A photovoltaic module detection method and apparatus

Abstract

The application discloses a photovoltaic module detection method and device, which determines the highest temperature of each hot spot and a dynamic environmental influence factor through an infrared thermal imaging photo, further determines a hot spot temperature rise energy efficiency decay rate, simultaneously determines the fault type of each cell piece with a fault and the corresponding defect type decay coefficient through an electroluminescence image, further determines an internal defect type cell piece decay rate, combines the hot spot temperature rise energy efficiency decay rate and the internal defect type cell piece decay rate to determine a defect module comprehensive fault decay rate, and determines the fault degree of the photovoltaic module. It can be seen that the application determines the decay condition of the efficiency of the photovoltaic module caused by the hot spot on the photovoltaic module through the hot spot temperature rise energy efficiency decay rate, determines the decay condition of the efficiency of the photovoltaic module caused by different fault types of the photovoltaic module through the internal defect type cell piece decay rate, further determines the fault degree of the photovoltaic module, and determines the state of the photovoltaic module.

Description

TECHNICAL FIELD

[0001] The present application relates to the field of renewable energy, in particular to a photovoltaic module detection method and device. BACKGROUND

[0002] A photovoltaic module is a core device for converting solar energy into electrical energy, which is composed of multiple cell pieces, encapsulating materials, glass cover plates, back plates and frames. Photovoltaic modules are exposed to the outdoor environment for a long time, and therefore face multiple challenges such as ultraviolet radiation, temperature changes, moisture erosion, mechanical stress (such as hail, wind pressure) and potential defects (such as hidden cracks, hot spots, PID (Potential Induced Degradation) effects), which can cause the performance of the photovoltaic module to degrade, such as power attenuation and efficiency reduction. Therefore, how to detect the photovoltaic module to determine the state of the photovoltaic module is a problem that needs to be solved by those skilled in the art. SUMMARY

[0003] The purpose of the present application is to provide a photovoltaic module detection method and device, which determines the degradation of the efficiency of the photovoltaic module caused by hot spots on the photovoltaic module through hot spot temperature rise energy efficiency degradation rate, and determines the degradation of the efficiency of the photovoltaic module caused by different fault types of the photovoltaic module through internal defect type cell piece degradation rate, and then determines the fault degree of the photovoltaic module to determine the state of the photovoltaic module.

[0004] To solve the above technical problems, the present application provides a photovoltaic module detection method, comprising: obtaining an infrared thermal imaging photo and an electroluminescence image of a photovoltaic module; determining the highest temperature of each hot spot on the surface of the photovoltaic module based on the infrared thermal imaging photo, and determining a dynamic environmental impact factor based on the highest temperature; determining a hot spot temperature rise energy efficiency degradation rate based on the highest temperature and the dynamic environmental impact factor; determining the fault type of each cell piece with a fault in the photovoltaic module based on the electroluminescence image, and determining a defect type degradation coefficient corresponding to each fault type; determining an internal defect type cell piece degradation rate based on each defect type degradation coefficient; determining a defect module comprehensive fault degradation rate based on the hot spot temperature rise energy efficiency degradation rate and the internal defect type cell piece degradation rate, and determining the fault degree of the photovoltaic module based on the defect module comprehensive fault degradation rate.

[0005] Preferably, the dynamic environmental impact factor is determined based on the highest temperature, comprising: determining a convective heat transfer coefficient and a radiation heat transfer coefficient based on the highest temperature; combining the convective heat transfer coefficient and the radiation heat transfer coefficient, and calculating the dynamic environmental impact factor based on a dynamic environmental impact factor expression; the dynamic environmental impact factor expression is:

[0006] ;

[0007] wherein f is the dynamic environmental influence factor, k is a dynamic environmental influence factor correction number, is the theoretical power generation of the photovoltaic module, is the convective heat transfer coefficient, is the radiative heat transfer coefficient, A is the surface area of the photovoltaic module, is the maximum temperature.

[0008] Preferably, before determining the hot spot temperature rise energy efficiency decay rate based on the maximum temperature and the dynamic environmental influence factor, the method further comprises: determining a target cell piece quantity of cell pieces with hot spots on the photovoltaic module based on the infrared thermal image; determining a temperature difference between the maximum temperature and an operating environment temperature of the photovoltaic module; determining the hot spot temperature rise energy efficiency decay rate based on the maximum temperature and the dynamic environmental influence factor, comprising: determining the hot spot temperature rise energy efficiency decay rate based on a hot spot area temperature rise loss power expression in combination with the target cell piece quantity, the maximum temperature and the dynamic environmental influence factor; and the hot spot area temperature rise loss power expression is:

[0009] ;

[0010] wherein, is the hot spot temperature rise energy efficiency decay rate, q is a first-year power decay rate of the photovoltaic module, n is a number of years of operation of the photovoltaic module, is the power decay rate of the photovoltaic module each year, is the temperature difference, is a decay coefficient of decay of output power of the photovoltaic module with temperature rise of the photovoltaic module, is the rated efficiency of the photovoltaic module, f is the dynamic environmental influence factor, is a temperature coefficient, a is the target cell piece quantity, and N is a total number of cell pieces in the photovoltaic module.

[0011] Preferably, the photovoltaic module comprises a plurality of parallelly connected cell circuits, and each of the cell circuits comprises a plurality of seriesly connected cell pieces; before determining the hot spot temperature rise energy efficiency decay rate based on the maximum temperature and the dynamic environmental influence factor, the method further comprises: determining a first target quantity of the cell circuits with hot spots on the photovoltaic module based on the infrared thermal image; and correcting the temperature coefficient based on the first target quantity.

[0012] Preferably, determining the fault type of each faulty cell piece in the photovoltaic module based on the electroluminescent image comprises: performing image recognition on each cell piece of the photovoltaic module in the electroluminescent image respectively to determine the faulty cell piece and determine the fault type of each faulty cell piece respectively; the fault type comprises one or more combinations of cell piece breakage, cell piece grayscale anomaly and diode breakdown anomaly.

[0013] Preferably, before determining the defect type attenuation coefficient corresponding to each fault type, the method further comprises: determining each cell piece with the fault type of cell piece breakage as a first type of faulty cell piece; determining the total area of the completely failed region and the total area of the degraded region in each first type of faulty cell piece respectively; the brightness value of the completely failed region in the first type of faulty cell piece is not greater than a first preset brightness value, and the brightness value of the degraded region is greater than the first preset brightness value but not greater than a second preset brightness value; the first preset brightness value is less than the second preset brightness value; dividing the cell piece breakage into one or more combinations of light fragment fault, medium fragment fault and serious fragment fault based on the proportion of the total area of the completely failed region and the total area of the degraded region in the total area of the cell piece; the proportion of the total area of the completely failed region or the total area of the degraded region of the cell piece with the light fragment fault in the total area of the cell piece is less than the proportion of the total area of the completely failed region or the total area of the degraded region of the cell piece with the medium fragment fault in the total area of the cell piece; the proportion of the total area of the completely failed region or the total area of the degraded region of the cell piece with the medium fragment fault in the total area of the cell piece is less than the proportion of the total area of the completely failed region or the total area of the degraded region of the cell piece with the serious fragment fault in the total area of the cell piece.

[0014] Preferably, before determining the defect type attenuation coefficient corresponding to each fault type, the method further comprises: determining each cell piece with battery piece gray abnormality as a second type of fault cell piece; calculating the brightness of each region of each second type of fault cell piece; dividing the battery piece gray abnormality into one or more combinations of local dark spot fault, whole piece dark piece fault, black piece fault, bright spot fault and black edge fault based on the brightness of each region of each second type of fault cell piece; in the cell piece with local dark spot fault, the area ratio of the area with brightness less than a third preset brightness value to the total area of the cell piece is greater than a first preset proportion; in the cell piece with whole piece dark piece fault, the brightness of the whole piece cell piece is less than the brightness of the normal cell piece; in the cell piece with black piece fault, the brightness of the whole piece cell piece is not greater than a fourth preset brightness value; in the cell piece with bright spot fault, there is a region with brightness greater than the brightness of the normal cell piece; in the cell piece with black edge fault, the brightness at the edge is not greater than the fourth preset brightness value; the third preset brightness value is not less than the fourth preset brightness value.

[0015] Preferably, the photovoltaic module comprises a plurality of cell circuits, and each cell circuit comprises a plurality of cell pieces and a diode connected in series, and the diodes in each cell circuit are connected in series between the output positive terminal and the output negative terminal of the photovoltaic module, and the brightness of each cell piece is not greater than a fourth preset brightness, and the cell circuit with the diode breakdown abnormality is the cell circuit with the diode breakdown abnormality; before determining the internal defect type cell piece attenuation rate based on each defect type attenuation coefficient, the method further comprises: determining a second target number of cell circuits with diode breakdown abnormality; determining the internal defect type cell piece attenuation rate based on each defect type attenuation coefficient, comprising: combining each defect type attenuation coefficient and the second target number, and determining the internal defect type cell piece attenuation rate based on an internal defect type cell piece attenuation rate expression; the internal defect type cell piece attenuation rate expression is:

[0016] ;

[0017] wherein, is the internal defect type cell piece attenuation rate, is the number of cell pieces with the i-th defect type other than the diode breakdown abnormality, is the defect type attenuation coefficient of the i-th defect type, is the number of remaining cell pieces in the photovoltaic module other than the cell pieces in the cell circuit with the diode breakdown abnormality, m is the second target number, and M is the total number of cell circuits in the photovoltaic module, is the rated efficiency of the photovoltaic module.

[0018] Preferably, determining the defect component comprehensive failure attenuation rate based on the hot spot temperature rise energy efficiency attenuation rate and the internal defect type cell piece attenuation rate comprises: determining the sum of the hot spot temperature rise energy efficiency attenuation rate and the internal defect type cell piece attenuation rate as the defect component comprehensive failure attenuation rate.

[0019] Preferably, determining the failure degree of the photovoltaic module based on the defect component comprehensive failure attenuation rate comprises: determining a first attenuation threshold, a second attenuation threshold and a third attenuation threshold, the first attenuation threshold, the second attenuation threshold and the third attenuation threshold being sequentially increased; if the defect component comprehensive failure attenuation rate is not greater than the first attenuation threshold, determining that the failure degree of the photovoltaic module is no failure; if the defect component comprehensive failure attenuation rate is greater than the first attenuation threshold but not greater than the second attenuation threshold, determining that the failure degree of the photovoltaic module is light failure; if the defect component comprehensive failure attenuation rate is greater than the second attenuation threshold but not greater than the third attenuation threshold, determining that the failure degree of the photovoltaic module is moderate failure; if the defect component comprehensive failure attenuation rate is greater than the third attenuation threshold, determining that the failure degree of the photovoltaic module is severe failure; the failure degrees of the no failure, the light failure, the moderate failure and the severe failure being sequentially increased.

[0020] Preferably, after determining the failure degree of the photovoltaic module based on the defect component comprehensive failure attenuation rate, the method further comprises: determining an electric quantity loss value of the photovoltaic module based on the defect component comprehensive failure attenuation rate, a theoretical power generation power of the photovoltaic module, a power generation time of the photovoltaic module in a full load state and a time during which the failure degree of the photovoltaic module is greater than the no failure.

[0021] To solve the above technical problems, the present application provides a photovoltaic module detection device, comprising: a memory for storing a computer program; and a processor for implementing the steps of the photovoltaic module detection method as described above when executing the computer program.

[0022] The application provides a photovoltaic module detection method and device, the highest temperature of each hot spot and a dynamic environmental influence factor are determined through an infrared thermal imaging photo, and then a hot spot temperature rise energy efficiency decay rate is determined, meanwhile, the fault type of each cell piece with a fault and a corresponding defect type decay coefficient are determined through an electroluminescence image, and then an internal defect type cell piece decay rate is determined, the defect module comprehensive fault decay rate is determined by combining the hot spot temperature rise energy efficiency decay rate and the internal defect type cell piece decay rate, so as to determine the fault degree of the photovoltaic module. It can be seen that, in the application, the hot spot on the photovoltaic module is determined through the hot spot temperature rise energy efficiency decay rate, so as to determine the decay condition of the efficiency of the photovoltaic module caused by the hot spot, and the different fault types of the photovoltaic module are determined through the internal defect type cell piece decay rate, so as to determine the decay condition of the efficiency of the photovoltaic module caused by the different fault types, and then the fault degree of the photovoltaic module is determined, so as to determine the state of the photovoltaic module. BRIEF DESCRIPTION OF DRAWINGS

[0023] In order to more clearly illustrate the embodiments of the present application, the drawings needed to be used in the embodiments will be briefly introduced as follows. Obviously, the drawings in the following description are only some embodiments of the present application, and other drawings can be obtained by those skilled in the art without any creative effort on the basis of these drawings.

[0024] Figure 1 A flowchart of a photovoltaic module detection method provided by the present application is shown in the figure.

[0025] Figure 2 An electroluminescence image of a serious fragment fault provided by the present application is shown in the figure.

[0026] Figure 3 An electroluminescence image of a moderate fragment fault provided by the present application is shown in the figure.

[0027] Figure 4 An electroluminescence image of a slight fragment fault provided by the present application is shown in the figure.

[0028] Figure 5 An electroluminescence image of a black piece fault provided by the present application is shown in the figure.

[0029] Figure 6 A connection diagram of each cell piece in a photovoltaic module provided by the present application is shown in the figure.

[0030] Figure 7 An electroluminescence image of a diode breakdown abnormality provided by the present application is shown in the figure.

[0031] Figure 8 A structure diagram of a photovoltaic module detection system provided by the present application is shown in the figure.

[0032] Figure 9A structural schematic diagram of a photovoltaic module detection device provided by the present application is provided.

[0033] Figure 10 A structural schematic diagram of a computer readable storage medium provided by the present application is provided. DETAILED DESCRIPTION

[0034] The core of the present application is to provide a photovoltaic module detection method and device, which determines the decay of the efficiency of the photovoltaic module caused by the hot spot on the photovoltaic module through the heat spot temperature rise energy efficiency decay rate, and determines the decay of the efficiency of the photovoltaic module caused by different fault types of the photovoltaic module through the internal defect type cell decay rate, and then determines the fault degree of the photovoltaic module to determine the state of the photovoltaic module.

[0035] In order to make the purpose, technical scheme and advantages of the embodiments of the present application clearer, the technical scheme in the embodiments of the present application will be described clearly and completely below with reference to the drawings in the embodiments of the present application. Obviously, the described embodiments are part of the embodiments of the present application, rather than all the embodiments. Based on the embodiments in the present application, all other embodiments obtained by those skilled in the art without creative labor fall within the scope of protection of the present application.

[0036] Please refer to Figure 1 , Figure 1 A flowchart of a photovoltaic module detection method provided by the present application is provided, which comprises:

[0037] S11: Obtain the infrared thermal imaging photo and the electroluminescence image of the photovoltaic module.

[0038] The photovoltaic module is composed of many cell pieces in series, and the output current of the entire photovoltaic module is determined by the cell piece with the smallest output current. Referring to the bucket effect, when the output capacity of a certain cell piece or several cell pieces in the photovoltaic module is lower than that of other cell pieces, the certain cell piece or several cell pieces cannot provide the same current as the normal cell pieces, and the current of the photovoltaic module is forced to be reduced to the maximum current value that can be provided by the "problem cell", since the current of the entire photovoltaic module is pulled down, but other normal cell pieces still strive to generate their original current under illumination, the current generated by the normal cell pieces is higher than the actual current flowing through, for the "problem cell" with insufficient output capacity, the current it should generate is less than the series current actually flowing through it, which leads to the polarity of the voltage across the cell piece being reversed, i.e. from normal forward bias to reverse bias state, i.e. from power generation state to power consumption state, in the reverse bias state, the cell piece is no longer a power source but a power consumption load, and the current flowing through it multiplied by the reverse voltage across it is the power loss generated inside the cell piece, most of which is converted into heat energy. In addition, when bird droppings, leaves, dust accumulation, snow accumulation, shadows of adjacent buildings, shadows of the module frame, etc. fall on the cell piece, they block the light, and the photogenerated current generated by the shaded cell piece also decreases sharply, and the heat generated by the cell piece in the reverse bias state cannot be dissipated in time and effectively, which will cause the temperature in this area to be significantly higher than that in other parts of the photovoltaic module, since the efficiency of the cell piece usually decreases with the increase of temperature, the high temperature will further reduce the performance of the cell piece in this area, forming a vicious cycle, making the local temperature higher and higher, and finally forming a visible "hot spot" or a clear "hot spot" in infrared imaging.

[0039] In addition, since the photovoltaic module is usually set outdoors, if the photovoltaic module is damaged due to external damage, even if it is broken or has other failures, it will also cause the impedance of the defective cell piece on the photovoltaic module to increase, reducing the output power and efficiency of the photovoltaic module.

[0040] Based on this, the infrared thermal imaging photograph is obtained by infrared imaging technology in the present application, since the output current of the photovoltaic module is proportional to the intensity of illumination, when the light is the strongest, the output current of the photovoltaic module reaches the peak value, the reverse current flowing through the cell piece with hot spot also reaches the maximum, and the heat generation power of the hot spot area is maximized, therefore, the power generation efficiency of the normal cell piece is high under strong light, but the temperature rises slowly, while the temperature of the hot spot area rises sharply due to additional power loss, under strong light, the temperature difference between the hot spot and the normal area on the photovoltaic module reaches the peak value, and the temperature difference between the hot spot and the normal area can be expanded to more than 30-50℃, which presents an extremely obvious hot spot in the infrared thermal imaging photograph.

[0041] Therefore, in this application, infrared thermal imaging photos of photovoltaic modules are obtained when the irradiance is relatively high, the solar altitude angle is greater than 45 degrees, cloud cover is avoided, the surface of the photovoltaic modules is uniformly illuminated, and the wind speed is low. At the same time, the extreme low temperature in winter or the extreme high temperature in summer is avoided to prevent interference with heat dissipation differences. A telephoto lens or a drone is used to obtain infrared thermal imaging photos of photovoltaic modules to avoid close contact with the high voltage system.

[0042] Furthermore, since infrared thermal imaging is used to capture differences in thermal radiation during photovoltaic (PV) module operation, the energy source of the hot spots detected on the PV module is the PV module's own heating. The detection target is functional abnormalities during operation, and requires strong light exposure and grid-connected operation of the PV module. To further ensure the accuracy of determining the PV module's condition, this application also acquires electroluminescence (EM) images of the PV module. EEM images are detected in a dark environment, requiring the PV module to be disconnected and a current to be applied to the cells to detect the intensity distribution of its self-emission. Therefore, the energy source for defects on the PV module detected by EEM images is the near-infrared emission of the cells excited by externally injected current. Physical defects in the cells themselves, such as microcracks, fragments, and manufacturing defects, can be detected through EEM images.

[0043] Based on this, by acquiring infrared thermal imaging photos and electroluminescent images of photovoltaic modules, this application can both diagnose the current faults of photovoltaic modules and provide early warning of potential risks, thus providing dual protection for the safe and efficient operation of photovoltaic systems.

[0044] S12: Determine the highest temperature of each hot spot on the surface of the photovoltaic module based on infrared thermal imaging photos, and determine the dynamic environmental impact factor based on the highest temperature.

[0045] Since the output current of a photovoltaic (PV) module is determined by the cell with the lowest output current, and the higher the temperature, the lower the output current of the cell, when multiple hot spots appear on a PV module, the hot spot with the highest temperature can be identified, and its maximum temperature can be determined. The dynamic environmental impact factor can then be determined using this maximum temperature, thus determining the impact of the hot spot with the highest temperature on the PV module. This dynamic environmental impact factor is related to wind speed, ambient temperature, and the temperature of the PV module, especially the temperature of the hot spots, and is related to the heat dissipation of the PV module. Therefore, the dynamic environmental impact factor also affects the degree of energy efficiency degradation of the PV module.

[0046] Figure 2 The areas with relatively high brightness are where the hot spots are located. Figure 2 The image shows a photovoltaic module with four hot spots.

[0047] S13: Determine the hot spot temperature rise energy efficiency decay rate based on the highest temperature and dynamic environmental influence factors.

[0048] Because the damage of hot spot to photovoltaic modules is a nonlinear function of temperature and time, and is strongly modulated by environmental conditions, such as 90℃ hot spot for 10 minutes and 90℃ hot spot for 10 hours, the degree of aging of photovoltaic materials is very different, or the same 90℃ hot spot, the heat dissipation efficiency is different in 25℃ environment and 45℃ environment, the actual thermal stress is also different, therefore, in this embodiment, the hot spot temperature rise energy efficiency decay rate is determined by combining the maximum temperature and the dynamic environmental impact factor, that is, the energy efficiency decay rate of the photovoltaic module caused by the hot spot.

[0049] S14: Determine the fault type of each cell with faults in the photovoltaic module based on the electroluminescence image, and determine the defect type decay coefficient corresponding to each fault type.

[0050] The cells in the photovoltaic module generate current under light, and the process of generating electroluminescence image is the reverse process. Specifically, when a forward bias is applied to the cell, that is, current is injected, the injected electrons and holes meet and recombine in the cell. A part of the recombination will release energy in the form of photons, emitting light with a wavelength mainly in the near-infrared band. The luminescence intensity is directly related to the non-equilibrium minority carrier concentration at a specific location and the current density passing through. The defect of the cell is usually the center of carrier recombination. In these areas, the injected carriers tend to recombine in a non-luminous manner, such as heat generation, resulting in a significant reduction or even disappearance of the luminescence intensity of the region, which appears as a dark area on the electroluminescence image. In addition, physical defects or serious electrical defects will hinder or completely cut off the flow of current in the cell. The area without current flowing through has no carrier injection and recombination, and therefore will not emit light, appearing as a dark line or dark block on the electroluminescence image.

[0051] Based on this, the electroluminescence imaging technology captures the near-infrared light emitted by the cells in the photovoltaic module when powered on, and converts the differences in current distribution and carrier recombination efficiency inside the cells into images with light and dark contrasts. Any defect that hinders the flow of current and increases non-radiative recombination will cause the local light to weaken, forming a characteristic dark area pattern. By interpreting the shape, position and characteristics of these patterns, the fault type of the cell can be accurately identified.

[0052] Different fault types affect the physical mechanism of carrier transport and recombination process, resulting in differences in current density distribution and radiation recombination efficiency, which directly reflects in the gray value or brightness of electroluminescence image, forming a characteristic decay coefficient, so different defect type decay coefficients can be determined according to different fault types. For example, the defect type decay coefficient corresponding to the fault type of completely destroying the current path is higher, the defect type decay coefficient corresponding to the fault type of strong recombination and combining part of the current block is relatively lower, and the defect type decay coefficient of the defect type of only reducing the current density is lower.

[0053] Figure 3 The area with low brightness or even black is the area with faults.

[0054] S15: Determine the internal defect type cell piece decay rate based on the defect type decay coefficients of each fault type.

[0055] In this embodiment, it is considered that different fault types cause local carrier loss through specific physical mechanisms (blocking current or enhancing non-radiation recombination), and the local loss is conducted step by step in the series / parallel circuit inside the cell piece, and finally it is shown as quantifiable power decay, so the defect type decay coefficients corresponding to each fault type in the electroluminescence image are mapped to the global performance loss, that is, the internal defect type cell piece decay rate caused by different fault types is determined.

[0056] S16: Determine the defect component comprehensive fault decay rate based on the hot spot temperature rise energy efficiency decay rate and the internal defect type cell piece decay rate, and determine the fault degree of the photovoltaic module based on the defect component comprehensive fault decay rate.

[0057] The defect component comprehensive fault decay rate of the entire photovoltaic module is determined by combining the hot spot temperature rise energy efficiency decay rate caused by the hot spot during the operation of the photovoltaic module, and the internal defect type cell piece decay rate determined according to different fault types on the cell piece of the photovoltaic module, so as to determine the fault degree of the photovoltaic module, that is, the fault degree of the photovoltaic module is deduced according to the power decay caused by different abnormalities of the photovoltaic module, so as to determine the state of the photovoltaic module and determine whether the photovoltaic module can work normally.

[0058] In summary, in this application, the hot spot on the photovoltaic module causes the efficiency decay of the photovoltaic module by determining the hot spot temperature rise energy efficiency decay rate, and the efficiency decay of the photovoltaic module caused by different fault types of the photovoltaic module is determined by determining the internal defect type cell piece decay rate, and then the fault degree of the photovoltaic module is determined to determine the state of the photovoltaic module.

[0059] On the basis of the above embodiment:

[0060] As a preferred embodiment, the dynamic environment impact factor is determined based on the maximum temperature, including: determining the convective heat transfer coefficient and the radiative heat transfer coefficient based on the maximum temperature; combining the convective heat transfer coefficient and the radiative heat transfer coefficient, and calculating the dynamic environment impact factor based on the dynamic environment impact factor expression; the dynamic environment impact factor expression is:

[0061] ;

[0062] Wherein, f is the dynamic environment impact factor, k is the dynamic environment impact factor correction constant, is the theoretical power generation of the photovoltaic module, is the convective heat transfer coefficient, is the radiative heat transfer coefficient, A is the surface area of the photovoltaic module, is the maximum temperature.

[0063] In determining the dynamic environment impact factor, the convective heat transfer coefficient and the radiative heat transfer coefficient are used in the embodiment, the convective heat transfer coefficient and the radiative heat transfer coefficient respectively quantify two essentially different heat transfer mechanisms between the environment and the photovoltaic module, and the comprehensive heat exchange capacity of the object in the real environment is determined by the two.

[0064] Specifically, the convective heat transfer coefficient quantifies the heat energy carried by fluid motion, which is dominated by wind speed; the radiative heat transfer coefficient quantifies the heat energy transferred by electromagnetic waves, which is dominated by surface characteristics and temperature difference. Both of them coexist, interact and change dynamically in real environment. Only by integrating the convective heat transfer coefficient and the radiative heat transfer coefficient can the temperature of the hot spot on the photovoltaic module in the variable environment be accurately predicted, and a reliable dynamic environment impact factor model can be constructed.

[0065] Therefore, the determination of the dynamic environment impact factor involves the influence relationship between the wind speed, the environmental temperature, the ground temperature, the irradiance and the photovoltaic module temperature, and the wind speed data is the average wind speed on the day of photovoltaic module detection.

[0066] The expressions of the convective heat transfer coefficient under the conditions of no wind and wind are as follows:

[0067] ;

[0068] Wherein, the part on the left side of the plus sign under the square root is the natural convection part, that is, the maximum temperature of the hot spot on the photovoltaic module under the natural environment without wind and the convective heat transfer coefficient of the natural environment, is the maximum temperature of each hot spot on the photovoltaic module, is the environmental temperature, is the absolute temperature difference between the surface of the photovoltaic module and the environmental temperature, the greater the temperature difference, the stronger the natural convection, is the inclination angle between the flat plate of the photovoltaic module and the horizontal plane, is the inclination correction factor, when the surface of the photovoltaic module is horizontal, i.e. , = 1, the denominator of the expression of the convective heat transfer coefficient is maximum, and the natural convection is weakest; when the surface of the photovoltaic module is vertical, i.e. , = 0, the denominator of the expression of the convective heat transfer coefficient is minimum, and the natural convection is strongest, b is a natural convection correction factor, c is an inclination correction number, b and c can be adjusted according to actual needs, for example, b can be 1.81 and c can be 1.382 according to experiments, of course, b and c in different scenarios can be adjusted accordingly, which is not limited in the present application.

[0069] The part on the right side of the radical sign is the forced convection part, i.e. the highest temperature of the hot spot on the photovoltaic module in the wind environment and the convective heat transfer coefficient in the natural environment, V is the average wind speed in the working environment of the photovoltaic module on the day of detection, d is a forced convection correction factor, which can be adjusted according to needs, for example, it can be 2.38, e is a forced convection correction index, which can be adjusted according to needs, for example, it can be 0.89, indicating that the influence of wind speed on heat transfer coefficient is nonlinear.

[0070] The natural convection part and the forced convection part are combined by square sum and square root to obtain the convective heat transfer coefficient, so as to reflect the synergistic effect of the two convection mechanisms, which is not a simple superposition.

[0071] The determination of the radiation heat transfer coefficient involves the long-wave radiation of the photovoltaic module to the sky and the ground, and needs to consider the highest temperature of the hot spot of the photovoltaic module, the environmental temperature and the ground temperature.

[0072] The expression of the radiation heat transfer coefficient is as follows:

[0073] ;

[0074] Among them, is the emissivity of the photovoltaic module, is the Stefan-Boltzmann constant, which is ; is the ground temperature, if it is a roof photovoltaic, is the roof temperature.

[0075] Based on this, after the determination of the convective heat transfer coefficient and the radiation heat transfer coefficient, the dynamic environmental influence factor can be further determined, k is a dynamic environmental influence factor correction number, which can be selected according to actual needs, for example, it can be 2.1507.

[0076] The denominator of the dynamic environment impact factor expression represents the theoretical maximum heat dissipation capacity. The theoretical power generation / theoretical maximum heat dissipation capacity of the photovoltaic module is used to obtain the irreversible loss ratio of thermoelectric conversion, that is, the dynamic environment impact factor.

[0077] As a preferred embodiment, before determining the hot spot temperature rise energy efficiency attenuation rate based on the maximum temperature and the dynamic environment impact factor, the method further comprises: determining a target cell piece quantity of the cell piece with the hot spot on the photovoltaic module based on the infrared thermal image; determining a temperature difference between the maximum temperature and an operating environment temperature of the photovoltaic module; and determining the hot spot temperature rise energy efficiency attenuation rate based on the maximum temperature and the dynamic environment impact factor, comprising: determining the hot spot temperature rise energy efficiency attenuation rate based on the hot spot area temperature rise loss power expression in combination with the target cell piece quantity, the maximum temperature and the dynamic environment impact factor.

[0078] The hot spot area temperature rise loss power expression is:

[0079] ;

[0080] wherein, is the hot spot temperature rise energy efficiency attenuation rate, q is a power attenuation rate of the photovoltaic module in the first year, and n is a running year number of the photovoltaic module, is the power attenuation rate of the photovoltaic module each year, is the temperature difference, is an attenuation coefficient of the output power of the photovoltaic module with the temperature rise of the photovoltaic module, is a rated efficiency of the photovoltaic module, and f is the dynamic environment impact factor, is a temperature coefficient, a is the target cell piece quantity, and N is a total number of cell pieces in the photovoltaic module.

[0081] The hot spot area temperature rise loss power expression comprises three parts, which are an aging temperature rise attenuation of the photovoltaic module, a dynamic environment impact factor and a local influence of the hot spot on the photovoltaic module, wherein q and is a basic aging constant of the photovoltaic module, is a power attenuation rate caused by aging in normal use of the photovoltaic module, and is linearly superimposed with the running year number, | represents a power attenuation rate caused by the temperature difference between the maximum temperature of the hot spot on the photovoltaic module and the operating environment temperature of the photovoltaic module, that is, a power attenuation rate caused by the temperature rise of the hot spot area. The output power of the photovoltaic cell decreases by about 0.3% to 0.5% per 1℃ of temperature rise. The sum of the above attenuation rates represents a power attenuation rate caused by the aging and the hot spot temperature rise of the photovoltaic module. The dynamic environment impact factor can represent the acceleration of the power attenuation of the photovoltaic module in a harsh environment and the slowing down of the power attenuation of the photovoltaic module in an ideal environment. The temperature coefficient represents the sensitivity of the whole photovoltaic module to temperature rise, and the ratio of a to N represents the proportion of the number of the cell pieces with hot spots to the total number of the cell pieces. The rated efficiencies of the above photovoltaic modules are multiplied to determine the power attenuation of the photovoltaic module caused by the hot spot temperature rise and the aging of the photovoltaic module.

[0082] As a preferred embodiment, the photovoltaic module includes a plurality of cell circuits connected in parallel, and each cell circuit includes a plurality of cell pieces connected in series. Before determining the hot spot temperature rise energy efficiency decay rate based on the highest temperature and the dynamic environmental influence factor, the method further includes: determining a first target number of the cell circuits with hot spots on the photovoltaic module based on the infrared thermal imaging photo; and correcting the temperature coefficient based on the first target number.

[0083] The cell circuits in the photovoltaic module are connected in parallel, and each cell circuit includes a plurality of cell pieces connected in series. When there is a hot spot on a cell piece in a cell circuit, the hot spot first affects the output current of the cell circuit in which the cell piece is located, and the cell circuit with the hot spot affects the output current of the whole photovoltaic module. The more the number of the cell circuits with hot spots, the greater the influence on the output current of the photovoltaic module. Based on this, the number of the cell circuits with hot spots, i.e., the first target number, is determined first, and the temperature coefficient in the hot spot area temperature rise power loss expression is corrected based on the first target number. The greater the first target number, the greater the temperature coefficient.

[0084] For example, when the first target number is 1, it means that there is only one cell circuit with a hot spot in the photovoltaic module, and at this time the temperature coefficient can be 0.3; when the first target number is 2, it means that there are two cell circuits with hot spots in the photovoltaic module, and at this time the temperature coefficient can be 0.5; when the first target number is 3, it means that there are three cell circuits with hot spots in the photovoltaic module, and at this time the temperature coefficient can be 0.6. Of course, the temperature coefficient can be adjusted according to actual conditions, which is not limited in the present application.

[0085] As a preferred embodiment, the fault type of each cell piece with a fault in the photovoltaic module is determined based on the electroluminescence image, including: performing image recognition on each cell piece of the photovoltaic module in the electroluminescence image to determine the cell pieces with faults, and respectively determining the fault type of each cell piece with a fault; and the fault type includes one or a combination of more than one of cell piece breakage, cell piece gray scale abnormality, and diode breakdown abnormality.

[0086] In this embodiment, the electroluminescent image is subjected to image recognition to determine the faulty cell pieces in the electroluminescent image and further determine the fault types of the cell pieces. Specifically, an image recognition model can be established in advance, a training set including images of various cell pieces with known fault types is input into the image recognition model to enable the image recognition model to learn the corresponding relationship between the cell piece images and the fault types, and then the electroluminescent image is segmented into various cell piece images in a test set, and the test set is input into the image recognition model to determine the faulty cell pieces in the photovoltaic module and determine the fault types of the cell pieces.

[0087] As a preferred embodiment, before determining the defect type attenuation coefficients corresponding to each fault type, the method further comprises: determining each cell piece with a fault type of cell piece breakage as a first type of faulty cell piece; determining a total area of a complete failure region and a total area of a degradation region in each first type of faulty cell piece; the brightness value of the complete failure region in the first type of faulty cell piece is not greater than a first preset brightness value, and the brightness value of the degradation region is greater than the first preset brightness value but not greater than a second preset brightness value; the first preset brightness value is less than the second preset brightness value; and dividing the cell piece breakage into one or more combinations of a slight fragment fault, a moderate fragment fault and a severe fragment fault based on the proportions of the total area of the complete failure region and the total area of the degradation region to the total area of the cell piece.

[0088] The proportion of the total area of the complete failure region or the total area of the degradation region of the cell piece with the slight fragment fault to the total area of the cell piece is less than the proportion of the total area of the complete failure region or the total area of the degradation region of the cell piece with the moderate fragment fault to the total area of the cell piece; and the proportion of the total area of the complete failure region or the total area of the degradation region of the cell piece with the moderate fragment fault to the total area of the cell piece is less than the proportion of the total area of the complete failure region or the total area of the degradation region of the cell piece with the severe fragment fault to the total area of the cell piece.

[0089] The cell piece with the fault type of cell piece breakage is classified into the first type of faulty cell piece, and the cell piece breakage is further divided into one or more combinations of a slight fragment fault, a moderate fragment fault and a severe fragment fault according to the total area of the complete failure region and the total area of the degradation region in the first type of faulty cell piece, that is, the fault type is further divided, and the slight fragment fault, the moderate fragment fault and the severe fragment fault obtained by the division also correspond to different defect type attenuation coefficients.

[0090] It should be noted that the complete failure area is an area where the cell piece is broken to form a closed ring-shaped complete breakage, resulting in the loss of electrical connection between the broken piece area and the main circuit of the photovoltaic module, and the power loss of the photovoltaic module is high. The degradation area is an area where the cell piece is not completely broken and still maintains electrical connection with the main circuit of the photovoltaic module, and still generates a photoelectric current, but the generated power is low. That is, the cell piece in the complete failure area completely loses the power generation capability, and the performance of the cell piece in the degradation area decreases but is not completely failed.

[0091] In the electroluminescent image, since the cell piece in the complete failure area loses connection with the main circuit, the brightness of the complete failure area is low, and the complete failure area can be determined by the brightness value being not greater than a first preset brightness value. The cell piece in the degradation area still maintains a certain connection with the main circuit, and the brightness value thereof is lower than that of the normal cell piece area, but is higher than that of the complete failure area. Therefore, the degradation area can be determined according to the brightness being greater than the first preset brightness value but not greater than a second preset brightness value. Therefore, the second preset brightness value can be the brightness of the normal cell piece in the electroluminescent image.

[0092] In the electroluminescent image, since the cell piece in the complete failure area loses connection with the main circuit, the brightness of the complete failure area is low, and the complete failure area can be determined by the brightness value being not greater than a first preset brightness value. The cell piece in the degradation area still maintains a certain connection with the main circuit, and the brightness value thereof is lower than that of the normal cell piece area, but is higher than that of the complete failure area. Therefore, the degradation area can be determined according to the brightness being greater than the first preset brightness value but not greater than a second preset brightness value. Therefore, the second preset brightness value can be the brightness of the normal cell piece in the electroluminescent image.

[0093] For the cell piece, among the light fragment fault, the medium fragment fault and the serious fragment fault, if the serious fragment fault occurs, the brightness of the cell piece area in the electroluminescent image is extremely low, and the dark area is the largest, as shown in FIG. 4. Figure 2 Figure 2 FIG. 4 is an electroluminescent image schematic diagram of a serious fragment fault provided by the present application, and the serious fragment fault has the greatest influence on the power attenuation of the photovoltaic module, and the corresponding defect type attenuation coefficient is the largest. If the medium fragment fault occurs, the brightness of the cell piece area in the electroluminescent image is low, and the dark area is large, as shown in FIG. 5. Figure 3 Figure 3 FIG. 5 is an electroluminescent image schematic diagram of a medium fragment fault provided by the present application, and the medium fragment fault has a greater influence on the power attenuation of the photovoltaic module, and the corresponding defect type attenuation coefficient is larger. If the light fragment fault occurs, the brightness of the cell piece area in the electroluminescent image is low, and the dark area is small, as shown in FIG. 6. Figure 4 Figure 4 FIG. 6 is an electroluminescent image schematic diagram of a light fragment fault provided by the present application, and the light fragment fault has a smaller influence on the power attenuation of the photovoltaic module, and the corresponding defect type attenuation coefficient is smaller. Figure 2 Figure 3 and Figure 4 ​​​​In the specific embodiment, the relatively darker part is the area where the fragment fault occurs, i.e., the complete failure area or the degradation area.

[0094] Specifically, in the specific embodiment, in the division of the light fragment fault, the medium fragment fault and the serious fragment fault, the light fragment fault is: the total area of the complete failure area is less than or equal to 5% of the total area of each battery piece or 5% of the total area of each battery piece < total area of the degradation area < 30% of the total area of each battery piece, and the corresponding defect type attenuation coefficient is 0.8S or 0.64S; the medium fragment fault is: 5% of the total area of each battery piece < total area of the complete failure area < 30% of the total area of each battery piece or the total area of the degradation area is greater than or equal to 30% of the total area of each battery piece, and the corresponding defect type attenuation coefficient is 3S or 1.8S; the serious fragment fault is: the total area of the complete failure area is greater than or equal to 30% of the total area of each battery piece or the total area of the degradation area is greater than or equal to 50% of the total area of each battery piece, and the corresponding defect type attenuation coefficient is 90%. Wherein, the defect type attenuation coefficient caused by the total area of the complete failure area can be determined based on the following expression:

[0095] ;

[0096] Wherein, is the defect type attenuation coefficient, not greater than 100%, and S is the total area of the complete failure area and the degradation area in the same battery piece accounts for the total area of the battery piece.

[0097] The defect type attenuation coefficient caused by the total area of the degradation area can be determined based on the following expression:

[0098] ;

[0099] In the selection of the defect type attenuation coefficient, the size relationship between the total area of the complete failure area and the total area of the degradation area can be determined, such as S≤5%, and when the total area of the complete failure area is greater than the total area of the degradation area, the defect type attenuation coefficient can be determined as 0.8S, which is not limited in the present application.

[0100] As a preferred embodiment, before determining the defect type attenuation coefficient corresponding to each fault type, the method further comprises: determining each cell with a fault type of cell gray abnormality as a second type of fault cell; calculating the brightness of each region of each second type of fault cell; dividing the cell gray abnormality into one or more combinations of local dark spot fault, whole dark piece fault, black piece fault, bright spot fault, and black edge fault based on the brightness of each region of each second type of fault cell; in the cell with local dark spot fault, the area ratio of the area with brightness less than a third preset brightness value to the total area of the cell is greater than a first preset proportion; in the cell with whole dark piece fault, the brightness of the whole cell is less than the brightness of the normal cell; in the cell with black piece fault, the brightness of the whole cell is not greater than a fourth preset brightness value; in the cell with bright spot fault, there is a region with brightness greater than the brightness of the normal cell; in the cell with black edge fault, the brightness at the edge is not greater than the fourth preset brightness value; the third preset brightness value is not less than the fourth preset brightness value.

[0101] The brightness and darkness imaging of each cell in the electroluminescent image can directly reflect the electrical performance and structural integrity of the cells inside the photovoltaic module. The imaging principle is based on the carrier recombination luminescence characteristics. The brightness difference of different regions corresponds to the existence of various defect types inside the cell. The electroluminescent imaging test of the whole photovoltaic module can obviously show that different cells have brightness differences. The brightness of the image is directly related to the carrier recombination efficiency. The higher the recombination efficiency, the stronger the luminescence, the brighter the image, indicating that the photovoltaic module has good power generation efficiency. On the contrary, the area with low recombination efficiency or defects appears as a dark area.

[0102] In the embodiment, each cell with a fault type of cell gray abnormality is classified as a second type of fault cell. The cell gray abnormality is further divided into one or more combinations of local dark spot fault, whole dark piece fault, black piece fault, bright spot fault, and black edge fault according to the brightness of each region of each second type of fault cell. The defect type attenuation coefficients between local dark spot fault, whole dark piece fault, black piece fault, bright spot fault, and black edge fault are also different.

[0103] For the battery piece, among the local dark spot failure, the whole dark spot failure, the black spot failure, the bright spot failure and the black edge failure, if the local dark spot failure occurs, there is an irregular gray-black area in the electroluminescent image of the battery piece region, that is, the area ratio of the area of the battery piece with a brightness less than the third preset brightness value to the total area of the battery piece is greater than the first preset proportion, and the first preset proportion can be 30%, and the corresponding defect type attenuation coefficient can be 20% Xg; if the whole dark spot failure occurs, the brightness of the battery piece region in the electroluminescent image is less than the brightness of the normal battery piece, the area ratio is 100%, and the corresponding defect type attenuation coefficient can be 100% Xg; if the black spot failure occurs, the reason for causing the failure can be PID effect or leakage current, the battery piece region in the electroluminescent image is black, the area ratio is 100%, and the corresponding defect type attenuation coefficient can be 100% Xg; if the bright spot failure occurs, the reason for causing the failure can be poor welding or hidden cracks of the battery piece, the battery piece region in the electroluminescent image is locally highlighted, that is, there is a region with a brightness greater than the brightness of the normal battery piece, and the corresponding defect type attenuation coefficient can be 80%; if the black edge failure occurs, the reason for causing the failure can be edge oxidation or packaging failure of the battery piece, the brightness of the edge of the battery piece region in the electroluminescent image is low, not greater than the fourth preset brightness value, and the corresponding defect type attenuation coefficient can be 60%.

[0104] wherein the brightness of the battery piece can be determined according to the gray value of different pixel points, specifically, the gray value calculation expression is:

[0105] ;

[0106] ;

[0107] is the gray value of the pixel point, R, G and B are color values of the photo pixel point, which are red, green and blue respectively, Xg is the average gray value of the single battery piece, and j is the total number of pixel points of the single battery piece.

[0108] It should be noted that the difference between the local dark spot failure and the slight, medium and severe fragment failure is that the edge of the low brightness area of the battery piece in the slight, medium and severe fragment failure is clearer, while the edge of the low brightness area of the battery piece in the local dark spot failure is more blurred, and the image recognition technology can be further trained to improve the accuracy of the fault type classification.

[0109] Please refer to Figure 5 , Figure 5A schematic diagram of an electroluminescent image with black piece failure is provided in the present application, which includes 6x10=60 pieces of cell pieces, the brightness of the whole piece of cell piece in the second piece from left to right in the fifth row from top to bottom and the first piece from right to left in the sixth row from top to bottom is not greater than the fourth preset brightness value, therefore, the two pieces of cell pieces have black piece failure. The third piece from left to right in the third row from top to bottom has local dark spot failure, the first piece from right to left in the first row from top to bottom has serious broken piece failure, the second piece from right to left in the first row from top to bottom has moderate broken piece failure, the second piece from left to right in the sixth row from top to bottom has black edge failure, the fourth piece from left to right in the second row from bottom to top has local dark spot failure, and the fifth piece from left to right in the second row from bottom to top has light broken piece failure. Compared with the local dark spot failure, the boundary of the light broken piece failure is clearer.

[0110] As a preferred embodiment, the photovoltaic module includes a plurality of cell circuits, and each cell circuit includes a plurality of cell pieces and a diode connected in series, the diodes in each cell circuit are connected in series between the output positive terminal and the output negative terminal of the photovoltaic module in turn, and the brightness of each cell piece is not greater than the fourth preset brightness. The whole cell circuit with diode breakdown abnormality; before determining the internal defect type cell piece decay rate based on the decay coefficient of each defect type, it further includes: determining the second target number of cell circuits with diode breakdown abnormality; determining the internal defect type cell piece decay rate based on the decay coefficient of each defect type, including: combining the decay coefficient of each defect type and the second target number, determining the internal defect type cell piece decay rate based on the internal defect type cell piece decay rate expression; the internal defect type cell piece decay rate expression is:

[0111] ;

[0112] wherein, the internal defect type cell piece decay rate, the number of cell pieces with the i-th defect type other than diode breakdown abnormality, the defect type decay coefficient of the i-th defect type, the number of remaining cell pieces in the photovoltaic module other than the cell pieces in the cell circuit with diode breakdown abnormality, m is the second target number, and M is the total number of cell circuits in the photovoltaic module, the rated efficiency of the photovoltaic module.

[0113] Please refer to Figure 6 , Figure 6 a connection diagram of each cell piece in a photovoltaic module is provided in the present application. Figure 6The battery piece with middle white color is a normal battery piece, and the battery piece with gray or black color is a battery piece with hot spot or any of the above faults, such as a battery piece with slight fragment fault, a battery piece with moderate fragment fault, a battery piece with serious fragment fault, a battery piece with local dark spot fault, a battery piece with whole dark piece fault, a battery piece with black piece fault, a battery piece with bright spot fault, or a battery piece with black edge fault.

[0114] The internal defect type battery piece decay rate is determined in combination with the defect type decay coefficients corresponding to different fault types. Specifically, the product of the number of battery pieces corresponding to the defect types of the battery piece breakage and the battery piece gray abnormality and the corresponding defect type decay coefficients is added to obtain a sum. The sum is divided by the number of the remaining battery pieces in the photovoltaic module except for the battery pieces in the battery circuit with diode breakdown abnormality. The sum is added to the proportion of the second target number of the battery circuit with diode breakdown abnormality to the total number of the battery circuits in the photovoltaic module. The sum is multiplied by the rated efficiency of the photovoltaic module, and the product is the power decay of the photovoltaic module caused by different fault types.

[0115] The left side of the plus sign specifically refers to the product of the number of battery pieces with slight fragment fault and the defect type decay coefficient corresponding to the slight fragment fault. The product is added to the product of the number of battery pieces with moderate fragment fault and the defect type decay coefficient corresponding to the moderate fragment fault. The product is added to the product of the number of battery pieces with serious fragment fault and the defect type decay coefficient corresponding to the serious fragment fault. The product is added to the product of the number of battery pieces with local dark spot fault and the defect type decay coefficient corresponding to the local dark spot fault. The product is added to the product of the number of battery pieces with whole dark piece fault and the defect type decay coefficient corresponding to the whole dark piece fault. The product is added to the product of the number of battery pieces with black piece fault and the defect type decay coefficient corresponding to the black piece fault. The product is added to the product of the number of battery pieces with bright spot fault and the defect type decay coefficient corresponding to the bright spot fault. The product is added to the product of the number of battery pieces with black edge fault and the defect type decay coefficient corresponding to the black edge fault. The result is divided by the number of the remaining battery pieces in the photovoltaic module except for the battery pieces in the battery circuit with diode breakdown abnormality.

[0116] For diode breakdown abnormality, if the diode in the battery circuit has breakdown abnormality, the entire battery circuit cannot output current even if each battery piece in the battery circuit is normal. In the electroluminescent image, the entire battery circuit is black, and the defect type decay coefficient is 100%. The power of the entire string of battery pieces is 0. Please refer to Figure 7 , Figure 7 The present application provides a schematic diagram of the electroluminescent image with diode breakdown abnormality. Figure 7 The battery circuit in the middle two columns in FIG. 1 has diode breakdown abnormality. The area where the battery circuit is located is completely black, and no current passes through.

[0117] As a preferred embodiment, the comprehensive failure attenuation rate of the defective assembly is determined based on the hot spot temperature rise energy efficiency attenuation rate and the internal defect type cell piece attenuation rate, comprising: determining the sum of the hot spot temperature rise energy efficiency attenuation rate and the internal defect type cell piece attenuation rate as the comprehensive failure attenuation rate of the defective assembly.

[0118] When the photovoltaic assembly has both infrared hot spot and breakage defects, the energy efficiency loss of the assembly in both cases needs to be considered comprehensively, and the expression of the comprehensive failure attenuation rate of the defective assembly is as follows:

[0119] , wherein, is the comprehensive failure attenuation rate of the defective assembly, is the hot spot temperature rise energy efficiency attenuation rate, is the internal defect type cell piece attenuation rate.

[0120] As a preferred embodiment, the failure degree of the photovoltaic assembly is determined based on the comprehensive failure attenuation rate of the defective assembly, comprising: determining a first attenuation threshold, a second attenuation threshold and a third attenuation threshold, the first attenuation threshold, the second attenuation threshold and the third attenuation threshold are sequentially increased; if the comprehensive failure attenuation rate of the defective assembly is not greater than the first attenuation threshold, it is determined that the failure degree of the photovoltaic assembly is no failure; if the comprehensive failure attenuation rate of the defective assembly is greater than the first attenuation threshold but not greater than the second attenuation threshold, it is determined that the failure degree of the photovoltaic assembly is light failure; if the comprehensive failure attenuation rate of the defective assembly is greater than the second attenuation threshold but not greater than the third attenuation threshold, it is determined that the failure degree of the photovoltaic assembly is moderate failure; if the comprehensive failure attenuation rate of the defective assembly is greater than the third attenuation threshold, it is determined that the failure degree of the photovoltaic assembly is severe failure; the failure degrees of no failure, light failure, moderate failure and severe failure are sequentially increased.

[0121] In determining the failure degree of the photovoltaic assembly, the defective assembly comprehensive failure attenuation rate can be divided according to the size, specifically, the first attenuation threshold, the second attenuation threshold and the third attenuation threshold can be set according to the nominal first year power attenuation rate q of the photovoltaic assembly and the annual power attenuation rate of the photovoltaic assembly, for example, the first attenuation threshold is q+n , the second attenuation threshold is q+n +10%, and the third attenuation threshold is q+n +20%, which is not limited in the present application and can be set according to actual needs.

[0122] When ≤q+n , it can be determined that the power loss of the photovoltaic assembly is mainly caused by aging, which is within the acceptable range of normal loss, the defect degree of the photovoltaic assembly can be ignored, and it is in no failure state and no other consideration is needed; when q+n ≤ ≤q+n At +10%, the photovoltaic module has a minor defect, which is considered a minor fault; regular monitoring is recommended. When q+n +10%≤ ≤q+n At +20%, the photovoltaic module exhibits a moderate fault, impacting the overall power generation of the power station and posing a safety hazard; replacement of the photovoltaic module is recommended. >q+n When the voltage drops by 20%, the module has a severe fault, the overall efficiency of the photovoltaic module is low, and there is a significant safety hazard. It is recommended to replace the photovoltaic module in a timely manner.

[0123] As a preferred embodiment, after determining the degree of failure of the photovoltaic module based on the comprehensive failure attenuation rate of the defective components, the method further includes: determining the power loss value of the photovoltaic module based on the comprehensive failure attenuation rate of the defective components, the theoretical power generation of the photovoltaic module, the power generation time of the photovoltaic module under full load, and the time when the degree of failure of the photovoltaic module is greater than the time without failure.

[0124] For faulty photovoltaic (PV) modules, the power loss value can be calculated by combining the overall fault attenuation rate of the defective module, the theoretical power generation of the PV module, the power generation time of the PV module under full load, and the time when the fault severity of the PV module is greater than the time without fault. This is a dynamic loss value, meaning that the power loss of the power station is directly proportional to the duration of the PV module fault. The expression for calculating the power loss value is as follows: Where E is the power loss value, Let t represent the theoretical power generation of the photovoltaic module, and t represent the power generation time of the photovoltaic module under full load in a day. This refers to the time during which the degree of failure of a photovoltaic module exceeds the time during which there is no failure, that is, the duration of any one or more failures among mild, moderate and severe failures in a photovoltaic module.

[0125] Based on this, users can determine the losses caused by photovoltaic module failures according to the power loss value and take corresponding remedial measures.

[0126] Please refer to Figure 8 , Figure 8A structural schematic diagram of a photovoltaic module detection system provided by the present application is shown in the figure, comprising: an acquisition unit 81 for acquiring an infrared thermal imaging photo and an electroluminescence image of a photovoltaic module; a first determination unit 82 for determining the highest temperature of each hot spot on the surface of the photovoltaic module based on the infrared thermal imaging photo, and determining a dynamic environmental impact factor based on the highest temperature; a second determination unit 83 for determining a hot spot temperature rise energy efficiency decay rate based on the highest temperature and the dynamic environmental impact factor; a third determination unit 84 for determining the fault type of each cell piece with a fault in the photovoltaic module based on the electroluminescence image, and determining the defect type decay coefficient corresponding to each fault type respectively; a fourth determination unit 85 for determining an internal defect type cell piece decay rate based on each defect type decay coefficient; and a fifth determination unit 86 for determining a defect module comprehensive fault decay rate based on the hot spot temperature rise energy efficiency decay rate and the internal defect type cell piece decay rate, and determining the fault degree of the photovoltaic module based on the defect module comprehensive fault decay rate.

[0127] For the photovoltaic module detection method provided by the present application, please refer to the above method embodiments, which will not be repeated here.

[0128] For the photovoltaic module detection method provided by the present application, please refer to the above method embodiments, which will not be repeated here. Figure 9 , Figure 9 A structural schematic diagram of a photovoltaic module detection device provided by the present application is shown in the figure, comprising: a memory 91 for storing a computer program; and a processor 92 for implementing the steps of the photovoltaic module detection method as described above when executing the computer program.

[0129] For the photovoltaic module detection device provided by the present application, please refer to the above method embodiments, which will not be repeated here.

[0130] For the photovoltaic module detection device provided by the present application, please refer to the above method embodiments, which will not be repeated here. Figure 10 , Figure 10 A structural schematic diagram of a computer readable storage medium provided by the present application is shown in the figure, wherein the computer readable storage medium 101 stores a computer program 102, and the computer program 102 is executed by the processor 92 to implement the steps of the photovoltaic module detection method as described above.

[0131] For the computer readable storage medium provided by the present application, please refer to the above method embodiments, which will not be repeated here.

[0132] It is also noted that, in this disclosure, relational terms such as first and second, and the like, can be used solely to distinguish one entity or action from another entity or action without necessarily requiring or implying any actual such relationship or order between such entities or actions. Moreover, the terms "comprises," "comprising," or any other variation thereof, are intended to cover a non-exclusive inclusion, such that a process, method, article, or apparatus that comprises a list of elements does not include only those elements but can include other elements not expressly listed or inherent to such process, method, article, or apparatus. An element proceeded by "comprises... a" does not, without more constraints, exclude the existence of additional identical elements in the process, method, article, or apparatus that comprises the element.

[0133] The above description of disclosed embodiments provides enabling concepts for practicing or using the application. Various modifications to these embodiments will be readily apparent to those skilled in the art, and generic principles defined herein can be applied to other embodiments without departing from the spirit or scope of the application. Thus, the present application is not intended to be limited to the embodiments shown herein but is to be accorded the widest scope consistent with the principles and novel features disclosed herein.

Claims

1. A photovoltaic module inspection method characterized by, The method comprises the following steps: acquiring an infrared thermal image and an electroluminescence image of a photovoltaic module; determining the maximum temperature of each hot spot on the surface of the photovoltaic module based on the infrared thermal image, and determining a dynamic environmental influence factor based on the maximum temperature; determining a hot spot temperature rise energy efficiency decay rate based on the maximum temperature and the dynamic environmental influence factor; determining the fault type of each faulty cell in the photovoltaic module based on the electroluminescence image, and determining a defect type decay coefficient corresponding to each fault type; determining an internal defect type cell decay rate based on each defect type decay coefficient; determining a defect module comprehensive fault decay rate based on the hot spot temperature rise energy efficiency decay rate and the internal defect type cell decay rate, and determining the fault degree of the photovoltaic module based on the defect module comprehensive fault decay rate; before determining the hot spot temperature rise energy efficiency decay rate based on the maximum temperature and the dynamic environmental influence factor, the method further comprises the following steps: determining a target cell number of cells with hot spots on the photovoltaic module based on the infrared thermal image; determining a temperature difference between the maximum temperature and the working environment temperature of the photovoltaic module; determining the hot spot temperature rise energy efficiency decay rate based on the maximum temperature and the dynamic environmental influence factor comprises the following steps: determining the hot spot temperature rise energy efficiency decay rate based on a hot spot area temperature rise loss power expression in combination with the target cell number, the maximum temperature and the dynamic environmental influence factor; the hot spot area temperature rise loss power expression is as follows: ； wherein, is the thermal hotspot temperature rise energy efficiency decay rate, q is the power decay rate of the photovoltaic module in the first year, n is the number of years of operation of the photovoltaic module, is the power decay rate of the photovoltaic module each year, is the temperature difference, is the decay coefficient of the output power of the photovoltaic module decaying with the temperature rise of the photovoltaic module, is the rated efficiency of the photovoltaic module, f is the dynamic environmental impact factor, is the temperature coefficient, a is the target number of cells, and N is the total number of cells in the photovoltaic module.

2. The photovoltaic module inspection method of claim 1, wherein, determining the dynamic environmental influence factor based on the maximum temperature comprises the following steps: determining a convective heat transfer coefficient and a radiative heat transfer coefficient based on the maximum temperature; determining the dynamic environmental influence factor based on a dynamic environmental influence factor expression in combination with the convective heat transfer coefficient and the radiative heat transfer coefficient; the dynamic environmental influence factor expression is as follows: ； wherein f is the dynamic environmental impact factor, k is a dynamic environmental impact factor correction number, is the theoretical power generation of the photovoltaic module, is the convective heat transfer coefficient, is the radiative heat transfer coefficient, A is the surface area of the photovoltaic module, is the maximum temperature.

3. The photovoltaic module inspection method of claim 1, wherein, the photovoltaic module comprises a plurality of cell circuits connected in parallel, and each of the cell circuits comprises a plurality of cells connected in series; before determining the hot spot temperature rise energy efficiency decay rate based on the maximum temperature and the dynamic environmental influence factor, the method further comprises the following steps: determining a first target number of the cell circuits with hot spots on the photovoltaic module based on the infrared thermal image; correcting the temperature coefficient based on the first target number.

4. The photovoltaic module inspection method of claim 1, wherein, determining the fault type of each faulty cell in the photovoltaic module based on the electroluminescence image comprises the following steps: respectively performing image recognition on each cell of the photovoltaic module in the electroluminescence image to determine the faulty cells and the fault type of each faulty cell; the fault type comprises one or more combinations of cell damage, abnormal cell grayscale and diode breakdown abnormality.

5. The photovoltaic module inspection method of claim 4, wherein, before determining the defect type decay coefficient corresponding to each fault type, the method further comprises the following steps: determining each cell with the fault type of cell damage as a first type of faulty cell; respectively determine total area of complete failure region and total area of degradation region in each of the first type of fault battery piece; the complete failure region in the first type of fault battery piece has a brightness value not greater than a first preset brightness value, and the degradation region has a brightness value greater than the first preset brightness value but not greater than a second preset brightness value; the first preset brightness value is less than the second preset brightness value; based on proportions of the total area of complete failure region and the total area of degradation region in the total area of the battery piece, divide the battery piece damage into one or more combinations of slight fragment fault, moderate fragment fault and serious fragment fault; the proportion of the total area of complete failure region or the total area of degradation region in the total area of the battery piece with the slight fragment fault is less than the proportion of the total area of complete failure region or the total area of degradation region in the total area of the battery piece with the moderate fragment fault; the proportion of the total area of complete failure region or the total area of degradation region in the total area of the battery piece with the moderate fragment fault is less than the proportion of the total area of complete failure region or the total area of degradation region in the total area of the battery piece with the serious fragment fault.

6. The photovoltaic module inspection method of claim 4, wherein, Before determining the defect type attenuation coefficient corresponding to each fault type, further comprising: determining each battery piece with battery piece grayscale anomaly as a second type of fault battery piece when the fault type is battery piece grayscale anomaly; respectively calculating the brightness of each region of each of the second type of fault battery piece; based on the brightness of each region of each of the second type of fault battery piece, dividing the battery piece grayscale anomaly into one or more combinations of local dark spot fault, whole piece dark piece fault, black piece fault, bright spot fault and black edge fault; in the battery piece with the local dark spot fault, the proportion of the area of the region with brightness less than a third preset brightness value in the total area of the battery piece is greater than a first preset proportion; in the battery piece with the whole piece dark piece fault, the brightness of the whole piece battery piece is less than the brightness of the normal battery piece; in the battery piece with the black piece fault, the brightness of the whole piece battery piece is not greater than a fourth preset brightness value; in the battery piece with the bright spot fault, there is a region with brightness greater than the brightness of the normal battery piece; in the battery piece with the black edge fault, the brightness at the edge is not greater than the fourth preset brightness value; the third preset brightness value is not less than the fourth preset brightness value.

7. The photovoltaic module inspection method of claim 4, wherein, The photovoltaic module includes a plurality of battery circuits, and each battery circuit includes a plurality of battery pieces and a diode connected in series, and the diodes in each battery circuit are connected in series between the output positive terminal and the output negative terminal of the photovoltaic module, and the brightness of each battery piece is not greater than the fourth preset brightness, and the battery circuit is a battery circuit with diode breakdown anomaly; Before determining the internal defect type battery piece attenuation rate based on each of the defect type attenuation coefficients, further comprising: determining a second target number of battery circuits with diode breakdown anomaly; determining the internal defect type battery piece attenuation rate based on each of the defect type attenuation coefficients, comprising: The internal defect type cell piece attenuation rate is determined based on the attenuation coefficient of each defect type and the second target number according to an internal defect type cell piece attenuation rate expression. The internal defect type cell piece attenuation rate expression is: ； wherein, is the internal defect type cell piece decay rate, is the number of cell pieces with the i-th defect type other than the diode breakdown abnormality, is the defect type decay coefficient of the i-th defect type, is the number of remaining cell pieces in the photovoltaic module other than the cell pieces in the cell circuit with the diode breakdown abnormality, m is the second target number, and M is the total number of cell circuits in the photovoltaic module, is the rated efficiency of the photovoltaic module.

8. The photovoltaic module inspection method of claim 1, wherein, The defect assembly comprehensive failure attenuation rate is determined based on the hot spot temperature rise energy efficiency attenuation rate and the internal defect type cell piece attenuation rate, including: The sum of the hot spot temperature rise energy efficiency attenuation rate and the internal defect type cell piece attenuation rate is determined as the defect assembly comprehensive failure attenuation rate.

9. The photovoltaic module inspection method of any of claims 1-8, wherein, The failure degree of the photovoltaic assembly is determined based on the defect assembly comprehensive failure attenuation rate, including: A first attenuation threshold, a second attenuation threshold and a third attenuation threshold are determined, and the first attenuation threshold, the second attenuation threshold and the third attenuation threshold are sequentially increased; If the defect assembly comprehensive failure attenuation rate is not greater than the first attenuation threshold, it is determined that the failure degree of the photovoltaic assembly is no failure; If the defect assembly comprehensive failure attenuation rate is greater than the first attenuation threshold but not greater than the second attenuation threshold, it is determined that the failure degree of the photovoltaic assembly is mild failure; If the defect assembly comprehensive failure attenuation rate is greater than the second attenuation threshold but not greater than the third attenuation threshold, it is determined that the failure degree of the photovoltaic assembly is moderate failure; If the defect assembly comprehensive failure attenuation rate is greater than the third attenuation threshold, it is determined that the failure degree of the photovoltaic assembly is severe failure; The failure degrees of the no failure, the mild failure, the moderate failure and the severe failure are sequentially increased.

10. The photovoltaic module inspection method of claim 9, wherein, After the failure degree of the photovoltaic assembly is determined based on the defect assembly comprehensive failure attenuation rate, the method further includes: The power loss value of the photovoltaic assembly is determined based on the defect assembly comprehensive failure attenuation rate, the theoretical power generation of the photovoltaic assembly, the power generation time of the photovoltaic assembly in a full load state and the time when the failure degree of the photovoltaic assembly is greater than the no failure.

11. A photovoltaic module inspection apparatus, characterized by, The method includes: A memory for storing a computer program; A processor for implementing the steps of the photovoltaic assembly detection method according to any one of claims 1-10 when executing the computer program.

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