Protection Relay Settings for UK Solar PV Systems

Protection Relay Settings for UK Solar PV Systems: The Technical Gap Most EPC Contractors Miss

Over 30% of grid connection applications for solar PV projects in the UK are delayed or rejected at the technical schedule review stage, and a significant proportion of those delays trace directly back to incorrectly specified or uncoordinated protection relay settings for UK solar PV systems. For EPC contractors working toward a G99 submission, this is not a paperwork formality. It is a technically complex engineering deliverable that requires relay coordination studies, DNO-specific setting ranges, and compliance verification against IEC 60255 and BS EN 50549 before a single document lands on the Distribution Network Operator’s desk. Getting this wrong does not just slow down a project. It costs real money, triggers re-submissions, and in some cases forces costly hardware changes after equipment has already been procured.

Why Protection Relay Specification Is Not a Checkbox Exercise

Consider a 4.9 MW ground-mounted solar site in the East Midlands. The EPC contractor submitted a full G99 Schedule 1 pack including a single-line diagram, generation data, and a relay settings table. The relay settings table listed ROCOF at 1.0 Hz/s and vector shift at 6 degrees, values that looked reasonable on paper. The DNO rejected the submission within three weeks. The reason was not that the values were wrong in principle. The issue was that the upstream DNO protection scheme at that particular substation had already been coordinated to operate at a lower ROCOF threshold due to a recent network reconfiguration, and the submitted settings would have created a discrimination gap that could have caused the solar site to remain connected during a genuine islanding event.

That scenario plays out repeatedly across the UK. The root cause is almost always the same: relay settings are populated from a generic template rather than being derived from a coordination study that accounts for the actual DNO network at the point of connection. For any EPC contractor who wants to pass grid connection approval without expensive re-submissions, the protection relay specification must be treated as a live engineering document, not a static template.

G99 and G98 Protection Relay Requirements: Understanding the Split

The first thing an EPC contractor must establish is which engineering recommendation governs the project, because G99 protection relay requirements and G98 requirements differ significantly in their technical depth and DNO interface obligations.

G98 applies to smaller generating units typically below 16 A per phase at low voltage. The protection requirements are largely self-contained within the inverter, which must hold a valid G98 type-test certificate. The EPC contractor’s relay specification role is limited in this context.

G99 applies to generating plants above those thresholds and to all MV-connected installations. Under G99, the EPC contractor is responsible for specifying a full protection scheme that the DNO will scrutinise against their own network requirements. The mandatory relay functions under G99 include:

• Over and under voltage protection with time delay settings that comply with the DNO’s accepted operating range
• Over and under frequency protection coordinated to the GB grid frequency limits
• Loss of Mains (LoM) protection using both passive and active detection methods
• ROCOF (Rate of Change of Frequency) relay with a DNO-approved threshold
• Vector shift relay as a secondary LoM detection mechanism
• Directional overcurrent and earth fault protection for MV-connected sites

Each of these functions must be specified with precise setting values, time delays, and relay model references before the Schedule 1 technical submission. Leaving any of these fields blank or populated with placeholder values guarantees a rejection at technical review.

Loss of Mains Protection: The Most Misunderstood Requirement in Solar PV Relay Coordination UK

Loss of Mains protection is mandatory under G99 for all generating plant connected to the distribution network. Its purpose is to detect islanding conditions, situations where the solar PV plant continues to energise a section of the DNO network after the upstream circuit breaker has opened. An islanded network presents a serious risk to DNO staff working on what they believe to be a de-energised circuit.

The challenge with loss of mains protection solar specification is that it must be coordinated with the DNO’s upstream protection scheme, not just set to a default value. A DNO operating a predominantly rural overhead line network will have different upstream clearing times than one managing an urban underground cable network. The LoM relay settings that work in one geographic area may be entirely inappropriate for another.

In practice, EPC contractors often approach this by running the same ROCOF and vector shift values across every project regardless of connection point. A site in a weakly interconnected rural area where frequency deviations caused by islanding are large and rapid can tolerate different ROCOF thresholds than a site connected to a stiff urban grid. The DNO technical review team will identify this misalignment immediately, because they know the characteristics of their own network.

The correct process is to request the DNO’s protection philosophy document and upstream relay settings as part of the pre-application technical enquiry. Some DNOs publish this information in their connection standards. Others provide it only on request. Either way, the LoM settings cannot be finalised without this information in hand.

ROCOF Relay Solar UK: Setting the Right Threshold for the Right Network

The ROCOF relay solar UK requirement under G99 historically specified a setting of 0.125 Hz/s with a 500 ms measurement window. Following the 2019 and subsequent revisions, this changed significantly. The current G99 requirements reflect the evolving GB grid dynamics, particularly the reduction in system inertia as more inverter-based generation displaces synchronous plant.

What this means in practice is that ROCOF settings that were acceptable for a project submitted five years ago may no longer pass DNO technical review today. EPC contractors specifying relay settings based on previous project records without checking the current version of G99 and the specific DNO connection standard are setting themselves up for rejection.

The ROCOF relay must also be specified with the correct measurement window. A shorter measurement window increases sensitivity to transient frequency events that are not genuine LoM conditions, which leads to nuisance tripping. A longer window may miss fast islanding events. The setting must balance sensitivity against stability, and the correct balance depends on the specific network characteristics at the point of connection.

From a relay hardware perspective, the specified device must be capable of the required measurement window and setting resolution. Not all protection relay devices marketed for solar PV applications can achieve the sub-cycle resolution required for accurate ROCOF measurement on a stiff grid connection. Specifying a relay that fails the DNO’s type-test requirements is another common source of Schedule 1 rejection.

Vector Shift Relay PV Specification: Secondary Protection That Cannot Be an Afterthought

The vector shift relay PV function operates as a complementary LoM detection mechanism alongside ROCOF. Where ROCOF detects islanding through frequency gradient, vector shift detects the sudden angular displacement in voltage waveform that occurs when the upstream supply is disconnected.

A well-remembered case involves a 2.8 MW rooftop solar portfolio across six commercial sites, all connected to a single DNO network area. The EPC contractor specified ROCOF correctly but left vector shift at the factory default setting of 12 degrees. During a planned DNO outage on an adjacent feeder, two of the six sites failed to detect the islanding condition within the required clearance time. The ROCOF rate at those sites was insufficient to trigger the relay because the load and generation were nearly balanced, a classic scenario where ROCOF alone is unreliable. The vector shift at 12 degrees was too insensitive to detect the phase jump, which was only 8 degrees at those connection points.

This is exactly why G99 requires both functions to be active, and why each setting must be derived from an analysis of the expected islanding detection performance at the specific site, not from a default value list. For a thorough approach to solar PV system design that incorporates protection requirements from the outset, reviewing a structured PV solar system design guide is a useful starting point before moving into relay specification.

MV Protection Relay Solar EPC: Directional Elements and Bi-Directional Power Flow

For medium voltage connected solar sites, the protection scheme complexity increases substantially. MV protection relay solar EPC specification must account for the bi-directional nature of power flow at the grid connection point, something that low voltage applications rarely need to address in the same depth.

A conventional non-directional overcurrent relay responds to current magnitude regardless of direction. On a radial distribution network, this is generally sufficient because fault current flows in one direction only. On a solar PV site connected at MV, the generation plant exports current into the DNO network during normal operation. Under certain fault conditions, this export current can be misinterpreted by a non-directional relay as a downstream fault, causing the relay to operate when it should not, or conversely, failing to operate when it should because the fault current direction is not what the relay expects.

Export-limited connections add a further layer of complexity. On an export-limited site, the active power management system periodically reduces inverter output to stay within the agreed export limit. During these curtailment transitions, the current at the grid connection point can change rapidly and may briefly flow in the reverse direction. A protection relay scheme that has not been designed to handle these transient conditions can produce nuisance trips during perfectly normal operational events.

The correct approach is to specify directional overcurrent and directional earth fault elements at the MV interface, with characteristic angles and polarising quantities selected to correctly discriminate between load current, fault current, and reverse power conditions. This requires the protection engineer to have access to the network fault level data from the DNO, which is typically provided as part of the connection offer documentation. Without fault level data, the overcurrent relay settings cannot be properly graded.

Time-Graded Coordination and Discrimination Studies for Solar PV Relay Coordination UK

One of the most technically demanding aspects of solar PV relay coordination UK is the discrimination study between the site protection scheme and the DNO’s upstream relays. Time-graded coordination ensures that for any given fault, the relay closest to the fault operates first, the upstream relay operates only if the downstream relay fails to clear the fault within the required time, and no spurious operation occurs on adjacent healthy circuits.

For a solar PV site, this coordination chain typically involves at least three levels:

1. The inverter-level AC overcurrent protection
2. The MV feeder protection at the site substation
3. The DNO’s upstream protection at the primary substation or grid supply point

The grading margins between these levels are not arbitrary. Each step in the coordination chain must account for the relay operating time tolerance, the circuit breaker interrupting time, and an overshoot allowance. For electromechanical relays, a grading margin of 400 ms was traditional. For modern numerical relays, this can be reduced to 250 to 300 ms. Using the wrong grading margin assumption can result in either over-protection (nuisance tripping) or under-protection (failure to clear faults within the DNO’s maximum fault clearance time requirement).

The discrimination study output must be presented as a time-current characteristic (TCC) plot showing all relays in the protection chain on a single log-log graph. DNOs increasingly require this as part of the technical submission, and sites that submit relay settings tables without the supporting TCC plot are routinely asked to supplement their submission before the review proceeds.

DNO Protection Settings EPC Submission: What Documentation Is Actually Required

Understanding what the DNO expects to receive is half the battle for any EPC contractor preparing a G99 submission. DNO protection settings EPC documentation requirements vary between the major distribution network operators, but a comprehensive submission will typically include the following elements:

• Single-line diagram showing all protection devices with relay model numbers, CT ratios, and VT ratios clearly annotated
• Relay settings schedule listing every protection function with its set value, time delay, and relay element reference
• Time-current characteristic plot demonstrating discrimination between site and DNO upstream protection
• ROCOF and vector shift settings justification with reference to the DNO’s network characteristics
• LoM protection coordination statement confirming the settings are compatible with the DNO’s upstream scheme
• Relay type-test evidence confirming IEC 60255 compliance and BS EN 50549 compliance where required
• Firmware version and setting group documentation for each specified relay device

The firmware version and setting group requirement is one that catches EPC contractors off guard. DNOs have experienced cases where relay devices were installed with firmware versions that contained known measurement errors or had different characteristic curves than the type-tested version. Specifying the exact firmware version in the submission, and confirming that the installed device will match, is now a standard expectation at several major DNOs.

For EPC contractors building their documentation process from scratch, working through a structured solar design preparation checklist that incorporates protection relay documentation requirements can significantly reduce the risk of incomplete submissions.

IEC 60255 and BS EN 50549 Compliance: The Standards Framework Behind Grid Connection Protection Settings UK

The regulatory standards framework governing grid connection protection settings UK is built on two principal documents: IEC 60255, which covers measuring relays and protection equipment in general, and BS EN 50549, which is the UK-adopted European standard specifically addressing requirements for generating plants connected to distribution networks.

BS EN 50549 defines the protection functions and performance requirements for generating plants connected below 110 kV. It specifies the mandatory protection functions, the setting ranges within which those functions must operate, and the performance tolerances that the relay hardware must achieve. For a G99 submission to be technically acceptable, every relay function specified must be demonstrably within the BS EN 50549 setting ranges and the relay hardware must be certified to IEC 60255 performance tolerances.

Where EPC contractors frequently encounter problems is with inverter-integrated protection functions. Many modern string and central inverters include built-in protection functions that are marketed as G99 compliant. However, the compliance certificate may apply to a specific firmware version, and inverter manufacturers update firmware frequently. If the installed firmware version has not been tested against the certification criteria, the DNO is entitled to reject it as non-compliant, even if the hardware platform is certified.

The safest approach for any project where the grid connection timeline is commercially critical is to specify dedicated, standalone protection relay hardware from manufacturers with established DNO acceptance records, rather than relying solely on inverter-integrated functions. Dedicated relay hardware is also significantly easier to commission, test, and provide evidence for during the protection commissioning test witnessed by the DNO.

How AutoCAD Documentation Supports Protection Relay Submission Quality

The quality of protection relay submission documentation is directly influenced by the quality of the underlying electrical design drawings. A protection relay settings schedule that does not match the single-line diagram, or a TCC plot that references relay designations not shown on the schematic, will be returned for correction regardless of how technically accurate the settings themselves are.

Using professional AutoCAD solar planning tools to produce the single-line diagram and protection schematic ensures that relay designations, CT ratios, cable ratings, and bus section details are consistently referenced across all submission documents. Inconsistencies between documents are one of the most common reasons for DNO technical queries during the review process, and they are entirely avoidable with a disciplined drawing management process.

A well-produced single-line diagram also enables the protection engineer to confirm relay locations, CT secondary burdens, and VT connection arrangements before finalising settings. These physical installation parameters affect relay performance and must be accounted for in the settings study.

Common Mistakes That Cause G99 Protection Relay Submissions to Fail

Drawing from patterns observed across multiple G99 technical review outcomes, the most frequently recurring protection relay specification errors are:

• Using ROCOF and vector shift settings from a previous project without confirming they are applicable to the new connection point
• Specifying non-directional overcurrent relays at MV connection points where bi-directional current flow exists
• Failing to include a TCC discrimination plot in the Schedule 1 submission
• Specifying relay hardware that lacks a current IEC 60255 type-test certificate
• Omitting firmware version references from the relay equipment schedule
• Setting grading margins based on electromechanical relay assumptions when numerical relays are specified
• Not requesting the DNO’s upstream relay settings before finalising LoM protection coordination
• Specifying earth fault protection without confirming the DNO network earthing arrangement at the connection point

Each of these errors is individually capable of causing a Schedule 1 rejection. Combined, they represent a pattern that extends project timelines by months and increases engineering costs significantly through the re-submission process.

Building a Repeatable Protection Relay Specification Process for EPC Contractors

The most effective EPC contractors working in the UK solar PV market have moved away from project-by-project relay specification and toward a structured engineering process that produces consistent, high-quality outputs regardless of project size or connection voltage.

This process typically begins at the feasibility stage, where the connection voltage and DNO are identified, and the relevant DNO connection standard is reviewed alongside G99 to establish the protection philosophy requirements. From that foundation, the protection relay specification develops iteratively through the detailed design stage, with the settings study completed before the Schedule 1 submission is compiled.

Integrating protection relay specification into the broader design workflow, rather than treating it as a standalone exercise completed at the last minute before submission, is the single most effective change an EPC contractor can make to improve first-submission approval rates. For contractors looking to build this integrated approach from the beginning of each project, structuring the overall design effort using a comprehensive solar design preparation checklist that flags protection relay deliverables at each design milestone helps ensure nothing is missed.

Conclusion: Protection Relay Settings Are a Technical Deliverable, Not an Administrative Task

The pattern across G99 technical review rejections in the UK solar PV market is consistent and preventable. Protection relay settings for UK solar PV systems are repeatedly under-resourced in EPC project programmes, treated as a form-filling exercise rather than the engineering deliverable they actually are. The consequences of this approach, measured in re-submission delays, DNO technical queries, and in some cases hardware replacement after procurement, are commercially significant and entirely avoidable.

The path to a successful first-submission outcome is straightforward in principle, even if technically demanding in execution. Engage the DNO early to obtain upstream relay settings and fault level data. Specify ROCOF and vector shift values based on the actual network characteristics at the connection point, not from a template. Complete a discrimination study before finalising the settings schedule and produce a TCC plot that demonstrates correct grading margins. Verify relay hardware against current IEC 60255 type-test certificates and confirm firmware version compatibility. Document everything with the precision that the DNO’s technical review team requires.

EPC contractors who build this engineering rigour into their standard design process, supported by high-quality electrical documentation and a structured design workflow, will find that grid connection approval becomes a reliable milestone rather than an unpredictable risk. For teams looking to strengthen their overall grid connection preparation, the resources available through Lion Solar’s grid connection approval guidance provide a valuable framework for building that confidence into every project from the outset.

Heval Arcan