Literature Survey on Fundamental Issues of Voltage and Reactive Power Control - Essay - United State Literature - Omid Alizadeh Mousavi, Essays (high school) of American literature

Download Literature Survey on Fundamental Issues of Voltage and Reactive Power Control - Essay - United State Literature - Omid Alizadeh Mousavi and more Essays (high school) American literature in PDF only on Docsity! 1 Literature Survey on Fundamental Issues of Voltage and Reactive Power Control Literature Survey Deliverable of the MARS Project financially supported by "swisselectric research" Omid Alizadeh Mousavi omid.alizadeh@epfl.ch EPF Lausanne – Power System Group Rachid Cherkaoui Rachid.Cherkaoui@epfl.ch EPF Lausanne – Power System Group 10. June 2011 2 Table of Contents 1- INTRODUCTION 4 2- VOLTAGE CONTROL CLASSIFICATION AND DEFINITIONS 8 2-1- HIERARCHICAL CLASSIFICATION 8 2-2- CLASSIFICATION BASED ON TSOS (CURRENT PRACTICES IN DIFFERENT TSOS) 10 2-2-1- ENTSO-E CONTINENTAL EUROPE 11 2-2-1-1- France 12 2-2-1-2- Italy 14 2-2-1-3- Belgium 15 2-2-1-4- Switzerland 17 2-2-1-5- Spain 18 2-2-1-6- Germany 19 2-2-1-7- NORDEL 20 2-2-1-8- Netherlands 21 2-2-2- NERC 21 2-2-3- CONCLUSION 22 3- TIME SCALE CLASSIFICATION OF VOLTAGE CONTROL AND PHENOMENA 24 4- PROVISION OF VOLTAGE CONTROL 27 4-1- REACTIVE POWER RESERVE 27 4-2- EMERGENCY COUNTERMEASURE 29 4-3- PROBLEMS OF VOLTAGE CONTROL PROVISION 30 4-4- ANALYSIS OF THE VOLTAGE CONTROL IN THE SYSTEM 30 4-5- TWO BUS TEST CASE SIMULATION 33 4-6- PROVISION OF VOLTAGE CONTROL IN PLANNING 35 4-7- PROVISION OF VOLTAGE CONTROL IN OPERATIONAL PLANNING AND REAL-TIME 36 4-7-1- RPR PROVISION 36 4-7-2- EC PROVISION 37 4-7-3- PREVENTIVE AND CORRECTIVE CONTROL ACTIONS 38 4-8- CONCLUSION 38 5- VOLTAGE CONTROL IN MULTI-AREA POWER SYSTEM 38 6- BIBLIOGRAPHY 43 5 The voltage control from generation resources is a necessary supplement to static reactive devices to prevent voltage problem because:  Generation supplied reactive resources do not lose effectiveness at low voltage as do static reactive devices.  The response of a generator to an emergency reactive requirement is much faster and more accurate than the static reactive sources (except power electronic based devices). The voltage control capability of synchronous generators is limited by saturation of both: field current and armature current. The generators under heavy real power loading require high amount of field current to maintain the desired terminal voltage which pushes the generator and exciter to the saturation region. When armature current limitation is in effect, a large reduction in the reactive power output is needed if the active power output is to remain constant [4]. Among different types of generating units, hydro power plants have less limitations and so higher capabilities in voltage and reactive power control. Pumped storage power plants, as a specific type of hydro power plants, not only can improve the frequency control but also can participate in reactive power control. New technologies like variable speed pumped storage power plants with higher capabilities than conventional ones, like frequency control during night time (at low loading) and independent active and reactive power control, bring more flexibility for the system control. However, the provided support by these generating units is usually affected by their far geographical location from load centers. The transmission customers can also supply reactive power to the system or can reduce the use of reactive resources by power factor correction. Note that even with a unity power factor, reactive supply and voltage control from generation sources is still required for dynamic voltage control, supplying reactive losses of the transmission system, and maintaining reactive reserves for security. Recently, provision of ancillary services by dispersed generation and demand side response became important. However, TSOs cannot effectively manage and operate the provided ancillary service by thousands of DG units. Therefore, their participation in the ancillary services is confronted with barriers at this time [5]. These voltage regulators can be operated in automatic or manual mode. From the system operation perspective, all voltage regulators should remain in automatic mode. Power plant operators for a short period of time may need to place voltage regulators in the manual mode because of maintenance, testing, or any problem in the generating units’ voltage regulator. These automatic controllers are set by the control area operators in order to maintain a scheduled voltage in response to system changes due to a disturbance or an unusual increase of power demand. The control of voltage could be accomplished with passive (shunt and series capacitors and reactors) and/or active (synchronous generators, synchronous condenser, and FACTS) devices. The former devices contribute to the voltage control by modifying the network characteristics, while the latter’s automatically adjust the absorbed or supplied reactive power to maintain the voltages of buses at specific points in the system [6]. Another classification divides the voltage control devices into static and dynamic types [7]. Dynamic reactive power resources refer to equipment that can respond within cycle of a disturbance where static devices are not capable of reacting fast enough. Appropriate balance between static and dynamic reactive power resources in an area should be provided to obtain a feasible operating point after a reactive power deficit in the area [8]. A well-planned and coordinated application of these devices is essential for the economical design and operation of a reliable system [9]. The proper selection and coordination of equipment for controlling reactive power and voltage are among the major challenges of the power system engineering [9]. For efficient and reliable operation of the power system, the control of voltage should a) maintain the voltages of all terminals in the system within acceptable limits, b) enhance the system stability to 6 maximize utilization of the transmission system, and c) minimize the reactive power flow so as to reduce active (RI2)and reactive (XI2) losses [9]. A power system at a given operating state and subjected to a given disturbance is voltage instable if the voltages could not approach post-disturbance equilibrium values. Basically, voltage instability has two origins: first, gradual increases of power demand without sufficient reactive power support, and second, a sudden change in the network topology which redirect the power flow in such a way that the required reactive power cannot be delivered to some buses. Overvoltage instability could be excluded because the over-excitation of machines is not permitted. The risk of overvoltage in the system during low loading conditions is normally more of an equipment problem rather than a power system stability problem (Page 525) [10]. In order to avoid such overvoltage problems reactive power sources and transmission equipments should be managed appropriately. One possible approaches for solving this problem could be disconnection of low loading transmission lines1 which doesn’t seriously affect the thermal limit margins or other constraints of the other paths in parallel [11]. Voltage instability is commonly analyzed by employing two techniques, namely time-domain (dynamic) simulation and steady-state analysis. Depending on the phenomena under investigation, one or both of these techniques may be applied [8]. The process by which the sequence of events accompanying the voltage instability leads to the loss of voltage in a significant part of the system is called voltage collapse. It means that, a power system undergoes the voltage collapse if the post disturbance equilibrium voltages are below acceptable limits. Voltage instability commonly occurs as a result of reactive power deficiency. The voltage collapse may be total (blackout) or partial [12], [13]. The term voltage security refers to the ability of the system to maintain the voltages within some limits following any credible contingency. In other words, there should be a considerable margin from an operating point to the voltage instability point (or to the maximum power transfer point) after a contingency [12]. System security can be distinguished from stability in terms of the resulting consequences. For example, two systems with equal stability margins, but one may be relatively more secure because the consequences of instability are less severe. During the disturbances, sufficient capabilities to supply static and dynamic reactive power are required to prevent the collapse and have to be mobilized on request even if this enforces a reduction of active power supply [14]. Inadequate voltage support can result in equipment damage and in the extreme case it can lead to voltage collapse and system instability. Voltage instability could be considered as important as thermal overloads and the associated risk of cascading outages. In recent two decades power system has revealed with widespread blackouts which insufficient reactive power support was an origin or a factor in major power outages worldwide. Lack of reactive power reserves response to the increased reactive power demand in contingencies, can lead to operation of protection system and also limit the generators reactive power support. As a consequence, both of active and reactive power deficient participate in the separation of the system and the spread of cascading events over the entire system and finally make a large blackout. Therefore, insufficient reactive power reserves in one area can increase the propagation of disturbance even in neighboring areas. Voltage collapse was a causal factor in the blackouts of August 4, 1982, Belgian; August 22, 1987, West Tennessee; July 2, 1996, in WSCC; August 10, 1996, in West Coast; July 12, 2004, in Greece. Voltage collapse also factored in the blackouts of December 19, 1978, in France; March 2, 1979, at Zealand in Denmark; July 1979, Canada in B. C Hydros north coast region; December 27, 1983, Sweden; May 17, 1985, South Florida; July 1985, Czechoslovakia; July 23, 1987, in Tokyo; January 12, 1987, in Western France; March 13, 1989, in Québec; August 1992, Southern Finland; August 14, 2003, North America; August 28, 2003, in London; September 23, 2003, in Sweden and Denmark; and September 28, 2003, in 1 It reduces the reactive power circulation and so its losses. 7 Italy. The following given examples which ended in voltage collapse and blackouts can demonstrate some aspects of the voltage control problems and their consequences. Greece The Hellenic system was prone to voltage instability on July 12th 2004. This phenomenon is related to the maximum power transfer from the generating areas in the North and West of Greece to the main load center in the Athens metropolitan area. The Hellenic interconnected system (Greece network) blackout was a sever voltage collapse. At that time two generating units in Peloponnese and Northern Greece were out of service which was further stressing the Athens grid. The sequence of events leading to the blackout was started with the failure of 300 MW generating unit in Athens area. This unit was reconnected to the network but it was lost again due to high drum level. A manual load shedding is implemented by the transmission system operator which was not enough to stop the voltage decline. So a further load shedding command was requested which didn’t have time to be executed, because of a generating unit trip was occurred at central Greece automatically. Another unit was manually tripped and the voltage was collapsed. The system was split into two parts. In one part, the remaining generators were disconnected by under-voltage protection leading to the blackout. The other part, North and Western of the Hellenic system, was saved due to the split of the system. This part was interconnected to the 2nd UCTE synchronous zone. The resulting surplus of power in this part created a severe disturbance in the neighboring systems of the UCTE network. This excess generation changed the flow in the northern interconnections. As a result, interconnection with FYROM was overloaded and tripped, the Bulgarian interconnection was received huge surplus power, and the frequency increased to 50.75 Hz. During the incident, the power stations in the affected area lost their voltage control due to the over-excitation. Therefore, they lowered their pre-disturbance active generation in an attempt to increase their reactive capability and controlling their terminal voltage. This, however, had an adverse effect, as it increased the import of power into the affected area, thus creating further voltage drop despite the increased reactive generation [15], [16]. Sweden and Denmark The system of southern Sweden and eastern Denmark were experienced blackout on 23th September 2003. The operating conditions were stable within the Nordic security requirements. Initial disturbance was outage of nuclear power plant due to mechanical problem and lose of 1175 MW generation. This contingency managed through operational reserves and the supply-demand balance was restored. Within 15 minutes time to restore the system into N-1 secure state, a double bus bar failure is occurred which disconnected four 400kV transmission lines. Power flow increased on the remaining transmission link between central and southern Sweden. At this stage, the level of reactive power support for voltage control was reduced because no major generators were left connected to the transmission system in southern Sweden. As a result, voltage levels on the lines dropped to critical levels and consequently a voltage collapse was developed in a section of the transmission network. Mal-function of distance protection tripped some transmission lines and severed all remaining transmission connections between north and south of Sweden. An electrical island containing southern Sweden and eastern Denmark was formed. However, the large generation deficiency led to collapse of frequency and voltage in the islanded system [17], [16]. 10 to the SVRs and would be used by local voltage/reactive power regulators, which are PVRs, to control their voltage/reactive power output with respect to their own reserves. Figure 2-1: PVR, SVR, and TVR overall structure. The operation of the system under the hierarchical scheme increases the transmission capacity associated with improvements in voltage stability characteristics of the interconnected grid [6]. Note that the voltage control areas are affected by both system topology and loading condition, and hence these areas change dynamically during system operation, which is an issue with the current SVR approaches, which assume that these areas remain fixed. This particular problem is addressed in [28] by a combined Secondary and Tertiary Voltage Regulation (SVR+TVR) methodology based on real-time optimal power flows (OPFs) to periodically update the generators’ AVR set points. Since the method is mainly software-based, the voltage control areas boundaries can be readily redefined to better reflect changes in the system operating and/or topological conditions. However, this method corresponds to centralized OPF models, where in practice, this is likely to be an issue due to the large size and the complexity of real systems. In the case of hierarchical voltage control in power systems, [29] proposes wide area voltage protection system, whenever the operating limits are reached and control efforts are saturated, including active power rescheduling and load shedding on the area which is the first cause of the voltage instability. The objective is the removal of the risk of voltage instability within the saturated voltage control area. 2-2- Classification based on TSOs (Current practices in different TSOs) The growing interest in creating a reactive reserve market indicates the development of reactive control as a specific ancillary service [1]. Several utilities developed special scheme for the control of the network voltages and the reactive power. It is likely that the preferred methods differ from network to network, and depend on the network structure and the reactive power compensation practices [23]. Some TSOs like Italy and France implemented some kind of automatic SVR and TVR. However, in many countries the adjustments of the AVR set-points are performed manually from a control center [30]. In this survey, recommendations and practices of voltage control in different TSOs in continental Europe and NERC are studied. SVR Ctrl. 11 2-2-1- ENTSO-E Continental Europe Several hierarchical controls based on the network area subdivision and the automatic coordination of the reactive power resources were first studied in Europe for achieving the network voltage control. The ENTSO-E operation handbook (former UCTE) [25] provides a procedure to keep the network voltage within predefined ranges according to the N-1 security principle by different facilities. Load shedding can also be initiated when voltages have declined to abnormal levels. Voltage must be maintained within a range of values in order to be compatible with the equipments size, to maintain the supply voltage within the contractual range, to guarantee the system reliability and the static stability and to avoid occurrence of voltage collapse. Furthermore, ENTSO-E released a draft for the grid connection requirements of power generating facilities [31]. The generating units are obliged to meet the requirements and to provide the technical capabilities with relevance to the system security. According to [31] each generating unit shall be capable of providing reactive power automatically by either voltage control mode, reactive power control mode, or power factor control mode in coordination with the relevant TSO. The control scheme characteristics, parameters and settings of the voltage control system components shall be coordinated in agreement with the relevant TSO. Each generating unit shall be equipped with over and under excitation limiters and stator current limiter and shall inform its network operator about its capabilities to provide reactive power. The relevant network operator shall have the right at any time to change the reactive power target value within the agreed reactive power range. Each TSO have the right to define voltage-against-time-profile at the connection point for fault conditions which describes the conditions in which the generating unit stay connected to the network and continue stable operation after the power system has been disturbed. Also generating units shall be capable to fulfill the relevant TSO requirements for automatic disconnection in case of voltage deviation at the connection point for a specified range and a minimum time period, as shown in table 2-1 for Continental Europe. The terms shall be agreed with the relevant TSO in the conditions set forth by national legislation, connection agreement or any other bilateral contracts or by the TSO. Table 2-1: The minimum time periods each generating unit has to operate for voltages deviating from the nominal value at the connection point without disconnecting from the network [31]. Generators in Continental Europe Voltage Range Time Period for Operation The voltage base is between 110 kV and 300 kV 0.80 pu – 0.85 pu 30 minutes 0.85 pu – 0.90 pu 180 min 0.90 pu – 1.115 pu Unlimited 1.115 pu – 1.15 pu 60 minutes The voltage base is between 300 kV and 400 kV 0.80 pu – 0.85 pu 30 minutes 0.85 pu – 0.90 pu 180 minutes 0.90 pu – 1.0875 pu Unlimited 1.0875 pu – 1.10 pu 60 minutes According to the [25], the voltage control has been divided into primary, secondary, and tertiary levels. Various TSOs employ different voltage control methods based on their policy. In most cases, a single transmission system operator (TSO) is responsible for the primary voltage control, whereas the other control modes might involve several TSOs. Each TSO continuously and coordinately support the voltage in its own network. The TSOs must have information of the available reactive resources and their restrictions. Besides, they have to exchange data for real time operation and network security analysis. In order to ensure a safe operation of the synchronous area, adjacent TSOs should agree on common voltage ranges on each side of the borders. In addition, they (adjacent TSOs) should provide coordinated 12 voltage control near the boundaries preventing that individual actions have opposite effects to the security of the neighbors in normal operation and in case of disturbances. TSO can have contract with the reactive power providers to get proper, adequate, and rapid reactive power resources for normal and emergency operation. It is declared that, if the reactive power can be produced in the adjacent TSOs, specific bilateral contracts should be made to transfer reactive power through the tie-lines. Moreover, [25] states that the TSOs are committed to have available a sufficient reserve of fast reactive power resources participating to the PVR in order to ensure normal operation condition with a continuous evolving of load and transits, and to prevent voltage collapse after any contingency of the contingency list. TSOs have to keep available a sufficient number of reactive power resources connected to the grid, which contribute to reactive power generation or absorption, in order to maintain or get back the voltage in normal ranges after any contingency. Different European grid operators, depending on their hierarchical level, developed and implemented specific voltage control schemes. Here, the current practices in France, Italy, Belgium, Switzerland, Spain, Germany, Nordic, and Netherlands TSOs are studied in depth. 2-2-1-1- France France TSO (RTE1) has organized a three level voltage control which concern distinct geographical zones. The zones are mutually decoupled and a decentralized secondary voltage control (DSVC) coordinate the action of different generating sets at zonal level. The DSVC acts on all PVRs of regulating units within the zone to control the zone pilot bus voltage and to maintain their uniform reactive loadings. RTE has designed a coordinated secondary voltage control (CSVC) which it can be considered as the first industrial implementation to improve the SVR. The CSVC is a closed loop centralized voltage control scheme with a dynamic of a few minutes. This coordinated control remains on the regional level and it is formed of several strongly coupled zones. In fact the CSVC take into account the interactions between voltage regulation zones. In each region one control center (CSVC) gathers the information of the pilot nodes voltage and critical nodes voltage and also generators participating in the CSVC. This information is used to determine the pilot nodes voltage and the set point of all PVRs in a region. The aim of the CSVC system is the controlling of the voltages at the pilot nodes and generator terminals to set point values while maximizing the reactive power reserves and improving the system voltage stability within a region. Actually the CSVC continuously employs optimization for computing the voltage set points of the generators in the supervised zone2. The CSVC is afforded to use the existing reactive resources and to avoid installation of new devices for the voltage control [23], [32], [33], [34]. The CSVC is installed only in the Western region which is particularly sensitive to voltage problems [35]. The described hierarchical voltage control of French system is depicted in figure 2-2. 1 RTE (Réseau de transport d'électricité) is the France Transmission System Operator. 2 For this purpose, each 10 seconds, measurements of "pilot node" voltages and generator reactive outputs are collected, from which new AVR voltage set-points are computed and sent to generators at the next time step. This computation consists in minimizing the sum of squared pilot node voltage deviations and machine reactive productions, with inequality constraints on controls, pilot node voltages, generator reactive outputs and sensitive bus voltages 15 Figure 2-5: Schematic diagram of the Hierarchical voltage control for the Italian transmission system [36]. The main achieved operational benefits of the hierarchical voltage control implementation are: the reduction of the real losses, the increase of the reactive reserves for facing large perturbations, the increase of the active power transfer capability, and the reduction of the risk of voltage collapse [22]. In addition to the described hierarchical voltage control, TERNA introduced a mandatory framework of payments (£/MVar/hr) for consumers and Distribution System Operators (DSOs) with excess reactive energy withdrawals [36]. 2-2-1-3- Belgium The coordinated voltage control has been employed in Belgium since 1998, as a tool to support decisions made by the system operators. Elia, the TSO of the Belgium network, ensure sufficient absorption or generation of the reactive power to stabilize the system voltage through making contract with the producers. In the network of Belgium, the secondary and tertiary hierarchical levels, as defined by the French and Italian propositions, is not utilized. In this application, the voltage control exercised both as primary control and centralized control. The primary voltage control automatically adjusts the voltage variation within a given band defined by the producer, while the centralized control is activated by the producer upon request of Elia depending on the contracted band. The main goal of alignment objective function is to spread and maximize the reactive power reserves on the different generators taking part to the voltage control of the system. The proper operation of this objective requires that the import and the export of reactive power from the neighboring system tend to zero. In the present implementation generating units, shunt capacitors, and UHV-HV transformers tap changers are considered as controllers [39]. 16 The reactive power generating units are divided into regulating units and non-regulating units. The regulating units are capable to participate in both of the primary and centralized controls while the non- regulating units are only involved in the centralized control. The generating units with capacity over 25 MW are required to participate in the primary voltage control of the Belgium network. As additional mean to solve a problem, Elia can ask the regulating units to activate the reactive power beyond the bands, if this activation didn’t jeopardize the security of the producing unit. Figures 2-6 and 2-7 demonstrate the aforementioned characteristics of the regulating and the non-regulating units, respectively [24]. Figure 2-6: Utilization of the reactive band for the regulating unit in Belgium [24]. Figure 2-7: Utilization of the reactive band for the non-regulated unit in Belgium [24]. Elia launches a tender for providing the voltage control, and chooses the providers based on the price of the received bids and the location of the generating units in the grid. The producers are paid for the actual consumed or generated volumes of the reactive power (€/MVar/hr). In addition, the required reactive power reserve is provided through adjusting the set of the generating units [24]. In order to improve the voltage control of the network of Belgium, a hierarchical voltage control scheme with SVR and TVR is studied in [40]. In this scheme, SVR calculates the voltage of the pilot nodes and sends the reactive power set-points to generators. The objective of TVR is defined as minimization of generators reactive production, capacitor switching, reactive power exchange with neighbor grids, and voltage deviation. General structure of the proposed control system is shown in figure 2-8. 17 Figure 2-8: General Diagram of the proposed hierarchical voltage control for the network of Belgium. 2-2-1-4- Switzerland There is no formal SVR and TVR in the Swiss grid. The TSO of Switzerland (Swissgrid) is responsible for ensuring voltage support in coordination with the prequalified ancillary service provider (ASP), power plant operators (PPO), distribution system operators (DSO) and TSOs in other countries (FTSO). Since 2009, Swissgrid has implemented a central voltage/reactive power control, which coordinates the generators’ AVR and the transformers’ tap changers through a Day-Ahead Reactive Planning (DARP). The DARP process is shown schematically in figure 2-9. Figure 2-9: Overview of the DARP procedure in Switzerland [41]. The main input data of the DARP process is the 24 DACF (Day-Ahead Congestion Forecast) snapshots that contain the 24 hours day-ahead power flow forecast. Moreover, it is necessary to add reactive power limits of power plants and tap changer transformers’ model. The minimum available reactive power of each plant is derived from its total active power production of the DACF model (Qlim=f(P)). The optimal set-point for the power plants and transformer tap changers are determined such that they minimize the cost of active power losses throughout the transmission system plus the cost of reactive energy payment to the generators. The optimization has to ensure a number of technical and operational constraints like voltage limits of generations and nodes, transformer tap position limits, and reactive power flow branch group limits at the borders and for Switzerland [42], [41]. The Optimal Power Flow (OPF) is performed in a consecutive manner for all 24 snapshots. The day-ahead voltage 20  the distribution networks connected to the system operator’s network,  the consumers connected to the system operator’s network. Generating facilities, reactive compensation installations, transformer tap changing, and modification of network topology are taken into consideration by the TSOs to ensure enough reactive power generation and demand in the system. The conditions for supply and purchase of reactive power are specified in bilateral agreements between the concerned parties. Each generating unit must meet the defined minimum requirements regarding to the specified power factor in the transmission codes. The generating unit under operation should provide the requested reactive power as specified by the TSO. According to the contractual agreements, if the suppliers notified a restriction in reactive power generation, the TSO should be immediately notified. In addition, if a TSO during daily operational planning cannot be ascertain of reactive power management by the available means (its own passive facilities and contractually guaranteed ancillary services), it should ask for supplementary generating units to supply reactive power. Financial compensation for that is settled on a bilateral basis [49]. 2-2-1-7- NORDEL The network of NORDEL is composed of four countries, including Norway, Sweden, Finland, and Denmark. Each one of the system operator is responsible for voltage regulation in its own grid. Deregulated markets in the Nordic countries do not have any provision for payments towards reactive power services [50]. For example, Sweden follows a policy wherein reactive power is supplied by generators on a mandatory basis and without any financial compensation. Some large generators are rarely used for voltage control and are operated at a constant reactive power output. Also in Norway there is mandatory reactive power supply, within power factor range of 0.93 lagging to 0.98 leading, without any financial compensation. Additional reactive power supply could be individually imposed to generators which it would be remunerated yearly by negotiation between system operator and producers. Moreover, the interaction between the system operators is considered such as communication between the Norwegian and the Swedish system operators. The voltage of the Norwegian system is monitored by the National Centre and also Regional Centers. If the Regional Centers do not have sufficient resources to maintain the voltage within the given limits, the National Centre will be contacted. Two operation centers in the Swedish system are responsible for voltage regulation in the northern and southern parts of the grid. If the operations centers do not have sufficient resources to maintain the voltage within the given limits, they should contact each others. In normal operation, the goal is the higher voltage within the normal operation range. In conjunction with operational disturbances and switching, the respective operations centers in Sweden and Norway can agree on actions to maintain the voltage within the given intervals. The margin for the PVR is set by each system operator for its own system and bilaterally between the system operators in borders between the systems. Voltage regulation in each system should be conducted in such a way that the operational security standards1 are upheld and the reactive flow between the systems does not entail operational problems. The Parties’ rights and liabilities regarding reactive power flows on the AC interconnections are limited to what corresponds to zero exchange (no reactive exchange) at the national border, based on values measured at the terminals of the links. NORDEL operational security standard states that there must be a reserve of reactive power within each subsystem. It must be constituted with regard to the size, the regulation capability and the localization to prevent the system collapse [51]. 1 Operational security standards are criteria which the system operators use when conducting operational planning in order to uphold the reliable operation of the power system. 21 2-2-1-8- Netherlands In the Netherlands, individual network companies have to provide for their own reactive power, usually through bilateral contracts with local generators, who are only paid for the reactive capacity but not for reactive energy [36]. The operating point for the reactive power exchange at the active power output is defined by one of the following three possibilities: power factor (cos ), reactive power level, voltage level, if necessary with tolerance band. The operating points are defined by agreement of a value or online set-point specification. The generators which active power is taken from must maintain a power factor of cos  = 0.95 (inductive) to 1. Further exchange of reactive power is permissible and has to be agreed separately [52]. 2-2-2- NERC In the North America power system, the enhanced voltage control is not utilized. Power plants are the primary resources used to control the transmission system voltage. The effectiveness of the existing reactive power and voltage control standards and how they are being implemented in practice has been reevaluated in the ten NERC regions [53]. New generators should have an over and under-excited power factor capability of 0.95 or less. If a generator could not meet this requirement, it should make alternate arrangements for supplying an equivalent dynamic reactive power capability. The provision of the basic voltage controls is compulsory in NERC. The generators are remunerated based on a regulated price. This price incurs the fixed and opportunity cost of the generators [27]. Generators must declare their reactive power capabilities for the system operator such as characteristics of the unit automatic voltage regulator, maximum and minimum reactive power output capabilities, and speed of response. The generators accept and confirm the scheduled voltage or the scheduled reactive output requests from the system operator within two minutes. These generators must modify MVAR output to keep the voltage or the reactive output error less than the specified band around the scheduled voltage. The generator must meet either the voltage or reactive output requirements, but not both of them at the same time [54]. However, the performance requirements for voltage controls are not dealt with in great detail by NERC. Thereby targets of network voltage schedules are left for the regional coordinating and operating entities to define these requirements more specifically. NERC voltage and reactive control requirements states that each transmission operator should acquire adequate dynamic and static reactive resources within its area to protect the voltage levels of interconnected system under normal and contingency conditions. Reactive resources should be dispersed so that they can be applied effectively and quickly when contingencies occur [55]. The adjacent transmission operators are responsible for facilitating the resolution of any potential conflicts in the applicable voltage limits. In addition to NERC standard, the Western Electricity Coordinating Council (WECC) defines more detailed performance requirements for automatic voltage regulators. WECC-specific standards addressed the required active and reactive power margin in the system for both transfer paths and load areas. The established standards of WECC assess the required static stability margin and reactive power margin through conducting PV and PQ analysis, respectively. It defines the active power margin requirement in such a way that the path flow transfer (the area load) should be kept 5% below the path flow transfer (the area load) of the nose-point on the PV curve for normal operation and worst single contingency. Also the active power margin should be kept 2.5% below the path flow transfer (the area load) of the nose-point on the PV curve for worst multiple contingency. Similarly, the reactive power margin requirement at the critical node under consideration is equal to the change in the reactive power margin between  100% and 105% of forecast loading (or path transfer) for single contingencies.  100% and 102.5% of forecast loading (or path transfer) for multiple contingencies. 22 The described active and reactive power margins requirements are depicted in figures 2-11 and 2-12, respectively [8]. 2-2-3- Conclusion Study of current practices in voltage and reactive power control demonstrates the intention of different system operators toward implementation of more sophisticated schemes like centralized and hierarchical voltage controls. Table 2-2 and 2-3 summarize the current practices of different TSOs in ENTSO-E and NERC for voltage and reactive power control and its remuneration, respectively, which explicitly described in this chapter. Moreover, a combined SVR and TVR (SVR+TVR) methodology based on real-time centralized optimal power flows (OPFs) is proposed in [28] to periodically update the generators’ voltage regulator set points. Minimum active power losses (MAPL) and maximum loadability (ML) OPF approaches are used for the proposed SVR+TVR control. However, in practice implementation of centralized OPF is problematic and regionalization of the OPFs for the proposed SVR+TVR needs to be studied. Figure 2-11: active power margins requirements [8]. Figure 2-12: reactive power margins requirements [8]. 25 time-scale within a few minutes is treated as a separate class [4], [8], [58], [59]. Nevertheless, as discussed in [9] (p.1078) distinction between mid-term and long-term stability appears less and less justified. Thus, in recent literatures the mid and long-term voltage instabilities are considered in the same category [13], [60], [61], [62]. In this report, the expression long-term voltage instability concerns all studies beyond the short-term. The short-term voltage stability is characterized by fast acting dynamics of the power system and its components following a disturbance. The time frame is from less than one second to several seconds. The response of the PVR is in this time scale. Time-domain or dynamic simulation considering different control actions are commonly used for the short-term studies. The long-term voltage stability involves slow phenomena and slower acting equipments. Its time frame may extend from several minutes to hours. It contains automatic or manual actions of higher level controls like the SVR and the TVR. The investigation in this time period is done through static analysis methods based on power flow models while considering fast dynamics stable. The mechanisms that make the system instable in short-term and long-term dynamics are a) loss of post-disturbance equilibrium (ST1 and LT1)1, b) lack of attraction toward stable equilibrium (ST2 and LT2), and c) post-disturbance oscillatory instability (ST3 and LT3). Usually the evolution of the long-term voltage instability, leads to a short-term instability. Similarly, this type of instability (S-LT1, S-LT2, and S- LT3) can be distinguished according to the three aforementioned mechanisms. To face the problem, the generators and the synchronous condensers can be asked to provide reactive power in excess of their current limits for a limited time. But it transforms a short-term voltage problem to a long-term one. This time scale decomposition perspective can be utilized to indicate time horizon of various phenomena and system components actions taking part in the voltage stability. The fast acting automatically controlled equipments participate in the short-term stability dynamics such as: generators automatic control devices (excitation system), synchronous condensers, automatic switched shunt capacitors, SVC, induction motor, voltage dependent loads, FACTS, HVDC links, etc. In the long-term stability dynamics, SVR, TVR, transformer tap changers, generator limiters, switched shunt compensation, and in the last resort load shedding could be enumerated. They typically act over several minutes. The response of the components in the long-term voltage stability is designed in such a manner that it has no interaction with the short-term dynamics. This time decoupling allows to categorize the voltage controls and to perform more precise analysis. Figure 3-1 depicts the dynamic of voltage control response in comparison with the response of other power system controllers’ timescale. Figure 3-1: Short and long-term voltage controls in comparison with different time scales of power system controls [6], [63]. 1 ST is for the short-term and LT is for the long-term phenomena 0.1 1 10 100 1000 time (s) Protection Short-term voltage control Power electronic controllers 0.01 Long-term voltage control AGC Operator LFC 26 It can be derived that fast response of automatic voltage controls, which are commonly available over the entire power system, is even faster than rapid active power control. For the first few seconds or even tens of seconds after a system disturbance, there is no active power control from the generators. The controllability of the reactive power in the generators is fast since it involves electronic control of excitation current and does not need any mechanical power control [64]. Therefore, when there is a sudden change in load, the voltage profile at the load buses can be controlled with rapid reactive power regulation of generators and then the generators’ governor restores the active power balance at their low speed [64]. All of the aforementioned controllers could be applied in both preventive and corrective strategies. The preventive and the corrective controls are two main defenses against instability incidents. These control actions must be taken appropriately to provide sufficient margin for security. The objective of the voltage security assessment in operational planning and real-time environments is to ensure the system security through taking into account both types of the remedial actions. Usually the secure operation point can be obtained with applying different countermeasure. Such decisions are taken in accordance with each action’s cost as a trade-off between reliability and economy. In the case of the short-term voltage problem, there is not always enough time to implement the corrective actions. Therefore, sufficient reactive power margin should be provided for the short-term voltage instability prior the disturbance by the automatic support of the control devices. The countermeasures for the long-term voltage instability contain both preventive and corrective actions, because in the long-term voltage instability usually there is time for operator actions. The SVR control actions are basically in the time scale of the long-term voltage studies. The various remedial actions for different time-scales of the voltage instability are shown in table 3-2. Table 3-2: Various preventive and corrective countermeasures for different time-scales of voltage instability. Preventive action Corrective action short-term PVR — long-term SVR TVR Capacitor switching Load tap changer Load shedding Generation redispatch Capacitor switching Load tap changer blocking Automatic or manual preventive controls include the optimization of the amount and location of reactive reserves. The PVR in the short-term voltage control and the SVR and the TVR schemes in the long-term voltage control can be used in this respect. Note that SVR is also in charge of the shunt compensation switching and the transformer tap changing with the objective of maintaining reactive reserves on generators to face incidents. Automatic or manual corrective controls in the long-term instability include shunt compensation switching, load tap changer blocking, load shedding and generation redispatch. In order to avoid voltage instability, three characteristics of countermeasures including amount, location, and execution time should be appropriately adjusted. The location of corrective actions should be selected such that the minimum amount could be achieved. The farther the countermeasure from the location with voltage instability, the more countermeasures is needed to save the system. Moreover, execution of corrective actions can restore the long-term equilibrium when they are performed before the time limit. If corrective actions were realized after the time limit, the system would be prone to LT2 instability. Otherwise, more corrective actions are required to restore the stable post-contingency equilibrium. 27 The provided emergency controls to protect the system against the voltage collapse are divided into two categories. The first group has no impact on consumers. This group could include the topology change, the modification of cross border flow, the reduction of exchange, the fast generation rescheduling, and the load tap changers. If they were available, they would be the first controls to be utilized. Some of these actions such as generation rescheduling may involve additional cost to the utilities. In this case, if the generators reactive power production affects on their active power dispatch, they receive an opportunity cost payment. The second group of emergency controls, like load shedding, have a direct impact on consumer and usually are used as the ultimate remedial action. In serious contingencies, the system cannot be efficiently restored without some form of load shedding. It is shown that among different emergency controls only load shedding is able to restore the long-term system equilibrium in the presence of load self-restoration1 [65]. However, the efficient load shedding scheme should be designed so that appropriate amounts of loads are disconnected within a delay to protect the system against the voltage collapse. For instance, the Hydro-Quebec operator has implemented an under voltage load shedding scheme -TDST- to have an extensive defense plan against major disturbances [66], [67]. Usually power systems are operated with sufficient preventive controls in such a way that they can survive credible contingencies. For more severe incidents the TSOs relies on corrective actions. When the preventive actions are insufficient or cannot be implemented fast enough, corrective measures should be adopted. The remedies for higher order contingencies could be covered either by its own TSO or with neighbors. During such situation, the TSO which is on alert provide the necessary information to the neighbors and also looks for convenient remedial actions with them [25]. Moreover to the various mentioned countermeasures, modification of cross boarder flow and reduction of exchanged power also can be included in the remedial actions. The reactive power reserve in the system should be managed to improve the voltage stability and to avoid the voltage control problems in case of disturbances. It requires adequate response of the equipments and coordination of the control and the protection equipments. Next chapter studies the concepts of reactive power reserve and emergency countermeasures in depth. 4- Provision of Voltage Control The proper provision of the voltage and reactive power control resources is required to maintain the security of the bulk power system against the short- and long-term instabilities. These resources are anticipated to support reactive capacity and reactive energy through automatic and manual actions of the controllers. Also these resources should be managed to keep the system voltages within established limits, under both pre- and post-contingency condition [64]. For this purpose, the TSOs should continuously acquire, deploy and maintain adequate amount of control actions from their resources to meet contingencies. These control actions comprise Reactive Power Reserves (RPR) and emergency countermeasures. The RPR and emergency countermeasures, respectively, can be considered as the preventive and corrective controls for the security of the system voltage. In the following sections both preventive and corrective actions are studied more in depth. 4-1- Reactive Power Reserve In addition to reactive power requirements to support the transmission system under normal conditions, RPRs should be maintained for contingency conditions to enable the secure system operation against the voltage instability and collapse. The RPR is spare reactive capability available in 1 Following a disturbance in the supply voltage, the active and reactive powers drawn by the load are restored by internal controllers (like thermostats). 30 actions subject to the system equalities and inequalities is often referred to as solvability restoration. The system operators must be able to recognize voltage stability related symptoms and take appropriate remedial actions. Generation redispatch can be one of the emergency countermeasures, since the available RPR of a generator varies depending on its loading condition. The generator RPR is determined by its capability curve. Note that for a given real power output, the reactive power generation is limited by both armature and field heating limits. Usually emergency action on load is the ultimate countermeasure. This can be implemented indirectly through a modified control of LTC’s or directly as load shedding. Emergency control of LTC’s can be achieved by LTC blocking or LTC voltage reduction. This emergency action has to be coordinated between different LTC levels in EHV transmission, HV sub-transmission and MV distribution levels. LTC emergency control slows down the system degradation, but its response is affected by counteraction of load power restoration mechanism and complex implementation due to large number of distribution transformer to control [60]. Appropriate load shedding is the ultimate way of stopping voltage instability. Under-voltage load shedding scheme can restore a long-term equilibrium by increasing the active power margin of the system. 4-3- Problems of Voltage Control Provision Adequate stability margin should be ensured by proper provision of voltage control including both the RPR and the EC. However, at present there are no widely accepted guidelines for the selection of the degree of reactive power margin. For the EC, each TSO utilizes different schemes to obtain sufficient active and/or reactive power margin to the voltage instable point. The specific EC can be taken based on the requirements of each network and TSO. The margins to keep the voltage secure depend on provided RPR by different reactive resources which should be managed by each TSO. In one hand, TSOs can define an acceptable voltage level for normal operation and contingencies and must guarantee that the voltage level is not near the critical voltage in these situations [25]. On the other hand, TSOs can determine appropriate RPR with respect to operating constraints and voltage stability criteria. In this case, the RPRs are taken in such a way to ensure the secure operation limit. The appropriateness of the provided RPR should be tested through contingency analysis. The RPR provision is affected by several problems and concerns regarding the current procurement practices and pricing policies for reactive power. These comprise a lack of transparent planning standards, noncompetitive procurement, discriminatory compensation policies, rigid interconnection standards that may not meet local needs, and poor real-time incentives for production, consumption and dispatch [53]. Existing standards are not specific for RPR requirements because the TSOs may not bear the full reliability costs of inadequate RPRs. So the TSOs may not consider all available alternatives in the procurement of reactive power capacity. 4-4- Analysis of the Voltage Control in the System Voltage instability imposes important limitations on the power systems operation. The system should be operated with an adequate voltage stability margin by the appropriate scheduling of reactive power resources and voltage profile. If the required reactive power margin cannot be met by using available reactive power resources and voltage control facilities, it may be necessary to limit power transfers and/or to ask additional reactive power resources to provide voltage support at critical areas. The knowledge of the reactive power reserve condition is of paramount importance in the system operation and strongly affects the reliability of the power systems [71]. Voltage instability scenarios and correspondingly system security should be analyzed at various decision stages from planning to real-time. T. Van Cutsem in [60] classifies these analysis methods in four 31 categories namely: contingency analysis, loadability limit determination, determination of security limits, and preventive and corrective control. Contingency analysis aims at analyzing the system response on a particular operating point to credible contingencies that may lead to instability or voltage collapse. The system should be operated such that to survive the credible contingencies by providing appropriate pre- and post-contingency controls. The analysis can be accomplished by static methods based on load flow, modified load flow, multi-time scale simulation, Quasy Steady State (QSS) simulation, and time-domain methods. Loadability limit determines how far a system can move away from its operating point and still remain in a stable state. This type of analysis typically utilizes load increase and/or generation rescheduling which stress the system by increasing power transfer or by drawing RPR. The singularity of Jacobian matrix and continuation load flow has been widely used in literature. In some applications loadability limits can be obtained as the solution of an optimal power flow. Traditional PV and VQ curves are the most well-known methods to distinguish the margin of the system operation point to instability. These curves provide the results with acceptable accuracy and little computational effort since these analyses are based on static approaches. The PV curve plot the relationship between the active power transfer (P) and load bus voltages (V). It demonstrates the active power stability margin. The relationship between Q and V can be used to show the sensitivity and variation of bus voltages (V) with respect to reactive power injections or absorptions (Q). It demonstrates the stability margin of the reactive power. The advantages of the latter method are as follow [9]:  It could be more readily derived for non-radial system.  Better suited for examining the requirements for reactive power compensation.  Not only it identifies the stability limit, but also defines the minimum reactive power requirement for stable operation. The PV and the VQ curves are utilized to obtain the active and the reactive power margins for two-bus test system as shown in figure 4-2. Figure 4-2: Two-bus test system. In the given system the synchronous generator at bus 1 with voltage E<0 (E=1.1) feeds the load at bus 2 with active power PL (PL=2) and reactive power QL (QL=0.4). Three parallel transmission lines, each one with inductance X (X=0.3), connect the generation bus to the consumption bus. The PV and the VQ curves are calculated for this system in pre-contingency, post-contingency #1 (outage of one transmission line), and post-contingency #2 (outage of two transmission lines) and are shown in figures 4-3 and 4-4, respectively. The point on the nose-curve where the maximum power occurs is called the “critical point” and in literature is often considered to be the voltage stability limit. In figure 4-3, the active power margin to the voltage collapse is the distance of the operating point (black circle) to the nose-point on the PV curve. This margin for the post-contingency #1 (∆1) decreases comparing with the pre-contingency (∆0) due to the loss of one transmission line (∆1<∆0). The contingency #2 has a negative active power margin (∆2) with respect to the current operating point which means voltage instability. The system operator can restore the system to voltage stable area by applying fast enough corrective countermeasures like shedding more than ∆2 MW of the loads. X X X Bus 2 Bus 1 V < θ PL , QL Qc E < 0 32 As shown in figure 4-2, a fictitious reactive power injection (QC) is added to bus 2 to obtain the VQ curves. The VQ curves for the three aforementioned scenarios and the corresponding reactive power margin are depicted in figure 4-4. The black circles show the operating points of the system where the fictitious injections are equal to zero (QC=0). The difference between the minimum of the VQ curve and the operating point is defined as the reactive power margin at the bus, which is equal to the negative value of the fictitious injected reactive power. The positive margins of the pre-contingency and post- contingency #1 are, Q0 and Q1, respectively. For the post-contingency #2, the reactive power margin (Q2) became negative. This value (Q2) is the reactive power margin to operability. The reactive power margin can be managed to keep the voltage secure by using different reactive resources. Note that at the minimum of the VQ curve, the RPRs of depleted generators are the effective reserves for the area and, thereby, determine the reactive margin in the area. The amount of effective RPR is a key index in voltage stability assessment [72]. Developing of VQ curves is recommended as an alternative method for time-domain or dynamic simulations to identify the appropriate RPR. Figure 4-3: The PV curves of the two-bus test system. Figure 4-4: The VQ curves of the two-bus test system. tan()=0.2  1  0  2 post-contingency #2 post-contingency #1 pre-contingency Secure Voltage Zone Margin from the critical voltage Q i is the Margin to Critical Point Q i > 0 : Positive Margin Q i < 0 : Negative Margin Q 2 Q 1Q 0 post-contingency #1 pre-contingency post-contingency #2 PL V/E 1 0 0 P (QCX)/E 2 V/E 0 1 35 b) Maximum reactive power capability of generator     is defined based on the generator’s capability curve by using this formula 1 . The generator’s capability curve is estimated with an ellipse with 1, where Pg and Qg are active and reactive power of generator, and PM and QM are maximum active and reactive power of generator which are equal to 3.5, 3. The effect of generator’s voltage on its capability curve is neglected in this formulation. c) In this test case the minimization of active power losses (Min Ploss) is in the direction of line reactive power flow minimization which means minimization of reactive power generation (Min. ∑Qg). It is the reason that the results of objectives (Min Ploss) and (Min. ∑Qg) are exactly the same. In “contingency #2”, there is not sufficient RPR to obstacle against the voltage collapse. In this case the obtained results in the last column of table 4-1 can be considered as an index which measures the severity of instability. In order to obtain an operable point, emergency countermeasures (ECs) such as active and reactive generation rescheduling and load shedding need to be utilized. Here, since there is only one generator, the generation rescheduling is not possible and load shedding should be implemented. For this purpose, an OPF is developed to obtain minimum amount of load shedding with respect to the system voltage collapse. The results are given in table 4-2. Table 4-2: The results of EC for the two bus test case. Contingency #2 Prob =0.0003 Pgc = 0.9022 Qgc = 0.4508 V1c = 1.0500 < 0 V2c = 0.9500 < -0.2631 PLS = 0.3238 4-6- Provision of Voltage Control in Planning In the planning perspective, the system operator has to evaluate reactive power margin requirement of the future system and ensure the viability of voltage controls, including RPR and EC. The RPR can be provisioned by the system reinforcements through construction of new generating units, transmission lines, series and shunt compensation. A suitable placement of shunt capacitors can free up spinning RPR in generators. Application of some devices and controllers can contribute to voltage control such as the line drop compensation in AVR, control of generator step-up transformer, and automatic shunt compensation switching. Moreover, the voltage control scheme and reactive power management can be enhanced through implementing SVR and TVR. The studies under the title of VAr planning are also included in the RPR provision. It is aimed at minimizing the installation cost of additional reactive support necessary to maintain the system in a secure manner. The planning priority is to minimize cost and also to minimize future operations costs (Page-349) [78]. The increasing participation of the variable distributed generation resources in the power system exacerbates the necessity of voltage and reactive power control. This condition heightens the need to pay more attention to the issue of voltage and reactive power control provision to maintain the reliability of the system. In order to face the severe disturbances with low probability of occurrence, automatic curative actions aimed at avoiding instability should be established. For this purpose, one TSO can implement system protection schemes as EC, such as LTC emergency control and emergency load shedding. Decisions are taken based on the cost of installation and the improved value of security. 36 4-7- Provision of Voltage Control in Operational Planning and Real-Time The provision of the voltage control in operational planning and real-time operation is dealt with different aspects in literatures. In this time horizon the main purpose is to best utilize the available system components for the voltage control. In order to define the set-points of the voltage controllers, different system operators utilize various objectives such as maximization of generator RPR (whether technical or effective), minimization of transmission losses, and minimization of voltage deviation. The system voltage should be kept in the secure region after a contingency by using RPR and EC. The available reactive resources and countermeasures accompany the system operator for the RPR. The SVR and the TVR schemes can be utilized to enhance the RPR in the system. For the EC, the system operator can count on all the available reactive resources and also the active power redispatch and as the last resort, load shedding. According to the earlier mentioned classification, here the provision of the voltage controls is separately investigated in the provision of the RPR and the EC. 4-7-1- RPR provision The provision of the RPR can be investigated in the perspective of the load RPR (LRPR) or the generation RPR (GRPR). More studies are performed around the former (reactive power support) rather than the latter (efforts in the RPR assessment). In both of LRPR and GRPR, the RPR requirements have been investigated in the context of voltage stability for enhancement of its margin. Most of the approaches use static analysis but some references confronted with this topic with regard to the stability analysis [72], [75]. In addition, the provision of RPR based on security constraints is widely proposed in literature to improve voltage stability. Various formulation of Security Constraint Optimal Power Flow (SCOPF) is employed to assess the RPRs with constraints on operation [75] and contingencies [79]. For this purpose some references specifically use the term Voltage Stability Constrained Optimal Power Flow (VSCOPF) [73]. The VSCOPF are divided in two classes. The first class aims at maintaining steady-state voltage stability which can be used for corrective control in severe emergency states. The second one aims at determining preventive control strategies in the normal state considering voltage stability. Some references utilize time-domain simulation to check the voltage stability in the preventive controls [80]. Small Perturbation Stability Constrained OPF (SSC-OPF) proposed in [81] include a stability index in the OPF algorithm. In the following section, different literatures around the RPR provision are surveyed based on the perspective of the load RPR and the generation RPR. a) Load RPR Reference [82] defines a reactive reserve basin for each zone as the sum of the exhausted reactive reserves at the minimum of the VQ curve. After a disturbance, the remained percentage of the basin reactive reserve is used as a measure of the proximity to voltage instability. The reactive reserve based Contingency Constrained Optimal Power Flow (RCCOPF) presented in [79] aims at enhancing the voltage stability margin (VSM) of the interface flow. This method solves preventive control in the normal state concerning VSM of post-contingency state by using a decomposition method. Active power margin of post-contingent states are determined with modified continuation power flow (MCPF) and an OPF is performed for preventive control. In fact, the RCCOPF uses reactive power dispatch as a control mean to relieve reactive power generation and increase the effective RPRs of the chosen generators. The proposed RPR management in [72], manages RPRs in critical areas based on the OPF and as a result it improves the voltage stability. A two-level benders decomposition is used for base case and a set of stressed cases sub-problems. In the base case, the RPR is maximized while the transmission losses is minimized. The optimization in the stressed cases deals with minimization of the fictitious reactive 37 power injections. The optimization procedure in this paper focuses on reactive reserve margin optimization instead of reactive power rescheduling. In the management scheme, the participation factors of the involved generators are determined based on the VQ curves. b) Generation RPR As described in section 4-1, the generator’s RPR (GRPR) can be classified into technical GRPR and effective GRPR. Many studies in this area utilize the technical GRPR since it can be calculated easily regardless stability analysis [83], [84], [85], [86], [87], and [88]. However, in [89] it is shown that the effective RPR not only depends on the generators capability curve, but also on the network characteristics that play an important role in generators’ RPRs. That means maximization of generators RPR could not demonstrate the effective RPR all the times. Moreover, active and reactive power limits of generators are linked together according to their capability curve. This dependency entails that the RPR of a generator depends on the active power reserves provided by the generator. The effective RPR for a bus or an area is determined in [90] as the weighted some of the individual RPRs of generators at the minimum of the VQ curve. The weights are calculated based on sensitivities of generator reactive outputs to reactive loads. In [91], correlative relationship between GRPR and system voltage stability margins (VSM) is investigated and a method for on-line voltage stability monitoring is proposed. Nonlinearity relationship between GRPR and both VSM and voltage violations is investigated in [92]. The TSOs is responsible to provide and to coordinate the RPR requirements. In one hand, inappropriate RPR provision treats the security of the system, and on the other hand, devoting large amount of RPRs increase the operating cost of the system. In order to maximize the efficient use of assets, the minimum amount and optimal location of required RPR should be well determined. The proposed approach in [93], determines the minimal RPR to face a contingency, while stressing the system in its pre-contingency state, until reaching an unacceptable post-contingency response. In [75] a two-step approach is proposed to assess the required RPR with respect to operating constraints and voltage stability for a set of assumed operating scenarios. At the first step a Security Constraint Optimal Power Flow (SCOPF) determines the minimum overall needed RPR of generators such that the system withstands any postulated scenario. In the second step additional RPR is determined to ensure voltage stability of scenarios, whenever the obtained RPRs by SCOPF are insufficient to confront with dynamic system behavior. Application of the aforementioned reactive power rescheduling and RPR management methods can be proposed as the objective of SVR and TVR, to increase voltage stability, and active and reactive power margins. 4-7-2- EC provision Given the cost of corrective countermeasures and the low probability of contingency occurrences, it would be desirable to resort to post-disturbance controls. However, an essential characteristic in these actions is the implementation time needed since the speed of response is an issue for long-term voltage stability. The system operator must be able to recognize voltage instability and take appropriate remedial actions such as voltage and power transfer controls, generation rescheduling, and as a last resort, load curtailment. One may try to find suitable remedial actions to restore the system to the voltage secure zone. Branch and generator participation factors are among the proposed methods to determine the appropriate remedial actions. The branch participation factor indicates which branches consume the most reactive power in response to an incremental change in reactive load. It would be useful for identifying remedial measures to alleviate the voltage stability problems and also for contingency selection. Similarly, the generator participation factor shows which generators supply the most reactive 40 In fact, when a contingency happens in an area, an automatic and non-coordinated response of voltage controller (PVR) by the generators electrically closer to the disturbance1 may lead to unacceptable reactive power flow or voltage level in its own control area or even in neighboring areas. That means some TSOs don’t provide sufficient MVar support. Due to locally provision characteristic of voltage control, normally in real time, each TSO is aware of this situation in its own control area. The added value of a wide coordinated control is to propose a global optimum remedial action to restore the system to a secure state. Otherwise, the system would be operated in a non-optimal state which means less security margin. This situation requires a higher level control to achieve the global optimum operation point. The experience of CORESO2 in ENTSO-E demonstrated such operating situation may happen and a coordinated control action can improve the taken remedial action. In the case of sever contingency in presence of interregional voltage management in the system, the TSOs can take the advantages of the available voltage controls in the neighboring TSOs to counteract with their problem or to limit the extent of the problem in the MAPS. Similarly, one TSO may utilize its own control facilities to help the neighboring TSO or to avoid the effects of external contingency in its own control area. The following uncertainties made the wide coordinated control system necessary [8]:  Neighboring system voltage profile for the operating condition.  Variations on neighboring system’s generation dispatch.  Large and variable reactive exchanges with neighboring systems.  Restrictive reactive power constraints on neighboring system generators.  Outages not routinely studied on neighboring systems. Combination of both preventive and corrective control actions including amount and place of RPRs and emergency controls should be determined to respond to the system sudden changes. The optimization of a system wide coordination is proposed as important measure for sharing reactive reserves when some control limits are reached [32]. If voltage constraints begin to be approached, a wide voltage scheduling regarding the effect of neighboring regions becomes significant. However, the implementation of a centralized control in MAPS is not possible since not only the TSOs don’t intend to reveal their operational information for the other TSOs but also implementation of a wide area control scheme would be technically more expensive and requires more communication. Therefore, distributed [99] or decentralized [98] control manners are needed to be considered for this purpose, which has got little attention up to now. These control schemes are difficult to be effectively implemented or might achieve suboptimal performance. In [99] distributed voltage control and Model Predictive Control (MPC) technique are applied for emergency voltage control to coordinate the control actions among the various grids while each operator preserves its own sensitive local system data. The proposed centralized control scheme is solved in a distributed fashion through Lagrangian decomposition method. Although the control problem is global, only local information is employed to achieve the overall optimum control. All AVR references and load shedding at some buses are assumed as available controls. At each iteration of solution procedure, the information which are sent out to the external control centers are the obtained local optimal cost and the calculated interface bus voltages. It is shown that in some operation conditions; when a contingency happens within an area, the control actions also must be taken in other areas to restore the grid to safe operation state according to the chosen globally optimal criterion. It should be noted that the proposed method in [99] cannot consider the different TSOs with different objectives, since a centralized control scheme has been taken. 1 The required reactive power will be produced by the generators electrically closer to the disturbance and hence the remained reserve may be unevenly distributed. 2 CORESO (Coordination of Electricity System Operators) is a centralized control center to coordinate control actions and strength operational security in the Central Western Europe. 41 The decentralized voltage control in MAPS is studied in [100], [84], [85], [86], [87] and [88] with different approaches such as neighboring network equivalent [84], fairness of different TSOs objective [86], [87], and advantages and disadvantages of centralized and decentralized voltage controls [85], [88]. A new layer of hierarchical control to coordinate long-term control actions over several control regions in normal operating conditions is proposed in [98]. The corresponding time horizon of the proposed MAPS voltage control in this work is shown in figure 5-2, in comparison to the different levels of hierarchical voltage control (PVR, SVR, and TVR). These works study reactive power scheduling using multi-objective optimization for minimizing reactive power support and active power losses. The TSOs different strategies in voltage control are considered with different combination of this multi-objective function. Figure 5-2: Time-space delineation of a four-layer hierarchical voltage control scheme [98]. The reference [100] compares two strategies for accessing to the information of the neighboring TSOs. In the first strategy, two TSOs have access to all the information of each other except their controllers’ value in the next step (It is called wide observation). In the second strategy each TSO just knows about its own control area and the access to the information of the neighboring TSO is limited to the borders. It should be mentioned that the latter strategy is closer to the present situation of power system. It is shown that the decentralized control of the system with wide observation leads to the worst result since each area behaves in greedy way and wants to import reactive power from the other area resources. However, the decentralized voltage control with limited access to the neighboring TSOs information can be considered in MAPS studies. In [84], [85], [86], [87] and [88] the centralized voltage control which optimizes a unique objective over the entire system is assumed as the utopian optimum. The result of the decentralized voltage control is evaluated based on the distance to this utopian optimum. The difference between global optimization results and decentralized optimization results is the additional cost that should be paid for decentralized control. In the decentralized manner each TSO solves its own objective function considering its own network constraints and imposed constraints of the external networks. Then all TSOs apply the solution to their own systems as a part of interconnected system and each TSO measures parameters for external network equivalents. If the control values don’t comply the constraints of the entire network, faster voltage control loop will change the operation setting while slow devices are remained unchanged. The fast voltage control actions use available reactive power reserves. The dynamics of the proposed method strongly depend on the number of interconnections and the size of the power system. In [84] the neighboring TSOs is modeled with a constant PQ injection corresponding to the value of flows outside of area. [85] compares the different models of neighboring areas such as PV, PQ, Thevenin equivalent, and more advanced models like REI equivalent and non-reduced power system equivalent. These equivalents replace the power system beyond an interconnection of a TSO with a single interconnection. The parameters of different models for neighboring TSOs are fitted by using different least square based methods according to the past and current observations. This method is only based on local voltage and current measurements in the interconnections and doesn’t need any coordination between the different TSOs. It is shown that PQ equivalent could achieve near optimal performance. In By each generator or compensator Zonal Scale Regional or National Scale International Scale 42 addition, PQ equivalent provides the possibility to consider the exchange of active and reactive power between areas according to bilateral contracts. The concept of fairness is introduced in [86] and [87] to evaluate a compromise between different objectives of TSOs so that each TSO is less displeased. It should be noted that the system security is not taken into account by the mentioned works in [84], [85], [86], [87], [88]. In conclusion, in addition to the aforementioned studies in this area, it is still needed to study the current practices in voltage and reactive power control from security point of view. Possible problems in current practices which can threat the security of MAPS would be investigated. Furthermore, it is necessary to enhance the voltage and reactive power control methods in SAPS based on security criteria. According to the literature some aspects of this topic like considering both of RPR (particularly generator RPR) and corrective countermeasures, in addition to security based voltage control provision need more attention. For this purpose, it is important to propose an approach to enhance the voltage and reactive power control in SAPS by considering both preventive and corrective actions. 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