DESS Articles

The following articles provide general information about distribution systems. We hope you find them useful whether you’re an existing DESS customer or want to learn more about our software.

General Articles

Load Variation and Modeling Describes load aggregation, peaks and useful tips for using available load data in system modeling.

Load Balancing Describes the purpose, method and benefits of phase balancing on a distribution system.

Regulator and Capacitor Voltage Control Describes controlling voltage with regulators and capacitors, including differences between devices.

Electronic Overcurrent Protection Provides an introduction to the basic features of electronic relays and gives some hints on how to make the most of the features they provide.

Distributed Generation Articles

Load Modeling

Introduction

The biggest factor in creating an accurate model in DESS is loading. To make sure the loading in DESS is accurate you need to understand the difference between average loads, coincident peaks, local peaks, and to understand daily peaks vs. monthly and annual peaks.

Individual vs. Aggregated Loads

The load on a distribution system is varying all the time and varying across the system. At the local level, the load on each distribution transformer may vary very quickly, with a large percentage fluctuation from minute to minute. If you were to graph the load versus time, there would be no discernible pattern. However, if you were to take 5 transformers and measure the aggregated load on these transformers, the load variation would begin to average out across the total load and a rough daily load pattern would begin to emerge. If you were to consider 25 or more transformers, then you would begin to approach a smooth daily load curve.

Variations Over Time

Load varies over the course of a day due to usage patterns. Lights are used more when it’s darker. Commercial customers use more electricity when they’re open for business. Residential customers use more power for cooking and refrigeration when they prepare meals. These variations give distinctive usage patterns for different types of customer over the course of a day.

Load also varies according to the type of day. The schedules of residential customers are different on weekdays than on weekends. Industrial loads may vary on Mondays and Fridays due to startup and shutdown issues.

Load also varies according to season. Seasonal temperatures affect heating and cooling loads. Businesses may have seasonal variations. The number of hours of daylight varies for utilities in northern and southern countries.

So we can see that even discounting random variation of loads, there are differences in load patterns across the course of a typical day, a typical week and a typical year.

Random Variation

In addition to all the patterns we can identify, there will also be random variation in loads. These may be an accumulation of random fluctuations at individual customers or may be caused by large scale but unpredictable events such as elections, strikes, or particularly popular TV shows! The best we can hope to achieve with load modeling is to model average conditions.

Peaks and Averages

There are a number of different types of peak that can be measured. These include the following:

• Local Peak – the time and magnitude of the peak load for a given feeder or station.
• System Peak – the time and magnitude of the peak for the entire system. This may be different from any/all of the local peaks.
• Absolute Annual Peak – the highest recorded value for an entire year. This can be either local or system wide.
• Absolute Monthly Peak – the highest recorded value for a given month. This can be either local or system wide.

Peak information is important for designing for system limits, and may be required for computation of demand charges, but it is less useful for inferring or predicting load behavior. The best data for predicting load behavior is average loading. Properly averaged load data can eliminate random load variation while maintaining useful information for daily, weekly, seasonal or temperature variations. For example, if you could take hourly readings on a feeder every weekday for June and July, and then average these values by hour, you would have a very good idea of how that feeder would behave during an average weekday in August.

DESS Load Modeling

You can’t model small individual loads accurately

There is simply too much variation on a small load and you can’t predictively model what it will do in the future. However, you can accurately model the behavior of loads on a feeder or a chunk of feeder. It is impossible to predictively model an individual customer (although some research has been performed on statistical modeling of individual loads). However, we can represent what happens on a typical type of load, such as a type of residential customer, or a class of commercial customer. DESS uses ‘load categories’ to represent these classes of customer. It is important to recognize that the load categories can only represent the load behavior under typical or average conditions. This is why it is important to understand the nature of system peaks.

Monthly absolute peaks of individual feeders are not useful for validating your DESS model

Monthly peaks may only represent conditions during a single 15 minute period during the month and do not represent average conditions, so the results of a load flow in DESS will typically produce lower loading that the absolute monthly peaks. Furthermore, the monthly peaks for different feeders may represent different times of day or even different days. This means that both the magnitude of the loads and the ratio between loads on different feeders will be different than what needs to be represented in DESS.

Coincident feeder measurement data is best

The most useful data for validating your DESS model is a set of feeder measurements taken at a single point in time. These will give a true relationship between the loading on the different feeders. Even better would be to take a series of these snapshots and average them. For example, if you were to take a snapshot of the loading on each feeder at 3pm on each weekday for two weeks and then average these values, they should match up very closely to the load values produced by a load flow in DESS.

Historical feeder data is probably not useful.

Many utilities keep a lot of historical data for loading on their feeders. Unfortunately, rather fewer people keep track of system configuration changes. Often, it is impossible to determine what the system configuration was when particular measurements were taken. Was there a load transfer between feeders? Was there maintenance activity? Has new load been added to a particular feeder since the measurements were taken? Uncertainty about these questions can limit the value of historical data.

You need to scale an analysis to simulate peak conditions

By default DESS will show average conditions on your system. However, sometimes you want to run analyses at absolute peak conditions. To do this, you will need to scale up the loads by changing the load scaling factor for the analysis. The scaling factor will represent the ratio between the absolute system peak and the average system peak.

References

1. Kundur, P., Power System Stability and Control, 1993, McGraw-Hill, Chapter 7.4, pp 306-311
2. Willis, H.L., Power Distribution Planning Reference Book, 2004, Marcel Dekker, Chapter 2,3, pp 47-102

Load Balancing

Introduction

In North American distribution systems, four-wire distribution feeders are made up of three-phase and single-phase sections, sometimes with limited two-phase sections. Customers are supplied three-phase or single-phase, either from the primary feeder of from a spur. As a consequence, the currents in the three-phase sections are never completely balanced and, in many cases, can be significantly out of balance. It is not uncommon to have as much as 50% difference in magnitude between the highest and lowest loaded phases. Moreover, the degree of imbalance varies along the length of each feeder. Balancing is accomplished by selecting the phase of the supply for each load so that the total load is distributed as evenly as possible between the phases for each section of feeder.

If a single-phase load is supplied from a three-phase node, there are three possibilities for connecting the load. If there are two single-phase loads present, there are 6 possible combinations. Three-phase loads are not considered since most are balanced and changing the phasing order can affect three-phase loads such as motors. If such loads are unbalanced, any corrective balancing action is usually taken at the load itself.

Since single-phase spurs are common in residential areas, the total load associated with such spurs can be significant when considered at the point of connection to the three-phase feeder section. In cases where such spurs are distributed along a feeder and spur loads differ considerably, the three-phase current imbalances between spur connections may be substantial. This is particularly so if the phase selected at such points is not carefully chosen. Figure 1 illustrates a situation where achieving balanced currents along the complete length of feeder is not possible, although the balance is perfect at the feeder start. The spurs could just as well be single-phase loads on a three-phase line.

Balancing Procedure

The procedure must consider all possible combinations of phase load changes at each 3-phase connection point for either single-phase spurs or loads. Consideration must be given to the order in which loads are considered so as not to exclude the best combinations of load phase connections when all selections have been made. The best set of connections will minimize the imbalance as far as possible for each 3-phase section of feeder between spur/load connections.

When planning a new feeder, the spur/load phasing selection is an important factor in producing the best design. A practical consideration when balancing an existing feeder is the need to accomplish the requisite degree of balance with the minimum number of changes to load phasing. To achieve this manually is a difficult exercise and the adoption of optimization techniques is necessary to produce a satisfactory solution. The optimized load balancing procedure ensures that the best balance is achieved along the feeder length, not just at the feeder supply point. It may also be necessary to consider the effect on multiple feeders, as a single-phase subdivision may be fed from more than one feeder, and it is undesirable to have mismatched phasing across open points in the single-phase section.

Benefits

There are a number of benefits that make efficient load phase balancing a worthwhile objective. These are discussed below.

Loading on a feeder section is synonymous with the most heavily loaded phase and, in the case of significant imbalance, feeder capacity is used inefficiently. Balancing between phases tends to equalize the phase loading by reducing the largest phase peak while increasing the load on the other phases. This equates to releasing feeder capacity that can be used for future load increases without reinforcing feeder conductors.

Balancing reduces feeder losses because any phase peak reduction affects the losses for the phases as the square of the current magnitude. A feeder section with 1-ohm resistance that has phase currents of 50A/100A/150A will have 35kW in losses. When balanced at 100A/100A/100A, the loss reduces to 30kW. The same effect is even more evident in the reduction of reactive power losses because the X/R ratio of most feeder sections is greater than 1.

Balancing improves voltage on a feeder by equalizing the voltage drops in each phase along the feeder.

Released feeder capacity provides more reserve loading capacity for emergency loading conditions.

It is realistic to assume that the benefits in improved use of feeder capacity and improved voltage quality are of more significance than the value of loss reduction except when loading is already high.

Overcoming Limitations

Where single-phase spur load is substantial, it may be difficult to improve upon the overall feeder load balance because spur phasing changes simply transfer the imbalances to different phases with no overall improvement. One solution is to increase the number of phases on the spur. If additional conductors are to be strung, the added flexibility of upgrading to three rather than two phases, with the potential for additional future loading and load balancing between feeders, is more attractive. Where a large single-phase load is supplied from a single-phase transformer on a 3-phase feeder, a possible solution is to replace the transformer by two of half the size supplied from different phases.

In certain types of feeder design, all spurs are single-phase and each spur can have substantial loading, as often happens in underground supplied residential areas. Great care must be taken to ensure that significant imbalances do not occur between spur connections on the main feeder, especially if the distances between connection points are significant. This situation is avoided if the spur connection is three-phase and the phases then separate to supply the individual spurs. Where spurs are designed as open loops, the other loop supply is arranged in the same way to form a 3-phase connection at the feeder.

Balancing over a range of loading levels is not a practical proposition because the load/spur connections are not switchable between phases. Consequently, balancing is targeted for what is considered the feeder mean peak loading pattern over all seasons of loading. A practical approach is to identify the conditions that give rise to the most severe imbalances between phases and endeavor to achieve the best balance for that loading condition.

The use of switched capacitors affects the feeder reactive power flow and hence the total phase current. Since capacitor switching is primarily affected by loading level, such capacitors are considered connected for phase balancing purposes.

Regulator and Capacitor Voltage Control

Introduction

Fixed capacitors are often used to supply reactive power demand and to compensate for reactive power losses due to line impedance. These capacitors result in improvements in voltage profile but their use is limited by the increases in voltage at light loads. Switched capacitors can be used if greater improvements in line power factors are necessary as load increases.

The policies adopted for applying line regulators and switched capacitors for voltage control purposes varies considerably between utilities across the world. This article compares the advantages and disadvantages of regulators versus capacitors and quantifies the respective voltage control capabilities and the impact on operations and feeder utilization.

Voltage control is used primarily to maintain the voltage at each load point within defined statutory limits to comply with regulatory requirements and to avoid customer complaints because of poor supply quality. In particular, customers at the end of long feeders are often subject to wide variations in supply voltage if no voltage regulation compensating equipment is installed. For practical purposes, utilities specify operational limits for voltage that are within the statutory limits to allow some latitude for unusual operating conditions.

Line Regulators

Line regulators have been used extensively for voltage control purposes, sometimes even at step-down transformer substations to provide voltage control in the absence of load tap change capability. Since a regulator is capable of both bucking and boosting the feeder voltage, it offers a wide range of control to accommodate both high and low voltage problems within a single device. Regulators of modest kVA rating can be applied to feeders where the kVA flow is many times the regulator rating. The through kVA capacity of a regulator is defined by the equation:

Through kVA = Rated kVA x 1/pu max tap where pu max tap is the maximum tap range from nominal (0%) tap in per unit quantities. For a regulator with +/-10% tapping range, the through kVA is ten times the regulator kVA rating. Generally, the regulator impedance is very low and is often ignored for analysis purposes.

Since a regulator functions like an autotransformer, the voltage difference between the input and output has a corresponding change in the current supplied to the regulator. For a boost setting, this results in a per unit current difference between input and output with a corresponding increase in the feeder current upstream of the regulator (Figure 1).

Applying a regulator for maximum boost or buck of the voltage may result in a step voltage change at the regulator (Figure 2) that approaches the operational limit in either direction. In practice, there is a limitation on how much boost/buck is practical and it may be necessary to apply regulators in series on order to limit the boost/buck at one location.

Capacitors

Where fixed capacitors only are used for power factor compensation and voltage profile improvement, they an be optimally located to maximize the benefits from voltage regulation and/or line loss reduction. If only peak voltages are too low, switched capacitors are added. The criteria are that voltage limits must not be violated for either maximum or minimum load. A feeder system including both fixed and switched capacitors can be designed such that the location and size of capacitors and their locations are determined optimally to minimize feeder losses and comply with voltage constraints for all loading levels. The capacitor size applied at any one node is usually limited to a maximum for convenience of installation and to constrain the reactive power flow immediately upstream of the capacitor to avoid leading power factor currents at light load. Computer programs are available to perform the optimum capacitor allocation function.

As opposed to line regulator application, the allocation of switched capacitors (at B, C, D, E  Figure 3) along a feeder produces a much smoother voltage profile without voltage steps. Capacitor location and size is chosen to match the voltage and reactive power flows along each line section to minimize feeder power flows. This is particularly effective where load is unevenly distributed along a feeder resulting in large local voltage drops. Pole mounted capacitors are switched as an entity and are suitable for distributing along a feeder. The DESS optimization process allocates these capacitors where they have the greatest effect. Applying capacitors in this manner can be looked upon as a form of distributed control.

Control Techniques

Switched capacitors are controlled by one of several parameters, such as time of switching, kVAr flow through an adjacent branch, voltage at the capacitor (regulated) node, or power factor of the adjacent branch flow, each of which has advantages and disadvantages. The primary concern is that any load added to the feeder due to load growth or temporary feeder reconfiguration necessitates a resetting of control parameters. The value of the controlled variable determines when the capacitor is switched in or out. Time delay elements are incorporated to eliminate spurious switching for transient events. More sophisticated modes of control are now available with digital control technology replacing analog methods. These newer techniques address some of the concerns described.

Voltage controls for line regulators incorporate time delays to prevent unnecessary initiation of tap changing for temporary voltage variations. The control will have a deadband and the voltage can be controlled only within the deadband accuracy. Thus the voltage can vary above or below the control setting by the value of the deadband before control action is initiated. Typically, deadbands represent about 1-1.5% of the voltage setting. Line drop compensation uses a replica impedance that represents the portion of feeder between the transformer and a node downstream whose voltage is to be controlled. The replica impedance is supplied from a current transformer with a current representing the feeder load current. The resulting voltage across the replica impedance is subtracted from the voltage measured at the line regulator to simulate the voltage at the downstream node. These controls also are moving to digital technology.

More sophisticated controls for switched capacitors and line regulators have an economic benefit by reducing the number of operations per year with a consequent reduction in maintenance costs. A cost-benefit analysis would be required to determine the economic viability of using these controls

Application Considerations

Because regulators have the ability to both boost and buck voltage, they offer a flexible form of voltage control over a wide control range. The regulator is self-contained and does not require additional switches. Control is based on voltage conditions measured at the regulator although the use of line drop compensation does allow a location downstream of the regulator to be chosen as the point whose voltage is to be controlled.

If line drop compensation is used with regulators, care must be taken to ensure that the effective point of control is not within the control sphere of another downstream regulator otherwise hunting between regulators will occur and it will be impossible to achieve a stable control scheme. If more than one significant feeder spur exists downstream of a regulator, it becomes more difficult to determine line drop compensation settings. This is particularly true if a regulator is located close to a substation. A full evaluation of regulator tap parameters and compensation settings for the complete range of loading conditions is essential to ensure satisfactory settings.

Capacitors always function to reduce feeder reactive power flows; voltage control is achieved by switching in capacitors when voltage increase is needed and switching out when voltage reduction is needed. Capacitors can produce undesirable transients when switching or other disturbances occur and the application of surge control devices must be considered to ensure effective insulation coordination. Since it is not practical to perform transient analysis for every capacitor location, these surge devices are applied on the basis of good practice established from many years of experience.

The power flow on voltage-controlled feeders may reverse for certain operating conditions. In the event of generation connected downstream of the regulator, the real power flow may be positive but the reactive power flow negative. This, coupled with situations where the substation power transformer also has automatic control of the secondary voltage, requires careful evaluation of the controlled section of system to ensure proper coordination between control devices. This is accomplished by selecting suitable voltage settings and time delays to decouple, as far as possible, the action of individual devices. The alternative is the use of communications circuits to achieve the correlation. Unfortunately this can be expensive, although the gradual adoption of Internet technology is making this more of a practical proposition.

Economic Considerations

Voltage regulators function to raise or lower voltages by injecting a voltage in series with the feeder branches and have only a second order effect upon the losses incurred by feeder power flows. Capacitors generate reactive power and have a significant impact in reducing feeder reactive power flows as described. Hence total feeder flows and consequently line losses are reduced; at the same time conductor capacity is also released. Both consequences have economic benefits, the former in reducing the cost of losses and the latter in delaying the need for additional feeder capacity with load growth. The practice of lumping capacitors at distribution substations is of benefit in reducing transmission reactive capacity requirements but is of no value in reducing distribution feeder losses or improving voltage profiles, only inasmuch as these capacitors reduce losses and voltage drop in the substation power transformer.

Electronic Overcurrent Protection

Overcurrent relays and fuses are the most commonly applied form of distribution power system protection. Relays are activated from current transformer secondaries with typical secondary ratings of 1A or 5A. These relays were originally electromechanical devices but modern versions are microprocessor based and incorporate many features and refinements to increase versatility and improve coordination between relays and fuses on the same feeder. All characteristics shown in the following diagrams are plotted on log-log time-current scales.

The generic term relay is used for a collection of elements that are associated with phase or ground fault protection supplied from current transformers to provide instantaneous or inverse-time phase and ground fault protection, with or without time delay characteristics. These elements are programmable to produce characteristics that can replicate fuse curves or multi-function curves composed of definite-time, inverse time and instantaneous components. Inverse-time elements are available with inverse, moderately inverse, very inverse, and extremely inverse characteristics specified by IEEE or IEC standards. Settings suitable for phase or ground fault protection are available, sometimes along with breaker fail backup protection.

A common feature for both phase and ground fault elements is selection between definite-time and inverse-time characteristics for different current operating levels commonly defined as high set and low set. High set elements provide fast operation to clear high fault current levels thus minimizing plant damage. In most cases, coordination with downstream protection is not an issue. Low set elements are required to properly coordinate with upstream and downstream protection and ensure adequate time margins between operating characteristics over the range of feeder fault current levels. A range of independently set timing elements provides a great deal of flexibility in dealing with the requirements to provide these margins.

Relay element settings are described generically in time and multiples of primary current or relay rated current. These in turn, can be translated into time multipliers and relay tap settings by reference to the manufacturers literature. In practice, most utilities employ a limited number of device types.

Types of Element

For application purposes, overcurrent relay elements are separated into:

• Instantaneous
• Definite time
• Inverse time

Instantaneous elements are simple devices that operate at a given level of current. In practice, the higher the fault current above the current setting the faster the operation. There is a minimum time of operation dictated by the rate at which the fault current rises. The operating current related to the element setting is not particularly accurate since the elements are intended for backup protection purposes or to achieve fast fault clearance where accuracy is not an issue.

A particular form of instantaneous element is designed to increase the setting accuracy by filtering out the dc component of fault current and is used where improved accuracy is an issue in ensuring correct discrimination between protective devices.

Definite time-overcurrent elements are simply instantaneous overcurrent elements assigned a given current setting and controlled by a timer set to operate at a designated time.

Inverse-time elements are designed to operate according to the inverse-time curve shown above. They have a definite minimum operating current, determined by the current setting, and a definite minimum time of operation, determined by the time setting. The curve is asymptotic to both the time and current axes. The shape of the curve is chosen according to whether an inverse-time, a very inverse-time, or an extremely inverse-time characteristic is desired.

Inverse-time elements have a range of current settings that determine the currents, defined in amps, supplied by the current transformer at which the element is designed to just operate. For example, a 1 amp rated phase fault element usually has tap settings of 0.5, 0.75, 1.0, 1.25, 1.5, 1.75, 2.0 amps, being the nominal currents at which the relay operates. In practice, a 1.0 amp setting requires typically 1.1 amps or more to operate the element in a finite time. The companion ground fault element is likely to have a setting range of 0.2, 0.3, 0.4, 0.5, 0.6, 0.7, 0.8 amps.

Detecting Different Types of Faults

Phase fault and ground fault detection requires separate elements designed to cover the range of prospective phase and ground fault currents. Typically, ground fault elements have lower current settings than phase faults because of the relative values of the fault magnitudes and the fact that ground fault element current settings need not account for peak loading currents on a feeder. They can be set at relatively low values of fault current for greater sensitivity. All the elements for phase and ground fault are incorporated in one relay for compactness. In addition to the overcurrent elements themselves, the relay will include targets or flags for each element that signifies physically or electronically that the element has operated in the event of a fault.

A common combination for overcurrent relays is an element supplied from A phase and another supplied from C phase. The ground fault element is supplied from the residual current from the three phases. At least one phase element will operate for any phase-phase fault. A ground fault energizes one phase and the ground fault element for faults on A or C phases and the ground fault element only for a B phase ground fault. Where greater security is desired, all three-phase fault elements are included in addition to the residually connected ground fault element. Now two fault elements operate for any phase-phase or phase-ground fault.

Improved Coordination

Some applications that take advantage of the enhanced functionality of modern overcurrent protection are discussed below.

Case (a) represents a common situation where the discrimination between an inverse-time overcurrent element (blue) and an upstream fuse (black) is lost for higher fault current levels because of the fuse characteristic shape relative to an inverse-time element. One solution is to use a very or extremely inverse characteristic for the relay (green) to prevent crossover of the fuse and overcurrent element characteristics. Another solution (b) is to use a multi-function characteristic comprised of inverse and instantaneous with a timer to produce a combined characteristic (blue) that prevents a crossover. The latter has the advantage of faster fault clearance for most fault levels and more latitude to accommodate a shift of the fuse characteristic to the left as a consequence of fuse aging and exposure to multiple faults.

Electronic relays have many additional features that include:

• Programmable output contacts
• Element blocking capability
• More than one setting group
• Directional features
• Communications capability

Such features can be put to good use to provide inexpensive solutions to resolve situations where compromise is often accepted in the absence of any other economic alternative. One such situation is shown below where local generation modifies the total fault current. Without generation the relay may not operate or may operate too slowly for effective protection.

The overcurrent setting is normally R2 when the generator is connected and the total fault current is If1 but must be reset to R1 when the machine is not running and the fault current is reduced to If1. A similar situation arises when the supply is lost and the generator is capable of supplying the local load on its own. Again, the relay setting is adjusted to ensure operation for reduced fault level conditions. The relay settings are changed on operation of the generator breaker.

These cases are just two examples of where electronic relay flexibility permits significant improvements in protection coordination at little cost. Opportunities arise to add sophisticated features when the logic and timing functions of these relays are employed effectively.