The Term “Intelligent Grid” Often Conjures Up Ideas About Smart Meters, remote-controlled thermostats, appliances controlled by the utility, two-way communication and time-of-day rates. It may even evoke intelligent distribution with self-monitoring feeders correcting problems before they happen.

“There is a ‘T’ in the grid as well as a ‘D,’” says Dr. Steve Ashworth, the applications team leader at Los Alamos National Laboratory (Los Alamos, New Mexico, U.S.). “Intelligent grid tends to be viewed as intelligent distribution only.”

Although much work has taken place in the bulk transmission system, it does not get the same attention as the customer connection. Too often, the bulk transmission system is the ignored offspring of the intelligent grid. And, what about substations? Substation automation can be as little as supervisory control and data acquisition (SCADA) with remote terminal units (RTUs). More sophisticated systems may include sequence-of-event recorders, annunciators and digital fault recorders.

For the most advanced systems, smart sensing and monitoring systems enable utilities to make increasingly smart decisions, automated or not. And if something like video for security and equipment observation is included, along with robust high-speed communications processors, then the substation has moved up the IQ scale quite a bit. Couple those with an energy-management system, which gives utilities real-time data for operations and ongoing maintenance, and the substation has moved into the realm of high intelligence. All the previously mentioned equipment is off the shelf and available today.

NEW DEVICE SIMPLIFIES

Intelligent electronic devices (IEDs) are part of intelligent substations, along with the new generation of control/protection microprocessors feeding data to computers. Asset-management software analyzes and determines the state of the equipment. This issue is especially critical when addressing aging infrastructure, high equipment loadings and reductions in the technical workforce. One innovative IED that is getting a lot of attention is the current-measuring device, which SSIPower, LLC (Hampton, Georgia, U.S.), a member of the Southern States Group, introduced a few years ago.

SSIPower's IED is used like a current transformer; however, it does not have to be installed in the bus work to perform its current-sensing function, because this is a noncontact measuring device that simultaneously measures three phases. Imagine being able to add the equivalent of a set of current transformers to an old oil circuit breaker without fear of causing leaks or damage to irreplaceable parts. Anyone who has ever tried to add a set of current transformers to the bridge of a station dead-end structure will tell you how much of a problem it is to retrofit the bus work to place a current transformer in the circuit. Expect to see engineers finding new applications for this device as they become more familiar with it.

REDUCING MAN-HOURS

Power circuit-breaker monitoring systems are making another piece of equipment smarter. The CB-Map system from GE Energy (Atlanta, Georgia) monitors contact timing and contact wear. CB-Map tracks the tank temperature and the SF6 pressure. Leaks are detected when pressures and temperatures go out of limits. Condition-monitoring units from ABB (Zurich, Switzerland) provide utilities with similar information, along with the capability to predict when maintenance is required.

A few years ago HVB-AE Power Systems Inc. (Suwanee, Georgia) developed an intelligent method to inspect the internal elements of a power circuit breaker using X-ray technology to inspect the interior mechanism of the breaker. This noninvasive technology requires less time and manpower (about a day per breaker), and utility personnel know exactly what future maintenance is needed. If nothing is found, the maintenance inspection is over. Considering that an inspection of a 362-kV or 500-kV power circuit breaker can take a week with a crew of three or four technicians, this method offers a substantial savings.

IMPROVING RELIABILITY

Another piece of substation equipment that can be made smarter is the large power transformer. These critical components cost millions of dollars to purchase and can take more than a year to manufacture. A power transformer can be the single-biggest capital investment in the substation, and it is the one device most subjected to overload under emergency conditions. Recent studies show the average age of a substation transformer is somewhere between 35 and 40-plus years. It is not hard to find a large power transformer commissioned in the 1970s on most utilities' transmission systems. For that matter, it's not too difficult to find a vintage unit from the 1950s on systems today.

In its 2006 smart grid report, the Global Environmental Fund estimates that more than 70% of North America's transformers are more than 25 years old. Last year, Transmission & Distribution World reported that data from Hartford Steam Boiler, a major insurer of power-generation equipment, predicted a failure rate of 1.5% per year of all transformers in operation. Less than 2% seems reasonable until you put it into perspective. GE reports there are approximately 100,000 transmission and distribution transformers in operation, so 1.5% is roughly 1500 possible failures a year. That equates to a significant loss of capacity.

Monitoring systems designed for after-market installations have been a big advancement in intelligence. Barry Ward, a principal consultant with Advantage T&D Consulting, LLC, points out that monitoring systems combine the data from all the devices along with ambient conditions to produce characteristic signatures of the operating condition of the equipment. This gives utilities a truer picture of the transformer's condition. The degree of sophistication for monitoring packages is up to the utility. The utility can monitor simple things like oil temperature to more-complex things like transformer status indications. Load current, winding hot spot, moisture in the insulation, cooling control, dynamic loadings, load tap-changer temperatures and contact wear are a few measurements available.

Tony Pink, general manager of Dynamic Ratings Inc. (Victoria, Australia), points out that utilities install monitoring as a means of improving reliability. There is also significant payback for those using the data provided by the monitoring system to drive maintenance decisions. According to Pink, utilities are moving from time-based maintenance to condition-based maintenance.

Dynamic Ratings offers a comprehensive monitoring and interactive system to manage all aspects of the transformer. GE Energy offers its FARADAY tMEDIC system, and ABB offers its advanced transformer monitoring TEC system. Siemens (Erlangen, Germany) has teamed up with Serveron (Hillsboro, Oregon, U.S.) to provide a complete line of transformer monitoring as well. All these systems will make the transformer intelligent and combine asset management along with remaining life-management capabilities to the monitoring system.

TRUSTING THE INSTRUMENTATION

Zbigniew Banach, a senior engineer and transformer monitoring specialist for Exelon Corp. (Chicago, Illinois, U.S.), reported about the transformer monitoring system installed on ComEd transformers in the July 2007 issue of Transmission & Distribution World. This complete monitoring system is performing as expected, but Banach noted an interesting finding. Technicians obtain data from the Dynamic Ratings system and verify the readings with manual tests. This is similar to the technology of the scientific calculator replacing the slide rule, when engineers would use the slide rule to check the calculator.

Engineers have to be convinced the technology works, and Steve Larson, manager of substation construction and maintenance at Snohomish County Public Utility District No. 1 (Everett, Washington, U.S.), has a solution for that type of behavior. He reports that Snohomish invested in a complete substation simulator, including a relay test-set SCADA and RTU.

This allows the utility's technicians to become completely familiar with each new device or scheme brought on their system before placing it in service. It has also allowed them to test the Dynamic Ratings system with devices currently in service (like Beckwith Electric's tap-changer controls and Advanced Power Technologies' temperature controllers). They want the devices and schemes to be interoperable. They prefer specific devices and will continue to specify them.

INTEROPERABILITY WORKS

Interoperability is a critical feature for many utilities. Standards such as IEC 61850 have been developed with this goal in mind. Utilities are unwilling to be locked into one specific supplier for advanced technologies; instead, they want devices that can be used interchangeably. Engineers want to be assured that next-generation devices will work with the existing equipment. At the same time, they want to align themselves with vendors that have staying power. These are the types of issues Comisión Federal de Electricidad (CFE) wanted addressed at its Wind Park La Venta II, located in Juchitán, Oaxaca, Mexico.

The CFE project was the world's first IEC 61850-based substation implemented using multiple suppliers' IEC 61850 products. The project included 21 IEDs from nine product platforms, manufactured by six different vendors. It would have been much easier for CFE to have one vendor supply the entire equipment requirements. CFE would have likely saved money on the initial installation as well as ongoing maintenance. The project would have been completed on a faster schedule using an interoperable multiple protocol IED network integrated with an information processor. However, it would not have proven that the single interoperable IEC standard satisfies all parts of the necessary communications.

Our industry owes CFE a lot for taking interoperability from trade-show demonstrations into the substation. Several willing manufacturers — including Schweitzer Engineering Laboratories (SEL; Pullman, Washington, U.S.), Siemens, ZIV (Des Plaines, Illinois), GE Energy, RuggedCom (Ontario, Canada) and TEAM-ARTECHE (Spain) — worked together in this groundbreaking project.

THE TEAM APPROACH

On the CFE project, IBERINCO (Spain) served as the main contractor, providing project management design for the bay-level reporting and control part of the factory-testing team and commissioning. CFE defined the gateway database to the SCADA master and provided technical support. SEL designed and implemented the integration and provided IEDs, relays, the primary SCADA gateway, station level peer-to-peer communications, SCADA system and training, as well as built the panels and provided on-site support of the commissioning.

GE and Siemens provided relays. ZIV provided human-machine interfaces and a redundant SCADA gateway. RuggedCom provided Ethernet switches and TEAM-ARTECHE provided an ancillary bay-control device. Each supplier provided equipment per the IEC 61850 standard. The standard can be interpreted in more than one way, as with all good standards, so interoperability was achieved through a group effort.

David Dolezilek, SEL's technology director, says this was not a pilot project but a very real substation expansion on a bulk transmission grid. Dolezilek points out that, though it was required each device speak IEC 61850, each protective device must also be approved for use within the utility. He was impressed with the professionalism of all the team members. Egos were pushed aside to meet the common goal of providing a compatible system. Protection schemes using IEC 61850 digital communications, field-tested among SEL devices, operate faster than the parallel hardwire protection scheme installed for security.

After all the devices were working together and controlling the station, CFE asked if it was possible for relays to be interchanged. Though not a requirement of the standard, CFE wanted to see if devices from two vendors could be made to communicate the same and be exchanged.

Because of the flexible nature of SEL's configuration interface, SEL was able to make one of its IEDs communicate identically to that of another vendor. When both IEDs were given the same IP address, either could be connected to the network, and none of the other IEDs or clients could tell the difference. Of course, each relay performs protection and automation differently and has different engineering-access capabilities, but their IEC 61850 reporting and control was made to be identical. The installation was a success, proof of interoperability was a success and the IEC 61850 standard was a success.

SMART AUTOMATION

Electronic information exchange between the control house and the station components has been taken well beyond substation automation presently in use throughout the industry. This information exchange enhances the functionality and reliability of the station and the utility's transmission grid. Interoperability is the keystone of this technology and industry standards are its foundation.

Technical societies such as the IEEE, CIGRÉ and the IEC, working with utilities, government agencies and manufacturers, are moving the industry forward.

Manufacturers will continue to develop proprietary technologies that are needed to maintain the advancements,but the technologies have to function, and that is where the engineers and technicians who work in the intelligent substation space are playing a major roll. They are beginning to get a handle on the potential impact of this advancing digital technology and are making suggestions based on the lessons learned for the next implantation.