Analytics enabled by waveform analysis

by Daniel Sabin and Jon A. Bickel

Executive summary Waveform analysis has long been a useful tool for troubleshooting power-quality events within a facility’s electrical system. Waveform captures, taken during anomalous power events, provide clues to an events’ causes, frequency, and their effects.

Interpreting waveform captures used to be the job of experienced power systems engineers. Today, though, non-engineers often are called on to understand their meanings. Doing so successfully requires an understanding of the ways various disturbances can present themselves during a captured event. Schneider Electric White Paper 2

The ability to capture waveforms of power quality events has been available since the Introduction 1980s. It has historically been a useful method to visualize disturbances, helping to troubleshoot and resolve problems. Only a subset of metering devices are capable of capturing waveforms, which often require special hardware and firmware and are typically more expensive to purchase. How exactly waveform captures are processed within the metering device is a topic for another paper; this document is focused on what to do with the waveform once it has been captured.

Historically, waveforms have been gathered and analyzed by experienced power systems Waveform engineers who analyzed and provided explanations of what they saw and how it was basics impacting (or could impact) the end-user’s electrical system. Analogous to physicians interpreting X-rays or MRIs in the medical field, specialized power systems engineers have analyzed and interpreted voltage and current signals captured from unhealthy electrical systems. Regrettably, fewer businesses now employ full-time power systems engineers, requiring non-engineers to become experts in the “cryptic arts” of interpreting waveforms captured by their power monitoring devices.

An example waveform measurement is exhibited in Figure 1, which shows voltage and current samples recorded during a single-phase fault. Clues that the measurement are due to a downstream fault include a drop in voltage amplitude on one phase, asymmetric rise in current magnitude on the same phase, the decay in asymmetry after one cycle, and the sudden interruption of the fault current magnitude at the same time the voltage amplitude returns to normal.

Figure 1 Voltage and current waveform recorded during a single-phase fault

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Waveform captures taken during anomalous power events include many clues as to those events’ causes, frequency, and their effects. These clues are in the form of waveform characteristics, some which are apparent and some which are not. These can include those summarized in affected phases, peak magnitude, RMS minimum, duration, phase jump, and more.

● Affect phase(s) ● RMS min/max ● IEEE 1159 1 ● Initial polarity ● Amplitude min/max category ● Rise time ● Duration ● Imbalance ● Phase shift ● Decay rate ● Zero-sequence ● Load impact ● Periodicity ● Negative-sequence ● Frequencies ● Waveshape

When evaluating waveform captures, it is important to consider external contributing influences as well. For example, a few of these influences may be load types, meter constraints, meter locations, configurations, operational parameters, and more.

As previously mentioned, voltage and current signals from one, two, or three phases may be captured by metering devices. Each captured signal and each phase provides insights into the cause, impact, and outcome of a power quality event. The voltage(s) provide information regarding the quality of the energy source; the current(s) provide information regarding the flow of energy from the source. Troubleshooting with waveform captures often requires the use of both voltage and current signals to fully comprehend an issue.

Voltage and current are the primary quantities measured by electrical sensors. Most What sensor instruments use analog-to-digital converters that sample instantaneous values of measurements the voltage and current signals. These digital voltage and current samples are used to are available derive a number of voltage, current, power, and energy characteristics. for evaluating AC electrical power systems are designed to provide voltage that follows a sinusoidal waveshape with a frequency of 50 Hz or 60 Hz (that is, with a sinusoid that repeats 50 or power quality 60 times per second), so these instantaneous voltage and current samples are frequently disturbances? referred to as waveform samples. A “Waveform Event” is a collection of waveform samples that start and end based on assigned triggers or thresholds. Waveform samples can be summarized by computing a root mean square (RMS) value over one 50 Hz or 60 Hz cycle that will result in a “DC-like” signal. An “RMS event” is a collection of RMS voltage and/or current values.

Waveforms may also be summarized using Fourier transforms that assume that the waveform is sinusoidal and periodic (that is, the waveform follows a pattern that repeats). Fourier transforms convert waveform samples into magnitudes and phasor angles known as “phasors”.

1 “IEEE Recommended Practice for Monitoring ,” in IEEE Std 1159- 2019 (Revision of IEEE Std 1159-2009) , vol., no., pp.1-98, 13 Aug. 2019.

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Measurements created from the measured waveform, RMS, and phasor values fall into five categories, see Table 1:

● High-Speed Transient Capture Events: Voltage signals sampled at a very high rate (for example, 10 MHz) for durations of microseconds to milliseconds. Voltage disturbances captured using this type of measurement may be caused by surges and circuit-switching events. Because the duration of the measurement capture is typically less than the period of a 50 Hz or 60 Hz waveform, these measurements are not usually called “waveform events,” although both types of measurements sample instantaneous voltage. More information about these types of measurements is available in another Schneider Electric white paper.2

● Waveform Events: Voltage, current, and/or power quantities sampled at a high rate (for example 10 kHz to 60 kHz) for durations of milliseconds to seconds. These measurements are frequently used to capture voltage and/or current signals associated with motor or other load startup, capacitor switching, operations, cable energizing, and other switching events.

● RMS Events: Voltage, current, and/or power quantities sampled at a slower rate than waveform logs (for example 50 to 120 Hz) for durations of 250 milliseconds to 60 seconds. In addition to RMS voltage and RMS current, these measurements may include derivations of system frequency, real power, and reactive power. These captures can be used to summarize short duration reductions in voltage known as “voltage sags” (generally due to faults) and longer events, such as a motor startup, overloaded or distribution systems, or the dynamic response of a power system during and after a transmission fault. Phasor magnitudes are often stored in these logs rather than RMS values, such as when the recording is for the fundamental frequency only (e.g., 50 Hz or 60 Hz).

● Event/Alarms Logs: Text or numeric summary of electric power disturbance events that might include minimum, average, and maximum values derived from high- speed transients, RMS event logs, RMS values, and phasor magnitudes. These summaries are often the only record available from a disturbance because the monitoring system was not designed or configured to collect, store, or transmit the waveform or RMS samples.

● Data Logs: Voltage, current, power, and/or energy quantities sampled in regular intervals for over a long period of time, such as an average value every ten minutes. These may be configured to record for days, months, or years. The logs are frequently seen as a record for the electrical system during steady-state but are sometimes enhanced beyond steady-state by providing the maximum or minimum value during an interval of time. They are frequently polled by SCADA systems using periodic sampling, yet may also be more rigorously recorded by a meter following a power quality specification such as IEC 61000-4-30.

2 Jon Bickel, “An Overview of Transients in Power Systems,” Schneider Electric White Paper 998-20579579_GMA.

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Measurement Type Sampling Rate Measurement Duration Quantity Type

Microseconds to High-Speed Transient Logs 5 to 10 MHz Waveform Samples Milliseconds

Table 1 Waveform Events 10 to 120 kHz Milliseconds to Seconds Waveform Samples Summary of measurements RMS Event Logs 50 to 120 Hz Milliseconds to Minutes RMS Samples

Lists of Characteristics Derived Event Summary Logs N/A N/A from Waveform or RMS Samples

Trends/Time Series of RMS Values Data Logs 1 s to 2 hrs Indefinite or Phasor Magnitudes/Angles

Waveform events and RMS events provide useful information to successfully understand and troubleshoot problems, as each provides its own set of clues. For example, waveform events may reveal harmonic distortion issues by direct observation; however, an RMS event capture of the same event is impractical to see the effect of harmonics. Conversely, it is inherently easier to evaluate the magnitude and duration of voltage sag events using RMS events rather than instantaneous waveform events. Transient events are more easily analyzed with instantaneous waveform captures, yet longer-term events such as imbalance, overvoltage and undervoltage conditions are easier to understand using RMS events. In short, each type of measurement is a powerful tool to be used as best suits the issue at hand.

Power monitoring systems may allow end users to incorporate multiple waveform captures from an event to better facilitate troubleshooting. Because each metering device is placed in a different location within an installation or on a circuit, each provides a unique perspective of an event. Composite analyses incorporating clues from multiple discrete metering devices can help locate the source of a problem precisely and more thoroughly validate a problem’s severity. This approach also can help identify the most beneficial or cost-effective approach to mitigate a problem.

Figure 2 shows a chart with the data log records for RMS voltage on Phase A. The Zooming in meter was configured to record minimum, average, and maximum RMS voltage once from data logs every ten minutes. During the ten-minute interval ending at 11:20 AM, the meter recorded a minimum RMS voltage of 75.9% of nominal voltage. It is not clear from looking at the to waveform data log chart whether the cause of this event was a short-duration RMS variation event event (that is, a “voltage sag”), which could be due to an upstream fault, downstream fault, or load startup. It also not clear if the event was due to a long-duration event (that is, “undervoltage”), which could be caused by an overloaded transformer. More detailed information about the ten-minute period is required to further analyze the event.

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Figure 2 Data log for RMS voltage for Phase A showing minimum, average, and maximum values every 10 minutes

Like Figure 2, the samples shown in the RMS event of Figure 3 are RMS voltages; however, it is “zoomed in” on the period when the voltage was reduced. The graph shows the RMS voltage for each 50 Hz cycle rather than a single summary with minimum, average, and maximum value at the end of a ten-minute interval. This expanded view of the disturbance illustrates the RMS voltage remained below the threshold of 90% of nominal voltage for 60 milliseconds, which is three cycles on the 50 Hz system from which the data was measured. In this example, the RMS voltage disturbance event is classified as an “instantaneous voltage sag” according to IEEE 1159-2019.3

Figure 3 RMS event recorded during the voltage sag

3 “IEEE Recommended Practice for Monitoring Electric Power Quality,” in IEEE Std 1159- 2019 (Revision of IEEE Std 1159-2009) , vol., no., pp.1-98, 13 Aug. 2019.

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Figure 4 presents an even more detailed view of the measurement as a waveform event. Data measurements were recorded at a rate of 128 samples per 50 Hz cycle. The voltage waveforms were sinusoidal during the voltage sag with reduced amplitudes. Figure 5 provides the most detail for the power quality disturbance, this time including current waveform samples. The current has a telltale signature of a single-phase fault: asymmetrical current during the first cycle of the disturbance with a decaying DC offset. Since the voltage and current waveforms are in phase with each other, the chart makes it possible to state that this disturbance was due to a downstream single-phase fault and cleared by a within three cycles.

Figure 4 Waveform event with voltage samples recorded during the voltage sag

Figure 5 Waveform event with voltage and current samples recorded during the voltage sag

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The previous section showed how we can use measurements from an advanced meter to Causes and provide better event resolution – from data logs to waveform event captures – to identify a impacts of voltage sag event. But what exactly are voltage sags and why are they important? voltage sags Voltage sags and other short-duration RMS variations are the most prevalent type of power quality issue in electrical systems. They are defined by IEEE 1159-2019 as having a duration of a half cycle to one minute. Short-duration RMS events such as voltage sags are transitory in nature, and often are characterized by larger reductions in the RMS voltage than generally occur in longer-duration voltage events. Voltage sags can originate inside an energy consumer’s facility or outside on the utility system’s network. The root cause of the voltage sag may be inadvertent or intentional, and the impact of the voltage sag may be subtle or overt. The influence of short-duration RMS variations on the proper operation of electrical systems is dependent on many factors including system design, load sensitivity, event characteristics, and/or process/business impact.

Specific sources of voltage events that originate inside facilities can include normal load activation (e.g., motor starts and transformer energization), switching events (e.g., open- transition ATS transfers), and anomalous events (e.g., faulted circuits or loads, or breaker trips). For example, induction motors consume 6 to 10 times their normal full-load running current when they are energized. This effect is commonly referred to as motor inrush current, which produces a corresponding voltage sag and sometimes impacts nearby loads. In some cases, voltage sags from motor starts can cause equipment controls to reinitialize, reset, or drop offline, impacting production. Open-transition switching may temporarily remove the source voltage from loads, causing impacted loads to trip. Electrical faults are the most severe cause of short-duration voltage events because they significantly change the impedance of the system on which they occur. During fault conditions, interruptions may be expected on the circuit experiencing the fault due to protection devices, and substantial voltage sags will likely occur on circuits adjacent (i.e., parallel) to the faulted circuit.

It is not unusual to see the start-up of a large motor within a facility causing voltage sags severe enough to disrupt sensitive equipment. Examples of loads may be air compressors, industrial pumps, chillers and fans.

External sources (that is, upstream from the utility service transformer) that can cause short-duration RMS voltage events are similar to internal sources, and may originate from customer loads, normal utility system operation, and abnormal utility system events. External sources may include a range of causes such as energization of large customer loads downstream of the facility being monitored or upstream on a parallel circuit, circuit switching, operation of protection devices, adverse atmospheric conditions such as lightning or high wind, encroaching vegetation, wildlife interference, construction dig-ins, equipment damage, accidents, and maintenance issues. Because utilities are typically the primary or sole energy source for the majority of energy consumers, short duration RMS events originating on utilities often produce substantial impacts on energy consumers’ electrical systems.

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Typical commercial or industrial facilities may experience ten or more voltage sags per year at the service entrance, and the occurrence of voltage sags measured inside the plant can be much higher. In fact, the majority of voltage sags have been shown to originate inside customer facilities. IEEE 1346-19984 presented a chart, shown in Figure 6, illustrates the average rate of voltage sags per year from a survey of 27 electric utility systems across the United States. EPRI determined that most voltage sags range between 70% and 90% of the system’s nominal voltage, which coincides with voltage sag thresholds of many types of equipment. More information about the EPRI survey of voltage sags in electric distribution systems is available in.5

Figure 6 Average rate of voltage sags per year for from EPRI Distribution System Power Quality (DPQ I) from IEEE 1346-1998

Voltage sags do not generally disrupt incandescent and fluorescent lighting, motors, and electric heaters. However, some electronic equipment lacks sufficient internal and therefore cannot ride through sags in their source voltage.

The aforementioned standard IEEE 1346-1998 recommends a standard methodology for technical and financial analysis of compatibility between process equipment and an electric power system. The more recent IEEE 1668-20176 presents recommended practices for testing the sensitivity of load equipment to voltage sags and interruptions. IEEE P2938 is a new standards project that will result in guidance for economic loss evaluation of sensitive industrial customers caused by voltage sags.

4 IEEE Recommended Practice for Evaluating Electric Power System Compatibility with Electronic Process Equipment,” in IEEE Std 1346-1998 , vol., no., pp.0_1-, 1998. 5 Daniel Sabin, Thomas Grebe and Ashok Sundaram, “RMS voltage variation statistical analysis for a survey of distribution system power quality performance,” IEEE Society. 1999 Winter Meeting (Cat. No.99CH36233), New York, NY, USA, 1999, pp. 1235-1240 vol.2. 6 IEEE Recommended Practice for Voltage Sag and Short Interruption Ride-Through Testing for End-Use Electrical Equipment Rated Less than 1000 V,” in IEEE Std 1668- 2017 (Revision of IEEE Std 1668-2014) , vol., no., pp.1-85, 27 Nov. 2017.

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This section provides more examples of power quality disturbances summarized with Voltage sag RMS event captures and waveform event captures. Also includes are the typical causes waveform event and impacts of the events. All of the examples in this section can be categorized as and RMS event voltage sags. examples Downstream load start Figure 7 presents the RMS event samples captured during a downstream load start event. Although the RMS voltage is below 90% of nominal voltage for only 0.22 seconds, the voltage takes more than 1.7 seconds to recover back to its pre-event levels. Figure 8 illustrates the instantaneous waveform event samples recorded during the event. The voltage and current waveforms can be used to calculate the change in delivered load, which is an increase of 115 kW.

Downstream Load Start

Figure 7 RMS event captured during a downstream load start event

Downstream Load Start

Figure 8 Waveform event captured during a downstream load start event

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Upstream voltage sag Figure 9 presents the RMS event samples captured during another voltage sag with a duration of 0.6 seconds and an RMS voltage below 90% of the nominal voltage. After 0.3 second voltage sag, it appears a significant portion of the load supplied by this voltage dropped offline. From the instantaneous waveform event samples shown in Figure 10 (see page 13), approximately 99% of the pre-event load was lost (that is, there was a reduction of 99.26 kW in the measured load). The load loss demonstrated in this example is the subject of another white paper by Schneider Electric.7 A clue that the cause of the voltage sag was upstream, not downstream, is the voltage sag continued even after the load current went nearly to zero.

Figure 9 RMS event captured during an upstream voltage sag

Figure 10 Waveform event captured during an upstream voltage sag

7 Jon Bickel, “Voltage Sag Analysis and Load Loss Detection”, Schneider Electric White Paper 998-20764650_GMA.

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Downstream fault Figure 11 presents the RMS voltage and current measured during a downstream single- line-to-ground fault. The Phase A voltage drops coincident with an increase in the Phase A current. Voltage on Phase B shows a slight rise, which is typical when there is shift in neutral. Figure 12 shows the instantaneous waveform event captured during the fault. After the first cycle, the waveforms are primarily sinusoidal with positive and negative peaks equal in magnitude. After the second cycle of a fault, the current is typically stable until the fault is interrupted by a circuit breaker or fuse. The duration of a fault is dependent upon the magnitude of the fault current. Larger fault currents typically trip a breaker or fuse more quickly.

Figure 11 RMS event captured during a downstream single-line- to-ground fault

Figure 12 Waveform event captured during a downstream single-line-to-ground fault

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Downstream inrush event Figure 13 presents another type of voltage sag caused by a downstream power transformer being energized. Inrush current is produced by saturating the magnetic core of the transformer. Figure 14 displays the instantaneous waveform event capture taken during the inrush current. Unlike the current waveform signatures for a fault, the positive and negative peaks of this waveform are asymmetrical. The current magnitude shows an offset that decays exponentially over a period lasting one second or more.

Downstream Inrush Event

Figure 13 RMS event captured during a downstream inrush event

Figure 14 Waveform event captured during a downstream inrush event

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Proper configuration of metering devices is an important part of capturing waveforms, and Configuration power quality events in general. Voltage and current events are generally captured by details setting thresholds to trigger the meter to save buffered waveform event data to memory. These thresholds are indicative of a change in the voltage and/or current signals, and may be based on the amplitude (e.g., absolute, relative, etc.), duration (e.g., how long the event lasted), content of the voltage and/or current signal (e.g., harmonic frequencies) or from some other external input.

It is important to validate that the metering device is properly configured before enabling the waveform capture feature both to ensure the appropriate information is captured by the meter and to reduce the prospect of copious and inconsequential alarms and waveform captures. Improperly swapping or inverting the metering device’s instrument transformer connections (e.g., interchanging the two leads on a current transformer) may produce measurements of limited value. Configuring the meter’s nominal voltage with incorrect values, or overlooking its configuration altogether, may trigger nuisance events, or result in missed events, respectively.

Capturing voltage and current waveforms events can greatly assist in determining the Conclusion cause and direction of a voltage sag. For example, the magnitude of current during an electrical fault and during an inrush current are significantly greater than the normal load current. However, waveform signatures can greatly assist in differentiating between the two. Knowing a voltage sag was the result of a downstream fault means the first step to resolve the problem should be finding the location of the fault and making the appropriate repairs. In contrast, knowing a voltage sag was caused by an upstream event means the first step in recovery might be as simple as restarting the impacted loads.

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About the authors Daniel Sabin, P.E. is an Edison Technical Expert and Senior Principal Architect with Schneider Electric in Andover, Massachusetts, USA. He is part of the Schneider Electric Digital Power team that accelerates data-based competencies & business by exploring & incubating new analytics applications, new analytics platforms, and new organizational models & processes for analytics. Previously, Dan was a Principal Engineer and Software Architect with Electrotek Concepts, where he led the development of the PQView software team for power quality database management & analysis and automatic fault analysis and fault location. He also developed PQDiffractor, which is a widely-used viewer for IEEE Std 1159.3 PQDIF and IEEE Std C37.111 COMTRADE files. He is also a project manager with EPRI Solutions and EPRI focusing on power quality monitoring, grid analytics algorithm development, and distribution fault location automation. Dan has a Master of Engineering Degree in Electric Power from Rensselaer Polytechnic Institute in New York. He is a registered professional engineer in Tennessee, an IEEE Fellow, the Vice Chair for Standards for the IEEE PES Transmission & Distribution Committee and a Past Chair of the Power Quality Subcommittee of the IEEE Power & Energy Society, and the chair of the IEEE P1409 Working Group on Power Quality Solutions.

Jon A. Bickel, P.E. is a Senior Edison Technical Expert and Multi-Technologies Distinguished Technical Expert with Schneider Electric in Franklin, Tennessee, USA. He is part of the Schneider Electric Digital Power team, accelerating data-based competencies & business by exploring & incubating new applications and analytics for hardware, software and cloud-based systems. Previously, Jon was a Senior Energy Consultant at TXU Corporation (now Oncor) in Dallas, Texas, and has worked in the areas of nuclear generation, distribution engineering, large customer account management and power quality services. Since joining Schneider Electric, Jon has worked in offer management, intellectual property development, and research and development. His fields of interest include power systems, power quality and metering systems. Jon received a B.S. (87’) and M.Sc. (99’) in electrical and computer engineering from Kansas State University, Manhattan, Kansas, and is a registered professional engineer in Alabama. He has also filed dozens of patent applications globally with more than 30 granting to date in the USA alone.

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Analytics enabled by waveform analysis