Apart from these special devices, indicating and recording meters were always required to be part of a control panel. Power system analysis requirement demanded special measurements like positive, negative and zero sequence currents and voltages. Power Quality Measurements and Demand Side Management schemes needed special intelligent metering devices.
Depending on the importance of the concerned substation in the sphere of overall grid operation, some or all of the above devices are installed in a substation. Many times, it is difficult to collate and correlate the outputs from these several discrete devices. Especially when these discrete devices overlap in their functionality, it leads to few inconsistencies. There was always a need for a common time base, to synchronise and match the outputs from various devices.
Apart from ease of monitoring, the above are some additional driving forces for the development of Integrated Substation Control System (ISCS). This Integrated Substation Control System (ISCS) should also integrate the monitoring and control requirements of Network Control Centres.
Requirements of network control centers
Initially, control centres or despatch centres were established with the primary purpose of coordinating transmission and distribution network operations to ensure system security and personal safety. RTUs were commissioned at the substations to collect data in the form of switch positions, protection indications and voltage, current and other measurements. These RTUs were communicating with a Central Master Station at the despatch centre through a dedicated communication network. Need for Supervisory Control was also met by this system which eventually evolved as Supervisory Control and Data Acquisition System (SCADA). Energy Management requirements of interconnected power systems and the resultant enhanced system security requirements called for the development of the SCADA centres into Energy Management Centres. This resulted in enhancement of the RTUs with additional functionalities. Along with this, requirement of local console at the substation also caused the RTUs to be developed with more intelligence then before. With the advent of PC/Windows based systems, there was a demand for open systems even in the field of process automation. Communication protocols were getting standardised. The need to establish a chronological sequence of events required the time tagging feature in the RTUs with improved resolution times of 1 millisecond. For the same reason, sampling rates of analogue input modules had to be increased. To match the resolution times of 1 millisecond on digital inputs, analogues were required to be acquired by direct AC modules without transducers. Application of DSP technology was resorted to, to generate more analogues from direct measurements of AC currents and voltages. With its technology, it was possible to include energy metering and power quality measurements also in the direct AC analogue modules.
When sampling rates of direct AC analogues could be achieved in the range of 64 samples per cycle (i.e. 3840 Hz), it opened up the possibility of incorporating an oscillography feature within the RTU. Disturbance recording functionality is now a feature that is included in the RTUs of the major suppliers. To improve the throughput and response times, the RTU architecture was modified to distribute the intelligence and processing to the peripherals modules. This gave rise to the concept of Bay Controllers and Distributed I/O modules. Being closer to the process cabling requirements were greatly reduced. Next, logical development was to include protection features into the RTU. Already Bay Controller RTUs are available with basic protection with configurable IDMT settings. Coupling this with the feature of obtaining the sequence components of currents and voltages through direct AC analogue measurements, higher level of protection features is only a small step away. Provision of local master at the substation with a SCADA software and graphic user interface was also achieved to help local operation and monitoring using same facilities as required for remote monitoring. With all this development several special devices at the substation were found redundant, including a conventional control panel. Functionalities of the disturbances recorders, sequence of event loggers and alarm annunciation panels are getting integrated into the RTUs.
Integrated substation control system As discussed in the previous sections, approach to an integrated substation control is already taken up by the suppliers of the SCADA systems at one end, and by suppliers of substation control and protection equipment at the other. This process is summarised in Figure 1. The time has come now to coordinate these independent approaches into a unified approach. The most accepted definition of Integrated Substation Control is "complete local programmable protection, control and monitoring of equipment in the substation".
Following are the devices in the substation, which need to be integrated into the ISCS system.
- Remote terminal units
- Microprocessor-based numerical relays
- Disturbances recorders
- Sequence of events recorders
- Meters
- Voltage regulators
- Transformers tape changers
- Capacitor bank controllers
- Reclosers and timers
- Supplementary interlocks
- Any other PLC or IED based schemes
More and more of the above devices are becoming IED-based. This makes it easier to integrate them into ISCS. When specifying, supplying and manufacturing these IED based devices, capability to integrate the same into an ISCS should be one of the major considerations. The following are the features to be considered.
- Ports for configuration
- Ports for communication
- Real time data exchange
- Physical communication interfaces: serial cable, fibre, etc
- Different modes of communication: RS232, RS 485 etc
- Standard protocols: IEC-870, DNP3 etc
- Communication speeds
- Direct LAN interfaces
- Time synchronising through LAN or direct GPS interface
- Upload/download capability and file transfer
With all the above facilities it will be possible to configure different integrated systems with different domains of functionality. A few examples are as below.
Maintenance and commissioning system
Access is provided to all IED-based devices. Using this system, the maintenance and commissioning engineers will be able to achieve:
- Retrieval of existing settings
· Downloading revised settings
· Altering the alarm limits
· Modifying the description texts
· Diagrams and configurations
· Retrieval of 1. Special measurements, 2. Fault and disturbance records, 3. Event records
· Modify load shedding schemes
- Control of breakers and switches
Monitoring, reporting and archiving system
The system is intended to achieve the following functionalities:
- Central/Local overview display
· Prioritised alarm annunciation
· Periodic/on-demand report generation
· Trending (real-time and historical)
· Archiving and retrieval
Substation control system
In addition to using all the monitoring facilities as in the earlier system, this will also achieve coordinated control of the substation at all levels - at bay level, at Local Master Level and at Grid Control Level. Some of the functionalities may be listed as below:
- Select, check, execute feature for controls of breakers and switches
· Permissive controls based on some interlocking conditions
· Tap changer control
· Set point control
· Sequencing of controls
· Facility to append permit and caution tags to switches to ensure safety.
- Facility to seize controls from and to release control to, other masters and submasters.
Human-machine interface
The Operator Inter-face or the Human Machine Interface is the most important feature of the whole ISCS system. The commissioning engineer, or the operator, or the maintenance engineer or anybody else, who wants an access to the system, needs a convenient user-friendly interface. At the same time, the interface should have sufficient features of security to selectively authorise designated people for the designated functional domains. The data must be presented to the operator in a clear and precise manner without any ambiguity. The present day PCs are very powerful in these areas. Equipped with suitable Graphic User Interface (GUI) and appropriate SCADA software, the PC serves as an advanced means of parameterising, monitoring and controlling the substation. PCs already have a wide choice of communication options and connectivities to LAN. By using the high resolution, full graphic capability as available now, the operator can view the data in many forms such as tables, charts, trends, schematics etc. Some of the more powerful packages can even animate the monitored processes, depending on the data acquired. Most often required features of a good HMI are:
· Windows based operation
· Interaction through key-board/mouse.
· Pull down/pop-up menus.
· Text and graphic displays.
· Alarm management
· Procedure and comment facilities
· Password protection.
- Hardcopy facility
General
A typical single line diagram showing the different components of an Integrated Substation Control is shown in Figure 2. It shows typically how IEDs of different manufacturers are networked with say, a Harris SCADA/HMI system. Figure 3 shows only the architecture of the above system for a clear understanding of ISCS architecture.
Approach to ISCS
Advantages are many in adopting a full integration of all the operation, control and monitoring requirements of the substation into a single, intelligent automation system as proposed by ISCS concept. Before we could propose implementing such systems, we have to deal with several drawbacks emanating from different areas such as:
- Substation design
- Legacy system
- Lack of skills among operation and maintenance staff,
- Lack of expertise at the planning level to be able to justify advanced technologies,
- Lack of parity between cost and quality of power supply,
- Lack of funding and, - Lack of stable management philosophy.
Substations need to be designed with remote operable isolators and earth switches. Numerical IED-based protection should be specified with adequate confidence. The operation and maintenance staff should be given accelerated training in these areas to accept such technological changes. At the planning level, the engineers should be aware of the range of products available and should visit sites where they are applied to gain first-hand knowledge of such products. They should employ experienced and capable consultants to engineer such systems effectively to complete the project justification. Problem of funding may get solved with the proposed re-organisation of electricity boards. Cost justification for this project should be seen in the following areas.
- Power Quality Improvement: voltage control, var reduction, reactor and capacitor switching load transfer.
- Operational Reliability: Better monitoring of system conditions, load management, load shedding fault detection, isolation and restoration.
- Maintenance Scheduling: Better monitoring of breaker and transformer conditions, better fault information and sequence of operation, proactive condition based maintenance.
Avoiding many discrete devices for all the above purposes expected to provide considerable economic justification.
Conclusions
An attempt has been made in this paper to revisit some of the older concepts of substation control and to introduce the new concept of Integrated Substation Control. The evolution of the control philosophy and the control devices towards such integrated concept is described in detail. It is our belief and hope that the utility engineers and managers will get their substations ready for accepting the concept of Integrated Substation Control and thus utility operations towards the 21st century.
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