Iacdrive|Automation Solution

Variable frequency drive key functions

Soft Starter, Auto Transformer, Electrolyte, series resistance – wound rotor- etc,). The starting factor of VFD drive is usually 1 up to 1.2 with respect to the rated load current while for Direct On line about 5-6.

Moreover and as you know the variable frequency drive can control the speed of the AC motors in accordance to the formula N=120f/P rpm
where f = the supply frequency and P = number of the Poles.
According to this formula, Motor Speed can be changed either by changing/control the frequency or by changing the number of Poles of the Motor by which step changed in the RPM will be given, while the former gives continuous variable speed as per application demand.

However, as per newly developed power Semi Conductor IGCT based on PWM VFD became the most smart, effective and efficient control device in Industries since is associated also with protective and monitoring means.

From my experience, I know that variable frequency drive plays around with the frequency which the motor operates. It starts at low speed and varies the frequency to attain maximum speed. This reduces the high starting torque usually experienced when motors are started on DOL, Star/Delta etc. When you are driving delicate materials through your conveyors or pumping liquid through pipes etc., VFD plays a useful role. It reduces hammering in pipes usually experienced when using DOL. In large hotel application, variable frequency drive could be used with pressure switches to regulate water flow and reduce hammering when guests are showing. The volume of water required will determine the speed at which the motor runs through VFD control. However, very large KW motors at high voltage level are usually started DOL due to the cost of ac drive but that is when one has enough (power) capacity otherwise it will impact on other users in the network.

Transformer tap changer

Q:
We are frequently changing tap position of Unit station transformer due to voltage problem. What are the impacts on transformer life and is there any solution to minimize this?

A:
Having more tap changing per week is not bad, but it wears out the tap changer faster and does require more maintenance. We set our bandwidth at 1.5 volts, 0.75 up and 0.75 down, with a minimum timer of 30 seconds (voltage has to be out of bandwidth for more than 30 seconds for tap changer to move). Voltage for the OLTC controller is based on a 120V base. This normally worked well for our city loads, but perhaps your loads vary even more. I have used a bandwidth of 2 volts maximum with good success to keep the OLTC from tapping more than I liked (250 taps per week, and naturally if your loads swing more than what we had then your taps per week are going to be higher). The 250 count per week maximum is just a goal we set to try and maximize the life of our tap changers and minimize our maintenance. Looking at your timer and bandwidth may help reduce the taps per week. When the tap count per week jumps up suddenly you can suspect the controller might be bad. One more thing, I never use the X setting, just the R. I would draw the voltage “curve” versus the current and figure out my maximum voltage based on the maximum current. This worked well for me for my 23 years of utility work (again, these are city loads, base power factor during the summer was 85%). The power factor would be higher in the winter and lower in the summer (summer at 85% and winter was over 95% because in the winter we had no air conditioning loads). That is why I did not use the X setting (one setting year round).

Since it appears that you are talking about OLTC, then 250 taps per week is the maximum level that is reasonable in my opinion for a transformer serving varying loads, such as a city. I worked for electric utilities in the US for 23 years and looked at load tap changing counts every week for over 450 MW of transformers (15 MVA to 46 MVA all serving city loads). This count is the top end we would allow. The average count was in the 125-150 range per week (summer loads, with wide varying loads each day, winter loads caused less tapping per week). Oil does not degrade rapidly in the OLTC (that is operating properly) even with a maximum of 250 counts per week, but we would take oil samples every year of the OLTC and the transformer to keep tabs on their overall health. If the oil in the OLTC does degrade rapidly, then there is a good chance that the alignment of the taps is improper and arcing may be occurring during the tap changing.

OLTC has little or no effect on the life of the transformer. Also, there are two separate oil compartments, one for the OLTC and one for the transformer.

VFD Kinetic Buffering and Flying restart

Voltage Loss ride through with flying restart:
In this method, when the voltage sag causes the variable frequency drive to reach its undervoltage trip level, the VFD drive will shut off the inverter section and thus remove power from the motor instead of tripping. The motor will coast down during the duration of the sag and, as soon as the voltage recovers, the VFD will start into the still-spinning motor and ramp up to set speed. How much the motor speed will drop depends on the inertia of the load and the duration of the sag.
You have to configure the VFD for flying restart. During low input voltage the inverter section is cut off to maintain the DC bus voltage. If the voltage restores before the DC bus voltage goes below the tripping value, the inverter is again put on but the driven load speed has already reduced due to brief period of no voltage at the motor terminal. Flying restart feature enables the variable frequency drive to restart the Motor at the same speed at which the motor is operating thus preventing any high current. So it is basically catching a spinning motor. Without flying restart high current will be observed once the inverter section is put ON. Flying restart feature is also helpful if you want to restart a motor which is already spinning.

Kinetic backup
This option, which is also provided by some variable frequency drive manufacturers, uses the energy stored in the mechanical load to keep the DC bus voltage from dropping down to the trip level. This is accomplished by running the inverter section during a voltage sag at a frequency slightly below the motor frequency, causing the motor to act as a generator. Similar to the flying restart option, the motor speed will drop while it is acting as a generator, however the advantage is that the motor is never disconnected from the drive. This option works best for those high-inertia loads.
Kinetic buffering is a feature to prevent the variable frequency drive from tripping during voltage sags. If the VFD trips due to DC bus undervoltage there is no need for kinetic buffering.

Hysteresis and eddy currents

Hysteresis would also lead to harmonics, complicating things even further. And, when considering unbalanced three-phase systems and/or the presence of harmonics, the conventional tools for power system analysis might not be applicable.

The losses due to hysteresis are limited by using better materials in transformer core. Eddy current losses are limited by using laminated construction. These losses are a relatively small portion of the total losses in a power system. Most of the losses are Joule losses (currents and resistances).

Because “energy” might be misinterpreted. Sure, But they do so twice (one positive, one negative) on every cycle of the AC system, so the average energy is zero.
There is an energy “exchange” between magnetic and electric fields. But no, that is not an oscillation in energy (kWh), not something that you could measure, for instance, in the torques on a mechanical shaft (that is purely kW, active power).

Charging Power transformer through lower rated grid auto Transformer

What is the Reactive Power?

For a “physical” interpretation, reactive current (power/KVA flow), in my opinion is best looked at from the perspective of a generator connected directly to an infinite bus (in LV generators this is the norm).

The generator when connected to the system, “see’s/feels” the parallel impedance combination of all other generators (circa 3 ohms each) with respect to ground – which basically parallel to equate to a zero impedance in terms of restriction to any current flow out of our generator.

Post initial synchronization, the system voltage prevents currents from flowing into or out of the generator due to pressure (voltage) balance of our generator matching that of the system voltage.

If you (as the generator operator), try to lift the generator voltage, the result will only be heaps of current output flowing into the system – but with no actual extra power generated!

This is due to the fact that to achieve the extra generator voltage setpoint you desired, the generator must send out enough current into the system impedance to create the back emf required to achieve the new desired generator terminal voltage setpoint.

But because the system impedance to ground is very low (as it actually is) – then despite the extra current sent out in that fruitless attempt, the generator is near impotent to make any substantial effect on raising the “system” voltage – “fruitless” current sent out.

In a DC sense you can equate this to a small DC generator trying to lift the voltage of a load system that has a zener diode installed across that system load.

Back to the AC world, ….that current sent out in the fruitless attempt to lift system voltage must flow through the parallel low impedance of the other connected generators (each of those working against you – lowering their own generator excitation, hell bent on keeping their own same old voltage set points), thwarting our futile attempt to achieve a raise in the system voltage.

All those generators, although collectively of low impedance, compose virtually no resistance, compared to their inductive reactance. Hence all our little generators current flow – in its futile attempt to lift system volts – is virtually purely inductive.

So we have heaps of current flowing out in our attempt to lift generator volts, but because the current is 90 degrees lagging the voltage, the only power imposed on the generator prime mover is that due to the resistance of the generator windings (circa 1% of the full load current rating – hence basically un-noticeable).

Hence the physical interpretation of VAR’s, is actually simply a look at the voltage balance perspective of an electricity network. It’s the collective attempt of many parallel-connected generators to influence the system voltage – either trying to raise the voltage at a particular node (positive VAR’s) or trying to reduce the voltage at a particular node (negative VAR’s flowing back through our generator due to our attempt to lower our generator setpoint – which “lets current in”).

Reactive Power is an electrical parameter that exist in a sinusoidal (AC circuits). It maybe zero or a certain magnitude. It maybe capacitive in nature or it maybe inductive nature. In the power triangle, it is the vertical power component (plus or minus / capacitive or reactive). It may be supplied from power sending end (grid or generator) on from the power receiving end (load). A capacitor bank connected on the grid provides capacitive reactive power. An inductor bank connected on the grid provides inductive reactive power. Both of them have magnitude. Reactive power also influences the between phase angle displacement between the voltage and the current. It is power but reactive power.

Pressure switch on three phase motor

Q: Is there a way of connecting a three phase pressure control switch on a three phase motor. Also is there a three phase float switch for a three phase submersible pump i know of a single phase switch.

A: The switch only needs to have a single contact since you use a three-phase motor controller to operate the motor. The switch is wired into the low voltage contactor coil circuit to turn the motor on and off.

You can connect a pressure switch for the purpose of motor control on its low level pressure or high level pressure. It is advisable to utilize pressure switch on the control cct, and connect the contactor coils through the auxiliary NC/NO contacts depending on whether you are interested on low pressure or high pressure control. It is not good practice to allow power cct through control ccts. You don’t need a 3 phase float switch to achieve controls of a 3phase submersible pump. You should be interested in the auxiliary terminals which will allow control flexibility for low level and upper level control. A single phase float switch will give you desired result. If you are controlling more than 1 no. 3phase motors located at different places from the same pressure signal, then your 3 phase pressure switch can be employed to control the different motors separately. In addition, some terminals could be used for indication/annunciation purposes. However, a single phase pressure switch can give you all the controls you need for a 3phase motor.

How to select a breaker?

Before breaker’s selecting for your electrical system, you need to calculate value of expected short circuit current at the place of breaker’s installation. Then you need to calculate value of heat pulse and 1s current (expected value of current during one second). After that you need to calculate power of breaker and finally, after all, you can select appropriate breaker. Values of characteristics of selected breaker need to be higher from calculated values of characteristics of your power system.

You can calculate operational current of breaker using this expression:

Inp=SnT/((sqrt(3))*Un)

After that, you need to calculate expected value of surge current:

kud=1+e(-0,01/Tae)
Iud=(sqrt(2))*kud*I’

After that, you need to calculate expected value of heat impulse:

A=(sqr(I0″))*Tae*(1-e(-2*ti/Tae))+(sqr(I’))*(ti+Td”)

And finally, you need to calculate 1s current (expected value of current during 1s):

I1s=sqrt(A/1s)

So, current of interruption of your breaker and power of interruption of your breaker are:

Ii=I’
Si=(sqrt(3))*Un*Ii

Additional expressions that you can use during your calculation:

I0″=Un/((sqrt(3))*Ze”);
I”=1,1*Un/((sqrt(3))*Ze”);
I’=1,15*Un/((sqrt(3))*Ze’);

where are:

ti-time of interruption
Inp-operational current of breaker
SnT-rated power of transformer
Un-rated voltage
kud-surge coefficient
Tae-time constant of aperiodic component of short circuit current
Iud-surge current
A-heat impulse
I0″-short circuit current in subtransient period (generators are in no-load conditions)
I’-short circuit current in transient period
Td”-time constant of subtransient component of short circuit current
I1s-current during one second
Ii=expected value of current of interruption of your breaker
Si=expected value of power of interruption of your breaker
Ze”-equivalent impedance of power system in the place of fault (subtransient period)
I”-short circuit current in subtransient period (generators are in full-load conditions)
I’-short circuit current in transient period
Ze’-equivalent impedanse of power system in the place of fault (transient period)

For a branch circuit feeding a single pump, you would generally size the circuit at 125% of the pump’s full-load amperage. If you’re not using a variable frequency drive or soft starter (which have built-in overload protection), you would use a Motor-circuit protector (MCP) breaker that has both thermal and magnetic trip capability. Sizing would be according the breaker manufacturer’s recommendations for a motor of a given horsepower, but not larger than would be required to protect the circuit conductors.

“The total load of an area” is much too ambiguous to answer. If you have lighting and receptacles, you’re going to need a different type of breaker than if you have motors or mixed types of load. There is no general approach. Circuit breaker types are very specific to the application.

Safety should not be taken lightly. Installing the wrong type of breaker could result in equipment damage and/or physical harm.

There are instantaneous breakers as well as time delay breakers. For time delay breaker, for example, you go 250% maximum of the rated current based upon the HP of a motor (look in the NEC), not on the nameplate label. The nameplate current value is for overload protection. Also try to size the breaker so that the conductors are protected.

As we kn

Variable frequency drive Constant Torque/Variable Torque

A typical variable torque application would be a centrifugal pump. A typical constant torque application would be a conveyor, and there are positive displacement pumps that are also constant torque. Have a talk with a mechanical engineer, get them to show you curves and explain.

DBR stands for Dynamic braking resistor. Regeneration will happen when the motor rotates a speed higher than the speed which corresponds to the frequency setpoint ie.. the rotor speed is more than the speed of the rotating magnetic field.
Regeneration feeds back energy to the drive which results in DC bus overvoltage. To prevent the drive from tripping due to DC bus overvoltage the DBRs are used. The regenerative energy is discharged in the resistor as heat.

Regenerative Breaking – we used to have VFD on a vehicle rolling road. So when the car is travelling faster than the VFD, the VFD generate back into the power supply – causing a break effect. If you had a large mass- large inertia that you want to stop quickly, you need to break the load- you can do that with regenerative breaking. Otherwise, disconnecting the variable frequency drive, will mean your load just freely rotates, and that can mean it will take 30 minute to come to a stop for a large inertia.

Active Front end- I first came across this term with ABB. It is all to do with how to mitigate harmonics from VFDs. You can use phase shift transformers, but with modern electronics, you can use a opposite phase current to counter act the harmonics generated from the VFD. So the overall impact on the network is small.
In active front end technology the rectifier is basically an inverter with IGBTs.
The main advantage are:
1) Low current THD <5 %
2) It is basically a four quadrant rectifier .Referring my last post please note that you will not require a DBR with AFE. The increase in voltage of DC Bus due to regeneration can be fed back to the input AC supply in the form of energy. So you don’t require a DBR.
3) AFE drives have very good immunity to input voltage fluctuations.

Just an advice. Please go through variable frequency drive literatures (available in plenty) to have a good understanding of the different VFD technologies.
Selection of VFD requires proper understanding of the VFDs and the overall electrical system. There are lots of marketing gimmicks in the world of VFD. Always be careful before selecting a VFD specially higher KW drives.

For large drives, you need to speak with supplier to configure your machine correctly. There are many options, but yes active front ends are available. But there are other solutions; ASI Robicon use a current driven VFD, so harmonics are lessened in the first place, so an active front end is not the right terminology. It is a different solution. I used a 10MW version of that type of ac drive. I think Siemens have bought the company since.

VFD PWM and PAM definition

PWM is shorted for Pulse Width Modulation, it’s a variable frequency drive (VFD) regulate way to change the pulse width according to certain rules to adjust the output volume and waveform.

PAM is shorted for Pulse Amplitude Modulation, it’s to change the pulse amplitude according to certain rules pulse amplitude pulse train to adjust the variable frequency drive output volume and waveform.