Gridcraft Advanced Power Lab

Study controls

Base, loads & tap changer

All impedances use the selected common three-phase MVA base. All buses are nominally 13.8 kV equivalents; utility-side values are already referred to this voltage.

Base · MVANominal voltage · kV

Plant load · MWPlant load · MvarFeeder load · MWFeeder load · Mvar

Tap position · −16…16Step size · %

Plant voltage target · pu

Static search over 33 positions; no automatic time-delay or hunting simulation.

Transformer, feeder & breakers

T1 R₁ = R₂ · puT1 X₁ = X₂ · puFeeder R₁ = R₂ · puFeeder X₁ = X₂ · pu

Branch Z₀ / Z₁ multiplier

T1 is a grounded-wye/grounded-wye equivalent with a zero-sequence path and no phase shift. These are explicit training assumptions.

T1 path closedFeeder path closed

BESS energy & state of charge

Stored-energy rating · MWhCurrent SOC · %Reserve SOC · %Upper SOC · %One-way efficiency · %

Fault & relay measurement

Fault busFault typeFault resistance · primary Ω

ABC: per phase. A–G: phase to ground. B–C: between phases. B–C–G: common joined phases to ground.

CT primary · ACT secondary · A

Same ideal CT ratio is applied to both displayed relay locations.

Phase overcurrent settings

Compare operating cases

Each preset starts from the default network.

Interactive study network

Apply fault at:

Source labels show solved MW injection. Negative means absorption. Breaker status and source controls are in the left panel.

Bus voltages & load schedules

Bus	Voltage · pu ∠°	Voltage · kV L–L	Load · MW / Mvar

Source dispatch

Source	Model	MW injected	Mvar injected	Primary current · A

Branch flow and losses

Path	From-end MW / Mvar	To-end MW / Mvar	Loss MW / Mvar

Branch powers are positive into the branch at each end. Their sum is branch loss. Conventional sources are fixed EMFs behind impedance; their MW/Mvar are solved, not dispatch setpoints.

BESS energy window

Positive BESS MW discharges; negative MW charges. Duration uses constant scheduled AC power, present SOC limits and the entered one-way efficiency. It excludes auxiliaries, temperature, degradation and voltage-dependent limits.

Fault current phasors

Fault-bus voltage phasors

A: cyan · B: amber · C: violet. RMS phasors, separate auto-scaled plots. Numerical values follow.

At the fault

Phase	Fault current · A ∠°	Voltage · kV L–G ∠°

Sequence quantities at the fault bus

Sequence	Fault current · A ∠°	Voltage · pu ∠°	Driving-point Z · pu

Source-terminal currents during fault

Source	IA · A ∠°	IB · A ∠°	IC · A ∠°

These are local terminal currents into the network. They include circulating currents and must not be added as scalar magnitudes. An off-nominal transformer changes current between its terminals.

Relay-location measurements

Relay / CT location	Max phase · primary A	Max phase · secondary A	Residual · primary A

Fault calculation trace

Solar and BESS use fixed positive-sequence current injections during the fault. Their magnitude and angle are explicit assumptions; no inverter controller, ride-through timing, negative-sequence controller or vendor-specific current-priority logic is simulated.

Time-current comparison

Cyan: feeder relay D. Amber: T1 relay U. Curves show element time; markers use the measured fault current at each location.

Timing for this fault

Relay	Measured primary A	Element time · s	Breaker time · s	Total · s

Magnitude-only phase-overcurrent comparison using max(|IA|, |IB|, |IC|). It excludes directionality, CT saturation, transient response, reset memory and logic. Utility B, DG and DER provide alternate infeeds: T1 relay U is not complete backup for every source. A time interval alone cannot establish full scheme selectivity.

Inverse-time equation

t = TMS × K / [(I / Ipickup)^α − 1], for I > Ipickup. No operation is reported at or below pickup.

IEC standard inverse: K = 0.14, α = 0.02. Very inverse: K = 13.5, α = 1. Extremely inverse: K = 80, α = 2. The required interval is measured from feeder breaker clearing to upstream element operation.

What this model does—and where it stops

Balanced power flow

Three-bus complex nodal equations with constant-PQ loads and solar/BESS injections. Two utility equivalents and one synchronous DG are voltage sources behind impedances. A damped Newton method solves six real current-balance equations. Results include convergence residuals and a complex power-balance check.

Generator excitation, governors and reactive limits are not simulated. Scheduled inverter P/Q is held constant; low-voltage operation may exceed rated current and is flagged rather than silently clamped.

Sequence fault study

Positive, negative and zero-sequence admittance matrices are formed independently. The solver obtains the selected bus driving-point impedances, connects the sequence networks for ABC, A–G, B–C or B–C–G, then reconstructs all bus voltages and branch currents.

Loads are omitted from the fault model. Conventional-source internal EMFs remain at their entered values. Fixed positive-sequence inverter fault injections use their rated current multiplier and angle relative to pre-fault local voltage. The fault-network open-circuit voltage is recalculated; it is not the loaded pre-fault voltage.

Tap & storage studies

T1 has a real off-nominal ratio a = 1 + tap × step/100 at the U end. Yff = y/a², Yft = Ytf = −y/a and Ytt = y. Increasing a reduces the ideal downstream voltage for fixed upstream voltage; other infeeds alter the system response.

BESS SOC is a static energy calculation with constant AC power. Tap search is a static sweep, not a dynamic OLTC simulation. Grid-following DER alone cannot establish an island voltage; unsupported islands are rejected.

Detailed model boundaries and reproducibility

All quantities are steady RMS fundamental-frequency phasors. One common three-phase MVA base and nominal line-to-line kV base apply throughout; Zbase = kV²/MVA and Ibase = MVA × 1,000/(√3 × kV). Changing the base without rebasing entered pu values changes the physical network. The same fixed source Thevenin impedance is used in power flow and the fault network; no separate transient/subtransient generator model or time evolution is provided. Source Z₂ = Z₁; source Z₀ and branch Z₀ use the entered multipliers. All conventional sources have a grounded zero-sequence path.

T1 is a grounded-wye/grounded-wye equivalent with no phase shift or core/neutral detail. Solar/BESS have no independent negative/zero-sequence injection or passive sequence shunt in this model. Their aggregate ratings are referred to the DER bus. There are no load unbalances, harmonic studies, electromagnetic transients, motor starting, dynamic stability, inverter control models, arc-flash calculations or multi-terminal protection logic.

Fault resistance conventions are displayed beside the inputs. For a B–C–G fault, B and C join before the common resistance to ground. Switches remove paths algebraically; they do not model interrupting duty or a time-domain event.

Reviewable original code: calculation engine and interface. Built-in presets and Reset make comparisons reproducible. Educational results require an appropriate engineering model and review before real equipment decisions.

References and relationship to the NERX example

NERX publicly describes power flow, fault analysis, relay coordination and phasor analysis. Those capability categories informed this original learning lab. NERX’s gated application was not inspected beyond its licence screen; this page does not assert feature-by-feature parity or use its code, layout or proprietary algorithms.

Study the whole network.