B5-114
CIGRE 2014
http : //www.cigre.org
A New Approach on Protection of Networks with Large Amounts of RES
F. BALASIU
Transelectrica
florin.balasiu@transelectrica.ro
Gh. MORARU
Smart
Romania
Summary
The integration of large amounts of distributed renewable energy sources (RES), in particular
wind power impacts the proper connection of the plants, the reinforcement of the network, the
operation of the power system, as well as the protection systems. Integration of RES results in
increased electricity generation capacities, smoothes the progress of coupling of national
networks into an internal market-base European network and an economically efficient
deployment of future network.
At present-day variable speed wind turbine generators, using doubly-fed asynchronous
generators (DFAG) or full ac-dc-ac converters are used. The behaviour of these generators
under short-circuit conditions is fully different from that of the traditional synchronous
generators. Adaptation of short-circuit contribution calculations to the existing tools is not
easy and is time consuming. The line side converters use power electronic devices (e.g.
insulated-gate bipolar transistors – IGBT), that do not accept large short-circuit currents,
during a fault. The short-circuit contribution magnitudes of a wind turbine [1] is quite small,
in the range of about 1.2 p.u. to 1.6 p.u., depending on the voltage at turbine terminals and
this issue must be considered when choosing the protection functions included into the multifunctional protection relays. In fact, short-circuit current contribution can be modelled as a
limited current source, with greater current levels for the first 1-2 cycles.
The photovoltaic generators (PVG) also use inverters based on the power electronic devices,
which are sensitive to over voltages and provide a quite small amount of short-circuit currents
during faults. Typically, the PVGs keep supplying current, for most of faults, for about two to
ten cycles. The steady-state short-circuit current contribution to a fault of a PVG [2] is up to
1.2 p.u., while during the first half-cycle the current contribution could reach 1.5 up to 2.0 p.u.
Thus, RES providing wind and PV generators represent a challenge for the protection
engineers for modelling, integration into the existing software tools, choosing the right
protection functions and testing as well.
1
1. Introduction
400 kV
21+85 21+85 BB 1
51
51
51N 51N
Q0
67N 67N
79
79
CT1
87BB
50BF
21
400 kV
BB 2
VT1
21
67N
CT3
CT1
VT 1
87T.1 87T.2 63
49
49
49
T2
400/110 kV
VT 2
VT 2
CT2
21
67N
AVR
Q01
110 kV
BB 1
87L
21+85
51
51N
67N
79
VT 1
87T.1 87T.2 63
49
49
49
T1
400/110 kV
87L
21+85
51
51N
67N
79
Q0
VT 1
21
67N
L2 400 kV
OHL
VT2
CT2
VT2
L1 400 kV
OHL
CT2
Large wind power plants, usually with more then 100 MW installed capacity are connected to
the transmission network through new substations. A common solution, based on economic
reasons is to connect the new substation into an existing transmission line as an input-output
layout. Double bus bar and a coupler is a common architecture of such a substation (Fig. 1).
Two line bays, two transformer bays 400/110 kV, the coupler and the bus bars voltage
measurement bays are common requirements to connect the wind power plant.
21
67N
CT2
87BB
50BF
AVR
Q01
21
VT1
110 kV
BB 2
VT1
CT2
CT4
T-1
110/MV kV
CT5
51
CT3
VT3
87T 63
49 49
21+85
51/51N
67N
67N
51N
L1 110 kV
(OHL)
50/51
46
CT4
T-2
110/MV kV
CT5
MV
51
CT 3
VT 3
87T 63
49 49
87L
21
51/51N 67N
51N
L2 110 kV
(UGL)
50/51
46
MV
Figure 1. Typical 400 kV connection of a wind power plant
2. Transformer and line protection
2.1 Power transformer protection
The power transformers include protection functions [3] against internal faults and back-up
protection functions against external network faults, both on the 400 kV and 110 kV. Usually,
only network protection functions need carefully coordination to the protective system of the
network. The power transformer protection are typically organized in two cubicles which
include the main 1 and the main 2 multi-function protection relays. Thus, the main 1 consists
of a multi-function relay including the transformer differential protection as essential
protection function and other additional functions, while the main 2 includes a second multifunction relay including the transformer differential protection and other functions, then a
multi-function relay, connected to the secondary windings of the 400 kV current transformers,
with the distance protection function as an essential one and a multi-function relay, connected
to the secondary windings of the 110 kV current transformers, providing the distance
protection function as an essential one. Other protection function such as phase overcurrent,
2
earth fault protection directional and non-directional and thermal overload protection are
typically include into the multi-function protection relays. The technological protections (e.g.
Buchholtz, valve over-pressure, oil/winding/core overtemperature, etc) of the transformer
issue the tripping order by both differential relays, thus offering the disturbance recording,
too.
The auxiliary transformer, if any, protection functions are typically included into a single
multi-functional relay and consist of the technological protections (e.g. Buchholtz,
oil/winding/core overtemperature, etc) and the transformer differential protection. In addition,
phase or earth overcurrent protection functions are also included. The auxiliary transformer
protection functions issue the trip command to the 400 kV and 110 kV circuit breakers (CBs).
2.2 A 400 kV line protection scheme
The 400 kV line protection system [4] is organized in two ways, either using two multifunction relays with the distance protection function as main and other protection functions,
or using two multi-function relays with the line differential protection function as main and
including also other protection functions. However, the mandatory protection function is the
distance protection function due to remote back-up capabilities. In each case two protection
communication links are provided to fast clearance of faults along the transmission line. If the
line differential is used, then the same fibre optic communication channel as for line
differential is used. In case of only distance protection, a direct communication scheme
between relays from both line ends is used or dedicated communication equipments are used.
2.3 The 110 kV protection schemes
Smaller renewable power plants (wind or photo-voltaic), in the range 20 MW up to 60-100
MW installed capacity are connected to the 110 kV sub-transmission network. Normally,
there are used two main connection methods, namely direct connection to an existing 110 kV
substation, through a new input-output substation (fig. 2.a) and the tie connection to an
existing 110 kV line by an overhead line or by an underground line (fig. 2.b).
a)
b)
Figure 2. Network connection types of renewable energy generation units
3
2.3.1 Single direct line connection
In case of the single direct line connection (fig. 2.a) of a generating unit, the line protection
system (fig. 3) consists of two multi-functional relays. The first (F87L) is assigned to the
CEE Cernavoda I
main protection and is primarily based on
the line current differential protection In=160 0A, 3 1.5 kA BUS-110 kV
function for two line ends. The
Q1
underground cable brings the line
differential protection as mandatory. The
Q0
w1:0, 2 20VA
w 2: 0,5/3P 75VA
data exchange between the line ends
w3: 3 P 75VA
P1
relays is based on an optical fibre
4 00/5
MET
communication link.
0,2SFS5
10VA
The second multi-function relay (F21), is
4 00/5
Wh
WFC
the back-up protection and includes the
0,2SFS5
10VA
M ircea Voda Nord
distance protection function as main T1
4 00/5
F87
F87
back-up. The distance protection mainly
5P20
50VA
Usync
provides protection against phase and
4
00/5
F21
F51
ground faults in the network and acts as
5P20
50VA
back-up protection for the step-up
P2
F21
transformers as well. It also provides
phase over current protection functions
and directional earth-fault protection
functions. Sometimes, (fig. 3), an
additional multi-function relay (F51) is
included as back-up to cope with high
Q9
Q8
resistive faults, mostly in case of the line
differential protection out-of-service.
T5
The line differential protection (87L),
w1:0,2 20VA
needs in this case a separate digital 64 w2: 0,5/3P 75VA
Kbit/s communication channels to w3: 3P 75VA
exchange telegrams among the line ends
LES 110 kV Mircea Voda Nord
relays.
Figure 3. Direct 110 kV line connection protection system arrangement
RED670
REF545
d; 100 V
SEL3 11L
d; 100 V
The telegrams contain current sample values, time synchronisation information, trip and
alarm signals and binary signals that may be used for any purpose. This application also uses
the communication feature for the breaker failure protection function (BFP) and for the
distance protection function communication scheme.
2.3.2 Single tie line connection
In case of the single tie line connection of a generator unit, the line protection system is in
some way typical (fig. 4) and consists of two multi-functional relays. The first, F87L, is
assigned to the main protection and is primarily based on the line current differential
protection function for three line ends. The data exchange among the line ends multifunctional relays is based on an optical fibre communication link. The distance protection
function is usually also included in the same multi-functional relay and offers back-up
protection for both network faults and generation units faults. Power swing detection and
either block distance protection zones or trip is commonly applied.
For a pretty long overhead line it is common to use the single-shot, single pole autoreclosing,
assuming proper circuit breakers and generation units’ capabilities. The second multi-function
relay (F21), the back-up protection includes the distance protection function, as the main
4
protection function and also phase over current protection functions and directional earth-fault
protection functions. This arrangement allows to keep the generation unit connected to the
network, even if the communication channel for the line differential protection function is
broken. The distance protection function is also used as back-up of the transformer
protections and to fast clearing of bus faults, assuming that the protection communication
scheme among multi-functional relays is available. Sometimes, an additional multi-function
relay (F51) is included as back-up, to cope with high-resistive faults, mainly in case of the
line differential protection out-of-service. Typically, the main protection is connected alone to
a protection secondary winding of the CT, while the back-up multi-function relay may be
Rasova
connected, together with other Medgidia Sud
110 kV
devices, to a separate protection
ENEL
Q9
secondary winding of the CT. The
connection to the protection
TV5
secondary windings of the VT is
w1 :0,2 2 0VA
w2 : 0,5/ 3P 75VA
either independently or on the same
w3 : 0,5/ 3P 75VA
secondary, but mandatory through
Q8
separate mini circuit breakers.
The line differential protection
CEE Pestera Q9
function, included in the main, is
90 MW
Med . Sud
an absolute selective one with
P2
some important advantages. The
T PT2000
6 00/5
F87L
0,2 s,10VA
first advantage consists in the
6 00/5
MET WFC
F87L
TI 1
0,2 s,15VA
ability to fast clearing of all faults
Rasova
6 00/5
F87L
on the line, located among the three
5P20,50VA
6 00/5
F51
line ends CTs. The second one is
5P20,50VA
6 00/5
F21
the sensitivity, which can be made
5P20,50VA
high, extremely important to detect
P1
and trip high resistive faults. Not
Q0
using voltage measurement, it does
not lie on the availability of the VT
and this is also an advantage.
Q1
d, 100V
RED670
RED670
RED670
REF545
SEL311C
110 kV
Figure 4. Protection system arrangement
The last, but not the least, coordination with other protections is simple. As it is phase
segregated, the identification of the faulted
phases is inherent and thus the application
of single pole auto-reclosing is reliable.
The line differential protection, used in
this case needs a digital 64 Kbit/s
communication channel (fig. 5) to
exchange telegrams among the line ends
relays. The telegrams contain current
sample values, time synchronisation
information, trip and alarm signals and up
to eight binary signals that may be used
for any purpose.
Figure 5. Three line ends communication link
5
The current differential function operating characteristic is in general a percentage restrained
dual slope one, based on the differential currents and restrain currents calculations.
As a paired solution to the line differential protection function, a permissive over-reach
transfer trip (POTT) scheme can be implemented into the distance protection function [5].
The communication scheme is using the same FO link as the differential protection. The
distance zone 2 settings can be set in such a way, that they will well cover remote line ends
and operate only for faults towards line. Suppose a fault at K1 (fig. 6), that is on the line side.
All distance protection functions will place the fault inside zone 2 and will send a permissive
signal to remote line ends. At one line end, when receiving the signals from the other remote
line ends and checking the starting signal in zone 2 of the local distance protection, a trip
signal is issued (fig. 7).
Z2Medgidia Sud
Z2Rasova
Medgidia Sud
K1
K2
Rasova
F21
F21
Z2Rasova
Z2CEE Pe stera
Z2Medgidia Su d
Z2CEE Pe stera
F21
CEE Pestera
Figure 6. Distance zone 2 settings for the POTT scheme
If we assume a fault beyond one remote line end (K2 in fig. 6), at least one distance protection
function will place the fault reverse and will not send a permissive signal to remote line ends
and no instantaneous trip will emerge. Particular solutions, such as weak infeed and echo
feature are to be taken in order to complete the overall POTT scheme.
Medgidia Sud
Z2
&
T xB.1
RxA.1
RxB.1
TxC.1
Z2
&
RxC.1
RxC.1
Channel C
Med-Ras
TxA. 1 RxA.1
&
Trip
T xC.1
Channel B
Ras-Pes
&
TxA.1
Channel A
Med-Pes
Trip
Rasova
RxB.1 TxB.1
Z2
CEE Pestera
&
&
Tr ip
Figure 7. Principle of operation of the POTT scheme
6
To trip all line ends CBs, in case of a CB failure, the same communication channel of the line
differential protection is used, via the binary inputs and outputs transfer capabilities.
3. Islanded Operation
Another important issue for RES integration is the islanded operation mode. When loosing the
connection to the utility network, the generators operate on the local load, if any. Generally,
islanded operation is not permitted due to safety reasons, due to power quality issues and to
protect equipment from adverse effects, in case of a sudden uncontrolled resynchronization.
Detecting of an islanding operation mode is not an easy task as it depends on the operating
principle of generators and on the balance between load and generation. Typically, islanded
operation detection is based either on primary circuit switches position, or on under/over
frequency and under/over voltage protection functions. In case of mismatch between active
power generation and consumption, a low or high frequency condition could appear and a
frequency based function can be used for detection and tripping. Based on the reactive power
difference prior to an islanding condition, an undervoltage or an overvoltage condition could
result, that can be used for detection and tripping. Monitoring of the circuit breakers position
and disconnectors to sense an islanding condition needs an exchange of data between control
devices, by use of a communication channel. These methods are based on local area data and
could be limited depending on certain system conditions.
Nowadays, phasor measurement units (PMU) are available either as separate devices or as an
integrated function into the protection or control relays. The ability of data exchange between
PMUs, using a proper communication channel, is the prerequisite for wide area detecting of
an islanding condition. One PMU is situated at the RES generator location and the other one
on the utility side, that is at the connection point. A phasor data processing unit (PDPU) is
used for accurate time data alignment and to perform various data calculations. Thus, the local
positive sequence voltage phase angle is measured by both PMUs and sent to the PDPU that
calculates the phase angle difference and issues an alarm and a trip signal if the set thresholds
are exceeded. The slip frequency is used for islanding detection in a similar way. A basic
equivalent diagram of the software implementation in the PDPU is shown in fig. 8 below.
PMU1-U1 _Cond=OK
PMU1-U1 _phase angle
&
∑
PMU2-U1 _Cond=OK
PMU2-U1 _phase angle
ΔΦ
PU
DO
&
Alarm
Alarm_Threshold
PU
DO
Trip _Threshold
Trip
PMU1-U1 _Cond=OK
PMU1-U1 _frequency
&
∑
PMU2-U1 _Cond=OK
PMU2-U1 _frequency
&
Δf
PU
DO
Alarm
Alarm_Threshold
Trip _Threshold
PU
DO
Trip
Figure 8. Basic of wide area islanding operation detection
7
4. Testing the protection systems
It is a common rule to start the field tests with preliminary checks based on visual check of
the protection and control cubicles, visual check of all racks, mechanical fixing of the cases,
relay protection degree check, visual check of external wiring and proper marking according
to the applicable drawings, visual check of cubicle and relays grounding and check of the DC
voltage supply.
Next, hardware checks have to confirm the proper connections of all binary inputs and
outputs to the protection and control scheme. Activation and deactivation of all binary inputs
and outputs is done for this purpose. Checking of the proper alarms, events and messages sent
to the substation SCADA system as well as to the remote EMS SCADA system at the
Network Control Centre (NCC) should be done during this stage.
For analogue inputs check, the injection of all voltages and currents at rated values is
mandatory. During this test it is possible to confirm the proper displayed values on the work
stations of the control systems and also to check for the secondary burden of the CTs and
VTs, as well as their proper connections related to the current direction flow.
Next step is checking of the correct operation of the different protection functions, trip relays,
alarm relays, LEDs, event recordings, alarms and messages both to local and remote NCC.
Basically, the tests have to confirm the proper operation of the different protection functions
included in the multi-function protection relays, according to the settings and configuration
logic. In case of the distance protection function, tests for single phase-to-ground and phasephase faults as well as forward and reverse are to be done for each zone. To test a two or more
line ends differential protection, two or more testing devices with GPS time synchronization
are needed. Thus, from one line end is possible to start both the local and remote testing
devices based on the accurate time synchronization and to simulate in-zone faults and outerzone faults as well.
Functionality checks of circuit breakers trip and reclose, close/open commands, teleprotection
scheme and interlocking are to be done according to a detailed procedure taking into account
the substation layout and the protection and control system philosophy.
The final confirmation of proper behaviour of the protection system according to the actual
load flow is done by the on-load tests on energised equipment. Checking of the correct on-line
direction of currents and voltages for all protection and control devices is the nearest test to
real conditions. During this test reading out the values of currents, voltages, active and
reactive power for both control and protection relays is the common way to confirm the
proper connection of the relays. In addition triggering of disturbance recordings and analysing
them offers valuable information of relay behaviour under load conditions.
5. Conclusions
Different connection solutions for RES are developed, voltage level and size dependent. Some
of the actual state-of-art, common met in the Romanian Power System were presented in the
paper. New philosophies and procedures for protection organization, setting calculation and
coordination, as well as testing were examined to improve the integration of these new
generation units. The paper emphasized on the impact of medium size RES units on the
protection systems and on the way that these difficulties can be solved.
The single tie line connection arrangement to integrate medium size generators face the
protection engineer to challenges regarding protection functions selection, calculation of
settings and their coordination. The use of the line differential protection function together
with a back-up distance protection function is a suitable solution. However, some difficulties
8
have to be solved to improve the total fault clearance time of the distance protection function
trip, in case of differential protection failure. One solution is to make use of the
communication channel among the multi-functional relays of the line ends to implement
additional logic.
Another important fact is to cope with the small amount of short-circuit contribution of RES
generators and on methods of islanding detection and clearance. Besides the traditional
islanding methods based on frequency and voltage protection functions, the paper has shown
a method based on a wide-area detection scheme using phasor measurement units .
Testing of the overall protection system becomes more difficult due to the large number of
used protection functions and due to use of the line differential protection for lines with
several line ends. Robust and flexible numerical testing devices are needed, but much more
strong and diverse knowledge for the protection engineer is a must.
BIBLIOGRAPHY
[1]
R.A. Walling, E. Gursoy, B. English “Current Contribution from Type 3 and Type 4 Wind
Turbine Generators During Faults”, PES IEEE Detroit 2011
[2]
F. Katiraei a.o., “Investigation of Solar PV Inverters Current Contributions during Faults on
Distribution and Transmission Systems Interrupting Capacity”, Western Protective Relay Conference,
October, 2012
[3] H. J. A. Ferrer, E. O. Schweitzer III, “Modern Solutions for Protection, Control, and Monitoring of
Electric Power Systems”, ISBN 978-0-9725026-3-4, chapter 5
[4]
IEEE Standard C37.113 “IEEE Guide for Protective Relay Applications to Transmission
Lines”
[5] G. Ziegler, “Numerical Distance Protection”, ISBN 978-3-89578-318-0, Publics Corporate
Publishing, Erlangen, 2008
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