In this article we will discuss about:- 1. Long Duration Voltage Variations in Power System 2. Short Duration Voltage Variations in Power System 3. Voltage Imbalance 4. Voltage Fluctuations.
Long Duration Voltage Variations:
It is defined as “Long-duration variations encompass root-mean-square (rms) deviations at power frequencies for longer than 1 min.” ANSI C84.1 specifies the steady-state voltage tolerances expected on a power system.
A voltage variation is considered to be long duration when the ANSI limits are exceeded for greater than 1 min. Long duration variations can be either over voltages or under voltages.
Over voltages and under voltages are generally not the result of system faults, but are caused by load variations on the system and system switching operations. Such variations are typically displayed as plots of rms voltage versus time.
It is defined as an under voltage is a decrease in the rms ac voltage to less than 90 percent at the power frequency for a duration longer than 1 min.
Over voltages are usually the results of load switching (e.g., switching off a large load or energizing a capacitor bank). The over voltages result because either the system is too weak for the desired voltage regulation or voltage controls are inadequate. Incorrect tap settings on transformers can also result in system over voltages.
Under Voltage and Sustained Interruptions:
An under voltage is a decrease in the rms ac voltage to less than 90 percent at the power frequency for a duration longer than 1 min. Under voltages are the results of switching events that are the opposite of the events that cause over voltages. A load switching on or a capacitor bank switching off can cause an under voltage until voltage regulation equipment on the system can bring the voltage back to within tolerances. Overloaded circuits can result in under voltages also.
When the supply voltage has been zero for a period of time in excess of 1 min, the long duration voltage variation is considered a sustained interruption. Voltage interruptions longer than 1 min are often permanent and require human intervention to repair the system for restoration. The term sustained interruption refers to specific power system phenomena and, in general, has no relation to the usage of the term outage. Utilities use outage or interruption to describe phenomena of similar nature for reliability reporting purposes.
However, this causes confusion for end users who think of an outage as any interruption of power that shuts down a process. This could be as little as one-half of a cycle. Outage, as defined in IEEE Standard 100,8 does not refer to a specific phenomenon, but rather to the state of a component in a system that has failed to function as expected. Also, use of the term interruption in the context of power quality monitoring has no relation to reliability or other continuity of service statistics. Thus, this term has been defined to be more specific regarding the absence of voltage for long periods.
Short Duration Voltage Variations:
This category encompasses the IEC category of voltage dips and short interruptions. Each type of variation can be designated as instantaneous, momentary, or temporary, depending on its duration.
Short duration voltage variations are caused by fault conditions, the energization of large loads which require high starting currents, or intermittent loose connections in power wiring. Depending on the fault location and the system conditions, the fault can cause either temporary voltage drops (sags), voltage rises (swells), or a complete loss of voltage (interruptions). The fault condition can be close to or remote from the point of interest. In either case, the impact on the voltage during the actual fault condition is of the short duration variation until protective devices operate to clear the fault.
It is defined as an interruption occurs when the supply voltage or load current decreases to less than 0.1 pu for a period of time not exceeding 1 min. Interruptions can be the result of power system faults, equipment failures, and control malfunctions. The interruptions are measured by their duration since the voltage magnitude is always less than 10 percent of nominal.
The duration of an interruption due to a fault on the utility system is determined by the operating time of utility protective devices. Instantaneous reclosing generally will limit the interruption caused by a non-permanent fault to less than 30 cycles. Delayed reclosing of the protective device may cause a momentary or temporary interruption. The duration of an interruption due to equipment malfunctions or loose connections can be irregular.
Some interruptions may be preceded by a voltage sag when these interruptions are due to faults on the source system. The voltage sag occurs between the time a fault initiates and the protective device operates.
Figure 1.6 shows such a momentary interruption during which voltage on one phase sags to about 20 percent for about 3 cycles and then drops to zero for about 1.8 s until the recloser closes back in.
ii. Sags (dips):
It is defined as sag is a decrease to between 0.1 and 0.9 pu in rms voltage or current at the power frequency for durations from 0.5 cycle to 1 min. The power quality community has used the term sag for many years to describe a short-duration voltage decrease. Although the term has not been formally defined, it has been increasingly accepted and used by utilities, manufacturers, and end users.
The IEC definition for this phenomenon is dip. The two terms are considered interchangeable, with sag being the preferred synonym in the US power quality community.
Terminology used to describe the magnitude of voltage sag is often confusing. A “20 percent sag” can refer to a sag which results in a voltage of 0.8 or 0.2 pu. The preferred terminology would be one that leaves no doubt as to the resulting voltage level: “a sag to 0.8 pu” or “a sag whose magnitude was 20 percent.” When not specified otherwise, a 20 percent sag will be considered an event during which the rms voltage decreased by 20 percent to 0.8 pu. The nominal, or base, voltage level should also be specified.
Voltage sags are usually associated with system faults but can also be caused by energization of heavy loads or starting of large motors. Figure 1.7 shows a typical voltage sag that can be associated with a single-line-to-ground (SLG) fault on another feeder from the same substation. An 80 percent sag exists for about 3 cycles until the substation breaker is able to interrupt the fault current. Typical fault clearing times range from 3 to 30 cycles, depending on the fault current magnitude and the type of overcurrent protection.
Figure 1.8 illustrates the effect of a large motor starting. An induction motor will draw 6 to 10 times its full load current during start-up. If the current magnitude is large relative to the available fault current in the system at that point, the resulting voltage sag can be significant.
In this case, the voltage sags immediately to 80 percent and then gradually returns to normal in about 3 s. Note the difference in time frame between this and sags due to utility system faults.
Until recent efforts, the duration of sag events has not been clearly defined. Typical sag duration is defined in some publications as ranging from 2 ms (about one- tenth of a cycle) to a couple of minutes. Under voltages that last less than one-half cycle cannot be characterized effectively by a change in the rms value of the fundamental frequency value. Therefore, these events are considered transients. Under voltages that last longer than 1 min can typically be controlled by voltage regulation equipment and may be associated with causes other than system faults. Therefore, these are classified as long-duration variations.
Sag durations are subdivided here into three categories—instantaneous, momentary, and temporary—which coincide with the three categories of interruptions and swells. These durations are intended to correspond to typical utility protective device operation times as well as duration divisions recommended by international technical organizations.
It is defined as swell is defined as an increase to between 1.1 and 1.8 pu in rms voltage or current at the power frequency for durations from 0.5 cycle to 1 min.
As with sags, swells are usually associated with system fault conditions, but they are not as common as voltage sags. One way that a swell can occur is from the temporary voltage rise on the unfaulted phases during an SLG fault.
Figure 1.9 illustrates a voltage swell caused by an SLG fault. Swells can also be caused by switching off a large load or energizing a large capacitor bank. Swells are characterized by their magnitude (rms value) and duration. The severity of a voltage swell during a fault condition is a function of the fault location, system impedance, and grounding. On an ungrounded system, with an infinite zero-sequence impedance, the line-to-ground voltages on the ungrounded phases will be 1.73 pu during an SLG fault condition.
Close to the substation on a grounded system, there will be little or no voltage rise on the unfaulted phases because the substation transformer is usually connected delta-wye, providing a low-impedance zero-sequence path for the fault current. Faults at different points along four-wire, multi-grounded feeders will have varying degrees of voltage swells on the unfaulted phases. A 15 percent swell, like that shown in Fig. 1.9, is common on US utility feeders.
The term momentary overvoltage is used by many writers as a synonym for the term swell.
Voltage imbalance (also known as voltage unbalance) is sometimes defined as the maximum deviation from the average of the three-phase voltages or currents, divided by the average of the three-phase voltages or currents, expressed in percent. Imbalance is more rigorously defined in the standards using symmetrical components.
The ratio of either the negative-or zero sequence components to the positive-sequence component can be used to specify the percent unbalance. The most recent standards 11 specify that the negative-sequence method be used. Figure 1.10 shows an example of these two ratios for a 1-week trend of imbalance on a residential feeder.
The primary source of voltage unbalances of less than 2 percent is single-phase loads on a three-phase circuit. Voltage unbalance can also be the result of blown fuses in one phase of a three-phase capacitor bank. Severe voltage unbalance (greater than 5 percent) can result from single-phasing conditions.
Voltage fluctuations are systematic variations of the voltage envelope or a series of random voltage changes, the magnitude of which does not normally exceed the voltage ranges specified by ANSI C84.1 of 0.9 to 1.1 pu.
IEC 61000-2-1 defines various types of voltage fluctuations. We will discuss about IEC 61000-2-1 Type (d) voltage fluctuations, which are characterized as a series of random or continuous voltage fluctuations.
Loads that can exhibit continuous, rapid variations in the load current magnitude can cause voltage variations that are often referred to as flicker. The term flicker is derived from the impact of the voltage fluctuation on lamps such that they are perceived by the human eye to flicker. To be technically correct, voltage fluctuation is an electromagnetic phenomenon while flicker is an undesirable result of the voltage fluctuation in some loads. However, the two terms are often linked together in standards. Therefore, we will also use the common term voltage flicker to describe such voltage fluctuations.
An example of a voltage waveform which produces flicker is shown in Fig. 1.13. This is caused by an arc furnace, one of the most common causes of voltage fluctuations on utility transmission and distribution systems. The flicker signal is defined by its rms magnitude expressed as a percent of the fundamental. Voltage flicker is measured with respect to the sensitivity of the human eye. Typically, magnitude of 0.5 percent can result in perceptible lamp flicker if the frequencies are in the range of 6 to 8 Hz.
IEC 61000-4-15 defines the methodology and specifications of instrumentation for measuring flicker. The IEEE Voltage Flicker Working Group has recently agreed to adopt this standard as amended for 60-Hz power systems for use in North America. This standard devises a simple means of describing the potential for visible light flicker through voltage measurements.
The measurement method simulates the lamp/eye/brain transfer function and produces a fundamental metric called short-term flicker sensation (Pst). This value is normalized to 1.0 to represent the level of voltage fluctuations sufficient to cause noticeable flicker to 50 percent of a sample observing group. Another measure called long-term flicker sensation (Plt) is often used for the purpose of verifying compliance with compatibility levels established by standards bodies and used in utility power contracts. This value is a longer-term average of Pst samples.
Figure 1.14 illustrates a trend of Pst measurements taken at a 161- kV substation bus serving an arc furnace load. Pst samples are normally reported at 10-min intervals. A statistical evaluation process defined in the measurement standard processes instantaneous flicker measurements to produce the Pst value. The Pit value is produced every 2 h from the Pst values.