Blog – Page 8 – AC DRIVES SOLUTION.

AQ: “Hissing sound” in SF 6 Gas insulated HV Switch Gear

This could be internal corona discharge. The switchgear should be de-energized and closely examined. That means pump out the SF6 and take it apart. Examine all insulating components.

Especially if the sound can be localized to portions of the switchgear which do not have bushings for connection to overhead lines. Even if the sound is in the area of air bushings, deenergizing will allow more in-depth inspection and addressing any sharp edges or cracked insulators, etc.

Take this pieces of equipment out of service immediately, perform a “hi-pot” or high potential test on the various elements of the switchgear and attempt to locate the area that is “leaking” to ground (or between phases). Inspect closely for indications of tracking on insulators from corona discharge and replace any compromised components. After component replacement, installation of new SF6 gas and other repairs, re-run the Hi-Pot test to confirm that the switchgear is able to withstand voltages at least 50% greater than the name-plate rating. Of course all of this advice is worthless if the unit has already failed.

Remember that a Hi-pot is actually a destructive test. It challenges the insulation to the point of breakdown. Check the vendor recommendations before you Hi-pot equipment that has been in-service.

AQ: 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.

AQ: Motor power cable – bigger or smaller?

When a choosing a power cable for a motor, we prefer using one larger diameter cable than two smaller diameter cables in parallel, although it would cost less to do so. Why?

1. Conductors/Cables/Feeders in parallel connection generally are not recommended unless there is no option, therefore it can be adopted under the following conditions:
i. Cables are of the same material and cross section area.
ii. Are of the same route and length.
iii. The sum of the current carring capacity of the parallel circuits after applying all necessary applicable correction factors should be greater than the nominal regulated current of the protective device.
iv. The current carrying capacity (before derating) shall be not less than 300A (according to the local authority/Service provider requirement/regulation).
v. Capability of addressing the Thermal & electrodynamics constraints in proper way.

2. Some designs call for parallel connection so as to:
i. Overcome the voltage drop.
ii. Avoid the difficulties of installing big size cables (bending, pulling) due corridor limitation,etc.
iii. Meet the Power demand.
iv. Mitigate the cost (Costwise).

3. For electrical Motors, two connections are normally required. One from MDB to Motor CP and other from CP to the Motor.
By virtue of the requirement of Delta/star starter, two cables are required (Mandatory) between CP & motor (one will be dead just after changing to delta connection).
While the connection from the MDB to CP will be one, sized according to the Motor rating.

However, Parallel connection of Feeders need an expert engineer(s) to meet the requirement since Short Circuit fault protection for parallel circuits require further evaluation from the Engineer that the impact of the short circuit current within the parallel section will have severe fault due to fault current path that can occur in addition subtransient contribution of the downstream system.

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.