Control method of photovoltaic solid state transformer under grid single-phase-to-ground fault condition

Abstract

The application discloses a control method of a photovoltaic solid-state transformer under a single-phase-to-ground drop fault condition of a power grid, and belongs to photovoltaic power generation technology in the electrical engineering field. Main steps are as follows: judging a three-phase power grid fault type and detecting a drop depth of a power grid voltage; calculating instruction values of positive sequence active and positive sequence reactive currents that can be provided by an inverter when the single-phase-to-ground drop fault of the power grid occurs and controlling three-phase power grid currents; judging an operation state of the system, and adopting different control strategies under different operation states to effectively inhibit active power backflow; and through control on a single-path input four-path output three-level full-bridge LLC converter, average value control on a DC bus capacitor voltage of an H-bridge converter is realized. When the single-phase-to-ground drop fault of the power grid occurs, the control method can improve adaptability of a three-phase cascaded H-bridge type photovoltaic solid-state transformer to different output powers and different power grid drop depths, and improve low-voltage ride-through capability of the system.

Description

Technical Field

[0001] This invention pertains to photovoltaic power generation technology in the field of electrical engineering, specifically relating to a control method for a photovoltaic solid-state transformer under single-phase ground fault conditions in the power grid. Background Technology

[0002] Photovoltaic solid-state transformers based on cascaded H-bridge (CHB) topology have attracted widespread attention from scholars due to their superior performance. Their modular structure allows for the expansion of systems to higher voltage and power levels using low-voltage switching devices, making it possible to connect an entire photovoltaic power plant to a medium-voltage grid using only a single converter. Furthermore, this modular cascaded photovoltaic solid-state transformer enables highly efficient, ultra-high-power, direct-connection to the medium-voltage grid without a power frequency step-up transformer. This is an important approach to constructing efficient, economical, reliable, and flexible large-scale photovoltaic power plants, aligning with the current development trend of large-scale photovoltaic power plants.

[0003] With the continuous increase in the penetration rate of medium- and high-voltage photovoltaic grid-connected converters, next-generation photovoltaic power generation systems must maintain grid connection and provide reactive power to support grid voltage during grid dips, i.e., low-voltage ride-through capability. However, the three-phase cascaded topology is relatively special, essentially consisting of three independent single-phase CHB inverters. If an asymmetrical fault occurs in the grid, due to the influence of negative sequence voltage, one phase of the three-phase inverter may absorb active power from the grid (while the other two phases transmit active power back to the grid), i.e., the active power backflow problem. Active power backflow will result in the system having no balanced operating point during low-voltage ride-through, the H-bridge DC bus voltage continuously rising, and the inverter eventually shutting down and disconnecting from the grid due to overvoltage faults. Therefore, for three-phase cascaded H-bridge photovoltaic solid-state transformers, not only must grid connection guidelines be met during low-voltage ride-through, but additional control strategies must also be adopted to suppress active power backflow.

[0004] Currently, many studies have investigated low-voltage ride-through control strategies for three-phase isolated cascaded H-bridge photovoltaic grid-connected inverters. The literature “Tao Zhao, and Daolian Chen, “Analysis and Suppression of Active Power Backflow of Three-Phase Common DC-Bus Cascaded H-Bridge PV Grid-Connected Inverter During LVRT,” IEEE Journal of Emerging and Selected Topics in Power Electronics, vol.10, no.1, pp.745-759, Feb.2022. (Tao Zhao and Daolian Chen, Analysis and Suppression of Active Power Backflow of Three-Phase Common DC-Bus Cascaded H-Bridge PV Grid-Connected Inverter During Low-Voltage Ride-Through, IEEE Journal of Emerging and Selected Topics in Power Electronics, vol.10, no.1, pp.745-759)” proposes an active current injection control strategy to suppress the active power backflow problem of three-phase photovoltaic solid-state transformers under low-voltage ride-through conditions. This method calculates a suitable positive-sequence active current specification value based on different types and degrees of voltage dips in the power grid. The deeper the voltage dip, the larger the positive-sequence active current that needs to be compensated. Under normal output power conditions of the photovoltaic power plant, this method can effectively suppress active power backflow. However, when the light intensity decreases, such as in the early morning, evening, or even on cloudy or rainy days, the actual positive-sequence active current that the system can output may be less than the minimum positive-sequence active current required to suppress active power backflow, and this method still cannot completely prevent active power backflow.

[0005] The paper "Tao Zhao, and Daolian Chen, 'Active Power Backflow Control Strategy for Cascaded Photovoltaic Solid-State Transformer During Low-Voltage Ride Through,' IEEE Trans. Ind. Electron., vol. 69, no. 1, pp. 440-451, Jan. 2022" proposes a low-voltage ride-through control strategy for cascaded photovoltaic solid-state transformers based on zero-sequence voltage compensation. This strategy aims to counteract the negative-sequence voltage's influence on the distribution of active power between phases in the three-phase converter by compensating with a suitable zero-sequence voltage, thereby suppressing active power backflow. However, when the grid voltage drops significantly, the amplitude of the modulated voltage increases substantially after zero-sequence voltage compensation. This can lead to inverter overmodulation and weaken the zero-sequence voltage compensation effect, resulting in the continued risk of active power backflow in the system. However, the document does not analyze this in depth.

[0006] In summary, existing control methods for suppressing active power backflow in three-phase cascaded photovoltaic solid-state transformers under low voltage ride-through conditions still have the following problems:

[0007] (1) The existing active current injection control strategy does not take into account the working scenario when the light intensity is reduced. In other words, the active current injection control strategy cannot effectively suppress active power backflow when the light intensity is low.

[0008] (2) For the existing zero-sequence voltage compensation strategy, when the grid voltage drops significantly, the amplitude of the modulation voltage of some phases will increase after the zero-sequence voltage is compensated. This may cause the inverter to over-modulate and weaken the compensation effect of the zero-sequence voltage, resulting in the risk of active power backflow in the system. Summary of the Invention

[0009] The technical problem to be solved by this invention is to overcome the limitations of the above-mentioned solutions and propose a control method for photovoltaic solid-state transformers under single-phase ground slip fault conditions of the power grid. Based on the actual active power output of the inverter and the voltage drop depth of the power grid, the operation of the system is divided into two states. Different control methods are adopted when operating in different states, which can reduce the amplitude of the three-phase modulation voltage and thus effectively suppress active power backflow.

[0010] To achieve the above objectives, the technical solution adopted by this invention is as follows:

[0011] A control method for a photovoltaic solid-state transformer under single-phase-to-ground slip fault conditions in a power grid is disclosed. The photovoltaic solid-state transformer using this control method is a three-phase photovoltaic grid-connected inverter based on a cascaded H-bridge topology, consisting of phases A, B, and C. Each of phases A, B, and C contains n modules, and all modules in phases A, B, and C have identical structures, where n is a positive integer greater than 1. Each module in phases A, B, and C consists of a single-input, four-output three-level full-bridge LLC converter and four H-bridge converters. Each of the four output ports of the converter is connected to an H-bridge converter. The input port of each H-bridge converter is connected in parallel with a DC bus capacitor of the H-bridge converter. The output ports of the four H-bridge converters are connected in series to form a total AC output port. In addition, the total AC output ports of all modules in phases A, B, and C are connected in series. One end of each module is connected together to form a common point, and the other end is connected to the three-phase star-connected power grid through a filter inductor. The input ports of all modules in phases A, B, and C are connected in parallel to form a common DC bus, and a photovoltaic array is connected in parallel on the common DC bus.

[0012] The control method includes grid fault type determination and voltage sag depth detection, three-phase grid current control, active power return current suppression, and average value control of the DC bus capacitor voltage of the H-bridge converter. The steps are as follows:

[0013] Step 1: Determining the type of power grid fault and detecting voltage sag depth

[0014] Step 1.1: Sample the three-phase grid voltage to obtain the sampled value u of the three-phase grid voltage. gA ,u gB ,u gC ;

[0015] Step 1.2: Use a decoupled dual-synchronous coordinate system phase-locked loop to sample the three-phase grid voltage value u. gA ,u gB ,u gC Phase-locked loop (PLL) is performed to obtain the phase angle ωt and angular frequency ω of the grid voltage. The sampled values ​​u of the three-phase grid voltage are then converted using synchronous rotating coordinate transformation. gA ,u gB ,u gC Converted to positive-sequence active power component u of grid voltage in synchronous rotating coordinate system dP Positive sequence reactive power component of grid voltage u qP Negative sequence active power component of grid voltage u dN and the negative sequence reactive power component of the grid voltage u qN The calculation formulas are as follows:

[0016]

[0017]

[0018] In addition, the amplitude U of the positive sequence phase voltage of the power grid P and the amplitude U of the negative sequence phase voltage of the power grid N The calculation formulas are as follows:

[0019]

[0020] Step 1.3, based on the negative sequence active power component u of the grid voltage calculated in Step 1.2 dN Negative sequence reactive power component of grid voltage u qN The amplitude U of the positive sequence phase voltage of the power grid P The amplitude U of the negative sequence phase voltage of the power grid N and the rated value U of the phase voltage amplitude of the power grid g Determining the fault type in a three-phase power grid:

[0021] WhenU P +U N =U g andu dN When u > 0, if u qN If the value is not equal to 0, then a single-phase-to-ground drop fault occurs in the three-phase power grid; otherwise, other types of faults occur in the three-phase power grid.

[0022] WhenU P +U N =U g andu dN When u < 0, if u qN If the value is 0, then a single-phase-to-ground fault occurs in the three-phase power grid; otherwise, other types of faults occur in the three-phase power grid.

[0023] Step 1.4: When a single-phase-to-ground voltage drop fault occurs in the power grid, the ratio of the phase voltage amplitude after the voltage drop to the phase voltage amplitude before the voltage drop is denoted as the voltage drop ratio D. The formula for calculating the voltage drop ratio D is:

[0024] D = 3u dP / U g -2

[0025] Step 2, Three-phase power grid current control

[0026] Step 2.1: Sample the three-phase grid current to obtain the sampled value i of the three-phase grid current. gA i gB i gC ;

[0027] Step 2.2, the sampled values ​​i of the three-phase grid current obtained in Step 2.1 are transformed by synchronous rotation coordinate transformation. gA i gBi gC Converting to the positive-sequence active component i of the grid current in a rotating coordinate system dP Positive-sequence reactive power component of grid current i qP Negative-sequence active power component of grid current i dN and the negative sequence reactive component of the grid current i qN ;

[0028] Positive-sequence active component i of grid current dP and the positive-sequence reactive component of the grid current i qP The calculation formulas are as follows:

[0029]

[0030] Negative-sequence active component i of grid current dN and the negative sequence reactive component of the grid current i qN The calculation formulas are as follows:

[0031]

[0032] Step 2.3: Based on the sag ratio D obtained in Step 1.4, calculate the command value of the positive sequence reactive current. The formula is:

[0033]

[0034] In the formula, I N This represents the rated value of the three-phase power grid current amplitude, K1 represents the reactive current proportional coefficient, and min{0.4I N ,K1×(0.9-D)I N} represents 0.4I N With K1×(0.9-D)I N The minimum value;

[0035] Step 2.4: Sample the common DC bus voltage and the photovoltaic array output current to obtain the sampled value U of the common DC bus voltage. PVT And the sampled value I of the output current of the photovoltaic array PVT And calculate the actual output power P of the photovoltaic array. T The formula for its calculation is:

[0036] P T =U PVT I PVT

[0037] Step 2.5, based on the drop ratio D calculated in Step 1.4 and the total actual output power P of the photovoltaic array calculated in Step 2.4. T and the command value of the positive sequence reactive current calculated in step 2.3. Calculate the command value of the positive sequence active current. The formula is:

[0038]

[0039] In the formula, express and The minimum value, express The square root of;

[0040] Step 2.6: The positive-sequence active current regulator and the positive-sequence reactive current regulator are used to regulate the positive-sequence active component i of the grid current. dP and the positive-sequence reactive component of the grid current i qP The command values ​​for controlling the positive sequence active current are respectively set. Command value of positive sequence reactive current The output value Δu of the positive sequence active current regulator is obtained. dP The output value Δu of the positive sequence reactive current regulator qP The calculation formulas are as follows:

[0041]

[0042] Among them, K IPPD K is the proportional coefficient of the positive-sequence active current regulator. IIPD K is the integral coefficient of the positive-sequence active current regulator. IPPQ K is the proportional coefficient of the positive sequence reactive current regulator. IIPQ is the integral coefficient of the positive-sequence reactive current regulator, and s is the Laplace operator;

[0043] Step 2.7, Set the negative sequence active current command value and negative sequence reactive current command value The negative-sequence active component i of the grid current is respectively controlled by the negative-sequence active current regulator and the negative-sequence reactive current regulator. dN and the negative sequence reactive component of the grid current i qN Controlled by negative sequence active current command value and negative sequence reactive current command value The output value Δu of the negative sequence active current regulator is obtained. dN and the output value Δu of the negative sequence reactive current regulator qN The calculation formulas are as follows:

[0044]

[0045] Among them, K IPND K is the proportional coefficient of the negative sequence active current regulator. IIND K is the integral coefficient of the negative-sequence active current regulator.IPNQ K is the proportional coefficient of the negative sequence reactive current regulator. IINQ The integral coefficient of the negative sequence reactive current regulator;

[0046] Step 2.8, based on the positive-sequence active power component u of the grid voltage obtained in Step 1.2 dP and the positive sequence reactive power component of the grid voltage u qP And the output value Δu of the positive sequence active current regulator obtained in step 2.6. dP The output value Δu of the positive sequence reactive current regulator qP The positive sequence active voltage amplitude was calculated. and positive sequence reactive voltage amplitude The calculation formulas are as follows:

[0047]

[0048] Step 2.9, based on the negative sequence active power component u of the grid voltage obtained in Step 1.2 dN Negative sequence reactive power component of grid voltage u qN And the output value Δu of the negative sequence active current regulator obtained in step 2.7. dN and the output value Δu of the negative sequence reactive current regulator qN The negative sequence active voltage amplitude was calculated. and negative sequence reactive voltage amplitude The calculation formulas are as follows:

[0049]

[0050] Step 2.10, calculate the positive sequence active voltage amplitude obtained in Step 2.8. and positive sequence reactive voltage amplitude The positive sequence voltage component u in the two-phase stationary coordinate system is obtained by inverse transformation of the synchronous rotating coordinate system. αP ,u βP The negative sequence active voltage amplitude calculated in step 2.9 and negative sequence reactive voltage amplitude The negative sequence voltage component u in the two-phase stationary coordinate system is obtained by inverse transformation of the synchronous rotating coordinate system. αN ,u βN Their transformation formulas are as follows:

[0051]

[0052]

[0053] Step 2.11, based on the positive sequence voltage component u in the two-phase stationary coordinate system obtained in Step 2.10 αP ,u βPand the negative sequence voltage component u in the two-phase stationary coordinate system αN ,u βN The total voltage u in the two-phase stationary coordinate system is obtained. α ,u β The calculation formulas are as follows:

[0054]

[0055] Step 2.12, calculate the total voltage u in the two-phase stationary coordinate system obtained in step 2.11. α ,u β The voltage u in the three-phase coordinate system is obtained after coordinate transformation. cA ,u cB ,u cC Their transformation formulas are as follows:

[0056]

[0057] Step 3, Active power backflow suppression

[0058] Step 3.1, based on the positive-sequence active power component i of the grid current in the rotating coordinate system calculated in step 2.2. dP and the positive-sequence reactive power component i of the grid current qP Determine whether the positive-sequence active current provided by the three-phase photovoltaic grid-connected inverter meets the active power return constraint condition: If Record the operating state of the three-phase photovoltaic grid-connected inverter based on the cascaded H-bridge topology as state 1 and proceed to step 3.2; otherwise, record the operating state of the three-phase photovoltaic grid-connected inverter based on the cascaded H-bridge topology as state 2 and proceed to step 3.3.

[0059] Step 3.2: When the three-phase photovoltaic grid-connected inverter based on the cascaded H-bridge topology is in state 1, the three voltages u in the three-phase coordinate system calculated in step 2.12 are... cA ,u cB ,u cC The modulation voltage of the three-phase photovoltaic solid-state transformer was calculated. The calculation formulas are as follows:

[0060]

[0061] Step 3.3: When the three-phase photovoltaic grid-connected inverter based on the cascaded H-bridge topology is in state 2, the three voltages u in the three-phase coordinate system calculated in step 2.12 are... cA ,u cB ,u cC The modulation voltage of the three-phase photovoltaic solid-state transformer was calculated. The calculation formulas are as follows:

[0062]

[0063] In the formula, when u dN ≤0 and u qN When u = 0, β = π; when u = 0, β = π. dN >0 and u qN When u > 0, β = π / 3; when ... dN >0 and u qN When <0, β=-π / 3; arctan(i qP / i dP ) represents i qP / i dP The arctangent value;

[0064] Step 3.4: Calculate the modulation voltage of the three-phase photovoltaic solid-state transformer obtained in steps 3.2 and 3.3. Divide each voltage by the number of H-bridge converters in phases A, B, and C, 4n, to obtain the modulation voltage u of the phase A H-bridge converter. AH The modulation voltage u of the B-phase H-bridge converter BH The modulation voltage u of the C-phase H-bridge converter CH The calculation formulas are as follows:

[0065]

[0066] Step 3.5: Sample the DC bus capacitor voltage of all H-bridge converters in phases A, B, and C respectively, and obtain the following data: Sample value U of the DC bus capacitor voltage of the j-th H-bridge converter in the i-th module of phase A. HAij The sampled value U of the DC bus capacitor voltage of the j-th H-bridge converter in the i-th module of phase B. HBij The sampled value U of the DC bus capacitor voltage of the j-th H-bridge converter in the i-th module of phase C. HCij ,i=1,2,...,n,j=1,2,3,4;

[0067] Step 3.6: Calculate the modulation waves of all H-bridge converters in phases A, B, and C; specifically, let m be the modulation wave of the j-th H-bridge converter in the i-th module of phase A. Aij The modulation wave of the j-th H-bridge converter of the i-th module in phase B is m Bij The modulation wave of the j-th H-bridge converter of the i-th module in phase C is m. Cij If i = 1, 2, ..., n, j = 1, 2, 3, 4, then m Aij m Bij and m Cij The calculation formulas are as follows:

[0068]

[0069] Step 4: Average value control of DC bus capacitor voltage of H-bridge converter

[0070] Step 4.1, based on the sampled value U of the DC bus capacitor voltage of the j-th H-bridge converter of the i-th module of phase A obtained in step 3.5. HAij The sampled value U of the DC bus capacitor voltage of the j-th H-bridge converter in the i-th module of phase B. HBij The sampled value U of the DC bus capacitor voltage of the j-th H-bridge converter in the i-th module of phase C. HCij The average value U of the DC bus voltage of the four H-bridge converters in the i-th module of phase A is calculated. HAi The average value U of the DC bus voltage of the four H-bridge converters in the i-th module of phase B. HBi The average value U of the DC bus voltage of the four H-bridge converters in the i-th module of phase C. HCi The calculation formulas are as follows:

[0071]

[0072] Step 4.2, using the same LLC voltage controller, calculate the average DC bus voltage U of the four H-bridge converters in the i-th module of phase A obtained in step 4.1. HAi The average value U of the DC bus voltage of the four H-bridge converters in the i-th module of phase B. HBi The average value U of the DC bus voltage of the four H-bridge converters in the i-th module of phase C. HCi By performing control, the switching frequency f of the i-th single-input four-output three-level full-bridge LLC converter of phase A is obtained. DAi The switching frequency f of the i-th single-input four-output three-level full-bridge LLC converter of phase B. DBi The switching frequency f of the i-th single-input four-output three-level full-bridge LLC converter of phase C. DCi The calculation formulas are as follows:

[0073]

[0074] In the formula, N T K is the turns ratio of the primary to secondary side of the high-frequency transformer in a single-input, four-output three-level full-bridge LLC converter. DP K is the proportional gain of the LLC voltage controller. DI The integral coefficient of the LLC voltage controller.

[0075] The advantages of this invention over the prior art are:

[0076] (1) When a single-phase ground fault occurs in the power grid, different control methods can be adopted under different operating conditions to reduce the amplitude of the three-phase modulation voltage, so that the three-phase cascaded H-bridge photovoltaic solid-state transformer can effectively avoid active power backflow throughout the entire operating range.

[0077] (2) When a single-phase ground fault occurs in the power grid, it can improve the adaptability of the three-phase cascaded H-bridge photovoltaic solid-state transformer to different output power and different power grid drop depths, and improve the low voltage ride-through capability of the system. Attached Figure Description

[0078] Figure 1 This is the main circuit topology of the cascaded photovoltaic solid-state transformer implemented in this invention.

[0079] Figure 2 This is a circuit diagram of the first module of phase A in the cascaded photovoltaic solid-state transformer of this invention.

[0080] Figure 3 This is a block diagram of the photovoltaic solid-state transformer control method under single-phase-to-ground slip fault conditions in the power grid, as implemented in this invention.

[0081] Figure 4 This is a flowchart of the photovoltaic solid-state transformer control method under single-phase ground slip fault conditions in the power grid, as implemented in this invention.

[0082] Figure 5 The present invention describes a three-phase grid voltage sampling value u under the following conditions: a phase-to-ground fault (A-phase), a rated phase voltage amplitude of 100V, and a phase voltage amplitude after the voltage drop being equal to the phase voltage amplitude before the voltage drop (D-phase drop ratio) of 0.5. gA ,u gB ,u gC A waveform diagram.

[0083] Figure 6 This is a diagram illustrating the working state division of the system implemented in this invention.

[0084] Figure 7 This is a schematic diagram of the output waveform of the carrier phase-shifting sinusoidal pulse width modulation strategy implemented in this invention, taking phase A as an example, which includes a module.

[0085] Figure 8 This is a schematic diagram of the switching device drive waveform of the LLC converter in the first module of phase A when the frequency conversion modulation strategy of the three-level full-bridge LLC converter implemented in this invention is adopted. Detailed Implementation

[0086] To make the objectives, technical solutions, and advantages of this invention clearer, the invention will be further described clearly and completely below in conjunction with the accompanying drawings and embodiments.

[0087] Figure 1 This invention describes the main circuit topology of a cascaded photovoltaic solid-state transformer. This cascaded photovoltaic solid-state transformer is a three-phase photovoltaic grid-connected inverter based on a cascaded H-bridge topology, consisting of phases A, B, and C. Each of phases A, B, and C contains n modules, and all modules in phases A, B, and C have identical structures, where n is a positive integer greater than 1. Each module in phases A, B, and C consists of a single-input, four-output three-level full-bridge LLC converter and four H-bridge converters. Each output port is connected to an H-bridge converter, and the input port of each H-bridge converter is connected in parallel with a DC bus capacitor. The output ports of the four H-bridge converters are connected in series to form a total AC output port. Furthermore, the total AC output ports of all modules in phases A, B, and C are connected in series, with one end connected together to form a common point N1, and the other end connected to the three-phase star-connected power grid through filter inductors. The input ports of all modules in phases A, B, and C are connected in parallel to form a common DC bus, and a photovoltaic array is connected in parallel on the common DC bus. Figure 1 in, u gA u gB and u gC i represents the sampled value of the three-phase power grid voltage. gA i gB and i gC This represents the sampled value of the three-phase grid current, which is also the output current of the cascaded photovoltaic solid-state transformer, L. f Indicates the filter inductance; C Xij U represents the DC bus capacitance of the j-th H-bridge converter in the i-th module of phase X. HXij This represents the sampled value of the DC bus capacitor voltage of the j-th H-bridge converter in the i-th module of phase A, where X = A, B, C, i = 1, 2, ..., n, j = 1, 2, 3, 4; U PVT I represents the sampled value of the common DC bus voltage. PVT Sampled value of the output current of the photovoltaic array.

[0088] Figure 2 This is the circuit diagram of the first module of phase A in the cascaded photovoltaic solid-state transformer of this invention. It consists of a single-input, four-output three-level full-bridge LLC converter and four H-bridge converters. The main switch Q... A11 ~Q A14 (Including anti-parallel diodes), voltage divider capacitor C dA11 and C dA12 Freewheeling diode D A11 and D A12 and flying capacitor C SA11The left bridge arm of a three-level full-bridge LLC converter with a single input and four outputs; Q A15 ~Q A18 (Including anti-parallel diodes), voltage divider capacitor C dA11 and C dA12 Freewheeling diode D A13 and D A14 and flying capacitor C SA12 The right bridge arm of a three-level full-bridge LLC converter with a single input and four outputs. rA1 C rA1 and L mA1 These represent the resonant inductance, resonant capacitance, and magnetizing inductance, respectively; T rA1 This represents a high-frequency transformer where all four secondary windings have the same number of turns, and the number of turns in the primary winding is N times the number of turns in the secondary winding. T times, ; D RA1-11 ~D RA1-14 D RA1-21 ~D RA1-24 D RA1-31 ~D RA1-34 and D RA1-41 ~D RA1-44 Indicates the output rectifier diode; the four H converters are each controlled by a fully controlled switching device T. A1-11 ~T A1-14 T A1-21 ~T A1-24 T A1-31 ~T A1-34 and T A1-41 ~T A1-44 Composed of (including anti-parallel diodes), C A11 C A12 C A13 and C A14 These represent the DC bus capacitors of the four H-bridge converters.

[0089] Figure 3 This is a block diagram of the photovoltaic solid-state transformer control method under single-phase-to-ground slip fault conditions in the power grid, as implemented in this invention. It mainly includes: using a decoupled dual-synchronous coordinate system phase-locked loop to sample the three-phase grid voltage value u. gA u gB and u gC Perform phase-locked loop and calculate the positive sequence voltage amplitude U of the power grid. P and the magnitude of the negative sequence voltage of the power grid U N 1. Determine the type of power grid fault and calculate the ratio of the phase voltage amplitude after the voltage drop to the phase voltage amplitude before the voltage drop (D). 2. For the power grid current i... gA i gB and i gCPerform synchronous rotating coordinate transformation (abc / dq transformation, i.e., transformation from the natural coordinate system to the synchronous rotating coordinate system), calculate the positive sequence active current command value and the positive sequence reactive current command value, control the grid current, and obtain the three voltages u in the three-phase coordinate system. cA u cB and u cC The system operating states are divided and the modulation voltage of the three-phase photovoltaic solid-state transformer is calculated. and To achieve active power backflow suppression and calculate the modulation wave m of all three-phase H-bridge converters. Aij m Bij and m Cij (i=1,2,…,n,j=1,2,3,4) and obtain the switching drive signals of all H-bridge converters and the average value control of the DC bus capacitor voltage of the H-bridge converter according to the carrier phase-shifted sinusoidal pulse width modulation strategy. The drive signals of all fully controlled switching devices in the three-level full-bridge LLC converter with single input and four output are obtained through frequency conversion modulation.

[0090] Figure 4 This is a flowchart of the photovoltaic solid-state transformer control method under single-phase-to-ground voltage drop fault conditions in the power grid, which includes: power grid fault type judgment and voltage drop depth detection, three-phase power grid current control, active power return current suppression, and average value control of DC bus capacitor voltage of H-bridge converter.

[0091] See Figure 1 , Figure 2 , Figure 3 and Figure 4 The implementation process of this invention is as follows:

[0092] Step 1: Determining the type of power grid fault and detecting voltage sag depth

[0093] Step 1.1: Sample the three-phase grid voltage to obtain the sampled value u of the three-phase grid voltage. gA ,u gB ,u gC ;

[0094] Step 1.2: Use a decoupled dual-synchronous coordinate system phase-locked loop to sample the three-phase grid voltage value u. gA ,u gB ,u gC Phase-locked loop (PLL) is performed to obtain the phase angle ωt and angular frequency ω of the grid voltage. The sampled values ​​u of the three-phase grid voltage are then converted using synchronous rotating coordinate transformation. gA ,u gB ,u gC Converted to positive-sequence active power component u of grid voltage in synchronous rotating coordinate system dP Positive sequence reactive power component of grid voltage u qPNegative sequence active power component of grid voltage u dN and the negative sequence reactive power component of the grid voltage u qN The calculation formulas are as follows:

[0095]

[0096]

[0097] In addition, the amplitude U of the positive sequence phase voltage of the power grid P and the amplitude U of the negative sequence phase voltage of the power grid N The calculation formulas are as follows:

[0098]

[0099] Step 1.3, based on the negative sequence active power component u of the grid voltage calculated in Step 1.2 dN Negative sequence reactive power component of grid voltage u qN The amplitude U of the positive sequence phase voltage of the power grid P The amplitude U of the negative sequence phase voltage of the power grid N and the rated value U of the phase voltage amplitude of the power grid g Determining the fault type in a three-phase power grid:

[0100] WhenU P +U N =U g andu dN When u > 0, if u qN If the value is not equal to 0, then a single-phase-to-ground drop fault occurs in the three-phase power grid; otherwise, other types of faults occur in the three-phase power grid.

[0101] WhenU P +U N =U g andu dN When u < 0, if u qN If the value is 0, then a single-phase-to-ground fault occurs in the three-phase power grid; otherwise, other types of faults occur in the three-phase power grid.

[0102] Step 1.4: When a single-phase-to-ground voltage drop fault occurs in the power grid, the ratio of the phase voltage amplitude after the voltage drop to the phase voltage amplitude before the voltage drop is denoted as the voltage drop ratio D. The formula for calculating the voltage drop ratio D is:

[0103] D = 3u dP / U g -2

[0104] Figure 5 The present invention describes a three-phase grid voltage sampling value u under the following conditions: a phase-to-ground fault (A-phase), a rated phase voltage amplitude of 100V, and a phase voltage amplitude after the voltage drop being equal to the phase voltage amplitude before the voltage drop (D-phase drop ratio) of 0.5. gA ,ugB ,u gC A waveform diagram.

[0105] Step 2, Three-phase power grid current control

[0106] Step 2.1: Sample the three-phase grid current to obtain the sampled value i of the three-phase grid current. gA i gB i gC ;

[0107] Step 2.2, the sampled values ​​i of the three-phase grid current obtained in Step 2.1 are transformed by synchronous rotation coordinate transformation. gA i gB i gC Converting to the positive-sequence active component i of the grid current in a rotating coordinate system dP Positive-sequence reactive power component of grid current i qP Negative-sequence active power component of grid current i dN and the negative sequence reactive component of the grid current i qN ;

[0108] Positive-sequence active component i of grid current dP and the positive-sequence reactive component of the grid current i qP The calculation formulas are as follows:

[0109]

[0110] Negative-sequence active component i of grid current dN and the negative sequence reactive component of the grid current i qN The calculation formulas are as follows:

[0111]

[0112] Step 2.3: Based on the sag ratio D obtained in Step 1.4, calculate the command value of the positive sequence reactive current. The formula is:

[0113]

[0114] In the formula, I N This represents the rated value of the three-phase power grid current amplitude, K1 represents the reactive current proportional coefficient, and min{0.4I N ,K1×(0.9-D)I N} represents 0.4I N With K1×(0.9-D)I N The minimum value.

[0115] In this embodiment, K1 = 2. Since 2013, China has implemented a new version of the "Technical Regulations for Photovoltaic Power Stations Connected to the Power System," which requires large and medium-sized photovoltaic power stations to possess a certain low-voltage ride-through capability. Furthermore, it sets a strict limit on this low-voltage ride-through capability, specifying that the dynamic reactive current that the inverter must inject into the grid during a grid fault is K1 × (0.9 - D)I. N In particular, when an asymmetrical fault occurs in a three-phase power grid, the maximum value of the dynamic positive-sequence reactive current should not exceed 0.4I. N Considering that a single-phase-to-ground slip fault in the power grid is an asymmetrical fault, the command value of the positive-sequence reactive current is... It should be 0.4I. N With K1×(0.9-D)I N The minimum value.

[0116] Step 2.4: Sample the common DC bus voltage and the photovoltaic array output current to obtain the sampled value U of the common DC bus voltage. PVT And the sampled value I of the output current of the photovoltaic array PVT And calculate the actual output power P of the photovoltaic array. T The formula for its calculation is:

[0117] P T =U PVT I PVT

[0118] Step 2.5, based on the drop ratio D calculated in Step 1.4 and the total actual output power P of the photovoltaic array calculated in Step 2.4. T and the command value of the positive sequence reactive current calculated in step 2.3. Calculate the command value of the positive sequence active current. The formula is:

[0119]

[0120] In the formula, express and The minimum value, express The square root of.

[0121] Step 2.6: The positive-sequence active current regulator and the positive-sequence reactive current regulator are used to regulate the positive-sequence active component i of the grid current. dP and the positive-sequence reactive component of the grid current i qP The command values ​​for controlling the positive sequence active current are respectively set. Command value of positive sequence reactive current The output value Δu of the positive sequence active current regulator is obtained. dPThe output value Δu of the positive sequence reactive current regulator qP The calculation formulas are as follows:

[0122]

[0123] Among them, K IPPD K is the proportional coefficient of the positive-sequence active current regulator. IIPD K is the integral coefficient of the positive-sequence active current regulator. IPPQ K is the proportional coefficient of the positive sequence reactive current regulator. IIPQ is the integral coefficient of the positive-sequence reactive current regulator, and s is the Laplace operator.

[0124] In this embodiment, K IPPD =K IPPQ =2,K IIPD =K IIPQ =250.

[0125] Step 2.7, Set the negative sequence active current command value and negative sequence reactive current command value The negative-sequence active component i of the grid current is respectively controlled by the negative-sequence active current regulator and the negative-sequence reactive current regulator. dN and the negative sequence reactive component of the grid current i qN Controlled by negative sequence active current command value and negative sequence reactive current command value The output value Δu of the negative sequence active current regulator is obtained. dN and the output value Δu of the negative sequence reactive current regulator qN The calculation formulas are as follows:

[0126]

[0127] Among them, K IPND K is the proportional coefficient of the negative sequence active current regulator. IIND K is the integral coefficient of the negative-sequence active current regulator. IPNQ K is the proportional coefficient of the negative sequence reactive current regulator. IINQ This is the integral coefficient of the negative sequence reactive current regulator.

[0128] In this embodiment, K IPND =K IPNQ =2,K IIND =K IINQ =250.

[0129] Step 2.8, based on the positive-sequence active power component u of the grid voltage obtained in Step 1.2 dP and the positive sequence reactive power component of the grid voltage u qPAnd the output value Δu of the positive sequence active current regulator obtained in step 2.6. dP The output value Δu of the positive sequence reactive current regulator qP The positive sequence active voltage amplitude was calculated. and positive sequence reactive voltage amplitude The calculation formulas are as follows:

[0130]

[0131] Step 2.9, based on the negative sequence active power component u of the grid voltage obtained in Step 1.2 dN Negative sequence reactive power component of grid voltage u qN And the output value Δu of the negative sequence active current regulator obtained in step 2.7. dN and the output value Δu of the negative sequence reactive current regulator qN The negative sequence active voltage amplitude was calculated. and negative sequence reactive voltage amplitude The calculation formulas are as follows:

[0132]

[0133] Step 2.10, calculate the positive sequence active voltage amplitude obtained in Step 2.8. and positive sequence reactive voltage amplitude The positive sequence voltage component u in the two-phase stationary coordinate system is obtained by inverse transformation of the synchronous rotating coordinate system. αP ,u βP The negative sequence active voltage amplitude calculated in step 2.9 and negative sequence reactive voltage amplitude The negative sequence voltage component u in the two-phase stationary coordinate system is obtained by inverse transformation of the synchronous rotating coordinate system. αN ,u βN Their transformation formulas are as follows:

[0134]

[0135]

[0136] Step 2.11, based on the positive sequence voltage component u in the two-phase stationary coordinate system obtained in Step 2.10 αP ,u βP and the negative sequence voltage component u in the two-phase stationary coordinate system αN ,u βN The total voltage u in the two-phase stationary coordinate system is obtained. α ,u β The calculation formulas are as follows:

[0137]

[0138] Step 2.12, calculate the total voltage u in the two-phase stationary coordinate system obtained in step 2.11. α ,u β The voltage u in the three-phase coordinate system is obtained after coordinate transformation. cA ,u cB ,u cC Their transformation formulas are as follows:

[0139]

[0140] Step 3, Active power backflow suppression

[0141] Step 3.1, based on the positive-sequence active power component i of the grid current in the rotating coordinate system calculated in step 2.2. dP and the positive-sequence reactive power component i of the grid current qP Determine whether the positive-sequence active current provided by the three-phase photovoltaic grid-connected inverter meets the active power return constraint condition: If Record the operating state of the three-phase photovoltaic grid-connected inverter based on the cascaded H-bridge topology as state 1 and proceed to step 3.2; otherwise, record the operating state of the three-phase photovoltaic grid-connected inverter based on the cascaded H-bridge topology as state 2 and proceed to step 3.3.

[0142] Figure 6 This is a diagram illustrating the working state division of the system implemented in this invention, based on i dP and i qP The system's operating states are divided based on the values ​​of the input voltage, and then the modulation voltage of the three-phase photovoltaic solid-state transformer is calculated under different operating states. and Specifically, when the three-phase photovoltaic grid-connected inverter based on the cascaded H-bridge topology is operating in state 1, the positive-sequence active current provided by the system can meet the constraint condition of active power return, and no zero-sequence voltage compensation is required; when the three-phase photovoltaic grid-connected inverter based on the cascaded H-bridge topology is operating in state 2, appropriate zero-sequence voltage compensation is required to suppress active power return. For example... Figure 6 As shown, the region occupied by state 2 is relatively small, and the amplitude of the three-phase modulation voltage does not increase significantly after compensating for the zero-sequence voltage. Therefore, this method can avoid overmodulation and effectively suppress active power backflow.

[0143] Step 3.2: When the three-phase photovoltaic grid-connected inverter based on the cascaded H-bridge topology is in state 1, the three voltages u in the three-phase coordinate system calculated in step 2.12 are... cA ,u cB ,u cC The modulation voltage of the three-phase photovoltaic solid-state transformer was calculated. The calculation formulas are as follows:

[0144]

[0145] Step 3.3: When the three-phase photovoltaic grid-connected inverter based on the cascaded H-bridge topology is in state 2, the three voltages u in the three-phase coordinate system calculated in step 2.12 are... cA ,u cB ,u cC The modulation voltage of the three-phase photovoltaic solid-state transformer was calculated. The calculation formulas are as follows:

[0146]

[0147] In the formula, when u dN ≤0 and u qN When u = 0, β = π; when u = 0, β = π. dN >0 and u qN When u > 0, β = π / 3; when ... dN >0 and u qN When <0, β=-π / 3; arctan(i qP / i dP ) represents i qP / i dP The arctangent value;

[0148] Step 3.4: Calculate the modulation voltage of the three-phase photovoltaic solid-state transformer obtained in steps 3.2 and 3.3. Divide each voltage by the number of H-bridge converters in phases A, B, and C, 4n, to obtain the modulation voltage u of the phase A H-bridge converter. AH The modulation voltage u of the B-phase H-bridge converter BH The modulation voltage u of the C-phase H-bridge converter CH The calculation formulas are as follows:

[0149]

[0150] Step 3.5: Sample the DC bus capacitor voltage of all H-bridge converters in phases A, B, and C respectively, and obtain the following data: Sample value U of the DC bus capacitor voltage of the j-th H-bridge converter in the i-th module of phase A. HAij The sampled value U of the DC bus capacitor voltage of the j-th H-bridge converter in the i-th module of phase B. HBij The sampled value U of the DC bus capacitor voltage of the j-th H-bridge converter in the i-th module of phase C. HCij ,i=1,2,...,n,j=1,2,3,4;

[0151] Step 3.6: Calculate the modulation waves of all H-bridge converters in phases A, B, and C; specifically, let m be the modulation wave of the j-th H-bridge converter in the i-th module of phase A.Aij The modulation wave of the j-th H-bridge converter of the i-th module in phase B is m Bij The modulation wave of the j-th H-bridge converter of the i-th module in phase C is m. Cij If i = 1, 2, ..., n, j = 1, 2, 3, 4, then m Aij m Bij and m Cij The calculation formulas are as follows:

[0152]

[0153] After calculating the modulation waves of all H-bridge converters, the switching drive signals of all H-bridge converters can be obtained using a carrier phase-shifted sinusoidal pulse width modulation (CPWM) strategy. The aforementioned carrier phase-shifted sinusoidal pulse width modulation strategy refers to the commonly used and mature technology in cascaded H-bridge converters. Many documents describe carrier phase-shifted sinusoidal pulse width modulation in detail, such as pages 84-88 of the monograph "Principles and Applications of High-Performance Cascaded Multilevel Converters" published by Zhou Jinghua and Chen Ya'ai in 2013 by Machinery Industry Press. Figure 7 Taking phase A as an example (a single-input, four-output, three-level full-bridge LLC converter and four H-bridge converters), the output waveform diagram of the carrier phase-shifting sinusoidal pulse width modulation strategy implemented in this invention is shown in the figure. A11 m A12 m A13 and m A14 These represent the modulation waves of the 1st, 2nd, 3rd, and 4th H-bridge converters in the first module of phase A, respectively. c1 u c2 u c3 and u c4 These represent the carriers of the 1st, 2nd, 3rd, and 4th H-bridge converters in phase A, respectively. HO1 u HO2 u HO3 and u HO4 These represent the AC output voltages of the 1st, 2nd, 3rd, and 4th H-bridge converters in phase A, respectively. HAT This represents the total output voltage on the AC side of phase A converter. As can be seen from the diagram, u... c2 The phase angle compared to u c1 Lag π / 4, u c3 The phase angle compared to u c2 Lag π / 4, u c4 The phase angle compared to u c3 A hysteresis of π / 4 means there is a phase shift between carrier waves. HO1 u HO2u HO3 and u HO4 Both are three-level waveforms, while u HAT It is a nine-level stepped wave. According to the carrier phase-shifted sinusoidal pulse width modulation strategy, for a converter with N H-bridge modules, the phase difference between the carriers of each module is π / N. Figure 7 This section uses four H-bridge modules as an example to introduce carrier phase-shifting sinusoidal pulse width modulation, so the phase difference between carriers is π / 4.

[0154] Step 4: Average value control of DC bus capacitor voltage of H-bridge converter

[0155] Step 4.1, based on the sampled value U of the DC bus capacitor voltage of the j-th H-bridge converter of the i-th module of phase A obtained in step 3.5. HAij The sampled value U of the DC bus capacitor voltage of the j-th H-bridge converter in the i-th module of phase B. HBij The sampled value U of the DC bus capacitor voltage of the j-th H-bridge converter in the i-th module of phase C. HCij The average value U of the DC bus voltage of the four H-bridge converters in the i-th module of phase A is calculated. HAi The average value U of the DC bus voltage of the four H-bridge converters in the i-th module of phase B. HBi The average value U of the DC bus voltage of the four H-bridge converters in the i-th module of phase C. HCi The calculation formulas are as follows:

[0156]

[0157] Step 4.2, using the same LLC voltage controller, calculate the average DC bus voltage U of the four H-bridge converters in the i-th module of phase A obtained in step 4.1. HAi The average value U of the DC bus voltage of the four H-bridge converters in the i-th module of phase B. HBi The average value U of the DC bus voltage of the four H-bridge converters in the i-th module of phase C. HCi By performing control, the switching frequency f of the i-th single-input four-output three-level full-bridge LLC converter of phase A is obtained. DAi The switching frequency f of the i-th single-input four-output three-level full-bridge LLC converter of phase B. DBi The switching frequency f of the i-th single-input four-output three-level full-bridge LLC converter of phase C. DCi The calculation formulas are as follows:

[0158]

[0159] In the formula, N TK is the turns ratio of the primary to secondary side of the high-frequency transformer in a single-input, four-output three-level full-bridge LLC converter. DP K is the proportional gain of the LLC voltage controller. DI The integral coefficient of the LLC voltage controller.

[0160] In this embodiment, K DP =50, K DI =10000.

[0161] Calculate the switching frequency f of the i-th single-input four-output three-level full-bridge LLC converter in phase A. DAi The switching frequency f of the i-th single-input four-output three-level full-bridge LLC converter of phase B. DBi The switching frequency f of the i-th single-input four-output three-level full-bridge LLC converter of phase C. DCi Subsequently, variable frequency modulation (VFM) of a three-level full-bridge LLC converter is used to generate the switching drive signal for the single-input, four-output three-level full-bridge LLC converter. Many documents have described in detail the VFM strategy of three-level full-bridge LLC converters, such as W. Chen, Y. Gu, and Z. Lu, “A novel three-level full bridge resonant DC-DC converter suitable for high power wide range input applications,” in APEC 07-Twenty-Second Annual IEEE Applied Power Electronics Conference and Exposition, Anaheim, CA, USA, Feb. 25-Mar. 1, 2007. Figure 8 This is a schematic diagram of the switching device drive waveform of the LLC converter in the first module of phase A when using the frequency conversion modulation strategy of the three-level full-bridge LLC converter implemented in this invention. It can be seen that in each switching cycle f... DA1 Internal and external switching transistor Q A11 and Q A18 Compared to the internal switching transistor Q A12 and Q A17 T opened later ON Time, turn off T early OFF Time; External switch QA14 and Q A15 Compared to the internal switching transistor Q A13 and Q A16 T opened later ON Time, turn off T early OFF time.

Claims

1. A control method for a photovoltaic solid-state transformer under single-phase-to-ground slip-out fault conditions in a power grid. The photovoltaic solid-state transformer using this control method is a three-phase photovoltaic grid-connected inverter based on a cascaded H-bridge topology, consisting of phase A, phase B, and phase C; phases A, B, and C each contain... There are 10 modules, and the structures of all modules in phases A, B, and C are completely identical. The integer is a positive integer greater than 1. Each module in phases A, B, and C consists of a single-input, four-output three-level full-bridge LLC converter and four H-bridge converters. The four output ports of the single-input, four-output three-level full-bridge LLC converter are each connected to an H-bridge converter. The input port of each H-bridge converter is connected in parallel with a DC bus capacitor. The output ports of the four H-bridge converters are connected in series to form a total AC output port. In addition, the total AC output ports of all modules in phases A, B, and C are connected in series, with one end connected together to form a common point, and the other end connected to the three-phase star-connected power grid through filter inductors. The input ports of all modules in phases A, B, and C are connected in parallel to form a common DC bus, and a photovoltaic array is connected in parallel on the common DC bus. Its features are, The control method includes grid fault type determination and voltage sag depth detection, three-phase grid current control, active power return current suppression, and average value control of the DC bus capacitor voltage of the H-bridge converter. The steps are as follows: Step 1: Determining the type of power grid fault and detecting the depth of voltage sag. Step 1.1: Sample the three-phase grid voltage to obtain the sampled values ​​of the three-phase grid voltage. , , ; Step 1.2: Use a decoupled dual-synchronous coordinate system phase-locked loop to sample the three-phase grid voltage values. , , Phase-locked loop (PLL) is performed to obtain the phase angle of the grid voltage. angular frequency The sampled values ​​of the three-phase grid voltage are then transformed using synchronous rotating coordinate transformation. , , Converted to positive-sequence active power components of grid voltage in a synchronous rotating coordinate system Positive sequence reactive power components of grid voltage Negative sequence active power component of grid voltage and the negative sequence reactive power component of the grid voltage The calculation formulas are as follows: In addition, the amplitude of the positive-sequence phase voltage of the power grid and the amplitude of the negative sequence phase voltage of the power grid The calculation formulas are as follows: Step 1.3, based on the negative sequence active power component of the grid voltage calculated in Step 1.

2. Negative sequence reactive power components of grid voltage The amplitude of the positive sequence phase voltage of the power grid Amplitude of negative sequence phase voltage of the power grid and the rated value of the phase voltage amplitude of the power grid Determining the fault type in a three-phase power grid: when and At that time, if If this occurs, a single-phase-to-ground slip fault will occur in the three-phase power grid. when and At that time, if If this occurs, a single-phase-to-ground slip fault will occur in the three-phase power grid. Step 1.4: When a single-phase-to-ground slip fault occurs in the power grid, the ratio of the phase voltage amplitude after the slip to the phase voltage amplitude before the slip is recorded as the slip ratio. D， drop ratio D The formula for calculation is: Step 2, Three-phase power grid current control Step 2.1: Sample the three-phase grid current to obtain the sampled values ​​of the three-phase grid current. , , ; Step 2.2: The sampled values ​​of the three-phase grid current obtained in Step 2.1 are transformed by synchronous rotation coordinate transformation. , , Converting to positive-sequence active components of grid current in a rotating coordinate system Positive-sequence reactive power component of grid current Negative-sequence active power component of grid current and the negative sequence reactive component of the grid current ; Positive-sequence active component of grid current and the positive-sequence reactive component of the grid current The calculation formulas are as follows: Negative sequence active component of grid current and the negative sequence reactive component of the grid current The calculation formulas are as follows: Step 2.3, based on the drop ratio calculated in Step 1.4 D Calculate the command value of the positive sequence reactive current. The formula for its calculation is: In the formula, This indicates the rated value of the three-phase power grid current amplitude. This represents the reactive current proportionality coefficient. express and The minimum value; Step 2.4: Sample the common DC bus voltage and the photovoltaic array output current to obtain the sampled value of the common DC bus voltage. and the sampled value of the output current of the photovoltaic array And calculate the total power actually output by the photovoltaic array. The formula for its calculation is: Step 2.5, based on the drop ratio calculated in Step 1.4 D Step 2.4 Calculate the actual total output power of the photovoltaic array and the command value of the positive sequence reactive current calculated in step 2.

3. Calculate the command value of the positive sequence active current. The formula for its calculation is: In the formula, express and The minimum value, express The square root of; Step 2.6: The positive-sequence active current component of the grid current is controlled by both the positive-sequence active current regulator and the positive-sequence reactive current regulator. and the positive-sequence reactive component of the grid current The command values ​​for controlling the positive sequence active current are respectively set. Command value of positive sequence reactive current The output value of the positive sequence active current regulator is obtained. and the output value of the positive sequence reactive current regulator The calculation formulas are as follows: in, This is the proportional coefficient of the positive sequence active current regulator. This is the integral coefficient of the positive-sequence active current regulator. This is the proportional coefficient of the positive sequence reactive current regulator. is the integral coefficient of the positive-sequence reactive current regulator, and s is the Laplace operator; Step 2.7, Set the negative sequence active current command value and negative sequence reactive current command value The negative-sequence active component of the grid current is controlled by the negative-sequence active current regulator and the negative-sequence reactive current regulator, respectively. and the negative sequence reactive component of the grid current Controlled to negative sequence active current command value and negative sequence reactive current command value The output value of the negative sequence active current regulator is obtained. and the output value of the negative sequence reactive current regulator The calculation formulas are as follows: in, This is the proportional coefficient for the negative-sequence active current regulator. The integral coefficient of the negative-sequence active current regulator. This is the proportional coefficient of the negative sequence reactive current regulator. This is the integral coefficient of the negative-sequence reactive current regulator; Step 2.8, based on the positive-sequence active power component of the grid voltage obtained in Step 1.2 and the positive sequence reactive power component of the grid voltage And the output value of the positive sequence active current regulator obtained in step 2.

6. and the output value of the positive sequence reactive current regulator The positive sequence active voltage amplitude was calculated. and positive sequence reactive voltage amplitude The calculation formulas are as follows: Step 2.9, based on the negative sequence active power component of the grid voltage obtained in Step 1.2 Negative sequence reactive power components of grid voltage And the output value of the negative sequence active current regulator obtained in step 2.

7. and the output value of the negative sequence reactive current regulator The negative sequence active voltage amplitude was calculated. and negative sequence reactive voltage amplitude The calculation formulas are as follows: Step 2.10, calculate the positive sequence active voltage amplitude obtained in Step 2.

8. and positive sequence reactive voltage amplitude The positive sequence voltage components in the two-phase stationary coordinate system are obtained by inverse transformation of the synchronous rotating coordinate system. , The negative sequence active voltage amplitude calculated in step 2.9 and negative sequence reactive voltage amplitude The negative sequence voltage components in the two-phase stationary coordinate system are obtained by inverse transformation of the synchronous rotating coordinate system. , Their conversion formulas are as follows: Step 2.11, based on the positive sequence voltage components in the two-phase stationary coordinate system obtained in Step 2.

10. , and the negative sequence voltage component in the two-phase stationary coordinate system , The total voltage in the two-phase stationary coordinate system is obtained. , The calculation formulas are as follows: Step 2.12, calculate the total voltage in the two-phase stationary coordinate system obtained in step 2.

11. , The voltage in the three-phase coordinate system is obtained after coordinate transformation. , , Their conversion formulas are as follows: Step 3, Active power backflow suppression Step 3.1: Based on the positive-sequence active power components of the grid current in the rotating coordinate system calculated in Step 2.

2. and the positive-sequence reactive component of the grid current Determine whether the positive-sequence active current provided by the three-phase photovoltaic grid-connected inverter meets the active power return constraint condition: If If the operating state of the three-phase photovoltaic grid-connected inverter based on the cascaded H-bridge topology is recorded as state 1, proceed to step 3.2; otherwise, if the operating state of the three-phase photovoltaic grid-connected inverter based on the cascaded H-bridge topology is recorded as state 2, proceed to step 3.

3. Step 3.2: When the three-phase photovoltaic grid-connected inverter based on the cascaded H-bridge topology is in state 1, calculate the three voltages in the three-phase coordinate system according to step 2.

12. , , The modulation voltage of the three-phase photovoltaic solid-state transformer was calculated. , , The calculation formulas are as follows: Step 3.3: When the three-phase photovoltaic grid-connected inverter based on the cascaded H-bridge topology is in state 2, calculate the three voltages in the three-phase coordinate system according to step 2.

12. , , The modulation voltage of the three-phase photovoltaic solid-state transformer was calculated. , , The calculation formulas are as follows: In the formula, when u dN ≤0 and hour, ;when and hour, ;when and hour, ; express The arctangent value; Step 3.4: Calculate the modulation voltage of the three-phase photovoltaic solid-state transformer obtained in steps 3.2 and 3.

3. , , Divide by the number of H-bridge converters in phases A, B, and C respectively. The modulation voltage of the A-phase H-bridge converter is obtained. The modulation voltage of the B-phase H-bridge converter Modulation voltage of C-phase H-bridge converter The calculation formulas are as follows: Step 3.5: Sample the DC bus capacitor voltage of all H-bridge converters in phases A, B, and C respectively, and obtain the following data: Phase A's... i The first module j Sampled values ​​of DC bus capacitor voltage of H-bridge converter Phase B i The first module j Sampled values ​​of DC bus capacitor voltage of H-bridge converter ; Phase C i The first module j Sampled values ​​of DC bus capacitor voltage of H-bridge converter , , ; Step 3.6: Calculate the modulation waves of all H-bridge converters in phases A, B, and C; specifically, denote the modulation wave of phase A... i The first module j The modulation wave of each H-bridge converter is Phase B i The first module j The modulation wave of each H-bridge converter is Phase C i The first module j The modulation wave of each H-bridge converter is , , ,but , and The calculation formulas are as follows: Step 4: Average value control of DC bus capacitor voltage of H-bridge converter Step 4.1, based on the A phase obtained in step 3.5... i The first module j Sampled values ​​of DC bus capacitor voltage of H-bridge converter Phase B i The first module j Sampled values ​​of DC bus capacitor voltage of H-bridge converter Phase C i The first module j Sampled values ​​of DC bus capacitor voltage of H-bridge converter The calculation yields the first phase of phase A. i The average DC bus voltage of the four H-bridge converters in each module Phase B i The average DC bus voltage of the four H-bridge converters in each module Phase C i The average DC bus voltage of the four H-bridge converters in each module The calculation formulas are as follows: Step 4.2, using the same LLC voltage controller, respectively apply the voltage to phase A obtained in step 4.

1. i The average DC bus voltage of the four H-bridge converters in each module Phase B i The average DC bus voltage of the four H-bridge converters in each module and the first phase of C i The average DC bus voltage of the four H-bridge converters in each module Control is performed to obtain the first phase of phase A. i The switching frequency of a single-input, four-output, three-level full-bridge LLC converter Phase B i The switching frequency of a single-input, four-output, three-level full-bridge LLC converter and the first phase of C i The switching frequency of a single-input, four-output, three-level full-bridge LLC converter The calculation formulas are as follows: In the formula, It is the turns ratio of the primary to secondary side of the high-frequency transformer in a single-input, four-output, three-level full-bridge LLC converter. The proportional gain of the LLC voltage controller. The integral coefficient of the LLC voltage controller.

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