Automated Shading Analysis

Answer: Automated shading analysis uses a site model and calculated sun positions to estimate how obstructions affect a solar array over time. Its outputs may describe shadows, irradiance losses or electrical energy losses; these are different quantities. Automation makes layout comparisons repeatable, but reliable estimates still require verified geometry, appropriate weather and electrical assumptions, and checks against current site conditions.

From a scene to a production estimate

Trees, adjacent buildings, chimneys, HVAC units, fences and terrain can obstruct sunlight. Software can repeat a calculation for revised layouts, but a simulation only includes the objects and behavior represented in its inputs. Remote analysis does not establish that a site visit or project-specific validation is unnecessary.

The workflow has six stages:

1. Build the scene: establish roof geometry, terrain, array locations, coordinates and orientation. Record imagery or survey date and the source of elevation information.
2. Model obstructions: add relevant heights, positions and shapes. Check tree canopy, seasonal foliage and plausible growth or removal scenarios; a tool may not support these explicitly.
3. Calculate sun positions: specify location, time reference and simulation period. Check time zone and timestamp handling rather than assuming a correct animation proves correct timing.
4. Project shadows: calculate obstruction overlap at the chosen time steps. A static snapshot cannot represent annual shade exposure.
5. Calculate irradiance: combine the geometric treatment with weather and the model’s treatment of beam, diffuse and reflected light.
6. Calculate electrical output where supported: use the array’s module arrangement, electrical connections and equipment behavior. Inspect the results and their limitations before accepting a production forecast.

Hourly analysis is common, but not every tool simulates every hour or uses the same resolution. A non-leap year contains 8,760 hours; a leap year contains 8,784. The number of annual hours is not an accuracy measure.

Shadow area is not energy loss

A shadow map describes geometry. An irradiance map describes received solar radiation. An electrical production estimate additionally depends on module and array behavior. Specify whether a reported percentage refers to an instantaneous value, annual irradiation, DC energy or AC energy.

PVsyst’s documented model separates irradiance loss from electrical mismatch loss and treats irradiance components separately. Its detailed module-layout calculation requires module placement and electrical assignment; the simpler partition approach is an approximation. This is a description of PVsyst’s methods, not a claim that all shading tools implement them. PVsyst shading calculation and model.

Hypothetical irradiation comparison: suppose the same array plane and annual weather produce 1,500 kWh/m² without the specified obstructions and 1,380 kWh/m² with them. The modeled irradiation reduction is (1500 − 1380) / 1500 × 100 = 8%. This is not automatically an 8% AC energy loss. Keep weather, geometry, period and irradiance boundary consistent in the comparison.

Shading can change the electrical operating point and activate bypass diodes. Module-level electronics cannot restore sunlight blocked by an obstruction, and any recovered mismatch loss is architecture- and condition-dependent. Avoid claims that shading a given fraction of one module always causes a fixed string loss.

Automated and on-site methods complement each other

There is no universal accuracy or duration for either method. Compare equivalent quantities over equivalent periods before describing a simulation as validated.

A review checklist before issuing a forecast

• Verify obstructions against current site evidence. A tree entered as 30 ft when it is actually 45 ft illustrates an input discrepancy; it does not imply a fixed energy error.
• Inspect winter and summer cases and low-sun periods. Check whether annual totals conceal a concentrated seasonal problem.
• Read the legend on a heat map: units, aggregation period, reference and color scale matter.
• Confirm module orientation, bypass assumptions, strings and inverter inputs where an electrical loss calculation is used. Review auto-stringing suggestions against equipment limits.
• Compare layout alternatives with consistent assumptions. Moving or omitting shaded modules changes capacity and may change economics; compare both total energy and cost.
• Treat tree trimming as a permission, maintenance and environmental decision as well as an energy scenario. Include realistic regrowth and ongoing costs rather than guaranteed lifetime savings.
• Preserve the scene, weather, layout and report revision. Feed site changes back into the design and customer estimate.

For the underlying concept, see shading analysis. To assess which inputs, outputs and validation steps a project needs, review the SurgePV shadow analysis page or book a demo.

Frequently asked questions

Does automation guarantee an accurate production estimate?

No. Missing objects, incorrect heights, stale imagery, weather assumptions and electrical simplifications can all affect results. State the method and validation evidence instead of a universal accuracy percentage.

Does an annual shading analysis remove the need for a site visit?

Not automatically. Verify current conditions and meet the project’s survey, design and installation requirements. Remote analysis can support that process.

Can optimizers eliminate shading losses?

They may reduce some mismatch effects in supported configurations. They cannot recover blocked irradiance, and modeled recovery is not a guaranteed field gain.

What should a shading report identify?

At minimum, the site and array revision, obstruction sources, weather, time treatment, model method, result units and loss boundaries. Include assumptions and unresolved validation items.