Читать книгу Power Electronics-Enabled Autonomous Power Systems - Qing-Chang Zhong - Страница 10
List of Figures
ОглавлениеFigure 1.1 Structure of the book.
Figure 2.1 Examples of divisive opinions in a democratized society.
Figure 2.2 The sinusoid‐locked loop (SLL) that explains the inherent synchronization mechanism of a synchronous machine.
Figure 2.3 Estimated electricity consumption in the US.
Figure 2.4 A two‐port virtual synchronous machine (VSM).
Figure 2.5 SYNDEM grid architecture based on the synchronization mechanism of synchronous machines (Zhong 2016b, 2017e).
Figure 2.6 A SYNDEM home grid.
Figure 2.7 A SYNDEM neighborhood grid.
Figure 2.8 A SYNDEM community grid.
Figure 2.9 A SYNDEM district grid.
Figure 2.10 A SYNDEM regional grid.
Figure 2.11 The iceberg of power system challenges and solutions.
Figure 2.12 The frequency regulation capability of a VSM connected the UK public grid.
Figure 3.1 Illustrations of the imaginary operator and the ghost operator.
Figure 3.2 The system pair that consists of the original system and its ghost.
Figure 3.3 Illustration of the ghost power theory.
Figure 4.1 Structure of an idealized three‐phase round‐rotor synchronous generator with p = 1, modified from (Grainger and Stevenson 1994, figure 3.4).
Figure 4.2 The power part of a synchronverter is a basic inverter.
Figure 4.3 The electronic part of a synchronverter without control.
Figure 4.4 The electronic part of a synchronverter with the function of frequency and voltage control, and real and active power regulation.
Figure 4.5 Operation of a synchronverter under different grid frequencies (left column) and different load conditions (right column).
Figure 4.6 Experimental setup with two synchronverters.
Figure 4.7 Experimental results in the set mode: output currents with 2.25 kW real power.
Figure 4.8 Experimental results in the set mode: output currents (left column) and the THD of phase‐A current (right column) under different real powers.
Figure 4.9 Experimental results in the droop mode: primary frequency response.
Figure 4.10 Experimental results: the currents of the grid, VSG, and VSG2 under the parallel operation of VSG and VSG2 with a local resistive load.
Figure 4.11 Real power P and reactive power Q during the change in the operation mode.
Figure 4.12 Transient responses of the synchronverter.
Figure 5.1 Structure of an idealized three‐phase round‐rotor synchronous motor.
Figure 5.2 The model of a synchronous motor.
Figure 5.3 PWM rectifier treated as a virtual synchronous motor.
Figure 5.4 Directly controlling the power of a rectifier.
Figure 5.5 Controlling the DC‐bus voltage of a rectifier.
Figure 5.6 Simulation results when controlling the power.
Figure 5.7 Simulation results when controlling the DC‐bus voltage.
Figure 5.8 Experimental results when controlling the power.
Figure 5.9 Experimental results when controlling the DC‐bus voltage.
Figure 6.1 Integration of a PMSG wind turbine into the grid through back‐to‐back converters.
Figure 6.2 Controller for the RSC.
Figure 6.3 Controller for the GSC.
Figure 6.4 Dynamic response of the GSC.
Figure 6.5 Dynamic response of the RSC.
Figure 6.6 Real‐time simulation results with a grid fault appearing at t = 6 s for 0.1 s.
Figure 7.1 Conventional (DC) Ward Leonard drive system.
Figure 7.2 AC Ward Leonard drive system.
Figure 7.3 Mathematical model of a synchronous generator.
Figure 7.4 Control structure for an AC WLDS with a speed sensor.
Figure 7.5 Control structure for an AC WLDS without a speed sensor.
Figure 7.6 An experimental AC drive.
Figure 7.7 Reversal from a high speed without a load.
Figure 7.8 Reversal from a high speed with a load.
Figure 7.9 Reversal from a low speed without a load.
Figure 7.10 Reversal from a low speed with a load.
Figure 7.11 Reversal at an extremely low speed without a load.
Figure 7.12 Reversal from a high speed without a load (without a speed sensor).
Figure 7.13 Reversal from a high speed with a load (without a speed sensor).
Figure 8.1 Typical control structures for a grid‐connected inverter.
Figure 8.2 A compact controller that integrates synchronization and voltage/frequency regulation together for a grid‐connected inverter.
Figure 8.3 The per‐phase model of an SG connected to an infinite bus.
Figure 8.4 The controller for a self‐synchronized synchronverter.
Figure 8.5 Simulation results: under normal operation.
Figure 8.6 Simulation results: connection to the grid.
Figure 8.7 Comparison of the frequency responses of the self‐synchronized synchronverter (f) and the original synchronverter with a PLL (f with a PLL).
Figure 8.8 Dynamic performance when the grid frequency increased by 0.1 Hz at 15 s (left column) and returned to normal at 30 s (right column).
Figure 8.9 Simulation results under grid faults: when the frequency dropped by 1% (left column) and the voltage dropped by 50% (right column) at t = 36 s for 0.1 s.
Figure 8.10 Experimental results: when the grid frequency was lower (left column) and higher (right column) than 50 Hz.
Figure 8.11 Experimental results of the original synchronverter: when the grid frequency was lower than 50 Hz (left column) and higher than 50 Hz (right column).
Figure 8.12 Voltages around the connection time: when the grid frequency was lower (left column) and higher (right column) than 50 Hz.
Figure 9.1 Controlling the rectifier DC‐bus voltage without a dedicated synchronization unit.
Figure 9.2 Controlling the rectifier power without a dedicated synchronization unit.
Figure 9.3 Simulation results when controlling the DC bus voltage.
Figure 9.4 Grid voltage and control signal.
Figure 9.5 Grid voltage and input current.
Figure 9.6 Simulation results when controlling the real power.
Figure 9.7 Experiment results: controlling the DC‐bus voltage.
Figure 9.8 Experiment results: controlling the power.
Figure 10.1 Typical configuration of a turbine‐driven DFIG connected to the grid.
Figure 10.2 A model of an ancient Chinese south‐pointing chariot (Wikipedia 2018).
Figure 10.3 A differential gear that illustrates the mechanics of a DFIG, where the figure of the differential gear is modified from (Shetty 2013).
Figure 10.4 The electromechanical model of a DFIG connected to the grid.
Figure 10.5 Controller to operate the GSC as a GS‐VSM.
Figure 10.6 Controller to operate the RSC as a RS‐VSG.
Figure 10.7 Connection of the GS‐VSM to the grid.
Figure 10.8 Synchronization and connection of the RS‐VSG to the grid.
Figure 10.9 Operation of the DFIG‐VSG.
Figure 10.10 Experimental results of the DFIG‐VSG during synchronization process.
Figure 10.11 Experimental results during the normal operation of the DFIG‐VSG.
Figure 11.1 Three typical earthing networks in low‐voltage systems.
Figure 11.2 Generic equivalent circuit for analyzing leakage currents.
Figure 11.3 Equivalent circuit for analyzing leakage current of a grid‐tied converter with a common AC and DC ground.
Figure 11.4 A conventional half‐bridge inverter.
Figure 11.5 A transformerless PV inverter.
Figure 11.6 Controller for the neutral leg.
Figure 11.7 Controller for the inverter leg.
Figure 11.8 Real‐time simulation results of the transformerless PV inverter in Figure 11.5(a).
Figure 12.1 STATCOM connected to a power system.
Figure 12.2 A typical two‐axis control strategy for a PWM based STATCOM using a PLL.
Figure 12.3 A synchronverter based STATCOM controller.
Figure 12.4 Single‐line diagram of the power system used in the simulations.
Figure 12.5 Detailed model of the STATCOM used in the simulations.
Figure 12.6 Connecting the STATCOM to the grid.
Figure 12.7 Simulation results of the STATCOM operated in different modes.
Figure 12.8 Transition from inductive to capacitive reactive power when the mode was changed at t = 3.0 s from the Q‐mode to the V‐mode.
Figure 12.9 Simulation results of the STATCOM operated with a changing grid frequency.
Figure 12.10 Simulation results of the STATCOM operated with a changing grid voltage.
Figure 12.11 Simulation results with a variable system strength.
Figure 13.1 Per‐phase diagram with the Kron‐reduced network approach.
Figure 13.2 Phase portraits of the controller.
Figure 13.3 The controller to achieve bounded frequency and voltage.
Figure 13.4 E+ surface (upper) and E− surface (lower) with respect to Ps and Qs.
Figure 13.5 Illustration of the areas characterized by E+ lines and E− lines.
Figure 13.6 Illustration of the area where a unique equilibrium exists.
Figure 13.7 Real‐time simulation results comparing the original (SV) with the improved self‐synchronized synchronverter (improved SV).
Figure 13.8 Phase portraits of the controller states in real‐time simulations.
Figure 14.1 The controller of the original synchronverter.
Figure 14.2 Active power regulation in a conventional synchronverter after decoupling.
Figure 14.3 Properties of the active power loop of a conventional synchronverter with Xpu = 0.05, ωn = 100π rad s−1, and α = 0.5%.
Figure 14.4 VSM with virtual inertia and virtual damping.
Figure 14.5 The small‐signal model of the active‐power loop with a virtual inertia block Hv(s).
Figure 14.6 Implementations of a virtual damper.
Figure 14.7 A VSM in a microgrid connected to a stiff grid.
Figure 14.8 Normalized frequency response of a VSM with reconfigurable inertia and damping.
Figure 14.9 Effect of the virtual damping (Jv = 0.2 s).
Figure 14.10 A microgrid with two VSMs.
Figure 14.11 Two VSMs operated in parallel with Jv1 = Jv2 = 1 s.
Figure 14.12 Two VSMs operated in parallel with Jv1 = 0.5 s and Jv2 = 1 s.
Figure 14.13 Simulation results under a ground fault with Jv = 0.1, 0.3, 0.5, 1 s.
Figure 14.14 Experimental results with reconfigurable inertia and damping.
Figure 14.15 Experimental results from the original synchronverter for comparison.
Figure 14.16 Experimental results showing the effect of the virtual damping with Jv = 0.2 s.
Figure 14.17 Experimental results when two VSMs with the same inertia time constant are in parallel operation.
Figure 14.18 Experimental results when two VSMs with different inertia time constants operated in parallel.
Figure 14.19 Experimental results when the two VSMs operated as the original SV in parallel operation with τω1 = τω2 = 1 s for comparison.
Figure 15.1 Block diagrams of a conventional PLL.
Figure 15.2 Enhanced phase‐locked loop (EPLL) or sinusoidal tracking algorithm (STA).
Figure 15.3 Power delivery to a voltage source through an impedance.
Figure 15.4 Conventional droop control scheme for an inductive impedance.
Figure 15.5 Conventional droop control strategies.
Figure 15.6 Linking the droop controller in Figure 15.4(b) and the (inductive) impedance.
Figure 15.7 Droop control strategies in the form of a phase‐locked loop.
Figure 15.8 The conventional droop controller shown in Figure 15.4(a) after adding two integrators and a virtual impedance.
Figure 15.9 The synchronization capability of the droop controller shown in Figure 15.8.
Figure 15.10 Connection of the droop controlled inverter to the grid.
Figure 15.11 Regulation of the grid frequency and voltage in the droop mode.
Figure 15.12 Robustness of synchronization against DC‐bus voltage changes.
Figure 15.13 System response when the operation mode was changed.
Figure 16.1 A single‐phase inverter.
Figure 16.2 Controller to achieve a resistive output impedance.
Figure 16.3 Controller to achieve a capacitive output impedance.
Figure 16.4 Typical output impedances of L‐, R‐, and C‐inverters.
Figure 16.5 Two R‐inverters operated in parallel.
Figure 16.6 Conventional droop control scheme for R‐inverters.
Figure 16.7 Experimental results: two R‐inverters in parallel with conventional droop control.
Figure 16.8 Robust droop controller for R‐inverters.
Figure 16.9 Experimental results for the case with a linear load when inverters have different per‐unit output impedances: with the robust droop controller (left column) and with the conventional droop controller (right column).
Figure 16.10 Experimental results for the case with a linear load when inverters have the same per‐unit impedance: with the robust droop controller (left column) and with the conventional droop controller (right column).
Figure 16.11 Experimental results for the case with the same per‐unit impedance using the robust droop controller: with Ke = 10 (left column) and Ke = 1 (right column).
Figure 16.12 Experimental results with a nonlinear load: with the robust droop controller (left column) and with the conventional droop controller (right column).
Figure 16.13 Robust droop controller for C‐inverters.
Figure 16.14 Experimental results of C‐inverters (left column) and R‐inverters (right column) with a linear load RL = 9 Ω.
Figure 16.15 Experimental results of C‐inverters (left column) and R‐inverters (right column) with a nonlinear load.
Figure 16.16 Robust droop controller for L‐inverters.
Figure 16.17 Experimental results of L‐inverters with a linear load: with the robust droop controller (left column) and the conventional droop controller (right column).
Figure 16.18 Experimental results of L‐inverters with a nonlinear load: with the robust droop controller (left column) and with the conventional droop controller (right column).
Figure 17.1 The model of a single‐phase inverter.
Figure 17.2 The closed‐loop system consisting of the power flow model of an inverter and a droop controller.
Figure 17.3 Interpretation of transformation matrices TL and TC.
Figure 17.4 Interpretation of the universal transformation matrix T.
Figure 17.5 Universal droop controller.
Figure 17.6 Real‐time simulation results of three inverters with different types of output impedance operated in parallel.
Figure 17.7 Experimental set‐up consisting of an L‐inverter, an R‐inverter, and a C‐inverter.
Figure 17.8 Experimental results with the universal droop controller.
Figure 18.1 The self‐synchronized universal droop controller.
Figure 18.2 Experimental results of self‐synchronization with the R‐inverter.
Figure 18.3 Experimental results when connecting the R‐inverter to the grid.
Figure 18.4 Experimental results with the R‐inverter: performance during the whole experimental process.
Figure 18.5 Experimental results with the R‐inverter: regulation of system frequency and voltage in the droop mode.
Figure 18.6 Experimental results with the R‐inverter: change in the DC‐bus voltage VDC.
Figure 18.7 Experimental results of self‐synchronization with the L‐inverter.
Figure 18.8 Experimental results with the L‐inverter: connection to the grid.
Figure 18.9 Experimental results with the L‐inverter: performance during the whole experimental process.
Figure 18.10 Experimental results with the L‐inverter: regulation of system frequency and voltage in the droop mode.
Figure 18.11 Experimental results with the L‐inverter: change in the DC‐bus voltage VDC.
Figure 18.12 Experimental results of self‐synchronization with the L‐inverter with the robust droop controller.
Figure 18.13 Experimental results from the L‐inverter with the robust droop controller: connection to the grid.
Figure 18.14 Experimental results from the L‐inverter with the robust droop controller: performance during the whole experimental process.
Figure 18.15 Experimental results from the L‐inverter with the robust droop controller: regulation of system frequency and voltage in the droop mode.
Figure 18.16 Experimental results with the L‐inverter under robust droop control: change in the DC‐bus voltage VDC.
Figure 18.17 A microgrid including three inverters connected to a weak grid.
Figure 18.18 Real‐time simulation results from the microgrid.
Figure 19.1 A general three‐port converter with an AC port, a DC port, and a storage port.
Figure 19.2 DC‐bus voltage controller to generate the real power reference.
Figure 19.3 The universal droop controller when the positive direction of the current is taken as flowing into the converter.
Figure 19.4 Finite state machine of the droop‐controlled rectifier.
Figure 19.5 Illustration of the operation of the droop‐controlled rectifier.
Figure 19.6 The θ‐converter.
Figure 19.7 Control structure for the droop‐controlled rectifier.
Figure 19.8 Experimental results in the GS mode.
Figure 19.9 Experimental results in the NS‐H mode.
Figure 19.10 Experimental results in the NS‐L mode.
Figure 19.11 Transient response when the system starts up.
Figure 19.12 Transient response when a load is connected to the system.
Figure 19.13 Experimental results showing the capacity potential of the rectifier: real power P, grid voltage Vg, DC‐bus voltage vDC, and Δϕ.
Figure 19.14 Controller for the conversion leg.
Figure 19.15 Comparative experimental results with a conventional controller.
Figure 20.1 A grid‐connected single‐phase inverter with an LCL filter.
Figure 20.2 The equivalent circuit diagram of the controller.
Figure 20.3 The overall control system.
Figure 20.4 Controller states.
Figure 20.5 Implementation diagram of the current‐limiting universal droop controller.
Figure 20.6 Operation with a normal grid.
Figure 20.7 Transient response of the controller states with a normal grid.
Figure 20.8 Operation under a grid voltage sag 110 V → 90 V → 110 V for 9 s.
Figure 20.9 Controller states under the grid voltage sag 110 V → 90 V → 110 V for 9 s.
Figure 20.10 Operation under a grid voltage sag 110 V → 55 V → 110 V for 9 s.
Figure 20.11 Controller states under the grid voltage sag 110 V → 55 V → 110 V for 9 s.
Figure 21.1 Two systems with disturbances interconnected through ΣI.
Figure 21.2 Two systems with disturbances and external ports interconnected through ΣI.
Figure 21.3 Three‐phase grid‐connected converter with a local load.
Figure 21.4 The controller for a cybersync machine with e to be supplied as u.
Figure 21.5 The mathematical structure of the system constructed to facilitate the passivity analysis, where the plant pair ΣP consists of the original plant and its ghost in grey and the input to the ghost plant is the ghost of the input to the plant.
Figure 21.6 Blocks Σω and Σφ implemented with the IC.
Figure 21.7 A cybersync machine equipped with regulation and self‐synchronization.
Figure 21.8 Simulation results from a cybersync machine, where the detailed transients indicated by the arrows last for five cycles with the magnitude reduced by 50%.
Figure 21.9 Experimental results from a cybersync machine.
Figure 22.1 A photo of the SYNDEM smart grid research and educational kit.
Figure 22.2 SYNDEM smart grid research and educational kit: main power circuit.
Figure 22.3 Implementation of DC–DC converters.
Figure 22.4 Implementation of uncontrolled rectifiers.
Figure 22.5 Implementation of PWM‐controlled rectifiers.
Figure 22.6 Implementation of the θ‐converter.
Figure 22.7 Implementation of inverters.
Figure 22.8 Implementation of a DC–DC–AC converter.
Figure 22.9 Implementation of a single‐phase back‐to‐back converter.
Figure 22.10 Implementation of a three‐phase back‐to‐back converter.
Figure 22.11 Illustrative structure of the single‐node system.
Figure 22.12 Circuit of the single‐node system.
Figure 22.13 Experimental results from the single‐node system equipped with a SYNDEM smart grid research and educational kit.
Figure 22.14 Texas Tech SYNDEM microgrid built up with eight SYNDEM smart grid research and educational kits
Figure 23.1 Illinois Tech SYNDEM smart grid testbed.
Figure 23.2 Topology of a θ‐converter.
Figure 23.3 Topology of a Beijing converter.
Figure 23.4 Back‐to‐back converter formed by a Beijing converter and a conversion leg.
Figure 23.5 Back‐to‐back converter formed by a θ‐converter and a conversion leg.
Figure 23.6 Operation of the energy bridge to black start the SYNDEM grid.
Figure 23.7 Integration of the solar power node.
Figure 23.8 Integration of the wind power node.
Figure 23.9 Performance of the wind power node when the wind speed Sw changes.
Figure 23.10 Integration of the DC‐load node.
Figure 23.11 Integration of the AC‐load node.
Figure 23.12 Operation of the whole testbed.
Figure 24.1 The home field at the Texas Tech University Center at Junction, Texas.
Figure 24.2 The home grid.
Figure 24.3 Black‐start and grid‐forming capabilities.
Figure 24.4 From islanded to grid‐tied operation.
Figure 24.5 Seamless mode change when the public grid is lost and then recovered.
Figure 24.6 Power sharing and regulation of the voltage and frequency of the home grid.
Figure 24.7 The nonlinearity of the transformer.
Figure 24.8 The nonlinearity of household loads.
Figure 24.9 The large inrush current of the air conditioning unit.
Figure 25.1 Panhandle wind power system.
Figure 25.2 Connection of wind power generation system to grid.
Figure 25.3 VSM controller for each wind turbine.
Figure 25.4 Standard DQ controller for GSC.
Figure 25.5 Simulated panhandle wind farms.
Figure 25.6 Simulation results from a single unit.
Figure 25.7 The voltage, frequency, active power and reactive power at 345 kV buses.
Figure 25.8 Panhandle wind power system: the voltage, frequency, active power, and reactive power at the PCC of a single unit at the Wind Mill wind farm.
