When a transmission line trips, the operations center knows about it immediately. Power is quickly rerouted through other lines by remote switching and a vast array of computer-controlled equipment and instrumentation. But for most utilities, when a distribution line trips, the Dispatch Center doesn't know about it until the telephone rings; therefore, power is slowly restored to the customer.

At many utilities, distribution restoration is accomplished by manual methods requiring a lot of manpower and valuable time. Load-transfer capabilities are limited due to the radial design of most distribution feeders and reliance on manual switching to do the transferring.

THE NINES OF RELIABILITY

Utility customers and regulators want superior reliability with few or no power outages. If there is an outage, they want fast restoration. Reliability is the key word here. Customers expect high-quality power 24/7, and they expect it to be adequate and secure.

There are many rating systems currently in use to measure feeder-circuit reliability. The utility industry has accepted the System Average Interruption Duration Index (SAIDI) rating system as a benchmark. SAIDI indicates the total time an average customer has power interruption during a predefined period of time. Utilities and regulators talk about SAIDI minutes as the guideline. The lower the number of minutes, the better the utility's standing in the reliability arena. This also has morphed into the nines of reliability. The nines refer to a conversion of the SAIDI minutes into a percentage, such as in the soap commercial where soap is 99.99% pure.

It is hard to believe that 99.998%, or 52 outage minutes, of uninterrupted electric service in a year's time (525,600 minutes) isn't good enough. But look at it from a customer's viewpoint. Customers use technology that has zero tolerance to any type of interruptions. They demand high-quality power because they need it. Even an outage time of less than a minute can be as much of a problem to a computer chip manufacturer as one of several hours.

Doug Staszesky, director of product management at S&C Electric Co. (Chicago, Illinois, U.S.), says that the most cost-effective method of reducing SAIDI minutes is the automation of the substation feeder. He also feels the more the feeder is segmented and automated, the more SAIDI minutes are improved.

DISTRIBUTION AUTOMATION

The digital distribution company combines the distribution automation (DA) with distributed intelligence (DI). It is continuously monitored, which requires low-cost sensors and intelligent devices be liberally deployed throughout the substation and the feeders. High-speed computers have been overlaid on the distribution system. Robust high-speed communications systems have been added to the mix. This has increased the functionality of the automation to the point of being able to monitor and control all of the devices on the feeders remotely.

Voltage and current sensors are good examples of the innovative, low-cost devices on the market. Joe Rostron, vice president of product development for Southern States (Richmond, Virginia, U.S.), reports that the CMD, a current-monitoring device from Southern States, was originally developed for use with the company's CapSwitcher. But then utilities discovered it could be used in pole-top applications where it is better not to have the measuring device contact the conductor.

Lindsey Manufacturing Co. (Azusa, California, U.S.) has developed current- and voltage-monitoring insulators for use on switches and lines to monitor in remote locations. Fisher Pierce (Cleveland, Ohio, U.S.) has introduced a line of high-accuracy line-post current sensors that feature a porcelain line-post insulator with an embedded coil to measure currents through an inductive coupling. Edison Controls (Fairhope, Alabama, U.S.) has designed a faulted-circuit indicator that clamps on the phase wire to indicate the exact location of a fault.

UTILITIES WITH A VISION

A national organization, including nine electrical utilities led by We Energies (New Berlin, Wisconsin, U.S.), proposed the formation of Distribution Vision 2010, LLC (DV2010) as the new century began. Their goal was to accelerate the development of new advanced technologies to improve the reliability of the distribution system through automation.

The DV2010 system applies new and existing automation technologies within a structure of a four-tier distributed logic system designed to make large portions of the distribution system immune to outages. We Energies placed into service the first pilot last year. Russ Fanning, a principal engineer in distribution automation for We Energies, says this installation implements three of the four tiers of the DV2010 automation system on a closed-loop network to create a premium power park over the existing power distribution infrastructure in one of the oldest and largest industrial parks in Wisconsin.

Fanning explains that Tier 1 of the DV2010 DA system implements an enhanced autonomous protection system using Cooper Power Systems' (Houston, Texas, U.S.) underground distribution switchgear with vacuum fault interrupters. They are controlled by Cooper's Edison Idea relays and pole-mounted NOVA reclosures controlled with enhanced Form6 controls. Tier 1 DA acts as a failsafe for the system. Should the communication system fail, it will do so in a manner that allows the equipment in Tier 1 to continue to operate and protect the circuit.

THE HIGH-SPEED VISION

Tier 2 was applied with the same Cooper equipment to establish faster fault location and isolation in the network. Fanning made it clear that the Tier 2 system is a high-speed Ethernet scheme. Each device monitors data from remote points at all times. When a fault occurs, the switches react quickly to simultaneously isolate the fault at several points on the network within 4.5 cycles. The system confines the outage to a relatively small part of the network and preserves an uninterrupted supply of power to all of the other customers in the industrial park.

BC Hydro placed the second DV2010 pilot in service in March 2006 in Vancouver, British Columbia, Canada. It demonstrates networked feeders with communication enhanced protection (Tier 2) functionality at a critical shopping center.

BC Hydro networked two feeders serving the shopping center. Wenpeng Luan, senior engineer for BC Hydro, reports the system has been in service for a year and has performed very well using equipment supplied by Cooper Power Systems and NovaTech, LLC (Quakertown, Pennsylvania, U.S.). BC Hydro experienced one outage to the shopping center in the past year and that was storm related on the transmission system.

The average SAIDI for the last four years for the shopping center's combined feeders was 3.42 hours, or 99.94%. BC Hydro expects an improvement to the SAIDI by 0.12 hours, or 99.99%, as a result of the reconfiguration to the feeder network. Luan expects to take this experience and, after careful analysis, apply it to other commercial customers on the BC Hydro system.

MONITORING AND RESTORATION

Joel Cannon, executive vice president of Cannon Technologies (Minneapolis, Minnesota, U.S.), a Cooper Power Systems' Energy Automation Solutions Business Unit, reports that the company has developed a new approach to distribution substation real-time monitoring of equipment and feeders called Esubstation, which runs on the Cannon Yukon software platform.

Esubstation provides the dispatcher with a comprehensive real-time imagine of the substation using the integrated browser-based application with Cannon's equipment sensors located on substation transformers, breakers, feeders, batteries and other equipment. Sensors located on the substation's transformers monitor loading information, critical unit temperatures, cooling equipment status, combustible gas and other key data points. Other sensors located on the substation's power circuit breakers monitor vital functions such as gas pressure, density, and temperature along with trip/close status.

Esubstation sensors also can be installed in the control house to monitor feeder loadings, relay targets, voltage regulation and the station battery system. In addition to the sensor data, Esubstation can supply video surveillance to provide the dispatcher a complete picture of what is taking place in the substation without sending a crew to the station. In these days of critical shortages of the technical workforce, it makes sense to use your resources efficiently.

Mr. Cannon points out that there are more than 200 North American users of the Yukon software. He says that Esubstation has been used to identify equipment problems before they became failures and has also proven useful to move maintenance to predictive need rather than arbitrary schedules.

S&C has developed the IntelliTEAM II Automatic Restoration System using a modular system of distributed intelligence and the UtiliNet radio network to provide peer-to-peer communications as well as remote functionality to dynamically track system conditions on distribution systems. It is fully automatic in its ability to locate a fault, isolate it and restore service to customers.

Dean Craig of ENMAX Corp. (Calgary, Alberta, Canada) says that ENMAX began a five-year feeder automation program in 2003, automating eighteen 25-kV feeders on its system in Phase 1. This resulted in an 8.6% reduction of SAIDI minutes for 2004. ENMAX completed Phase II in 2005 by automating ten 13-kV feeders, resulting in a 13.1% reduction of SAIDI minutes for 2005. Phase III added five 25-kV and fourteen 13-kV feeders for a 14.7% SAIDI reduction in 2006.

ENMAX has more than 120 operational switches in service, with 45 being installed in the first part of 2007. The goal is to have 200 in service by the end of 2007. According to Craig, ENMAX has saved more than 3 million customer outage minutes since the feeder automation system went into service. The initial five-year program ends in 2007; however, given the good results to date, ENMAX has decided to continue the program past the initial five-year deployment.

S&C recently unveiled the IntelliTEAM III Automatic Protection and Restoration System. It joins the IntelliTEAM II product line with the new IntelliRupter PulseClosure and combines that with its new SpeedNet radio system. IntelliTEAM III has the ability to automatically sectionalize feeders during a system disturbance and use adaptive protection for the reconfigured circuits.

Boyd Rice, vice president of strategic marketing for S&C, points out that IntelliTEAM III has the logic to perform automatic operations without human intervention. The utility sets the decision points on deployment. The dispatcher receives information on the condition of the system and has a choice of intervening or letting the system take care of it. This allows the dispatcher to concentrate on more critical alarms and let the IntelliTEAM III do its job automatically.

Tier 3 Component of DV2010

Russ Fanning, a principal engineer, distribution automation for We Energies, describes the Tier 3 component of the Distribution Vision 2010 system as the workhorse. It is a distribution automation (DA) controller that has been developed as a module of the ORION RTU (remote terminal unit) made by NovaTech, LLC to integrate information from devices located both inside and outside the substation for consideration by the DA logic. It also integrates the DA system into the utility's SCADA system.

In DA system installations where the advanced DA and high-speed features of Tier 1 and 2 are not required, the DA controller can work alone with any manufacturer's equipment capable of communications. The Tier 3 DA controller can perform its functions automatically without human intervention. When a fault occurs, the DA logic determines where the fault is located. It then automatically invokes switching commands to field devices to isolate the fault and reconfigure the circuit so service is restored whenever possible.

Fanning explains that the dispatcher is aware of what is taking place and can override the system if needed, but the reconfiguration is often finished before the dispatcher is aware of the problem. Typically, the circuit reconfiguration is completed within 2 minutes or less after the initial fault. The Tier 3 design also is used to create safety zones “on the fly” for field crews while performing live-line work within the DA system. According to Fanning, there are about a dozen systems installed at We Energies now, with more on the way.