By Gene Grace, Enspiria Solutions Inc., and Jim Bougie, We Energies
Substation automation has been a popularly used term in the industry for years, yet many utilities still use the term loosely to describe little more than a classic supervisory control and data acquisition (SCADA) system encompassing a master station and local remote terminal units (RTUs). As more utilities install microprocessor-based intelligent electronic devices (IEDs) to protect and operate their substations, automation is becoming essential to make the data captured by these IEDs available to the utility enterprise-wide.
The newer, processor-based IEDs provide exponentially more data/information than the previous genre of equipment. Substation automation systems provide a foundation layer for delivering the critical real-time and time-stamped historical data from these IEDs throughout the utility knowledge infrastructure (see Figure 1, page 28). This enhanced substation data availability helps utilities make business and operating decisions more accurately and quickly, and improve the quality of service provided to customers, while maintaining acceptable levels of risk and reliability.
This article highlights financial drivers and justification for substation automation and integration projects, provides architectural guidelines for enterprise-wide substation automation, and presents a solution roadmap for achieving benefits. In addition, it illustrates successful approaches and benefits through systems currently being installed and operated.
Enterprise Substation Automation Benefits
Substation automation, promoted and implemented across the enterprise, brings a number of cost justifications that promise a good return on investment. These justifications fall in three main categories: improved financial performance, improved customer service and improved organizational effectiveness.
Improved Financial Performance. Improved financial performance shows itself in both reduced T&D capital expenditures and reduced T&D operational costs. For example, leveraging the substation automation system to capture real-time power factor data, a utility can readily and accurately control system capacitance, in effect reducing its capital expenditure. Monitoring power factor in real-time not only saves on generation costs, but can significantly reduce generation emissions through a reduced need for power. Similarly, by leveraging serial communications to IEDs at the substation, significant savings are obtained in reduced wiring costs in the control house. Furthermore, through comprehensive use of IED capabilities, the need for substation equipment is often reduced: Auxiliary meters are no longer required, the need for control switches is reduced, and the need for stand-alone annunciator panels is eliminated.
Ongoing operational costs are reduced through substation automation’s ability to provide remote access to IEDs, reducing field-crew “windshield” time for diagnosing devices in the field. In addition, substation automation systems provide operational data that can be used to practice reliability-centered maintenance (RCM), allowing maintenance based on actual component use as opposed to elapsed time, potentially extending the life of, and reducing maintenance costs for, major substation equipment.
Improved Customer Service. Substation automation provides improved service through better system information that is available in one location. By communicating with all the IEDs across the utility, all fault information is available immediately following an event, potentially reducing the customer base affected and preventing outages in the future. Improved power quality is achieved through automated coordination of voltage regulation and capacitive control.
Improved Organizational Effectiveness. Organizational effectiveness is improved through the use of a single data-mining tool across the enterprise. Substation automation allows the utility to reach the source of the data in local substations and metering points and make that data available to both the SCADA master and to an enterprise-wide data repository. This data collection network provides a one-stop shop for critical system data, both real-time and historical. Data users across a utility’s various parts can efficiently get the information they need. The one-stop shop also eliminates information silos-disparate systems that cannot share data with each other-and redundant spending on division-specific systems that unnecessarily mirror the capabilities of systems belonging to other departments.
Architectural Guidelines for Enterprise Substation Automation
Successful substation automation starts with the system’s ability to effectively mine data from IEDs. As more utilities move toward installation of microprocessor-based IEDs, more of the important data captured by these IEDs can be made available to the utility enterprise. The issue then becomes how best to mine this data. Examination of available technologies is in order, with a few basic principles in the foreground.
The selected architecture should permit communication with any IED the user implements. The architecture should be as open as practical, minimizing dependence on propriety components. And, the chosen platform should be modular, allowing the user to architect systems with the appropriate mix of capabilities needed for a given application. Even utilities that have yet to make the move to microprocessor-based IEDs should consider a planned migration path to substation automation in their next generation of RTUs.
Many IEDs communicate most effectively through their native protocol. While there is a growing trend to standardize communication protocols, it is still common to find that a given IED’s complete data set is best communicated through the native proprietary protocol. This means that to access all the data from many IEDs, the chosen substation automation platform must have a comprehensive library of drivers to include virtually any IED the end-user may choose to implement. Careful selection of a provider will enable complete access to the IED data set across a variety of devices, including real-time as well as all historical file retrieval. Conversely, selection of a substation automation provider with a limited driver library will ultimately limit the variety of IEDs that can be used or the data that can be retrieved, a situation that most system protection departments don’t want to experience.
Openness of architecture reduces dependence on proprietary components. While some proprietary components are inevitable (the provider brings something unique to the market), minimizing dependence on proprietary components can save a lot of complexity in the long run. All too often, a provider has abandoned hardware and software platforms, leaving the end user with orphaned technology. Utilizing platforms that are widely embraced in other industries-such as PCs running a Microsoft operating system and commonly used programmable logic controllers (PLCs)-helps ensure that components and support will be available from a variety of sources for years to come.
Modular architecture in the chosen platform is advantageous for a number of reasons. As a station’s needs grow through load growth or with addition of data from an IPP, a modular substation automation system allows easy additions of capability, such as local data storage, a human machine interface (HMI) or multiple mapped data paths, as needed without incurring this cost upfront. Perhaps one of the most significant features of a modular architecture is that a utility looking at their next purchase of RTUs can go ahead with the basic substation automation system and essentially get RTU functionality at RTU pricing (see Figure 2). When that customer is ready to progress to more functionality, with the foundation laid, it will be easy to add in a modular fashion and achieve a fully capable automation system (see Figure 3).
Solution Roadmap for Enterprise Substation Automation Benefits
Planning a successful implementation involves five critical steps:
1. Begin with an assessment of enterprise data requirements.
2. Examine performance of existing infrastructure and develop benefit analysis.
3. Introduce the technology capability through a pilot project and actively pursue “buy-in” across the utility.
4. Develop specifications with an emphasis on system performance testing; and
5. Select the implementation team.
Step 1. Begin with an assessment of enterprise data requirements. Determining who needs what data is an essential building block of the substation automation system architecture, and also key to getting corporate-wide buy-in for a project. Through the assessment of enterprise data requirements, numerous groups within the enterprise start to see the benefit to their respective departments and begin to lend their support. In addition, they start to mold the data set that will be retrieved and made available to the enterprise. This effort will ultimately define the data set and how it is to be displayed. Taking time for this critical step early on will go a long way in prevention of the common misstep of first installing the system, turning on the data fire hydrant and then wondering what to do with all the data.
Step 2. Examine existing infrastructure performance and develop benefit analysis. Once the enterprise data needs are understood, an assessment of the existing data retrieval infrastructure is in order. Existing RTUs need to be examined relative to their effectiveness as data mining tools, their ability to communicate with IEDs and, if the RTUs are aging, the ongoing support from their manufacturer. The communication infrastructure needs to be examined to determine if it can handle the data throughput that will be required in bringing the selected mined data back to SCADA and other data repositories. Security issues also need to be addressed to ensure secure data transmittal to the intended end user. The existing SCADA master needs to be examined to assure that it can communicate readily with the various remote devices in the field, preferably through an industry standard protocol, and that it provides a secure and adequate repository for all real-time data. Lastly, a data repository plan needs to be established to provide long-term storage for all historical data that will be pulled from the IEDs and made available to the corporate enterprise.
Step 3. Introduce the technology capability through a pilot project and actively pursue “buy-in” across the utility. Using the previously defined data needs from each participating entity, show the system’s effectiveness as a data mining and retrieval tool. For example, present the load data to the planning department, the remote access to fault data to engineering, the fault interruption and station loading data to maintenance, the real-time data retrieval to SCADA, and the ability to control and monitor to operations. Develop a real-world example of an automation routine such as capacitive control or load transfer between station transformers. Write these algorithms into the system’s processor, and showcase the ability to perform some of these operations automatically. Regardless of whether the end user is ready to implement some of the true automation capabilities, it is important to realize the capability is there and to start the dialog relative to how these features can enhance system operation, reduce operating costs and improve customer service.
While a pilot project’s importance cannot be overstated, it is critical to realize from the beginning that it is merely a step toward a greater goal; that goal being successful substation automation system implementation. It is all too easy to get caught up in the pilot as a project unto itself and to perpetuate a protracted pilot, always proving one more component of system capability. Keep in mind the pilot is only one step on the way to success, and, like any step in the process, carefully delineate its scope and timeframe.
Step 4. Develop specifications with an emphasis on system performance testing. A crucial component of substation automation system specifications is performance testing. Since most utilities have experienced an evolution in substation design over the years, there is likely some element of uniqueness to each station. Before installation in the field, the end user should be satisfied that the chosen platform will perform as expected under real-world conditions. To this end, the expected performance testing, such as response time to the master and processor usage, should be clearly delineated. It may be wise to examine the existing substations, select several that are prototypical of common design types, and then require that the chosen performance parameters be proved on these prototypes. This may require a significant initial effort in wiring up IED racks and simulating input from hard-wired I/O, but it will go a long way toward providing a level of comfort in the technology and avoiding surprises in the final installations.
Step 5. Select the implementation team. A dedicated team is needed to architect and implement the substation automation project. Team responsibilities include design of the substation automation architectures, the communications architectures and the IED panels; project management; coordination with the system providers; integration of a variety of technologies involved in substation automation and the communication infrastructure interfaces; utility personnel training; change management to assist in preparing various utility entities for the impact of new technology on their organizations; scheduling of deliveries to coordinate with installation at the stations; construction work package development; etc. For each unique project, the utility must decide if sufficiently experienced resources are available in-house or if outside support from an integrator/implementer is required. If an integrator is needed, experience is a key selection criteria. Examine the integrator’s experience in successful automation projects of scale. While many have worked with customers through a pilot program, the field of integrators that have delivered large projects in a production mode is far smaller.
It is of primary importance to “think big” when looking at substation automation’s potential advantages. While the initial push toward substation automation may come from system protection or SCADA, keep in mind that this is a project for the utility as a whole. Virtually any department that needs information mined at the substation will obtain benefits. The ability to achieve one-stop shopping for enterprise data needs is powerful, enhancing efficiency while reducing costs. In the absence of this corporate-wide vision and cooperation, substation automation’s financial effectiveness and return on investment is often undermined by the procurement of disparate systems by individual departments to meet their own particular data needs. Early buy-in for substation automation across the enterprise promotes a collective sense of support and expectation that creates momentum, propelling the project to successful completion and giving each entity within the enterprise the data they need from a common source. à¢®à¢®
Gene Grace is a senior consultant with Enspiria Solutions Inc. He has 19 years experience in power systems design, including extensive experience with generation, substation and transmission as well as subtransmission design in system voltages from 230 kV to 25 kV. Gene has spent the last seven years specializing in substation automation, including system and architecture development/deployment to meet the needs of a wide array of clients in the United States, Mexico and Canada. His past experience includes positions with Black and Veatch, North Carolina EMC and Power Engineers. Gene holds a B.S. in Electrical Engineering from North Carolina State University.
Jim Bougie is a senior distribution automation engineer with We Energies. He has been responsible for We Energies substation integration for the past seven years, including specifying equipment, programming HMIs, setting up IEDs and programming changeover schemes. We Energies has automated more than 74 substations to date, with HMIs at 47 of these stations. Prior to moving into substation integration, Jim worked for five years in the standards group at We Energies, responsible for underground distribution products. His past experience includes positions with several consulting firms, as well as tenures at Milwaukee County and Milwaukee Metropolitan Sewage District. Jim holds a B.S. in Electrical Engineering from Marquette University.
Substation Automation at We Energies
We Energies, based in Milwaukee, Wis., has long pursued and improved its substation automation capabilities. Substation automation systems are now a standard part of all new stations at We Energies. The utility has used the following key criteria in selecting its systems: open architecture, commonly available PLC platform and modularity.
We Energies has developed a creative approach for replacement of aging RTUs at existing stations, which allows insertion of a new PLC-based automation system while leaving much of the existing wiring intact. Due largely to the system’s modularity, We Energies is able to insert the PLC chassis directly into the existing RTU enclosure. Wiring from the substation automation modules comes as a long bundle terminated on new terminal blocks that are mounted in the existing RTU enclosure. Interposing relays are left in place. Field wiring is cut over, communication paths are cabled to the new IEDs and the unit goes through a We Energy-performed site acceptance test. Following this procedure, We Energies can replace an RTU in one day with one day of preparation time and one day of clean-up time.
We Energies has experienced four major advantages from substation automation and integration:
“- Provides ability to access the full capabilities of the IEDs (real-time data as well as historical records);
“- Reduces wiring, as most points can be retrieved through a virtual path; and
“- Provides excellent transition path, allowing mix of existing hardwired points with new virtual points.
“- All data available at a single user interface, avoiding multiple interfaces in the station;
“- All data accessible locally or remotely;
“- Provides ability to turn reclosing on/off remotely;
“- Provides ability to control tap changers remotely;
“- Provides ability to control auto/manual switches remotely;
“- Reduces need to send personnel to substation; and
“- Simplifies incorporation of changeover schemes (implemented in the PLC instead of hardwired).
Modernization and Expansion
“- Provides ability to change IEDs without any substation automation hardware changes (requires a software upgrade);
“- Enables multiple IEDs to communicate with one communications module loaded with one protocol driver;
“- Provides a modular and easily expandable system;
“- Provides ability to talk to multiple energy management systems (provides the ability for different types of information); and
“- Provides ability to talk to distributed control systems (transfer information back and forth).
“- Reduces the amount of wiring needed;
“- Reduces equipment footprint;
“- Requires fewer panels;
“- Reduces the number of analog and digital boards required; and
“- Reduces man-hours needed in stations, and in transit to stations.
Substation Automation at LADWP
The Los Angeles Department of Water and Power is undertaking a substation automation project in more than 179 substations, as a part of its larger Energy Control System Upgrade (ECSU) program. To date, 92 systems have been ordered and 55 have been delivered
The ECSU program-of which the substation automation systems are an integral part-brings a number of important benefits to LADWP including improved system integrity, improved environmental quality, and establishment of a foundation layer for delivering critical data to the utility knowledge infrastructure.
The substation automation portion of LADWP’s program includes replacement of legacy REDAC RTUs with PLC/PC based substation automation systems, replacement of electromechanical relays with IEDs, and replacement of 1200 baud modems with OC-12 fiber optic ring communication. A new fiber optic communication ring now provides a WAN retrieving data from all LADWP stations in this project. In addition, this WAN allows remote loop through access to all IEDs, reducing the need to send personnel to the stations.
The project includes installation of HMIs incorporating alarms, annunciator panels, control functions, station one lines, etc. into one display that is accessed by the operators in the stations. This has reduced the need for panel space and provides one-stop shopping for most of the station functionality.
Other features of the project include the ability to automate select control functions (at LADWP’s discretion, automation algorithms can be implemented in the local PLC), improved data acquisition including oscillography and sequence of events, and improved remote diagnostics. Improved communications with the stations through the newly installed fiber optic WAN and the addition of Loop Through provide communication with the IEDs and the local station infoserver as though the engineer is in the station plugged into the IEDs’ diagnostic ports.