One of the final frontiers of applying computerized technology to the power industry lies in automating reactive power control on distribution systems. Most utilities have capacitor banks distributed throughout their systems; operating them manually is a time-consuming, expensive process. Salt River Project (SRP; Tempe, Arizona, U.S.) has realized several improvements in service to its 800,000 customers, including:

• Capacitor banks are operated only when needed, rather than on a pre-programmed timed basis.

• The capacitor bank response time is minutes instead of days, generating reactive power when it is needed most.

• The “windshield time” of technicians is significantly reduced now that remote control of banks is available.

• Distribution system operators can immediately assist with customer voltage problems, quickly locate failed or inadvertently de-energized banks, and easily find switching and mapping errors.

Currently, SRP has 3500 capacitor banks on its system. Most of these (2900) are installed on the 12-kV distribution system. The remaining 600 are located in substations. All capacitor banks are three-phase, and most are rated 1200 kVAR. Nearly 1700 of the banks are padmounted (Fig. 1). To date, about one-third (1100) are on the Automated Capacitor Control System (ACCS).

The ACCS begins with the control computer (Fig. 2). When the control computer determines that a capacitor bank needs to be opened or closed, it sends a VHF radio-frequency signal to the individual bank (Fig. 3) from a radio tower. The input to the ACCS control computer is substation watt and VAR data, provided by the Ranger Energy Management System (EMS), shown in Fig. 4. Changes in the watt and VAR loading are transmitted back to the EMS, which updates the ACCS computer each minute, completing the feedback loop.

SRP uses a Fisher Pierce capacitor control equipped with an antenna (Fig. 5). These units include a voltage override option that opens and closes the capacitor bank in the event communication to the unit is lost.

The control computer uses Radio Control Central Stations (RCCS) software. Figure 6 shows the client software-viewing screen for eight 12-kV feeders out of one substation. The boxes represent line capacitor banks as they proceed from left to right across the screen, away from the substation. The banks in yellow are still locally controlled. The boxes in red represent closed banks, and green boxes represent a tripped (open) bank.

The RCCS turns on and off capacitors, controlling reactive power flow based upon user-programmable parameters. SRP maintains a power factor of 0.98 leading at the 12-kV bus of each substation in order to have unity power factor at the 69-kV primary bus. The user also can determine which bank to turn on first, second and so on.

A key benefit of the ACCS is that capacitor banks are operated only when needed. Previously, a technician had to look at historical power factor data, predict when a given bank should be turned on each day, and travel to the site to adjust the mechanical timer. For example, the capacitor bank may need to be turned on each day at 10 a.m. and then turned off at 6 p.m. This would continue each day, regardless of whether load changes might otherwise require different settings. A typical bank requires four adjustments annually, thus entailing four site visits per year. The ACCS does not require any technician visits and operates banks at different times each day, depending on the power factor at the substation.

Another benefit is improved response time. Figure 7 shows the power factor in green and the substation MVA load in blue for a few days in September 2000. Note that at times the load is low and the power factor becomes too far leading. Figure 8 shows the same system one year after the ACCS has been installed. Notice the power factor is much more stable and always within required parameters.

A significant savings in technician man-hours and driving time is yet another benefit. Technicians were driving 24,000 miles (38,600 km) or more each year to every timed capacitor bank. In the first year after the ACCS was installed, the workload was reduced by approximately three man-months. If a technician must check on a possible failed controller, he now can go to the site and troubleshoot the bank using a wireless laptop.

Perhaps the most surprising benefit is how well the System Operators (Dispatchers) have acclimated to the ACCS. The ACCS does not require a new computer console and only involves a half-hour of training, along with some practice. If a capacitor bank is needed to improve voltage to a customer, the ACCS eliminates the need to send out a troubleshooter to operate the banks on nights and weekends. If a given bank is suspected to be the cause of imbalance on a circuit (usually because all three phases of the bank did not close in), the operator simply closes the bank and watches the ground currents on the EMS. If the ground current increases when the bank is closed, it is manually opened using the ACCS, isolating the problem. There have been cases when a healthy bank is closed, but the VARs change on a different circuit. This has led to the discovery of banks that are incorrectly mapped or inadvertently switched onto the wrong circuit. Occasionally, a bank that is thought to be 1200 kVAR will result in only a 600-kVAR change at the substation. A field visit will verify that what was recorded as a 1200-kVAR bank was in fact half that size.

Implementing the ACCS has not been without challenges. Systems in service 24 hours a day require a higher level of computer hardware in the form of reliable backup hard drives. Therefore, several people must be on-call day and night to assist with any possible system problems. In addition, personnel must check system operation daily, and anyone with access to the system must be trained on the importance of keeping it running. In one case, a software technician shut down the RCCS software to install virus protection software and failed to restart the software. That evening, the temperature dropped dramatically, from 90°F to 40°F (32°C to 4°C). By early morning, there were too many VARs on some parts of the system.

Another critical issue is ensuring the MW and MVAR data are reliable and available. The servers that provide this data are used by multiple departments, and thus occasionally must be taken down for testing and maintenance. When that happens, the ACCS might not get the data it needs to effectively control power factor. Fortunately, the RCCS software has a backup mechanism to use data from the previous 24 hours. Loss of input data from the EMS has been the most common cause of problems with the system and occurred monthly the first year of operation. Automatic movement to a backup server has essentially eliminated this problem, although there are times when both servers may not be available.

Another problem was vandalism of antennas on he padmounted banks, particularly at banks near school bus stops. Curious youths were bending and breaking off the antennas, but a vandal-proofing technique has effectively stopped these breakages (Fig. 9).

Options to ACCS

Alternatives to the type of ACCS described here include using two-way communications to and from the capacitor banks, which ensures the user knows the status of every bank. SRP opted to use one-way communication because the towers and infrastructure for a VHF radio signal were already in place, thus lowering the cost. Another alternative is to install an electronic controller on each capacitor bank that turns the bank on and off based upon the local power factor. Again, cost is an issue, as each controller is more expensive and there is no remote control of such a system.

SRP initiated the ACCS in 1999 and expects to complete the system by 2010. The added flexibility, cost benefits and operational value make it an efficient way to monitor and control the power factor to customers.

Acknowledgments

The author thanks Kristian Koellner, Philip Menne, Wally Pitts, Jason Smith and Ron Wilson for their assistance in writing this article.

Daniel Goodrich earned his BSEE degree from Arizona State University and has worked at SRP for 18 years. He is a senior member of the IEEE and a Distinguished Toastmaster.
dagoodri@srpnet.com