Iacdrive|Automation Solution

Flashover in busbars

As for XLPE cable testing, if XLPE is used for insulation in the switchgear, the cross linking will be treed by HV DC and permanently destroyed. For this reason, HV DC is no longer used for XLPE cable testing. The switchgear should have a power frequency withstand test only and not HV DC. Refer to the relevant switchgear standard for the applied rms voltage. Any XLPE insulation will need to be replaced as it is most likely has been damaged by treeing of the cross linkages in the insulation. A maximum of say 2.5 kV DC is allowed for IR and PI only.

Humidity plays important part in flashover. We faced a problem of flashovers in Air insulated 11kV Switchgear busbar compartments in rainy seasons. Any sharp edge will ionize the surrounding air, which becomes conductive to high voltage discharge. Moisture will hasten the process of discharge. During HV test also this aspect should be kept in mind.

And make sure the following:
Clean all the supporting bus insulators and spouts with CRC spray.
Ensure the earth bus continuity and its connection with the earth grid.
all PTs are taken out.
all CT ckt output shorted at the panel.
All LAs are disconnected
Conduct a general cleaning of busbars through CRC-sprays.
Megger the bus bar with 5KV between phases, and between phase to earth for 1 mints before HV test.
Ensure the earth bus continuity and its connection with the earth grid.
Use AC high voltage test preferably
Connect HV test kit body ground to the SWGR body ground.
Apply 80% of the power frequency voltage applied at the FAT test.
If you are doing with AC hv kit then this may be a larger unit and leakage current is exceeding and tripping.
Try for smaller sections of busbars/increase the leakage current if options are available.
Rate of rise of voltage should be in steps of 2KV/s and gradual.
Check tripping function of the test kit.
Apply voltage betweenL1-(L2+L3)=G-1mints
apply voltage in the same way between other phases also.
If it withstands ok alternately you have to go for individual inspection of the insulators/spouts.

Cable faults/fails

There are only 2 distinct types of Cable fault
1. Due to system Parameter or operating conditions – which you have to take care at the initial design stage for selection of the cable. There is a long list of checks – Design Engineers know.
For example, if 50 sq.mm cable is adequate for a particular Load, you may have to choose higher size in relation to the Fault Level. In urban Distribution system, you will find large size of cable is connected to a small size distribution Transformer.

2. Failure of Cable does not normally occur in the run of the cable unless it is damaged for external reasons. Damaged cable may not fail unless there is ingress of moisture / water through the damage. You will find cable failing during rainy season, high tide in the coastal areas.

Cable fails at the joints mainly because the (construction) characteristics of Cable are changed at the joints – joints become weak links in the run of the cable.

It is a well documented phenomenon that underground cables fail a week or so after lightning activity. Some of the can be attributed to lightning surges that enter the primary conductor and reflect off an open as you indicate. I believe the majority of the failures come from lightning strikes on adjacent structures or trees that reach the cable through ground and cause slight damages to the cable insulation. The maddening part related to customer service is the cables end up failing on a sunny day. Most customers understand outages during inclement weather but are not so understanding of outages on clear days.

Resistance Grounding System

Low Resistance Grounding:
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.
4. Does not prevent operation of overcurrent devices.
5. Does not require a ground fault detection system.
6. May be utilized on medium or high voltage systems. GE offers low
resistance grounding systems up to 72kV line-to-line.
7. Conductor insulation and surge arrestors must be rated based on the lineto-
line voltage. Phase-to-neutral loads must be served through an
isolation transformer.

High Resistance Grounding:
1. Limits phase-to-ground currents to 5-10A.
2. Reduces arcing current and essentially eliminates arc-flash hazards
associated with phase-to-ground arcing current conditions only.
3. Will eliminate the mechanical damage and may limit thermal damage to
shorted transformer and rotating machinery windings.
4. Prevents operation of overcurrent devices until the fault can be located
(when only one phase faults to ground).
5. Requires a ground fault detection system to notify the facility engineer that
a ground fault condition has occurred.
6. 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”.
7. Conductor insulation and surge arrestors must be rated based on the lineto-
line voltage. Phase-to-neutral loads must be served through an
isolation transformer.

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 overvoltages. 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.

What causes cables to fault during weather seasonal changes?

I currently work for a small utility with a small amount of underground installations but a lot of it is aging and failing during weather changes. I am curious as to why it happens during weather changes and if there are scientific facts that can support it? Is there a way to predict when a cable will fail based on weather patterns? I’ve heard of different opinions on the matter, but is there a proven reason why? It is my goal as a young engineer and Gonzaga T&D engineering graduate student to learn more about these phenomena’s and what better way than to hear it from industry professionals in a technical discussion?

Scenario #1: Lightning strikes during summer on power cable installations can cause voltage spikes on the line, which in turn doubles back when it finds the open point on an underground cable installation. The initial voltage spike can cause the insulation of the cable to deteriorate or fail, and the reflection of the surge can cause the voltage to spike which can then finish off the already deteriorating insulation if it hadn’t faulted from the initial surge. Side note: This is why it is good practice to have transformers with load on them at the end of a cable run, or lightning arrestor at the termination points of an underground run and not just an open switch. Faults, recloser operations and other switching events can also cause a voltage spike on underground installations which can break down the cable insulation, thus making it more susceptible to failing after future events.

Scenario #2: Cables could fail more during the weather change due to the stresses that are inserted in to the cables during heavy irrigation motor start-ups and operation. Today you will see more soft-starts on your pump motors. With older cable supplying energy to older pumps you may find an across the line motor starter at the end of it. Cross-line starters rapidly heat the cables that have laid dormant over the cold winter months. If there was any sort of treeing, insulation deterioration, rodents chewing on the dormant cable, dig-ins, or any other common cable damaging scenarios during the winter, the startup will speed the deterioration process up in these locations, which in turn lead to cable faults.

Scenario #3: In areas where older open concentric cable has been installed, you are most likely experiencing many faults if it hasn’t already been changed out for newer jacketed solid-dielectric cable. As the ground dries out in the spring/summer, you will see higher resistances on the return path of the old and deteriorating open concentric neutrals. Without the cable being in wet conditions as it was throughout the winter, the electric field around the cable is no longer uniform and in some cases is a complete loss of your neutral.

Regardless of the insulation you use on cables, you most likely have faults. Maybe you’ve been “lucky” and it’s only in your joints and terminations? Regardless of which type of cable insulation, temperature has a significant impact on the dielectric withstand of the cable (i.e. higher temperatures will result in lower dielectric strength properties). Drying conditions also equates to higher insulation temperature due to poor heat transfer characteristics of your cable.

There are some common points in each of the above three scenarios but there really isn’t any scientific proof, just observations. Does it depend on your system load factor, your power factor, your installation practices, or even your cable design? Is it all of the above or is it much more simple than that? Is it different between different manufacturers of cable? Are there different scenarios that you’ve seen or heard of?

480volt Solidly grounded system versus HRG system

High Resistance Ground will limit the current to about 5 amps. The good news is that it no longer be necessary to trip on a ground fault. The bad news is that you may not connect any single phase loads to that substation. If the single phase loads are an issue, it may be possible to support all those loads with one or two feeders. In that situation, an isolation transformer is added to create a separately derived ground.

High resistance grounding is an excellent option in systems where continuity of service is important. However it is important to understand that if a ground fault occurs, it needs to located and repaired. This can be at a time convenient to facility operation, but it must be chased down and fixed.

This troubleshooting is accomplished by pulsing the ground fault current between 5 and 8 amps. Then a hand held clamp on ammeter is used to search out the offending feeder. Most HRG manufacturers include this feature into their design.

480volt solid ground system the fault current L-g is limited to the fault rating of the system may be 50KA,and usually have a disastrous consequences during faults and system has to be properly selected and protected accordingly.

Presently for some emergency power systems in power plants there is a 480voltb 3ph supply is made with neutral grounded through a NGT ie to limit the L-g fault current within 10Amp, and this may result in overvoltage of the other two phases too. Overall this becomes a more stable system.

I would be very hesitant to use HRG for a medium voltage system. While a fault is on the system the neutral will not be at earth potential. This is usually not so important because the neutral is not carried to any of the loads on a high resistance grounded system. But the effect of the neutral straying away from ground potential is the two unfaulted phases will have a higher than normal line-to-ground voltage. Low voltage systems have a lot of built in margin in their insulation so it is not a problem with most equipment connected to that system. However MV equipment does not have so much “spare” insulation so the effect of high resistance grounding of a MV system is that it significantly increases the chance of migrating the fault from a single-line-to-ground fault to a double-line-to-ground or line-to-line fault.

Also at the point of the fault, the energy of 5 amps flowing in a 480 volt or 400 volt system may be somewhat dangerous but in most cases will be dissipated easily. On a higher voltage system, whether it is 4.16kV, 6.6kV, or higher, the energy at the point of the fault is higher and is much more likely to damage the insulation on the adjacent conductors and quickly turn into a more severe fault.

So I would resist using a high resistance grounded design on a medium voltage system (over 2000 volts).

The effect of power failure on VFD

Q: I am planning to put some variable frequency drives on non-critical section of factory where there will be planned interruption of 30 seconds but 2 times a day.

A: Why are you going to use VFD, variable frequency drives are expensive. What is the application?
If the application require fix speed / rate Soft Start device is required.

However, if there might be frequent start stop (Power OFF/ON) AC Contractor Duty AC3 are recommended to be used to bypass the Soft Starter or Static device once the required motor speed is reached and then Start/stop have no impact on the installation.

The technique of using AC3 Contactors, is not applicable for VFD if the VFD is necessary for application. In this case the other advantage associated with VFD no longer will be valid (Protection, control and monitoring).

AC induction motor constant power

An AC induction motor is supposed to be a constant power motor, which implies it draws more current on low voltage. Consider a motor running a constant torque load at a particular speed. Suppose now the voltage is reduced, which should cause it to settle down at a lower speed supplying the same torque as per the new torque speed characteristic. If we consider the electrical side, higher slip will cause more current to be drawn that too at higher pf, which should maintain the power justifying the above theory. But on the mechanical side the new output power Torque x speed is supposed to be lesser now as speed is less now. Is it this contradiction?

The following guidelines prove there is no contradiction since your question about Motor under running condition:

1. Torque / Slip characteristic for Induction Motor has three Zones.
a)- Starting Torque @ S=1, selection of this torque depends on the application. The starting should be greater the system torque at time of starting.
b)- Unstable Zone during which acceleration and torque development took place. This zone up to the Max. Torque can be developed.
In this regard, it may be necessary to mention that the seventh harmonics to be considered otherwise crawling / clogging may occur.
c)- Normal Operating Zone. NOZ about which your query raised. NOZ ranged as ” 0 < S< 1″ ie up to the Max. Torque. It is worth mentioning that Max. torque always remain the same regardless to its location of occurrence.

2. The torque is directly proportional to rotor resistance “r2” & varies with slip “S”. hence increase of rotor resistance is the most practical method of changing the torque (ie wound rotor Slip ring Motors). Moreover, the Max torque achieved when rotor Resistance “r2” = The Stator impedance, At starting S=1.

3. Accordingly, the ration r2/x2 gives the location of the max. Torque w.r.t Slip (if the max. torque is required at starting (S=!) then r2/x2 should equal “1”.

4. load being constant. Mechanical output = Electrical input – losses.

5. Tmax Propotional to Sq(v). decrease of 50% of the supply voltage generate a reduction of 20% in the max. running Torque (zone c) , increase in slip and also Full load current and temperature raise increase while the full load speed decrease. the status of the above parameters will be opposite if the voltage increases by 10%.

Based on the above, in all cases since the Motor is running within the operating range will be no issue unless the supply voltage falls behind the above limits (-50%, +110%). Accordingly, variable frequency drives provided by under/Over voltage protection relay to avoid damage to insulation due to Heat/temperature rise that will be generated due to excessive current intend to composite load.

Parallel operation of autotransformers

Q:
We have 2 no 160MVA 220/132/11 kV transformers with short circuit impedance 46.06 ohm, and one 160MVA transformer, 220/132/11 kV with % impedance 15.02%. Can we parallel these three transformers?

A:
Indeed, the vector group is an important (mandatory) consideration when connecting transformers in parallel. And also important if a transformer is going to close a loop in either the HV or LV sides.

But it is perfectly OK to parallel transformers with different impedances. All it is going to happen is an uneven distribution of the power flow, among the parallel transformers. The unit with the lowest impedance would carry a larger share of the load.

Regarding “same ratio”: are you talking about the transformer ratio, such as 138/230 kV? Or are you talking about tap positions? Within certain constraints, it is possible to parallel transformers with different ratios (let’s think, for a second, of identical transformers at different tap positions). This is not recommended, though, because of reactive power circulation.

So, without disagreeing with the factors that you have listed, I would like to re-order, if you will, the conditions you have described:
1) Mandatory: making sure that the vector group and nominal voltages of transformers being considered for parallel operation are indeed adequate and compatible with the intended parallel operation
2) Desirable: ability to operate parallel transformers at the same tap positions or as close as possible, to minimize reactive current circulation
3) Almost indifferent: identical impedances on the parallel transformers simplify things a bit, but this is not a “show stopper” for parallel operation of these transformers. Actually, it is more realistic to expect some differences in impedances, even for otherwise “identical” transformers (same manufacturer, same nameplate ratings, etc.)

For the “Y-Y- Delta” transformers operated in parallel, there exist two kinds of the circulating currents between the tanks and between the banks of the delta side. As the circulating current between the tanks is 90 degree out of phase of the load current, it is estimated by decomposing the line current into the component 90 degree out of phase of the load current. The circulating current between the banks in the delta side is estimated from the delta winding current and the line currents.

The estimated circulating current depends on the power factor of the system even with the same tank currents. This characteristic is derived from the view point of the active and reactive power. Also, it needs the voltage as well as the tank and the load currents.

What happen if we put a magnet near digital energy meter?

In the “olden” days when there were only moving disk meters, I heard that people drilled small holes into the Bakelite cases and tried to get spiders to make a web inside the meter and slow the meter down. It probably wasn’t true, but there have always been people trying to get something for nothing.
I also heard that some people were using a welder and found that their moving disk meter went backwards, but it depended where they positioned the welder, and how strong the welding current was.

Back to electronic meters, if there are transformers inside the electronic meter, placement of a magnet as close to this transformer as possible could cause over fluxing every half a cycle, this could cause a diode like affect in the meter electronics, and if the electronics are designed to eliminate harmonics for calculating energy usage, then the magnet has let this person pay less for electricity, i.e. steal electricity.

Of course the meter may also have a detection circuit for high harmonics and send a message back to the utility to say the harmonic level is too high and a serviceman may then discover this magnet.
I do know that some electronic meter IC manufacturers have added a bump circuit into their ICs so I am sure they have thought about this sort of trickery too.

I like everyone paying full dollar for their electricity, otherwise most of us are carrying the small number of people doing these sorts of things.

“Meters should offer compliance to requirements of CBIP-304 and its amendments for tampering using external magnets. The meter should be immune to tamper using external magnets. The meters should be immune to 0.2T of A.C. magnetic fields and 0.5 T of D.C. magnetic fields, beyond which it should record as tamper if not immune.”
The above statement is a requirement during the manufacturing of digital energy meter. Hence we shall assume that digital meters are tamper proof using Magnets.

Reactive consumptions in AC power system

There are two types of reactive consumptions in AC power system, inductive and capacitive reactances. We can not call them losses. The loss of a transmission line is the active power consumed by the line resistance which is determined by the current on the line. Reactive power can adjust the power factor and control the apparent power, then the current and losses on the line.

The minus reactive power means capacitive load is higher than the inductive load, which happens when the transmission line has no load or with pure resistive load because the capacitive load along the TL dominates the reactive load. In this situation the voltage at the end of the line should be higher than the one at the beginning (you should get it when you get the negative reactive power).

When the load (80% of the industry load is inductive) increases, the reactive power will be positive as the inductive load will dominate the reactive power consumption, and then voltage will lower than that at the beginning. So the optimized choice for the reactive load is that in power plant generating less reactive power (reducing the losses on the line) and generating the compensating reactive power (negative reactive power) at consumer side by using capacitor banks or synchronizing motor, which can increase the power factor of the consumption and regulate the voltage (if the transformer has no taps), and then efficiency (save money) as well.