Voltage sags and flicker are among the most common problems affecting distribution circuit performance. Both problems are caused predominantly by large nonlinear inductive customer loads. Examples of problem loads include windmills, arc furnaces, agricultural pumps, pipelines, and mining operations. In the past, engineers typically corrected these problems by upgrading or adding a new circuit. Today, however, distribution companies are using advanced static var compensators (ASVCs) as an alternative.
The traditional remedies for improving source impedance and reducing problem loads to acceptable levels can be costly. As stated above, these remedies include reconductoring (upgrading the circuit) and separating the problem load using a new (often dedicated) circuit. These solutions, however, require a permanent circuit-level investment to correct problems caused by a single customer. If circumstances change because of relocations, business failures, or operating modifications, the circuit may be overbuilt, leaving a stranded distribution asset.
Distribution-voltage ASVCs, on the other hand, lend themselves to field configuration and easy relocation. The Electric Power Research Institute (EPRI) and the National Rural Electric Cooperative Association (NRECA) pioneered these systems, which adjust capacitance on a 1-cycle basis, offsetting the offending loads and maintaining a stable voltage on the distribution primary.
In addition, the capital cost of a medium-sized ASVC system is equal to approximately 2 miles of reconductoring. A zero-maintenance design coupled with industry-standard distribution voltage capacitors and fuses helps further limit operating costs. The following case studies suggest that ASVCs can address many nonlinear load problems.
Case Number One
American Electric Power (AEP), based in Columbus, Ohio, uses ASVCs that range in size from 1200kvar to 4500kvar. AEP engineers employed their first ASVC at an area high school, which had recently installed two 300 hp chillers. The chillers' extended starting sag became the source of numerous complaints. Most noticeably, lights at the adjacent football stadium dropped out whenever the chiller motors kicked in.
Subsequent investigations showed that motor starts were causing a 5.9% drop on the distribution primary. The AEP engineers initially considered the reconductoring option, but the chillers were located thirteen miles from the nearest substation. Cost estimates for this type of project exceeded $500,000.
Another option involved the installation of a second-generation, 3-step-per-phase ASVC. Simulation tests indicated that applying three uniform steps would reduce the 5.9% primary drop to 2.2% for two cycles. AEP engineers chose this option, which cost less than $100,000 with installation.
The ASVC installed at the high school included one 120kvar and one 240kvar valve-capacitor combination on each phase (providing steps of 120kvar, 240kvar, and 360kvar per phase). It also was rated at 10kV to 15kV, but the engineers could alter the step size and unit capacity by changing software parameters and substituting capacitors.
Fig. 1 shows the pre- and post-installation motor-start recordings. The resolution target was based on motor-start frequency. During the uncompensated start, 10 cycles elapsed before the line voltage recovered.
Note that the voltage remains 1.5% lower while the motor is operating. During a compensated start, the voltage remained within 2.2% of the nominal line voltage for all but two cycles. The “kvar applied” line shows that 240kvar per phase were required for less than 0.10 sec during the start.
In the 17 months since the installation date, the unit has been out of service for a week (to replace a distribution capacitor). A senior lineman working in tandem with integral phone-line-based remote monitoring diagnosed and remedied the problem.
Case Number Two
Salt River Electric (SRE), a member of the East Kentucky Power Cooperative system, serves a pipeline pump station containing a single 800 hp motor. The motor is located at the end of a 12-mile, 12.47kV feeder.
With each motor start, voltage dips on the distribution feeder caused the surrounding customers to experience light dimming and flicker. The customer attempted to address this problem by installing a solid-state, current-limiting device. This reduced the current drawn by the motor, but it dramatically increased motor start times and left the voltage-sag problem unresolved. Studies showed that primary voltage sags exceeded 13% and motor start times reached 35 sec.
In addition, the current-limiting device caused significant 5th and 7th harmonics (see Fig. 2). More than 900 kvar per phase were required to support the voltage, and a 5th harmonic filter was necessary to avoid resonance in the high harmonic environment.
The operation of the ASVC shown in Fig. 2, however, shows no signs of harmonic resonance. The overall total harmonic distortion (THD) is lower when the capacitors are online.
In May 2001, SRE had an ASVC installed with valve-capacitor combinations of 300kvar and 600kvar per phase and integral harmonic filters (see the photo, on page 32). This was a cost-competitive solution compared to building a 5 MVA substation and 6 miles of 69kV transmission line.
Fig. 3, on page 34, shows motor starts with and without compensation. With compensation, the average start time dropped from 35 sec to 11 sec. In addition, the voltage sag was limited to less than 3%.
After the installation, one of two uncompensated attempts to start the motor while collecting data failed because of low voltage. The unit also experienced an intermittent problem resembling flicker that was eventually traced to a faulty 59-cent potentiometer in the control circuit. Since being replaced, the unit has operated flawlessly. If the pipeline pump's motor needs to be replaced, or if additional motors are installed, engineers can easily modify the ASVC.
Case Number Three
Mining operations and their related loads frequently cause voltage and sag problems. Most new mining operations are located in remote areas, last 3 to 5 years, and use large motors that continually operate at locked rotor levels. When the operations cease, these circuits no longer serve large loads, and previous upgrades are stranded.
One small, continuous-mining operation, located outside Pikeville, Kentucky, used the ASVC approach to diminish flicker problems. The mine, which was located twelve miles from the nearest substation, had two 135 hp motors — one on the mining gantry and the other on the cutter head.
Flicker complaints from neighboring customers had escalated to the regulatory level. Engineers measured maximum flicker levels of 8% on the primary. As it turned out, one or both of the motors operated several times per second under locked rotor conditions. Cost estimates for the circuit upgrade totaled $300,000.
Tests indicated that a 7-step (3-valve) ASVC would solve the problem and a 3-step one (2-valve) would reduce the problem. Step size (%ΔV) is important because, according to the GE flicker curve, finer voltage resolution is necessary while mitigating “fast flicker.”
In this particular application, the 7-step solution provided 0.9% compensation, and the 3-step solution provided 1.8% compensation.
The 3-step ASVC unit was installed in September 2000 for less than $100,000. Fig. 4 shows the compensated voltage and the amount of compensation applied at the mining site. The unit mirrored the changing load but did not hold the flicker below the flicker curve. It also was short 350kvar at simultaneous locked rotor, resulting in a 3% corrected voltage drop (8% uncorrected).
After the installation, complaints diminished by about 80%. Engineers planned on installing the 7-step solution, but the site was vacated before they could do so.
Though relatively new, ASVCs are a proven technology for addressing sags and flicker on distribution primaries. Advantages are lower cost, ease of operation, low maintenance, and flexibility in relocation and resizing.
There are several things to remember if you want to use ASVCs successfully. First, you must analyze existing circuit and load conditions and then determine the maximum kvar requirement and the minimum acceptable resolution (%ΔV). Finally, you must consider the magnitude and frequency of existing harmonics.
Kerry Diehl works for Power Quality Systems Inc., located in West Mifflin, Pa. You can reach him at email@example.com.
The author would like to acknowledge the contributions of the following people: Dr. Paul A. Dolloff, East Kentucky Power Cooperative; Eric Leef, American Electric Power; and Ramon Saenz Jr., Florida Power.