Calculation methods

Standards

• No code mandates the method; the voltage band (0.95–1.05 p.u.) is an engineering default you can change.

Method

• Newton-Raphson power flow by default (pandapower 3). Iwamoto Newton-Raphson, fast-decoupled (BX / XB), backward/forward sweep and Gauss-Seidel are available in the study options.
• One reference (slack) source per island: the first utility, else a generator set to slack mode, else the first generator. Other utilities in the same island are taken out of service and reported; the remaining generators hold their voltage (PV).
• Loads are constant power, scaled by the study case's load scale. Motors draw P = rated output ÷ efficiency × loading, with Q from their power factor. Inverters and PV/battery sources inject fixed P and Q.
• Transformers: a ratio tap changer on the higher-voltage winding. Off-load changers hold their position; on-load changers (OLTC) and step-voltage regulators (a 1:1 unit with an OLTC) step one position at a time until their secondary is inside target ± half the dead band (2 steps by default). Three-winding transformers are supported. Cables are modeled from R, X and C per length, with the corrected ampacity as their loading base.
• Suggested fixed taps: for each off-load changer, from the highest voltage down, the position that minimizes the largest deviation from 1.0 p.u. over the buses it feeds, with the study case's load.
• Islands with no source are de-energized. Switch positions come from the study case.
• When the solution does not converge, the run reports the buses with the largest power mismatch at the last iteration and any energized island without a reference source.

Data it needs

• Utility: voltage and set point; generators: rating, active power, voltage set point.
• Transformers: kVA, voltages, impedance, tap changer (kind, step, range, position; OLTC target and dead band).
• Loads: power and power factor; motors: rated output, efficiency, power factor, loading.
• Cables: cable type (R, X per length), length, parallel sets and installation (for the ampacity).
• Study case: switch positions, sources in service, load scale, transformer tap positions.

Assumed when missing

Typical values fill missing data. Each one is listed as assumed, with its source, in the run and in the report; replace them with nameplate data before relying on the results.

Load power factorAssumed

0.90

Engineering default

Motor efficiency and power factorAssumed

80 %/0.75 (≤ 1 kW) up to 96 %/0.89 (> 375 kW), by rated power

Typical induction-motor range (IEC 60034-30-1 IE2/IE3)

Motor loadingAssumed

100 %

Modeling convention

Generator dispatchAssumed

Rated kVA × rated power factor (0.8 when missing)

Full-load dispatch convention; IEC 60909-0 typical generator data

Transformer impedance Z% and X/RAssumed

Z% 4 (≤ 630 kVA), 5 (≤ 1,250), 6 (≤ 2,500), 7 (≤ 6,300); X/R 3 to 20 by rating; vector group Dyn11

IEC 60076-5 Table 1 minimum impedance; X/R trend of IEEE C37.010 / IEEE 551

Cable impedance when the cable type has only a sizeAssumed

R at 20 °C from the conductor resistivity; X 0.08 Ω/km (LV) or 0.12 Ω/km (MV)

IEC 60028 / IEC 60889 resistivity; typical reactance by voltage class

Limits

Undervoltage / overvoltage

0.95 / 1.05 p.u.

Engineering default, configurable per study

Overload

100 % of the cable ampacity or transformer rating

Configurable per study

Results

• Per bus: voltage (p.u., V, angle).
• Per branch: P, Q, current, loading %, losses and voltage drop between its ends.
• Per source: P, Q and power factor. Totals of generation, load and losses.
• Violations: undervoltage, overvoltage and overloaded cables and transformers.
• Transformer taps: the final position of each stepped changer, whether an OLTC ended inside its band (an OLTC at the end of its range is a violation) and the suggested fixed tap, also in the report.

Limitations and pending work

• Balanced three-phase, positive-sequence model: single-phase loads are spread over the three phases. The unbalanced load flow gives per-phase results.
• Tap control is a steady-state result: no time delays or coordination between cascaded changers. A dead band narrower than one step makes the changer hunt and the run fails with that advice.
• The motor starting study holds the taps where the study case sets them (an OLTC does not act during a start).
• Cables above 2 kV (NEC) or 1 kV (IEC) have no ampacity in the engine, so their loading is not reported.
• The reference source can't be picked in the study case yet; the automatic choice above applies.
• The normative values embedded in the engine (code tables, limits, standard ratings) were transcribed from published reproductions of the standards, not from the standard text, and are pending independent transcription and legal review.

Verification

Reference cases V02a (IEEE 14-bus published solution; one bus at ±0.0015 p.u.), V02b (hand-calculated industrial network) and V02c–e (OLTC, suggested fixed tap, step-voltage regulator, hand-calculated to 1e-6) pass. A comparison against MATPOWER runs is pending.

Standards

• Voltage unbalance factor VUF = |V2| / |V1| (IEC 61000-2-12, EN 50160: 2 % in LV and MV networks).
• Line voltage unbalance rate of NEMA MG-1 / ANSI C84.1: the largest deviation of a line voltage from the average of the three, in % of that average (ANSI C84.1 Annex D: 3 %).

Method

• Three-phase Newton-Raphson power flow in symmetrical components (pandapower runpp_3ph), on the same network as the load flow.
• Loads are constant power on their phase connection: A, B or C between line and neutral, A–B, B–C or C–A between two lines, or balanced on the three phases. A load's phase connection comes from its electrical data; a single-phase load without one gets the phase the panel schedule balancing chose for its circuit, and a load on no panel goes on phase A (A–B for a two-pole load), flagged as assumed.
• Motors are balanced constant-power loads (rated output ÷ efficiency × loading, with their power factor); inverter sources are balanced injections.
• Utilities are the reference: an ideal positive-sequence source at their voltage set point; the negative and zero sequences see the source impedance 1.1 × Un² / S″k with the R/X and zero-sequence ratios of the short circuit.
• Transformers keep their vector group: a delta winding blocks the zero sequence, and the zero-sequence impedance at a grounded star is the leakage impedance (as in the short circuit). Cables use R0 and X0 from their type, else 4 × R and 3.5 × X.
• On-load tap changers take the positions a balanced load flow settles at (the unbalanced solution has no tap control); or every tap holds the study case's position.

Data it needs

• Loads: power, power factor, number of phases (two poles = line-to-line) and the phase connection (electrical data).
• Utility: voltage set point, fault level, X/R and zero-sequence ratios.
• Transformers: kVA, voltages, impedance, vector group and grounding; tap changer.
• Cables: R, X, R0 and X0 per length (cable type), length, parallel sets.
• Study case: switch positions, sources in service, load scale, tap positions.

Assumed when missing

Typical values fill missing data. Each one is listed as assumed, with its source, in the run and in the report; replace them with nameplate data before relying on the results.

Load power factorAssumed

0.90

Engineering default

Motor efficiency and power factorAssumed

80 %/0.75 (≤ 1 kW) up to 96 %/0.89 (> 375 kW), by rated power

Typical induction-motor range (IEC 60034-30-1 IE2/IE3)

Phase of a single-phase load on no panelAssumed

Phase A (A–B for a two-pole load)

Listed per load as assumed in the run

Cable zero sequenceAssumed

R0 = 4 × R, X0 = 3.5 × X

Typical LV multicore cable with the return through the fourth conductor

Utility zero sequenceAssumed

X0/X1 = 1, R0/X0 = 0.1 when not given

Engine default, as in the short circuit

Transformer impedance Z% and X/RAssumed

Z% 4 (≤ 630 kVA), 5 (≤ 1,250), 6 (≤ 2,500), 7 (≤ 6,300); X/R 3 to 20 by rating; vector group Dyn11

IEC 60076-5 Table 1 minimum impedance; X/R trend of IEEE C37.010 / IEEE 551

Limits

Undervoltage / overvoltage

0.95 / 1.05 p.u. on every phase

Engineering default, configurable per study

Voltage unbalance

3 % NEMA line voltage unbalance (NEC projects) or 2 % VUF (IEC projects)

ANSI C84.1 Annex D; EN 50160. Configurable per study

Overload

100 % on the most loaded phase

Configurable per study

Results

• Per bus: the three phase-to-neutral voltages, the three line voltages, VUF and the NEMA unbalance.
• Per branch: the phase currents, the neutral (return) current of cables, loading of the most loaded phase, power and losses.
• Phase placement: the phase connection and the power on each phase of every load and source, and the total load of each phase.
• Violations: phase voltages outside the band, overloaded phases and buses above the unbalance limit.

Limitations and pending work

• Generators are modelled as balanced injections at their active power with no reactive power: they do not hold a voltage, and every island needs a utility. Islands fed only by generators can't be solved.
• Three-winding transformers are not supported: take them out of service in a study case or use the balanced load flow.
• A neutral conductor's own impedance and loading are not modelled: the neutral current is the return current of the cable's zero sequence.
• Loads are constant power on each phase; voltage-dependent loads and harmonics are not modelled.
• Line-to-line single-phase loads are recognized from two-pole circuits or their phase connection only.
• The normative values embedded in the engine (code tables, limits, standard ratings) were transcribed from published reproductions of the standards, not from the standard text, and are pending independent transcription and legal review.

Verification

Hand-calculated cases V17a (Dyn transformer, single-phase and line-to-line loads) and V17b (grounded LV utility, motor, unassigned single-phase load) pass, the voltages to 1e-6 and the unbalance and currents to 1e-4. A comparison with the IEEE 4-bus and 13-bus test feeders is pending.

Standards

• IEC 60909-0:2016, equivalent voltage source at the fault location.
• For ANSI/IEEE C37 (US) projects use Short circuit with the ANSI standard.

Method

• Voltage factor c from IEC 60909-0 Table 1: LV cmax 1.10 / cmin 0.90 with a ±10 % tolerance, or 1.05 / 0.95 with ±6 %; MV cmax 1.10 / cmin 1.00.
• Correction factors applied: network transformers KT = 0.95 cmax / (1 + 0.6 xT); generators KG = cmax / (1 + x″d sin φrG).
• Faults: three-phase, line-to-line, line-to-ground and two-phase-to-ground, with an optional fault impedance (not applied to two-phase-to-ground). Maximum or minimum case.
• Two-phase-to-ground: Ik″ of the faulted phases and the current to earth IkE2E″ from the positive and zero-sequence impedances at the fault (Z2 = Z1); ip and Ith use the κ of the three-phase fault at the same bus.
• Peak current ip by method C (equivalent frequency, default) or method B. Line-to-ground ip uses the κ of the three-phase fault at the same bus.
• Ib (three-phase) with the IEC 60909-0 meshed-network expression over the generators and motors, μ at the minimum time delay tmin (default 0.1 s). Ik is computed without motor contributions and with each synchronous generator held at λ × its rated current (λmax or λmin by case, excitation series one or two). Ith = Ik″ √(m + n) with m at the network frequency, n = 1, over the fault duration Tk (default 1 s).
• Every motor that contributes is included in the maximum case (conservative); motors and inverters are excluded in the minimum case.
• Solver: pandapower 3. Ib is computed by the engine from the impedance matrix, because pandapower does not provide it.

Data it needs

• Utility: available fault MVA and X/R (maximum and minimum), zero-sequence ratios for ground faults.
• Transformers: kVA, voltages, Z%, X/R or load losses, vector group and grounding.
• Generators: subtransient reactance x″d, saturated synchronous reactance xd (for λ), turbo or salient pole, X/R, rating. Motors: rating, locked-rotor current, R/X.
• Cables: R and X per length (R0/X0 for ground faults), length, parallel sets.
• Inverter sources: rating and short-circuit factor.

Assumed when missing

Typical values fill missing data. Each one is listed as assumed, with its source, in the run and in the report; replace them with nameplate data before relying on the results.

Utility available fault level and X/RAssumed

50 MVA, X/R 6 at ≤ 1 kV; 500 MVA, X/R 10 up to 35 kV; 5,000 MVA, X/R 15 above

Typical value by voltage class. Replace it with the utility's fault-duty letter.

Transformer impedance Z% and X/RAssumed

Z% 4 (≤ 630 kVA), 5 (≤ 1,250), 6 (≤ 2,500), 7 (≤ 6,300); X/R 3 to 20 by rating; vector group Dyn11

IEC 60076-5 Table 1 minimum impedance; X/R trend of IEEE C37.010 / IEEE 551

Generator x″d, power factor and R/X″dAssumed

15 %, 0.8, R/X″d 0.15 (LV) or 0.07 (HV < 100 MVA)

IEC 60909-0:2016 typical generator data

Generator saturated synchronous reactance xd sat (λ factors)Assumed

180 % (turbo) or 120 % (salient pole)

IEC 60909-0:2016 Figures 18/19 ranges

Motor locked-rotor currentAssumed

6.0 × FLC

Typical NEMA design B / IEC design N induction motor

Motor R/X at locked rotorAssumed

0.42 (LV), 0.15 (MV < 1 MW), 0.10 (MV ≥ 1 MW)

IEC 60909-0:2016 asynchronous motor values

Inverter short-circuit contributionAssumed

1.2 × rated current

Typical inverter current limit

Zero-sequence dataAssumed

Typical ratios where the equipment has none

Listed per element as an assumed value in the run

Limits

None

This study reports fault levels; pass/fail checks are in Device duty

—

Results

• Per bus: Ik″, ip, Ib, Ik, Ith, S″k (three-phase) and R/X at the fault; IkE2E″ for two-phase-to-ground.
• Branch and source contributions for up to 50 selected buses.

Limitations and pending work

• Not yet verified against the IEC TR 60909-4 example networks; the report is not available to the project. The minimum case (cmin, conductor end temperature) is not verified yet either.
• Motor factor q is taken as 1 (conservative; the model has no pole-pair count). The generator λ factors follow a closed form of IEC 60909-0 Figures 18/19 (pending review against the figures); Ik = min(Ik″ without motors less the generator decay to λ IrG, Ib).
• For unbalanced faults, Ib = Ik = Ik″. Two-phase-to-ground runs report no branch currents.
• LV motors contributing less than 5 % of Ik″ are not neglected, as IEC 60909-0 would allow; the run tells you how many buses would qualify.
• Impedance-grounded neutrals are pending review; the Ib/Ik method choices are pending review against the standard text.
• The normative values embedded in the engine (code tables, limits, standard ratings) were transcribed from published reproductions of the standards, not from the standard text, and are pending independent transcription and legal review.

Verification

Hand-calculated cases V01a–V01f and V04a–V04g pass (±0.5 %). The IEC TR 60909-4 cases are pending.

Standards

• IEEE 551-2006 (Violet Book) ch. 9 and 10: the three networks, the reactance multipliers of Table 9-1 and the E/Z method.
• IEEE C37.010 (and C37.04-2018 eq. 1 for the S factor): interrupting multiplying factors, local and remote, and NACD.
• IEEE C37.13 (LV power circuit breakers), UL 489 / UL 248 (molded-case breakers and fuses) for the device checks in Device duty.

Method

• Three networks from the same model: first cycle (all machines, subtransient reactances), interrupting (medium-voltage breakers, induction motors with larger multipliers or removed) and 30 cycles (induction motors removed; synchronous motors kept; generators at Xd′ by default).
• Machine reactance multipliers from IEEE 551 Table 9-1 (default) or C37.010 Table 20; induction motors are classed by horsepower and speed (large above 1,000 hp, or above 250 hp 2-pole; medium from 50 hp; small below).
• X/R from separate reductions: a network of resistances only and a network of reactances only, as C37.010 requires; the fault current itself uses the complex impedance (E/Z, default) or the reactance only (E/X, option).
• Faults: three-phase, line-to-ground, line-to-line and double line-to-ground by symmetrical components, with an optional fault impedance. The zero-sequence network follows the transformer winding connections and the neutral impedances.
• First cycle: Iasym and Ipeak from the X/R at the fault (IEEE 551 eq. 9.5 and 9.6).
• Interrupting (buses above 1 kV): multiplying factors for 1.5, 2, 3 and 4-cycle contact parting times, on the symmetrical and the total-current basis. Local contributions use the digitized C37.010 Figs. 22 and 23, remote ones the exponential formula, weighted by NACD (vector, all remote, or motors remote).
• S factor of symmetrically rated breakers from C37.04-2018 eq. 1 (default) or the legacy 1.3 / 1.2 / 1.1 / 1.0 embedded in the C37.010 figures (option).
• Inverter sources inject a fixed current (rated current × short-circuit factor), added arithmetically; they carry no multiplier.
• Solver: the engine's own impedance-matrix solution (no pandapower).

Data it needs

• Utility: available fault MVA and X/R, zero-sequence ratios for ground faults.
• Transformers: kVA, voltages, Z%, X/R, vector group, neutral grounding impedance.
• Generators: Xd″, Xd′, Xd, X/R, kind (round rotor or salient pole without amortisseur), neutral impedance.
• Motors: rating, speed, machine type (induction or synchronous), locked-rotor current, Xd″ of synchronous motors.
• Cables: R and X per length (R0/X0 for ground faults), length, parallel sets.
• Breakers (for the interrupting factors): contact parting time or rated interrupting time.

Assumed when missing

Typical values fill missing data. Each one is listed as assumed, with its source, in the run and in the report; replace them with nameplate data before relying on the results.

Utility available fault level and X/RAssumed

50 MVA, X/R 6 at ≤ 1 kV; 500 MVA, X/R 10 up to 35 kV; 5,000 MVA, X/R 15 above

Typical value by voltage class. Replace it with the utility's fault-duty letter.

Transformer impedance Z% and X/RAssumed

Z% 4 (≤ 630 kVA), 5 (≤ 1,250), 6 (≤ 2,500), 7 (≤ 6,300); X/R 3 to 20 by rating; vector group Dyn11

IEC 60076-5 Table 1 minimum impedance; X/R trend of IEEE C37.010 / IEEE 551

Motor machine type and speedAssumed

Induction when not given; a 250 to 1,000 hp induction motor without a speed is taken as 2-pole (large-motor multipliers)

Conservative side of IEEE 551 Table 9-1

Synchronous motor Xd″Assumed

Typical by pole count

IEEE 551 Table 5-2

Generator kind and 30-cycle reactanceAssumed

Round rotor; Xd′ (else Xd″) in the 30-cycle network when the chosen reactance is missing

IEEE 551 ch. 9, listed per generator as an assumed value

Prefault voltageAssumed

1.00 pu

IEEE 551 ch. 9 (option: 0.8 to 1.2 pu)

Contact parting timeAssumed

From the breaker's rated interrupting time; else 3 cycles (5-cycle breaker)

IEEE C37.010 Table 1 minimum parting times

Zero-sequence dataAssumed

Typical ratios where the equipment has none (generator X0 = 0.5 Xd″; transformer vk0 = uk)

Listed per element as an assumed value in the run

Limits

None

This study reports fault levels; pass/fail checks are in Device duty

—

Results

• Per bus and fault: first-cycle Isym, X/R, Iasym, Ipeak and ground current.
• Buses above 1 kV: interrupting Isym, X/R, NACD and the multiplying factor and duty for each contact parting time, on both bases.
• 30-cycle Isym and X/R.
• Source and branch contributions for up to 50 selected buses, and the multipliers applied to each machine.

Limitations and pending work

• Local multiplying factors on the total-current basis (legacy breakers rated on total current) are not digitized yet; the remote formula is used and the run says so.
• Not yet checked against the IEEE 551 ch. 10 example network: the local copy of the book is a translation whose tables print scrambled. The hand-calculated cases stand in.
• No time-domain (EMT) simulation, no arc-flash (IEEE 1584) and no protective-device coordination.
• Zigzag grounding transformers are not modeled in the zero sequence; the magnetizing branch of YNy transformers is ignored.
• Inverter contributions are added arithmetically at their rated fault current, not solved with a control model.
• The normative values embedded in the engine (code tables, limits, standard ratings) were transcribed from published reproductions of the standards, not from the standard text, and are pending independent transcription and legal review.

Verification

Hand-calculated cases (V12g, V12h, V12ih, V12j, V12k) and the IEEE C37.010 / C37.13 examples (V12e, V12f) pass, and the first-cycle currents match OpenDSS within 1 %. The IEEE 551 examples are pending confirmation in an English edition, and the ch. 10 network is pending.

Standards

• NEC 210.19(A) and 215.2(A) informational notes (recommendations, not requirements).
• IEC 60364-5-52 Annex G, Table G.52.1.

Method

• The real drops come from a balanced load flow (see Load flow).
• The reference point is the nearest upstream transformer secondary, or the source when there is none. The transformer's own regulation is not counted; the cumulative drop restarts at every transformer secondary, in percent of its nominal voltage.
• The branch circuit is the last cable to a load; the feeder part is the cumulative drop minus the branch drop.
• Circuits that feed only single-phase loads use the single-phase formula (k = 2 at line-to-neutral voltage) from the load-flow voltage at their origin, because a balanced load flow understates their drop.
• Optional side-by-side check with the simplified formula ΔV% = k·I·L·(R cos φ + X sin φ) ÷ V × 100, per cable at nominal voltage.

Data it needs

• Everything the load flow needs.
• Loads: phases (single-phase circuits) and circuit type (lighting uses the lighting limit).
• Study options: supply type for IEC (public LV network or private substation) or custom limits.

Assumed when missing

Typical values fill missing data. Each one is listed as assumed, with its source, in the run and in the report; replace them with nameplate data before relying on the results.

Load power factorAssumed

0.90

Engineering default

Motor efficiency and power factorAssumed

80 %/0.75 (≤ 1 kW) up to 96 %/0.89 (> 375 kW), by rated power

Typical induction-motor range (IEC 60034-30-1 IE2/IE3)

Cable impedance when the cable type has only a sizeAssumed

R at 20 °C from the conductor resistivity; X 0.08 Ω/km (LV) or 0.12 Ω/km (MV)

IEC 60028 / IEC 60889 resistivity; typical reactance by voltage class

Limits

NEC

3 % branch circuit, 3 % feeder, 5 % feeder + branch

NEC 210.19(A) / 215.2(A) informational notes (recommendations)

IEC, supply from a public LV network

Lighting 3 %, other uses 5 %

IEC 60364-5-52 Table G.52.1, type A

IEC, private substation

Lighting 6 %, other uses 8 %

IEC 60364-5-52 Table G.52.1, type B

Results

• Per load: branch and cumulative drop, the limit and ok / violation.
• Per cable: drop as feeder or branch circuit, with the simplified value when enabled.

Limitations and pending work

• Balanced three-phase, positive-sequence model: single-phase loads are spread over the three phases. The unbalanced load flow gives per-phase results.
• Meshed networks are walked as a spanning tree for the feeder/branch split (the drop itself is still the load-flow drop); the run warns about it.
• The IEC Annex G allowance of +0.005 % per meter beyond 100 m and the motor-starting relaxation are not applied.
• The limit values are pending review against the standard text.
• The normative values embedded in the engine (code tables, limits, standard ratings) were transcribed from published reproductions of the standards, not from the standard text, and are pending independent transcription and legal review.

Verification

Hand-calculated cases V03a (NEC) and V03b (IEC) pass. The NEC handbook and IEC application-guide examples are pending.

Standards

• Fault level: IEC 60909-0 maximum three-phase case, or ANSI/IEEE C37 three-phase and line-to-ground faults (default in NEC projects; see the two Short circuit studies).
• ANSI basis: IEEE C37.13 and UL 489 / UL 248 first-cycle checks for LV devices; IEEE C37.04 / C37.010 interrupting, close-and-latch and momentary checks for MV breakers and switches.
• UL 489 / ANSI C37.13 X/R multiplying factor for UL-rated devices (default in NEC projects).
• IEC 60947-2 (Icu / Ics / Icm), IEC 61439 (busbar Icw, Ipk), IEC 60949 and IEC 60364-4-43 (adiabatic cable withstand).

Method

• Breakers and fuses: interrupting rating Icu (or Ics when selected and declared) ≥ Ik″ at the more severe of their two buses.
• UL rating standard: when the fault X/R exceeds the test X/R, Ik″ is multiplied by MF = (1 + e^(−π/(X/R))) ÷ (1 + e^(−π/(X/R)test)). Test X/R by interrupting rating: 1.73 (≤ 10 kA), 3.18 (10–20 kA), 4.9 (> 20 kA); fuses 4.9.
• IEC rating standard: Icu is not corrected; the asymmetry is covered by the making check Icm ≥ ip. Fuses have no making check.
• Busbars: Icw × √(1 s ÷ t) ≥ Ith(t) at the busbar withstand time t (default 1 s), and Ipk ≥ ip.
• Cables: k²S² ≥ I²t, with I = Ik″ at the cable's upstream bus and t = the cable's clearing time, else its upstream device's, else the default (0.2 s). k comes from the conductor material and its initial and final temperatures (IEC 60949).
• ANSI basis: LV breakers and fuses against the first-cycle Isym times the C37.13 or UL multiplying factor of their class; MV breakers against the interrupting duty at their contact parting time (E/X × MF, with the voltage range factor K of legacy breakers) and against the first-cycle peak (close and latch); MV switches against their momentary rating; busbars against their bracing and peak; LV devices with a short-time rating against the 30-cycle current.
• A device without a rating is reported as unknown, never as a failure.

Data it needs

• Everything the short circuit needs.
• Breakers and fuses: interrupting rating (Icu, optional Ics), making rating Icm, clearing time, rating standard.
• Busbars: Icw and Ipk. Cables: material, size, insulation temperatures, clearing time.

Assumed when missing

Typical values fill missing data. Each one is listed as assumed, with its source, in the run and in the report; replace them with nameplate data before relying on the results.

Utility available fault level and X/RAssumed

50 MVA, X/R 6 at ≤ 1 kV; 500 MVA, X/R 10 up to 35 kV; 5,000 MVA, X/R 15 above

Typical value by voltage class. Replace it with the utility's fault-duty letter.

Transformer impedance Z% and X/RAssumed

Z% 4 (≤ 630 kVA), 5 (≤ 1,250), 6 (≤ 2,500), 7 (≤ 6,300); X/R 3 to 20 by rating; vector group Dyn11

IEC 60076-5 Table 1 minimum impedance; X/R trend of IEEE C37.010 / IEEE 551

Motor locked-rotor currentAssumed

6.0 × FLC

Typical NEMA design B / IEC design N induction motor

Cable initial / final temperatureAssumed

PVC 70/160 °C; THHN, THWN, TW 75/150 °C; XLPE, EPR, XHHW, RHW 90/250 °C

Typical values by insulation

Clearing timeAssumed

0.2 s where neither the cable nor its upstream device has one

Study option default

ANSI device class and MV breaker timingAssumed

Class inferred from the device type and voltage; a 5-cycle breaker (3-cycle contact parting time) when the timing is missing

IEEE C37.010 Table 1; listed per device as an assumed value

MV close-and-latch rating when missingAssumed

2.6 × the rated short-circuit current (60 Hz), 2.5 × (50 Hz)

IEEE C37.04 5.6.2.3

Limits

Pass criterion

Duty ≤ rating; margin = (rating − duty) ÷ rating

Per check above

UL test X/R

1.73 / 3.18 / 4.9 (UL 489 test power factors 0.5 / 0.3 / 0.2)

UL 489 / ANSI C37.13 practice, pending review

Results

• Per device: rating, duty, margin % and status (pass, fail, unknown).
• Failing devices are marked on the one-line, listed in Problems and in the report.

Limitations and pending work

• The fault level follows the study's short-circuit standard: IEC 60909 checks the IEC ratings; ANSI/IEEE C37 (the default in NEC projects) checks each device against the network of its class (first cycle for LV breakers and fuses, interrupting and close-and-latch for MV breakers).
• The cable clearing time is entered per circuit or defaulted; it does not come from time-current curves yet.
• The UL test X/R values and the multiplying-factor formula are pending review against the standards.
• The normative values embedded in the engine (code tables, limits, standard ratings) were transcribed from published reproductions of the standards, not from the standard text, and are pending independent transcription and legal review.

Verification

Constructed cases V05a–V05b pass.

Standards

• NEC 310.16 with 310.15(B) ambient correction, 310.15(C)(1) adjustment, 110.14(C) terminal limit and 310.10(G) parallel conductors.
• NEC 430.22 / 430.24 / Table 430.250 (motors), 210.19 / 215.2 (continuous loads at 125 %), 240.4 (conductor protection).
• IEC 60364-5-52 Tables B.52.2–B.52.5 and B.52.10–B.52.19 (methods A1 to G), IEC 60364-4-43 433.1.

Method

• Design current: the larger of the load-flow current and the code-rule current. NEC: 125 % of the motor FLC (Table 430.250) for a motor branch, 430.24 for motor feeders, 125 % of continuous loads. IEC: the sum of the load currents.
• Ampacity: Iz ≥ design current, with the installation's correction factors.
• Protection: the upstream device's rating protects the conductor (NEC 240.4; IEC Ib ≤ In ≤ Iz and I2 ≤ 1.45 Iz). Without a rating, a standard rating that does must exist. NEC motor branch circuits follow 240.4(G) / 430.52 instead.
• Voltage drop: simplified formula at the design current against the branch or feeder limit, and the cumulative drop from the last transformer against the total limit. Circuits are sized top-down, so upstream cables count at their recommended size.
• Short-circuit withstand: k·S ≥ Ik″ √t, with the clearing time as in Device duty.
• Candidates: catalog cables of the same material and insulation, smallest first, then 2 up to the maximum parallel sets above the largest single size (1/0 AWG and larger for NEC parallel sets). Catalog reactance is scaled to the project frequency.
• Governing criterion: the one the next smaller size fails. Status: undersized when the current cable fails a check; oversized when it is two or more catalog sizes above the recommendation.

Data it needs

• Everything the load flow and short circuit need.
• Cables: cable type (material, insulation, size), length, parallel sets, installation (method, ambient, grouping, soil).
• Loads: continuous flag, circuit type. Motors: rated output and voltage (for the table FLC).
• Upstream breaker or fuse rating and clearing time. The cable catalog of the project's standard.

Assumed when missing

Typical values fill missing data. Each one is listed as assumed, with its source, in the run and in the report; replace them with nameplate data before relying on the results.

Installation when the cable has noneAssumed

IEC: method B1 (single-core) or B2 (multi-core), in conduit on a wall; NEC: Table 310.16 at its 30 °C reference ambient

Reference installation, listed in the readiness check

Termination temperatureAssumed

75 °C

NEC 110.14(C)

Clearing timeAssumed

0.2 s where the circuit has none

Study option default

Load power factorAssumed

0.90

Engineering default

Motor efficiency and power factorAssumed

80 %/0.75 (≤ 1 kW) up to 96 %/0.89 (> 375 kW), by rated power

Typical induction-motor range (IEC 60034-30-1 IE2/IE3)

Limits

Voltage drop

3 % branch, 5 % total (NEC) or the IEC Table G.52.1 values

Same limits as Voltage drop, configurable

Largest single cable

240 mm² (≈ 500 kcmil), up to 4 parallel sets

Study option defaults

Results

• Per cable: current and recommended size, parallel sets, the result of each criterion and the governing one.
• Apply: replaces the cable types (and parallel sets) in one reversible change, recorded in the project. Run the study again to confirm every check passes.

Limitations and pending work

• MV cables have no ampacity in the engine: NEC Tables 310.17 (free air) and 311.60 (MV) and IEC 60502-2 are not embedded, so above 2 kV (NEC) or 1 kV (IEC) the ampacity check can't be made.
• IEC grouping beyond one tray (B.52.20/21), MI cable and NEC 392.80 (cable tray) are not embedded; NEC uses Table 310.16 for every installation method.
• The ampacity tables were checked against published reproductions (HELUKABEL NEC 2023, Top Cable IEC guide), not the standard text; uncertain cells are listed in the engine.
• The normative values embedded in the engine (code tables, limits, standard ratings) were transcribed from published reproductions of the standards, not from the standard text, and are pending independent transcription and legal review.

Verification

Ampacity cases V06a–V06d and sizing cases V07a (NEC) and V07b (IEC) pass; a test applies the recommended cable and protection and confirms every check passes.

Standards

• IEEE C57.12.00 preferred three-phase ratings, 15–10,000 kVA (NEC projects).
• IEC 60076-1 preferred ratings, R10 series, 25–2,500 kVA (IEC projects).

Method

• Demand: the panel schedule of the secondary bus (NEC 220 / 430 demand rules, IEC demand factors), else the load-flow apparent power at the secondary.
• Required = demand × (1 + growth) × (1 + spare) ÷ maximum loading.
• Recommended = the smallest standard rating whose capability covers it; with forced cooling the capability is the rating × the forced-air factor.
• Motor-start dip preview: largest motor below the secondary, ΔV% = 100 · Sstart ÷ (Sstart + Ssc), with Sstart from the locked-rotor current and Ssc the maximum three-phase fault power at the secondary without motors. It raises a warning above the limit; it does not drive the size.
• Status: undersized when the current rating can't carry the requirement; oversized when it is two or more standard sizes above the recommendation.

Data it needs

• Transformer: current kVA and voltages. Loads and motors downstream (the panel schedule).
• Largest motor: rated output and locked-rotor current. Upstream fault level.

Assumed when missing

Typical values fill missing data. Each one is listed as assumed, with its source, in the run and in the report; replace them with nameplate data before relying on the results.

Motor locked-rotor currentAssumed

6.0 × FLC

Typical NEMA design B / IEC design N induction motor

Utility available fault level and X/RAssumed

50 MVA, X/R 6 at ≤ 1 kV; 500 MVA, X/R 10 up to 35 kV; 5,000 MVA, X/R 15 above

Typical value by voltage class. Replace it with the utility's fault-duty letter.

Cooling typeAssumed

Liquid-immersed

The model has no cooling-type field

Limits

Load growth / spare

25 % / 0 %

Study option defaults

Maximum loading

100 %

Study option default

Forced-air factor (ONAN/ONAF, OA/FA)

×1.15 for 750–2,000 kVA, ×1.25 from 2,500 kVA; none below 750 kVA

Typical IEEE C57.12.10 practice, pending confirmation

Motor-start dip

15 %

Study option default

Results

• Per transformer: demand, required and recommended kVA with the justification, and the motor-start dip.
• Apply: sets the recommended kVA on the transformer in one reversible change.

Limitations and pending work

• Three-winding transformers are reported as unknown (not sized).
• The motor-start dip is a simplified preview; the full motor-starting study is planned.
• The forced-cooling factors are market practice, not a requirement of the standards; confirm them with the manufacturer.
• The normative values embedded in the engine (code tables, limits, standard ratings) were transcribed from published reproductions of the standards, not from the standard text, and are pending independent transcription and legal review.

Verification

Hand-calculated cases V08a–V08b pass.

Standards

• NEC 240.4 (B)/(C)/(D) with the 240.6(A) standard ratings; motor branch circuits: NEC 430.52 and Table 430.52, 430.32 (overload, as a note).
• IEC 60364-4-43 433.1; IEC 60364-4-41 (automatic disconnection, conventional method).

Method

• Design current: the same function cable sizing uses, so both studies recommend a coordinated cable and device.
• General rule: the smallest standard rating In ≥ design current that protects the conductor (NEC 240.4; IEC Ib ≤ In ≤ Iz and I2 ≤ 1.45 Iz, with I2 = 1.45 In for breakers and 1.6 In for gG fuses).
• NEC motor branch circuit (one motor, nothing else): Table 430.52 percent of the Table 430.250 FLC (inverse-time breaker 250 %, dual-element fuse 175 %), then the next higher standard rating (430.52(C)(1) Exception No. 1). 240.4(G) exempts the conductor coordination.
• Magnetic check (breakers with a curve or instantaneous pickup): the minimum fault at the end of the protected cable, by the IEC 60364-4-41 conventional method, against the upper bound of the instantaneous tripping range.
• Status judges the current rating; a device with no rating is reported as unknown.

Data it needs

• Breakers and fuses: type, rating, curve or instantaneous pickup.
• The cables they protect (ampacity inputs) and the loads below them.

Assumed when missing

Typical values fill missing data. Each one is listed as assumed, with its source, in the run and in the report; replace them with nameplate data before relying on the results.

Breaker curve (IEC magnetic check)Assumed

C (5–10 In) for breakers that declare none

Study option default

Load power factorAssumed

0.90

Engineering default

Motor efficiency and power factorAssumed

80 %/0.75 (≤ 1 kW) up to 96 %/0.89 (> 375 kW), by rated power

Typical induction-motor range (IEC 60034-30-1 IE2/IE3)

Limits

Standard ratings

NEC 240.6(A) values; IEC: 6 A to 1,600 A preferred series

Embedded tables, pending review

Motor branch percentages

250 % inverse-time breaker, 175 % dual-element fuse

NEC Table 430.52, pending cross-check

Results

• Per device: design current, protected cable ampacity, current and recommended rating, the rule applied and the magnetic check.
• Apply: sets the recommended rating in one reversible change.

Limitations and pending work

• Time-current selectivity between devices is the protection coordination study.
• The 240.6(A) list (with or without 10 A), Table 430.52 and the 430.32 percentages have not been cross-checked against the code text.
• The normative values embedded in the engine (code tables, limits, standard ratings) were transcribed from published reproductions of the standards, not from the standard text, and are pending independent transcription and legal review.

Verification

Hand-calculated cases V09a–V09b pass; a test confirms the recommended rating coordinates with the cable sizing recommendation.

Standards

• IEC 60947-2 Annex A (total and partial selectivity, selectivity limit Is).
• IEEE 242 (Buff Book) practice for the coordination time interval between relays.
• Device curves: IEC 60255-151 / IEEE C37.112 relays, IEC 60898-1 breakers, IEC 60947-2 electronic trip units (see the coordination sheet).

Method

• Pairs: each breaker or fuse on the one-line with the nearest protective device between it and the source.
• Fault current: the maximum at the downstream device's load side from the project's short circuit (IEC 60909 Ik″ max, or the ANSI/IEEE C37 first-cycle Isym); the whole current is assumed to flow through both devices, and the upstream device sees it through the voltage ratio.
• Margin at each current: the upstream device's minimum curve minus the downstream device's maximum clearing curve (tolerances and, for relays, the breaker interrupting time included).
• Required margin: the relay margin when the upstream breaker is relay-tripped (default 0.2 s), otherwise the trip-unit margin (default 0 s: the bands must not overlap).
• Status: selective up to Ik max; partial when the margin fails from a current Is below Ik max; not selective when it already fails at the downstream pickup; unknown without curve data.
• Two fuses without curves: the ampere-rating ratio against a generic 2:1.

Data it needs

• Protection settings of breakers, fuses and relays (Protection section of the equipment).
• The short-circuit data of the network (sources, transformers, cables, motors).

Assumed when missing

Typical values fill missing data. Each one is listed as assumed, with its source, in the run and in the report; replace them with nameplate data before relying on the results.

Relay coordination time intervalAssumed

0.2 s beyond the downstream clearing

Study option default (IEEE 242 practice)

Device tolerancesAssumed

Relays ±5 % or 40 ms, pickup 1.0–1.1×; electronic ±10 % pickup, ±20 % time; instantaneous 0.01–0.05 s

Typical of the families, not a standard

Fuse selectivity ratioAssumed

2:1 for fuse pairs without curves

Study option default (manufacturer tables govern)

Limits

Required margin

Relay 0.2 s; trip unit / fuse 0 s

Study options

Results

• Per pair: the downstream and upstream devices, the fault bus and Ik max, the selectivity limit, the smallest margin and where it occurs, the status and notes.
• Pairs not selective are violations: they appear in the Problems panel; each pair opens on a coordination (TCC) sheet.
• Sequence of operation: for a three-phase and a ground fault just below each protective device (or at the locations you pick), the devices on the path to the source with the current each sees, the band that operates, its trip and clearing times, the margin to the next one and the order they clear in. A sequence is in order, overlapping, out of order or not cleared; a fault no device clears and a ground fault cleared out of order by a ground band are in the Problems panel.

Limitations and pending work

• Pairs compare phase bands only; ground-fault protection takes part in the ground-fault sequences, followed up to the first transformer (above it the winding connection shapes the currents).
• Fuses and the thermal region of MCCBs need manufacturer curves (library pending): those pairs are unknown.
• Motor contributions from below the downstream device are not subtracted (conservative), and a meshed network is followed along a spanning tree.
• The delta-wye phase shift of transformers for unbalanced faults is not modelled.
• The normative values embedded in the engine (code tables, limits, standard ratings) were transcribed from published reproductions of the standards, not from the standard text, and are pending independent transcription and legal review.

Verification

Hand-calculated cases V11a–V11d pass (LV breakers, relay coordination time interval, fuse ratio, relay across a transformer), and V11e–V11g for the sequence of operation (MV relays, LV ground fault in and out of order).

Standards

• IEC 61869-2 (CTs: rated primaries, class P accuracy limit factor and burden, class PX knee point).
• IEEE C57.13 (class C ratings) and IEEE C37.110 (CT saturation criteria and time to saturate).
• IEC 61869-3 (VTs: accuracy over burden, rated voltage factors) and IEEE C62.92.1 (effectively earthed systems).
• IEC 61869-1 (default dynamic current) and IEC 60228 (conductor resistivity of the secondary wiring).

Method

• Location: a CT measured by a relay sits on the breaker the relay trips. Its fault is the three-phase fault just below that breaker, its current the share flowing through the breaker (the fault detail), its load the breaker's design current. A CT no relay uses is checked at its node with the whole fault current there.
• Burden: Rb = wiring + connected burden; the wiring once for a three-phase fault (star-connected CTs) and out and back for a ground fault. The worse case governs.
• Ratio: rated primary at least the load current plus the margin; the next standard primary is suggested.
• Class P (5P, 10P): ALF′ = ALF (Rct + Rn) / (Rct + Rb) at least Ktd × Ik / Ipn. Class PX: Vk at least Ktd × Isn × (Ik / Ipn) × (Rct + Rb).
• Class C: no AC saturation when Is × Zb ≤ Vx (the C voltage at the tap in use); no DC saturation either when (1 + X/R) × Is × Zb ≤ Vx, otherwise the time to saturate (no remanence) is reported as a warning.
• Withstand: Ith (1 s) against the thermal current of the fault over its duration, Idyn against the peak current.
• VTs: the primary against the phase-phase or phase-ground voltage, the connected burden between 25 % and 100 % of the rated one, and the rated voltage factor against the system earthing classified from the grounded sources between transformers.

Data it needs

• CT and VT data in the equipment's Analysis section or the electrical data table: ratio, class, rated burden, Rct, Vk, C rating, Ith, connected burden, secondary wiring.
• Which CT each relay measures through (relay settings, Protection section).
• The short-circuit data of the network.

Assumed when missing

Typical values fill missing data. Each one is listed as assumed, with its source, in the run and in the report; replace them with nameplate data before relying on the results.

Transient dimensioning factor KtdAssumed

1 (generic)

Study option default; the relay manufacturer's requirement per function governs

Secondary wiringAssumed

20 m one way of 2.5 mm² copper at 75 °C

Study option default, for CTs without their own

Dynamic current when not statedAssumed

2.5 × Ith at 50 Hz, 2.6 × Ith at 60 Hz

IEC 61869-1

Earth faults in non-effectively earthed systemsAssumed

Cleared automatically (1.9 for 30 s)

Study option default

Limits

Load margin

20 % above the load current

Study option

VT burden

25 % to 100 % of the rated burden

IEC 61869-3

Results

• Per CT: ratio, class and method, load and fault currents, burden, the accuracy check (ALF′, Vk or Vx), the DC saturation time, thermal and dynamic withstand, the suggested primary and ALF, status and notes.
• Per VT: connection, system earthing, the voltage factor needed, burden in % and status.
• Failing checks are violations in the Problems panel; the suggested primary can be applied to the CT (its relays keep their settings: a warning tells when they no longer match the CT).

Limitations and pending work

• Transient classes TPX, TPY and TPZ (differential protection) are not checked.
• Ktd is generic until the relay models carry their CT requirements (SIPROTEC templates, PRT-21).
• A missing Rct, Vk or Ith leaves its check unknown: no typical value is assumed.
• The ground-fault case takes the whole ground-fault current at the CT's location, and the three-phase X/R for the DC offset.
• The normative values embedded in the engine (code tables, limits, standard ratings) were transcribed from published reproductions of the standards, not from the standard text, and are pending independent transcription and legal review.

Verification

Hand-calculated cases V22a–V22e pass (class P with a real burden below the rated one, class PX knee point, class C on a tap with high and low X/R, withstand, VT burden and voltage factor).

Standards

• IEEE 1584-2018 (arcing current, incident energy, arc-flash boundary, enclosure size correction, arcing current variation).
• NFPA 70E Table 130.7(C)(15)(c) (PPE categories) and Table 130.4(E)(a) (shock approach boundaries).
• Bolted fault current: ANSI/IEEE C37 first cycle for NEC projects, IEC 60909 Ik″ max otherwise.

Method

• Arrangement of each bus: electrode configuration, gap, working distance and enclosure size from the busbar's arc-flash data, completed with the typical values of its equipment class (IEEE 1584-2018 Tables 8 and 10), else of a class chosen by voltage.
• Arcing current Iarc and the reduced Iarc_min (arcing current variation factor), from the bolted fault current.
• Arc duration: the nearest protective device between the bus and the source clears the arc. It carries the arcing current times the share of the fault current fed by the sources on its line side (referred to its own voltage); its maximum clearing time at that current is the duration, capped at 2 s.
• Incident energy at the working distance and arc-flash boundary (1.2 cal/cm²) for both currents; the larger energy governs.

Data it needs

• Busbars: arc-flash equipment class, electrode configuration, gap, working distance, enclosure size (optional; typical values otherwise).
• Protection settings of breakers, fuses and relays.
• The short-circuit data of the network.

Assumed when missing

Typical values fill missing data. Each one is listed as assumed, with its source, in the run and in the report; replace them with nameplate data before relying on the results.

Equipment arrangementAssumed

IEEE 1584-2018 typical values of the class; by voltage: 15 kV / 5 kV switchgear, LV panelboard (VCB)

IEEE 1584-2018 Tables 8 and 10

Maximum arc durationAssumed

2 s

Study option default (IEEE 1584-2018 6.9.1)

Device tolerancesAssumed

The maximum clearing curve of each device (generic tolerances)

Protection curves (C2-02)

Limits

Model range

208 V to 15 kV; Ibf 0.5–106 kA (≤ 600 V) or 0.2–65 kA; gap 6.35–76.2 mm or 19.05–254 mm; working distance ≥ 305 mm

IEEE 1584-2018 4.2

PPE categories

1: 4, 2: 8, 3: 25, 4: 40 cal/cm²

NFPA 70E Table 130.7(C)(15)(c)

Results

• Per bus: bolted and arcing currents, the clearing device and arc duration, incident energy, arc-flash boundary, PPE category, shock approach boundaries and the assumed values.
• Buses above 40 cal/cm², and arcs the protection does not clear within the maximum duration, are violations shown in the Problems panel.

Limitations and pending work

• Sources below the clearing device are counted for the whole duration (conservative); energy fed after it opens by generators below it is not added.
• Fuses and MCCBs without curve data clear at the maximum duration.
• The coefficient tables are pending the transcription and legal review of the IEEE 1584 text (R-05); they match the official calculator spreadsheet.
• DC arc flash and systems above 15 kV are outside the model.
• The normative values embedded in the engine (code tables, limits, standard ratings) were transcribed from published reproductions of the standards, not from the standard text, and are pending independent transcription and legal review.

Verification

IEEE 1584-2018 Annex D.1 and D.2 examples (V13a–V13b) and 105 120 cases of the official IEEE calculator spreadsheet (within 2.5 × 10⁻⁶).

Standards

• IEEE 399 (Brown Book) static motor starting method.
• Typical limits: 80 % at the terminals (NEMA MG 1 motors are designed to start at 85–90 %; check the load torque), 15 % dip at other buses.

Method

• Two load flows per start: before (the starting motors off, the others running) and at the instant of the start (locked rotor, before any acceleration).
• The starting motor draws its locked-rotor impedance S = √3·Vn·(Ip/In)·FLC at the starting power factor (direct on line); 1/3 of it for star-delta; tap² of it for an autotransformer; a constant current limit × FLC for a soft starter or a VFD.
• The utility is represented by its Thevenin impedance Zq = Un²/S″k (the minimum short-circuit power by default), which the plain load flow does not include.
• Sequence: each step starts its motors with the motors of the earlier steps running and those of later steps off.
• Starting torque: (V/Vn)² × the method's factor, as a percentage of the full-voltage locked-rotor torque.

Data it needs

• Motors: rated power, efficiency, power factor, locked-rotor current Ip/In and R/X, starting method (tap, current limit, starting power factor).
• The network data of the load flow and the utility's short-circuit powers.

Assumed when missing

Typical values fill missing data. Each one is listed as assumed, with its source, in the run and in the report; replace them with nameplate data before relying on the results.

Starting methodAssumed

Direct on line; VFD when a drive feeds the motor

Study default

Starter dataAssumed

Autotransformer tap 65 %; soft starter 3 × FLC; VFD 1.5 × FLC at pf 0.95

Typical values

Starting power factorAssumed

R/Z of the locked-rotor impedance (from its R/X)

Motor data

Limits

Terminal voltage

≥ 80 % of nominal

Study option

Dip at other buses

≤ 15 % of the pre-start voltage

Study option

Results

• Per start: each motor's voltage before and at the start, starting current and kVA, starting torque, and the largest dip at another bus.
• Per bus: the voltage before and during each start and the dip.
• Low terminal voltages, dips above the limit and starts without a load-flow solution are violations in the Problems panel.

Limitations and pending work

• Static: the instant of the start only, no acceleration time or torque–speed curves (dynamic motor starting is a later phase).
• Generators hold their set voltage (no transient reactance or voltage regulator response): the dip near them is underestimated.
• Loads keep constant power during the dip (conservative for the voltage).
• The normative values embedded in the engine (code tables, limits, standard ratings) were transcribed from published reproductions of the standards, not from the standard text, and are pending independent transcription and legal review.

Verification

Hand-calculated cases V14a–V14d (direct on line, star-delta, autotransformer, soft starter) match within 0.01 %.

Standards

• IEEE 446 (Orange Book) ch. 5, generator sizing; the manufacturers' sizing guides follow the same criteria.
• ISO 8528-5 load acceptance (the largest block load an engine takes at once).

Method

• Load: the listed loads and motors, else everything in service in the generator's island. Run the emergency scenario (utility out, transfer switch on the generator) to size it for what it really carries.
• Running: loads at P, Q × the scenario load scale; motors at P = Pn × loading / η with their power factor; × (1 + growth) × (1 + spare) / maximum loading.
• Nonlinear loads (drive-fed motors, listed UPS and rectifiers): the alternator carries the running kVA + (factor − 1) × the nonlinear kVA.
• Load steps: each step adds its loads at running power and starts its motors at their starting draw (the motor starting study's: locked-rotor kVA direct on line, 1/3 star-delta, tap² autotransformer, current limit soft starter / VFD).
• Voltage dip: the set is an EMF behind X′d and the step a constant impedance, so dip = x·s / (1 + x·s) with s = S_step / S_gen; the dip limit d needs S_gen ≥ S_step·X′d·(1 − d) / d.
• Block load: step kW ≤ the acceptance % of the engine kW. Peak: running kW before the step + step kW ≤ the engine kW.
• Recommended: the smallest standard standby kW rating covering every kW requirement and, at the rated pf, every kVA requirement; the governing criterion is reported.

Data it needs

• Loads (P, Q) and motors (rating, efficiency, power factor, locked-rotor current, starting method).
• The generator's rating, power factor and transient reactance X′d.

Assumed when missing

Typical values fill missing data. Each one is listed as assumed, with its source, in the run and in the report; replace them with nameplate data before relying on the results.

Transient reactance X′dAssumed

25 % on the generator rating

Typical alternator (study option)

Load stepsAssumed

The loads first, then each motor alone, largest first

Study default

Limits

Voltage dip

≤ 20 %

Study option

Block load

≤ 70 % of the engine kW

Study option (ISO 8528-5)

Spare capacity

10 %

Study option

Results

• Per generator: running kW / kVA, each requirement, the governing one, the recommended standard kW / kVA and the status.
• Per step: the starting kW / kVA, the peak kW and the dip with the current and the recommended rating.
• An undersized set and a step dipping above the limit are in the Problems panel; Apply writes the recommended kVA to the generator (revertible).

Limitations and pending work

• Closed form: no voltage regulator response or frequency dip simulation (the dynamic study is a later phase).
• The dip ignores the load already running; manufacturers' curves with their AVR may give a smaller dip.
• Standard ratings are a typical diesel standby ladder; check the manufacturer's range and its prime or continuous rating.
• The normative values embedded in the engine (code tables, limits, standard ratings) were transcribed from published reproductions of the standards, not from the standard text, and are pending independent transcription and legal review.

Verification

Hand-calculated cases V16a–V16c (direct on line start, soft starter, nonlinear UPS) match within 0.01 %; a published manufacturer example is pending.

Standards

• IEEE 1036 (application of shunt power capacitors) and IEC 60831 / IEEE 18 bank ratings.
• Qc = P · (tan φ1 − tan φ2): the classic correction formula, solved here with the load flow (the bank's own effect on the voltage included).

Method

• Delivery mode: the P and Q the utility supplies (losses included) are corrected by a bank at the chosen bus (the utility's bus by default).
• Per-bus mode: each chosen bus is corrected for the load downstream of it (loads, motors and existing capacitors in its subtree).
• Load flows are repeated, adjusting the bank, until Q = P · tan(acos pf target) at the point; existing capacitors at the bank's bus are part of the total.
• The total is rounded up to whole stages: 25 kvar (LV) or 300 kvar (MV) per stage, doubled until the bank fits the maximum stages; a need below one stage is one standard unit (5 … 300 kvar, 50 kvar minimum at MV).
• Light load: the loads and motors at the light-load level with the full bank in service; above the voltage limit the bank needs automatic stages.
• Parallel resonance: h = √(S″k / Qc) with S″k the IEC 60909 maximum at the bank's bus; within ±0.3 of the 5th, 7th, 11th or 13th harmonic it is an alert.

Data it needs

• Loads and motors with their power factor; existing capacitor banks (kvar, rated voltage).
• The utility's short-circuit powers (resonance) and the network data of the load flow.

Assumed when missing

Typical values fill missing data. Each one is listed as assumed, with its source, in the run and in the report; replace them with nameplate data before relying on the results.

Stage sizeAssumed

25 kvar LV / 300 kvar MV, doubled to fit 12 stages

Study default

Bank voltageAssumed

The bus voltage when the bank has no rated voltage

Study default

Limits

Target power factor

0.95 lagging

Study option (utility tariff)

Voltage at light load

≤ 1.05 pu at 30 % load

Study option

Results

• Per point: P, Q and the power factor before and after, the existing, required and recommended kvar, the stages, the light-load voltage and the resonance order.
• An existing bank can be adjusted with Apply (its rated kvar, revertible); a point without one says which bank to draw.
• Light-load overvoltage and resonance near a characteristic harmonic are warnings in the Problems panel.

Limitations and pending work

• Fixed-load snapshot: the demand profile and the switching of automatic stages are not simulated.
• Resonance is an alert from the short-circuit power only; the harmonic study (filters, detuned banks) is a later phase.
• A bank kvar is referred to its rated voltage by (Vrated / Vbus)²; capacitor tolerances are not applied.
• The normative values embedded in the engine (code tables, limits, standard ratings) were transcribed from published reproductions of the standards, not from the standard text, and are pending independent transcription and legal review.

Verification

Hand-calculated cases V15a–V15c (correction at a bus, delivery with an existing bank, resonance at the 5th harmonic) match within 0.01 %.