A state estimator is only as honest as the physics it enforces. This page is the physics — the swing equation, RoCoF, short-circuit level, reactive power, phase authority, excitation — with the actual GB numbers attached, and a note on where each one lives inside GridSim. If you only read one page before requesting an evaluation, read this one.
Every spinning mass synchronised to the grid stores kinetic energy, and when frequency moves, that energy moves first — before any controller, before any market, before any detection stage. It doesn't ask permission and it doesn't compute. It resists, because Newton said so.
| Technology | Typical H | Contributes system inertia? |
|---|---|---|
| Steam turbine alternator | 4–7 s | Yes — the deep end of the pool |
| Gas turbine alternator | 4–6 s | Yes |
| Hydro alternator | 2–4 s | Yes |
| Wind turbine (rotor) | 2–3 s | Decoupled — the inverter hides it from the grid |
| Solar PV | 0 s | Zero. There is nothing spinning |
Worked example, the honest way: a 660 MW thermal unit with H = 5 s contributes 660 × 5 = 3,300 MVA·s ≈ 3.3 GVA·s the moment it synchronises — and zero the moment it doesn't. GridSim carries exactly this arithmetic per machine, then maps it: inertia-per-unit in the MECHANICAL tab, inertia-by-source in NESO RP1, the synchronous / outturn / market GVA·s split in every streamed frame.
| GB system inertia | Value | Context |
|---|---|---|
| 1990s, typical | 300–400 GVA·s | Frequency held inside ±0.2 Hz almost all the time |
| Today — high load, traditional plant | 200–280 GVA·s | The comfortable half-hours |
| Today — low load, high renewables | 120–160 GVA·s | Routine now; unthinkable in 1995 |
| FRCR 2025 minimum target | 102 GVA·s | The floor the operator now plans to |
| Historic record low — 2019 | ~50 GVA·s | Briefly. The year the grid found out |
Roughly 30 GW of coal retired between 2012 and 2024, and this table is what it took with it. The scenario engine's risk curve — 260 → 155 → 120 → 102 → 50 GVA·s — traces exactly this decline, and every counterfactual GridSim runs is pinned to a rung of it. The thing inertia really buys is time: time for governors, time for frequency response, time for a human to act. That's why the NESO RP1 tab's hero metric is literally called purchased time — seconds of ride-through at the live credible loss, recomputed every tick.
The grid's frequency is the truest single measurement of its health — the balance of every generator against every kettle, resolved fifty times a second. GDA holds 392 million one-second samples of it, back to 2014. When it falls, it falls through a staircase of defences.
| Threshold | What it means |
|---|---|
| 50.0 ± 0.2 Hz | Normal operating band — where the grid lives almost always |
| 49.5 Hz | Statutory limit — the operator is now explaining itself |
| 49.2 Hz | The line the RP1 "purchased time" metric counts down to |
| 48.8 Hz | LFDD — automatic low-frequency demand disconnection begins shedding real customers, in blocks |
A lightning strike, two near-simultaneous losses, and roughly 1.4 GW of generation gone in seconds — a good part of it distributed generation tripping on RoCoF protection that was technically conforming to its settings. RoCoF spiked near 0.5 Hz/s on a system whose 1990s ancestors rarely saw 0.1–0.2. Frequency fell to 48.8 Hz. LFDD fired. A million people, trains stranded nationwide.
That day is in the lake — as a post-event dossier the evidence engine can replay, with the recorded RoCoF and nadir it must reproduce before any counterfactual is allowed to run. The relay settings it exposed are why the MECHANICAL tab shows dual RoCoF margins per machine: the original 0.125 Hz/s setting and the relaxed 1.0 Hz/s setting, side by side. The standards were rewritten after that day. Written in blood, as the engineering recommendations say — don't add to them.
Short-circuit level is the grid's immune system — how hard the network can push back at a fault. High SCL behaves like a strong, low-impedance source; low SCL behaves like a weak, easily-disturbed one. It is also, quietly, the property that makes protection, power quality and inverter stability work at all.
A synchronous machine with subtransient reactance X″d of 0.15–0.25 pu delivers 6–8× rated current into a fault, for hundreds of milliseconds, with a DC offset that doubles the first-cycle peak. A grid-following inverter is capped at 1.1–1.3× rated by IGBT thermal limits — for cycles, not seconds. Short-circuit studies routinely assume zero fault contribution from inverter fleets. A 2 GW coal station contributed upwards of 6,500 MVA of SCL at its connection bus; its replacement, in this particular respect, contributes approximately nothing.
| Where | Typical SCL |
|---|---|
| 400 kV node near major generation | 20,000–50,000 MVA |
| 400 kV, remote | 5,000–10,000 MVA |
| 132 kV bulk supply point | 2,000–8,000 MVA |
| 33 kV primary distribution | 200–1,500 MVA |
| 11 kV feeder | 80–300 MVA |
| LV, dense urban | 10–50 MVA |
| LV, rural | 1–5 MVA |
GridSim's network model carries the impedance data this is computed from — the same Y-bus the solver factorises is the Thévenin picture a fault study needs. When the condition query scores a bus, this is part of what it's scoring.
Q is the price of admission for using AC — pay it or the voltage collapses and nothing works. The wires don't know it's "only" reactive; they get hot just the same. This is the half of the power-flow problem most dashboards ignore, and exactly half of what GridSim solves at every bus.
Capacitor-bank output scales with V². Exactly when you need them most — voltage sagging — they supply less. The worst possible response curve, wired into the cheapest VAR source on the network. Voltage collapse is this trap plus constant-power loads plus tap-changers all pulling the same direction, and it unwinds in seconds. GridSim's solver enforces every generator's reactive limits exactly — zero violations across all fourteen validation cases — because this is the failure mode that punishes optimism.
| Level | Nominal | Statutory range (ESQCR 2002) |
|---|---|---|
| LV at consumer terminals | 230 V | +10% / −6% (216–253 V) |
| Distribution HV | 11 kV | ±6% typical |
| Sub-transmission | 33 kV | ±6% to ±10%, site-dependent |
| Transmission | 132–275 kV | ±5% typical |
| Super Grid | 400 kV | ±5% typical |
The machinery that holds those bands runs on a strict timescale hierarchy: AVRs in single-digit milliseconds, STATCOMs and inverter droop in sub-seconds, on-load tap-changers walking their ±10% range in 16 or 32 steps over minutes, capacitor switching over hours. The gb-full model carries 1,383 live OLTCs in its control loop — the solved GB state ends with 953 taps off-nominal and every bus inside 0.980–1.046 pu. That is what "electrically proofed" means in practice.
The whole AC grid is one giant cooperative agreement about where in the cycle "now" is — and something physical has to anchor that agreement. Pull a synchronous rotor a few degrees ahead of the network and it pushes power out; the rotor angle is the reference, enforced by megatonnes of spinning steel.
Grid-following inverters lock onto that reference with a phase-locked loop — passengers, not drivers. Grid-forming inverters hold a reference in a control-loop register: driving, but with fault current of 1.1–1.3× rated for a few cycles, against a synchronous machine's 6–8× for as long as its excitation says so. In 2019, inverters tripped not because they were broken, but because the phase reference they'd been freeloading off vanished.
Real phase authority and real inertia are the same property viewed from two angles — which is why GridSim refuses to treat either as a single system-wide scalar. Every machine in the model has an angle; every angle is solved; the map shows you whose steel is actually holding the reference at any half-hour you care to replay.
| Device class | Phase behaviour | Fault contribution |
|---|---|---|
| Synchronous machine | Decides — rotor angle is the reference, physically | 6–8× rated, hundreds of ms |
| Grid-following inverter | Follows — PLL tracks someone else's reference | 1.1–1.3× rated, cycles |
| Grid-forming inverter | Emulates — reference lives in a register | 1.5–2× rated, a few cycles |
"Phase isn't something you measure. It's something something gets to decide. That something better be made of steel."
One DC field winding governs a synchronous machine's terminal voltage, its reactive output, and its fault response. Understand the excitation system and the P-Q capability diagram stops being a compliance drawing and starts being a map of what the machine can actually do for the grid.
During a close-in fault the AVR drives a boost of roughly 2× rated field current for 5–10 seconds before thermal limits intervene — a deep copper-and-iron thermal envelope no silicon device replicates. Static excitation responds in single-digit milliseconds; the over- and under-excitation limiters (OEL/UEL) are the fences that keep the AVR from cooking the rotor or sliding out of synchronism.
The P-Q capability diagram is a teardrop bounded by four thermal realities: rotor copper heating (over-excitation), stator copper heating (current), stator end-region heating (under-excitation), and the static stability limit. GridSim's MECHANICAL tab draws it per machine, per tick, with the operating point inside it — and when the solver's Q-limit logic pins a generator at Qmax and switches its bus PV→PQ, that event lands in the math ladder with the bus number and the pass it happened on.
Zero reactive-limit violations across all fourteen validation cases isn't a slogan; it's this diagram, enforced at every bus, every solve.
Total harmonic distortion measures how far the grid has drifted from its 50 Hz ideal — and the stiffer the network at a point (the higher its SCL), the more harmonic current it can absorb without the voltage waveform deforming. Waveform quality and system strength are the same story told at different frequencies.
| Voltage level | G5/5 THD limit |
|---|---|
| LV (<1 kV) | 5% |
| MV (1–35 kV) | 4% |
| HV (35–230 kV) | 3% |
| EHV (230 kV+) | 2% |
The orientation scale engineers actually use: under 1% is exceptional, 1–3% is a healthy HV network, 3–5% tolerable, 5–8% uncomfortable, beyond 8% an operational problem. And the cautionary physics: a capacitor that looks like 100 Ω at 50 Hz looks like 20 Ω at the 5th harmonic — parallel resonance can amplify one harmonic until the capacitor fails. The compliance stack that polices all of this (G5/5 for harmonics, P28 for flicker, G98/G99/G100 for connections) exists because each rule is the codified memory of an incident.
Everything commercial on the GB grid resolves to the 30-minute settlement period — 48 of them a day, except the two days a year the clocks change and there are 46 or 50. GDA anchors every one of them to UTC correctly, which sounds trivial until you've debugged a dataset that doesn't.
Put the physics and the invoice on the same axis and interesting things fall out. One representative settlement period, reconstructed action by action through the bid-offer ladder: £2.65 million of balancing spend to move 271 MW net — across 993 separate actions. The weekly gap runs to nine figures.
This is what the MARKET tab streams alongside every solved frame: imbalance price, BSUoS, net imbalance volume, every interconnector flow — the money side of the same half-hour whose voltages you're looking at. Replay-only, horizon-guarded, and therefore useless for trading — which is precisely why you can publish research built on it.
Inertia, phase authority, short-circuit level, reactive capability, damping — five views of the same synchronous-mass property, and the five things the modern grid is quietly running out of. A tool that lumps them into system-wide scalars can't see the problem, let alone measure it. GridSim carries each one per machine and per bus, solves them together at machine epsilon, and replays how they've actually moved, half-hour by half-hour, since the records begin.
Resistance, not response. Measured, not asserted. That's the physics case for the licence.