1
Fault Analysis and Protection of a Microgrid
E. Sortomme, Student Member, IEEE, G. J. Mapes, B. A. Foster, S. S. Venkata, Fellow, IEEE
Abstract—As penetration of distributed generation (DG)
increases at the distribution level, managing these systems
effectively becomes increasingly challenging. One proposed way
to manage these systems is through the adoption of microgrids. A
microgrid is a distribution level network made of several loads
and DG sources that operate as a single aggregate load or
generation source. Microgrids can either operate connected to
the grid, or in the case of a grid fault, in an islanded mode. In this
paper, we use Matlab Simulink’s SimPowerSystems to model a
small portion of distribution network as if it were a microgrid.
We add a mix of renewable DG sources and one dispatchable
source, which at maximum output can produce more power than
the average microgrid load. We then simulate the four major
fault types at each bus in both grid-connect and island modes and
analyze fault currents and voltage levels in order to determine
how the protection scheme of the distribution network would
need to be changed to facilitate microgrid functionality. We show
that standard protection methods are insufficient and propose
the use of digital relays connected to breakers.
Index Terms—Fault Analysis, Microgrid, Protection.
D
I. INTRODUCTION
UE to the increased concern over global climate change,
the demand for clean sustainable energy sources has
increased greatly. One of the major problems with these
sources, such as wind and solar, is integrating them into the
larger power grid. One proposed way is to have distributed
renewable generation sources integrated into a microgrid. A
microgrid is defined as a low to medium voltage network of
small load clusters with Distributed Generation (DG) sources
and storage [1]. It can operate connected with the larger grid
or islanded in the event of a grid fault. A microgrid is
controlled by a single controller and is viewed as a single load
or generation source by the larger system. It can be operated in
industrial, commercial, and/or residential areas. One major
challenge with operating a distribution level microgrid with
Renewable Energy Sources (RES) connected to the system
with inverters is protection against faults.
In this paper we analyze fault currents on a larger system of
distribution network than that used in [1], [2]. Our system is
protected with a standard distribution protection scheme. Our
objective is to see how the protection will need to be changed
to facilitate microgrid operation with the inclusion of DG
sources and islanding capabilities. Our system was built and
simulated in Matlab Simulink’s SimPowerSystems.
E. Sortomme, G. J. Mapes, B. A. Foster and S. S. Venkata are with the
Department of Electrical Engineering, University of Washington, Seattle, WA
98195 USA (email. eric.sortomme@gmail.com, mapes2010@hotmail.com,
annebri@u.washington.edu, venkata@ee.washington.edu).
978-1-4244-4283-6/08/$25.00 ©2008 IEEE
II. SYSTEM TOPOLOGY AND DG MODELS
A. System Description
A microgrid usually consists of small segments of a
distribution network connected to local DG units and loads.
The system used in this study is an 18-bus network with a load
capacity of 3.03 MVA connected to a 10 MVA transformer.
This system is the example distribution system shown in [3]
with line parameters and feeder source impedance given. The
phase loads of each bus were also given and are shown in
Table 1. The system is protected using fuses and reclosers on
the overhead lines and breakers on the underground lines. The
classical distribution system is shown with the protection
devices in Fig. 1. To this system we added four solar arrays,
two wind turbines, and one diesel generator. The solar arrays
are each connected to three-phase inverters and provide a total
of 2,256 kW. The wind generators provide an additional 500
kW to the grid. During islanded operations, additional
generation and load following is provided by a 300 kW diesel
generator. The one line diagram of the system is shown in Fig.
2.
TABLE I
BUS LOADS FOR THE MICROGRID IN FIG. 1, BLANK AREAS INDICATE
UNCONNECTED PHASES
Phase A
Phase B
Phase C
BUS P (kW) Q (kvar) P (kW) Q (kvar) P (kW) Q (kvar)
3
117
73
121
65
90
98
4
97
33
86
35
91
36
6
46
15
77
23
64
19
7
100
65
8
85
32
9
354
180
13
75
34
75
34
75
34
14
111
53
15
176
34
16
89
63
89
63
89
63
17
314
126
18
210
99
B. Models of DG Sources
The inverter connected to the solar arrays is a current
converter made with a three-phase IGBT/Diode Bridge
controlled by a PWM generator with a voltage/current
controller. The PWM has a carrier frequency of 4,320 Hz.
This is connected in series to an LC low-pass filter for
improved power quality. An additional LC filter was used in
2
the input to maintain the quality of the dc input signal. The
input is any dc source rated between 50 kW and 570 kW and 5
kV. The output is a three-phase 12.47 kV system. Maximum
allowable current is limited to 90 A, approximately twice the
maximum power current. This is an adaptation of the inverter
used in [4].
The diesel motor model used in this study is a modified
version of the one used in [5] and is connected to a 300kW/12.47-kV synchronous generator Simulink block.
The wind turbines are based on the wind turbine Simulink
model demonstrated in [6]. This turbine is connected to a 100kW and 400-kW squirrel-cage induction generators. The
turbines are given constant wind input needed for maximum
capacity generation.
The model for the PV modules is a simple single diode
approximation with two resistors as shown in Fig. 3. This
circuit is used to model a Sharp ND-Q0E2U 160-W module
with I-V characteristics obtained from [7]. The resistor values
are computed with the equations given in [8]. Though this
model is not the most accurate, we feel it is sufficient for this
study as the current limiting features of the inverter will
dominate the dynamics in fault simulation. This module model
is used to construct 564-kW arrays.
Fig. 2. One line diagram of the microgrid with added DG sources.
1
+
Voc
Rsh
-
s
+
Rs
8.04
Isc
2
-
Fig. 3. Photovoltaic module model.
III. SIMULATION OF THE MICROGRID SYSTEM
Fig. 1. One line diagram of the conventional distribution system with standard
protection.
The DG sources are placed in desirable areas, with the
diesel generator supplying a balanced three-phase load which
will most likely be industrial and have a backup power supply.
The solar arrays are all, with the exception of the array at bus
12, placed with loads to simulate the aggregate effect of
rooftop solar panels on homes and businesses. The wind
turbines are placed on buses without loads as usually large
turbines are placed in wide open areas or hilltops near
transmission.
In this study, we are interested in evaluating the maximum
and minimum fault currents at each bus in the microgrid. The
system was built in Matlab Simulink using the
SimPowerSystem toolbox. The system is simulated using
Simulink’s ode3 with a fixed time step of 1 microsecond. The
four major faults—single line to ground, line to line, double
line to ground, and three phase faults—are initiated in the
system 0.1 second after the system had reached steady state
and is sustained for another 0.4 second. This allows the rms
values of the symmetric fault currents to be measured. The
fault impedance is chosen as 1mΩ. The system is only
simulated in the islanded mode as the fault currents at each
bus for the original system configuration are given in [3].
Faults with DG source contributions in grid-connect mode can
therefore be easily computed using superposition.
Fault currents are measured on both the high (closest to
substation) and low (farthest from the substation) side of the
fault as most locations had generation on both sides. Currents
are also measured at the high and low buses, (where high and
low mean the same as above) that would need to have backup
3
protection if the devices at the particular bus should fail.
Additionally, a three phase power flow study is conducted
for three cases: (1) on the original system, (2) on the gridconnected microgrid system, and (3) on the islanded system
with the utility system isolated to compare the operating
currents with the fault currents.
IV. SIMULATION RESULTS
The line currents for the three cases mentioned above are
shown in Tables 2-4. The currents for normal operation are
generally reduced with the addition of DG sources with the
exception of lines 5 and 6 which connected to over twice the
amount of generation than load. In grid-connect mode, the line
currents were very similar to those in the island mode with the
exception of lines 1 and 2 which have no connected sources or
loads in the island mode. The line numbers correspond to the
bus number on the furthest end from the substation, e.g., line
16 connects buses 16 and 10.
Fault currents are significantly lower on all lines during the
island mode. Some of the currents were less than 10% of the
grid connected current. Fault currents for the four different
types of faults are given in Tables 5-8 for islanded operation
and Table 9 for grid-connected mode without DG sources.
The voltage levels on all faulted phases dropped to less
than 95% of the initial value throughout the entire grid for all
grounded faults. For line-to-line faults, the voltage increased
by nearly 60%, most likely due to over excitation of the wind
turbines.
The fault currents for island mode are very low for three
main reasons. 1) Inverter current is limited to twice the
maximum load current, 2) the fault currents are divided
between the high side line and the low side line, and 3) the
wind turbines delivered very small amounts of fault current
due to loss of excitation field as a result of the voltage collapse
on grounded phases. The over excitation of wind generators
due to high voltage is also the reason why line-to-line faults in
some locations are higher than line-to-line-to-ground faults.
V. PROTECTION SCHEME
It is clear from Tables 5-9 that to operate safely in islanded
mode, the original protection scheme will be insufficient. The
fuses and device settings are for current levels far too high.
Next, it is clear that no standard over current protection
method will work. Line 16 for example has a normal line
current of 62 A on B-phase flowing from buses 10-16 and a
fault current of 90 A flowing in the opposite direction for a
fault at bus 10. Using directional protection will also not work
as is demonstrated in the case of line 10, with a normal current
of up to 77 A and a fault current for a fault at bus 10 of only
90 A.
The next logical step would be to use a combination of over
and under voltage protection. This will not work because the
geographical area is too small and the voltage drop will
propagate throughout the entire microgrid before the relays
will have time to isolate the faulted line, leading to the
tripping of all lines in the system. Additionally, over voltage
protection methods, such as surge arrestors, do not clear
faulted lines.
For these reasons, we propose that the only way to protect
the microgrid is to use digital relays with breakers at each linebus connection so each line will have a breaker and digital
relay at each end.
TABLE II
NORMAL LINE CURRENTS FOR GRID-CONNECTED WITHOUT DG SOURCES
Line A-Phase B-Phase C-Phase
1
134.40
130.69
160.11
2
134.40
130.69
160.11
3
57.10
56.49
53.06
4
14.36
13.06
13.77
5
23.65
24.24
9.37
6
6.83
11.35
9.37
7
16.98
0.00
0.00
8
0.00
12.90
0.00
9
0.00
0.00
55.99
10
77.30
74.23
51.21
11
28.96
11.57
36.62
12
28.96
11.57
11.60
13
11.61
11.57
11.60
14
17.34
0.00
0.00
15
0.00
0.00
25.23
16
48.37
62.67
15.23
17
0.00
47.65
0.00
18
33.03
0.00
0.00
TABLE III
NORMAL LINE CURRENTS FOR GRID-CONNECTED WITH DG SOURCES.
Line A-Phase B-Phase C-Phase
1
14.35
15.27
14.71
2
14.28
15.20
14.57
3
21.14
22.98
9.76
4
14.21
13.22
12.52
5
31.54
29.56
21.99
6
30.41
28.00
11.31
7
4.95
0.00
0.00
8
0.00
4.24
0.00
9
0.00
0.00
54.16
10
20.36
32.88
16.69
11
7.35
12.87
26.02
12
18.24
3.96
4.45
13
4.24
1.63
3.18
14
16.55
0.00
0.00
15
0.00
0.00
24.61
16
24.04
21.00
37.62
17
0.00
45.47
0.00
18
31.75
0.00
0.00
4
TABLE VI
FAULT CURRENTS FOR 3-PHASE FAULTS.
TABLE IV
NORMAL LINE CURRENTS IN ISLAND MODE.
Primary Primary Backup Backup Backup Backup
Low
High
Low
Low
High
High
Line Current Current Bus Current Bus
Current
Line A-Phase B-Phase C-Phase
1
0.00
0.00
0.00
2
0.07
0.07
0.07
3
20.65
23.62
13.36
4
14.07
13.08
12.30
5
32.31
29.20
23.62
6
28.28
25.95
10.18
7
4.74
0.00
0.00
8
0.00
4.24
0.00
9
0.00
0.00
56.57
10
20.72
29.84
13.36
11
5.23
11.17
24.54
12
12.80
3.89
7.07
13
5.52
1.98
6.86
14
16.90
0.00
0.00
15
0.00
0.00
24.04
16
29.20
15.41
42.71
17
0.00
44.69
0.00
18
31.89
0.00
0.00
1
2
3
4
5
6
10
11
12
13
16
15.6
89.8
0
0
0
22.5
104.3
89.8
85.6
0
0
89.8
0
0
225.2
285
269
224.4
173.8
153.9
14.6
12.2
179.7
319.8
153.1
170.3
231.3
263.4
210.2
109.2
178.1
259.1
3
3
6
5
6
91.1
89.9
89.7
22.5
89.7
6
6
10
12
13
13
83.2
88.4
94.8
57
58.6
49.6
13
12
11
48.6
40.1
108.2
16
119.5
10
10
10
2
2
3
3
3
3
3
2
10
11
11
10
2
10
10
3
3
6
2
6
179
179.5
89.6
228.7
88.9
12
13
13
52.6
54.9
150.4
11
141.1
10
10
10
5
3
5
3
2
10
11
2
223.8
234.3
227.8
89.7
225.6
203
179.3
179.3
268.6
394.7
179.3
Primary Primary Backup Backup Backup Backup
Low
High
Low
Low
High
High
Line Current Current Bus Current Bus Current
Primary Primary Backup Backup Backup Backup
Low
High
Low
Low
High
High
Line Current Current Bus Current Bus Current
0
0
89.8
401.7
406
316.9
405.2
312
203
405.5
269
315.2
357.9
317.3
TABLE VII
FAULT CURRENTS FOR LINE-TO-LINE-TO-GROUND FAULTS.
TABLE V
FAULT CURRENTS FOR LINE-TO-GROUND FAULTS.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
0
0
89.8
0
89.8
89.8
0
137.5
89.8
50.9
89.7
146.1
201.1
242.2
156.3
162.1
196.4
68
54.4
84.4
89.4
86.7
154.9
145.5
151.7
144.8
94
98
94.3
1
2
3
4
5
6
10
11
12
13
16
0
0
89.8
0
102.2
89.8
21.5
157
89.8
80.6
89.6
338.9
427.3
257.8
344.1
243.3
453.9
447.6
274.7
250.8
360.3
249.0
3
3
6
5
6
185.2
188.9
89.7
102.3
89.6
12
13
13
77.4
78.8
82.3
11
146.3
10
10
10
2
2
3
3
2
10
11
2
154.8
222.7
152.6
157.1
153.2
457.7
186
179.4
277.7
276.4
107.3
TABLE VIII
FAULT CURRENTS FOR LINE-TO-LINE FAULTS.
Primary Primary Backup Backup Backup Backup
Low
High
Low
Low
High
High
Line Current Current Bus Current Bus Current
1
2
3
4
5
6
10
11
12
13
16
0
0
80.6
0
106.1
93.6
12.9
132.1
89.8
46.6
93.2
368.0
365.2
285.1
89.7
290.8
56.0
361.9
243
305.1
328.3
311.7
3
3
6
5
6
171.6
170.8
85.6
103.9
85.6
12
13
13
47.0
49.4
46.8
11
133.2
10
10
10
2
2
3
3
2
10
11
2
198.6
199.9
198.2
213.1
208.9
138.4
169.7
174.5
244.5
242.8
175.3
5
TABLE IX
FAULT CURRENTS FOR GRID-CONNECTED WITHOUT DG SOURCES
LINE
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
TYPE OF FAULT
3-Phase
L-L-G
L-L
3123
3720
2705
2506
2497
2170
2013
1870
1743
1749
1608
1514
987
907
855
785
723
679
0
0
0
0
0
0
0
0
0
2245
2083
1944
2059
1831
1784
1924
1665
1666
1729
1449
1497
0
0
0
0
0
0
1972
1721
1708
2.6
1.9
0.39
0
0
0
L-G
3793
2947
2013
1623
767
586
526
518
2597
2579
2322
2138
1879
2056
2188
2202
1.73
2107
Digital relays such as those described in [10] can detect
over voltage, under voltage, and over current. They are
programmable and have communication which will allow for
fault isolation with over and under voltage by comparing
relative voltage levels. The highest over voltage will be the
location of the line-to-line fault, and the lowest under voltage
will be the location of the grounded fault. Programmability
and communication will also allow for over current protection
in grid connected mode and voltage protection in islanded
mode. These next generation programmable relays are the
only way to protect a microgrid that can operate in the
islanded mode.
VI. DISCUSSION
The purpose of this paper is to analyze the fault currents on
a realistic microgrid to investigate the changes needed to the
protection of the microgrid system. Though we did not
simulate line-to-ground, line-to-line, and line-to-line-toground faults on each phase combination of each bus, we feel
that we have sufficiently shown that the traditional protection
methods will not work. Fault simulation on additional phases
can only reinforce what we have already demonstrated
because protection must be for the lowest and highest fault
currents. The lowest can only get lower and the highest higher
with additional simulation.
Also, though our placement of DG sources is done in a
semi-logical manner, we feel that the results will hold true for
most generation mixes of high inverter penetration. This is
important since user installed DG can occur at any location in
the distribution network. Though we only used solar arrays
connected to the inverters, the current limiting characteristics
will be the same for all inverter connected sources such as 20
kW and smaller dc wind generators [11] and storage such as
fuel cells and grid-connected electric vehicles, which could
provide storage solutions in the near future.
We feel that as more and more utilities adopt net metering,
and consumers begin to install onsite RES such as wind and
solar, the type of microgrid presented in this paper will be the
more common occurrence. The main transition will be to give
the microgrid the ability to island, which will increase the
reliability to the consumer. The main problem with giving the
microgrid the ability to island for a time is the cost of
changing the protection scheme. Digital relays are very
expensive, costing between $900 and $3000 per relay [10].
One way to mitigate this cost is to charge the owners of DG
sources a protection and reliability tariff on their generation. A
tariff of 0.005$/kWh will generate $5,000 every ten years for
every 100 kW of installed RES capacity assuming it produces
at least 15% nameplate rating per year. This will be able to
more than pay for the cost of installing and maintaining digital
relays.
In addition to the protection abilities of the relays, the
communication link is integral to the development of
“Smartgrid”, and can be used to send price and other signals to
storage, controllable loads, and dispatchable generation within
the microgrid. This will lead to enhanced reliability and lower
costs to the consumers, as well as allow utilities to integrate
larger penetration levels of non-controllable RES such as wind
and solar farms.
VII. CONCLUSION
As demand for RES increases, one way to integrate them
into the power system is in microgrids. In this paper we have
accurately modeled and simulated an 18 bus microgrid with
several types of DG sources and high inverter penetration. We
simulated faults and calculated the fault currents in both gridconnect and island modes. We conclude that based on the
simulated currents, traditional protective devices will be
unable to protect the system in island operation. Our results
are in accordance with those shown in [1], [2], that
overcurrent protection methods are insufficient on microgrids
due to the current limitations of most inverters. We proposed
that programmable digital relays will be able to not only
protect the microgrid, but help enhance communication to
other parts of the system. This ability will further the
implementation of smartgrid to enhance security, reliability,
and economics for both users and for utilities.
VIII. REFERENCES
[1]
[2]
[3]
[4]
[5]
[6]
T. C. Green and J. D. McDonald, "Modelling and Analysis of Fault
Behaviour of Inverter Microgrids to Aid Future Fault Detection,"
Proceedings of the IEEE International Conference on System of Systems
Engineering, 2007, pp. 16-18.
H. Nikkhajoei and R. H. Lasseter, "Microgrid Protection," Proceedings
of IEEE Power Engineering Society General Meeting, 2007, June 2007,
pp. 1-6.
Cooper Power Systems, Ed. 3, Electrical Distribution-System
Protection, Cooper Industries, 1990.
G. Sybille Hydro-Quebec, Simulink: AC-DC-AC PWM Converter.
[Matlab]. Natick, MA: MathWorks, Inc., 2007.
G. Sybille Hydro-Quebec, Simulink: Emergency Diesel-Generator and
Asynchronous Motor. [Matlab]. Natick, MA: MathWorks, Inc., 2007.
R. Reid, B. Saulnier, R. Gagnon, Simulink: Wind-turbine asynchronous
generator in isolated network, [Matlab]. Natick, MA: MathWorks, Inc.,
2007.
6
[7]
Sharp Electronics Corportation, “160 Watt Spec Sheet,” Feb. 29, 2008,
http://directpower.com/products/modules/sharp/160WattSpecSheet.pdf.
[8] R. C. Campbell, “A Circuit-based Photovoltaic Array Model for Power
System Studies," Proceedings of North American Power Symposium,
2007, pp. 97-101.
[9] G. N. Kariniotakis, N. L. Soultanis, A. I. Tsouchnikas, S. A.
Papathanasiou, and N. D. Hatziargyriou, "Dynamic Modeling of
MicroGrids," in Future Power Systems International Conference, 2005,
pp. 1-7, 16-18.
[10] Schweitzer Engineering Laboratories, Inc., “SEL-751A Feeder
Protection Relay,” June 2008, http://www.selinc.com/sel-751a.htm.
[11] Proven Energy, “Proven Energy Products,” June 2008,
http://www.provenenergy.co.uk/windturbine_products.shtml.
IX. BIOGRAPHIES
Eric Sortomme was born in Ephrata, Washington
on September 22, 1981. He graduated Magna Cum
Laude from Brigham Young University in 2007 with
a Bachelors of Science in Electrical Engineering. He
is currently pursuing a PhD at the University of
Washington with research emphasis on Smartgrid
technologies and wind power integration.
His employment experience includes internships
with Wavetronix LLC and Puget Sound Energy. He
became a student member of IEEE in 2008.
Gregory Joel Mapes was born in Bremerton
Washington in 1981. Gregory graduated high school
at Bremerton High school in 2000. He is currently
an Electrical Engineering major at the University of
Washington.
Work experience includes an internship at the
Western Electricity Coordinating Council.
Brianne Foster was born in Everett, Washington on
June 20, 1987. She will graduate from the University
of Washington in June 2010 with a Bachelors of
Science in Electrical Engineering, specializing in
large scale power systems, sustainable electric
energy, and power electronics and electric drives.
Her employment experience includes the
Electrical Engineering Department at the University
of Washington and the United States Department of
Energy’s Bonneville Power Administration.
S. S. Venkata is currently an Adjunct Professor of Electrical Engineering
at the University of Washington. He has taught for more than 38 years at five
different universities. He is an author or co-author of more than 300 technical
publications and/or presentations. He is a Life Fellow of the IEEE