Taking Control of Voltage Drop and Reactive Power

Jul 1, 2004 12:00 PM
By Lee E. Welch, Georgia Power Co.

Voltage regulation and reactive power (VAR) control are fundamentals in the distribution of electric energy. In fact, voltage regulators and capacitor banks are so common that they are sometimes taken for granted. Nevertheless, it's important to understand how we select and apply them.

Georgia Power (Atlanta, Georgia, U.S.), with 44,000 miles (70,810 km) of distribution lines in about 2000 circuits, relies on a variety of voltage regulation and capacitor control methods to provide proper voltage to more than 2 million customers.

Line Losses and Voltage Drop

Distribution lines lose energy as a result of heating of the conductors. Losses are proportional to the square of the current; thus, as loads increase, the losses increase even faster. For example, if current doubles, the losses quadruple. Capacitors help by supplying a local source of reactive power, thereby reducing the current through all upstream devices.

Voltage drop along the circuit is proportional to current and to distance from the substation. Regulators at the substation can raise the voltage on the entire circuit; however, it can be a challenge to keep voltage at the end of the line high enough without going too high near the station. Capacitors help with this by “flattening” the voltage profile along the feeder.

Voltage Regulation Choices

Distribution voltage control starts at the substation, so distribution and substation engineers should work together to optimize overall economy and meet operational needs both inside and outside the fence.

One design decision is choosing the method of voltage regulation. Some stations have bus regulation, with the entire bus regulated by a load tap changer (LTC) built into the power transformer. Other stations have three single-phase voltage regulators per feeder.

The traditional view is that choosing between bus regulation and feeder regulation is a simple matter of minimizing initial cost. If a station has only a few circuits, then it might be less expensive to use single-phase voltage regulators on each feeder. If there are several circuits, then the LTC might cost less.

Operational issues must be considered as well. From the distribution operations perspective, feeder regulators have some advantages. Often, distribution circuits are dissimilar in length and conductor size, and their loads can be unbalanced. Single-phase regulators can respond individually to the needs of each feeder and phase. However, care must be taken not to overload the regulators if circuits are reconfigured in the field during trouble.

Bus regulation with an LTC is helpful at correcting for variations of transmission voltage that would affect all phases and circuits alike. It is a good choice where all of the distribution circuits are similar in size, length and loading. The area should have strong distribution ties between stations, because maintenance work on the LTC will require the entire bank load to be transferred or interrupted.

Voltage regulators can be pole-mounted if necessary, and Georgia Power occasionally uses them outside of substations. These installations are uncommon except on a few extremely long rural lines with small conductors.

Regulator Controls and SCADA

Electronic controls, now routinely specified for all new voltage regulators, have been retrofitted in many existing units.

Most distribution substations are equipped for SCADA, which enables operators to check bus voltage remotely. The system also has alarms for high or low voltage. In addition, SCADA logs provide load data to help engineers anticipate the need for system improvements before voltage problems escalate.

Distribution Line Design

Distribution line design has a huge impact on lifetime economy and ease of operations, as well as power quality. Engineers at Georgia Power try to limit the system's voltage drop so that service voltages can be maintained without unusual operating procedures or frequent reconfiguration of circuits. When selecting a conductor size for new lines, they take into account both voltage drop and the economic value of future losses.

Distribution Capacitors

Capacitors reduce current and therefore reduce losses and voltage drop, especially during the hot Georgia summers when air-conditioning loads are at their peak. Early capacitor banks were installed mostly in substations, where they benefited generation and transmission, but had little effect on distribution lines. In recent decades, capacitors have been dispersed throughout the distribution system to extend the benefits.

Georgia Power has more than 4300 pole-mounted capacitor banks, ranging in size from 600 to 1200 kVAR, all connected in grounded wye configuration. Many are fixed banks that stay online continuously all year, while others are switched seasonally to stay online from spring through fall. About 2900 banks are switched with automatic control units to power on whenever they are needed.

Voltage-sensing digital controls are presently the most common type being installed at Georgia Power. These work especially well on long lines with small conductors, where voltage drop is the most critical issue. Some of the newer units are equipped for remote control through the SCADA system, which has expanded beyond the substation fence out onto the distribution lines.

When digital electronic controls became available in the early 1990s, the company began using more VAR-sensing controls. These proved to be a beneficial choice for circuits where system losses are more of an issue than is voltage drop — especially for industrial feeders, where large conductors and short distances provide strong voltage even when power factor is poor.

Vacuum switches became standard for new capacitor banks in 2001, because they are expected to require less maintenance than oil switches. Although there is no plan to accelerate the retirement of the thousands of oil switches currently in service, this issue is re-evaluated from time to time.

Distribution Efficiency Program

No discussion of voltage and reactive power control at Georgia Power would be complete without mentioning the Distribution Efficiency Program (DEP), which started in 1996. The program was intended to shave demand by 200 MW, and it has exceeded expectations.

The basic idea of DEP was to decrease demand by lowering voltage. That was already a well-established concept, but DEP married modern SCADA technology with modern capacitor controls to make the process easy to control remotely, while maintaining acceptable voltage for all customers. Remote control allows reductions in peak demand without affecting energy sales at non-peak times when capacity is in ample supply.

For DEP, regulators and LTCs were retrofitted with electronic controls, which were then connected to the SCADA system. Programmers set up software commands that would let operators lower the voltage simultaneously on large groups of feeders by executing simple commands, known as “pushing the big red button.”

To maintain acceptable voltage for customers at the end of the line, the voltage profile along the feeder had to be flatten by installing switched capacitor banks all along the line. With DEP, a circuit that previously had two or three 1200-kVAR banks might [after DEP] have four to six 600-kVAR banks, correcting the feeder's power factor to near 100%. The capacitor controls are voltage sensing, and their settings are coordinated so they come on in proper sequence after the regulators drive down voltage. Although the capacitor banks are not remote controlled, some are monitored for status by the SCADA system.

Results of DEP

DEP has surpassed its goals. It reduced the 2001 peak demand by 264 MW, and net savings are projected to be US$24.1 million over 15 years. The project deferred the need for new generation and relieved stress on the distribution system and substations during seasonal peaks. The program involves approximately 450 feeders in 171 substations.

Acknowledgments

The author would like to thank IEEE for permission to use a paper he presented at the 2003 IEEE/PES Conference for this article. The author also thanks Jim Bright for providing information on the DEP project.

Lee E. Welch earned the BSEE degree at Mississippi State University. His experience at Mississippi Power Co. and Georgia Power Co. includes distribution engineering, region operations and metering. He currently specializes in distribution reliability. Welch is a registered professional engineer in Georgia, Alabama and Mississippi, and a senior member of IEEE.
LEWELCH@southernco.com

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