REF

Technical Discussions:

Refreshment of Electrical Fundamentals (REF) (21.02.2007 - 29.01.2008)

Index Session:1

Technical Tools of the Relay Engineer Er. A. Krishnavel, B.E.(Hons.), / AEE

Session:2

An Introduction to Harmonics Er. Joseph Chelladurai, A.M.I.E., / AEE

Session:3

Vector Groups / Vector Diagrams Er. C. Saroja, B.E., / AEE

Session:4

DCS fundamentals Er. R. Kamaraj, B.E.(Hons.), M.E., / EE

Session:5

EHV AC Transmission Er. A. Krishnavel, B.E.(Hons.), / AEE

Session:6

Battery Er. R. Muthukrishnan, B.E., / AEE

Session:7

Current Transformer – Part I Er. A. Krishnavel, B.E.(Hons.), / AEE

Session:8

Current Transformer – Part II Er. A. Krishnavel, B.E.(Hons.), / AEE

TNEB / TUTICORIN THERMAL POWER STATION

Refreshment course on Electrical Fundamentals - A. Krishnavel, B.E.(Hons.),M.I.E., Asst. Exe.Engineer / MRT2 / TTPS. 21.02.2007.

Technical Tools of the Relay Engineer

Session –

1(TM:46)

A relay engineer must have a good working understanding of phasors, polarity, and symmetrical components, including voltage and current phasors during fault conditions. These technical tools are used for application, analysis, checking, and testing of protective relays and relay systems.

1. Phasors & Notations : A phasor is a complex number used to represent electrical quantities. Originally called vectors, the quantities time were renamed to avoid confusion with space vectors. A phasor rotates with the passage of time and represents a sinusoidal quantity. A vector is stationary in space. In relaying, phasors and Phasor generation of Sinusoid phasor diagrams are used both to aid in applying and connecting relays and for the analysis of relay operation after faults. Phasor diagrams must be accompanied by a circuit diagram.

Circuit Diagrams: The phasor diagram shows only the magnitude and relative phase angle of the currents and voltages, whereas the circuit diagram illustrates only the location, direction, and polarity of the currents and voltages. These distinctions are important. There are several systems and many variations of subscript notation in use for circuit diagrams as below.

Circuit Diagram - Single Subscript Notation

Double subscript notation

In all cases, the directional arrow or double subscript indicates the actual or assumed direction of current (or flux) flow through the circuit during the positive half-cycle of the ac wave.

Phasor Diagram - 1

2. Phasor Diagram & Notations: In phasor diagram -1, all the phasors originate from a common origin. Whereas in phasor diagram – 2, the voltage phasors are moved away from a common origin to illustrate the phasor addition of voltages in series. Notation for 3-ph systems varies considerably around the World. The phases are lablled a,b,c or A,B,C or 1,2,3 in USA. In other countries, r,s,t (or) R, Y, B is used. ak_aee1_mrt2_ttps_REF_S1 _21.02.07_TM:46

Phasor Diagram - 2

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A typical 3-ph system with its separate circuit and phasor diagrams is shown as below.

Circuit Diagram

Phasor Diagram

Important Notes: • Neutral (n) and ground (g) are often incorrectly interchanged. They are not the same. The voltage from n to g is zero when no zero sequence voltage exists. With zero sequence current flowing, there will be a voltage between neutral and ground, Vng = Vo. • Ground impedance (Rg or RL) resulting in a rise in station ground potential can be an important factor in relaying.

• According to ANSI/IEEE Standard 100, „„the neutral point of a system is that point which has the same potential as the point of junction of a group of equal non-reactive resistances if connected at their free ends to the appropriate main terminals or lines of the system.‟‟

3. Phase Rotation Vs Phasor Rotation: Phase rotation, or preferably phase sequence, is the order in which successive phase phasors reach their positive maximum values. Phasor rotation is, by international convention, counterclockwise in direction. Phase sequence is the order in which the phasors pass a fixed point.

All standard relay diagrams are for phase rotation a, b, c. It is not uncommon for power systems to have one or more voltage levels with a, c, b rotation; then specific diagrams must be made accordingly. The connection can be changed from one rotation to the other by completely interchanging all b and c connections.

4. Polarity: The polarity indications shown in the adjacent figures apply for both current and voltage transformers, or any type of transformer with either subtractive or additive polarity.

The polarity marks X or —— indicate The current flowing out at the polarity – marked terminal on the secondary side is “essentially in phase” with the current flowing in at the polarity-marked terminal on the primary side. The voltage drop from the polarity-marked to the nonpolarity-marked terminal on the primary side is essentially in phase with the voltage drop from the polarity-marked to the non-polaritymarked terminals on the secondary side.

The expression „„essentially in phase‟‟ allows for the small phase-angle error.

5. Power System Faults – Some guidelines: • A fault-proof power system is neither practical nor economical.

• Modern power systems, constructed with as high an insulation level as practical, have sufficient flexibility so that one or more components may be out of service with minimum interruption of service.

• In addition to insulation failure, faults can result from electrical, mechanical, and thermal failure or any combination of these. ak_aee1_mrt2_ttps_REF_S1 _21.02.07_TM:46

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• To ensure adequate protection, the conditions existing on a system during faults must be clearly understood.

• Relays must operate for several types of faults like Three-phase (a-b-c, a-b-c-g), Phase-to-phase (a-b, b-c, c-a), Two-phase-to-ground (a-b-g, b-c-g, c-a-g), Phase-to-ground (a-g, b-g, c-g) • Unless preceded by or caused by a fault, open circuits on power systems occur infrequently.

Consequently, very few relay systems are designed specifically to provide open-circuit protection. One exception is in the lower-voltage areas, where a fuse can be open. Another is in EHV, where breakers are equipped with independent pole mechanisms.

• Simultaneous faults in two parts of the system are generally impossible to relay properly under all conditions. If both simultaneous faults are in the relays‟ operating zone, at least one set of relays is likely to operate, with the subsequent sequential operation of other relays seeing the faults.

Major Types and Causes of Failures Type Cause Insulation

Electrical

Thermal

Mechanical

Design defects or errors Improper manufacturing Improper installation Aging insulation Contamination Lightning surges Switching surges Dynamic overvoltages Coolant failure Overcurrent Overvoltage Ambient temperatures Overcurrent forces Earthquake Foreign object impact Snow or ice

• When faults appear both internal and external simultaneously, some relays have difficulty •

• • •

•

determining whether to trip or not. Fortunately, simultaneous faults do not happen very often and are not a significant cause of incorrect operations.

The power factor, or angle of the fault current, is determined for phase faults by the nature of the source and connected circuits up to the fault location and, for ground faults, by the type of system grounding as well. The current will have an angle of 80 to 85 deg. lag for a phase fault at or near generator units. The angle will be less out in the system, where lines are involved.

If the transformer and generator impedances predominate, the fault angles will be higher.

Systems with cables will have lower angles if the cable impedance is a large part of the total impedance to the fault.

Unless the fault is solid, an arc whose resistance varies with the arc length and magnitude of the fault current is usually drawn through air. Several studies indicate that for currents in excess of 100A the voltage across the arc is nearly constant at an average of approximately 440 V/ft.

Arc resistance is seldom an important factor in phase faults except at low system voltages. The arc does not elongate sufficiently for the phase spacings involved to decrease the current flow significantly. In addition, the arc resistance is at right angles to the reactance and, hence, may not greatly increase the total impedance that limits the fault current.

For ground faults, arc resistance may be an important factor because of the longer arcs that can occur. Also, the relatively high tower footing resistance may appreciably limit the fault current.

6. Symmetrical Components: > What should a relay engineer know? Relay application requires knowledge of system conditions during faults, including the magnitude, direction, and distribution of fault currents, and often the voltages at the relay locations for various operating conditions. Among the operating conditions to be considered are maximum and minimum generations, selected lines out, line-end faults with the adjacent breaker open, and so forth. With this information, the relay engineer can select the proper relays and settings to protect all parts of the power system in a minimum amount of time. > History of Symmetrical Components? It was formulated by Dr. C. L. Fortescue in a classic AIEE paper in 1918. The symmetrical components method was given its first practical application to system fault analysis by C. F. Wagner and R. D. Evans in the late 1920s and early 1930s. W. A. Lewis and E. L. Harder added measurably to its development in the 1930s. Today, fault studies are commonly made with the digital computer and can be updated rapidly in response to system changes. Manual calculations are practical only for simple cases. > What is Symmetrical Components? Fortecuse‟s concept proves that an unbalance system of n-related phasors can be resolved into n systems of balanced phasors called the symmetrical components of original phasors. The n-phasors of each set of components are equal in length, and the angles between adjacent phasors of the set are equal. The method of symmetrical components consists of reducing any unbalanced three-phase system of phasors into three balanced or symmetrical systems: the positive, negative, and zero sequence components. This reduction can be performed in terms of current, voltage, impedance, and so on. ak_aee1_mrt2_ttps_REF_S1 _21.02.07_TM:46

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The positive sequence components consist of three phasors equal in magnitude and 120° out of phase. The negative sequence components are three phasors equal in magnitude, displaced 1208 with a phase sequence opposite to that of the positive sequence. The zero sequence components consist of three phasors equal in magnitude and in phase. Note all phasors rotate in a counterclockwise direction.

For our convenience, in the following discussions, the subscript 1 will identify the positive sequence component, the subscript 2 the negative sequence component, and the subscript 0 the zero sequence component. For example, Va1 is the positive sequence component of phase-a voltage, Vb2 the negative sequence component of phase-b voltage, and Vc0 the zero sequence component of phase-c voltage. All components are phasor quantities, rotating counterclockwise.

Since the three phasors in any set are always equal in magnitude, the three sets can be expressed in terms of one phasor. For convenience, the phase-a phasor is used as a reference. > Why should a relay engineer know about Symmetrical Components? Three-phase fault data are used for the application and setting of phase relays and single phase-to-ground fault data for ground relays. The method of symmetrical components is the foundation for obtaining and understanding fault data on three-phase power systems. A knowledge of symmetrical components is important in both making a study and understanding the data obtained. It is also extremely valuable in analyzing faults and relay operations. A number of protective relays are based on symmetrical components, so the method must be understood in order to apply these relays successfully. In short, the method of symmetrical components is one of the relay engineer’s most powerful technical tools. Although the method and mathematics are quite simple, the practical value lies in the ability to think and visualize in symmetrical components. This skill requires practice and experience. > Symmetrical Components – Basic Structure?

Va = Va1 + Va2 + Va0 Va = V1 + V2 + V0, Vb = Vb1 + Vb2 + Vb0 Vb = a2 V1 + a V2 + V0 = a2 Va1 + a Va2 + Va0 Vc = a V1 + a2 V2 + V0 Vc = Vc1 + Vc2 + Vc0 (with out subscripts) = a Va1 + a2 Va2 + Va0 The above equations can be solved to yield the sequence components for a phase phasors as given below.

Ia = I1 + I2 + I0, Ib = a2 I1 + a I2 + I0 Ic = a I1 + a2 I2 + I0 general set of three-

V1 = (Va + a Vb + a2 VC ) / 3 I1 = (Ia + a Ib + a2 IC ) / 3 2 V2 = (Va + a Vb + a VC ) / 3 I2 = (Ia + a2 Ib + a IC ) / 3 V0 = (Va + Vb + VC ) / 3 I0 = (Ia + Ib + IC ) / 3 Important note: A sequence component cannot exist in only one phase. If any sequence component exists by measurement or calculation in one phase, it exists in all three phases. > Power System Neutral Vs Zero sequence component: a b Power system neutral is established by connecting together c the terminals of three equal resistances as shown in the figure with other terminal of the resistors connected to one R R of the phases. Here, R Vag = Van + Vng, Vbg = Vbn + Vng , Vcg = Vcn + Vng As per Symmetrical component concept, Zero sequence voltage V0 = (Vag + Vbg + Vcg) / 3 and n g Van + Vbn + Vcn = 0 >>> i.e) V0 = Vng Neutral and ground are distinctly independent and differ in Power System Neutral voltage by Vng = Zero sequence voltage V0 of the system.

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7. Sequence Networks: • In any part of a circuit, the voltage drop caused by current of a certain sequence (positive sequence, negative sequence or zero sequence) depends on the impedance of that part of the circuit to current of that sequence. The impedance of any section of a balanced network to current of one sequence may be different from impedance to current of another sequence.

• The impedance of a circuit when positive-sequence currents alone are flowing is called the impedance to positive-sequence current. i.e) positive sequence impedance. Similarly we can define negative sequence impedance and Zero sequence impedances also.

• Since the component currents of one phase sequence cause voltage drops of like sequence only and are independent of currents of other sequences, in a balanced system, currents of any one sequence may be considered to flow in an independent network composed of the impedances to the current of that sequence only.

• The single-phase equivalent circuit composed of the impedances to current of any one sequence is called the Sequence Network for that particular sequence.

• The sequence network includes any generated emfs of like sequence. Sequence networks carrying the currents Ia1, Ia2, and Ia0 ( I1, I2, I0) are interconnected to represent various unbalanced fault conditions.

• To calculate the effect of a fault by the method of symmetrical components, it is essential to determine the sequence impedances and to combine them to form the sequence networks.

Eg. Sequence Networks of Unloaded Generators: An unloaded generator, grounded through a reactor is shown in the figure. When a fault occurs at the terminals of the generator, currents Ia, Ib, and Ic flow in the lines. If the fault involves ground, the current flowing into the neutral of the generator is designated In. One or two of the line currents may be zero, but the currents can be resolved into their symmetrical components regardless of how unbalanced they may be. >> Positive Sequence network: The generated voltages are of positive sequence only, since the generator is designed to supply balanced three phase voltages. Therefore, the positive sequence network is composed of an emf in series with the positive sequence impedance of the Generator.

Negative Sequence Network << The negative sequence networks do not contain any emf. Normally, there are no negative sequence e.m.f sources. Negative sequence impedances of rotating machine is generally different from their positive sequence impedances. (The phase displacement of transformer banks for negative sequence is of opposite sign to that of positive sequence) >> Zero Sequence Network It does not contain any e.m.f. The current flowing in the impedance Zn between neutral and ground is 3Ia0.

The voltage drop of zero sequence from point a to ground is – 3Ia0 Zn - Ia0 Zg0, where Zg0 is the zero sequence impedance per phase of the generator.

Hence the total zero sequence impedance through which Ia0 flows is Z0 = 3 Zn + Zg0

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8. Sequence Networks – Some tips:  The positive and negative sequence impedances of linear, symmetrical, static circuits are identical because the impedance of such circuits is independent of phase order provided the applied voltages are balanced.  The impedances of rotating machines to currents of the three sequences will generally be different for each sequence. The m.m.f produced by negative sequence armature current rotates in the direction opposite to that of the rotor on which is the dc field winding. Unlike the flux produced by positive-sequence current, which is stationary with respect to the rotor, the flux produced by the negative-sequence current is sweeping rapidly over the face of the rotor. The currents induced in the field and damper windings by the rotating armature flux keep the flux from penetrating the rotor. This condition is similar to the rapidly changing flux immediately upon the occurrence of a short circuit at the terminals of a machine.  Three different positive sequence reactance values are specified in Synchronous machinery.

Xd” = Sub-transient reactance, Xd‟ = Transient reactance & Xd = Synchronous reactance. For our 210MW Turbo-generator, Xd” = 0.214 p.u., Xd‟ = 0.266 p.u., Xd = 2.225 p.u. Since the sub-transient reactance values give the highest initial current value, they are generally used in system short circuit calculations for high speed relay application. The transient reactance value is used for stability consideration and slow-speed relay application. The unsaturated synchronous reactance is used for sustained fault current calculation since the voltage is reduced below saturation during faults near the unit.  The negative sequence reactance of a turbo-generator is generally equal to the sub-transient Xd” reactance.  The impedance of a transmission line to zero sequence currents differs from the impedance to positive and negative sequence currents.  The zero sequence reactance of transmission lines is higher than that for positive sequence  The neutral grounding takes vital role in Zero sequence network Eg: A simple Power System and its Sequence Networks:

Snap shot taken from GRP-V Engineering Console >>>>>>>>>>>

References: 1. Protective Relaying Theory and applications by Walter A. Elmore 2. Elements of Power System Analysis by William D. Stevenson, Jr. 3. Switchgear and Protection by Sunil S. Rao 4. Modern Power Station Practice, BEI, London <<< 000 >>>

Total No. of Participants: 24 ak_aee1_mrt2_ttps_REF_S1 _21.02.07_TM:46

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TNEB / TUTICORIN THERMAL POWER STATION

Refreshment course on Electrical Fundamentals - J. Joseph Chelladurai, A.M.I.E., Asst. Exe.Engineer / O&E:1 / TTPS. 07.03.2007.

An introduction to Harmonics

Session –

2(TM:47)

1. What is Harmonics?

Alternating voltages and currents had been assumed that they had sinusoidal waveform or shape. But it is nearly impossible to realize such a wave form in practice. All the alternating wave forms divide to a lesser or greater degrees of its ideal sinusoidal shape. Such waveforms are referred to as ―Complex waveforms‖. These wave forms are produced due to the superposition of sinusoidal waves of different frequencies.

On analysis, it is found that a complex wave essentially consists of (i) a fundamental wave – it has the lowest frequency ―f‖ (ii) a number of other sinusoidal waves whose frequencies are multiple of the basic frequency like 2f, 3f, and so on.

This deviation from a perfect sine wave can be represented by harmonics—sinusoidal components having a frequency that is an integral multiple of the fundamental frequency (see Figure 1). Thus, a pure voltage or current sine wave has no distortion and no harmonics, and a non-sinusoidal wave has distortion and harmonics.

The complex waveform (distorted waveform) shown in the figure.1 is not a pure sinusoidal wave form. It indicates the presence of 3rd harmonic and fundamental wave. In general, if a waveform deviates from pure sinusoidal form, it is the indication of presence of harmonics having different frequencies. To quantify the distortion, the term total harmonic distortion (THD) is used. The term expresses the distortion as a percentage Figure.1 of the fundamental (pure sine) of voltage and current waveforms.

2. Why & how Harmonics are generated?

3-ph alternators are one of the Harmonic Generators. Due to irregularities like asymmetric nature of magnetic flux along the air gaps, harmonics are generated. Besides this, other sources of Harmonics are non linear Power System loads where the current will not perfectly follow the voltage waveform. When the load contains a combination of linear and non-linear elements, the current can be distorted and will contain harmonics of higher frequencies. Harmonics are the by-products of modern electronics. They occur frequently when there are large numbers of personal computers (single phase loads), uninterruptible power supplies (UPSs), variable frequency drives (AC and DC) or any electronic device using solid state power switching supplies to convert incoming AC to DC. Non-linear loads create harmonics by drawing current in abrupt short pulses, rather than in a smooth sinusoidal manner (see Figure 2).

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3. Why a pure sinusoidal wave is required?

Reliable performance of any system depends on providing the required input in its purest form possible. The desired input to an electrical system is the voltage in its purest sinusoidal form available which is a measure of quality power. When harmonic currents flow in a power system, they are known as poor â&#x20AC;&#x2022;Power Qualityâ&#x20AC;&#x2013; or dirty power. Other causes of Poor power quality include transients such as voltage spikes, surges etc. Since the harmonics are repeated every cycle, they are regarded as a Steady State Cause of Poor Power Quality.

4. What does IEEE standard say?

Current harmonics are a problem because they cause increased losses in the customer and utility power system components. Transformers are especially sensitive to this problem and may need to be de-rated to as much as 50% capacity when feeding loads with extremely distorted current waveforms.

IEEE standard C57.110-1986 (IEEE Recommended Practice for Establishing Transformer Capacity When Supplying Non-sinusoidal Load Currents) states that a transformer subject to non-sinusoidal load current having more than 5% total harmonics distortion needs to be de-rated. However, when current THD is below 15%, the de-rating of the transformer would be so small that it can be neglected.

On the other hand, when current THD exceeds 15%, the transformer capability should be evaluated by a professional.

5. How Harmonics are detected / measured?

To calculate / evolve individual harmonics component, the most sophisticated algorithm is Fast Fourier Transform (FFT). This FFT algorithm should do non-intermittent evolution of input signals simultaneously on three phases. Non-intermittent evolution and storing of data at regular interval give a clear picture of harmonics present in the system.

6. Complex waveform with various Harmonics:

2f

3f

4f

5f

7. Why even harmonics are absent in Alternator?

In the above complex waveforms, the 2nd and 4th harmonic complex waveforms are asymmetrical in shape. i.e) the 1st and 3rd quarter and 2nd and 4th quarter of the waveform are not identical. But in 3rd and 5th harmonic complex wave, the wave form is symmetrical in shape i.e.) 1st and 3rd quarter and 2nd and 4th quarter are identical. This conclusion is of great help in analyzing a complex waveform into its harmonic constituents because a visual inspection of the complex wave enables us to rule out the presence of certain harmonics. For example, if the positive and negative half cycles of a complex wave are symmetrical (i.e. the wave is symmetrical about X-axis) then we need not look for EVEN harmonics. In some cases, we may be able to forecast the types of harmonics to be expected from their mode of production.

Eg. In a symmetrically designed alternators we could expect ODD harmonics only.

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8. Single-phase load harmonics vs. three-phase load harmonics Single-phase non-linear loads, like personal computers, electronic ballasts and other electronic equipment, generate odd harmonics (i.e. 3rd, 5th, 7th, 9th, etc.). The troublesome harmonics for single-phase loads are the 3rd and odd multiples of the 3rd (9th, 15th, etc.). These harmonics are called ―triplens‖ and because the A-phase triplen harmonics, B-phase triplen harmonics and C-phase triplen harmonics are all in the phase with each other. They will add rather than cancel on the neutral conductor of a 3-phase 4-wire system. This can overload the neutral if it is not sized to handle this type of load. Additionally, triplen harmonics cause circulating currents on the delta winding of a deltawye transformer configuration. When current triplen harmonics on the neutral of a 3-phase 4-wire system reach the transformer, they are reflected to the delta-connected primary where they circulate.

The result is transformer heating similar to that produced by unbalanced 3-phase current. On the other hand, 3-phase non-linear loads like 3-phase DC drives, 3-phase rectifiers, etc., for not generate current triplen harmonics (3rd, 9th, 15th, etc.). These types of loads generate primarily 5th and 7th current harmonics and a lesser amount of 11th, 13th, and higher order.

9. Why 3rd harmonics are more important?

If we plot harmonic waves for 3-phases as above, some harmonics will have the same phase sequence like fundamental (Eg. 4th harmonics). Some harmonics have opposite phase sequence of fundamental (Eg.5th harmonics) and some harmonics have no phase sequence. Normal sequence has phase displacement of 120°.

• 1,4,7,10,13,16,19,22 . . . . . .

- Positive Sequence • 2,5,8,11,14,17,20,23 . . . . . .

- Negative Sequence • 3,6,9,12,15,18,21,24 . . . . . .

- Zero Sequence The higher order harmonics have lesser magnitude. So, they can be neglected. If we delete higher order harmonics (say double digit harmonics) and fundamental, the remaining harmonics are • 4,7 . . . . . . . . . . .. . . . . . . . . .

- Positive Sequence • 2,5,8. . . . . . . . . . . . . . . . . . .

- Negative Sequence • 3,6,9. . . . . . . . . . . . . . . . . . .

- Zero Sequence EVEN harmonics are generally not present in the output of an Alternator. Now the remaining list of the harmonics will include, • 7 . . . .. . . . . . . . .. . . . . . . .

- Positive Sequence • 5. . . . . . . . . . . . . . . . . . . . .

- Negative Sequence • 3,9. . . . . . . . . . . . . . . . . . . .

- Zero Sequence Out of above, the positive and negative sequence harmonics have 120° phase displacement and hence the vector sum is zero. But, the 3rd and ninth harmonics have in-phase vectors. And out of these two harmonics, the least order but higher in magnitude is 3rd harmonics. Hence 3rd harmonic is more important than other harmonics. As we know, the 3rd harmonic wave completes three cycles when fundamental completes one cycle. Since odd multiples of 3rd harmonics are higher in order (even multiple can be neglected) they have lesser magnitude. So, it will not give much effect in the circuit. As 3rd harmonics are having this property and it is in the lower order harmonic, the presence ak_aee1_mrt2_ttps_REF_S2 _07.03.07_TM:47

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will be appreciable amount and because of this, we are in a need to neutralize the 3 rd harmonic to get better quality of Power.

10. Properties of 3rd harmonics: Since the 3rd harmonics of 3-phases are co-phasors, it has the same property of Zero sequence component in Symmetrical component. But, the major differences are, • Zero sequence will be present during the fault condition or during system unbalance. But the 3 rd harmonics will be present even system is healthy.

• Zero sequence has the frequency of fundamental. But, 3rd harmonics has 3 times that of fundamental

11. Utilization of Harmonics: Even though Harmonics are harmful to the electrical equipments, it is better utilized in the detection of Earth faults for large 3-phase alternators. Due to non-linearity with in the generator, third harmonic voltage is produced in the stator winding. Under healthy conditions, this voltage causes circulation of third harmonic capacitive charging currents resulting in a third harmonic voltage appearing between the neutral of the generator and ground. The collapse of 3rd harmonic voltage and increase of Zero sequence voltage in the neutral circuit is used for earth fault detection.

(For further details please refer. page-5 of ―Advance course on Generator Protection‖ session-2).

Unit-5 GRP Engg.Console

12. Harmonics – Effects & Remedies • Current harmonics can distort the voltage waveform and cause voltage harmonics. Voltage distortion affects not only sensitive electronic loads but also electric motors and capacitor banks. In electric motors, negative sequence harmonics (i.e. 5th, 11th, 17th), is opposite of the fundamental sequence, produce rotating magnetic fields. These fields rotate in the opposite direction of the fundamental magnetic field and could cause not only overheating but also mechanical oscillations in the motor-load system.

• Harmonics only mean trouble if the power system is not designed to handle them. High harmonic neutral currents are a problem only if the neutral is not properly sized.

• Since the core losses in electrical equipments are proportional to the frequency, harmonics affects transformers. However, harmonics are not a big problem to a transformer if it is de-rated appropriately. Even some voltage distortion below 8% THD at the point of utilization is acceptable as long as sensitive equipment is not affected. However, it is always important to be aware of the presence of harmonics and to try to minimize them by purchasing low distortion electronic ballasts and reactors for PWM VFDs. This will not only keep the harmonics in check and improve the power factor in the facility, but will also save energy by reducing losses on power system components.

• Different frequencies in a complex waveform will result in a selective resonance phenomenon in LC network and account for failure of capacitors due to high voltage.

• Tuned harmonic filters consisting of a capacitor bank and reactor in series are designed and adopted for suppressing harmonics by providing low impedance path for harmonic component.

The harmonic help to reduce THD to acceptable limit.

Voltage distortion defines the relationship between the total harmonic voltage and the total fundamental voltage. Thus, if the fundamental ac line to neutral voltage is VL-N and the total line to neutral harmonic voltage is VH, then Total Harmonic Distortion (THD) = VH / VL-N Where, - An upper summation limit of h = 25 is chosen for calculation purposes. ak_aee1_mrt2_ttps_REF_S2 _07.03.07_TM:47

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13. Some important Examples: Case:1 Voltage = Fundamental only Current = 3rd harmonic only

Average Power = Zero

Case: 2 Voltage = 3rd harmonic only Current = 3rd harmonic only

Average Power = Non - Zero

Case: 3 Voltage = 1st, 3rd , 5th Current = 1st, 3rd , 5th

Ref: 1.

2.

3.

4.

Net energy is transmitted at fundamental and fifth harmonic frequencies

Electrical Technology by B.L.Theraja TNEB Power Engineers Hand Book 2002 Course Materials for Energy Auditors www.. . . . . . . com

Total No. of Participants: 26 <<< 000 >>> ak_aee1_mrt2_ttps_REF_S2 _07.03.07_TM:47

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TNEB / TUTICORIN THERMAL POWER STATION

Refreshment course on Electrical Fundamentals - C. Saroja, B.E., .M.I.E., Asst. Exe.Engineer / Instn.I / TTPS. 15.03.2007.

Vector Groups / Vector Diagrams

Session –

3(TM:48)

The vector group of a poly phase power transformer indicates its windings, configuration and difference in phase angle between them. The phase winding of poly phase transformer can be connected together internally in different configuration depending on what characteristics are needed from the transformer.

For example, in a three phase power system, it may be necessary to connect three wire systems to a four wire system or vice versa. Because of this, the transformers are manufactured with a variety of winding configuration to meet these requirements.

The different combination of winding connection will result in different phase angles between voltages on the windings. This limits a type of transformer that can be connected between two systems, because mismatching phase angle result in circulating current and other system disturbances.

The vector group provides a simple way of indicating how an internal connections of a particular transformer or arranged. In the system adopted by IEC, the vector group is indicated by a code consisting of two or three letters followed by one or two digits. The letters indicates the winding configuration as follows.  D: Delta winding also called Mesh winding. Each phase terminals connects to two windings, so the windings form a triangular configuration with terminals on the points of the triangle.  Y: WYE winding also called star winding. Each phase terminals connects to one end of a winding, and other end of each winding connects to the other two at a central point, so that the configuration resembles a capital letter ‘Y’.

The central point may or may not be connected outside of the transformer.  Z: Zigzag winding or interconnected star winding. Basically similar to star winding, but the windings are arranged so that three legs are bent when the phase diagram is drawn. Zigzag wound transformers have special characteristics and are not commonly used where these characteristics are not needed.

In the IEC vector group code, each letter stands for one set of windings. The primary (Input) winding is designated with a capital letter, while the other winding or windings are designated with a lower case letter. Digits following the letter code indicate the difference in phase angle between the windings, in the units of 30 degrees.

For example, the transformer with a vector group of Dy1 has a Delta connected primary winding and a Wye connected secondary winding. The phase angle of secondary lags the primary by 30 degrees.

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I. How to draw a winding diagram if the vector group is given?

Example:1 Vector Group: Yd1 Step 1: Draw Yd1 vector diagram Step 2: R1,Y1,B1 as primary and star point as R2,Y2, B2 Step 3: In transformer, Induced emf on primary and secondary are in phase So, mark r1 near R1and r2 near Y1and also mark y1 near Y1and y2 near B1,mark b1 near B1and b2 near R1

R1 [r1, b2] [b1, y2]

R

[Y1] [B1]

[y1, r2]

Example: 1 Now draw the Winding diagram Step 1 : Draw six winding as shown Step 2 : Mark R1,R2 as the R phase primary winding, Y1,Y2 as the Y phase primary winding and B1,B2 as the B phase primary winding, mark r1,r2 as the R phase secondary winding, y1,y2 as the Y phase secondary winding , b1,b2 as the B phase secondary winding Step 3 :Short R2, Y2, B2 Step 4 : As in the vector diagram , connect r1and b2, r2 and y1, y2 and b1 as shown Step 5 : Lead out r1, y1, b1

R1

R2

r1

r2

Y1

Y2

y1

y2

B1

B2

b1

y2

Example: 2 Vector Group: Dy11 Step 1 : Draw Dy11 vector diagram Step 2 : R1, Y1, B1 as primary on delta side Step 3 : Mark r1, y1, b1 as secondary on star side and r2, y2, b2 as star point Step 4 : In transformer, Induced emf on primary and secondary are in phase. So, mark r1 near R1 and also mark y1 near Y1, b1 near B1 and also mark R2 near Y1, Y2 near B1 & B2 near R1

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r1

(R1,B2)

Example: 2 Y1 (B1,Y2)

(Y1,R2)

b1

Now draw the winding diagram Step 1 : Draw six winding as shown Step 2 : Mark R1,R2 as the R phase primary winding, Y1,Y2 as the Y phase primary winding and B1,B2 as the B phase primary winding, mark r1,r2 as the R phase secondary winding, y1,y2 as the Y phase secondary winding , b1,b2 as the B phase secondary winding Step 3 : Short r2, y2, b2 Step 4 : As in the vector diagram , connect R1and B2, R2 and Y1, Y2 and B1 as shown Step 5 : Lead out R1, Y1, B1 on delta side R1 R2

r1

r2

Y1

Y2

y1

y2

B1

B2

b1

b2

II. How to find vector Group if winding diagram is given?

Example 1 r1 R1 Y1 B1

R2 Y2 B2

r2 y1

y2

b1

y2

Step 1:

Draw winding diagram as shown

Step 2:

Mark R1,R2 as the R phase primary winding, Y1,Y2 as the Y phase primary winding and

B1,B2 as the B phase primary winding, mark r1,r2 as the R phase secondary winding, y1,y2 as the Y phase secondary winding , b1,b2 as the B phase secondary winding Step 3:

Draw star vector diagram as shown. R1, Y1, B1 as primary and star point as R2, Y2, B2.

In transformer, induced emf on primary and secondary are in phase.Draw a parallel line with R1 R2 arm on right side since r2 and y1 connected and also mark r1 near R1and r2 near R2 (Y1), y1 near Y1 , y2 near Y2(B1) and mark b1 near B1and b2 near B2 ( R1)

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R1 [r1, b2] R

[b1, y2]

[Y1] [B1]

[y1, r2]

III. Practical Examples: a. CT connections and winding Diagrams for ST3 Differential Protection

P1

P1

R2

s2

s1

s1

s2

r2

Y2

s2

s1

s1

s2

y2

B2

s2

s1

s1

s2

b2

R2[rs2,bs1]

rs2,bs1

R r2 R R

b2

y2

bs2,ys1

ys2,rs1

B2 [Bs2,Ys1]

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Y2[Ys2, Rs1]

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b. CT connections and winding Diagrams for UAT Differential Protection

P2

P2

R1

s1

s2

s2

s1

r1

Y1

s1

s2

s2

s1

y1

B1

s1

s2

s2

s1

b1

Rs1] [rs1, bs2] [bs1, ys2]

R

[Bs1]

[Ys1] [ys1, rs2]

Ref: 1. Electrical Technology by B.L.Theraja 2. TNEB Power Engineers Hand Book 2002 3. TTPS Field Notes 4. www.. . . . . . . com

Total No. of Participants: 34

<<< 000 >>> ak_aee1_mrt2_ttps_REF_S3 _15.03.07_TM:48

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TNEB / TUTICORIN THERMAL POWER STATION

Refreshment course on Electrical Fundamentals - R. Kamaraj, B.E.(Hons.), M.E., Executive Engineer / MRT-2 / TTPS. 07.08.2007.

DCS Fundamentals

Session â&#x20AC;&#x201C;

4(TM:53)

(DISTRIBUTED DIGITAL CONTROL MONITORING AND INFORMATION SYSTEM (DDCMIS)

1. INTRODUCTION Controlling of a process variable has been achieved mechanically in olden days through the local pneumatic instruments and controllers. On development of electrical and electronic instruments for measurements, the controllers are changed to transistor circuits and operational amplifier circuits. Analog controllers have been widely used and are quite popular for modulating control and the logic chip circuits (AND/OR gates and RS flip-flops) are used for on-off control. The signal from the sensor for any process variables like flow, level, pressure, temperature etc., may be in the form of capacitance, resistance, milli volts etc., and this analog signal is converted into a standard signal of 4-20 mA which is used for measurement and control in instrumentation systems. The algorithms for controller are built through the analog circuits and the necessary tuning parameters are represented by the potentiometers. Any change in the controller algorithm, fault detection, fault analysis etc., are difficult in the analog system.

With the arrival of digital computers, Distributed Digital Control (DDC) concept is introduced in instrumentation and control systems. Here the computer receives the transmitter's analog signal of 4-20 mA digitally through the analog to digital converter. The computer uses this digital form of the process variable in the control algorithm to compute the required control action which will act on the final control element through the digital to analog converter.

Usage of single computer for control of all process variables of a plant would result in the loss of control action in the plant due to failure of single computer. Even the redundancy system is thought of for solving this, the single computer loaded with large number of data for processing and decision taking, the time required to respond for any action will be very slow. Hence by employing the several micro-processors, dedicated services for individual process systems of plant are achieved to monitor and control of each process of the plant.

All these micro-processors are linked together to a main computer via communication cable to form a Distributed Control System (DCS). Control system distribution is split into topographical distribution and functionally distribution. In the power plant, functionally distribution is achieved by allotting the micro-processors for controls pertaining to boiler side valves/fans, turbine side valves/pumps, boiler oil firing, boiler coal firing etc.

2. BASIC REQUIREMENTS OF DCS The Microprocessor based Distributed Digital Control Monitoring and Information System (DDCMIS) is designed to meet the following basic requirements. a) High Availability b) High Reliability c) High Maintainability d) Compact design. Controllers with the maximum capability is preferable in order to minimize the numbers of the same without sacrificing the performance criteria and prescribed maximum loading. e) Expandability, Modularity and Scalability ak_aee1_mrt2_ttps_REF_S4 _07.08.07_TM:53

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f) Future application capability using Advanced Process Control techniques and

Optimization solution for plant operation g) Seamless integration capability with Asset Management/ CMMS, ERP and plant wide MIS network h) Adherence to industry accepted open standards and protocols 3. DISTRIBUTED CONTROL SYSTEM ARCHITECTURE DCS has the following sub-systems with associated software and hardware interconnected with each other as shown in fig 1. a) Fully redundant Controllers, I/O subsystem for Closed Loop Control, Sequential/ b) c) d) e) f)

Protection/ Interlocking, Data Acquisition & SOE Operator interface (HMI) Engineering Subsystem including Centralized Historian station Communication and Data Highway (fully redundant) Subsystem for Foreign Device Interface Peripheral devices namely printers, disk/tape drives, HART Management System, Large Video Screen, Flame Monitoring System, CCTV interface, GPS Clock etc.

4. FUNCTIONAL GROUP CONTROLLERS / LOCAL PROCESS UNIT Distributed control system has several local processing units. The local process unit is having a micro-processor which will be central processing unit in the local bus and decides the control action for modulating/on-off control. The microprocessor has its own memory, address bus, data bus, control bus, several registers for execution and input/output devices. The processor can be programmable for required applications to be executed. The processor has supporting modules namely analog input module, analog output module, digital input module, digital output module and highway interfacing module to communicate in both the ways with the HMI. Communication Interface enables two way communications between the process control units and the HMI. The local process unit can be dedicated exclusively for on-off control or for modulating control or for both.

The local processing units are spread over the plant and all the information from LPUs are fed to the HMI which is located at central place to supervise the process functioning.

5. I/O SUB SYSTEM 5.1 Analog Input Module Analog signals are in the form of voltage, current, resistance etc. The signals other than the voltage signals are first converted into voltage at the input section of acquisition system. The voltage signals thus available are scanned periodically by the analog input module of the process I/O systems under the control of central processing unit (CPU). The scan cycle is pre-defined taking into consideration of the time constant, fluctuation characteristic and processing requirements of the signals. Since the micro-processor works on digital mode, the information required from the field by the processor should be in digital form. Hence the signal is subjected to analog to digital conversion and the data along with quality code is sent to the processor on demand. These digital values for analog signals are utilized in the control algorithm by the micro-processor. The set value limiters for the analog signals are extended to the on-off controls. The number of channels handled in a single module is eight or sixteen. This will vary from one vendor to another.

The analog input cards are intelligent type capable of carrying out functions like signal conditioning, Linearization of Thermocouple/RTD signal, A-D conversions etc.

Individual channels are optically/galvanically isolated. It will also detect open and short circuit condition. To improve conversion and reliability each channel may have individual

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converters. Various types of AI Cards are available to handle 4-20 mA, milli Volt/ TC, Bipolar DC Voltages (eg: -10 to +10 volt), RTD/Ohms etc.

5.2 Analog Output Module This module is used for modulating control actions and driving various devices like Recorders, Indicators etc. The value of the discrete signal obtained through the analog input module for any process variable is compared with discrete form of the set point to find out the error. An appropriate programme representing the controller called a control algorithm is executed by the processor which gives a discrete controller output through the analog output module. Since the final control element works on analog signal, this discrete output signal is converted by a digital to analog converter in the analog output module.

Depending on the nature of the final control element, the analog signal issued by the AOM drives the valve/damper to the new required position through the current to pressure converter for air operation or through the thyristor circuits for electrical operation. Again here also the numbers of channels are eight or sixteen.

5.3 Digital Input Module Digital inputs are of on-off signals representing the various feedbacks like open/close or stop/run or status of the equipments/parameters available in the plant. These signals have two statuses only. The command push buttons pressed at control desk are also of digital inputs. These signals are utilized in the logic controls for both modulating/on-off control actions. The Interrogation voltage depends on the system and in general the voltages will be of 24/48V. The number of channels per module is eight, sixteen or thirty two. Individual channels are optically/galvanically isolated.

5.4 Digital Output Module This module is used for on-off control actions. The Appropriate programme for protection, interlocking and sequential control are incorporated in the application software.

The start permissive and trip conditions from various process switches through the digital input module are presented to the central processing unit. These digital inputs are checked periodically on its scanning time and the system processes these information with the control logics in built and executes the necessary commands through the digital output module to the motor control modules, and the devices like power cylinders, solenoids etc for starting/tripping the device/equipments. The digital output modules are capable of outing 24/48 V DC, 110/220 V AC depending on the selection of module. This module also issues the voltage to the control desk to light the status lamps for various equipments and also to the annunciation systems for alarming the operator under abnormal conditions. The alarm limits are checked by processor and executes the alarm command through the digital alarm module. The digital output modules provide a potential free contact to any foreign system through Interposing relays for their logic operations.

5.5 Pulse Input/ Output Module The inputs coming towards the processor for counter applications are of pulse inputs.

For measurement of speed, operation of actuators and frequency converters, the pulse input/output cards are utilized.

5.6 Redundancy of Modules All the input/output modules discussed above and the micro-processor are prone to failures. During the failure of anyone module, the controls should be present continuously without disturbing the process for which the back-up feature can be made available subject to cost of hardware. The critical loops and critical equipments are all brought under the redundant controls with auto switching over of processor during faults. A watch dog timer ak_aee1_mrt2_ttps_REF_S4 _07.08.07_TM:53

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will be present in the system and switches the faulty module to good and second one for continuous operation. The fault in the primary system can also be cleared with out affecting the process.

6. CONTROL SYSTEM The control system will be broadly divided into SG C&I, TG C&I and BOP C&I. The SG C&I system will perform the following: a. Burner Management System (BMS) including control & protection of coal Mills, Fuel oil system etc. b. Analog control Functions pertaining to Secondary Air damper control, Aux PRDS Press & Temp Control etc. c. Soot Blower Control.

The TG C&I system will perform the following functions: a. Turbine Protection System function (TPS) b. HP/LP Bypass control system c. Turbo-Generator control system The Balance of plant C&I system will perform the following functions: a. Analog control functions performing to the other plant areas like co-ordinated master control, furnace draft control, FW flow control etc. b. Binary control functions pertaining to other plant auxiliaries like FD/ID/PA/APH/ BFP etc. and electrical breakers etc 6.1 BINARY CONTROLS/OPEN LOOP CONTROL SYSTEM (OLCS) FUNCTION The OLCS includes sequence control, interlock & protection for various plant auxiliaries/valves/dampers/drives etc. The sequence control provide safe and automatic startup and shutdown of plant and of plant items associated with a plant group. The interlock and protection system ensure safe operation of plant/plant items at all times and will automatically shut down plant/plant items when unsafe conditions arise It is possible to perform automatic unit startup & shutdown by issuing minimum number of command from the OWS. Sequence Control A sequence is used to move a set of groups, sub-groups from an initial steady state (for instance 'OFFâ&#x20AC;&#x;) to a final steady state (for instance 'ON'). The sequence initiating command for the unit & group level is issued from CRT/KBD. An integrated unit startup system can be implemented in DDCMIS incorporating all operational curves for SG, TG and auxiliaries. This guide the operator to take appropriate actions at appropriate time to bring the rated parameters safely within the specified time.

A sequence is made up of steps. The steps will be executed in predetermined order according to logic criteria and monitoring time consisting of the interlock & protection requirements and check-back of previous step, which will act as preconditions before the sequence control can execute the command for that step. Each step will have a "waiting time" implying that the subsequent step would not be executed unless the specified time elapses. A monitoring time can also be defined as the maximum time required in executing the commands of any step and the time required for appearance of check-back signals. In case, this is not completed within the specified time, a message will be displayed and programme will not proceed further.

Manual intervention is possible at any stage of operation and the sequence control will be able to continue at the correct point in the programme on return to automatic control.

Protection commands will have priority over manual commands, and manual commands will prevail over auto commands.

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In this mode of operation, the sequence will progress without involving any action from the operator. The sequence start/stop command is issued from the CRT/KBDs. ii) Semi-Automatic Mode: In this mode of operation, once the sequence is initialized, the step progressing will be displayed on the CRT. But the step execution command will be prevented and will be sent by the operator via the keyboards. It will be possible to bypass and/ or simulate one or more criteria to enable the program to proceed. This facility will allow the program to be executed even if some criteria are not fulfilled because of defective switching device, etc., while the plant condition is satisfactory. All the criteria bypassed will be logged and displayed. It is possible to put the system on Auto-mode after operating it on semi-automatic mode for some steps or vice-versa, without disturbance to the sequence operation. iii) Operator Test Mode: It is possible to use the sequential control in operator guide mode/ test mode i.e., the complete system runs and receives input from the plant and the individual push button stations (where provided)/ keyboards but its command output is blocked. The whole programme, in this case will run in manual mode. This mode will allow the operator to practice manual operation using step and criteria indications. The actual protection will remain valid during this mode of operation also.

6.2 ANALOG CONTROLS/ CLOSED LOOP CONTROL SYSTEM (CLCS) FUNCTIONS The CLCS continuously acts on valves, dampers or other mechanical devices such as hydraulic couplings etc., which alter the plant operation conditions. The system can give stable control action in steady state condition and for load changes in step/ramp over the load range of 60% to 100% MCR with variation or parameters within permissible limits. The controller capability includes (i) P, PI, PD and PID control functions and their variations (ii) cascade control (iii) feed forward control (iv) State variable based predictive control for SH/RH temperature control (v) On-Off control, (vi) Ratio and bias control, (vii) Logical operation etc.

The Loop reaction time (from change of output of the sensor of the transmitter/temperature element to the corresponding control command output) is normally within 500 milli seconds. For faster loops such as feed water, furnace draft, PA header pressure control loop etc. the same wil be within 100-250 milli seconds.

The control system will be bumplessly transferred to manual on Control power supply failure, Failure of redundant controllers, Field input signal not available, Analog input exceeding preset value, etc. Any switch over from auto to manual, manual to auto and switchover from CRT operation to H/A station operation and vice versa will be bump less and the same will be reported to the operator.

7. OPERATOR INTERFACE (HMI) 7.1 Displays / Process Mimics CRT displays provide the primary window through which plant operators monitor and control the performance of the plant. The status of all process equipments and real time values of process variables are displayed in the form of process mimics. The condition of the process at any time may be decided by the operator with the help of process mimics.

Each display includes alphanumeric and graphic symbols that will be programmed to change color or shape, or blink, as a function of different states of the process variables. ak_aee1_mrt2_ttps_REF_S4 _07.08.07_TM:53

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From the process mimics, the operator can perform any control action over the equipments.

The operators by clicking on any drive on the graphic displays will be able to call the related faceplate displays of that drive. Any alarms on abnormality are to be indicated in the station with necessary and selected sound. Reports and logs required by the operator can be had through the any of peripheral devices of printers connected to the operator stations, Faceplate display for modulating drives shows the following minimum parameters, process variable, Set point, Deviation, Position feedback from the actuator, Command output to the actuator, Whether in Manual / Auto/ cascade mode or not. These displays will be in the form of both a bar graph and in alpha-numeric forms. Switching of control mode between „Auto „ and „Manual‟ is possible from the faceplates. Faceplates of binary drives with inching duty is similar to those for modulating drives except that indications for set point and process value feedback are not available. However, OPEN/CLOSE status feedbacks will be available. Faceplate displays for the other binary drives exhibit the present status of the drive (ON/OFF, OPEN/CLOSE, etc.) Operators have the facility of issuing commands to the drives from these faceplates. The information acquired from the field are presented to the operator in suitable formats on CRT screen to facilitate easy and early analysis.

The other displays are detail display, trend graphs, bar charts, group displays and alphanumeric displays. Of the several parameters/points available in the DCS, details against any point can be received by calling detail display. The detail display gives hardware/software configuration details about the point, the digital values of the process variable, set point, control mode Auto/Manual, tuning parameters, high and low limits of set point, output, alarm and range. Operators can have control over the set point, control mode and output. Only the Maintenance engineer can change the various limits listed and any configurations of point from engineering console.

7.2 Alarm Management Alarm limits (high and low) are assigned for all the analog inputs. For digital inputs, specific status i.e, closure of contact or open of contact is to deemed as alarm condition for alarming. The computer checks each parameter for violation of the alarm limits and generates audio/visual messages. Additional features are auto alarm cutout and alarm suppression. Since the points available in the DCS are more in number, depending on the services of the points, they are grouped on process unit wise. Besides the process alarms, even the hardware/software modules of the DCS are being monitored by diagnostic tools and any fault occurs alarms are being generated. All the process alarms/system alarms initiated are stored in the disk for analysis.

It is possible to filter the alarms against each column (priority, point, area, time of occurrence, status etc.) with a single mouse click. The operators are also able to apply customized filters and save the same. It is possible to acknowledge alarms individually or by page. Once one authorized operator acknowledges a particular alarm from one authorized Operator station, the same will get acknowledged globally.

7.3 Event Summary: The Operator station has an Event Message Summary displaying the following in chronological order:  Occurrence, acknowledgement of alarms and “return to normal”  Operator action journal (all control actions by operator)  Login/ Security level changes  Database modifications  System restart 7.4 Real time and historical trend display ak_aee1_mrt2_ttps_REF_S4 _07.08.07_TM:53

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Trend display gives continuous post trending of any process variable allotted for historization in DCS. Real time trending is possible for the un-historized points also. The values of process variables are retrieved from the hard disk and shown as trend on the graphical style. Values can be shown in different colors. Time axis can be changed so that the trend represents any required period. Minimum time at single graph is 1 minute and the maximum time is 96 hours. The data archival and periodicity is depending on the capacity of the storage media available in DCS. Zooming of records on X axis or Y axis to see the enlarged variations is also possible.

The following types of trend displays are be available: Bar graph, Multi pen (16 points) trend against time, X-Y plot, Group trends The following user friendly features are available in trend displays: Assignment of points by operators; Combination of real-time and historical data; Panning/ zooming/ scrolling.

Archived historical data will by scrolling back automatically; Hairline cursor for instantaneous value readout; Copy/ paste of data to clipboard; De cluttering- to make few pens temporarily disabled.

7.5 Bar Charts Bar charts shows variations of variables with reference to full scale. A collection of bar charts can be built in the mimics also to see overall condition of various equipments/parameters.

7.6 Reports and logs The system generates three basic types of reports/logs i.e., Event activated, Time activated and Operator demand log & summaries. The system has the facility for viewing time activated and operator demand logs/summaries on the OWS. Hard copy records of operation of the plant are provided by printing out pre-defined parameters in suitable formats. Process alarms logs, shift logs, operator changes logs, parameter values, system fault logs, maintenance logs are presented by the system. CRT screen display also can be printed. In case of tripping of plant, pre-trip and post trip logs for pre defined parameters are generated automatically by the processor on sensing the pre defined initiation signals.

7.7 Sequence of events Critical process events needed for the analysis for Unit tripping and other major process disturbances are scanned directly by a dedicated DI cards, time stamped with 1 milli-second accuracy and presented as a report by the DCS System chronologically. This includes hardwired inputs in input cards and calculated points / generated points of control system. The SOE Input card are equipped with digital filters with filter delay of minimum 4ms to eliminate contact bounce such that field contact which is changing state must remain in the new state for successive 4 ms to be reported as one event.

7.8 Performance Calculations Complex calculations to find out the heat rates and efficiencies at various systems are calculated in a personal computer interfaced with the DCS and when the requirement arises, the data acquisition and computation software in PC is executed for the results of the above tasks.

8. ENGINEERING WORK STATION The Engineer Stations provides the ability to maintain the process database and monitor plant performance. Process variables are created, deleted, modified, or calibrated using this console. The engineer station is to build/configure the parameters, to draw the ak_aee1_mrt2_ttps_REF_S4 _07.08.07_TM:53

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process mimics, to write control logics with necessary control algorithms, to carry out any software/hardware modification by reconfiguration, to reboot the system on failures, to analyze the system failures, to form the reports/logs, to upkeep the data base for parameters and to compile the application tools developed by the engineer. Process schematics, configuration data, control logics files, general files and software tools are stored in the system disk and any required application can be called upon for viewing and modifying with the help of concerned software tool.

All the operator functionality can also be available in the Engineering work station besides the engineering functionality.

9. COMMUNICATION SUB SYSTEM The communication sub-system is a digital communication bus that provides a high speed data transfer rapidly and reliably between the various sub-systems. Communication sub-system is normally dual redundant, consisting of two separate communication buses and two separate communication interfaces for each node.

Both data highway subsystems are active at all times. Redundant communication controllers are provided to handle the communication between each functional group of controllers of Control System and the System Bus. Any failure or physical removal of any station/module connected to the system bus will not result in loss of any communication function to and from any other station/module. Communication speed on the communication bus will be sufficient to update the HMI data base minimum once every second.

Healthiness of each bus will be automatically tested periodically at regular intervals.

In case of main bus failure or any communication device failure, the transfer to the redundant back up device will be automatic without interrupting the system operation and without any operator's intervention. Information about the failed bus/device will be displayed on the HMI. 10. FEATURES AVAILABLE IN DDCMIS a. OPC COMPLIANCE & Foreign System Interface:: Modern DCS are based on â&#x20AC;&#x153;openâ&#x20AC;? system architecture to enable easy integration with Management Information System (MIS) for plant wide automation. The open capabilities also allow third party software (such as optimization software or expert systems) to be an integral part of the systems. Communications with other devices are via industry standard protocols. It is possible to integrate any 3rd party devices seamlessly with system using standard serial open standard protocols like MODBUS Master-Salve/ MODBUS RTU OR through Ethernet to the plant data highway. The control system allow for direct communication with major PLC makes used in Power Plants and support peer-to-peer communication between the DCS control processor and the PLCs. b. Annunciation system Function: The annunciation system can be implemented as an inbuilt function of the DDCMIS. The field contacts are acquired through DDCMIS. The annunciation sequence logic are implemented as apart of the DDCMIS controllers. The annunciation window lamps mounted on unit control panel can be driven through contact output modules of the control system of DDCMIS. c. HART Device Management System: For interfacing SMART transmitters and analyzers etc giving 4-20mA analog signal along with superimposed HART interface signals, HMS Package is used for configuration, maintenance, diagnostic and Record keeping. The control system use 4-20 mA signal and HMS Package use the superimposed HART signal. The HMS access the HART information either through System Bus or through any dedicated network. This package will perform the following functions.

1. Constant scanning to monitor faults or changes to instrument configuration ak_aee1_mrt2_ttps_REF_S4 _07.08.07_TM:53

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d.

e.

f.

g.

2. Any addition/ deletion of transmitters will be reported 3. Owner defined and standard calibration procedures for all transmitters 4. Constant signal data collection to maintain continuously updated records in accordance with ISO-9000 quality standards 5. Automatic tracking of configuration changes made in the field with hand-held communicator.

Large Video Screen: Large Video Screens (LVS) are provided in UCB with approximately 170 cm diagonal size. The LVS are based on Rear-projection configuration and electromagnetic focus system and complete with projection system, screens, workstation fitted with necessary graphic control card & required software. On the LVS specially designed plant over view mimic, display of important parameters, alarm annunciation facility are provided. Further, it is possible to bring display available on any CRT of OWS on a part/ full size of LVS. External video interface is available to receive & project pictures from CCTV, Employer's Live camera, VCP etc.

Video Management: Remotely located Video devices like CCTV Cameras can be controlled from DCS environment. Selection of Camera, Pan/Tilt/ Zoom Operation is possible from Operator Stations.

GPS Satellite Radio clock: DDCMIS have the capability and hardware required for receiving time signals from external source - GPS Satellite Radio clock, broadcasted for time synchronization of various controllers/ computers.

Connectivity to Outside World: 1. OPC Compatibility enables all walks of people in the plant to view the Process Parameters in real time through Station Wide LAN. 2. Co-Ordinated Master Control Loops in advanced DCS Systems allow automatic Load Control of Units by getting load set point from Main Load Despatch Centre.

3. Modern DCS System is capable of wireless communication with mobile devices like PDA, Mobile Phones etc from which the plant process can be monitored/ controlled from any remote location in the world.

4. Advanced diagnostics & trouble shooting of the DCS System from the Manufacturer‟s Technical Support Centre through Internet is possible.

5. Corporate decision support systems like ERP (Enterprise Resource Planning), CMMS (Computerized Maintenance Management System), and SCM (Supply Chain Management) can be linked to DCS through OPC.

11. DCS in TTPS: Unit – I : ABB make ADVANT AC-450 DCS System with PROCESS PORTAL – A Operators Stations (HMI) – IN SERVICE Unit – II : ABB make SYMPHONY – HARMONY DCS System and Power Generation Portal Operator Stations – UNDER EXECUTION Units - IV & V : For FSSS & EAST system, M/s BHEL / ABB make PROCONTROL P-13 / 42 DCS is available.

Now Unit-5 MMI system has been retrofitted with Process Portal OWS. For the Station C & I, KELTRON supplied HITACHI – 3000 series DCS system is in use with HIDIC (MMI), HISEC (Controllers), TURBODEM (Hardwired Logic Manager) and 9020 Analog Control System.

Reference: 1. TNEB Power Engineers Hand Book 2002 2. NTPC‟s Technical Specification for DDCMIS Total No. of Participants: 27 <<< 000 >>> ak_aee1_mrt2_ttps_REF_S4 _07.08.07_TM:53

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TNEB / TUTICORIN THERMAL POWER STATION

Refreshment course on Electrical Fundamentals

Session – 5(TM:54)

EHV AC Transmission - A. Krishnavel, B.E.(Hons.), M.I.E., Asst. Exe. Engineer / MRT-2 / TTPS. 08.08.2007

1. What is EHV Transmission?

Transmission of Electrical power from one location to another location or from one network to another network at a voltage level of above 220kV is called Extra High Voltage Transmission.

2. What is the need for EHV transmission?

When the distance between generating stations and load centers as well as the amount of power to be handled increased, 220kV transmission (HV Transmission) was found to be inadequate for economical transmission of Electrical power.

2 a) Power Transfer PT = IVSI . IVRI . Sin . / XL i.e) PT  V Where VS = Sending End voltage, VR = Receiving end voltage,  = angle between VS & VR XL = Series Inductive Reactance of the Line 2 b) Line Loss PL  I I = line current By increasing the transmission voltage, the quantum of Power to be transferred could be increased.

Due to reduction in line current at higher voltage for the same power, the line loss also will get reduced considerably. Hence, transmission system at EHV level is preferred for economical power transmission for longer distance.

3. Various (other) levels of Over Head Transmission (OHT) system a) HV AC : 132kV, 220kV b) EHV AC : 345kV, 400kV, 500kV c) UHV AC : 750kV, 1000kV, 1150kV d) HV DC : 200kV, 500kV, 600kV, 800kV, 1000kV, 1200kV – (Voltage between two poles) 4. Dislike features of EHV Transmission system For a LONG EHV AC line (above 250kM), the series Inductive reactance, shunt capacitive reactance, real power flow, reactive power flow are more significant when compared to HV lines. Also, the entirely new aspects such as Corona, Radio Interference, Reactive Compensation, Biological effects of electric field, Switching over voltage, Transient Stability limit etc. become predominant for AC voltages above 220kV. These predominant factors have great influence on EHV design Engineering.

5. Equivalent Circuit of a Long EHV Line & Voltage profile

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6. Main Components of EHV Transmission: Overhead Lines: Bundled Conductors, Insulators, Towers, Earth wires etc.

Switching Stations & Intermediate SS: Circuit Breakers, Instrument Transformers, Isolators, Bus bars, SVS etc.

Transformer yard: Power or Auto Transformer, Lightning arrestors, Shunt Reactors Reactive Compensation plant: Static VAr Source (SVS) like TSC (Thyristor Switched Capacitors / TCR (Thyristor Controlled Reactors) 6.1. Conductors (Stranded single conductor):

ACSR – Aluminium Conductor Steel Reinforced ACAR – Aluminium Conductor Alloy Reinforced AAAC – All Aluminium Alloy Conductor

Earth Conductor containing optical communication fibres

6.2. Shut Reactors: A shunt reactor is an electromagnetic apparatus similar in many aspects to a transformer except there is only one winding per phase. It is provided at sending-end and receiving-end of long EHV and UHV transmission line. When the line is on no load or low load, the shunt capacitance predominate and receiving end voltage is higher than the sending end voltage (Ferranti effect).

Eg. The receiving end voltage of a 400kV, 1000kM line may be as high as 800kV if it is not properly compensated by shunt reactors.

For a very long line (more than 500kM) shunt reactors are necessary in intermediate sub-stations to limit voltage at intermediate point during low loads.

Shunt reactors may be connected to the low voltage tertiary winding of a transformer via a suitable circuit breaker. Smooth and stepless voltage control is possible by using Thyristor Controlled shunt Reactor (TCR) where the conduction duration of Thyristors connected in series with Shunt reactor is controlled by means of Thyristor gate firing angle.

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6.3. Shunt Capacitor: Shunt capacitors are meant only to compensate the VAR needs of the loads and system. This means that the load should not need any VAR from the source through transmission lines i.e) the reactive component of the load is generated locally through shunt capacitors and there will not be any reactive component current dispatched by generators if the capacity of the shunt capacitor is properly quantified and located.

With proper VAR compensation using shunt capacitors, the following could be achieved  Increase in power transfer capability of the line (Power Transfer PT = IVSI . IVRI . Sin . / X where VR is increased because of shunt capacitor)  Line loss gets reduced (because of comparatively lesser MVA transfer for a particular connected load)  Reduction in line drop due to lesser current flow (lesser MVA transfer) for a particular connected load.

Providing improper quantity of Shunt capacitor at improper location will lead to negative impact on the transmission system. Dumping of over sized shunt capacitor at a particular point will account for low voltage problem. For an easy understanding, a HV system is given here as an example.

Shunt capacitors are switched in when VAR demand on the distribution line goes up and voltage of the bus goes down.

6.4. Series Capacitor: Series Capacitors are mainly installed in EHV transmission systems to increase the power transfer capability of the Transmission line and to obtain desired load division among parallel circuits. Further, series capacitors favorably influence the control of both voltages and the reactive power balance.

Power Transfer PT = IVSI . IVRI . Sin . / (XL – XC) VR = Receiving end voltage with out Series compensation (XC) VR’ = Receiving end voltage with Series compensation (XC) By means of series compensation, the overall series reactance of the line (X) is reduced. So, the power transfer capability of the line is increased. The Transmission line is made flexible (controllable) by adopting Solid state Switching technology (Thyristor) for Series capacitors. This type of AC transmission is called Flexible AC Transmission (FACT)

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Note: XL = Inherent series reactance of the AC line (shown lumped) TCS = Thyristor Controlled Switch, CSC = Controllable Series Capacitor bank CTL = Controllable Transmission Link (AC) R = Current Limiting reactor for TCS US = Sending-end bus bar voltage UR = Receiving-end bus bar voltage CB = By-pass circuit breaker By varying the phase angle of Thyristor controlled switch (TCS), the current IB is varied. Thereby IC is controlled. Variation of IC gives variation in series compensation TCS can be controlled in 20 to 30 milli-seconds. Hence series compensation can be rapidly controlled. The power Flow through AC line can be controlled.

6.5 Static VAR Sources (SVS): Switchable shunt reactors and shunt capacitors have inherent slow speed. Circuit breakers used for switching purpose require at least 3 cycles (60ms) and protection requires 1 cycle (20ms) resulting in total minimum time of 4 cycles. Secondly, circuit breakers are not suitable for repeated switching during voltage variations. These limitations of switchable shunt compensation have been overcome by Static VAR Sources (SVS). Thyristors are used as switching devices instead of circuit breakers. Thyristors are fast and the compensation can be varied within few tens of milli seconds

7. CORONA : Corona is a luminous discharge in air surrounding a conductor / accessories / hardware / insulator of a HV / EHV system due to ionization of air caused by voltage gradient of positive or negative polarity at surface of conductor exceeding certain critical value.

• Corona is accompanied by audible hissing sound, bluish visible glow, localized glow points and visible streamers, power loss, radio and television interference.

• Corona discharge radiates sound and electromagnetic waves in radio frequency band and television frequency band. This causes some objectionable disturbances like Radio Interference (RI), Television Interference (TVI) and Audible Noise (AN).

• The conductor surface electric stress and electric strength of air are the principal factors determining the corona discharge level.

• Corona occurs in EHV AC line conductors, conductor clamps, flexible conductors in EHV AC substations, tubular bus bars, sharp conducting points on conductor surface, open contacts of isolators, ends of tubular bus bars etc.

• Corona is weather dependent, corona loss is low in fair weather and high in rainy and snowy weather. Foul weather corona loss is several hundred kW / kM whereas fair weather corona is only a few tens of kW / kM. • On new conductors, corona losses are more due to scratches, burrs etc. As the line ages, such losses reduce.

• Usage of Bundled conductors will greatly reduce the Corona

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8. EHV Transmission Stability & Surge Impedance Loading (SIL): Power Transfer capability of a line can be derived from the equation PT = IVSI . IVRI . Sin . / XL Where VS = Sending End voltage, VR = Receiving end voltage,  = angle between VS & VR XL = Inductive Reactance of the Line Steady State Stability Limit refers to maximum P Power transfer possible with slow and small changes in power flow / small gradual disturbances with out loss of stability Pm •  increases – Power Transfer increases • Max. Power transfer occurs at  = 90 PT • Further increase in load ie) increase in  results in decrease in Power Transfer • Beyond 90 stability of the system is lost Transient Stability Limit: refers to maximum  Power transfer possible for a given amount of sudden / large changes in power disturbance with  = 90 out loss of stability • Sudden increase in load (disturbance) causes OVERSHOOT of load angle  - the new steady  = 1 state position due to inertia

• • •

This new load angle tends to overshoot beyond 90 and thereby synchronism is lost Transient stability limit is about half of the steady state stability limit ( = 30) Pt is much lower than the thermal limit of transmission line Voltage Stability Limit: refers to maximum Power transfer through the transmission line beyond which the voltage collapses and stability is lost • Below certain limit of V2 the further increases in power flow is not possible • Beyond this voltage limit, the voltage stability would be lost and the transmission power is rapidly reduced into zero resulting major outage • high lagging loads, starting of high rated induction motors, inadequate shunt compensation at receiving end, sudden tripping of generator, tripping of generator on loss of excitation, a line or bus fault etc, are the causes for voltage collapse Surge Impedance Loading (SIL): If the load on the line is such that the reactive power produced by the line (QC) is equal to the reactive power absorbed by the line (QL), the load impedance is called surge impedance (ZS).

ZS = √(L/C), where L = Inductance of the Line, C = Capacitance of the Line • Surge Impedance of the line depends on L and C parameters of the line and are independent of line length.

• At surge impedance loading, the line does not need any compensation of reactive power. Hence it is called natural load (Pn) • When a line is loaded with unit impedance (surge impedance), the VAR generated by the line capacitance is equal to the VAR absorbed by the line inductance. Hence the line does not take any reactive power from terminal.

• Surge impedance of a overhead line with single conductor is about 400 Ω and with twin bundled conductors about 300 Ω.

• Surge impedance loading gives approximate idea of loading of line Rated voltage of line(kV) 132 220 400 765 1100 SIL (MW) 40 125 500 1700 5000 For long lines, the permissible transmission line loading based on Thermal Ratings of conductors is much higher than 1.5 Pn. But, the increased requirements of compensation and voltage regulation

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problems set a limit of power transfer to about 1.3Pn. This difficulty is likely to be overcome by controllable series compensation and SVS. Presently, long EHV-AC transmission lines can be loaded upto P = k Pn where factor k varies between 0.85 to 1.3 depending upon natural load Pn of the line and length of the line (0.85 for long line and 1.3 for shorter line) 9. Biological Effects: Invisible power frequency electric field exists between the conductor surface and the ground surface below EHV AC transmission. The electric field is strong, non-uniform and of power frequency.

The field intensity at ground level is of the order of 1 to 9 kV/m (in vertical direction). The electric field intensity is maximum at conductor surface and minimum at ground level.

Any conducting object located in an AC Electric field has a current induced in it of a value directly related to the strength of the field and the effective collecting area of the object but, if it is connected to earth, it receives no charge. A man standing under or in the near vicinity of an overhead line or substation connection in field of 1kV/m has a total current induced in his body of typically 15 A. In the case of a motor car with dry tyres in an electric field, it will become charged and if a man who is in electric contact with the ground, e.g., by wearing ordinary shoes reaches out to open the car door, he will experience a shock or shocks just before contact is made with the door handle. A steady current of about 0.5mA has been measured in an earth connection to a motor car in a field of 5kV/m, and since the capacitance to earth of a car is typically 700pF, it will be charged to a voltage of about 2.3kV. When the man grasps the door handle, the steady current of 0.5mA will flow through him, usually without any further sensation since the threshold level of perception is about 1mA. Similarly, the risk of a dangerous situation arising if a petrol filling station is located in a relatively strong electric field and a metal filling nozzle is used by a man in electrical contact with the ground.

Hence care should be taken not to park cars, tankers below the transmission lines, not to store and build wooden structure or filling stations below a transmission line.

10. EHV Networks in Tamil Nadu: The following details are the extract of TAMIL NADU GRID MAP dtd. 30.09.2002 • 400kV Checkanurani – Trichy • 400kV Checkanurani – Udumalpet • 400kV Trichy – Sriperumbudur • 400kV Trichy – Salem • 400kV Udumalpet – Salem • 400kV Sriperumbudur – Cuddapah (Andra) • 400kV Salem – Somanahalli (Karnataka) • 400kV Udumalpet – North Trichur (Kerala) In addition to the above, there are many 400kV SS and 400kV Lines are under construction in Tamil Nadu. Both TNEB and PGCIL are establishing strong EHV networks in and around Tamil Nadu, especially in the southern part to resolve the power evacuation constraints.

Eg.: Abishekapatti 400kV SS (PGCIL), Kanarpatti 400kV SS (TNEB), TTPS 400kV SS (TJVTPS)

Reference: 1. BEI, London’s Modern Power Station Practice, Volume K 2. EHV –AC, HV DC Transmission & Distribution Engineering by S.Rao 3. Extra High voltage AC Transmission Engineering by Rakosh Das Begamudre 4. TNEB Power Engineers Hand Book 2002 Total No. of Participants: 25

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TNEB / TUTICORIN THERMAL POWER STATION Refreshment course on Electrical Fundamentals

Session – 6(TM:55) +

BATTERY

-

- R. Muthukrishnan, B.E., Asst. Exe. Engineer / MRT-2 / TTPS. 13.11.2007

1.INTRODUCTION An Electric cell is an electro chemical device that produces electro-motive force and delivers electrical current. An electric battery consists of a number of electrochemical cells. It is important to note that a battery does not store electricity but rather it stores a series of chemicals and through a chemical process electricity is produced. In a lead acid battery two numbers of lead and lead derived material electrodes are in an acid mixture react to produce an electro motive force. This electrochemical reaction changes chemical energy to electrical energy.

Two types of cells 1. Primary cells 2. Secondary cells Primary cells: If the stored energy is inherently present in the chemical substances they are called primary cells. The cell will be finished once the stored energy has been exhausted. Small batteries such as flash light and radio batteries are primary cells.

Secondary Cells: If the energy is induced in the chemical substances by applying from an external source, it is called secondary cell or rechargeable cell.

Eg. Lead acid cell and Nickel cadmium cell.

2. HOW THE LEAD ACID STORAGE BATTERY WORKS? The electromotive force producing active materials of lead acid storage battery are lead dioxide (PbO2) , lead (Pb) and sulfuric acid. Chemically, the elementary lead has the valence zero and the lead dioxide is a quadravalent and in sulfuric acid both of them are unstable, rich in chemical energy change into a stable bivalent lead (lead sulfate) gives rise to a flow of electrons in the external circuit, which may also be expressed as a conversion of chemical energy to electric energy.

Lead dioxide in contact with sulfuric acid tends to make formula (1) reaction PbO2 + 4H +SO4+2e →

PbSO4 +2 H 2 O ………..(1)

2e(Two electrons) on the left side of this formula signifies two electrons. As lead dioxide and sulfuric acid do not have these electrons, formula (1) reaction requires to have these electrons brought in form outside, meaning that lead dioxide in contact with sulfuric acid has a force develop formula (1) reaction, namely, to attract these electrons. This electron-attracting force is called the positive (+) single electrode electromotive force.

In the meantime lead in contact with sulfuric acid tends to make formula (2) reaction Pb + SO4 →

PbSO4 + 2e ……………..(2)

As different from the case of lead dioxide this reaction reduces electrons, meaning that lead in contact with sulfuric acid has a force to repel electrons outside, namely the negative(-) singleelectrode electromotive force. The net electromotive force of the cell is the sum of the two single electrodes electromotive forces

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Combining these two reactions, the electricity generating reaction of the lead-acid battery is basically as below.

Anode PbO2

Electrolyte +

2H2 SO4

cathode +

Pb

Anode

( Discharge)

Electrolyte

PbSO4

+

Cathode

2H2O

PbSO4

………..(3)

Formula (3) also shows that the discharge produces lead sulfate(PbSO4) on both electrode and changes sulfuric acid into water to reduce the specific gravity of electrolyte.

To return the discharged lead-acid storage battery back to the charged state, electrical energy must be supplied from outside. This will start formula (1) and (2) reactions in opposite directions to produce lead dioxide on the anode and lead on the cathode and increase the specific gravity of electrolyte. Thus the electric energy supplied from the external source is again stored in the battery in the form of chemical energy.

3.CHARGE & DISCHARGE SYSTEM Discharging: Battery capacity is expressed in ampere hours. The capacity varies with the rate of discharge, at a higher current the number of ampere hours that can be discharged is less than at a low current. The nominal capacity of a battery is usually expressed at the 10 hour rate of discharge and it is the number of ampere hours that can be discharged at a constant current over a period of 10 hours. The curve in fig shows how the capacity varies for other periods of discharge taking the 10 hour rated capacity as 100% AMPERE HOUR DISCHARGE RATE

Percentage of 10Hr capacity

120 100 80

82.5

79

98

95

92

87

100

71 63

60 50 40 20 0 1

2

3

4

5

6

7

8

9

10

Hours

It has been found by long experience that there is a certain voltage for each discharge rate down to which no harm is done to the cell but below which the discharge must not be prolonged. The final voltage level referred for the particular discharge rate and the appropriate figures are given in the following table.

Period of Discharge in hours

10

9

8

7

6

5

4

3

2

1

Min.permissible voltage

1.85 1.84 1.83 1.83 1.83 1.82 1.81 1.80 1.78 1.75

per cell with current flowing It is possible to estimate the state of discharge of a battery by measuring the specific gravity of the electrolyte. The decrease in specific gravity approximately proportional to the extent of discharge. For a discharge at the 10 hour rate the specific gravity when the cell is fully discharged is approximately’40’ points below the fully charged figure i.e. from 1.205 to 1.165. Corresponding falls in specific for discharge at the 5 hour, 3 hour and 1 hour rats are 33, 28 and 20 points ak_aee1_mrt2_ttps_REF_S6 _13.11.07_TM:55

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respectively. It must be noted that these figures for fall of specific gravity are related to the actual specific gravity of the cell concerned when last fully charged.

Over-discharging may cause buckling of the plates, unhealthy sulphation and eventually permanent loss of capacity.

Charging: It has been found by experience to be a very satisfactory rate and is so chosen that a complete recharge from the fully discharged condition can be accomplished in approximately eight hours. It is quite permissible to use either a higher or lower current. If a higher current is used it should not exceed twice the normal rate and it must always be reduced to normal rate or less as soon as the cells begin to gas, i.e. when the voltage has raised to about 2.4 volts per cell. If a lower current is used it must not be less than one quarter of normal rate and preferably not less than one half. Very low charging rates are ineffective and lead to sluggishness in the cells and the charge may be stopped before completion leaving the battery in only a partially charged state.

The ampere hour efficiency of the cell is approximately 90% which means that the excess of discharge must be approximately 11% in ampere hours.

Trickle charging: A trickle charge is a very small charging current passed continuously through a full charged battery to compensate for the internal losses and keep the battery healthy and fully charged. By this means the battery can be kept indefinitely in fully charged condition provided the trickle charge is correct and continuous and no discharges occur.

It has been proved over an extremely wide range of conditions that a battery is receiving the correct trickle charge current if its cell voltages are within the rang 2.25 to 2.3 volts. As a rough guide the current necessary to do this is of the order of 1mA per ampere hour of the rated capacity at the 10 hour rate.

4.FLOATING BATTERY SYSTEM: This method of operation usually applies to batteries which have carry standing loads which cannot tolerate the somewhat higher voltage necessitated by trickle charge. A charger or similar apparatus normally supplies the standing load with the battery connected in parallel so that in emergency it will take over without interruption. The output of the charger is adjusted to balance the load so that no appreciable current passes through the battery and it is therefore maintained at about its open circuit voltage of 2.08 volts per cell.

It is impossible to state here in general what the correct floating voltage should be, as it depends on the equipment used with the battery. Cell voltages below about 2.05 volts should be avoided as the battery is usually then discharging. If maintained in the range of 2.05/2.1 volts there is no compensation for the internal losses in the battery, which, in consequence gradually loses charge.

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If maintained above 2.1 volts per cell, the charging current that flows does partly compensate for the internal losses but this compensation is not as complete.

If the battery system float voltage is maintained between 2.08 to2.1 volts it needs periodical quick charging once in a month and the voltage is above 2.1volts the periodical quick charging of once in 3 month to be made.

5.PREPARATION OF ELECTROLYTE: While mixing always add acid to water. Never add water to acid as it will splash dangerously. In preparing electrolyte from 1.825 acid it transferable to dilute 1.190 specific gravity For 100 litres acid Initial Sp. Gravity

Final Sp. Gravity

Quantity of water in Quantity of acid in litres

1.826

1.190

litres 86

18

Note: When acid and water are mixed there is a volume concentration, hence columns 3 and 4 do not total 100,add the calculated amount of water to the vessel and then pour the measured amount of acid slowly in a thin stream, stirring the solution with a long glass rod or tube let the diluted acid cool.

Temperature corrections: The specific gravity varies with temperature. To correct it to the standard 27 oC add 0.0007 to reading for every 1 C above 27oC subtract 0.0007 for every 1 C below 27o C. Example: The Sp. Gr. Was 1.200 temperature of acid 37o C. The correct sp. Gr. At 27 C is 1.200 + .007 = 1.207o C. 6.AUTOMOBILE BATTERY: The battery used in automobiles is similar in construction as a lead acid storage battery.

6.1 Automobile battery capacity ratings: Cold Cranking Amps (CCA): This rating indicates the ability of a battery to deliver a specified current at low temperature. The rating is determined by the amount of current a fully charged battery can supply for 30 seconds at 0oF without having the battery terminal voltage fall below 7.2 V Cranking Amps : It is the battery ability to deliver a cranking current at 32o F . To convert CA at 32o F to CCA at 0 F divide CA by 1.25 Example: A 650 CCA rated battery has the same current capacity as a 812 CA rated capacity.

Reserve Capacity (RC): This rating is the time in minutes a vehicle can be driven after the charging system fails. This is roughly equivalent to the conditions after the alternator fails while the vehicle is being driven at night with the headlight on. The battery alone must supply current to the headlights and the ignition system. The assumed battery load is a constant discharge current of 25 A. The reserve capacity rating is the length of time a fully charged battery that is at a temperature of 80 F (26.7o C) can supply 25A before the terminal voltage falls below 10.5V. Amphere Hour: The Automobile battery have 20 hour rating without having the terminal voltage fall below 10.5V. 6.2 Current Drain in Automobile Batteries Parasitic Drains: These are the small current drains required to operate various electrical systems such as the clock or alarms that continue to work when the car is parked and the ignition is off. It will drain all batteries if not driven or charged periodically. The problem is when the parasitic drain becomes excessive usually over 35 milliamps. ak_aee1_mrt2_ttps_REF_S6 _13.11.07_TM:55

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Case Drain: If the top of the battery is wet or has excessive corrosion, it could create a path between the two battery posts causing a current drain; usually 0.5 volt potential or higher will result in a battery discharge . This is called case drain.

7.COMMON FAULTS IN BATTERIES: a) Internal Short circuit: A cell may be short circuited due to sediment o conducting particles between plates, splits or performation in the separators due to excessive charge or discharge currents. The indication of the short circuited cell is no gassing on charge and little or no volt between terminals. b) Shedding: Owing to the long use, excessive vibration, over charging or buckling of plates, the active material drops off from the plates. The sediments can be removed by washing out the cells with weak electrolyte. If too-much of active material is dropped off reducing the capacity of the battery below the required standard then the battery should be considered as totally unserviceable c) Buckling: It is the bending of the plates and is caused by excessive charge and discharge currents. The buckled plates can be removed and straightened by pressing them between the wooden blocks. d) Stratification: It is uneven density of the electrolyte caused by the restriction of the free circulation of the electrolyte. e) Sulphation: This is caused by the persistent under charging or persistent discharging to a low voltage. When a battery is discharged lead sulphate is formed on the plates and it is allowed to stand in a discharged condition the sulphate first formed slowly changes to a harder form which is difficult to remove. Failure of the specific gravity to rise in the correct value after charging is an indication of slight sulphation, which is allowed to continue, will become visible as a white deposit on the plate and impossible to remove it.

8.CARE AND MAINTENANCE OF BATTERIES: 

Maintain electrolyte level 10 to 15mm above the top of the plates and the level should not exceed 25mm – above the plates. Top up with pure distilled water t keep the correct level.

Check the specific gravity of the electrolyte of every cell periodically.



Never permit discharge of cells below a terminal voltage of 1.75V



Always charge the battery to their full rated capacity.



Recharging/Equal charging should be carried-out periodically as recommended or after every emergency discharge of batteries.



Batteries should never be allowed in a semi-charged or discharged condition.



The electrolyte temperature should not be allowed to raise above 40°C while charging.



The terminals and connection should be checked regularly and cleaned or replaced as may be necessary. They should be coated with petroleum jelly.



Carry-out the charge and discharge cycle once in 6 months. The surface of the battery and flooring of the battery should be kept clean.

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9. LATEST TREND IN BATTERY SYSTEM < SMF (Sealed maintenance free) / VRLA (Valve Regulated Lead Acid ) BATTERIES > Technical Overview i. Water loss: Water in a vented lead acid cell is lost during overcharge by a process known as

electrolysis. In this process, water is converted to oxygen at the positive plates and to hydrogen at the negative plates. The oxygen and hydrogen gases are allowed to vent out of the cell into the atmosphere, resulting in the loss of water. In VRLA cells, the oxygen recombination cycle limits the water loss. ii. Oxygen transport between positive and negative plates: The oxygen recombination cycle

depends primarily on the ability to transport the oxygen generated at the positive plated to the negative plates. In vented lead-acid cells the transport process is impeded by the bulk liquid electrolyte and oxygen is liberated to the atmosphere. The migration of oxygen through liquid sulfuric acid electrolyte is approximately 10000times slower than it is through air. iii. VRLA technology provides voids (gas passages) between positive and negative plates through

which oxygen transport is greatly enhanced. iv. Gelled Electrolyte technology :

Gelled electrolyte cells are designed such that voids

develop in the gel. These voids serve as passages through which oxygen transport to the negative plates is enhanced. v. Hydrogen evolution: It is possible to design VRLA cells in which, under normal float

conditions the oxygen recombination will operate at virtually 100% efficiency. However even under normal Float conditions some water will be lost by electrolysis. There are reactions that occur at the positive plates whose only possible corresponding reaction at the negative plate is the formation of hydrogen gas. The most familiar of this reaction is corrosion of the lead or lead alloy positive grid to lead dioxide, which results in hydrogen evolution at the negative plates. These reactions cannot be prevented. vi. Pressure regulation valve: The internal cell pressure caused by the evolved gases is

regulated by a valve that allows them to escape periodically. This is the origin of the term used VRLA valves.

10. MAJOR BATTERY SYSTEMS IN TTPS: Units 4 & 5 Control & Protection : For each unit . . .

• • •

2 sets of 24V, 1500AH Lead Acid Vented Cells with Tubular positive plate 2 sets of 24V, 800AH Lead Acid Vented Cells with Tubular positive plate 1 set of 220V, 1400AH Lead Acid Vented Cells with Tubular positive plate

Units 4 & 5 UPS : For each unit . . .

•

2 sets of 360V, 500AH Lead Acid Vented Cells with Tubular positive plate

Switchyard – II:

•

1 set of 220V, 1400AH Lead Acid Vented Cells with Tubular positive plate

Unit -1 DCS UPS:

•

2 sets of 384V, 240AH SMF / VRLA battery References: 1. Text book of Electrical Technology – B.L.Theraja & A.K. Theraja 2. Engineering Chemistry by Jain & Jain 3. Battery Maintenance Training Course by NPTI 4. IEEE guide for VRLA Batteries 5.

Battery Basics by Kelvin R.Sullivan

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TNEB / TUTICORIN THERMAL POWER STATION Refreshment course on Electrical Fundamentals

Session –

7(TM:56)

Current Transformers – Part I - A. Krishnavel, B.E.(Hons.), Asst. Exe. Engineer / MRT-2 / TTPS. 14.12.2007

1. What is a Current Transformer?

Current transformers are “measuring” transformers which are required to produce a scaled down replica of the input current quantity expected for the particular measurement. They are used both to protect personnel and apparatus from high voltage and to allow reasonable insulation levels and current capacity in relays, meters, and instruments.

IS: 2705 (Part I): 1981 – Current transformer is an instrument transformer in which the secondary current, in normal conditions of use, is substantially proportional to the primary current and differs in phase from it by an angle which is approximately zero for an appropriate direction of the connections.

2. Main parts of a CT? Winding(s), magnetic core, insulation & terminals 3. How does a CT work?

CT ratio: In1 / In2 ; Lm: CT equivalent inductive magnetisation (saturable); Im: magnetising current, I1: primary current. I2: secondary current corresponding to a perfect CT, i.e. I2= I1 x (In2 / In1) Is = CT current effectively crossing the CT secondary : I2 = vectorial sum of Im & Is Rct = Internal resistance of the CT secondary winding; Rp = External burden The working principle of a CT can be easily understood with the help of functioning of a simple transformer as below.

- If the primary winding is energized while the secondary circuit is open circuited, the transformer will become, in effect, an iron-cored inductor and will present relatively high impedance. A current will flow and a voltage drop will develop across the winding in proportion to its impedance. The current will be entirely expanded in magnetizing the CT core.

- The voltage drop in the primary winding occurs because of the electro-motive force induced in this winding by the flux in the core, and a corresponding e.m.f. is induced in the secondary winding, which links with the same flux.

- If the circuit of the secondary winding is closed through an impedance (burden) a proportional current will flow; this current produces an m.m.f. which, by Lenz‟s law, must be opposed to the flux.

The tendency for the flux to be reduced by this demagnetizing force combined with the corresponding reduction of the primary back e.m.f. will cause an increase in the primary current.

- If the primary winding had no losses and the applied voltage were maintained constant, the primary back e.m.f. and therefore also the core flux, would be maintained at the initial value, and the increase in primary m.m.f. would be identical to that of the secondary winding.

- In practice the primary winding will have some resistance and may possess additional reactance due to flux which does not link the secondary winding. In consequence, the secondary winding m.m.f. is not exactly balanced by an equivalent increase in primary m.m.f. For this reason, the main flux is slightly weakened, reducing the primary back e.m.f. by an amount sufficient to all the extra current to flow through the winding resistance and leakage reactance. This is fairly represented by putting the winding resistance and leakage reactance in the input leads.

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Leakage flux of a transformer

Equivalent Circuit of a Transformer

-

In the same way secondary leakage impedance can be regarded as being additional to the connected load impedance and is represented by a suitable value of impedance in the output leads.

The shunt exciting impedance has been treated as pure reactance; core losses can be included by connecting a resistance of an appropriate value in parallel with the magnetizing reactance.

- Even though the working principle of a CT is similar to above, the CTs have their primary windings connected in series with the power circuit, and so also in series with the system impedance. As in an ammeter, the primary winding input impedance is low, the current being controlled almost entirely by the primary system impedance 4. Classification of CTs – Construction wise (major types)  Bar-Type: A fixed insulated straight conductor that is a single primary turn passing through a core assembly with a permanently fixed secondary winding. Eg. 6.6kV CTs  Bushing Type: A secondary winding insulated from and permanently assembled on an annular core with no primary winding or insulation for a primary winding. Eg. Wall Through Bushing CTs  Window Type: A secondary winding insulated from and permanently assembled on the core with no primary winding but with complete insulation for a primary winding. Eg. Generator Bus Duct CTs.  Wound Type: A primary and secondary winding insulated from each other consisting of one or more turns encircling the core. Constructed as multi-ratio CTs by the use of taps on the secondary winding.

5. Classification of CTs – Application wise (IS:2705)  Measuring CTs: A current transformer intended to supply indicating instruments, integrating meters and similar apparatus.  Protective CTs: A current transformer intended to supply protective devices (relays / trip coils) 6. Special Type of CTs:  Core-balance current transformers: The core-balance CT (or CBCT) is normally of the ring type, through the centre of which is passed cable that forms the primary winding. An earth fault relay, connected to the secondary winding, is energised only when there is residual current in the primary system. The advantage in using this method of earth fault protection lies in the fact that only one CT core is used in place of three phase CT's whose secondary windings are residually connected.

In this way the CT magnetising current at relay operation is reduced by approximately three-to-one, an important consideration in sensitive earth fault relays where a low effective setting is required.

The number of secondary turns does not need to be related to the cable rated current because no secondary current would flow under normal balanced conditions. This allows the number of secondary turns to be chosen such as to optimise the effective primary pickup current. Corebalance transformers are normally mounted over a cable at a point close up to the cable gland of switchgear or other apparatus. Physically split cores ('slip-over' types) are normally available for applications in which the cables are already made up, as on existing switchgear.  Summation current transformers: The summation arrangement is a winding arrangement used in a measuring relay or on an auxiliary current transformer to give a single-phase output signal having a specific relationship to the three-phase current input.  Air-gapped current transformers: These are auxiliary current transformers in which a small air gap is included in the core to produce a secondary voltage output proportional in magnitude to current in the primary winding. Sometimes termed 'transactors' and 'quadrature current transformers', this form of current transformer has been used as an auxiliary component of unit protection schemes in which the outputs into multiple secondary circuits must remain linear for and proportioned to the widest practical range of input currents.

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Line Current CTs: CT‟s for measuring line currents fall into one of three types.

1.Overdimensioned CT :Overdimensioned CTs are capable of transforming fully offset fault currents without distortion. In consequence, they are very large. They are prone to errors due to remanent flux arising, for instance, from the interruption of heavy fault currents.

2. Anti-remanence CT: This is a variation of the overdimensioned current transformer and has small gap(s) in the core magnetic circuit, thus reducing the possible remanent flux from approximately 90% of saturation value to approximately 10%. These gap(s) are quite small, for example 0.12mm total, and so the excitation characteristic is not significantly changed by their presence. However, the resulting decrease in possible remanent core flux confines any subsequent d.c. flux excursion, resulting from primary current asymmetry, to within the core saturation limits. Errors in current transformation are therefore significantly reduced when compared with those with the gapless type of core. Transient protection current transformers are included in IEC 60044-6 as types TPX, TPY and TPZ and this specification gives good guidance to their application and use.

3. Linear current transformers: The 'linear' current transformer constitutes an even more radical departure from the normal solid core CT in that it incorporates an appreciable air gap, for example 7.510mm. As its name implies the magnetic behaviour tends to linearisation by the inclusion of this gap in the magnetic circuit. However, the purpose of introducing more reluctance into the magnetic circuit is to reduce the value of magnetising reactance. This in turn reduces the secondary time-constant of the CT, thereby reducing the overdimensioning factor necessary for faithful transformation.

7. Specification of a Current Transformer:

VA – Burden: The external load applied to the secondary of a current transformer is called the “burden”. The burden is expressed preferably in terms of the impedance of the load and its resistance and reactance components. The term “burden” is applied not only to the total external load connected to the terminals of a current transformer but also to elements of that load. Manufacturer‟s publications give the burdens of individual relays, meters, etc., from which, together with the resistance of interconnecting leads, the total CT burden can be calculated. The CT burden impedance decreases as the secondary current increases, because of saturation in the magnetic circuits of relays and other devices. Hence, a given burden may apply only for a particular value of secondary current.

Class - Accuracy: The ability of a CT to reproduce the primary current in secondary amperes in both wave-shape and magnitude. Also we can say, it is a designation assigned to a current transformer the errors of which remain within specified limits under prescribed conditions of use.

ALF – Accuracy Limit Factor: Protection equipment is intended to respond to fault conditions, and is for this reason required to function at current values above the normal rating. Protection class current transformers must retain a reasonable accuracy up to the largest relevant current. This value is known as the „accuracy limit current‟ and may be expressed in primary or equivalent secondary terms. The ratio of the accuracy limit current to the rated current is known as the 'accuracy limit factor'. Eg. 5, 10, 15, 20 & 30 Eg: A 15 VA-5P20 CT has a guaranteed error of less than 5 % when it is subjected to 20 times its nominal current and delivers into its nominal load (15 VA to In).

Secondary Limiting emf: The product (in volt) of the ALF, the rated secondary current (in amps) and the vectorial sum (in ohm) of the rated burden and the impedance of the secondary winding.

ISF - Instrument Security Factor or Safety Factor: The value of current assigned by the manufacturer as the lowest r.m.s primary current (Ips) at which the rms value of the secondary current ak_aee1_mrt2_ttps_REF_S7 _14.12.07_TM:56

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(Iss) multiplied by the rated transformation ratio (CT ratio = Kn) does not exceed 0.9 times the value of the primary current, the secondary burden being equal to the rated burden is called rated instrument security current. Ie) Kn . Iss â&#x2030;¤ 0.9 Ips. The ratio of the rated instrument security current (Ips) to the rated primary current (Ipn) as expressed by the formula . . . . Fs = (Ips / Ipn) is called ISF. 8. CT Errors: From the equivalent circuit of the CT, it can be seen that the shunting of the burden by the exciting impedance may account for some sort of erratic performance of the CT. The exciting impedance uses small portion of the input current for exciting the core, reducing the amount of current passed to the burden. This phenomena results in three kinds of CT errors.

Vector diagram for CT

Current or Ratio Error: This is the difference in magnitude between Ip and Is and is equal to Ir, the component of Ie which is in phase with Is Phase Error: This is represented by Iq, the component of Ie in quadrature with Is and results in the phase error . The values of the current error and phase error depend on the phase displacement between Is and Ie, but neither current nor phase error can exceed the vectorial error Ie. It will be seen that with a moderately inductive burden, resulting in Is and Ie approximately in phase, there will be little phase error and the exciting component will result almost entirely in ratio error.

Composite Error: This is defined as the r.m.s. value of the difference between the ideal secondary current and the actual secondary current. It includes current and phase errors and the effects of harmonics in the exciting current. In a CT with negligible leakage flux and no turns correction, â&#x20AC;&#x17E; composite errorâ&#x20AC;&#x; corresponds to the r.m.s value of the exciting current, usually expressed as a percentage of the primary current

9. CT Performance Characteristics: The CT magnetisation curve represents the magnetising current as a function of voltage Vs developed at the CT secondary. It can be divided into 3 zones.

1 - non-saturated zone, 2 - intermediate zone, 3 - Saturated zone.

In zone 1, current Im is low and voltage Vs increases almost proportionally to the primary current.

Zone 2 is a vague zone between the nonsaturated zone and the saturated zone. There is no real break in the magnetisation curve. It is hard to locate a precise point on the curve corresponding to the saturation voltage.

In zone 3, the curve (Vs Im) becomes almost horizontal.

The error is considerable on the ratio and the secondary current distorted by the saturation. A certain number of characteristic voltages are highlighted for a CT: they correspond to zone 2 ; knowledge of these voltages is necessary when another definition is given to a particular CT. 10. What is meant by CT saturation?

Technically, this is where a further increase in primary current does not produce a proportional increase in output current because the magnetic core is becoming saturated (Zone 3 of the above graph). A large DC component dramatically increases the chances for saturation of the core. A gap in the core is

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often used to limit flux and delay saturation. During saturation, the property of the core is lost. The wave form of the secondary current shall be highly distorted.

11. Why CT secondary circuit should not be open-circuited?

From Text books . . .  Sunil. S. Rao: Normal voltage across secondary of a 15VA CT with current of 5A = 15/5 = 3V. If by mistake, the secondary is open-circuited, the voltage across the secondary rises to a high value.

The peak value may reach some kV. Open-circuited secondaries results in zero secondary current hence reduced back e.m.f. The working flux increases and core gets saturated. The secondary e.m.f. increases due to increased flux. The primary gets overheated and the core also gets over heated. Voltages are induced in the secondary by electro-magnetic induction. The peak value of the secondary voltage on open circuit may be several times the r.m.s value since the core is saturated and waveform of voltage is distorted. This may cause danger to personnel working on secondary side.  ABB:If the secondary circuit is accidentally opened, all the current will have to pass through the exciting current branches of the equivalent circuit. This will develop a high voltage across the exciting branch, which will appear as a high voltage at the secondary terminals. Because this voltage is limited by saturation of the core, the RMS value measured by a voltmeter may not appear to be dangerous. As the current cyclically passes through zero, the rate of change of flux at current zero is not limited by saturation, and is very high indeed. This induces extremely high peaks or pulses of voltage.  AREVA: The primary winding of a current transformer is connected in series with the power circuit; the impedance of the transformer, with secondary burden connected, is negligible compared with that of the power circuit. Even with the secondary circuit open the resulting higher input impedance is still small enough to be neglected.

From the above figures, it is clear that the voltage drop across the magnetizing circuit (high impedance) of the CT will be very high when the secondary (low impedance) circuit is open circuited. This voltage will be that due to the entire primary current passing through the magnetizing impedance (which normally is very high).  GEC: When a secondary circuit is open, there is no secondary mmf to oppose that due to the primary current, and all the primary mmf acts on the core as a magnetizing quantity. If the current is appreciable, the core is driven into saturation on each half wave and the high rate of change of flux while the primary current passes through zero induces a high peak emf in the secondary winding.

With rated primary current flowing, this emf may be few hundred volts for a small CT but may be many kV for a large high ratio protective CT. With system fault current flowing, the voltage would be raised in nearly direct proportion to the current value. Such voltages are dangerous not only to the insulation of the CT and connected apparatus, but more important, to human life itself. The condition must therefore be avoided, and if the secondary circuit has to be disconnected while primary current is flowing it is essentially first to short circuit the secondary terminals of the CT. The conductor used for this purpose must be securely connected and of adequate rating to carry the secondary current, including what would flow if a primary system fault should occur.

From Internet search . . .  www - 1: With the flow of both primary and secondary currents the transformer's exciting current is very low. The secondary current mmf serves to keep the magnetizing flux in check! If the secondary now opens the primary current mmf produces an exciting current 'orders of magnitude' greater than normal. And, the resultant large increase in flux density produces an extremely high voltage in the secondary.  www – 2: Simply a transformer action. The turns ratios of most power transformers are low so the voltages are low also. In a CT the primary is 1 turn so the turns ratio is high. Normally the primary voltage drop is low because of the reflected impedance of the load which is usually a very low ak_aee1_mrt2_ttps_REF_S7 _14.12.07_TM:56

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







resistance like a current shunt. When you remove the load, the primary drops appreciable voltage according to it's now higher inductive reactance and the voltage is multiplied by the high turns ratio and you have sometimes very high voltages. The biggest danger is when you open the load under power as the voltage rises quickly enough to maintain an arc. If the transformer or something connected to it is not insulated for high voltages you can get a fire. If Jumper Joe is pulling the wire off, he can become the easiest path to ground www – 3: Turns-ratio is not responsible for overvoltage. Even CTs with lower ratios, like 5:1 or 1:1, have the cautionary notice (at least in the USA!) Furthermore primary voltage is a fraction of Volts.

So, using turns-ratio as the primary to secondary multiplier, secondary volts would be in the order of volts to tens of volts. Overvoltage occurs when the secondary open-circuits and the demagnetizing effect of the secondary emf is lost. Flux density quickly increases, limited only by core saturation.

As core saturation progresses, waveshape changes. The usual sinewave changes to a peaked wave. Such a waveshape has an extremely high dV/dT characteristic. It is very likely that insulation flashover and/or fire results from dV/dT... not from a high amplitude sine wave! www – 4: An open CT present itself as a large inductance to the primary current source and develops a large voltage on it primary winding. The secondary winding will then develop a voltage that is N times larger than the primary (because the transformer ratio is 1:N - Primary:Secondary). www – 5: The CT is designed to lower current to a safe and measureable level. To accomplish this, the voltage level on the secondary is raised. P=IE, if P is constant, I and E are then inversely proportional. The windings ratio determines the secondary voltage levels. While the secondary is connected to a measuring device, it is essentially shorted. Opening the secondary circuit immediately raises the voltage to levels pre-determined by the primary voltage and the windings ratio. There are shunted CT's available that greatly reduce potential hazards typically associated with standard design CT's. Always remove power and install shorting bars prior to working on CT circuits. www – 6: when you think about power transformer then voltage is aprox. constant and current in primary is depend on secondary load. so if you short power transformer then current in primary become very huge and may (must) be damage to winding and insulation.

But about currant transformer current passing in primary is depend (=same) on busbas or cable where current transformer mount (which is not dependent on load of secondary of CT) & voltage of primary is depend on secondary load. if your secondary of CT is open than as per magnetic coupling very high voltage generated (because of secondary current = 0 ) at secondary. And insulation will be fail.

Current Transformers – Part II . . . .

CT – a boon to protection engineer, CT testing, CT case studies, Modern trend in CT technology and application etc. etc. etc.

<<<000 >>> References: 1. The Art and Science of Protective Relaying by C. Russell Mason, 2. GEC measurements 2. Protective Relaying Theory and Application by Walter A. Elmore, 3. IS: 2705 part 1 – IV 3. Switchgear and Protection by Sunil. S. Rao

Total No. of Participants: 30

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TNEB / TUTICORIN THERMAL POWER STATION Refreshment course on Electrical Fundamentals

Session –

8(TM:57)

Current Transformers – Part II - A. Krishnavel, B.E.(Hons.), Asst. Exe. Engineer / MRT-2 / TTPS. 29.01.2008

1. CT Tests: (IS:2705 (Part-I) - 1981 As per IS:2705 (Part-I)-1981, the classification of CT tests have been listed out as below.

Sl Description of test Type Routine Special no. test test test a) Verification of terminal markings and polarity √ √ b) High voltage power frequency test on primary windings √ √ c) High voltage power frequency test on secondary windings √ √ d) Over voltage inter-turn test √ √ e) Determination of error according to the requirements of √ √ appropriate accuracy class f) Short time current tests √ g) Temperature rise test √ h) Impulse voltage test √ i) High voltage Power frequency wet withstand voltage test on √ outdoor current transformers j) Commissioning tests √ k) Partial discharge test √ Out of these tests, the following tests are carried out at site.

1.1 Polarity & test: When a CT is used with measuring or control device that responds only to the magnitude of the current, and the direction of current flow does not affect its response / operation, then there is no need for CT polarity confirmation. Whereas, if the direction of current flow / phase reversal affects the operation / response of that device, then the CT polarity plays an important role. In case of interaction of two or more currents, the correct operation of the device depends on the relative phase positions of the currents in addition to the magnitudes. To show the relative instantaneous directions of current flow, one primary and one secondary terminal are identified with a distinctive polarity marker. These indicate that at the instant when the primary current is flowing into the marked primary terminal, the secondary current is flowing out of the marked secondary terminal.

CT polarity can be determined by three generally accepted methods. i. The DC voltage test momentarily imposes a small DC voltage at one side of a C.T and the direction of the momentary switch 3 – 5V deflection of a milli-ammeter at the opposite side of the CT is (-) noted and compared with polarity marks. This is the most (+) widely used method P1 P2 ii. The AC voltage test utilizes an oscilloscope to compare the instantaneous values of voltage on the primary and secondary of a C.T while an AC voltage is impressed on the secondary S1 S2 iii. The current method compares the polarity of the CT under test - + with that of a C.T. whose polarity is known by circulating current through both and measuring the difference.

Switch is closed for a moment and response is observed in mA The convention is that when primary current enters the P1 terminal, meter secondary current leaves the S1 terminal as shown in the figure. +ve deflection => Polarity OK With the help of ordinary dry cells and mA meter, the polarity test can be successfully done.

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1.2 Insulation Resistance test: With 500V megger, IR value of the CT is measured between each windings in secondary (for muticore CTs like bushing type CTs), between Primary and Earth & between Primary and Secondary.

1.3 Winding resistance test: Using Wheatstone bridge or CT winding resistance measurement meter, the secondary winding resistance is measured. The temperature of the winding is to be noted specifically.

1.4 Magnetization Test: This test is mainly to asertain the characteristics of the magnetizating components in a CT, especially the magnetic core P2 P1 and to assure that CT is capable of developing its published secondary terminal voltage without excessive excitation current. CTs S1 S2 intended for different applications will have different magnetization characteristics. To get this, a variable ac voltage at rated frequency is applied across secondary winding of the CT as shown in the figure, with primary winding open circuited and secondary burden disconnected. The curve showing this externally applied excitation A Is V Vs voltage and measured excitation current is called magnetization curve of that particular CT core. Knee point voltage VK takes a vital Variable isolated AC voltage source role in protection class CT cores. It is defined as 'that point at which a further increase of 10% of secondary e.m.f. would require an increment of exciting current of 50%â&#x20AC;&#x2122; Prior and after the magnetization characteristic test, the core of the CT should be demagnetized by slowly raising the voltage to a high value and then slowly reducing it to zero two or three times. It should also be ensured that the applied voltage is slowly reduced to Zero after reaching the knee point. This is to avoid high rate of change of flux causing high induced voltage damaging secondary insulation.

While measuring secondary current and voltage, substantial deviations from published curves (supplied by manufacturer) should be investigated (or from the curves obtained during commissioning) and may indicate a turn to turn short circuit or a completed magnetic path around the CT core. In many instances several secondary cores are mounted in close proximity on the same primary lead. It is possible, through failure of grading shields or CT support structures, to have coupling between cores which is not detectible by excitation tests, but it is still substantial enough to improperly operate bus differential relays. The presence of abnormal coupling can be detected by reading open circuit voltage on CTâ&#x20AC;&#x2122;s adjacent to a CT being excitation tested.

In general, metering CTs need not to have higher saturation level, thus protecting the connected instruments or meters against over currents. They require accuracy over a range of primary current about 5% full load upto 125%. Whereas, the protection CTs have to maintain their accuracy upto short circuit magnitude which is being many times that of full load and hence the saturation level (knee point voltage) is high compared to metering CTs. 1.5 Ratio Test (for all taps) The transformation capability of a CT is confirmed by injecting rated Primary injection Ip Test kit primary current (Ip) of the CT through primary winding and the secondary current (Is) is measured. The ratio between these two is A termed as CT ratio (actual transformation ratio). If this ratio is different from the rated transformation ratio, the difference is mentioned in P1 P2 percentage of rated value, called ratio error.

Example.

S1 S2 CT ratio (rated) as per name plate = 1000 / 5A = 200 Primary injection current Ip = 1000 A A Secondary current measured Is = 5.2 A

Is

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CT ratio error = ([(200 x 5.2) – 1000] / 1000) x 100 = 4% 2.0 Latest Trends in CT technology: (Good bye to Electromagnetic era . . . ) The conventional electromagnetic type instrument transformers (CT & VT) have a problem of nonlinearity (saturation), electro-magnetic interference, bulky and weighty design. The Novel concept of using optical sensors is now becoming very popular in Modern Power system design and application.

(Electromagnetic) Optical sensors: Certain optical sensing media (glass, crystals, plastics) show a sensitivity to electric and magnetic fields and that some properties of a probing light beam can be altered when passing through them.

Refer the above diagram. Consider the case of a beam of light passing through a pair of polarising filters. If the input and output polarising filters have their axes rotated 45° from each other, only half the light will come through. The reference light input intensity is maintained constant over time. Now if these two polarising filters remain fixed and a third polarising filter is placed in between them, a random rotation of this middle polariser either clockwise or counter-clockwise will be monitored as a varying or modulated light output intensity at the light detector.

When a block of optical sensing material (glass or crystal) is immersed in a varying magnetic or electric field, it plays the role of the ‘odd’ polariser. Changes in the magnetic or electric field in which the optical sensor is immersed are monitored as a varying intensity of the probing light beam at the light detector. The light output intensity fluctuates around the zero-field level equal to 50% of the reference light input. This modulation of the light intensity due to the presence of varying fields is converted back to time-varying currents or voltages.

A transducer uses a magneto-optic effect sensor for optical current measuring applications.

This reflects the fact that the sensor is not basically sensitive to a current but to the magnetic field generated by this current. Although ‘all-fibre’ approaches are feasible, most commercially available optical current transducers rely on a bulk-glass sensor. Most optical voltage transducers, on the other hand, rely on an electro-optic effect sensor. This reflects the fact that the sensor used is sensitive to the imposed electric field.

Types of Optical Transducers: The hybrid family of non-conventional instrument transducers can be divided in two types: those with active sensors and those with passive sensors. The idea behind a transducer with an active sensor is to change the existing output of the conventional instrument transformer into an optically isolated output by adding an optical conversion system (as shown in above figure). This conversion system may require a power supply of its own: this is the active sensor type. The use of an optical isolating system serves to de-couple the instrument transformer output secondary voltages and currents from earthed or galvanic links. Thus the only ak_aee1_mrt2_ttps_REF_S8 _29.01.08_TM:57

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link that remains between the control-room and the switchyard is a fibre optic cable. Another type of hybrid non-conventional instrument transformer is achieved by retrofitting a passive optical sensing medium into a conventional ‘hard-wire secondary’ instrument transformer. This can be termed as a passive hybrid type since no power supply of any kind is needed at the secondary level.

“All Optical” Transducers (Optical Sensors): These instrument transformers are based entirely on optical materials and are fully passive. The sensing function is achieved directly by the sensing material and a simple fibre optic cable running between the base of the unit and the sensor location provides the communication link. The sensing element is made of an optical material that is positioned in the electric or magnetic field to be sensed.

In the case of a current measuring device the sensitive element is either located free in the magnetic field (Figure(a)) or it can be immersed in a field-shaping magnetic ‘gap’ (Figure (b)). In the case of a voltage-sensing device the same alternatives exist, this time for elements that are sensitive to electric fields. The possibility exists of combining both sensors within a single housing, thus providing both a CT and VT within a single compact housing that gives rise to space savings with in a substation

Current sensors

Voltage sensors

In all cases there is an optical fibre that channels the probing reference light from a source into the medium and another fibre that channels the light back to analysing circuitry.

In sharp contrast with a conventional freestanding instrument transformer, the optical instrument transformer needs an electronic interface module in order to function.

Therefore its sensing principle (the optical material) is passive but its operational integrity relies on the interface that is powered in the control room.

Similar to conventional instrument transformers there are ‘live tank’ and ‘dead tank’ optical transducers. Typically, current transducers take the shape of a closed loop of light-transparent material, fitted around a

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Novel instrument transducer concept requiring an electronic interface in the control room

straight conductor carrying the line current.

In this case a bulk-glass sensor unit is depicted, along with an ‘all-optical’ sensor.

Light detectors are basically very sensitive devices and the sensing material can thus be selected in such a way as to scale-up readily for larger currents. ‘All-optical’ voltage transducers however do not lend themselves easily for extremely high line voltages.

Conceptual design of a double-sensor optical CT

Zero Flux (Hall Effect) Current Transformers: In this case the sensing element is a semi-conducting wafer that is placed in the gap of a magnetic concentrating ring. This type of transformer is also sensitive to d.c. currents. The transformer requires a power supply that is fed from the line or from a separate power supply. The sensing current is typically 0.1% of the current to be measured. In its simplest shape, the Hall effect voltage is directly proportional to the magnetizing current to be measured. For more accurate and more sensitive applications, the sensing current is fed through a secondary, multiple-turn winding, placed around the magnetic ring in order to balance out the gap magnetic field. This zero-flux or null-flux version allows very accurate current measurements in both d.c. and high frequency applications.

Hybrid Magnetic Optical Sensors:

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This type of transformer is mostly used in applications such as series capacitive compensation of long transmission lines, where a non-grounded measurement of current is required.

In this case, several current sensors are required on each phase in order to achieve capacitor surge protection and balance. The preferred solution is to use small toroidally wound magnetic core transformers connected to fibre optic isolating systems. These sensors are usually active sensors in the sense that the isolated systems require a power supply.

Rogowski Coil sensor: The Rogowski coil is based on the principle of an aircored current transformer with a very high load impedance. The secondary winding is wound on a toroid of insulation material. In most cases the Rogowski coil will be connected to an amplifier, in order to deliver sufficient power to the connected measuring or protection equipment and to match the input impedance of this equipment. The Rogowski coil requires integration of the magnetic field and therefore has a time and phase delay whilst the integration is completed.

This can be corrected for within a digital protection relay.

3. Useful Tips on â&#x20AC;&#x153;Current Transformerâ&#x20AC;? a) The bushing type CT is almost invariably chosen for relaying in the higher voltage circuits because it is less expensive than other types. b) A bushing type CT is more accurate than other CTs at high multiples of the primary current because of its less saturation in a core of greater cross section. At low currents, a bushing CT is generally less accurate because of its larger exciting current. c) At high saturation, the impedance of the CT approaches DC resistance. d) Large currents flowing in a conductor close to a current transformer may greatly affect its accuracy.

A designer of compact equipment, such as metal-enclosed switchgear, should guard against this effect. e) Unused cores shall be shorted. But unused portion of a core shall never be shorted f) All the CT secondary circuits shall be earthed only one point, preferably nearer to CT end. g) If some of the turns in the secondary are shorted, the magnetization characteristic will be much lower than normal. This defect is detected by comparing the characteristic just obtained with the one plotted at an earlier date or with that of an identical CT. Deviation from normal in the case of shorted turns is most noticeable in the magnetization characteristics over the initial range of magnetization. h) The phase angle error for the protection CTs is not normally measured as the burden is normally at high lagging pf and hence in phase with exciting current. i) The CT secondary winding is earthed to protect the secondary equipments during break down between primary and secondary winding of CT & and to discharge electrostatic charges at secondary winding j) Typical Name plate of a Current Transformer

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References: 1. The Art and Science of Protective Relaying by C. Russell Mason, 2. GEC measurements 2. Protective Relaying Theory and Application by Walter A. Elmore, 3. IS: 2705 part 1 â&#x20AC;&#x201C; IV 4. Manual on Pre-commissioning & Periodical testing of electrical installation Er. K. Mounagurusamy, Rtd. CE/P&C/TNEB

Total No. of Participants: 34

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