased load, from the utility. Another estimate of the energy consumed during an unmetered supply has a large impact on the estimate of T&D losses due to the errors inherent in the estimate.
    Most utilities deliberately overestimate unmetered agricultural consumption in order to obtain a higher subsidy from the state government. and also project. reduction of losses. In other words, the higher the estimates of unmeasured consumption, the lower the T&D loss figure and vice versa.
    In addition, the correct estimate of unmeasured consumption by the agricultural sector largely depends on the type of crop, the level of the water table, seasonal variations, hours of operation, etc.
  3. Meter reading error
    A properly calibrated meter should be used to measure electrical energy. The defective energy meter must be replaced immediately. Reasons for faulty meters are burning of meters, meter terminal box due to heavy load, incorrect transmission ratio, reduction in registration, incorrect testing, and calibration of meters.
  4. Billing issues
    Defective and untimely invoices should be part of the non-technical losses.
    Normal billing complaints are not receipt of an invoice, late receipt of an invoice, receipt of a bad bill, wrong meter reading, wrong rate, wrong.
power distribution
power distribution and transmission lines

How to reduce technical losses?

  1. Conversion of LV line to HV line
    Much low voltage (430 V) distribution pockets in town are surrounded by higher-voltage power lines. At this lower voltage, more conductor current flows for the same power output, resulting in increased i 2 R losses.
    Conversion of the old LV (430 V) feeders to higher voltage power supply, the investment cost is high and is often not economically justifiable, but if some parts of the LV (430 V) primary power supplies are in relatively good condition, the installation of several step-down power transformers on the periphery of the 430-volt zone will reduce load current losses at several points ( i.e. reduce the total conductor current and the distance traveled by the current to serve the load ).
  2. Large commercial/industrial consumers get a direct line from the charger
    Design the distribution network system in such a way that, if possible, large consumers will get the feeder line directly.
  3. Adoption of high voltage distribution service (HVDS) for agricultural customer
    In direct high voltage service (HVDS) , 11KV line given directly to the group of 2 to 3 agricultural customers for a group of agricultural pumps and small distribution transformer (15KVA) for these 2 to 3 customers via smaller LT distribution lines (almost negligible ).
    In HVDS, the distribution losses are due to minimum distribution line length, high power quality without voltage drop, less motor burnout due to less voltage fluctuation, and good power quality, to avoid transformer overloads.
  4. Adoption of Arial Beam Driver (ABC)
    When the LT line is not totally avoidable, use Arial Bundle Conductor to minimize errors in the lines, to avoid direct line theft (line tampering ).
  5. Reduce the number of transformers
    Reduce the number of processing steps. Transformers are responsible for almost half of network losses. High-efficiency distribution transformers can have a big impact on reducing distribution losses.
  6. Use the charger at its average capacity
    By overloading the distribution, the distribution losses increase.
    The higher the load on a power line, the higher its variable losses. It has been suggested that the optimum average utilization rate of distribution network cables should be as low as 30% if the cost of losses is taken into account.
  7. Replacement of old conductors/cables
    By using more the cross-section of conductors/cables, the losses will be less, but at the same time cost will be high; thus, in forecasting the future load, an optimal balance should be maintained between investment costs and network losses.
  8. Feeder renovation / improvement program
    Renewal of the transmission and distribution line depending on the load.
    Identification of the weakest areas of the distribution system and strengthening/improvement of these.
    Reducing the length of LT lines by relocating distribution substations or installing new additional distribution transformers.
    Installation of low-capacity distribution transformers in each place of consumption instead of forming clusters and replacing distribution transformers with lower no-load losses, such as amorphous core transformers
    Installation of shunt capacitors to improve the power factor.
    Installation of single-phase transformers to supply domestic and non-domestic load in rural areas.
    Supply of small 25 kVA distribution transformers with a distribution box fixed to its body, allowing the installation of meters, an MCCB, and a capacitor
    Direct insulated service line for every agricultural consumer from distribution transformers
    Due to the feeder refurbishment program, production and processing losses can be reduced by 60-70% to 15-20%.
  9. A program targeting the industrial and urban sectors
    Separation of rural feeders from industrial feeders.
    Instant release of new industrial or HV connections.
    Identify and replace slow and slow meters with electronic type meters.
    Industrial and agricultural consumers adopt a consumer, a transformer system with a meter should be introduced.
    Change of the old service line by shielded cable.
    Due to the food center refurbishment program, D&D losses can be reduced from 60-70% to 15-20%.
  10. Strictly follow the preventive maintenance program
    Required to adopt a preventive line maintenance program to reduce losses due to faulty or leaking pipe parts. Required gaskets, wire to reduce leakage current.

How to reduce non-technical losses?

  1. Make distribution line mapping/data
    Mapping of the complete primary and secondary distribution system with all parameters such as conductor size, line length, etc.
    Compilation of data regarding existing loads, operating conditions, forecast of planned loads, etc. Preparation of long-term plans for the strengthening and phased improvement of the distribution systems as well as the transmission system.
  2. Implementation of energy audit programs
    It should be mandatory for all major industries and utilities to perform energy audits of their system.
    Additional action in time for the initiation of studies To ensure that losses incurred by technical and non-technical expenses are realistically assessed, utilities should also identify areas with high losses and take corrective measures to reduce them.
    The realistic assessment of a utility’s T&D loss depends largely on the sample size chosen, which in turn influences the desired level of confidence and the tolerance limit of variation in the results.
    In view of this, it is essential to set a limit on the sample size for a quick and realistic estimate of losses.
  3. Mitigate power theft by checking drives
    Electricity theft is a major problem with all-electric utilities. The state government needs to strictly regulate the theft of power. India’s Electricity Law has been amended to make stealing and reducing energy an offense punishable by death with a punitive sanction of up to three years in prison.
    The impact of theft is not limited to loss of income, it also affects the quality of electricity, resulting in low voltages and voltage dips.
    Required to install proper seal management at Meter terminal, CT / PT terminal to prevent power theft. Identify the power flight area and needed to speed up the power flight check commands. Installation of medium voltage distribution networks (MVD) in areas exposed to theft, with direct connection of each consumer to the low voltage terminal of the supply transformer.
    All existing unmetered services should be stopped immediately.
  4. Replacing the faulty/slow energy meter
    It is necessary to replace the faulty or slow meter with a distribution agency to reduce unmetered electrical energy.
    Required to test the multimeter periodically for the purpose of testing the accuracy of the meter. Replacement of old erroneous electromechanical meters with precise electrostatic meters (micro-presser base) for precise measurement of energy consumption
    Use the meter boxes and seal them properly to ensure that the meters are properly sealed and cannot be tampered with.
  5. Ease of invoice collection
    Increase the number of invoice payment cells and increase the number of drop boxes in all collection areas
    The electronic payment system provides further relief to the customer for paying invoices and the sourcing agency will get the payment from the customer on a regular and prompt basis.
    Effectively disconnect the link of the defaulting customer who does not pay the invoice rather than giving them the option to pay the invoice
  6. Reduce the flow areas of the sub-division
    Collection of old debts in certain cases through legal actions, communications, and legal proceedings. Make sure that the police intervene if necessary to disconnect the connection of the faulty consumer.
  7. Watchdog effect on users
    Users should be aware that the Distribution Agency can monitor consumption at its convenience. This allows the company to quickly detect any abnormal consumption due to the modification or bypass of a meter and allows it to take corrective measures.
    The result is consumer discipline. This has proven to be extremely effective with all categories of large and medium-sized consumers with a history of electricity theft. They stop stealing as soon as they realize that the utility has the means to detect and register it.
    These measures can significantly increase the revenues of non-technical high-loss utility companies.
  8. Scheduled loss reduction
    Increased supply hours for domestic Agriculture and Rural consumers have resulted in increased losses

The setting ranges of the time relays are explained in detail

Time delay
Time delay relays are used in control-switching operations involving a time delay. Most of these time relays have multiple setting ranges and are explained below.
Definition of the deadline
Timed relays carry out the activation or deactivation delay. An arrow is used to indicate the timer function. An arrow pointing up indicates a timing action with activation delay, while an arrow pointing down indicates a timing action without delay

Both delayed and delayed timers can turn their loads on or off, depending on how the timer output is wired into the circuit. The term “switch-on delay” indicates that a preset time must elapse after the timer receives a signal to be activated before the timer contacts change.
The term “off delay” indicates that a preset time must elapse after the timer receives a deactivation signal before the timer contacts change state.

Self-timer closed timer timed
The following illustration shows an example of a Delayed Close Timer, also referred to as a Normally Closed Timer NOT C ) Timer. In this example, the time delay relay ( TR1 ) has been set for a 5-second time delay.

When S1 is closed, timer TR1 starts timing. After 5 seconds, TR1 the contacts close and the pilot light PL1 lights up. When S1 opens, timer TR1 deactivates, and the TR1 contacts open immediately, extinguishing pilot PL1.

Self-timer, open timer timed
The following illustration shows an example of a programmed opening timer, also known as a programmed opening normally closed ( NCTO ) timer. The timing relay ( TR1 ) has been set for a 5-second delay.

When S1 closes, timer TR1 energizes. After 5 seconds, the TR1 contacts open and the PL1 pilot light goes out. When S1 opens, timer TR1 deactivates, and TR1, the contacts close immediately, lighting the pilot light PL1.

setting ranges of the time relays
setting ranges of the time relays

Out of time, timed opening
The following illustrations show an example of a programmed opening timer, also called a normally programmed opening delay (normally NOTO ) timer. The timing relay ( TR1 ) has been set for a 5-second switch-off delay.
When S1 closes, opens TR1 the contacts open immediately and the pilot light PL1 lights up.

When S1 opens, timer TR1 starts timing. After 5 seconds, TR1 TR1 contacts open and pilot light PL1 off.

Out of time, closed on time
The illustration below shows an example of a delayed close timer, also referred to as a normally closed timer ( NCTC ) timer. The timing relay ( TR1 ) has been set for 5 seconds.
When S1 closes, TR1 the contacts open immediately and the pilot light PL1 turns off.

When S1 opens, timer TR1 starts timing. After 5 seconds, timer TR1 the contacts close and the pilot light PL1 lights up.

Instant contacts
Time delay relays can also have instantaneous normally open or normally closed contacts. In the following example, when switching S1 closes, TR1 the instantaneous contacts close immediately and the pilot light PL1 lights up.
After a predefined delay, TR1 the synchronization contacts close and the night light PL2 lights up.

The main components of an oil circuit breaker and how it interrupts the arc

This is a 230,000-volt circuit breaker. We are using it on a 138 kV system at this station. Today I had to hang up the bus cables. We took them apart for the maintenance of the circuit breaker. Each of these tanks holds approximately 2,500 gallons of mineral oil. 2800PSI Hydraulic pressure activates the circuit breaker. Just a little beefier than the little puzzle on your home-panel

They are simple in construction. The main parts of an oil circuit-breaker excluding the poles are the base frame, the drive which is constructed as a stored energy opening and closing mechanism (the operating mechanism). The opening spring of the stored energy mechanism is charged automatically during the closing action. The closing spring is loaded either by means of an electric motor (integrated into the drive unit) or by means of a removable crank.
The pole consists of an insulating cylinder, arc chamber, fixed, guiding, and mobile contacts. It also includes the gas expansion chamber, terminals, oil pan, oil drain and fills plugs, and oil level indicator.

oil circuit breaker
main components of an oil circuit breaker

Interruption of the arc in petroleum
As the moving contact separates from the fixed contact in the arc chamber, current continues to flow through the metal current paths which vaporize. The high temperature that occurs under such conditions decomposes the oil (which boils at 658 ° K) in the immediate vicinity and a gas bubble forms (under high pressure).
It consists of (from the outside to the inside): wet oil vapor, superheated oil vapor, hydrocarbons (C 2 H 2 around 4000 ° K), the arc (approximate temperature 7000° K)
Explanation
CF 4 – carbon tetrafluoride
C you F 2 – Copper Difluoride
HF – Hydrogen fluoride
H 2 O – Water
SF 4 – Sulfur tetrafluoride
SF 6 – sulfur hexafluoride
THEN 2 – Sulfur dioxide
THEN 2 F 2 – Sulfuryl fluoride
SOF 2 – Thionyl fluoride
WF 6 – tungsten hexafluoride
WO 3 – Tungsten trioxide

As can be seen, the arc spins in a mixture of hydrogen (in molecular and atomic states), carbon and copper vapor. Thermal conductivity is high due to the dissociation of hydrogen molecules into atoms. The thermal energy generated in the arc is mainly dissipated outward through the surrounding gas jacket to the oil.
In addition, the gas in the arc chamber escapes to the gas expansion chamber, so that a type of convection heat dissipation is created, so that the rate of heat dissipation increases. Near the current zero, the thermal power generated by the current (in the arc) is close to zero.
If the heat dissipation to the outside is large enough, the temperature in the arc area can be reduced so that the arc loses its conductivity and is extinguished. An arc under hydrogen has a short thermal time constant, so conditions are favorable for quenching. Two other situations can occur under certain conditions: Thermal arc restart, reignition.
Thermal recovery occurs when the post-arcing current rises again and passes into the next half-cycle of the SCC, as the plasma of the arc heats up due to insufficient heat dissipation to make the conductance of the zone of the arc equal to zero. Reignition occurs when the braking voltage of the system causes the arc to form again (after the first interruption) and the current flow to continue. The design of the interrupting chambers is of the axial or radial ventilation type. Often a combination of the two is used in the minimal oil design, CB MVs.
The process of axial ventilation generates a lot of gas pressures and has high dielectric strength. This is mainly used for interrupting low currents. Radial ventilation is used for high power outages because the developed gas pressures are low and the dielectric strength is low.
The higher the current to be interrupted, the greater the gas pressure developed.

Tests before commissioning and in-service checks of the protection system

Pre-commissioning tests should be carefully scheduled so that they take place in a logical and efficient order so that no equipment is disrupted again in subsequent tests. Tests before commissioning and in-service checks of the protection system (photo credit: projectech.com.au)
Before starting the tests, it is essential to ensure that the assembly of the article to be tested has been completed and verified.
The most important tests before commissioning and in-service checks of the protection system can be summarized as follows:
Analysis of wiring diagrams to confirm the polarity of connections, positive and negative rotation, etc.
A general inspection of the equipment, physically checking all connections, at the relay and panel terminations
Measurement of the insulation resistance of protective equipment
Inspection and secondary injection test of relays
Testing current transformers
Checking the operation of the protection system trip and alarm circuits
In addition, the list of all tests to be performed should be arranged in chronological order with all the precautions to be taken into account. Some of the more common tests are briefly described below.
Pre-commissioning tests
Insulation resistance measurement
Secondary injection tests
Current transformer tests
Primary injection test

Protection System
pre-commissioning-tests-protection-system
  1. Measurement of insulation resistance
    This test should be performed using a 1000V Insulation Resistance Meter. It is difficult to be precise as to the resistance value that should be obtained. The climate can influence the results – a wet day tends to give lower values, while on a dry day much higher values ​​can be obtained.
  2. Secondary injection tests
    These tests are intended to reproduce the operating conditions of each relay and are limited to the protection as such. It is therefore important to read and understand the instruction manual of the relay (application, operation, technical characteristics, installation, and maintenance). ).
    To perform these tests, it is necessary to electrically isolate the relay using test plugs or physically remove the relay from its housing.
    Although the relays should have been carefully tested by the manufacturer, it is necessary to carry out on-site checks after they are mounted on the panels to ensure that they have not been damaged in transit to the installation. The tests performed on relays depend largely on the type of relay.
    Secondary injection tests are mandatory to ensure that the protection relay equipment is operating within its predefined settings.
    Relay inputs and outputs must be disconnected before performing these tests. The test equipment provides the relay with current and voltage inputs corresponding to different faults and different operating situations. The starting values ​​are reached by gradually changing the amplitudes of these inputs while simultaneously measuring the operating time of the relay.
    Contacts and trigger targets should be monitored during these tests to ensure that the relay is operating according to the manufacturer’s specifications and the settings made.
    If the curves and characteristics of a relay are to be tested at many points or angles, it is convenient to use test equipment capable of performing a test automatically. Modern protective relay test equipment has the ability to perform automatic tests using software, for which the testing process is much faster and more accurate.
    In addition, the time during which the relay is out of service is minimized.
    This equipment is capable of providing current and voltage injection as well as phase shift when testing directional protection. It thus allows testing of a wide variety of relay types such as overcurrent, directional overcurrent, reverse power, remote, and under / overvoltage units.
    It is very important to record all test results, preferably on special forms for each type of relay.

    The parameters used before the start of the tests, which had been applied in accordance with the protection coordination study. This information should include current pickup, hourly dialing, and instant settings.
    Operating times for different multipliers, as measured by calibration tests. These should be checked against the data provided by the manufacturer.
    Test data for instantaneous units.
    Finally, the equipment used in the test should be recorded with all relevant observations, as well as details of the personnel involved in the test.
    It is important to note that the mentioned tests correspond to steady-state conditions beforehand and the equipment used to perform them is rather conventional. Due to technological advances, it is now possible to use more sophisticated equipment to perform tests using signals very similar to those existing in the event of a failure.
    Since the relays are necessary to respond to the transient conditions of disturbed power systems, their actual response can be assessed by simulating the signals sent to the relays under such conditions. Several manufacturers offer equipment for performing dynamic and transient state simulation tests.
    A dynamic state test is one in which the test amounts of phase butter exhibiting multiple power system states are synchronously switched between states. The characteristics of the power supply system, such as high frequency and decrease in direct current, however, are not represented in this test.
    A transient simulation test signal can represent, in terms of frequency content, amplitude, and duration, the actual input signals received by a relay during power system disturbances.
  3. Current transformer tests
    Before commissioning a protection scheme, it is recommended to test the following functionalities of current transformers:

Overlapping TCs
When CTs are connected for a fault on a circuit breaker to be covered by both protection zones, the cover connections must be carefully checked. This should be done by visual inspection.
If this is not possible or difficult, a continuity test between the appropriate relay and the secondary terminals of the appropriate CT should be performed.

Correct connection of CTs
There are often several combinations of CTs in the same ring and it is important to ensure that the CTs are correctly connected to their respective protection. Sometimes all CT scanners have the same ratio but very different characteristics, or the ratios are different but the CT scanners are close to each other which can be confusing.

Polarity
Each CT scanner should be tested individually to verify that the polarity indicated on the primary and secondary windings is correct. The measuring instrument connected to the CT secondary should be a high impedance voltmeter or moving coil ammeter, with zero centers. A low voltage battery is used in series with a push button to energize the primary.
When the circuit breaker is closed, the measuring instrument should make a small positive deviation, and when opening the circuit breaker, there should be a negative deviation, if the polarity is correct.

  1. Primary injection test
    This test checks the entire protection system, including the current transformers. The main objectives of this test are to check the CT transformation ratios and all the secondary circuit wiring of the protection and measurement CTs in order to confirm the operation of the trip, signaling, and alarm circuits.
    The test current is generally between 100 and 400 A. The two high current terminals of the primary injection equipment marked must be temporarily connected to the terminals of the CT under test.