Part 5: AC Power Distribution Systems & Standards

Published by Nikola Zlatanov*

Medium Voltage Equipment Surge Protection Considerations

Transformers

If the voltage withstand/BIL rating of the transformer is less than that of the switchgear feeding the transformer, surge protection is recommended at the transformer terminals, in line with established practices. In addition, consideration should be given to using surge arresters and/or surge capacitors for transformers having equal or greater withstand/BIL ratings than that of the switchgear feeding the trans- former for distribution systems where reflected voltage waves and/or resonant conditions may occur. Typically incoming voltage surges are reflected at the transformer primary terminals (because of the change in impedance) resulting in voltages at the ends of the transformer primary terminals/windings of up to two times the incoming voltage wave. System capacitance and inductance values combined with the transformer impedance values can cause resonant conditions resulting in amplified reflected waves. Surge arresters/capacitors when required, should be located as close to the trans- former primary terminals as practical.

Motors

Surge capacitors and, where appropriate, surge arresters should be applied at the motor terminals.

Generators

Surge capacitors and station class surge arresters at the machine terminals.

Surge Protection

The distribution system can be subject to voltage transients caused by lighting or switching surges. Recognizing that distribution system can be subject to voltage transients caused by lighting or switching, the industry has developed standards to provide guidelines for surge protection of electrical equipment. Those guide- lines should be used in design and protection of electrical distribution systems independent of the circuit breaker interrupting medium. The industry standards are:

  • ANSI C62 Guides and Standards for Surge Protection
  • IEEE 242—Buff Book IEEE Recommended Practice for Protection and Coordination of Industrial and Commercial Power Systems
  • IEEE 141—Red Book Recommended Practice for Electric Power Distribution for Industrial Plants
  • IEEE C37.20.2
Surge Protection Recommendations
  1. For circuits exposed to lightning, surge arresters should be applied in line with Industry standard practices.
  2. Transformers:
  • Close-Coupled to medium voltage primary breaker: Provide transients surge protection, such as Surge Arrester in parallel with RC Snubber, or ZORC. The surge protection device selected should be located and connected at the transformer primary terminals or it can be located inside the switchgear and connected on the transformer side of the primary breaker.
  • Cable-Connected to medium voltage primary breaker: Provide transient surge protection, such as Surge Arrester in parallel with RC Snubber, or ZORC for transformers connected by cables with lengths up to 75 feet. The surge protection device should be located and connected at the transformer terminals. No surge protection is needed for transformers with lightning impulse withstand ratings equal to that of the switchgear and connected to the switchgear by cables at least 75 feet or longer. For transformers with lower BIL, provide surge arrester in parallel with RC Snubber or ZORC.

RC Snubber and/or ZORC damp internal transformer resonance:

The natural frequency of transformer windings can under some circumstances be excited to resonate. Transformer windings in resonance can produce elevated internal voltages that produce insulation damage or failure. An RC Snubber or a ZORC applied at the transformer terminals as indicated above can damp internal winding resonance and prevent the production of damaging elevated internal voltages. This is typically required where rectifiers, UPS or similar electronic equipment is on the transformer secondary.

  1. Arc-Furnace Transformers— Provide Surge Arrester in parallel with RC Snubber, or ZORC at the transformer terminals.
  2. Motors—Provide Surge Arrester in parallel with RC Snubber, or ZORC at the motor terminals. For those motors using VFDs, surge protection should be applied and precede the VFD devices as well.
  3. Generators—Provide station class Surge Arrester in parallel with RC Snubber, or ZORC at the generator terminals.
  4. Capacitor Switching—No surge protection is required. Make sure that the capacitor’s lightning impulse withstand rating is equal to that of the switchgear.
  5. Shunt Reactor Switching— Provide Surge Arrester in parallel with RC Snubber, or ZORC at the reactor terminals.
  6. Motor Starting Reactors or Reduced Voltage Auto-Transformers—Provide Surge Arrester in parallel with RC Snubber, or ZORC at the reactor or RVAT terminals.
  7. Switching Underground Cables— Surge protection not needed.
Types of Surge Protection Devices

Generally surge protective devices should be located as closely as possible to the circuit component(s) that require protection from the transients, and connected directly to the terminals of the component with conductors that are as short and flat as possible to minimize the inductance. It is also important that surge protection devices should be properly grounded for effectively shunting high frequency transients to ground.

Figure 1.4-10. Surge Protection Devices

*Mr. Nikola Zlatanov spent over 20 years working in the Capital Semiconductor Equipment Industry. His work at Gasonics, Novellus, Lam and KLA-Tencor involved progressing electrical engineering and management roles in disruptive technologies. Nikola received his Undergraduate degree in Electrical Engineering and Computer Systems from Technical University, Sofia, Bulgaria and completed a Graduate Program in Engineering Management at Santa Clara University. He is currently consulting for Fortune 500 companies as well as Startup ventures in Silicon Valley, California.

Part 4: AC Power Distribution Systems & Standards

Published by Nikola Zlatanov*

Ground Fault Protection

Article 230.95 of NEC requires ground- fault protection of equipment shall be provided for solidly grounded wye electrical services of more than 150 V to ground, but not exceeding 600 V phase-to-phase for each service disconnect rated 1000 A or more. The rating of the service disconnect shall be considered to be the rating of the largest fuse that can be installed or the highest continuous current trip setting for which the actual overcurrent device installed in a circuit breaker is rated or can be adjusted. The maximum allowable settings are: 1200 A pickup, 1 second or less trip delay at currents of 3000 A or greater. The characteristics of the ground-fault trip elements create coordination problems with downstream devices not equipped with ground fault protection. The National Electrical Code exempts fire pumps and continuous industrial processes from this requirement.

It is recommended that in solidly grounded 480/277 V systems where main breakers are specified to be equipped with ground fault trip elements that the feeder breakers be specified to be equipped with ground fault trip elements as well.

Suggested Ground Fault Settings

For the main devices:

A ground fault pickup setting equal to 20–30% of the main breaker rating but not to exceed 1200 A, and a time delay equal to the delay of the short- time element, but not to exceed 1 second.

For the feeder ground fault setting:

A setting equal to 20–30% of the feeder ampacity and a time delay to coordinate with the setting of the main (at least 6 cycles below the main). If the desire to selectively coordinate ground fault devices results in settings that do not offer adequate damage protection against arcing single line- ground faults, the design engineer should decide between coordination and damage limitation.

For low voltage systems with high- magnitude available short-circuit currents, common in urban areas and large industrial installations, several solutions are available. High interrupting Series C® molded case breakers, current-limiting circuit breakers, or current-limiting fuses, limiters integral with molded-case circuit breakers (TRI-PAC®) or mounted on power circuit breakers (MDSL) can be used to handle these large fault currents. To provide current limiting, these devices must clear the fault completely within the first half-cycle, limiting the peak current (Ip) and heat energy (I2t) let-through to considerably less than what would have occurred without the device. For a fully fusible system, rule-of-thumb fuse ratios or more accurate I2t curves can be used to provide selectivity and coordination. For fuse-breaker combinations, the fuse should be selected (coordinated) so as to permit the breaker to handle those overloads and faults within its capacity; the fuse should operate before or with the breaker only on large faults, approaching the interrupting capacity of the breaker, to minimize fuse blowing. Recently, unfused, truly current-limiting circuit breakers with interrupting ratings adequate for the largest systems (Type Series C, FDC, JDC, KDC, LDC and NDC frames or Type Current Limit-R®) have become available.

The Series G high performance, current-limiting circuit breaker series offers interrupting ratings to 200 kA. Frames are EGC, EGU, EGX, JGC, JGU, JGX, LGC, LGU and LGX.
Any of these current-limiting devices— fuses, fused breakers or current-limiting breakers—cannot only clear these large faults safely, but also will limit the Ip and I2t let-through significantly to prevent damage to apparatus downstream, extending their zone of protection. Without the current limitation of the upstream device, the fault current could exceed the with- stand capability of the downstream equipment. Underwriters Laboratories tests and lists these series combinations. Application information is available for combinations that have been tested and UL®-listed for safe operation downstream from MDSL, TRI-PAC, and Current Limit-R, or Series C breakers of various ratings, under high available fault currents.

Protective devices in electrical distribution systems may be properly coordinated when the systems are designed and built, but that is no guarantee that they will remain coordinated. System changes and additions, plus power source changes, frequently modify the protection requirements, sometimes causing loss of coordination and even increasing fault currents beyond the ratings of some devices. Consequently, periodic study of protective-device settings and ratings is as important for safety and preventing power outages as is periodic maintenance of the distribution system.

Grounding

Grounding encompasses several different but interrelated aspects of electrical distribution system design and construction, all of which are essential to the safety and proper operation of the system and equipment supplied by it. Among these are equipment grounding, system grounding, static and lightning protection, and connection to earth as a reference (zero) potential.

1.Equipment Grounding

Equipment grounding is essential to safety of personnel. Its function is to ensure that all exposed noncurrent- carrying metallic parts of all structures and equipment in or near the electrical distribution system are at the same potential, and that this is the zero reference potential of the earth. Equipment grounding is required by both the National Electrical Code (Article 250) and the National Electrical Safety Code regardless of how the power system is grounded. Equipment grounding also provides a return path for ground fault currents, permitting protective devices to operate. Accidental contact of an energized conductor of the system with an improperly grounded noncurrent-carry metallic part of the system (such as a motor frame or panelboard enclosure) would raise the potential of the metal object above ground potential. Any person coming in contact with such an object while grounded could be seriously injured or killed. In addition, current flow from the accidental grounding of an energized part of the system could generate sufficient heat (often with arcing) to start a fire. To prevent the establishment of such unsafe potential difference requires that (1) the equipment grounding conductor provide a return path for ground fault currents of sufficiently low impedance to prevent unsafe voltage drop, and (2) the equipment grounding conductor be large enough to carry the maximum ground fault current, without burning off, for sufficient time to permit protective devices (ground fault relays, circuit breakers, fuses) to clear the fault. The grounded conductor of the system (usually the neutral conductor), although grounded at the source, must not be used for equipment grounding.

The equipment grounding conductor may be the metallic conduit or raceway of the wiring system, or a separate equipment grounding conductor, run with the circuit conductors, as permitted by NEC. If a separate equipment grounding conductor is used, it may be bare or insulated; if insulated, the insulation must be green, green with yellow stripe or green tape. Conductors with green insulation may not be used for any purpose other than for equipment grounding. The equipment grounding system must be bonded to the grounding electrode at the source or service; however, it may be also connected to ground at many other points. This will not cause problems with the safe operation of the electrical distribution system. Where computers, data processing, or microprocessor- based industrial process control systems are installed, the equipment grounding system must be designed to minimize interference with their proper operation. Often, isolated grounding of this equipment, or isolated electrical supply systems are required to protect microprocessors from power system “noise” that does not in any way affect motors or other electrical equipment.

Such systems must use single-point ground concept to minimize “noise” and still meet the NEC requirements. Any separate isolated ground mat must be tied to the rest of the facility ground mat system for NEC compliance.

2.System Grounding

System grounding connects the electrical supply, from the utility, from transformer secondary windings, or from a generator, to ground. A system can be solidly grounded (no intentional impedance to ground), impedance grounded (through a resistance or grounded (with no intentional connection to ground.

3.Medium Voltage System: Grounding

Table 1.4-1. Features of Ungrounded and Grounded Systems (from ANSI C62.92)

Grounding/Ground Fault Protection

Because the method of grounding affects the voltage rise of the un-faulted phases above ground, ANSI C62.92 classifies systems from the point of view of grounding in terms of a coefficient of grounding This same standard also defines systems as effectively grounded when COG ð .8 such a system would have X0 /X1 ð 3.0 and R0 /X1 ð 1.0. Any other grounding means that does not satisfy these conditions at any point in a system is not effectively grounded. The aforementioned definition is of significance in medium voltage distribution systems with long lines and with grounded sources removed during light load periods so that in some locations in the system the X0 /X1, R0 /X1 may exceed the defining limits.

Other standards (cable and lightning arrester) allow the use of 100% rated cables and arresters selected on the basis of an effectively grounded system only where the criteria in the above are met. In effectively grounded system the line-to-ground fault current is high and there is no significant voltage rise in the un-faulted phases. With selective ground fault isolation the fault current should be at least 60% of the three-phase current at the point of fault. Damage to cable shields must be checked. Although this fact is not a problem except in small cables, it is a good idea to supplement the cable shields returns of ground fault current to prevent damage, by installing an equipment grounding conductor. The burdens on the current transformers must be checked also (for saturation considerations), where residually connected ground relays are used and the current transformers supply current to phase relays and meters. If ground sensor current transformers type) are used they must be of high burden capacity.

Table 1.4-1. Features of Ungrounded and Grounded Systems (Continued)

Table 1.4-2 taken from ANSI-C62.92 indicates the characteristics of the various methods of grounding.

Reactance Grounding

It is generally used in the grounding of the neutrals of generators directly connected to the distribution system bus, in order to limit the line-to-ground fault to somewhat less than the three- phase fault at the generator terminals. If the reactor is so sized, in all probability the system will remain effectively grounded.

Resistance Grounded

Medium voltage systems in general should be low resistance grounded. The ground fault is typically limited to about 200–400 A but less than 1000 A (a cable shield consideration). With a properly sized resistor and relaying application, selective fault isolation is feasible. The fault limit provided has a bearing on whether residually connected relays are used or ground sensor current transformers are used for ground fault relaying. In general, where residually connected ground relays are used (51N), the fault current at each grounded source should not be limited to less than the current transformers rating of the source. This rule will provide sensitive differential protection for wye-connected generators and transformers against line-to-ground faults near the neutral. Of course, if the installation of ground fault differential protection is feasible, or ground sensor current transformers are used, sensitive differential relaying in resistance grounded system with greater fault limitation is feasible. In general, ground sensor current transformers (zero sequence) do not have high burden capacity. Resistance grounded systems limit the circulating currents of triple harmonics and limit the damage at the point of fault. This method of grounding is not suitable for line-to-neutral connection of loads. On medium voltage systems, 100% cable insulation is rated for phase-to- neutral voltage. If continued operation with one phase faulted to ground is desired, increased insulation thickness is required. For 100% insulation, fault clearance is recommended within one minute; for 133% insulation, one hour is acceptable; for indefinite operation, as long as necessary, 173% insulation is required.

Table 1.4-2. Characteristics of Grounding

  1. Values of the coefficient of grounding (expressed as a percentage of maximum phase-to-phase voltage) corresponding to various combinations of these ratios are shown in the ANSI C62.92 Appendix figures. Coefficient of grounding affects the selection of arrester ratings.
  2. Ground-fault current in percentage of the three-phase short-circuit value.
  3. Transient line-to-ground voltage, following the sudden initiation of a fault in per unit of the crest of the prefault line-to-ground operating voltage for a simple, linear circuit.
  4. In linear circuits, Class A1 limits the fundamental line-to-ground voltage on an un-faulted phase to 138% of the prefault voltage; Class A2 to less than 110%.
  5. See ANSI 62.92 para. 7.3 and precautions given in application sections.
  6. Usual isolated neutral (ungrounded) system for which the zero-sequence reactance is capacitive (negative).
  7. Same as NOTE (6) and refer to ANSI 62.92 para. 7.4. Each case should be treated on its own merit.
  8. Under restriking arcing ground fault conditions (e.g., vacuum breaker interrupter operation),this value can approach 500%.
  9. Under arcing ground fault conditions, this value can easily reach 700%, but is essentially unlimited.
Grounding Point

The most commonly used grounding point is the neutral of the system or the neutral point created by means of a zigzag or a wye-broken delta grounding transformer in a system that was operating as an ungrounded delta system. In general, it is a good practice that all source neutrals be grounded with the same grounding impedance magnitude. However, neutrals should not be tied together to a single resistor. Where one of the medium voltage sources is the utility, their consent for impedance grounding must be obtained.

The neutral impedance must have a voltage rating at least equal to the rated line-to-neutral voltage class of the system. It must have at least a 10-second rating equal to the maximum future line-to-ground fault current and a continuous rating to accommodate the triple harmonics that may be present.

4.Low Voltage System: Grounding

Solidly grounded three-phase systems (Figure 1.4-2) are usually wye- connected, with the neutral point grounded. Less common is the “red- leg” or high-leg delta, a 240 V system supplied by some utilities with one winding center-tapped to provide 120 V to ground for lighting. This 240 V, three- phase, four-wire system is used where 120 V lighting load is small compared to 240 V power load, because the installation is low in cost to the utility. A corner-grounded three-phase delta system is sometimes found, with one phase grounded to stabilize all voltages to ground. Better solution are available for new installations.

Figure 1.4-2. Solidly Grounded Systems

Lightning and Surge Protection

Physical protection of buildings from direct damage from lightning is beyond the scope of this section. Requirements will vary with geographic location, building type and environment, and many other factors (see IEEE/ANSI Standard 142, Grounding of Industrial and Commercial Power Systems). Any lightning protection system must be grounded, and the lightning protection ground must be bonded to the electrical equipment grounding system.

Grounding Electrodes

At some point, the equipment and system grounds must be connected to the earth by means of a grounding electrode system. Outdoor substations usually use a ground grid, consisting of a number of ground rods driven into the earth and bonded together by buried copper conductors. The required grounding electrode system for a building is spelled out in the NEC Article 250.

The preferred grounding electrode is a metal underground water pipe in direct contact with the earth for at least 10 ft (3 m). However, because under- ground water piping is often plastic outside the building, or may later be replaced by plastic piping, the NEC requires this electrode to be supplemented by and bonded to at least one other grounding electrode, such as the effectively grounded metal frame of the building, a concrete-encased electrode, a copper conductor ground ring encircling the building, or a made electrode such as one or more driven ground rods or a buried plate. Where any of these electrodes are present, they must be bonded together into one grounding electrode system. One of the most effective grounding electrodes is the concrete-encased electrode, sometimes called the Ufer ground, named after the man who developed it. It consists of at least 20 ft (6 m) of steel reinforcing bars or rods not less than 1/2 inches (12.7 mm) in diameter, or at least 20 ft (6 m) of bare copper conductor, size No. 4 AWG or larger, encased in at least 2 inches (50.8 mm) of concrete. It must be located within and near the bottom of a concrete foundation or footing that is in direct contact with the earth. Tests have shown this electrode to provide a low-resistance earth ground even in poor soil conditions.

The electrical distribution system and equipment ground must be connected to this grounding electrode system by a grounding electrode conductor. All other grounding electrodes, such as those for the lightning protection system, the telephone system, television antenna and cable TV system grounds, and computer systems, must be bonded to this grounding electrode system.

*Mr. Nikola Zlatanov spent over 20 years working in the Capital Semiconductor Equipment Industry. His work at Gasonics, Novellus, Lam and KLA-Tencor involved progressing electrical engineering and management roles in disruptive technologies. Nikola received his Undergraduate degree in Electrical Engineering and Computer Systems from Technical University, Sofia, Bulgaria and completed a Graduate Program in Engineering Management at Santa Clara University. He is currently consulting for Fortune 500 companies as well as Startup ventures in Silicon Valley, California.

Part 3: AC Power Distribution Systems & Standards

Published by Nikola Zlatanov*

Short-Circuit Currents – General

The amount of current available in a short-circuit fault is determined by the capacity of the system voltage sources and the impedances of the system, including the fault. Voltage sources include the power supply (utility or on-site generation) plus all rotating machines connected to the system at the time of the fault. A fault may be either an arcing or bolted fault. In an arcing fault, part of the circuit voltage is consumed across the fault and the total fault current is somewhat smaller than for a bolted fault, so the latter is the worst condition, and therefore is the value sought in the fault calculations. Basically, the short-circuit current is determined by applying Ohm’s Law to an equivalent circuit consisting of a constant voltage source and a time- varying impedance. A time-varying impedance is used in order to account for the changes in the effective voltages of the rotating machines during the fault. In an AC system, the resulting short-circuit current starts out higher in magnitude than the final steady-state value and asymmetrical (due to the DC offset) about the X-axis. The current then decays toward a lower symmetrical steady-state value.

The time-varying characteristic of the impedance accounts for the symmetrical decay in current. The ratio of the reactive and resistive components (X/R ratio) accounts for the DC decay, see Figure 1.3-1. The fault current consists of an exponentially decreasing direct- current component superimposed upon a decaying alternating-current. The rate of decay of both the DC and AC components depends upon the ratio of reactance to resistance (X/R) of the circuit. The greater this ratio, the longer the current remains higher than the steady-state value that it would eventually reach. The total fault current is not symmetrical with respect to the time-axis because of the direct-current component, hence it is called asymmetrical current. The DC component depends on the point on the voltage wave at which the fault is initiated. See Table 1.3-2 for multiplying factors that relate the rms asymmetrical value of total current to the rms symmetrical value, and the peak asymmetrical value of total current to the rms symmetrical value. The AC component is not constant if rotating machines are connected to the system because the impedance of this apparatus is not constant. The rapid variation of motor and generator impedance is due to these factors:

Subtransient reactance (xd“), determines fault current during the first cycle, and after about 6 cycles this value increases to the transient reactance. It is used for the calculation of the momentary interrupting and/or momentary withstand duties of equipment and/or system.

Transient reactance (xd‘), which deter- mines fault current after about 6 cycles and this value in 1/2 to 2 seconds increases to the value of the synchro- nous reactance. It is used in the setting of the phase OC relays of generators and medium voltage circuit breakers.

Synchronous reactance (xd), which determines fault current after steady-state condition is reached. It has no effect as far as short-circuit calculations are concerned, but is useful in the determination of relay settings.

Transformer impedance, in percent, is defined as that percent of rated primary voltage that must be applied to the transformer to produce rated current flowing in the secondary, with secondary shorted through zero resistance.

Therefore, assuming the primary voltage can be sustained (generally referred to as an infinite or unlimited supply), the maximum current a trans- former can deliver to a fault condition is the quantity of (100 divided by percent impedance) times the transformer rated secondary current. Limiting the power source fault capacity will thereby reduce the maximum fault current from the transformer.

The electric network that determines the short-circuit current consists of an AC driving voltage equal to the pre-fault system voltage and an impedance corresponding to that observed when looking back into the system from the fault location. In medium and high voltage work, it is generally satisfactory to regard reactance as the entire impedance; resistance may be neglected. However, this is normally permissible only if the X/R ratio of the medium voltage system is equal to or more than 25. In low voltage (1000 V and below) calculations, it is usually worthwhile to attempt greater accuracy by including resistance with reactance in dealing with impedance. It is for this reason, plus ease of manipulating the various impedances of cables and buses and transformers of the low voltage circuits, that computer studies are recommended before final selection of apparatus and system arrangements.

When evaluating the adequacy of short-circuit ratings of medium voltage circuit breakers and fuses, both the rms symmetrical value and asymmetrical value of the short-circuit current should be determined. For low voltage circuit breakers and fuses, the rms symmetrical value should be determined along with either: the X/R ratio of the fault at the device or the asymmetrical short-circuit current.

Figure 1.3-1. Structure of an Asymmetrical Current Wave

Fault Current Waveform Relationships

The following Figure 1.3-2 describes the relationship between fault current peak values, rms symmetrical values and rms asymmetrical values depending on the calculated X/R ratio. The table is based on the following general formulas:

Where:

I = Symmetrical rms current
Ip = Peak current
e = 2.718
ω = 2πf
f = Frequency in Hz
t = Time in second

Based on a 60 Hz system and t = ½ cycle (ANSI/IEEE C37.13.1990/10.1.4)

Figure 1.3-2. Relation of X/R Ratio to Multiplication Factor

Fault Current Calculations

The calculation of asymmetrical currents is a laborious procedure since the degree of asymmetry is not the same on all three phases. It is common practice for medium voltage systems, to calculate the rms symmetrical fault current, with the assumption being made that the DC component has decayed to zero, and then apply a multiplying factor to obtain the first half-cycle rms asymmetrical current, which is called the “momentary current.” For medium voltage systems (defined by IEEE as greater than 1000 V up to 69,000 V) the multiplying factor is established by NEMA® and ANSI standards depending upon the operating speed of the breaker. For low voltage systems, short-circuit study software usually calculates the symmetrical fault current and the faulted system X/R ratio using ANSI guidelines. If the X/R ratio is within the standard, and the breaker interrupting current is under the symmetrical fault value, the breaker is properly rated. If the X/R ratio is higher than ANSI standards, the study applies a multi- plying factor to the symmetrical calculated value (based on the X/R value of the system fault) and compares that value to the breaker symmetrical value to assess if it is properly rated.

In the past, especially using manual calculations, a multiplying factor of 1.17 (based on the use of an X/R ratio of 6.6 representing a source short-circuit power factor of 15%) was used to calculate the asymmetrical current. These values take into account that medium voltage breakers are rated on maximum asymmetry and low voltage breakers are rated average asymmetry. To determine the motor contribution during the first half-cycle fault current, when individual motor horsepower load is known, the subtransient reactance found in the IEEE Red Book should be used in the calculations.

When the system motor load is unknown, the following assumptions generally are made: Induction motors—use 4.0 times motor full load current (impedance value of 25%).

*Mr. Nikola Zlatanov spent over 20 years working in the Capital Semiconductor Equipment Industry. His work at Gasonics, Novellus, Lam and KLA-Tencor involved progressing electrical engineering and management roles in disruptive technologies. Nikola received his Undergraduate degree in Electrical Engineering and Computer Systems from Technical University, Sofia, Bulgaria and completed a Graduate Program in Engineering Management at Santa Clara University. He is currently consulting for Fortune 500 companies as well as Startup ventures in Silicon Valley, California.

Part 2: AC Power Distribution Systems & Standards

Published by Nikola Zlatanov*

Voltage Classifications

ANSI and IEEE® standards define various voltage classifications for single-phase and three-phase systems. The terminology used divides voltage classes into:

  • Low voltage
  • Medium voltage
  • High voltage
  • Extra-high voltage
  • Ultra-high voltage

Table 1.1-1 presents the nominal system ese classifications. Voltages and Voltage Ranges (From IEEE Standard 141-1993)

BIL—Basic Impulse Levels

ANSI standards define recommended and required BIL levels for:

  • Metal-clad switchgear (typically vacuum breakers)
  • Metal-enclosed switchgear (typically load interrupters, switches)
  • Pad-mounted and overhead distribution switchgear
  • Liquid immersed transformers
  • Dry-type transformers

Table 1.1-2 through Table 1.1-6 contain those values.

Table 1.1-2. Metal-Clad Switchgear Voltage and Insulation Levels (From IEEE Std. C37.20.2-2015) Levels td. C37.20.3-2013)

Table 1.1-3. Metal-Enclosed S ear Voltage and Insulation Levels (From IEEE Std. C37.20.3-2013)

Table 1.1-4. Pad Mounted and Overhead Distribution Switchgear, Voltage and Insulation Levels

Table 1.1-5. Liquid-Immersed Transformers Voltage and Basic Lightning Impulse Insulation Levels (BIL) (From ANSI/IEEE C57.12.00)

Table 1.1-6. Dry-Type Transformers Voltage and Basic Lightning Impulse Insulation Levels (BIL)—From ANSI/IEEE C57.12.01-1998)

BIL values in bold typeface are listed as standard. Others listed are in common use. Optional higher levels used where exposure to overvoltage occurs and higher protection margins are required. Lower levels where surge arrester protective devices can be applied with lower spark-over levels.

Voltage Recommendations by Motor Horsepower

Some factors affecting the selection of motor operating voltage include:

  • Motor, motor starter and cable first cost
  • Motor, motor starter and cable installation cost
  • Motor and cable losses
  • Motor availability
  • Voltage drop
  • Qualifications of the building operating staff; and many more

The following table is based in part on the above factors and experience. Because all the factors affecting the selection are rarely known, it is only an approximate guideline.

Table 1.1-7. Selection of Motor Horsepower Ratings as a Function of System Voltage

Types of Systems

In many cases, power is supplied by the utility to a building at the utilization voltage. In these cases, the distribution of power within the building is achieved through the use of a simple radial distribution system. In cases where the utility service voltage is at some voltage higher than the utilization voltage within the building, the system design engineer has a choice of a number of types of systems that may be used. This discussion covers several major types of distribution systems and practical modifications of them.

  1. Simple radial
  2. Loop-primary system— radial secondary system
  3. Primary selective system— secondary radial system
  4. Two-source primary— secondary selective system
  5. Sparing transformer system
  6. Simple spot network
  7. Medium voltage distribution system design

Table 1.1-7. Three-Phase Transformer Winding Connections

1. Simple Radial System

The conventional simple radial system receives power at the utility supply voltage at a single substation and steps the voltage down to the utilization level. In those cases where the customer receives his supply from the primary system and owns the primary switch and transformer along with the secondary low voltage switchboard or switch- gear, the equipment may take the form of a separate primary switch, separate transformer, and separate low voltage switchgear or switchboard. This equipment may be combined in the form of an outdoor pad-mounted transformer with internal primary fused switch and secondary main breaker feeding an indoor switchboard. Another alternative would be a secondary unit substation where the primary fused switch, transformer and secondary switchgear or switch- board are designed and installed as a close-coupled single assembly. In those cases where the utility owns the primary equipment and transformer, the supply to the customer is at the utilization voltage, and the service equipment then becomes low voltage main distribution switchgear or a switchboard.

Low voltage feeder circuits run from the switchgear or switchboard assemblies to panelboards that are located closer to their respective loads as shown in Figure 1.1-1. Each feeder is connected to the switch- gear or switchboard bus through a circuit breaker or other overcurrent protective device. A relatively small number of circuits are used to distribute power to the loads from the switch- gear or switchboard assemblies and panelboards. Because the entire load is served from a single source, full advantage can be taken of the diversity among the loads. This makes it possible to minimize the installed transformer capacity. However, the voltage regulation and efficiency of this system may be poor because of the low voltage feeders and single source. The cost of the low voltage- feeder circuits and their associated circuit breakers are high when the feeders are long and the peak demand is above 1000 kVA.

A fault on the secondary low voltage bus or in the source transformer will interrupt service to all loads. Service cannot be restored until the necessary repairs have been made. A low voltage feeder circuit fault will interrupt service to all loads supplied over that feeder. A modern and improved form of the conventional simple radial system distributes power at a primary voltage. The voltage is stepped down to utilization level in the several load areas within the building typically through secondary unit substation transformers. The transformers are usually connected to their associated load bus through a circuit breaker, as shown in Figure 1.1-2. Each secondary unit substation is an assembled unit consisting of a three-phase, liquid- filled or air-cooled transformer, an integrally connected primary fused switch, and low voltage switchgear or switch- board with circuit breakers or fused switches. Circuits are run to the loads from these low voltage protective devices.

Figure 1.1-1. Simple Radial System

Figure 1.1-2. Primary and Secondary Simple Radial System

Because each transformer is located within a specific load area, it must have sufficient capacity to carry the peak load of that area. Consequently, if any diversity exists among the load area, this modified primary radial system requires more transformer capacity than the basic form of the simple radial system. However, because power is distributed to the load areas at a primary voltage, losses are reduced, voltage regulation is improved, feeder circuit costs are reduced substantially, and large low voltage feeder circuit breakers are eliminated. In many cases the interrupting duty imposed on the load circuit breakers is reduced. This modern form of the simple radial system will usually be lower in initial investment than most other types of primary distribution systems for buildings in which the peak load is above 1000 kVA. A fault on a primary feeder circuit or in one transformer will cause an outage to only those secondary loads served by that feeder or trans- former. In the case of a primary main bus fault or a utility service outage, service is interrupted to all loads until the trouble is eliminated. Reducing the number of transformers per primary feeder by adding more primary feeder circuits will improve the flexibility and service continuity of this system; the ultimate being one secondary unit substation per primary feeder circuit. This of course increases the investment in the system but minimizes the extent of an outage resulting from a transformer or primary feeder fault. Primary connections from one secondary unit substation to the next secondary unit substation can be made with “double” lugs on the unit substation primary switch as shown, or with separable connectors made in manholes or other locations.

Depending on the load kVA connected to each primary circuit and if no ground fault protection is desired for either the primary feeder conductors and trans- formers connected to that feeder or the main bus, the primary main and/or feeder breakers may be changed to primary fused switches. This will significantly reduce the first cost, but also decrease the level of conductor and equipment protection. Thus, should a fault or overload condition occur, downtime increases significantly and higher costs associated with increased damage levels and the need for fuse replacement is typically encountered. In addition, if only one primary fuse on a circuit opens, the secondary loads are then single phased, causing damage to low voltage motors.

Another approach to reducing costs is to eliminate the primary feeder breakers completely, and use a single primary main breaker or fused switch for protection of a single primary feeder circuit with all secondary unit substations supplied from this circuit. Although this system results in less initial equipment cost, system reliability is reduced drastically because a single fault in any part of the primary conductor would cause an outage to all loads within the facility.

2. Loop Primary System— Radial Secondary System

This system consists of one or more “PRIMARY LOOPS” with two or more transformers connected on the loop. This system is typically most effective when two services are available from the utility as shown in Figure 1.1-3. Each primary loop is operated such that one of the loop sectionalizing switches is kept open to prevent parallel operation of the sources. When secondary unit substations are used, each transformer may have its own duplex (2-load break switches with load side bus connection) sectionalizing switches and primary load break fused switch as shown in Figure 1.1-4 or utilizing three on-off switches or a four-position sectionalizing switch and vacuum fault interrupter (VFI) internal to the transformer saving cost and reducing footprint. When pad-mounted compartmentalized transformers are used, they are furnished with loop-feed oil-immersed gang-operated load break sectionalizing switches and Bay-O-Net expulsion fuses in series with partial range back- up current-limiting fuses. By operating the appropriate sectionalizing switches, it is possible to disconnect any section of the loop conductors from the rest of the system. In addition, it is possible to disconnect any transformer from the loop. A key interlocking scheme is normally recommended to prevent closing all sectionalizing devices in the loop. Each primary loop sectionalizing switch and the feeder breakers to the loop are interlocked such that to be closed they require a key (which is held captive until the switch or breaker is opened) and one less key than the number of key interlock cylinders is furnished. An extra key is provided to defeat the interlock under qualified supervision.

Figure 1.1-3. Loop Primary—Radial Secondary System

Figure 1.1-4. Secondary unit

Figure 1.1-5. VFI/Selector Switch

Figure 1.1-6. Pad-Mounted Switching Substation Loop Switching Combination Transformer Loop

In addition, the two primary main breakers, which are normally closed, and primary tie breaker, which is normally open, are either mechanically or electrically interlocked to prevent paralleling the incoming source lines. For slightly added cost, an automatic throw-over scheme can be added between the two main breakers and tie breaker. During the more common event of a utility outage, the automatic transfer scheme provides significantly reduced power outage time.

The system in Figure 1.1-3 has higher costs than in Figure 1.1-2, but offers increased reliability and quick restoration of service when 1) a utility outage occurs, 2) a primary feeder conductor fault occurs, or 3) a transformer fault or overload occurs.

Should a utility outage occur on one of the incoming lines, the associated primary main breaker is opened and the tie breaker closed either manually or through an automatic transfer scheme.

When a primary feeder conductor fault occurs, the associated loop feeder breaker opens and interrupts service to all loads up to the normally open primary loop load break switch (typically half of the loads). Once it is determined which section of primary cable has been faulted, the loop sectionalizing switches on each side of the faulted conductor can be opened, the loop sectionalizing switch that had been previously left open then closed and service restored to all secondary unit substations while the faulted conductor is replaced. If the fault should occur in a conductor directly on the load side of one of the loop feeder breakers, the loop feeder breaker is kept open after tripping and the next load side loop sectionalizing switch manually opened so that the faulted conductor can be sectionalized and replaced.

Note: Under this condition, all secondary unit substations are supplied through the other loop feeder circuit breaker, and thus all conductors around the loop should be sized to carry the entire load connected to the loop. Increasing the number of primary loops (two loops shown in Figure 1.1-8) will reduce the extent of the outage from a conductor fault, but will also increase the system investment.

When a transformer fault or overload occurs, the transformer primary fuses open, and the transformer primary switch manually opened, disconnecting the transformer from the loop, and leaving all other secondary unit substation loads unaffected.

Figure 1.1-7. Basic Primary Selective—Radial Secondary System

Figure 1.1-8. Single Primary Feeder – Loop System

A basic primary loop system that uses a single primary feeder breaker connected directly to two loop feeder switches which in turn then feed the loop is shown in Figure 1.1-8. In this basic system, the loop may be normally operated with one of the loop sectionalizing switches open as described above or with all loop sectionalizing switches closed. If a fault occurs in the basic primary loop system, the single loop feeder breaker trips, and secondary loads are lost until the faulted conductor is found and eliminated from the loop by opening the appropriate loop sectionalizing switches and then reclosing the breaker.

3. Primary Selective System— Secondary Radial System

The primary selective—secondary radial system, as shown in Figure 1.1-7, differs from those previously described in that it employs at least two primary feeder circuits in each load area. It is designed so that when one primary circuit is out of service, the remaining feeder or feeders have sufficient capacity to carry the total load. Half of the transformers are normally connected to each of the two feeders. When a fault occurs on one of the primary feeders, only half of the load in the building is dropped.

Duplex fused switches as shown in Figure 1.1-7 and detailed in Figure 1.1-9 may be utilized for this type of system. Each duplex fused switch consists of two (2) load break three-pole switches each in their own separate structure, connected together by bus bars on the load side. Typically, the load break switch closest to the transformer includes a fuse assembly with fuses. Mechanical and/or key interlocking is furnished such that both switches cannot be closed at the same time (to prevent parallel operation) and interlocking such that access to either switch or fuse assembly obtained unless both witches are opened.

Figure 1.1-9. Duplex Fused switch in Two Structures

One alternate to the duplex switch arrangement, a non-load break selector switch mechanically interlocked with a load break fused switch can be used as shown in Figure 1.1-10. The non- load break selector switch is physically located in the rear of the load break fused switch, thus only requiring one structure and a lower cost and floor space savings over the duplex arrangement. The non-load break switch is mechanically interlocked to prevent its operation unless the load break switch is opened. The main disadvantage of the selector switch is that conductors from both circuits are terminated in the same structure.

Figure 1.1-10. Fused Selector Switch in One Structure

This means limited cable space especially if double lugs are furnished for each line as shown in Figure 1.1-7 and should a faulted primary conductor have to be changed, both lines would have to be de-energized for safe changing of the faulted conductors. A second alternative is utilizing a three-position selector switch internal to the transformer, allowing only one primary feeder to be connected to the transformer at a time without the need for any interlocking. The selector switch is rated for load-breaking. If overcurrent protection is also required, a vacuum fault interrupter (VFI), also internal to the transformer, may be utilized, reducing floor space.

In Figure 1.1-7 when a primary feeder fault occurs, the associated feeder breaker opens and the transformers normally supplied from the faulted feeder are out of service. Then manually, each primary switch connected to the faulted line must be opened and then the alternate line primary switch can be closed connecting the trans- former to the live feeder, thus restoring service to all loads. Note that each of the primary circuit conductors for Feeder A1 and B1 must be sized to handle the sum of the loads normally connected to both A1 and B1. Similar sizing of Feeders A2 and B2, etc., is required. If a fault occurs in one transformer, the associated primary fuses blow and interrupt the service to just the load served by that transformer. Service cannot be restored to the loads normally served by the faulted transformer until the transformer is repaired or replaced.

Cost of the primary selective— secondary radial system is greater than that of the simple primary radial system of Figure 1.1-1 because of the additional primary main breakers, tie breaker, two-sources, increased number of feeder breakers, the use of primary- duplex or selector switches, and the greater amount of primary feeder cable required. The benefits from the reduction in the amount of load lost when a primary feeder is faulted, plus the quick restoration of service to all or most of the loads, may more than offset the greater cost. Having two sources allows for either manual or automatic transfer of the two primary main breakers and tie breaker should one of the sources become unavailable.

The primary selective-secondary radial system, however, may be less costly or more costly than a primary loop— secondary radial system of Figure 1.1-3 depending on the physical location of the transformers while offering comparable downtime and reliability. The cost of conductors for the two types of systems may vary greatly depending on the location of the transformers and loads within the facility and greatly override primary switching equipment cost differences between the two systems.

4. Two-Source Primary— Secondary Selective System

This system uses the same principle of duplicate sources from the power supply point using two primary main breakers and a primary tie breaker. The two primary main breakers and primary tie breaker being either manually or electrically interlocked to prevent closing all three at the same time and paralleling the sources. Upon loss of voltage on one source, a manual or automatic transfer to the alternate source line may be used to restore power to all primary loads.

Each transformer secondary is arranged in a typical double-ended unit substation arrangement as shown in Figure 1.1-11. The two secondary main breakers and secondary tie breaker of each unit substation are again either mechanically or electrically interlocked to prevent parallel operation. Upon loss of secondary source voltage on one side, manual or automatic transfer may be used to transfer the loads to the other side, thus restoring power to all secondary loads.

This arrangement permits quick restoration of service to all loads when a primary feeder or transformer fault occurs by opening the associated secondary main and closing the secondary tie breaker. If the loss of secondary voltage has occurred because of a primary feeder fault with the associated primary feeder breaker opening, then all secondary loads normally served by the faulted feeder would have to be transferred to the opposite primary feeder. This means each primary feeder conductor must be sized to carry the load on both sides of buses it is serving under secondary emergency transfer.

Figure 1.1-11. Two-Source Primary – Secondary Selective System

If the loss of voltage was due to a failure of one of the transformers in the double-ended unit substation, then the associated primary fuses would open taking only the failed transformer out of service, and then only the secondary loads normally served by the faulted transformer would have to be transferred to the opposite transformer. In either of the above emergency conditions, the in-service transformer of a double-ended unit substation would have to have the capability of serving the loads on both sides of the tie breaker. For this reason, transformers used in this application have equal kVA rating on each side of the double- ended unit substation and the normal operating maximum load on each transformer is typically about 2/3 base nameplate kVA rating. Typically these transformers are furnished with fan-cooling and/or lower than normal temperature rise such that under emergency conditions they can carry on a continuous basis the maximum load on both sides of the secondary tie breaker. Because of this spare trans- former capacity, the voltage regulation provided by the double-ended unit substation system under normal conditions is better than that of the systems previously discussed. The double-ended unit substation arrangement can be used in conjunction with any of the previous systems discussed, which involve two primary sources. Although not recommended, if allowed by the utility, momentary retransfer of loads to the restored source may be made closed transition (anti-parallel interlock schemes would have to be defeated) for either the primary or secondary systems. Under this condition, all equipment interrupting and momentary ratings should be suitable for the fault current available from both sources. For double-ended unit substations equipped with ground fault systems special consideration to transformer neutral grounding and equipment operation should be made. Where two single-ended unit substations are connected together by external tie conductors, it is recommended that a tie breaker be furnished at each end of the tie conductors.

5. Medium Voltage Distribution System Design

A. Single Bus, Figure 1.1-14
The sources (utility and/or generator(s)) are connected to a single bus. All feeders are connected to the same bus

Figure 1.1-14. Single Bus

This configuration is the simplest system; however, outage of the utility results in total outage. Normally the generator does not have adequate capacity for the entire load. A properly relayed system equipped with load shedding, automatic voltage/ frequency control may be able to maintain partial system operation. Any future addition of breaker sections to the bus will require a shutdown of the bus, because there is no tie breaker.

B. Single Bus with Two Sources from the Utility, Figure 1.1-15
Same as the single bus, except that two utility sources are available. This system is operated normally with the main breaker to one source open. Upon loss of the normal service, the transfer to the standby normally open (NO) breaker can be automatic or manual. Automatic transfer is id service restoration specially in unattended stations.

Figure 1.1-15. Single Bus with Two-Sources

Retransfer to the “Normal” can be closed transition subject to the approval of the utility. Closed transition momentarily (5–10 cycles) parallels both utility sources. Caution: when both sources are paralleled, the fault current available on the load side of the main device is the sum of the available fault current from each source plus the motor fault contribution. It is recommended that the short-circuit ratings of the bus, feeder breakers and all load side equipment are rated for the increased available fault current. If the utility requires open transfer, the disconnection of motors from the bus must be ensured by means of suitable time delay on reclosing as well as supervision of the bus voltage and its phase with respect to the incoming source voltage This busing scheme does not preclude the use of cogeneration, but requires the use of sophisticated automatic synchronizing and synchronism checking controls, in addition to the previously mentioned load shedding, automatic frequency and voltage controls.

This configuration is more expensive than the scheme shown in Figure 1.1-14, but service restoration is quicker. Again, a utility outage results in total outage to the load until transfer occurs. Extension of the bus or adding breakers requires a shutdown of the bus. If paralleling sources, reverse current, reverse power and other appropriate section should be added as requested by the utility.

Systems Analysis

A major consideration in the design of a distribution system is to ensure that it provides the required quality of service to the various loads. This includes serving each load under normal conditions and, under abnormal conditions, providing the desired protection to service and system apparatus so that interruptions of service are minimized consistent with good economic and mechanical design.

Under normal conditions, the important technical factors include voltage profile, losses, load flow, effects of motor starting, service continuity and reliability. The prime considerations under faulted conditions are apparatus protection, fault isolation and service continuity. During the system preliminary planning stage, before selection of the distribution apparatus, several distribution systems should be analyzed and evaluated, including both economic and technical factors. During this stage, if system size or complexity war- rant, it may be appropriate to provide a thorough review of each system under both normal and abnormal conditions.

  1. The principal types of computer programs used to provide system studies include:
  2. Short circuit—identify three-phase and line-to-ground fault currents and system impedances
  3. Arc flash—calculates arc flash energy levels, which leads to the selection of personal protective equipment(PPE)
  4. Circuit breaker duty—identify asymmetrical fault current based on X/R ratio
  5. Protective device coordination— determine characteristics and set- tings of medium voltage protective relays and fuses, and entire low voltage circuit breaker and fuse coordination
  6. Load flow—simulate normal load conditions of system voltages, power factor, line and transformer loadings
  7. Motor starting—identify system voltages, motor terminal voltage, motor accelerating torque, and motor accelerating time when starting large motors

Short-circuit calculations define momentary and steady-state fault currents for LV and MV breaker and fuse duty and bus bracings at any selected location in the system, and also determine the effect on the system after removal of utility power due to breaker operation or scheduled power outages. Computer software programs can identify the fault current at any bus, in every line or source connected to the faulted bus, or to it and every adjacent bus, or to it and every bus that is one and two buses away, or currents in every line or source in the system. The results of these calculations permit optimizing service to the loads while properly applying distribution apparatus within their intended limits.

The following additional studies should be considered depending upon the type and complexity of the distribution system, the type of facility and the type of loads to be connected to the system:

  • Harmonic analysis
  • Transient stability
  • Insulation coordination
  • Grounding study
  • Switching transient

*Mr. Nikola Zlatanov spent over 20 years working in the Capital Semiconductor Equipment Industry. His work at Gasonics, Novellus, Lam and KLA-Tencor involved progressing electrical engineering and management roles in disruptive technologies. Nikola received his Undergraduate degree in Electrical Engineering and Computer Systems from Technical University, Sofia, Bulgaria and completed a Graduate Program in Engineering Management at Santa Clara University. He is currently consulting for Fortune 500 companies as well as Startup ventures in Silicon Valley, California.

Part 1: AC Power Distribution Systems & Standards

Published by Nikola Zlatanov

Mr. Nikola Zlatanov spent over 20 years working in the Capital Semiconductor Equipment Industry. His work at Gasonics, Novellus, Lam and KLA-Tencor involved progressing electrical engineering and management roles in disruptive technologies. Nikola received his Undergraduate degree in Electrical Engineering and Computer Systems from Technical University, Sofia, Bulgaria and completed a Graduate Program in Engineering Management at Santa Clara University. He is currently consulting for Fortune 500 companies as well as Startup ventures in Silicon Valley, California.

Introduction

The best distribution system is one that will, cost-effectively and safely, supply adequate electric service to both present and future probable loads. The function of the electric power distribution system in a building or an installation site is to receive power at one or more supply points and to deliver it to the individual lamps, motors and all other electrically operated devices. The importance of the distribution system to the function of a building makes it almost imperative that the best system be designed and installed.

In order to design the best distribution system, the system design engineer must have information concerning the loads and a knowledge of the various types of distribution systems that are applicable. The various categories of buildings have many specific design challenges, but certain basic principles are common to all. Such principles, if followed, will provide a soundly executed design.

The basic principles or factors requiring consideration during design of the power distribution system include:

  • Functions of structure, present and future
  • Life and flexibility of structure
  • Locations of service entrance and distribution equipment, locations and characteristics of loads, locations of unit substations
  • Demand and diversity factors of loads
  • Sources of power; including normal, standby and emergency
  • Continuity and quality of power available and required
  • Energy efficiency and management
  • Distribution and utilization voltages
  • Bus and/or cable feeders
  • Distribution equipment and motor control
  • Power and lighting panelboards and motor control centers
  • Types of lighting systems
  • Installation methods
  • Power monitoring systems
  • Electric utility requirements
Modern Electric Power Technologies

Several new factors to consider in modern power distribution systems result from two relatively recent changes. The first recent change is utility deregulation. The traditional dependence on the utility for problem analysis, energy conservation measurements and techniques, and a simplified cost structure for electricity has changed. The second change is less obvious to the designer yet will have an impact on the types of equipment and systems being designed. It is the diminishing quantity of qualified building electrical operators, maintenance departments and facility engineers

Modern electric power technologies may be of use to the designer and building owner in addressing these new challenges. The advent of micro- processor devices (smart devices) into power distribution equipment has expanded facility owners’ options and capabilities, allowing for automated communication of vital power system information (both energy data and system operation information) and electrical equipment control.
These technologies may be grouped as:

  • Power monitoring and control
  • Building management systems interfaces
  • Lighting control
  • Automated energy management
  • Predictive diagnostics

Various sections of this guide cover the application and selection of such systems and components that may be incorporated into the power equipment Designed.

Goals of System Design

When considering the design of an electrical distribution system for a given customer and facility, the electrical engineer must consider alternate design approaches that best fit the following overall goals.

1.Safety: The No. 1 goal is to design a power system that will not present any electrical hazard to the people who use the facility, and/or the utilization equipment fed from the electrical system.

It is also important to design a system that is inherently safe for the people who are responsible for electrical equipment maintenance and upkeep.

The National Electrical Code® (NEC®), NFPA® 70 and NFPA 70E, as well as local electrical codes, provide minimum standards and requirements in the area of wiring design and protection, wiring methods and materials, as well as equipment for general use with the overall goal of providing safe electrical distribution systems and equipment.

The NEC also covers minimum requirements for special occupancies including hazardous locations and special use type facilities such as health care facilities, places of assembly, theaters and the like, and the equipment and systems located in these facilities. Special equipment and special conditions such as emergency systems, standby systems and communication systems are also covered in the code.

It is the responsibility of the design engineer to be familiar with the NFPA and NEC code requirements as well as the customer’s facility, process and operating procedures; to design a system that protects personnel from live electrical conductors and uses adequate circuit protective devices that will selectively isolate overloaded or faulted circuits or equipment as quickly as possible.

2.Minimum Initial Investment: The owner’s overall budget for first cost purchase and installation of the electrical distribution system and electrical utilization equipment will be a key factor in determining which of various alternate system designs are to be selected. When trying to minimize initial investment for electrical equipment, consideration should be given to the cost of installation, floor space requirements and possible extra cooling requirements as well as the initial purchase price.

3.Maximum Service Continuity: The degree of service continuity and reliability needed will vary depending on the type and use of the facility as well as the loads or processes being supplied by the electrical distribution system. For example, for a smaller commercial office building, a power outage of considerable time, say several hours, may be acceptable, whereas in a larger commercial building or industrial plant only a few minutes may be acceptable. In other facilities such as hospitals, many critical loads permit a maximum of 10 seconds outage and certain loads, such as real-time computers, cannot tolerate a loss of power for even a few cycles.

Typically, service continuity and reliability can be increased by:

  • Supplying multiple utility power sources or services.
  • Supplying multiple connection paths to the loads served.
  • Using short-time rated power circuit breakers.
  • Providing alternate customer- owned power sources such as generators or batteries supplying uninterruptable power supplies.
  • Selecting the highest quality electrical equipment and conductors.
  • Using the best installation methods.
  • Designing appropriate system alarms, monitoring and diagnostics.
  • Selecting preventative maintenance systems or equipment to alarm before an outage occurs.

4.Maximum Flexibility and Expendability: In many industrial manufacturing plants, electrical utilization loads are periodically relocated or changed requiring changes in the electrical distribution system. Consideration of the layout and design of the electrical distribution system to accommodate these changes must be considered. For example, pro- viding many smaller transformers or load centers associated with a given area or specific groups of machinery may lend more flexibility for future changes than one large transformer; the use of plug-in busways to feed selected equipment in lieu of conduit and wire may facilitate future revised equipment layouts. In addition, consideration must be given to future building expansion, and/or increased load requirements due to added utilization equipment when designing the electrical distribution system. In many cases considering trans- formers with increased capacity or fan cooling to serve unexpected loads as well as including spare additional protective devices and/ or provision for future addition of these devices may be desirable. Also to be considered is increasing appropriate circuit capacities or quantities for future growth. Power monitoring communication systems connected to electronic metering can provide the trending historical data necessary for future capacity growth.

5.Maximum Electrical Efficiency (Minimum Operating Costs): Electrical efficiency can generally be maximized by designing systems that minimize the losses in conductors, transformers and utilization equipment. Proper voltage level selection plays a key factor in this area and will be discussed later. Selecting equipment, such as transformers, with lower operating losses, generally means higher first cost and increased floor space requirements; thus, there is a balance to be considered between the owner’s utility energy change for the losses in the transformer or other equipment versus the owner’s first cost budget and cost of money.

6.Minimum Maintenance Cost: Usually the simpler the electrical system design and the simpler the electrical equipment, the less the associated maintenance costs and operator errors. As electrical systems and equipment become more complicated to provide greater service continuity or flexibility, the maintenance costs and chance for operator error increases. The systems should be designed with an alternate power circuit to take electrical equipment (requiring periodic maintenance) out of service without dropping essential loads. Use of draw out type protective devices such as breakers and combination starters can also minimize maintenance cost and out-of-service time. Utilizing sealed equipment in lieu of ventilated equipment may minimize maintenance costs and out-of-service time as well.

7.Maximum Power Quality: The power input requirements of all utilization equipment has to be considered including the acceptable operating range of the equipment and the electrical distribution system has to be designed to meet these needs. For example, what is the required input voltage, current, power factor requirement? Consideration to whether the loads are affected by harmonics (multiples of the basic 60 Hz sine wave) or generate harmonics must be taken into account as well as transient voltage phenomena. The above goals are interrelated and in some ways contradictory. As more redundancy is added to the electrical system design along with the best quality equipment to maximize service continuity, flexibility and expandability, and power quality, the more initial investment and maintenance are increased. Thus, the designer must weigh each factor based on the type of facility, the loads to be served, the owner’s past experience and criteria.

Summary

It is to be expected that the engineer will never have complete load information available when the system is designed. The engineer will have to expand the information made available to him on the basis of experience with similar problems. Of course, it is desirable that the engineer has as much definite information as possible concerning the function, requirements, and characteristics of the utilization devices. The engineer should know whether certain loads function separately or together as a unit, the magnitude of the demand of the loads viewed separately and as units, the rated voltage and frequency of the devices, their physical location with respect to each other and with respect to the source and the probability and possibility of the relocation of load devices and addition of loads in the future.

Coupled with this information, a knowledge of the major types of electric power distribution systems equips the engineers to arrive at the best system design for the particular building.

It is beyond the scope of this guide to present a detailed discussion of loads that might be found in each of several types of buildings. Assuming that the design engineer has assembled the necessary load data, the following pages discuss some of the various types of electrical distribution systems that can be used. The description of types of systems, and the diagrams used to explain the types of systems on the following pages omits the location of utility revenue metering equipment for clarity. A discussion of short-circuit calculations, coordination, voltage selection, voltage drop, ground fault protection, motor protection and other specific equipment protection is also presented.

Measurement Practices for Reliability and Power Quality: Appendix D and E

Published by

  • John D. Kueck and Brendan J. Kirby, Oak Ridge National Laboratory
  • Philip N. Overholt, U.S. Department of Energy
  • Lawrence C. Markel, Sentech, Inc.

Published in Measurement Practices for Reliability and Power Quality: A Toolkit of Reliability Measurement Practices, 2004

Prepared by Oak Ridge National Laboratory Oak Ridge, Tennessee 37831-6285 managed by UT-BATTELLE, LLC for the U.S. Department of Energy under contract DE-AC05-00OR22725

Appendix D Summary Table: Power Quality Standards Development Activities

Table 2, provided by courtesy of EPRI-Power Electronics Applications Center, provides a listing of various power quality topics, the standards body working on the topic, the project reference, and the subject of the document.

Table 2. Power quality topics and related documents

Appendix E Discussion of the Quality–Reliability–Availability Approach

The electric power industry is beginning to look at reliability and quality of service as interrelated aspects of utility performance. Utility performance is no longer being considered independently of customer needs and responsibilities. The quality-reliability-availability (QRA) approach takes an integrated approach to power quality, service interruptions, end user requirements, and the service contract (written or implied) between the utility and its customers.

The Consortium for an Electric Infrastructure to Support a Digital Society (CEIDS) is proposing an alternative method for assessing power quality and reliability that uses the QRA approach. CEIDS is a joint initiative by EPRI and the Electricity Innovation Institute. The method includes definitions of power quality levels that add consideration of mean time between failure and mean time to repair, and assessment of QRA-enhancing options that maximize digital system uptime at optimal cost.

When quantifying the QRA of supply, it is important to define what constitutes a failure. Different loads respond in different ways to various voltage disturbances. It is appropriate to define several levels of quality because of this difference in response. The definition must go beyond traditional utility definitions of reliability (interruptions greater than 5 minutes) and include shorter-duration events that cause customer disturbances.
In order of the most sensitive definition of a failure to the least sensitive, the levels that are initially proposed by CEIDS are these:

  • Level 1: Any voltage sags below those established by the Information Technology Industry Council (ITIC) in the guideline known as the “ITIC curve.” A failure is any voltage below 70% of nominal for greater than 0.02 seconds or below 80% of nominal for greater than 0.5 seconds. The steady-state values on the ITIC curve (voltage below 90% of nominal for more than 10 seconds) are excluded. The overvoltage portion of the ITIC curve is also excluded.
  • Level 2: A failure occurs if the voltage drops below 70% of nominal voltage for more than 0.2 seconds.
  • Level 3: A failure is an interruption of at least 1 second.
  • Level 4: A failure is an interruption of at least 5 minutes.

For the QRA approach, assessing the effects of an outage on a customer helps indicate what reliability indices and statistics are important. For a factory, even a momentary outage may shut down a production line and require 6 hours of in-plant work to remove in-process material and restart the line. For this factory, it does not matter whether the utility has restored service in 5 minutes or in 3 hours. The factory wants fewer interruptions, not necessarily shorter ones. QRA looks at which types of reliability or service quality are most important. A recloser will cause a momentary outage on an entire feeder, but in doing so it will prevent a fuse blowing on a feeder branch, which would result in an extended outage for all the customers on that branch. The factory used as an example would rather have the occasional extended outage (fuse) than the more frequent momentary outage (recloser). However, if the customer can install an uninterruptible power supply (UPS) or storage that allows it to ride through a momentary or short outage (1 to 2 minutes), then the recloser plus UPS may dramatically reduce outage-related costs.

For a factory, even a momentary outage may shut down a production line and require hours of work to restart. For this factory, it does not matter whether the utility restores services in 5 minutes or in 3 hours. The factory wants fewer interruptions, not necessarily shorter ones.

This is not a radical departure from the types of calculations and assessments that utilities, customers, and regulators have always done; but if the process is formalized, electricity consumers can know what level of reliability they should expect and all parties can compare the costs of improving reliability through system improvements (e.g., installing an alternate feed), versus improving reliability through customer-side measures (e.g., installing a UPS), versus costs incurred by the customers if reliability is not improved. The QRA approach begins to bridge the gap between generation, transmission, and distribution reliability assessment because it looks not only at the value of reliability but also at how best to improve the reliability (e.g., frequency versus duration of outages).

We anticipate that QRA may become a “best practice” for assessment of reliability and service quality.

Part 9 Markets and the Provision of Basic Service

Published by

  • John D. Kueck and Brendan J. Kirby, Oak Ridge National Laboratory
  • Philip N. Overholt, U.S. Department of Energy
  • Lawrence C. Markel, Sentech, Inc.

Published in Measurement Practices for Reliability and Power Quality: A Toolkit of Reliability Measurement Practices, 2004

Prepared by Oak Ridge National Laboratory Oak Ridge, Tennessee 37831-6285 managed by UT-BATTELLE, LLC for the U.S. Department of Energy under contract DE-AC05-00OR22725

The transmission and distribution (T&D) system is inherently a communal asset. The system provides the same level of service to all customers, or to all customers within a given area. Unlike the system for supplying energy, the T&D system does not easily differentiate among different customers’ needs. Consequently, there must be a communal decision concerning the basic level of power quality and reliability the system will provide to all customers. This is inherently a regulatory decision that regulators make by considering the value of reliability and power quality to the aggregation of all customers and comparing that value with the cost of providing that level of service. Once the regulator decides on the level of power quality and reliability that is desired, market forces can be used to motivate the regulated distribution company to provide that service at the lowest cost. Performance-based rates can provide a financial incentive for the T&D company to deliver the desired level of power quality and reliability.

The transmission and distribution system is a communal asset, providing the same level of service to all customers in a given area. So there must be a communal decision as to the basic level of power quality and reliability it will provide to all customers.

There is generally a tradeoff between the price of the energy delivery service and quality/reliability. (There are some situations where price reductions and increases in service quality can be achieved simultaneously, but generally there is a tradeoff.) Incentives to the T&D company to reduce the cost of energy delivery may encourage reductions in service quality. Hence, there is a clear need for performance targets and incentives to ensure that service quality is not sacrificed.

Once targets have been established that define the basic service for power quality and reliability, incentives can be established to motivate the T&D utility to meet these targets. Annual adjustments can be made to the T&D company’s maximum allowable price (and consequently revenues) based on the service performance achieved relative to set targets. The payments should be set at or above the projected cost of improving power quality and reliability, as an incentive for the utility to meet the targets (the utility keeps any profit that results if the utility exceeds the targets at costs that are below projections). The payment should be at or below the value placed on the improvement by customers. There is no point in increasing performance if the cost exceeds the value.

Basing these payments on the annualized cost of improving power quality and reliability, rather than on the value to customers, also limits the distribution company’s financial risk. This is especially important when an incentive program is first being established and the risks are not known precisely. Penalties and incentives should be symmetric. That is, the distribution company should lose revenue if it fails to meet the expected targets and should receive extra revenue if exceeds the expected targets.

It is also important to provide a mechanism such as compensation to individuals whose power quality and/or reliability is significantly below standard so the desired improvements in average performance do not mask problem spots. Improving reliability on one feeder is no use to customers on another feeder. We must be wary of averages.

In Victoria, Australia, where incentive rates are being tried,8 the threshold for requiring payments for poor performance was set at approximately four times the average duration of interruptions. The expected cost to the distribution companies is about 0.25% of revenue; the utility is running little risk. However, these incentives should encourage distributors to undertake capital expenditures to improve the quality and reliability of supply by introducing new technology as well as by making conventional investments.

The Victoria experience makes the statement that customers would much rather receive quality service than receive payment for poor reliability. The payments made to customers for unusually poor power quality or reliability performance are meant to motivate the utility; they are not intended to adequately compensate the customer for its loss.

Key Principles in Incentive Design

Several key principals for devising quality incentives are emerging in energy markets:

  • Clearly specify the metrics and incentives in advance.
  • Make the metrics and incentives as simple as possible for both distributors and customers without distorting the incentives.
  • Ensure that performance measurement is verifiable.
  • Address worst-case performance as well as average performance.
  • Provide penalties for under-performance as well as incentives for exceeding targets.
  • Limit the financial risk, especially when first implementing the system, but make the incentive large enough to provide real motivation. Incentives should be greater than the cost to the distributor to achieve the incremental improvement, but less than the value to customers.

Interestingly, Victoria includes one more key criterion: Allow no exceptions for external events. In fact, utility executives in Victoria specifically mentioned severe storms, load shedding, and shortfalls in generating capacity as external events for which the distribution company should remain liable. The regulator’s thinking is that the distribution utility is in a better position to take action to mitigate the risk than individual customers are. “Such risks are better allocated to distributors than customers, given that distributors have greater capacity to mitigate their impact,” says a review from the Office of the Regulator-General in Victoria.8 “For example, distributors are better able to make decisions about the appropriate level of investment in network changes to reduce the impact of adverse weather. They are also better able to seek demand reductions when there is a material risk of load shedding.”

Markets Serving Individual Customers’ Power Quality and Reliability Needs

Customer power quality and reliability needs differ greatly. The basic level of service established by the regulator will not be adequate for all customers. Customers requiring greater reliability or increased power quality can take actions to obtain the level of service they require. Competitive markets minimize the cost and ensure customer choice in obtaining these services.

Customers can install equipment within their facilities to achieve any desired level of power quality and reliability they desire. Filters, surge protectors, UPSs, and backup generators are all available. Further, the customer can decide if it is necessary to increase the reliability or power quality for the entire facility, or if it is more cost-effective to address individual loads within the facility. This is inherently the customer’s decision. Only the customer knows the value of increased reliability or power quality for the customer’s situation. Much of the DER industry is dedicated to meeting the power quality and reliability needs of individual customers through market-based solutions.

Customers can install equipment within their facilities to achieve any desired level of power quality and reliability they desire. Much of the DER industry is dedicated to meeting the power quality and reliability needs of individual customers through market-based solutions.

Though most of the serious economic impact from lower-than-needed power quality and reliability is in the commercial and industrial sectors, the residential sector provides examples that illustrate the problem and possible solutions. A typical home may have a number of high-power loads such as a heat pump, water heater, oven, dryer, refrigerator, and freezer. While none of these loads is (e.g., digital clocks in the VCR, microwave, and oven) are sensitive to momentary interruptions. Yet these sensitive loads are an insignificant portion of the energy or power demand. It makes little sense to raise the power quality and reliability of the entire distribution feeder in order to serve these loads. It makes much more sense to either design the clocks with enough energy storage (a small capacitor) to ride through momentary interruptions, or to place the individual appliances on UPSs.

An interesting problem arises when the market fails to offer products that meet the customer’s power quality needs. If a consumer cannot find a VCR that is designed to tolerate momentary power interruptions, for example, the customer may pressure the load-serving entity and the regulator to increase the power quality of the overall distribution system. This is understandable, but it is the wrong solution. It may be in the load-serving entity’s interest to help the customer address the power quality and reliability problem locally. For residential customers, this could be through educational material provided in the bill. For industrial customers this could include engineering support.

Some Customers Want Lower-Quality Service

Some price-sensitive customers are more interested in reduced costs and are willing to accept lower levels of reliability than the level provided under the basic regulated service. These customers can “sell” interruption rights back to the power system. The T&D company (or the energy supplier) would interrupt this customer when the system was under stress and thus avoid interrupting other customers. The T&D company could use this capability to postpone a distribution system upgrade, for example. This concept does not work well for power quality, sags, and dips—as opposed to interruptions. It will be difficult for many customers to accept lower power quality in exchange for payment from the T&D company.

Transmission and Distribution Companies Providing Premium Power

In many cases, the most cost-effective method for addressing the power quality and reliability needs of the customer is modifying the distribution system. An industry might desire a double-ended substation with two independent feeders to supply its load. It is entirely appropriate, and fairly easy, for the T&D company to identify the additional costs involved in providing this type of above-average service and to bill the customer for it. The customer is free to evaluate the T&D solution against local generation, UPSs, and other commercially available alternatives.

Because the T&D system is a communal asset that tends to provide the same level of service to all customers within a given area, having the system itself address individual issues regarding increased reliability and power quality can be problematic. The problem centers on the fact that the regulated entity may shift costs from the customers for which it is competing to other customers that are captive to its monopoly services. How could this happen? A T&D utility that wants to sell premium power to an industrial customer could, for example, design $100,000 of improvements to the distribution system and claim that $60,000 of them are really supporting the system as a whole and should be placed in the regulated rate base. It would then offer the premium power solution to the industrial customer for $40,000. It can be very difficult for someone on the outside, or even for regulators in some cases, to know if this split between the regulated ($60,000) portion and the competitive ($40,000) portion is appropriate.

Complications always arise when regulated and competitive markets interact. It is difficult for regulators to ensure that the monopoly customers they are charged with protecting are not being used to unfairly subsidize a competitive venture. Obviously, this subsidy would be viewed as unfair by the other companies competing to sell these products or services. But it also harms the regulated customers. First, they are harmed because their regulated rates are necessarily higher if they are subsidizing competitive ventures of the distribution company. Second, they are harmed again if the regulated company is able to use its unfair advantage to drive its competition out of business. Customer choice for the competitive service is then reduced, and prices will likely rise.

With this strong incentive not to allow regulated entities to deal in competitive services, why allow T&D companies to sell premium power? The economic benefits of solving power quality problems on the distribution system can be so overwhelming that eliminating this option would seriously harm customers. It is often technically easier and cheaper to implement power quality and reliability enhancements on the distribution system rather than exclusively (or in conjunction with) within the customer’s facility. This provides a strong argument for wanting to include T&D companies in the mix of solution providers.

Adomaitis and Frank9 provide an excellent example of a case in which enhancing the T&D system proved to be the most cost-effective way to address a power quality problem for a 15-MVA industrial customer. They describe a situation where a manufacturer of glass picture tubes was experiencing production problems and losses whenever a lightning storm occurred in the area. The manufacturing process requires maintaining tight tolerances and was sensitive to power quality. If the process is shut down in a disorderly fashion, hours or days may be required to restart and get production back within specification. Momentary power interruptions and voltage sags were causing such shutdowns. The customer had installed ride-through capability on the low-power devices. Ride-through capability for the large motors was prohibitively expensive, however. A dynamic voltage regulator (DVR) solution was estimated to cost $4 million. Supplying the plant directly from the 230-kV system was also investigated, but this move, too, was found to be too expensive, at about $2.5 million.

Allegheny Power studied the problem carefully and found that by installing lightning arresters every 600 to 800 ft on approximately 50 miles of the 46-kV subtransmission system (and recoordinating the protective relay scheme), they could eliminate the power quality problems. The solution cost approximately $400,000 and was clearly the economically correct choice.

While this project is a beautiful example of why it is technically and economically important for distribution companies to be able to participate in supplying enhanced power quality, Adomaitis and Frank did not address several interesting commercial and regulatory concerns. Who should pay the $400,000, for instance? Since the beneficiary was the picture tube manufacturer, should it pay the entire cost? Power quality on the entire regional 46-kV sub-transmission system was raised, opening the argument that other customers who also benefited from the improved power quality should help pay for the project. But there is no indication that other customers in the area were dissatisfied with the level of service they were already receiving. Future customers, especially power-quality-sensitive customers, are also a concern. If another sensitive factory locates in the region, should it share in the cost of the upgrade and reduce the share the picture tube manufacturer is paying? (Reference 10 discusses a situation where the customer should pay to provide premium power to its own facility.) Should the regulator allow the cost of the enhancement to be spread among all customers on the theory that enhanced power quality will attract new industry and be good for the economic growth of the region in general? These difficult policy issues are intimately related to the technical differences in the technology choices.

The manufacturers of DVRs, for example, would be especially concerned with how these questions are answered. Had the economic trade-off between the DVR and T&D solutions been closer, the decision could very easily have turned on who is paying how much. In fact, the picture tube manufacturer would likely favor the T&D solution, even if it were more expensive, if the distribution company were able to spread the cost among other customers.

At least three important points can be drawn from this picture tube factory example:

  • The distribution solution can be the lowest cost, by a significant margin.
  • The potential exists for the distribution company to cross-subsidize between regulated and competitive services—in fact it can be difficult to determine what the correct allocation between regulated and competitive services is.
  • A free-rider problem exists.

Ensuring That Market Forces Work to Provide Power Quality and Reliability

This chapter shows that market forces can be used to address power quality and reliability requirements for both the majority of customers that are satisfied with basic service and for customers with special requirements. It is important to get the rules right, however, or the unintended consequences can be dire. Basic principles include these:

  • Identify metrics to measure power quality and reliability.
  • Establish a baseline for normal service. The baseline will likely be different for each utility and for different types of feeders.
  • Establish a rate structure with incentives for the distribution utility to meet and exceed the power quality and reliability standards.
  • Define premium power as service beyond the normal expectation.

Historically, detailed standards for power quality and reliability have not been well defined. There is a need for more disaggregated measures of power quality and for the focus of regulation to shift from the current standards that provide a safety net to targets for service quality that customers expect to receive. When this shift occurs, it will become possible to more clearly distinguish premium power from normal power. Regulated T&D companies can then be allowed to sell premium power competitively, since the costs they incur to provide that service can more readily be distinguished from the regulated costs they incur to provide the normal regulated service. Concerns over cross-subsidies are thus greatly reduced. Without clear expectations for basic service power quality and reliability, it could appear that the T&D company was intentionally suppressing the quality of basic service to increase sales of premium power.

References

  1. 2001 Electricity Distribution Price Review, Draft Decision, Office of the Regulator-General, Victoria, Melbourne, Australia, May 2000, 15601.
  2. J. Reese Adomaitis and Fred F. Frank, Use of Surge Arresters in Place of Static Wires to Reduce Lightning Caused Voltage Sags on Subtransmission Systems, Allegheny Power, Engineering Development and Support, Greensburgh, Pa., 1997.
  3. Jim Evans, “Big Three Automakers Get What They Pay For,” Transmission and Distribution World, December 1999.
Appendix C Activities and Organizations Developing and Sharing Information on Reliability and Power Quality

The following is a list and brief synopsis of the many organizations that have ongoing activities in power quality or reliability. Again, this list is not intended to capture all organizations, but rather the significant ones that are presently involved in examining power quality.

North American Electric Reliability Council (NERC)—North American Electric Reliability Organization (NAERO)
Organization: NERC
Targeted industry segment: Utilities, state regulatory agencies.
Strengths: In 1997, NERC began a self-assessment activity to examine how best to ensure adequate reliability of electric power under the new, competitive structure of the North American electric utility industry. NERC is a voluntary member organization comprising regional reliability councils. The recommendation is to establish a successor organization, NAERO, with a similar structure but charged with developing a mandatory set of guidelines. Unlike NERC, NAERO will have the authority to enforce compliance with its guidelines.
Limitation: This activity is just beginning.

Self-Assessment Template, Power Delivery Reliability Initiative, EPRI Distribution Program, Level 2 report, April 2001
Organization: EPRI
Targeted industry segment: EPRI member utilities.
Limitations: This is a report of continuing research, not a final technical report. It is intended for EPRI member utilities that have contributed to this specific research target; the report is not available to the entire industry.
Strengths: This is a broad-based and comprehensive effort to develop data on levels of distribution system reliability (as seen by the customer) and causes of outages. This is a template for assessing practices at distribution companies and therefore is a precursor to the development of reliability-related best practices.
Other: EPRI is assembling a database of utilities’ responses to the template. The project includes a Web link for users to ask EPRI about industry practices or suggest enhancements to the template. EPRI has a similar activity to assess transmission system reliability.

Transmission Reliability Project, EPRI Transmission Program
Organization: EPRI
Targeted industry segment: Transmission planners of EPRI member utilities.
Limitations: This is continuing research project. It is intended for EPRI member utilities that have contributed to this specific research target; the report is not available to the entire industry.
Strengths: The Transmission Reliability Project takes a grid-wide approach to power system reliability, recognizing the regional interconnected structure of the U.S. transmission system. Its objective is the development of an improved probabilistic risk assessment technique that models the grid’s physical and operating margins probabilistically, rather than deterministically (as is now general practice). This is a first step in developing improved reliability-related best practices for transmission planning and operations.
Other: This is an on-going research activity and will not provide definitive results for several years. EPRI has a similar activity to assess distribution system reliability.

Assessment of Distribution System Power Quality, EPRI Research Project PR3098-1
Organization: EPRI
Targeted industry segment: EPRI member utilities.
Limitations: Reports distribution system power quality observations from a limited number of utilities. The full reports are available only to EPRI members. However, summary statistics have been published in open literature.
Strengths: Multi-year power quality statistics are given for more than 300 points on the distribution systems of 34 utilities. The summary statistics provide a large sample of power quality performance on utility systems throughout the United States. The database has the capability to correlate observed levels of power quality with utility, weather, geography, feeder topology, and customer characteristics.
Other: This project is ongoing and provides the broadest sample of U.S. distribution system power quality statistics. It is a necessary first step in setting power quality standards.

IEEE Power Quality Activities
This item lists some additional power quality groups within IEEE. IEEE groups are updating or developing some of the previously listed standards—1159 and 1346—as well as other related standards.
Organization: IEEE
Targeted industry segment: Utilities, vendors, equipment designers, systems designers.
Limitations: Voluntary organization; limited outreach to organizations and individuals not in IEEE; coordination among IEEE groups is critical because of the different constituencies (IEEE Standards Coordinating Committee SCC-22 is attempting to do this).
Strengths: Consensus standards; broad-based constituency

IEEE SCC-22 – Standards Coordinating Committee on Power Quality
SCC-22 is responsible for coordinating IEEE activities relating to power quality. In addition to coordinating the following activities, SCC-22 is the designated IEEE liaison with any other standards-developing bodies that are preparing power quality standards or guidelines.

IEEE P1409 Distribution Custom Power Task Force
This task force is developing the Guide for Application of Power Electronics for Power Quality Improvement on Distribution Systems Rated 1 kV through 38 kV. The document will provide guidelines and performance expectations for the application of power electronics–based equipment on utility distribution systems for improving power quality and control in these distribution systems. The guide will be a resource to utilities in the competitive marketplace, providing detailed information about custom power devices as options for solving power quality problems.

P1453 IEEE Voltage Flicker Task Group
This task force is developing a recommended practice for a measurement protocol for and limits to voltage flicker. The task force has voted to adopt and enhance the IEC Flickermeter measurement protocol.

IEEE Working Group on Surge Characterization
This working group completed a set of documents on surge characterization and test procedures:

  • C62.41.1—Guide on the surge environment in low-voltage ac power circuits
  • C62.41.2—Recommended practice on surge characterization in low-voltage ac power circuits
  • C62.45—Recommended practice on surge testing for equipment connected to low-voltage ac power circuits.

Other IEEE working groups

  • PC62.44 – Applications guide on secondary arresters
  • PC62.72 – Low-voltage ac power circuit protective devices
  • PC62.74 – Application guide for multi-port protectors

National Association of Regulatory Utility Commissioners (NARUC)
Organization: NARUC
Targeted industry segment: State regulators.
Limitations: It is difficult to address all of the reliability issues
Strengths: NARUC has a staff subcommittee on Electric Reliability that is working to develop standard reliability assessment techniques (and identifying how to enhance reliability). This activity is providing guidance to regulators who traditionally do not have extensive expertise in power system reliability and is helping to standardize evaluation procedures among states.

American Public Power Association (APPA), Distribution System Performance Improvement Guide
Organization: APPA
Targeted industry segment: Publicly-owned utilities, technical and engineering staff.
Strengths: This is a companion guide to APPA’s Making the Most of Your Distribution System, which was targeted to policymakers. It provides step-by-step procedures for evaluating distribution system performance and comparing performance improvement options. The report contains several case studies. It covers many aspects of utility operations, not just reliability. APPA has asked members to report outages consistent with IEEE P1366. APPA has conducted statistical surveys of the SAIDI and CAIDI but has found that these numbers cannot be compared because of differences among member utilities in how outages are defined (i.e., the problem is in defining what is an outage, not in how SAIDI is calculated). APPA has published the Distribution System Performance Improvement Guide and Distribution System Optimization Guide, consisting of selected case studies that illustrate how its members address this issue. This is the first attempt to assemble a comprehensive reliability performance database for public utilities.
Limitations: Voluntary reporting is not complete; there are different data definition and reporting procedures.

Maintenance Guidelines, Requirements Study Format
Organization: U.S. Department of Agriculture, Rural Utilities Service (RUS)
Targeted industry segment: Rural electric cooperatives.
Description and strengths: To qualify for a loan from RUS, a utility must submit a 5-year requirements study, including a Load Forecast, a Construction Work Plan, and a Long-Range Plan. RUS does not have a required format for these documents, but guidelines for their submission are on the RUS Web site, and data requirements are given in 7 CFR 1710. RUS is also instituting a Web-based data reporting system. The cooperatives’ plans must be updated every year for transmission projects and every 3 years for distribution projects. The cooperative must also follow the RUS maintenance guidelines, outlined in Bulletin 1730-1 Electric System Operation and Maintenance. This bulletin contains guidelines related to electric borrowers’ operation and maintenance (O&M) and outlines the RUS standard practices with respect to review and evaluation of O&M practices. While RUS does not have a reliability standard, the intent is that adhering to these loan conditions will result in a plan that provides an acceptable quality of service. For construction design criteria, RUS usually uses ANSI standards as requirements for cooperatives’ projects, but RUS has a more conservative standard than ANSI for transformers. Standard practices (e.g., in design, construction) across the country mean that a lineman from any cooperative can recognize (and help) any other cooperative. Design standards, lists of acceptable materials and equipment, and more detailed information can be found on the RUS Web site at Hwww.usda.gov/rus.

Limitations: These are general requirements and guidelines for utility practices and construction standards for cooperatives applying for loans from RUS. RUS does not impose a reliability standard. RUS also sees different problems—and solutions—for rural vs urban cooperatives.

NRECA Reliability and Power Quality Assessment
Organization: National Rural Electric Cooperative Association (NRECA), Cooperative Research Network (CRN)
Targeted industry segment: Rural electric cooperatives.
Description and strengths: NRECA feels that many industry guidelines—such as the IEEE reliability indices and definitions and the EPRI reliability performance studies—are not applicable to rural cooperatives, or even rural parts of electric utility service territories in general. Rural customers have different needs, expectations of quality and availability of service, ways to cope with service interruptions, and access problems from the typical urban customer. As a remedy, the CRN is undertaking a comprehensive look at reliability and power quality for rural areas to (1) develop reliability and power quality indices that apply to rural systems, (2) conduct benchmarking of reliability and power quality performance, and (3) identify relevant case studies. The intention is to eventually be able to develop recommended levels of reliability and power quality for rural systems based on the benchmarking work. This project is expected to be completed by the end of 2002. Through the CRN, NRECA also has developed several operations guidelines to improve system reliability for rural cooperatives. (These reports cover specific topics such as vegetation management.) Additional information can be obtained directly from NRECA or on the CRN Web site at Hhttp://www.crnweb.org/H.

Limitations: The reports are available only to CRN members.

International and European Organizations
Several European electric utility organizations have working groups developing power quality specifications:
Congress Internationale des Grand Reseaux Electriques a Haute Tension (CIGRE)—Working Group 36.05 on voltage quality
Congress Internationale des Reseaux Distribution (CIRED)—Working Group 2, joint with CIGRE Working Group 36.05
UNIPEDE/Eurelectric—Working groups on voltage limits, electromagnetic compatibility, harmonics
Targeted industry segment: Utilities, regulators.
Strengths: Broad-based participation from European countries.
Limitations: European practices and designs are not always compatible or consistent with those in the United States.

Reports on Electric Power Disturbances
Organization: Federal Energy Regulatory Commission (previously, Federal Power Commission, Energy Regulatory Agency)
Targeted industry segment: Utilities and regulatory agencies.
Limitations: These are summary reports of major outages. The information is not very detailed regarding the numbers of customers affected, duration of outages, and amount of load interrupted. The format is especially limiting for assessing partial restoration after the incident. However, the biggest limitation is that only major bulk power outages are included; events affecting fewer customers or for short durations may not be reported.
Strengths: Provides data on large outages in the United States over the last 30 years.
Other: Provides a historical perspective on U.S. power system reliability.

Scoping Study on Trends in the Economic Value of Electricity Reliability to the U.S. Economy
Organization: Consortium for Electric Reliability Technology Solutions (CERTS) Hhttp://certs.lbl.govH
Targeted industry segment: Utilities, industries, electrical consumers.
Limitations: This is a scoping study prepared using a literature review and the other available data with direction from EPRI. It is a step toward understanding the cost impact to the U.S. economy of unreliable electricity, how the value of reliability is likely to change in the future, and how customers are addressing their reliability needs.
Strengths: This study provides an analysis of trends in the economic value of electricity reliability in the U.S. economy. The analysis includes requirements of commercial office equipment, statistical indicators of industrial electricity use and economic activity to identify high-reliability market segments, and a case study of a market segment known to have high-reliability requirements.

Office of Electric Transmission and Distribution
Organization: Office of Electric Transmission and Distribution, U.S. Department of Energy
Targeted industry segment: Utilities, regulatory agencies, vendors, customers.
Purpose: This office is an in-depth resource for the many aspects of transmission and distribution reliability. One of the first reports is the National Transmission Grid study, available at http://www.ntgs.doe.gov.

Part 8 Standardizing Reliability and Power Quality Metrics

Published by

  • John D. Kueck and Brendan J. Kirby, Oak Ridge National Laboratory
  • Philip N. Overholt, U.S. Department of Energy
  • Lawrence C. Markel, Sentech, Inc.

Published in Measurement Practices for Reliability and Power Quality: A Toolkit of Reliability Measurement Practices, 2004

Prepared by Oak Ridge National Laboratory Oak Ridge, Tennessee 37831-6285 managed by UT-BATTELLE, LLC for the U.S. Department of Energy under contract DE-AC05-00OR22725

Utilities and/or distribution companies are able to provide only a level of reliability and power quality commensurate with the designs of their distribution systems. These levels vary greatly among locations and among distribution system designs. Underground network systems with several redundant primary feeders like those used in major metropolitan areas can provide very high levels of reliability and power quality, while rural distribution systems with long overhead radial feeders often experience voltage sags. In some cases, feeders for industrial plants come directly from transmission substations and have an inherently higher level of reliability and power quality.

These design features and arrangements are not possible in every location. Assumptions regarding the level of reliability and power quality should not be developed in a vacuum, without considering constraints on the local utility. A number of utility measures can be taken to minimize interruptions. IEEE Std 1250-1995 provides two sets of measures, design measures and operating measures:

Design measuresOperating measures
General circuit layout and construction
Circuit exposure, length, and type
Protective coordination
Fault sectionalizing
Grounding considerations
Surge arrestor application		Equipment inspection and maintenance
Line inspection and maintenance
Right-of-way inspection and maintenance
Prompt identification of chronic problems
Analysis of interruption data
Line monitoring

In the future, a level of required reliability and power quality may be developed and specified for a broad range of industrial processes. This has already been done for the computer industry and the semiconductor manufacturing industry. Levels could be developed for residences, commercial establishments such as restaurants, critical facilities such as hospitals and communication networking centers, and industry.

A reasonable expected level of reliability and power quality could be developed for specific distribution locations. As discussed earlier, these levels would be a function of a number of variables including climate, design, and maintenance. It would be essential to keep index calculation methods uniform. For example, the method for acquiring restoration times after an outage would have to be identical, both in theory and practice, between utilities. Step restoration, where end times of interruption are measured in large blocks (for example, at the substation level), can lead to large discrepancies if other utilities are measuring time at the sublateral or even customer level. Ideally, the actual individual customer restoration time would be measured and used in the index calculation.

Development of such standards would require a computer-based system that is programmed and managed identically among the utilities to acquire data and calculate indices. Definitions of concepts such as a major event would also have to clearly defined and practiced uniformly. If this could be done, this common method of computer-based data acquisition and calculation would produce indices that were meaningful for comparison between utilities.

A drawback to such a standardized programmed and managed reliability database is that some utilities will inherently have better reliability indices than others due to simple differences in climate and geography. For example, factors such as the number of lightning strikes, the length of exposed feeders, a desert climate, and urban network system designs will have a significant impact on the reliability figures, independent of the actions of the utility to competently operate and maintain its system. As noted in the previous section, Pacific Power is presently using performance incentives based on reliability indices. Once the calculation method is well defined and understood by both the utility and the regulator, it provides a common ground for assessing performance. In New York State, performance metrics are quite well defined and are agreed upon by both utilities and the public service commission.

Part 7 Valuing Reliability

Published by

  • John D. Kueck and Brendan J. Kirby, Oak Ridge National Laboratory
  • Philip N. Overholt, U.S. Department of Energy
  • Lawrence C. Markel, Sentech, Inc.

Published in Measurement Practices for Reliability and Power Quality: A Toolkit of Reliability Measurement Practices, 2004

Prepared by Oak Ridge National Laboratory Oak Ridge, Tennessee 37831-6285 managed by UT-BATTELLE, LLC for the U.S. Department of Energy under contract DE-AC05-00OR22725

Although reliability metrics do have their shortcomings, as discussed in Section 6, they are useful for trending when applied consistently with an unchanging set of calculation procedures. For example, Pacific Power has developed several performance standards that are on file with the applicable state commissions. Failure to meet these standards results in financial penalties for the utility. Four of these standards are as follows:

  1. In each state, annual SAIDI will be improved by 10% between 2003 and 2005.
  2. In each state, annual SAIFI will be improved by 10% between 2003 and 2005.
  3. In each state, annual MAIFI will be improved by 5% between 2003 and 2005.
  4. In each state, the five worst-performing distribution circuits will be improved by 20% over a 2-year period. Five new circuits will be selected in each state each year for a 5-year period.
    In addition to these metrics, which are part of the agreement with the public utility commissions, Pacific Power also has customer guarantees, again tied to financial penalties if the utility fails to deliver. Three of these are summarized as follows:5
  1. After an interruption, power will be restored within 24 hours, barring damage due to extreme weather. If this condition is not met, the residential customer receives $50, and the commercial customer, $100.
  2. Power will be switched on within 24 hours of the customer’s request or the customer receives $50.
  3. Customers will be notified two days prior to a planned interruption; if not, each customer receives $50.

These standards of reliability are part of a program to establish a high level of customer service as part of a fundamental business philosophy. The guarantees provide a concrete example of the value of reliability.

The worst-performing distribution circuits are chosen for upgrade by Pacific Power using the customer hours interrupted, or the numerator of SAIDI.6 Experienced judgment can then be used to implement known improvements based on reliable rules of thumb and without extensive analysis.

On the other hand, some utilities such as Commonwealth Edison in Chicago are using large-scale reliability modeling to analyze circuits and choose optimal improvements based on cost and benefit.

After a series of major distribution outages in Commonwealth Edison territory in 1999, ComEd launched a comprehensive investigation looking at equipment, design, personnel, and operations. The corrective actions included substation and feeder inspections, installation of new feeders, feeder upgrades, substation expansions, building of new substations, and the implementation of a new maintenance program. ComEd also developed a predictive reliability model consisting of more than 3,300 feeders. The model provided an intelligent system to automatically identify potential reliability problems and to recommend reliability improvement projects based on expected benefits and costs.7 A reliability assessment model quantifies reliability characteristics based on system topology and component reliability data. The model identifies areas of inherently good or poor reliability, and also identifies overloaded and undersized equipment that degrade system reliability. Some typical improvements that a predictive reliability model can explore include

  • load transfers between feeders,
  • building of new substations and substation expansions,
  • addition of line reclosers,
  • sectionalizing switches,
  • adding new feeder tie points,
  • automating feeders,
  • undergrounding of circuits, and
  • replacement of aging equipment.

The ComEd model uses a simulation that assesses each contingency, determines the impact, and weights the impact by the contingency’s probability of occurrence. A sample reliability assessment is shown in Figure 1. Areas with relatively low reliability are shaded in red. Potential problem areas can be quickly identified. If a red area is adjacent to a blue area, it may be desirable to transfer some customers through reconfiguration to improve the reliability of the transferred customers and to help equalize the reliability of the two areas.

Figure 1. Reliability assessment results. Components are shaded based on expected annual outage hours, a primary driver of SAIDI. Source: Ref. 7.

Computer-generated reliability improvements can be evaluated and different approaches can be compared from a cost-benefit perspective. Interestingly, the cost-effectiveness of reliability improvement projects varies widely from area to area. After the reliability model was completed, an intelligent system was used to automatically identify potential reliability problems and recommend reliability improvement projects based on benefits and costs. Figure 2 shows that the highest ranked project for the Northeast region is more than three times as cost-effective as the highest ranked project in the Southern region. The cost benefit varies widely, different types of projects tend to be more effective for different regions, and the best allocation of money will require flexibility in both the types of projects that are funded and the level of funding for each geographic region. This graph shows that the most cost-effective reliability gains can be made in the Northeast.

Figure 2. Plot of recommendations vs reliability score. Source: Ref. 7.

Some of the recommendations for reliability improvement projects included the following:

  • Transfer path upgrade: A transfer path is an alternate path to serve load after a fault occurs. If a transfer path is constrained due to small conductor sizes, reconductoring may be cost effective.
  • New tie points: A tie point is a normally open switch that allows a feeder to be connected to an adjacent feeder. Adding new tie points increases the number of possible transfer paths.
  • Increased line sectionalizing: Increased line sectionalizing is accomplished by placing normally closed switching devices on a feeder. Adding switches improves reliability by allowing more flexibility during post fault system reconfiguration.
  • Feeder automation: Adding SCADA-controlled switches on feeders will allow automated post-fault system reconfiguration.

The entire ComEd distribution modeling effort required less than one year. The results found that the most cost-effective approaches to improving reliability are not always obvious and can vary by feeder and region.7

Evaluating reliability improvements can thus require a range of techniques from detailed probability modeling of the entire system to using proven rules of thumb to plan upgrades. Interestingly, the utility discussed here that is simply using tried-and-true methods to plan improvements is meeting its reliability standards every year and posting the results on its website.

Conversely, the utility that developed the comprehensive reliability analysis model and the intelligent system to automatically identify potential problems and recommend improvements, made the news with three major outages in one summer. The subsequent effort modeled, calibrated, and assessed the reliability of more than 3300 feeders.

References

  1. Pacific Power, “Customer Service Commitments: Annual Report,” May 2003, available at http://www.pacific-power.com/File/File28086.pdf.
  2. Dennis Hansen, A Methodology for Maintaining and Improving Reliability, IEEE 0-7803-7285-9/01, Institute of Electrical and Electronic Engineers, Piscataway, N.J., 2001.
  3. Richard E. Brown, Distribution Reliability Modeling at Commonwealth Edison, IEEE 0-7803-7285-9/01, Piscataway, N.J., 2001.

Part 6 Pitfalls in Methods for Reliability Index Calculation

Published by

  • John D. Kueck and Brendan J. Kirby, Oak Ridge National Laboratory
  • Philip N. Overholt, U.S. Department of Energy
  • Lawrence C. Markel, Sentech, Inc.

Published in Measurement Practices for Reliability and Power Quality: A Toolkit of Reliability Measurement Practices, 2004

Prepared by Oak Ridge National Laboratory Oak Ridge, Tennessee 37831-6285 managed by UT-BATTELLE, LLC for the U.S. Department of Energy under contract DE-AC05-00OR22725

Because some utilities are adopting performance-based rates, the importance of calculating reliability indices is growing. In order to do an “apples-to-apples” comparison between utilities, it is essential that reliability index calculation and reporting methods be uniform. A nationwide survey of information used for calculating distribution reliability indices was recently performed.4 The survey found a number of different sources of disparity between utility practices. Some of the most significant issues are summarized as follows.

One significant source of discrepancies is step restoration. When a utility takes actions to restore power after a large-scale outage, the restoration proceeds in steps. If customer minutes are not tracked accurately as these steps are taken, the “start” and “end” times of the interruption can increase or decrease and have a major impact on the calculated indices.

How far down does the utility go in analyzing an interruption? Does the analysis go to the distribution substation, circuit breaker, recloser, sectionalizer, fuse, transformer, service, or meter? Survey results have shown that the system average interruption duration index (SAIDI) can double with the inclusion of data down to the fuse level. Some utilities calculate SAIDI only down to the substation level.

The momentary average interruption frequency index (MAIFI), which is the total number of customer momentary interruption events divided by the total number of customers served, measures data on “momentary” interruptions that result in a zero voltage. For example, two circuit breaker open operations equals two momentary interruptions. Another index, the system average interruption frequency index (SAIFI), is the total number of customer interruptions divided by the total number of customers served. Some utilities include MAIFI data in the SAIFI calculation. When MAIFI data is included in the SAIFI calculations, the SAIFI index can triple. In addition, obtaining the momentary information accurately is sometimes quite difficult because some reclosers and distribution breakers are not equipped with SCADA.

A “major event” is defined in IEEE Standard 1366 as a catastrophic event that exceeds the design limits of the power system. Utilities are permitted to exclude major events when calculating their indices. There is a wide variance, however, in how a major event is defined in practice and how it is used for excluding abnormal data. Some utilities use a major event definition that is set by the governing regulatory agency; others use their own definition. This has a tremendous impact on the calculated indices. Of the surveyed utilities, 70% said that they had a major event definition, and 53% said that their major event definition was the same as that used by the governing regulatory agency.

Finally, how data are entered has a bearing on validity. Some utilities have a computer-based system for calculating indices in which interruption data are automatically entered, while others enter data manually through a spreadsheet-based system. It was found that the more sophisticated the computerized system is, the more likely it is that the data will be consistent and reflect actual system performance.

In addition, there was a feeling expressed among the survey respondents that generation and transmission should have their own reliability indices, and that these should not be included in the calculation of distribution reliability. One utility found that including transmission and generation interruptions increases SAIDI by 131% and SAIFI by 120%.

It is clear that the process used for calculating reliability indices can vary greatly from utility to utility. The input data sources vary tremendously, and there are major differences in basic calculation methods. The indices are essentially useless for comparing utility performance unless these discrepancies are identified and understood. When applied consistently, the indices are useful for examining year-to-year trends within a specific utility, but when comparing utilities with different data collection methods and definitions, as described above, the indices presently can be quite misleading.

Reference

4. C. A. Warren, “A Nationwide Survey of Recorded Information Used for Calculating Distribution Reliability Indices,” IEEE Transactions on Power Delivery 18, no. 2 (April 2003).