A protection study for a solar farm or BESS connection proves that the plant's protection will detect and clear faults correctly, and that it coordinates with the network's own protection. It has three parts: a fault level study, a coordination and grading study, and a set of relay settings. The connecting DNSP or TNSP reviews all three before it will let the plant energise.
It is rarely what a developer worries about early, and often what holds up the last weeks before energisation.
Why Inverter Fault Contribution Complicates Protection
Conventional protection was designed around synchronous generators. A synchronous machine delivers a large fault current, often five to seven times its rated current in the first cycles, and that current is easy for a relay to see.
Inverters limit fault current electronically, typically to around 1.0 to 1.5 times rated current, and its shape is set by control software rather than physics. That creates three problems.
Fault current is small and close to load current
An overcurrent relay cannot tell a fault from heavy export by magnitude alone when the two are almost the same. Inverter-only feeders may never trip a conventional overcurrent element.
The response depends on the control mode
During a fault the inverter injects reactive current according to its fault ride-through settings, which are themselves part of the Generator Performance Standards. Negative sequence current may be suppressed or injected depending on the OEM and the settings. Directional and distance elements that expect a classic machine response can misoperate.
The plant also has to stay connected
Protection that is too sensitive will disconnect a plant the GPS says must ride through. Settings must clear plant faults fast while leaving the plant online for external ones.
For most solar and BESS connections, the fault current that actually operates the protection comes from the network side. That is why the NSP's fault level data is the starting point for everything else.
Fault Level Study: Inputs and Scenarios
The fault level study calculates the fault currents at every protected point in the plant: the connection point, the main transformer, the collector switchboard, each MV feeder and the inverter or PCS transformers.
Inputs from the NSP
The NSP supplies the network equivalent at the connection point. That normally means maximum and minimum three-phase and single-phase fault levels, X/R ratios, and sometimes a future-network case that includes committed nearby generation or network augmentation. Earthing arrangements on the network side also matter, because they set how much earth fault current flows.
From the project side, the study uses the transformer impedances and vector groups, cable data from the electrical design, the earthing design, and the OEM's fault current characteristic for the inverters or PCS.
Scenarios that matter
| Scenario | Why it is studied |
|---|---|
| Maximum network fault level, all plant in service | Sets equipment fault ratings and the highest currents relays must withstand |
| Minimum network fault level, system normal | Tests whether relays still see faults when the grid is weakest |
| Minimum fault level with a network outage | Common worst case for sensitivity; often where settings fail |
| Plant only, network disconnected | Confirms protection behaviour if the plant is islanded |
| Future network case | Avoids settings that work today and fail once nearby plant or augmentation commissions |
Minimum fault level cases are where protection most often struggles. A weak connection point that already needs detailed system strength work in PSS/E and PSCAD usually also has protection sensitivity issues.
The study normally follows IEC 60909 or an equivalent method, using the same network model as the load flow studies.
Coordination: Grading, Interface Protection, Anti-Islanding and Intertrip
Coordination means each relay operates for faults in its own zone, faster than anything upstream, and stays stable for faults elsewhere. For a solar farm or BESS this splits into plant-internal protection and the interface with the network.
Grading inside the plant
Typical grading runs from inverter or PCS protection, through the MV feeder relays and the main transformer, up to the connection point. Time margins between graded stages are commonly in the range of 0.2 to 0.4 seconds, depending on relay type and breaker operating times.
Main transformer protection usually includes differential protection, restricted earth fault and backup overcurrent. Collector feeders use overcurrent and earth fault, with directional elements where multiple feeders can back-feed a fault. Larger connections, especially at transmission voltages, add line differential or distance protection on the connection assets.
Interface protection
The interface protection is what the NSP cares about most. It disconnects the plant when network conditions go outside agreed limits. Typical functions include:
Common Interface Protection Functions
- Under and over voltage: staged settings that respect the plant's fault ride-through obligations
- Under and over frequency: set to coordinate with the network's frequency response requirements
- Neutral voltage displacement: detects HV earth faults where the plant's transformer gives no earth reference, especially after the upstream breaker opens
- Directional overcurrent or reverse power: limits export or detects faults fed from the plant
- Check synchronising: prevents closing onto a dead or out-of-phase network
The exact functions and settings come from each NSP's technical requirements and the connection agreement. They differ between networks, so a philosophy accepted by one DNSP cannot be assumed to pass with another.
Anti-islanding
An island forms when part of the network is disconnected but the plant keeps energising it, a hazard for line crews and for equipment on reclose. For larger plant, passive voltage and frequency protection may not detect it, because a plant closely matching local load can hold the island within limits.
Intertrip
Where passive methods cannot guarantee island detection, the NSP will usually require an intertrip: a direct signal from the network circuit breaker that trips the plant when the upstream breaker opens. Intertrip needs a reliable communications path, often fibre, and a defined failure mode. It is also one of the more common late-stage scope surprises, so it is worth confirming early.
Settings Files and the NSP Review Loop
NSPs want more than a report: the study, the coordination curves and the relay settings files in the manufacturer's native format.
A typical submission includes:
- The protection philosophy, with zones of protection marked on the single-line diagram.
- The fault level study and its scenarios.
- Time-current grading curves for each protection path.
- Interface protection settings with justification against the NSP's requirements and the plant's GPS.
- Relay settings files and a CT and VT schedule, including CT sizing checks.
- Intertrip and communications schematics where applicable.
How the review usually runs
Two or three rounds of comments are normal, each commonly taking a few weeks. The time depends more on NSP workload and the completeness of the first submission than on technical content.
Typical comments cover settings that conflict with fault ride-through, CTs that saturate at maximum fault level, missing minimum fault cases and intertrip failure modes. Most are avoidable when the GPS, fault study and protection design are coordinated.
The protection design also feeds the IFC design package, because secondary system drawings, panel layouts and cable schedules depend on the final relay selection. Changing protection philosophy after IFC is expensive.
Testing: Secondary Injection, End-to-End and Commissioning
Approved settings must be proven on site, usually in three layers.
Relay secondary injection
A test set injects voltages and currents into each relay's secondary inputs, confirming pickups, time delays and logic against the approved settings.
Primary injection and CT checks
Primary injection confirms CT ratios, polarity and wiring from the primary conductor through to the relay. Our article on current injection testing for solar farms covers related earthing and injection testing on site.
End-to-end and intertrip tests
Line differential and intertrip schemes are tested end to end, with both ends of the scheme operated together, often with the NSP witnessing. Breaker trip tests confirm the full chain from relay to circuit breaker.
The NSP usually witnesses or reviews the test results for interface protection before it allows energisation. Incomplete or unsigned protection test records are a common reason a planned energisation date moves. Our walkthrough of commissioning a 5 MW solar farm shows where protection testing sits in the sequence.
When Protection Studies Happen in a Project
A preliminary protection review belongs in the connection application, because the NSP will want to see the protection philosophy alongside the single-line diagram. Our checklist of what documents a DNSP needs covers how this fits the wider application.
The detailed study follows in detailed design, once the inverter, transformers and relay types are fixed. Starting too late compresses the NSP review into the commissioning window, where every week costs revenue.
Get Protection Design and Studies
ElectraGlobe carries out fault level studies, protection coordination and relay settings for solar farms, BESS and hybrid plants connecting to distribution and transmission networks, and supports the NSP review through to witnessed testing. See our detailed engineering service, or contact us to discuss your connection.
Frequently Asked Questions
What is included in a protection study?
A protection study normally includes a fault level study across several network scenarios, a protection philosophy and zone diagram, coordination and grading curves, interface protection settings, CT and VT sizing checks, and the relay settings files themselves. Where intertrip is required, it also covers the scheme design and its failure modes.
Who sets the protection settings at the connection point?
The plant owner's designer calculates and proposes the settings for the plant's protection, including the interface protection. The connecting NSP specifies the requirements, reviews the proposed settings and must accept them before energisation. The NSP sets its own network-side relays, so coordination across the boundary depends on both parties sharing data.
Why do inverters make protection harder?
Inverters limit fault current, typically to around 1.0 to 1.5 times rated current, so faults can look like full-load export. Their response is set by control software and fault ride-through settings, which can confuse protection designed around synchronous machines.
When are protection studies done in a project?
A preliminary protection philosophy goes into the connection application. The detailed study is done in detailed design, once equipment is selected. Final settings go to the NSP for review ahead of commissioning, then are proven by testing before energisation.