Most enquiries start with one of four situations. Each one leads to different questions, different information and different engineering work.
Illustrative systemNot connected to any installation · no measurements shown
Highlighted for reviewIllustrated fault or attentionIllustrative additionActual protection behaviour depends on system data, settings, equipment and fault conditions.
01 Challenge
Unexpected or non-selective trips
An illustrated fault on Feeder 1. Relay R3 is expected to clear it by opening breaker Q2. Relay R2 on the incomer acts as upstream backup — whether the two are correctly graded depends on their settings and the actual fault level.
In the diagram
1Illustrated fault location on Feeder 1
2R3 feeder relay — expected to operate first and open Q2
3R2 incomer relay — upstream backup; its timing against R3 is a common point of investigation
4Q1 main breaker — if Q1 opened instead of Q2, the whole busbar lost supply
What may need investigation
Disturbance and event records from the relays involved, where they exist.
Time–current coordination between the feeder, incomer and upstream devices at the relevant fault levels.
Settings as found compared with the settings intended — including setting groups and enabled functions.
Typical information required
Single-line diagram, as-built where available
Relay settings files or printouts
Disturbance and event records with timestamps
A description of the event and the operating conditions
An illustrative change: on-site generation connected downstream of Feeder 2. Fault current can now flow from more than one source, so fault levels and coordination may need reassessment.
In the diagram
1Illustrative change — new on-site generation (dashed)
2R4 feeder relay — may now see fault current in either direction
3Busbar fault level may increase with the added source
4R2 incomer relay — grading with downstream devices may need rechecking
What may need investigation
Updated short-circuit levels at the relevant points, for maximum and minimum conditions.
R2, the incomer relay, is shown as an existing relay under review. A replacement has to work with every interface around it — measurement inputs, trip circuits, logic and communications.
In the diagram
1R2 existing relay under review
2CT inputs — ratio, accuracy class and wiring
3VT input — voltage-based functions and supervision
4Trip circuit to Q1 — including interlocks and supervision
5Communications to station control or SCADA
What may need investigation
Inventory and condition of existing relays and associated equipment, based on available records.
Which protection functions the existing scheme provides — and which the replacement should provide.
CT and VT inputs, trip and close circuits, DC supply and interlocks the new relay must interface with.
Protection zones around the transformer, busbar and feeders. Each zone needs defined functions, settings and verification, and zones overlap at circuit breakers so that no section is left unprotected.
In the diagram
1Transformer zone — for example differential protection with overcurrent backup
2Busbar zone
3Feeder zones
4Zones overlap at circuit breakers
What may need investigation
Protection philosophy: zones, main and backup functions, and how they overlap.
Functions required for each item of plant.
The settings basis and coordination criteria.
Typical information required
Single-line diagram and equipment data
Owner or utility protection requirements
Selected or candidate relay platforms
Project schedule and interfaces with other packages
New transformers, generation, motors or supply arrangements change fault levels and power flows — and settings designed for the old system may no longer fit.
A transformer has been replaced or uprated.
On-site generation, energy storage or a second supply has been connected.
Tell us what your system is doing — and what you need it to do.
A few lines are enough to start. We will ask for drawings, settings or records later, through a channel agreed with you — there is no need to send them with your first message.
