Blog – Page 9 – AC DRIVES SOLUTION.

AQ: Change transformer vector group

Transformer nameplate vector group is YNd1. However, the nature of connection on both its primary and secondary side is such that:
Generator phase A = Transformer phase c
Generator phase B = Transformer phase b
Generator phase C = Transformer phase a

Also, on transformer HV (secondary connected to grid),
Transformer phase A = Grid phase C
Transformer phase B = Grid phase B
Transformer phase C = Grid phase A

The questions are:

1. How does this affect the vector group (YNd1) of the transformer? Will it be changed to YNd11?
2. Will it make any difference as far as the vector group is concerned if instead of phase A and C, phase B and C were swapped on both ends of the transformer?
3. The transformer protection relay is configured for YNd1 group, and it is reading negative phase sequence current (ACB instead of ABC). Changing the vector group configuration will solve the problem?
4. Relay is used for differential protection (percentage differential) of the transformer.
Will this negative phase sequence affect normal operation of the transformer in any way?

1. How does this affect the vector group (YNd1) of the transformer? Will it be changed to YNd11?

Yes, the name plate vector group of a transformer is only valid for a standard phase rotation ABC. for a phase rotation ACB the apparent vector group will be YNd11.

2. Will it make any difference as far as the vector group is concerned if instead of phase A and C, phase B and C were swapped on both ends of the transformer?

No, by swapping any two phases the rotation becomes no standard and the apparent vector group will become YNd1

3. The transformer protection relay is configured for YNd1 group, and it is reading negative phase sequence current (ACB instead of ABC). Changing the vector group configuration will solve the problem?

I think the way the relay is configured at the moment will give you problems, if I’m correct you should be able to see differential current when the transformer is loaded, and it is likely to trip on the first through fault (can you confirm this). To resolve this issue you have two options.
i) Set the vector group to YNd11 in the relay, this will remove the differential current but will mean the relays see’s 100% NPS current and 0% PPS current, this may give you problem if you have any NPS elements enabled in the relay ( inter turn fault detection, directional elements etc)
ii)Set the vector group to YNd1 and the phase rotation setting to non standard ACB this will get rid of the NPS currents and the differential current, so this is probably the best solution.

4. Relay is used for differential protection (percentage differential) of the transformer.
Will this negative phase sequence affect normal operation of the transformer in any way?

No, there will be no problem with the transformer itself just the relay protecting it.

As i said previously if I’m understanding the problem correctly, you should be able to see differential current at the moment when the transformer is loaded, is this correct?

AQ: 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.

AQ: Transformer Magnetic Design

AQ: Why industrial induction motor star point not grounded?

In any electrical system, we limit the neutral grounding to 1 or 2 locations at the power source, eg, the star-points of generators or transformers. By keeping the grounded neutrals at the power source, earth leakage current will be flowing radially from the power source to the point of short-circuit at downstream. In this way the direction of earth fault current flow can be easily identified and the earth fault protection relays in the distribution system can easily be coordinated.

Grounding a motor star point will create an earth path for earth leakage current to flow through that motor’s star point. If there are 10 motors in a process plant and their star points are all grounded, there are 10 additional paths for earth leakage currents to flow through.
If all the motors’ star points are grounded in this way the earth fault current detections by the protection relays will be complicated and likely they will trip at the incorrect locations because earth fault currents are flowing in many directions toward multiple grounded neutral points.

Therefore the electrical consumers (ie the load, including the capacitor banks), even if they are star connected, are not to be grounded.

Grounding of neutral point is not being decided base on the presence of unbalance loads. It is decided for safety reason and for earth fault protection requirement. Unbalance 3-phase load will result in some current flowing through the neutral conductor but it doesn’t result in a (residual) current flowing through the neutral-ground connection.

Motor is a balanced 3-phase load, this I agree. However when the system supply voltage is unbalanced caused by unbalanced loads somewhere else or due to network conductors problem, the motor operating under unbalance voltage will result in unbalance current in the 3 windings. The same is true for the generator windings under that condition. The design engineer may then decide that individual machines should be fixed with negative phase sequence current protection.

Even if there is a neutral voltage shift in the induction motor, we should not ground the motor’s neutral point. If you ground it, it may create nuisance trip of earth fault protection relays (the motor’s EF relay, upstream EF relays, or the EF relay connected to transformer’s neutral-ground CT).

I am sure in reality, there is some neutral voltage shift in motor’s star point. However, there is no harm with that.

If you ground the star point, you still will not get rid of the unbalance current/voltage from the motor windings. There the negative sequence current is still present in the motor winding.
If you think an unbalance voltage supply is causing problem to the motors, you should solve the unbalance voltage problem elsewhere, not by grounding the motor’s star point.

AQ: 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).

AQ: Why there are different type’s conductor cables, like EPR, XLPE

As far as the cables insulation material is concerned, EPR and XLPE insulated cables to some extent are having similar properties. In this respect, there are different types of Electrical cables such as ETFE ,FP, HOFR , LSF,LSOH, MI, PILC, TRS, VR, CTS, CSP, PTFE, etc.

However, it may be necessary to conduct a rough comparison (insulation) between the PVC and XLPE cables to clear the picture.
1. PVC/SWA/PVC multicore sheathed cables are manufactured in all sizes up to 400 mm² in accordance to BS 6346, the allowable operating temperature up to 70 °C.
2. XLPE Cables are used at max. ambient temp. of 90°C and are made to BS 5467. These cables have better insulation qualities than PVC and available in sizes up to 400 mm² or 1000 mm² Single Core.

Both type of cables are easy to lay and bending and they have less bending radius up 8 times nominal diameter.

These Different types of cables are not only based on the insulation material, are also either classified as cables of Aluminum conductors or Copper Conductors. Regardless, each has it own characteristics which can be appropriate to a range of installation / application since there are many wiring systems that may be adopted. In deciding the type of wiring system for particular, many factors have to be taken into consideration e.g….

a. Whether alteration & extensions are expected or not. Also, whether is going to be executed during the construction, in a completed project or as an extension of existing system.
b. Type of Project / building, function, purposes and ambient and environmental conditions.
c. Expected duration (life time) of the Installation.
d. The required layout, safety & constraints.
e. Feasibility & Cost

Eventually, I confirm that armored PVC & XLPE Insulated cables are now being used widely for feeders, submain cables & Industrial Installations.
Such Cable consists of multi conductors insulated by PVC or XLPE, with PVC sheath and steel wire armor (SWA), and PVC sheath overall.

AQ: Circulating current in parallel transformers

When two transformers are in a parallel group, a transformer with a higher tap position will typically have a higher (LV side) no-load voltage than the other one with a lower tap position. These unequal no-load voltages (unequal tap positions) will cause a circulating current to flow through the parallel connected transformers. A transformer with higher no-load voltage (typically higher tap position) will produce circulating current, while a transformer with lower no-load voltage (typically lower tap position) will receive circulating current.

When load is connected on these two parallel transformers, the circulating current will remain the same, but now it will be superimposed on the load current in each transformer, i.e. for a transformer producing circulating current, this will be added to its load current, and for a transformer receiving circulating current, this will be subtracted from its load current.

Thus voltage control of parallel transformers with the circulating current method aims to minimize the circulating current while keeping the voltage at the target value.

In case of a parallel operation of transformers, the electric current carried by these transformers are inversely proportional to their internal impedance. Think of it as two parallel impedances in a simple circuit behind a voltage source, you will have equal currents through each impedance only if you have two identical impedances, in some cases as stated above, tapping could be a problem, the other one is the actual manufacturing tolerances which could diverge by almost 5-10%, if the transformers are manufactured by different suppliers or not within the same batch. So, the difference in current between the currents through these two impedances is basically the circulating current as it is not seen outside these parallel impedances.

The currents that are produces due to magnetic flux circulation in the core are called eddy currents and these eddy currents are responsible for core losses in transformer.
While the circulating currents are the zero sequence currents that may be produces due to following causes.
1- when there is three phase transformer the (3rd, 5th, 7th….) harmonic currents which are called zero sequence currents from all the three winding of three phase transformer add up and become considerable even in loaded conditions these currents have no path in Y/Y connection of transformer so a tertiary winding is provided co conduct these currents but in Y/d or D/y connection these currents circulate in delta winding.
2- Whenever there is unbalanced loading in transformer. In which with positive sequence, negative sequence and zero sequence currents are also produced which cause circulating currents.
3- When the transformer banks are used and the transformers have phase between them then circulating currents are produced between them, than transformers in the bank get loaded without being shearing the power to the load.

AQ: 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.

AQ: Is frequency inverter better than soft starter in motor control?

There are hundreds of applications for a frequency inverter. I use them on a pump to test pumps with voltages from 208-600VAC 3PH 50 and 60 HZ. You just have to size the frequency inverter to the largest 208 HP motor, so it can handle the current. Many people are installing them on pumps, fans and air compressors to get the energy savings of lowering the speed on the motor to maintain the pressure, temperature and flow. Frequency inverters also have the ability to ride through power dips, since the DC bus to store in a capacitor bank.

It is correct the frequency inverter will reduce the staring current of and induction Motor, but as all of you know that the motor have to drive a load the starting torque is related to starting current, also the main role of frequency inverter is to control the speed.
The starting current is related to the rotor conductor structure or classes because we can get direct starting currents within 1.5-4 times the full load depend on the squirrel cage design or construction.

The effect is, that at the reduced frequency during start, the full torque can still be developed at nominal current. As soon as the frequency hits the nominal slip frequency, the nominal torque will also be developed, at nominal full-load current. (The slip frequency is the nominal frequency multiplied by the full load slip percentage, i.e. around 2.5Hz for a 50Hz motor with a full load slip of 5%).

It really depends on the application. If you are only interested in starting current, then soft start is what you need.

AQ: Circuit Breakers tests

1- For small circuit breakers we can do the test of Magnetic protection behavior by using “Injection Current Apparatus”, and suppose the CB’s results were good, do you think it’s enough? I’m sure not, because by this apparatus we can inject the necessary current with a very low voltage value (5-15V), so, do you think that the arc will be the same if we have the same current but with “400V”?

2- The same question for “Short Circuit Tests”

Personally, I done the tests of many MCBs for different manufactures by using “Injection Current Apparatus”, and I saw the same tests in laboratory in France for the same MCBs by injection the same currents values with 230V or 400V depending on the CB, be sure, the results weren’t the same, we found some differences for Magnetic protection tests, and big differences for Short Circuit tests.