Voltage stability and reactive power system restrictions have become growing concerns for utilities following the adoption of the Federal Energy Regulatory Commission's (FERC) open-access policies. Generation resources are being dispatched differently, further taxing already heavily loaded transmission corridors. As upgrades or replacements are made to the grid, it's imperative that the resulting system has the stability to withstand “system swings” and severe grid disturbances, especially in light of the vulnerability shown during the August 2003 blackout.

Pacific Gas & Electric Co. (PG&E; San Francisco, California, U.S.) considered these system concerns as it faced the need to retire old synchronous condensers that were reaching the end of their useful life at its Hunters Point Power Plant (HPPP). After assessing different options, PG&E determined that Flexible AC Transmission Systems (FACTS) devices could cost effectively replace the synchronous condensers and provide the voltage stability needed for the bulk transmission system.

Bay Area Transmission System

Transmission lines and local power plants supply electric demand in the city and county of San Francisco and the peninsula. HPPP and PPP are the power plants presently in operation within San Francisco. They are also major sources of dynamic reactive power support for the city. Their total combined generating capacity is 570 MW. There is also a 28-MW co-generation power plant, United Airlines Cogen, near San Francisco International Airport, which normally serves the United Airlines load south of the city.

The San Francisco Bay Area has some local generation but also imports electricity from outlying 500/230-kV substations and their connecting 230-kV transmission lines. The photo below shows the existing generation and transmission system in the Geater Bay Area (GBA). Most of the existing generation is concentrated in the northeast Bay Area — the Pittsburgh/Contra Costa region. Tesla, Metcalf and Vaca Dixon 500/230-kV substations are the three major bulk transmission sources that provide additional load-serving support for the Bay Area. Various 230-kV interconnections from Moss Landing Power Plant and the Geysers geothermal plants to the Bay Area also result in higher power import capability for load-serving purposes. In addition to the voltage support provided by generation in the area, there are several synchronous condensers (dynamic devices) and shunt capacitors (static devices) available for voltage support at 115-kV and 230-kV voltage levels.

Aging Assets at Hunters Point Power Plant

HPPP Units 2 and 3 were converted from power generation in 2001 to synchronous condenser operations to provide a total reactive support ranging from -80 to +162 MVAR. As condensers, HPPP Units 2 and 3 have performed satisfactorily and have been integrated into the planning and operation of the Bay Area transmission system to serve electric customers; however, both units are almost 55 years old. Capital-intensive equipment replacements soon will be needed, in addition to high ongoing operation and maintenance costs.

All synchronous condensers are expensive to maintain compared with traditional substation equipment. Periodic overhauls are required to ensure reliability. Structurally, the concrete foundation of both HPPP condensers is of concern because of its age. The foundation shows significant deterioration that will increase in severity with time. Within the next five years if the condensers continue to operate, additional investment will be needed to replace or refurbish electric components, such as Unit 3's rotor, both units' main and auxiliary transformers, copper bus work and enclosures, and associated protection and control systems. Upgrades also will be needed for the hydrogen cooling, mechanical and pumping systems.

Since generators located in the GBA are needed to maintain local area reliability, the California ISO (CAISO) has been using reliability must-run (RMR) contracts to maintain reliability and curb the market power of generators. PG&E makes significant payments to generating plant owners in the GBA under various RMR contracts to generate power and provide adequate voltage support for reliability. The shutdown of one or more of these HPPP condensers would have impacted system reliability and required contingency plans that may have customer service impacts in the city.

Analysis and Recommendations

PG&E performed a comprehensive reactive analysis of the GBA transmission system and determined that the dynamic reactive support currently available from these two condensers at HPPP was an absolute necessity to maintain system reliability, especially with the continued load growth and planned shutdown of HPPP in the city. The reactive support maintains an acceptable and necessary reactive reserve margin to mitigate voltage instability from unscheduled generation and transmission contingencies during high load conditions. Based on technical review, the costly upgrades of these aging condensers to resolve various technical, operational and environmental problems cannot be justified for their remaining life. Shunt capacitor banks also provide economic reactive support to transmission systems. But unlike synchronous condensers, shunt capacitors lack the damping and dynamic support capability because of slow switching and lack of inertia. Switching of shunt capacitors is simply too slow to provide the needed dynamic response, and their ability to provide support diminishes in a nonlinear fashion as system voltage drops off during unscheduled outages.

During 2002, an additional 150 MVAR of shunt capacitors were added at Potrero Switchyard to improve voltage profile in the area. Because slow-switched conventional capacitors do not provide dynamic reactive support, the system's dynamic reserve margin — to prevent fast voltage collapse — was not noticeably improved. The need for dynamic support to minimize the risk of voltage collapse, particularly during disturbances on the 230-kV system, remains critical in the GBA. PG&E conducted technical that confirmed the need to install a fast-acting dynamic FACTS device. Based upon study results, the recommended plan was to retire both synchronous condensers at HPPP with a single SVC system.

Potrero SVC

Consistent with study results, PG&E implemented a major capital project to install an SVC rated at -100/+240 MVAR at Potrero 115-kV switchyard. The new facility became operational by December 2004. The SVC has a short-term (4 hour) 10% overload capability of 264 MVAR to address system dynamic reactive requirements during severe disturbances in the GBA. Potrero SVC is comprised of one 174 MVAR thyristor-switched capacitor (TSC), one 190 MVAR thyristor-controlled reactor (TCR) and two harmonic filter branches rated 55 and 35 MVAR and tuned to the 5th and 7th harmonic, respectively. This creates the required dynamic range (inductive and capacitive) to provide rapid reactive power and voltage modulation during system disturbances that slow switched shunt capacitors and reactors are unable to provide. The TSC is an on-off device. The TCR reactive power absorption is continuously variable from zero to its rated value, because of the phase control of its conduction interval, which controls the fundamental frequency component of reactor current. The SVC will be connected to the 115-kV transmission system via three single-phase power transformers. The three-phase ratio of the transformer is 115/21.8 kV. Phase-angle control of the TCR and switching of the TSC obtains a continuous variable output through the entire output range of the SVC.

The SVC controls also would monitor and control operation of the three 75 MVAR mechanically switched capacitor (MSC) banks at Potrero for a fully integrated reactive compensation system. This SVC will be capable of maintaining virtually constant voltage at the point of interconnection — by reactive injection within one to two cycles. Such an integrated family of SVC with MSCs and associated digital control logic systems is commonly known as a static VAR system (SVS) unit.

Keeping the Power On

The SVC is controlled by a microprocessor-based control system that provides facilities for SVC control, either from the operator workstation (OWS) in the SVC control room or remotely by a conventional RTU/SCADA system.

The MSCs are operated either automatically from the SVC control or remotely from the PG&E transmission control center. In addition, the MSCs can be operated from the SVC OWS to be located in the SVC control cubicle at Potrero. The OWS shows the indications of the MSC circuit breakers and disconnector switches. The SVC will be controlled by a microprocessor-based control system similar to the Newark SVC control system. Dedicated voltage and current transformers provide the control system with information of the network condition, used to control the SVC. The control system provides facilities for SVC control either from the OWS in the SVC control room or remotely from a conventional RTU/SCADA system.

The normal mode of operation is automatic voltage control. The voltage control system is a closed-loop system with positive sequence voltage control. The voltage regulator must be fast enough to counteract voltage variations and disturbances and also retain an adequate stability margin. The positive sequence voltage on the 115-kV side of the SVC transformer is compared with a set voltage reference and controlled by the automatic voltage regulator.

The most critical failure point of an SVC system is the transformer, which would result in 100% loss of the system. For the SVC system, a “firm bank” comprised of three single-phase units plus a spare unit with associated bus work (typical for PG&E) will be employed. This will allow restoration of service within hours should a transformer phase fail. SVCs are widely used around the world both for their capabilities and for their low maintenance costs; the devices have no moving parts, so repairs are minimal.

PG&E issued a request for proposal to various qualified FACTS suppliers using a competitive-bidding process. ABB was awarded the project after completion of a careful bid evaluation process by the PG&E project team. Technically, ABB's solution offered a robust design ensuring high availability and reliability of the SVC unit. ABB also was able to commit to an 18-month turnkey delivery time to meet the critical in-service date.

SVS Arrives

ABB built a separate control room at the Potrero Switchyard for housing the thyristor valves and all associated control systems, including the MACH2 computer workstation for controlling the static VAR system.

The three 75 MVAR MSC banks are incorporated into the SVC voltage control to optimize operation to within +80/-40 MVAR, thus maintaining the dynamic SVC range for contingencies.

In automatic SVC mode, the MSCs are either in or out of service, depending on the capacitive power demand monitored by the SVC. In manual SVC mode, the MSCs are controlled from the OWS in the SVC control room. In remote mode, the MSCs are controlled remotely from the PG&E system operations center via the RTU/SCADA, independently of the SVC control. Should the SVC for any reason trip for an internal fault while the MSCs are in operation and controlled by the SVC, the MSCs will remain in operation and automatically assume remote mode. Harmonic filters usually are required to keep voltage distortion in the network at acceptable levels. The harmonic filter is capacitive at the fundamental frequency and contributes to the net capacitive output of the SVC. Potrero SVC meets specified distortion requirements.

Adding the SVC with associated capacitors, filters and controls in San Francisco will help maintain an acceptable and necessary reactive reserve margin to provide voltage stability during unscheduled generation or transmission contingencies under high load conditions, which otherwise could result in blackouts in the Bay Area. The SVC is sized slightly larger than the existing condensers to accommodate shutdown of entire HPPP and future load growth in the city.

Bhaskar Ray is a senior consulting engineer in the transmission planning at PG&E. He has 15 years of experience in the power transmission business of electric utility industry. He received a MSEE from Iowa State University in 1991. Prior to joining PG&E, he was employed with Northern States Power Co. for 10 years in the transmission business unit. Ray is a senior member of IEEE and has held various positions in Mid-Continent Area Power Pool, including chairman of MAPP Transmission Reliability Assessment Group. BxR0@pge.com

Static VAR Compensators

A static VAR compensator (SVC) can maintain virtually constant voltage within two cycles and is also a regulated source of leading or lagging reactive power. An SVC works by varying its reactive power output in response to the demand of an automatic voltage regulator. An SVC is comprised of a thyristor-switched capacitor, a thyristor-controlled reactor and harmonic filters. Together, these devices create the required dynamic reactive range — inductive and capacitive — to provide rapid reactive power and voltage modulation during system disturbances that conventional slow-switched shunt capacitors and reactors are unable to provide.

An SVC is comprised of standard inductive and capacitive branches controlled by thyristor valves connected in shunt to the transmission network via a step-up transformer. An SVC acts much like a synchronous condenser in its ability to rapidly inject or absorb VARs to dampen transients. An SVC can operate repeatedly and rapidly to changing network conditions, such as line or generator outage contingencies.