Bhaskar Ray Senior Member, IEEE Senior Consulting Engineer, Pacific Gas & Electric Company

FACTS TECHNOLOGY APPLICATION TO RETIRE AGING TRANSMISSION ASSETS AND ADDRESS VOLTAGE STABILITY RELATED RELIABILITY CHALLENGES IN SAN FRANCISCO BAY AREA Bhaskar Ray Senior Member, IEEE Senior Consulting Engineer, Pacific Gas & Electric Company ABSTRACT Loadability of electric transmission system in North America is currently influenced and restricted by several technical considerations. Since highly loaded transmission systems (with, consequently, high reactive power losses) are at the root of many reactive deficiency problems, it is not surprising that voltage instabilitykollapse are cause for increasing concem among transmission planners and operators. Detailed technical studies routinely performed by planners demonstrate that bulk system utilization is often restricted by voltage or angular instability related limits, which are typically significantly lower than thermal capacity limits. Relaxing such non-thermal transmission limitations in a cost-effective fashion can be very challenging in a deregulated utility environment. Recent experience at PG&E has shown that retirement of six aging synchronous condensers in the San Francisco Bay Area (which currently impose additional technical, operating and environmental problems coupled with high maintenance and operating costs) can be successfully accomplished with a (semiconductor-based) FACTS device installation in a cost-effective manner and thereby maintaining bulk transmission system reliability. PG&E installed a 230 kv (-100/+200 MVAR) SVS system at Newark substation near Silicon Valley during 2002. As a replacement for the condensers, a Static VAr Compensator (SVC) in the Bay area will help maintain an acceptable and necessary reactive reserve margin to prevent voltage instability arising from unscheduled generation and transmission contingencies during high load conditions in the Bay Area. This paper addresses reliability related issues arising from aging infrastructure and summarizes successful application of FACTS technology (equipped with smart digital control systems) to prevent any degradation of system performance upon retirement of synchronous condensers. INTRODUCTION FACTS (Flexible, ~ AC Transmission System) technology equipped with smart digital control systems offer an economic dtemative and can be successfully employed to maintain and enhance bulk system dynamic reactive reserve margin and address voltage stability related challenges. Historically, transmission planners have routinely conducted power flow and stability analysis to determine bulk power system performance and design the transmission grid to meet an acceptable level of reliability consistent with planning standards. This is typically accomplished with power flow analysis to identify thermal overloads and low voltage conditions resulting in criteria violations for a wide spectrum of credible generation and transmission contingencies. Dynamic simulation studies primarily focus on transient-stability analysis related to classical angular instability problems, and in some regions also on smallsignal stability restrictions due to lack of system damping. Utilities are faced with additional challenges when placement of new generation is not driven by planning studies but rather by market forces (in a deregulated environment), permitting issues and strict environmental constraints. Under these scenarios, load centers often end up connected far from generation resources and through heavily loaded weak transmission. Such 0-7803-81 IO-6/03/$17.002003 IEEE 1113

heavy reliance on power transfer on the aging transmission facilities in the US. is the root cause of many voltage stability problems. Therefore, reactive analysis and mitigation of voltage instability must become an integral part of planning and operating studies for transmission asset owning companies. This paper documents application of FACTS technology to mitigate risk of voltage instability in the Bay Area and thus ensure adequate load serving capability in the service territory. Bay Area Transmission System The San Francisco Bay Area load is supplied by both intemal generation and imports from outlying 500-230 kv substations and their connecting 230 kv transmission lines. Most of the existing generation is concentrated in the northeast Bay Area (the PittsburgIContra Costa region). Major generating units in San Francisco are the Hunters Point and Potrero power plants that are also major sources of reactive power SUDDO~~ in the area. Tesla. Metcalf and Vaca Dikn 500-230 kv substations are the three major bulk transmission sources that provide additional load-sewing 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 a number of synchronous condensers (dynamic devices) and shunt capacitors (static devices) available for voltage support at 115 kv and 230 kv voltage levels. Newark 230 kv substation near Silicon Valley also is a major location in the Bay Area because of its strong electrical interconnections with neighboring substations via 230 kv and 115 kv networks. Background of Aging Assets Six synchronous condensers at Newark 230 kv substation. primarily provided voltage support for the South Bay and Silicon Valley in the past. There were serious technical, operational and - environmental problems with the six condensers at Newark substation. Due to rapid load growth in Silicon Valley, system reactive margin had been reduced considerably thereby increasing the risk of voltage collapse. Consequently, the synchronous condensers or some other VAR source was vital to system security in this region. These six units were installed between 1934 and 1943; two of them had heen de-rated from 15 MVA to 10 MVA because of cable failure and numerous other breakdowns, requiring repair. Based on the service life of the two oldest units and the condition of the other condensers, the remaining condensers were fast approaching their end of life. However, the collateral equipment is largely original including breakers, oil pumps, regulators and controls. Maintenance and water treatment was of increasing concem; another primary cause for possible retirement is their unreliability. It was becoming increasingly difficult to keep the units operating and to know they will be online to respond whenever a system disturbance occurs. All synchronous condensers are expensive to maintain compared with traditional substation equipments. Periodic overhauls are required to ensure reliability. These overhauls are expensive because the condensers are large horizontal salient-pole machines. A mobile crane is required to disassemble the condenser for inspection and repair. In addition, the cooling water system required high maintenance. The condensers are cooled using open cooling towers that requires make-up water. The cooling towers also need periodic cleaning and their relatively short life means added refurbishments or replacement expenses. Historically the cooling water has been chemically treated to control scale formation and biological growth in the heat exchangers, piping and cooling towers; cooling water blowdown was discharged into an open field. As a result of stricter environmental regulations this practice was discontinued. Without a ready disposal mechanism, blowdown was discontinued and today bio fouling and scale are of great concem; no matter what method is used to treat or flush the systems, it is now an expensive proposition. 1114

PG&E makes significant payments to the generating plant owners in the Bay Area under various Reliability Must Run (RMR) contracts to generate power and provide adequate voltage support for area reliability. The loss of one or more of these condensers would have required contingency plans that may have customer service impacts. PG&E performed a reactive margin sensitivity analysis of the Bay Area transmission system and determined that the dynamic reactive support currently available from these synchronous condensers at Newark was an absolute necessity to maintain system reliability, especially with the continued load growth. The VAr support maintains an acceptable and necessary reactive reserve margin to mitigate voltage instability from unscheduled generation and transmission contingencies during high load conditions. Based upon study results, PG&E replaced the six synchronous condensers with a single Static VAR Compensator (SVC) system, which became operational during June, 2002. An SVC is comprised of thyristor switched capacitor (TSC), thyristor-controlled reactor (TCR) and harmonic filter (HF) which creates the required dynamic reactive 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 due to phase control of its conduction interval, which controls the fundamental frequency component of reactor current. The SVC controls would also monitor and control operation of the existing 225 MVAR mechanically switched capacitor (MSC) banks at Newark for a fully integrated reactive compensation system at 230 kv level. SVC is capable of maintaining virtually constant voltage at the ooint of interconnection (by ~, reactive injection within 1-2 cycles). Such an integrated family of SVC with MSCs and associated diaital - control logic systems is commonly known as an SVS (Static VAR System) unit. SVC system technology is mature with a proven track record of more than 25 years. This established semiconductor-based FACTS technology has been extensively installed and operated in the transmission grid to relax nonthermal system limitations. Concentrating the reactive support from six condensers to a single SVC system, though, increased the sensitivity to reliability. The most critical failure point of an SVC system is the transformer, which would result in 100 percent loss of the system. For the SVC system, a firm bank of 3 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. The SVC itself is composed of steps or segments with selective redundancy such that any particular component failure would result in either no or only partial reduction in operating capacity of the unit. PG&E does not have any SVCs on its system, but numerous utilities in the U.S. and world wide successfully operate similar systems for dynamic support of their transmission systems. This reconmended altemative is the lowest cost option that meets the dynamic capability requirements, and is a proven technology. Application of other FACTS devices including a STATCOM was evaluated in the analysis. The limited utility experience base (operating history) for STATCOMS creates uncertainty as to the in-service availability and reliability of these units. While a STATCOM provides a few benefits over an SVC (such as response time), these benefits are not required for this project and the additional costs are not justified for capturing these slight incremental benefits. The majority of the STATCOMs are bas9 upon Pulse Width Modulation (PWM) technology, which result in higher losses compared with a similar size SVC unit. At present the cost of a STATCOM is at least 25 percent more than an equivalent sized SVC unit in PG&E experience. Newark SVC Design A Static Var Compensator (SVC) is a regulated source of leading or lagging reactive power. By varying its reactive power output in response to the demand of an automatic voltage regulator, an 1115

SVC can maintain virtually constant voltage at the point in the network to which it is connected. 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. Thyristor control gives the SVC the characteristic of a variable shunt susceptance. In terms of its dynamic performance, an SVC acts much like a synchronous condenser in its ability to rapidly inject or absorb VARs to dampen transients. Unlike a synchronous condenser, however, an SVC has no inertia and contributes nothing to the network short circuit level. Unlike mechanically switched compensation, an SVC can operate repeatedly and is not encumbered by the delays associated with mechanical switching. This lets the SVC respond very rapidly to changing network conditions such as lie or generator outage contingencies. The SVC will be connected to the 230 kv system at the Newark substation and consists of one 154 MVAr Thyristor Controlled Reactor (TCR), one 166 MVAr Thyristor Switched Capacitor bank (TSC) and two 27 MVAr filter branches tuned to the 5th and 7th harmonic respectively, giving the SVC an operating range from 100 MVAr inductive to 220 MVAr capacitive. The SVC is connected to the 230 kv grid via three single phase power transformers connected in Yddl 1. The three phase ratio of the transformer is 230/21.5 kv. Phase angle control of the TCR and switching of the TSC obtains a continuous variable output through the entire output range. In addition to the SVC, three Mechanically Switched Capacitor banks (MSCs) are connected to the 230 kv bus located in the Newark substation. The MSCs are operated either automatically from the SVC control or remotely from the PG&E control center. In addition the MSCs can be operated from the SVC Operator Work Station (OWS) located in the SVC control cubicle. The OWS shows the indications of the MSC circuit breakers and disconnector switches. The SVC is controlled by a microprocessor based control system. The control system is based on the MACH 2 concept, built around an industrial PC with add in circuit boards and I/O racks connected via standard type field buses. 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 Operator Work Station (OWS) in the SVC control room or remotely via a conventional RTU/SCADA system. Newark SVC Control System In order to achieve highest possible availability of the SVC the control system is structured in following modes: 0 Automatic Voltage Control 0 Manual Control 0 Forced Manual Control I I Figure I : SVC Voltage ControlBlock Diagram The normal mode of operation is Automatic Voltage Control. As shown in Figure 1, 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 regulator output is the susceptance reference. The voltage response is multiplied with the susceptance reference, giving a signal proportional to the SVC current. This signal, multiplied with the slope setting, is added to the voltage feedback to obtain the desired slope in the SVC characteristic. The slope compensated voltage response is compared with the voltage reference and the resulting error signal fed to the regulator input. 1116

Automatic voltage control is the normal mode of operation. The positive sequence voltage on the 230 kv side of the SVC transformer is compared with a set voltage reference and controlled by the automatic voltage regulator. Since this is a closed loop voltage control mode it is not possible to operate should the voltage response be lost. Therefore, should the voltage response be lost, the SVC control will automatically be forced to go manual. In automatic control mode the manual B-reference level will follow the voltage regulator output and when in manual control mode, the voltage reference will follow the actual voltage corrected for slope. This will ensure a transition between the automatic and manual mode free of discontinuities. The desired voltage level is set from the OWS. In order to avoid instability there is an hysteresis between the TSC switch points. In the hysteresis region there are two states giving equal SVC output. One state is with the TSC branch in operation where the TCR is almost fully conducting and compensating for the TSC reactive power. The other state is with the TSC out of operation and the TCR controlled close to zero current. The desired voltage level is set from the OWS. In Manual Control mode the SVC is open loop controlled. The desired MVAr output is obtained by changing the susceptance reference Bref. The manual Bref value will be ramped to the desired value with a ramp rate, which can be set from the OWS. At SVC start, before the control functions are. deblocked, the manual reference will be set to zero. This way the SVC will always start with zero MVAr output. The operator then adjusts the output to the desired level. In Manual Control mode the voltage reference follows the actual line voltage including slope correction, whereas at SVC start up and in Automatic Control mode, the manual Bref follows the actual Bref from the voltage regulator. This way, transients in the SVC output are avoided at transition from one control mode to the other. If the system voltage drops below a preset low-level or increase over a preset high-level the manual control is disabled and the voltage control takes over. In Forced Manual Control mode, the compensator is automatically switched to MANUAL mode should the voltage response signal be lost. The control angle at the time of switching will remain. The MVAr output can now be adjusted, if needed, in MANUAL mode. MSC Operation at Newark There are three: 75 MVAr Mechanically Switched Capacitor banks connected to the 230 kv bus at Newark substation incorporated into the SVC voltage control in order to optimize operation by keeping the SVC operating within +/- 40 MVAr, thus maintaining the dynamic SVC range for contingencies. The function providing this facility is the so-called Q- optimization function. In addition to the three existing banks the' Q-optimization function is prepared to allow up to four additional banks, i.e. to control a total of seven MSCs. The existing MSC PLC control will be taken out of operation permanently after commissioning of the SVC. There are three different control modes in which the MSCs can operate: Automatic SVC mode. Manual SVC mode. Remote mode. In automatic SVC mode the MSCs are either switched in or taken out of service depending on the capacitive power demand monitored by the SVC system. 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.,the MSCs can be made available/unavailable to the Q-optimization independently via the RTWSCADA system from the PG&E syitem operations center. This is how the PG&E operator may choose an MSC to be part of the automatic control or not. The Q-optimization algorithm is coordinated by the SVC control, that tracks its own reactive output and determines if ~ MSC is required or not. At connection of an MSC an order to close the MSC circuit breaker is sent via the RTU. Back status indication of the requested circuit breaker is required by the SVC to ensure that the devise has not failed to operate or is timed out. Should an indeterminate signal be received or a timeout 1117

be encountered, the selected MSC will be changed to unavailable status. The Q-optimizer will then select the next available MSC. This will generate an alarm back to the PG&E system operations center. In addition to the availability signal individual for each MSC, signals for operating the MSC Circuit Breakers and back status have to be provided to enable control of the MSCs by 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., A remote signal makes an MSC available or not available for SVC operation. MSC availability is determined individually for each bank from the PG&E system operations center depending on power system conditions or by MSC CB status, i.e. if the MSC CB has been tripped by the MSC protection or is out of service for other reasons. Since the availability of the MSC can change at any time during operation, the SVC control will adapt automatically. When the SVC is operating close to the TSC switching point the TCR can be controlled to either a high current position balancing the TSC or a low current position with the TSC switched off, i.e. there are two states giving equal SVC output. One state is with the TSC hranch in operation where the TCR is almost fully conducting and compensating for the TSC reactive power. The other state is with the TSC out of operation and the TCR controlled closer to zero current. Since the SVC losses will be higher with the TCR fully conducting, the loss minimization function will intervene to prevent the TCR from operating in this mode for periods of long duration. The normal time delay for initiation of the function is 30 seconds. Large changes in the connecting network impedance may initiate oscillations in the SVC output power. The oscillations at such an occasion are caused by to high voltage regulator gain in relation to the network impedance. For this reason the control system is equipped with a gain supervisor to ensure stability in the closed loop voltage control also during extremely weak network conditions. The number of swings allowed at the beginning of a possible oscillation can be set by an individual parameter to avoid unnecessary interventions by the gain supervisor. Newark SVC Harmonic Filter Design Harmonic filters (HF) are usually required to keep voltage distortion in the network at acceptable levels. The HF is capacitive at the fundamental frequency and contributes to the net capacitive output of the SVC. The HF is normally not switched but fixed to the SVC bus and is therefore often referred to as a ftwed capacitor (FC). Based upon a harmonic performance study performed by ABB using information of the positive sequence harmonic driving point impedances for the required frequency span (in this case, up to and including the 50th harmonic), Newark SVC will have two 27 MVAr filter branches tuned to the 5th and 7th harmonic respectively. The control of the current in a TCR (Thyristor Controlled Reactor) is achieved by phase angle control. No TCR harmonics are generated when the TCR is fully conducting and the harmonic currents caused by the background harmonic voltages on the 230 kv network are very small and consequently neglected. For a balanced three phase system, the third harmonic and its multiples (3,9,15...) will be trapped in the delta connected TCR, thus not appearing in the TCR line currents and therefore prevented from being injected into the PG&E system. The harmonic performance criteria are 1.0 percent voltage distortion for individual harmonics and 1.5% THD according to IEEE 519-1992 guide. Newark SVC meets the distortion fequirements specified in the guide. Conclusion Recent experience at PG&E has shown that retirement of six aging synchronous condensers in the Greater Bay Area can be successfully accomplished with a (semiconductor-based) FACTS device installation in a cost-effective manner and thereby maintain bulk transmission system reliability. Based upon technical review, the costly upgrades of these aging assets to resolve technical, operational and environmental 1118

problems cannot be justified for the remaining life. Shunt capacitor banks also provide economic reactive support to transmission systems but unlike synchronous condensers, lack the damping and dynamic support capability because of slow switching and lack of inertia. Switching of shunt capacitors is 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 contingencies. Hence studies conducted by PGCE confirmed the need to install a fast acting dynamic FACTS device. Adding a Static Var Compensator (SVC) in the Bay Area during 2002 will help maintain an acceptable and necessary reactive reserve margin to prevent voltage instability from unscheduled generation or transmission contingencies during high load conditions and prevent blackouts in the Bay Area. Static Var Compensator (SVC) addition in the Bay area will greatly help maintain an acceptable and necessary reactive reserve margin to mitigate voltage instability from unscheduled generation/ transmission contingencies during high load conditions in the Bay Area. An SVC is comprised of thyristor switched capacitor (TSC), thyristor-controlled reactor (TCR) and harmonic filters (HF) which creates 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. The SVC controls would also monitor and control operation of the existing mechanically switched capacitor (MSCs) banks at the substation for a fully integrated reactive compensation system at 115 or 230 kv level. An SVC is capable of maintaining virtually constant voltage at the point of interconnection (by reactive injection within 1-2 cycles). Such an integrated family of SVC with MSCs and associated digital control logic systems is commonly termed as an SVS (Static VAR System). SVC system technology is mature with a proven track record of over 25 years worldwide. The Newark SVC' has been designed with a smart control system to enhance dynamic reactive benefits. Three existing 75 MVAr Mechanically Switched Capacitor banks connected to the 230 kv bus at Newark substation have been incorporated into the SVC voltage control in order to optimize operation by keeping the SVC operating within +/- 40 MVAr, thus maintaining the dynamic SVC range for unscheduled contingencies. Concentrating the reactive support from six synchronous condensers to a single SVC system, though, increases the sensitivity to reliability. To maximize the reliability of a single SVC unit at Newark several steps will be taken. The SVC will include a firm bank (3 single phase transformer units PIUS a spare. unit). Installing four single-phase units allows operation to be restored within hours rather than weeks or months, as may be the case if a 3-phase unit was installed and failed. The SVC unit is modular in nature, comprising of multiple segments of capacitors and possibly also the reactors. In addition, most of the common controls and protection will also be redundant to allow backup and continued operation in case' of problems or failures. Hence, a failure of any particular element would be isolated and may partially reduce capacity of the SVC but would likely not take the entire unit out of service. While this altemative does have certain inherent disadvantages from a reliability standpoint, measures can be taken which largely alleviates the reliability concem of a single unit. Overall, the advantages do not outweigh the additional equipment cost and space required. The SVC design is based on ABBs experience from numerous other utility SVCs, which meets all enlisted.pg&e requirements resulting in excellent performance and reliability. Hence, application of FACTS technology equipped with smart control systems will maintain and improve steady state and dynamic system performance in the Bay Area. Acknowledgements The author wishes to thank various staff members in the Transmission Planning and Electric System Operations departments of 1119

Pacific Gas and Electric Company who provided guidance, input and much helpful feedback throughout the course of these projects. In particular the author would like to thank Mr. Pouyan Pourbeik and Mr. Rodolfo Koessler for many insightful discussions and their useful suggestions during the course of reactive planning studies as consultants for PG&E. The author would also like to thank Mr. Stanley Nishioka and Mr. Moy Basu at PG&E for many fruitful ' discussions and useful suggestions during the course of SVC installation work and project implementation process. References R. J. Koessler. Y. Kazachkav, 1. W. Feltes, B. Ray and L. Btusseau 'Yoltage Stability Analysis of the MAPP System", presented at the American Power Conference (APC 2000). Chicago, April 2ooO. P. Kundur. Power System Slabiliry and Conrrol, McGraw- Hill, 1994. C. Taylor, Power Sysrem Volfnge Stnbifiry, Mffiraw-Hill. 1994. Western Electricity Coordinating Council, Summary of WECC Voltage Stnbiliry Assessment Methodology, July 2001 B. Ray, M. Bas". B. Farmer, M. Capismno and A. Bosform "Application of FACTS Tahnology to Replace Aging Trammission Assets and Address Voltage Stability Related Reliability Challenges in San Francisco Bay Area", presented at the American Power Conference 2002. Bhaskar Ray is currently employed as a Senior Consulting Engineer in Transmission Planning organization of Pacific Gas and EIecuic Company (ffi&e) located in San Francisco, California. Mr. Ray has over 12 years of experience in power "ission business of electric utility industry. Mr. Ray received his Masters Lkgree in Elecmeal Engiwering (with emphasis on Power System Dynamics) from Iowa State University during 1991. Pior to joining ffi&e, he has been employed with Minneapalis-based Nonhem States Power Company for ten y m in the uansmission business unit. In this capacity Mr. Ray has performed various load serving T&D studies and numerous buk transmission system studies and generation interconnection projects with other ulilities. He has been recently involved in the installation of W &Es fust 230 kv Static Var Compensator system in the Silicon Valley area and addressing voltage stability related reliability issues in San Francisco Bay Area. On behalf of F'GBE, Mr. Ray is also leading various generation interconnection studies in northern California of WECC region. Mr. Ray also has an extensive background in regulatory environment including uwity merger related issues with FERC and testimony preptian for transmission system related hearings with PUC. Mr. Ray has published technical papers extensively at various utility indusrry related conferences and semiws including EPRI. He is a senior member of IEEE and held various positions in Mid Continent Area Power Pool including being Chairman of MAPP Transmission Reliability Assessment Group. 1120