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Abstract-- This paper focus on how distributed generation
(DG) may impact on the fault detection and location in medium voltage (MV) distribution networks. Typical possible problems are protection blinding and sympathetic tripping. The purpose of the work is to gain an understanding of when problems are most likely to occur, and of possibilities for fault location in networks with distributed generation.
The paper presents simulations (PSCAD/EMTDC) done on a MV radial distribution network with a DG-unit (synchronous generator). An analytical approach is used to explain simulation results.
Distributed generation, medium voltage network, fault localization, blinding.
I. INTRODUCTION ORWAY has large potentials for small hydro power, and many small plants are already in operation. The
Norwegian Water Resources and Energy Directorate, NVE, has mapped at total potential of 25 TWh for plants smaller than 10 MW. New production capacity of totally 5 TWh is estimated to be developed during the next 10 years [1]. Most of the small hydro power plants are connected to MV distribution networks.
The operation of Norwegian distribution networks is based on a radial network structure, with unidirectional power flow. Non-directional overcurrent relays with constant-current characteristics are normally used for short circuit protection.
Whether traditional and inexpensive overcurrent protection can be used in networks with DG depend on the influence the DG has on fault situations. The impact of distributed generation on protection of distribution networks has been described in many papers [2], [3]. Two frequently mentioned problems when using traditional non-directional protection
Manuscript received April 15, 2007. This work is financed by the Norwegian Research Council, ABB, several
Norwegian utility companies and some other industry companies. J. I. Marvik is with the Department of Electric Power Engineering, NTNU,
Trondheim, Norway (e-mail: [email protected]). A. Petterteig is with SINTEF Energy Research, Trondheim, Norway (e-
mail: [email protected]). H. K. Hoidalen is with the Department of Electric Power Engineering,
NTNU, Trondheim, Norway (e-mail: [email protected]).
based on substation measurement of rms current are blinding and sympathetic tripping. In networks with DG, protection coordination is complicated, especially since there is a conflict between settings required to avoid blinding and settings required to avoid sympathetic tripping [4].
The influence DG has on fault detection and fault clearing, as well as an increased focus on minimizing the outage time and the number of load and generation customers affected by each fault, introduces need for changes in fault location methods and equipment [5]. Directional relays or fault indicators may be used to avoid sympathetic tripping, and more advanced methods based on fault transients, adaptive protection schemes or use of relay agents are proposed [2], [5]-[9] for more precise fault localization. These fault location methods utilize collection and communication of information about the actual system state, as well as computational intelligence.
This paper shows how DG influence on the short circuit protection of a radial feeder, and looks into possibilities of utilizing distance protection for automated fault location in a distribution network with DG.
II. SIMULATION MODEL A MV distribution network with a DG-unit connected to a
radial feeder is modeled in PSCAD/EMTDC, see Fig. 1. The DG-unit is a small hydro power plant with a synchronous generator. The generator is assumed to have brushless excitation, and the power factor is controlled to be 1 in steady-state. In all simulations the generators produce rated power. Two different generators are modeled; with rated power of 3 and 6 MW and corresponding typical reactance data. The generator with the largest rated power has the lowest reactance.
A static model is used for representing loads. Active power is represented as constant current and reactive power as constant impedance [10]. The loads are equally dispersed at 6 load taps, with 5 km between each. Maximum load for this feeder is 6 MVA. Low load is assumed to be 25 % of high load. The loads have a power factor of 0.9.
The cross-section area of the line decreases from the substation towards the end of the feeder.
Analysis of Fault Detection and Location in Medium Voltage Radial Networks with
Distributed Generation J. I. Marvik, A. Petterteig and H. K. Hoidalen
N
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2
DG-unit
Loads – 1 MVAcosφ=0,9
Is
I DG
Ifault66/22
22/6
.6
3 4 5 6
cosφ=1
25 MVA5 km
70mm25 km
50mm25 km
50mm25 km
25mm25 km
25mm25 km
16mm2
Main Grid
Sk=990 MVA
5 km70mm2
21
Adjacent feeder
Us
U0
UDG
Fig. 1. Simulation model of a radial feeder in a 22 kV distribution network
III. BLINDING OF FEEDER OVERCURRENT PROTECTION Radial distribution lines are commonly protected by
overcurrent relays. An overcurrent relay has to be set to pickup for a current larger than the maximum load current, and smaller than the smallest possible short circuit current. The following margins for setting of pickup current for overcurrent relays are given in Faanes [11] : 1 5 0 8load ,max relay ,pickup short circuit ,min, I I , I −⋅ ≤ ≤ ⋅ (1) Blinding occurs when, for a short circuit on the line, the current measured in the substation is smaller than the pickup current of the relay. This can happen when there is DG connected to the line.
A. Analytical analysis An analytical analysis on blinding of the line protection in
the substation can be done based on the simplified equivalent scheme shown in Fig. 2. The line is represented by lumped impedance parameters (Zline1 and Zline2), taking the not-constant cross section area of the feeder into account. Zgrid is the impedance of the main network and the short circuit reactance of the substation transformer. ZDG includes the transient reactance of the generator and the transformer short circuit reactance. IDG is the current fed from the DG. Is and Us are substation current and voltage. No loads are includes in the model.
ZDG
Zline1 Zline2
Ufault
DG
Main grid
Ifault
Zgrid
Is
IDG
Us
U0
UDG
Fig. 2. Simplified representation of the network, used for analytical analysis
The fault studied here is a three phase short circuit. The fault current can be expressed as a function of the impedance seen from the fault location, Zth, and the pre-fault voltage at
the fault location Ufault [11], [12]. The Thevenin impedance seen from the fault location is:
( )( )
12
1
DG grid line faultth line fault
thDG grid line
Z Z Z UZ Z I
ZZ Z Z
+= + ∧ =
+ + (2)
The fault current consists of two components; IDG, and Is. The relationship between the sizes of the two currents depends on the relationship between the impedances ZDG and Zgrid+Zline1, and the difference between main grid voltage U0 and generator internal voltage UDG. Eq. (3) gives an expression for the substation current:
( )
( )
0 1
0
1
2 11 2
1
grid line s DG DG DG DG fault s
DGs
grid line DG
faultline grid line
grid line lineDG
U Z Z I U Z I I I I
U UI
Z Z Z
UZ Z Z
Z Z ZZ
− + = − ∧ = −
−⇒ =
+ +
+ ⋅+
+ + +
(3)
The first term equals the substation current before fault. U0-UDG is assumed to be constant before and after fault inception, and equal to the value that corresponds to nominal generation in the DG. For a fault at the end of the radial, the total impedance of the line and the main grid is constant, independently of where the DG is connected:
1 2grid line line totalZ Z Z Z+ + = (4) By inserting (4) into (3), so that Zline2 is eliminated, (3) can
be plotted as a function of Zline1. This corresponds to moving the connection point of the DG unit. Fig. 3 shows the current in the substation as a function of the connection point of the DG for the two DG-sizes 3 MW and 6 MW, both at nominal generation. As a simplification, Ufault is assumed to be 1 pu in both cases.
0 5 10 15 20 25 30
2
2.5
3
3.5
Distance from substation to DG-unit [km]
I s [pu]
No DG3MW DG6MW DG
Fig. 3. The substation fault current (Is), from (3), when the connection point of the DG-unit is varied. Three-phase short circuit at the end of the feeder.
The plot shows that the reduction in the short circuit current is largest when the DG is connected at the middle of the feeder. The reduction is smallest when the DG is connected at the end of the feeder. Without DG the total current is fed via the substation and is seen by the feeder protection overcurrent relay. The probability of blinding increases with increased generation from the DG.
The impedance ZDG decreases with increasing DG-capacity. In addition, generators with the same generation capacity can
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have different short circuit capacity due to differences in reactance parameters. According to Kundur [10] standard d-axis transient reactance values for hydraulic generators are 0.2-0.5 p.u. A smaller transient reactance means larger short circuit capacity, or larger fault current contribution from the DG. This gives increased blinding probability.
Fig. 4 shows that the probability of blinding is increased for a longer feeder. For the calculations on the 45 km feeder, each line section is prolonged to 7.5 km, while other data are the same as for the 30 km feeder. The margin between short circuit and load current decreases as the feeder length increases. For very long lines it might not be possible to use overcurrent protection even without DG. Connecting DG to the network worsens this problem.
0 5 10 15 20 25 30 35 40 45
2
2.5
3
3.5
Distance from substation to DG-unit [km]
I s [pu]
30 km,no DG30 km,3 MW DG45 km,no DG45 km,3 MW DG
Fig. 4. The substation fault current (Is) for two different line lengths, when the connection point of the DG-unit is varied. Three-phase short circuit at the end of the feeder.
B. Short circuit simulation For comparison, simulation results of fault current
measured in the substation when the connection point of the DG is varied is shown in Fig. 5, together with the analytically calculated curve. The fault is a three-phase short circuit at the feeder end, and the DG production is 3 MW.
0 5 10 15 20 25 302.8
3
3.2
3.4
3.6
3.8
4
4.2
Distance from substation to DG-unit [km]
I s [pu]
simulated - high loadsimulated - low loadsimulated - no loadanalytical - no load
Fig. 5. Comparison between simulated and analytically calculated substation fault current (Is).
The simulated curves in Fig. 5 show the same tendency as the analytically calculated. They also show that it is not unreasonable to study a model without loads, since the short circuit current is smallest in this case.
In the simulated case, the voltage Ufault depends on load level, and on the generation level and connection point of the DG. In the no load case, Ufault becomes higher than 1 pu due to the DG-production. If a value higher than 1 pu is used in
the calculation, the analytical curve is lifted up, giving a result closer to the simulated curve.
The smallest possible short circuit current occurs when there is a two-phase short circuit at the end of the feeder. Fig. 6 and Fig. 7 show substation fault currents for this fault, for the high load and low load case. The curves are found by simulation, and the DG is connected at feeder mid-point.
7.49 7.5 7.51 7.52 7.53 7.54 7.55 7.56 7.570
1
2
3
4
Time [s]
I s [pu]
, at h
igh
load
No DG3 MW DG6 MW DG
Fig. 6. Simulated substation fault current (Is) with two-phase short circuit at feeder end, at high load
7.49 7.5 7.51 7.52 7.53 7.54 7.55 7.56 7.570
1
2
3
4
Time [s]
I s [pu]
, at l
ow lo
ad
No DG3 MW DG6 MW DG
Fig. 7. Simulated substation fault current (Is) with two-phase short circuit at feeder end, at low load
For the case presented, using (1), the chosen pickup current is typically 2 pu when there is no DG connected. The maximum load current is 1 pu (equal to high load). Minimum short circuit current will occur during low load, and is 3.3 pu, according to Fig. 7.
If Irelay,pickup is set to e.g. 2.0, the relay will not trip in the case with 6 MW DG in Fig. 7. There is still some margin between minimum short circuit current (~1.8 pu) and maximum load current, so the pickup-current could be adjusted down to e.g. 1.5 pu. However, in this case the margin would be slightly smaller than that given in (1).
With higher generation than 6 MW, the line voltage in the connection point could increase above acceptable limits (± 10% of nominal voltage) [13] during low load. With e.g. a generation of 8 MW from the DG, the voltage became 1.12 pu. For the presented case, it seems possible to avoid blinding for most realistic DG-capacities.
IV. SHORT CIRCUIT ON ADJACENT FEEDER Fig. 8 and Fig. 9 show simulated substation current on the
feeder with DG, when there is a three phase short circuit at an adjacent feeder. The DG-unit is connected near the substation,
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after line section 1. This represents the worst case as regards false tripping.
7.49 7.5 7.51 7.52 7.53 7.54 7.55 7.56 7.570
0.5
1
1.5
2
2.5
3
Time [s]
I s [pu]
, hig
h lo
ad
6 MW DG3 MW DGno DG
Fig. 8. Simulated substation current (Is) with three-phase short circuit at an adjacent feeder. High-load case.
7.49 7.5 7.51 7.52 7.53 7.54 7.55 7.56 7.570
0.5
1
1.5
2
2.5
3
Time [s]
I s [pu]
, low
load
6 MW DG3 MW DGno DG
Fig. 9. Simulated substation current (Is) with three-phase short circuit at an adjacent feeder. Low-load case.
The DG-unit feeds fault current to the adjacent feeder, and with a DG-production of 6 MW this current is large enough to trip the relay. This is not desirable, and can be prevented by installing a directional overcurrent relay at the feeder with DG.
It is worth to notice that if the pickup of the overcurrent relay is adjusted down in order to prevent blinding, the probability for unwanted disconnection due to short circuit at an adjacent feeder will increase.
V. DISTANCE PROTECTION AND FAULT LOCATION Distance protection is the most common line protection at
transmission level, and in meshed networks. They respond to the impedance between the relay location and the fault location. For e.g a fault between phases a and b, the impedance can be obtained from the voltages and currents in phases a and b:
a ba b
a b
U UZ
I I−
−=
− (5)
The impedance can be obtained correspondingly, for the other phase-to-phase faults. For a three-phase fault, voltage and current from any pair of phases can be used [14]:
a b b c c aa b c
a b b c c a
U U U U U UZ
I I I I I I− −
− − −= = =
− − − (6)
For fault location, the reactance part of the measured impedance is normally used for determining the distance to a
fault [15]. In this way, the impact from a possible fault resistance is reduced.
Distribution networks differ from transmission networks by some important characteristics:
• Due to the not constant cross-section area of distribution networks, there is no linear relationship between measured impedance and distance to the fault location.
• The line losses are larger, so the short circuit angle is smaller. This means that the difference between load angle and short circuit angle also is smaller for distribution lines.
• Load taps are found at irregular intervals. • Distribution networks have tree-structure, so that
one measured impedance might correspond to several possible fault locations. This is not examined in the current paper, but can be handled e.g. by using fault indicators in the branching points.
The accuracy of the calculated distance to the fault is influenced by several quantities. In the following sections the impact of intermediate load taps and of DG connected to the network is examined. In addition there might be errors due to inaccuracies in measurements and line parameters, but that is not further discussed here.
A. Impact of load current on calculated distance to fault The current in the primary substation contains a load
current component. This was seen in the short circuit simulations in the previous section on blinding. The equivalent circuit shown in Fig. 10 can be used to study the impact from an intermediate load.
Us,aIs,a
Is,b
Zline2
Zline1
Zline1
Zload
Zload Zload
Zline2
Zline2
Zline1
Is,c
Us,b
Us,c
U1,a
U1,b
U1,c
Fig. 10. Equivalent circuit for phase-to-phase fault in network with one load
From the equivalent circuit, the following expression for the impedance measured by the relay can be found:
, , 21
, , 2
1 2
3
3
s a s b load linea b line
s a s b load line
loadline line
U U Z ZZ Z
i i Z Z
ZZ Z
−
− ⋅= = +
− +
⎛ ⎞= + ⎜ ⎟⎝ ⎠
(7)
The second term in (7) becomes a bit less than Zline2, so the effect of intermediate loads is that faults appear to be closer to the substation than they actually are. The trend will be the
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5
same with more loads along the feeder. Fig. 11 shows that the case with high load, and a profile
where most of the load (5 MVA) is connected close to the substation and a small portion (1 MVA) connected at the end of the feeder, gives the largest distance-error. During a short circuit, the voltage is highest close to the substation. Since the loads are voltage-dependent, the total load current will be larger than in the case with evenly distributed loads, even though the total load were equal prior to the fault. Generally, the largest error in fault distance measurement appears when a large portion of the load is connected close to the substation.
5 10 15 20 25 30-0.2
-0.15
-0.1
-0.05
0
Distance from substation to fault location [km]
(X-d
ista
nce
- rea
l dis
tanc
e) /
real
dis
tanc
e
low load, profile:high load, profile: 1-1-1-1-1-1high load, profile: 5-0-0-0-0-1
Fig. 11. Relative error in calculated distance to fault location for two high load and one low load case. Distance is calculated from measured reactance.
Although the load is mostly active power, it has an impact on the measured reactance. This is due to the parallel in the second term of (7). In addition, the total resistance of the feeder is higher than the total reactance. A deviation in the reactance will influence relatively more on the accuracy of the calculated distance than a deviation in the resistance.
B. Load compensation For a radial line with unidirectional power flow, the load
current during a fault can be estimated from the voltage and current measured in the substation. In the simple approach described here, the load is assumed to be dispersed equally at N load taps. The loads are modeled as constant impedances, calculated from the active and reactive power flow in the substation before fault inception:
2,. -
, -.=
×s pre fault
loads pre fault
UZ
S N (8)
The line sections are represented by series impedance only. The number of load taps, N, is 6.
Fig. 12. Distribution of equal load equivalents along the feeder
With reference to Fig. 12, the voltages in the load tap points and the load currents are calculated iteratively, using (9).
,
,
− −= −
=
m k line k m k m
mload m
load
U U Z IUIZ
(9)
Fig. 13 shows that the load compensation works well for the two cases where the loads are evenly distributed, since this is the distribution that is assumed when calculating the load current during the fault. But, also for the case where the load distribution is 5-0-0-0-0-1 the distance error is reduced with load compensation, from ~17 % to ~9 % for a fault at the end of the feeder.
However, the approach for load compensation presented here, will not work with DG in the network, since it is based on an assumption of unidirectional power flow.
5 10 15 20 25 30-0.2
-0.15
-0.1
-0.05
0
Distance from substation to fault location [km]
(X-d
ista
nce
- rea
l dis
tanc
e) /
real
dis
tanc
e
low load, profile:high load, profile:1-1-1-1-1-1high load, profile:5-0-0-0-0-1
Fig. 13. Relative error in calculated distance to fault location with compensation of load current. Distance is calculated from measured reactance.
C. Impact of in-feed current from DG Fig. 14 shows simulation results for a low load case with a
3 MW DG-unit connected at the middle of the radial, 15 km from the substation. The fault location is varied along the feeder.
The DG has no impact on the fault distance for fault locations closer to the substation than the DG connection point. For faults beyond the DG connection point, the effect of the DG is that the calculated distance to the fault is larger than the real distance. The impact of the DG on the distance calculation is opposite of that from the load, so that they to some extent balance each other. Thus the largest error in the distance calculation appears in a low load situation.
10 12 14 16 18 20 22 24 26 28 30-0.1
0
0.1
0.2
0.3
0.4
Distance from substation to fault location [km]
(X-d
ista
nce
- rea
l dis
tanc
e) /
real
dis
tanc
e
6 MW DG3 MW DGno DG
Fig. 14. Relative error in calculated distance to fault location, with DG-unit at the mid-point of the feeder. Distance is calculated from measured reactance. Low load case.
Fig. 15 shows the error in calculated distance to the fault as the connection point of the DG-unit is varied. The fault is at
¼-¼-¼-¼-¼-¼
¼-¼-¼-¼-¼-¼
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the end of the line (worst case). The distance error is largest when the DG-unit is connected close to the substation.
5 10 15 20 25 30
0
0.2
0.4
0.6
Distance from substation to DG connection point [km]
(X-d
ista
nce
- rea
l dis
tanc
e) /
real
dis
tanc
e
6MW, low load6 MW, high load3MW, low load
Fig. 15. Relative error in calculated distance to fault location with the fault at the end of the feeder, as a function of DG-location. Distance is calculated from measured reactance.
VI. CONCLUSION Since distribution networks have largely varying extent and
design, it is hard to draw general conclusions on DG-impact on feeder protection.
DG reduces the margin between minimum short circuit current and maximum load current. For the feeder studied here, blinding of the overcurrent protection seems possible to avoid for most realistic DG generation-levels.
The probability of protection blinding is largest in weak networks, and in networks with large extent. Generators that are connected near the feeder mid-point contribute most to the reduction of substation short circuit current.
Unwanted disconnection of a feeder with DG due to a fault at an adjacent feeder, can occur if the feeder protection is not directional.
Distance protection can be used to obtain the distance to a fault from the measured fault reactance. Distribution networks have some characteristics that make fault location with distance protection more difficult than the conventional application in transmission networks. Load taps dispersed along the feeder makes the distance protection see a shorter fault distance than the real one. DG has the opposite effect, and makes the fault appear to be farther away than it is. Both load and DG must be taken into account, when using distance protection for automatic fault location in distribution networks with DG.
REFERENCES [1] Jensen, T. (red.), NVE 2004. Calculation of potential for small hydro
power stations in Norway (In Norwegian). www.nve.no [2] Li, H. Y., Crossley, P. A., Jenkins, N., 2002. Transient Directional
Protection for Distribution Feeders with Embedded Generations, 14th Power Systems Computation Conference, June 24-28 2002, Sevilla, Spain, 6 pages
[3] Kauhaniemi, K., Kumpulainen, L., 2005. Impact of distributed generation on the protection of distribution networks, Electric Energy T&D Magazine. Vol. 8 (2004) Nr: 5, pp. 161 – 163
[4] Mäki, K., Repo, S., Järventausta, P., 2006. Protection requirement graph for interconnection of distributed generation on distribution level. IJGEI - journal 2006, 9 pages
[5] Andrieu, Raison, Penkov, Fontela, Bacha, Hadjsaid, 2004. Fault detection and diagnostics in high-DG distribution systems, CRISP report D.1.4, 38 pages
[6] Brahma, S.M.; Girgis, A. A., 2004. Development of adaptive protection scheme for distribution systems with high penetration of distributed generation, IEEE Transactions on Power Delivery, Vol.: 19, Iss.: 1, Jan. 2004, Pages: 56 – 63
[7] Geidl, M., 2005. Protection of Power Systems with Distributed. Generation: State of the Art. . Power Systems Laboratory. Swiss Federal Institute of Technology, 20th July 2005, 35 pages
[8] Perera, N., Rajapakse, A.D., Gole, A.M., 2006, Wavelet-based relay agent for isolating faulty sections in distribution grids with distributed generators, The 8th IEE International Conference on AC and DC Power Transmission, 28-31 March 2006, Pages:162-166
[9] Zeng X., Li, K.K., Chan, W.L., Su S., 2004. Multi-agents based protection for distributed generation systems, Proceedings of IEEE International Conference on Electric Utility Deregulation, Restructuring and Power Technologies, Vol. 1, 5-8 April 2004, Pages: 393 – 397
[10] Kundur P. 1994. Power System Stability and Control. McGraw-Hill, New York, US pp. 153, 271-4
[11] Faanes H., Olsen, K. 2005. Compendium in course TET4115 Elektric Power Systems, Department of electric power engineering, NTNU, Trondheim, Norway 2005 (In Norwegian).
[12] Mäki K., Repo S., Järventausta P. 2005. Protection Coordination to meet the Requirements of Blinding Problems caused by Distributed Generation. WSEAS Transactions on Circuits and Systems, 2005, vol.4, no.7, p. 674-8.
[13] OED 2007. FOR 2004-11-30 nr 1557: Regulations on Power Quality (In Norwegian). http://www.lovdata.no/cgi-wift/ldles?doc=/sf/sf/sf-20041130-1557.html.
[14] Horowitz, S. H., Phadke, A. G. 1995. Power System Relaying. Second Edition. Research Studies Press Ltd. Taunton, Somerset, England 1995. pp. 106-134.
[15] Ziegler G. 2006. Numerical Distance Protection, Principles and Applications. Second Edition. Publicis Corporate Publishing, Erlangen, Germany
Jorun Marvik received the M.Sc. degree in Electrical Engineering from
the Norwegian University of Science and Technology in 2004. She is now PhD-student at the same institution.
Astrid Petterteig received the M.Sc. degree in Electrical Engineering from the Norwegian Institute of Technology in 1987, and the Ph.D. degree in 1992. She is presently working at SINTEF Energy Research as a research scientist.
Hans Kr. Høidalen received his MSc and PhD from the Norwegian University of Science and Technology in 1990 and 1998 respectively. He is now a professor at the same institution with a special interest of electrical stress calculations and modeling.
