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A novel adaptive current protection scheme for distribution systems with distributed generation
Electrical Power and Energy Systems 43 (2012) 1460–1466
Contents lists available at SciVerse ScienceDirect
Electrical Power and Energy Systems journal homepage: www.elsevier.com/locate/ijepes
A novel adaptive current protection scheme for distribution systems with distributed generation Jing Ma a,⇑, Xi Wang a, Yagang Zhang a, Qixun Yang a, A.G. Phadke b a b
State Key Laboratory of Alternate Electrical Power System with Renewable Energy Sources, North China Electric Power University, Beijing 102206, China Virginia Polytechnique Institute and State University, Blacksburg, USA
a r t i c l e
i n f o
Article history: Received 20 November 2011 Received in revised form 23 June 2012 Accepted 5 July 2012 Available online 9 August 2012 Keywords: Fault component Adaptive current protection Distributed generation Equivalent reduction
a b s t r a c t An adaptive current protection scheme is proposed for the protection of power systems with penetration of distributed generation (DG). In this scheme, steady state fault current of the related power transmission lines is derived from steady state network equivalent reduction. Then, settings criteria for adaptive primary and backup protection are established on the basis of the steady state fault current. The simulated results of a realistic power network verify the ranges of adaptive primary and backup protection are immune to implementation of DG and the fault types. Furthermore, compared with traditional current protection schemes, the proposed method has extended the primary and backup protection regions considerably. Ó 2012 Elsevier Ltd. All rights reserved.
1. Introduction Protective devices play a critical role in power systems by minimizing equipment damage and maintaining system stability. In traditional protection schemes, the settings principle of these protective devices is quite simple. Protective settings are determined at maximal modes of system operating conditions and severity is checked out at the minimal modes of system operating conditions. However, the settings principle is defective unless the following drawbacks are taken into consideration: (a) the protection settings are not optimal for other system operating conditions including the prevailing operating condition, and (b) protection coverage is shorter for certain fault types; especially phase-to-phase fault. To fulfill the requirement of absolute selectivity, high sensitivity and adequate severity, adaptive protection concepts were introduced in 1980s [1]. These concepts require that the protective settings should be automatically adjusted to make the protective relays more attuned to prevailing system conditions. Researchers all over the world have been devoted to putting these concepts into practice. Several methods have been proposed in the realm of adaptive protection, such as adaptive distance protection [2–5], adaptive current differential protection [6,7] and adaptive power differential protection [8]. Recently, increasingly more distributed generators (DGs), both synchronous and asynchronous – depending on the energy source ⇑ Corresponding author. Address: No. 52 Mailbox, North China Electric Power University, No. 2 Beinong Road, Changping District, Beijing 102206, China. Tel.: +86 10 80794899, mobile: +86 15801659769. E-mail address: [email protected] (J. Ma). 0142-0615/$ - see front matter Ó 2012 Elsevier Ltd. All rights reserved. http://dx.doi.org/10.1016/j.ijepes.2012.07.024
used, are being connected to the grid. The implementation of DG can create difficulties for the existing power system protection schemes and cause protection devices to operate incorrectly [9–12]. It is feasible for adaptive protection scheme to solve the problems that DG brings to the protection system. This paper continues as follows: first, the impact of DG on traditional protection is analyzed. Next, a novel adaptive non-pilot current protection scheme utilizing steady state fault current is presented. Finally, settings criteria for primary and backup adaptive protection are established. The experimental tests for a realistic power system in Tianjin province in China verify the regions of primary and backup protection are immune to the implementation of DG and types of faults. Furthermore, compared with traditional current protection, the proposed scheme extends the primary and backup protection regions considerably.
2. Impact of DG on traditional current protection Fig. 1 shows a traditional industrial distribution network. Load E is fed through source G and protected by R1, R2, and R3, which are overcurrent relays. Each protective relays is assigned a primary function to clear faults in a specific zone and a backup function to clear faults in downstream zones to the extent that the range of the device permits. When two protective relays operate properly in this primary/backup mode for any system fault, they are said to be ‘‘well set’’. However, protecting systems with DG is not well contemplated in traditional protection philosophy. A network with DG is used as an example to illustrate the malfunction of traditional protection,
J. Ma et al. / Electrical Power and Energy Systems 43 (2012) 1460–1466
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Nomenclature A C U UM UT UC UE UB I IM IT IC IE IB J JT YN Y YEE YBB YJJ YEB YBE YBJ YJB
node correlation matrix branch contribution factor matrix pre-fault bus voltage vector faulted bus voltage vector fault transient state bus voltage vector calculated fault steady state bus voltage vector bus voltage vector of the external nodes bus voltage vector for the boundary nodes pre-fault line current vector faulted line current vector fault transient state line current vector calculated fault steady state line current vector injected current vector from the external buses injected current vector from the boundary buses bus injected current vector variation of injected current vector bus admittance matrix branch admittance matrix bus admittance matrix of external buses only bus admittance matrix of boundary buses only bus admittance matrix of bus J bus admittance matrixes between boundary buses and external buses bus admittance matrixes between boundary buses and bus J
ICk
K Irel
magnitude of calculated fault steady state current of the kth distribution line magnitude of steady state fault current of the mth distribution line magnitude of load current of the mth distribution line before the fault occurs magnitude of calculated fault steady state current of the mth distribution line magnitude of calculated fault steady state current of the kth distribution line magnitude of fault steady state current of the kth distribution line magnitude of load current of the kth distribution line before the fault occurs adaptive primary protection setting for the kth distribution line coefficient of reliability of the primary protection
K IIrel
coefficient of reliability of the backup protection
Kp Kd
threshold value coefficient of fault type
IIIset:k uj ij
adaptive backup protection setting voltage phasor of bus J injected current phasor from bus J
ISm ILk ICm ICk ISk ISL IIset:k
Fig. 1. A traditional industrial distribution network fed through source G and protected by R1, R2 and R3.
Fig. 2. An industrial power network fed through source G, distributed generator (DG), and protected by R1, R2 and R3.
shown in Fig. 2. When fault F1 occurs, the fault current measured by R2 has two components-one coming from source G and the other from DG. The fault current is a variable; dependent upon changing operating conditions of the DG. Nevertheless, the primary protection settings for R2 are determined in the system without DG. In this situation, the primary protection settings for R2 could potentially be smaller than the measured fault current. Consequently, the primary protection of R2 is prone to misoperation. From this example, it can be seen that the implementation and the operating conditions of DG can alter fault current levels enough to cause the misoperation of protective relays. Hence, the protective settings should be adaptive to the implementation and operating conditions of DG. Nowadays, distributed generation interconnection guides in many countries require the immediate disconnection of all the DGs in case of faults. However, some utilities allow DGs to ride
through faults. In the following sections, a novel adaptive current protection scheme is proposed to deal with these situations. The proposed scheme properly performs protective functions in industrial distribution systems comprising DG.
3. Adaptive current protection scheme In power system, generators and loads can be taken as current injection sources. Ignoring nonlinear elements such as power electronic devices, the power network can be taken as a linear network which meets the requirement of the superposition theorem [13]. Thus, the fault network can be taken into the composition of the pre-fault network, the fault transient state network and the fault steady state network. All the electrical variables referred below are phase components.
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In the pre-fault network, the bus voltage vector U and line current vector I are given by
(
U ¼ Y1 N J
ð1Þ
I ¼ YAT U
where YN is the bus admittance matrix, Y is the branch admittance matrix, A is the node correlation matrix, and J is the injected current vector. In the fault transient state network, the bus voltage vector UT and line current vector IT are given by:
(
UT ¼ Y1 N JT
ð2Þ
IT ¼ YAT UT
where JT is the post-fault variation of injected current vector. In the steady state network for the fault condition, the bus voltage vector UC and line current vector IC can be calculated as follows:
UC ¼ UM U UT IC ¼ IM I IT
ð3Þ
where IM is the faulted line current vector and, UM is the faulted bus voltage vector in the fault network. Consider a distribution power system containing N distribution lines, which are numbered as i = 1,2, . . . , N. In the following analysis, the kth distribution lines and the mth distribution lines are used as an example to illustrate the adaptive protection scheme as shown in Fig. 3. In the faulted steady state network, the buses which directly connect to the bus J are called boundary buses denoted as set B. The others are called external buses denoted as set E. The nodal equations of the power network in the form of a partitioned matrix can be written as
2
YEE
6 4 YBE 0
YEB YBB YJB
0
32
UE
3
2
IE
3
76 7 6 7 YBJ 54 UB 5 ¼ 4 IB 5 YJJ uj ij
ð4Þ
where UE is the bus voltage vector of the external nodes. UB is the bus voltage vector for the boundary nodes. uj is the voltage phasor of bus J. The current IE is an injected current vector from the external buses. IB is the injected current vector from the boundary buses. ij is the injected current phasor from bus J. YEE is the bus admittance matrix of external buses only. YBB is the bus admittance matrix of boundary buses only. YJJ is the bus admittance matrix of bus J. YEB and YBE are the bus admittance matrixes between boundary buses and external buses. YBJ and YJB are the bus admittance matrixes between boundary buses and bus J. In case of topological changes, the elements of inductance matrix in (4) are all modified accordingly, so that the proposed method could work properly. By eliminating UE, the nodal equations can be written as
"
YBB YBE Y1 EE YEB
YBJ
YJB
YJJ
#"
UB uj
#
"
¼
IB YBE Y1 EE IE ij
#
ð5Þ
When a fault occurs at bus J in the kth distribution line, there is only one source in the faulted steady state network, located at bus J. Therefore, each steady state fault current injection at the boundary buses and the external buses is 0, which means IE = 0 and IB = 0. Then, the nodal equations can be deduced as
"
YBB YBE Y1 EE Y EB
YBJ
YJB
YJJ
#
UB
uj
¼
0 ij
ð6Þ
Thus, the steady state injected fault current phasor from bus J, ij can be calculated as 1 ij ¼ ½YJJ YJB ðYBB YBE Y1 EE YEB Þ Y BJ uj
ð7Þ
The relationship of the injected current phasor ij and line current vector IS is
IS ¼ ½YAT ðAYAT Þ1 ij
ð8Þ
where Y is the branch admittance matrix. A is the node correlation matrix. C(k) = YAT(AYA)1 is defined as the branch contribution factor matrix (BCFM). From (7) and (8), the line current vector in the steady state fault network can be calculated as 1 IS ¼ kJ ½YJJ YJB ðYBB YBE Y1 EE YEB Þ Y BJ uj
ð9Þ
where kJ is the Jth column of the branch contribution factor matrix C(k). uj is voltage phasor of bus J in the steady state fault network. Thus, the adaptive primary protection setting for the kth distribution line can be formulated as
( IIset:k
¼
K Irel K d ISk ; if
ISk > ITh1
ITh1 ;
ISk 6 ITh1
if
ð10Þ
where IIset:k is the adaptive primary protection setting for the kth distribution line. ISk is the magnitude of fault steady state current of the kth distribution line. ITh1 is the threshold current of the primary protection, the value of which is calculated as ITh = KpILk. ISL is the magnitude of load current of the kth distribution line before the fault occurs. Kp is the threshold value, which is set as 0.1. K Irel is the coefficient of reliability of the primary protection, the value of which is set as 1.1, considering relative errors caused by non-fundamental components, transient harmonics, voltage fluctuation and some other factors. Kd is the coefficient of fault type and can be previously determined according to the different fault type information which can be provided by fault phase selector. Kd is 1 when pffiffi a three-phase fault occurs and Kd is 23 when a phase-to-phase fault occurs. The measured current in R1 denoted as iCk can be calculated by using (1)–(3). Only if the magnitude of measured current ICk surpasses the protection setting IIset:k , will the primary protection issue a signal to the switching device to trip the fault. Due to the substations away from large generation units, the initial high ‘‘subtransient component’’ does not exist in the fault
Fig. 3. The kth distribution line’s primary protection R1 and backup protection R2.
J. Ma et al. / Electrical Power and Energy Systems 43 (2012) 1460–1466
current transients. In this way, the primary relays based on the steady-state fault current can not operate instantaneously but still fast enough for the distribution power system protection. Furthermore, the adaptive backup protection setting IIIset:k can be formulated as
( IIIset:k ¼
K IIrel K d ISm ; if
ISm > ITh2
ITh2 ;
ISm 6 ITh2
if
ð11Þ
where ISm is the magnitude of steady state fault current of the mth distribution line. ITh2 is the threshold current of the backup protection, the value of which is calculated as ITh2 = KpILm. ILm is the magnitude of load current of the mth distribution line before the fault occurs. K IIrel is the coefficient of reliability of the backup protection, which must be above K Irel to fulfill the selectivity and is set as 1.2. The Eqs. (10) and (11) are programmed in the relays. And the settings are calculated by the relays rather than commanded by a control center. The measured current in R2 denoted as iCm can be calculated by using (1)–(3). Only if the magnitude of measured current ICm surpasses the backup protection setting IIIset:k , will the adaptive backup protection issue a signal to the switching device to clear the fault on the adjacent transmission line.
4. Experimental system To verify the performance of the proposed method, the experimental tests have been carried out at the Electrical Power Dynamic Laboratory (EPDL). In these tests, a total of 156 cases have been divided into three main categories: 50 cases for adaptive primary
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current protection, 50 cases for adaptive backup current protection, and 56 cases for the impact of DG to the adaptive protection. In these tests, a realistic 10 kV distributed network in power system of Tianjin province in China is established as shown in Fig. 4. The base capacity is 500MVA and the base voltage is 10.5 kV. Branches AB, BC and AF are all overhead lines. The resistance and reactance of these lines are r1 = 0.027 X/km and x1 = 0.347 X/km, respectively. Moreover, branches CD, DE and FG are all underground cables. The resistance and reactance of these cables are r1 = 0.259 X/km and x1 = 0.093 X/km, respectively. The nominal capacity and the nominal power factor of each load are 6MVA and 0.85, respectively. DG with P–Q control schemes are connected to bus C, the nominal capacity of which is 10MVA. The devices at both ends of line are capable of sensing the fault with different current directions. In the following analysis, protective relays R2 and R3 are used as an example to demonstrate the effectiveness and accuracy of the adaptive primary protection function and the adaptive backup protection function, respectively. When a fault occurs in the transmission line CD, the measured current Ipm3 in R3 can be calculated using (1)–(3) and the adaptive primary protection setting Ips3 of R3 can be obtained by using (4)–(10). In the same way, the measured current Ibm2 in R2 can be achieved using (1)–(3) and the backup protection setting Ibs2 of R2 can be calculated using (4)–(9) and (11). Figs. 5–8 show some examples of the experimental test results: characteristic curves of instantaneous overcurrent relay and time delay instantaneous overcurrent relay in definite time operation, and the resulting analysis. The measured data are presented in the Tables 1–4 to identify the effectiveness of the adaptive protection.
Fig. 4. Experimental system.
Fig. 5. The adaptive primary protection setting and the measured current in R3 when a three-phase fault occurs on Section CD close to bus D.
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Fig. 6. The adaptive primary protection setting and the measured current in R3 when a phase-to-phase fault occurs in the middle of Section CD.
Fig. 7. The adaptive backup protection setting and the measured current of R2 when a three-phase fault occurs on Section CD 2.1 km away from bus C.
Fig. 8. The adaptive backup protection setting and the measured current of R2 when a phase-to-phase fault occurs in the middle of Section CD.
5. Testing results and analysis 5.1. Responses of adaptive primary current protection system A total of 50 test cases were carried out in this situation. In one case, a three-phase fault was applied to Section CD close to bus D (outside the range of primary protection of R3) at 0.30 s. Fig. 5
shows that the measured current Ipm3 and setting of the primary protection Ips3 respond considerably after the fault occurs. In addition, Ipm3 is less than Ips3 the entire time – ensuring that the primary relay does not issue a trip signal. In another case, a phase-to-phase fault was applied in the middle of the transmission line CD (within the region of primary protection of R3) at 0.3 s. Fig. 6 shows that the measured current Ipm3
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J. Ma et al. / Electrical Power and Energy Systems 43 (2012) 1460–1466 Table 1 Measured currents and setting of adaptive primary current protection.
Table 4 The impact of DG to adaptive backup current protection during three-phase fault.
Fault away from bus C
Phase-to-phase fault
Three-phase fault
Measured currents (A)
0% 30% 50% 60% 70% 80% 90% 100%
1408.8 1290.3 1210.8 1172.1 1134.3 1097.8 1062.5 1028.6
1627.1 1490.3 1398.5 1353.7 1310.2 1267.8 1227.1 1188.0
Setting (A)
–
1131.7
1306.8
Fault away from bus C
DG’s capacity (MVA) 5.1
11.5
28.2
Measured currents (A)
0% 30% 50% 60% 70% 80% 90% 100%
1209.9 1108.2 1039.9 1006.7 974.3 942.9 912.6 883.4
1366.5 1251.5 1174.3 1136.7 1100.1 1064.6 1030.4 997.5
1686.7 1543.6 1449.5 1401.1 1354.7 1314.2 1272.0 1231.3
Setting (A) Protective region
– –
1060.0 145.91%
1196.9 145.96%
1477.5 145.94%
Table 2 Measured currents and setting of adaptive backup current protection. Fault away from bus C
Phase-to-phase fault
Three-phase fault
Measured currents (A)
0% 30% 50% 60% 70% 80% 90% 100%
1047.6 959.5 900.4 871.6 843.5 816.3 790.1 764.9
1209.9 1108.2 1039.9 1006.7 974.3 942.9 912.6 883.4
Setting (A)
–
918.0
1060.0
Table 3 The impact of DG to adaptive primary current protection during phase-to-phase fault. Fault away from bus C
DG’s capacity (MVA) 5.1
11.5
28.2
Measured currents (A)
0% 30% 50% 60% 70% 80% 90% 100%
1408.8 1290.3 1210.8 1172.1 1134.3 1097.8 1062.5 1028.6
1590.9 1456.9 1367.0 1323.3 1280.6 1239.3 1199.5 1161.2
1963.8 1798.4 1687.4 1633.4 1580.8 1529.8 1480.6 1433.3
Setting (A) Protective region
– –
1131.7 72.88%
1277.9 72.84%
1577.4 72.84%
in R3 is larger than the protection setting Ips3 after fault occurs, which causes the primary relay to clear the fault accurately. Table 1 shows the measured currents in R3 with different fault locations and fault types occurring in the line CD and the setting of primary protection in R3. In the case of three-phase faults, the region of adaptive primary protection is about 72.94% of the line CD. In the case of phase-tophase faults, the region of adaptive primary protection is about 72.84% of the line CD. It can be seen that the region of adaptive primary current protection is immune to the fault type. In comparison, the primary protection of traditional overcurrent protection greatly affected by the fault type reaches only about 20% into the line CD in the cases of a phase-to-phase faults. 5.2. Responses of adaptive backup current protection system To fulfill the reliability and sensitivity, the operation time of the backup protection R2 should be larger than that of the primary protection R3 at least by a time interval called the ‘‘coordination time interval DIIt ’’.
A total of 50 test cases were carried out for this situation. In one case, a three-phase fault occurs in transmission line CD, 2.1 km away from bus C (within the region of backup protection) at 0.3 s. Assuming that the primary protection in R3 refuses to operate, R2 must operate to provide adaptive backup protection. The characteristic curve of adaptive backup protection in this situation is shown in Fig. 7. It can be seen that, after the fault occurs, the measured current Ibm2 and the backup protection setting Ibs2 respond considerably. Further, the measured current in R2 is larger than the protection setting all the time to makes the backup relay trip the fault accurately. In another case, a phase-to-phase fault occurs in the middle of Section CD (outside the range of backup protection) at 0.3 s. Assuming that the primary protection in R3 refuses to operate, R2 must operate to provide adaptive backup protection. The characteristic curve of adaptive backup protection is shown in Fig. 8. It can be found that the measured current Ibm2 and the backup protection setting Ibs2 respond considerably after the fault occurs. But Ibm2 is less than Ibs2 the entire time ensuring that the backup protective relay does not issue a trip signal. Table 2 shows the measured currents in R2 with different fault locations and fault types and setting of the adaptive backup protection in R2. In the case of three-phase faults, the adaptive backup protection reaches about 45.91% into the adjacent line CD. In the case of phase-to-phase faults, the adaptive backup protection reaches about 45.84% into the line emanating from the remote bus. Hence, the region of adaptive backup protection is not affected by the fault type. Furthermore, the backup protection region has been extended considerably in comparison to the traditional overcurrent protection. Comparing with [14], the proposed current protection scheme could properly deal with not only the disconnection of DG but also the changing output of DG, and the settings of primary and backup relays are automatically adaptive to the system operation and fault type without detecting the faulted section and updating the relays trip characteristics.
5.3. Impact of DG to the adaptive current protection In the traditional current protection scheme, a branch coefficient is needed for calculating the backup protection setting. However, the adaptive backup protection scheme proposed here is immune to the branch coefficient by transforming DG into injected current source. The setting of adaptive primary protection is growing in step with the capacity of DG, but the protection region remains about 72.84%. Also, the coverage of the adaptive backup protection is a fixed value and immune to the capacities of DG. These have been verified by a total of 56 comprehensive cases with different fault
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J. Ma et al. / Electrical Power and Energy Systems 43 (2012) 1460–1466
locations, different fault types (balanced and unbalanced) and different capacities of DG. The data from these tests are presented in Tables 3 and 4. It could be seen from Tables 3 and 4 that although DGs may be intermittent power sources, the proposed adaptive current protection scheme can deal with the variations of the DGs’ output and the disconnection of DGs from power system comparing with current phase comparison schemes protection [15]. Also, the proposed protection scheme includes not only primary protection but also backup protection. Although, integration of DG lead to connection of power electronic devices that limit the fault current magnitude, in this paper, DGs are considered as injected currents which can be timely measured. Thus, the proposed algorithm is immune to the fault current limitation caused by power electronic devices in DG. 6. Conclusion This paper proposed an adaptive current protection scheme. The paper offers an acceptable and practical solution to protection for distribution power systems with DG penetration. In the proposed scheme, the regions of primary and backup protection are immune to the implementation of DG and the indicated fault types. Furthermore, compared with traditional current protection, the proposed scheme has extended the regions of primary and backup protection considerably. Acknowledgments This work was supported by The National Basic Research Program of China (973 Program) (2012CB215200); National Natural Science Foundation of China (50907021, 50837002); The ‘‘111’’ Project (B08013); The Chinese University Scientific Fund Project (11MG01, 09QX64); The Project Sponsored by the Scientific Research Foundation for the Returned Overseas Chinese Scholars,
State Education Ministry ([2011] No. 1139); Hebei Natural Science Foundation (E2012502034); Electric Power Youth Science and Technology Creativity Foundation of CSEE ([2012] No. 46). References [1] Horwitz SH, Phadke AG, Thorp JS. Adaptive transmission system relaying. IEEE Trans Power Deliv 1988;3(4):1436–45. [2] El-Arroudi K, Joos G, McGillis DT, Brearley R. Comprehensive transmission distance protection settings using an intelligent-based analysis of events and consequences. IEEE Trans Power Deliv 2005;20(3):1817–24. [3] Hu Y, Novosel D, Saha MM, Leitloff V. An adaptive scheme for parallel-line distance protection. IEEE Trans Power Deliv 2002;17(1):105–10. [4] Gilany M, Al-Kandari A, Madouh J. A new strategy for determining fault zones in distance relays. IEEE Trans Power Deliv 2008;23(4):1857–63. [5] Sidhu TS, Baltazar DS, Palomino RM, Sachdev MS. A new approach for calculating zone-2 setting of distance relays and its use in an adaptive protection system. IEEE Trans Power Deliv 2004;19(1):70–7. [6] Li HY, Southern EP, Crossley PA, Potts S, Pickering SDA, Caunce BRJ, et al. A new type of differential feeder protection relay using global positioning system for data synchronization. IEEE Trans Power Deliv 1997;12(3):1090–9. [7] Dambhare S, Soman SA, Chandorkar MC. Adaptive current differential protection schemes for transmission-line protection. IEEE Trans Power Deliv 2009;24(4):1832–41. [8] Abdel-Maksoud IT, Hatem AD, Eman SA. Performance of power differential relay with adaptive setting for line protection. IEEE Trans Power Deliv 2007;22(1):50–8. [9] Brahma SM, Girgis AA. Development of adaptive protection scheme for distribution systems with high penetration of distributed generation. IEEE Trans Power Deliv 2004;19(1):56–63. [10] Sortomme E, Venkata SS, Mitra J. Microgrid protection using communicationassisted digital relays. IEEE Trans Power Deliv 2010;25(4):2789–96. [11] Salman SK, Rida IM. Investigating the impact of embedded generation on relay settings of utilities’ electrical feeders. IEEE Trans Power Deliv 2001;16(2):246–51. [12] Hui W, Li KK, Wong KP. An adaptive multiagent approach to protection relay coordination with distributed generators in industrial power distribution system. IEEE Trans Ind Appl 2010;46(5):2118–24. [13] Terzija VV, Radojevic ZM. Numerical algorithm for adaptive autoreclosure and protection of medium-voltage overhead lines. IEEE Trans Power Deliv 2004;19(2):554–9. [14] Mahat P, Chen Z, Bak-Jensen B, Bak CL. A simple adaptive overcurrent protection of distribution systems with distributed generation. IEEE Trans Smart Grid 2011;2(3):428–37.
Contents lists available at SciVerse ScienceDirect
Electrical Power and Energy Systems journal homepage: www.elsevier.com/locate/ijepes
A novel adaptive current protection scheme for distribution systems with distributed generation Jing Ma a,⇑, Xi Wang a, Yagang Zhang a, Qixun Yang a, A.G. Phadke b a b
State Key Laboratory of Alternate Electrical Power System with Renewable Energy Sources, North China Electric Power University, Beijing 102206, China Virginia Polytechnique Institute and State University, Blacksburg, USA
a r t i c l e
i n f o
Article history: Received 20 November 2011 Received in revised form 23 June 2012 Accepted 5 July 2012 Available online 9 August 2012 Keywords: Fault component Adaptive current protection Distributed generation Equivalent reduction
a b s t r a c t An adaptive current protection scheme is proposed for the protection of power systems with penetration of distributed generation (DG). In this scheme, steady state fault current of the related power transmission lines is derived from steady state network equivalent reduction. Then, settings criteria for adaptive primary and backup protection are established on the basis of the steady state fault current. The simulated results of a realistic power network verify the ranges of adaptive primary and backup protection are immune to implementation of DG and the fault types. Furthermore, compared with traditional current protection schemes, the proposed method has extended the primary and backup protection regions considerably. Ó 2012 Elsevier Ltd. All rights reserved.
1. Introduction Protective devices play a critical role in power systems by minimizing equipment damage and maintaining system stability. In traditional protection schemes, the settings principle of these protective devices is quite simple. Protective settings are determined at maximal modes of system operating conditions and severity is checked out at the minimal modes of system operating conditions. However, the settings principle is defective unless the following drawbacks are taken into consideration: (a) the protection settings are not optimal for other system operating conditions including the prevailing operating condition, and (b) protection coverage is shorter for certain fault types; especially phase-to-phase fault. To fulfill the requirement of absolute selectivity, high sensitivity and adequate severity, adaptive protection concepts were introduced in 1980s [1]. These concepts require that the protective settings should be automatically adjusted to make the protective relays more attuned to prevailing system conditions. Researchers all over the world have been devoted to putting these concepts into practice. Several methods have been proposed in the realm of adaptive protection, such as adaptive distance protection [2–5], adaptive current differential protection [6,7] and adaptive power differential protection [8]. Recently, increasingly more distributed generators (DGs), both synchronous and asynchronous – depending on the energy source ⇑ Corresponding author. Address: No. 52 Mailbox, North China Electric Power University, No. 2 Beinong Road, Changping District, Beijing 102206, China. Tel.: +86 10 80794899, mobile: +86 15801659769. E-mail address: [email protected] (J. Ma). 0142-0615/$ - see front matter Ó 2012 Elsevier Ltd. All rights reserved. http://dx.doi.org/10.1016/j.ijepes.2012.07.024
used, are being connected to the grid. The implementation of DG can create difficulties for the existing power system protection schemes and cause protection devices to operate incorrectly [9–12]. It is feasible for adaptive protection scheme to solve the problems that DG brings to the protection system. This paper continues as follows: first, the impact of DG on traditional protection is analyzed. Next, a novel adaptive non-pilot current protection scheme utilizing steady state fault current is presented. Finally, settings criteria for primary and backup adaptive protection are established. The experimental tests for a realistic power system in Tianjin province in China verify the regions of primary and backup protection are immune to the implementation of DG and types of faults. Furthermore, compared with traditional current protection, the proposed scheme extends the primary and backup protection regions considerably.
2. Impact of DG on traditional current protection Fig. 1 shows a traditional industrial distribution network. Load E is fed through source G and protected by R1, R2, and R3, which are overcurrent relays. Each protective relays is assigned a primary function to clear faults in a specific zone and a backup function to clear faults in downstream zones to the extent that the range of the device permits. When two protective relays operate properly in this primary/backup mode for any system fault, they are said to be ‘‘well set’’. However, protecting systems with DG is not well contemplated in traditional protection philosophy. A network with DG is used as an example to illustrate the malfunction of traditional protection,
J. Ma et al. / Electrical Power and Energy Systems 43 (2012) 1460–1466
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Nomenclature A C U UM UT UC UE UB I IM IT IC IE IB J JT YN Y YEE YBB YJJ YEB YBE YBJ YJB
node correlation matrix branch contribution factor matrix pre-fault bus voltage vector faulted bus voltage vector fault transient state bus voltage vector calculated fault steady state bus voltage vector bus voltage vector of the external nodes bus voltage vector for the boundary nodes pre-fault line current vector faulted line current vector fault transient state line current vector calculated fault steady state line current vector injected current vector from the external buses injected current vector from the boundary buses bus injected current vector variation of injected current vector bus admittance matrix branch admittance matrix bus admittance matrix of external buses only bus admittance matrix of boundary buses only bus admittance matrix of bus J bus admittance matrixes between boundary buses and external buses bus admittance matrixes between boundary buses and bus J
ICk
K Irel
magnitude of calculated fault steady state current of the kth distribution line magnitude of steady state fault current of the mth distribution line magnitude of load current of the mth distribution line before the fault occurs magnitude of calculated fault steady state current of the mth distribution line magnitude of calculated fault steady state current of the kth distribution line magnitude of fault steady state current of the kth distribution line magnitude of load current of the kth distribution line before the fault occurs adaptive primary protection setting for the kth distribution line coefficient of reliability of the primary protection
K IIrel
coefficient of reliability of the backup protection
Kp Kd
threshold value coefficient of fault type
IIIset:k uj ij
adaptive backup protection setting voltage phasor of bus J injected current phasor from bus J
ISm ILk ICm ICk ISk ISL IIset:k
Fig. 1. A traditional industrial distribution network fed through source G and protected by R1, R2 and R3.
Fig. 2. An industrial power network fed through source G, distributed generator (DG), and protected by R1, R2 and R3.
shown in Fig. 2. When fault F1 occurs, the fault current measured by R2 has two components-one coming from source G and the other from DG. The fault current is a variable; dependent upon changing operating conditions of the DG. Nevertheless, the primary protection settings for R2 are determined in the system without DG. In this situation, the primary protection settings for R2 could potentially be smaller than the measured fault current. Consequently, the primary protection of R2 is prone to misoperation. From this example, it can be seen that the implementation and the operating conditions of DG can alter fault current levels enough to cause the misoperation of protective relays. Hence, the protective settings should be adaptive to the implementation and operating conditions of DG. Nowadays, distributed generation interconnection guides in many countries require the immediate disconnection of all the DGs in case of faults. However, some utilities allow DGs to ride
through faults. In the following sections, a novel adaptive current protection scheme is proposed to deal with these situations. The proposed scheme properly performs protective functions in industrial distribution systems comprising DG.
3. Adaptive current protection scheme In power system, generators and loads can be taken as current injection sources. Ignoring nonlinear elements such as power electronic devices, the power network can be taken as a linear network which meets the requirement of the superposition theorem [13]. Thus, the fault network can be taken into the composition of the pre-fault network, the fault transient state network and the fault steady state network. All the electrical variables referred below are phase components.
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In the pre-fault network, the bus voltage vector U and line current vector I are given by
(
U ¼ Y1 N J
ð1Þ
I ¼ YAT U
where YN is the bus admittance matrix, Y is the branch admittance matrix, A is the node correlation matrix, and J is the injected current vector. In the fault transient state network, the bus voltage vector UT and line current vector IT are given by:
(
UT ¼ Y1 N JT
ð2Þ
IT ¼ YAT UT
where JT is the post-fault variation of injected current vector. In the steady state network for the fault condition, the bus voltage vector UC and line current vector IC can be calculated as follows:
UC ¼ UM U UT IC ¼ IM I IT
ð3Þ
where IM is the faulted line current vector and, UM is the faulted bus voltage vector in the fault network. Consider a distribution power system containing N distribution lines, which are numbered as i = 1,2, . . . , N. In the following analysis, the kth distribution lines and the mth distribution lines are used as an example to illustrate the adaptive protection scheme as shown in Fig. 3. In the faulted steady state network, the buses which directly connect to the bus J are called boundary buses denoted as set B. The others are called external buses denoted as set E. The nodal equations of the power network in the form of a partitioned matrix can be written as
2
YEE
6 4 YBE 0
YEB YBB YJB
0
32
UE
3
2
IE
3
76 7 6 7 YBJ 54 UB 5 ¼ 4 IB 5 YJJ uj ij
ð4Þ
where UE is the bus voltage vector of the external nodes. UB is the bus voltage vector for the boundary nodes. uj is the voltage phasor of bus J. The current IE is an injected current vector from the external buses. IB is the injected current vector from the boundary buses. ij is the injected current phasor from bus J. YEE is the bus admittance matrix of external buses only. YBB is the bus admittance matrix of boundary buses only. YJJ is the bus admittance matrix of bus J. YEB and YBE are the bus admittance matrixes between boundary buses and external buses. YBJ and YJB are the bus admittance matrixes between boundary buses and bus J. In case of topological changes, the elements of inductance matrix in (4) are all modified accordingly, so that the proposed method could work properly. By eliminating UE, the nodal equations can be written as
"
YBB YBE Y1 EE YEB
YBJ
YJB
YJJ
#"
UB uj
#
"
¼
IB YBE Y1 EE IE ij
#
ð5Þ
When a fault occurs at bus J in the kth distribution line, there is only one source in the faulted steady state network, located at bus J. Therefore, each steady state fault current injection at the boundary buses and the external buses is 0, which means IE = 0 and IB = 0. Then, the nodal equations can be deduced as
"
YBB YBE Y1 EE Y EB
YBJ
YJB
YJJ
#
UB
uj
¼
0 ij
ð6Þ
Thus, the steady state injected fault current phasor from bus J, ij can be calculated as 1 ij ¼ ½YJJ YJB ðYBB YBE Y1 EE YEB Þ Y BJ uj
ð7Þ
The relationship of the injected current phasor ij and line current vector IS is
IS ¼ ½YAT ðAYAT Þ1 ij
ð8Þ
where Y is the branch admittance matrix. A is the node correlation matrix. C(k) = YAT(AYA)1 is defined as the branch contribution factor matrix (BCFM). From (7) and (8), the line current vector in the steady state fault network can be calculated as 1 IS ¼ kJ ½YJJ YJB ðYBB YBE Y1 EE YEB Þ Y BJ uj
ð9Þ
where kJ is the Jth column of the branch contribution factor matrix C(k). uj is voltage phasor of bus J in the steady state fault network. Thus, the adaptive primary protection setting for the kth distribution line can be formulated as
( IIset:k
¼
K Irel K d ISk ; if
ISk > ITh1
ITh1 ;
ISk 6 ITh1
if
ð10Þ
where IIset:k is the adaptive primary protection setting for the kth distribution line. ISk is the magnitude of fault steady state current of the kth distribution line. ITh1 is the threshold current of the primary protection, the value of which is calculated as ITh = KpILk. ISL is the magnitude of load current of the kth distribution line before the fault occurs. Kp is the threshold value, which is set as 0.1. K Irel is the coefficient of reliability of the primary protection, the value of which is set as 1.1, considering relative errors caused by non-fundamental components, transient harmonics, voltage fluctuation and some other factors. Kd is the coefficient of fault type and can be previously determined according to the different fault type information which can be provided by fault phase selector. Kd is 1 when pffiffi a three-phase fault occurs and Kd is 23 when a phase-to-phase fault occurs. The measured current in R1 denoted as iCk can be calculated by using (1)–(3). Only if the magnitude of measured current ICk surpasses the protection setting IIset:k , will the primary protection issue a signal to the switching device to trip the fault. Due to the substations away from large generation units, the initial high ‘‘subtransient component’’ does not exist in the fault
Fig. 3. The kth distribution line’s primary protection R1 and backup protection R2.
J. Ma et al. / Electrical Power and Energy Systems 43 (2012) 1460–1466
current transients. In this way, the primary relays based on the steady-state fault current can not operate instantaneously but still fast enough for the distribution power system protection. Furthermore, the adaptive backup protection setting IIIset:k can be formulated as
( IIIset:k ¼
K IIrel K d ISm ; if
ISm > ITh2
ITh2 ;
ISm 6 ITh2
if
ð11Þ
where ISm is the magnitude of steady state fault current of the mth distribution line. ITh2 is the threshold current of the backup protection, the value of which is calculated as ITh2 = KpILm. ILm is the magnitude of load current of the mth distribution line before the fault occurs. K IIrel is the coefficient of reliability of the backup protection, which must be above K Irel to fulfill the selectivity and is set as 1.2. The Eqs. (10) and (11) are programmed in the relays. And the settings are calculated by the relays rather than commanded by a control center. The measured current in R2 denoted as iCm can be calculated by using (1)–(3). Only if the magnitude of measured current ICm surpasses the backup protection setting IIIset:k , will the adaptive backup protection issue a signal to the switching device to clear the fault on the adjacent transmission line.
4. Experimental system To verify the performance of the proposed method, the experimental tests have been carried out at the Electrical Power Dynamic Laboratory (EPDL). In these tests, a total of 156 cases have been divided into three main categories: 50 cases for adaptive primary
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current protection, 50 cases for adaptive backup current protection, and 56 cases for the impact of DG to the adaptive protection. In these tests, a realistic 10 kV distributed network in power system of Tianjin province in China is established as shown in Fig. 4. The base capacity is 500MVA and the base voltage is 10.5 kV. Branches AB, BC and AF are all overhead lines. The resistance and reactance of these lines are r1 = 0.027 X/km and x1 = 0.347 X/km, respectively. Moreover, branches CD, DE and FG are all underground cables. The resistance and reactance of these cables are r1 = 0.259 X/km and x1 = 0.093 X/km, respectively. The nominal capacity and the nominal power factor of each load are 6MVA and 0.85, respectively. DG with P–Q control schemes are connected to bus C, the nominal capacity of which is 10MVA. The devices at both ends of line are capable of sensing the fault with different current directions. In the following analysis, protective relays R2 and R3 are used as an example to demonstrate the effectiveness and accuracy of the adaptive primary protection function and the adaptive backup protection function, respectively. When a fault occurs in the transmission line CD, the measured current Ipm3 in R3 can be calculated using (1)–(3) and the adaptive primary protection setting Ips3 of R3 can be obtained by using (4)–(10). In the same way, the measured current Ibm2 in R2 can be achieved using (1)–(3) and the backup protection setting Ibs2 of R2 can be calculated using (4)–(9) and (11). Figs. 5–8 show some examples of the experimental test results: characteristic curves of instantaneous overcurrent relay and time delay instantaneous overcurrent relay in definite time operation, and the resulting analysis. The measured data are presented in the Tables 1–4 to identify the effectiveness of the adaptive protection.
Fig. 4. Experimental system.
Fig. 5. The adaptive primary protection setting and the measured current in R3 when a three-phase fault occurs on Section CD close to bus D.
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Fig. 6. The adaptive primary protection setting and the measured current in R3 when a phase-to-phase fault occurs in the middle of Section CD.
Fig. 7. The adaptive backup protection setting and the measured current of R2 when a three-phase fault occurs on Section CD 2.1 km away from bus C.
Fig. 8. The adaptive backup protection setting and the measured current of R2 when a phase-to-phase fault occurs in the middle of Section CD.
5. Testing results and analysis 5.1. Responses of adaptive primary current protection system A total of 50 test cases were carried out in this situation. In one case, a three-phase fault was applied to Section CD close to bus D (outside the range of primary protection of R3) at 0.30 s. Fig. 5
shows that the measured current Ipm3 and setting of the primary protection Ips3 respond considerably after the fault occurs. In addition, Ipm3 is less than Ips3 the entire time – ensuring that the primary relay does not issue a trip signal. In another case, a phase-to-phase fault was applied in the middle of the transmission line CD (within the region of primary protection of R3) at 0.3 s. Fig. 6 shows that the measured current Ipm3
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J. Ma et al. / Electrical Power and Energy Systems 43 (2012) 1460–1466 Table 1 Measured currents and setting of adaptive primary current protection.
Table 4 The impact of DG to adaptive backup current protection during three-phase fault.
Fault away from bus C
Phase-to-phase fault
Three-phase fault
Measured currents (A)
0% 30% 50% 60% 70% 80% 90% 100%
1408.8 1290.3 1210.8 1172.1 1134.3 1097.8 1062.5 1028.6
1627.1 1490.3 1398.5 1353.7 1310.2 1267.8 1227.1 1188.0
Setting (A)
–
1131.7
1306.8
Fault away from bus C
DG’s capacity (MVA) 5.1
11.5
28.2
Measured currents (A)
0% 30% 50% 60% 70% 80% 90% 100%
1209.9 1108.2 1039.9 1006.7 974.3 942.9 912.6 883.4
1366.5 1251.5 1174.3 1136.7 1100.1 1064.6 1030.4 997.5
1686.7 1543.6 1449.5 1401.1 1354.7 1314.2 1272.0 1231.3
Setting (A) Protective region
– –
1060.0 145.91%
1196.9 145.96%
1477.5 145.94%
Table 2 Measured currents and setting of adaptive backup current protection. Fault away from bus C
Phase-to-phase fault
Three-phase fault
Measured currents (A)
0% 30% 50% 60% 70% 80% 90% 100%
1047.6 959.5 900.4 871.6 843.5 816.3 790.1 764.9
1209.9 1108.2 1039.9 1006.7 974.3 942.9 912.6 883.4
Setting (A)
–
918.0
1060.0
Table 3 The impact of DG to adaptive primary current protection during phase-to-phase fault. Fault away from bus C
DG’s capacity (MVA) 5.1
11.5
28.2
Measured currents (A)
0% 30% 50% 60% 70% 80% 90% 100%
1408.8 1290.3 1210.8 1172.1 1134.3 1097.8 1062.5 1028.6
1590.9 1456.9 1367.0 1323.3 1280.6 1239.3 1199.5 1161.2
1963.8 1798.4 1687.4 1633.4 1580.8 1529.8 1480.6 1433.3
Setting (A) Protective region
– –
1131.7 72.88%
1277.9 72.84%
1577.4 72.84%
in R3 is larger than the protection setting Ips3 after fault occurs, which causes the primary relay to clear the fault accurately. Table 1 shows the measured currents in R3 with different fault locations and fault types occurring in the line CD and the setting of primary protection in R3. In the case of three-phase faults, the region of adaptive primary protection is about 72.94% of the line CD. In the case of phase-tophase faults, the region of adaptive primary protection is about 72.84% of the line CD. It can be seen that the region of adaptive primary current protection is immune to the fault type. In comparison, the primary protection of traditional overcurrent protection greatly affected by the fault type reaches only about 20% into the line CD in the cases of a phase-to-phase faults. 5.2. Responses of adaptive backup current protection system To fulfill the reliability and sensitivity, the operation time of the backup protection R2 should be larger than that of the primary protection R3 at least by a time interval called the ‘‘coordination time interval DIIt ’’.
A total of 50 test cases were carried out for this situation. In one case, a three-phase fault occurs in transmission line CD, 2.1 km away from bus C (within the region of backup protection) at 0.3 s. Assuming that the primary protection in R3 refuses to operate, R2 must operate to provide adaptive backup protection. The characteristic curve of adaptive backup protection in this situation is shown in Fig. 7. It can be seen that, after the fault occurs, the measured current Ibm2 and the backup protection setting Ibs2 respond considerably. Further, the measured current in R2 is larger than the protection setting all the time to makes the backup relay trip the fault accurately. In another case, a phase-to-phase fault occurs in the middle of Section CD (outside the range of backup protection) at 0.3 s. Assuming that the primary protection in R3 refuses to operate, R2 must operate to provide adaptive backup protection. The characteristic curve of adaptive backup protection is shown in Fig. 8. It can be found that the measured current Ibm2 and the backup protection setting Ibs2 respond considerably after the fault occurs. But Ibm2 is less than Ibs2 the entire time ensuring that the backup protective relay does not issue a trip signal. Table 2 shows the measured currents in R2 with different fault locations and fault types and setting of the adaptive backup protection in R2. In the case of three-phase faults, the adaptive backup protection reaches about 45.91% into the adjacent line CD. In the case of phase-to-phase faults, the adaptive backup protection reaches about 45.84% into the line emanating from the remote bus. Hence, the region of adaptive backup protection is not affected by the fault type. Furthermore, the backup protection region has been extended considerably in comparison to the traditional overcurrent protection. Comparing with [14], the proposed current protection scheme could properly deal with not only the disconnection of DG but also the changing output of DG, and the settings of primary and backup relays are automatically adaptive to the system operation and fault type without detecting the faulted section and updating the relays trip characteristics.
5.3. Impact of DG to the adaptive current protection In the traditional current protection scheme, a branch coefficient is needed for calculating the backup protection setting. However, the adaptive backup protection scheme proposed here is immune to the branch coefficient by transforming DG into injected current source. The setting of adaptive primary protection is growing in step with the capacity of DG, but the protection region remains about 72.84%. Also, the coverage of the adaptive backup protection is a fixed value and immune to the capacities of DG. These have been verified by a total of 56 comprehensive cases with different fault
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locations, different fault types (balanced and unbalanced) and different capacities of DG. The data from these tests are presented in Tables 3 and 4. It could be seen from Tables 3 and 4 that although DGs may be intermittent power sources, the proposed adaptive current protection scheme can deal with the variations of the DGs’ output and the disconnection of DGs from power system comparing with current phase comparison schemes protection [15]. Also, the proposed protection scheme includes not only primary protection but also backup protection. Although, integration of DG lead to connection of power electronic devices that limit the fault current magnitude, in this paper, DGs are considered as injected currents which can be timely measured. Thus, the proposed algorithm is immune to the fault current limitation caused by power electronic devices in DG. 6. Conclusion This paper proposed an adaptive current protection scheme. The paper offers an acceptable and practical solution to protection for distribution power systems with DG penetration. In the proposed scheme, the regions of primary and backup protection are immune to the implementation of DG and the indicated fault types. Furthermore, compared with traditional current protection, the proposed scheme has extended the regions of primary and backup protection considerably. Acknowledgments This work was supported by The National Basic Research Program of China (973 Program) (2012CB215200); National Natural Science Foundation of China (50907021, 50837002); The ‘‘111’’ Project (B08013); The Chinese University Scientific Fund Project (11MG01, 09QX64); The Project Sponsored by the Scientific Research Foundation for the Returned Overseas Chinese Scholars,
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