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Transmission grid topology control (TC) is an emerging technology proposed in recent years to improve power system performance by using e xisting transmission lines more efficiently. Incorporated into the optimal power flow (OPF) with different objective functions, TC can be used for various purposes, such as operational cost reduction and corrective actions. As a leader of employing TC in the power industry, the Pennsylvania New Jersey Maryland (PJM) Interconnection has identified and published a list of switching solutions for the purpose of thermal limit violation and voltage control. Moreover, with significant penetration of wind and solar generations installed in the grid, the optimal system topology varies with time caused by the uncertainty of intermittent nature. TC has a promising future to track the optimal topology for each hour to reduce the operational cost and the line capacity expansion cost. However, these benefits are only possible if we can overcome the stability issues in operation, which is the focus of our research. A line switching action may introduce a large disturbance in the system and thus transient instability becomes a potential security concern. In previous literature, transient instability is observed in line switching actions in different systems. As a result, some beneficial switching plans are abandoned for the sake of security. Therefore, the key problem is how to enhance system stability to enable beneficial switching actions. To achieve that, a proper index that can be calculated offline and then used online to provide preventive stabilizing control guidelines is desired for TC applications. However, existing indices such as critical clearing time, transient stability index and transient energy function are unsuitable for preventive stabilizing control in TC applications. In addition, these indices are usually used for deterministic studies where the uncertainties in the grid are not considered. In our research work, a new quantitative index, critical switching flow (CSF), is proposed to assess transient stability in TC. CSF is the maximum real power flow allowed on a transmission line so that the system is stable when switching off the line. When a line flow is greater than CSF, the system has a risk of instability when switching off the line. The rigorous mathematical derivation of CSF is provided on a two-machine system and then extended to multi-machine systems. CSF establishes a direct connection between the line flow measurement of a switching target line and system transient stability in TC. Thus, CSF has a natural advantage of providing explicit control instructions in TC over the aforementioned indices. A preventive stabilizing redispatch scheme based on CSF is then proposed to enhance system transient stability in TC applications. First, the CSF values are calculated offline in the day-ahead unit commitment and scheduling stage using our probabilistic algorithm based on PSS/E with precise dynamic models from the industry. The proposed two-stage Monte Carlo simulation algorithm will consider the uncertainties of loads and generations and find the statistically precise CSF, which shows the boundary between stable and unstable switching actions based on the worst scenario. This offline learning process will generate sufficient knowledge for online TC applications. Then, the CSF based preventive stabilizing redispatch scheme will provide control guidelines to find a stable trajectory for an online TC application. Once a switching plan is found unstable in the online stability check, the proposed scheme is carried out first to decrease the line flow to a safe value below the CSF to ensure the stability of the subsequent switching action. The proposed algorithm and scheme are tested on the modified IEEE-118 bus system, which has large scale of wind power and solar power installed. In the numerical studies, the calculated CSF values are valid to avoid all unstable scenarios. Moreover, the proposed redispatch scheme is activated when there are sufficient resources to redispatch and decrease the flow on the switching target line to a value below the CSF. The proposed scheme is activated in 371 out of 800 unstable switching cases in total. All the 371 activated cases are stabilized using our proposed preventive stabilizing redispatch scheme. The proposed scheme will not be activated for the rest of unstable cases because of insufficient resources to redispatch. And details of system response in the proposed scheme are also shown for validation and illustration.

Integration of converter-control based renewable generators (CCBGs) into power systems introduces new dynamics and influences system stability. One particular concern is its impact on power system oscillations. Among different types of CCBGs, doubly-fed induction generators (DFIGs) have attracted the most attention. Reference [1]–[3] use the DFIG model with detailed control loops developed by General Electric (GE) and study its impact on power system small signal oscillations. It is observed that the DFIG reactive power/voltage control loop introduces an oscillation mode whose frequency is in the range of electromechanical oscillations (0.1 Hz to 2 Hz) [1]. DFIG's influence on the electromechanical oscillations is found to be highly dependent on parameters of this control loop [1, 2]. In [3], eigenvalue analysis is conducted for the Western Electricity Coordinating Council (WECC) system with projected high CCBG penetration conditions. An oscillation mode involving both wind turbine and synchronous generator (SG) state variables is observed. It is found that the wind turbine reactive power/voltage control variables have the highest participation in this mode. The observations in [1]–[3] indicate interactions between the DFIG reactive power/voltage control mode (referred to as VAR controller mode hereafter) and the SG electromechanical mode. However, the mechanism of the interaction and the conditions for strong interaction is not explored. Moreover, how this interaction affects the mode shapes of the two modes is not studied. Since the CCBG mechanical dynamics are separated from the grid by the converter interface, coupling between the CCBG converter control modes and the electromechanical modes becomes a critical way by which the CCBG dynamics can influence the electromechanical oscillations and it deserves through study. Based on the mode coupling theory, this paper reveals the interaction mechanism between the VAR controller mode and the SG electromechanical mode. Impacts of this interaction on power system oscillations are demonstrated and discussed. First, the VAR controller mode is investigated using damping torque analysis. Impact of operating condition change on its damping and frequency is shown analytically. The coupling between this mode and an electromechanical inter-area mode is then explored in a two-area test system. It is demonstrated that when frequency of the VAR controller mode approaches the inter-area mode, mutual participation increases and the influence of DFIG dynamics on the inter-area mode is increased. Additionally, it is shown that both positive and negative effect on the inter-area mode damping can be imposed depending on the VAR controller parameters. Moreover, the influence of mode coupling on mode shape of the two modes is investigated and it is demonstrated that the VAR controller mode, if becomes unstable, can couple with a well damped inter-area mode and cause unstable inter-area oscillations. In other words, in this situation, the unstable local voltage oscillation at the DFIG wind farm will propagate to other areas of the system and cause detrimental effect to the system. This study has practical merits. Challenge of wind generator voltage control on weak grids has been identified in the Electric Reliability Council of Texas (ERCOT) system [4]. Voltage and power oscillations close to a wind power plant were observed in ERCOT, following the outage of a nearby transmission line [4] or update of its controller settings [5]. Voltage controller is identified as the source of oscillations [4, 5]. The study in this paper offers insights into the VAR controller mode and demonstrates that not only local oscillations, but also inter-area oscillations can be caused by improper setting of the DFIG VAR controller or change in system operating conditions close to the DFIG plant. The key findings and conclusions of this study are summarized as follows: The DFIG VAR controller mode is sensitive to the system operating condition close to the wind generator. The voltage control scheme of DFIG is more prone to instability than the reactive power control scheme and the damping of the VAR controller mode decreases when the system becomes weaker at the DFIG interconnection point.When frequency of the VAR controller mode approaches an inter-area mode, the followings are observed: 1) mutual participation of the two modes increases; 2) the influence of DFIG dynamics on the inter-area mode damping increases; 3) mode shape of the VAR controller mode changes to involve inter-area oscillation of the SGs. When mode coupling is strong between the two modes, unstable inter-area oscillations can be caused by two mechanisms: 1) a stable VAR controller mode contributes negative damping to the inter-area mode 2) the VAR controller mode becomes unstable and couples with a sufficiently damped inter-area mode (change in VAR controller mode shape) and cause inter-area oscillations. Both situations can be severely detrimental to the system and should be carefully studied to avoid them.Proper settings of the VAR controller can also increase the inter-area mode damping. Results of this study can be generalized to other types of CCBGs since they have the same VAR controller structure (based on models in PSS/E). Thus the potential coupling between the VAR controller mode and the inter-area mode is generic for CCBGs. [1] G. Tsourakis, B. Nomikos, and C. Vournas, “Effect of wind parks with doubly fed asynchronous generators on small-signal stability,” in Electr. Power Syst. Res., vol. 79, no. 1, pp. 190–200, 2009. [2] L. Fan, Z. Miao, and D. Osborn, “Impact of doubly fed wind turbine generation on inter-area oscillation damping,” in Proc. IEEE Power Eng. Soc. Gen. Meeting, 2008, pp. 1–8. [3] J. Quintero, V. Vittal, G. T. Heydt and H. Zhang, «The Impact of Increased Penetration of Converter Control-Based Generators on Power System Modes of Oscillation,» in IEEE Transactions on Power Systems, vol. 29, no. 5, pp. 2248-2256, Sept. 2014. [4] S-H. Huang et al. “Voltage Control Challenges on Weak Grids with High Penetration of Wind Generation: ERCOT Experience,” in Proc. IEEE PES General Meeting, San Diego, CA, July 2012, pp. 1–7. [5] Technology solutions for wind integration in ERCOT, [Online]. www.electrictechnologycenter.com/pdf/TPR2Rev0Chg0043014.pdf