When Sterling Electric Light Department went shopping for substation integration, the utility thought the new microprocessor-based protective relays it installed in its substation the previous year could be the eyes and hands of an integration system. What the utility didn't realize was how inexpensive it would be to get the integration features it wanted.

The Sterling Electric Light Department is the municipal utility for the town of Sterling, Massachusetts, U.S., located about 35 miles (56 km) west of Boston. The load on the system is mainly residential and consists of about 3500 meters served from a single substation (Fig. 1). As it was, the utility knew the system could not justify a large, traditional and expensive SCADA system.

The previous year, the utility upgraded the older microprocessor-based relays to SEL-351 microprocessor-based multifunction feeder relays, produced by Schweitzer Engineering Laboratories (SEL; Pullman, Washington, U.S.). The utility also installed an SEL-2030 communications processor, which, when properly configured, collects data from connected digital devices, supports control functions, and makes data and control points available to other devices using any of several available integration protocols, such as Modbus and DNP 3.0. The utility planned to integrate the new relays and communications processor to bring useful data to the central office, 3 miles (5 km) away in downtown Sterling, using an existing fiber-optic cable.

A Winning Game Plan

Sterling solicited proposals for protection and integration systems in early 2003 and selected a solution proposed by System Protection Services (SPS; Lewiston, Idaho, U.S.) (Fig. 2).

The functional operation of the systems are as follows: Microprocessor-based relays at each breaker perform data acquisition and breaker control. A communications processor collects meter and status information from the relays and condenses that information into a smaller, more relevant data set. The substation Ethernet switch is connected to the communications processor twice. One connection supports remote data acquisition via the central office desktop PC. The substation Ethernet switch is connected to the central office switch over the existing fiber. The other connection supports engineering access to the substation relays.

In a larger system, other substations and control center locations could be connected on the network. While the Sterling control center is connected via a desktop PC at the substation, additional devices can be connected to each Ethernet switch, including additional communications processors, digital video cameras and weather stations.

HMI Software

ClearControls (Benicia, California, U.S.) provided its ClearView HMI (human machine interface) software, which provides a user-friendly interface that offers all the features of a traditional supervisory control and data acquisition (SCADA) system with broad capability and an intelligent architecture.

Its ease of use is based on several tools that simplify the developer's tasks. A full slate of predefined objects allows the integration engineer to drag-and-drop elements onto user-interface screens. The object-based software allows developers to quickly view and modify properties of each on-screen item. An expression builder tool defines customized logic, operations and tags without complicated scripting. Prebuilt trending, alarm and data-logging functions allow the PC to monitor and record standard and derived data tags simply. Users can define security functions using 26 levels of built-in user authorization and administer them down to the level of a single object on the screen. Every login, logoff and failed attempt is recorded via built-in security reports. The powerful capability of the software includes the ability to design custom integration features using standard Visual Basic interface and methods. This software uses a common local database technology, relieving the cost and support burden of a server-based SQL database. Since the database is accessible, the data can be shared or integrated into other local applications.

Using a unique architecture that separates the HMI development from the real-time data collection function, ClearView HMI relies on an independent OPC (OLE [Object Linking and Embedding] for Process Control) server to collect data from substation IEDs. The integrator can select best-in-class protocol drivers to collect the data that support the interface. As additional IEDs or protocols require support, more OPC servers can be added without fundamentally changing the HMI. Existing OPC server packages support traditional protocols, such as DNP 3.0 and the various forms of Modbus, as well as many PLC and several RTU protocols. Many third-party vendors supply these OPC servers; therefore, the integrator does not have to develop custom drivers or rely on a single vendor for support. When the system changes, the integrator can make modifications to all aspects of ClearView while the software is online and continues to collect data. It is not necessary to shut down the system and compile the software for changes to be activated.

The Ethernet Channel

Selecting Ethernet to support the integration system makes available a wide range of both mature and newer technologies. Many channel media are available to support Ethernet connection, including fiber optic, the public Internet and others. A fiber-optic connection offers secure, reliable bandwidth. A virtual private network (VPN) established over the public Internet is inherently secure and is relatively inexpensive. Several styles of Ethernet radios are now available in licensed and unlicensed frequencies. These radios typically operate line-of-sight, with a range of anywhere from 2 to 60 miles (3 to 97 km). Some models support multiple hops between stations through the use of repeaters. Bandwidth ranges from 115 kbps to 8 Mbps.

Perhaps the Ethernet's most attractive feature is its channel flexibility, which allows the central office switch to be connected to substation links using whatever combination of media makes the most sense. Nearby residential substations might be connected using line-of-sight radios, and residential substations in the next town could use a VPN over public internet via a DSL connection, while a remote transmission substation might be equipped with a fiber connection. Any link can be upgraded to a less expensive or higher bandwidth channel at a later time if system requirements or available channels change without impacting the existing SCADA system.

Ethernet Switches

Substation-hardened Ethernet switches, such as those built by RuggedCom (Concord, Ontario, Canada), connect substation communications processors and other devices to the wide area network (WAN). In addition to connecting any Ethernet-capable device, many legacy devices also can be connected through suitable adapters. Several dual-redundant communications topologies are feasible using a combination of Ethernet switches without incurring the access complications and performance penalties of a two-tiered communications processor approach.

The flexibility and maturity of Ethernet communications expands the applications of the substation WAN, allowing the network to support additional communications sessions in parallel. This flexibility allows:

• Engineering access to relays and communications processors to adjust settings or retrieve event reports, fault type, location and sequence-of-event data.

• Monitoring through digital video and audio.

• Acquiring data and control functions using HMIs at the substation.

• Using substation telephony.

• Migrating selected data-collection tasks to wireless handheld devices.

The Selection Process

Sterling evaluated several integration proposals and found that none of them offered to use the SEL-351 relays in the way SPS offered. Since Sterling wanted to use its existing equipment to the fullest extent possible, it awarded SPS the project with the expectation that the system would be sophisticated in function and simple in operation.

The completed integration system uses a simple substation single-line diagram for its main screen, with breaker and circuit switcher positions indicated by auxiliary contacts connected to the substation relays (Fig. 3). These status points are collected by the communications processor and displayed on the main screen. Feeder load currents are updated every other second, and if a substation alarm is detected, the software displays a text message near the bottom of the screen. Buttons across the bottom of the screen open a list of active alarms; access a logbook function for dated and time-tagged operator notations; display graphical trends of selected analog data over time; and start a terminal session with the communications processor and protective relays for engineering access, such as event data collection and settings maintenance, all without interrupting the real-time SCADA functions.

Screen buttons associated with each feeder open dedicated feeder information and control screens, showing real-time metering data, information associated with the most recent feeder fault and the present state of the relay front-panel targets (Fig. 4). Authorized operators can trip and close the feeder circuit breakers, enable/disable reclosing and enable/disable ground overcurrent protection. Pistol grip switches in the substation duplicate the breaker controls and reclose enable/disable functions for each feeder, taking precedence over SCADA controls. For example, if the substation switch has been used to disable reclosing, the SCADA operator cannot enable it. Real-time data include bus voltages, feeder currents, real and reactive power values, system frequency and substation dc battery voltage. Fault data include the date, time and type of the most recent fault, which could include fault location and fault magnitude.

Conclusion

The integration system is operating successfully and has demonstrated its cost effectiveness and ease of operation. In addition, the system has eliminated the need to travel to the substation to examine feeder loads. It represents a system that could be of value to small utilities that need the technology.

Acknowledgment

The author would like to acknowledge John J. Kumm and Andy R. Clary for their help in preparing this article. Kumm is principle engineer and owner of Systems Protection Services (SPS). He previously worked for Schweitzer Engineering Labs as product development and applications engineer. Clary joined SPS in 2001 as an electrical engineer and is responsible for integration system design, electrical design and relay settings calculations.

Brian Allen served in the Marine Corps prior to starting his career in construction. He worked as a construction superintendent and then moved on to the West Boylston Municipal Light Department, where he was a groundman/lineman apprentice, advancing to journeyman. Allen joined the Sterling Municipal Light Department in 1999. He is presently operations supervisor responsible for the distribution system, meter department, substation and load management, and the generation facility.
ballen@energysterling.com