By Bob Fesmire, ABB Inc. and Dominic Berlingieri, PHI
FACTS devices had a big year in 2006, with numerous projects being initiated across the country. The uptick in FACTS use is not surprising, given the growing need for voltage support and increased transmission capacity in many areas and FACTS’ ability to deliver those benefits in a small package.
Pepco Holdings Inc. (PHI), the parent company of Pepco, Delmarva Power and Atlantic City Electric, was among the utilities that ordered FACTS devices last year, in this case a Static Var Compensator (SVC) for the company’s Dennis substation. However, this is far from the extent of PHI’s experience with FACTS, which includes three other installations that were built earlier in the decade.
One SVC is Good, Two is Better
In the mid-1990s, PHI performed several system studies, which showed that by the 2000 summer peak season, reactive power support would likely be required in the southern portion of the Delaware-Maryland-Virginia (Delmarva) peninsula. System planning was focused on building resiliency in the face of losing a major transmission line or generator. Static capacitors would not work, simply because they could not be switched in pre-contingency due to ensuing high voltage conditions, and there was not enough time post-contingency for static capacitors to prevent an outage.
The solution PHI arrived at was to install an SVC at the 138-kV Nelson substation. The device would offer high-speed, dynamic voltage support in a cost-effective package, and was scheduled to be in service by the summer of 2000. However, shortly after the unit was ordered, the summer of 1999 proved to be a more demanding peak season than expected. With reactive loads on the Delmarva peninsula higher than forecast and generator forced outages exacerbating the voltage problems, it became clear that a second SVC would be needed, this one at PHI’s Indian River substation.
The second SVC would require some additional work, however. The 230-kV bus was expanded from a 4- to a 6-breaker ring bus arrangement, a line terminal was relocated to a new bus position, and a 50 MVAr 230-kV mechanically switched capacitor bank controlled by the SVC was also installed. All of the engineering, installation and testing had to be done on a compressed schedule to make the SVC available for the following summer, but the Indian River SVC was energized on time in June of 2000, one month after the Nelson SVC and just nine months after the order for the unit was placed.
Summer 2000 saw the commissioning of the Nelson and Indian River SVCs, both located in southern Delaware. That same year, PJM published its Regional Transmission Expansion Plan in which the system operator identified the need for yet another SVC. This one would be located at PHI’s 230-kV Cardiff substation near Atlantic City, N.J. Similar to the first two, the business case for Cardiff centered on the fact that static capacitors could not be switched in pre-contingency to maintain system voltages post-contingency. The Cardiff SVC was ordered in 2001 and energized prior to the summer of 2003.
All three of the SVCs deployed on the PHI system to this point were of similar design and identical size (+150MVAr /-100MVAr), the only major difference being the high side voltage rating of the transformer connecting the SVC to the transmission system. Power to the SVCs was provided from auxiliary windings in the power transformer. The main components included:
- Control and protection system;
- Thyristor controlled reactor bank (TCR);
- Thyristor switched capacitor banks (TSC);
- Harmonic filter banks;
- Power transformer; and,
- Cooling system.
Of course, no FACTS installation is entirely free of speed bumps, and PHI encountered a few along the way. For example, shortly after installation, a resonant condition was identified between the Indian River SVC and the transmission system. ABB worked with PHI to identify the cause and responded with filter modifications that took care of the problem. An additional filter bank was also installed at the Cardiff station to address the need for 11th harmonic filtering that had been identified in a detailed frequency scan study.
Other issues came up in the operation of the SVCs. The introduction of any equipment with such a direct impact on operations is bound to produce some challenges. Some of the adjustments included allowing the SVCs to do what they were designed to do, and only switch in other local capacitors if needed.
Training was instrumental in making for a smooth transition. ABB provided a two-day session for engineering, field supervision and system operations staff as well as a one-day course for field workers. The latter was done after the SVC was placed into service so the training could take place on the actual equipment. There was even training on how to use the capacitor can lifting device, which field crews put into practice a year later when PHI experienced a can failure.
PHI’s work with SVCs over the past several years has given the company invaluable experience with these devices. So, when PJM’s most recent Regional Transmission Expansion Plan called for a fourth FACTS installation on PHI’s system, the process was a familiar one. PHI’s fourth SVC will be installed at the 230-kV Dennis substation in the Atlantic region, and is slated to be online by the end of 2007. PHI’s past experience has allowed the company to provide valuable feedback to ABB so that the Dennis SVC will incorporate a variety of improvements and new features such as redundant control systems, integrated cooling system control (with redundant sensors), and an elevated bus structure entering the valve hall.
PHI’s SVCs have proven to be very reliable. The company continues to contribute to the advancement of the technology by providing operational feedback and suggestions for improvements. As the demands on the transmission system continue to increase, the role of SVCs-and FACTS devices in general-in enhancing system reliability is likely to expand.