GE Watthour Meter

Power measurement in AC circuits can be quite a bit more complex than with DC circuits for the simple reason that phase shift complicates the matter beyond multiplying voltage by current figures obtained with meters.

What is needed is an instrument able to determine the product (multiplication) of instantaneous voltage and current. Fortunately, the common electrodynamometer movement with its stationary and moving coil does a fine job of this.

Three phase power measurement can be accomplished using two dynamometer movements with a common shaft linking the two moving coils together so that a single pointer registers power on a meter movement scale. This, obviously, makes for a rather expensive and complex movement mechanism, but it is a workable solution.

An ingenious method of deriving an electronic power meter (one that generates an electric signal representing power in the system rather than merely move a pointer) is based on the Hall effect.

Figure 1 - Hall effect: Voltage is proportional to current and strength of the perpendicular magnetic field.

The voltage generated across the width of the flat, rectangular conductor is directly proportional to both the magnitude of the current through it and the strength of the magnetic field. Mathematically, it is a product (multiplication) of these two variables.

The amount of “Hall Voltage” produced for any given set of conditions also depends on the type of material used for the flat, rectangular conductor. It has been found that specially prepared “semiconductor” materials produce a greater Hall voltage than do metals, and so modern Hall Effect devices are made of these.

It makes sense then that if we were to build a device using a Hall-effect sensor where the current through the conductor was pushed by AC voltage from an external circuit and the magnetic field was set up by a pair or wire coils energized by the current of the AC power circuit, the Hall voltage would be in direct proportion to the multiple of circuit current and voltage.

Having no mass to move (unlike an electromechanical movement), this device is able to provide instantaneous power measurement: (Figure 2)

Figure 2 - Hall effect power sensor measures instantaneous power.

Not only will the output voltage of the Hall effect device be the representation of instantaneous power at any point in time, but it will also be a DC signal! This is because the Hall voltage polarity is dependent upon both the polarity of the magnetic field and the direction of current through the conductor.

If both current direction and magnetic field polarity reverses - as it would ever half-cycle of the AC power – the output voltage polarity will stay the same.

If voltage and current in the power circuit are 90o out of phase (a power factor of zero, meaning no real power delivered to the load), the alternate peaks of Hall device current and magnetic field will never coincide with each other: when one is at its peak, the other will be zero. At those points in time, the Hall output voltage will likewise be zero, being the product (multiplication) of current and magnetic field strength. Between those points in time, the Hall output voltage will fluctuate equally between positive and negative, generating a signal corresponding to the instantaneous absorption and release of power through the reactive load.

The net DC output voltage will be zero, indicating zero true power in the circuit. Any phase shift between voltage and current in the power circuit less than 90o will result in a Hall output voltage that oscillates between positive and negative, but spends more time positive than negative. Consequently there will be a net DC output voltage.

Conditioned through a low-pass filter circuit, this net DC voltage can be separated from the AC mixed with it, the final output signal registered on a sensitive DC meter movement. Often it is useful to have a meter to totalize power usage over a period of time rather than instantaneously. The output of such a meter can be set in units of Joules, or total energy consumed, since power is a measure of work being done per unit time.

Or, more commonly, the output of the meter can be set in units of Watt-Hours.

The “motor” used in these meters has a rotor made of a thin aluminum disk, with the rotating magnetic field established by sets of coils energized by line voltage and load current so that the rotational speed of the disk is dependent on both voltage and current.

Resource: Lessons in electric circuits – volume II

Inspection of voltage drop in conductors

It is part of the inspection process to ensure that installed conductors have been correctly selected for current carrying capacity and voltage drop. To check the suitability of the current carrying capacity it is simply a matter of looking at the installation method, and then checking on the current carrying capacity tables for the cable in Appendix 4 of BS 7671.

To ensure that the cable meets the voltage drop requirements is slightly more complex. A simple method is to measure the voltage at the origin of the circuit, and then measure the voltage at the end of the circuit with the load connected and switched on. The difference between the two measurements will be the volt drop.

If the first method is impractical, then a resistance test should be carried out between the phase and neutral of the circuit. This test is carried out using the same method as the R₁ + R₂ test although, instead of the test being between phase and circuit protective conductor (CPC), it is between the phase and neutral for the circuit.

Once the resistance R₁ + R_n of the circuit has been measured it should be multiplied by the current that will flow in the circuit.

This will give you the volt drop for the circuit.

Voltage drop in conductor can be calculated by following software and MS Excel Spreadsheets:

• Ecodial (Schneider Electric)
• Simaris Design (Siemens)
• Etap
• Voltage Drop Calculator VDC
• Calculator of Bus Bar Size and Voltage Drop
• Voltage Drop Calculator (Albany Technical College)

Resource: Practical guide to inspection, testing and certification of electrical installations by Christopher Kitcher

Arc flash in switchboard

Incident energy is the energy per unit area received on a surface located a working distance away from the arc flash location. The working distance is the distance from where the worker to the flash location. This is basically an arm length away or approximately 18 inches for low voltage panelboards, smaller equipment, and 24 inches for Switchgear. The distance is longer as the voltage increases.

The unit of incident energy is cal/cm². The threshold value of incident energy for 2^nd degree burn of the human skin is about 1.2 cal/cm2. One cal/cm² is equivalent to the amount of energy produced by a cigarette lighter in one second. It is the incident energy that causes burns to the human skin. Table 1 illustrates the potential damage of incident energy.

Table 1: Incident Energy & Damage Level

Incident energy is both radiant and convective. It is inversely proportional to the working distance squared. It is directly proportional to the time duration of the arc and to the available bolted fault current. It should be noted that time has a greater effect on the incident energy than the available bolted fault current.

Figure 1 - Human Tissue – Tolerance to 2nd Degree Burn

Both the NFPA-70E and IEEE Standard 1584 uses the assumption that an arc flash generating 1.2 calorie/cm² (1.2 calorie/cm² = 5.02 Joules/cm² = 5.02 Watt-sec/cm²) for 0.1 second will result in a second-degree burn. It is also assumed that a second-degree burn will be curable and will not result in death.

Figure 1 above illustrates these points.

Arc Flash PPE Laboratory Testing Video

Reference: Arc Flash Hazard -  The Basics by Robert E. Fuhr, P.E. Senior Member IEEE,  Viet Tran, IEEE, and Tam Tran, IEEE

Figure 1 - Perfect resistor, inductor and capacitor

Resistance, R

Resistance is essentially friction against the motion of electrons. It is present in all conductors to some extent (except superconductors!), most notably in resistors. When alternating current goes through a resistance, a voltage drop is produced that is in-phase with the current.

Resistance is mathematically symbolized by the letter “R” and is measured in the unit of ohms (Ω).

Reactance, X

Reactance is essentially inertia against the motion of electrons. It is present anywhere electric or magnetic fields are developed in proportion to applied voltage or current. respectively; but most notably in capacitors and inductors. When alternating current goes through a pure reactance, a voltage drop is produced that is 90° out of phase with the current.

Reactance is mathematically symbolized by the letter “X” and is measured in the unit of ohms (Ω).

Impedance, Z

Impedance is a comprehensive expression of any and all forms of opposition to electron flow, including both resistance and reactance. It is present in all circuits, and in all components. When alternating current goes through an impedance, a voltage drop is produced that is somewhere between 0” and 90° out of phase with the current.

Impedance is mathematically symbolized by the letter “Z” and is measured in the unit of ohms (Ω), in complex form.

The impedance phase angle for any component is the phase shill. between voltage across that component and current through that component. For a perfect resistor, the voltage drop and current are always in phase with each other, and so the impedance angle of a resistor is said to be 0°. For an perfect inductor, voltage drop always leads current by 90°, and so an inductor’s impedance phase angle is said to be +90°.

For a perfect capacitor, voltage drop always lags current by 90°, and so a capacitor‘s impedance phase angle is said to be -90“.

Impedances in AC circuit behave analogously to resistances in DC circuit: they add in series, and they diminish in parallel. A revised version of Ohm’s Law, based on impedance rather than resistance, looks like this:

Kirchhoff’s Laws and all network analysis methods and theorems are true for AC circuits as well, so long as quantities are represented in complex rather than scalar form. While this qualified equivalence may be arithmetically challenging, it is conceptually simple and elegant. The only real difference between DC and AC circuit calculations is in regard to power.

Because reactance doesn’t dissipate power as resistance does, the concept of power in AC circuit is radically different from that of DC circuit.

Resource: Lessons in electric circuits, Volume II – AC, Sixth Edition

Alternator capability curve - Green area is normal operating range of a typical synchronous machine, yellow is abnormal but not damaging and operating in red regional will cause damage or misoperation.

Continued from technical article: Capacitor Banks In Power System (part three)

PF correction for loads connected on captive Diesel Generator (DG)

Let us consider that there is a captive diesel generator the rating of which is specified as 1000kVA and PF 0.85. Rating in kVA specifies the maximum current the alternator can deliver at the system voltage.

In the previous parts of this article we have seen that the role of power capacitors in improving the power factor and reducing total cost of electricity in an industrial installation is well established with regard to supply of power from the Utilitys/utilities.

Hence it seems logical to extend the above application of power capacitors when power is drawn from captive diesel generator to optimize their performance.

This article tries to analyze the same in the following paragraphs.

Diesel Generator Set Rating in kVA

As we have considered 1000kVA DG. This way of specifying the DG rating is very logical because specifies the maximum current the alternator can deliver at the system voltage.

DG set Rating in kVA at a particular PF

The diesel generator which we had assumed was of 1000kVA at 0.85PF. The relevance of PF in case of DG rating is as follows:

1. To find mechanical power rating of a diesel engine for a particular diesel generator, first convert kVA to kW and thereafter kW to BHP. This can only be done if we assume a certain average Power Factor (PF) under which the DG set would operate.
   .
2. The power factor so assumed should be in line with the average power factor prevalent in the industry. A typical industrial load comprises of induction motors (typical PF of 0.8 to 0.85), non-linear loads (typical PF of 0.5 to 0.6) and combination of unity PF loads (Resistive heating and incandescent lighting). Hence assuming an average power factor of 0.85 for typical industrial loads is considered acceptable by convention.
   .
3. Consequently a power factor of 0.85 is used for calculating the kW, which is then converted to the BHP rating of the prime mover. BHP rating so obtained is the output of the prime mover. Considering suitable engine losses it becomes possible to calculate the power rating of the engine.

Now after understanding the DG set name plate rating parameter, let us come back to the question should we connect the Capacitor Banks in parallel to the loads conned to DG? Answer is YES, It is however, important to ensure that under actual operating conditions the kW loading and current loading should not be exceeded.

Power Factor of loads supplied by DG sets can therefore be improved closer to unity by use of suitable Reactive Power Compensation Systems keeping in view the rated current loading is not exceeded.

Let us consider an example for the same:

** Any industry has a 1000 kVA DG set which is loaded at an average of 600 kW at 0.7 PF. In addition, there are 125 kW of other loads within the same installation, which are not loaded on the DG set due to capacity restrictions that arise during occurrence of short-term peak loads, such as motor starting, and intermittent welding load. Due to this, productivity in the Industry is lowered when the DG Set is in operation.

During the period when Utility supply is available all loads can be operated. Is it possible to improve productivity when DG Set is in operation?

** A well designed power factor correction capacitor bank panel can improve the cost of electricity consumed from utility as well as improve productivity when DG Set is in operation.

Now if we connect the suitably sized and designed (already discussed in part1 to 3) capacitor bank in parallel to the loads connected to DG and improve the average overall load power factor from 0.7 to 0.85 than for the same percentage loading of 85.7% that is 857kVA the active power that can be drawn is = 857 x 0.85 = 728.45 kW

Hence one can see the moment capacitor bank is connected in parallel to the loads connected to the DG the additional requirement of 125kW is comfortably met without exceeding the percentage loading on DG.

During the period when the Industry is using supply from the Utility the Capacitor banks system can ensure consistently high PF, thereby achieving demand savings and reduction in losses and elimination of any PF penalty. Consequently, cost of electricity consumed from the EB will be minimized.

The same Capacitor banks system can be also used when the Industry is using supply from the DG set. The fast acting property of the Capacitor banks system will reduce the peak load requirements that are to be met from the DG set. This is achieved by providing instantaneous compensation from the Capacitor banks system during conditions when motors are started and / or welding machines are being operated. This will enable the Industry to transfer the 125 kW of additional load on to the DG set and ensure that productivity is improved when the DG set is in operation.

REACTIVE POWER COMPENSATION SYSTEMS by Capacitor Banks can enable D.G set users to reconfigure their loads / D.G sets to achieve better percentage loading and efficiency on the machines. As a result reduction in cost / kWh can be attained.

Impact of leading kVAR on generators

Now since we have very well established that a suitably designed Capacitor Banks can be connected in parallel to the loads connected to DG. However what is the impact if one keeps on improving the power factor and the power factor goes on leading side.

Some inherent characteristics of an alternator limit the amount of leading kVAR that can be absorbed by a DG. We cannot go on switching ON the Capacitor Banks as and when required, this can create over voltage condition in DG and subsequently over fluxing.

The ability of any generator to absorb the kVAR is termed as reverse kVAR limit. This ability is defined as reactive capability curve. Below figure shows typical generator reactive capability curve. X axis is the kVAR produced or absorbed (positive to the right). Y axis indicates the kW (positive going up). kVAR and kW are shown as per unit quantities based on the rating of the alternator (not necessarily the generator set, which may have a lower rating.

The normal operating range of a generator set is between zero and 100 percent of the kW rating of the alternator (positive) and between 0.8 and 1.0 power factor (green area on curve). The black lines on the curves show the operating range of a specific alternator when operating outside of normal range. Notice that as power factor drops, the machine must be de-rated to prevent overheating. On the left quadrant, you can see that near-normal output (yellow area) can be achieved with some leading power factor load, in this case, down to about 0.97 power factor, leading. At that point, the ability to absorb additional kVAR quickly drops to near zero (red area), indicating that the AVR is “turning off” and any level of reverse kVAR greater than the level shown will cause the machine to lose control of voltage.

A good rule of thumb for generators is that it can absorb about 20% of its rated kVAR output in reverse kVAR without losing control of voltage. However, since this characteristic is not universal, it is advisable for a system designer to specify the reverse kVAR limit used in his design, or the magnitude of the reverse kVAR load that is expected.

Note that this is not specified as a leading power factor limit, but rather as a maximum magnitude of reverse kVAR.

Low Voltage Power Capacitor

Continued from part two – Capacitor Banks In Power System (part two)

Maximum Permissible Current

Capacitor units shall be suitable for continuous operation at an RMS current of 1.30 times the current that occurs at rated sinusoidal voltage and rated frequency, excluding transients. Taking into account the capacitance tolerances of 1.1 CN, the maximum permissible current can be up to 143 IN.

These overcurrent factors are intended to take care of the combined effects of harmonics and overvoltage’s up to and including1.10 UN, according to IS 13340.

Discharge Device

Each capacitor unit or bank shall be provided with a directly connected discharge device. The discharge device shall reduce the residual voltage from the crest value of the rated value UN to 50 V or less within 1 min, after the capacitor is disconnected from the source of supply. There must be no switch, fuse or any other isolating device between the capacitor unit and the discharge device.

A discharge device is not a substitute for short-circuiting the capacitor terminals together and to earth before handling.

Where:

t = time for discharge from UN Jr to UR(s),
R = equals discharge resistance
C = rated capacitance (pF) per phase,
U_N = rated voltage of unit (V),
U_R = permissible residual voltage
k = coefficient depending on both resistance and capacitor unit connections, Value of k to be taken as per IS13340

Configuration of Capacitor bank

A delta-connected bank of capacitors is usually applied to voltage classes of 2400 volts or less.

In a three-phase system, to supply the same reactive power, the star connection requires a capacitor with a capacitance three times higher than the delta connected capacitor. In addition, the capacitor with the star connection results to be subjected to a voltage √3 lower and flows through by a current √3 higher than a capacitor inserted and delta connected.

For Three Phase STAR Connection

Capacity of the capacitor bank C = Q_c / (2πF_rU_r²)
Rated current of the components I_RC = 2πF_rCU_r / √3
Line current I = I_RC

Three Phase Delta Connection

Capacity of the capacitor bank C = Q_c / (2πF_rU_r².3)
Rated current of the components I_RC = 2πF_rCU_r
Line current I = I_RC / √3

Where,

U_r = rated voltage, which the capacitor must withstand indefinitely;
F_r = rated frequeny
Q_c = generally expressed in kVAR (reactive power of the capacitor bank)

While deciding the size of capacitor bank on any bus it is necessary to check the voltage rise due to installation of capacitors under full load and light load conditions. It is recommended to limit the voltage rise to maximum of 3% of the bus voltage under light load conditions. The voltage rise due to capacitor installation may be worked out by the following expression.

Voltage Drop/Rise Due to Switching

Switching on or off a large block of load causes voltage change. The approximate value can be estimated by:

Voltage change ≅ load in MVA/fault level in MVA

Switching a capacitor bank causes voltage change, which can be estimated by:

Voltage change ≅ capacitor bank rating in MVA /system fault level in MVA

Where,

% V_C = % voltage change or rise due to capacitor
% X = % Reactance of equipment e.g. Transformer

If the capacitor bank is STAR connected than the required value of C will be higher in comparison to the value of C in DELTA connection for the same value of required kVAR. Higher value of C will cause higher voltage rise of the system causing nuisance tripping of the equipment provided with over voltage protection.

It is common practice to leave the star-connected capacitor banks ungrounded (there are separate reason for leaving it ungrounded) when used in the system or use delta-connected banks to prevent the flow of third harmonic currents into the power system through the grounded neutral.

Large capacitor banks can be connected in STAR ungrounded, STAR grounded or delta. However, the wye ungrounded connection is preferable from a protection standpoint. For the STAR ungrounded system of connecting single capacitor units in parallel across phase-to-neutral voltage the fault current through any incomer fuse or breaker of capacitor bank is limited by the capacitors in the two healthy phases. In addition the ground path for harmonic currents is not present for the ungrounded bank.

For STAR grounded or delta-connected banks, however, the fault current can reach the full short circuit value from the system because the sound phases cannot limit the current.

Detuning of Capacitor Banks

In an industrial plant containing power factor correction capacitors, harmonics distortions can be magnified due to the interaction between the capacitors and the service transformer. This is referred to as harmonic resonance or parallel resonance. It is important to note that capacitors themselves are not main cause of harmonics, but only aggravate potential harmonic problems. Often, harmonic-related problems do not show up until capacitors are applied for power factor correction.

Impedance of the capacitor decreases with increase in frequency. Capacitor capacity to cancel out harmonic decreases with increase in frequency. This offer the low impedance path to harmonic currents. These harmonic currents added to the fundamental current of capacitors can produce dangerous current overloads on capacitor. Each of the harmonic currents causes the voltage drop across the capacitor. This voltage drop is added to the fundamental voltage. Thus in presence of harmonics higher voltage rating of capacitor is recommended. This overvoltage can be much above permissible 10% value when resonance is present.

Another important aspect is resonance which can occur when p.f. capacitors forms the series or parallel resonant circuit with impedance of supply transformer. If the resonance frequency of this LC circuit coincides with one of the harmonic present, the amplitude of the harmonic current flowing through LC circuit is multiplied several times damaging the capacitors, supply transformer and other network components.

Precautions to be taken while switching ON a capacitor bank

Make sure that there is adequate load on the system. The normal current of the capacitor to be switched ON at 440 volts is say 100 amps. Therefore the minimum load current at which the capacitor should be switched ON is 130-150 amps.

If one capacitor unit is already on and a second one is to be added then minimum load current on this bus system must be equal to or more than the combined capacitor current of the two banks by at least a factor of 1.35 to 1.5.

After switching off the capacitor – wait for at least one minute before switching it on. Earth all the live terminals only after waiting for one minute before touching these with spanner etc. If above precautions are not observed, this could lead to dangerous situations both for plant and personnel.

Switch off the capacitors when there is not enough load. This is a MUST. If the capacitors are kept ON when there is no load or less load then Power factor goes to leading side and system voltage increases which may cause damage to the capacitors as well as other electrical equipments and severe disturbance can be caused.)

If the line voltages are more than the capacitor rated voltage, then do not switch on the capacitors. As the load builds up, the line voltage will fall. Switch on the capacitors then only.

Operation of capacitor bank and co relatation with harmonics in the system

Harmonics can be reduced by limiting the non-linear load to 30% of the maximum transformer’s capacity. By doing this we ensure that power system does not exceeds the 5% voltage distortion level of IEEE Standard 519. However, with power factor correction capacitors installed, resonating conditions can occur that could potentially limit the percentage of non-linear loads to 15% of the transformer’s capacity.

If F_R equals or is closed to a characteristic harmonic, such as the 5th or 7th, there is a possibility that a resonant condition could occur. Almost all harmonic distortion problems occur when the parallel resonance frequency is close to the fifth or seventh harmonic, since these are the most powerful harmonic current components. The eleventh and thirteenth harmonics may also be worth evaluating.

True and displacement power factor specially with regards to variable speed drives?

Power factor of variable speed drives – With the six-step and current source inverters, the power factor will be determined by the type of front end used. When SCR’s are used, the power factor will be relatively poor at reduced speeds. When diodes with a dc chopper are used, the power factor will be the same as a PWM inverter, which is relatively high (near to unity) at all, speeds.

True power factor is the ratio of real power used in kilo watts (kW) divided by the total kilo volt-amperes. Displacement power factor is a measure of the phase displacement between the voltage and current at the fundamental frequency. True power factor includes the effects of harmonics in the voltage and current. Displacement power factor can be corrected with capacitor banks. Variable speed drives have different displacement power factor characteristics, depending on the type of rectifier.

PWM type variable speed drives use a diode bridge rectifier and, have displacement power factors very close to unity. However, the input current harmonic distortion can be very high for these variable speed drives, resulting in a low true power factor. True power factor is approximately 60% despite the fact that the displacement power factor is very close to unity. The true power factor can be improved substantially in this case through the application of input chokes or transformers which reduce current distortion.

Capacitor banks provide no power factor improvement for this type of variable speed drives and can make the power factor worse by magnifying the harmonic levels.

Automatic capacitor banks consist of stages controlled by a power factor controller which ensures that the required capacitor power is always connected to the system, it means that always would be optimal correction. (pic by energolukss.lv)

Continued from part one – Capacitor Banks In Power System (part one)

Sizing of switching device for Capacitor banks

It should be noted that in an inductance the current lags the voltage by 90 degrees and in a capacitor the current leads the voltage by 90 degrees. These relationships are very important for drawing phasor diagrams.

It is very convenient to remember these relationships by the word CIVIL as follows:

Hence Current drawn from Capacitor bank =

Since sin90 = 1 hence the equation for current drawn can be rewritten as:

The relevant Standards on this device recommend a continuous overload capacity of 30%. A capacitor can have a tolerance of up to +15% in its capacitance value. All current-carrying components such as breakers, contactors, switches, fuses, cables and busbar systems associated with a capacitor unit or its banks, must therefore be rated for at least 1.5 times the rated current.

The rating of a capacitor unit will thus vary in a square proportion of the effective harmonic voltage and in a direct proportion to the harmonic frequency. This rise in kVAR, however, will not contribute to improvement of the system power factor. but only of the overloading of the capacitors themselves. Therefore it may, however, sometimes be desirable to further enhance the overloading capacity of the capacitor and so also the rating of the current-carrying components if the circuit conditions and type of loads connected on the system are prone to generate excessive harmonics.

Examples are when they are connected on a system on which we operating static drive and arc furnaces. It is desirable to contain the harmonic effects as far as practicable to protect the capacitors as well as inductive loads connected on the system and the communication network, if running in the vicinity.

Taking care of harmonics

It is common practice to leave the star-connected capacitor banks ungrounded when used in the system or use delta-connected banks to prevent the flow of third harmonic currents into the power system through the grounded neutral.

Use of filter circuits in the power lines at suitable locations, to drain the excessive harmonic quantities of the system into the filter circuits.

A filter circuit is a combination of capacitor and series reactance, tuned to a particular harmonic frequency (series resonance), to offer it the least impedance at that frequency
and hence, filter it out. Say, for the fifth harmonic, Xc5 = XLS.

The use of a reactor in series with the capacitors will reduce the harmonic effects in a power network, as well as their effect on other circuits in the vicinity, such as a telecommunication network. The choice of reactance should be such that it will provide the required detuning by resonating below the required harmonic, to provide a least impedance path for that harmonic and filter it out from the circuit.

It should be ensured that under no condition of system disturbance would the filter circuit become capacitive when it approaches near resonance. To achieve this, the filter circuits may be tuned to a little less than the defined harmonic frequency. Doing so will make the Land hence XL, always higher than Xc, since This provision will also account for any diminishing variation in C, as may be caused by ambient temperature, production tolerances or failure of a few capacitor elements or even of a few units during operation.

The power factor correction system would thus become inductive for most of the current harmonics produced by power electronic circuits and would not magnify the harmonic effects or cause disturbance to a communication system if existing in the vicinity A filter circuit can be tuned to the lowest (say the fifth) harmonic produced by an electronic circuit. This is because LT capacitors are normally connected in delta and hence do not allow the third harmonic to enter the circuit while the HT capacitors are connected in star, but their neutral is left floating and hence it does not allow the third harmonic to enter the circuit.

For more exact compensation, the contents and amplitudes of the harmonic quantities present in the system can be measured with the help of an oscilloscope or a harmonic analyzer before deciding on the most appropriate filter circuit/circuits. Theoretically, a filter is required for each harmonic, but in practice, filters adjusted for one or two lower frequencies are adequate to suppress all higher harmonics to a large extent and save on cost.

If we can provide a series reactor of 6% of the total kVAR of the capacitor banks connected on the system, most of the harmonics present in the system can be suppressed. With this reactance, the system would be tuned to below the fifth harmonic (at 204 Hz) for a 50Hz system.

Working of APFC Relay

The basic principle of this relay is the sensing of the phase displacement between the fundamental waveforms of the voltage and current waves of power circuit. Harmonic quantities are filtered out when present in the system. This is a universal practice to measure the p.f. of a system to economize on the cost of relay. The actual p.f. of the circuit may therefore be less than measured by the relay. But one can set the relay slightly higher (less than unity), to account for the harmonics, when harmonics are present in the system. From this phase displacement, a D.C. voltage output is produced by a transducer circuit.

The value of the D.C. voltage depends upon the phase displacement, i.e. the p.f. of the circuit. This D.C. voltage is compared with a built-in reference D.C. voltage, adjustable by the p.f. setting knob or by selecting the operating band provided on the front panel of the relay. Corrective signals are produced by the relay to switch ON or OFF the stage capacitors through a built-in sequencing circuit to reach the desired level of p.f. A little lower p.f. then set would attempt to switch another unit or bank of capacitors, which may overcorrect the set p.f. Now the relay would switch off a few capacitor units or banks to readjust the p.f. and so will commence a process of hunting, which is undesirable. To avoid such a situation the sensitivity of the comparator is made adjustable through the knob on the front panel of the relay.

The sensitivity control can be built in terms of phase angle (normally adjustable from 4 to 14 degrees electrical) or percentage kVAR. The sensitivity, in terms of an operating band, helps the relay to avoid a marginal overcorrection or under correction and hence the hunting.

As soon as the system’s actual p.f. deviates from the pre-set limits, the relay becomes activated and switches in or switches out capacitor units one by one, until the corrected p.f. falls within the sensitivity limit of the relay.

A time delay is built in to allow discharge of a charged capacitor up to 90% before it is reswitched. This is achieved by introducing a timer into the relay’s switching circuit. The timer comes on whenever an OFF signal occurs, and blocks the next operation of a charged capacitor, even on an ON command, until it is discharged to at least 90% of the applied voltage. This feature ensures safety against an overvoltage.

Normally this time is 1-3 minutes for LT and 5-10 minutes for HT shunt capacitors unless fast-discharge devices are provided across the capacitor terminals to reduce this time. Fast-discharge devices are sometimes introduced to discharge them faster than these stipulations to match with quickly varying loads. The ON action begins only when the timer is released. The time of switching between each relay step is, however, quite short, of the order of 3-5 seconds. It includes the timings of the control circuit auxiliary relays (contactors). It may be noted that of this, the operating time of the static relay is scarcely of the order of three to five cycles.

In rapidly changing loads it must be ensured that enough discharged capacitors are available in the circuit on every close command. To achieve this, sometimes it may be necessary to provide special discharge devices across the capacitor terminals or a few extra capacitor units to keep them ready for the next switching. It may require a system study on the pattern of load variations and the corresponding p.f. Fast switching, however, is found more often in LT systems than in HT. HT systems are more stable, as the variable loads are mostly LT.

The above discussion is generally related to IC-based solid-state relays and in most parts to microprocessor based relays of the more rudimentary types.

Power Factor Correction of Induction Motor

The selection of capacitor rating, for an induction motor, running at different loads at different times, due either to change in load or to fluctuation in supply voltage, is difficult and should be done with care because the reactive loading of the motor also fluctuates accordingly.
A capacitor with a higher value of kVAR than the motor kVAR, under certain load conditions, may develop dangerous voltages due to self-excitation.

At unity power factor, the residual voltage of a capacitor is equal to the system voltage. It rises at leading power factors. These voltages will appear across the capacitor banks when they are switched off and become a potential source of danger to the motor and the operator.
Such a situation may arise when the capacitor unit is connected across the motor terminals and is switched with it. This may happen during an open transient condition while changing over from star to delta, or from one step to another, as in an A/T switching, or during a tripping of the motor or even while switching off a running motor.

In all such cases the capacitor will be fully charged and its excitation voltage, the magnitude of which depends upon the p.f. of the system, will appear across the motor
terminals or any other appliances connected on the same circuit. The motor, after disconnection from supply, will receive the self-excitation voltage from the capacitor and while running may act as a generator, giving rise to voltages at the motor terminals considerably higher than the system voltage itself. The solution to this problem is to select a capacitor with its capacitive current slightly less than the magnetizing current, Im, of the motor, say, 90% of it.

If these facts are not borne in mind when selecting the capacitor rating, particularly when the p.f. of the motor is assumed to be lower than the rated p.f. at full load, then at certain loads and voltages it is possible that the capacitor kVAR may exceed the motor reactive component, and cause a leading power factor. A leading p.f. can produce dangerous overvoltages. This phenomenon is also true in an alternator. If such a situation arises with a motor or an alternator, it is possible that it may cause excessive torques.

Keeping these parameters in mind, motor manufacturers have recommended compensation of only 90% of the no-load kVAR of the motor. irrespective of the motor loading. This for all practical purposes and at all loads will improve the p.f. of the motor to around 0.9-0.95. which is satisfactory. Motor manufacturers suggest the likely capacitor ratings for different motor ratings and speeds.

Metal enclosed capacitor banks (MECB) - ABB

Capacitance

When a charge is delivered to a conductor its potential is raised in proportion to the quantity of charge given to it. At a particular potential a conductor can hold a given amount of charge. Capacitance is the term to indicate the limited ability to hold charge by a conductor.

Let charge given to a conductor be = q
Let V be the potential to which it is raised.

Then q α V, or

q = CV

C is constant for a conductor depending upon its shape size and surrounding medium. This constant is called capacitance of a conductor.

Capacitor

A capacitor or condenser is a device for storing large quantity of electric charge. Though the capacity of a conductor to hold charge at a particular potential is limited, it can be increased artificially. Thus any arrangement for increasing the capacity of a conductor artificially is called a capacitor.

• Capacitors are of many types depending upon its shape, like parallel plate, spherical and cylindrical capacitors etc….

• In capacitor there are two conductors with equal and opposite charge say +q and –q. Thus q is called charge of capacitor and the potential difference is called potential of capacitor.

Principle of Capacitor

Let A be the insulated conductor with a charge of +q units. In the absence of any other conductor near A charge on A is +q and its potential is V. The capacity of conductor A is therefore given by:

C = qV

If a second conductor B is kept closed to A than electrostatic induction takes place. –q units of charge are induced on nearer face of B and +q units of charge is induced on farther face of B. Since B is earthed the charge +q will be neutralized by the flow of electrons from the earth.

Potential of A due to self charge = V

Potential of A due to –q charge on B = -V’

Thus net potential of A = V + (-V’) = V -V’ which is less than V

Hence potential of A has been decreased keeping the charge on it fixed, hence capacitance has been increased.

With the presence of B the amount of work done in bringing a unit positive charge from infinity to conductor A decreases as there will be force of repulsion due to A and attraction due to B. Thus resultant force of repulsion is reduced on unit positive charge and consequently the amount of work doe is less and finally due to this potential of A decreases.

Therefore capacity of A to hold charge (Capacitance) is increased.

Dielectric Strength

The material between the two conductors A and B as shown in figure above is always some dielectric material. Under normal operating conditions the dielectric materials have a very few free electrons. If the electric field strength between a pair of charged plates is gradually increases, some of the electrons may be detached from the dielectric resulting in a small current.

When the electric filed strength applied to a dielectric exceeds a critical value, the insulating properties of the dielectric material gets destroys and starts conducting between the two conductors A and B.

This is called breakdown of dielectric which is fault condition for a capacitor bank. The minimum potential gradient required to cause such a break down is called the dielectric strength of the material. It measures the ability of a dielectric to withstand breakdown. It is expressed as kV/mm.

It is reduced by moisture, high temperature; aging etc. Below table gives dielectric strength of some dielectrics.

Dielectric Strength for capacitor is the maximum peak voltage that the capacitor is rated to withstand at room temperature. Test by applying the specified multiple of rated voltage for one minute through a current limiting resistance of 100 Ω per volt.

Sizing of Capacitor banks for power factor improvement

The Power Factor Correction of electrical loads is a problem common to all industrial companies. Every user which utilizes electrical power to obtain work in various forms continuously asks the mains to supply a certain quantity of active power together with reactive power.

The most common of these on modern systems is the inductive load. Typical examples includes transformer, fluorescent lighting, AC induction motors, Arc/induction, furnaces etc. which draw not, only active power from the supply, but also inductive reactive power (KVAr). Common characteristics of these inductive loads is that they utilize a winding to produce an electromagnetic field which allows the motor or transformer to function and requires certain amount of electrical power in order to maintaining the field.

Therefore Active Power (KW) actually performs the work whereas Reactive Power (KVAr) sustains the electro-magnetic field. This reactive power though is necessary for the equipment to operate correctly but could be interpreted as an undesirable burden on the supply.

If we quantify power factor improvement aspect from the utility company’s point of view, than raising the average operating power factor of the network from 0.7 to 0.9 means:

• Cutting costs due to ohmic losses in the network by 40%
• Increasing the potential of production and distribution plants by 30%.

These figures speak for themselves: it means saving hundreds of thousands of tons of fuel and making several power plants and hundreds of transformer rooms available.

Thus in the case of low power factors utility companies charge higher rates in order to cover the additional costs they must incur due to the inefficiency of the system that taps energy. It is a well-known fact that electricity users relying on alternating current – with the exception of heating elements – absorb from the network not only the active energy they convert into mechanical work, light, heat, etc. but also an inductive reactive energy whose main function is to activate the magnetic fields necessary for the functioning of electric machines.

Power Factor is also defined as cos Ø = kW / KVA

COMPENSATED kVAR =
kVAR1 – kVAR2 = kW tanØ1 – tan Ø2 = kW [tanØ1 - tan Ø2]

Power Factor Triangle

Hence Required Rating of Capacitor banks to be connected = kW [tanØ1 - tan Ø2]

Where,

cos Ø1 = Operating Power Factor
cos Ø2 = Target Power Factor or Power Factor after improvement.

Electricity - Teach your kids, keep them safe

It’s really not an easy task to explain kids what is the electricity and what is really happening in the wires while lamp is powered, or what are the magnets, magnetism and how all this stuff works. Most important of all is to explain your kids about danger that electric current can cause, and how to stay safe and alive.

Lucky kids, we didn’t have YouTube like them, to understand it lot easier Enjoy!

Episode 1 – What is electricity?

Episode 2 – Magnets

Episode 3 – Electromagnetism

Episode 4 – Electromagnetism in reverse

Episode 5 – AC Alternating current

Episode 6 – About safety and STAY ALIVE!

Low voltage switchgear - Power distribution (by MEC Electrical Engineering)

Continued from Types of neutral earthing in power distribution (part 1)

3. Resistance earthed systems

Resistance grounding has been used in three-phase industrial applications for many years and it resolves many of the problems associated with solidly grounded and ungrounded systems. Resistance Grounding Systems limits the phase-to-ground fault currents.

Grounding Resistors are generally connected between ground and neutral of transformers, generators and grounding transformers to limit maximum fault current as per Ohms Law to a value which will not damage the equipment in the power system and allow sufficient flow of fault current to detect and operate Earth protective relays to clear the fault. Although it is possible to limit fault currents with high resistance Neutral grounding Resistors, earth short circuit currents can be extremely reduced.

As a result of this fact, protection devices may not sense the fault.

Therefore, it is the most common application to limit single phase fault currents with low resistance Neutral Grounding Resistors to approximately rated current of transformer and / or generator.

In addition, limiting fault currents to predetermined maximum values permits the designer to selectively coordinate the operation of protective devices, which minimizes system disruption and allows for quick location of the fault.

There are two categories of resistance grounding:

1. Low resistance Grounding
2. High resistance Grounding

Ground fault current flowing through either type of resistor when a single phase faults to ground will increase the phase-to-ground voltage of the remaining two phases. As a result, conductor insulation and surge arrestor ratings must be based on line-to-line voltage. This temporary increase in phase-to-ground voltage should also be considered when selecting two and three pole breakers installed on resistance grounded low voltage systems.

The increase in phase-to-ground voltage associated with ground fault currents also precludes the connection of line-to-neutral loads directly to the system. If line-to neutral loads (such as 277V lighting) are present, they must be served by a solidly grounded system. This can be achieved with an isolation transformer that has a three-phase delta primary and a three-phase, four-wire, wye secondary.

Resistor neutral earthing

Neither of these grounding systems (low or high resistance) reduces arc-flash hazards associated with phase-to-phase faults, but both systems significantly reduce or essentially eliminate the arc-flash hazards associated with phase-to-ground faults. Both types of grounding systems limit mechanical stresses and reduce thermal damage to electrical equipment, circuits, and apparatus carrying faulted current.

The difference between Low Resistance Grounding and High Resistance Grounding is a matter of perception and, therefore, is not well defined. Generally speaking high-resistance grounding refers to a system in which the NGR let-through current is less than 50 to 100 A.Low resistance grounding indicates that NGR current would be above 100 A.

A better distinction between the two levels might be alarm only and tripping. An alarm-only system continues to operate with a single ground fault on the system for an unspecified amount of time. In a tripping system a ground fault is automatically removed by protective relaying and circuit interrupting devices. Alarm-only systems usually limit NGR current to 10 A or less.

Rating of The Neutral grounding resistor:

1. Voltage: Line-to-neutral voltage of the system to which it is connected.
2. Initial Current: The initial current which will flow through the resistor with rated voltage applied.
3. Time: The “on time” for which the resistor can operate without exceeding the allowable temperature rise.

A. Low Resistance Grounded

Low Resistance Grounding is used for large electrical systems where there is a high investment in capital equipment or prolonged loss of service of equipment has a significant economic impact and it is not commonly used in low voltage systems because the limited ground fault current is too low to reliably operate breaker trip units or fuses. This makes system selectivity hard to achieve. Moreover, low resistance grounded systems are not suitable for 4-wire loads and hence have not been used in commercial market applications.

A resistor is connected from the system neutral point to ground and generally sized to permit only 200A to 1200 amps of ground fault current to flow. Enough current must flow such that protective devices can detect the faulted circuit and trip it off-line but not so much current as to create major damage at the fault point.

Low resistance grounded

Since the grounding impedance is in the form of resistance, any transient over voltages are quickly damped out and the whole transient overvoltage phenomena is no longer applicable. Although theoretically possible to be applied in low voltage systems (e.g. 480V),significant amount of the system voltage dropped across the grounding resistor, there is not enough voltage across the arc forcing current to flow, for the fault to be reliably detected.

For this reason low resistance grounding is not used for low voltage systems (under 1000 volts line to-line).

Advantages

1. Limits phase-to-ground currents to 200-400A.
2. Reduces arcing current and, to some extent, limits arc-flash hazards associated with phase-to-ground arcing current conditions only.
3. May limit the mechanical damage and thermal damage to shorted transformer and rotating machinery windings.

Disadvantages:

1. Does not prevent operation of over current devices.
2. Does not require a ground fault detection system.
3. May be utilized on medium or high voltage systems.
4. Conductor insulation and surge arrestors must be rated based on the line to-line voltage. Phase-to-neutral loads must be served through an isolation transformer.
5. Used: Up to 400 amps for 10 sec are commonly found on medium voltage systems.

B. High Resistance Grounded

High resistance grounding is almost identical to low resistance grounding except that the ground fault current magnitude is typically limited to 10 amperes or less. High resistance grounding accomplishes two things.

The first is that the ground fault current magnitude is sufficiently low enough such that no appreciable damage is done at the fault point. This means that the faulted circuit need not be tripped off-line when the fault first occurs. Means that once a fault does occur, we do not know where the fault is located. In this respect, it performs just like an ungrounded system.

The second point is it can control the transient overvoltage phenomenon present on ungrounded systems if engineered properly.

Under earth fault conditions, the resistance must dominate over the system charging capacitance but not to the point of permitting excessive current to flow and thereby excluding continuous operation.

High resistance grounded

High Resistance Grounding (HRG) systems limit the fault current when one phase of the system shorts or arcs to ground, but at lower levels than low resistance systems.

In the event that a ground fault condition exists, the HRG typically limits the current to 5-10A.

HRG’s are continuous current rated, so the description of a particular unit does not include a time rating. Unlike NGR’s, ground fault current flowing through a HRG is usually not of significant magnitude to result in the operation of an over current device. Since the ground fault current is not interrupted, a ground fault detection system must be installed.

These systems include a bypass contactor tapped across a portion of the resistor that pulses (periodically opens and closes). When the contactor is open, ground fault current flows through the entire resistor. When the contactor is closed a portion of the resistor is bypassed resulting in slightly lower resistance and slightly higher ground fault current.

To avoid transient over-voltages, an HRG resistor must be sized so that the amount of ground fault current the unit will allow to flow exceeds the electrical system’s charging current. As a rule of thumb, charging current is estimated at 1A per 2000KVA of system capacity for low voltage systems and 2A per 2000KVA of system capacity at 4.16kV.

These estimated charging currents increase if surge suppressors are present. Each set of suppressors installed on a low voltage system results in approximately 0.5A of additional charging current and each set of suppressors installed on a 4.16kV system adds 1.5A of additional charging current.

A system with 3000KVA of capacity at 480 volts would have an estimated charging current of 1.5A.Add one set of surge suppressors and the total charging current increases by 0.5A to 2.0A. A standard 5A resistor could be used on this system. Most resistor manufacturers publish detailed estimation tables that can be used to more closely estimate an electrical system’s charging current.

Advantages

1. Enables high impedance fault detection in systems with weak capacitive connection to earth
2. Some phase-to-earth faults are self-cleared.
3. The neutral point resistance can be chosen to limit the possible over voltage transients to 2.5 times the fundamental frequency maximum voltage.
4. Limits phase-to-ground currents to 5-10A.
5. Reduces arcing current and essentially eliminates arc-flash hazards associated with phase-to-ground arcing current conditions only.
6. Will eliminate the mechanical damage and may limit thermal damage to shorted transformer and rotating machinery windings.
7. Prevents operation of over current devices until the fault can be located (when only one phase faults to ground).
8. May be utilized on low voltage systems or medium voltage systems up to 5kV. IEEE Standard 141-1993 states that “high resistance grounding should be restricted to 5kV class or lower systems with charging currents of about 5.5A or less and should not be attempted on 15kV systems, unless proper grounding relaying is employed”.
9. Conductor insulation and surge arrestors must be rated based on the line to-line voltage. Phase-to-neutral loads must be served through an isolation transformer.

Disadvantages

1. Generates extensive earth fault currents when combined with strong or moderate capacitive connection to earth Cost involved.
2. Requires a ground fault detection system to notify the facility engineer that a ground fault condition has occurred.

4. Resonant earthed system

Adding inductive reactance from the system neutral point to ground is an easy method of limiting the available ground fault from something near the maximum 3 phase short circuit capacity (thousands of amperes) to a relatively low value (200 to 800 amperes).

To limit the reactive part of the earth fault current in a power system a neutral point reactor can be connected between the transformer neutral and the station earthing system.

A system in which at least one of the neutrals is connected to earth through an

1. Inductive reactance.
2. Petersen coil / Arc Suppression Coil / Earth Fault Neutralizer.

The current generated by the reactance during an earth fault approximately compensates the capacitive component of the single phase earth fault current, is called a resonant earthed system.

The system is hardly ever exactly tuned, i.e. the reactive current does not exactly equal the capacitive earth fault current of the system.

A system in which the inductive current is slightly larger than the capacitive earth fault current is over compensated. A system in which the induced earth fault current is slightly smaller than the capacitive earth fault current is under compensated.

Resonant neutral earthing

However, experience indicated that this inductive reactance to ground resonates with the system shunt capacitance to ground under arcing ground fault conditions and creates very high transient over voltages on the system. To control the transient over voltages, the design must permit at least 60% of the 3 phase short circuit current to flow underground fault conditions.

Example – A 6000 amp grounding reactor for a system having 10,000 amps 3 phase short circuit capacity available. Due to the high magnitude of ground fault current required to control transient over voltages, inductance grounding is rarely used within industry.

Petersen Coils

A Petersen Coil is connected between the neutral point of the system and earth, and is rated so that the capacitive current in the earth fault is compensated by an inductive current passed by the Petersen Coil. A small residual current will remain, but this is so small that any arc between the faulted phase and earth will not be maintained and the fault will extinguish. Minor earth faults such as a broken pin insulator, could be held on the system without the supply being interrupted. Transient faults would not result in supply interruptions.

Although the standard ‘Peterson coil’ does not compensate the entire earth fault current in a network due to the presence of resistive losses in the lines and coil, it is now possible to apply ‘residual current compensation’ by injecting an additional 180° out of phase current into the neutral via the Peterson coil. The fault current is thereby reduced to practically zero. Such systems are known as ‘Resonant earthing with residual compensation’, and can be considered as a special case of reactive earthing.

Resonant earthing can reduce EPR to a safe level. This is because the Petersen coil can often effectively act as a high impedance NER, which will substantially reduce any earth fault currents, and hence also any corresponding EPR hazards (e.g. touch voltages, step voltages and transferred voltages, including any EPR hazards impressed onto nearby telecommunication networks).

Advantages

1. Small reactive earth fault current independent of the phase to earth capacitance of the system.
2. Enables high impedance fault detection.

Disadvantages

1. Risk of extensive active earth fault losses.
2. High costs associated.

5. Earthing Transformers

For cases where there is no neutral point available for Neutral Earthing (e.g. for a delta winding), an earthing transformer may be used to provide a return path for single phase fault currents.

Earthing transformers

In such cases the impedance of the earthing transformer may be sufficient to act as effective earthing impedance. Additional impedance can be added in series if required. A special ‘zig-zag’ transformer is sometimes used for earthing delta windings to provide a low zero-sequence impedance and high positive and negative sequence impedance to fault currents.

Conclusion

Resistance Grounding Systems have many advantages over solidly grounded systems including arc-flash hazard reduction, limiting mechanical and thermal damage associated with faults, and controlling transient over voltages.

High resistance grounding systems may also be employed to maintain service continuity and assist with locating the source of a fault.

When designing a system with resistors, the design/consulting engineer must consider the specific requirements for conductor insulation ratings, surge arrestor ratings, breaker single-pole duty ratings, and method of serving phase-to-neutral loads.

Comparison of Neutral Earthing System

Reference:

• By Michael D. Seal, P.E., GE Senior Specification Engineer.
• IEEE Standard 141-1993, “Recommended Practice for Electrical Power Distribution for Industrial Plants”
• Don Selkirk, P.Eng, Saskatoon, Saskatchewan Canada