Technical Glossary

A continuous measurement of mechanical stress on transformer windings in the outward direction — from thecore toward the tank wall. A rising value means the windings are loosening or deforming. Plain language: it tellsyou whether the physical structure of the windings is staying intact or beginning to give way.

Technically: the Radial Winding Health Metric (WHr) is derived from the high-frequency content of structuralvibration signals captured at VIE’s surface-mounted sensors. Healthy transformers show stable WHr valuescorrelated to load. A rising or elevated WHr maps to specific mechanical failure modes: forced buckling, hoopbuckling, broken conductor insulation, winding bulge, and spiraling. VIE tracks this metric continuously andtrends it against each transformer’s individual baseline — not a generic fleet average.

A continuous measurement of mechanical stress on transformer windings in the outward direction — from thecore toward the tank wall. A rising value means the windings are loosening or deforming. Plain language: it tellsyou whether the physical structure of the windings is staying intact or beginning to give way.

Technically: the Radial Winding Health Metric (WHr) is derived from the high-frequency content of structuralvibration signals captured at VIE’s surface-mounted sensors. Healthy transformers show stable WHr valuescorrelated to load. A rising or elevated WHr maps to specific mechanical failure modes: forced buckling, hoopbuckling, broken conductor insulation, winding bulge, and spiraling. VIE tracks this metric continuously andtrends it against each transformer’s individual baseline — not a generic fleet average.

A measurement that captures sudden mechanical shock events to the core-winding assembly. Unlike the Winding Health Metrics, which trend gradually over time, the Impact Metric responds to discrete events. A high or rising value is an intervention signal: core or winding structural integrity is likely compromised.

Technically: the Impact Metric (NHv, NHa) detects transient mechanical shocks in both vertical and horizontal directions. It is classified as a coincident indicator — it reflects conditions happening now, not conditions developing over weeks. Events that trigger a significant Impact Metric reading include through-fault currents, nearby seismic activity, and physical impacts during transport or maintenance. A meaningful Impact Metric event warrants a targeted Sweep Frequency Response Analysis (SFRA) test as confirmation.

Continuous measurements of insulating oil quality — without physically sampling the oil. Both metrics are derived from how the condition of the oil changes the way vibration pressure waves travel through it. Rising values are leading indicators of worsening oil quality, detectable before standard lab test thresholds are breached.

Technically: VIE’s two Oil Health Metrics (V2P and S2P) measure changes in the acoustic transmission characteristics of the insulating fluid. As oil degrades — through oxidation, contamination, moisture ingress, or thermal breakdown — its bulk modulus changes, altering how pressure waves attenuate as they travel from the winding assembly to the tank wall. VIE’s database includes readings from 8,979 healthy-oil and 2,551 warning-oil conditions, producing statistically distinct metric distributions that anchor VIE’s oil health detection. The Oil Health Metrics track conditions that map to oxidation, sludging, contamination, fluid integrity loss, and cellulose paper degradation.

The difference between the surface temperature VIE measures and the surface temperature its thermal model predicts for those load and weather conditions. Plain language: it tells you whether the transformer is running hotter than it should be — and where.

Technically: VIE’s thermal model calculates expected surface temperature continuously using current load, historical ambient temperature, and transformer metadata. The residual — actual minus predicted — is what VIE reports as the Excess Heat Flux (also called Residual Heat Flux). Absolute surface temperature alone is not diagnostic; ambient conditions change constantly. The residual isolates thermally anomalous behavior from normal variation. A rising residual at the top of the tank indicates insulation stress or internal overheating. A higher-than-expected residual at lower sensor heights points to a cooling obstruction. Spatial comparison across sensors on a single transformer is what makes this detection possible.

Two ratios produced by a Megger (Insulation Resistance) test that indicate the condition of winding insulation and whether moisture is present. Plain language: they tell you how healthy the insulation is at the moment the test is performed.

Technically: the Polarization Index (PI) compares the 10-minute resistance reading to the 1-minute reading; the Dielectric Absorption Ratio (DAR) compares the 60-second to the 30-second reading. Both indicate insulation condition and moisture content — a declining ratio indicates degradation or contamination. In VIE’s workflow, a significant rise in either Winding Health Metric is the trigger for ordering a targeted Megger test. The PI and DAR are what that test produces. VIE makes this test condition-targeted rather than time-scheduled.

The physical reason a transformer hums. Ferromagnetic core materials expand and contract slightly as the magnetic field cycles — and that mechanical movement is the primary vibration source in a healthy transformer. Plain language: the core is physically pulsing in sync with the AC supply, and VIE listens to that pulse.

Technically: magnetostriction is the cyclic deformation of ferromagnetic core laminations as magnetic domains realign with each half-cycle of the alternating current. Because the core deforms twice per electrical cycle, the primary vibration frequency is twice the line frequency — 120 Hz in 60 Hz North American grids, 100 Hz in 50 Hz systems internationally. This vibration travels primarily in the vertical direction and propagates to the tank surface through the transformer’s structural frame. Changes in the magnetostriction pattern — shifts in frequency content, asymmetric behavior across half-cycles, increased sub-harmonic energy — are indicators of core lamination degradation, DC bias effects, or developing core looseness.

The electromagnetic force that pushes transformer windings outward as current flows through them in the presence of a magnetic field. Plain language: the windings vibrate under load, and that vibration carries information about whether they are intact.

Technically: Lorentz forces act on current-carrying conductors in a magnetic flux field. In a transformer, the axial leakage flux generates radial electromagnetic forces that push windings outward and inward with each current cycle. The resulting pressure waves propagate primarily through the insulating oil to the tank wall. VIE tracks the Lorentz force-response relationship continuously — winding looseness or deformation changes how that force propagates, producing detectable deviations in the vibration signature before any mechanical failure occurs.

The two routes internal vibration takes to reach VIE’s sensors on the outside of the tank. Plain language: core events and winding events leave different vibration fingerprints because they travel to the surface by different routes.

Technically: structural-path signals — primarily from magnetostriction — travel through the solid steel frame and tank wall. This path preserves higher-frequency harmonic content because solid materials attenuate less. Oil-path signals — primarily from Lorentz forces on windings — travel as pressure waves through the insulating fluid, which attenuates high frequencies significantly. VIE’s triaxial sensors and signal processing algorithms separate these two propagation paths. This separation is the foundation of VIE’s ability to distinguish core events from winding events using a single externally mounted sensor — no internal access required.

The difference between the vibration pattern of a healthy transformer and one with a developing fault. Healthy transformers vibrate at predictable, mathematically regular frequencies. Faults introduce irregular vibration energy that does not fit that pattern. Plain language: VIE flags the irregular part.

Technically: healthy transformer vibration concentrates at the fundamental frequency (twice line frequency) and its integer multiples — the harmonic series. Fault conditions introduce non-harmonic frequency content: broadband energy and spikes at frequencies that do not belong to the harmonic series. Partial discharge, arcing, winding deformation, and through-fault events all produce characteristic non-harmonic signatures. VIE’s analytics continuously monitor for this non-harmonic content and flag it as anomalous transient activity, triggering alert escalation through the three-tier indicator framework.

A direct current component superimposed on the AC supply that forces the transformer core into an abnormal operating state. Plain language: it makes the transformer magnetically lopsided, which produces detectable vibration changes and accelerates wear.

Technically: DC bias is caused by geomagnetic disturbances (solar weather events), nearby DC rail or power systems, or asymmetric grid loads. When DC enters the transformer neutral, it shifts the core’s magnetic operating point into saturation on one half-cycle, causing asymmetric magnetostriction. The result is increased sub-harmonic vibration energy, elevated audible noise, elevated heat generation, and accelerated core lamination fatigue. VIE monitors DC bias as a leading indicator — it is detectable in the vibration signature before it produces measurable thermal or chemical effects.

VIE measures vibration on three axes simultaneously — vertical, radial, and lateral — rather than in a single direction. Plain language: this is why VIE can tell a core problem from a winding problem using one sensor on the outside of the tank.

Technically: VIE’s sensors measure vibration simultaneously on three orthogonal axes relative to the transformer body: vertical (aligned with the core stack), radial (horizontal, perpendicular to the tank face), and lateral (horizontal, parallel to the tank face). Core magnetostriction generates primarily vertical vibration. Lorentz winding forces generate primarily radial pressure waves. Measuring all three axes allows VIE’s signal processing to separate core signals from winding signals, detect directional anomalies that single-axis sensors miss, and localize fault sources to specific zones within the asset.

A test that measures gases dissolved in transformer oil to determine whether a fault is developing inside the unit. Plain language: it reads the chemical byproducts of internal faults — but only after those byproducts have accumulated.

There are two forms: lab and online. Lab DGA: an oil sample is extracted and sent to an accredited laboratory, where gas concentrations are measured by gas chromatography against IEEE and IEC standard thresholds. Lab DGA is a lagging indicator — gases accumulate only after a fault has already progressed. Lab DGA remains required annually alongside VIE as a confirmatory safety net. Online DGA: a permanently installed sensor provides continuous gas trend monitoring without manual sampling. VIE replaces the online DGA function — operators with VIE deployed do not require a separate online DGA system. VIE detects the mechanical and thermal precursors to gas generation before chemical signatures appear, extending the detection window earlier in the failure progression.

A test that produces a precise geometric fingerprint of winding and core mechanical condition by injecting a swept signal across the transformer terminals and comparing the response to a commissioning baseline. Plain language: it tells you whether anything inside the transformer has moved or deformed since the last test.

Technically: SFRA detects winding deformation, core movement, inter-winding shorts, and tap changer anomalies with high precision. It requires de-energization. It is the gold standard for confirming mechanical damage after a fault event or transport. In VIE’s workflow, SFRA is a targeted confirmatory test rather than a routine periodic one: a significant rise in VIE’s Impact Metric or Winding Health Metrics is the trigger for scheduling SFRA. VIE reduces the frequency of routine periodic SFRA testing; it does not eliminate post-fault or post-transport testing.

A test that measures dielectric loss in transformer winding insulation and bushings under AC voltage. Plain language: it indicates how well the insulation is still doing its job of blocking current.

Technically: the test is known by three names — Tan-Delta, Dissipation Factor, and Power Factor Test — all referring to the same measurement: the dielectric loss angle of insulation under AC stress. Performed offline. Important distinction for VIE content: bushing testing is outside VIE’s scope and must continue on its standard schedule regardless of VIE deployment. Winding body test frequency can be reduced when VIE Winding Health Metrics are stable — VIE provides the continuous trending that makes this deferral evidence-based rather than arbitrary.

A test that measures furfural compounds dissolved in transformer oil as a proxy for how much cellulose paper insulation has degraded. Plain language: it estimates how much life is left in the insulation by reading the chemical traces of its breakdown.

Technically: furfural compounds are produced by the thermal degradation of cellulose paper. Their concentration in oil provides a non-invasive estimate of paper aging and remaining insulation life. VIE’s Winding Health Metrics and thermal models provide continuous early indicators of insulation stress. A rising Winding Health Metric trend is the signal that warrants ordering a furan analysis — VIE makes this test condition-targeted rather than time-scheduled.

The most accurate direct measure of remaining insulation life, obtained by physically extracting a paper sample from inside the transformer. Plain language: it tells you exactly how degraded the insulation is — but getting the answer requires an outage and partial disassembly.

Technically: degree of polymerization (DP) measures cellulose chain length in a physical paper insulation sample. It is the definitive indicator of remaining insulation life — more accurate than any indirect proxy. It is invasive, requires a planned outage, and is not a routine test. It is performed during end-of-life assessment or when furan analysis results indicate advanced aging. VIE’s thermal models flag sustained overtemperature events that accelerate cellulose aging, helping maintenance teams identify when this test is warranted and avoid ordering it prematurely.

Localized electrical breakdown inside the insulation system — not a full arc, but a precursor to one. Plain language: it is the early warning sign that the insulation is beginning to fail in a specific location.

Technically: partial discharge (PD) occurs when a localized region of the insulation system breaks down electrically without fully bridging the gap between conductors. Left undetected, it progressively erodes insulation until full failure occurs. VIE detects a significant proportion of partial discharge activity through vibration anomalies: spikes in structural vibration as transients excite local resonance, increased high-frequency non-harmonic content, and thermal gradient shifts that correlate with transient events. Precise spatial localization of PD sources requires dedicated acoustic or electrical methods that VIE does not provide — VIE’s role is early detection and escalation, not pinpoint localization.

VIE’s mobile application used during sensor installation. Plain language: it is the tool the installation technician uses on-site to register sensors, document the installation, and confirm connectivity before leaving.

Technically: DeployVIE runs on Android and records all information required to commission a monitored asset — sensor IDs and transformer associations, installation locations and heights on the tank surface, transformer nameplate data, installation photographs for remote verification by VIE application engineers, and gateway connectivity confirmation. DeployVIE is an installation tool only. Ongoing health monitoring, trending, and alerts are managed through the myVIE platform.

VIE’s cloud-based monitoring and analytics platform — the interface where operators see transformer health data, alerts, and reports. Plain language: it is the dashboard where the intelligence lives.

Technically: myVIE displays real-time health metrics, historical trending, alert status, and diagnostic reports for every monitored asset in the fleet. It includes collaboration tools — notes, comments, and escalation management — for coordinating between field teams and engineering. An assisted expert mode supports time-domain and frequency-domain chart analysis for operators who want to go deeper than summary reports. Data is exportable for audit, compliance, and capital planning purposes. myVIE is accessible from any browser — no local software installation required.

The hardware device that connects VIE’s sensors to the cloud analytics platform. Plain language: it is the communication bridge between the sensors on the transformer and the platform that processes the data.

Technically: one gateway supports up to 100 simultaneous sensor connections within a 100-meter radius, collecting sensor data via Bluetooth Low Energy. It transmits to the VIE cloud platform via cellular (global and US low-power network variants), Wi-Fi, or Ethernet — selected based on site connectivity. The gateway carries the same IP69K ingress protection rating as the sensors. Auto-recovery architecture means connectivity interruptions do not cause data loss — data is buffered and transmitted when the connection restores. The gateway is configurable remotely without a site visit.

A hardware rating that defines how well equipment resists water intrusion under high-pressure, high-temperature spray. Plain language: it means the sensor and gateway can survive industrial washdowns and harsh outdoor environments, not just light rain.

Technically: IP69K specifies resistance to high-pressure, high-temperature water jets — 80 bar pressure, 80°C temperature, at close range. It is the standard applied to equipment deployed in food processing facilities, industrial plants, and environments with regular cleaning protocols. Both the VIE sensor and gateway carry this rating, making them suitable for outdoor substations, coastal and marine environments, and facilities where equipment is regularly cleaned under pressure. It is a stricter standard than general weatherproofing or splash resistance ratings.

A certification confirming that VIE sensors are safe to deploy in the most hazardous explosive atmospheres in oil and gas facilities. Plain language: it means VIE can be installed in classified areas where most commercial monitoring hardware is not permitted.

Technically: ATEX is the European certification framework for equipment used in potentially explosive atmospheres. Zone 0 is the most stringent gas atmosphere classification — an area where an explosive gas mixture is continuously present or present for long periods. Zone 20 is the equivalent classification for explosive dust atmospheres. VIE sensors are ATEX Zone 0/20 certified, meaning they meet the ignition-prevention requirements for deployment in refineries, offshore platforms, compressor stations, and other classified O&G environments where standard commercial monitoring hardware is excluded. This certification is the foundation of VIE’s deployment capability in oil and gas applications.

Two approaches to transformer maintenance that differ in when they act. Time-based maintenance tests and services equipment on a fixed calendar schedule regardless of its actual condition. Condition-based maintenance acts when monitoring data indicates the asset needs attention. Plain language: one approach treats every transformer the same; the other treats each transformer according to what it is actually doing.

VIE enables condition-based maintenance at fleet scale. Instead of testing every transformer on a fixed interval, operators direct diagnostic resources toward the assets whose VIE metrics are trending and defer testing on assets showing stable, baseline-consistent health. This is the core operational shift that continuous monitoring makes possible — and the explicit requirement of NFPA 70B-2023.

A three-category framework for describing when a diagnostic signal provides actionable information relative to a failure event. Plain language: leading indicators warn you early, coincident indicators tell you what is happening now, lagging indicators confirm what has already occurred.

In transformer diagnostics: Leading indicators change before a failure develops and provide the longest planning window — VIE’s Winding Health Metrics, Oil Health Metrics, and Partial Discharge detection are leading indicators. Coincident indicators reflect conditions happening right now and signal that intervention is urgent — VIE’s Impact Metric and Thermal Metrics are coincident indicators. Lagging indicators validate changes that have already occurred — Dissolved Gas Analysis, Sweep Frequency Response Analysis, Insulation Resistance testing, and Tan-Delta are lagging indicators. Most of the transformer maintenance industry currently operates on lagging indicators. VIE operates on leading and coincident ones.

The regulatory framework that governs the reliability of the North American bulk electric system. Plain language: NERC sets the rules that make utilities accountable for grid uptime — and VIE’s continuous monitoring capability directly supports compliance with those rules.

Technically: the North American Electric Reliability Corporation (NERC) develops and enforces mandatory reliability standards for transmission and bulk generation assets. Its Critical Infrastructure Protection (CIP) standards govern cybersecurity for grid assets. NERC reliability standards create direct incentives for utilities to adopt condition monitoring programs that reduce unplanned outages — the measurable outcome VIE’s continuous fleet intelligence delivers. For Greg persona (utility) buyers, NERC reliability obligations are a primary driver of the business case for continuous transformer monitoring.

The updated U.S. standard for electrical equipment maintenance that now requires condition-based maintenance documentation — making continuous monitoring a compliance obligation, not just a best practice. Plain language: it changed the rules. Scheduled inspections alone no longer satisfy it.

Technically: NFPA 70B-2023 is the National Fire Protection Association’s standard for Recommended Practice for Electrical Equipment Maintenance. The 2023 revision made condition-based maintenance (CBM) the required approach for transformer fleets — specifically requiring documentation that demonstrates actual equipment condition, not just a record of scheduled visits. VIE directly addresses six clauses: 4.2 (maintenance program requirements), 5.2 (condition monitoring), 9.1.2 and 9.2 (transformer inspection and testing), 9.2.3 (condition assessment), 11.3 (predictive maintenance), and Annex D (condition monitoring guidance). The myVIE platform generates a continuous, timestamped health record for every monitored asset from the day sensors are installed — satisfying the documentation requirement automatically.

The established IEEE and IEC standards that define how Dissolved Gas Analysis results are classified and acted upon. Plain language: they are the industry’s agreed-upon safety thresholds for what gas concentrations in oil mean — and VIE’s leading indicators are designed to complement them, not replace them.

Technically: IEEE C57.104 (North America) and IEC 60599 (international) define the gas concentration thresholds and ratio methods used to interpret DGA results. Both standards align closely on fault gas identification. VIE’s approach is complementary: annual lab DGA under these standards remains part of a complete maintenance program as a confirmatory safety net. VIE’s leading indicators detect the mechanical and thermal precursors to gas generation weeks to months before gas concentrations reach DGA thresholds — giving operators the planning window to respond before a lagging indicator confirms the fault has progressed.