Journal of Power and Energy Engineering, 2014, 2, 191-200
Published Online September 2014 in SciRes.
How to cite this paper: Tan, J.C., Zhang, S.X., Mo, J., Xiong, X.P., Liao, B.L. and Zhang, C. (2014) Dynamic Testing of an IEC
61850 Based 110 kV Smart Substation Solution. Journal of Power and Energy Engineering, 2, 191-200.
Dynamic Testing of an IEC 61850 Based
110 kV Smart Substation Solution
Jiancheng Tan, Shuxian Zhang, Jun Mo, Xiaoping Xiong, Bilian Liao, Chao Zhang
Smart Substation Technologies and Applications Lab, Guangxi University, Nanning China
Received August 2014
This paper presents the dynamic simulation and testing to verify the smart substation solutions
designed for a brown field 110 kV retrofitting project. An IEC 61850 based aotomation design,
transitioning the conventional substation into a smart substation, where existing current/voltage
transformers remain in service, and smart Field Apparatus Interface Units (FAIUs) are utilised to
bridge the conventional primary system to the IEC 61850 based secondary system. While outdoor
switchgears and field instrument transformers are equipped with FAIUs, MV indoor switchgears
are installed with IEDs mounted on the top. Direct point-to-point connections serve as process
buses, and a single PRP/RSTP LAN is employed at station bus level. Extensive dynamic simulation
and testing were conducted in the Smart Substation Technologies Lab, and test results show the
smart substation performance meets and exceeds the substation reliability requirement.
Process Bus, Station Bus, GOOSE, Digital Substations, Smart Substations, Parallel Redudancy
1. Introduction
At present, China is undergoing the development of a large-scale strong solid power grid. The complexities of
power systems associated with various operational modes, demands smart and intelligent apparatus, and more
efficient information exchange at all levels. New substations should be built in a new way, in order to facilitate
easy engineering, shorten installation and commissioning time, and be capable of performing incremental up-
grades in the future in a flexible and robust way. The new national-wide initiative for smart substations aims at
tapping to the latest technology available for innovative solutions [1] [2].
The global standard IEC 61850 facilitates seamless information exchange between apparatus and the network
based secondary system. Moving towards an information highway for protection, control, automation and beyond,
opens up a world of opportunities in engineering, construction, commissioning, operation and maintenance. With
the ample proof of its significant savings incurred in thousands projects world-wide [3]-[5], IEC 61850 based
smart substation solutions are proven to be viable and cost effective [6]-[8].
This paper investigates an IEC 61850 related smart substation solution, where intelligent field interface units
(FAIUs) are employed to transfer conventional current/voltage transformers and outdoor switchgears into smart
J. C. Tan et al.
apparatus. The FAIUs are of merging unit modules, integrated with RTU and communication functions, which
acquires the analog current and voltage signals, digitizes them into IEC 61850-9-2LE sampled value streams, and
transmits them over the dedicated point-to-point connected process buses. The field apparatus interface units
(FAIUs) are of rugged modular design, configurable Sampled Value (SV) and GOOSE datasets, supports up to
eight 100mbps FX ports, thus are flexible, robust and versatile for field deployment. At the station bus level, a
single substation LAN is designed for protection signaling, SCADA control and remote access, where parallel
redundancy protocol (PRP) and rapid spinning tree protocol (RSTP) are used to ensure reliable data transmission
with guaranteed delivery of mission critical and time stringent protection signals.
The 110 kV/10 kV smart substation demonstrates the use of FAIUs for sampled value streams over the pro-
posed process bus, and for GOOSE applications over the substation LANs. A complete secondary system is
constructed in the Smart Substation Technologies Lab, Guangxi University, where Real Time Digital Simulator
(RTDS) is used to model the primary system of the substation equipment. Current and voltage signals from the
relaying points from RTDS are amplified to the true secondary level and injected onto the FAIUs and relays under
testing, with statuses of indoor and outdoor switchgears from the RTDS hard wired to the FAIUs and relays.
Decisions from the secondary system, i.e. either the FAIUs or relays are fed back to the RTDS, and the late con-
tinues simulating the power system in real time until it reaches a new steady state or have lost stability. A RTDS
batch test program for automatic testing and recoding is developed in the lab, which repeats the same test for a
pre-set 100 times. While during the tests, a traffic generation device hosted in the engineering station generates
network traffics and injects them into the station bus LAN, to flood the substation communication infrastructure.
Test results were plotted to verify the proposed solutions under various background traffic conditions.
Extensive tests were conducted in the lab. Analyzing the recorded test results, no package drops were observed.
Sampled value streams and GOOSE tripping over the LAN is proven to be fast, reliable and not affected by the
background traffic over the proposed substation LAN, where dedicated point-to-point connections are utilized at
process bus level, which contain the process bus traffic into where absolutely required, and a single PRP/RSTP
LAN for multicasting GOOSE messages, SCADA applications and remote access etc, and is proven to be robust
and reliable.
2. Overview of 110 kV/10 kV Substations
The 110 kV/10 kV substation is of eight indoor switchgear feeders connected onto two separated busbars. The
two bus sections are connected via a normally closed bus sectionaliser. A transfer bus with a bus coupler dedi-
cated for maintenance related tasks is installed but not shown in Figure 1. While the 10 kV indoor switchgear
F1_50A F2_50A F3_50A F4_50A F5_50AF6_50A F7_50AF8_50A
10 kV
110 kV
110 kV
50BF1 50BF2
Figure 1. 110 kV/1 0 kV substation arrangement.
J. C. Tan et al.
system is within the control building, the 110 kV lines and transformers are outdoor in the switchyard. Each 10
kV bus section is supplied by a 110 kV/10 kV, 25 MVA transformer with a two (2) cycle breaker on the HV side.
There is no circuit breaker but a motor driven disconnect switch at the 10 kV side.
Distributed generations (DGs) are tapped onto the 10kV feeders. As observed in Figure 1, if a fault occurs on
T1, or on Bus1, fault isolation requires tripping the associated HV breaker, the bus sectionaliser, and all feeder
breakers connected on Bus 1. Thus, integrated dual redundant transformer and bus protection schemes are ap-
plied, and each 110 kV breaker failure protection is a standalone single breaker failure (50BF) relay hard wired
from all digital and non-didgital relays tripping the breaker. Upon detection of a breaker failure, the 50BF will
initiate the trip to all electrically connected breakers, as well issue direct transfer trip (DTT) signals to the re-
mote substations where lines are directly connected with the fauty breaker. No 110kV line protection is applied
in this case.
2.1. 10 kV Feeder Protection
A feeder relay provides feeder protection and the associated controls, is configured to receive GOOSE trip sig-
nals from the 110 kV 50BF relay and the transformer/bus relays to trip the feeder breaker upon a breaker failure,
transformer or bus fault.
The feeder relay will issue a GOOSE signal to the associated bus relay upon detection of a fault, a motor start
up or load encroachment condition. The feeder relay will also issue a GOOSE trip to the Bus relay if a breaker
failure condition is detected. The following GOOSE publications are applied
Feeder fault GOOSE Blocking;
Feeder downstream motor start-up GOOSE Blocking;
Feeder load encroachments GOOSE Blocking;
Feeder breaker failure Bus GOOSE Trip.
2.2. 10 kV Bus Protection
Medium Voltage Switchgear 10kV Bus protection is designed with a fast bus protection scheme, and a coordi-
nated time overcurrent scheme in parallel. The bus relay trip decision is delayed for a pre-set four (4) cycle de-
lay in the fast bus scheme, and a minimum 300ms delay time in the coordinated overcurrent scheme. The fast
bus protection scheme was a hard wired approach, simple in principle, easy to expand, but requires information
exchange between multiple devices. The complicated hard-wiring is error-prone, and tremendously increases the
installation and maintenance costs. In this application, wiring between the bus and other relays are removed, and
GOOSE messages are employed, with the blocking time delay reduced to two (2) cycles. Upon a Bus fault, a
GOOSE BF Initiation will be issued to the 50BF relay, and reclose of the feeder breaker is prohibited. While the
hard wired solution requires two seperated connections, a single multicasting GOOSE Bus Trip signal is suffi-
cient to serve all.
The following GOOSE messages are configured to receive:
Feeder 1 Fault/Start-up/Load Encroachment GOOSE Blocking;
Feeder 2 Fault/Start-up/Load Encroachment GOOSE Blocking;
Feeder 3 Fault/Start-up/Load Encroachment GOOSE Blocking;
Feeder 4 Fault/Start-up/Load Encroachment GOOSE Blocking;
Feeder 1 Breaker failure GOOSE Bus Trip;
Feeder 2 Breaker failure GOOSE Bus Trip;
Feeder 3 Breaker failure GOOSE Bus Trip;
Feeder 4 Breaker failure GOOSE Bus Trip.
2.3. Transformer Protection
Protection of the 110 kV/10 kV transformers is provided by dual differential schemes. Upon detection of a
transformer fault, a GOOSE BF initiation signal is issued, and cancel reclose GOOSE message is send to pre-
vent the breaker being reclosed. The following GOOSE messages will be published:
Transformer fault GOOSE BF Initiation;
Transformer fault GOOSE cancel recluse;
J. C. Tan et al.
2.4. 50BF Protection
The breaker failure 50BF relay will issue GOOSE BF trips to open the 10 kV feeder breakers upon detection of
a breaker failure condition, as well sends direct transfer trip signals to the remote line ends relays. The 50BF re-
lay receives the following BF initiation signals from digital relays:
Transformer/Bus A relay GOOSE BF Initiation;
Transformer/Bus B relay GOOSE BF Initiation;
Non-digital relay hard wired Initiation.
All digital relays are configured to receive the associated switchgear GOOSE status messages, and report to
the Gateway/HMI for SCADA applications. Station wide controls are implemented using the HMI single line
diagram graphic interface.
For outdoor switchgears, field apparatus interface units/boxes (FAIUs) are used to transfer the conventional
current and voltage transformers and circuit breakers into smart apparatus.
3. Field Apparatus interface Units
The field apparatus interface unit (FAIU) serves as the interface units between primary systems in the switch-
yard and secondary systems in the control building. As illustrated in Figure 2, the FAIU units are equipment
with two analog modules, hard wired to conventional current and voltage transformers, as well switchgears such
as breakers and disconnect switches in the switchyard. Connections to the secondary IEDs in the control build-
ing are via optical fiber connections. The functional modules of the FAIUs are as below:
3.1. Merging Unit Functions
A merging unit module may equip two analog modules, acquires analog current and voltage signals, and digi-
tizes them into maximum 4 sets of sampled value streams according to IEC 61850-9-2LE. Each set of the sam-
pled value streams is configurable with (4I, 4V) or (4I, 4I) signals, and is independently assigned with the com-
munication ports specified. The following analog modules are available in a FAIU:
4I (5A), 4V;
4I (1A), 4V;
8I (5A);
8I (1A).
IO Module
16I , 24O
A/D Conversions / Data Processing
IEC 61850-9-2-LE
Merging Unit Module
RTU Module
Analog Module 1
4I, 4V
Analog Module 1
4I, 4V
Analog Module 1
4I, 4V
Analog Module 2
Data Processing
IEC 61850-8-1
A/D Conversions / Data Processing
IEC 61850-9-2-LE
Communication Module 1
100mbps, FX, PRP/RSTP, HSR
Communication Module 2
100mbps, FX, PRP/RSTP, HSR
Port1 Port2 Port3 Port4Port5 Port6 Port7 Port8
Figure 2. Field interface unit t.
J. C. Tan et al.
3.2. Remote Terminal Unit Functions
A Remote Terminal Unit module interfaces with switchyard circuit breakers and disconnect switches, is of the
bay control unit function. It acquires the breaker status, processes them as various GOOSE data sets according to
IEC 61850-8-1 and publish tem onto the station bus LAN. Each GOOSE data sets can be configured individu-
ally and can be assigned to specific ports.
3.3. Communication Module
Each communication module is of 4 ports, each port is capable of transmitting the assigned sampled value
streams, and/or combined with GOOSE message transmission, as well receiving GOOSE messages, support
PRP, HSR and/or RSTP redundancy protocols.
The configurable field interface units (FAIUs) are robust, flexible and scalable, serve as key elements in green
field substations installed with conventional CTs/PTs, or for substation retrofitting solutions, where conven-
tional apparatus installed have an average life cycle of 60 years.
4. Substation Architecture
The reliability of the substation architecture is vital to the acceptance of the industry. This is particularly true to
field deployment when time stringent and mission critical protection signals such as sampled values and trip
signals come to play. The reliability of the process bus system not only depends on the merging units and the
process bus relays utilised, the process bus architecture and the associated redundancy protocols supported by
the LAN and the IEDs, will also have significant impact, as well the volume of traffic and their related priority
levels while transmitting on the network.
4.1. Process Bus
Considering an IEC61850-9-2LE sampled value data stream consuming approximate 5mbps bandwidth, at sys-
tem frequency 50Hz and the defined sampling rate of 80 samples per cycle, process bus traffic is of high volume
in nature, and consistent all time, thus must be carefully engineered at the process bus level, and bridge to where
absolutely needed, and provide means of isolation from the mission critical and time stringent protection trip-
ping signals.
Table 1 illustrates the detailed current and voltage configuration and assignments. In this application, dual
redundant field interface units are employed for the transformer/bus protection schemes. Six (6) process bus re-
lays and four (4) field interface units are designated for process bus applications. The protection relays include:
The field interface units are hard wired to acquire the current and voltage signals, as well the status informa-
tion circuit breakers and disconnect switches, and are of the following modules:
Module 1: Merging Unit module;
Module 2: RTU module;
Module 3: Communication module.
Where, the Merging Unit module consists of two (2) 4I, 4V analog modules, and the copper connections with
the current, voltage transformers and outdoor switchgears are as described in Figure 3.
The field interface unit is configured to transmit various sampled value streams for specific protection appli-
cations. A transformer/bus relay will receive sampled values from one single field interface unit, information
received include:
J. C. Tan et al.
Table 1. IEC 61850-9-2le sampled value datasets assignments.
SV Dataset 4 I 4 V
SVT1_12 CT_T1L1A CT_T1L1B CT_T1L1C CT_T1L1G PT_Bus1A PT_Bus1B PT_Bus1C PT_Bus1G
SVT1_22 CT_T1L2A CT_T1L2B CT_T1L2C CT_T1L2G PT_Bus1A PT_Bus1B PT_Bus1C PT_Bus1G
SVT2_12 CT_T2L1A CT_T2L1B CT_T2L1C CT_T2L1G PT_Bus2A PT_Bus2B PT_Bus2C PT_Bus2G
SVT2_22 CT_T2L2A CT_T2L2B CT_T2L2C CT_T2L2G PT_Bus2A PT_Bus2B PT_Bus2C PT_Bus2G
F1_50A F2_50A F3_50A F4_50A
10 kV
110 kV
To Station Bus
To Station Bus
Figure 3. Process bus (partial).
Four (4) Currents from transformer HV bushing CT;
Four (4) Currents from transformer LV bushing CT;
Four (4) Voltages from 110 kV Line PT;
Four (4) Voltages from 10 kV Bus PT.
As demonstrated in Table 2, a field interface unit also supplies current and voltage signals to the breaker fail-
ure relay. No redundancy is required for standalone breaker failure protection.
Data transmitted over a process bus is mission critical. In this application, point-to-point fiber connections
from field interface units (FAIUs) to relays are utilized as process bus architecture, this contains process bus
traffic to where it is absolutely required. This simple architecture design ensures short latency delay, prevents
traffic flooding the LAN. It is simple, robust, easy to maintain, and reliable to operate. The scalability and ex-
pandability of the overall substation process bus applications are inherently achieved by the field interface units
deployment strategies, thus are flexible, robust and versatile for all substation configurations.
4.2. Station Bus
Previous applications for station bus architecture design utilizes rugged Ethernet switches and rapid spanning
tree protocol (RSTP) as self-healing redundancy mechanism. While it is proven to be viable with many indus-
trial applications, it is doubtful that reliability of the Protection/SCADA system may subject to issues, and there
J. C. Tan et al.
is possibility reliability of the system may decline due to complicated routing algorithms and configurations,
which in return may probes more human error during engineering and maintenance stages.
1) Ethernet Switch
Two substation grade Ethernet switches are installed to form up the parallel redundancy network for station bus,
each with 24 × 100 mbps FX ports, 4 × RJ45 100/1000 mbps ports for maintenance and engineering access.
2) Parallel Redundancy Protocol
All IEDs and FAIUs in the secondary system supports PRP/RSTP redundancy, this gurantees no GOOSE
messsage drops, for network architecture design as depicted in Figure 4.
3) VLAN and Priority Tagging
No VLANs are applied. VLAN ID is set to zero. Priority mapping between IEC 61850 and Ethernet Switch
hardware related priority forward is given in Figure 5.
4) Message Priority Assignments
All GOOSE messages transmitted over the station bus LAN are with priority tagging, and are transmitted over
the LAN, potentially available to all IED connected. The priority of GOOSE message assignments are based on
the signal missions inherited, and are listed in Table 3.
All GOOSE messages transmitted over the Station LAN are priority tagged. Other traffic such as SCADA
MMS alarms, remote access, file transfers etc. are dealt with best effort.
The Station Bus LAN employs PRP/RSTP redundancy, requires all IEDs connected support the PRP protocol.
Minimum switch configuration is required, simple, easy and straightforward.
5. Solution Evaluation
A fully functional secondary system with all protective relays, substation Gateway to SCADA, and HMI for
alarm processing and station wide control of the 110 kV/10 kV substation as depicted in Figure 1 has been de-
veloped and constructed in the Smart Substation Technology LAB of Guangxi University.
The real time digital simulator (RTDS) models the detailed apparatus including the two 110 kV transmission
lines transformers, circuit breakers, current and voltage transformers etc. in the 110 kV/10 kV substation, and
grid beyond the two 110 kV lines are modeled using simplified grid models and equivalent sources at both ends.
Table 2. Field interface units assignments.
Protection SV1 SV2 FAIU
T1_87A/Bus1_50A SVT1_11 SVT1_12 FAIU_T1A
T1_87B/Bus1_50B SVT1_21 SVT1_22 FAIU_T1B
50BF1 SVT1_21 FAIU_T1B
T2_87A/Bus2_50A SVT2_11 SVT2_12 FAIU_T2A
T2_87B/Bus2_50B SVT2_21 SVT2_22 FAIU_T2B
50BF2 SVT2_21 FAIU_T2B
F1_50A F2_50A F7_50A F8_50AF8_50A
Field Apparatus Interface Units
Field Apparatus Interface Units
Process Buses
Control Building, Station Bus
HMI GatewayEngineering
Process Buses
Figure 4. Substation LAN Architecture.
J. C. Tan et al.
IEC 61850 Priority Mapping
7 4
6 4
5 3
4 3
3 2
2 2
1 1
0 1
Figure 5. Priority mapping between IEC 61850
and Ethernet Switches.
Figure 6. RTDS test setup.
Table 3. Message priority assignments.
Message Priority
Tripping 7
BF Tripping 7
BF Initiation 7
Reclose Initiation 5
Reclose Blocking 5
Open/Close 5
Switchgear Status 3
Alarm 3
Other Network Traffic Best effort
J. C. Tan et al.
The RTDS simulates the power system normal and fault conditions. Currents and voltage signals at the relay-
ing points are outputted to the amplifiers, which are scaled to the true secondary level and injected on the field
apparatus interface units (FAIUs) and indoor switchgear protective relays under testing, and the responses from
the feeder relays and field interface units (RAIBs) are fed back into the RTDS, which open/trip the circuit
breakers in real time, while the simulation continues, until the power system under study reached a new steady
state operational point, then starts the next round simulation. The RTDS dynamic simulation and testing con-
figuration is given in Figure 6, and a RTDS batch test program is developed which enables the test to be re-
peated as pre-defined. A RTDS batch test program is developed which enables the test to be repeated as
pre-defined. A total one hundred (100) tests are configured to verify the performance of the proposed smart sub-
station solutions under various background traffic conditions.
A traffic simulation software developed by the university is hosted in the engineering station, which generates
the pre-configured multicasting/unicasting traffic and injects onto the station bus PRP/RSTP LAN, where the
secondary system under testing. The multicasting traffic is set with various priority tags, and is intended to flood
the LAN under test.
Figure 7 demonstrates the trip times recorded for a Bus1 A-G fault with 0.01Ω fault resistance. The back-
ground traffic injected onto the station bus LAN under each test is given in Table 4.
Analyzing the above test results recorded, the following are observed:
1) Bus 1 relays detect the A-G fault in 12 ms - 20 ms, with the first relay decision time recoded, and the sec-
ond discarded.
Trip Time Recorded
Bus 1 A-G Solid Fault
No. of Tests
Figure 7. Trip times recorded for 100 RTDS tests.
Table 4. Preconfigure traffic injection.
Test No. Multicast Unicast Total
Start End Volume (mbps) Priority mbps (%)
1 1
2 5 10 5 20 30
6 10 10 6 20 30
11 15 10 7 20 30
16 20 15 5 40 45
21 25 15 6 40 45
26 30 15 7 40 45
31 40 25 5 50 75
41 50 25 6 50 75
51 60 25 7 50 75
61 75 35 5 50 85
76 85 35 6 50 85
86 100 35 7 50 85
J. C. Tan et al.
2) The recoded Bus relays trip decisions are consistent between 52 ms - 55 ms. This reflects the two (2) cycles
40 ms preset time delays to ensure blocking signals from the downstream feeder relays are received.
3) The 110 kV circuit breaker opens generally in less than 100 ms, where two cycles’ breakers are utilized
and simulated in the RTDS.
4) No packagesare dropped off and end point relays. This scenario is not observed throughout the entire batch
test duration.
5) Influence of the background traffic injected onto the LAN on relay trip decisionsis not observed.
6. Conclusion
This paper investigated into the dynamic simulation testing for evaluation of smart substation solution applied
on brown field 110 kV/10 kV substations. The RTDS simulated substation under testing in detail, and the rest of
the power grid is simplified, where a true substation LAN and process buses are constructed with secondary de-
vices and FAIUs connected. The FAIUs acquire the analog current/voltage signals from RTDS amplifiers, and
digitizes them into sampled value streams that multi-casted onto the process bus LAN. Extensive RTDS tests
performed in the Smart Substation Technologies Lab, have shown that the smart solution is viable, robust, meets
and exceeds the reliablity requirement. It is easy to install and maintain, of incremental upgrade advantages,
with performance meets and exceeds the conventional hard wired copper substation solutions.
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