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Role of Multi-infeed VSC-HVDC on Dynamic Behaviour of Future North Scotland Transmission System Rakibuzzaman Shah, Robin Preece and Mike Barnes School of Electrical and Electronic Engineering, The University of Manchester, M13 9PL, United Kingdom E-mail: [email protected]; [email protected]; [email protected] Keywords: Dynamic interaction, multi-infeed HVDC, North Scotland system, outer controller. called multi-infeed (MI)-HVDC system, especially in the North of Scotland as reported in . The MI-HVDC has more flexibility and transmission capacity, which can improve the controllability and reliability of the whole AC system. However, as reported in [4-7], the mutual interaction between HVDC links within MI-HVDC can bring a number of operational challenges in power systems. Since most of the globally installed HVDC links are based on the line-commutated converter (LCC), voltage stability has been identified as the key concern in such a mixed AC-DC system [4-6]. The developments in VSC technology and controls are making VSC-HVDC a strong option for HVDC connections. However, to date, limited research has focussed on the operational challenges associated with a mixed AC-DC system with multi-infeed VSC-HVDCs except , where an outer controller selection of multi-infeed VSC-HVDC considering the stability aspects of the AC-DC system is addressed. However, it articulates quite generic and far-reaching conclusions based on a limited number of operating conditions in a naïve test system. Abstract Due to the expected proliferation of HVDC systems up to and beyond 2020 into the Great British transmission network, it is anticipated that in some locations two or more HVDC converter stations will be installed with only a short electrical distance between them and will form a multi-infeed (MI)HVDC system. This is a particular concern in the North of Scotland. This paper investigates the impact of MI-HVDC links on the North Scotland system for two different system generation mixes. A list of control schemes has been formulated to assess the dynamic performance of the developed realistic system under typical loading scenarios. The work has been conducted in a DIgSILENT Power Factory using case study simulations of the integrated North Scotland system model. From the set of case studies, it has been found that the AC voltage control allocation within the HVDC links has a significant influence on the smalldisturbance angle and transient voltage stability of the system. It is anticipated that two or more HVDC links will be installed with only a short electrical distance in the North Scotland system. Therefore, it is important for the GB transmission system operator to have a greater clarity of the dynamic behaviour of the North Scotland system with MIHVDC. This study, therefore, has analysed the impact of VSC-based MI-HVDC links on the dynamics of the North Scotland system under electromechanical transient timeframe. A variety of test case studies including varied operating conditions and control configurations have been conducted and reported in this paper. 1 Introduction High voltage DC (HVDC) transmission systems are recognized around the world as the prospective technology to integrate the large far-from-shore wind power plants (WPPs) and asynchronous AC grids . It is also a leading candidate for AC grid reinforcement. Since most of the UK’s suitable offshore sites for wind power are located a significant distance from shore (i.e. more than 100 km), a large portion of these new WPPs in the UK will be connected through HVDC links. Moreover, the growing desire to interconnect with the asynchronous grids in North Sea region will increase the use of HVDC links, especially VSC-HVDC in the Northeast of UK [2, 3]. 2 System Modelling The test system illustrated in Fig. 1 has been designed as a reduced dynamic equivalent of the North Scotland power system, henceforth referred as reduced North Scotland (RNS) system in this paper. The basis for this model is obtained from the GB network and published previously in [8, 9]. To represent the RNS system, the network elements beyond the node 4 of the original GB system have not been considered for this reduced test system. Therefore, the network elements beyond node 4 are represented as an external grid behind a high voltage transformer. Currently, there are four HVDC links connecting the Great Britain (GB) transmission system to other asynchronous grids: IFA to France, Moyle to Northern Ireland, BritNed to Netherlands, and EWIC to Ireland. It is expected that this type of interconnection will increase in the future, and five more HVDC links to interconnect GB transmission system to other asynchronous grids are due to be commissioned by 2020. Due to the incremental use of HVDC systems, it is expected that two or more HVDC links will feed into the UK’s transmission network within a short electrical distance and will form a so- 1 The RNS model consists of four nodes interconnected through transmission lines. In addition to the original nodes 1 to 4 from the initial GB model, a further node (node 5), is added to the test system to facilitate the integration of the HVDC infeed to represent the Caithness-Moray link (see Fig. 2). All AC transmission lines consist of a double circuit, except for line 2‒3 which is a single circuit only. These transmission lines represent the main power flow across North Scotland. All the transmission lines have a nominal voltage of 275 kV. HVDC infeeds representative of the Western Isles and the Northconnect will be integrated with the AC system model at node 1 and 2, shown in Fig. 2. The modelling of generator controllers is essential to ensure the realistic dynamic performance of the AC system. Depending on the focus of the study this can include exciters, power system stabilizers (PSSs), and governors. For this study, governor models are not important since the focus of the simulations is in the electromechanical transient timeframe which is faster than the action of the governors. For the test system, the DC1A excitation system is used in all the generation types since this has widely been implemented by industry for coal, gas, and hydro plants. PSSs have been added to the system and have been designed based on the single machine infinite bus (SMIB) model of every generator in the system. System demand is modelled at the high voltage buses as a static load as given in . Since the detailed information of load compositions is not available, the dynamic simulations will be conducted using a polynomial load model, i.e. a combination of constant impedance, constant current, and constant power, (ZIP) load model. This model has been widely used by utilities . The resulting “RNS model” has a total installed generation capacity of approximately 6.98 GW, with a demand (at nodes 1-5) of 2.95 GW. A further 2.24 GW flows from the RNS system to the external grid (i.e. to Southern Scotland, England and Wales). 3 Generic VSC-HVDC Control Fig. 1: Single-line diagram of RNS network. This section presents a generic primary control structure for VSC-HVDC converters suitable for studies on an electromechanical dynamic time-frame. The average value model (AVM) of VSC-HVDC system presented in  has been used throughout this study. A positive sequence phasor representation is used for the AC system when performing dynamic studies in an electromechanical time-frame, which is compatible with balanced AC system studies. Hence, a negative sequence current control is neglected . The control system analysis is based on the per unit representation of the controller transfer function to avoid the complications associated with different ratings and units . An internal model control (IMC) tuning method given as in (1) has been used to obtain robust current loop controller settings . All VSC-HVDC infeeds model are standardized at 1000 MW. Fig. 2: Representative RNS network with proposed HVDC links. Dynamic data is required for the developed RNS system to perform dynamic analysis with MI-HVDC links. This includes the detailed modelling of the generators, excitation systems, and power system stabilizers (PSSs). The type of generator in each node is selected based on their corresponding contribution on that node. The resulting dominant generator types in the RNS network model are summarized in Table 1. A Sixth order synchronous generator model has been used for all units. The selected generation types are parameterized with corresponding data as recommended in . Generator type Hydro unit CCGT unit Fossil fuel unit (coal) G( s ) 1 Ls R 1 des 1 1 kp 1 1 L des ,ki R des (1) In (1), L is the inductance of the reactor, R is the resistance of the reactor, and des is the desired time constant of the closed-loop step response. Node GT-1,GT-3 GT-2 GT-4 The generic model of the DC voltage (VDC)/active power (P), and AC voltage (VAC)/reactive power (Q) controllers as shown in Fig. 3 are implemented in VSC-HVDC links for Table 1: Generator types. 2 dynamic simulations. The detail of these controllers can be found in  and the references therein. Moreover, the feedforward reactive power controller in  is amended by Ptanϴ to articulate the power factor (pf) control. For this study, a point-to-point HVDC link with detailed models of grid-side and remote converters and controls has been employed. A voltage source has been used to represent the distant power system at the remote end of the converter. A detailed DC cable model (i.e. distributed features of DC cables and frequency dependent models) gives more accurate results whereas the nominal pi model of a DC cable might be more numerically stable in simulations than the distributed model. The distributed features of DC cable modelling or frequency dependent DC cable model cannot be utilized in DIgSILENT Power Factory . Therefore, a cascaded PI model has been employed to represent the DC cables for the proposed studies to achieve the higher model fidelity on the analysis time-frame of interest. In (2), N is the total number of buses in the system, T is the time-frame considered for evaluating TVSI, Tc is the fault clearing time, and TVDI i ,t is the transient voltage deviation Fig. 3: VSC-HVDC primary control system. Two cases have been used: (1) with a current generation mix as defined for 2013; and (2) with an anticipated generation mix representative of 2023. Conventional generator models are used to form the dynamic model of the 2013 case, whereas, for the 2023 generation scenario, the conventional generator (Hydro) at GT-3 (see Fig. 1) is replaced by a large wind generator . A priority based current control limit has been used for all control schemes listed in Table 2. To facilitate the HVDC infeeds into the system, the loads at nodes 1 and 2 are increased by 40%, from the summer peak scenario as given in , referred as summer peak loading condition in this paper. The winter peak loading (approximately 150 % of the summer peak ) has also been used to analyse the impacts of the MI-HVDC system in the RNS network. It should be noted that identical summer and winter peak loading conditions are used for both the generation scenarios since it is reported that the load growth will be minimum over the next seven to ten years’ time . index of bus i at time t. The TVDI i ,t can be evaluated as (3): TVDI i ,t 4.2 Control schemes and test cases A number of different hierarchical control schemes can be implemented in a VSC-HVDC system. In a MI-HVDC scheme, the control method might be dictated by the application. It is, therefore, possible that the MI-HVDC system will be operated with different mode of operations. It has previously been reported that the VSC-HVDC outer controllers have significant impacts in the AC-DC dynamics of the system . Hence, in this study, different combinations of outer control schemes, listed in Table 2, are used to analyse the effects of MI-HVDC control characteristics on the dynamics of the host AC system. It is acknowledged that control combinations other than these can be encountered in real systems. However, the idea behind the selection of these control combinations is to illustrate the effects of divergent control characteristics at different VSCHVDC terminal in the MI-HVDC scheme and identify scenarios for further detailed study and analysis. From the perspective of AC-side small-disturbance rotor angle stability, the investigation focuses on the impact of the MIHVDC control allocation on the damping of various electromechanical (EM) modes of the system. The QR analysis method has been used to evaluate the eigenvalues to the frequency of interest (0.2‒3.0 Hz) and the corresponding damping ratios are calculated. Short-term voltage stability (transient voltage stability) mainly focuses on the transient voltage limit violation, delayed voltage recovery or fast voltage collapse following a largedisturbance to the system. To measure the transient voltage stability of the system, a transient voltage severity index (TVSI) proposed in  has been used in this paper. Transient voltage performance of the system buses following the clearance of the fault can be evaluated as (2): 4.3 Small-disturbance angle stability analysis The aim is to investigate the host AC system EM modes under the effect of various control combinations (see Table 2) within a MI-HVDC system and the given operating points of the AC system. The damping ratios of the EM modes without the proposed HVDC links to the RNS system (referred as the T TVDI i ,t i 1 t Tc N T Tc (3) and Vi ,0 is the nominal voltage of bus i. From (2), it is evident that the smaller TVSI value means the better transient voltage performance of the system. 4.1 Stability Indices TVSI Vi ,0 In (3), Vi ,t refers to the voltage magnitude of bus i at time t, 4 Numerical Analysis N Vi ,t Vi ,0 (2) 3 base case) are given in Table 3 for a clear comparison. The damping ratios of the EM modes for 2013 and 2023 generation scenarios are demonstrated in Fig. 4 and 5 under summer and winter peak loading conditions. Control ID (CI) 1 2 Grid-side converter 5 Vdc-Q (all) Vdc-Q (W), Vdc- Vac (CM); Vdc-pf (N) Vdc-Q (N), Vdc- Vac (W); Vdc-pf (CM) Vdc-Q (CM), Vdc- Vac (N); Vdc-pf (W) Vdc-Q (W,CM), PQ (N) 6 Vdc- Vac (W,CM), PQ (N) 3 4 three-phase fault clearance can be seen, which is in agreement with the results given in Fig. 4 and 5. Remote converter PQ(all) PQ (all) PQ(all) PQ (all) (a) PQ (W,CM), VdcQ (N) PQ (W,CM), VdcQ (N) W = Western Isles; CM = Caithness-Moray; N = Northconnect Table 2: Control schemes for converter stations. EM mode ID 1 2 3 4 Damping ratio 0.13 0.096 0.10 0.042 Frequency (Hz) 2.60 2.07 1.37 0.73 (b) Table 3: EM modes of the RNS system without HVDC links. Fig. 4: Damping of EM modes for 2013 generation scenario (a) summer peak (b) winter peak Examining the results in Fig. 4, it is seen that the damping of the mode 4 (inter-area mode) is reduced for all control combinations (the only exception is CI-3 under summer peak) within MI-HVDC system, and the system experienced the lowest inter-area mode damping under CI-4. From the results in the figure, it can be seen that the damping of mode 1 is almost kept constant at the base case value for CI-1 and CI-2, and is reduced from the base case for other control combinations. Furthermore, with the integration of the proposed HVDC links, the damping of mode 2 is reduced from the base case, however, it is not significantly affected by the control allocation within the MI-HVDC. On the contrary, the damping of mode 3 is increased from the base case for CI1 and CI-2, however, is reduced for other control combinations. Looking at the results presented in Fig. 5, it can be seen that the damping of the inter-area mode is reduced from the base case for the 2023 generation scenario. Mode 1 of the system is eliminated for this scenario due to the replacement of the synchronous generator with a full converter WPP at GT-3. The damping of mode 2 is reduced from the base case, however, is not significantly affected by the control allocation within the MI-HVDC. Similar to the previous study, the damping of mode 3 shows an increasing trend for CI-1 and 2, and a decreasing trend for other control combinations. (a) It is identified that the CI-4 in MI-HVDC has the most adverse effect on the inter-area mode of the system. Therefore, the effect of CI-4 at MI-HVDC system is validated by time domain simulations presented in Fig. 6. The active power responses of a single line between node 2 and 4 following a three-phase fault at node 3 for 80 ms are given in Fig. 6. Sustained oscillations of line active power following a (b) Fig. 5: Damping of EM modes for 2023 generation scenario (a) summer peak (b) winter peak 4 voltage control of the system. The dynamic responses of the DC-link voltages following a disturbance to the AC system are presented in Fig. 8. Analysis has been conducted for various operation scenarios. Since the DC voltage responses of different operating conditions display very similar dynamic behaviour, the DC voltage response results for 2013 generation scenario at summer peak are presented here for brevity. From the figure, it can be seen that DC link voltages are effectively maintained within acceptable limits by the designed DC voltage controllers. From the results in Fig. 8, it can be seen that the DC voltage excursion following the fault clearance is affected by the MI-HVDC control combinations. Moreover, it should be noted that following the fault in node 3 at 12.5 s, the DC link voltage of the grid-side converter at Northconnect is reduced for CI-5 and CI-6 control combination since the grid-side converter at Northconnect is operating in rectifier mode under those control combinations. Fig. 6: Line 2-4 power responses for CI-4 at different generation scenarios. 4.4 Transient voltage stability analysis In a converter dominated power system, transient voltage stability is becoming important due to the voltage or reactive power management issues associated with converters and synchronous generators in the system. The effect of MIHVDC control combinations on the transient voltage stability is presented in this section by considering the transient voltage severity index illustrated in Section 4.1. The TVSIs are assessed for 2013 and 2023 generation mixes under summer and winter peak loading for a three-phase fault at node 3 and 5 of the RNS system. The TVSI of the system for 2013 generation scenario is given in Fig. 7 (a). Examining the upper and lower ranges of TVSI across all control combinations, it can be obtained that the CI1 has the most adverse effect on the transient voltage stability of the system (a larger TVSI value corresponds to the lower transient voltage stability level). From the figure, it can also be seen that the CI-6 could claim to outperform the other control combinations given in Table 2. Voltage control is applied to the grid-side converters of the proposed Western Isles and Caithness-Moray HVDC link under CI-6. This enables fast dynamic reactive power management to the system nodes after the fault clearance, resulting in a better transient voltage stability level for the system. (a) The TVSI of the system for 2023 generation scenario is given in Fig. 7 (b). For 2023 generation scenario, it is assumed that the WPP at GT-3 (see Fig. 1) is operating at constant power factor mode. Comparing the upper and lower ranges of all TVSIs for the given control combinations, it is evident that CI-1 is adversely affecting the transient voltage stability of the system. Comparably, CI-6 provides the enhanced transient voltage stability level among all control combinations considered in this study. It should be noted that the interaction among VSC-HVDC reactive power and generator excitation controls causes the higher transient overvoltage following the fault clearance under 2013 generation scenario, thereby, having the higher value of TVSIs for all control combinations as compared to the 2023 generation scenario. (b) Fig. 7: Transient voltage severity index (a) 2013 generation scenario (b) 2023 generation scenario 5 Conclusions This study has investigated the impacts of the planned MIHVDC system on the dynamic behaviour of the representative North Scotland power transmission system. The study has been conducted by investigating the influence of various control combinations of the proposed HVDC links on the host AC system small-disturbance angle and transient voltage stability. From the results given in this paper, it can be seen that the outer controller allocation within the MI-HVDC system has a significant influence on the small-disturbance angle and transient voltage stability of the system. Based on the set of simulation results it can be concluded that the 4.5 DC system effect The dynamic response of the DC-side is much faster than the AC-side of the system, thereby, are shown by the DC-side transient responses. It has been reported that the VSC-HVDC operating points and grid strength may affect the DC-link 5 transient voltage stability performance of the system is improved when AC voltage control is applied to the Western Isles and Caithness-Moray HVDC link. However, it has demonstrated an aggravated impact on the small-disturbance angle stability of the RNS system.     (a)   (b)    (c) Fig. 8: DC voltage responses of grid-side converter (a) Western Isles (b) Caithness-Moray (c) Northconnect  Acknowledgments  The authors would like to thank the Scottish and Southern  Energy Plc (SSE Plc) for supporting this work. References   N. Flourentzou, V. G. Agelidis, and G. D. Demetriades, “VSC-HVDC power transmission systems: an  overview,” IEEE Trans. Power Electron., vol. 24, no. 3, pp. 592-602, (2009). “National Grid Electricity Ten Year Statement,” National Grid Electricity Transmission plc. [Online]. 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