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IEC 61850 Goose applications to distribution protection schemes


  • pg 1

                         IEC 61850 Goose applications to
                          distribution protection schemes
                                                                          by Alexander Apostlov and Benton Vandiver; Omicron Electronics USA

The distribution industry is going through significant changes due to the increased requirements for improved quality of power supplied by
the utility in order to avoid costly interruptions of manufacturing or other processes caused by voltage sags, swells or unbalanced conditions
when a short circuit fault occurs in the distribution system.

The prolonged effect of short circuit
faults on sensitive equipment supplied
by distribution feeders can lead to their
failure and significant losses. This is pushing
the requirements for the performance of
distribution protection systems and making
them similar to transmission protection
systems requirements.
The improvement of power quality during
short circuit faults can be achieved in
several different ways. Like any other
problem that has to be solved, we need
first to understand the nature of the
problem and its effect on sensitive users.
                                                                 Fig. 1: Phase voltages for a single-phase-to ground fault (Phase A).
The most common short circuit faults in
the system, single-phase to ground faults,
are characterised by the fact that they
introduce a voltage sag in the faulted
phase, and at the same time they result in
a voltage swell in the two healthy phases.
This is clearly seen in Fig. 1 which shows
the recorded waveform and the voltage
phasor diagram for a single-phase to
ground fault.
The case of two or three-phase faults is
quite different. For three-phase faults all
phases experience a voltage sag, while for
a two-phase fault the two faulted phases
will have lower voltages, with the healthy
                                                                                   Fig. 2: ITI (CBEMA) curve from a
phase having no significant change                                                       manufacturing plant.
compared to the pre-fault levels.
Fig. 2 shows a plot of depth vs. duration
of actual cases from a high-volume
manufacturing plant, with some of them
resulting in process shutdown due to
variable speed drives and vacuum pumps
There are several factors that determine
the voltage level during a short circuit fault
on the transmission or distribution system:
   System configuration
   Fault location
   Fault resistance
The first characteristic of a voltage sag, the
depth, is something that we can't control,
but we have to study in order to be able to
predict or estimate the effects of different
faults on sensitive equipment.
                                                                          Fig. 3: Distributed function definition in IEC 61850.
The second characteristic of the voltage
sag, the duration, is the parameter
that we can control by properly                   feeder protection relays. The focus of this            in distributed protection schemes that
applying the advanced features of                 paper is the impact of IEC 61850, and                  can reduce the fault clearing time in
state-of-the-art multifunctional distribution     especially the use of Goose messages                   distribution substations.

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                                                                            TRANSMISSION AND DISTRIBUTION
                                                                                                     The functions in the substation can be
                                                                                                     distributed between IEDs on the same,
                                                                                                     or on different levels of the substation
                                                                                                     functional hierarchy. IEC 61850 defines
                                                                                                     three such levels:
                                                                                                        Station
                                                                                                        Bay/unit
                                                                                                        Process
                                                                                                     These levels and the logical interfaces
                                                                                                     are shown by the logical interpretation of
                                                                                                     Fig. 4. IEC 61850 focuses on a subset of the
                                                                                                     interfaces shown in Fig. 4 with Interface 8
                                                                                                     (shown in red) being used for high-speed
                                                                                                     peer-to-peer communications.
                                                                                                     The logical interfaces IF8 is defined as
                                                                                                     direct data exchange between the
                                                                                                     bays especially for fast functions like
                              Fig. 4: Logical interfaces in a substation.
                                                                                                     Distribution bus protection
                                                                                                     The protection and control in substations
                                                                                                     is distributed in nature by the fact that
                                                                                                     each protective relay is designed in
                                                                                                     general to provide primar y protection
                                                                                                     of individual substation equipment such
                                                                                                     as transmission and distribution lines,
                                                                                                     transformers, capacitor banks, etc.
                                                                                                     The only substation equipment that
                                                                                                     requires a centralised form of protection
                                                                                                     in conventional systems is the busbar.
                                                                                                     Transmission buses are typically protected
                                                                                                     by bus differential protection relays. They
                                                                                                     require current signals from each primary
                                                                                                     equipment connected to the bus to be
                       Fig. 5: High speed peer-to-peer communications based                          available at the central location of the
                                       distributed bus protection.
                                                                                                     bus differential protection. The scheme
                                                                                                     becomes much more complicated and
                                                                                                     expensive if the current transformer ratios
                                                                                                     are different. Things get even worse if the
                                                                                                     bus differential protection is used in a
                                                                                                     substation where the bus configuration
                                                                                                     may change.
                                                                                                     Because of the high cost and the increased
                                                                                                     requirements for maintenance, in many
                                                                                                     cases bus differential protection is not
                                                                                                     installed on distribution or sub-transmission
                                                                                                     buses. As a result, bus faults are cleared
                                                                                                     by back-up relays with longer fault clearing
                                                                                                     times caused by the need for time
                                                                                                     coordination between the distribution
                                 Fig. 6: Sympathetic trip protection.
                                                                                                     feeder relays and the transformer relays.
                                                                                                     This becomes a significant power quality
Distributed protection applications peer-            functional hierarchy can be located in the      problem because of the increased
to-peer communications are used to                   same physical device, and at the same           duration of voltage sags.
perform protection, control, monitoring              time different physical devices can be
and recording functions. Any function                exchanging data at the same functional          Multiple protective IEDs with IEC 61850
can be divided into sub-functions and                                                                Goose can be connected to the substation
functional elements. Functional elements                                                             LAN and used in distributed bus protection
are the smallest parts of a function that            Fig. 3 shows logical connections (LC) - the     applications for distribution systems.
can exchange data. In IEC 61850 these                communication links between functional
                                                                                                     In case of a fault on any of the protected
are called logical nodes. When a function            elements, in this case logical nodes
                                                                                                     feeders (F1 in Fig. 5), the feeder protection
is executed based on the exchange of                 of the P and R groups. IEC 61850 also           IED will see a fault. The same fault current
communications messages between two                  defines interfaces that may use dedicated       will be seen by the transformer protection
or more devices, it is called "distributed           or shared physical connections, the             IED. As soon as the overcurrent protection
function".                                           communication links between physical            element of the feeder relay starts, the IED
The exchange of data is not only between             devices. The allocation of functions            will send a Goose message indicating the
functional elements, but also between                between different physical devices defines      detection of a fault on the feeder. The
different levels of the substation functional        the requirements for the physical interfaces,   transformer protection IED subscribes to
hierarchy. It should be kept in mind                 and in some cases may be implemented            Goose messages from all feeder relays.
that functions at different levels of the            into more than one physical LAN.                When it receives the message indicating

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                                                                                                       can be use to adjust the sensitive settings
                                                                                                       of the relays on the healthy feeders for the
                                                                                                       duration of an inrush condition following
                                                                                                       the clearing of a fault in a distribution
                                                                                                       system with a significant number of motor
                                                                                                       loads. Automation systems clearing of
                                                                                                       a fault in a distribution system with a
                                                                                                       significant number of motor loads.
                                                                                                       This is known as a sympathetic trip scheme.
                                                                                                       As soon as a relay detects a fault on the
                                                                                                       feeder that it is protecting, it sends a
                                                                                                       Goose message to all other feeder relays
                                                                                                       informing them to expect an inrush as a
                                  Fig. 7: Selective backup tripping.
                                                                                                       result of the voltage recovery following
                                                                                                       the clearing of the fault. Each of the
                                                                                                       relays on the healthy feeders subscribes to
                                                                                                       Goose messages from all adjacent feeder
                                                                                                       protection IEDs and when it receives a
                                                                                                       message indicating adjacent feeder fault,
                                                                                                       it adapts its settings for the period of time
                                                                                                       that the expected inrush condition is going
                                                                                                       to last. Two options are usually available:
                                                                                                          Block the sensitive overcurrent setting
                                                                                                          Reduce the sensitivity by increasing
                                                                                                           the pickup setting for the duration of
                                                                                                           the inrush
                                                                                                       The benefit of using Goose messages
                                  Fig. 8: Breaker failure protection.                                  in such a scheme is that instead of the
                                                                                                       large number of required wires between
                                                                                                       the binary inputs and relay outputs of all
                                                                                                       distribution feeder protection IEDs, the just
                                                                                                       need to publish and subscribe to Goose
                                                                                                       messages from the adjacent feeders' IEDs.

                                                                                                       Selective backup tripping
                                                                                                       The common approach that many utilities
                                                                                                       have taken is to use a single protection
                                                                                                       IED on a feeder. In case of failure of this
                                                                                                       relay, faults on the line are cleared by the
                                                                                                       backup over-current protection on the
                                                                                                       transformer or sectionalising breaker. The
                                                                                                       problem with this approach is the long fault
                                                                                                       clearing time that may affect sensitive
                                                                                                       loads fed by the distribution substation.
                                                                                                       A solution that significantly reduces the
                                                                                                       duration of the fault is based on the
                   Fig. 9: Test system/configuration tool, simplified block diagram.
                                                                                                       adjustment that the backup relay can
                                                                                                       make in its decision to trip based on the
                                                                                                       knowledge that a specific IED has failed.
that there is a fault on one of the feeders,           of clearing the bus fault with the long
                                                                                                       This adaptive form of protection uses
the overcurrent protection element that is             time delay of a coordinated backup
                                                                                                       the normally closed contacts of the
used for bus protection is blocked.                    transformer protection, the only time           feeder relays that close when the relay
                                                       delay required will be the longest possible     is not healthy. When the transformer of
If the fault is on the bus (F2 in Fig. 5), no
                                                       overcurrent element starting time plus a        sectionalising breaker relay sees a fault
feeder IED will see a fault, the transformer
                                                       safety margin.                                  and does not get any blocking signal from
protection IED is not going to receive a
Goose message indicating a feeder fault.               The benefit of the peer-to-peer                 any of the feeder relays, it knows that there
This indicates a bus fault and the relay is            communications based distributed bus            are two possible cases:
going to trip the transformer breaker to               protection is that it provides fast fault          The fault is on the feeder with the failed
clear the fault.                                       clearance for distribution bus faults without       relay
                                                       the need for any additional protection              The fault is on the distribution bus
The peer-to-peer communications based                                                                  
bus protection requires an operating time                                                              Since the probability for a fault on a
for the fault detection of about one cycle             Sympathetic trip logic                          distribution feeder is much higher that
for the relays involved. The addition of 0,25                                                          the probability for a distribution bus fault,
cycle (4 – 5 ms) for the communication                 The changes of fault conditions in the
                                                                                                       the. relay first sends a signal (1) to trip the
message and the safety time delay of                   distribution system impact not only the
                                                                                                       breaker of the failed relay. If this does not
0,75 cycle in the transformer protection               sensitive loads, but also depending on the
                                                                                                       clear the fault, then it is clear that the fault
                                                       load may lead to the undesired operation
relay ensures a total operating time of                                                                is on the bus and it is cleared by tripping
                                                       of protection elements of multifunctional
about two cycles.                                                                                      the source breakers with signals (2).
                                                       relays on healthy feeders. Detecting the
The benefit of this scheme is that instead             operation of a relay on adjacent feeder         The conventional implementation of

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                                                                                 TRANSMISSION AND DISTRIBUTION
this scheme is based on the use of the                         Functional testing Of IEC 61850-8-1 and          function being tested. For example, if
normally closed contact of an output                           IEC 61850-9-2 based bay and substation           the tested function is based on RMS
relay that closes when the relay fails.                        level distributed applications                   values or phasor measurements, the
This implementation requires hardwiring                                                                         simulation tool may include a sequence
                                                               The testing of distributed protection            of steps with the analog values in each
between all feeder relays and the
                                                               functions that are based on IEC 61850            of the steps defined as phasors with their
dedicated opto inputs of the transformer
                                                               Goose are similar functionally to the            magnitude and phase angle. Based
relay. The IEC 61850 Goose repetition
                                                               testing of hardwired schemes. The main           on these configuration parameters the
mechanism can be used to eliminate the
                                                               difference is that in this case the test         simulation tool will generate the sine
need of the above described hard wiring.
                                                               devices need to be able to act as                waveforms to be applied as analog
If the transformer protection IED subscribes
                                                               IEC 61850 devices, i.e. to be able to            signals or in a digital format to the tested
to Goose messages from all feeder
                                                               publish and subscribe to Goose messages.         components or systems. If the tested
protection IEDs, within the maximum
                                                               If the distributed scheme includes devices       functions are designed to detect transient
repetition time interval it will receive a                                                                      conditions or operate based on sub-cycle
                                                               located remotely from each other in the
Goose message from all healthy IEDs.                                                                            set of samples from the waveform, an
                                                               substation, we may need multiple test
If one of the feeder protection IEDs fails,                    devices with virtual simulators or analog        electromagnetic transients simulation will
it will stop sending Goose messages. This                      outputs. The simulation of the substation        be more appropriate.
will cause the enabling of the selective                       and system environment required for the          The third component of the test system
backup trip logic in the transformer                           functional testing of bay and system level       is the Virtual IED simulator that is used to
protection IED.                                                functions will require the simulation of         represent components of the system that
                                                               multiple IEDs.                                   are not available at the time of testing,
Breaker failure protection
                                                                                                                for example during factory acceptance
Breaker failure protection is a scheme                         A test system designed for IEDs or distributed   testing. During the testing this module
that is typically used at the transmission                     applications based on IEC 61850 have             send Goose messages that the function
level of the system due to the impact of                       multiple components that are needed              or sub-function under test uses as inputs
such event on the stability of the electric                    for the testing of the individual functions,     that determine its behavior under the test
power system. With the availability of built                   as well as a complete application. A             conditions applied.
in breaker failure protection function in                      simplified block diagram of such a system
many multifunctional protection IEDs and                       is shown in Fig. 9.                              The fourth component of the test system
the increasing requirements for decrease                                                                        is the test evaluation tool that includes the
in the duration of distribution faults. The                    The first component of the test system           monitoring functions used to evaluate the
distributed breaker protection scheme                          is the test configuration tool. It takes         performance of the tested elements within
can be implementation using two different                      advantage of one of the key components           a distributed sampled analog value based
approaches depending on the location                           of the IEC 61850 standard – the substation       system. Such evaluation tool requires
of the breaker failure detection element.                      configuration language. The configuration        multiple evaluation sub-modules that
                                                               tool is used to create the files required for    are targeted towards the specifics of the
I n t h e f i r s t c a s e t h e b r e a ke r f a i l u r e   configuration of different components            function being tested. In our case they are
protection element is in the multifunctional                   of the test system. It imports different         based on monitoring the Goose messages
transformer protection relay. When the                                                                          from a tested IED.
                                                               configuration files defined by part 6 of
distribution feeder protection relay
                                                               IEC 61850. The test system Configuration         The fifth component of the test system is
operates, it sends a Goose message
                                                               Tool reads the information regarding             the reporting tool that will generate the test
indicating the change of state of any of
                                                               all IEDs, communication configuration            reports based on a user defined format
the protection functional elements.
                                                               and substation description sections. This        and the outputs from the simulation and
The transformer protection relay subscribes                    information is in a file with. SCD extension     evaluation tools.
to this message, and when it receives the                      (for substation configuration description)
change of value of a feeder protection                         and is used to configure the set of tests to     Conclusions
functional element operate data object to                      be performed.                                    The application of IEC 61850 Goose
True, initiates the breaker failure protection                                                                  messages allows significant improvements
function. If the breaker fails to trip, the                    The overall functionality of any IEC 61850
                                                                                                                in the protection of distribution substations
fault current will keep the level of the                       compliant device is available in a file that
                                                                                                                that reduce fault clearing times and
current above the pickup setting of the                        describes its capabilities. This file has an
                                                                                                                minimise the effect of short circuit faults
breaker failure detection element, the                         extension .ICD for IED capability description.
                                                                                                                on sensitive loads. Using such high-speed
timer will time out and the relay will trip                    The IED configuration tool sends to the          messages eliminates the need for multiple
the required breakers to clear the fault as                    IED information on its instantiation within      hard wired connections. In some cases
shown in Fig. 8.                                               a substation automation system (SAS)             the implementation of a hard-wired
Another implementation of the scheme                           project. The communication section of the        distribution protection scheme (such as
is based on a built-in breaker failure                         file contains the current address of the IED.    sympathetic trip logic) in a large substation
protection in each of the distribution                         The substation section related to this IED       requires also that all protection IEDs have
feeder protection IEDs. In this second when                    may be present and then shall have name          a significant number of binary opto inputs
the distribution feeder protection relay                       values assigned according to the project         and relay outputs. The publisher/subscriber
operates, it initiates the built-in breaker                    specific names. This file has an extension.      mechanism used with Goose messages
failure protection function. If the breaker                    CID (for configured IED description). The        eliminates this problem.
fails to trip the breaker failure protection                   second component of such a system is a
function will operate and send a Goose                         simulation tool that generates the current       Acknowledgement
message indicating the change of state                         and voltage waveforms. The specifics             This article was presented at the 2010
of this protection functional element. The                     of each simulated test condition are             S o u t h e r n A f r i c a n Po w e r p r o t e c t i o n
transformer protection relay subscribes                        determined by the complete, as well as           Conference, Gauteng November 2010
to this message, and when it receives                          the configured functionality of the tested       and is reprinted with permission.
the change of value of a breaker failure                       device or application.
protection function element Operate data                                                                        Contact Alexander Dierks, Alectrix,
object to True, will trip the required breakers                The simulation tool requirements will also       Tel 021 790-1665,
to clear the fault as shown in Fig. 8.                         be different depending on the type of            alexander.dierks@alectrix.co.za 

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