**4. Setting zones for MHO distance relays**

### **4.1. Principal**

Distance protection is so called because it is based on an electrical measure of distance along a transmission line to a fault. The distance along the transmission line is directly proportional to the series electrical impedance of the transmission line.

Impact of Series FACTS Devices (GCSC, TCSC and TCSR) on Distance Protection Setting Zones in 400 kV Transmission Line 47

Under reach is also caused by intermediate current sources, errors in CT, and VT and measurement performed by the relay. To take into account the under reaching tendency caused by these factors, the normal practice is to set the second zone reach up to 20% of the shortest adjoining line section. The protective zone of the second unit is known as the second zone of protection. The second zone unit operates after a certain time delay. Its

It is provided for back-up protection of the adjoining line. Its reach should extend beyond the end of the adjoining line under the maximum under reach, which may be caused by arcs, intermediate current sources and errors in CT, VT and measuring unit (Zellagui. M.; Chaghi. A., 2012.b). The protective zone of the third stage is known as the third zone of

The characteristic curve on MHO (admittance) relay for setting zones is shown in figure 6.

**Figure 6.** Characteristic curve *X* (*R*) for setting zones for distance protection.

Figure 7 represents the tripping time *T1*, *T2* and *T3* correspond to these three zones of

The fourth setting zones for protected transmission line (forward and reverse) without

11 1 80% 0,8.( ) *Z R jX Z R jX AB AB AB* (11)

operation for circuit breaker installed at busbar *A* and MHO distance relay (*RA*).

series FACTS are given by (Zellagui, M.; Chaghi, A. 2012.c), (Gérin-Lajoie, L. 2009):

operating time is 0,3 sec.

*4.2.3. Third zone* 

protection.

Impedance is defined as the ratio of voltage to current. Therefore, distance protection measures distance to a fault by means of a measured voltage to measured current ratio computation (Zigler, G., 2008), (Zellagui, M.; Chaghi, A., 2012.b). The philosophy of setting relay at Sonelgaz Group is three forward zones and one reverse zone to protect EHV transmission line between busbar *A* and *B* with total impedance *ZAB* as shown in figure 5.

**Figure 5.** Principal operation of distance relay

#### **4.2. Setting zones**

#### *4.2.1. First zone*

In practice it is normal to adjust the first zone relays (*Z1*) at A to protect only up to 80% of the protective line AB. This is a high speed unit and is used for the primary protection of the protected line. Its operation is instantaneous (Dechphung, S.; Saengsuwan, T., 2008).

This unit is not set to protect the entire line to avoid undesired tripping due to over reach. Over reach may occur due to transients during the fault condition.

#### *4.2.2. Second zone*

It is set to cover about 20% of the second line (BC). The main object of the second zone unit is to provide protection to the end zone of the first section which is beyond the reach of the first unit. The setting of the second unit is so adjusted that it operates the relay even for arcing faults at the end of the line. To achieve this, the unit must take care beyond the end of the line. In other words its setting must take care of under reach caused by arc resistance (Dechphung, S; Saengsuwan, T., 2008), (Zellagui, M.; Chaghi, A., 2012.b).

Under reach is also caused by intermediate current sources, errors in CT, and VT and measurement performed by the relay. To take into account the under reaching tendency caused by these factors, the normal practice is to set the second zone reach up to 20% of the shortest adjoining line section. The protective zone of the second unit is known as the second zone of protection. The second zone unit operates after a certain time delay. Its operating time is 0,3 sec.

#### *4.2.3. Third zone*

46 An Update on Power Quality

**4.1. Principal** 

**4. Setting zones for MHO distance relays** 

**Figure 5.** Principal operation of distance relay

**4.2. Setting zones** 

*4.2.1. First zone* 

*4.2.2. Second zone* 

Distance protection is so called because it is based on an electrical measure of distance along a transmission line to a fault. The distance along the transmission line is directly

Impedance is defined as the ratio of voltage to current. Therefore, distance protection measures distance to a fault by means of a measured voltage to measured current ratio computation (Zigler, G., 2008), (Zellagui, M.; Chaghi, A., 2012.b). The philosophy of setting relay at Sonelgaz Group is three forward zones and one reverse zone to protect EHV transmission line between busbar *A* and *B* with total impedance *ZAB* as shown in figure 5.

In practice it is normal to adjust the first zone relays (*Z1*) at A to protect only up to 80% of the protective line AB. This is a high speed unit and is used for the primary protection of the

This unit is not set to protect the entire line to avoid undesired tripping due to over reach.

It is set to cover about 20% of the second line (BC). The main object of the second zone unit is to provide protection to the end zone of the first section which is beyond the reach of the first unit. The setting of the second unit is so adjusted that it operates the relay even for arcing faults at the end of the line. To achieve this, the unit must take care beyond the end of the line. In other words its setting must take care of under reach caused by arc resistance

protected line. Its operation is instantaneous (Dechphung, S.; Saengsuwan, T., 2008).

Over reach may occur due to transients during the fault condition.

(Dechphung, S; Saengsuwan, T., 2008), (Zellagui, M.; Chaghi, A., 2012.b).

proportional to the series electrical impedance of the transmission line.

It is provided for back-up protection of the adjoining line. Its reach should extend beyond the end of the adjoining line under the maximum under reach, which may be caused by arcs, intermediate current sources and errors in CT, VT and measuring unit (Zellagui. M.; Chaghi. A., 2012.b). The protective zone of the third stage is known as the third zone of protection.

The characteristic curve on MHO (admittance) relay for setting zones is shown in figure 6.

**Figure 6.** Characteristic curve *X* (*R*) for setting zones for distance protection.

Figure 7 represents the tripping time *T1*, *T2* and *T3* correspond to these three zones of operation for circuit breaker installed at busbar *A* and MHO distance relay (*RA*).

The fourth setting zones for protected transmission line (forward and reverse) without series FACTS are given by (Zellagui, M.; Chaghi, A. 2012.c), (Gérin-Lajoie, L. 2009):

$$Z\_1 = R\_1 + jX\_1 = 80\% \\ Z\_{AB} = 0, 8. (R\_{AB} + jX\_{AB}) \tag{11}$$

$$\mathbf{Z}\_2 = \mathbf{R}\_2 + j\mathbf{X}\_2 = \mathbf{R}\_{AB} + j\mathbf{X}\_{AB} + \mathbf{0}, \mathbf{Z}(\mathbf{R}\_{BC} + j\mathbf{X}\_{BC}) \tag{12}$$

Impact of Series FACTS Devices (GCSC, TCSC and TCSR) on Distance Protection Setting Zones in 400 kV Transmission Line 49

(16)

In addition fault resistance may create problem for distance measurement because of the fault resistance may be difficult for predict. It is particularly challenging for distance relays to measure correct fault impedance when the current in feed from the other end of the line create an unknown voltage drop on the fault resistance (Kazemi, A. et al., 2009), (Kulkami,

This may contribute to erroneous computation of the impedance, called apparent impedance 'seen' by the relay located at the end of the line and using the current and voltage measurement just from the end. Once the impedance is computed, it is compared to the settings that define the operating characteristics of the relay. Based on the comparison, a

The principle behind the standard distance protection function is based on measured apparent impedance (*Zseen*) at the transmission line terminals. The apparent impedance is computed from fundamental power frequency components of measured instantaneous voltage and current signals (Liu, Q.; Wang, Z., 2008), (Khederzadeh, M.; Sidhu, T. S., 2006),

> . *seen seen <sup>Z</sup> seen <sup>V</sup> Z K <sup>I</sup>*

The power system studied in this paper is the 400 kV, 50 Hz eastern Algerian electrical transmission networks at group SONELGAZ (Algerian Company of Electricity and Gas) which is shows in figure 8 (Sonelgaz Group/GRTE, 2011). The MHO distance relay is located in the bus bar at Ramdane Djamel substation in Skikda to protect transmission line between busbar *A* and busbar *B* at Oued El Athmania substation in Mila, the bus bar *C* at Salah Bay

The figure below represents a 400 kV transmission line in the presence of a series FACTS type GCSC, TCSC and TCSR installed in the midpoint of the transmission line protected by

Figure 9 shows the characteristic curves of the different compensators used GCSC, TCSC

The impact of the angle variation *γ* and injected reactance *XGCSC* by compensator GCSC on reactance and resistance of the total impedance for transmission line (*XAB* and *RAB*) and on the parameters of measured impedance by MHO distance relay (*XRelay* and *RRelay*) in the

decision is made if a fault has occurred, if so in what zone.

(Jamali, S.; Shateri, H. 2011), the apparent impedance is given by:

**5. Case study and simulation results** 

a MHO distance relay between busbar A and B.

**5.1. Characteristic curve of installed series FACTS devices** 

**5.2. Impact on the impedance of a protected transmission line.** 

and TCSR installed on transmission line in this case study.

inductive and capacitive mode is summarized in table 1.

P.A. et al., 2010).

substation in Sétif.

$$Z\_3 = R\_3 + jX\_3 = R\_{AB} + jX\_{AB} + 0.4.(R\_{BC} + jX\_{BC}) \tag{13}$$

$$\mathbf{Z}\_4 = \mathbf{R}\_4 + \mathbf{j}\mathbf{X}\_4 = -\mathbf{60}\%\\\mathbf{Z}\_{AB} = -\mathbf{0}, \mathbf{6}, (\mathbf{R}\_{AB} + \mathbf{j}\mathbf{X}\_{AB})\tag{14}$$

The total impedance of transmission line AB measured by MHO distance relay is:

$$\mathbf{Z}\_{\rm AB} = \mathbf{K}\_{\rm Z} \mathbf{Z}\_{\rm L} \quad \quad \mathbf{K}\_{\rm Z} = \bigvee \mathbf{K}\_{\rm VT} \tag{15}$$

Where, ZAB is real total impedance of line AB, and KVT and KCT is ratio of voltage to current respectively.

The presence of series FACTS systems in a reactor (*XFACTS*) has a direct influence on the total impedance of the protected line (*ZAB*), especially on the reactance XAB and no influence on the resistance RAB.

**Figure 7.** Selectivity of distance relay

#### **4.3. Measured impedance by relay in presence fault**

Distance relaying belongs to the principle of ratio comparison. The ratio is between voltage and current, which in turn produces impedance. The impedance is proportional to the distance in transmission lines, hence the distance relaying designation for the principle.

This principle is primarily used for protection of high voltage transmission lines. In this case the over current principle cannot easily cope with the change in the direction of the current flow, which is common in the transmission but no so common in radial distribution lines. Computing the impedance in the three-phase system is a bit involved in each type of the fault produces a different impedance expression. Because of these differences the settings of the distance relay are needed to be selected to distinguish between the ground and phase faults.

In addition fault resistance may create problem for distance measurement because of the fault resistance may be difficult for predict. It is particularly challenging for distance relays to measure correct fault impedance when the current in feed from the other end of the line create an unknown voltage drop on the fault resistance (Kazemi, A. et al., 2009), (Kulkami, P.A. et al., 2010).

This may contribute to erroneous computation of the impedance, called apparent impedance 'seen' by the relay located at the end of the line and using the current and voltage measurement just from the end. Once the impedance is computed, it is compared to the settings that define the operating characteristics of the relay. Based on the comparison, a decision is made if a fault has occurred, if so in what zone.

The principle behind the standard distance protection function is based on measured apparent impedance (*Zseen*) at the transmission line terminals. The apparent impedance is computed from fundamental power frequency components of measured instantaneous voltage and current signals (Liu, Q.; Wang, Z., 2008), (Khederzadeh, M.; Sidhu, T. S., 2006), (Jamali, S.; Shateri, H. 2011), the apparent impedance is given by:

$$Z\_{\text{seen}} = \left(\underset{\text{\text{\textquotedblleft}even}}{\text{\textquotedblleft}I\_{\text{seen}}}\right) K\_Z \tag{16}$$

### **5. Case study and simulation results**

48 An Update on Power Quality

current respectively.

the resistance RAB.

**Figure 7.** Selectivity of distance relay

faults.

**4.3. Measured impedance by relay in presence fault** 

22 2 0,2.( ) *Z R jX R jX R jX AB AB BC BC* (12)

*CT <sup>K</sup> Z KZ K <sup>K</sup>* (15)

33 3 0,4.( ) *Z R jX R jX R jX AB AB BC BC* (13)

44 4 60% 0,6.( ) *Z R jX Z R jX AB AB AB* (14)

. , *VT*

Where, ZAB is real total impedance of line AB, and KVT and KCT is ratio of voltage to

The presence of series FACTS systems in a reactor (*XFACTS*) has a direct influence on the total impedance of the protected line (*ZAB*), especially on the reactance XAB and no influence on

Distance relaying belongs to the principle of ratio comparison. The ratio is between voltage and current, which in turn produces impedance. The impedance is proportional to the distance in transmission lines, hence the distance relaying designation for the principle.

This principle is primarily used for protection of high voltage transmission lines. In this case the over current principle cannot easily cope with the change in the direction of the current flow, which is common in the transmission but no so common in radial distribution lines. Computing the impedance in the three-phase system is a bit involved in each type of the fault produces a different impedance expression. Because of these differences the settings of the distance relay are needed to be selected to distinguish between the ground and phase

The total impedance of transmission line AB measured by MHO distance relay is:

*AB Z L Z*

The power system studied in this paper is the 400 kV, 50 Hz eastern Algerian electrical transmission networks at group SONELGAZ (Algerian Company of Electricity and Gas) which is shows in figure 8 (Sonelgaz Group/GRTE, 2011). The MHO distance relay is located in the bus bar at Ramdane Djamel substation in Skikda to protect transmission line between busbar *A* and busbar *B* at Oued El Athmania substation in Mila, the bus bar *C* at Salah Bay substation in Sétif.

The figure below represents a 400 kV transmission line in the presence of a series FACTS type GCSC, TCSC and TCSR installed in the midpoint of the transmission line protected by a MHO distance relay between busbar A and B.

#### **5.1. Characteristic curve of installed series FACTS devices**

Figure 9 shows the characteristic curves of the different compensators used GCSC, TCSC and TCSR installed on transmission line in this case study.

#### **5.2. Impact on the impedance of a protected transmission line.**

The impact of the angle variation *γ* and injected reactance *XGCSC* by compensator GCSC on reactance and resistance of the total impedance for transmission line (*XAB* and *RAB*) and on the parameters of measured impedance by MHO distance relay (*XRelay* and *RRelay*) in the inductive and capacitive mode is summarized in table 1.

Impact of Series FACTS Devices (GCSC, TCSC and TCSR) on Distance Protection Setting Zones in 400 kV Transmission Line 51

**Figure 9.** Characteristic curve for series FACTS devices installed

**Figure 8.** Electrical networks 400 kV study in Algeria

**Figure 9.** Characteristic curve for series FACTS devices installed

**Figure 8.** Electrical networks 400 kV study in Algeria


Impact of Series FACTS Devices (GCSC, TCSC and TCSR) on Distance Protection Setting Zones in 400 kV Transmission Line 53

Figures 10 and 11 show the impact of the variation extinction angle *γ* and reactance *XGCSC* on the value of setting zones reactance and setting zones resistance respectively in presence of

**5.3. Impact on setting zones** 

*5.3.1. Impact of GCSC Insertion* 

**Figure 10.** Impact of insertion GCSC on reactance of setting zones

GCSC on transmission line.

**Table 1.** Variation of reactance and resistance as a function of *γ* and *XGCSC*

The impact of the angle variation *α* and *XTCSC* injected reactance by compensator TCSC on reactance and resistance of the total impedance for transmission line (*XAB* and *RAB*) and on the parameters of measured impedance by MHO distance relay (*XRelay* and *RRelay*) in the inductive and capacitive mode is summarized in table 2.


**Table 2.** Variation of reactance and resistance on function *α* and *XTCSC*

The impact of the angle variation *α* and injected reactance *XTCSR* by compensator TCSR on reactance and resistance of the total impedance for transmission line (*XAB* and *RAB*) and on the parameters of measured impedance by MHO distance relay (*XRelay* and *RRelay*)in the inductive and capacitive mode is summarized in table 3.


**Table 3.** Variation of reactance and resistance on function *α* and *XTCSR*

#### **5.3. Impact on setting zones**

52 An Update on Power Quality

**Mode Inductive Capacitive**

**Table 1.** Variation of reactance and resistance as a function of *γ* and *XGCSC*

inductive and capacitive mode is summarized in table 2.

**Mode Inductive Capacitive**

**Table 2.** Variation of reactance and resistance on function *α* and *XTCSC*

inductive and capacitive mode is summarized in table 3.

**Table 3.** Variation of reactance and resistance on function *α* and *XTCSR*

Mode **Inductive**

*γ* **(***°***) 0 20 40 80 100 120 140 180**  *XGCSC* **(***Ω***)** 32,000 18,3415 7,7466 0,0718 -0,0718 -1,8454 -7,7466 -32,000 *XAB* **(***Ω***)** 143,44 129,78 119,19 111,51 111,37 109,59 103,69 79,440 *RAB* **(***Ω***)** 11,526 11,526 11,526 11,526 11,526 11,526 11,526 11,526 *XRelay* **(***Ω***)** 7,1720 6,4891 5,9593 5,5756 5,5684 5,4797 5,1847 3,9720 *RRelay* **(***Ω***)** 0,5763 0,5763 0,5763 0,5763 0,5763 0,5763 0,5763 0,5763

The impact of the angle variation *α* and *XTCSC* injected reactance by compensator TCSC on reactance and resistance of the total impedance for transmission line (*XAB* and *RAB*) and on the parameters of measured impedance by MHO distance relay (*XRelay* and *RRelay*) in the

*α* **(***°***) 90 91 92 100 140 180**  *XTCSC* **(***Ω***)** 3,159.106 3,385.106 6,7825.106 -4828,0 -440.684 -106.670 *XAB* **(***Ω***)** 3,158 106 3,384.106 6,7826.106 -48177,0 -329,24 4,7697 *RAB* **(***Ω***)** 11,526 11,526 11,526 11,526 11,526 11,526 *XRelay* **(***Ω***)** 1,579.105 1,692.105 3,3913.105 -2408,9 -16.4622 0.2385 *RRelay* **(***Ω***)** 0,5763 0,5763 0,5763 0,5763 0,5763 0,5763

The impact of the angle variation *α* and injected reactance *XTCSR* by compensator TCSR on reactance and resistance of the total impedance for transmission line (*XAB* and *RAB*) and on the parameters of measured impedance by MHO distance relay (*XRelay* and *RRelay*)in the

*α* **(***°***) 90 100 110 120 130 140 160 180**  *XTCSR* **(***Ω***)** 32,000 32,021 32,170 32,563 33,308 34,506 38,645 45,714 *XAB* **(***Ω***)** 143,44 143,46 143,61 144,00 144,75 145,95 150,09 157,15 *RAB* **(***Ω***)** 11,526 11,526 11,526 11,526 11,526 11,526 11,526 11,526 *XRelay* **(***Ω***)** 7,1720 7,1731 7,1805 7.2002 7,2374 7,2973 7,5043 7,8577 *RRelay* **(***Ω***)** 0,5763 0,5763 0,5763 0,5763 0,5763 0,5763 0,5763 0,5763

#### *5.3.1. Impact of GCSC Insertion*

Figures 10 and 11 show the impact of the variation extinction angle *γ* and reactance *XGCSC* on the value of setting zones reactance and setting zones resistance respectively in presence of GCSC on transmission line.

**Figure 10.** Impact of insertion GCSC on reactance of setting zones

Impact of Series FACTS Devices (GCSC, TCSC and TCSR) on Distance Protection Setting Zones in 400 kV Transmission Line 55

**Figure 12.** Impact of insertion TCSC on reactance of setting zones

**Figure 11.** Impact of insertion GCSC on resistance of setting zones

#### *5.3.2. Impact of TCSC Insertion*

Figures 12 and 13 is show the impact of the variation extinction angle of *α* and reactance *XTCSC* on the value of setting zones reactance and setting zones resistance respectively in presence of a TCSC on transmission line.

**Figure 12.** Impact of insertion TCSC on reactance of setting zones

**Figure 11.** Impact of insertion GCSC on resistance of setting zones

Figures 12 and 13 is show the impact of the variation extinction angle of *α* and reactance *XTCSC* on the value of setting zones reactance and setting zones resistance respectively in

*5.3.2. Impact of TCSC Insertion* 

presence of a TCSC on transmission line.

Impact of Series FACTS Devices (GCSC, TCSC and TCSR) on Distance Protection Setting Zones in 400 kV Transmission Line 57

**Figure 14.** Impact of insertion TCSR on reactance of setting zones

**Figure 13.** Impact of insertion TCSC on resistance of setting zones

#### *5.3.3. Impact of TCSR Insertion*

Figures 14 and 15 is show the impact of the variation extinction angle *α* and reactance *XTCSR* on the value of setting zones reactance and setting zones resistance respectively in presence of TCSC on transmission line.

**Figure 14.** Impact of insertion TCSR on reactance of setting zones

**Figure 13.** Impact of insertion TCSC on resistance of setting zones

Figures 14 and 15 is show the impact of the variation extinction angle *α* and reactance *XTCSR* on the value of setting zones reactance and setting zones resistance respectively in presence

*5.3.3. Impact of TCSR Insertion* 

of TCSC on transmission line.

Impact of Series FACTS Devices (GCSC, TCSC and TCSR) on Distance Protection Setting Zones in 400 kV Transmission Line 59

Therefore settings zones of the total system protection must be adjusted in order to avoid

Acha, E.; Fuerte-Esquivel, C.R.; Ambriz-Pérez, H.; & Angeles-Camacho, C., (2004). *FACTS Modelling and Simulation in Power Networks*, John Wiley & Sons Ltd Publication, ISBN:

Blackburn, J.L.; Domin, T.J. (2006). *Protective Relaying: Principles and Applications*, 3rd Edition,

De Jesus F. D.; De Souza L. F. W.; Wantanabe E.; Alves J. E. R. (2007). SSR and Power Oscillation Damping using Gate-Controlled Series Capacitors (GCSC), *IEEE Transaction* 

De Souza, L. F. W.; Wantanabe, E. H.; Alves, J. E. R. (2008). Thyristor and Gate-Controlled Series Capacitors: A Comparison of Component Ratings, *IEEE Transaction on Power* 

Dechphung, S.; Saengsuwan, T. (2008). Adaptive Characteristic of MHO Distance Relay for Compensation of the Phase to Phase Fault Resistance, *IEEE International Conference on Sustainable Energy Technologies (ICSET' 2008),* Singapore, Thailand, 24-27 November

Gérin-Lajoie, L. (2009), A MHO Distance Relay Device in EMTP Works, *Electric Power* 

Horowitz, S.H.; Phadke A.G. (2008). *Power System Relaying*, 3rd Edition, Published by John

Jamali, S.; Shateri, H. (2011). Impedance based Fault Location Method for Single Phase to Earth Faults in Transmission Systems, *10th IET International Conference on Developments* 

Khederzadeh, M.; Sidhu, T. S. (2006). Impact of TCSC on the Protection of Transmission Lines, *IEEE Transactions on Power Delivery*, Vol. 21, No. 1, (January 2006), pp. 80-87. Kulkami, P. A.; Holmukhe, R. M.; Deshpande, K. D.; Chaudhari, P. S. (2010). Impact of TCSC on Protection of Transmission Line, *International Conference on Energy Optimization* 

*in Power System Protection (DPSP)*, United Kingdom, 29 March - 1 April, 2010. Kazemi, A.; Jamali, S.; Shateri, H. (2009). Measured Impedance by Distance Relay with Positive Sequence Voltage Memory in Presence of TCSC, *IEEE/PES Power Systems* 

*Conference and Exposition (PSCE' 09)*, Seattle, USA, 15-18 March 2009.

*and Control (ICEOC' 10)*, Maharashtra, India, 28-30 December 2010.

unwanted circuit breaker tripping in the presence of series FACTS compensator.

*LSP-IE Research Laboratory, Department of Electrical Engineering, Faculty of Technology,* 

**Author details** 

**7. References** 

2008.

*University of Batna, Algeria* 

Mohamed Zellagui and Abdelaziz Chaghi

978-0470852712, London, England.

Published by CRC Press, ISBN: 978-1574447163, USA.

*Delivery*, Vol. 23, No.2, (May 2008), pp. 899-906.

*Systems Research*, 79(3), March 2009, pp. 484-49.

Wiley & Sons Ltd, ISBN: 978-0470057124, England, UK.

*on Power Delivery*, Vol. 22, N°3, (Mars 2007), pp. 1806-1812.

**Figure 15.** Impact of insertion TCSR on resistance of setting zones

#### **6. Conclusions**

The results are presented in relation to a typical 400 kV transmission system employing GCSC, TCSC and TCSR series FACTS devices. The effects of the extinction angle *γ* for controlled GTO installed on GCSC as well as extinction angle *α* for controlled thyristors on TCSC and TCSR are investigated. These devices are connected at the midpoint of a transmission line protected by distance relay. However as demonstrated these angles injected variable reactance (*XGCSC*, *XTCSC* or *XTCSR*) in the protected line which lead to direct impact on the total impedance of the protected line and setting zones.

Therefore settings zones of the total system protection must be adjusted in order to avoid unwanted circuit breaker tripping in the presence of series FACTS compensator.

## **Author details**

58 An Update on Power Quality

**Figure 15.** Impact of insertion TCSR on resistance of setting zones

impact on the total impedance of the protected line and setting zones.

The results are presented in relation to a typical 400 kV transmission system employing GCSC, TCSC and TCSR series FACTS devices. The effects of the extinction angle *γ* for controlled GTO installed on GCSC as well as extinction angle *α* for controlled thyristors on TCSC and TCSR are investigated. These devices are connected at the midpoint of a transmission line protected by distance relay. However as demonstrated these angles injected variable reactance (*XGCSC*, *XTCSC* or *XTCSR*) in the protected line which lead to direct

**6. Conclusions** 

Mohamed Zellagui and Abdelaziz Chaghi *LSP-IE Research Laboratory, Department of Electrical Engineering, Faculty of Technology, University of Batna, Algeria* 

#### **7. References**


Liu, Q.; Wang, Z. (2008). Research on the Influence of TCSC to EHV Transmission Line Protection, *International Conference on Deregulation and Restructuring and Power Technology (DRPT' 08)*, Nanjing, China, 6-9 April 2008.

**Chapter 4** 

© 2013 Leung and Lu, licensee InTech. This is an open access chapter distributed under the terms of the Creative Commons Attribution License (http://creativecommons.org/licenses/by/3.0), which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited.

© 2013 The Author(s). Licensee InTech. This chapter is distributed under the terms of the Creative Commons Attribution License http://creativecommons.org/licenses/by/3.0), which permits unrestricted use, distribution,

**A PSO Approach in Optimal FACTS Selection** 

Static Var Compensator (SVC) has been commonly used to provide reactive power compensation in distribution systems [1]. The SVC placement problem is a well-researched topic. Earlier approaches differ in problem formulation and the solution methods. In some approaches, the objective function is considered as an unconstrained maximization of savings due to energy loss reduction and peak power loss reduction against the SVC cost. Others formulated the problem with some variations of the above objective function. Some have also formulated the problem as constrained optimization and included voltage

In today's power system, there is trend to use nonlinear loads such as energy-efficient fluorescent lamps and solid-state devices. The SVCs sizing and allocation [2-4] should be properly considered, if else they can amplify harmonic currents and voltages due to possible resonance at one or several harmonic frequencies and switching actions of the power electronics converters connected. This condition could lead to potentially dangerous magnitudes of harmonic signals, additional stress on equipment insulation, increased SVC

SVC values are often assumed as continuous variables whose costs are considered as proportional to SVC size in past researches. Moreover, the cost of SVC is not linearly proportional to the size (MVAr). Hence, if the continuous variable approach is used to choose integral SVC size, the method may not result in an optimum solution and may even

Current harmonics are inevitable during the operation of thyristor controlled rectifiers, thus it is essential to have filters in a SVC system to eliminate the harmonics. The filter banks can not only absorb the risk harmonics, but also produce the capacitive reactive power. The SVC

and reproduction in any medium, provided the original work is properly cited.

**with Harmonic Distortion Considerations** 

H.C. Leung and Dylan D.C. Lu

http://dx.doi.org/10.5772/54555

constraints into consideration.

**1. Introduction** 

Additional information is available at the end of the chapter

failure and interference with communication system.

lead to undesirable harmonic resonance conditions.

