Reliably serving large motor loads at the end of a long overhead distribution circuit is quite a challenge. Not only does it require trying to mitigate the typical interruptions associated with line exposure but also finding a viable way to strengthen the distribution source so it can handle hard-starting loads.

After reviewing design alternatives, Wisconsin Public Service Corp. (WPS; Green Bay, Wisconsin, U.S.), a WPS Resources affiliate, installed a distribution-voltage static VAR compensator to remedy the situation. The installation eliminated flicker concerns and reduced voltage sags caused by lateral fuses clearing downstream of the installation.

WPS and its subsidiaries serve 450,000 customers in central and northeast Wisconsin and the Michigan Peninsula. While the service areas include towns and cities like Green Bay, long distribution circuits typify the service territory. Reports of objectionable voltage flicker were increasing on a specific 25-kV circuit. A long-time customer, a hardwood sawmill, was suspected to be the primary voltage-flicker source. Data collected near the mill over a month-long period confirmed it was the source and also confirmed frequent and significant sags.

Table 1. Primary Voltage Sags

Sags		GE flicker curve ΔV/V levels at observed frequencies
Magnitude	Frequency (per hour)	Visibility	Irritation	Con Ed (objection)
2% to 4%	10	1.1%	3.1%	6%
4% to 6%	5.5	1.4	3.5	6.7
>6%	2.2	3.2	4.4	NA

On-site inspection determined the sawmill contains seven motors capable of causing sags greater than 2% when starting or when loaded close to locked rotor conditions. Two nearby facilities contain four other motors capable of contributing to the primary flicker levels observed. The motors operate independently and several can conceivably contribute to any sag event. Review of the collected data showed sags ranging up to 10%, which could only be caused by several motors being overloaded simultaneously.

Reconductoring to eliminate the flicker would not be cost effective because the location is more than 20 miles (32 km) from the nearest substation. The number and size of the motors involved makes a customer-side approach very expensive. A distribution-voltage static VAR compensator became the first consideration.

The company was already investigating capacitive static VAR technology, which eliminates sags and flicker with very rapid zero-voltage-differential capacitor switching. Placed adjacent to a problem load, they improve the circuit's apparent source impedance and isolate the remainder of the circuit from voltage fluctuations.

WPS approached distribution-voltage static VAR manufacturer Power Quality Systems (PQS; West Mifflin, Pennsylvania, U.S.) with the problem. PQS performed a power system and load study using the existing WPS data and recommended an advanced static VAR compensator (ASVC) system optimized for motor-related sags and flicker.

The recommended system provides VAR support in 150 kVAR/phase steps from 0 to 1050 kVAR/phase, providing a voltage resolution better than 1.4%, which is close to the GE flicker curve “level of visibility.” It is sized to handle two motor starts and two near-locked rotor conditions occurring simultaneously, because of the multiple-motor sags identified in the data collected. PQS identified two more issues. First, an ASVC that connects directly to 25-V distribution is more expensive than the correspondingly sized 15-kV class system. Second, the maximum capacitance applied will lower the resonant frequency at the site below the third. This increases the chance that harmonic amplification will occur and results in a PQS recommendation to add harmonic detuning filters to the system.

Addressing both, PQS proposed a 15-kV class ASVC connected through a step-down transformer bank. Three standard 500-kVA 14.4/7.2 kV wye/wye transformers would adequately connect the ASVC to the 25-kV primary and act as harmonic detuning filters. These recommendations eliminated cost of harmonic filters and reduced the net cost well below a filtered system connecting directly at 25 kV.

Dual Benefit

Reviewing the proposal, WPS personnel mentioned a second power-quality problem. Laterals to the main 25-kV circuit are fused. When lateral faults occur beyond the proposed ASVC location, the entire circuit experiences sags lasting 20 to 30 cycles before the lateral fuses clear. Could the ASVC use its available VARs to support the line voltage on the affected phase(s), “feeding the lateral fault” and reducing clearance time?

Responding, PQS proposed an “IntelliSwitch” containing a modified control system, which allows independent VAR control on each phase, and allows for multiple sets of current sensors. Two sets of current sensors are now proposed. One set to monitor the flicker-causing customer site, while the other monitors total downstream current on each phase. The total system capacity is not changed.

System Design and Installation

WPS identified four sites and two were investigated. The site selected placed the ASVC system immediately adjacent to the problem load.

PQS supplied complete drawings to install the ASVC on an 18-ft (5-m) Aluma-form rack. WPS designed the remainder of the installation including an additional 18-ft Aluma-form platform with three 500-kVA step-down transformers, and six current sensors in at two locations, one measuring the problem load, the other monitoring down-circuit.

The ASVC is connected in shunt to the circuit it compensates. The simplest system installation placed the step-down transformers on a platform underneath the existing 25-kV lines, and then, using two new poles, placed the ASVC on a platform parallel and about 15 ft (4.5 m) away from the existing circuit.

Site preparation used a line crew, two hoists and a pair of bucket trucks and took about a day and a half. The work consisted of:

• Placing a new two-pole line on an 18-ft center.

• Placing a third pole under the existing 25-kV line to permit installation of an Aluma-form platform.

• Mounting two 18-ft Aluma-form racks. The step-down transformer platform was placed under the existing 25-kV line. The ASVC platform was placed on the parallel pole line.

• Running a two-by-six used for mounting the fused cutouts below the ASVC pole tops.

• Mounting a 10-kVA 7200/120 V step-down transformer on the center pole power the communications box. This allows for remote dial-up interrogation of the ASVC.

• Running a customer-provided phone line to a nearby pedestal.

System installation began as soon as site preparation was completed. The three 500-kVA 14.4/7.2 wye/wye transformers were mounted on the first platform and fused on the high side.

Actual ASVC installation took four hours. The system arrived on three pallets, and required one lift per phase. Each phase required one power connection to the appropriate fused overhead cutout. Grounding was through the alumna-form platform. Bright yellow control cables were run from the integral control box located underneath the middle phase to each module and tightened. The communications box, which is fiber-optically isolated from the ASVC and provides local and remote system control, was installed at the same time. Placed at the base of one pole, it was connected to 120 V (from the 10 kVA transformer), to the telephone line and to the ASVC via fiber-optic cable.

The only task remaining was placing and connecting the current sensors. Six sensors were required in two sets. Cable runs were minimal at this location, since both sets of sensors could be placed within 200 ft (61 m) of the ASVC. The current sensors were externally summed (paying careful attention to maintain proper phasing) and fed to the ASVC.

Start-up took less than 90 minutes and almost seemed anticlimactic. When the cutouts were closed, the ASVC powered up immediately and without incident. The control system was immediately placed in open loop to prevent inadvertent operation. The internal ASVC voltage sensors were calibrated based on clamp-on readings provided by the line crew. Then the external current sensors were calibrated in the same manner. After that, each capacitive step was manually switched to ensure proper operation. The controls were then optimized based on the power-quality data WPS originally collected. The system was placed in closed loop and began operating.

Engineer field training took place concurrently with ASVC start-up and testing. After PQS personnel initially placed the ASVC in open loop, WPS personnel performed the other tasks under PQS supervision. After the unit was online copies of a “cheat sheet” of frequently used ASVC commands was provided to all present and placed in the communications box.

New System, New Training

WPS began training assessments a month before system installation. PQS trained three engineers on the ASVC during installation. The line crew performing the installation received hands-on training at the same time.

Virtually any lineman or engineer in the district could encounter the ASVC during storm duty. During storms chances that the circuit and ASVC would be in abnormal states are greatly increased. Basic ASVC awareness and safety training was planned for all district line crews and engineers. After a planned presentation by PQS was cancelled (line crews and district engineers were unavailable to be present due to inclement weather), WPS personnel presented a slide-based training presentation.

A lineman's job demands familiarity with a wide variety of equipment. Equipment deviating from the “norm” or requiring specialized handling complicates field operations. Because the installation includes common distribution system components — line capacitors, platforms, cutout type fuse links, and current-limiting fuses — linemen rapidly became comfortable with the ASVC during training.

The control system shuts down when line voltage is outside a preset range, and auto-starts when circuit voltage remains within a “normal” range for 3 minutes. Personnel were taught that they could remove the ASVC from the circuit using the local hand-held terminal to remove all capacitors from the line and then opening the fuse links without a capacitive load, or by simply opening the fuse links under capacitive load. Once finished in the area, they need only close the cutouts and walk away; the auto-start feature means the ASVC will come on-line, self-test and restart automatically. Crews encountering the ASVC during storm situations will treat it in the same manner they would a normal capacitor bank.

Post-Installation Performance

Since installation the ASVC has performed reliably. There have been a couple nuisance “new installation” glitches, such as broken phone wires and fuse coordination. One valve on the unit failed because of a manufacturing defect. PQS replaced the valve, recertified each module in the unit and extended the warranty.

One nagging problem almost defied resolution. The circuit had a lagging power factor, but the ASVC would report a leading power factor. This was a serious problem since the ASVC would not correct flicker until the power factor became lagging. Software modifications and new control system parts did not affect the readings. Finally, lab tests showed that the sensors used on the 25-kV circuit delivered their reactive current measurements 90 degrees out of phase with the printed technical specifications. PQS supplied a software patch to account for the phase shift and the controls have worked smoothly ever since.

WPS supplied the current sensors. PQS, who always used another manufacturer's sensors, approved the use of these sensors, and programmed the ASVC based on the technical literature. The quick and simple joint decision to use a new current sensor wound up costing more hours than anything else associated with the project.

The lessons learned from the ASVC application include:

• The ASVC will eliminate flicker and associated sag complaints on the circuit.

• The need to perform training soon and keep it simple.

• Turnkey contracts work well for first installations. Most troubleshooting time can be avoided if testing is performed prior to shipment.

Melinda A. Mangold is a professional engineer in the state of Wisconsin. She received the BSEE and BSBS degrees at Michigan Technological University in 1984. She spent 12 years as a distribution electrical/field engineer at the Upper Peninsula Power Co. and five years as a distribution planning engineer at Wisconsin Public Service Corp. She is currently manager of engineering design at Kansas City Power and Light.
Melinda.Mangold@kcpl.com

Brian C. Teddy is a professional engineer and received the BSEE degree from Michigan Technological University in 1998. He works for Wisconsin Public Service Corp. as a regional electric engineer.
bteddy@wpsr.com