SVG for Solar PV Plants: Reactive Power and Grid Code Compliance

Summary. Specifying an svg for solar pv is different from specifying one for a factory, because the reactive requirement follows the generation profile rather than the production schedule. Inverters must deliver or absorb reactive power across the whole output range, grid codes define voltage support duties at the point of connection, and the plant may need to remain connected and supportive during disturbances. This guide explains what modern grid codes ask of a PV plant, how a static var generator complements inverter reactive capability, how to size for both steady-state and dynamic duties, and what changes when battery storage is added. It closes with a sizing table and a grid-code evidence checklist for EPC contractors.

What Reactive Duties Does a Solar Plant Carry?

A grid-tied inverter can normally deliver a defined reactive range at its terminals, typically expressed as a power factor range such as 0.95 leading to 0.95 lagging at rated output. That capability shrinks as output falls, because the converter's current rating is fixed: at 20 percent output the inverter has spare current for reactive duty, but at full output the reactive capability may be limited by the same thermal constraint that limits active power.

Grid codes add requirements that are not always aligned with that capability. Many require a defined power factor or voltage setpoint at the point of connection, not at the inverter terminals; some require dynamic voltage support during faults; others require reactive capability at zero active output, which inverters generally cannot provide without a separate device. The gap between the requirement and the inverter's capability is where a static var generator is required.

There is also a network-level requirement that has nothing to do with the code: the collection system itself consumes reactive power. Transformers, cables and filters all absorb reactive current, and on a large plant with long feeders the absorption can be significant. A low-voltage SVG for photovoltaic plants compensates both the plant's own absorption and the code requirement at the connection point.

Finally, the timing matters. Reactive demand changes at sunrise, sunset and whenever cloud cover moves across the array. A capacitor bank switched in stages cannot follow that profile smoothly, whereas a converter responds continuously and keeps the voltage at the connection point stable through the transition.

How codes express the requirement. Most define a power factor or reactive current range at the point of connection, sometimes as a function of active output. Some require a defined voltage regulation characteristic with a droop setting, so that the plant supports voltage in proportion to deviation rather than holding a rigid setpoint. Others specify behaviour during and after a disturbance. Reading the clause structure matters more than reading the headline number, because a plant designed to a single power factor figure may still fail a droop or ride-through requirement.

Where capacitors still make sense. A fixed capacitor bank can be an economical way to supply the base reactive demand of a plant's auxiliary loads, provided the resonance check is done and the bank is detuned. The risk is that the tuning assumed one harmonic environment while the inverters introduce another, which is why converter-based compensation is normally preferred where generation dominates.

Why an SVG Earns Its Place in a PV Plant

1. It covers the gap between inverter capability and code requirement. Where the code specifies a power factor at the connection point across the full output range, a converter makes compliance achievable without oversized inverters.

2. It absorbs reactive power when the plant is exporting. Long cable runs and lightly loaded transformers consume reactive power, which can push voltage above the limit at the connection point during high export. An SVG can absorb the excess and hold the setpoint.

3. It maintains support at zero output. At night, inverters are unavailable, yet some codes require reactive capability to remain. A converter supplied from the plant's auxiliary supply can continue to provide it.

4. It responds faster than the inverters themselves. A converter can correct a voltage excursion within milliseconds while inverter control loops are still ramping, which matters for flicker measurements during variable irradiance.

5. It reduces losses in the collection system. Compensating close to the point of connection reduces the reactive current flowing through transformers and cables, lowering I²R losses and freeing capacity in the plant's own equipment.

6. It is modular and can follow plant phases. A 30 kvar SVG for green energy applications can be installed with phase one and paralleled as additional blocks are commissioned, matching compensation to installed capacity.

7. It coordinates with the plant controller. Modern converters accept setpoints from the plant controller, so reactive output can follow a dispatch instruction or a voltage schedule rather than a fixed local setting. That coordination is usually a code requirement in itself.

Losses and efficiency trade-offs. Reactive current flowing through the collection system produces I²R losses, and the loss per kVAr is higher on long feeders. Compensating near the connection point reduces that current and improves the plant's measured efficiency, which matters for performance guarantees and for the operator's revenue calculation. A converter has its own standing losses, so the net benefit depends on feeder length and loading — another reason to calculate rather than assume.

How to Size and Deploy an SVG in a PV or Storage Plant

Step 1 — Read the grid code for the connection point. Identify the required power factor or voltage range, whether it applies at the connection point or the inverter terminals, and whether support is required at zero output and during disturbances. That clause set defines the functional requirement before any sizing calculation.

Step 2 — Calculate the plant's own reactive absorption. Sum transformer reactive loss, cable charging and absorption, and filter reactive consumption at the relevant loading conditions. On a large plant this is often the dominant term.

Step 3 — Compare with inverter capability. Subtract the reactive capability available from the inverters at the applicable output level. The difference, plus a margin, is the device requirement.

Step 4 — Size for the dynamic duty. Check the fastest reactive change the plant will experience: cloud transients, dispatch commands and startup of large auxiliary loads. The converter's response time and short-term overload capability should cover that change without saturating.

Step 5 — Choose the voltage and mounting arrangement. Low-voltage converters are installed at the plant's auxiliary board or the LV side of the station transformer; medium-voltage units at the collection substation. Where space is limited, a 75 kvar 480 V cabinet provides a compact solution for export-oriented projects.

Step 6 — Coordinate with the plant controller and inverters. Define which device regulates voltage and which follows a fixed power factor, and confirm that the inverter's own voltage control is not fighting the converter. Document the priority and the deadband.

Step 7 — Verify with a witnessed test. Most network operators require a reactive capability test at several output levels plus a step response test. Prepare the procedure with the setpoints, the measurement point and the acceptance criteria agreed in advance.

Where the plant includes storage, the PCS can itself provide reactive capability, and the sizing exercise becomes a coordination problem rather than a pure capacity calculation. In that case the converter's role shifts toward fast dynamic support and voltage regulation during transitions, while the PCS handles steady-state setpoints. A modular SVG for distorted grids is often the better choice in these plants because it can be expanded as storage blocks are added, and the SVG range covers wall, rack and cabinet formats for different plant layouts.

Working with the network operator early. Reactive capability requirements are frequently clarified through a study submitted during the interconnection process. Engaging the operator before the equipment is specified avoids the situation where a plant is built to one interpretation and assessed against another. Document the agreed characteristic — setpoints, response, measurement point — and design the control system to reproduce it exactly during the witnessed test.

Documenting the reactive model. Keep the calculation that established the requirement, including transformer impedance, cable data, inverter capability curves and the code clause referenced. When the operator asks why the device was sized as it was, that document answers the question and demonstrates that the design was not arbitrary. It also makes the next plant in the portfolio faster to specify.

Consider the plant's auxiliary load. Tracking systems, cooling, monitoring and battery HVAC consume reactive power and change with the season. A converter can compensate those loads as well as the connection-point requirement, which is often overlooked when the design focuses only on generation.

Sequencing with plant commissioning. Reactive capability must be demonstrated before commercial operation, so the converter's commissioning has to align with the plant's energisation programme rather than follow it. Plan the auxiliary supply, control integration and test window in the construction schedule; discovering at the end that the test requires a full-output day in winter is the sort of detail that delays payment milestones.

FAQ

Do PV inverters already provide reactive power?

Yes, within a defined range that usually shrinks at high active output and disappears at night. Where the code requires reactive capability at the point of connection across all conditions, a separate device is normally needed to close the gap.

Why does a PV plant need reactive absorption?

Long collection feeders and lightly loaded transformers consume reactive power, and excessive export can push voltage above the limit. Absorbing reactive power at the connection point brings voltage back into range, which is often a code requirement.

Can a capacitor bank be used instead?

It can supply reactive power, but it cannot absorb it, cannot follow fast changes smoothly, and interacts with network resonance. For plants with variable output and grid-code duties, a converter is the practical choice.

How do I size the SVG for a plant with storage?

Start from the code requirement at the connection point, subtract what the PCS and inverters can provide at each operating state, and size for the fastest reactive transition. Coordinate control so devices do not oppose each other.

Is a medium-voltage SVG needed for utility-scale plants?

Often yes, because the reactive requirement scales with plant size and connecting at MV avoids large LV cable runs. Smaller plants and LV-connected sites can use LV converters at the auxiliary or station board.

What tests will the network operator require?

Typically a reactive capability test at several output levels, a step response test and evidence of coordination with the plant controller. Some operators also require verification of behaviour during voltage disturbances.

Conclusion

Reactive compensation in a PV plant is defined by the grid code, the collection system's own absorption and the inverters' shrinking capability at high output. Measure each term, size for the dynamic transitions rather than a single steady value, coordinate control with the plant controller, and prepare the witnessed test in advance. On most utility-scale plants the result is a converter at the connection point, supplemented by inverter capability rather than replaced by it.

Working on a PV or storage interconnection? Send us the grid-code clause, single-line diagram and inverter data, and we will calculate the reactive gap, size the converter and draft the test procedure. Contact our renewables team.