Application of SVCs by CenterPoint Energy to Address Voltage Stability Issues: Planning and Design Considerations

1 Application of SVCs by CenterPoint Energy to Address Voltage Stability Issues: Planning and Design Considerations Wesley Woitt, Alberto Benitez, David Mercado; CenterPoint Energy Frank Schettler, Heinz Tyll, Ralph Nagel, Brian Gemmell, Tammy Savoie; Siemens Abstract - CenterPoint Energy (CNP) is in the process of installing two SVCs on its transmission system which serves the greater Houston, Texas metropolitan area. Extensive voltage stability assessment was performed to understand the problem and determine the optimum size and location of the SVCs. This paper presents planning and design aspects of the SVC installations. As part of the planning consideration, the fundamental problem, alternative solutions evaluated, selection of the preferred option and other reactive power issues are covered. Additionally, as part of the design considerations, the SVC configuration, control strategy and other design issues are discussed. Index Terms- Voltage Stability, FACTS, SVC, STATCOM, and DVAR I. INTRODUCTION The last ten years have seen extraordinary changes to the operation of the electric grid of the Electric Reliability Council of Texas (ERCOT). Foremost among the changes was the deregulation of the wholesale and retail electricity markets starting in 2002. Many new generating plants were built from 1999-2004 throughout the State of Texas which ultimately displaced many of the older less economical generating units. As a result of this change in generation dispatch, historical flow patterns were drastically changed across the ERCOT grid. Specifically, the CNP transmission system, which serves the greater Houston metropolitan area, prior to 2002 very little flow across the 345kV tie lines occurred that connect Houston with other parts of Texas; however, after 2002, imports into Houston across the 345kV tie lines of several thousand megawatts became routine. This occurred because more economical generation outside the Wesley Woitt, Alberto Benitez and David Mercado are with CenterPoint Energy, Houston, TX 77002, USA (e-mail: wesley.woitt@centerpointenergy.com, alberto.benitez@centerpointenergy.com and david.mercado@centerpointenergy.com). Frank Schettler, Heinz Tyll and Ralph Nagel are with Siemens AG PTD High Voltage Division, Power Transmission Solutions, 91058 Erlangen, Germany (e-mail: frank.schettler@siemens.com, heinz.tyll@siemens.com and ralph.nagel@siemens.com). Brian Gemmell and Tammy Savoie are with Siemens Power Transmission & Distribution, Inc. Wendell, NC 27591, USA (e-mail: brian.gemmell@siemens.com and tammy.savoie@siemens.com). Houston area began displacing large amounts of less economical generation within the Houston area. A by-product of this displacement was a reduction in local dynamic reactive support. History has shown that metropolitan areas that import large amounts of power are susceptible to voltage collapse events [1]. This situation is exacerbated for the CNP system since the Houston area has one of the highest concentrations of residential air conditioning load in the world. It is well known that residential air conditioners have response characteristics that contribute to slow transmission system voltage recovery during voltage dips. With these developments as a backdrop, CNP began investigating ways to mitigate risk, including adding new sources of dynamic reactive support to its transmission system. In 2003, CNP performed studies necessary to determine an under-voltage load shedding (UVLS) scheme, which was installed in 2004. In 2004, CNP completed a study which identified a set of projects that would allow additional transfer capability into the Houston area from both the north and the south. That study contained analysis that indicated the transmission system also required the addition of some amount of dynamic reactive support. The transmission projects were approved by ERCOT in March 2005 through their open planning process. Prior to ERCOT approval of the transmission projects, it was announced that 3,800MW of generation connected to the CNP transmission system was to be retired before the summer of 2005. It was at this point that CNP undertook an analysis that will be discussed in this paper and ultimately to the decision to install two 140MVar Static VAR Compensators (SVC) by summer 2008. This paper will discuss the planning and design aspects of the two SVCs. In Section II, the study methodology and performance criteria will be discussed, including the various dynamic models that were developed for the study. Section III will focus on the study results and the various technologies that were considered. Section IV discusses design considerations of the SVC as well as the control and protection philosophy.

2 II. STUDY METHODOLGY AND CRITERIA USED The CenterPoint Energy transmission system is extremely strong with high fault currents throughout the system. The Texas-New Mexico Power Company s (TNMP) Texas City and West Columbia systems are basically radial feeds from CNP s system totaling 2,100MW of load. The TNMP system and load are included in the detailed models that were developed for these studies. For system events, CNP and TNMP buses essentially act as one contiguous bus group, meaning severe voltage dips are felt across the entire system. CNP studied projected 2006 summer peak conditions with the expectation that summer peak conditions would provide the worst conditions for voltage recovery. The projected 2007 summer peak conditions included a CNP and TNMP system load of 20,936MW. CNP s stability studies included the normal ERCOT dynamics data as well as the following additional models that were deemed to be necessary for the study: Generator Over-excitation Limiter (OEL) models for units connected to the CNP transmission system Under-voltage load shedding (UVLS) models simulating the CNP UVLS scheme Load models which include explicit motor models Large motor contactor drop-out models A. Models Included for Voltage Recovery Studies 1) Generator OEL Models OEL models are intended to model the control characteristics of generators that reduce reactive output to continuous rating to avoid damage to the field windings. Generators typically allow several multiples of the steadystate reactive rating for a short length of time, approximately 10 seconds. For voltage recovery studies where low voltage persists for more than this length of time, OEL action needs to be considered because of its negative impact on recovery. With some exceptions, ERCOT Operating Guides require generators connected to the transmission system to have an over-excited (lagging) power factor capability of ninety-five hundredths (0.95) or less determined at the generating unit s maximum net power to be supplied to the transmission voltage level. Generators are modeled in steady-state base cases with reactive capability based on generator reactive test results and operational history. In some cases, this may result in even greater than 0.95 power factor capability. For the voltage recovery studies, CNP decided to set the OEL models to reduce reactive output down to the higher of the two levels. In other words, CNP modeled all generators providing reactive output equal to or greater than that required by ERCOT standards. The models were designed to allow the generator reactive power output to be driven by the excitation system model for an amount of time inversely proportional to the generator reactive output. Once the timer output has been met, the model reduces the reactive output to a continuous level as described above. For example, if the generator reactive output is twice rated value, the OEL model will limit its reactive output to its rated value after 10 seconds. 2) UVLS Models Models were included that represent the UVLS scheme installed on the CNP system. The system is designed to utilize an undervoltage element in the under-frequency load shedding relays that were already installed on the system. This represents about 25-30% of the non self-serve load connected to the CNP system. The scheme has three blocks of load, all with a voltage setpoint of 0.91 pu. Block 1 has a time delay of 3 seconds, block 2 has a time delay of 5 seconds, and block 3 has a time delay of 8 seconds. 3) Load Models Load modeling is incredibly important to voltage recovery studies, as has been demonstrated in many studies where actual voltage collapse events did not match simulated response. In many cases, one of the reasons for the disparity between simulated and actual response was incorrect load modeling. It has been proven that for voltage recovery studies the characteristics of motor response to voltages below about 80% of nominal must be taken into account to produce reasonable response. Therefore, CNP decided to convert the simple load modeled at each bus in the Houston area into load separated components, such as small motors, large motors, discharge lighting and resistive load. While this information can only be definitively determined by very involved research of the native load, reasonable assumptions can be made for each of these components. In this case, past ERCOT voltage studies had used load models developed by Powertech Labs, Inc. (Powertech) that were based on previous research [2]. CNP decided to use the same load models that were used for the previous ERCOT study. The method for determining the load model at a bus is to determine the breakdown of the load at the bus by percentage of load which is residential, commercial, and industrial. This is information that is readily available for the CNP system. The Powertech load model converts the residential, commercial and industrial load into various standard percentages of resistive, small motor, large motor and discharge lighting, as shown in Table 1. The small motor model is intended to represent the typical residential air conditioner load that exists at summer peak conditions. The derivation of the parameters for the small motor, large motor, and discharge lighting models is described in previous research [2]. These models were applied to distribution substations in both CNP s and TNMP s system, which represents 15,377MW of load. Most of the remaining load exists at customer-owned substations in CNP s transmission system. Nearly all of these substations are industrial in nature; therefore, the load components were broken down by applying the percentages associated with the industrial load

3 classification in Table 1. Any remaining loads in the CNP system were modeled as 100% constant MVA. All loads outside of the Houston area were modeled using a similar procedure based on load classifications taken from previous ERCOT study. Load Class / Season Residential / Summer Commercial / Summer Industrial / Summer Load Composition Small Resistive Motor Table 1: Residential, Commercial and Industrial Load Model Composition 4) Large Motor Contactor Drop-Out Large Motor Discharge Lighting 25% 75% 0% 0% 14% 51% 0% 35% 5% 20% 56% 19% CNP operational experience and research has led to the conclusion that at voltages less than 60% of nominal, large motors, such as those used in industrial applications, tend to disconnect or drop out due to the contactor opening after a short delay time and then are reconnected after the voltage has recovered. Since the amount of large motor load on the CNP system is a significant portion of the overall load (i.e. ~25%), the large motor contactor drop-out has a significant effect on overall system response and needs to be included. The specific model is applied to all load classified as large motor load. It drops the large motor load if the voltage dips below 60% of nominal for 0.5 seconds and then reconnects after the voltage rises above 80% of nominal for 1 second. B. Disturbances Studied CNP s Transmission Design Criteria specifically requires that system instability should not occur due to a three-phase fault and a breaker failure condition resulting in a common mode multiple contingency condition. This requirement is based on operational experience which shows that these types of disturbances are credible even though they are classified as Category D by the North American Electric Reliability Council (NERC) Reliability Standards [3]. C. Performance Criteria CNP chose to apply two different performance criteria to the voltage recovery studies, the first applies to voltages at generator terminals based on ERCOT criteria and the second applies to the amount of UVLS load that is shed. In 2005, ERCOT adopted a requirement for generators to remain connected to the grid for disturbances where voltage recovers to at least 90% of rated design voltage within 10 seconds. CNP chose to apply a companion criterion that requires system response to ensure that all generator terminal voltages recover to at least 90% of nominal within 10 seconds after falling below 90%for the breaker failure events described in Section II-B. Therefore, as long as generators are meeting the ERCOT requirements, the transmission system is designed to ensure no generators are tripped due to a low voltage event. The second performance criteria applied to CNP s voltage recovery studies is to limit the amount of load shed due to activation of the UVLS relays. CNP currently has about 25-30% of its summer peak load (approximately 5,000MW) available to be shed by UVLS relays. The potential UVLS load is considered a safety net to help protect the system during a severe system event; however, it seems unwise to plan for using the entire available UVLS load for a simulated event due to the uncertainty inherent in study assumptions. Also, too much load being removed from the system within a few seconds is likely to result in a frequency excursion which could put generators in danger of tripping due to overfrequency. Currently, the ERCOT transmission system is designed to withstand generation outages of 1,250MW; therefore, in a similar fashion, CNP chose to limit the UVLS load shed to 1,250MW for events described in Section II-B. D. Dynamic Reactive Device Models and Location CNP chose to evaluate a number of dynamic reactive device types to meet the performance criteria. The study evaluated synchronous condenser, Distribution Static Compensator (D-STATCOM), Static Synchronous Compensator (STATCOM), Static VAR Compensator (SVC), and Thyristor Switched Capacitor (TSC) solutions. For each of these types of devices, typical step-up transformers were modeled along with typical block diagrams and parameters. From CNP s discussions and meetings with other transmission companies and dynamic reactive device vendors, it became apparent that blocking voltage could be a concern. Basically, to protect the device or some component of the device, it would not react until the voltage rose above a safe level. For the disturbances on the CNP system, system-wide post-fault voltages could be 0.5-0.8 pu at most buses. If the dynamic reactive device had a blocking control function in this voltage range, then CNP was concerned that it would be blocked from operation precisely when the system needed the reactive support the most. A model was developed that blocked each of the devices below a user defined voltage, except for the synchronous condenser which operates through low voltages. For the study, blocking voltages of 0.5 pu, 0.6 pu, and 0.7 pu were tested for each device. It was decided that dynamic reactive devices would be placed at not one, but two locations, to avoid a single point of failure and that the two devices would be of equal size. CNP investigated likely sites for locating dynamic reactive devices and determined the top three optimal sites: one Eastern, one Central and one Western location. III. STUDY RESULTS A. Screening Studies With the models described above, a screening analysis was performed on the base case to determine the fault locations resulting in the slowest voltage recovery. This screening study placed an 8 cycle three-phase fault on each 345kV bus

4 in the Houston area with subsequent clearing of a single 345kV transmission line connected to that same bus. 8 cycles is the breaker failure delayed clearing time for CNP s 345kV substations. All buses 138kV and above were monitored and the duration recorded for bus voltages to recover to 0.7 pu of its pre-fault value. The contingencies were then ranked by maximum duration to recover to 0.7 pu. The 20 worst contingencies were for outages at two 345kV buses that are very close to each other. Further analysis identified the worst contingency as one where the fault with breaker failure is followed by tripping one generator and one transmission line that share a common breaker at this 345kV substation. This contingency, which will be identified as #6-L72, was chosen for all remaining analysis. B. Voltage Recovery Studies Figure 1 shows Houston area bus voltage plots for contingency #6-L72. This disturbance resulted in 2709 MW of UVLS load shed; however, UVLS activation allowed all the generator terminal voltages to recover to 90% voltage well within 10 seconds. Therefore, for this contingency one of the two performance criteria were not met. At this point, the various dynamic reactive devices were added and studied at the various blocking voltages. always considered an optimal site. Subsequent discussion with dynamic reactive device vendors, led to the conclusion that specifying a blocking voltage of 0.5 pu or lower was appropriate for alleviating the blocking voltage concerns. It was determined that the TSC based SVC technology was best suited for this application. CNP issued a functional technical specification for two dynamic reactive devices, one at the Central 138kV substation and one at the Eastern 138kV substation. Figure 2 shows the expected reactive output from the Central and Eastern SVCs for the contingency #6-L72. Dynamic Reactive Device Synchronous Condenser D- STATCOM STATCOM SVC TSC Blocking Voltage (pu) Best Two of the Three Sites MVA of Each Device Resulting MW Load Shed N/A Western/Eastern 70 996 0.5 Central/Eastern 35 1,246 0.6 Western/Eastern 40 1,093 0.7 Central/Eastern 70 1,061 0.5 Central/Eastern 85 1,226 0.6 Western/Eastern 95 1,093 0.7 Western/Eastern 160 1,214 0.5 Central/Eastern 120 1,170 0.6 Western/Eastern 130 1,104 0.7 Central/Eastern 200 1,189 0.5 Central/Eastern 140 1,121 0.6 Central/Eastern 255 1,079 0.7 Central/Eastern 360 1,204 Table 2: Reactive Device and Blocking Voltage Analysis Results Buf. Binary Result File Scenario Contingency 1 07bc+hill+.5tsc140_47015+40390_wapL.bin 07bc+hill+tsc 1 -- WAP#6-L72 2 07bc+hill+.5tsc140_47015+40390_wapL.bin 07bc+hill+tsc 1 -- WAP#6-L72 Output of SHCUDM block (MVAR) 200 Bus # Bus Name ID Buf. 40388 CROSBYSC13.8 1 1 block: QCOMP 47013 BELAIRSC13.8 1 2 block: QCOMP 150 100 Figure 1: Houston Area Bus Voltages for Worst Case Contingency Table 2 lists the device sizes that need to be added at the two best locations to reduce the UVLS load shed below 1,250MW. It was not attempted to size the devices so that exactly 1,250MW of UVLS was shed, but the sizes were increased by 5MVar blocks until UVLS load shed fell below 1,250MW. The synchronous condenser results were primarily for comparison purposes as CNP was not considering synchronous condensers for installation. As seen in Table 2, the remaining devices all showed that the Eastern location was one of the best two locations. For devices with blocking voltages of 0.5 pu or 0.7 pu, the Central site was 50 0 0.000 5.000 10.000 15.000 20.000 25.000 30.000 Time (sec) Figure 2: Simulated Reactive Power Output for Central and Eastern SVCs IV. SVC DESIGN CONSIDERATIONS TSAT Based on the study results in the previous Sections and in conjunction with CNP s specification, the contract to design and construct the Central and Eastern SVCs was awarded on a turnkey basis to Siemens, in partnership with Beta

5 Engineering, LLC for constructing two 140MVAr TSC based SVCs. Both SVCs are identical in topology, deriving their continuous 140MVar continuous rating from one 140MVar thyristor switched capacitor (TSC). A one-line diagram of the SVC is shown in Figure 3. The configuration of the TSC and the voltage level on the low side of the SVC coupling transformer were chosen by Siemens to optimize the performance and cost of the SVC components. V NHV = 138 kv, f N = 60 Hz V NLV = 26 kv S N = 154.4 MVA u k =9.1 % CTSC The V-I characteristic of the SVCs as seen at the HV side is shown below in Figure 4, which was the basis for the determination of the secondary side connected components. The SVCs are designed to operate under system voltage conditions as shown in Figure 5. Table 3 shows the voltage and current stresses of the SVC components, related to the different system voltage conditions as defined in Figure 5. The capacitive design point of 140MVar is achieved with the TSC conducting and the reactive power of 0MVar at 1.0 pu voltage is achieved with the TSC branch blocked. Operation at 1.05 pu system voltage defines the rating of the transformer, with increased power output at 1.10 pu system voltage achieved by the transformer design. At 1.2 pu and 1.3 pu, the TSC branch is blocked and the power output at the HV side of the transformer is 0 MVAr. L TSC 2B TSC Figure 3: Central and Eastern Simplified SVC One-Line Diagram A. SVC Design The LV-side is connected to the HV system via an SVC coupling single phase transformers with a nominal power rating of 154.4MVA and a leakage impedance of 9.1%. The nominal voltage of the secondary busbar of the SVC was optimized with respect to best utilization of the thyristor current carrying capability to 26kV. The number of series connected anti-parallel thyristors is determined from transient stress calculations based on the assumption of having a misfiring in the TSC. Internally fused capacitors are used for the TSC capacitor bank. Each capacitor is rated 714kVAr at 9,817V. Figure 5: SVC Continuous and Overload Duty from the Specification V/I Stresses Time Continuous 180s 1s V NHV (pu) 1.00 1.00 1.05 1.10 1.20 1.30 Q HV (MVar) 140.0 0.00 154.35 169.40 0.00 0.00 Q LV (MVar) 151.57 0.00 167.11 183.40 0.00 0.00 V NLV (pu) 1.083 1.000 1.137 1.191 1.200 1.300 I TSC (A) 3108.8 0.0 3264.3 3419.7 0.0 0.0 V CTSC (pu) 1.155 0.0 1.213 1.270 0.0 0.0 Table 3: Voltage and Current Stresses of TSC Components at Characteristic Operating Points (See Figure 5) The technical specification requirements specifically emphasized life cycle cost together with a loss evaluation which shows 0MVar operation for most of the time. This was considered an ideal application for a single TSC solution: at 0MVar the TSC is switched off and does not generate any load losses, nor excessive magnetic fields, nor load or harmonic current related audible noise. Figure 4: V-I Characteristic of the SVC at the HV-side of the Transformer B. SVC Control The redundant controller includes the control function of the SVC and also coordinates the switching interaction of: two existing 138kV mechanically switched capacitor (MSC) banks (129.6MVar and 108MVar) and one tap changer at the Central substation; one 115MVar MSC and one 75MVar reactor bank at the Eastern substation.

6 The control system of the SVC consists primarily of open and closed loop control functions. The controller has been built up in a fully redundant system which uses standardized hardware and software modules, which secures maximum availability of the SVCs. The Plant Control contains all the necessary functions to control and monitor the entire SVC components with associated control systems (e.g. protection, cooling, valve base electronics (VBE), local switchyard controls and remote control). A simplified control overview is shown in Figure 6. components are integrated in the input circuits of the controller. The signals are then transformed by galvanically isolated V/V or I/V converters into signals at control circuit potential with voltage limitation and interference suppression. Calibration facilities are integrated for each input. All frequency dependent circuits are automatically adjusted to the actual frequency of the power system. This feature ensures that the evaluation of the actual system values is precise for a system frequency range of 60Hz ±5Hz. 2) Control Philosophy The primary purpose of the two SVCs is to provide Dynamic Voltage Support (DVS Mode) for the CNP transmission grid for specific three-phase faults with delayed clearing under certain conditions. In addition, the SVCs shall be capable of controlling the 138kV bus voltage in steady state voltage regulation (SSVR Mode). The control loops are operational simultaneously and are adjustable independently of each other. a) 138kV Dynamic Voltage Support Mode Figure 6: Control Overview 1) Closed Loop Control Functions The control system of the SVC is of a three-phase symmetrical, closed loop voltage control type. The simplified block diagram of the closed loop controller is shown in Figure 7. Figure 7: Closed Loop Controller Central SVC a) Input Signal Processing The actual voltage signal V act is the average of the magnitudes of the 3-phase fundamental frequency busbar voltages V HV. This signal must be accurate, insensitive to system harmonics and system frequency deviations. Over-voltage protection devices and interference suppression filters to guard against high frequency voltage Dynamic Voltage Support (DVS) Mode is to provide voltage support for the transmission system during network faults, and is always active. If the system voltage drops below the adjusted V min setpoint, a sequence of events happens. At the Central substation, the TSC and MSCs are switched in to support the 138kV system voltage. During low voltage events the load tap changer (LTC) control will be blocked to prevent tap change operations in the event of a network breakdown. The short-circuit calculation and dead band adjustments are blocked if the system voltage decreases under the minimum voltage setpoint V min. With voltage recovery, the LTC control will be enabled at the adjusted LTC enable level. The MSCs will remain switched in and will only be switched off if there is an overvoltage condition >1.1 pu. During system faults the SVC will stay on-line to stabilize the system voltage. After a period of ten minutes following the low voltage event, the SVC control will return to steady state voltage support mode automatically. There is a similar sequence of events at the Eastern substation. Special additions must be incorporated into the secondary SVC equipment (i.e. cooling system). All primary and auxiliary equipment must be designed to ensure that the SVC can remain on-line for the low voltage ride through event. In this case, the primary cooling pumps used to cool the thyristor valve were supported via a set of stand-by redundant inverters. b) 138kV Steady State Voltage Regulation Mode The 138kV steady state bus voltages at the Central and Eastern Substations are controllable to a reference value which can be set by the operator to a continuously adjustable

7 value between 0.90 pu and 1.10 pu. The control objective is to maintain the steady state bus voltage close to the reference value. As can be seen from the block diagram in Figure 7, the Steady State Voltage Regulation mode can be activated or deactivated. The voltage deviation V determined by the difference between the V act and V ref voltage is fed to the deadband controller which is used for TSC, MSC and Tap Change control. Dependent of the measured short circuit level, the deadband is adjusted for each element. c) Special Control Functions Additional control functions are implemented and will override the normal control. Specific control features for optimal use of the SVC are explained below. Due to the fact that the SVC will operate in stand by position for most of the time, the TSC will be off for the majority of the time. To test the availability of the SVC, a periodical TSC on/off test function is integrated to the controls. Furthermore, to ensure optimum dynamic response of the SVC during various network conditions and to avoid continuous on/off actions of the TSC, automatic deadband adjustment dependent on the measured short circuit level is included in the regulator. A stability controller is integrated which is an important feature for stability improvement under very weak system conditions in combination with transient interactions. The voltage controller output is monitored in order to detect multiple consecutive changes in direction of the Q reg signal. In this case, it will increase the deadband stepwise until stability is reached. The deadband adaptation is activated for hunting above a pre-defined frequency level. This detection level ensures sufficient margin to avoid unwanted increases of the deadband in the lower frequency range of power swings. Such specific controls improve the SVC performance and provide benefits to the SVC user. d) Supervision and Protection Functions Special control and protection functions are integrated in the SVC controller to detect abnormal operating conditions and to react rapidly to avoid damage and unnecessary tripping by the plant protection system. These control features, which are included in the closed loop control software, are very flexible and can be adapted to specific customer requirements. The special control and protection functions consist of: HV Over-voltage Protection HV Under-voltage Protection LV Under-voltage Protection TSC Current Supervision TSC Thermal Replica The outputs of these protection devices are evaluated by the interrupt and protection logic for optimal reactions. These features increase the overload capability, in addition to improvements in the availability and performance of the SVC. e) Verification of Control Design The Control and Protection cubicles are connected to a Real Time Digital Simulator (RTDS TM ) which is used to perform all TNA tests of the SVCs in Erlangen, Germany. With this RTDS system, steady state and transient behaviors of the original control, measuring and protection equipment can be studied under real network conditions. Some of the specific tests are: Steady state and functional performance tests Verification of protection strategies Performance tests under transient system conditions The digital and real-time simulation is used to optimize the SVC control design and regulator adjustment and results in minor adjustments being required on site during commissioning. Thus the time required to put the SVCs in operation is minimized. 3) Control and Protection Summary The two static Var compensators installed at the Central and Eastern substations will improve the system stability by providing dynamic reactive power support in case of faults but also by controlling the 138kV bus voltage. As part of the SVC commissioning, the real time digital simulator tests proved to be particularly helpful in studying and understanding the control and protection systems of the SVCs. V. SUMMARY AND CONCLUSION In this paper, the results of the voltage stability assessment for CenterPoint Energy s transmission system are discussed. Metropolitan areas that import large amounts of power are susceptible to voltage collapse events. CenterPoint Energy had to include various models for their dynamic studies, as well as the performance criteria and evaluation of several Flexible Alternating Current Transmission Systems (FACTS) to mitigate the problem. Two identical 140MVar SVCs connected at Central and Eastern 138kV substations were selected as the preferred options. The two SVCs are expected to enter commercial service in May 2008, and a follow-up paper is planned which will present the construction and final commissioning considerations.

8 VI. REFERENCES [1] Krebs, R.; Lemmer, S.; Retzmann, D.; Sezi, T.; Weinhold, M., "Blackout Prevention by Online Network and Protection Security Assessment," IEEE Power Engineering Society General Meeting, pp.1-3, 24-28 June 2007. [2] C.W.Taylor, Power System Voltage Stability, McGraw-Hill Inc, 1992. [3] North American Electric Reliability Council Standards, available at http://www.nerc.com. [4] H. Tyll, K. Leowald, F. Labrenz, D. Mader, Special Features of the Control System of the Brushy Hill SVC, CEA HVDC and SVC Control Committee, Power System Planning and Operating Section, March 1989. [5] S.R. Chano et al., Static Var Compensator Protection, IEEE Transactions on Power Delivery, Vol. 10, No. 3, July 1995. VII. BIOGRAPHIES Wesley D. Woitt received his Bachelors degree in Electrical Engineering from Mississippi State University in 1993. He joined CenterPoint Energy in 1993 and has worked in transmission planning functions for over 14 years where he is currently Supervising Engineer of the Special Studies group of Transmission Network Planning. Alberto Benitez received his BSEE and MEE from the University of Houston in 1993 and 1998, respectively. He joined CenterPoint Energy in 1994 in the Substation Project Department and is currently a Consulting Engineer for CenterPoint Energy. Department. Since 1996 he is responsible for Basic Design of SVC, SC and FACTS applications. He contributed to CIGRE WG 38 TFs and to relevant IEEE WG. He is member of IEEE and VDE. Ralph Nagel received his Dipl.-Ing. in Electrical Engineering from the Technical University of Leipzig, Germany in 1988. He has been with Siemens since 1991 and since 1996 working in the SVC Control and Protection engineering design group. He has been involved in design, test and commissioning of various SVC projects. Brian D. Gemmell (M 00) received his MEng and PhD in Electrical and Electronic Engineering from the University of Strathclyde, UK in 1990 in 1995 respectively. During 1992, he spent 6 months as a Visiting Engineer at the Massachusetts Institute of Technology. He worked for ScottishPower (1994-2000) in Substation Engineering and Transmission Planning. He has spent the past 7 years working in FACTS & HVDC Business Development and is currently Director of Business Development with Siemens Power Transmission & Distribution, Inc., based in Wendell, NC. Tammy M. Savoie (M 97) received her BS in 1997 from North Carolina Weslayan and her MBA from the University of Houston in 2005. She is an Industrial Advisory Board Member for the Electrical and Computer Engineering Department at the University of Houston and a member of IEEE Women in Engineering. She has worked for Siemens for the past 13 years. David L. Mercado received his Bachelors of Science Degree in Electrical Engineering from Rice University in 2003. He joined CenterPoint Energy in 2001 and is currently working as an Engineer in the Special Studies group of Transmission Network Planning at CenterPoint Energy. Frank Schettler received his Dipl.-Ing. and PhD in Electrical Engineering from the Technical University of Ilmenau, Germany in 1992 and 2003 respectively. He has been working with Siemens in the field of power transmission and distribution for about 15 years. As a systems engineer he gained experience in the fields of power system design, development, application engineering and sales. He is currently head of the System Engineering team for FACTS in Siemens. Heinz Karl Tyll (M 88, SM 93) graduated in 1968 in Electrical Engineering from Coburg Polytechnikum. In 1974 he received the Diplom degree from the Technical University of Berlin. After joining Siemens AG, he worked in their High Voltage Transmission Engineering Department since 1975 in the field of network and SVC system analysis with transient network analyzer and digital programs. In 1988 he transferred to the System Engineering Group of the HVDC and SVC Sales