Moving existing substations to the digital age will require careful analysis and sound strategies.
The Substation is the Critical Link Between Transmission, Distribution and Customers. This link must be robust and reliable. In the digital age, however, a robust substation is a strength and a weakness. Technological development is accelerating so fast that it almost seems to be planned obsolescence.
Although substations are built to last, utilities cannot just lock the gate and walk away. Once a substation becomes part of the grid, it will be modified and improved. Visit an older substation, and it is a sure bet old and new technologies are working in concert with multigenerational devices sharing the same control building. Last century's electromechanical relays will be sitting next to today's ultramodern digital microprocessors, and they all have to function collectively and perfectly.
Engineers and technicians from utilities and manufacturers have been working together to adapt each generation with the next.
IT STARTED SIMPLE
The evolution began when utilities introduced intelligence into the substation by staffing critical substations 24/7. The system operator called the station and gave operating instructions to station personnel. It was a human-machine interface in its simplest form.
Somewhere along the way, someone had an idea to use a timer, cam, relay or some combination of these to make a machine do some simple repetitive task, freeing up the human to do other things. Substation automation was born, which took a big step forward in the 1960s with the development of supervisory control and data acquisition (SCADA) systems, remote terminal units (RTUs) and high-speed communications systems. It gave utilities the ability to energize and de-energize transmission circuits remotely from great distances. This simplified operations as far as the logistics of moving technicians around to far-flung substations for switching procedures, but increased the complexity of the system with the need for elaborate schemes to make certain each part was reliable.
Computers found their way into the system in the form of programmable logic controllers (PLCs) a few years later. PLCs allowed for more-sophisticated sensors and actuators, which increased the SCADA system's abilities manifold. The microprocessor — a computer on a chip — followed shortly, along with Web-based access, Internet protocols and expert systems programs.
With all this control and interaction between components, someone noticed a great deal of information was being generated from each substation. It showed operational and nonoperational data, which utilities started to record and store.
Here we are today with substations in various stages of evolution. Some have very limited cognitive abilities. Others can run self-diagnostics and anticipate problems, and some can correct those problems before the human operators even know a problem exists.
“The challenge is the fact that if a piece of technology has ever been used in a substation, it is still being used,” explained Jonathan Piel, global product director for Cooper Power Systems (Waukesha, Wisconsin, U.S.). “Utilities have decades of legacy devices operating throughout their systems. They can't afford to scrap and start over.”
Utilities must make those existing systems work with the newer technologies. Piel made the point that early intelligent electronic devices (IEDs) weren't made with interfaces to work with protocols developed for today's digital world. “They don't speak the same language,” Piel said.
Cooper's approach was to take data from the many generations of sensors and devices found in older substations and develop a black-box approach known as the data concentrator. “The data concentrator has become a universal translator for substations,” Piel noted.
The data concentrator bridges the generations of sensors and monitors found in the substation, allowing them to communicate with each other using their native protocols. Cooper's Cybectec division's Substation Modernization Platform (SMP) has the ability to interconnect all data-producing (sensors and monitors) devices and data-consuming (control, maintenance and engineering centers) clients easily. Data is converted to a standard format and stored in the SMP's Real-Time Data Exchange component with Web-based access from transmission control protocol/Internet protocol (TCP/IP) on serial or local area network connections for flexibility.
Cooper's Cannon division, working with Oklahoma Gas and Electric (Oklahoma City, Oklahoma, U.S.), has been doing some interesting things using IEDs to monitor circuit breakers and transformers for several years. The Cannon Advisor system provides equipment condition monitoring, alarm notification and trending, and it is Web-based for accessibility. It also uses wireless communication to monitor the equipment, which eliminates cabling between the equipment and the control building. Video is also installed as part of the monitoring system. “You can put a sensor on the equipment for data, but video allows you to see what is taking place in the substation,” Piel reported.
ONE STEP AT A TIME
"Some utilities have trial installations with sensors connected to their electromechanical relay signals," said Alan Grightmire, group vice president of substation automation at ABB Inc. (Zurich, Switzerland). "This is driven mainly by the increasing need for more information to effectively diagnose and manage critical assets that they cannot afford to abandon."
Although solutions like this presently satisfy some of the local information requirements for data analysis, there is an increasing trend among utilities toward planning for system-wide upgrades to intelligent relays and automation for their substations to fully meet their future information requirements. ABB's ability to retrofit existing substations and install new substation automation technology is a part of ABB's Smart Grid offering.
Steve Kunsman, group assistant vice president of global product management at ABB Inc., put it this way: "Every utility is moving forward into the intelligent substation at its own pace, and all are dealing with multigenerational electronics, sensors, monitors and apparatus found in their substations."
Large modernization projects are done in phases, often over several years, to minimize disrupting service and to accommodate the utility's budget. "ABB uses a modular design approach for retrofit projects where old equipment is removed and replaced," Kunsman explained. "The more you replace old equipment, the more sense it makes to use modular designs."
Modularization offers the benefit of the standardization of designs, which saves installation time, reduces the number of spare parts required, keeps maintenance simple and lowers costs. Consolidated Edison Company of New York (New York, New York, U.S.) has selected ABB to replace 1970 vintage RTUs in 39 Con Edison substations with ABB's RTU 560. The retrofit will also include 72 MicroSCADA PRO workstations. The turnkey project started in late 2007 and is scheduled to last roughly two years. The project also includes a migration plan for future upgrades of more of the system as work progresses.
Substations can be made smarter by adding sensors, monitoring, automation and analysis systems. "Utilities generally have a hierarchy for their substations based on complexity and criticality," said Wes Sylvester, director, distribution solutions Siemens Power T&D Inc. (Wendell, North Carolina, U.S.). "Those defined as complex/critical will tend to be more fully monitored and highly intelligent, while less critical substations may not justify as much automation or intelligence."
Add-on intelligent components give substation owners cost-effective options to incrementally transform their substations, prioritized by greatest value to their business. "Many start out by adding intelligence to transformers — some owners are more interested in circuit breakers and others are focused on security issues. In many cases, it is dependent on what issues have caused them the most problems with reliability," Sylvester explained.
The Siemens approach is to work with the owner and develop a road map of what is needed. Sylvester uses the example of monitoring a medical patient's vital signs to successfully predict and avoid heart attacks. It is the same principle in the substation. Siemens' Spectrum Power CC Asset Monitoring system lets the utility select the software suite of components for the issue at hand.
RURAL ISN'T REMOTE
Rural substations offer their owners a different type of challenge. Although they would benefit from substation automation, it seems the cost outweighs the returned gain. These substations typically have little in the way of communications ability, and they contain some old equipment that was never designed with IEDs or any type of sensor in mind, but that is exactly what is happening. As technology advances, the price of the parts goes down, making systems affordable. Just look at memory for computers.
Cellular coverage also has increased to the point that very few areas are without access. Telemetric (Boise, Idaho, U.S.) is making small rural substations smarter with its wireless communications systems. Telemetric delivers an end-to-end system consisting of three main parts: intelligent remote telemetry devices; Telemetric's PowerVista, a network management software application; and the AT&T nationwide cellular network. Sensors are added to selected substation equipment, and cellular communications connects the substation to the utility. The system can be integrated to any SCADA system via a DNP3.0 interface called SCADA-Xchange.
The intelligent field devices allow the utility to view the status of equipment, initiate changes and automate selected events to trigger a control action to take place in the substation. "It is limited information, but these stations do not require full SCADA systems," noted Tom Loutzenheiser, Telemetric's CEO. "Over 200 utilities in North America have installed Telemetric's systems on their systems."
Buckeye Power Inc., a wholesale power supplier in Ohio, improved its system reliability with the deployment of roughly 330 Telemetric TVM3 voltage monitors. This system is designed to detect and report delivery-point outages on its rural network. Buckeye personnel are notified by alarms and messaging sent via pagers, cell phones and e-mails. Operations personnel are responding more rapidly to events and are reducing customer outage times.
Loutzenheiser reports that Nevada Power (Las Vegas, Nevada, U.S.) started an innovative capacitor automation project last year using cellular data communications equipment from Telemetric and eCap capacitor controls from QEI Inc. (Springfield, New Jersey, U.S.) on roughly 2200 capacitor banks. When this project is completed, Nevada Power will have two-way communications confirming all switching commands and capacitor bank status.
Along with the intelligent substation came the cyber attack. Many initially believed SCADA was secure because of its remoteness to the Internet, it was unnoticed by hackers or its protocols were so specialized they would provide protection. All of these proved to be wrong, and cyber security became part of the electric industry's vocabulary.
New substations can be constructed with appropriate, advanced security packages. But what about the existing stations with all the added-on intelligence? There is no such thing as a "grandfather clause" in cyber security. Hackers probe systems looking for a weakness they can exploit, and the North American Electric Reliability Corp. is paying attention.
NERC is responsible for the reliability of the bulk electric systems in North America. NERC has been developing its critical infrastructure protection (CIP) standards, CIP 002 through CIP 009, for the past several years. Utilities have until August 2009 to implement the standards, and NERC will begin full compliance audits a year later.
"Utilities are reacting to the fact they must meet those deadlines or face the penalties," said John Shaw, executive vice president of GarrettCom Inc. (Fremont, California, U.S.). "Utility management has often viewed automation initiatives as discretionary. Systems upgrades have sometimes taken a back seat to more fundamental transmission and distribution investments, but NERC mandates are forcing some systems initiatives to move forward. NERC's CIP compliance can be embraced as an opportunity to upgrade the infrastructure to enable new levels of substation networking and new intelligent systems support."
GarrettCom offers products such as CrossBow Secure Access Manager to integrate security measures across the old and new systems, including serial and Ethernet devices. Adapting these legacy systems with old protocols can be tricky, but systems like CrossBow make the transition easier.
Cutting-edge technology is available for remote monitoring of critical and noncritical apparatus and systems. The extension of digital technology into older infrastructure assures improved reliability, reduced costs and enhanced customer choice and service. Adding expert systems with analytics will help us operate our assets more efficiently. Cyber-security compliance issues are manageable with other add-on technology. Change is difficult, but it can be invigorating, too, as we position substations to serve the rapidly evolving digital utility.