The Antioch Tie: a Lesson in Substation Integration

The Antioch Tie: a Lesson in Substation Integration

By Alex Apostolov, Ph.D., Tasnet Inc., Martin F. Best and David W. Colson, Duke Engineering & Services Inc.

A number of electric utilities in the United States are currently developing integrated protection, control and data acquisition systems. The ultimate goal of such a system is to gather together the wide array of power-system data and make it available on a WAN. Employees are then able to access the data and use it throughout the company`s business processes to increase productivity and add value to products and services.

Duke Power Co.`s vision of an integrated protection, control and data acquisition system has been named PowerNet. In September 1994, the PowerNet Intelligent Electronic Device (IED) team accepted the challenge of selecting and overseeing the installation of a substation integration system at the Antioch Tie Station. After completing a rigorous evaluation of several vendors, the IED team selected Tasnet Inc. to supply the integration system.

By mid-July 1995, the Antioch system was basically operational with most IEDs supplying data to the system. As Duke Power continues to update, modify and evaluate the Antioch system, several lessons learned are worth noting.

System Configuration

Antioch Tie is a 525/230-kV station on the northwest end of the Duke Power system. The station consists of a 525-kV switchyard and a 230-kV switchyard linked by a pair of 525/230-kV autotransformers. Both switchyards are arranged in a breaker-and-a-half configuration.

The new technology required some departures from traditional practice. First, neither panel meters were installed for values of watts, vars, volts or amperes nor was a stand-alone sequential events recorder (SER) installed. Instead, the integration display is the routine source of this information; as backup displays are also available from various microprocessor relays.

All sequence of events (SOE) points are connected to the RTU. The RTU sends to the integration system the point number, time, date, and point status (opened or closed) of any changed SOE point over a data link. The system then adds the appropriate point description and status label (alarm, normal, etc.) to each event and makes the data available locally via video display or printout. Another data port is connected to a second local printer that prints the raw RTU event data. Though not as convenient as the integration system`s formatted event data, this printout remains available for event analysis in case of system failure.

Breaker and transformer alarms are sent from dedicated programmable logic controller (PLC) device annunciators over a fiber-optic loop back to the integration system. However, all traditional alarms are hard-wired to the station annunciator in the standard fashion. The RTU receives its analog data from standard transducers and communicates with the transmission control center in the normal manner. Station switching operations are most easily accomplished through the integration system, but a downsized electromechanical system of hard-wired switches and a mimic panel are installed in case of integration-system failure.

Remote access to integration-system data is provided through a dial-up phone line and the corporate WAN. Both can support file transfers and remote substation control through commercially available remote PC control programs.

Document, Document, Document!

It is critically important that the customer supply the integration system developer with an accurate data and control point list showing names, analog point scaling, event point labels for each state and which state constitutes an alarm. It should also show data items to be placed on the station`s graphical user interface (GUI), along with their screen locations. Likewise, the vendor should be required to provide documentation on all configurable parameters and their options, including such items as IED polling intervals, historical database retention time, system access control and the location of particular system files. To avoid confusion, documentation should also provide directions for changing configuration parameters.

The key to the successful integration of all IEDs into the network is ensuring that the integration system developer has accurate and complete communications protocol and hardware interface information for each IED. The vendor must be able to quickly and conveniently rewrite drivers whenever an IED protocol is changed due to upgrade or replacement. At Antioch Tie, three new IED communications drivers were required within the first six months of system installation because of firmware changes.

The wide variety of microprocessor relays, meters, RTUs and PLCs challenges both customer and vendor to stay current on all firmware and communications software revisions. In the development as well as in the full-scale implementation of substation integration, it is vital to administer version control of software and firmware, including the IEDs, the data acquisition and control (DAC) system, and the GUI. This will continue to be especially important until communication protocol standards for station integration are well established.

Theory Collides With Reality

PLCs are used at Antioch to record the operating and alarm status of each circuit breaker and the 525/230-kV autotransformers. These PLC annunciators are linked over a fiber-optic interface to Tasnet`s network interface module (NIM).

The original design assumed that a relay IED would control a single breaker and obtain its status. Although this is possible with some IEDs and single-breaker arrangements, Antioch Tie has a breaker-and-a-half arrangement.The only relay IED used on a per-breaker basis did not have full open/close control or status input capability. (In a breaker-and-a-half arrangement, all line relaying is associated with both breakers.) This problem was resolved by using the status inputs and control outputs of the breaker annunciator PLCs. The PLC outputs can trip or close breakers for remote control, and the inputs can report breaker opened/closed status.

Experience at Antioch has shown that metering data can be collected from relay IEDs on a reliable basis. The difference between relay IED metering data and RTU (transducer-fed) metering data is instantly calculated and displayed on a GUI screen. It is not yet certain whether this difference, which typically varies between one and six percent, is due to IED inaccuracy or to the fact that relays typically sample the analog signal much faster than transducers. A relay IED operating at a higher sample rate would be more likely to report signal variations than the much slower transducer/RTU combination. In addition, a relay IED is sampling metering quantities at the extreme low end of its dynamic range. Some users of metering data may need samples that reflect signal variations, while others may require a filtered or smoothed presentation of the data. The end users of metering data should define their data requirements so that the proper source can be selected.

The integration system SER function receives raw time-tagged event data from the RTU and attaches appropriate point descriptors and alarm status labels. Since the RTU is time-synched with an IRIG-B signal, all event data is accurately time-tagged to one millisecond.

One drawback to this function is that there seems to be no practical way for the system to print formatted events in real-time. The system supplier has created a print-on-demand feature and an automatic nightly printout of all previously unprinted events. The acceptability of this approach will be evaluated further as station operators gain more experience with the system. Remote access to SER data using a PC remote control program works essentially like local access, although it takes noticeably longer to bring up the event data on the screen. Upgrading the 9600 baud modems to 28.8k baud has greatly improved system response. Remote access through file transfer is available, but not user-friendly. In addition, the SER function lacks a convenient method of modifying point parameters, such as point name, status descriptor and whether an open or closed contact constitutes an alarm.

System Particulars

Initial system development and prototyping can best be accomplished through the use of a system integration simulator equipped with all approved IED types. Proposed changes to hardware, software or firmware can then be tested on the development system before implementation. Specific control problems, such as designing the interlocks between the circuit breakers and the motor-operated disconnects, can be set up and debugged on the simulator before the system goes into the field. The simulator can also double as a troubleshooting aid after system installation, or it can easily be modified for use in prototyping another station.

All IEDs supplying data need an accurate time sync, and data users need to specify their timing requirements. Although some data may not require such precise timing, a separate IRIG-B signal of one millisecond accuracy supplied to IEDs worked well at Antioch. Time-sync commands over the regular communications link were used for those IEDs that could not accept IRIG-B.

Interfacing the integration system to Duke`s WAN was achieved by installing a small router. A hub with a 10BASE-T host connection was added to provide an Ethernet interface to the substation computer. The WAN protocol is TCP/IP.

It is essential to ensure the use of a stable substation computer or controller operating system. To avoid interrupting system operation, it is important to be able to detect error or lockup so that the system can be automatically rebooted. Additionally, the station`s entire computer or controller system software should be backed up on tape or removable disk for quick system restoration in case of hard disk failure or file corruption.

Graphical User Interface

The DAC system polls each IED for selected data and initiates selected control actions. While the GUI cannot directly display the IED configuration or settings, or perform other special programming functions relating to particular IEDs, these IED functions can be accessed by running the particular IED manufacturer`s communications software on the DAC. When the system is placed in the “loopthrough” mode, the user can interact with the IED just as if a dedicated computer were connected directly to the IED and running the IED manufacturer`s custom communications software. It is recommended that future systems be designed to allow additional “built-in” functions, such as viewing IED settings, without having to utilize the “loopthrough” mode.

The GUI should be intuitive to operate so that new service technicians require only minimal training. Most data needs by the typical user should be available through the graphical one-line diagram. The user should be able to start with the “big picture” and easily “drill down” to the needed data.

Some GUI menus will still be needed in order to provide data. These menus should be designed so that the user can easily find information hidden behind the menus. Information intended only for the system administrator need not be quite as accessible as that which is intended for the typical user. Most GUI screens should have a button taking the user back to the previous screen. A button to return the user to the main one-line screen would also be useful.

It is important for the GUI designer to understand any fundamental differences between the customer`s convention and that of the industry. For example, the standard ABC phase rotation of the industry translates to a phase rotation of ZYX on the Duke Power system. Also, some relay IEDs provide metered and fault data in primary values and others provide the same data in secondary values. The substation computer should be programmed to apply appropriate multipliers to the raw data coming from IEDs so that the desired values will be displayed.

Communications Issues

Both the system developer and the user need convenient remote access to the installed system for data collection, troubleshooting and upgrades. This can be accomplished with a remote PC-control program. Corporate users routinely use ReachOut software to establish connections to the Antioch system over both dial-up link and corporate WAN.

Most data is available to any user without having to log onto the system. Access to various levels of control or system reconfiguration is assigned through six authorization levels, providing accountability as well as documentation of control actions or system configuration changes. For example, a relay engineer is given an access authorization level that allows “loopthrough” to the relays, allowing him to change relay settings. A relay engineer does not, however, have access to control breakers, which is reserved for operations personnel. The system also inhibits an unauthorized user from leaving the GUI/DAC application and accessing the controller`s operating system or running unauthorized applications.

Conclusion

The Antioch Tie system is the most extensive substation integration system installed at Duke Power. Lessons learned at Antioch are being applied to the next generation integration system design. However, before the PowerNet project can be fully implemented across the whole Duke Power system, several additional issues must be addressed. These include finalizing the substation controller design, specifying a standardized IED communications network inside the station, and developing an enterprise-wide solution for delivering data to all corporate users. Other challenges on the horizon include selecting a station operating system platform, designing Duke Power`s system object model and managing the data from all substations. The development process promises to be a long one, and the final product may not be exactly what we envision today. The substation integration system at Antioch Tie has been a successful effort, and it will provide Duke Power with a valuable store of experience and lessons learned in the years to come.

Author Bios

Alex Apostolov, Ph.D., is a principal engineer at Tasnet Inc. He has more than 23 years experience in power system protection, control and automation. He is a senior member of IEEE, a member of the Power Systems Relaying Committee and chairman of Working Group I-16: New Technology Related to Transmission and Distribution Protection.

Martin Best and David Colson are senior engineers in the Protective Relay Engineering group of Duke Engineering & Services Inc. (DE&S). A business unit of Duke Power, DE&S provides engineering, technical and professional services specializing in energy and environmental projects to clients worldwide.

Click here to enlarge image

A 230kv `One line` display on a PC monitor.

Click here to enlarge image

Cabinet containing substation integration equipment.

Previous articlePOWERGRID_INTERNATIONAL Volume 1 Issue 4
Next articlePOWERGRID_INTERNATIONAL Volume 1 Issue 5
The Clarion Energy Content Team is made up of editors from various publications, including POWERGRID International, Power Engineering, Renewable Energy World, Hydro Review, Smart Energy International, and Power Engineering International. Contact the content lead for this publication at Jennifer.Runyon@ClarionEvents.com.

No posts to display