IEDs Expand Substation Automation Capabilities
By William Ackerman, ABB Power T&D Inc.
Substation automation is not a new concept. Substations have been equipped to perform automatic reclosing, automatic bus sectionalizing, automatic load transfers, automatic capacitor switching and many other functions for many years. In the past, however, these and other functions were implemented using a combination of control panels, auxiliary relays, switches, lights, meters, transducers and extensive wiring and cabling.
In many applications today, substation automation is perceived as being something “new.” This perception is probably because equipment developments have expanded substation automation capabilities far beyond previous accomplishments.
The principal development is generically defined as an intelligent electronic device (IED) which typically consists of one or more microprocessors and communications ports; with the ability to transmit data and execute control commands, and frequently provide a local user interface. Typical examples are relays, meters and specialized sensors.
What Makes Substation Automation “New?”
Prior to the introduction of microprocessor-based relays, the protection and control of a very small substation consisting of one incoming line, one transformer and two feeders would require four large panels filled with relays, switches and lights. Only one panel is required when microprocessor relays are used. Interestingly, at the same time the space requirements are reduced by a factor of four, so is the installed cost.
Advances in communications technology are used to tie everything together into a useful network. Within the substation, a single high-speed local area network (LAN) is used to transmit data and control commands, replacing the extensive and costly cables that had been required. At the present time, a number of different LAN techniques and protocols are in use.
There are already many techniques for moving data out of the substation to a master station or to other substations. These include the use of leased or dedicated telephone lines, dial-up phone lines, cellular telemetry techniques, satellite transmissions, various radio techniques and fiber-optic networks. Basically, this variety of communications methods results in the ability to transmit large amounts of information at a rapidly declining cost per bit.
The combination of microprocessor-based devices and communications technology creates the ability to obtain more information about the power system and the equipment being used. Besides power system real-time variables, information is available regarding the initiating event for relay operation, the location of faults and fault analysis. Specialized sensors and transducers are used to build a database relating to equipment condition and use; so that analysis techniques can be used to determine equipment condition and/or base maintenance activities on actual condition rather than time schedules.
Within the substation, the use of programmable logic controllers or other types of computers opens up a vast array of automation possibilities. Complex schemes for dead bus and dead line reclosing can be implemented, with the sequence being based on actual power-system conditions that exist at the time. Reclosing circuits can be modified based on cold-load-pickup requirements. Load transfers between busses and transformers can be made to protect against transformer overloads. Bus voltages and power factors can be tightly controlled to minimize losses or voltage variations. Supplementary measurements and inputs can be used to re-energize automatic equipment after a transformer or bus differential.
What`s Driving Substation Automation?
Utility industry deregulation is creating a situation where utilities must automate and acquire more information in order to remain competitive. Reduced costs of installing, operating and maintaining the utility plant is a major objective. There are significant and quantifiable cost savings that can be achieved through the use of substation automation. Somewhat less tangible objectives include improved efficiency, improved system reliability, improved power quality and improved customer service. All of these items, in one or more ways, will be important in customer retention.
Open access, sometimes referred to as wholesale and retail wheeling, creates a number of requirements for additional information about the power system. The objective of open access is to maximize the electric power system`s capabilities without violating any stability or equipment operation limits. Some states and the federal government are mandating the use of independent system operators (ISO) to control the operation and use of the power system in a safe and reliable manner. The ISO uses computers and complex software to perform real-time calculations of transmission capacity, stability, contingency identification and evaluation and operating costs. All of these programs, however, are based on the use of power system data from the substation. It is evident that if the quality and quantity of available substation information is inadequate, then the results of the calculations will be less precise, thereby requiring greater “safety margins” to be applied. It can be expected that the ISO will demand more and better data in order to ensure that maximum benefits of open access are obtained without creating undue risk of blackouts or other system operating problems.
Protective devices` operating settings are typically established based on short-circuit calculations made at various system load levels. It is impossible for these calculations to include all possible conditions on the power system; consequently, compromises have to be made. There is no inherent reason why relay settings cannot be re-calculated based upon any significant change in power system conditions. These settings could then be automatically loaded into the relays as appropriate.
Open access creates the necessity to establish prices for various services. For example, in the past, system operators would allow loads in excess of nameplate to persist on transformers in order to avoid interruptions or lower quality of service to customers. Depending upon conditions, these excess loads would result in a statistical decrease in the transformer life. With open access operations, the owning utility would charge the wheeling entity for this loss of life. In order to do so, however, it will be necessary to have an appropriate database of supporting information. Technology already exists to measure and quantify the various parameters that influence transformer life. A substation automation system can accumulate this data for further analysis and use.
In like manner, sensors and transducers can be included in substation apparatus such that maintenance can be performed on an as-needed basis, rather than on a scheduled basis. In fact, it should be possible to develop analysis procedures that would allow failure prediction and remedial action prior to the actual failure.
What is a Substation Automation System?
Today, a major function of the substation automation (SA) system is to provide SCADA RTU functionality. Essentially, this means concentrating data from the substation IEDs into one or more messages for transmission to the master station. Often, this can include protocol translation when collecting data from different IEDs. Typically, the SA system will include a local user interface for data monitoring and control, and a local database of real time and other data. Some systems include complete alarm and event processing, and data access and control for non-real-time information such as fault records, event records, oscillography, relay settings and load profiles.
The SA system will normally have a high-speed LAN to support local automation functions that are typically programmed into the SA system itself. Or, they are done using programmable logic controllers. To the extent possible, the LAN will provide peer-to-peer communications between devices in the substation. Once significant processing power in the form of a SA system is introduced into the substation, it becomes possible to support “beyond-the-fence” automation such as feeder and load transfers within the same substation or between substations; or feeder reconfiguration schemes that can minimize customer interruptions, improve power quality and achieve maximum utilization of installed equipment.
At the present time, there are two IEEE trial-use recommended protocols for interfacing IEDs to a RTU–IEC 870-5 and DNP 3.0. DNP 3.0 is based on IEC 870-5 and is probably the most widely used. It was originally developed as a protocol for communications between SCADA master stations and RTUs and is rapidly approaching the status of a “de facto” standard for such applications. There are a number of different protocols being used for communications within the substation; some being `open` and others being proprietary. Modbus Plus is commonly used for high-speed applications; while ASCII (generally viewed as very slow speed) is almost universally available for access to any IED.
There is a very active movement, sometimes called the LAN Initiative, in the utility industry to develop a common, high-speed protocol for all uses within and between substations. There are two major objectives of this work. The first is to define a LAN that can transmit about 70 protective device commands between substation elements in less than one-fourth cycle, in addition to all of the other data traffic that might exist. The second is to define structured elements of a protocol such that devices and data are self-identifying, so that the concept of “plug-and-play” becomes a reality.
Substation Automation and Data Volume
Figure 1 illustrates the two connections for a traditional SCADA-RTU data gathering system and for implementation of an IED. The table in Figure 1 indicates the type of data available from each connection.
In addition to real-time data, the IED can provide sets of maximum and minimum values of currents, kW and kvar, consisting of magnitudes, dates and times. Finally, non-real-time data available includes up to 32 fault records, 128 operations records, 3,840 load profile records and over 14,000 waveform samples. Considering real-time values only, the numbers in Table 1 would apply to a 10-feeder substation, not even counting incoming lines or transformers. Even by ignoring all other data, the potential data to be transmitted and the SCADA database are at least 10 times larger when IEDs are used as the data source.
It is standard practice to perform a detailed end-to-end check to verify that all variables in the SCADA database are correctly linked to displays, have the correct limits and that the correct substation devices operate when selected by the dispatcher. Typical test techniques involve a technician at the substation causing a specified value to be transmitted to the SCADA master station. The complexities of getting an IED to generate the desired test result, especially in light of the increased amount of data, requires a different method for performing the tests. New IEDs will allow a technician, or a remote program, to inject a numerical value into the communications registers of the IED, and that value is then transmitted to the SCADA master. Using these techniques will make it possible to check out the SCADA database in a rapid and efficient manner.
It`s Not All Bad News!
There has to be a purpose and objective behind all the effort to utilize the increased data. Typically, more data allows the application programs to be more accurate in their results. This is not only desirable, it may be essential, in order to cope with the problems associated with open access and open wheeling. Utilities should be able to do a more precise job of contingency selection and evaluation. Contingency avoidance techniques can be optimized for minimum cost or risk. The contingency analysis program could include remedial action recommendations as part of the solution. New techniques may make real-time voltage and system stability calculations a reality.
Finally, the advent of IEDs makes the goal of corporate-wide access to data a reality. New methods for accessing this data appear to be moving towards the web browser techniques. The only serious problem is that of secure access. If access to the IED database is via a SA system, firewalls and other security techniques can be incorporated into the SA system to provide a good level of security.
William Ackerman has over 30 years experience as a supplier and a user of SCADA, EMS, DMS and substation automation systems. He is currently ABB Power T&D Company, Power Automation & Protection Division`s substation automation systems manager.