Partial Discharge, Infrared Thermography and NFPA 70b

A Case for Electrical Reliability and Condition-Based Maintenance

Insulation-related failure mechanisms account for the majority of electrical equipment failures in industrial and commercial power systems.

IEEE Std 493 (Gold Book)

As of this writing, NFPA® 70B has been a mandatory standard for just over three years; however, industry surveys suggest that only approximately 16% of organizations are positioned for compliance. This gap is significant when viewed alongside long standing industry data. According to the IEEE Gold Book (IEEE Std. 493), insulation failure remains the predominant cause of electrical equipment outages, with many asset classes demonstrating insulation related failure rates between 84% and 95%. Given these statistics, Condition Based Monitoring (CBM) programs that strategically deploy both Partial Discharge (PD) monitoring and Infrared (IR) thermography should be considered standard practice for any organization operating medium or high voltage substations.

My aim is to provide technically accurate, accessible guidance on both technologies—explaining their roles, advantages, limitations, and practical integration—while helping remove persistent misconceptions surrounding PD monitoring. Historically, PD technologies have been perceived as cost prohibitive or requiring expert interpretation. Modern advancements have largely eliminated these barriers. Today, PD is not only viable but essential for improving equipment reliability, enhancing personnel safety, and achieving NFPA® 70B compliance. Although numerous vendors offer solutions and opinions may vary, the aim here is to communicate in clear language how PD monitoring can be readily integrated into existing electrical infra structure to advance compliance, safety, and reliability objectives.

PD Testing and Monitoring functions much like diagnostic bloodwork in medicine, revealing hidden internal problems long before symptoms appear, while also acting as an emergency physician when severe electrical stress is present. IR thermography complements this by detecting thermal symptoms on the external surfaces of components, such as loose connections, unbalanced loading, or overheating conductors – similar to how an urgent care or emergency room evaluates visible physical symptoms that signal conditions requiring prompt intervention.

This writing serves to frame PD as the primary predictive insulation diagnostic and IR as a rapid thermal condition identifier. A PD first analysis compares detection physics, failure stage sensitivity, data structures, deployment methods, and maintenance implications, interpreting both technologies within NFPA® 70B’s CBM philosophy and equipment condition categories. A Partial Discharge led integrated maintenance strategy recognizes that PD and IR each identify existing issues as well as conditions that may progress into future failures—but within different layers of the electrical system.

Because insulation defects account for most electrical failures, PD delivers the earliest insight into internal degradation and also captures late stage discharge activity requiring immediate response. In this respect, the following analogy remains central to understanding their complementary roles:

PD functions much like diagnostic bloodwork in medicine, revealing hidden internal problems long before symptoms appear, while also acting as an emergency physician when severe electrical stress is present. IR thermography complements this by detecting thermal symptoms on the external surfaces of components, such as loose connections, unbalanced loading, or overheating conductors – similar to how an urgent care or emergency room evaluates visible physical symptoms that signal conditions requiring prompt intervention.

Together, these technologies form a layered CBM methodology in which PD provides deep predictive insight into insulation condition, while IR identifies surface level thermal anomalies once a condition becomes externally evident. This combined diagnostic strategy enhances reliability, supports informed maintenance decisions, and significantly reduces the likelihood of unplanned outages in mission critical electrical environments.

Partial discharge measurements are among the most important diagnostic tools for reliable assessment of the condition of new or service-aged high-voltage components.

Introduction

Reliability expectations for medium-and high-voltage power systems continue to tighten, particularly in mission-critical facilities where insulation failures can precipitate disproportionate operational and safety consequences. NFPA® 70B formalizes Condition-Based Maintenance (CBM) as the organizing principle for electrical maintenance programs, directing organizations to base maintenance intervals and actions on measurable equipment condition and to use qualified diagnostic techniques, including continuous monitoring and infrared thermography. Within this CBM paradigm, Partial Discharge (PD) diagnostics provide a leading indicator of insulation health by detecting localized dielectric breakdown (voids, surface tracking, corona, and defects in joints/terminations) that often precedes thermal expression by months or years. PD can be identified using portable spot testing and via semi-permanently or permanently installed monitoring systems that capture intermittent activity and trending behavior needed for predictive decisions. Infrared (IR) thermography, in turn, delivers rapid, energized detection of thermal symptoms—such as resistive heating at terminations and load imbalance—especially effective when performed through polymer-optic IR windows that maintain closed-panel safety and repeatable access points. This paper elevates PD to the primary predictive layer and positions IR as the essential condition-identification layer, consistent with NFPA® 70B’s emphasis on evidence-based maintenance and equipment condition categorization.

Technologies Overview

PD Spot Testing

PD spot testing uses portable tools for snapshot diagnostics on energized equipment. Core modalities include ultrasonic (airborne acoustic emissions from arcing/tracking), TEV (transient earth voltage on metalclad surfaces), HFCT (current pulses on earth/ground conductors), and RF/UHF sensing for radiated emissions (e.g., GIS). Contemporary instruments add phase-resolved PD analysis and noise rejection algorithms to distinguish true PD from environmental noise, enabling effective detection and localization during short test windows. Spot testing is well-suited for periodic screening, troubleshooting, and pre-shutdown checks across MV/HV assets. While its snapshot nature can miss intermittent activity, it is an efficient front-end filter to identify assets that warrant escalation to continuous monitoring.

PD Continuous Monitoring

Permanent instrumentation (TEV, ultrasonic, HFCT, RF/UHF) attached to critical assets streams time series PD data to analytics platforms for trending, pattern recognition, and alarm thresholds; this captures intermittent events and supports predictive maintenance schedulingbefore faults occur. Decades of field experience and large installed bases have produced extensive PD event databases and long-running networks, strengthening confidence in trend thresholds and classification methodologies [2]. Monitoring is deployed from secondary distribution switchgear to EHV transmission and underground cables, prioritizing assets whose failure consequences justify the investment.

Infrared Thermography

Infrared (IR) thermography is a non-contact diagnostic method that converts infrared radiation emitted from energized electrical equipment into visual thermal images. It is widely used to identify abnormal heating associated with loose or deteriorated connections, load imbalance, faulty components, and mechanical friction that manifest as localized temperature rise at the surface level. IR inspections are typically performed while equipment remains energized, making the technology particularly valuable for routine condition based maintenance surveys. The use of polymer optic IR inspection windows further enhances safety and repeatability by enabling closed panel inspections while reducing arc flash exposure.

While IR thermography is highly effective at identifying present state thermal anomalies, its diagnostic visibility is inherently limited to external surface conditions and requires sufficient heat generation to be detectable.

Technology Advantages and Limitations

Partial Discharge Surveying Tools and Infrared Thermography Tools share many common traits, both in ease of operation and portability:

• Rapid scanning of large equipment populations during rounds
• Portable and efficient for CBM walk-downs and troubleshooting.

However, Partial Discharge surveying offers some distinct advantages over IR:

• Detects insulation defects before thermal symptoms.
• Multi-modal sensing (ultrasonic, TEV, HFCT, RF) covers diverse assets.
• Advanced noise rejection and PRPD analytics enhance confidence.
• Supports localization for targeted maintenance.
• Closed Panel Inspections without need for Modification or Special Windows
• Recognized in NFPA® 70B as a routine diagnostic for energized systems.

Infrared Thermography has additional drawbacks:

• Surface-level; cannot detect incipient insulation defects without heat.
• Load-dependent sensitivity and environmental influences.
• Requires optical line-of-sight (mitigated, not eliminated, by windows).
• No direct classification of electrical root causes (e.g., void/corona).

With both Partial Discharge Surveying and Infrared Scans you are only getting a snapshot in time. To get a true sense of the systems health continuous monitoring provides a clear advantage. While there are some strides being made in integrating Infrared technology into continuous monitoring systems currently the mainstream options are primarily Partial Discharge Monitors.

The advantages are clear:

• Continuous time-series trending for predictive thresholds and rate-of change analysis.
• Captures intermittent/transient activity missed by periodic tests.
• Enables risk prioritization, alarms, and remote diagnostics.
• Proven scalability across MV/HV networks and cables.
• Strengthens CBM documentation and decision defensibility.
• Greater level of noise rejection and calssification of PD as opposed to handheld surveyors.

However this methodology is not without some limitations:

• Higher initial installation/integration cost. This investment is readily justified, since avoiding a single major fault event can offset or exceed the full cost of system deployment.
• Sensor and system maintenance/calibration required every few years
• Installation constraints may require outages/retrofits. Though this is mitigated with external sensor installation.
• Sensor placement/design limits constrain coverage in some assets.

These limitations are outweighed by the advantages and abilities to make strategic planned repair decisions. Many operators see return on investment quickly, especially in aging assets, by avoiding unplanned outages and preventing risks to life safety.

Cost of Failure: Industry case studies have documented medium voltage cable termination flashovers in which infrared inspections showed no abnormal thermal conditions prior to failure, while post event investigations confirmed ongoing partial discharge activity originating from installation defects. In these cases, on line partial discharge monitoring would have provided early warning of insulation degradation, enabling corrective intervention before arc fault and flashover occurred.

See W. G. Higinbotham, “On Line Cable PD Testing,” NETA World Journal, Winter 2022 (EA Technology)

Alignment with NFPA® 70B

NFPA® 70B mandates an Electrical Maintenance Program (EMP) built on CBM, emphasizing diagnostics and continuous monitoring to inform maintenance intervals and actions. The standard uses equipment Condition Categories (1–3) and ties inspection frequencies (e.g., annual IR for Condition 1; semiannual for Condition 3) to equipment health and risk.

Within the standard, insulation condition is the primary factor considered for system health. Partial discharge measurement is a globally recognized method for insulation diagnosis and has become a widely adopted and often specified element of acceptance testing for high voltage equipment.NFPA® 70B identifies internal dielectric degradation mechanisms as a leading indicator of failure risk.

Reliance on infrared thermography alone cannot satisfy the diagnostic depth necessary for full alignment with NFPA® 70B’s CBM philosophy. Facilities meaningful alignment with NFPA® 70B’s CBM framework should incorporate partial discharge testing, either through periodic PD assessment or continuous monitoring, into their electrical maintenance programs In this context, PD monitoring is a fundamental compliance element for medium and high voltage systems where insulation failure represents the dominant risk.

Partial discharge activity is a clear indication of insulation defects or degradation and represents one of the earliest detectable phenomena preceding insulation breakdown.

CIGRE Guidelines For Partial Discharge Detection Using Conventional (IEC60270) and Unconventional Methods

Integrated Maintenance Strategy

A PD-first, IR-supported strategy aligns with CBM and maximizes risk reduction: (1) PD Continuous Monitoring on critical assets establishes baseline and trend in real time, captures intermittency, and issues alarms that direct predictive work orders and outage planning; (2) PD Spot Testing provides periodic snapshot screening and localization, identifying candidates for sensorization or targeted repair; and (3) PD Spot Checks and IR Scans validate active ther-mal symptoms and confirms corrective action effectiveness through closed-panel, repeatable inspections using IR windows.

Framing the program in this order aligns with NFPA® 70B’s EMP. Partial Discharge Monitoring gives a constant health check of the system, while PD Scans and IR Scanning allows for quick diagnostics once potential issues have been identified.

Discussion

In high-consequence environments (data centers, substations, industrial plants), the advantage of PD trending is decisive: an asset with rising PD magnitude or changing PRPD pattern can be flagged weeks or months before thermal rise, enabling planned repairs rather than reactive outages. IR remains indispensable for broad, rapid coverage and immediate risk identification, but by design it indicates issues that already produce heat; therefore, as a standalone method, it can miss incipient defects. NFPA® 70B’s condition categories and interval guidance reinforce this PD-first approach: use predictive evidence (including continuous monitoring outputs) to adjust intervals and prioritize interventions, while maintaining routine annual IR (or more frequent for deteriorated conditions) to catch symptomatic issues. A combined program offers both forward-looking (PD) and present-state (IR) visibility, strengthening safety, reliability, and compliance within modern CBM-driven EMPs. This is a best practice approach to the condition-based monitoring ecosystem.

Recent advances in signal processing, automation, and analytics have reduced the expertise barrier historically associated with PD interpretation. While advanced PD analysis still benefits from specialist expertise, modern handheld and continuous monitoring systems have significantly reduced the training barrier, enabling field engineers to obtain actionable results during routine inspections.

Conclusion

In an era defined by hyperscale data centers, tightening power margins, and increasing grid instability, electrical downtime is no longer an acceptable risk. Reliability, availability, and regulatory alignment have become operational imperatives. With NFPA® 70B now in effect as a mandatory standard, organizations are expected to move beyond traditional inspection practices toward measurable, condition based maintenance programs. Infrared thermography remains a valuable component of this approach; however, it satisfies only a portion of the standard’s diagnostic intent. Partial discharge monitoring addresses the critical gap by providing direct insight into insulation health—the dominant failure mechanism in medium and high voltage systems.

The implications for network operators are clear. Compliance with NFPA® 70B is no longer theoretical, asset condition can no longer be inferred solely from surface symptoms, and maintenance strategies based on periodic inspection alone are increasingly misaligned with modern risk exposure. As the industry continues its transition toward predictive and data driven maintenance models, the more relevant question is no longer whether organizations will adopt condition based maintenance, but whether they can afford to be late in doing so. PD monitoring, integrated alongside IR thermography, represents a necessary evolution in achieving compliance, sustaining reliability, and protecting mission critical electrical infrastructure.

References:

[1] IEEE Std 493 2007, IEEE Recommended Practice for the Design of Reliable Industrial and Commercial Power Systems (Gold Book), IEEE, New York, NY, USA.
[2] NFPA 70B 2023, Standard for Electrical Equipment Maintenance, National Fire Protection Association, Quincy, MA, USA.
[3] IEC 60270:2015, High Voltage Test Techniques – Partial Discharge Measurements, International Electrotechnical Commission, Geneva, Switzerland.
[4] IEEE Std 400 2022, IEEE Guide for Field Testing and Evaluation of the Insulation of Shielded Power Cable Systems, IEEE, New York, NY, USA.
[5] CIGRÉ Technical Brochure 654, Guide for the Application of Online Partial Discharge Monitoring on High Voltage Equipment, CIGRÉ Working Group D1.37, Paris, France, 2016.
[6] ISO 18434 1:2008, Condition Monitoring and Diagnostics of Machines – Thermography – Part 1: General Procedures, International Organization for Standardization, Geneva, Switzerland.
[7] ASTM E1934 2015, Standard Guide for Examining Electrical and Mechanical Equipment with Infrared Thermography, ASTM International, West Conshohocken, PA, USA.
[8]NFPA 70E 2024, Standard for Electrical Safety in the Workplace, National Fire Protection Association, Quincy, MA, USA.
[9] IEEE Std 1434 2014, IEEE Guide for the Measurement of Partial Discharges in AC Electric Machinery, IEEE, New York, NY, USA.
[10] CIGRÉ Technical Brochure 781, Practical Use of Partial Discharge Measurements for MV and HV Equipment, CIGRÉ Working Group D1, Paris, France, 2019.
[11] W. G. Higinbotham, “On-line cable PD testing,” NETA World Journal, Winter 2022.
[12] G. McIntosh and R. Huf, “Classification of electrical problems detected by infrared thermography,” The Snell Group, 2021.
[13] M. Goodman, “Methods of inspection to determine the presence of potential arc flash incidents,” UE Systems, 2004.
[14] IEC 60270:2015, High-voltage test techniques – Partial discharge measurements.
[15] CIGRÉ Technical Brochure 654, Guide for the application of online partial discharge monitoring on high-voltage equipment, 2016