Direct answer
Power quality metering is the evidence base for any APF or SVG inquiry. Before a mitigation RFQ is issued, the site team should log where each measurement was taken, which operating states were covered, how long the meter ran, and what the harmonic spectrum and reactive-power trend looked like at the point of common coupling. A supplier can only discuss equipment fit against that record, not against a single snapshot reading.
This matters because harmonic-current questions, reactive-power questions, voltage events, protection coordination, and equipment-operation questions can overlap without having the same technical answer. CNBYG can discuss AHF/APF product-line context when measured harmonic current is the defined objective. It cannot establish a compliance verdict, a specific measurement outcome, or a guaranteed harmonic result from an article or a nameplate rating. For wider navigation, use the Power Quality System Engineering Guides.
Define the electrical boundary before collecting data
The first decision is where the result will be used. A measurement at an individual feeder can help characterize a local load. A measurement at a service entrance, transformer secondary, or point of common coupling answers a different question. Record the meter location, CT orientation, voltage reference, sample interval, aggregation period, operating state, and whether other major loads were active. Without those details, a number cannot reliably be compared with a project target.
For a pre-RFQ metering campaign, create an operating log that identifies normal production or occupancy schedules, start-up sequences, idle periods, maintenance states, and coincident loads. The log should make clear when the monitored load is active and what else is connected to the same bus. Log at least one full operating cycle so the RFQ record covers minimum, typical, and peak windows rather than a single afternoon.
A useful pre-RFQ measurement record normally covers these items:
- The single-line diagram position of every meter, with CT ratio and polarity noted.
- Voltage and current spectra captured at defined aggregation intervals, not single snapshots.
- A time-stamped operating log linking each measurement window to the logged operating state.
- Existing capacitor, reactor, filter, and drive inventory on the same bus.
- The demand and reactive-power trend over at least one representative operating cycle.
| Measurement question | Useful project input | Decision it supports |
|---|---|---|
| What is occurring at the metered feeder or bus? | Current spectrum, RMS trend, load state, CT location | Local troubleshooting and source characterization |
| What is occurring at the system boundary? | Voltage/current trends, demand, transformer and upstream data | System-level assessment and target definition |
| Is the condition repeatable across operating weeks? | Time-stamped operating log and multiple representative periods | Capacity and commissioning planning |
| What equipment is already connected? | Single-line, capacitor/reactor/filter and protection details | Interaction and integration review |
Separate harmonic planning from other electrical questions
Harmonic planning should not become a catch-all explanation for every operational concern. A waveform reading may exist alongside voltage variation, reactive-power demand, unbalance, switching events, or an upstream disturbance. Each issue needs its own evidence and acceptance method. A recommendation made before this separation can create an incorrect scope, especially where the installation includes existing compensation equipment or multiple sources of non-linear current.
The IEEE 519 standard overview is useful context for discussing harmonic control at system boundaries, but it is not a universal plug-in sizing rule. Project teams must establish the applicable point, data set, network conditions, and contractual requirement. Similarly, an article cannot confirm that the measured condition causes a particular operational event. Use site measurements and the responsible engineering process to establish that relationship.
Compare mitigation paths without defaulting to one device
The mitigation path follows the defined objective. An option should be shortlisted only when the measurement record supports it and the integration design is understood. No single device is automatically the correct answer for every distortion reading, reactive-power target, voltage event, or system-study finding. Existing capacitor banks, reactors, filters, drives, transformer impedance, protection, and expected load variation all affect the project review.
| Option category | May be considered when | Must be confirmed before selection |
|---|---|---|
| AHF / APF | Harmonic-current mitigation at the assessed PCC or bus is a defined, measured objective | Current profile, installation location, CT plan, capacity basis, protection, heat, and acceptance method |
| SVG / ASVG | Dynamic reactive-power behavior is the primary defined objective | Reactive-power profile, voltage context, existing equipment, controls, and commissioning boundary |
| Passive components | The system study identifies an appropriate fixed or tuned function | Resonance risk, switching, network data, protection, and physical installation |
| Operational or upstream change | The source, schedule, or distribution configuration is material | Owner responsibilities, utility coordination, and documented implementation path |
For a product-line discussion, see the CNBYG AHF Active Harmonic Filter page. It should be used with the project data, not as a substitute for the study. The related guide on VFD harmonics measurement and APF selection explains the same measurement-led approach in a neighboring application context.
Plan integration and commissioning early
Integration questions should be identified before an RFQ is issued. The team should document the proposed connection location, CT arrangement, feeder and bus configuration, available space, cable routing, ventilation, environmental conditions, access, communications, alarms, and maintenance expectations. Protection coordination and shutdown requirements also need a project-specific review. These are design inputs, not details to defer until equipment arrives.
Commissioning should compare representative post-installation conditions with the pre-agreed baseline and the defined acceptance method. Keep the operating condition comparable: record what major loads were running, where meters were connected, and what measurement settings were used. If the site objective includes a system-boundary metric, the measurement plan must retain that boundary. A different meter position or a different load state can produce a different result without demonstrating a change in equipment performance. The guide on IEEE 519 harmonic limits and APF sizing shows how the same commissioning discipline applies in a related scenario.
RFQ checklist and fit boundary
An inquiry is more useful when it contains the single-line diagram, nominal voltage and frequency, transformer information, representative voltage/current data, operating schedule, load inventory, existing capacitors/reactors/filters, protection information, proposed installation point, space and cooling data, and communication requirements. Describe the decision required: local troubleshooting, system-boundary assessment, harmonic-current mitigation, reactive-power response, or a coordinated review.
CNBYG can review these inputs and discuss whether its product line fits the stated scope. It should not be asked to promise a compliance verdict, a specific measurement outcome, or a guaranteed harmonic result. Where a project has regulated, critical, or unusual operating constraints, involve the relevant owner, system engineer, utility, and equipment specialists. Use the CNBYG contact page to submit the available project information.
Frequently asked questions
How long should power quality metering run before an APF or SVG RFQ?
Long enough to capture representative operating states. Many industrial campaigns log at least one full production week, and longer where seasonal or scheduled loads change the demand profile.
Should harmonics be logged at the PCC or at individual feeders?
Both locations answer different questions. Feeder data characterizes a source, while PCC data supports a system-boundary discussion, so each record must be labeled with its position.
Which load events should appear in the metering record?
Start-up sequences, shutdowns, coincident peaks, capacitor switching, and any abnormal events, each linked to a time-stamped operating note.
Is one measurement enough to select mitigation equipment?
Usually not. The measurement location, operating condition, duration, electrical topology, and project objective determine whether the data is representative.
Can mitigation equipment be sized from connected load alone?
No. A capacity discussion requires measured current behavior, an operating profile, the installation topology, and a defined project objective.
Does this article guarantee a compliance or operational outcome?
No. Standards application, network conditions, acceptance criteria, and commissioning must be defined and verified for the specific project.
References
- IEEE 519 — Recommended Practice and Requirements for Harmonic Control in Electric Power Systems
- NEMA MG 1 — Motors and Generators
- U.S. Department of Energy — Industrial Efficiency and Decarbonization Office
