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Home / Technical Articles / Quick estimation of the short-circuit current at the end of a feeder

Quick estimation of the short-circuit current at the end of a feederPosted Nov 21 2014 by Edvard in Energy and Power with 5 Comments

Quick estimation of the short-circuit current at the end of a feeder (photo credit: SIEMENS)

Rule of thumb for quick estimation

If we consider a branch circuit going away from the point of supply and follow it radially along all the connections and branches, we shall find that further away we are from the transformer, lower is the value of the maximum possible short-circuit current.

Each length of conductor or each device in the circuit provides an impedance which helps to reduce the short-circuit current.

Example of Isc at the end of feeder

A prospective short-circuit current of 50 kA at the secondary terminals of a transformer at 400 V,will be limited to about 10 kA at the end of a connecting lead with a length of 10 m and cross-section of 10 mm2. If the same feeder has a cross-section of 25 mm2, the length of the wire is to be 25 m for reducing the current down to 10 kA.

Figure 1 – Rule of thumb for a quick estimation of the short-circuit current at the end of a feeder

Specimen example //

Figure 2 – Arrangement of a section of an installation

The expected short-circuit current at the end of the feeder is expressed by the relation :

Where:

IK” - Short-circuit current [kA]

UNTrafo - Rated voltage of the supply transformer on the low-tension side [V]

ZTrafo - Impedance of the transformer

ZConducting – Impedance of the conducting lead

However, short-circuit at the point 5 is according to the above mentioned formula:

The value calculated above is rather conservative and includes a factor of safety as other sources of current reduction like the arc voltage, the contact resistance and the internal resistances of the different devices in the path of the short-circuit were not considered.

Reference: Basics of circuit breakers – Rockwell

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Electrical life (durability) of LV circuit breakers due to the switching operationsDecember 1, 2014

Article Tags //

arc voltage, cross-section, feeder, rated voltage, short-circuit, transformer, transformer impedance,

Filed Under Category //

Energy and Power

About Author //

Edvard Csanyi

Edvard - Electrical engineer, programmer and founder of EEP. Highly specialized for design of LV high power busbar trunking (<6300A) in power substations, buildings and industry fascilities. Designing of LV/MV switchgears. Professional in AutoCAD programming and web-design. Present on Google+

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5 Comments

1.Mustafa

Nov 26, 2014

Good Example but I dont understand some values. How are they calculated Uk , all R/mohm , X/mohm and all cable length and cross section best regards.

could you help me pls

best regards

(reply)

2.T.N.Ramesh

Nov 25, 2014

Yes I’m an Electrical Engineer

(reply)

3.Girish

Nov 22, 2014

Nice article. The procedure is similar to IEC 60909 method, only the correction factor in case of the transformer and voltage is not considered. Nevertheless, it is a good way of estimating the short circuit current.

(reply)

4.Vicente Martinez

Nov 21, 2014

Those are very instructive articles, they help me a lot Thank you

(reply)

5.LALO EL HIPPIE

Nov 21, 2014

La simpleza hace hermoso los desarrollos matemáticos. Calculo con Melshort de Mitsubishi dio el mismo resultado

(reply)

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Testing a Distribution/Power Transformer

25 Saturday Jan 2014

Posted by TSSPDCL in Operation & Maintenance

≈ 9 Comments

Tags

Continuity Test, Core Diameter, DC Resistance Test, DTR, PTR

I would like to share some of the tips which can help in ascertaining failure of a distribution/power transformer and also in repair of the same. SPM/TRE Engineers in particular must have these on finger tips.

All most all the three phase distribution/power transformers we have in the system are delta/star connected with capacity ranging from 16 KVA to 12500 KVA. We have to conduct many tests to establish failure of a transformer but we have to have alternate three phase/single phase supply which may not be available at the failure locations. At such instance a simple tong tester and insulation tester will be sufficient and serves the purpose in more than 90% of the cases

1) Tests to be conducted:a) Continuity test:Tests the continuity of the winding (Healthy transformer must have continuity in all the phases but transformer with shorted windings can also have).

Testing terminals:HV LVRY r nYB y nBR b n

b) IR values:Tests insulation resistance between windings and winding to earth. A healthy transformer should have resistance >0 in Mega Ohms.

If HV—E=0 (HV winding is earthed)LV—E=0 (LV winding is earthed)HV—LV=0 (HV and LV winding are shorted)

Any of the HV three terminals and any of the LV four terminals can be used for conducting the tests (If continuity in winding is available).

We should never test charge a DTR/PTR if the IR values are 0 in any of the above three parameters.

c) DC resistance testA healthy transformer will have approximately same resistance in all the three phase in HV winding though its value changes with the capacity of the transformer. LV winding resistance cannot be measured with a tong tester since it has less number of turns and higher size conductor when compared to the HV winding. Continuity of the LV winding can only be established.

For example:a) If the resistance of coils in one phase is 30 Ohms then for a healthy transformer resistance between RY, YB & BR terminals will be equal and 20 Ohms.

i.e. 1/R=1/30+1/60=3/60=1/20

i.e. R=20 Ohms

b) If winding is opened/cut in one phase.RY=60, YB=30, BR=30 (R winding is open)YB=60, BR=30, RY=30 (Y winding is open)BR=60, RY=30, YB=30 (B winding is open)

i.e. resistance measured is double across one winding in case the winding is open and other two winding are healthy.

c) In case two windings are open and one winding healthy.RY=30, YB=infinity, BR=infinity (Y&B windings open)YB=30, BR=infinity, RY=infinity (B&R windings open)BR=30, RY=infinity, YB=infinity (R&Y windings open)

From the above it is understood that:

When resistance values are equal in all the HV phases the PTR/DTR may be OK.

If resistance across one winding is double when compared to other individual winding it is clear that winding is open in one phase and PTR/DTR can be declared failed without going for other tests.

If one winding is showing resistance and others are showing open (infinity) it can be suspected that two phases are open and one phase is healthy.

Note: But it should be kept in mind that even opening of a jumper wire leading to HV bush rod may give similar value and can result in minor failure instead of two limb failure. So verification of jumper connection is to be done before declaration of a failure.

The failure in windings causes erosion of winding material which results in collection of gas in bucholz relay and transformer tank.

If the DTR/PTR is still found healthy in above tests it can be subjected for further test like 1. ratio tests, 2. short circuit test, 3. magnetic balance test/arranging LT phase test supply to take final decision for declaration of failure/healthiness.

Design aspects in repairing of DTR/PTRLV & HV windings of a power transformer and LV winding of a failed distribution transformer will be generally reinsulated during repairs. Conductor to the extent of damaged portion will be replaced for PTRs and damaged HV winding coils will be replaced for distribution transformers.

For rewinding of coils after re-insulation the winder generally takes into consideration the dia-metre and height of the damaged coil. But the winder may endup with a coil with less/excessnumber of turns and slight variation in height and dia-metre. Hence the AE/Winder should havethe knowledge of minimum size of conductor, number of turns, number of conductors anycapacity distribution/power transformer should have to deliver the rated output.

a) Number of turns in LV winding:ET =K√QET =Voltage per turn that can be allowedQ=Rated KVAK=Constant (0.32 to 0.35 for aluminum transformer and 0.37 to 0.45 for copper transformer)

Example:For 100 KVA aluminum DTRET =0.32 √100=0.32 voltsLV turns =250V / 3.2V=78 turns (minimum)

Hence 100 KVA aluminum distribution transformer should have a minimum of 78 turns to have voltage/turn within limits.

Similarly,For 25 KVA aluminum DTRET =0.32 √25=1.6

Hence LV turns=250V/1.6V=156 turns

It means lesser capacity DTR/PTR will have more number of turns when compared to higher capacity transformer

Number of turns in HV winding can be easily arrived by formula.Number of turns in HV winding = voltage ratio X Number of turns in LV winding.= 11000/250V X LV turns= 44 X LV turns

b) Size of the conductor:The size of the conductor depends on the current density of the material used for winding. Current density that can be allowed is.

Aluminum = 1.5Amps/sqmmCopper = 3.0Amps/sqmm

Hence cross sections of LV conductor can be arrived at follows:

For 100 KVA Alu. DTR LV cross section = Rated phase current/current density= 133.3/1.5Amps=88.8 sqmmCross section for HV conductor = Rated phase current/current density= 3.03/1.5Amps=2.02 sqmm

The above values are minimum size of cross section the conductor that can be utilized for replacement of damaged conductor. However higher size can be utilized provided minimum clearances are maintained between windings and core.

c) Shape of conductor:If the dia-metre of the conductor comes more than 3.5mm dia, rectangular shaped strip to be usedsince strip has better surface length and more space factor than that of a round conductor.

Hence for distribution transformer round conductor is used for HV windings and rectangular strip is used for LV windings.

Example:For 100KVA HV winding wire, cross section of the conductor required is 2.02 sqmmi.e. ∏r2=2.02

r=√2.02/∏r=0.80diameter=1.6

The dia-metre of the HV conductor being used for a 100 KVA is 1.6mm i.e. 16 SWG.

Selection of size of rectangular strip of equal cross section is more importance since we can havemany sizes for the same cross section.

In general for all practical purposes for easy handling.

Width of the strip is to be more than double the depth of the strip.

Minimum depth of the strip is to be 2.25mm

From the above it is evident that more number of conductor in parallel can be utilized instead of higher sized single connector. Utilization of multiple conductors results in more flexibility duringwinding and also decreases skin-effect since surface length of conductor is more with multiple conductors.

Example:For 100KVA aluminum transformer LV conductor of 88 sqmm cross section can be had by having two conductors of size 44 sqmm each in parallel. Depth of strip should be minimum a 2.25mm and width can be calculated to accommodate required number of the LV turns within theheight of LV coils in single layer or double layer.

d) Diameter of the core:Dia-metre of the core can be calculated by arriving at gross core area by using following formula:

Ag=Et/4.44 X f X Bm X 0.97 X 10-4

f=frequencyAg=gross core area in sqcmBm=maximum flex density in tesla = 1.6Et=phase voltage/turn0.97=stacking factor (assumed)Once Ag is calculated dia-metre of the core can be calculated by formulaAg=K1 X ∏d2 X ¼K1=0.92 for six step coreK1=0.925 for seven step coreK1=0.93 for eight step coreK1=0.935 for nine step core etc

By Er. K Sadasiva ReddySE/Operation/Mahaboobnagar

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9 thoughts on “Testing a Distribution/Power Transformer”

1. K. Durga Srinivas ADE/M&P/Jadcherla said:

February 19, 2014 at 7:33 PM

Thank u sir .U have provided very useful information to the all field engineers.

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2. Krishna, Elect contractor/ Narayanpet/Mahabubnagar said:

March 7, 2014 at 7:43 PM

Sir, Testing of DTRs data provided by you is very useful for us in Repairing of DTRs at SPM Sheds and the failure of DTRs can be minimized by these testings and we will use the data for testing of DTR at Narayanpet SPM.

Thanking You Sir,

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3. g.sudheer reddy said:

March 7, 2014 at 10:24 PM

Ok good

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4. g.sudheer reddy said:

March 7, 2014 at 10:33 PM

Thank u sir. It will be helpful to farmers and prevents repeated failures.

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5. MD.NAZEER KHAN said:

March 23, 2014 at 6:42 PM

Very Informative and useful in practical adoption in determining the condition of dtr/ptr. Sir, kINDLY PROVIDE few more articles for consumers and contractors like on PF,ENERGY CONSERVATION TECHNICS,ENRGY MEASUREING PRE FAILURE MEASURES ETC…… NAZEER KHAN,RELIANCE ENGINEERING WORKS,HYDERABAD

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6. mubeen said:

April 12, 2014 at 12:33 PM

a) Continuity test:Tests the continuity of the winding (Healthy transformer must have continuity in all the phases but transformer with shorted windings can also have).

my doubt is usually in sheds the first thing for a sick DTR continuity test is done ,as you said even if the windings are shorted it shows continuity is there any alternate method that shows the difference in continuity for shorted windings(any values)

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7. mubeen said:

April 12, 2014 at 12:38 PM

thank you sir for such information

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8. Vivek kumar vishwakarma said:

May 2, 2014 at 11:55 PM

Thank you sir

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o pvr said:

December 13, 2014 at 4:25 PM

Sir,thank u for reminding me that I am electrical engineer

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Understanding standby power system grounding

Knowing how to apply proper grounding and bonding to electrical systems and transfer switches for common standby power system configurations can minimize power outages, equipment damage, and injuries.

David Chesley, PE, LEED AP, RCDD, Interface Engineering, Portland, Ore.

12/14/2011

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Electrical system grounding is an often misunderstood area of electrical system design and construction that can cause havoc when misapplied. This problem is even more pronounced with standby power systems. Circuit breakers trip, generators are dropped offline, and crucial standby and life safety loads are lost because of a hidden grounding problem made manifest during a power outage, just when backup power is needed most.

Despite this harrowing picture, most grounding issues can be resolved with attentive design, and then checked and avoided during the installation and testing stages of construction, eliminating most issues before a facility is occupied.

Know grounding and bonding terminology

Before discussing the challenges of grounding standby power systems, key terms are explained—as defined in the 2011 National Electric Code (NEC) (NFPA 70)—to offer a better understanding of why we ground electrical systems. Unless otherwise noted, the following definitions are cited from NEC, Article 100, “Definitions.”

Ground: The earth itself is taken as “ground”. Building grounding electrode systems are sunken into the earth.

The connecting of current-carrying equipment to the earth is the definition of grounding. NEC Article 250.4(A)(2) states:

Grounding of Electrical Equipment. Normally, non-current-carrying conductive materials enclosing electrical conductors or equipment, or forming part of such equipment, shall be connected to earth so as to limit the voltage to ground on thesematerials.

This is different from bonding, where adjacent conductive surfaces that do not normally carry electricity (such as chassis on a toaster, an x-ray, or a milling machine) are connected to another conductive object (such as the metallic racewaycontaining power wiring, nearby building steel, or an adjacent metallic water pipe) to create an electrically continuous, low-impedance path. NEC Article 250.4(A)(3) states:

Bonding of Electrical Equipment. Normally non-current carrying conductive materials enclosing electrical conductors or equipment, or forming part of such equipment, shall be connected together and to the electrical supply source in a manner that establishes an effective ground fault-current path.

Grounding electrode: A conducting object through which a direct connection to the earth is established.

Grounding electrodes in practice includes ground rods and (conductive) metallic water piping, and concrete-encased building steel (e.g., steel rebar embedded in concrete foundation in direct contact with the earth).

Grounding electrode conductor: A conductor used to connect the system-grounded conductor or the equipment to a grounding electrode or to a point on the grounding electrode system. This conductor connects the building grounding system to the earth by means of the grounding electrode.

Grounded (grounding): Connected to ground without inserting resistors or impedance devices. Grounded equipment or panels can trace a continuous conductive path from their chassis to an equipment grounding conductor, to the grounding electrode conductor, to the grounding electrode to the earth (ground) itself (see Figure 1).

Equipment grounding conductor (EGC): The conductive path(s) installed to connect normally non-current-carrying metal parts of equipment together and to the system grounding conductor or to the grounding electrode conductor, or both.

The EGC connects objects back to the grounding electrode system and to the earth.

Ground fault current path: From NEC, Article 250.2, an electrically conductive path from the point of a ground fault on a wiring system through normally non-current-carrying conductors, equipment, or the earth to the electrical supply source.

Effective ground fault current path: From NEC, Article 250.2, an intentionally constructed, low-impedance electrically conductive path designed and intended to carry current under ground fault conditions from the point of a ground fault on a wiring system to the electrical supply source and that facilitates the operation of theovercurrent protective device or ground fault detectors on high impedance grounded systems.

All current tries to return back to its source to complete the circuit. A live conductor striking an ungrounded conductive metal surface will go through whatever, or whoever, connects the metal object to earth, and back to the power source.

Because having large amounts of electrical current unintentionally going through people is generally a bad thing, we want the overcurrent protection device to trip asquickly as possible, removing the fault current before damage, injury, or death can occur. The best means of doing this for ground fault current is to provide a low enough impedance path such that ground fault current is high enough in magnitudeto quickly trip the overcurrent protective device.

Figure 1 shows this in practice. A ground fault in an appliance, rather than routing tothe earth through our unsuspecting victim, routes through the EGC back through the panelboard, and ultimately to the main service (utility transformer), completing the circuit.

More importantly, because this is an effective ground fault current path, the fault current is high enough to allow the circuit breaker in the panelboard to open, cuttingthe fault current.

Separately derived system: A premises wiring system whose power is derived from a source of electrical energy or equipment other than a service. Such systems have no direct connection from circuit conductors of one system to circuit conductors of another system, other than connections through the earth, metal enclosures, metallic raceways, or equipment grounding conductors.

When using a backup source such as a generator, note that if a generator has a neutral conductor that is directly bonded to the utility service neutral (for example, a 3-pole transfer switch), the generator is not separately derived. On the other hand, if its neutral never comes in direct contact with the utility neutral (either because the neutral is switched at the transfer switch, or the generator is a 3-wire system without a neutral), it is a separately derived system.

System bonding jumper: The connection between the grounded circuit conductor (often called the neutral) and the supply-side bonding jumper, or the EGC, or both, at a separately derived system.

Simply put, the jumper ties the ground and neutral together at the generator. When this occurs at a utility service, we now use a different term to mean the same thing: supply-side bonding jumper.

Supply-side bonding jumper: From NEC, Article 250.2, a conductor installed on the supply side of a service or within a service equipment enclosure(s), or for a separately derived system, that ensures the required electrical conductivity between metal parts required to be electrically connected.

This term, introduced in the 2011 NEC, applies to both utility services and alternate sources of power such as a generator. This conductor is how return ground-fault current goes from the EGC to the neutral and back to the power source, completing the circuit, and hopefully tripping the overcurrent protection in minimal time.

Grounding standby power systems

Grounding systems are created to allow overcurrent devices to quickly open when a line-to-ground fault occurs. For this reason, bonding between the neutral and ground bus (or chassis) in the generator should not occur when a 3-pole transfer switch is used that directly bonds the main service panel neutral to the neutral bus of the generator.

Figure 2 shows the problem with this approach. Return current from the electrical load travels down to the transfer switch and then splits with part heading back to the utility service and part heading down to the generator. At the generator, this current then returns through the neutral-ground bond back over the grounding system to the utility service, leading to stray current potentially traveling over metallic raceway, piping, and even building structural steel to return to its source.

An added problem of connecting the neutral to ground at both the main service and the generator without transferring the neutral occurs with ground fault protection (GFP), which is required by NEC Article 240.13 on overcurrent protection at 480 V and more than 1,000 A.

GFP devices operate by measuring the outgoing and incoming current and looking at differences between the two, with the assumption that any current difference is stray return current that is traveling over the building grounding system. If the measured current difference is high enough, the GFP device is then set to trip open,

cutting power to downstream loads and the ground fault causing the stray return current.

However, if stray return current is caused for other reasons, such as a condition where return neutral current from the load can travel over the neutral-to-ground bond at the generator, the GFP device can also trip, because the current difference can be the same as in an actual ground fault, especially if the generator is relativelyclose to the service.

If the GFP is then dialed to a higher current setting to minimize interruptions, one is left with current regularly running over the ground system from standby loads, and has reduced the protection from the GFP in the event of a real line-to-ground fault.

Note that the current routed from neutral to ground at the generator can be similar in magnitude to a line-to-ground fault at the standby load—especially if the impedance of the path from the load to the generator is relatively low. Thus, setting the GFP protection to a higher trip setting can mean that a real line-to-ground fault at the load may not cause the breaker to open, leading to a sustained ground fault in the electrical system.

This leads us to our first rule of standby power system grounding:

Rule No. 1: For a 3-phase, 4-wire system, do not bond the neutral and ground bus together at the generator unless the neutral is switched at the transfer switch together with the phase conductors.

Transferring the neutral can be accomplished by one of two means:

A 4-pole transfer switch that switches the load neutral between the utility source to the standby source

A 3-pole transfer switch with overlapping contacts for the neutral that overlaps the utility and standby neutrals very briefly at the time of switching.

Note that the bonding of a generator’s neutral and ground bus should not be confused with the question of whether a generator should have a grounding electrode system. If the generator is a separately derived system, the NEC requires a grounding electrode system at the generator per NEC Articles 250.30 and 250.52(A).

If the system is not separately derived, the grounding electrode system may be installed as a supplemental grounding electrode system, providing it is also bonded to the equipment ground conductor (NEC Article 250.54).

This leads us to the second rule of standby power system grounding:

Rule No. 2: A standby power source should have its own grounding electrode systemto facilitate ground fault current returning to the generator if a line-to-ground fault

occurs when a generator is powering load. However, this grounding electrode system must always be bonded to the equipment ground conductor that is also bonded to grounding electrode conductor at the utility service disconnect.

This raises the question of whether there are times by code or design where the engineer must design the generator as a separately derived system with a neutral-ground bond at the generator.

One of the most common instances occurs when more than one level of GFP is used. This often happens in health care facilities where more than one transfer switch is used to isolate life safety, critical, and equipment branches from one another, and a second level of GFP is used on the overcurrent protection. Even when the generator does not have a neutral-ground bond and multiple 3-pole transfer switches are used, return current from the life safety branch returns on both its own neutral and on the neutral used by the equipment branch (see Figure 3).

Since outgoing phase and incoming neutral current are not the same, the GFP for both branches may perceive a line-to-ground fault and trip one or more branches offline. Again, adjusting the trip setting to a higher amperage level compromises theeffectiveness of the GFP when a real line-to-ground fault occurs.

This leads us to the third rule of standby power system grounding:

Rule No. 3: When using more than one transfer switch on a 3-phase, 4-wire system where any one transfer switch may have two or more levels of GFP protection upstream of itself, the generator should be grounded as a separately derived system, and transfer switches that can switch the neutral should be used for all transfer switches.

Because it is much less expensive to specify the generator with the proper grounding and install the correct transfer switches initially than do so as a retrofit, consideration of this approach should be used if there is a possibility that a future upgrade could create this condition that doesn’t exist initially in the building.

For example, if an owner advises the engineer on a project with a small life safety generator that it may be replaced in the future with a large generator capable of backing up most of the building, and that upgrade would require two levels of GFP for the non-life safety branch, the engineer will want to specify a 4-pole transfer switch for the life safety branch to avoid needing to replace that transfer switch during the future upgrade.

Because the problem of neutral current—whether under normal conditions or line-to-ground fault conditions—emerges where multiple transfer switches are used in one facility, we can generalize Rule No. 3 as follows:

Generalized Rule No. 3: When using more than one transfer switch on a 3-phase, 4-wire system where any one transfer switch may have two or more levels of GFP protection upstream of itself, all generators should be grounded as separately derived systems, and transfer switches that can switch the neutral should be used for all transfer switches. In the discussion to this point, all mention of GFP has been assumed to be on the utility side of the transfer switches. While generators can be specified with an output circuit breaker with GFP, this is normally avoided with good reason, because a ground fault trip would result in the loss of the standby power source when it is critically needed.

Instead, where a GFP would otherwise be required, generators should be specified with a ground fault annunciation feature on the output circuit breaker, to notify via the generator control panel and annunciator when a ground fault condition has occurred while the facility is running on backup power. This allows the facility manager to hunt down the source of the ground fault without cutting power to critical loads.

The oddballs you must know

There are numerous cases where a 3-phase, 3-wire system (no neutral) is used on the generator side.

Case No. 1—solidly grounded, 3-phase, 3-wire standby power system: In this case, atransformer may be used on the load side of the 3-pole transfer switch to derive a

neutral for any line-to-ground loads on the standby power system (see Figure 4). However, the transfer switch sees only phase and ground connections from the utility, generator, and load connections to itself. Because there is no way for line-to-ground current to return on any path except the ground plane, we do not see a splitting of return ground fault current between a neutral and ground. Thus, a GFP can monitor just the phase conductors and trip properly if the current does not return through the same phase conductors.

Case No. 2—solidly grounded, 3-phase, 3-wire standby power system with interlocked circuit breakers used for load transfer: By definition, because the circuit breakers (unless they are 4-pole) can only switch the phase conductors and not the neutral, we would have the same problem of neutral current from the standby load returning on two pathways. One way of avoiding this problem is to connect only 3-phase, 3-wire loads (no neutral) to the common distribution board served from both sources (see Figure 5).

Case No. 3—high-resistance grounded, 3-phase, 3-wire standby power system: In this case, a high-resistance source between neutral and ground at the generator is used to limit any return ground fault current that may occur. This is often used in industrial settings where the owner does not want to interrupt power in the event ofthe ground fault, but also wants to reduce the fault current magnitude (and thus its inherent danger) while troubleshooting the location and source of the fault. Conditions of NEC Article 250.36 must also be met.

Much of the control the building owner, engineer, and electrician have over resolving grounding issues with the generator can be resolved with careful planning at the generator and transfer switch. Careful forethought and planning can do muchto maximize the ground fault protection of the power system, and minimize power outages due to stray currents.

Chesley is an associate principal and senior electrical engineer at Interface Engineering. He has been with the company since 1993. His engineering expertise includes building integration, renewable energy systems, telecommunications infrastructure, backup power systems, energy metering, and building dashboards.

Related News:

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Renovating electrical distribution systems - 09.05.2011 00:00

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Home / Technical Articles / Protection and Relays Used In Main Circuit Board at a Power Grid Substation

Protection and Relays Used In Main Circuit Board at a Power Grid Substation

Posted Feb 17 2012 by Bipul Raman in High Voltage, Medium Voltage, Protection with 5 Comments

Differential relay for transformer applications. Protection features include over-excitation (V/Hz), under/over-voltage, phase overcurrent, negative-sequence overcurrent, and breaker fail-to-trip/fail-to-close indicators. (pic by thomasnet.com)

1. High speed biased differential relay

The DMH type relay provides high speed biased differential protection for two or three windingtransformers. The relay is immune to high inrush current and has a high degree of stability against through faults. It requires a max of two cycles operating time for current above twice relay rated current. Instantaneous overcurrent protection clears heavy internal faults immediately. This relay is available in two forms.

Firstly for use with time Cts, the ratios of line which are matched to the load current to give zero differential current under normal working conditions. Secondly with tapped interposing transformers for use with standard line current transformers of any ratio.

2. Directional inverse time overcurrent and earth fault relays

The CDD type relays are applied for directional or earth fault protection of ring mains, parallel transformers or parallel feeders with the time graded principle. It is induction disc type relay withinduction cup used to add directional feature.

3. Instantaneous voltage relay

The type VAG relay is an instantaneous protection against abnormal voltage conditions such as over voltage, under voltage or no voltage in AC and DC circuits and for definite time operation when used with a timer. It is an attracted armature type relay.

4. Auxiliary relays

The VAA/CAA type auxiliary relays are applied for control alarm, indication and other auxiliary duties in AC or DC systems. CAA is a current operated and VAA is a voltage operated relay.. it isattracted armature type.

5. High speed tripping relays

This VAJH type relay is employed with a high speed tripping duties where a number of simultaneous switching operations are required. This is a fast operating multi contact attracted armature relay.

6. Definite time delay relay

This VAT type relay is used in auto reclosing and control schemes and to provide a definite time feature for instantaneous protective relay. It is an Electro mechanical definite time relay. It has two pair of contacts. The shorter time setting is provided by a passing contact and longer time setting by the final contact.

7. Trip circuit supervision relay

This VAX relay is applied for after closing or continuous supervision of the trip circuit of circuit breakers.

They detect the following conditions:

1. Failure of trip relay

2. Open circuit of trip coil

3. Failure of mechanism to complete the tripping operation

8. Instantaneous over current and earth fault relay

An instantaneous phase or earth fault protection and for definite time operation when used with atimer. It is a CAG 12/12G standard attracted armature relay with adjustable settings. It may be a single pole or triple pole relay.

9. Inverse time over current and earth fault relay

This CDG 11-type relay is applied for selective phase and earth fault protection in time graded systems for AC machines. Transformers, feeders etc. this is a non-directional relay with a definite minimum time which has an adjustable inverse time/current characteristics. It may be a single pole or triple pole relay.

10. Fuse failure relay

This VAP type relay is used to detect the failure or inadvertent removal of voltage transformer sec. fuses and to prevent incorrect tripping of circuit breaker. It is three units, instantaneous attracted armature type relay the coil of each unit connected across one of the VTs.

The secondary fuses under healthy conditions, the coil is SC by fuses and can’t be energized. Butone or more fuses blow the coil is energized and relay operates.

11. Instantaneous high stability circulating current relay

It is used to serve the following three purposes

1. Differential protection of Ac machines , reactors auto transformers and bus bars

2. Balanced and restricted earth fault protection of generator of generator and transformer windings

3. Transverse differential protection of generators and parallel feeders.

This CAG type relay is a standard attracted armature relay. In circulating current protection schemes, the sudden and often asymmetrical growth of the system current during external fault conditions can cause the protection current transformers to go into saturation, resulting in high unbalance current to insure stability under these conditions.

The modern practice is to use a voltage operated high impedance relay, set to operate at a voltageslightly higher than that developed by CT under max fault conditions. Hence this type of relay is used with a stabilizing resistor.

12. Local breaker back up relay

this is a CTIG type three phase or two phase earth fault instantaneous over current unit intended for use with a time delay unit to give back up protection in the event of a circuit breaker failure.

13. Poly-phase directional relay

The PGD relay is a high speed induction cup unit used to give directional properties to three phase IDMT over-current relays, for the protection of parallel feeders, inter connected networks

and parallel transformers against phase to phase and three phase faults. Owing to low sensitivity on phase to earth faults the relay is used with discretion on solidly earthed systems.

14. Auto reclose relay

Five types of auto reclose relays are available:

a) VAR21 giving one reclosure. The dead time and reclaim time are adjustable form 5 to 25 secs. If the circuit breaker reopens during reclaim time, it remains open and locked out.

b) VAR41B is a single shot scheme for air blast circuit breakers. Reclaim time is fixed at between 15 to 20 secs. Dead time adjustment is from 0.1 to 1.0 sec of which first 300 millisec will be circuit breaker opening time.

c) VAR 42 giving four reclosure. It is precision timed from 0 to 60 sec. it can be set for max four enclosures at min intervals of 10 sec and instantaneous protection can be suppressed after the first reclosure so that persistent faults are referred to time graded protection.

d) VAR 71 giving single shot medium speed reclosure with alarm and lockout for circuit breaker.This allows up to 10 faults clearance before initiating an alarm. The alarm is followed by lockoutif selected no. of faults clearances exceed. If the circuit breaker reopens during reclaim time, it remains open and locked out. It offers delay in reclosing sequence. Instantaneous lockout on low current earth fault and suppressing instantaneous protection during reclamation time.

e) Var81 is a single shot high-speed reclosure with alarm and lockout for circuit breaker This allows up to 10 faults clearance before initiating an alarm.

Top

Reactance distance scheme

this scheme consists of the following relays, XCG22-3 for phase to phase and 3 for phase to ground, YCG17, mho starting unit one in each place, VAT51 along with timing unit for zone 2 and 3, 86-X aux. tripping relay and 30G, H, and J for 1st, 2nd and 3rd. Zone indication VAA51, CAG12 and VAA31. These schemes provide three zone phase and earth fault protection using reactance relays type XCG22 and also starting relays YCG17.

They are applicable to important line sections where high values of arc resistance would otherwise affect the accuracy of measurement and where high speed tripping is essential. High-speed protection is provided for phase and earth faults on 80-90% of the line section and faults on the remaining section are cleared in second zone, time. The third zone provides backup protection after further time interval.

Each mho starting unit Y3 and its auxiliary Y3 X is associated with one phase and operates for all faults involving this phase. Each reactance unit X is connected to measure phase or earth faultdistance, but is prevented from operating by short circuit across the polarizing coils. Under the phase fault conditions, the Y3 X units unblock the appropriate X1 reactance units, which initiate tripping immediately for faults within their setting.

Operation of the earth auxiliary relay 64 in conjunction with the Y3 X units selects the appropriate reactance units for measurement of earth faults. The reach of reactance units is extended by the timer, 2 after successive intervals to cover faults in zone 2 and 3.

The principle of distance scheme - Block diagram

Discrimination is not affected by changing faults, for example a zone 2 earth fault which develops into a double phase to earth fault will be cleared correctly by the X1 (phase fault) units

in zone 2 time. In the rare event of two faults occurring simultaneously at different points on the line; the scheme will measure to a distance approximately half way.

Source: Internet and several books of Electrical Engineering

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Article Tags //

auxiliary relays, differential relay, earth fault, grid, main circuit board, overcurrent, power substation, relays,

Filed Under Category //

High Voltage Medium Voltage Protection

About Author //

Bipul Raman

Bipul Raman - Bipul Raman (@BipulRaman), a graduate in Electrical Engineering had presented two research papers in National Conferences. He has overtaken and successfully completed a project to design an Automated CB Test-Rig for Light Combat Aircraft at Aircraft Research and Design Center (HAL). Apart from this, he has done several projects at NTPC and Grid Substation. Not only limited to Electrical Engineering, He is also very much passionate in Software Development. He has contributed few of his code to 'Codeplex' ( a Microsoft OpenSource software hosting website ). Visit his complete profile at http://bipul.in/about

RSS Feed for Comments

5 Comments

1.sanjay goyal

Nov 12, 2014

We want a aux. relay for transformer protection. The relay details are as under. Auxiliary relay, Type: VAA. Model no: SPECM2ZG76B. Volts: 110VDC. Make: E.E. So kindly provide the dealer or shop from where we can purchase this relay.

(reply)

2.jobert moleno

Oct 20, 2014

Nice article very informative.

(reply)

3.Delayed Auto-Reclosing On EHV Systems | EEP

Dec 16, 2013

[...] is an unacceptable shock to the system.It is therefore usual practice to incorporate a synchronism check relay into the reclosing system to determine whether auto-reclosing should take place.After tripping on a [...]

(reply)

4.jeewangarg

May 03, 2013

how to calculate the capacity of a contactor (high/low voltage cutoff).

(reply)

5.Connections Of Overcurrent Relay (part 2) | EEP

Feb 02, 2013

[...] 3 Nos O/C relay for overcurrent and earth fault protectionIt’s used for:3-phase faults the overcurrent relays in all the 3-phases act.Phase to phase faults the relays in only the affected phases operate.Single [...]

(reply)

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Home / Technical Articles / Protection and Relays Used In Main Circuit Board at a Power Grid Substation

Protection and Relays Used In Main Circuit Board at a Power Grid Substation

Posted Feb 17 2012 by Bipul Raman in High Voltage, Medium Voltage, Protection with 5 Comments

Differential relay for transformer applications. Protection features include over-excitation (V/Hz), under/over-voltage, phase overcurrent, negative-sequence overcurrent, and breaker fail-to-trip/fail-to-close indicators. (pic by thomasnet.com)

1. High speed biased differential relay

The DMH type relay provides high speed biased differential protection for two or three windingtransformers. The relay is immune to high inrush current and has a high degree of stability against through faults. It requires a max of two cycles operating time for current above twice relay rated current. Instantaneous overcurrent protection clears heavy internal faults immediately. This relay is available in two forms.

Firstly for use with time Cts, the ratios of line which are matched to the load current to give zero differential current under normal working conditions. Secondly with tapped interposing transformers for use with standard line current transformers of any ratio.

2. Directional inverse time overcurrent and earth fault relays

The CDD type relays are applied for directional or earth fault protection of ring mains, parallel transformers or parallel feeders with the time graded principle. It is induction disc type relay withinduction cup used to add directional feature.

3. Instantaneous voltage relay

The type VAG relay is an instantaneous protection against abnormal voltage conditions such as over voltage, under voltage or no voltage in AC and DC circuits and for definite time operation when used with a timer. It is an attracted armature type relay.

4. Auxiliary relays

The VAA/CAA type auxiliary relays are applied for control alarm, indication and other auxiliary duties in AC or DC systems. CAA is a current operated and VAA is a voltage operated relay.. it isattracted armature type.

5. High speed tripping relays

This VAJH type relay is employed with a high speed tripping duties where a number of simultaneous switching operations are required. This is a fast operating multi contact attracted armature relay.

6. Definite time delay relay

This VAT type relay is used in auto reclosing and control schemes and to provide a definite time feature for instantaneous protective relay. It is an Electro mechanical definite time relay. It has two pair of contacts. The shorter time setting is provided by a passing contact and longer time setting by the final contact.

7. Trip circuit supervision relay

This VAX relay is applied for after closing or continuous supervision of the trip circuit of circuit breakers.

They detect the following conditions:

1. Failure of trip relay

2. Open circuit of trip coil

3. Failure of mechanism to complete the tripping operation

8. Instantaneous over current and earth fault relay

An instantaneous phase or earth fault protection and for definite time operation when used with atimer. It is a CAG 12/12G standard attracted armature relay with adjustable settings. It may be a single pole or triple pole relay.

9. Inverse time over current and earth fault relay

This CDG 11-type relay is applied for selective phase and earth fault protection in time graded systems for AC machines. Transformers, feeders etc. this is a non-directional relay with a definite minimum time which has an adjustable inverse time/current characteristics. It may be a single pole or triple pole relay.

10. Fuse failure relay

This VAP type relay is used to detect the failure or inadvertent removal of voltage transformer sec. fuses and to prevent incorrect tripping of circuit breaker. It is three units, instantaneous attracted armature type relay the coil of each unit connected across one of the VTs.

The secondary fuses under healthy conditions, the coil is SC by fuses and can’t be energized. Butone or more fuses blow the coil is energized and relay operates.

11. Instantaneous high stability circulating current relay

It is used to serve the following three purposes

1. Differential protection of Ac machines , reactors auto transformers and bus bars

2. Balanced and restricted earth fault protection of generator of generator and transformer windings

3. Transverse differential protection of generators and parallel feeders.

This CAG type relay is a standard attracted armature relay. In circulating current protection schemes, the sudden and often asymmetrical growth of the system current during external fault conditions can cause the protection current transformers to go into saturation, resulting in high unbalance current to insure stability under these conditions.

The modern practice is to use a voltage operated high impedance relay, set to operate at a voltageslightly higher than that developed by CT under max fault conditions. Hence this type of relay is used with a stabilizing resistor.

12. Local breaker back up relay

this is a CTIG type three phase or two phase earth fault instantaneous over current unit intended for use with a time delay unit to give back up protection in the event of a circuit breaker failure.

13. Poly-phase directional relay

The PGD relay is a high speed induction cup unit used to give directional properties to three phase IDMT over-current relays, for the protection of parallel feeders, inter connected networks

and parallel transformers against phase to phase and three phase faults. Owing to low sensitivity on phase to earth faults the relay is used with discretion on solidly earthed systems.

14. Auto reclose relay

Five types of auto reclose relays are available:

a) VAR21 giving one reclosure. The dead time and reclaim time are adjustable form 5 to 25 secs. If the circuit breaker reopens during reclaim time, it remains open and locked out.

b) VAR41B is a single shot scheme for air blast circuit breakers. Reclaim time is fixed at between 15 to 20 secs. Dead time adjustment is from 0.1 to 1.0 sec of which first 300 millisec will be circuit breaker opening time.

c) VAR 42 giving four reclosure. It is precision timed from 0 to 60 sec. it can be set for max four enclosures at min intervals of 10 sec and instantaneous protection can be suppressed after the first reclosure so that persistent faults are referred to time graded protection.

d) VAR 71 giving single shot medium speed reclosure with alarm and lockout for circuit breaker.This allows up to 10 faults clearance before initiating an alarm. The alarm is followed by lockoutif selected no. of faults clearances exceed. If the circuit breaker reopens during reclaim time, it remains open and locked out. It offers delay in reclosing sequence. Instantaneous lockout on low current earth fault and suppressing instantaneous protection during reclamation time.

e) Var81 is a single shot high-speed reclosure with alarm and lockout for circuit breaker This allows up to 10 faults clearance before initiating an alarm.

Top

Reactance distance scheme

this scheme consists of the following relays, XCG22-3 for phase to phase and 3 for phase to ground, YCG17, mho starting unit one in each place, VAT51 along with timing unit for zone 2 and 3, 86-X aux. tripping relay and 30G, H, and J for 1st, 2nd and 3rd. Zone indication VAA51, CAG12 and VAA31. These schemes provide three zone phase and earth fault protection using reactance relays type XCG22 and also starting relays YCG17.

They are applicable to important line sections where high values of arc resistance would otherwise affect the accuracy of measurement and where high speed tripping is essential. High-speed protection is provided for phase and earth faults on 80-90% of the line section and faults on the remaining section are cleared in second zone, time. The third zone provides backup protection after further time interval.

Each mho starting unit Y3 and its auxiliary Y3 X is associated with one phase and operates for all faults involving this phase. Each reactance unit X is connected to measure phase or earth faultdistance, but is prevented from operating by short circuit across the polarizing coils. Under the phase fault conditions, the Y3 X units unblock the appropriate X1 reactance units, which initiate tripping immediately for faults within their setting.

Operation of the earth auxiliary relay 64 in conjunction with the Y3 X units selects the appropriate reactance units for measurement of earth faults. The reach of reactance units is extended by the timer, 2 after successive intervals to cover faults in zone 2 and 3.

The principle of distance scheme - Block diagram

Discrimination is not affected by changing faults, for example a zone 2 earth fault which develops into a double phase to earth fault will be cleared correctly by the X1 (phase fault) units

in zone 2 time. In the rare event of two faults occurring simultaneously at different points on the line; the scheme will measure to a distance approximately half way.

Source: Internet and several books of Electrical Engineering

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Article Tags //

auxiliary relays, differential relay, earth fault, grid, main circuit board, overcurrent, power substation, relays,

Filed Under Category //

High Voltage Medium Voltage Protection

About Author //

Bipul Raman

Bipul Raman - Bipul Raman (@BipulRaman), a graduate in Electrical Engineering had presented two research papers in National Conferences. He has overtaken and successfully completed a project to design an Automated CB Test-Rig for Light Combat Aircraft at Aircraft Research and Design Center (HAL). Apart from this, he has done several projects at NTPC and Grid Substation. Not only limited to Electrical Engineering, He is also very much passionate in Software Development. He has contributed few of his code to 'Codeplex' ( a Microsoft OpenSource software hosting website ). Visit his complete profile at http://bipul.in/about

RSS Feed for Comments

5 Comments

1.sanjay goyal

Nov 12, 2014

We want a aux. relay for transformer protection. The relay details are as under. Auxiliary relay, Type: VAA. Model no: SPECM2ZG76B. Volts: 110VDC. Make: E.E. So kindly provide the dealer or shop from where we can purchase this relay.

(reply)

2.jobert moleno

Oct 20, 2014

Nice article very informative.

(reply)

3.Delayed Auto-Reclosing On EHV Systems | EEP

Dec 16, 2013

[...] is an unacceptable shock to the system.It is therefore usual practice to incorporate a synchronism check relay into the reclosing system to determine whether auto-reclosing should take place.After tripping on a [...]

(reply)

4.jeewangarg

May 03, 2013

how to calculate the capacity of a contactor (high/low voltage cutoff).

(reply)

5.Connections Of Overcurrent Relay (part 2) | EEP

Feb 02, 2013

[...] 3 Nos O/C relay for overcurrent and earth fault protectionIt’s used for:3-phase faults the overcurrent relays in all the 3-phases act.Phase to phase faults the relays in only the affected phases operate.Single [...]

(reply)

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Directional Comparison Blocking Scheme

By Admin On April 9, 2011 · Add Comment

The Directional Comparison Blocking (DCB) scheme is the most popular pilot relaying scheme, implemented to protect extra high voltage power lines. This scheme is more dependable than permissive transfer trip schemes because it trips the breaker even when there is no carrier signal from the remote end pilot relay. Ofcourse, the protective relays need to see the fault first.

Equipment needed for DCB scheme

Distance relay like the Schweitzer 421 and the carrier equipment Pulsar TC-10B.

Power line carrier equipment: line tuner, wave-traps, and hybrids. Output from the carrier equipment is coupled to the power line using line tuners. Hybrids are required to multiplex signals (Tx/Rx) from the carrier equipment. Wave-traps limit the carrier signals to the intended line section.

Implementation

Let’s examine the DCB scheme using the figure below and its scenarios.

Figure 1: Affect of internal vs external faults on relay operation

Fault @ F1 on T-line:This fault is internal to the circuit breakers CB1 and CB2. These breakers are the closest to the fault and tripping them will isolate the fault. In this scenario, CB1 and CB2 will be tripped without any delay by SEL-421.

Fault @ F2 on T-line:The fault is external to CB1 and CB2 but internal to CB3 and its remote end breaker(s). Since zone 2 protective element on the CB1 relay can trip on it, it shouldbe blocked from doing so. The intent is to trip the breakers local to the fault rather than taking out a larger portion of the system.

Thus, while CB3 takes measures to isolate the fault, CB2’s zone 3 element (which looks backwards) detects this fault as external and keys a “block from tripping” signal to CB1. It should be clear now that the SEL-421 at CB1 uses zone 1 and zone 2 to detect faults and that zone 2 is a time delayed logic that acts as a backup to CB3 when it fails to operate.

Fault @ Bus1CB’s 1, 4, and 5 should trip to isolate the fault on Bus 1. If CB1 fails and does not trip then its breaker failure logic will send a transfer trip signal to CB2. Typically, a bus lockout relay is tripped when a breaker connected to the bus fails. The lockout relay is capable of tripping multiple CB’s at the same time. A contact from this relay

can be assigned to the 85 device at CB1 so that it can key the Direct Transfer Trip signal. See figure 2 for the oneline implementation of this scheme.

Figure 2: Directional Current Blocking Oneline

The DCB scheme is typically used as the first line of defense against faults on the high voltage or extra high voltage transmission lines. When using the power line carrier, the DCB logic is implemented by TC-10B equipment using RF frequency for both transmission and reception of carrier signal.

Advantage of DCB scheme

Dependable scheme since relays do not rely on trip signal from remote end substation to provide protection for internal faults on transmission line. However, to check the integrity of the communication channel, a test signal is transmitted 3 or 4times a day.

* * * * *

Tagged with → directional comparison blocking • line relaying • pilot relaying • pulsar TC10B • Substation Protection

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Read the ebook

Substation Faults and Protection

Technical Report, 2011, 17 Pages

Engineering - Power Engineering

Printing version for only US$ 0.99

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Institution / College

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Excerpt

TABLE OF CONTENT

1.0 Introduction

2.0 General Analysis and Background Theory2.1 Protection Against Direct Over Voltage2.2 Protection Against Travelling Waves

3.0 Method of Study

4.0 Results

5.0 Discussion

6.0 Recommendation

7.0 Conclusion

8.0 References

SUBSTATION FAULTS AND PROTECTION

1.0 INTRODUCTION:

The purpose of this work is to establish the type of faults that may result when substations are sited in the region of the Niger Delta due to the prevailing climatic conditions. This will aimed atensuring as far as possible a small probability of damage to substation insulations.

For most transmission lines, relatively large numbers of yearly flashovers are permitted but such number of insulation damages is absolutely not allowed for substations. Flashover of insulation at substation means a short circuit on the busbar which even with the modern means of relay protection can cause most sever system damages. Substations unlike lines have very low probability of damage therefore a quantitative idea of the probability, the so called index of lightning resistance of a substation is used. It is equal to the calculated number of years during which a voltage dangerous for the substation installation does not occur. For modern high voltage substations, the index of lightning resistance is calculated as hundred or even as thousandyears which is a proof of attempts made by designers to ensure the largest degree of lightning resistance of substation (Rao,2008,U.S Dept of Agri.2001,Martinez and Castro 2003).

Substations must be protected from the direct lightning strokes and voltage waves travelling from the line as well as switching surges. In transmission lines the induced strokes (indirect strokes) due to lightning are important for 11kv lines only. For high voltage transmission lines (up to 220kv) the surges due direct lightning strokes determine the line insulations design. For extra high voltage (400kv and above) the severity of swiching surges is much more than that due to lightning (Gupta, 2008). Whether external or internal over voltage, for reliable operations of substation proper protection is necessary. There are factors that may not produce over voltage butare capable of affecting the operation of the equipments as well as lowering the flashover, these are humidity, rain temperature, pressure and to some extent contamination on the surface of insulator and equipments (outdoor).

For proper consideration of these factors with the external and internal over voltages, a proper selection of protective devices may be made for the safe operation of substation

2.0 GENERAL ANALYSIS AND BACKGROUND THEORY:

Substations can simply be seen as a combination of apparatus that transforms the characteristics of electrical energy from one form or level to another form with the provision of facilities for switching. There are various types of substations and are classified according to their services, design, voltage level and functions. Whatever function a substation is meant for, it is the most sensitive part of the supply system.

For any reliable operation of substation the basic functions must be performed.

- Protection against direct stroke- Protection over travelling surges- Proper earthing scheme must be maintained

2.1 Protection Against Direct Over Voltage:

The effectiveness of lightning protection schemes for high and extra high voltage (ehv) stations depends upon the degree of overhead shielding against direct strokes to the station area. Quantitatively, information on shielding efficiency in terms of shielding failure exposures as a function of shielding angle has been given in several literatures.

The two ways of protecting the equipment from direct stroke is one of the following ways:

(i) Overhead shielding screen (earthed) covering the outdoor substation and the overhead lines approaching the substation.(ii) Lightning masts installed at strategic location in the station. Lightning masts are preferred foroutdoor stations up to 33kv. For 66kv and above the lightning masts become too tall and uneconomical. The overhead shielding wires are preferred because they give adequate protection

and the height of structures in the station provided with overhead shielding wires is comparatively less than that of lightning masts (Rao, 2008 Mousa 1991).

The height above the surface of ground at which the leader discharge finally orients itself on one of the objects on earth is called “the height of orientation of lightning H”, which in the first instance depend on the height of the lightning conductor h. It is customary to consider that for lightning conductor up to a height of 30m will be, H = kh, where the proportionality k has a value of 10-20 (Razevig 2003 Uppal and Rao 2009)

[...]

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Title

Substation Faults and Protection

Course

SFP 673

Author

John Tarilanyo Afa

Year2011

Pages

17

Archive No.

V213055

ISBN (eBook)

978-3-656-41136-9

ISBN (Book)

978-3-656-41233-5

File size

901 KB

Language

English

Tags

substation faults protection

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John Tarilanyo Afa

, 2011, Substation Faults and Protection, Munich, GRIN Publishing GmbH, http://www.grin.com/en/e-book/213055/substation-faults-and-protection

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Permissive Overreaching Transfer Trip Scheme (POTT)

By Admin On January 9, 2012 · Add Comment

POTT scheme relies on receiving a trip signal from the remote end relay and the local relay to initiate breaker trip. The signal is keyed using a Frequency-Shift Keying(FSK) transmitter/receiver.

Under normal conditions, the relay transmits a “guard” frequency. This frequency disengages the relay from operating.

Under abnormal conditions, the relay switches to a higher or a lower frequency to transmit a “trip” signal. When relays on both ends of the line shift to the “trip” frequency, only then are the breakers tripped. The guard/trip frequencies are maintained and specified by the utility such that no two lines in the system use the same frequency.

Usually POTT schemes are not implemented using the power line carrier. A fault on the T-line may short out the trip signal and therefore inhibit relay operation. In this scenario, multi-phase coupling of the carrier signal provides the necessary redundancy for the secure operation of this scheme.

* * * * *

Tagged with → FSK • permissive over reaching transfer trip • POTT • POTT scheme •Power Line Carrier

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What Do Symmetrical, Asymmetrical, Momentary, Interrupting, Close & Latch Ratings Mean?

By Admin On June 7, 2011 · 6 Comments

These terms were coined over the years to identify the appropriate short circuit current magnitude that engineers could use to rate the switchgears, switchboards, panelboards, circuit breakers, fuses, etc.

Without delving into details, the following is a simple explanation of these terms andwhen they are used. Note that these ratings are current ratings.

Symmetrical (RMS) Current

This term is widely used to identify the short circuit rating of breakers in low voltagesystems. This is because the low voltage breakers take 8 to 10 cycles to break a circuit. In 8 or more cycles (typically 15), the fault current will decay to a symmetrical waveform which, ofcourse, would have no DC offset.

Low voltage panels too are rated by their symmetrical current rating.

Most modern circuit breakers implicitly list their ratings in symmetrical amps.

Asymmetrical (RMS) Current

During the first half of a cycle, the fault current is at its largest magnitude – occurring at a moment when the voltage wave is passing the reference axis. This asymmetry is brought on by the DC offset current (see Figure 1 below.) At the half cycle mark, the peak RMS value of the asymmetrical current is about ~1.6 times thesymmetrical current.

Keep in mind that this magnitude is NOT the same as peak asymmetrical current. In 1987, the IEEE committee established this term (peak asymmetrical) to make it clear to the manufacturers that it is the peak current magnitude and not the RMS peak that generates destructive forces. How destructive? Well, peak asymmetrical current is about ~2.7 times the symmetrical current.

Realistically, the RMS quantity of any AC signal (voltage or current) is a phantom quantity. It is created to compare the AC magnitude to that of the DC i.e. making sure you are comparing apples to apples.

So, for example, a 5Amp RMS AC current is the same as a 5Amp DC current.

However, the peak value of the AC quantity will be .

Figure 1: Fault current magnitude following a fault

Momentary Rating

This rating is used in medium voltage and high voltage systems especially when calling out switchgears, switchboards and circuit breakers.

This is a half cycle rating and quite similar in meaning to peak RMS asymmetrical amps except it does not have the same unwieldy name.

Interrupting Rating

Quintessentially associated with medium voltage and high voltage circuit breakers and fuses.

It is the short circuit current a protective device can safely interrupt typically in 2 cycles to 5 cycles. The fault current magnitude is less than the momentary currents since the fault current would have decayed in this duration.

Interrupting rating can be specified as short circuit MVA too. This is given by the following:

where,

= Line to line voltage in kV

= Interrupting current in kA

Close & Latch Rating or Making Current

Again, used for high voltage and medium voltage circuit breakers. It is the capabilityof the breaker to close into a fault and stay in that position without destroying its poles. This rating is same as the peak asymmetrical current (during the first cycle) after the breaker closes.

Typically, in HV systems, the circuit breakers are programmed to automatically reclose after opening for approximately 15 to 50 cycles (depending on the operatingvoltage.) If the fault condition disappears in this duration then the breaker will remain closed otherwise the breaker is tripped and blocked from reclosing. Essentially, this rating determines if the breaker can stay closed or not.

One cycle is ‘ th of a second, assuming the system frequency is 60hz.

Tagged with → asymmetrical current • close and latch rating • interrupting rating • momentary rating • short circuit MVA • short circuit rating • symmetrical current

6 Responses to What Do Symmetrical, Asymmetrical, Momentary, Interrupting, Close & Latch Ratings Mean?

Allan Camello says:

September 27, 2014 at 2:45 am

What is the difference between interrupting current and momentary current?

Solomon Cooper says:

July 7, 2014 at 3:09 pm

make and break current rating(IEC) is then associated synonymously with the close and latch current rating(ANSI).

ashok reddy reguri says:

January 29, 2014 at 9:57 am

Good information

dilip says:

November 23, 2013 at 9:09 pm

i want to check asymmetrical waveform in my relay with current source, how it is possible

Admin says:

January 30, 2013 at 10:58 pm

Got it.

nathan lee says:

July 24, 2011 at 8:04 am

we also use make current and peak current…

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voltage drop limitation

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What Do Symmetrical, Asymmetrical, Momentary, Interrupting, Close & Latch Ratings Mean?

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Ranveer

Lightining Arrester Why we take the rating of surge arrestor( KV) always less then system voltage? what's calculation involved?

Ranveer S.Power Engineer

I have raised this query in Electrical Professional Group And find following answer

Radomir Pistek • You can check next document: http://www.oez.com/file/402and calculation tool: http://www.oez.com/technical-support-software-support/computational-program-sichr

Michael Novev • Lightning arresters are always connected phase to ground. Rating is based on system grounding. Simplified calculation are if effectively grounding Uar=√2Usys÷√3, if isolated neutral Uar=√2Usys To be more precise you need better coordination study.

Radomir Pistek • for HV applications you can check this document: http://www05.abb.com/global/scot/scot245.nsf/veritydisplay/5e7929863c37055ac1257ab6004619da/$file/1HSM%209543%2012-00%20Surge%20Arresters%20Buyers%20Guide%20Edition%209.2%202012-08%20-%20English.pdf

Radomir Pistek • Yaw. I think there is missing from your side voltage level and application description. This is important for calculation. Based on my previous experience in this area I think that up to 1kV you can "calculate" solution in own way, but what can be higher there is better to ask for any producer for help. There is not problem to propose / calculate parameters, problems begin with design and realization (safe spaces around products, design for cabinets with this kind of equipment, possible customized standards defined by local regulators / country /world area and of course at the end customer standards).

Ranveer singh • Is it possible to have LA rating greater than the system voltage?

Michael Novev • Yes for isolated neutral system. In case of ground fault, line to ground voltage increases up to line to line or system voltage.

Michael Novev • Electrical selection of LA is based upon 3 major factors, system voltage, system grounding and ground fault duration. (or earthing instead of grounding as used in Europe). If system neutral is isolated in case of ground fault there is no ground fault current. The voltage between any of the healthy phases and ground raises up to line to line level (faulty phase becomes ground). System can operate in this condition for prolonged period of time in some cases. If ground fault condition can be extended beyond 2 hours recommended LA minimum value should be up to 1,25Usys. That's the reason why in my first response I used simplified calculation for effectively grounded system Uar=√2Usys÷√3, for isolated neutral Uar=√2Usys. These are basic simplified calculations, to be more precise full insulation coordination study is desirable. Then LA will be better coordinated. Some LA manufacturers also simplified selection. However it follows same principles.

Ajikumar Nair • LA(Lightning Arrester) protect power system and equipment from external surge voltages (lightning) and not depended on the power system characteristics(except the voltage level) and is sensitive to the frequency of the lightning surges.

Michael Novev • LA are intended to protect the equipment in two cases. First is as Mr. Ajikumar mentioned external surge voltage or lightning, second is commutation overvoltage. First one exceeds significantly system insulation level. Second are more difficult to predict, but not less dangerous. That's why LA should be designed at lower possible safe insulation level. This will

definitely depend on system characteristics. If LA suitable for directly grounded system are used at same system voltage at insulated neutral system they will operate on the healthy phases at eachground fault.

Arshad Siddiqui • Actually surge arrestor should be rated as 80% maximum of the system voltage just like we take for the breakers loading as a tolerance factor. i.e 0.80xsystem voltage.Michael also has given this concept mathematically.But this is not applicable for isolatedneutral. In that case LA will be more than the system voltage.

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December 14, 2012

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Dinesh K. likes this

2 comments

Chandra Sekhar

Chandra Sekhar ..

Senior Manager - Electrical, Thermal Power Generation professional.

You should consider system Phase to Earth voltage as Lightning arrester rating, as it will be connected in between phase and earth. However, arrester rating differs depending upon1). the type of system i.e., effectively grounded system or non-effectively grounded system and2). class of use i.e., station class or distribution class.

chandra sekhar, Mobile- +91 - 9492 7696 35

Naomi

Naomi M.

Maintenance Engineer at ZAMBIA National Broadcastinng Corporation

a question in line with this,how is the rating of a surge arrestor determined? example: single phase load: 220Vac,30A,at 700w or 3phase 400Vac,90A,and 700w

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this a valid statement as per thestandard IEC 61508 or can other wording be used?

1. What is a SIS?A SIS is a Safety Instrumented System. It is designed to prevent or mitigate hazardous events by taking the process to a safe state when predetermined conditions are violated. A SIS is composed of a combination of logic solver(s), sensor(s), and final element(s). Other common terms for SISs are safety interlock systems, emergency shutdown systems (ESD), and safety shutdown systems (SSD). A SIS can be one or more Safety Instrumented Functions (SIF).

2. What is a SIF? SIF stands for Safety Instrumented Function. A SIF is designed to prevent or mitigate a hazardous event by taking a process to a tolerable risk level. A SIF is composed of a combination of logic solver(s), sensor(s), and final element(s). A SIF has an assigned SIL level depending on the amount of risk that needs to be reduced. One or more SIFs comprise a SIS.

3. What is SIL? SIL stands for Safety Integrity Level. A SIL is a measure of safety system performance, or probability of failure on demand (PFD) for a SIF or SIS. There are four discrete integrity levels associated with SIL. The higher the SIL level, the lower the probability of failure on demand for the safety system and the better the system performance. It is important to also note that as the SIL level increases, typically the cost and complexity of the system also increase.

A SIL level applies to an entire system. Individual products or components do not have SIL ratings. SIL levels are used when implementing a SIF that must reduce an existing intolerable process risk level to a tolerable risk range.

4. What does functional safety mean?Functional safety is a term used to describe the safety system that is dependent on the correct functioning of the logicsolver, sensors, and final elements to achieve the desired risk reduction level. Functional safety is achieved when every SIF is successfully carried out and the process risk is reduced to the desired level.

5. Why were the ANSI/ISA 84, IEC 61508, and IEC 61511 standards developed? The standards were a natural evolution for the need to reduce process risk and improve safety through a more formalized and quantifiable methodology. Additionally, and specifically for IEC 61508, as the application and usage of software has evolved and proliferated, there was an increased need to develop a standard to guide system / product designers and developers in what they needed to do to ensure and “claim” that their systems / products were acceptably safe for their intended uses.

Click here for additional information on Standards.

6. When do I need a SIF or a SIS? The philosophy of the standards suggests that a SIS or SIF should be implemented only if there is no other non-instrumented way of adequately eliminating or mitigating process risk. Specifically, the ANSI/ISA-84.00.01-2004 (IEC 61511 Mod) recommends a multi-disciplined team approach that follows the Safety Lifecycle, conducts a process hazard analysis, designs a variety of layers of protection (i.e., LOPA), and finally implements a SIS when a hazardousevent cannot be prevented or mitigated with something other than instrumentation.

7. What is a proof-test interval? Proof testing is a requirement of safety instrumented systems to ensure that everything is working and performing as expected. Testing must include the verification of the entire system, logic solver, sensors, and final elements. The interval is the period of time that the testing occurs. The testing frequency varies for each SIS and is dependent on the technology, system architecture, and target SIL level. The proof-test interval is an important component of the probability of failure on demand calculation for the system.

8. What is a Process Hazard Analysis (PHA) and who conducts this?A PHA is an OSHA directive that identifies safety problems and risks within a process, develops corrective actions to respond to safety issues, and preplans alternative emergency actions if safety systems fail. The PHA must be conducted by a diverse team that has specific expertise in the process being analyzed. There are many consulting and engineering firms that also provide PHA services. PHA methodologies can include a What-If Analysis, Hazard and Operability Study (HAZOP), Failure Mode and Effects Analysis (FEMA), and a Fault Tree Analysis.

9. What voting configurations are required for each SIL level? Obtaining a desired SIL level is dependent on a multitude of factors. The type of technology employed, the number of system components, the probability of failure on demand (PFD) numbers for each component, the system architecture (e.g., redundancy, voting), and the proof testing intervals all play a significant role in the determination of a SIL level. There is not a standard answer for what voting configurations are required for each SIL level. The voting architecture must be analyzed in the context of all the factors noted above.

10. Will a SIL rated system require increased maintenance? SIL solutions are certainly not always the most cost-effective solutions for decreasing process risk. Many times, implementing a SIL solution will require increased equipment, which inevitably will require increased maintenance. Additionally, it is likely that the higher the SIL level, the more frequent the proof testing interval will be, which may ultimately increase the amount of system maintenance that is required. This is why the standards recommend a SIL based solution only when process risk cannot be reduced by other methods, as determined by LOPA.

11. Can a F&G system be a SIF or SIS? A Fire and Gas (F&G) system that automatically initiates process actions to prevent or mitigate a hazardous event and subsequently takes the process to a safe state can be considered a Safety Instrumented Function / Safety Instrumented System.

However, it is absolutely critical in a F&G system to ensure optimal sensor placement. If there is incorrect placement of the gas / flame detectors and hazardous gases and flames are not adequately detected, then the SIF / SIS will not be effective.

Correct sensor placement is more important than deciding whether a F&G SIF / SIS should be SIL 2 or SIL 3.

12. What is SIL 4?SIL 4 is the highest level of risk reduction that can be obtained through a Safety Instrumented System. However, in the process industry this is not a realistic level and currently there are few, if any, products / systems that support this safety integrity level.

SIL 4 systems are typically so complex and costly that they are not economically beneficial to implement. Additionally,if a process includes so much risk that a SIL 4 system is required to bring it to a safe state, then fundamentally there is a problem in the process design which needs to be addressed by a process change or other non-instrumented method.

13. Can an individual product be SIL rated? No. Individual products are only suitable for use in a SIL environment. A SIL level applies to a Safety Instrumented Function / Safety Instrumented System.

14. What type of communication buses or protocols are applicable for SIL 2 or SIL 3 systems? The type of communication protocol that is suitable for a SIL 2 or SIL 3 system is really dependent on the type of platform that is being used. Options include, but are not limited to: 4-20 mA output signal, ControlNet (Allen Bradley), DeviceNet Safety (Allen Bradley), SafetyNet (MTL), and PROFIsafe. Currently, the ISA SP84 committee is working ondeveloping guidelines for a safety bus, to make sure that the foundations comply with IEC 61508, and IEC 61511 standards. The first devices with a safety bus should be available by 2008. The Fieldbus Foundation is actively involved in the committee and working on establishing Foundation Fieldbus Safety Instrumented Systems (FFSIS) project to work with vendors and end users to develop safety bus specifications.

15. For General Monitors, how can I access the PFD and MTBF data for the products? The General Monitors SIL certificates have the PFD, SFF, and SIL numbers that correspond to each product. MTBF data can be provided by request.

16. Can a manufacturer state their products are “SIL X certified” rather than “suitable for usein a SIL X system”? Individual products are only suitable for use in a SIL environment. A SIL level applies to a Safety Instrumented Function / Safety Instrumented System.

Product certificates are issued either by the manufacturer (self-certification), or other independent agency to show that the appropriate process is followed, calculations have been performed, and analysis has been completed on the individual products to indicate that they are compatible for use within a system of a given SIL level.

Full IEC 61508 certification can apply to a manufacturer’s processes. Full certification implies that a manufacturer’s product development process meets the standards set forth in the appropriate parts of sections 2 – 3 of IEC 61508 (including hardware / system and software). Receiving full certification from an accredited notifying body gives the end user confidence that the manufacturer’s engineering process has been reviewed and its product’s electrical content, firmware and logic have been assessed and conform to the guidelines set forth in the standard.

There are very few nationally accredited bodies that can issue nationally accredited certifications. Other consulting firms issue certificates that indicate that the product and / or process has been reviewed by an independent third party.

17. Can a manufacturer state their products meet all parts of the requirements of IEC 61508 parts 1 to 7?IEC 61508 consists of the following parts, under the general title Functional Safety of electrical/electronic/programmable electronic safety-related systems:Part 1: General requirementsPart 2: Requirements for electrical / electronic/programmable electronicsafety-related systemsPart 3: Software requirementsPart 4: Definitions and abbreviationsPart 5: Examples of methods for the determination of safety integrity levelsPart 6: Guidelines on the application of parts 2 and 3Part 7: Overview of techniques and measures

To be in compliance with the standard, it is necessary to conform to Parts 1 – 3. Parts 4 – 8 are informative only and can be useful in understanding and applying the standard, but do not have requirements for conformance.

Manufacturers of products generally meet Section 2 requirements to determine through a FMEDA analysis that their products are suitable for use within a given SIL level.

Companies choosing to certify their engineering processes and receive full IEC 61508 certification will also comply with Section 3 as it relates to software development.

18. What does SIL X suitable mean, is this a valid statement as per the standard IEC 61508 orcan any other wording be used?SIL stands for Safety Integrity Level. A SIL is a measure of safety system performance, or probability of failure on

demand (PFD) for a SIF or SIS. There are four discrete integrity levels associated with SIL. The higher the SIL level, the lower the probability of failure on demand for the safety system and the better the system performance. It is important to also note that as the SIL level increases, typically the cost and complexity of the system also increase.

A SIL level applies to an entire system if it reduces the risk in the amount corresponding to an appropriate SIL level. Individual products or components do not have SIL ratings. SIL levels are used when implementing a SIF that must reduce an existing intolerable process risk level to a tolerable risk range.

To be compliant with the standards. It is up to the user to ensure that procedures have been followed properly, the proof testing is conducted correctly, and suitable documentation of the design, process, and procedures exists. The equipment or system must be used in the manner in which it was intended in order to successfully obtain the desired risk reduction level. Just buying SIL 2 or SIL 3 suitable components does not ensure a SIL 2 or SIL 3 system.

..

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Arun Khilnani

Larsen and Toubro

In an industrial set-up, why are the capacitors in a APFC Bank in LV systems connected in Delta, while in HV they are connected in Star?

Why do we use a delta connected capacitor bank for LV systems and a star connected capacitor bank for HV systems? Is it because the Shor Circuit current on LV side is more than HV ? Or has it something to do with in-rush currents ?

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Sujit K. Biswas · Jadavpur University

In AC circuits, any Star connection has an equivalent Delta connection, and vice versa. Thus, the actual connection is immaterial electrically, but there are practical conveniences involved.

AC Capacitors upto about 500volts AC rating are cheap and commonly available. Thus, on LT side, connection in Delta meets the voltage need of each capacitor while generating maximum kVAR of compensation per uF used. Capacitors can be easily paralleled to achieve the requirement.

On the HT side, capacitors have to be connected in series. Star connection gives the lower voltage rating requirement of each limb (line voltage divided by 1.732), which is created by series connectionof minimum capacitors. The less the number in series, more is the reliability against failure, requiring the smallest number of capacitor of a given uF to achieve the requirement. However, note that series connection of capacitors reduce the overall uF value of the series string, thus individual capacitors need to be of higher uF value !

Nov 5, 2014

All Answers (7)

Sujit K. Biswas · Jadavpur University

In AC circuits, any Star connection has an equivalent Delta connection, and vice versa. Thus, the actual connection isimmaterial electrically, but there are practical conveniences involved.

AC Capacitors upto about 500volts AC rating are cheap and commonly available. Thus, on LT side, connection in Delta meets the voltage need of each capacitor while generating maximum kVAR of compensation per uF used. Capacitors can be easily paralleled to achieve the requirement.

On the HT side, capacitors have to be connected in series. Star connection gives the lower voltage rating requirementof each limb (line voltage divided by 1.732), which is created by series connection of minimum capacitors. The less the number in series, more is the reliability against failure, requiring the smallest number of capacitor of a given uF to achieve the requirement. However, note that series connection of capacitors reduce the overall uF value of the series string, thus individual capacitors need to be of higher uF value !

Nov 5, 2014

Dhaval Patel · Gujarat Power Engineering and Research Institute

Higher the voltage rating higher is the cost of capacitor. the cost does increase with increase in capacitance value. But a major factor is the voltage rating. On LV side, both star and delta connections can be used. But on HV side, Starconnection is more preferable from the cost point of view as, one can use capacitors of voltage rating which is 1.732thof the HV line voltage, if the capacitor are connected in star.

Nov 6, 2014

Arun Khilnani · Larsen and Toubro

Dear Dhaval,

I got your point. Does the capacitance value has something to do with in-rush currents into the bank as well ?

Regards,

Arun.

Nov 6, 2014

Arun Khilnani · Larsen and Toubro

Dear Sujit Sir,

Thank you for answering. My doubts are quite clear now. Would it be possible to share some literature about this ?

Regards,

Arun.

Nov 6, 2014

Mojtaba Mirsalim · Amirkabir University of Technology

Dear Arun Khilnani, as the price of capacitors go up with the voltage rating, it is economical to use low voltage capacitors in delta connection. In order to use the same cheap capacitors for HV systems, we connect the capacitors in series and in star arrangement to have smaller voltage across each capacitor. As you know the voltage for a phase of a star is 1 over 1.73 the line voltage.

Nov 7, 2014

Arun Khilnani · Larsen and Toubro

Dear Mr. Mirsalim,

Thank you for your reply. That explains a lot.

Regards,

Arun.

Nov 8, 2014

Pravin Sonawane · K. K. Wagh Institute of Engineering Education and Research

Dear Arun Khilnani, as the price of capacitors go up with the voltage rating, and in star voltage rating is divided by 1.732 so in HV system less voltage and hence become economical.

In LV system voltage is already less where capacitor are available in low cost and you can generate more KVAR in this.

secondly, in delta third harmonic current can be circulated and hence harmonic current can not pass towards utility. whereas in star we need to take care of harmonic current through proper neutral grounding.

In both cases series and parallel resonance must be checked while designing circuit.

Nov 10, 2014

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Zero cross over turn on - SCR firing card for Capacitor Bank

Libratherm offers SCR firing card model TSC-306 which is specially designed for APFC control applications to switch ON and OFF 3 phase capacitor banks, based on the command from the automatic power factor controller (APFC). These cards are developed to replace the electro-mechanical contactor based capacitor bank switch with the solid state switch using silicon controlled rectifiers (SCRs) or thyristors. The firing pulses are generated using zero cross over firing techniques and two sets of gate / cathode pulses are isolated using the on card ferrite core pulse transformers. Each card can simultaneously trigger 2 sets of back to back SCRs or 2 thyristor modules to switch 3 phase capacitor bank. TSC-306 accepts control signal in the form of relay contact or DC pulse from APFC, there by turning on or off the SCRs to connect or disconnect the capacitor bank to the incoming 3 phase power lines.

TSC-306-S

TSC-360-D

Each TSC-306 card has the provision to accept 2 external thermostat contacts, which can be used to operate the cooling fan mounted on the heat sinks and to trip the circuit in case of over - heating. On card LED indicates the on/off status of incoming DC power supply, firing of capacitor banks and over temperature. Normally, each of the power factor controller gives 6 to 12 outputs to select that many capacitor banks of different KVAR depending on the total KVAR demand to maintain the unity power factor. Hence, for each output from APFC it will be requiredto use 6 to 12 nos. of TSC-306 cards.

The APFC panel builders can use TSC-306 as an independent firing card and can wire the SCR modules separately mounted on the heat sink in the panel. The physical isolation of electronic cards and SCR modules makes the overall system more safe, reliable and it becomes easy to maintain and service. Libratherm has supplied more than 5000 cards, which are installed on the field giving satisfactory performance for power factor control application.

Technical Specifications:

Item Zero cross over SCR Firing Card for 3 phase capacitor bank selection.

Model TSC-306-S (Stud mounting) and TSC-306-D (DIN rail mounting)

Control Command

12 to 24DC pulse or potential free contact from APFC

Triggering Pulses

Gate/ Cathode pulses - isolated from the Input – suitable to fire 25A to 500A back to back connected SCRs

modules G1K1+G2K2 and G3K3+G4K4

Triggering Technique

Guaranteed Zero cross over firing to prevent generation of transients during switching action.

Gate Current Max. 350 mA.

Switching time Min. 100mS (5 AC cycles @ 50Hz line frequency)

Load Configuration

Single capacitor bank in 3 phase delta configuration. (Detail wiring diagram as shown below)

Over Temperature Protection

Facility to accept 2 nos. of thermostat input for fan control and trip function.

LED Indications For Power ON, THY1 ON, THY2 ON, FAN ON, CB ON, Over Temperature.

Aux. Supply Voltage

12VDC @ 600mA max.

Three Phase Voltage

110 to 500VAC (Special cards are available for 690VAC supply)

Mounting Can be easily mounted on the 35 mm DIN rail or on the base plate.

Card Size 150 (l) x 109 (w) x 60 (h) mm. (with DIN rail frame)

Application:Following diagram shows – one of the application of using ZERO CROSS OVER firing card model: TSC-306 for Automatic power factor control – for selecting the capacitorbank using back to back connected SCRs. One such card will be required for each of the capacitor bank, which can be selected through APFC controller by giving relay contacts or DC pulse to this card. TSC-306 cards can be used by APFC panel buildersand OEMs. Using this card, one can make their own thyristor switch module for desired KVAR by appropriately choosing SCRs, Heat sinks and RC snubber circuits.

For more information,Web : www.libratherm.com

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Posts: 6

capacitors are in Delta connected? y not in Star?

12/20/2011 11:47 AM

Why PF improvement capacitors are in Delta connected? y not in Star?.

In Star-Delta starter, at which point it is better to connect capacitor for improving p.f.

@ delta contactor? or @ main contactor? or @ line side?....... pls guide me.........

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#3 "Re: Why PF improvement capacitors are in Deltaconnected? y not in Star?" by Ron Nombri on

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12/22/2011 7:23 AM (score 2)

lyn

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Re: Why PF improvement capacitors are in Delta connected? y not in Star?

12/20/2011 11:58 AM

Isn't this in your text book?

Powerfactor - Wikipedia, the free encyclopedia

__________________Luck comes and goes. Skill is what you make of it. The supply of fools will always outstrip the demand .

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Re: Why PF improvement capacitors are in Delta connected? y not in Star?

12/21/2011 12:29 PM

hello.......lyn..... i know about pf. understand my question...ok. dont answer as like that........

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Re: Why PF improvement capacitors are in Delta connected? y not in Star?

12/22/2011 7:23 AM

Capacitor banks in PFC Units are connected in Delta because sums of stored KVARs are required in parallel across a three phase network to improve the power angle on the load. The summations of KVARs are done in electrical stepping sequences via the PFC Unit controller depending on the number of capacitor banks in the PFC Unit.

Where to connect capacitor to Star-Delta Starter?

Reasoning is used here; pleasefind out more before attempting.

Star-Delta Stater is soft starter for motors with high torque. To connect capacitor at the main contactor or the line side will be exposing the capacitor to instantaneous in-rush current magnitude and the rise in current magnitude switch fromstar to delta, which may in the long term have reducing effects on the life of the capacitor. Therefore, connect

the capacitor to the delta contactor. So that the capacitor is working on the delta contactor when the motor in is full running. Where its power factor will be better improved at running load. The capacitor may still be connected to the line side, but as stated, its life may be reduced when exposed to in-rush current and the change incurrent magnitude from star-delta.

Another suggestion is that, it may be connected to the line side, via a capacitor contactor, protection fuses, and a timer. So that it may be switched in seconds after the motor runs in delta mode. Motor contactors will not withstand the arching energy release from capacitors, where a capacitor contactor must be used.

__________________Kind regards, Ron

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Re: Why PF improvement capacitors are in Delta connected? y not in Star?

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12/29/2011 6:33 AM

Draw the equivalent circuit of adelta connected capacitor. You will find that for the same cell capacitance (C), delta connection will give 1.5C between any two lines, whereas if they are star connected, you would only get 0.5C between any two lines. Which is cost effective?

Having said that, please note that this delta connection of capacitors is practised only in low voltage. All HV capacitors are invariably Star connected. Because, if HV capacitors too are Delta connected (for the total capacitance advantage, as in the case of LV Capacitors), the insulation has to be done for line voltage. Whereas if you connect it in star, you need only the phase voltage insultaion, which wouldgreatly reduce the cost.

In, LV there is no big cost difference between phase voltage (240V) insulation and Line Voltage (415V) insulation; so, you get cost-effective by going for delta connection so that you get a bigger line capacitance with a smaller cell capacitance.

Whereas in HV, there is considerable cost difference between phase voltage insulation and line voltage insultaion and this cost

advantage far outweiighs any advantage that one gets from a bigger line capacitance, had it been connected in Delta.

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#3 "Re: Why PF improvement capacitors are in Deltaconnected? y not in Star?" by Ron Nombri on 12/22/2011 7:23 AM (score 2)

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About us> Collaborative platform brought to you bySchneider Electric> Helping to design electrical installations according to standards

Low voltage tariff and metering

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General rules of electrical installation design

Connection to the MV utility distribution network

Connection to the LV utility distribution network

Low voltage utility distribution networks

o Low-voltage consumers

o Low-voltage distribution networks

o The consumer-service connection

o Quality of supply voltage

Low voltage tariff and metering

MV and LV architecture selection guide for buildings

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No attempt will be made in this guide to discuss particular tariffs, since there appears to be as many different tariff structures around the world as there are utilities.Some tariffs are very complicated in detail but certain elements are basic to all of them and are aimed at encouraging consumers to manage their power consumptionin a way which reduces the cost of generation, transmission and distribution.The two predominant ways in which the cost of supplying power to consumers canbe reduced, are:

Reduction of power losses in the generation, transmission and distribution of electrical energy. In principle the lowest losses in apower system are attained when all parts of the system operate at unity power factor

Reduction of the peak power demand, while increasing the demand at low-load periods, thereby exploiting the generating plant more fully, and minimizing plant redundancy

Contents

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1 - Reduction of losses

2 - Reduction of peak power demand

3 - Meters

4 - Principle of kVA maximum demand metering

Reduction of losses

Although the ideal condition noted in the first possibility mentioned above cannot be realized in practice, many tariff structures are based partly on kVA demand, as well as on kWh consumed. Since, for a given kW loading, the minimum value of kVA occurs at unity power factor, the consumer can minimize billing costs by taking steps to improve the power factor of the load (as discussed in Chapter L). The kVA demand generally used for tariff purposes is the maximum average kVA demand occurring during each billing period, and is based on average kVA demands, over fixed periods (generally 10, 30 or 60 minute periods) and selecting the highest of these values. The principle is described below in “principle of kVA maximum-demand metering”.

Reduction of peak power demand

The second aim, i.e. that of reducing peak power demands, while increasing demand at low-load periods, has resulted in tariffs which offer substantial reduction in the cost of energy at:

Certain hours during the 24-hour day

Certain periods of the year

The simplest example is that of a residential consumer with a storage-type water heater (or storage-type space heater, etc.). The meter has two digital registers, one of which operates during the day and the other (switched over by a timing device) operates during the night. A contactor, operated by the same timing device, closes the circuit of the water heater, the consumption of which is then indicated on the register to which the cheaper rate applies. The heater can be switched on and off atany time during the day if required, but will then be metered at the normal rate. Large industrial consumers may have 3 or 4 rates which apply at different periods during a 24-hour interval, and a similar number for different periods of the year. Insuch schemes the ratio of cost per kWh during a period of peak demand for the

year, and that for the lowest-load period of the year, may be as much as 10: 1.

Meters

It will be appreciated that high-quality instruments and devices are necessary to implement this kind of metering, when using classical electro-mechanical equipment. Recent developments in electronic metering and micro-processors, together with remote ripple-control(1) from an utility control centre (to change peak-period timing throughout the year, etc.) are now operational, and facilitate considerably the application of the principles discussed.In most countries, some tariffs, as noted above, are partly based on kVA demand, in addition to the kWh consumption, during the billing periods (often 3-monthly intervals). The maximum demand registered by the meter to be described, is, in fact, a maximum (i.e. the highest) average kVA demand registered for succeeding periods during the billing interval.

(1) Ripple control is a system of signalling in which a voice frequency current (commonly at 175 Hz) is injected into the LV mains at appropriate substations. The signal is injected as coded impulses, and relays which are tuned to the signal frequency and which recognize the particular code will operate to initiate a required function. In this way, up to 960 discrete control signals are available.

Figure C10 shows a typical kVA demand curve over a period of two hours dividedinto succeeding periods of 10 minutes. The meter measures the average value of kVA during each of these 10 minute periods.

Fig. C10: Maximum average value of kVA over an interval of 2 hours

Principle of kVA maximum demand metering

A kVAh meter is similar in all essentials to a kWh meter but the current and voltage phase relationship has been modified so that it effectively measures kVAh (kilo-volt-ampere-hours). Furthermore, instead of having a set of decade counter dials, as in the case of a conventional kWh meter, this instrument has a rotating pointer. When the pointer turns it is measuring kVAh and pushing a red indicator before it. At the end of 10 minutes the pointer will have moved part way round the dial (it is designed so that it can never complete one revolution in 10 minutes) and is then electrically reset to the zero position, to start another 10 minute period. The red indicator remains at the position reached by the measuring pointer, and that position, corresponds to the number of kVAh (kilo-volt-ampere-hours) taken by the load in 10 minutes. Instead of the dial being marked in kVAh at that point however it can be marked in units of average kVA. The following figures will clarify the matter.Supposing the point at which the red indicator reached corresponds to 5 kVAh. It isknown that a varying amount of kVA of apparent power has been flowing for 10 minutes, i.e. 1/6 hour.If now, the 5 kVAh is divided by the number of hours, then the average kVA for the period is obtained.In this case the average kVA for the period will be:

Every point around the dial will be similarly marked i.e. the figure for average kVA will be 6 times greater than the kVAh value at any given point. Similar reasoning can be applied to any other reset-time interval.At the end of the billing period, the red indicator will be at the maximum of all the average values occurring in the billing period.The red indicator will be reset to zero at the beginning of each billing period. Electro-mechanical meters of the kind described are rapidly being replaced by electronic instruments. The basic measuring principles on which these electronic meters depend however, are the same as those described above.

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