Electricity Grid Substation Automation
To meet the needs of India’s growing economy, providing reliable, affordable and sustainable energy requires exploring a range of options. One of the most important requirements is reinventing the grid with the introduction of grid intelligence and communication systems for its secure and efficient operation. This paper is an attempt towards grid redesign to meet the requirements of the transforming energy sector in India...
- Er. K S Sidhu
India has significant challenges in the power sector. The country is home to about 25% of the worldwide total of 1.4 billion people who lack access to electricity apart from growing centres of electricity consumption. There is also a massive demand-supply gap aggravated by delays in capacity addition and inefficiencies, especially, in network segments. For fulfilling huge power demands, number of generating stations – hydro, thermal, atomic (conventional) and solar and wind etc. (non-conventional) are being created. Depending upon the availability of resources, these stations are constructed at different places. So, it is necessary to transmit these huge power blocks from generating stations to their load centres. The power transmission system is a complex network. Power generated at voltage levels of 11to 33KV, has to be stepped up to high/extra-high voltages (220/400/800KV-AC) and then again reduced in stages to lowest distribution voltage level of 240/415 volts. Typical power system network is shown in the figure.
For maintaining these voltage levels and for providing stability, a number of transformation and switching stations have to be created in between generating station and consumer ends. These transformation and switching stations are known as substations or grid substations or electricity grids. It is these grids that are required to be developed to achieve reduction in system malfunctions as well as reduction in the meantime to repair. Consequently, outage times shall be reduced leading to a significant decrease in the energy losses.
The electricity grid has grown and changed immensely since its origins, when energy systems were small and localized. With the passing of time, rising electricity consumption, new power plants and increasingly decentralised generation (DG) of electricity from renewable energies require grid expansion. However, simply expanding the grid, as it is constructed now, would be highly inefficient. The wildly fluctuating power feed-in from renewable energies (sun, wind) into the entire power grid occasionally leads to unforeseeable power flows, which can affect grid stability. Furthermore, the liberalisation of the electricity market in India has led to an increase in electricity trading. Short-term trading activities and the associated transmission of electricity over long distances represent an additional challenge for the grid. Due to the nature of the changes, the grid needs to be partially reinvented and automated. Grid intelligence and communication is required for grid operation to meet the requirements of the transforming energy sector. Nevertheless, data measurements from various places and various levels in the grid are necessary to enable the utilities to monitor everything that happens on a real time basis (or to start with, on a daily, hourly or quarterly basis). The utilities then can take actions more accurately, effectively and swiftly, improving the energy services. Electricity grid is shown in the picture.
Present State of Grid Automation
Developed countries have already automated their complete power supply system and their grids are remotely controlled. On the other hand, even after having edge in IT skill, India is way behind in automation. What to talk of existing grid network automation, even the new grids (especially, by states) are being constructed with old and outdated technology without any intervention of automation. Centre Government’s initiative of providing funds for automation & improvement under ARPDC scheme are either unutilized or are invested haphazardly in IT that resulted in issues such as:
• Stand-alone systems-Coverage to limited geographical areas
• Inadequate interface and integration with other applications
• Absence of a standard architecture
• High cost of maintenance
• Basic operations are still manual without inbuilt controls
These issues have adversely affected the returns from IT investments. Incoherent technology strategy leads to situations where incompatible options are selected and large sums of money are wasted in attempts to integrate them. The bottom line is that the business performance has not improved. Power sector expenses and revenue yield is depicted in Fig. 1:
Evidently, fundamental changes are required in the working of the power sector entities. Information Technology (IT) would become the key enabler in the initiatives under the reform process initiated by Government of India. This will enable substantial improvement in the overall health of the utilities.
It is absolutely clear that all the grid substations can’t be automated in all power sector utilities in one go because of the enormous magnitude of the effort and investment required. The approach, therefore, should be to give priority to generation and extra-high voltage level grids, especially, those linking inter-state power systems. Nevertheless, the overall blue print of IT architecture of complete power system network (transmission system in particular) must be prepared and kept in view so that in the final phase all applications must be integrated easily and the hardware requirements are also minimized.
Different phases of automation project are portrayed in Figure 2 (there is no scope to explain these phases in this paper)
Ownership of IT Components
Utilities need to assess to what extent they will buy, deploy and operate the solutions on their own.
The main components to be considered for ownership are:
• Software licenses
• Infrastructure-Network and
• Hardware People and skills.
Substation Automation System (SAS)
In SAS, the various quantities (e.g., voltage, current, switch status, temperature, and oil level) of various equipment are recorded, using a data acquisition device called Intelligence Electronic Devices (IED). IED can establish communication between remote sensors and controllers and the communications network. An IED differs from a Programmable Logical Units (PLC) in that a single IED can control several different aspects of a piece of equipment so that the entire piece of equipment works in harmony with the rest of the needs of the system and within established design parameters.
A key difference between the Remote Terminal Unit (RTU) and the IED, is the same as that of the RTU and PLC, and it is illustrated in the Fig: 3.
In this figure, note that the machine language, and hence the data, moves in both directions, thus, allowing for not only data acquisition, but also control. IEDs receive data from sensors and power equipment, and can issue control commands, such as tripping circuit breakers if they sense voltage, current, or frequency anomalies, or raise/lower voltage levels in order to maintain the desired level. Common types of IEDs include protective relaying devices, On Load Tap Changers, circuit breaker controllers, capacitor bank switches, recloser controllers, voltage regulators etc. These system quantities are transmitted on-line to the remote control room through a variety of communication media. The media could be either wireless or wired. The measured field data are processed in the control room for display of any operator selected system quantity through Graphic User Interface (GUI). In the event of a system quantity crossing a pre-defined threshold, an alarm is automatically generated for operator intervention. Any control action (for opening or closing of the switch or circuit breaker) is initiated by the operator and transmitted from the remote control room through the communication channel to the RTU associated with the corresponding switch or circuit breaker. The desired switching action then takes place and the action is acknowledged back to operator for information.
SAS is dedicated to the monitoring and protection of the critical equipment of a substation and its associated lines or feeders and also generates MIS data, reports and graphs etc from remote control centre, station HMI as well as from local bay controller IED. Traditionally, the functionality of SAS has been logically allocated on three distinct levels called the station, bay and process levels classical hierarchical system architecture.
• The bay level or field bus functionality is concerned with coordinated measurement and control relating to a well-defined sub-part of a substation (usually denoted as a bay - comprises of one circuit breaker and associated isolator, earth switches and instrument transformer). Data that comes from the sensors and is sent to actuators due to the special temporal requirements needed, is transmitted over the field buses. These are buses where operation is done in real time, and are designed to support a high traffic of limited messages in the form of orders and status data. They are buses with low transmission rate and cable length. These buses are typically proprietary one, but lately some open buses have also been developed.
• The process level or control bus functionality is more or less an interface to the primary equipment. Typical functions specified at this level are data acquisition (sampling) and issuing of I/O commands. The communication between process control devices and/or between personal computers with SCADA/HMI application is usually performed over another type of bus, known as control bus. Control buses have higher transmission rates and more relaxed temporal restrictions than field buses; the network reach is also wider than on field buses.
• The topmost station level is the control centre or the information bus with HMI that protects and controls the entire substation and provides linkages to remote control centres. These systems need to deal with a greater data load. These buses are known as information buses. Information buses are designed to support a high load of information, but are more sensitive to data such as status and control messages arrival of which can’t be delayed.
Figure 4 below shows three level network architecture:
Figure 4: Typical buses on SCADA systems
The data exchange between the electronic devices on bay and station level shall take place via the communication infrastructure. This shall be realized using fibre-optic cables. Data exchange is to be realised using IEC 61850 protocol with a redundant managed switched Ethernet communication infrastructure. The communication shall be made in 1+1 mode, excluding the links between individual bay IEDs to switch, such that failure of one set of fibre shall not affect the normal operation of the SAS. The installation of IEDs for control and protection of different equipments at a 132/11KV substation is shown in Figure 5 as an illustration.
Figure 5: Single Line Diagram of a typical 132/11 KV Grid Substation showing IEDs
Abbreviations: OC: over current relay, DOC: directional over current relay, EF: earth fault relay, DEF: directional earth fault relay, BDF: biased differential relay, REF: restricted earth fault relay, BRK: circuit breaker, T1, T2: transformers, IED: intelligent electronic device.
Specifications & Design
The SAS specifications and design must fulfill the following conditions:
• The system should be totally open on its architecture, software, technology and it must comply with the latest standards.
• Operating system software should be industry-standard, off-the-shelf software. It should provide a window based full graphical user interface (GUI) environment.
• The system must include all required communication protocols as part of its library of protocols (DNP3.0, Modbus, IEC-60870-5-101/104 as communication protocol between Host Computers & IEDs & for transfer of data from Grid’s real time database to the existing SCADA system. IEC 60870-5-104 may be preferred to IEC 60870-5-101. IEC-61850 for LAN communications, ICCP, etc.). There should be no need for an external protocol converter (hardware) or internal (third party driver – software). The SCADA/EMS System of the Center and the Information Systems of the State will collect information in parallel from the field and will be able to exchange data by means of a direct link using the ICCP protocol.
• The system should not have any limitation on the type (power line carrier, microwave, optical fibre, VSAT or leased line) or number of communication lines, so it will be capable to handle as many communication lines as needed by the end user whether they are serial or over TCP/IP.
• No additional licensing and software upgrade must be required to increase the number of communication lines for protocols already available on the SCADA systems.
• The system must be able to grow to handle an unlimited number of Intelligent Electronic Devices (sub-stations RTUs, Meters, Protection Relays and Controls etc.), an unlimited number of local and remote operator and engineering workstations, unlimited number of zone groups (areas of responsibility) with ability to enable/disable events and sufficient data; without any need for software or hardware upgrade or expansion or having to pay any additional licence-fee.
• The system must be capable of communicating with other systems/servers such as SCADA, DMS or EMS no matter what type or model those systems are (any vendor) by means of the use of ICCP (Inter Control-Centre Communication Protocol – TASE.2) without any additional license fee or having to expand/upgrade the hardware/software of the SCADA system.
• The system should include Data Exchange facilities that allow to exchange real time, historical, operations and events information to/from any relational databases (i.e. MS Access, MS SQL Server, Oracle, Sybase, etc.), directly from/to the SCADA database. This data exchange capability must be available bi-directionally (to/from the SCADA system).
• The system must be able to notify any alarm condition identified by the system remotely by means of any commercial paging system, e-mail or SMS (Short message Service).
• The system must include tools to exchange any type of information available within the SCADA system (real time, historical, operations, events, etc.). It should include functions of master/slave alarm hierarchy, storm alarm suppression and on line editing. The alarms and events shall be time-tagged with a time resolution of 1 ms. All recorded data from the IEDs with integrated disturbance recorder as well as dedicated disturbance recording systems shall be automatically uploaded (event triggered or once per day) to a dedicated computer and be stored on the hard disc.
• System must be able to generate trend and historical measured and calculated reports on real time and time interval basis (half hourly, daily, weekly, monthly, semi-yearly and yearly) with display facility.
Allowing ease of access for Central and State staff to gather necessary information from anywhere in the electricity network using web services subject to security controls consistent with international standards and best industry practices. In order to support remote control the development of a communication backbone connecting all the substations under the states’ management is a fundamental requirement. Fully digitalized substations, remote terminal units, remote operation and supervision represent the key elements for the success of SAS initiative.
In particular, protocol IEC 61850 to be assumed as a base reference for the allocation of functions and communications, whilst the communication with the remote centre can be performed using protocol IEC 60870-5-104.
Conceptual models of grid substation architecture are also shown in Fig: 6 and picture, highlighting the basic systems and equipment involved; the two protocols used for communication are also indicated.
Enabling geographically-dispersed sites to freely exchange information and messages is a boon to business productivity. However, the data is traveling unprotected over an open network where it is vulnerable to hackers and others. Therefore, cyber security is an important criterion for a secure, efficient and reliable operation of the Automated Grid. The most important goal of cyber security is the protection of all relevant assets in grid substation from any type of hazards such as deliberate cyber security attacks, inadvertent mistakes, equipment failures, information theft and natural disasters. In order to achieve an adequate level of protection, security objectives such as confidentiality, integrity, availability and privacy must be assured by the implementation of security controls.
Reinventing, expanding and interconnecting power grids have proven to be economically desirable. In developed countries, billions of dollars are presently being saved through buying, selling and wheeling power between neighbouring utilities and countries. In India too, electricity is being traded within the states. However, present power systems are based on concepts that haven't reformed much in a century: to generate power, step up the voltage, transmit power, step down the voltage and distribute power. Due to numerous small scale generating plants (DG), upsurge in dependency on electricity and increasing demand of electricity, power system has become intricate and is becoming complex day by day. Limitations of space for electrical installations, rights of way constraints for new line routes, environmental concerns; all demand newer and more advanced alternatives to more effectively manage the power supply system. As on today, with all the latest technologies in place, there is no security of electricity supply; brief and widespread blackouts are possible, albeit rare.
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