6 Important Items for Solar Irradiation Condition Settings from the PVSyst Manual

Table of Contents

• Positioning of solar radiation condition settings in PVSyst

• Important Item 1: Confirm the source of the meteorological data and the target location

• Important Item 2: Understand global horizontal irradiance and diffuse irradiance

• Important item 3: Correctly assess the conversion to inclined-surface irradiance

• Important Item 4: Do not underestimate albedo and surface reflection

• Key point 5: Consider far-field occlusion and near-field occlusion separately

• Important Item 6: Check monthly and hourly variability and uncertainty

• Common Mistakes When Setting Solar Radiation Conditions

• Verification Procedures for Using the PVSyst Manual in Practice

• Summary

Positioning of Solar Radiation Condition Settings in PVSyst

When conducting an energy-yield simulation of a photovoltaic power system in PVSyst, the first thing to check carefully is the solar irradiance conditions. Module capacity, power conditioner, wiring losses, temperature losses, and shading conditions are also important, but all of these are based on the premise of "how much solar irradiance reaches that location."

If the solar irradiance conditions are incorrect, no matter how precisely you adjust equipment settings, the reliability of the final annual and monthly energy yield will decrease.

Reading the PVSyst manual makes clear that meteorological data are the starting point for project assessment and at the same time a major source of uncertainty. In PVSyst, meteorological data, geographic location, solar radiation components, conversion to tilted surfaces, shading, reflections, incidence-angle losses, and so on are linked together to ultimately calculate the irradiance that effectively reaches the solar cells. In other words, the solar irradiation condition settings are not merely initial inputs but the foundation of the entire simulation.

In practice, it is more important to understand what the numbers mean, how well they are justified, and over what range they affect the results than simply whether you can enter values into PVSyst’s interface. For example, even with the same system capacity, the perceived annual energy production can vary depending on the type of meteorological data used, the choice of location, the treatment of diffuse irradiance, ground surface albedo, and shadows from surrounding terrain or buildings. Therefore, the purpose of learning the solar irradiance settings in the PVSyst manual is not merely to memorize operating procedures; it is to develop the ability to judge whether the design conditions are reasonable, whether you can fulfill accountability, and whether they can be used for comparative evaluations.

Important Item 1: Confirm the source of the meteorological data and the target location

What you should first check when setting solar irradiation conditions is which meteorological data to use. In PVSyst, simulations are run using meteorological data files. Meteorological data can include representative year data, time-series data based on actual measurements, synthetic data generated from monthly data, data that incorporate external sources, and so on. In PVSyst's meteorological data, global horizontal irradiance, diffuse horizontal irradiance, and ambient air temperature are treated as important basic inputs.

What is important here is not to stop at simply "choosing data from a nearby location." The solar irradiation environment changes depending on the distance between the planned power plant site and the meteorological data point, the elevation difference, whether it is coastal or inland, mountainous or flat, and whether the area experiences heavy snowfall or fog. Even if the latitude and longitude are close, differences in terrain and weather patterns can cause variations in annual solar radiation and its seasonal distribution.

For projects within Japan, the NEDO solar radiation database is sometimes consulted. PVSyst's documentation mentions METPV-20, which handles hourly data, and MONSOLA-20, which handles monthly data, as solar radiation data for Japan. In practice, it is important to compare such domestic data, satellite-derived data, data from weather companies, and on-site observational data and consider which data are appropriate to adopt.

Also, when using PVSyst results in business plans or in explanations for financial institutions, it is necessary to clearly state the source of the meteorological data used. Confirming which database was used, how many years of representative data it covers, whether the data are monthly or hourly, and whether any missing-data imputation or transformation processing was performed will make it easier to justify the estimated power generation later.

When using the PVSyst manual, it is important not only to know how to import meteorological data but also to understand the characteristics of the data. In particular, annual irradiation at the same site can differ depending on the data source. If the difference is small, it can be managed through a data selection policy, but if it is large, you need to verify why the discrepancy occurs. Differences in solar radiation data translate directly into differences in power generation forecasts, so they should be handled carefully at an early stage.

Important Point 2: Understand global horizontal irradiance and diffuse irradiance

To handle solar irradiation conditions correctly in PVSyst, you need to understand not only the global horizontal irradiance but also the relationships between diffuse irradiance and direct irradiance. In PVSyst notation, global horizontal irradiance is referred to as GlobHor, horizontal diffuse irradiance as DiffHor, direct normal irradiance as BeamNorm, and the horizontal direct component as BeamHor. In PVSyst’s radiation model, the global horizontal irradiance is decomposed into the diffuse component and the horizontal direct component, and this decomposition is relevant to subsequent shading calculations and tilted surface conversions.

In photovoltaic practice, people tend to focus only on the total annual solar radiation. However, even with the same annual total, the calculated amount of radiation reaching an inclined surface differs between regions with a high proportion of direct irradiance and regions with a high proportion of diffuse irradiance. Because direct irradiance has strong directionality from the sun, it is more affected by azimuth and tilt angles and by shading. On the other hand, diffuse irradiance is treated as a component arriving from the entire sky, so its response to shading and to conversion for an inclined surface is different.

For example, in mountainous areas or regions with frequent cloud cover, the proportion of diffuse irradiance can be relatively large. In coastal or arid regions, the proportion of the direct component may be higher. In PVSyst simulations, these differences in components affect tilted-surface irradiance, shading losses, incidence angle losses, and the final effective irradiance.

When consulting the PVSyst manual, it is important not to follow only the terms for irradiance, but to be aware of which components are used at which stages. The reliability of the results and how they should be explained differ depending on whether diffuse irradiance is included in the input data or is estimated by a model. If measured diffuse irradiance is available, the accuracy of conversion to tilted surfaces can improve; however, since many datasets do not directly measure the diffuse component, it is necessary to read the results assuming model estimation.

What designers need to check is what the input data contains. The calculation flow changes depending on whether it is only global horizontal irradiance, also includes diffuse irradiance, includes direct normal irradiance, or is handled in a special way such as back-calculating from tilted-surface irradiance. When comparing PVSyst results, it is essential to verify that the input conditions for the irradiance components are consistent, rather than simply looking at differences in energy production.

Important Point 3: Correctly assess the conversion to solar irradiance on tilted surfaces

Photovoltaic modules are typically installed with a certain tilt and azimuth rather than on a horizontal plane. Therefore, horizontal-plane solar irradiance cannot be used directly for power generation calculations. In PVSyst, horizontal-plane irradiance data are converted into the tilted-plane irradiance incident on the module surface. This process is called transposition, and PVSyst handles models such as the Hay or Hay-Davies model, the Perez model, and others.

This tilted-surface conversion is one of the aspects of the solar irradiance settings that greatly influences the results. This is because, even with the same horizontal-plane irradiance, the amount of irradiance reaching the module surface changes depending on the installation angle and orientation. Whether the array is south-facing or east–west-facing, whether the tilt angle is low or high, and whether the mounting is fixed or tracking, the annual pattern of incident irradiance differs significantly.

The PVSyst manual shows that the conversion to tilted-surface irradiance is handled by separating it into direct, diffuse, and albedo components. In particular, the treatment of the diffuse component varies by model: the Perez model accounts for a more detailed sky distribution but is also more sensitive to the quality of the input data. In PVSyst, the Perez model is currently used as the standard, but in past configurations and comparison cases there are instances where differences with the Hay model are checked.

In practice, if the tilt angle and azimuth are entered incorrectly, the entire simulation can be off even before setting the solar irradiance conditions. It is necessary to correctly sort out the orientation on the drawings, the difference between true north and magnetic north, roof pitch, racking pitch, slope of the developed land, and differences in orientation for each array. Especially for roof installations with multiple orientations or east–west racking, a single azimuth and tilt angle alone may not be able to represent the actual situation.

Also, irradiance on the tilted plane affects monthly generation trends. Low tilt tends to be advantageous in summer, while high tilt can capture more winter irradiance. For self-consumption projects, not only maximizing annual output but also matching the load curve with the generation curve is important. When checking tilted-plane irradiance in PVSyst, it is important to look not only at annual generation but also at month-by-month variations, morning and evening generation, and seasonal peaks together.

Key Point 4: Do not underestimate albedo and surface reflection

Albedo is often overlooked when setting solar irradiance conditions. Albedo refers to the component of solar radiation that is reflected from the ground surface and surrounding surfaces and reaches the module surface. In conventional ground-mounted installations its impact may appear limited, but in projects in snowy regions, with highly reflective paving, white roofs, or using bifacial modules, the way albedo is treated is more likely to affect energy generation.

In PVSyst, when considering the solar irradiance reaching an inclined surface, the direct component, diffuse component, and albedo component are involved. The albedo component is evaluated as reflection from the ground surface, but because the visible ground surface changes depending on nearby obstructions, terrain, and distant shading conditions, it is not appropriate to simply enter a fixed value. PVSyst documentation also indicates that the way the albedo contribution is considered changes depending on the distant horizon and nearby obstruction conditions.

For example, in snowy regions ground surface reflectance can increase during winter. Because snow has a high reflectivity, reflected light can more easily reach the modules even during periods of low solar elevation. At the same time, it is necessary to consider module surface coverage by snow, shading beneath the mounting structure, snow-removal practices, and snow soiling. Setting a high albedo does not necessarily lead to increased actual power generation; consistency with on-site conditions is required.

When using bifacial modules, the importance of albedo becomes even greater. Rear-side power generation is strongly affected by ground surface reflectance, racking height, row spacing, ground color, and shadows from surrounding structures. When modeling bifacial generation in PVSyst, albedo should not be treated as a mere secondary parameter but should be verified as a primary design condition affecting energy yield.

Even for rooftop installations, reflective conditions vary by project—white waterproofing layers, metal roofs, concrete surfaces, etc. However, on roofs equipment, parapets, mounting racks, piping, and shadows from adjacent rows interact in complex ways, so simply entering a high albedo can lead to overestimation. While referring to the PVSyst manual, it is important to determine whether the reflections actually reach the module surface.

Important Item 5: Consider far-field shielding and near-field shielding separately

When setting solar irradiation conditions, the treatment of shadows is also important. In PVSyst, distant shading and near shading are considered separately. Distant shading refers to mountains, hills, distant buildings, and so on, which affect the entire power plant almost uniformly. By contrast, near shading refers to adjacent buildings, parapets, utility poles, trees, rows of mounting structures, equipment, and the like, which cast partial shadows on the module surface. In PVSyst documentation, distant shading is treated as a horizon line, while near shading is described as a complex calculation that requires detailed 3D representation.

A typical example of far shading is a mountain ridge. When the solar altitude is low at sunrise and sunset, solar radiation can be blocked by mountains or hills, affecting annual energy production and winter energy production. In PVSyst, by setting a horizon profile you can account for the times when the sun is visible and when it is not. Far shading has an almost on/off effect on direct irradiance, and it also takes into account the timing within a time step when the sun crosses the horizon.

Proximity shading requires extra care. Partial shading does not necessarily reduce power output simply in proportion to the shaded area. Photovoltaic modules can suffer electrical mismatches from partial shading because of how cells and strings are connected. In PVSyst, proximity shading is addressed not only in terms of irradiance losses but also in terms of the electrical effects resulting from string and module configurations.

A common mistake in practice is confusing far-field shading with near-field shading. For example, if a nearby building is treated simplistically using only a horizon profile, the effects of partial shading may not be adequately represented. Conversely, if a distant mountain is modeled as a detailed 3D obstacle, the model can become overly complex, increasing computational load and the risk of setup errors.

For ground-mounted installations, the treatment of inter-row shading is also important. Morning, afternoon, and winter shading vary depending on the north–south inter-row spacing, tilt angle, racking height, and the sun elevation near the winter solstice. For east–west racking, it is necessary to consider mutual shading between adjacent faces and the irradiance patterns characteristic of low tilt. For roof-mounted installations, the extent to which parapets, roof penthouses, outdoor air-conditioning units, lightning protection equipment, handrails, and adjacent buildings are modeled affects the results.

When reading the PVSyst manual, don’t view shading as a single loss rate; understand that shading is treated differently for the direct, diffuse, and albedo components. In PVSyst, shading calculations are performed hourly and applied in different ways to the direct, diffuse, and albedo components. Understanding this will make it easier to explain why shading impacts vary by season and time of day when you look at the shading loss results.

Key Item 6: Check monthly and hourly variability and uncertainty

One thing to check at the end of setting solar irradiance conditions is the month-by-month and hour-by-hour variability. If you look only at the annual generation, you can miss problems with the irradiance conditions. For example, even if the annual value looks reasonable, there can be cases where winter irradiance is too high, irradiance during the rainy season is too low, generation in the morning and evening is unnatural, or generation in a particular month is extremely high.

In PVSyst, you can check the contents of meteorological data files and understand monthly and hourly trends. Depending on the format of the meteorological data, there may be time-series data, representative-year data, or synthetic data generated from monthly data, and the way to interpret the results differs for each. The PVSyst documentation also shows the process for generating hourly synthetic data when only monthly data are available.

When representative-year data are used, they are expected to show trends close to the long-term average, but they do not necessarily match the actual single-year power generation. When time-series data for a specific year are used, they include that year’s weather bias. For example, using a year with many sunny days tends to produce higher generation, while using a year with many cloudy or rainy days tends to produce lower generation. Therefore, when explaining simulation results, it is important to clarify whether the data used are representative-year data or data for a specific year.

When checking monthly data, verify whether it matches the local climate. In Japan, the effects of the rainy season, typhoons, snowfall, winter sunshine rate, sea breezes, fog, and other factors differ by region. In Hokkaido, Tohoku, the Sea of Japan side, the Pacific side, inland basins, and Okinawa, the seasonal distribution of solar irradiation changes even with the same equipment specifications. When interpreting PVSyst results, don’t just check the annual values—confirm that the regional characteristics are consistent with the shape of the monthly generation profile.

When checking by time of day, we look at morning and evening ramp-up, midday peaks, the effects of shading, and biases in generation time windows due to azimuth. East-facing systems are stronger in the morning, west-facing systems are stronger in the afternoon, and south-facing systems tend to peak around noon. In self-consumption projects, not only the total generation but also the hours that overlap with demand are important. Therefore, setting solar irradiance conditions is important not only for annual generation but also for power usage planning.

Regarding uncertainty, it is also necessary to avoid asserting overly fine numerical differences. PVSyst simulations are detailed, but they do not fully predict meteorological data, future weather, soiling, snowfall, maintenance conditions, or changes in the surrounding environment. Carefully setting solar irradiance conditions is important to improve prediction accuracy, but one should assume that the results will have a certain range of variability.

Common Mistakes in Setting Solar Radiation Conditions

If you proceed with the settings without reading the PVSyst manual, several typical mistakes occur in the solar radiation conditions. The most common is adopting an initial candidate or a seemingly nearby site without checking the source of the meteorological data. Similar place names alone do not guarantee that elevation, terrain, sea breezes, snowfall, or cloudiness patterns will match. When using the data for a commercial feasibility assessment, you must choose data for which you can explain the reasons for selecting it.

Another common mistake is judging solely by annual solar radiation. Even if the annual totals are the same, differences in monthly distribution or hourly distribution change the practical implications. This is especially important for projects that assume self-consumption, battery storage, or output control, since when generation occurs matters. When setting solar radiation conditions, it is necessary to check the annual total, monthly, and hourly distributions separately.

Errors in entering azimuth and tilt angles are also a significant problem. If the orientation on the drawings is not organized relative to true north, entering the angles from the design drawings as-is may introduce errors. For roof installations, azimuth and pitch can vary for each roof surface. For ground-mounted installations, definitions of site grading slope and the tilt angle of the mounting structure can become conflated. If these remain ambiguous when entered into PVSyst, the solar irradiation conditions will not be correctly reflected.

Over-simplifying the treatment of shadows is also a common mistake. Distant mountains should often be treated as horizon profiles, while nearby buildings and equipment may need to be considered as proximate shading. In projects with significant partial shading, it is necessary to consider not only the shaded area but also the electrical effects. PVSyst’s shading functions are powerful, but if used without understanding the modeling intent they can produce results that are either more optimistic or more pessimistic than reality.

Treating the albedo setting as fixed is also a point of caution. Even if differences do not appear large on typical ground surfaces, snow, white roofs, bifacial PV, and highly reflective pavements can affect the results. Conversely, at sites with many obstructions or soiling, overestimating reflectance can lead to an overprediction of energy production. Albedo should be evaluated together with ground surface conditions and module arrangement.

Finally, it is also problematic to look only at the PVSyst results without verifying the validity of the input conditions. Rather than judging that a result is correct because the energy yield is close to the expected value, incorrect because it is low, or good because it is high, it is important to confirm whether the input solar irradiation conditions match the on-site conditions. The PVSyst manual can be used not only as a guide for carrying out the procedures but also as a benchmark for interpreting the results.

Verification Steps for Using the PVSyst Manual in Practice

When using the PVSyst manual in practice, it is efficient to begin by checking the meteorological data. Organize the target site's latitude and longitude, elevation, nearby observation stations, the database to be used, and whether you are using a representative year or a specific year. Then confirm how the global horizontal irradiance, diffuse irradiance, and ambient air temperature are provided. Because meteorological data are the starting point for PVSyst evaluations, it is important not to rush this stage.

Next, we will organize the installation conditions. Confirm the module surface azimuth, tilt angle, mounting structure type, number of roof surfaces, row spacing, mounting height, and whether tracking is used. These are directly related to converting horizontal-plane solar irradiation to tilted-surface irradiation. Because PVSyst’s transposition model is an important process for deriving tilted-surface irradiation from horizontal-plane irradiation, input errors in the installation conditions will lead to errors in the overall solar irradiation conditions.

After that, check the shading conditions. Classify items into those treated as distant shading, those treated as near-field shading, and minor items that will not be modeled. Rather than modeling everything in detail, prioritize those that affect power generation. As a rule, features that uniformly affect the entire site, such as mountains or hills, should be handled as a horizon profile, while objects that cast partial shadows, such as buildings or equipment, should be treated as near-field shading.

Additionally, verify the albedo and ground surface conditions. Classify ground surface reflectance conditions as design conditions, such as bare ground, grassland, concrete, white roofs, and snow. For bifacial systems or regions with snowfall, conducting a sensitivity analysis on how albedo affects the results is also effective. Rather than treating albedo as a single fixed value, adopt a perspective that considers local conditions and seasonal variations.

Finally, we check the output results not only as annual values but also on a monthly and hourly basis. While examining the relationships among irradiance, tilted-surface irradiance, shading losses, and power generation, we confirm that the input conditions and the results are consistent. If generation is extremely low only in winter, we isolate which of the solar irradiance data, snow, shading, or tilt angle is having an effect. If the summer peak appears anomalous, we check not only temperature conditions and output limits but also the solar irradiance conditions themselves.

Thus, when using the PVSyst manual in practice, it is more important to follow how solar radiation data are converted, what losses and corrections they undergo, and how they ultimately become effective irradiance than to memorize the operations for each screen. By understanding the sequence of input, conversion, shading, reflection, and verification, you will be better able to explain the simulation results.

Summary

When learning how to set solar radiation conditions in the PVSyst manual, you must first understand that meteorological data are the starting point for the simulation. The reliability of the results depends on which data are used, whether they match the site, whether they represent a typical year or a specific year, and how the global horizontal irradiance and diffuse irradiance are provided.

Next, it is important to understand the concept of converting horizontal-plane irradiance to module-plane irradiance. In PVSyst, irradiance on a tilted surface is calculated by accounting for direct irradiance, diffuse irradiance, and albedo components. If the azimuth or tilt inputs are off, both the irradiance on the tilted surface and the energy production will change. Carefully verify the consistency among design drawings, site conditions, and input values.

Furthermore, albedo, distant shading, and near shading are also important factors. In particular, in snowy regions, white roofs, bifacial power generation, mountainous areas, and rooftop installations with many building shadows, the way solar irradiance conditions are handled greatly affects the results. Regarding shadows, it is important to consider distant mountains and terrain separately from nearby buildings and equipment.

Finally, the results from PVSyst should not be judged solely by annual energy production; you need to check trends by month and by hour. Even if the annual values appear reasonable, inconsistencies in solar irradiance conditions can be found when viewed by season or time of day. Rather than reading the PVSyst manual as a mere operational guide, use it as a practical document to connect input conditions and calculation results, which will enhance the accuracy and explanatory power of your energy production simulations.