AIR CONDITIONER AND HEATERS ENERGY RATINGS EXPLANATION AND TUTORIALS

Energy ratings indicate the efficiency of heating and cooling equipment. Basically, these ratings are a comparison of output (heating or cooling) to input (electricity, gas, or oil).

Energy Efficiency Rating (EER)
Cooling efficiency rating for room air conditioners. The ratio of the rated cooling capacity in Btu per hour divided by the amount of electrical power used in kilowatt-hours.

The higher the EER number, the greater the efficiency.

Seasonal Energy Efficiency Rating (SEER)
Cooling efficiency rating for central air conditioners and heat pumps. SEER is determined by the total cooling of an air conditioner or heat pump in Btu during its normal usage period for cooling divided by the total electrical energy input in kilowatt-hours during the same period.

The higher the SEER number, the greater the efficiency.

Annual Fuel Utilization Efficiency (AFUE)
Tells you how efficiently a furnace converts fuel (gas or oil) to heat. For example, an AFUE of 85% means that 85% of the fuel is used to heat your home, and the other 15% goes up the chimney.

The higher the efficiency, the lower the operating cost. Old furnaces might have an AFUE rating as low as 60%.

Mid-efficiency ratings are approximately 80%.

High-efficiency ratings are 90% or higher.

Maximum furnace efficiency available is approximately 96.6%.

The higher the AFUE number, the greater the efficiency.

Heating Seasonal Performance Factor (HSPF)
Heating efficiency of a heat pump. HSPF is determined by the total heating of a heat pump in Btu during its normal usage period for heating divided by the total electrical energy input in kilowatt-hours during the same period.

The higher the HSPF rating, the greater the efficiency.

SUBMERSIBLE PUMPS BASIC INFORMATION AND DIAGRAM

PARTS OF SUBMERSIBLE PUMP

figure 1

A submersible pump consists of a centrifugal pump driven by an electric motor. The pump and the motor are contained in one housing, submersed below the permanent water level, within the well casing.

The pump housing is a cylinder 3–5 in. in diameter and 2–4 ft long. When running, the pump raises the water upward through the piping, to the water tank. Proper pressure is maintained in the system by a pressure switch. The disconnect switch, pressure switch, limit switches, and controller, are installed in a logical and convenient location near the water tank.

Pumps commonly called “2-wire pumps” contain all required starting and protection components and connect directly to the pressure switch—with no other aboveground controller. Generally, there are no moving electrical parts within the submersible pump, such as the centrifugal starting switch found in a typical single-phase, split-phase induction motor.

Other pumps, referred to as “3-wire pumps,” require an aboveground controller that contains any required components not in the motor, such as a starting relay, overload protection, starting and running capacitors, lightning arrester, and terminals for making the necessary electrical connections.

Most water pressure tanks have a precharged air chamber in an elastic bag (bladder) that separates
the air from the water. This ensures that air is not absorbed by the water. Water pressure tanks compress air to maintain delivery pressure in a usable range without cycling the pump at too fast a rate.

When in direct contact with the water, air is gradually absorbed into the water, and the cycling rate of
the pump will become too rapid for good pump life unless the air is periodically replaced. With the elastic
bag, the initial air charge is always maintained, so recharging is unnecessary.

Submersible pumps are covered by UL Standard 778.

Submersible Pump Cable
Power to the motor is supplied by a “drop” cable, especially designed for use with submersible pumps. This cable is marked “submersible pump cable,” and it is generally supplied with the pump.

This cable can also be purchased separately. The cable is cut to the proper length to reach between the pump and its controller, as shown above (figure 1) or between the pump and the well cap, as shown below:

When needed, the cable may be spliced according to the manufacturer’s specifications. Submersible water pump cable is “tag-marked” for use within the well casing for wiring deep-well water pumps, where the cable is not subject to repetitive handling caused by frequent servicing of the pump units.

A submersible pump cable is not designed for direct burial in the ground unless it is marked “Type USE” or “Type UF.” Should it be required to run the pump’s circuit underground for any distance, it is necessary to install Type UF or Type USE cable or a raceway with suitable conductors, and then make up the necessary splices in a listed weatherproof junction box.

THERMAL (LAGGED DEMAND) ELECTRICITY METERS

Electromechanical
In the electromechanical thermal or lagged-type demand meter, the pointer is made to move according to the temperature rise produced in elements of the meter by the passage of currents. Unlike the integrating demand meter, the lagged meter responds to load changes in accordance with the laws of heating and cooling, as does electrical equipment in general.

Because of the time lag, momentary overloading, instead of being averaged out, will have a minor effect on the lagged meter unless the overloading is held long enough or is severe enough to have some effect on the temperature of equipment.

The demand interval for the lagged meter is defined as the time required for the temperature sensing elements to achieve 90% of full response when a steady load is applied. Like the integrating meter, the lagged meter is generally designed to register kilowatt demand.

The lagged type is essentially a kind of wattmeter designed to respond more slowly than an ordinary wattmeter. An important difference in these methods of metering demand is in the demand interval. In the integrating meter, one demand interval follows another with regularity, giving rise to the term block interval.

The thermal or lagged meter measures average load with an inherent time interval and a response curve which is based on the heating effect of the load rather than on counting disk revolutions during a mechanically timed interval.

Electronic
Electronic thermal demand emulation is the logarithmic average of the power used, with a more recent load being weighted more heavily than a less recent load, (approximated exponentially). The meter will record 90% of a change in load in 15 minutes, 99% in 30 minutes, and 99.9% in 45 minutes.

Because thermal demand emulation is the logarithmic average, the demand is not set to zero on a demand reset. On a demand reset, present demand becomes the new maximum demand.

ELECTRICITY METER (KW-HR) ANTI CREEP HOLES

Without anti-creep holes, the interaction of the voltage coil and the light-load adjustment might provide enough torque to cause the disk to rotate very slowly when the meter was energized, but no current flowing.

This creep would generally be in a forward direction, because the light-load adjustment is so designed that it helps overcome the effects of friction and compensates for imperfections of the electromagnet steels. In order to prevent the disk from rotating continuously, two diametrically opposed holes are cut into the disk.

These holes add resistance to the flow of eddy currents caused by the voltage flux. Earnshaw’s Theorem explains that a conductor in a flux field tends to move to a position of least coupling between the conductor and the source of the flux field.

Because of this, the disk will tend to stop at a position in which the anti-creep hole causes the greatest reduction in the eddy currents (sometimes moving backward a portion of a revolution in order to stop in this position). A laminated disk or one of varying thickness will also tend to stop in a position of least coupling.

RACEWAY SIZING AS PER NEC BASIC INFORMATION

In keeping with the emphasis of the metric system of measurements in the NEC, a Metric Designator has been introduced to provide an equivalency to the inch system of measurement for circular raceways
used for many years as shown in table below.

You may have noticed the NEC uses the term “trade size” rather than simply “size” or “size in
inches” to indicate the size of circular raceways. There is a simple explanation for this designation.
Trade size 2 conduit is not two inches!

You should know that the circular raceway with the largest internal size in trade sizes 1⁄2 through 2 (metric designator 16 through 53) size is IMC and from trade size 21⁄2 through 4 (metric designator 63 through 103) is EMT. Thus, these raceways allow a larger number of conductors in some cases.

It will be useful to review some of the terms used in the NEC concerning raceways:

• A ferrous conduit is made of iron or steel; a nonferrous conduit is made of a metal other than iron or steel.

• Common nonferrous raceways include aluminum, brass and stainless steel.

• Metal or metallic would include both ferrous and nonferrous.

• Nonmetallic raceways would include PVC, ENT, and fiberglass.

• Couplings are used to connect sections of a raceway.

• Locknuts, metal bushings, or connectors are used to connect raceways to boxes or fittings.

• Integral couplings are formed into some raceways and cannot be removed.

• Associated fittings such as couplings and connectors are separate items.

• A running thread is a longer-than-standard length thread cut on one conduit and is sometimes referred to as “continuous-thread” or “all-thread.” Connection to another conduit is achieved by screwing a coupling on the running thread, butting the conduits together, and then backing the coupling onto the second conduit.

As shown in Figure 6-1, running threads are not permitted for connecting conduits together with a coupling as a tight connection is not assured, NEC 344.42(B). Running thread can be used to connect two enclosures by cutting the conduit to length, installing the outer locknuts on the running thread, and sliding the conduit into one enclosure, then into the other.

Caution: If running thread is created by cutting threads in the field, no galvanizing will remain on the conduit,
and protection against rusting should be provided. An option to installing running thread between enclosures is to connect two conduit nipples together with a split coupling.

ADVANTAGES OF IMPLEMENTING SMART GRID

WHY IMPLEMENT SMART GRID NOW?

Since about 2005, there has been increasing interest in the Smart Grid. The recognition that ICT offers significant opportunities to modernise the operation of the electrical networks has coincided with an understanding that the power sector can only be de-carbonised at a realistic cost if it is monitored and controlled effectively. In addition, a number of more detailed reasons have now coincided to stimulate interest in the Smart Grid.

Ageing assets and lack of circuit capacity
In many parts of the world (for example, the USA and most countries in Europe), the power system expanded rapidly from the 1950s and the transmission and distribution equipment that was installed then is now beyond its design life and in need of replacement. The capital costs of like-for-like replacement will be very high and it is even questionable if the required power equipment manufacturing capacity and the skilled staff are now available.

The need to refurbish the transmission and distribution circuits is an obvious opportunity to innovate with new designs and operating practices. In many countries the overhead line circuits, needed to meet load growth or to connect renewable generation, have been delayed for up to 10 years due to difficulties in obtaining rights-of-way and environmental permits.

Therefore some of the existing power transmission and distribution lines are operating near their capacity and some renewable generation cannot be connected. This calls for more intelligent methods of increasing the power transfer capacity of circuits dynamically and rerouting the power flows through less loaded circuits.

Thermal constraints
Thermal constraints in existing transmission and distribution lines and equipment are the ultimate limit of their power transfer capability. When power equipment carries current in excess of its thermal rating, it becomes over-heated and its insulation deteriorates rapidly.

This leads to a reduction in the life of the equipment and an increasing incidence of faults. If an overhead line passes too much current, the conductor lengthens, the sag of the catenary increases, and the clearance to the ground is reduced.

Any reduction in the clearance of an overhead line to the ground has important consequences both for an increase in the number of faults but also as a danger to public safety. Thermal constraints depend on environmental conditions, that change through the year. Hence the use of dynamic ratings can increase circuit capacity at times.

Operational constraints
Any power system operates within prescribed voltage and frequency limits. If the voltage exceeds its upper limit, the insulation of components of the power system and consumer equipment may be damaged, leading to short-circuit faults. Too low a voltage may cause malfunctions of customer equipment and lead to excess current and tripping of some lines and generators.

The capacity of many traditional distribution circuits is limited by the variations in voltage that occur between times of maximum and minimum load and so the circuits are not loaded near to their thermal limits. Although reduced loading of the circuits leads to low losses, it requires greater capital investment.

Since about 1990, there has been a revival of interest in connecting generation to the distribution network. This distributed generation can cause over-voltages at times of light load, thus requiring the coordinated operation of the local generation, on-load tap changers and other equipment used to control voltage in distribution circuits.

The frequency of the power system is governed by the second-by-second balance of generation and demand. Any imbalance is reflected as a deviation in the frequency from 50 or 60 Hz or excessive flows in the tie lines between the control regions of very large power systems. System operators maintain the frequency within strict limits and when it varies, response and reserve services are called upon to bring the frequency back within its operating limits [1].

Under emergency conditions some loads are disconnected to maintain the stability of the system. Renewable energy generation (for example. wind power, solar PV power) has a varying output which cannot be predicted with certainty hours ahead. A large central fossil-fuelled generator may require 6 hours to start up from cold. Some generators on the system (for example, a large nuclear plant) may operate at a constant output for either technical or commercial reasons.

Thus maintaining the supply–demand balance and the system frequency within limits becomes difficult. Part-loaded generation ‘spinning reserve’ or energy storage can address this problem but with a consequent increase in cost. Therefore, power system operators increasingly are seeking frequency response and reserve services from the load demand.

It is thought that in future the electrification of domestic heating loads (to reduce emissions of CO2) and electric vehicle charging will lead to a greater capacity of flexible loads. This would help maintain network stability, reduce the requirement for reserve power from part-loaded generators and the need for network reinforcement.

Security of supply
Modern society requires an increasingly reliable electricity supply as more and more critical loads are connected. The traditional approach to improving reliability was to install additional redundant circuits, at considerable capital cost and environmental impact.

Other than disconnecting the faulty circuit, no action was required to maintain supply after a fault. A Smart Grid approach is to use intelligent post-fault reconfiguration so that after the (inevitable) faults in the power system, the supplies to customers are maintained but to avoid the expense of multiple circuits that may be only partly loaded for much of their lives. Fewer redundant circuits result in better utilisation of assets but higher electrical losses.

National initiatives
Many national governments are encouraging Smart Grid initiatives as a cost-effective way to modernise their power system infrastructure while enabling the integration of low-carbon energy resources. Development of the Smart Grid is also seen in many countries as an important economic/commercial opportunity to develop new products and services.

NEC CONTINUOUS LOAD CALCULATION FOR ELECTRICAL SYSTEM DESIGN

Several NEC sections contain the very important requirement to size conductors and overcurrent devices at 100% of the noncontinuous loads plus 125% of the continuous loads. This takes into account heat buildup resulting from the current flowing through the conductors and overcurrent devices for an extended period of time.

These requirements are found in NEC 210.19(A)(1) for branch circuits, 210.20(A) for branch circuit overcurrent devices, 215.2(A)(1) for feeder conductors, 215.3 for a feeder overcurrent protection, 230.42(A)(1) for service conductors, 409.20 and 409.21 for industrial control panels, and 625.21 for electric vehicle charging system overcurrent protection.

It is not necessary to apply the 125% factor for grounded (often neutral) conductors that are not connected to an overcurrent device, NEC 210.19(A) (1) Exception No. 2, 215.2(A)(1) Exception No. 2, and 230.42(A)(2).

The logic of this Code exception is that the heat developed in the neutral conductor
will not contribute to the possible nuisance tripping of a circuit breaker or the opening of a fuse because
the neutral conductor is terminated on a neutral bus, not to the terminal of an overcurrent device.

A second exception provides that if both the overcurrent device and its assembly are listed for operation at 100% of their rating, it is not necessary to increase the ampacity of the conductors and overcurrent device by 25%. Be very cautious with this exception.

Most electrical equipment in the 600 volt class is not rated for continuous operation at 100% of its rating.
Store lighting is an example of continuous loads, whereas receptacle outlets typically are not considered
continuous loads.

There are two ways to compensate for continuous loads. One way is to apply a 125% factor to the
continuous load plus 100% of the noncontinuous load, and this becomes the minimum rating of the
conductor and the overcurrent device.

The second method is to limit the continuous load on the circuit to not more than 80% of the rating of the overcurrent device and the conductor.

WIRING DIAGRAMS FOR A TYPICAL STANDBY GENERATOR

For simplicity, the diagrams presented are one-line diagrams. Actual wiring consists of two ungrounded conductors and one grounded “neutral” conductor. Equipment grounding of all of the components is accomplished through the metal raceways that interconnect the components.

The neutral bus in a panelboard that serves selected loads must not be connected to the metal panelboard enclosure. Connecting the neutral conductor, the grounding electrode conductor, and the equipment grounding conductors together is permitted only in the main service panelboard.

If you were to bond the neutral conductor and the metal enclosures of the equipment (panelboard, transfer switch, and generator) together beyond the main service panelboard, you would create a parallel path. A parallel path means that some of the normal return current and fault current will flow on the grounded neutral conductor and some will flow on the metal raceways and other enclosures. This is not a good situation!

Manufacturers of generators in most cases do not connect the generator neutral conductor lead to the metal frame of the generator. Instead, they connect it to an isolated terminal. Then it is up to you to determine how to connect the generator in compliance with the NEC and/or local electrical codes.

Most inspectors will permit the internal neutral bond in a portable generator to remain in place. In fact, when you purchase a portable generator, you should insist the neutral-to-case bond is in place.

Without the bond, an overcurrent device cannot function on a ground fault because a return path does not
exist. For permanently installed generators, inspectors will generally not permit a bond between the
generator neutral and the metal frame of the generator because of the explicit requirements in the NEC.

A sign must be placed at the service-entrance main panelboard indicating where the standby
generator is located and what type of standby power it is.

The total time for complete transfer to standby power is approximately 45–60 seconds. To further give the homeowner assurance that the standby generator will operate when called upon, some systems provide automatic “exercising” of the system periodically, such as once every 7 or 14 days for a run time of 7 to 15 minutes.


WARNING: When an automatic type of standby power system is in place and set in the automatic
mode, the engine may crank and start at any time without warning. This would occur when the utility
power supply is lost.

To prevent possible injury, be alert, aware, and very careful when working on the standby generator equipment or on the transfer switch. Always turn the generator disconnect to the “Off” position, then lock out and tag out the switch, warning others not to turn the switch back “On.” In the main panelboard, locate the circuit breaker that s upplies the transfer equipment, turn it “Off,” then lock out and tag out the circuit breaker feeding the transfer switch.

UNGROUNDED SYSTEM BASIC INFORMATION

In this type of system, a phase-to-earth fault only produces a weak current through the

phase-to-earth capacity of the fault-free phases.

It can be shown that Id = 3 CwV

V being the simple voltage,

C the phase-to-earth capacity of a phase,

wthe frequency of the system (w = 2* pi *f).

The Id current can remain for a long time, in principle, without causing any damage since

it does not exceed a few amperes (approximately 2 A per km for a 6 kV singlepole

cable, with a 150 mm2 cross-section, PRC insulated, with a capacity of 0.63 mF/km).

Action does not need to be taken to clear this 1st fault, making this solution advantageous in

terms of maintaining service continuity.

However, this brings about the following consquences:

c if not cleared, the insulation fault must be signalled by a permanent insulation monitor, c subsequent fault tracking requires device made all the more complex by the fact that it is automatic, for quick identification of the faulty feeder, and also maintenance personnel qualified to operate it, c if the 1st fault is not cleared, a second fault occurring on another phase will cause a real two-phase short circuit through the earth, which will be cleared by the phase protections.

Advantage

The basic advantage is service continuity since the very weak fault current prevents automatic tripping.

Drawbacks

The failure to eliminate overvoltage through the earth can be a major handicap if overvoltage is high. Also, when one phase is earthed, the others are at delta voltage (U = V* sqrt 3) in relation to the earth increasing the probability of a 2nd fault.

Insulation costs are therefore higher since the delta voltage may remain between the phase and earth for

a long period as there is no automatic tripping. A maintenance department with the equipment

to quickly track the 1st insulation fault is also required.

Applications

This solution is often used for industrial systems (< or = 15 kV) requiring service continuity.

INSULATION RESISTANCE TEST AND HI POT TESTING BASICS

Insulation resistance tests are typically performed on motors, circuit breakers, transformers, low-voltage (unshielded) cables, switchboards, and panel boards to determine if degradation due to aging, environmental, or other factors has affected the integrity of the insulation. This test is normally conducted for 1 min, and the insulation resistance value is then recorded.

As mentioned earlier, the electrical properties of the insulation and the amount of surface area directly affect the capacitance between the conductor and ground, and therefore affect the charging time. With larger motors, generators, and transformers, a common test is to measure the "dielectric absorption ratio" or the "polarization index" of the piece of equipment being tested.

The dielectric absorption ratio is the 1 min insulation resistance reading divided by the 30 s insulation resistance reading. The polarization index is the 10 min (continuous) insulation resistance reading divided by the 1 min reading.

Both of these provide additional information as to the quality of the insulation. Many types of insulation become dry and brittle as they age, thereby becoming less effective capacitors.

Thus, a low polarization index (less than 2.0) may indicate poor insulation. Even though insulation may have a high insulation resistance reading, there could still be a problem, since the motor and transformer windings are subjected to strong mechanical stresses on starting.

With the exception of electronic equipment (which can be damaged by testing), insulation resistance testing is normally done on most types of new equipment and is also part of a maintenance program. It is a good practice to perform insulation resistance testing on switchgear and panelboards after maintenance has been performed on them, just prior to re-energizing them. This prevents re-energizing the equipment with safety grounds still applied or with tools accidentally left inside.


High-potential testing, as its name implies, utilizes higher levels of voltage in performing the tests. It is generally utilized on medium-voltage (1000-69 000 V) and on high-voltage (above 69 000 V) equipment.

As stated earlier, the leakage current is usually measured. In some cases, such as in cable hi-potting, the value of leakage current is significant and can be used analytically. In other applications, such as switchgear hi-potting, it is a pass/fail type of test, in which sustaining the voltage level for the appropriate time (usually 1 min) is considered "passing."

AUTOMATIC METER READING (AMR) TECHNOLOGIES BASIC INFORMATION AND TUTORIALS

PURPOSE AND ADVANTAGE OF AMR
To eliminate meter access problems and data entry errors while improving overall meter reading efficiency, many utilities are implementing Automatic Meter Reading (AMR) technology. The AMR technology enables utilities to collect meter data without having to visit the meter. Nationwide, an increasing number of electric, gas, and water utilities are installing these remote data collection technologies.

Electric utilities are also beginning to deploy AMR technology for reasons that go beyond metering and customer billing. As the energy marketplace deregulates and becomes more competitive, utilities are seeking ways to use advanced metering data throughout their distribution operations to achieve a variety of other objectives.

These are; improved demand forecasting accuracy, increased energy distribution system efficiency, delivery of new rates and services, and successful management of customer choice and retail competition in their service territories.

Utilities have a wide choice of AMR technologies and companies from which to choose. These technologies include wired and wireless data collection systems that use both public and private communication networks, including broadband and cellular.

Some AMR vendors offer products that use existing power lines to transmit collected data while others are working to develop systems that rely on satellites and other more exotic technologies that have yet to prove themselves as either practical or cost effective. The AMR industry also features meter data collection technologies to serve residential, commercial, and industrial customers equipped with more advanced solid-state electric meters.

From radio-equipped handheld terminals to vehicle-based systems to large fixed networks, these automatic meter-reading systems offer a wide range of data collection functionality at a wide range of costs. The suitability and cost-effectiveness of a particular AMR technology depends on a number of variables; the type of service territory (urban, suburban, or rural), the type of customer (residential, commercial, or industrial), and the data collection needs of a particular utility.

These needs can vary greatly.

Many utilities are deploying integrated AMR solutions that combine different collection technologies (e.g., network, mobile, and telephone), to deliver the desired level of data collection functionality for different service areas and customer segments in the most cost-effective manner.

Each of these technologies— handheld computers, mobile vehicle-based systems, wireless networks, telephone-based systems and powerline carrier—has its own set of strengths depending on a utility’s operational and strategic objectives.


Radio-Based Mobile Automatic Meter Reading
With a radio-based system, each meter is adapted with a compact, low-power transmitter/receiver that upon request, broadcasts a radio signal containing metering and tamper data.

These meters are polled by a mobile handheld terminal or vehicle-based transmitter/receiver that collects meter readings from many meters and carries the readings back to the central office. At the end of the day, the readings are loaded directly into the utility’s billing computer.

The mobile transceiver can be in a handheld terminal, or a higher-powered unit installed in a truck that is driven down streets, polling meters and recording replies. Depending on the service environment, meter density, memory capacity, and the type of meter readings collected, handheld terminals are typically capable of reading several hundred meters or more in a day.

More powerful vehicle-based units raise meter reading efficiency even further by reading thousands of meters in a single day.  Radio-based meter reading is fast, efficient, and generally reliable. Some meter installations inside metal buildings create difficulties for radio transmission but these site-related problems can often be solved by re-locating the
meter antenna.

Network Meter Reading
Radio-based fixed networks offer the most advanced data collection functionality of any wireless meter reading technology. There are many variations in the network data collection products available from different vendors.

Most wireless network meter reading systems involve installing a fixed communications network over a population of meters equipped with radio transmitters to send the data through the network to the host processor. Companies apply a variety of communications strategies for their network products that utilize private dedicated wireless networks, public networks, or some combination of the two.

Though more costly than handheld and mobile automatic meter reading systems, these networks provide electric utilities with state-of-the-art automatic meter reading functionality, including consumption reads, on-request reads, tamper reporting, time-of-use, demand metering, load profile/interval reads, virtual connect/disconnect capabilities, outage detection and restoration reporting, consumption monitoring, and aggregation capabilities.

Until now the handful of electric utilities that have deployed network meter reading systems have done so mostly on a large-scale, territory-wide basis to spread the cost of the network over a large number of meters—typically more than 100,000. However, recently several new more scalable and flexible network products have emerged that enable electric utilities to deploy advanced network meter reading technology on a more selective and cost-effective basis to serve specific meter populations or specific customer segments (such as commercial and industrial customers with advanced solid-state meters).

To reduce both implementation and ongoing operations costs, these new networks combine private, dedicated RF communication networks to gather data from designated populations of automated meters and then use public communications networks to back haul the data from local collection points to the host processor. While its penetration has been limited thus far, deployment of network meter reading and data collection technology will likely accelerate in the years to come as costs come down and the need for utilities to gather more advanced metering data increases.

DYNAMOMETER POWER FACTOR AND PHASE ANGLE MEASUREMENT

Measurement of Power Factor and Phase Angle

A variation of the fundamental electrodynamometer instrument is used to measure power factor or the phase angle, and is called the crossed-coil type. See Figure 6-7. In this design the moving element consists of two separate coils, instead of one which are mounted on the same shaft and set at an angle to each other.

The lead-in springs or spirals to the crossed coils are made as light or weak as possible so as to exert practically no torque. In the single-phase instrument, one of the crossed moving coils is connected in series with a resistor across the line while the other is connected in series with a reactor across the line.

The current flowing through the reactor-connected coil is approximately 90 degrees out of phase with the line voltage. The field coil is connected in series with the line as an ammeter coil.

In operation, the moving system assumes a position dependent upon the phase relationship between the line current and the line voltage. If the line current is in phase with the line voltage, the reactor-connected moving coil will exert no torque and the resistor-connected coil will align its polarities with those of the fixed-coil field.

If the line current is out of phase with the line voltage, the reactor connected moving coil will exert a restraining or counter torque and the moving element will assume a position in the field of the fixed coil where the two torques are in balance.

This instrument may be calibrated to indicate either power factor or the phase angle between the line voltage and current. In the three-phase power factor instrument, the crossed moving coils are connected to opposite legs of a three-phase system.

The fixed coils are connected in series with the line used as a common for the moving-coil connection. This instrument will give correct indication on balanced load only.

When these instruments are not energized, the pointer has no definite zero or rest position as do instruments whose restraining torque is a spring. They are therefore known as free-balance instruments.

Power factor meters may also be of the induction type. In one such type for single-phase use, the fixed element consists of three stationary coils and the moving element comprises an indicator shaft bearing an iron armature. As in the electrodynamometer type, operation is based on the interaction of a rotating and an
alternating magnetic field.

THREE-WIRE,THREE-PHASE DELTA SERVICE METERING TUTORIALS

Two-Element (Two-Stator) Meter
The three-wire, three-phase delta service is usually metered with a two-stator meter in accordance with Blondel’s Theorem. The meter used has internal components identical to those of network meters, but may differ slightly in base construction.

Typical meter connections are shown in Figure 7-4. In the top element (stator) of the meter the current sensor carries the current in line lA and the voltage sensor has load voltage AB impressed on it. The bottom element (stator) current sensor carries line current 3C and its corresponding voltage sensor has load voltage CB impressed. Line 2B is used as the common line for the common voltage-sensor connections.

The phasor diagram of Figure 7-4 is drawn for balanced load conditions. The phasors representing the load phase currents IAB, IBC, and ICA are shown in the diagram lagging their respective phase voltages by a small angle . By definition, this is the load power-factor angle. The meter current coils have line currents flowing through them, as previously stated, which differ from the phase currents. To determine line currents, Kirchhoff’s Current Law is used at junction points A and C in the circuit diagram. Applying this law, the following two equations are obtained for the required line currents:


The operations indicated in these equations have been performed in the phasor diagrams to obtain I1A and I3C. Examination of the phasor diagram shows that for balanced loads the magnitude of the line currents is equal to the magnitude of the phase currents times the sqrt of 3.

The top element (stator) in Figure 7-4 has voltage EAB impressed and carries current I1A. These two quantities have been circled in the phasor diagram and inspection of the diagram shows that for the general case the angle between them is equal to 30° . Therefore, the power measured by the top element (stator) is EABI1Acos(30° ) for any balanced-load power factor. Similarly, the bottom element (stator) uses voltage ECB and current I3C. These phasors have also been circled on the diagram and in this case the angle between them is 30° . The bottom element (stator) power is then ECBI3Ccos(30° ) for balanced loads. The sum of these two expressions is the total metered power.


Examination of the two expressions for power shows that even with a unity
power factor load the meter currents are not in phase with their respective
voltages. With a balanced unity power factor load the current lags by 30° in the top
element (stator) and leads by 30° in the bottom element (stator). However, this
is correct metering. To illustrate this more cleanly, consider an actual load of
15 amperes at the unity power factor in each phase with a 240-volt delta supply.
The total power in this load is:
3 EPhase IPhase cos 3 240 15 1 10,800 watts
Each element (stator) of the meter measures:
Top Element EABI1Acos(30° )
Since I1A 3 IPhase
Top Element 240 3 15 cos(30° 0°)
240 3 15 0.866 5,400 watts
Bottom Element ECBI3Ccos(30° °)
Since I3C 3 IPhase
Bottom Element 240 3 15 cos(30° 0°)
240 3 15 0.866 5,400 watts
Total Meter Power Top Element Bottom Element 5,400 5,400
10,800 watts Total Load Power
When the balanced load power factor lags, the phase angles in the meter vary
in accordance with the 30° expressions. When the load power factor reaches
50%, the magnitude of is 60°. The top stator phase angle becomes 30° 90°
and, since the cosine of 90° is zero, the torque from this stator becomes zero at this
load power factor. To illustrate this with an example, assume the same load current
and voltage used in the preceding example with 50% load power factor.
Total Load Power 3 240 15 0.5 5,400 watts
Top Element 240 3 15 cos(30° 60°)
240 3 15 0 0 watts
Bottom Element 240 3 15 cos(30° 60°)
240 3 15 0.866 5,400 watts
Total Meter Power 0 5,400 5,400 watts Total Load Power.
With lagging load power factors below 50%, the top element power reverses
direction and the resultant action of the two elements (stators) becomes a differential
one, such that the power direction is that of the stronger element (stator).
Since the bottom element (stator) power is always larger than that of the top
element (stator), the meter power is always in the forward direction, but with
proportionately lower power at power factors under 50%. Actually on a balanced
load, the two elements (stators) operate over the following ranges of power factor
angles when the system power factor varies from unity to zero: the leading
element (stator) from 30° lead to 60° lag, the lagging element (stator) from 30° lag
to 120° lag.


As such, the watt metering formula for any instant in time is:
Watts (Vab Ia) (Vcb Ic) Accumulating the watts over time allows the metering of watthours.