Increasing partnerships between electric and telecommunications spark growth

Lloyd Cibulka

Contributing Editor

Most utilities own their own communications systems and buy or lease services from other providers where it serves their cost and reliability target(s). But deregulation is opening the possibility that utilities may want to form partnerships with communications companies for strategic or financial advantages, and to open up new lines of business. While specific examples of this trend are relatively few to date (PacifiCorp`s Pacific Telecom and Williams Co.`s WilTel network, both spun off after initial success, are notable examples), the potential is great.

Existing and emerging telecommunication needs

Utilities realize that many sources of data need to be interfaced for new and flexible functions. Raw data from substations, customers, financial records, and many other sources needs to be accessed, combined and processed in many different ways and by many different users, depending on the business purpose. Many of these applications require intelligent electronic devices (IEDs) to obtain and store the data before transmitting it to where it`s needed. Technology advances, particularly in sensors, are enabling numerous new applications heretofore impractical or uneconomic.

A key factor is volume of data. Some applications require that only a few bits be sent at infrequent intervals, e.g., maintenance data for a reliability-centered maintenance (RCM) database. Others may require a lot of data at infrequent intervals, or data sampled and transmitted frequently, e.g., breaker status or transmission line voltage and power flows.

Cost is always a crucial parameter for utilities, but reliability is also important: some functions, such as protective relaying, require fast response and near 100 percent reliability, while other applications are more tolerant of low speed and less-than-perfect reliability.

Traditional applications evolving

Utilities are migrating from manual reading of customer meters to interrogation via hand-held devices, with the data being downloaded to a computer, sometimes remotely. Ultimately, intelligent electronic meters can be remotely read without the need for a human meter reader, alleviating the problem of remote and hard-to-access meters and saving on labor costs. In the high-voltage arena, metering of transmission lines allows utilities to control the exchange of power between companies and coordinate tie-line flows for regional reliability.

Protective relaying systems must operate in the range of a few milliseconds (for transmission and generation applications) to fractions or tens of seconds (for distribution system systems) to protect equipment and people. Many utilities use dedicated microwave radio channels to accomplish high-speed relaying over large distances, e.g., transfer trip schemes for transmission systems.

Monitoring & control is performed at a number of levels. The most common system employed is SCADA (Supervisory Control and Data Acquisition): data is processed and displayed in graphical user interfaces (GUIs) for system operators; control actions may be automatic via expert systems or manual, i.e., by human operators. Real-time data from power plants, switching centers, substations and transmission lines is processed by the utility`s power control center, also called the Energy Management System (EMS), an advanced form of SCADA. In areas where restructuring has progressed (California, for example), the utility control center is migrating to the ISO, along with new communications channels. At the local level, substation personnel use monitoring data to operate the local system according to real-time needs, and also to track maintenance needs using RCM-type databases.

Distribution automation describes how distribution systems are being upgraded with SCADA or other forms of monitoring and control to improve reliability, power quality and maintain adequate levels of customer service. Desired applications would include voltage control, fault detection, fault location and isolation, reconfiguration and restoration of feeders after faults, re-setting of relays and protection schemes, remote switching of capacitor banks, remote meter reading, and customer interface.

Customer services applications include meter reading, electronic billing, power quality monitoring, demand side management, outage detection, time-of-use rate information, and remote service connect/disconnect. This area is expected to experience strong growth, as competition and deregulation lead to greater customer choice and efforts to lower costs and improve service.

Mobile communications are used by utilities to communicate with and track maintenance and emergency vehicles, personnel and equipment in the field, using telephone, database access and wireless Internet connections. Global positioning systems (GPS) are being used more extensively due to their portability, accuracy and low cost.

Internet access is now a crucial resource for almost every utility employee, a phenomenon that would have seemed unthinkable 10 years ago. Everyone has e-mail for routine communications and Web-based information is becoming a necessity.

Many utilities have their own internal telephone systems, ranging from standard telephone systems to microwave-based wide-area systems, and satellite channels for video conferencing.

Restructuring`s emerging needs

Real-time device access includes applications that relate to real-time monitoring, operation and control of the physical system. Data volume is low, but response time may need to be very fast. There is a general trend toward embedded intelligence, i.e., microprocessor technology built into the intelligent electronic device (IED). Advanced capabilities in the field devices can ultimately lead to bypass of the remote terminal unit (RTU) function and to more direct integration. Integration and interoperability between different manufacturers` devices and systems is simplified and cheaper. EPRI`s UCA protocols have gone a long way toward facilitating progress in this area. Applications that could benefit from these developments include:

– volt/VAR control via capacitors, tap changers, etc.;

– remote generation control and scheduling;

– protective relaying;

– switching and reclosing;

– remote metering and revenue metering;

– distribution automation systems;

– customer interface systems; and

– real-time pricing.

Real-time database access has a high growth potential, based on the enabling factors of improved sensor technologies and increased integration of systems. Applications tend to be in the planning and analytical domains, so data rates need not be high; however, data volume may be great. Applications in this category include:

– communication between control centers,

– generation scheduling and dispatch,

– marketing,

– planning,

– geographic information systems (GIS),

– capacity scheduling (generation, transmission),

– condition-based maintenance and

– marginal pricing.

Restructured markets result in new entities in the marketplace: a power exchange, which handles the generation market transactions; a system operator that controls the grid; power brokers, who buy generation for resale; aggregators, who represent groupings of customers; wholesale customers; electric service providers (ESPs) and electric service companies (ESCOs); and customers (primarily industrial and commercial) who actively shop for power. New lines of communication might be established between and among all these players.

Distributed generation (DG) has advanced in recent years, to compete with utility generation for new load, to relieve line loading and transformer constraints, and to improve reliability and power quality. ESPs and ESCOs can use DG to sell lower-cost power and enhanced services to customers. Customers themselves may want to install DG to lower their energy costs, reduce demand charges, and have standby power in case of utility outage. Utilities can contract with owners of standby generators to help on peak days. But DG still needs to be interfaced to the system control center, and this usually means new communications channels.

Conclusion

Electric utilities have always wrestled with the strategic implications of telecommunications systems: how to match the available technologies with the current and future data requirements in a cost-effective way. Today, that task is more difficult than ever. Each utility needs to know what its business will be in an ever-changing environment, and hope that its telecommunications investments will pay off with success in the marketplace.

Lloyd Cibulka is an EL&P contributing editor and a technology consultant based in San Francisco. He formerly worked in PG&E`s research and development department.

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