1.1 system than the above control panels. The whole

1.1  INTRODUCTION

 

Technology advancement is happening all over the
world and complete world is moving towards digitalization. Substation Equipments
are getting smarter in collecting data and information exchange. Energy
Automation is in transformation stage from partial digitalization to complete
digitalization with the advancement in communication and standards. Traditional
Control panels and complex wiring from process Equipments like circuit
breakers, Current Transformers, Voltage Transformers are now with Fiber Optic
Communication.

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Decentralization is also a topic for today and
tomorrow as cloud computing and Internet of Things technologies are ready to
roar in the Energy Automation and power grids. Pilot projects are happening all
over the world with decentralization concepts with these technologies. On the
other side cybersecurity incidents are happening in the energy environment and
need for awareness and standard implementation for cybersecurity is challenge
in order to ensure the assets and data.

 

Further chapters in this study shall provide
detailed information regarding digital substations and Decentralization in
energy Automation.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

1.2  TRADITIONAL CONTROL PANEL

 

A traditional control panel which were in place
until 2000’s where the field and process equipments were wired to control panel
for monitoring and operation. Single Line Diagrams of substation are made in form
of mimic semaphore indications and control push buttons. Alarm and reset
handling was through indication lamps leaving to a complex maintenance and
troubleshooting issues. Operators need to be there in the substation on shift
basis and all records of measurements, alarms and notable events to be manually
noted in the Maintenance Register. Root Cause Analysis was a challenge with the
available less data in the Maintenance register.

 

 

 

Figure-1 – Traditional Control Panel until early
2000s

 

The modern-day substation control system is a
complete different system than the above control panels. The whole data can be
visualized with the Human Machine Interface(HMI) operator workstations and
Engineering workstations. All Alarms and Events with the data history can be
visualized in the Alarm and Event window of HMI Screens. Control and Monitoring
is possible via keyboards and mouse operation in the HMI PCs. Protection
Relays, Fault Recorders are smarter and communicable to the station controller
and thorough fiber optic communication network with a speed of 10/100 MBPS. In
addition to these, recent development of merger units adjacent to CT/VT ensures
the complete digitalization of data from process bus to station bus.

 

This complete information exchange from process/field
equipments to control center is called as digital substation.

 

Figure 2: Modern Substation Control System.

 

The advantages of digital substation are as below

 

1.    Human
Machine Interaction.

2.    Alarm
and Event Windows with Filtering Facility.

3.    Archiving
Backup.

4.    Simple
FO Cabling -No Complex wiring.

5.    Easy
Maintenance and Trouble Shooting.

6.    Information
Exchange from Process to Station Level.

7.    Better
Decision Making.

8.    Unmanned
substations.

 

Nothing runs with out electricity in this modern
world and no time for breakdowns which will produce economics loss and tensions
around. The major tasks of substation digital automation are:

 

§  To
ensure personnel and operational safety always.

§  To
optimize control and monitoring of the electrical network concerned utilizing
the functions implemented.

 

Operator Workstation, Engineering Workstation and
Station Controllers are Industrial PCs with higher Hardisk capacity and RAM
based on the latest availability. Communications equipments such as Layer-2
Ethernet switches and Layer-3 Ethernet switches (also called as Routers),
Firewalls, Event Printers, Ethernet Patch chords and its connection to
Intelligent Electronic Devices (Protection Relays, Bay Control Units,
Multi-Function Meters etc.) form the station bus.

 

 

1.3 hierachy levels of substation
information exchange

 

The three levels of current substation automation
system is as per the figure (X)below

 

 

Figure(X)

 

Level 1 bay level/ied level

 

At this lower level all CT/PT inputs are hardwired
to Intelligent Electronic Devices (Bay Control Units and Protection Relays) for
upward communication to Substation Automation System and Control center.
Various Feeder status, indications, measurements and metering as well as fault
records are collected with these bay devices and sent to upstream level for
monitoring, control, diagnosis and analysis.

 

Fiber Optic Ring or star topology to ensure highest
level of redundancy is adapted for connection to system. Inter bay
communication and communication to station controller is achieved via IEC 61850
protocol standard for all protection relays and bay control units(IEDs). If any
non-IEC 61850 devices exist, the same shall be communicated via other serial
transmission protocols or hardwired to station controller.

 

Level 2 STATION level

 

At station level the station controller used offers
high flexibility spanning numerous communication protocols including IEC
61850.With reference to UAE projects IEC 60870-5-101, IEC 60870-5-104, IEC
61850, Modbus & OPC protocol are still used and in future all data
integration shall happen through only IEC 61850 Standard. Additionally, this
highly robust system allows for a universal automation system CFC for IEC 61131
standard logic realization.

 

Generally redundant station units working as full
servers are provided at station level with automatic switch over facility
further upstream under HMI level to ensure the necessary uptime is maintained
for control, monitoring and data acquisition. Both servers communicate to
downstream level 1 IEDs via Ethernet LAN using Layer 2 Ethernet switches (IEC
61850 complaint) that are interconnected in cross configuration.

 

HMI Softwares run on windows platform with familiar
drop-down menus as in windows applications. The Redundant computers (Operator
workstation and Engineering workstation) where data archiving, Event., Alarm
handling and data distribution are done from respective downstream station
controllers (RTU/PC Server). This redundant HMI Computers normally equipped
with 2no flat screen monitors, keyboards, mouse ,Event printer together with
laser printer, forms the Front End part of Control. Monitoring and Automation
for the End User at station level.

 

Taking the focus to Engineering and Operator work
station major Visual Diagrams include

 

§  System
Communication Overview Diagram

§  Overall
Voltage Level Single Line Diagram

§  Detailed
views of Individual Bay Wise Diagram

§  Event
list in a Chronological listing

§  Alarm
list with Alarm classification

§  Trend
Analysis Graphical Displays

§   

The figure(X) below shows the connection overview of
various hardware equipments together with their panel arrangement and
communication mediums that represents the substation automation system.
Segregation of voltage level is also done via dedicated voltage level
communication overview buttons and screens.

Fig(X)

 

Communication status of every connected equipment
including IEDs, Monitos,Ethernet Ports is indicated by dynamic color coded line
across the perimeter of every connection block 
with “Red” indicating communication failure and “Green” indicating online
status with good connectivity .Communication failure will also result in a
logged response in the Event and Alarm List.

 

The below figure (X)gives an electrical
representation of the overall system status in the form of single line diagram
that operators are more familiar with. This substation overview screen provides
a summed-up bus and feeder displays with sufficient dynamic switching device
status information necessary for the operator to get an overall system overview
of the station. Additional overview pictures can also be developed for
individual voltage and bay screens which enhance he details to the operator.

 

 

 

Fig(X)

 

The figure (X) shows the display of trend curves
which are available for voltages and currents in every phase together with
frequency, active and reactive power readings. These analog values are
cyclically read from respective IEDs at fixed intervals and graphically
displayed in screens.

 

Buttons with in the frames on the left give access
to individual trend curves for specific bays being studied. Tabulated readings
are also available via access button within each trend window. Other facilities
available include printing, saving and trend freezing via stop button. Bay
related information such as voltages (phase to phase ,phase to ground ,bus
voltage),Three phase currents, Active, Reactive power, power factor and bus
frequency amongst others are all detailed on these screens .

 

 

 

The below figure(X) shows the display of Event and
Alarm processing information via Event and Alarm list configured in Operator
and Engineering Work station. Incoming information from multiple resources
like  below are all accumulated for
necessary operator intervention(in case of Alarms) or for historical records
for future analysis and diagnosis(Event list)

 

§  Feeder
specific Information from individual bay control units

§  Auxiliary
system information -Common station signals

§  System
generated information like login/logout, Equipment failure etc.

§  Time
synchronization information from GPS receiver equipments

§  Configuration
Limit violations from predefined threshold limits

 

By default, all signals received are recorded in the
event list and preconfigured signals with assigned classifications are sent to
the Alarm list.

Interchangeability between these two lists is
achieved via the navigation selection bar at the bottom of the screen.

 

Specifically, to Alarm lists, Operator
Acknowledgement facilities available provide for a systematic approach to
tackle incoming and persistent alarms. Incoming Alarms appear with “Red”
background for immediate operator action. Disappearing alarms take on a “Green”
background. Acknowledged Alarms take on a “Blue” font to indicate recognition
of occurrence.

 

 

 

Fig(X)

 

In general, the following functionality is
incorporated in the above-mentioned screens

 

§  Local/Remote
Status Indication at Bay Level

§  Switching
Operations

§  Periodic
Measurement Monitoring

§  Priority
Alarm Classification

§  Disturbance
record uploading facility with fault analysis

§  Storage
and Archiving Facility via Event list Archiving

§  User
Administration -Password Authorization for various user levels.

§  GPS
Time Synchronization

§  Help
Button

§   

LEVEL 3 -CONTROl CENTER SCADA LEVEL

 

At this level critical signals as per approved SCADA
signal list will be sent to Control Centre for necessary control and monitoring
at SCADA or Load Dispatch Center. Linkup from station controller via IEC
60870-5-104 protocol a tele control ethernet based protocol will be provided up
to dedicated redundant channel interface. This connection will allow for either
Automatic (in case of station controller failure) or manual control center
operator selected switchover if required.

 

Future protocol between substation and control
center shall be IEC 61850 and further research is ongoing to achieve the same.

 

1.4 Process BUS

 

Due to the technological advancement, a new addon to
hierarchy level in communication arrived which is called process bus where
there is no hardwiring CT and VT measurement and signals required at IED level
and the same shall be communicable via merger unit which can be integrated to
IEDs on IEC 61850 protocol. All CT, VT wiring shall be done at switchgear level
itself to the merger unit which an integral part of switchgear. Fiber Optic
patch chords are used to communicate to IEDs (Bay Control Units and Protection
relays) and Station bus. The below figure (X)show the difference in CT VT
hardwire connection and introduction of Process bus communication.

 

 

Figure (X) Process Bus

 

Due to the above implementation from the process bus
to the station bus the information exchange is completely in digital form and
hence these substations are called as digital substation.

 

Merger units with smart communication ports and its
connectivity to IEDs form the process bus. These Station bus and process bus initiating
the information exchange form process to station is called as digital
substation.

 

The whole communication network is fully on ethernet
and digitalization leads to speed and scaling possible at same time. All these
advancements are happening due to introduction of IEC Communication standard
called IEC 61850. Our Hierachy level of information exchange is now adapted as
below figure X

 

 

 

Figure (X) Hierarchy levels for Information Exchange
of Digital Substation

 

 

 

1.5 IEC 61850 STANDARD 

 

IEC 61850 is a standard developed by International
Electro Techno Technical Commission and these standards are followed worldwide
for power transmission and distribution. The arrival of standard open doors for
below advantages in substation Automation

 

§  Modular
Hardware.

§  Variable
system topologies like Ring Topology, Star Topology etc.

§  Parallel
processing of services.

§  High
Interoperability.

§  Standardized
Engineering.

§  Efficient
Service concepts.

§  Disturbance
Fault Retrieval through IEDs.

§  Remote
Parameterization of IEDs via Ethernet network.

§  Interchangeability

 

The Ethernet system interfaces for IEDs as shown in
figure 3 enable a retroactive free communication independent of protective
functions and control functions. Electrical or Fiber Optic port modules are
available, and relays can be ordered depending on the client requirement and
distance limitation.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 Figure 3:
Communication Port Modules for IEC 61850 in a Protection Relay.

 

 

Interoperability is an important feature which
allows exchange of information between IEDs of same vendor or different vendor.
Interchangeability is the ability to replace a device supplied by one
manufacturer with a device supplied by another manufacturer without making
changes to the other elements in the system. However, Interchangeability is
beyond this communication standard but always possible with this type of
Ethernet network.

 

1.6 MAJOR COMPONENTS OF SUBSTATION
AUTOMATION

 

The major components typically used in a substation for information
exchange is as below

 

§  Remote
Terminal Units.

§  Human
Machine Interface-Industrial PCs.

§  Ethernet
Switches -Layer 2/Layer 3.

§  Intelligent
Electronic Devices.

 

 

In addition to the main equipments Communication patch chords, printers, GPS
Antenna, media converters also form part of substation Automation system.

 

     Remote terminal units(rtu)

 

                                Remote Terminal
Units act as a data concentrator for data from process level and IED Level.
Kernel based architecture exists in RTU with an embedded operating system.
Plugin communication and IO modules is used for easy maintenance, scaling and
expandability. The below figure x is a typical RTU which a rack based feature.

 

 

 

 

 

 

 

 

 

 

 

 

 

Figure
X: Typical Remote Terminal Unit.

 

 

Human MACHINE INTERFACE INDUSTRIAL PC(HMI PC)

 

                     A
typical substation automation system consists of an operator workstation and
engineering workstation as a part of Human machine interface. These pcs act as
an interface to the maintenance operator in substation for control and
monitoring realization. All graphical representations are configured in these
PCs.These PCs are normally industry grade handling high working temperature
(approximately 55degree Celsius) and redundant raid configurations and
redundant power supply units. All substation archives shall be stored in this
HMI PCs.  The below figure (X) is a
physical representation of an Industrial PCs with front and rear view.

 

 

 

 

 

 

 

 

 

 

 

 

Figure
X: Typical Industrial PCs

 

Ethernet switch

 

Ethernet switches form the communication network of the
station bus where station level equipments such as HMI PCs and IEDs shall
integrate via this ethernet switches. Layer-2 switches are generally used for
substation network and for exchange of data between dissimilar networks layer-3
switches are required. These Layer-3 switches are called as routers. Integrated
Routers with firewall functionality is used for connection to control center
since control center is of different network with different IP address class
and subnet. The below figure is a typical layer-2 ethernet switch having
modular communication ports.

 

 

Figure(X)
Layer -2 Ethernet switch

These
switches are IEC 61850 complaint and industrially hardened, fully managed
specifically designed to operate reliably in electrically harsh and climatically
demanding utility substation and industrial environments. These rugged hardware
design provides improved system reliability and advanced networking features of
Ethernet.

 

INtelligent iec 61850 ied

 

Bay
control Units, Protection IEDs, Multifunction Meters, Fault Recorders are
called as IEDs – Intelligent Electronic Devices which can transfer data as soft
signal to station level controllers. Bay Control Units are smart IEDs with
graphical display of individual feeder/bays having the alarms, measurement and status
of device representation of primary devices and operation of the primary
devices like circuit breaker and Isolator of the particular bay is possible
through Bay control units. Authority between bay control units and substation
station controller shall be possible via local/remote keys present in the BCUs.
The below figure (X) is a typical siemens make bay control unit

 

 

Figure(X)
Typical Intelligent Electronic Device-Bay Control Unit.

 

Features
of a Typical Bay Control Unit include:

 

Programming
Interface and Function Chart Application

Software
and key switch security mechanism

Calculation
of Metering data

Collection
of Maintenance data

Comprehensive
digital fault recording capabilities

LCD
display providing local control and monitoring of bay

User
definable function keys

LAN
Communication protocol over Fiber optic or electrical media

Synchro
check function

Backup
if main HMI failure occurs at station level.

 

 

 

 

CYBER THREATS & RISKS

 

Though
technology is in advanced mode, at the same related cyber risks and hacking
incidents are happening throughout the globe. The most published
vulnerabilities in critical infrastructure are in the Energy area. The
figure(X) below depicts ICS-CERT responses to sector specific cyber security
threats across the critical infrastructure sectors in the U.S in 2014.

 

Figure (X) Cyber Security
reported incidents in U.S

 

CYBER security

 

It is important that all data transmitted and received are
to be in a secured and environment. Awareness and understanding of cyber security
should be at all levels starting from product level, Solution level and at
operational level. All Communicable products should support
Confidentiality-Integrity-Availability(CIA) criteria and comply to Industrial
standard.

 

The Key standards to be complied are as below

 

          IEC 62443
(System Security)

          IEC
62351(Communication Security)

       

         
IS0 27001 (Security Management)

 

 

Cybersecurity
processes should cover the whole product life-cycle and to foster solution and
operational requirements.

 

 

 

 

 

 

 

CONCLUSIONS

 

IEC 61850 standard provides a uniform method of
communication and integration in substation in an interoperable manner among
multi-vendor IEDs used for bay control, protection, metering and fault record
applications. This standard addresses the migration to digital substation with
the definition of process bus. Research discussions are on board for control
center communication on IEC 61850 which gives the universal choice of protocol
for substations Automation in Utilities and Electrical Industrial sectors.
These digitalization in substation is clearly a future driver for energy world.

 

 

FUTURE SCOPE OF WORK

 

In addition to Digitalization as key future driver for
energy world, my research study will continue for other drivers such as
Decarbonization and Decentralization. Renewable Energy is a vital part of
decreasing global carbon foot prints and the investment pace has greatly
improved as the cost of these technologies drop down and efficiency level
continue to rise. This clearly shows that Decarbonization play a vital role as
a future driver in energy world.

 

Due to effect of Distributed generation, Distribution
Automation and Technology advancement in Internet of Things and Cloud computing
will result in decentralization architecture of Information exchange from the
IEDs directly to server via Internet and Cloud. In this context undoubtedly,
Decentralization shall also be a future driver for energy world.

 

A detailed study in Decentralization and Decarbonization
shall be my future scope of work.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

List of figures

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

REFERENCES

 

1
Roy E Cosse, Harrison T Combs, Martyn A. Hildreth, James E Bowen, Donald G.
Dunn and Alan Pilcher. (2003),” Smart Industrial Substations-A Modern
Integrated approach”, IEEE Paper No. PCIC-2003-08.

 

2
R.E. Mackiewiz. (2006),” Overview of IEC 61850 and Benefits”, IEEE Paper
No.1-4244-0178-X/06 PSCE 2006.

 

3
Brent K. Duncan, Bruce Bailey. (2003),” Protection, Metering. Monitoring and
Control of Medium Voltage Power systems”, IEEE Paper No. 0-7803-7771-0/03

 

4 Tarlochan
S Sidhu, Mital Kumar G. Kanabar and Palak.P Parikh, (2008),” Implementation Issues with
IEC 61850 Based Substation Automation Systems” Fifteenth national power systems
conference(NPSC), IIT Bombay

 

5 David
C. Mazur, Joseph Sottile and Thomas Novak (March/April 2015) “An Electrical
Mine Monitoring System Utilizing the IEC 61850 Standard” IEEE Transactions on
Industry Applications, Vol.51NO.2

 

6 K.
P Brand, C. brunner and W. Wimmer. (2004)”Design of IEC 61850 based substation
Automation systems according to customer requirements” CIGRE session 2004,
reference B5-103