Power Quality Fundamentals: Harmonics, Voltage Sags…

Introduction

Power quality is the silent profit-killer of industrial plants. A single voltage sag lasting 100 milliseconds can drop a continuous process line, causing hours of restart time and tens of thousands of dollars in scrap product. Harmonic distortion that looks benign on a meter can cook neutral conductors, trip RCDs unpredictably, and reduce motor life by 30–50%. And yet, many plant engineers cannot tell you the THD at their main busbar or when their utility last exceeded the voltage sag threshold.

This article covers the four pillars of power quality: harmonic distortion, voltage sags and swells, flicker, and three-phase imbalance. For each, we explain the physical phenomenon, the relevant standard limits, and the practical mitigation options.

Harmonic Distortion: When Currents Stop Being Sinusoidal

What Causes Harmonics

Any non-linear load — a device that draws current in pulses rather than as a smooth sine wave — injects harmonic currents into the distribution system. The most common offenders in industrial plants:

Variable frequency drives (VFDs): 6-pulse rectifiers produce 5th, 7th, 11th, and 13th harmonics (characteristic harmonics of order 6k±1).
Uninterruptible power supplies (UPS): Similar rectifier front-end, plus inverter switching harmonics.
LED lighting with switch-mode drivers: High 3rd harmonic content.
Welding machines: Highly intermittent but extreme harmonic content during the arc.
Arc furnaces: The worst offenders — broadband harmonic spectrum plus interharmonics.

Total Harmonic Distortion (THD)

THD is the most commonly quoted metric, defined as:

THDv = √(∑ Vn²) / V1 × 100%   (for voltage, n = 2 to 40 or 50)
THDi = √(∑ In²) / I1 × 100%   (for current)

Where Vn and In are the RMS values of the n-th harmonic, and V1 and I1 are the fundamental (50/60 Hz) components.

Critical distinction: High current THD does not necessarily mean high voltage THD. The voltage distortion depends on the system impedance at each harmonic frequency. A plant with high THDi but connected to a very stiff grid (low impedance) may have acceptable THDv. The same THDi on a weak grid can cause unacceptable THDv.

Effects of Harmonics

Neutral conductor overheating: Triplen harmonics (3rd, 9th, 15th) are zero-sequence and add arithmetically in the neutral. A three-phase system with 80% 3rd harmonic load current will see 240% of the phase current on the neutral — more than double the phase conductor rating.
Transformer overheating: Eddy-current losses scale with f², and harmonic currents cause disproportionate additional heating. A transformer loaded to 100% of its nameplate kVA with significant harmonic content may already be thermally overloaded.
Capacitor bank resonance: At some harmonic frequency, the capacitive reactance of a PFC bank equals the inductive reactance of the supply transformer, creating a parallel resonance. If a harmonic source near that frequency is present, the resulting voltage magnification can destroy the capacitors in seconds.
Nuisance RCD tripping: High-frequency harmonic currents can capacitively couple to earth, causing RCDs to trip on non-fault leakage current.

IEEE 519 Harmonic Limits

IEEE 519-2022 defines voltage distortion limits at the point of common coupling (PCC):

Bus Voltage at PCC	Individual Harmonic (%)	THDv (%)
V ≤ 1.0 kV	5.0	8.0
1 kV < V ≤ 69 kV	3.0	5.0
69 kV < V ≤ 161 kV	1.5	2.5
V > 161 kV	1.0	1.5

Current distortion limits are defined based on the ratio of short-circuit current to maximum demand load current (Isc/IL) at the PCC, recognizing that higher Isc/IL means a "stiffer" system that can absorb more harmonic current without excessive voltage distortion.

Voltage Sags and Swells

Voltage Sag (Dip)

Per IEC 61000-4-30 and IEEE 1159, a voltage sag is a reduction to between 10% and 90% of nominal voltage lasting from 0.5 cycles to 1 minute. The most common cause: remote faults on the transmission or distribution network that are cleared within 3–30 cycles by protection.

A sag to 70% for 100 ms (6 cycles at 60 Hz) is the most common event in utility statistics — long enough to drop contactors and trip VFD undervoltage protection, but too short for the human eye to notice without instrumentation.

Mitigation:

UPS / battery energy storage: Fast enough to ride through sags, but expensive.
Dynamic voltage restorer (DVR): Injects series voltage to compensate during the sag — cheaper than full UPS for protecting specific critical loads.
Ride-through settings: Many VFDs can be configured to ride through 100-200 ms sags by using the motor's rotational inertia to regenerate the DC bus.

Voltage Swell

A voltage swell is an increase to between 110% and 180% of nominal lasting from 0.5 cycles to 1 minute. The most common cause: single-phase-to-earth fault on an impedance-earthed system, which raises the voltage on healthy phases to √3 × nominal (173%) until the fault clears.

Mitigation: Fast fault clearing is the primary defense. Surge arresters protect against the transient overvoltage but not the sustained power-frequency swell. For sensitive loads, a voltage regulator or online UPS provides immunity.

Flicker

Flicker is the subjective perception of light output fluctuation caused by voltage variations in the 0.5–30 Hz frequency range. The human eye is most sensitive to 8.8 Hz modulation — a voltage variation of only 0.25% at this frequency is perceptible.

IEC 61000-3-7 defines two flicker indices:

Pst (short-term flicker severity): Measured over 10 minutes. Pst > 1.0 is considered irritating under laboratory conditions.
Plt (long-term flicker severity): Measured over 2 hours. Plt > 0.65 may generate complaints.

Flicker is primarily caused by large fluctuating loads: arc furnaces, welders, sawmills, and large motor starts. Mitigation uses static VAR compensators (SVCs) or STATCOMs to provide reactive power fast enough (sub-cycle response) to counteract the voltage fluctuations.

Three-Phase Voltage Imbalance

Imbalance (or unbalance) is the deviation of the three-phase voltages from equal magnitude and 120° phase displacement. Per IEC 61000-2-1 and NEMA MG-1, it is quantified as:

Voltage Imbalance (%) = (Maximum Deviation from Average) / Average × 100

Effects

Induction motors: The negative-sequence component of imbalanced voltage produces a counter-rotating magnetic field, causing rotor heating and torque pulsations. NEMA MG-1 requires motor derating for imbalance above 1%: at 3% imbalance, derate by roughly 10%; at 5%, derate by approximately 25%.
Transformer saturation: Negative-sequence flux can drive the core into saturation on one phase, causing additional harmonic generation and heating.

Limits

IEEE 1159 recommends ≤ 2% voltage imbalance at the point of use. IEC 61000-2-12 specifies compatibility levels of 2% for LV systems and 1% for MV systems.

Active Filters vs. Passive Filters

When harmonic distortion exceeds limits, two families of solutions exist:

Passive Harmonic Filters

A series-tuned LC circuit connected in shunt, designed to present a low-impedance path at a specific harmonic frequency (typically the 5th). The filter sinks that harmonic current from the bus, preventing it from propagating upstream.

Pros: Low cost, high efficiency, no control electronics. Cons: Fixed tuning — if the harmonic spectrum changes (e.g., VFDs replaced with active-front-end drives), the filter becomes ineffective or even dangerous (resonance shift). Susceptible to detuning from capacitor aging and temperature.

Active Harmonic Filters (AHF)

A power-electronic inverter that measures the harmonic current in real time and injects a compensating current 180° out of phase, canceling the harmonics at the connection point.

Pros: Adapts to changing load profiles. Can cancel multiple harmonics simultaneously (typically up to the 50th). No risk of resonance with the system. Cons: Higher cost (2–4× passive), requires auxiliary power, generates its own switching losses.

Selection Guideline

For a single large VFD with a stable load profile, a passive filter is usually sufficient and cost-effective. For a plant with many variable-speed drives, multiple harmonic sources, or a need for dynamic reactive power compensation, an active filter or a STATCOM with harmonic mitigation capability is the better choice.

FAQ

Q: My plant's THDv is 5.2% but IEEE 519 says it must be below 5%. Do I need to install filters?

Not necessarily. IEEE 519 is a recommended practice, not a legal requirement (unless adopted by your utility tariff or local regulation). The practical question is: are you experiencing equipment problems attributable to harmonics? If not, the cost of a filter may not be justified. However, if the THDv is trending upward (was 3% last year, 5.2% now), investigate which loads have been added and plan proactive mitigation.

Q: Can connecting a capacitor bank make my harmonics worse?

Yes, and this is one of the most common power quality mistakes. A capacitor bank forms a parallel resonant circuit with the transformer leakage inductance. If the resonant frequency happens to land near the 5th or 7th harmonic (which it often does), the capacitor bank amplifies those harmonics and can fail catastrophically. Always perform a harmonic study before installing PFC capacitors. If resonance is a risk, use detuned capacitor banks (with a 7% series reactor, shifting resonance below the 5th harmonic) or active PFC.

Q: What is the difference between THD and TDD?

THD (Total Harmonic Distortion) expresses harmonics as a percentage of the fundamental component at that moment. TDD (Total Demand Distortion) expresses harmonics as a percentage of the maximum demand load current. TDD is the preferred metric in IEEE 519 because it prevents the distortion percentage from appearing acceptable simply because the fundamental load is low at the time of measurement.

Q: How much harmonic current can a transformer handle?

A standard distribution transformer can typically handle 5% THDi without derating. Above this, the additional eddy-current and stray losses require derating per IEEE C57.110 or the K-factor method. At THDi = 20%, the effective load capacity of a standard transformer drops to roughly 85–90% of nameplate. K-rated transformers are designed with larger conductors and reduced core flux density specifically to accommodate higher harmonic content.

Q: Why did my plant trip on a voltage sag when the DOL motors kept running?

Motor contactors typically drop out below about 70–80% of nominal coil voltage, but the dropout time is voltage-dependent and contactor-specific. Electronic equipment (VFDs, PLCs, computers) often has undervoltage protection that trips faster than a contactor drops out. If the PLC controlling a DOL motor loses power but the contactor coil holds in, the motor keeps running until the normally-closed PLC output drops — which it cannot do if the PLC has already reset. This is why critical control power circuits should have UPS backup even when the process motors ride through.

Q: Is flicker still relevant in the age of LED lighting?

Yes, but differently. Incandescent lamps had thermal inertia that smoothed flicker to some extent. LEDs have virtually zero inertia and can reproduce voltage fluctuations more faithfully — meaning a given voltage variation may be more perceptible with LED lighting. However, well-designed LED drivers include active power factor correction that inherently regulates light output against supply voltage variations, reducing flicker sensitivity. Cheap LED bulbs without active PFC are the worst performers.

References / Standards

Standard	Title	Relevance
IEEE 519-2022	Recommended Practice and Requirements for Harmonic Control in Electric Power Systems	Harmonic current and voltage limits at PCC
IEC 61000-3-6	Assessment of Harmonic Emission Limits for MV, HV, and EHV Systems	Harmonic planning levels
IEC 61000-4-30	Testing and Measurement Techniques — Power Quality Measurement Methods	Standardized sag/swell/flicker measurement
IEC 61000-3-7	Assessment of Flicker Emission Limits	Flicker planning levels, Pst and Plt indices
IEEE 1159	Recommended Practice for Monitoring Electric Power Quality	Sag categories, imbalance definitions
NEMA MG-1	Motors and Generators	Voltage imbalance derating curves for induction motors

Power Quality Fundamentals: Harmonics, Voltage Sags, Flicker, and Filtering Solutions